The Electric Utility Chemistry Workshop was organized in the early 1980s as a conference to provide solid, practical information about steam generation chemistry, makeup water and cooling water treatment, air emissions control, environmental regulations and other topics to power plant personnel in the Great Lakes region.

Direct utility participation and abundant networking opportunities were key features of the EUCW. These benefits attracted personnel from other parts of the country, and now, as the workshop emerges from the disruption of the pandemic, we are seeing more national and international participation, including this year from Power Engineering’s/POWERGEN International’s Kevin Clark. A heretofore somewhat overlooked benefit of this conference is its potential value for those employed at cogeneration and large industrial plants, as water/steam treatment issues cut across many industries.

The following discussion highlights several important topics from this year’s event. The positive response to the diversity of topics has the committee considering a rename of the conference to the Electric Utility and Cogeneration Chemistry Workshop (EUC²W).

Cooling water

Virtually all large industrial plants have multiple cooling water systems. While some large heat exchangers such as power plant steam surface condensers may be on once-through cooling, many cooling systems are of the open-recirculating design that have a cooling tower as the core heat discharge process.

A universal feature of cooling towers is that evaporation increases the dissolved and suspended solids concentration of the recirculating water, which requires a combination of blowdown and precise chemistry control to minimize scale formation and corrosion. (Sidestream filtration is a common, but not always employed method for suspended solids removal.¹) Furthermore, cooling systems provide an excellent environment for microbiological fouling that can cause extreme problems.

With the substantial aid of expert colleagues, this author has discussed cooling water treatment methods and program evolution numerous times during the last 15 years of the EUCW. Key points include:

• The very popular acid/chromate programs of the middle of the last century have disappeared due to concerns over the toxicity of hexavalent chromium (Cr⁶⁺).
• The primary replacement programs relied on inorganic and organic phosphates, with perhaps a small dosage of zinc, for scale and corrosion protection. However, calcium phosphate deposition became a major problem with these programs, requiring development of polymers to control this deposition. In recent years, concerns have dramatically grown about phosphate in cooling tower blowdown and its influence on receiving water bodies such as lakes and rivers. Phosphorus is a primary nutrient for algae growth in surface waters.
• The major water treatment companies have developed non-phosphorus (non-P) programs that rely on specialized organic compounds and additives to establish a direct barrier on metal surfaces to minimize corrosion. The formulations typically include advanced polymeric compounds for scale control.
• Microbiological fouling control continues to be of paramount importance. However, the higher pH (typically near or slightly above 8) of modern scale/corrosion control programs can reduce the efficacy of chlorine (usually fed as bleach) treatment. Alternative oxidizers such as chlorine dioxide and monochloramine may be more effective in these moderately alkaline environments. Periodic treatment with non-oxidizing biocides can also be beneficial. Careful evaluation is necessary for selection of the best treatment method. And, changes to a biocide feed program are not allowed without approval of the proper regulatory authorities.

Makeup water treatment

Makeup water treatment technology has evolved substantially in the last several decades. This section provides an overview of important developments, starting with a fundamental requirement for new projects and finishing with discussion directly related to co-generation and industrial applications.

Importance of comprehensive raw water analyses

One of this author’s important tasks for several years was review of proposed makeup water treatment configurations for new combined cycle power plants and other industrial facilities. Comprehensive, and ideally historical, raw water chemistry data is very important to correctly size and select treatment systems and treatment programs, but only on rare occasions did the design specs for new projects contain complete analyses. Even when a report offered comprehensive data, it was usually based on a single “snapshot” analysis. The chemistry of many supplies can change significantly over seasons and often after heavy precipitation, necessitating the need for more than a single analysis. Cases are known in which the original treatment system had to be replaced because it could not process the makeup water per improper design based on faulty or missing raw water quality data. Understandably, replacement costs were quite large.

Pretreatment system evolution

In the last century, clarification/sand filtration was a standard method for raw water suspended solids removal. Clarifiers were typically circular in shape and had a large footprint to allow the particles produced by coagulation and flocculation to settle into a sludge blanket within the outer clarifier zone. A common metric for clarifier operation is the rise rate, which is the ratio in gallons-per-minute of effluent divided by the surface area at the top of the clarifier. A reasonable rise rate for large circular clarifiers was around 1 gpm/ft². Periodic sludge blowdown is important to maintain the blanket at a proper depth.

Detailed discussion of clarifier evolution is beyond the scope of this article, but a modern clarifier technology, which utilizes microsand ballast that is recycled to the process, is shown in Figure 3.

An immediate observation is the rectangular nature of the unit and the inclined plates (lamella style) to improve floc settling. A key feature is the use of microsand to enhance floc formation, with sand recovery and recycle in hydrocyclones. Rise rates of 25 gpm/ft² or greater may be possible in such units, greatly reducing the footprint.

It should be noted that other similar systems have appeared. A prime example is Xylem’s CoMag® process with a ballast material of the iron oxide, magnetite (Fe₃O₄). This process has emerged as a treatment method for some industrial wastewaters containing heavy metals, where some metals co-precipitate with magnetite and are directly removed from solution.

Yet another twist to makeup water treatment is the increasing use of alternative sources, most notably municipal wastewater treatment plant effluent, for industrial plant makeup. These waters may require additional treatment equipment such as membrane bioreactors (MBR) or moving-bed bioreactors (MBBR) to reduce the concentrations of microbiological nutrients and food.^{1, 3}

Advancements in high-purity water production for utility boilers

When this author began his career in the early 1980s, a very common method for high-purity makeup production for utility boilers was pretreatment by clarification/filtration followed by ion exchange (IX) for dissolved solids reduction to part-per-billion (ppb) concentrations. The typical but by no means exclusive IX arrangement was strong acid cation (SAC)-strong base anion (SBA)-mixed bed (MB). This process proved effective, but service runs were relatively short, especially with feed water having high dissolved solids concentrations. An outcome was frequent IX resin regenerations that consumed significant quantities of acid and caustic.

Within the last four decades, the membrane technology of reverse osmosis (RO) has evolved and become quite mature. RO membranes can remove 99% of dissolved solids, which made them ideal for retrofit at plants with IX units and excellent as the core demineralization process in new makeup systems. Also emerging during this time period was membrane-based micro- and ultrafiltration (MF and UF, respectively) pretreatment technology.

In many cases, these units can replace clarifiers/filters for suspended solids removal of RO feed water. (The author once initiated a project to replace an aging clarifier with MF at a former power plant, and the unit performed superbly.) Accordingly, a common makeup water configuration for modern combined cycle power plants is MF (or UF) / RO / MB polishing. Popular is an arrangement that includes mixed-bed portable units, aka “bottles,” that an outside vendor swaps out and regenerates at their facility.

Paradoxically, makeup water treatment for low pressure boilers (<600 psig) may be more troublesome than for high-pressure units, but the difficulties can be mindset- rather than technology-based. Because low-pressure boilers have reduced heat fluxes as compared to utility boilers, makeup quality requirements are more relaxed.⁴ Critical, however, is hardness removal to minimize the potential for scale formation. Ion exchange sodium softening, sometimes with downstream dealkalization, has been a popular technique for decades. Sodium softeners are straightforward to operate, and resin regeneration only requires simple brine solutions.

Unfortunately, way too many cases are known where plant management has focused on process chemistry and engineering to the neglect of water treatment support, both from an infrastructure and staffing perspective. Periodic softener upsets (and sometimes complete unit failure) allow hardness excursions. Figure 4 illustrates one outcome.

One of the first items a consultant often examines when called in to investigate boiler tube failures is softener operating history. Further information is available in references 3 and 5.

Cogeneration presents a wild card with condensate return

One other major issue exists when comparing cogeneration/industrial boiler operation to utility units. The water/steam path for fossil-fired power boilers is usually straightforward. Steam produced in the boiler and superheater/reheater drives a turbine to generate electricity. The turbine exhaust steam is condensed in a water-cooled (or perhaps air-cooled) condenser, with the condensate returning directly to the boiler. The condensate and steam typically remain pure unless a condenser cooling water leak, or, more rarely, a makeup water system upset, introduces contaminants. The situation is often quite different at co-generation and large industrial plants, where condensate may come from a variety of heat exchangers and processes. Impurities can potentially include inorganic ions, suspended solids, acids and alkalis, and organic compounds.

Depending on the intermediate and final products that circulate through process heat exchangers and reaction vessels, a wide variety of compounds can potentially enter the condensate. These impurities include inorganic ions, acids and bases, suspended solids, and organics. The author once visited a chemical plant where organic contamination of the condensate return caused foaming in four, 550 psig package boilers, which in turn required frequent and costly superheater replacements.

Several possibilities may be available to minimize impurity transport from condensate to steam generators. The root cause solution is to repair heat exchanger leaks and eliminate problems at the source. This may be easier said than done given that large plants can have dozens if not hundreds of heat exchangers with complicated configurations.

Condensate polishing is a viable option in some cases. For example, ion exchange is a mature technology for removing inorganic ions from condensate (it is an absolute requirement for protecting supercritical power boilers). Activated carbon may perhaps be effective for some organic compounds, but molecular size, presence of active groups, and other factors can influence the reactivity of the organics towards carbon. Laboratory and pilot testing are often needed to determine the viability of activated carbon polishing.

Sometimes necessary (and as Figure 4 includes) are automatic dump valves that, as the name implies, dump the condensate to drain if on-line instrumentation detects contaminant ingress. Of course, condensate dumping requires increased makeup water production and it adds to the load on a plant’s wastewater treatment system.

A key takeaway from this section is that while several solutions may be available to protect boilers from condensate contamination, careful analysis and testing is necessary to determine the proper solution. But the investment can pay for itself many times over.

Conclusion

Many industries face water/steam treatment issues that are well known in the power industry. The EUCW is a place to hear presentations and participate in valuable discussions about these issues and modern technologies to address them. Because I am also actively involved with POWERGEN International, I hope to address several of these topics at PGI 2025 next January.

References

1. Water Essentials Handbook (Tech. Ed.: B. Buecker). ChemTreat, Inc., Glen Allen, VA, 2023.  Currently being released in digital format at https://www.chemtreat.com/.
2. R. Post, B. Buecker, and S. Shulder, “Power Plant Cooling Water Fundamentals”; pre-conference seminar for the 37^th Annual Electric Utility Chemistry Workshop, June 6, 2017, Champaign, Ill.
3. B. Buecker and E. Sylvester, “Foundational and Modern Concepts in Makeup Water Treatment”; pre-conference seminar for the 42^nd Annual Electric Utility Chemistry Workshop, June 4, 2024, Champaign, Ill.
4. 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.
5. E. Sylvester, “Makeup Water Treatment Processes – Ignore at Your Peril”; presentation at the 42^nd Annual Electric Utility Chemistry Workshop, June 4-6, 2024, Champaign, Ill.

About the Author: Brad Buecker is president of Buecker & Associates, LLC, consulting and technical writing/marketing. Most recently he served as a senior technical publicist with ChemTreat, Inc. He has many years of experience in or supporting the power industry, much of it in steam generation chemistry, water treatment, air quality control, and results engineering positions with City Water, Light & Power (Springfield, Ill.) and Kansas City Power & Light Company’s (now Evergy) La Cygne, Kan., station. His work has also included eleven years with two engineering firms, Burns & McDonnell and Kiewit, and he spent two years as acting water/wastewater supervisor at a chemical plant. Buecker has a B.S. in chemistry from Iowa State University with additional course work in fluid mechanics, energy and materials balances, and advanced inorganic chemistry. He has authored or co-authored over 250 articles for various technical trade magazines, and he has written three books on power plant chemistry and air pollution control. He is a member of the ACS, AIChE, AIST, ASME, AWT, CTI, the Electric Utility Chemistry Workshop planning committee, and he is active with the International Water Conference and POWERGEN International.

Steam surface condensers are still a critical component at many power plants and co-generation
facilities. Maintaining tube cleanliness is vital to maximize heat transfer. Table 1 illustrates the
thermal conductivities of two common heat exchanger tube materials and also three common
waterside foulants, and in particular, bio-slime and calcium carbonate.

*Data extracted from Reference 1
The data shows the strong insulating properties of deposits. A primary focus of this article is
purported new technology for lowering the potential for CaCO₃ deposition.

Issues with calcium carbonate scale formation

Probably from the time humans began heating water for cooking, hygienic, and other purposes
they became acquainted with calcium carbonate scale formation. Two of the most common ions
in fresh waters are calcium (Ca²⁺) and bicarbonate alkalinity (HCO₃^–). In combination, these
ions have a low solubility, and when heated the solubility decreases even further.

Ca²⁺ + 2HCO₃^– + heat → CaCO₃↓ + CO₂↑ + H₂O

In untreated waters, CaCO₃ (calcium carbonate) is usually the predominant scaling compound.
CaCO₃ is the deposit that forms in home hot water piping and showerheads, and which is
incorrectly referred to as “lime scale.” (Lime is calcium oxide (CaO) or in its hydrated form,
Ca(OH)₂) Furthermore, many thousands of cooling water systems have a cooling tower at the
heart of the process. Heat transfer primarily occurs from evaporation of a fraction of the
recirculating water. Evaporation causes the water to “cycle up” in concentration, which in turn
significantly increases the potential for scale formation without proper treatment.

A very effective solution to reduce CaCO₃ scaling potential is sulfuric acid injection to the
makeup or circulating water to convert bicarbonate alkalinity into carbon dioxide that escapes
from solution.

HCO₃^–_(aq) + H₂SO₄ → HSO₄^2-_(aq) + H₂CO_3(aq)

H₂CO_3(aq) ⇌ CO₂↑ + H₂O

In the middle of the last century a hugely popular treatment program for open-recirculating
systems consisted of sulfuric acid feed for scale control (to establish a pH range of 6.5-7.0), and
use of disodium chromate (Na₂Cr₂O₇) for corrosion control. This latter compound provides
chromate ions (CrO₄^2-) that react with carbon steel to form a pseudo stainless-steel layer which
passivates the metal surface and inhibits corrosion.

In the 1970s and 1980s dawning recognition of hexavalent chromium (Cr⁶⁺) toxicity led to a ban on
chromium discharge to the environment that essentially eliminated chromate treatment for open-recirculating cooling water systems. The replacement programs utilized inorganic and organic
phosphate compounds, with supplemental or inclusive polymer chemistry becoming much more
common in recent times.^2,3

But articles and reports continue to appear about the possibility of waterside tube coatings to
minimize scale formation in condensers, with a piece last month from Power Engineering’s editor,
Kevin Clark, posted on the PE website.⁴ These coatings are designed to inhibit scale formation. It
seems though that a number of questions must be answered before coatings technology becomes
viable.

Coating questions

Having worked with condensers for many years and recently authoring two articles on the subject
for Power Engineering,^5,6 several questions/comments came to mind regarding Reference 2. Perhaps many of these questions could be answered from pilot testing. They include:

• The authors focus on the coating’s potential to inhibit calcium carbonate scaling. The
  question that obviously comes to mind is, “How much would this coating (or any other
  coating for that matter) impede heat transfer?” If the thermal conductivity is not
  significantly greater than the mineral deposits the coating inhibits, it becomes difficult to see
  the benefits.
• What is a typical coating thickness?
• How is the coating applied?
• What surface preparation is needed to ensure strong coating attachment?
• What process is needed to impart the ridges (highlighted in Reference 2) on the coating
  surface?
  o Might these ridges offer more sites for settling of microorganisms and subsequent
  microbial fouling?
• What are the curing methods and cure times for the coating?
• What safety precautions are necessary for coating applications?
  o Necessary personal protective equipment
  o Confined space issues
  o Potential release of volatile organic carbon (VOC) compounds
  o Disposal of application waste materials
• How resistant is the coating to normal mechanical wear, oxidizing biocides, and
  temperature?
• Consider the potential situation of a condenser that becomes fouled and requires mechanical
  cleaning with either tube scrapers or brushes. How much damage would this do to the
  coating?

Conclusion

Having lived all my life and attended college in three of the states that border Missouri, I guess I
have a bit of a “show me” attitude at times. From the questions above, the most important still
seems to be the heat transfer issue. It is hard to imagine that any coating would have a heat transfer
coefficient close to those of typical tube metals. Also, other cooling system components require
corrosion and deposition protection that come with good chemistry programs. Finally, even if
coatings prove to be successful at inhibiting scale formation, microbial control issues will surely
remain and will continue to require well-designed and operated biocide feed systems.

References

1. “Thermal Conductivities of Biofilm, Metals, and Scale”; ChemTreat Technical Bulletin #164, June 2013.
2. B. Buecker (Tech. Ed.), “Water Essentials Handbook”; 2023. ChemTreat, Inc., Glen Allen, VA.  Currently being released in digital format at www.chemtreat.com.
3. Buecker, B. and P. Kalakodimi, PhD., “Current Concepts in Cooling Water Chemistry”; pre-conference seminar to the 41^st Annual Electric Utility Chemistry Workshop, June 6-8, 2023, Champaign, Illinois.
4. K. Clark, “Researchers say hydrogel coating a possible solution in the fight against scaling”; Power Engineering, www.power-eng.com, February 23, 2024.
5. B. Buecker, “Condenser Performance Monitoring – Part 1”; Power Engineering, August 2023.
6. B. Buecker, “Condenser Performance Monitoring – Part 2”; Power Engineering, December 2023.

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 many years 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 is a member of the ACS, AIChE, AIST, ASME, AWT, CTI, and the Electric Utility Chemistry Workshop planning committee.  He is active with the International Water Conference and Power-Gen International.  He may be reached at beakertoo@aol.com.

POWERGEN International (PGI) has been a beacon of information for over 35 years. Coal was king for the first two-thirds of PGI’s history, and at one point a satellite conference, Coal-Gen, even emerged. Obviously our industry has undergone dramatic changes, and the recently concluded “POWERGEN 2024: Destination 2050” offered many examples of this continuing evolution. 

But every year, this author hears some colleagues exclaim “This is not the POWERGEN that I once knew.” 

Being a former coal-fired power plant steam generation chemist and air pollution control specialist, I can sympathize with these feelings. But we all must face the reality of a rapidly changing industry, where decarbonization is a major driver, and meeting this goal requires many technologies and solutions. Kevin Clark, the content director of Power Engineering and POWERGEN International, emphasized these ideas during an informative conversation we had at the conference. 

This article highlights several of the most important topics from this year’s event. A foundational concept to remember in this discussion is the importance of continued grid stability as the country progresses towards decarbonization. The potential for blackouts and even partial grid collapse from prematurely implemented alternative energy systems could be catastrophic to our economy and personal well-being.

The King is (not quite) dead

Coal-fired power production is not completely dead, and in recent months we have seen some power companies extend deadlines for coal plant retirements due to issues regarding grid stability. In that vein, several tracks at PGI 2024 addressed carbon capture and sequestration (CCS), a contentious issue often defined by one’s side of the political/environmental spectrum. The obvious major benefit of CCS is that the technology might allow some continued use of a plentiful fuel that has a large storage capacity.  Common for coal plants is a 30-day fuel inventory, which vastly exceeds current battery storage capabilities for renewable sources.

However, this benefit is counterbalanced by a number of potentially troublesome issues related to the leading CCS technology at present, CO₂ removal via scrubbing with an amine solution. Some of the most important include:

• The process adds a large and expensive chemical plant to any unit.
• Parasitic power consumption may reach 30%.
• The process consumes a significant amount of water and generates several wastewater streams.
• Concerns continue to grow, some from the general public, about safety issues related to CO₂ transport to injection sites. Pipeline projects have been halted per such concerns.

Another critical issue facing coal plants, retired or still operating, is storage and disposal of bottom ash and fly ash. Of great concern is leachate from these ponds contaminating groundwater and surface water. Much time, effort, and expense will be required to remediate ash storage ponds. The situation has not been helped by several high-profile ash pond failures that have occurred over the last two decades or so.    

Talk continues to swirl about carbon dioxide reduction from the combined-cycle power plants that have served as a bridge technology in the transition from coal to renewables. A requirement to install CO₂ scrubbing technology, at least as it currently exists, on natural gas-fired power units would put those facilities in a huge economic bind.

Renewables: Not yet a straightforward path

Renewable energy, and most notably but certainly not limited to wind and solar, is a primary topic at PGI events. It is hard to argue the foundational concept of wind/solar renewable energy, free and inexhaustible fuel from the sun. However, many clouds still populate the horizon (pardon the pun).  Infrastructure issues can be very challenging. Many wind turbines or solar cells are required to generate the equivalent power of a large coal- or gas-fired plant. Individual wind farms can cover many acres and generate public resistance about their influence on the scenery. Replacement and disposal of aging materials are additional concerns.

A particular development, which was addressed at POWERGEN and also very recently in Reference 1, is the emergence of winter load vs. generating capacity conflicts. When coal was king, it, along with nuclear energy provided most of the electricity to the country. Plants produced steady power throughout the year, apart from periodic regional severe weather events. So, maximum generating capacity bumping up against load requirements was usually limited to summer operation. With wind and solar, nature has much more of a say regarding generating capacity. In northern locations with short winter days and sometimes frequent snowstorms, solar production may fall to near zero for extended periods. 

Compounding the problem are the not uncommon wind droughts that can cover a wide region.  Wind/solar generating capacity has been known to drop to a very small fraction of nameplate. The kicker is that present battery storage capacity is limited to just a few hours. So, it is very difficult at present to store enough energy to cover load when nature says, “I am taking over.” Obviously, improved battery technology will help alleviate these problems, but how quickly will long-term battery storage arrive? An interesting aspect in this regard are research efforts into more abundant materials than lithium for future battery systems.

A nuclear renaissance?

For years the term “nuclear renaissance” has been tossed around. Nuclear power produces no CO₂ emissions, but public perception of nuclear energy still in large measure remains negative per the enormously high-profile accidents of yesteryear in the U.S., Russia, and Japan. Furthermore, large nuclear plants continue to be enormously expensive. 

Many in the industry are banking on small modular reactor (SMR) technology as the path forward. An argument I hear regularly about the viability of small reactors is that the “U.S. Navy has been using them for years in many of their ships, so the technology is established.” That answer may sound somewhat simplistic, but one argument for continued development of SMR technology is the potential for design standardization to help keep costs low, relatively speaking. Power experts are also looking at small reactors for microgrid applications, where a unit would provide the energy for a local area or perhaps a concentrated group of heavy industries. Managers at refineries, petrochemical plants, steel mills, etc., continue to explore opportunities for replacing some steam-fed heat exchangers with electrical energy. 

Of course, an issue that will remain at the forefront of new nuclear development is spent fuel disposal.  Some argue that breeder reactor technology to convert spent material to new fuel is proven. This discussion will definitely continue, including at future PGI events.

Is hydrogen part of the answer?

Much is being made about projects to produce “green” hydrogen; the generation of H₂ by electrolysis of water with either renewable or nuclear as the energy source. The hydrogen could then serve in multiple applications, including fuel for transportation and as a blended fuel or perhaps even the primary fuel for combined cycle power units. Already in design are combustion turbines to burn blended fuel or even straight hydrogen. 

Some significant speed bumps exist along this path. One is the presence of adequate water supplies for the hydrogen feedstock. I have seen some maps that show potential production facilities in interior portions of the country where water is scarce. This concept seems unrealistic. An alternative is to place production facilities along the coasts with their inexhaustible supply of seawater. However, electrolyzers require high-purity feed water, which would in turn require considerable effort to purify seawater.

Hydrogen distribution also presents challenges. Hydrogen pipeline technology is well established at industries along the “chemical coast” of Texas and Louisiana, but for new energy applications, hydrogen might have to be moved much longer distances. One concept is establishment of “hydrogen hubs” for gathering and distribution of the gas. Of course, hydrogen is extremely combustible, so safety considerations must take top priority. Another concept is to convert the produced nitrogen to ammonia and then transport that product to final locations. Anhydrous ammonia is combustible, but burning it directly produces nitrogen oxides (NO_x), which for years power plants have been removing from flue gas via selective and non-selective catalytic reduction. This is yet another hurdle to consider.

Conclusion

As was mentioned in the introduction, POWERGEN is not the same conference it was in halcyon days of fossil fuel-fired power generation. But this must be expected. The power industry has changed dramatically in the last ten to twenty years, and this change will continue. The conference must keep pace with the industry. Perhaps within a few years we might start seeing papers on fusion-based power production. “Never say never” is a key phrase when it comes to technology advancements, a concept that POWERGEN management well understands.

References

1. K. Kohlrus, “Transition to renewables increases winter reliability risk”; Power Engineering, January 31, 2024.
2. S. Russell, P.E., and E. Eisenbarth, “Carbon Capture Water Requirements and Wastewater Treatment”; from the proceedings of the 2023 International Water Conference, November 12-16, 2023, San Antonio, Texas.

About the Contributor: 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 Part 1 of this series, we examined the importance of heat transfer in steam surface condensers,
where waterside microbiological fouling and scale formation, or excess air in-leakage on the stem-side, can greatly inhibit energy transfer.¹ Waterside deposits may also generate under-deposit
corrosion of condenser tubes that can lead to premature failures.

Accordingly, condenser performance monitoring is a critical tool to detect problems and respond accordingly. This article outlines fundamental methods to do so, some of which the author reported on in Power Engineering over three decades ago,² but which are still valid today.

Condenser heat transfer

Figure 1 outlines the basic schematic of a two-pass condenser. Three temperature readings are
required for a perfunctory performance analysis, inlet water temperature, outlet water temperature
and the hotwell temperature.

Under normal conditions, the hotwell temperature is equivalent to the steam saturation temperature,
as the cooling process extracts the amount of heat necessary to convert the turbine exhaust steam to
condensate but does not sub-cool the condensate. (Some sub-cooling may occur in winter without
adjustments to the inlet water flow.)

Seasonal changes in the inlet water temperature will, of course, influence the hotwell temperature
(and the pressure in the condenser, often referred to as the backpressure) and the outlet temperature. Comparison of the inlet to outlet temperature is not effective for tracking performance, but a
measurement that does remain relatively constant over time, in the absence of tube fouling or excess
air in-leakage, is the terminal temperature difference (TTD); the difference between the hotwell
temperature and the outlet temperature. Regular TTD monitoring provides a simplified method for
tracking condenser performance, however, sometimes seemingly minor TTD increases can go
unnoticed when in actuality the onset of some heat transfer degradation issue is underway.

Condenser cleanliness factors

As outlined in references 2 and 4, the author was introduced to an excellent method for tracking
condenser performance per a training module developed by the General Physics Corp. (now GP
Strategies Corp.) utilizing data supplied by the Heat Exchange Institute. I first put the calculations
into BASIC language and then, as spreadsheet software emerged, converted the program to that
format. The program utilizes the three temperature readings mentioned above plus the following
data:

• Cooling water density
• Cooling water flow rate
• Circulating water correction factor
• Condenser tube correction factor
• Number of condenser tubes
• Number of tube passes
• Inside tube diameter
• Outside tube diameter
• Tube length
• A “C” value from tables given in the GP course

Because the tube dimensions and correction factors are constant for any particular condenser, over
half of the items above can be initially incorporated into the calculations with no further
modifications. Also, because water density does not change very much over ambient temperature
ranges, an average value can be utilized without compromising the calculations.

The program calculates an actual and a design heat transfer coefficient, where the ratio of actual to
design is the cleanliness factor. Because tube surfaces are typically coated with an oxide layer, the
calculations are designed to give a maximum factor of 85% for clean tubes, although this is not an
absolute guideline. Best is to establish baseline values after a condenser tube cleaning with the unit
at full load, and with the condenser air ejector system operating properly. Then track performance
over time to observe changes.

The program proved to be excellent for monitoring performance, as the following case histories
indicate.

Case histories

The following histories come from work at my first utility, City Water, Light & Power (CWLP)
in Springfield, Illinois. These will be followed by an additional example from my second utility.
All examples are from two-pass, once-through condensers, but the method is equally effective on
systems with circulating water supplied by cooling towers.

Case History #1

I had been performing thrice-weekly cleanliness factor analyses on the largest condenser, rated at
1,000,000 lb/hr at maximum load. The values remained very steady in the mid-70% range for
several months, but suddenly within two days dropped to 45%. Waterside fouling does not occur
this rapidly, and such drastic changes are more indicative of excess air in-leakage. Visual
inspection revealed a large crack in the condenser shell where a heater drips line penetrates.

Once maintenance sealed this crack, the cleanliness factors returned to previous values where
they remained for another two months until suddenly dropping again. The seal had failed. The
maintenance crew then welded a collar around the drips line, which totally sealed the crack and
cured the problem.

Case History #2

I had been collecting thrice-weekly readings on two, 690,000 lb/hr condensers. Suddenly, one
condenser began performing erratically. At maximum unit loads, the cleanliness factors ranged
between 70% to 75%, but at low loads the factor dropped as low as 18%. Again, such
fluctuations could not have been the result of waterside fouling. Plant management brought in a
leak detection firm to look for air leaks. The inspectors employed helium leak detection to
completely check the condenser and low-pressure end of the turbine. They classified leaks as
large, medium, and small, and found over a dozen leaks, including two large ones, one of which
was from a crack in the expansion joint between the turbine exhaust and condenser.

Maintenance crews repaired all leaks, but this did not solve the problem. Finally, an operator
discovered that a trap on a line from the gland steam exhauster was sticking open at low loads.
The trap and line are designed to return condensed gland steam from the condensate subcooler to
the condenser, but vent gases to the atmosphere. When the trap stuck open, the strong condenser
vacuum pulled outside air in through the vent. Once maintenance personnel replaced the trap,
the condenser performance problems disappeared. This is a classic example of the many
possibilities for condenser air in-leakage.

Case History #3

This history illustrates how the program detected a problem that had never occurred before. (It
can be quite significant in systems with cooling towers, where the circulating water typically
operates at several cycles of concentration.) The 1,000,000 lb/hr condenser from Case History #1 had been in operation for 10 years but had never suffered from scaling.

During one very dry summer, the lake volume decreased dramatically, and lab chemists calculated that the dissolved solids concentration in the lake increased four times over normal values. However, no thought was given to the possibility of scale formation. Throughout the summer the cleanliness factor declined slowly but noticeably from around 80% to 45%. When the unit came off line for an autumn outage, an inspection team found that the waterside of the tubes was completely covered with a layer of calcium carbonate (CaCO3), less than one millimeter in thickness. The deposits were a direct result of the drought. Plant management brought in a firm to mechanically scrape the tubes.

We observed an interesting peculiarity during this event. The condenser that scaled was
equipped with 90-10 and 70-30 copper-nickel tubes. The two other condensers, both tubed with
Admiralty brass, did not show scale buildups, even though operating temperatures were similar.
We surmised that heat transfer in the one condenser was just great enough to push the CaCO3
saturation index over the edge.

Case History #4

The program is very useful for detecting the onset of microbiological fouling, but if quick action is
not taken and microbiological colonies become established, heat transfer degradation may be very
swift. Also, deposit removal may be difficult. One year, when I was monitoring performance of the
1,000,000 lb/hr condenser from Case History #1, the cleanliness factor dropped from around 80% in
the early spring to 40% by early summer. Malfunction of the biocide feed system for a two-week
period proved to be the problem. Unfortunately, by the time the system was repaired the slime layer
produced by the microbial colonies inhibited the effectiveness of the biocide. (Additional details
regarding such issues are available in Reference 3.)

In mid-summer, we shock chlorinated the condenser, but this only restored the cleanliness factor to
around 65%. Visual inspection revealed that although the microorganisms had been killed, much of
the slime layer tenaciously remained. Again, plant management employed an outside contractor to
mechanically scrape the tubes.

Recognizing the data

At my second utility, which I joined approximately 10 years after performing the work above, I
found that a condenser cleanliness program had been incorporated into the distributed control
system (DCS) logic of each of the two units. It provided results that consistently matched my
spreadsheet program. But it became obvious that the plant staff was too busy to keep close track of
the data. After more attention was given to the program’s value, we observed the onset of
microbiological fouling in the condensers (again due to a biocide feed system malfunction) and a
sudden occurrence of excess air in-leakage in one condenser. Unfortunately, I do not recall the
issue that caused the air in-leakage difficulty.

A key takeaway from this example and Case History #4 above is the criticality of biocide feed
system design and diligent maintenance. Once microbes settle on cooling system surfaces, growth
can be extremely rapid.

Conclusion

Part 1 of this two-part series illustrated the significant penalties possible due to condenser upsets.
This part outlines reliable techniques for tracking condenser performance. The program that
colleagues and I developed at CWLP per training provided by GP Strategies proved to be very
valuable on numerous occasions. Even though coal-fired power plants have declined in number,
condensers remain a critical component for heat recovery steam generators at combined cycle and
co-gen facilities.

References

1. B. Buecker, “Condenser Performance Monitoring – Part 1”; Power Engineering, August
   2023.
2. B. Buecker, “Computer Program Predicts Condenser Cleanliness”; Power Engineering,
   June 1992.
3. B. Buecker (Tech. Ed.), “Water Essentials Handbook”; 2023. ChemTreat, Inc., Glen
   Allen, VA. Currently being released in digital format at www.chemtreat.com.
4. B. Buecker, “Condenser Chemistry and Performance Monitoring: A Critical Necessity
   for Reliable Plant Operation”; from the Proceedings of the 60th International Water
   Conference, Pittsburgh, Pennsylvania, October 18-20, 1999.
5. Post, R., Buecker, B., and S. Shulder, “Power Plant Cooling Water Fundamentals”; pre-conference seminar for the 37th Annual Electric Utility Chemistry Workshop, June 6,
   2017, 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 many years 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 is a member of the ACS, AIChE, AIST, ASME, AWT, the Electric Utility Chemistry Workshop planning committee, and he is active with the International Water Conference and Power-Gen International. He may be reached at beakertoo@aol.com.

By Denton Slovacek and Jean Holz, Hach

Introduction from Author

Frequently, author Buecker sees a post on LinkedIn offering a blanket recommendation for feedwater deaeration in high-pressure utility steam generators. The various authors of these commentaries seem to be unaware of the issue of flow-accelerated corrosion (FAC). Given the potentially large distribution of LinkedIn posts, many people may be exposed to critical misinformation in this regard. I wrote about FAC issues in a Power Engineering series last autumn,¹ followed by a recent article on trace metal analysis for feedwater corrosion monitoring.² The present article provides an overview of the details, with additional discussion from Hach on the importance of accurate dissolved oxygen (D.O.) monitoring for feedwater chemistry control.

 A review of important feedwater chemistry issues

The following bullets provide a condensed, mostly chronological review of high-pressure boiler feedwater chemistry evolution from the middle of last century to present times.

·  The common material of construction for condensate/feedwater piping and boiler tubes has always been mild carbon steel. It provides good strength at low cost.

·  Steam generator pressure and temperature were steadily increased from the 1930s into the middle of the century and beyond to improve boiler efficiency. Adoption of regenerative feedwater heating represented a major improvement to recover some energy that would otherwise be lost in the condenser. Copper alloys became a common choice for heater tube material, per copper’s decent strength and excellent heat transfer properties. Feedwater networks with carbon steel piping and copper alloys in the feedwater heaters are known as mixed-metallurgy systems.

Figure 1. Basic schematic of a large coal-fired power unit. Note the multiple feedwater heaters, including the deaerator.³

·  Iron and copper exhibit minimal general corrosion at a mildly alkaline pH, with the optimal value for iron shown below in the well-known Sturla diagram.

Figure 2. Feedwater carbon steel dissolution as a function of pH and temperature. Note: The pH analyses are at 25^o C.⁴

As is evident, general corrosion greatly diminishes as pH rises into a mid- to upper-9 range.   

However, a lower range in the mid-8s is better for the protective oxide that forms on copper.⁵ For mixed metallurgy systems, a common guideline for years was 8.8-9.1 to balance corrosion control between the two metals, but modern guidelines now suggest 9.1-9.3.⁶ Ammonia or in some cases a neutralizing amine (the new term is alkalizing amine) was, and still is, the treatment chemical to establish the proper pH range. Alkalizing amines offer potential benefits and drawbacks, and must be carefully evaluated.⁷

·  As power boilers grew in size and sophistication in the last century, researchers became convinced that even trace amounts of dissolved oxygen during operation would cause serious metal corrosion, which is true for copper alloys in ammoniated water. Virtually all units were equipped with a mechanical deaerator. The common DA effluent guarantee is 7 ppb D.O.

·  Even 7 ppb was considered excessive, so chemical oxygen scavenging became standard. Originally, hydrazine was the oxygen scavenger/reducing agent of choice, but health concerns from handling the chemical led to hydrazine replacement with such compounds as carbohydrazide, diethylhydroxylamine (DEHA) and others.

·  The combination of ammonia or an amine for pH control and oxygen scavenger feed became known as all-volatile treatment reducing (AVT(R)). The reducing chemistry generates the familiar gray-black iron oxide layer magnetite (Fe₃O₄) on carbon steel, and it maintains the reduced copper oxide layer, cuprous oxide (Cu₂O)), on copper alloys.

·  1986, “On December 9 of that year, an elbow in the condensate system ruptured at the Surry Nuclear Power Station [near Rushmere, Virginia.] The failure caused four fatalities and tens of millions of dollars in repair costs and lost revenues.” ⁸ This phenomenon is known as single-phase FAC. (Two-phase FAC, which can affect deaerators, feedwater heater drains, and low-pressure HRSG evaporators is discussed in greater detail in references 8 and 9.) Other single-phase FAC-induced failures over the last three decades have caused additional fatalities and much damage at several power plants. FAC has been observed in many HRSGs around the globe. Gradual metal loss occurs at FAC locations, until the affected area can no longer resist the fluid pressure.

Figure 3a. Photo of tube-wall thinning caused by single-phase FAC.³

Figure 3b. Surface view of single-phase FAC. Note the orange peel texture.³

Figure 3c. Catastrophic failures induced by FAC.⁹

·  In the late 1960s and early 1970s, chemists at supercritical units in Russia and western Europe discovered that with high-purity makeup water (conductivity after cation exchange (CACE) <0.15 mS/cm), direct injection of oxygen induced formation of ferric oxide hydrate (FeOOH) on carbon steel surfaces. (OT cannot be employed in systems with copper alloy feedwater heater tubes.) This oxide layer, a rather deep red in color, is denser and stronger than magnetite. After some evolution, this chemistry regime became known as oxygenated treatment (OT). Current guidelines from the International Association of the Properties of Water and Steam (IAPWS) call for a feedwater D.O. range of 30-150 parts-per-billion.⁶ OT has been adapted at most supercritical units around the world that have all-ferrous feedwater systems. With proper control and monitoring, total feedwater iron concentrations should remain at or below 1 ppb.

·  While OT can be employed for feedwater treatment in drum units, personnel from the Electric Power Research Institute (EPRI) developed all-volatile treatment oxidizing (AVT(O)) for high-pressure drum boiler feedwater. The primary source for oxygen is the small amount (usually) of oxygen that enters the condenser through small air leaks at condenser shell penetrations, turbine/condenser expansion joints, etc. Original AVT(O) guidelines recommended <20 ppb D.O. in the condensate with a 5-10 ppb residual at the economizer. EPRI has since expanded the latter range to 5-30 ppb.¹⁰ The key point is that with OT or AVT(O), all surfaces in the feedwater system and economizer should have the deep red color mentioned above. Patches of gray-black magnetite indicate insufficient protection. In some cases, and most notably for feed forward low-pressure HRSGs, direct oxygen injection (similar to OT applications but lower feed rates) may be needed to protect intermediate- and high-pressure economizer circuits.^{1, 8}

The importance of D.O. monitoring

As the discussion above indicates, each of the feedwater treatment programs has a well-defined D.O. range. Thus, along with analytical measurements for trace metal concentrations and, for mixed-metallurgy systems, oxidation-reduction potential (ORP), continuous on-line D.O. monitoring is of major importance.  Like other technologies, D.O. measurement has evolved and become more precise. For many years, amperometric methods were de rigueur for oxygen analyses. This is an electrochemical technique that can be quite accurate. However, amperometric instruments are labor intensive with frequent calibrations and sensor maintenance, the latter of which often requires replacement of a fragile membrane, especially if flow is discontinued and the membrane dries. These difficulties have only been exacerbated by the now common load cycling of most combined cycle (and even many remaining traditional) power plants. The figure below shows the response time of an amperometric sensor vs the luminescent dissolved oxygen (LDO) technology (in this case an Orbisphere K1100 instrument) that continues to increase in popularity.

Figure 4. Response time of an amperometric sensor vs. LDO. 

This graph outlines the analysis of a sample with D.O. concentrations that are common for OT applications, but “Since 2009, accurate measurement at levels below 1 ppb has now been made possible.” ¹¹ The technology is a practical example of quantum mechanics. In short, the instrument uses shorter-wavelength blue light to excite electrons in the atoms of the measuring device. The electrons release longer-wavelength red light as they return to an unexcited state. Oxygen molecules capture this released energy and lower the amount of red light to the sensor. O₂ also reduces the duration that the electrons exist in the excited state. Measurement of these two parameters allows very accurate calculation of D.O. concentrations, where “A constant alignment of the sensor occurs with the help of [a] red LED fitted in the probe. Before each measurement, this [LED] sends out a light beam of a known radiation characteristic.  Changes in the measurement system are hence detected without any time delay.” ¹²

Figure 5. Basic representation of a luminescent dissolved oxygen measurement system.¹²

Beyond the above-mentioned technical capabilities, the LDO instrument typically only requires one, 30-minute calibration per year. And, the analyzer is not affected if sample flow is discontinued. Startup is immediate. Most combined-cycle plants operate with minimal personnel, who often have limited chemistry training. Yet, proper operation of on-line water/steam chemistry analytical instruments is critical to prevent major upsets that can severely damage equipment and jeopardize employee safety.  Maintenance un-intensive instruments like LDO can be of great benefit in that regard.

Note: The choice of sample tubing for low-range dissolved oxygen analyzers is very important. Outside air can penetrate polyethylene tubing and significantly increase the oxygen concentration of the sample, making readings meaningless. Alternatives include stainless steel and specially-fabricated nylon.

Other applications

Water cooled stator coils for turbine generators are typically of copper-alloy construction. They are normally designed to operate with a either a very low dissolved oxygen concentration (<10 ppb) or in a several parts-per-million (ppm) range. The middle ground between these two ranges can lead to severe corrosion.  D.O. measurements are valuable for monitoring stator chemistry.

Increasingly, and especially in locations where water conservation is of concern, new power plants have air-cooled condensers (ACC) rather than water-cooled condensers. ACCs are enormously larger due to the much lower density of air than water. The extensive piping in an ACC offers many locations for air in-leakage.  Condensate D.O. monitoring can help plant technical personnel to select and adjust feedwater treatment chemistry. Because of high air in-leakage and subsequent carbon steel corrosion, often recommended is a particulate filter on the condensate discharge to remove iron oxide particulates and prevent transport to the steam generator.

Conclusion

The complexity of modern steam-based power generation requires up-to-date information sharing and analytical technology to maintain water/steam chemistry within acceptable parameters. This article hopefully serves as an additional reminder of issues related to flow-accelerated corrosion and that dissolved oxygen monitoring is an important tool for any chemistry program.   

References

1. B. Buecker, “HRSG issues: Re-emphasizing the importance of FAC corrosion control”; four-part series published on the Power Engineering website, September-October 2022, Water Treatment News – Power Engineering (power-eng.com)
2. B. Buecker, “Trace metal analysis for corrosion monitoring in cogeneration condensate systems”; Power Engineering, August 2023.
3. B. Buecker (Tech. Ed.), “Water Essentials Handbook”; 2023. ChemTreat, Inc., Glen Allen, VA.  Currently being released in digital format at www.chemtreat.com.
4. P. Sturla, Proceedings of the Fifth National Feedwater Conference, Prague, Czechoslovakia, 1973.
5. F. U. Leidich, “Chemistry Requirements of the Steam Turbine”; PPCHEM JOURNAL, 2023/04.
6. International Association for the Properties of Water and Steam, Technical Guidance Document: Volatile treatments for the steam-water circuits of fossil and combined cycle/HRSG power plants (2015).
7. Buecker, B., and S. Shulder, “Remember the 3Ds of Alkalizing Amines: Dissociation, Distribution, and Decomposition”; PPCHEM JOURNAL, 2023/01.
8. Guidelines for Control of Flow-Accelerated Corrosion in Fossil and Combined Cycle Power Plants, EPRI Technical Report 3002011569, the Electric Power Research Institute, Palo Alto, California, 2017.  This document is available to the industry as a free report because FAC is such an important safety issue.
9. Shulder, S. and B. Buecker, “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.
10. Conversation with S. Shulder at the 40^th Annual Electric Utility Chemistry Workshop, June 6-8, 2022, Champaign, Illinois.
11. Hach Technical Bulletin LIT2192, “OPTICAL DISSOLVED OXYGEN MEASUREMENT IN POWER PLANTS”, 2012.
12. Hach Application Note: LDO Sensors, “Optical Dissolved Oxygen Measurements in Power and Boiler Applications.”  (DOC043.52.30333)

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.

Combined-cycle power plants are frequently located in or near residential or commercial areas, with many people residing or working near the plant. The high energy required for power production generates much noise, which, without abatement controls, would be intolerable to the public and would present a safety hazard. One potential source of intense noise are the steam vents on heat recovery steam generators (HRSGs). Design, inspection and maintenance of steam vent silencers (SVS) are critical items of a plant’s noise abatement plan.

SVS Design

A heat recovery steam generator has several steam vents including:

• Drum relief (most HRSGs are multi-pressure units)
• Safety relief
• Blowdown tank
• Deaerator
• Startup

These vents are located at or extend to the top of the unit for safety reasons. Even at a high elevation, when a safety valve lifts the noise can be intense. Accordingly, the vents on many HRSG units are equipped with vent silencers to dampen the noise. The basic diagram of a steam vent silencer (SVS) is shown in Figure 1.

Vent silencers must be designed to handle a variety of steam pressures with high velocity inlet flow. The silencers manufactured by SVI Bremco have three major components, an inlet radial diffuser, lower plenum section and an upper absorptive (passive) silencer. Let’s examine how these components work together to dampen noise.

Inlet Radial Diffuser

This is shown as the floating diffuser in Figure 1. The diffusers can be designed in a one-, two-, or three-wall arrangement based on system conditions. Each layer has a specifically-designed perforation pattern that allows the steam to expand through mesh material located between the wall stages and the core of the diffuser. The floating basket design allows for thermal expansion in both the axial and transverse directions.

This stage helps to dissipate the incoming acoustic energy of the stream and splits the single stream into hundreds of smaller streams at each wall stage. This begins the noise attenuation process and decelerates the flow for further attenuation in the upper absorptive silencer.

Lower Plenum Section

The lower plenum section serves as an expansion chamber for radial dispersion of the steam. This arrangement provides for uniform flow to the absorptive silencer upper stage.

Upper Absorptive (Passive) Silencer

Several designs are possible for this final noise silencing stage:

• Concentric baffle
• Tubular array
• Bar array
• Parallel baffle

General illustrations of these designs are shown below.

These baffles provide the final noise attenuation.

Silencer stress and failure mechanisms

As can readily be surmised, silencers, and especially the inlet radial diffuser, are subject to large mechanical and thermal stress. Material degradation over time is the result. SVI Bremco can, to some extent, proactively address these issues by replacing older pressure safety valves (PSV) with modern designs that reduce steam-flow mechanical stress on silencer components. Even so, wear and tear on silencer components is still of primary concern. The photos below illustrate several of the most important issues.

Figure 6. Corrosion from water accumulation at the bottom of the diffuser.

Not only do these corrosion mechanisms affect silencer performance, but failed components can blow out of the silencer, presenting a potential safety hazard.

Of course, thermal stress issues in combined cycle units and HRSGs are usually quite substantial because of the regular load cycling of most units. However, numerous proactive techniques are available to improve performance and longevity of silencers. Primary concepts include:

1. Design and fabrication

a. Materials metallurgical composition. Higher grade alloys than plain carbon steel, although adding expense, may pay for themselves in increased durability. 

b. Materials thickness and well-designed support components. Techniques such as computational fluid dynamics (CFD) can help determine the stresses on components and provide maximized structural design. CFD is also a critical technique in evaluating the aerodynamics of silencers and optimizing designs to reduce high steam velocity and back pressure.

c. Welding techniques. Proper welding techniques and selection of weld filler material are critical throughout steam generating systems including silencers. Welding induces localized stresses that can become rapid failure points if the welding is not planned and performed properly.

2. Excessive Water-Induced Corrosion. To the greatest extent possible, silencers and their discharge vent should be designed to minimize water collection from rain and condensation. Given the cycling nature of combined cycle units, control of water accumulation can be a challenging task.

3. Inspections. Silencers, like some other power plant components, often fit in the “out of sight, out of mind” category; that is until a major failure brings the equipment to everyone’s attention. The next section outlines important items for silencer inspections.

Silencer inspection details

A recommendation at any industrial plant is to develop written protocols for every process and inspection, and to strictly follow the guidelines at all times. However, in this era of minimal staffing at many plants (combined cycle facilities are prime examples) plant personnel may not have the expertise to evaluate all situations. A solution is to work with an industry expert or company to develop inspection guidelines and perhaps assist directly with the inspections. The following lists outline primary inspection parameters for SVI silencers.

Visual Inspection

• Silencer support brackets and welds for degradation, corrosion, and cracking
• Outer shells for corrosion, degradation, cracks, or thinning
• Inlet pipe connection for missing or loose bolts, or corrosion
• Inlet pipe welding for cracks
• Drainage pipe for corrosion
• Exterior paint integrity

Internal Video

• Baffle frame for degradation or cracking
• Baffle support for degradation or cracking
• Baffle perforated sheets for degradation or cracking
• Weld between the diffuser base plate and inlet pipe for cracking
• Weld between the diffuser basket and base plate for cracking
• Diffuser perforated plates for degradation, corrosion, or cracking
• Diffuser cap condition for corrosion

Early detection of component degradation allows repairs before a major failure occurs.

Conclusion

Safety vent silencers are an important component of steam generators. These components operate under high mechanical and thermal stress, and will fail without regular inspection and maintenance. A failure may raise noise to unacceptable levels. Furthermore, pieces of failed components may discharge from the vent to produce a safety hazard. SVI Bremco provides the services and equipment to protect and maintain these vital power plant items.

Contributing editor for this SVI Bremco article is Brad Buecker.

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. His work also included 11 years with two engineering firms, Burns & McDonnell and Kiewit, and he also spent two years as acting water/wastewater supervisor at a chemical plant. Buecker has a B.S. in chemistry from Iowa State University with additional course work in fluid mechanics, energy and materials balances, and advanced inorganic chemistry. 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.

A recent Power Engineering article discussed a technology being developed by the University of
Illinois at its Abbot Power Plant to increase steam surface condenser performance by up to 2%.¹

This may not sound like much, but such improvement can be very valuable. In this first part of
a two-part series, we will examine basic ideas behind the importance of condenser heat transfer,
and in the second part, we will review straightforward methods to monitor condenser performance.
Water-side fouling or scaling, or steam-side excess air in-leakage can severely affect condenser
efficiency and cooling capacity.

A brief review of some fundamental thermodynamic concepts

The word “thermodynamics” conjures up visions of complex mathematics to many people
(including at times this author). Yet, relatively simple formulas from thermodynamics can explain
much about steam generator fundamentals, including condenser heat transfer.

Thermodynamics is primarily built around two laws. They are sometimes jokingly referred to as
(first law), “You can’t get something for nothing,” and (second law), “You can’t break even.”
The first law is based on the conservation of energy. It says that energy used within a system is
neither created nor destroyed but only transferred. The classic energy equation for a
fundamental system (defined as a control volume in textbooks)^2,3 is:

Q – W_s = ṁ₂[V₂²/2 + gz₂ + u₂ + P₂υ₂] – ṁ₁[V₁²/2 + gz₁ + u₁ + P₁υ ₁] + dE_c.v./dt Eq. 1

Where,

Q = Heat input per unit time
W_s = Shaft work, such as that done by a turbine, per unit time
ṁ₂ = Flow out of the system per unit time
ṁ₁ = Flow into the system per unit time
(V₂² – V₁²)/2 = Change in kinetic energy
gz₂ – gz₁ = Change in potential energy
u₂ = Internal energy of the exiting fluid
u₁ = Internal energy of the entering fluid
P₂υ₂ = Flow work of fluid as it exits the system (P = pressure, υ = specific volume)
P₁υ ₁ = Flow work of fluid as it enters the system
dE_c.v./dt = Change in energy within the system per unit time

While this equation may look complicated, it can be better understood through a few definitions and
simplifications. First, in many systems and especially steam generators, potential and kinetic
energies are very minor compared to other energy changes and can be neglected. Second, in a
steady flow process such as a steam generator, the system does not accumulate energy, so dE_c.v./dt is
zero. Removal of these terms leaves the internal energy of the fluid (u) plus its flow work (Pυ)
capabilities. Scientists have combined these two terms into the very useful property known as
enthalpy (h). Enthalpy is a measure of the available energy of the fluid, and enthalpies have been
calculated for a wide range of steam and saturated liquid conditions. These values may be found in
standard steam tables, where saturated water at 0^oC has been designated as having zero enthalpy

Using these simplifications and definitions, the energy equation for steady flow operation reduces
to:

Q – W_s = ṁ(h₂ – h₁) Eq. 2

But this equation represents the ideal scenario with no energy losses, and here is where the second
law steps in. Among other things, the second law describes process direction. A warm cup of
coffee placed on a kitchen table does not become hotter while the room grows colder. Human
beings grow old. A literally infinite number of examples are possible, but these examples convey
the essence of the second law.

The second law has as a foundation the concept of the Carnot cycle, which says that the most
efficient engine that can be constructed operates with a heat input (Q_H) at high temperature (T_H)
and a heat discharge (Q_L) at low temperature (T_L), in which

Q_H/T_H – Q_L/T_L = 0 Eq. 3

This equation represents a theoretically ideal engine. In every process known to humans, some
energy losses occur. These may be due to friction, heat escaping from the system, flow
disturbances or a variety of other factors. Scientists have defined a property known as entropy (s),
which, in its simplest terms, is based on the ratio of heat transfer in a process to the temperature
(Q/T). In every process, the overall entropy change, of a system and its surroundings, increases.

So, in the real world, Equation 3 becomes

Q_H/T_H – Q_L/T_L < 0 Eq. 4

While entropy may seem like a somewhat abstract term, it is of great benefit in determining process efficiency. Like enthalpy, entropy values are included in the steam tables.

Two important points should be noted about the Carnot cycle, and by logical inference, all real-world processes. First is that no process can be made to produce work without some extraction of heat from the process (Q_L) in Equation 3.

Second, the net efficiency (η) of a Carnot engine is defined as:

η = 1 – T_L/T_H Eq. 5

So, in general as inlet temperature goes up and/or exhaust temperature goes down, efficiency increases. Calculations can become rather complicated for complex systems, but the focus of this series is on the steam surface condenser.

Condensers

For simplicities’ sake, consider the very basic system shown below with a turbine that has no frictional, heat or other losses, which means no entropy change (isentropic).

Per the concepts outlined in Equations 3 and 4, QB, the heat input to the boiler and superheater,
represents Q_H; and Q_C, the waste heat extracted by the condenser, represents Q_L.

I have been asked on several occasions throughout the years why turbine exhaust steam must be condensed. Why not transport it directly back to the boiler? Among several answers, a primary reason is that much energy would be required to compress the exhaust steam to return it to boiler pressure. By converting the steam to water, which is essentially an incompressible fluid under normal conditions, the fluid can be returned to the boiler by a feedwater pump with a much lower energy requirement than a vapor compressor.

The benefits of steam condensation can also be illustrated via basic thermodynamics. Let’s return to the isentropic system shown in Figure 1. (In actuality, turbines are typically 80 to 90 percent efficient, but this factor does not need to be included here to show the importance of condenser performance.) Conditions for this first case are:

• Main Steam (Turbine Inlet) Pressure – 2000 psia

• Main Steam Temperature – 1000^oF

• Turbine Outlet Steam Pressure – Atmospheric (14.7 psia)

The steam tables give an enthalpy (h₁) of the turbine inlet steam as 1474.1 Btu per pound of fluid (Btu/lbm). Thermodynamic calculations at isentropic conditions indicate that the exiting enthalpy (h₂) from the turbine is 1018.5 Btu/lbm (steam quality is 86.4%). The first law, steady-state energy equation for work from a turbine is, w_T = ṁ(h₁ – h₂). Accordingly, the unit work available from this ideal turbine is (1474.1 Btu/lbm – 1018.5 Btu/lbm) = 455.6 Btu/lbm. To put this into practical perspective, assume steam flow (ṁ) to be 1,000,000 lb/hr. The overall work is then 455,600,000 Btu/hr = 133.4 megawatts (MW).

Now consider case 2, where the system has a condenser that reduces the turbine exhaust pressure to 1 psia (approximately 2 inches of mercury). Again assuming an ideal turbine, the enthalpy of the turbine exhaust is 871.1 Btu/lbm (steam quality is 77.4%). The turbine output becomes 1474.1 – 871.1 = 603.0 Btu/lbm. At 1,000,000 lb/hr steam flow, the total work is 603,000,000 Btu/hr = 176.6 MW. This represents a 32% increase from the previous example. Obviously, condensation of the steam has an enormous effect upon efficiency. Remember, Equation 5? This is a practical illustration of how the condenser lowers T_L.

One can also look at this example from a physical perspective. The condensate volume is many times lower than that of the turbine exhaust steam. Thus, the condensation process generates a strong vacuum that acts as a driving force to pull steam through the turbine. (The vacuum also pulls in air from outside sources, where excessive air in-leakage can seriously affect heat transfer. We will address this issue in Part 2 of this series.)

Let’s take this concept a step further in case 3. Consider if waterside fouling or scaling (or excess air in-leakage) causes the condenser pressure of the previous example to increase from 1 psia to 2 psia. In line with the calculations shown above, the work output of the turbine drops from 176.6 MW to 166.5 MW. This is a primary reason why proper cooling water chemical treatment and condenser performance monitoring are very important. Another is protection of condenser tubes from such issues as under-deposit and microbiologically-influenced corrosion.⁵ Degraded condenser efficiency and loss of generating capacity can cause a plant much money. Problems during peak operating conditions may be enormously expensive, especially if the unit must be de-rated to keep the turbine from tripping due to high condenser backpressure.

Notes: The term steam quality is often confused with steam purity. Steam quality refers to the percentage of steam in a water steam mixture. For example, a mixture having a steam quality of 0.9 is 90% steam and 10% water droplets. Steam purity, as its name implies, refers to the impurities in a steam supply. For instance, a common guideline for steam purity in high-pressure utility units is <2 parts-per-billion (ppb) of sodium, chloride, and sulfate, and <10 ppb of silica.

In the examples shown above, the steam quality for each case is less than 90%. Such a high moisture content would cause erosion of low-pressure turbine blades. A common recommendation is <10% moisture at the turbine exhaust. For this reason, virtually all utility boilers are equipped with steam re-heaters. Reheating improves efficiency but more importantly adds enough heat to the steam to keep the moisture at the last rows of the low-pressure turbine below the 10% level.

The heat lost in the condenser is primarily the latent heat of vaporization and represents that portion of energy input to the boiler that converts feedwater to steam. The next section examines this issue more closely.

A brief re-comparison of conventional steam generation vs. cogeneration

Returning again to Figure 1, for simple steam generating systems, the general efficiency can be
represented by the following equation:

η = (w_T – w_P)/q_B Eq. 6

Where,

w_T = Work produced by the turbine
w_P = Work needed by the feedwater pump
q_B = Heat input to the boiler

The energy required by the feedwater pump is much less than the work produced by the turbine,
so we can neglect w_P in Equation 6. The boiler heat input (q_B) is equivalent to the difference in
enthalpy of the condensate entering the boiler vs. that of the main steam exiting the boiler.

Assuming isentropic conditions again, for case 2 above, q_B calculates to 1380.1 Btu/lbm. From
the simplified efficiency equation (η = w_T/q_B), the respective net efficiency is 43.7%. As
conventional steam-based power units evolved in the last century, modifications included
incorporation of (or enhancements to) regenerative feedwater heaters, economizers, superheaters
and reheaters, inlet air heaters, and other equipment. But parasitic power requirements for fans,
pumps, air pollution control systems, etc., combined with the large heat loss in the condenser
limited state-of-the-art drum boilers to perhaps mid-30% net efficiency. Even ultra-supercritical
steam units can only achieve net efficiencies of perhaps 45% or slightly above. This is one of
several reasons that combined cycle power units gained popularity. The combination of a
combustion turbine (operating on the Brayton thermodynamic cycle) and one or more heat
recovery steam generators (HRSGs) on advanced Rankine cycles, can now operate at or a bit
above 60% net efficiency. But even then, much energy is still lost in HRSG condenser(s).

In cogeneration and combined heat and power (CHP) applications, where the steam is extracted
from a turbine before reaching the saturation point and is then utilized for process heating, much
of the latent heat is recovered rather than wasted. Such turbines are classified as “non-condensing” or “backpressure” turbines.

Non-condensing turbines operate at a design backpressure, set by the process requirements. They
are common in many heavy industries – petrochemicals, pulp and paper, primary metals, etc., –
and are often used to drive centrifugal equipment such as turbo blowers and compressors. Some
co-generation processes may approach or perhaps even exceed 80% net efficiency, making it
hard to argue against the economics of these processes.⁴

Conclusion

This installment outlined some of the most important fundamentals regarding condenser heat
transfer and the importance of maximizing condenser efficiency. While cogeneration is
becoming increasingly popular at many industrial plants, most dedicated power plants with
steam turbines still have condensing turbines. In the second and final part of this series, we will
examine practical methods for monitoring condenser performance.

References

1. Clarion Energy Content Directors, “Researchers say new coating could boost efficiency
   at coal and gas plants”; Power Engineering, August 2023.
2. Van Wylen, G., and R. Sonntag, “Fundamentals of Classical Thermodynamics, 3
   rd Ed.”; John Wiley & Sons, 1986.
3. Potter, M., and C. Somerton, “Thermodynamics for Engineers”; Schaum’s Outline Series,
   McGraw-Hill, 1993.
4. B. Buecker (Tech. Ed.), “Water Essentials Handbook”; 2023. ChemTreat, Inc., Glen
   Allen, VA. Currently being released in digital format at www.chemtreat.com.
5. B. Buecker, “Condenser Chemistry and Performance Monitoring: A Critical Necessity
   for Reliable Plant Operation”; from the Proceedings of the 60th International Water
   Conference, Pittsburgh, Pennsylvania, October 18-20, 1999.

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.  His work also included 11 years with two engineering firms, Burns & McDonnell and Kiewit, and he also spent two years as acting water/wastewater supervisor at a chemical plant.  Buecker has a B.S. in chemistry from Iowa State University with additional course work in fluid mechanics, energy and materials balances, and advanced inorganic chemistry.  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.

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.

Lower pressure boilers still must be handled with care

Figure 1 provides a basic schematic of a common co-generation configuration.   

Figure 1. Generic flow diagram of a co-generation system. The blowdown heat exchanger and feedwater heater may not be present in some configurations. Note the multiple condensate return lines. Illustration courtesy of ChemTreat, Inc. 

Depending on boiler pressure and design, and the processes served by the boiler steam, makeup treatment may range from sodium softening to reverse osmosis to perhaps even the high-purity arrangements outlined in Part 1. For steam generators under 600 psig pressure, sodium softening, often combined with downstream equipment for alkalinity removal, is common. Figure 2 below is an extract taken from the recent revision of the American Society of Mechanical Engineers (ASME) industrial boiler water guidelines ⁽¹⁾. This extract provides insight on impurity level limits for low- to medium-pressure water tube industrial steam generators. The complete guidelines are available from the ASME at very reasonable cost and should be in the library of any industrial plant with steam generators.

Figure 2. Data extracted from Table 1, Reference 1 – “Suggested Water Chemistry Targets Industrial Water Tube with Superheater”

While power plant chemists are (or should be) familiar with stringent requirements for their high-pressure units (which we will return to in later parts of this series), several guidelines in this extract stand out for lower-pressure boilers. These include:

• Low feedwater hardness, dissolved oxygen, total iron, copper, and total organic carbon (TOC)
• Feedwater pH ranges designed to protect most metals. (Operation near the lower-end of the range is common to project copper alloys.)
• The long-standing philosophy of allowing some bicarbonate alkalinity (HCO₃^–) in the boiler water, but which may influence condensate return chemistry.
• A strong emphasis on steam purity, which is in part a function of boiler water impurity concentrations, thus the increasingly stringent boiler water contaminant guidelines as a function of increasing pressure.

 Let us consider these items in greater detail with help from References 2 and 3.

Hardness Excursions

A very common comment/question that steam generation chemistry experts receive from industrial boiler operators is, “We are suffering repeated boiler tube failures, can you help us find the source.” One of the first items a specialist will typically examine is the sodium softener. Time after time, the consultant will learn that softener upsets have been common but that the plant continues to operate with out-of-spec makeup water going to the boiler. Figures 2 and 3 illustrate the typical result of softener upsets and malfunctions.

Figure 4.  Bulges and blisters in a boiler tube from overheating due to internal deposits.  Photo courtesy of ChemTreat, Inc.

A common malady at many plants, which this author has directly observed on several occasions, is an intense focus by plant personnel on process chemistry and engineering with insufficient attention to steam generators (and cooling systems) until failures begin to cause unit shutdowns that affect production. Water and steam are the lifeblood at many plants, and to neglect these systems puts plant operation and sometimes employee safety at peril.

Apart from hardness capture, even well-operated sodium softeners by themselves remove no other ions from the makeup water. In low-pressure boilers with good blowdown control, most impurities may be manageable. However, issues regarding alkalinity (the alkalinity in raw water is usually in the bicarbonate, HCO₃^–, form) deserve additional discussion.

HCO₃^–, upon reaching the boiler, in large measure converts to CO₂ via the following reactions:

2HCO₃^– + heat → CO₃^2- + CO₂↑­ + H₂O                                             Eq. 1

CO₃^2- + heat → CO₂↑­ + OH^–                                                              Eq. 2

The conversion of CO₂ from the combined reactions may reach 90%. CO₂ flashes off with steam, and when the CO₂ re-dissolves in the condensate can increase the acidity. 

CO₂ + H₂O ⇌ H₂CO₃ ⇌ H⁺ + HCO₃^–                                                 Eq. 3

Long-term carbon-steel corrosion may be the result.

Figure 5.  Carbonic acid grooving of a condensate return line. Photo courtesy of ChemTreat, Inc.

Furthermore, the iron oxide corrosion products will transport to the steam generators and form porous deposits on boiler tubes and other internals. These precipitates can become sites for under-deposit corrosion (UDC) fed by impurities in the boiler water. UDC generally increases in severity with increasing boiler pressure and temperature. At high-pressures, UDC can lead to hydrogen damage, a very insidious corrosion mechanism. 

Some sodium-softened makeup systems also have a forced-draft de-carbonator or split-stream de-alkalizer to remove most of the bicarbonate alkalinity, but even with this equipment the remaining dissolved ions in the raw water still enter the boiler makeup. These impurities reduce the allowable cycles of concentration in the boiler, which leads to increased blowdown. If not properly monitored and controlled, they may cause corrosion or increase the dissolved solids concentration in the boiler steam. Accordingly, becoming more popular is reverse osmosis (RO) for makeup water treatment. Even single-pass RO will remove 99% or greater of the total dissolved ions in the makeup water.

Figure 6. Basic design of a single-pass, two-stage RO. The designation two-stage comes from treatment of the first stage reject in a second stage. (3)

As we discussed in Part 1, addition of a second pass to the RO system with downstream polishing by ion exchange or electrodeionization produces makeup suitable for even the highest-pressure steam generators.

The wild card for co-gen units – Condensate return

Steam generators that solely produce power nearly represent (usually) a closed circuit. A tight system may only have 1% water loss. The most common source of impurity ingress is a leaking tube or tubes in the steam surface condenser. (Units with air-cooled condensers offer other factors to consider.) So, with a good on-line chemistry monitoring system and attentive plant personnel, upsets can usually be quickly corrected. The situation is frequently much different in co-gen units, where condensate could be coming back from any number of chemical heating/reaction processes. Consider the following case history.

A number of years ago, the author and a colleague were invited to an organic chemicals plant that had four 550-psig package boilers with superheaters. The steam provided energy to multiple plant heat exchangers, with recovery of most of the condensate. Each of the boiler superheaters failed, on average, every 1.5–2 years from internal deposition and subsequent overheating of the tubes. Inspection of an extracted superheater tube bundle revealed deposits of approximately ⅛–¼ inches in depth. 

Additional inspection revealed foam issuing from the saturated steam sample line of every boiler, whose cause became quickly apparent. Among the data from water/steam analyses performed by an outside vendor were total organic carbon (TOC) levels of up to 200 mg/L in the condensate return. Contrast that with the <0.5 mg/L feedwater TOC recommendation in Figure 2. No treatment processes or condensate polishing systems were in place to remove these organics upstream of the boilers. Based on the TOC data alone, it was easily understandable why foam was issuing from the steam sample lines, and why the superheaters rapidly accumulated deposits and then failed from overheating.

To protect steam generators from what could be a wide variety of impurities, careful planning is needed to determine, among others, what contaminants and in what concentration may be in the return condensate, can the impurities be economically removed by some form of condensate polishing system, and what streams may need diversion directly to the wastewater treatment plant? The latter issue, of course, influences the size and treatment methods of the wastewater system. Also, condensate dumping to the WWT plant requires increased makeup water production and a larger system in that regard.

Another important issue with co-gen and industrial steam units is feedwater dissolved oxygen control.  In September and October of 2022, Power Engineering published a four-part series by the author on the importance of controlling flow-accelerated corrosion (FAC) in combined cycle heat recovery steam generators (HRSGs). ⁽⁴⁾ Because these high-pressure HRSGs require high-purity makeup (cation conductivity ≤0.2 mS/cm), and typically have no copper alloys in the feedwater system, the recommended chemistry calls for a small amount of dissolved oxygen (D.O.) in the feedwater with no oxygen scavenger (the better term is reducing agent) feed. For units with deaerators, it may be necessary to close the deaerator vents to help maintain a D.O. residual in the economizer circuits. Supplemental oxygen injection may also be required. For those who review this series, note that these guidelines are part of a feedwater chemistry program known as all-volatile treatment oxidizing (AVT(O)).

However, because the condensate return purity in co-gen and industrial steam generators often does not meet high-pressure feedwater guidelines, AVT(O) is usually not acceptable. The feedwater network may also contain heat exchangers with copper-alloy tubes, which further negates AVT(O) as a potential treatment program. Accordingly, a standard requirement is feed of an alkalizing amine to maintain pH within the range shown in Figure 2 plus mechanical deaeration and reducing agent/oxygen scavenger feed to maintain very low feedwater D.O. concentrations. This in turn necessitates accurate monitoring for feedwater iron (and at times copper) corrosion products to fine-tune chemical treatment programs. The author and colleagues have reported on these issues in previous Power Engineering articles. ^{(5, 6)}

Note:  The Electric Power Research Institute (EPRI) has published a comprehensive book on flow-accelerated corrosion that is offered to EPRI members and non-members alike. ⁽⁷⁾     

Conclusion

Co-generation is becoming increasingly popular for power production and process heating at many facilities, in large part because the net efficiency is much higher (and corresponding carbon dioxide emissions are lower) than for traditional power generation. ⁽⁸⁾ However, co-gen chemistry personnel often face additional challenges over those encountered by their power plant counterparts. Careful planning and good vigilance are necessary to minimize corrosion and fouling in these systems.

References

1. 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.
2. Buecker, B., Koom-Dadzie, A., Barbot, E., and F. Murphy, “Makeup Water Treatment and Condensate Return:  Major Influences on Chemistry Control in Co-Gen and Industrial Steam Generators”; presented at the 41^st Annual Electric Utility Chemistry Workshop, June 6-8, 2023, Champaign, Illinois.
3. B. Buecker (Tech. Ed.), “Water Essentials Handbook”; 2023. ChemTreat, Inc., Glen Allen, VA.  Currently being released in digital format at www.chemtreat.com.
4. B. Buecker, “HRSG Steam Generation Issues: Reemphasizing the Importance of FAC Corrosion Control, Parts 1-4”; Power Engineering, September-October 2022.
5. Buecker, B., and F. Murphy, “Breakdown:  Is Flow-Accelerated Corrosion a Concern in Co-Generation Steam Generators”; Power Engineering, October 2020.
6. Buecker, B., Kuruc, K., and L. Johnson, “The Integral Benefits of Iron Monitoring for Steam Generation Chemistry Control”; Power Engineering, January 2019.
7. Guidelines for Control of Flow-Accelerated Corrosion in Fossil and Combined Cycle Plants, 2017. Electric Power Research Institute, Palo Alto, CA, USA, 3002011569. While EPRI typically charges a fee for reports to non-EPRI members, this document is available at no charge due to the importance of safety for FAC understanding and mitigation.
8. B. Buecker, “A Thermodynamic Overview of Co-Generation and Combined Cycle Power vs. Conventional Steam Generation”; Power Engineering, March 2021.

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 also spent two years as acting water/wastewater supervisor at a chemical plant.  Buecker has a B.S. in chemistry from Iowa State University with additional course work in fluid mechanics, energy and materials balances, and advanced inorganic chemistry.  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.

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.