Fundamentals of Industrial Boilers and Steam Generation Systems

Introduction to Industrial Boilers and Steam Generation Systems

Steam systems are a fundamental energy transfer medium, generating electricity, providing energy for industrial heat exchangers, producing mechanical energy for propulsion of naval and merchant vessels, and serving as the energy source for commercial and residential heating.

Steam boilers vary in size, encompassing units designed for small-scale commercial applications to those that are several stories tall and utilized for generating electricity. Operating pressures can vary significantly, ranging from slightly above atmospheric levels to 2,800 psi in large drum boilers, and reaching 4,500 psi or potentially higher in advanced ultra-supercritical units.

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Table of Contents

• Introduction to Industrial Boilers and Steam Generation Systems
• Boiler and Steam System Design
• Specialty Boilers
• Steam Generation Chemistry
• The Evolution of Power Boiler Water Treatment
• Internal Treatment Methods for Industrial Steam Generators
• Boiler Layup
• Returning the Boiler to Service
• Chemical Cleaning of Steam Generators
• Steam Systems and Chemistry
• Steam Chemistry
• Additional Superheater/Reheater Issues
• References
• Appendix 4-1
• Appendix 4-2
• About the Authors

Boiler and Steam System Design

One major differentiating factor with steam generators is whether the steam is utilized solely for process and equipment heating or if it drives turbines for power or mechanical energy production. This has significant impacts on several factors, including the guidelines for makeup water purity, selection of pre-boiler and boiler chemical treatment programs, and steam purity requirements. Figure 4.1 is a basic flow chart of a common industrial steam generating system.

Figure 4.1. A schematic of a fundamental industrial steam generation system. The blowdown heat exchanger and feedwater heater are optional items in many systems.

The key components of this system are:

• Makeup water treatment to remove harmful impurities. Techniques range from simple softening, as shown here, to high-purity demineralized water. The extent of makeup treatment depends largely on system pressure but includes other factors, as will be outlined in this chapter and is discussed in High-Purity Makeup Water.
• Condensate return from various plant processes.
• A mechanical deaerator to remove non-condensable gases, most notably dissolved oxygen, from the makeup water and condensate return. A deaerator also serves as a feedwater heater and includes a storage vessel for reserve feedwater capacity.
• Feedwater pump(s) to boost the pressure above the boiler pressure.
• A steam generator, often including a superheater.
• Steam users that may include turbines, reaction vessels, re-boilers, or many other varieties of heat exchangers.

Steam Generator Design Aspects

Boilers, of course, require heat and water to make steam. Generally, fuel combustion within the furnace serves as the heat source. Combustion occurs separately from the steam generator, and the exhaust heat subsequently generates steam in a separate boiler. A common example is a combined cycle power generator, where a portion of the total power is produced by a gas turbine, similar to a jet engine. The turbine exhaust gas provides energy for heat recovery steam generators (HRSGs).

Three types of heat transfer occur in conventional boilers. Radiant energy is a major heat transfer mechanism within the furnace. Convective heating is the second form of energy transfer, where hot gases, propelled by boiler fans, contact the boiler tubes and additional heat exchangers like superheaters and economizers. Convective heating is the primary energy transfer mechanism for combined cycle HRSGs, although many HRSGs are equipped with duct burners to provide additional heat during peak demand. The third form of heat transfer is conduction, which is the transfer of kinetic energy from molecule to molecule within boiler tubes from the furnace side to the water/steam side.

Boilers are typically categorized by the following criteria:

• Function, e.g., process steam only or power turbine operation/co-generation
• Fuel type
• Waterwall or firetube arrangement
• Drum-type or once-through
• For drum-type boilers, natural or forced circulation
• Pressure
• Size/steaming rate
• Direct fired or powered with waste heat

Common Industrial Boiler Designs

A few common industrial watertube boiler classes are D-Style and O-Style, both with a single steam and single mud drum, and A-Style with single steam and two mud drums. The following illustrations are examples of these watertube boilers.

Figure 4.10 a. D-Style Boiler and b. O-Style Boiler

Figures 4.10 c. A-Style Boiler

The figure below shows a side view of a common industrial boiler, illustrating how the burners are often arranged in these units.

Figure 4.11. Side view of a natural gas-fired industrial boiler. Courtesy of The Babcock & Wilcox Company (Reference 1).

Natural gas is the most common fuel for modern industrial boilers though some older, oil-fired boilers may still be in operation. In chemical plants or refineries, they may also burn waste fuels, often in combination with natural gas.

Power Generation Boilers

Coal-Fired Plant Design

The need for rigorous understanding of coal-fired power plant design and operation continues to diminish, as in many countries these units are being phased out of operation. Two primary factors for coal’s decline are concerns related to carbon dioxide release and its influence on climate change, and the fact that alternative energy supplies such as natural gas and renewable sources have become much more viable economically. Furthermore, environmental issues involving flue gas, ash, and wastewater discharges, and corresponding pollutant control requirements for coal plants, can significantly influence the economics of plant operation. These issues are covered more extensively in Chapter 5. However, coal-fired power plants are still scattered throughout the world, and for plant managers, operators, and technical personnel at those facilities, proper monitoring and control of steam generation chemistry remains a critical issue.

Many early coal-fired boilers were used stoker systems, where coal chunks were placed on a grate and air was blown upward through the grate to facilitate combustion. More modern designs utilize a traveling grate, in which fresh fuel is loaded at the entrance to the furnace and the grate continually moves through the combustion zone. Ash is discharged at the tail end of the traveling grate.

Figure 4.16. General stoker boiler design.

Stoker boilers remain in use, and they may offer the best technology for firing alternate fuels such as municipal waste and biomass.

Most coal units still in operation in the United States, as well as those being constructed globally, utilize pulverized coal technology. In this system, coal is ground into a fine powder and ignited in burners located at the furnace walls or corners. Chapter 5 provides more information about coal properties and chemistry, and those of the ash produced from coal units.

The peak period for large coal plant construction was in the mid-20th century, with drum-type units being the most popular design. Boiler size ranged from around 25 MW to near 1,000 MW. Figure 4.17 illustrates a common design from that era.

Figure 4.17. A common drum-type, coal-fired boiler design from the 1990s. Courtesy of The Babcock & Wilcox Company (Reference 1).

The pronounced vertical nature of the boiler compared to industrial gas-fired boilers is notable. The large furnace provides residence time to properly combust the solid fuel and distribute heat to the waterwall tubes. Note the series of heat exchangers that reside in the gas path downstream of the furnace, including the superheater sections, the reheat superheaters, the economizer, and the air heater.

Boiler dimensions depend on the desired steam production and the type of coal combusted. At the pinnacle of large plant construction, many units were designed for the bituminous coals of Illinois, West Virginia, and other eastern locations. The combination of high heat content and sufficient volatile components that ignite quickly made bituminous coal the best option for many boilers. However, the higher sulfur content of most bituminous coals induced a switch by some power plants to the low-sulfur coal from the Powder River Basin of Wyoming and Montana. PRB coal has a lower heat content than bituminous, requiring a higher fuel feed rate and larger furnace volume for equivalent steam production. Finally, some power plants were placed directly adjacent to large lignite coal deposits in North Dakota and Texas. Lignite typically has the lowest heat content of all commercial coals. The wide variability between coal chemistry and the slagging behavior of the ash produced has a large influence on furnace size. An illustration of comparative size is shown below.

Figure 4.18. Comparative coal-fired power boiler size based on the slagging characteristics of the fuel.

Solid fuel boilers are equipped with sootblowers (usually steam, but sometimes air-driven) to control slag formation on the furnace walls. Additional details on coal properties may be found in Fundamentals of Industrial Boilers and Steam Generation.

Figure 4.19 illustrates the water/steam network of a conventional power unit.

Figure 4.19. A general schematic of a large fossil-fired power unit. The steam extraction lines from the turbine to the feedwater heaters are not shown here but are illustrated in Appendix 4-1.

We will consider the various heat exchangers in this circuit, apart from the boiler, which are all designed to increase net efficiency and provide steam of the required pressure and temperature to the turbine.

Supercritical Steam Generators

Thermodynamic calculations clearly show enhanced steam generator efficiency with increased operating temperature and pressure. Of the coal-fired plants that are still being constructed in some areas of the world, many are designed for supercritical pressures above 3,200 psi. Some advanced ultra-supercritical (USC) units operate at or slightly above 4,500 psi, with reheat steam temperatures near 1,200°F. At these conditions, water and steam exist as a single phase, rendering the drum design invalid. A common supercritical design might have three waterwall “passes” within the furnace, where each pass is connected to the next pass by headers. Supercritical boilers usually have a start-up drum to produce steam when the boiler is being fired from cold conditions. Once the required start-up pressure and temperature are achieved in the unit, isolation valves close to remove the drum from the circuit. Supercritical units cannot tolerate feedwater contamination, as the solids would precipitate on the tube walls when feedwater converts to the single-phase fluid in the boiler. A high-purity makeup water system and a full-flow condensate polisher to capture impurities that might enter from a condenser tube leak or other source are required for all supercritical units.

Waste Heat Steam Generators for Chemical Manufacturing and Refining

Specialized steam generators exist at many plants to recover process heat. Applications include:

• Heat generated as a necessary part of the process, which would otherwise be discarded. Examples include syngas processes such as ammonia, methanol, and hydrogen.
• Heat that is a byproduct of a chemical manufacturing process, such as black liquor boilers in paper manufacturing and ethylene cracking quench boilers that cool the cracked hydrocarbons.
• Heat available from combustion of residues such as waste wood, agricultural waste, garbage, and carbon monoxide (CO) gas generated from crude oil cracking in a refinery or blast furnace gas in a steel mill.

Many processes produce gases with temperatures greater than 1,000°F. The waste heat boilers can operate as firetube or watertube boilers depending on the process.

Table 4-1: Common Temperature Ranges of Waste Heat Gases

Source: Waste Heat Recovery: Technology and Opportunities in US Industry DOE 2008.

A boiler that generates steam from these processes can be exemplified by those primarily used in the ethylene industry, where the primary unit operation is a cracking furnace. The hot, cracked gas must be quickly cooled to minimize additional cracking. Cracker gas cooling takes place in steam generators known as Trans Line Exchangers (TLE or TLX). The hot gas flows through the tube side of the boiler with water on external tube surfaces. The exchangers may be oriented horizontally or vertically with high-pressure steam produced in a steam drum that connects TLEs. Gas temperatures may be at or near 1,500°F, with produced steam pressures up to 1,800 psi.

Figure 4.23. Basic diagram of a TLE.

Careful observation reveals that the configuration to some extent resembles a firetube boiler, with the hot gases flowing through the tubes and steam being generated within the shell.

Not uncommon with non-traditional boiler designs is the potential for localized high-heat spots that can accentuate deposition and corrosion. Consistent high-purity makeup water production and carefully designed boiler water treatment programs are key components for reliable performance.

Steam Generation Chemistry

Makeup, condensate, and boiler water treatment and chemistry requirements vary significantly depending factors like boiler pressure and configuration, heat input method (direct or waste-heat fired), steam function (energy for process heat exchangers or to drive turbines), etc. The following table illustrates the general chemistry requirements for industrial boilers.

Figure 4.24. Sample guidelines for impurity limits in low-pressure industrial boilers.

As this data indicates, the limits become tighter as boiler pressure increases. Appendix 4-2 outlines impurity limits for high-pressure utility units.

Makeup Water Treatment for High-Pressure Steam Generators

For high-pressure utility units, the feedwater must be very pure to minimize corrosion and other potential problems in the steam generator. Impurity concentrations are normally limited to low ppb ranges. Common guidelines for makeup system effluent purity are:

• Specific conductivity: ≤0.1 µS/cm
• Sodium: ≤2 parts-per-billion (ppb)
• Silica: ≤10 ppb

Ion exchange demineralization was commonly used throughout the last century to achieve this purity. Of the various ion exchange combinations possible, the most popular was the following configuration:

Figure 4.26. A common ion exchange configuration for utility units in the last century.

SAC = Strong acid cation exchanger
SBA = Strong base anion exchanger
MB = Mixed bed exchanger

Operational details of this process are discussed in Chapter 3.

This ion exchange configuration, and variations of it, can be very effective at producing high-purity water. However, one critical factor has led to a variant of this technology for makeup treatment in high-pressure and some intermediate-pressure steam generators. Most raw waters have several hundred mg/L of combined cations and anions. When introduced directly to ion exchange systems, the resins may exhaust within a relatively short period of time, sometimes within hours. A typical arrangement has two identical systems. When one exhausts, the other is placed in service, with the SAC and SBA resins in the exhausted system being regenerated with a strong acid and strong base, respectively. However, frequent regenerations can be expensive and require plant personnel to work with dangerous chemicals on a regular basis. Reverse osmosis (RO) technology has become common for bulk removal of dissolved ions. It supplants the SAC and SBA ion exchange vessels shown in Figure 4.27 and can often serve as the stand-alone demineralization process for intermediate-pressure boilers.

In many cases in the power industry, two-pass RO has replaced SAC and SBA exchangers. Final treatment is then performed with portable mixed-bed (MB) technology, wherein a contractor supplies MB “bottles” that have simple connections to the system. When a bottle becomes exhausted, plant personnel switch to a redundant system, and the contractor removes the exhausted bottle for resin regeneration off-site. An alternative polishing method is continuous electrodeionization (CEDI), which utilizes both membrane and ion exchange technology to produce the required high-purity makeup. The resin in these systems is automatically regenerated and can operate for long periods without maintenance.

One form of makeup water production that deserves a brief mention is evaporation. Raw water is evaporated with waste heat and is then condensed as product. Evaporators were common in older, subcritical utility plants and remain in wide use for marine steam generators.

Condensate/Feedwater Chemistry

While several general principles apply to condensate/feedwater treatment and chemistry control for all steam generators, variabilities in system design influence specific programs. Steam generators for power production can be thought of as nearly closed systems with the makeup system easily supplying water and steam from small losses. Impurity ingress is often negligible unless it comes from a leak in a steam surface condenser (or occasionally a makeup system upset). The primary feedwater treatment goals for these systems involve minimizing both general corrosion and FAC of carbon steel condensate/feedwater piping, deaerators, economizers, and, for multi-pressure HRSGs, the low-pressure evaporator. FAC control requires a different strategy regarding feedwater dissolved oxygen (DO) concentrations, as will be outlined.

Industrial facilities that use steam to provide energy to multiple heat exchangers differ greatly. This steam can be recovered as condensate for return to the boiler. Depending on the processes that utilize steam heating, a wide variety of contaminants are possible in the condensate return. These can range from mineral salts to organic compounds to particulates generated from corrosion of condensate return piping.

Oxygen Scavengers/Reducing Agents/Metal Passivators

Even though a well-designed and operated mechanical deaerator can reduce DO concentrations to approximately 7 ppb, in the past, this level was still considered to be excessive. So, at many plants, chemical treatment supplemented mechanical deaeration. These chemicals are oxygen scavengers/reducing agents, many of which are also metal passivators. The most common are:

• Sulfite (catalyzed and uncatalyzed)
• Erythorbate (also referred to as erythorbic acid [EA])
• Hydrazine
• Diethylhydroxylamine (DEHA)
• Carbohydrazide (CZ)
• Methylethylketoxime (MEKO)
• Hydroquinone (HQ)

The list is ordered generally by the amount of product consumed per year, excluding hydrazine, as will be explained. Sodium sulfite is a common compound (Na₂SO₃), as it is suitable for many boilers up to approximately 600 psig in pressure.

2Na₂SO₃ + O2 → 2NaSO₄ | Eq. 4-5

The deaerator storage tank is a common injection point. Sulfite reacts over a wide range of temperatures, though, as with all scavengers, reaction rates increase as temperature increases. Reaction time is important, as a poorly operating deaerator (especially with a small storage section) can allow serious oxygen attack in feedwater piping and economizers because the scavenging reactions are not completed before the feedwater reaches the boiler. Sulfite often includes a cobalt catalyst to speed reactions, though its efficacy is questioned by some researchers.

Although sulfite is often injected into the feedwater system, it is usually measured as a residual in the boiler water. A once-common range was 30–60 ppm in low-pressure boilers, with decreasing levels at higher boiler pressures. As sulfite is non-volatile, it remains in the boiler water and does not escape with steam. Sulfite (and erythorbate, outlined below) should not be utilized in steam generators that provide attemperating water to steam, as this will lead to direct introduction of non-volatile solids to steam systems and, most critically, turbines. Sulfite decomposition is another potential issue. Some literature suggests that sulfite may be employed at pressures up to 900 psi, but at the high temperatures in boilers, sulfite will break down to produce hydrogen sulfide (H₂S) and acid. These products can cause significant damage to boiler metal. A more practical upper limit for sulfite use is 600 psi. Sodium sulfite is often selected as a layup chemical for low-pressure boilers, but the solution should not be allowed to enter superheaters, especially if they are non-drainable.

Erythorbate/erythorbic acid (or the typical feed material, sodium erythorbate, C₆H₇NaO₆) is a non-volatile, FDA-approved alternative to sulfite. The reaction with oxygen is complex, but reaction rates are rapid. Erythorbate is an excellent passivator for low- and medium-pressure boilers. Additional details on metal passivation and the role that these chemicals play in this process are included in Appendix 4-2.

For high-pressure boilers and, most notably, power units, hydrazine (N₂H₄) was once the primary feedwater reducing/passivating agent. The breakdown products of residual hydrazine are ammonia and water, so neither the hydrazine nor its decomposition products introduce non-volatile solids to the feedwater or steam. Thus, the chemical was ideal for treatment ahead of any steam attemperator take-offs. However, hydrazine is now rarely used as it is considered a carcinogen. Alternative chemistries are available and are outlined next.

Carbohydrazide (CH₆N₄O) was developed as a direct replacement for hydrazine. At elevated temperatures in the feedwater system, it converts to hydrazine. Because of the carbon component, carbohydrazide decomposition products include CO₂ along with the ammonia that comes from the breakdown of the intermediate hydrazine product.

DEHA (diethylhdroxylamine, (C₂H₅)₂NOH)) is a volatile scavenger with both neutralizing amine and passivation properties. DEHA and the others listed below serve as alternatives to hydrazine. DEHA is stable in boilers up to 1,200 psi and offers protection to the steam condensate system, feedwater, and boiler drums. Its initial breakdown products are diethylamine and ethylmethylamine, both neutralizing amines. Continued thermal decomposition will yield nitrogen, water, and small amounts of acetic acid.

MEKO (methylethylketomime, C₄H₉NO) is a reducing agent that breaks down into ammonia and organic acid byproducts at 1,250 psi, so is not widely utilized as a hydrazine alternative in the power industry. It is commonly used in industrial, commercial, and institutional steam cycles.

Hydroquinone (C₆H₆O₂) is a powerful oxygen scavenger, but it is toxic and must be handled very carefully. It acts rapidly and is occasionally included with other hydrazine alternatives as a catalyst to speed reactions with oxygen. The primary decomposition product is CO₂.

Oxygen scavengers are no longer recommended due to their influence on FAC for most power steam generating systems., which will be discussed in further detail later in this chapter.

Industrial Condensate Return pH Control

Chemistry control of complex industrial condensate return systems can be a challenge. pH depression from carbon dioxide carryover in the steam is a common issue.

Figure 4.32. Carbonic acid grooving of a condensate return line.

Accordingly, alkalizing amine injection to condensate systems is frequently employed to minimize corrosion in carbon steel piping. The chemical or chemical blend not only protects the condensate but carries through the system. Figure 4.33 lists several of the most common alkalizing amines.

Figure 4.33. List of common alkalizing amines.

The three key aspects of amines can be summarized as the three “Ds.”

• Dissociation: Dissociation is the base strength defined by the dissociation constant k_b. For the ammonia reaction shown in Equation 4-6 earlier, k_b is:

k_b = [NH₄⁺] * [OH^–] / [NH₃]

This equation is similar for alkalizing amines. Higher K_b values (see Table 4-3 below) indicate higher basicity of the products. Basicity is variable with temperature, so this aspect must be considered when designing chemical programs.

• Distribution: Distribution is the ratio of the amine that remains in boiler water and enters steam. Depending on steam generation design, an amine blend can be formulated to establish desired ratios. The distribution ratio varies with temperature.
• Decomposition: Alkalizing amines decompose at high temperatures. The decomposition becomes particularly noticeable in high-pressure applications such as utility boilers. Acetic acid, a small-chain organic acid, is a common decomposition product. There is debate as to whether acetate and formic acid, a smaller organic compound, initiate corrosion on turbine blades. Evidence suggests that such corrosion is not a major concern, but the presence of acetic and formic acids in condensate influences conductivity readings. The decomposition process can establish a problematic cycle, where the breakdown products lower the condensate pH, resulting in increased alkalizing amine feed, which then creates more acid.

Table 4-3 Alkalizing Amine Properties (Reference 21)

Careful evaluation of steam-generating and condensate return system operating and design conditions is necessary when selecting the most appropriate amine or amine blend. One important consideration is the presence of copper alloys in the network. These alloys were a common choice for heat exchanger tubes because of excellent heat transfer properties, but the presence of ammonia and oxygen can cause serious copper corrosion. Other considerations center on the efficacy of some of the compounds. For example, once commonly utilized morpholine has lost favor because the relatively high molecular weight and weaker basicity (vs. the other amines) influences cost-effectiveness.

Amine feed directly to steam headers is usually the best approach from a technical standpoint; however, feed to these locations requires installation and maintenance of high-pressure pumps and injection quills. A common alternative injection point is the boiler feedwater system, but some fresh chemicals, especially those with lower volatilities, are lost in the boiler blowdown.

The combination of ammonia or neutralizing amine feed along with a volatile oxygen scavenger/reducing agent is known as all-volatile treatment reducing (AVT(R)).

Film-Forming Products

It has long been recognized that some compounds can form a protective barrier on metal surfaces and potentially minimize corrosion. Decades ago, filming amine chemistry was attempted in steam generators, with octadecylamine (C₁₈H₃₉N, ODA). serving as a common compound. The amine group attaches to the metal surface, and the hydrophobic organic “tail” extends into the fluid to shield the metal.

Figure 4.38. A general illustration of filming amine attachment to metal surfaces.

However, poor control and a lack of detailed knowledge often led to problems with ODA applications, including the formation of “gelatinous spheroids,” or “gunk balls,” in the common vernacular, which fouled steam generators.

More advanced amine and non-amine film-forming substances (FFS) have been developed. To ensure optimal operation, most of these products require mildly basic conditions, necessitating the use of ammonia or an alkalizing amine feed. However, FFS feed is not tied to pH or CO₂ control; rather, product concentration is based on the residual concentration that best protects metal surfaces. Regular iron monitoring can be very important in evaluating and fine-tuning programs. Some products will cause partial dissolution of iron oxides during initial application, which can sometimes be falsely assumed to be major corrosion.

Internal Boiler Water Treatment

Figure 4.39. Aftermath of a steam locomotive boiler explosion.

As steam boilers became common for industrial power, heating applications, and railroad locomotion in the 1800s, boiler explosions from overheating were common occurrences. Evidence indicated that boilers operating with softened makeup water had fewer failures and required less frequent cleanings. However, it was also apparent that internal boiler water treatment was required, especially as boiler pressures and size increased, particularly in the power industry.

During this evolutionary phase of makeup water improvements, a variety of deposition occurred, depending on the impurities present. These compounds included:

• Calcium carbonate (CaCO₃)
• Calcium sulfate (CaSO₄)
• Magnesium hydroxide [Mg(OH)₂]
• Magnesium silicate (MgSiO₃)
• Magnesium phosphate [Mg₃(PO₄)₂],
• Silica (quartz SiO₂)
• Metal oxides, most notably iron, but also copper and, at times, aluminum
• Sodium salts, including chloride and sulfate
• Carbonaceous compounds

Two of the most common scale-forming reactions are shown below.

Ca²⁺ + 2HCO₃^– → CaCO₃↓ + CO₂ + H₂O | Eq. 4-7

Mg²⁺ (or Ca²⁺) + SiO₃^-2 → CaSiO₃↓ (or MgSiO₃↓) | Eq. 4-8

These reactions persist in steam generators today, particularly when makeup water treatment systems fail or other contamination arises.

Deposition reduces heat transfer, which requires increased fuel firing to produce the necessary steam. More importantly, deposits can cause overheating of tubes and subsequent failure. Figure 4.41 illustrates the effects of scale formation on tube wall temperatures.

The composition of scale influences the insulating properties, as illustrated in the figure below.

Figures 4.40. Influence of deposits on boiler tube wall temperatures.

Figure 4.41. Effects of boiler scale on tube metal temperature.

Elevated tube temperatures can also induce “creep,” where the metal grains exposed to long-term high temperatures begin to slip over time, resulting in irregularities within the metal structure. Metal composition, wall thickness, and other properties are designed for the projected life of the unit. However, overheating caused by scale formation or other issues can accelerate creep, shortening the life of the metal. This problem is compounded by the greater deposition typically observed on the hot side of the tubes. Heavy deposition from a severe upset can induce short-term overheating and rapid failure.

Figure 4.42 Thick lip failure due to long-term overheating and metal creep. Lines of parallel stress marks are visible underneath the failure.

Appendix 4-2 outlines the maximum operating temperatures of common boiler tube steels and provides the composition of several of these materials along with brief descriptions of alloying benefits.

Mechanical factors that can influence creep and other metal properties include:

• Operating the boiler above normal maximum capacity.
• Excessive ramp rates when increasing boiler load.
• Excessive heat input in localized areas. Misaligned burners are a primary cause.
• Unbalanced or restricted flow in some tubes.

The Evolution of Power Boiler Water Treatment

Power boiler chemistry has largely become established, following various modifications. This is because of, in part, the development of reliable high-purity makeup systems, and because steam turbine exhaust is usually the only condensate return source.

The last century saw significant advancements in high-pressure steam generation technology for electricity production, accompanied by the development of methods to produce high-purity makeup water. These included ion exchange demineralization, which has since largely morphed into reverse osmosis filtration in combination with ion exchange polishing. Modern systems can produce very clean makeup to meet the recommended guidelines.

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

Utility steam generators are (usually) nearly closed systems with modest makeup requirements. If contaminant ingress was impossible, internal treatment programs would be relatively simple. Unfortunately, this is not always the case. Notably, there is potential for impurity ingress from a leaking tube or tubes in a water-cooled steam condenser. Cooling water from a lake or river typically contains several hundred ppm of cations and anions, primarily calcium, sodium, magnesium, bicarbonate, chloride, silica, and sulfate, as well as other impurities, including suspended solids. The concentrations multiply if the water “cycles up” in a cooling tower. A condenser tube leak introduces these contaminants directly to the high-purity condensate.

Numerous reactions are possible if the impurities reach the boiler, as previous equations have shown. However, the most problematic issue in many cases is represented as:

MgCl₂ + 2H₂O → Mg(OH)₂↓ + 2HCl | Eq. 4-14

Hydrochloric acid (HCl) is a product of this reaction. While HCl can cause general corrosion in and of itself, the compound will concentrate under deposits where the reaction of the acid with iron generates hydrogen, which, in turn, can lead to hydrogen damage of the tubes. In this mechanism, atomic hydrogen penetrates into the metal wall and then reacts with carbon atoms in the steel to generate methane (CH4):

4H + Fe₃C → 3Fe + CH₄↑ | Eq. 4-15

The formation of the gaseous methane and hydrogen molecules induces cracking in the steel, weakening it. Hydrogen damage is troublesome because it cannot be easily detected. After hydrogen damage has occurred, the plant staff may replace tubes, only to find that additional tubes continue to rupture.

Figure 4.46. Hydrogen damage tube failure. Note the thick-lipped failure. The failure occurred with little metal loss.

The potential for impurity ingress and acid formation, as illustrated in Equation 4-14, requires neutralizing alkalinity in drum boilers to mitigate acid attack and hydrogen damage. As is outlined next, phosphate programs evolved to serve this purpose and to protect against caustic damage. Given the earlier discussion on caustic attack, it is noteworthy that some facilities have implemented an alternative program that replaces phosphate with caustic. This chemistry requires thorough planning.

Internal Treatment Methods for Industrial Steam Generators

Although industrial steam generators typically operate at lower pressures and temperatures than utility boilers, the choice of internal treatment can often be more complex. One influencing factor regards makeup water purity, with a common example coming from those units where sodium softening is the primary makeup treatment method with no additional equipment for alkalinity removal. Low- and medium-pressure boilers often only need the alkalinity present in the feedwater to provide the necessary basicity for internal chemistry. Sometimes, however, additional alkalinity may be required. Two common alkalinity builders are sodium hydroxide and potassium hydroxide (KOH) for boilers <600 psi. These alkalis are often blended into boiler water chemical formulations at concentrations appropriate for the targeted boiler pressures. Potassium hydroxide is sometimes selected because of favorable blending properties. Potassium hydroxide also has a lower freezing point than sodium hydroxide at commercial concentrations.

Additional treatments are often required to prevent scale formation or fouling by impurities. A summary of treatment evolution and influencing factors is outlined below.

• Boiler pressures increased from 10–20 psi in the mid-1800s to 200 psi and greater by the 1920s.
• Patents were issued in 1857 for lignins and tannins as boiler treatments, in 1863 for di-sodium phosphate, and in 1887 for tri-sodium phosphate.
• Phosphates became widely accepted in the 1930s as a replacement for earlier, less science-based programs.
• Phosphate/polymer combinations emerged in the 1950s, with a key component being acrylate dispersants that reduced sludge production.
• Chelants came into use in the 1960s and were often combined with acrylate dispersants such as PAA (polyacrylic acid) or AMPS (2-acrylamido-2-methylpropane sulfonic acid). These were solubilizing programs and could provide very clean boilers, but chelants can induce significant corrosion if not properly applied.
• All-polymer programs have become popular for many applications. They can also cause corrosion without careful control but are less likely to induce corrosion than chelants.

Phosphate and Phosphate-Polymer Programs

The applications of phosphates are even more important for low-pressure boilers, particularly if hardness is present. As noted, phosphate and the alkalinity produced by its reaction with water will, with correct chemistry, react with hardness to generate relatively non-adherent calcium and magnesium precipitates that depart in the boiler blowdown.

The phosphate donors for such programs are typically either compounds of the orthophosphate ion PO₄^-3, generated from tri- and di-sodium phosphate, or a polyphosphate, such as sodium hexametaphosphate or crystalline sodium tripolyphosphate/tetrasodium pyrophosphate. These latter compounds break down to orthophosphate in the boiler.

Modern phosphate programs for industrial boilers often include polymer conditioning agents, first developed in the 1950s and 1960s, to enhance deposit removal through boiler blowdown. The polymers function by altering the crystalline structure and increasing the solubility of compounds that precipitate from phosphate treatment. A key characteristic of certain polymers is their capacity to maintain iron oxide corrosion products in suspension, allowing these particles to be subsequently removed through blowdown.. The transport of condensate return and feedwater corrosion products, primarily iron oxides, to the boiler is a common issue affecting industrial and utility boilers. This results in the deposition of these substances on the internal surfaces of the boiler.

Monitoring and control of phosphate feed and boiler water residual concentrations is simple with the aid of continuous on-line and grab sample instrumentation. Grab sample analyses for filtered and unfiltered phosphate concentrations can assist in troubleshooting chemistry during upset conditions. Analytical methods are also available to monitor the concentrations of polymeric additives.

Feed of a phosphate/polymer formulation upstream of the boiler, perhaps as far back as the deaerator storage tank, will maximize reaction time. However, this arrangement is not acceptable if a feedwater slipstream is utilized for steam attemperation. The injection of non-volatile compounds directly into steam can damage superheaters and turbines.

Advantages and Disadvantages of Phosphate/Polymer Programs

Chelant Programs 

Chelant chemistry for steam generator treatment became somewhat popular in the 1960s, but these programs are rare today, with phosphate and polymer treatment methods more prominent.

The study of chelants can involve a deep dive into inorganic chemistry, but from a practical standpoint, each chelant molecule typically bonds with a metal ion through four or six reactive sites on the chelant. These bonds can be very strong, preventing metal ions from undergoing other reactions such as scale formation in the fluid.

Ethylene-diamine-tetraacetic acid (EDTA) is the most well-known chelant. It has been utilized in numerous applications, notably in the health industry for treating individuals affected by lead poisoning.

Figure 4.48. The chemical structure of EDTA. The molecule bonds with metals through the two nitrogen atoms and four oxygen atoms.

An alternative is nitrilotriacetic acid (NTA), but it is rarely utilized. EDTA stoichiometrically requires 3.8 ppm per 1 ppm of hardness, is stable to 400 psi, and has full FDA approval for these types of applications.

The order of EDTA affinity for cations is: Fe⁺³ → Cu⁺¹/Cu⁺² → Fe⁺² → Ca⁺² → Mg⁺². Thus, the compound can effectively sequester iron that enters the boiler.

Chelants should be injected continuously to the feedwater through a stainless-steel quill, typically downstream of the feedwater pumps to protect pump impellors. Rigorous deaeration of the feedwater is required, as the combination of oxygen and the chelant could cause severe corrosion of feedwater piping, heat exchangers, and other equipment.

Controlling chelant chemistry is more challenging than phosphate or phosphate/polymer chemistry. Concentrations of either EDTA or NTA are typically kept well below 20 ppm in boiler water, usually within the 3–6 ppm range. Higher concentrations could lead to corrosion issues, especially at the rolled tube ends in boiler drums.

Testing procedures for chelant concentration are available, but they have poor reproducibility and are difficult to perform. Mass balance calculations may be needed to accurately determine feed rates. It is also important to maintain proper alkalinity concentrations in the boiler water. ChemTreat personnel can provide guidelines for individual applications.

Boiler Layup

When a unit comes off-line, air ingress may occur at the smallest openings within the water/steam network, particularly as the unit cools and the water volume shrinks. Oxygen can then attack at localized areas and cause serious damage to tubing, piping, and other components. The most problematic issues include:

• Pitting of carbon steel (and copper alloys in those units where they still exist) in the feedwater system, boiler, and superheater/reheater circuits.
• Enhanced corrosion fatigue (CF) and stress corrosion cracking (SCC) in boiler circuits, which are often initiated by pitting.
• Carryover of corrosion products to the boiler, where deposition, particularly of porous iron oxides, can lead to underdeposit corrosion (UDC) during unit operation.
• Pitting of turbine blades in the last low-pressure stages where salt deposition occurs. Pitting here also leads to CF and SCC.

As this list indicates, proper corrosion protection covers the entire steam generating system, not just the boiler.

Protection strategies should take into account site-specific factors, operational requirements, and unit design. A seamless transition from service through shutdown, into the out-of-service or layup period, and through the subsequent unit startup must be factored into the strategy. Proper storage of all major components or systems should be incorporated into a comprehensive layup procedure for the unit. The shutdown and layup periods should be viewed as a continuation of the good water chemistry practices used during operation. The primary purpose of the cycle chemistry is to provide protective oxide surfaces on all components throughout the steam and water circuits in order to minimize corrosion and reduce concentrating and performance-robbing deposits on heat transfer and aerodynamic surfaces.¹⁷

“Operational requirements” is a key phrase from the quote above. During much of the last century, base-load operation of large, coal-fired power plants was the norm. Now, well into the 21st century, with the significant expansion of renewable energy, most fossil-fired plants, whether they are remaining coal units or combined-cycle power generators, operate on a cycling mode, with frequent startups and shutdowns. This aspect plays an important role in selecting layup techniques.

Significant layup factors include:

• Type and duration of outage
  • Short to intermediate outage per load fluctuations
  • Forced outage due to an equipment issue such as a boiler tube failure
  • Scheduled maintenance outage
  • Long-term storage
• Anticipated lead time before startup
• Metallurgy and equipment present in the boiler and condensate/feedwater circuits
• Potential for freezing
• Local atmospheric conditions (i.e., relative humidity) and risk of acid formation on the boiler fireside.
• The ability (and desire) of plant personnel to install a nitrogen blanketing system or utilize dehumidified air for dry layup.

Nitrogen Blanketing

As noted, if the steam system is allowed to cool with water remaining, air can be drawn in that then generates localized and potentially very damaging corrosion. The application of nitrogen at various strategic points in the steam-generating system when the boiler cools to 5 psig pressure will inhibit the in-leakage of air and establish an inert atmosphere. The following table, provides a general overview of the shutdown and wet layup process as developed for conventional steam-generating power plants.¹⁷

Table 4-4 – Wet Layup Procedures for Conventional Units with Nitrogen Blanketing

Adherence to these guidelines will provide protection to the entire steam-generating unit. Although nitrogen is not poisonous (our atmosphere contains 78% nitrogen), entering an enclosed area with limited oxygen content can lead to rapid asphyxiation.

The procedures for nitrogen capping HRSGs are generally similar. However, a notable difference is that most HRSGs lack feedwater heaters, except for a deaerator, allowing for the elimination of that step. Given the frequent shutdowns and startups of many combined-cycle units, nitrogen capping can provide excellent protection of the HRSGs during the short turnaround times. Reference 18 provides details on the nitrogen capping system of a combined-cycle plant in the Midwest. This facility has a nitrogen generator for the production and storage of the gas, which protects the plant’s two HRSGs during wet layups. A circulating system that can move the treated condensate and boiler water throughout the water-side circuits of the HRSGs is also employed at this facility for wet layup protection. The circulating system of any unit should be equipped with at least one sample tap and valve so samples can be collected on a regular basis, such as once per week or month to evaluate conditions. If the treatment chemical concentration has dropped below a pre-selected limit, fresh chemicals should be added.

At many plants, management may balk at the expense of installing nitrogen blanketing systems without realizing the technology could easily pay for itself if in place. Concerns about confined-space safety also sometimes factor into these decisions. For units on AVT(R) feedwater chemistry, some protection remains possible by installing the aforementioned circulating system to move treated water through the boilers and condensate/feedwater systems. This helps minimize stagnant sites that induce localized corrosion. The pH is adjusted above 9.5 with ammonia or alkalizing amine, with supplemental non-volatile reducing agent feed. The situation becomes more complicated for AVT(O) systems without nitrogen blanketing, as the use of a reducing agent during shutdown violates the principle of maintaining the same oxidation state with the unit on or off.

Chemical Treatment for Industrial Steam Generator Layup

As noted above, volatile chemicals such as ammonia or neutralizing amines, and, in certain cases, reducing agents/oxygen scavengers, are required for high-pressure utility and industrial boiler layups, with high pressure in this instance defined as >900 psi. The primary reason for volatile chemical treatment, and this applies both to layup and normal operation, is that most of these high-pressure steam generators employ direct spray attemperation of main and reheat steam temperature control. This is a direct path from the feedwater to steam, and the use of non-volatile compounds could cause severe problems in superheater/reheater circuits and especially turbines.

While nitrogen blanketing is a possibility for wet layup of industrial units, this method is often considered too expensive or laborious. For extended wet layups of low- to intermediate-pressure boilers with no direct steam attemperation, it is common to dose with sodium sulfite (Na₂SO₃) at up to 100 ppm concentration to react with dissolved oxygen. Several possibilities are possible to control pH. The alkalizing amines described earlier in this chapter are one option, but for units without superheaters, another possibility is hydroxide alkalinity to maintain a pH of 11.0. Corrosion data suggests that this is a good pH to minimize carbon steel corrosion at ambient conditions. Because chemical mixing can be challenging once the unit has shut down, chemical injection is typically recommended up to 30 minutes before shutdown. This allows thorough mixing of layup chemicals. Sulfite levels should be initially maintained at 200 ppm due to the demand created by air ingress. Once dissolved oxygen is consumed, maintain 100 ppm of sulfite.

Returning the Boiler to Service

Space limitations prevent a detailed discussion of boiler startup procedures, which can be quite variable depending on whether the unit is being returned from wet or dry layup, but several general guidelines are helpful.

• If returning from a wet layup where chemical dosages were increased to protect the unit, some draining combined with purified makeup replacement may be required to reach operational chemistry limits.
• When a boiler is returned to service from a dry layup, care is needed to minimize potential corrosion from the fill water. Several methods to accomplish this are outlined below.
• When filling a boiler for startup, it is important that the procedures include the addition of the steam generator chemicals so the proper chemistry is in place as the boiler is heated and eventually placed on-line. A key aspect in this regard is establishing a boiler water pH >8.0 before firing. For the many drum boilers using phosphate treatment, this means establishing the proper phosphate concentration in the boiler water.

The first item can be particularly important in units with copper alloys in the condensate/feedwater system. Mostly, these situations are limited to older, conventional units with multiple feedwater heaters. The combination of oxygen and ammonia can be quite corrosive to copper and its alloys.

With regard to filling a boiler from dry layup, some of the efforts in protecting the unit from corrosion can be negated by filling from an ambient-temperature, atmospherically-vented condensate storage tank. Steam sparging, if the equipment is in place, of such tanks before boiler filling will greatly reduce the D.O. concentration. At the combined-cycle plant outlined in Reference 17, a gas-transfer membrane treatment system is in place to reduce the dissolved oxygen concentration of makeup water to 10 ppb. Even with deoxygenated makeup, as the boiler is being filled, oxygen can enter the condensate from air in the boiler. Filling the boiler from the bottom of the unit reduces air exposure.

At startup, it is important to follow the manufacturer’s guidelines regarding heating rates, alternatively known as ramp rates. Excessive firing can damage equipment, including superheaters and reheaters (if present), and turbines. Given the high cycling duty of many boilers now, these issues are accentuated. The result may be shortened asset life and increased forced outages from stress-induced failures.

Steam Systems and Chemistry

While condensate/feedwater and boiler water chemistry control are quite important, perhaps even more critical is the protection of the steam system, particularly if the steam powers turbines. Steam turbines are highly tuned mechanical devices that, if a failure occurs from a mechanical or chemistry-related issue, are extremely expensive to repair or replace, and may hobble a plant for months or longer. Additionally, and this includes industrial steam generators without turbines, carryover of solids into steam can induce deposition and corrosion in superheaters, which may cause failures in these heat exchangers. Steam chemistry control is, therefore, an integral part of any steam generator chemistry program. The next section outlines fundamentals regarding steam turbines followed by a discussion of methods to protect steam systems and turbines from impurity deposition and corrosion.

Condensing and Backpressure Turbines

The figures above illustrate condensing turbines. Whether water-cooled or air-cooled, the condensers convert all the turbine exhaust steam to liquid. Most common are surface condensers in which the steam passes over thousands of relatively small-diameter tubes through which cooling water is circulated. The steam-to-condensate conversion reduces the volume by a factor of well over 10,000. The steam collapse produces a very strong vacuum inside the condenser shell, and this induced vacuum pulls steam through the turbine, maximizing power output. The condensate collects at the bottom of the condenser shell in a compartment known as the hotwell. From there the condensate returns to the boiler.

Figure 4.52. Basic schematic of a two-pass steam surface condenser.

Automatic controls maintain water level within a pre-set range in the hotwell by moving condensate to and from a separate storage tank. Condensate additions or extractions are automatically adjusted based on changes in boiler load.

Although condensate is generally of high purity, it does contain non-condensable gases, most of which enter due to the strong vacuum in the condenser that pulls air in through even the smallest openings. These gases will, in time, grow in concentration and increase the turbine backpressure, thereby lowering efficiency. Accordingly, steam surface condensers are equipped with an air removal compartment to which an external vacuum is applied either by steam-jet ejectors or, more commonly, vacuum pumps. Steam is then exhausted to the atmosphere.

A point to be noted is that at an increasing number of plants, air-cooled condensers (ACCs) are being selected as a water conservation method. Because the density of air is so much lower than water, ACCs must be massive to achieve similar cooling.

Figure 4.53 Air-cooled condenser.

Furthermore, ACCs can only approach the dry-bulb temperature of the ambient air, whereas water-cooled condensers supplied by a cooling tower approach the wet-bulb temperature of the tower. In warm weather especially, efficiency losses are greater with ACC units.

Condensing turbines primarily serve power generation applications, including fossil and nuclear. A difficulty with condensing turbines from an energy efficiency standpoint is that well over half of the heat input to the boiler water is required to convert water to steam, i.e., the latent heat of vaporization. Most of this energy is lost in a standard condenser. However, in cogeneration and combined heat and power (CHP) applications, where the steam is extracted before reaching the saturation point and is utilized for direct heating, much of the latent heat is recovered rather than wasted. Such turbines are classed as “non-condensing” or “backpressure” turbines.

Figure 4.54. Schematic showing the difference between backpressure and condensing turbines

Non-condensing turbines operate at a design backpressure set by the process requirement. They are common in a vast array of heavy industries: petrochemicals, pulp and paper, primary metals, etc., and are often used to drive centrifugal equipment such as turbo blowers, turbo compressors, and so forth.

Cogeneration steam is often produced in specialized boilers, including HRSGs, and is first expanded through a turbine to produce electrical energy. Some ports for steam extraction to plant processes may exist within the turbine. The main turbine exhaust is not condensed but serves other heating applications. For example, consider a turbine with a 600-psi inlet steam supply and an exhaust pressure of 110 psi. The differential pressure (DP) is 490 psi, which produces electrical energy. However, the exhaust steam still contains superheat and may be used to drive other smaller turbines or for direct heating of equipment such as reboilers, process heat exchangers and reaction vessels, deaerators, etc. In this type of turbine, the exhaust must be maintained at a constant pressure to prevent fluctuations that would affect the turbine speed.

Additional Steam Turbine Details

Steam turbines are complex machines that must be designed, manufactured, and maintained to strict tolerances to meet and preserve the design power output and unit availability and reliability. This section briefly outlines additional turbine details for non-experts.

Bearings and Lubrication

Two types of bearings serve to support and stabilize turbine rotors: journal and thrust bearings. A journal bearing consists of two half-cylinders that enclose the shaft and are internally lined with Babbitt, a metal alloy usually consisting of tin, copper, and antimony. Turbine lubricating oil is applied to the journal bearings, and the rotor spins on the thin film of oil produced thereby. Thrust bearings are located axially on the turbine rotors. The decrease in steam pressure as it flows from high to low pressure induces a force on the turbine that must be counteracted, which is the function of these bearings. High-pressure oil is also applied to these bearings for lubrication. Turbine lube oil must be carefully filtered to remove solid particles. Lube oil systems normally include specially designed centrifuges or other coalescing devices to remove water from the oil. Even so, microbes will grow in turbine lube oil tanks that may, at times, necessitate off-line cleaning.

Seals

Within each turbine shell, the disks with the longest blades must have a very tight tolerance to the casing to prevent steam leakage. These shaft seals consist of a series of ridges and grooves around the rotor and the housing, which present a long, tortuous path for any steam leaking through the seal, hence the commonly known name of labyrinth seals. The small amount of steam that does escape is collected and returned to a low-pressure part of the steam circuit, typically the gland steam condenser, which drains to the main condenser.

Turning Gear

Operating on “turning gear” during unit shutdowns is standard for large steam turbines. The slow rotation maintains balance on the rotor and prevents bowing from the heavy weight if the rotation was completely halted. Rotation also allows the temperature to equilibrate throughout the rotor as it cools.

Steam Chemistry

Two important properties of steam are its quality and purity. Sometimes they are incorrectly interchanged in steam discussions. Steam quality refers to the amount of moisture in steam. For example, steam with a quality of 0.95 contains 5% moisture. In boilers with superheaters, the steam entering the turbine or other process equipment has a steam quality of 1.0 plus much superheat energy to keep it dry, although it drops slightly below that level in the last rows of the low-pressure turbine as early condensate forms.

As the name implies, steam purity refers to the level of impurities within the steam. Contaminants can enter steam through several possible pathways:

• Mechanical carryover in the drum
• Vaporous carryover
• Direct introduction from attemperator sprays for steam temperature control
• Decomposition of certain water treatment chemicals, most notably neutralizing amines
• Exfoliation of iron oxides from steam piping

Mechanical Carryover

Mechanical carryover is usually the issue of greatest concern. Steam that accumulates in the boiler drum will contain entrained moisture. To a lesser or greater extent depending on the boiler design, pressure, and other factors, the steam drum will have a combination of internal water-steam separators to remove entrained water droplets and return them to the drum liquid. The figure below shows some of the most common separating devices.

Figure 4.55. Illustration of the most common steam-moisture separators in a boiler drum.

Even with well-designed separators, a small amount of mechanical carryover still occurs, with pressure being a significant influence.

Figure 4.56. General relationship of mechanical carryover as a function of pressure.

This effect, in turn, plays a part in boiler water chemistry guidelines, as boiler water in drum units may cycle up anywhere from 20 to 200 times. Even slight carryover can introduce unacceptable concentrations of contaminants to steam if not monitored and controlled. Some compounds, most notably sodium hydroxide and sodium chloride, can cause serious corrosion of turbine blades and rotors. Most boiler manufacturers design for 0.2% maximum mechanical carryover, a specification that can usually be met, although, as Figure 4.57 indicates, pressure has a direct influence.

System upsets and equipment wear can induce carryover excursions in drum boilers. The list below re-emphasizes the most prominent mechanisms that lead to excessive carryover.

• Damaged steam separation equipment
• High dissolved solids content in the boiler water
• Foaming compounds such as organics in the boiler water
• Poor drum design (e.g., small drum size, inadequate separator design)
• High drum water level/malfunctioning drum level instrumentation & control
• Excessive load ramp rates

Vaporous Carryover

A few compounds will carry over into steam as a vapor, most notably silica. Silica is not corrosive, but silica deposits can impact the aerodynamics of turbines and reduce output. The extent of silica carryover is a direct function of boiler pressure and becomes much more pronounced as pressure increases. For high-pressure utility units, the recommended silica limit from the makeup system is 10 ppb to keep the compound from accumulating in the drum to concentrations that would induce excessive carryover.

Copper compounds will also carry over vaporously to steam, especially at pressures above 2,000 psi. The copper then deposits on high-pressure turbine blades and reduces aerodynamic efficiency. Copper carryover was, at one time, a significant issue with coal-fired units, as many of these had copper-alloy feedwater heater tubes. The retirement of many coal-fired plants and their replacement with combined-cycle generation has, in large measure, reduced this problem.

Attemperator Impurity Introduction

Steam attemperation offers a direct pathway for impurities to enter superheaters and turbines and is yet another reason why units should not be operated with a condenser tube leak. Contaminant ingress can be detected by both steam and feedwater on-line instrumentation.

Decomposition of Some Treatment Chemicals

A previous section discussed the long-time use of ammonia as the primary chemical for feedwater pH control in power units, and the basic equation is shown again for reference.

NH₃ + H₂O ⇌ NH₄⁺ + OH^–

In many lower-pressure non-utility boilers and in the low-pressure evaporator of HRSGs, ammonia will flash off with steam and provide little protection against such phenomena as two-phase FAC. As noted, alkalizing amines are sometimes selected as a supplement or even a direct replacement for ammonia as the feedwater pH conditioning chemical. However, in superheaters, the amines will decompose to small-chain organic acids, most predominantly acetic and formic acids.

Iron Oxide Intrusion

Steam piping and superheater/reheater tubing also develop an iron oxide layer during operation. Excessive temperatures and frequent cycling can generate thick oxide layers that may spall in various locations. The particulates are then carried downstream to the turbine. Even though turbines have inlet screens for protection, fine particulates can still enter the turbine and cause abrasion, particularly in the high-pressure stages.

Sample Transport

While flowing through sample tubing, both liquid and steam samples will tend to release and gather some impurities. In properly designed sampling systems, the impurity exchange will reach an equilibrium state, such that the sample will flow through the tubing virtually unchanged. In general, it takes a month or so for new samples to reach an equilibrium state. It is recommended, whenever possible, to maintain continuous sample flow as opposed to intermittent flow. This has become a more difficult proposition for power units, as many now cycle up and down in load per generation swings from renewable sources.

Moisture-Induced Erosion and Solid Particle Erosion of Turbines

Apart from chemistry-related corrosion, steam turbines may be subject to two mechanical degradation mechanisms: moisture-induced erosion and solid particle erosion (SPE). Either can establish rough, uneven surfaces on turbine blades that influence steam flow and, consequently, reduce turbine efficiency and capacity.

Erosion of intermediate- and low-pressure blades is usually caused by water in the steam. The presence of water droplets, especially in the last stages of a turbine, leads to erosion of the exit row blades. Most major turbine manufacturers impose a limit at or below 12% moisture in the final exhaust steam. Operation below design inlet steam temperature or at low load can cause excess condensation in these last turbine stages, leading to erosion. Steps to mitigate moisture-driven erosion include hardening of the base metal, installation of moisture removal devices to fight liquid droplet impingement, thinning of nozzle trailing edges to promote the formation of smaller and less harmful droplets, and elimination of radial seals to remove water before it can impinge on blades.

Solid particle erosion (SPE) is a condition that affects many turbines. SPE comes from the entrainment in superheated steam of hard, erosive iron oxides that primarily exfoliate from superheater and reheater tubes. The particles cause excessive and premature wear of turbine blades. SPE impacts the performance of turbines in two ways: loss of efficiency and loss of steam flow capacity. Compounded losses through the HP/IP/LP sections can reach 1–2%. At turbine-blade tips, the steam travels at supersonic speeds, where most metal erosion occurs. Replacing a complete set of blades in a large steam turbine may cost millions of dollars. Solid particle erosion is typically most troublesome at startup or during rapid load changes.

A variety of commercially available coating technologies exists to combat SPE and corrosion on steam turbine rotors, diaphragms, buckets, and control valves. Although significant advances have been made in product effectiveness, these technologies are still not mainstream due to mixed results and high costs. Researchers continue to explore methods for mitigating SPE.

Turbine Deposit Cleaning

If the turbine accumulates water-soluble salts, the deposits can often be removed by water washing with condensate or wet steam. This process should be performed off-line, although, at many plants, it is done on-line with the turbine spinning at low speed. Approval from the turbine manufacturer is important before selecting a washing program.

If the turbine becomes fouled with non-water-soluble compounds, most notably silica, water washing rarely restores full turbine capacity. Off-line cleaning is required during a turbine outage. Aluminum oxide or similar soft grit material blasting is a common procedure to remove hard non-water-soluble deposits. Experience indicates that water-soluble deposits may sometimes become embedded in layers of insoluble deposits. When washing is performed, soluble deposits dissolve to leave a loose, friable skeleton of insoluble deposits that may fragment and wash away. Water washing can cause considerable damage to the turbine, and it should be supervised carefully, with strict adherence to the turbine manufacturer’s recommendations.

For some older coal-fired power plants that still have feedwater heaters with copper-alloy tubes, copper deposition on HP turbine blades may remain problematic. Even a small amount of copper can cause a serious loss of turbine capacity. Off-line chemical cleaning is required to remove copper deposits.

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References

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2. Westfall, R. S. (2022, August 23). Isaac Newton. Encyclopedia Britannica. https://www.britannica.com/biography/Isaac-Newton

3. U.S. Nuclear Regulatory Commission December 27, 1988. NUREG-0933: Thinning of Carbon Steel Piping in LWRs.

4. Crawford, M. (2012, June 7). Charles A. Parsons. Retrieved from The American Society of Mechanical Engineers ASME: https://www.asme.org/topics-resources/content/charles-a-parsons

5. Britannica, T. Editors of Encyclopaedia (2022, May 5). Carl Gustaf Patrik de Laval. Encyclopedia Britannica. https://www.britannica.com/biography/Carl-Gustaf-Patrik-de-Laval

6. Van Wylen, G.J., and Sonntag, R.E., Fundamentals of Classical Thermodynamics, Third Edition, John Wiley & Sons, 1986.

7. Perry, Robert H. & Green, Don W. (1984). Perry’s Chemical Engineers’ Handbook (6th ed.). McGraw-Hill. ISBN 0-07-049479-7.

8. ANSI/FCI 87-1, Classification and Operating Principles of Steam Traps.

9. 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.

10. Comprehensive Cycle Chemistry Guidelines for Combined Cycle/Heat Recovery Steam Generators (HRSGs). EPRI, Palo Alto, CA: 2013. 3002001381.

11. Sturla, P., Proc., Fifth National Feedwater Conference, 1973, Prague, Czechoslovakia.

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

13. 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.

14. Buecker, B., and Shulder, S., “Combined Cycle and Co-Generation Water/Steam Chemistry Control”; pre-conference seminar for the 40^th Annual Electric Utility Chemistry Workshop, June 7-9, 2022, Champaign, Illinois.

15. D. Stuart, “Mitigating Flow-Accelerated Corrosion with Film-Forming Chemistry in HRSGs”; Power Engineering, April 2021, www.power-eng.com.

16.International Association for the Properties of Water and Steam, Technical Guidance Document: Phosphate and NaOH treatments for the steam-water circuits of drum boilers of fossil and combined cycle/HRSG power plants (2015). Available from http://www.iapws.org.

17. J. Mathews, “Layup Practices for Fossil Plants”; Power, February 2013.

18.Buecker, B., and Dixon, D., “Combined-Cycle HRSG Shutdown, Layup, and Startup Chemistry Control”; Power Engineering, February 2012.

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Appendix 4-2

For high-pressure steam generators, especially those that drive turbines, diligent chemistry control is necessary to minimize corrosion and fouling of boilers, superheaters/reheaters, and turbines. During the period of conventional coal-fired power construction and generation in the 20th century, many lessons were learned regarding the criticality of water/steam chemistry monitoring. Some lessons were quite dramatic, resulting not only in lost production and equipment repair but sometimes in injuries and fatalities. From these events, continuous on-line chemistry monitoring became common at most plants. Now, for both power and industrial plant steam production, heat recovery steam generators (HRSGs) are a common choice. This appendix provides an overview of typical on-line instrumentation and water/steam chemistry guidelines for combined cycle plants.

Sampling Points and Monitoring Parameters

The samples of primary importance throughout the steam-generating network are:

• Makeup treatment system
• Condensate pump discharge
• Condensate return, when applicable
• Feedwater or economizer inlet
• Boiler water
• Saturated steam
• Main and reheat steam

Condensate Pump Discharge (CPD)

In stand-alone steam generation power units, the primary location for potential contaminant ingress is the condenser, particularly water-cooled condensers where tube leaks allow cooling water to infiltrate the high-purity condensate. A tube leak will introduce a variety of impurities, including hardness ions, chloride and sulfate, and silica, which, when subjected to the harsh environment in the steam generator, can cause serious problems. A condensate polisher will provide a buffer against contaminant ingress, but polishers are often not considered for drum units to reduce capital cost.

Recommended continuous CPD analyses are:

• Cation conductivity (CACE): ≤0.2 µS/cm
• Specific conductivity (SC): Consistent with pH
• Sodium: ≤2 ppb
• Dissolved oxygen: ≤20 ppb
• pH: 9.6–10.0 (This is the pH range for the HRSG design in Figure 1. The range may be a bit lower for other HRSG designs.)

Sodium monitoring is highly effective for detecting condenser tube leaks. With a tight condenser, sodium levels in the condensate are normally very low (<2 ppb), and in many cases, <1 ppb. A rise in sodium provides the earliest indication of a condenser tube leak.

Cation conductivity is now often referred to as conductivity after cation exchange (CACE) to represent the fact that the sample is routed through a cation exchange column to replace all cations, e.g., ammonium, sodium, calcium, etc., with hydrogen ions. This creates a very dilute acid solution of primarily trace amounts of chloride and sulfate ions, whose conductivity is then measured. As with sodium, a rise in CACE indicates impurity in-leakage, although this measurement is also influenced by carbon dioxide ingress, most often from air in-leakage at the condenser. Thus, degasified CACE is becoming increasingly popular , as it utilizes either a re-boiler or nitrogen sparging compartment to remove CO₂. A low CACE value is a requirement for proper control of AVT(O) chemistry, which is outlined in the main text.

Dissolved oxygen (D.O.) analyses are important for monitoring condenser air in-leakage. A sudden increase in dissolved oxygen may indicate a mechanical or structural failure at or near the condenser, which allows excess air to enter the system. However, with modern AVT(O) chemistry, some dissolved oxygen is required for the chemistry to be effective.

With regard to specific conductivity and pH, ammonia (or sometimes an amine or ammonia/amine blend) is the pH-conditioning agent for condensate/feedwater. Direct pH measurement of high-purity water can be tricky, and algorithms have been developed to calculate pH based on conductivity measurements to provide more accurate results. Specific conductivity (SC) in high-purity water is directly correlated to the ammonia concentration, and thus, SC measurements offer better control of ammonia feed than pH.

A parameter not typically monitored continuously, but which can be of major importance is total organic carbon (TOC), as discussed in the next section. For utility steam generators, the recommended TOC limit in the CPD is 100 ppb.

LP Economizer Inlet/Boiler Feed Pump Discharge

The main text discusses AVT(R) and AVT(O) feedwater chemistry programs. The following list outlines the additional recommended feedwater monitoring parameters for AVT(O) chemistry.

• CACE: ≤0.2 µS/cm
• SC: Consistent with pH
• Sodium: ≤2 ppb
• D.O. (range): 5–10 ppb
• pH: 9.6–10.0 (This is the pH range for the HRSG design shown in Figure 1. The range may be a bit lower for other HRSG designs.)
• Iron: ≤2 ppb

Discussion for CACE, SC, pH, and sodium mirrors that for the condensate pump discharge. These measurements, along with dissolved oxygen, are critical for proper AVT(O) chemistry.

Note the inclusion of iron in this list. Iron monitoring provides a direct measurement of FAC (or hopefully lack thereof) and the effectiveness of the feedwater chemistry program. Typically, 90% or greater of iron corrosion products are particulate in nature. Several methods exist to monitor carbon steel corrosion, including:

• Continuous particulate monitoring
• Corrosion product sampling
• Grab sample analysis

Improved grab sampling techniques allow for iron measurements down to 1 ppb with proper sample treatment. This method can provide near real-time data of corrosion rates, although on a snapshot basis.

Figure 4.2.2. Iron digestion unit and spectrophotometer. Photo courtesy of Hach.

About the Authors

Luis Carvalho

Founder and Owner of Industrial Water Treatment Academy (iwtA)

Luis Carvalho is a Chemical Engineer and a Licensed Professional Engineer in Ontario, Canada with over 35 years of broad-based industrial water treatment. His knowledge base includes high-pressure boiler cycle chemistry, including FAC, RO, UF, EDI, and cooling water technology. He is the Founder and Owner of the Industrial Water Treatment Academy (iwtA) and recently held the position of Principal Engineer at ChemTreat for 8 years, where he was responsible for technical leadership in high-pressure boiler treatment across a myriad of industries worldwide. Luis played a significant role in defining new criteria for steam purity for use in turbines and introducing changes to decades-long steam purity guidelines. He won the Paul Cohen Award in 2006 at the International Water Conference. In 2018, Luis was the Chair of the Technical Subcommittee on Air In-leakage in Steam-Water Systems at the International Association of the Properties of Water & Steam (IAPWS).

Tom Nix

Senior Technical Staff Consultant

Tom Nix is a trusted technical expert with decades of industrial water treatment experience. Nix is well-versed in a wide range of applications, including influent clarification, softening, demineralization, reverse osmosis, cooling water treatment, low- and high-pressure boiler treatment, and wastewater treatment. He holds a B.S. in Environmental Biology from the University of Texas at Austin.

Brad Buecker

President of Buecker & Associates, LLC

Brad Buecker is president of Buecker & Associates, LLC, and most recently he served as Senior Technical Publicist with ChemTreat, Inc. He has over four decades of experience in or supporting the power industry, much of it in steam generation chemistry, water treatment, and air quality control. Buecker has a B.S. in Chemistry from Iowa State University. 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 serves on the Editorial Advisory Board of Water Technology and is a member of the ACS, AIChE, AIST, ASME, NACE (now AMPP), and the Electric Utility Chemistry Workshop planning committee.