Boiler water treatment

The Babcock & Wilcox Company

Chapter 42 Water and Steam Chemistry, Deposits and Corrosion

Steam generation and use involve thermal and physical processes of heat transfer, fluid flow, flow, evaporation, and condensation. However, steam and water are not chemically inert physical media. Pure water dissociates to form low concentrations of hydrogen and hydroxide ions, H + and OH −, and both water and steam dissolve some amount of each material that tha t they contact. They also chemically react with materials to form oxides, hydroxides, hydrates, and hydrogen. As temperatures and velocities of water and steam vary vary,, materials may dissolve in some areas and redeposit in others. Such changes are especially prevalent where water evaporates to form steam or steam condenses back to water, but they also occur where the only change is temperature, pressure, or velocity. velocity. In addition, chemical impurities in water and steam can form harmful deposits and facilitate dissolution (corrosion) of boiler structural materials. Therefore, to protect vessels, tubing, and other components used to contain and control these working fluids, water and steam chemistry must be controlled. Water used in boilers must be purified and treated to inhibit scale formation, corrosion, corros ion, and impurity contamination of steam. stea m. Two Two general approaches are used to optimize boiler water chemistry chemist ry.. First, impurities in the water are minimized by purification of makeup water, condensate polishing, deaeration and blowdown. Second, chemicals are added to control pH, electrochemical potential, and oxygen concentration. Chemicals may also be added to otherwise inhibit scale formation and corrosion. Proper water chemistry control improves boiler efficiency and reduces maintenance and component replacement costs. It also improves performance and life of heat exchangers, pumps, turbines, and piping throughout the steam generation, use, and condensation cycle. The primary goals of boiler water chemistry treatment and control are acceptable steam purity and acceptably low corrosion and deposition rates. In addition to customized boiler-specific guidelines and procedures, qualified operators are essential to achieving Steam 41 / Water and Steam Chemistry, Deposits and Corrosion

these goals, and vigilance is required to detect early signs of chemistry upsets. Operators responsible for plant cycle chemistry must understand boiler water chemistry guidelines and how they are derived and customized. They must also understand how water impurities, treatment chemicals, and boiler components interact. Training must therefore be an integral, ongoing part of operations and should include management, control room operators, chemists, and laboratory staff. General water chemistry control limits and guidelines have been developed and issued by various groups of boiler owners and operators (e.g., ( e.g., ASME, 1,2,3 EPRI4 and VGB5 ), water treatment specialists 6,7,8 utilities and industries. Also, manufacturers provide recommended chemistry control limits for each boiler and for other major cycle components. However, optimum water and steam chemistry limits for specific boilers, turbines, and other cycle components depend on equipment design and materials of construction for the combination of equipment employed. Hence, for each boiler system, boiler-specific water chemistry limits and treatment practices must be developed and tailored to changing conditions by competent specialists familiar with the specific boiler and its operating environment.

Chemistry-boiler interactions To understand how water impurities, treatment chemicals and boiler components interact, one must first understand boiler circuitry, and steam generation and separation processes. Boiler feed pumps provide feedwater pressure and flow for the boiler. From the pumps, feedwater often passes through external heaters and then through an economizer where it is further heated before entering the boiler. In a natural circulation drum-type unit, boiling occurs within steel tubes through which a water-steam mixture rises to a steam drum. Devices in the drum separate steam from water, and steam leaves through connections at the top of the drum. This steam is replaced by feedwater which is supplied 42-1


by the feedwater pumps and injected into the drum just above the downcomers through through a feedwater pipe where it mixes with recirculating boiler water which has been separated from steam. By way of downcomers, the water then flows back through the furnace and boiler tubes. Boiler water refers to the concentrated water circulating within the drum and steam generation circuits. Chapters 1 and 5 provide detailed descriptions of steam generation and boiler circulation. Boiler feedwater always contains some dissolved solids, and evaporation of water leaves these dissolved impurities behind to concentrate in the steam generation circuits. If the concentration process is not limited, these solids can cause excessive deposition and corrosion within the boiler and excessive impurity carryover with the steam. To avoid this, some concentrated boiler water is discarded to drain by way of a blowdown line. Because the boiler water is concentrated, a little blowdown eliminates a large amount of the dissolved solids. Since steam carries very little dissolved solids from the boiler, dissolved and suspended solids entering in the feedwater concentrate in the boiler water until the solids removed in the blowdown (boiler water concentration times the blowdown rate lb/h or kg/s) equal the solids carried in with the feedwater (lb/h or kg/s). A small amount of dissolved solids is carried carried from the drum by moisture (water) droplets with the steam. Because moisture separation from steam depends on the difference between their densities, moisture separation is less efficient at high pressures where there is less difference between the densities. Therefore, to attain the same steam purity at a higher pressure, the dissolved solids concentration in boiler water must generally be lower lower.. In a drum boiler, the amount of steam generated is small compared to the amount of water circulating through the boiler. However, circulation is also largely driven by the difference in densities between the two fluids, so as pressure increases the ratio of water flow to steam flow decreases. At 200 psi (1379 kPa), water flow through the boiler must be on the order of 25,000 pph (3 kg/s) to produce just 1000 pounds per hour of steam. Even at 2700 psi (18.6 MPa), 2500 to 4000 40 00 pounds of water circulates to produce 1000 pounds of steam. By contrast, most or all of the water entering a once-through boiler is converted to steam without recirculation. Some boiler operators have asked why boiler water concentrations change so slowly once a source of contamination is eliminated and the continuous blowdown rate is increased. How quickly can excess chemical be purged from a boiler? How much impurity or additive is needed to upset boiler water chemistry? How quickly do chemical additions circulate through the boiler? To answer these questions and explore some other chemistry-boiler interactions, interactions, consider for example a typical 450 MW natural circulation boiler, boiler, generating 3,000,000 pounds of steam per hour. It has a room temperature water capacity of 240,000 pounds and an operating water capacity of 115,000 pounds. The furnace wall area is 33,000 square feet, about 5800 of which are in the maximum heat flux burner zone.

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Impurities purge slowly from the boiler because the boiler volume is large compared to the blowdown rate. For example, at maximum steaming capacity with a blowdown rate 0.3% of the steam flow from the drum, 17 hours may be required to decrease the boiler water concentration of a non-volatile impurity by 50%. Almost two hours are required to effect a 50% reduction in the boiler water concentration even at a blowdown rate of 3%. Without blowdown, dissolved sodium with a fractional carryover factor of 0.1% would have a half life of 52 hours. While long periods of time are generally required to purge impurities, mixing within the boiler is rapid. For the boiler being used as an example, the internal recycle rate is about one boiler volume per minute, and steam is generated at a rate of one boiler volume every 5 minutes. The rate of steam generation is such that replacement feedwater must be essentially free of hardness minerals and oxides that deposit in the boiler. For example, feedwater carrying only 1 ppm of hardness minerals and oxides could deposit up to 25,000 lb (11,340 kg) per year of solids s olids in the boiler, so the boiler might require chemical cleaning as often as 3 or 4 times per year. Also, small chemical additions have a large effect on boiler water chemistry. For example, addition of 0.2 lb (0.09 kg) of sodium hydroxide to the boiler water increases the sodium concentration by 1 ppm, which can significantly affect the boiler water chemistry. Similarly, Similarly, a small amount of chemical che mical hideout can have a large effect on boiler water concentration. Hideout or hideout return of only 0.01 gram per square foot (0.1 g/m 2) in the burner zone can change the boiler water concentration by 1 ppm.

Control of deposition, corrosion, and steam purity The potential for deposition and corrosion is inherent to boilers and increases with boiler operating pressure and temperature. Evaporation of water concentrates boiler water impurities and solid treatment chemicals at the heat transfer surfaces. During the normal nucleate boiling process in boiler tubes, small bubbles form on tube walls and are immediately swept away by the upward flow of water. As steam forms, dissolved solids in the boiler water concentrate along the tube wall. Additionally, the boundary layer of water along the wall is slightly superheated, and many dissolved minerals are less soluble at higher temperatures (common phenomenon referred to as inverse temperature solubility). solubility) . Both of these factors favor deposition of solids left behind by the evolution of steam in high heat flux areas, as illustrated in Fig. 1. These deposits in turn provide a sheltered environment which can further increase chemical concentrations and deposition rates. In a relatively clean boiler tube, concentration of chemicals at the tube surface is limited by the free exchange of fluid between the surface and boiler water flowing through the tube. Wick boiling as illustrated in Fig. 2 generally produces sufficient flow within the deposits to limit the degree of concentration. However, However, as heavy deposits as illus-

Steam 41 / Water and Steam Chemistry, Deposits and Corrosion


Fig. 1 Three years of operation resulted in light deposits because of good water treatment. The upper right figure is the heated side, and the lower right figure is the unheated side.

trated in Fig. 3 accumulate, they restrict flow to the surface. Some boiler water chemicals concentrate on tube walls during periods of high load and then return to the boiler water when the load is reduced. This is termed hideout and hideout return. return . This can greatly complicate efforts to control cont rol boiler water chemistry. Typical boiler deposits are largely hardness precipitates and metal oxides. Hardness, easily precipitated minerals (mainly calcium and magnesium), enters the cycle as impurities in makeup water and in cooling water from condenser leaks. Metal oxides are largely

Fig. 2 Schematic of the wick boiling mechanism ( adapted from Reference 9). 9).


from corrosion of pre-boiler cycle components. Scaling occurs when these minerals and oxides precipitate and adhere to boiler internal surfaces where they impede heat transfer. The result can be overheating of tubes, followed by failure and equipment damage. Deposits also increase circuitry pressure drop, especially detrimental in once-through boilers. Effective feedwater and boiler water purification and chemical treatment minimizes deposition by minimizing feedwater hardness and by minimizing corrosion and associated iron pickup from the conden condensate sate and feedwater systems. systems. Also, Also, phosphate and other water treatment chemicals are used in drum boilers to impede the formation of particularly adherent and low thermal conductivity deposits. Some chemicals become corrosive as they concentrate. Corrosion can occur even in a clean boiler, but the likelihood of substantial corrosion is much greater beneath thick porous deposits that facilitate the concentration process. Concentration at the base of deposits can be more than 1000 times higher than that in the boiler water and the temperature at the base ba se of these deposits can substantially exceed the saturation temperature. Hence, as deposits accumulate, control of boiler water chemistry to avoid the formation of corrosive concentrates becomes increasingly important. Since chemistry upsets do occur, operation of a boiler with excessively thick deposits should be avoided. Because local concentration of boiler water impurities and treatment chemicals is inherent to steam generation, water chemistries must be controlled so the concentrates are not corrosive. On-line corrosion is often caused by concentration of sodium hydroxide, concentration of caustic-forming salts such as sodium carbonate, or concentration of acid-forming salts such as magnesium chloride or sulfate. 10 Effective feedwater and boiler water treatment minimizes corrosion by minimizing ingress of these impurities and by add-

Fig. 3 An example of internal deposits resulting from poor boiler water treatment. These deposits, besides hindering heat transfer, allowed boiler water salts to concentrate, causing corrosion.

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ing treatment chemicals (such as trisodium phosphate) that buffer against acid or caustic ca ustic formation. However, corrosion and excessive precipitation can also be caused by improper use of buffering agents and other treatment chemicals. For example, underfeeding or overfeeding of treatment chemicals, out-of-specification out-of-specification sodiumto-phosphate ratios, or out-of-specification free-chelant concentrations can cause corrosion. Dissolved carbon dioxide and oxygen can also be corrosive and must be eliminated from feedwater. Carbon dioxide from air in-leakage and from decomposition of carbonates and organic compounds tends to acidify feedwater and steam condensate. Oxygen is especially esp ecially corrosi corrosive ve because it facilitates facilitates oxidation oxidation of iron, copper, and other metals to form soluble metal m etal ions. At hig higher her temp temperat eratures ures,, oxyg oxygen en is less solu soluble ble in wate waterr and the rate of chemical chemica l reaction is increased. As boiler feedwater is heated, oxygen is driven out of solution and rapidly corrodes heat transfer surfaces. The combination of oxygen and residual chloride is especially corrosive, as is the combination of oxygen and free chelant. Carryover of impurities from boiler water to steam is also inherent to boiler operation. Though separation separa tion devices remove most water droplets carried by steam, some residual droplets containing small amounts of dissolved solids always carry through with the steam. Also, at higher pressures, there is some vaporous carryover. Excessive impurities can damage superheaters, steam turbines, or downstream process equipment.

Boiler feedwater To maintain boiler integrity and performance and to provide steam of suitable turbine or process purity, purity, boiler feedwater must be purified and chemically conditioned. The amount and nature of feedwater impurities that can be accommodated depend on boiler operating pressure, boiler design, steam purity requirements, type of boiler water internal treatment, blowdown rate, and whether the feedwater is used for steam attemperation. Feedwater chemistry parameters to be controlled include dissolved solids, pH, dissolved oxygen, hardness, suspended solids, total organic carbon (TOC), oil, chlorides, sulfides, alkalinity, alkalinity, and acid or base forming tendencies. At a minimum, boiler feedwater must be softened water for low pressure boilers and demineralized water for high pressure boilers. It must be free of oxygen and essentially free of hardness constituents and suspended solids. Recommended feedwater limits are shown in Table 1. Use of high-purity feedwater minimizes blowdown requirements and minimizes the potential for carryover, deposition, and corrosion problems throughout the steam-water cycle. Operation within these guidelines does not by itself ensure trouble-free operation. Some feedwater contaminants such as calcium, magnesium, organics, and carbonates can be problematic at concentrations below the detection limits of analytical methods commonly used

Table 1 Recommended Feedwater Limits Once-Through Boilers

Drum Boilers

Oxygen

Pressure, psig (MPa)

with AVT*

AVT

Treatment

15 to 300 (0.10 to 2.07)

301 to 600 (2.08 to 4.14)

601 to 900 (4.14 to 6.21)

901 to 1000 (6.21 to 6.90)

1001 to 1500 (6.90 to 10.34)

>1500 (>10.34)

All

All

All

pH, all ferrous heaters

9.3 to 10.0

9.3 to 10.0

9.3 to 10.0

9.3 to 9.6

9.3 to 9.6

9.3 to 9.6

9.3 to 9.6

9.3 to 9.6

8.0 to 8.5

pH, copperbearing heaters

8.8 to 9.2

8.8 to 9.2

8.8 to 9.2

8.8 to 9.2

8.8 to 9.2

8.8 to 9.2

8.8 to 9.2** 8.8 to 9.2

Total hardness, as ppm CaCO3, maximum

0.3

0.2

0.1

0.05

0.003

0.003

0.003

0.003

0.001

0.007

0.007

0.007

0.007

0.007

0.007

0.007

0.007

0.030 to 0.150

Iron, ppm maximum

0.1

0.04

0.02

0.02

0.01

0.01

0.01

0.010

0.005

Copper, ppm maximum

0.05

0.02

0.01

0.01

0.005

0.002

0.005

0.002

0.001

Organic, ppm TOC max.

1.0

1.0

0.5

0.2

0.2

0.2

0.2

0.200

0.200

Cation conductivity, µS/cm max.









0.5

0.2

0.2

0.15

0.15

Oxygen, ppm maximum***

N/A

* All volatile treatment. ** AVT not recommended for copper-bearing copper-bearing cycles and associated low feedwater feedwater pH where the drum pressure is less than than 400 psig. *** By mechanical deaeration before chemical scavenging of residual. Note: ppm = mg/kg

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for industrial boilers. Also, operators must be sensitive to changes in feedwater chemistry and boiler operating conditions, and must adapt accordingly. accordingly.

Makeup water Boiler feedwater is generally a mix of returned steam condensate and fresh makeup water. For utility boilers, most of the steam is usually returned as condensate, and only 1 to 2% makeup is necessary. However,, for some industrial cycles, there is little or However no returned condensate, so as much as 100% makeup may be necessary. Chemistry requirements for makeup water depend on the amount and quality of returned st eam condensate. Where a large portion of the feedwater is uncontaminated condensate, makeup water can generally be of lesser purity so long as the mixture of condensate and makeup meet boiler feedwater requirements. The feedwater concentration for each chemical species is the weighted average of the feedwater and makeup water concentrations: Feedwa Feedwater ter concen concentra tratio tion n + makeup concentration

= ×

(conde (condensa nsate te concen concentra tratio tion n

×

flow flow

makeup flow) / total feedwater flow ow

(1)) (1

The selection of equipment for purification of makeup water must consider the water chemistry requirements, raw water composition, and quantity of makeup required. All natural waters contain dissolved and suspended matter. The type and amount of impurities vary with the source, such as lake, river, well or rain, and with the location of the source. Major dissolved chemical species in source water include sodium, calcium, and magnesium positive positive ions (cations) (cations) as well as bicarbonate, carbonate, sulfate, sulfate , chloride, and silicate negative ions (anions). Organics are also abundant. The first steps in water purification are coagulation and filtration of suspended materials. Natural settling in still water removes relatively coarse suspended solids. Required settling time depends on s pecific gravity, shape and size of particles, and currents within the settling basin. Settling and filtration can be expedited by coagulation (use of chemicals to cause agglomeration of small particles to form larger ones that settle more rapidly). Typical coagulation chemicals are alum and iron sulfate. Following coagulation and settling, water is normally passed through filters. The water is chlorinated to kill micro-organisms, then activated charcoal filters may be used to remove the f inal traces of organics and excess chlorine. Subsequently, various processes may be used to remove dissolved scale-forming constituents (hardness minerals) from the water. For some low pressure boilers, removal of hardness minerals and scale-forming minerals is adequate. For other boilers, the concentration of all of all dissolved solids must be reduced or nearly eliminated. For low pressure boilers, the capital and operating cost for removal must be weighed against costs associated with residual dissolved solids and hardness. These include increased costs for boiler water treatment, more frequent chemical cleaning of the boiler,, and possibly higher rates of boiler repair. Deboiler mineralized water nearly free of all dissolved solids is recommended for higher pressure boilers and espeSteam 41 / Water and Steam Chemistry, Deposits and Corrosion

cially for all boilers operating at pressures greater than 1000 psi (6.9 MPa). Sodium cycle softening , often called sodium zeolite softening , replaces easily precipitated hardness minerals with sodium salts, which remain in solution as water is heated and concentrated. The major hardness ions are calcium and magnesium. However, zeolite ionexchange softening also removes dissolved iron, manganese, and other divalent and trivalent cations. Sodium held by a bed of organic resin is exchanged for calcium and magnesium ions dissolved in the water. The process continues until the sodium ions in the resin are depleted and the resin can no longer absorb calcium and magnesium efficiently. The depleted resin is then regenerated by washing it with a high concentration sodium chloride solution. At the high sodium concentrations of this regeneration solution, the calcium and magnesium are displaced by sodium. Variations V ariations of the process, process, in in combination combination with with chemichemical pre-treatments and post-treatments, can substantially reduce hardness concentrations and can often reduce silica and carbonate concentrations. For higher pressure boilers, evaporative or more complete ion-exchange demineralization of makeup water is recommended. Any of several processes may be used. Evaporative distillation forms a vapor which is recondensed as purified water. Ion exchange demineralization replaces cations (sodium, calcium, and magnesium in solution) with hydrogen ions and replaces anions (bicarbonate, sulfate, chloride, and silicate) with hydroxide ions. For makeup water treatment, two tanks are normally used in series in a cation-anion sequence. The anion resin is usually regenerated with a solution of sodium hydroxide, and the cation resin is regenerated with hydrochloric or sulfuric acid. Reverse osmosis purifies water by forcing it through a semi-permeable membrane or a series of such membranes. It is increasingly used to reduce total dissolved solids (TDS) in steam cycle makeup water. Where complete removal of hardness is necessary, reverse osmosis may be followed by a mixed-bed demineralizer. Mixed-bed demineralization uses simultaneous cation and anion exchange to remove residual impurities left by reverse osmosis, evaporator evaporator,, or twobed ion exchange systems. Mixed-bed demineralizers are also used for polishing (removing impurities from) returned steam condensate. Before regenerating mixed-bed demineralizers, the anion and cation resins must be hydraulically separated. Caustic and acids used for regeneration of demineralizers and other water purification and treatment chemicals present serious safety, health, and environmental concerns. Material Safety Data Sheets must be obtained for each chemical and appropriate precautions for handling and use must be formulated and followed. Dissolved organic contaminants (carbon-based molecules) are problematic in that they are often detrimental to boilers but are not necessarily removed by deionization or evaporative distillation. Organic contamination of feedwater can cause boiler corrosion, furnace wall tube overheating, drum level instability, carryover,, superheater tube carryover t ube failures, and turbine cor42-5


rosion. The degree to which any of these difficulties occurs depends on the concentration and nature of the organic contaminant. Removal of organics may require activated carbon filters or other auxiliary purification equipment.

Returned condensate – condensate polishing For many boilers, a large fraction of the feedwater is returned condensate. Condensate has been purified by prior evaporation, so uncontaminated condensate does not generally require purification. Makeup water can be mixed directly with the condensate t o form boiler feedwater feedwater.. In some cases, however, steam condensate is contaminated by corrosion products or by in-leakage of cooling water. Where returned condensate is contaminated to the extent that it no longer meets feedwater purity requirements, mixed-bed ion-exchange purification systems are commonly used to remove the dissolved impurities and filter out suspended solids. Such demineralization is referred to as condensate polishing . This is essential for satisfactory operation of oncethrough utility boilers, for which feedwater purity requirements are especially stringent. While high pressure drum boilers can operate satisfactorily without condensate polishing, many utilities recognize t he benefits in high pressure plants. These benefits include shorter unit startup time, protection from condenser leakage impurities, and longer intervals between acid cleanings. Condensate polishing is recommended for all boilers operating with all volatile treatment (A (AVT) VT) and is essential for all boilers operating with all volatile treatment and seawater cooled condensers. Provisions for polishing vary from adequate capacity for 100% polishing of all returned condensate to polishing only a portion of the condensate. However, Howev er, all must be adequate to meet feedwater requirements under all anticipated load and operating conditions. Most of the pressure vessels that contain ion exchange resins have under-drain systems and downstream traps or strainers to prevent leakage of ion exchange resins into the cycle water. These resins can form harmful decomposition products if allowed to enter the high temperature portions of the cycle. Unfortunately, the under-drain systems and the traps and strainers are not designed to retain resin fragments that result from resin bead fracture. Also, the resin traps and strainers can fail, resulting in resin bursts. Resin intrusion can be minimized by controlling flow transients, reducing the strainer’s screen size, increasing flow gradually during vessel cut-in, and returning the polisher vessel effluent to the condenser during the first few minutes of cut-in.

injection pumps or alternative feedwater pH control is achieved using a feedback signal from a specific conductivity monitor. Conductivity provides a good measure of ammonium hydroxide concentration, and automated conductivity measurement is more reliable than automated pH measurement. Also, the linear rather than logarithmic relationship of conductivity to ammonia concentration gives better control. Fig. 4 shows the relationship between ammonium concentration, pH, and conductivity of demineralized water. While an equilibrium concentration of ammonium hydroxide remains in the boiler water, much of the ammonium hydroxide added to feedwater volatilizes with the steam. Conversely, the solubility of ammonium hydroxide is such that little ammonia is lost by deaeration. Hence, returned condensate often has a substantial concentration of ammonium hydroxide before further addition. Common alternative alternativ e pH control agents include neutralizing amines, such as cyclohexylamine and morpholine. For high pressure utility boilers with superheaters, the more complex amines are thermally unstable and the decomposition products can be problematic.

Deaeration and chemical oxygen scavengers Oxygen and carbon dioxide enter the cycle with undeaerated makeup water, with cooling water which

Feedwater pH control Boiler feedwater pH is monitored at the condensate pump discharge and at the economizer inlet. When the pH is below the required minimum value, ammonium hydroxide or an alternate alkalizer is added. Chemicals for pH control are added either downstream of the condensate polishers or at the condensate pump discharge for plants without polishers. For high purity demineralized feedwater, ammonium hydroxide

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Fig. 4 Approximate relationship between conductivity and pH for ammonia solutions in demineralized water.



leaks into the condenser, and as air leaking into the vacuum portion of the cycle. For turbine cycles, aeration of the feedwater is initially limited by use of air ejectors to remove air from the condenser. condenser. Utility industry standard practice is to limit total air in-leakage to less than one standard cubic foot of air per minute per 100 MW of generating capacity (approximately 0.027 Nm 3/100 MW), as measured at the condenser air ejectors. Final removal of oxygen and other dissolved gases adequate for boiler boile r feedwater applications is generally accomplished by thermal deaeration of the water ahead of the boiler feed pumps. Thermal deaeration is accomplished by heating water to reduce gas solubility. solubility. Gases are then carried away by a counter flow of steam. The process is typically facilitated by the use of nozzles and trays which disperse water droplets to increase the steamto-water interfacial area. Thermal deaeration can reduce feedwater oxygen concentration to less than 7 parts per billion (ppb). It also essentially eliminates dissolved carbon dioxide, nitrogen, and argon. Chemical agents are generally used to scavenge residual oxygen not removed by thermal the rmal deaeration. Traditional oxygen scavengers have been sodium sulfite for low pressure boilers and hydrazine for high pressure boilers. Sulfite must not be used where the boiler pressure is greater than 900 psig (6.2 MPa). Other oxygen scavengers (erythorbic acid, diethylhydroxylamine, hydroquinone and carbohydrazide) are also used. Hydrazine has been identified as a carcinogen and this has increased the use of alternative scavengers. Scavengers are generally fed at the exit of the condensate polishing system and/or at the boiler feed pump suction.

Attemperation water Water spray attemperation is used to control steam temperature. Attemperation for utility boilers is discussed in the Steam temperature adjustment and control section of Chapter 19, Boilers, 19, Boilers, Superheaters and Reheaters.. The spray water is feedwater Reheaters feedwat er,, polished feedwater,, or steam condensate. As the spray water evapowater rates, all chemicals and contaminants in the water remain in the steam. This addition must not be excessive. It must not form deposits in the attemperator piping, and it must not excessively contaminate the steam. If a superheated steam purity limit is imposed, the steam purity after attemperation must not exceed this limit. To meet this requirement, the weighted average of the spray water total tot al solids concentration and the saturated steam total solids concentration must not exceed the final f inal steam total solids limit. Additionally, spray water attemperation must not increase the steam total solids concentration by more than 0.040 ppm. Independent of other considerations, the spray water solids concentration must never exceed 2.5 ppm. Ideally, the purity of attemperation water should equal the desired purity of the steam.

Drum boilers and internal boiler water Boiler water that recirculates in drum and steam generation circuits has a relatively high concentration of dissolved solids that have been left behind by wa-


ter evaporation. Water chemistry must be carefully controlled to assure that this concentrate does not precipitate solids or cause corrosion within the boiler circuitry.. Boiler water chemistry must also be controlled circuitry cont rolled to prevent excessive carryover of impurities or chemicals with the steam. Customized chemistry limits and treatment practices must be established for each boiler. These limits depend on steam purity requirements, feedwater chemistry, and boiler design. They also depend on boiler owner/operator preferences regarding economic tradeoffs between feedwater purification, blowdown rate, frequency of chemical cleaning, and boiler maintenance and repair. Direct boiler water treatment (usually referred to as internal treatment) treatment ) practices commonly used to control boiler water chemistry include all volatile treatment, coordinated phosphate treatments, high-alkalinity phosphate treatments, and high-alkalinity chelant and polymer treatments. In all cases, when treatment chemicals are mixed, the identity and purity of chemicals must be verified and water of hydration in the weight of chemicals must be taken into account. The specific treatment used must always be developed and managed by competent water chemistry specialists. Feedwater is the primary source of solids that concentrate in boiler water, and feedwater purity defines the practical limit below which the boiler water solids concentration can not be reduced with an acceptable blowdown rate. Additionally, Additionally, hardness and pre-boiler corrosion products carried by the feedwater play ma jor roles in defining the type of boiler water treatment that must be employed. Where substantial hardness is present in feedwater, provision must be made to ensure that the hardness constituents remain in solution in the boiler water or to otherwise minimize the formation of adherent deposits. This is often accomplished by use of chelant, polymer, or high-alkalinity phosphate boiler water treatment. Where substantial hardness is not present, boiler water treatment can be optimized to minimize impurity carryover in the steam and to minimize the potential for boiler tube corrosion. Because boiler water impurities and treatment chemicals carry over in the steam, steam purity requirements play a major role in defining boiler water chemistry limits. Boiler specifications normally include a list of boiler-specific water chemistry limits that t hat must be imposed to attain a specified steam purity. purity. Limits must always be placed on the maximum dissolved solids concentration. Limits must also be placed on impurities and conditions that cause foaming at the steam-water interface in the drum. These include limits on oil and other organic contaminants, suspended solids, and alkalinity. alkali nity. The carryover factor is the ratio of an impurity or chemical species in the stea m to that in the boiler water water..

Blowdown The dissolved solids concentration of boiler water is intermittently or continuously reduced by blowing down some of the boiler water and replacing it with feedwater.. Blowdown rate is generally expressed as a feedwater percent relative to the steam flow rate from the drum.

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Blowdown is accomplished through a pressure letdown valve and flash tank. Heat loss is often minimized by use of a regenerative heat exchanger. The ratio of the concentration of a feedwater impurity in the boiler water to its concentration in the feedwater is the concentration factor, factor , which can be estimated by use of Equation 1. However, a more complex formula must be used where there is substantial carryover. If there is no blowdown, solids concentrate until carryover with the steam is sufficient to carry away all of the solids that enter the boiler with the feedwater. For example, where the feedwater silica concentration is 0.01 ppm and 10% of the silica in the boiler water carries over with the steam, the equilibrium boiler water silica concentration is 0.1 ppm.

Traditional all volatile treatment For all volatile treatment (A (AVT), VT), no solid chemicals are added to the boiler or pre-boiler cycle. Boiler water chemistry control is by boiler feedwater treatment only.. No chemical additions only a dditions are made directly to the drum. Feedwater pH is controlled with ammonia or an alternate amine. Because ammonia carries away preferentially with the steam, the boiler water pH may be slightly lower (0.2 to 0.4 pH units) than the feedwater pH. For traditional all volatile treatment, as opposed to oxygen treatment, hydrazine or a suitable alternate is added to scavenge residual oxygen. Table 1 shows the recommended AVT AVT feedwater control co ntrol limits. Because all volatile treatment adds no solids to the boiler water, solids carryover is generally minimized. All volatile treatment provides provides no chemical control for hardness deposition and provides no buffer against agai nst caustic or acid-forming impurities. Hence, feedwater must contain no hardness minerals from condenser leakage or other sources. It must be high-purity condensate or polished condensate with mixed-bed quality demineralized makeup mak eup water. All volatile v olatile treatment can be, but rarely is, used below 1000 psig (6.9 MPa). Normally it is used only for boilers operating at or above 2000 psig (13.8 MPa) drum pressure. It is not recommended for lower pressure boilers where other options are feasible. While all volatile treatment treatme nt is one of several options for drum boilers, it is the only option for once-through boilers.

viet Union (FSU). It can only be used where there is no copper in the pre-boiler components beyond the condensate polisher, and where feedwater is consistently of the highest purity, e.g., cation conductivity < 0.15 µS/cm at 77F (25C). (2 5C). A low concentration concentration of oxygen is added to the condensate. The target oxygen concentration is 0.050 to 0.150 ppm for once-through boilers and 0.040 ppm for drum boilers. With oxygen treatment, the feedwater pH can be reduced, e.g., down to 8.0 to 8.5. An advantage of oxygen treatment is decreased chemical cleaning frequencies for the boiler.. In addition, when oxygen treatment is used in boiler combination with lower pH, the condensate polisher regeneration frequency is reduced.

Coordinated phosphate treatment Coordinated phosphate-pH treatment, introduced by Whirl and Purcell of the Duquesne Light Company,12 controls boiler water alkalinity with mixtures of disodium and trisodium phosphate added to the drum through a chemical feed pipe. The objective of this treatment is largely to keep the pH of boiler water and underdepos underdeposit it boiler water concentrates within an acceptable range. Fig. 5 indicates the phosphate concentration range that is generally necessary and sufficient for this purpose. Phosphate treatment must not be used where the drum pressure exceeds 2800 psig (19.3 MPa). All volatile treatment is recommended at the higher pressures. In sodium phosphate solutions, an H + + PO4 ≡ → HPO4 = balance buffers the pH (i.e., retards H + ion concentration changes). Solution pH depends on the phosphate concentration and the molar sodium-tophosphate ratio. The relationship between pH, phosphate concentration, and molar sodium-to-phosphate ratio is shown in Fig. 6. Where solutions contain other dissolved salts (e.g., sodium and potassium chloride and sulfate), sodium phosphate phosphat e can still be used to control pH, and the curves of Fig. 6 are still applicable. However,, for such solutions, the sodium-to-phosphate However ratio labels on these curves are only apparent values with reference to pure sodium phosphate solutions. Measured sodium concentrations can not be used in calculating sodium-to-phosphate ratios for control of 100

Oxygen treatment Even in the absence of dissolved oxygen, steel surfaces react with water to form some soluble Fe ++ ions which may deposit in the boiler, superheater, turbine, or other downstream components. However, in the absence of impurities, oxygen can form an especially protective Fe +++ iron oxide that is less soluble than that formed under oxygen-free conditions. To take advantage of this, some copper-free boiler cycles operating with ultra pure feedwater maintain a controlled concentration of oxygen in the feedwater. feedwat er. Most of these are high pressure once-through utility boilers, but this approach is also used successfully in some drum boilers. Oxygen treatment was developed in Europe, largely by Vereinigung Vereinigung der Grosskesselbetreiber Grosskesselb etreiber (VGB), 11 and there is also extensive experience in the former So-

42-8

m p p , e t a 10 h p s o h P

1

1

10

100

1000

10000

Dissolved Solids, ppm

Fig. 5 Phosphate concentrations to control boiler water chemistry (little or no residual hardness in the feedwater). Indicates phosphate range at a given dissolved solids concentration.


The Babcock & Wilcox Company 11

10.5 Na/PO4 = 3.0 + 1ppm NaOH Na/PO4 = 3.0 H p

10 Na/PO4 = 2.8 Na/PO4 = 2.6 Na/PO4 = 2.4 9.5

9

1

10

100

Phosphate, ppm

Fig. 6 Estimated pH of sodium phosphate solutions. Note: pH values can differ by up to 0.2 pH units, depending on the choice of chemical equilibrium constants used, but more often agree within 0.05 0.05 pH units.

boiler water pH because measured sodium concentrations include non-phosphate sodium salts. While dissolved sodium chloride and sulfate do not alter boiler water pH, ammonia does alter the pH. Hence, the presence of ammonia must be taken into account where ammonia concentrations are significant compared to phosphate concentrations. Historically,, the initial goal of Historically o f coordinated pH-phosphate control was to keep the effective molar sodiumto-phosphate to-phosph ate ratio just below 3, to prevent caustic stress corrosion cracking, acid corrosion, and hydrogen damage. This proved to be an effective method for control of deposition and corrosion in many boilers. However, caustic gouging of furnace wall tubes occurred in some boilers using coordinated pH-phosphate control, and laboratory tests indicated that solutions with molar sodium-to-phosphate sodium-to-p hosphate ratios greater than about 2.85 can become caustic when highly concentrated. Subsequently,, many boilers were operated under congruent quently control with a target effective sodium-to-phosphate ratio of less than 2.85, generally about 2.6, and often less than 2.6. Again, this proved to be an effective method of control for many boilers, but some of the boilers operating with low molar sodium-to-phosphate ratios experienced acid phosphate corrosion. Instances of boiler tube corrosion generally occurred in boilers that tha t experienced substantial phosphate hideout and hideout-return when the boiler load changed. Phosphate hideout, hideout-return, and associated corrosion problems are now addressed by equilibrium phosphate phosp hate treatme treatment. nt.13 The concentration of phosphate in the boiler water is kept low enough to avoid hideout and hideout return associated with load changes, thus it is always in equilibrium with the boiler. The effective molar sodium-to-phosphate ratio is kept above 2.8. The free hydroxide, as depicted in Fig. 6, is not to exceed the equivalent of 1 ppm sodium hydroxide. Concern about caustic gouging at the higher ratios is largely reduced by experience with this treat-


ment regime and by experience with caustic boiler water treatment. Tables 2 and 3 show recommended boiler water chemistry limits. Customized limits for a specific boiler depend on the steam purity requirements for the boiler.. Boiler and laboratory boiler laborat ory experience indicate that, under some conditions, phosphate-magnetite interactions can degrade protective oxide scale and corrode the underlying metal. To minimize these interactions, the pH must be greater than that corresponding to the 2.6 sodium-to-phosphate ratio curve of Fig. 6, and preferably greater than that corresponding to the 2.8 curve. The pH must always be above the 2.8 curve when the drum pressure is above 2600 psig (17.9 MPa). The maximum pH is that of trisodium phosphate plus 1 ppm sodium hydroxide. Additionally, Additionally, the boiler water pH is not to be less than 9 nor greater than 10. As discussed below, it may be necessary to reduce the maximum boiler water phosphate concentration to avoid hideout and hideout return, and to avoid associated control and corrosion problems.

Table 2 Boiler Water Limits Pressure Range, psig (MPa)

Maximum TDS, ppm

Maximum Suspended Solids, ppm

Maximum Silica, ppm

15 to 50* (0.10 to 0.35)

1250

15

30

15 to 50** (0.10 to 0.35)

3500

15

150

51 to 325 (0.35 to 2.24)

3500

10

150

326 to 450 (2.25 to 3.10)

3000

8

90

451 to 600 (3.11 to 4.14)

2500

6

40

601 to 750 (4.14 to 5.17)

2000

4

30

751 to 900 (5.18 to 6.21)

1500

2

20

901 to 1000 (6.21 to 6.90)

1250

1

8

* For natural separation with with no diffuser baffles in the steam drum. ** Where the drum includes baffles that separate water droplets from steam. Notes: 1. Operation outside the limits limits defined in this table is not recommended. Within these broad limits, more restrictive limits must be imposed, consistent with the type of boiler water treatment method chosen to control deposition, corrosion, and carryover. For example, the boiler water pH range of 8.5 to 9.0 is only acceptable with all volatile treatment (AVT). 2. ppm = mg/kg

42-9


Table 3 Boiler Water Limits for Coordinated Phosphate Boiler Water Treatment Treatment Pressure, psig (MPa) 15 to 1000 (0.10 to 6.90) Maximum TDS, ppm Maximum sodium, ppm Maximum silica, ppm

Defined by Table 2 or as necessary to attain required steam purity, whichever is less

1001 to 1500 (6.90 to 10.34)

1501 to 2600 (10.35 to 17.93)

100 ppm or as necessary to 50 ppm or as necessar necessary y to attain required steam attain required steam purity, whichever is less purity, whichever is less

2601 to 2800 (17.93 to 19.31) 15 ppm or as necessary to attain required steam purity, whichever is less

Maximum sodium concentration (if any) as necessary to attain required steam purity Defined by Table 2 or as necessary to attain required steam purity, whichever is less

2 ppm or as necessar necessary y to attain required steam purity, whichever is less

0.5 ppm or as necessary to attain required steam purity, whichever is less

0.1 ppm or as necessar necessary y to attain required steam purity, whichever is less.

Phosphate as PO4, ppm

See Fig. 5

"Effective" Na/PO4 molar ratio

2.6 to 3.0

2.6 to 3.0 + 1 ppm NaOH

2.6 to 3.0 + 1 ppm NaOH

2.8 to 3.0 + 1 ppm NaOH

pH

See Figs. 6 and 7

9.4 to 10.5 and as dictated by Figs. 6 and 7



Maximum specific conductivity, µS/cm

Twice the maximum TDS (ppm).

Note: ppm = mg/kg

Phosphate treatment chemicals may hide out during periods of high-load operation, then return to the boiler water when the load and pressure are reduced. This type of hideout makes control of boiler water chemistry difficult and can cause corrosion of furnace wall tubes. This hideout and return phenomena is caused by concentration of phosphate at the tube/ water interface in high heat flux areas. In these areas, phosphates accumulate in the concentrated liquid. The concentrated phosphates then precipitate, or they adsorb on or react with surface deposits and scale.13,14,15 Where excessive deposits are not present, this hideout and hideout return associated with load and pressure changes can be eliminated by decreasing the phosphate concentration in the boiler water or possibly by increasing the sodium-to-phosphate ratio. Where hideout and hideout-return are caused by excessive deposits, the boiler must be chemically cleaned. The amount of phosphate hideout or return accompanying load changes must not be more than 5 ppm. Corrective action is necessary if the amount of phosphate hideout or return accompanying load changes is more than 5 ppm and/or the boiler water pH change is more than 0.2 pH units, or where there are changes in the hideout/hideout-return behavior. This phenomenon must be distinguished from loss los s of phosphate to passive film formation. As the passive oxide film reforms following a chemical cleaning of the boiler,, some phosphate is irreversibly boiler irreversib ly lost from the boiler water. This is minimized if chemical cleaning is followed by a phosphate boilout repassivation of the boiler. Operators should not over-correct for deviations of 4 2 -1 0

pH and phosphate concentration from target values. Corrective action must be taken with an understanding of system response times, the amounts of impurities being neutralized, and the amount of treatment chemicals likely to be required. Where phosphate treatment is used, pH is an especially critical parameter, parameter, so the accuracy of pH measuring devices and temperature corrections must be assured. The boiler water pH must also be corrected to discount the pH effect of residual a mmonia in the boiler water. Fig. 7 shows the estimated effect of ammonia on boiler water pH. The figure indicates the expected pH for solutions with different concentrations of sodium phosphate and 0.2 ppm ammonia. Where these species dominate the solution chemistry, such figures may be used to estimate sodium-to-phosphate molar ratios. With high purity feedwater, the recommended boiler water pH can be attained with appropriate additions of trisodium phosphate. If the recommended boiler water pH can not be maintained within the above limits using trisodium phosphate or a mixture of trisodium and disodium phosphate, this is indicative of alkaline or acid-forming impurities in the feedwater or excessive hideout, and the root cause must be addressed. An exception is low level equilibrium phosphate treatment, where the small amount of trisodium phosphate added to the boiler water may at times be insufficient to achieve the recommended pH. A small amount of sodium hydroxide may be added to attain the recommended pH, but the excess sodium hydroxide must not exceed 1.0 ppm. 13 Even 1.0 ppm sodium Steam 41 / Water and Steam Chemistry, Deposits and Corrosion


used where waterside deposits are excessively t hick, where there is steam blanketing or critical heat flux (see Chapter 5), or where there is seepage (e.g., through rolled seals or cracks). Fig. 8 shows phosphate concentration limits for high-alkalinity phosphate treatment. With some feedwaters (e.g., high-magnesium low-silica), lower phosphate concentrations may be advisable. The required pH is attained by adjusting the sodium hydroxide concentration in the chemical feed solution. The total (M alkalinity in calcium carbonate equivalents) must not exceed 20% of the actual boiler water solids concentration.

10 NH3 PO4 + 1ppm NaOH Na/PO4 = 3.0 9.8

9.6

Na/PO4 = 2.8

H 9.4 p

Na/PO4 = 2.6

9.2

Dispersants, polymers, and chelants Dispersants, (low pressure boilers only)

9

8.8

0

1

2

3

4

5

6

7

Phosphate, ppm

Fig. 7 Estimated pH of sodium phosphate solutions containing 0.2 ppm ammonium hydroxide. Note: pH values can differ by up to 0.2 pH units, depending on the choice of chemical equilibrium constants used, but more often agree within 0.05 pH units.

hydroxide may be excessive for some units, for example oil-fired boilers with especially high heat fluxes in some areas of the furnace. When mixing boiler water treatment chemicals, operators should verify the identity and purity of the chemicals and take into account water of hydration in the weight of the chemicals. Neither phosphoric acid a cid nor monosodium phosphate should be used for routine boiler water treatment. If monosodium phosphate is used to counter an isolated incident of alkali contamination of the boiler water, it must be used with caution, and at reduced load.

High-alkalinity phosphate treatment (low-pressure boilers only) Minimal carryover and deposition are achieved with demineralized makeup water and minimal dissolved solids, but this is not necessarily cost-effective for all low pressure industrial boilers. Where softened water with 0.02 to 0.5 ppm residual hardness (as CaCO3) is used as makeup water for low pressure industrial boilers, high alkalinity or conventional phosphate treatment may be used to control scale formation. This high alkalinity treatment must only be used for boilers operating below 1000 psig (6.9 MPa). The pH and phosphate concentrations are attained by addition of a trisodium phosphate and (if necessary) sodium hydroxide solution through a chemical feed line into the drum. With high-alkalinity phosphate treatment, the boiler water pH is maintained in the range of 10.8 to 11.4. This high pH precipitates hardness constituents that are less adherent than those formed at lower pH. Where high alkalinity boiler water is excessively concentrated by evaporation, the concentrate can become sufficiently caustic to produce caustic gouging or stress corrosion cracking of carbon steel. Hence, high-alkalinity boiler water treatment must not be Steam 41 / Water and Steam Chemistry, Deposits and Corrosion

Where substantial hardness (e.g., 0.1 ppm as CaCO3) is present in feedwater, chelant treatment is often used to ensure that the hardness constituents remain in solution in the boiler water, or polymer treatment is used to keep precipitates in suspension. Blowdown of the dissolved contaminants and colloids is more effective than that of noncolloidal hardness precipitates and metal oxides. While phosphate treatment precipitates residual calcium and magnesium in a less detrimental form than occurs in the absence of phosphate, chelants react with calcium and magnesium to form soluble compounds that remain in solution. Chelants commonly employed include ethylene-diaminetetraacetic acid (EDTA) and nitrilotriacetic acid (NTA). Because of concern about thermal stability, the use of chelants and polymers should be limited to boilers operating at less than 1000 psi (6.9 MPa). To be most effective, effective , chelant must mix with the feedwater and form thermally stable calcium a nd magnesium complexes before there is substantial residence time at high temperature, where free chelant is not thermally stable. Because the combination of free chelant and dissolved oxygen can be corrosive, chelant must be added only after completion of oxygen removal and scavenging. Also, there must be no copper-bearing components in the feedwater train beyond the chelant feed point. Control limits depend on the feedwater chemistry chemistry,, specific treatment chemicals used, and other factors. However, the boiler feedwater pH is generally be70 60 m 50 p p , e t a 40 h p s o h 30 P

Maximum Optimum Minimum

20 10

0 (0 )

20 0 (1379)

400 (2758)

600 (4137)

80 0 (5516)

1000 (6895)

Operating Pressure, psig (kPa)

Fig. 8 Phosphate concentration limits for high-alkalinity phosphate treatment.

42-11


tween 9.0 and 9.6 and hardness as calcium carbonate is less than 0.5 ppm. The boiler water pH is generally maintained in the range of 10.0 to 11.4. The boiler water pH is attained by a combination of alkalinity derived from the chelant feed (e.g., as Na 4 EDTA), evolution of CO 2 from softened feedwater feedwater,, and addition of sodium hydroxide. Polymeric dispersants are generally used to impede formation of scale by residual solids.

Once-through universal pressure boilers In a subcritical once-through boiler, there is no steam drum. As water passes through boiler tubing, it evaporates entirely into steam. Because steam does not cool the tube as effectively as water, the tube temperature increases beyond this dry-out location. Subcritical once-through boilers are designed so this transition occurs in a lower heat flux region of the boiler where the temperature increase is not sufficient to cause a problem. However, because the water evaporates completely, it must be of exceptional purity to avoid corrosion and rapid deposition, and carryover of dissolved solids. Similarly stringent water purity requirements must be imposed for supercritical boilers. While there is no distinction between water and steam in a supercritical boiler, the physical and chemical properties of the fluid change as it is heated, and there is a temperature about which dissolved solids precipitate much as they do in the dry-out zone of a subcritical oncethrough boiler. This is termed the pseudo transition zone.. (See Chapter 5.) zone Satisfactory operation of a once-through boiler and associated turbine requires that the total feedwater solids be less than 0.030 ppm total dissolved solids with cation conductivity less than 0.15 µS/cm. Table 1 lists recommended limits for other feedwater parameters. Feedwater purification must include condensate polishing, and water treatment chemicals must all be volatile. Ammonia is typically added to control pH. For traditional all volatile treatment, hydrazine or a suitable volatile substitute is used for oxygen scavenging. Iron pickup from pre-boiler components can be minimized by maintaining a feedwater pH of 9.3 to 9.6. Prior to plant startup, feedwater must be circulate circulated d through the condensate polishing system to remove dissolved and suspended solids. Temperatures should not exceed 550F (288C) at the convection pass outlet until unt il the iron levels are less than 0.1 ppm at the economizer inlet. Utility once-through boilers with copper-free cycle metallurgy commonly use oxygen treatment. Table 1 includes recommended limits for other feedwater chemical parameters for oxygen treatment. Startup is with increased pH and no oxygen feed. Oxygen addition to feedwater is initiated initiate d and pH is reduced only after feedwater cation conductivity is less than 0.15 µS/cm. System transients and upsets inevitably cause excursions above recommend limits. Increased rates of deposition and corrosion are likely to be in proportion to the deviations. Small brief deviations may individually be of little consequence, but the extent, duration, and frequency of such deviations should be minimized.

4 2 -1 2

Otherwise, over a period of years the accumulative effects will be significant. Potential effects include increased deposition, pitting, pressure drop, and fatigue cracking. Particular care is required to minimize the extent and duration of chemistry deviations for cycling units where operational transients are frequent.

Steam purity Purity or chemistry requirements for steam can be as simple as a specified maximum moisture content, or they can include maximum concentrations for a variety of chemical species. Often, for low-pressure building or process heater steam, only a maximum moisture content is specified. This may be as high as 0.5% or as low as 0.1%. Conversely, some turbine manufacturers specify steam condensate maximum cation conductivity, pH, and maximum concentrations concentrati ons for total dissolved solids, sodium and potassium, silica, iron, and copper. Turbine Turbine steam must generally have total dissolved solids less than 0.050 ppm, and in some cases less than 0.030 ppm. Individual species limits may be still lower. If steam is to be superheated, a maximum steam dissolved solids limit must be imposed to avoid excessive deposition and corrosion of the superheater. This limit is generally 0.100 ppm or less. Even where steam purity requirements are not imposed by the application, steam dissolved solids concentrations less than 1.0 ppm are recommended at pressures up to 600 psig (4.1 MPa), dissolved solids concentrations less than 0.5 ppm are recommended at 600 to 1000 psig (4.1 to 6.9 MPa), and dissolved solids concentrations less than 0.1 ppm are recommended recomm ended above 1000 psig (6.9 MPa). Up to 2000 psig (13.8 MPa), most non-volatile non-volat ile chemicals and impurities in the steam are carried by small water droplets entrained in the separated steam. Because these droplets contain dissolved solids in the same concentration as the boiler water, the amount of impurities in steam contributed by this mechanical carryover is the sum of the boiler water impurities concentration multiplied by the steam moisture content. Mechanical carryover is limited by moisture separation devices placed in the steam path, as described in Chapter 5. High water levels in the drum and boiler water chemistries that cause foaming can cause excessive moisture carryover and therefore excessive steam impurity concentrations. Foaming Foaming is is the formation of foam or excessive spray above the water line in the drum. Common causes of foaming are excessive solids or alkalinity, and the presence of organic matter such as oil. To keep dissolved solids below the concentration that causes foaming requires continuous or periodic blowdown of the boiler. High boiler water alkalinity increases the potential for foaming, particularly in the presence of suspended mat ter ter.. Where a chemical species is sufficiently volatile, it also carries over as a vapor in the steam. Total carryover is the sum of the mechanical and vaporous carryover. Vaporous carryover depends on solubility in steam and is different for each ea ch chemical species. For most dissolved solids found in boiler water, water, it is negligible by comparison to mechanical carryover at pres-



sures less than 2000 psig (13.8 MPa). An exception is silica for which vaporous carryover can be substantial at lower pressures. Fig. 9 shows typical vaporous carryover fractions (distribution ratios) for common boiler water constituents under typical conditions over a wide range of boiler pressures. Fig. 10 shows expected total dissolved solids carryover carry over for typical highpressure boilers. boilers . Vaporous Vaporous carryover carryove r depends on pressure and on boiler water chemistry. It is not affected by boiler design. Hence, if vaporous carryover for a species is excessive, the carryover can only be reduced by altering the boiler water chemistry. chemistry. Only mechanical carryover is affected by boiler design. Non-interactive gases such as nitrogen, argon, and oxygen carry over almost entirely with the steam, having no relationship to moisture carryover. Excessive steam impurity concentrations can also be caused by feedwater and boiler water chemistries that favor volatile species formation. Carryover of volatile silica can be problematic at pressures above 1000 psig (6.9 MPa). MPa ). Fig. 11 shows boiler water silica concentration limits recommended recommended to obtain steam silica concentrations less than 0.010 ppm at pressures up to 2900 psig (20.0 MPa) where the pH may be as low as 8.8. Vaporous silica carryover at a pH of 10.0 is 88% of that at a pH of 8.8. The vaporous silica carryover at a pH of 11.0 is 74% of that at 8.8. The only effective method for preventing excessive silica or other vaporous carryover is reduction of the boiler water wate r concentrations. Another common source of excessive impurities in steam is inadequate attemperation spray water purity.. All impurities in the spray water rity wa ter enter directly direct ly into the steam. Procedures for measuring steam quality qualit y and purity are discussed in Chapter 40.

Fig. 10 Solids in steam versus dissolved solids in boiler water.

Water sampling and analysis

Fig. 9 Impurity carryover coefficients of salts and metal oxides in boiler water (adapted ( adapted from Reference 16 ). ).

A key element in control control of water and steam chemistry is effective sampling to obtain representative samples, prevent contamination of the samples, and prevent loss of the species to be measured. 17 References 18 and 19 provide detailed procedures. In general, sample lines should be as short as possible and made of stainless steel, except where conditions dictate otherwise. Samples should be obtained from a continuously flowing sample stream. The time between sampling and analysis should be as short as possible. Samples should be cooled quickly to 100F (38C) to avoid loss of the species of interest. Sample nozzles nozz les and lines should provide for isokinetic sample velocity and maintain constant high water velocities [minimum of 6 ft/s (1.8 m/s)] to avoid loss of materials. Sample points should be at least 10 diameters downstream of the last bend or flow disturbance. Guidelines and techniques for chemical analysis of grab samples are listed in Table 4. The detailed methme thods are readily available from f rom the American Society for Testing and Materials Materia ls (ASTM) in Philadelphia, Pennsylvania, U.S. and the American Society of Mechanical Engineers (ASME) in New York, York, New York, U.S. Wherever practical, on-line monitoring should be considered as an alternative to grab samples. This gives real-time data, enables trends to be followed, and provides historical data. However, on-line monitors require calibration, maintenance, and checks with grab samples or on-line synthesized standard samples to ensure reliability. Table 5 lists important on-line monitoring measurements and references to specific methods. In addition to the measurements listed, in-


42-13

The Babcock & Wilcox Company 100

Table 4 Guidelines for Measurements on Grab Samples

Measurement

10 m p p , a c i l i S r e t a W 1 r e l i o B m u m i x a M 0.1

0.01

0 (0)

500 (3447)

1000 (6895)

1500 (10,342)

2000 (13,790)

2500 (17,237)

3000 (20,684)

Drum Pressure, psig (kPa)

Fig. 11 Boiler water silica concentration limit, where maximum steam silica is 0.010 ppm and boiler water pH is greater than 8.8.

strumentation is commercially available to monitor chloride, dissolved oxygen, dissolved hydrogen, silica, phosphate, ammonia and hydrazine. Adequate water chemistry control depends on the ability of boiler operators to consistently measure the specified parameters. Hence, formal quality assurance programs should be used to quantify and track the precision and bias of measurements. Detailed procedures should be in place to cover laboratory structure, training, standardization, calibration, sample collection/storage/analysis, reporting, maintenance records, and corrective action procedures. Further discussion is provided in Reference 20.

pH

Electrometric

ASTM D 1293 Method A

Conductivity

Dip or flow type conductivity cells energized with alternating current at a constant frequency (Wheatstone Bridge)

ASTM D 1125 Methods A or B

Dissolved oxygen

Colorimetric or titrimetric

ASTM D 888 Methods A, B, C

Suspended iron oxides

Membrane comparison charts

ASME PTC 31 Ion exchange equipment

Iron

Photometric (bathophenanthroline) or atomic absorption (graphite furnace)

ASTM D 1068 Method C, D

Copper

Atomic absorption (graphite furnace)

ASTM D 1688 Method C

Sodium

Atomic absorption or flame photometry

ASTM D 4191 or ASTM D 1428

Silica

Colorimetric or atomic absorption


Phosphate

Ion chromatography or photometric

ASTM D 4327 or ASTM D 515 Method A

Ammonia

Colorimetric (nesslerization) or ion-selective electrode

ASTM D 1426 Method A or B

Hydrazine

Colorimetric

ASTM D 1385

Chloride

Colorimetric, ion-selective electrode or ion chromatography


Sulfate

Turbidimetric or ion Turbidimetric chromatography


Calcium and magnesium

Atomic absorption; gravimetric or titrimetric


Fluoride

Ion-selective electrode or ion chromatography


Morpholine

Colorimetric

ASTM D 1942

Alkalinity

Color-change titration

ASTM D 1067 Method B

Hydroxide ion in water

Titrimetric

ASTM D 514

Total organic carbon

Instrumental (oxidation and infrared detection)

ASTM D 4779

Common fluid-side corrosion problems Water and steam react with most metals to form oxides or hydroxides. Formation of a protective oxide layer such as magnetite (Fe 3O4) on the metal surface causes reaction rates to slow with time. Boiler cycle water treatment programs are designed to maintain such protective oxide films on internal surfaces and thus prevent corrosion in boilers and other cycle components. With adequate control of water and steam chemistry,, internal corrosion of boiler circuitry can be chemistry minimized. Yet, Yet, chemistry upsets (transient losses of control) do occur. Vigilant Vigilant monitoring of system chemistry permits quick detection of upsets and quick remedial action to prevent boiler damage. Where these measures fail and corrosion occurs, good monitoring and documentation of system chemistry can facilitate identification of the root cause, and identification of the cause can be an essential step toward avoiding further corrosion. Where corrosion occurs and the origin is unknown, the documented water chemistry chem istry,, location of 4 2 -1 4

Technique(s) Techni que(s)

Reference/ Comment (Notes 1 and 2)

Notes: 1. ASME PTC refers to Performance Test Test Codes of the American Society of Mechanical Engineers, New York, New York. 2. ASTM refers to testing procedures of the American Society for Testing and Materials, Philadelphia, Pennsylvania.



Table 5 On-line Monitoring Measurements Measurement

Technique(s echnique(s))

Reference

pH

Electrometric

ASTM D 5128

Conductivities Conductivities (general, cation and degassed)

Electrical conductivity measurement measureme nt before and after hydrogen cation exchanges and at atmospheric boiling water after acidic gas removal

ASTM D 4519

Sodium

Selective ion electrode flame photometry

ASTM D 2791

Total organic carbon

Instrumenta l (oxidation Instrumental and measurement of carbon dioxide)

ASTM D 5173

the corrosion, appearance of the corrosion, and chemistry of localized deposits and corrosion products often oft en suggest the cause. Common causes are flow accelerated corrosion, oxygen pitting, chelant corrosion, caustic corrosion, acid corrosion, organic corrosion, acid phosphate corrosion, hydrogen damage, and corrosion assisted cracking. Figs. 12 and 13 show typical locations locat ions of common fluid-side corrosion problems. Further dis-

Fig. 13 Boiler convection pass showing typical locations of various types of water-side corrosion.

Fig. 12 Typical locations of various types of water-side corrosion in a boiler furnace water circuit.

cussion of corrosion and failure mechanisms is provided in References 21, 22, 23, and 24. For EPRI members, Boiler Tube Failures: Theory and Practice 25 provides an especially thorough description of utility boiler corrosion problems, causes, and remedial measures. One distinguishing feature of corrosion is its appearance. Metal loss may be uniform so the surface appears smooth. Conversely, Conversely, the surface may be gouged, scalloped, or pitted. Other forms of corrosion are microscopic in breadth, and subsurface, so they are not initially discernible. Subsurface Subsurfa ce forms of corrosion include intergranular corrosion, corrosion fatigue, stress corrosion cracking, and hydrogen damage. Such corrosion can occur alone or in combination with surface wastage. In the absence of component failure, detection of subsurface corrosion often requires ultrasonic, dye penetrant, or magnetic particle inspection (Chapter 45). These forms of corrosion are best diagnosed with destructive cross-section metallography. Another disting distinguishin uishing g feature is the chemic chemical al composition of associated surface deposits and corrosion products. Deposits may contain residual corrosives such as caustic or acid. Magnesium hydroxide in deposits can suggest the presence of an acid-forming precipitation process. Sodium ferrate (Na 2FeO4) indicates caustic conditions. Sodium iron phosphate indicates acid phosphate wastage. Organic deposits suggest corrosion by organics, and excessive amounts of ferric oxide or hydroxide with pitting suggest oxygen attack. Flow accelerated corrosion is the localized dissolution of feedwater piping in areas of flow impingement. It occurs where metal dissolution dominates over protective oxide scale formation. For example, localized


42-15


conditions are sufficiently oxidizing to form soluble Fe ++ ions but not sufficiently oxidizing to form Fe +++ ions needed for protective oxide formation. Conditions known to accelerate thinning include: flow impingement on pipe walls, low pH, excessive oxygen scavenger concentrations, temperatures in the range of 250 to 400F/121 to 204C (although thinning can occur at any feedwater temperature), chemicals (such as chelants) that increase iron solubility, solubility, and thermal degradation of organic chemicals. Thinned areas often have a scalloped or pitted appearance. Failures, such as that shown in Fig. 14, can occur unexpectedly and close to work areas and walkways. To assure continued integrity of boiler feedwater piping, it must be periodically inspected for internal corrosion and wall thinning. Any thinned areas must be identified and replaced before they become a safety hazard. The affected piping should be replaced with low-alloy chromium-bearing steel piping, and the water chemistry control should be appropriately altered. Oxygen pitting and pitting and corrosion during boiler operation largely occur in pre-boiler feedwater heaters and economizers where oxygen from poorly deaerated feedwater is consumed by corrosion before it reaches the boiler. A typical area of oxygen pitting is shown in Fig. 15. Oxygen pitting within boilers occurs when poorly deaerated water is used for startup or for accelerated cooling of a boiler boiler.. It also occurs in feedwater piping, drums, and downcomers in some low pressure boilers which have no feedwater heaters or economizer. Because increasing scavenger concentrations to eliminate residual traces of oxygen can aggravate flow accelerated corrosion, care must be taken to distinguish between oxygen pitting and flow accelerated

Fig. 14 Rupture of 6 in. (152 mm) feedwater pipe in an area thinned by internal corrosion.

4 2 -1 6

corrosion which generally occurs only where all traces of oxygen have been eliminated. Chelant corrosion occurs where appropriate feedwater and boiler water chemistries for chelant treatment are not maintained. Potentially corrosive conditions include excessive concentration of free chelant and low pH. (See prior discussion of boiler water treatment with dispersants, polymers, and chelants.) Especially susceptible surfaces include flow impingement areas of feedwater piping, riser tubes, and cyclone steam/water separators. Affected areas are often dark colored and have the appearance of uniform thinning or of flow accelerated corrosion. Corrosion fatigue is cracking well below the yield strength of a material by the combined action of corrosion and alternating stresses. Cyclic stress may b e of mechanical or thermal origin (Chapter 8). In boilers, corrosion fatigue is most common in water-wetted surfaces where there is a mechanical constraint on the tubing. For example, corrosion fatigue occurs in furnace wall tubes adjacent to windbox, buckstay buckstay,, and other o ther welded attachments. Failures Failures are thick thick lipped. On examination of the internal tube surface, multiple initiation sites are evident. Cracking is transgranular. Environmental Environmen tal conditions facilitate fatigue cracking where it would not otherwise occur in a benign be nign environment. Water chemistry factors that facilitate cracking include dissolved oxygen and low pH transients associated with, for example, cyclic operation, condenser leaks, lea ks, and phosphate hideout and hideout-return. Acid phosphate corrosio corrosion n occurs on the inner steamforming side of boiler tubes by reaction of the t he steel with phosphate to form maricite (NaFePO 4 ). Fig. 16 shows ribbed tubing that has suffered this type of wast age. The affected surface has a gouged appearance with maricite and magnetite deposits. Acid phosphate corrosion occurs where the boiler water effective sodiumto-phosphate ratio is less than 2.8, although ratios a s low as 2.6 may be tolerated at lower pressures. Though not always apparent, common signs of acid phosphate corrosion include difficulty maintaining target phosphate concentrations, phosphate hideout and pH increase with increasing boiler load or pressure, phosphate hideout return and decreasing pH with decreasing load or pressure, and periods of high iron concentration in boiler water. The potential for acid phosphate corrosion increases with increasing internal deposit loading, decreasing effective sodiumto-phosphate molar ratio below 2.8, increasing phosphate concentration, inclusion of acid phosphates (disodium and especially monosodium phosphate) in phosphate feed solution, and increasing boiler pressure. To avoid acid phosphate corrosion, operators should monitor boiler water conditions closely, assure accuracy of pH and phosphate measurements, assure purity and reliability of chemical feed solutions, assure that target boiler water chemistry parameters are appropriate and are attained in practice, and watch for aforementioned signs of acid phosphate corrosion. Under-deposit acid corrosion and hydrogen damage occur where boiler water acidifies as it concentrates beneath deposits on steam generating surfaces. Hydrogen from acid corrosion diffuses into the steel where



Fig. 17 Schematic of hydrogen attack, showing steps that occur and the final result. Hydrogen attack can occur in both carbon and low alloy steels in acidic or hydrogen environments.

Fig. 15 Oxygen pitting of economizer feedwater inlet.

it reacts with carbon to form methane as depicted in Fig. 17. The resultant decarburization and methane formation weakens the steel and creates microfissures. Thick lipped failures like that shown in Fig. 18 occur when the degraded steel no longer has sufficient strength to hold the internal tube pressure. Signs of hydrogen damage include under deposit corrosion, thick lipped failure, and steel decarburization and microfissures. The corrosion product from acid corrosion is mostly magnetite. Affected tubing, which may extend far beyond the failure, must be replaced. The boiler must be chemically cleaned to remove internal tube deposits, and boiler water chemistry must be altered or better controlled to prevent acid-formation as the water concentrates. Operators should reduce acidforming impurities by improving makeup water, reducing condenser leakage, or adding condensate polishing. For drum boilers, operators should use phosphate treatment with an effective sodium-to-phosphate molar ratio of 2.8 or greater.

Fig. 16 Acid phosphate corrosion of ri bbed tubing.


Caustic corrosion, gouging and grooving occur where boiler water leaves a caustic residue as it evaporates. In vertical furnace wall tubes, this occurs beneath deposits that facilitate a high degree of concentration and the corroded surface has a gouged appearance as shown in Fig. 19. In inclined tubes where the heat flux is directed through the upper half of the tube, caustic concentrates by evaporation of boiler water in the steam space on the upper tube surface. Resulting corrosion is in the form of a wide smooth groove with the groove generally free of deposits and centered on the crown of the tube. Deposits associated with caustic gouging often include Na 2FeO4. To To prevent preven t reoccurrence of caustic gouging, operators should prevent accumulation of excessive deposits and control water chemistry so boiler water does not form caustic as it concentrates. The latter can generally be achieved by assuring appropriate feedwater chemistry with coordinated phosphate boiler water treatment, taking care to control the effective sodium-to-phosphate molar ratio as appropriate for the specific boiler and the specific chemical and operating conditions. In some instances, where caustic grooving along the top of a sloped tube is associated with steam/water separation, such separation can be avoided by use of ribbed tubes which cause swirling motion that keeps water on the tube wall. Caustic cracking can occur where caustic concentrates in contact with steel that is highly stressed, to or beyond the steel’s yield strength. Caustic cracking is rare in boilers with all welded connections. This

Fig. 18 Brittle tube failure in hydrogen damaged area.

42-17


extent that a tube no longer retains adequate strength and bulges or ruptures. Internal tube deposits generally cause moderate overheating for extended periods of time, causing long-term overheat failures. Shortterm overheat failures generally occur only when there is gross interruption of internal flow to cool t he tube, or grossly excessive heat input. Out-of-service corrosion is predominantly oxygen pitting. Pitting attributed to out-of-service corrosion occurs during outages but also as aerated water is heated when boilers return to service. Especially common locations include the waterline in steam drums, areas where water stands along the bottom of horizontal pipe and tube runs, and lower bends of pendant superheaters and reheaters. Pinhole failures are more common in thinner walled reheater and economizer tubing. Such corrosion can be minimized by following appropriate layup procedures for boiler outages and by improving oxygen control during boiler startups.

Pre-operational cleaning Fig. 19 Caustic gouging initiated along weld backing ring.

generally occurs in boilers using a high alkalinity caustic boiler water treatment, and it is normally associated with unwelded rolled joints and welds that are not stress relieved. On metallographic examination, caustic cracking is intergranular and has the branched appearance characteristic of stress corrosion cracking as illustrated in Fig. 20. It can generally be avoided by use of coordinated phosphate treatment. Where a high alkalinity caustic phosphate boiler water treatment is used for low pressure boilers, nitrate is often added to inhibit caustic cracking. Overheat failures like that shown in Fig. 21 occur where deposits impede internal heat transfer to the

In general, all new boiler systems receive an alkaline boilout, i.e. hot circulation of an alkaline mixture with intermittent blowdown and final draining of the unit. Many systems also receive a pre-operational chemical cleaning. The superheater and reheater should receive a conventional steam blow (a period of high velocity steam flow which carries debris from the system). Chemical cleaning of superheater and reheat surfaces is effective in reducing the number of steam blows to obtain clean surfaces, but is not required to obtain a clean superheater and reheater.

Alkaline boilout All new boilers should be flushed flushed and given an alkaline boilout to remove debris, oil, grease and paint. This can be accomplished with a combination of trisodium phosphate (Na 3PO4) and disodium phosphate (Na2HPO4), with a small amount of surfactant added as a wetting agent. The use of caustic NaOH and/or soda ash (Na2CO3) is not recommended. If either is used, special precautions are required to protect boiler components.

Chemical cleaning

Fig. 20 Schematic of stress corrosion cracking.

4 2 -1 8

After boilout and flushing are completed, corrosion products may remain in the feedwater system and boiler in the form of iron oxide and mill scale. Chemical cleaning should be delayed until full load operation has carried the loose scale and oxides from the feedwater system to the boiler. Some exceptions are units that incorporate a full flow condensate polishing system and boilers whose pre-boiler system has been chemically cleaned. In general, these units can be chemically cleaned immediately following pre-operational boilout. Different solvents and cleaning processes are used for pre-operational chemical cleaning, usually determined by boiler type, metallic makeup of boiler components, and environmental concerns or restrictions. The four most frequently used are: 1) inhibited 5% hydrochloric acid with 0.25% ammonium bifluoride, 2) 2%



hydroxyacetic/1% formic acids with 0.25% ammonium hydroxyacetic/1% bifluoride and a corrosion inhibitor, 3) 3% inhibited ammonium salts of ethylene-diaminetetraacetic acid (EDTA), and 4) 3% inhibited ammoniated citric acid.

Steam line blowing The steam line blow procedure depends on unit design. Temporary piping to the atmosphere is required with all procedures. This piping must be anchored to resist high nozzle reaction force. All nor normal mal star startup tup pre precau cautio tions ns sho should uld be obse observe rved d for steam line blowing. The unit should be filled with treated demineralized water. Sufficient feedwater pump capacity and condensate storage must be available to replace the water lost during the blowing period. Numerous short blows are most effective. The color of the steam discharged to the atmosphere provides an indication as to the quantity of debris being removed from the piping. Coupons (targets) of polished steel attached to the end of the exhaust piping are typically used as final indicators.

Periodic chemical cleaning Cleaning frequency Internal surfaces of boiler water-side components (including supply tubes, headers and drums) accumulate deposits even though standard water treatment practices are followed. These deposits are generally classified as hardness-type scales or soft, porous-type deposits. To determine the need for cleaning, tube samples containing internal deposits should be removed from high heat input zones of the furnace and/or areas where deposition problems have occurred. The deposit weight is first determined by visually selecting a heavily deposited section. After sectioning the tube (hot and cold sides), the water-formed deposit is removed by scraping from a measured mea sured area. The weight of the dry material is reported as weight per unit area: either grams of deposit per square foot of tube surface or mg/cm2. Procedures for mechanical and chemical methods of deposit removal are provided in ASTM D3483.26 General guidelines for determining when a boiler should be chemically chemica lly cleaned are shown in Table 6. The deposit weights shown are based on the mechanical scraping method. This removes the porous deposit of external origin and most of the dense inner oxide scale. Values are slightly lower than those obtained from the chemical dissolution method. Because of the corrosive nature of the fuel and its combustion products, furnace tubes in Kraft recovery and refuse-fired boilers are particularly susceptible to gas-side corrosion which can be aggravated by relatively modest elevated tube metal temperatures. (See Chapters 28 and 29.) Through-wall failures due to external metal corrosion can occur in these tubes at water-side deposit weights much less than 40 g/ft 2 (43 mg/cm2 ). In addition, for Kraft recovery boilers there are significant safety concerns for water leakage in the lower furnace. (See Chapters 28 and 43.) For these units, a more conservative cleaning criterion is recommended for all operating pressures.


Fig. 21 Short-term overheat thin edged failure.

Chordal thermocouples The chordal thermocouple (see Chapter 40) can be an effective diagnostic tool for evaluating deposits on operating boilers. Properly located thermocouples can indicate a tube metal temperature increase caused by excess internal deposits, and can alert the operator to conditions that may cause tube failures. Thermocouples are often located in furnace wall tubes adjacent to the combustion zone where the heat input is highest and the external tube temperatures are also high. (See Fig. 22.) Deposition inside tubes can be detected by instrumenting key furnace tubes with chordal thermocouples. These thermocouples compare the surface temperature of the tube exposed to the combustion process with the temperature t emperature of saturated water water.. As deposits grow, grow, they insulate the tube from the cooling water and cause tube metal temperature increases. Beginning with a clean, deposit-free boiler, the instrumented tubes are monitored to establish the temperature differential at two or three boiler ratings; this establishes a base curve. At maximum load, with clean tubes, the surface thermocouple typically indicates metal temperatures 25 to 40F (14 to 22C) above saturation in low duty units and 80 to 10 0F (44 to 56C) in high duty units as shown in Fig. 23. The temperature variation for a typical clean instrumented tube is dependent upon the tube’s location in the furnace, tube thickness, inside fluid pressure, and the depth of the

Table 6 Guidelines for Chemical Cleaning Unit Operating Pressure, psig (MPa)

Water-side Deposit Weight* (g/ft2 )

Below 1000 (6.9)

20 to 40

1000 to 2000 (6.9 to 13.8) including all Kraft recovery and refuse-fired boilers

12 to 20

Above 2000 (13.8)

10 to 12

* Deposit removed from hot or furnace side of tube using the mechanical scraping method. (1 g/ft 2 = 1.07 mg/cm2 )

42-19


Clean Tube 500F (260C) Chemical Recovery Boiler

583F (306C) Saturation Temp 500F (260C) at 665 psi (4.6 MPa)

Heat Input 120,000 Btu/h ft2 (378,550 W/m2 )

510F (266C)

Typical Locations for Chordal Thermocouples Outer Casing Side

Furnace Side Scaled Tube

80

g/ft2

Fossil Fuel-Fired Boiler

877F (469C) 785F (418C)

500F (260C)

500F (260C)

Typical Locations for Chordal Thermocouples

Fig. 22 Typical locations of chordal thermocouples.

surface thermocouple. Internal scale buildup is detected by an increase in temperature differential above the base curve. Chemical cleaning should normally be considered if the temperature differential at maximum boiler load reaches 100F (56C). Initially, readings should be taken weekly, preferably using the same equipment and procedure as used for establishing the base curve. Under upset conditions, when deposits form rapidly, the checking frequency should be increased.

3. The uni unitt is tre treated ated to neut neutral ralize ize and and passivate passivate the heating surfaces. This treatment produces a passive surface, i.e., it forms a very thin protective film on freshly cleaned ferrous surfaces. 4. The unit is flushe flushed d with with clean clean water water to to remove remove any any remaining loose deposits. The two generally accepted chemical cleaning methods are: 1) continuous circulation of the solvent (Fig. 24), and 2) filling the unit with solvent, allowing it to soak, then flushing the unit (Fig. 25).

Chemical cleaning procedures and methods In general, four steps are required in a complete chemical cleaning process: 1. The inter internal nal heati heating ng surfac surfaces es are washe washed d with a solvent containing an inhibitor to dissolve or disintegrate the deposits. 2. Clea Clean n water water is used to flush flush out out loose loose deposi deposits, ts, solvent adhering to the surface, and soluble iron salts. Corrosive or explosive gases that may have formed in the unit are also displaced.

4 2 -2 0

Circulation cleaning method In the circulation (dynamic) cleaning method (Fig. 24), after filling the unit with demineralized water, the water is circulated and heated to the required cleaning temperature. At this time, the selected solvent is injected into the circulating water and recirculated until the cleaning is completed. Samples of the return solvent are periodically tested. Cleaning is considered complete when the acid strength and t he iron



content of the returned solvent reach equilibrium (Fig. 26), indicating that no further reaction with the deposits is taking place. In the circulation method, additional solvent can be injected if the dissipation of the solvent concentration drops below the recommended minimum concentration. The circulation method is particularly suitable for cleaning once-through boilers, superheaters, and economizers with positive liquid flow paths to assure circulation of the solvent through all parts of the unit. Complete cleaning can not be assured by this method unless the solvent reaches and passes through every circuit of the unit.

200

150

F , T

Solvents Many acids and alkaline compounds have been evaluated for removing boiler deposits. Hydrochloric acid (HCl) is the most practical cleaning solvent when using the soaking method on natural circulation boilers. Chelates and other acids have a lso been used. An organic acid mixture such as hydroxyacetic-formic (HAF) is the safest chemical solvent when applying the circulation cleaning method to once-through boilers. These acids decompose into gases in the event of incomplete flushing. For certain deposits, the solvent may require additional reagents, such as ammonium bifluoride, to promote deposit penetration. Alloy steel pressure parts, particularly those high in chromium, should generally not be cleaned with certain acid solvents. A general guideline for solvent selection can ca n be found in Table 7. Prior to chemically cleaning, it is strongly recommended that a representative tube section be removed and subjected to a laboratory cleaning test to determine and verify the proper solvent chemical, and concentrations of that solvent.


Base Curve Clean Condition

100

50

0

Soaking method The soaking (static) cleaning method (Fig. 25) involves preheating the unit to a specified temperature, filling the unit with the hot solvent, then allowing the unit to soak for a period of time, depending on deposit conditions. To assure complete deposit removal, the acid strength of the solvent must be somewhat greater than that required by the actual conditions; unlike the circulation method, control testing during the course of the cleaning is not conclusive, and samples of solvent drawn from convenient locations may not truly represent conditions in all parts of t he unit. The soaking method is preferable for cleaning units where definite liquid distribution distribution to all circuits (by the circulation method) is not possible without the use of many chemical inlet connections. The soaking method is also preferred when deposits are extremely heavy, or if circulation through all circuits at a n appreciable rate can not be assured without an impracticall impractically-sized y-sized circulating pump. These conditions may exist in large natural circulation units that have complex furnace wall cooling systems. Advantages of this method are simplicity simplicity of piping connections and assurance that all parts a re reached by a solvent of adequate acid strength.

With Internal Deposits After Operation

50

0

100

Firing Rate, % Low Duty Units

200 With Internal Deposits After Operation

150

F , T

100

50 Base Curve Clean Condition 0

0

50

100

Firing Rate, % High Duty Units

Fig. 23 Temperature difference between surface and saturation thermocouples.

Deposits Scale deposits formed on the internal heating surfaces of a boiler generally come from the wat er er.. Most of the constituents belong to one or more of the following groups: iron oxides, metallic copper, carbonates, phosphates, calcium and magnesium sulfates, silica, and silicates. The deposits may also contain various amounts of oil. Pre-cleaning procedures include analysis of the deposit and tests to determine solvent strength and contact time and temperature. The deposit analyses should include a deposit weight in grams per sq uare foot (or milligrams per square centimeter) and a spectrographic analysis to detect the individual elements. X-ray diffraction identifying the major crystalline constituents is also used. If the deposit analysis indicates the presence of copper (usually from corrosion of pre-boiler equipment, such as feedwater heaters and condensers), one of three procedures is commonly used: 1) a copper complexing agent is added directly to the acid solvent, 2) a separate cleaning step, featuring a copper solvent, is used followed by an acid solvent, and 3) a chelantbased solvent at high temperature is used to remove iron, followed by addition of an oxidizing agent at re-

42-21


duced temperature for copper removal. The decision to use one of these methods depends on the estimated quantity of copper present in the deposit. When deposits are dissolved and disintegrated, oil is removed simultaneously, provided it is present only in small amounts. For higher percentages of oil contamination, a wetting agent or surfactant may be b e added to the solvent to promote deposit penetration. If the deposit is predominantly oil or grease, boiling out with alkaline compounds must precede the acid cleaning.

Inhibitors The following equations represent the reactions of hydrochloric acid with constituents of boiler deposits: Fe3 O4 + 8H 8HCl

→

2FeCl 3 + Fe FeCl 2 + 4H 4 H 2O

CaCO3 + 2HCl → CaCl 2 + H2 O + CO2

(2)) (2 (3)) (3

At the same time, however, the acid can also react with and thin the boiler metal, as represented by the equation: Fe + 2H 2HCl

Fig. 24 Chemical cleaning by the circulation method – simplified arrangement of connections for once-through boilers.

→

FeCl 2 + H2

(4)) (4

unless means are provided to slow this reaction without affecting the deposit removal. A number of excellent commercial inhibitors are available to perform this function. The aggressiveness of acids toward boiler deposits and steel increases rapidly with temperature. However,, the inhibitor effectiveness decreases as the However temperature rises and, at a certain temperature, the inhibitor may decompose. Additionally, Additionally, all inhibitors are not effective with all acids.

Determination of solvent conditions Deposit samples The preferred type of deposit sample is a small section of tube with the adhering deposit, though sometimes tube samples are not easily obtained. Selection of the solvent system is made from the deposit analyses. After selection of the solvent system, it is necessary to determine the strength of the solvent, the solvent temperature, and the length of time required for the cleaning process. Solvent strength The solvent strength should be proportional to the amount of deposit. Commonly used formulations are:

1. Natural Natural circu circulat lation ion boiler boilerss (soaking (soaking metho method) d) (a) pre-operational – inhibited 5% hydrochloric acid + 0.25% ammonium bifluoride (b) operational – inhibited 5 to 7.5% hydrochloric acid and ammonium bifluoride based on deposit analysis 2 Onc Once-th e-throu rough gh boi boiler lerss (cir (circul culati ation on met method hod)) (a) pre-operational – inhibited 2% hydroxyacetic1% formic acids + 0.25% ammonium bifluoride (b) operational – inhibited 4% hydroxyacetic-2% formic acids + ammonium bifluoride based on deposit analysis

Fig. 25 Chemical cleaning by the soaking method – simplified arrangement of connections for drum-type boilers.

4 2 -2 2

Solvent temperature The temperature of the solvent should be as high as possible without seriously reducing the effectiveness of the inhibitor. An inhibitor test should be performed prior to any chemical cleaning



to determine the maximum permissible temperature for a given solvent. When using hydrochloric acid, commercial inhibitors generally lose their effectiveness above 170F (77C) and corrosion rate increases rapidly. rapidly. Therefore, the temperature of the solvent, as fed to the unit, should be 160 to 170F (71 (7 1 to 77C). In using the circulation method with a hydroxyacetic-formic acid mixture, a temperature of 200F (93C) is necessary for adequate cleaning. Chelate-based solvents are generally applied at higher temperatures (about 275F/ 135C). In these cases, the boiler is fired to a specific temperature. The chelate chemicals are introduced and the boiler temperature is cycled by alternately firing and cooling to predetermined limits. Steam must be supplied from an auxiliary source to heat the acid as it is fed to the unit. When using the circulation method, steam is also used to heat the circulating water to the predetermined and desired temperature before injecting the acid solution. Heat should be added by direct contact or closed cycle heat exchangers. The temperature of the solvent should never be raised by firing the unit when using an acid solvent. Cleaning time When cleaning by the circulation method, process completion is determined by analyzing samples of the return solvent for iron concentration and acid strength. (See Fig. 26.) However, acid circulation for a minimum of six hours is recommended. In using the soaking method, the cleaning time should be predetermined but is generally between six to eight hours in duration.

Preparation for cleaning Heat transfer equipment All parts not to be cleaned should be isolated from the rest of the unit. To exclude acid, appropriate valves should be closed and checked for leaks. Where arrangements permit, parts of the unit such as the superheater can be isolated by filling with demineralized water. Temporary piping should be installed to flush dead legs after cleaning. In addition to filling the superheater with demineralized water, once-through type units should be pressurized with a pump or nitrogen. The pressure should exceed the chemical cleaning pump head. Bronze or brass parts should be removed or temporarily replaced with steel. All valves should be steel or steel alloy. alloy. Galvanized piping or fittings should not be

Table 7 Comparative Cleaning Effectiveness Makeup of Deposit Type of Cleaning HCl HAF EDTA Citric Bromate

Iron

Copper

Silica

Hardness (Ca/Mg)

Good Good Good Good N/A

Medium Poor Medium Medium Good

Medium Medium Poor Poor N/A

Good Medium/poor Medium/poor Poor N/A

used. Gauge and meter connections should be closed or removed. All parts not otherwise protected by blanking off or by flooding with water will be exposed to the inhibited solvent. Vents to a safe discharge should be provided wherever vapors might accumulate, because acid vapors from the cleaning solution do not retain the inhibitor. Cleaning equipment The cleaning equipment should be connected as shown in Fig. 24 if the continuous circulation method is used, or as shown in Fig. 25 if the soaking method is used. Continuous circulation requires an inlet connection to assure distribution. It also requires a return line to the chemical cleaning pump from the unit. The soaking method does not require a return line. The pump discharge should be connected to the lowermost unit inlet. The filling or circulating pump should not be fitted with bronze or brass parts; a standby pump is recommended. A filling pump should have the capacity to deliver a volume of liquid equal to that of the vessel within two hours at 100 psi (0.7 MPa). A circulating pump should have sufficient capacity to meet recommended cleaning velocities. With modern oncethrough boilers, a capacity of 3600 GPM (227 l/s) at 300 psi (2.1 MPa) is common. A solvent pump, closed mixing tank and suitable thermometers, pressure gauges, and flow meters are required. An adequate supply of clean water and steam for heating the solvent should be provided. Provision should be made for adding the inhibited solvent to the suction side of the filling or recirculating pump. Cleaning solutions Estimating the content of the vessel and adding 10% to allow for losses will determine the amount of solvent required. Sufficient commercial acid should then be obtained. An inhibitor qualified for use with the solvent also needs to be procured and added to the solvent.

Cleaning procedures The chemical cleaning of steam generating equipment consists of a series of distinct steps which may include the following: 1. 2. 3. 4. Fig. 26 Solvent conditions during cleaning by the circulation method.


isolation of the isolation the system system to be cleaned cleaned,, hydrostatic hydro static testin testing g for for leaks, leaks, leak detection detection during during each each stage of the the process, process, back flushing flushing of the the superheater superheater and forward forward flushing of the economizer economizer,, 5. preheating of the system and and temperature temperature control, 42-23


6. 7. 8. 9. 10. 11.

solvent injection/ci solvent injection/circul rculation ation (if circulati circulation on is used), draining drain ing and/or and/or displac displacement ement of the solvent, solvent, neutralizati neutr alization on of residu residual al solven solvent, t, passivation passiv ation of clean cleaned ed surfac surfaces, es, flushing flush ing and inspec inspection tion of cleaned cleaned surface surfaces, s, and layup lay up of the uni unit. t.

Every cleaning should be considered unique, and sound engineering judgment should be used throughout the process. The most important importa nt design and procedural considerations include reducing system leakage, controlling temperature, maintaining operational flexibility and redundancy redundancy,, and ensuring personnel safety safety..

Precautions Cleaning must not be considered a substitute for proper water treatment. Intervals between cleanings should be extended or reduced as conditions dictate. Every effort should be used to extend the time between chemical cleanings. Hazards related to chemical cleaning of power plant equipment are fairly well recognized and understood, and appropriate personnel safety steps must be instituted. 27

Chemical cleaning of superheater, reheater and steam piping In the past, chemical cleaning of superheaters and reheaters was not performed because it was considered unnecessary and expensive. With the use of higher steam temperatures, cleaning procedures for superheaters, reheaters and steam stea m piping have gained importance and acceptance. When chemically cleaning surfaces that have experienced severe high-temperature oxide exfoliation (spalling of hard oxide particles from surfaces), it is important to first remove a tube t ube sample representing the worst condition. Oxidation progresses at about the same rate on the outside of the tubes as on the inside; exfoliation follows a similar pattern. The tube sample should be tested in a facility capable of producing a flow rate similar to that used in the actual cleaning. This allows development of an appropriate solvent mixture. To determine the circulating pump size and flows required, it is usually necessary to contact the boiler manufacturer. Figs. 27 and 28 show possible superheater/reheater chemical cleaning piping schematics for drum boiler and once-through boiler systems, system s, respectively. respectively. If, in the case of a drum boiler, the unit is to be cleaned along with the superheater and reheater, it is usually necessary to orifice the downcomers to obtain the desired velocities through the furnace walls. A steam blow to purge all air and to completely fill the system must precede cleaning in all systems containing pendant non-drainable surfaces. Most drainable systems also benefit bene fit from such a steam blow. blow. Presently, two solvent mixtures are available to clean superheater, reheater and steam piping. One is a combination of hydroxyacetic and formic acids containing ammonium bifluoride; the other is an EDTA (ethylenediaminetetraacetic acid)-based solvent.

4 2 -2 4

Fig. 27 Typical superheater/reheater chemical cleaning circuit for a drum-type boiler.

Solvent disposal chemical cleaning cleaning General considerations A boiler chemical is not complete until the resultant process waste water stream is disposed of. Selection of handling and disposal methods depends on whether the wastes are classified as hazardous or non-hazardous. Boiler chemical cleaning wastes (BCCW) are different in volume and frequency of generation and have different discharge regulations from other power plant waste streams. Of all power plant discharges, BCCWs are most likely to be classified as hazardous. Depending upon the cleaning process, the resultant BCCW may become one of the driving forces in solvent selection. Under National Pollutant Discharge Elimination System (NPDES) requirements, boiler cleaning wastes are considered chemical metal cleaning wastes. The primary parameters of concern are iron, copper, copper, chromium and pH. In all cases, waste management must be performed in accordance with current regulatory requirements. Waste management options Table 8 lists the handling practices for BCCW. In co-ponding , the BCCW is mixed in an ash pond with other waste streams from the power plant. Acid wastes are neutralized by the alkaline ash, and the metals are precipitated as insoluble metal oxides and hydroxides, or absorbed on ash particles. Co-ponding is the least expensive and the easiest disposal option. Incineration of organic-based cleaning wastes by direct injection into the firebox of the utility b oiler is another common disposal practice. Potential emissions from the boiler must be carefully monitored to ensure regulatory compliance. Large quantities of BCCW are often disposed of in a secure landfill. Evaporation can reduce waste volume and, thereby, reduce overall landfill disposal costs. HCl cleaning wastes can be treated to NPDES standards using lime or caustic precipitation. It is more



Removing metal ions and reusing chemical cleaning waste are subjects receiving increased attention. As the regulatory environment continues to change, more emphasis will be placed on the treatment and reuse of BCCW.

Layup

Fig. 28 Typical superheater/reheater chemical cleaning circuit for a once-through boiler.

difficult to treat the organic cleaning agents (such as EDTA) by current techniques. Treatment methods with permanganate, ultraviolet light, and hydrogen peroxide (wet oxidation) have been used with limited success. Several vendors have proprietary processes which claim to successfully treat chelated wastes. 28,29

Table 8 Boiler Chemical Cleaning Wastes Practices/Options Source Reduction Optimize cleaning frequency Reduce volume of cleaning solution Improve boiler water chemistry Alternate Solutions Change the cleaning solvent Disposal Evaporation Incineration Co-ponding Secured landfill Treatment Neutralization Physical waste treatment Chemical waste treatment Recycle and Reuse Recycle for metal recovery Reuse acid in alternate applications


During periods when boiler operation is interrupted, substantial pitting and general corrosion can occur within unprotected water-steam water-stea m circuitry. circuitry. When boilers return to operation, corrosion products migrate to high heat flux areas of the boiler or carryover to the turbine. Out-of-service corrosion can therefore impede boiler startup and lead to operational problems such as deposition, under-deposit corrosion, corrosion fatigue, and cycle efficiency loss. Preservation methods inhibit out-of-service corrosion by eliminating or controlling moisture, oxygen, and chemical contaminants that cause corrosion. Table 9 provides a brief summary and comparison of common preservation methods. These methods are designed to limit corrosion caused by the normal range of boiler and atmospheric contaminants. Gross contamination must be avoided and, if it occurs, the contaminants must be immediately neutralized and removed. Respective vendors should be contacted for specific recommendations recommendations for balance-of-plant equipment (turbine, condensate, feedwater, and atmospheric pollution control systems). Vendor V endor procedures should also be followed for boiler auxiliary equipment such as pulverizer gearboxes, sootblowers, fans, and motors.

Boiler shutdown for layup Appropriat Appro priate e shutd shutdown own proced procedures ures can facili facilitate tate preservation for subsequent idle periods. Reducing load dissipates fluid-side salts that concentrate on tube surfaces in high heat flux areas. As boiler load is reduced, feedwater and boiler water pH should be increased to the upper end of the target operating range, preferably 9.6 or higher. Where an oxygen scavenger/inhibitor scavenger/inhibit or is employed, concentration should increase to 0.050 ppm hydrazine* or equivalent. When boiler water is to remain in the boiler for a substantial cold layup period, the oxygen scavenger/inhibitor concentration in the water should be increased to 20 ppm hydrazine or equivalent after the boiler pressure has decayed to below 200 psig (1.4 MPa). At higher pressures and associated temperatures, the scavenger may rapidly decompose. An oxygen scavenger/inhibitor is not added to boilers that employ emp loy oxygen treatment. For boilers on oxygen treatment, the oxygen feed should be stopped at least an hour be-

*WARNING: HYDRAZINE IS A PROVEN GENERIC CHEMICAL FOR THIS APPLICATION. HOWEVER, HYDRAZINE IS A KNOWN CARCINOGEN, AND CAN BE REPLACED WITH OTHER PRODUCTS THAT HAVE HA VE EQUIVALENT ABILITY TO SCAVENGE SC AVENGE OXYGEN AND INHIBIT CORROSIO CORROSION. N.

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Table 9 Summary and Comparison of Boiler Lay-up Methods Lay-up Method Drained and dry for erection or maintenance

Effectiveness Effectivene ss

Costs

Safety and Environmental Concerns

Strengths

Weaknesses

Poor

Minimal

Minimal

Allows full access to internal surfaces Quick and easy

Not effective

Variable, Va riable, generally fair

Chemicals Chemical applicat application ion Chemical removal and disposal

Handling and and disposal of chemicals

Minimal maintenance maintenance requirements

Remaining inhibitive inhibitive capacity is difficult to monitor Chemicals must be replaced periodically Difficult to distribute through components

Nitrogen blanketing

Excellent

Nitrogen distributi distribution on system Nitrogen

Nitrog en suffocation Nitrogen

Consistently effective Easy to monitor

Safety concerns Nitrogen leakage

Hot standby

Good

Heat

Residual temperature and pressure

Fast restart

Not recommend recommended ed for more than 3 days

Cold standby

Poor

Minimal

Minimal

Fast restart

Not recommend recommended ed for more than 30 days

Wet, water-filled

Variable, generally good

Demineralized water Chemical treatment Disposal of treated water

Handling of chemicals Disposal of treated water

Easily applicab applicable le to non-drainable components componen ts Facilitates rapid return to service

Freeze damage Valve seepage and associated corrosion damage Difficult to monitor and inspect May corrode copper alloys beyond boiler

Dry, dehumidifie Dry, dehumidified d air

Excellent

Dehumidifier and blower unit Air recirculation piping

Minimal

Consistently effective Safe No disposal problems Easy to monitor

Boiler must be totally drained Initial plumbing and equipment requirements

Vaporous Vaporous corrosion inhibitors

fore shutdown; there can be no oxygen leakage into the cycle. Where possible, as steam pressure decays to atmospheric pressure, nitrogen should be introduced through upper vents to keep the internal pressure positive and prevent air ingress. Boiler-specific operating instructions should be consulted for other important shutdown procedures and precautions.

brief as possible, preferably less than 3 weeks. Where a long maintenance outage with minimal preservation is necessary, the boiler and open sections of the pre-boiler system should generally be chemically cleaned and repassivated to reform a protective oxide film following the outage.

Draining for boiler maintenance and inspection

When a boiler b oiler returns to operation while steam prespressure remains above atmospheric pressure, preservation requirements are minimal. If the shutdown period is less than 72 hours and there is no air in-leakage, ammonia and oxygen scavenger/inhibitor concentrations need only be raised to the high end of the normal operating range with an oxygen scavenger/inhibitor concentration equivalent to about 0.050 ppm hydrazine. Oxygen scavengers are not used for boilers that employ oxygen treatment. treatment . However, a low oxygen concentration must be maintained by effective deaeration, and water must remain at a high level of purity with cation conductivity less than 0.15 µS/cm. Extended hot standby is not recommended. Hot layup can be extended by use of auxiliary heat, but

Draining boilers without further preservation is often necessary for maintenance and inspection, and the unit should be drained and dried as thoroughly as possible. Draining the boiler hot (for example, at 20 psig/0.14 MPa) will facilitate drying, but may leave condensate in non-drainable superheater elements. Boiler components that need not be open for maintenance should, where possible, be isolated and protected. For example, while the lower furnace is open for maintenance, the superheater should, if possible, be protected with an appropriate wet or dry layup method. All openings should remain covered to prevent ingress of contaminants. The unpreserved maintenance period should be as

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Hot standby and hot layup



non-corrosive and non-depositing conditions can be difficult to assure, especially in economizers, superheaters, and reheaters. If temperature is maintained by injecting blowdown from an adjacent boiler, excessive blowdown solids can accumulate under low-flow conditions in the standby boiler. When steam is in jected from another boiler, deposition and corrosion problems can arise from temperature and chemistry differentials. Also, care must be taken to avoid cavitation and to control the chemistry of steam condensate. Water leakage across valves can cause corrosion in seepage areas, and the corrosion is aggravated by relatively high material and water temperatures.

Cold standby for up to thirty days For short periods (not more than a week), boilers may remain on cold standby status with little or no chemical additions. Moderate ammonia and oxygen scavenger/inhibitor additions can extend this period up to thirty days. Treated demineralized water for shorts hortterm cold standby should have a minimum concentration of 10 ppm ammonia. The concentration of oxygen scavenger/inhibitor normally used in the boiler should be increased to the equivalent of 25 ppm of hydrazine. Nitrogen blanketing (see below) is recommended. For boilers employing oxygen treatment, no scavenger should be used for short cold standby periods. However, oxygen ingress must be avoided and low oxygen concentrations must be maintained mainta ined (for example, by use of nitrogen blanketing of boiler and deaeration of makeup water). Throughout the storage period, the pH must be 9.2 or higher, and cation conductivity throughout the boiler must be less than 0.15 µS/cm.

Boiler storage for more than seven days Any of several s everal layup practices are acceptable for storage periods up to six months. Alternatives for fluidside layup include nitrogen blanketing, wet layup with treated demineralized water, and dry dehumidified layup. For extended outages, it is important that the pre-boiler feedwater train, balance of the water-steam cycle, auxiliary equipment, and fireside of the b oiler are adequately preserved. For idle periods longer than six months, dry (dehumidified) storage is recommended. For boilers with non-drainable components, water removal issues must be weighed against the advantages of dry layup.

Reheaters – all periods Reheaters are generally stored dry because they can not easily be isolated from the turbine. Wet storage requires installation of blanks or special valves in the connecting lines. Drying can be performed by exposing reheaters to condenser vacuum after the fires have been removed, the unit tripped, and the turbine seals maintained. With approximately 20 in. (5 kPa) of vacuum on the condenser, vents or drains on the reheater inlet should be opened to allow air to pass through and remove all moisture. Dehumidified dry storage is recommended where the storage period exceeds 30 days. Alternatively, Alternatively, the evacuated reheater may be isolated and nitrogen blanketed, or it may be nitrogen blanketed in conjunction with the turbine.


Nitrogen blanketing Even where water is present, corrosion can be prevented by eliminating oxygen from the environment. Oxygen can be eliminated by sealing and pressurizing the entire boiler, or the space above water level, with nitrogen to prevent air in-leakage. In the absence of acids and other oxidants, eliminating air stops corrosion. Nitrogen blanketing is a highly effective method for preventing corrosion. It is easy t o monitor and alarm, so effective preservation can be assured. However, the boiler must be well sealed to prevent excessive leakage. It is absolutely imperative that working spaces around nitrogen blanketed equipment be well ventilated. Venting of nitrogen during purging or water filling operations can release large amounts of nitrogen into surrounding areas. Also, before entry, entry, areas that have been nitrogen blanketed must be well ventilated and the air tested to confirm that all parts have adequate oxygen concentrations.

Wet (water-filled) layup Wet layup in combination with nitrogen blanketing is often the most practical method of protection, especially for boilers that are not fully or easily drainable. However, for longer storage periods, advantages of wet layup are offset by accumulative corrosion in areas of valve seepage and by accumulative cost of replacement water, chemicals, treated water disposal, nitrogen cover gas, and heat in cold climates. Consequently, dry layup is generally recommended for storage periods longer than six months. Before a boiler is flooded with layup water, provision must be made to support the additional weight when drum (if present), superheater, and steam piping are filled. If the boiler is to be completely complet ely filled with layup water, an expansion tank or surge tank above the highest vent is necessary to accommodate volume changes that are caused by normal temperature fluctuations. The expansion space at the top of the boiler (whether in a drum or in a surge tank) should be nitrogen blanketed to assure that there is no air ingress. Where freezing conditions are expected or possible, provision must be made for heating water-filled components. Wet layup generally requires demineralized water having a specific conductivity less than 1.0 µS/cm before treatment chemicals are added. Use of demineralized water and all volatile treatment chemicals is essential where boilers include non-drainable or stainless steel components. Use ammonium hydroxide to raise water pH into the range of 10.0 to 10.4. Use an oxygen scaven scavenger/inhibi ger/inhibitor tor to further retard corrosion. corrosion.

Dry (dehumidified) layup Dry layup requires the removal of all water and t he dehumidification of air to maintain a relative humidity less than 50%, and preferably less than 40%. This prevents corrosion by hygroscopic salts. Dry-air (dehumidified) storage is highly effective, and its continued effectiveness is easy to monitor. Dry layup allows easy and safe access for maintenance, with no potential for suffocation and no exposure to toxic chemicals.

42-27


It also eliminates the potential for biological activity, damage from freezing water, and corrosion by leaking water. However, implementation requires requi res that the boiler be completely drained and dried, and this is a major problem for boilers with non-drainable superheaters or other non-drainable circuits. Also, mechanical circulation and dehumidification equipment and piping installation can be costly. In preparation for dry storage, water must be drained completely from all boiler b oiler circuits, including feedwater piping, economizer, superheater, and reheater. All non-drainable boiler tubes and superheater tubes should be blown with pressurized air. Auxiliary sources of heat are used to dry fluid-side f luid-side surfaces. Deposits of sufficient thickness to retain moisture must also be removed. The preferred dry layup method is continuous recirculation of dehumidified air. Fans force air through the dehumidifier, boiler fluid-side circuitry, circuitry, and back to the dehumidifier. The system must include instrumentation for measuring relative humidity. humidity. Recirculating dehumidification also requires external (usually flexible plastic) piping to complete the path. The system must be sized to handle the residual moisture and moist air in-leakage, and must be monitored to

assure that relative humidity remains less than 50%. An alternative, but inferior inferior,, dry layup method is the use of static desiccant to absorb moisture with no forced air circulation. This method is effective for boiler components and small (package) boilers, but not generally adequate for large complex boiler circuitry. Termination of the storage period requires removal of the recirculati recirculation, on, dehumidification, and monitoring materials and equipment. Any loose desiccant particles or dust (which generally contain silica or sulfite chemicals) must be cleaned from the boiler.

Vaporous corrosion inhibitors (VCI) Vaporous V aporous corrosion inhibitors retard corrosion by forming a thin protective film over metal surfaces. Where such chemicals are sealed into a closed space, they can retard corrosion even in the presence of both water and oxygen. These inhibitors are not generally used for completed boilers, where the size and complexity of boiler circuits precludes effective distribution of dry powders. However, they are often used to inhibit internal corrosion of boiler components, as supplements to dry storage for small boilers, and as an alternative treatment for hydrotest water.

References 1. Klein, H.A., H.A., and Rice, J.K., “A research research study on internal corrosion in high pressure boilers,” Journal of En gineering for Power, V Power, Vol. ol. 88, No. 3, pp. 232-242, July, July, 1966. 2. Cohe Cohen, n, P., P., Ed., Ed., The ASME Handbook on Water Technology in Thermal Power Systems, The American Society of Mechanical Engineers, New York, New York, 1989. 3. “Consens “Consensus us on Operating Operating Practices Practices for the Control Control of Feedwater and Boiler Water Quality in Modern Industrial Boilers,” The American Society of Mechanical Engineers, New York, New York, 1994. 4. “Interim consensus consensus guidelines on fossil plant cycle chemistry,” Report CS-4629, Electric Power Research Institute, Palo Alto, California, June, 1986. 5. “Guideline for Boiler Feedwater, Feedwater, Boiler Water Water,, and Steam of Steam Generators with a Permissible Operating Pressure > 68 bar,” VGB PowerTech e.V., Essen, Germany, VGB-R 450 Le, (in German), 1988. 6. Bet z Han dbo ok of Ind ust ri rial al Wa Wate terr Con di diti tioni oni ng, Ninth Ed., Betz Laboratories, Trevose, Pennsylvania, September, 1991. 7. Drew Principle P rincipless of Industrial Water Treatment, 11th Ed., Drew Industrial Division, Ashland Chemical Co., Boonton, New Jersey, 1994. 8. Kemmer Kemmer,, F.N., F.N., Ed., Ed., The Nalco Water Handbook, Second Ed., McGraw-Hill, New York, New York, York, 1988. 9. Macbeth, R.V., R.V., et al., UKAEA Report Report No. AAEW-R71 AAEW-R711, 1, Winfrith, Dorchester, Dorchester, United Kingdom, 1971. 10. Goldstein Goldstein,, P., P., and Burton, C.L., “A research research study on internal corrosion of high-pressure boilers – final report,” Journal of Engineering for Power, Vol. 91, pp. 75- 101 , April, 1969.

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11. Freier, R.K., R.K., “Cover layer layer formation on on steel by oxyoxygen in neutral salt free water,” VGB Speiserwassertagung 1969 Sunderheft, pp. 11-17 (in German), 1969. 12. Whirl, S.F., S.F., and Purcell, T.E., T.E., “Protection against against caustic embrittlement by coordinated pH control,” Third Annual Meeting of the Water Water Conference of the Engineers’ Society of Western Pennsylvania, Pittsburgh, Pennsylvania, 1942. 13. Stodola, J., J., “Review of of boiler water alkalinity alkalinity control,” control,” Proceedings of the 47th Annual Meeting of The International Water Conference, Pittsburgh, Pennsylvania, pp. 235-242, October 27-29, 1986. 14. Econom Economy y, G., et al., “Sodium phosphate solutions at boiler conditions: solubility, phase equilibrium and interactions with magnetite,” Proceedings of the International Water Technology Conference, Pittsburgh, Pennsylvania, pp. 161-173, 1975. 15. Tremaine, P., et al., “Interactions of sodium phosphate salts with transitional metal oxides at 360C,” Proceedings of the International Conference on Interaction of Iron Based Materials with Water and Steam, Heidelberg, Germany, June 3-5, 1992. 16. Martynova Martynova,, O.I., “Transport “Transport and concentration concentration proprocesses of steam and water impurities in steam generating systems,” Water and Steam: Their Properties and Current Industrial Applications, J. Staub and K. Scheffler, Eds., Pergamon Press, Oxford, United Kingdom, pp. 547562, 1980. 17. Nagda, N.L. and Harper, Harper, J.P., J.P., Monitoring Water in the 1990s: Meeting New Challenges, STPl102, American Society for Testing and Materials, Philadelphia, Pennsylvania, 1991.


The Babcock & Wilcox Company 18. Annual Book Bo ok of ASTM Standards, Standar ds, Section 11, Water and Environmental Technology, Vol. 11.01 (D 1192 Specification for Equipment for Sampling Water and Steam; D 1066 Practice for Sampling Steam; D 3370 Practice for Sampling Water; and D 4453 Handling of Ult ra-pure Water Samples), American Society for Testing and Materials, Philadelphia, Pennsylvania, 2004.

24. Port Port,, R.D., R.D., and Herro, Herro, H.M., H.M., The Nalco Guide to Boiler Company,, New York, New Failure Analysis, McGraw-Hill Company York, Y ork, 1991.

19. Steam and Water Sampling, Conditioning, and Analysis in the Power Cycle, ASM E Pe Perf rfor orman man ce Tes t Cod e 19.11,, The American Society of Mechanical Engineers, 19.11 New York, New York, 1997. 20. Rice, J., “Quality “Quality assurance assurance for continuous continuous cycle chemchemistry monitoring,” Proceedings of the International Conference on Fossil Plant Cycle Chemistry, Report TR100195, Electric Power Research Institute, Palo Alto, California, December, 1991.

26. Annual Book of ASTM AST M Standards, Standar ds, Section 11, Water and Environment al Technology, Technology, Vols. 11.01 and 11.02, American Society for Testing Testing and Materials, Philadelphia, Pennsylvania, 2003.

21. Uhlig, H.H., H.H., and Revic, Revic, R.W., R.W., Corrosion and Corrosion Control, Third Ed., John Wiley & Sons, New York, New York, 1985. 22. Lamping, G.A., G.A., and Arrowood, Jr., Jr., R.M., Manual for Investigation and Correction of Boiler Tube Failures, Report CS-3945, Electric Power Research Institute, Palo Alto, California, 1985.

25. Dooley Dooley,, R.B., and McNaughton, W.P W.P., ., “Boiler Tube Failures: Theory and Practice,” Electric Power Research Institute, Palo Alto, California, 1996. LICENSED MATERIAL available to EPRI members.

27. Wackenhuth ackenhuth,, E.C., E.C., et al., “Manual on chemical cleaning of fossil-fuel steam generating equipment,” Repor t CS3289, Electric Power Research Institute, Palo Alto, California, 1984. 28. Samuelso Samuelson, n, M.L., McConnell, S.B., S.B., and Hoy, Hoy, E.F., E.F., “An on-site chemical treatment for removing iron and copper from chelant cleaning wastes,” Proceed ings of the 49th International Water Conference, Pittsburgh, Pennsylvania, p. 380,1988. 29. “Nalmet heavy heavy metal removal removal program,” program,” Nalco ChemiChemical Company, Naperville, Illinois, February, 1989.

23. Fre French nch,, D.N. D.N.,, Metallurgical Failures in Fossil Fired Boilers, Boile rs, Second Ed., Wiley, New York, New York, 1993.


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Degassed conductivity analyzer for water quality analysis.

4 2 -3 0


Boiler water treatment

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