Boiler and Feedwater Treatment

Boiler and Feedwater Treatment$ A Banweg, Nalco an Ecolab company, Naperville, IL, USA r 2016 Elsevier Inc. All rights reserved.

1 2 3 3.1 4 4.1 4.2 4.3 4.4 5 5.1 5.2 5.3 5.4 5.5 5.6 5.7 5.8 5.9 6 7 7.1 8 References

Introduction Make Up Water Treatment Feedwater Treatment Dissolved Oxygen Control pH Control All Volatile Treatment (Reducing) Flow Accelerated Corrosion All Volatile Treatment (Oxidizing) Oxygenated Treatment Boiler Water Treatment Residual Phosphate Treatment Steam Purity Chelant Treatments All-Polymer Treatment Coordinated Phosphate Treatment Congruent Phosphate Treatment Phosphate Continuum Treatment (Formerly Equilibrium Phosphate Treatment) AVT Caustic Treatment Condensate Treatment Boiler Treatment During Out-of-Service Conditions Miscellaneous (But Important) Comments

Abbreviations ASME ASTM AVT AVT(O) AVT(R) ED EDI EDR EDTA

American Society of Mechanical Engineers American Society of Testing and Materials All volatile treatment All volatile treatment, oxidizing All volatile treatment, reducing Electrodialysis Electrodionization Electrodialysis reversal Ethylenediaminetetraacetic acid

Glossary Attemperation The process for reducing and controlling the temperature of superheated steam. Cation conductivity The measurement of the electrical conductivity of a water sample after it has been passed through a strong acid cation resin that is in the hydrogen form. Decarbonator A degasifier used to remove carbon dioxide.

EPRI FAC JIS NTA ORP OT RO TDS VGB

2 2 5 5 6 6 7 7 9 9 9 10 10 11 11 12 13 14 14 14 16 16 16 16

Electric power research institute Flow accelerated corrosion Japanese Industrial Standards Nitrilotriacetic acid Oxidation–reduction potential Oxygenated treatment Reverse osmosis Total dissolved solids Vereinigung Grosskraftwerk Betreiber (Germany)

Desuperheat Removing superheat from steam typically by injecting high-purity water or steam condensate. Duct burner A means of auxiliary firing in many combined cycle plant heat recovery steam generators (HRSG’s). Feedwater heater A heat exchanger used to raise the feedwater temperature. Low-pressure feedwater heaters are typically located ahead of the deaerator; high-pressure feedwater heaters are typically located after the deaerator.

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Change History: May 2015. A. Banweg provided minor updates on the topics of phosphate treatment, oxygenated treatment, and condensate treatment. Added references 6, 31, 38, and 39. Also corrected typos mS/cm to mS cm−1.

Reference Module in Materials Science and Materials Engineering

doi:10.1016/B978-0-12-803581-8.01691-X

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Boiler and Feedwater Treatment

Mud drum The lower drum in a boiler circuit that acts as a point of recirculation and collects suspended solids for removal by bottom blowdown. Mud drum attemperator A steam to water heat exchanger located in the mud drum used to control steam temperature. Specific conductivity The measure of the ability of water to conduct an electric current. Often related to the dissolved solids content of the water.

1

Steam blanketing A condition in a boiler tube where the steam water mixture stratifies into separate layers. This is more likely to occur in an inclined tube. Sweetwater condenser A heat exchanger that cools a portion of generated steam so that the resultant condensate can be used for attemperation of the superheated steam.

Introduction

Water is abundant on our planet. However, very little is suitable for human consumption (potable) without pretreatment. It is very rare that even potable quality water is suitable for makeup water to a boiler system without additional pretreatment. There are many technical organizations around the world that publish guidelines on recommended feedwater and boiler water specifications. There are the European Standard1 and the Vereinigung Grosskraftwerk Betreiber (VGB)2 in Europe, the American Society of Mechanical Engineers (ASME)3 and Electric Power Research Institute (EPRI)4 in the United States, and the Japanese Industrial Standards (JIS)5 in Asia. These guidelines are generally developed by a consensus of committee members that can include equipment manufacturers, industrial equipment operators, water treatment companies, and experienced consultants. Some of these guidelines focus more on a particular segment of the industry than another. For example, the EPRI guidelines focus on boiler systems in the electric utility industry, whereas ASME focuses on boiler systems in industrial applications. Others may try to cover the entire scope of boiler applications. These guidelines are, for the most part, very general, and only in rare cases do these guidelines specify a treatment chemistry or treatment chemical to use. This is because the actual treatment chemistry used is a function of the makeup water quality available, the desired steam purity to be produced, and economic considerations. For instance, the ASME guidelines relate steam purity to the appropriate boiler water limits but do not specify feedwater purity in terms of total dissolved solid content. This is an economic decision left to the individual boiler system operator to decide how much is invested in the pretreatment system to purify the water as opposed to higher blowdown rates to maintain the boiler water dissolved solid limits. The EPRI guidelines are an example of such an exception from these more general types of guidelines, in that they are intended for a very specific audience of a narrowly defined type of boiler system – in this case, the electric utility industry. Finally, since these guideline committees are continually updating their guidelines based on the most current information available and the latest operating experience, they will only be referenced in the chapter. For actual guidelines, the most current relevant issue of the chosen guideline should be obtained for use in a particular boiler system. This chapter addresses the subject of makeup water, feedwater, boiler water, and steam and condensate treatment in steam boiler systems. Feedwater by definition is the combination of returned condensate and fresh makeup water (Figure 1). This make up portion can range from 0 to 100% in industrial steam-generating systems, in which the steam-generating system is generally part of an industrial or manufacturing plant. Figure 2 is a typical field-erected water tube industrial boiler. Notably different are steam-generating systems in the electric utility industry, which are dedicated only to the production of electric power and have condensate return rates consistently greater than 95% of the feedwater by design. Figure 3 is a typical drum-type utility boiler.

2

Make Up Water Treatment

The type of pretreatment will dictate the necessary further chemical treatment that the water will require prior to use in the particular steam-generating system. The possible types of pretreatment are 1. 2. 3. 4. 5. 6.

clarification, cold lime softening, hot lime softening, zeolite (ion exchange) softening, demineralization, and reverse osmosis (RO).

Clarification is used to reduce the suspended solids of the water; cold lime, hot lime, and zeolite softening are used to reduce only the hardness, that is, the calcium and magnesium content of the water; RO and demineralization are used for a more effective reduction of the total dissolved solids content of the water. When precipitating processes for hardness removal such as cold or hot lime softening are used as pretreatment, the effluent water pH is inherently high, in excess of a pH of 10.0. pH control is a very important aspect of water treatment to protect the

Boiler and Feedwater Treatment

Makeup

3

Steam

Feedwater Continuous blowdown Condensate

Intermittent blowdown

Figure 1 Schematic of typical boiler flows.

Figure 2 Field-erected water tube industrial boiler. Courtesy of the Babcock and Wilcox Co., Barberton, Ohio, USA.

materials of construction of these systems. A secondary benefit of these precipitation processes is the partial reduction of the water’s silica content. When these precipitating processes are used to reduce water hardness, it is important to remember to measure the total hardness of the effluent water. This involves an acid digestion step, as opposed to the normal soluble hardness tests, since there can be suspended solids of hardness in the effluent from these systems that the soluble hardness test would not detect and must be accounted for in the chemical treatments applied.

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Boiler and Feedwater Treatment

Steam drum

Reheat superheater

Platen secondary superheater

Primary superheater

Secondary superheater

Economizer Wing walls

Furnace Overfire air ports

SCR

Low NOx burners

Trisector air heater

B&W roll wheelTM pulverizers

Forced draft fans

Primary air fans

Figure 3 Natural circulation drum-type utility boiler. Courtesy of the Babcock and Wilcox Co., Barberton, Ohio, USA.

Softened makeup water is generally acceptable for lower-pressure boiler systems. Higher-pressure systems will require more purified water such as that treated by RO or a demineralization processes. A high percentage of condensate return in the feedwater can also produce high-purity feedwater. Zeolite softening, an ion exchange process using strong acid cation resin in the sodium form, can also be used to remove the hardness from the water. This process can be applied in conjunction with one of the precipitating softening processes or alone. Ion exchange softening can also include a dealkalizer for the alkalinity reduction of the makeup water. This is typically done using anion resin in the chloride form, but several configurations are possible. Conventional ion exchange demineralization of makeup water typically involves a two-bed demineralization system. Most common is a strong base cation resin bed in the hydrogen form, followed by a strong base anion bed in the hydroxide form. There may or may not be a decarbonator in between. There are many configurations of these systems available, which vary from cocurrent to counter current regeneration configurations. They may also include alternative resin types, weak acid resin, or weak

Boiler and Feedwater Treatment

5

base resin with multiple cation and anion units, depending on the starting water composition, the final desired water purity and local economics. For the highest water purity requirements, a mixed-bed resin unit is applied at the end of the process. RO, a membrane-based water purification system, can be used to reduce the total dissolved solids content of the water. There are numerous configurations of the RO process available that can be chosen based on the water’s composition to be treated, the level of effluent purity required versus the percentage of recovery required and the local economics of chemical cost, power cost, and labor cost. The details of these systems are beyond the scope of this chapter and will not be addressed in this chapter. The reader is directed to numerous literature sources available on these topics for specific information.6 RO, a semipermeable membrane process, reduces the dissolved substances in water, but this removal is not complete, and effluent or permeate may not yet be suitable for boiler makeup water. A conventional mixed-bed resin polisher, electrodialysis (ED), or some modification of this process can follow the RO. ED is a membrane process in which mineral salts and other ions are transported through ion-permeable membranes from one solution into another under the influence of a direct current electrical potential. Electrodeionization (EDI) is a modification of the ED process that combines ED with self-regenerating mixed-bed ion exchange resins installed between the membranes. Electrodialysis reversal (EDR) is another modification of ED in which the electrical field is periodically reversed to provide a self-cleaning process that can run at increased recovery rates. Though these electrochemical processes have been available commercially and are capable of producing high-purity water, they are becoming more commonly used in the boiler makeup water treatment application, whereas in the past they were more likely to be seen in the microchip manufacturing industry. Conventional mixed-bed resin deionization is much more common in the production of high-purity boiler makeup water.

3

Feedwater Treatment

Corrosion protection in the feedwater system is generally achieved by mechanically and chemically removing dissolved oxygen from the feedwater and buffering the feedwater pH into a range suitable for the system materials of construction. Feedwater must generally be deaerated for industrial steam boiler applications, but there are special circumstances in which full deaeration is not recommended. These are discussed separately.

3.1

Dissolved Oxygen Control

Dissolved oxygen removal from the feedwater is typically accomplished in a deaerating heater or deaerator in which steam is used to remove the dissolved oxygen from the feedwater. Each of these pieces of equipment has its own dissolved oxygen removal efficiency. In some very low-pressure applications, there may only be a feedwater tank in which makeup water and condensate are mixed, which may or may not be actively steam sparged or otherwise heated to try to remove the dissolved oxygen. The goal of the mechanical deaeration process is to reduce the dissolved oxygen content of the feedwater to less than 7 ppb for a system using a true deaerator. Dissolved oxygen in the feedwater can cause pitting corrosion damage of the feedwater system components. More complex feedwater systems can include both low- and high-pressure feedwater heaters in addition to an economizer. Additionally, vacuum degasifiers or deaerating condensers can be used for dissolved oxygen removal. Recently, a semipermeable membrane process7 has also been developed to reduce the dissolved oxygen content of water. These membrane systems have been used in laboratory environments for more than 25 years but have only recently become commercially feasible for industrial applications. This membrane process can use a combination of vacuum and stripping gas arrangements to deaerate the water. The membrane modules can be arranged in series to produce ppb level oxygen concentrations in the final water. These membranes, dependant on the pH of the water, can also remove carbon dioxide. RO pretreatment is recommended ahead of the gas membrane to prevent fouling. A conventional deaerator provides only limited removal of carbon dioxide, based on the typical alkaline pH of the water where the carbon dioxide would exist as the bicarbonate ion, not as a gas. After any of these mechanical/thermal deaeration processes, a chemical oxygen scavenger can be applied to further reduce the dissolved oxygen content of the feedwater (Table 1). Sodium sulfite is the most common chemical oxygen scavenger used in low-pressure boiler systems. It is also available in a catalyzed form, which increases the speed of reaction with the dissolved oxygen. This can be important when the mechanical deaeration process does not provide sufficient residence time. Sodium sulfite is a nonvolatile inorganic compound that does contribute dissolved solids to the feedwater and the boiler water. This dissolved solids contribution prevents its use in feedwater that is to be used as attemperator spray or desuperheat spray for steam temperature control, as these solids would become impurities in the steam. The control of sodium sulfite is generally based on maintaining a sulfite residual concentration in the boiler water. This can be a problem in a system where the feedwater system deaeration process and chemical injection point do not provide sufficient residence time and temperature for the chemical oxygen scavenging reaction to be completed prior to the feedwater entering the

6

Boiler and Feedwater Treatment

Table 1

Oxygen scavengers used in steam-generating systems

Scavenger

Primary reaction

Comments

Hydrazine Hydrazine decomposition Sodium sulfite Carbohydrazide

N2H4 þ O2-2N2 þ 2H2O 3N2H4-4NH3 þ N2 2Na2SO3 þ O2-2Na2SO4 (H2N–NH)2CO þ 2O2-2N2 þ 3H2O þ CO2

N,N-Diethylhydroxylamine

4(CH3CH2)2NOH þ 9O2-8CH3COO
þ 9H þ þ 2N2 þ 6H2O

Hydroquinone

C6H4(OH)2 þ 1/2O2-C6H4O2 þ H2O

Erythorbate Methyl ethyl ketoxime

C6H4 O6 þ 1/2O2-C6H5O8 þ H2O 2CH3(C2H5)CNOH þ O2-N2O þ 2CH3(C2H5)CO þ H2O

Toxicity and handling issues At temp. 4200 1C Also NaHSO3, Na2S2O5, NH4HSO3 Forms hydrazine at temperature 4150 1C, NH3, N2, and H2 on decomposition Frequently fed with hydroquinone, acetic acid, CO2, acetaldehyde, NH3 at temperatures above 275 1C Acetates, CO2 decomposition products, toxicity issues CO2, lactic acid, decomposition products Frequently fed with hydroquinone, NH3, CO2, ketones, aldehydes on decomposition

steam drum of the boiler. Oxygen scavengers and dissolved oxygen can coexist in the feedwater, and in such a situation, pitting corrosion of pre-boiler components can occur. Because of the dissolved oxygen’s high volatility, the oxygen preferentially goes into the steam phase when the feedwater enters the boiler steam drum, leaving the unreacted sulfite as an apparent residual in the boiler water. Another point of oxygen ingress into the system not to be overlooked is a leak path through the boiler feed pump seals. It is wise not only to monitor the temperature and pressure operating conditions of the deaerating device for proper operation but also to periodically measure the feedwater dissolved oxygen content directly after the boiler feed pump. Sodium sulfite can also produce some acidic gaseous decomposition products, such as sulfur dioxide, that will be carried out of the boiler in the steam. This can be significant at boiler operating pressures above 4.1 MPa g (600 psi g). These decomposition products can cause low steam condensate pH. Hydrazine is another available oxygen scavenger that has been used primarily in higher-pressure boiler applications. It is a volatile compound that can be used in feedwater that is used for steam temperature control by attemperation or desuperheating. However due to its status as a suspect carcinogen, its use in industry has declined. When it is used, a closed feed system is typically required. Given these health concerns, alternatives to hydrazine have been developed. The most common of these are carbohydrazide, erythorbate, diethylhydroxylamine, hydroquinone, and methylethyl ketoxime. Many of these oxygen scavengers also function as passivating corrosion inhibitors. Each is an organic compound that has its own temperature limitations. Decomposition products can vary from only carbon dioxide to several organic acids and other organic compounds. Some decomposition products are more undesirable than others, and the amount of these decomposition products can be application-specific, depending on system temperatures and metallurgy. Each application should be evaluated based on the benefit provided versus the potential undesirable effects of the decomposition products. As a note, commercially available erythorbate can be either in the acid form or in the sodium salt form. The sodium salt form is nonvolatile, which restricts its use if the feedwater is used as spray attemperation or in desuperheating.

4

pH Control

Feedwater pH adjustments to slightly alkaline conditions are used to minimize corrosion of the feedwater system piping and components, and the resultant corrosion product transport to the boiler. Caustic, neutralizing amines or ammonia are commonly used for this task. Obviously, caustic cannot be used where the feedwater is used as spray attemperation for steam temperature control. The more common amines in use are morpholine, cyclohexylamine, monoethanolamine, diethanolamine, and methoxypropylamine.

4.1

All Volatile Treatment (Reducing)

The feedwater target pH range is a function of the feedwater system metallurgy. In the past, a target pH range of 8.8–9.2 had been specified for feedwater systems containing mixed metallurgy – typically heat exchanger components constructed of copper alloys. Recent work8–10 has shown that reducing conditions in the feedwater system, an oxidation–reduction potential (ORP) of
300 to
350 mV at 25 1C (77 1F), measured between a Pt electrode and a Ag/AgCl (saturated KCl) reference electrode, at the deaerator inlet, are necessary to minimize copper corrosion and corrosion product transport in these mixed-metal feedwater systems. This

Boiler and Feedwater Treatment

7

work showed that the feedwater pH is a secondary control parameter, which should be restricted to a pH range of 9.0–9.3. EPRI has used the terminology AVT(R), all volatile treatment (reducing) to describe this treatment chemistry. In practice, many systems are not able to reach these low levels of ORP, but copper corrosion and copper corrosion product transport have been successfully reduced in some systems with feedwater ORP levels of even
200 to
100 mV at 25 1C (77 1F), measured between a Pt electrode and a Ag/AgCl (saturated KCl) reference electrode. This treatment chemistry is expected to reduce corrosion production transport to the boiler system for all operating pressure boiler systems, but is most critical for the very high-pressure boiler systems used by the electric utility industry, where at their operating pressures (416.4 MPa g (42400 psi g)), copper has volatility properties into the high-pressure saturated steam and has caused deposition problems in the high-pressure steam turbine. This deposition in the steam turbine can limit steam throughput and megawatt output. Although the consequences of high copper corrosion product transport to most industrial boiler systems are not as dire as in the very high-pressure electric utility boiler systems, only more frequent chemical cleaning of the boilers may be required; this new information on copper corrosion and strategies to minimize it should also be applied to industrial mixed metallurgy feedwater systems. Theoretically these reducing conditions should be maintained by lay-up practices even when the system is out-of-service, to prevent the reversion of the more protective, more reduced form of copper oxide, cuprous oxide, Cu2O, formed in service, to the more oxidized and less protective form of copper oxide, cupric oxide CuO. Based on the actual circumstances of the out-of-service period, it may not be practical to maintain a reducing environment. This work8,9 also showed that the desired reducing environment was difficult to achieve by the addition of excessive amounts of a chemical reducing agent such as an oxygen scavenger to compensate for a mechanical problem in the system such as a malfunctioning DA or high levels of air in leakage into a condenser or hotwell. Excessive chemical feed can have other detrimental consequences. For an all-steel metallurgy feedwater system, the feedwater pH target range is somewhat more alkaline pH ¼ 9.3–9.6. For most industrial boiler feedwater systems, definitely those with softened water make up even those with demineralized make up water or high percentages of condensate return, it is still advisable to fully deaerate the feedwater and treat the system with a chemical oxygen scavenger to prevent dissolved oxygen pitting corrosion damage to the feedwater system components, as previously discussed.

4.2

Flow Accelerated Corrosion

In boiler systems in dedicated electric utility service, where the typical percentage of condensate return in the feedwater is over 95%, the feedwater most likely will be pure enough to make the system susceptible to flow accelerated corrosion (FAC) damage.11– 14 FAC is a corrosion mechanism that can cause corrosion damage and failures in feedwater systems including economizers, feedwater heaters, and piping. EPRI has compiled a significant amount of information on this topic as it relates to boiler systems in dedicated electric utility service.15 FAC is a very localized damage mechanism that affects predominantly, areas of flow turbulence in the feedwater system. It is a primarily hydrodynamic phenomenon that prevents the formation of the normal protective oxide (magnetite) coating to form on carbon steel and prevent any further metal loss. FAC is a process whereby the normally protective oxide surface dissolves into a moving fluid. The most susceptible systems are typically all-steel, and employ very high-purity feedwater, due to the purity prerequisite of the steam purity required by the steam turbine in these systems. A significant amount of research has been done on this topic in power plants and is very well documented.15 FAC is possible at a water temperature range of 100–250 1C (212– 482 1F), but there seems to be a maximum susceptibility at about 150728 1C (300750 1F). Even though FAC is primarily a hydrodynamic phenomenon, those mechanical parameters that control velocity and turbulence are fixed and not easily changed in an existing system. The research work has identified two water chemistry parameters that influence FAC behavior that can be optimized–feedwater pH and ORP.

4.3

All Volatile Treatment (Oxidizing)

EPRI has developed a feedwater treatment philosophy for boilers in the electric utility service industry that has been termed AVT (O),4 all volatile treatment (oxidizing), to minimize the potential for FAC in these systems. With AVT(O) treatment, no chemical oxygen scavenger is fed and a nominal amount of dissolved oxygen, (typically o10 mg l
1, o10 ppb) is considered acceptable. This is expected to result in an ORP of
50 to þ 50 mV, measured between a Pt electrode, and a Ag/AgCl (saturated KCl) reference electrode. This condition is considered less susceptible to FAC than the completely oxygen deficient-reducing conditions of AVT(R) in this high-purity feedwater. Feedwater cation conductivity required for AVT(O) is less than 0.2 mS cm
1. ORP measurements in many AVT(O) systems have shown, that even in the absence of a chemical oxygen scavenger, they can be in a very reducing condition due to the mechanical efficiency of their dissolved oxygen removal systems. In these situations then some dissolved oxygen may have to be added to attain a true AVT(O) environment.

8

Boiler and Feedwater Treatment

All the discussion on ORP measurement of feedwater up to this point has been regarding the measurement of the ORP of a sample depressurized and cooled to room temperature, 25 1C (77 1F). Room temperature ORP measurements have had problems with a lack of sensitivity and response. The capability to measure the feedwater ORP at system temperature and pressure has been developed, AT ORP™ (originally known as @T ORP™).16,17 The potential is measured against an external pressure balanced reference electrode (Ag/AgCl//0.1 N KCl). This technology is much more responsive to system changes that affect ORP. These at temperature ORP measurements can be made at feedwater temperatures up to 260 1C (500 1F). Feedwater pH is another chemistry parameter that affects FAC, and for an all-steel feedwater system, typically the more alkaline the better (pH 49.2 up to about 10.0). Even though the feedwater system may be all-steel, there may be a copper alloy condenser that could limit the feedwater pH adjustment to prevent yellow metal attack of the condenser that can occur when ammonia is the alkalizing agent or a decomposition product. This near-neutral ORP control, AVT(O), is quite acceptable for high-purity boiler feedwater systems such as those in the electric utility industry, in which the level and consistency of feedwater purity is high. Industrial boiler feedwater systems employing highpurity feedwater are also potentially susceptible to FAC, but the possible chemistry-related corrective actions are not nearly as clear. In industrial boiler systems, even when make-up water is demineralized, the required level of purity for this treatment – o0.2 mS cm
1 – is rarely achieved. Additionally, because of the lower percentage of condensate return and the very significant potential for constant low levels and periodic high levels of contamination, feedwater purity can be very inconsistent. For these industrial systems, the simultaneous presence in the feedwater of dissolved oxygen and any feedwater contamination provides the potential for oxygen pitting damage of the feedwater system, especially heat exchanger components, such as an economizer. From the existing research work, it is unclear how pure feedwater must be in order for dissolved oxygen to act as a corrosion inhibitor rather than cause the pitting damage common in industrial systems. From the experience with AVT(O) and oxygenated treatment (OT), feedwater cation conductivity of o0.2 and o0.15 mS cm
1 respectively are conditions in which dissolved oxygen acts as a corrosion inhibitor. But even the OT guidelines recommend ceasing oxygen feed and going to an AVT(O) treatment when cation conductivity exceeds 0.3 mS cm
1. There are no further guidelines for acceptable higher levels of cation conductivity in the feedwater for AVT(O). OT is discussed in the next section. This FAC mitigating philosophy of AVT(O) near-neutral ORP can also be accomplished in industrial systems by feeding a very low level of one of the available organic oxygen scavengers/passivators. In this treatment scheme, the oxygen scavenger/passivator is not fed in the stoichiometric ratio to scavenge the dissolved oxygen but rather is fed at a rate to passivate the steel and provide the neutral ORP target. The feedwater concentration needed to accomplish this ORP is unique to each of the scavengers (hydroquinone, erythorbate, carbohydrazide, diethylhydroxylamine, methylethyl ketoxime). In this treatment, when there is an excursion in the chemistry or dissolved oxygen concentration due to mechanical problems, the scavenger feed is able to compensate. Note that sodium sulfite, although it is an oxygen scavenger, cannot be used for this purpose, as it does not appear to have any passivating properties for steel. Finally, monitoring feedwater ORP does not supply quantitative information regarding FAC, only qualitative information. It has been found that measuring the soluble iron concentration of the feedwater18–20 at various points in the system can provide more quantitative information regarding FAC. Given that FAC is a very localized damage mechanism related to flow turbulence, it is important to sample the feedwater before and after a feedwater system component with a large surface area subjected to local flow turbulence for this soluble iron testing. Such a component is typically an economizer or feedwater heater with heat transfer surfaces constructed of carbon steel. Detecting a significant increase in the soluble iron content of the feedwater between the inlet and outlet indicates a potential for FAC in the system. Then optimizing feedwater treatment chemistry parameters (feedwater pH first, then ORP/oxygen scavenger feed) individually and reviewing their impact on the change in feedwater soluble iron content demonstrates the potential impact that feedwater chemistry changes can have on FAC in the feedwater system. As soluble iron in the water is relatively unstable, soluble iron determination requires careful sample handling to minimize the potential to oxidize the soluble iron in the sample. Feedwater dissolved oxygen content should be less than 20 ppb, and it has been found that it is best to take the sample directly into the reagent to preserve the iron in the soluble state. There have been a number of different ferroin compounds used to determine iron spectrophotometrically.18,19 One of the most widely used compounds is 3-(2-pyridyl)-5–6-bis (4-phenylsulfonic acid)-1,2,4-triazine, monosodium salt. The test procedure involves collecting samples directly into an acid-cleaned, iron-free container containing the ferroin reagent. Stainless steel sample lines are required. Even though this soluble iron testing gives a more quantitative picture of the FAC susceptibility of a system and this information can be used to optimize feedwater chemical treatment, it cannot identify a specific feedwater system component that could be experiencing a particularly high local rate of FAC damage. For this reason, it is still recommended that such a system have periodic nondestructive testing performed on susceptible components (tees, elbows, piping, downstream of valves, flow orifices, etc.) especially those that are in the more prone temperature environment, with water at 150728 1C (300750 1F). It has been found that in most cases, feedwater chemistry optimization has been able to reduce FAC rates in high-purity industrial boiler feedwater systems prone to FAC but not eliminate them, even in some cases where the treatment has been converted to AVT(O). But as the research work11 on FAC has shown, commercially available low-chrome alloys (41% chromium content) are much less susceptible to FAC than carbon steel. Replacing a carbon steel component found to be thinning due to FAC with one of these low-chrome alloy alternatives has eliminated future FAC damage in all but the most extreme situations.

Boiler and Feedwater Treatment 4.4

9

Oxygenated Treatment

21–26

OT is a feedwater treatment developed for once-through boilers in the electric utility industry in Germany in the 1960s. Prior to OT, these boilers were treated with all volatile treatment (AVT) using ammonia and hydrazine. With this conventional AVT treatment, these boilers required frequent chemical cleaning to prevent the accumulation of corrosion products from the feedwater system (primarily iron oxide) in the boiler. These deposits caused pressure drop increases in the boiler’s flow circuitry and insulating deposits on high heat transfer areas of the boiler, which could lead to overheating damage. A once-through boiler is an inherently high-purity feedwater system, since the feedwater purity must meet the steam turbine’s steam purity requirement. Most of the once-through boilers in Germany operate at subcritical pressures, whereas most of the oncethrough boilers in the United States operate at super-critical pressures. Most of these systems have all-steel feedwater systems and full-flow condensate polishing. In these systems, it was found that low levels of dissolved oxygen added to this high-purity feedwater acted as a corrosion inhibitor, producing a more protective oxide on the steel than conventional AVT. This reduced corrosion product transport to and accumulation in these boilers. Most of the once-through boilers in operation worldwide today have now been converted to OT. Some boilers on OT treatment in Germany have never required chemical cleaning. Once-through boilers in the United States that have converted to OT have significantly extended the time required between required chemical cleanings. Typical control parameters for OT are a feedwater cation conductivity of less than 0.15 mS cm
1; feedwater pH and dissolved oxygen can be controlled by what is termed the combined method in which the feedwater pH is 8–9 and the dissolved oxygen content is 30–150 mg l
1 (30–150 ppb). Only ammonia can be used in this treatment as the alkalizing treatment chemical; dissolved oxygen degrades the more complex amines, increasing the cation conductivity. OT is only occasionally used on high-pressure drum-type boilers because they rarely have the prerequisite feedwater system metallurgy and the consistent level of feedwater purity required, which typically requires a full-flow condensate polishing system. Finally, the required chemical cleaning requirements for drum-type boilers that do meet the metallurgy and feedwater purity requirements are already quite long; therefore, OT does not provide the same economic benefit as it does to once-through boilers. OT for these drum boilers could provide a benefit regarding FAC potential in their feedwater systems, but this benefit is also provided to some degree by the AVT(O) feedwater treatment. When OT is used on a conventional drum boiler, typical feedwater control parameters are pH ¼ 9–9.6 and dissolved oxygen content 30–50 mg l
1 (30–50 ppb). Additionally boiler water dissolved oxygen content should be limited to o5 mg l
1 (o5 ppb) in the recirculating boiler water sample from a downcomer, not the normal continuous blowdown sample point.

5 5.1

Boiler Water Treatment Residual Phosphate Treatment

Boiler water internal treatment options are dependant on the type of makeup water pretreatment, percent condensate return, and boiler operating pressure. For softened makeup water systems, one of the most common internal treatments is residual phosphate treatment, a precipitating treatment for the hardness contaminants in the feedwater. This treatment chemistry is designed to purposefully precipitate the feedwater hardness contaminants into more desirable, less adherent forms than if they precipitated on their own in the boiler due to their retrograde solubility characteristics. The intent is to precipitate calcium as basic calcium phosphate and magnesium as magnesium hydroxide by maintaining an appropriate boiler water orthophosphate residual and a free hydroxide concentration. The orthophosphate concentration must be measured on a filtered (0.45 micron filter) boiler water sample. A synthetic organic polymer or naturally occurring organic material such as lignins or tannins may be used to help disperse the resultant precipitated suspended solids. The precipitated calcium and magnesium contaminants, though in a more desired form, are still difficult to remove from an operating boiler via the continuous blowdown. This is because they are entrained in the boiler’s internal circulation between the downcomer and riser circuitry, which is many times the flow rate of the steam that the boiler actually produces. This circulation continually passes the particulates past the high heat transfer areas of the boiler, where they can form deposits. Suspended solids caught up in the boiler’s internal circulation are also not removed very effectively by a boiler’s intermittent blowdown system (mud drum blowdown), if the boiler has this capability. Because of the limited effectiveness of the boiler blowdown systems in removing suspended solids, the success of residual phosphate treatment is very much dependent upon minimizing the hardness contaminants in the feedwater and potentially cleaning the boiler, chemically or mechanically, periodically, to control deposit accumulation in the boiler. Residual phosphate chemistry is controlled by maintaining an orthophosphate residual in the boiler water that is chosen as a function of the boiler’s operating pressure, Table 2. Free hydroxide levels in the boiler water are typically maintained at a level of three times the boiler water silica concentration to aid in maintaining silica mineral solubility in the boiler water. In higherpressure boiler applications (44.1 MPag (4600 psi g)) where volatile silica transport into the saturated steam is a concern, or anytime the steam being produced is for use in a condensing steam turbine, maximum boiler water silica concentrations are

10

Boiler and Feedwater Treatment

Table 2

Typical control limits for residual phosphate treatment Drum pressure (psi g; MPa g)

Boiler water component (ppm)

TDS (max)a Phosphate (as PO4) Hydroxide (as CaCO3) Sulfite Silica (as SiO2) maxb

150 (1.0)

300 (2.1)

600 (4.1)

900 (6.2)

4000 30–60 300–400 30–60 100

3500 30–60 250–300 30–40 50

3000 20–40 150–200 20–30 30

2000 15–20 120–150 15–20 10

a

The limits on TDS will vary with the design of the boiler and with the needs of the system with regard to steam purity. Example silica values are listed but if silica volatility is a concern, such as condensing steam turbine applications, available pressure dependant and pH dependant control curves on boiler water silica concentration should be used. Silica may be carried at higher levels if there are no condensing turbines in the cycle. In any case, maintain an OH/SiO2 ratio of at least 3/1 to inhibit silica deposition. b

maintained to limit the silica concentration in the saturated steam to the specified limit for the turbine (typically 10–20 mg l
1 (10–20 ppb) silica in the steam).

5.2

Steam Purity

Boiler water total dissolved solids are maintained at or below a maximum value to control the overall purity of the saturated steam required. More stringent steam purity limits are required for that steam when it is to be used in a condensing steam turbine application as opposed to a process heating application. With the exception of silica, which has vaporous solubility characteristics in saturated steam, all other nonvolatile species of concern in boiler applications at less than 13.7 MPa g (2000 psi g) end up in the steam as a result of mechanical carryover of boiler water droplets that have passed through the mechanical separating equipment in the steam drum. Therefore, the steam purity is directly proportional to the boiler water purity. The restrictions on boiler water total dissolved solid limits to maintain the same steam purity do vary with boiler operating pressure and are more restricted at higher operating pressures because the mechanical steam/water separation process is more efficient when the density difference between the steam and water phases is greater. Sodium salts and copper oxides, considered nonvolatile at lower operating pressures exhibit volatility characteristics above 16.4 MPa g (2400 psi g). This mode of transport into the steam then must also be considered and controlled by the maintenance of the appropriate boiler water concentration limits for the desired steam purity. In addition, when attemperation is used for final steam temperature control, the impact of that attemperation water on the final steam purity must also be considered, in the design stage as well as while diagnosing steam purity problems. The potential sources of attemperation water are feedwater (if it is pure enough), condensate and a sweetwater condenser. A sweetwater condenser is typically a shell-and-tube heat exchanger that condenses saturated steam with incoming feedwater. That condensed saturated steam is then used as attemperation water for steam temperature control. Each of these sources of attemperation water can be potentially contaminated and have an impact on steam purity. A mud drum attemperator may also be used for steam temperature control. This is typically a heat exchanger located in the mud drum. By design, there is no intended contact between the steam and the boiler water, but in the event of a leak in the exchanger, boiler water can contaminate the steam.

5.3

Chelant Treatments

Realizing the shortcomings of residual phosphate chemistry in the way it handles feedwater hardness contamination (precipitation), alternative treatment chemistries were developed. The first was the use of chelants to solubalize the hardness contaminants. The most common chelants used were ethylenediaminetetraacetic acid (EDTA) and nitrilotriacetic acid (NTA). Both EDTA and NTA form soluble complexes with calcium and magnesium that are stable to relatively high temperatures, up to 6.8 MPa g (1000 psi g). The removal of hardness contaminants from the boiler, now in a soluble form, are no longer limited by the continuous blowdown’s limited ability to remove suspended solids from the circulating boiler water. If the species in question is soluble in the feedwater, remains soluble in the boiler water and is nonvolatile, the continuous blowdown removes that species at 100% efficiency. Theoretically, if the required stoichiometric ratio of chelant to hardness were maintained, there would be no accumulation of hardness-based deposits in the boiler. However in practice, there are variations in the level of hardness contaminants in the feedwater, and some overfeed must be applied continually to account for these variations. This overfeed is typically controlled to result in a small residual chelant concentration in the boiler water above that required for the actual hardness. It was found that this boiler water chelant residual must be controlled very tightly because high levels of the residual can result in corrosion of the boiler base material. This corrosion is most likely to occur in areas of high fluid velocity or turbulence in the boiler. For this reason, chelant residual control limits vary as a function of boiler operating pressure and range from about 1–5 mg l
1 (1–5 ppm).

Boiler and Feedwater Treatment

11

Chelants have been applied at boiler pressures over 6.8 MPa g (1000 psi g) early in their history but later were only commonly applied up to about 2.7 MPa g (400 psi g) for EDTA and about 6.2 MPa g (900 psi g) for NTA. Today, chelants are rarely used for several reasons. NTA is classified as a suspected carcinogen, the potential corrosions problems, and challenges in controlling the required residual level and alternative treatment chemicals have been developed.

5.4

All-Polymer Treatment

Technically, the ability of the chelant chemistry to maintain the solubility of feedwater hardness contaminants is a much more effective way to control hardness deposit accumulation in boiler systems than residual phosphate treatment. Synthetic organic polymer chemistries have been developed that also have chelating abilities for hardness control. These are based typically on polyacrylate or polymethacrylate polymers. Such synthetic organic polymers can be applied in what is termed an all-polymer treatment, the purpose of which is the same as the chelant chemistry: form a soluble complex with calcium and magnesium and maintain that soluble complex at boiler water conditions to allow for the efficient removal of these contaminants from the boiler in the continuous blowdown as dissolved solids. In addition to the ability of these polymers to maintain soluble hardness contaminants, they are typically anionically charged, whereas suspended solid contaminants such as iron oxide tend to be cationically charged. The polymers then also have the ability to disperse particulate contaminants. This dispersion minimizes their ability to agglomerate into larger particles as well as adhere to the heat transfer surfaces of the boiler. But as a suspended solid, there is still the same physical limitation on the ability of the continuous blowdown to remove even these dispersed contaminants from the boiler. There are many synthetic organic polymers in use in boiler water treatment. It is important to note that not all of these polymers have chelant properties relative to calcium and magnesium, and it is only those that do that can be used as an ‘allpolymer’ treatment for feedwater hardness contamination. And even those polymers that do have this chelating ability must be of an appropriate molecular weight for the boiler operating pressure and saturation temperature to function as intended. Polymers that do not have the chelant properties with respect to hardness tend to act only as dispersants and therefore do not have the same effectiveness in handling feedwater hardness contamination. Even though the polymers used in the ‘all-polymer’ technology have chelant properties, they are much weaker chelants than EDTA or NTA. As much weaker chelants, the need to control the excess polymer residual relative to the hardness is much less critical. However as with all solubalizing treatments, the potential for corrosion of the boiler’s base material must be recognized and an appropriate control strategy used. As there are many synthetic polymer treatments on the market today and most are offered as proprietary treatment chemistries, hopefully the end user can ask the appropriate questions based on the information provided, such as what the purpose and abilities of their available products are and what the control limits and control strategies are, to decide while choosing between various offerings to best meet his/her needs. Polymeric dispersants are also used within other treatment philosophies, such as in chelant treatments to disperse iron oxide contaminants and in residual phosphate treatment to disperse the resultant calcium and magnesium precipitated suspended solids. In these cases, however, the concentration of the polymers to hardness is much less than the stoichiometric requirement to solubalize the hardness, and as such they only act as a dispersant and do not compete with the primary intended purposes of the chelant or phosphate chemistry. In industrial boiler systems, there have been many mixed treatment chemistries that have had mixed success–chelant/polymer, chelant/phosphate, polymer/chelant/phosphate, etc. There are too many to address specifically.

5.5

Coordinated Phosphate Treatment

In the past, it was more common to find high-purity feedwater in only high-pressure boiler applications 46.8 MPa g (41000 psi g). Today the use of high-purity makeup water in low-pressure boilers is much more common. Coordinated phosphate chemistry27 was developed as a response to caustic embrittlement failures of boiler drums. In the early days of boiler water treatment, prior to the development of efficient make-up water pretreatment systems, coagulation internal treatments were used. This type of treatment used soda ash (Na2CO3) to precipitate the hardness salt contaminants into the desired form and then added organic materials (tannins and lignin) to condition this precipitated material (sludge) where hopefully it would settle in the mud drum and be removed from the boiler via the intermittent blowdown (mud drum blowdown) practice. The use of soda ash introduced high levels of alkalinity, including free hydroxide or caustic alkalinity, into the boiler water, and at that time boiler drums were constructed by riveting rolled sections of steel plate together. These mechanical joints were prone to leaking. When a leak did occur, the leaking boiler water containing free hydroxide would flash to steam, resulting in very high local caustic concentrations at the site of the leak. Carbon steel is susceptible to stress corrosion cracking failure when it is highly stressed and in contact with high concentrations of caustic. The geometry of the riveted construction provided a location of stress concentration, and the flashing boiler water provided the environment that resulted in the potential for stress corrosion cracking or

12

Boiler and Feedwater Treatment

pH

caustic embrittlement failure of the steel. In the early days of boiler water treatment, these embrittlement failures and sometimes resultant boiler explosions were not uncommon, and there were fatalities. Coordinated phosphate chemistry control was developed as a chemical solution to this problem. Coordinated phosphate chemistry balances the boiler water pH and orthophosphate concentration to a maximum Na:PO4 molar ratio of 3.0:1 to theoretically prevent the formation of free hydroxide in the boiler water. It is important to note that the Na:PO4 molar ratio used in this treatment as well as the other high-purity phosphate chemistries is not determined by directly measuring both the boiler water sodium and phosphate concentration and calculating the ratio but rather is determined by measuring the boiler water pH and orthophosphate concentrate and then plotting that data on a graph similar to Figure 4.

10.7 10.5 10.3 10.1 9.9 9.7 9.5 9.3 9.1 8.9 8.7 8.5 8.3 8.1 7.9 7.7 7.5

Control vectors NaOH

Na3PO4

Na2HPO4 Blowdown NaH2PO4

0

2

4

6

8

10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 Total Orthophosphate as PO4, ppm (mg l–1)

Na/PO4=3.0 Na/PO4=2.30

Na/PO4=2.8 Na/PO4=2.20

Na/PO4=2.60

Figure 4 pH vs. PO4 graph at different Na/PO4 molar ratios.

The reason for this is that in most boiler systems, there are neutral sodium salts present that do not affect the boiler water pH. There can also be contaminants in the makeup water such as organic materials that can decompose to form organic acids in the boiler water, affecting boiler water pH but with no contribution of sodium. With this in mind it is also important to realize that what affects the boiler water pH and phosphate relationship is that which is added intentionally as the treatment chemicals and that other contaminants may concentrate in the boiler water and affect pH (organic materials in the makeup water or sodium leakage (NaOH) from the make up demineralizer). Sodium salts of various phosphate species and sodium-to-phosphate molar ratios and sodium hydroxide may have to be used to buffer the pH into the desired control range in these situations.

5.6

Congruent Phosphate Treatment

Caustic problems in boiler systems were not totally alleviated by the adoption of coordinated phosphate chemistry. This was thought to be due to the solubility characteristics of sodium phosphate salts – a characteristic known as incongruent precipitation. Studies28 showed that precipitation of phosphate from a high temperature (300 1C, 572 1F) sodium phosphate solution having a Na:PO4 molar ratio greater than 2.85:1 always results in an increase in the Na:PO4 molar ratio of the remaining solution, toward or further into the free caustic region above the 3.0:1 ratio boundary. Conversely, when phosphate is precipitated from a solution having a Na:PO4 molar ratio less than 2.85:1, the Na:PO4 molar ratio decreases in the remaining solution, further away from the free caustic region. With a solution Na:PO4 molar ratio of exactly 2.85, the Na:PO4 molar ratio in the precipitated phosphate solids is identical, that is, congruent. Subsequent studies showed that at higher temperatures, the congruent point could be at a Na:PO4 molar ratio as low as 2.6:1. Again, control is based entirely on the relationships of boiler water pH and orthophosphate concentration, endeavoring to keep their plotted coordinates within the appropriate zones on a control diagram (see Figure 1).29 Congruent phosphate30 then is a refinement of the original coordinated phosphate treatment with new boundaries on the Na/PO4 molar ratio; typically a maximum ratio of 2.6:1 and a minimum ratio of 2.3:1. The actual PO4 concentration control range is typically chosen based on boiler operating pressure and the degree of control capability in the plant and the consistency of feedwater quality (purity). Generally, higher phosphate control ranges (10–20 mg l
1 (10–20 ppm)) at lower boiler operating pressures and lower phosphate control ranges (5–10 mg l
1 (5–10 ppm)) at higher boiler operating pressures are employed.

Boiler and Feedwater Treatment

13

When the chosen PO4 control range is less than 2 mg l
1 (2 ppm) in the boiler water, the effect of ammonia or neutralizing amines must be taken into account due to their effect on the boiler water pH measurement at room temperature.31 Even though boiler drums are constructed using welded joints today, most industrial boilers operating at less than 6.8 MPa g (l000 psi g) are constructed with mechanical roll expanded joints to connect the tubes between the steam drum and the mud drum. Therefore, there is still the possibility of a local caustic embrittlement failure of the drum if one of these mechanical joints were to leak and the boiler water contained free hydroxide. Congruent phosphate chemistry provides a level of protection for these boilers from this failure mechanism and would be a preferred choice provided the feedwater purity requirements are met and the boiler is not experiencing phosphate hideout behavior (see the following section) due to the Congruent Phosphate treatment.

5.7

Phosphate Continuum Treatment (Formerly Equilibrium Phosphate Treatment)

Congruent phosphate programs can be difficult to control because of phosphate hideout.32 Phosphate hideout is the simultaneous decrease in the phosphate concentration of the boiler water and an increase in boiler water pH during a load or heat flux increase. Hideout return is the reverse during a load decrease–phosphate concentration increases and boiler water pH decreases. Equilibrium phosphate control solves this problem and has therefore gained acceptance with electric utility drum boiler operators. As phosphate hideout occurs, the phosphate concentration in the bulk boiler water is reduced down to very low remaining equilibrium levels. The boiler water phosphate might drop from a normal 5 mg l
1 (5 ppm) down to 2 mg l
1 (2 ppm) or even less during hideout. Attempts to maintain the original boiler water phosphate levels by adding phosphate during hideout are usually futile, because ongoing hideout simply continues to remove boiler water phosphate down to the equilibrium level. In the past, phosphate hideout had been thought to be associated with the retrograde solubility behavior and incongruent precipitation behavior of sodium phosphates, but laboratory research work33 has shown that phosphate hideout is actually the temperature-dependent reaction of low Na:PO4 molar ratio compounds in the boiler water with magnetite. These reactions are significant when boiler water Na:PO4 molar ratios are 2.3–2.6:1, but are essentially nonexistent when the boiler water Na:PO4 molar ratio is greater than 2.85:1. During phosphate hideout, phosphate wastage of the boiler metal can result due to the concentration of low Na:PO4 molar ratio materials in high-heat flux zones. Maracite (NaFePO4) and/or Iron Phosphate (FePO4) are the residual corrosion products found on boiler tubes damaged by the phosphate wastage mechanism.34 Phosphate hideout and phosphate wastage are more likely at higher boiler operating pressures but are also possible in lowerpressure boilers with high local heat fluxes. Phosphate wastage corrosion predominantly occurs in conventional boilers operating at greater than 13.8 MPa g (2000 psi g), although it has been seen in an industrial boiler operating at 6.9 MPa g (1000 psi g) that was experiencing steam blanketing. It is also common in vertical shell-and-tube steam generators; these are commonly unfired process boilers with flat tube sheets and deep oxide sludge deposits on the tube sheet, which is generally at the inlet of the highest process gas temperature. In addition, heat recovery steam generators (HRSG) commonly used in combined cycle plants with duct burners are also prone to phosphate hideout and the potential for phosphate wastage, especially when duct burners are in use. Equilibrium phosphate control32 makes no attempt to carry boiler water phosphate concentration above its hideout equilibrium level. Equilibrium phosphate levels vary from boiler to boiler, depending on the severity of hideout conditions and must be determined by testing for each unit. EPRI has recently revised and renamed the Equilibrium Treatment philosophy to what is now termed Phosphate Continuum Treatment4 as illustrated in Figure 5. The maximum Na/PO4 ratio control boundary is a

TSP + 2 PPM NaOH TSP + 1 PPM NaOH Na/PO4 = 3.0 Na/PO4 = 2.8

10.2 10.0

pH at 25 °C

9.8

Na/PO4 = 2.6

9.6 9.4

Note: 1. Minimum PO4 > 0.2 (mg l–1)

9.2 9.0 8.8 8.6

0

1

2

Figure 5 Phosphate continuum control chart.

3

4

5 6 PO4 (mg l–1)

7

8

9

10

14

Boiler and Feedwater Treatment

Na/PO4 equal to 3.0 plus 1 mg l
1 (1 ppm) NaOH and the minimum Na/PO4 control boundary is Na/PO4¼ 3.0. Additionally, there is a minimum pH ¼ 9.0 and a minimum boiler water orthophosphate concentration of 0.2 mg l
1 (0.2 ppm). For mixed-bed makeup water systems with no significant sodium leakage and low organic contamination of the makeup and condensate, only trisodium phosphate and caustic soda (when needed) are recommended for Phosphate Continuum Treatment. Monosodium, disodium, and polyphosphates should not be needed. But for many industrial boiler systems that can have significant sodium leakage from the makeup system or significant organic contaminants in the makeup water or condensate, a wide range of Na:PO4 molar ratio treatment chemicals might be required to maintain the desired control in a particular boiler system situation. Phosphate Continuum Treatment does include the presence of free hydroxide in the boiler water and therefore does present the known concerns associated with caustic in boilers. There is the potential for under deposit caustic gouging in the boiler, the potential for stress corrosion cracking of steam system components in the event of boiler water carry over and the potential for embrittlement damage to the drums if the boiler has mechanical rolled tube joints if one were to leak.

5.8

AVT 35,36

AVT helps achieve sufficiently high pH to protect boiler steel without introducing any dissolved solids. It is based on the use of entirely volatile, solid-free chemicals, such as hydrazine or carbohydrazide for oxygen scavenging, plus neutralizing amines or ammonia for boiler water pH control. AVT may be used in drum boilers that have the appropriate feedwater purity. In drum boilers, AVT may be used for simplicity where phosphate hideout has caused control problems on phosphate-pH control programs or where ultra pure steam is required. A disadvantage of all volatile treatment for drum boilers is that the boiler water is unbuffered and thus subject to extensive and rapid pH excursions in the event of feedwater contamination. Prompt detection and remedial action is required in the event of any feedwater contamination. A condensate polishing system, either for continuous polishing or for start-up and emergency polishing, is very desirable. Some utilities do operate high-pressure drum cycles on AVT without the benefits of polishers, but their systems have extensive instrumentation that allows immediate remedial action to be taken in the event of cycle contamination (including feeding phosphate until the problem is resolved). A mixed-bed polisher is essential in the makeup system. The AVT program control is simple and highly effective as long as feedwater purity is maintained. Feedwater contamination of an otherwise solids-free system produces undesirable effects immediately. With essentially no chemical buffering capacity in the system, boiler water pH values can reach free acidity levels (pHo4.3) very rapidly following contamination. This is particularly true in systems using seawater or brackish water for condenser cooling. Cation conductivity measurements of the boiler water are used to monitor any dissolved solids contamination of the cycle. Cation conductivity is also preferred for condensate and feedwater monitoring since it is very sensitive to changes in dissolved solids concentrations and is not affected by changing the amine or ammonia levels. Specific conductance is used primarily to monitor the level of ammonia or neutralizing amine present in the cycle. Continuous pH monitoring of the boiler water is desirable, as pH provides another indication of a contamination problem. Boiler water pH values will typically be lower than the feedwater pH because of the volatilization of the amine or ammonia from the boiler water; pH control in the feedwater cycle will vary with cycle metallurgy.

5.9

Caustic Treatment

Sodium hydroxide alone can also be used as the solid alkali in internal boiler water treatment for pH control. It is a common practice in high-pressure drum boilers in the United Kingdom, and many of these are high-pressure drum boilers in the electric utility service industry.4,37 A typical boiler water pH control range is 9.0–9.4. Caustic can still be very corrosive to carbon steel under concentrated conditions, such as under porous metal oxide deposits on a boiler’s heat transfer surfaces, and can cause under deposit corrosion damage. It is therefore very important to keep the boiler’s heat transfer surfaces clean by minimizing the feedwater corrosion product transport into the boiler and periodic chemical cleaning. There is also a concern that chloride contamination may increase this corrosion potential, and individual operators have also restricted boiler water chloride limits.

6

Condensate Treatment

Condensate is a very valuable commodity (resource) in a boiler system, not only because of its energy content but also because of its high purity. Therefore, the more condensate that can be returned as part of the boiler feedwater, the more efficient the economics are of operating the boiler system. As condensate is very pure water, very small amounts of contamination can render it extremely corrosive and unsuitable as feedwater. One of the more common contaminants that can depress the pH of the condensate is carbon dioxide. Carbon dioxide can originate from the bicarbonate alkalinity in the makeup water, which decomposes at boiler operating pressure, contributing

Boiler and Feedwater Treatment

15

the carbon dioxide to the steam or from air in leakage into the system. The latter is most likely to occur when the pressure in the condensate system is at or below atmospheric pressure. In addition, organic materials in the makeup water can decompose in the boiler water, resulting in the formation of low molecular weight organic acids such as acetic, formic, and glycolic acids. These organic acids have volatility characteristics that are a function of pressure. All are considerably stronger acids than carbonic acid and will increase the demand for the neutralizing amine treatment that is commonly employed to neutralize acids and so elevate the condensate pH. Hydrogen sulfide and sulfur dioxide, the products of decomposition of the sodium sulfite oxygen scavenger, that can occur at boiler operating pressures 44.1 MPa g (4600 psi g), can also depress condensate pH and contribute to the amine demand. Depressed pH conditions of the condensate can cause significant corrosion damage to condensate system components. Dissolved oxygen either not removed by the deaeration processes or that has leaked into the system at points where the pressure is at less than atmospheric pressure can also cause corrosion damage in the condensate system. Ammonia can also be considered a contaminant in the condensate if there are copper alloys in the condensate system that can be attacked by the ammonia. Chemically, four types of treatment are used for condensate system corrosion control: ammonia or neutralizing amines, filming amines, oxygen scavengers/metal passivators, and nonamine filming treatment. Neutralizing amines and ammonia are volatile, alkaline compounds that are added to either the boiler feedwater or the steam. They function by volatilizing into the steam and redissolving into the condensate. The amines and ammonia chemically neutralize the carbonic acid or any other acid present in the condensate. Then they raise the pH of the condensate to minimize the corrosion of the materials of construction of the condensate system. The most common neutralizing amines in use today are cyclohexylamine, morpholine, diethylaminoethanol, methoxypropylamine, and monoethanolamine. Each has a unique volatility and basicity characteristic. Industrial boiler systems can have very extensive and complex steam/condensate systems. Complex steam systems that operate at multiple pressure levels, especially where high-pressure condensate is flashed to produce additional low-pressure steam, can concentrate a single treatment amine to one part of the system while simultaneously depleting its concentration in another part of the system due to its unique single, pressure-dependent vapor-to-liquid distribution ratio characteristic. This leads to a situation in which some parts of the complex system can be undertreated, even though from the pH measurement of the combined condensate sample the system appears to be sufficiently treated. The common solution to this situation is the use of an amine treatment product – that may be a combination of multiple amines, each with a different vapor-to-liquid distribution characteristic. In the most complex steam systems, satellite feed to a particular point in the system may still be required to provide adequate corrosion protection. In a simple steam condensate system such as the typical electric utility situation, a single amine or ammonia may provide adequate protection. But there have been many cases where a low volatility amine or the industrial multiple amine philosophies of treatment have provided better protection as measured by a reduction in corrosion product transport, in even the simple system. Neutralizing amine treatment does not provide protection for the system from dissolved oxygen attack. The feed of an oxygen scavenger/passivator to the condensate can protect the system against dissolved oxygen attack. Sodium sulfite is typically not used for this application since it contributes nonvolatile solids. More typically, one of the volatile organic oxygen scavenger/passivator materials can be used in this application. Preferably though, the source of the oxygen in leakage should be found and corrected. There can also be situations in which the carbon dioxide content of the steam is so high because of the natural bicarbonate alkalinity of the makeup water, and that treating the condensate with neutralizing amine technology is prohibitively expensive. In this case, a filming amine technology can be used. In the filming amine treatment, the carbon dioxide is not neutralized, but the filming amine forms a nonwettable barrier on the condensate system components preventing the low pH condensate from coming into contact with the materials. Filming amines also provide protection from dissolved oxygen attack. The amount of filming amine required is related to the surface area of the system. Octadecylamine is a commonly used filming amine in industrial steam systems. There are also proprietary filming amines.38 Polyamines39 are another filming amine technology that is seeing more use in electric utility steam systems. Filming amines have the ability to move corrosion products from the surface of the piping. It is therefore advisable to start with low dosages, which are gradually increased until residual limits are met. There may be restrictions on amine concentrations in steam when there is contact of that steam with food or food products, when the steam is used for humidification of air or when it can contact certain catalysts used in industrial processes. A nonamine filming corrosion inhibitor technology40 has been developed for when there isa prohibition on amines in the treated steam. There are also mechanical means of treating condensate to remove contaminants and preserve its purity for reuse. If corrosion products – typically iron oxides and copper oxides – exist as suspended solids in the condensate, they can be filtered out. Cartridge filters can be used. Condensate polishers, an ion exchange process in which strong acid cation resin is in the sodium or amine form in industrial situations, act primarily as a filter but can also remove hardness that may have come from cooling water contamination of the condensate. In electric utility boiler situations where condensate temperatures are considerably lower, mixedbed resin polishers (typically a mixture of strong acid cation resin in the hydrogen form and strong base anion resin in the hydroxide form) are used. These can be deep bed regenerable units or they can be of the powdered resin, one-time-use type. In

16

Boiler and Feedwater Treatment

addition, high gradient electromagnetic filters have been used to remove corrosion products of iron and copper that are magnetic or paramagnetic. As a final alternative, contaminated condensate can be discarded or diverted rather than returned to the system. The condensate diversion system (condensate dumps) is a system of sensors, valves, and piping to detect the contamination of the condensate and divert it to waste. These condensate diversion systems must be properly engineered to detect and divert the contamination in a timely manner to prevent the contamination of the feedwater. This technique is only applicable to systems where the makeup water system capacity can compensate for this lost condensate.

7 7.1

Boiler Treatment During Out-of-Service Conditions

Boilers constructed out of carbon steel and low chromium alloys up to about 9% chromium content are prone to corrosion at ambient temperatures in contact with untreated, typically aerated, water. The maximum corrosion rate occurs where carbon steel is in contact with a water–air interface. This water–air interface can occur when an operating boiler is taken out-of-service and the vents are opened to the atmosphere during the cooling process and air displaces the condensing steam. Even if the boiler is drained at this point, depending on the boiler design configuration there may be areas of the boiler that do not drain completely. In addition, in many boiler designs that incorporate superheaters and reheaters, heat transfer surfaces can be of a pendant or other design configuration that is inherently nondrainable. Nondrainable components require special treatment if a wet lay-up method is employed. Water purity must be very high, condensate or demineralized quality, and any treatment chemicals used in the water must be volatile. Guidelines41,42 are available for the proper treatment of a boiler in the out-of-service condition. The goal of the guidelines is to use a procedure that generally eliminates the air–water interface. This can be accomplished in a number of ways – by draining the boiler under a positive nitrogen pressure or draining the boiler and installing a desiccant, for example. The appropriate procedure depends on many variables, including the configuration of the boiler and the expected duration of the out-of-service period.

8

Miscellaneous (But Important) Comments

Proper sampling is a prerequisite of effectively monitoring a system. Effective monitoring of the makeup water, feedwater, boiler water, steam, and condensate is necessary to control deposition and corrosion within the system. No matter how accurate or precise the analysis of a sample obtained is, if the sample is not truly representative of the stream being sampled, the results are useless (F.J. Pocock, Pers. comm.). Effective monitoring requires a proper sampling system, adequate sample system purging, the required sample velocity, and appropriate sample handling.44 A particular case in point is sampling steam to determine its purity. Isokinetic sampling nozzles and procedures are required.45 (There is currently a difference of opinion on the need for isokinetic sampling for saturated steam between the ASTM and VGB guidelines that should be resolved shortly.) When sampling superheated steam, sample cooling considerations are especially important. The distance between the sampling nozzle and the primary cooler must be minimized, no more than 7 m (20 ft), and any sample line length between the nozzle and the cooler must be insulated. The proper sampling and analysis of condensate is especially critical, because of its inherent high purity and the volatility characteristics of both the treatment chemicals and some of the contaminants it might contain. A stainless steel injection quill must be used to inject treatment chemical into the system. Concentrated treatment chemicals in contact with carbon steel at elevated system operating temperatures present a corrosive situation for the carbon steel. A properly designed and installed chemical injection quill admits the chemical into the fluid stream, so that it is properly diluted in the stream.

References 1. Water-Tube Boilers and Auxiliary Installations-Part 12: Requirements for Boiler Feedwater and Boiler Water quality. CEN European Committee for Standardization, Brussels: Belgium, EN 12952−12:2003, 2003. 2. VGB Guideline for Feedwater, Boiler Water and Steam of Steam Generators with Admissible Operating Pressure 468 bar. VGB Kraftwerkstechnik GmbH, Essen, Germany, VGB-R 450 L, 1988. 3. Consensus on Operating Practices for the Control of Feedwater and Boiler Water Chemistry in Modern Industrial Boilers, CRTD-Vol. 34. American Society of Mechanical Engineers, New York, NY, 1994. 4. Dooley, R.B., Shields, K.J., 2004. Power Plant Chem. 6 (3), 5. Japanese Industrial Standard, Water Conditioning for Boiler Feed Water and Boiler Water, JIS B 8223, Japanese Standards Association, 1989. 6. Kucera, J., 2010. Reverse Osmosis, Industrial Applications and Processes. JWiley/Scrivener. ISBN 978-0-470-61843-1. 7. Miller, B., Munoz, J., Wiesler, F., 2005. Proceedings of the International Water Conference, Pittsburgh, PA, 2005; paper no. IWC-05−79.

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