Boiler water treatment

Steam 41 / Water and Steam Chemistry, Deposits and Corrosion 42-1

The Babcock & Wilcox Company

Chapter 42Water and Steam Chemistry,

Deposits and Corrosion

Steam generation and use involve thermal andphysical processes of heat transfer, fluid flow, evapo-ration, and condensation. However, steam and waterare not chemically inert physical media. Pure waterdissociates to form low concentrations of hydrogen andhydroxide ions, H+ and OH−, and both water andsteam dissolve some amount of each material that theycontact. They also chemically react with materials toform oxides, hydroxides, hydrates, and hydrogen. Astemperatures and velocities of water and steam vary,materials may dissolve in some areas and redeposit inothers. Such changes are especially prevalent wherewater evaporates to form steam or steam condensesback to water, but they also occur where the onlychange is temperature, pressure, or velocity. In addi-tion, chemical impurities in water and steam can formharmful deposits and facilitate dissolution (corrosion)of boiler structural materials. Therefore, to protectvessels, tubing, and other components used to containand control these working fluids, water and steamchemistry must be controlled.

Water used in boilers must be purified and treatedto inhibit scale formation, corrosion, and impurity con-tamination of steam. Two general approaches are usedto optimize boiler water chemistry. First, impurities inthe water are minimized by purification of makeupwater, condensate polishing, deaeration andblowdown. Second, chemicals are added to control pH,electrochemical potential, and oxygen concentration.Chemicals may also be added to otherwise inhibit scaleformation and corrosion. Proper water chemistry con-trol improves boiler efficiency and reduces mainte-nance and component replacement costs. It also im-proves performance and life of heat exchangers,pumps, turbines, and piping throughout the steamgeneration, use, and condensation cycle.

The primary goals of boiler water chemistry treat-ment and control are acceptable steam purity andacceptably low corrosion and deposition rates. In ad-dition to customized boiler-specific guidelines and pro-cedures, qualified operators are essential to achieving

these goals, and vigilance is required to detect earlysigns of chemistry upsets. Operators responsible forplant cycle chemistry must understand boiler waterchemistry guidelines and how they are derived andcustomized. They must also understand how waterimpurities, treatment chemicals, and boiler componentsinteract. Training must therefore be an integral, ongo-ing part of operations and should include management,control room operators, chemists, and laboratory staff.

General water chemistry control limits and guidelineshave been developed and issued by various groups ofboiler owners and operators (e.g., ASME,1,2,3 EPRI4 andVGB5), water treatment specialists6,7,8 utilities and in-dustries. Also, manufacturers provide recommendedchemistry control limits for each boiler and for othermajor cycle components. However, optimum water andsteam chemistry limits for specific boilers, turbines, andother cycle components depend on equipment designand materials of construction for the combination ofequipment employed. Hence, for each boiler system,boiler-specific water chemistry limits and treatmentpractices must be developed and tailored to changingconditions by competent specialists familiar with thespecific boiler and its operating environment.

Chemistry-boiler interactionsTo understand how water impurities, treatment

chemicals and boiler components interact, one mustfirst understand boiler circuitry, and steam generationand separation processes.

Boiler feed pumps provide feedwater pressure andflow for the boiler. From the pumps, feedwater oftenpasses through external heaters and then through aneconomizer where it is further heated before enteringthe boiler. In a natural circulation drum-type unit,boiling occurs within steel tubes through which awater-steam mixture rises to a steam drum. Devicesin the drum separate steam from water, and steamleaves through connections at the top of the drum.This steam is replaced by feedwater which is supplied

42-2 Steam 41 / Water and Steam Chemistry, Deposits and Corrosion


by the feedwater pumps and injected into the drumjust above the downcomers through a feedwater pipewhere it mixes with recirculating boiler water whichhas been separated from steam. By way of downcom-ers, the water then flows back through the furnaceand boiler tubes. Boiler water refers to the concen-trated water circulating within the drum and steamgeneration circuits. Chapters 1 and 5 provide detaileddescriptions of steam generation and boiler circulation.

Boiler feedwater always contains some dissolvedsolids, and evaporation of water leaves these dissolvedimpurities behind to concentrate in the steam genera-tion circuits. If the concentration process is not lim-ited, these solids can cause excessive deposition andcorrosion within the boiler and excessive impuritycarryover with the steam. To avoid this, some concen-trated boiler water is discarded to drain by way of ablowdown line. Because the boiler water is concen-trated, a little blowdown eliminates a large amountof the dissolved solids. Since steam carries very littledissolved solids from the boiler, dissolved and sus-pended solids entering in the feedwater concentratein the boiler water until the solids removed in theblowdown (boiler water concentration times theblowdown rate lb/h or kg/s) equal the solids carried inwith the feedwater (lb/h or kg/s).

A small amount of dissolved solids is carried fromthe drum by moisture (water) droplets with the steam.Because moisture separation from steam depends onthe difference between their densities, moisture sepa-ration is less efficient at high pressures where thereis less difference between the densities. Therefore, toattain the same steam purity at a higher pressure, thedissolved solids concentration in boiler water mustgenerally be lower.

In a drum boiler, the amount of steam generated issmall compared to the amount of water circulatingthrough the boiler. However, circulation is also largelydriven by the difference in densities between the twofluids, so as pressure increases the ratio of water flowto steam flow decreases. At 200 psi (1379 kPa), waterflow through the boiler must be on the order of 25,000pph (3 kg/s) to produce just 1000 pounds per hour ofsteam. Even at 2700 psi (18.6 MPa), 2500 to 4000 poundsof water circulates to produce 1000 pounds of steam. Bycontrast, most or all of the water entering a once-throughboiler is converted to steam without recirculation.

Some boiler operators have asked why boiler wa-ter concentrations change so slowly once a source ofcontamination is eliminated and the continuousblowdown rate is increased. How quickly can excesschemical be purged from a boiler? How much impu-rity or additive is needed to upset boiler water chem-istry? How quickly do chemical additions circulatethrough the boiler? To answer these questions andexplore some other chemistry-boiler interactions, con-sider for example a typical 450 MW natural circula-tion boiler, generating 3,000,000 pounds of steam perhour. It has a room temperature water capacity of240,000 pounds and an operating water capacity of115,000 pounds. The furnace wall area is 33,000square feet, about 5800 of which are in the maximumheat flux burner zone.

Impurities purge slowly from the boiler because theboiler volume is large compared to the blowdown rate.For example, at maximum steaming capacity with ablowdown rate 0.3% of the steam flow from the drum,17 hours may be required to decrease the boiler wa-ter concentration of a non-volatile impurity by 50%.Almost two hours are required to effect a 50% reduc-tion in the boiler water concentration even at ablowdown rate of 3%. Without blowdown, dissolvedsodium with a fractional carryover factor of 0.1%would have a half life of 52 hours. While long periodsof time are generally required to purge impurities,mixing within the boiler is rapid. For the boiler beingused as an example, the internal recycle rate is aboutone boiler volume per minute, and steam is generatedat a rate of one boiler volume every 5 minutes.

The rate of steam generation is such that replace-ment feedwater must be essentially free of hardnessminerals and oxides that deposit in the boiler. Forexample, feedwater carrying only 1 ppm of hardnessminerals and oxides could deposit up to 25,000 lb(11,340 kg) per year of solids in the boiler, so the boilermight require chemical cleaning as often as 3 or 4 timesper year. Also, small chemical additions have a largeeffect on boiler water chemistry. For example, addi-tion of 0.2 lb (0.09 kg) of sodium hydroxide to theboiler water increases the sodium concentration by 1ppm, which can significantly affect the boiler waterchemistry. Similarly, a small amount of chemical hide-out can have a large effect on boiler water concentra-tion. Hideout or hideout return of only 0.01 gram persquare foot (0.1 g/m2) in the burner zone can changethe boiler water concentration by 1 ppm.

Control of deposition, corrosion, andsteam purity

The potential for deposition and corrosion is inher-ent to boilers and increases with boiler operating pres-sure and temperature. Evaporation of water concen-trates boiler water impurities and solid treatmentchemicals at the heat transfer surfaces. During thenormal nucleate boiling process in boiler tubes, smallbubbles form on tube walls and are immediately sweptaway by the upward flow of water. As steam forms,dissolved solids in the boiler water concentrate alongthe tube wall. Additionally, the boundary layer ofwater along the wall is slightly superheated, andmany dissolved minerals are less soluble at higher tem-peratures (common phenomenon referred to as inversetemperature solubility). Both of these factors favordeposition of solids left behind by the evolution ofsteam in high heat flux areas, as illustrated in Fig. 1.

These deposits in turn provide a sheltered environ-ment which can further increase chemical concentra-tions and deposition rates. In a relatively clean boilertube, concentration of chemicals at the tube surfaceis limited by the free exchange of fluid between thesurface and boiler water flowing through the tube.Wick boiling as illustrated in Fig. 2 generally producessufficient flow within the deposits to limit the degreeof concentration. However, as heavy deposits as illus-



trated in Fig. 3 accumulate, they restrict flow to thesurface. Some boiler water chemicals concentrate ontube walls during periods of high load and then re-turn to the boiler water when the load is reduced. Thisis termed hideout and hideout return. This can greatlycomplicate efforts to control boiler water chemistry.

Typical boiler deposits are largely hardness precipi-tates and metal oxides. Hardness, easily precipitatedminerals (mainly calcium and magnesium), enters thecycle as impurities in makeup water and in coolingwater from condenser leaks. Metal oxides are largely

from corrosion of pre-boiler cycle components. Scalingoccurs when these minerals and oxides precipitate andadhere to boiler internal surfaces where they impedeheat transfer. The result can be overheating of tubes,followed by failure and equipment damage. Depositsalso increase circuitry pressure drop, especially detri-mental in once-through boilers. Effective feedwaterand boiler water purification and chemical treatmentminimizes deposition by minimizing feedwater hard-ness and by minimizing corrosion and associated ironpickup from the condensate and feedwater systems. Also,phosphate and other water treatment chemicals are usedin drum boilers to impede the formation of particularlyadherent and low thermal conductivity deposits.

Some chemicals become corrosive as they concen-trate. Corrosion can occur even in a clean boiler, butthe likelihood of substantial corrosion is much greaterbeneath thick porous deposits that facilitate the con-centration process. Concentration at the base of depos-its can be more than 1000 times higher than that inthe boiler water and the temperature at the base of thesedeposits can substantially exceed the saturation tem-perature. Hence, as deposits accumulate, control ofboiler water chemistry to avoid the formation of corro-sive concentrates becomes increasingly important. Sincechemistry upsets do occur, operation of a boiler withexcessively thick deposits should be avoided.

Because local concentration of boiler water impuri-ties and treatment chemicals is inherent to steam gen-eration, water chemistries must be controlled so theconcentrates are not corrosive. On-line corrosion isoften caused by concentration of sodium hydroxide,concentration of caustic-forming salts such as sodiumcarbonate, or concentration of acid-forming salts suchas magnesium chloride or sulfate.10 Effective feed-water and boiler water treatment minimizes corrosionby minimizing ingress of these impurities and by add-

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

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

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



ing treatment chemicals (such as trisodium phosphate)that buffer against acid or caustic formation. However,corrosion and excessive precipitation can also be causedby improper use of buffering agents and other treat-ment chemicals. For example, underfeeding or overfeed-ing of treatment chemicals, out-of-specification sodium-to-phosphate ratios, or out-of-specification free-chelantconcentrations can cause corrosion.

Dissolved carbon dioxide and oxygen can also becorrosive and must be eliminated from feedwater.Carbon dioxide from air in-leakage and from decom-position of carbonates and organic compounds tendsto acidify feedwater and steam condensate. Oxygenis especially corrosive because it facilitates oxidation ofiron, copper, and other metals to form soluble metal ions.At higher temperatures, oxygen is less soluble in waterand the rate of chemical reaction is increased. As boilerfeedwater is heated, oxygen is driven out of solution andrapidly corrodes heat transfer surfaces. The combinationof oxygen and residual chloride is especially corrosive,as is the combination of oxygen and free chelant.

Carryover of impurities from boiler water to steamis also inherent to boiler operation. Though separationdevices remove most water droplets carried by steam,some residual droplets containing small amounts of dis-solved solids always carry through with the steam. Also,at higher pressures, there is some vaporous carryover.Excessive impurities can damage superheaters, steamturbines, or downstream process equipment.

Boiler feedwaterTo maintain boiler integrity and performance and

to provide steam of suitable turbine or process purity,boiler feedwater must be purified and chemically con-ditioned. The amount and nature of feedwater impu-rities that can be accommodated depend on boiler op-erating pressure, boiler design, steam purity require-ments, type of boiler water internal treatment,blowdown rate, and whether the feedwater is used forsteam attemperation. Feedwater chemistry param-eters to be controlled include dissolved solids, pH, dis-solved oxygen, hardness, suspended solids, total or-ganic carbon (TOC), oil, chlorides, sulfides, alkalinity,and acid or base forming tendencies.

At a minimum, boiler feedwater must be softenedwater for low pressure boilers and demineralized wa-ter for high pressure boilers. It must be free of oxy-gen and essentially free of hardness constituents andsuspended solids. Recommended feedwater limits areshown in Table 1. Use of high-purity feedwater mini-mizes blowdown requirements and minimizes the po-tential for carryover, deposition, and corrosion prob-lems throughout the steam-water cycle.

Operation within these guidelines does not by itselfensure trouble-free operation. Some feedwater contami-nants such as calcium, magnesium, organics, and car-bonates can be problematic at concentrations below thedetection limits of analytical methods commonly used

Table 1Recommended Feedwater Limits

Once-Through Drum Boilers Boilers

Oxygen with AVT* AVT TreatmentPressure, 15 to 300 301 to 600 601 to 900 901 to 1000 1001 to 1500 >1500 psig (MPa) (0.10 to 2.07) (2.08 to 4.14) (4.14 to 6.21) (6.21 to 6.90) (6.90 to 10.34) (>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, copper- bearing 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 N/A

Total hardness, as ppm CaCO3, maximum 0.3 0.2 0.1 0.05 0.003 0.003 0.003 0.003 0.001

Oxygen, ppm maximum*** 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

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

Note:ppm = mg/kg



for industrial boilers. Also, operators must be sensitiveto changes in feedwater chemistry and boiler operat-ing conditions, and must adapt accordingly.

Makeup waterBoiler feedwater is generally a mix of returned

steam condensate and fresh makeup water. For util-ity boilers, most of the steam is usually returned ascondensate, and only 1 to 2% makeup is necessary.However, for some industrial cycles, there is little orno returned condensate, so as much as 100% makeupmay be necessary.

Chemistry requirements for makeup water dependon the amount and quality of returned steam conden-sate. Where a large portion of the feedwater is uncon-taminated condensate, makeup water can generallybe of lesser purity so long as the mixture of conden-sate and makeup meet boiler feedwater requirements.The feedwater concentration for each chemical spe-cies is the weighted average of the feedwater andmakeup water concentrations:

Feedwater concentration (condensate concentration flow +

= × makeup concentration makeup flow) / total feedwater fl× oow (1)

The selection of equipment for purification ofmakeup water must consider the water chemistry re-quirements, raw water composition, and quantity ofmakeup required. All natural waters contain dissolvedand suspended matter. The type and amount of im-purities vary with the source, such as lake, river, wellor rain, and with the location of the source. Major dis-solved chemical species in source water include sodium,calcium, and magnesium positive ions (cations) as wellas bicarbonate, carbonate, sulfate, chloride, and silicatenegative ions (anions). Organics are also abundant.

The first steps in water purification are coagulationand filtration of suspended materials. Natural settlingin still water removes relatively coarse suspended sol-ids. Required settling time depends on specific grav-ity, shape and size of particles, and currents withinthe settling basin. Settling and filtration can be ex-pedited by coagulation (use of chemicals to cause ag-glomeration of small particles to form larger ones thatsettle more rapidly). Typical coagulation chemicals arealum and iron sulfate. Following coagulation and set-tling, water is normally passed through filters. Thewater is chlorinated to kill micro-organisms, then ac-tivated charcoal filters may be used to remove the fi-nal traces of organics and excess chlorine.

Subsequently, various processes may be used toremove dissolved scale-forming constituents (hardnessminerals) from the water. For some low pressure boil-ers, removal of hardness minerals and scale-formingminerals is adequate. For other boilers, the concen-tration of all dissolved solids must be reduced or nearlyeliminated. For low pressure boilers, the capital andoperating cost for removal must be weighed againstcosts associated with residual dissolved solids andhardness. These include increased costs for boiler watertreatment, more frequent chemical cleaning of theboiler, and possibly higher rates of boiler repair. De-mineralized water nearly free of all dissolved solids isrecommended for higher pressure boilers and espe-

cially for all boilers operating at pressures greater than1000 psi (6.9 MPa).

Sodium cycle softening, often called sodium zeolitesoftening, replaces easily precipitated hardness min-erals with sodium salts, which remain in solution aswater is heated and concentrated. The major hardnessions are calcium and magnesium. However, zeolite ion-exchange softening also removes dissolved iron, man-ganese, and other divalent and trivalent cations. So-dium held by a bed of organic resin is exchanged forcalcium and magnesium ions dissolved in the water.The process continues until the sodium ions in the resinare depleted and the resin can no longer absorb cal-cium and magnesium efficiently. The depleted resinis then regenerated by washing it with a high con-centration sodium chloride solution. At the high so-dium concentrations of this regeneration solution, thecalcium and magnesium are displaced by sodium.Variations of the process, in combination with chemi-cal pre-treatments and post-treatments, can substan-tially reduce hardness concentrations and can oftenreduce silica and carbonate concentrations.

For higher pressure boilers, evaporative or morecomplete ion-exchange demineralization of makeupwater is recommended. Any of several processes maybe used. Evaporative distillation forms a vapor whichis recondensed as purified water. Ion exchange de-mineralization replaces cations (sodium, calcium, andmagnesium in solution) with hydrogen ions and re-places anions (bicarbonate, sulfate, chloride, and sili-cate) with hydroxide ions. For makeup water treat-ment, two tanks are normally used in series in a cat-ion-anion sequence. The anion resin is usually regen-erated with a solution of sodium hydroxide, and thecation resin is regenerated with hydrochloric or sul-furic acid. Reverse osmosis purifies water by forcing itthrough a semi-permeable membrane or a series ofsuch membranes. It is increasingly used to reduce totaldissolved solids (TDS) in steam cycle makeup water.Where complete removal of hardness is necessary,reverse osmosis may be followed by a mixed-bed dem-ineralizer. Mixed-bed demineralization uses simulta-neous cation and anion exchange to remove residualimpurities left by reverse osmosis, evaporator, or two-bed ion exchange systems. Mixed-bed demineralizersare also used for polishing (removing impurities from)returned steam condensate. Before regeneratingmixed-bed demineralizers, the anion and cation res-ins must be hydraulically separated. Caustic andacids used for regeneration of demineralizersand other water purification and treatmentchemicals present serious safety, health, andenvironmental concerns. Material Safety DataSheets must be obtained for each chemical andappropriate precautions for handling and usemust be formulated and followed.

Dissolved organic contaminants (carbon-basedmolecules) are problematic in that they are often det-rimental to boilers but are not necessarily removed bydeionization or evaporative distillation. Organic con-tamination of feedwater can cause boiler corrosion,furnace wall tube overheating, drum level instability,carryover, superheater tube failures, and turbine cor-



rosion. The degree to which any of these difficultiesoccurs depends on the concentration and nature of theorganic contaminant. Removal of organics may re-quire activated carbon filters or other auxiliary puri-fication equipment.

Returned condensate – condensate polishingFor many boilers, a large fraction of the feedwater

is returned condensate. Condensate has been purifiedby prior evaporation, so uncontaminated condensatedoes not generally require purification. Makeup wa-ter can be mixed directly with the condensate to formboiler feedwater.

In some cases, however, steam condensate is con-taminated by corrosion products or by in-leakage ofcooling water. Where returned condensate is contami-nated to the extent that it no longer meets feedwaterpurity requirements, mixed-bed ion-exchange purifi-cation systems are commonly used to remove the dis-solved impurities and filter out suspended solids. Suchdemineralization is referred to as condensate polish-ing. This is essential for satisfactory operation of once-through utility boilers, for which feedwater purityrequirements are especially stringent. While highpressure drum boilers can operate satisfactorily with-out condensate polishing, many utilities recognize thebenefits in high pressure plants. These benefits includeshorter unit startup time, protection from condenserleakage impurities, and longer intervals between acidcleanings. Condensate polishing is recommended forall boilers operating with all volatile treatment (AVT)and is essential for all boilers operating with all vola-tile treatment and seawater cooled condensers. Pro-visions for polishing vary from adequate capacity for100% polishing of all returned condensate to polish-ing only a portion of the condensate. However, all mustbe adequate to meet feedwater requirements underall anticipated load and operating conditions.

Most of the pressure vessels that contain ion ex-change resins have under-drain systems and down-stream traps or strainers to prevent leakage of ionexchange resins into the cycle water. These resins canform harmful decomposition products if allowed toenter the high temperature portions of the cycle. Un-fortunately, the under-drain systems and the trapsand strainers are not designed to retain resin frag-ments that result from resin bead fracture. Also, theresin traps and strainers can fail, resulting in resinbursts. Resin intrusion can be minimized by control-ling flow transients, reducing the strainer’s screensize, increasing flow gradually during vessel cut-in,and returning the polisher vessel effluent to the con-denser during the first few minutes of cut-in.

Feedwater pH controlBoiler feedwater pH is monitored at the condensate

pump discharge and at the economizer inlet. Whenthe pH is below the required minimum value, ammo-nium hydroxide or an alternate alkalizer is added.Chemicals for pH control are added either downstreamof the condensate polishers or at the condensate pumpdischarge for plants without polishers. For high pu-rity demineralized feedwater, ammonium hydroxide

injection pumps or alternative feedwater pH controlis achieved using a feedback signal from a specific con-ductivity monitor. Conductivity provides a good mea-sure of ammonium hydroxide concentration, and au-tomated conductivity measurement is more reliablethan automated pH measurement. Also, the linearrather than logarithmic relationship of conductivityto ammonia concentration gives better control. Fig. 4shows the relationship between ammonium concen-tration, pH, and conductivity of demineralized water.

While an equilibrium concentration of ammoniumhydroxide remains in the boiler water, much of theammonium hydroxide added to feedwater volatilizeswith the steam. Conversely, the solubility of ammo-nium hydroxide is such that little ammonia is lost bydeaeration. Hence, returned condensate often has asubstantial concentration of ammonium hydroxidebefore further addition.

Common alternative pH control agents include neu-tralizing amines, such as cyclohexylamine andmorpholine. For high pressure utility boilers with su-perheaters, the more complex amines are thermallyunstable and the decomposition products can be prob-lematic.

Deaeration and chemical oxygen scavengersOxygen and carbon dioxide enter the cycle with un-

deaerated makeup water, with cooling water which

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



leaks into the condenser, and as air leaking into thevacuum portion of the cycle.

For turbine cycles, aeration of the feedwater is ini-tially limited by use of air ejectors to remove air fromthe condenser. Utility industry standard practice is tolimit total air in-leakage to less than one standardcubic foot of air per minute per 100 MW of generat-ing capacity (approximately 0.027 Nm3/100 MW), asmeasured at the condenser air ejectors. Final removalof oxygen and other dissolved gases adequate for boilerfeedwater applications is generally accomplished bythermal deaeration of the water ahead of the boilerfeed pumps. Thermal deaeration is accomplished byheating water to reduce gas solubility. Gases are thencarried away by a counter flow of steam. The processis typically facilitated by the use of nozzles and trayswhich disperse water droplets to increase the steam-to-water interfacial area. Thermal deaeration can re-duce feedwater oxygen concentration to less than 7parts per billion (ppb). It also essentially eliminatesdissolved carbon dioxide, nitrogen, and argon.

Chemical agents are generally used to scavenge re-sidual oxygen not removed by thermal deaeration. Tra-ditional oxygen scavengers have been sodium sulfite forlow pressure boilers and hydrazine for high pressureboilers. Sulfite must not be used where the boiler pres-sure is greater than 900 psig (6.2 MPa). Other oxygenscavengers (erythorbic acid, diethylhydroxylamine, hy-droquinone and carbohydrazide) are also used. Hydra-zine has been identified as a carcinogen and this hasincreased the use of alternative scavengers. Scavengersare generally fed at the exit of the condensate polishingsystem and/or at the boiler feed pump suction.

Attemperation waterWater spray attemperation is used to control steam

temperature. Attemperation for utility boilers is dis-cussed in the Steam temperature adjustment and con-trol section of Chapter 19, Boilers, Superheaters andReheaters. The spray water is feedwater, polished feed-water, or steam condensate. As the spray water evapo-rates, all chemicals and contaminants in the waterremain in the steam. This addition must not be exces-sive. It must not form deposits in the attemperatorpiping, and it must not excessively contaminate thesteam. If a superheated steam purity limit is imposed,the steam purity after attemperation must not exceedthis limit. To meet this requirement, the weightedaverage of the spray water total solids concentrationand the saturated steam total solids concentrationmust not exceed the final steam total solids limit. Ad-ditionally, spray water attemperation must not in-crease the steam total solids concentration by morethan 0.040 ppm. Independent of other considerations,the spray water solids concentration must never ex-ceed 2.5 ppm. Ideally, the purity of attemperationwater should equal the desired purity of the steam.

Drum boilers and internal boiler waterBoiler water that recirculates in drum and steam

generation circuits has a relatively high concentrationof dissolved solids that have been left behind by wa-

ter evaporation. Water chemistry must be carefullycontrolled to assure that this concentrate does notprecipitate solids or cause corrosion within the boilercircuitry. Boiler water chemistry must also be controlledto prevent excessive carryover of impurities or chemi-cals with the steam.

Customized chemistry limits and treatment prac-tices must be established for each boiler. These limitsdepend on steam purity requirements, feedwaterchemistry, and boiler design. They also depend onboiler owner/operator preferences regarding economictradeoffs between feedwater purification, blowdownrate, frequency of chemical cleaning, and boiler main-tenance and repair. Direct boiler water treatment(usually referred to as internal treatment) practicescommonly used to control boiler water chemistry in-clude all volatile treatment, coordinated phosphatetreatments, high-alkalinity phosphate treatments,and high-alkalinity chelant and polymer treatments.In all cases, when treatment chemicals are mixed, theidentity and purity of chemicals must be verified andwater of hydration in the weight of chemicals mustbe taken into account. The specific treatment usedmust always be developed and managed by compe-tent water chemistry specialists.

Feedwater is the primary source of solids that con-centrate in boiler water, and feedwater purity definesthe practical limit below which the boiler water solidsconcentration can not be reduced with an acceptableblowdown rate. Additionally, hardness and pre-boilercorrosion products carried by the feedwater play ma-jor roles in defining the type of boiler water treatmentthat must be employed. Where substantial hardnessis present in feedwater, provision must be made toensure that the hardness constituents remain in so-lution in the boiler water or to otherwise minimize theformation of adherent deposits. This is often accom-plished by use of chelant, polymer, or high-alkalinityphosphate boiler water treatment. Where substantialhardness is not present, boiler water treatment can beoptimized to minimize impurity carryover in the steamand to minimize the potential for boiler tube corrosion.

Because boiler water impurities and treatmentchemicals carry over in the steam, steam purity re-quirements play a major role in defining boiler waterchemistry limits. Boiler specifications normally includea list of boiler-specific water chemistry limits that mustbe imposed to attain a specified steam purity. Limitsmust always be placed on the maximum dissolvedsolids concentration. Limits must also be placed onimpurities and conditions that cause foaming at thesteam-water interface in the drum. These include lim-its on oil and other organic contaminants, suspendedsolids, and alkalinity. The carryover factor is the ratioof an impurity or chemical species in the steam to thatin the boiler water.

BlowdownThe dissolved solids concentration of boiler water

is intermittently or continuously reduced by blowingdown some of the boiler water and replacing it withfeedwater. Blowdown rate is generally expressed as apercent relative to the steam flow rate from the drum.



Blowdown is accomplished through a pressure letdownvalve and flash tank. Heat loss is often minimized byuse of a regenerative heat exchanger.

The ratio of the concentration of a feedwater im-purity in the boiler water to its concentration in thefeedwater is the concentration factor, which can be es-timated by use of Equation 1. However, a more com-plex formula must be used where there is substantialcarryover.

If there is no blowdown, solids concentrate untilcarryover with the steam is sufficient to carry awayall of the solids that enter the boiler with the feed-water. For example, where the feedwater silica con-centration is 0.01 ppm and 10% of the silica in theboiler water carries over with the steam, the equilib-rium boiler water silica concentration is 0.1 ppm.

Traditional all volatile treatmentFor all volatile treatment (AVT), no solid chemicals

are added to the boiler or pre-boiler cycle. Boiler wa-ter chemistry control is by boiler feedwater treatmentonly. No chemical additions are made directly to thedrum. Feedwater pH is controlled with ammonia oran alternate amine. Because ammonia carries awaypreferentially with the steam, the boiler water pH maybe slightly lower (0.2 to 0.4 pH units) than the feed-water pH. For traditional all volatile treatment, as op-posed to oxygen treatment, hydrazine or a suitablealternate is added to scavenge residual oxygen. Table1 shows the recommended AVT feedwater control lim-its. Because all volatile treatment adds no solids to theboiler water, solids carryover is generally minimized.

All volatile treatment provides no chemical controlfor hardness deposition and provides no buffer againstcaustic or acid-forming impurities. Hence, feedwatermust contain no hardness minerals from condenserleakage or other sources. It must be high-purity con-densate or polished condensate with mixed-bed qual-ity demineralized makeup water.

All volatile treatment can be, but rarely is, usedbelow 1000 psig (6.9 MPa). Normally it is used onlyfor boilers operating at or above 2000 psig (13.8 MPa)drum pressure. It is not recommended for lower pres-sure boilers where other options are feasible. Whileall volatile treatment is one of several options for drumboilers, it is the only option for once-through boilers.

Oxygen treatmentEven in the absence of dissolved oxygen, steel sur-

faces react with water to form some soluble Fe++ ionswhich may deposit in the boiler, superheater, turbine,or other downstream components. However, in the ab-sence of impurities, oxygen can form an especially pro-tective Fe+++ iron oxide that is less soluble than thatformed under oxygen-free conditions. To take advantageof this, some copper-free boiler cycles operating with ul-tra pure feedwater maintain a controlled concentrationof oxygen in the feedwater. Most of these are high pres-sure once-through utility boilers, but this approach is alsoused successfully in some drum boilers.

Oxygen treatment was developed in Europe, largelyby Vereinigung der Grosskesselbetreiber (VGB),11 andthere is also extensive experience in the former So-

viet Union (FSU). It can only be used where there isno copper in the pre-boiler components beyond thecondensate polisher, and where feedwater is consis-tently of the highest purity, e.g., cation conductivity< 0.15 µS/cm at 77F (25C). A low concentration of oxy-gen is added to the condensate. The target oxygen con-centration is 0.050 to 0.150 ppm for once-throughboilers and 0.040 ppm for drum boilers. With oxygentreatment, the feedwater pH can be reduced, e.g.,down to 8.0 to 8.5. An advantage of oxygen treatmentis decreased chemical cleaning frequencies for theboiler. In addition, when oxygen treatment is used incombination with lower pH, the condensate polisherregeneration frequency is reduced.

Coordinated phosphate treatmentCoordinated phosphate-pH treatment, introduced

by Whirl and Purcell of the Duquesne Light Com-pany,12 controls boiler water alkalinity with mixturesof disodium and trisodium phosphate added to thedrum through a chemical feed pipe. The objective ofthis treatment is largely to keep the pH of boiler wa-ter and underdeposit boiler water concentrates withinan acceptable range. Fig. 5 indicates the phosphateconcentration range that is generally necessary andsufficient for this purpose. Phosphate treatment mustnot be used where the drum pressure exceeds 2800psig (19.3 MPa). All volatile treatment is recommendedat the higher pressures.

In sodium phosphate solutions, an H+ + PO4≡ →HPO4= balance buffers the pH (i.e., retards H+ ion con-centration changes). Solution pH depends on thephosphate concentration and the molar sodium-to-phosphate ratio. The relationship between pH, phos-phate concentration, and molar sodium-to-phosphateratio is shown in Fig. 6. Where solutions contain otherdissolved salts (e.g., sodium and potassium chlorideand sulfate), sodium phosphate can still be used to con-trol pH, and the curves of Fig. 6 are still applicable.However, for such solutions, the sodium-to-phosphateratio labels on these curves are only apparent valueswith reference to pure sodium phosphate solutions.Measured sodium concentrations can not be used incalculating sodium-to-phosphate ratios for control of

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

Pho

spha

te, p

pm

100

10

11 10 100 1000 10000

Dissolved Solids, ppm



boiler water pH because measured sodium concentra-tions include non-phosphate sodium salts. While dis-solved sodium chloride and sulfate do not alter boilerwater pH, ammonia does alter the pH. Hence, thepresence of ammonia must be taken into accountwhere ammonia concentrations are significant com-pared to phosphate concentrations.

Historically, the initial goal of coordinated pH-phos-phate control was to keep the effective molar sodium-to-phosphate ratio just below 3, to prevent caustic stresscorrosion cracking, acid corrosion, and hydrogen dam-age. This proved to be an effective method for controlof deposition and corrosion in many boilers. However,caustic gouging of furnace wall tubes occurred in someboilers using coordinated pH-phosphate control, andlaboratory tests indicated that solutions with molarsodium-to-phosphate ratios greater than about 2.85 canbecome caustic when highly concentrated. Subse-quently, many boilers were operated under congruentcontrol with a target effective sodium-to-phosphateratio of less than 2.85, generally about 2.6, and oftenless than 2.6. Again, this proved to be an effectivemethod of control for many boilers, but some of theboilers operating with low molar sodium-to-phosphateratios experienced acid phosphate corrosion. Instancesof boiler tube corrosion generally occurred in boilers thatexperienced substantial phosphate hideout and hide-out-return when the boiler load changed.

Phosphate hideout, hideout-return, and associatedcorrosion problems are now addressed by equilibriumphosphate treatment.13 The concentration of phosphatein the boiler water is kept low enough to avoid hide-out and hideout return associated with load changes,thus it is always in equilibrium with the boiler. Theeffective molar sodium-to-phosphate ratio is keptabove 2.8. The free hydroxide, as depicted in Fig. 6,is not to exceed the equivalent of 1 ppm sodium hy-droxide. Concern about caustic gouging at the higherratios is largely reduced by experience with this treat-

ment regime and by experience with caustic boilerwater treatment.

Tables 2 and 3 show recommended boiler waterchemistry limits. Customized limits for a specific boilerdepend on the steam purity requirements for theboiler. Boiler and laboratory experience indicate that,under some conditions, phosphate-magnetite interac-tions can degrade protective oxide scale and corrodethe underlying metal. To minimize these interactions,the pH must be greater than that corresponding to the2.6 sodium-to-phosphate ratio curve of Fig. 6, andpreferably greater than that corresponding to the 2.8curve. The pH must always be above the 2.8 curvewhen the drum pressure is above 2600 psig (17.9MPa). The maximum pH is that of trisodium phos-phate plus 1 ppm sodium hydroxide. Additionally, theboiler water pH is not to be less than 9 nor greaterthan 10. As discussed below, it may be necessary toreduce the maximum boiler water phosphate concen-tration to avoid hideout and hideout return, and toavoid associated control and corrosion problems.

Table 2Boiler Water Limits

Pressure Maximum Range, Maximum Suspended Maximum psig (MPa) TDS, ppm Solids, ppm Silica, ppm

15 to 50* 1250 15 30(0.10 to 0.35)

15 to 50** 3500 15 150(0.10 to 0.35)

51 to 325 3500 10 150(0.35 to 2.24)

326 to 450 3000 8 90(2.25 to 3.10)

451 to 600 2500 6 40(3.11 to 4.14)

601 to 750 2000 4 30(4.14 to 5.17)

751 to 900 1500 2 20(5.18 to 6.21)

901 to 1000 1250 1 8(6.21 to 6.90)

* For natural separation 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 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

pH

11

10.5

10

9.5

91Phosphate, ppm

10 100

Na/PO4 = 2.8Na/PO4 = 2.6Na/PO4 = 2.4

Na/PO4 = 3.0 + 1ppm NaOHNa/PO4 = 3.0

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



Phosphate treatment chemicals may hide out dur-ing periods of high-load operation, then return to theboiler water when the load and pressure are reduced.This type of hideout makes control of boiler waterchemistry difficult and can cause corrosion of furnacewall tubes. This hideout and return phenomena iscaused by concentration of phosphate at the tube/water interface in high heat flux areas. In these ar-eas, phosphates accumulate in the concentrated liq-uid. The concentrated phosphates then precipitate, orthey adsorb on or react with surface deposits andscale.13,14,15 Where excessive deposits are not present,this hideout and hideout return associated with loadand pressure changes can be eliminated by decreas-ing the phosphate concentration in the boiler wateror possibly by increasing the sodium-to-phosphateratio. Where hideout and hideout-return are causedby excessive deposits, the boiler must be chemicallycleaned. The amount of phosphate hideout or returnaccompanying load changes must not be more than 5ppm. Corrective action is necessary if the amount ofphosphate hideout or return accompanying loadchanges is more than 5 ppm and/or the boiler waterpH change is more than 0.2 pH units, or where thereare changes in the hideout/hideout-return behavior.

This phenomenon must be distinguished from loss ofphosphate to passive film formation. As the passive ox-ide film reforms following a chemical cleaning of theboiler, some phosphate is irreversibly lost from the boilerwater. This is minimized if chemical cleaning is followedby a phosphate boilout repassivation of the boiler.

Operators should not over-correct for deviations of

pH and phosphate concentration from target values.Corrective action must be taken with an understand-ing of system response times, the amounts of impuri-ties being neutralized, and the amount of treatmentchemicals likely to be required.

Where phosphate treatment is used, pH is an es-pecially critical parameter, so the accuracy of pH mea-suring devices and temperature corrections must beassured. The boiler water pH must also be correctedto discount the pH effect of residual ammonia in theboiler water. Fig. 7 shows the estimated effect of am-monia on boiler water pH. The figure indicates theexpected pH for solutions with different concentrationsof sodium phosphate and 0.2 ppm ammonia. Wherethese species dominate the solution chemistry, suchfigures may be used to estimate sodium-to-phosphatemolar ratios.

With high purity feedwater, the recommended boilerwater pH can be attained with appropriate additionsof trisodium phosphate. If the recommended boilerwater pH can not be maintained within the above lim-its using trisodium phosphate or a mixture of triso-dium and disodium phosphate, this is indicative ofalkaline or acid-forming impurities in the feedwateror excessive hideout, and the root cause must be ad-dressed. An exception is low level equilibrium phos-phate treatment, where the small amount of trisodiumphosphate added to the boiler water may at times beinsufficient to achieve the recommended pH. A smallamount of sodium hydroxide may be added to attainthe recommended pH, but the excess sodium hydrox-ide must not exceed 1.0 ppm.13 Even 1.0 ppm sodium

Table 3Boiler Water Limits for Coordinated Phosphate Boiler Water Treatment

Pressure, psig (MPa)

15 to 1000 1001 to 1500 1501 to 2600 2601 to 2800 (0.10 to 6.90) (6.90 to 10.34) (10.35 to 17.93) (17.93 to 19.31)

Maximum Defined by Table 2 or as 100 ppm or as necessary to 50 ppm or as necessary to 15 ppm or as necessary toTDS, ppm necessary to attain required attain required steam attain required steam attain required steam steam purity, whichever is less purity, whichever is less purity, whichever is less purity, whichever is less

Maximum sodium, ppm Maximum sodium concentration (if any) as necessary to attain required steam purity

Maximum Defined by Table 2 or as 2 ppm or as necessary to 0.5 ppm or as necessary to 0.1 ppm or as necessary tosilica, ppm necessary to attain required attain required steam attain required steam attain required steam steam purity, whichever is less purity, whichever is less purity, whichever is less purity, whichever is less.

Phosphate as PO4, ppm See Fig. 5

"Effective"Na/PO4molar 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 9.0 to 10.0 and as dictated 9.0 to 10.0 and as dictated by Figs. 6 and 7 by Figs. 6 and 7 by Figs. 6 and 7

Maximum specific conduc-tivity, µS/cm Twice the maximum TDS (ppm).

Note:ppm = mg/kg



hydroxide may be excessive for some units, for ex-ample oil-fired boilers with especially high heat fluxesin some areas of the furnace.

When mixing boiler water treatment chemicals,operators should verify the identity and purity of thechemicals and take into account water of hydrationin the weight of the chemicals. Neither phosphoric acidnor monosodium phosphate should be used for rou-tine boiler water treatment. If monosodium phosphateis used to counter an isolated incident of alkali con-tamination of the boiler water, it must be used withcaution, and at reduced load.

High-alkalinity phosphate treatment(low-pressure boilers only)

Minimal carryover and deposition are achievedwith demineralized makeup water and minimal dis-solved solids, but this is not necessarily cost-effectivefor all low pressure industrial boilers. Where softenedwater with 0.02 to 0.5 ppm residual hardness (asCaCO3) is used as makeup water for low pressure in-dustrial boilers, high alkalinity or conventional phos-phate treatment may be used to control scale forma-tion. This high alkalinity treatment must only be usedfor boilers operating below 1000 psig (6.9 MPa). ThepH and phosphate concentrations are attained byaddition of a trisodium phosphate and (if necessary)sodium hydroxide solution through a chemical feedline into the drum. With high-alkalinity phosphatetreatment, the boiler water pH is maintained in therange of 10.8 to 11.4. This high pH precipitates hard-ness constituents that are less adherent than thoseformed at lower pH.

Where high alkalinity boiler water is excessivelyconcentrated by evaporation, the concentrate can be-come sufficiently caustic to produce caustic gougingor stress corrosion cracking of carbon steel. Hence,high-alkalinity boiler water treatment must not be

used where waterside deposits are excessively thick,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 forhigh-alkalinity phosphate treatment. With somefeedwaters (e.g., high-magnesium low-silica), lowerphosphate concentrations may be advisable. The re-quired pH is attained by adjusting the sodium hydrox-ide concentration in the chemical feed solution. Thetotal (M alkalinity in calcium carbonate equivalents)must not exceed 20% of the actual boiler water solidsconcentration.

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

Where substantial hardness (e.g., 0.1 ppm asCaCO3) is present in feedwater, chelant treatment isoften used to ensure that the hardness constituentsremain in solution in the boiler water, or polymertreatment is used to keep precipitates in suspension.Blowdown of the dissolved contaminants and colloidsis more effective than that of noncolloidal hardnessprecipitates and metal oxides.

While phosphate treatment precipitates residualcalcium and magnesium in a less detrimental formthan occurs in the absence of phosphate, chelants re-act with calcium and magnesium to form soluble com-pounds that remain in solution. Chelants commonlyemployed include ethylene-diaminetetraacetic acid(EDTA) and nitrilotriacetic acid (NTA). Because of con-cern about thermal stability, the use of chelants andpolymers should be limited to boilers operating at lessthan 1000 psi (6.9 MPa).

To be most effective, chelant must mix with the feed-water and form thermally stable calcium and magne-sium complexes before there is substantial residencetime at high temperature, where free chelant is notthermally stable. Because the combination of freechelant and dissolved oxygen can be corrosive, chelantmust be added only after completion of oxygen removaland scavenging. Also, there must be no copper-bear-ing components in the feedwater train beyond thechelant feed point.

Control limits depend on the feedwater chemistry,specific treatment chemicals used, and other factors.However, the boiler feedwater pH is generally be-

pH

10

9.8

9.6

9.4

9.2

9

8.80 1 2 3 4 5 6 7

Phosphate, ppm

Na/PO4 = 2.8Na/PO4 = 2.6

NH3 PO4 + 1ppm NaOHNa/PO4 = 3.0

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

Phos

phat

e, p

pm

70

60

50

40

30

20

10200

(1379)

Operating Pressure, psig (kPa)

Maximum

Optimum

Minimum

400(2758)

1000(6895)

0(0)

600(4137)

800(5516)

Fig. 8 Phosphate concentration limits for high-alkalinity phosphatetreatment.



tween 9.0 and 9.6 and hardness as calcium carbon-ate is less than 0.5 ppm. The boiler water pH is gen-erally maintained in the range of 10.0 to 11.4. Theboiler water pH is attained by a combination of alka-linity derived from the chelant feed (e.g., as Na4

EDTA), evolution of CO2 from softened feedwater, andaddition of sodium hydroxide. Polymeric dispersantsare generally used to impede formation of scale byresidual solids.

Once-through universal pressure boilersIn a subcritical once-through boiler, there is no

steam drum. As water passes through boiler tubing,it evaporates entirely into steam. Because steam doesnot cool the tube as effectively as water, the tube tem-perature increases beyond this dry-out location. Sub-critical once-through boilers are designed so this tran-sition occurs in a lower heat flux region of the boilerwhere the temperature increase is not sufficient tocause a problem. However, because the water evapo-rates completely, it must be of exceptional purity toavoid corrosion and rapid deposition, and carryoverof dissolved solids.

Similarly stringent water purity requirements mustbe imposed for supercritical boilers. While there is nodistinction between water and steam in a supercriti-cal boiler, the physical and chemical properties of thefluid change as it is heated, and there is a tempera-ture about which dissolved solids precipitate much asthey do in the dry-out zone of a subcritical once-through boiler. This is termed the pseudo transitionzone. (See Chapter 5.)

Satisfactory operation of a once-through boiler andassociated turbine requires that the total feedwatersolids be less than 0.030 ppm total dissolved solids withcation conductivity less than 0.15 µS/cm. Table 1 listsrecommended limits for other feedwater parameters.Feedwater purification must include condensate polish-ing, and water treatment chemicals must all be vola-tile. Ammonia is typically added to control pH. For tra-ditional all volatile treatment, hydrazine or a suitablevolatile substitute is used for oxygen scavenging. Ironpickup from pre-boiler components can be minimizedby maintaining a feedwater pH of 9.3 to 9.6. Prior toplant startup, feedwater must be circulated through thecondensate polishing system to remove dissolved andsuspended solids. Temperatures should not exceed 550F(288C) at the convection pass outlet until the iron lev-els are less than 0.1 ppm at the economizer inlet.

Utility once-through boilers with copper-free cyclemetallurgy commonly use oxygen treatment. Table 1includes recommended limits for other feedwater chemi-cal parameters for oxygen treatment. Startup is withincreased pH and no oxygen feed. Oxygen addition tofeedwater is initiated and pH is reduced only after feed-water cation conductivity is less than 0.15 µS/cm.

System transients and upsets inevitably cause ex-cursions above recommend limits. Increased rates ofdeposition and corrosion are likely to be in proportionto the deviations. Small brief deviations may individu-ally be of little consequence, but the extent, duration,and frequency of such deviations should be minimized.

Otherwise, over a period of years the accumulative ef-fects will be significant. Potential effects include in-creased deposition, pitting, pressure drop, and fatiguecracking. Particular care is required to minimize theextent and duration of chemistry deviations for cyclingunits where operational transients are frequent.

Steam purityPurity or chemistry requirements for steam can be

as simple as a specified maximum moisture content,or they can include maximum concentrations for avariety of chemical species. Often, for low-pressurebuilding or process heater steam, only a maximummoisture content is specified. This may be as high as0.5% or as low as 0.1%. Conversely, some turbinemanufacturers specify steam condensate maximumcation conductivity, pH, and maximum concentrationsfor total dissolved solids, sodium and potassium, silica,iron, and copper. Turbine steam must generally havetotal dissolved solids less than 0.050 ppm, and in somecases less than 0.030 ppm. Individual species limitsmay be still lower. If steam is to be superheated, amaximum steam dissolved solids limit must be imposedto avoid excessive deposition and corrosion of the su-perheater. This limit is generally 0.100 ppm or less.Even where steam purity requirements are not im-posed by the application, steam dissolved solids con-centrations less than 1.0 ppm are recommended atpressures up to 600 psig (4.1 MPa), dissolved solidsconcentrations less than 0.5 ppm are recommended at600 to 1000 psig (4.1 to 6.9 MPa), and dissolved sol-ids concentrations less than 0.1 ppm are recommendedabove 1000 psig (6.9 MPa).

Up to 2000 psig (13.8 MPa), most non-volatile chemi-cals and impurities in the steam are carried by smallwater droplets entrained in the separated steam. Be-cause these droplets contain dissolved solids in the sameconcentration as the boiler water, the amount of impu-rities in steam contributed by this mechanical carryoveris the sum of the boiler water impurities concentrationmultiplied by the steam moisture content. Mechanicalcarryover is limited by moisture separation devices placedin the steam path, as described in Chapter 5.

High water levels in the drum and boiler waterchemistries that cause foaming can cause excessivemoisture carryover and therefore excessive steamimpurity concentrations. Foaming is the formation offoam or excessive spray above the water line in thedrum. Common causes of foaming are excessive sol-ids or alkalinity, and the presence of organic mattersuch as oil. To keep dissolved solids below the concen-tration that causes foaming requires continuous orperiodic blowdown of the boiler. High boiler water al-kalinity increases the potential for foaming, particu-larly in the presence of suspended matter.

Where a chemical species is sufficiently volatile, italso carries over as a vapor in the steam. Total carry-over is the sum of the mechanical and vaporous car-ryover. Vaporous carryover depends on solubility insteam and is different for each chemical species. Formost dissolved solids found in boiler water, it is negli-gible by comparison to mechanical carryover at pres-



sures less than 2000 psig (13.8 MPa). An exception issilica for which vaporous carryover can be substan-tial at lower pressures. Fig. 9 shows typical vaporouscarryover fractions (distribution ratios) for commonboiler water constituents under typical conditions overa wide range of boiler pressures. Fig. 10 shows ex-pected total dissolved solids carryover for typical high-pressure boilers. Vaporous carryover depends on pres-sure and on boiler water chemistry. It is not affectedby boiler design. Hence, if vaporous carryover for aspecies is excessive, the carryover can only be reducedby altering the boiler water chemistry. Only mechani-cal carryover is affected by boiler design. Non-inter-active gases such as nitrogen, argon, and oxygencarry over almost entirely with the steam, having norelationship to moisture carryover.

Excessive steam impurity concentrations can alsobe caused by feedwater and boiler water chemistriesthat favor volatile species formation. Carryover ofvolatile silica can be problematic at pressures above1000 psig (6.9 MPa). Fig. 11 shows boiler water silicaconcentration limits recommended to obtain steamsilica concentrations less than 0.010 ppm at pressuresup to 2900 psig (20.0 MPa) where the pH may be aslow as 8.8. Vaporous silica carryover at a pH of 10.0is 88% of that at a pH of 8.8. The vaporous silica carry-over at a pH of 11.0 is 74% of that at 8.8. The only effec-tive method for preventing excessive silica or other va-porous carryover is reduction of the boiler water concen-trations. Another common source of excessive impuritiesin steam is inadequate attemperation spray water pu-rity. All impurities in the spray water enter directly intothe steam. Procedures for measuring steam quality andpurity are discussed in Chapter 40.

Water sampling and analysisA key element in control of water and steam chem-

istry is effective sampling to obtain representativesamples, prevent contamination of the samples, andprevent loss of the species to be measured.17 References18 and 19 provide detailed procedures. In general,sample lines should be as short as possible and madeof stainless steel, except where conditions dictate oth-erwise. Samples should be obtained from a continu-ously flowing sample stream. The time between sam-pling and analysis should be as short as possible.Samples should be cooled quickly to 100F (38C) toavoid loss of the species of interest. Sample nozzles andlines should provide for isokinetic sample velocity andmaintain constant high water velocities [minimum of6 ft/s (1.8 m/s)] to avoid loss of materials. Samplepoints should be at least 10 diameters downstream ofthe last bend or flow disturbance.

Guidelines and techniques for chemical analysis ofgrab samples are listed in Table 4. The detailed meth-ods are readily available from the American Society forTesting and Materials (ASTM) in Philadelphia, Penn-sylvania, U.S. and the American Society of Mechani-cal Engineers (ASME) in New York, New York, U.S.

Wherever practical, on-line monitoring should beconsidered as an alternative to grab samples. Thisgives real-time data, enables trends to be followed,and provides historical data. However, on-line moni-tors require calibration, maintenance, and checks withgrab samples or on-line synthesized standard samplesto ensure reliability. Table 5 lists important on-linemonitoring measurements and references to specificmethods. In addition to the measurements listed, in-

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

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



strumentation is commercially available to monitorchloride, dissolved oxygen, dissolved hydrogen, silica,phosphate, ammonia and hydrazine.

Adequate water chemistry control depends on theability of boiler operators to consistently measure thespecified parameters. Hence, formal quality assuranceprograms should be used to quantify and track theprecision and bias of measurements. Detailed proce-dures should be in place to cover laboratory structure,training, standardization, calibration, sample collec-tion/storage/analysis, reporting, maintenance records,and corrective action procedures. Further discussionis provided in Reference 20.

Common fluid-side corrosion problemsWater and steam react with most metals to form

oxides or hydroxides. Formation of a protective oxidelayer such as magnetite (Fe3O4) on the metal surfacecauses reaction rates to slow with time. Boiler cyclewater treatment programs are designed to maintainsuch protective oxide films on internal surfaces andthus prevent corrosion in boilers and other cycle com-ponents. With adequate control of water and steamchemistry, internal corrosion of boiler circuitry can beminimized. Yet, chemistry upsets (transient losses ofcontrol) do occur. Vigilant monitoring of system chem-istry permits quick detection of upsets and quick re-medial action to prevent boiler damage. Where thesemeasures fail and corrosion occurs, good monitoringand documentation of system chemistry can facilitateidentification of the root cause, and identification of thecause can be an essential step toward avoiding furthercorrosion. Where corrosion occurs and the origin isunknown, the documented water chemistry, location of

Table 4Guidelines for Measurements on Grab Samples

Reference/ CommentMeasurement Technique(s) (Notes 1 and 2)

pH Electrometric ASTM D 1293 Method A

Conductivity Dip or flow type conductivity ASTM D 1125 cells energized with Methods A or B alternating current at a constant frequency (Wheatstone Bridge)

Dissolved Colorimetric or ASTM D 888oxygen titrimetric Methods A, B, C

Suspended Membrane comparison ASME PTC 31iron oxides charts Ion exchange equipment

Iron Photometric ASTM D 1068 (bathophenanthroline) Method C, D or atomic absorption (graphite furnace)

Copper Atomic absorption ASTM D 1688 (graphite furnace) Method C

Sodium Atomic absorption or ASTM D 4191 or flame photometry ASTM D 1428

Silica Colorimetric or ASTM D 859 or atomic absorption ASTM D 4517

Phosphate Ion chromatography or ASTM D 4327 or photometric ASTM D 515 Method A

Ammonia Colorimetric ASTM D 1426 (nesslerization) or Method A or B ion-selective electrode

Hydrazine Colorimetric ASTM D 1385

Chloride Colorimetric, ASTM D 512 or ion-selective electrode ASTM D 4327 or ion chromatography

Sulfate Turbidimetric or ion ASTM D 516 or chromatography ASTM D 4327

Calcium and Atomic absorption; ASTM D 511 ormagnesium gravimetric or ASTM D 1126 titrimetric

Fluoride Ion-selective electrode ASTM D 1179 or or ion chromatography ASTM D 4327

Morpholine Colorimetric ASTM D 1942

Alkalinity Color-change titration ASTM D 1067 Method B

Hydroxide ion Titrimetric ASTM D 514in water

Total organic Instrumental (oxidation ASTM D 4779carbon and infrared detection)

Notes:1. ASME PTC refers to Performance 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.

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

Max

imum

Boi

ler W

ater

Silic

a, p

pm

Drum Pressure, psig (kPa)

100

10

1

0.1

0.010

(0)500

(3447)1000

(6895)1500

(10,342)2000

(13,790)2500

(17,237)3000

(20,684)



the corrosion, appearance of the corrosion, and chem-istry of localized deposits and corrosion products oftensuggest the cause. Common causes are flow acceleratedcorrosion, oxygen pitting, chelant corrosion, causticcorrosion, acid corrosion, organic corrosion, acid phos-phate corrosion, hydrogen damage, and corrosion as-sisted cracking. Figs. 12 and 13 show typical locationsof common fluid-side corrosion problems. Further dis-

cussion of corrosion and failure mechanisms is providedin References 21, 22, 23, and 24. For EPRI members,Boiler Tube Failures: Theory and Practice25 provides anespecially thorough description of utility boiler corro-sion problems, causes, and remedial measures.

One distinguishing feature of corrosion is its ap-pearance. Metal loss may be uniform so the surfaceappears smooth. Conversely, the surface may begouged, scalloped, or pitted. Other forms of corrosionare microscopic in breadth, and subsurface, so theyare not initially discernible. Subsurface forms of corro-sion include intergranular corrosion, corrosion fatigue,stress corrosion cracking, and hydrogen damage. Suchcorrosion can occur alone or in combination with sur-face wastage. In the absence of component failure, de-tection of subsurface corrosion often requires ultra-sonic, dye penetrant, or magnetic particle inspection(Chapter 45). These forms of corrosion are best diag-nosed with destructive cross-section metallography.

Another distinguishing feature is the chemical com-position of associated surface deposits and corrosionproducts. Deposits may contain residual corrosives suchas caustic or acid. Magnesium hydroxide in deposits cansuggest the presence of an acid-forming precipitationprocess. Sodium ferrate (Na2FeO4) indicates causticconditions. Sodium iron phosphate indicates acid phos-phate wastage. Organic deposits suggest corrosion byorganics, and excessive amounts of ferric oxide or hy-droxide with pitting suggest oxygen attack.

Flow accelerated corrosion is the localized dissolu-tion of feedwater piping in areas of flow impingement.It occurs where metal dissolution dominates over pro-tective oxide scale formation. For example, localized

Table 5On-line Monitoring Measurements

Measurement Technique(s) Reference

pH Electrometric ASTM D 5128

Conductivities Electrical conductivity ASTM D 4519(general, cation measurement before and and degassed) after hydrogen cation exchanges and at atmospheric boiling water after acidic gas removal

Sodium Selective ion electrode ASTM D 2791 flame photometry

Total organic Instrumental (oxidation ASTM D 5173carbon and measurement of carbon dioxide)

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

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



conditions are sufficiently oxidizing to form solubleFe++ ions but not sufficiently oxidizing to form Fe+++

ions needed for protective oxide formation. Conditionsknown to accelerate thinning include: flow impinge-ment on pipe walls, low pH, excessive oxygen scav-enger concentrations, temperatures in the range of250 to 400F/121 to 204C (although thinning can oc-cur at any feedwater temperature), chemicals (suchas chelants) that increase iron solubility, and thermaldegradation of organic chemicals. Thinned areas of-ten have a scalloped or pitted appearance. Failures,such as that shown in Fig. 14, can occur unexpect-edly and close to work areas and walkways. To assurecontinued integrity of boiler feedwater piping, it mustbe periodically inspected for internal corrosion andwall thinning. Any thinned areas must be identifiedand replaced before they become a safety hazard. Theaffected piping should be replaced with low-alloy chro-mium-bearing steel piping, and the water chemistrycontrol should be appropriately altered.

Oxygen pitting and corrosion during boiler opera-tion largely occur in pre-boiler feedwater heaters andeconomizers where oxygen from poorly deaeratedfeedwater is consumed by corrosion before it reachesthe boiler. A typical area of oxygen pitting is shown inFig. 15. Oxygen pitting within boilers occurs whenpoorly deaerated water is used for startup or for ac-celerated cooling of a boiler. It also occurs in feedwaterpiping, drums, and downcomers in some low pressureboilers which have no feedwater heaters or econo-mizer. Because increasing scavenger concentrationsto eliminate residual traces of oxygen can aggravateflow accelerated corrosion, care must be taken to dis-tinguish between oxygen pitting and flow accelerated

corrosion which generally occurs only where all tracesof oxygen have been eliminated.

Chelant corrosion occurs where appropriate feed-water and boiler water chemistries for chelant treat-ment are not maintained. Potentially corrosive condi-tions include excessive concentration of free chelantand low pH. (See prior discussion of boiler water treat-ment with dispersants, polymers, and chelants.) Es-pecially susceptible surfaces include flow impingementareas of feedwater piping, riser tubes, and cyclonesteam/water separators. Affected areas are often darkcolored and have the appearance of uniform thinningor of flow accelerated corrosion.

Corrosion fatigue is cracking well below the yieldstrength of a material by the combined action of cor-rosion and alternating stresses. Cyclic stress may beof mechanical or thermal origin (Chapter 8). In boil-ers, corrosion fatigue is most common in water-wet-ted surfaces where there is a mechanical constrainton the tubing. For example, corrosion fatigue occursin furnace wall tubes adjacent to windbox, buckstay,and other welded attachments. Failures are thick lipped.On examination of the internal tube surface, multipleinitiation sites are evident. Cracking is transgranular.Environmental conditions facilitate fatigue crackingwhere it would not otherwise occur in a benign environ-ment. Water chemistry factors that facilitate crackinginclude dissolved oxygen and low pH transients associ-ated with, for example, cyclic operation, condenser leaks,and phosphate hideout and hideout-return.

Acid phosphate corrosion occurs on the inner steam-forming side of boiler tubes by reaction of the steel withphosphate to form maricite (NaFePO4). Fig. 16 showsribbed tubing that has suffered this type of wastage.The affected surface has a gouged appearance withmaricite and magnetite deposits. Acid phosphate cor-rosion occurs where the boiler water effective sodium-to-phosphate ratio is less than 2.8, although ratios aslow as 2.6 may be tolerated at lower pressures.Though not always apparent, common signs of acidphosphate corrosion include difficulty maintainingtarget phosphate concentrations, phosphate hideoutand pH increase with increasing boiler load or pres-sure, phosphate hideout return and decreasing pHwith decreasing load or pressure, and periods of highiron concentration in boiler water. The potential foracid phosphate corrosion increases with increasinginternal deposit loading, decreasing effective sodium-to-phosphate molar ratio below 2.8, increasing phos-phate concentration, inclusion of acid phosphates (di-sodium and especially monosodium phosphate) inphosphate feed solution, and increasing boiler pres-sure. To avoid acid phosphate corrosion, operatorsshould monitor boiler water conditions closely, assureaccuracy of pH and phosphate measurements, assurepurity and reliability of chemical feed solutions, as-sure that target boiler water chemistry parameters areappropriate and are attained in practice, and watchfor aforementioned signs of acid phosphate corrosion.

Under-deposit acid corrosion and hydrogen dam-age occur where boiler water acidifies as it concentratesbeneath deposits on steam generating surfaces. Hy-drogen from acid corrosion diffuses into the steel where

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



it reacts with carbon to form methane as depicted inFig. 17. The resultant decarburization and methaneformation weakens the steel and creates microfissures.Thick lipped failures like that shown in Fig. 18 occurwhen the degraded steel no longer has sufficientstrength to hold the internal tube pressure. Signs ofhydrogen damage include under deposit corrosion,thick lipped failure, and steel decarburization andmicrofissures. The corrosion product from acid corro-sion is mostly magnetite. Affected tubing, which mayextend far beyond the failure, must be replaced. Theboiler must be chemically cleaned to remove internaltube deposits, and boiler water chemistry must be al-tered or better controlled to prevent acid-formation asthe water concentrates. Operators should reduce acid-forming impurities by improving makeup water, re-ducing condenser leakage, or adding condensate pol-ishing. For drum boilers, operators should use phos-phate treatment with an effective sodium-to-phosphatemolar ratio of 2.8 or greater.

Caustic corrosion, gouging and grooving occurwhere boiler water leaves a caustic residue as it evapo-rates. In vertical furnace wall tubes, this occurs be-neath deposits that facilitate a high degree of concen-tration and the corroded surface has a gouged appear-ance as shown in Fig. 19. In inclined tubes where theheat flux is directed through the upper half of thetube, caustic concentrates by evaporation of boilerwater in the steam space on the upper tube surface.Resulting corrosion is in the form of a wide smoothgroove with the groove generally free of deposits andcentered on the crown of the tube. Deposits associatedwith caustic gouging often include Na2FeO4. To preventreoccurrence of caustic gouging, operators should pre-vent accumulation of excessive deposits and controlwater chemistry so boiler water does not form causticas it concentrates. The latter can generally be achievedby assuring appropriate feedwater chemistry with co-ordinated phosphate boiler water treatment, takingcare to control the effective sodium-to-phosphate mo-lar ratio as appropriate for the specific boiler and thespecific chemical and operating conditions. In some in-stances, where caustic grooving along the top of a slopedtube is associated with steam/water separation, suchseparation can be avoided by use of ribbed tubes whichcause swirling motion that keeps water on the tube wall.

Caustic cracking can occur where caustic concen-trates in contact with steel that is highly stressed, toor beyond the steel’s yield strength. Caustic crackingis rare in boilers with all welded connections. This

Fig. 16 Acid phosphate corrosion of ribbed tubing.

Fig. 15 Oxygen pitting of economizer feedwater inlet.

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

Fig. 18 Brittle tube failure in hydrogen damaged area.



generally occurs in boilers using a high alkalinitycaustic boiler water treatment, and it is normally as-sociated with unwelded rolled joints and welds thatare not stress relieved. On metallographic examina-tion, caustic cracking is intergranular and has thebranched appearance characteristic of stress corrosioncracking as illustrated in Fig. 20. It can generally beavoided by use of coordinated phosphate treatment.Where a high alkalinity caustic phosphate boiler wa-ter treatment is used for low pressure boilers, nitrateis often added to inhibit caustic cracking.

Overheat failures like that shown in Fig. 21 occurwhere deposits impede internal heat transfer to the

extent that a tube no longer retains adequate strengthand bulges or ruptures. Internal tube deposits gener-ally cause moderate overheating for extended periodsof time, causing long-term overheat failures. Short-term overheat failures generally occur only when thereis gross interruption of internal flow to cool the tube,or grossly excessive heat input.

Out-of-service corrosion is predominantly oxygenpitting. Pitting attributed to out-of-service corrosionoccurs during outages but also as aerated water isheated when boilers return to service. Especially com-mon locations include the waterline in steam drums,areas where water stands along the bottom of hori-zontal pipe and tube runs, and lower bends of pen-dant superheaters and reheaters. Pinhole failures are morecommon in thinner walled reheater and economizer tub-ing. Such corrosion can be minimized by following appro-priate layup procedures for boiler outages and by improv-ing oxygen control during boiler startups.

Pre-operational cleaningIn general, all new boiler systems receive an alka-

line boilout, i.e. hot circulation of an alkaline mixturewith intermittent blowdown and final draining of theunit. Many systems also receive a pre-operationalchemical cleaning. The superheater and reheatershould receive a conventional steam blow (a period ofhigh velocity steam flow which carries debris from thesystem). Chemical cleaning of superheater and reheatsurfaces is effective in reducing the number of steamblows to obtain clean surfaces, but is not required toobtain a clean superheater and reheater.

Alkaline boiloutAll new boilers should be flushed and given an al-

kaline boilout to remove debris, oil, grease and paint.This can be accomplished with a combination of triso-dium phosphate (Na3PO4) and disodium phosphate(Na2HPO4), with a small amount of surfactant addedas a wetting agent. The use of caustic NaOH and/orsoda ash (Na2CO3) is not recommended. If either isused, special precautions are required to protect boilercomponents.

Chemical cleaningAfter boilout and flushing are completed, corrosion

products may remain in the feedwater system andboiler in the form of iron oxide and mill scale. Chemi-cal cleaning should be delayed until full load opera-tion has carried the loose scale and oxides from thefeedwater system to the boiler. Some exceptions areunits that incorporate a full flow condensate polish-ing system and boilers whose pre-boiler system hasbeen chemically cleaned. In general, these units canbe chemically cleaned immediately following pre-op-erational boilout.

Different solvents and cleaning processes are usedfor pre-operational chemical cleaning, usually deter-mined by boiler type, metallic makeup of boiler compo-nents, and environmental concerns or restrictions. Thefour most frequently used are: 1) inhibited 5% hydro-chloric acid with 0.25% ammonium bifluoride, 2) 2%Fig. 20 Schematic of stress corrosion cracking.

Fig. 19 Caustic gouging initiated along weld backing ring.



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

Steam line blowingThe steam line blow procedure depends on unit

design. Temporary piping to the atmosphere is re-quired with all procedures. This piping must be an-chored to resist high nozzle reaction force.

All normal startup precautions should be observed forsteam line blowing. The unit should be filled with treateddemineralized water. Sufficient feedwater pump capac-ity and condensate storage must be available to replacethe water lost during the blowing period.

Numerous short blows are most effective. The colorof the steam discharged to the atmosphere providesan indication as to the quantity of debris being re-moved from the piping. Coupons (targets) of polishedsteel attached to the end of the exhaust piping aretypically used as final indicators.

Periodic chemical cleaning

Cleaning frequencyInternal surfaces of boiler water-side components (in-

cluding supply tubes, headers and drums) accumulatedeposits even though standard water treatment prac-tices are followed. These deposits are generally classifiedas hardness-type scales or soft, porous-type deposits.

To determine the need for cleaning, tube samplescontaining internal deposits should be removed fromhigh heat input zones of the furnace and/or areaswhere deposition problems have occurred. The depositweight is first determined by visually selecting aheavily deposited section. After sectioning the tube(hot and cold sides), the water-formed deposit is re-moved by scraping from a measured area. The weightof the dry material is reported as weight per unit area:either grams of deposit per square foot of tube surfaceor mg/cm2. Procedures for mechanical and chemicalmethods of deposit removal are provided in ASTMD3483.26 General guidelines for determining when aboiler should be chemically cleaned are shown in Table6. The deposit weights shown are based on the me-chanical scraping method. This removes the porousdeposit of external origin and most of the dense inneroxide scale. Values are slightly lower than those ob-tained from the chemical dissolution method.

Because of the corrosive nature of the fuel and itscombustion products, furnace tubes in Kraft recoveryand refuse-fired boilers are particularly susceptible togas-side corrosion which can be aggravated by rela-tively modest elevated tube metal temperatures. (SeeChapters 28 and 29.) Through-wall failures due toexternal metal corrosion can occur in these tubes atwater-side deposit weights much less than 40 g/ft2 (43mg/cm2). In addition, for Kraft recovery boilers thereare significant safety concerns for water leakage inthe lower furnace. (See Chapters 28 and 43.) For theseunits, a more conservative cleaning criterion is recom-mended for all operating pressures.

Chordal thermocouplesThe chordal thermocouple (see Chapter 40) can be

an effective diagnostic tool for evaluating deposits onoperating boilers. Properly located thermocouples canindicate a tube metal temperature increase caused byexcess internal deposits, and can alert the operator toconditions that may cause tube failures. Thermo-couples are often located in furnace wall tubes adja-cent to the combustion zone where the heat input ishighest and the external tube temperatures are alsohigh. (See Fig. 22.)

Deposition inside tubes can be detected by instru-menting key furnace tubes with chordal thermo-couples. These thermocouples compare the surfacetemperature of the tube exposed to the combustionprocess with the temperature of saturated water. Asdeposits grow, they insulate the tube from the coolingwater and cause tube metal temperature increases.

Beginning with a clean, deposit-free boiler, the in-strumented tubes are monitored to establish the tem-perature differential at two or three boiler ratings; thisestablishes a base curve. At maximum load, with cleantubes, the surface thermocouple typically indicatesmetal temperatures 25 to 40F (14 to 22C) above satu-ration in low duty units and 80 to 100F (44 to 56C) inhigh duty units as shown in Fig. 23. The temperaturevariation for a typical clean instrumented tube is de-pendent upon the tube’s location in the furnace, tubethickness, inside fluid pressure, and the depth of the

Table 6Guidelines for Chemical Cleaning

Water-side Unit Operating Deposit Weight* Pressure, psig (MPa) (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/ft2 = 1.07 mg/cm2 )

Fig. 21 Short-term overheat thin edged failure.



surface thermocouple. Internal scale buildup is de-tected by an increase in temperature differentialabove the base curve. Chemical cleaning should nor-mally be considered if the temperature differential atmaximum boiler load reaches 100F (56C).

Initially, readings should be taken weekly, prefer-ably using the same equipment and procedure as usedfor establishing the base curve. Under upset condi-tions, when deposits form rapidly, the checking fre-quency should be increased.

Chemical cleaning procedures and methodsIn general, four steps are required in a complete

chemical cleaning process:

1. The internal heating surfaces are washed with asolvent containing an inhibitor to dissolve or dis-integrate the deposits.

2. Clean water is used to flush out loose deposits,solvent adhering to the surface, and soluble ironsalts. Corrosive or explosive gases that may haveformed in the unit are also displaced.

3. The unit is treated to neutralize and passivate theheating surfaces. This treatment produces a pas-sive surface, i.e., it forms a very thin protective filmon freshly cleaned ferrous surfaces.

4. The unit is flushed with clean water to remove anyremaining loose deposits.

The two generally accepted chemical cleaningmethods are: 1) continuous circulation of the solvent(Fig. 24), and 2) filling the unit with solvent, allow-ing it to soak, then flushing the unit (Fig. 25).

Circulation cleaning methodIn the circulation (dynamic) cleaning method (Fig.

24), after filling the unit with demineralized water,the water is circulated and heated to the requiredcleaning temperature. At this time, the selected sol-vent is injected into the circulating water and recir-culated until the cleaning is completed. Samples of thereturn solvent are periodically tested. Cleaning is con-sidered complete when the acid strength and the iron

Fig. 22 Typical locations of chordal thermocouples.

Clean Tube

Saturation Temp500F (260C) at

665 psi (4.6 MPa)

Scaled Tube

80 g/ft2

500F(260C)

877F(469C)

785F(418C)

500F(260C)

500F(260C)

583F(306C)

510F(266C)

Heat Input120,000 Btu/h ft2(378,550 W/m2)

FurnaceSide

OuterCasingSide

Chemical Recovery Boiler

Typical Locations forChordal Thermocouples

Fossil Fuel-Fired Boiler

Typical Locations forChordal Thermocouples



content of the returned solvent reach equilibrium (Fig.26), indicating that no further reaction with the de-posits is taking place. In the circulation method, ad-ditional solvent can be injected if the dissipation of thesolvent concentration drops below the recommendedminimum concentration.

The circulation method is particularly suitable forcleaning once-through boilers, superheaters, andeconomizers with positive liquid flow paths to assurecirculation of the solvent through all parts of the unit.Complete cleaning can not be assured by this methodunless the solvent reaches and passes through everycircuit of the unit.

Soaking methodThe soaking (static) cleaning method (Fig. 25) in-

volves preheating the unit to a specified temperature,filling the unit with the hot solvent, then allowing theunit to soak for a period of time, depending on depositconditions. To assure complete deposit removal, theacid strength of the solvent must be somewhat greaterthan that required by the actual conditions; unlike thecirculation method, control testing during the courseof the cleaning is not conclusive, and samples of sol-vent drawn from convenient locations may not trulyrepresent conditions in all parts of the unit.

The soaking method is preferable for cleaning unitswhere definite liquid distribution to all circuits (by thecirculation method) is not possible without the use ofmany chemical inlet connections. The soaking methodis also preferred when deposits are extremely heavy,or if circulation through all circuits at an appreciablerate can not be assured without an impractically-sizedcirculating pump. These conditions may exist in largenatural circulation units that have complex furnacewall cooling systems.

Advantages of this method are simplicity of pipingconnections and assurance that all parts are reachedby a solvent of adequate acid strength.

SolventsMany acids and alkaline compounds have been

evaluated for removing boiler deposits. Hydrochloricacid (HCl) is the most practical cleaning solvent whenusing the soaking method on natural circulation boil-ers. Chelates and other acids have also been used.

An organic acid mixture such as hydroxyacetic-for-mic (HAF) is the safest chemical solvent when apply-ing the circulation cleaning method to once-throughboilers. These acids decompose into gases in the eventof incomplete flushing.

For certain deposits, the solvent may require addi-tional reagents, such as ammonium bifluoride, to pro-mote deposit penetration. Alloy steel pressure parts,particularly those high in chromium, should generallynot be cleaned with certain acid solvents. A generalguideline for solvent selection can be found in Table 7.

Prior to chemically cleaning, it is strongly recom-mended that a representative tube section be removedand subjected to a laboratory cleaning test to deter-mine and verify the proper solvent chemical, and con-centrations of that solvent.

DepositsScale deposits formed on the internal heating sur-

faces of a boiler generally come from the water. Mostof the constituents belong to one or more of the fol-lowing groups: iron oxides, metallic copper, carbon-ates, phosphates, calcium and magnesium sulfates,silica, and silicates. The deposits may also containvarious amounts of oil.

Pre-cleaning procedures include analysis of thedeposit and tests to determine solvent strength andcontact time and temperature. The deposit analysesshould include a deposit weight in grams per squarefoot (or milligrams per square centimeter) and a spec-trographic analysis to detect the individual elements.X-ray diffraction identifying the major crystalline con-stituents is also used.

If the deposit analysis indicates the presence of cop-per (usually from corrosion of pre-boiler equipment,such as feedwater heaters and condensers), one ofthree procedures is commonly used: 1) a coppercomplexing 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 chelant-based solvent at high temperature is used to removeiron, followed by addition of an oxidizing agent at re-

Fig. 23 Temperature difference between surface and saturationthermocouples.

Firing Rate, %Low Duty Units

T, F

200

150

100

50

0100500

With InternalDeposits

After Operation

Base CurveClean Condition

200

150

100

50

0100500

With InternalDeposits

After Operation

Base CurveClean Condition

Firing Rate, %High Duty Units

T, F



duced temperature for copper removal. The decisionto use one of these methods depends on the estimatedquantity of copper present in the deposit.

When deposits are dissolved and disintegrated, oilis removed simultaneously, provided it is present onlyin small amounts. For higher percentages of oil contami-nation, a wetting agent or surfactant may be added tothe solvent to promote deposit penetration. If the de-posit is predominantly oil or grease, boiling out withalkaline compounds must precede the acid cleaning.

InhibitorsThe following equations represent the reactions of

hydrochloric acid with constituents of boiler deposits:

Fe O + 8HCl 2FeCl + FeCl + 4H O3 4 3 2 2→ (2)

CaCO + 2HCl CaCl + H O + CO3 2 2 2→ (3)

At the same time, however, the acid can also reactwith and thin the boiler metal, as represented by theequation:

Fe + 2HCl FeCl + H2 2→ (4)

unless means are provided to slow this reaction with-out affecting the deposit removal. A number of excel-lent commercial inhibitors are available to perform thisfunction. The aggressiveness of acids toward boilerdeposits and steel increases rapidly with temperature.However, the inhibitor effectiveness decreases as thetemperature rises and, at a certain temperature, theinhibitor may decompose. Additionally, all inhibitorsare not effective with all acids.

Determination of solvent conditionsDeposit samples The preferred type of deposit

sample is a small section of tube with the adheringdeposit, though sometimes tube samples are not eas-ily obtained. Selection of the solvent system is madefrom the deposit analyses. After selection of the sol-vent system, it is necessary to determine the strengthof the solvent, the solvent temperature, and the lengthof time required for the cleaning process.

Solvent strength The solvent strength should beproportional to the amount of deposit. Commonly usedformulations are:

1. Natural circulation boilers (soaking method)(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 de-posit analysis

2 Once-through boilers (circulation method)(a) pre-operational – inhibited 2% hydroxyacetic-

1% formic acids + 0.25% ammonium bifluoride(b) operational – inhibited 4% hydroxyacetic-2%

formic acids + ammonium bifluoride based ondeposit analysis

Solvent temperature The temperature of the solventshould be as high as possible without seriously reduc-ing the effectiveness of the inhibitor. An inhibitor testshould be performed prior to any chemical cleaning

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

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



to determine the maximum permissible temperaturefor a given solvent.

When using hydrochloric acid, commercial inhibi-tors generally lose their effectiveness above 170F(77C) and corrosion rate increases rapidly. Therefore,the temperature of the solvent, as fed to the unit,should be 160 to 170F (71 to 77C). In using the circu-lation method with a hydroxyacetic-formic acid mix-ture, a temperature of 200F (93C) is necessary foradequate cleaning. Chelate-based solvents are gen-erally applied at higher temperatures (about 275F/135C). In these cases, the boiler is fired to a specifictemperature. The chelate chemicals are introducedand the boiler temperature is cycled by alternatelyfiring and cooling to predetermined limits.

Steam must be supplied from an auxiliary source toheat the acid as it is fed to the unit. When using thecirculation method, steam is also used to heat the cir-culating water to the predetermined and desired tem-perature before injecting the acid solution. Heat shouldbe added by direct contact or closed cycle heat exchang-ers. The temperature of the solvent should never beraised by firing the unit when using an acid solvent.

Cleaning time When cleaning by the circulationmethod, process completion is determined by analyz-ing samples of the return solvent for iron concentra-tion and acid strength. (See Fig. 26.) However, acid cir-culation for a minimum of six hours is recommended.

In using the soaking method, the cleaning timeshould be predetermined but is generally between sixto eight hours in duration.

Preparation for cleaningHeat transfer equipment All parts not to be cleaned

should be isolated from the rest of the unit. To excludeacid, appropriate valves should be closed and checkedfor leaks. Where arrangements permit, parts of theunit such as the superheater can be isolated by fill-ing with demineralized water. Temporary pipingshould be installed to flush dead legs after cleaning.In addition to filling the superheater with demineral-ized water, once-through type units should be pres-surized with a pump or nitrogen. The pressure shouldexceed the chemical cleaning pump head.

Bronze or brass parts should be removed or tempo-rarily replaced with steel. All valves should be steel orsteel alloy. Galvanized piping or fittings should not be

used. Gauge and meter connections should be closedor removed.

All parts not otherwise protected by blanking off orby flooding with water will be exposed to the inhib-ited solvent. Vents to a safe discharge should be pro-vided wherever vapors might accumulate, becauseacid vapors from the cleaning solution do not retainthe inhibitor.

Cleaning equipment The cleaning equipment shouldbe connected as shown in Fig. 24 if the continuouscirculation method is used, or as shown in Fig. 25 ifthe soaking method is used. Continuous circulationrequires an inlet connection to assure distribution. Italso requires a return line to the chemical cleaningpump from the unit. The soaking method does notrequire a return line. The pump discharge should beconnected to the lowermost unit inlet.

The filling or circulating pump should not be fittedwith bronze or brass parts; a standby pump is recom-mended. A filling pump should have the capacity todeliver a volume of liquid equal to that of the vesselwithin two hours at 100 psi (0.7 MPa). A circulatingpump should have sufficient capacity to meet recom-mended cleaning velocities. With modern once-through boilers, a capacity of 3600 GPM (227 l/s) at300 psi (2.1 MPa) is common. A solvent pump, closedmixing tank and suitable thermometers, pressuregauges, and flow meters are required. An adequatesupply of clean water and steam for heating the sol-vent should be provided. Provision should be made foradding the inhibited solvent to the suction side of thefilling or recirculating pump.

Cleaning solutions Estimating the content of thevessel and adding 10% to allow for losses will deter-mine the amount of solvent required. Sufficient com-mercial acid should then be obtained. An inhibitorqualified for use with the solvent also needs to be pro-cured and added to the solvent.

Cleaning proceduresThe chemical cleaning of steam generating equip-

ment consists of a series of distinct steps which mayinclude the following:

1. isolation of the system to be cleaned,2. hydrostatic testing for leaks,3. leak detection during each stage of the process,4. back flushing of the superheater and forward

flushing of the economizer,5. preheating of the system and temperature control,

Table 7Comparative Cleaning Effectiveness

Makeup of Deposit

Type of Hardness Cleaning Iron Copper Silica (Ca/Mg)

HCl Good Medium Medium GoodHAF Good Poor Medium Medium/poorEDTA Good Medium Poor Medium/poorCitric Good Medium Poor PoorBromate N/A Good N/A N/A

Fig. 26 Solvent conditions during cleaning by the circulation method.



6. solvent injection/circulation (if circulation is used),7. draining and/or displacement of the solvent,8. neutralization of residual solvent,9. passivation of cleaned surfaces,

10. flushing and inspection of cleaned surfaces, and11. layup of the unit.

Every cleaning should be considered unique, andsound engineering judgment should be used through-out the process. The most important design and proce-dural considerations include reducing system leakage,controlling temperature, maintaining operational flex-ibility and redundancy, and ensuring personnel safety.

PrecautionsCleaning must not be considered a substitute for

proper water treatment. Intervals between cleaningsshould be extended or reduced as conditions dictate.Every effort should be used to extend the time be-tween chemical cleanings. Hazards related to chemi-cal cleaning of power plant equipment are fairly wellrecognized and understood, and appropriate person-nel safety steps must be instituted.27

Chemical cleaning of superheater, reheater andsteam piping

In the past, chemical cleaning of superheaters andreheaters was not performed because it was consid-ered unnecessary and expensive. With the use ofhigher steam temperatures, cleaning procedures forsuperheaters, reheaters and steam piping have gainedimportance and acceptance.

When chemically cleaning surfaces that have ex-perienced severe high-temperature oxide exfoliation(spalling of hard oxide particles from surfaces), it isimportant to first remove a tube sample representingthe worst condition. Oxidation progresses at about thesame 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 ca-pable of producing a flow rate similar to that used inthe actual cleaning. This allows development of anappropriate solvent mixture.

To determine the circulating pump size and flowsrequired, it is usually necessary to contact the boilermanufacturer.

Figs. 27 and 28 show possible superheater/reheaterchemical cleaning piping schematics for drum boiler andonce-through boiler systems, respectively.

If, in the case of a drum boiler, the unit is to becleaned along with the superheater and reheater, itis usually necessary to orifice the downcomers to ob-tain the desired velocities through the furnace walls.

A steam blow to purge all air and to completely fillthe system must precede cleaning in all systems con-taining pendant non-drainable surfaces. Mostdrainable systems also benefit from such a steam blow.

Presently, two solvent mixtures are available toclean superheater, reheater and steam piping. One isa combination of hydroxyacetic and formic acids con-taining ammonium bifluoride; the other is an EDTA(ethylenediaminetetraacetic acid)-based solvent.

Solvent disposalGeneral considerations A boiler chemical cleaning

is not complete until the resultant process waste wa-ter stream is disposed of. Selection of handling anddisposal methods depends on whether the wastes areclassified as hazardous or non-hazardous. Boilerchemical cleaning wastes (BCCW) are different involume and frequency of generation and have differ-ent discharge regulations from other power plant wastestreams. Of all power plant discharges, BCCWs aremost likely to be classified as hazardous. Dependingupon the cleaning process, the resultant BCCW maybecome one of the driving forces in solvent selection.

Under National Pollutant Discharge EliminationSystem (NPDES) requirements, boiler cleaning wastesare considered chemical metal cleaning wastes. Theprimary parameters of concern are iron, copper, chro-mium and pH. In all cases, waste management mustbe performed in accordance with current regulatoryrequirements.

Waste management options Table 8 lists the han-dling practices for BCCW. In co-ponding, the BCCWis mixed in an ash pond with other waste streams fromthe power plant. Acid wastes are neutralized by thealkaline ash, and the metals are precipitated as in-soluble metal oxides and hydroxides, or absorbed onash particles. Co-ponding is the least expensive andthe easiest disposal option.

Incineration of organic-based cleaning wastes bydirect injection into the firebox of the utility boiler isanother common disposal practice. Potential emissionsfrom the boiler must be carefully monitored to ensureregulatory compliance.

Large quantities of BCCW are often disposed of in asecure landfill. Evaporation can reduce waste volumeand, thereby, reduce overall landfill disposal costs.

HCl cleaning wastes can be treated to NPDES stan-dards using lime or caustic precipitation. It is more

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



Table 8Boiler 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

difficult to treat the organic cleaning agents (such asEDTA) by current techniques. Treatment methods withpermanganate, ultraviolet light, and hydrogen per-oxide (wet oxidation) have been used with limitedsuccess. Several vendors have proprietary processeswhich claim to successfully treat chelated wastes.28,29

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

LayupDuring periods when boiler operation is inter-

rupted, substantial pitting and general corrosion canoccur within unprotected water-steam circuitry. Whenboilers return to operation, corrosion products migrateto high heat flux areas of the boiler or carryover tothe turbine. Out-of-service corrosion can therefore im-pede boiler startup and lead to operational problemssuch as deposition, under-deposit corrosion, corrosionfatigue, and cycle efficiency loss.

Preservation methods inhibit out-of-service corro-sion by eliminating or controlling moisture, oxygen,and chemical contaminants that cause corrosion. Table9 provides a brief summary and comparison of com-mon preservation methods.

These methods are designed to limit corrosioncaused by the normal range of boiler and atmosphericcontaminants. Gross contamination must be avoidedand, if it occurs, the contaminants must be immedi-ately neutralized and removed. Respective vendorsshould be contacted for specific recommendations forbalance-of-plant equipment (turbine, condensate,feedwater, and atmospheric pollution control systems).Vendor procedures should also be followed for boilerauxiliary equipment such as pulverizer gearboxes,sootblowers, fans, and motors.

Boiler shutdown for layupAppropriate shutdown procedures can facilitate

preservation for subsequent idle periods. Reducingload dissipates fluid-side salts that concentrate ontube surfaces in high heat flux areas. As boiler load isreduced, feedwater and boiler water pH should beincreased to the upper end of the target operatingrange, preferably 9.6 or higher. Where an oxygenscavenger/inhibitor is employed, concentration shouldincrease to 0.050 ppm hydrazine* or equivalent.When boiler water is to remain in the boiler for a sub-stantial cold layup period, the oxygen scavenger/in-hibitor concentration in the water should be increasedto 20 ppm hydrazine or equivalent after the boilerpressure has decayed to below 200 psig (1.4 MPa). Athigher pressures and associated temperatures, thescavenger may rapidly decompose. An oxygen scav-enger/inhibitor is not added to boilers that employ oxy-gen treatment. For boilers on oxygen treatment, theoxygen feed should be stopped at least an hour be-

*WARNING: HYDRAZINE IS A PROVEN GENERICCHEMICAL FOR THIS APPLICATION. HOWEVER,HYDRAZINE IS A KNOWN CARCINOGEN, AND CANBE REPLACED WITH OTHER PRODUCTS THATHAVE EQUIVALENT ABILITY TO SCAVENGE OXYGENAND INHIBIT CORROSION.

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



fore shutdown; there can be no oxygen leakage intothe cycle. Where possible, as steam pressure decaysto atmospheric pressure, nitrogen should be introducedthrough upper vents to keep the internal pressurepositive and prevent air ingress. Boiler-specific oper-ating instructions should be consulted for other im-portant shutdown procedures and precautions.

Draining for boiler maintenance and inspectionDraining boilers without further preservation is

often necessary for maintenance and inspection, andthe unit should be drained and dried as thoroughlyas possible. Draining the boiler hot (for example, at20 psig/0.14 MPa) will facilitate drying, but may leavecondensate in non-drainable superheater elements.Boiler components that need not be open for mainte-nance should, where possible, be isolated and pro-tected. For example, while the lower furnace is openfor maintenance, the superheater should, if possible,be protected with an appropriate wet or dry layupmethod. All openings should remain covered to pre-vent ingress of contaminants.

The unpreserved maintenance period should be as

brief as possible, preferably less than 3 weeks. Wherea long maintenance outage with minimal preserva-tion is necessary, the boiler and open sections of thepre-boiler system should generally be chemicallycleaned and repassivated to reform a protective oxidefilm following the outage.

Hot standby and hot layupWhen a boiler returns to operation while steam pres-

sure remains above atmospheric pressure, preservationrequirements are minimal. If the shutdown period isless than 72 hours and there is no air in-leakage, am-monia and oxygen scavenger/inhibitor concentrationsneed only be raised to the high end of the normal oper-ating range with an oxygen scavenger/inhibitor con-centration equivalent to about 0.050 ppm hydrazine.Oxygen scavengers are not used for boilers that em-ploy oxygen treatment. However, a low oxygen concen-tration must be maintained by effective deaeration, andwater must remain at a high level of purity with cat-ion conductivity less than 0.15 µS/cm.

Extended hot standby is not recommended. Hotlayup can be extended by use of auxiliary heat, but

Table 9Summary and Comparison of Boiler Lay-up Methods

Safety and Lay-up Method Effectiveness Costs Environmental Concerns Strengths Weaknesses

Drained and dry Poor Minimal Minimal Allows full access to Not effectivefor erection or internal surfacesmaintenance Quick and easy

Vaporous Variable, Chemicals Handling and disposal Minimal maintenance Remaining inhibitive corrosion generally Chemical application of chemicals requirements capacity is difficultinhibitors fair Chemical removal to monitor and disposal Chemicals must be replaced periodically Difficult to distribute through components

Nitrogen Excellent Nitrogen distribution Nitrogen suffocation Consistently effective Safety concernsblanketing system Easy to monitor Nitrogen leakage Nitrogen

Hot standby Good Heat Residual temperature Fast restart Not recommended for and pressure more than 3 days

Cold standby Poor Minimal Minimal Fast restart Not recommended for more than 30 days

Wet, water-filled Variable, Demineralized water Handling of Easily applicable to Freeze damage generally Chemical treatment chemicals non-drainable Valve seepage and good Disposal of treated Disposal of treated components associated corrosion water water Facilitates rapid damage return to service Difficult to monitor and inspect May corrode copper alloys beyond boiler

Dry, dehumidified Excellent Dehumidifier and Minimal Consistently effective Boiler must be air blower unit Safe totally drained Air recirculation No disposal problems Initial plumbing piping Easy to monitor and equipment requirements



non-corrosive and non-depositing conditions can bedifficult to assure, especially in economizers, super-heaters, and reheaters. If temperature is maintainedby injecting blowdown from an adjacent boiler, exces-sive blowdown solids can accumulate under low-flowconditions in the standby boiler. When steam is in-jected from another boiler, deposition and corrosionproblems can arise from temperature and chemistrydifferentials. Also, care must be taken to avoid cavi-tation and to control the chemistry of steam conden-sate. Water leakage across valves can cause corrosionin seepage areas, and the corrosion is aggravated byrelatively high material and water temperatures.

Cold standby for up to thirty daysFor short periods (not more than a week), boilers

may remain on cold standby status with little or nochemical additions. Moderate ammonia and oxygenscavenger/inhibitor additions can extend this period upto thirty days. Treated demineralized water for short-term cold standby should have a minimum concentra-tion of 10 ppm ammonia. The concentration of oxygenscavenger/inhibitor normally used in the boiler shouldbe increased to the equivalent of 25 ppm of hydrazine.Nitrogen blanketing (see below) is recommended.

For boilers employing oxygen treatment, no scaven-ger should be used for short cold standby periods. How-ever, oxygen ingress must be avoided and low oxygenconcentrations must be maintained (for example, by useof nitrogen blanketing of boiler and deaeration ofmakeup water). Throughout the storage period, the pHmust be 9.2 or higher, and cation conductivity through-out the boiler must be less than 0.15 µS/cm.

Boiler storage for more than seven daysAny of several layup practices are acceptable for

storage periods up to six months. Alternatives for fluid-side layup include nitrogen blanketing, wet layup withtreated demineralized water, and dry dehumidifiedlayup. For extended outages, it is important that thepre-boiler feedwater train, balance of the water-steamcycle, auxiliary equipment, and fireside of the boilerare adequately preserved. For idle periods longer thansix months, dry (dehumidified) storage is recom-mended. For boilers with non-drainable components,water removal issues must be weighed against theadvantages of dry layup.

Reheaters – all periodsReheaters are generally stored dry because they

can not easily be isolated from the turbine. Wet stor-age requires installation of blanks or special valves inthe connecting lines. Drying can be performed by ex-posing reheaters to condenser vacuum after the fireshave been removed, the unit tripped, and the turbineseals maintained. With approximately 20 in. (5 kPa)of vacuum on the condenser, vents or drains on thereheater inlet should be opened to allow air to passthrough and remove all moisture. Dehumidified drystorage is recommended where the storage period ex-ceeds 30 days. Alternatively, the evacuated reheatermay be isolated and nitrogen blanketed, or it may benitrogen blanketed in conjunction with the turbine.

Nitrogen blanketingEven where water is present, corrosion can be pre-

vented by eliminating oxygen from the environment.Oxygen can be eliminated by sealing and pressuriz-ing the entire boiler, or the space above water level,with nitrogen to prevent air in-leakage. In the absenceof acids and other oxidants, eliminating air stops cor-rosion. Nitrogen blanketing is a highly effectivemethod for preventing corrosion. It is easy to monitorand alarm, so effective preservation can be assured.However, the boiler must be well sealed to preventexcessive leakage.

It is absolutely imperative that working spacesaround nitrogen blanketed equipment be well venti-lated. Venting of nitrogen during purging or waterfilling operations can release large amounts of nitro-gen into surrounding areas. Also, before entry, areasthat have been nitrogen blanketed must be well ven-tilated and the air tested to confirm that all parts haveadequate oxygen concentrations.

Wet (water-filled) layupWet layup in combination with nitrogen blanket-

ing is often the most practical method of protection,especially for boilers that are not fully or easilydrainable. However, for longer storage periods, advan-tages of wet layup are offset by accumulative corro-sion in areas of valve seepage and by accumulativecost of replacement water, chemicals, treated waterdisposal, nitrogen cover gas, and heat in cold climates.Consequently, dry layup is generally recommended forstorage periods longer than six months.

Before a boiler is flooded with layup water, provisionmust be made to support the additional weight whendrum (if present), superheater, and steam piping arefilled. If the boiler is to be completely filled with layupwater, an expansion tank or surge tank above the high-est vent is necessary to accommodate volume changesthat are caused by normal temperature fluctuations.The expansion space at the top of the boiler (whetherin a drum or in a surge tank) should be nitrogen blan-keted to assure that there is no air ingress. Where freez-ing conditions are expected or possible, provision mustbe made for heating water-filled components.

Wet layup generally requires demineralized waterhaving a specific conductivity less than 1.0 µS/cm be-fore treatment chemicals are added. Use of deminer-alized water and all volatile treatment chemicals isessential where boilers include non-drainable or stain-less steel components. Use ammonium hydroxide toraise water pH into the range of 10.0 to 10.4. Use anoxygen scavenger/inhibitor to further retard corrosion.

Dry (dehumidified) layupDry layup requires the removal of all water and the

dehumidification of air to maintain a relative humid-ity less than 50%, and preferably less than 40%. Thisprevents corrosion by hygroscopic salts. Dry-air (de-humidified) storage is highly effective, and its contin-ued effectiveness is easy to monitor. Dry layup allowseasy and safe access for maintenance, with no poten-tial for suffocation and no exposure to toxic chemicals.



1. Klein, H.A., and Rice, J.K., “A research study on in-ternal corrosion in high pressure boilers,” Journal of En-gineering for Power, Vol. 88, No. 3, pp. 232-242, July, 1966.

2. Cohen, P., Ed., The ASME Handbook on Water Tech-nology in Thermal Power Systems, The American Soci-ety of Mechanical Engineers, New York, New York, 1989.

3. “Consensus on Operating Practices for the Control ofFeedwater and Boiler Water Quality in Modern IndustrialBoilers,” The American Society of Mechanical Engineers,New York, New York, 1994.

4. “Interim consensus guidelines on fossil plant cyclechemistry,” Report CS-4629, Electric Power Research In-stitute, Palo Alto, California, June, 1986.

5. “Guideline for Boiler Feedwater, Boiler Water, andSteam of Steam Generators with a Permissible Operat-ing Pressure > 68 bar,” VGB PowerTech e.V., Essen, Ger-many, VGB-R 450 Le, (in German), 1988.

6. Betz Handbook of Industrial Water Conditioning,Ninth Ed., Betz Laboratories, Trevose, Pennsylvania, Sep-tember, 1991.

7. Drew Principles of Industrial Water Treatment, 11thEd., Drew Industrial Division, Ashland Chemical Co.,Boonton, New Jersey, 1994.

8. Kemmer, F.N., Ed., The Nalco Water Handbook, Sec-ond Ed., McGraw-Hill, New York, New York, 1988.

9. Macbeth, R.V., et al., UKAEA Report No. AAEW-R711,Winfrith, Dorchester, United Kingdom, 1971.10. Goldstein, P., and Burton, C.L., “A research study oninternal corrosion of high-pressure boilers – final report,”Journal of Engineering for Power, Vol. 91, pp. 75-101,April, 1969.

11. Freier, R.K., “Cover layer formation on steel by oxy-gen in neutral salt free water,” VGB Speiserwassertagung1969 Sunderheft, pp. 11-17 (in German), 1969.12. Whirl, S.F., and Purcell, T.E., “Protection againstcaustic embrittlement by coordinated pH control,” ThirdAnnual Meeting of the Water Conference of the Engineers’Society of Western Pennsylvania, Pittsburgh, Pennsylva-nia, 1942.13. Stodola, J., “Review of boiler water alkalinity control,”Proceedings of the 47th Annual Meeting of The Interna-tional Water Conference, Pittsburgh, Pennsylvania, pp.235-242, October 27-29, 1986.14. Economy, G., et al., “Sodium phosphate solutions atboiler conditions: solubility, phase equilibrium and inter-actions with magnetite,” Proceedings of the InternationalWater Technology Conference, Pittsburgh, Pennsylvania,pp. 161-173, 1975.15. Tremaine, P., et al., “Interactions of sodium phosphatesalts with transitional metal oxides at 360C,” Proceedingsof the International Conference on Interaction of IronBased Materials with Water and Steam, Heidelberg, Ger-many, June 3-5, 1992.16. Martynova, O.I., “Transport and concentration pro-cesses of steam and water impurities in steam generatingsystems,” Water and Steam: Their Properties and Cur-rent Industrial Applications, J. Staub and K. Scheffler,Eds., Pergamon Press, Oxford, United Kingdom, pp. 547-562, 1980.17. Nagda, N.L. and Harper, J.P., Monitoring Water inthe 1990s: Meeting New Challenges, STPl102, AmericanSociety for Testing and Materials, Philadelphia, Pennsyl-vania, 1991.

References

It also eliminates the potential for biological activity,damage from freezing water, and corrosion by leak-ing water. However, implementation requires that theboiler be completely drained and dried, and this is amajor problem for boilers with non-drainable super-heaters or other non-drainable circuits. Also, mechani-cal circulation and dehumidification equipment andpiping installation can be costly.

In preparation for dry storage, water must bedrained completely from all boiler circuits, includingfeedwater piping, economizer, superheater, andreheater. All non-drainable boiler tubes and super-heater tubes should be blown with pressurized air.Auxiliary sources of heat are used to dry fluid-sidesurfaces. Deposits of sufficient thickness to retainmoisture must also be removed.

The preferred dry layup method is continuous re-circulation of dehumidified air. Fans force air throughthe dehumidifier, boiler fluid-side circuitry, and backto the dehumidifier. The system must include instru-mentation for measuring relative humidity. Recircu-lating dehumidification also requires external (usu-ally flexible plastic) piping to complete the path. Thesystem must be sized to handle the residual moistureand moist air in-leakage, and must be monitored to

assure that relative humidity remains less than 50%.An alternative, but inferior, dry layup method is the

use of static desiccant to absorb moisture with no forcedair circulation. This method is effective for boiler com-ponents and small (package) boilers, but not gener-ally adequate for large complex boiler circuitry.

Termination of the storage period requires removalof the recirculation, dehumidification, and monitoringmaterials and equipment. Any loose desiccant particlesor dust (which generally contain silica or sulfitechemicals) must be cleaned from the boiler.

Vaporous corrosion inhibitors (VCI)Vaporous 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 bothwater and oxygen. These inhibitors are not generallyused for completed boilers, where the size and com-plexity of boiler circuits precludes effective distribu-tion of dry powders. However, they are often used toinhibit internal corrosion of boiler components, assupplements to dry storage for small boilers, and asan alternative treatment for hydrotest water.



18. Annual Book of ASTM Standards, Section 11, Waterand Environmental Technology, Vol. 11.01 (D 1192 Speci-fication for Equipment for Sampling Water and Steam; D1066 Practice for Sampling Steam; D 3370 Practice forSampling Water; and D 4453 Handling of Ultra-pure WaterSamples), American Society for Testing and Materials,Philadelphia, Pennsylvania, 2004.19. Steam and Water Sampling, Conditioning, and Analy-sis in the Power Cycle, ASME Performance Test Code19.11, The American Society of Mechanical Engineers,New York, New York, 1997.20. Rice, J., “Quality assurance for continuous cycle chem-istry monitoring,” Proceedings of the International Con-ference on Fossil Plant Cycle Chemistry, Report TR-100195, Electric Power Research Institute, Palo Alto, Cali-fornia, December, 1991.21. Uhlig, H.H., and Revic, R.W., Corrosion and Corro-sion Control, Third Ed., John Wiley & Sons, New York,New York, 1985.22. Lamping, G.A., and Arrowood, Jr., R.M., Manual forInvestigation and Correction of Boiler Tube Failures, Re-port CS-3945, Electric Power Research Institute, Palo Alto,California, 1985.23. French, D.N., Metallurgical Failures in Fossil FiredBoilers, Second Ed., Wiley, New York, New York, 1993.

24. Port, R.D., and Herro, H.M., The Nalco Guide to BoilerFailure Analysis, McGraw-Hill Company, New York, NewYork, 1991.25. Dooley, R.B., and McNaughton, W.P., “Boiler TubeFailures: Theory and Practice,” Electric Power ResearchInstitute, Palo Alto, California, 1996. LICENSED MATE-RIAL available to EPRI members.26. Annual Book of ASTM Standards, Section 11, Waterand Environmental Technology, Vols. 11.01 and 11.02,American Society for Testing and Materials, Philadelphia,Pennsylvania, 2003.27. Wackenhuth, E.C., et al., “Manual on chemical clean-ing of fossil-fuel steam generating equipment,” Report CS-3289, Electric Power Research Institute, Palo Alto, Cali-fornia, 1984.28. Samuelson, M.L., McConnell, S.B., and Hoy, E.F., “Anon-site chemical treatment for removing iron and copperfrom chelant cleaning wastes,” Proceedings of the 49th In-ternational Water Conference, Pittsburgh, Pennsylvania,p. 380,1988.29. “Nalmet heavy metal removal program,” Nalco Chemi-cal Company, Naperville, Illinois, February, 1989.



Degassed conductivity analyzer for water quality analysis.

Boiler water treatment

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