Water and Steam chemistry-Deposits and Corrosion-

Apostolos Kavadias, Water treatment additives, hardware and services
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Water and Steam Chemistry, Deposits and
Corrosion.
Steam generation and use involve thermal and physical processes of heat transfer, fluid flow,
evaporation, and condensation. However, steam and water are not chemically inert physical media.
Pure water dissociates to form low concentrations of hydrogen and hydroxide ions, H+
and OH−
, and
both water and steam dissolve some amount of each material that they contact. They also
chemically react with materials to form oxides, hydroxides, hydrates, and hydrogen. As
temperatures and velocities of water and steam vary, materials may dissolve in some areas and
redeposit in others. Such changes are especially prevalent where water evaporates to form steam
or steam condenses back to water, but they also occur where the only change is temperature,
pressure, or velocity. In addition, chemical impurities in water and steam can form harmful deposits
and facilitate dissolution (corrosion) of boiler structural materials. Therefore, to protect vessels,
tubing, and other components used to contain and control these working fluids, water and steam
chemistry must be controlled.
Water used in boilers must be purified and treated to inhibit scale formation, corrosion, and
impurity contamination of steam. Two general approaches are used to optimize boiler water
chemistry. First, impurities in the water are minimized by purification of makeup water, condensate
polishing, deaeration and blowdown. Second, chemicals are added to control pH, electrochemical
potential, and oxygen concentration.
Chemicals may also be added to otherwise inhibit scale formation and corrosion. Proper water
chemistry control improves boiler efficiency and reduces maintenance and component replacement
costs. It also improves performance and life of heat exchangers, pumps, turbines, and piping
throughout the steam generation, use, and condensation cycle.
The primary goals of boiler water chemistry treatment and control are acceptable steam purity and
acceptably low corrosion and deposition rates. In addition to customized boiler-specific guidelines
and procedures, qualified operators are essential to achieving these goals, and vigilance is required
to detect early signs of chemistry upsets. Operators responsible for plant cycle chemistry must
understand boiler water chemistry guidelines and how they are derived and customized. They must
also understand how water impurities, treatment chemicals, and boiler components interact.
Training must therefore be an integral, ongoing part of operations and should include management,
control room operators, chemists, and laboratory staff.
General water chemistry control limits and guidelines have been developed and issued by various
groups of boiler owners and operators (e.g., ASME,1,2,3
EPRI4
and VGB5
), water treatment specialists
6,7,8
utilities and industries.
Also, manufacturers provide recommended chemistry control limits for each boiler and for other
major cycle components. However, optimum water and steam chemistry limits for specific boilers,
turbines, and other cycle components depend on equipment design and materials of construction
for the combination of equipment employed. Hence, for each boiler system, boiler-specific water
chemistry limits and treatment practices must be developed and tailored to changing conditions by
competent specialists familiar with the specific boiler and its operating environment.

Water and Steam chemistry-Deposits and Corrosion
Apostolos Kavadias, Water treatment additives, hardware and services p.2 of 41
Chemistry-boiler interactions
To understand how water impurities, treatment chemicals and boiler components interact, one
must first understand boiler circuitry, and steam generation and separation processes.
Boiler feed pumps provide feedwater pressure and flow for the boiler. From the pumps, feedwater
often passes through external heaters and then through an economizer where it is further heated
before entering the boiler. In a natural circulation drum-type unit, boiling occurs within steel tubes
through which a water-steam mixture rises to a steam drum. Devices in the drum separate steam
from water, and steam leaves through connections at the top of the drum.
This steam is replaced by feedwater which is supplied by the feedwater pumps and injected into the
drum just above the downcomers through a feedwater pipe where it mixes with recirculating boiler
water which has been separated from steam. By way of downcomers, the water then flows back
through the furnace and boiler tubes. Boiler water refers to the concentrated water circulating
within the drum and steam generation circuits.
Boiler feedwater always contains some dissolved solids, and evaporation of water leaves these
dissolved impurities behind to concentrate in the steam generation circuits. If the concentration
process is not limited, these solids can cause excessive deposition and corrosion within the boiler
and excessive impurity carryover with the steam. To avoid this, some concentrated boiler water is
discarded to drain by way of a blowdown line. Because the boiler water is concentrated, a little
blowdown eliminates a large amount of the dissolved solids. Since steam carries very little dissolved
solids from the boiler, dissolved and suspended solids entering in the feedwater concentrate in the
boiler water until the solids removed in the blowdown (boiler water concentration times the
blowdown rate lb/h or kg/s) equal the solids carried in with the feedwater (lb/h or kg/s).
A small amount of dissolved solids is carried from the drum by moisture (water) droplets with the
steam. Because moisture separation from steam depends on the difference between their
densities, moisture separation is less efficient at high pressures where there is less difference
between the densities. Therefore, to attain the same steam purity at a higher pressure, the
dissolved solids concentration in boiler water must generally be lower.
In a drum boiler, the amount of steam generated is small compared to the amount of water
circulating through the boiler. However, circulation is also largely driven by the difference in
densities between the two fluids, so as pressure increases the ratio of water flow to steam flow
decreases. At 200 psi (1379 kPa), water flow through the boiler must be on the order of 25,000 pph
(3 kg/s) to produce just 1000 pounds per hour of steam. Even at 2700 psi (18.6 MPa), 2500 to 4000
pounds of water circulates to produce 1000 pounds of steam. By contrast, most or all of the water
entering a once-through boiler is converted to steam without recirculation.
Some boiler operators have asked why boiler water concentrations change so slowly once a source
of contamination is eliminated and the continuous blowdown rate is increased.
Ø How quickly can excess chemical be purged from a boiler?
Ø How much impurity or additive is needed to upset boiler water chemistry?
Ø How quickly do chemical additions circulate through the boiler?
To answer these questions and explore some other chemistry-boiler interactions, consider for
example a typical 450 MW natural circulation boiler, generating 3,000,000 pounds of steam per
hour. It has a room temperature water capacity of 240,000 pounds and an operating water capacity
of 115,000 pounds. The furnace wall area is 33,000 square feet, about 5800 of which are in the
maximum heat flux burner zone. Impurities purge slowly from the boiler because the boiler volume
is large compared to the blowdown rate.

For example, at maximum steaming capacity with a blowdown rate 0.3% of the steam flow from the
drum, 17 hours may be required to decrease the boiler water concentration of a non-volatile
impurity by 50%.
Almost two hours are required to effect a 50% reduction in the boiler water concentration even at a
blowdown rate of 3%. Without blowdown, dissolved sodium with a fractional carryover factor of
0.1% would have a half life of 52 hours. While long periods of time are generally required to purge
impurities, mixing within the boiler is rapid. For the boiler being used as an example, the internal
recycle rate is about one boiler volume per minute, and steam is generated at a rate of one boiler
volume every 5 minutes.
The rate of steam generation is such that replacement feedwater must be essentially free of
hardness minerals and oxides that deposit in the boiler. For example, feedwater carrying only 1
ppm of hardness minerals and oxides could deposit up to 25,000 lb (11,340 kg) per year of solids in
the boiler, so the boiler might require chemical cleaning as often as 3 or 4 times per year. Also,
small chemical additions have a large effect on boiler water chemistry. For example, addition of 0.2
lb (0.09 kg) of sodium hydroxide to the boiler water increases the sodium concentration by 1 ppm,
which can significantly affect the boiler water chemistry. Similarly, a small amount of chemical
hideout can have a large effect on boiler water concentration.
Hideout or hideout return of only 0.01 gram per square foot (0.1 g/m2
) in the burner zone can
change the boiler water concentration by 1 ppm.
Control of deposition, corrosion, and steam purity
The potential for deposition and corrosion is inherent to boilers and increases with boiler operating
pressure and temperature. Evaporation of water concentrates boiler water impurities and solid
treatment chemicals at the heat transfer surfaces. During the normal nucleate boiling process in
boiler tubes, small bubbles form on tube walls and are immediately swept away by the upward flow
of water. As steam forms, dissolved solids in the boiler water concentrate along the tube wall.
Additionally, the boundary layer of water along the wall is
slightly superheated, and many dissolved minerals are less
soluble at higher temperatures (common phenomenon
referred to as inverse temperature solubility). Both of these
factors favor deposition of solids left behind by the evolution
of steam in high heat flux areas, as illustrated in Fig. 1.
These deposits in turn provide a sheltered environment
which can further increase chemical concentrations and
deposition rates. In a relatively clean boiler tube,
concentration of chemicals at the tube surface is limited by
the free exchange of fluid between the surface and boiler
water flowing through the tube.
Wick boiling as illustrated in Fig. 2 generally produces
sufficient flow within the deposits to limit the degree of
concentration. However, as heavy deposits as illustrated in
Fig. 3 accumulate, they restrict flow to the surface. Some
boiler water chemicals concentrate on tube walls during
periods of high load and then return to the boiler water when
the load is reduced. This is termed hideout and hideout
return. This can greatly complicate efforts to control boiler water chemistry.
Fig. 1 Three years of operation resulted in light
deposits because of good water treatment. The
upper right figure is the heated side, and the lower
right figure is the unheated side.

Typical boiler deposits are largely hardness precipitates and metal oxides. Hardness, easily
precipitated minerals (mainly calcium and magnesium), enters the cycle as impurities in makeup
water and in cooling water from condenser leaks. Metal oxides are largely from corrosion of pre-
boiler cycle components. Scaling occurs when these minerals and oxides precipitate and adhere to
boiler internal surfaces where they impede heat transfer. The result can be overheating of tubes,
followed by failure and equipment damage. Deposits also increase circuitry pressure drop,
especially detrimental in once-through boilers. Effective feedwater and boiler water purification
and chemical treatment minimizes deposition by minimizing feedwater hardness and by minimizing
corrosion and associated iron pickup from the condensate and feedwater systems. Also, phosphate
and other water treatment chemicals are used in drum boilers to impede the formation of
particularly adherent and low thermal conductivity deposits.
Some chemicals become corrosive as they concentrate.
Corrosion can occur even in a clean boiler, but the
likelihood of substantial corrosion is much greater
beneath thick porous deposits that facilitate the
concentration process. Concentration at the base
of deposits can be more than 1000 times higher
than that in the boiler water and the temperature
at the base of these deposits can substantially exceed the saturation temperature.
Hence, as deposits accumulate, control of boiler water chemistry to avoid the formation of
corrosive concentrates becomes increasingly important. Since chemistry upsets do occur, operation
of a boiler with excessively thick deposits should be avoided. Because local concentration of boiler
water impurities and treatment chemicals is inherent to steam generation, water chemistries must
be controlled so the concentrates are not corrosive. On-line corrosion is often caused by
concentration of sodium hydroxide, concentration of caustic-forming salts such as sodium
carbonate, or concentration of acid-forming salts such as magnesium chloride or sulfate.10
Effective
feedwater and boiler water treatment minimizes corrosion by minimizing ingress of these
impurities and by adding treatment chemicals (such as trisodium phosphate) that buffer against
acid or caustic formation. However, corrosion and excessive precipitation can also be caused by
improper use of buffering agents and other treatment chemicals. For example, underfeeding or
overfeeding of treatment chemicals, out-of-specification sodium to phosphate ratios, or out-of-
specification free-chelant concentrations can cause corrosion.
Fig. 2 Schematic of the wick boiling mechanism
Fig. 3 An example of internal deposits resulting from poor
boiler water treatment. These deposits, besides hindering
heat transfer, allowed boiler water salts to concentrate,
causing corrosion

Dissolved carbon dioxide and oxygen can also be corrosive and must be eliminated from feedwater.
Carbon dioxide from air in-leakage and from decomposition of carbonates and organic compounds
tends to acidify feedwater and steam condensate. Oxygen is especially corrosive because it
facilitates oxidation of iron, copper, and other metals to form soluble metal ions.
At higher temperatures, oxygen is less soluble in water and the rate of chemical reaction is
increased. As boiler feedwater is heated, oxygen is driven out of solution and rapidly corrodes heat
transfer surfaces. The combination of oxygen and residual chloride is especially corrosive, as is the
combination of oxygen and free chelant.
Carryover of impurities from boiler water to steam is also inherent to boiler operation. Though
separation devices remove most water droplets carried by steam, some residual droplets
containing small amounts of dissolved solids always carry through with the steam. Also, at higher
pressures, there is some vaporous carryover.
Excessive impurities can damage superheaters, steam turbines, or downstream process equipment.
Boiler feedwater
To maintain boiler integrity and performance and to provide steam of suitable turbine or process
purity, boiler feedwater must be purified and chemically conditioned. The amount and nature of
feedwater impurities that can be accommodated depend on boiler operating pressure, boiler
design, steam purity requirements, type of boiler water internal treatment, blowdown rate, and
whether the feedwater is used for steam attemperation. Feedwater chemistry parameters to be
controlled include dissolved solids, pH, dissolved oxygen, hardness, suspended solids, total organic
carbon (TOC), oil, chlorides, sulfides, alkalinity, and acid or base forming tendencies.
At a minimum, boiler feedwater must be softened water for low pressure boilers and demineralized
water for high pressure boilers. It must be free of oxygen and essentially free of hardness

constituents and suspended solids. Recommended feedwater limits are shown in Table 1. Use of
high-purity feedwater minimizes blowdown requirements and minimizes the potential for
carryover, deposition, and corrosion problems throughout the steam-water cycle.
Operation within these guidelines does not by itself ensure trouble-free operation. Some feedwater
contaminants such as calcium, magnesium, organics, and carbonates can be problematic at
concentrations below the detection limits of analytical methods commonly used for industrial
boilers. Also, operators must be sensitive to changes in feedwater chemistry and boiler operating
conditions, and must adapt accordingly.
Makeup water
Boiler feedwater is generally a mix of returned steam condensate and fresh makeup water. For
utility boilers, most of the steam is usually returned as condensate, and only 1 to 2% makeup is
necessary.
However, for some industrial cycles, there is little or no returned condensate, so as much as 100%
makeup may be necessary.
Chemistry requirements for makeup water depend on the amount and quality of returned steam
condensate. Where a large portion of the feedwater is uncontaminated condensate, makeup water
can generally be of lesser purity so long as the mixture of condensate and makeup meet boiler
feedwater requirements.
The feedwater concentration for each chemical species is the weighted average of the feedwater
and makeup water concentrations:
Feedwater concentration = (condensate x concentration flow + makeup concentration x makeup
flow) / total feedwater flow (1)
The selection of equipment for purification of makeup water must consider the water chemistry
requirements, raw water composition, and quantity of makeup required. All natural waters contain
dissolved and suspended matter. The type and amount of impurities vary with the source, such as
lake, river, well or rain, and with the location of the source. Major dissolved chemical species in
source water include sodium, calcium, and magnesium positive ions (cations) as well as
bicarbonate, carbonate, sulfate, chloride, and silicate negative ions (anions). Organics are also
abundant.
The first steps in water purification are coagulation and filtration of suspended materials. Natural
settling in still water removes relatively coarse suspended solids. Required settling time depends on
specific gravity, shape and size of particles, and currents within the settling basin. Settling and
filtration can be expedited by coagulation (use of chemicals to cause agglomeration of small
particles to form larger ones that settle more rapidly). Typical coagulation chemicals are alum and
iron sulfate. Following coagulation and settling, water is normally passed through filters. The water
is chlorinated to kill micro-organisms, then, activated charcoal filters may be used to remove the
final traces of organics and excess chlorine.
Subsequently, various processes may be used to remove dissolved scale-forming constituents
(hardness minerals) from the water. For some low pressure boilers, removal of hardness minerals
and scale-forming minerals is adequate. For other boilers, the concentration of all dissolved solids
must be reduced or nearly eliminated. For low pressure boilers, the capital and operating cost for
removal must be weighed against costs associated with residual dissolved solids and hardness.
These include increased costs for boiler water treatment, more frequent chemical cleaning of the
boiler, and possibly higher rates of boiler repair. Demineralized water nearly free of all dissolved

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

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

Feedwater pH control
Boiler feedwater pH is monitored at the condensate pump discharge and at the economizer inlet.
When the pH is below the required minimum value, ammonium hydroxide or an alternate alkalizer
is added.
Chemicals for pH control are added either downstream of the condensate polishers or at the
condensate pump discharge for plants without polishers. For high purity demineralized feedwater,
ammonium hydroxide injection pumps or alternative feedwater pH control is achieved using a
feedback signal from a specific conductivity monitor. Conductivity provides a good measure of
ammonium hydroxide concentration, and automated conductivity measurement is more reliable
than automated pH measurement. Also, the linear rather than logarithmic relationship of
conductivity to ammonia concentration gives better control. Fig. 4 shows the relationship between
ammonium concentration, pH, and conductivity of demineralized water. While an equilibrium
concentration of ammonium hydroxide remains in the boiler water, much of the ammonium
hydroxide added to feedwater volatilizes with the steam. Conversely, the solubility of ammonium
hydroxide is such that little ammonia is lost by deaeration. Hence, returned condensate often has a
substantial concentration of ammonium hydroxide before further addition.Common alternative pH
control agents include neutralizing amines, such as cyclohexylamine and morpholine. For high
pressure utility boilers with superheaters, the more complex amines are thermally unstable and the
decomposition products can be problematic.
Deaeration and chemical oxygen scavengers
Oxygen and carbon dioxide enter the cycle with un-deaerated makeup water, with cooling water
which leaks into the condenser, and as air leaking into the vacuum portion of the cycle.
For turbine cycles, aeration of the feedwater is initially limited by use of air ejectors to remove air
from the condenser. Utility industry standard practice is to limit total air in-leakage to less than one
standard cubic foot of air per minute per 100 MW of generating capacity (approximately 0.027
Nm3/100 MW), as measured at the condenser air ejectors. Final removal of oxygen and other
dissolved gases adequate for boiler feedwater applications is generally accomplished by thermal
deaeration of the water ahead of the boiler feed pumps. Thermal deaeration is accomplished by
heating water to reduce gas solubility. Gases are then carried away by a counter flow of steam. The
process is typically facilitated by the use of nozzles and trays which disperse water droplets to
increase the steam-to-water interfacial area. Thermal deaeration can reduce feedwater oxygen
concentration to less than 7 parts per billion (ppb). It also essentially eliminates dissolved carbon
dioxide, nitrogen, and argon.
Chemical agents are generally used to scavenge residual oxygen not removed by thermal
deaeration. Traditional oxygen scavengers have been sodium sulfite for low pressure boilers and
hydrazine for high pressure boilers. Sulfite must not be used where the boiler pressure is greater
than 900 psig (6.2 MPa). Other oxygen scavengers (erythorbic acid, diethylhydroxylamine,
hydroquinone and carbohydrazide) are also used. Hydrazine has been identified as a carcinogen
and this has increased the use of alternative scavengers. Scavengers are generally fed at the exit of
the condensate polishing system and/or at the boiler feed pump suction.

Attemperation water
Water spray attemperation is used to control steam temperature. The spray water is feedwater,
polished feedwater, or steam condensate. As the spray water evaporates, all chemicals and
contaminants in the water remain in the steam. This addition must not be excessive.
It must not form deposits in the attemperator piping, and it must not excessively contaminate the
steam. If a superheated steam purity limit is imposed, the steam purity after attemperation must
not exceed this limit. To meet this requirement, the weighted average of the spray water total
solids concentration and the saturated steam total solids concentration must not exceed the final
steam total solids limit. Additionally, spray water attemperation must not increase the steam total
solids concentration by more than 0.040 ppm. Independent of other considerations, the spray
water solids concentration must never exceed 2.5 ppm. Ideally, the purity of attemperation water
should equal the desired purity of the steam.
Drum boilers and internal boiler water
Boiler water that recirculates in drum and steam generation circuits has a relatively high
concentration of dissolved solids that have been left behind by water evaporation. Water chemistry
must be carefully controlled to assure that this concentrate does not precipitate solids or cause
corrosion within the boiler circuitry. Boiler water chemistry must also be controlled to prevent
excessive carryover of impurities or chemicals with the steam.
Customized chemistry limits and treatment practices must be established for each boiler. These
limits depend on steam purity requirements, feedwater chemistry, and boiler design. They also
depend on boiler owner/operator preferences regarding economic tradeoffs between feedwater
purification, blowdown rate, frequency of chemical cleaning, and boiler maintenance and repair.
Direct boiler water treatment (usually referred to as internal treatment) practices commonly used
to control boiler water chemistry include all volatile treatment, coordinated phosphate treatments,
high-alkalinity phosphate treatments, and high-alkalinity chelant and polymer treatments.
In all cases, when treatment chemicals are mixed, the identity and purity of chemicals must be
verified and water of hydration in the weight of chemicals must be taken into account. The specific
treatment used must always be developed and managed by competent water chemistry specialists.
Feedwater is the primary source of solids that concentrate in boiler water, and feedwater purity
defines the practical limit below which the boiler water solids concentration can not be reduced
with an acceptable blowdown rate. Additionally, hardness and pre-boiler corrosion products carried
by the feedwater play major roles in defining the type of boiler water treatment that must be
employed. Where substantial hardness is present in feedwater, provision must be made to ensure
that the hardness constituents remain in solution in the boiler water or to otherwise minimize the
formation of adherent deposits. This is often accomplished by use of chelant, polymer, or high-
alkalinity phosphate boiler water treatment. Where substantial hardness is not present, boiler
water treatment can be optimized to minimize impurity carryover in the steam and to minimize the
potential for boiler tube corrosion.
Because boiler water impurities and treatment chemicals carry over in the steam, steam purity
requirements play a major role in defining boiler water chemistry limits. Boiler specifications
normally include a list of boiler-specific water chemistry limits that must be imposed to attain
specified steam purity. Limits must always be placed on the maximum dissolved solids
concentration. Limits must also be placed on impurities and conditions that cause foaming at the
steam-water interface in the drum. These include limits on oil and other organic contaminants,

suspended solids, and alkalinity. The carryover factor is the ratio of an impurity or chemical species
in the steam to that in the boiler water.
Blowdown
The dissolved solids concentration of boiler water is intermittently or continuously reduced by
blowing down some of the boiler water and replacing it with feedwater. Blowdown rate is generally
expressed as a percent relative to the steam flow rate from the drum.
Blowdown is accomplished through a pressure letdown valve and flash tank. Heat loss is often
minimized by use of a regenerative heat exchanger. The ratio of the concentration of a feedwater
impurity in the boiler water to its concentration in the feedwater is the concentration factor, which
can be estimated by use of Equation 1. However, a more complex formula must be used where
there is substantial carryover.
If there is no blowdown, solids concentrate until carryover with the steam is sufficient to carry away
all of the solids that enter the boiler with the feedwater. For example, where the feedwater silica
concentration is 0.01 ppm, the water concentration factor into the boiler is 100 and 10% of the
silica in the boiler water carries over with the steam, the equilibrium silica concentration into the
steam is 0.1 ppm.
Traditional all volatile treatment
For all volatile treatment (AVT), no solid chemicals are added to the boiler or pre-boiler cycle. Boiler
water chemistry control is by boiler feedwater treatment only. No chemical additions are made
directly to the drum. Feedwater pH is controlled with ammonia or an alternate amine. Because
ammonia carries away preferentially with the steam, the boiler water pH may be slightly lower (0.2
to 0.4 pH units) than the feedwater pH. For traditional all volatile treatment, as opposed to oxygen
treatment, hydrazine or a suitable alternate is added to scavenge residual oxygen. Table 1 shows
the recommended AVT feedwater control limits. Because all volatile treatment adds no solids to the
boiler water, solids carryover is generally minimized.
All volatile treatment provides no chemical control for hardness deposition and provides no buffer
against caustic or acid-forming impurities. Hence, feedwater must contain no hardness minerals
from condenser leakage or other sources. It must be high-purity condensate or polished
condensate with mixed-bed quality demineralized makeup water. All volatile treatment can be, but
rarely is, used below 1000 psig (6.9 MPa). Normally it is used only for boilers operating at or above
2000 psig (13.8 MPa) drum pressure. It is not recommended for lower pressure boilers where other
options are feasible. While all volatile treatment is one of several options for drum boilers, it is the
only option for once-through boilers.
Oxygen treatment
Even in the absence of dissolved oxygen, steel surfaces react with water to form some soluble Fe+++
ions which may deposit in the boiler, superheater, turbine, or other downstream components.
However, in the absence of impurities, oxygen can form an especially protective Fe++++
iron oxide
that is less soluble than that formed under oxygen-free conditions. To take advantage of this, some
copper-free boiler cycles operating with ultra pure feedwater maintain a controlled concentration
of oxygen in the feedwater. Most of these are high pressure once-through utility boilers, but this
approach is also used successfully in some drum boilers.

Fig. 6 Estimated pH of sodium phosphate solutions.
Note: pH values can differ by up to 0.2 pH units, depending
on the choice of chemical equilibrium constants used, but
more often agree within 0.05 pH units.
Oxygen treatment was developed in Europe, largely
by Vereinigung der Grosskesselbetreiber (VGB),11
and there is also extensive experience in the former
Soviet Union (FSU). It can only be used where there
is no copper in the pre-boiler components beyond
the condensate polisher, and where feedwater is
consistently of the highest purity, e.g., cation
conductivity < 0.15 μS/cm at 77ο
F (25ο
C). A low
concentration of oxygen is added to the
condensate. The target oxygen concentration is
0.050 to 0.150 ppm for once-through boilers and
0.040 ppm for drum boilers. With oxygen
treatment, the feedwater pH can be reduced, e.g.,
down to 8.0 to 8.5. An advantage of oxygen
treatment is decreased chemical cleaning
frequencies for the boiler. In addition, when oxygen
treatment is used in combination with lower pH,
the condensate polisher regeneration frequency is
reduced.
Coordinated phosphate treatment
Coordinated phosphate-pH treatment, introduced
by Whirl and Purcell of the Duquesne Light
Company, 12 controls boiler water alkalinity with
mixtures of disodium and trisodium phosphate added to the drum through a chemical feed pipe.
The objective of this treatment is largely to keep the pH of boiler water and under-deposit boiler
water concentrates within an acceptable range. Fig. 5 indicates the phosphate concentration range
Fig. 5 Phosphate concentrations to control boiler water chemistry
(little or no residual hardness in the feedwater). Indicates
phosphate range at a given dissolved solids concentration.

that is generally necessary and sufficient for this purpose. Phosphate treatment must not be used
where the drum pressure exceeds 2800 psig (19.3 MPa). All volatile treatment is recommended at
the higher pressures.
In sodium phosphate solutions, an H+
+ PO4
3-
→ HPO42-
balance buffers the pH (i.e., retards H+
ion
concentration changes). Solution pH depends on the phosphate concentration and the molar
sodium-to-phosphate ratio. The relationship between pH, phosphate concentration, and molar
sodium-to-phosphate ratio is shown in Fig. 6. Where solutions contain other dissolved salts (e.g.,
sodium and potassium chloride and sulfate), sodium phosphate can still be used to control pH, and
the curves of Fig. 6 are still applicable.
However, for such solutions, the sodium-to-phosphate ratio labels on these curves are only
apparent values with reference to pure sodium phosphate solutions. Measured sodium
concentrations cannot be used in calculating sodium-to-phosphate ratios for control of boiler water
pH because measured sodium concentrations include non-phosphate sodium salts. While dissolved
sodium chloride and sulfate do not alter boiler water pH, ammonia does alter the pH. Hence, the
presence of ammonia must be taken into account where ammonia concentrations are significant
compared to phosphate concentrations.
Historically, the initial goal of coordinated pH-phosphate control was to keep the effective molar
sodium to- phosphate ratio just below 3, to prevent caustic stress corrosion cracking, acid
corrosion, and hydrogen damage.
This proved to be an effective method for control of deposition and corrosion in many boilers.
However, caustic gouging of furnace wall tubes occurred in some boilers using coordinated pH-
phosphate control, and laboratory tests indicated that solutions with molar sodium-to-phosphate
ratios greater than about 2.85 can become caustic when highly concentrated. Subsequently, many
boilers were operated under congruent control with a target effective sodium-to-phosphate ratio of
less than 2.85, generally about 2.6, and often less than 2.6. Again, this proved to be an effective
method of control for many boilers, but some of the boilers operating with low molar sodium-to-
phosphate ratios experienced acid phosphate corrosion. Instances of boiler tube corrosion
generally occurred in boilers that experienced substantial phosphate hideout and hideout- return
when the boiler load changed.
Phosphate hideout, hideout-return, and associated corrosion problems are now addressed by
equilibrium phosphate treatment.13
The concentration of phosphate in the boiler water is kept low
enough to avoid hideout and hideout return associated with load changes, thus it is always in
equilibrium with the boiler. The effective molar sodium-to-phosphate ratio is kept above 2.8. The
free hydroxide, as depicted in Fig. 6, is not to exceed the equivalent of 1 ppm sodium hydroxide.
Concern about caustic gouging at the higher ratios is largely reduced by experience with this
treatment regime and by experience with caustic boiler water treatment.
Tables 2 and 3 show recommended boiler water chemistry limits. Customized limits for a specific
boiler depend on the steam purity requirements for the boiler. Boiler and laboratory experience
indicate that, under some conditions, phosphate-magnetite interactions can degrade protective
oxide scale and corrode the underlying metal. To minimize these interactions, the pH must be
greater than that corresponding to the 2.6 sodium-to-phosphate ratio curve of Fig. 6, and
preferably greater than that corresponding to the 2.8 curve. The pH must always be above the 2.8
curve when the drum pressure is above 2600 psig (17.9 MPa). The maximum pH is that of trisodium
phosphate plus 1 ppm sodium hydroxide. Additionally, the boiler water pH is not to be less than 9
nor greater than 10. As discussed below, it may be necessary to reduce the maximum boiler water

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

Where phosphate treatment is used, pH is an
especially critical parameter, so the accuracy of
pH measuring devices and temperature
corrections must be assured. The boiler water
pH must also be corrected to discount the pH
effect of residual ammonia in the boiler water.
Fig. 7 shows the estimated effect of ammonia
on boiler water pH. The figure indicates the
expected pH for solutions with different
concentrations of sodium phosphate and 0.2
ppm ammonia. Where these species dominate
the solution chemistry, such figures may be
used to estimate sodium-to-phosphate molar
ratios.
With high purity feedwater, the recommended
boiler water pH can be attained with
appropriate additions of trisodium phosphate.
If the recommended boiler water pH cannot be
maintained within the above limits using
trisodium phosphate or a mixture of trisodium and disodium phosphate, this is indicative of alkaline
or acid-forming impurities in the feedwater or excessive hideout, and the root cause must be
addressed. An exception is low level equilibrium phosphate treatment, where the small amount of
trisodium phosphate added to the boiler water may at times be insufficient to achieve the
recommended pH. A small amount of sodium hydroxide may be added to attain the recommended
pH, but the excess sodium hydroxide must not exceed 1.0 ppm.13
Even 1.0 ppm sodium hydroxide
may be excessive for some units, for example oil-fired boilers with especially high heat fluxes in
some areas of the furnace.
When mixing boiler water treatment chemicals, operators should verify the identity and purity of
the chemicals and take into account water of hydration in the weight of the chemicals. Neither
phosphoric acid nor monosodium phosphate should be used for routine boiler water treatment. If
monosodium phosphate is used to counter an isolated incident of alkali contamination of the boiler
water, it must be used with caution, and at reduced load.
High-alkalinity phosphate treatment (low-pressure boilers only)
Minimal carryover and deposition are achieved with demineralized makeup water and minimal
dissolved solids, but this is not necessarily cost-effective for all low pressure industrial boilers.
Where softened water with 0.02 to 0.5 ppm residual hardness (as CaCO3) is used as makeup water
for low pressure industrial boilers, high alkalinity or conventional phosphate treatment may be used
to control scale formation.
This high alkalinity treatment must only be used for boilers operating below 1000 psig (6.9 MPa).
The pH and phosphate concentrations are attained by addition of a trisodium phosphate and (if
necessary) sodium hydroxide solution through a chemical feed line into the drum. With high-
alkalinity phosphate treatment, the boiler water pH is maintained in the range of 10.8 to 11.4. This
high pH precipitates hardness constituents that are less adherent than those formed at lower pH.
Fig. 7 . Estimated pH of sodium phosphate solutions
containing 0.2 ppm ammonium hydroxide.
Note: pH values can differ by up to 0.2 pH units, depending on
the choice of chemical equilibrium constants used, but more
often agree within 0.05 pH units.

Where high alkalinity boiler
water is excessively
concentrated by evaporation,
the concentrate can become
sufficiently caustic to produce
caustic gouging or stress
corrosion cracking of carbon
steel. Hence, high-alkalinity
boiler water treatment must
not be used where waterside
deposits are excessively thick,
where there is steam
blanketing or critical heat flux,
or where there is seepage (e.g.,
through rolled seals or cracks).
Fig. 8 shows phosphate concentration limits for high-alkalinity phosphate treatment. With some
feedwaters (e.g., high-magnesium low-silica), lower phosphate concentrations may be advisable.
The required pH is attained by adjusting the sodium hydroxide concentration in the chemical feed
solution. The total (m-alkalinity in calcium carbonate equivalents) must not exceed 20% of the
actual boiler water solids concentration.
Dispersants, polymers, and chelants (low pressure boilers only)
Where substantial hardness (e.g., 0.1 ppm as CaCO3) is present in feedwater, chelant treatment is
often used to ensure that the hardness constituents remain in solution in the boiler water, or
polymer treatment is used to keep precipitates in suspension.
Blowdown of the dissolved contaminants and colloids is more effective than that of noncolloidal
hardness precipitates and metal oxides.
While phosphate treatment precipitates residual calcium and magnesium in a less detrimental form
than occurs in the absence of phosphate, chelants react with calcium and magnesium to form
soluble compounds that remain in solution. Chelants commonly employed include ethylene-
diaminetetraacetic acid (EDTA) and nitrilotriacetic acid (NTA). Because of concern about thermal
stability, the use of chelants and polymers should be limited to boilers operating at less than 1000
psi (6.9 MPa).
To be most effective, chelant must mix with the feedwater and form thermally stable calcium and
magnesium complexes before there is substantial residence time at high temperature, where free
chelant is not thermally stable. Because the combination of free chelant and dissolved oxygen can
be corrosive, chelant must be added only after completion of oxygen removal and scavenging. Also,
there must be no copper-bearing components in the feedwater train beyond the chelant feed
point.
Control limits depend on the feedwater chemistry, specific treatment chemicals used, and other
factors. However, the boiler feedwater pH is generally between 9.0 and 9.6 and hardness as calcium
carbonate is less than 0.5 ppm. The boiler water pH is generally maintained in the range of 10.0 to
11.4. The boiler water pH is attained by a combination of alkalinity derived from the chelant feed
(e.g., as Na4EDTA), evolution of CO2 from softened feedwater, and addition of sodium hydroxide.
Polymeric dispersants are generally used to impede formation of scale by residual solids.
Fig. 8 Phosphate concentration limits for high-alkalinity phosphate treatment.

Once-through universal pressure boilers
In a subcritical once-through boiler, there is no steam drum. As water passes through boiler tubing,
it evaporates entirely into steam. Because steam does not cool the tube as effectively as water, the
tube temperature increases beyond this dry-out location. Subcritical once-through boilers are
designed so this transition occurs in a lower heat flux region of the boiler where the temperature
increase is not sufficient to cause a problem. However, because the water evaporates completely, it
must be of exceptional purity to avoid corrosion and rapid deposition, and carryover of dissolved
solids.
Similarly stringent water purity requirements must be imposed for supercritical boilers. While there
is no distinction between water and steam in a supercritical boiler, the physical and chemical
properties of the fluid change as it is heated, and there is a temperature about which dissolved
solids precipitate much as they do in the dry-out zone of a subcritical once-through boiler. This is
termed the pseudo-transition zone.
Satisfactory operation of a once-through
boiler and associated turbine requires
that the total feedwater solids be less
than 0.030 ppm total dissolved solids
with cation conductivity less than 0.15
μS/cm. Table 1 lists recommended limits
for other feedwater parameters.
Feedwater purification must include
condensate polishing, and water
treatment chemicals must all be volatile.
Ammonia is typically added to control
pH. For traditional all volatile treatment,
hydrazine or a suitable volatile
substitute is used for oxygen scavenging.
Iron pickup from pre-boiler components
can be minimized by maintaining a
feedwater pH of 9.3 to 9.6. Prior to plant
startup, feedwater must be circulated
through the condensate polishing
system to remove dissolved and
suspended solids. Temperatures should
not exceed 550ο
F (288ο
C) at the
convection pass outlet until the iron
levels are less than 0.1 ppm at the
economizer inlet. Utility once-through boilers with copper-free cycle metallurgy commonly use
oxygen treatment. Table 1 includes recommended limits for other feedwater chemical parameters
for oxygen treatment. Startup is with increased pH and no oxygen feed. Oxygen addition to
feedwater is initiated and pH is reduced only after feedwater cation conductivity is less than 0.15
μS/cm.
Fig. 9 Impurity carryover coefficients of salts and metal oxides
in boiler water (adapted from Reference 16)

System transients and upsets inevitably
cause excursions above recommend limits.
Increased rates of deposition and corrosion
are likely to be in proportion to the
deviations. Small brief deviations may
individually be of little consequence, but the
extent, duration, and frequency of such
deviations should be minimized. Otherwise,
over a period of years the accumulative
effects will be significant. Potential effects
include increased deposition, pitting,
pressure drop, and fatigue cracking.
Particular care is required to minimize the
extent and duration of chemistry deviations
for cycling units where operational transients
are frequent.
Steam purity
Purity or chemistry requirements for steam
can be as simple as a specified maximum
moisture content, or they can include
maximum concentrations for a variety of
chemical species. Often, for low-pressure
building or process heater steam, only a
maximum moisture content is specified. This
may be as high as 0.5% or as low as 0.1%.
Conversely, some turbine manufacturers
specify steam condensate maximum cation
conductivity, pH, and maximum concentrations
for total dissolved solids, sodium and
potassium, silica, iron, and copper. Turbine
steam must generally have total dissolved
solids less than 0.050 ppm, and in some cases
less than 0.030 ppm. Individual species limits
may be still lower. If steam is to be
superheated, a maximum steam dissolved
solids limit must be imposed to avoid excessive
deposition and corrosion of the superheater.
This limit is generally 0.100 ppm or less.
Even where steam purity requirements are not
imposed by the application, steam dissolved
solids concentrations less than 1.0 ppm are
recommended at pressures up to 600 psig (4.1
MPa), dissolved solids concentrations less than
Fig. 10 Solids in steam versus dissolved solids in boiler water.
Fig. 11 Boiler water silica concentration limit, where maximum
steam silica is 0.010 ppm and boiler water pH is greater than 8.8.

0.5 ppm are recommended at 600 to 1000 psig
(4.1 to 6.9 MPa), and dissolved solids
concentrations less than 0.1 ppm are
recommended above 1000 psig (6.9 MPa).
Up to 2000 psig (13.8 MPa), most non-volatile
chemicals and impurities in the steam are
carried by small water droplets entrained in the
separated steam. Because these droplets
contain dissolved solids in the same
concentration as the boiler water, the amount
of impurities in steam contributed by this
mechanical carryover is the sum of the boiler
water impurities concentration multiplied by
the steam moisture content. Mechanical
carryover is limited by moisture separation
devices placed in the steam path.
High water levels in the drum and boiler water
chemistries that cause foaming can cause
excessive moisture carryover and therefore
excessive steam impurity concentrations.
Foaming is the formation of foam or excessive
spray above the water line in the drum.
Common causes of foaming are excessive solids
or alkalinity, and the presence of organic matter
such as oil. To keep dissolved solids below the
concentration that causes foaming requires
continuous or periodic blowdown of the boiler.
High boiler water alkalinity increases the
potential for foaming, particularly in the
presence of suspended matter.
Where a chemical species is sufficiently volatile,
it also carries over as a vapor in the steam. Total
carryover is the sum of the mechanical and
vaporous carryover.
Vaporous carryover depends on solubility in
steam and is different for each chemical
species. For most dissolved solids found in
boiler water, it is negligible by comparison to
mechanical carryover at pressures less than
2000 psig (13.8 MPa). An exception is silica for
which vaporous carryover can be substantial at
lower pressures. Fig. 9 shows typical vaporous
carryover fractions (distribution ratios) for
common boiler water constituents under typical
conditions over a wide range of boiler
pressures. Fig. 10 shows expected total dissolved solids carryover for typical highpressure boilers.

Vaporous carryover depends on pressure and on boiler water chemistry. It is not affected by boiler
design. Hence, if vaporous carryover for a species is excessive, the carryover can only be reduced by
altering the boiler water chemistry. Only mechanical carryover is affected by boiler design. Non-
interactive gases such as nitrogen, argon, and oxygen carry over almost entirely with the steam,
having no relationship to moisture carryover.
Excessive steam impurity concentrations can also be caused by feedwater and boiler water
chemistries that favor volatile species formation. Carryover of volatile silica can be problematic at
pressures above 1000 psig (6.9 MPa). Fig. 11 shows boiler water silica concentration limits
recommended to obtain steam silica concentrations less than 0.010 ppm at pressures up to 2900
psig (20.0 MPa) where the pH may be as low as 8.8. Vaporous silica carryover at a pH of 10.0 is 88%
of that at a pH of 8.8. The vaporous silica carryover at a pH of 11.0 is 74% of that at 8.8. The only
effective method for preventing excessive silica or other vaporous carryover is reduction of the
boiler water concentrations.
Another common source of excessive impurities in steam is inadequate attemperation spray water
purity. All impurities in the spray water enter directly into the steam.
Water sampling and analysis
A key element in control of water and steam chemistry is effective sampling to obtain
representative samples, prevent contamination of the samples, and prevent loss of the species to
be measured.17
References 18 and 19 provide detailed procedures. In general, sample lines should
be as short as possible and made of stainless steel, except where conditions dictate otherwise.
Samples should be obtained from a continuously flowing sample stream. The time between
sampling and analysis should be as short as possible.
Samples should be cooled quickly to 100ο
F
(38ο
C) to avoid loss of the species of interest.
Sample nozzles and lines should provide for
isokinetic sample velocity and maintain constant
high water velocities [minimum of 6 ft/s (1.8
m/s)] to avoid loss of materials. Sample points
should be at least 10 diameters downstream of
the last bend or flow disturbance. Guidelines
and techniques for chemical analysis of grab
samples are listed in Table 4. The detailed
methods are readily available from the
American Society for Testing and Materials
(ASTM) in Philadelphia, Pennsylvania, U.S. and
the American Society of Mechanical Engineers
(ASME) in New York, New York, U.S.
Wherever practical, on-line monitoring should be considered as an alternative to grab samples. This
gives real-time data, enables trends to be followed, and provides historical data. However, on-line
monitors require calibration, maintenance, and checks with grab samples or on-line synthesized
standard samples to ensure reliability. Table 5 lists important on-line monitoring measurements
and references to specific methods. In addition to the measurements listed, instrumentation is
commercially available to monitor chloride, dissolved oxygen, dissolved hydrogen, silica, phosphate,
ammonia and hydrazine.

Adequate water chemistry control depends on the ability of boiler operators to consistently
measure the specified parameters. Hence, formal quality assurance programs should be used to
quantify and track the precision and bias of measurements. Detailed procedures should be in place
to cover laboratory structure, training, standardization, calibration, sample collection/
storage/analysis, reporting, maintenance records, and corrective action procedures. Further
discussion is provided in Reference 20.
Common fluid-side corrosion problems
Water and steam react with most metals to form oxides or hydroxides. Formation of a protective
oxide layer such as magnetite (Fe3O4) on the metal surface causes reaction rates to slow with time.
Boiler cycle water treatment programs are designed to maintain such protective oxide films on
internal surfaces and thus prevent corrosion in boilers and other cycle components.
With adequate control of water and steam chemistry, internal corrosion of boiler circuitry can be
minimized. Yet, chemistry upsets (transient losses of control) do occur. Vigilant monitoring of
system chemistry permits quick detection of upsets and quick remedial action to prevent boiler
damage. Where these measures fail and corrosion occurs, good monitoring and documentation of
system chemistry can facilitate identification of the root cause, and identification of the cause can
be an essential step toward avoiding further
corrosion. Where corrosion occurs and the origin is unknown, the documented water chemistry,
location of the corrosion, appearance of the corrosion, and chemistry of localized deposits and
corrosion products often suggest the cause. Common causes are flow accelerated corrosion, oxygen
Fig. 13 Boiler convection pass showing typical
locations of various types of water-side corrosion.
Fig. 12 Typical locations of various types of water-side
corrosion in a boiler furnace water circuit

pitting, chelant corrosion, caustic corrosion, acid corrosion, organic corrosion, acid phosphate
corrosion, hydrogen damage, and corrosion assisted cracking. Figs. 12 and 13 show typical locations
of common fluid-side corrosion problems. Further discussion of corrosion and failure mechanisms is
provided in References 21, 22, 23, and 24. For EPRI members, Boiler Tube Failures: Theory and
Practice25 provides an especially thorough description of utility boiler corrosion problems, causes,
and remedial measures.
One distinguishing feature of corrosion is its appearance. Metal loss may be uniform so the surface
appears smooth. Conversely, the surface may be gouged, scalloped, or pitted. Other forms of
corrosion are microscopic in breadth, and subsurface, so they are not initially discernible.
Subsurface forms of corrosion include intergranular corrosion, corrosion fatigue, stress corrosion
cracking, and hydrogen damage. Such corrosion can occur alone or in combination with surface
wastage. In the absence of component failure, detection of subsurface corrosion often requires
ultrasonic, dye penetrant, or magnetic particle inspection. These forms of corrosion are best
diagnosed with destructive cross-section metallography. Another distinguishing feature is the
chemical composition of associated surface deposits and corrosion products. Deposits may contain
residual corrosives such as caustic or acid. Magnesium hydroxide in deposits can suggest the
presence of an acid-forming precipitation process. Sodium ferrate (Na2FeO4) indicates caustic
conditions. Sodium iron phosphate indicates acid phosphate wastage. Organic deposits suggest
corrosion by organics, and excessive amounts of ferric oxide or hydroxide with pitting suggest
oxygen attack. Flow accelerated corrosion is the localized dissolution of feedwater piping in areas of
flow impingement. It occurs where metal dissolution dominates over protective oxide scale
formation. For example, localized conditions are sufficiently oxidizing to form soluble Fe+++
ions but
not sufficiently oxidizing to form Fe++++
ions needed for protective oxide formation. Conditions
known to accelerate thinning include: flow impingement on pipe walls, low pH, excessive oxygen
scavenger concentrations, temperatures in the range of 250 to 400ο
F/121 to 204ο
C (although

thinning can occur at any feedwater temperature), chemicals (such as chelants) that increase iron
solubility, and thermal degradation of organic chemicals. Thinned areas often have a scalloped or
pitted appearance. Failures, such as that shown in Fig. 14, can occur unexpectedly and close to
work areas and walkways. To assure continued integrity of boiler feedwater piping, it must be
periodically inspected for internal corrosion and wall thinning. Any thinned areas must be identified
and replaced before they become a safety hazard. The affected piping should be replaced with low-
alloy chromium- bearing steel piping, and the water chemistry control should be appropriately
altered.
Oxygen pitting and corrosion during boiler
operation largely occur in pre-boiler feedwater
heaters and economizers where oxygen from poorly deaerated feedwater is consumed by corrosion
before it reaches the boiler. A typical area of oxygen pitting is shown in Fig. 15. Oxygen pitting
within boilers occurs when poorly deaerated water is used for startup or for accelerated cooling of
a boiler. It also occurs in feedwater piping, drums, and downcomers in some low pressure boilers
which have no feedwater heaters or economizer. Because increasing scavenger concentrations to
eliminate residual traces of oxygen can aggravate flow accelerated corrosion, care must be taken to
distinguish between oxygen pitting and flow accelerated corrosion which generally occurs only
where all traces of oxygen have been eliminated.
Chelant corrosion occurs
where appropriate feedwater
and boiler water chemistries
for chelant treatment are not
maintained. Potentially
corrosive conditions include
excessive concentration of
free chelant and low pH. (See
prior discussion of boiler
water treatment with
dispersants, polymers, and
chelants.) Especially
susceptible surfaces include
flow impingement areas of
feedwater piping, riser tubes,
and cyclone steam/water separators. Affected areas are often dark colored and have the
appearance of uniform thinning or of flow accelerated corrosion.
Fig. 17 Schematic of hydrogen attack, showing steps that occur and the final result.
Hydrogen attack can occur in both carbon and low alloy steels in acidic or hydrogen
environments.

Corrosion fatigue is cracking well below the yield strength of a material by the combined action of
corrosion and alternating stresses. Cyclic stress may be of mechanical or thermal origin. In boilers,
corrosion fatigue is most common in water-wetted surfaces where there is a mechanical constraint
on the tubing. For example, corrosion fatigue occurs in furnace wall tubes adjacent to windbox,
buckstay, and other welded attachments. Failures are thick lipped.
On examination of the internal tube surface, multiple initiation sites are evident. Cracking is
transgranular. Environmental conditions facilitate fatigue cracking where it would not otherwise
occur in a benign environment.
Water chemistry factors that facilitate cracking include dissolved oxygen and low pH transients
associated 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 with phosphate to form maricite (NaFePO4). Fig. 16 shows ribbed tubing that has suffered this
type of wastage. The affected surface has a gouged appearance with maricite and magnetite
deposits. Acid phosphate corrosion occurs where the boiler water effective sodium to- phosphate
ratio is less than 2.8, although ratios as low as
2.6 may be tolerated at lower pressures.
Though not always apparent, common signs of
acid phosphate corrosion include difficulty
maintaining target phosphate concentrations, phosphate hideout and pH increase with increasing
boiler load or pressure, phosphate hideout return and decreasing pH with decreasing load or
pressure, and periods of high iron concentration in boiler water. The potential for acid phosphate
corrosion increases with increasing internal deposit loading, decreasing effective sodium to-
phosphate molar ratio below 2.8, increasing phosphate concentration, inclusion of acid phosphates
(disodium and especially monosodium phosphate) in phosphate feed solution, and increasing boiler
pressure. To avoid acid phosphate corrosion, operators should monitor boiler water conditions
closely, assure accuracy of pH and phosphate measurements, assure purity and reliability of
chemical feed solutions, assure that target boiler water chemistry parameters are appropriate and
are attained in practice, and watch for aforementioned signs of acid phosphate corrosion.
Under-deposit acid corrosion and hydrogen damage occur where boiler water acidifies as it
concentrates beneath deposits on steam generating surfaces. Hydrogen from acid corrosion
Fig. 20 Schematic of stress corrosion cracking

diffuses into the steel where it reacts with carbon to form methane as depicted in Fig. 17. The
resultant decarburization and methane formation weakens the steel and creates microfissures.
Thick lipped failures like that shown in Fig. 18 occur when the degraded steel no longer has
sufficient strength to hold the internal tube pressure. Signs of hydrogen damage include under
deposit corrosion, thick lipped failure, and steel decarburization and microfissures. The corrosion
product from acid corrosion is mostly magnetite. Affected tubing, which may extend far beyond the
failure, must be replaced. The boiler must be chemically cleaned to remove internal tube deposits,
and boiler water chemistry must be altered or better controlled to prevent acid-formation as the
water concentrates. Operators should reduce acidforming impurities by improving makeup water,
reducing condenser leakage, or adding condensate polishing.
For drum boilers, operators should use phosphate treatment with an effective sodium-to-
phosphate molar ratio of 2.8 or greater.
Caustic corrosion, gouging and grooving occur where boiler water leaves a caustic residue as it
evaporates. In vertical furnace wall tubes, this occurs beneath deposits that facilitate a high degree
of concentration and the corroded surface has a gouged appearance as shown in Fig. 19. In inclined
tubes where the heat flux is directed through the upper half of the tube, caustic concentrates by
evaporation of boiler water in the steam space on the upper tube surface. Resulting corrosion is in
the form of a wide smooth groove with the groove generally free of deposits and centered on the
crown of the tube. Deposits associated with caustic gouging often include Na2FeO4. To prevent
reoccurrence of caustic gouging, operators should prevent accumulation of excessive deposits and
control water chemistry so boiler water does not form caustic as it concentrates. The latter can
generally be achieved by assuring appropriate feedwater chemistry with coordinated phosphate
boiler water treatment, taking care to control the effective sodium-to-phosphate molar ratio as
appropriate for the specific boiler and the specific chemical and operating conditions. In some
instances, where caustic grooving along the top of a sloped tube is associated with steam/water
separation, such separation can be avoided by use of ribbed tubes which cause swirling motion that
keeps water on the tube wall.
Caustic cracking can occur where caustic concentrates in contact with steel that is highly stressed,
to or beyond the steel’s yield strength. Caustic cracking is rare in boilers with all welded
connections. This generally occurs in boilers using a high alkalinity caustic boiler water treatment,
and it is normally associated with unwelded rolled joints and welds that are not stress relieved. On
metallographic examination, caustic cracking is intergranular and has the branched appearance
characteristic of stress corrosion cracking as illustrated in Fig. 20. It can generally be avoided by use
of coordinated phosphate treatment. Where a high alkalinity caustic phosphate boiler water
treatment is used for low pressure boilers, nitrate is often added to inhibit caustic cracking.
Overheat failures like that shown in Fig. 21 occur where deposits impede internal heat transfer to
the extent that a tube no longer retains adequate strength and bulges or ruptures. Internal tube
deposits generally cause moderate overheating for extended periods of time, causing long-term
overheat failures. Short-term overheat failures generally occur only when there is gross interruption
of internal flow to cool the tube, or grossly excessive heat input.

Out-of-service corrosion is predominantly oxygen pitting. Pitting attributed to out-of-service
corrosion occurs during outages but also as aerated water is heated when boilers return to service.
Especially common locations
include the waterline in steam
drums, areas where water stands
along the bottom of horizontal pipe
and tube runs, and lower bends of
pendant superheaters and
reheaters. Pinhole failures are more
common in thinner walled reheater
and economizer tubing. Such
corrosion can be minimized by
following appropriate layup
procedures for boiler outages and
by improving oxygen control during
boiler startups.
Pre-operational cleaning
In general, all new boiler systems receive an alkaline boilout, i.e. hot circulation of an alkaline
mixture with intermittent blowdown and final draining of the unit. Many systems also receive a pre-
operational chemical cleaning. The superheater and reheater should receive a conventional steam
blow (a period of high velocity steam flow which carries debris from the system). Chemical cleaning
of superheater and reheat surfaces is effective in reducing the number of steam blows to obtain
clean surfaces, but is not required to obtain a clean superheater and reheater.
Alkaline boilout
All new boilers should be flushed and given an alkaline boilout to remove debris, oil, grease and
paint. This can be accomplished with a combination of trisodium phosphate (Na3PO4) and disodium
phosphate (Na2HPO4), with a small amount of surfactant added as a wetting agent. The use of
caustic NaOH and/or soda ash (Na2CO3) is not recommended. If either is used, special precautions
are required to protect boiler components.
Chemical cleaning
After boilout and flushing are completed, corrosion products may remain in the feedwater system
and boiler in the form of iron oxide and mill scale. Chemical cleaning should be delayed until full
load operation has carried the loose scale and oxides from the feedwater system to the boiler.
Some exceptions are units that incorporate a full flow condensate polishing system and boilers
whose pre-boiler system has been chemically cleaned. In general, these units can be chemically
cleaned immediately following pre-operational boilout.
Different solvents and cleaning processes are used for pre-operational chemical cleaning, usually
determined by boiler type, metallic makeup of boiler components, and environmental concerns or
restrictions. The four most frequently used are:
1) inhibited 5% hydrochloric acid with 0.25% ammonium bifluoride,
2) 2% hydroxyacetic/1% formic acids with 0.25% ammonium bifluoride and a corrosion inhibitor,
3) 3% inhibited ammonium salts of ethylene-diaminetetraacetic acid (EDTA), and

4) 3% inhibited ammoniated citric acid.
Steam line blowing
The steam line blow procedure depends on unit design. Temporary piping to the atmosphere is
required with all procedures. This piping must be anchored to resist high nozzle reaction force.
All normal startup precautions should be observed for steam line blowing. The unit should be filled
with treated demineralized water. Sufficient feedwater pump capacity and condensate storage
must be available to replace the water lost during the blowing period. Numerous short blows are
most effective. The color of the steam discharged to the atmosphere provides an indication as to
the quantity of debris being removed from the piping. Coupons (targets) of polished steel attached
to the end of the exhaust piping are typically used as final indicators.
Periodic chemical cleaning. Cleaning frequency
Internal surfaces of boiler water-side components (including supply tubes, headers and drums)
accumulate deposits even though standard water treatment practices are followed. These deposits
are generally classified as hardness-type scales or soft, porous-type deposits.
To determine the need for cleaning, tube samples containing internal deposits should be removed
from high heat input zones of the furnace and/or areas where deposition problems have occurred.
The deposit weight is first determined by visually selecting a heavily deposited section. After
sectioning the tube (hot and cold sides), the water-formed deposit is removed by scraping from a
measured area. The weight of the dry material is reported as weight per unit area:
either grams of deposit per square foot of tube surface or mg/cm2. Procedures for mechanical and
chemical methods of deposit removal are provided in ASTM D3483.26 General guidelines for
determining when a boiler should be chemically cleaned are shown in Table 6. The deposit weights
shown are based on the mechanical scraping method. This removes the porous deposit of external
origin and most of the dense inner oxide scale. Values are slightly lower than those obtained from
the chemical dissolution method.
Because of the corrosive nature of the fuel and its combustion products, furnace tubes in Kraft
recovery and refuse-fired boilers are particularly susceptible to gas-side corrosion which can be
aggravated by relatively modest elevated tube metal temperatures. Through-wall failures due to
external metal corrosion can occur in these tubes at water-side deposit weights much less than 40
g/ft2
(43 mg/cm2
). In addition, for Kraft recovery boilers there are significant safety concerns for
water leakage in the lower furnace. For these units, a more conservative cleaning criterion is
recommended for all operating pressures.
Chordal thermocouples
The chordal thermocouple can be an effective diagnostic tool for evaluating deposits on operating
boilers. Properly located thermocouples can indicate a tube metal temperature increase caused by
excess internal deposits, and can alert the operator to conditions that may cause tube failures.
Thermocouples are often located in furnace wall tubes adjacent to the combustion zone where the
heat input is highest and the external tube temperatures are also high. (See Fig. 22.) Deposition
inside tubes can be detected by instrumenting key furnace tubes with chordal thermocouples.
These thermocouples compare the surface temperature of the tube exposed to the combustion
process with the temperature of saturated water. As deposits grow, they insulate the tube from the
cooling water and cause tube metal temperature increases. Beginning with a clean, deposit-free

boiler, the instrumented tubes are monitored to establish the temperature differential at two or
three boiler ratings; this establishes a base curve. At maximum load, with clean tubes, the surface
thermocouple typically indicates metal temperatures 25 to 40ο
F (14 to 22o
C) above saturation in
low duty units and 80 to 100 ο
F (44 to 56 o
C) in high duty units as shown in Fig. 23. The temperature
variation for a typical clean instrumented tube is dependent upon the tube’s location in the
furnace, tube thickness, inside fluid pressure, and the depth of the surface thermocouple. Internal
scale buildup is detected by an increase in temperature differential above the base curve. Chemical
cleaning should normally be considered if the temperature differential at maximum boiler load
reaches 100 ο
F (56 o
C).
Initially, readings should be taken weekly, preferably using the same equipment and procedure as
used for establishing the base curve. Under upset conditions, when deposits form rapidly, the
checking frequency should be increased.
Chemical cleaning procedures and methods
In general, four steps are required in a complete chemical cleaning process:
1. The internal heating surfaces are washed with a solvent containing an inhibitor to dissolve or
disintegrate the deposits.
Fig. 22 Typical locations of chordal thermocouples

2. Clean water is used to flush out loose deposits, solvent adhering to the surface, and soluble iron
salts. Corrosive or explosive gases that may have formed in the unit are also displaced.
3. The unit is treated to neutralize and passivate the heating surfaces. This treatment produces a
passive surface, i.e., it forms a very thin protective film on freshly cleaned ferrous surfaces.
4. The unit is flushed with clean water to remove any remaining loose deposits.
The two generally accepted chemical cleaning methods are: 1) continuous circulation of the solvent
(Fig. 24), and 2) filling the unit with solvent, allowing it to soak, then flushing the unit (Fig. 25).
Circulation cleaning method
In the circulation (dynamic) cleaning
method (Fig. 24), after filling the unit with
demineralized water, the water is circulated
and heated to the required cleaning
temperature. At this time, the selected solvent is injected into the circulating water and
recirculated until the cleaning is completed. Samples of the return solvent are periodically tested.
Cleaning is considered complete when the acid strength and the iron content of the returned
solvent reach equilibrium (Fig. 26), indicating that no further reaction with the deposits is taking
place. In the circulation method, additional solvent can be injected if the dissipation of the solvent
concentration drops below the recommended minimum concentration.
The circulation method is particularly suitable for cleaning once-through boilers, superheaters, and
economizers with positive liquid flow paths to assure circulation of the solvent through all parts of
the unit. Complete cleaning cannot be assured by this method unless the solvent reaches and
passes through every circuit of the unit.
Fig. 24 Chemical cleaning by the circulation method –
simplified arrangement of connections for once-through
boilers.

Soaking method
The soaking (static) cleaning method (Fig. 25)
involves preheating the unit to a specified
temperature, filling the unit with the hot solvent,
then allowing the unit to soak for a period of time,
depending on deposit conditions. To assure
complete deposit removal, the acid strength of the
solvent must be somewhat greater than that
required by the actual conditions; unlike the
circulation method, control testing during the
course of the cleaning is not conclusive, and
samples of solvent drawn from convenient
locations may not truly represent conditions in all
parts of the unit. The soaking method is preferable
for cleaning units where definite liquid distribution
to all circuits (by the circulation method) is not
possible without the use of many chemical inlet
connections. The soaking method is also preferred
when deposits are extremely heavy, or if circulation
through all circuits at an appreciable rate can not
be assured without an impractically-sized
circulating pump. These conditions may exist in
large natural circulation units that have complex
furnace wall cooling systems.
Advantages of this method are simplicity of piping connections and assurance that all parts are
reached by a solvent of adequate acid strength.
Solvents
Many acids and alkaline compounds have been evaluated for removing boiler deposits.
Hydrochloric acid (HCl) is the most practical cleaning solvent when using the soaking method on
natural circulation boilers.
Chelates and other acids have also been used. An organic acid mixture such as hydroxyacetic-formic
(HAF) is the safest chemical solvent when applying the circulation cleaning method to once-through
boilers. These acids decompose into gases in the event of incomplete flushing. For certain deposits,
the solvent may require additional reagents, such as ammonium bifluoride, to promote deposit
penetration. Alloy steel pressure parts, particularly those high in chromium, should generally not be
cleaned with certain acid solvents. A general guideline for solvent selection can be found in Table 7.
Prior to chemically cleaning, it is strongly recommended that a representative tube section be
removed and subjected to a laboratory cleaning test to determine and verify the proper solvent
chemical, and concentrations of that solvent.
Deposits
Scale deposits formed on the internal heating surfaces of a boiler generally come from the water.
Most of the constituents belong to one or more of the following groups: iron oxides, metallic
Fig. 25 Chemical cleaning by the soaking method –
simplified arrangement of connections for drum-type
boilers.

copper, carbonates, phosphates, calcium and magnesium sulfates, silica, and silicates. The deposits
may also contain various amounts of oil.
Pre-cleaning procedures include analysis of the deposit and tests to determine solvent strength and
contact time and temperature. The deposit analyses should include a deposit weight in grams per
square foot (or milligrams per square centimeter) and a spectrographic analysis to detect the
individual elements.
X-ray diffraction identifying the major crystalline constituents is also used.
If the deposit analysis indicates the presence of copper (usually from corrosion of pre-boiler
equipment, such as feedwater heaters and condensers), one of three procedures is commonly
used:
1) a copper complexing agent is added directly to the acid solvent,
2) a separate cleaning step, featuring a copper solvent, is used followed by an acid solvent, and
3) a chelant-based solvent at high temperature is used to remove iron, followed by addition of an
oxidizing agent at reduced temperature for copper removal.
The decision to use one of these methods depends on the estimated quantity of copper present in
the deposit. When deposits are dissolved and disintegrated, oil is removed simultaneously,
provided it is present only in small amounts. For higher percentages of oil contamination, a wetting
agent or surfactant may be added to the solvent to promote deposit penetration. If the deposit is
predominantly oil or grease, boiling out with alkaline compounds must precede the acid cleaning.
Inhibitors
The following equations represent the
reactions of hydrochloric acid with
constituents of boiler deposits:
Fe3O4 + 8HCl → 2FeCl3 + FeCl2 + 4H2O (2)
CaCO3 + 2HCl → CaCl2 + H2O + CO2 (3)
At the same time, however, the acid can
also react with and thin the boiler metal, as
represented by the equation:
Fe + 2HCl → FeCl2 + H2 (4)
unless means are provided to slow this
reaction without affecting the deposit
removal. A number of excellent commercial
inhibitors are available to perform this function. The aggressiveness of acids toward boiler deposits
and steel increases rapidly with temperature. However, the inhibitor effectiveness decreases as the
temperature rises and, at a certain temperature, the inhibitor may decompose. Additionally, all
inhibitors are not effective with all acids.
Determination of solvent conditions
Deposit samples The preferred type of deposit sample is a small section of tube with the adhering
deposit, though sometimes tube samples are not easily obtained. Selection of the solvent system is
made from the deposit analyses. After selection of the solvent system, it is necessary to determine
the strength of the solvent, the solvent temperature, and the length of time required for the
cleaning process.
Solvent strength The solvent strength should be proportional to the amount of deposit. Commonly
used formulations are:

1. Natural 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 deposit
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 on deposit
analysis
Solvent temperature The temperature of the solvent should be as high as possible without
seriously reducing the effectiveness of the inhibitor. An inhibitor test should be performed prior to
any chemical cleaning to determine the maximum permissible temperature for a given solvent.
When using hydrochloric acid, commercial inhibitors generally lose their effectiveness above 170o
F
(77o
C) and corrosion rate increases rapidly. Therefore, the temperature of the solvent, as fed to the
unit, should be 160 to 170o
F (71 to 77o
C). In using the circulation method with a hydroxyacetic-
formic acid mixture, a temperature of 200o
F (93o
C) is necessary for adequate cleaning. Chelate-
based solvents are generally applied at higher temperatures (about 275o
F/ 135o
C). In these cases,
the boiler is fired to a specific
temperature. The chelate chemicals
are introduced and the boiler
temperature is cycled by alternately
firing and cooling to predetermined
limits.
Steam must be supplied from an
auxiliary source to heat the acid as it is
fed to the unit. When using the
circulation method, steam is also used
to heat the circulating water to the
predetermined and desired temperature before injecting the acid solution. Heat should be added
by direct contact or closed cycle heat exchangers.
The temperature of the solvent should never be raised by firing the unit when using an acid solvent.
Cleaning time When cleaning by the circulation method, process completion is determined by
analyzing samples of the return solvent for iron concentration and acid strength. (See Fig. 26.)
However, acid circulation for a minimum of six hours is recommended. In using the soaking method,
the cleaning time should be predetermined but is generally between six to eight hours in duration.
Preparation for cleaning
Heat transfer equipment All parts not to be cleaned should be isolated from the rest of the unit. To
exclude acid, appropriate valves should be closed and checked for leaks. Where arrangements
permit, parts of the unit such as the superheater can be isolated by filling with demineralized water.
Temporary piping should be installed to flush dead legs after cleaning. In addition to filling the
superheater with demineralized water, once-through type units should be pressurized with a pump
or nitrogen. The pressure should exceed the chemical cleaning pump head.
Bronze or brass parts should be removed or temporarily replaced with steel. All valves should be
steel or steel alloy. Galvanized piping or fittings should not be used. Gauge and meter connections
should be closed or removed.

All parts not otherwise protected by blanking off or by flooding with water will be exposed to the
inhibited solvent. Vents to a safe discharge should be provided wherever vapors might accumulate,
because acid vapors from the cleaning solution do not retain the inhibitor.
Cleaning equipment The cleaning
equipment should be connected as
shown in Fig. 24 if the continuous
circulation method is used, or as
shown in Fig. 25 if the soaking method
is used. Continuous circulation
requires an inlet connection to assure
distribution. It also requires a return
line to the chemical cleaning pump
from the unit. The soaking method
does not require a return line. The
pump discharge should be connected
to the lowermost unit inlet. The filling
or circulating pump should not be
fitted with bronze or brass parts; a
standby pump is recommended. A
filling pump should have the capacity
to deliver a volume of liquid equal to
that of the vessel
within two hours at 100 psi (0.7 MPa).
A circulating pump should have sufficient capacity to meet recommended cleaning velocities. With
modern oncethrough boilers, a capacity of 3600 GPM (227 l/s) at 300 psi (2.1 MPa) is common. A
solvent pump, closed mixing tank and suitable thermometers, pressure gauges, and flow meters are
required. An adequate supply of clean water and steam for heating the solvent should be provided.
Provision should be made for adding the inhibited solvent to the suction side of the filling or
recirculating pump.
Cleaning solutions Estimating the content of the vessel and adding 10% to allow for losses will
determine the amount of solvent required. Sufficient commercial acid should then be obtained. An
inhibitor qualified for use with the solvent also needs to be procured and added to the solvent.
Cleaning procedures
The chemical cleaning of steam generating equipment consists of a series of distinct steps which
may include the following:
1. 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,
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, and

11. layup of the unit.
Every cleaning should be considered unique, and sound engineering judgment should be used
throughout the process. The most important design and procedural considerations include reducing
system leakage, controlling temperature, maintaining operational flexibility and redundancy, and
ensuring personnel safety.
Precautions
Cleaning must not be considered a substitute for proper water treatment. Intervals between
cleanings should be extended or reduced as conditions dictate. Every effort should be used to
extend the time between chemical cleanings. Hazards related to chemical cleaning of power plant
equipment are fairly well recognized and understood, and appropriate personnel safety steps must
be instituted.27
Chemical cleaning of superheater, reheater and steam piping
In the past, chemical cleaning of superheaters and reheaters was not performed because it was
considered unnecessary and expensive. With the use of higher steam temperatures, cleaning
procedures for superheaters, reheaters and steam piping have gained importance and acceptance.
When chemically cleaning surfaces that have experienced severe high-temperature oxide
exfoliation (spalling of hard oxide particles from surfaces), it is important to first remove a tube
sample representing the worst condition. Oxidation progresses at about the same rate on the
outside of the tubes as on the inside; exfoliation follows a similar pattern. The tube sample should
be tested in a facility capable of
producing a flow rate similar to that
used in the actual cleaning. This allows
development of an appropriate
solvent mixture.
To determine the circulating pump size
and flows required, it is usually
necessary to contact the boiler
manufacturer.
Figs. 27 and 28 show possible
superheater/reheater chemical
cleaning piping schematics for drum
boiler and once-through boiler
systems, respectively. If, in the case of
a drum boiler, the unit is to be cleaned
along with the superheater and
reheater, it is usually necessary to
orifice the downcomers to obtain the
desired velocities through the furnace
walls. A steam blow to purge all air
and to completely fill the system must
precede cleaning in all systems
containing pendant non-drainable
surfaces. Most drainable systems also
benefit from such a steam blow.

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