Corrosion found in the Boiler and feed systems
Corrosion found in the Boiler and feed systems
Corrosion and tube failure caused by water chemistry
Metals obtained from their oxide ores will tend to revert to
that state. However , if on exposure to oxygen the oxide layer is
stable , no further oxidation will occur. If it is porous or
unstable then no protection is afforded.
Iron+O2 --- magnetite(stable and protective) + O2----ferrous
oxide (porous)
Two principle types of corrosion
Direct chemical-higher temperature metal comes into contact with
air or other gasses (oxidation, Sulphurisation )
Electrochemical-e.g. Galvanic action , hydrogen evolution , oxygen
absorption
Hydrogen Evolution (low pH attack)
Valency = No of electrons required to fill outer shell
Pure water contains equal amounts of hydrogen and hydroxyl ions
. Impurities change the balance . Acidic water has an excess of
hydrogen ions which leads to hydrogen evolution
For hydrogen absorption to occur no oxygen needs to be present,
a pH of less than 6.5 and so an excess of free hydrogen ions is
required.The Protective film of hydrogen gas on the cathodic
surface breaks down as the hydrogen combines and bubbles off as
diatomic hydrogen gas.
Oxygen Absorption(high O2 corrosion)
pH between 6- 10, Oxygen present. Leads to pitting. Very
troublesome and can be due to ineffective feed treatment prevalent
in idle boilers. Once started this type of corrosion cannot be
stopped until the rust scab is removed , either by mechanical means
or by acid cleaning. One special type is called deposit attack, the
area under a deposit being deprived of oxygen become anodic. More
common in horizontal than vertical tubing and often associated with
condensers.
Boiler corrosion
General Wastage Common in boilers having an open feed
system.
.
.
Pitting -Most serious form of corrosion on the waterside
-Often found in boiler shell at w.l.
-Usually due to poor shape
-In HP blrs found also in screen and generating tubes and in
suphtr tubes after priming.
Corrosion fatigue cracking
Cases found in water tube blrs where due to alternating cyclic
stresses set up in tube material leading to a series of fine cracks
in wall. Corrosive environment aggravates. Trans crystalline
more in depth: Occurs in any location where cyclic stressing of
sufficient magnitude are present
Rapid start up and shut down can greatly increase
susceptibility.
Common in wall and supht tubes, end of the membrane on waterwall
tubes, economisers, deaerators . Also common on areas of rigid
constraint such as connections to inlet and outlet headers
Other possible locations and causes are in grooves along
partially full boiler tubes (cracks normally lie at right angle to
groove ), at points of intermittent stm blanketing within
generating tubes, at oxygen pits in waterline or feed water lines,
in welds at slag pockets or points of incomplete fusion , in
sootblower lines where vibration stresses are developed , and in
blowdown lines.
Caustic cracking (embrittlement) or stress corrosion
cracking
Pure iron grains bound by cementite ( iron carbide).
Occurs when a specific corrodent and sufficient tensile stress
exists
Due to improved water treatment caustic stress- Corrosion
cracking ( or caustic embrittlement ) has all but been
eliminated.
It can however be found in water tubes , suphtr and reheat tubes
and in stressed components of the water drum.The required stress
may be applied ( e.g. thermal, bending etc. ) or residual ( e.g.
welding) Boiler steel is sensitive to Na OH , stainless steel is
sensitive to NaOH and chloridesA large scale attack on the material
is not normal and indeed uncommon. The combination of NaOH , some
soluble silica and a tensile stress is all that is required to form
the characteristic intergranular cracks in carbon steel.
Concentrations of the corrodent may build up in a similar way to
those caustic corrosion i.e.
DNB
Deposition
Evaporation at water line
And also by small leakage
Caustic corrosion at temperatures less than 149oC are rare
NaOH concentration may be as low as 5% but increased
susceptibility occurs in the range 20- 40 %
Failure is of the thick walled type regardless of ductility.
Whitish highly alkaline deposits or sparkling magnetite may
indicate a corrosion sight.
To eliminate this problem either the stresses can be removed or
the corrodent. The stresses may be hoop stress( temp', pressure)
which cannot be avoided bending or residual weld stresses which
must be removed in the design/ manufacturing stage.
Avoidance of the concentrations of the corrodents is generally
the most successful. Avoid DNB , avoid undue deposits prevent
leakage of corrodents, prevent carryover.
Proper water treatment is essential.
Caustic corrosion
Takes place at high pressure due to excessive NaOH
In high temperature, high evaporation rates leading to local
concentrations nearly coming out of solution and form a thin film
near heating surface.
Magnetite layer broken down
Soluble compound formed which deposits on metal as a porous
oxide
Local concentrations may cause a significant overall reduction
in alkalinity.
If evaporation rate reduced alkalinity restored.
More in depth:Generally confined to
1. Water cooled in regions of high heat flux
2. Slanted or horizontal tubes
3. Beneath heavy deposits
4. Adjacent to devices that disrupt flow ( e.g. backing
rings)
Caustic ( or ductile ) gouging refers to the corrosive
interaction of concentrated NaOH with a metal to produce distinct
hemispherical or elliptical depressions.
Depression are often filled with corrosion products that
sometimes contain sparkling crystals of magnetite.
Iron oxides being amphoteric are susceptible to corrosion by
both high and low pH enviroments.
High pH substances such as NaOH dissolve the magnetite then
attack the iron.
The two factors required to cause caustic corrosion are;
the availability of NaOH or of alkaline producing salts. ( e.g.
intentional by water treatment or unintentional by ion exchange
resin regeneration.)
Method of concentration, i.e. one of the following;
i. Departure form nucleate boiling (DNB)
ii. Deposition
iii. Evapouration
i)Departure form nucleate boiling (DNB)Under normal conditions
steam bubbles are formed in discrete parts. Boiler water solids
develop near the surface . However on departure of the bubble
rinsing water flows in and redissolves the soluble solids
However at increased rates the rate of bubble formation may
exceed the flow of rinsing water , and at higher still rate, a
stable film may occur with corrosion concentrations at the edge of
this blanket.The magnetite layer is then attacked leading to metal
loss.The area under the film may be relatively intact.
ii), DepositionA similar situation can occur beneath layers of
heavy deposition where bubbles formation occur but the corrosive
residue is protected from the bulk water
iii), Evaporation at waterlineWhere a waterline exists
corrosives may concentrate at this point by evaporation and
corrosion occurs.
prevention's Rifling is sometimes fitted to prevent DNB by
inducing water swirl.
Reduce free NaOH by correct water treatment
Prevent inadvertent release of NaOH into system (say from an ion
exchange column regenerator )
Prevent leakage of alkaline salts via condenser
Prevent DNB
Prevent excessive waterside deposits
Prevent creation of waterlines in tubes- slanted or horizontal
tubes are particularly susceptible to this at light loads were low
water flows allow stm water stratification.
Hydrogen attack
If the magnetite layer is broken down by corrosive action, high
temperature hydrogen atoms diffuse into the metal, combine with the
carbon and form methane. Large CH-3 molecules causes internal
stress and cracking along crystal boundaries and sharp sided pits
or cracks in tubes appear.
more in depth: Generally confined to internal surfaces of water
carrying tubes that are actively corroding. Usually occurs in
regions of high heat flux, beneath heavy deposits, in slanted and
horizontal tubes and in heat regions at or adjacent to backing
rings at welds or near devices that disrupt flow .
Uncommon in boilers with a W.P.of less than 70 bar
A typical sequence would be ; NaOH removes the magnetite
free hydrogen is formed ( hydrogen in its atomic rather than
diatomic state) by either the reaction of water with the iron
reforming the magnetite or by NaOH reacting with the iron
This free hydrogen can diffuse into the steel where it combines
at the grain boundaries to form molecular hydrogen or reacts with
the iron carbide to form methane
As neither molecular hydrogen or methane can diffuse through the
steel the gasses build up , increasing pressure and leading to
failure at the grain boundaries
These micro cracks accumulate reducing tensile stress and
leading to a thick walled failure. Sections may be blown out.
This form of damage may also occur in regions of low pH
For boilers operating above 70 bar , where high pH corrosion has
occurred the possibility of hydrogen damage should be
considered
High temperature corrosion.
Loss of circulation , high temperature in steam atmosphere, or
externally on suphtr tubes
Chelant corrosion
Concentrated chelants ( i,e. amines and other protecting
chemicals) can attack magnetite , stm drum internals most
susceptible.A surface under attack is free of deposits and
corrosion products , it may be very smooth and coated with a glassy
black like substanceHorse shoe shaped contours with comet tails in
the direction of the flow may be present.
Alternately deep discrete isolated pits may occur depending on
the flow and turbulence
The main concentrating mechanism is evaporation and hence DNB
should be avoided
Careful watch on reserves and O2 prescience should be
maintained
Low pH attack
Pure water contains equal amounts of hydrogen and hydroxyl ions
. Impurities change the balance . Acidic water has an excess of
hydrogen ions which leads to hydrogen evolution.See previous notes
on Hydrogen Evolution
For hydrogen absorption to occur no oxygen needs to be present,
a pH of less than 6.5 and so an excess of free hydrogen ions is
required.The Protective film of hydrogen gas on the cathodic
surface breaks down as the hydrogen combines and bubbles off as
diatomic hydrogen gas. May occur due to heavy salt water
contamination or by acids leaching into the system from a
demineralisation regeneration.
Localised attack may occur however where evaporation causes the
concentration of acid forming salts . The mechanism are the same as
for caustic attack. The corrosion is of a similar appearance to
caustic gouging
Prevention is the same as for caustic attack . Proper
maintenance of boiler water chemicals is essential
Vigorous acid attack may occur following chemical cleaning .
Distinguished from other forms of pitting by its being found on all
exposed areasVery careful monitoring whilst chemical cleaning with
the temperature being maintained below the inhibitor breakdown
point. Constant testing of dissolved iron and non ferrous content
in the cleaning solution should be carried out.
After acid cleaning a chelating agent such as phosphoric acid as
sometimes used . This helps to prevent surface rusting , The boiler
is then flushed with warm water until a neutral solution is
obtained.
Oxygen corrosion
Uncommon in operating boilers but may be found in idle
boilers.Entire boiler susceptible , but most common in the
superheater tubes (reheater tubes especially where water
accumulates in bends and sags )
In an operating boiler firstly the economiser and feed heater
are effected.
In the event of severe contamination of oxygen areas such as the
stm drum water line and the stm separation equipment
In all cases considerable damage can occur even if the period of
oxygen contamination is short
Bare steel coming into contact with oxygenated water will tend
to form magnetite with a sound chemical water treatment
program.However , in areas where water may accumulate then any
trace oxygen is dissolved into the water and corrosion by oxygen
absorption occurs( see previous explanation )
Oxygen Absorption
in addition to notes above pH between 6- 10, Oxygen
present.Leads to pitting. Very troublesome and can be due to
ineffective feed treatment prevalent in idle boilers. Once started
this type of corrosion cannot be stopped until the rust scab is
removed , either by mechanical means or by acid cleaning.
One special type is called pitting were metal below deposits
being deprived of oxygen become anodic . More common in horizontal
than vertical tubing and often associated with condensers.
The ensuing pitting not only causes trouble due to the material
loss but also acts as a stress raiser
The three critical factors are
i. the prescience of water or moisture
ii. prescience of dissolved oxygen
iii. unprotected metal surface
The corrosiveness of the water increases with temperature and
dissolved solids and decreases with increased pHAggressiveness
generally increases with increased O2
The three causes of unprotected metal surfaces are
i. following acid cleaning
ii. surface covered by a marginally or non protective iron oxide
such as Hematite (Fe2O3)
iii. The metal surface is covered with a protective iron oxide
such as magnetite (Fe3O4 , black) But holidays or cracks exist in
the coating, this may be due to mechanical or thermal
stressing.
During normal operation the environment favours rapid repair of
these cracks. However, with high O2 prescience then corrosion may
commence before the crack is adequately repaired.
FEED SYSTEM CORROSION.
Graphitization
Cast iron , ferrous materials corrode leaving a soft matrix
structur of carbon flakes
Dezincification
Brass with a high zinc content in contact with sea water ,
corrodes and the copper is redeposited. Inhibitors such as arsenic
, antimony or phosphorus can be used , but are ineffective at
higher temperatures.Tin has some improving effects
Exfoliation (denickelfication)
Normally occurs in feed heaters with a cupro-nickel tubing (
temp 205oC or higher)Very low sea water flow condensers also
susceptible.Nickel oxidised forming layers of copper and nickel
oxide
Ammonium corrosion
Ammonium formed by the decompositin of hydrazineDissolve cupric
oxide formed on copper or copper alloy tubesDoes not attack copper,
hence oxygen required to provide corrosion,Hence only possibel at
the lower temperature regions where the hydrazine is less effective
or inactive,The copper travels to the boiler and leads to
piting.Deposits and scales found in boilers
Definition: material originating elsewhere and conveyed to
deposition site; Oxides formed at the site are not deposits.
Water formed and steam formed deposits
May occur anywhere
Wall and screen tubes most heavily fouled , superhtr has
deposits formed elsewhere and carried with the steam or carryover.
Economisers ( non-steaming) contain deposits moved from there
original site.
Tube orientation can influence location and amount of
deposition.
Deposits usually heaviest on the hot side of the steam
generating tubes. Because of steam channelling, deposition is often
heavier on the top portion of horizontal or slanting tubes
Deposition occurs immediately downstream of horizontal backing
rings.
Water and steam drums can contain deposits, as these are readily
accessed then inspection of the deposition can indicate types of
corrosion. e.g. Sparkling black magnetite can precipitate in stm
drums when iron is released by decomposition of organic complexing
agents.
Superhtr deposits ( normally associated with high water levels
and foaming ) tend to concentrate near the inlet header or in
nearby pendant U-tubes
Contaminated attemperating spray water leads to deposits
immediately down stream with the possibility of chip scale carried
to the turbines.
At high heat transfer rates a stable thin film boiling can
occur, the surface is not washed ( as it is during bubble formation
) and deposits may form
Thermal stressing can lead to oxide spalling ( the exfoliation
of oxide layers in areas such as the suphtr). These chips can pass
on to the turbine with severe results. Steam soluble forms can be
deposited on the turbine blades , If chlorides and sulphates are
present , Hydration can cause severe corrosion due to
hydrolysis.
As deposits form on the inside of waterwall the temperature
increases. This leads to steam blanketing which in turn leads to
reduced heat transfer rate , long term overheating and tube
failure.
Effects on tube temperature of scale deposit
DEPOSITS
Iron oxides
Magnetite (Fe3O4)A smooth black tenacious , dense magnetite
layer normally grows on boiler water side surfaces.taken to
indicate good corrosion protection as it forms in low oxygen levels
and is susceptible to acidic attack
Heamatite (Fe2O3)is favoured at low temperatures and high oxygen
levels can be red and is a binding agent and tends to hold over
materials in deposition. This is an indication of active corrosion
occuring within the boiler/feed system
Other metals
Copper and Copper oxide is deposited by direct exchange with
iron or by reduction of copper oxide by hydrogen evolved during
corrosion . Reddish stains of copper are common at or near areas of
caustic corrosion. Copper Oxide appears as a black depositi. It is
considered very serious corrosion risk because of the initiation of
galvanic corrosion mechanisms.
Galvanic corrosion associated with copper deposition is very
rare in a well passivated boiler. Zinc and nickel are very often
found near copper deposition , nickel being a particularly
tenacious binder
Rapid loss of boiler metals can occur. Copper can appear in
various forms as a deposit in the boiler. As a copper coloured
metallic deposit, usually in a corrosion pit, as a bright
red/orange tubercules on the boiler metal surface or as a brown
tear drop shaped formation.
Copper is generally an indicator of corrosion (or possible wear)
occuring in the feed pump whether in the condensate lines or in the
parts of a feed pump. A possoble cause of this is the excessive
treatement of hydrazine which decompose to ammonia carrying over
with the steam to attack suc areas as the air ejectors on
condensers.
Copper oxide formed in boiler conditions is black and non-
metallic.
SALTS
The least soluble salts deposit first
Calcium carbonate-effervesces when exposed to HCl acid
Calcium sulphate-Slightly less friable then CaCO3
Magnesium Phosphate-Tenacious binder, discoloured by
contaminants
Silicates-Insoluble except in hydroflouric acid E.G.
Analcite
Water soluble deposits can only be retained if local
concentration mechanism is severe. Prescence of NaOH , NaPO3 Na2SO3
should be considered proof of vapouration to dryness.
Calcium and magnessium salts exhibit inverse solubility. As the
water temperature rises their solubility reduces, at a temperature
of 70'C and above they come out of solution and begin to deposit.
Feed water must be condition to remove the hardness salts before
the water enters the boiler. The purity of the water is related to
the steam conditions required of the boiler.
Hydrolyzable salts such as MgCl can concentrate in porous
deposits and hydrolyze to hydrochloric acid
Scaling mechanism examples
Calcium CarbonateCacium Carbonate is formed by the thermal
decomposition of Calcium BiCarbonate and apperas as a pale cream to
yellow scale
Ca(HCO3)2 + Heat = CaCO3 + H2O + CO2
Magnessium SilicateTor form requires sufficient amounts of
magnessium and silicate ions coupled with a deficiency in OH-
alkalinity
Mg2+ + OH- = MgOH+
H2SiO3 = H+ + HSiO3-
MgOH- + HSiO3- = MgSiO3 + H2SO4
Thus this rough tan scale can be prevented by the maintenace of
alkalinity levels
Calcium Phosphate (hydroxyapatite)Ca10(PO4)6(OH)2
Found in biolers using the phosphate cycle treatment method this
is a tan/cream deposit. This is generally associated with
overdosing a boiler but can occur where insufficient disperseing
agent reduces the effects of blow down.
In anouther form Ca3(PO4)2Ca(OH)2 it is associated with correct
treatment control
Scales forming salts found in the boiler
Calcium Bi-Carbonate 180ppm Slightly soluble
>65oC breaks down to form CaCO3 +CO2, remaining Calcium
carbonate insoluble in water
Forms a soft white scale
Magnesium BiCarbonate 150 ppm Soluble in water
at more than 90oC breaks down to form MgCO3 and CO2 and then
Mg(OH)2 and CO2
Forms a soft scale
Calcium Sulphate 1200 ppm
Worst scale forming salt
> 140oC (sat. press 2.5bar) or >96000ppm will precipitate
out
Forms a thin hard grey scale
Magnesium Sulphate 1900ppm
Precipitates at high temperatures and about 8 bar
Forms sludge
Magnesium Chloride 3200ppm
Breaks down in boiler conditions to form MgOH and HCl
forms a soft white scale Rapidly lowers pH in the event of sea
water contamination of the boiler initiating rapid corrosion MgCl2
+ 2H2O---> Mg(OH)2 + 2HCl HCl + Fe --->FeCl + H 2FeCl +
Mg(OH)2 ---> MgCl2 + 2FeOH This series is then repeated.
Effective feed treatment ensuring alkaline conditions controls this
problem
Sodium Chloride 32230 to 25600 ppm
Soluble 40bar) silica can distill from the bioler as Silicic
acid and can sublime and pass over into the steam system as a gas.
Here it glazes surfaces with a smooth layer, which due to thermal
expansion crack and roughen the surface. Troublesome on HP blading.
Can be removed only by washing with Hydroflouric acid.
Magnessium Silicate 3MgO.2SiO2.2H2O (Serpentine) is formed in
water with proper treatment control
SCALE FORMATION
The roughness of the heated surface has a direct relationship to
the deposit of scale. Each peak acts as a 'seed' for the scale to
bind to.
Nucleate Boiling
Scale built up as a series of rings forming multi layers of
different combinations. Much increased by corrosion products or
prescience of oil, even in very small quantities.Oil also increases
scale insulatory properties.
Departure form nucleate boiling (DNB) Under normal conditions
steam bubbles are formed in discrete parts. Boiler water solids
develop near the surface . However on departure of the bubble
rinsing water flows in and redissolves the soluble solids However
at increased rates the rate of bubble formation may exceed the flow
of rinsing water , and at higher still rate, a stable film may
occur with corrosion concentrations at the edge of this
blanket.
Dissolved solids in fresh water
Hard water -Calcium and magnesium salts
- Alkaline
-Scale forming
.
.
Soft water -Mainly sodium salts
- Acidic
- Causes corrosion rather than scale
Boiler water tests
Corrosion and tube failure caused by water chemistry
Recommended ranges( Co-ordinated phosphate treatment for w/t
boiler )
pH - 9.6 to 10.3
PO4 - 4 to 20 ppm
N2H4 - 0.01 to 0.03 ppm
TDS - < 150 ppm
Cond pH - 8.6 to 9.0
Cl - 20 ppm
O2 - 10 ppb
Si - 10 ppb
Chlorides
Measure 100ml of sample water into a casserole
Add 10 drops phenol pthalein (RE 106)
Neutralize with sulphuric acid
Add 10 drops of Potassium Chromate
Titrate Silver Nitrate untill sample just turns brick red
ppm as CaCO3= (ml x 10) ppm
TDS
Measure 100ml of sample water into a casserole
Add 10 drops of phenolpthalein
Neutralise with TDS reagent (acetic acid)
Temperature compensate then read off scale in ppm.
Phosphates Fill one 10 ml tube with distilled water
Fill one 10 ml tube with boiler water tests.
Add 0.5 ml sulphuric acid (RE 131) to each Add 0.5 ml Ammonium
Molybdnate (RE130) to each Add 0.5 ml Aminonapthol Sulfonic acid
(RE 132) to each Stir well between each addition
Wait 3 minutes for calorimetric compaison
Alternately Vanado-molybdnate test
Place 5 ml boiler water in 10 ml tube
Place 5 ml distilled water in other 10 ml tube
Top both to 10 ml with Vanado-molybdnate reagent
Place in colour comparator and compare after 5 mins
Hydrazine Add 9ml distilled water to one tube
Add 9 ml boiler test water to anouther
Add 1 ml hydrazine reagent to each
Use colour comparator
Alkalinity Phenolpthalein 100 ml filtered water
Add 1 ml phenolpthalein
If pH >8.4 Solution turns pink
Add H2SO4 untill pink disapears
Ml 0.02N H2SO4 x 10 = ALk in CaCO3 ppm
Measures hydroxides and carbonates in sample, bi-carbonates do
not show up so sample should not be allowed to be exposed to the
air for too long
Alkalinity Methyl orange Bi carbonates do not show up in the
phenolpthalein sample as they have a pH < 8.4. Bi carbonates can
not occur in boiler but if suspected in raw feed then the following
test.
Take phenolpthalein sample, add 1 ml methyl orange
If yellow, bi carbonates are present
Add H2SO4 untill red
Total 0.02N H2SO4 x 10 = Total Alk in CaCO3
pH 100 ml unfiltered sealed water poured into two 50 ml glass
stoppered test tubes
Add 0.2 ml pH indicator to one ( pH indicator vary's according
to required measuring range)
Use colour comparator
Due to difficulty of excluding air, electronic pH meter
preferred
Sulphite reserve Exclude air at all stages
100 ml unfiltered water
Add 4 ml H2SO4 + 1 ml starch
Add potassium iodate-iodide untill blue colour
ml Iodate-Iodide sol x 806 / ml of sample = SO3 reserve in
ppm
Ammonia in feed Only necessary where N2H4 used in blr
Pour condensate sample into two 50 ml colour comparator
tubes
Add 2 ml Nessler reagent to one
Wait 10 mins
Use colour comparator
Boiler water treatment
Alkalinity
Treatment
For pressures below 20 bar dissolved O2 in the feed does not
cause any serious problems so long as the water is kept
alkalineHowever cold feed should be avoided as this introduces
large amounts of dissolved O2 are present, for pressures greater
than 18.5 bar a dearator is recommended
Feed Treatment Chemicals
Sodium Hydroxide
Calcium Bicarbonate (CaCO3 + Na2CO3)
Magnesium Bicarbonate
Magnesium Chloride.
. .
Sodium Phosphate
Calcium Carbonate
Calcium Sulphate
Magnesium Sulphate
All in this column precipitated as hydroxide or phosphate based
sludges All in this column form sodium salts which remain in
solution
Sodium Hydroxide
Reacts with highly corrosive MgCl2
Does not readily react with CaSO4
Strongly alkaline
Produces heat when mixed with water
Absorbs CO2 changing to Sodium Carbonate
Unsuitable for standard mixes
Sodium Carbonate Na2CO3 ( soda ash )
Alkaline
At pressures above 14 bar some of the Sodium Carbonate
decomposes to form NaOH and CO2 . Increasing on pressure
increase
Changes to Sodium Bi-Carbonate when exposed to air
Still usable but larger amounts make control difficult
Standard mix ingredient
Sodium Hexa Meta Phosphate NaPO3 (calgon)
Safe,soluble in water, slightly acidic
May be injected any where as will only react in the boiler
Suitable for LP blrs which require lower alkalinity
DiSodium Phosphate Na2HPO4 (Cophos II)
Neutral used with alkaline additive
Combines with NaOH to give trisodium phosphate
Basic constituent
TriSodium Phosphate Na3 PO4 (Cophos III)
Alkaline
When added to water decomposes to NaOH and Na2 HPO4
As water evaporated density increases and NaOH and Na2 HPO4
recombine
Phosphates can form Phosphides which can coat metal to form a
protective barrier, with excessive phosphate levels, this coating
can be excessive on highly rated boilers operating at higher
steaming rates
Chemicals are normally added as a dilute solution fed by a
proportioning pump or by injection from pressure pot.Use of
chemicals should be kept to a minimum.
Injection over a long period is preferable as this prevents
foaming.
Excessive use of phosphates without blowdown can produce
deposits of phosphides on a par with scale formations.
Therefore it is necessary to add sludge conditioners
particularly in the forms of polyelectrolytes, particularly in LP
blrs
Oxygen Scavengers
Hydrazine N 2 H 4
Oxygen scavenger, continously injected to maintain a reserve
within the boiler of 0.02 to 0.1 ppm and a feed water O2 content of
less than 10 ppb
At temperatures greater than 350oC , will decompose to ammonia
and nitrogen and will aid in maintaining balanced alkalinity in
steam piping.Steam volatile, neutralises CO2 Inherent alkalinity
helps maintain feed water alkalinity within parameters of 8.6 to
9.0.
Used in boiler operating above 32 bar, will not readily react
with O2 below 50oC hence risk of copper corrosion occurs with the
ammonia stripping off the continuously reforming copper oxides.
Supplied as a 35% solution
Carbohydrazide (N 2 H3)2CO
Is a combined form of Hydrazine
It is superior to hydrazine in performace and is designed to
minimise the vapours during handling
Carbohydrazide and its reaction products create no dissolved
solids
Is an oxygen scavenger and metal passivator at both high (230'C)
and low (65'C) temperatures
Can be used with boilers up to 170 bar
Diethylhydroxylamine DEHA
Like hydrazine, provides a passive oxide film ( magnetite) on
metal surfaces to minimise corrosion
Contributes to pH netralisation to an extent that seperate
condensate control may not be necessary
Protects entire system-feedwater, boiler and condensate
Sodium sulphite Na2SO3
Takes the form of a soft white powder
Slightly alkaline
Will react with oxygen to form Sodium Sulphate at about 8ppm
Sodium Sulphite to 1ppm Oxygen
Use limited to low pressure boilers due to increasing TDS and
reducing alkalinity by its action
Tannins
Certain alkaline tannin solutions have a good oxygen absorbing
ability with about 6ppm tannin able to remove 1ppm oxygen.
The reaction with oxygen is complex and unreliable, no official
reserve levels exist for the maintenance of a system using
tannin
Erythorbic Acid (Sur-gard) R1-C(OH)
An effective oxygen scavenger and metal passivator
It is the only non-volatile scavenger which can be used with
spray attemperation
does not add measureable solids to the boiler water
May be used in boilers up to 122 bar
Officially recognised as a Safe Substance
As with hydrazine a small amount of ammonia is created in the
boiler, it is not recommended for layup.
Polymer Treatment
Polymer is a giant molecular built up by stringing together
simple molecules
E.G. Polyelectrolytes-Formed from natural or synthetic ionic
monomersPolyacrylates - Polymers of acrylic acidPolyamides -
Polymers of amides
Polymer treatment prevents scale formation and minimises sludge
formation. It can also loosen scale so established blrs introduced
to this form of treatment may develop leaks where previously
plugged with scale. Especially in way of expanded joints. Also can
absorb trace oil
Use limited to LP blrs as no PO4 present to prevent caustic
alkalinity
For auxiliary blrs this is a superior form of treatment to the
old alkaline and phosphate treatment. The correct level of
alkalinity must be maintained as too low a level neutralises the
electric charge of the polyelectrolyte. Too high causes caustic
alkalinity.
Amine treatment
Compounds containing nitrogen and hydrogen.
Neutralising amines
Hydrazine N2H4see above
Bramine ( cyclohexalamine )
(Bull & Roberts amine treatment)
Neutralising amine as with hydrazine. Used with hydrazine to
maintain feed water alkalinity within parameters. As a knock on
effect will slightly increase boiler water alkalinity.
Stable at high temperatures so is used more than hydrazine to
control the steam line alkalinity as there is less chance of copper
corrosion which occurs with the prescience of ammonia
Proper boiler water treatment eliminates sludge and scale
deposits within the boiler. However, over along period of time a
film of copper and iron oxides build up on the tube surface. Most
of these oxides are transported from oxides of corrosion within the
feed system to the boiler with the condensate.
Bramine reduces this corrosion and eliminates the build up of
these oxide deposits.
Mechanism of functionCondensate from the condenser is very pure
and slightly acidic, often referred to as 'hungry water'. It can
dissolve metals in trace amounts to satisfy this hunger.Distilled
make up water aggravates this situation containing much dissolved
CO2 and hence being acidic carries its own corrosion products.Trace
amounts of bramine are introduced into the system to establish an
alkalinity level greatly reducing the effects of the hungry
water.
Some of the bramine is used almost immediately, most however,
passes on to the boiler where it is then transported through boiler
water, boiler stm drum, stm lines back to the condenser. It has no
effect anywhere except the condensate system.
Bramine also has a cleaning effect and may assist in the
cleaning the film off the tube over a period of time.Bramine is
safer to handle than Bramine and will protect all metals.
Hydrazine however readily breaks down to form ammonia which
whilst protecting ferrous metals will attack those containing
copper
Filming amines
Shows neutralising tendencies, main function however is to coat
piping with a molecular water repellent protective film
Injection of aminesMay be injected between HP and LP turbines in
the X-over pipe or after the dearator.Adding in X-over pipe-reduces
corrosion of copper alloysDearator only effective as a feed
heater
Adding after dearator -Dearator correctly performing as a
dearator and feed heater. If possible the best system is to have a
changeover to allow norm inj into the X-over at sea and injection
after the dearator when the turbine shut down
Limits of density/pressure
Sludge conditioning agents
Coagulants-
Mainly polyelectrolytes
Prevents the precipitated sodium based particles forming soft
scales
Will keep oil in an emulsion
the water must be kept alkaline
Antifoams
reduce the stability of water film around steam bubble and cause
it to collapse.
Common type polyamide is an organic compound of high molecular
weight.
In the event of severe contamination separate injection of an
antifoam is recommended
Dispersing agents
Sludge conditioners such as starch or tannin.
Prevent solid precipitates uniting to form sizeable crystals
e.g. MgSO4
Treatment in boilers (non congruent)
LP tank blrs (