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.

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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

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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.

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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 (