6_Presentation - Boiler Water Chemistry

10-10-2015

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Ansuman Sen Sharma

India Boiler dot Com

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What is our objective?

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What makes Boiler Water Chemistry Critical for the O&M Engineers?

10Ca2+ + 6PO43– + 2OH– →

[Ca3(PO4)2]3·Ca(OH)2 $ßĦ¥ŦŲΏλ + σπςЊμ→ βζρЛξ

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Water Flow diagram in Boiler

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Deaerator

Boiler Feed Pump

CEP

Economizer

SH-1 SH-2

Attemperator

RH

TO CONDENSER

CIRCULATING WATER AND STEAM CYCLE

L P

Heate

r

H P

Heate

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Co

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What are the adverse Conditions under which a Boiler operates?

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Water Tube Boiler:

Temperature inside the furnace : 1100 -1200oC

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Natural Circulation:

Nucleate Boiling :

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Departure from Nucleate Boiling (DNB):

Film Boiling

Disturbance of Water Chemistry due to Steam Blanketing:

Increase in concentration of contaminants

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High Heat Flux – Critical Heat Flux

Poor Circulation Ration

Departure from Nucleate Boiling (DNB) leads to Film Boiling – overheating of evaporator tube and rapture

Cause:

Natural Circulation

H ρd ρr

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H ρd g H ρr g - ΔP = = H g (ρd – ρr)

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Natural Circulation

Drum Level

ρd ρr

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ΔP = H g (ρd – ρr)

Factors inducing DNB and tube overheating

Fast Ramp up during cold start

Low drum level

Obstruction due to foreign object fouling the tube

Formation of scale inside the tube

Flame shifting towards one side wall

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Other than Heat what other adverse Conditions?

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Longitudinal Stress & Hoop Stress in a cylinder:

σL = (P x D) / 4 t

σc = (P x D) / 2 t

σc = (P x D ) / 2 t

When σc exceeds σAllowable……..Tube fails in the

longitudinal direction

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What do we check in the Feed Water, Boiler Water & Steam?

Water Analysis:

Analysis Feed Water Boiler Water Steam Cond.

pH √ √ √ √

Conductivity √ √ √ √

Silica √ √ √ √

Residual

Hydrazine

√

Residual

Phosphate

√

P Alkalinity √

M Alkalinity

√

Chloride √

Iron & Copper √

Residual

Ammonia

√

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What are the consequences of faulty Water Chemistry in Boiler?

Scale

Corrosion

Carry Over

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Scale and Corrosion :

›

Carry Over :

›

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Carry Over :

›

Impurities in Water

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Water has been called a universal solvent

The natural surface water picks up:

• Minerals and salts from the earthen layer – dissolved condition

• Organic and inorganic impurities

• Decayed vegetation and marine lives

• Coarse and un-dissolvable substances in suspended form, mainly silt and clay matters - turbidity

• Siliceous matters, in dissolved as well as in colloidal forms

• Various gases, mainly Oxygen, and others like Carbon dioxide etc.

IMPURITIES

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SOLID IMPURITIES:

Suspended (> 1 micron)

Dissolved (< 0.001 micron)

Colloidal (< 0.5 micron)

Dissolved Solids:

Ionization of dissolved NaCl → Na+ + Cl-

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Suspended (> 1 micron)

Dissolved (< 0.001 micron)

Colloidal (< 0.5 micron)

Non Reactive

Reactive

Non Reactive

Dissolved Solids in Natural Water:

Mainly mineral salts

CATION (Basic Radical) ANION (Acidic Radical)

Ca++ (Calcium) HCO3– (Bicarbonate)

Mg++ (Magnesium) CO3– – (Carbonate)

Na+ (Sodium) SO4– – (Sulphate)

Cl – (Chloride)

NO3– (Nitrate)

PO4– – – (Phosphate)

HSiO3– (Bisilicate)

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t2 = t4 + (1/α + D/ k2) x Q

Where,

t2 = inner skin temperature of tube (°C)

t4 = boiler water temperature (bulk) (°C)

α = heat transfer coefficient of boiling surface (kcal/ m2·h·°C)

D = scale thickness (m)

k2 = thermal conductivity of scale (kcal/ m·h·°C)

Q = heat flux (kcal/m2·h)

Scale Formation

Thermal Conductivity of various scales

Substance Thermal conductivity (kcal/m2·h·°C)

Silica scale 0.2–0.4

Calcium carbonate scale 0.4–0.6

Calcium sulfate scale 0.5–2.0

Calcium phosphate scale 0.5–0.7

Iron oxide (hematite) scale

3–5

Iron oxide (magnetite) scale

1

Carbon steel 40–60

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Most deposits can be classified as one of two types scale that crystallized directly onto tube surfaces sludge deposits that precipitated elsewhere and were transported to the metal surface by the flowing water

Scale formation is a function of two criteria

1. The concentration and solubility limits of the dissolved salt

2. The retrograde solubility (inversely proportional to temperature) characteristic of some salts

The principal scaling and fouling ions are:

Calcium, Magnesium, Iron and bicarbonate and carbonate

Silica

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Distribution Ratio (DR) = mass dissolved in steam

mass dissolved in water

The need of Managing Silica

Forms hard glassy deposit on turbine blade

Decrease Enthalpy drop across stages

Increase specific steam consumption

May lead to imbalance and vibration sometimes

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Stage pressure increased by 5% after 15 months


Total accumulation can happen very fast


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Money down the drain =

Bw x (hf – h) x C/ (BE x CV)

Where,

Bw = Blow down quantity per hour

hf = Enthalpy of 1 kg of saturated water in drum,

h = Enthalpy of 1 kg of feed water entering the Economizer.

Continuous Blow Down


Factors that make Managing Silica difficult

Dissolved Silica is weakly ionized

Colloidal Silica can not be detected by Molybdate reaction test

Colloidal Silica becomes reactive silica at high temperature in the drum

Silica sometimes enter in colloidal state, particularly during high run off condition

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Economizer

Superheater

F W

B W

M S


Distribution Ratio (DR) = mass dissolved in steam

mass dissolved in water

ms

mw

Silica < 10 - 20 ppb

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Above 28 kg/ cm2 pressure, silica DR starts increasing almost logarithmically

Boiler Water pH > 9.2

Silica DR starts decreasing above 9 pH


In the turbine, the solubility sharply decreases after around 15 kg/ cm2 pressure

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ms

mw

Silica < 0.01 - 0.02 ppm

Managing Silica

F W

B W

M S

Boiler Water pH – 9.2 to 9.8

Silica < 0.5 ppm

SiO2 in steam in ppm

Pressure in bar

SiO2 in boiler (mg/L) SiO2 in steam in ppm

Pressure in bar

SiO2 in boiler (mg/L)

Managing Silica

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EPRI recommended Guideline for Boiler Water

Managing Silica

EPRI recommended Guideline for steam

Managing Silica

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ms

mw

Silica < 0.01 ppm

Managing Silica

F W

B W

M S

Boiler Water pH – 9.2 to 9.6

Silica < 0.3 ppm

Silica < 0.01 ppm

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Deaerator

Boiler Feed Pump

Cond. Extraction Pump

Econom

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SH-1

SH-2

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HP H

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CRH

LP H

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HP IP LP

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HRH

Condenser

Managing Silica

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Clariflocculator

Strong Based Anion

Mix Bed

Silica Control:

Managing Silica

Ultra Filtration

Reverse Osmosis

Drum Separator

Unwanted intrusion

Using Ultra Filter at MB outlet

MWCO (Molecular Weight Cut-off = 10,000 D )

Managing Silica

Membrane treatment can remove virtually all colloidal silica. Both reverse osmosis and ultra-filtration are effective in this respect. Reverse osmosis offers the additional advantage of significant reduction (98%+) of reactive silica as well.

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Managing Silica

Checking of Drum Separators to avoid mechanical carry over

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Deaerator

Boiler Feed Pump


Econom

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SH-1

SH-2

APH

HP

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CRH

LP

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HP

IP LP

GEN

HRH

Condens

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Managing Silica

Unwanted intrusion

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Managing Silica

Date : 03.8.11 To 19.08.11 (Day Average data)

Date

Boiler Feed water Boiler Drum Main Steam Condensate Water

Boiler Pr. Load pH Silica Iron pH Cond Silica Iron Po4 pH Silica Iron pH Silica Iron

Control Limits 8.8-9.5 < 0.02 0.01 9.4-9.7 < 80 < 0.5 - 5 to 10 8.8-9.5 < 0.02 < 0.02 8.8-9.5 < 0.02 -

Unit - ppm ppm - mS/cm ppm ppm ppm - ppm ppm - ppm ppm Kg/Cm2 MW

03.08.11 9.43 0.21 0.16 9.68 31 3.44 0.03 2.6 9.52 0.08 0.02 9.44 0.10 0.14 - -

05.08.11 9.43 0.24 0.13 9.55 32 4.41 0.05 2.1 9.44 0.07 0.01 9.50 0.13 0.08 - -

07.08.11 9.39 0.18 0.11 9.51 32 2.96 0.04 3.3 9.33 0.06 0.02 9.38 0.13 0.09 - -

08.08.11 9.45 0.19 0.09 9.69 31 2.88 0.07 3.1 9.46 0.04 0.02 9.39 0.11 0.09 - -

10.08.11 9.46 0.17 0.09 9.62 34 2.08 0.07 4.6 9.39 0.06 0.03 9.38 0.10 0.13 - -

15.08.11 9.40 0.12 0.10 9.66 34 1.89 0.09 5.4 9.45 0.06 0.05 9.39 0.08 0.09 - -

16.08.11 9.44 0.09 0.07 9.68 40 1.83 0.03 5.7 9.46 0.04 0.02 9.48 0.05 0.05 - -

17.08.11 9.54 0.08 0.04 9.70 42 1.45 0.03 4.4 9.53 0.04 0.02 9.54 0.04 0.04 112 107

18.08.11 9.43 0.08 0.07 9.62 38 1.97 0.04 5.0 9.45 0.05 0.01 9.49 0.05 0.05 109 75

19.08.11 9.41 0.06 0.03 9.64 34 0.95 0.02 6.0 9.42 0.03 0.01 9.43 0.03 0.02 139 97

Average 9.44 0.14 0.09 9.64 35 2.39 0.05 4.2 9.44 0.05 0.02 9.44 0.08 0.08 120 93

150 MW unit, silica went sky high during commissioning

Managing Silica

S.No Description Unit Design value Actual value

1 RO water ppm < 3 < 0.4

2 MB outlet ppm < 0.02 < 0.02

3 Condensate ppm < 0.02 0.04

Mine water was being used

DM water analysis

Treatment :

RO DM MB

They were operating with lower drum level to avoid mechanical carry over !!!!

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Managing Silica

strongly advise against operating with lower drum level

as mechanical Silica carry over is not indicative. It also doesn't appear to be Colloidal Silica Problem, but rather physical Silica intrusion from some point, so don't go for that test immediately. First rule out silica intrusion from LP dozing / HP dozing, Deaerator and CST. better clean all of them. Covering the area is a good idea

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Deaerator

Boiler Feed Pump


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Managing Silica

A gunny bag was found in Deaerator storage tank

CONCLUSION:

Mass can not be created, neither can it be destroyed

An analytical investigation is likely to lead you to the

problem

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Mainly due to Dissolved Oxygen

The degree of oxygen attack depends on

• The concentration of dissolved oxygen

• The pH and

• The temperature of the water

Corrosion

Oxidation of Fe in Boiler water:

Corrosion

Fe + ½O2 + H2O Fe(OH)2

4Fe2 + 3O2 + 6H2O → 2Fe2O3 6H2O

3Fe + 4H2O = Fe3O4 + 4H2

Magnetite

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Corrosion

Boiler internals with stable magnetite layer

Without stable magnetite layer

Formation of Magnetite: N2H4 + 6Fe2O3 → 4Fe3O4 + N2 + 2H2O

This reaction is then followed by the Schikorr reaction where precipitated ferrous hydroxide is converted into magnetite: 3Fe(OH)2 → Fe3O4 + 2H2O + H2 (2)

When carbon steel is exposed to oxygen-free water, the following reaction occurs: Fe + 2H2O → Fe2+ + 2OH- +H2 → Fe(OH)2 + H2 (1)

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LOW pH CORROSION AND OXYGEN PITTINGS

Anode:

Fe Fe2+ + 2e¯

Cathode:

½O2 + H2O + 2e¯ 2OH¯

Overall:

Fe + ½O2 + H2O Fe(OH)2

Galvanic Corrosion:

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It occurs when a metal or alloy is electrically coupled to a different metal or alloy while being immersed in an electrolyte

Galvanic Corrosion:

Anything that results in a difference in electrical potential at discrete surface locations can cause a galvanic reaction, such as:

scratches in a metal surface

differential stresses in a metal

differences in temperature

conductive deposits

Influence of temperature on carbon steel corrosion in water including dissolved oxygen

Effect of Temperature:

In a closed system like boiler feed water degree of corrosion is directly proportional to temperature

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Anode:

2Fe (solid) → 2Fe2+ (aq) + 4e-

Cathode:

O2 (gas) + 4H+ (aq) + 4e- → 2H2O

(liquid)

Further oxidation of Fe2+(aq) ions at Anode:

4Fe2+(aq) + 3O2 (gas) + 6H2O

(liquid) → 2Fe2O3 .6H2O (solid)

Effect of pH:

The H+ (aq) are available, when the medium is acidic. Therefore low pH increases the rate of corrosion.

pH

The pH indicates the concentration of hydrogen ion in an aqueous solution and is used as an index showing the acidity or alkalinity of water.

The ion product of water is a constant and it is 1 X 10–14 at 25°C; [H+] x [OH–] = 1 X 10–14

The pH is calculated from the H+ concentration by using the equation; pH = log 1/[H+] = - log [H+]

In case of pH 7, [H+] and [OH–] are equal at 1 X 10–7 and this water is said to be neutral.

Water only slightly dissociates into hydrogen ion (H+) and hydroxide ion (OH–); H2O → H+ + OH–

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The corrosion rate of carbon steel at high temperature is minimized in the pH range of 11 to 12 as shown in Figure below.

Effect of pH:

The corrosion rate of copper is low in the condensate of the pH 6 to 9 as shown in Figure below.

Effect of pH:

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Alkalinity

The three basic sources of alkalinity in water are: alkalinity resulting from

the bicarbonate ion (HCO3-),

the carbonate ion (CO32-), and the hydroxyl ion (OH-).

The amount of each of these in water can be determined by titrating with an acid to certain pH levels (end points) using phenolphthalein (P alkalinity) and a methyl orange (M alkalinity).

HCO3- Heat CO3

2- + H2O → CO2 + OH-

"P" alkalinity: It is the measure half of the carbonate ion (CO32-)

and Hydroxyl ion content and is expressed in ppm of calcium carbonate.

“M" alkalinity: It is the measure of carbonate ion content, bicarbonate ion (HCO3

-) and hydroxide content.

Alkalinity

1. At the P endpoint, all OH and 1/2CO3 would be reacted. 2. At the M endpoint, all OH and all CO3 would be reacted, or, P = 1/2CO3 + OH; 2P = CO3 + 2OH M = CO3 + OH + HCO3

Neutralization of alkaline water with H2SO4 (assume 50 ppm M alkalinity)

When HCO3 is absent; Subtracting, 2P – M = OH and CO3 = (M – OH) = [M – (2P – M)] = 2 (M – P)

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Alkalinity

EXAMPLE : If P = 86 ppm as CaCO3, and if M = 118 ppm as CaCO3

Then, situation 2 exists (P > ½M) Hydroxyl = 2P - M = (2 x 86) - 118 = 54 ppm as CaCO3

Carbonate = 2(M - P) = 2 x (118 - 86) = 64 ppm as CaCO3

Bicarbonate = 118 – 54 – 64 = 0 ppm as CaCO3

Caustic Corrosion (Gouging ):

Typical gouging caused by caustic attack developed under an original adherent deposit. Note irregular depressions and white (Na2CO3) deposits remaining around edges of original deposit area.

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Caustic corrosion (gouging) occurs when caustic is concentrated and dissolves the protective magnetite (Fe3O4 ) layer.

Na3PO4 + H2O Na2HPO4 + NaOH

4NaOH + Fe3O4 → Na2FeO2 + 2NaFeO2 + 2H2O

2NaOH + Fe → Na2FeO2 +2H

UNDER DEPOSIT BOILING

Protective Oxide Protective Oxide Fe3O4

Tube metal wall

Water and Steam

Porous Oxide

Wick Boiling

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Na3PO4 + H2O ↔ Na2HPO4 + NaOH


Case study:

30 MW BFB Boiler

Location: Bed Coil Tubes

Size & Spec : Ø 51 x 6.35 mm & SA 210 Gr.A1

Bed Temperature: 905°C

Service: less than 1 year

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Tube Location

Bed Coil Tube

BFB Boiler

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Failed Tube

Failed Bed Coil Tube

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Failed Tube

Damage at 12 O Clock position

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Failed Tube

Deposits near damage

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During discussion, it was noted :

all three boilers are operated at nearly 25% over loading conditions

Charcoal is used as start up fuel

Recently drum level maintained at 8 – 12% lower than normal level to avoid mechanical carry over (which was observed taking place)

Residual Phosphate was also maintained at 2-3 ppm instead of 6-8 ppm as required for the same reason

Fuel Distribution plates were found in damaged condition.

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Acid Attack:

This results in a visually irregular surface appearance, as shown in Figure. Smooth surfaces appear at areas of flow where the attack has been intensified.

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ACID CHLORIDE CORROSION

MgCl2 + H2O → MgO + 2HCl

Fe3O4 +HCl → FeCl2 + FeCl +H2O

Fe + 2HCl → FeCl2 + H2

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Embrittlement

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Violent rupture Hydrogen Damage

HYDROGEN DAMAGE (EMBRITTLEMENT)

Thick Lip Brittle Appearance

Mechanism:

4NaOH + Fe3O4 → 2NaFeO2 + Na2FeO2 + 2H2O

Fe + 2NaOH → Na2FeO2 + 2H

4H+ + Fe3C → CH4 + 3Fe


MgCl2 + H2O MgO + 2HCl

Fe3O4 +HCl FeCl2 + FeCl +H2O

Fe + 2HCl FeCl2 + 2H

4H+ + Fe3C → CH4 + 3Fe

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Decarburization weakens tube

Gas generated collects in grain boundaries and form fissures as pressure builds up which eventually grow

Failure occurs when the ruptured section can no longer

withstand the internal pressure. Ruptures are violent and sudden, and can be disastrous

Case Study:

120 MW Oil Fired Boiler

Location: Goose Neck Rear Water Wall

Size : Ø 76.1 x 5.5 mm

Specification: SA210 GR A1

Working Temp. & Pressure: 350°C & 90 kg/cm²

Service: 250000 Hrs

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The middle tube has burst opened with thick lips

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Dimensional Measurement (mm): Tube location Outside Diameter Thickness 0°-180° 90°-270° 0° 90° 180° 270˚

Near failed lip - - 4.08 - 6.12 - Ring section 74.15 78.73 3.97 5.60 5.78 5.67

Flattening Test: Test Method ASTM A370 A flattening specimen was taken near the failed region. The flattening test showed cracks on ID surface, indicative of hydrogen embrittlement.

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The middle tube was transverse sectioned and micro examined at the failed region. The failed lip shows a lot of oxide filled discontinuous cracks starting from ID surface

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Decarburization is observed near the crack edges throughout this region.

• Opposite to the failed region, the

microstructure consists of polygonal grains of ferrite and pearlite

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On a ring section a littleaway from the failed region, a similar structure is observed

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Conclusion: Several oxide filled discontinuous cracks are observed on the ID surface of the tube. The flattening test result indicates hydrogen embrittlement.

The failure of the tube is attributed to hydrogen embritlement.

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Case 1:


Location: LHS Water Wall

Size : Ø 76.1 x 5.5 mm

Specification: SA210 GR A1


Service: 254378 Hrs

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The tube shows blisters at four locations (OD = 80 to 82 mm) in the spool piece between two weld joints.

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A circumferential crack is observed near the fusion line of one of the butt joint. Heavy deposits are observed on the ID surface of the tube.

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Wall thickness at 0o was measured as 1.5 mm

Micro examination of Transverse sections of the tube at two out of four blisters reveal oxides on the blister edges and ID surface of the tube

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Oxides filled rounded pits are observed on the ID surface.

Copper coloured copper rich phase segregation is observed near the blister

edges and ID surface

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No significant deformation / decarburisation of the adjoining grains of the pit edges and blister edges are observed.

The microstructure consists of polygonal grains of ferrite and pearlite

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Transverse section of the weld joint where the circumferential crack was observed reveals segregation of copper rich phase near the ID surface.

Several discontinuous grain boundary cracks with decarburisation of the adjoining grains, typical of Hydrogen embrittlement cracks are observed in the spool piece PM, HAZ and weld metal of the butt joint

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One more transverse section of the weld joint at about 180° from the circumferential crack was also micro examined. Mismatch between the tube members, lack of sidewall fusion, incomplete root penetration and slag are observed

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Conclusion:

Micro examination reveals presence of copper coloured copper rich phase on the ID surface and blister edges of the tube. Also damage due to Hydrogen embrittlement is observed in the PM, weld and HAZ regions of the weld joint.

The blisters observed on the OD surface is attributed to waterside corrosion may be due to condenser leakage.

The circumferential crack observed near the fusion line of the butt joint is attributed Hydrogen embrittlement caused by waterside corrosion.

Swab analysis shows presence of some chloride and sulphur with a pH value of 7.8.

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CAUSTIC EMBRITTLEMENT

REASON

For caustic embrittlement to occur, three conditions must exist:

The boiler metal must have a high level of stress

A mechanism for the concentration of boiler water must be present

The boiler water must have embrittlement-producing characteristics

Fine cracks adjacent and parallel to the weld joint can be seen on a Super heater tube. Surface branching of the crack is apparent


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Micro-structural examinations revealed branched cracks running across the grains (trans-granular) and originating on the internal surface. The cracks are located in the heat-affected zone immediately adjacent to the weld.



REMEDIAL ACTION

Proper stress relieving of all welded or

rolled section

Application of a coordinated pH/phosphate

control

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Carry Over

A. Chemical Carry Over

B. Mechanical Carry Over

Factors related to water quality:

A. Chemical Carry Over:

Excess concentration of the boiler water

Contamination of boiler water with oils and fats causing foaming

Dissolution of silica to steam

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Factors related to Operating control, causing Priming:

B. Mechanical Carry Over:

Operation at the high water level

Rapid fluctuation of heat load

Failure of flow control

Factors related to the mechanical structure of boiler:

Inadequate, or, poor condition of the water and steam separator

Water treatment

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Water treatment

Pre treatment

Demineralization

Deaeration

Chemical conditioning

Cl2 + H20 HOCl + H+ + Cl-

Chlorination:

Effective Biocide

To Neutralize the Micro-Biological organisms, chlorine is dosed into raw water, before the process of clarification

Pre-treatment:

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Clariflocculator:

The “precipitator” operates on the “sludge blanket” principle

Pre-treatment

Clarification

Lime precipitates and forms sludge:

Coagulating agent added –

• Alum [Al2(SO4)3] and Hydrated Lime [Ca(OH)2] solutions

• Polyelectrolyte solutions (PAC)

Ca ( OH )2 + Ca ( HCO3 )2 2CaCO3↓ + 2H2O

Ca ( OH )2 + MgCO3 Mg( OH )2↓ + 2CaCO3↓

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The colloidal produced by Aluminum Hydroxide is negatively charged, and is an effective coagulant of the positively charged

Alum with calcium bicarbonate

Al2(SO4)3*18H2O + 3Ca(HCO3)2 2Al(OH)3 + 6CO2 + 3CaSO4 + 18H2O

To avoid algae formation chlorine is dosed into raw water, before the process of clarification

Polyelectrolyte

These are polymers with ionizable groups that can dissociate in solution, leaving ions of one sign bound to the chain and counter-ions in solution. They are soluble in water and help to coagulate.

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Lamella Plate System:

The settling surface is provided by a series of inclined, parallel plates.

Saving in space compared with a settling tank is 90%

The water to be treated is admitted through the inlet chamber in the mid-section, flows upward through the plate assembly and is discharged to the runoff channels through a series of holes arranged to distribute the flow

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Filter medium - sand, fabric or porous membranes.

Pressure Filters

Cl2 + H20 HOCl + H+ + Cl-

Na2S2O3 + Cl2 + H2O Na2S04 + S + 2HCl

Na2S2O3 + HCl NaCl + H2O + S + SO2

Chlorination:

De-Chlorination:

Effective Biocide

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Activated Carbon Bed adsorbs left over chlorine

Demineralization:

• Ion exchange

• Membrane desalination (RO)

• Thermal desalination

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Ion Exchange Process

Ion exchange resins in ion exchange pressure vessels


Ion exchange resins:

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Ion exchange resins:

R-H+

R+OH-


Ion exchange DM process:

Cation resin:

R-H+ + C+ ↔ R-C+ + H+

Anion resin:

R+OH- + A- ↔ R+A- + OH-

The hydrogen ions (H+) displaced from the cation resin react with the hydroxide ions (OH-) displaced form the anion resin and form pure water (H2O)

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Regeneration of exhausted resins

Cation resin regeneration:

2R-C+ + HCl ↔ 2R-H+ + C+Cl-

R+A- + NaOH ↔ R+OH- + Na+A-

Anion resin regeneration:


Degasifier:

Before anion exchanger, this is placed primarily for the removal of CO2 and lessen the load on Anion exchanger

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Degasifier:


Mixed Bed:

It consists of both Cation and Anion resins mixed together

Traces of all Cation and Anions are totally absorbed and removed. Primarily used for silica removal

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Mixed Bed:


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In case of water to be treated contains a high proportion of strong anions (chlorides and sulphates)


Mixed Bed Regeneration

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Membrane Desalination Process (Reverse Osmosis):

»


»

Membrane Material:

Cellulose Acetate

Polyamide

Nylon

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»

Osmotic Pressure: A simple equation relates osmotic pressure to concentration: P = ∆C x R x T Where, P is osmotic pressure in Pa, ∆C is difference in concentration in mol.m-3

[mol.m-3 = concentration in kg.m-3/ mol. Weight in kg.mol-3] R is constant of an ideal gas = 8.314 (J/mol.K),

Example: Concentration in solution = 100 kg.m-3; T = 300 K; for a compound with A molecular weight of 0.050 kg.mol-1 ∆C = 100/ 0.05 = 2000, P = 2000 x 8.3143 x 300 = 50 x 105 Pa = 50 bar


»

When water is transferred, the molecules and ions retained by the membrane tend to accumulate along its entire surface

This phenomenon is known as concentration polarization of the membrane and is defined by the coefficient: Ψ = Cm/ Ce

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»

For a saline solution, the water flux rates may be obtained by Fick's and Henry's laws. Qp = Kp x S x (∆P - ∆p) x Kt/e Where, Qp = flow of water through the membranes, Kp = membrane permeability coefficient for water, S = membrane surface area, e = thickness of the membrane, ∆P = hydraulic pressure differential across the membrane, ∆p = osmotic pressure differential across the membrane, Kt = temperature coefficient.

Thermal Desalination Process:

Treatable water is vaporized and the vapour is subsequently condensed as pure water. Particularly

used when raw water is sea water

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Zeolite Softening Process:

Deaeration:

at 10°C, the solubility of principal gases under a pressure of pure gas equal to 102 kPa

Gas Solubility

mg.l-1

N2 23.2

O2 54.3

CO2 2318

CH4 32.5

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Deaeration:

Dissolved oxygen is removed by thermo-mechanical action.

Temperature is raised with steam to lower the solubility of gas and trays are used to atomize the water Oxygen removal up to 0.007 ppm

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Temperature

…… 0 solubility at saturation temperature

Partial pressure of Oxygen on water surface

Solubility of Oxygen depends on :

PT LT TE

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Chemical conditioning

Oxygen scavengers:

Sodium sulfite: It reacts readily with oxygen, particularly at elevated pH and temperature, to form sodium sulfate

2 Na2SO3 + O2 → 2 Na2SO4

The use of sodium sulfite should be avoided in high pressure boilers because of its potential for thermal decomposition

2 Na2SO3 + H2O + Heat → 2NaOH + SO2

Hydrazine (N2H4): For low and medium pressure applications and more extensive in high pressure systems.

N2H4 + O2 → 2H2O + N2

Hydrazine will also react with Ferric oxide and Cupric oxide

N2H4 + 6Fe2O3 → 4Fe3O4 + N2 + 2H2O N2H4 + 4CuO → 2Cu2O + N2 + 2H2O

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Hydrazine dosing is done either at condensate line or at feed water suction line where the temperature is well below 270°C

At 270°C, hydrazine undergoes rapid thermal degradation 3N2H4 + Heat → N2 + 4NH3

Alternative of Hydrazine:

Carbohydrazide: [1.4 : 1] H6N4CO + 2O2 → CO2 + 2N2 + 3H2O

Methylethylketoxime, or MEKO: [11 : 1] 2 H3C(C=N-OH) CH2CH3 + O2 → 2 H3C (C=O) CH2 CH2 + N2O + H2O

Hydroquinone: [6.9 : 1] HO CH6 OH + ½ O2 → H2O + O=(double bond) CH6=O

Diethylhydroxylamine, or DEHA : [1.3 - 3 : 1] 4 (CH3CH2)2 NOH + 9O2 → 8 CH3 COOH + 2 N2 + 14 H20

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pH correction

In high pressure Boiler, the pre-boiler conditions are having a high temperature

Ammonia and/or Morpholine or Cyclo-hexylamine is sometimes added before the Deaerator for pH control

In case Copper alloys are used in the pre-boiler section like HP heater, pH is to be kept lower to avoid oxidation

pH correction

Volatile pH booster chemicals: Ammonia [NH3], (DR - 10); mildly basic Cyclohexylamine [C6H11NH2], (DR – 4.0) ; highly basic Diethylaminoethanol [C6H15NO], (DR – 1.7); mildly basic Morpholine [C4H9NO], (DR – 0.4); significantly less basic

Amines will decompose and produce Ammonia in feed water. A general rule of thumb suggests that Ammonia concentration should be limited to 0.5 ppm in systems with Copper alloy metal. pH should be maintained below 8.5

DR: Amine in vapor phase divided by amine in water phase

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pH correction

When non-condensed gases, such as ammonia and oxygen, are contained in the steam, they are highly concentrated near the air ejector and copper is attacked by the following reactions:

Cu + 1/2O2 + H2O → Cu(OH)2

Cu(OH)2 + 4NH3 → [Cu(NH3)4](OH)2

[Cu(NH3)4](OH)2 Cu(NH3)42+ + 2OH–

The boiler water pH is maintained by dosing of TSP or Tri Sodium Phosphate in the boiler section

Na3PO4 + H2O ↔ Na2HPO4 + NaOH

In addition to increasing the pH of the Boiler water, Phosphate helps 1. By reacting with hardness components (Ca2+, Mg2+) in water and

converting them into the suspended solids to be easily discharged from boiler with blow down water,

2. By keeping silica in the water soluble form.

1. 10Ca2+ + 6PO43– + 2OH– → Ca5(OH)(PO4)3

[hydroxyapatite]

2. Mg2+ + 2OH– → Mg (OH)2 Mg2+ + HSiO3

– + OH– → MgSiO3 + H2O

3. H2SiO3 + 2NaOH → Na2SiO3 + 2H2O

[sodium meta silicate]

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Damage Mechanism: Flow Accelerated

Corrosion

HP Economizer drain

tube Feed Pipe

Feed Pipe

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Damage Mechanism: Flow Accelerated Corrosion

Flow-accelerated corrosion (FAC) is a well-known damage mechanism that affects carbon steel components carrying water or two-phase flow. Caused by the mechanically-assisted chemical dissolution of the protective oxide and base metal.

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It has lead to failures or severe wall thinning in:

Economizer/preheater tubes at inlet headers.

Economizer/preheater tube bends in regions where

steaming occurs.

Vertical LP evaporator tubes on Horizontal HRSGs,

especially in the bends near the outlet headers

LP evaporator inlet headers which have a tortuous fluid

entry path and where orifices are installed.

LP riser tubes/pipes to the LP drum.

LP evaporator transition headers.

Feed Water Line.

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FAC is a mass-transfer process in which the protective oxide (mostly magnetite) is removed from the steel surface by flowing water. Material wear rate depends on (1) Steel composition, temperature, flow velocity and turbulence, (2) Water and water-droplet pH, and (3) The concentrations of both oxygen and oxygen scavenger.

FLOW ASSISTED CORROSION

Localized thinning

Dissolution of protective oxide and base metal

Occurs in single or two phase water

Low pressure system bends in evaporators,

Risers and economizer tubes

Feed water cycle

FAC affected by:

Temperature

pH

O2 concentration

Mass flow rate

Geometry

Quality of fluid

Alloys of construction

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Greatest potential for FAC occurs around 150 ºC

Effect of temperature on normalized wear rate of various metallurgies


pH has significant effect on normalized wear rate of carbon steel

Nearly forty (40) fold reduction between pH 8.6 and 9.4

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FAC minimized above 30 ppb O2

FAC increases exponentially below 30 ppb O2

Dissolved oxygen has direct impact


Normalized wear rate minimal below 10 ft/sec

Rate increases by 2.8 times at 100 ft/sec

Effect of Velocity

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Geometry affects location of FAC, regardless of Reynold’s Number

Location

Formation of Magnetite: When carbon steel is exposed to oxygen-free water, the following reaction occurs: Fe + 2H2O ⇒ Fe2+ + 2OH- +H2 ⇔ Fe(OH)2 + H2 (1)

This reaction is then followed by the Schikorr reaction where precipitated ferrous hydroxide is converted into magnetite: 3Fe(OH)2 ⇒ Fe3O4 + 2H2O + H2 (2)

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Dissolution of Magnetite

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Precaution: For HRSG and fossil fired boiler plants with all-ferrous feedwater systems the feedwater chemistry should be AVT(O) to avoid single-phase FAC in the feedwater and LP evaporator circuit.

The basic idea of AVT is to minimize corrosion and FAC by using deaerated high purity water with elevated pH. The pH elevation should be achieved by the addition of ammonia.

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Effect of Temperature and Ammonia on iron dissolution

Effect of pH on FAC

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Precaution: Turbulences should be minimized by proper design

For new replacement and for new units material of construction may be changed to P11 or P22

Regular inspection of susceptible components by ultrasonic (UT) examination needs to be undertaken to prevent any catastrophic failure

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Precaution: For the carbon steel materials operating under reducing feedwater chemistry the oxide formed is Fe3O4

(magnetite) and its solubility is strongly influenced by the reducing conditions.

This constitutes the highest probability for FAC in a fossil plant with highest solubility being around 1500C.

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Precaution: Changing the feedwater to an oxidizing treatment by eliminating the reducing agent and/or adding oxygen will result in the formation of FeOOH (ferric oxide hydrate). This reduces the solubility of the surface oxide by at least two orders of magnitude in the temperature range up to about 3000C.

pH correction with AVT

AVT(R) [Reducing All Volatile Treatment]

Reducing all volatile treatment uses ammonia and a reducing agent (N2H4).

Used for mixed metallurgy feed water systems

Achievable iron level for units operating with AVT(R) is less than 2ppb

In AVT(R), the steel surface in contact with water is covered by a magnetite layer

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AVT(R) [Reducing All Volatile Treatment]

The requirements for AVT(R) :

Elevated pH of 9.0 – 9.3 Cation conductivity of less than 0.20 μS/cm Minimum air in-leakage to ensure less than

10 ppb dissolved oxygen


AVT(O) [Oxidizing All Volatile Treatment]

In oxidizing all volatile treatment the use of reducing agent is eliminated.

For units operating with AVT(O), the achievable iron levels can be around 1ppb or less.

With AVT(O) or OT, the protective cover layer pores become plugged with ferric oxide hydrate (FeOOH)

Used for all ferrous metallurgy

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AVT(O) [Oxidizing All Volatile Treatment]

The requirements for AVT(O):

Elevated pH of 9.2 – 9.6 Cation conductivity of less than 0.20 μS/cm Minimum air in-leakage to ensure less than

10 ppb dissolved oxygen at CPD No additional reducing agent


OT (Oxygenated Treatment)

In Oxygenated treatment, oxygen and ammonia are added to feedwater

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The requirements for OT:

Cation conductivity of less than 0.15 μS/cm Addition of oxygen to the feed water

OT (Oxygenated Treatment)

Blow Down control:

CBD (Continuous Blow Down)

IBD (Intermittent Blow Down)

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Failures Case Studies

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Case 1:


Location: Primary SH Coil

Size : Ø 57.15 x 4.2 mm


Service: 243000 Hrs

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The tube shows bulging (OD=61.5 mm) and burst opened like a fish mouth

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Dimensional Measurement (mm): Tube location Outside Diameter Thickness 0°-180° 90°-270° 0° 90° 180°

270˚

Near failed lip -- -- 3.03 -- 4.27 --

Ring section 59.21 61.81 3.35 3.68 3.93 3.82

little away

Burst section is having thick lip

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Transverse section of the burst lip reveals oxidation of the edges. Several oxides filled rounded pits are observed on the edges of the lip as wells on the ID surface of the tube. No significant deformation / decarburisation of the adjoining grains of the pit edges are observed. The microstructure consists of polygonal grains of ferrite and pearlite.

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Opposite to the burst and a ring section little away from the burst also show similar type of microstructure. Oxides filled pits are observed in both the sections examined.

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Conclusion:

Micro examination indicates several rounded pits filled with oxides on the ID surface of the tube.

The failure is attributed to waterside corrosion.

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Tube shows bulging (OD= 83.5 mm) and burst opened with thin lips. No significant amount of deposits is observed on ID and OD surface.

However, take the case of a similar failure in the same Boiler

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Some rounded pits filled with oxides are observed on the ID surface tube in all the three sections examined.

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Transverse section of the burst lip shows oxidation of the edges and the structure consists of bainite.

Opposite to the burst the structure shows polygonal grains of ferrite and pearlite.

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A ring section little away from the burst shows transformed ferrite and pearlite along the axis of burst and polygonal grains of ferrite and pearlite, opposite to the burst axis.

Above observations suggests that the tube has been overheated to above AC3 temperature for the steel for a short period of time.

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6_Presentation - Boiler Water Chemistry

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Transcript of 6_Presentation - Boiler Water Chemistry