This document provides a root cause analysis and recommendations for corrosion issues in MPL's heat recovery steam generators (HRSGs). It discusses key factors influencing corrosion rates, including metallurgy, velocity, and circulation ratio. The document analyzes root causes of boiler tube failures and factors affecting repeat failures. It provides recommendations for corrective actions, future testing, and conclusions. Attachments include thickness measurement data and boiler chemistry guidelines.

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MPL
RCA and Recommendation of HRSG’s
Corrosion
Prepared by
Md. Abdul Hannan
Plant Chemist, MPL.
Date: 18th
February; 2012

2. 2 of 25
Contents
1. Introduction --------------------------------------------------------------------------------3
2. The key factors which influencing the corrosion rate ---------------------------------5
3. Metallurgy ----------------------------------------------------------------------------------6
4. Velocity ----------------------------------------------------------------------------------10
5. Circulation ratio --------------------------------------------------------------------------11
6. High risk areas for FAC -----------------------------------------------------------------11
7. Root cause analysis of boiler tube failure ----------------------------------------------12
8. Factors influencing repeat tube failure -------------------------------------------------15
9. Boiler tube sampling -------------------------------------------------------------------16
10. Recommendation of corrective/preventive action for protection of boiler
corrosion/failure to minimize the rate of material loss -------------------------------16
11. Recommendation for future testing ----------------------------------------------------24
12. Conclusions ------------------------------------------------------------------------------24
Attachment: 1. HRSG-1(thickness measurement) LP riser UT data for 2012,
2. HRSG-2(thickness measurement) LP riser UT data for 2012,
3. LP evaporator header tube diameter,
4. Boiler Chemistry guidline from GE-Betz experts,
5. We started HRST’s guidelines chemicals
6. Proposed limit value of boiler chemistry,
7. Competitive study of phosphate guidelines.

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Root Cause Analysis (RCA), Comments
& Recommendations for MPL HRSG’s
Corrosion:
1. Introduction:
No metal is truly insoluble, and all have a tendency to pass into solution. The
solubility depends on the attraction of valence spin electron to the nucleus i.e.
field of pure potentiality of the atom. The de-coference of electron depends on
the availability of electron coordinator, acceptor or donor environment as well
as friction of the environment with the valence energy levels of the metal. The
lower the attraction force the higher is the solubility. It also depends on the
attraction of the available electronegative atoms (O, Cl, F etc.) or radicals
(OH, SO4, CO3, HCO3, PO4 etc.) of the environment and friction between the
metal atom & water molecules due to high water flow velocity.
When metal atoms are exposed to an environment containing electronegative
atoms/ions/radicals/molecules/complex ions they can give-up electrons,
becoming themselves positively charged ions, provided an electrical circuit
can be completed. This effect can be concentrated locally to form a pit or,
sometimes a crack, or localized corrosion that leads to pitting may provide
sites for fatigue initiation and, pitting corrosion also occurs much faster in
areas where microstructural changes have occurred due to welding
operations.
The corrosion resistance of metal and alloys of the metals is a basic property
related to the easiness with which these materials react with a given
environment. Corrosion is a natural process that seeks to reduce the binding
energy in metals. The end result of corrosion involves a metal atom being
oxidized, where it loses one or more electrons and leaves the bulk metal.
Certain environments offer opportunities for these metals to combine
chemically with elements to form compounds and return to their lower energy
levels from their excited state.
At high temperatures, Fe will corrode at PH<9 produces ferrous and ferric ions
and consequently ferrous hydroxideFe (OH) 2 ,ferric hydroxide Fe (OH) 3 and
at very alkaline conditions, complex HFeO2
-
ions. The corrosion products are
solid and important iron ore constituents, hematite (Fe2O3) and magnetite
(Fe3O4), and protective under this PH condition. If the potential of Fe is made

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sufficiently negative or shifted cathodically below 0.5V Fe will corrode much
less.
Energy of Cr>Fe>Cu required to convert them from their oxides to metal due to
their different energy levels/ Oxidation states. The Cr element has more
available empty orbital and the significant presence of it in a metal alloy leads
the resistance of corrosion of that metal alloy.
Corrosion is the disintegration of metal through an unintentional chemical or
electrochemical action, starting at its surface. All metals exhibit a tendency
to be oxidized, some more easily than others.
Flow accelerated/Assisted Corrosion (FAC) is a flow-induced corrosion
process that increases the rate of thinning of pressure part components due
to mainly the high water flow velocity in water or a steam-water mixture
phase. FAC is also known as “Erosion-Corrosion”.
Fig. FAC damage to header.

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A heat recovery steam generator (HRSG) is not a boiler. Conventional boilers
are built for radiant and convection heating. HRSGs are supper efficient
absorbers of convective heat provided by a combustion turbine’s exhaust.
HRSGs consist of four major components: the Economizer, Evaporator,
Superheater and Water preheater. It categorized into vertical or horizontal
modules of tubes closely spaced and tightly-finned for optimum heat transfer.
MPL’s HRSGs are multi pressure HRSGs empty triple pressure steem drums
consist of three sections: (i) an LP (low pressure) section, (ii) a reheat/IP
(intermediate pressure) section and (iii) an HP (high pressure section). Each
section has a steam drum and an evaporator section where water is converted
to steam. This then passes through super heaters to raise the temperature
and pressure past the saturation point.
2. The key factors which influencing the corrosion rate
are—
1. Nature of the metal:
(a) Oxidation potential/ Effective electrode potential in solution
(b) Overvoltage of hydrogen on the metal
(c) Relative area of the anode and cathode
(d) Purity of the metal
(e) Physical state of the metal
(f) Inherent ability to form an insoluble protective film.
(g) Solubility of the products of corrosion
(h) Physical & Chemical homogeneity of the metal surface.
2. Nature of the Environment:
(a) Construction of equipments through design
(b) Temperature
(c) Contact between dissimilar metals or other materials as affecting
localized corrosion.
(d) Ability of environment to form a protective deposit on the metal.
(e) Concentration of O2 and influence of O2 in solution adjust to the
metal.
(f) Flow velocity of process streams in contact with the metal.
(g) Start-up and shut-down procedure.
(h) Cyclic stress ( Corrosion fatigue )
(i) Potential of H+
Concentration (PH) in the solution.
(j) Nature of anions and cations present.
(k) Conductance of the medium.
(l) Other operational practices.
(m) Replacement & Repair of corroded equipment and

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(n) Process management to avoid future corrosion problem.
3. Metallurgy:
Steels are used in boiler construction because they are inexpensive, readily
available, easily formed and welded to the desired shape and, within the broad
limits, are oxidation and corrosion- resistant enough to provide satisfactory
service for many years. MPL’s HRSG tube & header’s metallurgy are mainly
carbon steel & low-alloy steels. The alloys should have satisfaction with the
current heat transfer performance and mechanical reliability. The future
outlook for the boiler should no change in the operating conditions or fuel(s)
fired.
Alloying elements added to improve some properties of the material (strength,
high-temperature strength, oxidation or corrosion resistance for example). By
definition, steels contain at least 50% iron. For welded construction, the ASME
Boiler and Pressure Vessel Code limits the carbon content to less than 0.35%.
Steels are divided into two subcategories: ferritic steels and austenitic steels,
depending on the arrangement of atoms within the solid.
The increase of conductor/semi conductor elements in the alloy will increase
thermal conductivity as well as improves the thermal efficiency of the boiler
and its power generation capabilities as the increase of the availability of
empty orbitals. The increased hardness improves erosion resistance of the
tubes.
All matter is made up of atoms. These atoms arrange themselves to form a
solid is referred to as a “lattice”. The body-centered cubic arrangement is
referred to as “ferrite”, and the face-centered cubic arrangement is called
“austenite.” The addition of the element carbon does not alter this
arrangement. Carbon is a small atom and some will fit within the holes
between the spheres of iron.
Atoms of iron are quite small, about 100,000,000 would fit in an inch. Thus,
useful sizes of material contain a huge number of individual atoms. The
building block of making useful shapes is a crystal or grain where two grains
come together and meet; they form a crystal or grain boundary. The lattice
arrangement in these two crystals is the same, but the orientation is different.
At the grain boundary, individual atoms are not arranged regularly and
therefore short-range disorder characterizes the grain boundaries.

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MPL HRSG’s tube, headers & drum vessels metallurgy is given bellow:
Most frequently used steels (MPL HRSG's tubes, headers &
drum vessels Metallurgy):
Sl.
No.
MPL
HRSG’s
Vessels
Code
Specification
Grade
Alloy
Type
Main
Composition
Maximum
useful
Temperature,oF
1
HPEV
tube
SA 178 C
C = 0.06 -
0.18%
2
HPEC
tube
SA 178 C
Cr,Mo
negligible
3 IPSH tube SA 178 A
Cu absent
and
4 IPEV tube SA 178 A
Ni trace
level.
5 IPEC tube SA 178 A
6 LPSH tube SA 178 A
7 LPEV tube SA 178 A 850
8 LPEC tube SA 178 A
Carbon
Steel
9 - SA192 -
10 - SA 210 -
11 - SA 515 - 516 -
12
HPEV
Header
SA 106 C
C =0.25 -
0.35%
13
HPEC
Header
SA 106 C Cr = 0.4%
14
IPSH
Header
SA 106 B Cu = 0.4%
15
IPEV
Header
SA 106 B Mo = 0.15%
16
IPEC
Header
SA 106 B Ni = 0.4%
17
LPSH
Header
SA 106 B
18 LPEV SA 106 B

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Header
19
LPEC
Header
SA 106 B
20 - SA 209 - C - 1/2 Mo 900
21 - SA 213 T-11
11/4Cr -
1/2Mo
1025
22 - SA 335 P-11
23
HPSH
Tube
SA 213 T-22
Low
alloy
steel
24
Reheater
Header(2)
SA 335 P-22
21/4Cr - 1Mo -
1/2Si - 1/2Mn
1075
25
HPSH 3&
4 Header
SA 335 P-22
26
Reheat
tube
SA 213 T - 91
27
Reheater
header
SA 335 P - 91
Cr-Mo
alloy
steel
9Cr - 1Mo -
1/2Si - 1/2Mn
28
HPSH 1 &
2 Header
SA 335 P - 91
29 HP Drum C = 0.35%
30 IP Drum SA 515 70
C-Si-Mn
alloy
steels
Si = 0.15 -
0.30%
31 LP Drum Mn = 0.90%
32 - SA 213 T - 9
Cr-Mo
alloy
steel
9Cr - 1Mo
33 -
SA 213 TP
304(H)
Cr-Ni
alloy
steel
18Cr - 10 Ni 1500
34 321(H),347(H)
Metal Compositions:
A 106:
ASTM A106
Chemical
Composition
GradeA GradeB GradeC

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C(max) 0.25 0.3 0.35
Mn 0.270.93 0.291.06 0.291.06
P(max) 0.035 0.035 0.035
S(max ) 0.035 0.035 0.035
Si(min) 0.1 0.1 0.1
Cr(max ) 0.4 0.4 0.4
Cu(max) 0.4 0.4 0.4
Mo(max) 0.15 0.15 0.15
Ni(max ) 0.4 0.4 0.4
V(max) 0.08 0.08 0.08
A178 A:
SPECIFICATION C% Mn % P % Si% Cr% Mo%
ASTM A178A 0.06-0.18 0.30-0.60 0.035 0.035 - -
Table 1 - ASME SA-178A steel (UNS K01200) Boiler Tube Composition.
Weight %
C Mn P S Si Ni Cr Mo Cu Al Ca Nb N Ti
0.07 0.47 0.01 0.00
4
0.06 0.05
4
0.01
6
0.01 0.11
9
0.02
6
0.00
1
0.00
2
0.0
08
0.003
The balance of the alloy is Fe
Common Boiler Tube Materials:
Carbon Steel Low Alloy Steel Stainless Steel Ni-Cr Alloy Steel
SA-178 A SA-209 T1 SA-213TP304H SB-407 800
SA-178 C SA-213 T2 SA-213TP310H SB-407 800H
SA-192 SA-213 T11 SA-213 TP316H SB-407 800HT
SA-210 A1 SA-213 T12 SA-213 TP321H
SA-210 C SA-213 T22 SA-213 TP347H
SA-213 T91
ASTM A213
Chemical Composition
Grad
e
C % Si % Mn % P % S % Ni % Mo % Cr % V %

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T5 0.15 max 0.50 max 0.30-0.60 0.025 max 0.025 max / 0.45-0.65 4.00-6.00 /
T9 0.15 max 0.25-1.00 0.30-0.60 0.025 max 0.025 max / 0.90-1.10 8.00-10.0 /
T11 0.05-0.15 0.50-1.00 0.30-0.60 0.025 max 0.025 max / 0.44-0.65 1.00-1.50 /
T12 0.05-0.15 0.50 max 0.30-0.61 0.025 max 0.025 max / 0.44-0.65 0.80-1.25 /
T22 0.05-0.15 0.50 max 0.30-0.60 0.025 max 0.025 max / 0.87-1.13 1.90-2.60 /
T91 0.08-0.12 0.20-0.50 0.30-0.60 0.020 max 0.010 max 0.40 max 0.85-1.05 8.00-9.50 0.18-0.25
Mechanical Properties
Grade Tensile Strength MPA Yield Strength MPA Hardness HB
T5 415 min 205 min 163 max
T9 415 min 205 min 179 max
T11 415 min 205 min 163 max
T12 415 min 220 min 163 max
T22 415 min 205 min 163 max
T91 585 min 415 min 250 max
4. Velocity:
The velocity at the top of the upstream tubes LP evaporator tubes is very high.
The calculated average velocities for Meghnaghat HRSG are:
Row 1, header 1 – 65 ft/sec
Row 2, header 1 – 53 ft/sec
Row 1, header 2– 43 ft/sec
Row 2, header 2 – 36 ft/sec
Row 3, header 2 – 29 ft/sec
Row 1, header 3 – 25 ft/sec
Row 2, header 3 – 20 ft/sec
Row 3, header 3 – 17 ft/sec
For Meghnaghat HRSG’s pressure range, 25 ft/sec is a safe maximum tube
velocity in this pressure range. The velocities will be higher at the ends of the
header where the tube sees bypass flow and absorbs more heat.

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The wear pattern in the tubes roughly follows the velocity. There is heavy
wear on many of the tubes in Header 1. There is moderate wear on the Header
2 tubes. Very few tubes in Header 3 are worn.
The complexities of two-phase flow behavior result to be random wear
pattern.
There are few practical methods to reduce LP evaporator velocity. Increasing
the production of HP steam takes heat from the LP boiler and (slightly)
reduces LP evaporator velocity. HP steam production is being maximized by
minimizing and cleaning the HP evaporator.
Velocity is a significant component of the root cause of LP evaporator FAC
and the velocity component cannot be eliminated. FAC is going to be difficult
to control chemistry must be very good if FAC is going to be reduced to an
acceptable level.
5. Circulation Ratio:
A normal design circulation ratio for IP and LP evaporators is 15:1. To
determine the circulation ratios, the complete circulation circuit of tubes,
feeders (down comers), risers and primary separators are modeled. High
circulation ratios in excess of 50:1 are known to contribute to flow
instabilities which can lead to FAC if there is not sufficient pressure loss on
the feeder side of the circuit to “meter” the downcomer water between the
tubes with high steam generation rates and the ones with low steam
generation rates.
6. High Risk Areas for FAC:
1. Cyclones and primary separator baffles in LP and IP steam drums,
2. LP and IP evaporator tube bend areas near the discharge to the riser or
steam drum and elbows in risers where the velocities are relatively high
coupled with high circulation ratios,
3. Elbows and branch connections of IP and LP evaporators
feeders(downcomers),
4. Economizer crossover lines and return bends,
5. Feed pump discharge or suction connections where the pipe size nay be
reduced.
6. Upper headers of LP panels MS-19, MS-20, and MS-21. The tops of the
headers and interior baffle.

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7. LP header feeder. The DN250 tee off the main downcomer and the 90O
elbows.
8. LP main feeder. The DN250 tee used for the 90O turn and DN250 tees to
the feeder branches.
9. LP economizer water outlet line. The DN200*DN150 tees, T3LE01A,
(where DN50 line branches to DN200 main line) are at the most risk.
10.IP economizer water inlet line. The DN75*DN50 tees, B3IE01, (where
DN50 line branches from DN75 main line).
11.RH SH attemperator spray water line near FCV. DN50*DN25 reducers
upstream and downstream of FCV.
7. Root Cause Analysis (RCA) of Boiler Tube
Failure (BTF):
From a boiler designer’s point of view the root cause of the FAC problem at
the Meghnaghat Plants is not a single item. Tube failures are the major cause
of availability loss and lost capacity in HRSGs.
The extended outages for major tubing replacement are ultimately in costly.
There are many different types of boiler tube failure mechanisms which can be
sorted into the following most predominant categories:
1. Erosion–Corrosion/Flow Accelerated (or Assisted) Corrosion (FAC) of
carbon steel tube inlet due to combination of a ---
(a) Design, Manufacturer and Date range.
(b) Velocity change due to : (i) include duct firing( provide additional
energy to produce more steam and hence increases the output of
the steam turbine, from 48 t/hr to 52 t/hr and thus provides
electrical output at lower capital cost.)
(ii) Thermal cycling operation (peak load
operation)
(iii) Part load or off- design flow etc.
© High local flow velocities or scrubbing action – Areas where the
metal surfaces are being scrubbed by liquid water (impingement
zones, elbows etc.) are susceptible.
(d) High local heat input,

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(e) High bulk flow rates,
(f) Turbulence,
(g) Low or very high PH – the rate of material loss raises rapidly as PH
drop. Very high PH also increases the corrosion rate.
(h) To use excessive concentration of ammonia & not using the non-
volatile PH control in the LP section.
(i) Lengthy start-up and shutdown procedures etc. LP riser with FAC
thickness in the FAC areas was down to 0.32-inches compared to
the original thickness of 0.52-inches. All material loses was
observed to be in the two – phase flow (water and steam) areas
of the boiler. This includes the tubes, the headers, the header
nozzles and bellypan – all of which are CS.
2. Galvanic corrosion can occur at welds due to stresses in heat –
affected zones or the use of different alloys in the welds which
contribute the contact of dissimilar metals. These dissimilar cells can
also be formed when deposits are present. Anything that results in a
difference in electrical potential at discrete surface locations can
cause a galvanic reaction. Causes include – scretches in a metal
surface, differential stresses in a metal, differences in temperature and
conductive deposits. Galvanic coupled to a different metal or alloy.
3. Frequent forced full and partial outages (rate greater than 1.5%). Have
more complicated flow patterns, lower tube hot-side temperatures and
they usually have many more start-up and cool-down cycles. They
experience faster ramp-up rates/temperature changes than a base
loaded industrial boiler. These conditions can cause severe flow and
turbulent conditions that lead to FAC.
4. FAC has often connections where either the turbulence and or the
rate of the flows are changing. Since the tube/piping size and material
properties of the tube/pipe are main factors in FAC attack, this damage
mechanism is a design-related mechanism. Piping in the low pressure
end of the HRSG is very susceptible to FAC damage. Although damage
is less at higher temperatures and pressures. These areas are not
immune. Design features such as tees, ells, and reducers are likely
locations for FAC.
5. Two-phase FAC can occur in the LP evaporator circuits which typically
operates around 60 – 70 psi (0.4 - 0.5 MPa) with a temperature about
150O
C(300O
F). Its constitutes has the highest probability for FAC under

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reducing conditions. Single phase FAC can be controlled by operating
without a reducing agent & by producing a protective oxide film.
6. Component type/materials of construction that do not resist FAC or has
poor resistance in that portion (Replace with better material). Carbon
steel is vulnerable. The combination of temperature and velocity
indicate vulnerability.
7. Stress rupture (Short term overheating, high temperature creep,
dissimilar metal welds, high local heat flux and poor circulation). The
economizer, IP and LP systems are susceptible to FAC. FAC risk on
temperature range of 93 to 204O
C(200 – 400O
F). The rate of material loss
maximizes at approximately 150O
C(300O
F).
8. Lack of quality control (damage during chemical cleaning, poor water
chemistry control, material defect, welding defects etc.).
9. Fatigue (corrosion fatigue and thermal fatigue) of carbon steel
(vibration, thermal expression).
10.Extremely low levels of oxygen are well known to exacerbate FAC. High
oxygen in effluent (due to distress of the internals insufficient steam
sparging) will also attack.
11.Air leakage/ingress (Oxygen and Carbon di oxide).
12.Water-side corrosion (Caustic corrosion/gouging, hydrogen damage,
pitting, stress corrosion, cracking).
13.Release of make-up or condensate (Fe, Cu, Organics, Process
chemicals).
14.Release of make-up or condensate polisher regenerants due to
unreliable or poorly designed valving and inadequate monitoring.
15.Units are older than 10 years.
16.Mixed metallurgy (Fe + Cu), copper alloy. Cu is corroding when exposed
to ammonia gas.
17.Lack of lay up protection / No lay up.
18.Bad make-up / Marginal steam chemistry.

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19.Insufficient commissioning of new units.
20.The deposit / Scale build-up area with the highest heat flux, which is
usually where the most severe damage occurs.
21.FAC Risk Factor,
Fr = Fw / Tnom and
Fw=Ft*Fm*Fq*Fs
Where, Fw= FAC wear factor,
Tnom=nominal metal thickness,
Ft = Temperature factor,
Fm = Material factor,
Fq = Steam quality factor and
Fs = shear force factor.
Values for the normalized wear factor that are >1 are areas to check for
FAC. For example a wear factor of 2 would indicate the possibility of
the loss of metal that is 2* good practice and would decrease the life of
that component by 50% and
22. Have followed different water chemistry guidelines at different time
supplied from different and or same experts for same metallurgy, pressure &
temperature of same HRSG.
8. Factors influencing Repeat Tube Failure:
Primary factors influencing repeat tube failures are:
1. Not following state-of-the-art operation, maintenance or engineering
practices,
2. Lack of proper boiler tube failure root cause analysis,
3. Wrong choice of corrective/preventive action,
4. Lack of definitive boiler tube failure reporting and monitoring prior to
removing a failed tube, mark and photo-document the tube (gas flow
direction, fluid flow direction, row number, elevation, boiler section etc.

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9. Boiler Tube Sampling:
The following information should be provided with the tube samples:
1. Boiler operating pressure, temperature, steaming rate, and unit MW.
2. Drawing of boiler showing the location of each tube sample.
3. Specified tube material, dimentionsions, etc.
4. Operating hours since commercial operation date or tube replacement
5. Tube failure history of the boiler
6. Boiler maintenance records ( i.e. replacements or modifications) for the
boiler section of concern
7. Boiler water chemistry ( typical chemistry and frequency, extent, and
duration of excursions)
8. Lay up procedures ( Short-term, long-term)
9. Any additional pertinent information on the unit
10.Visual inspection
11.Determination of chemical composition and morphology of deposits
12.Deposit weight density determination
13.Scale thickness measurements
14.Wall loss determination
15.Metallurgical analysis – material composition and microstructure
16.Pit dept measurements
17.Determination of failure mechanism
18.Root cause analysis
19.Recommend corrective actions
20.Determination of time for tube replacement etc.
10. Recommendation of corrective/
preventive action for Protection of Boiler
Corrosion / Failure to minimize the rate of
material loss:

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Humans have most likely been trying to understand and control corrosion for
as long as they have been using metal objects.
Corrosion cannot be eliminated. So, measures for controlling the corrosion are
effective rather than preventing. Corrosion control techniques vary according
to the type of corrosion encountered. Major methods include the following
comments and recommendations for more optimizing the protection from
corrosion:
1. Reduce/Avoid forced full and partial outage. Faster recovery and plan for
future outage.
2. Improve availability. Increase pressure. Pont reliability.
3. Extent component life by construction of new equipments. Replace with
more resistant material. Use metal alloy with 1.5 – 2.25 % chromium as it
enhance heat & corrosion resistance. Change the C.S tubes which has no
adequate corrosion resistance, because without adequate corrosion
resistance or corrosion allowance, components often fall short of extended
design life. Change material of construction that does not resist FAC &
stresses through design. Small amount of chrome profoundly increase the
resistance to FAC. 1 to 2 % chrome can reduce material losses by a factor
of 10 to 100. Cr produces more effective films that resist breakdown and
repassivate rapidly.
4. Reduce the flow velocity in the tubes of LP evaporator. Pressure should be
controlled also.
5. Adjust combustion. Control the temperature. Reduce the maximum load.
6. Balance the heat input in the economizer. Balancing the fire side
temperature.
7. Raise the DO control range to 15 – 25 ppb from the existing 5 – 15 ppb to
produce thick protective magnetite,Fe3O4 film as well as red
hematite,Fe2O3 layer. Considerable level of DO (15 – 25 ppb) should be
maintained to passivate and stabilize the protective oxide film on steel
surface as well as protect the dissolution of red Fe2O3 layer and the
thinning tendency of black Fe3O4 which leads the steel for further
corrosion.
The normally protective magnetite ( Fe3O4, black oxide) layer on steel
dissolves into a steam of flowing water (single face flow) or a water steam
mixture (two-phase flow). Both the PH at temperature and the level of
dissolved oxygen in the stream influence the stability and solubility of the
magnetic oxide layer.

18. 18 of 25
If the oxidation reduction potential is negative, a reducing environment
exists that can reduce or eliminate the magnetic protective oxide layer
that leads to FAC. As the magnetite oxide layer become thinner and less
protective the erosion rate is increased. Overtime general reduction of wall
thickness damage is caused by FAC. The damage is localized in the sense
that it typically occurs downstream of elbows, fittings, and bends within a
limit area of a pipe. FAC is thinning from the inside out; therefore, it cannot
be detected except through non-destructive testing (i.e. ultrasonic or
radiographic or visual examination).
A thinned component will typically fail due to overstress from operating
pressure excursions, or abrupt changes in conditions such as water
hammer, start-up loading, etc. Large rupture occurs suddenly rather than
providing warning of their degraded condition by first leaking.
8. Control oxygen to control deposits. Change in steam sparging to control
DO to reduce iron sludge and to form protective oxide film which covers
the metal surface from FAC. DO can increase the potential in nearly pure
water so that hematite replaces magnetite as the protective film. Provided
the film remains intact, corrosion is then even more strongly inhibited.
The terms passivation and repassivation, as they pertain to boiler water-
side steel, describe the reduction of hematite to magnetite, one means by
which a protective oxide film is created. Oxygen adversely affects the
quality of a natural magnetite film and causes the formation of non-
protective porous oxides such as hematite. In the absence of oxygen,
magnetite gradually forms as a highly adherent, tight bonded, protective
coating on boiler surfaces. Higher pressure/temperature boilers can
develop this magnetite layer directly from the reaction of the steel with
water.
2Fe2O3 (ferric oxide) + 4e-  4FeO (ferrous oxide) + O2 Reduction
FeO + Fe2O3  2Fe3O4 (ferrosoferric oxide of iron)
4FeO + O2  2Fe2O3 + 4e- Oxidation
So, 4Fe3O4 + O2  6Fe2O3 + 4e- Oxidation
9. Reduce the PH control range from 9.7 – 9.9 to 9.6 – 9.8 for CEP discharge,
9.5 – 9.7 to 9.4 – 9.6 for LPD and from 9.8 – 10.2 to 9.7 – 10.0 for LPSH as
the high concentration of ammonia to raise the moderately high PH will
increase the corrosion rate. PH maintenance and control should be done
within favorable limit for FAC. Low level or very high level increase the
corrosion rate.
Relation between Ammonia, Specific Conductivity and PH:

19. 19 of 25
Sl. No. Specific
Conductivity, μS/cm
Resultant PH from
Ammonia
NH3, ppm
1 1.0 8.6 0.07
2 2.0 8.8 0.18
3 3.0 9.0 0.30
4 5.0 9.2 0.65
5 6.0 9.3 0.80
6 7.0 9.4 1.10
7 9.0 9.5 1.70
8 11.0 9.6 2.50
9 14.0 9.7 3.70
10 15.0 9.75 4.60
11 17.0 9.8 6.50
12 23.0 10.0 9.00
10. Reduce PO4 dosing in HP & IP drums to avoid PO4 hideout (creates PH
instability with changing load) as well as reduction of sludge growth rate.
Phosphate concentration should be maintained 2 – 4 ppm for HPD and 4 – 6
ppm for IPD instead of existing practice 3 – 5 ppm for HPD and 5 – 8 ppm
for IPD. So, the PH & conductivity range should be reduced to 9.4 – 9.8 &
<40 μS/cm for HPD and 9.4 – 9.8 & <60 μS/cm for IPD respectively.
Na3PO4 + H2O   Na2HPO4 + NaOH
Na2HPO4 + H2O   NaHPO4 + NaOH
High Na3PO4 dosing will produce high caustic concentration which will
dissolve constantly the magnetite, causing a loss of base metal and
eventual failure. Excess caustic can also result in caustic
gouging/cracking and foaming with resultant carryover.
Although all-volatile treatment is recommended for HRSGs, some operators
feel more comfortable maintaining a small phosphate residual (normally 0.5
– 3.0 ppm) in their units’ high-pressure (HP) and inter mediate-pressure (IP)
drums due to by using phosphate dosing: (1) sticky and adherent scaling
components converted to ppt. /sludge and then ease to blow down, (2)
transfer of solid from boiler water to steam is prevented.
High dosages of PO4 increases the caustic concentration as well as
increase the localized areas i.e. deposition on boiler tubes & pipes. Caustic
can concentrate in localized areas, when porous deposits are present on
boiler surfaces. Water & NaOH can diffuse into the porous deposit and
trapped. Water boils and produces relatively pure steam and diffuses out of
the deposit, leaving a concentrated NaOH residue behind. This

20. 20 of 25
concentrated residue causes severe caustic “gouging” and dissolves the
protective magnetite (Fe3O4) layer and consequent failures.
Na3PO4 + H2O  Na2HPO4 + NaOH
NaOH + H2O(Water)  NaOH + H2O(Steam)
Fe3O4 + 4 NaOH  Na2FeO2 + 2NaFeO2
Where the protective magnetite film is dissolved, the parent tube metal is
exposed and is susceptible to corrosion.
3Fe + 4 H2O  Fe3O4 + 4 H2
3Fe +2 NaOH  Na2FeO2
11.Fe levels should be measured in the LP steam drum feed water and/or
condensate. The total iron range should <0.5 ppm. An increase is an
indication of Fe removal in the LP evaporator. Measure the iron in the feed
water and drum water at different times – lay-up, during transient load
swings such as start-up and during steady state operation.
The limit value guidelines of boiler chemistry from different experts,
existing practice and my proposal are given below:
Meghnaghat Power Limited, 450MW CCPP
Limit value of boiler Chemistry.
System Parameters
Limit
Value,06 (
When used
betz
Chemicals)
Limit
Value,08
(HRST
given)
Existing
practices
Proposed
limit value
CEP PH
8.5 ~ 9.5 9.3~9.7 9.7 ~ 9.9 9.6~9.8
Discharge Cond’ty <10 6~20 14~20 11~16
Iron ppm - - - <0.5
Dissolved O2
(ppb)
(on
line/sample)
5~15 5~15 5~15 15~25
HP Drum
PH
9.0 ~ 10.0 9.0 ~ 10.0 9.4 ~ 10.0 9.4 ~ 9.8
Cond’ty < 150 <40 < 40 <40
Silica ppb < 1000 <500 < 500 <500

21. 21 of 25
PO4 ppm 4 ~ 10 2~5 3 ~ 5 2~3
Iron ppm 0 - 3 0 - 3 <0.5 <0.5
IP Drum
PH
9.0 ~ 10.0 9.0 ~ 10.0 9.4 ~ 10.0 9.4 ~ 9.8
Cond’ty < 2500 <100 < 100 <60
Silica ppm < 40000 <2000 < 1000 <1000
PO4 ppm 15 ~ 30 3~15 5 ~ 8 3~5
Iron ppm 0 ~ 3 0 ~ 3 <0.5 <0.5
LP Drum
PH
8.5 ~ 9.5 9.3~9.7 9.5 ~ 9.7 9.4~9.6
Cond’ty < 20 6~15 9~14 7~11
Iron ppm - - - <0.5
HP SH
Steam
PH
8.5 ~ 9.5 9~10 9.4 ~ 10 9.4~9.7
Cond’ty < 5 10~20 5~20 7~14
Silica ppb < 20 <10 < 20 <20
IP SH
Steam
PH
8.5 ~ 9.5 9~10 9.4 ~ 10 9.4~9.7
Cond’ty < 5 10~20 5~20 7~14
Silica ppb < 20 <10 < 20 <20
LP SH
Steam
PH
8.5 ~ 9.8 9~10 9.7 ~ 10.2 9.7~10.0
Cond’ty < 20 10~25 20~30 15~23
12.Modify the feed water flow path to enable the addition of trisodium
phosphate into the LP evaporator. Due to high volatility of ammonia, it
does not remain considerably in the liquid phase and can’t elevate the PH
properly in every remote point. Moreover, high concentration of ammonia
may attack copper alloys in the system. Na3PO4 addition to the LP
evaporator section would be extremely effective in minimizing two phases
FAC. From the header metal composition and analysis report of drum’s dust
sample it seems that copper corrosion is also taking place. Phosphate are
non-volatile and will remain in the LP evaporator section for long periods of
time and can elevate the PH in liquid phase successfully by small dosing
due to high p- alkalinity. Thus both together Na3PO4 & NH3 dosing we can
stabilize the PH in two phase section as well as can reduce FAC.

22. 22 of 25
Compositions contain in the dust samples of HP, IP & LPD:
Sl. No. Items HPD IPD LPD
1 Total Fe 36% 28% 24%
2 Sand(SiO2) 18% 6.50% 7%
3 PO4 0.40% 0.50% 0.45%
4 Total Cu 1.20% 1.25% 1.05%
13.Control the CBD and confirm everyday minimum 2 – 3 hrs into both HP &
IPD to avoid carryover of SiO2, salt etc. and to avoid sludge accumulation
in the tubes.
14.Cathodic & Anodic protection by applying current to bring the potential of
the structure into or near the immunity region of the Pourbaix diagram.
Avoid galvanic effect i.e. a difference in temperature at separated sites on
the same metal surface. Because negatively charged ions produced at the
cathode, migrate to the anode of the corrosion cell. Positively charged ions
will move toward the cathode. This movement of ions can cause additional
reactions at the anode. Hydroxyl ions will combine with the ferrous cations
produced by dissolution of the metal:
Fe  Fe2+
+ 2e- Oxidation reaction
O2 + 2H2O + 4e-  4 OH- Reduction reactions.
Fe2+
- Fe3+
+ e- Oxidation reaction
Fe3+
+ e-  Fe2+
Occur under acidic, turbulent condition (acid cleaning).
Fe2+
+ 2OH-
Fe (OH) 2
4Fe (OH) 2 + O2 + 2H2O  4 Fe (OH) 3
The ferrous hydroxide produced has a very low solubility and is quickly
precipitate as a white floe at the metal-water interface. The floe is then
rapidly oxidized to ferric hydroxide. Dehydrolysis of this product leads to
the formation of the corrosion products normally seen on ferrous surfaces,
red dust and hydrated ferric oxide:
Fe (OH) 2  FeO + H2O
2Fe (OH) 3  Fe2O3 + 3H2O.Fe (OH) 3  FeOOH + H2O
FeO + Fe2O3  Fe3O4 (magnetite)
3Fe + 4H2O  Fe3O4 + 4H2
Fe3O4 + O2  Fe2O3 + Fe2+
The ferrous ions are susceptible to FAC. A reducing environment
regenerates ferrous iron ions that go into solution of the boiler water. This
weakens/remove magnetite layer. A weakened magnetite layer is more

23. 23 of 25
susceptible to flow induced disturbances. For a range up to approximately
200O
C (392O
F) the steel surface is contact with water remains active with
respect to iron dissolution. A reducing environment is a negative potential
and an oxidation environment is a positive potential. This can be
determined with oxidation-reduction potential measurement. :NH3 has a
lone pair of electrons and has tendency to share the electrons. So,
ammonia is a reducing agent and ammonia dosing should be controlled to
prevent the opposite desired effect of producing a protective oxide film to
one where erosion-corrosion of iron based material increased.
15.Use optimum operational practices by proper operator actions(such as
start-up and shut-down procedure),
16. Replace repair of corroded equipment. Fix internals. Do not patch weld.
Tube inlet inserts,
17. Process management to avoid future conversion problem etc.
18.Monitor, Polish & Automatic dump of return condensate,
19. Reliable design, maintenance, corrosion testing & monitor every year
through recording thickness measurement data. Develop a FAC inspection
program to plan every year thoroughly inspection and thickness testing
from LP section to superheater tube to establish initial “benchmark”
readings & to determine the “baseline” thickness from adjacent sections of
the same pressure part. From these two sets of readings, determine
detectable material loss rate. Use the loss rate to determine the next
inspection interval. If no loss is detected, retest the same areas in 2 – 3
years, depending on operating time and cycles.
20. A more reliable methodology to select material and evaluate corrosion
risks may be provided by software system.
21.Repair or replace the online DO analyzer to counter check the correctness
of the DO results and
22.Top variations in guidelines supplied from different experts( see attached
files):
There were top variations between the experts’ Boiler chemistry guidelines
at different time for same metallurgy of same HRSGs.
Up to April 2007, we were following GE-Betz’s guidelines which were
within corrosive ranges according to HRST. At 2006, the lower limit of PH
value was 8.5 for CEP, LPD, HPSH, IPSH & LPSH. It raised and implemented
as 9.2/9.3 at 2008 and now it go up to 9.5/9.7.

24. 24 of 25
In this period conductivity for IPD changes from <2500 μS/cm to <100
μS/cm and SiO2 for IPD changes from <40,000 to <1,000 ppm.
Although we were properly maintaining the boiler chemistry analysis by
using sophisticated instruments with high accuracy & precision following
the experts’ guidelines; the HRST guidelines started from April,2007 were
also corrosive for C.S metal as per their further change on February,2010
( increase the PH & conductivity range of LP section) which also cannot
decrease the material loss but in some cases increases failure rate.
11. Recommendation for future testing:
(a) The first expert was GE-Betz. The second party was HRST. The
second party had changed all chemicals and guidelines of 1st
party and has given new chemical and guidelines which we are
following. But cannot reduce the corrosion rate. So, we should be
counter checked to compare the chemicals and guidelines of the
above two technical parties and necessary to plan future field
testing for FAC damage.
(b) Use the material loss rate to determine the next inspection
interval. If no loss is detected, retest the same areas in 2 -3
years, depending on operating time and cycles.
12. Conclusions:
(a) The current chemical control scheme as directed by HRST is not
producing the best results for FAC control.
(b) HRST’s modification of the chemistry control program/treatment
program could not resist the boiler tube failures; moreover the
rate of material loss increases significantly.
(c) Superior treatment to the existing program should be
developed/provided/promoted by the third party which will
significantly low the rate off material loss as well as minimize
the FAC damage.

25. 25 of 25
Reported by: Md. Abdul Hannan
Plant Chemist, MPL.
Sign --------------------
Date: February 19, 2012.