Acid Dew Point Corrosion in HRSGs

NETRA A Maharatna Company

14th Feb. 2012

ASHWINI K. SINHA AGM (NETRA)

[email protected] [email protected]

NTPC Energy Technology Research Alliance (NETRA) NTPC LIMITED. E 3, Ecotech II, Udyog Vihar, Greater Noida 201308 (UP) FAX 0120-2350469

1

Cases of Acid Dew Point and Flow

Accelerated Corrosion in HRSGs and their

Remedial Measures

mailto:[email protected]

mailto:[email protected]


Overview

1. Cold End (Acid Dew Point)

Corrosion of HRSGs

2. Flow Accelerated Corrosion of

HRSGs


3

3

NETRA: Focus Areas

Efficiency & Availability Improvement and Cost Reduction:

Waste Heat Recovery, VFD Retrofit, Health Assessment,

ANN Modeling, CFD analysis, CHEM Analyzer, MALAE

Cycle, Combustion Optimization, etc

Rankin

Corresponding NH3/H2O Absorption Cycle

Entropy

Tem

pera

ture

2

3

Higher Work Than

Rankin Cycle

1

4

5

6

7

8

Rankin

Corresponding NH3/H2O Absorption Cycle

Entropy

Tem

pera

ture

2

3

Higher Work Than

Rankin Cycle

1

4

5

6

7

8

Renewable and Alternate Energy: Solar Thermal Platform,

Solar PV, Integrated Biodiesel Systems, Energy from

Municipality Waste, etc

Climate Change and Environment: CO2 Capture & Utilization

Technologies, Fly ash Mineralization by flue gas, Waste Water

Recycling, Emission Reduction, etc

Support to Stations (NTPC & Other Utilities): Condition

Monitoring of Transformers, Failure Investigations, Corrosion

Control, Boiler & Condenser Cleanings, Vibration Analysis,

Water & Waste Water Treatment, Robotic Devices, etc


Corrosion Activities at NETRA

Cathodic Protection

Chemical Development

for CW System

Corrosion Monitoring &

Audit

Water Management

Selection of Anticorrosive

Coatings Heat Transfer Improvement for Boilers &

HE

Acid Dew Point Corrosion of

HRSGs

Failure Investigations

Health Assessment of

Boiler Tubes

Corrosion of Turbines &

Other Equipment

Corrosion

Analysis,

Monitoring

& Control

Laboratory

4


Corrosion Analysis & Control

Objective: Preventing corrosion, scaling,

fouling in Power plant

components

1. Corrosion Assessment

2. Development of Chemical treatment for CW

3. Design of cathodic protection systems

(Condenser water boxes & underground

pipes)

4. Failure analysis (PA Fan blade, condenser

tubes)

5. Energy efficient coatings (Pumps, Ducts)

6. Control of corrosion of RCC structures

(cathodic protection of RCC structures)

7. Chemical cleaning of condensers & HRSGs

8. Corrosion audit (CW systems, Structures)

9. Development of water & waste water

treatment programs

10. Evaluation of Anti-Corrosive Coatings

Benefits: Improving Availability,

Reliability & life of

Stations


Overview


Corrosion of HRSGs


HRSGs


Overview

L. P. Drum

EXHAUST GAS

DEAERATOR

Exhaust

FUEL

(GAS / NAPTHA / HSD / NGL

COMBUSTION

CHAMBER

(SILO / CAN TYPE)

AIR

FLUE GAS

W.H.R.B.

H.P.T.

CONDENSER.

L.P.T.

GENERATOR

CONDENSATE PUMP

GENERATOR

GAS TURBINE COMPRESSOR

COMBINED CYCLE GAS POWER PLANT

H. P. Drum


8

Acid Dew Point Corrosion of HRSG


9

―Whenever tube wall surfaces in boiler air heater or

economizer fall below acid dew point temperatures of vapors

such as hydrochloric acid,nitric acid,sulfuric acid or even water

vapor,condensation of these vapors can occur on these

surfaces,leading to corrosion and tube failures.Of course,one

could use teflon coated tubes as in condensing

exchangers,but the cost may be significant. A simple solution

is to ensure that the lowest tube wall or surface temperature is

above the acid dew point‖.

Acid Dew Point:

The acid dewpoint (also acid dew point) of a flue gas (i.e., a

combustion product gas) is the temperature, at a

given pressure, at which any gaseous acid in the flue gas will

start to condense into liquid acid


http://chemengineering.wikispaces.com/flue+gas



http://chemengineering.wikispaces.com/pressure


10

Cold-end corrosion can occur on surfaces that are lower in temperature

than the dew point of the flue gas to which they are exposed.

Air heaters and economizers are particularly susceptible to corrosive attack.

Other cold-end components, such as the induced draft fan, breeching, and stack,

are less frequently problem areas. HRSGs are also susceptible to acid dew point

corrosion at the flue gas exit points. The accumulation of corrosion products often

results in a loss of boiler efficiency and, occasionally, reduced capacity due to

flow restriction caused by excessive deposits on heat transfer equipment.

Acidic particle emission, commonly termed "acid smut" or "acid fallout," is another

cold-end problem. It is caused by the production of large particulates (generally

greater than 100 mesh) that issue from the stack and, due to their relatively large

size, settle close to the stack. Usually, these particulates have a high

concentration of condensed acid; therefore, they cause corrosion if they settle on

metal surfaces.

The most common cause of cold-end problems is the condensation of sulfuric

acid. Sulfur in the fuel is oxidized to sulfur dioxide:



11

The most common cause of cold-end problems is the condensation of

sulfuric acid. Sulfur in the fuel is oxidized to sulfur dioxide:

S + O2 = SO2

Sulfur oxygen sulfur dioxide

A fraction of the sulfur dioxide, sometimes as high as 10%, is oxidized to sulfur

trioxide. Sulfur trioxide combines with water to form sulfuric acid at temperatures

at or below the dew point of the flue gas. In a boiler, most of the sulfur trioxide

reaching the cold end is formed according to the following equation:

SO2 + 1/2 O2 = SO3

sulfur dioxide oxygen sulfur trioxide

The amount of sulfur trioxide produced in any given situation is influenced by

many variables, including excess air level, concentration of sulfur dioxide,

temperature, gas residence time, and the presence of catalysts. Vanadium

pentoxide (V2O5) and ferric oxide (Fe2O3), which are commonly found on the

surfaces of oil-fired boilers, are effective catalysts for the heterogeneous

oxidation of sulfur dioxide. Catalytic effects are influenced by the amount of

surface area of catalyst exposed to the flue gas. Therefore, boiler cleanliness, a

reflection of the amount of catalyst present, affects the amount of sulfur trioxide

formed.



12


Typical Acid Dew Point Corrosion


13




14




15




16


Typical Stack Liner Corrosion


17



18



19



20


Loss on ignition (%)

Temperature 105 0C 400 0C 815 0C

Loss on

ignition 1.13 6.5 3.94

Chemical Analysis of deposit

% Fe as Fe2O3 % Ca/Mg as

CaO/MgO % Acid Insolubles

84 4.5 11.5

Chemical Analysis of 1% water extract of Deposit

pH

Cond Chloride Sulphate

Nitrate

Sodium

Potassiu

m

µs/cm ppm ppm ppm ppm ppm

3.4 240 10 57.2 4 0.2 0.1

X-Ray Diffraction

Phases Identified FeO (OH), Fe2O3 (Sample amorphous in nature)


21


S

No.

PARAMETER UNIT SAMPLE NO.

697/C-2084

HP EVA & ECO

Dust (1.0 %)

extract

SAMPLE NO.

697/C-2085

CPH Area

Dust (1.0 %)

extract

1 Temperature Deg C 25 25

2 pH 2.86 2.73

3 Conductivity S 2297 3137

4 Sulphate As SO42- ppm 1040 2400

5 Sodium As Na+ ppm 2.9 4.2

6 Potassium As K+ ppm 0.3 2.3

7 Nitrate As NO3- ppm 17.2 22.5

8 Water Soluble % 12.00 31.6

9 Acid Insoluble % 14.3 13.2

Sample

No.

Description Fe (%) as

Fe2O3

Na (%) as

Na2O

Si (%) as

SiO2

Cu (%) as

CuO

C- 2084 HP EVA &

ECO Area

Dust

54.2 0.9 7.6 0.1

C- 2085 CPH Area Dust 40.0 0.5 7.7 0.1

Chemical analysis of Deposit Extract


22


S. No. Sample No. Description Phase identified

1. C- 2084 HP EVA & ECO Area

Dust

Fe2O3, Fe+3(OH)SO4.2H2O,

FeO(OH)

2. C- 2085 CPH Area Dust Fe2O3, Fe2S2O9.5H2O

Sample Fluoride

(ppm)

Chloride

(ppm)

Nitrate

(ppm)

Bromide

(ppm)

Phosphate

(ppm)

Sulphate

(ppm)

1 Nil 3.17 7.00 Nil Nil 43.67

2 Nil 1.89 0.812 Nil Nil 2518.6

3 1.64 1.49 14.46 7.6 Nil 60.14

4 Nil 3.08 16.57 Nil Nil 1190.8

Ion Chromatographic analysis of Deposit Extract

X-Ray Diffraction analysis of Deposit


23


Sl No Data Required by NETRA Data given by Site

1 Flue gas composition of each HRSG at

inlet to CPH, outlet to CPH and Stack.

A typical composition of flue gas (dry) is

as follows and these values remain more

or less the same throughout the stack

path as long as there is no air ingress in

to the flue gas duct:

1. Oxygen content = 15.4%

2. Oxides of Nitrogen (NOx) = 95 PPM

3. CO2 = 3.0 %

4. Carbon Monoxide = BDL (< 1 PPM)

5. Oxides of = 8 - 10 PPM (Online value)

6. Temperature = 118 Deg C

7. The average sulphur = 0.010 %

2 Surface area of CPH structures/inside

walls & stack (steel chimney)

Stack ID= 6m. Height = 70 m .

The surface area is approx: 1320 Sqm.

Area of MS duct & structures in CPH area

approx.: 350 Sqm

3 Mass flow rate of flue gas/velocity profile

in each HRSG

Aprox. 380 Kg/s

No data available on Velocity

4 Any repairs carried out at the flue gas

ducts/stack?

No repair has been carried out.

5 Any other information relevant to this. The chimney is of MS construction. Other

than the area between CPH and stack the

duct internal surface is SS cladded.


24


S.No. Unit No. Reason Date Outage

hours From To

1 I Planned Outage 21.09.09 26.09.09 116.35

2 I Planned Outage 12.07.10 24.07.10 290.37

3 I No demand 24.05.09 29.05.09 105.31

4 I No demand 03.09.09 14.09.09 266.19

5 I No demand 27.09.09 10.10.09 325.34

6 I No demand 01.07.10 11.07.10 240.13

7 I No demand 24.07.10 19.08.10 635.15

8 I No demand 14.10.10 01.11.10 424.56

9 II Planned Outage 30.06.09 07.07.09 167.58



12 II No demand 11.11.09 16.11.09 110.15

13 II No demand 20.08.10 14.10.10 1311.45

14 II No demand 10.12.10 20.12.10 231.14

Average Relative Humidity during the year: 79.4% (Min. 22.4%, Max. 96.9%)

Average Temperature during the year: 27.4 oC (Min. 16.4 oC, 35.8 oC)


25


Method Advantages Disadvantages

Nitrogen - Effective

- No foreign Chemicals introduced

- Low oxygen environment may be

hazardous to personnel

- Difficult to confirm that all spaces are filled

with nitrogen (not air) unless cap is installed

as pressure decays.

- Large volume of inert gas required

- Does not remove standing water

Desiccant

Trays

- Proven traditional method

- Easy to source material (silica gel,

quick lime, activated alumina); rule of

thumb is 5 lb silica gel/100 cft of

volume

- Need to handle chemicals

- Damp chemical is corrosive if spilled in

drum.

- Air circulation through HRSG is not

accomplished naturally

- Requires frequent checking

Dehumidified

Air

- Successful in humid climates

- Clears small pockets of water within

hours

- Simple and effective

- No foreign chemicals introduced

- Equipment intensive; requires blowers,

flexible ducting

- Seal must be maintained with relative

humidity of < 30% re-established

- Constant use of blowers

Vapour Phase

Corrosion

Inhibitor

- Simple to add

- Chemicals are water soluble

- Require flush and refill

- Personnel should not enter drums until after

a flush, refill and startup

- Handling and introduction of foreign

chemicals

- Do not clear residual water

- Difficult to confirm dispersion throughout

HRSG


26


Gas-side layup

Gas-side corrosion can be problematic for HRSGs in cycling service. Layup of

the gas side historically has been given less consideration than it has for the

water side, but that may be changing.

As ambient temperature increases during the daylight hours, the cooler HRSG

components, with their considerable thermal inertia, lag behind, and moisture

condenses on metal surfaces. Condensation typically occurs when the relative

humidity is more than 35%.

Also, when HRSG internal surfaces are cooler than ambient temperature,

reverse draft through the stack occurs. Air entering through the stack exits via

the gas turbine, open gas-side manways, and other leakage points.

Dewpoint corrosion of tubes, fins, headers, and casing can cause many

problems including particulate emissions at restart, piping and hanger corrosion,

increased gas-turbine backpressure, and reduced heat transfer in the HRSG.


27


Corrosion can be minimized either by removing oxygen or moisture from

ambient air; the latter usually is easier. In either case, it is important to minimize

the amount of air that must be handled and conditioned. This requires blocking

air flow through the stack with a damper or balloon.

Options for minimizing dewpoint corrosion include adding heat (1) by injecting

sparging steam on the water side, and (2) installing portable heating coils or

radiant heaters on the gas side. Another practical option is dehumidification. In

many cases, a combination approach may be required.

Finally, some plants that clean tube panels early in an outage see residual

deposits ―growing‖ as they absorb moisture. A good strategy for a long outage

may be to inspect the HRSG during the first five days of the outage, engage

heating or dehumidification, clean as close to restart as possible, and return to

the heating or dehumidification plan if startup is delayed.


28


Relationship between corrosion rate and the moisture content of air shows the

importance of maintaining relative humidity below about 40%.


29


The water vapour pressures from the water vapour table. A gas with 6.5 v% H2O has a

vapour pressure of 49.7 mm Hg (100 v% water has a vapour pressure of 758 mm Hg) and

a dewpoint of 38 °C.


30


A: Dewpoint equation of SO3 according to Verhoff:

T d=1000/{2.276 - 0.0294ln(PH2O) - 0.0858*ln(PSO3) + 0.0062*ln(PH2O*PSO3)}

B: Dewpoint equation of SO2 according to Kiang:

Td=1000/{3.9526 - 0.1863*ln(PH2O) + 0.000867*ln(PSO2) - 0.00091*ln(PH2O*PSO2)}

C: Dewpoint equation of HCl according to Kiang:

Td=1000/{3.7368 - 0.1591*ln(PH2O) - 0.0326*ln(PHCl) + 0.00269*ln(PH2O*PHCl)}

D: Dewpoint equation of NO2 according to Perry:

Td NO2 = 1000/(3.664 - 0.1446*ln(v%H2O/100*760) - 0.0827*ln(vppmNO2/1000000*760)

+

0.00756*ln(v%H2O/100*760)*ln(vppmNO2/1000000*760)) - 273

Pressures (P) in the equations B, C and D are given in mm Hg; in equation A in

atmosphere.


31


Dew points of SO3 at various water contents of the gas, calculated from the formula

of Verhoff.


32


Dew points of SO2 at various water contents of the gas, calculated from the formula

of Kiang. The SO2 dew points for all gasses are lower than the water dew point of

the gasses.


33


Dew points of HCl at various water contents of the gas, calculated from the formula

of Kiang and the water vapour table.


34


Dew points of NO2 at various water contents of the gas, calculated from the formula

of Perry and the water vapour table


35



36



37


Condensate Pre-heater (CPH), HP Evaporator and Stack liner of HRSGs are getting

affected by Corrosion by Condensed gases (SO2, H2O, NO2).

Corrosion products consists of iron oxides, sulphate , nitrate, and acid

insolubles and the products are acidic in nature.

Naptha contains around 0.01% sulphur and at around 6.5% moisture in flue gas,

the expected acid dew point is around 95 oC.

The flue gas temperature at CPH outlet is around 125 oC (rated 120 oC). This

suggests that flue gases are above acid dew point temperature during normal operating

period. However; the exit gas temperature is higher than the rated temperature,

suggesting that there is lesser heat transfer than the design in CPH region perhaps due

to fouling of tubes.

The deposit analysis indicates presence of sufficient quantity of sulphates (ranging

from 1000 -2500 ppm on boiler tubes & 58 ppm on stack liner), nitrates are

ranging from 4 ppm on stack to 22 ppm on boiler tubes and pH of 1% solution of

the deposit in water is ranging between 2.7 to 3.4.

The acid dew point of SO2 under the present conditions of operation is around 95

oC and dew point of NO2 is around 38 oC. These conditions can occur only when

the units are shutdown and the equipment are exposed to relative humidity of >

40% and ambient temperatures leading to corrosion from condensation of flue

gases.


38


Application of Novolac Vinyl Ester Glass Flake coating 1000 – 1200 microns

DFT on Structures of CPH and Stack Liners to improve life of the

structures.

To improve the performance of the HRSGs, there is a need to remove the

deposited corrosion/flue gas condensation products from the boilers. Some

methods of cleaning are indicated further.

Proper preservation of water-side and gas-side portions of HRSG during shut

down of the unit.

Prevent ingress of humidity & rainwater into the HRSG systems. One possible

method of keeping the gas side system dry is to install duct balloons at the

entrance of HRSG from gas turbine and in the stack.

It might be worthwhile to install online corrosion monitoring system to keep a

check on the corrosion initiation, progress and control.

There is a need to revisit the lay up strategy for the HRSGs (Gas Side) so that

ingress of atmospheric moisture can be prevented.

Control Measures


39


Cleaning

Method

Pros Cons

Water

Washing

1. Low Cost

2. Can be performed by plant O & M

1. Water reacts with ammonia salts

to form sulphuric acid

2. Water waste must be removed

and treated

3. Water can leak into the internal

insulation

Grit Blasting: 1. Low Cost

2. Can be performed by plant O & M

1. A small portion of metal is

removed along with the coating

2. High amount of waste has to be

vacuumed

CO2 Blasting 1. Cleaning process causes no tube

or fin damage?

2. No cleanup except for what was on

the tubes?

1. Higher Costs?

2. Must be subcontracted

3. Environmentally friendly

Magnesium

Hydroxide

Washing

(NETRA)

1. Neutralizes the acidic materials.

2. Forms a passivating layer on the

boiler surfaces which gets

removed after firing of boiler.

3. Being in a slurry form can move

along the boiler surfaces and

remove the acidic deposit

1. Waste water needs to be removed

2. Water can leak into internal

insulation (may need to place

polyethylene sheets on the joints

to prevent water ingressing into

insulations)


40


Advantage / Gain of WHRB-4 washing

Date of parameters :06/09/02

Time :10:00-10:30

Parameters WHRB-3 WHRB-4

(Without

washing)

(After

washing)

Fuel Unit Gas Gas

GT load MW 124.744 122.811

Frequency Hz 50.21 50.21

Power Gain by Washing by WHRB-4

WHRB outlet temp.(measured) deg. C 123.500 100.300

GT mass flow rated 471.59 471.59

Rated flue gas temp. at WHRB outlet

during gas firing

deg. C 102 102

Rated flue gas temp. at WHRB outlet

during HSD firing

deg. C 150 150

Power loss When CHP is bypass totally

(from HBD)

MW 4.725 4.725

Loss / Gain due to CPH MW -2.11640625 0.16734375

Net Effect of boiler washing MW 2.28375


41


Advantage / Gain of WHRB-4 washing

Financial Gain

Power saving MW 2.28375

Total Energy saving in day KWHr 54810

Total saving of Gas with 80 % loading

per year

KWHr 16004520

Per unit cost with Gas Rs. 1.4

Net saving per annume Rs. 22406328

( say Rs, 2.241crores)

Saving in Petroleum product

Sp. Gas Consumptions sm3/kwhr 0.215

Total Energy saving per year Kwhr 16004520

Total Natural Gas saving per year sm3 3440971.8

Cost of Gas per 1000 sm3 Rs. 4307.78

Saving due to Natural Gas saving Rs. 14822949.5

(Rs. One Corer Forty Eight Lakhs Twenty Two Thousand and Nine Hundred

Fifty Only)


42


HRSG HRSG manhole


43


Hanger Rod Installation of Duct Balloon


44


Deflated Duct Balloon Blower for inflating Duct Balloon


45


Inflated Duct balloon inside stack


46


Duct Balloons for isolating the gas path from atmosphere & humidity


47


Installation of dehumidifier in HRSG


V = I*R

R = ρ*l/A

Electrical

resistance

probe

Corrosion Monitoring



Online Corrosion Monitoring of HRSGs



Electrical Resistance (ER) Monitoring

The ER technique measures the change in Ohmic resistance of a corroding metal

element exposed to the process stream. The action of corrosion on the surface of

the element produces a decrease in its cross-sectional area with a corresponding

increase in its electrical resistance. The increase in resistance can be related

directly to metal loss and the metal loss as a function of time is by definition the

corrosion rate.

Although still a time averaged technique, the response time for ER monitoring is

far shorter than that for weight loss coupons. The graph below shows typical

response times.



ER probes have all the advantages of coupons, plus:

• Direct corrosion rates can be obtained.

• Probe remains installed in-line until operational life has been exhausted.

• They respond quickly to corrosion upsets and can be used to trigger an alarm.

ER probes are available in a variety of element geometries, metallurgies and

sensitivities and can be configured for flush mounting such that pigging operations

can take place without the necessity to remove probes. The range of sensitivities

allows the operator to select the most dynamic response consistent with process

requirements.


Water Extraction from Flue Gas

Pilot Test Heat Exchanger installed for Studies


53

Pilot Heat Exchanger Installed

Coal power station

Parameters unit Value

pH - 2.55

Conductivity µS/cm 2890

Total

Hardness

ppm as

CaCO3

Nil

Cl ppm as Cl- Nil

M-alk ppm as Cl- Nil

EMA - 1500

Acidity - 450

Quality of Water condensed from flue gas

Gas power Station

PARAMETERS Unit Value

pH - 4.3

K µS/cm 213

TDS ppm 107

Salinity % 0.1

Sodium ppm as Na 1

Potassium ppm as K 0.7

Total Hardness ppm as CaCO3 Nil

Ca Hardness ppm as CaCO3 Nil

p-Alkalnity ppm as CaCO3 Nil

m-Alkalnity ppm as Cl- Nil

Chloride ppm as Cl- 1

Sulphate ppm as SO42- 58

Nitrate ppm as NO3- 6


Overview


Corrosion of HRSGs


HRSGs


Flow Accelerated Corrosion in HRSGs

Piping Rupture Caused by Flow Accelerated Corrosion

(FAC):

A piping rupture likely caused by flow accelerated corrosion

and/or cavitation-erosion occurred at Mihama-3 at 3:28pm on

August 9, 2004, killing four and injuring seven. One of the

injured men later died, bringing the total to five fatalities.

The rupture was in the condensate system, upstream of the

feedwater pumps, similar to the Surry and Loviisa locations.

The AP reports that sections of the failed line were examined

in 1996, recommended for additional inspections in 2003, and

scheduled for inspection August 14 (five days after the

rupture). This story was published Wednesday, August 11th,

2004 By James Brooke, New York Times News Service

On Monday, four days before the scheduled shutdown,

superheated steam blew a 2-foot-wide hole in the pipe, fatally

scalding four workmen and injuring five others seriously. The

steam that escaped had not been in contact with the nuclear

reactor, and no nuclear contamination has been reported.

The rupture was 560 mm in size. The pipe wall at the

rupture location had thinned from 10mm (394 mils) to

1.5mm.

http://corrosion-doctors.org/Forms-Erosion/erosion.htm





http://corrosion-doctors.org/Forms-cavitation/cavitation.htm





OSHA Safety Hazard Information Bulletin - Potential for Feed Water Pipes in Electrical

Power Generation Facilities to Rupture Causing Hazardous Release of Steam and Hot

Water (Excerpts from OSHA Bulletin – 19961031)

October 31, 1996

MEMORANDUM FOR:REGIONAL ADMINISTRATORSFROM:STEPHEN J. MALLINGER

Acting Director Directorate of Technical SupportSUBJECT:Hazard Information

Bulletin(1): Potential for Feed Water Pipes in Electrical Power Generation Facilities to Rupture

Causing Hazardous Release of Steam and Hot Water. The Directorate of Technical Support

issues Hazard Information Bulletins (HIBs) in accordance with OSHA Instruction CPL 2.65 to

provide relevant information regarding unrecognized or misunderstood health hazards,

inadequacies of materials, devices, techniques, and safety engineering controls. HIBs are

initiated based on information provided by the field staff, studies, reports, and concerns

expressed by safety and health professionals, employers, and the public. Bulletins are

developed based on a thorough evaluation of available facts in coordination with appropriate

parties

The Chicago Regional Office has brought to our attention the potential for feed water pipes in

electrical power generation facilities to rupture causing hazardous release of steam and

hot water. During an investigation of a multiple fatality accident at an electrical power

generation facility in an industrial plant, the Appleton Area Office uncovered at least three

other feed water pipe failure incidents in other power plants. In two of the three incidents,

six additional fatalities had occurred. In all cases, the feed water pipe failures were attributed to

wall thinning as a result of single-phase erosion/corrosion, leading to rupture of the pipes under

high working pressures



The rupture of feed water pipes due to wall thinning creates the potential for serious burns,

massive property damage, and power outages in electrical power generation plants. These feed

water pipe failures could not be linked to any specific aspect of system designs, materials, or

operating histories to support a conclusion that single-phase erosion/corrosion was distinctive

to these particular power plants. This suggests that these may not be isolated incidents but a

problem that may be widespread in the industry.

Several factors affect the rate of erosion/corrosion in piping. These factors include material

composition of carbon steel piping, temperature, low water pH, low dissolved oxygen content,

pipe geometry, and fluid velocity. The flow path through elbows, bends, tees, orifices, welds,

valves, and backing rings creates turbulence in flow which, with fluid velocity, has the potential

to react with the protective oxide layer of carbon steel piping, contributing to the

erosion/corrosion process.

Feed water pipes are addressed in the standard boiler inspection. Generally only a visual

inspection with the pipe insulation in place is done or required. Since this will not reveal pipe

thinning, employers may not have actual knowledge of the pipe wall thinning that could be

occurring.

To minimize the potential for personal injury or loss of life, property damage, and power

interruptions resulting from feed water pipe failure, it is recommended that employers of

electrical power generation facilities establish a flow-assisted corrosion (FAC) program:

to identify the most susceptible piping components/areas and establish a sampling protocol

consistent with engineering principles and practices;

• use appropriate nondestructive testing (usually ultrasound) to determine the extent of pipe

thinning (if any); and,

• where thinning is identified, establish a preventative maintenance program and replace piping

in accordance with ASME recommendations.



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, it has lead to failures or severe wall

thinning in:

• Main Feed water Piping

• HRSG LP & IP Evaporator Tubes

• HRSG Economizer Tube and Piping

• LP and IP Drum Internals

• Feed water Heaters

• Blowdown Lines

Frequent startups and low load operation results in substantial transients in

boiler water chemistry, therefore HRSGs in cycling operation can increase the

risk for FAC. In combined-cycle (CC) plants, thinning of pipe and damage to

system components made of carbon and low-alloy steel typically occur in the

feed water and wet-steam sections of the cycle.



Difference between Erosion, FAC, Erosion-Corrosion, and Cavitation

Erosion?

Erosion- is defined as the damage resulting from water, steam, particles, or the

combination thereof on the material at hand. It can be seen as etching, defined lines, or

the wallowing out of a certain area. Often this can be misdiagnosed as Flow Accelerated

Corrosion. Chemistry as well as velocity can be a factor.

Flow Accelerated Corrosion (FAC) - EPRI defines FAC, Flow Accelerated (or Assisted)

Corrosion, as “A process whereby the normally protective oxide layer on carbon or low-

alloy steel dissolves into a stream of flowing water or a water-steam mixture.” It can

occur in single phase and in two phase regions. EPRI has stated that the cause of FAC is

water chemistry. Two phase FAC can be differentiated between Cavitation by the evidence of

“tiger stripes” or “chevrons”. FAC has often been classified as Erosion-Corrosion. FAC is a

term originating with EPRI for a condition that the industry has previous labeled with the more

generic term Erosion-Corrosion.

Erosion-Corrosion (EC) - EPRI defines this as “Degradation of material caused by both

mechanical and chemical processes. FAC is often mislabeled as Erosion-Corrosion, even

though FAC is caused by chemical and mass transfer effects”. The term Erosion-Corrosion

includes many erosion and corrosion mechanisms while FAC is very specific. It is not incorrect

to call FAC, erosion corrosion however; FAC refers to a specific set of erosion corrosion

conditions. FAC is a term originating with EPRI for a condition that the industry has previous

labeled with the more generic term Erosion-Corrosion. Although there is industry practice in

calling FAC erosion corrosion, there are no mechanical processes associated with FAC.




Erosion?

Cavitation Erosion (CE) - Occurs downstream of a directional change or in the

presence of an eddy. Evidence can be seen by round pits and is often misdiagnosed as

FAC. Like Erosion, CE involves fluids accelerating over the surface of a material; however,

unlike erosion, the actual fluid is not doing the damage. Rather, cavitation results from

small bubbles in a liquid striking a surface. Such bubbles form when the pressure of a

fluid drops below the vapor pressure, the pressure at which a liquid becomes a gas. When

these bubbles strike the surface, they collapse, or implode. Although a single bubble

imploding does not carry much force, over time, the small damage caused by each bubble

accumulates. The repeated impact of these implosions results in the formation of pits. Also,

like erosion, the presence of chemical corrosion enhances the damage and rate of material

removal. Cavitation is not a property of the material, but a property of the system itself. The

fluid pressure is determined by the size and shape of the vessel, not the material. While a

stronger material can be highly resistant to cavitation, no metal is immune.




Erosion?

Flow-accelerated corrosion (FAC) and erosion corrosion (EC) are often used interchangeably

to describe similar material degradation processes. As a result, confusion exists regarding the

identification of FAC and the differences between FAC and EC. Both types of damage

involve destruction of a protective oxide film on the surface of a material (usually a

metal or metal alloy). The elimination or removal of the oxide film is generally referred to

as the "erosion" process. This is followed by electrochemical oxidation, or corrosive

attack of the underlying metal. Both processes involve a fluid that flows across or impinges

on a metal surface. The differences between FAC and EC involve the mechanism by which

the protective film is removed from the metal surface. In the EC process, the oxide film is

mechanically removed from a metallic substrate. This most often occurs under

conditions of two-phase flow (i.e., water droplets in steam, solid particles in water, or

steam bubbles in water). It is also possible, but less likely, for erosion to occur under single

phase flow conditions. For this to happen, the fluid velocity must increase the surface shear

stress to a level that causes the oxide film to breakdown. In addition to shear stress, there

must also be variations in the fluid velocity

In the FAC process, the protective oxide film is not mechanically removed. Rather, the

oxide is dissolved or prevented from forming, allowing corrosion of the unprotected

surface. Thus, flow-accelerated corrosion may be defined as corrosion, enhanced by mass

transfer, between a dissolving oxide film and a flowing fluid that is unsaturated in the

dissolving species.



Failed HP Economizer Drain Tube



Failed LP Economizer Tube



Failed LP Feed Line ―T‖



LP Feed Pipe



LP Feed Pipe



Failed LP Feed Line



Failed LP Feed Line



Failed LP Feed Line



Thickness reduction along the length of the pipe

Single phase FAC Two phase FAC



In combined-cycle (CC) plants,

thinning of pipe and damage to

system components made of carbon

and low-alloy steel typically occur in

the feed water and wet-steam

sections of the cycle.

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.



The FAC problem is most pronounced in carbon steels. In these materials, even small

concentrations of chromium, molybdenum, and copper can improve FAC resistance. Where

FAC problems cannot be resolved by changing water chemistry, carbon steels often are

replaced by low-alloy steels, such as P11 and P22

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.

Temperature has a pronounced effect on the FAC wear rate and when a system is

inspected, components in the 250-400F range get a priority. Flow velocity has a strong

effect, which makes wet steam systems very susceptible to FAC. Reason is that the velocity

of the steam usually is much higher than that of the water.

Water chemistry effects on FAC often are not well interpreted. The pH of feedwater and

steam droplets must be kept above a certain threshold, which depends on the pH agent

used and on temperature. For ammonia and amines, their effect diminishes with

temperature. For feedwater treatment with ammonia, a room-temperature pH above 9.5

is desirable.

Oxygen actually is good for preventing FAC. Experience indicates that 5 ppb of oxygen

in feedwater can practically stop FAC, while excessive concentration of oxygen scavengers

accelerates it. In most CC units that do not have copper-alloy tubing, oxygen concentrations

can be as high as 20 ppb without causing any problem.



Any carbon- or low-alloy-steel component or piping system at a CC plant is a

candidate for FAC. These include:

■ Single-phase systems—HRSG economizers, headers, drum liners, boiler tubes,

and feedwater pipes in drums; condensate/feedwater; auxiliary feedwater, heater,

and other drains; pump glands and recirculation lines.

■ Two-phase systems—low-pressure (l-p) turbine wet-steam extraction sections

and pipes, glands, blade rings, casing, rotors, and disks; flashing lines to the

condenser (miscellaneous drains); feedwater-heater vents, shells, and support

plates; feedwater heaters; HRSG moisture separators; condenser shell and

structure.





1. Flowing water increases material loss rate exponentially with flow velocity. Data are for

neutral 580-psig/356F water with an oxygen content of less than 5 μg/kg. Exposure time is

200 hr

2. Decreasing pH increases material wear, particularly below 9.2

3. Oxygen content above 100 μg/kg gives maximum steel protection in neutral water



Typical Locations for FAC in HRSGs



FACTORS AFFECTING FAC:

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)

Magnetite (Fe3O4) forms a protective surface layer which inhibits further

oxidation of the steel. However, magnetite is slightly soluble in demineralized,

neutral or slightly alkaline water (pH in the range of 7.0 to 9.2) and low dissolved

oxygen concentration (<20 ppb [mg/L]). When these conditions exist, a protective

magnetite layer may not form. For a carbon or low alloy steel in an aqueous system,

several critical factors are needed to establish an environment in which FAC can

occur. When each parameter is within a specific range of values, FAC is likely to

proceed; however, because of the complexity of the interactions between

parameters, the onset and rate of metal loss is difficult to predict.



Control of FAC:

An effective FAC control program should include the assessment of the propensity of

different plant systems and components to FAC, the use of available software with

water and steam chemistry corrections and periodic inspections. Monitoring of iron

concentration around the steam cycle is also useful; elevated concentrations may

indicate ongoing damage in a specific subsystem. FAC and cavitation evaluation

procedures used include the combined effects of:

• Component geometry

• Flow velocity

• Water and steam parameters

• Material composition

• Water chemistry (pH, oxygen, oxygen scavenger, CO2, organics)

• Operating experience.



Notes: EI - economizer inlet, CPD - condensate pump discharge, DAI - deaerator inlet,

D - drum unit, O - once-through unit

* - Copper alloys may be present in condenser.

+ - These ORP values are meant to be indicative of a reducing treatment where a reducing agent

is added to the feedwater, after the CPD, and oxygen levels are less than 10 ppb at the CPD.

However, ORP is a sensitive function of many variables and may under these conditions be as

high as –80 mV.

For HRSG 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.

For both fossil and HRSG plants, 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. The actual pH range depends on the cycle metallurgy. The use and application of AVT(R)

in either type of plant with all-ferrous feedwater systems can result in FAC



Effect of Temperature and Ammonia

on iron dissolution



Effect of pH on FAC



Recommendations:

1. AVT (O) water treatment should be continued with tighter control on water

chemistry parameters.

2. Turbulences should be minimized by proper design.

3. For new replacement and for new units material of construction may be

changed to P11 or P22.

4. NETRA has developed CHEMAnalyzer, implementation of the same (after

suitable modifications to meet HRSGs requirement) should be considered.

For this necessary instruments need to be procured & installed.

5. Regular inspection of susceptible components by ultrasonic (UT)

examination needs to be undertaken to prevent any catastrophic failure.


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Acid Dew Point Corrosion in HRSGs

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