Paper 3 Acid Dew Point Corrosion in HRSGs

A Maharatna Company

Cases of Acid Acid Dew Point and Flow Accelerated Corrosion in HRSGs and their Remedial Measures

ASHWINI K. SINHA AGM (NETRA) [email protected] [email protected] 1

NTPC LIMITED. E 3, Ecotech II, Udyog Vihar, Greater Noida 201308 (UP)

14th Feb. 2012

A Maharatna Company

Overview

1. Cold End (Acid Dew Point) Corrosion of HRSGs

2. Flow Accelerated Accelerated Corrosion of HRSGs

A Maharatna Company

Overview


2. Flow Accelerated Accelerated Corrosion of HRSGs

NETRA: Focus Areas A Maharatna Company

Rankin Corresponding NH 3/H2O Absorption Cycle 3

e r u t a r e p m e T

2

7 1 8

5 6

Higher Work Than Rankin Cycle

4

Efficiency & Availability Improvement and Cost Reduction: Waste Heat Recovery, Recovery, VFD Retrofit, Health Assessment, ANN Modeling, CFD analysis, CHEM Analyzer, Analyzer, MALAE Cycle, Combustion Optimization, etc

Entropy

Renewable and Alternate Energy: Solar Thermal Platform, Solar PV, 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 3 Monitoring of Transformers, Failure Investigations, Corrosion Control, Boiler & Condenser Cleanings, Vibration Analysis, 3 Water & Waste Water Treatment, Robotic Devices, etc

A Maharatna Company

Corrosion Activities at NETRA

Corrosion of Turbines & Other Equipment

Health Assessment of Boiler Tubes

Failure Investigations

Acid Dew Point Corrosion of HRSGs

Cathodic Protection Chemical Development for CW System

Corrosion Analysis, Monitoring & Control Laboratory

Heat Transfer Improvement for Boilers & HE

Corrosion Monitoring & Audit

Water Management

Selection of Anticorrosive Coatings

4

Corrosion Analysis & Control A Maharatna Company

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

A Maharatna Company

Overview


2. Flow Accelerated Corrosion of HRSGs

Overview A Maharatna Company

COMBINED CYCLE GAS POWER PLANT EXHAUST GAS

L. P. Drum

DEAERATOR

H. P. Drum

FUEL (GAS / NAPTHA / HSD / NGL

Exhaust

COMBUSTION CHAMBER (SILO / CAN TYPE)

W.H.R.B.

AIR

GENERATOR FLUE GAS H.P.T.

CONDENSER.

GENERATOR

COMPRESSOR

GAS TURBINE

CONDENSATE PUMP

L.P.T.

Acid Dew Point Corrosion of HRSG A Maharatna Company

8


―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

9


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. 10

The most common cause of cold-end problems is the condensation of sulfuric acid. Sulfur in the fuel is oxidized to sulfur dioxide:


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 + sulfur dioxide

1/2 O2 oxygen

=

SO3 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 (Fe 2O3), 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 11 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


13


14


15


16


17


18


19


Loss on ignition (%) Temperature Loss on ignition

105 0C

400 0C

815 0C

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

pH

3.4

Chemical Analysis of 1% water extract of Deposit Nitrate Potassiu Cond Chloride Sulphate Sodium m µs/cm ppm ppm ppm ppm ppm 240 10 57.2 4 0.2 0.1 X-Ray Diffraction

Phases Identified

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

20


S No.

1 2 3 4 5 6 7 8 9

PARAMETER

Temperature pH Conductivity Sulphate Sodium Potassium Nitrate Water Soluble Acid Insoluble

UNIT

Deg C S

As SO42 As Na+ As K+ As NO3-

ppm ppm ppm ppm % %

SAMPLE NO. 697/C-2084 HP EVA & ECO Dust (1.0 %) extract 25 2.86 2297 1040 2.9 0.3 17.2 12.00 14.3

SAMPLE NO. 697/C-2085 CPH Area Dust (1.0 %) extract 25 2.73 3137 2400 4.2 2.3 22.5 31.6 13.2

Chemical analysis of Deposit Extract Sample No.

Description

C- 2084

HP EVA & ECO Area Dust CPH Area Dust

C- 2085

Fe (%) as Fe2O3 54.2

Na (%) as

Si (%) as

Cu (%) as

Na2O 0.9

SiO2 7.6

CuO 0.1 21

40.0

0.5

7.7

0.1


S. No. 1.

Sample No. C- 2084

2.

C- 2085

Description HP EVA & ECO Area Dust CPH Area Dust

Phase identified Fe2O3, Fe+3(OH)SO4.2H2O, FeO(OH) Fe2O3, Fe2S2O9.5H2O

X-Ray Diffraction analysis of Deposit

Sample

Fluoride (ppm)

Chloride (ppm)

Nitrate (ppm)

Bromide Phosphate Sulphate (ppm) (ppm) (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

22


Sl No 1

Data Required by NETRA Flue gas composition of each HRSG at inlet to CPH, outlet to CPH and Stack.

2

Surface area of CPH structures/inside walls & stack (steel chimney)

3

Mass flow rate of flue gas/velocity profile in each HRSG Any repairs carried out at the flue gas ducts/stack? Any other information relevant to this.

4 5

Data given by Site 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 % Stack ID= 6m. Height = 70 m . The surface area is approx: 1320 Sqm. Area of MS duct & structures in CPH area approx.: 350 Sqm Aprox. 380 Kg/s No data available on Velocity No repair has been carried out. 23

The chimney is of MS construction. Other than the area between CPH and stack the


S.No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14

Unit No. I I I I I I I I II II II II II II

Reason Planned Outage Planned Outage No demand No demand No demand No demand No demand No demand Planned Outage Planned Outage Planned Outage No demand No demand No demand

Date From 21.09.09 12.07.10 24.05.09 03.09.09 27.09.09 01.07.10 24.07.10 14.10.10 30.06.09 25.04.10 03.02.11 11.11.09 20.08.10 10.12.10

To 26.09.09 24.07.10 29.05.09 14.09.09 10.10.09 11.07.10 19.08.10 01.11.10 07.07.09 02.05.10 07.03.11 16.11.09 14.10.10 20.12.10

Outage hours 116.35 290.37 105.31 266.19 325.34 240.13 635.15 424.56 167.58 156.13 761.11 110.15 1311.45 231.14

Average Relative Humidity during the year: 79.4% (Min. 22.4%, Max. 96.9%) 24

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


Method Nitrogen

Desiccant Trays

Dehumidified Air

Advantages - Effective - No foreign Chemicals introduced

- 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

- Successful in humid climates - Clears small pockets of water within hours - Simple and effective - No foreign chemicals introduced Vapour Phase - Simple to add Corrosion - Chemicals are water soluble Inhibitor

Disadvantages - 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 - Need to handle chemicals - Damp chemical is corrosive if spilled in drum. - Air circulation through HRSG is not accomplished naturally - Requires frequent checking - Equipment intensive; requires blowers, flexible ducting - Seal must be maintained with relative humidity of < 30% re-established - Constant use of blowers - Require flush and refill - Personnel should not enter drums until after a flush, refill and startup - Handling and introduction of foreign 25 chemicals - Do not clear residual water - Difficult to confirm dispersion throughout HRSG


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. 26


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.

27

Acid Aci d Dew Point Corrosion of HRSG A Maharatna Company

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 m m Hg) and a dewpoint of 38 °C.


A: Dewpoint equation of SO 3 according to Verhoff: T d=1000/{2.276 - 0.0294ln(PH2O) - 0.0858*ln(PSO3) + 0.0062*ln(PH2O*PSO3)} B: Dewpoint equation of SO 2 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 NO 2 according to Perry: P erry: Td NO2 = 1000/(3.664 - 0.1446*ln(v%H2O/100*760) 0.1446*ln(v%H2O/100*760) - 0.0827*ln(vppmNO2/1000000*760) + 0.00756*ln(v%H2O/100*760)*ln(vppmNO2/100 0.00756*ln(v%H2O/100*760)*ln(vppmNO2/1000000*760)) 0000*760)) - 273 Pressures (P) in the equations B, C and D are given in mm Hg; in equation A in atmosphere.

30


31

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


32

D ew p o i n t s o f S O 2 a t v ar i o u s w a t e r c o n t e n t s o f t h e g a s , c a l c u l a te d f r o m t h e f o r m u l a o f K i a n g . T h e S O2 d e w p o i n t s f o r a l l g a s s e s ar e lo w e r t h a n t h e w a t e r d e w p o i n t o f


33

Dew points of HCl at various water contents of the gas, calculated from the formula of Kiang and the water vapour table.


34

D ew p o i n t s o f N O 2 a t v a r i o u s w a t e r c o n t e n t s o f t h e g a s , c al c u l a t ed f r o m t h e f o r m u l a o f P e r r y a n d t h e w a t er v a p o u r t ab l e


35


36




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 SO 2 under the present conditions of operation is around 95 37 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


Control Measures

of Novolac Vinyl Ester Glass Flake coating 1000 1200 microns DFT on Structures of CPH and Stack Liners to improve life of the structures.

 Application

–



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. 38



There is a need to revisit the lay up strategy for the HRSGs (Gas Side) so that ingress of atmospheric moisture can be prevented.


Cleaning Method Water Washing

Grit Blasting:

CO2 Blasting

Magnesium Hydroxide Washing (NETRA)

Pros

Cons

1. Low Cost 1. Water reacts with ammonia salts 2. Can be performed by plant O & M to form sulphuric acid 2. Water waste must be removed and treated 3. Water can leak into the internal insulation 1. Low Cost 1. A small portion of metal is 2. Can be performed by plant O & M removed along with the coating 2. High amount of waste has to be vacuumed 1. Cleaning process causes no tube 1. Higher Costs? or fin damage? 2. Must be subcontracted 2. No cleanup except for what was on 3. Environmentally friendly the tubes? 1. Neutralizes the acidic materials. 1. Waste water needs to be removed 2. Forms a passivating layer on the 2. Water can leak into internal boiler surfaces which gets insulation (may need to place removed after firing of boiler. polyethylene sheets on the joints 39 3. Being in a slurry form can move to prevent water ingressing into along the boiler surfaces and insulations) remove the acidic deposit


Advantage / Gain of WHRB-4 washing Date of parameters :06/09/02 Time :10:00-10:30 Parameters

Fuel GT load Frequency

WHRB-3 (Without washing) Unit MW Hz

WHRB-4 (After washing)

Gas 124.744 50.21

Gas 122.811 50.21

deg. C

123.500 471.59 102

100.300 471.59 102

deg. C

150

150

Power Gain by Washing by WHRB-4 WHRB outlet temp.(measured) GT mass flow rated Rated flue gas temp. at W HRB outlet during gas firing Rated flue gas temp. at W HRB outlet during HSD firing Power loss When CHP is bypass totally (from HBD) Loss / Gain due to CPH

deg. C

40

MW

4.725

4.725

MW

-2.11640625

0.16734375


Advantage / Gain of WHRB-4 washing Financial Gain Power saving Total Energy saving in day Total saving of Gas with 80 % loading per year Per unit cost with Gas Net saving per annume

MW KWHr KWHr Rs. Rs.

2.28375 54810 16004520

1.4 22406328 ( say Rs, 2.241crores)

Saving in Petroleum product Sp. Gas Consumptions Total Energy saving per year Total Natural Gas saving per year Cost of Gas per 1000 sm3

sm3/kwhr Kwhr sm3 Rs.

0.215 16004520 3440971.8 4307.78

Saving due to Natural Gas saving Rs. 14822949.541 (Rs. One Corer Forty Eight Lakhs Twenty Two Thousand and Nine Hundred Fifty Only)


HRSG

HRSG manhole

42


Hanger Rod

Installation of Duct Balloon 43


Deflated Duct Balloon

Blower for inflating Duct Balloon

44


45

Inflated Duct balloon inside stack


Duct Balloons for isolating the gas path from atmosphere & humidity

46


Installation of dehumidifier in HRSG

47

Corrosion Monitoring A Maharatna Company

V = I*R

Electrical resistance probe R = ρ*l/A


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.

A Maharatna Company

Water Extraction from Flue Gas

Pilot Test Heat Exchanger installed for Studies

P i l o t H ea t E x c h a n g e r I n s t a l l e d

A Maharatna Company

Quality of Water condensed from flue gas

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

Gas power Station PARAMETERS pH K TDS Salinity Sodium Potassium Total Hardness Ca Hardness p-Alkalnity m-Alkalnity Chloride Sulphate Nitrate

Unit µS/cm ppm % ppm as Na ppm as K ppm as CaCO3 ppm as CaCO3 ppm as CaCO3 ppm as Clppm as Clppm as SO42ppm as NO3-

Value 4.3 213 107 0.1 1 0.7 Nil Nil Nil Nil 1 58 6 53

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Overview


2. Flow Accelerated Corrosion of HRSGs

A Maharatna Company

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.

A Maharatna Company


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

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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

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Flow Accelerated Corrosion: F l o w - a c c e l er a t ed c o r r o s i o n ( FA C ) i s a w e l l -k n o w n d a m a g e m e c h a n i s m t h a t af f ec t s c a r b o n s t e e l c o m p o n e n t s c a r r y i n g w a t e r o r t w o - p h a s e f l o w . Caused by the mechanically-assisted chemical dissolution of the p r o t e c t i v e o x i d e an d b a s e m e t a l , i t h a s l e a d t o f a i l u r e s o r s e v e r e w a l l 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.

A Maharatna Company

Difference Erosion?

Flow Accelerated Corrosion in HRSGs between

Erosion,

FAC,

Erosion-Corrosion,

and

Cavitation

E r o s i o n - is defined as the damage resulting from water, steam, particles, or the c o m b i n a t i o n t h e r e o f o n t h e m a t er i a l at h a n d . 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. F l o w A c c e l er a t ed C o r r o s i o n ( FA C ) - EPRI defines FAC, Flow Accelerated (or Assisted) Corrosion, as “A p r o c e s s w h e r e b y t h e n o r m a l ly p r o t e c t i v e o x i d e l a y e r o n c a r b o n o r l o w - a l lo y s t e e l d i s s o l v e s i n t o a s t r ea m o f f l o w i n g w a t er o r a w a t e r -s t e a m m i x t u r e .” 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. E r o s i o n -C o r r o s i o n (E C ) - EPRI defines this as “Degradation o f m a t er i a l c a u s e d b y b o t h m e c h a n i c a l a n d c h e m i c a l p r o c e s s e s. 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

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Difference Erosion?


Erosion,

FAC,

Erosion-Corrosion,

and

Cavitation

Cavitation Erosion (CE) - Occurs downstream of a directional change or in the p r e s e n c e o f a n e d d y . 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, c a v i t a t i o n r es u l t s f r o m s m a l l b u b b l e s i n a l i q u i d s t r i k i n g a s u r f a c e . 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.

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Difference Erosion?


Erosion,

FAC,

Erosion-Corrosion,

and

Cavitation

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

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Failed HP Economizer Drain Tube

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Failed LP Economizer Tube

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Failed LP Feed Line ―T‖

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LP Feed Pipe

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Failed LP Feed Line

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Failed LP Feed Line

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Failed LP Feed Line

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Thickness reduction along the length of the pipe

Single phase FAC

Two phase FAC

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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.

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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

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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.

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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

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Typical Locations for FAC in HRSGs

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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.

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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.

•

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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)

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Effect of Temperature and Ammonia

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Effect of pH on FAC

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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.

Paper 3 Acid Dew Point Corrosion in HRSGs

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