E2. Boiler Tube Failure Part 2

(1)

#6 Hydrogen Damage

 One of most disturbing tube failure mechanisms in HRSG and conventional boiler

 Caused by the reaction of the iron carbide (FeC) in the tube microstructure with hydrogen – from under deposit

corrosion process- which produces methane (CH₄) at the grain boundaries of tube steel

(2)

#6 Hydrogen Damages: Features

 Thick Edged

 Brittle final fracture

 Often “window” opening

 Multi layered deposits

 Major: magnetite

 Microstructural decarburization

Source: B. Dooley,

PPChem101-Boiler and HRSG Tube Failure: Hydrogen Damage, PP Chem 2010 , 12(2)

(3)

#6 Hydrogen Damages: Features

(4)

#6 Hydrogen Damages: Features

(5)

#6 Hydrogen Damages: Mechanisms

1. Excessive Deposition

2. Acidic Contamination

(6)

#6 Hydrogen Damages: Location

 HP & IP Evaporator

 Water flow is disrupted

 Welded join

 Internal deposition

 Thermal hydraulic flow disruption

- Local steam blanketing

(7)

#6 Hydrogen Damages

Root Causes & Action to Confirm

 Excessive deposits

 High iron in BFW and evaporator – increasing potential for concentration mechanism

- Condenser tube leaks where Cl and SO₄ enter the boiler  Selective tube sampling

 Flow disruption

 Selective tube sampling

 Gas side issue

 Tube heat flux & temperature measurement

(8)

#6 Hydrogen Damages

 Minor condenser leaks – over an extended period

 High cation conductivity

 High chloride and / or sulfates

 Major condenser leaks – one serious event

 pH depression in Boiler

 Water treatment plant upset

 High cation conductivity

(9)

H

₂

Damages, Caustic Gouging & Acid PO

₄

Corrosion

Characteristic H₂ Damage Caustic Gouging Acid Phosphate Corrosion

Features of Failure • Gouged. thick deposit • Thick edged  window opening • Gouged, thick deposit • Ductile, thin edged, pin hole

• Gouged, thick deposit

• Ductile, thin edged, pin hole

Deposit • Metal oxide • Rich in caustic

• feroate , Na-feroite

• Acid PO4

• 2-3 distinct layer • Maricite

Cycle Chemistry Source of low pH

exist

Source of high pH exist

DSP, MSP, or Na:PO₄<3.0

Attack Rate Very rapid10

mm/year

Rapid up to 2 mm/year

(10)

#7 Oxygen Pitting

 Localized dissolution of metal.

 Relatively small amount of metal loss that initiate failure with catastrophic results

 Type of pitting in Boiler

 Oxygen pitting

 Pitting caused by improper chemical cleaning  Pitting caused by carry over of sodium sulfate

(11)

#7 Oxygen Pitting: Features

 Pit shape: broad, rounded

 Pit distribution can be numerous or random

 Corrosion product and deposit are present – primarily Fe₂O₃

(12)

# 7 Oxygen Pitting: Features

(13)

#7 Oxygen Pitting: Mechanisms

1. Moisture

2. Oxygen

(14)

#7 Oxygen Pitting: Location

 Prevalent in economizer

 Any wet surface, especially no-drainable

horizontal surfaces

 Poor lay-up procedures

 Can be found in Superheater and reheater

(15)

#7 Oxygen Pitting

 Stagnant, oxygenated water with no protective environment due to improper layup

 Review the procedure  Selective tube sampling  Corrosion product analysis

(16)

Case History

Industry: Chemical process Location: Economizer

Orientation: Horizontal Pressure: 41 bar

Tube metallurgy: Carbon steel

Treatment Program: Polymer & O2 Scav Time in Service: 7 years

The reddish color & the presence of turbecles capping iron oxide-filled pits is typical of exposure of steel to water containing excessively high level of dissolved oxygen, Pitting & perforation of

economizer tubes was a recurrent problem at this plant. Failures were occurring every 3 or 4 months. Excursions to high levels of oxygen was suspected but could not be documented. The boiler was

operated continuously.

Source: R.Port, The Nalco Guide to Boiler Failure Analysis, Mc Graw Hill, Inc., 1991

(17)

#8 Stress Corrosion Cracking

 Metal failure resulting from a synergistic interaction of a tensile stress and a specific corrodent to which the metal is sensitive

(18)

#8 Stress Corrosion Cracking: Features

 Thick-edged, brittle failure

 May often involve the blow out of small “window-type”

pieces

 Little or no loss of wall thickness

 Cracks

 Can initiate either inside or outside surfaces

 Can be oriented circumferentially or longitudinally  May have significant branching

(19)

#8 Stress Corrosion Cracking - Features

(20)

#8 Stress Corrosion Cracking: Mechanisms

Can occur if 2 (two) conditions exist:

 The existence of a critical system of “material and corrosive

medium” i.e., a specific corrosive medium must be present for a given material

 The presence of tensile stress

 Static tensile stress

 Tensile stresses which increase over time

(21)

#8 Stress Corrosion Cracking: Mechanisms

(22)

(23)

Stress Corrosion Cracking:

Material & Corrodents

 Austenitic Stainless Steel (300 series)

 Chlorides  Sodium hydroxide  Hydrogen sulfide  Carbon Steel  Sodium hydroxide  Copper-based Alloys  Ammonia

(24)

#8 Stress Corrosion Cracking: Location

 Potential for the highest concentration of contaminants

 Condensate can form during shutdown

 High stress locations

 Bends, welds, tube attachment, supports, near weld, spacers; etc  Especially where a change in thickness occur

(25)

#8 Stress Corrosion Cracking

Root Causes & Action to Confirm  Environmental Effects

 Chloride: Condenser in-leakage & chemical cleaning  Caustic: Carry over

 Stress Effects

 Residual stresses: fabrication/welding/heat treatment/bend  Service stresses: especially at attachment & supports

(26)

Case History

Industry: Petrochemical

Location: Superheater, first stage Orientation: Vertical

Pressure: 41 bar

Tube metallurgy: 304 stainless steel Treatment Program: Phosphate Time in Service: 3 weeks

The original tubes were CS that cracked after 9 months of service. SS tubes were specified to replace CS. Moderate bends were put to relieve the thermal expansion and contraction stress that had caused cracking in the CS tubes.

SS failed because caustic stress corrosion

cracking (lacked adequate devices for separation and load swings- carry over of ) boiler water. In addition , the bends provided high residual stress (no stress-reilef-annealed apply on the bend)

(27)

#9 Short Term Overheating

 Occur when the tube metal temperatures are well above the design temperature for the tubing

 In SH/RH tubing occur when the normal flow of cooling steam is blocked or partially blocked

 Excessive temperatures and subsequent tube failures can occur in very short period of time

(28)

#9 Short Term Overheating: Features

 Thin-edged, ductile final failures

 Longitudinal “fish mouth” or rupture  Tube bulging – is often

 Scale not necessarily thick or can be absent  Localized hardening near the rupture

(29)

#9 Short Term Overheating - Features

(30)

#9 Short Term Overheating - Features

(31)

#9 Short Term Overheating: Mechanisms

(32)

#9 Short Term Overheating: Mechanisms

(33)

#9 Short Term Overheating: Location

 Can occur in steam-cooled tubing (SH/RH) or the hotter

sections of the water cooled tubing (evaporator)

 Susceptible locations:

 Tubing nearest to the gas inlet, especially down stream of supplemental burner (most common leading row SH)

(34)

#9 Short Term Overheating

Root Causes & Action to Confirm  Excessive gas temperature

 Visual examination of flame pattern

 Operating condition (gas temperature measurement; etc)  Metallurgical analysis

 Tube blockage

 Oxide from exfoliation tube material, chemical cleaning and /or improper repair

 Videoscope & metallurgical analysis to confirm

 Start up with condensate filled tubes

 Thermocouple measurement  Review start up procedure

(35)

Case History

Industry: Utility

Location: Water wall, nose arch Orientation: Slanted

Pressure: 124 bar Material: Carbon steel

Treatment Program: Coordinated Phosphate Time in Service: 5 years

Rupture occurred shortly after start-up.

Microstructural evidence indicated that the tube metal near the rupture exceed 870 0_{C. No}

significant thermally formed oxide was found anywhere on the received section.

The burst was caused by insufficient coolant flow on start-up.

(36)

#10 Long Term Overheating

 Occur when metal temperature exceed design limits for days, weeks, months or longer

 Because steel loses much strength at elevated

temperature, rupture caused by normal internal pressure becomes more likely as temperature rise

(37)

#10 Long Overheating: Features

 Thick-edged, brittle final failure

 Bulging and plastic deformation

 Scale

 Internal: Extensive, multilaminated & exfoliating

 External: Thick, laminated & often longitudinally cracked

 May have “wastage flats”

 Extensive sign of tube material degradation

(38)

#10 Long Term Overheating - Features

(39)

#10 Long Term Overheating - Features

(40)

#10 Long Term Overheating: Mechanisms

 Thermal Oxidation (metal burning)

 Excessive if temperatures > certain value for each alloy

 Cause crack and exfoliated patches

 Cyclic thermal oxidation & spalling resulting wall thinning

 Process can continue until the entire wall is converted to oxide,

creating a hole

 Creep Rupture

 Plastic deformation during overheating

(41)

#10 Long Term Overheating : Mechanisms

(42)

#10 Long Term Overheating: Location

 Near the material changes – just before the change to a

higher grade of material

 Tubing nearest to the flue gas inlet, especially for supplementary-fired units

(43)

#10 Long Term Overheating

Root Causes & Action to Confirm  Excessive gas temperature

 Visual examination of flame pattern

 Operating condition (gas temperature measurement; etc)  Metallurgical analysis

 Tube blockage

 Oxide from exfoliation tube material, chemical cleaning and /or improper repair

 Videoscope & metallurgical analysis to confirm

 Start up with condensate filled tubes

 Thermocouple measurement

(44)

Case History

Industry: Power Plant

Location: Primary SH Inlet Pressure: 83 bar

Orientation: Horizontal

Treatment Program: Phosphate Time in Service: 20 years

Creep rupture caused by prolong overheating at temperature above 570 0C. Coolant flow

irregularities immediately downstream of a partially circumferential weld, along with internal deposition, which reduced heat transfer were contributing

factors. Additionally, a switch from oil to coal firing likely changed fire-side heat input.

The superheater had a history of boiler –water carryover and load swing were common.

(45)

Short Term vs Long Term Overheating

(46)

#11 Exfoliation: Location

 Superheater and Reheater Tubes

 Results of long term overheating of tubes

(47)

#11 Exfoliation: Results

 Exfoliated particles will collect in bends and can cause

blockage of tubes

 Excessive exfoliation can result in particulate erosion of

turbine components, especially the nozzle block

 May result in impacting the following:

(48)

(49)

Determine the Extend of Damage

Failure Mechanisms Recommended Test

Corrosion Fatigue Ultrasonic Testing UT)

Selective Tube Sampling

Thermal/Mechanical Fatigue Fluorescence magnetic partcle

examination (WFMT) or Fluorescence penetrant (WFPT)

Thermal stress analysis

Deposit Selective tube sampling

Deposit Weight Density (DWD)

FAC Ultrasonic Testing (UT)

H₂ Damage, Caustic & Acid Phosphate Corrosion

Ultrasonic Testing (UT) Selective Tube Sampling Boroscope

(50)

Determine the Extend of Damage

Failure Mechanisms Recommended Test

Stress Corrosion Cracking Fluorescence magnetic particle

examination (WFMT) or Fluorescence penetrant (WFPT)

Thermal stress analysis Short & long term overheating Radiography

Tube removal

Tube diameter measurement (wall thickness)

(51)

Nalco SEA

(52)

(53)

Case #1: Plant Data

 Combined Cycle Power Plant, 110 MW – Thailand

 HRSG, Multiple Pressure (HP:62 bar, LP: 5 bar), Capacity:

67 tons/hr (HP), 11 tons/hr (LP)

 Condensing steam turbine

 Surface condenser with admiralty tubes and Cu:Ni=90:10

for air removal section

 Boiler make-up: demineralized water from mixed bed  Condensate polisher: no

(54)

Two HRSG –HP

Evaporator - tube failure in

1 week!

(55)

 November 2010 : Condenser in-leakage has identified and confirmed

 May 23-25, 2011 : Major ingress due to condenser

in-leakage become bigger

 May 28-29, 2011 : Plant shutdown. Plugged leak tubes

in condenser. Drum inspection

 May 30, 2011 : Plant is running back

 Sept 8 – 22, 2011 : Major schedule shutdown. Drum

inspection

 Sept 18, 2011 : Tube failure of HP evaporator section.

 Sept 22-23, 2011 : Unscheduled plant shutdown due to

HRSG tube failure.of HP Evap

 Sept 25, 2011 : Plant is running back

(56)

Elements/ Compounds Steam Drum – May ‘11 Steam Drum – Sept ‘11 HP Evap-Sept’11 (Sample #1) HP Evap-Sept’11 (Sample #2) Iron (Fe2O3) 33 wt% 22 wt% 50 wt% 90 wt% Copper (CuO) 12 wt% 8 wt% 15 wt% - Phosporus (P2O5) 23 wt% 32 wt% 14 wt% 3 wt% Calcium (CaO) 15 wt% 26 wt% 8 wt% 2 wt% Magnesium (MgO) 8 wt% 6 wt% 5 wt% 1 wt% Sulfur (SO3) 2wt% - 2 wt% - Silicon (SiO2) 4 wt% 1 wt% 1 wt% - Zinc (Zn) 1 wt% 1 wt% 1 wt% - Carbonate (CO2) <1 wt% <1 wt% <1 wt% <1 wt% Manganese (Mn) 1 wt% 1 wt% Sodium (Na2O) 1 wt% 1 wt% Loss at 925 0C 2 wt% 1 wt% 1 wt% -

Major compounds Magnetite-Fe3O4 Magnetite-Fe3O4 Magnetite-Fe3O4 Magnetite-Fe3O4 Minor compounds Magnesium Iron

Oxide (MgFe2O4)

Ca Phosphate-Ca3PO4

Hematite-Fe2O3 Iron Oxide - FeO Hematite-Fe2O3

(57)

Screen Analysis –Fracture/Appearance

Excessive/ thick deposit Metal loss under deposit Rectangular “Window” No tube bulging Thick edge

(58)

under deposit

Rectangular “Window” Thick edge

(59)

Major Root Cause Influences Confirmation Remarks

Influence of excessive deposits Yes.  Deposit in steam drum (boiler inspection May and September 2011)

 Heavy deposition in sampling tube (September 2011)

Flow disruption: deposits, DNB, bend/sharp changes in tube direction, locally high heat transfer; etc

Yes Flow disruption only influenced by deposition

Influence of acidic contamination Yes. pH of boiler dropped to ~8.5 on May 2011 Condenser leaks – minor but occurring over

an extend period

Yes. Condenser leaks occurred November 2010 – May 2011

Condenser leaks – major ingress, generally one serious event

Yes. May 2011

 pH of boiler dropped to ~8.5

 Hardness in condensate went up >0.5 ppm

 Chloride concentration in HP evaporator went up > 10 ppm

Water treatment plant up set leading to low pH condition

No.

Errors in chemical cleaning process No. No chemical cleaning conducted on 2010-2011.

(60)

 Condenser in-leakage

 Increase chloride and sulfate level in BFW and boiler water  Introduce hardness salts into BFW

 Introduce O2 into condensate and BFW

 Deposition

 Hardness

 Iron

 Copper

(61)

 Ultrasonic test – not applicable for finned tube  Visual inspection by using fiber optic (boroscope/

videoscope) - not applicable

 Selective tube sampling ?

(62)

 Isolate the condenser and plug all the leaking tubes and tubes with high depth wastage. Ensure there is no cooling water in-leakage by checking condensate quality (cation conductivity, hardness, chloride; etc)

 Selective tube sampling for deposit measurement. Inspection using fibre optic (boroscope) can provide useful information

 Tube replacement for all tubing with hydrogen damage and/or significant wall loss be replaced

(63)

 Chemical cleaning

 Proper chemical cleaning method/procedure.

 Pressure test 1.5x than normal operating pressure  Replace all tube failed in pressure test

 Improving integrity of surface condenser

 Install on-line instrumentation to improve condenser leakage detection capability & control

 Develop specific cycle chemistry targets, action levels and shutdown policies to maintain HRSG cleanliness.

(64)

(65)

Case #2: Plant Data

 Cogeneration Plant (Coal Fired) for Paper Mill  3x35 MW + 1x65 MW – Indonesia

 Boiler #6, 300 tons/hr, 100 bar

 Condensing steam turbine

 Surface condenser with admiralty tubes

 Boiler make-up: demineralized water from mixed bed  Condensate polisher: yes, for process condensate

(66)

 July 2011 : Change boiler chemical treatment

program

 July – December 2011 :Total iron in BFW > 10 ppb  15th December 2011 : Low pH Boiler water (~ 5.7)

 18th_{December 2011 : 1}st_{boiler tube failure (water wall)}

(67)

Screen Analysis: Location

Location of BTF: • Water Wall

• Radiant heat transfer in front of buner

(68)

(69)

(70)

(71)

(72)

Metallurgical Analysis Result

(73)

Major Root Cause Influences Confirmation Remarks

Influence of excessive deposits Yes.  Deposit in steam drum (Boiler inspection)

 Deposition in sampling tube

 High iron in BFW (>10 ppb) Flow disruption: deposits, DNB, bend/sharp

changes in tube direction, locally high heat transfer; etc

Yes Flow disruption only influenced by deposition

Influence of acidic contamination Yes. pH of Boiler dropped to <8.0 after start up in December 2011

Condenser leaks – minor but occurring over an extend period

? Need to confirm by conducting condensate analysis by IC

Condenser leaks – major ingress, generally one serious event

No

Water treatment plant up set leading to low pH condition

Yes Contamination from pretreatment (possibly organic acids

(74)

 Selective tube sampling

 Chemical cleaning followed by boiler pressure test (1.5x than normal operation pressure)

(75)

 Conducting proper chemical cleaning

 1,8 tons of iron has removed from the boiler during cleaning  DWD test after cleaning = clean

 Followed by boiler pressure test (1.5x than normal)

 Some tubes were failed during pressure test

(76)

 Minimize deposit build up on boiler tubes by ensuring

minimum corrosion product formation in BFW and transport into the boiler

 Total Iron < 10 ppb (ASME), EPRI < 2 ppb

 Total copper < 10 ppb (ASME), EPRI < 2 ppb

 Use adequate chemistry related instrumentation and

installation

 Preventing acidic contamination into the boiler system  Preventing upset of the water treatment plant

- UF-RO-Ion Exchange for all boilers to minimize TOC intrusion

(77)