116379556-EPRI-Field-Guide-for-Boiler-Tube-Failures.pdf

ELECTRIC POWER RESEARCH INSTITUTE

Field Guide: Boiler Tube Failure 1017471

Field Guide: Boiler Tube Failure 1017471

Final Report, December 2009

EPRI Project Managers B. Carson K. Coleman ELECTRIC POWER RESEARCH INSTITUTE

Product Description In conventional and combined-cycle plants, boiler tube failures (BTFs) have been the main availability problem for as long as reliable statistics have been kept for each generating source. The three volumes of the Electric Power Research Institute (EPRI) report Boiler and Heat Recovery Steam Generator Tube Failures: Theory and Practice (1012757) present an indepth discussion of the various BTF and degradation mechanisms, providing plant owners and operators with the technical basis to address tube failures and create permanent solutions. This field guide is based on the content of Boiler and Heat Recovery Steam Generator Tube Failures: Theory and Practice .

Results and Findings Tube failures emanate from poor initial design, poor operation and maintenance, harsh reside and cycle chemistry environments, and lack of management support for comprehensive reduction programs. A total of 35 tube failure mechanisms affecting conventional fossil plants are described in this field guide.

Challenges and Objectives Most BTFs have been repeat failures, indicating that the return to service of a unit has historically been more important than understanding the failure. This field guide provides guidance on identifying and addressing the mechanism and contributing causes of each tube failure to help eliminate repeat failures.

Applications, Value, and Use Tube failures occur in new and old units; in units that cycle and those that operate under baseload conditions; in supercritical, once-through, and drum units; and in units burning every sort of combustible material. The information and comprehensive approach presented will help organizations to approach and achieve world-class performance.

EPRI Perspective Worldwide, EPRI’s comprehensive BTF reduction program, integrated with the cycle chemistry improvement program, has been applied to more than 70 organizations since 1977. A similar program was initiated in 2002 to reduce heat recovery steam generator tube failures. This eld guide makes the most essential practical information learned from these two programs available to plant owners and operators in the form of a convenient pocket reference.

Approach This field guide was developed from the content of Boiler and Heat Recovery Steam Generator Tube Failures: Theory and Practice (1012757).

Keywords Contributing causes Failures Fossil plants Tubes

Acknowledgments The technical content of this field guide was obtained in its entirety from Boiler and Heat Recovery Steam Generator Tube Failures: Theory and Practice, Volume 1, Fundamentals, Volume 2, Water Touched Tubes, and Volume 3, Steam Touched Tubes (EPRI report 1012757). The technical staff at Altran Solutions worked to reorganize the data in these three volumes and present it in a compact and practical format that would be convenient for field use. Most important, this field guide would not be possible without the authors, editors, and technical contributors of EPRI report 1012757. Their names are listed as presented in the original document.

viii

Individual R. Anderson D. Aspden W. Bakker M. Ball D. Blood K. Coleman J. Drennen D. Gandy A. Howell D. Hubbard P. James R. Lynch D. O’Connor J. Parker S. Paterson K. Shields J. Stallings R. Tilley S. Walker I. Wright

Organization Competitive Power Consultant Consultant Consultant E-ON UK EPRI Drennen Engineering EPRI Xcel Energy AEP E-ON UK Detroit Edison EPRI Structural Integrity Aptech Engineering Services EPRI EPRI EPRI EPRI Oak Ridge National Laboratory

Country U.S.A. South Africa U.S.A. U.K. U.K. U.S.A. U.S.A. U.S.A. U.S.A. U.S.A. U.K. U.S.A. U.S.A. Canada U.S.A. U.S.A. U.S.A. U.S.A. U.S.A. U.S.A.

Contents 1. Introduction ...................................................................... 1 Background ...........................................................................2 Purpose ................................................................................2 Scope ................................................................................... 2 2. Fundamentals of Field Inspection .........................................3 Safety ................................................................................... 4 Tools..................................................................................... 4 Foreign Material Exclusion ...................................................... 5 Where to Look ....................................................................... 5 What to Look for .................................................................... 5 Documentation....................................................................... 6 Trending ............................................................................... 6 Just Look Around .................................................................... 6 3. Tube Failure Mechanisms ....................................................7

4. Water-Touched Tubes ..........................................................9 Screening Table for Water-Touched Boiler Tube Failures (Chapter 2).........................................................10 Corrosion Fatigue (Chapter 19) ............................................. 17 Fly Ash Erosion (Chapter 21) ................................................. 26 Hydrogen Damage (Chapter 22) ........................................... 35 Acid Phosphate Corrosion (Chapter 23).................................. 45 Caustic Gouging (Chapter 24)............................................... 54 Waterwall Fireside Corrosion (Chapter 25) ............................. 64 Thermal Fatigue in Waterwalls (Chapter 26) ...........................77 Thermal Fatigue of Economizer Header Tubes (Chapter 27) ...... 87 Thermal-Mechanical and Vibration-Induced Fatigue in Water-Touched Tubes (Chapter 28)....................................90 Thermal Fatigue Caused by Water Blowing (Chapter 29).......... 93 Flow-Accelerated Corrosion in Economizer Inlet Header Tubing (Chapter 32) ........................................................ 96 Sootblower Erosion in Water-Touched Tubes (Chapter 33) ....... 103 Short-Term Overheating in Waterwall Or Evaporator Tubing (Chapter 34) ...................................................... 105

Low Temperature Creep Cracking (Chapter 35) ..................... 109 Chemical Cleaning Damage: Waterwalls (Chapter 36) .......... 112 Pitting in Water-Touched Tubes (Chapter 37).......................... 116 Coal Particulate Erosion (Chapter 38)...................................119 Falling Slag (Chapter 40).................................................... 121 Acid Dewpoint Corrosion (Chapter 41) ................................. 124

5. Steam-Touched Tubes ............................................. 127 Screening Table for Steam-Touched Boiler Failures (Chapter 2) ..................................................................128 Longterm Overheating/Creep in SH/RH Tubes (Chapter 44) ... 134 Fireside Corrosion in SH/RH Tubes (Chapter 45) ................... 144 SH/RH Fireside Corrosion (Chapter 46) ................................153 Dissimilar Metal Weld Failures (Chapter 47) .......................... 159 Short-Term Overheating in SH/RH Tubing (Chapter 48) .......... 165 Stress Corrosion Cracking in Steam-Touched Tubes (Chapter 49) ................................................................171 Sootblower Erosion in SH/RH Tubes (Chapter 50) . ................. 176 Explosive Cleaning Damage in SH/RH (Chapter 51) .............. 178

Thermal-Mechanical and Vibration-Induced Fatigue in Steam-Touched Tubes (Chapter 52) .................................. 180 Rubbing/Fretting (Chapter 57)............................................. 184 Pitting in Steam-Touched Tubes (Chapter 58) .......................... 186 Graphitization (Chapter 59) ................................................ 188 Chemical Cleaning Damage in SH/RH Tubes (Chapter 60) ..... 191 Maintenance Damage (Chapter 61) ..................................... 193 Material and Manufacturing Flaws (Chapter 62) .................... 194 Welding Defects (Chapter 63) ............................................. 196 BTF Issues in Bubbling Bed FBCs (Chapter 64) ....................... 199 BTF Issues in Circulating Bed FBCs (Chapter 65) .................... 203 BTF Issues in Waste-To-Energy Units (Chapter 66) ................... 206

1. Introduction

Introduction

Background Relatively simple materials are designed and constructed to function effectively as boiler tubes under high temperature and high pressure conditions. The tubes are subject to potential degradation by a variety or mechanical and thermal stresses and potential environmental attack on both the fluid- and fire-/gas-side of the tube. If there are no breakdowns from the original design conditions, watertouched tubes such as water wall and economizer tubes are designed for and should have essentially infinite life. The case for steam-touched tubes such as superheater (SH)and reheater (RH) tubes is somewhat different. These tubes are affected by the inevitability of creep-limited lifetime, although lifetimes in excess of 200,000 operating hours are achievable. Unfortunately, boiler tube failures (BTFs) and cycle chemistry corrosion and deposition problems in fossil steam plants remain significant and pervasive, leading causes of availability and performance losses worldwide. This field guide provides a description of the mechanism producing the failure, identifies the contributing causes of the degradation, presents immediate actions that can be taken to remove or reduce the effect of the contributing causes, and addresses the potential ramifications or implications to other parts of the boiler unit. ELECTRIC POWER RESEARCH INSTITUTE

2

In no case should the information presented in this field guide be used to the exclusion of established and applicable codes, standards, plant procedures, and criteria. This includes the notification of responsible personnel at your plant for investigation of degradation that may be noted.

Purpose The purpose of this field guide is to provide a practical and convenient presentation of information on the degradation mechanisms producing BTFs, contributing causes of the degradation, appropriate mitigating actions to remove or reduce the effect of the contributing causes, and possible ramifications and implications of the degradation or failure on other parts of the unit.

Scope This field guide addresses water-touched and steam-touched tubes in conventional boilers. It presents information that can be used to implement the following three-step approach to reducing tube failures: • Understand the failure. • Identify the contributing causes. • Develop long-term mitigating actions or solutions.

2. Fundamentals of Field Inspection

Fundamentals of Field Inspection

Boiler tubes are normally inspected on a routine basis during scheduled maintenance outages and overhauls. Less frequently, they are scrutinized when the plant is forced to shut down due to suspected component failure or degraded performance (catastrophic failures result in a level of examination beyond the scope of this eld guide). In some cases, inspections may be constrained by schedule. You may be given a limited time window in which to complete your inspection. To make the most effective use of your time, review equipment drawings and documents, previous inspection reports, work orders, and other boiler history data prior to the inspection. In addition, there may be potential hazards to deal with, especially when working in a conned space. Pre-job briefings are useful in ensuring effective and safe inspections.

• Make others aware of your intents and whereabouts. Check in with the control room as required. • Work in teams—have a work buddy or assistant. • Follow confined space protocols for required attendants, ventilation, air quality, and egress. • Reconnoiter the area in which you will be working for physical hazards (e.g., energized equipment and shock hazards, hot equipment or structures, projecting equipment or structures that you might bump into, operating equipment, potential fall or trip locations). • Use proper climbing equipment (ladders and scaffolds) and safety harnesses.

Safety

Effective and timely inspections require proper tools. Make sure you have everything you need before starting your walkdown. The following is a list of tools and equipment to be considered: • Bright flashlight or other light source. Some inspectors combine their use with helmet-mounted lights. • Camera. LCD cameras with telephoto capabilities are ideal for this use. Note that most of your photos will require the use of a ash—make sure your batteries are charged and bring extra batteries if necessary. • Inspection mirror—telescoping handles and pivots are preferred.

Typically, tube inspections are conducted when the boiler is shutdown and cooled. However, safety is still a paramount consideration. Obey your respective plant safety rules and procedures. Remember that in the field, so much of your safety depends on awareness of your environment and common sense. Use both. Comply with the following safety rules: • Wear proper personal protective equipment (PPEs)—clothing, hard hats, gloves, safety boots, eye protection, and ltration masks or breathing equipment. Hearing protection may be necessary even though the plant is down. ELECTRIC POWER RESEARCH INSTITUTE

4

Tools

• Material sampling tools—scraper, pocket knife, screwdriver, putty knife, along with bags or containers. • Tape measure and magnetic ruler for photo scales. • Magnets for distinguishing between carbon steel and stainless steel. • Hammer. • Marking pen (e.g., Sharpies, paint pens—follow plant rules for their use on equipment). Marking pens can also be used to label sample bags or containers. • Small level and plumb bob. • Small clipboard or eld book—don’t forget your pen. • Audio recording device (e.g., digital voice recorder or microcassette recorder) optional. • Video recorder.

Foreign Material Exclusion Foreign materials left in the boilers by careless inspectors have the potential to cause more damage faster than degradation itself. Be careful not to lose equipment that could plug or otherwise damage components. Also remember that nding and extracting dropped items can be costly and time-consuming. • Bring only the tools that are necessary into the immediate inspection area. • Secure loose items. Use lanyards when necessary. • Make sure equipment caps (e.g., lens caps, battery covers) are secured. • Conduct pre- and post-inspection inventories of equipment.

Where to Look During operation, inspections are typically limited to external areas and review of operational data including temperatures, ows, and water levels. External inspections should include, among others, piping arrangements and drains, supports, boiler walls, access ports, and instrumentation lines. Inspections during a shutdown should include all areas of the boiler or HRSG including, among others, crawl spaces, penthouses, access lanes, re boxes, drums, headers, tubes, piping, supports, hangers, expansion joints, and ducting.

What to Look for In inspecting boiler or HRSG interiors for tube degradation, you should look for indicators of the following: • Plugging • Pitting • Leaks • Wastage • Cracks • Blisters and bulges • Corrosion • Overheating • Misalignment or displacement (out of position)

Fundamentals of Field Inspection

Documentation • All noteworthy degradation or indications of degradation should be quantified and mapped. Where photographic or videotape documentation is used, care should be taken to include a location reference. A tape measure or magnetic ruler should be included in the visual record for comparison to illustrate relative size. • Locations of cracks and crack tips may be noted with a marking pen in order to be more visible in the photograph. • Where small samples have been obtained for metallurgical or chemical analysis, record the locations from where the samples were obtained and make sure there is a unique corresponding identier on the sample container. Photograph the location from which the sample was obtained. • Failed headers or tube sections that have been replaced should be treated as documentation. Do not throw them away summarily! They provide the best evidence of the cause of failure or mechanism of degradation. Records should include the following: • Measurements such as size, location, and population of cracks, pits, blisters, or other indications of material degradation • Color photographs or videotape of the general condition, observed degradation indications, and specific degradation


6

• Sketches that map the location of degradation and degradation indications • Written notes that describe the general condition, observed degradation indications, and specific degradation

Trending Trending of quantitative and qualitative data is a powerful tool in predicting degradation rates and component service life. It is also very important in planning repairs, maintenance, and mitigation. Ensure that your inspection and resulting documentation revisits previously inspected areas in order to ascertain degradation rates.

Just Look Around While the emphasis of the inspections is on boiler or HRSG tube degradation, it always helps to look around for indications of other problems with the boiler. For example: • Damaged or missing baffles • Areas of flame impingement • Damaged piping penetration seals • Degraded condition of access door • Damaged or bent pipe supports and hangers • Cracked or spalling concrete support • Missing bolts, nuts, washers • Excess debris accumulation

3. Tube Failure Mechanisms

Tube Failure Mechanisms

Tube failures are produced by a number of degradation mechanisms. The occurrence of one mechanism rather than another is dependent upon a variety of factors ranging from tube material to operating conditions to time in ser vice. Understanding the degradation mechanism producing a tube failure, recognizing the contributing causes of the degradation, and implementing appropriate mitigating actions are key steps to developing an effective failure reduction program. The information provided in the following sections of the field guide is grouped by water-touched and steam-touched tubes and then organized by the degradation mechanism within each group. Each degradation mechanism section is organized as follows: • Description of the degradation mechanism supplemented with photographs and/or sketches to illustrate the mechanism • Identification of the contributing causes of the degradation • Discussion of mitigating actions that can be taken to remove or reduce the effect of the contributing causes • Identification of potential ramifications and implications on other unit components When appropriate, tables and charts are used to present the information. Chapter numbers provided at the beginning of the description of each degradation mechanism refer to the corresponding chapter in EPRI report 1012757. The user of this guide is encouraged to review the referenced chapter for additional detailed information. Various citations are made in this field guide, typically in figure captions, to a reference source. Please refer to the References section in the corresponding chapter of EPRI report 1012757 for the specifc source reference indicated in the respective citation.


8

4. Water-Touched Tubes

Water-Touched Tubes

Screening Table for Water-Touched Boiler Tube Failures (Chapter 2) The following table provides information that can be used to perf rom an initial screening of a boiler tube failure to identify a likely degradation mechanism that may have contributed to the failure. The table also includes a reference to the applicable chapter in EPRI report 1012757 for more information on the respective degradation mechanism. Table 2-1 Screening Table for Water-Touched Boiler Tube Failures

Typical Fracture Surface Appearance

Other Likely Macroscopic and Metallographic Features

Typical Locations

Possible Mechanism

Chapter in Volume 2

Thick-Edged Fracture Surface Thick-edged or large window blowout (pinhole leak or circular cracking is also possible)

Multi-array, multiple, transgranular cracks that initiate on the inside of the tube; cracks often associated with corrosion pits or other surface discontinuities.


10

• Near attachments, particularly where high restraint stresses can develop. • Near or associated with bends,particularly neutral axis. • Generally initiates on cold side of the tube, but can be fireside.

Corrosion Fatigue

19

Table 2-1 (con tinue d) Screening Table for Water-Touched Boiler Tube Failures



Thick-edged, leak or window Internal damage: gouging, wall thinning; tube blowout deposits.

Typical Locations High heat flux areas; hot side of tube; horizontal or inclined tubing; pad welds; locations with local flow disruptions such as upstream of weld, backing ring, or other discontinuities.

Possible Mechanism

Chapter in Volume 2 Volume

Hydrogen Damage

22

Thick-edged

Multiple, parallel crac ks on the outside tube Maximum heat flux locations; fireside of waterwall surface or on membrane; sharp, V-shaped tubing or membranes between tubes oxide coated cracks; wall thinning from external surface when found with fireside corrosion. Can occur on weld overlays.

Waterwall Thermal Fatigue Cracking

26

Thick-e Thi ck-edged dged,, leak leak or crack crack

First Fir st sign sign as pinh pinhole ole leak leak at at toe of of stub stub weld; weld; multiple, longitudinal, transgranular cracks; borehole cracking.

Thermal Fatigue in Economizer Inlet Headers

27

Economizer inlet header stub tubes nearest the feedwater inlet.

Water-Touched Tubes Table 2-1 (con tinue d) Screening Table for Water-Touched Boiler Tube Failures



Typical Locations

Possible Mechanism


Thick-edged

Outside su surface in initiated, in intergranular cr crac k growth with significant microfissuring aligned parallel with the main crack and significant secondary cracking; evidence of grain boundary creep cavitation and creep voids.

Predominant in tube bends, particularly at intrados on outside surface, and other locations subject to high residual, forming, or service stresses.

Low Temperature Creep Cracking

35

Thick-edged

Transgranular cr cracking, OD OD-initiated an and associated with tubing (at tube bends longitudinal or attachments - transverse) or headers (particularly at the ends).

Near attachments, particularly solid or jammed sliding attachments; at bends in tubing.

Ther Th erma mal-l-Me Mech chan anic ical al Fatig Fatigue ue

28

Thick-edged

Damage to outside tube surface - multiple, closely spaced circumferential cracks, although longitudinal cracks may also form; “crazing” pattern; no wastage.

Waterwalls cleaned with water blowers (lances or cannons).

Water Blower Thermal Fatigue

29


12




Typical Locations

Possible Mechanism


Thin-Edged Fracture Surface Thin-edged, longitudinal, “cod-“or “fish-mouth”

Polishing of tube outside surface; very localized Near side and rear walls; near economizer banks; near Fly Ash Erosion damage, wastage flats. plugged or fouled passages; where previous baffles have been installed; driven by high local velocities.

21

Thin Th in-e -edge dged, d, leak leak or spli splitt

Inte In tern rnal al dama damage: ge: gou gougi ging ng,, wall wall thin thinni ning ng;; tube tube deposits.

As for hydrogen damage.

Acid Phosphate Corrosion

23

Thin Th in-e -edge dged, d, leak leak or spli splitt

Inte In tern rnal al dama damage: ge: gou gougi ging ng,, wall wall thin thinni ning ng;; tube tube deposits.

As for hydrogen damage.

Caustic Gouging

24

Thin-edged, Thinedged, long fish-m fish-mouth outh

External Extern al wastage; wastage; proba probably bly affectin affecting g a number number of tubes; maximum wastage at crown facing flame (maybe flame impingement); damage extending in 120° arc around tube; hard deposits on tube outside surface.

Areas with locally substoichiometric environment; side and rear walls near burners; highest heat flux areas.

Fireside Corrosion (coal-fired units)

25

On units with low NOX burners and SOFAs, the corrosion is usually maximum just above the burners.

Water-Touched Tubes Table 2-1 (cont inued ) Screening Table for Water-Touched Boiler Tube Failures



Typical Locations


Thin Th in-e -edg dged ed ru rupt ptur ure e

Eros Er osio ion, n, wal alll th thin inni ning ng fr from om in insi side de;; co cont ntin inuo uous us scallop or orange peel appearance.

Thin-e Thi n-edge dged, d, fish-m fish-mout outhh

Was asta tage ge fla flats ts on tu tube be ex exte tern rnal al su surf rfac ace e at at 45° 45° Circular pattern around wall blowers. around tube from sootblower direction, little or no ash on tube surface.

Generally thin-edged

Often shows signs of tube bulging or fish-mouth appearance; real keys will be transformation products in microstructure. May also be thickedged under certain circumstances.

Highest heat flux locations above locations such as the Shor t-Term Overheating site of a tube or orifice blockage or in horizontal tubing where a downcomer steam “slug” can occur.

34

Thin-edged

External wa wall th thinning an and wa wastage, little or no surface ash; location should be key key..

Tubes near replaceable wear liners in cyclone burners; throat or quarl region of burners.

38


14

Economizer inlet header stub tubes nearest to point of feedwater inlet.

Possible Mechanism Flow Fl ow-A -Acc ccel eler erat ated ed Co Corr rros osio ionn

32

Sootblower Erosion

33

Coal Particle Erosion




Typical Locations

Possible Mechanism

Chapter in Volume 2

Thin-edged

External erosion or mechanical impact damage Sloping wall tubes and/o r ash hopper near bot tom. features.

Falling Slag Damage

40

Thin-edged

External, thinned or missing external oxide; final failure typically thin-edged, transgranular and ductile; presence of sulfur in ash deposits remaining on tube.

Acid Dewpoint Corrosion

41

Chemical Cleaning Damage or Pitting

36 or 37

Low temperature areas of economizer.

Pinhole Damage Pitting

Internal tube surface damage; distinctive aspect Locations where boiler water can stagnate during unit ratio of damage - deep relative to area; partial shutdown (pitting). or total (through-wall) dissolution of the tube wall metal may be observed.

Water-Touched Tubes Table 2-1 (con tinue d) Screening Table for Water-Touched Boiler Tube Failures



Typical Locations

Possible Mechanism

Chapter in Volume 2

Miscellaneous Damage Types Depends on underlying cause Usually obvious from type of damage and correspondence to past maintenance activity.

Maintenance Damage

Chap. 61, Volume 3

Depends on defect

Materials Flaws

Chap. 62, Volume 3

Welding Flaws

Chap. 63, Volume 3

Usually thick-edged

Care required to separate weld defects from another problem located at a weld.


16

Corrosion Fatigue (Chapter 19) Description Macro Features • Initiation from the inside (water side) of the tube • Typical development is on the cold side of the tube, but it can develop on the fire-side of the tube. • Cracks can be oriented longitudinally with respect to the tube axis, that is, normal to the predominant stress field, which in the typical case are tensile hoop stresses. • Cracks also can be circumferential or any direction that is normal to the major applied stress. • Cracks can occur along or near the neutral axis of tube bends, particularly tight hairpin bends. • Cracks are multi-array, that is, there usually will be a number of parallel cracks rather than a single crack found where there is corrosion fatigue damage. • Can be initiated from pits or other surface discontinuities such as tube extrusion marks. • Not specifically related to presence of weld defects

Figure 19-4 Thick-edged failure by corrosion fatigue (Type iii).

Source: TR-100455 V4, 1993 Micro Features • Multiple, transgranular cracks • Cracks usually wide • Cracks usually oxide lled and blunt tipped • Crack proles usually irregular • Signs of discontinuous growth, re-initiations (beach marking)

Water-Touched Tubes

Figure 19-9 Schematic showing the general features of corrosion fatigue cracks.

Source: Moles, 1980 Figure 19-31 Radiograph clearly showing the presence of corrosion fatigue cracks at a tube/lower windbox connection. ELECTRIC POWER RESEARCH INSTITUTE

18

Source: EPRI TC/Set-Aside Project on Corrosion Fatigue Report

Figure 19-10a, Figure 19-10b Cross-sections of corrosion fatigue cracks showing typical features: oxide coating of the fracture surface, corrosion within the crack, wide crack mouths and tip, a transgranular fracture path, and oxide bulges down the crack length.

Source: TR-102433, 1993

Water-Touched Tubes

Contributing Causes/Susceptible Components • Excessive stresses/strains caused by the following: – Thermal expansion/contraction under transient operating conditions – Changing boiler pressure – Subcooling in natural circulation boilers • Water wall tube strain can occur at scallop bar attachments, buckstay attachments, windbox casing attachments. • Economizer tube strain can occur at tube bends and weld heat affected zones. • Physical strain cracks protective magnetite oxide layer on ID. • Fresh base metal beneath oxide layer cracking is exposed to corrosive environment, that is, water on ID of the tube. • Poor water chemistry can increase corrosion: – Low pH – High levels of dissolved oxygen – High levels of contaminates such as chlorides and sulfur • pH variation has a more significant effect than variations in chloride or sulfur concentrations. ELECTRIC POWER RESEARCH INSTITUTE

20

Figure 19-32 Pad weld repair showing renewed corrosion fatigue crack growth

Source: TR-100455 V4, 1993

• Over aggressive or improper chemical cleaning. • Corrosion fatigue most often occurs in subcritical units, but can occur in supercritical units.

Table 19-4 Actions to Confirm and Immediate Actions and Solutions

Major Root Causes All Root Causes

Actions to Confirm

Immediate Actions and Solutions

• Use the Inuence Diagram method to screen for highly susceptible units, and locations within a unit and to highlight likely “worst” root causes.

Excessive strains/stresses Subcooling (cooling water stratification) in natural circulation boilers

• Perform NDE and selective sampling to see if cracking has initiated at suspect locations and to size cracks. • Field test with thermocouples and strain gauges to evaluate levels of strain developed during all operating regimes, including all transients. • Perform global and local nite element stress analysis using as-built configuration and field measured strains and temperatures.

• Replace damaged tubes in-kind only if a system emergency exists for the unit. • Do not pad weld corrosion fatigue leaks (pinholes).

Subcooling (cooling water stratification) in natural circulation boilers

• Review operating records. • Thermocouple top and bottom of the downcomers to monitor DT as function of shutdown time. • Strain gauge to conrm.

• Same as above.

Water-Touched Tubes Table 1 9-4 (con tinue d) Actions to Confirm and Immediate Actions and Solutions

Major Root Causes

Actions to Confirm


Environmental Factors Poor water chemistry

• Review water chemistry logs and practices, with particular emphasis on pH reductions during shutdown and early startup. • Estimate the severity of the environment using the “environmental parameter” for the Influence Diagram. • Evaluate timing of environmental contributors at various strain levels. Use NDE or selectively sample tubes to determine whether pitting or corrosion fatigue damage has begun.

• Same as above.

Overly aggressive or improper chemical cleaning

• Review chemical cleaning procedures, and correlate chemical cleaning with corrosion fatigue failures. • Perform NDE and/or selectively sample at-risk tubes.

• Same as above, plus revise chemical cleaning procedures, as required

Improper boiler shutdown and/or layup procedures

• Determine whether a comprehensive boiler shutdown procedure is used.

• Optimize shutdown, layup procedures.


22

Table 19-4 (con tinue d) Actions to Confirm and Immediate Actions and Solutions

Major Root Causes Unit operation

Actions to Confirm • Review operating records to determine operating hours and boiler transients (hot, warm, and cold start ups as well as shutdowns and forced cools). Is t he boiler regularly force cooled? • Plot failure history against unit operating conditions. • Field test with thermocouples and strain gauges and perform finite element analysis to confirm.

Immediate Actions and Solutions • Modify operating procedures to reduce thermal strains.

Water-Touched Tubes

Figure 19-34 Influence diagram for corrosion fatigue in waterwall tubes. The lines E1–E4 represent the results of the environment param eter evaluation. Line E1 is approximately equivalent to operating with EPRI guidelines or better. Decreasing water chemistry is represented by E2–E4. Conditions to the right of a particular environment line indicate a high risk for corrosion fatigue or confirm that corrosion fatigue has already occurred. Conditions to the left of a given environment line indicate a lower risk of corrosion fatigue. ELECTRIC POWER RESEARCH INSTITUTE

24

Figure 19-36 Strain gauge and thermocouple monitoring locations on a buckstay attachment detail.

Source: EPRI TC/Set-Aside Project on Corrosion Fatigue

Table 19-6 Potential Ramifications

Corrosion Fatigue Aspect

Alert for Other Cycle Components

Problems with boiler water or feedwater chemistry control.

• Potential for boiler tube damage by other mechanisms such as acid phosphate corrosion, if underlying problem is phosphate hideout, or hydrogen damage such as via condenser leakage. • Potential for carryover in steam to reheater and turbine.

Excessive or overly aggressive chemical cleans.

Potential for boiler tube damage by other mechanisms.

Inadequate or improper shutdown procedures.

Potential for boiler tube damage by other mechanisms such as pitting.

Water-Touched Tubes

Fly Ash Erosion (Chapter 21) Description • • • • • •

Usually very localized. Characterized by burnishing or polishing of affected tube surfaces facing the gas flow. Heavy black polishing is rst indication of impingement erosion. Qualitatively, light polishing removes only the paint or scale. Formation of fresh rust on tubes only a few hours after boiler washing is a distinctive feature of advanced erosion that has removed the protective scale. As erosion becomes more severe, the tubes begin to thin, flattened areas develop, and eventually the internal pressure leads to tube rupture.

Figure 21-1a, Figure 21-1b Examples of erosion da maged boiler tubing that led to wall thinning and final failures by rupture.

Source: TR-102432, 1994 ELECTRIC POWER RESEARCH INSTITUTE

26

Figure 21-3 Example of extensive damage to shields caused by fly ash erosion.

Source: J. Drennen

Water-Touched Tubes

Contributing Causes/Susceptible Components

• For a constant ash loading, increasing particulate velocity from ~18.3 m/sec (~60 ft/sec) to ~27.4 m/sec (90 ft/sec) can triple the rate of y ash erosion. • At a constant velocity, doubling the ash loading will double the erosion rate. Table 21-3 Fly Ash Composition Affects the Erosion Rate

Controllable* Factors

Constant* Factors

Fuel and fly ash composition

Temperature profile

Gas ow rate

Pressure part arrangement

Ash flux

Tube material properties

Mode of operation

Target shape

Boiler design characteristics (during design process)

Angle of impingement

* Controllable factors include those that can be changed during the design process or by operating choices; constant factors are those that are not likely to change without fundamental modifications once the boiler is built.


28

Table 21-1 Typica l Loc atio ns fo r Fl y As h Er osio n

Economizer / Superheater / Reheater Leading edges of all tubes

Roof and back wall

All pendant SH/RH surfaces, especially bottom bends at exit from furnace nose to rear pass

Rear pass RH/SH and economizer; tube bends (all rows) adjacent to back wall of rear pass

At top of rear pass

Tube rows adjacent to side walls of rear pass

Staggered tube bank configurations (economizer); sides of t ubes in accessible top rows and often of tubes in middle of the tube bank.

Staggered tube bank configurations (economizer); sides of tubes in accessible top rows and often of tubes in middle of the tube bank.

Rear pass SH/RH and economizer; tube bends (all rows) adjacent to back wall of rear pass

Near tube bank stiffeners (wrapper tubes in pendant banks; antivibration bars in horizontal banks)

Finned tubes (economizer); at base of fins

Tubes immediately after open areas in tube bank

Adjacent to sootblower runs

Water-Touched Tubes Table 21-1 (con tinue d) Typica l Loc atio ns fo r Fl y As h Er osio n

Waterwalls Top of rear wall where gases change direction to rear pass Where misalignment or ash plugging of pendant tubes occurs near waterwall. Waterwall circuits in the back pass, especially the following: (i) those forming dividing walls (ii) those that protrude into flow (iii) those that bend around openings Around wall blowers


30

Figure 21-5 Typical boiler locations where fly ash erosion can occur.


Major Root Causes

Actions to Confirm


Excessive local velocities Excessive (nonuniform) local gas flows: geometry (design) causes

• Compare locations of failure to those typical of y ash erosion. • Eliminate other root causes as primary factor.

• Change problem geometries, such as replacing staggered tube rows with in-line tubes in the economizer.

Excessive (non-uniform) local gas flows: • Maintenance causes - Distortion or misalignment of tubing rows - Misalignment or loss of gas flow guides and baffles

• Visual inspection in areas near erosion problem for obvious distortions, misalignments, etc.

• Repair, replace, align damaged components.

Excessive (nonuniform) local gas flows: • Operational causes - Operating above the continuous design rating - Operating above design excess air flow - Fan or air heater imbalance leading to nonuniform gas flows

• Apply CAVT.

• Changes in unit operation such as reducing load or lowering excess air, but economic penalties are high.

Water-Touched Tubes Table 2 1-4 (con tinue d) Actions to Confirm and Immediate Actions and Solutions

Major Root Causes

Actions to Confirm


Increased Particle Loading Increase in particle loading: fuel causes

• Evaluate ash and erosive material content of fuel from an erosivity index and/or use a coal quality impact modeling tool to assess the economic impact. Compare to design coal. • Evaluate whether changes in fuel handling or blending are evident.

Apply CAVT to determine extent of problem; design and install flow modifications (local diffusion screens and distribution screens); confirm efficacy with CAVT retest. • Fuel and fuel handling changes may be considered to reduce the amount of ash and erosive minerals. • Change to fuel with lower ash content. • Wash or blend coal. • Apply indices and/or use a coal quality impact modeling tool to assess economic impact.

Increase in erosive particle loading: sootbl ower operation or maintenance causes

• Review sootblower operating procedures and conrm that equipment is properly functioning, such as at proper temperatures.

• Institute intelligent sootblowing.


32


Major Root Causes

Actions to Confirm


Other Root Causes Palliative shields and baffles, usually punched plates or solid baffles t hat were misapplied previously

• Review history of y ash erosion, prior repairs, and relationship to current damage.

• Remove prior modications. • Apply CAVT to determine the extent of the problem; design and install flow modification (local diffusion screens and distribution screens); confirm efficacy with CAVT retest

Inappropriate material; improperly or poorly applied coating

• Review prior maintenance activities to document such palliative • Temporary pad weld, spray coating, or shielding may be used. techniques. These are not recommended for the long term as they will most likely lead to continual repairs.

Water-Touched Tubes

Potential ramifications include the possibility of redirecting the flow of air or ash to other locations, thereby causing a new problem area.

Figure 21-11 Erosion locations on a side elevation drawing, also showing subsequent application of distribution and diffusing screens.


34

Hydrogen Damage (Chapter 22) Description Macro Features • Gouged areas; thick deposits • Thick-edged, often “window opening” failure appearance • Brittle failure • Oxide growth under stress leads to thick, multilayer scale (alternating layers of porous and dense magnetite), which may be missing as a result of failure incident • Very rapid: can be >10 mm/yr (>0.39 in/yr). Failures can occur within six months. Micro Features • Intergranular microssures in base tube material linking to form cracks. • Multilaminated, non-protective oxide sometimes containing chloride at scale/metal interface. • Decarburization gradually spreads across tube wall from ID. Figure 22-1 Typical multilaminated magnetite scale and subsurface microcracking associated with hydrogen damage in a conventional waterwall.

Source: J. Hickey, ESB Ireland

Water-Touched Tubes

Figure 22-8 Hydrogen damage window opening and thick-edged failure. It occurred just downstream of a butt weld. (Flow is right to left).

Source: D.E. Hendrix

Figure 22-2 Hydrogen damaged tube showing thick-edged final fracture. Note that there was a tube bend just out of view of the photograph. ELECTRIC POWER RESEARCH INSTITUTE

36

Table 22-2 Contributing Causes/Susceptible Components

Location/Tube Condition Locations where the water/fluid flow adjacent to the tube wall is disrupted • Welded joints and welding processes (i) welded joints with backing rings (ii) poor repair welds including pad welds, canoe pieces, or window welds (iii) poor weld overlay (penetrating to the inside surface) (iv) weld overlay on relatively thin wall that, because of high heat input, results in waviness on the tube ID • Locations with existing internal deposits caused by (i) a deposition mechanism (ii) deposits left from improper chemical cleaning (iii) locally high heat flux/transfer (iv) locally high steam quality • Geometric features (i) bend around burners or openings (ii) sharp changes of direction (such as the nose of the furnace) (iii) tubes bending off lower headers and drums

Water-Touched Tubes Table 2 2-2 (con tinue d) Contributing Causes/Susceptible Components

Location/Tube Condition Locations with a high heat flux/transfer Locations where boiling first initiates Locations with thermal-hydraulic flow disruptions • Locations with local very high steam quality • Locations with horizontal or inclined tubing heated from above or below (roof tubes) Localized overheating of the tubes (fireside conditions) • Flame impingement • Burner misalignment • Operating conditions such as overring or underring, gas channeling, or inadequate circulation rates • Major change in fuel source, such as higher Btu value coal, dual ring with gas, changeover to oil, or g as ring where heat ux increases


38

Figure 22-3a, Figure 22-3b Through-wall thick-edged cracking caused by hydrogen damage. Note this thick-edged leak is downstream of the line of butt welds.

Water-Touched Tubes

Figure 22-4a, Figure 22-4b Deposits and hydrogen damage associated with backing rings in conventional water wall tubing. Flow is right to left. ELECTRIC POWER RESEARCH INSTITUTE

40


Major Root Causes

Actions to Confirm


Excessive Deposits—All Causes

• Analyze results from chemistry monitors with particular emphasis on levels of Fe and Cu in the feedwater. • Perform selective tube sampling for deposit measurement. • Check the efcacy of chemical cleaning.

• Perform internal tube assessment (typically using videoprobes). • Remove tube samples for analysis.

Flow disruption: • Weld backing bar/ring • Poor weld geometry, pad welds, canoe piece repairs, etc. • Weld overlay on tube OD • Deposits • Locally high heat ux or steam quality • Bends or sharp changes in tube direction • Horizontal or near horizontal tubing • Local regions of DNB

• Examine boiler and maintenance history for evidence of potential flow disruption sites. • Take and examine tube samples for distinctive bathtub ring deposits. • Perform circulation testing.

• As above.

Fireside conditions: • Flame impingement • Burner misalignment • Change in heat ux patterns following installation of low NOX burners • Major change in fuel source

• Inspect furnace wall for evidence of ame impingement. • Adjust burners, etc. • Check burner operation for possible direct ame impingement. • Address combustion conditions. • Measure heat ux at selected locations

Water-Touched Tubes Table 22-3 (con tinue d) Actions to Confirm and Immediate Actions and Solutions

Major Root Causes

Actions to Confirm


Acidic Contamination—All Causes

• Evaluate cation conductivity and/or sodium in the hotwell or at • Depending upon severity, initiate established procedures for unit the condensate pump discharge. shutdown and chemically clean, as needed.

Condenser leaks: minor but occurring over an extended period

• Review chemistry control logs to determine if, and when, • Depending upon severity, initiate established procedures for unit impurities were excessive. Particularly important is boiler water shutdown and chemically clean, as needed. cation conductivity.

Condenser leaks: major ingress, generally one serious • Conrm from chemistry control logs, especially the extent and • Immediate shutdown of unit, conrm pH depression, and event depth of pH depression in boiler water. chemically clean. Water treatment plant or condensate polisher • Evaluate results from and reliability of monitoring and alarm regeneration chemical upset leading to low pH condition systems, particularly for cation conductivity

• Remove unit from service and chemically clean; clean up water chemistry.

Improper use of low level phosphate treatments

• Review cation conductivity, boiler water chloride control curves, and levels resulting from current choice of chemistr y and its implementation

• Make sure that appropriate chloride control curves are chosen. • Make sure that operators understand where to operate for the particular chemistry chosen.

Errors in chemical cleaning process

• Review chemistry logs during cleaning and rinsing. • Depending upon severity, initiate established procedures for unit • Borescope/videoprobe examination to check the efcacy of the shutdown and reclean as needed. chemical cleaning.


42

Figure 22-11 Typical locations of hydrogen damage in conventional units.

Figure 22-17 Schematic of the ultrasonic velocity change technique to detect hydrogen damage.

Source: Lamping, 1991

Water-Touched Tubes Table 22-5 Potential Ramifications

Hydrogen Damage Aspect


Actions Indicated

Waterwall deposits indicate high feedwater corrosion products

• Poor feedwater chemistry control (probably iron levels at the • Implement stricter cycle chemistry control program, core level of economizer inlet are > 2 ppb) instrumentation, etc. • High Cu levels in deposits might indicate Cu deposition in HP turbine • Develop monitoring program to optimize feedwater chemistry.

Excessive waterwall deposits

• Potential BTF by overheating and creep

• Sampling to determine nature and extent of deposit problem. • Apply guidelines for chemical cleaning.

Geometric boiler water ow disruptions

• Potential for excessive deposit buildup • Tube failures by overheating

• Remove pad welds and other improper repairs. • Identify and remove other sources for ow disruption.

Contaminant ingress

• Corrosion of other cycle parts: turbine, SH/RH

• Inspect susceptible components; sample steam and/or material in susceptible locations for indications of damage. • Careful examination of cycle chemistry monitors to characterize extent of problem.

Contamination by improper chemical cleaning

• Potential for problems throughout cycle

• Inspect for problems and carefully monitor chemistry on return to service. • Establish proper chemical cleaning processes.

Fireside problems (flame impingement, burner alignment, major fuel change)

• Possible BTF by reside corrosion of waterwall tubing • Possible BTF by overheating • Possible thermal fatigue cracking on waterwalls

• Inspect and adjust as required.


44

Acid Phosphate Corrosion (Chapter 23) Description Table 23-1 Characteristics and Appearance of Acid Phosphate Corrosion

Characteristic

Appearance

Features of failure

• Gouged areas; thick, adherent deposits. • Ductile, thin-edged, or pinhole failure.

Effect on oxide and characteristic deposit

• Caustic concentrates at base of deposit and leads to dissolution of protective oxide via fluxing. • Deposit usually contains distinctive crystals of sodium ferroate and/or sodium ferroite.

Key microstructural features

• Material removal only; no microstructural changes in tube steel. • No protective oxide layer. • Distinctive metal removal usually lled with adherent deposit.

Attack rate

• Rapid: up to 2 mm/yr (0.08 in./yr).

Water-Touched Tubes

Figure 23-1 Example of acid phosphate cor rosion showing tube gouging. Tube is from a 400 MW boiler with an 18.2 MPa (2640 psig) dr um pressure. The severely corroded region was approximately 2.5 cm x 10 cm (1 in. x 4 in.) in extent. The stepped pattern on this ribbed tube is typical of that which occurs by d ryout.


46

Figure 23-2 Acid phosphate corrosion damage. The railroad track pattern of corrosion is indicative of local steam blanketing.

Table 23-2 Contributing Causes/Susceptible Components

Location/Tube Condition Locations where the water/fluid flow adjacent to the tube wall is disrupted • Welded joints and welding processes, such as the following: (i) welded joints with backing rings (ii) poor repair welds, including pad welds, canoe pieces, or window welds (iii) poor weld overlay (penetrating to the inside surface) (iv) weld overlay on relatively thin wall that, because of high heat input, results in waviness on the tube ID • Locations with existing internal deposits caused by the following: (i) a deposition mechanism (ii) deposits left from improper chemical cleaning (iii) locally high heat flux/transfer (iv) locally high steam quality • Geometric features, including the following: (i) bends around burners or openings (ii) sharp changes of direction (such as the nose of the furnace) (iii) tubes bending off lower headers and drums

Water-Touched Tubes Table 2 3-2 (con tinue d) Contributing Causes/Susceptible Components

Location/Tube Condition Locations with a high heat flux/transfer Locations where boiling first initiates Locations with thermal-hydraulic flow disruptions • Locations with local very high steam quality • Locations with horizontal or inclined tubing heated from above or below (roof tubes) Localized overheating of the tubes (fireside conditions) • Flame impingement • Burner misalignment • Operating conditions such as overring or underring, gas channeling, or inadequate circulation rates • Major change in fuel source, such as higher Btu value coal, dual ring with gas, changeover to oil, or g as ring where heat ux increases


48

Figure 23-11 Typical boiler locations where acid phosphate corrosion can occur in conventional units. Figure 23-3 Acid phosphate corrosion gouging showing concentric “bathtub” rings. The fact that these rings are visible on the sides of the tube up to the mid-diameter indicates that at some point steam blanketing encompassed the upper half of the tube. Gouging and a pinhole leak occurred within the concentric rings.

Water-Touched Tubes Table 2 3-3 Actions to Confirm and Immediate Actions and Solutions

Major Root Causes

Actions to Confirm



• Analyze results from chemistry monitors with particular emphasis on levels of Fe and Cu in the feedwater. • Perform selective tube sampling for deposit measurement. Check the efficacy of chemical cleaning.

Flow disruption, including the following: • Weld backing bar/ring • Poor weld geometry, pad welds, canoe piece repairs, etc. • Weld overlay on tube OD • Deposits • Locally high heat ux or steam quality • Bends or sharp changes in tube direction • Horizontal or near horizontal tubing • Local regions of DNB

• Examine boiler and maintenance history for evidence of • As above. potential flow disruption sites. • Take and examine samples for distinctive bathtub ring deposits. • Perform circulation testing.


50



Major Root Causes

Actions to Confirm


Fireside conditions, including the following: • Flame impingement • Burner misalignment • Change in heat ux patterns following installation of low NOX burners • Major change in fuel source

• Inspect furnace wall for evidence of ame impingement. • Check burner operation for possible direct ame impingement. • Measure heat ux at selected locations.

• Adjust burners, etc. • Address combustion conditions.

Phosphate Concentration

• Evaluate boiler water; “black boiler water” samples are an indication that severe corrosion is taki ng place over large areas of the waterwall.

• Depending upon severity, initiate established procedures for unit shutdown and chemical clean, as needed.

Use of improper cycle chemistry controls, particularly “chasing” phosphate hideout by using monosodium and/or an excess of di-sodium phosphate

• Determine if boiler has a persistent problem with phosphate • As above. hideout: review plant chemistry control logs, on-line cycle chemistry records, chemical additions to the boiler, and/ or alarms. • Review phosphate control additions; tabulate monthly usage of mono- and di-sodium phosphate for at least the past two years. • Perform metallurgical analysis to conrm nature of deposits.


Acid Phosphate Corrosion Aspect


Actions Indicated

Waterwall deposits indicate high feedwater corrosion products

• Poor feedwater chemistry control (probably iron levels at the economizer inlet are >2 ppb) • High Cu levels in deposits might indicate Cu deposition in HP turbine

• Implement stricter cycle chemistry control program, instrumentation, etc. • Develop monitoring program to optimize feedwater chemistry.

Excessive deposits


• Perform sampling to determine nature and extent of deposit problem. • Apply guidelines for chemical cleaning.

Geometric boiler water ow disruptions



Phosphate hideout

• Only a control problem by itself; however, chasing the hideout • Optimize phosphate treatment without problem through the use of mono- and/or an excess of diexcessive use of phosphate additions. sodium phosphate can lead to excess phosphate throughout the boiler with possible carryover into the turbine. • If associated with pH decreases during a startup, then there is a possibility of increasing corrosion fatigue.


52


Acid Phosphate Corrosion Aspect


Actions Indicated

Excessive phosphate in steam

• Possibility for transport and deposit in SH/RH and turbine

• Check steam chemistry and carryover.

Fireside problems (flame impingement, burner alignment, major fuel change)

• Possible BTF by reside corrosion of waterwall tubing. • Possible BTF by overheating. • Possible thermal fatigue cracking on waterwalls


Figure 23-9 Acid phosphate corrosion damage. The “railroad track”pattern of corrosion is indicative of local steam blanketing.

Water-Touched Tubes

Caustic Gouging (Chapter 24) Description Table 24-1 Characteristics and Appearance of Caustic Gouging

Characteristic

Appearance

Features of failure

• Gouged areas; thick, adherent deposits. • Ductile, thin-edged, or pinhole failure.

Effect on oxide and characteristic deposit

• Caustic concentrates at base of deposit and leads to dissolution of protective oxide via fluxing. • Deposit usually contains distinctive crystals of sodium ferroate and/or sodium ferroite.

Key microstructural features

• Material removal only; no microstructural changes in tube steel. • No protective oxide layer. • Distinctive metal removal usually lled with adherent deposit.

Attack rate

• Rapid: up to 2 mm/yr (0.08 in./yr).


54

Figure 24-2 Cross-section through the thick, layered deposit shown in figure at left.

Source: TR-102433, 1993

Figure 24-10 Cross-section through the failed tube showing the internal attack that occurred. The following figures show detail of the thick deposit and scale at the failure location.

Water-Touched Tubes Table 24-2 Contributing Causes/Susceptible Components

Location/Tube Condition Locations where the water/fluid flow adjacent to the tube wall is disrupted • Welded joints and welding processes, including the following: (i) welded joints with backing rings (ii) poor repair welds, including pad welds, canoe pieces, or window welds (iii) weld overlay on relatively thin wall that, because of high heat input, results in waviness on the tube ID • Locations with existing internal deposits caused by the following: (i) a deposition mechanism (ii) deposits left from improper chemical cleaning (iii) locally high heat flux/transfer (iv) locally high steam quality • Geometric features, including the following: (i) bend around burners or openings (ii) sharp changes of direction (such as the nose of the furnace) (iii) tubes bending off lower headers and drums


56

Table 24-2 (con tinue d) Contributing Causes/Susceptible Components

Location/Tube Condition Locations with a high heat flux/transfer Locations where boiling first initiates Locations with thermal-hydraulic flow disruptions • Locations with local very high steam quality • Locations with horizontal or inclined tubing heated from above or below (roof tubes) Localized overheating of the tubes (fireside conditions) • Flame impingement • Burner misalignment • Operating conditions such as overring or underring, gas channeling, or inadequate circulation rates • Major change in fuel source, such as higher Btu value coal, dual ring with gas, changeover to oil, or gas ring where heat ux increases

Water-Touched Tubes

Figure 24-3 Needle-shaped crystals in the deposits.


58

Figure 24-1 Thick deposits and gouged tube metal on the downstream side of a weld. A large amount of copper is deposited, and the deposit is laminated.

Source: TR-102433, 1993


Major Root Causes

Actions to Confirm



• Analyze results from chemistry monitors with particular emphasis on levels of Fe and Cu in the feedwater. • Perform selective tube sampling for deposit measurement. Check the efficacy of chemical cleaning.


Flow disruption caused by the following: • Weld backing bar/ring • Poor weld geometry, pad welds,canoe piece repairs, etc. • Weld overlay on tube OD • Deposits • Locally high heat ux or steam quality • Bends or sharp changes in tubedirection • Horizontal or near horizontal tubing • Local regions of DNB

• Examine boiler and maintenance history for evidence of • As above. potential flow disruption sites. • Take and examine samples for distinctive bathtub ring deposits. • Perform circulation testing.

Fireside conditions, including the following: • Flame impingement • Burner misalignment • Change in heat ux patterns following installation of low NOX burners • Major change in fuel source

• Inspect furnace wall for evidence of ame impingement. • Check burner operation for possible direct ame impingement. • Measure heat ux at selected locations.

• Adjust burners, etc. • Address combustion conditions.


Major Root Causes

Actions to Confirm

Sources of Caustic Concentration—All Causes

Immediate Actions and Solutions • Depending upon severity, initiate established procedures for unit shutdown and chemical clean, as needed.

Elevated caustic level over time (units on caustic treatment)

• Review plant chemistry control logs, on-line cycle chemistry records, or instrumentation alarms.

• As above, plus reduce levels of NaOH addition to Caustic Treatment Guidelines

Excessive caustic addition to units on AVT

• Review plant chemistry control logs, on-line cycle chemistry records, or instrumentation alarms.

• As above, plus: –Use blowdown more effectively to minimize NaOH additions. –Investigate the need to use NaOH on startups. The optimum approach is to remove the reason that NaOH is added (perhaps air in leakage)

Excessive caustic addition to contro phosphate treatment

• As above.

• As above. plus set-up optimum phosphate continuum with <1 ppm NaOH treatment control range

Water treatment plant upset leading to high pH condition • Check/conrm operation and records of regeneration of water • Shut down unit, remove excess sodium hydroxide, ush unit a (regeneration of condensate polishers or makeup water treatment plant equipment. number of times until water is within specification, then ion exchange resins, for example) investigate the need to chemically clean unit.


60

Figure 24-5 Typical boiler locations where caustic gouging can occur in conventional units.

Figure 24-8 Schematic of caustic gouging beneath a region of heavy deposition. Depending on the rate of corrosion, there may be a layer of protective Fe3O 4 beneath the concentrated NaOH.


Caustic Gouging Aspect


Actions Indicated

Waterwall deposits indicate high feedwater corrosion products.

• Poor feedwater chemistry control (probably iron levels at the economizer inlet are >10 ppb) • High Cu levels in deposits might indicate Cu deposition in HP turbine

• Implement stricter cycle chemistry control program and instrumentation. • Develop monitoring program to optimize feedwater chemistry.

Excessive deposits.


• Perform sampling to determine nature and extent of deposit problem. • Apply guidelines for chemical cleaning.

Geometric boiler water ow disruptions.



Elevated caustic level over a long period (units on caustic treatment).

• Potential for carryover into steam; damage to austenitic SHs and to turbine.

• Consider additional sodium monitoring for feedwater, boiler water, and steam. • Ensure that steam limits for sodium (2 ppb) are not exceeded.


62

Table 24-5 (con tinue d) Potential Ramifications

Caustic Gouging Aspect


Actions Indicated

Excessive caustic additions in units on AVT.

• Same as above

• Consider additional monitoring and alarms to prevent recurrence. • Investigate the need to add NaOH during startup.

Excessive caustic additions in units on phosphate treatment.

• Same as above

• Consider additional monitoring and alarms to prevent recurrence.

Ingress from water treatment plant deficiency

• Same as above

• Check/conrm operation of condensate polishers and ion exchange resins of makeup water.

Fireside problems (flame impingement, burner alignment, major fuel change

• Possible BTF by reside corrosion of waterwall tubing. • Possible overheating tube failures


Water-Touched Tubes

Waterwall Fireside Corrosion (Chapter 25) Description • • • • • • • • •

Large loss of wall thickness (wastage) on reside of tube. Maximum attack usually at the crown of the tube facing the ame encompassing approximately 120 degrees of tube circumference. Longitudinal cracking may be evident. Hard, fired inner-layer deposits on tube with loosely bonded ash on outer layers. Removing deposits reveals tube surface grooving similar to “alligator hide. Final failure occurs when remaining wall thickness is unable to withstand hoop stress. Final failure usually manifested as longitudinal thin-eged cracks. Has occurred in a significant number of boilers retrofitted with low-NOx sytems that employ overfire air (OFA) ports. Waterwall corrosion is most severe in super critical boilers burning relatively high sulfur coal, but subcritical boilers and boilers firing low sulfur coals are not immune.


64

Figure 25-1 Typical appearance of damage caused by waterwall fireside corrosion.

Figure 25-2 Cross-section through a tube affected by severe fireside corrosion showing significant wall loss.

Water-Touched Tubes Table 25-1 Contributing Causes/Susceptible Components

Summary of Factors Affecting Waterwall Corrosion in Boilers Staged with Low NOx Combustion Systems Sources: TR-111155, 1998; Bakker, 2004; Bakker, 2003; Kung, 2000; Bakker, 2002 Main factors

FeS and alkali chlorides in deposits and CO and HCl in the flue gas are the main factors increasing waterwall wastage rates.

FeS deposition

FeS deposition increases with increased staging, thus increasing both wastage rates and the area affected by corrosion.

Effect of amo unt of FeS

Corrosio n rat es increase rapidly wit h inc reasing FeS cont ent up to 20%; at higher FeS levels, was tag e rates increase fur ther, but at a lower rate.

Effect of amo unt of Cl

Corrosio n rat es increase rapidly wit h inc reasing chloride cont ent up to 2%. At higher chloride levels, wast age rates increase fur ther, but at a slower rate.

Effect of st oic hiometr y

FeS deposit s form under reducing conditions but dec ompose under subseq uent oxi dizing conditio ns to produce ver y cor rosive species.


66

Table 25-1 (con tinue d) Contributing Causes/Susceptible Components

Summary of Factors Affecting Waterwall Corrosion in Boilers Staged with Low NOx Combustion Systems Sources: TR-111155, 1998; Bakker, 2004; Bakker, 2003; Kung, 2000; Bakker, 2002 Reducing conditions needed

Reducing conditions are needed for FeS and alkali chloride deposition.

Temperature effect

Both FeS and alkali chlorides are less stable at higher temperatures, wit h little or no deposition occurring above 900°C (1652°F). Thus FeS and chloride deposition decrease with increasing deposit thickness. Chlorides, and to a lesser extent FeS, will deposit only on bare or nearly bare tubes under high heat absorption conditions.

Effect of HCl in the flue gas

HCl in the flue gas increases corrosion rates. The rate of increase is proportional to the amount of chloride in the deposit. Without chloride in the deposits, the effect of HCl in the flue gas is minimized.

Role of H2S

Corrosion caused by H2S in the flue gas cannot be neglected, but is generally less than 0.5 mm/yr (20 mils/yr) for supercritical boilers. Modeling studies have indicated t hat measures to reduce FeS deposition may also reduce H2S levels near the furnace wall

Water-Touched Tubes

Figure 25-3 The general structure of the corrosion scale formed on a furnace waterwall tube under fireside corrosion conditions, which are usually related to a reducing environment. Scale thickness is approximately 0.25 mm (0.01 in.).

Adapted from Cutler, 1978 ELECTRIC POWER RESEARCH INSTITUTE

68

Figure 25-4 Grooving of the tube’s external surface, known as “alligator hide,” associated with oil and coal-ash corrosion. The fireside oxide scale and ash deposit were removed by glass bead blasting.

Source: TR-102433, 1993

Figure 25-5 Sample of highly corroded tube showing wall loss and fireside surface appearance. Note the rounded pits on the surface.


Major Root Causes

Actions to Confirm


All causes of fireside corrosion

• Collect and evaluate samples of reside scale/ash to determine • Choose repair strategy based on the severity of the corrosion concentration, patterns, and melting points of elements and rate and extent. compounds n present. • Use corrosion probes to monitor wastage.

Substoichiometric (reducing) Environment—All Causes

• Monitor for levels of O2, CO, H2S, and HCl along damaged or • As above. susceptible locations. • Field testing to detect combustion conditions in susceptible areas with waterwall deposition probes to collect deposits. • Establish a combustion uid dynamics model and use the model to evaluate potential improvements in combustion parameters.


Major Root Causes

Actions to Confirm


Use of low NOX combustion systems with OFA

• Collect and evaluate samples of reside scale/ash to determine concentration, patterns, and melting points of elements and compounds present. • Use corrosion probes to monitor wastage. • Monitor for levels of O2, CO, H2S, and HCl along damaged or susceptible locations.

• As above.

Poorly adjusted or worn burners

• Visual examination to detect localized ame impingement. • Monitor for change in furnace slagging conditions. Use waterwall deposition probe, as needed.

• Adjust burners to prevent ame impingement.

Improper air/fuel mixing

• Improper air/fuel mixing.

• Choose repair strategy based on the severity of the corrosion rate and extent.

Deposition of carbon rich deposit


70

• Use visual and metallographic analysis to determine whether carbon particle impingement is occurring. • Analyze coal neness.

• As above, plus adjust mill classication.


Major Root Causes

Actions to Confirm


Overheated Tubes – All Causes

• Measure tube crown temperatures directly by installing chordal thermocoupled tubes. • Evaluate tube microstructure.

Excessive heat absorption rates

• Measure heat absorption rates with ux domes in areas experiencing corrosion.

Flame impingement

• Examine ame patterns within the furnace.

Excessive buildup of waterside deposits,such as ripple magnetite (this should occur only on boilers where the feedwater treatment has not been changed to oxidizing AVT (O) or oxygenated treatment).

• Excessive buildup of waterside deposits, such as ripple magnetite • Chemically clean waterwalls. (this should occur only on boilers where the feedwater treatment has not been changed to oxidizing AVT (O) or oxygenated treatment).

Flow restrictions of tubes

• Examine failure records for evidence of conditions such as short term overheating failures of the tubes. • Determine whether past buildups of deposits were sufciently severe so as to cause extensive areas of flow restriction.

• Examine ame patterns within the furnace.


Major Root Causes

Actions to Confirm

Excessive sootblowing

• Review sootblowing procedures

Coal composition and/or changes

• Review of the coal and coal ash chemistry (proximate and ultimate analyses and ash chemistry) for the coals currently being used and that were used prior to the occurrence of the fireside corrosion. • Perform an analysis of the scales being formed.

Presence of pyrite and distribution of pyrite size in coal grinds

• Review of the coal and coal ash chemistry (proximate and ultimate analyses and ash chemistry) for the coals currently being used and that were used prior to the occurrence of the fireside corrosion. • Perform an analysis of the scales being formed. • Determine coal neness.


72


• Adjust mills to decrease grind size.


Major Root Causes

Actions to Confirm

Presence of chlorine in coal

• Collect and evaluate samples of reside scale/ash to determine whether Cl is appearing in scale layers, particularly the scale/metal interface) • Review the coal and coal ash chemis try (proximate and ultimate analyses and ash chemistry) for the coals currently being used and that were used prior to the occurrence of the fireside corrosion. • Determine coal neness.

Operating changes such as load change that result in alternating between locally oxidizing and reducing conditions

• Monitor for levels O2, CO, H2S, and HCl along damaged or susceptible locations as a function of various load conditions. • Establish a combustion uid dynamics model and use the model to evaluate various operating regimes.


Water-Touched Tubes


74

Figure 25-6 Typical boiler locations where fireside corrosion can occur.


Waterwalls Fireside Corrosion Aspect


Actions Indicated

Corrosive coal or coal blend

• Potential for SH/RH reside corrosion. • Potential for back-end corrosion.

• Mitigate negative aspects of coal composition if possible by fuel switch, blending, or washing.

Poor combustion conditions

• Low unit efciency. • Poor mill performance. • Combustion is delayed and occurring in the convective passes, which could lead to corrosion of SH/RH surfaces.

• Combustion adjustments to improve unit efciency. • Correct mill performance

Tube overheating by thick internal deposits or ripple magnetite

• Overheating in tubes. • Alert of poor feedwater treatment or controls.

• Chemically clean unit if necessary. • Implement program to clean up and ensure proper cycle chemistry

Water-Touched Tubes Figure 25-7 Strategies for preventing repeat failures by waterwall fireside corrosion in coal-fired plants. Note: The circled numbers are used to identify options for the discussions presented in EPRI report 1012757, and no ranking of the possible solutions is thus implied.


76

Thermal Fatigue in Waterwalls (Chapter 26) Description Macro Features

• Multiple parallel circumferential cracks in waterwalls of coalred supercritical units. • Cracking in weld overlays on waterwall in areas of severe reside corrosion. • Crack density can be approximately 20–40 cracks per inch of tube length, but adjacent cracks can be of different lengths. • “Ripple” magnetite scale on waterside (tube ID). • Thick ID oxide that causes tube OD temperature to rise. • Cracking on tube ID in the thick oxide in some cases. Micro Features • Cracking is primarily transgranular. • Sulfur and small amount of intergranular suldation at crack tip.

Water-Touched Tubes

Figure 26-1 Circumferentially cracked waterwall tubes from an 800 MW supercritical boiler.


78

Figure 26-2 Thermal fatigue cracking through a 622 weld overlay and into the base tube (T11).

Figure 26-4 Cross-section showing the typical appearance of cracking: sharp-pointed features and the oxide (dark) and sulfide (light) corrosion products.

Source: TR-104442, 1995

Figure 26-7 Appearance of thick internal oxide common in recent cases of thermal fatigue. The left hand photograph shows the ID of the tube on the furnace side, and the arrows indicate the extent of oxide was 0.14 mm (5.5 mils). The right hand photograph shows the ID of the tube on the casing side with an oxide layer (shown by the arrows) of 0.25 mm (1 mil) thickness.

Figure 26-5 Closeup of typical cracking indicating the appearance at the crack tip and presence of a minor amount of intergranular sulfidation at the tip. The right of the two photographs is of etched material.

Source: TR-104442, 1995

Water-Touched Tubes


Similar cracking can occur on waterwalls of subcritical units where water cannon is used to remove the ash.Most susceptible locations are areas of: slag buildup and shedding, wall blower quenching, high heat uxes, and flame impingement.

Figure 26-10 Location of thermal fatigue cracking relative to the position of the fireball. ELECTRIC POWER RESEARCH INSTITUTE

80

Figure 26-9 Typical areas of supercritical waterwall thermal fatigue.

Source: Plumley, 1991


Major Root Causes All causes

Actions to Confirm


• Compile needed background information and review. • Determine the distribution of thermal fatigue damage and plot • Conduct NDE of cracked locations. similar to that shown in Figure 26-9. • Use metallurgical evaluation to determine which root cause(s) • Institute appropriate repairs or replacements. appears most likely (see details below). • Establish a monitoring program to determine the time in operating space in which thermal transients are occurring. • Perform detailed stress/strain FEA analysis to determine peak surface strain ranges for each type of operating transient.

High Initial Waterwall Tube Temperatures Thick weld overlays

• Measure total tube metal thickness, including weld overlay, and correlate to locations of thermal fatigue damage. • Measure tube temperatures at susceptible locations using chordal thermocouples.

• Apply thinner layers of protection or alternates.

Higher heat fluxes

• Measure heat ux at selected locations. • Perform boiler modeling to evaluate unit furnace temperatures and the effect on waterwall circulation.

• Address combustion conditions.


Major Root Causes Flame impingement

Actions to Confirm


• Inspect furnace waterwall slag patterns for evidence of ame impingement. • Monitor the ame prole and extent of ame impingement. • Install a number of heat ux meters at representative locations and compare results with CFD heat flux map of waterwalls.

• Adjust burners, etc. • Compare heat ux patterns.

• Analyze tube samples and deposits, specically to determine the presence of rippled magnetite, thick oxide layers, or corrosion products. This should include chemical a nd metallurgical examination. • Evaluate unit pressure drop. • Evaluate unit chemical cleaning frequency and records. • Evaluate cycle chemistry, including monitoring records, to determine the cause of ripple magnetite or feedwater corrosion product deposits.

• Perform chemical cleaning if indicated by level of deposits that has formed. Plot pressure drop before and after. • Perform chemical cleaning of thick (steamlike) oxides.

Increasing Waterwall Tube Temperatures Over Time Internal deposits, including ripple magnetite, thick oxide layers, ormfeedwater corrosion products


82


Major Root Causes

Actions to Confirm


Reduced internal tube flow rates

• Consider installation of anubar ow meters into selected tubes and pressures taps to measure steam quality, fluid velocity, and pressure drop over a wide range of operating conditions. • Conduct a ow hydrodynamics analysis to check for uid flow to waterwall panels. • Check orice design and operation across load range

• Evaluate/correct uid ow and/or orice design across load range.

Formation of external oxides and deposits

• Evaluate unit slagging patterns to determine if excessive deposits are accumulating and, in areas of thermal fatigue damage, make heat flux measurements.

• Temperature monitoring to determine frequency of slag shedding.

Frequent severe thermal transients

• Analyze tube and uid temperature transients to determine effective midwall and tube crown temperatures. • Review plant records for indications of the source of the problem.

• Monitoring of temperature and heat ux to identify time in operating space when thermal transients occur.

Natural or forced slag removal, including slag shedding and sootblowing

• Set up a monitoring program. • Perform periodic testing of sootblowers to ensure proper function • Evaluate the slagging and fouling characteristics of the unit of the water removal system. in conjunction with the thermal monitoring to determine the frequency of thermal transients and their extent. • Evaluate sootblower operation and maintenance to determine whether excessive conditions or too frequent operation have occurred. Relate thermal transients to sootblowing.


Major Root Causes

Actions to Confirm


Application of water blowing (cannons) or improper sootblowing

• Use instrumented tube/panel and measured thermal transients • Perform periodic testing of sootblowers to ensure proper function along with thermal analysis to estimate local stresses created of the water removal system. within the wall and at the crown. With the predicted local stresses and frequency of blowing operations, the life of the tubes can be predicted by fatigue analysis. • Perform visual examination to detect extent of problem and identify any obvious deficiencies in the operation or maintenance of the equipment.

Application of water blowing (cannons) or improper sootblowing (continued)

• Evaluate sootblower or water cannon operation and maintenance to determine whether condensate introduced into the sootblower media is causing excessive thermal shock to tubes. • Perform calibration and testing to measure key parameters such as heat flux or temperature as a function of travel and sequence times.


84


Major Root Causes

Actions to Confirm


Flame instabilities

• Monitor the ame prole and extent of ame impingement using a tube/instrumented panel.

• Adjust burners, etc. • Compare heat ux patterns.

Unit operations, including the following: • Forced fan cooling • Rapid startups • Initial ring • Frequent load cycling • Furnace pressure cycles in balanced-draft unit

• Review unit operating records for conditions outlined above to • Modify operating regimes in conjunction with results from identify potential sources of excessive cyclic stresses. instrumented tube/panel. • Monitor temperatures and strains during all unit transients using instrumentation.

Fireside Environment

• Collect and perform chemical and thermogravimetric evaluations of the fireside scale/ash to deter mine concentration, patterns, and melting characteristics and corrosivity of elements and compounds present. • Review Chapter 25 for actions to evaluate the various root causes

Effect of Susceptible Site

• Review locations of cracking and correlate to obvious geometric conditions or material degradation. Review waterwall attachment details.


Waterwalls Thermal Fatigue Aspect High levels of feedwater corrosion products

Alert for Other Cycle Components • Flow-accelerated corrosion (FAC) and/or corrosion may be occurring in the feedwater system: in the feedwater heaters, deaerators, piping, or at the economizer inlet. • Corrosion products have probably deposited in other locations, such as the boiler feed pump and at boiler orifices. The latter could lead to BTF by overheating.

Actions Indicated • Need to develop an optimized cycle chemistry control program, preferably by instituting oxygenated treatment but consisting at a minimum of periodic chemical cleaning and optimizing feedwater treatment.

Figure 26-19 Close-up view of cleaned area of a tube with thermal fatigue cracks showing the radiographic crack indications, their visual crack mouth appearance, and the measured crack depth. Note that a longitudinal saw cut was made through the tube.


86

Thermal Fatigue of Economizer Header Tubes (Chapter 27) Description Macro Features • Initiated on ID of stub tube at stress concentrations associated with borehole and tube attachment to header • Multiple longitudinal cracks on tube ID

Figure 27-2 Damage developed from a tube penetration in an economizer inlet header.

Micro Features • Straight transgranular cracks lled with oxides • Longitudinal cracking propagating radially from ID to OD of stub tube


• Worst damage usually found in tubes closest to the feedwater inlet • First indication often pinhole leak in toe of stub tube to header weld on the tube side

Figure 27-1 Cross-section through economizer inlet header and tubes showing stub tube leak location and typical longitudinal pattern of cracking in the tube and header bore.

Water-Touched Tubes Table 27-2 Actions to Confirm and Immediate Actions and Solutions

Major Root Causes

Actions to Confirm


For all root causes

• Perform metallurgical analysis of removed tube sample to confirm orientation, initiation sites,and extent of cracking. Ensure that damage is in fact thermally induced and not either flexibility induced or caused by FAC.

Unit operations that introduce large DT excursions through the wall of the header

• Install thermocouples and measure through- • Conrm mechanism. wall thermal gradients during all operating • Inspect to determine the extent of damage (ber periods, including feedwater flow, drum optic is the usual first approach). top-up, and during shutdown. • For minor damage, replace tube, modify operating procedures, and institute long-term monitoring. • For major damage, replace header, modify operating procedures, and institute long-term monitoring.

Stress concentrations

• Evaluate inspection data indicating locations of damage.


88

• Possible header redesign to lower stress concentrations and stress levels caused by temperature differentials (when replacing header).

Figure 27-3 Typical thermal fatigue cracking morphology. Note regular spacing of cracks and that they become thinner and straighter with propagation.

Potential Ramifications

• Implications will mostly be confined to the economizer inlet header • If pitting in the tubes, caused by poor shutdown conditions, was a contributor to flaw initation and growth, then other economizer regions may be at risk for pitting damage

Figure 27-7 Inspection methods and areas to be inspected. (MP) – magnetic particle inspection, (DP) – dye penetrant inspection.

Source: GS-5949, 1989

Figure 27-6 Schematic of typical thermocouple locations on the economizer inlet header. Thermocouple locations are designated by a letter (S, F, R) followed by an identifying number.

Source: GS-5949

Water-Touched Tubes

Thermal-Mechanical and Vibration-Induced Fatigue in Water-Touched Tubes (Chapter 28) Description

Micro Features include the following: • Predominately straight transgranular cracks. • Cracking may be intergranular when occurring in creep-damaged materials. • Depending on service conditions, the cracks may be lled with oxides.

Macro Features include the following: • Thick-edged failures. • Circumferential cracking initiated on OD. • Appearance of beach marks is typical, but they may be obliterated by oxidation.

Figure 28-1 Fatigue failure of a wall tube from a once-through boiler. The tube is a finned tube and forms part of a manhole door opening. The failure initiated on the OD of the tube at the toe of the fin/tube weld. The tube is shown here with the fin removed by mechanical grinding to allow removal from the boiler.

Source: J. Hickey, Irish Electricity Supply Board ELECTRIC POWER RESEARCH INSTITUTE

90

Figure 28-2 Micrograph taken through the crack showing transgranular cracking typical of fatigue.

Source: J. Hickey, Irish Electricity Supply Board


• Typical locations for fatigue failure include: – Attachments, particularly solid attachments or jammed sliding attachments – Bends in tubing – Economizer inlet header

• The locations are often associated with welds, particularly where the weld or condition of the attachment does not allow for thermal expansion, including the end of membrane of water wall tubing at either the lower slope region near the ash hopper or at the top of the rear wall at the entrance of the near gas passage, and tie bars, K bars, or beams

Figure 28-4 Three possible locations for tubing-related fatigue failures in tight 180° bends.

Figure 28-3 Typical spacers or sliding supports where fatigue in water-touched tubing can occur.

Figure 28-5 Schematic illustrating failures caused by inflexibility to the movement between header and waterwall.


Major Root Causes

Actions to Confirm


Excessive strains caused by constraint of thermal expansion.

• Visual examination for distortion or bending in adjacent tubes. • Identify similar damaged locations. • Strain gauging of suspect locations to evaluate strains during unit • Repair/replace affected tubes. starts and cycling operation. • LVDT measurements to monitor the relative movement of the header/tube during transients.

Poor design and/or manufacture giving rise to excessive mechanical stresses

• Strain gauging to measure actual strains experienced at the local area during operation. • LVDT measurements to monitor the relative movement of the header/tube during transients. • For tight, hairpin bends, determine whether residual stresses are high.

• As above.

Vibration (flue-gas-induced) by direct flow or vortex shedding.

• Metallurgical examination to conrm high cycle fatigue.

• As above.

Potential Ramifications • None for this mechanism ELECTRIC POWER RESEARCH INSTITUTE

92

Thermal Fatigue Caused by Water Blowing (Chapter 29) Description Macro Features • Closely spaced multiple circumferential cracks on tube OD • Thick-edged failures with no metal wastage Micro Features • Straight transgranular cracks lled with oxides • Longitudinal cracking propagating radially from ID to OD of stub tube

Figure 29-1 Typical appearance of the waterwall tube thermal fatigue cracks caused by water blowing.

Water-Touched Tubes


Damage is usually found in waterwall tubes cleaned with water blowers. Carbon steel tubes (e.g., SA 21- A1) are much more susceptible than low chromium alloy (e.g., SA 213 T-2).

Figure 29-2 Close-up of damage showing portions with exclusively water cannon damage and portions of the tube that were affected by normal circumferential thermal fatigue and water-cannon-induced thermal fatigue.


94

Figure 29-3 Surface appearance of cracking (right hand portion of tube shown in figure to left).


Major Root Causes Excessive Operation of Water Blowers • Operation is too frequent. • Progression velocities are too slow. • Flow volumes too large. • Maintenance or blower problems.

Actions to Confirm • Perform visual examination to determine location and obvious maintenance shortcomings or blower problems. • Perform calibration and testing to measure key parameters such as heat flux or temperature as a function of travel and sequence times • Perform thermal, stress, and fatigue crack growth rate analyses.

Figure 29-4 Microscopic view of typical water-cannon-induced thermal fatigue cracks. Features indicated include surface initiation, circumferential orientation, narrow v-shape, oxide-coated, and generally straight- sided cracks with some minor side branching in the deeper cracks. [1 mil = 0.0254 mm].

Immediate Actions and Solutions • Evaluate the extent of cracking. • Execute the applicable repairs or replacements. • Avoid the use of temporary measures such as pad welding, shielding, and/or coatings unless they are absolutely required to get the unit to the next scheduled outage. • Repair blower inadequacies or maintenance shortcomings. • Adjust progression velocity of blower.

Potential Ramifications • None for this mechanism

Water-Touched Tubes

Flow-Accelerated Corrosion in Economizer Inlet Header Tubing (Chapter 32) Description Macro Features • Localized to a particular area of the system, but the damaged area may affect an entire component, e.g., elbow, tee, etc., and can extend for more than one pipe diameter. • Causes wall thinning in carbon steel tubing exposed to owing water (single phase) or wet steam (two phase); water must be present, i.e., FAC will not occur in dry steam or superheated steam regions of the system. • FAC occurs when the protective magnetite iron oxide layer on the tube wall is dissolved. The magnetite becomes thinner and less protective, resulting in a higher corrosion rate. When the oxide formation and dissolution rates become equal, a stable corrosion rate is maintained. • Continued corrosion of the tube reduces the tube wall thickness until it is too thin to withstand normal system operating pressures and fails by ductile overload. • Single-phase FAC damage typically exhibits an orange peel appearance and may also exhibit chevrons or “horseshoes” toward the extremities of the damage (in areas of slower FAC damage). ELECTRIC POWER RESEARCH INSTITUTE

96

• Two-phase FAC is more wavy or scalloped and may sometimes appear as “tiger stripes” (alternate bands of rapid FAC and slow or nonexistent FAC). • Although FAC-damaged areas may appear to have no protective magnetite layer, it is always present. FAC is the dissolution and removal of the magnetite layer and not removal of the tube wall metal. Micro Features • FAC preferentially attacks the pearlite colonies in the tube wall microstructure and sometimes of the welds. Figure 32-2 Typical surface appearance of FAC. The feedwater flow was from bottom to top.

Table 32-2 Distinguishing Features of the Common Damage Mechanisms in Economizer Inlet Headers

Characteristic

Flow-Accelerated Corrosion

Location on header

• Near feedwater inlet.

Location in tube attachment weld area

• Long-term monitoring and alarm of through-Anywhere along the rst 10-12 cm (4-5 in.) from the header inlet.

Nature of damage

• Wastage with an -orange peel appearance of internal tube surface. • Generally FAC is not visible along the header bore or on header ID.

Damage morphology

• Generalized corrosion, orange peel appearance typical on tube ID.

Initiation site

• ID initiated.

Orientation of the damage

• In the middle of the largest gouge on the ID.

Water-Touched Tubes Figure 32-4 Cross-section through the economizer inlet header and tubes showing locations of FAC in the tubes. The tube bore shows the orange peel appeara nce. This FAC peaks after a distance of about 2.5–5 cm (~1–2 in.) into the tube.


98

Table Contributing Causes/Susceptible Components

Factor

Effect on Flow-Accelerated Corrosion (FAC)

Oxidizing-reducing potential (ORD)

As ORP becomes more reducing (negative), possibility of FAC will increase.

pH of the water (at the “hot” operating temperatures)

Generally, a higher pH will reduce FAC; an alkaline pH with a positive ORD will minimize FAC.

Temperature

FAC occurs over range of 100°C to 250°C (212°F to 482°F) but tends to peak in the range of 150°C to 180°C (300°F to 350°F).

Velocity

Under laminar flow, magnetite growth at the oxide/steel interface matches the dissolution rate, and the corrosion rate is stable. Under turbulent and higher velocity conditions, the flow disrupts the boundary layer and the magnetite growth cannot match the flow- accelerated dissolution, exfoliation, and spallation, and FAC occurs.

Mass transfer

Local mass transfer coefficient addresses transport of material (essentially magnetite) from surface to bulk flow and is dependent in a complex manner on fluid velocity and viscosity, flow geometry, temperature, and tube surface roughness. Mass transfer is a strong factor with an exponent of approximately 3.

Geometry

FAC is more common at points of hydrodynamic disturbance.

Alloy composition

Even trace amounts of chromium (and copper and molybdenum) can significantly reduce the solubility of magnetite and therefore FAC. A chromium concentration as low as 0.1 weight percent in carbon steel can significantly reduce FAC.

Water-Touched Tubes Table 32-1 Survey Results of FAC Incidents in Fossil Plants in 2006 (2003, 2000, and 1997)

Locations of FAC FAC – any location Economizer inlet tubing*

Percentage Reporting 70% (60%, 60%, 40%) 23% (25%, 22%)

Heater drain lines*+

65% (52%, 32%, 10%)

Piping around BFP*

20% (25%, 16%)

Tubesheet/tubes in HP heaters*

10% (11%, 12%)

Piping to economizer inlet header*

18% (35%, 11%)

Deaerator shell*

43% (14%, 11%)

Shell side of LP heaters* Notes: *indicat es single-phase FAC


100

13% (7%) +indicates two-phase FAC

Figure 32-3 Cross-section of the failed tube shown in figure on left. Note the almost complete absence of protective magnetite on the inside surface.


Major Root Causes Reducing conditions (single-phase FAC)

Actions to Confirm • Review chemistry records and monitoring systems for (i) ORP <-300 mV or (ii) di ssolved oxygen levels approaching 1 ppb or less and the presence of a reducing agent.

Figure 32-1 Appearance of an economizer inlet tube that failed by FAC. The weld is the header nipple weld about 5 cm (~2 in.) from the header. The orange peel appearance of FAC is clearly visible.

Immediate Actions and Solutions • Visual examination and UT thickness measurements in susceptible areas. • Replace severely thinned tubes with 1.25% Cr material.

Figure 32-11 Economizer inlet tube removed from a conventional fossil unit that had previously experienced FAC damage. This drum unit was converted from reducing AVT (with a reducing agent) to an oxidizing AVT. As a result, and as can be seen here, the protective magnetite, previously lacking, has been restored. Importantly, no further loss of wall thickness occurred after operating on the oxidizing AVT for a year.

Water-Touched Tubes Figure 32-12 Road map of activities for controlling FAC.

Source: 1008082, 2005

Table 32-4 FAC Resistance of Commonly Used Replacement Alloys Compiled in (TR-106611 R1, 1998) based on (Ducreux, 1982; ANSI B31.1, 1990)

Alloy

Rate (Carbon Steel)/Rate (Alloy)

Nominal Composition (Chromium and Molybdenum only)

1

0; 0

A213 Grade T11 or P11

39 *

1.25% Cr; 0.5% Mo

A213 Grade T22 or P22

76 *

2.25% Cr; 1% Mo

Type 304 **

> 250

18% C

Carbon Steel

Notes: * These values were determined using the nominal alloy content. ** Type 304 not permitted in water-wetted applications for an ASME Section I design.

Potential Ramifications ELECTRIC POWER RESEARCH INSTITUTE

102

• FAC is a unit-wide problem. Discovery of a problem in one part of the unit must trigger the initiation of a unit-wide program. • High iron levels in the fluid caused by FAC can cause deposition in HP evaporator tubes that act as centers for under-deposit corrosion.

Sootblower Erosion in Water-Touched Tubes (Chapter 33) Description

• Wall thinning caused by external tube sur face wastage. • Little or no ash deposits or protective oxide on the tube. • Thermal fatigue cracking may be present if there is water in the rst steam flow from the sootblower. • Erosion pattern will be angled to the tubes from the direction of the blow. • Appearance of fresh rust on the tube surface only a few hours after boiler washing, indicating protective oxide has been removed from the tube surface. • If erosion is rapid, failure may be thin-edged, pinhole shaped, or a long, thin blowout.


• Typical failure locations are in a circular pattern around wall blowers; corner effects are important. • Entrainment of ash in sootblower medium will abrade tube wall surface and remove metal. • Introduction of wet steam in place of normal superheated steam in the sootblower can greatly increase the amount of ash loading in the medium and accelerate erosion. • Refer to Fly Ash Erosion (Chapter 21) for more discussion of the effects of fly ash impacting tube surfaces.

Potential Ramifications • None for this mechanism.


Major Root Causes

Actions to Confirm


Improper Maintenance of Sootblowers such as: • Incorrect setting and conrmation of blowing temperature (insufficient superheat) • Improper operation and maintenance of moisture traps • Misalignment of sootblower

• Use visual examination to determine location and obvious maintenance shortcomings or blower problems. • Measure key parameters such as: – Blowing temperature and pressure. – Operation of moisture traps.

• Evaluate the extent of wall thinning and erosion damage to determine whether repairs or replacements are required. • Execute the applicable repairs or replacements. • Avoid the use of temporary measures such as pad welding, shielding, and/or coatings unless they are absolutely required to get the unit to the next scheduled outage. • Repair sootblower inadequacies or maintenance shortcomings.

Improper Operation of Sootblowers such as: • Condensate in blowing media • Excessive sootblowing pressures • Improper location of sootblower • Malfunction of sootblower • Excessive sootblowing

• As above, plus measure key operating parameters such as checking travel and sequence times.

• As above.


104

Short-Term Overheating in Waterwall or Evaporator Tubing (Chapter 34) Table 34-1 Distinguishing Features of the Three Levels of Short-Term Overheating for Waterwall and Evaporator Materials

Type of Overheating

Temperature Range

Fracture Surface

Extent of Tube Swelling

Subcritical short-term overheating

> Design < Lower critical temperature, A1

Thin-lipped, fish-mouth

Considerable

Intercritical short-term overheating

Between the lower critical temperature, A1 and the upper critical temperature, A3

Thin-lipped, fish-mouth

Considerable

Upper critical short-term overheating

Upper critical temperature, A3

Thick-lipped, fish-mouth

Little

Transgranular void formation by power law creep

Ferrite and spheroidized pearlite or bainite.

Near that of original hardness

Transgranular or mixed inter- and transgranular Ferrite, transformational products (pearlite, Variable, with hardness near void formation by power law creep bainite, and/or martensite). Some spheroidized transformation products being above pearlite or bainite may also be present. the original Inter- or transgranular creep fracture

Near rupture, transformational products Above original (pearlite, bainite, and/ or martensite). Some ferrite may also be present.

Water-Touched Tubes

Contributing Causes/Susceptible Components Typical Locations for Short-Term Overheating Failures usually do not occur where the interruption of tube flow occurs but in the higher (or highest) heat ux zone above. Failure locations might therefore include the following: • Above places where ow has been partially or completed blocked by prior maintenance activities, such as: in tubes where weld repairs have been performed and weld spatter has been left in the tube or where tools or repair materials have been left in tu bing • Above those orices in lower waterwalls where blockage or restricted flow results from deposition of feedwater corrosion products across the orifice • Locations, such as horizontal tubing, that are affected when a slug of steam comes down the downcomer from the steam drum


106

Figure 34-2 Typical locations in conventional boilers where short-term overheating in waterwalls can occur.


Major Root Causes

Actions to Confirm

Partial blockage caused by maintenance activities: • Check ows through tubes and/or for signs of obvious • Tools left in tubes blockage in tubes or lower headers. • Poor maintenance practices, particularly improperly • Review repair records to see whether the tube circuit was executed weld repairs such as where weld spatter recently repaired. is allowed to fall into a tube

Immediate Actions and Solutions • Institute repair and replacement as required.

Plugging of waterwall orifices by feedwater c orrosion • Inspect orices in other lower waterwall areas for evidence of • Clean orices. products blockage. • Institute repair and replacement as required. • Check records of pressure drop across boiler circulation pumps. Poor control of drum level

• Review operating records, including drum level control.

• Institute repair and replacement as required. • Check drum internals and operation.

Loss of coolant because of upstream tube failure

• Review past BTF locations in relation to current problem.

• Institute repair and replacement as required.


Water-Touched Tube ShortTerm Overheating Aspect


Actions Indicated

Orifice deposits may indicate high levels of feedwater corrosion products.

• Poor feedwater chemistry control (probably iron levels at the economizer inlet are > 10 ppb and/or Cu levels are > 5 ppb). • On high drum pressure units (> 17 MPa [2400 psi]), high Cu levels in deposits might indicate Cu deposition in HP turbine.

• Implement stricter cycle chemistry control program and instrumentation. See Chapter 8, Volume 1. • Develop monitoring program to optimize feedwater chemistry. See Chapter 8, Volume 1.

Excessive deposits.

Potential BTF by overheating and creep.

• Perform sampling to determine nature and extent of deposit problem. • Apply guidelines for chemical cleaning. See Chapter 9, Volume 1.


108

Low-Temperature Creep Cracking (Chapter 35)

• Thick-edged failure. • Tend to tunnel inside the tube wall, i.e., their true size will be larger than inferred by the exposed length on the tube surface.

Description

Micro Features • Predominately intergranular cracking with micro-ssuring aligned parallel with the main crack and signicant secondary cracking. • For higher stress and lower hardness, the cracking also may be transgranular. • Cracking will generally display evidence of grain boundary cavitation and formation of creep voids.

Macro Features • Typically initiates in high stress locations, notably the outside surface of tube bends. • Circumferential cracks are common, but longitudinal cracks also have been observed on economizer bends in conventional units. Figure 35-1 Low temperature creep in the 135° bend of a reheater tube.

Source: Hickey, 1995

Figure 35-2 Micrograph of section through cracking. Indicative of low-temperature creep damage are the intergranular fracture, associated secondary cracking, grain boundary creep cavitation, and creep voids in the tube material.


Water-Touched Tubes


• Elevated stress loading, including high residual stresses from cold forming, enhanced membrane stresses caused by pipe ovality at bends, and high service stresses. • Elevated hardness of the tube material. • As a rule of thumb, bends with ovality greater than 8% or hardness greater than 220-240 HV are considered to be at the greatest risk.

Figure 35-3 Cross-section through a failed reheater tube showing ovality in excess of 8%. ELECTRIC POWER RESEARCH INSTITUTE

110


Table Actions to Confirm and Immediate Actions and Solutions

Major Root Causes • High residual stress • High service stress • High metal hardness


Actions to Confirm • Perform an in situ hardness test • Measure distortion (ovality) in susceptible locations. • Measure residual stresses. This action may not be denitive as relaxation during service or removal of the tube from the boiler may have lowered initial stresses.

Immediate Actions and Solutions • All affected tube bends should be replaced.

Water-Touched Tubes

Chemical Cleaning Damage: Waterwalls (Chapter 36) Description

• Generalized corrosion of affected tube surf aces. • Affected surface can appear as localized jagged, rough, straight-sided, or undercut pits or as generalized wall thinning that can occur around the entire tube circumference.

Figure 36-1 Internal surface of a failed tube exhibiting a rough pitted and scalloped appearance typical of acid cleaning corrosion. (MAG: 1.2X) ELECTRIC POWER RESEARCH INSTITUTE

112

Source: TR-102433, 1993

Figure 36-2a, Figure 36-2b Cross-sections of a`pitted region revealing straight-sided and undercut pit morphologies associated with acid cleaning corrosion. Note also the absence of deposits within the pits, also characteristic of chemical cleaning corrosion.

Source: TR-102433, 1993

Water-Touched Tubes


Improper operations of the chemical cleaning process, including the following: • Use of inappropriate cleaning solvent • Excessively strong acid concentration • Excessively long cleaning times • Too high a temperature • Failure to neutralize, drain, and rinse after cleaning


There is a concern for volatile carryover. In conventional units, the chemical carries over and inadvertently cleans the superheater. These steam circuits are not rinsed; therefore, the material removed by the inadvertent chemical cleaning remains in the tubes and can cause deposits and blockage that result in short-term overheating and tube failure.


114

Table Actions to Confirm and Immediate Actions and Solutions

Major Root Causes • • • • •

Use of an inappropriate cleaning solvent. Excessively strong acid concentration. Excessively long cleaning times. Too high a temperature. Failure to neutralize, drain, and rinse after cleaning. • Failure to monitor Fe levels during the cleaning. • Fe levels were monitored but did not level out during the cleaning. • Breakdown of inhibitors as a result of temperature excursions.

Actions to Confirm


• Review of chemical cleaning procedures, chemical pumping systems, and chemical control logs. Items of particular concern are those listed above, which would lead to significant damage. • Review of cycle chemistry monitoring records to detect a pH depression on startup of the unit aft er cleaning, indicating improper rinsing of acid from the unit. • Sampling of affected tubes to allow examination of the inside surface for evidence of generalized corrosion. Part of an optimized procedure for chemical cleaning will be sampling of selected tubes to confirm the efficacy of the cleaning process. These samples can be used to determine whether excessive damage has accumulated. Wall thickness measurements can provide a quick screening as to whether excessive tube corrosion has occurred.

• Repairing or replacing the damaged tubes • Immediate chemical cleaning followed by proper neutralizing and rinsing

Water-Touched Tubes

Pitting in Water-Touched Tubes (Chapter 37) Description

• Pitting is associated with exposure to stagnant, oxygensaturated water formed during shutdown. • Pits can be numerous and closely spaced or isolated. • Pits usually covered with caps of corrosion product (tubercles or nodules). • Pits may undercut the tube surface.

Figure 37-1 Pitting in a carbon steel economizer tube. Pits are covered with caps of corrosion products (arrow). (MAG: 1.6X)


116

Figure 37-2 Cross-section through a pit showing corrosion product cap and corrosion products in the pit.

Source: TR-102433, 1993

Figure 37-9 Pitting on waterwall tube hot side caused by acid phosphate corrosion.

Water-Touched Tubes


• In conventional units, pitting typically occurs where boiler waste stagnates in the tubes during shutdown and/or layup. • In HRSG units, pitting occurs in any component that is intentionally maintained wet during idle periods or that is intended to be dry but is subject to incomplete draining or condensation accumulation. Horizontal tubes are particularly susceptible.


• Improper shutdown/layup procedures also can lead to problems in other areas, such as feed water heaters, condenser, and turbine. Table 37-1 Actions to Confirm and Immediate Actions and Solutions

Major Root Causes Accumulation of stagnant, oxygenated water with no protective environment during shutdown


118

Actions to Confirm • Analyze corrosion products in and around pits, specically looking for presence of hematite. • Perform critical evaluation of shutdownprocedures and of unit condition during shutdown.

Immediate Actions and Solutions • Identify damaged locations. • Replace affected tubes. • Revise shutdown/layup procedures.

Coal Particulate Erosion (Chapter 38) Description

• Wear of surfaces where resistant liners or refractory coatings no longer perform their function. • Failure occurs where the remaining tube wall is insufficient to withstand the normal operating stresses. • Features include wall thinning, external wastage ats, little or no surface ash, a shallow layer of surface hardening caused by the particle impact, and in some case, grooving of the tube surface.


• In cyclone burners, impact of the coal particles entrained in the high velocity combustion air can wear out resistant liners and refractory coatings and erode the subsequently exposed tube surfaces. • Particularly in front- or rear-fired burners, impact of the coal stream, before ignition, erodes the tubes in the throat or quarl region.


• None are identified in the report

Water-Touched Tubes Table Actions to Confirm and Immediate Actions and Solutions

Major Root Causes • In cyclone burners, wear of replacable liners near end of burner and wear of refractories covering waterwall tubes • In front- or rear-red burners, direct impingment of coal stream before ignition in the throat or quarl regions


120

Actions to Confirm • Visual examination of refractory coatings and wear-resistant liners

Immediate Actions and Solutions • Periodic program of inspection and replacement of wearresistant liners and refractory coatings • Adjustment of secondary and tertiary air dampers

Falling Slag (Chapter 40) Description

• If erosion is the form of damage, tube wastage occurs on a progressive basis, leading to a thin-edged ductile failure when the remaining tube wall is insufficient to contain service stresses. • In the form of mechanical damage, impacts can cause breakage of tubes and supports.


• Sloping wall tubes and/or the ash hopper. • Typically, the heaviest damage tends to occur in the first 0.9–1.2 m (3–4 feet) along each end of the furnace bottom opening. • Ash falling from superheater pendents can cause damage to tubes near the center of the boiler. Figure 40-1 Distribution of falling ash along furnace hopper opening. The higher concentrations of falling ash through the first 0.9 to 1.2 m (3 to 4 ft) at each end of the bottom opening result in significant fireside wall thinning.

Source: Combustion Engineering, Inc.

Water-Touched Tubes Table 4 0-1 Actions to Confirm and Immediate Actions and Solutions

Major Root Causes

Actions to Confirm


Falling slag: all causes

• Perform visual inspection of superheater pendents and boiler • Lower boiler load to cause partial freezing and shedding of slag waterwalls. Determine location of damage on slope tubes and or deposits. ash hopper. • Correlate extent of damage with variations in coal quality and boiler operating conditions. • Obtain coal and slag samples for testing. • Perform probe studies to determine the slag potential as a function of time.

Deposition and sloughing of deposits on pendent superheaters

• Evaluate boiler FEGT and changes in fouling. • Examine the morphology of deposits. • Determine the extent of clays in the coal.


122

• Lower FEGT by keeping waterwalls and economizer clean through optimized sootblowing. • Install retractable blowers just below the leading edge of the pendents. • Inject refractory additives to freeze deposits and cause them to slough off before becoming too large. • Inject modifying agent to melt deposits before they become hard.


Major Root Causes Deposition and sloughing of deposits from waterwalls


Actions to Confirm • • • • •

Check mill performance. Inspect boiler condition (tilts, alignment, oxygen levels, etc.). Conrm presence of “popcorn ash.” Evaluate coal and slag samples. Distinguish between boiler operation causes and coal quality causes. • Perform thermoequilibrium modeling.

Immediate Actions and Solutions • Service or adjust mills. • Perform boiler operational checks

Water-Touched Tubes

Acid Dewpoint Corrosion (Chapter 41) Description

• The normal reside oxide scale will typically be thin or absent in the affected regions. • The corroded surface of the tube, after removing fire-side deposits, if any, will have a gouged or orange peel appearance. • The final failure will be over pressurization caused be wall thinning; the fracture will appear thin-edged, transgranular, and ductile. • The presence of sulfur in ash deposits remaining on the tube is likely because the attack is typically by sulfuric acid. A white layer of iron sulfate may be present at the tube to deposit interface.


• Acid dewpoint corrosion will occur in locations where the following occur: – The boiler metal temperatures are below the acid dewpoint, allowing condensation to form on the metal sur face. – Flue gas temperatures are below the acid dewpoint, allowing condensation to form on the fly ash particle. • Oil-red, stoker-red, and cyclone-burner-red (coal) boilers are more likely to experience acid dewpoint corrosion; these types of units produce less fly ash, a product that acts to neutralize any acid formed.

Figure 41-2 Influence of fuel type and sulfur in fuel on the minimum design tube metal temperatures to avoid dewpoint corrosion.

Source: Steam, 1972


124


Major Root Causes

Actions to Confirm

For all root causes

• Examine affected areas for wall thinning (UT thickness testing). • Make the necessary tube repairs.

Economizer tube temperatures below the acid dewpoint

• Measure economizer temperatures and compare to calculated or measured acid dewpoint.

High acid dewpoint caused by fuel or operating choices

• Evaluate dewpoi nt or measure with deposition probes and relate to operating and fuel parameters.

Local air in leakage

• Examine for localized wastage patterns.



• All downstream components such as ductwork, air heaters, ue gas cleaning equipment, and stack are at risk for extensive corrosion damage.

5. Steam-Touched Tubes

Steam-Touched Tubes

Screening Table for Steam-Touched Boiler Tube Failures (Chapter 2) The following table provides information that can be used to perf rom an initial screening of a boiler tube failure to identify a likely degradation mechanism that may have contributed to the failure. The table also includes a reference to the applicable chapter in EPRI report 1012757 for more information on the respective dergardation mechanism. Table 2-2 Screening Table for Water-Touched Boiler Tube Failures



Typical Locations

Possible Mechanism

Chapter in Volume 2

Thick-Edged Fracture Surface Thick-edged

Outside surface initiated, intergranular crack growth with significant microfissuring aligned parallel with the main crack and significant secondary cracking; evidence of grain boundary creep cavitation and creep voids.

Predominant in lower temperature regions in tube bends, particularly at intrados on outside surface, and other locations subject to high residual, forming, or service stresses. Found in the lower temperature regions of the reheater and in primary superheater.


128

Low temperature creep cracking

Chap. 35 Volume 2


Typical Fracture Surface Appearance Thick-edged

Other Likely Macroscopic and Metallographic Features In ferritic materials, thick, internal oxide scales cracked longitudinally (alligator hide appearance); potentially external wastage typically at 10 o’clock and 2 o’clock positions; generally longitudinal (axial) orientation; damage on heated side of tube; microstructural damage by overheat and intergranular or transgranular creep.

Typical Locations Highest temperature locations: near material transitions, where there is a variation in gas-touched length, in or just beyond cavities, in the final leg of tubing just prior to the outlet header.

Possible Mechanism Long-term Overheating (Creep)

Chapter in Volume 2 44

Also longitudinal cracking on austenitic tubing. Thick-edged, leak

Usually fusion line cracking at or near the heat-affected zone on low alloy side of weld, circumferential orientation.

At dissimilar metal welds (transitions between ferritic and austenitic materials)

Dissimilar Metal Weld Failure

47

Thick-edged (may manifest as a pinhole)

Cracking is transgranular or intergranular usually with significant branching; initiation can be at ID (most common) or on OD, circumferential or longitudinal orientation; may involve blowout of window-type pieces. Sometimes around attachments to SH or RH tubing.

Bends and straight tubing with low spots; points with the highest concentration of contaminants; high-stress locations are particularly susceptible at bends, welds, tube attachments, supports, or spacers

Stress Corrosion Crac ki ng

49

Steam-Touched Tubes Table 2-2 (con tinue d) Screening Table for Water-Touched Boiler Tube Failures



Typical Locations

Possible Mechanism

Chapter in Volume 2

Thick-edged

Typically straight, transgranular cracking, OD Tubing-related failures associated with attachments or initiated and associated with tubing (at tube bends bends in tubing; header-related generally at ends of or attachments) or headers (particularly at the header ends).

Fatigue

52

Thick-edged, leak

May have helical fracture path; most commonly Low temperature regions of the SH/RH; adjacent to in HAZ of C or C-Mo steel tubes, although may weld fusion line at heat- affected zone most common also be remote from weld; key is microstructure appearance of graphite particles or nodules.

Graphitization

59

Thick-edged

Brittle fracture; typically ID initiating cracks.

Locations where explosive cleaning has been used

Explosive Cleaning Damage

51

External polishing of tube surface; very localized damage.

Most prominent in backpass regions; bends near to walls

Fly ash Erosion

Chap. 21 Volume 2

Thin-Edged Fracture Surface Thin-edged (unless creepassisted)


130




Typical Locations

Possible Mechanism

Chapter in Volume 2

Thin-edged

External damage; wastage at 10 and 2 o’clock (fluegas at 12 o’clock); longitudinal cracking; perhaps alligator hide appearance; real key to identification will be the presence of low-meltingpoint ash in external deposits.

Highest temperature tubes: leading tubes, near transitions, tubes out of alignment, tubes around radiant cavities

Fireside Corrosion (coal-fired units and oil-fired units)

45 (Coal-fired units) 46 (Oil-fired units)

Thin-edged

Often shows signs of tube bulging or fishmouth appearance, longitudinal orientation.

Most commonly near bottom bends in vertical loops of SH/RH; outlet legs, and near material transitions

Short-Term Overheating

48

Thin-edged, pinhole or thin longitudinal blowout

Wall thinning caused by external wastage flats around tube from sootblower direction; little or no ash deposits on tube.

First tubes in from wall entrance of retractable blowers; tubes in direct path of retractable blowers

Sootblower Erosion

50

Thin-edged

External damage; obvious metal-to-metal contact on tube surface.

Rubbing/Fretting

57

Steam-Touched Tubes Table 2-2 (con tinue d) Screening Table for Water-Touched Boiler Tube Failures



Typical Locations

Possible Mechanism

Chapter in Volume 2

Pinhole Damage Pitting

Internal tube surface damage; distinctive aspect For pitting: Tubes where condensate can form and Chemical Cleaning Damage ratio of damage - deep relative to area; partial or remain during shutdown: bottoms of pendant loops on or Pitting total (through-wall) dissolution of the tube wall metal either SH or RH, low points in sagging horizontal tubes may be observed.

58 or 60

Usually obvious from type of damage and correspondence to past maintenance activity.

61

Various Other Damage Types Depends on the underlying cause


132

Maintenance Damage




Typical Locations

Depends on defect Usually thick-edged or pinholes

Care required to separate weld defects from another problem located at a weld.

Possible Mechanism

Chapter in Volume 2

Materials Flaws

62

Welding Flaws

63

Fly ash Erosion

Chap. 21 Volume 2

Thin-Edged Fracture Thin-edged (unless creepassisted)

External polishing of tube surface; very localized damage.

Most prominent in backpass regions; bends near to walls

Steam-Touched Tubes

Long-Term Overheating/Creep in SH/RH Tubes (Chapter 44) Description Macro Features • Failures are generally longitudinal (axial to tube) and located on the heated side of the tube. • Generally a thick-edged failure corresponding to low ductility. • Reheater tube failures in conventional boilers tend to look more ductile than superheater tube failures due to thinner-walled materials. • Primary evidence of overheat of SH/RH tubes is thickened external scales with Y-shaped grooves that give the appearance of alligator hide. • In ferritic tube materials, particularly in T91 material, indicators include thickened internal oxide scales and longitudinal cracks. Micro Features • Ferritic tubes will exhibit a spheroidized microstructure and creep cavities in the immediate vicinity of the rupture or the part-through-wall cracks. • Austenitic stainless steels will exhibit sigma phase microstructure and grain boundary creep cavities (microvoids).


134

Figure 44-1 Typical appearance of a tube failure by LTOC with axially oriented thick-edged crack.

Figure 44-2 Typical appearance of an LTOC failure in a reheat tube.

Water-Touched Tubes


Locations susceptible to longterm overheating/creep include the following: • Near material changes such as in the middle of at tube circuit just before the change to a higher grade material • Where there is a variation in the gas-touched length among tubes of the same material • In the final leg of tubing just before the outlet header, where steam temperatures are the highest • Tubing nearest to the flue gas inlet, especially for supplementally fired units


136

Figure 44-4 Example of alligator hide appearance of a tube subject to LTOC.

Figure 44-5 Example of wastage flats o n a tube subject to LTOC.

Figure 44-6 Example of spheroidized microstructure and creep cavitation associated with a long-term overheating/ creep failure in 2¼ Cr - 1 Mo material (MAG: 500X, Nital etch).

Source: 1004503, 2002

Figure 44-8 Typical grain boundary creep cavitation/ microcracking at and adjacent to a crack.


Steam-Touched Tubes Table 44-4 Actions to Confirm and Immediate Actions and Solutions

Major Root Causes All causes of overheating


138

Actions to Confirm • Review SH/RH circuit material diagrams, calculate and plot GTL as a function of steam and metal temperatures; plot positions of failures. • Direct measurement of temperatures by thermocouples, especially on new units, prior to there being enough oxide to measure. This is a proactive approach. • Indirect estimation of temperature by steamside oxide scale thickness measurements. • Metallurgical analysis of tube structure,especially for austenitics, and oxide thickness and morphology of selected tube samples. • Visual examination for evidence of slag buildup, laning, bowed, or misaligned tubes acting as leading tubes.

Immediate Actions and Solutions • Make local repairs as appropriate. • Perform selective sampling and/or ultrasonic measurement to determine extent of problem. • Perform remaining life estimate of affected tubes (Chapter 14).


Major Root Causes Initial Design and/or Material Choice • Original alloy choice and extent inadequate for actual operating temperatures. • Inadequate heat treatment of original alloy. • Tubes at failure location have gas-touched lengths (GTL) longer than design estimate and/or row-torow variation in gas-touched length. • Side-to-side or local gas temperature differences. • Radiant cavity heating effects. • Lead tube/wrapper tube material not resistant enough to temperature. Buildup of Steamside Oxide Scale

Actions to Confirm • Perform GTL analysis. • Review temperature data from thermocouples installed in vestibule or across the header.

• Review SH/RH circuit material diagrams, calculate and plot GTL as a function of steam and metal temperatures; plot positions of failures. • Direct measurement of temperatures by thermocouples, especially on new units prior to there being enough oxide to measure. This is a proactive approach • Indirect estimation of temperature by steamside oxide scale thickness measurements. • Metallurgical analysis of tube structure,especially for austenitics, and oxide thickness and morphology of selected tube samples.

Immediate Actions and Solutions • As above.

Steam-Touched Tubes Table 44-4 (con tinue d) Actions to Confirm and Immediate Actions and Solutions

Major Root Causes Restricted Steam Flow due to Chemical or Other Deposits, Scale, Debris, etc.

Actions to Confirm


• Selective sampling of suspect locations to verify whether local blockage is leading to excessive temperatures.

• Clean out tubes and remove source of blockages.

Operating Conditions or Changes in Operation

• Perform metallographic analysis to determine if the tube is overheated or carburized due to delayed combustion.

• Make local repairs as appropriate. • Perform selective sampling and/or ultrasonic measurement to determine extent of problem. • Perform remaining life estimate of affected tubes. • See long-term action.

Previous similar problems in adjacent SH/RH

• Check temperature distribution through the circuit by performing analysis of GTL and measured temperatures.

• As above.

(This can cause short-term overheating as well – see Chapter 48).


140


Major Root Causes

Actions to Confirm

Combustion conditions • Excessive ue gas temperature • Displaced reball • Delayed combustion • Periodic overring or uneven ring of fuel burners

• Metallographic analysis. • Monitor gas temperatures with pyrometers or infrared instruments.

Blockage or Laning of Boiler Gas Passages

• Can be recognized using cold air velocity technique. • Visual examination to identify local ow blockages.

Thinned Tube Wall • Wrong wall thickness tube installed. • Tube wall thinned by a wastage mechanism, such as sootblower erosion or fly ash erosion.

• NDE evaluation to determine the wall thickness. • If another mechanism is suspected, initiate actions to conrm their involvement.

Immediate Actions and Solutions • As above, plus: – Restore boiler design (or optimized) conditions.

• Check short-term actions for wastage mechanisms: reside corrosion (Chapters 45 and 46), sootblower erosion (Chapter 50), or fly ash erosion (Chapter 21).

Steam-Touched Tubes Table 44-6 Potential Ramifications

Long-Term Overheating Aspect


Actions Indicated

Tube overheating as evidenced by buildup of internal oxide scale

• Potential for exfoliation of oxide from ferritic materials, which can carry over into turbine sections. • Exfoliating scale from austenitic materials can lead to tube blockage and failures by short-term overheating (see Chapter 48).

• Chemical cleaning of SH/RH sections. • Monitoring plan to assess the severity of oxide buildup in affected tubes, including UT inspection for direct measurement of oxide scale and tube sampling to confirm type and extent of scale.

Tube overheating as evidenced by buildup of internal oxide scale

• SH/RH tubes are more susceptible to damage from reside corrosion if coal is corrosive.

• Correct cause of overheating if possible; upgrade to more resistance materials as required.

Total redesign of the superheater or reheater

• May change absorption patterns through the SH/RH sections and may increase temperatures in other circuits.

• Check temperatures in the redesigned section and other sections.


142

Figure 44-9 Schematic representation of steamside oxide thickness versus tube wastage (wall loss). Such a plot can be used to distinguish between long-term overheating/creep and fireside corrosion mechanisms. [1 in. = 25.4 mm].

Source: TR-102433, 1993

Steam-Touched Tubes

Fireside Corrosion in SH/RH Tubes (Chapter 45) Description

• Typically, multilayered fireside scale and ash deposits that are generally tightly bound to tubes at room temperatures and will typically consist of three layers 1. A hard, brittle, and porous outer layer, which makes up the bulk of the deposit and has a composition similar to that of boiler y ash. 2. A white intermediate layer consisting of compounds of complex alkali sulfates, including alkali iron trisulfates. When this layer has a chalky consistency, corrosion has been found to be mild or nonexistent; when fused and semi-glossy, corrosion has been found to be severe. 3. A black, glossy inner layer, composed primarily of oxides, sulfates, and suldes of iron. • Tube wastage will often be evident and manifested as at spots on the tube at the 10 o’clock and 2 o’clock positions (12 o’clock is the upstream position). • Fireside corrosion damage will be primarily distinguished from long-term overheating by the presence of low melting point ash compounds. • Greatest wall loss will generally be seen in tubes that have been operated at the highest temperatures over a period of time.


144

Figure 45-1 Schematic representation of fireside corrosion development for superheaters and reheaters involving a molten interme diate layer (alkalis, sulfates). This case shows maximum wastage at the 10 and 2 o’clock positions.

Figure 45-2 Tube sample exhibiting fireside corrosion. Note the presence of multilayered scale along with wastage flats at the 10 and 2 o’clock positions of the tube’s circumference.

Source: TR-102433, 1993

Steam-Touched Tubes


Corrosion will generally be the worst in the highest temperature locations. Parts at highest risk therefore include the following: • Leading sides of all tubes in pendant platens, especially hottest (leading) tubes and steam outlet tubes. • Tubes out of alignment that act as leading tubes. • Tubes in the outlet (final) sections towards the header, because these are at the highest temperatures. • Just prior to a change of material, e.g., in T22 just prior to the austenitic material, as the lower Cr content. material may be operating above its design point. • Wrapper tubes. • Tubes that surround a radiant cavity (i.e., they may pick up more heat). • At bottom bends of platens, especially those facing the fireball. • Tubes with a longer GTL. (GTL is the distance measured along the tube circuit from the inlet header to the point of corrosion. See long-term overheating, Chapter 44.) • Spacers and uncooled hangers and the fins and studs on tubes.


146

Figure 45-6 Typical locations where fireside corrosion can occur. Figure 45-3 Two tube sample segments showing fireside corrosion. The left shows the ash pattern as removed; the r ight shows the tube with the ash removed. On this segment, the 12 o’clock position shows a smooth contour typical of a fluxing fireside corrosion reaction, and the 10 and 2 o’clock positions show alligator hide, here indicative of long-term overheating/creep.

Steam-Touched Tubes Table 45-2 Actions to Confirm and Immediate Actions and Solutions

Major Root Causes

Actions to Confirm


For all root causes of fireside corrosion

• Collect and evaluate ash and deposits to identify presence of low melting point constituents, particularly alkali iron trisulfates. • Use corrosion probes to monitor deposit compositions and wastage. • Use NDE measures (typically UT) to identify wall thinning.

Influence of overheating of tubes (These root causes will only increase the corrosion rate, – not initiate it, unless there is a corrosive coal)

• Measure steamside oxide thicknesses and evaluate whether • As above. overheating has occurred. • Perform selective tube sampling and metallurgical analysis to confirm steamside oxide and wall thickness. • Monitor temperatures using thermocouples installed across the SH/ RH outlet legs in vestibule to identify hottest platens across the boiler

Poor initial design: choice of material

• Evaluate temperatures across the element (via thermocouple or steamside oxide measurements) to determine if sections particularly near material changes are running too hot.


148

• Choose repair strategy based on severity of corrosion rate. • Implement long-term actions in conjunction with on-going program of remaining life assessment and monitoring.

• As above; primary emphasis on upgrading to a more resistant material.


Major Root Causes

Actions to Confirm


Poor initial design: extra gas-touched length

• Evaluate temperatures across the element (via thermocouple or steamside oxide measurements) to determine if sections particularly near material changes are running too hot. See discussion of gas-touched length in Chapter 44 for long-term overheating.

• As above

Internal oxide growth which occurs during operation

• Measure oxide scale thickness and use selective sampling to c onfirm the results.

• As in primary list above (repairs followed by long-term strategy) plus chemical cleaning of steamside scale.

High temperature laning

• Monitor temperatures. • Consider the use of the cold air velocity technique. See Chapter 21, Volume 2, on fly ash erosion for a discussion of the technique.

• As in primary list above (repairs followed by long-term strategy).

Tube misalignment (out of bank)

• Visual examination.

• Realign tubes; implement ongoing program of remaining life assessment and monitoring.

Operational problems when coal type is changed

Rapid startups causing reheater to reach temperature before full steam flow

• Evaluate whether operating procedures such as sootblowing can be economically changed to protect SH/RH tubes. • Check startup probe and that initial gas is limited to 1000°F (538°C) prior to RH flow.

• Modify startup procedures if feasible.

Steam-Touched Tubes Table 45-2 (cont inued ) Actions to Confirm and Immediate Actions and Solutions

Major Root Causes Root Causes Related to Fuel Factors • Use of, or change to, fuel with corrosive ash, particularly those with high S, Na, K, or Cl

Root Causes Related to Combustion

Use of low NOX combustion systems


150

Actions to Confirm


• Evaluate coal composition using corrosivity index. • As in primary list above (repairs, followed by long-term actions). • Analysis for low melting point of ash components using probes. • Analysis of metallurgical cross-sections, particularly for Cl, S, C, Na, and K. • Install continuous readout corrosion sensors if unit switches coal or uses spot market coal • Choose repair strategy based on severity of corrosion rate. • Implement long-term actions from choices in Figure 45-12 in conjunction with ongoing program of remaining life assessment and monitoring • Monitor for levels of O2, CO, H2S, and HCl along damaged or • As above, plus: susceptible locations. – Increase combustion air to avoid reducing conditions (however • Establish a combustion uid dynamics model and use the model to may increase corrosion by other mechanisms, and may evaluate potential improvements in combustion parameters. adversely affect NOX control).


Maj ajo or Root Cause sess

Acti Ac tion onss to to Con Confir firm m

Imme Im medi diat ate e Act Actio ions ns an and d Solutions

Use of startup oil, which coats • Check for for unburnt the tube and leads to tube startup oil deposits on carburization tubes. Excess of unburnt or partially burnt particles leading to an increase in carburization

°F = (°C x 1.8) + 32) 1nm = 0.00004mils 1mil = 0.025nm

• Perform metallurgical • Adjust mills to decrease examination, including grind size. evaluating carbides, and • Increase combustion air to check for phase avoid reducing conditions transformations. (however, (howev er, this may increase • Perform microhardness t corrosion by other traverses. mechanisms and may • Evaluate carbon prole prole adversely affect NOX control). if necessary. • Decrease amount of • Check for for ferromagnetic sootblowing to help keep response. oxide layer intact (by decreasing thermal changes to tube surface).

Figure 45-11 The linear dependence of corrosion rate on coal chlor ine content for UK coals and austenitic steels. 50 nm/hr is approximately 18 mils/yr. Superheater corrosion as a function of coal chlorine content.

Source: Gibb, 1983


Aspect of SH/R Aspect SH/RH H Alert for Other Cycle Cycle Fireside Corrosion Components

Actions Indicated Indicated

Corrosive coal

• Potential for waterwall fireside corrosion • Potential for back-end corrosion

• Develop a reside testing program using guidance such as provided in the fireside testing guidelines (CS-5552, 1988). • Investigate coal changes with Vista Fuel Quality Impact Model (Vista, 2006) or equivalent, including economics evaluation. • Mitigate negative aspects of coal composition if possible by fuel switch, blending, or washing

Poor combustion conditions

• Low unit efciency • Poor mill performance

• Combustion adjustments to improve unit efficiency. See guidance in (CS-5552, 1988). • Correct mill performance.


152

Figure 45-4 Grooving of the tube’s external surface, known as alligator hide, here associated with coal ash corrosion. The fireside oxide scale and ash deposit have been removed by glass bead blasting.

Source: TR-102433, 1993

SH/RH Fireside Corrosion (Chapter 46) Description

• The tube will usually be coated with multilayered fireside scale and ash deposits that typically consist of two layers: 1. A hard, brittle, and and porous porous outer layer, which may have alternating alternating dark/black/blue dark/black/b lue and light bands 2. A black, glossy inner layer layer.. If this layer is glassy or shows signs of having been molten against the tube metal, then a very fast corrosion rate has probably occurred. The absence of a layer of protective oxide adjacent adjacent to the tube surface is indicative of the fastest corrosion rates. • Tube wastage will often be evident and manifested as undulations and unevenness of the tube surface. • Fireside corrosion damage will be primarily distinguished from long-term overheating by the presence of low melting point ash compounds. • Greatest wall loss will generally be seen in tubes that have been operated at the highest temperatures over a period of time.

Figure 46-1 General appearance of a 9% Cr final superheater tube containing fireside corrosion deposits (top of the figure) in an oil-fired boiler after 50,000 hours of service. The bottom of the figure shows a section of tubing having been acid cleaned to remove the deposits, and the ring section taken through the cleaned section shows the general appearance of tube wastage on the outside surface.


Steam-Touched Tubes


Corrosion will generally be the worst in the highest temperature locations. Parts at highest risk therefore include the following: • Leading sides of all tubes in pendant platens, especially hottest (leading) tubes and steam outlet tubes. • Tubes out of alignment that act as leading tubes. • Tubes in the outlet (final) sections towards the header, because these are at the highest temperatures. • Just prior prior to a change change of mater material, ial, e.g., e.g., in T22 just prior prior to to the austeni austenitic tic material, as the lower Cr content. material may be operating above its design point. • Wrapper tubes. • Tubes that surround a radiant cavity (i.e., they may pick up more heat). • At bottom bends of platens, especially those facing the fireball. • Tubes with a longer GTL. (GTL is the distance measured along the tube circuit from the inlet header to the point of corrosion. See long-term overheating, Chapter 44.) • Spacers and uncooled hangers and the fins and studs on tubes.


154

Figure 46-4 Typical boiler locations where oil ash fireside corrosion can occur.


Major Root Causes

Actions to Confirm


For All Root Causes of Fireside Corrosion

• Ash and deposit analysis to identify presence of low melting point constituents, par ticularly vanadium/vanadiumsodium and sodium sulfate complexes. • NDE measures (typically UT) to identify wall thinning and steamside oxide scale buildup.

• Choose repair strategy based on severity of corrosion rate. • Implement long-term actions in conjunction with ongoing program of remaining life assessment and monitoring.

Oil Composition

• Monitor oil corrosiveness using corrosion or deposition probes. • As above, plus: • Analyze ash deposits. – Ongoing consideration of the use of Mg-based additives.

Overheating of Tube Excessive temperatures caused by steamside oxide buildup

• NDE of steamside oxide thicknesses. • Choose repair strategy based on severity of corrosion rate. • Selective tube sampling and metallurgical analysis to conrm • Implement long-term strategy in conjunction with ongoing steamside oxide and wall thickness. program of remaining life assessment and monitoring. • Monitoring of thermocouples installed across the SH/RH outlet • Institute periodic chemical cleaning. legs in vestibule to identify hottest platens across the boiler.


Major Root Causes Excessive temperatures as caused by operating conditions, such as the following: • High temperature laning of gases • Changes in absorption patterns between furnace and convection sections • RH overheating because of rapid startups • Tube misalignments

Actions to Confirm


• For high temperature laning: monitor temperatures as in (g) above and consider the use of the cold air velocity technique (CAVT). Details of the latter can be found in Chapter 21, Volume 1 on fly ash erosion. • For reheater overtemperature during start sequences: check the startup probe and limit temperatures to 538°C (1000°F) prior to RH flow. • Visual inspection can be used to detect tube misalignments.

• Modify operation to correct the specic problem. • Implement long-term strategy in conjunction with ongoing program of remaining life assessment and monitoring.

• Check operating logs for typical excess oxygen levels.

• Modify operating procedures, if economically feasible to reduce levels of excess oxygen. • Implement long-term strategy in conjunction with ongoing program of remaining life assessment and monitoring.

Operating Factors Operation with high levels of excess oxygen and/or periods of very low excess oxygen


156


Major Root Causes Poor sootblowing operations

Actions to Confirm • Check sootblowing frequency, effectiveness, and superheat level of blowing medium.

Immediate Actions and Solutions • Evaluate whether operating procedures such as sootblowing can be economically changed to protect SH/RH tubes. • Implement long-term strategy in conjunction with ongoing program of remaining life assessment and monitoring.

Excess of unburnt or partially burnt Particles leading to • Perform metallurgical examination, including evaluating carbides, • Increase combustion air to avoid reducing conditions (however, an increase in carburization and check for phase transformations. may increase corrosion by other mechanisms, and may adversely • Perform microhardness traverses. affect NOX control). • If necessary, evaluate carbon prole. • Decrease amount of sootblowing to help keep oxide layer intact • Check for ferromagnetic response. (by decreasing thermal changes to tube surface).


SH/RH Fireside Corrosion Aspect


Actions Indicated

Use of additives

• Mg-based additives can coat the waterwalls of the furnace and • Monitor unit for signs of detrimental effects of additives. cause a reflection of heat into the convective passes. This could lead in turn to higher temperatures for SH and/or RH tubes and an increase in boiler tube failures by long-term overheating (see Chapter 44). • Additives can also cause increased erosion of burner components and additive transport lines.

Tube overheating because of excessive steamside oxide

• Potential for additional tube failures by longterm overheating • Chemically clean unit if necessary mechanism. • Exfoliation of scale with subsequent carryover into turbine could lead to solid particle erosion. • Exfoliation could lead to tube blockage and additional SH/RH failures by a short-term overheating mechanism (Chapter 48).

Total redesign of the superheater or reheater

• Would change absorption patterns through the SH/RH sections and may increase temperatures in other sections.


158

• Check temperatures in the redesigned and other areas.

Dissimilar Metal Weld Failures (Chapter 47) Description Macro Features • Thick-edged fractures with signs of low ductility. • Circumferential cracking in the ferritic material. • Located near a dissimilar metal weld. • Formation of an oxide notch on the outside surface of the tube in the ferritic material. • Flat, featureless fracture surface (typical of induction welds). • Cracking following fusion line (typical of fusion welds). • Failures may be associated with bent tubes or other signs of overstressing

Figure 47-1 Typical appearance of a cracked dissimilar metal weld.

Steam-Touched Tubes Table 47-2 Distinguishing Features (Microscopic) of Failures in Fe-Based Stainless Steel and Ni-Base Filler Metals of DMW

Characteristic

Iron-Base Stainless Steel Filler Metal

Nickel-Base Filler Metal

Location of cracking within HAZ (generally)

• Along prior austenite grain boundaries approximately 1–2 grain diameters from fusion line

• Immediately along weld interface associated with carbide precipitation and creep cavitation

Carbide morphology

• Generally Type II

• Generally Type I

Nature of carbide

• Dif fuse array of smaller carbides

• Planar array of glob ular carbides

Do carbides encourage interfacial growth?

• No

• Yes

Creep voids associated with this carbide type?

• No

• Yes

Carbon activity gradient of filler with ferritic material?

• Higher than for Ni-base llers

• Lower than Fe-base llers

Thermal expansion with ferritic materials

• Along prior austenite grain boundaries approximately 1–2 grain diameters from fusion line

• Immediately along weld interface associated with carbide precipitation and creep cavitation

Time to final failure

• Generally Type II

• Generally Type I

Note: Induction-welded DMW will have similar properties to those listed for Fe-based fusion welds above.


160

Figure 47-2 Typical cross-sectional appearance of a dissimilar metal weld failure after longtime boiler service. This example is a DMW with stainless steel filler metal. Note the oxide notch on the OD and the intergranular cracking adjacent to the weld line.

Source: TR-102433, 1993

Figure 47-3 Further detail of the intergranular creep cracking adjacent to a pressure weld. Note that the cracking is oriented normal to the hoop stress.

Source: D. French

Figure 47-4 Detailed metallographic appearance of cracking along the weld fusion line associated with a line of carbides. This is typically observed in dissimilar metal welds made with nickel-base filler metals.

Steam-Touched Tubes


• Dissimilar metal welds (DMW) between ferritic steels and austenitic stainless steels. • Welds made by induction process have properties similar to those for fusion welding with austenitic filler. • DMW are more suceptible to failure than like material welds due to the following differences: – Thermal expansion – Creep behavior of the joined materials – Local metallurgical cchanges at the low alloy to weld metal interface • DMW are located in the superheater, reheater, vestibule, and penthouse regions of the boiler.


162


Major Root Causes

Actions to Confirm


Excessive tube stresses such as caused by improper initial design or improper tube supports • Locating the DMW near the roof, furnace wall, or other fixed points or near to the header • Weld placement in the middle of a long span • Inadequate allowance for thermal expansion • Support failures or slag accumulation leading to constraint of thermal expansion

• Visual examination of the unit to determine whether there are • Determine the extent of damage through (i) visual examination suspect locations or evidence of a problem such as bent tubes, to detect adjacent locations with obvious signs of distress, (ii) warpage of tubes, misalignment, or missing or broken specialized radiography, (iii) oxide scale measurements and supports. analysis, and (iv) selective sampling as required for confirmation. • Perform a stress analysis of suspect locations. Piping stress • Repair damaged locations using either a shop welded codes can be used to determine both primary and secondary “dutchman” (preferred) or in situ weld repair wit h nickel-base stresses. filler metal. • Implement additional weld changes: (i) optimize weld geometry, (ii) make welds in vertical runs not horizontal runs of tubing, and (iii) avoid post-weld heat treatment

Excessive local tube temperatures • Tube temperatures above those anticipated in the design • Variation across the SH/RH

• Conduct a GTL analysis up to the DMW. • As above. • Review of available vestibule thermocouple data for indicatio ns of overheating. • Perform oxide scale thickness evaluation, including ultrasonic measurement, and analysis of results.

Changes in unit operation • To increased unit cycling • Change of fuel causing increased tube temperatures • Redesign of adjacent SH/RH that results in higher tube service temperature

• Review operating records with an eye toward conditions that may have increased either tube stresses or temperatures.

• As above.


Major Root Causes Initial fabrication defects

Actions to Confirm • Metallographic samples should be used to evaluate whether initial weld defects, such as incomplete fusion or lack of penetration, are a contributing cause.

Immediate Actions and Solutions • As above.


DMW Aspect


Actions Indicated

Tubes are being subjected to temperatures in excess of • Possibility of additional tube failures by mechanisms such as those that were expected by the design. long-term overheating/creep (Chapter 44) or fireside corrosion (Chapter 45 or 46)

• Evaluate sources of overheating and determine what control measures are possible to prevent future failures. • Consider installation of additional thermocouples or instituting periodic oxide scale surveys via UT to monitor tube temperature progression.

Redesign of SH/RH has changed absorption pattern within convective pass.

• Ensure that the locations of DMW are known and that the ramifications to them by any redesign of an adjacent SH/RH section are known.


164

• Potential for overheating in other sections, which might include a DMW

Short-Term Overheating in SH/RH Tubing (Chapter 48) Description Macro Features • Visual appearance can be misleading. • Tube swelling and fish-mouth rupture are much less distinct than observed in non-finned tubes. • Typically a thin-edged, ductile final failure. • Failures can appear as pinhole leaks. Micro Features • Fracture mode will typically be transgranular creep. • If the short-term overheating temperature is less than the lower critical temperature of th e metal (subcritical), the microstructure wil exhibit ferrite and moderate to severely spheroidized carbides in ferritic tubing. In HRSGs without auxillary ring, only subcritical short-term overheating is possible. • Overheating at temperatures above the lower critical temperature but less than the upper critical temperature (intercritical) will be indicated by transformation of the orignal pearlite, bainite, or martensite to austenite. Localized regions of transformation products indciate flame impingement or l ocalized fluid side deposits. Gradulal change in microstructure indicates inadequate fluid flow or other causes were active. • Supercritical overheating (temperature greater than upper critical temperature) will cause essentially the entire microstructure to transform to austenite

Steam-Touched Tubes


Locations susceptible to short-term overheating include: • Tubing downstream of bends and other locations where exfoliated debris, condensate, etc. can accumulate and cause a blockage • Tubing nearest to the gas inlet, especially for supplementally fired units

Figure 48-2 Fish-mouth appearance typical of failures by shor t-term overheating. ELECTRIC POWER RESEARCH INSTITUTE

166

Source: Austra Electric, Australia


Major Root Causes Tube Blockage Caused by Exfoliated Oxide in SH tubes

Actions to Confirm


• Remove damaged tube to conrm source of blockage. Metallurgical examination may be required. See Chapter 12, Volume 1, for an overview of such techniques. • Examine for signs of exfoliation in unit, such as outbreaks of SPE in the turbine. • Perform NDE, such as radiography, for other locations of similar blockage. • For austenitic materials, a hand-held magnet will detect spalled oxide in bends.

• NDE to determine blocked tubes. • Removal of bends with blockages. • Blow out debris and replace tubes or, if solid, remove bends and replace tubing. • An interim solution can be to change operating procedures to limit temperature transients if the problem is exfoliation in austenitic material; especially important is to minimize forced or rapid cooldowns. • Increase frequency of cooldowns so as to trigger more frequent exfoliations of less quantity of material (for units that run for long periods of time without shutdown).

• Remove damaged tube to conrm source of blockage. Metallurgical examination may be required. See Chapter 12, Volume 1, for an overview of such techniques. • Review chemical cleaning procedures. See Chapter 9, Volume 1, for additional discussion.

• As above for tube blockages, plus: – Clean out tubes and remove source of blockages

Maintenance-Induced Short- Term Overheating in SH or RH Improper chemical cleaning: • Of SH/RH: poor ushing procedures left deposits in bends. • Of waterwalls: volatility of chemicals getting into SH circuits or poor backfilling of SH.


Major Root Causes Improper repairs, miscellaneous maintenance shortcomings

Actions to Confirm • Review repair records and correlate to locations of failures.

Immediate Actions and Solutions • Replace tubing.

Operation-Induced Short-Term Overheating in SH or RH Improper shutdown and startup of unit (condensate collection in SH/RH bends

• Check thermocouples in outlet; determine whether tubes are running cold because of no flow. • Review shutdown procedures; determine whether proper procedures have been employed to boil out any condensate.

• Replace tubing.

Overfiring when a top feedwater heater is out of service

• Review operating logs of feedwater heater operation and service.

• Replace tubing and perform NDE of adjacent areas.


168

Figure 48-4 Bottom bend and debris causing blockage in a conventional unit.

Source: Austra Electric, Australia


Short-Term Overheating Aspect Presence of thick and exfoliating oxide


Actions Indicated

• Potential for solid particle erosion damage to begin in turbine • Chemical cleaning of boiler. See Chapter 9, Volume 1. components. • Remnant life assessment using oxide technique. • Potential for long-term overheating of SH/RH tubes and loss of tube life.

Figure 48-10 Appearance of thick-section fish-mouth f ailure in Type 304 superheater tube.


170

Stress Corrosion Cracking in Steam-Touched Tubes (Chapter 49) Description Macro Features • Stress corrosion cracking (SCC) fractures are typically thick-edged, brittle failures. • May ofter involve blowout of small “window-type” pieces. • May be a pinhole leak. • Cracking will form perpendicular to ddominant stress and may have significant branching. • Can initiate on ID or OD of tube. Micro Features • Crack propagation can be transgranular or intergranular. • Transgranular cracking often exhibits branching.


• More often occurs in austenitic stainless steels. • Typical locations are those with potential for highest concentration of contaminants, such as bends and low spots in straight tubing where condensate can form during shutdown. • High stress locations, such as bends, welds, tube attachments, supports or spacers, and near welds where a change of thickness occurs are susceptible.

Steam-Touched Tubes

Figure 49-1 Cracking of SA-213 Type 304H base material near the edge of a weld backing bar in a dissimilar metal weld joint. This tube contained through-wall cracks after a few weeks of service. The corrodent causing the cracking was suspected to be a petroleum-based preservative which was not effectively flushed from the weld backing rings prior to service.


172

Figure 49-2 Intergranular stress corrosion cracking (IGSCC) of an SA-213 Type 304H reheater tube. Away from the rupture, the IGSCC was limited to the tube’s inside surface. Carryover of chlorides was believed to have been the corrodent responsible for the cracking.

Source: TR-102433, 1993


Major Root Causes

Actions to Confirm

Influence of environment, mainly contamination from: • Carryover of chlorides or sulfates from the chemical cleaning of waterwalls • Boiler water carryover • Volatile carryover of sulfurcontainingcompounds • Introduction of high levels of caustic from desuperheating or attemperator spray • Condenser cooling water constituents from a condenser leak • Fireside contaminantssuch as polythionic acid • Ingress of ue gas environment into tube through primary failure, especially in RH when vacuum is drawn

• Analyze steamside fracture surfaces and oxide deposits for presence of contaminant species such as chlorides. • Analyze reside deposits for indications of aggressive corrodents. • Review chemistry records, monitoring records, etc. for indication of source of contamination. Perform carryover test. See main text for additional discussion on this point. • Review recent chemical cleaning operations, either waterwalls or SH/RH circuits, for potential sources of contamination. • Review polisher operation for leakage of chloride and/or sulfate.

Immediate Actions and Solutions • Institute repair and replacement as required. • Clean up sources of contamination, if possible. For example, reclean SH/RH circuits if improper flushing of solvents is underlying cause.

Steam-Touched Tubes Table 49-1 (cont inued ) Actions to Confirm and Immediate Actions and Solutions

Major Root Causes

Actions to Confirm


Influence of Excessive Stresses • Fabrication/welding/heat treatment residual stresses • Service stresses, especially at attachments and supports

• Visual examination for signs of obvious distress, such as broken or missing attachments or supports, etc. • Review manufacturing process details to evaluate whether proper heat treatment/annealing procedures were used. • Review eld welding procedures for details of post-weld heat treatment.

• Repair any obvious contributors to excess stress levels. • Ensure that any redesign of supports, etc. will actually lower the imposed stress.

Influence of Susceptible Material • Tube materials which can sensitize during service (Type 300 stainless steels)

• Perform a metallurgical examination to determine whether sensitization developed in service or was present as a result of the fabrication process used. • Test the material for baseline susceptibility using ASTM Standard Practice A262. • Analyze the chemical composition of the failed material to see if the proper material was used.

• Consider replacement of material with a stabilized grade of stainless steel.

• Sulfate and chloride leakage from condensate polishers


174


• Contamination that has caused SCC in the SH or RH tubes may cause significant damage to other parts of the unit, especially the steam turbine

Figure 49-3 View of the top tubes on the upper bank of the reheater showing the failure, which was located in an area away from stress concentrations (such as welds or bends). Figure 49-4 Closeup view of the damaged location indicating the window-type blowout of a section of tube.

Steam-Touched Tubes

Sootblower Erosion in SH/RH Tubes (Chapter 50)


Description

• Wall thinning caused by external tube sur face wastage • Little or no ash deposits or protective oxide on the tube • Appearance of gouges on external tube surface where eddying of the stream occurs between adjacent tub • Wastage flats on the tube sur face from the direction of impact from the sootblower with severity of wastage decreasing with distance from the sootblower • Formation of fresh rust only a few hours after boiler washing


Typical failure locations for sootblower erosion in the SH/RH include those that: • Are the first tubes in from the wall entrance of the retractable blowers. • Are in the direct path of the retractable blowers. ELECTRIC POWER RESEARCH INSTITUTE

176

Figure 50-1 Superheater tube that failed because of sootblower erosion. Note wastage flats and absence of ash deposits.

Source: TR-102433, 1993


Major Root Causes Improper Maintenance of Sootblowers such as: • Incorrect setting and conrmation of blowing temperature (insufficient superheat) • Improper operation and maintenance of moisture traps • Misalignment of sootblower

Improper Operation of Sootblowers such as: • Condensate in blowing media • Excessive sootblowing pressures • Improper location of sootblower • Malfunction of sootblower • Excessive sootblowing

Actions to Confirm • Use visual examination to determine location and obvious maintenance shortcomings or blower problems. • Measure key parameters such as: – Blowing temperature and pressure – Operation of moisture traps

• As above, plus measure key operating parameters such as checking travel and sequence times.

Immediate Actions and Solutions • Evaluate the extent of wall thinning and erosion damage to determine whether repairs or replacements are required. • Execute the applicable repairs or replacements. • Avoid the use of temporary measures such as pad welding, shielding, and/or coatings unless they are absolutely required to get the unit to the next scheduled outage. • Repair sootblower inadequacies or maintenance shortcomings. • As above.

Steam-Touched Tubes

Explosive Cleaning Damage in SH/RH (Chapter 51) Description

• Explosive cleaning used in cases of extreme ash deposition on the gas passages of superheater pendent sections. • Explosive impact can induce high strains in the metal leading to immediate brittle fracture failure or to progressive degradation of the base metal resulting in failure during subsequent cleaning. • May cause exfoliation of tube ID scales that could lead to short-term overheating (Chapter 48).

Actions to Confirm and Immediate Actions and Solutions

• Recommended that ash deposition problems be resolved prior to reaching point at which explosive cleaning is required. • As a minimum, utilities using explosive cleaning processes need to have specications in place to detail the allowable practices.


178

Figure 51-1 Longitudinal split in the superheat pendent tube. Figure 51-2 Closeup of the split showing the thick-edged fracture surface. Figure 51-3 Cross-section through the leak. No significant wall thinning or tube deformation was present.

Steam-Touched Tubes

Thermal-Mechanical and Vibration-Induced Fatigue in Steam-Touched Tubes (Chapter 52) Description

• Failures in bends, particularly U-bends, can be initiated on the intrados, extrados, or neutral axis. • Failures in U-bends usually occur in the cooler (below creep temperature) regions of the primary SH or RH.

Macro Features • Thick-edged failures. • Circumferential cracking initiated on OD. • Appearance of beach marks is typical, but they may be obliterated by oxidation. Micro Features • Predominately straight transgranular cracks. • Cracking may be intergranular when occurring in creep-damaged materials. • Depending on service conditions, the cracks may be lled with oxides.


• Typical locations for fatigue failure include: – Attachments, particularly solid attachments or jammed sliding attachments – Bends in tubing • Often associated with welds, particularly where the weld or condition of the attachment does not allow for thermal expansion. ELECTRIC POWER RESEARCH INSTITUTE

180

Figure 52-1 Thermal-mechanical fatigue failure of an SA 213 Type 304H superheater tube. The portion of the rupture that is missing was believed to have contained a welded attachment clip.

Source: TR-102433, 1993


Major Root Causes

Actions to Confirm


Excessive strains caused by constraint of thermal expansion.

• Visual examination for distortion or bending in adjacent tubes. • Identify similar damaged locations. • Strain gauging of suspect locations to evaluate strains during • Repair/replace affected tubes. unit starts and cycling operation. • LVDT measurements to monitor the relative movement of the header/tube during transients.

Poor design and/or manufacture giving rise to excessive mechanical stresses.

• Strain gauging to measure actual strains experienced at the local area during operation. • LVDT measurements to monitor the relative movement of the header/tube during transients. • For tight, hairpin bends, determine whether residual stresses are high.

• As above

Vibration (flue-gas-induced) by direct flow or vortex shedding.

• Metallurgical examination to conrm high cycle fatigue. • Estimate natural and forcing frequencies and conrm by test.

• As above

Poor welding, particularly poor geometry of final joint.

• Visual and microscopic examination of weld quality.

• As above


Steam-Touched Tubes

Figure 52-3 Three possible locations for tubing-related fatigue failures in tight 180° bends. Figure 52-2 Schematic showing typical locations of fatigue f ailures in steam-touched tubing.

Source: Dooley, 1983 ELECTRIC POWER RESEARCH INSTITUTE

182

Figure 52-5 Schematic illustrating failures due to inflexibility of movement between steam header and waterwall.

Figure 52-4 Fatigue tube failures caused by differential thermal expansion of e lement transfer tubes on a header.

Source: Sylvester, 1978

Steam-Touched Tubes

Rubbing/Fretting (Chapter 57) Description

• Smooth wastage ats on the reside of the tube; ash and reside oxide scale may be missing. • Rubbed area may exhibit a concave shape that matches the prole of the adjacent tube. • Occurs where adjacent tubes come into direct metal-to-metal contact. Metal loss results from rubbing/fretting and be accelerated oxidation of the tube surface where the protective iron oxide is removed by the rubbing/fretting.

Actions to Confirm and Immediate Actions and Solutions

• Root causes may include (i) misaligned, nonfucntioning, broken, or inadequate tube supports or (ii) misaligned rubbing. • Repair or replace damaged tube. • Repair or replace defective or inadequate supports and correction misalignment.


184

Figure 57-1 Region of a tube surface where rubbing occurred (arrow). Note the smooth appearance and absence of a fireside scale in this region. (MAG: 1.3X)

Figure 57-2 Side view of the rubbed area. Note the concave surface formed as a result of the rubbing. (MAG: 1.3X)

Source: TR-102433, 1993

Source: TR-102433, 1993

Steam-Touched Tubes

Pitting in Steam-Touched Tubes (Chapter 58) Description • • • •

Pitting is associated with exposure to stagnant, oxygen-saturated water formed during shutdown. Pits can be numerous and closely spaced or isolated. Pits usually covered with caps of corrosion product (tubercles or nodules). Pits may undercut the tube surface. Figure 58-1, Figure 58-2 Superheater inlet heater drain with a failure at the neutral axis. The tube was resting flat on a horizontal suppor t at this location resulting in oxygen-saturated water remaining in the tube during shutdown periods of the unit. Typical pitting on the ID surface of the tube is shown at the right.



186


• Pitting occurs in any component that is intended to be dry but is subject to incomplete draining or condensation accumulation, such as the bottoms of pendent loops.


• Improper shutdown/layup procedures also can lead to problems in other areas, such as feedwater heaters, condenser, and turbine. Table 58-2 Actions to Confirm and Immediate Actions and Solutions

Major Root Causes

Actions to Confirm


Accumulation of stagnant, oxygenated water with no protective environment during shutdown

• Analyze corrosion products in and around pitting, specically • Identify damaged locations. looking for presence of hematite. • Replace affected tubes. • Perform critical evaluation of shutdown procedures and of unit • Revise shutdown/layup procedures. condition during shutdown. Check logs of chemistry monitoring during shutdown.

Carryover of (Ca,Na)2SO4 (Drum and once-through boilers)

• Analyze corrosion products, in this case, specically looking • As above, plus: for a confirmation of (Ca,Na)2SO4. – Execute any obvious mechanical repairs such as damage to • Review drum condition and operation for carryover. drum furniture, sources of air in leakage, etc. • Review steam composition, particularly evaluating for excesses of Na, SO4, and Cl.

Steam-Touched Tubes

Graphitization (Chapter 59) Description

• Occurs most commonly in the heat affected zones (HAZ) of welds in carbon or carbon molydenum low alloy steel. • Microscopically, the damage is manisfested by brittle fracture along a line of graphite nodules (often termed “chain” graphitization) that forms along the HAZ. • Failure is usually circumferential and parallel to the weld, but it can folllow any line of graphite formation. • Thick-edged, brittle failure.


• Most prevalent in the low temperature portions of the superheater and reheater • Can occur over long periods of exposure to temperatures in the range of 450–700°C (~840–1290°F)


188

Figure 59-2 Closeup of graphitization damage. Figure 59-1 Failures of tubes by graphitization. Note the almost helical nature o f the fractures.

Steam-Touched Tubes Table Actions to Confirm and Immediate Actions and Solutions

Major Root Causes All causes


• Metallurgical examination on samples removed from service to • Replace or repair damaged tubes. characterize the appearance of graphitization. • Identify those similar locations or welds that may also be at risk • Bend testing of removed samples. Since graphitization results given the failures experienced. in embrittled material, a bend specimen can be used to determine qualitatively whether significant damage has accumulated. A 45° bend at failure is taken as indicative of severe graphitization damage and a 90° bend of mild damage. • Fracture toughness testing on miniature specimens removed from suspect locations. A method t o remove small samples from components for fracture testing using miniature specimens has been developed (McMinn, 1988). These tests are harder to apply and interpret than bend testing but provide a more quantitative approach to flaw tolerance.

Potential Ramifications • None for this mechanism. ELECTRIC POWER RESEARCH INSTITUTE

190

Actions to Confirm

Chemical Cleaning Damage in SH/RH Tubes (Chapter 60) Description

• Generalized corrosion of affected tube sur faces. • Affected surface can appear as localized jagged, rough, straight-sided, or undercut pits or as generalized wall thinning that can occur around the entire tube circumference.


Improper operations of the chemical cleaning process, including: • Use of inappropriate cleaning agent, inhibitor, or other chemical • Excessively strong acid concentration • Excessively long cleaning times • Too high a temperature • Failure to neutralize, drain, and rinse properly after cleaning


• Exfoliation of steamside oxides not loosened and removed by the chemical cleaning process can lead to solid particle erosion (SPE) in the turbine. • Oxide scale loosened but not removed can cause SPE or tube blockage when it releases. • Potential for SH/RH short-term overheating due to blockage or long-term overheating (creep) if the scale is not removed.

Steam-Touched Tubes Table Actions to Confirm and Immediate Actions and Solutions

Major Root Causes • • • • •

Use of an inappropriate cleaning solvent. Excessively strong acid concentration. Excessively long cleaning times. Too high a temperature. Failure to neutralize, drain, and rinse after cleaning. • Failure to monitor Fe levels during the cleaning. • Fe levels were monitored but did not level out during the cleaning. • Breakdown of inhibitors as a result of temperature excursions.


192

Actions to Confirm


• Review of chemical cleaning procedures,chemical pumping • Repairing or replacing the damaged tubes systems, and chemical control logs. Items of particular concern • Immediate chemical cleaning followed by proper neutralizing are those listed above, which would lead to significant and rinsing damage. • Review of cycle chemistry monitoring records to detect a pH depression on startup of the unit after cleaning, indicating improper rinsing of acid from the unit. • Sampling of affected tubes to allow examination of the inside surface for evidence of generalized corrosion. Part of an optimized procedure for chemical cleaning will be sampling of selected tubes to confirm the efficacy of the cleaning process. These samples can be used to determine whether excessive damage has accumulated. Wall thickness measurements can provide a quick screening as to whether excessive tube corrosion has occurred.

Maintenance Damage (Chapter 61) Description and Contributing Causes

Tube damage can be introduced during the maintenance activity, mostly as a result of the maintenance cleaning of the gas side of the tubing. Typical Typ ical of the damage that can be done to tubing during maintenance operations are as follows: • Wall thinning by excessive application of high pressure steam, water, or abrasive slurries used in the cleaning process • Impacts to tubes from projectiles • Damage to tubes by mishandled or improperly applied tools • Damage incurred during a repair

Quality control measures such as (i) preparatio preparationn of cleaning procedures and (ii) training of personnel can minimize the possibility of damage occurring during the maintenance procedure. Inspection of tubing following cleaning and testing for integrity, such as with hydrostatic testing, are recommended recommended..

Actions to Confirm and Immediate Immediate Actions and Solutions If damage is found immediately following the suspect maintenance, then the confirmation of root cause is straightforward; it is done by comparing the tube damage to type of equipment or process used in the recently completed maintenance. Damage Damage found some time later may take somewhat more analysis to tie it back to a prior operation. Repair and replacement decisions will depend on the severity of the damage. Cracks and punctures will require immediate repair. Gouges, dents, or thinned tubes should be subjected to a fitness-for-service evaluation on a case-by-case basis.

Figure 61-1 Cross-section of a tube near a rupture; deformation was caused by the impact of an explosive charge.

Source: TR-102433, 1993

Steam-Touched Tubes

Material and Manufacturing Flaws (Chapter 62) Description and Contributing Causes

Examples of material aws include such possibilities as: • Defects introduced into the tube during its manufacture, fabrication, fabrication, storage, and/or installation. Such defects might include (CS-3945, 1985): – For Forgi ging ng lap laps. s. – Inclusi Inclusions ons or laminatio laminations ns in the metal. – Lack of fusion of the welded seams. – Deep tool marks or scores from tube piercing, extrusion, or rolling operations. – Gouges, punctures, corrosion, corrosion, or or impact impact dents. • Use of the wrong tube material caused by errors in design, supply, storage, storage, and stockroom exchange or issue.


194

Examples of manufacturing aws include the following: • Fabrication lap - may include such features as orientation in the tube’s forming direction rather than perpendicular perpendicular to the tube service ser vice stress, decarburization and/or inclusions along the lap surface, branching, and secondary laps along the tube length. Stress corrosion cracking of U-bends caused by inadequate heat treatment - Excessive residual stresses originating from manufacturing of u-bends in SH wrapper tubes made of Type 347 H led to failures by stress corrosion cracking. The solution annealing heat treatment was inadequate for completely relieving the tensile stresses that originated in the bending process. • Unfused membrane weld - during manufacture, if the process leaves unfused material between the n and tube sur face, small initial cracks are introduced by the lack-of-fusion or introduced into the martensitic heat-affected zone during lifting of the panels during manufacture. These cracks propagate in service and result in a “window pane” failure where the failure occurs along the membrane line. The affected tube areas are large and can result in a significant release of water or steam on final rupture. The problem is overcome by using full penetration fusion welds.

Figure 62-5 Materials flaws can be introduced by the original fabrication process. Here an electric resistance weld used to join a tube to a membrane results in a lack of fusion region. Subsequent handling during manufacture can introduce cracks in the weld heat-affected zone (HAZ), which has a martensitic zone.

Source: Flatley, 1995

Steam-Touched Tubes

Welding Defects (Chapter 63) Table 63-1 Welding Practices as Contributors to Various Tube Failures

Weldin We lding/Re g/Repair pair Prac Practice tice/Pro /Problem blem

Potential Tu Tube be Failure

Weld spatter or cutting debris left in tubes; improperly executed weld repairs that leave material in tubes.

Tube blockage leading to short-ter m overheating failures in SH/RH tubes (Chapter 48)

Stress Str ess ris riser er cause caused d by the toe toe of a fillet fillet weld weld or impro improper per geom geometry etry to a weld weld repa repair ir..

Mechan Mec hanical ical fat fatigu igue e failu failures res nea nearr tubin tubing g attachm attachment entss in SH/R SH/RH H tubes tubes (Ch (Chapte apterr 52)

Weld and attachment design can lead to constraint of thermal stresses and is a contributor to tube failure.

Contributor to excessive stresses that can cause mehanical fatigue (Chapter 52)

Imprope Impr operly rly exe execut cuted ed ind induct uction ion pre pressu ssure re wel welds ds betw between een dis dissim simila ilarr metal metalss in in SH/R SH/RH. H.

Direct Dir ect cau cause se of dis dissim simila ilarr meta metall weld weld fai failur lures es (Ch (Chapt apter er 47)

Welding procedures can lead to sensitization of material, or weld defects act as an initiation site for stress corrosion cracking


196

Stress corrosion cracking (Chapter 49)

Generally, planar or “sharp” defects such as cracks, lamellar tears, lack-of-fusion, and lack-of-penetration are the most likely to grow into cracks and propagate to final failure, particularly in the high residual stress fields that remain after the welding process. Often, metallurgical analysis is needed to determine whether a welding problem has been at the root cause of a tube failure. A review of the welding process, welder qualification records, inspection records, and weld material control reports may also provide an indication about whether a weld process error is responsible for an observed failure.

Avoiding Weld-Related Weld-Related Damage

• Detection of a weld shortcoming, once the joint has been placed in service, is difficult. Avoiding Avoiding weld failures is therefore mostly preventive. • Solution of welding-defect-induced tube failures will consist of removing the problem areas and re-welding with proper techniques. References for welding in conventional units (1004701, 2003) have been developed.

Steam-Touched Tubes Figure 63-2 Example of a poorly executed pad weld, which led to tube failure.

Figure 63-1 Example of a pad weld made on a tube with corrosion fatigue; the process extended the corrosion fatigue crack. ELECTRIC POWER RESEARCH INSTITUTE

198

BTF Issues in Bubbling Bed FBCs (Chapter 64) Table 64-1 Overview of Boiler Tubing Failure Mechanisms in Bubbling Bed Fluidized-Bed Combustors

Mechanism

Prevalence to Date

For More Information, Refer to:

Wastage of in-bed tubes

Major industry concern; severity highly variable between units; mitigation options established

Chapter 64 (this chapter).

Underdeposit corrosion (internal), particularly caustic gouging and hydrogen damage

Several incidences known, including tube leaks in as short a period as 500 hours of operation

Discussed in this chapter, see also primary discussions in caustic gouging (Chapter 24, Volume 2) and acid phosphate corrosion (Chapter 23, Volume 2).

Fretting

Few incidences reported to date

Tube rubbing/fretting (Chapter 57).

Corrosion in austenitic tubing of superheaters and reheaters

None known to date; potential ramification to consider if caustic is used

Corrosion fatigue

Concern based on knowledge of conventional plant and similarities with aspects of FBC designs.

Fly ash erosion of convective steam sections

A few incidences known in non-coal-fi red (agricultural waste) units. Fly ash erosion (Chapter 21, Volume 2).

See chapter on corrosion fatigue (Chapter 19, Volume 2).

Steam-Touched Tubes

Figure 64-1 Schematic of a bubbling-bed boiler.

Source: J. Makansi, “Special Report: Fluidized Bed Boilers,” Power, March 1991. Reproduced with permission. ELECTRIC POWER RESEARCH INSTITUTE

200

Figure 64-2 A horizontal bottom tube from an atmospheric fluidized bed. The tube experienced caustic corrosion at the 12 o’clock position due to steam blanketing and additional heat transfer through the top rib. Tube leaks occurred after only 500 hours of operation.

Table 64-2 Actions to Confirm and Immediate Actions and Solutions Mechanism: In-Bed Wastage of FBC Tubes

Major Root Causes

Actions to Confirm


Susceptible material

• Visual and UT inspection to determine extent of problem.

• Upgrade material by armoring. • Upgrade material through chromizing, nitriding, or other surface protection, alone or in conjunction with armoring.

Fuel factors • Excessively hard particles • Excessively angular or sharp-edged particles • High chlorine content • High alkali contents

• Evaluate ash and erosive/abrasive content of fuel. Compare to • Determine quartz content and assess fuel’s erosive/abrasive design coal. potential. • Metallographic analysis of tube deposits and bed materials may provide indicators of key contaminants.

Local jetting or flow characteristics that result from blockage of air distributor nozzles and/or from agglomeration of particles in the bed

• Determine whether there has been a change in pressure drop across the air distributor plate,or across the bed as a whole (depends on what instrumentation is used).

Steam-Touched Tubes Table 64-3 Actions to Confirm and Immediate Actions and Solutions Mechanism: Underdeposit Corrosion in the In-Bed Tubes of FBC Units

Major Root Causes Excessive deposits due to steam blanketing

Underdeposit corrosion: influence of poor water chemistry • Contaminated ingress • Use of mono- or di-sodium phosphate • Use of an excess of caustic


Actions to Confirm

• Analysis of results from chemistry monitors, mainly for levels of • Chemically clean to remove excessive levels of deposits. See Fe and Cu. guidance in (1003994, 2001) and summary in Chapter 9, • NDE examination and selective sampling of tubes for deposit Volume 1. measurements. • Check efcacy of chemical cleaning. • Check circulation ratio and conrm that tube ows are outside regime of DNB. • Perform metallurgical analysis of tube samples to determine nature and extent of tube deposits. • Perform metallurgical examination of damaged tubes, particularly to determine composition of deposits. • Analyze cycle chemistry data: plant chemistry control logs, on-line cycle chemistry records, chemical additions to boiler, and instrumentation alarms.

See appropriate chapters; otherwise there are none for these mechanisms. ELECTRIC POWER RESEARCH INSTITUTE

202


• As above, plus: - Move to optimum cycle chemistry as detailed in (1004187, 2002; 1004188, 2004)

BTF Issues in Circulating Bed FBCs (Chapter 65) Table 65-1 Overview of Boiler Tubing Failure Mechanisms in Circulating Bed Fluidized-Bed Combustors

Mechanism

Prevalence to Date

For More Information, Refer to:

Underdeposit corrosion in horizontal tubes of external Some occurrences in external heat exchangers heat exchangers or cyclone separators in some designs

Same mechanism in BFB units; also chapters on underdeposit corrosion in conventional plants, partic ularly hydrogen damage (Chapter 22, Volume 2), acid phosphate corrosion (Chapter 23), and caustic gouging (Chapter 24).

Wast age on water wall tubes at t he refractor y lining

Mos t prevalent mat er ial l oss mec hanism

Main t ext in t his c hapt er (Chapter 64).

Fly ash erosion of tubes in convection steam sections

Has also occurred with agricultural waste-fired units

See discussion of fly ash erosion in Chapter 21, Volume 2.

Corrosion fatigue

Concern based on knowledge of conventional plants and similarities with aspects of FBC designs, especially if pH depressions occur in units on phosphate t reatment with hideout and return

See Chapter 19, Volume 2, on corrosion fatigue.

Steam-Touched Tubes


Two problems have been found in CFB units that are somewhat different from those in conventional plants: • Erosion/abrasion on waterwall tubes, particularly at the interface between the refractory lining on the lower portions of the bed and the waterwall tube panels – Wear has, in some cases, been extremely rapid, e.g., maximum loss rates up to 1800 mils per year (5200 nm/hr). – Because the problem is not uniform around the walls, inspections to determine the extent of damage must be as comprehensive as possible. – Corrective/preventive acitons have included (i) applying proprietary coatings, (ii) installing shelves above the refractory interface, (iii) reducing the angle of the tapered region, and (iv) routing the affected tubes outside of the bed. • Potential for damage to external heat exchangers or in the cyclone separator by mechanisms such as wastage, fretting, and fatigue; a particular concern is waterside corrosion in CFB units with horizontal tubes in these areas. – The potential for horizontal tubing to develop excessive deposits and for concentration of control chemicals (caustic or phosphates) within the deposits has been extensively discussed in Chapter 64 on BFB. The mechanism, root causes and actions for preventing the development of underdeposit corrosion in susceptible CFB locations are identical.


204

Figure 65-2 Typical wear pattern on the waterwall above the refractory lining in circulating fluidized-bed units.

Source: Stringer, 1991

Figure 65-1 General schematic of a circulating fluidized bed.

Adapted from E. Bretz, Power, 133, No. 3, 1989, p. W-8. Reproduced with permission.

Steam-Touched Tubes

BTF Issues in Waste-to-Energy Units (Chapter 66) Description and Contributing Causes

• Fuel composition in waste-to-energy (WTE) units has a major impact on the nature and extent of tube failures. • High levels of chlorine (from PVC and NaCl), as well as alkalis such as Pb, Zn and Sn can lead to formation of aggressively corrosive low melting point compounds. • Non-optimal (either oxidizing or substoichiometric) combustion conditions caused by the diverse nature of the fuel exacerbates the reside corrosion problems. Some examples include: Water-Touched Tubes • Waterwall thinning along grate line from mechanical wear/corrosion* • Mechanical wear from molten aluminum • Wastage from direct flame impingement on waterwalls • Fireside corrosion caused by low-melting-point chlorides and sulfates* • Fireside corrosion by combustion gases* • Erosion caused by high local velocities and carryover of particles (economizer)* ELECTRIC POWER RESEARCH INSTITUTE

206

Steam-Touched Tubes • Fireside corrosion caused by low-melting-point chlorides and sulfates* • Fireside corrosion by combustion gases* • Erosion from excessive sootblowing required by slagging of superheater tubes* • Fouling that results in flow-channeling, high local velocities, and subsequently to excessive erosion rates* • Flame impingement from furnace in older units with shor t furnace zones • Pitting (external) from aqueous corrosion during unit downtime Notes: 1. * Indicates mechanisms that are specically discussed in Chapter 66. 2. Not all designs have all these problems; some of the problems are also specific to older designs, and prevention has been achieved by various approaches

116379556-EPRI-Field-Guide-for-Boiler-Tube-Failures.pdf

Recommend Documents