EPRI Boiler Condition Assessment Guideline 4 Edition

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Boiler Condition Assessment Guideline Fourth Edition

Technical Report

Effective December 6, 2006, this report has been made publicly available in accordance with Section 734.3(b)(3) and published in accordance with Section 734.7 of the U.S. Export Administration Regulations. As a result of this publication, this report is subject to only copyright protection and does not require any license agreement from EPRI. This notice supersedes the export control restrictions and any proprietary licensed material notices embedded in the document prior to publication.

Boiler Condition Assessment Guideline Fourth Edition 1010620

Final Report, June 2006

EPRI Project Manager R. Tilley

ELECTRIC POWER RESEARCH INSTITUTE 3420 Hillview Avenue, Palo Alto, California 94304-1395 • PO Box 10412, Palo Alto, California 94303-0813 • USA 800.313.3774 • 650.855.2121 • [email protected] • www.epri.com

DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS AN ACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCH INSTITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THE ORGANIZATION(S) BELOW, NOR ANY PERSON ACTING ON BEHALF OF ANY OF THEM: (A) MAKES ANY WARRANTY OR REPRESENTATION WHATSOEVER, EXPRESS OR IMPLIED, (I) WITH RESPECT TO THE USE OF ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT, INCLUDING MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE, OR (II) THAT SUCH USE DOES NOT INFRINGE ON OR INTERFERE WITH PRIVATELY OWNED RIGHTS, INCLUDING ANY PARTY'S INTELLECTUAL PROPERTY, OR (III) THAT THIS DOCUMENT IS SUITABLE TO ANY PARTICULAR USER'S CIRCUMSTANCE; OR (B) ASSUMES RESPONSIBILITY FOR ANY DAMAGES OR OTHER LIABILITY WHATSOEVER (INCLUDING ANY CONSEQUENTIAL DAMAGES, EVEN IF EPRI OR ANY EPRI REPRESENTATIVE HAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES) RESULTING FROM YOUR SELECTION OR USE OF THIS DOCUMENT OR ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT. ORGANIZATION(S) THAT PREPARED THIS DOCUMENT EPRI Bevilacqua-Knight, Inc.

NOTE Requests for copies of this report should be directed to EPRI Orders and Conferences, 1355 Willow Way, Suite 278, Concord, CA 94520, (800) 313-3774. Electric Power Research Institute and EPRI are registered service marks of the Electric Power Research Institute, Inc. Copyright © 2006 Electric Power Research Institute, Inc. All rights reserved.

CITATIONS This report was prepared by EPRI Charlotte Office 1300 W.T. Harris Blvd. Charlotte, NC 28262 Principal Investigator R. Tilley Bevilacqua-Knight, Inc. 1000 Broadway, Suite 410 Oakland, CA 94607 Principal Investigator E. Worrell This report describes research sponsored by the Electric Power Research Institute (EPRI). The report is a corporate document that should be cited in the literature in the following manner: Boiler Condition Assessment Guideline: Fourth Edition. EPRI, Palo Alto, CA, 2006. 1010620.

iii

REPORT SUMMARY

Because boiler component failures are the most common cause of unplanned outages in fossil steam plants, a cost-effective condition assessment program is an important element of any operation plan that considers use of demanding operating modes. Condition assessment involves determining which components are most vulnerable, inspecting these components, estimating their remaining life, making a run-repair-replace decision, and choosing an optimal re-inspection interval. This report provides an overview of guidelines developed by EPRI to help power plant operators cost-effectively determine extent of degradation and predict the remaining life of key boiler components. Background EPRI published the first edition of the Boiler Condition Assessment Guideline in 1998. Subsequent updates of the Guideline further addressed a number of issues, including considerations for safely extending outage intervals, cycling, low-NOX operation, and firing low grade and off-design fuels. The current revision updates and refines the third edition, adding recent research results and guidance on boiler components not explicitly addressed in previous versions, namely deaerators, feedwater heaters, and superheater crossover piping. Increased emphasis is placed on identifying and mitigating root causes before damage occurs or progresses. For many fossil plants, today’s market-driven operating practices expose boiler components to conditions not anticipated in their design. Competitive markets value a plant’s ability to change output quickly to match load with demand. Plants must maintain high reliability and availability while using operating modes, such as load-following and nighttime turndown to very low loads, that introduce rapid and cyclic temperature and furnace chemistry changes that can exacerbate damage mechanisms. Lengthened intervals between major maintenance outages provide less opportunity to inspect and repair or replace damaged components. At the same time, budgetary pressure continues to force plants to do more with less. Objective To provide an overview of guidelines developed by EPRI to help power plant operators costeffectively determine the extent of degradation and remaining life of key boiler components. Approach These guidelines draw from EPRI’s detailed, area-specific guidelines, which in turn are based on extensive research findings by EPRI, EPRI contractors, EPRI member companies, and other organizations. EPRI research reports and software provide a sound technical basis for performing condition assessment activities for boiler components. This Guideline consolidates EPRI’s extensive research findings addressing failure modes and condition assessment tools and practices for major boiler components. Reference citations provide direction to the more detailed information in the EPRI reports on which the Guideline is based. v

Results This Guideline provides a starting point for power plant personnel to develop condition assessment programs for specific boiler components, based on boiler type, history, and modes of operation. The Guideline features the EPRI-recommended three-level approach to condition assessment. The iterative character of this approach allows plants to match the level of condition assessment efforts with their need and value. The Guideline is organized by major boiler component. It covers tubing, high-temperature headers, drums, economizer headers, piping, valves and attemperators, and feedwater heaters, deaerators, and blowdown vessels. Each chapter begins with discussion the relationship between damage mechanisms and specific design details and operating conditions for the subject component. A generic or component-specific “roadmap” shows the connections between recommended condition assessment activities based on EPRI’s three-level approach. Tables provide key supporting information. References to EPRI’s detailed guidelines are provided in each chapter and in the appendices. This Guideline, and the more detailed guidelines referenced in it, provide a systematic approach to help managers: •

Prioritize condition assessment expenditures

•

Estimate the remaining life of damaged components

•

Make better run-repair-replace decisions

•

Establish cost-effective maintenance re-inspection intervals

•

Make unit deployment decisions that more accurately consider maintenance impacts of different operating modes.

EPRI Perspective This Guideline provides an overview of remaining life estimation procedures used to support maintenance decisions, preserve asset value, and guide deployment decisions. It serves as an entrée to a family of EPRI reports that provide detailed background and procedures for damage characterizations and inspection recommendations for key boiler components. In addition, the Guideline identifies actions that can mitigate or prevent future damage from occurring in boiler components. This approach has been successfully demonstrated in past EPRI programs on boiler tube failures. Keywords Fossil fuel power plants Condition assessment NDE Remaining life Boiler tube failures High-energy piping

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ABSTRACT

This report (Boiler Condition Assessment Guideline) provides a concise overview of procedures developed by EPRI to help power plant operators cost-effectively determine the extent of degradation and remaining life of key boiler components. The Guideline draws from EPRI’s detailed area-specific guidelines, which in turn are based on extensive research findings by EPRI, member companies, and other organizations. This Guideline offers a starting point for power plant personnel to develop condition assessment programs for specific boiler components. The Guideline is organized by major boiler component. It covers tubing, high-temperature headers, drums, economizer headers, piping, valves, attemperators, and low-temperature vessels and piping. The Guideline reviews the relationship between damage mechanisms and design details and operating conditions for each major boiler component and provides a “roadmap” of recommended condition assessment activities based on EPRI’s three-level approach to condition assessment. This approach allows plant personnel to match the level of condition assessment efforts with their need and value. Additional information on typical damage mechanisms for each component type, suitable nondestructive evaluation techniques, life assessment software, and damage prevention is provided to support the roadmaps. References are provided to more detailed guidelines and source material for specific components, failure modes, and condition assessment tools and practices.

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ACKNOWLEDGMENTS

Rich Tilley of EPRI provided essential material for the technical updates embodied in this fourth edition of the Boiler Condition Assessment Guideline.

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CONTENTS

1 OVERVIEW AND STRATEGY FOR BOILER CONDITION ASSESSMENT .........................1-1 1.1

Introduction ..................................................................................................................1-1

Approach ..........................................................................................................................1-1 Industry Environment........................................................................................................1-1 1.2

Condition Assessment Fundamentals .........................................................................1-2

1.3

The Condition Assessment Program Plan ...................................................................1-6

1.4

Impact of Operational Trends ......................................................................................1-7

Cycling..............................................................................................................................1-8 Low-NOX Operation ..........................................................................................................1-8 Off-Design and Low-Grade Fuels.....................................................................................1-9 Considerations for Extending Outage Intervals ................................................................1-9 1.5

Evaluation and Repair Technology ............................................................................1-10

NDE Inspection and Monitoring Tools ............................................................................1-10 Analysis Tools ................................................................................................................1-11 Repair Tools ...................................................................................................................1-11 1.6

Life Optimization by Design .......................................................................................1-12

Design for Condition Assessment ..................................................................................1-12 Inherently Reliable Design..............................................................................................1-12 1.7

Structure of this Guideline .........................................................................................1-13

1.8

Resources and References Overview .......................................................................1-15

2 BOILER TUBING....................................................................................................................2-1 2.1

Programmatic Approach ..............................................................................................2-1

2.2

Condition Assessment Roadmap for Boiler Tubing .....................................................2-2

2.3

Example Case Actions for Corrosion-Fatigue..............................................................2-4

Actions 1A and 1B: Initial Evaluation................................................................................2-4 Action 2: Determine/Confirm That the Mechanism Is Corrosion-Fatigue .........................2-5 Action 3: Determine Root Cause of Corrosion-Fatigue ....................................................2-6

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Action 4: Determine the Extent of Damage or Affected Areas .........................................2-7 Action 5: Implement Repairs, Immediate Solutions, and Actions .....................................2-8 Action 6: Implement Long-Term Actions to Prevent Repeat Failures...............................2-8 Action 7: Determine Possible Ramifications or Ancillary Problems ..................................2-9 2.4

Waterwall Tubing .......................................................................................................2-10

Damage Mechanisms for Waterwall Tubing...................................................................2-10 NDE and Sample Evaluation Options for Waterwall Tubing...........................................2-26 Analysis and Disposition for Waterwall Tubing...............................................................2-29 Preventive Actions for Waterwall Tubing........................................................................2-31 2.5

Superheater/Reheater (SH/RH) Tubing.....................................................................2-37

Damage Mechanisms for SH/RH Tubing .......................................................................2-38 NDE and Sample Evaluation Options for SH/RH Tubing ...............................................2-63 Analysis and Disposition for SH/RH Tubing ...................................................................2-65 Preventive Actions for SH/RH Tubing ............................................................................2-68 2.6

Economizer Tubing ....................................................................................................2-75

Damage Mechanisms for Economizer Tubing................................................................2-76 NDE and Sample Evaluation Options for Economizer Tubing .......................................2-88 Analysis and Disposition for Economizer Tubing ...........................................................2-90 Preventive Actions for Economizer Tubing.....................................................................2-92 2.7

References for Boiler Tubing .....................................................................................2-96

3 HIGH-TEMPERATURE STEAM HEADERS ..........................................................................3-1 3.1

Damage Mechanisms for High-Temperature Steam Headers.....................................3-2

3.2

Condition Assessment Roadmap for High-Temperature Headers...............................3-4

3.3

NDE and Sample Testing for High-Temperature Headers ........................................3-10

3.4

Analysis and Disposition for High-Temperature Headers ..........................................3-13

Using BLESS for Creep and Fatigue Crack Growth Prediction......................................3-14 3.5

Preventive Actions for High-Temperature Steam Headers........................................3-15

3.6

References for High-Temperature Steam Headers ...................................................3-17

4 STEAM AND LOWER DRUMS ..............................................................................................4-1

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4.1

Damage Mechanisms for Drums .................................................................................4-1

4.2

Condition Assessment Roadmap for Drums................................................................4-3

4.3

NDE Options for Drums ...............................................................................................4-5

4.4

Analysis and Disposition for Drums .............................................................................4-7

4.5

Preventive Actions for Drums ......................................................................................4-9

4.6

References for Steam and Lower Drums...................................................................4-11

5 ECONOMIZER HEADERS .....................................................................................................5-1 5.1

Damage Mechanisms for Economizer Headers ..........................................................5-1

5.2

Condition Assessment Roadmap for Economizer Headers.........................................5-4

5.3

NDE Options for Economizer Headers ........................................................................5-7

5.4

Analysis and Disposition for Economizer Headers ....................................................5-10

5.5

Preventive Actions for Economizer Headers .............................................................5-12

5.6

References for Economizer Headers.........................................................................5-14

6 MAIN STEAM AND HOT REHEAT PIPING ...........................................................................6-1 6.1

Damage Mechanisms for High-Energy Piping .............................................................6-2

6.2

Condition Assessment Roadmap for High-Energy Piping ...........................................6-5

6.3

Inspection Techniques – NDE and Sample Testing ..................................................6-10

6.4

NDE Monitoring Techniques ......................................................................................6-14

6.5

Analysis and Disposition for High-Energy Piping.......................................................6-15

Using BLESS for Crack Growth Prediction and Remaining Life Analysis ......................6-15 6.6

Preventive Actions for High-Energy Piping ................................................................6-17

6.7

References for Main Steam and Hot Reheat Piping ..................................................6-18

7 COLD REHEAT AND SUPERHEATER CROSSOVER PIPING ............................................7-1 7.1

System Evaluation Approach for CRH and SHXO Piping............................................7-2

7.2

Damage Mechanisms for CRH and SHXO Piping .......................................................7-3

7.3

Application of Three-Level Condition Assessment Approach ......................................7-6

Level I Evaluation – Pre-Outage.......................................................................................7-9 Level II Evaluation – On-Pipe Inspections During Outage .............................................7-16 Level III Evaluation – Enhanced NDE and Sampling .....................................................7-19 7.4

NDE Options for CRH and SHXO Piping...................................................................7-22

7.5

Preventive Actions for CRH and SHXO Piping ..........................................................7-23

7.6

References for CRH and SHXO Piping .....................................................................7-24

8 ATTEMPERATORS (DESUPERHEATERS)..........................................................................8-1 8.1

Considerations for Attemperators and Downstream Impacts ......................................8-1

8.2

Damage Mechanisms in Spray Attemperator Systems ...............................................8-3

8.3

Condition Assessment Roadmap for Attemperator Systems.......................................8-5

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8.4

NDE Options for Attemperator System Components...................................................8-8

8.5

Analysis and Disposition for Attemperator System Components...............................8-10

8.6

Preventive Actions for Attemperators and Adjacent Components .............................8-13

8.7

References for Attemperator Systems.......................................................................8-15

9 VALVES..................................................................................................................................9-1 9.1

Damage Mechanisms Involving Valves .......................................................................9-2

9.2

Condition Assessment Roadmap for Valves................................................................9-5

9.3

NDE Options for Valve Components ...........................................................................9-8

9.4

Analysis and Disposition for Valves ...........................................................................9-10

9.5

Preventive Actions for Valves and Adjacent Components.........................................9-12

9.6

References for Valves................................................................................................9-14

10 DEAERATORS, FEEDWATER HEATERS, AND BLOWDOWN VESSELS .....................10-1 10.1

Damage Mechanisms for Low-Temperature Vessels and Piping .........................10-2

Deaerators......................................................................................................................10-2 Feedwater Heaters .........................................................................................................10-3 Feedwater and Attemperator Supply Piping...................................................................10-3 Drain Piping, Vent Piping, and Blowdown Vessels.........................................................10-3 Extraction Steam Piping .................................................................................................10-3 10.2

Roadmap for Low-Temperature Vessels and Piping ............................................10-6

10.3

NDE Options for Low-Temperature Vessels and Piping .......................................10-8

10.4

Analysis and Disposition for Low-Temperature Vessels and Piping ...................10-11

10.5

Preventive Actions for Low-Temperature Vessels and Piping ............................10-13

10.6

References for Low-Temperature Vessels and Piping........................................10-15

A DAMAGE MECHANISM ABSTRACTS ................................................................................ A-1 Corrosion (General).............................................................................................................. A-1 Gas-Side Mechanisms ......................................................................................................... A-2 Fireside Corrosion ........................................................................................................... A-2 Waterwall Wastage with Low-NOX Combustion............................................................... A-3 Flow-Accelerated Corrosion (FAC) ...................................................................................... A-3 Single-Phase FAC ........................................................................................................... A-3 Two-Phase FAC .............................................................................................................. A-4 Corrosion (Under-deposit and Pitting).................................................................................. A-5

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Acid Phosphate Corrosion (Phosphate Hideout and Return) .......................................... A-5 Caustic Gouging .............................................................................................................. A-5 Chemical Cleaning Damage............................................................................................ A-6 Hydrogen Damage .......................................................................................................... A-6 Pitting............................................................................................................................... A-7 Fatigue ................................................................................................................................. A-8 Corrosion-fatigue ............................................................................................................. A-8 Thermal Fatigue .............................................................................................................. A-8 Fireside Erosion and Wear................................................................................................... A-9 Coal Particle Erosion ....................................................................................................... A-9 Fly Ash Erosion ............................................................................................................... A-9 Rubbing/Fretting ............................................................................................................ A-10 Sootblower Erosion ....................................................................................................... A-10 Microstructural Damage ..................................................................................................... A-11 Graphitization ................................................................................................................ A-11 Fabrication Flaws ............................................................................................................... A-12 Material Flaws ............................................................................................................... A-12 Welding Flaws ............................................................................................................... A-12 Overheating........................................................................................................................ A-13 Creep (Long-Term Overheating) ................................................................................... A-13 Short-Term Overheating................................................................................................ A-13 Supercritical Waterwall Cracking................................................................................... A-14 B NDE AND SAMPLING METHOD ABSTRACTS .................................................................. B-1 B-1

NDE Techniques .................................................................................................... B-1

Acoustic Emission ........................................................................................................... B-4 Eddy Current Testing....................................................................................................... B-4 EMAT (Electromagnetic Acoustic Transducer)................................................................ B-4 Magnetic Particle Testing (MT)........................................................................................ B-5 Liquid Penetrant Testing (PT).......................................................................................... B-5 Replication....................................................................................................................... B-5 Radiographic Testing (RT) .............................................................................................. B-6 Ultrasonic Testing (UT).................................................................................................... B-7 Advanced Ultrasonic Examination................................................................................... B-7 Linear Phased Array ................................................................................................... B-7

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Time-of-Flight Diffraction............................................................................................. B-8 B-2

Sample Evaluation Techniques.............................................................................. B-8

C RESOURCES AND REFERENCES ..................................................................................... C-1 C-1

EPRI Software for Condition Assessment.............................................................. C-1

C-2

EPRI Program Support .......................................................................................... C-2

C-3

EPRI Reports ......................................................................................................... C-3

Boiler Condition Assessment and Component Life Management ................................... C-3 Boiler Tube Failures ........................................................................................................ C-3 Cycle Chemistry, Corrosion, and Deposition................................................................... C-5 Materials, Damage Mechanisms, Welding, and Repair Techniques ............................... C-6 Nondestructive Evaluation, Sample Testing, and Analysis ............................................. C-8 Operations, Maintenance, and Design Considerations ................................................... C-9 C-4

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Other References................................................................................................. C-11

LIST OF FIGURES Figure 1-1 General Procedure for Boiler Component Life Assessment .....................................1-5 Figure 2-1 General Condition Assessment Roadmap for Identifying, Evaluating, and Anticipating BTF.................................................................................................................2-3 Figure 3-1 Condition Assessment Screening Questions for High-Temperature Steam Headers..............................................................................................................................3-5 Figure 3-2 Level I Life Assessment Roadmap for Fatigue in High-Temperature Steam Headers..............................................................................................................................3-6 Figure 3-3 Level I Life Assessment Roadmap for Creep in High-Temperature Steam Headers..............................................................................................................................3-7 Figure 3-4 Level II Life Assessment Roadmap for High-Temperature Steam Headers.............3-8 Figure 3-5 Level III Life Assessment Roadmap for High-Temperature Steam Headers............3-9 Figure 4-1 Condition Assessment Roadmap for Steam Drums and Lower Drums....................4-4 Figure 5-1 Condition Assessment Roadmap for Economizer Headers .....................................5-5 Figure 5-2 Details of Action 7 – Serviceability Evaluation for Economizer Headers ..................5-6 Figure 5-3 Details of Action 10 – Addressing Operating Impacts on Economizer Headers.......5-7 Figure 6-1 Roadmap for Main Steam and Hot Reheat Piping System Evaluation.....................6-6 Figure 6-2 Level I Roadmap—Creep Life Expenditure Analysis for Seam Welds .....................6-7 Figure 6-3 Level II Life Assessment Roadmap—Inspection Process for Seam Welds..............6-8 Figure 6-4 Level III-a Roadmap—Implications of Flaw and Cavitation Findings........................6-9 Figure 6-5 Level III-b Roadmap—Determining RL through Creep Crack Growth Analysis .....6-10 Figure 7-1 Roadmap for Evaluation of Cold Reheat and Superheater Crossover Piping ..........7-8 Figure 7-2 Details of Step 1 of the Roadmap.............................................................................7-9 Figure 7-3 Details of Roadmap Steps 2A and 4A ....................................................................7-11 Figure 7-4 Details of Step 4B of the Roadmap: On-Pipe Seam Weld Examination.................7-17 Figure 7-5 Details of Step 5 of the Roadmap: Interpret Findings for Level II ...........................7-18 Figure 7-6 Details of Step 6 of the Roadmap: Level III Inspections.........................................7-19 Figure 7-7 Details of Step 7 of the Roadmap: Interpreting Level III Evaluation .......................7-20 Figure 8-1 Condition Assessment Roadmap for Attemperator Systems ...................................8-7 Figure 9-1 Condition Assessment Roadmap for Valves ............................................................9-7 Figure 10-1 Condition Assessment Roadmap for Low-Temperature Vessels and Piping .......10-7

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LIST OF TABLES Table 1-1 Data Requirements for the Multi-Level Life Assessment Approach...........................1-4 Table 1-2 Key Boiler Components and Applicable Classes of Damage ..................................1-14 Table 2-1 Action 1A – Initial Evaluation for Corrosion-Fatigue ..................................................2-4 Table 2-2 Action 1B – Steps to Follow with Corrosion-Fatigue Precursor .................................2-4 Table 2-3 Action 2 – Steps Confirming Corrosion-Fatigue ........................................................2-5 Table 2-4 Action 3 – Steps for Determining Root Cause of Corrosion-Fatigue .........................2-6 Table 2-5 Action 4 – Steps for Determining Extent of Corrosion-Fatigue ..................................2-7 Table 2-6 Action 5 – Steps for Immediate Actions for Corrosion-Fatigue ..................................2-8 Table 2-7 Action 6 – Long-Term Actions for Corrosion-Fatigue ................................................2-9 Table 2-8 Action 7 – Determining Ramifications or Ancillary Problems .....................................2-9 Table 2-9 Precursors for Waterwall Tubing Damage...............................................................2-11 Table 2-10 Screening Table for Waterwall Tubing Failures .....................................................2-20 Table 2-11 NDE Options for Waterwall Tubing........................................................................2-28 Table 2-12 Analysis and Disposition for Waterwall Tubing ......................................................2-29 Table 2-13 Preventive Actions for Waterwall Tubing Damage ................................................2-31 Table 2-14 Precursors for Superheater and Reheater Tubing Damage ..................................2-39 Table 2-15 Screening Table for SH/RH Tubing Failures .........................................................2-54 Table 2-16 NDE Options for SH/RH Tubing ............................................................................2-64 Table 2-17 Analysis and Disposition for SH/RH Tubing...........................................................2-66 Table 2-18 Preventive Actions for SH/RH Tubing Damage .....................................................2-68 Table 2-19 Precursors for Economizer Tubing Damage..........................................................2-76 Table 2-20 Screening Table for Economizer Tubing Failures..................................................2-85 Table 2-21 NDE Options for Economizer Tubing.....................................................................2-89 Table 2-22 Analysis and Disposition for Economizer Tubing...................................................2-90 Table 2-23 Preventive Actions for Economizer Tubing Damage .............................................2-92 Table 3-1 Damage Mechanisms for High-Temperature Steam Headers...................................3-3 Table 3-2 NDE and Sample Testing Options for High-Temperature Steam Headers..............3-11 Table 3-3 Analysis and Disposition for High-Temperature Steam Headers.............................3-14 Table 3-4 Preventive Actions for High-Temperature Steam Headers......................................3-16 Table 4-1 Damage Mechanisms for Steam Drums and Lower Drums.......................................4-2 Table 4-2 NDE and Sample Testing Options for Steam Drums and Lower Drums ...................4-5 Table 4-3 Analysis and Disposition for Steam Drums and Lower Drums ..................................4-8

xix

Table 4-4 Preventive Actions for Steam Drums and Lower Drums..........................................4-10 Table 5-1 Damage Mechanisms for Economizer Headers ........................................................5-3 Table 5-2 NDE and Sample Testing Options for Economizer Headers .....................................5-8 Table 5-3 Analysis and Disposition for Economizer Headers ..................................................5-10 Table 5-4 Preventive Actions for Economizer Headers ...........................................................5-13 Table 6-1 Damage Mechanisms for Main Steam and Hot Reheat Piping..................................6-3 Table 6-2 NDE Options for Main Steam and Hot Reheat Piping .............................................6-11 Table 6-3 Invasive Testing Options for Main Steam and Hot Reheat Piping ...........................6-13 Table 6-4 Analysis and Disposition for Main Steam and Hot Reheat Piping ...........................6-16 Table 6-5 Preventive Action for Main Steam and Hot Reheat Piping ......................................6-17 Table 7-1 Common Damage Mechanisms for Cold Reheat Piping ...........................................7-4 Table 7-2 Common Damage Mechanisms for Superheater Crossover Piping ..........................7-4 Table 7-3 Typical Damage Sites in CRH and SHXO Piping Systems .......................................7-5 Table 7-4 Inspection Recommendations Based on Risk Self-Assessment Findings...............7-12 Table 7-5 Analysis and Disposition for Thick-Walled Steam Piping.........................................7-21 Table 7-6 NDE Options for Thick-Walled Steam Piping ..........................................................7-22 Table 7-7 Preventive Actions for Thick-Walled Steam Piping..................................................7-24 Table 8-1 Damage Mechanisms for Attemperator Systems ......................................................8-4 Table 8-2 NDE Options for Attemperator Systems ....................................................................8-8 Table 8-3 Analysis and Disposition for Spray Attemperator Systems......................................8-11 Table 8-4 Preventive Actions for Attemperator Systems .........................................................8-13 Table 9-1 Damage Mechanisms for Valves ...............................................................................9-3 Table 9-2 NDE Options for Valves.............................................................................................9-9 Table 9-3 Analysis and Disposition for Valves.........................................................................9-11 Table 9-4 Preventive Actions for Valves ..................................................................................9-13 Table 10-1 Damage Mechanisms for Low-Temperature Vessels and Piping ..........................10-4 Table 10-2 NDE Options for Low-Temperature Vessels and Piping........................................10-8 Table 10-3 Analysis and Disposition for Low-Temperature Vessels and Piping....................10-11 Table 10-4 Preventive Actions for Low-Temperature Vessels and Piping .............................10-13 Table B-1 NDE Methods Overview ........................................................................................... B-1 Table B-2 Sample Evaluation Methods Overview..................................................................... B-8

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1 OVERVIEW AND STRATEGY FOR BOILER CONDITION ASSESSMENT

1.1

Introduction

Boiler components command a major portion of maintenance activities and produce a majority of operational outages for coal and other fossil fuel power plants. For effective management of unit operations and maintenance, plant personnel must have trustworthy information on key components. This Boiler Condition Assessment Guideline was developed to aid utilities in preparing and maintaining such information for coal-fired units. Many sections are also relevant for oil and gas units. Approach This Guideline is designed as a concise introduction and overview of boiler condition assessment. It summarizes information derived largely from the library of EPRI-sponsored work on condition assessment of boiler components and impacts of operating strategies such as cycling. This material is generally presented in a streamlined format. The intent is to quickly focus efforts on the required activities, and corresponding tools available, to perform boiler component condition assessments. Key references are listed in each chapter, and a comprehensive list of references is provided in Appendix C. Since its first publication, in 1998, the Boiler Condition Assessment Guideline has been updated on a periodic basis to respond to industry trends, incorporate new additions to the EPRI knowledge base, and refine the presentation to help make the reader better aware of available tools. For this fourth edition, significant additions have been made to reflect knowledge gained from new studies and guidelines addressing “Flow-Accelerated Corrosion,” “Reliability Under Cycling Operation,” and “Cold Reheat Piping.” Other additions include new nondestructive evaluation (NDE) techniques and new repair techniques. To further extend the reach of “lessons learned” in the work that led up to this guideline, candidate preventive actions include principles of “design for condition assessment” and “inherently reliable design.” Industry Environment Component condition assessment and component life management play a central role in efforts to achieve plant safety, reliability, and economic objectives. For many fossil plants, operating practices subject boiler components to conditions not anticipated in their design. Competitive markets and regional transmission pools value the ability of a plant to change output quickly to 1-1

Overview and Strategy for Boiler Condition Assessment

match load to demand. A plant’s financial success may hinge on ramping up and down, to match daily peaks and lows. Or, it may require successful response to just a few incidents of high demand that are compensated at premium prices. In response to these challenges, many power plant operators have implemented comprehensive condition assessment programs. In many instances, programs are enhanced with continuous condition monitoring for high-risk components. In practice, these challenges require the plant to maintain high reliability and availability, avoiding forced outages and extending major maintenance outage intervals, while operating generating units in load-following, two-shifting, and other cyclic modes. Extension of outage intervals allows fewer opportunities to inspect and repair (or replace) damaged components. This can translate into greater risk of component failure. Similarly, rapid load changes and cyclic operation can exacerbate certain damage mechanisms, such as fatigue and corrosion. For many plants, maintenance challenges are greater at a time when staff and budgets have been reduced. Plants must, increasingly, “do more with less.” Reliable condition assessments are crucial for managing units dedicated to load following, two shifting, and other cycling modes. Knowledge of component condition and expected remaining life is similarly critical to success when efforts are made to extend major maintenance outage intervals to reduce costs and improve availability. When units designed for baseload operation are cycled, they often experience accelerated component degradation. The large number of startups and rapid load changes that cycling entails add substantial thermal stress to many boiler components, thereby contributing to fatigue. Cycling also makes water chemistry more difficult to control, promoting corrosion and other material degradation phenomena. This situation is aggravated when condensation occurs in steam piping during startup, shutdown, and reduced load conditions. Many baseloaded and cycled units now operate in off-design combustion modes to limit NOX formation. This may entail low excess air, rich or lean recalibration of individual burners or burner elevations, shut-off of selected burners, recirculation of a flue gas slipstream back to the combustion zone, and/or increased overfire air. These operating modes often create local oxygen-starved areas (i.e., reducing conditions), which can dramatically accelerate corrosion, especially when alternating with oxidizing conditions during cyclic operation. Finally, in response to economic factors and emissions control mandates, many units now fire off-design fuels and/or switch fuels more frequently. This changes furnace heat absorption profiles, slag rates and composition, fly ash properties, and more.

1.2

Condition Assessment Fundamentals

In general, condition assessment relies on three pieces of information: •

the current type and extent of damage in the component

•

the rate of damage accumulation

•

the extent of damage required to cause failure

1-2


EPRI research has provided extensive information in each of these categories. That material is incorporated within this guideline both directly and by reference. The bibliography at the end of this chapter lists the key reports used in preparing the guideline. Other references are listed at the end of their respective topical chapter and in Appendix C. In the chapters that follow, specific processes are identified for acquiring and evaluating these three pieces of data for key boiler components. These processes are organized around a condition assessment roadmap that: •

develops background information on component design and operational history

•

estimates risk of component damage based on available knowledge

•

provides decision points with follow-up actions based on assessment of risk

•

suggests increasingly stringent evaluation techniques to confirm or reduce the known level of risk

Background, information, which may be gathered and used for a one-time assessment or as part of a comprehensive condition management program, includes the following: •

design and fabrication records for the component

•

operating and maintenance history for the plant and component

•

operating and maintenance history for similar components at plants of similar design

•

the operating plan (including desired service life) for the component and the plant

The condition assessment process develops additional information through: •

nondestructive evaluation tools

•

material removal and testing

•

stress analysis

•

fracture mechanics analysis

•

other software tools for predicting damage progression and risk

Damage prevention options are included as a subset of the damage accumulation category. Generally, the most cost-effective life management approach entails addressing the root cause(s) of component damage and eliminating the vulnerability to future damage. Much of EPRI’s successful program to reduce boiler tube failures (BTF) is based on this approach and is described in Chapter 2, “Boiler Tubing.” The condition assessment approach recommended by EPRI uses a multi-level structure in which component evaluations become progressively more detailed as needed (see Figure 1-1). Specifically, a three-level structure enables the estimated remaining life (RL) of a component to be iteratively compared with its desired life (DL). The DL is typically set by the desired inspection or maintenance interval for the component, often 3 to 5 years plus a margin of safety. For very expensive components, the DL could 1-3


correspond to the desired remaining economic life of the plant. This economic life is generally set via an asset management approach applied to all of a company’s operating units. Developing asset management strategies is outside the scope of this guideline. This iterative approach allows engineers to balance the costs of obtaining additional data against the value of those data. Table 1-1 illustrates the increasing levels of sophistication required in progressing through Level I, II, and III life assessments. In the chapters that follow, componentspecific activities, such as inspections, are categorized as Level II or Level III. A Level III assessment is typically recommended when the highest confidence in the RL of a particular component is required. Table 1-1 Data Requirements for the Multi-Level Life Assessment Approach Feature

Level I

Level II

Level III

Failure History

Plant records

Plant Records

Plant Records

Failure History in Components/Plants with Similar Design Details

Plant Records, Company Records, EPRI Guidelines and Reports, EPRI Condition Assessment Database, Peer Contacts

Plant Records, EPRI Guidelines and Reports, EPRI CA Database, Peer Contacts s

Plant Records, EPRI Guidelines and Reports, EPRI CA Database, Peer Contacts

Dimensions

Design or Nominal

Measured or Nominal

Measured

Condition

Records or Nominal

Inspection

Detailed Inspection

Temperature and Pressure

Design or operational

Operational or Measured

Measured

Stresses

Design or operational

Simple Calculation

Refined Analysis

Material Properties

Minimum

Minimum

Actual Material

Material Samples Required?

No

No

Yes

More rigorous assessment --------------------------------------------------------------------------------------------Æ More accurate operation data required ----------------------------------------------------------------------------Æ More accurate estimate of equipment RL -------------------------------------------------------------------------Æ

1-4

Overview and Strategy for Boiler Condition Assessment Assemble service information historical records

YES

Is key information missing? NO Level I Analysis Is RL >> DL?

YES

Establish re-evaluation period

NO Gather additional information (generally inspection results)

Level II Analysis

YES

Is RL > DL?

Establish re-inspection period

NO

Conduct root cause analysis

NO

Cost Evaluation (Is Level III economically justified?) YES

Mitigate driving force

Gather additional information (sampling, analysis, inspection)

Level III Analysis Is RL > DL?

YES

Establish re-evaluation and/or re-inspection period or install condition monitoring system

NO Choose to repair/replace/refurbish components

Understand root cause of damage

Figure 1-1 General Procedure for Boiler Component Life Assessment

1-5


1.3

The Condition Assessment Program Plan

Experience with the successful EPRI BTF reduction program indicates that a successful condition assessment program requires several key elements beyond the technical guidance provided in this guideline and the referenced EPRI reports. These elements include: •

management commitment of support

•

cross-functional teaming of maintenance, operations, and engineering personnel

•

attention to long-term solutions to the root cause(s) of problems

•

training

•

documentation of results and periodic review

The condition assessment program should capture as much data as practical on the unit’s operating history. Of particular importance are records of operation at conditions in excess of design values. Data gathered should include: •

unit operating hours

•

number of starts, by type (cold, warm, hot), and applicable ramp rates

•

steamside “indicators,” such as steam temperature, pressure, pressure drop, mass flow, and attemperator spray cycle timing, mass flow rate, and temperatures

•

gas-side indicators, such as boiler furnace and convective section exit temperatures (with detailed temperature distribution, if available), mass flow, excess oxygen level, economizer outlet temperature, draft loss, and soot-blowing timing and process

•

water chemistry control indicators (e.g., iron and copper levels, pH, oxygen)

•

detailed records of excursion incidents such as over-temperature, water hammer, etc.

•

relationships (concurrence) between the various data values

Boiler condition assessment efforts should produce a document that fully captures the condition assessment results and provides a clear basis for O&M decision-making. The document should include the following types of information: •

date the assessment was performed

•

summary of assessment activities, such as inspections, material tests, and results

•

estimate of component RL, summary of basis, and reference to calculations and other supporting documents for the estimate and basis

•

DL, summary of basis for DL, and reference to calculations and other supporting documents

•

damage mitigation/prevention actions, if appropriate

•

follow-on inspections or monitoring actions and their timing, if appropriate

•

recommendations for next assessment, including operating changes/upsets that would prompt a reassessment

1-6


All background information and assessment results should be carefully maintained for easy access and future reference. Use of an accepted database structure, such as the one integrated in EPRI’s Boiler Maintenance Workstation, is strongly recommended. Some plant owners/managers augment condition assessment programs with investment in condition monitoring systems, such as arrays of acoustic emission receptors that can be used to screen for creep and fatigue damage locations in high-energy piping and high-temperature headers. Use of these systems can decrease the amount of corrective maintenance and associated cost and downtime. By providing more confidence when balancing equipment failure risks with economic goals, real-time condition information helps extend outage intervals while reducing the number or frequency of time-based preventive maintenance tasks. Successful condition monitoring and component life management require the appointment of a recognized program coordinator and the development of guidelines and procedures that provide clear programmatic direction and indicate the persons responsible for key elements. Boiler condition monitoring is a data-intensive activity that goes beyond such traditional predictive maintenance activities as vibration analysis, lube oil analysis, and infrared thermography. Additional on-line sensors and data acquisition equipment may be needed. New or refined NDE methods will also be beneficial. Collected data can be analyzed by a growing range of software models, with varying degrees of sophistication. At the high end, three-dimensional finite element analysis models, such as EPRI’s Creep-FatiguePro, can be queried to produce up-to-date component damage accumulation and remaining life estimates (after calibration using historic condition and operating data and linkage to current operating data). Simplified software models, such as EPRI’s Boiler Life Evaluation and Simulation System (BLESS) and Tube Life Probability (TULIP) can often produce suitable results without the expense of creating geometrically accurate finite element representations of key components. Company and plant engineers must decide, on a case-by-case basis, the appropriate degree and sophistication of condition monitoring required to optimize both costs and risks within a component, a boiler system, a generation unit, or a family of similar units. Depending on the rate of damage accumulation (and the level of existing damage), options include: •

periodic monitoring of components with off-line analysis to determine whether the rate of damage has changed significantly from historic trends

•

continuous monitoring plus automated off-line analysis

•

continuous monitoring with automated off-line analysis and on-line “real-time” display/alarming of component stress and accumulated damage

1.4

Impact of Operational Trends

Restructuring of the power industry, beginning in the 1990s, changed the way many generating units are operated and maintained. Industry trends continue to pressure conventional fossil power plants to use challenging operating modes not considered in their original design. Competition from a deregulated marketplace and/or demands of an independent system operator 1-7


(ISO) in a regional transmission organization (RTO) has pushed utilities to increase operating plan flexibility while reducing O&M staffing and budgets. At the same time, more stringent environmental regulations have placed greater financial and operational burdens on many plants (and drained available capital budgets). Comprehensive boiler condition assessment programs have helped many companies respond to the challenge, with their units performing at levels of availability beyond those once thought possible. Still, these programs cannot completely negate the challenges to boiler component reliability and longevity imposed by age and by operating regimes including cycling, low-NOX combustion, and the use of off-design or low-grade fuels. Despite the appearance of success in “doing more with less,” the rates of material damage accumulation and the subsequent failure risk have, in fact, increased in many units. Under these conditions, condition assessment and component life management programs become even more crucial to boiler component reliability, plant longevity, and economic objectives. Cycling Cycling can affect virtually all boiler components. In particular, cycling promotes several key problems: (1) water/steamside chemical attack, because control of boiler cycle water chemistry is markedly more difficult, (2) thermal-stress-induced fatigue of thick-walled components, (3) creep-fatigue interactions, in which adverse synergies accelerate material damage, and (4) corrosion-fatigue interactions. Condensation and condensate pooling during cycling operation also increase risks of corrosion, corrosion/fatigue interactions and water hammer. To help limit damage due to cycling, many power companies are investing in better NDE equipment, conducting more comprehensive inspections, and applying damage accumulation and life prediction models to better estimate failure probabilities. In addition, some companies are supplementing condition assessment activities with condition monitoring systems. Low-NOX Operation Combustion modifications to decrease NOX formation almost invariably affect the types and rates of damage experienced by boiler components, especially tubing. Established corrective measures can also produce secondary problems. Damage mechanisms of particular concern when using low- NOX burners or low excess air stoichiometries include: •

waterwall fireside corrosion and erosion

•

alternation between reducing and oxidizing chemistry during cyclic operation, which has been recognized as a major factor in waterwall wastage

•

hydrogen damage

•

acid phosphate corrosion

•

caustic gouging

•

overheating of superheater and reheater tubes

1-8


Off-Design and Low-Grade Fuels Many units now fire fuels that differ from their original design coal or oil for reasons of SO2 compliance and economics. To take advantage of spot markets, a single unit also may now burn a much broader range of fuels. Furnace dimensions and size, location, and operating temperature of different heat exchange surfaces are typically optimized for the combustion, slagging and ash properties of a single fuel. Changes in slagging and fouling patterns will in turn affect the relative heat absorption rates of the waterwall and convective passes. In oil-fired units, magnesium-based additives can coat waterwalls and boost convective pass temperatures. These relative heat absorption rates are also influenced by flame pattern and radiance differences between fuels. Increased superheater and reheater temperatures accelerate creep damage, increase demands on attemperators, and make tubing more susceptible to erosion and corrosion. Corrosion and erosion in these and other components is also influenced by ash chemistry, fusion temperature, and abrasivity. Other observations related to specific coal properties include: •

the abrasive content in coals high in silica and iron pyrite causes higher erosion

•

high-potassium and especially high-sodium content, including the contribution from thawing salts, increases fouling in convective passes and promote corrosion

•

low-sulfur coal with high chloride content (>0.3% Cl) can accelerate corrosion in boilers that use overfire air for NOX control

•

heavily slagging coals increase the need for sootblowing, which can accelerate erosion

•

Powder River Basin coal tends to form more tenacious, insulating waterwall deposits and sticky convective pass deposits than eastern bituminous coal

Considerations for Extending Outage Intervals Many operators have improved unit availability and decreased maintenance costs by extending the intervals between major boiler inspection and maintenance outages. They have achieved this, without compromising safety, through systematic efforts to collect component-specific data and operating history data. Improved data and analysis reduces “material condition uncertainty” and thereby permits use of less conservative assumptions than are required when using “component/material class” (statistical average) information. Such efforts usually entail added investment in NDE and other techniques to estimate remaining life and failure probabilities. This incremental expense can often be justified by the premiums earned through assured availability at critical times in competitive power markets. Plants with “performance monitoring” systems have a valuable source of historic pressure, temperature, excess air, and other historic operating data. Condition monitoring systems provide a further tool for use in a predictive maintenance program.

1-9


Although condition monitoring systems do not obviate the need for off-line inspection, many systems offer a solid basis for the “proactive” (preventive) operating strategies recommended in this guideline. Where specific components of concern are not covered by a condition monitoring system, data from other components can sometimes be used for analyzing the operating history of target components. New approaches to unit operation and availability have recognized that some cracks can be tolerated, depending on location, size and other factors. Use of improved data collection and analysis tools is key to making confident run/repair/replace decisions.

1.5

Evaluation and Repair Technology

The heart of a boiler condition assessment program is the assortment of inspection and analysis tools that are used to determine the condition of boiler components, determine root causes if damage is detected, and predict how long they can safely operate (i.e., determine remaining life). As operating trends impose new challenges, technology development is increasing the selection of tools available to address them. Run/repair/replace decisions are also influenced by new metallurgical choices and welding technologies that can extend component life and shorten maintenance outages. NDE Inspection and Monitoring Tools Conventional ultrasonic, radiographic, dye, and magnetic particle techniques are well established, but inadequate for the quality NDE required for high levels of confidence regarding the condition of boiler components. Although many gaps remain, many new technologies are enabling faster and/or higher resolution location and characterization of flaws. New inspection tools include: •

advanced ultrasonic techniques, some capable of identifying creep and fatigue damage prior to the formation of cracks (i.e., “pre-crack damage”)

•

non-intrusive tools for flow and temperature measurement

•

smart pigs and robotic crawlers that permit faster inspections in locations unsafe or inconvenient for human access

•

robotic welding machines that improve weld quality and speed for shop and field repairs ranging from boiler tube patches to high-temperature header spool replacement

•

digital radiographic techniques that increase resolution while reducing source strength and corresponding exclusion zones

Continued efforts on acoustic emissions detection and analysis have developed useful techniques for locating and characterizing active damage in high energy piping and other components with minimal downtime and without extensive insulation removal as is required for other NDE techniques.

1-10


Other tools, such as digital thermography, high-temperature strain gages, and laser flow sensors, provide more complete temperature, stress, and flow inputs to condition assessment and root cause analysis. Analysis Tools EPRI and other organizations are continually working to develop new types of Level III condition assessment and remaining life analyses tools to support the approaches presented in this guideline. Available tools (described in more detail in Appendix C) include: •

EPRI’s Boiler Life Evaluation and Simulation System (BLESS) software for analyzing cracks and predicting the rate of crack growth

•

EPRI’s Boiler Overhaul Interval Optimization tool for prioritizing equipment screening and repairs

•

EPRI’s Creep-FatiguePro software for analyzing and predicting damage accumulation due to creep and fatigue interactions in high-temperature thick-walled components

•

EPRI’s Dissimilar Metal Weld Prediction of Damage In-Service (DMW-PODIS) software for estimating damage accumulation and remaining life in dissimilar metal welds in superheaters and reheaters

•

EPRI’s Tube Life Probability (TULIP) software for estimating the remaining life of superheater/reheater tubing

•

accelerated creep and fatigue tests that use miniature specimens to gauge remaining life

•

tools for quantifying the ability of weld repairs to provide adequate creep strength to safely extend component life

•

use of “small punch” tests to gauge a thick-walled component’s fracture appearance transition temperature

•

tools for determining the kinetics of the fine grain and coarse grain portions of weld heataffected zones (HAZ) and their role in Type IV cavity formation and growth

The specialized tools developed for boiler condition assessment are supplemented or enabled by advanced finite element analysis tools that decrease the cost and increase the speed and accuracy of static and dynamic modeling of thermal, mechanical and fluid flow phenomena. Repair Tools The end result of condition assessment (i.e., the disposition or run/repair/replace decision) is also affected by new repair technologies, including: •

robotic welding machines that improve weld quality and speed for shop and field repairs ranging from boiler tube patches to spool replacement in high-temperature piping and headers

1-11


•

temper-bead and other welding techniques that reduce requirements for post-weld heat treatment (and the delays they impose on outage schedules)

1.6

Life Optimization by Design

The effectiveness of a boiler condition assessment program, in advancing the safe, reliable and economic life of the facility, is significantly affected by decisions made during the design and construction of the facility. Existing plants can benefit from updated understanding of good design principles by implementing modifications incorporating “design for condition assessment” and “inherently reliable design.” Such modifications may be pursued reactively, when damage accumulation or failure forces replacement, or proactively, when modification is justified by safety or economic benefits. Design for Condition Assessment In many cases, the confidence level provided by condition assessment findings is limited by the ability to obtain complete and timely inspections of at-risk components. “Design for Condition Assessment” adjusts design parameters and incorporates design details to improve on-line monitoring and to improve inspection access during outages. For example, inspection access may be improved by: •

increasing the number of RT test ports and making them large enough to accept video probes

•

incorporating inspection windows during the installation or reinstallation of insulation

•

using removable panels instead of cast-in-place refractory

•

considering NDE probe size when selecting tube spacing

•

ensuring that pipe routing and support spacing do not hamper inspection access

On-line monitoring may be improved by: •

installing thermocouples and high-temperature strain gages to provide better information on thermal and stress transients during cycling

•

installing permanent wave guides for acoustic emissions monitoring

•

installing travel indicators and load cells or strain gages on key supports

•

installing sight windows for laser and thermographic monitoring

•

installing access ports and allowing space on the cold side of waterwalls for NDE probes mounted on robotic arms or crawlers

Inherently Reliable Design Principles of “inherently reliable design” are incorporated in many of the preventive action recommendations provided in this guideline. Existing plants may implement these principles when components are replaced or when benefits justify costs of proactive modifications. 1-12


These design principles generally aim to reduce the vulnerability of boiler components to thermal or mechanical stresses or corrosion mechanisms. Design features that accomplish this purpose include: •

recirculation pumps and piping as well as low flow warm-up bypasses around main valves that help avoid thermal shock and thermal stress during startup and shutdown

•

well located and properly sized drains for steam piping and reheater/superheater passes

•

erosion resistant severe duty valves, with multi-stage pressure drop and tight shut-off, to provide long-term accurate throttling and prevent leakage than can lead to pooling, corrosion, thermal shock, and water/steam hammer

•

continuously adjustable flow control for spray attemperators, to allow gradual temperature adjustment and prevent thermal shock and fatigue

•

pipe routing and support design with adequate leeway to ensure reliable condensate drainage for the life of the facility

•

condenser and feedwater heater metallurgy that allows use of oxygenated treatment and avoids flow-accelerated corrosion

1.7

Structure of this Guideline

This guideline contains a series of chapters that address damage mechanisms and provide condition assessment roadmaps for specific types of major boiler component. Table 1-2 provides a map of boiler components and their major in-service damage mechanisms. A series of appendices provide more detailed descriptions of damage mechanisms and assessment tools, and provide listings of EPRI publications and other reference material. The component-specific chapters each begin with discussion of component and system characteristics, damage mechanisms, damage precursors, and other conditions relevant to that type of component. Key information is tabulated for quick reference. This background material is followed by presentation of a generic or component-specific “roadmap” of recommended condition assessment activities for the class of components. These roadmaps have been developed to reflect damage mechanisms and degradation timeframes as the key drivers to performing specific condition assessment activities. For each component, additional information on NDE techniques, life assessment calculations, and damage prevention is introduced, briefly, and presented in tabular form. This supporting information is linked to the component life assessment roadmap, with Level I, II, and III designations provided as appropriate.

1-13


Table 1-2 Key Boiler Components and Applicable Classes of Damage Component

Damage Mechanism Creep

Fatigue

Corrosion

Internal Erosion / FAC

External Erosion / Corr’n

Thermal / Mech’l Deform’n

Waterwall Tubing (Ch 2)

X

X

X

X

X

X

Superheater (SH) and Reheater (RH) Tubing (Ch 2)

X

X

X

X

X

X

X

X

X

Economizer Tubing (Ch 2)

X

Superheater Headers (Ch 3)

X

X

X

X

Reheater Headers (Ch 3)

X

X

X

X

Steam and Lower Drums (Ch 4)

X

X

X

X

Waterwall Headers (Ch 4)

X

X

X

X

Downcomers (Ch 4)

X

X

X

X

Economizer Inlet Headers (Ch 5)

X

X

X

X

Main Steam Piping (Ch 6)

X

X

(2)

X

Hot Reheat Piping (Ch 6)

X

X

(2)

X

(1)

X

X

X

X

X

X

X

X

X

X

X

Valves (Ch 9)

X

X

X

X

Deaerators (Ch 10)

X

X

X

X

Feedwater Heaters (Ch 10)

X

X

X

X

Blowdown Vessels (Ch 10)

X

X

X

Superheater Crossover Piping (Ch 7) Cold Reheat Piping (Ch 7) Attemperators (Ch 8)

X

NOTES: (1) May occur with high outlet temperature from primary SH. (2) May occur with cyclic operation due to oxide scale formation and shedding or condensation combined with contaminants from attemperator or drum carryover.

1-14


The intent of this format is to allow users to quickly identify relevant issues and appropriate actions for their condition assessment programs. More detailed information is available through the appendices and other referenced EPRI documents. Key references are included at the end of each chapter. Appendix A provides descriptions of individual damage mechanisms while Appendix B provides descriptions of NDE techniques. Appendix C provides an expanded list of references and other resources.

1.8

Resources and References Overview

EPRI has produced a number of comprehensive technical reports to assist member companies with implementing comprehensive condition assessment programs and performing equipmentspecific activities. A series of “guideline” reports assembles and organizes information from numerous EPRI reports and other references into a single document addressing a particular group of related boiler components. Key reports include: Boiler Tube Failures: Theory and Practice. EPRI: 1996. Report TR-105261, Vols. 1-3. Damage to Power Plants Due to Cycling. EPRI: 2001. Report 1001507. Guidelines for the Evaluation of Cold Reheat Piping. EPRI: 2005. Report 1009863. Guidelines for the Evaluation of Seam-Welded High-Energy Piping. EPRI: 2003. Report 1004329. Guidelines for Controlling Flow-Accelerated Corrosion in Fossil and Combined Cycle Plants, EPRI: 2005. Report 1008082. Header and Drum Damage: Theory and Practice: Volume 1: Information Common to All Damage Types. EPRI 2003. Report 1004313-V1. Header and Drum Damage: Theory and Practice: Volume 2: Mechanisms. EPRI: 2003. Report 1004313-V2. Impact of Operating Factors on Boiler Availability. EPRI: 2000. Report 1000560. Inherently Reliable Boiler Component Design. EPRI: 2003. Report 1004324. Life Assessment of Boiler Pressure Parts. EPRI: 2000. Report 1000311. NDE Guidelines for Fossil Power Plants. EPRI: 1997. Report TR-108450 and CD-ROM CD-108450. State-Of-the-Art Boiler Design for High Reliability Under Cycling Operation. EPRI: 2004. Report 1009914. Key references are listed in each chapter of this guideline. Appendix C contains an expanded list of references along with lists of software tools, training programs, individualized service 1-15


programs, and other resources that EPRI has developed to help member utility personnel learn and perform condition assessment activities.

1-16

2 BOILER TUBING

Boiler tube failure (BTF) continues to be the most frequent cause of fossil plant forced outages. The large variety of damage mechanisms seen with boiler tubing corresponds to a similarly large variety of relatively harsh operating conditions to which different tubing is exposed and therefore must be designed. Similarly, the sheer number of welds and separate pieces of tubing, and the challenges in selecting materials and configuration, present ample opportunity for vulnerabilities related to flaws in design and fabrication. This chapter emphasizes processes for determining boiler tube damage mechanisms and their root causes, and for implementing long-term, corrective actions to minimize or prevent future damage. The material in the following sections highlights the scope of effort and required actions for determining the condition of boiler tubing components. The tables on nondestructive evaluation options update a key area in which technology continues to evolve. Recommendations on when to use which “level” of NDE techniques aim to help a crossfunctional team execute a BTF reduction program cost-effectively. Formal implementation of the EPRI program on BTF reduction is recommended for all fossil steam plant operators as part of their boiler condition assessment activities. Experience with this program has shown that much of the damage sustained by boiler tubing is avoidable. Utilities participating in the BTF program have achieved significant reductions in BTF and corresponding increases in unit availability and average boiler tube life. EPRI’s three-volume publication, Boiler Tube Failures: Theory and Practice (1996, Report TR105261) still serves as the comprehensive reference for implementing a BTF reduction program. More recent work, with benchmarking tools to help utilities evaluate the strength of their programs, shows that many facilities can make great gains with better use of current tools. Even the best performers have not yet reduced BTF to a non-significant level. Toward this end, EPRI and others are continuing work to develop better techniques to detect damage and to implement durable repairs in locations that are subject to harsh conditions and/or difficult access.

2.1

Programmatic Approach

As noted, a comprehensive BTF reduction program is the key to addressing the most significant cause of lost production in most power plants. To be carried out effectively, this programmatic effort must: •

have the clearly communicated sanction of management

•

assign specific responsibilities to members of a cross-functional team involving engineering, operations and maintenance personnel 2-1

Boiler Tubing

•

provide broad-based training of personnel, including managers

•

make effective and timely use of condition assessment tools within a broad-based boiler condition assessment program

•

include action plans for addressing root causes of repeat failures

Other features of the most successful programs generally include: •

formalized goals and objectives for the BTF failure reduction program

•

record keeping and analysis to determine the equivalent availability loss (EAL) due to BTF

•

a ranking of damage mechanisms within plants and systems by EAL, lost MWh, or costs

•

proactive plans to inspect superheater (SH) and reheater (RH) tubes and perform remaining creep life calculations prior to the first failure incidents

•

formalized action plans to address damaged tubing and BTF forced outages, including assessment of neighboring and similarly positioned tubing

•

maximizing use of opportunities for additional inspection, especially during BTF forced outages and by extending outages at times of low-demand/revenue

2.2

Condition Assessment Roadmap for Boiler Tubing

The EPRI approach to BTF reduction is summarized in the roadmap of actions shown in Figure 2-1. The process begins with identification of actual tube failure mechanisms of concern. EPRI has cataloged 33 separate damage mechanisms. Each damage mechanism can be related to factors such as materials, design, fuel, NOX controls, and plant operations and maintenance practices. Each boiler tube section in any given power plant will generally only be susceptible to a few of these mechanisms. The EPRI BTF reduction program recognizes this situation and advocates that a cross-functional team, composed of representatives from maintenance, operations, and engineering, jointly undertake the steps in the Figure 2-1 roadmap. The process shown in Figure 2-1 is illustrated by an example case on corrosion-fatigue damage in waterwall tubing in Section 2.3. Tables 2-1 through 2-8 provide the details for corrosionfatigue corresponding to the action steps in the general roadmap. As noted, the focus is root cause identification and implementation of damage-limiting or damage-preventing actions. Sections 2.4 through 2.6 are arranged by major boiler tube section: waterwalls, superheaters and reheaters, and economizers. Text and tables in these sections summarize characteristics and condition assessment approaches for typical failure types and damage mechanisms and for each boiler tube section.

2-2

Boiler Tubing

For the actions specific to other damage mechanisms (parallel to those shown in the corrosionfatigue example in Section 2.3), Volumes 2 and 3 of Boiler Tube Failures: Theory and Practice should be consulted. BTF—Mechanism Unknown

BTF—Known Mechanism

Anticipating Future BTF

Identify candidates

Tentative identification of mechanism

Tentative identification of mechanism

NO

Action 1A:

Action 1B:

Perform screening analysis to answer the question “Is it possible that this BTF was caused by this mechanism?”

Perform screening analysis (Review precursor list; remove tube sample to determine extent of damage)

YES Action 2: Determine/confirm mechanism

YES

Are BTFs likely to occur in the future due to this mechanism?

Action 3: Determine root cause

Action 4: Determine extent of damage or affected areas

Action 5: Implement repairs, immediate solutions, and actions

Action 6: Implement long-term solutions to prevent repeat failures

Action 7:

NO

Determine possible ramifications/ancillary unit problems A shaded box indicates that there is a more detailed version of the action.

Figure 2-1 General Condition Assessment Roadmap for Identifying, Evaluating, and Anticipating BTF

2-3

Boiler Tubing

2.3

Example Case Actions for Corrosion-Fatigue

Actions 1A and 1B: Initial Evaluation Two paths exist for the BTF cross-functional team to follow in the investigation of corrosionfatigue. The goal of the actions in these paths is to determine whether further investigation of corrosion-fatigue is warranted or if another BTF mechanism should be investigated. Follow Action 1A if a tube failure has occurred and corrosion-fatigue is the likely mechanism. Follow Action 1B if a precursor has occurred in the unit that could lead to future tube failures by corrosion-fatigue. Table 2-1 Action 1A – Initial Evaluation for Corrosion-Fatigue Steps for Determining if Corrosion-Fatigue Is the Likely Mechanism 1.

Determine whether the failure has occurred in a location typical of corrosion-fatigue by: • Reviewing typical boiler regions • Reviewing susceptible locations • Determining whether failure locations are near tube attachments or other locations constrained during temperature and pressure transients

2.

Confirm that the macroscopic appearance of the failure includes features such as: • Cracking that initiated on the inside surface of the tube, typically at multiple locations • Association of the failure with an external attachment • A pinhole leak, a thick-edged crack oriented either axially or circumferentially, or a thick-edged blowout or rupture

3.

Go to Action 2 for further steps to confirm the BTF mechanism if the failure seems consistent with the features described in Steps 1 and 2 above.

4.

Go to the screening table for water-touched tubing to find a more likely candidate if the failure does not have features like those described in Steps 1 and 2.

Table 2-2 Action 1B – Steps to Follow with Corrosion-Fatigue Precursor Steps to Follow if a Precursor Has Occurred in the Unit 1.

Determine whether one or more of the following precursors has been found or is likely to have occurred in the unit: • Evidence of cracking found during routine inspections, particularly at susceptible locations • Evidence of corrosion-fatigue damage found in similar units

2-4

Boiler Tubing • Evidence that one or more risk factors, such as environmental ranking, stress ranking, or equivalent operating hours, may lead to a concern • Evaluation of unit cycle chemistry indicates an environmental ranking of E3 or E4. Such a warning might be triggered by one or more of the following: -

a persistent problem with phosphate hideout and return

-

one or more tube failures caused by either hydrogen damage or caustic gouging

-

cycle chemistry operating parameters for pH, cation conductivity, or dissolved oxygen that are consistently outside the recommended ranges during normal operation or startup

-

more than one chemical cleaning by hydrochloric acid

-

boiler shutdown and layup procedures that have not included such steps as nitrogen capping, chemical treatment for pH, oxygen control during layup and restart, and dry storage during draining periods

• Unit has been subjected to numerous starts or has accumulated a large number of “equivalent operating hours.” (This should be considered in conjunction with location stress rank and environmental factors.) 2.

Go to Action 3 to confirm the influence of each if one or more of these precursors has occurred. These precursors can be the root cause influences of corrosion-fatigue.

Action 2: Determine/Confirm That the Mechanism Is Corrosion-Fatigue If a failure has occurred that the BTF cross-functional team tentatively identified as being caused by corrosion-fatigue (Action 1A), Action 2 should confirm that corrosion-fatigue is the primary mechanism or it should point to another cause. The following steps are executed by removing representative tube samples and conducting a visual examination and a detailed metallographic analysis. One of the primary aims is establish that damage did not initiate as fatigue on the outside diameter (OD). Table 2-3 Action 2 – Steps Confirming Corrosion-Fatigue Steps for Determining/Confirming that the Mechanism is Corrosion-Fatigue 1.

Confirm that damage location is consistent with corrosion-fatigue. “Is damage associated with a susceptible location?” If the answer is no, review for indications of mechanical failure. (The mechanism may still be corrosion-fatigue.)

2.

Determine the location of damage initiation “Did damage initiate from the inside, or waterside, of the tube?” If the answer is no, the mechanism is more likely to be mechanically induced fatigue

3.

Evaluate nature of cracking “Is there evidence of multiple initiation sites with wide cracks of a transgranular nature?”

2-5

Boiler Tubing IF the answer is no, check to see if an under-deposit corrosion mechanism such as hydrogen damage, caustic gouging, or acid phosphate corrosion is active. 4.

The following are confirming characteristics of corrosion-fatigue: • cracks that are filled with oxide and are blunt tipped • crack profiles that are irregular • signs of discontinuous growth or re-initiation

5.

Go to Action 3

Action 3: Determine Root Cause of Corrosion-Fatigue Action 3 is followed if it has been confirmed that a tube failure has occurred and the mechanism is corrosion-fatigue (Action 2) or that a precursor occurred (Action 1B). The BTF crossfunctional team reviews the potential root causes of corrosion-fatigue, identifies probable causes, and takes the actions necessary to confirm which root causes are operative in the unit. The goal of Action 3 is to enable proper actions to be taken to prevent future failures due to corrosionfatigue. Execute this action in parallel with Action 4, which determines the extent of damage. Table 2-4 Action 3 – Steps for Determining Root Cause of Corrosion-Fatigue Major Root Cause Influence

Actions to Confirm

Influence of Excessive Stresses/Strains Restraint stresses at attachments

Compare damaged locations to those typical of corrosion-fatigue Inspect susceptible locations before tube failures occur Selectively sample tubes to gauge damage accumulation Conduct finite element stress analysis to predict high-strain locations Install thermocouples and/or strain gauges to confirm high-stress locations

Subcooling (cooling water stratification) in natural circulation boilers

Review operating records Install thermocouples at top and bottom of boiler to monitor ΔT as function of shutdown time Install strain gauges to confirm stresses

Influence of Environmental Factors

2-6

Boiler Tubing Major Root Cause Influence Poor water chemistry

Actions to Confirm Review water chemistry logs and practices, with particular emphasis on pH reductions during shutdown and early startup. If the review suggests a problem, implement a monitoring program. Calculate the “environmental parameter” to assess its contribution to corrosion-fatigue Selectively sample tubes from at-risk areas for evidence of pitting or corrosion-fatigue damage

Overly aggressive or improper chemical cleaning

Review chemical cleaning procedures, and correlate chemical cleaning with corrosion-fatigue failures Selectively sample at-risk tubes

Improper boiler shutdown and/or layup procedures

Review water chemistry logs and practices, with particular emphasis on pH reductions during shutdown and early startup. If the review suggests a problem, implement a monitoring program. Calculate the “environmental parameter” to assess its contribution to corrosion-fatigue

Influence of Historical Unit Operation Operating procedures that have produced high stresses

Review operating records to determine the number of operating hours and boiler starts; ramp rates during boiler starts Review feedwater heater startup procedures Plot failure history against unit operating conditions

Action 4: Determine the Extent of Damage or Affected Areas The BTF cross-functional team should conduct Action 4 in parallel with Action 3. The evaluation will be based on obvious signs of cracking. Table 2-5 Action 4 – Steps for Determining Extent of Corrosion-Fatigue Steps for Determining the Extent of Damage or Affected Areas 1.

Identify all locations to be examined. Corrosion-fatigue is unlikely to occur in only one area. (Missed locations are sites where future failures may occur.)

2.

Perform visual examination to detect obvious signs of cracking

3.

Perform ultrasonic testing (UT) / radiographic testing (RT) / video probe survey, as practical, to measure the extent of cracking

4.

Perform tube sampling to confirm results of NDE inspection and to determine the degree of damage

2-7

Boiler Tubing

5.

Use results interactively with Action 3

6.

Go to Action 5

Action 5: Implement Repairs, Immediate Solutions, and Actions The most important immediate actions for the BTF cross-functional team are to apply the influence diagram to determine the probable effectiveness of longer-term solutions, to repair or replace damaged tubes, and to implement available short-term changes to operation or chemical cleaning (when it is the root of the problem). Table 2-6 Action 5 – Steps for Immediate Actions for Corrosion-Fatigue Steps for Implementing Repairs, Immediate Solutions, and Actions 1.

Implement repairs or replacement of affected tubes as identified by the NDE survey (Action 4) Develop a plan to reduce affected tubing on the basis of root causes and probable choice of long-term solution

2.

Apply the influence diagram. The influence diagram approach will help pinpoint which root cause must be addressed to prevent repeat failures caused by corrosion-fatigue (primarily a long-term action). During any repair or replacement activity, ensure that all necessary plant information is gathered and recorded

3.

Implement the appropriate guidelines, controls and monitoring if the root cause is poor cycle chemistry

4.

Institute modified procedures to correct overly aggressive chemical cleaning

5.

Modify procedures if improper unit shutdown or layup procedures underlie the problem

6.

Go to Action 6

Action 6: Implement Long-Term Actions to Prevent Repeat Failures Correction of underlying problems and prevention of repeat failures are priorities for the BTF cross-functional team. The proper choice of long-term actions will be based on clear identification of the underlying root causes and guidance from the influence diagram. The most effective long-term solution has been to lower the applied stresses by modifying attachment designs. Beware of improper modifications, as they can intensify the problem.

2-8

Boiler Tubing Table 2-7 Action 6 – Long-Term Actions for Corrosion-Fatigue Major Root Cause Influence

Long-Term Action

Influence of Excessive Stresses/Strains Restraint stresses at attachments

The most effective solution has been attachment modification s to reduce stresses

Subcooling (cooling water stratification) in natural circulation boilers

Install off-line boiler circulation pumps to reduce the degree of subcooling

Influence of Environmental Factors• Poor water chemistry

Clean up overall cycle, and confront specific chemistry problems such as condenser leaks, impurity ingress, lack of appropriate procedures, and lack of appropriate monitoring devices Apply appropriate guideline procedures for specific chemistry, monitoring, and instrumentation

Overly aggressive or improper chemical cleaning

Optimize chemical cleaning procedures and frequency

Improper boiler shutdown and/or layup procedures

Optimize shutdown and layup procedures

Influence of Historical Unit Operation Operating procedures that have produced high stresses

Reduce stresses or improve the environmental parameter

Action 7: Determine Possible Ramifications or Ancillary Problems The final step for the BTF cross-functional team is to examine any possible ramifications to other boiler components implied by the presence of corrosion-fatigue or its precursors. Table 2-8 Action 7 – Determining Ramifications or Ancillary Problems Corrosion-Fatigue Aspect Problems with boiler water or feedwater chemistry control

Alert for Other Cycle Components Potential for boiler damage by other mechanisms, such as acid phosphate corrosion, or under-deposit hydrogen damage that might follow condenser leakage Potential for carryover in steam to superheater and HP turbine; contaminated attemperator spray to secondary superheater and HP turbine or reheater

Actions Implement stricter cycle chemistry control program and instrumentation Stay alert to potential problems throughout cycle

2-9

Boiler Tubing

Corrosion-Fatigue Aspect

Alert for Other Cycle Components

Excessive or overly aggressive chemical cleaning

Potential for boiler tube damage by other mechanisms

Inadequate or improper shutdown procedures

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

2.4

Actions Apply guidelines for chemical cleaning Modify shutdown procedures

Waterwall Tubing

High heat flux and challenging chemistry are related to numerous damage mechanisms on interior and exterior surfaces of waterwall tubing. Tube wall temperatures vary between tubes and from front-to-back and top-to-bottom in every tube. Rigid membrane structures and design of support structures concentrate stress in some locations while distributing it in others. Inspection access has traditionally required extensive scaffolding inside the furnace. Inspection of the backside OD surface of the tubing has been limited by time and budgets available to remove and replace lagging, insulation, and support hardware. New condition assessment technology and better understanding of damage mechanisms are helping to reduce the frequency of waterwall tubing failures. New repair techniques are reducing costs and outage duration. The most significant developments include: •

Recent trials have shown success with digital phosphor plate radiography for detecting and evaluating corrosion-fatigue on the inaccessible cold side of waterwall tubing. Additional work is ongoing with linear phased array UT for detecting corrosion-fatigue cracking from the furnace side of the tube.

•

Scanning processes using electromagnetic transducers (EMATs), eddy current testing, active infrared response, and other techniques have provided some ability to quickly detect wall thickness changes and other damage over large areas of tubing.

•

Robotic systems, capable of maneuvering via magnetic treads or similar attachment to the tube surfaces, have been developed to improve inspection options for waterwall tubing and new efforts are addressing access issues for pendant section tubing.

•

Automated welding systems are starting to be applied to tubing repair and replacement. EPRI has recently licensed such a system for waterwall tubing and additional work is continuing.

•

Weld overlay, spray coatings, and nonmetallic coatings have shown varying degrees of success for repairing or reducing waterwall erosion and corrosion.

Damage Mechanisms for Waterwall Tubing Because of the large number of potential damage mechanisms for waterwall tubing, it is essential that correct identification be made of the specific mechanism(s) producing tube failures or causing pre-failure damage. Once a correct identification is made, potential root causes can be 2-10

Boiler Tubing

investigated, with the objective of identifying corrective actions that can slow or eliminate future damage. Table 2-9 categorizes waterwall tubing damage mechanisms by their likely precursors. For example, research has shown that waterwall wastage in boilers with low-NOX combustion is linked to chlorine content in coal, pyrite content in coal, and load cycling modes that alternate furnace gas chemistry between reducing (full load, low excess air) and oxidizing (part load, high excess air). The wastage due to iron sulfate deposits, from un-oxidized pyrite, involves generation of corrosive gas during FeS decomposition under oxidizing, mildly reducing, and alternating conditions. Table 2-10 is designed to quickly focus failure analysis efforts by characterizing failure types by appearance and location, and providing corresponding damage mechanisms and root causes most likely to be responsible for a failure with those characteristics. Appendix A provides description of these damage mechanisms and their causes. Additional detail may be found in EPRI’s BTF reduction technical reports (see the reference list in Section 2.7). Table 2-9 Precursors for Waterwall Tubing Damage Precursor

Mechanisms of Concern for Waterwall Tubing

Potential Root Cause(s)

Inspection / Appearance Precursors – Waterwall Tubing (Waterside) Excessive waterside deposits (>>30 mg/cm2) for high-pressure boilers

Hydrogen damage Acid phosphate corrosion Caustic gouging Short-term overheating

Non-optimum cycle chemistry and/or metallurgy allowing corrosion in condenser and/or feedwater system, with redeposition downstream Improper chemical cleaning Not flushing after chemical cleaning Condenser tube leakage Inadequate condensate polishing

Excessive waterside deposits, such as ripple Fe3O4 in oncethrough (O/T) and supercritical units

Supercritical waterwall cracking

Boiler water samples that appear black (high suspended solids)

Acid phosphate corrosion

Non-optimum cycle chemistry Inadequate condensate polishing Inadequate chemical cleaning Non-optimum cycle chemistry Phosphate hideout and return

2-11

Boiler Tubing

Precursor Corrosion/erosion in feedwater system Fouling in boiler feed pump or orifices

Pressure drop across circulation pumps (orifices are plugging)



Supercritical waterwall cracking of supercritical or O/T units

Non-optimum cycle chemistry

Hydrogen damage, acid phosphate corrosion, or caustic gouging of subcritical or non-O/T units

Inadequate chemical cleaning

Short-term overheating in waterwall tubing

Non-optimum cycle chemistry and/or metallurgy allowing corrosion in condenser and/or feedwater system, with redeposition downstream

Inadequate condensate polishing

Not flushing after chemical cleaning Phosphate hideout and return

Inadequate condensate polishing Inadequate chemical cleaning Not flushing after chemical cleaning Cavitation/deposition at orifice due to pump NPSHR versus flow temperature and pressure and/or orifice size versus flow rate Inspection / Appearance Precursors – Waterwall Tubing (Fireside) Flame impingement caused by burner change or misalignment, leading to excessive tube deposits

Hydrogen damage Acid phosphate corrosion Caustic gouging

Misaligned, misbalanced, or damaged burner Setting not corrected after fuel change

Fireside corrosion Fresh rust found on tubes after unit washing

Fly ash erosion

External flat spot

Sootblower erosion in waterwalls

Burnishing or polishing

Coal particle erosion

Inadequate or damaged tube shields Misaimed or misadjusted burners Problems with sootblower design, operation, or maintenance Excessive sootblowing Concentration of flow along top of waterwalls due to plugging in center of convective section

2-12

Boiler Tubing

Precursor



Failed tubes, or any upstream tube leaks, as a warning to look for potential short-term overheating

Short-term overheating in waterwall tubing

Cracking on tube exterior (fireside or cold side)

Thermal/mechanical fatigue

Stress concentrator at toe of membrane weld

Thermal shock

Cyclic stress due to temperature differences during cyclic operation, especially fireside–to– cold-side temperature difference during overfire on startup

Tubes or tube orifices plugged by deposition or exfoliated scale Denucleated boiling due to localized high heat flux, possibly caused by misaimed/misadjusted burners or high heat flux in one area due to widespread slagging elsewhere

Steam/water contact during sootblowing/deslagging Cycle Chemistry Precursors – All Units Problem with high levels of feedwater corrosion products Operating ranges for pH, cation conductivity, or dissolved oxygen consistently outside recommended ranges, including persistent reducing conditions or excessive use of oxygen scavengers

Corrosion-fatigue Hydrogen damage Acid phosphate corrosion Caustic gouging Waterwall fireside corrosion Supercritical waterwall cracking Short-term overheating in waterwall tubing

Major acid contamination event (pH >2 ppm)

Caustic gouging

Non-optimum cycle chemistry Inadequate instrumentation or testing Inadequate operator training

Cycle Chemistry Precursors – Units on All-Volatile Treatment (AVT) Caustic used in excess of the amount necessary for optimal control of contaminant ingress (to counteract pH depressions on startup)

Caustic gouging

Non-optimum cycle chemistry Inadequate instrumentation or testing Inadequate operator training Air in-leakage to condenser or deaerator Air in-leakage during shutdown Condenser tube leakage

pH depression during shutdown and early startup (pH about 7–8) Hideout/return of sulfate

Corrosion-fatigue

Non-optimum cycle chemistry plus source of cyclic stress Inadequate instrumentation or testing Inadequate operator training Air in-leakage to condenser or deaerator Air in-leakage during shutdown Condenser tube leakage

2-14

Boiler Tubing

Precursor



Cycle Chemistry Precursors – Units on Caustic Treatment Caustic used in excess of the amount necessary for optimal control (>>2 ppm)

Caustic gouging

Non-optimum cycle chemistry Inadequate instrumentation or testing Inadequate operator training

Maintenance-Related Precursors – Chemical Cleaning Evidence of shortcoming in chemical cleaning process, such as inappropriate cleaning agent, excessively strong concentration, or long cleaning time

Chemical cleaning damage in waterwalls Short-term overheating

Improper chemical cleaning Inadequate flush after chemical cleaning

Too high a temperature Failure to neutralize, breakdown of inhibitor, or inadequate rinse Evidence that level of Fe in cleaning solution continued to increase instead of leveling out when cleaning process was ended.

Chemical cleaning damage in waterwalls

Improper chemical cleaning

Need for excessive cleaning in supercritical units (interval

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