Boiler Condition Assessment Guideline -...

Technical Report

Boiler Condition Assessment Guideline

Fourth Edition

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 onlycopyright 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.

PCDO001

Rectangle

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

Boiler Condition Assessment Guideline Fourth Edition

1010620

Final Report, June 2006

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.

iii

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.

v

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 cost-effectively 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.

vi

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

vii

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.

ix

ACKNOWLEDGMENTS

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

xi

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

xii

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 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

xiii

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

xiv

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

xv

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

xvi

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

xvii

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

xix

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

xx

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

1-1

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

Overview and Strategy for Boiler Condition Assessment

1-2

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


1-3

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


1-4

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, component-specific 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 --------------------------------------------------------------------------------------------

More accurate operation data required ----------------------------------------------------------------------------

More accurate estimate of equipment RL -------------------------------------------------------------------------


1-5

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

Is RL > DL?

YES 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


1-6

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


1-7

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


1-8

(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


1-9

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.


1-10

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.


1-11

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 heat-affected 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


1-12

• 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.


1-13

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.


1-14

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

Component Damage Mechanism

Creep Fatigue Corro-sion

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

Economizer Tubing (Ch 2) X X X X 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

Superheater Crossover Piping (Ch 7) (1) X X X

Cold Reheat Piping (Ch 7) X X X X

Attemperators (Ch 8) 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

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.


1-15

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 equipment-specific 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


1-16

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

2-1

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 cross-functional 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 TR-105261) 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

Boiler Tubing

2-2

• 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 corrosion-fatigue 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.

Boiler Tubing

2-3

For the actions specific to other damage mechanisms (parallel to those shown in the corrosion-fatigue 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: Perform screening analysis

to answer the question “Is it possible that this BTF

was caused by this mechanism?”

Action 1B: 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: Determine possible

ramifications/ancillary unit problems

NO

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

Boiler Tubing

2-4

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 corrosion-fatigue. 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

Boiler Tubing

2-5

• 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?”

Boiler Tubing

2-6

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 cross-functional 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 corrosion-fatigue.

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

Boiler Tubing

2-7

Major Root Cause Influence Actions to Confirm

Poor water chemistry 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

Boiler Tubing

2-8

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.

Boiler Tubing

2-9

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

Alert for Other Cycle Components Actions

Problems with boiler water or feedwater chemistry control

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

Implement stricter cycle chemistry control program and instrumentation

Stay alert to potential problems throughout cycle

Boiler Tubing

2-10

Corrosion-Fatigue Aspect

Alert for Other Cycle Components Actions

Excessive or overly aggressive chemical cleaning

Potential for boiler tube damage by other mechanisms

Apply guidelines for chemical cleaning

Inadequate or improper shutdown procedures

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

Modify shutdown procedures

2.4 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

Boiler Tubing

2-11

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 once-through (O/T) and supercritical units

Supercritical waterwall cracking

Non-optimum cycle chemistry


Inadequate chemical cleaning

Boiler water samples that appear black (high suspended solids)

Acid phosphate corrosion Non-optimum cycle chemistry

Phosphate hideout and return

Boiler Tubing

2-12



Corrosion/erosion in feedwater system

Fouling in boiler feed pump or orifices

Supercritical waterwall cracking of supercritical or O/T units

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





Phosphate hideout and return

Pressure drop across circulation pumps (orifices are plugging)

Short-term overheating in waterwall tubing





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


Caustic gouging

Fireside corrosion

Misaligned, misbalanced, or damaged burner

Setting not corrected after fuel change

Fresh rust found on tubes after unit washing

External flat spot

Burnishing or polishing

Fly ash erosion

Sootblower erosion in waterwalls

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

Boiler Tubing

2-13



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


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

Cracking on tube exterior (fireside or cold side)

Thermal/mechanical fatigue

Thermal shock

Stress concentrator at toe of membrane weld

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

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


Caustic gouging

Waterwall fireside corrosion



Non-optimum cycle chemistry; inadequate instrumentation




Air in-leakage at condenser or deaerator

Air in-leakage during shutdown

Major acid contamination event (pH <8) when unit is at full load

Hydrogen damage Condenser leak

Breakdown with entrance of makeup or condensate polisher regeneration chemical


Boiler Tubing

2-14



Cycle Chemistry Precursors – Units on Phosphate Treatments

Evidence of a persistent problem with phosphate hideout, particularly where monosodium phosphate and/or an excess of disodium phosphate has been added to the boiler

Acid phosphate corrosion Non-optimum cycle chemistry

Inadequate instrumentation or testing

Inadequate operator training

Persistent phosphate hideout with phosphate return causing a pH depression

Corrosion-fatigue Non-optimum cycle chemistry plus source of cyclic stress



Caustic level in excess of the amount needed for optimal control (>>2 ppm)

Caustic gouging Non-optimum cycle chemistry



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)




Air in-leakage to condenser or deaerator



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



Air in-leakage to condenser or deaerator



Boiler Tubing

2-15



Cycle Chemistry Precursors – Units on Caustic Treatment

Caustic used in excess of the amount necessary for optimal control (>>2 ppm)




Maintenance-Related Precursors – Chemical Cleaning

Evidence of shortcoming in chemical cleaning process, such as inappropriate cleaning agent, excessively strong concentration, or long cleaning time

Too high a temperature

Failure to neutralize, breakdown of inhibitor, or inadequate rinse

Chemical cleaning damage in waterwalls



Inadequate flush after chemical cleaning

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


Inadequate flush after chemical cleaning

Need for excessive cleaning in supercritical units (interval <2 years)


Non-optimum cycle chemistry; AVT with all ferrous metallurgy


Maintenance-Related Precursors – Repairs

Backing rings, pad welds, canoe pieces, or weld overlays that penetrate to inside surface and become a source of flow disruption and excessive deposits in water-touched tubes.

Hydrogen damage


Caustic gouging

Specification and/or performance of repair procedures

Pad welds applied with too little tube thickness; improperly used for long-term fix

Boiler Tubing

2-16



Backing rings, pad welds, canoe pieces, tube section replacements, or weld overlays become a source of stress concentration and chemical vulnerability in water -touched tubes.

Stress corrosion cracking


Corrosion-fatigue

Hydrogen damage

Problems with specification and/or performance of repair procedures, including:

• Penetration of heat-affected zone to inside surface

• Chemical interaction with deposits on inside surface

• Pad welds applied with too little tube thickness; improperly used for long-term fix

• Dissimilar metal welds

• Poor preparation before weld-buildup

• Poor match between thermal expansion coefficients of weld material and base material

Improper selection of weld rod/wire, flux, heat input, inert gas flow rate, etc.

Cu in waterside deposits in water-touched tubes

Hydrogen damage Copper embrittlement or other welding defects caused by copper in deposits

Non-optimum cycle chemistry; excess oxygen, CO2, or NH3 with mixed metallurgy


Improper repair procedures

Operation-Related Precursors – Combustion Conditions

Heat flux change caused by a change to higher Btu-value coal, dual firing with gas, or changeover to oil- or gas-firing leading to excessive tube deposits in waterwalls

New burners causing impingement

Hydrogen damage


Caustic gouging

Fireside corrosion

Improper adjustment after change of burners or fuel.

Excessive deposits result from high heat flux or flame impingement

Boiler Tubing

2-17



Implementing low excess air strategies for NOX control and the potential for waterwall fireside corrosion


Load cycling leading to fireside chemistry cycling between reducing (full load, low excess air) and oxidizing (part load, higher excess air)

Reducing conditions weaken protective oxide coating. FeS decomposition forms corrosive gas under oxidizing, mildly reducing, and alternating conditions. FeS may be related to pyrite in coal.

Operation-Related Precursors – Fuel Choices and Changes

Fuel change involving either more ash or elements that are more erosive, such as quartz

Fly ash erosion

Thermal shock/fatigue cracking on fireside

Flow design or damper adjustment

Inadequate liners, tube shields

Plugging or channeling creates local high velocity

Design velocity too high for high ash levels

Thermal shock/stress due to steam/water contact during sootblowing/deslagging

Fuel change involving a more corrosive coal, particularly one high in chloride, Na, K, or S content


Use of Mg-based additives for oil-fired units, leading to coating of waterwalls, reflecting heat into convection passes

Long-term overheating (creep)

Coating of waterwalls, reflecting heat into convection passes

Operation-Related Precursors – Cycling

Conversion of the unit to cyclic operation, or an increase in the number of cycles

Fatigue and corrosion-fatigue in water-touched tubing

Thermal and mechanical stress due to cycling.

Overfire during startup

Changes in feedwater heater alignment

Inadequate cycle chemistry control (load cycling leads to waterside chemistry cycling)

Boiler Tubing

2-18



Operation-Related Precursors – Shutdown or Layup

Evidence of a shortcoming during unit shutdown/layup, such as uncertainty about water and/or air quality

Insufficient nitrogen blanketing

Insufficient oxygen scavenger

Evidence of air in-leakage

Pitting in water-touched or steam-touched tubing

Maybe corrosion-fatigue

Air in-leakage causing pH depression in oxygen-rich water with stagnation during shutdown/layup

Cycling leading to thermal/mechanical stress cycles and difficulty in controlling cycle chemistry

Indication that stagnant, oxygenated water may have rested in tubes during shutdown or layup, particularly in economizer and RH

Pitting in water-touched or steam-touched tubes


Inadequate shutdown/layup procedures


Operation above the design maximum continuous rating with excess air flow settings and unbalanced fans or air heaters, leading to non-uniform gas flows

Fly ash erosion Non-uniform gas flows. May be accentuated by plugging of gas passages; design that creates non-uniform flows

Low drum level Short-term overheating Inadequate or misadjusted drum level control

Fouling or damage to level sensor

Specific Equipment – Precursors Involving Condensers

Major condenser leaks or minor leaks that have occurred over a long period of time

Hydrogen damage Non-optimum cycle chemistry and/or metallurgy allowing corrosion in condenser

Cathodic protection problem allowing corrosion in condenser

Inadequate conductivity sensor/alarm


Specific Equipment – Precursors Involving Water Treatment Plant or Condensate Polisher

Upset in water treatment plant or condensate polisher regeneration chemicals leading to low pH in the boiler (pH <8); Hydrogen damage

Upset in water treatment plant or condensate polisher regeneration chemicals leading to low pH in the boiler (pH <8) Inadequate conductivity sensor/alarm


Boiler Tubing

2-19



Upset in water treatment plant or condensate polisher regeneration chemicals leading to high pH condition

Caustic gouging Upset in water treatment plant or condensate polisher regeneration chemicals leading to high pH



Specific Equipment – Precursors Involving Sootblowers

Poor sootblower design, maintenance or operation

Sootblower erosion in waterwalls

Thermal shock/fatigue cracking on fireside

Excessive concentration of flow due to nozzle design, nozzle damage, or flow control

Overlapping flow due to misalignment

Excessive use of sootblowers

Thermal shock/stress due to steam/water contact during sootblowing/deslagging

Specific Equipment – Precursors Involving Supports/Attachments

Original or redesigned waterwall tube attachments without adequate stress analysis

Corrosion-fatigue Source of stress in combination with non-optimum cycle chemistry (most likely during cyclic operation)

Inadequate flexibility in support design

Redesign to increase flexibility without analysis to determine whether solution is actually beneficial

Failure to account for shifts in boiler structure; deterioration of supports with age

Boiler Tubing

2-20

Table 2-10 Screening Table for Waterwall Tubing Failures

Arranged by Typical Fracture Surface Appearance

Other Likely Macroscopic and

Metallographic Features

Typical Location(s)

Possible Mechanism

Potential Root Cause(s) for Waterwall Tubing Failure

Thick-Edged Fracture Surface

Multiple, transgranular cracks that initiate on the inside of the tube

Pinhole leak also possible

Near attachments, particularly where high restraint stresses can develop

Near membrane weld on hot or cold side of tube

Corrosion-fatigue

Excessive stresses/strains from the original design, especially at attachments

Environmental factors, such as poor water chemistry, overly aggressive or improper chemical cleaning, and improper boiler shutdown and/or layup practices

Operating procedures that produce high stresses (e.g., fast ramping, change in feedwater heater lineups, etc.)

Subcooling in natural circulation boilers during two-shift or weekend shutdown operation

Metallurgical changes during membrane welding

Leak or window blowout

Internal damage, such as gouging or wall thinning

Tube deposits

High heat flux areas

Hot side of tube

Horizontal or inclined tubing

Pad welds

Locations with local flow disruptions, such as upstream of weld

Backing ring or other discontinuities

Hydrogen damage

Excessive localized deposits due to flow disruptions attributable to weld bars/rings, poor weld geometry, pad welds, canoe piece repairs, locally high heat flux or steam quality, bends or sharp changes in tube direction, horizontal or near-horizontal tubing, or departure from nucleate boiling (DNB)

Flame impingement, burner misalignment, fuel change, or furnace modification that alters slag deposit patterns

Acidic contamination from condenser leaks (either a prolonged minor leak or a major ingress event), a chemical upset in the water treatment plant or condensate polisher regeneration that creates a low pH condition, or an error in chemical cleaning

Boiler Tubing

2-21



Typical Location(s)

Possible Mechanism


Multiple, parallel cracks around circumference on outside tube surface or on membrane

Sharp, V-shaped oxide-filled cracks

Wall thinning from external surface when found with fireside corrosion

Maximum heat flux locations

Fireside or waterside tubing, or membranes between tubes


(corrosion-enhanced thermal fatigue on fireside)

Excessive internal deposits leading to increased tube metal temperatures

Thermal cycling caused by slagging/deslagging

Fireside deposits, wastage, and surface cracking caused by cycling stresses and other operating factors

Wastage related to cycling between oxidizing and reducing conditions during load cycling with low-NOX combustion

Outside surface-initiated

Intergranular crack growth with evidence of grain boundary creep cavitation and creep voids

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

Low-temperature creep cracking

A combination of high residual and service stresses

Transgranular cracking that is OD-initiated and associated with tubing

Near attachments, particularly solid or jammed sliding attachments

At bends in tubing

At toe of membrane welds

Fatigue

Creep-fatigue

Poor design (excessive strains due to thermal expansion)

Poor manufacturing (excessive mechanical stresses or residual stresses)

Flue-gas-induced vibration by direct flow or vortex shedding

Poor welding, especially poor geometry of final joint

Cyclic operation

Thermal cycling caused by slagging/deslagging

Thermal shock caused by water or steam contact during sootblowing/deslagging

Boiler Tubing

2-22



Typical Location(s)

Possible Mechanism


Thin-Edged Fracture Surface

Longitudinal

Cod- or fish-mouth

Polishing of outside surface of tube

Localized damage

Wastage flats

Near side and rear walls

Fly ash erosion

Excessive local velocities due to non-uniform gas flow attributable to poor design geometry; distortion or misalignment of tubing rows, gas flow guides, or baffles during maintenance; improperly placed corrective shields or baffles or poorly applied coatings; operation above the design maximum continuous rating above design airflow, or at high excess air; or convective pass fouling

Increase in particle loading and erosive ash elements, such as quartz and iron pyrite

Leak or split

Internal damage, such as gouging and wall thinning

Tube deposits


Hot side of tube


Pad welds




Excessive localized deposits due to flow disruptions attributable to weld bars/rings, poor weld geometry, pad welds, canoe piece repairs, locally high heat flux or steam quality, bends or sharp changes in tube direction, horizontal or near-horizontal tubing, or DNB


Improper cycle chemistry controls, particularly chasing phosphate hideout by using monosodium phosphate and/or an excess of disodium phosphate

Boiler Tubing

2-23



Typical Location(s)

Possible Mechanism


Leak or split

Internal damage, such as gouging and wall thinning

Tube deposits


Hot side of tube


Pad welds



Caustic gouging

Excessive localized deposits due to flow disruptions attributable to weld bars/rings, poor weld geometry, pad welds, canoe piece repairs, locally high heat flux or steam quality, bends or sharp changes in tube direction, horizontal or near-horizontal tubing, or DNB


Caustic concentration due to elevated caustic levels over time (for units using caustic cycle water treatment), excessive caustic addition to units using all-volatile or phosphate treatment, and water treatment upside leaking to high pH condition (e.g., regeneration of condensate polishers or makeup water on exchange resins)

Long fish-mouth

External wastage

Probably affects numerous tubes

Maximum wastage at crown facing flame (may be flame impingement)

Damage extending in 120o arc around tube

Hard deposits on outside surface of tube

Areas with locally sub-stoichiometric environment

Side and rear walls near burners

Highest heat flux areas

Fireside corrosion (coal-fired units)

Poor general combustion conditions or poorly adjusted or worn burners

Altered combustion air levels and/or distribution, such as low excess air operation with reducing condition at full load cycling to oxidizing at part load, low-NOX burners with overfire air, incomplete combustion (i.e., high CO and LOI) with high-sulfur coal, flame impingement, and high FeS deposits in areas with free oxygen

Excessive internal deposits leading to increased tube metal temperatures

Changing to a more corrosive coal, particularly one high in chloride, Na, K, or S content

Carbon particle impingement and carbon deposition

Boiler Tubing

2-24



Typical Location(s)

Possible Mechanism


Fish-mouth

Wastage flats on tube external surface at 45o around tube from sootblower direction with little or no ash

Circular pattern around wall blowers

Sootblower erosion

Incorrect setting of blowing temperature (insufficient superheat)

Condensate in blowing media

Improper operation of moisture traps

Excessive sootblowing pressure

Improper location of sootblower

Misalignment of sootblower

Malfunction of sootblower


Usually thin-edged

Often shows signs of tube bulging or fish-mouth appearance

Real keys will be transformation products in microstructure

May also be thick-edged under certain circumstances

Highest heat flux locations above the site of a tube or orifice blockage

In horizontal tubing where a downcomer steam “slug” can occur


Tools left in tubes during maintenance

Improperly executed weld repairs (e.g., weld spatter allowed to fall into tubes)

Plugging of waterwall orifices by feedwater corrosion products

Poor control of drum level

Over-firing on startup

Loss of coolant because of upstream tube failure

External wastage with little or no ash

Location should be key

Tubes near replaceable wear liners in cyclone burners

Throat or quarl region of burners

Coal particle erosion

Failed protective devices (e.g., wear liners for cyclone burners, refractory for PC burners)

External erosion or mechanical impact damage features

Sloping wall tubes and/or ash hopper near bottom

Falling slag damage

Erosion or impact by fused coal ash deposits or re-solidified molten slag that detached from furnace walls and SH pendants

Boiler Tubing

2-25



Typical Location(s)

Possible Mechanism


Pinhole Damage

Internal tube surface damage

Locations where boiler water can stagnate during unit shutdown

Chemical cleaning damage

Pitting

Poor shutdown procedures leading to formation of stagnant, oxygenated water

Poor water chemistry control (e.g., high dissolved oxygen, condenser leak, and inadequate layup protection)

Improper chemical cleaning, including use of an inappropriate cleaning agent, excessively strong acid concentration, too high a temperature (breakdown of inhibitors), and failure to neutralize, drain, and rinse after cleaning

Other Types of Damage – Fracture Surface Appearance Depends on Underlying Cause

Depends on underlying cause

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

Any location; most likely at areas with greater exposure during maintenance (e.g., crown of tube on fireside or cold-side or edge or end of panel sections)

Maintenance damage

Overstress

Fatigue

Creep

Creep fatigue

Corrosion pitting


Compromised pressure boundary

Impact, grinding, or heat damage site may not be obvious without close inspection

Through-wall cracks have originated at barely perceptible indentations

Various damage mechanisms may propagate from work hardened area, weld HAZ, or area of thinning

Overheating due to flow restriction: indentation, buckling, sediment, scale, foreign objects left in tubing

Crack in protective oxide creating vulnerability during layup/startup chemistry conditions

Excessive localized deposits due to flow disruptions

Boiler Tubing

2-26



Typical Location(s)

Possible Mechanism


Appearance varies with location and nature of defect

Damage may propagate from flaw at any location and at any time in unit life. Most likely early in life or after change fuel increase cycling, or increase operating pressure and/or temperature.

Most likely at bends and welds

Material flaws leading to:

Overstress

Fatigue

Creep

Creep fatigue

Corrosion pitting


Metallurgy or wall thickness out-of-spec

Improper bending procedures causing work hardening; excessive thinning

Improper heat or solution treatment

Various damage mechanisms may propagate from work hardened area, weld HAZ, area of thinning, or weld/base metal inclusion(s)

Shop damage may not be obvious without close inspection (impact, grinding, or heat damage site)

Usually thick-edged or pinholes

Welding flaws leading to:

Overstress

Fatigue

Creep

Creep fatigue

Corrosion pitting


Defect may result from one or multiple flaws in welding materials or process, including heat input, weld metal, inclusions, preheat, post-weld heat treatment (PWHT), or failure to clean contaminants from tubing interior before welding on exterior. Care is required to separate weld defects from another problem located at a weld.

Excessive localized deposits due to flow disruptions

NDE and Sample Evaluation Options for Waterwall Tubing

Table 2-11 lists inspection means recommended for assessing the condition of waterwall tubing and associated supports, in accordance with Action 4 in the boiler tube condition assessment roadmap (Figure 2-1). At the time of this update, available techniques remain less than ideal for obtaining a thorough and accurate picture of tubing condition over the full extent of the waterwalls. Detecting corrosion-fatigue cracking, on the cold side of waterwall tubing, remains particularly problematic when outage duration is insufficient for removing lagging, insulation, and other impediments to access.

Boiler Tubing

2-27

Tradeoffs must be made between desired accuracy and available time and budget for inspection. As research and development work continues on a regular basis, the EPRI NDE center should be consulted for up-to-date advice on equipment and processes.

NDE and destructive evaluation options are categorized as a function of the condition assessment level being pursued (i.e., II or III). For inspections on units without significant operating changes or reducing stoichiometry, and a history of predictable tubing wear, EPRI recommends starting with the lower-cost Level II methods. The more-involved Level III methods are used if additional data on crack sizes or thinning rates can provide greater confidence in the remaining life estimates, with value sufficient to justify the added costs).

As noted in Chapter 1, EPRI recommends using the Level III NDE techniques, and considering sampling techniques (destructive evaluation), if the goal is to support an operating plan that entails greater risk of damage. Relevant conditions include:

• long outage intervals

• low-grade fuels

• extensive combustion staging for NOX control

• cycling, or other “challenging” conditions

• tube sections known to be prone to rapid wastage or frequent failure

Sample evaluation techniques should be used to determine the root cause of a tube failure.

Boiler Tubing

2-28

Table 2-11 NDE Options for Waterwall Tubing

Component / Location NDE Detection Technique (Level II)

NDE and Sample Evaluation Techniques (Level III)

Tubing Visual

Video probe

Dimensional

Hardness testing

Conventional ultrasonic testing (UT)

Electromagnetic acoustic transducer (EMAT)

Low-frequency eddy current (LFEC)

Magnetostrictive Sensor Guided-Wave (MsS)

Radiographic testing (RT)

• Conventional film

• Digital imaging

Flash thermography/active infrared response

Replication

UT

EMAT

LFEC

RT

Phased array (focused) UT—more extensive scan of damage indication, such as linked or oriented cavities

Time-of-flight diffraction UT—more extensive scan to accurately size flaws

Sample removal and testing:

• Visual

• Hardness

• Oxide dating

• Chemical analysis of deposits

• Chemical analysis of metallurgy

• Visual microscopy, with and without etching

• Electron microscopy

• Cryogenic cracking

• Tensile and toughness testing

Membranes Visual

Magnetic particle testing (MT)

Penetrant testing (PT)

Welds Visual

Hardness testing

MT/PT

RT

Phased array (focused) UT

Time-of-flight diffraction UT

Sample removal and testing (as shown for tubing)

Boiler Tubing

2-29



Supports/attachments Visual/video inspection

PT

MT

Analysis and Disposition for Waterwall Tubing

Table 2-12 summarizes minimum wall thickness criteria, allowable crack size criteria, and recommended analysis or action options for flaws found in waterwall tubing. Detailed analysis procedures are contained in EPRI’s Boiler Tube Failures: Theory and Practice and other EPRI technical reports.

EPRI recommends using Level III inspection methods when crack growth analyses based on NDE Level II methods does not provide remaining life estimates with an acceptable margin for uncertainty, if the value of the added RL confidence warrants the time and expense of additional testing.

The time interval for conducting the next condition assessment activity should be set after run/repair/replace decisions have been made. Typically, intervals are established to support planning efforts for major maintenance outages. Obviously, the interval should not exceed the estimated remaining life produced by the analysis (based on wall thinning and crack growth projections).

All analysis results and disposition decisions should be documented as part of a comprehensive boiler condition assessment program. Estimates of remaining waterwall tubing life should be reassessed whenever there is a significant change in furnace operating conditions, such as a change in fuel or fuel additives, furnace stoichiometry or heat absorption patterns, sootblower scheduling, boiler cycle water treatment, or duty cycle.

A post-outage review should be performed to note information and procedural shortcomings and develop recommended changes in inspection techniques, on-line monitoring, and outage preplanning.

Table 2-12 Analysis and Disposition for Waterwall Tubing

Component / Location

Permissible Flaw Size Recommended Analytical Techniques and Disposition

Tubing (inside surface)

Minor wall loss that does not result in wall thickness <70% of design minimum

Minor corrosion-fatigue cracking, less than 30% through wall

Confirm damage mechanism and determine extent of damage using Level II and/or Level III NDE and material testing techniques

Evaluate stresses and remaining life for wall loss plus crack depth <30% of thickness

Boiler Tubing

2-30



Damage growth not to exceed limits before next planned inspection

Corrosion pitting can result in failure by reducing wall thickness below pressure design minimum or by acting as initiation sites for fatigue cracking

Localized pitting can be evaluated in detail to determine actual minimum wall limits according to ASME (American Society of Mechanical Engineers) code

As necessary, replace tubing to restore wall integrity

Pad-welding to restore wall thickness should be done only on an emergency basis and only as a temporary repair until tubes can be replaced

Address root cause(s) of corrosion pitting, fatigue, and/or corrosion-fatigue

Tubing (fireside) Minor wall loss that does not result in wall thickness <70% of design minimum




Wall loss can occur via corrosion and erosion mechanisms. Minor wall loss can be trended over time by performing periodic wall thickness measurements.


In many cases, weld build-up with high chrome material can restore wall thickness in addition to providing protection against corrosion. Minimum remaining wall thickness is required to prevent heat damage that compromises the mechanical or chemical characteristics of the inside surface.

Pad-welding to restore wall thickness should be done only on an emergency basis and only as a temporary repair until tubes can be replaced

Address root cause(s) of corrosion (wastage), fatigue, and/or corrosion-fatigue

Boiler Tubing

2-31

Preventive Actions for Waterwall Tubing

As noted in the introduction to condition assessment for boiler tubing, the most effective approach to obtaining optimum life is to eliminate the root cause(s) of the damage mechanism(s) that can or have produced failures in the waterwall tubing. Table 2-13 summarizes preventive actions applicable to typical root causes and damage mechanisms. This listing is simplified to provide preventive actions for the general groupings of the various root causes seen in the right hand column of Tables 2-9 and 2-10. For each case, choice of a preventive action should be based on a careful review of all factors acting on the specific tubing or component area(s) during particular modes of operation and for particular methods of cycle chemistry control.

Many damage precursors can be addressed by applying appropriate corrective action to normal operation and maintenance activities, without a major impact on plant performance and without the need for major capital investment. Plant personnel may choose to implement these actions if a given damage type is suspected, without it being formally identified through the three-level process for assessing the condition and remaining life of waterwall tubing.

Table 2-13 Preventive Actions for Waterwall Tubing Damage

Category Corrective Actions Comments

Root causes involving corrosion and deposits related to cycle chemistry

Review cycle chemistry and optimize per EPRI guidelines

Consider changing feedwater treatment program, for example:

• Reduce corrosion in all-ferrous systems by changing from AVT to AVT(O) or oxygenated treatment

• Address phosphate hideout and return by changing type or quantity of phosphate and/or caustic or by changing to equilibrium phosphate treatment (EPT)

AVT(O) is similar to standard AVT but increases the oxygen concentration

Review cycle chemistry monitoring process and procedures. Remedy shortcomings.

Review design, function, and condition of cycle chemistry monitoring instrumentation. Remedy shortcomings.

Review design, function, and condition of makeup water treatment system. Remedy shortcomings in equipment and/or procedures.

Review design, function, and condition of condensate polishing system. Remedy shortcomings in equipment and/or procedures.

Consider adding condensate polisher if not already installed

Boiler Tubing

2-32


Determine and remedy cause of contamination by condensate polisher or demineralizer regeneration chemicals

Verify high conductivity alarms settings and function

Root causes involving fireside erosion, corrosion, combustion conditions, fuel choices, and/or excessive heat flux

Review design, function, and condition of plant instrumentation and control systems. Remedy shortcomings

Review design, function, and condition of burners. Correct burner alignment, balancing, air-fuel mix, etc. Repair damage.

Consider replacement of burners

Maintain feeders, pulverizers, etc., to prevent failures leading to burner outage and firing imbalance

Review design basis, function, and condition of fans and air heaters. Adjust/balance/repair as needed to remedy shortcomings.

Review design, function, and condition of tube shields. Remedy shortcomings.

Adjust burners and/or over-fire air to minimize conditions leading to waterwall wastage

Boiler Tubing

2-33


Increase corrosion resistance of fireside surface with weld overlay, spray metal deposition, or anti-corrosion/anti-slagging coatings

Install tubing with better corrosion resistance (duplex tubes, shop-applied weld overlay with high chromium alloys). Chromium content >20% is general rule for adequate protection from reducing and acid gas conditions.

Results have been inconsistent; consult with EPRI and other specialists for up-to-date technologies and test results to ensure choice of proper materials and procedures

The best weld overlay results are generally obtained by matching thermal expansion coefficients and minimizing thickness and heat input. Minimum remaining wall thickness is required to prevent heat damage that compromises the mechanical or chemical characteristics of the inside surface.

Consider impact of weld overlay profile on future inspections

Adjust flow dampers and monitor fly ash erosion damage rate to allow timely replacement of liners and shields after a change to a fuel that contains either more ash or elements that are more erosive, such as quartz

Review coal properties versus boiler design parameters

Consider blending coals, rather than alternating, to optimize flame characteristics, erosivity, corrosivity, ash, and slagging

Reduce or eliminate Mg-based oil fuel additive to reduce waterwall coating. Perform periodic wall cleaning.

Boiler Tubing

2-34


Review design, function, and condition of sootblowing systems; monitor frequency of use. Remedy shortcomings in equipment, operating procedures, or maintenance procedures.

Consider implementing intelligent sootblowing (ISB) to provide consistently appropriate sootblowing activity in response to slagging, fouling, temperature, heat flux, and other boiler performance information

Sootblowing and deslagging alternatives include steam, water, and air nozzle arrays and lances, water cannons, and sonic horns

An ISB system typically includes a PLC for sootblower control, a PC for analysis and planning, and integration with the plant DCS for information gathering

Root causes involving inadequate cooling

Check for flow blockages. Purge or manually clean tubing and/or orifices. Chemically clean boiler as necessary.

Review cycle chemistry and remedy problems for root cause of blockage resulting from deposition or exfoliation

Review flow distribution design. Change orifice sizing or perform other remedy for cause of imbalance.

Check design, function and condition of circulation pump, if applicable. Remedy shortcomings.

Check design, function and condition of drum internals and susceptibility of downcomers to steam carryover. Remedy shortcomings.

Review design, function, condition of drum level control and alarms. Remedy shortcomings to maintain drum water level.

Root causes involving cycling

Review/improve startup and shutdown procedures to minimize rate and magnitude of temperature, pressure, and stress transients

Upgrade controls to minimize instability caused by over-firing and under-firing during load ramping

Install off-line boiler circulation pumps to reduce subcooling

Implement condition monitoring to better predict remaining life

Boiler Tubing

2-35


Install on-line water chemistry sampling, analysis, and chemical feed systems to improve awareness and response to fluctuations during cycling

Implement changes to reduce stress due to hot-side–to–cold-side temperature difference by reducing cold side heat loss, by:

• Sealing casing/lagging leaks

• Repairing insulation voids

• Installing baffles to reduce convective heat transfer

• Optimizing insulation and supports to minimize conductive heat transfer

• Applying low emissivity coatings (to cold side of tubing and membranes and support hardware) or reflective sheeting (to insulation) to reduce radiant heat transfer

Root causes involving shutdown or layup

Review procedures and monitoring capability prior to shutdown/layup. Remedy shortcomings.

• Monitor water quality before/during shutdown

• Monitor moisture and other air quality parameters during shutdown/layup

• Ensure plentiful supply of nitrogen or clean, dry air

• Review and monitor oxygen scavenger injection quantity and locations

• Consider pressurization/ depressurization procedures to clear exfoliated scale and trapped water and ensure change-over to clean, dry air or nitrogen

Boiler Tubing

2-36


Root causes involving condenser design, condition, or operation

Check and repair tube leaks. Determine and remedy root cause of tube leaks:

• Check and correct cycle chemistry and/or monitoring procedures/equipment

• Check and correct problems with condenser cathodic protection

• Consider applying coating to interior and/or exterior of condenser tubing and tubesheets

Consider replacing tube bundle with metallurgy (e.g., titanium) more resistant to cooling water chemistry

Check and remedy air in-leakage

Consider replacing tube bundle with metallurgy that allows change in cycle chemistry

Change from AVT to AVT(O) or oxygenated treatment may be practical if copper based alloys can be eliminated from the feedwater heaters in the feedwater system

Root causes involving chemical cleaning

Review chemical cleaning procedures. Remedy shortcomings.

Replace damaged tubing

Shortcomings in chemical cleaning process may involve inappropriate cleaning agent; overly strong concentration; long cleaning time; temperature too high; failure to neutralize; breakdown of inhibitor; inadequate rinse

Review frequency of chemical cleaning

Optimize cycle chemistry per EPRI guidelines to minimize corrosion and redeposition

Consider change to Oxygenated Treatment to reduce excessive need for cleaning in supercritical units (interval <2 years) (see note above on copper metallurgy)

Root causes involving repairs

Review records of repairs versus EPRI reports indicating problematic procedures. Perform life assessment. Make run/repair/replace decision.

Backing rings, pad welds, canoe pieces, or weld overlays that penetrate to inside surface and become a source of flow disruption and excessive deposits in water-touched tubes

Review in-house and vendor repair procedures prior to outage. Revise repair procedures to eliminate potential damage sources.

Boiler Tubing

2-37


Review presence of Cu in waterside deposits in water-touched tubes.

• Revise and carefully monitor repair procedures related to welding in presence of copper.

• Evaluate and modify cycle chemistry to reduce copper corrosion and redeposition.

• Consider condenser/feedwater tubing changes to eliminate future copper deposits.

Consider chemical cleaning prior to welding

Root causes involving supports/ attachments

Perform detailed evaluations to validate design of supports/attachments. Perform follow-on monitoring to confirm effectiveness.

Redesign waterwall tube attachments to increase flexibility. Perform detailed analysis before implementing changes; follow-on monitoring to confirm effectiveness.

2.5 Superheater/Reheater (SH/RH) Tubing

Like waterwall tubing, superheater and reheater tubing presents many challenges for condition assessment and damage prevention. High heat flux and challenging chemistry are related to numerous damage mechanisms on interior and exterior surfaces of the tubing. Tube wall temperatures vary between tubes and at different locations in every tube. Pendant, platen and support structure designs concentrate stress in some locations. Spacing of tubes, other furnace design features, and fouling may concentrate gas flow at certain locations, resulting in accelerated erosion, corrosion, slagging, ash buildup, and heat flux. Flow blockage and channeling may cause stresses due to uneven heat distribution.

Inspection access has traditionally required extensive scaffolding inside the furnace. Tight tube spacing often limits access to many tube surfaces.

New condition assessment technology and better understanding of damage mechanisms are helping to reduce the frequency of superheater and reheater tubing failures. New repair techniques are reducing costs and outage duration. The most significant developments include:

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

Boiler Tubing

2-38

• Portable digital radiographic equipment (digital phosphor plate radiography) is providing increased resolution and/or reduced source strength (with smaller exclusion zones) compared to traditional film-based radiography

• Smaller sized tools, versatile reaching devices are providing easier access on the interior of tubing passes. Efforts are addressing access issues for pendant section tubing using robotic systems, similar to those developed for waterwall tubing, which maneuver with magnetic treads or similar attachment to the tube surfaces.

• Use of weld overlay, spray coatings, and nonmetallic coatings have shown varying success for repairing or reducing erosion and corrosion


• Experience-based refinements in cold air velocity testing and use of flow control devices to redistribute flow and reduce erosion

Damage Mechanisms for SH/RH Tubing

Because of the large number of potential damage mechanisms for superheater and reheater 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 investigated, with the objective of identifying corrective actions that can slow or eliminate future damage.

Table 2-14 categorizes superheater and reheater tubing damage mechanisms by their likely precursors. Table 2-15 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. These tables are adapted from comparable tables for steam-cooled tubing in Volume 3 of EPRI’s Boiler Tube Failures: Theory and Practice.

Appendix A provides descriptions 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).

Boiler Tubing

2-39

Table 2-14 Precursors for Superheater and Reheater Tubing Damage

Precursor Mechanisms of

Concern for SH/RH Tubing


Inspection / Appearance Precursors – Steam-Touched Tubes (Steamside)

Excessive steamside oxide, which may be detected by:

UT measurement of oxide thickness or analysis of removed tube samples

Buildup of excessive exfoliation in U-bends of pendants

Solid particle erosion in the HP turbine and/or turbine bypass valve(s)


SH/RH fireside corrosion

Dissimilar metal weld failures


Flow distribution problems

Reduced heat flux in radiant section due to slagging; magnesium coating in oil-fired boilers.

Over-firing

Inadequate/improper chemical cleaning

Metallurgy not suitable for peak temperatures

Steamside deposits in SH and RH tubing.

Pitting and failure in steam-touched tubes

Sodium sulfate, or high Na or SO4 levels in steam carryover from drum may be caused by problems with drum internals (separation) or level control; foaming in drum. May be increased by excessive chemical addition to drum, inadequate blowdown.

Deposits containing iron oxides and/or copper may result from contaminants in attemperator spray water or boiler feedwater.

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





Boiler Tubing

2-40




Inspection / Appearance Precursors – Steam-Touched Tubes (Fireside)

Excessive flue gas temperature

Displaced fireball

Delayed combustion

Periodic overfiring or uneven firing of burners

Excessive furnace slagging (or fuel change) that could lead to overheating in the convective passes




Misaligned, misbalanced, or damaged burners

Burner settings not corrected after fuel change

Poor match between furnace characteristics and new fuel.

Misaligned, misbalanced, or damaged fans or dampers

Problems with sootblowing design, operation, or maintenance.

High levels of excess oxygen

SH/RH fireside corrosion for oil-fired unit





Blockage or laning of boiler gas passages observed during inspections

Fly ash erosion


SH/RH fireside corrosion for coal- and oil-units


Non-optimum flow distribution due to furnace design.



Problems with flow distribution introduced by redesigned platens, pendants, etc.

Boiler Tubing

2-41




Excessive temperatures measured by thermocouples in vestibule or header area

Fly ash erosion



Blockage/channeling due to problems with sootblowing design, operation, or maintenance

Non-optimum flow distribution due to furnace design, operation, or maintenance



Poor match between furnace characteristics and new fuel



Problems with steam flow distribution

High turbine stop valve pressure setting

Problems with attemperator design, operation, or maintenance

Evidence of “alligator hide” appearance on external tube surface found during boiler inspection and associated with wall loss or thinning










Problems with steam flow distribution

High turbine stop valve pressure setting

Problems with attemperator design, operation, or maintenance

Boiler Tubing

2-42





External flat spots


Fly ash erosion

Sootblower erosion in SH/RH





Problems with flow distribution introduced by redesigned platens, pendants, distribution and diffusion screens, etc.

Significant hardness or ovality found during routine inspection, particularly on tube bends


Improper temperature and/or strain rate used during tubing manufacture

Improper heat treatment after forming

Shortcomings in metallurgy of base tubing stock

Distorted or misaligned tube rows found during routine inspection

Fly ash erosion



Fatigue of SH/RH tubing

Rubbing/fretting

Constrained movement due to design problems or damage to supports or attachments

Bowing and/or thermal shock resulting from condensate flow during startup

Bowing and/or thermal shock resulting from use of water lances for deslagging

Bowing resulting from temperature imbalance caused by gas-side or steam side flow imbalance

Furnace explosion

Failed tube supports and lugs

Location of dissimilar metal welds close to fixed supports

Fatigue of SH/RH tubing


Constrained movement due to design problems or damage to supports or attachments

Bowing and/or thermal shock resulting from condensate flow during startup

Bowing resulting from temperature imbalance caused by gas-side or steam side flow imbalance

Boiler Tubing

2-43





Carryover of non-volatile chemicals from boiler, such as NaOH for units on caustic treatment, or excess Na, SO4, and/or chloride


Pitting in SH/RH tubes



Sodium sulfate or high Na or SO4 levels in steam carryover from drum may be caused by problems with drum internals (separation) or level control; foaming in drum. May be increased by excessive chemical addition to drum, inadequate blowdown. May be related to inadequate steam blows and chemical cleanings during commissioning.

Deposits containing iron oxides and/or copper may result from contaminants in boiler feedwater






Condenser leak, leading to condenser cooling water constituents in attemperator spray water or drum makeup/boiler feedwater


Pitting in SH/RH tubing



Deposits and/or chloride contamination resulting from condenser tube leaks caused by:

• Problems with cycle chemistry control; mismatch between cycle chemistry and condenser metallurgy

• Inadequate condenser maintenance plan

• Thermal shock resulting from inadequately controlled/attemperated bypass to condenser

Contaminants introduced by tube leakage not detected/remedied due to:

• Problems with design, operation, or maintenance of high conductivity alarms

• Problems with design, operation, or maintenance of condensate polisher

Boiler Tubing

2-44





Shortcoming in chemical cleaning process, such as inappropriate cleaning agent, excessively strong concentration, or long cleaning time, too high a temperature, inadequate flow verification, failure to neutralize, breakdown of inhibitor, or inadequate rinse

Chemical cleaning damage in SH/RH

Short-term overheating SH/RH tubing

Inadequate planning, implementation, and monitoring of chemical cleaning program

May involve inadequate information on cycle chemistry program, plant metallurgy, tubing volume, etc.

Inadequate training of personnel responsible for planning, implementation, and monitoring of chemical cleaning program

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 or SH/RH


May involve inappropriate cleaning agent, excessively strong concentration, inadequate flow verification, failure to neutralize, breakdown of inhibitor, or inadequate rinse

Contamination in SH/RH (particularly by chlorides) during chemical cleaning of SH/RH (breakdown of inhibitors or improper flushing of solvents) or waterwalls (caused by poor backfill procedures that failed to protect SH circuits)




Modification/application of shielding, baffles, or palliative coatings to mitigate fly ash erosion without the use of a cold-air velocity test

Fly ash erosion

Fireside corrosion

Introduction of non-optimum flow distribution with high velocity areas conducive to erosion

Ash trapped in gaps between shielding and tubing holds water in contact with tubing during shutdown/layup

Boiler Tubing

2-45




Backing rings, pad welds, canoe pieces, tube section replacements, or weld overlays become a source of stress concentration, chemical vulnerability, creep vulnerability in steam-touched tubes


Thermal/ mechanical fatigue

Hydrogen damage


Caustic gouging


Creep and creep-fatigue




• Pad welds applied with too little tube thickness; improperly used for long-term fix

• Dissimilar metal welds



• Improper selection of weld rod/wire, heat input, inert gas flow rate, etc.

Operation-Related Precursors – Startup Procedures

Rapid unit startups that cause the reheater to reach temperature before full flow starts (no furnace exit gas temperature control)


Inadequate startup procedures

Inadequate training of operations personnel on startup procedures and component life extension

Problems with design, operation, and/or maintenance of instrumentation and control systems

Operation-Related Precursors – Combustion Conditions and Additives (Oil-fired Units)

Operation with high levels of excess oxygen (>1%)

SH/RH fireside corrosion in oil-fired units

Problems with design, operation, and/or maintenance of air-fuel ratio controls and monitoring systems

Inadequate training of operations personnel

Changes in fuel without corresponding changes in procedures, instrumentation settings, burner settings, or fan settings

Operation with Mg-based additives


SH/RH fireside corrosion in oil-fired units

Coating of waterwalls reduces heat flux in radiant section with resulting increase in gas temperature in convection passes

Inadequate maintenance to clean walls

Undetected change in fuel properties

Boiler Tubing

2-46




Operation-Related Precursors – Fuel Choices and Changes (Coal-fired Units)

Fuel change involving either more ash or constituents that are more erosive, such as quartz

Fly ash erosion Blockage/channeling due to problems with sootblowing design, operation, or maintenance







Fuel change involving a lower ash fusion temperature

Stress corrosion cracking (fireside)


Hydrogen damage


Caustic gouging


Creep and creep-fatigue


Uneven temperature/stress distribution due to slagging of RH/SH tubing

Steamside deposits in areas of local overheating

Slagging of waterwalls reduces heat flux in radiant section with resulting increase in gas temperature in convection passes; may be further impacted by overfiring to increase boiling in waterwalls

Slag changes chemical balance at tube surface



Stress corrosion cracking (fireside)

Inadequate metallurgy for gas chemistry

Boiler Tubing

2-47





Conversion of the unit to cycling operation or an increase in the number of cycles


Creep-fatigue


Short-term overheating damage

Hydrogen damage


Caustic gouging

Thermal and mechanical stress due to thermal, mechanical, and/or pressure transients during startup, shutdown, load change; overfiring and underfiring during load ramping

Inadequate startup/shutdown procedures.

Inadequate training of operations personnel on procedures and component life extension.

Problems with design, operation, and/or maintenance of instrumentation and control systems.

Inadequate cycle chemistry control and/or load cycling leading to water, steam, and gas chemistry cycling.

Overheating resulting from overfiring during ramping.

Overheating resulting from flow restriction due to inadequate condensate boil out.

Increased scale shedding leading to flow restriction and overheating.

Boiler Tubing

2-48





Evidence of a shortcoming during unit shutdown/layup, such as uncertainty about water and/or air quality during period

Insufficient nitrogen blanketing Insufficient oxygen scavenger.

Evidence of air in-leakage Indication that stagnant, oxygenated water may have rested in tubes during shutdown or layup, particularly in RH


Hydrogen damage


Caustic gouging


Overheating damage resulting from deposits

High oxygen/low pH conditions conducive to pitting due to:

• Inadequate water treatment and monitoring before and during shutdown/layup

• Air in-leakage

• Insufficient nitrogen blanketing

• Insufficient oxygen scavenger

• Inadequate drainage hardware and/or procedures

• Too little air, blockages, mis-valving, or other problems with dry air layup

Attemperator water supply valve leakage

Corrosion and redeposition of corrosion products

Deposits/contamination remaining due to inadequate water flush or chemical cleaning for removal of carryover products from drum or attemperator water contamination

Evidence that condensate is forming in SH/RH bends during unit shutdown, exacerbated if steam purity is not good (as determined by elevated levels of SO4)

Short-term overheating in SH/RH tubes


Overstress

Thermal shock


Inadequate startup/shutdown procedures

Inadequate training of operations personnel on procedures and component life extension

Problems with design, operation, and/or maintenance of instrumentation and control systems

Overheating resulting from flow restriction due to inadequate condensate boil out

Overheating due to flow restriction by condensate in combination with build-up of shed scale

Overheating can increase scale formation; subsequent thermal shock can cause scale shedding

Thermal shock, thermal fatigue, and or water/steam hammer as a result of sudden flow of condensate

Boiler Tubing

2-49




Operation-Related Precursors – Other

Operation above the design maximum continuous rating with excess air flow settings and unbalanced fans or air heaters, leading to non-uniform gas flows

Fly ash erosion





Misbalanced or damaged burners

Burner and fan settings not corrected after fuel change


High HP turbine stop valve pressure setting




Change in tube cooling due to changes in steam pressure and mass flow

High temperature at reheater or secondary superheater inlet header




Problems with design, operation, or maintenance of attemperators

Low drum level Short-term overheating

Problems with design, operation, or maintenance of drum level control

Boiler Tubing

2-50





Condenser leak, leading to condenser cooling water constituents in attemperator spray water or drum makeup/boiler feedwater





Deposits/chloride contamination resulting from condenser tube leaks caused by:

• Problems with cycle chemistry control; mismatch between cycle chemistry and condenser metallurgy

• Inadequate condenser maintenance plan

• Thermal shock resulting from inadequately controlled/attemperated bypass to condenser

Contaminants introduced by tube leakage not detected/remedied due to:

• Problems with design, operation, or maintenance of high conductivity alarms

• Problems with design, operation, or maintenance of condensate polisher

Specific Equipment – Precursors Involving Steam Drums

Carryover test indicates high mechanical carryover





Problems with drum internals (separation) or level control; foaming in drum. May be increased by excessive chemical addition to drum, inadequate blowdown.

Problems with design, maintenance, or operation of drum level control system

Operating with high drum level allowing excessive carryover into steam





Problems with design, maintenance, or operation of drum level control system

Boiler Tubing

2-51





Problems with sootblowing design, operation, or maintenance


SH/RH sootblower erosion

Problems with sootblowing design, operation, or maintenance:

• Incorrect setting of blowing temperature (insufficient superheat)

• Condensate in blowing media

• Improper operation of moisture traps

• Excessive sootblowing pressure

• Improper location of sootblower

• Misalignment of sootblower

• Malfunction of sootblower

Excessive sootblowing because of slagging/fouling resulting from:

• Non-optimum flow distribution due to furnace design, operation, or maintenance.

• Misaligned, misbalanced, or damaged burners

• Burner settings not corrected after fuel change

• Poor match between furnace characteristics and new fuel.

• Misaligned, misbalanced, or damaged fans or dampers

• Problems with flow distribution introduced by redesigned platens, pendants, etc.

Boiler Tubing

2-52




Specific Equipment – Precursors Involving High-Temperature Headers

Excessive relative movement of header/tube during unit transients

Restricted movement (i.e., the header is not allowed to expand freely, which may be ash-related)

Unit conversion to cycling

Fatigue in SH/RH tubing

Creep-fatigue

Problems with design or maintenance of header supports

Restriction of support flexibility due to ash fouling

Imbalanced temperature distribution in SH/RH tubing and/or header(s) due to non-optimum furnace gas flow distribution; steam flow distribution, slagging (see more detail on root causes, with related precursors, above)

Imbalanced temperature distribution in header(s) due to leakage of furnace gas

Bowing of header due to temperature asymmetry caused by condensate induction (startup or low load cycling) or non-optimum attemperator operation

Excessive temperature ramp rates during startup/shutdown/load following

Cycling initiated in unit with substantial creep life expended

Specific Equipment – Precursors Involving Turbines

Solid particle erosion in the HP turbine or turbine bypass valve

Short-term overheating in SH/RH tubing


Thermal fatigue/thermal shock

Scale formation and shedding in superheater/reheater due to overheating

Overheating may result from many root causes covered previously

Scale growth and shedding may be increased by non-optimum steam chemistry and/or thermal shock. Thermal shock may result from sudden flow of condensate on startup, excessive temperature ramp rates, or non-optimum attemperator operation, or excessive ramp rates.

Boiler Tubing

2-53




Specific Equipment – Precursors Involving SH/RH Circuit

Problems with design or maintenance of header and tubing supports and attachments

Redesign of the SH/RH circuit may change absorption patterns through other SH/RH sections and increase tube temperatures




Imbalanced temperature distribution in SH/RH tubing may result from non-optimum furnace gas flow distribution or steam flow distribution, slagging, fouling

Imbalanced temperature distribution in SH/RH tubing may result from slagging or ash fouling. Slagging behavior may be changed by tube temperature redistribution as well as flow distribution.

Problems may result from inappropriate match of materials to temperature regions and/or location of transition welds

Redesign of the SH/RH circuit may change gas flow patterns through other SH/RH sections and increase slagging, fouling, or erosion

Fly ash erosion



Imbalanced gas flow distribution in convective passes (see other contributing precursors and more detail on root causes)

Specific Equipment – Precursors Related to Supports/Attachments


Addition of supports without consideration of their impact on the stresses in dissimilar metal welds


Creep-fatigue


Problems with design or maintenance of header and tubing supports and attachments: too little or too much flexibility, range of motion, balanced load distribution, etc.


Boiler Tubing

2-54

Table 2-15 Screening Table for SH/RH Tubing Failures




Typical Location(s)

Possible Mechanism

Potential Root Cause(s) for SH/RH Tubing Failure


Outside-surface initiated

Intergranular crack growth with evidence of grain boundary creep cavitation and creep voids

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


A combination of high residual and service stresses

Boiler Tubing

2-55



Typical Location(s)

Possible Mechanism


Internal thick scales, which may be accompanied by external wastage at the 10 o’clock and 2 o’clock positions

Generally longitudinal orientation

Damage on heated side of tube

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


Original alloy inadequate for actual operating temperatures

Inadequate heat treatment of original alloy

Tubes with gas-touched lengths longer than design length

Side-to-side or local gas temperature differences

Radiant cavity heating effects

Lead tube/wrapper material not resistant enough to temperatures

Build-up of internal oxide scale

Overheating because of restricted steam flow due to contaminant deposits, scale, debris, etc.

Combustion conditions such as excessive flue gas temperature, displaced fireball, delayed combustion, or high LOI carryover causing secondary combustion

Periodic over-firing or uneven firing

Blockage/laning of gas passages

Increased stress due to wall thinning

Boiler Tubing

2-56



Typical Location(s)

Possible Mechanism


Leak

Usually fusion line cracking on low-alloy side of weld

Circumferential orientation

At dissimilar metal welds

Dissimilar metal weld failure

Excessive tube stresses caused by a dissimilar metal weld (DMW) near the roof, furnace wall or other fixed points, the middle of a span, or near a header; inadequate allowance for thermal expansion; support failures or slag accumulation constraining thermal expansion

Tube temperatures above those anticipated in the design

Tube temperature variation across the SH/RH

Change to cyclic operation

Change of fuel, causing increased temperatures

Redesign of adjacent SH/RH that results in higher tube service temperatures

Increased gas temperature in convective passes due to decreased heat flux to waterwalls resulting from slagging or from plating out of magnesium additive in oil-fired units

Defects in initial fabrication or field-welded DMW joint

Boiler Tubing

2-57



Typical Location(s)

Possible Mechanism


Pinhole

Cracking is transgranular or intergranular, usually with significant branching

Initiation can be at inside diameter (ID), which is most common, or on OD

Circumferential or longitudinal orientation

Bends and straight tubing with low spots

High-stress locations are particularly susceptible at bends, welds, tube attachments, supports, or spacers


Carryover of chlorides from the chemical cleaning of waterwalls

Boiler water carryover

Introduction of high levels of caustic or chloride from attemperator spray

Condenser cooling water constituents from a condenser leak

Fireside contaminants such as polythionic acid; chloride from coal (with naturally high chloride or deicing compounds)

Ingress of a flue gas environment into the tube through primary failure, especially in RH when vacuum is drawn

Transgranular cracking

OD-initiated and associated with tubing (particularly at tube bends or attachments) or headers (particularly at the ends)

Tubing-related failures associated with attachments or bends in tubing

Header-related (generally at ends of header)

Fatigue Poor design (excessive stress/strain due to constrained thermal expansion)

Poor manufacturing (excessive mechanical stresses or residual stresses)

Flue-gas-induced vibration by direct flow or vortex shedding

Poor welding, especially poor geometry of final joint

Cyclic operation

Most commonly in HAZ of C or C-Mo steel tubes

Key is microstructure appearance of graphite particles or nodules

Adjacent to weld fusion line at heat-affected zone most common

Graphitization High flue gas temperature

Overheating due to steamside deposits or steam flow restriction

Boiler Tubing

2-58



Typical Location(s)

Possible Mechanism



External polishing of tube surface

Localized damage

Most prominent in backpass regions and bends near walls

Fly ash erosion Excessive local velocities due to non-uniform gas flow attributable to design geometry; distortion or misalignment of tubing rows, gas flow guides, or baffles during maintenance; improperly placed corrective shields or baffles or poorly applied coatings; operation above the design maximum continuous rating above design airflow, or at high excess air; or convective pass fouling

Increase in particle loading and erosive ash elements, such as quartz and iron pyrite

Boiler Tubing

2-59



Typical Location(s)

Possible Mechanism


External damage

Wastage at 10 o’clock and 2 o’clock (with flue gas at 12 o’clock)

Longitudinal cracking

Sometimes “alligator hide” appearance

Key to identification will be the presence of low-melting point ash in external deposits

Highest temperature tubes are leading tubes, tubes that are out of alignment, tubes around radiant cavities, and near tube transitions

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

For coal-fired units:

Operation in the creep regime

Fuels with corrosive ash, particularly those with high S, Na, K, or Cl

Incomplete or delayed combustion

Frequent load changes, which lead to breakdown of oxide scale, enhancing corrosion, sulfidation, and carburization, particularly in austenitic steels

For oil-fired units:

Oil with low-melting-temperature ash, and high sulfur, sodium, or vanadium content

Excessive temperatures caused by steamside oxide scale buildup

High-temperature laning of gases, changes in absorption patterns between furnace and convection sections, RH overheating due to rapid startups, and tube misalignment

Mg-based additives that coat the waterwalls, increasing heat flux in the convective passes

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


Boiler Tubing

2-60



Typical Location(s)

Possible Mechanism


Often shows signs of tube bulging or fish-mouth appearance

Longitudinal orientation

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


Tools left in tubes during maintenance

Improper weld execution (e.g., weld spatter on tubes)

Improper chemical cleaning (e.g., poor flushing leaves deposits in bends, volatile chemicals get into SH circuits, or poor backfill of SH)

Blockage caused by exfoliated oxide scales (formation and exfoliation of scale is accelerated by thermal transients)

Incomplete boil-out of condensate during startup

Over-firing on startup

Over-firing when top feedwater heaters are out of service

Improper shutdown and startup of unit (condensate collection in SH/RH bends)

Loss of coolant because of upstream tube failure

Pinhole or “thin” longitudinal blowout

External wastage flats at 45o around tube from sootblower direction

Little or no ash

First tubes in from wall entrance of retractable blowers

Tubes in direct path of retractable blowers

Sootblower erosion


Incorrect setting of blowing temperature (insufficient superheat)







Excessive sootblowing because of sootblowing system problems or response to excessive slagging/fouling

Boiler Tubing

2-61



Typical Location(s)

Possible Mechanism


External damage

Obvious metal-to-metal contact on tube surface

Rubbing/fretting Tube metal-to-metal contact

Pinhole Damage

Pitting


Tubes where condensate can form and remain during shutdown

Bottoms of pendant loops in SH or RH

Low points in sagging horizontal tubes


Pitting

Shutdown procedures leading to formation of stagnant, oxygenated water in reheater loops

Carryover of Na2SO4

Improper chemical cleaning, including use of an inappropriate cleaning agent, excessively strong acid concentration, too high a temperature (breakdown of inhibitors), and failure to neutralize, drain, and rinse after cleaning



Any location; most likely at areas with greater exposure during maintenance: tube bends, outside surfaces of pendants and platens

Maintenance damage leading to:

Overstress

Fatigue

Creep

Creep fatigue

Corrosion pitting



Impact, grinding, or heat damage site may not be obvious without close inspection. For example, through-wall cracks have originated at barely perceptible indentations.




Boiler Tubing

2-62



Typical Location(s)

Possible Mechanism



Any location; most likely at areas with greater exposure during maintenance: tube bends, outside surfaces of pendants and platens


Overstress

Fatigue

Creep

Creep fatigue

Corrosion pitting



Impact, grinding, or heat damage site may not be obvious without close inspection. For example, through-wall cracks have originated at barely perceptible indentations.





Damage may propagate from flaw at any location; any time. Most likely early in life; after change fuel; increase cycling; increase operating pressure/ temperature

Most likely at bends; welds

Materials flaws leading to:

Overstress

Fatigue

Creep

Creep fatigue

Corrosion pitting








At welds Welding flaws leading to:

Overstress

Fatigue

Creep

Creep fatigue

Corrosion pitting


Defect may result from one or multiple flaws in welding materials or process, including heat input, weld metal, inclusions, preheat, PWHT, or failure to clean contaminants from tubing interior before welding on exterior. Care is required to separate weld defects from another problem located at a weld.

Boiler Tubing

2-63

NDE and Sample Evaluation Options for SH/RH Tubing

Effective life management of SH/RH tubing requires early detection and evaluation of creep, fatigue and other damage, in conjunction with rigorous root cause analysis of failures that occur. Visual inspections and NDE techniques combine with a variety of tests performed on material samples to provide the input for analysis and run/repair/replace decisions.

Table 2-16 lists inspection means recommended for assessing the condition of superheater and reheater tubing and associated supports, in accordance with Action 4 in the boiler tube condition assessment roadmap (Figure 2-1). Available techniques remain less than ideal for obtaining a thorough and accurate picture of tubing condition over the full extent of the superheaters and reheater. Tradeoffs must be made between desired accuracy and available time and budget for inspection. As research and development work continues on a regular basis, the EPRI NDE center should be consulted for up-to-date advice on equipment and processes.

NDE and destructive evaluation options are categorized as a function of the condition assessment level being pursued (i.e., II or III). For inspections on units without significant operating changes or reducing stoichiometry, and a history of predictable tubing wear, EPRI recommends starting with the lower-cost Level II methods. The more-involved Level III methods are used if additional data on crack sizes or thinning rates can provide greater confidence in the remaining life estimates, with value sufficient to justify the added costs.

As noted in Chapter 1, EPRI recommends using the Level III NDE techniques, and considering sampling techniques (destructive evaluation), if the goal of condition assessment is to support an operating plan that entails greater risk of damage. Relevant conditions include:

• long outage intervals

• low-grade fuels

• extensive combustion staging for NOX control

• cycling, or other “challenging” conditions

• tube sections known to be prone to rapid wastage or frequent failure

Sample evaluation techniques should be used to determine the root cause of a tube failure.

Boiler Tubing

2-64

Table 2-16 NDE Options for SH/RH Tubing



Tubing Visual

Video probe

Dimensional

Hardness testing

Conventional ultrasonic testing (UT, for cracking, thickness/inside diameter pitting detection, scale thickness)

EMAT (cracking, thickness/inside diameter pitting detection)

Low-frequency eddy current (thickness/inside diameter pitting detection)


RT (cracking/inside diameter pitting detection, exfoliated scale accumulation in pendant U-bends)

• Conventional film

• Digital imaging

Flash thermography/active infrared response

UT (metal and steamside oxide thickness, crack sizing)

EMAT

LFEC

Replication

RT




• Visual

• Hardness

• Oxide dating







Welds and dissimilar metal welds PT (surface cracking) UT (crack sizing)

RT

Replication



Sample removal and testing (as noted for tubing)

Boiler Tubing

2-65



Attachments and spacers Visual/Video inspection

PT

MT

RT


• Visual

• Hardness



Analysis and Disposition for SH/RH Tubing

Table 2-17 lists minimum wall thickness criteria and recommended analysis or action options for flaws found in superheater and reheater tubing. EPRI recommends using Level III inspection methods when remaining life analyses based on NDE level II methods do not provide an acceptable margin for uncertainty if the value of the added RL confidence warrants the time and expense of additional testing.

Although sample testing is a key part of the process for evaluating creep damage progression, its effectiveness is limited by the complexity of actual temperature distribution among the large number of tubes. As NDE techniques are not well developed for visualizing actual creep damage, the most widely used NDE approach has been to perform UT measurement of both metal and ID oxide thickness. Along with operating data and available sample data, this information is input to analytical models to estimate creep damage and forecast remaining life.

The time interval until the next condition assessment should be established after run/repair/replace decisions have been made. Typically, intervals are set to support planning efforts for major maintenance outages. Obviously, the interval should not exceed the estimated remaining life produced by the analysis (based on wall loss and crack growth projections).

All analysis results and disposition decisions should be documented as part of a comprehensive boiler condition assessment program. Estimates of remaining SH/RH tubing life should be reassessed whenever there is a significant change in upper furnace operating conditions, such as a change in fuel or fuel additives, furnace stoichiometry or heat absorption patterns, boiler cycle water treatment, or duty cycle.

A post outage review should be performed to note information and procedural shortcomings and develop recommended changes in inspection techniques, on-line monitoring, and outage preplanning.

Boiler Tubing

2-66

Table 2-17 Analysis and Disposition for SH/RH Tubing



Tubing (general), especially at bends

Remaining Life (RL) > Desired Life (DL) to next inspection based on creep life evaluation with wall thickness at DL


Calculate remaining creep life and compare to DL

Determine remaining wall thickness for representative locations using Level II NDE. Calculate rate of wall loss based on past experience and expected future operating conditions.

Use operating history and oxide dating to estimate creep exposure and detect areas of overheating

Use Level III material testing techniques to determine existing creep damage, in representative areas of each metallurgy in each SH/RH pass, and provide benchmarking for creep life calculations based on oxide dating

Replace tubing with RL < DL

Ensure that the full extent of the damage is removed to avoid repeat failures

Consider changes in metallurgy and/or SH/RH design

Temporary pad welds should not be used because of uncertainty associated with base metal condition

Address root causes of overheating and excessive wall loss, if detected



Minor fatigue or corrosion-fatigue cracking, less than 30% through wall




Use creep-fatigue crack evaluation methods





Address root cause(s) of corrosion pitting, fatigue, corrosion-fatigue and/or stress corrosion cracking

Boiler Tubing

2-67



Tubing (outside surface)

Wall loss of less than 30% due to erosion and corrosion

Wall loss associated with creep and short-term overheating damage should be evaluated separately




Use creep-fatigue crack evaluation methods

Wall loss can occur via corrosion and erosion mechanisms. Minor wall loss can be trended over time by performing periodic wall thickness measurements




Consider addition of tubing shields in key areas

Consider application of corrosion/erosion resistant coatings


Address root cause(s) of erosion, corrosion (wastage), fatigue, and/or corrosion-fatigue

Tubing (dissimilar metal welds between ferritic and austenitic materials)

Not established Confirm damage mechanism and root cause(s)

Estimate RL using level III analysis based on weld metal composition, unit operating history, and tube metal temperatures

Determine extent of damage to adjacent locations with visual, special radiography, oxide dating and sample testing techniques

Repair damaged locations using either a “dutchman” (preferred) or in-situ welding with nickel based filler metal

Consider SH/RH redesign to locate DMWs in areas of lower stress or lower temperature

Address other root cause(s) of temperature and stress exposure

Monitor for similar problems in other areas

Boiler Tubing

2-68

Preventive Actions for SH/RH Tubing

As noted in the introduction to condition assessment for boiler tubing, the most effective approach to obtaining optimum life is to eliminate the root cause(s) of the damage mechanism(s) can or have produced failures in superheat and reheat tubing. Table 2-18 summarizes preventive actions applicable to typical root causes. This listing is simplified to provide preventive actions for the general groupings of the various root causes seen in the right hand column of Tables 2-14 and 2-15. For each case, choice of a preventive action should be based on a careful review of all factors acting on the damage mechanisms seen in specific tubing and component areas during specific operations.

In general, these precursors can be addressed through normal operation and maintenance activities, by applying the suggested corrective actions, without a major impact on plant performance and without the need for major capital investment. Therefore, plant personnel may choose to implement some actions if a given damage type is suspected, without it being formally identified through the three-level process for assessing the condition and remaining life of SH/RH tubing.

Table 2-18 Preventive Actions for SH/RH Tubing Damage




Consider changing feedwater treatment program. For example, reduce corrosion in all-ferrous systems by changing from AVT to AVT(O) or oxygenated treatment.

Review cycle chemistry monitoring instrumentation, process and procedures. Remedy shortcomings.

Review operator training on procedures and importance of cycle chemistry. Remedy shortcomings.


Check design, function and condition of drum internals and susceptibility to mist carryover. Remedy shortcomings.

Review design, function, and condition of drum level control and alarms. Remedy shortcomings to prevent high drum water level leading to mist carryover.

Boiler Tubing

2-69


Review role of attemperators in introducing deposit forming contaminants to SH/RH tubing. Address root causes.

See corrective actions below for root causes involving inadequate cooling





Root causes involving fireside erosion, corrosion, combustion conditions, fuel choices, and/or excessive heat flux

Review design, function, and condition of plant instrumentation and control systems. Remedy shortcomings.

Perform cold air velocity test. Install/modify distribution and diffusion screens, baffles, damper settings, etc., to balance gas flow and reduce erosion and corrosion related to localized flow concentration/acceleration

Performance of CAV test before and after implementing any changes is critical to obtaining successful results


Review design, function, and condition of burners. Correct burner alignment, balancing, air-fuel mix, overfire air, etc. Repair damage.

Consider replacement of burners

Maintain feeders, pulverizers, etc., to prevent failures leading to burner outage and firing imbalance


Boiler Tubing

2-70


Install tubing with better corrosion resistance (e.g., duplex tubes, shop-applied plating, or weld overlay with high chromium alloys)

Redesign tubing to place dissimilar metal welds in locations with lower stress and/or lower heat flux

Increase corrosion resistance of fireside surface with anti-corrosion/anti-slagging coatings

Chromium content >20% is general rule for adequate protection from reducing and acid gas conditions




Reduce or eliminate Mg-based oil fuel additive to reduce waterwall coating. Perform periodic wall cleaning.

Mg plating on waterwalls reduces heat flux to waterwalls and increases temperature in SH/RH passes



Sootblowing and deslagging alternatives include steam, water, and air nozzle arrays and lances, water cannons, and sonic horns


Root causes involving inadequate cooling

Review design, function, and condition of plant instrumentation and control systems. Remedy shortcomings.

Check for flow blockages. Purge or manually clean tubing. Chemically clean boiler as necessary.

Check for deposition and thick oxide scale. Chemically clean boiler as necessary.

Boiler Tubing

2-71


Review cycle chemistry and remedy problems for root cause of deposition or blockage resulting from exfoliation

Review steam flow distribution. Change orifice sizing or perform other remedy for cause of imbalance.

Steam flow and/or temperature distribution problems may arise in one area after redesign of other SH/RH circuits changes heat flux patterns


Review design, function, condition of drum level control and alarms. Remedy shortcomings to prevent high drum water level leading to mist carryover.

Review design, function, condition, and operating history of attemperator systems. Remedy shortcomings in equipment, procedures, and/or operator training. (See Chapter 8 on attemperators.)

Excessive use of attemperators to limit SH/RH outlet temperature is an indicator of temperature distribution problems with root causes elsewhere and may be a root cause of many types of damage in piping, headers, and tubing

Attemperator water source, quality, and temperature may be a root cause of damage related to deposition, corrosion, and/or fatigue

Root causes involving cycle temperature, pressure and flow settings

Review ALL parameters carefully prior to changing to higher stop valve pressure/temperature or commencing sliding pressure operation


Review/improve startup and shutdown procedures, including ramp rates, to minimize rate and severity of temperature, pressure, and stress transients

Upgrade controls to minimize instability caused by overfiring and underfiring during load ramping


Boiler Tubing

2-72



Review and upgrade tubing and header drains to reduce/eliminate condensate buildup and flow events during startup, shutdown, and low load operation

Consider redesign of SH/RH tubing configurations


Review procedures and monitoring capability prior to shutdown/layup:


• Monitor and control moisture and other air quality parameters during shutdown/layup



Consider pressurization/depressurization procedures to clear exfoliated scale and trapped water and ensure change-over to clean, dry air or nitrogen

Reduce or avoid forced cooling to reduce condensate accumulation and flow in SH/RH tubing, especially bends


Check and repair tube leaks. Determine and remedy root cause of tube leaks.

Check and correct cycle chemistry and/or monitoring procedures/equipment

Check and correct problems with condenser cathodic protection

Consider applying coating to interior and/or exterior of condenser tubing and tubesheets



Boiler Tubing

2-73



Change from AVT to AVT(O) or oxygenated treatment may be practical if copper based alloys can be eliminated from feedwater system

Root causes involving drum design, condition, or operation

Review design, function, and condition of makeup water treatment system and chemical additions to drum. Remedy shortcomings in equipment, procedures and/or operator training.


Review design, function, and condition of drum level control and alarms. Remedy shortcomings to prevent high drum water level leading to mist carryover.




Shortcomings in chemical cleaning process may involve inappropriate cleaning agent, overly strong concentration, long cleaning time, temperature too high, failure to neutralize, breakdown of inhibitor, inadequate rinse




Boiler Tubing

2-74


Root causes involving high-temperature headers

Review and remedy causes of force transfer from header to tubing:

• Excessive relative movement of header/tube during unit transients may be related to ramp rates, attemperator operation, or inadequate supports and restraints

• Restricted movement or expansion of header may be related to inadequate supports/restraints or blockage by ash

• Bowing of header may be related to imbalanced flow distribution, imbalanced steam temperature distribution due to slagging/fouling/gas flow channeling, condensate flow from tubing, or attemperator operation, gas leakage from furnace impinging on header, supports, or connected piping

Root causes involving repairs, materials, and original construction



Review records of materials, welding, and other fabrication techniques of original construction or previous repairs/modifications. Field check items with inadequate documentation or issues identified in other locations and applications.

Assess condition of tubing with significant hardness or ovality noted on field inspections. Replace proactively, as necessary, to prevent future failures.

Significant numbers of tube bends have problems related to original design and/or construction; stresses imposed by support deficiencies and cyclic operation

Boiler Tubing

2-75


Review and enforce maintenance equipment and procedures to reduce risk of accidental impact and arc strike damage

Implement procedures to account for all tools and materials that enter the boiler

Perform thorough post-maintenance inspections to detect unnoticed or unreported damage

Very small indentations may create stress concentrations leading to SH/RH tubing failure

Failures caused by tools, temporary plugs, rags, weld rod, etc., left in tubing are not uncommon

Root causes involving supports, restraints, and attachments

Check design, function, hot and cold settings, and condition of supports and restraints. Remedy shortcomings.


Perform finite element thermal and stress analysis of problem areas and prior to implementing support modifications

2.6 Economizer Tubing

For economizer tubing, waterside mechanisms, such as corrosion, corrosion-fatigue, and flow-accelerated corrosion, are generally the primary concern. Tubing life may also be affected by gas-side mechanisms related to ash fouling, flow channeling, and acid dewpoint corrosion.

Overheating and related mechanisms, which are of major interest for waterwall and SH/RH tubing, are rarely a concern for economizer tubing. Its location in the lower temperature region beyond the SH/RH convection passes provides protection from the more extreme gas-side exposures involving high temperature, high heat flux, and liquid ash corrosion.

Tight tube spacing often limits access to many tube surfaces for inspection. New condition assessment technology and better understanding of damage mechanisms are helping to reduce the frequency of economizer tubing failures. New repair techniques are reducing costs and outage duration. The most significant developments include:

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

• Portable digital radiographic equipment (digital phosphor plate radiography) is providing increased resolution and/or reduced source strength (with smaller exclusion zones) compared to traditional film-based radiography.

• Smaller sized tools, versatile reaching devices are providing easier access on the interior of tubing passes.

Boiler Tubing

2-76

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


• Experience has led to refinements in cold air velocity testing and use of flow control devices to redistribute flow and reduce erosion.

Damage Mechanisms for Economizer Tubing

Because of the large number of potential damage mechanisms for economizer 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 investigated, with the objective of identifying corrective actions that can slow or eliminate future damage.

Table 2-19 categorizes economizer tubing damage mechanisms by their likely precursors. Table 2-20 is designed to quickly focus failure analysis efforts by characterizing failure types by appearance and location, and by providing corresponding damage mechanisms and root causes most likely to be responsible for a failure with those characteristics. These tables are adapted from comparable tables for water-cooled tubing in Volume 2 of EPRI’s Boiler Tube Failures: Theory and Practice.

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 bibliography in Section 2.7).

Table 2-19 Precursors for Economizer Tubing Damage

Precursor

Mechanisms of Concern for Economizer

Tubing


Inspection / Appearance Precursors – Economizer Tubes (Waterside)

Corrosion/erosion of economizer inlet header stub tubing

Corrosion/erosion in feedwater system

Fouling in boiler feed pump or orifices (redeposition from corrosion in condenser/feedwater system)

Flow-accelerated corrosion

Flow-accelerated corrosion resulting from excessively reducing cycle chemistry

Excessive use of oxygen scavenger (especially hydrazine) in response to air in-leakage in condenser or attemperator or during shutdown

Non-optimum match between cycle chemistry and metallurgy

Boiler Tubing

2-77

Precursor


Tubing


Under-deposit pitting in feedwater system or economizer header/tubing.

Fouling in boiler feed pump or orifices (redeposition from corrosion in condenser/feedwater system)

Corrosion pitting

Corrosion-fatigue


Corrosion-fatigue results from combination of corrosion mechanism with cyclic stress (thermal, pressure, or mechanical)

Air in-leakage in condenser or attemperator or during shutdown





Contamination by condensate polisher or makeup water treatment regeneration chemicals


Cracking on tube interior

Low cycle fatigue

Corrosion-fatigue

Thermal and pressure stress cycles due to unit cycling; may be influenced by restriction of movement by supports or inadequate flexibility near header stub tubes

Feedwater introduced intermittently into economizer inlet at high flow rates during startups and particularly during off-line top-ups

Thermal shock due to (intermittent) introduction of cold feedwater at high flow rates after unit warm-up; may be related to bringing out-of-service feedwater heater on-line or off-line top-ups

Corrosion-fatigue results from combination of corrosion mechanism with cyclic stress (thermal, pressure, or mechanical)

Inspection / Appearance Precursors – Economizer Tubes (Gas Side)

Boiler Tubing

2-78

Precursor


Tubing



External flat spot


Fly ash erosion Channeling of flow due to boiler geometry, tubing arrangement, poorly designed or damaged flow baffles, diffusers, deflectors, etc.

Channeling of flow due to fouling


Problems with sootblower design, operation, or maintenance


Corrosion grooves at welds on tube exterior

Corrosion grooves on attachments/supports

Corrosion pitting under ash fouling in contact with tubing or supports

Acid dewpoint corrosion

Economizer surface temperature below acid dewpoint of exhaust gases

Inadequate feedwater heater performance and/or convection pass temperature balance

High sulfur oxide and water vapor content in exhaust gases

May be influenced by stagnation and insulation under ash deposits resulting from gas flow distribution problems or inadequate sootblowing

May be influenced by low steam temperature or water use for sootblowing

Cracking on tube exterior

Low cycle fatigue

High cycle fatigue

Corrosion-fatigue

Thermal and pressure stress cycles due to unit cycling; may be influenced by restriction of movement by supports or inadequate flexibility near header stub tubes

Combination of corrosion mechanism with cyclic stress (thermal, pressure, or mechanical)

Vibration due to gas flow dynamics and/or inadequate tubing support/restraint (high cycle fatigue)


Boiler Tubing

2-79

Precursor


Tubing


Problem with high levels of feedwater corrosion products

Operating parameters for pH, cation conductivity, or dissolved oxygen consistently outside recommended ranges, including persistent reducing conditions or excessive use of oxygen scavenger

Flow-accelerated corrosion, especially in economizer inlet header stub tubing.

Corrosion pitting

Corrosion-fatigue


Problems with design, operation, or condition of cycle chemistry instrumentation and control




High oxygen/low pH conditions resulting from air in-leakage in condenser or deaerator; air in-leakage during shutdown

Cooling water contamination from condenser tube leakage



Cycle Chemistry Precursors – Units on Phosphate Treatments

Persistent phosphate hideout with phosphate return causing a pH depression


Corrosion-fatigue


Problems with design, operation, or condition of cycle chemistry instrumentation and control


Cycle Chemistry Precursors – Units on AVT

pH depression during shutdown and early startup (pH around 7-8)

Hideout/return of sulfate

Corrosion-fatigue Problems with design, operation, or condition of cycle chemistry instrumentation and control


Boiler Tubing

2-80

Precursor


Tubing


Shortcoming in chemical cleaning process, such as inappropriate cleaning agent, excessively strong concentration, or long cleaning time, too high a temperature, inadequate flow verification, failure to neutralize, breakdown of inhibitor, or inadequate rinse

Chemical cleaning damage in economizer tubing



Inadequate training of personnel responsible for planning, implementation, and monitoring of chemical cleaning program

Evidence that level of Fe in cleaning solution continued to increase instead of leveling out when cleaning process was ended

Chemical cleaning damage in economizer tubing




Modification/application of shielding, baffles, or palliative coatings to mitigate fly ash erosion without the use of a cold-air velocity test

Fly ash erosion Introduction of non-optimum flow distribution with high velocity areas conducive to erosion

Ash trapped in gaps between shielding and tubing holds water in contact with tubing during shutdown/layup

Backing rings, pad welds, canoe pieces, tube section replacements, or weld overlays become a source of stress concentration, chemical vulnerability

Fatigue

Corrosion-fatigue

Corrosion pitting


Introduction of flow disturbance






• Improper selection of weld rod/wire, heat input, inert gas flow rate, etc.

Boiler Tubing

2-81

Precursor


Tubing


Cu in waterside deposits in water-touched tubes

Copper embrittlement or other welding defects caused by copper in deposits

Non-optimum cycle chemistry; excess oxygen, CO2, or NH3 with mixed metallurgy


Improper repair procedures

Operation-Related Precursors – Startup Procedures

Feedwater introduced intermittently into economizer inlet at high flow rates during startups and particularly during off-line top-ups

Thermal fatigue, particularly at or near economizer inlet header

Thermal shock/stress due to cold feedwater introduced to hot condenser

Inadequate procedures; instrumentation and controls; operator training for implementing and monitoring feedwater introductions and feedwater heater lineup changes

Operation-Related Precursors – Fuel Choices and Changes (Coal-fired Units)

Fuel change involving either more ash or more erosive elements, such as quartz






High sulfur oxide and water vapor; other compounds, in exhaust gases





Boiler Tubing

2-82

Precursor


Tubing



Conversion of the unit to cycling operation or an increase in the number of cycles

Fatigue

Corrosion-fatigue

Problems with design, operation, or condition of unit instrumentation and control used during startup and shutdown; procedures; or operator training, resulting in:

• Excessive ramp rates

• Severe thermal and mechanical stress transients

• Instability caused by overfiring and underfiring during load ramping, overfire during startup, or changes in feedwater heater alignment

Problems with design, operation, or condition of cycle chemistry instrumentation and control (load cycling leads to waterside chemistry cycling)


Evidence of a shortcoming during unit shutdown/layup, such as uncertainty about water and/or air quality during period

Pitting

Corrosion-fatigue

Air in-leakage causing pH depression in oxygen-rich water with stagnation during shutdown/layup

Inadequate shutdown/layup procedures

Inadequate training of personnel involved in shutdown/layup

Inadequate instrumentation and control systems for monitoring shutdown/layup

Insufficient supply/use of nitrogen or dry air for dryout and blanketing

Insufficient oxygen scavenger

Operation-Related Precursors – Other

Operation above the maximum continuous design rating with excess air flow settings and unbalanced fans or air heaters, leading to non-uniform gas flows



Boiler Tubing

2-83

Precursor


Tubing


Specific Equipment – Precursors Involving Economizer Headers

Header transfers high force/stress to header to tubing welds and economizer tubing due to header design and/or system operation

Poor weld quality related to header design and fabrication specifications

Fatigue

Corrosion-fatigue

Temperature stratification causing bowing of economizer inlet header during startup, shutdown, and off-line conditions; feedwater heater lineup changes

Tight spacing of boreholes leads to inflexible tubing arrangements; difficult welding conditions

Partial penetration welds at header-to-stub tube joints create stress concentration/vulnerability and nexus for crevice corrosion

Overly rigid or flexible header and/or tubing supports lead to high stress


Air in-leakage

Cooling water in-leakage due to condenser tube leaks

Corrosion pitting

Corrosion-fatigue

Non-optimum cycle chemistry and/or metallurgy allowing corrosion in condenser

Cathodic protection problem allowing corrosion in condenser



Specific Equipment – Precursors Involving Water Treatment Plant or Condensate Polisher

Upset in water treatment plant or condensate polisher regeneration chemicals leading to low pH in the boiler (pH <8)

Corrosion pitting

Corrosion-fatigue

Upset in water treatment plant or condensate polisher regeneration chemicals leading to low pH in the boiler (pH <8)



Specific Equipment – Precursors Related to Supports/Attachments


Addition of supports without consideration of their impact on the stresses


Corrosion-fatigue

Problems with design or maintenance of header and tubing supports and attachments: too little or too much flexibility, range of motion, balanced load distribution, etc.


Boiler Tubing

2-84

Precursor


Tubing





Economizer sootblower erosion;

Fatigue

Corrosion-fatigue


Incorrect setting of blowing temperature







Excessive sootblowing because of slagging/fouling resulting from:

• Non-optimum flow distribution due to furnace design, operation, or maintenance

• Misaligned, misbalanced, or damaged fans or dampers

• Problems with flow distribution introduced by redesigned or damaged diffusers, baffles, etc.

Boiler Tubing

2-85

Table 2-20 Screening Table for Economizer Tubing Failures




Typical Location(s)

Possible Mechanism

Potential Root Cause(s) for Economizer Tubing Failure


Pinhole leak also possible

Multiple, transgranular cracks that initiate on the inside of the tube

Near attachments, particularly where high restraint stresses can develop

Corrosion-fatigue

Combination of corrosion mechanism with cyclic stress (thermal, pressure, or mechanical)

Shortcomings in cycle chemistry plan, monitoring and control instrumentation or procedures, and/or operator training

Cyclic operation and other sources of thermal and stress transients; external restraint due to shortcomings in design, function, or condition of supports and attachments; interaction between tube and header

Leak or crack

First sign is a pinhole leak at toe of stub weld

Multiple, longitudinal cracks

Bore hole cracking

Economizer inlet header stub tubes nearest the feedwater inlet

Thermal fatigue

Cyclic operation and other sources of thermal and stress transients; external restraint due to shortcomings in design, function, or condition of supports and attachments; interaction between tube and header

OD-initiated transgranular cracking

Near attachments, particularly solid or jammed sliding attachments

At bends in tubing

Fatigue Cyclic operation and other sources of thermal and stress transients; external restraint due to shortcomings in design, function, or condition of supports and attachments; interaction between tube and header

Vibration due to gas flow dynamics and/or inadequate tubing support/restraint (high cycle fatigue)

Boiler Tubing

2-86



Typical Location(s)

Possible Mechanism



Longitudinal

Cod- or fish-mouth

Polishing of outside surface of tube

Localized damage

Wastage flats

Near economizer banks

Near plugged or fouled passages

At places where baffles were previously installed

Fly ash erosion

Channeling of flow due to boiler geometry, tubing arrangement, poorly designed or damaged flow baffles, diffusers, deflectors, etc.

Coal with more erosive material (quantity or quality) than considered in boiler design

Thin-edged rupture

Wall thinning from inside

“Orange peel” appearance

Economizer inlet header stub tubes nearest to point of feedwater inlet





External (thinned or missing external oxide)

Generally in economizer

Low-temperature areas of economizer




High content of sulfur oxide, other corrosive compounds, and water vapor in exhaust gases



Boiler Tubing

2-87



Typical Location(s)

Possible Mechanism


Pinhole Damage


Locations where boiler water can stagnate during unit shutdown


Corrosion pitting

Inadequate planning, implementation, and monitoring of shutdown/layup

Insufficient supply/use of nitrogen or dry air for dryout and blanketing

Procedures allow air in-leakage during shutdown without adequate oxygen scavenger




Any location; most likely at areas with greater exposure during maintenance, such as crown of tube on fireside or cold side or edge or end of panel sections


Overstress

Fatigue

Corrosion pitting



Impact, grinding, or heat damage site may not be obvious without close inspection

Through-wall cracks have originated at barely perceptible indentations


Corrosion under excessive localized deposits due to flow disruption

Boiler Tubing

2-88



Typical Location(s)

Possible Mechanism



Damage may propagate from flaw at any location and at any time in unit life. Most likely early in life or after change fuel increase cycling, or increase operating pressure and/or temperature

Most likely at bends and welds

Materials flaws leading to:

Overstress

Fatigue

Corrosion pitting

Corrosion-fatigue







Welds Welding flaw leading to:

Overstress

Fatigue

Corrosion pitting

Corrosion-fatigue

Defect may result from one or multiple flaws in welding materials or process, including heat input, weld metal, inclusions, preheat, PWHT, or failure to clean contaminants from tubing interior before welding on exterior. Care is required to separate weld defects from other problems located at welds.

Corrosion under excessive localized deposits due to flow disruptions

NDE and Sample Evaluation Options for Economizer Tubing

Table 2-21 lists inspection means recommended for assessing the condition of economizer tubing and associated supports, in accordance with Action 4 in the boiler tube condition assessment roadmap (Figure 2-1). Tradeoffs must be made between desired accuracy and available time and budget for inspection. As research and development work continues on a regular basis, the EPRI NDE center should be consulted for up-to-date advice on equipment and processes.

NDE and destructive evaluation options are categorized as a function of the condition assessment level being pursued (i.e., II or III). For inspections on units without significant operating changes or reducing stoichiometry, and with a history of predictable tubing wear, EPRI recommends starting with the lower-cost Level II methods. The more-involved Level III methods are used if additional data on crack sizes or thinning rates can provide greater confidence in the remaining life estimates, with value sufficient to justify the added costs).

Boiler Tubing

2-89

Because economizer tubes are not apt to be the limiting factor in setting allowable maintenance outage intervals, only inspections using the lower-cost Level II NDE methods are recommended for routine condition assessment. The more advanced Level II NDE tests might be used where more complete or faster coverage is required, particularly within tightly spaced and hard to access tubing passes. Sample evaluation techniques should be used to determine the root cause of a tube failure or serious damage, especially suspected flow-accelerated corrosion.

Table 2-21 NDE Options for Economizer Tubing



Tubing Visual

Video probe

Dimensional

Hardness testing


Electromagnetic acoustic transducer (EMAT)

Low frequency eddy current (LFEC)



• conventional film

• digital imaging


• Visual

• Hardness

• Oxide dating







Welds Penetrant testing (PT)


RT

Sample removal and testing (as noted for tubing)

Supports, attachments, and spacers

Visual/video inspection

PT

MT

RT


• Visual

• Hardness



Boiler Tubing

2-90

Analysis and Disposition for Economizer Tubing

Table 2-22 summarizes minimum wall thickness, allowable crack size criteria, and recommended analysis or action options for flaws found in economizer tubing. Detailed analysis procedures are contained in EPRI’s Boiler Tube Failures: Theory and Practice and other EPRI technical reports.

EPRI recommends using Level III inspection methods when crack growth analyses based on NDE Level II methods does not provide remaining life estimates with an acceptable margin for uncertainty, if the value of the added RL confidence warrants the time and expense of additional testing. As economizer tubing generally requires less expensive materials and welding techniques, the timing of the next condition assessment should be established after run/repair/replace decisions have been made. Typically, intervals are set to support planning efforts for major maintenance outages. Obviously, the interval should not exceed the estimate remaining life of the economizer tubing (based on wall thinning and crack growth projections).

All analysis results and disposition decisions should be documented as part of a comprehensive boiler condition assessment program. Estimates of remaining economizer tube life should be reassessed whenever there is a significant change in operating conditions, such as a change in boiler cycle water treatment or conversion to cyclic duty.

A post outage review should be performed to note information and procedural shortcomings and develop recommended changes in inspection techniques, on-line monitoring, and outage preplanning.

Table 2-22 Analysis and Disposition for Economizer Tubing





Minor corrosion-fatigue cracking, less than 30% through wall




Corrosion pitting can result in failure by reducing wall thickness below pressure design minimum or by acting as initiation sites for fatigue cracking

Localized pitting can be evaluated in detail to determine actual minimum wall limits according to ASME code



Boiler Tubing

2-91



If flow-accelerated corrosion is confirmed, a comprehensive inspection and root cause evaluation should address all susceptible areas to determine rate of wall loss, replacement requirements and reinspection interval. Level III sample evaluation should be applied to suspected FAC. The root cause of FAC should be remedied or mitigated to the extent practical.

If permitted by metallurgy, all volatile feedwater treatment (AVT) should be replaced with AVT(O) or oxygenated treatment

If mixed metallurgy requires AVT, consideration should be given to accelerating schedules for condenser and feedwater tube replacement to allow use of AVT(O) or oxygenated treatment

Tubing (outside surface)

Minor wall loss that does not result in wall thickness becoming <70% of design minimum


Minor wall loss due to erosion mechanisms can be trended over time by performing periodic wall thickness measurements

Wall loss to <70% of design minimum is typically used to trigger action for replacement

Cracks and sharp edged pits, capable of initiating fatigue cracking, should be evaluated on a case-by-case basis

Repair by grinding out and/or weld buildup may be acceptable in some cases. As necessary, replace tubing to restore wall integrity.

Pad-welding to restore wall thickness should be done only on an emergency basis and only as a temporary repair until tube replacement can be performed

Address root cause(s) of erosion, corrosion pitting, fatigue, and/or corrosion-fatigue

Boiler Tubing

2-92



Welds at/near header

Minor fatigue or corrosion-fatigue cracking, less than 30% through wall


Confirm damage mechanism and determine extent of damage using advanced Level II techniques

Cracks and sharp edged pits, capable of initiating fatigue cracking, should be evaluated on a case-by-case basis

Repair by grinding out and/or weld buildup may be indicated in some cases


Preventive Actions for Economizer Tubing

As noted in the introduction to condition assessment for boiler tubing, the most effective approach to obtaining optimum life is to eliminate the root cause(s) of the damage mechanism(s) producing failures in economizer tubing. Table 2-23 summarizes the typical root causes, or precursors, for the various damage mechanisms observed in economizer tubing during particular modes of operation and for particular methods of cycle chemistry control.

In general, these precursors can be addressed through normal operation and maintenance activities—by applying the suggested corrective actions (in italics)—without a major impact on plant performance and without the need for major capital investment. Therefore, plant personnel may choose to implement some actions if a given damage type is suspected, without it being formally identified through the three-level process of performing condition and life assessment on economizer tubing.

Table 2-23 Preventive Actions for Economizer Tubing Damage




Consider changing feedwater treatment program; for example:

• Reduce corrosion in all-ferrous systems by changing from AVT to AVT(O) or oxygenated treatment


Boiler Tubing

2-93










Root causes involving gas-side erosion, corrosion, and fuel choices



Increase corrosion resistance of gas-side surface with anti-corrosion coatings




Boiler Tubing

2-94




Sootblowing alternatives include steam, water, and air nozzle arrays and lances, water cannons, and sonic horns



Review/improve startup and shutdown procedures to minimize rate and magnitude of temperature, pressure, and stress transients

Upgrade controls to minimize instability caused by overfiring and underfiring during load ramping

Install off-line boiler circulation pumps to reduce subcooling




Review procedures and monitoring capability prior to shutdown/layup. Remedy shortcomings.




• Review and monitor oxygen scavenger (reducing agent) injection quantity and locations

• Consider pressurization/ depressurization procedures to clear exfoliated scale and trapped water and ensure change-over to clean, dry air or nitrogen

Boiler Tubing

2-95



Check and repair tube leaks. Determine and remedy root cause of tube leaks:

• Check and correct cycle chemistry and/or monitoring procedures/equipment

• Check and correct problems with condenser cathodic protection

• Consider applying coating to interior and/or exterior of condenser tubing and tubesheets




Change from AVT to AVT(O) or oxygenated treatment may be practical if copper-based alloys can be eliminated from feedwater system




Shortcomings in chemical cleaning process may involve inappropriate cleaning agent; overly strong concentration; long cleaning time; temperature too high; failure to neutralize; breakdown of inhibitor; inadequate rinse




Root causes involving repairs


Backing rings, pad welds, canoe pieces, or weld overlays that penetrate to inside surface and become a source of flow disruption and excessive deposits in water-touched tubes


Boiler Tubing

2-96


Review presence of Cu in waterside deposits in water-touched tubes

Revise and carefully monitor repair procedures related to welding in presence of copper

Evaluate and modify cycle chemistry to reduce copper corrosion and redeposition

Consider condenser/feedwater tubing changes to eliminate future copper deposits

Consider chemical cleaning prior to welding

Root causes involving supports/ attachments


Redesign economizer tube attachments to increase flexibility. Perform detailed analysis before implementing changes; follow-on monitoring to confirm effectiveness.

2.7 References for Boiler Tubing

EPRI has published numerous technical reports relevant to damage mechanisms, condition assessment, and failure prevention for boiler tubing (see following list). An expanded listing of references and resources is contained in Appendix C.

Boiler Tube Failure Metallurgical Guide. EPRI: 1993. Report TR-102433, Vols. 1-2.

Boiler Tube Failure Reduction Program. EPRI: 1991. Report GS-7454.

Boiler Tube Failures. EPRI: 2001. Report PS-114825.

Boiler Tube Failures: Theory and Practice. EPRI: 1996. Report TR-105261, Vols. 1-3.

Circumferential Cracking on the Waterwalls of Supercritical Boilers. EPRI: 1995. Report TR-104442, Vols. 1-2.

Corrosion-Fatigue Boiler Tube Failures in Waterwalls and Economizers. EPRI: 1992, 1996. Report TR-100455, Vols. 1-5.

Corrosion-Fatigue Crack Initiation of Boiler Tubes: Effect of Phosphate in Boiler Water. EPRI: 1997. Report TR-105568.

Cyclic Operation of Power Plant (Technical, Operation, and Cost Issues). EPRI: 2001. Report 1004655.

Boiler Tubing

2-97


Feasibility Study for Detecting Cold-Side Fatigue Cracks in Waterwall Tubes Using the Magnetostrictive Sensor (MsS) Technique. EPRI: 2003. Report 1007798.

Guidelines for the Control and Prevention of Fly Ash Erosion in Fossil-Fired Power Plants. EPRI: 1994. Report TR-102432.


Intelligent Sootblowing at TVA's Bull Run Plant. EPRI: 2003. Report 1004115.

Long-Range MsS Guided-Wave Inspection of Reheater Boiler Tubes. EPRI: 2003. Report 1007803.

Proceedings: Third International Conference on Boiler Tube Failures in Fossil Plants. EPRI: 1998. Report TR-109938. (See report TR-100493 for proceedings of the Second International Conference.)

State-of-Knowledge Assessment for Accelerated Waterwall Corrosion with Low-NOX Burners. EPRI: 1997. Report TR-107775.

Waterwall Fireside Corrosion Under Low-NOX Burner Conditions. EPRI: 2001. Report 1001351.

Weld Overlay of Waterwall Tubing, Repair Procedures and Contract Specifications. EPRI: 2002. Report 1004615.

3-1

3 HIGH-TEMPERATURE STEAM HEADERS

High-temperature steam headers present significant safety concerns when operating aging plants. Some notable failures have occurred in these headers, which are among the largest and most expensive in boilers. As such, understanding and dealing with the types of damage that they accumulate is vital to the safe and economic operation of fossil power plants.

This chapter summarizes the basic elements of condition assessment of headers collecting steam from superheat and reheat tubing. This material is adapted from EPRI’s 2003 publication, Header and Drum Damage: Theory and Practice (Report 1004313), and other EPRI reports.

“High-temperature” steam headers, at the outlet of secondary superheater and reheater tube sections, are the primary focus of this chapter. They are of particular concern because they are subject to both creep and fatigue damage mechanisms. The very thick walls required to withstand high pressure and high temperature can make these headers particularly vulnerable to creep fatigue damage, when cyclic operation introduces high thermal stresses to header materials that already have substantial creep life expended.

The material in this chapter is similar to that presented in Chapter 6, which covers main steam and hot reheat transfer piping. Because both headers and piping are made of the same “piping grade” materials, many of the damage mechanisms, NDE techniques, and analytical methods described in the two chapters are similar or identical. There are important differences, however, such as stress and temperature variations within the component. Therefore, life consumption trends for a given material in one component type may not be transferable to another, even if they share the same general operating history.

Much of the information in this chapter is also applicable to the “low-temperature” steam headers that distribute steam to superheat and reheat tubing. These headers generally are not subject to creep damage but often have significant thermal fatigue and corrosion-fatigue concerns because of their thick walls and location just downstream of spray attemperators. Their conditions are very similar to those for cold reheat and superheater crossover piping, which are addressed in Chapter 7.

Primary superheater outlet headers may qualify as “high temperature” or “low temperature,” depending on the installation.

Section 3.1 tabulates typical damage mechanisms for high-temperature steam headers.

Section 3.2 provides a series of flow charts to illustrate a variation of EPRI’s three-level condition assessment roadmap for identifying and evaluating damage mechanisms specific to high-temperature steam headers.

High-Temperature Steam Headers

3-2

Section 3.3 tabulates NDE and sample testing techniques suitable for Level II and Level III life assessments.

Section 3.4 tabulates data analysis and decision-making criteria used for run/repair/replace disposition of condition assessment findings for high-temperature steam headers.

Section 3.5 tabulates candidate preventive actions that may be used to enhance the life of high-temperature steam headers.

Section 3.6 lists EPRI reference materials pertaining to condition assessment and life optimization of high-temperature steam headers.

3.1 Damage Mechanisms for High-Temperature Steam Headers

Traditionally, creep has been the predominant damage mechanism of concern for high-temperature steam headers in baseloaded units. As these units are converted to cyclic duty, fatigue damage can also become important, especially in thick-walled superheater headers and in material already degraded by years of creep damage. Further, simultaneous creep and fatigue can produce complex interactions in which creep strains reduce fatigue life and fatigue strains reduce creep life, accelerating crack growth.

Table 3-1 lists the most common types and locations of damage found in high-temperature steam headers. Inspectors should, at a minimum, check for these types of damage during maintenance outages. Most of these mechanisms can be traced to one or more of the following root causes:

• Normal creep life expenditure; end of design life in baseloaded units

• Localized overheating due to temperature distribution problems in superheater or reheater. Systemic overheating due to overfiring or temperature distribution problems between boiler passes.

• Overheating or cyclic quenching due to shortcomings in design, operation, or maintenance of attemperators

• Localized overheating due to impingement of hot gases leaking through voids in furnace lagging and insulation

• Bore-hole and bottom surface quenching due to condensate flow events during cyclic operation and/or to inadequate drainage

• Cyclic stresses resulting from temperature and pressure transients during cyclic operation

• Problems with design or maintenance of header and/or tubing supports and attachments: too little or too much flexibility or range of motion, imbalanced load distribution, etc.

Table 2-14, “Precursors for Superheater and Reheater Tubing Damage.” should be consulted for a more detailed presentation of root causes, which are, in many cases, also applicable to steam headers.


3-3

Appendix A provides descriptions of header damage mechanisms and their causes. Additional characterizations and experience data are available in the EPRI technical reports listed in Section 3.6. Other relevant references are listed in Appendix C.

Table 3-1 Damage Mechanisms for High-Temperature Steam Headers

Component / Location Damage Mechanisms

Body spool pieces Creep swelling

Temper embrittlement

Thermal softening

Oxide-notching

Fatigue

Humping

Tee body External creep cracking

Internal thermal fatigue cracking

Ligament regions Thermal fatigue cracking in (and between) bore holes, often initiating at corner on interior (most common in secondary SH outlet headers)1

Girth welds External creep damage

Internal thermal fatigue cracking at areas weakened by weld preparation counterbores

Seam welds Creep cracking

Creep-fatigue cracking

Saddle welds at outlet nozzle(s), drain lines, hand hole fittings, etc.

Creep cracking

Fatigue cracking

Differential creep

Stub tubes Creep swelling

Thermal softening

Wall wastage from oxide exfoliation


Tube stub to header welds External creep cracking

Weld root creep cracking

1Nakoneczny, G. & Schultz, C, Life Assessment of High Temperature Headers, Babcock & Wilcox Company: 1995. BR-1586.


3-4


Drain line penetrations Internal thermal fatigue cracking

Internal thermal shock cracking

External creep/fatigue cracking

Radiographic testing (RT) plug and thermowell welds

Creep cracking

With bimetallic welds—fatigue cracking

Supports Overload

Corrosion

Interference with motion

Support/Lifting Lugs Creep cracking

Thermal softening

3.2 Condition Assessment Roadmap for High-Temperature Headers

The condition assessment roadmaps shown in Figures 3-1, 3-2, 3-3, and 3-4 provide a sound, stepwise approach to identifying damage mechanisms and estimating the remaining life of high-temperature steam headers. Tables 3-1, 3-2, 3-3, and 3-4 provide support information for the different elements of the condition assessment process, including identification of relevant damage mechanisms, run/repair/replace decision-making and determination of the next inspection interval.


3-5

Assemble design information (dimensions, materials, minimum

creep rupture, pressure, temperature, stresses) and service information

(boiler running hours, past repairs/replacements, dimension

and composition checks)

Answer the following key questions:

Has unit significantly exceeded its design P (pressure) and/or T (temperature)?

YES

NO

Will future service involve P and/or T above original design?

YES

NO

Has the header experienced significant (rapid) thermal transients?

YES (or DON’T KNOW) Go to Level II Assessment

NO

Has failure history of the boiler been excessive?

YES

NO

Are steam temperature records available? NO

YES

Go to Level I Assessment

Figure 3-1 Condition Assessment Screening Questions for High-Temperature Steam Headers


3-6

Construct histogram of time at various steam temperatures; adjust to obtain nominal metal

temperatures

Construct histogram of time at various operating pressures; for each pressure level, estimate the

applied stress (σ) by calculating the mean diameter hoop stress due to internal pressure, where P* = gage pressure, R = header radius to midwall, and

t = header wall thickness:

σ = P*R t

For each damage mechanism**, use the calculated material life (L*) and service exposure time (texp) at each “condition level” to estimate the Life Fraction

Expended (LFE) for each operating regime

LFE = texp/L*

Then approximate total LFE for all mechanisms:

LFE =

Estimate remaining life:

RL = [(1-LFE)/LFE]texp

NO

Is the remaining life substantially greater than

the desired life? YES

Go to Level II Assessment

n

∑LFEii=1

Set re-inspection interval; maintain

accurate operating records

Figure 3-2 Level I Life Assessment Roadmap for Fatigue in High-Temperature Steam Headers

**For creep, see Figure 3-3.


3-7

NO

YES

Has a thorough inspection been performed within the last 48 months?

Establish the lifetime operating hours at various pressure and temperature (P, T) levels

Use the Stress-Larson-Miller ASTM minimum curve for the pipe material and σs to calculate the creep material life (L*) at given P-T conditions, where: LMP* = Larson-Miller parameter (for each σ ) and T* = temperature in °R (for

each operating temperature level)

LMP* = T*(20 + log10L*)

For each operating pressure, estimate the applied stress (σ) by calculating the mean

diameter hoop stress due to internal pressure, where:

P* = gage pressure, R = pipe radius to midwall, and t = pipe wall thickness

σ = P*Rt

Use the calculated L* and service exposure time (texp) at each P-T level to calculate the

Life Fraction Expended (LFE) for each operating regime

LFE = texpL*

Calculate total LFE:

Total LFE =

Where n is number of operating regimes (P-T combinations)

n

∑LFEii=1

No inspection necessary unless a change in operating

parameter is anticipated. If so, go

to life assessment Level III b

Is LFE > 10%?

Go to Level II

NO

YES

Figure 3-3 Level I Life Assessment Roadmap for Creep in High-Temperature Steam Headers


3-8

NO

Conduct careful inspection using relatively inexpensive methods (visual, UT, PT, MT, replication, hardness) based on expected damage types and locations.

Were cracks found, or are there signs of significant creep

cavitation?

YES

Attach thermocouples; after restart, determine temperature distribution, and monitor

temperature

Go to Level III Assessment

Measure operating pressure; calculate hoop stresses from mean diameter formula

Measure strain at key locations on component, if possible.

Input new stress/strain and temperature data into Level I life expenditure calculations (using ASTM minimum properties) and re-estimate remaining

life

Is the revised remaining life estimate substantially greater than the desired life?

NO YES

Conduct Level III Assessment

during next outage

Set re-inspection interval; maintain

accurate operating records

Figure 3-4 Level II Life Assessment Roadmap for High-Temperature Steam Headers


3-9

Conduct detailed inspection by best NDE methods available; size and orient all crack-like defects

Determine material properties by trepanning specimens and measuring: tensile properties; impact or toughness properties

(from Charpy V-notch, small punch, or fracture mechanics tests); isostress creep rupture properties; fatigue behavior; and

creep-crack growth rates via miniature specimens

Evaluate microstructure at key locations by replication and electron microscopy*

Determine material properties by trepanning specimens and measuring: tensile properties; impact or toughness properties

(from Charpy V-notch, small punch, or fracture mechanics tests); isostress creep rupture properties; fatigue behavior; and

creep-crack growth rates via miniature specimens

Input available data and perform transient and steady-state thermal analyses by finite element or finite difference methods

Input available data and perform detailed stress analysis by finite element method or finite

difference method

Perform fatigue, creep, and fracture mechanics analyses; calculate time to crack initiation

and to fracture after crack growth

NO Is RL greater than the desired life? YES

Make decision about repair/replacement Set re-inspection interval; maintain accurate operating records

Estimate costs and schedule

Input to plant and corporate plans

Figure 3-5 Level III Life Assessment Roadmap for High-Temperature Steam Headers

*determine creep cavity density and size; classify for BLESS analysis (i.e., oriented, linked, etc.)


3-10

3.3 NDE and Sample Testing for High-Temperature Headers

Successful implementation of life extension and operating strategies depends on accurate knowledge of potential impacts of operating changes as well as existing material conditions. With the exception of Type IV creep cracking, it is nearly always possible to detect accumulating damage with sufficient remaining life to allow implementation of rational run/repair decisions. The microscopic scale, dispersion and orientation of Type IV cracking make it difficult to detect so it tends to be extensive before it is detected.

As significant work continues to produce new NDE methods, and improve the capability of existing methods, the EPRI NDE center and other authorities should be consulted on a regular basis by those planning inspections. Improved methods, using miniature specimens for tensile and toughness testing as well as visual and electron microscopy, have also made sample removal and evaluation more practical.

Table 3-2 summarizes recommended NDE options for inspecting high-energy steam headers in accordance with the condition and remaining life assessment process depicted in Figures 3-1 through 3-4. The NDE options are categorized by life assessment inspection and analysis level (i.e., II or III; the Level I analysis determines whether an inspection is warranted).

As noted in Chapter 1, if the goal of condition assessment is to support an operating plan with long outage intervals, cycling, or other challenging conditions, or if known cracks are approaching a size or density of concern, then EPRI recommends using Level III NDE techniques. For inspections on headers early in their creep life, on units without a history of significant overheating, EPRI recommends starting with the lower-cost Level II inspections and only moving to the more-involved Level III inspections and analyses if additional data on crack sizes or densities are needed and the cost of added inspections can be justified by the value of greater confidence in remaining life estimates.

Phased array ultrasonic testing, and potentially other NDE methods, can also be used to identify microstructural creep damage prior to crack initiation (e.g., void formation and migration to grain boundaries). The level of confidence in being able to safely run for an extended period would be heightened, for situations where conventional UT using multiple beams found no cracks of concern, if added phased array examination also found no significant “early” damage.

The particular areas of the header, most susceptible to creep and fatigue damage, vary in response to non-uniform temperature and stress profiles throughout the component. However, weldments tend to warrant added examination.

More information on this topic can be found in EPRI Report 1004313, Header and Drum Damage: Theory and Practice (2003). Key areas of concern for damage related to cycling operation are highlighted in EPRI Report 1009914, State of the Art Boiler Design for High Reliability Under Cycling Operation.


3-11

Table 3-2 NDE and Sample Testing Options for High-Temperature Steam Headers



Body spool pieces Dimensional

Replication

Hardness testing

Tee body Video probe







Ligament regions Dimensional

Video probe


Conventional UT



Eddy current testing


Time-of-flight diffraction UT—more extensive scan to accurately size flaws, especially at stub tube penetrations

Acoustic emission


3-12



Major welds (girth, seam, and saddle)

PT


Conventional UT


RT

Replication (on the header surface, spanning the fusion line, the weld metal, the heat-affected zone, and the base metal)

Hardness testing



Acoustic emission

Alternating current (AC) potential drop


• Visual

• Hardness

• Oxide dating

• Replication






Stub tubes Visual inspection

Dimensional measurements

UT thickness measurements

UT oxide measurements

Replication

Stub tube welds PT

MT

Conventional UT


RT

Replication

Hardness testing

Conventional UT—more extensive scan to size flaw or obtain more information on an area especially susceptible to damage


RT—more extensive scan of (a) damage indication or (b) area that is especially susceptible to damage

Sample removal and testing (as noted for major welds)


3-13



Drain line penetrations Video probe

Conventional UT


RT


RT (more extensive scan of (a) damage indication or (b) area that is especially susceptible to damage.

RT plug and thermowell welds

PT

MT

RT

Replication


Supports Visual inspection

PT

MT

3.4 Analysis and Disposition for High-Temperature Headers

Table 3-3 lists allowable crack depth and location criteria and recommended action options (based on crack growth projection results) for the disposition of various types of damage in header walls and welds.

When remaining life estimates, based on data acquired via the NDE level II methods in Table 3-2, do not provide an acceptable margin for uncertainty, EPRI recommends performing Level III inspections if the value of the added RL confidence warrants the time and expense of additional testing. The extra inspection is generally justified by the rapidly accelerating damage often seen, with combined creep and fatigue, for aging units with significant cycling activity.

After run/repair/replace decisions have been made, the timing of the next condition assessment should be set. Typically, inspection intervals are established in conjunction with plans for the next major maintenance outage, which may be determined in part by header life estimates.

All analysis results and disposition decisions should be documented as part of a comprehensive boiler condition assessment program. A steam header’s RL should be reassessed whenever there is a significant change in operating conditions, such as a change in boiler cycle water treatment or conversion to cycling duty.


3-14

Table 3-3 Analysis and Disposition for High-Temperature Steam Headers



Header ligament cracking

Shallow (<15% through wall), non-growing cracks may be left in place

Deeper flaws may be allowed if supported by Level III analysis

Perform creep/fatigue crack growth analysis to see if crack will grow to exceed failure criteria before next inspection. Use EPRI’s Creep-FatiguePro or Boiler Life Evaluation and Simulation System (BLESS) code, or equivalent, for crack growth analysis.

If necessary, weld repair to restore ligament integrity

Determine and address root cause(s) of fatigue mechanisms

Header body seam welds

Dependent upon location and characteristics of damage within the area of the weld

Presence of flaws detected by NDE inspection requires Level III analysis of flaw growth

Perform creep/fatigue crack growth analysis to see if crack will grow to exceed failure criteria before next inspection. Use EPRI’s Creep-FatiguePro or BLESS code, or equivalent, for crack growth analysis.

If necessary, weld repair to restore weld integrity


Header body girth welds

Dependent upon location and characteristics of damage within the area of the weld

Presence of flaws detected by NDE actions requires Level III analysis of flaw growth

Perform creep/fatigue crack growth analysis to see if crack will grow to exceed failure criteria before next inspection. Use EPRI’s Creep-FatiguePro or BLESS code, or equivalent, for crack growth analysis

If necessary, weld repair to restore weld integrity


Tube attachment welds

None established Perform cycling crack growth analysis to assure weld integrity until next planned inspection

If necessary, grind out cracks and weld repair to restore weld integrity


Using BLESS for Creep and Fatigue Crack Growth Prediction

EPRI’s BLESS (Boiler Life Evaluation and Simulation System) is one example of a reliable software product that is faster and easier to use than programs requiring construction of three-


3-15

dimensional finite element models. BLESS-Headers 4.3 (cited in Table 3-3) analyzes crack growth in all header types, including high-temperature steam headers, and it supports header seam weld assessment. Because headers have a complex geometry, crack growth analysis can be complicated. BLESS Headers incorporates four models to capture crack initiation and growth—an oxide notching model, a creep-fatigue (time and cycle fractions) initiation model, a creep crack growth model, and a fatigue crack growth model.

BLESS calculates estimated remaining life as either a single value (when run in deterministic mode) or a statistical distribution (when run in probabilistic mode).

3.5 Preventive Actions for High-Temperature Steam Headers

Table 3-4 lists actions that have been shown to prevent or reduce continued damage accumulation or failure risk. There may be others.

Where practical, mitigating or eliminating the root causes of damage is the recommended approach to maximizing the useful life of high-temperature steam headers. At other times, repair or replacement of damaged welds or base metal is the necessary course for reducing risk to acceptable levels. In most cases, these repairs can be accomplished with well established repair methods based on many years of research and successful application.

In practice, strategic and economic objectives may limit the extent to which damage-causing conditions can (or should) be feasibly reduced. For example, the cost-effectiveness of avoiding rapid load changes to prevent fatigue cracking depends on the estimated savings from deferred or avoided header repairs or replacements versus the “opportunity cost” (i.e., the foregone revenue premium) of not providing load-following or cycling service to grid operators.

Similarly, the cost-effectiveness of lowering steam temperature set points to below design-basis values to reduce the rate of creep damage depends on the estimated savings from deferred or avoided header repairs or replacements versus the cost of higher fuel consumption per kWh (due to reduced thermal efficiency) and lost revenue during full load operating periods (due to reduced maximum unit output). The practicality of modifying header supports depends on the available clearance. The ability to correct temperature maldistributions depends on whether there are suitable available means of redirecting steam flows.


3-16

Table 3-4 Preventive Actions for High-Temperature Steam Headers

Damage Mechanism Preventive Actions

Thermal fatigue cracking of ligaments

Avoid fast thermal transients during startups, shutdowns, and load changes. Establish safe operating envelope. Evaluate and remedy shortcomings in boiler system operating and control systems/procedures and operator training.

Equalize temperature distributions of superheater and reheater tubing into outlet headers to reduce localized thermal mismatch. Evaluate and remedy temperature imbalances due to ash fouling, slagging, deslagging/sootblowing, gas flow distribution, and other furnace operating parameters (see precursors and root causes for superheater and reheater tubing damage in Section 2.3).

Evaluate and address root causes related to attemperator operation (see Chapters 7 and 8) and to condensate flow events during cycling operation

Perform weld repairs or replace end-of-life headers in sections, or in total, as necessary

Consider replacement of failure-plagued headers with higher strength, high-alloy ferritic steels, enabling the use of thinner walls, for which thermally induced stresses are lower

Creep/fatigue of header body weldments

Maintain steam temperatures at or below the design basis to slow creep. Evaluate and remedy shortcomings in boiler system operating and control systems/procedures and operator training.

Minimize bending stress on girth welds by addressing shortcomings in design, function, and condition of supports and restraints for header and attached piping and tubing

Correct end-to-end temperature distribution to minimize thermally induced bending stresses:

• Evaluate and remedy temperature imbalances due to ash fouling, slagging, deslagging/sootblowing, gas flow distribution, and other furnace operating parameters (see precursors and root causes for superheater and reheater tubing damage in Section 2.3)

• Evaluate and remedy root causes of temperature imbalance related to furnace gas leakage (impingement on header, ash accumulation, etc.)


Perform weld repairs, or replace end-of-life headers in sections, or in total, as necessary



3-17


Creep/fatigue cracking of tube attachment welds

Minimize bending stress at tube to header welds by addressing shortcomings in design, function, and condition of supports and restraints for header and attached piping and tubing.

Correct tube temperature distributions to maintain design limits:

• Evaluate and remedy temperature imbalances due to ash fouling, slagging, deslagging/sootblowing, gas flow distribution, and other furnace operating parameters (see precursors and root causes for superheater and reheater tubing damage in Section 2.3)

• Evaluate and remedy root causes of temperature imbalance related to furnace gas leakage (impingement on header, ash accumulation, etc.)


Perform weld repairs, or replace end-of-life fittings, as necessary

Quench cracking of superheater outlet headers (especially horizontal) as a result of condensation during startup

Review drainage effectiveness:

• Modify or add drains if necessary

• Address low points created by shortcomings in design, function, and condition of supports and restraints for header and attached piping and tubing

Evaluate and address root causes related to condensate flow events during cycling operation

Perform weld repairs, or replace end-of-life headers in sections, or in total, as necessary


3.6 References for High-Temperature Steam Headers

EPRI has published numerous technical reports relevant to damage mechanisms, condition assessment, and failure prevention for high-temperature steam headers (se following list). An expanded listing of references and resources is contained in Appendix C.

Condition Assessment and Damage Mechanisms

Accelerated Stress Rupture Testing Guidelines for Remaining Creep Life Prediction. EPRI: 1997. Report TR-106171.


3-18

Guidelines for Performing Probabilistic Analysis of Boiler Pressure Parts. EPRI: 2000. Report 1000311.


Header and Drum Damage: Theory and Practice, Volume 1: Information Common to All Damage Type, Volume 2: Mechanisms. EPRI: 2003. Report 1004313.

Repair Technology for Stub Tube-to-Header Creep Damage. EPRI: 1999. Report HW-113512.

Nondestructive Evaluation

Acoustic Emission Monitoring of High-Energy Headers. EPRI: 1997. Report TR-107839-V1.

Assessment of NDE for Pre-Crack Creep Damage in Boiler Components. EPRI: 2000. Report 1000310.

Guidelines for the Time-of-Flight Diffraction Inspection of Ligament Cracking in Steam Headers. EPRI: 2003. Report 1007702.


Operational Considerations






4-1

4 STEAM AND LOWER DRUMS

Drums (along with headers) are among the largest and most expensive boiler components. Damage to drum internals may also play a major role in damage to waterwall and/or superheater tubing (along with other influences involving design, operation, and maintenance of drums). As such, understanding and addressing the types of damage that drums accumulate is vital to the safe and economic operation of fossil power plants.

Boiler drums and drum internals are subject to numerous thermal, mechanical, and chemical influences that may initiate or propagate damage mechanisms involving corrosion and fatigue. Degradation is usually greatest in cycled units, which undergo many more startups and rapid load changes with associated thermal stresses. Startups after brief shutdowns can produce the highest thermal stresses because the drum will still be fairly hot while cooling may have occurred in feedwater heaters, economizer and waterwall tubing, and downcomers.

This chapter summarizes the basic elements of condition assessment of boiler drums. This material is adapted from EPRI’s 2003 publication, Header and Drum Damage: Theory and Practice (Report 1004313), and other EPRI reports.

Section 4.1 tabulates typical damage mechanisms for boiler drums in fossil power plants.

Section 4.2 provides a flow chart (Figure 4-1) to illustrate the general roadmap of EPRI’s three-level condition assessment approach, which is supplemented by the drum-specific tables in the other sections of this chapter.

Section 4.3 tabulates NDE and sample testing techniques suitable for Level II and Level III life assessments for drums.

Section 4.4 tabulates data analysis and decision-making criteria used for run/repair/replace disposition of condition assessment findings for boiler drums.

Section 4.5 tabulates candidate preventive actions that may be used to enhance the life of drums.

Section 4.6 lists EPRI reference materials pertaining to condition assessment and life optimization of drums.

4.1 Damage Mechanisms for Drums

Steam drums and lower drums generally operate at 700°F (370°C) or below, so they are not subject to significant creep degradation. Thus, as shown in Table 4-1, corrosion and cracking

Steam and Lower Drums

4-2

due to thermally and mechanically induced stresses are the two most common forms of damage. Inspectors should, at a minimum, check for these types of damage during maintenance outages. Critical supports and restraints should also be evaluated for wastage and creep damage if the hot walkdown inspection reveals significant signs of hot gas impingement due to leakage though gaps in the furnace lagging and insulation. If drum humping has occurred, plant personnel should address possible support damage and deformation and fatigue damage in attached tubing and piping.

Table 4-1 lists the most common types and locations of damage found in steam and lower drums. Most of these mechanisms can be traced to one or more of the following root causes:

• Deposits and/or corrosion resulting from:

– shortcomings in cycle chemistry selection, monitoring, or control

– shortcomings in condensate polisher and makeup water system; failure resulting in introduction of regeneration chemicals to boiler water

– inadequate or excessive blowdown or addition of chemicals to drum

– improper chemical cleaning

– inadequate planning and performance of shutdown/layup procedures

– air in-leakage to condenser or deaerator or during shutdown

• Thermal stress/shock resulting from introduction of cold makeup water to hot drum; startup with subcooled water in downcomers and waterwall tubing; uneven temperature distribution in waterwalls; and backflow from drains

• Temperature stratification, thermal stress, and humping due to damaged or poorly located/designed makeup water nozzles or drum internals

• Localized overheating due to impingement of hot gases leaking through voids in furnace lagging and insulation

• Cyclic stresses resulting from temperature and pressure transients during cyclic operation

• Problems with design or maintenance of drum and/or tubing supports and attachments (e.g., too little or too much flexibility or range of motion, imbalanced load distribution, etc.)

Table 2-9, “Precursors for Waterwall Tubing Damage,” should be consulted for a more detailed presentation of root causes that are, in many cases, also applicable to steam headers.

Appendix A provides descriptions of drum damage mechanisms and their causes. Additional characterizations and experience data are available in the EPRI technical reports listed in Section 4.6. Other relevant references are listed in Appendix C.

Table 4-1 Damage Mechanisms for Steam Drums and Lower Drums



4-3


Internal surfaces Corrosion

Thermal fatigue cracking

Corrosion-fatigue cracking

Internal structures and attachments Corrosion



Tube attachments, including downcomers

Corrosion



Body spool pieces Fatigue

Humping

Ligament regions Thermal/corrosion-fatigue cracking in (and between) bore holes, often initiating at corner on interior

Girth welds Internal thermal fatigue cracking at counterbores

Seam welds Corrosion

Corrosion-fatigue

Saddle welds for outlet nozzle(s) drain lines, hand hole fittings

Fatigue cracking

Stub tubes

Tube stub to drum welds

Internal thermal/corrosion-fatigue cracking


External fatigue cracking

Drain line penetrations Internal thermal fatigue cracking




Supports Overload

Support/lifting lug welds Fatigue cracking

4.2 Condition Assessment Roadmap for Drums

The condition assessment roadmap shown in Figure 4-1 provides a stepwise approach to identifying damage mechanisms and estimating the remaining life of steam and lower drums. Tables 4-1, 4-2, 4-3, and 4-4 provide support information for the different elements of the condition assessment process, including identification of relevant damage mechanisms and


4-4

guidance on run/repair/replace decision-making and determination of the next inspection interval.

Assemble and Review Inspection/Maintenance, Design/Fabrication, and Operating Records

Leve

l I: P

re -O

utag

e Step 2AConduct Hot

Walkdown and Interview Current and Retired Plant

Personnel to Supplement

Records

Step 2C

Risk Self-Assessment

Step 3

Perform Additional Inspections

Interpret Data/Indications;

Do Findings Warrant Additional Inspections

Now?

Step 5

Step 6

Step 7

Run or Make Repairs*/ReplacementsEstablish Inspection IntervalInstall New Instrumentation

Step 8ContinueRoutine

Inspection and

Maintenance Programs

Step 9

LOWInspections; Add as Convenient)

Cross-CheckFindings

NO

YES

Leve

l II:

Dur

ing

Out

age

Leve

l III:

Det

aile

d In

spec

tions

MODERATE/HIGH (Plan Inspection Outage)

OBSERVEDANOMALIES

*See EPRI weld repair and other guidelines

-

-Assessment

Step 1


Make DispositionDecision

Interpret Data Findings

Functional Tests

(Conduct Routine

Roadmaps for Waterwalls, Superheater Inlet Header,

and Superheater

TubingCross-Check Findings

Cross-Check Findings

Step 4 -- Perform Visual, Video, and NDEInspections on Drum Shell and Internals


Leve

l I: P

re -O

utag

e Step 2AConduct Hot

Walkdown and Interview Current and Retired Plant


Records

Step 2C


Step 3




Now?

Step 5

Step 6

Step 7



Inspection and


Step 9


Cross-CheckFindings

NO

YES

Leve

l II:

Dur

ing

Out

age

Leve

l III:

Det

aile

d In

spec

tions


OBSERVEDANOMALIES


-

-Assessment

Step 1




Functional Tests

(Conduct Routine

Roadmaps for Waterwalls, Superheater Inlet Header,

and Superheater

TubingCross-Check Findings


Step 4 -- Perform Visual, Video, and NDEInspections on Drum Shell and Internals

Figure 4-1 Condition Assessment Roadmap for Steam Drums and Lower Drums


4-5

4.3 NDE Options for Drums

Table 4-2 lists recommended NDE and sample testing methods for inspecting steam and lower drum walls and various internal structures and attachments, in accordance with the condition assessment process depicted in Figure 4-1. NDE options are categorized as a function of the condition assessment level being pursued (i.e., II or III; the Level I analysis determines whether an inspection is warranted).

As noted in Chapter 1, if the goal of condition assessment is to support an operating plan with long outage intervals, cycling, or other challenging conditions, or if known cracks are approaching a size of concern, then EPRI recommends using the Level III NDE methods. For routine inspections on units operating under design conditions, EPRI recommends starting with the lower-cost magnetic and penetrant testing and only moving to the more advanced Level II or Level III methods if additional data are needed on crack sizes and the cost of added inspections can be justified.

Work is under way to develop NDE methods that can identify microstructural fatigue damage (e.g., the creation and movement of dislocations in the metal lattice) prior to crack initiation. For situations where no cracks of concern were found, if added examination also found no significant “early” fatigue damage, the level of confidence in being able to safely run for an extended period would be heightened. This would be especially true for drums susceptible to high-cycle fatigue, where crack propagation rates can be fast. One of the leading candidate technologies is ultrasonic testing using electromagnetic acoustic transducers. Success appears most likely when the material properties of the wall were originally very homogeneous and when, as in drums, creep is not likely to be present. More information on this topic can be found in EPRI Report 1000313, Assessment of NDE for Pre-Crack Fatigue Damage in Boiler Components, and in EPRI Report 1004313, Header and Drum Damage: Theory and Practice.

Table 4-2 NDE and Sample Testing Options for Steam Drums and Lower Drums



Internal surfaces Visual/video probe



Chemical analysis of deposits


Alternating Current (AC) potential drop

Internal structures and attachments

Visual/video probe

MT/PT


4-6




Visual/video probe

MT/PT

UT

AC potential drop



Body spool pieces (if unusual sag or crack or corrosion progression is noted)

Dimensional

Hardness testing


• Visual

• Hardness

• Oxide Dating

• Replication


• Visual microscopy, with or without etching





Video probe

PT

Conventional UT






Acoustic emission


PT

MT

Conventional UT



Replication

Hardness testing



AC potential drop

Sample removal and testing (as noted for spool pieces)


4-7



Drain line penetrations Video probe

Conventional UT


RT



RT plug and thermowell weld

PT

MT

RT

Replication



PT

MT

4.4 Analysis and Disposition for Drums

As in the case of NDE options, the recommended action thresholds and run/repair/replace options are organized by drum component in Table 4-3. This information corresponds to the roadmap steps on “data/indication interpretation” and “disposition” in Figure 4-1.

If crack growth analyses based on magnetic and/or penetrant test data (i.e., the NDE level II methods in Table 4-2) do not provide remaining life estimates with an acceptable margin for uncertainty, EPRI recommends evaluating the cost of performing ultrasonic or AC potential drop inspections and determining if the value of the added RL confidence warrants the time and expense of additional testing.

After run/repair/replace decisions have been made, the timing of the next condition assessment should be set. Typically, inspection intervals are established in conjunction with plans for the next major maintenance outage.

All analysis results and disposition decisions should be documented as part of a comprehensive boiler condition assessment program. A drum’s remaining life should be reassessed whenever there is a significant change in operating conditions, such as a change in boiler cycle water treatment or conversion to cycling duty.


4-8

Table 4-3 Analysis and Disposition for Steam Drums and Lower Drums



Internal surface corrosion and fatigue cracking

Must maintain minimum wall thickness per American Society of Mechanical Engineers (ASME) code

Perform cycling crack growth analysis to ensure minimum wall not exceeded before next inspection

If necessary, grind out cracks and small pits to eliminate stress concentrators. Weld repair to restore wall thickness.

Determine and address root cause(s) of corrosion and fatigue mechanisms

Internal Structures and attachments

Must maintain adequate strength and geometry for functional performance

Analyze corrosion mechanisms and perform stress analysis and cycling crack growth analysis to ensure structural strength and function

If necessary, grind out cracks and small pits to eliminate stress concentrators. Replace or weld repair to improve or restore strength and function.

Determine and address root cause(s) of deformation and corrosion and fatigue mechanisms


None established Perform cycling crack growth analysis to assure weld integrity until next planned inspection


Consider welding rolled tubing connections that have loosened



Must maintain minimum wall thickness per ASME code

Must maintain functional geometry

Perform cycling crack growth analysis to assure weld integrity until next planned inspection

If necessary, grind out cracks and weld repair to restore wall thickness



4-9



Ligament regions


Analyze corrosion mechanisms and perform cycling crack growth analysis to ensure minimum wall not exceeded before next inspection








Drain line penetrations





Supports/ restraints

Maintain weight distribution and flexibility to adjust to hot/cold dimensional changes

Determine and address root cause(s) of functional failure

4.5 Preventive Actions for Drums

Where practical, mitigating or eliminating the root causes of material degradation is the recommended approach to maximizing the life of drums and their internals. Table 4-4 lists actions that have been shown to prevent or reduce continued damage accumulation in steam drums and lower drums. There may be others. In practice, strategic and economic objectives may affect the extent to which damage-causing conditions can be feasibly reduced. For example, the cost-effectiveness of any of these options depends on the specific drum and component materials, the affect on other components of changes in cycle chemistry, and the opportunity cost of changing operating conditions (e.g., avoiding fast cooldowns).

Table 2-13, “Preventive Actions for Waterwall Tubing Damage,” provides additional detail for some of these actions.


4-10

Table 4-4 Preventive Actions for Steam Drums and Lower Drums


Corrosion

Corrosion-fatigue





Review chemical cleaning procedures. Remedy shortcomings. (Shortcomings in chemical cleaning process may involve inappropriate cleaning agent, overly strong concentration, long cleaning time, temperature too high, failure to neutralize, breakdown of inhibitor, or inadequate rinse.)








4-11


Fatigue

Corrosion-assisted fatigue

Drum humping

Review/improve startup and shutdown procedures to minimize rate and magnitude of temperature, pressure, and stress transients. Evaluate and remedy shortcomings in boiler system operating and control systems/procedures and operator training.

Avoid forced cooling of the boiler

Consider using preheated feedwater for startups

Consider installing a furnace off-load circulating pump to equalize temperature in drums, waterwalls, and downcomers during shutdown

Equalize temperature distributions of waterwall tubing. Evaluate and remedy temperature imbalances due to ash fouling, slagging, deslagging/sootblowing, burner settings, and other furnace operating parameters (see precursors, root causes, and preventive actions for waterwall tubing damage in Section 2.3).

Modify drum internals to reduce temperature stratification and prevent contact of cold makeup water with drum walls, especially in ligament areas

Evaluate and remedy shortcomings in design, setting, function, and maintenance of supports and restraints

Redesign tubing and downcomer attachments to improve flexibility

4.6 References for Steam and Lower Drums

EPRI has published numerous technical reports relevant to damage mechanisms, condition assessment, and failure prevention for steam and lower drums (see following list). An expanded listing of references and resources is contained in Appendix C.




Thermal Fatigue Cracking in Fossil Boiler Drums; Finite-Element-Based and Fracture Mechanics Analyses. EPRI: 2005. Report 1011916.

Thermal Fatigue Cracking of Boiler Drums. EPRI: 2002. Report 1004614.

Thermal Fatigue of Fossil Boiler Drum Nozzles. EPRI: 2005. Report 1008070.


4-12





Cycle Chemistry Upsets During Operation: Cost and Benefit Considerations. EPRI: 2005. Report 1008005.



Deposition on Drum Boiler Tube Surfaces. EPRI: 2004. Report 1008083.

Guidelines for Chemical Cleaning of Conventional Fossil Plant Equipment. EPRI: 2001. Report 1003994.




5-1

5 ECONOMIZER HEADERS

Economizer headers, especially the inlet header, are prone to crack formation and failure due to thermal shock, thermal fatigue, and corrosion-fatigue. In recent years, flow-accelerated corrosion at economizer header inlet and tube outlet transitions has also been recognized as a significant risk factor. Degradation is usually greatest in cycled units, which undergo many more startups and rapid load changes that produce high thermal stresses due to high temperature differentials between gas-side and waterside. Startups after brief shutdowns can produce the highest thermal stresses because the economizer headers may still be fairly hot whereas economizer tubing and the feedwater heaters may have cooled.

This chapter summarizes the basic elements of condition assessment for economizer headers. This material is adapted from EPRI’s 2003 publication, Header and Drum Damage: Theory and Practice (Report 1004313), and other EPRI reports.

Section 5.1 tabulates typical damage mechanisms for economizer headers in fossil power plant boilers.

Section 5.2 presents illustrates the application of EPRI’s three-level condition assessment approach with flowcharts specific to economizer headers.

Section 5.3 tabulates NDE and sample testing techniques suitable for Level II and Level III life assessments for economizer headers.

Section 5.4 tabulates data analysis and decision-making criteria used for run/repair/replace disposition of condition assessment findings for economizer headers.

Section 5.5 tabulates candidate preventive actions that may be used to enhance the life of economizer headers.

Section 5.6 lists EPRI reference materials pertaining to condition assessment and life optimization of economizer headers.

5.1 Damage Mechanisms for Economizer Headers

In general, relatively low operating temperatures eliminate creep as a concern. Mechanical, pressure, and temperature fluctuations make fatigue a primary concern, especially with cyclic operation. Feedwater temperature and cycle chemistry may also be conducive to corrosion and flow-accelerated corrosion.

Economizer Headers

5-2

Table 5-1 lists the most common types and locations of damage found in economizer headers, stub tubes, and attachments. Inspectors should, at a minimum, check for these types of damage in these locations during maintenance outages. Additionally, extra efforts should address possible support damage and deformation and fatigue damage in attached tubing and piping, which may not be sufficiently flexible to accommodate humping or expansion of the header.

Most of these mechanisms can be traced to one or more of the following root causes:

• Deposits and/or corrosion resulting from:

– shortcomings in cycle chemistry selection, monitoring, or control

– shortcomings in condensate polisher and makeup water system; failure resulting in introduction of regeneration chemicals to boiler water

– improper chemical cleaning

– inadequate planning and performance of shutdown/layup procedures

– air in-leakage to condenser or deaerator or during shutdown

• Flow-accelerated corrosion resulting from reducing cycle chemistry, especially with excessive use of oxygen scavenger during shutdown or while operating with AVT

• Thermal stress/shock resulting from the introduction of cold feedwater to a hot header, particularly with slug feeding for drum top-off during shutdown or high flow rates during hot starts. This situation is particularly a concern at vulnerable locations created by:

– Large thermal gradients

– Small ligament spacing (generally less than 35 mm or 1.375 inch)

– Thickness well above code minimum (generally greater than 32 mm or 1.25 inch)

– Partial fillet welds for header to stub tube joints

– Restricted and/or differential expansion of attachments

• Bowing resulting from temperature stratification during trickle feeding on startup

• Fatigue and corrosion-assisted fatigue mechanisms driven by cyclic operation, water hammer, piping system loads, etc.

• Problems with design or maintenance of header and/or tubing supports and attachments (too little or too much flexibility or range of motion, imbalanced load distribution, etc.)

Table 2-19, “Precursors for Economizer Tubing Damage,” should be consulted for a more detailed presentation of root causes, which are generally also applicable to economizer headers.

Appendix A provides descriptions of these damage mechanisms and their causes. Additional characterizations and experience data may be found in the EPRI technical reports listed in Section 5.6. Other relevant references are listed in Appendix C.

Economizer Headers

5-3

Table 5-1 Damage Mechanisms for Economizer Headers


Header ID surface/body spool pieces

Corrosion

Thermal/corrosion-fatigue cracking (most likely at areas of highest temperature difference, particularly near to feedwater inlet and recirculation outlet)

Humping

Penetrations for tube and piping attachments, especially with sharp-edged transitions

Ligaments between tubing boreholes

Corrosion


Thermal/corrosion-fatigue cracking

Stub tubes Internal thermal/corrosion-fatigue cracking at toe of fillet weld

Flow-accelerated corrosion (most likely in first 4 to 5 inches from header outlet)

External thermal/mechanical fatigue (most likely on area with most movement near ends of header; tube jacking may occur with inadequate gap between stub tube and bottom of bore hole)

Thermal fatigue

Major welds (girth, seam) Corrosion

Internal thermal/corrosion-fatigue cracking at weld preparation counterbores or unground toe of seam welds

Saddle welds for outlet nozzle(s), drain lines, hand hole fittings, etc.

Thermal/mechanical fatigue cracking


Thermal fatigue cracking (especially with bimetallic welds)

Supports Overload


Corrosion

Erosion

Support/lifting lug welds Fatigue cracking

Economizer Headers

5-4

5.2 Condition Assessment Roadmap for Economizer Headers

The roadmap shown in Figure 5-1, and the detailed actions shown in Figures 5-2 and 5-3, provide step-by-step procedures for determining the condition and estimating the remaining life of economizer inlet headers and associated stub tubes. Tables 5-1, 5-2, 5-3, and 5-4 provide support information for the different elements of the condition assessment process, including identification of relevant damage mechanisms, run/repair/replace decision-making, determination of the next inspection interval, and actions to reduce the likelihood of future damage.

Economizer Headers

5-5

Assemble and Review Inspection/MaintenanceDesign/Fabrication, and Operating Records

Industry Experience

History of Stub Tube Failures

Design—General and Local

OperatingPractice

Assess susceptibility to cracking NOT SUSCEPTIBLE

SUSCEPTIBLE

Inspection decision.Plan inspection.

Was damage observed?NO

YESServiceability EvaluationMap extent and size of cracks.Perform worst case analysis to assess crack growth.Conduct detailed evaluation of cause of cracking.

Is safe operation possible?

Action 1:

NODispositionMake run/repair/replace decision

Review/modify procedures, control systems, and training as needed for safe and economic operation within plant goals

Action 2:

Establish re-inspection interval.Maintain records of operating conditions.Re-establish interval if plans change.

Hot WalkdownInspection, as

Practical

Verify with cold walkdownvisual inspection

Were cracks or riskfactors observed?

Conduct visual and NDEinspection; cold walkdownof supports, etc.

YES

NO

Action 8:

Action 4:

YES

Action 7:

Make repairs.Return header to service.

Replace or make immediate repairs and operating changes; schedule replacement; return to service.Replace with redesigned header ASAP.

Record baseline information.Note input for reinspectioninterval.

Return header to service

Leve

l I: P

re-O

utag

eLe

vel I

I: D

urin

g O

utag

eLe

vel I

II: D

etai

led

Insp

ectio

ns

Action 6:

Action 3:

Action 5:

Action 10:

Action 11:

Action 9c: ReplaceAction 9a: RunAction 9b:

Repair

Assemble and Review Inspection/MaintenanceDesign/Fabrication, and Operating Records

Industry Experience

History of Stub Tube Failures

Design—General and Local

OperatingPractice

Assess susceptibility to cracking NOT SUSCEPTIBLE

SUSCEPTIBLE

Inspection decision.Plan inspection.

Was damage observed?NO

YESServiceability EvaluationMap extent and size of cracks.Perform worst case analysis to assess crack growth.Conduct detailed evaluation of cause of cracking.

Is safe operation possible?

Action 1:

NODispositionMake run/repair/replace decision

Review/modify procedures, control systems, and training as needed for safe and economic operation within plant goals

Action 2:

Establish re-inspection interval.Maintain records of operating conditions.Re-establish interval if plans change.

Hot WalkdownInspection, as

Practical

Verify with cold walkdownvisual inspection

Were cracks or riskfactors observed?

Conduct visual and NDEinspection; cold walkdownof supports, etc.

YES

NO

Action 8:

Action 4:

YES

Action 7:

Make repairs.Return header to service.

Replace or make immediate repairs and operating changes; schedule replacement; return to service.Replace with redesigned header ASAP.

Record baseline information.Note input for reinspectioninterval.

Return header to service

Leve

l I: P

re-O

utag

eLe

vel I

I: D

urin

g O

utag

eLe

vel I

II: D

etai

led

Insp

ectio

ns

Action 6:

Action 3:

Action 5:

Action 10:

Action 11:

Action 9c: ReplaceAction 9a: RunAction 9b:

Repair

Figure 5-1 Condition Assessment Roadmap for Economizer Headers

Economizer Headers

5-6

Action 7:

Serviceability evaluation

Review NDE results and categorize defects into

one of the following groups:

Case 1:

No cracks

Case 2:

Cracks in borehole,none across inside diameter (ID)

Case 3:

Cracks across ID ligament

Perform temperature monitoring to determine if

damaging through-wall temperature gradients (ΔTs)

are being produced


damaging through-wall ΔTs are being produced

Perform temperature monitoring

Go to Action 8 Go to Action 8Conduct leak-before-break

analysis to ensure that header is safe to operate in

a cracked condition

Perform economic evaluation to determine if it is desirable

to operate with cracks

Go to Action 8

Action 7:

Serviceability evaluation

Review NDE results and categorize defects into

one of the following groups:

Case 1:

No cracks

Case 2:

Cracks in borehole,none across inside diameter (ID)

Case 3:

Cracks across ID ligament


damaging through-wall temperature gradients (ΔTs)

are being produced


damaging through-wall ΔTs are being produced

Perform temperature monitoring

Go to Action 8 Go to Action 8Conduct leak-before-break

analysis to ensure that header is safe to operate in

a cracked condition

Perform economic evaluation to determine if it is desirable

to operate with cracks

Go to Action 8

Figure 5-2 Details of Action 7 – Serviceability Evaluation for Economizer Headers

Economizer Headers

5-7

Figure 5-3 Details of Action 10 – Addressing Operating Impacts on Economizer Headers

5.3 NDE Options for Economizer Headers

Table 5-2 lists recommended NDE and sample testing methods for inspecting the economizer headers and stub tubes as part of the condition assessment process depicted in Figures 5-1 through 5-3. NDE options are categorized as a function of the condition assessment level being pursued (i.e., II or III; the Level I analysis determines whether an inspection is warranted).

As noted, the ligaments between stub tube penetration holes on the inlet header are especially prone to cracking.

Action 10:

Modify and monitor operating procedures

Determine ΔT limits for headers by performing stress analysis and fatigue crack growth analysis

Modify operating procedures so that ΔT limits are not exceeded

Install surface and through-wall thermocouples to measure temperature differentials

Monitor temperature levels to ensure that the calculated ΔT limit is not exceeded and to

record the severity and number of exceedances

Go to Action 11

Economizer Headers

5-8

As noted in Chapter 1, if the goal of condition assessment is to support an operating plan with long outage intervals, cycling, or other challenging conditions, or if known cracks are approaching a size of concern, then EPRI recommends using the Level III NDE methods. For routine inspections on units operating under design conditions, EPRI recommends starting with the lower-cost magnetic and penetrant testing and only moving to the more advanced Level II or Level III methods if additional data are needed on crack sizes and the cost of added inspections can be justified.

Work is under way to develop NDE methods that can identify microstructural fatigue damage (e.g., the creation and movement of dislocations in the metal lattice) prior to crack initiation. For situations where no cracks of concern were found, if added examination also found no significant “early” fatigue damage, the level of confidence in being able to safely run for an extended period would be heightened. This would be especially true for headers susceptible to high-cycle fatigue, where crack propagation rates can be fast.

One of the leading candidate technologies is ultrasonic testing using electromagnetic acoustic transducers. Success appears most likely when the material properties of the wall were originally very homogeneous and when creep is not an issue.

More information on this topic can be found in EPRI Report 1004313, Header and Drum Damage: Theory and Practice (2003).

Table 5-2 NDE and Sample Testing Options for Economizer Headers


NDE Detection Technique (Level II)


Internal Surfaces Visual/video probe






Tube attachments Visual/video probe

MT/PT, with weld toe dressing, as needed

UT

AC potential drop



Exploratory grinding

Economizer Headers

5-9





Dimensional

Hardness testing


• Visual

• Hardness

• Replication







Video probe

PT

Conventional UT






Acoustic emission


PT

MT

Conventional UT



Replication (on header surface, spanning fusion line, the weld metal, heat-affected zone, and base metal)

Hardness testing



AC potential drop

Sample removal and testing (as noted for spool pieces)

Drain line penetrations

Video probe

Conventional UT


RT

Phased array (focused) UT—more extensive scan of damage indication


Economizer Headers

5-10




RT plug and thermowell weld

PT

MT

RT

Replication



PT

MT

5.4 Analysis and Disposition for Economizer Headers

Table 5-3 lists header wall thickness code criteria and recommended action options (based on crack growth projection results) for the “serviceability evaluation” and “disposition” steps in the Figure 5-1 roadmap.



If FAC is discovered, disposition should also include plans to evaluate possible FAC damage in the boiler and turbine systems that have exhibited single-phase or two-phase FAC in other plants. A comprehensive FAC control program should address feedwater chemistry and evaluate possible material changes to provide resistance to FAC or allow use of chemistry that does not promote FAC.

All analysis results and disposition decisions should be documented as part of a comprehensive boiler condition assessment program. An economizer header’s remaining life estimate should be reassessed when there is a significant change in operating conditions, especially conversion to cycling duty.

Table 5-3 Analysis and Disposition for Economizer Headers



Internal surface Must maintain minimum wall Perform cycling crack growth analysis and

Economizer Headers

5-11



corrosion and fatigue cracking

thickness per American Society of Mechanical Engineers (ASME) code

extrapolate corrosion trends to assure that minimum wall thicknesses will exceed the minimum allowable values at least until the next inspection

If necessary, grind out cracks and small pits to eliminate stress concentrators. Weld repair to restore wall thickness or plan header replacement.


Tube attachment welds

None established Determine and address root cause(s) of corrosion and fatigue mechanisms

Perform thermal and stress analysis to differentiate between mechanical (flexibility) and thermal contributors to fatigue

Perform cycling crack growth analysis to assure weld integrity at least until the next planned inspection

If necessary, grind out cracks and repair weld to restore weld integrity

Body spool pieces



Perform cycling crack growth analysis to assure integrity at least until the next planned inspection



Ligament regions


Analyze corrosion mechanisms and perform cycling crack growth analysis to ensure minimum wall is not exceeded before the next inspection



Economizer Headers

5-12





Perform cycling crack growth analysis to assure weld integrity at least until the next planned inspection



Feedwater, recirculation, and drain penetrations


Determine and address root cause(s) of corrosion and fatigue mechanisms:

• Review flow regimes and analyze resulting thermal/stress transients for cycling conditions

• Consider installing extensive thermocouples for on-line monitoring

Analyze corrosion mechanisms and perform cycling crack growth analysis to ensure minimum wall is not exceeded before next inspection


Supports/ restraints

Maintain weight distribution and flexibility to adjust to hot/cold dimensional changes


5.5 Preventive Actions for Economizer Headers

Where practical, mitigating or eliminating the root cause(s) of material degradation is the recommended approach to maximizing economizer header life. Table 5-4 lists actions that have been shown to prevent or reduce continued damage accumulation in economizer headers. There may be others.

In practice, strategic and economic objectives may affect the extent to which damage-causing conditions can (or should) be feasibly reduced. The cost-effectiveness of any of the recommended actions in Table 5-4 depends on the specific economizer header design and material, the effect of changes in cycle chemistry on other components, the opportunity cost (i.e., the foregone revenue premium) of not providing load-following or cycling service, and the clearance available to allow tube support modifications if needed.

Table 2-23, “Preventive Actions for Economizer Tubing,” provides additional detail for some of these actions.

Economizer Headers

5-13

Table 5-4 Preventive Actions for Economizer Headers


Corrosion

Corrosion-fatigue












Economizer Headers

5-14


Fatigue


Humping

Review/improve startup, shutdown, and load change procedures to minimize rate and magnitude of temperature, pressure, and stress transients:

• Evaluate and remedy shortcomings in boiler system and control systems, operating procedures, and operator training

• Avoid forced cooling of the boiler

• Consider using preheated feedwater for startups

Consider installing an economizer off-load circulating pump to equalize temperature in drums, waterwalls, and downcomers during shutdown

Modify tube stubs and tubes to improve flexibility

Use full penetration welds to reduce stress concentrations

Modify pipework and header design/layout to reduce stresses; adjust operating procedures to accommodate remaining stresses

Evaluate and remedy shortcomings in design, setting, function, and maintenance of supports and restraints:

• Correct/repair tubing supports to reduce bending stresses at weld attachments

• Remove constraints that limit header movement in response to temperature changes

Redesign tubing and downcomer configuration near drum to improve flexibility

Perform stress analysis to confirm that planned modifications do, in fact, reduce stresses

Evaluate use of insulation on headers within convection pass. Procedures must be adjusted accordingly. Faster warmup on bare headers may allow thermal shock when cold feedwater is introduced on startup. Slower cooling on insulated headers creates opportunity for thermal shock during shutdown.

5.6 References for Economizer Headers

EPRI has published numerous technical reports relevant to damage mechanisms, condition assessment, and failure prevention for steam and lower drums (see following list). An expanded listing of references and resources is contained in Appendix C.

Economizer Headers

5-15


Guidelines for the Prevention of Economizer Inlet Header Cracking in Fossil Boilers. EPRI: 1989. Report GS-5949.

Guidelines on Controlling Flow-Accelerated Corrosion in Fossil and Combined Cycle Plants. EPRI: 2005. Report 1008082.


Low-Temperature Corrosion Problems in Fossil Power Plants—State of Knowledge Report. EPRI: 2003. Report 1004924.





Cycle Chemistry Guidelines for Fossil Plants: All-Volatile Treatment, Revision 1. EPRI: 2002. Report 1004187.

Cycle Chemistry Guidelines for Fossil Plants – Oxygenated Treatment. EPRI: 2005. Report 1004925.

Cycle Chemistry Guidelines for Fossil Plants – Phosphate Continuum and Caustic Treatment. EPRI: 2004. Report 1004188.





6-1

6 MAIN STEAM AND HOT REHEAT PIPING

History has shown that serious concern is warranted with respect to creep damage that may result from the combination of high temperature, high pressure, and seam welds in thick-walled piping—features that are characteristic of main steam and hot reheat piping, as well as the high-temperature headers covered in Chapter 3. Catastrophic failures of seam welds have occurred in several instances and are an important safety issue. Failures have also been seen in girth welds and other components such as valve bodies.

Creep damage occurs over time, mainly in piping that operates above 900°F (480°C). In large power plants, steam temperatures (and inside wall temperatures) in main and “hot” reheat piping (i.e., from the reheater to the turbine) are typically at or above 1000°F (540°C). Longitudinal (seam) welds are a specific concern because hoop stress acts on the weld metal and adjacent heat affected zone, which have increased vulnerability to stress.

The rate of creep is affected by temperature, stress, and material factors. High-temperature components in plants that are cycled may also degrade due to thermal fatigue or a combination of creep and fatigue. Damage resulting from creep-fatigue interaction can occur faster than either mechanism acting alone. Attemperator use or condensation during shutdown may further expose the piping to thermal shock, thermal fatigue, and/or corrosion-related damage mechanisms.

By accounting for component degradation by these various mechanisms, engineers can obtain a more accurate picture of a pipe section’s remaining life, better optimize inspection intervals, and improve the quality of run/repair/replace decisions.

Even when plant managers have opted to replace seam-welded piping in these services to mitigate the risk of failure and cost of condition assessment, continued diligence is still required for the lesser risks presented by girth welds.

This chapter summarizes and updates information presented in EPRI’s 2003 publication, Guidelines for the Evaluation of Seam-Welded High-Energy Piping, Rev. 4 (Report 1004329). It covers steam piping and associated fittings and equipment (tees, wyes, valves, attemperator internals, etc.) subject to continuous operation at temperatures in the creep region. In some plants, other piping may also operate in the time-temperature regime for which creep is a concern. This includes part or all of the superheater crossover piping (between stages of multi-stage superheaters), turbine bypass piping, and cold reheat piping subject to un-attemperated turbine bypass flow.

The main focus of this chapter is evaluation of creep and creep-fatigue. Other damage mechanisms are covered in Chapter 7, which addresses steam piping (and components) for which creep is not a significant concern. High-temperature steam distribution or collection headers,

Main Steam and Hot Reheat Piping

6-2

which are made of piping-grade material with greater wall thickness and more complicated geometry, are covered in Chapter 3.

After providing further information on damage mechanisms (Section 6.1 and Table 6-1), this chapter illustrates application of EPRI’s three-level evaluation methodology as appropriate for piping components operating at high temperature and pressure. Figure 6-1 (Section 6.2) provides a flow-chart roadmap of the three-level approach as applied to high-energy piping. Figures 6-2, 6-3, 6-4, and 6-5 illustrate key steps for determining the condition, serviceability, and disposition of seam-welded steam piping.

Section 6.3 reviews inspection and monitoring techniques applicable to Level II and Level III life assessments. Table 6-2 lists NDE techniques commonly used for Level II evaluations. Table 6-3 addresses sampling and NDE techniques that may be used for the more-extensive Level III evaluations.

Section 6.5 addresses procedures for data analysis and decision-making (disposition).

Section 6.6 provides a list of candidate “preventive actions” that may be useful for limiting damage and/or preventing future failures.

Detailed guidance and comprehensive reference material for assessing the condition of seam-welded high-temperature steam piping, including failure histories and analyses, can be found in EPRI Report 1004329, Guidelines for the Evaluation of Seam-Welded High-Energy Piping.

6.1 Damage Mechanisms for High-Energy Piping

Table 6-1 lists the most common types of damage found in high-energy steam piping systems. Inspectors should, at a minimum, check for these types of damage during maintenance outages. The most vulnerable locations appear to be:

• Superheater outlet lead (link) piping

• Clamshell elbows in hot reheat piping

Traditionally, creep has been the predominant damage mechanism of concern in baseloaded units. As these units are converted to cyclic duty, fatigue damage can become important, especially in the thicker-walled main steam piping and in material already degraded by years of creep damage. Further, simultaneous creep and fatigue can produce complex interactions in which creep strains reduce fatigue life and fatigue strains reduce creep life (i.e., overall crack growth is accelerated). Corrosion damage may further accelerate fatigue-related damage in units that have attemperators or accumulate condensation during cyclic operation.

Condition assessment of high-energy piping also requires evaluation of pipe supports, other boiler structures, and connections to turbines and high-energy headers. Misalignment or damage to these components may cause or give clues to damage in piping. Such damage may result from failed/misadjusted piping or header supports, water hammer, steam hammer, asymmetric quenching from condensate flow, or overheating due to furnace leakage or furnace temperature excursions.


6-3

Brief descriptions of piping damage mechanisms and their causes can be found in Appendix A. Additional characterizations and experience data may be found in the EPRI technical reports listed in the bibliography at the end of this chapter and in Appendix C. As the body of knowledge on creep behavior is expanding every year, more recent references should be consulted as they become available.

Table 6-1 Damage Mechanisms for Main Steam and Hot Reheat Piping

Component/Location Damage Mechanism

Seam welds Pre-crack and “Type IV” creep

Creep cracking

Fatigue cracking

Combined creep-fatigue cracking


Corrosion pitting

Weld flaws (including heat treatment)

Overheating

Spool pieces Creep swelling

Temper embrittlement

Thermal softening and sag

Oxide notching

Corrosion pitting

Overstress

Bowing

Wye and tee bodies; valve bodies

External creep cracking

External thermal fatigue cracking




Corrosion pitting

Overheating


6-4


Girth welds Pre-crack and “Type IV” creep

Creep cracking (internal/external)

Fatigue/thermal fatigue cracking (especially at toe of unground weld cap or at stress concentrator created by weld preparation counterbore)



Corrosion pitting


Weld flaws (including heat treatment)

Overheating

Overstress

Saddle welds Pre-crack and “Type IV” creep

Creep/creep cracking at saddle welds

Thermal fatigue cracking of saddle welds

Overstress

Radiographic testing (RT) plug and thermowell welds; small bore pipe connections

Creep/creep cracking

Fatigue/thermal fatigue cracking, especially with bimetallic welds

Overstress of branch pipe and welds

Penetrations Creep cracking at borehole

Thermal fatigue cracking at borehole

Thermal shock cracking at borehole

Supports Creep cracking

Fatigue cracking

Overload

Thermal softening

Corrosion

Improper alignment/setting/design


6-5

6.2 Condition Assessment Roadmap for High-Energy Piping

In general, EPRI’s condition assessment procedure seeks the answer to three questions to enable informed decision-making regarding run/repair/replace choices and the safe operational interval until the next inspection:

• What is the degree of damage already present in the component?

• What is the rate of damage accumulation, and is it likely to change?

• What is the extent of damage required to cause failure, and how long will it be until that occurs given the expected rate of future damage accumulation and an adequate margin of safety?

For high-energy piping systems, EPRI’s three-level approach may be arranged as follows and as illustrated in Figure 6-1:

• Level I provides for pre-outage information collection and risk self-assessment. It includes gathering and reviewing records on design and fabrication, operation, and past inspection/maintenance for the plant. Thorough information gathering, including a hot walkdown and interviews with current and retired staff, is key to accurately determining if the piping system is subject to relevant risk factors. For systems subject to creep, the Level I evaluation should include a calculation of remaining life using information available prior to on-pipe inspection (Figure 6-2). Use of acoustic emissions monitoring during operation may also be desirable at this point.

• Level II entails the performance of visual and NDE inspections during an outage at priority locations determined from the Level I risk assessment (Figure 6-3). Interpretation of findings will determine whether additional inspections are warranted during the outage. If not well documented, it may be necessary to wait until piping cools and insulation is removed to verify if the piping is indeed seam-welded. For main steam and hot reheat piping, diligent completion of this step is critical. A seam weld with serious sub-surface creep damage may be may be ground flush and thereby elude visual inspection. (Note: For cold reheat piping, covered in Chapter 7, seam weld damage is unlikely to occur if the weld cap is ground smooth on both OD and ID so it may be sufficient simply to determine if the pipe wall is smooth on inner and outer surfaces.)

• Level III provides for more detailed NDE testing and analysis to support run/repair/replace decisions for damage found during the Level II evaluation. For evaluation of creep, it generally will also involve metallurgical tests on plug or boat samples taken from the area of suspected damage. Figures 6-4 and 6-5 provide procedures for evaluating creep damage in thicker-walled main steam and lower pressure hot reheat piping.


6-6


Perform Visual and NDE Inspections

On-Pipe Verification

Leve

l I: P

reO

utag

e

Step 2A

Conduct Hot Walkdown

Step 2BInterview Current and Retired Plant


Records

Do Records Indicate Seam

Welds?

Step 2C


Step 3

Step 4BStep 4A




Now?

Step 5

Step 6

Step 7


Step 8

Flaws or Cavitation

Present?

ContinueRoutine

Inspection and


Step 9

NO

YES

LOW (Conduct Routine Inspections; Consider Added Inspection When Convenient)

SEAM-WELDED

SEAMLESS

NO

YES

Leve

l II:

Dur

ing

Out

age

Leve

l III:

Det

aile

d In

spec

tions

Step 1

MODERATE/HIGH (Plan Inspection and Outage)

OBSERVEDANOMALIES


-

-


Step 3YES

YES

Step 1


Creep Life Assessment (Figure 6-2)

Level IIIaFigure 6-4

Level IIIbFigure 6-5

NO

Make Disposition Decision

Interpret Data Finding




Leve

l I: P

reO

utag

e

Step 2A




Records


Welds?

Step 2C


Step 3

Step 4BStep 4A




Now?

Step 5

Step 6

Step 7


Step 8

Flaws or Cavitation

Present?

ContinueRoutine

Inspection and


Step 9

NO

YES


SEAM-WELDEDSEAM-WELDED

SEAMLESS

NO

YES

Leve

l II:

Dur

ing

Out

age

Leve

l III:

Det

aile

d In

spec

tions

Step 1


OBSERVEDANOMALIES


-

-


Step 3YES

YES

Step 1





NO



Figure 6-1 Roadmap for Main Steam and Hot Reheat Piping System Evaluation


6-7

NO

YES

Has a thorough inspection been performed within the last 48 months?

Establish the lifetime operating hours at various pressure and temperature (P, T) levels

Use the Stress-Larson-Miller ASTM minimum curve for the pipe material and σs to calculate the creep material life (L*) at given P-T conditions, where: LMP* = Larson-Miller parameter (for each σ ) and T* = temperature in °R (for

each operating temperature level)

LMP* = T*(20 + log10L*)

For each operating pressure, estimate the applied stress (σ) by calculating the mean

diameter hoop stress due to internal pressure, where:

P* = gage pressure, R = pipe radius to midwall, and t = pipe wall thickness

σ = P*Rt

Use the calculated L* and service exposure time (texp) at each P-T level to calculate the

Life Fraction Expended (LFE) for each operating regime

LFE = texpL*

Calculate total LFE:

Total LFE =

Where n is number of operating regimes (P-T combinations)

n

∑LFEii=1

No inspection necessary unless a change in operating

parameter is anticipated. If so, go

to life assessment Level III b

Is LFE > 10%?

Go to Level II

NO

YES

Figure 6-2 Level I Roadmap—Creep Life Expenditure Analysis for Seam Welds2

2 Adapted from Guidelines for the Evaluation of Seam-Welded High-Energy Piping, EPRI Report 1004329, December 2003.


6-8

Perform a visual inspection, supplemented as needed by liquid penetrant or magnetic

particle NDE.

Perform a conventional UT examination. Carefully inspect areas showing obvious

evidence of damage.

NO

YES

Is there a UT indication in the weld metal

interior?

Go toLevel III a

Go toLevel III b

Go toLevel III b

main steam piping hot reheat piping

Perform a visual inspection, supplemented as needed by liquid penetrant or magnetic

particle NDE.

Perform a conventional UT examination. Carefully inspect areas showing obvious

evidence of damage.

NO

YES

Is there a UT indication in the weld metal

interior?

Go toLevel III a

Go toLevel III b

Go toLevel III b

main steam piping hot reheat piping

Figure 6-3 Level II Life Assessment Roadmap—Inspection Process for Seam Welds3

3 Adapted from Guidelines for the Evaluation of Seam-Welded High-Energy Piping, EPRI Report 1004329, December 2003.


6-9

Cavitation limited to

area near tip of flaw

Cavitation

(A) Remove and evaluate a material plug or scoop sample near the UT indication location

(B) Perform metallographic replication on the removed sample

Are flaws or cavitation present?Go to

Level III b

Flaw at fusion line, creep cavitation

Flaw at fusion line, no cavitation

Cavitation in weld metal

Type IV HAZ cavitation

Extensive cavitation at fusion line,

spread throughout thickness

Replace spool

immediately

Position of cavities:

isolated (A) oriented (B), or linked (C)

Cavitation with

macrocracks

Estimate remaining life (RL) for cavity

position:

(A) RL = 0.4t

(B) RL = 0.18t

(C) RL = 0.06t

Where t=service life expended

Replace spool

immediately

Estimate remaining life by calculating life fraction expended:

(LFE) =

where N= cavity density, Nr= cavity density at indication

and λ and μ are material properties.Estimate remaining

life (RL):

RL = t

[1-( )λ]μ1-NNr[1-( )λ]μ1-NNr

1-LFELFE

1-LFELFE

Inspect girth welds, supports, etc.,

according to normal program*

Is RL > DL?

Replace spool

immediately

Go to Level III b

*See, for example, Condition Assessment Guidelines for Fossil Power Plant Components, EPRI report GS-6724, March 1990.

YES

NO

NO

YES

[ ]

Figure 6-4 Level III-a Roadmap—Implications of Flaw and Cavitation Findings4

4 5 Adapted from Guidelines for the Evaluation of Seam-Welded High-Energy Piping, EPRI Report 1004329, December 2003.


6-10

Run BLESS WM CCG* for a conservatively sized flaw extrapolated from the

indication and with:(A) 3xCt(B) 4xCt

NO

YES

Did the UT analysis from Level II reveal indications that were

(A) reliably located in the weld metal interior or (B) located in the

weld metal interior, but not reliably?

Did UT analysis performed in Level II reveal NO indications?

Did testing performed in Level III a reveal (A) a flaw in the weld metal with no cavitation or (B) a flaw at

the fusion line with creepcavitation only near the flaw tip?

Did testing performed in Level III a reveal a flaw at the fusion line with

no cavitation?

Run BLESS WM CCG for a 0.05-inch (0.125 cm)

flaw with 4xCt

Run BLESS WM CCG for actual

flaw size and with: (A) 2xCt(B) 4xCt

Run BLESS WM CCG for actual

flaw size with: (HIGH inclusion density near

fusion line)4xCt

(MEDIUM) 3xCt(LOW) 2xCt

YES

YES

YES

Is remaining life (RL) > DL?

Inspect girth welds, supports, etc.,

according to normal program**

Has a Level III a inspection been

completed?

Go to Level III a

Replace spool within remaining

life period

NOYES

*WM CCG is the BLESS Weld Metal Creep Crack Growth algorithm. Ct is the crack tip driver.

**See, for example, Condition Assessment Guidelines for Fossil Power Plant Components, EPRI report GS-6725, March 1990.

NO

NO

NO

YES

Figure 6-5 Level III-b Roadmap—Determining RL through Creep Crack Growth Analysis5

6.3 Inspection Techniques – NDE and Sample Testing

Level II evaluation of high-energy piping generally involves several types of nondestructive evaluation for inspection of areas of concern. Level III evaluation may cover greater area with


6-11

NDE and/or use more time-consuming techniques to acquire better information. Samples of material may be removed and tested (destructive evaluation) to verify damage indications or determine remaining life.

Some plants now supplement off-line NDE with on-line acoustic emissions (AE) monitoring. For some users, AE has been successful in pinpointing areas with active creep crack development. This allows more effective planning and prioritization of off-line inspections.

Table 6-2 summarizes NDE options for inspecting main steam and hot reheat piping as part of Level II or Level III condition assessments. Table 6-3 addresses techniques that require removal (and subsequent repair) of a material sample. For piping early in its creep life (i.e., less than 10% of life expended) on units without a history of significant overheating excursions, no special NDE measures may be needed. If known cracking or cavitation approaches a size or density of concern, the more-extensive Level III methods are recommended to provide greater confidence in remaining life estimates.

Phased array ultrasonic testing and other NDE methods can also be used to identify microstructural creep damage (e.g., void formation and migration to grain boundaries) prior to crack initiation. Where conventional ultrasonic testing (UT) using multiple beams finds no cracks of concern, the level of confidence in being able to safely run for an extended period would be heightened if phased array examination also found no significant “early” damage. Such NDE tests for added assurance would most likely be applied to longitudinal seam welds, particularly along the fusion line between the base metal and the weld metal. More information on this topic can be found in EPRI Report 1004329, Guidelines for the Evaluation of Seam-Welded High-Energy Piping, and in EPRI Report 1000310, Assessment of NDE for Pre-Crack Creep Damage in Boiler Components.

Table 6-2 NDE Options for Main Steam and Hot Reheat Piping

Component/Location NDE Detection Technique (Level II)

NDE Characterization Technique (Level III)

Spool pieces Dimensional checks

Hardness testing

Replication

Tee and wye bodies; valve bodies

Video probe


Replication





Phased array (focused) UT—more extensive scan of area with damage indication, such as linked or oriented cavities



6-12

Component/Location NDE Detection Technique (Level II)


Major welds (seam, girth, and saddle)

Liquid penetrant testing (PT)

MT

Conventional UT


RT

Replication (on the pipe surface, spanning the fusion line, the weld metal, the heat affected zone, and the base metal)

Hardness testing

Video probe



Acoustic emission

Replication (on a sample taken fromthe pipe where a UT indication has been found)



PT

MT

Conventional UT


RT

Hardness testing

Replication

Conventional UT—more extensive scan of (a) damage indication or (b) area with high risk of damage


RT—more extensive scan of (a) damage indication or (b) area that isespecially susceptible to damage

Pressure tap and drain line penetrations

Video probe

Conventional UT


RT

Phased array (focused) UT—more extensive scan of area with damage indication, such as linked or oriented cavities

RT


PT

MT

Replication

NOTES: In addition to the NDE techniques listed above, infrared thermography (IRT) is often used to determine if a valve is passing steam during operation. Acoustic emission (AE) leak detection is also useful for finding leaks in valves. Material chemical analysis may be performed to resolve any uncertainty regarding the composition of base or weld metals.


6-13

Table 6-3 Invasive Testing Options for Main Steam and Hot Reheat Piping

Sample Type Test Technique Data Acquired

On-pipe (grind out to subsurface)

Replication

Hardness testing

Liquid penetrant testing (PT)


Fusion line/interior weld metal/heat-affected zone (HAZ) damage (limited to exposed surface)

Cavitation

Cracking

Slag inclusion density

Spheroidization

Sulfide segregation

Hardness profile

Grain size/type

Fusion line cracking

Removal of OD crack or weld flaw (adequacy of weld repair preparation)

Boat or core plug sample Replication

Hardness testing

Optical microscopy

Electron microscopy

Cryogenic cracking

Cross weld stress rupture test on miniature tensile sample


Interior weld metal damage

Cavitation

Inclusion density

Spheroidization


Fine-grain HAZ damage

Weld centerline Type IV voids

Hardness profile

Grain size/type


6-14

Sample Type Test Technique Data Acquired

Ring sample Replication

Hardness testing

Optical microscopy

Electron microscopy

Cryogenic cracking

Cross weld stress rupture

Tensile and toughness tests


Interior weld metal damage

Cavitation

Inclusion density

Spheroidization

Fine-grain HAZ damage

Weld centerline Type IV voids

Hardness profile

Grain size/type

6.4 NDE Monitoring Techniques

On-line NDE monitoring may be used to prioritize areas for out-of-service inspection or for root cause analysis of damage discovered during Level II and Level III inspections. These techniques can be implemented with minimal plant downtime or set-up during an outage.

Thermography can provide indication of temperature rise rates, local impact of attemperator spray cycles, and bypass valve and drain operation or leakage. It can be performed with no work on the piping systems, but its utility is limited by pipe insulation.

Arrays of thermocouples and high-temperature strain gages provide more specific indication of thermal profiles and stresses resulting from thermal, pressure, or mechanical influences. These are particularly useful for indicating local effects of load cycling, startup, shutdown, and attemperation, but normally must be installed with insulation removed during an outage.

Acoustic emission monitoring is gaining increasing favor by some engineers as a technique that can significantly reduce inspection costs by identifying areas of active damage where limited inspection resources should be focused. AE can provide indication of probable creep damage locations, can be used to evaluate the comparative damage accumulation at different operating conditions, and can help distinguish between active and inactive cracks. With small patches of insulation removed, wave guides are welded to the pipe to allow detection of the high-frequency sounds emitted when cracks grow. By measuring the travel time to different detectors, damage locations can be approximated. The acoustic frequency and event count may help indicate damage mechanisms.

EPRI’s 2003 publication, Condition Monitoring for Boiler Availability Improvement (Report 1004300) addresses AE and other monitoring techniques for various boiler components. A summary description of AE monitoring techniques is provided in Appendix B. Other reference materials are listed in Appendix C.


6-15

6.5 Analysis and Disposition for High-Energy Piping

The goal of the condition assessment roadmap, as illustrated in Figures 6-1, 6-2, 6-3, and 6-4, is to establish a basis for making a decision to run, repair, or replace a boiler piping component. Table 6-4 lists recommended criteria for allowable crack characteristics along with recommended analysis or action options for cracks found in longitudinal and girth welds in various high-energy piping components.

As indicated, EPRI recommends performing Level III inspections if significant voids or cracks are found using the NDE level II methods in Table 6-2, if other data suggest likelihood of damage, or if higher confidence is required for inspection interval determination. The inspection findings are then used in crack growth analyses calculations to determine if, and for how long, the piping section is safe to operate. Depending on the findings and type of determination needed, this analysis may use a simplified software tool, like EPRI’s BLESS program, or a more demanding technique such as finite element analysis.

Typically, the need is to establish adequate confidence that the estimated remaining life exceeds the desired interval for the next inspection (most likely in conjunction with plans for the next major maintenance outage). In some cases, the timing for the next outage will be determined in part by the estimated life of high-energy piping welds. In other cases, the analyses may justify more aggressive repair or replacement actions to allow extension of this interval and improvement of unit availability. After run/repair/replace decisions have been made, the timing of the next condition assessment should be set.

All analysis results and disposition decisions should be documented and reviewed on a regular basis as part of a comprehensive boiler condition assessment program. Timing of routine condition assessment activities should be planned far in advance to coordinate with planned maintenance outages. The plan should include contingent plans to enable best use of opportunities presented by unplanned shutdowns and forced outages. Steam piping remaining life estimates should be recalculated whenever there is a significant change in operating conditions, such as a change in boiler cycle water treatment or conversion to cycling duty. The plan should also include criteria for reassessment, including what constitutes a significant change and whether reassessment should be performed before the change is made.

Using BLESS for Crack Growth Prediction and Remaining Life Analysis

EPRI’s BLESS (Boiler Life Evaluation and Simulation System) is one example of a software product that is faster and easier to use than programs requiring construction of three-dimensional, geometrically accurate, finite element models. BLESS-Pipes 4.3 (cited in Table 6-4) analyzes crack growth in seam-welded piping, including subsurface cracks and surface connected cracks. It is also capable of evaluating semi-elliptical surface cracks where the aspect ratio (crack length to crack depth) changes as the crack grows. The BLESS software supports both deterministic and probabilistic analyses, and includes material properties for 2-1/4Cr-1Mo, 1-1/4Cr-1/4Mo, the heat-affected zone, and weld metal, as well as default values for material-related variables, including crack depth, crack aspect ratio, stress-strain rate, and creep/fatigue crack growth relation.


6-16

For deterministic analysis, BLESS-Pipes uses median material properties for default values. Users can modify material properties by adding or subtracting standard deviations. They can also apply a multiplier to Ct (the crack driving force for crack-fatigue growth).

For probabilistic analysis, which involves Monte Carlo simulation and provides failure probability as a function of time, users can choose either conventional simulation or importance sampling. In general, the conventional method is more accurate, but importance sampling is significantly faster.

Table 6-4 Analysis and Disposition for Main Steam and Hot Reheat Piping

Component/Location Recommended Analytical Techniques and Disposition

Longitudinal seam welds in main steam piping

Characterize cracks regarding the presence of cavitation

For cracks with cavitation in the heat-affected zone (HAZ), determine if cracks are “macrocracks.” If macrocracks are present, replace spool immediately. If macrocracks are not present, use cavity density, material properties, and life expended to calculate remaining life. If remaining life is less than the desired inspection interval, replace spool immediately.

For cracks with cavitation that (1) are not located in the HAZ and (2) do not constitute macrocracks, determine if cavities are isolated, oriented, or linked. Use this information (plus cavity location and service life expended) to calculate remaining life. If remaining life is less than the desired inspection interval, replace spool immediately.

For cracks with no (or very minimal) cavitation, perform creep/fatigue crack growth analysis using EPRI’s Boiler Life Evaluation and Simulation System (BLESS) code, or equivalent, to ensure that remaining life is greater than the desired inspection interval. Because crack growth processes are not fully understood, these analyses are typically performed using conservative assumptions.

Longitudinal seam welds in hot reheat piping

Perform creep/fatigue crack growth analysis using EPRI’s BLESS code, or equivalent, to ensure that remaining life is greater than the desired inspection interval. Because crack growth processes are not fully understood, these analyses are typically performed using conservative assumptions.

If necessary, weld repair to restore weld integrity until the spool can be replaced (upon replacement, consider a seamless pipe section).

Girth welds (all piping and valves)


If necessary, weld repair to restore weld integrity until the spool can be replaced.


6-17

6.6 Preventive Actions for High-Energy Piping

Where practical, mitigating or eliminating the root causes of damage is the recommended approach to maximizing the useful life of main steam piping, hot reheat piping, and associated valves. Table 6-5 lists actions that have been shown to prevent or reduce material damage accumulation. There may be others.

In practice, strategic and economic objectives may affect the extent to which damage-causing conditions can (or should) be feasibly reduced. For example, reducing steam temperature will reduce the rate of creep damage accumulation and may prevent creep cracks from reaching the size requiring spool replacement, but estimated savings from deferred or avoided piping repairs or replacements must be weighed against the lost revenue from a reduction in maximum plant output and increased fuel cost per MWh.

Table 6-5 Preventive Action for Main Steam and Hot Reheat Piping


Creep/fatigue in piping seam welds

Maintain operating temperatures at or below the design basis to slow creep

Correct/repair piping supports to minimize stress on welds

Minimize cycling duty to reduce fatigue contribution to total damage. Optimize startup and shutdown procedures to minimize steam-to-metal temperature differentials prevent condensate flow events, water hammer, or steam hammer.

Seal hot gas leaks that affect piping outside furnace roof/wall

Creep/fatigue in piping girth welds

Maintain operating temperatures at or below design basis to slow creep

Correct/repair piping supports to minimizing bending stress on girth welds

Minimize cycling duty to reduce fatigue contribution to total damage. Optimize startup and shutdown procedures to minimize steam-to-metal temperature differentials and prevent condensate flow events, water hammer, or steam hammer.

Creep/fatigue in valves Maintain operating temperatures at or below design basis to slow creep

Correct/repair piping supports to minimize stress on valve bodies

Minimize cycling duty to reduce fatigue contribution to total damage. Optimize startup and shutdown procedures to minimize steam-to-metal temperature differentials and prevent condensate flow events, water hammer, or steam hammer.


6-18


Local thermal quenching of main steam piping during boiler shutdown; thermal quenching at drains due to suction from drain system

Monitor steam piping and drain temperatures

Maintain piping (and boiler) above saturation temperature for as long as possible during shutdown

Reduce pressure in steam piping to reduce saturation temperature (sliding pressure operation)

Optimize startup procedures to minimize steam-to-metal temperature differentials and condensate flow events

Modify pipe and boiler header drain systems

Change pipe support settings to improve/redirect condensate drainage

Cyclic cooling or quenching of main steam piping by attemperator operation

Evaluate/modify impact on attemperator operation from boiler settings and sootblowing operation

Modify attemperator water flow control to reduce cycling

6.7 References for Main Steam and Hot Reheat Piping

EPRI has published numerous technical reports relevant to damage mechanisms, condition assessment, and failure prevention for high-energy piping subject to creep (see following list). An expanded listing of references and resources is contained in Appendix C.


Condition Monitoring for Boiler Availability Improvement. EPRI: 2003. Report 1004300.




Life Assessment of Boiler Pressure Parts, Vols. 1-3, 5, and 7. EPRI: 1993. Report TR-103377.

The Use of Weld Overlays to Extend the Useful Life of Seam Welded High Energy Piping in Fossil Power Plants. EPRI: 2001. Report 1001270.




6-19

Acoustic Emission Monitoring of High-Energy Steam Piping. EPRI: 1995. Report TR-105265, Vol. 1.


Guidelines for Advanced Ultrasonic Examination of Seam-Welded High-Energy Piping. EPRI: 2000. Report 1000564.







7-1

7 COLD REHEAT AND SUPERHEATER CROSSOVER PIPING

Although serious incidents have been uncommon, cold reheat (CRH) piping systems present significant safety concerns. Recent analysis by EPRI and others has addressed catastrophic failures that originated at seam welds in CRH piping. A failure at a different plant appears to have initiated at a girth weld during a severe water hammer event. Each of these incidents released considerable destructive energy, resulted in significant economic loss, and could have caused severe injury or loss of life.

Like CRH piping, superheater crossover (SHXO) piping has sufficiently thick walls that vulnerability to thermal fatigue is increased. SHXO piping also may be exposed to cyclic operation of attemperators and standing water resulting from attemperator leakage or condensation during shutdown. Along with pipe geometry, weld geometry, and pipe support settings, these actors can lead to fatigue, corrosion, overstress, or combinations of mechanisms. Damage caused by these mechanisms includes cracking in girth welds where SHXO piping joins superheater headers.

There may be cases where parts of the CRH and SHXO piping are vulnerable to creep damage due to extended operation at high temperature. For these cases, creep evaluation techniques presented in Chapter 6 should be applied in tandem with the techniques described in this chapter. Creep is not an issue for pipe that has not experienced extended operation above 800°F (425°C).

Power plant operators should also evaluate other steam piping systems (i.e., turbine extraction, attemperation steam, low-pressure turbine bypass, etc.) and apply the procedures in this chapter to the extent warranted by the risks involved. Steam piping systems that may experience two-phase flow also require evaluation for flow-accelerated corrosion (see Chapter 10).

EPRI’s 2005 publication, Guidelines for the Evaluation of Cold Reheat Piping (Report 1009863) provides background and guidance for condition assessment of CRH piping systems. It encompasses all CRH piping system components, from the high-pressure turbine outlet to the reheater inlet header, including the piping runs and all major welds, piping supports, branch connections, attemperators, and drain and instrument connections that affect CRH piping behavior.

The knowledge areas and activities used for condition assessment of cold reheat piping systems are also applicable to superheater crossover piping and other systems with similar conditions.

Cold Reheat and Superheater Crossover Piping

7-2

7.1 System Evaluation Approach for CRH and SHXO Piping

Although appearing to be simple and straightforward, CRH and SHXO piping actually operate as complex systems that affect, and are affected by, numerous other systems. Each reported failure has a different combination of precursors. Each power plant and each piping system have a different fabrication, operation, and maintenance history and a different set of operating conditions.

Root causes may be related to many influences, both internal and external to the system, including pipe geometry, weld geometry, attemperator operation, and standing water from attemperator leakage or condensation during cycling. The same mechanisms that affect the piping systems may apply harmful stress to the headers to which they are connected. In some cases, parts of the SHXO piping or CRH piping may experience extended operation at temperatures high enough to cause metallurgical changes, including creep, although this is not likely to be as extreme as for main steam and hot reheat piping.

Diligence is required to be sure that multiple risk factors are adequately evaluated and that complex and non-obvious interactions of damage precursors are considered. CRH and SHXO piping systems have not been sufficiently studied to enable quantitative correlations between the extent or degree of the damage precursor(s) and damage accumulation. Still, it is possible to greatly reduce the risk of failure by determining and evaluating known and potential precursors and damage mechanisms.

Physical Properties of CRH Piping: A common configuration for cold reheat piping has a horizontal run from a low point near the high-pressure turbine exit valve. It may be joined by an HP turbine bypass pipeline before splitting into two CRH piping runs that climb the boiler structure and are routed to the two ends of the reheater inlet header. Each run may have a spray attemperator in the vertical run. Another attemperator will be integral with or downstream of the HP turbine bypass valve. A series of pressure relief valves may be installed near the high point of one or both CRH runs. Depending on geometry, the CRH system may have one or more low point drains.

CRH piping will typically operate at a pipe wall temperature of about 500°F to 700°F (260°C to 370°C). If all systems are working properly, only the pipe upstream of the HP turbine bypass attemperator (when operating, if separate from the bypass) would be exposed to temperatures above 800°F (425°C), where some metallurgies may be vulnerable to creep. Pipe wall thickness will be much lower than main steam and hot reheat piping but still thick enough to be exhibit thick-walled behavior. Pipe spools and elbows may be seam-welded or seamless. ASTM A256 Gr155 carbon steel is a common specification. The most vulnerable parts of CRH piping appear to be:

• Seam welds and girth welds in elbows and nearby piping, especially in the 6 o’clock position

• Attemperator components: spray nozzle, liner, attachment welds, and feedwater piping welds

• Radiographic plug and thermowell seal welds

• Pipe support assemblies


7-3

Physical Properties of SHXO Piping: Typically, a plant with two superheat stages will have two parallel SHXO piping runs, each carrying steam at high pressure and temperature from one end of the outlet header from the primary superheater to the inlet header of the secondary superheater. Each piping run may have a spray attemperator to control inlet temperature to the secondary SH.

SHXO piping will typically operate at pressures close to HP boiler output pressure and with pipe wall temperatures up to 800°F (425°C), which is high enough to make creep a minor concern. Pipe wall thickness will be similar to main steam piping whereas pipe material may be similar or a lower grade low-alloy steel or austenitic stainless steel. Pipe spools may be seam-welded or seamless. Piping runs will generally be shorter and have more complex routings than CRH piping, allowing less flexibility for dissipating expansion and contraction forces resulting from thermal cycling. The most vulnerable parts of the SHXO piping appear to be:

• Nozzles and welds at the superheater headers

• Attemperator components: spray nozzle, liner, attachment welds, and water supply piping welds

• Pipe elbow welds

• Radiographic plug and thermowell seal welds

• Pipe support assemblies

7.2 Damage Mechanisms for CRH and SHXO Piping

Knowledge of precursors, and the damage mechanisms they may cause, provides a starting point for systematic evaluation of risks and selection of mitigations for CRH and SHXO piping systems. Key factors in damage to this piping include:

• Sources of pressure and thermal variation that cause stress extremes or stress cycles that can initiate and drive fatigue crack growth:

– Frequent attemperator operation and cyclic duty have been key contributors to major failures

– Asymmetric cooling by attemperator flow or water induction can cause high displacement and damage to supports and support attachment areas

• Standing water that can lead to corrosion or to water hammer

• Design, fabrication, operation, and maintenance factors that can increase vulnerability to stress and corrosion

Although SHXO piping appears to have less risk associated with standing water than CRH piping, this vulnerability should be checked on a case-by-case basis. Water pooling may result from condensation during shutdown, including by water induction from superheater tubing. Pooling is less likely in systems without spray attemperators.


7-4

Tables 7-1 and 7-2 summarize damage mechanisms of greatest concern to CRH and SHXO piping, respectively. Table 7-3 relates damage mechanisms and precursors to specific components of the piping systems.

Table 7-1 Common Damage Mechanisms for Cold Reheat Piping

Damage Mechanism Comments

Fatigue cracking and corrosion-assisted fatigue

May initiate at fabrication flaws, corrosion pits, or other stress concentrators. May initiate and/or be driven by thermal, pressure, or mechanical transients.

Corrosion pitting In carbon steel CRH piping, corrosion pitting is typically associated with standing water. At welds, corrosion may form long, narrow grooves rather than pits.

Overheating May be caused by furnace gas leakage, incorrect selection of metallurgy, excessive superheater outlet temperature, or problems with the turbine or turbine bypass system

Overstress May be caused by water hammer or by sudden constraint of movement related to asymmetric quenching by water induction or inadequate performance of pipe supports. Generally undocumented. Water hammer appears to have been a key contributor to at least two catastrophic CRH line failures.

Note: Adapted from Table 3-1 of EPRI’s Guidelines for the Evaluation of Cold Reheat Piping (Report 1009863).

Table 7-2 Common Damage Mechanisms for Superheater Crossover Piping

Damage Mechanism Comments

Fatigue cracking Nozzles and welds at piping joint to primary superheater outlet header and secondary SH inlet header

Corrosion pitting In carbon steel SHCO piping, corrosion pitting is typically associated with standing water. At welds, corrosion may form long, narrow grooves rather than pits.

Corrosion-assisted fatigue May initiate at fabrication flaws, corrosion pits, or other stress concentrators. May initiate and/or be driven by thermal, pressure, or mechanical transients. Most likely where piping geometry allows pooling of attemperator spray or water induction from SH tubes.

Overheating May be caused by furnace gas leakage, incorrect selection of metallurgy, excessive superheater outlet temperature, or insufficient attemperation

Overstress May be caused by water hammer, inadequate performance of pipe supports, or by constraint of movement related to asymmetric quenching by attemperator spray or water induction. Generally undocumented.


7-5

Table 7-3 Typical Damage Sites in CRH and SHXO Piping Systems


Spool pieces and fittings Internal fatigue and corrosion-assisted fatigue at seam weld (if applicable)

Corrosion pitting and flow-accelerated corrosion

Oxide cracking

Tensile overload/deformation

Deformation due to differential heating/cooling/quenching

Thermal shock

Foreign object damage

Creep in seam welds (rare cases with extended operation above 700°F or 370°C)

Girth welds Tensile overload/deformation (outer diameter bending, stress-induced cracking)

Corrosion pitting/grooves and flow-accelerated corrosion


Internal fatigue and corrosion-assisted fatigue cracking, especially where stress concentration is created by weld preparation counterbores

Thermal shock


Wye and tee bodies, valve bodies


Internal fatigue and corrosion-assisted fatigue cracking

Tensile overload/deformation

Valve internals Erosion/corrosion of seats and plugs

Deformation and binding due to differential heating/quenching


7-6


Attemperators and bypass valves with integrated attemperation

Thermal fatigue cracking of thermal shields

High-cycle fatigue of attachment welds due to vibration

Thermal fatigue cracking of spray nozzles

Thermal and mechanical fatigue cracking of attachment welds to steam piping

Attemperator damage due to leaking from eroded valve seats

Leaking due to interference with valve motion—this may be due to design issues or related to other events

Performance changes (spray quality or flow rate) related to corrosion/erosion of spray nozzles

Piping drains Plugging with corrosion products and other contaminants

Erosion/corrosion of valve seats

Performance failure due to mechanical or control failure

Performance failure due to inadequate design and/or fabrication

Drain line, pressure tap, safety relief valve, and attemperator penetrations and attachments

Internal fatigue and corrosion-assisted fatigue cracking


Fatigue cracking at external attachment welds



With bimetallic welds, fatigue cracking

Piping Support System Deformation of static supports due to overload

Failure of dynamic support mechanisms due to overload or environmental factors

Functional failure of supports due to design issues or system changes

Note: Adapted from Table 3-2 of EPRI’s Guidelines for the Evaluation of Cold Reheat Piping (Report 1009863).

7.3 Application of Three-Level Condition Assessment Approach

For CRH and SHXO piping systems, as with other boiler components, a successful and cost-effective condition assessment program is founded on well-informed assessment of risk. For these piping systems, EPRI’s three-level approach works toward this goal as follows:

• Level I provides for pre-outage information collection and risk self-assessment. It includes gathering and reviewing records on design and fabrication, operation, and past inspection/maintenance for the plant. Thorough information gathering, including conducting a hot walk-down and interviewing current and retired staff, is key to determining if the piping system is subject to relevant risk factors.


7-7

• Level II entails the performance of visual and NDE inspections during an outage at priority locations determined from the Level I risk assessment. Interpretation of findings will determine whether additional inspections are warranted during the outage. Adequate information may be obtained to make component disposition decisions with additional (Level III) inspections.

• Level III provides for more detailed NDE testing and analysis to support run/repair/replace decisions for damage found during Level II evaluation.

Figure 7-1 presents an overview of the Condition Assessment Roadmap that adapts this three-level approach to the specific concerns of CRH and SHXO piping systems. The individual steps are summarized in the following paragraphs and explained in detail in EPRI’s Guidelines for the Evaluation of Cold Reheat Piping (Report 1009863). For piping that may have temperature-time exposure for which creep may be a concern, the procedures in Chapter 6, applicable to main steam and hot reheat piping, should also be considered.


7-8




Leve

l I: P

re-O

utag

eStep 2A




Records


Welds?

Step 2C


Step 3

Step 4BStep 4A

Perform Additional NDE Inspections



Now?

Step 5

Step 6

Step 7

Run and Establish Reinspection Interval, Make Repairs*/Replacements, and Install

New Instrumentation

Step 8

Interpret Data/Indications; Make Disposition

DecisionContinueRoutine

Inspection and


Step 9

NO

YES


SEAM-WELDED

SEAMLESS/

SMOOTH

SEAM

NO

YES

Leve

l II:

Dur

ing

Out

age

Leve

l III:

Det

aile

d In

spec

tions

Step 1


OBSERVEDANOMALIES





Leve

l I: P

re-O

utag

eStep 2A




Records


Welds?

Step 2C


Step 3

Step 4BStep 4A




Now?

Step 5

Step 6

Step 7


New Instrumentation

Step 8



Inspection and


Step 9

NO

YES


SEAM-WELDED

SEAMLESS/

SMOOTH

SEAM

NO

YES

Leve

l II:

Dur

ing

Out

age

Leve

l III:

Det

aile

d In

spec

tions

Step 1


OBSERVEDANOMALIES


Figure 7-1 Roadmap for Evaluation of Cold Reheat and Superheater Crossover Piping


7-9

Level I Evaluation – Pre-Outage

Step 1: Review Records

Condition assessment of the thick-walled steam piping system begins with assembly of records of design, fabrication, inspection, and maintenance for the system components along with operating history of the piping components and the generating unit as a whole (see Figure 7-2). If available, relevant information for similarly constructed and operated units should also be reviewed to identify potential problem areas.

Assemble and Review Records of CRH Piping Component/Support Walkdowns and Other Inspection

and Maintenance Records

Assemble and Review Plant Operating Records (Hours, Cold and Hot Starts, Attemperator Spray

Flow/Frequency, Water Hammer Log, etc.)

Assemble and Review CRH Piping System Design and Fabrication Records, Including As-Builts,

Modification Histories, and Piping Stress Analyses

Step 1.1

Step 1.2

Step 1.3

Proceed to Steps 2A-C

Assemble and Review Records of CRH Piping Component/Support Walkdowns and Other Inspection

and Maintenance Records

Assemble and Review Plant Operating Records (Hours, Cold and Hot Starts, Attemperator Spray

Flow/Frequency, Water Hammer Log, etc.)

Assemble and Review CRH Piping System Design and Fabrication Records, Including As-Builts,

Modification Histories, and Piping Stress Analyses

Step 1.1

Step 1.2

Step 1.3

Proceed to Steps 2A-C

Figure 7-2 Details of Step 1 of the Roadmap

Step 2A: Determine If Piping Is Seam-Welded

Figure 7-3 provides procedures for determining if piping is seam welded. This should be determined, early in the process, if piping is seam-welded or seamless, as this piping presents more risk requires much more work for inspection. Plant documentation may be unclear or inaccurate.

If the interior and exterior surfaces of the pipe are smooth and not obviously seam-welded, precise determination may not be critical as it is with hot reheat piping, where mid-weld creep is a concern. For CRH and most SHXO piping, the absence of stress concentrators significantly reduces risk.


7-10

Step 2B: Conduct Hot Walkdown

The hot walkdown should include all supports, connections to the high-pressure turbine and reheater, the HP turbine bypass, if present, and all branch piping connected to the piping including attemperator water supply piping starting at its source, and drain piping, ending at its final discharge point. Hanger settings, condition, and deviations from design are recorded on a piping support inspection checklist. A record of operating data, at the time of the walkdown, will facilitate analysis of observations. If strain gages or acoustic emission transducer arrays are installed, their readings should also be recorded.

Step 2C: Interview Personnel

Gaps in written documentation, and questions raised by field observation, are addressed through interviews with current and former operations, maintenance, and engineering personnel. The interviews should obtain multiple recollections regarding key periods in the unit’s history. Important questions address items that are often not present in plant records, such as:

• Do personnel recall any movement or damage to piping and supports that may have been caused by water hammer or severe quenching?

• Has there been any repair, modification, or replacement of piping system elements (e.g., spool, fitting, or support replacements) that may not have been recorded in the central filing system? Why were repairs or modifications made?

• Have they had any operating problems with piping drains?

• How frequently do attemperators operate? Have they been problematic?

• What changes in operating practices occurred over their tenure (e.g., pressure, temperature, dispatch duty, startup/bypass procedures)?


7-11

At Locations Identified for Inspection, Conduct Visual/Physical Examination

Step 2A

Contact Corporate Engineering and/or Piping Fabricator To See if Shop Records/Radiographs

Show Seam Welds

Do Plant Records Indicate

Seam Welds?

Proceed to Step 3, Risk

Self-Assessment

YES

NO

Were Seam WeldsObserved?

YES, SEAMED PIPE

NO, SEAMLESS OR SMOOTH SEAMED (Not Likely To Concentrate Stress)

Do Records Indicate Seam Welds?

Proceed to Step 4B,Visual and NDE Inspection

YES

Proceed to Step 3,Risk Self-Assessment

Check Records/ Radiographs for Grinding/ Blending of ID Weld Caps

NOStep 4A

From Step 1, Assembly and Review of Plant Records


At Locations Identified for Inspection, Conduct Visual/Physical Examination

Step 2A

Contact Corporate Engineering and/or Piping Fabricator To See if Shop Records/Radiographs

Show Seam Welds

Do Plant Records Indicate

Seam Welds?

Proceed to Step 3, Risk

Self-Assessment

YES

NO

Were Seam WeldsObserved?

YES, SEAMED PIPE

NO, SEAMLESS OR SMOOTH SEAMED (Not Likely To Concentrate Stress)

Do Records Indicate Seam Welds?

Proceed to Step 4B,Visual and NDE Inspection

YES

Proceed to Step 3,Risk Self-Assessment



NOStep 4A

From Step 1, Assembly and Review of Plant Records



Figure 7-3 Details of Roadmap Steps 2A and 4A


7-12

Step 3: Conduct Risk Self-Assessment

The Level I risk self-assessment entails review of all information collected in Steps 1 and 2 for indication of the presence and severity of damage precursors. Conclusions are reached regarding the existence and significance of risk factors that could lead to unacceptable damage in the piping. A decision is made that at this point—either no further investigation is needed, beyond routine inspection and maintenance procedures, or inspections are warranted during an upcoming maintenance outage (i.e., proceed to Level II and Step 4).

Findings should be well documented to facilitate future reference and periodic update in light of subsequent inspection data, operating changes, or equipment upgrades.

A piping stress analysis may be performed to help prioritize welds and other features to be inspected. For this analysis, design and as-built data should be supplemented by any available data from on-line monitoring instrumentation such as thermocouples and strain gages.

Table 7-4 provides criteria for selecting inspection of evaluation methodologies during the risk self-assessment.

Table 7-4 Inspection Recommendations Based on Risk Self-Assessment Findings

Risk Factor Indicators of Concern Suggested Inspection/Evaluation

Overstress mechanisms, including observed or suspected water hammer, severe quenching, restraint of thermal expansion/ contraction, imbalanced supports, or external loading

Pipe displacements that bent or broken support/ restraint hardware or structures, fractured pipe support welds, or otherwise appear to have exceeded about 6-12 inches (15-30 cm) of abnormal travel

Significant imbalance in support loading

Operator recollections of significant water hammer, pipe bowing, or external loading (such as from reheater inlet header bowing or seismic events)

Inspect surfaces of girth OD welds and hanger stanchion and branch piping welds in vicinity of support damage using PT/MT

Inspect girth and seam welds in vicinity of support damage using UT/TOFD

Perform stress analysis; inspect other major welds near areas with high bending stress when piping is hot or cold

Inspect pipe support/restraint mechanisms and structures and associated welds in vicinity of support damage using PT/MT


7-13


Undesirable seam weld orientation

Seams in the 6 o’clock position at piping low points or in horizontal spools/elbows with inadequate slope

Seams at locations with high bending stress when piping is hot or cold (locations in or near horizontally oriented elbows are of particular concern)

Inspect 6 o’clock welds and HAZ transitions for corrosion pitting or grooving and presence of cracks using UT/TOFD

Perform finite elements analysis, rather than simple pipe stress analysis, to evaluate stress fields around seam welds near elbows

Inspect high-stress seam welds, especially adjacent to girth welds, using UT/TOFD

If access is sufficient, consider an initial video/optical probe inspection

Stress concentrators on piping OD

Unground weld caps

Corrosion crevices

Weld flaws

Bimetallic welds (such as at thermowells or radiography ports)

Inspect areas surrounding OD stress concentrators or bimetallic welds using PT/MT

Consider hardness testing to confirm weld and HAZ properties

Inspect crevices and flaws using UT/TOFD

Stress concentrators on piping ID (if shown by radiography or a video/optical probe)

Unground weld caps

Weld flaws (if significant based on a review of radiographs or previous UT inspection)

History of hot dry steam conditions with low O2 (above 750°F or 400°C) that could create thick, brittle oxide scale, leading to corrosion pits/grooves upon flaking

Inspect areas surrounding ID stress concentrators using UT/TOFD

Consider ID hardness testing to confirm weld and HAZ properties (a Level III inspection requiring access to pipe interior)


7-14


Inadequate drainage

Unintended low points, due to line sag, where condensate can pool during outages

Indications of inadequate drain design, operation, or maintenance:

• Operator reports of inoperable or unused drains

• Drain configurations and mechanisms with known problems elsewhere

• Drain mechanism and piping configuration that can allow backflow due to pressure head or blowdown vessel pressure during unit shutdown

Indications of thermal stratification in piping (visible bowing or thermocouple readings, if installed)

Inspect piping low points and areas adjacent drains for corrosion pitting or grooving and presence of cracks using UT/TOFD

If access is sufficient, consider an initial video/optical probe inspection

Consider disassembly and inspection of drain mechanism and shutoff valve at each maintenance shutdown

Consider installing OD thermocouples at pipe tops and bottoms at low points and near drains for monitoring during startup

Frequent startups, shutdowns, and load changes (cycling)

Units with hundreds of starts and many more than comparable units in the fleet

Heat sinks due to gaps or thin insulation, especially at branches

Inspect surfaces of girth OD welds using PT/MT

Inspect girth and seam welds using UT/TOFD, especially at areas subject to corrosion or high bending stress when piping is either hot or cold

Inspect pipe for corrosion at low points using UT/TOFD, especially at seam and girth welds and drain penetrations

Inspect branch, instrumentation, and support attachment welds using PT/MT

Where heat sink effects could be an issue, inspect surface welds of stub-in connections using PT/MT and penetration boreholes (e.g., attemperator flange or thermowell port) for evidence of thermal stress cracking using UT


7-15


Frequent or poorly controlled attemperation

A high number of accumulated water spray cycles (e.g., >100,000)

Evidence of significant thermal quenching downstream of the attemperator liner:

• Temperature drop or high strain readings on pipe exterior (instrumentation recommended for frequently used attemperators with simple on-off controls)

• Thermal shock indications (alligator skin) on pipe interior (via video/optical probe)

Indications of inadequate attemperator design, operation, or maintenance:

• Attemperator configurations and mechanisms with known problems elsewhere

• Worn/damaged attemperator shutoff valves or spray nozzles

• Leakage due to poor valve shutoff detected by sound or by frequent operation of low-point drains

• Control/shutoff valve design inadequate for severe duty service

Inspect seam and girth welds downstream of attemperators using UT/TOFD:

• The most critical areas are at low points subject to water accumulation and corrosion; areas of high bending stress when piping is either hot or cold.

• Upstream piping should be inspected when attemperators are in or near poorly sloped horizontal pipe runs.

Inspect pipe for corrosion at low points using UT/TOFD, especially at 6 o’clock seam welds and girth welds and drain penetrations)

Inspect branch, instrumentation, and support attachment welds at attemperators using PT/MT, and also downstream

Consider disassembly and inspection of attemperator spray mechanism (nozzle and integral control valve) and shutoff valve at each maintenance shutdown

Consider in service monitoring of quench-prone areas using thermocouples, strain gages, and/or acoustic techniques

Water Induction Long deadlegs, such as inactive high-pressure turbine bypass

Reheaters with headers at low points and geometry that allows condensate overflow (during outage) back into CRH piping

Superheaters with headers at low points and geometry that allows condensate overflow (during outage) back into SHXO piping

Inspect CRH and SHXO piping entrance/exit where thermal shock or stress from quenching could occur, first via video/optical probe and with UT/TOFD if “alligator skin” is observed


7-16


Overheating Bowing at HP turbine bypass piping or CRH piping at entrance from turbine bypass

Thick oxide scale/oxide cracking observed during internal inspection

Bowing of SHXO piping

Consider ID hardness testing, replication, or other tests to detect metal damage due to overheating (a level III inspection requiring access to the pipe interior)

Level II Evaluation – On-Pipe Inspections During Outage

Level II evaluation will generally occur, during a routinely scheduled maintenance outage. Specific areas, identified during Level I evaluation, may warrant earlier attention when opportunity presents (i.e., by extending a shutdown during low demand).

Step 4A: Conduct On-Pipe Verification to Determine If Seam-Welded

On-pipe verification of seam welds should be conducted after cool-down and insulation removal (see Figure 7-3). Limited spot verification is recommended for weld position and finish shown on drawings. Step 3 risk determinations should be re-evaluated based on findings.

Step 4B: Perform Visual and NDE Inspections

Figure 7-4 outlines the inspection process involved in evaluation of major welds in CRH and SHXO piping. EPRI recommends starting with the lower-cost Level II methods and only moving to the more-involved Level III methods if additional data on crack sizes are needed for greater confidence in remaining life estimates (such as for units operating outside design conditions or with history of water hammer).

Level II evaluation involves visual and advanced inspection techniques that can be efficiently performed during a routine maintenance outage. If no anomalies are found, Level II activities will generally provide sufficient basis for a continuing condition assessment program using reinspection intervals consistent with other boiler components.


7-17

Develop Inspection Plan, including selection of priority locations (e.g., high-stress welds, downstream of attemperator, low points, and anomalies from hot walkdown) and NDE methods

Remove Insulation

Step 4B.1

Step 4B.2

Conduct Cold Walkdown and Visual Inspection (including video/optical probe)

Step 4B.3

Clean SurfacesStep 4B.4

Conduct PT and/or MT Examination for Priority Welds (major weld ODs and

attachment welds); Conduct any Hardness Testing at Major Weld ODs/HAZ

Step 4B.5

Conduct Pulse-Echo UT for Low Point Pitting Corrosion and Priority Major Weld ODs/IDs

Step 4B.6

Conduct TOFD UT for Major Weld IDsStep 4B.7

From Step 3, Recommendations for Inspection or Step 4A, On-Pipe Seam Weld Examination

Proceed to Step 5, Indication Interpretation and Further Inspection Decision

Develop Inspection Plan, including selection of priority locations (e.g., high-stress welds, downstream of attemperator, low points, and anomalies from hot walkdown) and NDE methods

Remove Insulation

Step 4B.1

Step 4B.2

Conduct Cold Walkdown and Visual Inspection (including video/optical probe)

Step 4B.3

Clean SurfacesStep 4B.4

Conduct PT and/or MT Examination for Priority Welds (major weld ODs and

attachment welds); Conduct any Hardness Testing at Major Weld ODs/HAZ

Step 4B.5

Conduct Pulse-Echo UT for Low Point Pitting Corrosion and Priority Major Weld ODs/IDs

Step 4B.6

Conduct TOFD UT for Major Weld IDsStep 4B.7

From Step 3, Recommendations for Inspection or Step 4A, On-Pipe Seam Weld Examination

Proceed to Step 5, Indication Interpretation and Further Inspection Decision

Figure 7-4 Details of Step 4B of the Roadmap: On-Pipe Seam Weld Examination

The cold walkdown inspection of the piping system should cover the same components covered in the hot walkdown (Step 2B), with additional inspection of areas exposed by removal of insulation. Pipe support settings should be checked against the cold walkdown checklist. Exposed piping surface, seam welds, girth welds, attachment welds, and seal welds (on radiography plugs and thermowells) should be checked for obvious signs of corrosion cracking or other damage.


7-18

The on-pipe inspection process includes development of an inspection plan and thorough cleaning prior to inspection. Spool piece number should be verified and recorded along with inspection date, time, locations and observations, weld orientations, instrument and examiner IDs, and type/brand of the applied NDE. The inspection plan may also specify surface hardness testing of welds and HAZ in the areas where significant UT indications were found.

Step 5: Interpret Findings for Level II

All UT indications identified during Step 4 inspections should be mapped, sized and classified by likely type (see Figure 7-5). EPRI’s Guidelines for the Evaluation of Cold Reheat Piping (Report 1009863) describes indicators that can be used to help establish or estimate a fatigue crack’s locus of initiation and growth history.

Tabulate and Review PT/MT Observations and UT/TOFD Indications:

• Sizing (depth, length)• Location• Probable Type (weld inclusion or porosity,

corrosion pit/groove, fabrication crack, fatigue crack)

• Proximity of cracks and stress concentrators

Are Further Inspections

Warranted Now?

Step 5

NO

YES

Proceed to Step 6, Additional NDE Inspections

Proceed to Step 8, Run and Establish Reinspection Interval or Repair/Replace

From Step 4B, Visual and NDE Inspections

Tabulate and Review PT/MT Observations and UT/TOFD Indications:



• Proximity of cracks and stress concentrators

Are Further Inspections

Warranted Now?

Step 5

NO

YES

Proceed to Step 6, Additional NDE Inspections


From Step 4B, Visual and NDE Inspections

Figure 7-5 Details of Step 5 of the Roadmap: Interpret Findings for Level II


7-19

Level III Evaluation – Enhanced NDE and Sampling

Step 6: Perform Additional NDE Inspections (Level III)

Figure 7-6 illustrates the roadmap for using Level III NDE techniques when the goal of condition assessment is to support an operating plan with long outage intervals, cycling, or other challenging conditions; if known cracks are approaching a size of concern; if the unit has experienced numerous water hammer events; or if a walk-down revealed other obvious evidence of damage.

Step 6 is similar to Step 4, except that it covers more welds, pipe surfaces, and components, as specified in the revised or supplemental inspection plan. It may also involve more sophisticated NDE and metallurgical analysis methods if a spool or material sample is removed.

Remove Additional Insulation, Inspect Visually, and Prepare Surfaces

Step 6.1

Step 6.2

Conduct Pulse-Echo UT and TOFD UT for Additional Major Welds

Step 6.3

If a Spool Is Removed, Conduct Hardness Testing/Replication at Priority Weld IDs/HAZ

Step 6.4

From Step 5, Determination of Need for Further Inspection

Proceed to Step 7, Indication Interpretationand Disposition Decision

Conduct PT and/or MT Examination for Additional Welds

Remove Additional Insulation, Inspect Visually, and Prepare Surfaces

Step 6.1

Step 6.2

Conduct Pulse-Echo UT and TOFD UT for Additional Major Welds

Step 6.3

If a Spool Is Removed, Conduct Hardness Testing/Replication at Priority Weld IDs/HAZ

Step 6.4

From Step 5, Determination of Need for Further Inspection

Proceed to Step 7, Indication Interpretationand Disposition Decision

Conduct PT and/or MT Examination for Additional Welds

Figure 7-6 Details of Step 6 of the Roadmap: Level III Inspections

Step 7: Interpret Level III Findings

Procedurally, Step 7 (Figure 7-7) is similar to Step 5, except that it may involve interpretation of more sophisticated NDE, metallurgical analysis methods for removed materials, and more sophisticated crack growth and remaining life modeling.


7-20

Tabulate and Review UT/TOFD Indications and Hardness/Other Data:



• Proximity of cracks and stress concentrators• Metallurgical changes• Consider applicability of crack growth algorithms

(LEFM, CDM, SAA, other) and estimate remaining life

Step 7


From Step 6, Additional NDE Inspections

Tabulate and Review UT/TOFD Indications and Hardness/Other Data:



• Proximity of cracks and stress concentrators• Metallurgical changes• Consider applicability of crack growth algorithms

(LEFM, CDM, SAA, other) and estimate remaining life

Step 7


From Step 6, Additional NDE Inspections

Figure 7-7 Details of Step 7 of the Roadmap: Interpreting Level III Evaluation

Step 8: Disposition Decisions

Table 7-5 lists minimum wall thickness and allowable crack size criteria and recommended analysis or action options for cracks found in CRH and SHXO piping components. Condition assessment disposition decisions are determined on a case-by-case basis involving technical and strategic or economic factors. These include run/repair/replacement alternatives, remaining-life estimation, and selection of reinspection intervals.

If remaining life estimates, obtained through crack growth analyses, do not provide an acceptable margin for uncertainty, EPRI recommends performing Level III inspections. This assumes that the value of the added RL confidence warrants the time and expense of additional testing.


All analysis results and disposition decisions should be documented as part of a comprehensive boiler condition assessment program. Cold reheat piping RL estimates should be recalculated whenever there is a significant change in operating conditions, such as a change in boiler cycle water treatment or conversion to cycling duty.


7-21

Table 7-5 Analysis and Disposition for Thick-Walled Steam Piping

Component/Location Permissible Flaw Size Recommended Analytical Techniques and Disposition


Must maintain minimum wall thickness per ASME (American Society of Mechanical Engineers) code

Extrapolate corrosion trends and perform cycling crack growth analysis to assure that wall thicknesses will exceed the minimum allowable values until the next inspection. Use EPRI’s BLESS code or equivalent for crack growth analysis.

If necessary, weld repair to restore wall thickness

Girth weld fatigue cracking

Use crack growth analysis to assure that cracks will not reach critical size before the next inspection. The typical maximum allowed size is 0.030-0.050 inch (0.075-0.125 cm).

Perform cycling crack growth analysis using EPRI’s BLESS code or equivalent to ensure weld integrity until next planned inspection


Repairs

When the decision outcome calls for repairs, EPRI suggests consideration of innovative, code-approved weld repair methods developed by its Fossil Repair Applications Center.

Step 9: Continue Routine Inspection and Maintenance Programs

Routine inspection and maintenance programs for cold reheat piping systems are often part of a generation company’s overall high-energy piping integrity program. EPRI recommends that, at a minimum, the elements of such programs devoted to CRH and SHXO piping systems should include:

• routine hot walkdowns

• cold walkdowns during maintenance outages, attemperator inspection and maintenance

• opportunistic inspections when access is provided by major maintenance on other components (e.g., examination of piping low points for corrosion when the high-pressure turbine casing is opened)

• planned inspections whenever aging or operational changes cross the thresholds for indicators of concern in Table 7-5


7-22

7.4 NDE Options for CRH and SHXO Piping

Table 7-6 lists many of the NDE tools used for Level II inspection, and more advanced or invasive techniques used for Level III.

If NDE indications suggest that damage of concern may be present in areas beyond those prioritized in the inspection plan, a revised or supplemental inspection plan should address additional areas (Level III evaluation or supplement to Level II). Further inspections may include inside wall hardness testing and advanced NDE techniques that require removal of fittings or spools. A refined analysis of all loads and stress analysis by finite element or other methods could also be used to identify other highly stressed regions. As with the initial Level II NDE inspections, all findings should be properly recorded to facilitate revised risk assessments and subsequent inspections.

More detailed discussion of the application, methodology, and capability of these tools is provided in Appendix B and in EPRI’s Guidelines for the Evaluation of Cold Reheat Piping (Report 1009863). Appendix C includes references pertaining to some of these tools.

Table 7-6 NDE Options for Thick-Walled Steam Piping




Spool pieces Dimensional

Video probe

Magnetic particle testing



Time-of-flight diffraction



Time-of-flight diffraction UT—more extensive scan to accurately size flaws found via conventional UT

Girth welds Penetrant testing


Conventional UT


Radiographic testing


Time-of-flight diffraction UT—more extensive scan to accurately size flaws found via conventional UT

Acoustic emission



7-23





Penetrant testing


Conventional UT



Conventional UT—more extensive scan of (a) damage indication or (b) area that is especially susceptible to damage


Radiographic testing—more extensive scan of (a) damage indication or (b) area that is especially susceptible to damage

Pressure tap and drain line penetrations

Video probe

Conventional UT






Penetrant testing


NOTE: Material chemical analysis may be performed to resolve any uncertainty regarding the composition of base or weld metals.

Monitoring

Enhanced monitoring techniques may reduce risk without the expense or delay involved with repair or replacement of components or economic sacrifice from limiting operating options. EPRI’s Guidelines for the Evaluation of Cold Reheat Piping (Report 1009863) describes thermocouple monitoring of pipe wall temperatures to aid study of thermal stress cycles and to prevent water hammer and other damage mechanisms related to pooled water. Strain measurements taken before a shutdown can help with timely decision-making if significant damage is found.

7.5 Preventive Actions for CRH and SHXO Piping

In some cases, run/repair/replace decisions may address changes in operating plans or improvement of monitoring capability. Table 7-7 lists actions that have been shown to prevent excessive corrosion and fatigue cracking. There may be others.

In practice, strategic and economic objectives may affect the extent to which damage-causing conditions can (or should) feasibly be reduced. For example, the cost-effectiveness of avoiding rapid load changes to prevent cracking depends on the estimated savings from deferred or avoided piping repairs or replacements versus the opportunity cost (i.e., the foregone revenue premium) of not providing load-following or cycling service to grid operators.


7-24

Table 7-7 Preventive Actions for Thick-Walled Steam Piping


Corrosion Maintain dry conditions in lines during shutdown/layup periods

Readjust/modify pipe supports to eliminate low spots and prevent pooling

Remedy shortcomings in attemperator design, maintenance, and operation; temperature and quality of attemperator water supply. (See further discussion on attemperators in Chapter 8.)

Remedy shortcomings in design, operation, and maintenance; temperature of drains



Avoid fast thermal transients during startup, shutdown, and load changes

Remedy shortcomings in attemperator design, operation, and maintenance; temperature of attemperator water supply

Remedy shortcomings in support and restraint design, maintenance, condition, and function

7.6 References for CRH and SHXO Piping

EPRI has published numerous technical reports relevant to damage mechanisms, condition assessment, and failure prevention for high-energy piping subject to fatigue (see following list). An expanded listing of references and resources is provided in Appendix C.









7-25


Acoustic Emission Monitoring of High-Energy Steam Piping. EPRI: 1995. Report TR-105265-V1.


High Temperature Strain Gaging. EPRI: 2005. Report 1004526.







8-1

8 ATTEMPERATORS (DESUPERHEATERS)

Attemperators can significantly affect other boiler components if they are not designed, operated, maintained properly. Although detection of damage to attemperator components is important, a functional review of the full attemperator system is a critical part of EPRI’s recommended Level I review and may be part of a root cause analysis for other boiler components adversely affected by attemperator operation. Accordingly, this chapter provides background information for such a broader review as well as the condition assessment roadmap for attemperator systems.

Attemperators (also known as desuperheaters) provide a means for power plant operators to control steam temperature at key locations in the boiler system. This chapter focuses on spray attemperators, which have been tied to catastrophic failure of cold reheat piping and cracking of welds in superheater crossover piping. The chapter gives less attention to direct contact steam attemperators or surface-type attemperators. Condition assessment involving these systems should be included with the applicable piping run or steam drum and use the condition assessment principles for high-energy piping, steam drums, and heat exchangers.

8.1 Considerations for Attemperators and Downstream Impacts

Understanding the design, operation, and maintenance of attemperator systems is important for understanding damage mechanisms in other systems, as well as for evaluating damage mechanisms experienced by attemperator system components. Any compromised function of these systems may cause or accelerate damage mechanisms in piping, headers, tubing, and other components.

Attemperators may be located:

• in cold reheat piping, between the high-pressure turbine exhaust and the reheater

• integral with a high-pressure turbine bypass valve (steam energy is used to atomize spray and mix with steam)

• downstream of a high-pressure turbine bypass valve, before the junction with cold reheat piping (steam energy may be used to atomize spray and mix with steam)

• in superheater crossover piping

• in main steam piping

• in hot reheat piping

• integral with or downstream of a low-pressure turbine bypass valve

• integral with or downstream of a process steam control valve

Attemperators (Desuperheaters)

8-2

Most power plants use direct contact attemperation as primary means for controlling superheater, reheater, and turbine bypass system exit temperatures. Spray attemperators and steam attemperators cool superheated steam through direct contact by adding water or slightly superheated steam to the superheated steam flow.

Some plants have only spray attemperators. Others may also include steam attemperators, typically to control steam temperature to the turbine during part-load operation when spray attemperation may not be effective. Steam attemperators are often located downstream of the secondary superheater and reheater. Spray attemperators are typically located upstream of the secondary superheater and reheater to prevent wet steam from reaching the turbine and to control tubing temperature in these components.

Surface-type attemperators are more common in industrial boilers than in some power plants. The surface attemperator cools superheated steam while heating water in a shell-and-tube heat exchanger or a heating coil installed in the boiler drum.

Spray Attemperator System Design and Operation

A spray attemperator will typically have a spray nozzle centered within a venturi insert in the piping system. The venturi accelerates the steam flow to help entrain the water flow. A thermal sleeve, extending downstream from the venturi, shields the piping from unevaporated water droplets. The spray attemperator system also includes the attachment nozzle, spray control valve, shut off/extraction valve, water supply line, and control system.

The spray attemperator system requires a supply of high purity water at a pressure somewhat higher than the pressure in the steam piping. If quality and pressure are adequate, boiler feedwater may be supplied from a takeoff at the boiler feedwater pump or downstream of it. A dedicated pump may be used to supply the attemperators from the low-pressure portion of the feedwater system, from feedwater heater shell drains, or from a specially treated source.

Spray attemperators are favored because they provide quick response and large operating range with minimal capital cost. At the same time, the introduction of water to steam piping introduces a number of risk factors:

• thermal shock or thermal fatigue may result from rapid or cyclic cooling of the hot ID surface of the pipe

• improper water chemistry may lead to corrosion, flow-accelerated corrosion, or corrosion- fatigue

• high dissolved solids content may result in deposition on heater tubes and turbine blades

• erosion may result from impingement of droplets or solid particles, or from steam bubble entrainment and collapse

• water hammer and steam hammer can result from entrainment of pooled water during startup and load change


8-3

Ideally, a spray attemperator will, at all times, provide just the right amount of water to maintain optimum steam temperature at the exit from the superheater, reheater, or turbine bypass. Use of attemperation will be limited by control systems and sootblowing practices that optimize distribution of boiler gas temperatures and tube surface heat transfer properties. Attemperator water flow will be increased and decreased gradually so as to minimize local or systemic temperature differentials. Steam and water will be thoroughly mixed to provide uniform steam temperature downstream of the attemperator, with all droplets evaporated before they have opportunity to contact the ID wall of the pipe.

In reality, attemperators often operates in a cyclic, on-off mode that can create rapid and extreme temperature differentials (and associated thermal stresses) through droplet impingement and/or bulk steam temperature changes. Asymmetric cooling may cause rapid pipe movement that can damage supports or the pipe itself. Poor mixing, excess water flow, or leakage during shutdown may establish water film flow along the pipe wall or pooling at undrained low points.

Attemperator system characteristics most likely to promote damage mechanisms include:

• damaged or poorly designed spray nozzles that create inadequate spray characteristics

• on-off operation that creates rapid temperature change at the ID surface and extreme temperature gradient through the pipe wall

• high differential between steam temperature and attemperator water temperature [Differential may be increased by cooling in long supply lines, especially when stagnant due to cyclic or infrequent usage.]

• pressure/temperature conditions that allow flashing or cavitation downstream of spray control valve

• spray control valves and instrumentation with poor response time, inadequate range, low precision, or performance degradation due to erosion or other damage

• location too close to pipe bends

The section on prevention, at the end of this chapter, lists operating and design practices that are less likely to lead to damage in attemperator systems and downstream components.

8.2 Damage Mechanisms in Spray Attemperator Systems

As noted, design and operating factors can cause damage to spray attemperator system components or piping downstream of the attemperator. Table 8-1 lists forms of damage found in spray attemperator system components, including functional damage that may itself lead to damage downstream of the system. More complete descriptions of damage mechanisms and their causes can be found in Appendix A.

Inspectors should, at a minimum, check for these types of damage during maintenance outages. As noted, specific types of functional damage may indicate greater risk of damage downstream of the attemperator. However, absence of such damage should not be assumed to mean the absence of risk to downstream piping.


8-4

Table 8-1 Damage Mechanisms for Attemperator Systems


Thermal shields Thermal fatigue cracking

High cycle fatigue due to vibration

Deformation by water or steam hammer

Thermal and mechanical fatigue cracking of attachment welds to steam piping

Creep damage to attachment welds (if installed in main steam or hot reheat; less likely in superheater crossover or HP turbine bypass)

Spray nozzles Thermal fatigue cracking



Spray nozzles integrated with or downstream of bypass valves

Creep or other overheating damage

Spray control valve Erosion of seat, plug, body due to high velocity flow, cavitation or flashing (resulting from high pressure drop; leakage; inadequate design, etc.)

Erosion of seat, plug, body due to solid particle entrainment

Deformation and binding due to differential heating/quenching

Fatigue, impact, or other damage to valve operator

Thermal, mechanical, and corrosion-assisted fatigue cracking of valve body

Flow-accelerated corrosion of valve body

Corrosion pitting of valve body

Penetrations and attachment welds to steam piping

Internal/external mechanical, thermal, and/or corrosion-assisted fatigue cracking



Creep damage to welds (if installed in main steam or hot reheat; less likely in superheater crossover or HP turbine bypass)


8-5


Water supply piping Thermal, mechanical, and corrosion-assisted fatigue cracking



Corrosion pitting

Erosion downstream of control valve due to cavitation or flashing

Damage from external impact

Functional damage to attemperators and bypass valves with integrated attemperation

Performance changes related to cracking, corrosion, or erosion of spray nozzles:

• Excess flow

• Oversized droplets or stream flow

• Asymmetric flow; poor pattern

Performance changes related to blockage of spray nozzles:

• Reduced flow

• Asymmetric flow; poor pattern

• Leakage from eroded valve seats/plugs

Leakage due to interference with valve motion—due to design issues, warped body or internals, or other damage

Reduced opening due to interference with valve motion—due to design issues, warped body or internals, or other damage

Piping support system Deformation of static supports due to overload



8.3 Condition Assessment Roadmap for Attemperator Systems

The condition assessment process for spray attemperator systems has two goals:

• determine risks and assess condition of attemperator system components

• develop input for risk determination and root cause analysis for possible damage in downstream components

As with other piping system components, hot and cold walkdown inspections are important parts of this evaluation. These inspections should cover the attemperator system from the water source to the attemperator installation and should confirm design details or note deviations. When possible, direct observation of physical response, noise, and temperatures (at the water


8-6

source and upstream and downstream of the spray control valve) should be obtained while the system is cycling. A detailed boiler operation history should be gathered, including attemperator cycles, corresponding boiler temperatures, and cycle chemistry programs and upsets.

The generic condition assessment roadmap (see Figure 8-1) illustrates step-by-step guidelines that can be used to assess the condition of attemperators. The information presented in the previous sections of this chapter provides background for Level I evaluation of downstream components as well as for attemperator system components. Techniques and criteria for NDE (inspection), data analysis, and decision-making are presented in Sections 8.4 and 8.5. Section 8.6 addresses preventive actions that should be considered to prevent future damage.


8-7


Step 4B -- Perform Visual, Video, and NDEInspections onAttemperator Components

Dismantle Valve(s)/Nozzles Inspect/Overhaul Internals

Leve

l I: P

re -O

utag

e

Step 2AConduct Hot

Walkdown and



RecordsScheduled for

Overhaul?

Step 2C


Step 3

Step 4A




Now?

Step 5

Step 6

Step 7



Inspection and


Step 9

NO


Cross-CheckFindings

NO

YES

Leve

l II:

Dur

ing

Out

age

Leve

l III:

Det

aile

d In

spec

tions


OBSERVEDANOMALIES


-


Step 3

YES

Step 1




Inspections on Body InteriorPerform Visual/NDE

Functional Tests

(Conduct Routine

Roadmap(s) for

Systems and Components Downstream

from Attemperator



Valve(s)and Nozzles


Step 4B -- Perform Visual, Video, and NDEInspections onAttemperator Components

Dismantle Valve(s)/Nozzles Inspect/Overhaul Internals

Leve

l I: P

re -O

utag

e

Step 2AConduct Hot

Walkdown and



RecordsScheduled for

Overhaul?

Step 2C


Step 3

Step 4A




Now?

Step 5

Step 6

Step 7



Inspection and


Step 9

NO


Cross-CheckFindings

NO

YES

Leve

l II:

Dur

ing

Out

age

Leve

l III:

Det

aile

d In

spec

tions


OBSERVEDANOMALIES


-


Step 3

YES

Step 1





Functional Tests

(Conduct Routine

Roadmap(s) for

Systems and Components Downstream

from Attemperator



Valve(s)and Nozzles

Figure 8-1 Condition Assessment Roadmap for Attemperator Systems


8-8

8.4 NDE Options for Attemperator System Components

Table 8-2 lists recommended NDE options for inspecting attemperator system components in accordance with the condition assessment process depicted in Figure 8-1. This table categorizes the options by the condition assessment level being pursued (i.e., I, II, or III).

The Level I analysis, which determines whether an out-of-service inspection is warranted, can be supplemented with thermal and acoustic techniques to detect functional damage. If acoustic emissions monitoring is used on the steam piping run, it may also provide indications relevant to Level I evaluation of the attemperator installation.

For attemperators, EPRI recommends starting with lower-cost magnetic or penetrant testing and only moving to the Level III methods if added data are needed to reduce remaining life uncertainty and can be economically justified. However, some attemperator installations use fully welded construction, and cannot be directly inspected without cutting welds. For these installations, radiography may be appropriate for Level II inspections while magnetic particle testing and penetrant testing of ID surfaces may be more appropriately categorized as Level III rather than Level II.

In general, Level III techniques are most relevant for welds where the attemperator assembly attaches to the steam piping, and for cases where the goal of condition assessment is to support an operating plan with long outage intervals or extensive cycling.

Table 8-2 NDE Options for Attemperator Systems


In-Service Inspection (Level I)

NDE Detection Technique(Level II)


Thermal shields

Acoustic/vibration sensor

Video/fiber optic probe

Magnetic particle testing (1)

Penetrant testing (1)

Radiographic imaging (1)

Spray nozzles; nozzle assembly


Thermal imaging

Thermocouples

Acoustic emission monitoring


Visual (remove assembly)





8-9





Branch nozzle assembly

Visual

Thermal imaging

Thermocouples


Visual



Penetrant testing



Replication

Material sample testing

Time-of-flight diffraction UT—more extensive scan to accurately size flaws found via conventional or focused UT

Nozzle penetration


Video probe

Conventional UT






Control valve bodies

Visual

Thermal imaging

Thermocouples

Visual


Penetrant testing

Conventional UT



Control valve internals


Thermal imaging

Thermocouples

Visual


Penetrant testing

Water supply piping

Visual

Thermal imaging

Thermocouples

Visual

Magnetic particle testing (welds)

Penetrant testing (welds)

Conventional UT (elbows, other transitions, and downstream of control valve)

Video probe




Material sample evaluation


8-10






Penetrant testing


Conventional UT






Dimensional and/or load measurement (hot position)

Visual inspection

Dimensional and/or load measurement (cold position)

Penetrant testing


NOTES:

1) Direct inspection techniques may be categorized as Level III rather than Level II if access is difficult. Radiographic imaging or another technique should be considered.

2) Material chemical analysis may be warranted if there is any uncertainty about base or weld metal composition.

8.5 Analysis and Disposition for Attemperator System Components

Table 8-3 provides basic criteria and techniques for the “data/indication interpretation” and “disposition” steps in Figure 8-1. The basic Level I goal is determining damage risk and prioritizing inspection activities. As noted, Level I condition assessment also provides insight regarding the affect of attemperator system operation on downstream components. This impact evaluation should be weighed in conjunction with other inputs to run/repair/replace decisions.

In many cases, little analysis is required following Level II inspection. The dominant damage mechanism—thermal fatigue—can produce rapid crack growth and the cost of repairs is much less than that for major components such as headers and drums. Accordingly, grinding and weld repair of any observed damage is the norm. Crack growth analysis would only be performed where the attemperator attaches to the more expensive superheater piping.

In other cases, the cost of repairs or the relationship to damage mechanisms in other components may justify more extensive Level II and Level III analysis. Such would be the case where discovery of wall thinning could involve localized conditions or could be related to a boiler-wide FAC problem. Discovery of a deformed venturi/thermal shield insert might warrant extensive root cause analysis. Flow modeling might be considered to weigh the impact of continued operation against the time and cost involved in opening the pipe for repair or replacement.


8-11

Table 8-3 Analysis and Disposition for Spray Attemperator Systems

Component/Location Permissible Flaw Size and Other Decision Criteria

Recommended Analytical Techniques and Disposition

Thermal shields (cracking)

None. Fatigue cracks progress rapidly in this component.

Grind out surface cracking. Replace if damage is severe.

Thermal shields (corrosion/erosion)

Serviceability

Trend of material loss

Perform root cause analysis. Extrapolate corrosion/erosion trends and evaluate serviceability. Remedy cause if serious. Reinforce or replace if damage is severe. Consider material and/or design change.

Thermal shields (deformation)

Serviceability Perform root cause and downstream impact analysis. Remedy cause if serious. Repair or replace if damage is severe. Consider material and/or design change. Consider fluid flow analysis if warranted to avoid repair cost or delay of return to service.

Spray nozzles (erosion)

Serviceability Perform root cause and downstream impact analysis. Remedy cause if serious. Replace if damage is severe. Consider material and/or design change. Consider fluid flow analysis if warranted to avoid repair cost or delay of return to service.

Spray nozzles (cracking)

None. Fatigue cracks progress rapidly in this component.

Grind out surface cracking. Replace if damage is severe.

Attachment welds to steam piping

Maintain minimum wall per American Society of Mechanical Engineers (ASME) code

Perform crack growth analysis using fracture mechanics code. If necessary, perform weld repair to maintain integrity until next planned inspection.


8-12



Internal surface corrosion/erosion


Extrapolate corrosion trends

If necessary, replace or weld repair to restore wall thickness

Perform root cause analysis to determine if metal loss is due to corrosion, erosion, or flow-accelerated corrosion

If FAC, evaluate water source and cycle chemistry. Change metallurgy if source or chemistry cannot be changed to limit FAC.

If oxygen corrosion, evaluate water source and cycle chemistry. Determine source of excess oxygen. Evaluate feasibility of change to operating modes (i.e., bleed or recirculation to eliminate stagnation), cycle chemistry, metallurgy, etc.



Extrapolate corrosion trends and perform cycling crack growth analysis to assure that wall thicknesses will exceed the minimum allowable values until the next inspection. Use EPRI’s BLESS code or equivalent for crack growth analysis.

If necessary, weld repair to restore wall thickness

Perform root cause analysis to determine if metal loss is due to corrosion, erosion, or flow-accelerated corrosion. Evaluate cycle chemistry. Revise if indicated. Change metallurgy if mixed metallurgy.

All analysis results and disposition decisions should be documented as part of a comprehensive boiler condition assessment program. For attemperator systems, results should be clearly cross-referenced where they are relevant to piping system and cycle chemistry evaluations.

After repairs are made or parts replaced, a time interval must be set for conducting the next condition assessment. Typically, the interval is set in light of plans for future maintenance outages and results of any crack growth analyses. The latter should be reassessed whenever there is a significant change in operating conditions, such as a major change in fuel or duty cycle.

For attemperator systems, one disposition goal should be to implement cost-effective system repairs and revisions that keep attemperator-related damage from being the determining factor in


8-13

planned or unplanned outages. For some systems, Level I evaluation may indicate that Level II and Level III evaluation should be bypassed in favor of preventive changes addressed in Section 8.6.

8.6 Preventive Actions for Attemperators and Adjacent Components

Table 8-4 lists actions that may be used to prevent or reduce continued damage accumulation in attemperator components or downstream of the attemperator. Where practical, mitigating or eliminating the root cause(s) of material degradation is the recommended approach to maximizing component life.

In many cases, damage to attemperator components or to piping, boiler, and turbine components downstream of the attemperator results from shortcomings in the design, operation, or maintenance of the attemperator system. Damage may also involve excessive use of attemperation, which itself may be a symptom of design, maintenance, or operation problems elsewhere in the boiler system.

Each candidate action must be evaluated in a systematic manner, with detailed attention to other boiler parameters. In practice, strategic and economic objectives may affect the extent to which damage-causing conditions can (or should) be feasibly reduced. For example, the cost-effectiveness of any option may depend on the specific attemperator design, the incremental cost of higher strength materials, or limits imposed on cycle chemistry elsewhere in the boiler system. However, the remedy may also involve inexpensive but non-obvious adjustments that provide benefits via improved heat rate, reduced chemical cost, or reduced damage in other boiler components.

Table 8-4 Preventive Actions for Attemperator Systems

Damage Mechanism or Precursor

Preventive Actions

High cycle fatigue of thermal shield

Replace with new design using higher strength materials, stiffer structure, and/or greater flow stability

Deformation of thermal shield Replace with new design using higher strength materials, stiffer structure, and/or greater flow stability

Improve steam piping or superheater drains to prevent water/steam hammer or slugging

Thermal fatigue cracking of spray nozzle assemblies

Reduce temperature differentials or cycling (see Thermal shock/fatigue section)

Replace with fatigue resistant materials

Erosion/corrosion of spray nozzle

Replace with resistant materials and/or geometry


8-14


Preventive Actions

Plugging of spray nozzle Change water source

Improve/install condensate polishing

Flush/chemically clean supply lines

Install strainer upstream of spray control valve

Thermal shock/fatigue at attemperator or in downstream components

Decrease temperature difference between attemperator water supply and steam piping

Change source of attemperator water supply

Provide for recirculation or continuous bleed to maintain temperature to attemperator control valve

Improve insulation of attemperator supply piping

Add or relocate thermocouples to provide low temperature alarm

Reduce spray impingement on thermal shield or pipe wall

Change spray nozzle geometry

Reduce or increase water supply pressure

Change venturi geometry

Extend thermal shield

Decrease rate and magnitude of temperature change downstream of attemperator

Reduce spray nozzle orifice size

Change to staged attemperation using multiple nozzles/control valves

Change spray nozzle and/or control valve to allow continuously variable water flow

Change control valve actuator and/or control logic

Add or relocate thermocouples to improve control response

Reduce use of attemperation

Change burner angle, damper settings, exhaust gas recirculation, sootblowing, turbine throttle pressure, etc., to change boiler temperature distribution

If attemperator is used to prevent relief valve lifting, evaluate and remedy cause of overpressure or increase relief settings (if temperature limits can be maintained)

Move or modify attemperator to ensure complete mixing/evaporation prior to bends and other sources of stress concentration


8-15


Preventive Actions

Flashing/cavitation across control valve

Reduce nozzle diameter to change location of pressure drop

Replace control valve with severe duty model with multistage pressure reduction

Change to lower temperature water source


Add acoustic sensor to detect cavitation

Eroded/corroded valve seat/plug

Upgrade materials


Increase valve seating force. Remedy actuator travel problems.

Install shutoff/isolation valve downstream of control valve to reduce use of control valve for shutoff; permit more frequent maintenance

Creep damage to installation nozzle

Evaluate and adjust piping supports to eliminate bending stresses on weldment

Protect from furnace gases

Evaluate cause of high exit temperature from primary SH

(Steam attemperator downstream of secondary SH or RH should be addressed with main steam and HRH piping)

Creep damage to spray nozzle

Evaluate cause of high exit temperature from primary SH

8.7 References for Attemperator Systems

EPRI has published numerous technical reports relevant to damage mechanisms, condition assessment, and failure prevention for attemperators and components influenced by their operation (see following list). An expanded listing of references and resources is contained in Appendix C.


Guidelines for Controlling Flow-Accelerated Corrosion in Fossil and Combined Cycle Plants. EPRI: 2005. Report 1008082.




8-16



Infrared Thermography Guide (Revision 3). EPRI: 2002. Report 1006534.







Severe Duty Valve Maintenance Guide. EPRI: 2005. Report 1011828.

Valve Application, Maintenance, and Repair Guide. EPRI: 1999. Report TR-105852-V1.

9-1

9 VALVES

By their function, valves experience the environmental conditions seen by piping and other components upstream and downstream of their location. The differences between the ends of a given valve may be extreme when the valve is closed or when throttling flow in applications such as:

• turbine stop valves

• turbine bypass valves

• superheater/reheater bypass valves

• attemperator control valves and shut-off valves (water or steam)

• drain valves

• pressure relief valves

• feedwater heater bypass valves

As with attemperator systems, inspection and maintenance of valves involves several aspects of a boiler condition assessment and component life management program:

• the integrity of the pressure boundary required for safety and availability

• the functional performance of the valve required for plant operation and/or safety

• the impact of valve operation on other plant components

This chapter adapts the condition assessment methodology for high-energy piping systems (see Chapter 6), and briefly reviews elements unique to valves, which are typically covered in a comprehensive valve maintenance and inventory program. Potential valve impacts on other boiler components are noted in the damage mechanism and prevention sections.

Section 9.1 tabulates typical damage mechanisms for valves in fossil power plant boiler systems and includes contributions of valve operation to damage in other components.

Section 9.2 presents a flow chart illustrating the application of EPRI’s three-level condition assessment approach to valves.

Section 9.3 tabulates NDE and sample testing techniques suitable for Level II and Level III life assessments for valves.

Section 9.4 tabulates data analysis and decision-making criteria used for run/repair/replace disposition of condition assessment findings for valves.

Valves

9-2

Section 9.5 tabulates candidate preventive actions that may be used to enhance the life of valves or reduce the contribution of valve operation to damage in other components.

Section 9.6 lists EPRI reference materials pertaining to condition assessment and life optimization of valves.

9.1 Damage Mechanisms Involving Valves

The two ends of a valve may be subject to very different temperature, pressure, and steam or water chemistry conditions. Valve bodies and internals may experience severe stresses and strains, resulting from high temperature gradients and/or pressure and mechanical forces.

The moving parts and seats of valves may experience functional damage from stress, friction, erosion, corrosion, and external forces. Damage to these components is likely to be caused by normal wear while design deficiencies may allow accelerated component degradation. Other boiler components may be affected if a valve is not operating properly.

Valve installation and design characteristics most likely to promote damage mechanisms include:

• sharp edges and other geometrical discontinuities that create stress concentrators, especially when exposed to thermal transients

• high pressure drop across valve seats and plugs during opening, closing, or throttling operation

• inadequate material specifications

• inadequate design for actual valve operator force/torque

• inadequate operator seating force that allows leakage

• inadequate clearances and/or imbalanced temperature and/or stress distribution resulting in binding

• rapid operation that creates rapid temperature change at the ID surface and extreme temperature gradient through the valve walls and in pipe and other components downstream of the valve

• rapid operation that causes water or steam hammer upstream or downstream of the valve

• high differential between attemperator temperature and steam temperature downstream of the valve, possibly increased by cooling in long supply lines, especially when stagnant due to cyclic or infrequent usage

• pressure/temperature conditions that allow flashing or cavitation downstream of attemperator spray control valves and drain valves

• relief valve settings too close to operating pressure or not adjusted for actual operating temperatures

• inadequate piping support; pipe loads transmitted through valve body

• inadequate restraint of relief reaction forces or water/steam hammer forces

Valves

9-3

The section on prevention at the end of this chapter lists operating and design practices that are less likely to lead to damage in valves and downstream components.

Table 9-1 lists forms of damage found in valves, including functional damage that may itself lead to damage downstream of the valve. Descriptions of damage mechanisms and their causes can be found in Appendix A.

Inspectors should check for the types of damage applicable for the temperature, pressure, and cycle chemistry of each specific valve location.

Table 9-1 Damage Mechanisms for Valves


Damage Mechanism

Valve bodies Internal/external creep cracking

External thermal fatigue cracking





Corrosion pitting

Erosion due to high velocity flow, cavitation or flashing (resulting from high pressure drop; leakage; inadequate design or materials, etc.)

Erosion due to solid particle entrainment


Overheating


Deformation due to differential heating/quenching


Attemperator spray nozzles integrated with bypass valves




Creep or other overheating damage

Valves

9-4


Damage Mechanism

Valve internals

Erosion of seat, plug, due to high velocity flow, cavitation or flashing (resulting from high pressure drop; leakage; inadequate design or materials, etc.)

Erosion of seat, plug, due to solid particle entrainment

Binding due to differential heating/quenching of body or internals

Over-torque of valve stem

Valve operator

Fatigue

Impact

Corrosion

Control failure

Welds to piping

Internal/external thermal, mechanical, and corrosion-assisted fatigue cracking



Internal/external creep cracking

Type IV creep

Functional damage to valves

Performance changes related to cracking, corrosion, or erosion of seats and plugs:

• Leakage

• Excess flow

• Vibration and noise

• Asymmetric flow leading to erosion or FAC of valve body

Performance changes related to blockage of valve by debris or deposits:

• Reduced flow

• Asymmetric flow leading to erosion or FAC of valve body

• Flashing or cavitation

Leakage due to interference with valve motion—due to design issues, warped body or internals, or other damage

Reduced opening due to interference with valve motion—due to design issues, warped body or internals, or other damage

Valve/piping/valve operator support system

Deformation of static supports due to overload



Valves

9-5


Damage Mechanism

Upstream/ downstream damage related to valve operation

Overheating in reheater/superheater tubing due to open bypass valve

Internal/external creep cracking downstream of leaking HP turbine bypass valve

Internal/external thermal fatigue and thermal shock due to:

• Corrosion pitting and corrosion-fatigue near leaking attemperator supply valve

• Erosion or flow-accelerated corrosion related to high velocity flow, cavitation, or flashing downstream of feedwater system and attemperator water supply valves

Pipe or support/restraint damage caused by water or steam hammer or asymmetric quenching from fast valve opening

Pipe or support/restraint damage related to relief valve reaction forces

Thermal fatigue, corrosion, corrosion-fatigue resulting from restricted drainage or backflow through drain valves

9.2 Condition Assessment Roadmap for Valves

As indicated, the condition assessment process for valves has two goals:

• determine risks, assess condition of valves, and determine disposition of damage findings for valves

• develop input for risk determination and root cause analysis for possible damage in upstream and downstream components

In general, the structural integrity of valve bodies will be evaluated in concert with condition assessment of piping or other boiler components on the high-pressure, high-temperature side of the valve. Disassembly, inspection, and overhaul of valve internals will be performed per the schedule of a distinct valve maintenance program, which may not be coordinated with the piping condition assessment. Field observations during piping condition assessment may dictate changes to this schedule.

Hot and cold walkdown inspections of valve installations and other piping system components are important parts of this evaluation. These inspections should confirm valve installation details or note deviations. Data review should include the valve specifications and aspects of boiler operation history, which may highlight problem areas related to valves in addition to general data applicable to the adjacent piping. When possible, direct observation of valve operation and system response should be observed. Physical response, noise, and temperatures should be noted.

The generic condition assessment roadmap (see Figure 9-1) illustrates step-by-step guidelines that can be used to assess the condition of valves and the impacts resulting from valve operation. The information presented in the chapter introduction and Section 9.1 provides background for

Valves

9-6

Level I evaluation of downstream components as well as for valve components. Techniques and criteria for NDE (inspection), data analysis, and decision-making are presented in Sections 9.3 and 9.4. Section 9.5 addresses preventive actions that should be considered to prevent future damage.

Valves

9-7


Step 4B -- Perform Visualand NDE Inspections

on Body Exterior and Welds

Dismantle Valve Inspect/Overhaul Internals

Leve

l I: P

re -O

utag

e

Step 2AConduct Hot

Walkdown and



Records

Scheduled for Valve Program

Overhaul?

Step 2C


Step 3

Step 4A




Now?

Step 5

Step 6

Step 7


Step 8

Flaws or Cavitation

Present?

ContinueRoutine

Inspection and


Step 9

NO


Cross-CheckFindings

NO

YES

Leve

l II:

Dur

ing

Out

age

Leve

l III:

Det

aile

d In

spec

tions


OBSERVEDANOMALIES


-


Step 3

YES

YES

Step 1





NO




Functional Tests

(Conduct Routine

Roadmap(s) for

Systems and Components

Upstream and Downstream from Valve




Step 4B -- Perform Visualand NDE Inspections

on Body Exterior and Welds

Dismantle Valve Inspect/Overhaul Internals

Leve

l I: P

re -O

utag

e

Step 2AConduct Hot

Walkdown and



Records

Scheduled for Valve Program

Overhaul?

Step 2C


Step 3

Step 4A




Now?

Step 5

Step 6

Step 7


Step 8

Flaws or Cavitation

Present?

ContinueRoutine

Inspection and


Step 9

NO


Cross-CheckFindings

NO

YES

Leve

l II:

Dur

ing

Out

age

Leve

l III:

Det

aile

d In

spec

tions


OBSERVEDANOMALIES


-


Step 3

YES

YES

Step 1





NO




Functional Tests

(Conduct Routine

Roadmap(s) for

Systems and Components

Upstream and Downstream from Valve



Figure 9-1 Condition Assessment Roadmap for Valves

Valves

9-8

9.3 NDE Options for Valve Components

Table 9-2 lists recommended NDE options for inspecting valve components, in accordance with the condition assessment process depicted in Figure 9-1. This table categorizes the options by the condition assessment level being pursued (i.e., I, II, or III).

In general, Level I and Level II evaluation will be conducted in concert with the higher pressure portion of adjoining piping. For valves, the Level I analysis, which will determine whether out-of-service inspections are warranted, should be supplemented with operational testing of the valves to detect functional damage. If acoustic emissions monitoring is used on the steam piping run, it may also provide indications relevant to Level I evaluation of valve installations.

For valves operating at lower temperatures, EPRI recommends starting with lower-cost magnetic or penetrant testing and only moving to the more advanced Level II and Level III methods if added data are needed to reduce remaining life uncertainty and can be economically justified. In general, Level III techniques are most relevant for cases where the goal of condition assessment is to support an operating plan with long outage intervals or extensive cycling.

Some valve installations use fully welded construction, and cannot be directly inspected without cutting welds. For these installations, radiography may be appropriate for Level II inspections while magnetic particle testing and penetrant testing of ID surfaces may be more appropriately categorized as Level III than as Level II.

For valves operating under conditions where creep is a concern, phased array ultrasonic testing and other NDE methods should be used to evaluate possible creep damage, including possible detection of microstructural creep damage (e.g., void formation and migration to grain boundaries) prior to crack initiation.

More detailed discussion of the application, methodology, and capability of these tools is provided in Appendix B and in EPRI Report 1009863, Guidelines for the Evaluation of Cold Reheat Piping.

More information relevant to for valves subject to creep can be found in the Appendix C references, including EPRI Report 1004329, Guidelines for the Evaluation of Seam-Welded High-Energy Piping, and EPRI Report 1000310, Assessment of NDE for Pre-Crack Creep Damage in Boiler Components.

Valves

9-9

Table 9-2 NDE Options for Valves





Valve bodies (exterior)

Visual

Thermal imaging

Thermocouples


Visual


Magnetic particle testing (MT) (1)

Penetrant testing (PT) (1)

Radiographic imaging (RT) (1)



Replication



Valve bodies (interior)

Thermal imaging

Thermocouples


Visual


MT (1)

PT (1)

RT (1)

Replication



Valve internals


Thermal imaging

Thermocouples



Visual (remove assembly)

MT (1)

PT (1)

RT (1)


Penetrant testing


Conventional UT






Dimensional and/or load measurement (hot position)

Visual inspection

Dimensional and/or load measurement (cold position)

Penetrant testing


Valves

9-10

NOTES:

1) Direct inspection techniques may be categorized as Level III rather than Level II if access is difficult. Radiographic imaging or another technique should be considered.

2) Material chemical analysis may be warranted if there is any uncertainty about base or weld metal composition.

9.4 Analysis and Disposition for Valves

Table 9-3 provides basic criteria and techniques for the “data/indication interpretation” and “disposition” steps in Figure 9-1. Much of the analysis basis will be developed during achievement of the Level I goal of determining damage risk and prioritizing inspection activities for the subject system. As noted, Level I condition assessment should also provide insight regarding the impact of valve operation on downstream components. This impact evaluation should be weighed in conjunction with other inputs to run/repair/replace decisions.

The valve location, function, cost, and repair procedure limitations are key inputs for deciding the level of analysis to be applied following Level II inspections. Extensive Level II and Level III inspection and analysis measures will be applied to large, expensive valves in high-temperature, high-pressure service, where creep is a concern. Smaller valves, and valves in locations where corrosion, thermal fatigue and corrosion-fatigue are the main concerns and extended post-weld heat treatment is not required, may simply be cut out and replaced. Such would be the case where discovery of wall thinning could involve localized conditions or could be related to a boiler-wide FAC problem. In other cases, cracks and localized corrosion pitting may be ground out and weld repaired without removal of the valve body.

All analysis results and disposition decisions should be documented as part of a comprehensive boiler condition assessment program. Results should be clearly cross-referenced where they are relevant to piping system and cycle chemistry evaluations.

After repairs are made or parts replaced, a time interval must be set for conducting the next condition assessment. Typically, the interval is set in light of plans for future maintenance outages and results of any crack growth analyses. The latter should be reassessed whenever there is a significant change in operating conditions, such as a major change in fuel or duty cycle.

Valves

9-11

Table 9-3 Analysis and Disposition for Valves



Valve body—internal surface corrosion

Must maintain minimum wall thickness per ASME (American Society of Mechanical Engineers) code

Extrapolate corrosion trends to assure that wall thicknesses will exceed the minimum allowable values until the next inspection

Perform root cause analysis to determine if metal loss is due to corrosion, erosion, or flow-accelerated corrosion

If FAC, evaluate water source and cycle chemistry. Change metallurgy if source or chemistry cannot be changed to limit FAC.

If oxygen corrosion, evaluate water source and cycle chemistry. Determine source of excess oxygen. Evaluate feasibility of change to operating modes (i.e., bleed or recirculation to eliminate stagnation), cycle chemistry, metallurgy, etc.

If erosion due to cavitation or leakage at shut-off, evaluate cause. Remedy valve operator problems or replace valve or valve internals with materials and/or design more suitable for operating conditions.

If practical, weld repair to restore wall thickness

Valve body and girth weld fatigue and corrosion-fatigue cracking

Use crack growth analysis to assure that cracks will not reach critical size before the next inspection. The typical maximum allowed size is 0.030–0.050 inch (0.075–0.125 cm).

Perform cycling crack growth analysis using EPRI’s BLESS code or equivalent to ensure weld integrity until next planned inspection. Finite element analysis and/or vendor guidance may be required for complex geometries.

If practical, grind out cracks and weld repair to restore mechanical integrity. Replace valve if necessary.

Valves

9-12



Girth welds (valve installations subject to creep)

Use crack growth analysis to assure that cracks will not reach critical size before the next inspection. The typical maximum allowed size is 0.030-0.050 inch (0.075-0.125 cm).


If necessary, weld repair to restore weld integrity until the valve can be replaced

Valve bodies—deformation

Serviceability Perform root cause and downstream impact analysis. Remedy cause if serious. Repair or replace if damage is severe. Consider material and/or design change.

Valve internals—erosion, corrosion, cracking

Serviceability Perform root cause and downstream impact analysis. Remedy cause if serious. Replace if damage is severe or trend risks failure prior to next scheduled outage. Consider material and/or design change.

9.5 Preventive Actions for Valves and Adjacent Components

Table 9-4 lists actions that may be used to prevent or reduce continued damage accumulation in valve components or other components affected by valve operation. In many cases, damage may result from shortcomings in the design, maintenance, or operation of the valve. Damage may also involve excessive use of the valve, which itself may be a symptom of design, maintenance, or operation problems elsewhere in the boiler system.

Each candidate action must be evaluated in a systematic manner, with detailed attention to other boiler parameters. In practice, strategic and economic objectives may affect the extent to which damage-causing conditions can (or should) be feasibly reduced.

Valves

9-13

Table 9-4 Preventive Actions for Valves

Damage Mechanism or Precursor Preventive Actions

Internal surface corrosion or erosion of valve body or internals

Evaluate and remedy shortcomings in cycle chemistry plan, procedures, instrumentation, monitoring, and/or operator training

Evaluate valve design and materials. Replace valve or upgrade internals with:

• Materials resistant to erosion and corrosion

• Severe-duty design suitable for conditions, such as valve plug with multi-stage pressure drop to reduce stress, flow velocity, and/or cavitation

Apply weld overlay, non-metallic coating, or insert to improve resistance to corrosion and erosion

Upgrade operator, install stronger spring, or correct settings to ensure adequate seating force

Install shutoff/isolation valve downstream of control valve to reduce use of control valve for shutoff; permit more frequent maintenance

Install inline strainers to keep debris from entering valves

Evaluate and remedy causes of excessive scale formation and shedding in reheater and superheater tubing

Valve body and girth weld cracking by mechanical overload, thermal/mechanical fatigue, thermal shock, and/or corrosion-fatigue

Valve body—deformation

Install low-flow bypass around valves to reduce thermal shock during load cycling, warm-up and cool-down

Modify control instrumentation and/or settings to reduce opening and closing speed

Evaluate and modify system operation to reduce thermal and pressure transients

Evaluate and modify operating procedures to reduce condensate pooling and flow events during load change, shutdown and startup

Evaluate design, condition, maintenance, and operation of drains. Remedy shortcomings.

Evaluate design, condition, maintenance, and operation of supports and restraints. Remedy shortcomings to reduce loads on valves and improve piping drainage.

Valves

9-14

Damage Mechanism or Precursor Preventive Actions

Performance changes related to blockage of valve by debris or deposits

Evaluate and remedy shortcomings in cycle chemistry plan, procedures, instrumentation, monitoring, and/or operator training that can lead to deposition

Evaluate and remedy shortcomings in valve design, condition, or operation that can lead to deposition during cavitation or flashing across the valve

Flush/chemically clean piping

Upstream/downstream damage related to valve operation

Review operating procedures and operator training. Remedy shortcomings to reduce likelihood of damage due to incorrect valve position.

Remedy cause(s) of leakage, flashing, or cavitation across valve

Evaluate pipe supports and restraints. Modify to reduce risk of damage caused by water or steam hammer or asymmetric quenching from fast valve opening.

Evaluate pipe supports and restraints. Modify to reduce risk of damage caused o relief valve reaction forces.

Review operating and maintenance procedures and operator training. Remedy shortcomings to reduce likelihood of damage due to restricted drainage or backflow through drain valves.

Flashing/cavitation across control valve


Change to lower temperature water source or higher downstream pressure


Add acoustic sensor to detect cavitation

9.6 References for Valves

EPRI has published numerous technical reports relevant to damage mechanisms, condition assessment, and failure prevention for attemperators and components influenced by their operation (see following list). An expanded listing of references and resources is contained in Appendix C.



Valves

9-15






Acoustic Emission Monitoring of High-Energy Steam Piping. EPRI: 1995. Report TR-105265-V1.









Severe Duty Valve Maintenance Guide. EPRI: 2005. Report 1011828


10-1

10 DEAERATORS, FEEDWATER HEATERS, AND BLOWDOWN VESSELS

Although operating at lower temperatures and/or pressures than other components addressed in this guideline, failures in deaerators, feedwater heaters, blowdown vessels, water piping, and lower pressure steam piping are capable of causing significant destruction and/or injury to personnel.

This chapter addresses components with the common phenomena of flowing water, condensing steam, or flashing water. Erosion may result from entrained solids, cavitation, or condensate droplet impingement. In recent years, flow-accelerated corrosion (FAC) has been better understood and more frequently recognized as a cause of damage. An example is EPRI’s 2005 publication of Guidelines for Controlling Flow-Accelerated Corrosion in Fossil and Combined Cycle Plants (Report 1008082).

Piping, vessels, and vessel internals are also subject to corrosion, fatigue, and corrosion-fatigue. Temperature stratification may cause deformation that compromises function or imposes stresses on vessel components or supports. Degradation is usually greatest in cycled units, which undergo many more startups, shutdowns, and rapid load changes. Thermal stresses result from high temperature differentials when cold feedwater is introduced to a hot deaerator or hot steam is introduced to a cold feedwater heater or blowdown drum.

The principles and procedures used in this chapter are similar to those used for cold reheat piping, economizer headers, and steam drums.

Section 10.1 tabulates typical damage mechanisms.

Section 10.2 provides a flow chart (Figure 10-1) to illustrate the general roadmap of EPRI’s three-level condition assessment approach.

Section 10.3 tabulates NDE and sample testing techniques suitable for Level II and Level III life assessments.

Section 10.4 tabulates data analysis and decision-making criteria used for run/repair/replace disposition of condition assessment findings.

Section 10.5 tabulates candidate preventive actions that may be used to enhance the life of deaerators, feedwater heaters, blowdown vessels, and low-temperature steam and water piping.

Deaerators, Feedwater Heaters, and Blowdown Vessels

10-2

Section 10.6 lists EPRI reference materials pertaining to condition assessment and life optimization of these components.

10.1 Damage Mechanisms for Low-Temperature Vessels and Piping

Among damage mechanisms affecting the boiler system components addressed in this chapter, flow-accelerated corrosion (FAC) has drawn the most focused attention, having been the cause of numerous piping and equipment failures in fossil power plants and other facilities.

FAC causes wall thinning (metal loss) of carbon steel piping, tubing, and vessels exposed to flowing water (single phase) or wet steam (two phase). FAC occurs when reducing chemistry breaks down the oxide layer that would otherwise prevent dissolution of the base metal exposed to continuous flow of water. It is most active at temperatures of about 300°F (150°C) and almost nonexistent where temperature is consistently maintained above 570°F (300°C). Prevention or mitigation generally involves changing to oxidizing chemistry or using metallurgy with greater than 1.25% chrome content. [See Guidelines for Controlling Flow-Accelerated Corrosion in Fossil and Combined Cycle Plants (EPRI Report 1008082) for a detailed explanation of FAC mechanisms and a programmatic approach to FAC prevention.]

Wall thinning may also result from solids entrainment, droplet impingement in wet steam flow, or cavitation in water flow. These erosive mechanisms have little relationship to water chemistry and metallurgy. Alternatively, wall thinning may be related to water chemistry conditions that are no longer present. Thus, before mitigation measures are selected, it must be clearly determined if wall thinning is caused by currently active FAC, another mechanism, or conditions that are no longer present.

The lower pressures and/or temperatures in these systems allow use of materials with thinner walls and therefore lower vulnerability to thermal fatigue relative to higher energy systems with thick walls. Nonetheless, this mechanism should not be ignored in comprehensive condition assessments, as is also the case for thermal shock cracking, thermal deformation, corrosion, and corrosion-assisted fatigue.

Component-specific discussions and tables of damage mechanisms and locations follow. Descriptions of damage mechanisms are provided in Appendix A.

Deaerators

Deaerators are prone to corrosion, flow-accelerated corrosion, fatigue, and corrosion-fatigue. Material failure that compromises function of vessel internals is more common than damage to the vessels themselves. Complex geometries may create stress concentrators. Flow-induced vibration of thin materials may cause mechanical fatigue.

Degradation is usually greatest in cycled units. Startups after brief shutdowns can produce the highest thermal stresses because the deaerator will still be fairly hot while the incoming feedwater will be cold until the feedwater heaters come into service. Where nozzle arrangements allow severe temperature stratification, bowing of the vessel can cause functional problems and


10-3

impose stresses in the vessel shell, internals, attached piping, and supports. Water chemistry is also harder to control in cycled units, because there is more opportunity for air infiltration and phenomena such as phosphate hideout.

Feedwater Heaters

Like deaerators, feedwater heaters are prone to corrosion, flow-accelerated corrosion, fatigue and corrosion-fatigue. Feedwater heater vessels and internals are generally exposed to greater temperature extremes than are deaerators. Thick tubesheets with small ligaments between boreholes are the most vulnerable area for thermal fatigue and corrosion-fatigue (in addition to welded or rolled tubing attachments). On the steamside, feedwater heater drains are one of the most frequent locations for corrosion-fatigue damage. Even with oxygenated water chemistry, reducing conditions may exist on the steamside if vent settings allow too much oxygen off-gassing.

Degradation is usually greatest in cycled units, where startup, shutdown, and rapid load changes may cause high or cycling steamside-to-waterside temperature differentials that produce high thermal stress.

Feedwater and Attemperator Supply Piping

FAC is the primary concern for feedwater and attemperator supply piping, which operate in the temperature range where this phenomenon is most active while also operating at high pressures where energy release upon failure can be substantial. Corrosion and fatigue cracking (due to thermally induced stresses) are the two most common types of damage found in economizer headers operating at similar conditions. Although the thinner walls and more uniform temperature distribution in feedwater and attemperator supply piping make it less susceptible to thermal stress, thermal fatigue and corrosion-fatigue should still be considered during condition assessment. As with other piping and boiler components, cycled units are more likely to experience damage.

Drain Piping, Vent Piping, and Blowdown Vessels

The intermittent operation of boiler drain and blowdown (blowoff) systems subjects them to rapid pressurization, thermal shock, vibration, two- or three-phase flow, and changing chemistry. Thermal, mechanical, and corrosion-fatigue mechanisms (as well as flow-accelerated corrosion and erosion) may result from impingement of condensate droplets or solid particles. Overstress of piping, vessels, and supports may result from water hammer, steam hammer, or inadequate supports and restraints.

Extraction Steam Piping

Each steam extraction system requires individual attention based on the temperature, pressure, and operating regime of its source and destination and also on the geometry of the piping and quality of its insulation. Different lines may be subject to conditions ranging from creep to two-


10-4

phase FAC. Damage mechanisms may result from rapid pressurization, thermal shock, vibration, and changing chemistry. Thermal, mechanical, and corrosion-fatigue mechanisms (as well as flow-accelerated corrosion and erosion) may result from impingement of condensate droplets or solid particles. Overstress of piping and supports may result from water hammer, steam hammer, or inadequate supports and restraints.

The following tables summarize the damage mechanisms relevant to the components covered in this chapter. Appendix A provides descriptions of damage mechanisms and their causes. Additional characterizations and experience data may be found in the EPRI technical reports listed in Section 10.6. Other relevant references are listed in Appendix C.

Table 10-1 Damage Mechanisms for Low-Temperature Vessels and Piping

Component / Location Damage Mechanism

Internal surfaces of vessels and piping

Corrosion

Thermal shock



Single-phase flow-accelerated corrosion (FAC)

Two phase FAC in:

• Deaerators

• Drain lines and blowdown vessels

• LP feedwater heater shell, especially at drain penetration


Corrosion

Thermal shock




Overstress and deformation from water/steam hammer, thermal imbalance, or design deficiency

Body spool pieces (deaerators)

Fatigue

Humping


10-5

Component / Location Damage Mechanism

Tube attachments (at feedwater heater tubesheets)

Corrosion




Leakage due to differential expansion and plastic deformation

Feedwater heater tubesheets, especially in ligament regions

Corrosion

Thermal/corrosion-fatigue cracking in (and between) bore holes, often initiating at corner on interior

Girth welds Corrosion

Thermal/corrosion-fatigue cracking, especially at weld preparation counterbores and unground weld toes

Seam welds Corrosion

Thermal/corrosion-fatigue, especially at unground weld toes on interior

Saddle welds for outlet nozzle(s), drain lines, hand hole fittings


Crevice corrosion

Inlet, outlet, and drain line penetrations and piping

Corrosion


Internal thermal/corrosion-fatigue cracking





Supports Overload

Corrosion

Impact damage

Functional failure due to maladjustment, design deficiency, debris, etc.

Support/Lifting Lug Welds Fatigue cracking

Crevice corrosion


10-6

10.2 Roadmap for Low-Temperature Vessels and Piping

The condition assessment roadmap, shown in Figure 10-1, provides a sound, stepwise approach to identifying damage mechanisms and estimating the remaining life of low-temperature vessels and piping. Tables 10-1, 10-2, 10-3, and 10-4 provide support information for the different elements of the condition assessment process, including identification of relevant damage mechanisms, run/repair/replace decision-making, and determination of the next inspection interval.


10-7




Leve

l I: P

re-O

utag

e

Step 2A




Records


Welds?

Step 2C


Step 3

Step 4BStep 4A




Now?

Step 5

Step 6

Step 7


New Instrumentation

Step 8



Inspection and


Step 9

NO

YES


SEAM-WELDED

SEAMLESS/

SMOOTH

SEAM

NO

YES

Leve

l II:

Dur

ing

Out

age

Leve

l III:

Det

aile

d In

spec

tions

Step 1


OBSERVEDANOMALIES





Leve

l I: P

re-O

utag

e

Step 2A




Records


Welds?

Step 2C


Step 3

Step 4BStep 4A




Now?

Step 5

Step 6

Step 7


New Instrumentation

Step 8



Inspection and


Step 9

NO

YES


SEAM-WELDED

SEAMLESS/

SMOOTH

SEAM

NO

YES

Leve

l II:

Dur

ing

Out

age

Leve

l III:

Det

aile

d In

spec

tions

Step 1


OBSERVEDANOMALIES


Figure 10-1 Condition Assessment Roadmap for Low-Temperature Vessels and Piping


10-8

10.3 NDE Options for Low-Temperature Vessels and Piping

Table 10-2 lists recommended NDE and sample testing methods for inspecting low-temperature vessel and piping walls and various internal structures and attachments, in accordance with the condition assessment process depicted in Figure 10-1. NDE options are categorized as a function of the condition assessment level being pursued (i.e., II or III; the Level I analysis determines whether an inspection is warranted).

As noted in Chapter 1, if the goal of condition assessment is to support an operating plan with long outage intervals, cycling, or other challenging conditions, or if known cracks are approaching a size of concern, then EPRI recommends using the Level III NDE methods. For routine inspections on units operating under design conditions, EPRI recommends starting with the lower-cost magnetic and penetrant testing and only moving to the more advanced Level II or Level III methods if additional data are needed on crack sizes and the cost of added inspections can be justified. If significant wall loss is detected, sample removal and evaluation is generally recommended to confirm that wall thickness loss is a result of FAC or another mechanism and that the mechanism is still active.

More information on these techniques can be found in Appendix B and in the references list in Section 10.6 and Appendix C.

Table 10-2 NDE Options for Low-Temperature Vessels and Piping

Component / Location NDE Detection Technique(Level II)


Vessel Shells and Piping

Conventional ultrasonic testing (UT) for thickness measurement and flaw detection

Hardness testing




• Visual

• Hardness

• Replication







10-9






Conventional UT


Replication (spanning the fusion line, the weld metal, the heat-affected zone, and the base metal)

Hardness testing





• Visual

• Hardness

• Oxide dating

• Replication






Internal Surfaces, structures, and attachments

Visual/video probe

MT

PT


Conventional UT

AC potential drop



RT

Piping attachments Visual/video probe

MT/PT

UT

AC potential drop




10-10



Tubesheets, especially in ligament regions

Video probe


Conventional UT








• Visual

• Hardness

• Replication




Piping and drain penetrations

Video probe

Conventional UT


RT




• Visual

• Hardness

• Replication





PT

MT

RT

Replication



PT

MT

Replication


10-11

10.4 Analysis and Disposition for Low-Temperature Vessels and Piping

Table 10-3 lists pressure vessel wall thickness code criteria and recommended action options (based on crack growth projection results) for the “data/indication interpretation” and “serviceability” steps in the Figure 10-1 roadmap.



If FAC is discovered, disposition should also include plans to evaluate possible FAC damage at other locations in the boiler and turbine systems that have exhibited single-phase or two-phase FAC in other plants. A comprehensive FAC control program should address feedwater chemistry and evaluate possible material changes to provide resistance to FAC or allow use of chemistry that does not promote FAC.

All analysis results and disposition decisions should be documented as part of a comprehensive boiler condition assessment program. Estimated RL values should be reassessed whenever there is a significant change in operating conditions, especially conversion to cycling duty.

Table 10-3 Analysis and Disposition for Low-Temperature Vessels and Piping


Vessel shells and piping, including internal surface corrosion and fatigue cracking

Must maintain minimum wall thickness per American Society of Mechanical Engineers (ASME) code


Perform cycling crack growth analysis and extrapolate corrosion trends to ensure minimum wall not exceeded before next inspection

If necessary, grind out cracks and corrosion pits and weld repair to restore wall thickness and/or reduce stress concentration



10-12



Must maintain adequate strength and geometry for functional performance

Analyze corrosion mechanisms and perform stress analysis and cycling crack growth analysis to ensure structural strength and function

If necessary, grind out cracks and small pits to eliminate stress concentrators. Replace or weld repair to improve or restore strength and function.

Determine and address root cause(s) of deformation and corrosion and fatigue mechanisms



Perform cycling crack growth analysis and extrapolate corrosion trends to ensure minimum wall not exceeded before next inspection



Tubesheets, especially in ligament regions




Consider welding rolled tubing connections that have loosened



10-13


Piping and drain penetrations





Supports/restraints Maintain weight distribution and flexibility to adjust to hot/cold dimensional changes


10.5 Preventive Actions for Low-Temperature Vessels and Piping

Where practical, mitigating or eliminating the root causes of material degradation is the recommended approach to maximizing the life of vessels and piping. Table 10-4 lists some actions that have been shown to prevent or reduce continued damage accumulation.

In practice, strategic and economic objectives may affect the extent to which damage-causing conditions can be feasibly reduced. For example, the cost-effectiveness of any of these options depends on the specific component design, materials, and operating conditions, the affect on other components of changes in cycle chemistry, and the opportunity cost of changing operating conditions (e.g., avoiding fast cooldowns).

Table 10-4 Preventive Actions for Low-Temperature Vessels and Piping


Corrosion

Corrosion-fatigue


Review cycle chemistry and optimize per EPRI guidelines to minimize corrosion and redeposition



Review design, function, and condition of cycle chemistry monitoring instrumentation. Remedy shortcomings. Verify high conductivity alarms settings and function.

Review design, function, and condition of condensate polishing system. Remedy shortcomings in equipment and/or


10-14


procedures. Consider adding condensate polishing if not already installed.

Determine and remedy cause of contamination by condensate polisher or demineralizer regeneration chemicals.

Consider changing feedwater treatment program, for example:

• Reduce flow-accelerated corrosion in all-ferrous systems by changing from AVT to AVT(O) or oxygenated treatment


Consider changing metallurgy for better performance with existing cycle chemistry. Even with AVT(O) or oxygenated treatment, wet steam flow may not provide enough oxygen at the metal surface to maintain a protective oxide film. Consider use of 0.5% chrome (minimum) base metal or 1.25% chrome overlay in drain piping, blowdown vessels, extraction steam piping, and feedwater heater shells to prevent two-phase FAC.

Consider changing metallurgy to allow use of a different feedwater treatment program. Flow-accelerated corrosion can be reduced by replacing copper alloys in condenser and feedwater tubing with all-ferrous or titanium tubing, allowing change from AVT to AVT(O) or oxygenated treatment.



Review procedures and monitoring capability prior to shutdown/layup. Remedy shortcomings. Monitor water quality before/during shutdown. Monitor moisture and other air quality parameters during shutdown/layup. Ensure plentiful supply of nitrogen or clean, dry air.

Review and monitor oxygen scavenger injection quantity and locations

Fatigue


Thermal deformation/humping

Mechanical deformation

Review/improve startup and shutdown procedures to minimize rate and magnitude of temperature, pressure, and stress transients. Evaluate and remedy shortcomings in boiler system operating and control systems/procedures and operator training.

Avoid forced cooling of the boiler

Consider using preheated feedwater for startups

Consider installing a furnace off-load circulating pump to equalize temperature in feedwater system, economizer headers, and tubing during shutdown.


10-15


Modify vessel internals to reduce temperature stratification and prevent contact of cold makeup water with vessel walls, especially in area of shell penetrations and attachment welds

Evaluate/modify valve sequencing and valve operator speed (open/close time) to reduce risk of water or steam hammer

Evaluate and remedy shortcomings in design, setting, function, and maintenance of supports and restraints

Redesign piping attachments to improve flexibility

Evaluate insulation and upgrade to reduce cooling of water and steam lines, especially those subject to intermittent use

10.6 References for Low-Temperature Vessels and Piping

EPRI has published numerous technical reports relevant to damage mechanisms, condition assessment, and failure prevention for low-temperature vessels and piping (see following list). An expanded listing of references and resources is contained in Appendix C.


Guidelines on Controlling Flow-Accelerated Corrosion in Fossil and Combined Cycle Plants. EPRI: 2005. Report 1008082.


Influence of Water Chemistry on Copper Alloy Corrosion in High Purity Feedwater. EPRI: 2003. Report 1007162.




Condensate Polishing Training Manual. EPRI: 2004. Report 1004933.



10-16







Repairs of Deaerators. EPRI: 2004. Report 1008069.


A-1

A DAMAGE MECHANISM ABSTRACTS

Corrosion (General)

Corrosion damage falls into two general categories: chemical and electrochemical. Direct chemical corrosion results from highly corrosive environments, such as those where metal surfaces come into contact with strong acids or alkalis, high temperatures, or both, as in utility boilers. The second category, electrochemical corrosion, involves an oxidation-reduction (redox) reaction, in which one metal, or area of a metal surface, functions as an anode, and another functions as a cathode. Through this process, the metal dissolves in an anodic reaction, producing positively charged metal ions that are plated out in the cathodic reaction.

The location, mechanism, and rate of any specific incidence of waterside or steamside corrosion may be influenced by steam quality, temperature, base metallurgy and flow velocity, and parts per million and parts per billion variations in the concentration of numerous chemical constituents. Low levels of oxygen in cycle water help maintain a protective oxide film that prevents corrosion by simple dissolution methods. If other constituents are different, the same metallurgy may experience extensive pitting with high dissolved oxygen level in water. Use of oxygen scavengers to reduce high dissolved oxygen and prevent pitting corrosion may inadvertently weaken or dissolve the thin oxide film that provides significant protection against corrosion by simple dissolution.

Similarly, fireside corrosion, including waterwall wastage phenomena, may result from complex combinations of combustion chemistry, heat flux, gas flow patterns, tube wall temperature, and ash properties.

Component failure may be a direct or indirect result of corrosion. For example:

• Material loss may reduce metal thickness below the minimum required to withstand prevailing pressure and temperature conditions

• Corrosion pitting may create a stress concentration that serves as the initiation point for fatigue cracking

• Corrosion-assisted fatigue occurs when fatigue cracking exposes a fresh surface to the corrosion mechanism, which, in turn, further weakens the metal and promotes further cracking

• Corrosion products may redeposit elsewhere in the system, leading to under-deposit corrosion or overheating

Damage Mechanism Abstracts

A-2

Gas-Side Mechanisms

Fireside Corrosion

Cause: Corrosion of external superheater or reheater tubes is most often caused by complex alkali compounds within coal and oil fly ash with low melting points. In the case of corrosive coal ash, an alkali-iron-trisulfate layer covering an iron sulfide/iron oxide scale is commonly observed in the deposit. For oil fly ash corrosion, sodium vanadates or vanadylvanadates are generally found. The leading theory regarding this corrosion mechanism is that the molten alkali compounds draw away the protective oxide surface layer and accelerate oxidation. This corrosion mechanism occurs after the tubing has reached a sufficiently high temperature (either due to high design service temperature or due to buildup of a steamside oxide scale) to melt the corrosive alkali compounds. Melting points between approximately 1030°F (550°C) to 1150°F (620°C) have been measured. It is, thus, expected that regions of tubing operating above 1000°F (540°C) are prone to this type of attack. The liquid ash will readily attack both ferritic and austenitic tubing.

Fireside corrosion of superheater and reheater tubing may also involve a sulfidation mechanism when reducing conditions exist, especially on austenitic stainless steel tubing. Discrete iron sulfides have been found in the grain boundaries on the corroded region of the tubes, which also exhibited surface carburization.

Molten salt wastage rates are a strong function of the inherent corrosivity of the fuel. For coals commonly used in the United States, sodium, potassium, sulfur, iron, aluminum, and chloride have the most influence on the high-temperature ash corrosivity. Vanadium, sodium, and sulfur are the elements most often associated with oil ash corrosion. The position of the tube in a bank, the circumferential position around the tube wall, and the proximity of the tubes to sootblowers also influence corrosion rates.

Response: The presence of a liquid ash, which provides a measure of ash corrosivity, can be confirmed by measuring the melting temperatures of the fireside scale/ash constituents. Long-term solutions to fireside corrosion problems include fuel blending or use of additives; lowering the tube crown temperatures of the hottest tubes by burner tuning or by steam flow redistribution; and replacing tubes using more corrosion-resistant materials or thicker walls. If corrosion is occurring under reducing/carburizing conditions, maintaining sufficient and proper delivery of secondary and tertiary air will assure complete combustion and will minimize the carbon monoxide and hydrogen sulfide levels relative to the oxygen concentration. Excessive oxygen concentration must also be avoided, however, as this will increase the likelihood and rate of liquid ash corrosion.

For fuel oil, lowering flue gas oxygen levels to about 0.25% will produce a drop in liquid ash corrosion rates, especially when the fuel contains high vanadium and sodium content. For oil with a high vanadium-to-sodium ratio, low excess air operation is thought to produce less oxidized compounds of vanadium in the ash deposits (i.e., less of the fully oxidized V2O5). As a result, the formation of low melting point compounds from a combination of V2O5 and sodium oxide is less likely. Additives employing magnesium or calcium oxide, which raise the melting point of the ash constituents, are also used to control the corrosiveness of fuel oils.


A-3

Waterwall Wastage with Low-NOX Combustion

Cause: A waterwall wastage phenomena was recognized not long after the introduction of combustion with low excess air for the purpose of decreasing formation and emission of oxides of nitrogen (NOX). The mechanism was linked to reducing combustion chemistry that removes and prevents reformation of the thin layer of iron oxide that protects carbon steel from a variety of corrosion phenomena.

More recent research has determined that this form of waterwall wastage is most prevalent in boilers that cycle between full load conditions, with low excess air and reducing combustion chemistry, and part load conditions with more excess air and oxidizing chemistry. The base metal oxidizes during part load conditions. The protective oxide is then stripped away during full load conditions, exposing more base metal to oxidation and corrosion mechanisms.

Response: Modification of air-fuel ratio, burner angles, overfire air, and other combustion parameters may reduce or prevent this type of damage in some cases. Use of corrosion resistant alloys—typically containing >20% chromium for iron-based alloys—is an alternative approach where combustion modification are insufficient to prevent high corrosion rates.

Weld overlays with high chrome materials have been successful at restoring wall thickness and preventing waterwall wastage and other corrosion mechanisms. Some applications have experienced cracking, which can be prevented with careful attention to preparation and welding techniques. It is important to have a good match between the thermal expansion coefficient of the overlay metal and base metal. Minimum effective heat input should be used to prevent metallurgical changes on the inner surface of the tubing. Techniques under development using spray metal deposition or non-metallic coatings are showing some promise.

Flow-Accelerated Corrosion (FAC)

Flow-accelerated corrosion (formerly called erosion-corrosion) causes wall thinning (metal loss) of carbon steel piping, tubing, and vessels exposed to flowing water (single-phase) or wet steam (two-phase). If undetected, the degraded component can suddenly rupture, releasing high-temperature steam and water.

Single-Phase FAC

Cause: Single-phase FAC occurs under specific conditions of metallurgy, water chemistry, temperature, and flow. The chemistry and temperature conditions maximize the solubility of the magnetite form of iron oxide (Fe3O4), which provides protection against corrosion under other conditions. Turbulent water flow increases the rate of dissolution of the magnetite and the base metal, which is normally protected by a thin magnetite film.

Typical conditions for single-phase FAC are:

• carbon steel component metallurgy

• temperature below 570°F (300°C) with peak activity at about 300°F (150°C)


A-4

• highly reducing chemistry (below -300mV redox or ORP potential), typically with both ammonia and a reducing agent [Note: Appropriate cycle chemistry will depend on metallurgy in feedwater system. Systems containing copper alloys in feedwater heater tubing will require reducing chemistry. Systems containing all ferrous alloys require oxidizing chemistry.]

• very low oxygen (<1 ppb)

• turbulent flow due to a disruption such as an elbow or the entrance to an economizer tube stub

Response: Single-phase FAC may be addressed by:

• monitoring key sites subject to moderate FAC and replacing thinned pipe or tubing before it becomes a safety issue

• changing feedwater chemistry from AVT to AVT(O) (i.e., adding oxygen and removing reducing agents—oxygen scavengers—from all volatile treatment programs)

• changing from AVT to oxygenated treatment

• replacing copper alloy tubing in condensers and feedwater heaters to allow use of AVT (O) or oxygenated treatment

• changing metallurgy of specifically vulnerable vessels, pipe, or tubing [Typically this requires base metal of 1.25% or higher chrome or weld overlay of 1.25% or higher chrome. Other alloy constituents may replace some of the chrome.]

Two-Phase FAC

Cause: Two-phase FAC occurs under specific conditions of steam chemistry, temperature, and flow. The chemistry and temperature conditions maximize the solubility of the magnetite form of iron oxide (Fe3O4), which provides protection against corrosion under other conditions. High velocity turbulent flow increases the rate of dissolution of the magnetite and the base metal, which is normally protected by a thin magnetite film.

Typical conditions for FAC are:

• high velocity, turbulent flow of wet steam that forms a liquid layer on a carbon steel surface

• temperature below 570°F (300°C) with peak activity at about 300°F (150°C)

• oxygen and ammonia partition to the vapor phase, leaving very low oxygen content and lower pH at the water/metal interface

Response: Two-phase FAC does not respond to chemistry changes to increase ORP. Available response includes:

• monitoring key sites subject to moderate FAC and replacing thinned pipe or tubing and repairing damaged portions of vessels before it becomes a safety issue


A-5

• changing metallurgy of specifically vulnerable vessels, pipe, or tubing [Typically this requires base metal of 1.25% or higher chrome or weld overlay of 1.25% or higher chrome. Other alloy constituents may replace some of the chrome.]

Corrosion (Under-deposit and Pitting)

Acid Phosphate Corrosion (Phosphate Hideout and Return)

Cause: Phosphate corrosion is caused by a combination of high boiler pressure, high steamside metal temperature, and high local concentrations of monosodium or disodium phosphate. It has only been observed in boilers where monosodium and disodium phosphate was added. It has not been observed in boilers that use only trisodium phosphate.

Phosphate corrosion is also associated with phosphate hideout and return, where phosphate concentrations fluctuate with pressure. During boiler shutdown or pressure reduction, the phosphate that “hid” in the boiler during pressure increase is returned to the system. The return of phosphate can cause a pH depression in the boiler water, which can lead deplete the tube surface protective layer and, ultimately, the base metal.

In high-pressure boilers (above 2600 psig) and at high heat fluxes, sodium phosphate can become concentrated within tube surface deposits, leading to rapid corrosion of the underlying metal. This corrosive condition involves a phosphate concentrating mechanism, such as local steam blanketing or boiling within porous deposit, and buildup of a thermal barrier (from local steam blanketing or from the buildup of an internal deposit).

Response: Corrective actions center on improving control of boiler water chemistry by switching to low-level or equilibrium phosphate control using only trisodium phosphate; minimizing the ingress of feedwater corrosion products into the boiler; and removing corrosion product deposits by periodic chemical cleaning. Boiler operating conditions that result in local hot spots, such as excessive overfiring or underfiring, misaligned burners, gas channeling, and inadequate circulation rates, should also be modified. Eliminating welds that use backing rings or other internal surface contour irregularities can help reduce internal deposits that can cause a thermal barrier. In severe cases, a switch to all-volatile treatment and the addition of condensate polishers may be required. In cases where inadequate circulation produces local steam blanketing, design modifications may even be necessary.

Caustic Gouging

Cause: Caustic gouging is caused by localized concentration of sodium hydroxide (NaOH), creating high pH levels that solubilize the protective magnetite layer of the tubing steel and lead to rapid dissolution of the underlying tube metal. Susceptible boiler locations include high heat flux regions, horizontal or inclined tubing, and sections that have flow disruptions such as weld backing rings, protrusions, and crevices. In the case of high heat flux areas, feedwater corrosion products can deposit and accumulate and act as concentrators of NaOH through a process known as wick boiling, in which feedwater is drawn to the tube surface underneath the porous deposit where boiling is enhanced, leaving behind any dissolved salts. In inclined or horizontal tubes,


A-6

steam tends to accumulate on the upper surface of the tube, creating a steam blanket in which soluble salts, such as NaOH, can become concentrated. The protective oxide is then attacked by the high pH conditions, and the underlying metal is rapidly corroded, usually in a localized region on the crown of the tube where temperatures are highest. The locally thinned tube often corrodes through or succumbs to ductile rupture. Typical reactions of caustic with iron oxide and iron are:

Fe3O4 + 4NaOH ⇒ 2NaFeO2 + Na2FeO2 + 2H2O

2NaOH + Fe ⇒ Na2FeO2 + H2

Response: Preventive actions center on improving boiler water chemistry, minimizing the ingress of feedwater corrosion products and condenser leakage products, and removing corrosion product deposits through periodic chemical cleaning. In addition, boiler operating conditions that lead to local hot spots, such as excessive overfiring or underfiring, misaligned burners, and gas channeling, should be modified.

Chemical Cleaning Damage

Cause: Acid cleaning, typically with hydrochloric acid, is routinely performed during outages to remove built-up deposits on boiler tube steamside surfaces. Steel corrodes in low pH environments, and for this reason inhibitors are usually added along with the acid to reduce corrosion of the tube metal. If not carefully controlled, however, the cleaning process can lead to extensive tube corrosion. For example, temperature excursions can cause the inhibitor to break down and become ineffective. In addition, use of inappropriate cleaning agents, excessively high acid concentration or long cleaning times, or failure to completely neutralize, drain, and rinse after cleaning can also result in tube corrosion.

Response: The entire cleaning operation, including temperature, cleaning agent concentration, and the iron and copper content of the cleaning solution and rinse water, during and after the operation, should be carefully monitored. A visual inspection of tube and drum internals should be performed following the cleaning.

Hydrogen Damage

Cause: Hydrogen damage (sometimes called hydrogen blistering) results from low pH (acidic) conditions, either in localized areas or in overall boiler water chemistry, that cause corrosion and subsequent diffusion of hydrogen into the steel tubing. Under low pH conditions, the protective surface oxide of the tubing steel breaks down and exposes the base metal to attack. This corrosion reaction produces hydrogen at the metal surface, which diffuses into the steel and reacts with iron carbide (Fe3C) to form methane gas. This reaction also produces weakened regions due to local decarburization of the steel. The large methane molecules, which cannot easily diffuse through the metal lattice, become trapped at grain boundaries. As the gas accumulates, the pressure builds, and networks of internal fissures form, which link up over time to cause through-wall fractures.


A-7

An overall lowering of the bulk boiler pH may occur in rare circumstances, such as ingress of seawater or accidental acid contamination. Usually, however, low pH conditions only occur locally, such as at high heat flux regions, beneath deposits, or in crevices, in slanted or horizontal tubes, or at flow disruptions such as welds. Even slightly abnormal water conditions can result in the formation of local low pH conditions due to concentrating mechanisms, such as wick boiling, steam blanketing, and evaporation. The presence of dissolved salts, such as calcium chloride, sodium chloride, and magnesium chloride, in the bulk water can also cause acid corrosion, especially under deposits or in crevices. Salts can decompose to release chloride ions, which can then combine with hydrogen ions to form hydrochloric acid. The acid then disrupts and removes the protective oxide layer, exposing the underlying tube metal to attack. Therefore, hydrogen damage can be particularly severe under conditions of rapid on-load acid chloride corrosion.

Response: Corrective actions include maintaining boiler water chemistry at the proper values; promptly reacting to contaminant ingress and removing the boiler from service if the pH drops below 7; and eliminating hot spots or flow disrupters where excessive deposition can take place. Chemical cleaning can remove internal deposits and stop further generation of hydrogen on the tube surface. It should be considered when the boiler water pH has been below 7 for more than one hour due to the ingress of saline condenser cooling water or acidic chemicals into the boiler, or from breakdown of boiler water conditioning elements. If significant wall thinning has occurred, the damaged tubing sections must be replaced to prevent recurring in-service failures. The use of low -alloy steel tubes will reduce the likelihood of hydrogen damage. Pad weld repairs, which can lead to deposit buildup, should be avoided.

Pitting

Cause: Pitting occurs when cracks develop at small imperfections in a tube’s protective oxide layer, exposing the underlying metal to localized corrosion. The corrosion can result from either acidic conditions, or high dissolved oxygen levels at the tube surface, which cause small anodic regions to form on the tube surface, with the adjacent metal acting as the cathode.

Pitting commonly results from two sources, both associated with unit shutdown. First, poor shutdown procedures can leave stagnant oxygenated water in some tubes. For example, forced cooling and/or improper draining and venting procedures can produce excess moisture throughout the boiler. Economizer tubes and the bottom of pendant loops of superheaters and reheaters are common locations where stagnant conditions can occur. The second source of pitting occurs primarily in reheater tubes because of deposited Na2SO4 compounds. Reheater circuits are particularly susceptible locations because the temperature and pressure conditions increase the solubility of Na2SO4 compounds, which acidify during shutdown periods.

Response: Corrective actions focus on protecting tubing during non-operating periods. Proper draining and venting after shutdown will reduce the amount of moisture that condenses in the tubing as the boiler cools. Nitrogen “blanketing” of the steam-cooled circuits can provide protection during outages of less than four days, whereas long-term protection involves filling the superheater and reheater tubing with condensate that contains hydrazine and ammonia.


A-8

Fatigue

Corrosion-fatigue

Cause: Corrosion-fatigue is caused by the combined action of thermally induced stresses from load cycling and corrosive boiler water conditions. In such an environment, cracks that would normally form over long periods of time at high-stress locations, such as tube attachments or restraints, will initiate and propagate at a much faster rate. Steamside cracks that are formed from oxygen or acid cleaning pits, or along cracks in the protective iron oxide coating as a result of cyclic stress, can act as stress concentrators. These cracks may also become anodic and prone to localized corrosion. If these conditions persist, shallow pits or oxide cracks can extend across the tube wall, eventually leading to pinhole leaks or complete window-type blowout failures.

Response: Corrective actions include redesigning tube attachments to eliminate or reduce differences in thermal expansion between joining components; timely chemical cleaning to remove tube deposits before pitting occurs—while avoiding overly aggressive cleaning; eliminating impurity ingress (e.g., condenser leaks); and restoring water chemistry stability, with a focus on limiting the dissolved oxygen level to <5 ppbw and maintaining pH within an acceptable range (pH at the economizer inlet of 8.6–9.2 for mixed metallurgy, and 9.0–9.6 for ferrous metallurgy). It may also be necessary to restrict cyclic operation if corrosion-fatigue failures are frequent. Prevention entails locating and replacing tubes that contain cracks, and optimizing boiler shutdown/layup procedures to eliminate the dissolved oxygen or acidic conditions during shutdown that can lead to preferential pitting corrosion at locations with high residual or service stress.

Thermal Fatigue

Cause: Thermal fatigue is caused by excessive temperature differentials between inside and outside component walls, the cumulative effective of which is the initiation and propagation of cracks. If no corrective active is taken, failure can occur when component materials reach specified fatigue limits. Thick-walled components, such as headers and piping, are especially susceptible to thermal fatigue-induced cracking. In headers, ligament cracking is most common. Thermal fatigue is often attributable to rapid ramp rates associated with cycling operation in addition to poor design and manufacturing detail and/or poor temperature control.

Response: The risk of failure due to thermal fatigue can be mitigated through inspection programs (including pre-crack fatigue monitoring) focused on at-risk headers and other components. Preventive measures include improving temperature control by implementing advanced control systems to minimize temperature swings during transient conditions, modifying operating procedures to avoid temperature swings, and, in extreme cases, replacing selected headers with new components designed using high-strength, high-temperature alloys, such as P91.


A-9

Fireside Erosion and Wear

Coal Particle Erosion

Cause: Erosion from unburned coal particles is unique to cyclone boilers. The introduction of combustion air in the burners causes coal particles to be directed tangent to boiler tube surfaces at high velocity. Over time the wear-resistant liners and refractory coatings inside the cyclone burner wear out, allowing erosion of tube surfaces. A thin-wall fracture develops when the tube can no longer support the operating stress.

Response: After verifying by examination that the wear-resistant liners and refractory coatings have been degraded, corrective action involves surveillance and replacement of the liners and coatings. Observing the flow patterns in the burner from the introduction of secondary and tertiary air may reveal where significant erosion will occur. Adjusting inlet dampers may be necessary to change burner flow patterns to reduce the rate of liner and coating erosion.

Fly Ash Erosion

Cause: Fly ash particles carried along in exhaust gases erode tubes, supports, and other gas path structures in pulverized-coal boilers. In pulverized-coal boilers, fly ash particles in flue gas can impact boiler tube surfaces at high velocity, especially in the convective pass. The impacts increase the fireside wastage rate, eventually leading to stress-rupture. Depending on the wastage rate, tubes can fail in one of two modes: a fast wastage rate leads to rapid wall loss and thin-wall failure, whereas a slower rate of wall loss leads to thick-wall failures due to creep damage from the combined effect of increased temperature and a thinner tube wall. Tube wastage due to fly ash erosion occurs via two mechanisms: fly ash directly impacting the metal surface and removing metal by abrasive wear, or removing the fireside scale during impact, which exposes the base metal and accelerates oxidation. The contribution from these mechanisms changes as the metal temperature increases, with the scale removal mechanism becoming dominant at temperatures above 800°F (430°C). Fireside erosion is most common in units burning high-ash-content coals that contain a high fraction of abrasive ash material, such as quartz (SiO2).

In the case of abrasive wear, there are three basic modes for metal removal, which are linked to the angle of impingement. At low impingement angles, metal is cut or abraded from the surface. At angles near 45º, metal is deformed with a plowing-type action and particles often imbed into the surface. At angles near perpendicular, the metal is extruded from the impact site and may be removed by a subsequent adjacent particle impact. The maximum erosion generally takes place at impingement angles between 15º and 35º.

Although there is a strong link between erosion rates and particle velocity, the level at which flue gas velocity produces significant fly ash erosion (i.e., failure in 10,000 to 50,000 hours) is roughly two times greater than average flue gas design velocities. Thus, most erosion damage is due to localized conditions of increased gas flow, such as at narrow, poorly designed passages, blockages, and in the vicinity of sootblowers. Specific locations most prone to this form of damage include:


A-10

• areas that have gaps between the tube bank and the duct walls

• bends and other locations where the flue gas is made to turn sharply, but the inertia of the fly ash particles causes them to impact the duct walls

• gas bypass channels where the velocity of the flue gas can be much higher than that of the main flow

• protrusions or misaligned rows of tubing

• regions adjacent to tubing where large accumulations of fly ash act as a channel that increases velocity

In the early stages of fly ash erosion, smoothly polished areas of the tubing surface mark damage. In advanced stages, flat spots and defined edges indicate where the metal has been eroded away.

Response: Approaches to reducing fly ash erosion generally focus on either reducing the quantity and velocity of ash striking the tube, or increasing the wear resistance of the tube. Changing boiler operation conditions, such as lowering excess air levels, balancing air flows, installing distribution and diffusion screens, and modifying sootblowers are good approaches to reducing ash velocity. Sootblowing can eliminate the ash accumulations that can increase local gas flow rates, but excessive sootblowing itself can cause erosion. Coal cleaning, or switching to coals with lower ash content, reduces ash loading and consequently erosion rates. The only way to significantly increase erosion resistance is to use coatings, because differences in the erosion resistance of commercial tubing alloys are too small to provide significant increases in life.

Rubbing/Fretting

Cause: Periodic sliding or impact of tubes against adjacent tubing may cause removal of the protective iron oxide on the fireside surface of the tube that, in turn, accelerates the oxidation rate. In more extreme cases, repeated tube contact will result in complete removal of the oxide followed by adhesive or abrasive wear of the underlying tube material. The end result is accelerated fireside wall thinning. Tube rubbing may be caused by inadequate or nonfunctioning tube supports that allow tubes to impact or slide against adjacent tubes. Tube misalignment can also lead to tube rubbing.

Response: Following a visual examination to identify the extent and cause of damage, corrective actions include realigning tubing, repairing malfunctioning tube supports, and modifying supports to eliminate tube-to-tube contact.

Sootblower Erosion

Cause: Excessive blowing, mechanical malfunctions that concentrate the blowing medium, or improper location or operation with excessive moisture in the blowing medium can lead to wastage flats or gouging of tubing surfaces. In addition, operating a sootblower with condensed water in the media can result in significant erosion. The damage mechanism is often referred to


A-11

as sootblower-enhanced ash erosion because the ash supplies the erosive species and the sootblower action simply increases the approach velocity of the ash impinging the tubing.

Sootblower erosion is associated with locations that receive indirect impingement from wall blowers near the furnace corners; those in the direct path of retractable blowers and in the hotter outlet regions of steam-cooled sections; those that are blown with a missing or damaged nozzle; and the first tubes adjacent to the wall entrance of retractable blowers.

Response: As always, identifying the exact nature of the problem is the first step. A visual inspection of the sootblower device can identify any malfunction or misalignment, while malfunction of the system can be detected by measuring blowing pressure, testing moisture traps, or checking travel and sequence times. Long-term corrective actions include setting optimized sootblower frequency schedules and improving maintenance of sootblowers and system components. Temporary measures, such as shielding, spray coatings, or pad welding can serve as emergency repairs, but are not recommended as long-term fixes.

Microstructural Damage

Graphitization

Cause: Graphitization is a diffusion process whereby graphite nodules form as carbon atoms migrate from supersaturated ferrite. Although the microstructure of a typical boiler tube is metastable, it will remain essentially unchanged below about 800°F (430°C). If a tube sustains long-term exposure with metal temperatures between 800°F (430°C) and 1330°F (720°C), the pearlitic microstructure will decompose by spheroidization of the pearlitic lamellae, and by graphitization if the steel contains less than about 0.6% chromium. Graphitization occurs preferentially between the two competing mechanisms at temperatures below approximately 1025°F (550°C). Graphitization is most damaging when the graphite particles form continuous planes of weakness; this phenomenon has been observed in the grain refined region of weld heat-affected zones (GRHAZ).

Response: The extent and cause of the graphitization can be determined by metallographic examination, mechanical tests, chemical composition analysis, and temperature exposure measurements. Steels with more than about 0.6% chromium are immune. Steels containing less than 0.6% chromium (e.g., SA-209-T2) may need to be replaced if used under conditions where long-term exposure promotes graphite formation. In susceptible steels, aluminum contents above 0.025% increase the tendency for graphitization. Weld joints can be stabilized to resist chain-like graphitization by a post-weld heat treatment between 1325°F (720°C) and 1350°F (730°C) for a minimum of four hours.


A-12

Fabrication Flaws

Material Flaws

Cause: Material flaws, dating from the time of fabrication, can include laminations, inclusions, seams, or generally inferior properties that can act as crack initiation sites or otherwise make the material inadequate for an intended application. Such flaws are generally caused by poor quality control during tube manufacture, either in the steel-making process or the fabrication of the tubes and tube panels. Due to interactions with stress-driven failure mechanisms, material defects are more likely to cause failures in high-temperature locations. Therefore, it is also important to maintain proper quality control measures for material storage, labeling, and handling to avoid mistakenly installing inadequate materials in the wrong locations during boiler erection or repair.

Response: Material flaws can be identified through metallurgical analysis, material properties testing, and review of the procurement records of the tube. A tube containing a material flaw is very likely to fail before the flaw can be found and the tube can be replaced. Because detection of the defective tube is difficult once it has been installed, preventive actions are necessary to discover defects before installation. Quality control measures provide for inspection and documentation of the manufacturing, shipping, storage, and installation activities.

Welding Flaws

Cause: Welding flaws can include porosity, slag inclusions, excess penetration, lack of fusion, undercut, cracks, and lack of penetration. Such defects can act as stress risers and crack initiation sites or as locations where corrosive contaminants can accumulate. Flaws can result from bad welding practices, poor joint preparation and cleaning, improper welding parameters, and lack of, or inadequate, stress relief. Tube blockage from welding debris has also been observed, resulting in a short-term overheating stress-rupture failure. The cause of failures due to welding flaws can be identified through visual inspection and metallurgical analysis and a review of the welding procedures, the welder’s qualifications, the welding inspection records, and the welding material control reports.

Response: Once a defective welded joint has been placed into service, it will usually fail before it is detected and replaced. Therefore, corrective measures focus on preventive actions (quality assurance procedures) that will minimize the possibility that a defective weld will be produced or that it will go undetected and be approved. Strict adherence to well-established quality control measures is necessary to ensure the integrity of welded joints. Such measures include qualification of welding procedures, welders, and welding operators; certification of welding inspectors and nondestructive testing examiners; calibration of welding equipment and testing devices; documentation of welding and testing methods, materials, and equipment; and proof tests.


A-13

Overheating

Creep (Long-Term Overheating)

Cause: Damage accumulation by creep has an initiation phase followed by stable crack growth and, finally, unstable crack growth. The process begins with isolated grain boundary creep cavities that, with increased exposure to stress and temperature, increase in size and density. They become directionally oriented and then link to form microcracks. Eventually, the formation of macrocracks can lead to crack instability or even component failure. Creep is often a leading cause of damage in high-temperature components, such as main steam piping, hot reheat piping, and superheater and reheater headers and tubes.

Component failures due to high-temperature creep occur after long-term exposure to temperatures that are within the creep regime, and usually above the oxidation limit of the material. This type of exposure may be a direct result of design conditions, or it may occur when unplanned conditions, such as internal deposit buildup or blockages, inadequate coolant circulation, or excess combustion gas temperatures, cause component temperatures to rise above the design temperature. Initially, damage occurs via a slight amount of creep deformation. Near the end of life, inter- or trans-granular creep voids form.

In thick-walled components, creep failure is generally the result of localized damage. It occurs because a crack develops in a critical location, such as a stress concentration, and propagates to cause failure. Most frequently, creep-related damage appears in seam welds, girth welds, and (in the case of headers) at tube attachment joints or in the borehole/ligament area.

Boiler tubes that experience above average temperatures will also be likely to have relatively higher fireside ash corrosion rates and steamside oxidation rates. Although ash corrosion by sulfur species is not a requirement for long-term overheating failures, ash corrosion will increase wall loss, and consequently increase the hoop stress, leading to increased creep damage accumulation rates. As noted, steamside scale buildup can lead to an increase in metal temperature, which leads to accelerated creep damage accumulation rates. Elevated stress levels due to erosion or corrosion can also contribute to higher creep damage rates.

Response: Corrective actions center on determining the remaining life of the thick-walled component or section of tubing based on the temperatures experienced, stress level, and material properties. Parametric analysis methods, such as the Larson Miller Parameter (LMP) method, can be used to estimate the effects of various actions. Proper redesign, including material upgrades, may be necessary to provide more creep-resistant steel in high-temperature locations. Steam flow redistribution to reduce peak temperatures can also mitigate degradation and optimize future live and availability.

Short-Term Overheating

Cause: Short-term overheating occurs when a tube is heated well above its design temperature, leading to the formation of cavities or microcracks along grain boundaries that ultimately cause failure. This can happen when local flue gas temperatures are elevated or when the cooling


A-14

effect of steam or water flowing through the tube is inadequate. Excessive gas temperature can be produced by overfiring during startup or firing with an irregular fuel burner pattern. Inadequate cooling may result if a tube becomes blocked, the drum level is too low, incomplete boil out of steam-cooled tubing occurs, or conditions lead to local steam blanketing or rapid internal deposit buildup. Short-term overheating failures can occur either below or above the lower critical temperature of the tube alloy.

Response: Choosing the proper corrective action depends on first identifying the root cause of overheating failure. Such an investigation usually begins with a review of plant records and events leading up to the failure in search of an obvious link between the operating conditions and the failure. The usual second step entails looking for tubing blockages through physical or radiographic examination. If neither of these options can determine the root cause, then boiler monitoring may be necessary. Tubing and/or gas temperatures can be measured using thermocouples, flux gages, infrared cameras, and other means. If all other options prove fruitless, then a final course of action is a more thorough design/operation/thermal hydraulic review. Once the root cause has been determined, fixes include removing blockages, altering startup practices, correcting drum levels, adjusting burners, or in extreme cases, redesigning the affected boiler section to improve the thermal-hydraulic response.

Supercritical Waterwall Cracking

Cause: Circumferential waterwall cracking is one of the leading causes of boiler tube failures in supercritical units. It is caused by two complementary processes that enable boiler tube surface temperatures to reach into the creep range: (1) the gradual buildup of deposits on the inside tube surfaces and (2) slagging-deslagging of the fireside surface. The internal deposits are formed from corrosion products entering the boiler via the feedwater and usually appear in a “rippled” formation. In some cases, failure is preceded by increased boiler pressure drop due to flow constraints from internal (ripple) tube deposits.

Waterwall cracking is typically localized, and may be limited to (or most severe in) tubes of a specific pass. In addition, cracking is usually limited to a narrow range of elevations in the boiler, usually in a limited span at the burner level with the maximum heat flux zone. The affected regions are indicated by numerous, closely spaced cracks. In most, but not all, cases the cracks do not penetrate through the full wall thickness. This type of cracking is often not observed until after a supercritical boiler has been in operation for a number of years. However, once the cracking is detected and repaired, it can return within a matter of months.

Response: Corrective actions focus on cycle chemistry changes, such as oxygenated treatment (OT) and eliminating oxygen scavengers from all-ferrous feedwater systems. These changes reduce the amount of internal deposits on the waterwalls by lowering the flow of feedwater corrosion products into the boiler and by changing the transported oxide from magnetite (Fe3O4), to hematite (Fe2O3), the latter of which does not adhere to tube surfaces and buildup. When these measures are applied, no ripple deposits form, chemical cleaning can be eliminated, and the boiler pressure drop does not increase

B-1

B NDE AND SAMPLING METHOD ABSTRACTS

B-1 NDE Techniques

Table B-1 provides an overview of the nondestructive evaluation methods frequently used to identify and locate material damage in boiler components. More detailed descriptions of the NDE techniques follow.

Table B-1 NDE Methods Overview

Method Applications Advantages Limitations Comments

Visual Surface discontinuities: cracks, porosity, slag, misalignment, warping, leaks

Inexpensive; fast; simple; real-time examination. Can eliminate need for other methods.

Surface only; variable and poor resolution; eye fatigue; distractions. Need good illumination.

Should always be the first method applied

Liquid Penetrant Surface discontinuities: cracks, porosity, seams, laps, leaks

Inexpensive; easy to apply; more sensitive than visual alone; applicable to most materials; rapid; portable

Surface only; not useful on hot, dirty, painted, or very rough surfaces

Messy; need good ventilation

May need to dress weld toe to avoid false indications

Magnetic Particle

Surface and near- surface discontinuities: cracks, voids, porosity, inclusions, seams, laps

Low cost; fast; more sensitive to tight cracks than Liquid Penetrant; can do near-subsurface; portable. Will work on some coated materials

Material must be ferromagnetic; surface must be clean; part may need demagnetization; alignment of field is important

Wet fluorescent technique very sensitive to small surface flaws

May need to dress weld toe to avoid false indications

Potential drop crack-depth gage

Sizing of cracks detected with other methods

NDE and Sampling Method Abstracts

B-2


Ultrasonic (UT) Surface and deep subsurface discontinuities: cracks, laminations, porosity, lack of fusion, inclusions, wall thickness, scale thickness

Can give location and size of discontinuity; good sensitivity; inspect from one side; portable

Couplant required; thin complex shapes are difficult; orientation of discontinuity important; very operator-dependent due to difficult calibration for material variability and level of damage

Need good standards. Automated digital ultrasonic systems are highly developed.

Linear Phased Array UT

Focused UT

Surface and deep subsurface discontinuities: cracks, laminations, porosity, lack of fusion, inclusions



Different sizes and shapes of heads can adapt for different conditions but require time to develop and test for each new application

Time of Flight Diffraction (TOFD) UT

Surface and deep subsurface discontinuities: cracks, laminations, porosity, lack of fusion, inclusions, thickness



Need good standards. Automated digital ultrasonic systems are highly developed.

Eddy Current Surface and near surface flaw detection

Established techniques provide versatile and fast coverage. Detects all types of flaws. Sensitive to microstructure. Surface cleaning and contact not required.

Surface and near surface only. Part must be electrical conductor. Problems with ferromagnetic materials. Very operator-dependent due to difficult calibration for material variability and level of damage.

Advanced techniques show correlation with early stage fatigue damage. Large technology base.

Magnetic Barkhausen

Magnetic property change (multi-parameter)

Fatigue cracking Established sensitivity to fatigue damage and stress conditions

Provides only near surface measurements; very operator-dependent due to difficult calibration for material variability and level of damage

Advanced techniques show correlation with early stage fatigue damage


B-3


Magnetostrictive Sensor (MsS) Guided Wave

“Remote” detection of cracking in inaccessible piping; waterwall cold-side, superheater pendants, feedwater heater tubing

Able to detect cracking at a distance from the probe or on far side of tubing

In early stage commercialization. Availability is limited and calibration techniques are not fully developed.

Application to boiler tubing is new. Technology has several years of commercial experience for buried and inaccessible piping.

Radiography (film)

Subsurface discontinuities: cracks, voids, inclusions, thickness variation, lack of fusion, incomplete penetration, corrosion, missing components, composition

Provides permanent record; can be portable; applicable to wide range of materials

Not sensitive to misaligned planar, crack-like flaws; radiation hazards; relatively expensive; poor resolution on thick, double-wall exposures for large diameter piping. Large exclusion zone stops work in nearby areas.

May be used to assist with disposition of ultrasonic indications

Digital Radiography

Phosphor Plate Radiography

Subsurface discontinuities: cracks, voids, inclusions, thickness variation, lack of fusion, incomplete penetration, corrosion, missing components, composition

Provides permanent record; can be portable; applicable to wide range of materials. Higher resolution and smaller exclusion zone than film techniques; useful for some complex geometries that were not previously inspectable.

Similar limitations to traditional radiology. While smaller than for traditional techniques, the exclusion zone still limits nearby work. Access to some areas is limited by size of equipment.

May be used to assist with disposition of ultrasonic indications

Acoustic Emission

Detection of active creep and fatigue crack initiation and growth, leaks, boiling and cavitation, phase changes

Remote and continuous surveillance, location, severity, permanent record. Tests an entire vessel or system. Costs 50–90% less than direct costs for UT examination. Piping need not be taken out of service.

Contact with system; may need many contact points; complex interpretation; system must be stressed; some systems are too complex

Current practice is to confirm indications by other methods. Use is growing rapidly.

Replication Surface microstructural condition

Damage assessment and determination of microstructure and heat treatment verification without sectioning the component

Requires significant cooling, surface polishing, and etching prior to use. Evaluates surface condition only.

Can reveal extent of creep-related damage only at the tested surface


B-4

Acoustic Emission

Acoustic emission (AE) is a passive monitoring technique that “listens” for the high frequency sounds of material degradation. The detected energy comes from sound waves generated by growing flaws. The sound waves can originate from a number of sources, such as dislocations, subcritical crack growth, ductile tearing, fatigue crack growth, stress corrosion cracking, leaks, scale cracking, frictional rubbing, and loose parts. The sound waves propagate radially throughout the structure, attenuating with distance from the source. The waves change direction as they are reflected and refracted at the boundaries of the structure. An AE sensor transforms their mechanical displacement into an electrical signal.

AE signals can be of two types: burst or continuous. A burst emission is a discrete transient signal associated with a specific event. Continuous emissions occur when burst emissions are so frequent that signal features associated with an individual burst event can no longer be measured (such as rise time, event duration, etc.). Continuous emissions are typically associated with background noise, flow, and leaks. In order to distinguish between discrete events and background noise, a voltage threshold level is set, above which most signal characteristics are measured.

Eddy Current Testing

Eddy current testing can be used to identify material discontinuities, such as changes in thickness, cracks, seams, phase transformation, case depth, cold working, hardness, and heat treatment. When a magnetic field is applied to a metal it establishes an eddy current in the material, which in turn creates an opposing magnetic field. Discontinuities in the metal create changes in the eddy current that can be measured as an apparent change in the impedance of the inducing coil. It is these changes in impedance that are measured and correlated to known defects.

Test coils of various configurations are used to establish a magnetic field in or around the object. Circular coils surround the test specimen, bobbin coils are inserted within it, and probe coils are placed on the surface. Frequencies ranging from 1 Hz to 5 MHz can be used, but frequency will determine the depth of current penetration, with high frequencies revealing only surface defects. Low frequency testing is sensitive to both surface and deep internal defects. For analysis, ECT uses meters and oscilloscopes that can be adjusted to respond to a specific phase or amplitude, which helps testers narrow the focus of the test.

EMAT (Electromagnetic Acoustic Transducer)

Electromagnetic acoustic transducers (EMAT) can reduce the acoustic scattering found in piezoelectric transducers that are commonly used in ultrasonic inspections. EMATs exhibit certain advantages over piezoelectric transducers because they do not require a coupling medium between the part and the transducer, and they can be designed to generate and detect focused sound waves unavailable to conventional probes. They can also be phased to create different refracted angles or focal distances, rather than using multiple transducers. Because EMATs require no couplant fluid, the surface of a part can be scanned by using synthetic aperture


B-5

focusing techniques to enhance the detectability of small defects. EMATs can generate and detect shear horizontal waves at an angle to the surface of the part being examined and direct waves to specific locations inside a part without complicated geometrical constructions or loss of energy.

Magnetic Particle Testing (MT)

Magnetic particle testing (MT) can identify surface or shallow subsurface cracks in ferrous materials. Magnetic particles applied to the surface of a magnetized test object will congregate around inconsistencies in the metal, indicating the location of the problem. The magnetic particles can be applied dry or in a wet suspension of water or kerosene, depending on the nature of the suspected defect and the finish of the component being tested. A wet suspension can more effectively detect fine cracks in smoother surfaces, while a dry powder is recommended when testing for subsurface cracks in rough surfaces. The use of fluorescent particles and an ultraviolet light is popular because that method renders the most striking visual indicator.

Various types of magnetic currents can be used to locate different kinds of anomalies. Alternating, direct, or half-wave direct current are the best options for identifying surface defects. For subsurface defects, half-wave direct current is the most effective. For best results, the current should be applied parallel to the direction of the anticipated defect. Although surface defects become apparent, testers should be trained to interpret indications of subsurface defects.

Liquid Penetrant Testing (PT)

Liquid penetrant testing (PT) can reveal surface cracks in nonporous materials. The process uses a penetrant liquid, which is brushed, sprayed, or dripped onto the surface of the metal being tested. After the test specimen has been left for a short time (about 30 minutes to an hour) to allow the liquid to penetrate any cracks that may exist, the surface is thoroughly cleaned and an absorptive coating (developer) is applied to draw the penetrant back out of the cracks. This process reveals the location, shape, and size of any surface defects.

Different types of penetrating liquids are used for testing in visible and ultraviolet light, with best results usually obtained using a fluorescent penetrant and ultraviolet light. The developer consists of a fine powder in a liquid suspension.

Another type of PT, filtered-particle testing, is used for porous objects. In this case, a liquid containing suspended particles is typically sprayed on the component. Liquid collects at a crack, making it visible. Some applications use colored or fluorescent sprays to enhance the visibility of cracks.

Replication

A replica is essentially a “fingerprint” of the surface under examination and can be used to detect cracking, creep cavitation, porosity, inclusions, and other similar surface defects. Extensive, indiscriminate replication can be very expensive and time consuming. The selection of locations where surface replication should be performed is primarily based upon the results of NDE


B-6

analysis and used as a supplement to the NDE. Replication should be performed in the areas where flaws were detected by ultrasonic or other examination techniques. In the event that no indications were detected by the NDE methods, it may still be desirable to perform a carefully selected number of replications.

Replication is capable of detecting creep damage and slag inclusions at the surface. Feature details obtained with the plastic replication technique have been shown to be similar to those obtained from a metallographic mount and the resolution is approximately 0.004 mils (0.1 micron). Replica results alone are generally insufficient to enable disposition of the component. If high-density slag inclusions are present, their distribution in the through thickness direction has to be ascertained by sample removal. If creep damage is present, the overall evaluation should include actual flaws detected by NDE and possible presence of buried flaws in the through-thickness direction.

There are some significant disadvantages of the replication technique with respect to the assessment of creep damage. Because the component is not destroyed and only one surface is accessible, the damage detection is limited to that surface, typically the outside surface of the component. The lack of detectable creep damage on a replica does not preclude the possibility of creep damage at some other location throughout the wall thickness. Similarly, the technique is limited by the location chosen for the replica. A lack of damage at the chosen location does not necessarily mean that there is no damage several inches (about 10 cm) away from the site.

Radiographic Testing (RT)

Radiographic testing (RT) uses x-rays, gamma rays, or other high-energy radiation to reveal features such as cracks, voids, inclusions, and changes in thickness. The radiation is projected at the test object, where it is absorbed at different rates depending on the thickness and density of the material. The result is usually recorded on a radiographic film, although other methods for measuring the level of radiation leaving the object, such as Geiger counters, can also be used. Like photographic films, radiographic films can vary in grain size (speed) and contrast, with slower, small-grain film showing the greatest level of detail. Fast, large-grain films are best suited for revealing large differences in thickness, or other gross features.

Several factors effect the quality and accuracy of the image produced on film. For example, direct radiation forms a clear, sharp image, whereas scattered radiation produces a foggy image. An intensifying screen made of lead can help mitigate scattered radiation for radiography at high voltages. To achieve the clearest picture, the focal point should be small, the ray source should not be too far away, and the film should be placed close to the test object, parallel to the area of interest on the component and perpendicular to the rays emitted by the source.

New portable digital techniques provide immediate images with sharper resolution than film techniques. Shorter exposure times, lower energy levels, and focused beams allow reduced exclusion zone size, thereby allowing more timely radiographic work and less disruption to other work. In some cases, successful inspections are performed on complex geometries that were considered un-inspectable with film radiology.


B-7

Technologies used in the new equipment include high-energy x-ray sources, direct digital detectors with high-energy x-ray and traditional isotope sources, and phosphor plate imaging. Work is under way to adapt computed tomography techniques now used in medical imaging.

Ultrasonic Testing (UT)

Ultrasonic testing is used to identify both surface and subsurface defects as well as measure material thickness. Specific applications include weld inspection, detecting evidence of hydrogen attack, measuring ID oxide scale in boiler tubes, and measuring tubing wall thickness. It can also be used to measure change of stress in a component.

Any material that transmits vibrational energy can be analyzed using ultrasonic testing methods. UT employs a piezoelectric transducer to generate mechanical vibrations, which are transmitted through a coupling liquid into the component being tested. Because the velocity of sound through a material is a function of its density and modulus, each material has a characteristic response, and any changes in its properties will cause a change in response. Material flaws or discontinuities can be detected by measuring the presence, position, and amplitude of echoes.

Ultrasonic testing falls into two general categories: pulse-echo systems, which use a single transducer, and through-transmission systems, which use both a sending and receiving transducer. The optimal frequency range varies depending on material properties. For example, low frequencies (40 kHz to 1.0 MHz) are best suited for materials with low elastic modulus or large grain size, while high frequencies (2.25 to 25 MHz) produce better results with small defects, thin sections, and fine grain materials. Testers can confirm suspected results by comparing received signals (visually or electronically) with reference blocks that have a known similar construction or defect (e.g., holes or cracks).

Advanced Ultrasonic Examination

Emerging advanced applications of UT include linear phased array and time of flight diffraction (TOFD). Linear phased array techniques use pulse-echo systems and TOFD options fall under the through-transmission category.

Linear Phased Array

An “array” is a type of ultrasonic transducer that has been segmented into many individual, parallel elements; an array may be configured using either a single piezoelectric or electromagnetic acoustic transducer (EMAT). In a linear phased array, each array element is connected to a separate pulser, receiver, and analog-to-digital converter. The system operator controls the time at which each element is pulsed and the time delay applied to the response received by each element. After application of the reception delays, the waveforms received by the elements are summed to form a single, resultant waveform. Beam focusing and angle control are accomplished by precise nonlinear delays in both the emission pulse and the received pulse for each element in an array of transducers.


B-8

By controlling the timing, or “phase,” of each element’s excitation and reception, a single array probe can be made to simulate many different conventional probes. Without moving the probe, sound beams of many angles can be generated sequentially, inspecting a large portion of the component’s cross-section. In this manner, a slice of a component may be scanned electronically in milliseconds instead of being scanned mechanically in a few seconds. Instead of the slow, two-dimensional scan pattern necessary to scan a weld joint using conventional UT methods, the probe may simply be swept along the length of the weld one or more times at different array setback positions to achieve similar results. The ability to use this line scan procedure versus the more conventional raster scan can reduce scan times by at least an order of magnitude.

Time-of-Flight Diffraction

TOFD detects and sizes flaws based on analyzing the arrival time of diffracted sound waves emitted from a flaw’s extremities. The TOFD method employs two angled L-wave transducers arranged symmetrically opposite each other, straddling the weld. The transducers are located on the parent material, clear of the weld crown, facing each other. One transducer acts as transmitter and the other as receiver. The transducer and pulser/amplifier characteristics are selected to generate as broad a distribution of energy as possible over the weld body, heat-affected zone, and adjacent parent material.

The major benefits of TOFD include speed of operation, ease of application, reliable detection capabilities, and accuracy of crack sizing.

B-2 Sample Evaluation Techniques

Table B-2 provides an overview of sample (destructive) evaluation methods frequently used to analyze material damage in boiler components.

Table B-2 Sample Evaluation Methods Overview


Tube Section

Used for analysis of all forms of damage in boiler tubing: corrosion, erosion, fatigue, overheating, creep, material and welding flaws, deposits

Direct testing of sample provides most accurate evaluation

Significant time and expense for removing sample, repairing tubing, and performing tests

Many facilities use routine sampling of key locations for monitoring damage accumulation and planning repair or replacement


B-9


Ring Sample Used for root cause analysis of creep, fatigue and corrosion-fatigue damage; creep life management

Direct testing of sample provides most accurate evaluation

Significant time and expense for removing sample, performing repair welds, post-weld heat treatment, and sample testing

Boat Sample Used for analysis of creep and overheating damage; original material and weld properties

Easier sample removal and weld repair

Limited volume of sample; damage in removal process; time and expense of analysis

Miniature Punch Test

Used for analysis of creep and overheating damage; original material and weld quality

Easier sample removal and weld repair

Limited volume of sample; damage in removal process; time and expense of analysis

Cryogenic Cracking

Sample preparation for visual or electron microscopy

Exposes unaltered microstructure for highest resolution analysis

Time and expense of sample removal, preparation, and analysis

Visual Surface discontinuities: corrosion pitting or patterning, cracks, porosity, slag, misalignment, warping, leaks, oxide and deposit characterization

Inexpensive; fast; simple; real-time examination. Used first for early results and to guide selection of eliminate need for other methods.

For best results, requires sample with unaltered surface. Surface only; variable and poor resolution; eye fatigue; distractions. Need good illumination.

Should always be the first method applied

Oxide Dating Used to estimate time of initiation and rate of development of fatigue cracks and corrosion pitting

Can help provide good understanding of time and cause of origination, and drivers of damage mechanisms

Best results require time and expense of sample removal, preparation, and analysis by visual microscopy. Accuracy limited somewhat by quality of operating records.


B-10


Chemical Analysis of Deposits

Used to evaluate root causes of under-deposit corrosion; identify problems with cycle chemistry, correlate damage seen in metal

Provides understanding of chemical drivers for damage mechanisms

Time and expense of sample removal, preparation, and analysis. Clean sample required for reliable results.

Chemical Analysis of Metallurgy

Used to confirm conformance or variance from intended specification; identification where records are unavailable

Knowledge of material properties provides basis for analysis of damage mechanisms

Portable instruments are now available with high reliability in identifying standard alloys

Visual Microscopy

High resolution imaging of microstructure for analysis of fatigue, creep, overheating, corrosion; oxide aging

Able to detect most significant changes


Used with and without etching for best imaging of different microstructures

Electron Microscopy

Very high resolution imaging of microstructure for analysis of creep, overheating

Able to detect early stage changes in microstructure

Time and expense of sample removal, preparation, and analysis. Expensive equipment with limited availability.

Hardness Mechanical properties of materials

Reveals macro-level material properties, including changes due to overheating, strain hardening, etc.

Information limited to the actual surface tested

Can be performed on surfaces in field or sample in lab

Tensile and Toughness Testing

Mechanical properties of materials

Reveals macro-level material properties, including changes due to overheating, strain hardening, etc.



B-11


Stress rupture testing

Estimating long-term creep life, mostly for weld metal samples

Can confirm or indicate if remaining life is likely to be significantly below expectations

Results are affected by sample size and homogeneity, test environment, and stress calculations. Time and expense of sample removal, preparation, and analysis.

Uses increased temperature to accelerate creep. A 15% change in test stress can produce a factor-of-two change in estimated life.

C-1

C RESOURCES AND REFERENCES

C-1 EPRI Software for Condition Assessment

BLESS: EPRI’s Boiler Life Evaluation and Simulation System software is used to analyze cracks and predict the rate of crack growth. Although techniques for detecting and measuring cracks are well established, methods to confidently predict a component’s remaining life after crack initiation are less developed. Although some cracks present significant risk in many instances, crack initiation may occur early but propagation is so slow that it poses little or no failure risk. Ongoing upgrades to EPRI’s BLESS software have simplified and improved prediction of crack initiation and growth rates.

Boiler OIO: EPRI’s Boiler Overhaul Interval Optimization tool is used to prioritize equipment screening and repairs. This series of spreadsheets supports two levels of semi-quantitative screening to determine which components are sufficiently critical to maximize return on overhaul maintenance investments. A complementary tool, STACKER, helps engineers generate data on the probability of failure based on interviews with knowledgeable plant personnel.

EPRI’s Creep-FatiguePro software is used to analyze and predict damage accumulation due to creep and fatigue interactions in high-temperature thick-walled components. Creep and fatigue interact in complex ways to accelerate material damage in high-temperature components subject to thermal and expansion-constraint stresses. Creep-FatiguePro models these components and predicts the likely total damage accumulation.

DMW-PODIS: EPRI’s Dissimilar Metal Weld Prediction of Damage In-Service software is used to estimate damage accumulation and remaining life in dissimilar metal welds in superheaters and reheaters. DMW-PODIS is based on empirical equations that relate damage to loading history for stainless steel and nickel-based filler metal welds. Damage evaluations provided by DMW-PODIS can help engineers plan corrective action—plant modification or change in operating conditions—to prolong weld life.

TULIP: EPRI’s Tube Life Probability software is used to estimate the remaining life of superheater/reheater tubing. TULIP models continuum creep damage mechanics and estimates the probability of superheater and reheater tubing failure using Monte Carlo simulation.

Resources and References

C-2

C-2 EPRI Program Support

In addition to its publications and periodic conferences, EPRI offers a number of training seminars and other support programs to assist member companies with implementing and improving condition assessment and component life management programs. Contacts and listings can be obtained through the EPRI web site, www.epri.com. Key offerings include:

• On-site training for Boiler Tube Failure Reduction and Cycle Chemistry Improvement

• Customized training programs and consulting

• Boiler Reliability Interest Group (BRIG)

• High-Energy Piping Interest Group (HEPIP)

• EPRI NDE Center


C-3

C-3 EPRI Reports

An extensive catalogue of technical reports documents EPRI’s work with member companies and research organizations to study damage mechanisms and develop tools and guidelines for conducting condition assessment and component life management programs. Reports relevant for boiler components include the following:

Boiler Condition Assessment and Component Life Management

Proceedings: Advances in Life Assessment and Optimization of Fossil Power Plants. EPRI: 2002. Report 1006965.


Demonstration of the Cold Air Velocity Technique to Control Fly Ash Erosion at a National Thermal Power Corporation (NTPC) Plant. EPRI: 2004. Report 1010542.

Examples Manual for Boiler Overhaul Interval Optimization. EPRI: 2004. Report 1004305.




Guidelines for the Prevention of Economizer Inlet Header Cracking in Fossil Boilers. EPRI: 1989. Report GS-5949.




Boiler Tube Failures

Acoustic Boiler Tube Leak Detection: Utility Experience. EPRI: 1987. Report CS-5136.

Boiler Tube Failure Metallurgical Guide. EPRI: 1993. Report TR-102433, Vols. 1-2.

Boiler Tube Failure Reduction Program. EPRI: 1991. Report GS-7454.


C-4

Boiler Tube Failures. EPRI: 2001. Report PS-114825.

Boiler Tube Failures: Theory and Practice. EPRI: 1996. Report TR-105261. Volume 1: Boiler Tube Fundamental Volume 2: Water-Touched Tubes Volume 3: Steam-Touched Tubes

Circumferential Cracking on the Waterwalls of Supercritical Boilers. EPRI: 1995. Report TR-104442. Vols. 1-2.

Corrosion-Fatigue Boiler Tube Failures in Waterwalls and Economizers, Vols. 1-5. EPRI: 1992–96. Report TR-100455.

Corrosion-Fatigue Crack Initiation of Boiler Tubes: Effect of Phosphate in Boiler Water. EPRI: 1997. Report TR-105568.

Evaluation of Supercritical Boiler Waterwall Cracking. EPRI: 2005. Report 1012862.


Guidelines for the Control and Prevention of Fly Ash Erosion in Fossil-Fired Power Plants. EPRI: 1994. Report TR-102432.

Intelligent Sootblowing at TVA's Bull Run Plant. EPRI: 2003. Report 1004115.


Mitigation of Fireside Corrosion in Low-NOX Boilers: A State of the Art Assessment of Materials Solutions. EPRI: 1999. Report TR-112823.

Proceedings: International Conference on Boiler Tube Failures in Fossil Plants, November 6-8, 2004, Phoenix, Arizona. EPRI: 2002. Report 1007347.

Proceedings: Third International Conference on Boiler Tube Failures in Fossil Plants. EPRI: 1998. Report TR-109938. (See report TR-100493 for proceedings of the Second International Conference.)

State-of-Knowledge Assessment for Accelerated Waterwall Corrosion with Low-NOX Burners. EPRI: 1997. Report TR-107775.

Tube Repair and Protection for Damage Caused by Sootblower Erosion. EPRI: 2004. Report 1008037.

Waterwall Fireside Corrosion Under Low-NOX Burner Conditions. EPRI: 2001. Report 1001351.


C-5

Cycle Chemistry, Corrosion, and Deposition

8th International Conference on Cycle Chemistry in Fossil and Combined Cycle Plants. EPRI: 2005. Report 1012930.

Behavior of Aqueous Electrolytes in Steam Cycles: The Final Report on the Solubility and Volatility of Copper (I) and Copper (II) Oxides. EPRI: 2004. Report 1011075.

Boiler Water Deposition Model, Part 1, Feasibility Study. EPRI: 2004. Report 1004931.

Condensate Polishing Training Manual. EPRI: 2004. Report 1004933.

Copper Alloy Corrosion in High Purity Feedwater. EPRI: 2000. Report 1000456.

Copper Alloy Corrosion in High Purity Feedwater: Admiralty Brass, Aluminum Brass, and 90/10 Copper Nickel at 95oC. EPRI: 2003. Report 1007391.





Deposition in Boilers: Review of Soviet and Russian Literature. EPRI: 2003. Report 1004193.

Deposition on Drum Boiler Tube Surfaces. EPRI: 2004. Report 1008083.

EPRI Cycle Chemistry Advisor Code, Version 3.1. EPRI: 2002. Report 1006935.



Guidelines for Copper in Fossil Plants. EPRI: 2000. Report 1000457.

Influence of Water Chemistry on Copper Alloy Corrosion in High Purity Feedwater. EPRI: 2003. Report 1007162.


C-6

Justifying Cycle Chemistry Upgrades to Improve Availability, Performance, and Profitability. EPRI: 2001. Report 1004586.

Low-Temperature Corrosion Problems in Fossil Power Plants—State of Knowledge Report. EPRI: 2003. Report 1004924.

Proceedings: 7th International Conference on Cycle Chemistry in Fossil Plants. EPRI: 2004. Report 1009194.

Proceedings: 6th International Conference on Fossil Plant Cycle Chemistry. EPRI: 2001. Report 1001363.

Real Time Cycle Chemistry Excursions: An Approach to Valuation and Decision Guidance. EPRI: 2003. Report 1004935.

State-of-Knowledge on Deposition: Part 1: Parameters Influencing Deposition in Fossil Units. EPRI: 2002. Report 1004194.

State-of-Knowledge on Deposition: Part 2: Assessment of Deposition Activity in Fossil Plant Units. EPRI: 2003. Report 1004930.

The Volatility of Impurities in Water/Steam Cycles. EPRI: 2002. Report 1004194.

Valuing Cycle Chemistry in Fossil Power Plants. EPRI: 2002. Report 1004641.

User's Manual for EPRI ChemExpert, Version 3.0: Cycle Chemistry Advisor for Fossil Power Plants. EPRI: 2001. Report 1006404.

Materials, Damage Mechanisms, Welding, and Repair Techniques

Advances in Materials Technology for Fossil Power Plants: Proceedings from the Fourth International Conference. EPRI: 2005. Report 1011381.

Application and Repair of Overlay Welds. EPRI: 2005. Report 1009755.

Development of Advanced Methods for Joining Low-Alloy Steels. EPRI: 2004. Report 1004916.

Effect of Cold-Work and Heat Treatment on the Elevated-Temperature Rupture Properties of Grade 91 Material. EPRI: 2005. Report 1011352.

Effect of Normalization and Temper Heat Treatment on P91 Weldment Properties. EPRI: 2005. Report 1004915.

Embrittlement of Components in Fossil Fueled Power Plants. EPRI: 2003. Report 1004515.

EPRI Conference on 9Cr Materials Fabrication and Joining Technologies. EPRI: 2001. Report 1006299.


C-7

Evaluation of Filler Materials for Transition Weld Joints between Grade 91 and Grade 22 Components. EPRI: 2005. Report 1009758.

Fossil Welding Program Best Practices. EPRI: 2004. Report 1008059.

Fourth International Conference on Advances in Materials Technology for Fossil Power Plants. (2004) EPRI: (Proceedings Pending)

Further Validation of EPRI's Remaining Life Assessment of Austenitic Stainless Steel Superheater and Reheater Tubes: AEP-Amos 3. EPRI: 2004. Report 1011072.

Grade 22 (2-1/4Cr-1Mo) Low Alloy Steel Handbook. EPRI: 2005. Report 1011534.

Grade 22 Low Alloy Steel Handbook. EPRI: 2005. Report 1012840.

Guideline on Fossil Boiler Field Welding. EPRI: 2003. Report 1004701.

Guideline for Welding P(T) 91 Materials. EPRI: 2002. Report 1006590.

Materials Solutions for Waterwall Wastage—An Update. EPRI: 2005. Report 1009618.

Metallurgical Guidebook for Fossil Power Plant Boilers. EPRI: 2005. Report 1004509.

Optimum Hardness of P91 Weldments. EPRI: 2003. Report 1004702.

Performance Review of T/P91 Steels. EPRI: 2002. Report 1004516.

P-No. 4 and P-No. 5A Temperbead Repair Using the Flux-Cored Arc Welding (FCAW) Process. EPRI: 2001. Report 1001271.

Remaining Life Assessment of Austenitic Stainless Steel Superheater and Reheater Tubes. EPRI: 2002. Report 1004517.

Remaining Life Assessment of Grade 91 Superheater and Reheater Tubing Subject to Long-Term Overheat-Creep Damage. EPRI: 2004. Report 1011286.

Repair Technology for Stub Tube-to-Header Creep Damage. EPRI: 1999. Report HW-113512.

Repairs of Deaerators. EPRI: 2004. Report 1008069.

Temperbead Repair Welding of Grade 91 Material. EPRI: 2005. Report 1009757.

Temperbead Welding of P-Nos. 4 and 5 Materials. EPRI: 1998. Report TR-111757.



C-8

The Use of Weld Overlays to Extend the Life of Seam Welded High Energy Piping in Fossil Power Plants: Common PQR and Thinner Piping Evaluation. EPRI: 2002. Report 1004616.

Thermal Fatigue Cracking of Boiler Drums. EPRI: 2002. Report 1004614.

Thermal Fatigue of Fossil Boiler Drum Nozzles. EPRI: 2005. Report 1008070.

Weld Overlay of Waterwall Tubing, Alternative Filler. EPRI: 2001. Report 1001268.

Weld Overlay of Waterwall Tubing, Alternative Materials and Distortion. EPRI: 1999. Report TR-112643.

Weld Overlay of Waterwall Tubing, Repair Procedures and Contract Specifications. EPRI: 2002. Report 1004615.

Nondestructive Evaluation, Sample Testing, and Analysis


Acoustic Boiler Tube Leak Detection: Utility Experience. EPRI: 1987. Report CS-5136.

Acoustic Emission Monitoring of Cracks in Fossil Fuel Boilers. EPRI: 1987. Report CS-5264.

Acoustic Emission Monitoring of High-Energy Headers. EPRI: 1997. Report TR-107839, Vol. 1.

Acoustic Emission Monitoring of High-Energy Steam Piping. EPRI: 1995. Report TR-105265, Vol. 1.


Assessment of NDE for Pre-Crack Fatigue Damage in Boiler Pressure Components. EPRI: 2000. Report 1000313.

Assessment of Robotics for Boiler NDE and Repair. EPRI: 2000. Report 1000301.


Fossil-Fired Boiler Tube Inspection. EPRI: 1986. Report CS-4633, Vol. 1.



C-9

Guidelines for the Ultrasonic Time-of-Flight Diffraction Inspection of Ligament Cracking in Steam Headers. EPRI: 2003. Report 1007702.

Guidelines for Performing Probabilistic Analyses of Boiler Pressure Parts. EPRI: 2000. Report 1000311.



Life Assessment of Boiler Pressure Parts. EPRI: 2000. Report 1000311.


Miniature X-ray Diffraction System for In Situ Residual Stress Measurement. EPRI: 2003. Report 1004522.


Providing Access for Inspection of Corrosion-Fatigue Damage in Waterwalls and Subsequent Repair. EPRI: 2005. Report 1011517.

Thermal Fatigue Cracking in Fossil Boiler Drums; Finite-Element-Based and Fracture Mechanics Analyses. EPRI: 2005. Report 1011916.

Operations, Maintenance, and Design Considerations



Guidelines on the Effects of Cycling on Maintenance Activities. EPRI: 2001. Report 1004017.




State of the Art Boiler Design for High Reliability Under Cycling Operation. EPRI: 2004. Report 1009914.


C-10

Statistical Analysis Methodology for Predicting Impact of Operation Factors on Boiler Availability. EPRI: 2001. Report 1004064.

Severe Duty Valve Maintenance Guide. EPRI: 2005. Report 1011828.



C-11

C-4 Other References

Steam: Its generation and use. 41st edition. The Babcock & Wilcox Company, 2005.

B&W has made significant additions for the 41st edition of this classic reference and includes a CD with searchable text in PDF format. The text now includes a comprehensive section on condition assessment and better explanations of operating modes and other key knowledge areas for steam power plants and other steam systems.

http://www.babcock.com

The extensive catalog of technical papers available, in PDF format, on the Babcock and Wilcox Company website includes many documenting B&W experience with condition assessment of boiler components.

http://www.babcockpower.com

References on damage mechanisms and condition assessment from the Babcock Power Inc. web site include PDF versions of technical papers from Babcock Power Services Inc., Boiler Tube Company of America, Riley Power Inc. (Riley Stoker Company, DB Riley), and Vogt Power International Inc.

http://www.structint.com/tekbrefs/

Structural Integrity website provides access to PDF versions of technical papers addressing a variety of damage mechanisms and condition assessment processes and technologies, including use of EPRI’s Creep-FatiguePro software.

© 2006 Electric Power Research Institute (EPRI), Inc. All rights reserved.Electric Power Research Institute and EPRI are registered service marks ofthe Electric Power Research Institute, Inc.

Printed on recycled paper in the United States of America

Program:

Boiler Life and Availability Improvement Program

1010620

Export Control Restrictions

Access to and use of EPRI Intellectual Property is granted with

the specific understanding and requirement that responsibility

for ensuring full compliance with all applicable U.S. and

foreign export laws and regulations is being undertaken by

you and your company. This includes an obligation to ensure

that any individual receiving access hereunder who is not a

U.S. citizen or permanent U.S. resident is permitted access

under applicable U.S. and foreign export laws and

regulations. In the event you are uncertain whether you or

your company may lawfully obtain access to this EPRI

Intellectual Property, you acknowledge that it is your

obligation to consult with your company’s legal counsel to

determine whether this access is lawful. Although EPRI may

make available on a case-by-case basis an informal

assessment of the applicable U.S. export classification for

specific EPRI Intellectual Property, you and your company

acknowledge that this assessment is solely for informational

purposes and not for reliance purposes. You and your

company acknowledge that it is still the obligation of you and

your company to make your own assessment of the applicable

U.S. export classification and ensure compliance accordingly.

You and your company understand and acknowledge your

obligations to make a prompt report to EPRI and the

appropriate authorities regarding any access to or use of EPRI

Intellectual Property hereunder that may be in violation of

applicable U.S. or foreign export laws or regulations.

The Electric Power Research Institute (EPRI)

The Electric Power Research Institute (EPRI), with major locations in

Palo Alto, California, and Charlotte, North Carolina, was established

in 1973 as an independent, nonprofit center for public interest

energy and environmental research. EPRI brings together members,

participants, the Institute’s scientists and engineers, and other leading

experts to work collaboratively on solutions to the challenges of electric

power. These solutions span nearly every area of electricity generation,

delivery, and use, including health, safety, and environment. EPRI’s

members represent over 90% of the electricity generated in the

United States. International participation represents nearly 15% of

EPRI’s total research, development, and demonstration program.

Together...Shaping the Future of Electricity

ELECTRIC POWER RESEARCH INSTITUTE3420 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

Boiler Condition Assessment Guideline -...

Documents

Transcript of Boiler Condition Assessment Guideline -...