Boiler Reliabiliti Optimization 2001

EPRI Boiler Reliability Optimization Program Case Studies from 1998-2001

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Technical Report

EPRI Boiler Reliability Optimization Program Case Studies from 1998-2001 1006537

Final Report, December 2001

EPRI Project Manager P. Abbott

EPRI • 3412 Hillview Avenue, Palo Alto, California 94304 • PO Box 10412, Palo Alto, California 94303 • USA 800.313.3774 • 650.855.2121 • [email protected] • www.epri.com

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

ORDERING INFORMATION Requests for copies of this report should be directed to EPRI Customer Fulfillment, 1355 Willow Way, Suite 278, Concord, CA 94520, (800) 313-3774, press 2. Electric Power Research Institute and EPRI are registered service marks of the Electric Power Research Institute, Inc. EPRI. ELECTRIFY THE WORLD is a service mark of the Electric Power Research Institute, Inc. Copyright © 2001 Electric Power Research Institute, Inc. All rights reserved.

CITATIONS This report was prepared by Eskom Megawatt Park P.O. Box 1091 Johannesburg, 2000 South Africa Principal Investigator D. McGhee This report describes research sponsored by EPRI. The report is a corporate document that should be cited in the literature in the following manner: Boiler Reliability Optimization Project Case Studies from 1998 – 2001, EPRI, Palo Alto, CA: 2001. 1006537.

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REPORT SUMMARY

The prospect of competing in a deregulated environment is driving utilities to explore more costeffective means of operating and maintaining their plants. Recognizing this, a number of companies —including American Electric Power, Great River Energy, Detroit Edison, Arizona Public Services Company, and Hawaiian Electric Company— have participated in EPRI’s Boiler Reliability Optimization Program. This report provides seven case studies demonstrating key aspects of the program. Background EPRI’s Boiler Reliability Optimization Program consists of several customized projects. Each project includes four phases that involve EPRI technical staff, with participation from the plant’s operating, maintenance, and engineering support staff, as follows: Phase 1—technical and organizational assessments, Phase 2—development of a boiler failure defense plan, Phase 3—implementation of a failure defense plan, and Phase 4—continuous improvement and process automation. Each phase, in turn, builds on the strengths of the preceding phase. EPRI compiled these case studies to demonstrate the scope of the program and its applicability to a wide range of power production issues. Objective To provide case studies from membership participation in EPRI’s Boiler Reliability Optimization Program between 1998 and 2001. Approach The principal investigators on this report selected case studies that would demonstrate key facets of the program, including development of a maintenance strategy, implementation of Streamlined Reliability Centered Maintenance (RCM) procedures, outage task prioritization, Boiler Predictive Maintenance (BPdM), performance of root cause analysis, and application of EPRI’s Boiler Maintenance Workstation (BMW) software. Each case study includes a scope of work description, findings and observations, conclusions, and recommendations. Results Two case studies from American Electric Power—Big Sandy Plant-Unit 2 demonstrate phases 1, 2, and 4 of the program, with specific application to water- and steam-touched tubing. This project focused on the long-term integrity of the water- and steam-touched tubing within the boiler envelope. It involved training on EPRI’s Streamlined RCM software using the fuel system as an example, additional training on EPRI’s tube failure reduction program, development of a

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BPdM process, and the provision of EPRI’s BMW software package for trending and tracking tube failure data and information. An outage task prioritization model—Risk Evaluation and Prioritization (REAP)—was used to prioritize the tasks identified for the Unit 2 scheduled outage in April 2000. A case study from Great River Energy’s Coal Creek Station-Unit 2 discusses the decision to change the boiler maintenance overhaul frequency from two to three years. The project emphasizes development of a comprehensive and effective boiler inspection plan to take the place of the currently reactive plan, which focuses almost entirely on sootblower erosion and does not cover all boiler components in sufficient detail. A case study from Detroit Edison’s St Clair Plant-Unit 7 focuses on technical and programmatic opportunities for improving boiler reliability. The project identifies the causes of boiler tube failures and highlights a number of opportunities for improvement with respect to managing the short- and long-term health of the boiler. Two case studies at Arizona Public Services Company’s Four Corners and Cholla plants emphasize root cause analysis. A review of the 1999 Lost Generation Action Plans from both plants evaluates whether the “true” root causes of lost generation have been identified, and whether appropriate action plans are in place to address these causes. A case study from Hawaiian Electric Company (HECO) addresses EPRI’s independent review of HECO’s Remaining Useful Life and Generation Asset Management Program. The EPRI team identified a number of opportunities where current project management and root cause analysis efforts could be enhanced to provide additional assurance that availability and reliability goals would be achieved. EPRI Perspective A Boiler Reliability Optimization Program is only as effective as the people, management systems, component manufacturers, technology specialists, and predictive maintenance tools or equipment that comprise it. For a condition-based, highly planned, maintenance optimization program to be effective, it must integrate the work process, management, work culture, technologies, and people into the total plant operation. EPRI believes this documentation of case studies demonstrates innovative applications of EPRI’s Boiler Reliability Optimization Program and methods for achieving such integration under a wide variety of circumstances. Utilities will find that implementation of the Boiler Reliability Optimization Program will help them compete cost-effectively in the deregulated power generation market. Keywords Boiler reliability Boiler Reliability Optimization Program Competitive power generation

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CONTENTS

1 BOILER RELIABILITY OPTIMIZATION PROJECT PHASE 1, 2 & 4 AT AMERICAN ELECTRIC POWER’S BIG SANDY PLANT – UNIT 2............................................................ 1-1 1.1

EXECUTIVE SUMMARY........................................................................................... 1-1

1.2

INTRODUCTION ...................................................................................................... 1-2

1.3

SCOPE OF WORK ................................................................................................... 1-3

1.4

FINDINGS AND OBSERVATIONS............................................................................ 1-3

1.4.1 Phase I and II - Technical and Organisational Assessment.................................. 1-3 1.4.1.1 Work Process................................................................................................ 1-5 Maintenance Strategy........................................................................................... 1-7 Findings:............................................................................................................... 1-8 Recommendations:............................................................................................... 1-8 Work Identification ................................................................................................ 1-8 Findings:............................................................................................................... 1-9 Recommendations................................................................................................ 1-9 Work Control .......................................................................................................1-10 Findings...............................................................................................................1-10 Recommendations...............................................................................................1-10 Work Execution ...................................................................................................1-11 Findings...............................................................................................................1-11 Recommendations...............................................................................................1-11 1.4.1.2 Technologies................................................................................................1-11 Findings...............................................................................................................1-12 Recommendation ................................................................................................1-12 Work Management System .................................................................................1-12 Findings...............................................................................................................1-12 Recommendations...............................................................................................1-12 Maintenance & Diagnostic Technologies .............................................................1-12 Findings...............................................................................................................1-12

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Recommendations...............................................................................................1-12 Information Integration.........................................................................................1-13 Findings...............................................................................................................1-13 Recommendations...............................................................................................1-13 1.4.1.3 Management and Work Culture....................................................................1-13 Recommendations...............................................................................................1-14 1.4.1.4 People..........................................................................................................1-15 Findings:..............................................................................................................1-15 Recommendations...............................................................................................1-15 1.4.2 Failure Defence Plan – Water and Steam Touched Tubing..................................1-15 Findings ...................................................................................................................1-16 Economiser .........................................................................................................1-16 Waterwalls...........................................................................................................1-16 Platen Superheat.................................................................................................1-17 Finishing Superheat.............................................................................................1-17 First Reheat (High Pressure) ...............................................................................1-17 Second reheat (low pressure)..............................................................................1-18 Spray Attemperators............................................................................................1-18 Recommendations...............................................................................................1-18 1.4.3 Streamlined Reliability-Centered Maintenance.....................................................1-30 1.4.4 Unit 2 Outage Task Prioritisation..........................................................................1-30 1.4.5 Boiler Tube Failure Reduction and Cycle Chemistry Improvement Training .........1-33 1.4.6 Boiler Maintenance Workstation (BMW) installation and training..........................1-33 AEP Big Sandy Unit 2, Boiler Reliability Optimization - Phase 4, July 2001.......................1-34 Executive Summary ..........................................................................................................1-34 Introduction .......................................................................................................................1-34 Description of Phase 4 of a Typical Boiler Reliability Optimization Project.........................1-35 Findings ........................................................................................................................1-35 Conclusions.......................................................................................................................1-40 Recommendations ............................................................................................................1-41 Appendix 1: Interview List..................................................................................................1-44 Appendix 2: List of Typical headings that appear in a policy and or a procedure ...............1-45

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2 BOILER RELIABILITY OPTIMIZATION PROJECT PHASE 2 – BOILER INSPECTION PLAN REVIEW AT GREAT RIVER ENERGY’S COAL CREEK STATION – UNIT 2 ................................................................................................................................. 2-1 2.1 Executive Summary..................................................................................................... 2-1 2.2 Introduction.................................................................................................................. 2-1 2.3 Findings and Observations .......................................................................................... 2-2 2.4 Recommendations....................................................................................................... 2-3 ANNEXURE I: Extract from a Boiler Inspection Report....................................................... 2-7 Inspection Areas ....................................................................................................... 2-7 1200 Waterwall Cleaning Devices, operational condition ............................................... 2-7 Inspection results........................................................................................................... 2-7 Recommendations for 2004: .......................................................................................... 2-8 1501 Superheat Division Panels, attachment problems ................................................ 2-8 Inspection results:.......................................................................................................... 2-8 Recommendations for 2004: .......................................................................................... 2-8 ANNEXURE II: Unit 2 Outage Inspection Plan as of August 21, 2000 ................................ 2-9 1. Burner Front Team Member...................................................................................... 2-9 1.1 Prior to the outage (within 2 weeks of the start of the outage) ............................. 2-9 1.2 At the start of the outage (During the installation of the boiler scaffolding)..........2-10 1.3 Burner Front inspection (Upon completion of the boiler scaffolding) ...................2-10 2. Waterwall Team Member .........................................................................................2-12 2.1 Prior to the outage (within 2 weeks of start of the outage) ..................................2-12 2.2 Prior to the installation of the boiler scaffolding (after the throat scaffolding is installed) ..................................................................................................................2-12 2.3 Upon completion of the boiler scaffold................................................................2-12 2.4 Upon completion of the bottom ash scaffolding ..................................................2-13 3. Superheat and Reheat Team Member .....................................................................2-14 3.1 Prior to the outage (within 2 weeks of start of the outage) ..................................2-14 3.2 During the outage...............................................................................................2-14 4. Back-pass Team Member ........................................................................................2-16 4.1 Prior to the outage (within 2 weeks of start of the outage) ..................................2-16 4.2 During the outage...............................................................................................2-16 5. External Boiler Team Member .................................................................................2-18 5.1 Prior to the outage (within 2 weeks of the start of the outage) ............................2-18 5.2 During the outage...............................................................................................2-18

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3 BOILER RELIABILITY OPTIMIZATION PROJECT PHASE 1 AT DETROIT EDISON’S ST CLAIR PLANT – UNIT 7 AMERICAN ELECTRIC POWER’S BIG SANDY PLANT – UNIT 2 ....................................................................................................... 3-1 Executive Summary ........................................................................................................... 3-1 3.1 Introduction.................................................................................................................. 3-3 3.2 Findings and Observations .......................................................................................... 3-3 3.2.1 Programmatic and Data Sources Assessment ..................................................... 3-3 3.2.1.1 Maintenance Strategy................................................................................... 3-6 3.2.1.1.1 Findings ................................................................................................ 3-6 3.2.1.1.2 Recommendations ................................................................................ 3-7 3.2.1.2 Work Process............................................................................................... 3-7 3.2.1.2.1 Findings ................................................................................................ 3-8 3.2.1.2.2 Recommendations ................................................................................ 3-8 3.2.1.3 Predictive Maintenance Program and Technology.......................................3-10 3.2.1.3.1 Findings ...............................................................................................3-10 3.2.1.3.2 Recommendations ...............................................................................3-11 3.2.1.4 People.........................................................................................................3-11 3.2.1.4.1 Findings ...............................................................................................3-11 3.2.1.4.2 Recommendations ...............................................................................3-12 3.2.2 Failures and Root Causes...................................................................................3-12 3.2.2.1 Boiler Tubes ................................................................................................3-12 3.2.2.1.1 Failure Mechanisms, Actions taken and Recommendations ................3-14 3.2.2.2 Boiler Headers.............................................................................................3-18 3.2.2.2.1 Boiler Test and Inspection Plan Guideline............................................3-19 Purpose...............................................................................................................3-19 Definitions............................................................................................................3-19 Scope ..................................................................................................................3-19 Inspection and Test Plan Development ...............................................................3-20 3.3 Conclusions................................................................................................................3-21 3.4 Recommendations......................................................................................................3-21 Appendix 1: List of interviewees ........................................................................................3-23 Appendix 2: Example of a Typical Equipment Condition and Technology Matrix ...............3-24 Appendix 3: Remnant Life Assessment Flow Chart for Thick Section................................3-25

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4 BOILER RELIABILITY OPTIMIZATION PROJECT PHASE 1- ROOT CAUSE ANALYSIS AT ARIZONA PUBLIC SERVICES COMPANY’S FOUR CORNERS AND CHOLLA PLANTS.................................................................................................................. 4-1 FOUR CORNERS PLANT .................................................................................................. 4-1 4.1 Executive Summary...................................................................................................... 4-1 4.2 Introduction................................................................................................................... 4-2 4.3 Plant Description .......................................................................................................... 4-3 4.4 Incidents investigated ................................................................................................... 4-3 4.4.1 Unit 5 #4 Turbine Control Valve chatter - 197,471 Mwh lost................................ 4-4 Incident Description................................................................................................... 4-4 Root Cause Analysis Chart ....................................................................................... 4-4 4.4.2 Unit 3 Scrubber unit failure - 33,446 Mwh lost...................................................... 4-5 Incident Description................................................................................................... 4-5 Root Cause Analysis Charts...................................................................................... 4-6 4.4.3 Unit 4 Loss of Booster Fans

38,413 Mwh.......................................................... 4-7

Incident Description................................................................................................... 4-7 Root Cause Analysis Chart ....................................................................................... 4-7 4.4.4 Unit 3 Pulverizer Pinion & Bull Gear Failure - 34,881 MW Hrs. ............................ 4-7 Incident Description................................................................................................... 4-7 Root Cause Analysis Chart ....................................................................................... 4-8 4.4.5 Unit 3 Back-pass Flyash Erosion 39,378 Mwh ................................................... 4-8 Problem Description.................................................................................................. 4-8 Root Cause Analysis Chart ....................................................................................... 4-9 4.4.6 Unit 4 Air Pre-heater Failure 166,744 Mwh. ....................................................... 4-9 Problem Description.................................................................................................. 4-9 Root Cause Analysis Chart ....................................................................................... 4-9 4.4.7 Units 4 Flyash Erosion 39,288 MW/Hrs.............................................................. 4-9 Problem Description.................................................................................................. 4-9 Root Cause Analysis Chart ......................................................................................4-10 4.4.8 Unit 3 Turbine H.P. Nozzle Pluggage 100,628 Mwh..........................................4-10 Problem Description.................................................................................................4-10 Root Cause Analysis Chart ......................................................................................4-10 4.4.9 Unit 4 LP Exciter Field Failure 45,229 Mwh........................................................4-11 Incident Description..................................................................................................4-11 Root Cause Analysis................................................................................................4-11

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4.4.10 Unit 4 HP Exciter Field Failure 33,500 Mwh .....................................................4-11 Problem Description.................................................................................................4-11 Root Cause Analysis................................................................................................4-11 4.5

Findings ...................................................................................................................4-12

4.6 Conclusions.................................................................................................................4-12 4.7 Recommendations.......................................................................................................4-13 4.8 Appendix 1: Root Cause Analysis Charts ...................................................................4-13 CHOLLA PLANT ...............................................................................................................4-26 4.9 Executive Summary.....................................................................................................4-26 4.10 Introduction................................................................................................................4-27 4.11 Plant Description .......................................................................................................4-28 4.12 Incidents Investigated................................................................................................4-28 4.12.1 Mechanical Dust Collector Retrofit 41,146 Mwh. ..............................................4-29 Problem Description.................................................................................................4-29 Root Cause Analysis Chart ......................................................................................4-29 4.12.2 Unit One ID Booster Fan Bearing Failures 7,544 Mwh. ....................................4-30 Incident Description..................................................................................................4-30 Root cause Analysis Chart .......................................................................................4-30 4.12.3 Unit one Turbine Thrust Trips 9,971 Mwh. .......................................................4-31 Incident Description..................................................................................................4-31 Root Cause Analysis Chart ......................................................................................4-31 4.12.4 Unit Two “A” Booster ID Fan Motor Failure 30,464 Mwh. ................................4-32 Incident Description..................................................................................................4-32 Root Cause Analysis Chart ......................................................................................4-32 4.12.5 Unit Four Air Pre-heater Pluggage 48,740 Mwh. ..............................................4-33 Problem Description.................................................................................................4-33 Root Cause Analysis Chart ......................................................................................4-34 4.12.6 Unit Four Scrubber Problems 76,917 Mwh.......................................................4-34 Problem Description.................................................................................................4-34 Root Cause Analysis Chart ......................................................................................4-34 4.12.7 Unit Four High Opacity Shutdown 42,731 ........................................................4-35 Problem Description.................................................................................................4-35 Root Cause Analysis Chart ......................................................................................4-35 4.12.8 Unit Two Waterwall Tubes Hydrogen Damage 188,944 Mwh...........................4-35

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Problem Description.................................................................................................4-36 Root Cause Analysis Chart ......................................................................................4-36 4.12.9 Unit Two Cable Tray Fire 28,899 Mwh. .............................................................4-36 Problem Description.................................................................................................4-36 Root Cause Analysis Chart ......................................................................................4-37 4.12.10 Unit Four Air Pre-heater Guide Bearing Fire 6,099 Mwh. ...............................4-38 Problem Description.................................................................................................4-38 Root cause Analysis Chart .......................................................................................4-38 4.13

Findings...............................................................................................................4-39

4.14

Conclusions.........................................................................................................4-40

4.15

Recommendations...............................................................................................4-40

4.16 Appendix 2 ...............................................................................................................4-40 Root Cause Analysis Charts (Excel file)........................................................................4-40 5 BOILER RELIABILITY OPTIMIZATION PROJECT PROGRAM AUDIT AT HAWAIIAN ELECTRIC COMPANY........................................................................................ 5-1 5.1 EXECUTIVE SUMMARY ............................................................................................. 5-1 5.2 Introduction.................................................................................................................. 5-1 5.3 Findings....................................................................................................................... 5-2 5.3.1 Boiler Reliability Optimization Project Plan........................................................... 5-2 5.3.2 Project Activities................................................................................................... 5-2 5.3.2.1 BTFR/CCI Program ...................................................................................... 5-2 5.3.2.2 Streamlined Reliability Centered Maintenance ............................................. 5-3 5.3.2.3 Root Cause Analysis .................................................................................... 5-3 5.3.3 Condition based data collection ........................................................................... 5-4 5.4 Conclusions................................................................................................................. 5-4 5.5 RECOMMENDATIONS ............................................................................................... 5-4 Appendix 1: Boiler Reliability Optimization Storage Plan .................................................... 5-7 Appendix 2 ........................................................................................................................5-10 Appendix 3 ........................................................................................................................5-11 List of Typical Headings that Appear in a Policy or a Procedure ...................................5-11

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LIST OF FIGURES Figure 1-1 Maintenance Optimization Program ....................................................................... 1-4 Figure 1-2 Big Sandy benchmarked against Industry Best Practice ........................................ 1-5 Figure 1-3 Work Process ........................................................................................................ 1-6 Figure 1-4 Work Process Model.............................................................................................. 1-7 Figure 1-5 Task Scatter Diagram - Value to Cost ...................................................................1-31 Figure 1-6 Accumulated Value verse Cost .............................................................................1-31 Figure 3-1 Spider Chart........................................................................................................... 3-4 Figure 3-2 ..............................................................................................................................3-13 Figure 4-1 Unit 5, #4 Control Valve 197,471 Mwh ..................................................................4-14 Figure 4-2 Unit 3 Scrubber Problems 33,446MW/Hrs.............................................................4-15 Figure 4-3 Unit 3, Scrubber Problems 33,446MW/Hrs............................................................4-16 Figure 4-4 Unit 3 Scrubber Recycle Pump Problems 33,446MW/Hrs.....................................4-17 Figure 4-5 Unit 4, Loss of Booster Fans, 38, 413 MW/Hrs .....................................................4-18 Figure 4-6 Unit 3 Pulverizer Pinion and Bull Gear Failures, 38,881 MW/Hrs. .........................4-19 Figure 4-7 Unit 3 Backpass Flyash Erosion 39,378 MW/Hrs. .................................................4-20 Figure 4-8 Unit 4 Air Preheater Failure 166,744 MW/Hrs. ......................................................4-21 Figure 4-9 Units 4 and 5 Backpass Flyash Erosion ................................................................4-22 Figure 4-10 Unit 3 HP Turbine Nozzle Plugging, 100,628 MW/Hrs.........................................4-23 Figure 4-11 Unit One, Mechanical Dust Collection Retrofit, 41,146 Mwhs..............................4-41 Figure 4-12 Unit One, ID Booster Fan Bearing Failures, 7,544 Mwhs ....................................4-42 Figure 4-13 Unit One Turbine Thrust Trips, 9,971 Mwhs........................................................4-43 Figure 4-14 Unit Two, A Booster ID Fan Motor Failure, 30,464 Mwhs....................................4-44 Figure 4-15 Unit Four, Air Preheater Pluggage, 48,740 Mwh .................................................4-45 Figure 4-16 Unit Four Scrubber Outage, 76,917 Mwh ............................................................4-46 Figure 4-17 Unit Four, High Capacity Shutdown, 42,731 Mwh ...............................................4-47 Figure 4-18 Unit Two Waterwall Tubes Hydrogen Damage, 188,944 Mwh.............................4-48 Figure 4-19 Unit Two Cable Tray Fire, 28,899 Mwh ...............................................................4-49 Figure 4-20 Unit Two Cable Tray Fire March 1999, 28,899 Mwh............................................4-50 Figure 4-21 Unit Four Air Preheater Guide Bearing Fire, 6,099 Mwh .....................................4-51

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LIST OF TABLES Table 1-1 Component Description and Engineering Identification Number.............................1-18 Table 1-2 Phase 2 Recommendations and Actions Taken .....................................................1-36 Table 3-1 Boiler tube Failures, Causes and Recommended Action........................................3-15 Table 3-2 Typical Header and Steam Drum Problem Areas ...................................................3-18 Table 4-1 Cholla - Megawatt-hour loss summary report-fourth quarter 1999..........................4-28

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1 BOILER RELIABILITY OPTIMIZATION PROJECT PHASE 1, 2 & 4 AT AMERICAN ELECTRIC POWER’S BIG SANDY PLANT – UNIT 2

1.1

EXECUTIVE SUMMARY

Preparing for competition American Electric Power (AEP) requested EPRI to undertake a Boiler Reliability Optimisation project at their Big Sandy Plant. An availability of 95 % during peak periods – May through August and 90 % for the remainder of the year was set as a corporate target. Meeting this target would give Senior Management the assurance that they could compete successfully in the power generation market. The project focussed on the long-term integrity of the water and steam touched tubing within the boiler envelope, training on EPRI’s tube failure reduction program and the provision of a EPRI’s Boiler Maintenance Workstation (BMW) software package for trending and tracking tube failure data and information. The project scope also included training on EPRI’s Streamlined Reliability Centered Maintenance software using the fuel system as an example. An outage task prioritisation model – Risk Evaluation and Prioritisation (REAP) was used to prioritise the tasks identified for the Unit 2 scheduled outage in April 2000. This project, Phase II of EPRI’s Boiler Reliability Optimisation project, commenced in March 2000 and was finalised with the installation of the BMW software and user training in July 2000. Phase I was completed with the issuing of the final report in January 1999. Between March and July 2000 a number of visits to the plant were made to interview and collect data for analysis. This report focuses on the development of a failure defense plan for the water and steam touched boiler tubing and contains a number of recommendations. The main recommendation are listed below: 1. In the Technical and Organisational Assessment section there are a number of specific recommendation. Collectively these are related to improving planning and scheduling of boiler maintenance work. Thus, a high level recommendation would be to align the boiler maintenance strategy i.e. frequency and duration of scheduled outages and inspection scopes of work to the overall station performance goals of 95% availability during peak periods. Specific boiler availability targets should be developed relating to the number of tube leaks per year. One tube leak per unit per year, no repeat failures, no failures because of sootblower erosion are considered reasonable targets. The strategy and performance targets

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EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

should be compiled into separate plant directives, which are reviewed annually for effectiveness and appropriateness. 2. To repair and calibrate all boiler instrumentation critical to the efficient and effective operation of the boiler. This includes air, gas, water and steam temperatures and pressures and reheater and superheater metal temperatures. 3. The installation of on-line water and steam chemistry instrumentation and the establishment chemical performance index. This index can the be used in a proactive way to ensure compliance to EPRI water and steam chemistry guidelines. 4. To prepare detailed inspection plans based on the tasks identified in the Boiler Failure Defence Plans presented in this report. These inspection plans should be loaded into the CMMS. This would facilitate the development of a scheduled and or forced outage plan at short notice. 5. Once the installation and the user training on the Boiler Maintenance Workstation (BMW) have been completed, the BMW database needs to be updated with all the history of previous tube failures. This will enable tube leaks and repairs to be tracked and trends to be established. This will also assist in formulating focussed boiler inspections plans. The plant has knowledgeable and skilful people. Given time, management support and coaching to implement the recommendations highlighted in this report the plant team will achieve the goals identified by Senior Management.

1.2

INTRODUCTION

During the period 1997 to 1999 AEP – Big Sandy Plant’s availability loss was 7.9 % of which 4.2 % can be attributed to boiler tube failures. The causes of these failures varied however the dominate repeat failures were due to fly ash erosion, oxygen pitting, long term over heating and firing side corrosion. During 1999, in excess of $2.0 million dollars of lost revenue can be attributed to outages on Unit 2. Concerned about this loss and a possible future increase in the Equivalent Forced Outage Rate (EFOR) lead senior management at Big Sandy Plant to request assistance from EPRI. Participation in EPRI’s Boiler Reliability Optimization program was proposed. The program consists of several customised Boiler Reliability Optimisation Projects. Each project consists of four phases that involve EPRI technical staff, with participation from the plant’s operating, maintenance and engineering support staff. Each phase builds on the strengths of the preceding phase. These phases are: •

Phase I - Technical and Organisational Assessments

•

Phase II - Development of a Boiler failure defence plan

•

Phase III - Implementation of a failure defence plan

•

Phase IV - Continuous Improvement and Process automation

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EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

AEP – Big Sandy Plant’s management chose to limit their participation to elements of Phase I. This was completed in January 1999. Satisfied with the results, AEP – Big Sandy management requested EPRI to continue with the program, i.e. complete Phase I – Technical and Organisational Assessment, and implement a tailored Phase II. Phase II was limited to only the water- and steam- touched boiler tubing. This report discuss the findings of this limited scope project.

1.3

SCOPE OF WORK

This consisted of the following activities: 1.1 Complete Phase I – Technical and Organisational Assessment. 1.2 Develop a Failure Defence Plan for water and steam touched tubing. 1.3 Provide Streamlined Reliability Centered Maintenance (SRCM) software and training, and analyse two systems. 1.4 Evaluate and prioritise all outage tasks on an upcoming outage, using EPRI’s – Risk Evaluation and Prioritise Program. 1.5 Provide Boiler Tube Failure Reduction and Cycle Chemistry Improvement training. 1.6 Supply, install and provide training on EPRI’s Boiler Maintenance Workstation (BMW) software for tracking boiler tube failure information.

1.4

FINDINGS AND OBSERVATIONS

1.4.1 Phase I and II - Technical and Organisational Assessment A maintenance process assessment was conducted as a part of the work performed in the Boiler Reliability Optimization Project. The purpose is to understand the current processes, technologies, organizational strengths and weaknesses, and plant people to design a manageable change within the implementation plan. Data was collected and evaluated and benchmarked against best practices identified and tailored by EPRI. The assessment team spent one week on site interviewing a cross section of plant staff to determine how boiler maintenance work is identified and performed. The team focused on four main topics namely Work Process, Work Culture/Management, Technology and People. The data and information obtained was compared to industry best practice as identified in the EPRI “Best Practice”, to identify opportunities for improvement. This section of the report presents the findings and recommendations to align AEP - Big Sandy Plant’s work process with Best Practice i.e. to move boiler maintenance from a reactive mode to one that is planned. The benefits of moving towards a more planned approach will be seen in reduced O&M cost and improving boiler reliability. 1-3

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

With this information and available resources AEP - Big Sandy Plant can become the “Best Practice Plant” within the AEP organisation for which it has been striving to become. Given time, management commitment and coaching, the plant team has the vision and can successfully lead this plant into full implementation of the boiler reliability optimization processes. From the data and interviews, strengths and weaknesses were plotted on a spider chart and recommendations formulated For a condition-based, highly planned, maintenance optimization program to be effective, it must integrate the Work Process, Management and Work Culture, Technologies, and the People into the total operation of the pant. Each category is equally important to the success of the program, as illustrated in Figure 1-1.

E C

P E O

O R

P LE

P S S

T N

TE C

E M

H

E G A

N O

N A

LO G Y

M

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Figure 1-1 Maintenance Optimization Program

To derive maximum value, all four categories and their sub-categories must be integrated to form one cohesive program. The key sub-categories are listed below: Work Process

Work culture/Management

Work Identification

Setting Goals

Leadership

Work Planning

Organisation

Accountability

Work Execution

Communications

Work Close-out

Global Metrics

Technology

People/Skills

Work Management System

Training

Qualifications

Diagnostic Technologies

Utilization

Communication

Integration Tools/Techniques

1-4

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

Figure 1-2 is the benchmarked Spider chart utilizing the Power Industry as the source database. The outer circle at 8.0 represents best practice elements found in industry. The inner circle at 5.8 is the industry norm. Big Sandy Plant was evaluated and found to be at or near the industry norm. Big Sandy Plant has second quartile performance when compared to industry benchmarks. Information Integration, Work Execution, Metrics, and Utilization elements are slightly below industry norms. It should be noted that overall, Big Sandy has relatively equal strengths throughout most elements. Information Integration can be improved in accordance with some of the recommendations coming from this project. Metrics are also contained in this project. Utilization will improve as more effective planning and a scheduling processes are put into place. Big Sandy staff given the direction has the strengths that are necessary to succeed.

P M B as is Q ualific ation Com m unic ation Intra

8.00 7.00 6.00

W ork Identific ation W ork Control

5.00

Utiliz ation

W ork E x ec ution

4.00 3.00

Training

W ork M anagem ent S y s tem s

2.00 1.00 0.00

CB M Tec hnologies

B enc hm ark ing

S etting G oals

Inform ation Integration Tools

Com m unic ation Inter M etric s Leaders hip

Continuous Im provem ent A c c ountability O rganiz ation

Figure 1-2 Big Sandy benchmarked against Industry Best Practice

1.4.1.1 Work Process For a maintenance program to function cost effectively, all equipment maintenance work should proceed through four distinct steps – Maintenance Strategy, Work Identification, Work Control (Planning and Scheduling) and Work Execution (including feedback) as shown in Figure 1-3.

1-5

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

Work Flow Process PM Basis

CBM

Planning Scheduling

Work Activities

Maint. Strategy

Work ID

Work Control

Work Execution

Feedback CBM

Figure 1-3 Work Process

Using the Work Process Model - Figure 1-3 the assessment team produced a detailed model that highlights the areas of responsibilities. These are shown in Figure 1-4.

1-6

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

PM Basis Change Control

PM Basis

RCA

Boiler Specialist

PM's Planners

Information Integration & Decision

CBM Coordinator Technology Owners

Boiler Specialist CAP Technology Owners, CBM Coordinator, RCA Process Owner

CD's, PR's Boiler Specialist

Work Mgmt System Operators

Work Order Generation

CM's

Improvement

Work Identification

CBM Data Collection & Analysis

Initiator

Planning

Planners Boiler Specialist

Work Control

Planners

Scheduling

Work Execution

Work Execution

Boiler Specialist

Boiler Specialist Craft

Post Maintenance Testing

Close Out

Boiler Specialist Boiler Specialist, CBM Coordinator

Boiler Specialist Planners, Craft

Figure 1-4 Work Process Model

Maintenance Strategy

The starting point for developing a maintenance strategy is to first determine a maintenance objective. An objective should be quantified in terms of availability and performance. These requirements should be determined jointly between the Maintenance and Operating and or the 1-7

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

Production Departments. Maintenance Management is then in a position to determine the best mix of maintenance techniques to used, resources requirements and the costs thereof. A maintenance strategy is then developed from these agreed objectives. It defines the process for identifying and achieving sound operational objectives, selecting the maintenance approaches, monitoring performance and providing effective management control. The strategy therefore consists of a management and technical strategies. The Management strategy defines how the business management skills are used to integrate people, policies, equipment and practises to identify improvement opportunities. The technical strategy states how the technical knowledge and experience are used to identify and implement the best proactive maintenance, repair, service and replacement of all equipment in line with AEP’s business performance objectives. The maintenance strategy is built primarily from the preventive maintenance (PM) basis that exists at the plant. The aim is to develop an optimized set of PM tasks that will ensure Big Sandy Plant - Unit #2 Boiler will achieve its reliability targets. Findings:

•

The Boiler Specialist owns the Boiler System PM Basis.

•

The Boiler System PM contains most of the inspection requirements, physical improvement PM’s, etc for work to be performed at various intervals on the various boiler components.

•

Boiler Specialist ensures that the technology owners complete their inspection PM’s in accordance with the PM Basis for the Boiler.

•

The Boiler Specialist actively participates in the Root Cause Analysis performed on the boiler events.

•

Operating procedures have not been reviewed for some time and are out of date with current practice.

Recommendations:

1. The PM Basis must be reviewed and updated to take into account the failure mechanisms identified during the past outage inspection. 2. The Boiler Specialist should have an Operating Department counterpart who would be responsible to review and update and align operating procedures to current practice. 3. Boiler tube failures/Root Cause Analysis should be tracked and trended. 4. The boiler inspection plans need to be updated to take cognise of the change in the frequency of boiler periodic outages. Work Identification

Work on equipment is identified from one of the following three sources of information:

1-8

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

Corrective Maintenance Repair tasks (CM) - tasks as a result of loss-of-performance, component breakdown, or catastrophic equipment failure that must be attended to immediately. These tasks are generally not scheduled. Preventive Maintenance Tasks (PM) - tasks that are time based recurring work that is deemed necessary to keep equipment in optimum running condition. Implementation of this work should be both planned and scheduled. Predictive Maintenance tasks (CD) - tasks that are condition directed based on information derived from a variety of condition information sources. These sources are identified and controlled on an E&CI matrix. All condition directed efforts to maintain equipment should be both planned and scheduled. Findings:

•

Prioritization seems to be “fix it now” or “fix it later”. When dealing with boiler issues, which are mainly outage tasks, “value of work” concepts should replace “prioritization”.

•

The work process is split into two separate planning windows. One for emergency work i.e. works requiring immediate attention and the other for normal work, which passes through a daily scheduling activity.

•

Emergency maintenance work is discussed between operations and maintenance leaders, while all other work orders (CM, PM and CD) are reviewed, selected and assigned to be executed by the PSL’s.

•

The various Crafts persons walk the job down and plan job requirements.

•

There is no formal root cause analysis process in place to ensure failures are thoroughly investigated to prevent recurrence.

Recommendations

1. A formal RCA program will result in additional information valuable in managing the Boiler. 2. The roles and responsibilities of the PdM Co-ordinator should be clearly defined and should include the following aspects: – Ensure data collection routes and analyses are performed on schedule. – Conduct pre-outage inspections. – Post-maintenance testing. – Working with system owners to integrate condition based data/information – Develop and maintain a condition status report. – Document case histories and cost-benefit calculations. – Ensure PDM results are used to moderate the PM program – extend periodicity, PM activity modifications, removing redundant PM etc. Thus taking full advantage of the CBM program. 1-9

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

3. Infrared thermography should be used on the boiler to identify casing leaks, valve passing etc. 4. Develop an Equipment and Condition Indicator matrix (E&CI) for all critical boiler equipment/components such as in Figure 1-5. This will assist the equipment owner to assessing the condition of equipment under his control. Work Control

The work control function shown in Figure 1-3 is an important function when focussing on reducing O&M costs and simultaneously increasing reliability One of the activities when optimizing work control is to review and purge if necessary the corrective maintenance (CM) component of the workload. CM negatively impacts the ability to meet performance goals of reducing O&M cost performance and Equivalent Forced Outage Rate (EFOR). Decreasing the amount of CM does not mean that equipment failures will no longer occur. Rather, it means that management will be actively involved in deciding whether the best economic decision for the station is to allow a specific component, with “known problem conditions” to run-to-failure; or, should plans be established to effect the repair at a convenient time. Findings

•

The frequency of major outages has been changed to every 3 years with an inspection/minor repair outage of short duration at approximately 18 months.

•

Outage work scopes are agreed to prior to the outage. However, a considerable amount of outage work is uncovered during the outage with the inspections. Review of the data available prior to the outage indicates some of the inspection results could have been predicted and repairs planned.

•

Planners prepare work packages for critical work orders.

•

Boiler Specialist serves the role of QA/QC for all boiler activities whether performed by AEP forces or contractors.

•

Forced outages are planned, reviewed, and published once per month. Not all items on the forced outage list are fully planned and trigger ready.

•

Forced outage plans are coded in the PIMS and maintained by planners.

Recommendations

1. In order for the 3 yearly boiler outages to be successful a detailed inspection plan needs to be developed by the boiler specialist to all known and potential problem areas are adequately inspected and repaired to ensure a high availability between periodic outages. 2. Develop a four-week rolling scheduling process for all maintenance to assure high utilization of resources. 1-10

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

3. Include post maintenance testing requirements into the planning process. This is a must for most CD work orders. Work Execution

This is the final activity and includes work close-out. Findings

•

AEP support personnel and contractors do a reasonable job judged by the small number of QA/QC issues raised and re-work done.

•

Pad welding and temporary repairs are tracked and noted to enable final repairs to be done during a suitable planned outage.

•

Limited post maintenance testing is done.

•

Work close out is performed by the PSL’s and at times without the knowledge of the Boiler Specialist.

Recommendations

1. System owners and the Boiler Specialist should review close-out information for effectiveness.

2. Compile a management directive identifying the minimum acceptable standards to be complied with when performing boiler maintenance or repair work. This would include such statements as every tube leak/failure should be investigated, pad welding should be discouraged etc. 1.4.1.2 Technologies An Optimisation program is made up of people, management systems, component owners, technology specialists and predictive maintenance tools or equipment. The key predictive maintenance tools used in a Boiler Reliability Optimisation project are infrared thermography, vibration, oil analysis, ultra-Sonics and plant process data and information such as air, gas water and steam temperatures and pressures, metal temperatures and water and steam chemistry data. Equipment owners and technology specialists collect and collated data on various boiler components. This data is organised and presented in an Equipment and Condition Indicator Matrix. The matrix specifies the predictive maintenance technology to be used, the equipment to be monitored and when the data should be collected. The “how”, “what”, and “when” of condition data analysis is based on exceeding preestablished threshold levels and this information is presented in an “Event Report” and in an “Asset Condition Status Report”. Analysis of the data and diagnosis of the cause incorporates all available information including diagnostic data from all related technologies, operating conditions from process data, operating log information, maintenance history, design information 1-11

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

and knowledge of the experienced personnel. Condition Assessment Reports should list, by asset, any marginal or critical determinations by each technology, and include recommendations for action based on the integrated analysis of the data. The “what”, “how” and “when” of action is based on analysis of the data, and this establishes what action is to be taken to correct the anomaly, how the work should be accomplished, and when the work needs to be done to prevent an unplanned failure. Determining the threshold levels to declare an event is based on technology standards and deviations from baselines for the monitored equipment. Therefore, it is necessary to establish baselines for all equipment in the PDM Program, and re-baseline the equipment following any related repairs by performing post-repair acceptance testing. Findings

•

Draught gauges and metal temperature thermocouples were found to be defective.

•

No on line sodium analysers for continue monitoring of steam and water quality was available.

Recommendation

1. Repair and calibrate all essential/critical boiler instrumentation. Work Management System Findings

•

PIMS meets the basic needs of the organization and has the capability to capture boiler inspection data.

Recommendations

1. PIMS should be expanded to capture all boiler inspection data Maintenance & Diagnostic Technologies Findings

•

NDE Inspections are consistent with industry practice

•

Limited boiler performance testing and trending of results is done.

Recommendations

1. Establish technology owners with responsibilities to include condition analysis. 1-12

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

2. Need to have a more comprehensive PDM reports as health report not exception reports. Information Integration

The key to utilizing the condition-based information in an effective manner is the ability to quickly access the information and to trend the data over time to enable a prediction of when work should be performed. EPRI’s Boiler Maintenance Workstation (BMW) is one such system, which can be used to track and trend boiler tube failure data and information. Another useful tool is the WEB based “Condition Status Report” software. The software has the capability to store equipment data and information, capture recommended actions, and report on the overall condition of the critical plant equipment in detail. From this information, management can determine whether the overall condition of the plant is deteriorating or improving by tracking the history and costs of the equipment. Decisions made and or action taken and work order numbers are also recorded. Post maintenance test results are recorded to determine whether the diagnosis and maintenance was appropriate. Findings

•

There is no integrated condition status reports produced on the boiler or in fact any other part of the plant.

Recommendations

1. Formalise monthly Boiler Condition Based Maintenance (CBM) meetings. Attendance by Equipment/Component and Technology owners, PdM Co-ordinator, Operating and Maintenance staff and the Boiler Specialist to make maintenance decisions based on the condition of the equipment/component. Once a year, perhaps prior to any budgeting cycle, the Boiler Specialist should present a Boiler Failure Defence Plan – indicating the current condition, short and long term activities/tasks that need to be undertaken to ensure boiler reliability. 2. Case histories and cost benefits analysis of using PDM technologies should be document either in the BMW or PIMS databases. 1.4.1.3 Management and Work Culture The objective is to develop a work environment in which an effective combination of people, work processes and technologies are used to achieve the overall business goals. To achieve this management must exhibit leadership i.e. the ability to delegate responsibility and authority, and to hold people accountable for their performance. Leadership also includes defining organisational direction, setting realistic measures and targets and communicating these through out the organisation. Measures (metric) can be lagging – measure the output of the process or leading a measure of the effectiveness of the elements of an organisation.

1-13

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

Recommendations

1. Roles and responsibilities must be clearly defined and understood by the individuals in the plant. 2. Measures (metrics) and targets need to be developed for the boiler. These metrics could be the following: – # of tube leaks per year –suggest one tube per boiler per year, – no tube leaks caused by sootblower erosion, – no repeat boiler tube leak failures, –

boiler availability,

– boiler forced outage rate as a contribution to the overall forced outage rate and – long term plant health measures like a thermal index which is a measure of the equivalent number of operating hours or extra life consumption experienced by boiler headers as a result of operation at metal temperatures in excess of design. These measures and targets should be specific, measurable, achievable within a specified period of time and reasonable and should be communicated through out the organisation. 3. An annual review of the maintenance program should be undertaken to determine its effectiveness i.e. the right technologies are being applied to the right assets at the right frequency to meet the overall business objectives and maintenance strategy. These assessments should validate the following questions: – Were there unexpected or premature failures that were not detected by at least one technology? This could result in applying PDM to an asset that was not previously being monitored, or increasing the frequency of monitoring on a previously established route, or indicate the need for a new PDM technology, or readjustment of a CM Task. – Were failures occurring that were detected but without sufficient time to take action? This could result in adjustment of alert threshold levels. – Were there long periods of operation without any developing problems that contained numerous condition data sets? This could result in decreasing the frequency of monitoring. – Was a technology ineffective in detecting an emerging problem? This could result in removal of an ineffective technology from the program. – Did the costs, measured in dollars, exceed the benefits of the program? This could signal the need to redesign the program. – Was all of the data collected analyzed? – Was action taken on detected events? This could result in a refocus of the program leaders and a re-aligning of sponsors. – Did the program fail to meet the established goals? This could result in a redesign of the program. 1-14

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

4. Consideration should be given to having an annual Boiler Specialist Meeting and forming a Boiler Specialist’s Users Group. This will aid in the transferring of information and knowledge amongst the Boiler Specialists within the AEP organisation. 1.4.1.4 People Human beings are an important asset. Their reliability – “making and keeping commitments” has a huge impact on plant reliability. All equipment can in some way be traced back to human beings. If human beings are reliable, your equipment will be reliable. Findings:

•

Training meets the basic needs of the plant. New equipment training for the craft is lacking.

•

Communications among PSL’s is good.

•

Good team work.

•

Utilization is lower than expected. This is as a result of inadequate planning and staff has to wait for other disciplines.

Recommendations

1. Consider providing Level of Awareness training (LOA) training for the entire staff on Plant Maintenance Optimization. 2. Re-train all PIMS users on the details of PIMS and how best to it. 1.4.2 Failure Defence Plan – Water and Steam Touched Tubing To have an effective defence plan, it is important to uniquely identify – Equipment Identification Number (EID) all the various sections and/or components to be included in the Defence Plan. This number is then used in the Computerised Maintenance Management System (CMMS) to track inspection details and trends. Table 1-1 shows all the various tubing sections of the boiler. Table 1-2 represents the Failure Defence Plans for the various sections of tubing listed in Table 1-1. These plans were developed from a detailed boiler inspection and discussions with the Boiler Specialist. They identify the failure mechanisms, direct causes, short and long-term actions to be taken to prevent or at least minimise the failure and or damage. These action plans also give the various NDE and NDT techniques to be used to identify and quantify damage by the various failure mechanisms and the criteria to be used when using performing boiler maintenance and or repair work. The following failure mechanisms were identified as being active in the various tubing sections: •

Sootblower erosion

•

Fly ash erosion 1-15

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

•

Fire side corrosion

•

Corrosion fatigue

•

Dissimilar metal welds

•

Oxygen pitting

•

Short term overheating

•

Long term overheating

Findings Economiser

•

No significant tube failures have been experienced in the economizer.

•

The economizer is of the ringed tube type and suffers from pluggage especially on the North side. Baffles have been installed to equalize gas flow and minimize ash pluggage.

•

Clean air velocity tests have not been done to verify the correct position of the baffles.

•

Plans are in place to open up gas passes to minimize pluggage.

•

One leak was encountered last year due to flyash erosion. Tube shields were installed 2 years ago to minimize flyash erosion.

•

No header cracking has been noted.

Waterwalls

•

The ash hopper slope has channelling between the membrane and the tube in the tube material. About 82 tubes have been found with some amount of material loss due to slag erosion. No leaks have been attributed to this problem. Slagging of these tubes has not been a problem since changing to low NOx burners in 1994.

•

The sidewalls have experienced severe wall loss since conversion to low NOx burners. Portions of the sidewalls were overlaid in the fall of 1999 with Type 312 SS to mitigate this problem. No further testing has been performed since this inspection. The unit has only experienced one trip since the outage and did not stay off line long enough to allow for testing. This overlay will be inspected in March and an additional 500 sq. ft. will be overlaid.

•

Since the overlay outage, testing has been performed using 3/8” tubing inserted through the wall membrane during the outage on the left side. Initial measurements showed no oxygen during operation. Burner modifications and adjustment have raised the oxygen content to a positive level. Plans are to install several more taps into the firebox during the next outage to help facilitate future burner adjustments. Currently measurements are performed manually on the sample positions. Automatic sampling should be developed and tied into the database with feedback to controls or maintenance.

•

The upper furnace has experienced no problems.

1-16

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

•

The center division wall has experienced no problems.

•

One failure has been reported in the roof due to erosion from a casing leak. The attic has since been pressurized and no more leaks have been observed.

•

Several areas of casing/membrane leaks were noted in the upper firebox. These should be repaired at the next outage to prevent erosion from ash or casing damage from heat.

•

Screen tubes have had some erosion from flyash and sootblowers. Tube shields have been tried with no success. The screen tubes are carbon steel with a wall thickness of 0.300”.

•

Some pad repair or weld overlay work is expected next outage. More information is needed on this problem including UT thickness readings. This wear is probably from water in the sootblowing system but could be aggravated by large coal size, late combustion and LOI. Plant staff indicated coal mill fineness tests were performed twice a year.

•

No severe problems were noted with the waterwalls other than the wastage due to low NOx burners. This is being addressed with the weld overlay and burner adjustments.

Platen Superheat

•

Approximately 300 DMW are located in the platen superheat section and are scheduled for replacement using EPRI developed technology.

Finishing Superheat

•

Some sootblower erosion has occurred in this section. Some tubing has been pad welded to restore minimum wall. No leaks have occurred due to erosion. Alignment handcuffs in this area are in need of repair. Current plans are to install heavier handcuffs next outage to keep tubing in alignment and avoid flyash erosion.

•

No plugging problems have been noted in this area except when sootblowers are out of service. The tubing in this area was too long when installed and hit the slope when hot. This tubing has been shortened. No operational problems are noted at this time.

First Reheat (High Pressure)

•

This area probably contains the most damage of any part of the boiler. Past lay-up procedures allowing moisture to condense in this area has led to oxygen pitting in the horizontal sections.

•

Current lay-up procedures of using nitrogen blanketing, drying out with dried air, or heating up to dry after coming off line are believed to have stopped the damage.

•

The second or third tube in the bundle has suffered from long term overheat – fish-mouth type failures. Other AEP 800 MW plants have replaced this tubing with P91 material. A life assessment using EPRI TUBELIFE and other NDE should be performed on this tubing. If tubing requires replacement, T91 or other new upgraded material such as T23 should be used.

•

Damage is also occurring in this section from vibration fretting of the “cane” tube spacers. Egg shaped spacers are placed vertically between tubing bundles and turned until tight. Then 1-17

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

straps are welded between adjacent spacers to hold in place. No attachment is made to the boiler tubing. During operation these spacers become loose and allow the tubing to vibrate, fretting the tubing and causing leaks. AEP is currently not replacing spacers when they fall out. Second reheat (low pressure)

•

The outlet header and top two sections of tubing have been replaced with SA 213 T-91 material in the highest temperature areas. No other leaks or failures have occurred in this area.

Spray Attemperators

•

The nozzles have been inspected and replaced. The liner has been replaced on the Main Steam Attemperator. This equipment is currently on a seven-year inspection cycle. This inspection frequency should be monitored and adjusted as required. Liners should be inspected with boroscope. Nozzles should be removed and inspected. Water stop valves should be inspected to prevent thermal shocks to the superheat and reheat piping.

Recommendations

1. Develop a series of inspection tasks using the data and information identified in the Failure Defence Plans in Table 1-2. These Defence Plans need to be reviewed and converted into specific action tasks with allocated responsibilities for completion. The inspection type tasks need to be formatted and standardised and put into the Computerise Maintenance Management System database for reference and future boiler inspections. Table 1-1 Component Description and Engineering Identification Number #

1-18

EID

DESCRIPTION

1

5512230200 ECON 1

Economiser Tubes U2 – 1 Reheater side

2

5512230200 ECON 2

Economiser Tubes U2 – 2 Reheater side

3

5512240200 DIVWL

Waterwall Tubes U2 – Division wall

4

5512240200 LFFWL

Waterwall Tubes U2 – Lower furnace front wall

5

5512240200 LFSWL

Waterwall Tubes U2 – Lower furnace side walls (incl. 40 tubes front and rear)

6

5512240200 LFRWL

Waterwall Tubes U2 – Lower furnace rear wall

7

5512240200 UFRWL

Waterwall Tubes U2 – Upper furnace rear wall

8

5512240200 UFFWL

Waterwall Tubes U2 – Upper furnace front wall

9

5512240200 UFSWL

Waterwall Tubes U2 – Upper furnace side walls

st

nd

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2 10

5512243200

Screen Tubes U2 – Furnace

11

5512241200 HRAT

Heat Recovery Area (HRA) U2 – Incl. Side, front and rear walls, partition wall and roof

12

5512241200

Aperture Tubes U2 – Incl. Side walls, floor and screen

13

5512240200 FROOF

Waterwall Tubes U2 – Furnace roof tubes

14

5512210200

Platen Superheater

15

5512212200

Finishing Superheater

16

5512220200

1 Reheater

17

5512222200

2 Reheater

st

nd

1-19

EPRI Licensed Material

Components 1 through 16 (all components within sootblower range)

Malfunction of a sootblower or 1 the sootblowing system because of incorrect operation and/or inadequate maintenance (control logic sequence, operating temperature and pressure, mechanical misalignment, drainage pipe slopes etc)

1-20

•

Preventive Measures Short/Long Term

NDE Detection Technique

Sootblower Erosion

L M N O P Q #

Fire Side Corrosion

K

Falling Slag Erosion

Caustic Gouging

J

Coal Particle Erosion

Acid Phosphate Corrosion

I

Short Term Overheating

Supercritical Waterwall Cracking

Low Temperature Creep

Corrosion Fatigue

Fatigue

Acid Dewpoint Corrosion

Pitting

A B C D E F G H

Hydrogen Damage

#

Fly Ash Erosion

Possible Causes

Thermal Fatigue

Corrosion Corrosion

Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

CRITERIA

• Confirm mechanism by VT inspecting tubes around and in /EMAT the immediate vicinity of the blower.

• Check for tube wastage - flat and/or 'shiny' surfaces or if the boiler has been washed check for a fresh layer of rust and gouges from steam cutting.

• Determine the extent of the UT erosion by mapping the tube thickness in the affected ares. Compare with previous readings and calculate an erosion rate and trend results if applicable.

• Use AEP's Standard for repairing or replacing tubes. Typically 70% of wall thickness is used. Do not pad weld to restore thickness for < 70% because of the potential to introduce other detrimental failure mechanisms - copper embrittlement and hydrogen damage. If root cause of erosion has been determined and adequately addressed no additional erosion should place.

• Check, correct and verify the VT operation of moisture traps and remove remaining orifices. • Check, correct and verify VT blower or system operation to ensure correct sequence, frequency, angel of rotation, travel, misalignment, operating steam temperature and pressure. • Check, correct and verify VT steam supply (pressure and temperature), drainage slopes and piping insulation.

• Use the OEM's manual or site specific procedure.

EPRI Licensed Material

NDE Detection Technique

Sootblower Erosion

L M N O P Q #

Fire Side Corrosion

K

Falling Slag Erosion

Caustic Gouging

J

Coal Particle Erosion

Acid Phosphate Corrosion

I

Short Term Overheating

Supercritical Waterwall Cracking

Low Temperature Creep

Corrosion Fatigue

Fatigue

Acid Dewpoint Corrosion

Pitting

A B C D E F G H

Hydrogen Damage

#

Fly Ash Erosion

Possible Causes

Thermal Fatigue

Corrosion Corrosion

Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

Preventive Measures Short/Long Term

CRITERIA

• Emergency repairs such as pad welding should be replaced at the next opportunity. • Develop a map identifying the exact location of each pad weld to ensure all locations are recorded. • Optimize blowing sequence to ensure an effective boiler sootblowing program.

VT

• Establish and implement a routine maintenance schedule to inspect and test blower operation.

1-21

EPRI Licensed Material

Component # 1, 2 and 12 through 17

Primary causes are excessive 2 local velocities and/or dust burden. Excessive local velocity design/configuration distorted/misalignment tubes - Gas flows above design rating Dust burden - Increase in erosive particles ie increase % ash - Sootblower operation Other - Incorrectly install shields and/or baffles Inappropriate and/or incorrectly applied coatings - Broken or misaligned "canes" and "handcuffs.

1-22

•

Preventive Measures Short/Long Term

NDE Detection Technique

Sootblower Erosion

L M N O P Q #

Fire Side Corrosion

K

Falling Slag Erosion

Caustic Gouging

J

Coal Particle Erosion

Acid Phosphate Corrosion

I

Short Term Overheating

Supercritical Waterwall Cracking

Low Temperature Creep

Corrosion Fatigue

Fatigue

Acid Dewpoint Corrosion

Pitting

A B C D E F G H

Hydrogen Damage

#

Fly Ash Erosion

Possible Causes

Thermal Fatigue

Corrosion Corrosion

Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

• Confirm mechanism and UT VT determine the extent by completing a dirty and a clean inspection. The dirty inspection will highlight areas where excessive local velocities occur. These can be comfirmed by a detailed clean inspection. The areas mostly likely to show signs are at the base of the fins of the first economiser bank, the element ends between tube and wall and adjacent to any flow staighteners and/or baffles. • Perform a CAVT to confirm high velocity areas. If high velocities are detected - design and install baffles or flow straighteners. Perform a second CAVT to confirm actual velocity profile. • If baffles and/or flow straighteners have been installed perform an annual inspection to determine the effectiveness of the modification and adjust if necessary.

CRITERIA

• Use AEP's standard for tube replacement ( 50% inspection and sampling. through wall then replace tubing. Remove sample attachment tubes and areas of high stress. • Replace damaged tubes. • Modify tube attachments to relieve obvious stress raisers.

• Use AEP's Standard for repairing or replacing Tubes

• Ensure compliance to AEP's water chemisrty practices. • Ensure compliance to startup and shut down procedures. • Ensure compliance to AEP's chemical cleaning procedures. • Correct tube spacing • Set inspection levels to determine the effectiveness of any modification and monitor damage accumulation.

1-25

EPRI Licensed Material

Preventive Measures Short/Long Term

Component # 14

Possible Causes Higher than expected metal temperatures (brought on by overfiring conditions) and stresses - both thermal and differential expansion

1-26

# 5

A B C D E •

F G H

I

J

K L M N O

P Q

NDE Detection Technique

Fly Ash Erosion

Long Term Overheat

Graphitization

Chemical cleaning Damage

Pitting

Fatigue

Rubbing/Fretting

Sootblower Erosion

Stress Corrosion Cracking

Dissimilar Metal

Short Term Overheat

Creep

Fireside Corrosion

Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

CRITERIA

# • Confirm mechanism and VT UT determine the extent. Map location and inspect all DMWs. • Replace DMW with a "dutchman"of upgraded material. Depending on the specific circumstamces re-positioning the DMW may be more cost effective. • Perform a remaining life assessment calculation (Level I, II or III). • Inspect and correct tube supports, tube bindings etc leading to axial stresses at welds. • Ensure functionality of metal and steam temperature thermocouples.

• Use AEP's stanard for tube insert- 18 inches preferably 36 inches. • Use EPRI's standard for weld geometry.

DMW life code from SIA (based on EPRI PODIS code)

EPRI Licensed Material

Preventive Measures Short/Long Term

Component # 17

Possible Causes • Oxygen-saturated stagnant condensate as a result of a unit shutdown - forced cooling and/or imprper draining and venting and aggrevated by the • Carryover of sodium sulfate from the reheat steam (Sodium Sulfate tends to form at typical reheat pressures)

# 6

A B C D E

F G H

I

•

J

K L M N O

P Q

NDE Detection Technique

Fly Ash Erosion

Long Term Overheat

Graphitization

Chemical cleaning Damage

Pitting

Fatigue

Rubbing/Fretting

Sootblower Erosion

Stress Corrosion Cracking

Dissimilar Metal

Short Term Overheat

Creep

Fireside Corrosion

Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

CRITERIA

# • Confirm mechanism and VT UT determine the extent by inspection and sampling in particular areas where the tubing has sagged allowing condensate to accumulate. • If root cause has been identified and rectified, minor pitting damage can be left alone ie there is no need replace tubing. Continue to monitor and take samples for analysis to check for deterioration. • For major damage, plan to replace, modify operating procedure and institute long-term monitoring. • Review and correct if necessary the effectiveness of the shut down and lay up procedures.

• Use the remaining life assessment calculations results from Level I or II as judgement criteria.

• Use AEP's Standard for repairing or replacing Tubes

• Enforce compliance to shut down and lay up - nitrogen blanketing procedures. • If the lay up procedure nitrogen blanketing cannot be used because of boiler work, some other means of drying must be used to ensure a moisture free enviroment in the reheater.

1-27

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

Preventive Measures Short/Long Term

Component # 3 to 17 (water and steam circuits)

Possible Causes • Exfoiliation induced: Caused by the natural process of growth and exfoiliation of oxides. These oxide flakes tend to collect at sharp bends. • Mainenance induced: Caused by poor quality control during welding, improper/incorrect chemical cleaning or poor combustion resulting in flame impingment on water walls. • Operatging induced: Caused by improper start-up and shut down practice (not boiling out condensate collected in the loops/bends) and overfiring to compensate for low feedwater temperature.

# 7

A B C D E

•

F G H

I

J

K L M N O

P Q

CRITERIA

# • Confirm cause by either an VT MT analysis of a sample of the debris or start-up and/or shut down records. Confirm extent through inspection of tube in the immediate vicinity. Check for swelling and cracks. • Check to ensure blockage has been removed by using compressed air or water. • Repair by inserting a 36 inch • Use AEP's Standard for chemical cleaning "dutchman". • Ensure compliance to start-up and shut down practices. • Ensure compliance to start-up and shut down practices. • Check combustion and or burners are optimized to ensure no flame impingment is taking place.

1-28

NDE Detection Technique

Fly Ash Erosion

Long Term Overheat

Graphitization

Chemical cleaning Damage

Pitting

Fatigue

Rubbing/Fretting

Sootblower Erosion

Stress Corrosion Cracking

Dissimilar Metal

Short Term Overheat

Creep

Fireside Corrosion

• Check drainage slopes and tube bundle sagging. Correct if possible, if not possible then to check for any deterioration by inspection and sampling.

• Use AEP's Standard for repairing or replacing tubes

EPRI Licensed Material

Preventive Measures Short/Long Term

Component # 17

Possible Causes Prolonged operation at high temperatures (design operating temperature and above)

# 8

A B C D E

F G H

I

J

K L M N O

•

P Q

NDE Detection Technique

Fly Ash Erosion

Long Term Overheat

Graphitization

Chemical cleaning Damage

Pitting

Fatigue

Rubbing/Fretting

Sootblower Erosion

Stress Corrosion Cracking

Dissimilar Metal

Short Term Overheat

Creep

Fireside Corrosion

Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

CRITERIA

# • Confirm mechanism and VT UT determine the extent by inspection. Perform UT metal and ID oxide thickness measurements. • Remove several samples both across and within the bank for analysis and replace withn a 36 inch "Dutchman" • Perform a remaining life assessment calculation (Level I, II or III).

• For major damage, plan to replace, modify operating procedure and or design and institute long-term monitoring. • Perform hydraulic test as an integrity check.

• Use AEP's Standard for repairing or replacing Tubes

• Use the remaining life assessment calculations results from Level I or II as judgement criteria- EPRI's TUBELIFE program. • Replacement should be T91 or equivalent material such as T23.

• Compliance to ASME code requirements fo r test pressures and temperatures. Increasing pressures above code to force failure is a poor practice and fruitless as crack > 50% through wall can tolerate design pressures without failure.

• Calibrate and ensure functionality of all installed metal temperature thermocouples. • Set inspection levels to determine the effectiveness of any modification and monitor damage accumulation.

1-29

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

1.4.3 Streamlined Reliability-Centered Maintenance Streamlined Reliability Centered Maintenance is a logical, systematic, functionally based methodology used in the evaluation of a facility’s system or unit. The evaluation includes a stepby-step consideration of the integral functions related to the operation of the system or unit. The failure mechanisms of each of these functions, the effects of the failure and the selection of appropriate and effective maintenance tasks to mitigate these failures are identified. The goal is to develop a cost-effective maintenance program, based on system functionality, which will enhance system reliability. This makes optimum use of available maintenance resources and provides a documented base for future additions/revisions to the maintenance program. Two systems were reviewed – steam- and water-touched tubing and the fuel system. Appendix 1 gives the results of this analysis. These results still need to be compared with those in Computerised Maintenance Management System. The purpose of this comparison is to identify changes to the existing program, to optimise the Fuel system preventive maintenance program. The comparison also provides another check of the analysis to ensure completeness and validity of assumptions. Once the comparison is complete and has been approved the “new” tasks can be incorporated in the CMMS. 1.4.4 Unit 2 Outage Task Prioritisation An EPRI Risk Evaluation and Prioritisation (REAP) model was used to demonstrate how outage tasks can be evaluated and prioritised. Thus providing a documented basis for decision making. The model is based on determining the risk of performing or not performing a preventive or corrective maintenance task. This is achieved by scoring a number of answers to questions about the task at hand. Labour hours and cost are also used to determine the value and cost of the task. The following is the results of a REAP analysis performed using the Unit 2 outage task list. A total of 119 maintenance outage tasks were reviewed. These tasks had been determined from a much longer list, which had been subjected to a “gut” feel prioritisation method. Unfortunately the total list was not available to compare the “gut” feel method verse the approach taken in the EPRI model. Figure 1-5 represents the resultant scatter diagram of all 119 tasks analysed.

1-30

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

T a s k C o s t V a lue S c a t t e r

1.E+09

V alue/C o s t O p timiz atio n Line s

1.E+08 1.E+07 1.E+06 1.E+05 1.E+04 1.E+03 1.E+02 1.E+01 1.E+00 $100

$1,000

$10,000

C os t

Figure 1-5 Task Scatter Diagram - Value to Cost

The angled lines in figure 1-5 are generated by recognising that outage work scopes are built by starting with the most valuable least cost work and continuing to add more expensive valuable work until all to work has been included. Integrating all this work results in the Accumulative Value and Cost curve – Figure 1-6.

140

5.E + 09 4.E + 09 4.E + 09 3.E + 09 3.E + 09 2.E + 09 2.E + 09 1.E + 09 5.E + 08 0.E + 00

120 100 80 60 Task s

40

V alue

20

No. of Ta sks

V a lue

N o. of Tasks & V alue vs C ost

0 0

20000

40000

60000

80000

100000

Costs

Figure 1-6 Accumulated Value verse Cost

1-31

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

Figure 1-6 represents the accumulated value versus cost versus number of tasks and shows that at the 32,700 cost level (cost is number of man-hours), 3.74 E09 value is captured with 95 of the 119 outage tasks. In other words – with 40% of the outage task hours, 95% of the outage task value can be captured with 80% of the tasks being performed. The vertical lines show where there is a significant slope change. In this case they show perhaps where one can “draw the line” on an outage work scope i.e. where 80 % of the value is captured with 20 % of the cost. At that threshold, the following tasks would not be performed: AIR HEATER SEALS

3356430

AIR HEATER SEALS

3423125

AIR HEATER SEALS

3381022

AIR HEATER SEALS

3423136

4KV ROOM WALL

3374302

INSPECT GAS OUTLET DUCTS

3422425

CIRC WATER PUMP DISCHARGE EXP. JOINTS

3356636

DEAERATOR INSPECTION

3422484

OVERLAY SIDEWALLS

3357443

NDE ON FACTORY WELDS 1ST RH PIPING

3374254

PA & FD FANS - CLEAN & INSPECT

3422941

BOILER DIVISION VALVE-OPEN, INSPECT & REPAIR

3420561

COAL CHUTE RENEW WEAR PLATES

3422915

COAL CHUTE RENEW WEAR PLATES

3422904

REPLACE COAL CHUTES

3415274

REPAIR PENTHOUSE CASING LEAKS

3421165

REPLACE 80 TUBES REAR ASH HOPPER SLOPE

0577695

REPAIR APERATURE MEMBRANE

3365526

801 ASH GATE

3358014

BURNER REGISTERS - INSPECT & REPAIR

3420966

BURNER REGISTERS - INSPECT & REPAIR

3420970

GENERATOR INSPECTION

3374350

MAIN TURBINE OIL COOLERS

3423195

INSPECT #1 BEARING ON TURBINE

3424116

Although the outage tasks have all been approved and scheduled, this REAP analysis shows how outage scope of work in terms of cost and value can be determined, evaluated and prioritised.

1-32

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

1.4.5 Boiler Tube Failure Reduction and Cycle Chemistry Improvement Training From 8–10 February 2000, an EPRI team presented the above training programs to a number of plant and corporate staff. Appendix 1 lists the names of all attendees. A vertical and horizontal cross section of staff attended, representing all disciplines – operating, maintenance engineering and management. The two-and-half day course was well received by all attendees, and they were eager to proceed with the development of a Boiler Tube Failure Reduction program. A plant directive – Boiler Reliability Optimisation Project has been signed by the Plant Manager in support of the program. The directive (see Appendix 2) outlines the minimum requirements to manage a successful Boiler Reliability Optimisation program. 1.4.6 Boiler Maintenance Workstation (BMW) installation and training During July 2000 the BMW software was successfully installed. Software user training was given to a number of site staff. BMW is a windows based software program used to track and trend boiler tube failure data and information – tube failures, correction and prevention, and control actions. It consists of two modules - Boiler Works and Tube Condition. The boiler works module is a database and graphics program designed to track maintenance failure data/information – failure location and mechanism, repair costs and methods, etc. This collated information is used to focus attention on specific activities, for both planned and forced outages, to prevent future repeat failures. The Tube Condition program stores and analyses data collected from various inspections, e.g. tube wall thickness, oxide thickness data. It uses two or more data sets to determine wastage rates. These wastage rates are used to determine remaining tube life and predict tube wall thickness. This helps plant personnel plan future boiler tube inspections, maintenance activities and tube replacements.

1-33

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

AEP Big Sandy Unit 2, Boiler Reliability Optimization - Phase 4, July 2001 Executive Summary Utilities throughout North America are facing the challenges of deregulation and competition. The prospect of competing in a non-regulated environment is driving utilities to find more cost effective means to operate and maintain their plants. Recognizing this, Big Sandy Plant participated in EPRI’s Boiler Reliability Optimization Program. The project started during the fourth quarter of 1999. The project aim was to identify improvement opportunities to attain and sustain an availability of 95% during peak periods – May through August and at least 90% during the remainder of the year. During 2000 phase 1,2 and a portion of phase 3 were successfully implemented resulting in sustained plant performance. As a result Big Sandy Staff were keen to continue with the Boiler Reliability Optimization Project – Phase 4, albeit with limited funding. Phase 4 is the continuous improvement phase – the proactive maintenance aspects of the program. The emphasis is on the operations aspect that is what the operator can do to minimize maintenance. During July 2001 an EPRI team spent a week on site reviewing actions taken as a result of the Phase 1 to 3, interviewing operating and maintenance staff and published a draft report. This report documents all the findings, conclusions and recommendations accepted by Big Sandy Plant staff.

Introduction Utilities throughout North America are facing the challenges of deregulation and competition. The prospect of competing in a non-regulated environment is driving utilities to find more cost effective means to operate and maintain their plants. Recognizing this, Big Sandy Plant participated in EPRI’s Boiler Reliability Optimization Program. The project started during the fourth quarter of 1999. During 2000 phase 2 and a portion of phase 3 was completed with the issuing of a final report. The staff at Big Sandy were keen to continue with the Boiler Reliability Optimization Project – Phase 4, albeit with limited funding. Phase 4 is the continuous improvement phase – the living aspects of the program. The scope of work of this project covered the implementation of a portion of Phases 4 of EPRI’s Boiler Reliability Optimization Project and was limited to the boiler steam and water system – tubes and headers. The project consisted of the following tasks: 1. Review the progress made in implementing recommendations from previous Boiler Reliability Optimization phases. 2. Develop a framework for specific boiler long-term plant health indicators. 3. Review and optimize/enhance the daily operation of Unit 2 to result in proactive maintenance. 1-34

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

Description of Phase 4 of a Typical Boiler Reliability Optimization Project Phase 4 is the continuous improvement - the “living aspects” of a Boiler Reliability Optimization Project. It builds on the successful implementation of the previous phases and provides proactive action and feedback on the overall boiler performance – reliability and maintainability aspects. Phase 4 focuses on the human reliability aspects as there is a direct relationship between plant reliability and the people who operator and maintain the boiler. If the people are reliable then the plant will be reliable. In this context human reliability is making and keeping commitments. Phase 4 also introduces the concepts of proactive maintenance into the world of the operator. Proactive maintenance is an activity performed to detect and correct root cause abnormalities of failure. It is a first line of defense against material degradation and subsequent performance degradation, failures that ultimately lead to precipitous and catastrophic forms of failure and plant breakdown. The operator can correct a conditional failure mode that is the cause of an unstable condition and ensure that degradation type failures never occur. Thus proactive maintenance is not an activity that reacts to material and/or performance type failure conditions of a plant. Rather, it prevents such plant degradation from occurring. In reality, proactive maintenance is a preemptive first strike against failure – a true avoidance activity. Thus, the focus of Phase 4 is on the: •

role operations personnel play in the effective and efficient operation of the boiler,

•

tools, both hardware and software at their disposal

•

instrumentation to control and monitor critical component parameters and

•

Standard Operating instructions and procedures.

The ultimate success of a Phase 4 Boiler Reliability Optimization project is largely dependent on the following: •

Operator skills and knowledge of the boiler and the steam raising process,

•

Operator understanding of the effects operating practices have on both the short and longterm plant health and

•

The extent to which operating is involved in both the long and short-term maintenance decision making process.

Findings 1. All of the recommendations made in the Phase 2 report have been accepted. More than 80% have been implemented while the remaining are in the budgetary and approval processes. Table 1-1 below summarizes the status of the actions taken and for each recommendation given in Phase 2. A recommendation that has still to be implemented is a formalized root cause analysis process. This is key to the successful implementation of a boiler reliability optimization project.

1-35

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2 Table 1-2 Phase 2 Recommendations and Actions Taken #

Recommendations Tabled

Action taken

1

Specific boiler availability targets should be developed relating to the number of tube leaks per year. The strategy and performance targets should be compiled into separate plant directives, which are reviewed annually for effectiveness and appropriateness.

The following the best in class (BIC) goals for unit 2 have been established: 01

’02

’03

FOF

5.38

1.69

0.82

MOF

0.41

0.41

0.41

POF

0.0

26.85

1.92

To meet these goals a Strategic Plan for the boiler has been compiled 2

To repair and calibrate all boiler instrumentation critical to the efficient and effective operation of the boiler. This includes air, gas, water and steam temperatures and pressures and reheater and superheater metal temperatures.

3

The installation of on-line water and steam chemistry instrumentation and the establishment chemical performance index. This index can be used in a proactive way to ensure compliance to EPRI water and steam chemistry guidelines.

Improved cycle chemistry monitoring with the installation of sodium analyzer in sample room and “ChemExpert” software in the control room.

To prepare detailed inspection plans based on the tasks identified in the Boiler Failure Defense Plans presented in this report. These inspection plans should be loaded into the CMMS. This would facilitate the development of a scheduled and or forced outage plan at short notice.

Prepared detailed inspection plans on noted problems and drew up inspection PM’s.

Once the installation and the user training on the Boiler Maintenance Workstation (BMW) have been completed, the BMW database needs to be updated with all the history of previous tube failures. This will enable tube leaks and repairs to be tracked and trends to be established. This will also assist in formulating focussed boiler inspections plans.

BMW was installed and the history data file has been updated with data from 1994 to 2000. Currently working on updating the history file with data from 1986 to 1994.

Fireside corrosion – Confirm mechanism and extent of wall thinning by inspecting the area around the burners and side wall. Also monitor O2 and CO near the tubes on the side walls

Monitoring NOx strategy has taken top priority to measuring O2 on the side walls however inspections and NDE is done during forced outage.

4

5

6

1-36

During the planned outage in 2000 the boiler tube temperature recorders and draft gauges were repaired. However since then some are out of service awaiting spare parts

Chemical indices still need to be developed.

Developed a “short notice forced outage plan”. Tasks are discussed at a weekly meeting – every Thursday morning.

Training classes for welders is scheduled for August 2001

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2 7

Fly ash erosion – Perform a CAVT to confirm high velocity areas. If high velocity areas are detected – design and install baffles or flow strengtheners. Perform a second CAVT to confirm results and velocity profile

Only CAVT completed on the economizer and repositioned baffles and re-tested. Results not as expected. Re-testing will continue as outage work permits

8

DMW failures – Replace all DMW with Dutchmen of upgraded material. Depending on the specific circumstances re-positioning of the DMW may be more cost effective

All DMW replaced.

9

Internal pitting – Revise and update the boiler lay-up procedure

1 Reheater lay-up procedure revised and updated. st Performed remaining life estimation on 1 reheater, replaced tubes below minimum wall thickness. Plan to replace reheater in 2002. NDE results taken in 2000 show that there was no need to do a chemical clean.

10

Perform a level II assessment of all final outlet headers in accordance with EPRI guidelines.

Completed during 2000

11

The PM Basis must be reviewed and updated to take into account the failure mechanisms identified during the past outage inspection.

Developed new inspection PM to inspect repeat mechanisms

12

The Boiler Specialist should have an Operating Department counterpart who would be responsible to review and update and align operating procedures to current practice.

As a result of the adopting the Process Centering model, this task is now the responsibility of the Sub-process owner.

13

Boiler tube failures/Root Cause Analysis should be tracked and trended

BMW software will assist in tracking and trending tube failures and their associated causes

14

The boiler inspection plans need to be updated to take cognize of the change in the frequency of boiler periodic outages

The weekly outage-planning meeting discusses and develops a forced outage plan. Inspections plans (PM) are included in these forced outage plans

15

A formal RCA program will result in additional information valuable in managing the Boiler.

st

RCA still not formalized. Tube failures are analyzed and tracked through BMW

16

The roles and responsibilities of the PdM Coordinator should be clearly defined

The PdM Coordinator position has been made obsolete by the re-organization – Process Centering. However, the PdM activities still remain with the previous incumbent.

17

Infrared thermography should be used on the boiler to identify casing leaks, valve passing etc.

Infrared thermography survey are performed quarterly as described in EPRI Boiler reliability Optimization IR TAD document

1-37

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

18

Develop an Equipment and Condition Indicator matrix (E&CI) for all critical boiler components. This will assist the equipment owner to assessing the condition of equipment under his control.

19

To ensure a high availability between periodic outages, 3 yearly, a detailed a inspection, test and repair plan of all known and potential problem areas

20

Develop a four-week rolling scheduling process for all maintenance to assure high utilization of resources.

It is intended to incorporate a four week rolling schedule in the new CMMS – Indus-passport system

21

Include post maintenance testing requirements into the planning process. This is a must for most CM work orders.

Post maintenance testing will be incorporated into the new CMMS

22

System owners and the Boiler Specialist should review closeout information for effectiveness.

The newly appointed Process Centering Subowners review closeout information.

23

Compile a management directive identifying the minimum acceptable standards to be complied with when performing boiler maintenance or repair work. This would include such statements as every tube leak/failure should be investigated, pad welding should be discouraged etc.

A Boiler Reliability Optimization Directive has been signed by the Plant Manager and is in effect.

24

Establish technology owners with responsibilities to include condition analysis.

Process Centering sub-owners have been nominated in place of technology owners.

25

Need to have a more comprehensive PDM reports as health report not exception reports

An existing PdM health report is considered adequate

26

Formalize monthly Boiler Condition Based Maintenance (CBM) meetings. Once a year, perhaps prior to any budgeting cycle, the Boiler Specialist should present a Boiler Failure Defense Plan – indicating the current condition, short and long term activities/tasks that need to be undertaken to ensure boiler reliability.

Plan to include monthly Boiler CBM meetings into the Boiler Reliability Optimization Directive

1-38

Trending boiler process data, using the E&CI matrix as a base, is done using the limited available instrumentation. Addition instrumentation will be installed, if, and when a new DCS is approved. It is intended to install FEGT indication during the next outage.

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2 27

Case histories and cost benefits analysis of using PDM technologies should be document either in the BMW or PIMS databases.

Case histories are being established in the BMW database. Metric are being developed through the centering process

28

An annual review of the maintenance program should be undertaken to determine its effectiveness i.e. the right technologies are being applied to the right assets at the right frequency to meet the overall business objectives and maintenance strategy.

Included in the business strategy feedback loop.

29

Consideration should be given to having an annual Boiler Specialist Meeting and forming a Boiler Specialist’s Users Group. This will aid in the transferring of information and knowledge amongst the Boiler Specialists within the AEP organization.

AEP has formed a Boiler Reliability Optimization Team whose responsibility is to support the implementation of the program

30

Consider providing Level of Awareness training (LOA) training for the entire staff on Plant Maintenance Optimization.

LOA training has been done previously. Not considered necessary at this stage.

31

Re-train all PIMS users on the details of PIMS and how best to it

PIMS is to be replaced by Indus – passport by January 2002. Training on the new system starts in the last quarter of 2001

32

Develop a series of inspection tasks using the data and information identified and update the CMMS.

Inspection tasks for 2000 have been completed.

2. Five operators with a wide range of experience were interviewed (four Unit operators and one Equipment Operator). The interviews focussed on the knowledge of the boiler and the steam and water cycle. Responses to questions from some of the operators regarding boiler operation and operating parameters on critical equipment were incorrect. Critical components within the boiler were not known. Under base or transient loads the focus is on steam temperature only, metal temperatures are not considered. These same operators have been given latitude to develop their personal operating practices and to experiment with set points on critical equipment. The combined effect of the above can lead to an increased risk with the consequent reduction in unit performance, both efficiency and reliability. 3. Each unit operator interviewed uses his or her own set of procedures - start-up procedure, marked up with his or her own notes. The start-up procedure reviewed in the control room was dated 1970, where as, the set given at the beginning of this project was dated October 1998. Not all operators were aware there was a new/revised start-up procedure. Those who had a revised copy preferred to use their own marked up copy. This results in inconsistent start-up times, and possible inappropriate actions during unit start-ups. 1-39

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

Operating instructions in the form of unsigned, undated, hand written notes were found taped to the control panel. The operator bases identification of the author of these instructions on trying to recognize the handwriting. Operators have no way of knowing what new operating instructions have been issued unless they see a new piece of paper taped on the board or page through the log book assuming it was written. There is no way of ensuring that all operating personnel are being made aware of changes in critical operating parameters. 4. There is no documentation standard or control of Operating Procedures and Instructions. Procedures reviewed did not follow a common format, approval signatures, date issued, revision number etc. The new Unit Lay-up procedure given for review was in the form of an email. 5. Operators are not always informed of equipment, including chart recorders, being taken out of service for maintenance work. Unanticipated requests to have equipment taken out of service and clearances issued results in inefficiencies and delays for both maintenance and operators. The introduction of the “Forced Outage Maintenance Work” matrix posted in the control room has eased this situation. The matrix is an excellent communication tool. It keeps operating personnel informed of what work will be done under several forced outage scenarios. This puts the operators in a proactive mode regarding clearances and equipment shut down priorities. 6. Experienced and qualified Laboratory personnel control unit chemistry within EPRI guidelines. Operating personnel have limited knowledge of unit chemistry or the effects of operating outside EPRI guidelines on unit reliability. Operators are in a reactionary mode regarding chemistry excursions, depending on laboratory personnel for direction and corrective action. There are no feedwater or boiler pH indications in the control room. On a once-through, super critical unit using an oxygenated treatment (OT), maintaining a proper pH level is of the highest importance, as there is only a short time window of opportunity to react to low pH levels. Lack of pH readings in the control, coupled with the limited knowledge of operating, presents an increased risk to the reliability of the unit. 7. Operators spend approximately 25% of their time taking manual readings for staff personnel. A number of these reside in the computers in the control. The need for and the information from these readings has not been explained and or justified. This leads to resentment and frustration between operators and other staff members.

Conclusions 1. Big Sandy staff needs to be congratulated on the effort they have expended in successfully implementing the recommendations from Phase 2 Boiler Reliability Optimization Report. This effort shows the commitment to improve and sustain high performance. 2. There is a lack of management control in the operations area. Operators are not held accountable for their individual actions, nor the results of their actions on Unit efficiency or reliability.

1-40

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

3. Operators are not being given the tools or resources they need to operate the Unit in a consistently safe, reliable, and efficient manner. Operating procedures and instructions are written and distributed in a uncontrolled manner. Training of operators is inadequate and inconsistent. As a result, there are no primary standards for operation or control of critical Unit processes. 4. The loss of many older, more experienced operators and supervisors has diluted the knowledge base of the operations group. This has resulted in a wide range of operating philosophies among the Unit Operators. 5. Chemistry control is good due primarily to the efforts of the laboratory group personnel. Operations contribution to the success of this program is minimal due to their lack of knowledge of the chemical processes involved. 6. Control room instrumentation is an extension of the Unit Operators senses. The sense of urgency related to instrument repair and/or replacement needs to be raised to a new level. This should be accomplished in the near future if the practice of assigning only one operator to the control room is to be successful. 7. If Big Sandy is to successfully implement a “Pro-Active Maintenance (PAM) program, it is essential that the Operations group plays an active role with its implementation. Without their full commitment, success will be difficult. Serious consideration should be given to the preceding recommendations before plant management attempts to implement such a program.

Recommendations 1. Continue with the efforts to implement the outstanding recommendations from Phase 1 (above table) especially with installation of a FEGT monitoring system. This will allow the operator to load the unit to its maximum without placing excessive thermal stresses on the super heater. 2. Develop a series of long term plant health indices for the boiler: thermal excursion, chemical and trip index. – Thermal excursion index is the number of additional equivalent operating hours experienced by the most sensitive header in the boiler as a result of metal temperature excursions in excess of design temperature with a boiler pressure > 80% of normal o operating pressure. In addition, all excursions in excess of design + 100 F shall be included irrespective of boiler pressure. The Additional Operating hours = Constant (k) x Σ (∆ T x ∆ t) Where: ∆ T = difference between the peak temperature reached in an excursion and the design operating metal temperature ∆ t = total duration of the excursion in hours

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EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

Constant (k) = approximation, assuming a straight-line relationship between elevated temperatures and equivalent operating hours.

Thermal index = Additional Operating hours x Total hours in month divided Σ of unit operating hours for the month. – Chemical Excursion Index is a set of indices in which measurements taken on the plant of chemical conditions of steam, feedwater, etc are normalized to a base of one. The actual values are manipulated mathematically to give a result that is of the order of one. A result of 0.5 is excellent and greater than 0.9 is considered unacceptable. Results of between 0.6 and 0.9 indicate chemical condition under control and no risk to long term health. Results between 0.9 and I are acceptable for short duration only. Results greater than 1 require immediate attention. These results can be represented in a bar chart and displayed to the operator Chemical index = Σ of all incidents of unit parameters > 0.9 for current month x Total hours in month divided by Σ of operating hours for the current month – Trip index is the accumulative total number of automatic and manual trips of the unit. This will give a feel for the number of stress cycles the plant has been subjected to no matter what was the cause Trip Index = Σ of all trips for current month x Total hours in the month divided by sum of unit operating hours for the month These indices can be developed for all units and used as a means to compare unit performance Note the numbers quoted above are guidelines, they should be adjusted to suite the particular unit circumstances and conditions

3. Analyze the effects of the wide range of conditions under which the Unit is operated. Select the “Best Practice” and develop a set of procedures and hold all Unit Operators to those standards. The start-up procedure should have target times for mile stone activities and check boxes for the operator to insert the actual time and reasons for any deviation from target. After the start-up these times can be analyzed for improvement opportunities. 4. Operations group should be involved in planning and scheduling of maintenance on any equipment that needs to be taken out of service. Operators should be informed on the status of any instrumentation that is out of service. They should know why, and the expected return to service date. 5. Develop a document control system and conduct periodic compliance audits to ensure the correct document/procedures are being used. This system should include all operating procedures and instructions. As a minimum, these should include signed approval levels, revision date, distribution list, standardized format, and collection and disposal of outdated documents. A list of typical headings found in a procedure can be found in Appendix 2. One complete set of operating procedures and a “temporary operating instruction” book should reside in the control room. All entries in this book should be signed and dated. Operators at the beginning of their shift should review this book for updated changes. 1-42

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

6. Provide training to all operating personnel on basic unit water and steam chemistry and the alarm and action level guidelines. 7. Provide pH indication for condensate, economizer inlet, and main steam in the control room. 8. Review the need and frequency for the manually recorded readings. Values, which reside in the computer, should be collected automatically by creating a specific computer log. The use of and value obtained from the readings collected manually should be feed back to the operators. 9. Develop and formalize an improvement program - root cause analysis process. Use the following as a guide. – Obtain Management support such a program – financial and human resources – Select and nominate a champion – owner of the process – Review the industry and select a root cause analyses system using the following seven factors: Easy to use in the field by non-experts Effective in consistently identifying root causes Well documented Accompanied by effective user training Credible with the workforce Helpful in presenting results to management Designed to allow collection, comparison, and measurement of root cause trends. – Train investigators/ Coaches – representation from Operating and Maintenance – Give awareness training to operators and craftsperson – Compile an administrative procedure – purpose, objective, scope responsibilities, investigation and reporting matrix etc – Develop a database for causes and corrective actions 10. Provide training to ALL operating personnel on Unit chemistry guidelines and emergency responses. Of special importance is the relationship between specific conductivity, ammonia levels, and pH values in the condensate/feedwater systems. The ammonia feed-rate is controlled using the specific conductivity of the feedwater, which maintains the target pH values. The relationship between conductivity values and ammonia is a straight-line relationship, whereas the pH is logarithmic. Changes in conductivity are the operator’s first indication of approaching problems. Operators should also understand the difference between cation and specific conductivity, as well as the importance of sodium levels. Provide Ph reporting instrumentation to the control room. This should pH values on the condensate, feedwater, boiler, and main steam.

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EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

Appendix 1: Interview List

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Name

Designation

1

D. Mell

Production Support Manager

2

J. Burton

Region 3 Engineer

3

E. Dillow

Region 3 Engineer

4

A. Robinson

Production Services Leader

5

S. Jenks

Production Services Leader

6

J. Skaggs

Lab Technician

7

D. Pinson

Unit Operator

8

R. Lewis

Unit Operator

9

J. Adkins

Unit Operator

10

R. Peck

Unit Operator

11

M. Keene

Equipment Operator

12

M. R. Mckenzie

Production Services Leader

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1, 2 & 4 at American Electric Power’s Big Sandy Plant – Unit 2

Appendix 2: List of Typical headings that appear in a policy and or a procedure 1. Group name 2. Document type: policy, standard, guideline, procedure etc 3. Reference number 4. Revision number 5. Description of revisions made 6. Review date 7. Date authorized 8. Date when document came into effect 9. Compiled by 10. List of designations who have approved the document 11. Authorized by 12. Title 13. Background/preamble/introduction 14. Purpose 15. Scope of document 16. References 17. Definitions and or abbreviations 18. Responsibilities 19. Responsibility matrix 20. Requirements: step by step of what is required to be done 21. Work process flow and responsibility matrix 22. Distribution list 23. Appendices

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EPRI Licensed Material

2 BOILER RELIABILITY OPTIMIZATION PROJECT PHASE 2 – BOILER INSPECTION PLAN REVIEW AT GREAT RIVER ENERGY’S COAL CREEK STATION – UNIT 2

2.1 Executive Summary Senior Management made the decision to change the boiler maintenance overhaul frequency from two to three years, and wanted assurance prior to the Spring 2001 outage that the existing boiler inspection plans were comprehensive and complete. Confidence in the newly adopted maintenance strategy is essential, as the next general overall outage after the Spring 2001 outage is in 2004. EPRI was requested to review the current Unit 2 outage inspection plan and recommend changes and/or additions, to provide this assurance. During the week of August 21, 2000, two EPRI representatives interviewed a number of Coal Creek Power Plant staff members from the operations, maintenance, engineering and management groups. The unit history, maintenance, operating practices, and the boiler inspection plan were reviewed and analyzed. The current boiler inspection plan is reactive, i.e. it focuses almost entirely on known problem area – sootblower erosion - and does not cover all the components within the boiler in sufficient detail. There is a limited predictive element to the plan. It does not address any future or potential failure mechanisms, and is therefore not comprehensive and will not give the necessary assurance that all risk areas have been adequately covered. This report highlights a number of recommendations that would assist in developing a comprehensive and effective boiler inspection plan. These recommendations, together with comments/suggestions added to the Unit 2 Outage Inspection Plan given to the EPRI team on 21 August 2000, will provide a quality inspection plan. Annexure II An extract from another utility’s boiler inspection plan and is given in Annexure I to illustrate the detail that is required in a typical Boiler Inspection Plan.

2.2 Introduction Faced with de-regulation and competition, Senior Management at Great River Energy – Coal Creek Station, challenged the existing plant maintenance strategy and sought opportunities to improve plant availability and reliability. One of the changes made was to the overall unit 2-1

EPRI Licensed Material Boiler Reliability Optimization Project Phase 2 – Boiler Inspection Plan Review at Great River Energy’s Coal Creek Station – Unit 2

maintenance strategy, i.e. the frequency and duration of outages was changed from 2 to 3 year intervals and a shortened duration. This change would improve the overall unit availability. To improve unit reliability the focus shifted to understanding and eliminating the causes of boiler forced outages; the predominant cause being boiler tube leaks. To ensure “no surprises” a comprehensive boiler inspection plan needs to be developed and implemented during the next outage – Spring 2001 . A boiler internal inspection is one of the most important inspections to be carried out during an outage. It must be done timeously, systematically, accurately and by experienced inspectors. The quality of this inspection will ensure that a reliable boiler will be put back into service. The only approach is “do it right the first time all the time” The selection and number of inspectors should not be based on quantity but rather on quality. The staff chosen must be committed to the assignment and have sufficient experience and background to identify any abnormalities. The staff should have a good knowledge of the gas flow patterns, temperature profiles, material composition and movement/expansion of the boiler. EPRI was requested to review the existing plans and suggest changes and or additions that will give this assurance, to provide assurance that an adequate and comprehensive plan was in place. During the week August 21, 2000 two EPRI representatives visited the plant, reviewed and discussed the current boiler inspection plan and tube leak history data with the boiler engineer, and interviewed a number of staff from the operating, maintenance and engineering groups.

2.3 Findings and Observations The findings below are based on the Unit 2 outage inspection plan as presented during the review (see Annexure II) and on the personal interviews. 2.3.1 The inspection plan is divided into five sections: burner front, waterwall, Superheater and reheater, back -pass and boiler external. Although the boiler as a whole is covered, the specific inspection details of the areas within each section are not covered sufficiently e.g. superheater, DMW etc. 2.3.2 Each section has been assigned to a responsible person who will manage the inspection and data collection. The boiler engineer has overall responsibility to ensure adequacy of inspections, data collection and coordination between the various sections. 2.3.3 The plan is reactive and focuses almost entirely on inspecting known problem areas e.g. identifying and correcting soot blower erosion damage.

2.3.4 Areas within each of the five sections are not prioritized and no “go” – “no go” criteria given e.g. minimum tube wall thickness and crack/groove size/length and shape.

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EPRI Licensed Material Boiler Reliability Optimization Project Phase 2 – Boiler Inspection Plan Review at Great River Energy’s Coal Creek Station – Unit 2

2.3.5 Documentation of the pre-outage external inspection and walk-down of the boiler is comprehensive 2.3.6 Infrared survey of the boiler casing and valves is not included in the pre-outage inspection. 2.3.7 No provision is made to complete a ‘dirty boiler’ inspection. 2.3.8 The present sootblower maintenance strategy is not in line with current or future operating mode of the unit. Sootblower preventive maintenance has not been adequate, as shown by the number of corrective maintenance activities that have needed to be performed. The top five SB problem areas are: Feed tube wear, Sprocket and chain wear, Bearing failures, Packing failure and Carriage wear 2.3.9 Thermal drains are being replaced with steam traps without a thorough root causes analysis being done to ensure that this is the correct action to take. There is a limited history regarding failures and repairs. 2.3.10 Result trending and predictions cannot be adequately completed, as there is no central database to record and keep boiler test and inspection data and information. Boiler inspection reports that identify actions taken, future actions needed, or lessons learned, are inadequate. All history data on the boiler’s tube leaks is owned and maintained by the Boiler Engineer and is in hard copy format. 2.3.11 Root Cause Analysis is not formally done. The Boiler Engineer maintains tube leak reports, using “CE Availability” data sheets. Not all tube leaks are investigated. History summary is available from 1989. The summary includes date, suspected failure cause, corrective action taken, and recommended outage follow up actions. 2.3.12 Startup and shutdown procedures are combined. They are too general and give little guidance as far as criteria to be met – metal temperatures have been exceeded in the past because of this. No precautionary measures are given to the operator, e.g. when firing the boiler at over pressure.

2.4 Recommendations 2.4.1 A more detailed proactive inspection plan is needed to support a three-year outage cycle plan, while meeting plant goals. The boiler components are time and temperature dependent. Over-stressing these components will accelerate aging. By adopting a proactive stance, knowing the remaining life of these components, replacement plans can be developed and implemented before aging/failure affects unit reliability. 2.4.2 A schedule should be developed for all inspection areas in the boiler. Prioritization should be based on potential findings that would affect outage duration, safety, budget restraints, and unit reliability. All areas that have a high priority should be completed by the end of the first week. This requires a pre-outage study of the duration and cost of inspection techniques to be used. It should include component disassembly, scaffolding, 2-3

EPRI Licensed Material Boiler Reliability Optimization Project Phase 2 – Boiler Inspection Plan Review at Great River Energy’s Coal Creek Station – Unit 2

insulation removal, surface preparation, ventilation, lighting, and environmental compliance. 2.4.3 Criteria need to be developed for the inspection of each area, based on historical data, possible damage mechanisms, typical locations, inspection techniques, required preparation and support, and estimated inspection times. It is important to establish a definition of what are permissible flaws, and what action should be taken regarding a repair/replace decision when an unacceptable flaw is found. Non-critical flaws should be duly noted, entered into the database, and trended over at least two outage cycles. 2.4.4 All data gathered during the inspection, as well as all repair/replace decisions, should be entered into a database maintained by the Boiler Engineer. This database should include ‘as found ‘ and ‘as left’ conditions, repairs made, and recommendations for future outages. Examples of both inspection and repair record formats are included in the annexure I 2.4.5 Expand inspections of the superheater and reheater sections beyond soot blower damage, broken clips, rubbing damage, and ash erosion to include remaining life assessments. UT measurements should be taken to determine the oxide thickness on the superheater. These values can be used to determine the high temperature areas in the SH and will validate the temperature profile as measured by the installed tube metal temperature instrumentation. Tube samples should be taken from hot areas of the SH for metallurgical analysis to determine remaining life. These analyses may have an impact on operating practices. 2.4.6 Horizontal and pendant SH sections are difficult to drain completely, if at all. As a result, they often suffer internal damage due to pitting from condensation. Tube samples should be taken and analyzed for this. 2.4.7 Header base line data, internal and external, needs to be obtained, as it would indicate the effect of past operating modes, and provide information to determine future operating modes. Superheat and reheat headers have never been inspected. Fiber optics can be used to determine if any erosion or cracks have developed. 2.4.8 The current inspection plan calls for inspection of the remaining wall blower refractory tabs. Some of these tabs have been removed, as they have been a source of tube leaks. The remaining tabs should be removed, as they are neither used nor needed and are potential areas for tube leaks. 2.4.9 High stress raisers are potential sources for tube leaks. Inspect and itemize all internal boiler tube attachments for cracks, erosion or damage. 2.4.10 An infrared survey of the boiler casing, valves, and other potential sources of heat loss, should be performed as part of a pre-outage inspection. 2.4.11 A ‘dirty boiler’ inspection should be included in the boiler inspection plan. Many will argue that this inspection is uneconomical. However, there is much to be gained by 2-4

EPRI Licensed Material Boiler Reliability Optimization Project Phase 2 – Boiler Inspection Plan Review at Great River Energy’s Coal Creek Station – Unit 2

observation and correct interpretation of what is observed. An experienced boiler engineer can benefit enormously and gather insight of what is going on inside the furnace from this inspection. Visually examining ash deposits – color, size, build up and profiles - and tube surface conditions, will highlight areas of erosion and high or low gas flow regions. 2.4.12 Although no Dissimilar Metal Weld (DMW) failures have been reported, welds should be inspected visually at every outage using UT. DMW tube samples should be taken and analyzed for remaining life. 2.4.13 The sootblowing system’s design should be reviewed. This should include an evaluation of reliability, availability, maintenance and operating issues. This review should also include an evaluation of the effectiveness of steam traps in eliminating water in the system. From this design review an optimized sootblower operation and maintenance strategy can be developed, implemented, and issued regularly via the Maximo system. 2.4.14 Perform a functional check on all sootblowers. Each sootblower should be operated in turn and checked visually from the inside of the furnace for correct nozzle position, blower insertion length and rotation.

2.4.15 Full implementation of the Maximo system should include the following. – All identified boiler inspection tasks should be kept in the Maximo system as preventive maintenance (PM). – These PM should include, but not be limited to, duration, location, man-hours, equipment needed, and collaboration needed with other groups. 2.4.16 Implement EPRI’s Boiler Maintenance Workstation (BMW). BMW is a Windows-based software program used to track and trend boiler tube failure data and information – tube failures, correction and prevention, and control actions. It consists of two modules Boiler Works and Tube Condition. The boiler works module is a database and graphics program designed to track maintenance failure data/information – failure location and mechanism, repair costs and methods, etc. This collated information is used to focus attention on specific activities, for both planned and forced outages, to prevent future repeat failures. The Tube Condition module stores and analyzes data collected from various inspections, e.g. tube wall thickness, oxide thickness data. It uses two or more data sets to determine wastage rates. These wastage rates are used to determine remaining tube life and predict tube wall thickness. This helps plant personnel plan future boiler tube inspections, maintenance activities and tube replacements. 2.4.17 Following every planned outage, a detailed report should be issued. This report should identify inspection results, repairs and modifications, lessons learned, and activities that need to be planned for the next outage. 2.4.18 All NDE data on boiler pressure parts should be trended and used for failure prediction and long term planning. 2-5

EPRI Licensed Material Boiler Reliability Optimization Project Phase 2 – Boiler Inspection Plan Review at Great River Energy’s Coal Creek Station – Unit 2

2.4.19 Senior Management should support a formalized ‘Boiler Tube Failure Reduction’ team. The team, headed by the Boiler Engineer, should have members from the operations, maintenance and engineering groups. The team should follow a recognized root cause analysis process when analyzing all boiler tube leaks. Records should be kept in a central database and failure statistics and tube condition – minimum wall thickness, oxide thickness and remaining life results, etc., should be tracked and trended. 2.4.20 Separate Unit Start-up and Shut Down procedures should be written, as these are two distinctly different activities each with specific criteria and operator requirements. Each procedure should identify the precautions to be taken before or during each step. This should be followed by a step by step sequence of actions with criteria to be met, e.g. metal temperature rates of change, pressure ramp rate, differential temperatures, etc. Each action should have a check box and a remark column where the operator can check off the action and explain/give reasons for any deviation from the specified criteria.

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EPRI Licensed Material Boiler Reliability Optimization Project Phase 2 – Boiler Inspection Plan Review at Great River Energy’s Coal Creek Station – Unit 2

ANNEXURE I: Extract from a Boiler Inspection Report This report covers all boiler internal inspections, including tubes, burner tips, and dead air spaces performed by Plant personnel. Inspections of the mud drums, the main steam drum, and penthouse are included.

1st digit (location):

1 2 3 4 5

Firebox Upper Arch Down draft Dead-air Spaces, Drums Penthouse

2nd digit (tube type):

1 2 3 4 5

Economizer Tubes Waterwall Circuit Tubes Steam Cooled Tubes Reheater Circuit Tubes Superheater Circuit Tubes

Inspection Areas Most of these are known areas where failures have occurred or repairs have been made during past Periodic Outages and Forced Outages. DM designates D-meter inspections for tube thickness.

1200 Waterwall Cleaning Devices, operational condition This inspection involves both pre-outage and outage responsibilities. Operations must check blower and lance operating conditions prior to Unit shutdown. This requires that all water-lances be tested for proper speed settings and visually verified for operating effectiveness, noting condition of the booster pumps and blowing pressures. All "partial-arc" wall-blowers must be verified for proper operation. Note any existing conditions that may effect tube life and closely inspect theses areas (see item Nos. 1209 and 1210). A furnace side inspection is to be performed by the Boiler Inspection Team from a furnace scaffold, including nozzle head conditions and insertion depth settings on all wall blowers. Inspection results All wall blowers were inserted for inspection and checked for appropriate depth setting, yielding 20 required adjustments (vs. 43 total in 1996). Lists of all damage and needed adjustments were given to the Unit Planner. Depth setting adjustments were made during the outage, while the lance changes were scheduled for after the outage due to parts availability. Over half of the original water-lances (WL) were found with damaged lance tips (cracking or holes).. Lists of all damage and needed adjustments were given to the No. 7 Unit Planner 2-7

EPRI Licensed Material Boiler Reliability Optimization Project Phase 2 – Boiler Inspection Plan Review at Great River Energy’s Coal Creek Station – Unit 2

Recommendations for 2004: Several of the lances were binding on start-up, and at least three of the lance tubes will need replacement. Air cooling to the control boxes will be added to keep the box temperatures below 0 122 F. Access to WL nozzles inside the windbox will need to be made during a furnace cleaning outage. For 2004, wall blower and WL repairs and adjustments are expected to be minimal. 1501 Superheat Division Panels, attachment problems Look for misalign tubes and possible resulting damage. Look for failed "wrapper tube" ties. Look for abrasion damage from the attachment “ears” rubbing into adjacent tubes. Recommend repairs.

division tub

attachment rub damage Attachment “ear”

Figure No.

area(s)

6

Inspection results: There were 10 locations found and repaired (vs. 31 found and 23 completed in 1996). Of these, two were failed attachments, and 8 were from attachment rubbing damage. Some of the rub damage locations were severe, causing abrasion damage in excess of 1/2 wall thickness (see Fig. 6). The recommended repair for the ear rubbing was to remove that portion of the attachments. Recommendations for 2004: Continue inspections for failed attachments and attachment ear rubbing. Expect nearly the same amount of work as in 2001.

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EPRI Licensed Material Boiler Reliability Optimization Project Phase 2 – Boiler Inspection Plan Review at Great River Energy’s Coal Creek Station – Unit 2

ANNEXURE II: Unit 2 Outage Inspection Plan as of August 21, 2000 This plan contains numerous visual checks and does not give guidance on what to look for, how to look for it, and what to do with the data/information obtained? Some guidance needs to be documented for each team on what to do if cracks or dents are identified, e.g. measure wall thickness, cut out and insert a “Dutchman”, weld over lay, etc. Comments/additions have been made in each section below. For ease of identification they have been underlined. 1. Burner Front Team Member Will perform burner front inspection and coordinate all repairs of the burner from inside and outside the boiler. The following inspections will be performed: 1.1 Prior to the outage (within 2 weeks of the start of the outage) Conduct and external walk down of the burner fronts from 5th floor to 10th. The items to check shall include: •

Look for any coal or ash leaks around the coal piping and nozzles.

•

Check the condition of all coal piping spring hangers. A. Record the hot position of the hangers. B. Check if any hangers are bottomed out. C. Visually inspect the hanger rods and attachment pins. D. Inspect the hanger lugs on the support steel and on the coal piping.

•

Note if any hagen drives are disconnected.

•

Inspect the air supply and signal lines to the hagen drives. Check for any broken or disconnected lines and to see if any lines have broken loose from their supports. Check the condition of the multi tube lines from the burner front to the LIE cabinets.

•

Check with Operations and the E&I techs to see if any of the tilt drives are short stroked.

•

Visually inspect the external tilt linkage for any members that are bent, broken or disconnected.

•

Note from the Honeywell any flame scanner with low intensity readings. These scanners will be inspected in detail after the unit is off line.

•

Check with the E&I techs to find out if there are any flame scanners that they have had trouble inserting or removing. Also check to see if there are any work orders on the flame scanners.

•

Check for any oil leaks around the burner front oil guns and supply piping. 2-9

EPRI Licensed Material Boiler Reliability Optimization Project Phase 2 – Boiler Inspection Plan Review at Great River Energy’s Coal Creek Station – Unit 2

•

Inspect all of the oil guns and spark igniters and oil gun air lines.

•

Visually inspect the new SAS air ducts on 9th and 10th floor. A. Visually inspect the SAS duct hanger rods and attachment pins. B. Check for any interference's between the SAS registers and the structural steel. C. Inspect the windbox hanger rods on 9th floor.

•

Visually inspect the fabric expansion joints.

•

Inspect all external pipe work of the various systems for steam and water leaks, sagging, abnormal internal noise, signs of shock, pipe guides, hangar supports – free movement of constant and spring supports, missing bolts and nuts and dust covers, signs of corrosion and integrity of the supports.

•

Inspect boiler skin casing cladding for damage, missing or corroded sheets.

•

Inspect all ducts for air and gas leaks, abnormal movement or vibration, defective damper linkages or fouling with moving parts.

•

Inspect the boiler main and sub structure for deformation, missing bolts and nuts, flame cutting damage, severe corrosion, signs of unauthorized welding on main load bearing beams, beams/buckstays for sagging and or distortion.

1.2 At the start of the outage (During the installation of the boiler scaffolding) •

Inspect the windbox and windbox expansion joints.

•

Stroke all of the windbox dampers manually, checking for any that are binding and that the connector link between the damper blades is intact.

•

Remove all the flame scanners and insert an old one in each guide tube noting any problems with inserting the flame scanner.

•

Manually stroke the tilts on the over and underfire air compartments and the underfire air compartment dampers.

•

Stroke all aux air and SAS yaws.

•

Inspect the inside of the SAS ducts. Check condition of the fabric expansion joints and air dampers.

1.3 Burner Front inspection (Upon completion of the boiler scaffolding) •

Insert all oil guns and check the dimension from the face of the diffuser to the oil gun tip. See the CE drawing for details.

•

Insert all of the ignitors and check the insertion depth and position of the ignitor tip.

•

Inspect the oil nozzles looking for the following items.

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EPRI Licensed Material Boiler Reliability Optimization Project Phase 2 – Boiler Inspection Plan Review at Great River Energy’s Coal Creek Station – Unit 2

A. Condition of the tip. Look for distortion and burning of the tip. (Oil guns should be tested in a test rig to ensure proper oil spray angles. This help determine the performance of each gun) B. Check condition of the oil gun and the flame scanner guide tubes. C. Look for broken or bent tilt linkage. Note if any lever arms are working off of the stationary pivot pin. D. Note if any of the diffuser discs are missing on the elevation 5/6 and 7/8 oil nozzles. •

Inspect the coal nozzles looking for the following items. A. Condition of the two piece tip. Determine which tips will be repaired or replaced. B. Check for thinning of the removable transition piece on the front of the coal nozzle body. C. Check for missing or loose ceramic tile in the coal nozzle body and gate body. D. Look for broken or bent tilt linkage. Note if any lever arms are working off of the stationary pivot pin.

•

Inspect the aux air and SAS nozzles looking for the following items. A. Condition of the tip. Look for distortion and burning of the tip B. Check condition of the yaw linkage, looking for any bent or broken pieces. C. Check condition of the scanner guide tubes in the aux air nozzles. D. Look for broken or bent tilt linkage. Note if any lever arms are working off of the stationary pivot pin.

Use the form shown as Attachment 1 to record all of the repairs that the contractor shall perform. All repairs such as nozzle replacement, linkage repairs and nozzle ceramic repairs should be detailed on the form.

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EPRI Licensed Material Boiler Reliability Optimization Project Phase 2 – Boiler Inspection Plan Review at Great River Energy’s Coal Creek Station – Unit 2

2. Waterwall Team Member Will perform inspections and coordinate repairs of the waterwalls, center wall and slopes. The following inspections will be performed. 2.1 Prior to the outage (within 2 weeks of start of the outage) •

Review the tube leak records for the last three years and identify any areas that need further repairs. This should include any areas where window were installed or any areas where tubes were just welded shut.

2.2 Prior to the installation of the boiler scaffolding (after the throat scaffolding is installed) •

Perform a general visual inspection of the slope before the scaffold is installed. Check for large dents in the slope, dented tubes and worn areas. The wear areas should include the following. A. The slope along the side walls under corners 2 and 7. B. Both the front and rear slope along both sides of the center wall. C. The side walls at the throat opening. D. The center wall where it penetrates the slope.

2.3 Upon completion of the boiler scaffold •

Clean the waterwalls and perform an UT inspection of the waterwalls between the upper burner front and the SAS registers. See the attached drawing, Attachment 2 for details of the area to be inspected.

•

Inspect all of the wall blower openings. The following items should be checked. A. Visually inspect for any worn or eroded tubes. Mark any tubes that may need a follow up UT inspection. Mark any tubes that require replacement. (Criteria need to be developed – 70 % wall thickness is commonly used) B. Check the condition of the refractory and mark any openings that require refractory repairs. A list of the openings requiring refractory repairs should be forwarded to the External Boiler Team Member. C. Visually inspect for any cracking occurring at the tabs welded around the opening. (Remove unnecessary tabs by carefully grinding)

•

Inspect the crotch tubes at the top and bottom of the burner front and SAS register openings.

2-12

EPRI Licensed Material Boiler Reliability Optimization Project Phase 2 – Boiler Inspection Plan Review at Great River Energy’s Coal Creek Station – Unit 2

•

Perform an UT inspection of the boiler nose. (“Go” and ‘no go” criteria need to be provided). See the attached drawing, Attachment 2 for details of the area to be inspected.

•

Inspect the bends in the waterwall tubing below the nose. Perform a random UT inspection of the tube bends. (record the measurement position and tube location as a reference)

•

Inspect the bends at the bottom of the radiant reheat section. Perform a random UT inspection of the bends. Also check for any tubes out of alignment or bent tubes.

•

Visually inspect the joints between the center wall panels. Check for rubbing damage on the tubes at the panel joints.

•

Perform a visual and UT inspection of the slope looking at the following areas. A. The front and rear slope along both sides of the center wall. The area to be inspected should be the full length of the slope for a 20 tube wide panel. B. The slope along the side walls under corners 2 and 7. The area to be inspected should be the full length of the slope for a 20 tube wide panel. C. The slope just below the upper bends directly under burner fronts 2, 4, 5 and 7.

•

Inspect the front wall between the burner front and radiant reheat for any tubes that are smashed or dented.

•

Replace the lower radiant reheat bend and section of tubing in furnace ‘A’ that previously failed.

•

Remove a two tube samples from the waterwalls. The sample should be removed from the front or rear wall on ninth floor between the burner fronts. (consider taking more samples to get a representative set)

2.4 Upon completion of the bottom ash scaffolding •

Visually inspect for any smashed or dented tubes at the throat opening.

•

Check the side wall tubes at the throat opening. Check the horizontal tubes at the center joint of the side wall.

•

Inspect the lower side of the throat tubes.

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EPRI Licensed Material Boiler Reliability Optimization Project Phase 2 – Boiler Inspection Plan Review at Great River Energy’s Coal Creek Station – Unit 2

3. Superheat and Reheat Team Member Will perform inspections and coordinate repairs of the superheat and reheat pendants. This work will be completed on night shift. The following inspections will be performed. 3.1 Prior to the outage (within 2 weeks of start of the outage) •

Review the tube leak records for the last three years and identify any areas that need further repairs. This should include any areas where windows were installed or any areas where tubes were just welded shut.

3.2 During the outage •

Visually inspect all of the sootblower lanes on the leading edge of the superheat pendants. This work will be performed using the boiler scaffolding.

•

Visually inspect the fluid cooled spacer tube that runs through the front of the superheat pendant. Check for broken clips or rubbing damage.

•

Scaffold the sootblower lanes in the center of the superheat pendants and visually inspect all sootblower lanes. A. Special attention should be given to inspecting the double offset bends in the crossover area. B. Visually inspect the fluid cooled spacer tube that runs along the center wall. Check for rubbing damage. C. Check for any broken or missing flex connectors in the pendants D. Inspect the bent tubes located on the A side of the furnace. Determine what repairs will be required to straighten the tubes.

•

Scaffold the sootblower lanes between the rear waterwall hanger tubes and the reheat pendants. The following inspections should be performed. A. Perform a UT inspection of the trailing edge of the rear waterwall hanger tubes at each sootblower lane. B. Inspect the rear waterwall hanger tubes where they penetrate the slope. Check for ash erosion on the trailing edge of the tube from ash sliding down the slope and check the leading edge for flyash erosion. C. Visually inspect the leading edge of the reheat pendants and the trailing edge of the superheat pendants at each sootblower lane, checking for sootblower erosion. D. Visually inspect the fluid cooled spacer tubes located in the center of the boiler on the back side of the superheat pendants. Check for rubbing damage between the spacer tube and the rear waterwall hanger tubes and superheat pendants.

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EPRI Licensed Material Boiler Reliability Optimization Project Phase 2 – Boiler Inspection Plan Review at Great River Energy’s Coal Creek Station – Unit 2

E. Inspect the fluid cooled spacer tube that runs through the front of the reheat pendants. Check for broken clips or rubbing damage. F. Inspect the front lower bends of the reheat pendants. Check for sootblower erosion on the inside and outside of the bends and for any missing or damaged tube shields. •

Perform oxide thickness measurement on the “hottest” across the superheater to determine the temperature profile.

•

Remove samples for metallurgical analysis – creep damage and remaining life.

•

Inspect DMW for cracks. If cracks are found cut out a section and replace with a “Dutchman”. If no cracks found cut out a section from the hottest area for metallurgical analysis.

•

Scaffold the sootblower lane on the back side of the reheat pendants. The followings inspections should be performed. A. Visually inspect the sootblower lane looking for sootblower erosion. Special attention should be directed to the double offset bends in the crossover and to the bottom side of the horizontal crossover tubes. B. Visually inspect the spacer strap in the reheat finishing section, looking for broken or missing U straps. C. Check for any broken or missing flex connectors D. Inspect the tube shields at the bottom sootblower on the trailing edge of the reheat pendants. Check for missing or damaged shields.

•

Inspect all sootblower openings along the side wall. Check for tube erosion and for cracking along the tabs. Also visually check the condition of the lance nozzles.

•

Inspect the roof and slope tubes, checking for bent or warped tubes.

•

When performing pendant inspections special attention should be given to the first five pendants from each side wall. Historically the first five pendants have suffered more severe sootblower erosion.

2-15

EPRI Licensed Material Boiler Reliability Optimization Project Phase 2 – Boiler Inspection Plan Review at Great River Energy’s Coal Creek Station – Unit 2

4. Back-pass Team Member Will perform inspections and coordinate repairs of the back-pass from the furnace screen tubes to the economizer. The following inspections will be performed. 4.1 Prior to the outage (within 2 weeks of start of the outage) •

Review the tube leak records for the last three years and identify any areas that need further repairs. This should include any areas where windows were installed or any areas where tubes were just welded shut.

4.2 During the outage •

Perform an UT inspection of the inner radius of the lower bend of the furnace screen tubes just above the refractory dam.

•

Visually inspect the spacer straps in the front of the superheat finishing section looking for missing or broken U clips. Also inspect the spacer straps that wrap around each pendant. Check for any broken or cracked welds on the front of the wrap around straps. 30 new straps have been ordered based on a previous inspection. Inspect for sootblower erosion along the lower sootblower lane on the front of the superheat finishing section and the rear of the furnace screen tubes.

•

Scaffold the sootblower lanes on the front side of the superheat finishing section. Visually inspect the condition of the tube shields on the trailing edge of the furnace screen tubes. Visually inspect the condition of the superheat pendants checking for sootblower erosion and broken or missing flex connectors.

•

Visually inspect the rear extended backpass floor tube located directly in front of the superheat backpass front tubes. Check for sootblower erosion on the floor tube that occurs in the spaces between the backpass front tubes.

•

Scaffold the upper sootblower lane on the back side of the superheat finishing section. Check for sootblower erosion on the trailing edge of the superheat pendants and on the leading edge of the backpass front wall tubes.

•

Visually inspect the spacer straps located on the backpass front wall tubes.

•

Check for any U clips that are broken or have burned off. Also check for any damaged tube shields in this area.

•

The sootblower lane for retracts 19 and 48 which is located at the rear of the front wall tubes will require several inspections.

missing or superheat

A. The trailing edge of the superheat front wall tubes and the top side of the horizontal superheat tubes should have a UT inspection performed on them along this sootblower lane. B. The front side of the superheat low temperature pendants should be visually inspected for sootblower erosion and for missing or damaged tube shields. Special attention should be given to the lower bends on the low temp pendant section. 2-16

EPRI Licensed Material Boiler Reliability Optimization Project Phase 2 – Boiler Inspection Plan Review at Great River Energy’s Coal Creek Station – Unit 2

C. There was a previous tube failure on the West Side on the top of the superheat horizontal section. Tubes number 2 and 3 from the West Side wall should be replaced. •

Visually inspect the top of the horizontal superheat section. Check for any tubes that have broken loose from the hanger tubes and check the bends on each end for any bend that may be displaced and rubbing on an adjacent tube row. Also check the condition of the refractory and flyash screens located at the rear bends of the horizontal superheat. Inspect the rear bends for any indication of flyash erosion.

•

Inspect the area between the two horizontal superheat sections. Check for any tubes that have broken loose from the hanger tubes. Visually inspect the spacer straps located on the front hanger tubes. Check for any broken or missing U clips and to ensure that the straps are still raised up off of the horizontal tubes in the center half of the boiler. The spacer straps were raised because they were deflecting the sootblower steam down against the horizontal tubes.

•

Special attention should be given to inspecting the sootblower lanes for retracts 10 and 39. This area has been a very high wear area. A. Check the condition of the tube shields located on the lower side of the upper horizontal section. The condition of these tubes on the lower side of the upper horizontal section should be checked at least 5 tubes deep up into the bundle. B. Check the condition of the deflectors installed on the hanger tubes. The horizontal tubes should be checked for sootblower erosion where they are attached to the hanger tube. C. Visually inspect the condition of the pad welding on the top side of the lower horizontal section. A UT inspection of these tubes should be performed on any tubes that are not covered with tube shields.

•

Visually inspect the area on the topside of the economizer. Check for any broken economizer hangers or bent tubes. Perform an UT inspection on the topside of the bends located at the superheat horizontal inlet header. These tubes have shown signs of flyash erosion on the outer radius of the bends.

•

Inspect the area located between the economizer sections. Check for any broken hangers or bent tubes. Check the condition of the offset bends located along the superheat backpass front inlet header located along the front wall. These offset bends have been subjected to some flyash erosion.

•

Check the condition of the refractory dam at the furnace screen tubes. Check for any broken or missing pieces.

•

When performing pendant inspections special attention should be given to the first five pendants from each side wall. Historically the first five pendants have suffered more severe sootblower erosion.

2-17

EPRI Licensed Material Boiler Reliability Optimization Project Phase 2 – Boiler Inspection Plan Review at Great River Energy’s Coal Creek Station – Unit 2

5. External Boiler Team Member Will perform inspections and coordinate the repairs external to the boiler. The following inspections will be performed. 5.1 Prior to the outage (within 2 weeks of the start of the outage) Conduct an external walk down of the boiler from 21st to 2 1/2 floor. The items to check shall include: •

Condition of the buckstays. Checking for any binding or bent buckstays. Look for any missing or loose pins in the connector links for the boiler trusses.

•

Check for any external steam leaks at the sootblowers, sootblower piping and boiler vent and drain valves.

•

Note any lagging or flashing that may require repair. Check the Maximo system for workorders for any boiler vent and drain valves that may require a code repair. Review all boiler valves that are going to be replaced to determine if the repairs should be code repairs.

5.2 During the outage •

A visual inspection should be performed in the front and rear lower dead air spaces. The following items should be checked. A. Inspect all of the hanger rods checking for broken or missing pins. Also check for cracking on the hanger rod lugs. B. Check for any missing or cracked tube clips on the horizontal buckstays. C. Perform a dye penetrant inspection where the side wall capture angle irons are welded to the back side of the slope tubes. D. Visually inspect the scallop bars located at the bottom of the side walls. Check for any cracking where the scallop bar was repaired and for any cracking were the scallop bar is welded to the tube. E. Check for any cracking in the tube membrane located towards the inside of the side wall scallop bars. F. In the rear dead air space, check the condition of the centerwall tube nipple that was cut off and plugged. G. Check for any bent or cracked buckstays and structural steel. H. Visually inspect for any tube membrane cracking at the throat bends and where the slope is welded to the side walls.

2-18

EPRI Licensed Material Boiler Reliability Optimization Project Phase 2 – Boiler Inspection Plan Review at Great River Energy’s Coal Creek Station – Unit 2

•

Visually inspect both upper dead air spaces. Check for any membrane or skin casing leaks and check the condition of the structural steel.

•

After the boiler has cooled, walk down the entire external boiler checking for any bent or warped buckstays.

•

Inspect the upper boiler drum, check the following items. A. The turbo separators, checking for alignment, loose hold down clamps and the condition of the chevrons. B. Missing or loose screens at the downcommer nozzles. C. Loose or missing feed pipe hold down clamps. D. The condition of the secondary separators. E. Plugged lines for the boiler level devices.

•

Inspect the lower boiler drums, check the following items. A. Check for any missing orifices or orifice clamps. B. Check the condition of the screens. Look for any loose or missing screen bolts. C. Visually inspect the drum crossover links.

•

Remove the hand hole covers on the superheat desuperheaters and use the borescope to check the condition of the liner, set screws and the nozzle.

•

Visually inspect all of the boiler access and inspection doors recording any that require refractory or other repairs.

•

Perform an internal inspection of the penthouse checking for the following items. A. Check the condition of all the hanger rods. Check for broken rods or missing pins. B. Look for any tubes that exhibit signs of overheating. The overheated tubes will have a dark discoloration and may have some scale exfoliation. C. Look for any cracks and flyash leaks in the skin casing. Also check for any flyash leaks at the crown seals. Special attention should be given the skin casing at the center of the boiler. The boiler has a history of skin casing cracks along the center of the boiler D. Check the condition of the insulation at the superheater outlet header and links. E. Visually inspect all of the trapeze hangers located on the connector links.

2-19

EPRI Licensed Material Boiler Reliability Optimization Project Phase 2 – Boiler Inspection Plan Review at Great River Energy’s Coal Creek Station – Unit 2

F. Visually examine all of the headers. Look for any signs of cracking at the nipples or ligaments.(Suggest you use some NDE method than just looking – dye penetrant) Perform and inspection on top of the penthouse. Check the condition of the upper hanger rod attachment looking for any missing pins or cracked lugs.

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EPRI Licensed Material

3 BOILER RELIABILITY OPTIMIZATION PROJECT PHASE 1 AT DETROIT EDISON’S ST CLAIR PLANT – UNIT 7 AMERICAN ELECTRIC POWER’S BIG SANDY PLANT – UNIT 2

Executive Summary In an effort to improve boiler reliability at the Detroit Edison St. Clair Plant, EPRI was contracted to identify technical and programmatic opportunities for improving Unit 7 boiler reliability. The scope of work was limited to a portion of Phase 1 of EPRI’s Boiler Reliability Optimization project, namely boiler tubes and headers. The study was requested by the then Production Manager – Phil Thigpen from St Clair Plant. A team from EPRI spent two weeks on site reviewing plant record, boiler inspection plans, procedures etc and conducted interviews with key operations, maintenance and engineering staff. A list of those interviewed can be found in appendix 1. The report focuses on two areas - the programmatic and data collection and tube failures and their causes and highlights a number of opportunities for improvement with respect to managing the short and long term health of the boiler. From the review of the data/information obtained and the interviews revealed that the current maintenance strategy, of a periodic every three years, is in line with other utilities however the duration is out of step with best practice in the industry. Utilities with comparable units have 4 to 5 week outages with a Forced Outage Rate of between 4 and 6 percent. . Unit # 7 has a comprehensive boiler tube inspection plan. Tube leaks, their causes and action plans to prevent recurrence are recorded and well managed as evidenced by the reduction in the number of tube leaks over the past five years. The inspection plan is reactive as it only includes known boiler tube problem areas. Inspection of the headers is limited to the superheater and reheater outlet header. This is of concern as there is little to no information is available about the condition of the remaining headers within the boiler. The recent down sizing and re-organization has resulted in some uncertainty regarding the roles and responsibilities of the newly formed service groups. Key staff have been moved to perform other project activities, thus losing the advantage gained from past inspections. Organizational measures and measurements were also not well understood. To improve and sustain a high boiler reliability/availability and to minimize the future risk of down time and subsequent production loss it is recommended that Detroit Edison – St Clair Plant 3-1

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1 at Detroit Edison’s St Clair Plant – Unit 7 American Electric Power’s Big Sandy Plant – Unit 2

•

Invest into a comprehensive Boiler Reliability Optimization program to develop a detailed Boiler Failure Defense Plan. This plan would assist in the development of a specific Boiler Test and Inspection Plan that would cover all the major components within the boiler envelop. This plan can then be integrated into an expanded – 15 years plus Long term Reliability Plan. This can be accomplished through EPRI’s Boiler Reliability Optimization Program

•

Review the basis of their current outage management philosophy and approach. The current nine week outage on unit # 7 is out of step with other USA and international utilities even with the current turbine problems being experienced. Huge operating and maintenance cost saving and increased revenue can be made by reducing outage times by bring them inline with best practice.

•

Implement the recommendations identified in the various section of this report.

Participating in Phase II of EPRI’s Boiler Reliability Optimization Program would not only enhance the efforts being put into the program but will give Senior Management the assurance that the goals being set will be met. Membership details and costs related to a Phase II can be obtained from the author. Armed with the information in this report and available resources, St Clair plant can become the “Best Practice “ plant within the Detriot Edison organization for which it has been striving to become. Given time, management commitment and coaching in EPRI’s Boiler Reliability Optimization Program, the plant team has the vision and capability, as evidence in the Boiler Tube Inspection Reports, to successfully lead the plant into full implementation of a Boiler Reliability Optimization Project.

3-2

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1 at Detroit Edison’s St Clair Plant – Unit 7 American Electric Power’s Big Sandy Plant – Unit 2

3.1 Introduction Detriot Edison St Clair Unit 7 had a history of tube failures causing considerable down time with corresponding loss of production. Phil Thigpen, the St. Clair Production Manager, requested that EPRI be contracted to review their boiler technical plans and identify opportunities for improvement. The scope of work was limited to the high pressure, high temperature boiler components – tubes and headers. Four EPRI team members - Dave McGhee, Pat Abbott, Jack MacElroy, and Jim Cossey spent varying amounts of time on site studying documentation and conducting interviews. Interviews were conducted with both Plant and Support staff responsible for activities on the boiler. These interviews were conducted during the weeks of May 15 and August 29. 2000. The names of those interviewed are listed in the appendix 1. All relevant and available data and information on Boiler 7 was reviewed. In addition, data and information relating to the overall management of the boiler, from an operating, maintenance and engineering point of view was reviewed. This enable the team to gain an insight into the overall approaches taken to manage the technical aspects of the boiler.

3.2 Findings and Observations Based on the scope of work, the following represents the findings and observations in the two areas, viz. programmatic/data sources, and failures and root causes. 3.2.1 Programmatic and Data Sources Assessment A maintenance process assessment was conducted as part of the work performed in this project. The purpose is to understand how the management processes and technologies used in the plant affect or influence boiler operation and maintenance and therefore the long-term health. Data was collected and evaluated and benchmarked against known best practices. The assessment team spent a week on site reviewing this data and interviewing key site and support staff. From the data analyzed, together with the information obtained from the interviews a “spider” chart was drawn.

3-3

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1 at Detroit Edison’s St Clair Plant – Unit 7 American Electric Power’s Big Sandy Plant – Unit 2

Score

Score

Maintenance Strategy 8 Utilization Work Identification 6

Skills/Experience Profile

4

Technical Resource Development

2 0

Metrics Communication

Work Control Work Closeout Documentation Project Management

W orld Cla ss

Change Control

Roles & Responsibilities

Operating Practices

Performance Monitoring

Boiler Inspection Plan Technical & Action Plans

Figure 3-1 Spider Chart

3-4

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1 at Detroit Edison’s St Clair Plant – Unit 7 American Electric Power’s Big Sandy Plant – Unit 2 Attribute

Key Findings

Boiler Maintenance Strategy

Conscience change from 2 to 3 years Inspection and repair plan is aligned with outage frequency

Work Process

50% of the backlog are preventive maintenance activities. “as found” and “as left” conditions were not being documented

Project/Outage Management

Capital projects are detailed and well planned Performance/Reliability of a unit returning from a periodic outage does not meet expectations i.e. not optimal Unreliability and unavailability occurrences are not investigated to determine their cause and root cause.

Operating Practices

Critical boiler metal temperatures are not monitored or trended Metal temperature excursions are not analyzed or recorded No objective evidence to indicate that boiler start-up or shut down procedures are followed Sootblowing procedure and criteria are not being adhered to.

Boiler Test and Inspection Plan

Well documented boiler tube inspection and repair plan No detailed condition assessment of all boiler headers – only superheater and reheater outlet are inspected

Metrics and targets

Overall plant performance targets exists Boiler EFOR is not measured Boiler tube leak target is place

Roles and responsibilities

Many of the staff interviewed were unsure of their roles and responsibilities and that of the support group. This was illustrated by the performance of unit 4 after its periodic outage

Performance Monitoring

Superheater metal temperature excursions are not investigated or recorded No objective evidence that excess oxygen is controlled or monitored

Skills/experience profile

Experienced people are being lost due down sizing and retirements. This affects the transfer of technical “know how” to new incumbents - operators

3-5

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1 at Detroit Edison’s St Clair Plant – Unit 7 American Electric Power’s Big Sandy Plant – Unit 2

3.2.1.1 Maintenance Strategy The starting point for developing a maintenance strategy is to first determine a maintenance objective. An objective should be quantified in terms of availability and performance. These requirements should be determined jointly between the Maintenance and Operating and or the Production Departments. Maintenance Management is then in a position to determine the best mix of maintenance techniques to use, resources requirements and the costs thereof. A Maintenance strategy is then developed from these agreed objectives. It defines the process for identifying and achieving sound operational objectives, selecting the maintenance approaches, monitoring performance and providing effective management control. The strategy therefore consists of a management and technical strategies. The Management strategy defines how the business management skills are used to integrate people, policies, equipment and practices to identify improvement opportunities. The Technical strategy states the what, who and how the technical knowledge and experience are used to identify and implement the best proactive maintenance, repair, service and replacement of all equipment in line with the Plant’s business performance objectives. The technical strategy therefore consists of a combination of corrective, preventive, predictive and proactive maintenance activities where: Corrective – “Fix it when it breaks” Preventive – “Fix it before it breaks” Predictive – “Fix it when it starts to break” Proactive – “Fix it before it starts to fail” The maintenance strategy is built primarily from the preventive and predictive maintenance basis that exists at the plant. 3.2.1.1.1 Findings

•

The Preventive Maintenance (PM) base has not been updated for some years. Preventive maintenance is not being done judged on the age and extent of PM in the backlog.

•

Random outage rate (ROR) – defined “as the sum of all forced outages and de-rates and all unforeseen outages and de-rates divided by the available generation excluding periodic outages and de-rates and expressed as a percentage” is the availability/reliability measure used.

•

Nearly all the staff interviewed could not define ROR nor did they know what the target was for St Clair.

•

The planned outage frequency has been increased from two years to three years. The next periodic is scheduled for Spring 2001

3-6

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1 at Detroit Edison’s St Clair Plant – Unit 7 American Electric Power’s Big Sandy Plant – Unit 2

•

During the 1998 periodic an extensive inspection and repairs were carried out on the boiler tubes. Since the return to service to August 2000, only two boiler tube leaks outages have occurred. Thus meeting management’s expectations/target, of one tube leak per unit per year. This achievement illustrates the effort that has been put in by the boiler engineer to reduce the risk of tube leaks.

•

Boiler tube inspections are detailed and thoroughly done, the data and information obtained from these inspections and subsequent repair work is stored on the Boiler Engineer’s computer.

•

Ownership of the boiler preventive and predictive maintenance basis is unclear.

•

EPRI’s Boiler Maintenance Workstation (BMW) has been purchased however implementation has been restricted because of the lack of allocated financial and human resources.

3.2.1.1.2 Recommendations

•

Clearly define and allocate the roles and responsibilities of the various plant system engineers.

•

Clearly define plant performance measures and targets to all staff. These should be tracked, trended and displayed where everyone can see them.

•

Review and update the PM basis on the boiler and its auxiliaries. This can be achieved through the use of a reliability centered maintenance package. The aim is to develop an optimized set of PM tasks that will ensure the plant will achieve its reliability targets.

•

Continue with the detailed boiler tube inspection program and develop a common database, accessible to other key people, that enables trending of the data and information and predictions to be made.

•

Allocate resources to complete the implementation of the BMW throughout all Detroit Edison plants

3.2.1.2 Work Process A typical work process consists of four separate, but equally important steps. •

Work Identification - Work is identified as corrective, preventive, predictive, or pro-active.

•

Work Control - Establishing a balance between the four types of identified maintenance which maximizes the use of manpower while ensuring that the proper maintenance is performed on equipment at the appropriate time.

•

Work Execution - Work is planned and scheduled. Parts and tools are staged and the proper level of manpower is dedicated to the job.

•

Work Closeout – Recording of “as found” and “as left” information on all work orders. This information is maintained in an electronic database and used to plan future maintenance activities.

3-7

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1 at Detroit Edison’s St Clair Plant – Unit 7 American Electric Power’s Big Sandy Plant – Unit 2

3.2.1.2.1 Findings

•

Periodic outage duration is between 7 and 9 weeks. Boiler inspection is an on going activity that can take up to three weeks to complete while boiler cleaning and scaffolding is accomplished during the first week of the outage..

•

Boiler tube repairs made during planned periodic outages are well documented albeit in an independent system to the CMMS. The inspection report and repair records are well written, detailed, and complete. The repair record identifies the location of all repairs and the type of repair made on the tubes, as well as the suspected failure mechanism.

•

All boiler tube repairs during a periodic are prioritized using three levels, #1 being the highest priority.

•

Numerous priority # 2 and # 3 are not completed because of lack of time and resources.

•

Quality control plans for boiler tube repairs are used and checked by the boiler engineer.

•

Recommendations made by the Boiler Engineer as a result of a periodic outage inspection are not acted on until a few months before the next periodic outage. With the current outage frequency, this could be a three-year gap. The responsibility for acting on these recommendations is not clearly understood or defined.

•

There is no backlog of planned boiler work – preventive, predictive etc to be worked during forced outages, nor is there a team dedicated to boiler inspections during forced outages.

•

Boiler performance data does not play a role in planning boiler outage work. The large amount of data generated by the DCS system or stored in the PI system to assist in directing or planning boiler work is not being used. Parameters such as tube metal temperatures, temperature changes across reheat and superheat sections, furnace gas temperatures, heat rate, and changes in gas pressure and flows can be used to direct inspection and repair activities.

•

A long-term Reliability Management plan has been developed. The plan establishes five year ROR, LOP, and generation targets for the St. Clair Power Plant. The plan details work to be done at the next periodic outage, and there are no specific plans for the high pressure sections which are approaching or exceeded the expected 100,000 hours life expectancy.

•

Although net heat rate is mentioned in the long-term Reliability Plan, there are no goals established for heat rate improvement, or heat rate improvement projects listed

3.2.1.2.2 Recommendations

•

Conduct a technical review of outage management. This review should be and based on sound project management principles and include a technical review of the scope of work from each discipline. Many USA and International utilities are achieving 4 to 5 week outages every three years. These plants are similar to St Clair Unit # 7 in size and capacity burning Powder River Basin Coal. Shortening a 9 week outage by two weeks would have huge impacts on outage costs and revenue.

•

The boiler inspection plan should be integrated into an all-inclusive Predictive Maintenance (PdM) plan. A PdM program consists of a series of activities that are performed prior to breakdown in order to forestall the immediate occurrence of impending failures. The present

3-8

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1 at Detroit Edison’s St Clair Plant – Unit 7 American Electric Power’s Big Sandy Plant – Unit 2

boiler inspection program focuses on identifying and correcting existing problems. Application of PdM methods for boiler inspections and inclusion of findings into an integrated plant PdM database would enhance the scheduling and planning of boiler maintenance work and contribute to reduced ROR goals. The inspection report and repair records prepared by the boiler engineer are key indicators of the boilers condition. These indicators should lay the groundwork of both long- and short-term planning for the boiler maintenance program and improvement projects. •

Responsibility for compiling work orders, and following through on recommendations made as a result of the boiler inspections, should be assigned and acted on in a timely manner. The reports should be made available in electronic form to all Detroit Edison employees involved with the boiler maintenance program.

•

Advantage should be taken of forced outages to inspect available areas of the boiler. “Trigger ready” forced outage plans - work orders/work packages need to be developed for inspection of identified problem areas in the boiler immediately following both periodic and forced outages. Thus, in the event of a forced outage advantage can be taken to perform boiler inspection and or repair work.

•

The present long-term plan should be expanded to a minimum of ten years and a maximum of twenty years. Mile stone years should be based on the outage frequency i.e. the plan should have significant detail for years one, three, six etc. The steps to consider in formulating this long-term plan are:

•

History 1. Design review 2. Construction review 3. Operating and maintenance history review 4. Inspection reports 5. Industry experiences

•

Evaluation of Present Condition 1. Metallurgical evaluations 2. Visual inspections 3. Non-destructive examination (NDE) prioritization 4. Destructive examination prioritization 5. Operating conditions and practices 6. Maintenance strategy 7. Database compilation

•

Plan Formulation 1. Remaining life assessment 2. Long-term inspection plan 3. Risk assessment 3-9

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1 at Detroit Edison’s St Clair Plant – Unit 7 American Electric Power’s Big Sandy Plant – Unit 2

4. Short and long-term recommendations •

Plan Re-evaluations 1. Review and updating of inspection plan 2. Reviews of new NDE technology 3. Inspection planning and scheduling 4. Risk assessment re-evaluation 5. Confirmation of remaining life assessment 6. Updating of plan database

•

Boiler performance and process data (metal temperatures, excess oxygen, steam and water temperatures and pressures and air and gas temperatures) is available via the DCS and PI system and should be tracked and trended. Deviations from specified should be investigated analyzed and action taken to prevent recurrence.

•

Enforce the use of the CMMS historian. No Work Order should be closed out until the craftsman who has done the work fills out this section of the Work Order. Every Work Order should be reviewed for repeat failures, and a proper action plan developed. This is a key factor in the continuous improvement cycle.

3.2.1.3 Predictive Maintenance Program and Technology An optimization boiler maintenance program is made up of people, management systems, component owners, technology specialists and predictive maintenance tools or equipment. The key predictive maintenance tools used in a Boiler Reliability Optimization project are infrared thermographs, vibration, oil analysis, ultra-sonic etc. Equipment owners and technology specialists collect and collate data on various boiler components. This data is organized and presented in an Equipment and Condition Indicator (E&CI) Matrix. The matrix specifies the predictive maintenance technology to be used, the equipment to be monitored and when the data should be collected, threshold/action limits/levels and actions to be taken. An example of such E&CI matrix can be found in Appendix 2 The “how”, the “what”, and the “when” of condition data analysis is based on exceeding preestablished threshold levels and this information is presented in an “Event Report” and in an “Asset Condition Status Report”. Direct causes of deviations from threshold are determined and corrective actions are communicated to the relevant people. Threshold levels are based on industry, design criteria and baseline data. 3.2.1.3.1 Findings

•

During periodic outage, visual inspections and ultra sonic measurement methods are used extensively by the boiler engineer. The focus is on the boiler tubes.

•

Infrared thermography is used on electrical equipment, the boiler casing, and identification of leaking valves.

•

Metallurgical analysis of failed boiler tubes is performed on a limited basis.

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EPRI Licensed Material Boiler Reliability Optimization Project Phase 1 at Detroit Edison’s St Clair Plant – Unit 7 American Electric Power’s Big Sandy Plant – Unit 2

•

An oil analysis program on the fans and pulverizes is in place.

•

The unit water chemistry program is well controlled and the units operated within EPRI guidelines. The unit has not been chemically cleaned for nine years, and there have been no boiler tube failures due to waterside problems.

•

Report 97E08-81, dated 10/20/97, gives the results of deposit analysis on three Unit 7 waterwall tubes. The north wall sample had the highest grams/ft2 and 19.15% copper, as Cu. 2 The two other tube samples showed significantly less grams/ft and copper values

•

Boiler efficiency/performance tests are no longer performed.

3.2.1.3.2 Recommendations

•

The boiler inspection report, tube leak reports, DCS data, and PdM data need to be integrated into a single database. The key to utilizing the condition-based information in an effective manner is the ability to quickly access the information and to trend the data over time to enable a prediction of when work should be performed. EPRI’s Boiler Maintenance Workstation (BMW) is one such system, which can be used to track and trend boiler tube failure data and information. Another useful tool is the WEB based Plant view software.

•

Remove additional tube samples from areas where high copper had been detected (see Report 97E08-81 dated 10/20/97) and check and confirm the presence of copper.

•

Use the data collected by the DCS and PI proactively eg trend and track metal temperatures, excess oxygen etc, in order to identify incipient failures.

3.2.1.4 People Human beings are an important asset. Their reliability – “making and keeping commitments” has a huge impact on plant reliability. The design, manufacture, installation, operation and maintenance of all equipment is in some way or other related to the performance of human beings. Therefore, “if human beings are reliable your equipment will be reliable”. 3.2.1.4.1 Findings

•

The staff at St. Clair has recently undergone reorganization, with a reduction in staff numbers. The present organization is highly matrixed, and the roles and responsibilities of individuals are not clearly understood. Communication within the matrix is poor, with many of the plant staff reporting they are out of the loop regarding decisions on the boiler. As an example, there is no clear understanding, of who is responsible for following up on recommendations made by the boiler engineer in the boiler inspection report. Is it the boiler engineer or maintenance supervisor? At the time of writing this report, the current boiler engineer had been assigned other duties which would take him away from doing thorough inspections.

•

There is no succession planning for plant staff. Technical expertise and experience is concentrated among a small number of staff within AMO and ESO. Plant staff are therefore dependent on these organizations for support and boiler expertise. 3-11

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1 at Detroit Edison’s St Clair Plant – Unit 7 American Electric Power’s Big Sandy Plant – Unit 2

•

An extensive on-job-training program for new operators has recently been put in place.

3.2.1.4.2 Recommendations

•

A ‘Boiler Tube Failure Reduction’ team consisting of plant, ESO, and AMO staff should be formed. Every tube failure should be investigated and an in-depth report issued. This report should include a ‘Root Cause Analysis’, short and long-term recommendations, and a copy of Work Orders written by the team. Semi-annual progress reviews should be issued giving the status of action being taken on recommendations.

•

Management needs to clearly define and communicate roles and responsibilities of the Plant, AMO, and ESO staff, and the relationship of individuals within these groups.

•

With the current age profile of the plant work force, it is essential to develop and put in place a succession plan that will provide qualified people.

3.2.2 Failures and Root Causes The section deals with the causes of failures, actions taken and the actions to be taken to mitigate future failure. 3.2.2.1 Boiler Tubes From 1995 to April 2000, on Unit 7 there have been 21 forced outages due to boiler tube failures. Analysis of these reports shows 54 tube failures, involving eight failure mechanisms. See Figure 3-2 below. The documenting of tube leaks is done via the “Short Form” report. The report also includes details of the other repairs due to the consequence of the first failure.

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EPRI Licensed Material Boiler Reliability Optimization Project Phase 1 at Detroit Edison’s St Clair Plant – Unit 7 American Electric Power’s Big Sandy Plant – Unit 2 16

14

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A tta c h m e n ts C li n k e r D a m a g e F a ti g u e C ra c k i n g

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O xi d a ti o n o f R H T u b e s Q u a li ty C o n tro l/W e ld s

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S la g E ro s i o n S o o t B lo w e r E ro s i o n 6

W a te r L a n c e Q u e n c h i n g

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1996

A tta c h m e n ts 1

C li n k e r D a m a g e

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F a ti g u e C ra c k i n g

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Figure 3-2 Tube Leak Failures 1995 - 2000

Analysis of Figure 3-2 reveals the following trends: •

Failures due to water lance quenching peaked in 1995 and 1997, with four tube failures in each year. Since replacement of the water lances, there has only been one incident, which was due to damage prior to replacement. This pro-active approach has been successful in eliminating this problem.

•

Failures due to soot blower erosion peaked in 1995 with four failures, and only one reported in 1998 and 1999. This is due to extensive pad welding done during the 1998 outage. This

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EPRI Licensed Material Boiler Reliability Optimization Project Phase 1 at Detroit Edison’s St Clair Plant – Unit 7 American Electric Power’s Big Sandy Plant – Unit 2

approach seems to have solved this problem for the short-term, but the large number of pad welds threatens the unit’s future reliability. •

Failures due to clinker damage were the highest in 1997 with four failures, followed by two reports in 1998. Installation of reinforced wear bars during the 1998 outage to date has eliminated this mechanism.

•

Failures caused by the lack of adequate welding quality control has increased. Of the eight tube failures reported in 1999 and 2000, five, or 63%, were due to poor workmanship or using the wrong material. There were also three incidents in 1997. These failures peak following periodic outages.

•

Analysis of a failed reheat tubes in 1997, showed the cause of the failure to be excessive external oxidation. Inspections performed during the 1998 periodic outage revealed additional fifteen tubes with excessive wall thinning due to excessive oxidation. Although there was only one forced outage due to this mechanism, it emphasizes the importance of monitoring, trending, and controlling tube metal temperatures.

3.2.2.1.1 Failure Mechanisms, Actions taken and Recommendations

The 1998 Boiler Inspection and Action Plan was reviewed and the following table represents the Findings and Recommendations. The bold text represents the additional recommendations as a result of the review process.

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EPRI Licensed Material Boiler Reliability Optimization Project Phase 1 at Detroit Edison’s St Clair Plant – Unit 7 American Electric Power’s Big Sandy Plant – Unit 2 Table 3-1 Boiler tube Failures, Causes and Recommended Action Attachment Failures Findings

Cause/effect

Action taken/Recommendations

In 1997 two seal trough failures occurred

The cause of the stress cracks was not determined.

During 1998 the boiler seal system was replaced with an upgraded design to minimize the design.

In February 2001 an inspection revealed several rigging/support lugs welded onto the waterwall and back pass/economizer.

In many instances these lugs if not carefully removed can cause future tube leaks

Welding lugs on pressure parts – waterwall, economizer etc is not a good practice and should be discouraged.

Burned or eroded superheater alignment clips are rlaced and or repaired.

Continual welding as in repair/replace can result in damage to the external and internal tube surface of the tube, resulting in a tube leak

”Hancuffs” should be used after carefully removing broken or damaged clips.

In September 1998 and April 1999 two failures occurred in the horizontal portion of the steam cooled spacer tube attachments. This failure mechanism was first noticed in 1994 and 1996 periodic outages

The cause, as recorded in the “Short Form Report” is erosion which lead to thinning of the material and increased mechanical stress.

During the 2001 periodic outage replace the water-cooled spacers utilizing the new PIB-74 attachment system as designed by ABB-CE In future, when an attachment failure occurs - tube samples should be removed to check for possible corrosion fatigue damage.

Clinker Damage/Slag erosion Findings

Cause/effect

Action taken/Recommendations

Six failures have occurred, one in 1996, four in 1997 and two in 1998.

Localized slagging – three to four feet from each end has been the major cause.

Investigate the cause of this localized slagging. During 1998 periodic outage, all tubes on the lower slope have been replaced with a wear barring tube – extra material on top of the tube. Continue to inspect these tube as and when opportunities arise - during forced and planned outages, to determine a wear rate from which predictions can be made

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EPRI Licensed Material Boiler Reliability Optimization Project Phase 1 at Detroit Edison’s St Clair Plant – Unit 7 American Electric Power’s Big Sandy Plant – Unit 2 Fatigue/Stress Cracking Findings

Cause/effect

Action taken/Recommendations

Nine fatigue/stress failures have occurred. Four in both 1995 and 1997 and one in 1999.

These failures were all caused water quenching from defective/deficient water lances.

These water lances have been replaced with an upgraded design

In February 1997 a superheater rear wall hanger tube

Loose/broken hanger resulting in the tube vibrating loose and crack caused this failure.

Compile a hangar inspection PM with all the necessary data/ information to be recorded so it could easily be issued during a forced outage. This same PM would also be issued during a periodic outage.

Long Term Overheating/Creep

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Findings

Cause/effect

Action taken/Recommendations

In 1997 and 1998 there were one and fifteen failure on the reheater respectively. Analysis of tube samples by ESO (Report # 99V0080001) indicated tube failures were due to thinning by oxidation. The protective oxide coating had spalled off because of mechanical stress causing thinning,

Two causes were given – high temperature and mechanical stress because of hangar support failures. A hanger support pin was missing.

The action taken during the 1998 periodic outage consisted of repairing the hangers and insert 60 “Dutchman”

The ESO report failed to identify or mention if any short or long term overheating had taken place. There was no mention of the metallurgical aspects/condition of the tube. The report states “thermocouple data does higher temperature in the center” however no conclusions or recommendations are made regarding the high temperatures.

The ESO report therefore did not provide adequate information/guidance on long term heath/life aspects of the reheater tubing.

Regarding recommendation for hanger inspection – see recommendation under fatigue/stress cracking. Use UT to measure oxide thickness across the superheater, correlate with temperature profile – thermocouples and remove tube samples metallurgical analysis and conformation of oxide thickness measurement

All analysis reports of tube samples should give recommendation regarding future inspection strategies and or examination requirements.

Remove during the Spring 2001 a representative sample of tubes from across the reheater for remaining life assessment.

EPRI Licensed Material Boiler Reliability Optimization Project Phase 1 at Detroit Edison’s St Clair Plant – Unit 7 American Electric Power’s Big Sandy Plant – Unit 2 During start-up and under normal operation little attention is given to adhering to metal temperature limits and or recording the extent and duration of excursions.

Creep damage is dependent on stress level and tube metal temperature. Thus conditions. Therefore conditions that deviate from design which lead to increase stress and temperature will result in reduced tube life.

The importance of operating within design parameters must be impressed upon operating staff. Metal temperatures should be continuously recorded and monitored by the operator. Rates of change and maximum limits should be determined and adhered to. Deviations from expected should be recorded and investigated. Actions to prevent recurrence should be reviewed and followed up to ensure compliance.

Quality Control Findings

Cause/effect

Action taken/Recommendations

Since 1997 a number of pad welds and or welding have failed

An inspection and or investigation revealed that the welders failed to comply with the welding norms and standards. Quality control of these welds was also inadequate.

Pad welding should be discouraged not only because it destroys the evidence but it also can create the potential for other mechanisms to occur – hydrogen damage. However if it is used, criteria should given to when and when not to use pad welding. Welding procedures should be compile with and all welding should be inspected – quality control

Soot Blower Erosion Findings

Cause/effect

Action taken/Recommendations

Since 1995 several tube failures have occurred because of soot-blower erosion. Forty nine tube were repaired during the 1998 periodic outage

Soot-blower erosion is controllable. The causes are related to excessive use – operational and improper maintenance.

Continue with the soot blower replacement project – new helix design. Optimize the soot blowing sequence and frequency by using thermal condition in the boiler to determine when and how long to blow.

Waterwall Fireside Corrosion Findings

Cause/effect

Action taken/Recommendations

During the 2001 periodic outage low Nox burners will be fitted

Apart from the environmental benefits low Nox burners can cause substoichiometric conditions on the side and rear wall near the burners. These conditions nearly almost result localized corrosion taking place.

Obtain a baseline by measuring tube thickness local to the burners - near the bottom burner level to about 10 feet above the top burners and the side walls midway between the front and rear walls at the same height of the burners. Ensure that the newly installed burners are correctly optimized – measure CO and Oxygen near tube walls if possible. High levels of CO (>1%) and low levels of oxygen (