Over Haul of steamTurbine

Guidelines for Reducing the Time and Cost of TurbineGenerator Maintenance Overhauls and Inspections Volume 1: General Practices R I A L

LICE

N

SED

M AT E

Place Image Here

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

Guidelines for Reducing the Time and Cost of Turbine-Generator Maintenance Overhauls and Inspections Volume 1: General Practices 1014730 Final Report, March 2007

EPRI Project Manager A. Grunsky

ELECTRIC POWER RESEARCH INSTITUTE 3420 Hillview Avenue, Palo Alto, California 94304-1338 ▪ PO Box 10412, Palo Alto, California 94303-0813 ▪ USA 800.313.3774 ▪ 650.855.2121 ▪ [email protected] ▪ www.epri.com

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

NOTE For further information about EPRI, call the EPRI Customer Assistance Center at 800.313.3774 or e-mail [email protected]. Electric Power Research Institute, EPRI, and TOGETHER…SHAPING THE FUTURE OF ELECTRICITY are registered service marks of the Electric Power Research Institute, Inc. Copyright © 2007 Electric Power Research Institute, Inc. All rights reserved.

CITATIONS This report was prepared by: Electric Power Research Institute (EPRI) 1300 W. T. Harris Blvd. Charlotte, NC 28262 This report describes research sponsored by EPRI. The report is a corporate document that should be cited in the literature in the following manner: Guidelines for Reducing the Time and Cost of Turbine-Generator Maintenance Overhauls and Inspections, Volume 1: General Practices. EPRI, Palo Alto, CA: 2007. 1014730.

iii

REPORT SUMMARY

Up to 70% of the outages planned for conventional steam power plants involve work on the turbine. The challenge for the engineer is to improve performance and extend reliability, while eliminating unproductive activities from the maintenance outage schedule. This report provides general guidelines for planning and performing maintenance on steam turbines during outages. Background As a focus of innovative approaches and techniques, maintenance of aging steam turbines has assumed increased importance. In 2003, coal-fired steam plants were an average of 32 years old, and oil- or gas-fueled plants were an average of 36 years old. Many old steam plants, particularly those that are coal fired and well maintained, can be positioned to succeed in the current deregulated environment. To support this goal, EPRI is developing a series of engineering guidelines, repair procedures, and support technologies. This report is part of that effort. It contains guidelines to assist the turbine engineer in reducing the time and cost associated with maintenance overhauls and inspections of turbine-generator systems. Planning and management practices are described that are common to both nuclear and fossil units. Objective • To provide general guidelines for planning and performing a steam turbine maintenance outage Approach Under the direction of a Technical Advisory Group, the project team prepared a comprehensive guideline and series of procedures to address the sequence of activities involved with planning and performing a steam turbine maintenance outage. This information is available to members in a four-CD set, to which information is added annually. Results This first volume of Guidelines for Reducing the Time and Cost of Turbine-Generator Maintenance Overhauls and Inspections presents general practices for each of the fundamental maintenance activities usually associated with an outage: •

Operational turbine-generator condition assessment

•

Pre-outage planning and bidding

•

Unit shutdown procedures

•

Foreign material exclusion

•

Disassembly and recording clearances v

•

Turbine-generator condition assessment

•

Oil flushing

•

Rotor alignment and balancing

•

Pre-startup checks

•

Post-outage activities

Volume 2 of this report provides a series of detailed repair, replacement, and inspection procedures to guide the pre-bid, inspection, disassembly, and repair of critical turbine-generator components. Volume 3 provides balancing and alignment procedures for turbines, generators, and exciters as well as an alignment primer and a balancing primer. Volume 4 provides turbine blade/bucket, HP, IP, LP, and generator rotor and stator procurement specifications; generator rotor and stator rewind specification; a turbine-generator major overhaul procurement specification; and a turbine insulation specification. Volume 5 consists of a domestic and an international turbine-generator engineering database containing unit-specific information. Volumes 6 and 7 provide blade/disk design audit and inspection procedures for HP, IP, and LP blades/disks. Disk 4 of this set contains TGAlign V2.1 in both English units and SI units and their program user manuals. TGAlign is an automated tool for turbine-generator bearing alignment. EPRI Perspective This guideline represents a significant collection of technical information related to maintenance practices associated with an outage. The information in this report, collected by the project’s Technical Advisory Group which is made up of utility members, provides an important compilation of information and procedures to be used by maintenance staff while they prepare for and complete turbine-generator outages. As the current engineering and craft work force continues to age and retire, taking their experience and knowledge with them, this document will be of assistance in transferring the skill and knowledge of the current staff to new employees. Keywords Steam turbines Maintenance Outages

vi

ABSTRACT Maintenance of aging steam turbines has assumed increased importance as a focus for reducing costs associated with scheduled overhauls and inspections. Under the direction of a Technical Advisory Group, EPRI has prepared a comprehensive guideline and series of procedures to address the sequence of activities that are involved with the planning and performance of a maintenance outage. Volume 1 consists of a comprehensive guide for operational turbinegenerator condition assessment and general practices for each of the fundamental maintenance activities generally associated with an outage.

vii

ACKNOWLEDGMENTS In 2004, the EPRI Guidelines for Reducing the Time and Cost of Turbine-Generator Maintenance Overhauls and Inspections, Volume 1: General Practices was produced by Generation Program 65.0 (Steam Turbine-Generator and Balance of Plant), Nuclear Program Nuclear Steam Turbine-Generator Initiative (NSTI), and Technical Advisory Group (TAG) members. In 2005, sections 5.17.4.1–5.17.4.3 were contributed by Geoff Klempner and Isidor Kerszenbaum, Operation and Maintenance of Large Turbo-Generators. © 2004 The Institute of Electical and Electronics Engineers, Inc. The TAG members who assisted in the production of this report are: Name

Utility

Tom Alley

Duke Power Company

Bob Bjune

South Texas Project Electric Generating Station

Randy Bunt

Southern Nuclear

Mitch Burress

Tennessee Valley Authority

Greg Carlin

Nova Scotia Power

Russell Chetwynd

Southern California Edison

John Cizek

Nebraska Public Power District

David Crawley

Southern Company

Rick Dayton

Progress Energy

Chris Essex

Detroit Edison

Bob Garver

First Energy

Tom Kordick

Ameren

Bill McGinnis

Reliant Energy

Scott McQueen

Reliant Energy ix

Chuck Mendenhall

Salt River Project

Tom Murray

Salt River Project

Don Osborne

Duke Power Company

Ken Palmer

Pacific Gas and Electric Company

Ralph Pederson

Nuclear Management Co.

Tim Scholl

Tennessee Valley Authority

Philip Schuchter

First Energy

Dave Sharbaugh

First Energy

Ken Tillich

Northern Indiana Public Service Co.

Generation Program 65.0, NSTI, and the TAG were supported in their efforts to develop this guide by: Turbine Technology International, Inc. 2024 W. Henrietta Road Rochester, NY 14623 Principal Investigators R. Dewey M. Pollard Sequoia Consulting Group, Inc. 9042 Legends Lake Lane Knoxville, TN 37922 Principal Investigator M. Tulay

x

CONTENTS

1 TURBINE-GENERATOR CONDITION ASSESSMENT – IN SERVICE ............................... 1-1 1.1

Overview ................................................................................................................... 1-1

1.2

Procedure and Objectives ......................................................................................... 1-5

1.3

Planning a Steam Turbine-Generator Condition Assessment.................................... 1-6

1.4

Documentation of Condition Assessment .................................................................. 1-7

1.5

Condition Assessment Procedure ............................................................................. 1-7

1.5.1

Turbine-Generator History, Upgrades, and Major Forced Outage Events ......... 1-9

1.5.2

Turbine Vibration .............................................................................................1-14

1.5.3

Bearing Metal and Oil Temperatures ...............................................................1-18

1.5.4

Thermal Performance ......................................................................................1-19

1.5.5

Unit Start and Load Data .................................................................................1-25

1.5.6

Unit System Steam/Water Purity .....................................................................1-26

1.5.7

Lubricating Oil and EHC Fluid Testing .............................................................1-27

1.5.8

Pump Testing ..................................................................................................1-30

1.5.9

Turbine Steam Valve Test Results...................................................................1-31

1.5.10

Overspeed and Trip Checks.........................................................................1-34

1.5.11

Instrument Surveys ......................................................................................1-36

1.5.12

Generator Electrical Operating Data.............................................................1-38

1.5.13

Auxiliary Systems Data.................................................................................1-43

1.5.14

Component Visual Inspections .....................................................................1-46

1.5.15

Out-of-Limit Conditions and Upsets..............................................................1-47

1.5.16

Review/Update Turbine Generator Maintenance Plans ................................1-48

1.6

Evaluating Situations and Making Recommendations ..............................................1-48

1.7

Condition Assessment Example...............................................................................1-48

1.8

Summary Remarks ..................................................................................................1-52

xi

2 PRE-OUTAGE PLANNING AND BIDDING ......................................................................... 2-1 2.1

Identifying and Establishing Engineering Responsibilities ......................................... 2-3

2.1.1

Engineering Responsibilities in a Major Outage Work Scope............................ 2-4

2.1.1.1

Pre-Outage Activities.................................................................................. 2-4

2.1.1.2

Outage Activities........................................................................................2-11

2.1.1.3

Post-Outage Activities ...............................................................................2-14

Post-Outage Meeting...........................................................................................2-15 2.1.2

Methods to Estimate Engineering Resources and Work Force Required.........2-16

2.1.3

Tasks Deferred to Reduce the Scope and the Potential Implications ...............2-17

2.1.4

Tools Available and Input Needed to Define Tasks for a Scope of Work .........2-17

2.2

Pre-Bidding and Procuring Parts or Services (When Scope Is Defined) ...................2-18

2.2.1

Stationary Repairs - Diaphragms, Packing Rings, and Sealing Strips..............2-19

2.2.2

Blade/Bucket Replacement or Repairs ............................................................2-28

2.2.3

Bearing and Shaft Seal Repairs.......................................................................2-31

2.2.4

Generator Repairs ...........................................................................................2-33

2.2.5

Valve Part Replacement and Repair................................................................2-36

2.2.6

Parts Stores Review ........................................................................................2-37

2.2.7

Miscellaneous Turbine-Generator Exciter Parts, Bolts, Nuts, and Other Parts................................................................................................................2-41

2.3

Identifying and Procuring Specialized Support .........................................................2-41

2.3.1

Lead Times to Arrange for Different Types of Support. ....................................2-42

2.3.2

Web Searches: Key Words or Identifiers to Produce Supplier Lists .................2-44

2.4

Scaffolding Requirements ........................................................................................2-44

2.4.1

Customization of a Scaffolding Plan ................................................................2-46

2.4.2

Ways to Reduce Scaffolding Erection Time .....................................................2-47

2.5

Safety Procedures....................................................................................................2-47

2.5.1 2.6

Environmental Planning ...........................................................................................2-50

2.6.1

EHC Fluid ........................................................................................................2-51

2.6.2

Waste Products to Be Considered ...................................................................2-53

2.7

xii

Plan for Insulation/Asbestos Identification, Handling, and Disposal .................2-48

Crane Availability .....................................................................................................2-53

2.7.1

Crane Maintenance to Be Performed in Advance ............................................2-54

2.7.2

Types of Cranes ..............................................................................................2-54

2.7.3

Crane Use Schedule .......................................................................................2-55

2.8

Turbine Deck Lay-Down Planning ............................................................................2-55

2.8.1

Basic Elements for Any Deck Lay-Down Plan..................................................2-56

2.8.2

Basic Items or Issues to Be Reviewed.............................................................2-58

2.8.3

Items to Amend in a Customized Plan .............................................................2-59

2.9

Special Tools, Equipment, and Facilities ..................................................................2-59

2.9.1

Storage and Work Space Provisions for Cleaning and/or NDE ........................2-61

2.9.2

Provisions for Cleaning and Inspecting Different Turbine Parts .......................2-61

2.9.3

Items or Issues Specified as Part of the Work Order for Vendors ....................2-63

2.10

Machine Disassembly Plan..................................................................................2-64

2.10.1

Basic Elements in the Machine Disassembly Plan........................................2-64

2.10.2

Issues or Items Reviewed ............................................................................2-64

2.10.3

Identifying Contingency Plans for Unexpected Work ....................................2-66

2.11

Foreign Material Exclusion ..................................................................................2-66

2.11.1

Organizational Responsibilities for Turbine-Generator Contracts .................2-66

2.11.2

Areas of the Turbine-Generator to Protect ...................................................2-70

2.11.3

Measures to Take for Each Critical Area ......................................................2-71

2.11.4

Implementation of FME Plans for Turbine-Generator Work ..........................2-73

2.11.5

Performance of Work Inside the Turbine-Generator FMEA ..........................2-74

2.11.6

Retrieval of Foreign Objects.........................................................................2-79

2.11.7

Video Inspection of Shells and Steam Lines ................................................2-79

2.12

Training ...............................................................................................................2-80

2.12.1

Training Formats..........................................................................................2-80

2.12.2

Recommended Training Topics ...................................................................2-81

2.12.3

Training Options...........................................................................................2-83

2.13

Rigging, Special Tools, Parts, and Expendable Materials....................................2-83

3 UNIT SHUTDOWN............................................................................................................... 3-1 3.1

Pre-Outage Testing................................................................................................... 3-1

3.2

Generic Steps for Shutdown...................................................................................... 3-3

3.3

Critical Engineering Concerns ................................................................................... 3-4

3.4

Parameters to Monitor............................................................................................... 3-5

3.5

Opportunities to Reduce Shutdown Time .................................................................. 3-7

3.6

Practices That Have Been Used to Reduce Shutdown Time..................................... 3-7

3.6.1

Overspeed Trip Testing .................................................................................... 3-9

3.6.2

Electrical Trips vs. Mechanical Trips................................................................. 3-9

xiii

3.6.3

Boiler/Reactor Feed Pump Turbine Controls ...................................................3-10

3.7

Removal of Covers and Crossover Piping ................................................................3-10

3.8

Valve Disassembly...................................................................................................3-11

3.9

Practices to Accelerate Cooling................................................................................3-12

3.10 Operations Performed During Turning Gear Operations...........................................3-12 3.11 Lubrication Oil Blanking............................................................................................3-15 3.12 Removal of Insulation...............................................................................................3-16 3.13 Lagging Removal .....................................................................................................3-16 4 DISASSEMBLY AND RECORDING CLEARANCES .......................................................... 4-1 4.1

Planning Lay-Down Areas......................................................................................... 4-1

4.1.1

Material Handling Methods and Considerations................................................ 4-3

4.1.2

Component Disassembly Requirements........................................................... 4-3

4.1.3

Component Work Scopes and Work Centers ................................................... 4-3

4.1.4

Component Weights and Floor Loading............................................................ 4-7

4.1.5

Tooling/Support Locations ................................................................................ 4-9

4.1.6

Power/Air/Water Requirements .......................................................................4-10

4.1.7

Personnel Needs (Restrooms, Eating Facilities) ..............................................4-10

4.2

Features of the Basic Rigging Plan ..........................................................................4-11

4.2.1

Rigging/Lifting Drawings for Major Components ..............................................4-11

4.2.2

Rigging Devices, Lifting Bars, Wire Rope, Synthetic Slings, and Shackles ......4-14

4.2.3

Practical Methods for Efficient Handling of Certain Components .....................4-16

4.2.4

Special Turbine Tools ......................................................................................4-17

4.3

Scheduling Overhead Crane Time ...........................................................................4-18

4.4

Moving Without the Overhead Crane .......................................................................4-18

4.5

Special Storage Considerations ...............................................................................4-18

4.5.1

Racks for Diaphragms .....................................................................................4-19

4.5.2

Valve Stands, Rotor Stands, Mandrels, Try Bars, and Stub Shafts ..................4-21

4.5.3

Shell Racks, Supports, and Cribbing ...............................................................4-23

4.6

xiv

Bolt Removal Practices and Techniques ..................................................................4-25

4.6.1

Identifying the Necessary Personnel for Unbolting the Turbine-Generator.......4-27

4.6.2

Available Tools Needed...................................................................................4-28

4.6.3

Useful Tools and Techniques for Different Applications ...................................4-30

4.6.4

Bolt Removal Sequence ..................................................................................4-30

4.6.5

Required Inventory of Bolts .............................................................................4-33

4.7

Taking Axial and Radial Clearances and Their Use..................................................4-34

4.8

Required Rotor Radial Position and Coupling Alignment Checks .............................4-38

4.9

Checks to Assess Spare Rotor Compatibility ...........................................................4-40

5 TURBINE-GENERATOR CONDITION ASSESSMENT ....................................................... 5-1 5.1

Cleaning Without Disassembly.................................................................................. 5-2

5.2

Recommended Inspection and Testing Techniques .................................................. 5-3

5.2.1

Proof Test......................................................................................................... 5-8

5.2.2

Megger Test ..................................................................................................... 5-9

5.2.3

Doble Test .......................................................................................................5-10

5.2.4

Other Tests......................................................................................................5-10

5.3

In Situ Inspection......................................................................................................5-12

5.3.1

Economic Incentives Imposed by Deregulation................................................5-12

5.3.2

Machine Access ..............................................................................................5-13

5.3.3

Video Probe Systems ......................................................................................5-14

5.3.4

Utility Experiences ...........................................................................................5-15

5.4

Accelerating Different Types of Inspections..............................................................5-16

5.4.1

Defect Sizing and Implications of Results ........................................................5-17

5.5

Cleaning Coated Versus Non-Coated Parts .............................................................5-19

5.6

Coating-Removal Techniques ..................................................................................5-20

5.7

Sampling and Analyzing Deposits ............................................................................5-20

5.8

NDE of Turbine-Generators and Collecting Boresonic Data .....................................5-21

5.8.1

Turbine-Generator Nondestructive Evaluation Techniques..............................5-21

5.8.2

Collecting Boresonic Data ...............................................................................5-22

5.8.3

EPRI-Supported Rotor Boresonic Inspection ...................................................5-24

5.8.4

Boresonic System Evaluation Procedures .......................................................5-25

5.8.5

Inspection of Boreless Rotors ..........................................................................5-26

5.8.6

Inspection of Steam Turbine Disk Blade Attachments......................................5-26

5.8.7

Inspection of Nonmagnetic Generator Retaining Rings....................................5-28

5.9

Inspection of Shrunk-On Components......................................................................5-28

5.10 Bearings – Journal and Thrust Types.......................................................................5-29 5.11 Stationary Components............................................................................................5-34 5.12 Buckets/Blades ........................................................................................................5-40 5.13 Rotors ......................................................................................................................5-43 5.13.1

Causes of Rotor Bowing...............................................................................5-43

xv

5.13.1.1

Severe Rubbing.......................................................................................5-43

5.13.1.2

Bows Caused by Water Induction............................................................5-46

5.13.1.3

Bows Caused by Metallurgical Problems.................................................5-46

5.13.1.4

Corrective Actions ...................................................................................5-46

5.13.2

Other External Rotor Problems.....................................................................5-47

5.14 Shaft Seals ..............................................................................................................5-48 5.15 Valves .....................................................................................................................5-51 5.15.1

Stop Valves ..................................................................................................5-51

5.15.2

Control Valves..............................................................................................5-52

5.15.3

Reheat Stop Valves......................................................................................5-53

5.15.4

Non-Return Valves .......................................................................................5-53

5.16 Casings, Steam Chests, and Nozzle Chests............................................................5-54 5.17 Generator ................................................................................................................5-57 5.17.1

Classifications ..............................................................................................5-57

5.17.2

Generator Stator...........................................................................................5-58

5.17.3

Generator Field ............................................................................................5-62

5.17.4

Generator Electrical Testing .........................................................................5-66

5.17.4.1

Generator Stator Core Electrical Tests ....................................................5-71

5.17.4.2

Generator Stator Winding Electrical Tests ...............................................5-89

5.17.4.3

Generator Rotor Electrical Testing.........................................................5-105

5.18 Excitation System ..................................................................................................5-119 5.19 Using Data on Condition Assessment to Assess Risk of In-Service Failure ..........5-120 6 OIL FLUSHING.................................................................................................................... 6-1 6.1

Preparations and Precautions for Flushing the System ............................................. 6-1

6.2

Resources That Should Be Available While Flushing ................................................ 6-3

6.3

Precautions While Flushing....................................................................................... 6-4

6.4

Oil Cleanliness Criteria.............................................................................................. 6-5

6.5

Heating and Cooling the Oil Without Damaging the Bearing...................................... 6-8

6.6

Minimizing the Use of External Piping While Flushing ............................................... 6-9

6.7

Flushing Without an External Filter...........................................................................6-10

6.8

Techniques to Get Maximum Flow Through Piping ..................................................6-11

7 ROTOR ALIGNMENT AND BALANCING ........................................................................... 7-1 7.1

xvi

Different Tight Wire Techniques ................................................................................ 7-1

7.2

Information Collected from the Unit ........................................................................... 7-4

7.3

Automated and Semi-Automated Alignment Processes ............................................ 7-5

7.4

Slow-Speed Versus High-Speed Balancing............................................................... 7-6

7.4.1

Slow-Speed Balance Requirements/Considerations......................................... 7-8

7.5

When Spin Balancing Is Required............................................................................. 7-9

7.6

On-Line Balancing Devices ......................................................................................7-11

7.7

Potential Consequences of Not Balancing the Rotor ................................................7-12

7.8

Selecting Vibration Limits .........................................................................................7-13

7.9

Balance Limits..........................................................................................................7-14

7.10 Access to Turbine-Generator Rotors ........................................................................7-17 7.11 Turbine-Generator Balance Support.........................................................................7-18 7.12 Turbine-Generator Balance Weights ........................................................................7-20 7.12.1

Split-Weight Design Dovetail Weights ..........................................................7-20

7.12.2

Tungsten-Style Weights ...............................................................................7-22

8 PRE–STARTUP CHECKS................................................................................................... 8-1 8.1

Steps to Minimize Startup Time................................................................................. 8-1

9 POST-OUTAGE ACTIVITIES .............................................................................................. 9-1 9.1

Post-Overhaul Engineering Reports .......................................................................... 9-1

9.2

Documentation for Vendor Signoff ............................................................................ 9-7

9.3

Issues to Review for Future Planning ........................................................................ 9-8

9.4

Recommendations for Planning Future Outages......................................................9-11

9.4.1

Problem Description ........................................................................................9-11

9.4.2

Solution ...........................................................................................................9-12

9.5

Inventory Decision Making .......................................................................................9-12

9.6

Integration with Maintenance Management Systems ...............................................9-13

10 REFERENCES .................................................................................................................10-1 A CONDITION ASSESSMENT DATA SHEETS ..................................................................... A-1 B TURBINE-GENERATOR OUTAGE REPORT.....................................................................B-1 B.1

Outage Report Instructions ....................................................................................... B-1

B.2

Report Table of Contents .......................................................................................... B-3

B.3

Blank Report Format ................................................................................................. B-6

xvii

C DATA SHEETS ...................................................................................................................C-1 D FOREIGN MATERIAL EXCLUSION GUIDANCE ............................................................... D-1 D.1

Introduction and Purpose.......................................................................................... D-1

D.2

Definitions................................................................................................................. D-2

D.2.1

Glossary of Key Terms..................................................................................... D-2

D.2.2

Categorization of FME Areas ........................................................................... D-6

D.2.3

Categorization of FME Events.......................................................................... D-6

D.3

D.3.1

FME Responsibilities for All Personnel............................................................. D-8

D.3.2

Typical Individual FME Responsibilities ........................................................... D-8

D.4

Establishing and Implementing FME Program Requirements ................................. D-11

D.4.1

Introduction .................................................................................................... D-11

D.4.2

General Programmatic Guidance................................................................... D-13

D.4.3

Sources of Foreign Material Contamination ................................................... D-13

D.4.4

Defining the Scope of Equipment Controlled by FME Procedures.................. D-14

D.4.5

Training and Qualification of Individuals......................................................... D-15

D.5

Developing and Implementing FME Control Plans.................................................. D-16

D.5.1

Factors to Consider When Developing an FME Control Plan ......................... D-16

D.5.2

Typical Contents of an FME Control Plan ...................................................... D-17

D.5.3

Establishing the FMEA................................................................................... D-19

D.5.4

Determining Appropriate FME Controls for the Area ...................................... D-20

D.5.5

Establishing an FMEA Boundary.................................................................... D-21

D.5.6

Installing the FMEA Boundary........................................................................ D-21

D.5.7

Conducting Pre-Job Briefings ........................................................................ D-22

D.6

xviii

Plant/Station Responsibilities....................................................................................D-8

Performance of Work Inside the FMEA................................................................... D-22

D.6.1

FMEA Entry Requirements ............................................................................ D-22

D.6.2

Use of Control Logs ....................................................................................... D-23

D.6.3

Monitoring the FMEA ..................................................................................... D-25

D.6.4

Cleanliness and Readiness Inspections......................................................... D-26

D.6.5

Performance of Maintenance Activities Within the FMEA............................... D-26

D.6.6

Examples of Good Work Practices Inside the FMEA...................................... D-28

D.6.7

Implementing Graded FME Controls .............................................................. D-30

D.6.8

Ensuring Cleanliness Inside the FMEA .......................................................... D-31

D.6.9

Use of FME Devices ...................................................................................... D-33

D.7

Recovery of Loss of FMEA Control......................................................................... D-37

D.7.1

Initiation of a Condition Report ....................................................................... D-37

D.7.2

FME Recovery Plan ....................................................................................... D-38

D.7.3

Foreign Material Retrieval .............................................................................. D-38

D.7.4

Recovering Foreign Material After Returning the System to Service .............. D-40

D.8

Close Out of a Foreign Material Exclusion Area...................................................... D-40

D.9

References ............................................................................................................. D-41

xix

LIST OF FIGURES Figure 1-1 Example of the Form Used to Rate the Final Condition of the TurbineGenerator ........................................................................................................................ 1-3 Figure 1-2 Example of NERC-GAD List of Maintenance Outage Events for a Typical Unit.....1-13 Figure 1-3 Typical Orbits Showing Different Problems ...........................................................1-17 Figure 1-4 Location and Function of Basic Turbine Controls ..................................................1-32 Figure 1-5 Location of Typical Turbine Supervisory Instrumentation ......................................1-36 Figure 1-6 Typical Generator Capability Curve.......................................................................1-39 Figure 2-1 Example of an Outage Plan ................................................................................... 2-7 Figure 2-2 Sample of Engineering-Supported Activities .........................................................2-13 Figure 2-3 Dimensional Requirements That May Be Provided Within a Repair Procedure.....2-21 Figure 2-4 Major Repair Times per Inch of Partition Radial Height .........................................2-23 Figure 2-5 Estimate of Total Major Repair Time per Partition .................................................2-24 Figure 2-6 Estimation Tool for Minor Partition Repairs ...........................................................2-25 Figure 2-7 Total Diaphragm Repair Time Divided by the Nonproductive Time .......................2-26 Figure 2-8 Plot to Track Consumable Costs vs. Productive Labor Costs................................2-27 Figure 2-9 Change in HP Section Efficiency After Four Separate Outage Periods .................2-28 Figure 2-10 Examples of Rotor Weight and Coupling Geometry Measurements ....................2-32 Figure 2-11 Examples of Shells Used to Bridge Between the Retaining Ring and Rotor ........2-34 Figure 2-12 Part Location Information ....................................................................................2-39 Figure 2-13 Four-Level Part Location Hierarchy.....................................................................2-39 Figure 2-14 Types of Lifting Cranes .......................................................................................2-54 Figure 2-15 FME Organizational Structure for T-G Contracts.................................................2-67 Figure 3-1 Section Efficiency Change During the Course of Three Outages ........................... 3-2 Figure 3-2 Example of Access Platforms................................................................................3-11 Figure 3-3 Plot of Shutdown Activities....................................................................................3-14 Figure 3-4 Plot of Accelerated vs. Non-Accelerated Cool-Down Rates ..................................3-15 Figure 3-5 Example of a Toggle Blank ...................................................................................3-16 Figure 4-1 Example of a Work Center Lay-Out Plan ............................................................... 4-4 Figure 4-2 Lay-Out Plan with Work Center Layouts to Match the Expected Work Scope ........ 4-6 Figure 4-3 Example of Loading a Reference for a Turbine Deck ............................................. 4-9 Figure 4-4 Example of a Lifting Drawing.................................................................................4-12 Figure 4-5 Example of a Detailed Rigging and Lifting Drawing...............................................4-13

xxi

Figure 4-6 Rigging Fixtures for CRVs.....................................................................................4-14 Figure 4-7 Rigging Fixture for a Control Valve Actuator .........................................................4-15 Figure 4-8 Modification to a Lifting Beam That Allows the Turnbuckle to Remain Attached While Lifting.....................................................................................................4-15 Figure 4-9 Example of a Generator Field Support Modification ..............................................4-16 Figure 4-10 Example of a Diaphragm Transport and Storage Rack .......................................4-19 Figure 4-11 Example of an Oil Deflector Rack........................................................................4-20 Figure 4-12 Example of a Fixture Holding a Control Valve .....................................................4-21 Figure 4-13 Example of a Fabricated Rotor Stand with Rollers ..............................................4-22 Figure 4-14 Example of a Bearing Fitting Mandrel to Check Tilt Pads....................................4-22 Figure 4-15 Example of a Mandrel to Check Cylindrical or Elliptical Bearing Bores................4-23 Figure 4-16 Example of a Rack for Holding an HP Upper Shell..............................................4-24 Figure 4-17 Example of a Fabricated Shell Support ...............................................................4-24 Figure 4-18 Example of a Support for Generator Field Removal Without Cribbing .................4-25 Figure 4-19 Coupling Alignment Nomenclature ......................................................................4-39 Figure 5-1 Access Path for Video Probe Delivery Device .......................................................5-13 Figure 5-2 Examples from Remote Video Probe In Situ Inspection ........................................5-15 Figure 5-3 Elliptical Bearing Construction...............................................................................5-31 Figure 5-4 Diaphragm Construction .......................................................................................5-35 Figure 5-5 Mechanics Describing Rubbing Process ...............................................................5-44 Figure 5-6 Typical Non-Return Valve Construction ................................................................5-54 Figure 5-7 Terminal Stud Hydrogen Seal Construction ..........................................................5-64 Figure 5-8 Location Susceptible to High-Cycle Fatigue and Low-Cycle Fatigue in Certain Main Lead Designs.........................................................................................................5-65 Figure 5-9 Flux Fault Current Path .........................................................................................5-72 Figure 5-10 EL-CID Excitation Setup .....................................................................................5-73 Figure 5-11 EL-CID Analog Equipment ..................................................................................5-74 Figure 5-12 EL-CID Digital Equipment ...................................................................................5-75 Figure 5-13 EL-CID Chattock Theory .....................................................................................5-76 Figure 5-14 EL-CID MMF Theory...........................................................................................5-77 Figure 5-15 EL-CID Signal Interpretation ...............................................................................5-79 Figure 5-16 Toroid Wrap ........................................................................................................5-82 Figure 5-17 Operating Flux Pattern ........................................................................................5-82 Figure 5-18 B-H Curve Example ............................................................................................5-84 Figure 5-19 Flux Test Electrical Setup ...................................................................................5-85 Figure 5-20 Flux Test Mirror Setup.........................................................................................5-85 Figure 5-21 Infrared Hot Spot – Bruce 7.................................................................................5-86 Figure 5-22 Infrared Hot-Spot Flux Test 1 ..............................................................................5-86 Figure 5-23 Infrared Hot-Spot Flux Test 2 ..............................................................................5-87

xxii

Figure 5-24 Flux-Temperature Profiles...................................................................................5-88 Figure 5-25 IR Versus Temperature.......................................................................................5-92 Figure 5-26 Polarization Index Dryness Curve .......................................................................5-93 Figure 5-27 IR Versus Temperature – PI................................................................................5-95 Figure 5-28 DC Ramp ............................................................................................................5-97 Figure 5-29 Stator Hi-Pot Arcing ............................................................................................5-99 Figure 5-30 LKV G5 EE Hoseglow .......................................................................................5-100 Figure 5-31 PD Off-Line Capacitive Coupling.......................................................................5-101 Figure 5-32 Dissipation Factor Tip-Up..................................................................................5-104 Figure 5-33 NO Shorted Turns Traces – Superimposed ......................................................5-109 Figure 5-34 NO Shorted Turns Traces – Separated.............................................................5-109 Figure 5-35 NO Shorted Turns Traces – Summed ...............................................................5-109 Figure 5-36 RSO Single-Shorted Turn – Dual Superimposed Trace ....................................5-110 Figure 5-37 RSO Single-Shorted Turn – Difference Trace ...................................................5-110 Figure 5-38 RSO Dual-Trace – Multi-Shorts.........................................................................5-110 Figure 5-39 RSO Difference Trace – Multi-Shorts ................................................................5-111 Figure 5-40 STD by Open Circuit .........................................................................................5-112 Figure 5-41 STD by Impedance ...........................................................................................5-113 Figure 5-42 C-Core 1 ...........................................................................................................5-114 Figure 5-43 C-Core 2 ...........................................................................................................5-115 Figure 5-44 Rotor Ground – Split Voltage ............................................................................5-117 Figure 5-45 Rotor Ground – Current Through Forging .........................................................5-118 Figure 5-46 Example of a Probability Distribution and Limit State Function..........................5-121 Figure 5-47 Basic Elements of a Probabilistic Analysis ........................................................5-122 Figure 5-48 Example of SPE Inspection Criteria Using Series of Probability of Failure Curves..........................................................................................................................5-123 Figure 5-49 Ratio of Actual Crack Sizes to Measured Crack Sizes ......................................5-125 Figure 6-1 Oil Flushing Piping ................................................................................................6-10 Figure 7-1 Ten-Year Record of Rotor Bowing ......................................................................... 7-4 Figure 7-2 Exaggerated Rotor Motion for the First Three Field Critical Speeds ....................... 7-8 Figure 7-3 Low-Speed Portable Balance Machine .................................................................. 7-9 Figure 7-4 Various Standards for Residual Unbalance...........................................................7-16 Figure 7-5 Offset Modification to a Shell Bore ........................................................................7-17 Figure 7-6 Access to Balance Grooves ..................................................................................7-18 Figure 7-7 Split-Weight Dovetail Weight.................................................................................7-21 Figure D-1 Foreign Material Exclusion Flowchart .................................................................. D-12 Figure D-2 Example of an FME Plan Document.................................................................... D-18 Figure D-3 Example of an FME Boundary Sign..................................................................... D-19 Figure D-4 Example of an FME Boundary Sign..................................................................... D-20

xxiii

Figure D-5 Examples of FME Boundaries and Entry Locations ............................................. D-21 Figure D-6 Example of an Individual Entry Log ..................................................................... D-24 Figure D-7 Example of a Long-Term Placement Log............................................................. D-25 Figure D-8 Example of Lanyard Use ..................................................................................... D-36

xxiv

LIST OF TABLES Table 1-1 Breakdown of Condition Assessment ...................................................................... 1-8 Table 1-2 Critical Components Identified in Assessment Procedure ......................................1-10 Table 1-3 Cause Codes Associated with Critical Components Found in the Assessment Procedure.......................................................................................................................1-12 Table 1-4 Effect of Component Condition Changes on Fossil Cycle Performance Parameters (at Valve Wide Open Operation) .................................................................1-22 Table 1-5 Guidance for Interpreting Turbine Cycle Steam Flow and Unit Load Changes .......1-23 Table 1-6 Effect of Leakage to the Condenser on Heat Rate and Load..................................1-24 Table 1-7 Example of Overall Unit Condition Assessment .....................................................1-50 Table 2-1 Index to Turbine Outage Report: Appendices B and C............................................ 2-2 Table 2-2 Checklist of Pre-Outage Activities ........................................................................... 2-8 Table 2-3 Recommended Process Instruction Sheet and Detailed Work Package Information .....................................................................................................................2-10 Table 2-4 Recommended Information for Parts and Part Use Databases ..............................2-11 Table 2-5 Post-Outage Activities ............................................................................................2-15 Table 2-6 Recommended Parts Purchase Document Information ..........................................2-19 Table 2-7 Recommended Diaphragm Repair Purchase Document Information......................2-20 Table 2-8 Recommended Information for Bucket Replacement or Repair ..............................2-29 Table 2-9 Geometry and Tolerances Required to Support a Repair Procedure......................2-31 Table 2-10 Classification of Generator Components ..............................................................2-33 Table 2-11 Generator Tests and When They May Be Performed...........................................2-34 Table 2-12 Parts and Consumables Used to Support Routine Work ......................................2-38 Table 2-13 Examples of Specialized Sources for Locating Vendors and Supplies .................2-42 Table 2-14 Selected Activities and Estimated Lead Times .....................................................2-43 Table 2-15 Basic Elements of a Scaffolding Plan ...................................................................2-45 Table 2-16 Typical Locations Where Asbestos Is Found Around a Turbine............................2-49 Table 2-17 Items Recommended in an Asbestos Abatement Program ..................................2-50 Table 2-18 Alternative Lifting Devices for Turbine-Generator Components ............................2-55 Table 2-19 List of NDE Equipment Used to Support a Turbine-Generator Outage .................2-63 Table 2-20 Areas of a Turbine-Generator to Be Protected During Disassembly .....................2-71 Table 2-21 Areas of a Turbine-Generator That Should Be Blocked........................................2-72 Table 2-22 Example of FME Measures During Turbine Disassembly and Reassembly..........2-75

xxv

Table 2-23 List of Recommended Training Topics .................................................................2-86 Table 2-24 Typical Consumables Required for an Outage .....................................................2-88 Table 3-1 Steps Typically Involved with the Shutdown of a Turbine-Generator ....................... 3-4 Table 4-1 Checklist for Preparing a Lay-Down Plan ................................................................ 4-2 Table 4-2 Activities Required to Support a Generator Field Rewind ........................................ 4-7 Table 4-3 Tooling and Support for Turbine Deck Lay-Down Plan ...........................................4-10 Table 4-4 Tooling and Support for Turbine Deck Lay-Down Plan ...........................................4-19 Table 4-5 Comparison of Accuracy Between Different Preload Methods [14].........................4-26 Table 4-6 Tooling and Support for Turbine Deck Lay-Down Plan ...........................................4-29 Table 4-7 Outage Fastener Usage Record.............................................................................4-34 Table 4-8 Checks to Determine Compatibility Between Original and Replacement Rotors.....4-41 Table 5-1 NDE Inspection Methods Used on Different Turbine-Generator Elements .............. 5-4 Table 5-2 Visual Inspection Methods Used on Different Generator Elements ......................... 5-8 Table 5-3 Sizing and Mapping Constraints Associated with NDE...........................................5-18 Table 5-4 Cleaning Processes Used for Coated and Non-Coated Components.....................5-19 Table 5-5 Support Information Required to Interpret UT Data ................................................5-23 Table 5-6 Coupling Inspections – Disassembly and Reassembly...........................................5-29 Table 5-7 Recommended Action for Bearing Damage Typically Found at Inspection.............5-33 Table 5-8 Recommended Pre-Outage Preparations for Bearings...........................................5-34 Table 5-9 Separate Areas That Form a Stationary System ....................................................5-35 Table 5-10 Recommended Action for Diaphragm Damage Typically Found at Inspection......5-37 Table 5-11 Blade Damage Typically Found at Inspection.......................................................5-42 Table 5-12 Typical Seal Design Clearances with Field Tolerances ........................................5-49 Table 5-13 Casing Repair Issues ...........................................................................................5-56 Table 5-14 Combined Cooling Designs with Retaining Rings.................................................5-57 Table 5-15 Alternative Processes for Grinding Collector Rings ..............................................5-63 Table 5-16 Generator Electrical Tests....................................................................................5-66 Table 5-17 Capabilities of LAI vs. Conventional Inspections ..................................................5-68 Table 5-18 Summary of Advantages and Disadvantages of LAIs...........................................5-69 Table 6-1 Recommended Cleanliness Criteria ........................................................................ 6-7 Table 7-1 Specifications for an On-Line Active Balancing System..........................................7-12 Table 7-2 Sources for Equipment and Rotor Balancing Standards.........................................7-15 Table 8-1 Recommended Outline for a Startup Document ...................................................... 8-2 Table 9-1 Recommended Information to Be Collected After the Outage Is Complete.............. 9-3 Table 9-2 Examples of Post-Outage Engineering Reporting ................................................... 9-5 Table 9-3 Uses for Engineering Information Obtained in the Outage....................................... 9-8

xxvi

1

TURBINE-GENERATOR CONDITION ASSESSMENT – IN SERVICE

In order to justify the extension or reduction of time between overhauls of turbine-generator components, a systematic procedure is presented in this section to guide in the gathering and evaluation of information that, in turn, may be used to assess the turbine-generator’s condition since the last major overhaul. The assessment procedure in this section deals primarily with the information that can be obtained and evaluated while a unit is operating. The condition assessment presented later in Section 5 of this volume treats the information and processes that are recommended for when the unit is off-line and components or systems are available for detailed inspection and testing.

1.1

Overview

The purpose of this steam turbine-generator condition assessment is to: •

Track and monitor the turbine-generator’s condition since its last overhaul

•

Assemble relevant information from multiple sources (interviews and reviews of actual maintenance or operating information)

•

Offer a basis for assessing the collected results in term of recommendations for future work scope and schedule

This procedure and method of reporting is not to be confused with a system of artificial intelligence or decision-making software. This is a step-by-step process to be undertaken by an assigned team of experts and specialists. It is supported with a series of generic formats (data sheets) to guide in the collection of information for the purpose of making an informed, documented determination of when work on a specific system or component of a unit should be performed. This type of assessment is to be conducted by appropriate technical personnel and specialists acting as a group, with support provided by others within the specific plant or utility as necessary. Personnel likely to be involved in the process include: •

Those who are familiar with plant operations, such as a unit engineer

•

Those who are responsible for unit operations and conducting various tests on the equipment

•

Staff or plant personnel responsible for unit performance monitoring

•

Staff personnel responsible for unit vibration monitoring 1-1

Turbine-Generator Condition Assessment – In Service

•

Plant electrical and mechanical personnel responsible for performing preventive maintenance (PM) or predictive maintenance (PdM) on the various equipment

•

Staff chemistry personnel responsible for maintenance of steam and water purity within specified limits

Input and insight will be required from all the above individuals in order to obtain the best possible assessment of the turbine-generator’s current condition. It is important to note that this procedure is designed so that, when each evaluation process is complete, there is only one of three possible outcomes for the systems, sections or components involved: •

The current condition is rated as excellent, and the inspection interval should be extended.

•

The current condition is rated as acceptable, and the inspection interval can be maintained.

•

The current condition has significantly or drastically changed, and the inspection interval should be reduced on various components or systems.

For each of these possibilities, only three types of recommendations are allowed in terms of when the unit should be taken off-line so that corrective action can be implemented: •

Immediate – This recommends that a weekend shutdown be scheduled to correct a potentially serious problem.

•

Intermediate – This recommends that the maintenance be deferred until the next scheduled outage.

•

Long term – This recommends that major maintenance be performed but not until the next scheduled overhaul, based on the most current evaluated condition.

These recommendations are highlighted in the summary page of the condition assessment (Data Sheet #17) report by the use of color coding where the following definitions are applied: •

Green. There are no perceived problems, and the system or component is expected to perform reliably until the next assessment.

•

Blue. No specific immediate or intermediate action is considered necessary, but the issue is significant enough to be monitored.

•

Yellow. Work is required at the next convenient outage; otherwise, a potential problem will develop that could become serious (threaten a forced shut-down) if not corrected.

•

Red. A specific component or system needs immediate attention. Risk of a component or system failure is considered high, and such a failure would cause loss of the unit for an extended time.

If the condition is rated as good or excellent, the item would be color-coded as green, and the summary report should recommend that the scheduled maintenance for these systems or components be long term, with the options to extend, maintain, or shorten the present intervals based on the further details gathered in the assessment. 1-2


In the case of the other two possible outcomes (immediate or intermediate) where some condition degradation is identified, the three possible colors allow the degradation to be further monitored (blue), treated as soon as conveniently possible (yellow), or immediately (red). As a general rule of thumb, unless an unexpected event of drastic proportions has suddenly occurred, the yellow or red rating would be based on more than just an anomaly noted in some indicator or sensor. An issue or problem flagged with a yellow or red code on the summary sheet should have the suspected root cause(s) identified and the appropriate action specified, based on this diagnosis. In other words, every issue associated with degradation of a system or component does not demand a shutdown of the unit. This ultimate action can be deferred until the condition is more precisely defined if the trending of the key criteria or parameters that identified the problem or issue indicates that time permits additional study. This decision of course, must be balanced against the system or component that is involved and the potential risk if a sudden unexpected breakdown of the system should occur. For example, evidence of either a balancing or a misalignment problem might be studied at greater length to identify which of the two is most likely, and the appropriate corrective resources could be planned in the most effective manner. However, the threat raised by a high particle count observed in the bearing lubricating oil system is more immediate and not worth the risk to the bearings and/or the turbine-generator system. A summary form, Data Sheet #17 (see Figure 1-1), is used to document the condition assessment based on information gathered on Data Sheets #1–16. These data sheets are provided in Appendix A.

Figure 1-1 Example of the Form Used to Rate the Final Condition of the Turbine-Generator

The intention for a limited number of outcomes and the use of color codes is to force the assessment to a conclusion and to summarize the results into recommendations that are easy to present to and use by management. Given that two of the three possible recommendations from the assessment could require the unit to come off-line earlier than originally planned, the 1-3


financial consequences of such a decision will invariably be a factor. Therefore, for a condition assessment to be effective, it must offer tangible recommendations, not simply provide a chronicle of assembled data. In this regard, it should be recognized that the assessment approach and method offered here is based on the best combined judgment of the personnel who are responsible for the operation and maintenance of the turbine-generator units. These judgments and recommendations are to be supported by the indicators, trends, known problems, and issues that have been collected specific to the unit since the last overhaul or conditions that may have occurred at some time in the past. In certain cases, particularly where the outcome indicates a “red” condition (where immediate attention is recommended), the human judgment of this in-service procedure can then be further supported by an analytical risk assessment in which all of the pertinent facts are considered. This supplemental assessment is most likely to involve issues associated with the rotating components, particularly those whose catastrophic failure would seriously harm or damage the unit, and not just shut it down. Examples where such analytical assessments might be appropriate for high-pressure (HP) and intermediate-pressure (IP) rotors include the potential for creep failures, solid-particle erosion (SPE), high-cycle fatigue (HCF), and erosion, typically for the first HP and first reheat stages. For LP rotors, the probability for stress corrosion cracking (SCC), HCF, low-cycle fatigue (LCF), water droplet erosion, stall/flutter, and corrosion fatigue would most often focus on the last stages of the LP turbine wheel attachments and blades. It is at this point where the responsibility of the condition assessment ends, and the work remaining transitions into a task of life cycle management (LCM). EPRI has produced a series of Life Cycle Management Planning Sourcebooks, each of which contains a compilation of industry experience, information, and data on aging, degradation, and historical performance for specific types of systems and components. These are potentially useful as references to complement and compare with the information assembled during this machine-specific condition assessment. The EPRI report name, number, and date of publication for Volumes 1–10 of the LCM Planning Sourcebooks are as follows Report Name

Report #

Report Date

Volume 1:

Instrument Air Systems

1006609

December 2001

Volume 2:

Buried Large-Diameter Piping

1006616

May 2002

Volume 3:

Main Condenser

1003651

March 2003

Volume 4:

Large Power Transformers

1007422

March 2003

Volume 5:

Main Generator

1007423

July 2003

Volume 6:

Feedwater Heater Controls

1007425

March 2003

Volume 7:

Low Voltage Electrical Distribution Systems 1007426

February 2003

Volume 8:

Main Turbine

1009071

January 2004

Volume 9:

Electrohydraulic Controls

1009072

September 2003

Volume 10:

Feedwater Heaters

1009073

December 2003

1-4


1.2

Procedure and Objectives

The principal objectives for applying the approach discussed in this section to perform an inservice condition assessment can be summarized as follows: 1. To assess whether the unit may be able to operate successfully until the next major planned overhaul. This recommendation is qualified based on the limits of the evaluation. The objective is to provide a basis for why an unscheduled outage or an extension of a major overhaul interval is recommended. The major limitation to the quality of this condition assessment is the inability to evaluate the condition of internal steam path stationary and rotating parts by means of direct visual inspection. However, by looking at and trending performance data and startup vibration, by performing visual and limited NDE in the exhaust ends of the turbine, and by reviewing bearing metal temperatures and other turbine supervisory instrumentation (TSI) data, it should be possible to obtain a reasonable picture of the internal health of the turbine-generator. 2. To determine what maintenance work needs to be performed on the unit during a weekend shutdown or upcoming future outages. The objective is to reduce the potential of a forced outage prior to the next major planned unit overhaul. 3. To provide additional input for determining the risk of failure (Pf) associated with extending turbine-generator outage intervals. Analytical calculations can be performed using stress (both dynamic and steady), material property variations, and operating data to analytically predict blade failure probability due to SCC, HCF, LCF, SPE, erosion, and creep. The need for such an analysis is dependent on the uncertainty of assigning failure probabilities to certain turbine components and their value to the utility. 4. To provide a relative risk assessment of the individual turbine sections and systems of a specific plant. When a formal system is in place, it becomes possible to compare the risk assessment to other units within the fleet. Three tasks are to be accomplished in the process of performing this level of condition assessment: •

Completion of evaluation forms (found in Appendix A). These should be kept as records and used as the basis to regularly assess, monitor, and trend unit condition change over time.

•

Development of recommendations for work to be performed on a short-term, intermediateterm, or long-term basis. These are done for each system and component and itemized on the summary sheet.

•

Development of recommendations for extending or shortening the time interval for the next planned major outage with justification as to why this work is required.

The overall unit condition evaluation of the turbine-generator and its systems will require input from technical support personnel involved in turbine-generator and plant maintenance and from operations and performance personnel. This information will be used to complete all attachments and to give an overall risk assessment of the turbine components and systems.

1-5


As noted previously, and in addition to the above recommendations, each component should be assessed using a color scheme that makes it easier for management to review and focus on the most critical issues or problems with the machine.

1.3

Planning a Steam Turbine-Generator Condition Assessment

Before proceeding with obtaining the data discussed in this procedure, the following four basic concepts/actions should be clearly communicated to the condition assessment team: •

Responsibility. The organization responsible for planning, scheduling, budgeting, coordinating, and performing the condition assessment of turbine-generators within the system should be clearly identified.

•

Resources. The personnel resources required to coordinate and perform condition assessment of turbine-generators should be identified. Additional resources at a specific station/site for which the assessment is being conducted and the time required of these resources should also be identified. This is necessary to ensure timely completion of data sheets and the turbine-generator unit condition assessment.

•

Budget and Schedules. The group responsible for developing a long-range and/or annual schedule must be identified. This plan and schedule should identify what turbine-generator units will require an assessment with a specified completion date. Included in this should be a budgetary estimate of all costs associated with performing the assessment. Estimated costs of different corrective actions may be found in the previously referenced LCM sourcebook, Main Turbine, 1009071, first published in January 2004.

•

Frequency. The frequency for conducting a condition assessment on a turbine-generator should be identified. In general, the following guidelines are recommended: –

A baseline assessment should be conducted as soon as practical after a major overhaul to provide a benchmark for subsequent comparison and evaluation.

–

A second assessment should be considered at mid-cycle relative to the next scheduled major inspection. For example, if a unit is on a 10-year inspection interval, the next condition assessment should be conducted after five years of operation.

–

The frequency of the inspection interval after this should depend upon the findings of the first condition assessment.

–

If the second condition assessment is satisfactory, the last assessment should be conducted one to two years in advance of the scheduled overhaul.

Contingent upon its findings, the final assessment may show that the planned overhaul can be postponed or must be performed earlier than planned. An interval extension may be supported by calculated failure probabilities based on analytical calculations.

1-6


1.4

Documentation of Condition Assessment

The final report of the turbine-generator condition assessment (along with any additional information/documentation) should be filed at the specific plant where the assessment was performed and at the utility general office. A series of recommended forms are provided in Appendix A: Data Sheets #1 through #17. Note that these forms are meant to be both comprehensive and generic in nature. Not all are required to be completed for many units. Only the most relevant information should be incorporated in the final condition assessment report (Data Sheet #17).

1.5

Condition Assessment Procedure

The assessment begins with a systematic collection of information that is typically available while a unit is in service. The data sheets in Appendix A have been organized in a manner and sequence to provide a natural framework for this process and a comprehensive report that can be updated at each successive assessment interval. The 17 separate data sheets are listed in Table 1-1. Generally, each series of data sheets consists of the three same basic parts: •

The first part is identified as an audit. This sheet provides a summary of relevant available data collected from the system as a whole or from individual sections.

•

The second sheet supplements the first by identifying key questions that are to be answered by means of an interview with the specialist, engineer, or operator directly responsible for maintaining and monitoring the system.

•

The third sheet uses a consistent format to summarize the findings drawn from the audit and interview. The perceived risk and considered need for action are both identified.

Four of the series are distinct from the others in that they form the minimum of information that a condition assessment would always include: •

Series #1 provides an overall review and assessment of the maintenance history for the unit, including a record of any upgrades made to replace original systems.

•

Series #15 is a checklist of 69 “out-of-limit” indicators. These highlight the myriad of unexpected problems or issues that are common to large steam turbine-generators.

•

Series #16 is a summary of the current long-range maintenance plans for the individual systems, sections, and components that are contained within the unit.

•

Series #17 is the consequence of the information obtained and reviewed in the preceding series of documents. It provides a one-page synopsis that lists the components/systems and then ranks their present condition. It is the last form completed, but it should be used as the first page of the report, with the subsequent sheets attached.

1-7

Turbine-Generator Condition Assessment – In Service Table 1-1 Breakdown of Condition Assessment Series

System or Component

Data Assembled and Reviewed

1

Maintenance History Summary

Record of modifications and upgrades

2

Turbine-Generator Vibration

Readings at minimum-maximum load, criticals

3

Bearing Metal and Oil Temperatures

Readings at minimum-maximum load

4

Section Performance Parameters

Readings at full load, valves wide open

5

Start-Up Operation

Record of starts, trips, service hours

6

Steam Purity

Frequency of tests, criteria, out-of-spec events

7

Lubricating Oil and EHC Analysis

Particle counts, presence of contaminates

8

Pump Start Tests

Frequency of tests, pressures, out-of-spec events

9

Valve Tightness Tests

Frequency of tests, criteria, sticking events

10

Turbine Trips and Tests

Record of trips, results, consequences

11

Turbine Monitoring Instrumentation

Readings at minimum-maximum load, calibrations

12

Generator-Exciter Condition

Readings, criteria, test results

13

Auxiliary System Operation

Readings, criteria, test results

14

Visual Inspection Results

HP, IP, LP inlets and exhausts

15

Checklist of Out-of-Limit Events

Record of unit upsets, actions, and consequences

16

Current Maintenance Plan

Record of inspections: last, next, frequency

17

Overall Condition Assessment

Summary with recommended actions

As noted, it may not be necessary to complete Data Sheets #2 through #14 for every unit. The extent to which the assessment is performed is at the discretion of the owners and operators. The checklist of indicators provides a snapshot to identify warnings of problems that should also be subsequently covered in the more detailed evaluation of a specific system or component. However, these warnings only highlight a potential problem and do not provide the additional detail that an audit or interview is meant to supply as a basis for estimating the risk of a failure and the type of action that is needed. Data Sheet #17 is essentially a digest of the critical systems and components, itemized for the main steam turbine in Data Sheet #16. It principally focuses on the fundamental issues or problems identified in the assessment, although it should include an assessment of certain systems whose health is critical to the reliable operation of the turbine-generator. In other words, it is just as valid to report that the conditions of these key systems are presently considered good, as it is to highlight the potential or immediate problems. As a general rule, the summary report should not exceed a single page.

1-8


The next 14 subsections of this section present a system-by-system breakdown of the checks, inspections, tests, etc., that are recommended on particular systems and components and some guidance in how these would be used to evaluate the operating health of the machine. The subsections are in the sequence of the data sheets previously shown in Table 1-1. Each set (series) of data sheets is referenced to a specific plant and unit number, with the following generic information included throughout the package of information that is finally assembled into a report: •

Turbine, generator, and exciter original equipment manufacturer (OEM)

•

Unit maximum dependable capacity (MDC) and unit design rating

•

Date the unit went into commercial operation and date the unit was last inspected

1.5.1 Turbine-Generator History, Upgrades, and Major Forced Outage Events After the proper planning and organizational measures have been finalized, a condition assessment may be initiated. The process starts by using Data Sheet #1 to prepare a detailed list of past maintenance performed on the specific turbine, generator, or auxiliary system. The purpose for completing this form is to have a concise and up-to-date record on the components and systems that make up the particular turbine-generator under assessment. This step in the assessment is meant to provide a historical perspective, which in turn is used to weigh the importance of issues or anomalies that are identified for certain systems or parts. It identifies what types of problems have been reported in the past, whether a problem appears to be chronic, and if that problem has been eliminated. Part 1(a) of this set of data sheets assembles a baseline of information that reflects the date that critical components of the unit were inspected. Key recommendations made as a consequence of these inspections are also identified, and whether the action taken was considered to be addressing a chronic problem is noted. To assist in defining what is considered to be a “critical component”, in the aforementioned EPRI Life Cycle Management Sourcebooks, the critical components of the main turbine, generator, controls, and support systems were organized by their function. The most prominent components in the assessment procedure are shown in Table 1-2. These components form an integrated system within the overall unit and are subject to a condition assessment as opposed to an assessment of single parts (nuts, bolts, tenons, etc.) that make up a component.

1-9

Turbine-Generator Condition Assessment – In Service Table 1-2 Critical Components Identified in Assessment Procedure Classification

Critical Components (If Present)

1

Pressure Boundaries

HP/LP Outer Casing, HP/IP Inner Casing

2

Piping

Interconnecting, Cross-Over, Cross-Under

3

Nozzles

Impulse and Reaction

4

Turbine Rotor Sections

HP, IP, and LP Rotors; Disks and Blades

5

Packing and Seals

Interstage Packing, Shaft End Seals, Oil Seals

6

Coupling and Bearings

Bolts, Shells, Journals, Pads

7

Front Standard Assemblies

Main Oil Pump, Speed Sensors, Trip Systems, PMG

8

Essential Instrumentation

Vibration, Temperature, Expansion, Speed

9

Generator and Exciter

Stator, Rotor, Windings, Hydrogen Seals, Coolers

10

Controls

Valves, Governors, Trips, Meters, Regulators

11

Lubrication

Bearing Oil System, EHC System

Part 1(b) of this set of data sheets provides a record of any modifications or upgrades that were made to improve the unit’s performance or reliability over its history of operation. In making this evaluation, it should be noted that to improve the reliability of the component does not necessarily require a design modification. For example, a replacement in-kind with a new component would reflect a condition whereby the accumulated damage to the original material is eliminated. A replacement re-sets the aging clock for the time-dependent mechanisms that caused the original material properties of the component or system to deteriorate. Part 1(c) assembles a list of the significant forced outages that have occurred and the components they affected (such as a blade failure, a bearing journal wipe, etc). If the root cause is suspected or known, these should be described. Any specific documentation available should be referenced or attached. When defining what type of information should be included in this section, a significant forced outage event is one in which the unit was automatically removed from service based on a turbine supervisory trip or was removed from service by operators in order to correct a deficiency that could have seriously jeopardized the unit’s operational reliability. Part 1(d) concludes this review with an assessment of the potential risk for failure, based on the past maintenance history. A judgment is required as to whether the forced outage events identified on the prior sheets are likely to be isolated events or symptoms of a longer, chronic problem. The judgment of potential risks is consistent with all the parts forming a condition assessment and is reduced to three possibilities: high, medium, or low. Because this is dealing with the maintenance history, the need to recommend action associated with each itemized problem is not required. Instead, this is determined on a component-by-component basis based on the most recent information made available through audit and interview.

1-10


As reflected on the data sheet, the maintenance history does not necessarily have to be limited to any specific item, but it also should not be too detailed. In other words, when subsequent parts of the evaluation identify specific issues, this summary provides a basis for deciding if this is a new problem, a chronic problem, or a routine problem. A new problem may indicate that a system or component is reaching the end of its useful life, or it may reflect the consequence of an action taken during the last overhaul. A repeat or chronic problem suggests that a more permanent solution is warranted, and the condition assessment may need to account for the additional planning and time to find this solution, as well as the potential risk if the problem worsens. A routine problem would be one that can be expected to require action on a periodic basis. Trending the rate at which the system’s or component’s condition appears to deteriorate provides the basis to either shorten or lengthen the interval of inspection and planned replacement. When beginning an assessment, a search of available databases is recommended to assist the condition assessment team in determining an initial list of historical issues that might be considered for further scrutiny in a unit-specific assessment. For example, details such as those compiled by the North American Electricity Reliability Council’s Generator Availability Data System (NERC-GADS) can provide a broad profile of what the plant has officially reported on the unit over time. So as not to be overwhelmed by this raw data, the user should seek information only on a specific unit and focus on entries that are classified as “unplanned events involving required maintenance action.” Events compiled within the NERC-GADS database are organized and reported with “cause codes.” A partial list of cause codes associated with the main turbine is shown in Table 1-3. A search made for a specific unit can produce a simple record like that shown in Figure 1-2. This forms a starting point to build and cross check a historical record of system or component maintenance. It can also be useful in identifying specific issues that would be pursued in the interview part of the assessment.

1-11

Turbine-Generator Condition Assessment – In Service Table 1-3 Cause Codes Associated with Critical Components Found in the Assessment Procedure Critical Components

NERC-Defined Cause Codes

Other Steam 4499: Turbine-Generator Other Problems (All Problems Components) 4000: Pressure Boundaries, (HP/LP HP Outer Casing and Hoods) Casing

4001:

4200:

4201:

HP Inner Casing

LP Outer Casing

LP Inner Casing

Interconnecting and 4270: Crossover Piping Crossover Piping

4279:

Nozzle Boxes

4009:

4010:

4209:

4210:

HP Nozzle Bolting

HP Nozzle Boxes

LP Nozzle Bolting

LP Nozzle Boxes

HP Rotor Sections 4011: 4012: (Disk, Blades, HP HP Buckets Stationaries) Diaphragms Blades

4013:

4014:

4015:

HP Diaphragm Unit

HP Bucket Fouling

HP Wheels HP Rotor Other HP or Spindles Shaft Problems

LP Rotor Sections, 4211: 4212: (Disk, Blades, LP LP Buckets Stationaries) Diaphragms Blades

4213:

4215:

4230:

LP Blade Fouling

LP LP Rotor Wheels - Shaft Spindles

Packing (Interstage 4020: and Shaft End), Oil HP Shaft Seals Seals

4021:

4022:

4220:

HP Dummy Rings

HP Gland Rings

LP Shaft LP Dummy LP Gland Gland Seal Seals Rings Rings System

Bearings and Couplings

4040:

4240:

HP Bearings

LP Bearings

Front Standard 4280: Bearing Pedestal Lube Oil Instrumentation and Pumps Associated TSI Essential Condition 4420: Monitoring (TSI) Turbine Instrumentation Vibration Data Major Turbine 4400 Overhaul >720 hrs Major (All Components) Overhaul

1-12

Miscellaneous Turbine Piping

4300:

4309:

Turbine Supervisory System

Other Turbine I & C Problems

4221:

4030:

4099:

4250: Other LP Problems 4222:

4430:


Caution should be exercised in analyzing raw entries in the NERC-GADS data. Scrutiny must be applied to ensure that events are categorized and counted correctly. This principally involves (a) reviewing the cause code component identification and (b) consolidating multiple events. Specific cause codes tend to be assigned subjectively. The same problem can be associated to causes that differ from plant to plant. Some plants use the “Turbine Vibration” and “Other Steam Turbine Problems” categories as a catchall. A review of each entry should be made to ensure that it was assigned to the proper component (when details on the entry make this possible). Multiple events should be consolidated into one when the records indicate that they were actually associated with a single, larger event. The most common example of this circumstance is when several attempts were required to return a unit on-line, with each being logged as a separate entry associated with “turbine vibration.” In such instances, the multiple GADS entries dealing with the same issue (often occurring within a period of hours or minutes) should be treated as a single occurrence for that type of event, and the individual hours for the multiple entries consolidated into a total for the single event. This step prevents overestimation of the frequency of reports made for the specific component.

Figure 1-2 Example of NERC-GAD List of Maintenance Outage Events for a Typical Unit

1-13


Beyond the previously listed LCM sourcebooks, additional research published by EPRI that is associated with historical experience on component or system reliability, upgrades, and major forced outage events related to turbine-generators is as follows (listed by year of publication): Survey of Steam Turbine Blade Failures, Project 1856-1, EPRI, Palo Alto, CA: 1985. CS3891. Condition Assessment Guidelines for Fossil Fuel Power Plant Components, EPRI, Palo Alto CA: 1990. GS 6724. Improving Maintenance Effectiveness Guidelines: An Evaluation of Plant Preventative and Prediction Maintenance Activities, EPRI, Palo Alto, CA: 1996. TR-107042. Main Turbine Performance Upgrade Guideline, EPRI, Palo Alto, CA: 1997. TR-106230. Low Pressure Rotor Rim Attachment Cracking Survey of Utility Experience, EPRI, Palo Alto, CA: 1997. TR-107088. Reliability Assessment of North American Steam Turbines, EPRI, Palo Alto CA: 2002. 1006952. Component Failure Database: Version 2.0, EPRI, Palo Alto, CA: 2003. 1004863. Predictive Maintenance Primer: Revision to NP-7205, EPRI, Palo Alto, CA: 2003. 1007350. 1.5.2 Turbine Vibration The signature obtained from the turbine-generator bearing vibration instrumentation may reflect a condition of misalignment or unbalance present within the system. Characteristics (frequency, amplitude, and phase) are typically processed by an expert or specialist in vibration diagnostics. For operators, vibration limits are set to prevent damage caused by exceeding the journal clearances. The condition assessment of turbine vibration is intended to identify the root cause of problems that may be indirectly reflected in the system vibration signature. When trended, the vibration signatures can also provide a sense of whether the problem is stable or deteriorating over time. Data Sheet #2 (a) assembles a complete set of turbine-generator vibration amplitude and phase angle data recorded from the unit at both full load and minimum load. Obtaining data on a unit roll-up and roll-down is also strongly recommended. In addition, a frequency scan should be recorded and attached to the respective data sheet at each bearing location. The specialist providing these data should also be the individual who is responsible for tracking, trending, and evaluating any significant data changes in comparison to readings taken at the last outage or to the first set of benchmark data taken after the unit is returned to service.

1-14


On #2 (b), the data recorded in the audit is then analyzed by the vibration specialist through an interview process. A series of questions are identified. These are designed to assist in soliciting details and opinions that go beyond the data collected and summarized on the initial sheet. Ultimately, the results from the audit and interview are summarized in the third sheet #2 (c), where both the risk of failure (low, medium, high) and the need for action (immediate, intermediate, long term) are identified relative to the turbine vibration. To assist in the interpretation of data assembled from both the audit and the interview, typical orbit plots showing symptoms of common problems registered in the vibration signature are provided in Figure 1-4. A more detailed discussion on the symptoms and interpretation of vibration measurements related to common turbine-generator balance and alignment problems can be found in Volume 3 of these Guidelines, specifically the Balance Primer and the Alignment Primer. In terms of possible actions relating to turbine vibration, the most common issues likely to be found in an assessment are: •

Repeated balancing attempts are ineffective. This involves a condition where significant changes in unit vibration have required numerous balance shots, but the running speed vibration amplitude and phase angle at the shaft rotation frequency remain high or are still not improved. For example, the failure to relieve the vibration problem may indicate that the problem is instead with a coupling, or that unbalance in the rotor system is highly static (where phase angles are in-line), indicated by the phase angles recorded at each bearing. When considering recommendations, determine if a coupling has excessive run-out between the coupling halves. If so, this condition will result in high vibration that cannot be improved by balance shots. Coupling disassembly will be required to eliminate excessive run-out. A large static unbalance in the rotor system may require shop balancing of one or more rotors to correct this condition.

•

Significant changes are noted at harmonics of shaft speed. Vibration frequency scans should identify any significant changes associated with one-half X, 2X, 3X, 4X, or 5X harmonics of shaft rotational speed (where X represents rotor speed). For example, a frequency that is less than one-half rotor running speed represents an oil whip instability if seen during unit operation. There would also be a significant difference between the filter-out and filter-in vibration amplitudes. A significant change in the 2X frequency response could be noted if a unit has a large peripheral crack (with orientation orthogonal to the shaft centerline). Such a response would be seen in comparing a 2X scan before and after cooling and re-heating a rotor by changing the main or reheat steam temperature by 50–75ºF (10–24ºC). A large difference between filter-in and filter-out vibration typically signifies significant vibration at other frequencies as noted above. If a vibration problem is identified, it should be considered as serious and treated immediately in order to prevent a potential catastrophic failure of the rotor during operation. Vibration technical experts should be immediately contacted to further assess this problem and for guidance as to possible unit shutdown.

1-15


•

A major change is noted when load is added. Major changes in rotor vibration amplitude and phase angle that occur from minimum load to full load can be due to alignment problems on the unit or other reasons (such as partial arc loading issues at minimum load). For example, on some units the static and dynamic vector components may show significant changes in amplitude and phase between minimum load and full load. A subsequent alignment check may reveal significant rim and face misalignment of one rotor to another rotor.

•

A major vibration change is noted when passing through shaft critical speeds. Significant vibration amplitude and phase angle changes at rotor critical speeds could be caused by rotor bowing. Such bowing can be due to operation at high temperature over a long time period or due to rubs in the steam packing or elsewhere within the rotor system. This would typically be seen in the HP or IP turbines.

•

Sudden step increases in vibration are measured at the journals. Large, sudden step increases in journal vibration often indicate a loss of rotating blade material. Such changes generally require immediate inspection to assess damage and determine other corrective actions that may be required.

As a rule, progressive changes in measured vibration over extended periods of time reflect degradation due to wear of the bearings, settling of the foundation, permanent rotor bowing, or the cumulative effect of individual section overhauls that eventually require a major correction. A condition assessment should seek to determine the point in time when a major unit realignment would be worthwhile to restore the unit to its originally aligned condition. An interview of the operators can aid in determining whether unit vibration problems have been chronic, are getting worse, or have only recently started. After multiple rotor overhauls, possible settling of the bearing foundation, and/or thermal distortion of stationary components, the unit will require extensive alignment, This will establish the radial position of the rotor with respect to stationary components and to re-establish the cantenary position of the bearings to the initial cantenary line. If a system becomes badly misaligned, it may become impossible to find a reasonable alignment solution without a complete disassembly of the unit to perform a tops-on and tops-off alignment to correct the problem. Pronounced step changes in vibration typically signify a situation that requires immediate concern and attention. These steps changes reflect a loss of noticeable rotating mass, often caused when portions of a rotating blade such as a tip or cover are lost. This indication is significant in that it may represent an early warning of the progressive deterioration of the structural system as a prelude to a more catastrophic failure. For example, if the blade is designed to have its natural frequencies fall within certain prescribed operating bands; the loss of part of a cover band may shift one of the fundamental frequencies into a condition of resonance. If a large blade fails at the platform or root, the loss of mass can be sufficient to cause an unbalance that will cause extensive damage to the entire machine. Such cases have been recently documented.

1-16


Figure A shows the orbit of a shaft with several concurrent whirls at different frequencies taken from unfiltered vibration. Figure B shows the same plot at synchronous speed where nonsynchronous frequencies have been filtered out, showing the unbalance whirl orbit.

Stiffness affects the shape of the orbit as noted by Figures C–E. Identical bearing stiffness gives a circular orbit, dissimilar stiffness gives an elliptical orbit, and cross coupling of stiffness in vertical and horizontal direction gives a rotated elliptical orbit. Misalignment can be indicated as shown in Figures F–H. Note that the orbit is highly elliptical in F, indicating poor alignment. In Figure G the orbit for two bearings on each side of a coupling are banana-shaped, indicating severe misalignment. In Figure H the misalignment is also severe and suggests backward precession. Fluid whirl, a subsynchronous fluid instability, occurs within the range of 30–48% of machine operating speed. Figure I shows precession of vibration in the same direction as shaft rotation, displaying a circular orbit and two key-phasor dots. If the dots slowly rotate against shaft rotation, the subsynchronous frequency is less than 50% of shaft speed; if the two dots remain stationary, the frequency is exactly 50% of shaft speed.

Fluid whip is a subsynchronous excitation at the first critical speed of a rotor that operates far above twice first critical speed and has vibration amplitudes equivalent to bearing clearance. The orbit for this is shown in Figure J. Note the multiple key-phasor dots that this excitation produces.

Rubs are a typical problem seen on steam turbines and are generally at 1X frequency for units that operate at less than twice first critical speed. If a rotor operates well above first critical speed, frequencies generated would be at 1X and 1/2X frequencies. Figure K shows a rub in a unit whose speed is well above first critical speed frequency and has a predominant 1/2X frequency.

Figure 1-3 Typical Orbits Showing Different Problems

1-17


In addition to the information referenced in Volume 3 of these guidelines, previous research published by EPRI related to turbine-generator vibration is as follows (listed by year of publication): Periodic Vibration Monitoring: Utility Experience, EPRI, Palo Alto CA: 1987. CS-5517 Symposium Proceedings: Rotating Machinery Dynamics, Bearings and Seals, EPRI, Palo Alto, CA: 1988. CS-5858. Applying Vibration Monitoring, EPRI, Palo Alto CA: 1991. NP-6340. Shaft Alignment Guide, EPRI, Palo Alto CA: 1999. TR-112449. Technology Development for Shaft Crack Detection in Rotating Equipment Using Torsional Vibration, EPRI, Palo Alto CA: 2003. 1009060. 1.5.3 Bearing Metal and Oil Temperatures Pressure-lubricated journal-type bearings support the rotor shaft elements at both ends. A thin oil wedge that is created by rotation within the stationary pads supports the shaft. Maintaining the proper thickness of this oil wedge is critical to preventing bearing vibration due to oil film instabilities. Since steam pressure differential across most turbine stages produces a net thrust along the shaft, the thrust bearing provides a reaction force to this differential and limits the rotor’s axial position to maintain proper axial clearances between the stationary and moving elements. Loss of lubrication, oil temperature excursions, or contamination of the lubricating oil can result in serious damage to the bearings. This step of the condition assessment is meant to ensure that no unusual loading condition is occurring at the rotor journals or bearings. As part of the assessment, bearing metal, oil inlet, and oil outlet temperatures should be recorded at maximum and minimum load and recorded as recommended in Data Sheet #3(a). Recording these data should also be considered throughout the load range. As in the previous Data Sheet, #3(b) identifies a list of questions that should be answered as part of the specialist interview. The series concludes with Data Sheet #3(c) and the assessment of risk and need for action relative to this system or component. The most common issues likely to be found in an assessment are: •

Pronounced changes in metal temperature since the last evaluation which can be an indication of alignment changes or bearing wipes. Both conditions generally represent a high risk to the overall system. As with a step change in vibration, they should be taken seriously and corrected promptly.

•

Sudden spikes in bearing metal temperature may indicate that a bearing may have actually wiped. If a sudden metal temperature change has occurred, this can mean that other bearings are now more heavily loaded. Their journal radial position may have changed, meaning that the rotor may now be running close to a rub condition that could take the unit off-line and potentially damage rotating and stationary components.

1-18


It should be noted that bearing vibration amplitude or metal temperature changes could be observed on some units due to valve arc loading. For these units, this may be normal. It should be considered an abnormal condition in the assessment only if this is the first time it has been observed. Actions that may be required to correct a bearing problem can include checking the rotor radial position to either oil or gland bores along with the disassembly of couplings and realigning the turbine depending on the radial position found. Such work can be easily accomplished during a limited outage if planned sufficiently in advance. A partial list of research published by EPRI related to aspects of turbine-generator bearing operation is listed as follows (by year of publication): Guidelines for Maintaining Steam Turbine Lubrication Systems, EPRI, Palo Alto CA: 1986. CS-4555. Manual of Bearing Failures and Repair in Power Plant Rotating Equipment, EPRI, Palo Alto CA: 1991. GS-7352. Bearing Troubleshooting Advisor, Version 2.0, EPRI, Palo Alto CA: 1994. AP-100531-R1. Bearing Technology Topics: Various Technical Papers, Volumes 1 and 2, EPRI, Palo Alto CA: 1999. TR-113059-V1 and V2. 1.5.4 Thermal Performance The state-of-the-art methodology in axial steam turbine thermal design takes into account many factors, including optimal stage-to-stage loading (enthalpy drop). Other design factors include: •

Airfoil shapes used in nozzles, diaphragms, rotating blades/buckets (three-dimensional designs being increasingly used)

•

End-wall shape (that is, the inner and outer boundaries of the flow passage

•

Blade/bucket shroud configuration

•

LP turbine stage wetness removal

•

Blade/bucket tie-wire losses

•

Interstage sealing

The dry internal efficiency of modern steam turbine sections ranges from the high 80s percentage range to the low 90s percentage range. Wetness losses in both the HP (nuclear) and LP (nuclear and fossil) sections of units reduce this efficiency somewhat, depending on the wetness level. Individual stage efficiency, particularly in the superheated early stages of the LP turbine, can exceed 90%. However, the overall multistage expansion is always less than the individual stage efficiencies. 1-19


As part of the overall condition assessment, thermal performance degradation is used as an indirect indicator for identifying problems that may be developing within the HP, IP, or LP turbine steam paths that in some manner inhibit or disrupt the flow so that noticeable losses are produced. These losses are reflected as a higher turbine cycle heat rate or loss of power output. To facilitate the interpretation of performance-related test data, Tables 1-4 and 1-5 reflect common changes in the condition of different components of the turbine steam path in terms of their consequence on measurable performance cycle parameters. Table 1-6 provides general guidance in terms of the impact on heat load due to various forms of steam leakage into the condenser. To make this assessment, the most current data should be gathered and recorded using Data Sheet #4. Data assembled on 4 (a) should be trended at the same load point to further assess performance degradation over time. Often, a key in the interpretation of overall performance data is to isolate the cause within the respective section of the overall steam path. Identifying the source of a suspected flow restriction can be approached in a systematic manner: •

Steam extractions, reheat conditions, and moisture separators are logical cycle points that can be used to identify turbine sections or plant systems that may be deteriorating.

•

The first HP (control) stage and last LP stage have a significant influence on the overall unit performance. Although most turbines consist of a large number of individual stages, only the first and last stages tend to be significantly influenced by changes in the flow rate. First stage performance is primarily more sensitive to variations in load. The last stage is more sensitive to variations in both load and backpressure.

•

Throttle flow factor is usually an indication of increased nozzle erosion. Trending this value will give an indication of the rate of nozzle degradation that may be occurring for the specific unit. Evaluation of other performance parameters may show other types of deterioration, such as nozzle area closure or significant deposit formation on stationary and rotating blades.

•

Excessive erosion on the leading edge of a last stage blade may be an indication of high feedwater levels in the neck heaters or of problems in the moisture removal system in the LP section. If significant erosion is seen, such as 1/8" (3.18 mm) or greater on the leading edge of a last stage blade since the last inspection, attention to feedwater heater controls should be considered along with a detailed inspection of the LP section moisture removal system at the next scheduled overhaul. If numerous tube leaks have occurred in these heaters, immediate actions should be taken to eddy current inspect and plug suspect tubes. A long-term fix may be to re-tube these feedwater heaters.

•

Operating at low loads and high backpressures can result in excessive moisture droplet erosion in the last stage blades or the development of fatigue cracks due to a vibratory condition referred to as flutter. This can occur as a result of increased cycling duty. In the current utility financial operating environment, many units designed in the 1960s and 1970s for base load operation are now being run to match peak consumption swings, sometimes on a daily basis. When performing a condition assessment, changes to the condenser system or operating pattern of the unit should be noted, and the condition of the LSB monitored for these signs of distress during limited outages where the condition can be visually inspected.

1-20


Performance-related problems such as blade erosion or nozzle deterioration are generally not catastrophic, unless a severe condition is allowed to persist. The incentive to address the thermal performance issues is therefore typically based on the loss of efficiency produced by the deterioration of the steam path. However, the location and extent of work that may be required to restore a component should be seriously evaluated so that damage that would require only small repairs is not allowed to escalate into a major scope of activities that compound the risk of an extended outage due to unforeseen circumstances. For example, erosion in the HP nozzles can normally be tracked by periodic visual inspection with corrective actions planned for the next overhaul. Monitoring performance parameters such as those identified in Tables 1-4 and 1-5 can assist in identifying consequences of such erosion. However, if erosion cuts or erosion are allowed to become deep, the time required for repair will be extended based the amount of weld repair required to correct the problem. The location of the repair may also increase the level of risk assigned to a reliability issue. For example, extensive erosion to the HP nozzle plates can then result in significant erosion to the HP first stage buckets. Unintended removal of material from the buckets can make them more susceptible to resonant vibration, particularly at certain valve points. It is this type of secondary consequence that should always be considered when assessing the potential need and urgency to address an original problem. A partial list of research published by EPRI related to turbine-generator performance is as follows (organized by year of publication): Assessment of Supercritical Power Plant Performance, EPRI, Palo Alto CA: 1986. CS-4969. Heat-Rate Improvement Guidelines for Existing Fossil Plants, EPRI, Palo Alto CA: 1986. CS-4554 Fossil Unit Performance: 1965-1984, EPRI, Palo Alto CA: 1987. CS-5627. Solid Particle Erosion Technology Assessment, EPRI, Palo Alto CA: 1994. TR-103552. Thermal Performance Engineering Handbook, Volume 2: Advanced Concepts in Thermal Performance, EPRI, Palo Alto CA: 1998. TR-107422-V2. Turbine Steam Path Damage: Volumes 1 and 2, EPRI, Palo Alto CA: 1998. TR-108943.

1-21

Turbine-Generator Condition Assessment – In Service Table 1-4 Effect of Component Condition Changes on Fossil Cycle Performance Parameters (at Valve Wide Open Operation) Condition

Throttle Low #/hr

PT

P1st

PHRH

PLP

H. P. Efficiency

I. P. Efficiency

Increase TT

↓

N. C.

-

↓

↓

↓

-

Increase THRH

-

N. C.

-

↑

↑

-

-

Increase A1st (SPE) in HP

↑

N. C.

↑

↑

↑

↓

-

Increase AHRH (SPE) in IP

-

N. C.

-

↓

-

-

↓

Decrease A1st (Deposits and Peening) in HP

↓

N. C.

↓

↓

↓

↓

-

Decrease AHRH (Deposits and Peening) in IP

-

N. C.

-

↑

-

-

↓

Decrease A2nd (Deposits) in HP

↓

N. C.

↑

↓

↓

↓

-

Increase A2nd (Rubs) in HP

↑

N. C.

↓

↑

↑

↓

-

Decrease ALP (Deposits and Damage) in LP

-

N. C.

-

-

↑

-

-

Note that every change in turbine condition results in a different three-key pressure pattern.

1-22

Turbine-Generator Condition Assessment – In Service Table 1-5 Guidance for Interpreting Turbine Cycle Steam Flow and Unit Load Changes Type Problem

Timing

Throttle Flow

Section Efficiency

Electrical Load

SPE

Gradual

Increase

Decrease (-HPη decrease greatest at light load)

Increase or essentially constant

Deposits

Gradual

Decrease (may increase after shutdown)



Foreign Object (Wrench, Bolts, etc.)

Abrupt following outages

Decrease

Decrease

Decrease

Peening (weld bead)

Abrupt following boiler repairs

Decrease

Decrease

Decrease

Mechanical Failure

Abrupt anytime, usually during operation

Usually decrease

Decrease

Decrease

Water Induction

Abrupt anytime during operation

Slight increase

Decrease

Decrease

Vibration

Abrupt, usually most severe at first startup

Slight increase

Decrease

Decrease

Steam Whirl

Abrupt at first startup

Slight increase

Decrease

Decrease

Internal Leakage (Balance Hole Plug)

Abrupt following overhaul

Increase

HP turbine – decrease

Decrease

Internal Leakage (Inner Shell)

Gradual

Slight increase

Decrease

Slight increase

Broken Valve Stem

Abrupt

Decrease

Decrease

Decrease

1-23

Turbine-Generator Condition Assessment – In Service Table 1-6 Effect of Leakage to the Condenser on Heat Rate and Load Effect of 1% Leakage to the Condenser on Fossil Reheat Origin of 1% Leakage Flow

On Heat Rate

On Load

Throttle

0.83%

0.94%

HP Turbine Exhaust

0.53%

0.69%

Ahead of Intercept Valves

0.69%

0.56%

Crossover

0.44%

0.44%

Rules of Thumb 1% ηHP

=

0.16% heat rate or 0.3% kilowatt

1% ηIP

=


1% ηLP

=


1% flow increase =

0.94% increase in kilowatts

1°F (0.56°C) temperature increase = 0.08% decrease in kWs and 0.024% better heat rate (VWO) 1 Btu TEL (total exhaust loss) = 0.1% poorer heat rate 10°F (5.6°C) decrease in TT increases ηHP 0.11%. A 5% increase in stage pressure flow relationship is cause for alarm. 1% ∆P increase in steam path = 0.1% poorer heat rate A 1% change in P1st due to a change downstream indicates a 1.5% change in flow for a 1.25 pressure ratio control stage (Curtis stage, not single Rateau stages). nd

A 1% change in P1st due to a change upstream of the 2 stage indicates a 1% change in flow . Bench mark η HP 2% is better than heat balance. A 10% nozzle area increase due to SPE results in a 6½% loss in stage efficiency for the control stage and 3–4% for the other stages. A 10% decrease in control stage nozzle area decreases the flow passing capacity by 3%. % ∆P SV and CV 4% (VWO) % ∆P IV 2% % ∆P crossover 3% A 1% increase in HP and IP turbine stage pressures due to a restriction downstream of the stage results in a 0.6% increase in pressure upstream for an impulse type stage and 0.7% for a 50% reaction stage.

1-24


1.5.5 Unit Start and Load Data Unit start and load data are primarily used to assess (a) rotor life, (b) issues associated with creep damage in the first HP or reheat stages, and (c) low-cycle fatigue in the last two or three rows of the LP turbine, depending on the size of the blades and the loads they exert on the blade root attachments. The condition assessment should evaluate the record of accumulated start-stop events to determine the potential for these damage mechanisms to affect the future reliability of the rotor components. To perform the assessment, the number of hot, cold, and warm starts are gathered since the last overhaul along with the unit service hours and recorded on Data Sheet #5. These totals (since the unit went into commercial operation) should also be determined to assess creep (total hours) or low-cycle fatigue damage (total start-stop cycles). Unit start/load information for the time period from the last inspection can be entered into Equation 1-1 to assess the potential need for a major inspection. This equation equates unit start types and trips to equivalent operating hours (EOH) for a unit. EOH = 20 x CS + 10 x HS + 5 x WS + SH+ 40 x FLT + 10 x LFLT

Eq. 1-1

EOH = Equivalent operating hours CS

= Number of cold starts

HS

= Number of hot starts

WS

= Number of warm starts

SH

= Synchronized hours since last overhaul

FLT

= Number of unit trips above 75% of full load

LFLT = Number of trips on unit at less than 75% full load (includes annual overspeed trip). Using this formula, the maximum number of equivalent operating hours between outages should not exceed 80,000 equivalent operating hours (EOH) for base load and load cycling units. This assumes that unit condition is acceptable and that normal predictive/preventive maintenance and system tests are being performed on the unit as specified by the OEM. It should be noted that higher EOH might be allowed for newer designed machines. Experience may show that 80,000 EOH is not advisable in some situations, especially in supercritical HP and IP sections. Judgment, experience, and a continuing condition assessment program for a unit should be the basis for selecting EOH limits. If detailed component life consumption models exist for the critical elements, such as blades and rotors, this information can be used to determine the probability of problems due to creep, highand low-cycle fatigue, stress corrosion cracking, or other blade issues without having to use Equation 1-1 above. The additional accuracy provided by such models offers a basis for changing the turbine overhaul interval. 1-25


A partial list of research published by EPRI on turbine-generator unit start-up and loading is as follows (organized by year of publication): Variable Pressure Operation: An Assessment, EPRI, Palo Alto CA: 1990. GS-6772. Steam Turbine Start-Up and Loading, EPRI, Palo Alto CA: 1998. CD-110966. 1.5.6 Unit System Steam/Water Purity Inadequate control of steam or water purity can introduce contaminants into the steam path, particularly at the LP section Wilson Line (“wet zone”), causing corrosion damage and/or plugging to the steam path. As such, a change or deterioration in steam or water purity can affect both reliability and output and therefore is included as a separate part of the condition assessment. Data Sheet #6 outlines the purity tests that are typically conducted and at what locations. In general, purity is defined by measurements of: •

Specific conductivity

•

Cation conductivity

•

Presence of sodium

•

Presence of silica

•

The pH level

Typical limits are identified on Data Sheet #6(a). Purity is monitored at the polisher or economizer outlet, the main steam or reheat steam inlet, and the condensate pump discharge. Any out-of-limit chemistry excursions that have occurred since the last assessment should also be noted. If specific problems have been experienced, determine by means of the interview when it occurred, how the problem was resolved, and then assess the impact on future turbine reliability. In terms of interpreting the potential impact of water impurities as a consequence to unit condition, the following guidance is offered: •

If a steam or water chemistry upset has occurred, there may be an increased risk of caustics, sodium, chlorides, copper, or sulfates being deposited on steam path components.

•

Copper typically deposits in HP turbine sections with chlorides, sulfates, and caustics in the LP section near the phase transition zone. These deposits can lead to pitting and eventually stress corrosion cracking (SCC) or corrosion fatigue (CF) of turbine blades, wheel dovetails, or other highly stressed rotating components. The leading indicators of this problem can be determined by visual observation of pitting on LP wheels and blades and the coloration of the deposit (white or light grey). Such deposits, if seen, should be analyzed to determine their composition in that specific deposit at the stage in which they were located.

1-26


•

Copper deposition in the HP section can be determined by noting a gradual loss of steam flow passing capability and turbine performance degradation. There have been cases where copper deposits were removed by flooding the specific turbine section with a mixture of ammonia and water. Several utilities have reported the success of such an activity.

A partial list of additional research published by EPRI on turbine-generator steam and water purity is as follows (organized by year of publication): Guide for the Use of Corrosion Resistant Coatings on Steam Turbine Blades, EPRI, Palo Alto, CA: 1987. CS-5481. Cycling, Startup, Shutdown and Layup Fossil Plant Cycle Chemistry Guidelines for Operators and Chemists, EPRI, Palo Alto CA: 1997. TR-107754. Steam, Chemistry and Corrosion in the Phase Transition Zone of Steam Turbines: Volumes 1 and 2, EPRI, Palo Alto CA: 1997. AP-108184. Corrosion of Low Pressure Steam Turbine Components, EPRI, Palo Alto, CA: 2000. 1000557. Turbine Steam Chemistry and Corrosion: Electrochemistry in LP Turbines, EPRI, Palo Alto, CA: 2001. 1006283. 1.5.7 Lubricating Oil and EHC Fluid Testing Contaminated lubricating oil can damage bearings, thrust runners, and rotor journals. It can also cause problems on units that use lubrication oil in control systems, such as mechanical hydraulic controls. This increases the risk of overspeed events and result in problems in other turbine systems. Any sudden increase in particle count size, water, color, or neutrality number may require plant actions to correct such problems before the turbine-generator experiences problems. Data Sheet #7 is provided to guide the assessment of lubricating oil and EHC fluid condition. As with the preceding data sheets, it begins with an audit #7(a), moves to the interview with the system specialist in #7(b), and concludes with an assessment of the risks and recommendation of action in #7(c). Typical problems that can be experienced due to contaminated lubricating oil or EHC fluid are discussed below. Lubricating oil: •

A copy of the lubricating oil particle counts, water neutralization number, and color should be obtained, and this data should be recorded on Data Sheet #7a. Oil samples are normally taken near the booster oil pump or eductor, on the inlet side of the oil tank return screens and from the discharge side of the oil purification system.

1-27


•

These values should be trended and compared against the OEM limits. High particle counts can result in scored journals and increase the risk of bearing wipes (thrust and heavily loaded journal bearings) along with having a detrimental affect on the hydraulic control system. The control system components can seize due to dirt accumulation and, in some severe cases, fail to properly function during transient events on the machine.

•

Water in the lubricating oil can result in reduced oil film thickness at operating speed and loss of insulation on generator and exciter bearings and the insulated hydrogen seal casing. Electrical discharge from the journals to the bearing babbitt material can result in the frosting of bearings and journals and increase the risk of a wiped journal or thrust bearing during unit operation.

•

Contaminated lubricating oil can be corrected by installing a vacuum dehydration system at the oil tank to remove both water and particles from the oil. There are recirculation pump and filter units that can be installed at the oil tank to clean particles from the oil. These actions will clean the lubricating oil, but they do not clean the piping, which may also be contaminated.

EHC Fluid: •

A copy of the EHC fluid sample test results should be obtained and recorded on the same set of data sheets. It is important that fluid quality be maintained within the limits specified in Table 11-1 of the EPRI report EHC Fluid Maintenance Guide (1004554) to prevent hydrolysis on valve spools. Hydrolysis can cause sticking or binding of EHC components or cause stress corrosion cracking in stainless steel parts of the EHC system. A copy of this table is shown on the next page for reference.

1-28


EHC Test Results 1

Parameter

EPRI Limit of 4.0 max or monthly increase of 0.5

Color

Frequency

Reference

Achievable2

Comments

Monthly

4.4.3.1

1.5 (Light Tan)

ASTM D-1500 Color Criteria; OEM’s limits are included in Appendix H. Fluid Color Scale Comparison Chart is included in Appendix G5. System contamination measurement most important after breach of system

Viscosity

+/- 10% initial value

Monthly

4.4.3.2

N/A

Acidity (mg KOH/g)

< 0.1

Monthly

4.4.3.3

< 0.05

Chlorines (ppm)

< 50

Quarterly

4.4.3.4

< 10

System contamination measurement most important after breach of system

Water (%, ppm)

< 0.1, 1000ppm

Monthly

4.4.3.5

< 0.05, 500ppm

2 main methods for improving this are dry air purge and vacuum dehydration

Mineral Oil 3 (%)

< 0.5

Quarterly

4.4.3.6

<0.1


Resistivity (G-Ohm-cm)

> 5 - 10

Monthly

4.4.3.7

> 20

Can cause erosion problems on stagnant areas of system, fluid types have different values

Particulate4

<2K/100 ml of 5-10 5 micron

Monthly

4.4.3.8

1K/100 ml of 5-10 micron5

EPRI value is a good starting point for developing fluid monitoring, but it has to have consistent sample methods and points

Individual Metals (per metal)

< 10 ppm

6 Months

4.4.3.9

< 2 ppm

Not a routine check, but indicative of degrading system, exclude phosporus and chromium. If particulate or acid #’s increase then increase the frequency of metal testing.

Foaming (Height/Colla pse time)

< 100 ml/ < 5 minute

12 Months

4.4.3.10

N/A

Collapse time is reported as time to get to nil foam height

Air Release

< 10 minutes

12 Months

4.4.3.11

< 8 minute

Should be performed with the system health check. With natural fluids < 5 minutes is achieveable.

B8

2 Years

4.4.3.12

B2/B3

Indicator of heat related problems

Hexane Test

6

NOTES: 1. Any one parameter out of the recommended values does not condemn a fluid or system. The collective data is what determines if a fuild or system is of concern. More than 2 parameters outside of the values would require evaluation to determine the total affect. Test methods are specified in Table 4-10 in section 4.4 of EPRI report 1004554. 2. Achievable values normally require system modifications and upgrades. 3. Some standard tests (GE) do not report only mineral oil, but generate a number that includes other non-soapontifiables (fluid degradation by products). 4. If this parameter doubles from one sample to the next then a new sample is needed per the EPRI sample procedure in section 4.2.2 of EPRI report 1004554. 5. ISO cleaniness code equivalent numbers are not available at this time due to changes in calibration test dust and the techniques which had been used in the most previous testing. 6. Rate according to ASTM D-2276 Appendix A3 B scale for aviation turbine fuels going from B-0 (white) to B-10 (very dark brown to black).

1-29


•

Follow-up actions should be taken if these recommendations for EHC cleanliness are exceeded. Efforts should be made to ensure that EHC pumping system components are on a fixed PM schedule and they are inspected and repaired when recommended limits are reached.

It has been shown that high water content in the EHC fluid can be minimized by pressurizing the EHC tank with instrument air at a pressure of 2 inches (50.8 mm) of water above atmospheric and the fuller’s earth filter is operated as recommended by the OEM. In addition, if maintenance is frequently performed to servo valves and valve actuators during overhauls, the plant needs to have a foreign material exclusion (FME) program to prevent system contamination. A partial list of EPRI research published on lubricating oil and EHC fluid testing is as follows (by year of publication): Lube Oil System Leakage Mitigation, EPRI, Palo Alto, CA: 1999. TR-111413. Lubrication Guide: Revision 3 (Formerly NP 4916-R2), EPRI, Palo Alto, CA: 2001. 1003085. Electrohydraulic Control (EHC) Fluid Maintenance Guide, EPRI, Palo Alto, CA: 2002. 1004554. Turbine Oil Lubrication Compatibility Testing, EPRI, Palo Alto, CA: 2004. 1011028. Turbine-Generator Auxiliary Systems Maintenance Guides: Lube Oil System Maintenance Guide, EPRI, Palo Alto, CA: 2005. 1010191. Electrohydraulic Control (EHC) Fluid Elastomer Compatibility Study, EPRI, Palo Alto, CA: 2005. 1011823. 1.5.8 Pump Testing The lubrication system in a turbine-generator includes a variety of pumps that work continuously. The loss of or inadequate oil pressure can result in significant damage to bearings and turbine-generator internal components if a unit is tripped and rolls down from operating speed. Inadequate oil pressure (normal pressure is 25 psig (172 kPa) at the turbine centerline) can result in increased bearing metal temperatures and sluggish operation of the MHC control system. To assess the condition of these components, eight pumps are identified on Data Sheet #8: •

AC auxiliary oil pump

•

Turning gear oil pump

•

DC lubricating oil pump

•

Main seal oil pump

•

Recirculation seal oil pump

•

DC seal oil pump

1-30


•

Stator cooling pump

•

EHC pump

The assessment should review and record start results on all pumps in the lubricating oil, seal oil, EHC, and stator-cooling systems as recommended by the specific OEM. The pump condition should be assessed based on start test data, which includes the frequency of starts, the results of the test, and their comparison to acceptance criteria. Interviews should be conducted with operators and maintenance personnel responsible for PM or PdM on these pumps in order to determine if they are being tested, operated, and maintained in accordance with internal organizational or OEM requirements. Also, it should be determined if there are issues with these pumps that could result in the potential for a forced outage on the machine. In terms of evaluating the information gathered in the assessment, the following are offered as guidance: •

A spot check of EHC or lubricating oil pump discharge pressures or at the turbine centerline should be taken and reviewed to ensure that they are within prescribed limits noted in the specific OEM instruction book.

•

Pumps not meeting minimum OEM requirements should be recommended for inspection and/or corrective action. Action should include checking the pressure switches that initiate starting for correct actuation or repair/replacement at the next inspection if conditions dictate.

•

If these pumps are not being tested, a recommendation should be made to initiate testing in order to minimize the risk of operating failures when these pumps are required to function as intended.

A partial list of EPRI research on turbine-generator pumps is as follows (by year of publication): Symposium Proceedings: Power Pump Plants, EPRI, Palo Alto, CA: 1988. CS-5857. Power Plant Pump Repair Guideline (Interim Report), EPRI, Palo Alto, CA: 2000. SV 113418-OL. Pump Troubleshooting, Volumes 1 and 2, EPRI, Palo Alto, CA: 2000. 1000919. Vertical Pump Maintenance Guide: Supplement to NP-7413, Deep Draft Vertical Centrifugal Pump Maintenance and Application Guide, EPRI, Palo Alto CA: 2002. 1003467. 1.5.9 Turbine Steam Valve Test Results A turbine’s governing system controls the steam flow through the unit by small adjustments to the control or governor valve positions. Governing valves and control valves admit steam to the nozzles of the first stage. Stop or throttle valves isolate the turbine sections from their steam supply in the event of load loss. Intercept and reheat stop valves control the flow of LP inlet steam during rapid load changes or overspeed events to prevent reheat steam from entering the LP turbine. Locations of common turbine control elements and valves discussed in this portion of the assessment procedure are shown in Figure 1-4. 1-31


If the turbine inlet steam flow is maintained in the event of a loss of generator load, the rotor can accelerate to destructive overspeed within seconds. Periodic valve open/close tests and tightness tests are therefore necessary to ensure smooth valve operation in the event of emergency loss-ofload situations. Valve deterioration can also play a role in the thermal efficiency and performance of the turbine.

Figure 1-4 Location and Function of Basic Turbine Controls

Data Sheet #9 is used to guide the assessment, specific to the control, main stop, reheat stop, intercept, and non-return valves that may be found in a unit. Basic acceptance criteria are identified that focus on the fundamental problems that typically affect valves. The more common valve problems to be aware of when assessing valve condition are: •

Broken valve stems are typically found immediately because there is an abrupt change in throttle flow, section efficiency, and unit load. Unless corrected, the unit output will likely remain restricted.

•

In the case of fossil units, valve stems can become stuck due to oxidation and corrosion on the stems and bushings, resulting in zero stem bushing clearance. Another cause for sticking may be stem bending due to residual stress caused by manufacture or steam bending/side loading forces acting on the stem. Different symptoms may be observed depending on where in the stroke stem the stem sticks. For example, if a control valve stem starts to stick just as the valve opens, the operator will see no increase in throttle flow or load at the valve crack points. The stem may eventually move slowly and make irregular changes in load and flow, thus causing difficulties in load control. It should be recommended that this condition be corrected as soon as possible.

•

External leaks are principally due to improper gasket compression or broken valve bonnet studs. Valve conditions such as these normally take one to two days to correct, but can take at least five days if studs are found to be cracked and need to be replaced. The consequence of this type of valve degradation is lost generation to make repairs, which may be significant, depending upon when the maintenance is scheduled.

1-32


•

Internal steam leakage occurs primarily as a result of the deteriorated condition of the valve disk and seat. Leakage can be due to: –

Valve disk or seat distortion

–

Damage to the valve seat or contact surfaces

–

Improper setting of the controls that results in the disk being lifted off the seat when the valve is in a closed position setting

–

Bent/broken valve stems, which cause the valve to stick open slightly when the valves have been given a control signal to close

The consequence of valve internal leakage can be an overspeed of the unit during operation or prevention of the unit from going on turning gear. Valve leakage can be checked by first opening and closing valves with pressure applied to the valve being tested and then recording turbine shaft speed. An increase in shaft speed indicates internal leakage. Valves should be leak tested in accordance with OEM recommendations. Failure of the valves to close when tested means there may be a significant increase in the risk of a turbine overspeed event (worldwide, the failure of valves to close has resulted in numerous overspeed events). Such risks have such catastrophic potential that a valve problem should be corrected no later than the next unit weekend shut down. For fossil units, it is recommended that open/close tests be performed weekly on all valves. Functional tests on the main stop, intercept, and reheat valves should be performed weekly. Control valves should be closed weekly. Tightness tests are normally recommended on the main stop, control, and intercept valves on a 6–12 month interval to ensure minimal steam leakage by these valves. Nuclear valves may be tested at intervals that are different from those for most fossil valves. Typically, open-close tests are performed at OEM-recommended intervals, with tightness tests performed on the governor (control) valves and on the main stop (throttle) valves on a 6–12 month basis. Most GE valves have specific criteria for testing tightness. For example, a GE nuclear main stop valve is considered tightly closed when turbine speed reduces to less than twothirds of rated speed. If the valve does not completely close and if speed stays at more than twothirds of rated speed, the valve condition should be monitored. Eventually, a valve may not pass the tightness check. If this occurs, corrective action should be taken as soon as possible. A GE nuclear control valve is considered tightly controlled when speed reduces to one-third of rated speed or less. If the unit cannot go to turning gear, corrective action should be taken at the next outage. If shaft speed during the test is greater than one-third of rated speed, action should be taken sooner. SWPC nuclear valves may have different acceptance criteria; thus, OEM recommendations should first be followed. If no criteria are provided, the acceptance criteria described above for GE nuclear valves should be used. The frequency of valve testing can be increased, depending on a unit’s particular experience. However, if the interval is extended too much, the risk of an overspeed event may be increased 1-33


significantly. Valve tests prove that the control system is functioning properly and that valves will close without sticking. If any part of the above tests fail, then the first and second lines of defense against overspeed have been compromised. All machines should be wired so that the generator breaker is not opened until the valves are clearly indicated as closed (the generator is allowed to motor for 3 to 5 seconds, for example). This very simple feature added to the trip system logic could have prevented many units located in the United States from experiencing overspeed events. Numerous technical bulletins by turbine-generator OEMs have been published on this subject. The condition assessment should thoroughly review the results of these tests performed by operations, or if they have not been performed, have them conducted during the annual review. Appropriate comments should be made in the specified areas on the data sheets. As noted, valves not meeting the criteria specified should be recommended for inspection at the next unit outage or, if severe enough, at the next weekend shutdown of the machine. For additional information relating to valve testing and maintenance, refer to the valve primer found in the EPRI report Guidelines and Procedures for Steam Valve Condition Assessment (1008352). A partial list of EPRI research on turbine-generator valves is as follows (organized by year of publication): Guidelines and Procedures for Steam Valve Condition Assessment, EPRI, Palo Alto, CA: 2004. 1008352. Turbine Steam Valve Diagnostics Testing, EPRI, Palo Alto, CA: 2004. 1004960. 1.5.10 Overspeed and Trip Checks In all turbines, loss of turbine speed control can result in overspeed and a risk of rotor failure. Overspeed and trip checks are the front line of defense against the risk of a catastrophic turbine failure. The turbine control system must therefore always operate properly and reliably. This condition assessment task is meant to evaluate the present capability of the control system to rapidly isolate the main turbine from the boiler/reheater/reactor and/or the moisture separator/reheater (MSR) steam supply. Data Sheet #10 identifies a minimum of five trip tests: •

Overspeed trip

•

Minimum oil trip

•

Vacuum trip

•

Solenoid trip

•

Shaft pump trip

1-34


Other trip devices, like those listed below, may also be installed on particular units. Locations of these common trips are shown in Figure 1-4. •

The overspeed trip backs up the normal speed-governing system, including the main and preemergency speed governors, and is activated only when control or governor valves cannot act rapidly enough.

•

The low bearing oil pressure trip guards against wiping the main bearings when the lubrication fails by activating the emergency shutdown systems and promptly closing all steam valves.

•

The low vacuum trip closes every steam valve in the turbine if the exhaust vacuum falls below a set allowable pressure.

•

The solenoid trip shuts down the turbine by closing all valves.

•

The thrust trip measures the position of the rotor relative to the thrust-bearing cage and trips the emergency shutdown systems if the position deviates from safe limits.

It should be confirmed in the interview with operations that all turbine-generator trips noted in the audit were performed properly. The trip speeds or acceptability of the test for each trip should be indicated, along with the date on which the test was performed. Any other pertinent operational tests not specified in this data sheet (#10) should be recorded along with the results of these tests. In terms of completing the assessment, failure of any trip device to actuate is cause for immediate action to be taken by the plant to correct the problem. Otherwise, the risk of catastrophic failure of the unit is significantly increased. A partial list of EPRI published research related to turbine-generator overspeed and trip testing is as follows (by year of publication): Development of a Risk Monitor for Assessing Plant Trips, EPRI, Palo Alto, CA: 2002. 1003117. Risk Evaluation of Steam Turbine Destructive Overspeed, EPRI, Palo Alto CA: 2003. 1008740. Turbine Overspeed Risk Management and Reliability Improvement Workshop, EPRI, Palo Alto CA: 2003. 1009333. Trip Monitor Customization and Implementation Guideline, EPRI, Palo Alto, CA: 2004. 1009112.

1-35


1.5.11 Instrument Surveys Supervisory instruments installed on the turbine and its piping monitor the condition of the steam as it flows through all parts of the overall cycle and the condition of the turbine stationary and rotating elements. Wide ranges of instruments are available; some are simple indicators, others are integrated with recorders, and still others are integral parts of the automatic turbine control system. This portion of the condition assessment is meant to evaluate and ensure that the unit operators have adequate, accurate instrumentation to make operating decisions during times when unexpected transient events occur. The location of typical turbine supervisory instrumentation found on the turbine is shown in Figure 1-5.

Figure 1-5 Location of Typical Turbine Supervisory Instrumentation

The instrumentation that should be audited is as follows (see Data Sheet #11): •

Shaft differential expansion and position data at minimum and full load

•

A histogram plot of temperature versus time in minutes should be made of various thermocouples specified by the OEM (first stage inner metal, valve bowl) in their start and load instructions in order to ensure that the temperature ramp rates are being correctly followed by operations. This ensures that the turbine is being started and loaded correctly, thus minimizing the risk of startup rubs, rotor-long or rotor-short problems, and reduction of rotor bore life during the critical startup period.

•

Lubricating oil system pressures should be noted at the turbine generator centerline and oil tank.

•

A plot of water induction thermocouple temperature differential is useful to assess whether water induction problems are possible during a startup to minimum load. Such data superimposed over turbine vibration and rotor or casing expansion should clearly identify if potential problems (rotor short, rotor long) could occur during hot, warm, or cold starts.

1-36


During an assessment of these instruments, data should be checked and recorded at full load. In addition, a plot of data from each of the instruments should be obtained from the unit historian during a typical unit startup and reviewed to ensure that they function as designed. Typically, such plots during a cold start are more informative because more problems are likely due to the larger thermal transients and operational problems that can occur. In reviewing start and load data, the engineer or technician should be looking for the following: •

Expansion data. Is casing and rotor expansion smooth, or is there sudden movement during startup and ramp to load? Such jumps in expansion can be due to excess friction between the pedestal and sole plate. It can also be used, when superimposed over water induction thermocouple temperature differential plots, to determine if water induction problems potentially exist.

•

Historian plots of first stage inner metal temperatures. Along with other OEM temperatures specified in their start and load instructions, these plots ensure that the OEM-specified ramp rates and hold times are being followed for the machine. Higher-than-expected ramp rates or shorter-than-expected hold times at specified speeds increase the rotor peripheral and bore life consumption, thus increasing the risk of future serious problems during unit operation. It also increases the risk of rotor short or rotor long problems, which can cause axial rubs in the various turbine sections.

•

Oil pressures: Compare oil pressures at the various locations to expected values. Significant differences in actual versus expected—coupled with gauges out of calibration—requires that corrective action be taken.

•

Thermocouple temperatures: Evaluate thermocouple temperature readings to be sure that they make sense and are at expected values. Significant discrepancies warrant a recommendation to calibrate or replace defective thermocouples because these are relied on by operators to warn of the need to take corrective actions when transient events occur.

A general review of the data gives the unit engineer/technician an immediate indication of the condition of the information that operators use to operate and maintain the health of the machine, especially during transient events where damage could occur to the unit. Obvious problems with this instrumentation require a recommendation to take corrective action on at least an intermediate basis. A partial list of EPRI published research on turbine-generator instrumentation is as follows (by year of publication): Guide for Monitoring Equipment Environments During Nuclear Plant Operation, EPRI, Palo Alto, CA: 1991. NP-7399. SysMon 2.0 User’s Guide: System Monitoring by Systems Engineers, 37 System Templates, EPRI, Palo Alto, CA: 2000. 1000260. Equipment Condition Assessment: Vol. 1 - Application of On-Line Monitoring Technology, EPRI, Palo Alto, CA: 2004. 1003695.

1-37


Equipment Condition Assessment: Vol. 2 - Technology Evaluation and Integration, EPRI, Palo Alto, CA: 2004. 1009601. Implementation Guidelines for On-Line Monitoring, EPRI, Palo Alto, CA: 2004. 1003361. Modeling Guidelines for On-Line Monitoring, EPRI, Palo Alto, CA: 2004. 1003579. 1.5.12 Generator Electrical Operating Data Most generator issues are mechanical or thermal in nature and, in turn, become electrical problems as the dielectric strength of the insulation degrades. The mechanical issues do not always lend themselves to early detection by electrical testing, but they may produce some visible effects that are discernable during service. This portion of the condition assessment is meant to evaluate the present condition of the generator, based primarily on electrical operating data and measurements that are taken during unit operation. The control room monitors the key parameters of: •

Stator current

•

Stator voltage

•

Output (MW)

•

Reactive power output (MVA)

•

Power factor (PF)

Safe operating levels for a specific generator are defined by design curves supplied by the OEM, where the MW, MVA, and PF are applied. An example showing the general format of these design curves and how their limits are established is shown in Figure 1-6.

1-38


Figure 1-6 Typical Generator Capability Curve

Generators are typically designed for some voltage variation. An OEM may specify a 5% overor under-voltage design rating. Abnormal voltage operation causes damage due to increased flux heating densities and core heating. Under-voltage operation requires increased excitation and may result in additional wear/damage to the excitation system. Data Sheet #12 further organizes the electrical inspections of generators into those associated with (1) the stator and (2) the field and exciters: DC, Alterex, and brushless. The stator core serves a mechanical and electrical purpose. Mechanically, it supports the windings. Electrically, it provides a return path for the lines of magnetic flux induced by the field. The generator field produces an electrical potential induced during normal operation. Shaft grounding brushes are usually installed near the coupling between the turbine and generator to provide a ground path for the potential difference. Temperature monitoring of the stator windings is normally done with resistance temperature detectors (RTDs) that are embedded within the stator slots. Thermocouples (TCs) measure inlet and exit water temperatures for generators with water-cooled windings. Allowable limits are set 1-39


as a maximum temperature for the exit water, as well as the differential temperatures between the inlet and exit. Gas-cooled windings generally have the same arrangement. In the audit portion of the assessment, temperatures should be recorded at full load. The number of RTDs and TCs out of service should also be noted and whether the failure rate is considered normal or unusual. Stator winding availability is most often compromised by looseness caused from vibration. Monitored vibration readings should therefore be noted and compared to trend changes against what values are expected from past service. Partial discharge data are an indicator of deterioration or degradation of the windings. A partial discharge occurs because there is still some insulation left, whereas a complete breakdown would lead to a ground. Individual units will have their own signature and unique condition, so actual partial discharge levels are trended over time to assess the condition of the winding insulation. A meggering (megger) test reports insulation resistance where any conducting paths within the insulating system being tested result in current flow and a reduction in the meter reading. A high reading does not necessarily indicate that the equipment can withstand the operating or rated potential since the megger uses a potential much lower than the rated potential. The megger should provide an index of the insulating material through a dielectric absorption test, that is, a measure of dryness of the winding. The ratio of the 1-minute and 10-minute readings is known as the polarization index (PI). The periodic resistance readings are trended to indicate impending insulation failures. PIs above 2.5 for the stator and 1.25 for the field are considered acceptable. Stator current should never be allowed to exceed the nameplate values. All phases should remain equally balanced. A condition of phase unbalance (a nonsymmetrical magnetic field) can cause negative sequence currents that may overheat one phase of the stator. The amount of damage to the field will be dependent on the magnitude of the negative sequence current imposed on the field. If additional heating occurs in the rotor surface, it can cause further damage to the wedges and retaining rings. These conditions can also occur during a ground fault incident. The generator field operates with direct current (dc) fed into the rotor windings from an excitation source, the exciter, through a brushless excitation or a carbon brush and collector ring system. Rotation of the shaft across the dc winding field creates the rotating flux field that induces both current and voltage at the stationary coils of the stator, which has been previously discussed. Generator internal clearances are not typically close enough to result in damage from excessive vibration (mechanical or thermal imbalance) during operation, except in the bearing and sealing areas. Generator bearings may experience the same problems as turbine bearings. One bearing, usually the collector end bearing will be insulated. This bearing should be checked with a 500volt megger. A minimum of 100,000-ohms resistance is required. Potential vibration problems due to thermal sensitivity are determined by monitoring rotor vibration with changes in load (or VAR output). On-line flux probes can identify the presence of shorted turns

1-40


The generator field collector rings should be checked for vibration to provide an overview of their condition. A good operating collector ring/ brush assembly will have vibration levels in the range of 2–3 mils (0.05–0.08 mm). Up to 6 mils (0.15 mm) is satisfactory. Readings of 10–20 mils (0.25–0.51 mm) may be experienced when there are problems. High collector ring vibration levels may mean mechanical problems with the rings. The amplitude of vibrations will normally increase as collector rings wear. Often, however, this is more a reflection of the condition of the rings. Damage manifests itself as peaks and valleys caused by the brushes. Grinding the collector rings will restore the rings to a round condition. A high collector ring wear rate would indicate both mechanical abrasion and electrical arcing as the brush contact begins to degrade. The brushes tend to chatter and chip as temperatures rise from loss of contact as the condition worsens. The hydrogen leakage test reports the amount of hydrogen consumed during operation that is absorbed into the seal oil or lost through leakage at the seals or other locations. Damage to the hydrogen seal will reduce sealing capacity and increase hydrogen consumption. Seal oil flow (absorption) is usually 5–15 gallons per minute (gpm) (18.9–56.8 liters per minute or lpm). If the absorption rate is less than 5 gpm (18.9 lpm), this indicates tight seals that may easily be damaged. A rate greater than 15 gpm (56.8 lpm) means that the seals are open, and when combined with air-side losses, the seal oil requirements may exceed the seal oil supply pump capacity. Acceptable gas loss (leakage) is generally <1000 cubic feet (28.31 cubic meters) per day. If seals are too open, oil leakage may occur into the generator stator and also result in liquid level alarms on the generator. In evaluating the present condition, the assessor should take note of the following issues or problems that may potentially affect generators: •

Vibration (related to the rotor winding system) is primarily a consequence of mechanical unbalance or uneven cooling and heating in the rotor winding and body. Thermal instabilities result from (a) blocked cooling passages, (b) localized temperature changes due to multiple shorted turns, or (c) other temperature instabilities that result in uneven growth of the copper windings. With regard to unbalance, multiple shorted turns are one of the most common sources of vibration in which the temperature decrease in the shorted turn slot causes less expansion and causes the rotor to bow.

•

Thermal aging is the principal cause of the degradation of rotor winding insulation. The deterioration is a combination of high temperature, long operating time, and mechanical stress.

•

If the shaft grounding system is not functioning properly, the potential difference between the rotor and stationary components will naturally seek an alternative path through the oil film of the bearings or the hydrogen seal. The result will be electrolysis at either location. It is important to monitor the grounding brushes during normal operation, ensuring that they are clean and in good contact with the rotor.

•

Loss of field excitation can produce severe heating in the rotor. Without excitation, the unit becomes an induction generator, where significant surface current is induced in the rotor body and wedges. The consequence may be arced or burned wedges. 1-41


In evaluating the risk and need for action, the assessor should be aware of the following circumstances where additional components of the unit may be affected by the condition of the generator: •

If the generator is supplied with excitation and system power, but the turbine loses the driving force from the steam, the generator can effectively operate as a synchronous motor and drive the turbine at rated speed. This is known as motoring. It is not necessarily harmful to the generator, but it may damage the turbine. No cooling of the turbine blades will occur with the steam flow blocked. If the blades rotating at rated speed have large tip diameters, they may heat up rapidly in the stagnant atmosphere.

•

Off-frequency operation may also have a more detrimental effect on the turbine than on the generator. The blades of various stages in the turbine may be tuned to operate within a reasonably narrow operating speed (or frequency). Off-speed operation of those stages may induce harmful stimuli to the blades, resulting in resonant fatigue failures.

•

Transients and faults may result in high rotor currents and resulting temperature increases, but physical or mechanical damage may result from sudden changes during operation. The mechanical shock induced by strong changes in the magnetic field may distort end turns, loosen or break end turn ties, shift end turn blocking, or damage insulation.

In additional to the generator repair specifications found in Section 8 of Volume 2, a partial listing of EPRI published research on generator operation and testing is as follows (by year of publication): Demonstration of an Alternative ASME Steam Turbine Generator Acceptance Test, EPRI, Palo Alto CA: 1985. CS-4410. Synchronous Machine Operation with Cutout Coils, EPRI, Palo Alto CA: 1987. EL-4983. Generator Unbalanced Load Capability, EPRI, Palo Alto CA: 1991. GS-7393. Main Generator On-Line Monitoring and Diagnostics, EPRI, Palo Alto CA: 1996. TR107137. Generator Stability Parameter Identification Data Acquisition System (PIDAS): Volumes 1 3, EPRI, Palo Alto, CA: 1996. TR-106902. Generator Core Overheating Risk Assessment, EPRI, Palo Alto CA: 1999. TO-113531. Guide to Rotating Electrical Machine Hipot Testing: Draft Report, EPRI, Palo Alto CA: 2000. 1000666. Voltage Unbalance: Power Quality Issues, Related Standards and Mitigation Techniques: Effect of Unbalanced Voltage on End Use Equipment Performance, EPRI, Palo Alto, CA: 2000. 1000092. Partial Discharge On-Line Testing of Turbine-Driven Generator Stator Windings: A guide for the Use of Partial Discharge in Assessing the Condition of Generator Stator Windings, EPRI, Palo Alto CA: 2000. 1001209. 1-42


Testing of Stator Windings for Thermal Aging, EPRI, Palo Alto CA: 2000. 1000376. Tools to Optimize Maintenance of Generator-Excitation System, Voltage Regulator and Field Ground Protection, EPRI, Palo Alto CA: 2002. 1004556. Generator Rotor Slot Dovetail Inspection and Risk Assessment, EPRI, Palo Alto CA: 2003. 1008222. Guide for On- and Off-Line Testing and Monitoring of Turbine Generators, EPRI, Palo Alto, CA: 2004. 1009406. Generator On-Line Monitoring and Condition Assessment, Partial Discharge and Electromagnetic Interference, EPRI, Palo Alto, CA: 2006. 1012216. Steam Turbine-Generator Torsional Vibration Interaction with the Electrical Network. EPRI, Palo Alto, CA: 2005. 1011679. Torsional Interaction Between Electrical Network Phenomena and Turbine-Generator Shafts. EPRI, Palo Alto, CA: 2006. 1013460. 1.5.13 Auxiliary Systems Data Auxiliary systems addressed in this part of the overall assessment are (1) the overall steam seal system, (2) the generator hydrogen seal oil system, and (3) the generator stator cooling water system. This portion of the condition assessment is meant to review the mechanical integrity of the two principal sealing systems found on the turbine and generator and to determine that the generator stator is being cooled effectively. Data Sheet #13 organizes the audit of the steam seals, hydrogen seal oil system, and stator cooling systems into three parts. Steam Seals: Leaks in the shaft steam sealing system may result in steam entering the lubricating oil system, thereby increasing its water content and resulting in the problems identified in Section 1.5.7. Steam leakage past the steam seals is typically due to either (a) improper adjustment of the steam seal pressure and/or vacuum at the regulator or (b) the steam seals have experienced a rub, thus increasing the shaft-to-seal clearances. The best way to initially determine if a problem exists with the steam seal system is to walk the turbine deck during a startup of the machine and observe if steam leakage by the packing cases or gland is occurring on a frequent basis. This can also be determined through interviews with operators who have also observed unit startups in this manner. To confirm the possibility of a steam seal leakage problem, inspect the lubricating oil at the oil tank to determine if water is in the oil. The oil will be yellow to orange in color if excessive water is present. In addition to contamination, a large steam seal leak can also result in unexpected heating of the pedestals. The resulting thermal expansion, in turn, may introduce changes to the alignment of 1-43


the turbine bearings. In the vibration signature, this may appear as symptoms of misalignment, but it is indirectly related back to the leakage and overheating that is occurring. If steam leakage is seen at the packing cases or glands, a recommendation should be made to take corrective action during the next outage or a weekend shutdown, depending on the degree of the steam leak. Corrective action while the unit is operating involves adjusting steam seal pressure at the steam seal regulator (steam feed or unloading valves) and adjusting the vacuum at the steam packing or gland exhauster. Reliance on the plant instruction book is recommended. Corrective action with the unit off gear is to take feeler checks between the shaft and the steam seals using a feeler gage to be sure that excess clearances are not present that result in steam leakage even if seal pressure and vacuum are properly set. If this is found, it may be necessary to replace the labyrinth seals during a unit outage. In the interim, frequent lubricating oil checks should be performed to ensure that less than 1,000-ppm water is maintained in the lubricating oil. This may require connecting a vacuum dehydration unit to the lubricating oil system to achieve the required water content in the lubricating oil. Hydrogen seal oil system: The purpose of the system is to maintain the hydrogen pressure inside the generator. The primary issue of concern to the assessor is contamination of the lubrication and the reliability issues this raises that are associated with the generator. Leakage can be due to: •

Problems in maintaining seal oil pressure differential

•

Excessively worn hydrogen seals or excessive inner oil seal problems

•

Hydrogen seal casing and outer end shield contact problems on vertical and horizontal joints

•

Failure of a float valve in the closed position or hydrogen seal oil cooler tube leaks (depending on whether water is seen in the seal oil)

Water may also be a result of excessive steam seal leakage or lubricating oil cooler leaks if the hydrogen seal oil coolers have no problems, or it may be from failure of the vacuum pump. From a long-term perspective, oil ingress into the generator is detrimental to stator coils because oil causes the coils and wedges to become loose and thus vibrate and wear at a faster rate than normal, causing a potential re-wedge/rewind or more than normal damage to the end winding system during overhauls. Maintenance of hydrogen purity is important in order to prevent a possible explosion and fire. If purity is less than 90%, a recommendation for immediate shutdown should be made to correct the problem. A review of instruction book recommendations regarding hydrogen purity problems should be thoroughly reviewed. Excess hydrogen leakage (twice the design leakage rate) should be checked and corrected during a weekend shutdown or during a unit outage. A vibration problem during startup/shutdown could be related to unbalance or generator thermal problems causing bowing of the rotor at high load and field current. The extent of this problem depends on the level of vibration at load and during roll-up/roll-down. This requires immediate corrective action since generator and turbine parts can be rubbed or damaged, causing future 1-44


problems. If problems are found, a review of the vibration data should be performed to determine if the generator has a thermal vibration problem or a mechanical unbalance problem as it passes through its critical speeds. The best method to determine the health of the hydrogen seal oil system is to question plant operators about the system and maintenance personnel about PM and PdM checks that are performed. Intermediate recommendations should be made if no such programs exist or if problems found during such inspections have not been corrected. Stator cooling water system: The purpose of the assessment is to ensure that the water system will maintain an adequate supply of cooling to the stator conductors. Condition is assessed based on an audit of water conductivity, pressures, and temperatures and stator bar temperatures. Criteria for each are noted on the audit portion of the data sheets. It should be noted these values may vary with the unit and should therefore be checked against the OEM specifications. The basic condition of the stator cooling water system can be determined by interviewing the operators and plant maintenance personnel who have responsibility for stator cooling system PM/PdM programs. Any instrument that does not function properly requires immediate actions to correct the problem because these protect the stator from failure of the stator coils. Intermediate action is generally necessary if a reasonable PM/PdM program is not being performed on the equipment. No short-term recommendations are necessary if the system appears to be in good condition, if operators have performed tests as recommended by the OEM, and if maintenance programs are adequate for the system. There may be long-term recommendations by the OEM that improve the stator cooling system’s reliability and performance. If such an OEM recommendation exists, it should be implemented during the next major overhaul if it is technically and economically reasonable. A partial listing of EPRI published research on auxiliary systems (steam seals, hydrogen oil seals, and the generator stator cooling system) is as follows (by year of publication): Primer on Maintaining the Integrity of Water-Cooled Generator Stator Windings, EPRI, Palo Alto, CA: 1995. TR-105504. Preventing Leakage in Water Cooled Stator Windings (Phase 2), EPRI, Palo Alto, CA: 1998. TR-111180. Prevention of Flow Restrictions in Water Cooled Generators, EPRI, Palo Alto CA: 2001. 1006684. Water Chemistry Tutorial for Generators, EPRI, Palo Alto, CA: 2003. 1007765. 1-45


1.5.14 Component Visual Inspections Although the condition assessments described in this section are meant to be performed based on data obtained while a unit is in service, there are opportunities to make certain visual checks at the turbine inlets and exhausts areas without a full teardown of the sections. It is always recommended that plants take advantage of these opportunities although it may be possible to verify and/or isolate a specific problem indicated by the sensors and tests discussed in previous sections. Results of the component inspections are documented in accordance with Data Sheet #14. During unit outages or valve inspections, a fiber-optic visual inspection of the HP first stage and IP first stage stationary and rotating elements should be performed to check their current condition. In addition, an inspection should be performed of the discharge side of the last stage blading in both the HP and IP sections. Perform a visual inspection of the LP turbine last stage buckets (LSB), and note their condition. On either fossil or nuclear units, access ports may be available at other LP locations also to make similar visual inspections. If access ports are not available, plants should consider a plan to install them as part of the work scope during upcoming major outages. Cracking on the blade airfoil, roots, disk steeples, lashing lugs, shrouds, or erosion shields requires immediate attention to preclude the possibility of an operating failure. Significant erosion to the inlet edge of the last stage LP turbine blade can indicate water level problems in the neck heaters or moisture removal drains. Such problems should be immediately corrected. LP moisture removal drains can be inspected only during a planned section overhaul. Foreign object damage to any blades should be noted because this may be due to loss of rotating components during unit operation. The accumulation of deposits should also be noted. On some blades with historical cracking problems, it may be necessary to perform a limited florescent penetrant or eddy current inspection to search for cracks in locations where they have been previously found. During an outage, perform a crawl-through inspection of the generator and evaluate the visual condition of the windings, retaining rings, through bolts, and blocking, and note the conditions. Inspect the collector rings and brushes for wear, grooving, and vibration, and note the conditions. Visual inspection should be done after a transient disturbance, such as a short circuit or out-ofphase synchronization. Early signs of a loose or vibrating end winding are dusting or greasing. Dusting consists of visible deposits of a fine power, found on the coils as they exit the core, near coil-to-coil tie wraps or on coils next to wedgings and blocking.

1-46


Greasing is the same powder mixed with oil that was able to enter the generator. Oil can become deposited throughout the windings either through a malfunction of the seal oil system or by gradual entrainment of oil in the hydrogen gas due to a low purity situation. Visual inspections may also reveal obvious signs of girth cracking that is present in the coil’s ground wall insulation as the coil exits the stator core. A partial listing of EPRI published research related to the in situ visual inspection of turbinegenerator components is as follows (organized by year of publication): Interim Guidelines for In-Situ Inspection and Monitoring Techniques for Steam Turbines: Volume 1: An Overview of Remote Visual Inspection, EPRI, Palo Alto CA: 1999. TR113996-V1. Interim Guidelines for In Situ Visual Inspection of Inlet and Outlet Turbine Stages: Parts 1 & 2, EPRI, Palo Alto CA: 1999. TR-114961. Demonstration of a Video Probe Delivery Device for In Situ Inspection of Steam Turbine and Combustion Turbine Machines, EPRI, Palo Alto CA: 2002. 1004002. 1.5.15 Out-of-Limit Conditions and Upsets Out-of-limit upsets or other operating mishaps may be isolated incidents of limited consequence or an early warning of a potentially significant problem that may impact future unit reliability and result in a premature unit major overhaul. This portion of the condition assessment is meant to provide a backup for the more extensive audits and interviews previously discussed for the major systems and components. Data Sheet #15 itemizes the most common problems that can manifest themselves on a unit. For each item, the assessor is to specify when the problem occurred, how many times, and what action was taken by operations or maintenance. The assessor is then requested to make an initial determination as to whether it is likely to have a significant impact on turbine-generator reliability, and if so, rank the potential as low, medium, or high. As further guidance, it should be noted that this part of the assessment is limited primarily to identifying the occurrence of events or problems that have been known to affect turbinegenerator systems. Further determination as to their source or root cause would be performed in the more comprehensive evaluations of individual systems and components. Therefore, the results of the out-of-limit condition assessment are most likely to provide the basis for issues that are color-coded as blue in the summary report (where the recommended action is to monitor the issue more closely until a more specific diagnosis is possible).

1-47


1.5.16 Review/Update Turbine Generator Maintenance Plans Data Sheet #16 complements the maintenance history summary on the turbine-generator components and systems prepared at the start of the assessment (Data Sheet #1). This portion of the condition assessment provides a supplemental record for each system or component, where a record is compiled of the date of last inspection, the date of next inspection, and comments as to the ability to run until the next inspection of each component and system, based on the results of the condition assessment performed. From this comprehensive record, the final overall condition assessment is summarized on Data Sheet #17. The process of using the information that has been gathered to make this overall assessment is discussed next.

1.6

Evaluating Situations and Making Recommendations

To complete a condition assessment report, the results from the previous data sheets are (1) assembled into a package of reference documentation, (2) consolidated onto a single summary sheet, and (3) individually evaluated in terms of the need for action based on the perceived risks involved. Item 3 uses a summary table (Data Sheet #17) that divides the turbine-generator into the major systems or components that were individually examined. The most critical finding associated with each is identified. To complete the report, the engineer or person responsible for the unit assessment must further indicate the severity or immediate need for action by means of a color code. As previously noted, this final step in the overall assessment procedure is specifically designed so that once the evaluation process is complete, there is only one of three possible outcomes recommended for the systems, sections, or components involved.

1.7

Condition Assessment Example

Table 1-7 presents an example of the summary documentation produced by a turbine-generator condition assessment, using the format provided in Data Sheet #17. In the example, 13 systems and components are identified. The first seven provide an update on the status for the major components that form the turbine-generator system, for example, the five turbine subsections, the generator, and the exciter. The remaining six reflect the current status of the support systems involving lubrication, seals, controls, and monitoring instrumentation. A color code is used in the example in Table 1-7 to denote the level of component degradation and degree of urgency required in corrective action. As indicated by their green color-coding, the three LP turbines are considered to be in good to excellent condition. In essence, this may be interpreted that no perceptible symptoms, indicators, evidence, or warnings were identified from the audit and interview that indicated that their condition had changed in any significant or noticeable manner since the last assessment. The 1-48


possibility of recommending the scheduled maintenance be extended would be based on how far into their interval the assessment had been made. If this assessment were completed only six months after the most recent maintenance performed on the section, it would be premature to make a recommendation to extend the current maintenance interval. Conversely, if the reported condition had remained stable over an extended period of several years, this would be worth noting since deferring the scheduled maintenance could save significant maintenance costs and possibly be adopted by management if the risks of deferred maintenance associated with these sections were assessed as low. Because such a recommendation would involve significant savings, the audit and interview attached to the summary would be relied upon as a basis for such a consequential decision. In the example, both the HP and IP turbines are reported as showing signs of degradation in their performance. The data sheets associated with performance (#4) would provide the documentation supporting this observation in terms of the measured values. The recommended action (color coded blue) is a consequence of the expert/specialist interview. From the interview, it was noted that the percentage of change in the performance and timing suggested that a problem was appearing, but that the rate of degradation was not sufficiently rapid to warrant immediate or intermediate attention. The blue color code indicates that the condition of a particular system or component is changing enough to take notice, but that the specific root cause or component has yet to be clearly identified. Referring back to Table 1-6, eleven potential causes are noted in which a decrease in HP performance is the consequence. In this example, the blue code indicates that insufficient information has been collected and examined to make a more precise determination. The reasonable and appropriate action is therefore to monitor it until a more definitive assessment is possible.

1-49

Turbine-Generator Condition Assessment – In Service Table 1-7 Example of Overall Unit Condition Assessment Plant and Unit Number: Any Plant #1 Unit OEM: GE

Date of Assessment: 9/1/04

Design Rating: (MW): 500

Date Last Inspected: 1/1/00

Unit Maximum Dependable Capacity: (MW): 490

Commercial Operation: 12/15/80

CONDITION ASSESSMENT SUMMARY Component or System

DEGRADATION Severe

Significant

Some

Good Condition

Comments

HP

X

Performance down 1% monitor.

IP

X

Performance down 1.5% monitor.

LPA

X

LPB

X

LPC

X

Generator

X

Exciter Lubricating Oil System

X

Particle count far exceeds specs X

Controls

Vacuum values trending toward higher end of acceptable criteria

X

EHC/MHC System

TSI Instrumentation

Exciter needs balancing. Insulation is very low on bearing.

X

Seal Oil System

Valves

End windings may be loose. Vibration data has not been consistent.

Overspeed trip too high. CV crack and intercept points need adjustment. X

Chloride count trending toward higher end of acceptable ppm.

X

Control valves and main stop valves are sticky. Last inspected three years ago. X

Recommendations: Both the lubricating oil and valves require Immediate attention. Refer to Data Sheets #5 and #7 for details. Based on their condition, the unit needs a weekend shutdown as soon as possible to correct these potentially serious problems. Work is also required on the exciter and turbine controls. Refer to sheets #12 and #13 for details. The urgency is not immediate, but this will require action before the currently scheduled intervals listed for these systems. Refer to sheet #16 for the current schedule of maintenance.

1-50


With regard to the generator, seal oil system, and EHC/MHC systems, the same situation applies. Some degradation was noted in the measurements. Similar to the HP and IP turbines, the color code reflects that early indicators had been noted but that it was not possible to conclusively identify the cause at this time. In the case of end winding vibration, it is noted at the time that the readings may be suspect because of noted inconsistencies and the inability to get repeatable results. The transition from a suspected to a more conclusive identification of the problem is noted on both the exciter and the turbine controls. Color-coded as yellow, the need for balancing and insulation replacement on the exciter is explicitly recommended. For the controls, the overspeed trip and the control valve intercept points need to be readjusted. Yellow indicates that these actions do not immediately threaten the reliability or health of the unit but that action should be taken at the next unit outage opportunity. Two components, the lubricating oil system and valves, are highlighted as condition red, meaning that, as a consequence of the assessment, there is a considerable risk to the unit based on the present condition of these systems. In the case of the lubricating oil, the particle count far exceeds recommended limits. At best, this could cause significant damage to the bearings. At worst, the breakdown of a bearing could damage the entire rotor system. The previous condition assessment on these two systems would also play a role in determining if this was a change in the severity level for a problem previously noted or if this was the first time the problem was reported. Presuming that the condition assessment on the lubrication system had been performed regularly, a change in color from yellow to red would indicate a steadily deteriorating situation. Based on the earlier report, provisions should have been made to flush, filter, and replace the oil. However, if the problem was not apparent before this report, this indicates that the change in particle count was sudden and the risk of an in-service breakdown was even more imminent. In the case of the control and main stop valves, the principal reason given for immediate correction is the fact that their last inspection was over three years ago, based on the record assembled in data sheet #1. Note that assigning urgency to the issue is in part a reflection of the degree of precision that the assessment can provide. Any problem that is assigned a code that requires intermediate or immediate action generally should have sufficient supporting data to make an informed opinion as to the root cause of the problem. If the assessor cannot make this determination, then a blue condition would be more appropriate until more information can be gathered. The exception to this rule would be a situation in which a sudden or abrupt change occurred and/or one or more of the indicators began to degrade rapidly. Any abrupt or abnormal conditions should have been identified on data sheet #15, where a range of symptoms are itemized in which alarms were tripped or normal operating parameters were exceeded. For example, a sudden step change in vibration that could be attributable to a loss of a cover or blade tip might warrant immediate action even though there had been no early warning of the problem or the present level of increased vibration appeared stabilized. The potential consequence of losing more covers or even blade sections outweighs the need to proceed with a deliberate plan of corrective action. 1-51


1.8

Summary Remarks

Two common reasons why a plant does not follow best maintenance practices are cited as (1) the maintenance is totally reactive, and (2) management has not defined the rules of conduct to achieve the best maintenance practices that are possible. The major emphasis for performing an in-service condition assessment is to adopt a proactive approach. In this approach, a systematic examination of key indicators is assembled and supplemented by interviews with specialists/experts. The team assigned responsibility for conducting the assessment understands that beginning this process demands that they produce one of three outcomes regarding recommendations for the systems, sections, or components that form the unit. The data collected within the assessment report format is specifically directed to support the formation of an informed decision. A summary of periodic recordings and measurements are maintained to signify trends or changes. Interviews provide the opportunity to solicit opinions from those who are most familiar with the particular system. A checklist of abrupt events provides a further catchall to note issues or problems that may or may not prove significant but should not be ignored since historically they have proven to be signs or symptoms of reliability problems for steam turbine-generator units. Critical to the success of the assessment is the formation of a team that is empowered both with the authority and budget to meet with the respective specialists and allow the report to be periodically updated. As noted, a baseline assessment should be conducted as soon as practical after a major overhaul to provide the optimum benchmark for subsequent comparison and evaluation. The next assessment should be considered at mid-cycle from the next scheduled major inspection. The frequency of the inspection interval after this should depend upon the findings of the first condition assessment. In completing the report, it should be emphasized to the team that the opinions and recommendations offered in the summary are expected to be subjective to some degree. Because this assessment relies on on-line data available at different points within the overall system, the recommendations are based on the perceived condition, rather than what an inspection during a shutdown may reveal to be the actual, absolute status of the unit health. The team should recognize this when it is formed so that an unreasonable demand for 100% certainty does not inhibit the assessments of risk and need for action that are required for each major system. If the team is not allowed certain latitude to speculate based on the evidence at hand, then the process will be compromised. So as not to exaggerate or overstate the perceived condition of any given system, a general rule of thumb is applied to rate the degradation as it proceeds from “some” to “severe.” Some degradation is identified by a change in one or more data points that is notable but not necessarily an early indication of an impending breakdown. As a condition progressively registers “significant” or “severe” in concert with this appraisal, there should be an attempt by the team to specify the suspected root causes and the corrective action that would be required, assuming the diagnosis is correct.

1-52


At this point, management can proceed to either follow the recommendation or invest additional resources in analysis or testing to verify the condition. This is considered to be the break point where in-service condition assessment transitions to life cycle management. If a problem identified in the assessment were particularly significant (such as a potential for a catastrophic failure or breakdown of a major component that would require a major outage to correct), a more involved decision process would be required. This process would evaluate strategies of whether to seek a repair, replace the system in kind, or seek a new/upgraded design. Results from the condition assessment would provide input to this process in terms of details on the history, frequency, and urgency of the system or component under scrutiny. Should the life cycle management team decide to replace or upgrade a system or component, the process would come full circle because this action would be noted in the first data sheets of the condition assessment on the replaced/upgraded system or component.

1-53

2

PRE-OUTAGE PLANNING AND BIDDING Traditional methods of turbine-generator outage planning have focused on the speed of repair, that is, planning outage scopes and managing vendors to speed up the open-repair-close cycle of the machine. With the continuing pressure to reduce outage duration, the temptation is to “reduce scope” and not repair the machine. The initial portion of this guideline, associated with preoutage planning in the context of general outage practices, deals with the engineer’s responsibility to play a greater role in defining reasonable expectations of technical support to meet different scopes of work envisioned by a plant. A basic element in such planning is how to reach outage duration or O&M budget goals by means of shorter outages. Pre-outage bidding, particularly from third-party suppliers, offers a sizable potential return in both reduced downtime and direct costs if reliable replacement parts can be negotiated and secured prior to when the teardown begins. This section of the guidelines is divided into steps that are organized in a sequence that begins when the tentative scope of maintenance is first proposed and ends when the unit is actually returned to service. The information contained within this volume of the guidelines is designed to assist a turbine engineer anticipate, identify, and recommend reasonable expectations of technical support that meet different scopes of work envisioned by a plant. After the scope of maintenance has been established, this volume provides an approach to prebid critical components using the repair/replacement criteria compiled in Volume 2. A way to identify, arrange, and monitor the involvement of outside sources of specialized support is also addressed as an activity within the pre-outage planning phase. This volume of the guidelines concludes with a review and discussion of the basic procedures and plans that should be in place before the next phase of the outage (disassembly) begins. Appendix B provides a complete turbine-generator outage report template. The basic principle behind this formatted template is to provide the user with a way to complete the report as an outage progresses. If updated on a daily basis, the outage report should be basically complete at the end of the job except for minor clerical details. Appendix C includes over 155 data reporting sheets to supplement the various component- or system-related activities addressed within the outage report. An index of the information organized within the turbine-generator outage report is shown in Table 2-1.

2-1

Pre-Outage Planning and Bidding Table 2-1 Index to Turbine Outage Report: Appendices B and C Section

Appendix B Table of Contents

I

Introduction

II

Name Plate Rating

III

Outage Personnel

IV

Summary of Recommendations

V. Work Summary

V

Work Summary

A. HP Turbine

VI

Data Sheets

B. IP Turbine

VII

Test Data

C. LP Turbine

VIII

Photos

D. Generator

IX

Appendix

E. Exciter

X

Contractor Reports

F. Valves G. Other

Section

2-2

Appendix C Table of Contents

Sheet Numbers

I

Turbine Axial/Radial Clearances, Alignment and Position

1 – 27

II

Turbine Bearings, Journals, Oil Seals, Rings, and Coupling Data

28 – 56

III

Cylinders, Shells, Rotors and Blade Ring Dimensional Data

57 – 71

IV

Controls and Front Standard Mechanisms

72 – 93

V

Oil Pumps

94 – 99

VI

Main Turbine Valves

100 – 126

VII

Generator Exciter

127 – 150

VIII

Protective Devices and Pre-Operational Checks

151 – 153

IX

Vibration and Balance

154 –155

Pre-Outage Planning and Bidding

2.1

Identifying and Establishing Engineering Responsibilities

A utility engineer’s involvement in any maintenance outage may range from preparation and cursory overview to outage management and technical direction. The utility’s philosophy and the engineer’s skill and experience levels will ultimately be a factor in the role the engineer will play before, during, and after the outage. To be an effective participant, a turbine-generator engineer must have or must gain a basic understanding of the turbine and generator mechanical, electrical, and thermodynamic processes involved with the operation and maintenance of the turbine and generator. An understanding of machine function, operation, and repair is demonstrated by the variety of potential activities to which the engineer may expect or be asked to contribute: •

Developing work packages - before and during overhauls to support inspections, repairs, and other activities

•

Assessing stocking levels and alternative approaches

•

Reviewing historical purchases

•

Assessing parts requirements for upcoming overhauls

•

Monitoring procurement process with key inspections

•

Integrating receipt of components/parts with outage and overhaul planning

•

Evaluating vendors and bids

•

Assessing current condition of components

•

Performing visual inspections and nondestructive evaluation

•

Comparing the current machine condition with historical records

•

Maintaining the number and types of failures

•

Maintaining historical records and evaluating data

•

Providing problem resolutions

•

Accessing and examining procedures

•

Preparing functional procedures including drawings

•

Creating and reviewing repair procedures

•

Monitoring repairs: costs, time, efficiency, and effectiveness

•

Interfacing with OEM and non-OEM personnel

•

Assisting in startup functions

•

Evaluating repair/overhaul frequency

A utility’s style of turbine and generator maintenance may place an increased emphasis on maintaining constant attention on current machine conditions and future needs. This requires concentrated preparation, effort during turbine outages, and focused outage follow-up. The responsible engineer, therefore, requires a well-rounded background to meet the demanding and changing maintenance environment. As an introduction to and reference source for the current state of knowledge associated with the turbine steam path and damage in steam turbines, engineers should start with the two-volume EPRI report Turbine Steam Path Damage: Theory 2-3


and Practice, TR-108943-V1 and V2 [1]. The volumes represent an integration of the work performed and reported by researchers, designers, and turbine operators spanning the twentieth century, with emphasis on the last 20 years. In particular, data offered in this compilation can provide the engineer with a basis of accepted industry standards on which to formulate and support specific recommendations. 2.1.1 Engineering Responsibilities in a Major Outage Work Scope The plant engineer should plan support for an outage work scope as three distinct phases of activities: •

Pre-outage

•

Outage

•

Post-outage

Each phase requires unique but interrelated activities. As an example, the pre-outage plan implemented during the outage should automatically require a post-outage review to re-evaluate it from both its technical and economic merit. It is recommended that technical merit be measured in terms of improved machine function or performance, and the economic merit can be measured in terms of schedule or economic impact. 2.1.1.1

Pre-Outage Activities

As shown in Figure 2-1, the pre-outage planning and preparation can begin in May of one year for an outage beginning in February of the next year. Engineering involvement crosses each one of the areas listed and may extend from an advisor or a consultant capacity in some areas to direction and responsibility in others. It is not unrealistic for a single major outage to involve more than 750 engineering work force hours in turbine and generator outage planning and preparation. Based on all the databases and plant information used to develop a plan for an outage, the maintenance plan is evolving from a time-based or reliability-centered approach to one based on financial risk. This method optimizes operations and maintenance expenditures over the entire plant or system. EPRI software (Turbo-X, 1001074) has been developed that provides a powerful planning tool for engineers to use in evaluating specific proposals for deferred maintenance options. The program provides maintenance interval planning that is based on financial risk assessment and component reliability data. Through an industry survey, general turbine-generator outage information was obtained by EPRI in early 2005. The survey asked various questions relating to five major areas concerning T-G outages: general unit information, outage scope, outage interval, outage length, and labor source. Responses were received from 13 utilities encompassing 103 units from approximately 40 plants. The units included both fossil and nuclear plants and ranged in unit size from 20–1350 MW. The goal of the survey was to provide outage planners with general T-G outage intervals and practices of other utilities and plants. A summary of the compiled results follows. 2-4


General unit information: •

•

63 of the 103 units are GE: –

43 are ≥ 40 years old.

–


28 of the 103 Units are SW: –


–


•

10 of the 103 units are Alstom, ABB, or Hitachi.

•

16 of the 103 units are nuclear.

•

47 of the 103 units are load following, subcritical, and tandem.

•

15 of the 103 units are base load, supercritical, and non-nuclear.

Outage scope information (out of 103 units): •

38 perform full-train outages for turbine, generator, and valves.

•

16 perform partial outages for turbine, full for generator, and partial for valves.

•

51 perform partial outages on valves.

•

18 try to shorten outages by having spare parts.

•

39 have spare journal or thrust bearing components.

•

57 have spare valve stem and disc assemblies.

•

88 have made changes to improve work execution during turbine/generator/valve outages including the use of racks, rollers, valve maintenance guides, and so on.

Outage interval information (out of 103 units): •

52 determine outage intervals based completely on calendar time.

•

12 determine outage intervals based completely on refueling.

•

29 determine outage intervals based on operating hours and starts.

•

58 have outage intervals of < 10 years for turbine sections.

•

81 have outage intervals of ≤ 6 years for valves.

•

78 conduct detailed outage planning at least 1 year in advance.

•

29 conduct detailed outage planning 2 years in advance.

2-5


Outage length information (out of 103 units): •

32 have ≤ 6 week outages for turbine sections.

•

92 have ≤ 10 week outages for turbine sections.

•

71 have ≤ 2 week outages for valves.

•

5 have strict outage work weeks of 20 hours/day, 6 days/week.

•

72 have outage work weeks of 20 hrs/day, 6 days/week but alter this to 24/7 outage coverage at the beginning and/or end of an outage.

•

29 have the turbine-generator outage as the critical path item for the outage.

•

55 have the boiler as the critical path for the outage half or all the time.

Labor source information (out of 103 units): •

59 have a combination of plant/utility/contractor/OEM for turbine/generator/valve craft labor.

•

20 have solely contractors for turbine/generator/valve craft labor.

•

23 have solely plant staff as turbine/generator/valve craft labor (all from the same utility).

•

55 have utility supervision of the turbine/generator/valve craft labor.

•

34 have plant project management of turbine/generator/valve component.

•

58 have utility project management of turbine/generator/valve component.

•

17 have contractor/OEM technical direction for turbine/generator/valve components.

•

52 have utility technical direction for turbine/generator/valve components.

•

53 contract for specialty labor including NDE, sandblasting, scaffolding, and induction heating.

•

67 have craft labor of classification including millwrights, mechanics, carpenters, scaffolders, machinists, and pipe fitters.

•

66 have crews within their utility dedicated to turbine/generator/valve work and repair.

2-6


Figure 2-1 Example of an Outage Plan

2-7


A recommended pre-outage work scope checklist of activities is presented in Table 2-2. Table 2-2 Checklist of Pre-Outage Activities Agenda

Action Item

Subsystem

1. Recommendations

Stationary components

Steam path and shells

Rotating components

Steam path and rotors

Sealing areas Valves Auxiliary equipment Controls Operation history 2. Planning

Budget Work packages Parts Services Laydown plan

3. Scheduling

Sequencing

4. Procurement

Specifications

Diaphragm, buckets, bearings, oil deflectors

Services

Vendor resources, blanket purchase orders

Manpower resources

Quantity, craft mix

5. Maintenance

Equipment resources Training 6. Performance assessment

Outage activities

Condition assessment, corrective actions, job management, vendor/contract administration

Post-outage activities

Performance

Pre-outage activities include a review of at least the most recent past outage reports, recommendations (including OEM-initiated recommendations), and operating conditions to determine the expected machine condition and repair requirements. Outage reports should contain machine condition, condition assessments, and recommendations from each area of outage activity including: •

Disassembly and reassembly

•

Opening and closing clearances including alignments

•

Stationary and rotating components

•

Valves

•

Auxiliary equipment

2-8


At a minimum, these reports should include an evaluation of what was found, what was done, and what is expected in the future. Condition assessment and outage action may be documented in a variety of electronic formats as well as hard copy. Electronic formats may most easily transcend the intervals between outages. Using commercially available applications (spreadsheets, databases, and word processors) may provide a measure of protection against software obsolescence and issues with future data exchange. Either hard copy or electronic format should be supplemented with photographs. Both methods of record keeping require a method to log, document, and summarize the results for ease of coordination, review, and monitoring. Outage recommendations and follow-up activities are easily managed in a database that would include, as a minimum, the following inputs: •

Event

•

Event date

•

Type of event (major outage, forced outage, pre-outage or post outage meeting)

•

Discussion or description of the condition

•

Recommendation

•

Response to the recommendation

•

Action required

•

Assignments

•

Required completion date

The information provided within the recommendation section of the database may easily supplement or complement a full-scale maintenance management system (MMS). Depending on the size of the utility and functional structure, a review of outage recommendations will result in task assignments to both the engineer and other resources. Those other resources may include maintenance, procurement, or planning. The plant engineer will be required to develop specifications for use with procurement of materials, repairs, and vendor support. The engineer will also be required to develop work packages to accomplish the “in-house” support activities. A work package may be either a simple process instruction or a detailed work plan. A process instruction sheet is an easy tool to use during an outage when communication to other internal resources, such as a machine shop, is required. A process instruction sheet can be used in either electronic or hard copy format. A detailed work package would normally be prepared before an outage. However, the work package format is still usable during an outage to provide repair instructions after disposition of a finding. Information that should be included in either is itemized in Table 2-3.

2-9

Pre-Outage Planning and Bidding Table 2-3 Recommended Process Instruction Sheet and Detailed Work Package Information Process Instruction Sheet

Detailed Work Package

Contact person to answer questions

Descriptive title

Shift and extension of contact person

Scope – Intended use

Time and date of submission

- Generic application

Component identification

- Specific application

Request return date and time

Support required

Work completed by contact person

- Craft resources

Description of what must be done including

- Parts or materials

- Material requirements

Processing instructions

- Dimensional tolerances

Tracking Information

- Description of action required

- Unit or equipment assignment

Sketch

- MMS identifier - Prepared by - Preparation date Activity instructions - Sketches - Sequence of activities - Material requirements or alternatives

Pre-outage activities also include a review of part requirements. Stand-alone or integrated commercially available software is a vital tool for this activity. Use of a database will allow searching, querying, and displaying part information for both pre-outage evaluation and part selection during an outage. Information may be reviewed “live” through the utility’s warehousing database or as a “snapshot.” A snapshot allows independent review and manipulation of data independent from live information. The parts database may include all information about parts that are available for use. The database can include parts not currently stocked but provide ordering information. Complementing a database of part information is a database of part use. The part information database provides all the information unique to a part. The part use database provides all the locations where a part is used. The database is updated to reflect changes in part application requirements or modifications for a specific location. Recommended information to maintain on a parts database and a database of part use is summarized in Table 2-4.

2-10

Pre-Outage Planning and Bidding Table 2-4 Recommended Information for Parts and Part Use Databases Parts Database

Part Use Database

Part identifier

Part identifier

- Stock number

- Stock number

- Part number

- Part number

Part description

Unit application

Alternate or superseded information

Location grouping or identifier(s)

Stocking level

- Descriptive

Quantity available

- Numeric

Date of last update

Part name

History of usage

Location description

Purpose of information

Location

- Stocking

Quantity used at location

- Ordering but not stocking

Visual representation of location of use

- Refurbishment

Link to part information database

Comments Action items Visual representation of part

The part use database may also provide a shopping list of parts by including an “available/nonavailable” field in a database table. Parts needed may be identified automatically, grouped and sorted, and printed out during either pre-outage activities or the outage. 2.1.1.2

Outage Activities

The outage work scope begins to take shape after the recommendation review and work package creation. Recommendation-driven services for outage activities can then be identified. Selection of in-house capability or vendor resources is determined. The outage budget is often outlined much further in advance than the preceding outage year. But after the work scope is developed, definition and refinement of the budget can take place. Procurement can begin to secure vendor support and lock in resources months before the outage. Often, the availability of the specialized turbine repair resources is limited, and reserving their services should be done as far ahead as possible (at least four to six months in advance). Two other derivatives of pre-outage planning should be schedule development and turbine deck work flow. The schedule development is impacted by the sequence of disassembly necessary to accomplish the known repairs within the outage duration. The turbine deck lay-down plan is reviewed and modified to support repair activities.

2-11


Maintenance work force resources are determined from scope of work, budget constraints, and the scheduled outage duration. Pre-outage training is a useful tool most effectively completed just before an outage. Training can be focused into a number of areas: •

Work scope presentation and review

•

Turbine and generator assembly/disassembly sequence

•

Turbine and generator maintenance procedures –

Terminology

–

Procedures

–

Readings and documentation

Figure 2-2 represents a typical spread of engineer-supported outage activities.

2-12


Figure 2-2 Sample of Engineering-Supported Activities

2-13


Plant engineering provides both pre-outage support and real-time outage support. The amount of pre-planning dictates the workload during the outage, allowing time to handle other outage issues. Non-emergency areas that may be covered during an outage are as follows: •

Component inspection

•

NDE finding disposition

•

Component condition assessment

•

Corrective action evaluation

•

Repair evaluations

•

Timekeeping and schedule reporting for vendor activities

•

Job management

•

Problem resolution (both technical and personnel)

•

Repair direction

•

Vendor surveillance

•

Vendor/contact administration

•

Startup

2.1.1.3

Post-Outage Activities

Post-outage activities are a reflection of the pre-outage preparation. The purpose of post-outage activities is to review outage documentation and disseminate the information for appropriate future action. A list of post-outage documentation and action requirements or purposes is shown in Table 2-5.

2-14

Pre-Outage Planning and Bidding Table 2-5 Post-Outage Activities Documentation

Action/Purpose

Outage dates

Log actual outage date

Photos

Sort and file for documentation

Files

Disseminate and update miscellaneous data Review work package information and update file version

Diaphragm QA

Review outage report and log repair recommendations

Bearings

Log repairs, create repair reports and update bearing repair specification (as required)

Buckets

Review repair times and update repair history Create repair reports, log measurements and update File

L-0 and L-1 pins

Update replacement location and size history

Diaphragms

Review repair times and update repair history, area checks, etc. Create repair reports and modify diaphragm repair specification as required

Boresonics

Review reports and update inspection history

Studs

Update stretching/replacement history

Main steam lead flange

Check thickness

Piping inspection report


IP rotor run outs


Startup document

Review and update

Turbine deck layout

Update layout plan

Repair of removed parts

Spares: diaphragms, double flows, nozzle box, valve components

Miscellaneous

Outage assessments, recommendations, and parts (needs, changes, description, updates, stocking levels, etc.)

Post-Outage Meeting

Post-outage meetings should be conducted within a reasonable time (four-to-six weeks) following the outage. The post-outage meeting distance in time from the outage is a balance between documentation review and outage personnel availability. Documentation prepared for the post-outage meeting should include: •

Recommendations entered into review format (for example, databases)

•

Work force expenditures

•

Parts

•

Budget

•

Lessons learned 2-15


Attendees at the post-outage meeting should include: •

Turbine and generator outage supervisors

•

Turbine and generator foremen

•

Utility turbine and generator engineers

•

Turbine-generator planner

•

Outage vendors (as applicable)

2.1.2 Methods to Estimate Engineering Resources and Work Force Required In order to identify the engineering resources required to support a turbine-generator outage, the direction or philosophy of what is to be accomplished must be identified. The following are examples of turbine maintenance philosophy statements: •

Turbine and generator overhaul maintenance is performed 24 hours a day, 7 days a week. This means each maintenance shift is staffed and responsible for doing an even split of the overhaul work scope. Therefore, each shift requires all elements of support. Engineering support is provided by whatever means necessary to the turbine maintenance overhaul crews to meet their direction.

•

Equipment is maintained in a manner that will restore the equipment to at least the quality standard to which it was originally designed and, where appropriate, based on experience, it will be rebuilt to a higher quality standard. Under no circumstances is the quality standard to be reduced. Therefore, engineering support is provided as appropriate to the turbine overhaul to meet equipment needs.

Turbine-generator outage activities can be grouped into the following major areas: 1. Preparation 2. Shutdown 3. Turbine disassembly and clearance documentation 4. Component inspection 5. Component repair 6. Turbine reassembly, alignment, and clearance documentation 7. Startup 8. Review

2-16


The scope of activities within each grouping is defined by what must be accomplished and should be consistent with, but independent of, the application of resources. The distribution of responsibilities within each grouping is adjusted to meet the utility’s resources and turbinegenerator maintenance philosophy. For example, turbine disassembly requires: •

Knowledge of how the turbine-generator is put together

•

Knowledge of the best direction for disassembly to meet the repair plan

•

Knowledge of what readings are necessary to evaluate the machine condition

•

Knowledge of what readings are necessary to reassemble the turbine

The utility’s engineer, the OEM engineer, the vendor engineer, or utility maintenance resources can perform these functions. 2.1.3 Tasks Deferred to Reduce the Scope and the Potential Implications Absorption, consolidation, and redistribution of activities are methods used to reduce turbine engineering support scope. There are additional resources, such as OEM engineers, utility maintenance and planning, and vendors, in addition to turbine engineering that can be included to accomplish the activities and tasks of pre-outage planning. Each resource may be able to—in part or in combination with others—provide the necessary technical and cohesive interaction for a successful outage. But it should be noted that nothing comes without a cost. The level of focused continuity maintained where additional resources are planned to be used will be consistent with the involvement allowed to turbine engineering as overseer and coordinator of this support. Standardization of practices, record keeping, electronic interface, and electronic data storage are methods of reducing activity involvement without losing continuity. Data recording and retrieval become essential when interaction is reduced. One way to reduce activity support requirements is to reduce data and information handling, retrieving, and processing time. The advantages of maintaining the knowledge or historical database directly complement the ability to plan an outage and quickly retrieve and apply information during an outage. Engineering support scope is reduced through shared and distributed information resources, which can be retrieved and used by others. Personnel that are not reasonably familiar with the database are slowed during outages and lose their effectiveness. 2.1.4 Tools Available and Input Needed to Define Tasks for a Scope of Work One of the best tools available to a utility is its own activity history. Utilization of relevant history incorporates the utility nuances into the resource identification and estimation process. This information is typically available through an MMS or other record keeping method. Non-MMS tools available are spreadsheets and databases. These can be maintained as individual records or group or department entries. The important message is to begin. Too many times, 2-17


critical knowledge is maintained by an individual’s memories, notes, or recollections. When these individuals leave, retire, or are promoted, their wealth of recollection is lost. Essential information to log for future reference is: •

System

•

Scope

•

Duration

•

Description of activities performed

Standard industry practices are a starting place if no information is available within the utility. Information may be obtained through other sources such as EPRI, utility contacts, or vendor contacts to form a basis against which in-house details are compared.

2.2

Pre-Bidding and Procuring Parts or Services (When Scope Is Defined)

Preparation to purchase either services or parts requires the same two fundamental items: •

Defining what is needed

•

Identifying when it is needed

Included with each of these items are the details of what it looks like, how many are required, how it is obtained, and what method of payment will be used. These details develop, shape, and become the specific elements of the purchase as the type of purchase is defined. Specific guidance is provided in Volume 4 for the procurement of turbine-generator components such as blade rows, HP/IP/LP turbines, and generator rotors for both fossil and nuclear units as well as a generator rotor rewind specification. The guidelines address very specific issues associated with the purchase of these expensive components. They also provide advice regarding critical issues such as warranty, liquidated damages, information needs, and other issues that may be important to a specific plant. Part purchasing requires identifying two essential items that will help ensure that the right part is ordered, received, and purchased. The two items are: •

The part geometry

•

The materials

The pitfalls of purchasing parts may seem obvious, but far too often they put a snag in the best of outage plans. For example, a part is ordered that is identified with a geometry description of 1" (2.54 cm) pipe and made from stainless steel (SS) material. The item could be received matching the outside dimensional requirements of 1" (2.54 cm) pipe (manufactured to National Pipe Standards [NPS]), but the wall thickness could be anything. The material could be any of the austenitic, ferritic, or martensitic stainless steels but would probably be the cheapest of the three. The received replacement part probably would not meet the desired functional requirements, and the inappropriateness would most likely be discovered during the repair process. Either the 2-18


serviceability of the replacement part has to be evaluated, or the part must be returned and replaced within the outage duration. Unlike part purchasing which deals only with parts, services purchasing is defined as containing the services of people and may include activities such as consulting, technical direction, or onsite repairs. They may also include parts, but the primary thrust is services provided. A list of information recommended for parts and services purchasing documents is presented in Table 2-6. Table 2-6 Recommended Parts Purchase Document Information Parts Purchasing Document

Services Purchasing Document

Nontechnical description of the item

Nontechnical description of the scope of service

Technical description of the item, as appropriate

Schedule

Part use and location information

Definitions, as appropriate

Quantity of items required

Material requirements

If a first time purchase, describe the material/geometry

Service requirements

If a repetitive purchase, specify the appropriate part number

Inspections

Special handling: packaging, in-transit protection

Quality assurance

Delivery instructions: carrier (as appropriate), transportation, location, time of day

Reporting requirements Mobilization and demobilization requirements Living expenses scope Schedule Form of proposal

2.2.1 Stationary Repairs - Diaphragms, Packing Rings, and Sealing Strips Damage occurs to the diaphragm steam path and body (structure) in service that must be repaired during outages. The degree and location of damage varies depending on steam conditions and position within the steam path. The following is typical of the type of damage that might be evaluated and repaired during an outage: •

Foreign object damage (FOD)

•

Solid particle erosion

•

Water/steam erosion

•

Chemical attack

•

Packing and spill strip hook fit damage 2-19


•

Integral spill strip damage

•

Thermal/pressure distortion – dishing/out of round

•

Fretting on loaded surfaces

•

Cracking

•

Failed welds

Two basic items are required to pre-bid steam path stationary (diaphragm) repairs to both the steam path and structure: •

Repair procedures with either the work scope definition or the anticipated work scope

•

A standard by which to evaluate the bids

Examples of repair procedures are found in Volume 2. In general, it is recommended that any repair procedure include the items listed in Table 2-7. Table 2-7 Recommended Diaphragm Repair Purchase Document Information Item

Subsection

Work scope Process definitions

Major repairs, layout procedures, measurements, sidewall repairs, partition repairs, horizontal joint repairs, minor repairs, process deviations

Quality assurance Nondestructive tests Tolerances

Partition shape, area, dimensional

Partition dimensional data sheets

Area checks, diaphragm checks

Diaphragm inspection requirements

A diaphragm repair procedure contains certain essential variables. If the repair involves using a filler material of 410 stainless steel, a stress relief procedure is required after repair; a diaphragm repair using an Inconel filler material does not require this. Partition shape information should be either reverse engineered during the repair or provided within the repair procedure. Partition shape tolerances and dimension data sheets are important to achieve a consistent and quality-centered repair. Typically, they may be developed after the first repair, using the information obtained during the reverse engineering process of the repair. Figure 2-3 shows an example of the dimensional requirements that would be provided within a diaphragm partition repair procedure of the type discussed.

2-20


Figure 2-3 Dimensional Requirements That May Be Provided Within a Repair Procedure

Diaphragm repairs done on-site require identification of resources that the utility is expected to provide versus those the vendor is to supply. This is an important element of diaphragm repairs, and its delineation should be contained within either the repair procedure or the purchasing document.

2-21


The following are some of the items of consideration when planning for an on-site repair: •

Work location partitions - welding and debris protection

•

Diaphragm repair stands

•

Argon and supply

•

Pressurized air and supply

•

Fittings for argon and air supply

•

Welding machines

•

Power and hookups (connectors/plug ends/pigtail connectors)

•

Lighting

•

Lifting and rigging equipment

•

Layout equipment - tables, rulers, gigs, copper partition backing plates/forms, centerpunches, and other necessary tools

•

Consumables

The work scope of a pre-outage bid may be based on either the cost to perform a specific type of repair or the cost to perform a given quantity of repairs of a specific type. The vendors are to evaluate their estimated costs accordingly. The best source of information to develop the scope of repair is the previous outage report and subsequent recommendations that were noted at the time. The previous outage report should be detailed enough to provide a way to ”best guess” the upcoming diaphragm repair requirements. This will assist in defining the total resources required to complete the repairs in a predefined duration. Typical history of similar pressure, service, and other types of equipment and plant maintenance history may be reviewed to provide guidance if previous outage recommendations are not available. Bidding alternatives and the potential costs savings of competitive offers can be taken advantage of if the expected scope of repairs is known. The repair procedure can be constructed to obtain a fixed price for the scope of repairs, or a cost-plus bid can be used after determining the number of workers likely to be applied to diaphragm repairs. The following charts are offered to assist in determining either the level of resources that are likely to be required or the reasonableness of a contractor’s estimates for repairs. The charts provide estimates based on two different types of repairs: •

Major repair - defined as a comprehensive repair to all of the partitions in a diaphragm half. This work includes: cutting back the partition approximately 5/8" (15.875 mm) from the trailing edge or to a partition-section thickness of 1/8" (3.175 mm), rebuilding each partition, reading and recording area check data for every opening, and repairing sidewalls, horizontal joints, spill strip grooves, etc., as required.

2-22


•

Minor repair – defined as a repair limited in scope. Minor repairs may include any or all elements of major repairs but usually do not involve all of the partitions in a diaphragm half. Dimensions and tolerances for partition shape and opening area may or may not be the same as for major repairs.

Figure 2-4 provides a way to estimate major repair times based on hours per inch of partition radial height. As suggested by the chart, the shorter the partition, the greater the impact of sidewall repair on the repair time per inch.

Figure 2-4 Major Repair Times per Inch of Partition Radial Height

2-23


Figure 2-5 provides an estimate of total major repair time per partition based on the length of the partition. In this instance, the greater the radial height, the longer the total estimated time to complete the partition repair.

Figure 2-5 Estimate of Total Major Repair Time per Partition

2-24


Figure 2-6 provides a way to estimate minor repairs. In this case, the shorter the partitions, the longer the minor repair time per partition. Shorter partitions are generally located in the upstream portions of the steam path where increased foreign object or solid particle erosion damage is more likely to occur. Therefore, although shorter, there is typically more work per partition than is required to repair longer partitions found further downstream.

Figure 2-6 Estimation Tool for Minor Partition Repairs

The times represented in the preceding figures reflect “productive” repair time. Use the figures to estimate the repair duration or work scope support requirements, or to evaluate repair performance. The diaphragm outage scope also includes nonproductive time. Examples of nonproductive time would include: •

Set up time – both diaphragm and equipment setup and relocation

•

Standby time – awaiting inspections, decisions, access, or other activities

•

General support – rigging, diaphragm movement, diaphragm readings including dishing, roundness checks, or other work

2-25


Figure 2-7 inputs were obtained from recording on-site productive and nonproductive time. Six separate repair events were recorded. Greater repair time detail was obtained in the left three events. Dividing the total diaphragm repair time into the nonproductive time yielded the data points as shown in the figure:

Figure 2-7 Total Diaphragm Repair Time Divided by the Nonproductive Time

As shown in the figures, data point scatter does exist and some amount of nonproductive time will occur. If the diaphragm repairs are not being performed on a fixed price contract, it is important to note the potential cost savings that might be achieved by appropriate job management. The total hours expended to complete diaphragm repairs also include job management and administrative time. Each scope of repair will dictate the type and strength of overhead support required. Supervision is a critical element of diaphragm repairs, but sufficient record keeping is too. The total hours expended to complete diaphragm repairs will be the summation of productive time + nonproductive time + job management and administrative time. The diaphragm repair cost is not only a function of hours, but it also may include equipment rentals, transportation, mobilization/demobilization, consumables, and other items. Consumables are generally defined as those items that are required to complete the repairs and that are used up in the process. This should include such items as: •

Argon

•

Filler material

2-26


•

Sanding disks

•

Burrs

•

Files

The nature of diaphragm repairs requires the consumption of tools only to their level of maximum effectiveness. Using a grinding disc beyond its sharp and useful life causes overheating of the material and produces a low quality repair. Figure 2-8 represents a relationship between consumable cost per productive labor hour (left axis) and a percentage of consumable cost per productive labor hour cost (right axis). The average cost for consumables is approximately $10/productive labor hour or an average of 18.6% of productive labor dollars. The relationship between the two methods of evaluation is consistent and useful. Either direct consumable use can be tracked during a repair and charged appropriately, or consumables can be charged as a cost per productive labor hour or as a percentage of productive labor costs. The important element is tracking productive labor.

Figure 2-8 Plot to Track Consumable Costs vs. Productive Labor Costs

Tracking the repair time or cost can be tedious, but a simple database (or spreadsheet) supported with field time inputs is sufficient to record and provide the information for later analysis and evaluation. Field inputs can be processed with simple time cards that identify the repair time expended on a selected diaphragm. If consumables are being tracked, the consumables that were used during that period should be logged. Outage diaphragm repair cost can range from less than a quarter of a million to a million dollars. Therefore, effective job preparation and management applied to this activity can have significant economic benefits and consequences. 2-27


Two measures of an effective repair are the cost to do the repair and the measured restored turbine section efficiency (gains or losses) from the repair. Accurate details of time spent (reflected as dollars, or as hours) and job element cost can provide an economic assessment of the completed repairs. Tracking of turbine section efficiency before and after the outage is a measure that indicates the performance restored by the repairs. Regained section efficiency and subsequent energy production costs also assess whether the cost to do the repair was recovered. For example, Figure 2-9 shows the change in high-pressure (HP) section efficiency after four separate outage periods. The data was obtained from station instrumentation with a large scatter in the beginning of the third operating period due to station data calibration problems. Lines have been drawn through each operation cycle as a visualization aide. The efficiency change is obvious across the section. Note that all of the efficiency change is attributed to just the diaphragm repairs. An estimated economic benefit of the section maintenance is the result of calculating the change in efficiency over time and applying this to a unit-specific operating value.

Figure 2-9 Change in HP Section Efficiency After Four Separate Outage Periods

Partition repairs of diaphragms are only one element of the total diaphragm repair. Additional areas of repair include body repairs to the horizontal joint, packing and spill strip “hook” areas, and integral spill strips. Repair procedures for various portions of the diaphragm and nozzle are collected in Volume 2. 2.2.2 Blade/Bucket Replacement or Repairs Pre-outage planning for blade/bucket activities can be broken down into two major categories: parts and services. The blade/bucket repair work scope is often labor intensive and may only require minimal replacement parts and, therefore, a service purchasing action. However, the repair work scope may also require a significant investment for replacement or repair of blades/buckets. Under such circumstances, the blade/bucket installation purchase contract may be negotiated separately from the blade/bucket purchase contract.

2-28


The purchasing documents for services to install or repair in-place blade/buckets should contain and address each of the requirements previously listed in Section 2.2. Guidelines and examples of specifications developed exclusively for the procurement and installation of buckets are contained within Volume 4. Included within a technical specification for the replacements of blades/buckets and/or shrouds/covers should be checklists that itemize installation requirements, quality control issues, assembly tolerances, machining tolerances, etc. Often bucket installation requirements are overlooked, and installation procedures are lean. The skill and knowledge of the bucket installation craftsman are often relied on as the only assurance of a quality installation. In many cases, non-OEM bucket craftsmen were OEM trained and used this skill level to provide a source of qualified expertise for blade/bucket installation and repairs. But, as these craftsmen age, it is foreseen that utilities will ultimately be required to develop installation and repair procedures to ensure a quality installation. The blade/bucket repair and installation procedure may not only include tolerances for machining of blade/bucket cover, platforms, and other items, but it should also contain additional items, such as those listed in Table 2-8, along with locations that may require unique attention within the repair and installation procedure and technical details needed to describe their manufacture. Table 2-8 Recommended Information for Bucket Replacement or Repair Information Sought

Special Attention Items

Technical Details

Blade/bucket removal

First stage

Auxiliary buckets/blades

Blade/bucket lean (off radial condition)

Coated vane sections

Dimensional data

Attachments between blade/bucket – at root/platform, at covers

Tuned L-0, L-1 and often L-2 rows

Moment weights for “tuned” buckets/blades

Blade/bucket fit to rotor – assembly clearances, wheel rolling

Tangential, axial, radial entry roots. Finger dovetail, straddle dovetail roots. “T” root type

Root form, inspection requirements, tolerances and surface finish

Tie-wire installation – assembly locations, brazing

Hardware – tie wire, covers, pins

Row assembly and closure for tangential entry buckets – fitting/”drive up”/pinning and staking.

Closure procedure for bucket/blade

Cover tenon peening

Blade/bucket repair and installation procedures may be either broken down into separate procedures or grouped by steam path location and attachment style, and in some cases, according to blade/bucket material.

2-29


Part requirements may be broken into two activities, purchasing new or refurbished parts, or repairing existing parts. Outage duration, economic posture, and other factors may dictate the direction of repair during an outage or replacement with purchased buckets. The parts specification has two fundamental elements; the first describes the geometry of the blade/bucket and the second describes the material. Nearly everything else falls under these two categories. The material section defines what the blade/bucket and hardware are to be manufactured from and should include the following items: •

Chemical composition

•

Heat treatment

•

Mechanical properties

•

Testing requirements

Each section should contain appropriate standard references for processing and materials as appropriate. A final report containing all the material information, dimensional results, inspection results, and other information should be supplied with the blades/buckets. A minimum amount of information is required to begin the replacement process if detailed blade/bucket information is not available before an outage and if the outage work scope includes manufacture and replacement of the blade/bucket during the outage. The following information will assist in the bidding and planning process: •

Number of blades/buckets

•

Type of blade/bucket attachment

•

Overall blade/bucket dimensions

•

Vane form/type

•

Cover type and grouping

•

Tie wire – type/size/arrangement

Information may be obtained from past outage reports, rotor work, and other sources. Photographs of the row to be replaced taken during outages may also provide sufficient information for bidding and planning. Blade/bucket repairs require the same type of information as manufacturing replacements but not to the same level of detail. Whether the blade/bucket will be repaired in place or removed from the rotor and then repaired also dictates the amount of information and planning required. As a final note, the degree of technical information used to qualify a replacement bucket is dependent on the history of the design in service. If a new or modified design is being purchased to replace a design that has experienced a problem, it is advisable to seek information that can be used to establish the soundness of the new design. Volumes 6 and 7 provide explicit information for many of the most commonly replaced blades, that is, those that are most likely to experience damage during a period of extended service. This information in Volumes 6 and 7 on stresses and operating frequencies provides a way to contrast and calibrate an “improved” design. 2-30


To take advantage of this database, the plant should include a requirement within the procurement specification that makes purchase contingent upon the completion of an independent examination of the new design. In support of this requirement, provisions should be made within the purchase document to obtain either a sample of the design (for reverse engineering) or the cooperation of the supplier to supply details under an agreement of confidentiality. Examples of such requirements are included in Volume 4. 2.2.3 Bearing and Shaft Seal Repairs During service, physical damage to rotors may be caused through rotating elements coming in contact with stationary objects. This typically occurs in bearing or sealing areas, and is caused by contaminants either embedded in or building up on the stationary component. Physical exterior rotor damage can also be caused by thermal-induced eccentricity or rotor imbalance. This causes the rotor to contact stationary sealing areas typically near areas of the rotor maximum displacement and reduced clearance. These conditions may occur during startup or operation as a consequence of load changes. As an example, material buildup on an oil deflector can occur in service and slowly “machine” the rotor as more buildup occurs. Particles may accumulate within the bearing babbitt and slowly score the rotor bearing journal surface, especially when on turning gear or transitioning from turning gear operation to hydrodynamic operation. Some damage to these surfaces is tolerable and can be remedied during an outage by “strap lapping” the damaged surface. Other exterior related damage can occur from chemical attack and may be seen as pitting or cracking, depending on the rotor and its location, and may result in stress corrosion cracking (SCC). Outage reports, previous damage identification, and recommendations become useful tools in planning for remedial action for the rotors during the outage. Three methods of repair are generally available: machining the rotor in place, machining the rotor on-site, or machining the rotor off-site. Rotor size, proximity to repair facilities, cost, total rotor repair scope, repair requirements, and outage duration will all factor into the method of repair selected. The rotor geometry necessary to construct a repair procedure is listed in Table 2-9. Table 2-9 Geometry and Tolerances Required to Support a Repair Procedure Journal

Rotor

Other

Journal sizes

Rotor length

Diameter to be machined if not journal

Journal length

Rotor weight

Machining length

Journal location on rotor

Maximum steam path diameter Coupling diameter and geometry Proximity to “obstruction”

Note: In-place machining will not require all listed items. TOLERANCES

Diameter

Taper

Out of Round

Surface Finish

2-31


The rotor geometry will dictate support and setup requirements for the rotor-turning device (RTD or lathe) for both on-site and off-site repairs. Journal sizes (or appropriate rotor support location during machining) will be used in determining RTD bearings or vee-pads and shimming requirements for rotor leveling. Coupling information is required for drive plate setup. Overall rotor length and maximum diameter are used to determine RTD bed length and “swing.” Rotor weight may be required to determine the loading at the support points on the rotor. Figure 2-10 shows examples of information on rotor weight and coupling geometry that is generally required.

Figure 2-10 Examples of Rotor Weight and Coupling Geometry Measurements

2-32


Required machining dimensions may be included within the repair procedure, especially for seal areas. However, in rotor journal repairs, the journal finish dimension is often determined by the minimum cleanup to restore the journal to serviceable condition. Bearings are then made to fit the rotor journal. The repair procedure should include the tolerances shown in Table 2-9. For off-site repairs, the repair procedure should include rotor handling and protection requirements. For on-site repairs, the repair procedure should either identify the services available—electrical, air, and water—or require the repair vendor to identify the service requirements for both the RTD and machining equipment. 2.2.4 Generator Repairs Pre-outage procurement planning for the generator (a rotating excitation system may also share some of the same planning and repair activities) begins with defining the type of the generator and its components. Generators are coded and subsequently classified by their manufacturers. Coding typically identifies how they are cooled and the type of construction, both for the stator and rotor. As an example, generator rotor cooling may be by either air or hydrogen. Stators may be gas-cooled or liquid-cooled. Each form of cooling will have distinctive related components and maintenance requirements. Types of construction coding also apply to both the rotor and stator; characteristically, the number of poles is described in the generator coding. Components of a generator can be broken into three major areas identified in Table 2-10. Table 2-10 Classification of Generator Components Stator

Rotor (Field)

Auxiliaries

Bearings

Body

Electrical conduction system

Core and windings

Collector

Excitation system

Electrical and hydraulic connections

Conductor (Coils)

Rotor cooling system

Fans

Connections

Sealing

Frame and end bells

Retaining rings

Stator cooling system

Seals

Wedges

Retaining rings may be mounted in a variety of ways but are mounted either to the body of the rotor or to the “spindle” portion of the rotor. Figure 2-11 shows a silver-plated ring/shell that bridges the joint between the retaining ring and rotor body. It has fingers that extend into the coil slots that contact the slot wedges and the retaining ring, providing a current-carrying capability to protect the field under fault conditions.

2-33


Figure 2-11 Examples of Shells Used to Bridge Between the Retaining Ring and Rotor

Each of these areas may have distinct and unique requirements to support the disassembly, inspection, repair, reassembly, and testing activities during an outage. The types of tests typically performed on a generator and when they are required are summarized in Table 2-11. Table 2-11 Generator Tests and When They May Be Performed Types of Tests

When Testing Is Performed

Winding resistance

Prior to the outage while the unit is on line, for example, hydrogen leak test

Insulation resistance

During assembly, for example, NDE

Dielectric strength

During reassembly

Shorted turns

After reassembly when the unit is off line, for example, insulation or air leak test

Hydraulic integrity

After reassembly when the unit is off line, for example, hydrogen leak test

Sealing capability Mechanical capability

Testing is an integral part of the generator outage. Therefore, coordination to be obtained from the plant must be identified in the procurement plan and integrated into the plant schedule. Knowing the parts breakdown for the components that are to be disassembled and reassembled provides a way to identify replacement components. These components can be integrated into the pre-outage purchases that are to be made. For example, if retaining rings are to be removed, parts to have available should include insulation, locking keys, snap rings, and amortisseur (damper) windings. In some cases, replacement parts may be needed or vendors coordinated to refurbish parts removed during the outage.

2-34


Numerous specifications, which can be found in Chapter 8 of Volume 2 of the guidelines, have been developed to guide the repair to major generator-exciter components and systems. Examples of these specifications include: •

Rewedge of a water-cooled stator and a hydrogen inner-cooled stator

•

Repair to babbitted and nonbabbitted hydrogen seals

•

Inspection of a brushless and Alterrex exciter

•

Inspection of a hydrogen and nonhydrogen seal oil system

•

Rewind of a water-cooled stator and hydrogen inner-cooled stator

•

Procedures for torquing stator bolts in a generator

Other procedures are being developed and will be added to Volume 2 as they are completed. During service, operational abnormalities may provide indications of additional maintenance requirements to be planned. Operational damages may sometimes be anticipated, knowing the event and potential subsequent damage mechanism. Checking operating logs and outage reports are ways to provide insight into the health of the generator. The following are some abnormal operating conditions that may result in additional maintenance during an outage. •

Generator internal clearances are not usually close enough to see damage from excessive vibration (mechanical or thermal imbalance) during operation (except in the bearing and any sealing areas). Typically, the shaft sealing areas will have the smallest clearance and are, therefore, most susceptible to damage from excessive vibration.

•

Generators are typically designed for some voltage variation. A manufacture may specify a 5% over- or under-voltage design rating. Abnormal voltage operation maintenance concerns focus on damage created during these periods because of increased flux densities and core heating. Under-voltage operation requires increased excitation and may result in additional wear/damage to the excitation system.

•

If a generator is supplied with excitation and system power but the turbine loses the driving force from the steam, the generator can effectively operate as a synchronous motor and drive the turbine at rated speed. This operation is known as “motoring” and is not necessarily harmful to the generator, but it may be damaging to the turbine. No “cooling” of turbine buckets will occur with the steam flow blocked. The buckets, especially at the larger tip diameter locations, will spin at rated speed in a stagnant atmosphere and may heat quite rapidly.

•

Loss of field excitation can produce severe heating in the rotor. Without excitation, the unit becomes an induction generator where significant surface current is induced in the rotor body and wedges. A result may be arced or burnt wedges.

•

Out-of-frequency operation may also have more detrimental effects on the turbine than on the generator. The buckets of various stages in the turbine may be tuned to operate within a reasonably narrow operating speed (frequency from a generator perspective). Off-speed 2-35


operation of those stages may induce harmful stimuli to the buckets, resulting in failures or damage uncovered during a maintenance outage. One issue for the generator is reduced rotor cooling as a result of off-speed operation, and subsequent problems with regard to heating may also occur. •

Transients and faults may result in high rotor currents and resulting temperature increases, but physical or mechanical damage may result from sudden changes during operation. The mechanical shock induced by strong changes in the magnetic field may distort end turns, loosen or break ties, shift end turn blocking, or possibly damage insulation.

•

Unbalanced current operation in a generator designed to operate with balanced three-phase current loading can cause overheating of one phase of the stator. Unbalanced currents in the stator also produce a nonsymmetrical magnetic field. The field sees the changes in flux as traveling in the reverse direction (negative sequence). Damage to the field is dependent on the magnitude of the negative sequence currents imposed on the field. Additional heating occurs in the rotor surface and may cause damage to the wedges and retaining rings. These conditions may occur during a ground fault incident.

Performing repairs on generator components may require asbestos removal or interaction with other materials that are identified as hazardous waste. Therefore, included in the pre-outage planning is the identification of all products and wastes to be interacted with during the repairs. This includes obtaining all the appropriate product identifications (Material Safety Data Sheets or MSDS); material handling and waste disposal procedures; and notifications to the appropriate persons, departments, or agencies. 2.2.5 Valve Part Replacement and Repair Valve component manufacture or repairs to “spares” are often done during non-outage periods; therefore, the scope of repair is easy to determine. Preparation for outage repairs requires a review of past outage recommendations or historical activities to develop the anticipated repair scopes and planning. The actual repair or manufacture of replacement parts requires the same elements, whether performed during an outage or at another time. Damage mechanisms to valve components are usually from: •

Wear on sliding surfaces

•

Solid particle erosion

•

Water/steam erosion

•

Bending (stems)

•

Cracking

Repairs required from these damage mechanisms are normally done to the following valve components: •

Stems

•

Discs

2-36


•

Bypass valves

•

Caps

•

Actuator guides

•

Seats

Determination of the scope of repair is done by evaluating the serviceability of the component. This begins with cleaning the part so both nondestructive testing (NDT) and a dimensional analysis can be performed. The repair procedure may contain the requirements for the serviceability evaluation, or the evaluation may be done separately and the repair work scope provided from it. In either case, the information should be documented to become part of the repair work package. In order to track the repair item to its repair work package information, it may be necessary to mark or uniquely identity the item being repaired. Caution is always advised in the type and location of markings. If performed inappropriately, the marking may be removed during the repair process or may even become a point of failure during future service. Repair estimates may be obtained with a known repair scope. The value of a repair is determined by the utility and may be expressed as a fixed dollar amount or a percentage of a replacement part. This value should be determined in advance of the repair. Replacement part manufacture may be required if the repair exceeds a value of a new part. Repairs are completed in accordance with the repair procedure that contains the appropriate material and dimensional data. At this point, the repair process may not differ from original part manufacture. Both require material identification, including material processing requirements such as nitriding, and dimensional information that includes tolerances. Replacement part information may be contained within the repair procedure or provided separately as needed. EPRI report Guidelines and Procedures for Steam Valve Condition Assessment (1008352) provides a series of disassembly, condition evaluation, and reassembly procedures for 12 major types of fossil and nuclear valves. Additionally, EPRI report Turbine Steam Valve Diagnostic Testing (1004960) provides details on testing procedures that can be used to determine the current condition of a turbine steam valve during operation. These tests help determine the degradation of the valve stem, bushings, seats, and springs as well as describe how steam seal leakoff testing can be performed to further diagnose valve condition. 2.2.6 Parts Stores Review Before an outage, it is essential to review the parts requirements for both stock (warehoused) and non-stock (direct purchase, just-in-time, stock supplements) parts to support routine work and planned work. Routine work is defined as work associated with the normal disassembly, inspection, and reassembly of the turbine-generator. Parts to support routine work are itemized in Table 2-12.

2-37

Pre-Outage Planning and Bidding Table 2-12 Parts and Consumables Used to Support Routine Work Parts

Consumables

Gaskets

Rags

Sealants

Fish paper

O-rings

Oil adsorption materials

Adhesives

Shop ticket holders

Bolts

Triple-boiled linseed oil

Markers

Plywood

Washers

Pails and buckets

Liquid nitrogen

Pallets

Nuts

Welding cloth

Dry ice

Bushings

Safety wire

Fuse wire

Bearings

Shim stock

Tongue depressors

Valve components

Paraffin wax

Oak cribbing

Planned work is work that is not part of the normal disassembly and reassembly process. Planned work can be as simple as designating the replacement of packing as required or as complex as a complete rotor change-out. Reviewing historic usage is one step in evaluating the status of a plant’s stock level to match outage requirements. A review of non-stock parts used during the last outage coupled with its work scope is also beneficial. It is important to evaluate the status of critical items at a timely interval because warehouse stock levels are reduced to meet utility economic guidelines, and part ordering is often dictated by just-in-time delivery cycles. Missing a simple gasket can cause delays at the wrong time during unit assembly. Desktop or LAN-based databases introduced in Section 2.1.1 are an appropriate tool to assist in reviewing parts. Resident databases allow the reviewer access to information that may be queried to meet a specific review question. The master parts database should contain all identified parts associated with the turbine-generator. This includes both stocked and non-stocked items. The master parts database should contain as much history of part use as possible. The location of use is the second database necessary for parts review. The part use location database can be constructed with information available from unit construction or acquired through time. The information can be organized in a variety of formats. One format used by an OEM provides the location information identified by both numeric and location descriptive coding. Regardless of the method used, the coding or grouping location information becomes the basis for querying the database to determine part requirements. Figure 2-12 shows one method of coding or grouping part location information.

2-38


Figure 2-12 Part Location Information

It is useful to build the part location database (catalog of use) with grouping level descriptions that will aid in planning as well as in finding associated parts. One method is to group and divide parts into four levels, three of which identify the location of use and the fourth identifies the part. In most cases, this will provide a sufficient breakdown to find a part by beginning at the highest level and “drilling” to the part itself. The drilling process excludes all parts not associated with the higher-level item. It also helps in identifying all like parts used within a specific section. Figure 2-13 visually depicts this breakdown.

Figure 2-13 Four-Level Part Location Hierarchy

"Section” is the highest level of identification within either the turbine or generator. The “subsection” is the next logical breakdown when observing the makeup of the section. “Location” is the third descriptor and might not always be needed. The last item is the “common” name associated with the part. The common name may be a single “nickname” or 2-39


multiple nicknames normally used for that part by the utility. A nickname is always included. For example, one commonly used part is one that the OEM identifies as the outer stationary sealing component for the rotating row of buckets. This item is called a steam deflector; however, this item is often called simply a “spill strip.” So, spill strip is used as the familiar part identifier or nickname. The OEM often provides some form of part use information. This information can then become the seed or foundation for the parts catalog database. The information provided by the OEM might not provide sufficient breakdown or organizing details, so grouping levels are added to the part use location information. The combination of this information now provides a familiar and useful tool. The following are two examples of the grouping structure. The database contains all the relationship information for each part location. Within the database, these are the fields for each record. The record is all of the information that describes a part. Coded in the database is the ability to display only the appropriate information, limited by the items selected to be queried. As in Figure 2-13: 1. If HP is selected as the section: •

N-1, N-2, and shell (or all subsections associated with HP) would be displayed as subsection choices for further drilling.

•

No other subsection is displayed.

2. If N-1 is selected as the subsection: •

Grv-1 and Grv-2 (or all locations associated with N-1) would be displayed as location.

3. If Grv-1N-1 is selected as the location: •

Only those parts associated with that location would be displayed.

This approach moves down to a specific item. To look at all parts of specific types associated within a level, make a selection at the highest level desired and choose from the available parts. For example, if HP is selected as the section and Key is chosen as the part, four keys will appear in the resulting listing. If followed carefully, this system can become an extremely valuable tool. For instance, to list all the gaskets associated with main steam control valves (MSCVs), select MSCV as the section, and choose gasket as the nickname. All gaskets used within all MSCVs will be displayed, and the quantities required at each location will be listed. By producing a report based on this query, a bill of materials (BOM) of replacement parts is created and becomes the “shopping list” of items required. Comparing this list to the parts available shows part requirement needs.

2-40


2.2.7 Miscellaneous Turbine-Generator Exciter Parts, Bolts, Nuts, and Other Parts The need for miscellaneous turbine and generator parts should be identified from the previous outage report, outage recommendations, design changes, or modifications to existing parts. These parts may be items that can be reverse engineered during an outage or manufactured during non-outage periods. The requirements to produce parts are the same for both scenarios. Material identification of the part or assembly is required. Most materials used for turbine or generator components can be identified with an equivalent ASTM (American Society for Testing and Materials) number. A material ASTM number is a precise statement of a set of requirements to be satisfied by a material, product, system, or service that also indicates the procedures for determining whether each of the requirements is satisfied. Other material choices may come from such standards such as AISI (American Iron and Steel Institute). A drawing or sketch is used to define part geometry. Information obtained through reverse engineering may be in an electronic format that is easily converted to a fabrication drawing or sketch. Numerically controlled machine tools may be able to directly use the electronic drawing or sketch information. Manufacturing drawings must contain functional tolerances on the machined surfaces. Tolerances may be defined by the function of the part or through experience.

2.3

Identifying and Procuring Specialized Support

The turbine-generator engineer may be faced with a challenging problem when it is necessary to identify and locate the appropriate resources to resolve an issue or supply a part. It may be necessary to expand your database of available resources to perform the routine activities of turbine-generator repairs. Often, the first hurdle to overcome in problem solving is the identification of available resources. Traditional tools include: •

Yellow pages and directory listings

•

Trade publications

•

Annual trade publication handbooks

•

Professional and trade organization listings

•

Institute of Electrical and Electronics Engineers, Inc. (IEEE)

As regional and world boundaries change, the traditional methods of resource identification may no longer suffice. The Internet adds another resource identification method to the traditional toolkit. The Internet can be a maze of confusion or an ocean of information that can be tapped with the right resource tools and assist the turbine engineer trying to find available resources.

2-41


Suppliers and vendors who supported the last outage may no longer be in business by the next outage. One of the challenges facing the turbine engineer is being able to identify and obtain the right service or part in the right amount of time at the right cost. Examples of items that can assist in this process are summarized in Table 2-13. Table 2-13 Examples of Specialized Sources for Locating Vendors and Supplies Trade Crafts

Trade Magazines

Seminars/Meetings Sponsored by

NDE

Electric Light and Power

American Society of Mechanical Engineers

Sandblasting

Power Magazine

International Joint Power Generation Conference

Shot peening

Power Engineering

Electric Power Research Institute

Welding

Turbomachinery

American Welding Society

2.3.1 Lead Times to Arrange for Different Types of Support. Service support lead times may differ from parts-related lead times. Whenever possible, it is advantageous to secure services as far in advance of outages as possible. Outage season brings competition for resources between utilities because windows of opportunity may be limited during “outage season” for preferred resources. As a rule, purchase orders should be issued at least three months prior to the beginning of an outage. It is often preferable to obtain all parts prior to an outage, but economic factors may dictate leaving certain items to be purchased within the outage window. Purchases made then are based on inspection results, not on recommendations or pre-outage assumptions. The limiting factors for parts purchases during outages are that inspections must be completed early in the outage so that part orders can be made. Additional limitations are the availability of materials and lead times required by the manufacturer. Table 2-14 provides considerations and typical estimates for selected activities and lead times.

2-42

Pre-Outage Planning and Bidding Table 2-14 Selected Activities and Estimated Lead Times Type

Item

Lead Time

Considerations

Service

Diaphragm repairs

Four months

Many of the diaphragm repair vendors use independent repair craftsmen. These resources may often be shared by multiple vendors.

Service

Bucket repairs

Three months

Similar to diaphragm repair craftsmen. However, the number of craftsmen required per outage is usually less; therefore, this lead time may be shortened.

Service

Technical direction

Three months

Service

Balancing

Three months

Service

Sandblasting

Three months

Service

NDE

Three months

Service

Generator repair

Three months

Service

Coating or plating

During outage

Service

Glass beading

Three months

Parts

Buckets

Three to six months

Possible to manufacture during outage if there is a long outage duration. It is best to have spares on hand prior to the outage start date.

Parts

Packing and hardware

During outage

Multiple vendors are available with lead times such that these parts may be identified and purchased during the outage. Identification is required early in the outage.

Parts

Spill strips and hardware

During outage

Multiple vendors are available with lead times such that these parts may be identified and purchased during the outage. Identification is required early in the outage.

Parts

Fasteners

During outage

Limitation may be materials for higher temperature bolting. Typically, these items may be either purchased as part of the pre-outage process or purchased during the outage. For the latter, identification is required early in the outage to allow for lead time.

Parts

Field copper

Six to 12 months

Parts

Retaining rings

12 months +

2-43


2.3.2 Web Searches: Key Words or Identifiers to Produce Supplier Lists The ability to “see” information on the Internet is through web browsers like Netscape and Internet Explorer. The ability to find and then extract information from the Internet through the web is accomplished by using one of the following two primary methods: •

Directories. Directories contain “human” inputs for their listings. A short description is submitted to the directory for a web site and assigned to the appropriate category and subcategory. The search looks only for matches in the description. Because of the human organization, the directories can often provide better results than search engines

•

Search engines. Search engines create listings automatically. Search engines examine or crawl through the web, and then humans examine the results of the search. Search engines use tools to explore and catalog a web site and its information.

All search engines contain the same basic web-exploring tools and methods, but the difference is how each engine is “tuned.” That is why the same search item used by different search engines may produce different results. The difference is also the power of the search engine. There are at least a dozen major search engines as well as a myriad of specialized search engines, with more being introduced as the web grows in both size and complexity. In order to use the web and search engines as effective resource information tools, it is essential to understand how a particular search engine is cataloged or indexed and how to construct definitive searches. Most search engines will not only accept direct single word requests (for example, plant, turbine, etc.) but will also understand constructed searches (such as power plant, steam turbine, etc.) by employing a Boolean technique. It is important not only to identify key words for searches associated with turbine-generator repairs or parts purchase or replacement but also to know the relative strengths and weaknesses of a search engine and its querying techniques to be able to obtain meaningful results. When accessing information on the Internet, the following items are helpful: •

Become familiar with the type of web search devices available.

•

Become familiar with Boolean operators for searches.

•

Turbine-generator general keywords are helpful.

•

Maintain your own database of resources and URLs indexed to your needs and component identifications.

2.4

Scaffolding Requirements

Scaffolding provides access to various areas of the turbine-generator that are either inaccessible or unsafe to work on without temporary support structures. The scaffolding must be in place at the right time with access to the right area in order to support the turbine-generator outage. Scaffolding must also be constructed in a safe manner allowing a safe entrance and exit from the area. The scaffolding must not only provide access, but it must also act as a secure work platform as appropriate. Items that a scaffolding plan should include are listed in Table 2-15. 2-44

Pre-Outage Planning and Bidding Table 2-15 Basic Elements of a Scaffolding Plan Item

Comment/Example

1

Description of activity

“Install steam lead scaffold so machinist can dress face of steam flange. Need access to both flanges and to be able to maintain HP shell work below scaffolding.”

2

When the scaffolding is required

3

How the scaffolding is to be built

From where, to where, with access to what. Identification of support requirements – personnel, materials, equipment.

4

Additional craft support, if required

“Insulators to remove insulation which will provide ‘footing’ for scaffolding leg.”

5

Modifications required

Unique access to special areas during assembly and disassembly. Up and down to facilitate turbine-generator repairs.

6

Scaffolding component requirements

Quantities, type, and staging area.

7

Safety concerns

“All valves and equipment in the area will be hot. Be careful and don’t get burned.”

8

Regulatory compliance

9

OSHA Standards: Part 1926

Safety and Health Regulations for Construction - Subpart L – Scaffolds.

1926.450

Scope, application, and definitions applicable to this subpart.

1926.451

General requirements.

1926.452

Additional requirements applicable to specific types of scaffolds.

1926.453

Aerial lifts.

1926.454

Training requirements: Appendix A-E Subpart L – Scaffolds.

The items of a scaffolding plan that should be verified prior to an outage are as follows: •

Is there a scaffolding erection plan that identifies all of the components that correspond to the application? –

Footing or bearing requirements for the scaffolding.

–

Scaffold duty ratings should be assigned for locations based on expectations of use (for example, personnel only, equipment and personnel, etc.).

–

Planking span dimensions corresponding to loading requirements: light duty – 25 pounds per square foot (11.3 kg/m2), medium duty – 50 pounds per square foot (22.7 kg/m2), heavy duty – 75 pounds per square foot (34.0 kg/m2).

–

Safety factor – scaffolding system should be able to support “x” times the load required (for example, a safety factor of 4 means the components used within the design can carry four times the rated load before possible failure). 2-45


–

Toe board height and clearance requirements

–

Overlap of planking (if wooden planking is used).

–

Planking material, size, and grade requirements.

–

Fastener material, size, and grade requirements.

–

Locking wire material, size, and grade requirements. –

•

Handrail/guardrail height and span requirements.

How is the material to be staged? –

Are there pre-staging sites?

–

Is there a central delivery location and supporting distribution system?

–

Are component storage locations clearly identified (bins, racks, etc.)?

–

Has the required amount of material been identified and staged?

•

Have all the scaffolding locations been identified?

•

Is there a process for safety inspection after erection of the scaffolding? Prior to use, the appropriate supervisor responsible for scaffolding completion should visually inspect the job site and ensure at least the following: –

Integrity of the hardware

–

Proper access (ladders, etc.)

–

Guardrails

–

Toe boards

–

Scaffolding locks in place

–

Appropriate decking and structure to meet identified requirements

–

Completion and attachment of scaffolding inspection/release form (ready to use) to scaffolding at access location

•

Does the scaffolding construction plan match how the scaffolding is to be used?

•

Has the scaffolding erection schedule been completed and cross-referenced to the outage plan?

2.4.1 Customization of a Scaffolding Plan Typically, the items of a scaffolding plan that will require modification during an outage are the following: •

The timing of the scaffolding erection may be impacted by disassembly or reassembly.

•

The planned scaffolding foundation location may change as a result of a change in machine disassembly or reassembly, for example, planning to build off the turbine-generator lagging when the lagging has been previously removed.

2-46


•

Loading requirements may change, for example, if the plan was only to inspect and repairs are required, the scaffolding may be required to support equipment.

•

Planned access to scaffolding may change during the outage that could require a modification to the scaffolding plan.

2.4.2 Ways to Reduce Scaffolding Erection Time Constructing easy-on/easy-off platforms and accesses often significantly reduces disassembly, repair, or reassembly time. Such items would include: •

Access to cross over pipe flange bolting instead of scaffolding

•

Stands for valve components that include platforms instead of scaffolding

•

Covers/platforms instead of planking for access openings

•

–

Shell openings

–

Areas in turbine pedestal

Complete fabricated assemblies installed by crane, which include: –

Supporting structure

–

Grating

–

Unique tool holding or storage areas

–

Aligning, orienting, or locking devices

2.5

Safety Procedures

Safety is always considered a top priority during a turbine-generator outage. The components worked with during a turbine-generator outage may be heavy, awkward to handle, difficult to access, and require special handling and protection. Safe working attitudes, actions, and conditions must be maintained at all times. Safety attitudes should be reinforced daily during job planning meetings and “tail boards” and at other opportunities. Safe actions, “near misses,” and unsafe actions should be noted, commented on, and corrected as appropriate. Good work environment conditions should be maintained at all times during an outage. Good housekeeping is a visual indication of safety attitudes. Clean and orderly work areas reflect good safety attitudes and make the work easier. Trash should be cleaned up and disposed of; lumber and cribbing areas should be neatly organized with any nails either removed or bent over so they are not exposed. Tools and equipment should be picked up and put away. Hoses, extension cords, and general clutter should be kept out of the walkways. Portable overhead “cable/hose” racks should be used to maintain clear walkways. If none are available, cords, cables, and hoses should be taped down to reduce tripping hazards. Liquid spills and oily surfaces should be cleaned up immediately to reduce slipping hazards. This includes the bearing standard areas.

2-47


The following are other indicators that reflect a safe working attitude: •

•

Are proper rigging practices being followed? –

Use of eye bolt

–

Cable angles

–

Use of “shortcuts”

How are openings handled? –

Many are exposed during an outage - shells, standards, valves, etc.

–

Properly barricade openings using marking tape, temporary handrails, etc.

–

Cover the opening as soon as possible.

–

Minimize personnel traffic in the area until the opening is covered.

•

Is eye protection worn?

•

Is equipment tagged out and released for operation properly?

•

How is equipment reactivated for “in test” operation?

•

Is there finger- and hand-safety consciousness? –

Gloves are worn as appropriate.

–

Hand- and finger-safety awareness is practiced when using sledgehammers, lifting, etc.

2.5.1 Plan for Insulation/Asbestos Identification, Handling, and Disposal Most, if not all turbine-generator manufacturers stopped using asbestos or asbestos-impregnated products in the late 1980s. However, many, if not all, of the turbine-generators built before then contained some form of asbestos. Most often, asbestos was used in some form of insulation (both thermal and electrical), but it can also be found in sound-deadening materials, sealing materials, and higher temperature gasket materials. Table 2-16 lists typical areas where asbestos can be found around the turbine/ generator.

2-48

Pre-Outage Planning and Bidding Table 2-16 Typical Locations Where Asbestos Is Found Around a Turbine Turbine and Components Material Type Heat retention material

Location Casing/shells

High-temperature steam piping

Steam packing exhauster

Main steam valves

Non-return valves

Auxiliary steam valves

Refractory “mud”

Cloth used for insulation and blankets

Sound insulation

Turbine enclosures

Lagging

Gaskets (spiral and flat)

Shell and casing: Access, inspection hole, balance hole covers Main steam piping: Piping flanges and crossover flanges Valve assemblies: Heads, control valve stands, bolted in seats Valve assemblies: Leak-off flanges and attachment flanges Secondary/auxiliary piping

Packing

Heat exchanger

Steam packing, valve stems, and cylinder rod seals Shaft seals: Lube oil system, valve motors, non-return valves Valve seals: Butterfly valves Generator

Material Type

Location

Sound insulation

Generator lagging

Gaskets (flat)

Heat exchangers: Tube sheets, cooler heads Generator access covers

Motors

Thermocouples

Generator heaters

Generator: Tape, blocking, and insulation Electrical wiring

Exciter

Asbestos abatement is a comprehensive program that controls fiber release from asbestoscontaining materials and includes identification, removal, encapsulation, enclosure, repair, demolition, and disposal. Each element requires planning to accomplish abatement in a safe and timely manner. Elements of an abatement program are itemized in Table 2-17. 2-49

Pre-Outage Planning and Bidding Table 2-17 Items Recommended in an Asbestos Abatement Program Program Elements

Actions or Issues

Awareness and understanding of asbestos rules and regulations

OSHA 29 CFR 1910.1001 - Work Place Exposure Standards for Asbestos OSHA 29 CFR 1926.58 - Asbestos Standard for Construction Work EPA 40 CFR Part 61 National Emission Standards – Hazardous Air Pollutants – Subpart M, National Emission Standard for Asbestos

Asbestos identification and sampling procedures Work procedures

Large demolition, renovation, and removal Small demolition, renovation, or maintenance Glove bag removal

Air monitoring Work notification Medical surveillance Record keeping Asbestos disposal Training Additional details

2.6

Warning signs Warning labels Enclosure details Disposal container requirements

Environmental Planning

During an outage, a greater variety and larger quantity of chemicals are used than during nonoutage periods. The chemicals may be used for cleaning, bonding, sealing, and other purposes. Consequently, environmental issues and concerns should be a part of every outage planning process. Requesting the Material Safety Data Sheet (MSDS) for each chemical brought onto the site is a necessity. Providing access to information about all chemicals used by a utility is a requirement. Having the MSDSs available complies with “Right to Know” requirements and makes good sense. MSDS information about all chemicals is required before the chemicals are actually brought onsite. The MSDS form should be submitted in advance of the outage to appropriate safety personnel at the site to allow their complete review without impacting the scheduled activities.

2-50


Contractor or service personnel should be responsible for reporting and cleaning up any spills caused by their personnel. The clean up should be accomplished in accordance with the latest federal and state rules and regulations. Any spill should be reported to the utility. Unless otherwise specified, the contractor or service personnel should be responsible for the removal and disposal of any chemical or by-product that is considered hazardous by regulation. Disposal should be made to a licensed and certified facility approved by the utility. 2.6.1 EHC Fluid Fluid handling should be done in accordance with the MSDS instructions and precautions, with the handler wearing the appropriate personal protection equipment (PPE). Spills of any fluid should be attended to immediately. Spills may not only pose an environmental but also a safety risk. A synthetic phosphate ester fluid is typically used for electrohydraulic control (EHC) systems. Phosphate ester fluids are used in turbine controls because of their higher flash point and fire point over their petroleum-based counterparts. A phosphate fluid, with the look and feel of a light mineral oil, should not be confused with petroleum-based hydraulic fluids. The phosphate fluid requires specific safeguards and procedures to maintain its usability as a serviceable hydraulic fluid. EHC fluid is shipped in lined 55-gallon (208 L) drums to protect the fluid from contamination. Fluid removed from the EHC tank reservoir should be placed in suitable containers to prevent fluid contamination. Drum tops should be cleaned with a non-chlorinated fluid to prevent contamination before transferring the EHC fluid to and from the tank. Under normal operating temperatures, phosphate ester fluids do not emit any harmful vapors; the MSDS should be consulted for additional information regarding PPE. Appropriate measures should be taken when the fluid contacts the skin. Phosphate ester fluid has minimal skin exposure risks, but the areas should be cleaned in accordance with the MSDS and exposure limited. Oral ingestion does pose a health risk; therefore, immediate medical assistance should be obtained in accordance with the MSDS. Phosphate ester EHC fluid affects the serviceability of items used in and around EHC systems. Most items commonly used with petroleum-based hydraulic fluids are not compatible with phosphate ester fluids. For that reason, caution should be taken when allowing the fluid to be exposed to the following items: •

Seal materials –

Improper seal materials can swell, soften, or become eroded and cause leaks or binding of moving parts.

–

Preferred material – Fluorocarbon (FPM) - Viton.

–

Acceptable substitutes [2] ∗

Ethylene-propylene (EPDM) suitable under certain conditions 2-51


•

•

•

∗

Butyl rubber

∗

Teflon for pressurized water reactors (PWRs). Teflon is not used in boiling water reactors (BWRs) because of degradation from radiation.

Packings –

Improper packing materials can swell, soften, or become eroded causing leaks or binding of moving parts.

–

Preferred materials - Teflon, fiber sheet.

–

Acceptable substitute - RTV silicone.

Paints –

Standard coatings will soften and peel with the possible result of a system malfunction.

–

Preferred material - special phosphate ester resistant, amine-cured epoxy.

–

Acceptable substitute – none.

Electrical wiring insulation –

Some insulation coatings will soften and eventually decompose after exposure to phosphate ester fluids.

–

Preferred materials - silicon rubber, Teflon, nylon, polyethylene, or polypropylene.

An EPRI guide is available that not only discusses the environmental issues but also provides plant personnel with information about EHC systems. Electrohydraulic Control (EHC) Fluid Maintenance Guide, 1004554, [3] can help plant workers improve the system reliability, performance, and plant maintenance practices. Many topics are covered in this guide including fire resistant fluids, fluid purification, fluid sampling and analysis, condition monitoring, material compatibility, and operating limits. Another EPRI guide, General Electric Electrohydraulic Controls (EHC) Electronics Maintenance Guide, TR-108146, [4] provides maintenance recommendations for system electronics and identifies design changes. The EPRI guide Steam Turbine Hydraulic Control System Maintenance Guide, TR-107069, [5] has been developed to improve the reliability of system hydraulic components and fluid through maintenance recommendations. The results of the guide can serve as a valuable source of information for plant personnel who are evaluating their hydraulic system to determine how to improve performance. The EPRI guide EHC Tubing/Fittings and Air Piping Applications and Maintenance Guide, 1000935, [2] was developed to deal with the tubing, fittings, and air piping in the steam turbines that can be a cause of plant trips, load reductions, and maintenance problems. The guide identifies causes of tubing, fitting, and air piping failures and also recommends maintenance practices that will improve their reliability. Utilities can use the information provided in this guide to identify causes of failures and implement maintenance practices that will improve the reliability of the components. 2-52


2.6.2 Waste Products to Be Considered Epoxies are used in a variety of locations in the construction and maintenance of both the turbine and generator. The generator typically has the most and widest use of epoxies and other materials where waste products are at issue. Within the generator, epoxies are used in the assembly or reconstruction of stator end winding liquid connections. Epoxy paint may be used to seal joints. The epoxy and its solvent require special handling during processing. Waste products may include mica, fiberglass, epoxy, and absorbents from cleanup. Often, the liquid waste can be more easily handled by mixing the remaining components together to form a solid product. Waste handling can be done by incineration or landfill disposal in accordance with local, state, and federal regulations.

2.7

Crane Availability

Most components associated with a turbine-generator outage require lifting devices to assist in their disassembly, handling, transport, repair, alignment, and reassembly. Therefore, having sufficient resources and coordination of these lifting devices is essential to a successful outage. There are three important phases of overhead crane usage during an outage: •

Phase 1 – Disassembly: Depending on the utility, one or two overhead cranes may be available for use during disassembly. It is important to plan disassembly and required vertical lifting clearances so that a crane does not become “load locked,” that is, lifting a load and having to wait until another crane moves; this increases the outage time. Not only is coordination of usage essential but also the sequence of use.

•

Phase 2 – Overlap during disassembly: The second phase is the transportation or moving of components for cleaning, NDE, or repairs. This phase will usually overlap the disassembly of other components. Components should be initially set once during disassembly and then prepared for lifting/transport for the next phase of activity. It is best, but not always practical, to lift once and to set/load for the final destination. Having multiple lifting systems appropriately located during the outage facilitates this phase of activity.

•

Phase 3 – Assembly: The final sequence is assembly. The same disassembly concerns apply to reassembly; improper hook or overhead clearances during assembly can “load lock” a load and delay assembly.

Other concerns for coordination of crane usage during an outage are associated with non-turbinegenerator requirements. Often, the turbine deck overhead crane will be required to support nonturbine deck activities. Non-turbine deck requirements should be planned and coordinated before the outage begins. This allows for the integration of the other activities into the turbine-generator outage plan. Outage support activities usually begin at least one week before the start of the outage. During this time, the utility uses the overhead crane to pre-stage turbine-generator outage support equipment. This is an ideal time for vendor support equipment to arrive at the station and be transported to the turbine deck and work centers as appropriate. Lifting beams, lifting eyes, lifting slings, and cables used during an outage should be inspected by NDE before the outage. The critical components should be inspected before each outage and visually inspected before each use. Less critical items should be on a periodic inspection schedule. 2-53


The proper operation, testing, and maintenance of overhead gantry cranes can contribute significantly to improved reliability and safety and to the avoidance of costly downtime. The EPRI guide Crane Maintenance and Application Guide: Maintenance and Application of Overhead Cranes, 1000986, [6] includes detailed component information, in-depth overhead bridge crane maintenance practices, and inspection programs for different types of cranes. 2.7.1 Crane Maintenance to Be Performed in Advance Normally, turbine deck overhead cranes accumulate minimal usage hours throughout the year but are constantly used during an outage. Outage preparation is necessary to ensure safe and reliable operation during the high usage period . An out-of-service overhead crane can severely impact the schedule. All critical lifting devices should be load tested prior to the outage. This test checks the capacity and operating components of the lifting device. The hook should also be NDE inspected before the outage and as part of the load test. The crane rails should be visually inspected before the outage. Any abnormalities should be addressed. 2.7.2 Types of Cranes Lifting device selection during an outage will be dependent primarily on weight and reach. A central lifting device can be used that has reach capability and relieves some of the overhead crane use. Often, the primary lifting device to remove turbine-generator components is the overhead crane, which is later supported with other strategically located lifting devices in the work center areas as shown in Figure 2-14. On most outdoor turbine-generator installations, a large gantry crane is the primary lifting device.

Figure 2-14 Types of Lifting Cranes

Table 2-18 offers alternatives for lifting turbine-generator components. Note: The component weight and lift orientation determine the right lifting device. 2-54

Pre-Outage Planning and Bidding Table 2-18 Alternative Lifting Devices for Turbine-Generator Components Component

Overhead

Picker

Jib

Gantry

Bearings - in place

x

x

Bearings - repair area

x

x

x

Bolting

x

x

x

Crossovers

x

Diaphragms

x

Generator end shields

x

x

Generator field

x

x

Miscellaneous parts

x

x

Packing heads/casings

x

x

Rotors

x

x

Shells, casings, hoods

x

x

Valve components - in place

x

x

Valve components - repair area

x

x

x x

x

x

x

x x

x

x x

2.7.3 Crane Use Schedule An effective crane use plan is made up of a number of elements. The first and most critical element is a person assigned to coordinate all crane activities at least during the crucial times of turbine-generator assembly/disassembly. Multiple personnel will vie for crane usage and, without a coordinator, will soon create scheduling and sequencing havoc. Another element is involvement with the current sequence of turbine-generator activity that is linked to the outage schedule. Crane usage may be noted either on the schedule directly or by association to component activity description such as “remove.” The next element is having a detailed lay-down plan, so that when an item is removed, it can be positioned once and not have to be moved to facilitate locating another component. Having racks and stands pre-staged complements a single lift and set. It is also necessary to coordinate “floats” (truck trailers) if they are to be used for loading turbine-generator components from the turbine deck to other locations for sandblasting, NDE, repairs, or other activities.

2.8

Turbine Deck Lay-Down Planning

The turbine deck lay-down plan is a map for component placement during the disassembly of the turbine-generator. The turbine-generator is made up of thousands of parts, and when disassembled, the parts can be scattered over thousands of square feet of floor space (and across 2-55


acres of space if the removed components are placed off the physical turbine deck). Like any map, it is a useful tool for providing location information. Therefore, it is essential that the plan be followed when placing components. The map not only provides logistical information but also, depending on the turbine deck construction, may act as a guide for safely placing heavy loads that are removed from the turbine-generator onto the turbine deck or other surfaces. Unlike roadmaps, the turbine deck lay-down plan can be modified and the modifications registered during an outage. 2.8.1 Basic Elements for Any Deck Lay-Down Plan The turbine deck lay-down plan is a valuable tool for use by all personnel associated with the turbine-generator outage. Each group may interact with the lay-down plan in a different manner but share in its use as a communication tool. Consequently, the elements that make up the plan must meet the interactive needs of those associated with the turbine-generator outage. Consideration should be given to the work being performed on the components removed from the turbine-generator. Like activities may be grouped into work centers. A work center should provide all the requirements within the concise location to perform the “job.” Arrangements to meet any unique or specific job plans should also be included. A standard template for the lay-down plan should be created. The template will contain the information that is “static” for each outage. The template should be created as a “layer” within a drafting program, and each outage can be created on top of the template as a separate layer. Disassembly consistencies, work centers, etc., may also be contained on the template layer or on a layer unique to each. Similar components can also be color coded so that they can be easily distinguished. Part “orphaning” can be easily detected on a computer monitor during the planning phase. Printouts from a color printer or plotter can also indicate the visible component groupings and show potential interferences on the turbine deck. The following list details the type of information that should be included in the template for a lay-down plan: •

Grid references – distances/column coordinates/plant reference/orientation

•

Plant equipment outlines

•

Fire lanes or other safety zones

•

Support facilities - rest rooms/cafeteria/lunch rooms

•

Floor loading requirements - uniform loading/point loading

•

Special component lay-down information

•

Component - footprint/weights/identification - color coding

•

Lifting resource locations, other than an overhead crane

•

Overhead crane limitations and hook location restrictions

•

Power – voltage/phase/amperage/”feed” panels, breaker locations, etc.

•

Compressed air supply locations

2-56


•

Floor drain locations

•

Water locations – potable/service

•

Tools – tool room/slings, cables, etc.

•

Work centers (permanent) – identification/storage/work area/support equipment/component racks/component orientation

The outage plan includes the component lay-down locations for that outage, including any unique outage activity requirements. Routine outage work must be integrated with any unique outage activities, both from the turbine-generator and from any other area of the plant. Component grouping and lay-down location should take into account the following: •

Setting orientation should consider activities to be performed including scaffolding and repairs Example: machining of the main steam lead flanges of the HP outer shell. This requires a shell orientation where scaffolding can be erected for access to the flanges with sufficient room to machine the flanges without limiting access to other areas of the shell.

•

The total area required to perform any maintenance on the item, including the footprint of component, access areas around the component, work tables, support equipment, and other things. Example: replacing the last stage bucket on an LP rotor. Encroachment can occur into the repair area if not properly planned, especially if the rotor is set early in the outage, before the bucket work begins. Having a plan that identifies all the area required will help prevent having to rig and re-rig components to make floor space available to perform the actual maintenance.

•

Loading interaction with other components Example: the performance of a generator field rewind that will require a special area with unique floor loading requirements, access to support equipment, and floor spacing to construct a “clean room.” Generator fields provide a high density floor loading; therefore, proximity to other components and equipment may require a total section floor loading evaluation.

•

Outage sequence dependent lay-down utilization Example: performing rotor bore inspections. The rotor bore inspection is usually performed early in the repair cycle when turbine deck space is at a premium. Approximately double the rotor length space is required in order to perform the inspection. Because the inspection is usually short, that deck space may be recycled quickly.

•

Safety considerations Example: slow-speed balancing turbine rotors on the turbine deck. Location, weight, safety, contamination, and outage sequence are all considerations when planning the location for the lay-down plan. Rotating rotors at slow-speed balancing speeds require area access control.

2-57


Example: application of thermal spray coatings such as high-volume oxygen fluid (HVOF) process on diaphragms. Acoustic energy produced during the HVOF may cause noise pollution concerns for those on the turbine deck. The following lists of some information that should be considered when planning for unique activities: •

•

•

Work centers (temporary) –

Footprint

–

Utilities

–

Storage and lay-down space for component pre-assembly or disassembly

Support equipment –

Arrival date

–

Utilities

–

Setup information

Expected activity dates

2.8.2 Basic Items or Issues to Be Reviewed If a turbine deck template containing all the static information has been created, the pre-outage review and planning can focus just on the upcoming outage, including both the routine and exceptional activities. If the lay-down plan has been created in a drafting program with layers assigned to the work centers, routine component locations, and other areas, the review can start with those. Identifying any unique work for items typically assigned to the routine plan will cause those items to be pulled from the routine plan. They may either be set on separate layers within the drafting program or keyed with another color. Comparing the outage disassembly plan and the repair scopes for the remaining components will identify any other lay-down areas that might require modification. Consideration can be given to traveling distances, first selecting the location and other subsequent variables to meet both the special and routine requirements for a component. A component can be broken out from its normal setting location to perform the special activity on it and then returned to its routine location. Therefore, the review sequence checklist is: 1. Identify unique or special jobs to be performed. 2. Remove those items from their normal location. 3. Evaluate special job requirements and available turbine deck space. 2-58


4. Shuffle the components to accommodate special activities. 5. Rearrange routine location items to accommodate as necessary. Note: The number of components removed from the turbine-generator and the space to place them is a constant. The variables are support equipment to perform special activities and the timing sequence within the outage. Therefore, the lay-down plan is a dynamic jigsaw puzzle to be solved for each outage. 2.8.3 Items to Amend in a Customized Plan The first draft of the turbine deck lay-down plan should be issued for review before the outage. All groups involved with the turbine-generator outage should review the initial draft. This review includes other maintenance plans from other work areas if they affect turbine deck usage. All comments and suggestions should be reviewed and implemented as appropriate. One last review should take place during the pre-outage meeting. A typical pre-outage meeting can be held within a month to two months before the outage. All turbine-generator work should be locked in prior to the pre-outage meeting so that final revisions can be made to component location, work center details, and other items.

2.9

Special Tools, Equipment, and Facilities

An important utility component is its compressed air system. It is needed to operate air tools in the maintenance shop and in the plant; it operates pneumatic controls of air-operated valves, airoperated solenoid valves, etc. Companies will install, operate, and maintain a compressed air system on-site to provide required compressed air. Unit reliability and energy costs are affected by the system performance. The EPRI guide Compressed Air System Maintenance Guide, 1006677, [7] provides information for plant maintenance and operations personnel on how to maintain system reliability, which ensures that the system is functioning as required. It identifies corrective, preventive, and predictive maintenance that can be implemented to improve system performance and also troubleshoots system problems. Nondestructive examination (NDE) is an integral part of every turbine-generator outage. The simplest and most often used form of NDE is visual inspection. NDE is used as an investigative tool during a turbine-generator outage to assist in the determination of the repair scopes for components. NDE is performed to identify indications, abnormalities, and discontinuities of components. It is the responsibility of the turbine engineer to evaluate the NDE result and outline the scope of the repair. Not all NDE indications require repair, but all NDE indications require a disposition. The disposition made may be return to service “as is,” repair, or replace, but a determination must be made. Many forms of NDE are available to the turbine-generator engineer; each is a unique tool that may be used alone or in conjunction with another to provide component condition. The items that follow list NDE methods and processes available and normally used for turbine-generator maintenance inspections: •

Magnetic particle (MT) – AC/DC/dry power/wet fluorescent

•

Liquid penetrant (PT, red dye) 2-59


•

Ultrasonic (UT)- straight beam/shear wave

•

Eddy current

•

Video – CCTV/cameras

•

Radiography (RT)

•

Replication – creep/stress corrosion cracking (SCC)

The use of each process may require planning and coordination during an outage. Most are unobtrusive to the turbine-generator maintenance being performed; however, RT is one process that must be planned and coordinated if it is being performed on the turbine deck. RT can be scheduled for off shifts, lunch breaks, and other times when the impact on workflow can be minimized. Processes such as replication may be used more on older machines than newer ones, as time-inservice-dependent damage begins to occur. Other processes such as UT may have more schedule impact than others when applied to rotor inspections. All forms of NDE require some form of surface preparation. Sometimes, it may be only wiping the oil or dirt from the surface so the component can be viewed. Other cases may require actually etching the surface of the metal to enhance indications. The most used process during the outage is MT (both wet fluorescent and dry particle), followed by PT and UT. The other processes are used as appropriate. Testing is a significant portion of a generator outage. Today’s generator tests tend to focus on two areas: •

Insulating system test

•

Water cooled stator winding integrity test

Of the two tests, the stator winding integrity test requires equipment that makes use of more turbine deck space around the generator. For this test, skid-mounted equipment is employed to dry out the stator windings by using pressurized air to blow contamination/particles from the windings and a vacuum to boil off any remaining moisture. The skid is then utilized to test the hydraulic integrity of the stator windings. Special care is required when the generator field is removed from the stator for inspection or repair. It is not only important to protect the field from moisture and contamination but also from using the wrong types of solvents, cleaners, or inspection media. Ideally, when the rotor is removed from the stator, it is maintained a few degrees above ambient temperature to prevent water vapor from condensing on the generator parts. Constructing a wood-frame, visquine(plastic) covered enclosure over the field while it is removed from the stator and on the turbine deck is one method of protection from the environment. The enclosure should be constructed with sufficient room to perform inspections and limited maintenance. Using an enclosure can also limit access to the field, helping to ensure cleanliness. A lengthy and tedious process may be required if dryness and cleanliness are not maintained during the outage. 2-60


2.9.1 Storage and Work Space Provisions for Cleaning and/or NDE NDE may be performed in a variety of locations during a turbine-generator outage. Sometimes, components will be inspected at a central location. Normally, NDE is performed in place on large components such as rotors and shells or where they have been set. NDE may also be performed in work areas or work centers where it is easier to bring the NDE to the part than vice versa. This condition would include items such as bearings, etc. Smaller components such as fasteners or fan blades will be done at a central location. Temporary structures may be required both for cleaning and for NDE. Grit blasting is done in some locations on or near the turbine deck. In these cases, temporary enclosures are erected with exhaust and collection systems to handle the grit dust. The preferred location for grit blasting is away from and off the turbine deck; however, in some cases, grit blasting must be done on or near the turbine deck. For example, when the valve chest must be blasted for NDE, the choices are limited to working on or near the turbine deck. The valve area must be enclosed and an exhaust collection system used. It is advantageous to locate the exhaust system and filter bag (collection system) off the turbine deck. This will help prevent depositing the small uncollected grit dust onto the turbine deck and components in close proximity. Other methods of cleaning may be performed on the turbine deck. Part cleaners and temporary cleaning areas may be designated where wire brush and abrasive cleaning is done. On larger components, the cleaning is completed where the component is set. Grit blasting and cleaning generally require well-lit areas, but a light-limited environment is required when doing wet fluorescent magnetic particle inspection. Temporary frames covered with black 3–5 mil (0.0762–0.127 mm) plastic may be sufficient for small areas. Large portable or permanent structures are required for larger components. Some components require that scaffolding or pre-constructed structures be erected for both cleaning and inspection. Outage planning may be required to coordinate activity in the larger facilities if they are used for multiple activities during the outage. 2.9.2 Provisions for Cleaning and Inspecting Different Turbine Parts Cleaning is required to remove insoluble deposits on various turbine components. The purpose of cleaning of a component may be just to remove surface deposits to facilitate inspection, or cleaning can be focused on the removal of deposits that are causing a reduction in turbine efficiency. In either case, the purpose of cleaning is never to damage the component through excessive material removal or by leaving detrimental surface conditions, such as scratches or gouges, that might affect the fatigue strength of the component. Therefore, it is not only important to remove the surface masking deposits but also not to damage the part in the process, so selection of the appropriate cleaning method is important. The most commonly used method of cleaning is grit blasting. Grit blasting is economical because it is thorough and faster than most any other cleaning process. It also provides uniformly cleaned surfaces that are an aid to NDE. It is also aggressive and can remove tough surface deposits. 2-61


Typically, 220-grit alumina oxide (other materials are also acceptable) is used to remove surface deposits from the turbine steam path, shells, casing fits, horizontal joints, bolting, valve pressure seal heads, gasket fits, and other items. Depending on the quantity and toughness of the deposits, anywhere from several hundred pounds to a ton of oxide may be used to clean turbine components. The oxide may be reused after screening to remove foreign objects that might damage the turbine component. The oxide particle size and cutting edges are changed as the oxide is used. The change in size and loss of cutting edges make the oxide less aggressive; this change is advantageous when doing fasteners. The blasting media for the rotor bucket/blade attachments is glass beads. Glass beads are less aggressive than oxide and pose a lower chance of material removal. Glass beads leave a very smooth finish; therefore, it is important to identify the scope of work and the type of blast media required, especially for any bucket/blade removals. Methods of local cleaning include: •

Hand stoning - used to remove oxide buildups from turbine-generator fit-up areas that cannot be grit blasted. Soft stones, such as griddle stone, are fast-cutting stones and are normally used to clean the oxide scale from joints and fits. Harder stones, such as India Oil and Arkansas stones, are used for precision work in finding burrs when a true flat stone is needed.

•

Strap lapping - used for both cleaning and surface preparation of bearing journal surfaces. “Strapping” uses narrow emery cloth of at least one or possibly two different grits.

•

Wire brushing - used to clean smaller bolt threads, carbonized oil from oil deflector teeth, etc. Wire brushing is not a method recommended for surface preparation for NDE. Wire brushing “smears” the surface metal and may hide or mask indications.

•

Scotch-Brite pads and abrasives - used to “polish” or clean light, thin surface deposits depending on the medium. Aggressive cutting discs may be used to prepare surfaces for repair or NDE.

•

Chemical cleaning - used to remove oils, chemical surface deposits, and penetrants. Two concerns are evident with chemical cleaning: will the product produce a hazardous waste and what impact will it have on the component being cleaned. Use of the wrong cleaners may not only have an impact on the environment, but also may attack the base material, causing pitting, or contribute to SCC.

Outage planning should include a review of all the consumable items required to support inhouse cleaning of components. Table 2-19 lists the NDE equipment for each process that is typically required as support for a turbine-generator outage.

2-62

Pre-Outage Planning and Bidding Table 2-19 List of NDE Equipment Used to Support a Turbine-Generator Outage Magnetic Particle Testing

Liquid Penetrant

Ultrasonic Testing

AC yokes with articulating legs

Cleaner

Flaw detectors

DC yokes with articulating legs

Penetrant

Thickness meters

Power supplies - large applications

Developer

Transducers

Cables

Calibration blocks

Extension cords

Couplant

Dry power Wet fluorescent Fluorescent lamp (black light)

Materials planned for the outage may be in bulk form or in smaller portable units. A review of the outage plan will provide an insight into the scope of inspections required. From this review, a comprehensive list of required NDE equipment and supplies can be developed. 2.9.3 Items or Issues Specified as Part of the Work Order for Vendors A list of items that should be contained within the vendor work/purchase order for turbinegenerator NDE activities is provided here: •

Scope of work: Comprehensive list of the components to be inspected. Component cleaning responsibilities. Inspection process (for example, first, complete visual, then…). Component marking

•

Contractor/vendor-supplied materials and equipment

•

Utility-supplied materials and equipment

•

Commencement and expected completion dates

•

Work force loading and shift requirements

•

Daily reporting and timekeeping

•

Documentation: NDE personnel certifications. NDE personnel eye exams. Current equipment calibration NDE procedures

•

Rates

•

Office: space, computer and printer

•

Safety equipment and requirements 2-63


•

Inspection standards: OEM inspection standards, utility turbine-generator inspection guidelines

•

Communication: findings notification process, report format, rough and final, disposition process, schedule, priorities, and direction updates

•

Chemicals: MSDS, handling and disposal

2.10 Machine Disassembly Plan Effective turbine-generator disassembly begins with planning months before the first fastener is removed. Physical activities supporting machine disassembly begin during the pre-outage period that is usually one to two weeks before the outage. The disassembly plan should not only include the setup or staging activities and actual disassembly but also take into account reassembly and post outage activities. The machine disassembly plan also includes methods for disassembly, identification, and determination for alternative disassembly/reassembly methods. Resource planning is also an element of this plan. Add in the work scopes, and all the ingredients necessary to develop a plan are present. 2.10.1 Basic Elements in the Machine Disassembly Plan The sequence for the removal of turbine-generator components is the central element of the unit disassembly plan. Inputs from defined work scopes, logical or norm disassembly processing, work force availability and quantity, and facility resource availability shape the disassembly sequence. Defined work scopes may place an emphasis on a particular section to be disassembled, but the normal disassembly sequence and data collection may delay the disassembly work on that section. Limitations in both work force and facility resources may also affect the actual disassembly sequence. 2.10.2 Issues or Items Reviewed The following is a list of items that should be reviewed as part of the outage plan: •

Schedule If the outage is properly planned, the schedule becomes an accurate guide or roadmap for the outage. Even the best-planned outage will often have unexpected damage found that requires repairs. These activities are generally unplanned for and may, if not properly addressed, affect the outage duration. The schedule should be constructed of the activities that are performed to components that make up the turbine-generator. These activities are assembled into a logical manner reflecting the disassembly, repair, and reassembly of the turbine-generator. These activities should be constructed into groups or modules. Each group or module is a self-contained unit with branches or links to other modules as appropriate. Alternative modules can be

2-64


pre-constructed and developed for “what-if” scenarios. These what-if modules can be inserted into the schedule when the time comes to accommodate the unexpected. Instead of many unguided paths arising from an unexpected repair, a predetermined integrated plan of action is now ready. An example of a shift in action is the result of stuck coupling bolts that cause resources to shift slightly and redirect the flow of disassembly. Ensuring that all component modules are completed (with all the elements and activities identified) is the primary focus of schedule planning. A second planning activity is the development of alternative modules that can be used to address unplanned but potential disassembly problems. •

Resources Certain resources are limited during any maintenance outage. Limits on these resources will impart constraints on the disassembly and can have a significant impact on the overall schedule if not properly addressed. Review the historic actual hours, craft types, and other resources that were logged in to complete previous outage activities. A review of work force` loading for the upcoming outage, including work load and craft distribution, is essential as the schedule develops. It may be beneficial to extend the workdays of the disassembly personnel to expedite component exposure. Ensure that the correct number of qualified personnel on the appropriate shifts are available to support the outage including supervisors, mechanics, craft personnel, and engineers. A review of quantities of tools and equipment and the state of repair or status of tools is part of the disassembly preparation.

•

Work Packages A work package should contain all pertinent information of what is to be completed, how it is to be completed, by whom it is to be completed, and with what resources it is to be completed. This is important so that a smooth transition from disassembly to work package implementation can be made.

•

Disassembly/Reassembly Methods Disassembly activities include not only removing fasteners and moving “iron” but also taking measurements and performing alignment checks to both assess the current machine condition and identify items to be addressed. A review of the disassembly plan should contain the appropriate rotor position checks, rotor clearance checks, coupling alignment checks, and bearing clearance checks before rotors are removed. Optional plans should be prepared for exceptions or problems during disassembly. Plans would include alternative vendor resources and additional equipment so that if an “emergency” arose, it could be handled expeditiously.

2-65


2.10.3 Identifying Contingency Plans for Unexpected Work The types of problems that are normally encountered during disassembly often involve fasteners. Stuck fasteners can be at any location along split lines: shells, diaphragms, valves, and coupling rotors. Having one stuck fastener can delay disassembly if alternative removal methods have not been prepared. The most often used method is to air-arc off the resistant fastener component. Occasionally, shells can stick because of galling on fitted areas or distortion from water induction incidents and may require additional parting resources. Potential disassembly problems should be investigated before they happen. The plan to address problems should include not only resource options but also an agreed upon “if-then decision flow process.” This will reduce delays during disassembly.

2.11 Foreign Material Exclusion Like it or not, gravity exists, and anything dropped always seems to fall into the most unlikely locations in a turbine. Around a turbine-generator, dropped objects will find their way to the lowest and the most difficult locations from which to be extracted. Therefore, the best foreign material exclusion (FME) plan begins with attempting to defy the laws of nature by not giving them an opportunity to be demonstrated. An FME plan should consist of three items: •

Prevention

•

Documentation and notification

•

Extraction

The foreign material that enters a system can cause equipment degradation or inoperability, and—for a nuclear station—fuel cladding damage, spreading high radiation and contamination levels throughout the plant. As a result, great care and strict precautions must be taken to avoid the introduction of foreign materials into plant systems. To present a proactive approach to preventing foreign materials in a plant, the EPRI report Foreign Materials Exclusion Guidelines, Revision 1, 1009709, [8] has been developed. The report provides a comprehensive overview of the technical considerations required to develop, implement, and manage an FME program at a nuclear power station; however, much of the information in this guide is directly applicable to establishing an effective FME program in a fossil station. In addition to the EPRI report cited in the previous paragraph, programmatic guidance is provided in Appendix D of this report. Appendix D compiles many good practices and lessons learned from plant and site personnel and should be considered if developing or enhancing an FME program. 2.11.1 Organizational Responsibilities for Turbine-Generator Contracts Prior to performing any work on the turbine-generator, responsibilities should be assigned so that the likelihood of foreign material intrusion is minimized. Appendix D.3 of this report provides additional guidance from a programmatic perspective. However, it may be beneficial to establish organizational responsibilities specifically for contracts related to work on the turbine-generator. 2-66


Figure 2-15 illustrates a typical organizational structure for assigning and implementing the responsibilities described in this section.

Figure 2-15 FME Organizational Structure for T-G Contracts

In these instances and as described in Figure 2-15, some utilities have established the following positions and related responsibilities: 2.11.1.1

Turbine-Generator Contract Technical Coordinator

The turbine-generator contract technical coordinator (CTC) typically reports to the project manager and has the following responsibilities: •

Plans, sets up, and executes the Foreign Material Exclusion (FME) program for all zones of the turbines, generator, main steam valves, and auxiliary systems that present a potential threat for the introduction of foreign material into the turbine-generator system

•

Communicates the foreign material control program requirements to plant personnel and contractor personnel who are working on the turbine deck

•

Ensures that periodic surveillance is conducted of the FME zone to make sure that good engineering practices are implemented in support of this program

2.11.1.2

Contract FME Engineer

The contract FME engineer typically reports to the CTC and has the following duties: •

Serves as primary assistant to the CTC for technical matters relating to the FME program. Ensures that the contractor sets up the turbine deck using the recommendations contained within this performance guide. 2-67


•

At the direction of the FME lead, ensures that FME zones are clearly identified and adequately segregated from the work zones.

•

Ensures that the requirements of this performance guide are complied with by all contractor staff and in all FME zones.

2.11.1.3

Lead Foreign Material Exclusion Monitor

The lead foreign material exclusion monitor (FMEM) typically reports to the plant CTC and has the following duties: •

Serves as primary assistant to the CTC for matters relating to the execution of the FME program requirements

•

Directs the FMEMs in the execution of their assigned duties and acts as their first line supervisor in the execution of the FME program

•

Ensures that supplies and materials are available to perform all FMEM duties

•

Is the primary means of supplying necessary FME zone training and providing management oversight in the enforcement of FME requirements for all FMEM personnel who have assigned duties in the FME zone

•

Conducts all training for the turbine-generator team on FME zone operations

•

Assists the FME engineer with craft training of FME policy and procedures

•

Prepares and administers the work schedule for the rotation of duty FMEMs

•

Upon completion of the FME zone audit and after completion of the outage, turns in all FME zone records to the FME engineer for review

•

Ensures that FME paperwork gets put into the work package for processing FME records to the RMS for the life of the plant

2.11.1.4

Foreign Material Exclusion Monitor

Foreign material exclusion monitors (FMEMs) typically report to the plant CTC via the lead FMEM. An FMEM often has the following responsibilities: •

Serves as entry log monitor

•

Assists both primary and secondary monitors, rover position

•

Assists with observing craft upon ingress and egress

•

Assists with craft/guest personal possession process upon ingress and egress

•

Provides observation support in FME area zone 2

•

Relieves primary and secondary monitors for rest and lunch breaks

•

Supplements supplies necessary for FMEM duties

2-68


An FMEM often has the following duties: •

Ensures that the recommendations of this performance guide are used within all FME zones.

•

Ensures that all personnel who enter the FME zones have been approved for entrance and have signed the FME zone Rules Form.

•

Completes the required FME documents such as the permanent parts storage log, long-term tool and material storage form, daily tool and material entry log; and any other forms deemed appropriate by the turbine-generator CTC for all parts, tools, and other materials that enter into or are removed from the FME Area.

•

Ensures that personal belongings such as jewelry, wallets, coins, watches, pens, and pencils are removed prior to entering FMEA zone 1 (Exception: wedding rings).

•

Ensures that FME zone 1 is secured by lock or personnel during periods of no work. FME zone 1 will be monitored when personnel are assigned to work during lunch periods and assigned breaks or when personal belongings are unable to be secured under lock and key.

•

Advises the CTC (or their designee) and the FME engineer on the effectiveness of the FME zone security system.

•

Ensures that the daily audit of tools is completed and signed by the FME engineer prior to leaving the turbine deck at the completion of the shift.

•

Controls all personnel access and egress to the FME zone.

•

Controls the master “turbine-generator drop list” and ensures that each drop is recorded. Immediately after a drop is recorded, it should be reported to the engineer responsible for the equipment.

•

Periodically walks down the FME areas to watch for unattended tools, materials, or trash.

•

Provides a physical presence during fire watch/confined space entry/escort.

2.11.1.5

Personnel Assigned Duties Within the Turbine-Generator FME Zone

In general, personnel performing duties within the turbine-generator FME zone typically have the following responsibilities: •

Clearly understand that it is each person’s responsibility to understand and comply with the FME zone rules.

•

Ensure that the recommendations of this performance guide are used while inside an FME zone.

•

Ensure that prior to entering the FME zones they have been approved for entrance and have signed the FME zone Rules Form.

•

Provide the FMEM any assistance required in filling out the required FME documents such as the permanent parts storage log, long-term tool and material storage form, daily tool and material entry log; and any other forms deemed appropriate by the turbine-generator CTC.

2-69


•

Be familiar with the general requirements for the protection of turbine-generator equipment or systems during disassembly and reassembly if their duties include assembly and disassembly of this equipment that could involve a potential FME incident

•

View any appropriate FME training material (for example, the video tape “Generator Job Site Control”) prior to beginning work in that FME zone.

2.11.2 Areas of the Turbine-Generator to Protect Appendix D.4 of this report provides general guidance for establishing and implementing FME program requirements. Specific to turbine-generators, the following guidance should be considered when determining the areas of the turbine-generator to protect and subsequently in developing requirements to protect them. Damage to the rotating element and subsequent stationary components are what an FME plan is trying to prevent. Almost anything lodged in the steam passage can be broken down over time. Fragments are then transported by the steam flow and ultimately contact the rotating components where they either do damage or are accelerated and do damage to the stationary components of the steam path. Foreign objects left in the air gap (space between the field and the stator core) and non-metallic items can block ventilation areas, but conductive objects can cause shorting of the core, leading to failure and restacking of the core and rewinding. Magnetic material can be influenced by the rotating magnetic field, accelerated up to operating speed, and flung off—causing damage in multiple regions before finally becoming wedged at some location. Objects left in the generator end windings may cause chafing from vibration or flutter, ultimately cutting through insulation. Foreign object damage (FOD) in bearing oil or hydrogen seal feed lines will do similar damage to either the stationary or rotating components; damage will occur when the fragments are forced through the tight clearance. Not all lines lead into the turbine; extraction and steam seal lines may lead to other components that can be damaged by items dropped or left in the lines. Items can be transported and lodged in a valve, preventing operation at a critical time. Understanding the piping routing, machine components, and possible damage scenarios helps to identify the critical areas that must be protected. Some of the critical drop locations around a turbine-generator change with the state of disassembly or reassembly. It is easy to extract a file that is dropped into the shell when the rotor and diaphragms are removed, but extraction when the rotor and diaphragm are in place may become a time-consuming challenge.

2-70


Table 2-20 lists critical areas that should be protected. Table 2-20 Areas of a Turbine-Generator to Be Protected During Disassembly Area

Potential Damage To:

Bearing feed lines

Bearings Journals

Extraction lines

Non-return valve Isolation block valve Heater

Generator

Stator end windings Stator core Field Cooler bundles Bushing boxes Ventilation areas (ducts, passageways)

Hydrogen seal feed lines

Hydrogen seal Journal

Main steam lines

Steam path

Reheat lines

Downstream valve Steam path

Shells

Steam path Extraction system

Steam seal lines

Valves Heat exchangers Seal supply areas

Stop or control valve

Down stream valve Steam path

2.11.3 Measures to Take for Each Critical Area The primary intent of a foreign material exclusion plan is prevention. Prevention planning has three elements: •

Educating personnel. FOD training should occur as part of the pre-outage training program. Emphasis in training should include what FOD can do to a turbine-generator and how to keep foreign objects out. 2-71


•

Preventing items from being dropped. Simple exclusion plans include such items as personnel emptying pockets before entering critical areas and tying off tools at critical times of reassembly. Notification is essential if an item is dropped into the turbine. This includes foreman/supervisor notification and logging the drop on a “drop” list. The drop list should contain: the date, the name of the person who dropped the item, a description of the dropped item, the location of the dropped item, and an extraction check off.

•

Preventing items from entering critical areas. A blocking device log should record when every blocking device is installed and removed. If the blocking device is not removed, it can also result in FOD in the unit. Table 2-21 lists suggested locations and types of prevention that can be used. Table 2-21 Areas of a Turbine-Generator That Should Be Blocked Area

Prevention

Bearing feed lines

Use brightly colored duct tape. Silver duct tape is often used to cover items, but this matches the color of the metal too closely.

Extraction lines

Use plywood or metal covers. Continue to use the covers until after the diaphragms and rotors are in place. Connect a brightly colored extraction cord to each cover.

Generator

Empty pockets. Cover openings with plastic film/sheets. (See Note)

Hydrogen seal feed lines

Use rags to stuff in the lines. Use brightly colored duct tape. Silver duct tape is often used to cover items, but this matches the color of the metal too closely.

Main steam lines

Place covers over the valve openings when no activities are taking place.

Reheat lines


Shells

Empty pockets. Tie off tools when components are being reassembled.

Steam seal lines

Use brightly colored duct tape. Silver duct tape is often used to cover items, but this matches the color of the metal too closely. Use plywood or metal covers. Continue to use the covers until after the diaphragms and rotors are in place. Connect a brightly colored extraction cord to each cover.

Stop or control valve


Note: Avoid using black or red duct tape because these colors can easily blend in with red or black colored turbine stator parts and can be overlooked when they need to be removed.

2-72


2.11.4 Implementation of FME Plans for Turbine-Generator Work Maintenance activities on the turbine-generator should be conducted with a plan to prevent the intrusion of any foreign material. Appendix D.5 of this report provides additional guidance regarding the development of FME plans. The following issues should be considered during the development of FME plans for turbine-generator work. 2.11.4.1

Steam Turbine

Operating experience tells us that turbine components are considered high-risk FME areas. Rotor blades tend to be susceptible to various types of damage due to foreign material intrusion. Flow paths upstream of the turbine blades need to remain free of foreign materials. Working in the vicinity of turbine bearings and coupling faces requires that the areas be controlled to prevent the entry of foreign material. In addition to the main steam paths of the turbine and the bearings, consideration should be given to FME requirements for work on the stop and control valves, steam chest, turbines, electrohydraulic components, seal oil, and lube oil components of the turbine systems. The controls put in place should include the completion of FME plans prior to the start of any work. These plans should reference pertinent industry operating experience to prevent the chance of foreign material intrusion. 2.11.4.2

Generator

Due to the size of the component and the large number of persons involved in generator maintenance, the electrical generator is extremely susceptible to foreign material intrusion during maintenance operations. Cases have been reported where plastic bags, metal-handled brushes, and even large items, such as the skid tray used in extracting the generator rotor for maintenance, have been left inside upon completion of the maintenance activity. Assignment of strict FME control is recommended for the main generator area whenever the generator is open for maintenance. For major maintenance involving several work groups or exposing the generator internals, establish physical barriers, and restrict access for nonessential personnel. Some plants erect metal cages to restrict access to the unit. Establish requirements for post-maintenance inspections immediately before closing the generator. Consider flushing the cooling and lubrication systems to ensure that they are free of debris. 2.11.4.3

Cross-Under Piping

Cross-under piping comes from the bottom of a high- or intermediate-pressure turbine cylinder casing. Cross-under piping often has a sufficiently large diameter for items to be dropped into. Prior to working in the areas of cross-under pipe openings, cover, dam, or seal these openings to 2-73


prevent foreign material intrusion. After the completion of the work, remove the covers, dams, or seals, and inspect the cross-under piping visually. Use a video probe or borescope, when available. Consider using material accountability logs during work in these areas. Develop an FME plan prior to beginning work. 2.11.4.4

Condensers

Condensers are common places to find foreign materials. Any time that a turbine, turbine component, or piping is opened, allowing access to the condenser, the shell side should be inspected prior to closing to ensure that no foreign material is present. Consider covering the tubes under work areas such as extraction lines and expansion joints. The controls put in place should include the completion of FME plans prior to the start of any work. These plans will reference pertinent industry operating experience to prevent the chance of foreign material intrusion. Where water boxes, such as cooling water condensers or heat exchangers, have been opened for cleaning, ensure that a thorough water box and tube sheet inspection has been performed prior to closure. An FME plan should also be considered prior to beginning this type of work. 2.11.5 Performance of Work Inside the Turbine-Generator FMEA Appendix D.6 of this report provides general guidance for performing work inside a foreign material exclusion area (FMEA), with emphasis on the need for cleanliness before, during, and after maintenance activities, as well as using graded FME controls. The following guidance should be considered when performing work on the turbine-generator. Table 2-22 describes a number of actions that should be taken to prevent the intrusion of foreign material into the turbine-generator.

2-74

Pre-Outage Planning and Bidding Table 2-22 Example of FME Measures During Turbine Disassembly and Reassembly Courtesy of FirstEnergy Step

Description of FME Action

1

All steam inlets, valve bodies, extraction ports, and oil lines that are opened for maintenance purposes during scheduled and forced outages must be temporarily plugged until repairs and inspections are completed and reassembly is imminent.

2

Installation of FME plugs should be listed as specific line items or indicated as written comments or notes on the appropriate work list line item, on the Turbine Area Outage Shift Work List. The Work List should be generated by the assigned turbine engineer and distributed to the shift foreman for job assignments and pre-job meetings with assigned plant craft labor. Installation of FME plugs should also be described within the Component Work Plan or Maintenance Work Order for the assigned work item.

3

The FME plugs that are to be installed should generally be prefabricated, tight fitting, compressible polyurethane foam plugs; inflatable rubber, or rubberized fabric bladders; and/or plywood covers made especially for the intended applications. The plugs should have permanent handles for ease of manipulation and removal. FME plugs should be available in various sizes and should be accessible from a dedicated material storage cage or gang box to be located on the operating floor in close proximity to the work being performed.

4

All FME plugs should have special, brightly colored 3/8" (9.5 mm) diameter nylon ropes tied to the plugs. The ropes should extend outside the turbine cylinders, shells, bearing pedestals, reservoir, or structures and should be tied-off to a rigid fixture such as permanently installed pipe, horizontal joint stud, or shell tie-off point. The intent of this feature of this procedure is to provide a “tell-tale,” that is, to provide a physical means of communication signifying that there are FME plugs present in the turbine component being inspected and/or repaired.

5

The tie-off ropes should have special, brightly colored inventory tags that are attached to the ropes. Inventory tags should be available from within the dedicated FME material storage cage or gang box. Each FME plug should have its own separate tie-off rope and inventory tag. FME plug inventory tag numbers should be written into a log, to be located in the FME material storage cage or in the turbine engineer’s office. The FME log should contain the inventory tag number, a description of the plug location, the date that the FME plug was installed, and the date that the FME plug was removed.

6

It is the responsibility of the plant maintenance personnel performing the disassembly of the turbine components to install the appropriate FME plugs into all ports, orifices, and openings that are associated with the assigned disassembly. Installation of the FME plugs will include tying off the plug with the special nylon rope, installing the inventory tag, and logging the location and date of FME plug installation.

7

It is the responsibility of the assigned turbine engineer to identify the ports, orifices, and openings that will require FME plug installation. In the event that the turbine engineer for FME protection has not previously identified an opening, orifice, or port, it is expected that the lead maintenance person working on the assigned turbine project would bring this condition to the attention of the foreman and/or turbine engineer.

2-75

Pre-Outage Planning and Bidding Table 2-22 (cont.) Example of FME Measures During Turbine Disassembly and Reassembly Courtesy of FirstEnergy Step

Description of FME Action

8

Temporary removal of the plugs for maintenance activities may be required. In this event, the FME plugs should be replaced at the end of each shift, providing that replacement of the plugs does not cause harm or rework for the maintenance activity. If the FME plug cannot be replaced at the end of the shift, the lead maintenance person should so advise the foreman and turbine engineer.

9

Prior to reassembly of the turbine components into which FME plugs have been installed, the assigned maintenance personnel should remove the FME plugs. Removal should include returning the plugs, ropes, and identification tags to the FME material storage cage and also recording the date of removal into the FME log.

10

Prior to reassembly of the turbine components for which FME plugs have been required, the ports, openings, and orifices should be visually inspected by either the lead maintenance person, the foreman, or the turbine engineer to ascertain that the FME plugs, ropes, and identification tags have been removed.

11

Additionally, prior to reassembly of certain critical turbine components, such as steam inlet lines, extraction ports, and main oil pump suction and discharge lines, these lines should be inspected by video borescope by qualified NDE personnel, in order to ascertain that no potential injurious materials have been inadvertently left in the lines. Identification of the application of video inspections should be the responsibility of the foreman or turbine engineer.

Appendix D.6.9 of this report provides general guidance regarding the use of FME devices, including plugs when performing work inside the FMEA. The following guidance should be considered when performing work on the turbine-generator. The list that follows1 describes various locations on the turbine-generator where plugs may be useful in minimizing the intrusion of foreign material: •

Main steam inlets following the removal of HP and IP upper-half outer cylinders or shells. Since these line ports are typically positioned well above and away from the turbine centerline, a short (12–18" or 30.5–46 cm) “tell-tale” rope can be used, and it does not need to be tied off. Instead, let the tell-tale ropes (and ID tags) hang down from the steam lead ports.

•

Cold reheat ports following the removal of the HP upper half outer cylinder or shell. These ports are typically large bore and located in either end of the lower-half outer cylinder. These ports require the use of inflatable bladders or plywood covers. Tell-tale ropes (and ID tags) should be extended above the horizontal joint (HJ) and tied off to a permanent fixture outside the turbine shell.

1

Courtesy of FirstEnergy

2-76


•

Main steam inlets following the removal of the lower-half HP and IP inner cylinders. These ports are usually located near the axial centers of the turbine shells at the bottom of the outer shell. In the case of SA-1 and SA-2 HP-RH sections, these ports are exposed after the removal of the flanged lower shell inlet elbows. Tell-tale ropes and ID tags should be extended above the HJ and tied off outside the shell.

•

HP and IP section extraction line ports. These ports should be protected by installing foam FME plugs with tell-tale ropes and ID tags extended outside the outer cylinder HJs and tied off to permanent fixtures.

•

Cross-over exhaust ports on the IP turbine outer cylinders when the IP turbine section will not be disassembled or when the disassembly of the IP section will be significantly delayed after the removal of the cross-over. Since these ports are located on the upper-half outer cylinders, short (12–18" or 30.5–46 cm) tell-tale ropes and ID tags can be used

•

LP turbine outer cylinders, following the removal of the upper-half outer covers. These cylinders are normally covered by wooden “dance floors” to protect the exposed condenser tubes and to provide access to the LP inner cylinders. LP “dance floors” do not require telltale ropes and ID tags.

•

LP cross-under inlets, following the removal of the upper-half inner cylinders and DFLP rotors. These ports are large bore and require plywood covers. Tell-tale ropes and ID tags should be extended above the inner cylinder HJ and tied off to extension studs.

•

LP inner cylinder extraction ports, following the removal of the upper-half inner cylinders and in those situations when the lower-half LP inner cylinders are not removed. These ports should be protected by plywood covers, cut to match the irregular shapes of the HJ openings. These covers do not require tell-tale ropes and ID tags.

•

LP inner cylinder extraction ports, following the removal of the lower-half inner cylinders. These ports should be protected by installing foam FME plugs with tell-tale ropes and ID tags extended outside the outer cylinder HJ and tied off to permanent fixtures.

•

Bearing pedestal drain ports.

•

Bearing oil supply ports located in the bearing shell support brackets.

•

Main oil pump (MOP) suction and discharge ports.

•

Thrust bearing oil supply ports.

•

Turning gear oil supply ports.

•

Coupling guard cooling oil supply ports.

•

Control block and control components.

2-77


An example2 of how one utility assigned responsibilities among key personnel within their FME program to minimize the risk of intrusion of foreign material into the turbine-generator when using FME plugs and other devices is shown in the list that follows: •

The assigned turbine engineer should identify the locations for FME plug installation and should include the installation of FME plugs within the turbine component work plans and also the daily shift work lists.

•

Component work plans should be included within the maintenance work order and available for review by both the turbine foreman and the assigned craft labor.

•

Daily shift work lists should be given to the turbine foreman by the turbine engineer and reviewed during pre-shift planning meetings between the engineer and foreman.

•

The assigned turbine foreman should provide specific job assignments to the craft labor, including the installation of FME plugs, and should specifically discuss the necessity for FME plug installation with maintenance personnel during pre-job conferences.

•

The assigned maintenance personnel should install the defined FME plugs and should also advise the foreman and/or turbine engineer of ports and openings that are present but have not been identified within the work plan.

•

The assigned maintenance personnel should advise the turbine engineer of the location and tag identification of FME plugs that they have installed. The turbine engineer should maintain the FME log.

•

Removal of the FME plugs should also be described in the daily shift work lists (written by the turbine engineers) and described within the component work plans.

•

In the event that an FME plug has been installed, but has not been identified as a removal item on the daily shift work list, and may be covered by an imminent re-assembly, maintenance personnel should advise the foreman and/or turbine engineer.

•

Turbine component assembly should be stopped until the condition is communicated and corrected.

•

The turbine engineer should maintain the FME log, document the installation and removal of FME devices in the engineer’s outage log, and perform an inventory audit of the FME plugs throughout the turbine outage. In the event that an inventory audit indicates that an FME plug may have been left in a turbine component, the log should provide sufficient information to locate the missing plug.

•

Pre-outage planning should include preparation of the FME storage cage and procurement of FME devices, tell-tale rope, and ID tags.

2

Courtesy of FirstEnergy

2-78


2.11.6 Retrieval of Foreign Objects Appendix D.7 of this report provides general guidance for recovering after loss of FMEA control, including the initiation of a condition report, the recovery plan, and the actual retrieval of the foreign materials. The following guidance should be considered for retrieval of foreign objects in or around the turbine-generators. Foreign objects dropped into turbine-generator areas come in various shapes, sizes, materials, and weights, and each can pose unique extraction problems. Two methods of extraction are used: •

Disassembly and retrieval of the dropped items

•

Remote acquisition and retrieval

Remote closed circuit television (CCTV), borescopes, and fiber optic scopes provide methods to locate the dropped item; however, the difficulty is not location, but extraction. Many NDE vendors have taken technology that was developed for inspection and adapted it for retrieval. The ideal extraction device contains both elements: viewing (that is, location) and extraction. Extraction methods have included everything from “chewing gum” (something sticky) on the end of a rod or bar to snares, hooks, and even “pigs” (cloth, foam, or some material that fills the area) pulled through the section. Magnets have been strapped to robotic video cameras to extract small metallic/magnetic items. Pneumatically operated jaws/fingers/grippers/extractors have also been used to extract odd-shaped or non-magnetic items. The most difficult item to extract is something large, heavy, and non-magnetic, especially if geometrically difficult terrain must be negotiated. A large vacuum can be used to extract small debris found in lines. A limitation for vacuuming is the diameter of the line to be cleaned. Most likely, the extraction of dropped parts will be required during reassembly, delaying critical path activities. 2.11.7 Video Inspection of Shells and Steam Lines Appendix D.8 of this report provides additional programmatic guidance on the close out of FMEAs. The following guidance should be considered for closing out an FMEA that includes the turbine-generator. Before closing a turbine section, it is a good idea to inspect between the shells to verify that no foreign material is located there. Inspection between shells can easily be done with borescopes, fiberscopes, or video cameras. Internal pipe inspection can be a bit more challenging than between shells. Remote robotic cameras are the preferred method of internal pipe inspection. The robot must be able to navigate vertical sections of piping with the ability to articulate the camera views. Planning for the outage includes identifying internal pipe dimensions to be inspected and the total length to be traversed.

2-79


2.12 Training Preparing the personnel to perform an outage is just as important as developing the plan or creating the schedule. The training should be customized to accommodate the type of maintenance personnel performing the outage. If the support staff is part of a centralized maintenance organization and dedicated to performing outages throughout the utility, the preoutage training will be focused on the specific activities to be performed and may involve a different cross section of personnel than a decentralized maintenance organization. Decentralized maintenance management can be defined as outage support provided only by the plant. The training for a decentralized maintenance staff maintains a different focus that that of a centralized maintenance staff. Because a decentralized maintenance staff is not focused year round on turbine outages, the training will include more basic, generic, and refresher information. The information presented here focuses on a decentralized maintenance concept. The information can easily be adapted to centralized maintenance focus by extracting only the unit-specific information. The purpose of training is to enable plant personnel to identify, inspect, and maintain the turbinegenerator unit with the knowledge that will allow them to approach the maintenance activities with confidence. Participants will accomplish this by gaining an understanding of machine operation, maintenance practices, safety, damage mechanisms, and the work planned for the turbine-generator. 2.12.1 Training Formats Training can be conducted in a variety of formats and durations. The ideal timing is a one week course held two weeks before the outage; the following week would be dedicated to pre-outage activities. Computer-based training (CBT) can be used for some of the general maintenance practices and can be accomplished before formal training begins . Student-instructor participation and interaction is the recommended format, especially for detailed specific maintenance practices and specific work scope presentation. Attendee selection may vary based on utility guidelines, but should at least include all turbine-generator supervisors, and technical support personnel. It can include support contractors and even vendors at the appropriate time. The ideal setting includes all personnel who will be performing the turbine-generator maintenance. Instructors should be personnel involved with the outage. Journeymen or maintenance supervisors may present specific maintenance activities, for example, field or turbine rotor removal. Technical direction personnel may review the readings to be taken and the reasons for taking them. The planning department should be represented to review and discuss the outage plan and schedule. Vendors may be asked to present a demonstration on use and repair of their tooling. A repair vendor may be asked to present damage mechanisms, assessment, and repair processes. The training must be focused and profitable to the attendees to be effective.

2-80


Training can be organized into a single general session where all attendees receive the same information. It can also be organized as a general session where the outage plans are presented and specialized sessions where the unique section information is presented. 2.12.2 Recommended Training Topics The following is a breakdown of the topics that should be considered in turbine-generator preoutage training. A detailed list of subjects is presented in Table 2-23. 1. Turbine-generator basics The items listed for this and for each topic are comprehensive, but the items listed can be grouped and tailored to meet the specific need of the attendees. Outage staff with very limited exposure or staff that does turbine outages only once a year can benefit from the comprehensive list. The minimum exposure during training is the preparation for the work to be accomplished and included under the planning section. 2. Maintenance Practices A listing follows of the various topics for which the utility’s maintenance practices would be presented. Included within the description are standard practices performed and special methods or standards that were developed by the utility. Examples would include the use of hydraulic wrenches instead of sledgehammers. Included in the training would be pictures, graphic displays, and written instructions on how to perform the listed operation. The idea is to be unit- or utility-specific, not generic. 3. Inspection testing and repair The purpose of this training is to provide the attendee with background information regarding why damage occurs, what damage to look for, and what repairs are required. The attendee will also be provided with generic cleaning, NDE, testing, repair information, and specific repair information when applicable. 4. Planning The planning portion provides all the information that has gone into the making of the upcoming outage. Everything unique to that outage is presented. The first sections focused on the machine itself, with unchanging or slow-to-change practices. This section focuses on what is going to be done during this outage and may be limited only to this outage.

2-81

Pre-Outage Planning and Bidding Table 2-23 List of Recommended Training Topics Turbine Generator Basics Turbine construction

Flow path, sections, extractions, components

Generator construction

Stator, methods of cooling, field

Section and component terminology

Orientation: Left and right. TE, GE and CE. Upper and lower Numbering: Odd and even. A,B, and C.

Identification

Hood, casing, shell, packing casing, packing head, diaphragms, rotors, valves, generator, exciter

Operation

Turbine, generator, stress, thermal growth, auxiliaries Maintenance Practices

Documentation

Entry requirements, forms, process instruction sheets, vendor/turbine deck repair sheets, discrepancy report, drop list

Rigging

Rigging manual, how to “flip”, hand signals, rotors, field, valves

Tools

Tool room, how to use, tips on repeatability of readings, hydraulic wrenches: proper use, do’s and don’ts, maintenance, applications

Sequence Disassembly and reassembly

Thermal lagging, crossover piping, horizontal joint bolting, joint feeler checks, rotor position checks, coupling checks, bearings: [journal, thrust], bearing checks: [support pad blue checks, blue checks and scraping, mandrel checks, measuring journal and bearing, tilt and twist, pinch checks, hydraulic coupling bolts], component removal: [shells, casings, hoods, rotors, diaphragms – upper and lower, packing cases], valves: [stop, control, intercept, reheat stop, ventilator, non-return], generator: field removal

Alignment

Internal: [philosophy, required reading – position clearance checks, rotor clearances], interpretation: [refined readings, determining need for alignment], diaphragm realignment: [radial crush pins, arch spring supports, centering pin], external: [required readings – rim and face], Interpretation: [refined readings, determining need for alignment, coupling alignment: [calculated bearing moves, changing shims]

Auxiliaries

Lube oil, seal oil, EHC system, stator cooling water system, extractions, iso-phase cooling, steam seals. Inspection and Repair

2-82

Cleaning methods

Grit blast, stoning, strap lapping, wire brush, chemical

NDE methods

Visual, PT, MT, UT, eddy current, RT, hardness, etching

Steam path inspection

Diaphragms, buckets, sealing areas

Type of distress

Erosion: [solid particle, water, steam cutting], deposits, Cracking: [chemical, mechanical], Chemical attack: [corrosion, pitting], Electrolysis, FOD, distortion

Pre-Outage Planning and Bidding Table 2-23 (cont.) List of Recommended Training Topics Inspection and Repair (cont.) Rotor and field

Couplings, journals, wheels, packing areas, buckets: [vendor repairs], shrouding/covers, rotor bowing [reasons], stress, size/construction, operation, detection [in-service, during outage], slow speed balancing [imbalance, resolution], end plane, midspan [cleaning in service balance locations]

Stationary components

Casings, joints, packing, nozzles, diaphragms [spill strip removal, packing removal, ledge and seal key, vendor repairs], bearings, bolts

Bearings

Wear patterns, bonding and cracking, clearances, contact checks, repairs [onsite, scrapping, off-site]

Valves

Body, pressure seal area, stem, disc, bolting, crossheads, strainers, actuators and linkage

Repair/replace/reuse decision process Planning Planning

Disassembly focus, major jobs, work orders, outage schedule, sandblast schedule, NDE schedule, pre-shutdown activities, pre-shutdown maintenance, lay down plan, environmental – MSDS/hazardous waste disposal, vendors

2.12.3 Training Options Many of the training vendors provide turbine-generator training that can be customized to a specific type of turbine-generator. This is an alternative to creating in-house training for: •

Turbine-generator basics

•

Maintenance practices

•

Inspection and repair

2.13 Rigging, Special Tools, Parts, and Expendable Materials Pre-outage planning includes a review of availability and status of rigging and special tools. An inspection program of lifting devices prior to the outage is prudent; this includes crane hooks, lifting cables, eyebolts, and lifting beams. The inspection program should serve two functions: the first is NDE and the second is an inventory of available lifting devices. It is not uncommon to have cables or lifting devices borrowed during non-outage periods and returned damaged or not returned at all. Special tools such as hydraulic wrenches, hydraulic power packs, porta-powers, and tooling that supports work centers should be functionally inspected and repaired if necessary prior to the outage. Although tools should be repaired after an outage and before storage, there is always a seal or a hydraulic fitting that leaks or a pump that will no longer pressurize. Special tooling to support rotor-turning devices such as slides, tool posts, oilers, misters, etc., should be inspected for correct operation. 2-83


The last outage report should be reviewed for specific comments regarding lifting device modification and component stands. The use of safety netting around the turbine pedestal to prevent components from falling on anyone or anything below should be reviewed. The manufacturer recommendations should be reviewed for inspection requirements, testing, etc. The pre-outage review should also focus on the use on consumable or expendable materials. A comprehensive list should be kept each outage and reviewed before the next outage. Table 2-24 lists typical consumables used during an outage. Table 2-24 Typical Consumables Required for an Outage

2-84

Category

Item

Typical adhesives and sealants used by some utilities

3M Super 77 spray, Belzona super meta,. Fluorosilicon (fittings, sealant), GE R V 60 without catalyst, Superglue, Ultrablue Permatex RTV

Cleaning

Brushes (metal scratch (tooth brush), paint, tube cleaning), cleaning compounds (degreaser, denatured alcohol, detergent (parts washer), hand cleaner (5 lb can) (2.27 kg), solvent, water-soluble soap), cleanup (broom, broom handle, dust pan, floor squeegee), oil absorbent (sock, loose), spray bottle, towels (paper), rags (lint free, regular), trash can liner (large, small)

Gases and coolants

Argon, dry ice, nitrogen, oxygen

Inspection

Fuse wire 0.025" (0.635 mm), 0.028" (0.711 mm), 0.031"(0.787 mm), feeler gauge, information tags, leak detector – “snoop”, markers (felt, metal, soapstone), Prussian blue, shop ticket holders

Lubricants

Fasteners (anti-seize, penetrating, thread lubricants), lube oil strainer bags, oil (triple-boiled linseed, gear, hydraulic, jack, multipurpose, synthetic), wax (paraffin, toilet seal)

Metal working

Abrasives (Arkansas stone: hard and soft, grinding wheels, ScotchBrite: green and red), emery (crocus cloth of various grits and widths, disc), file handles, fluids (cutting, tapping)

Personal and Protection

Batteries, disposable gloves, drinking cups, ear protector, eyeglass cleaner, industrial flashlight, lamps (incandescent, quartz lite 300watt), respirator (disposable, face shield)

Storage

Buckets - white 5-gallon (18.93 liter), oak cribbing, pails (buckets white 5-gallon [18.93 liter], economy), pallets, plastic bags (large, self-locking), plywood sheets

Gasket and Insulating

Gasket material, Kaowool, non-asbestos gasket material, Rubatex

Fasteners and Lifting

Hose clamps, manila rope, rope (nylon, poly-dacron, polyester), safety tie wire, tape, cable ties

Miscellaneous

Music (piano) wire 0.016" (0.406 mm), fish paper, shim stock, tongue depressors, welding cloth

3

UNIT SHUTDOWN

During unit shutdown, practices and techniques are continuously sought to reduce the margin of conservatism in generic loading and starting curves without damaging the thermally stressed components of the high-pressure turbine. In addition, practical methods are also sought to minimize the valuable critical path time that is used while waiting for the unit to cool, at which point disassembly can begin. This section of the guidelines identifies, reviews, and compiles the practices and techniques that are normally involved or should be undertaken during the shutdown of a turbine-generator for a maintenance outage, leading up to the point where the unit is brought off turning gear and general disassembly can begin. The information here is primarily designed to identify and describe the methods or approaches that have been used to reduce the time required to bring a unit from full speed to placing it on turning gear. Methods or practices that have been used to further accelerate the cooling process during the shutdown process are also reviewed. Activities that can be undertaken while the unit is cooling, that is, on turning gear, in preparation for the disassembly of the unit are also discussed.

3.1

Pre-Outage Testing

A number of non-intrusive tests should be performed throughout the operation cycle of the turbine-generator and before shutting the unit down for a maintenance outage. The results from pre-outage and post-outage test comparisons can provide insight into the effectiveness of the outage as well as warn of potential maintenance problems. Periodic enthalpy drop tests during the operation of the turbine can provide information that reflects potential deterioration to the high-pressure (HP) and intermediate- or reheat- pressure (IP or RH) turbines. Tests should be performed both before and after the outage as a way to evaluate the effectiveness of the steam path and sealing repairs. Enthalpy drop efficiency tests are highly cost-effective tests and can be fairly accurate, ±0.25% if ASME PTC 6 type instrumentation is used [9, p. 265]. But consistent use of station instrumentation can provide meaningful test results if done at frequent intervals. The unit must be maintained at a constant load before performing an enthalpy drop test. The section inlet and outlet pressures and temperatures should be recorded while the unit is at steady load. The load preference is valves wide-open. Valves wide-open operation reduces the pressure drop across the valves, which is included in the section efficiency calculation. If the valves wide-open condition cannot be consistently maintained, use a consistent valve position for the periodic test as a minimum.

3-1

Unit Shutdown

The section efficiency is calculated from the following: •

Inlet condition entropy and enthalpy are determined from the inlet pressure and temperature

•

Outlet condition is determined from the inlet pressure and temperature.

•

Outlet condition isentropic enthalpy is determined from inlet entropy and outlet pressure.

These values are combined as follows to determine section efficiency: 100% x (Inlet enthalpy - Outlet enthalpy)/(Inlet enthalpy - Isentropic outlet enthalpy) Figure 3-1 is a plot of HP section efficiency over an approximate 14-year period with three outages. Tests were completed using station instrumentation, unit at steady load, and valves at a reasonably constant position. The initial dip in the third operating period was caused by bad (out of calibration) instrumentation. Notice the reset of section efficiency after each outage as well as the steadily increasing efficiency. Also note the last operating period when steam path changes were made. The resulting tests indicate that the new steam path components were less susceptible to solid-particle erosion (SPE) than their predecessors.

Figure 3-1 Section Efficiency Change During the Course of Three Outages

Another non-intrusive test to assess machine condition (such as tightness in the low-pressure [LP] section) is helium leak testing. Helium is sprayed around the LP expansion joints and areas that are subject to vacuum operation. A probe is placed in the air ejector discharge that can sense traces of helium. This test is used to assist in determining the tightness of or damage to the following items: •

Crossover pipe bellows

•

Condenser seal bellows

•

Extraction bellows external to the condenser

3-2

Unit Shutdown

A turbine supervisory instrumentation (TSI) system fitted with proximity probes provides realtime shaft and bearing information during operation. This non-intrusive tool is a health monitor during operation and a post-outage “tell-tale” sign of potential reassembly problems. Before the outage, the TSI system provides vital information regarding possible bearing repairs that may be required. This information would allow pre-outage planning for the potential repairs. A history of machine vibration information, obtained with shaft rider vibration or proximity probes, is also another tool that can provide pre-outage planning and machine condition information. Rotors that are susceptible to bowing and that have received midspan balance corrections over the operating period may be a warning of an increasing bow and a need for subsequent action. Flux probes installed in the generator air gap (the space between the rotating field and the stator) may be used to predict the condition of field end turns and, therefore, are a useful condition assessment and pre-outage planning tool. Coil distortion, abrasion, and foreign object damage can cause shorts in the ends of the coils. A shorted turn reduces the number of active turns in the field. The remaining coils must then carry more current to maintain the same flux density (magnetism) in order to produce the same generator output. Generator operation may not be significantly affected by the sorted turns. The impact on operation is dependent on location, magnitude, and the number of shorts. Rotor imbalance may occur when a turn is shorted and manifesting itself as a thermally (load) sensitive rotor. This condition may first be noticed as vibration changes. Air-gap flux probes can be used to aid in identifying this condition by detecting the flux distribution between each of the field coil slots. This test is done at speed with load. By implementing a comprehensive predictive maintenance program, a utility can reduce costly equipment outages. A fundamental component of this is infrared thermography (IR). It uses nonintrusive techniques to monitor the operating condition of equipment and components. The EPRI Infrared Thermography Guide, 1006534, [10] provides a great deal of helpful information on this technology. Key topics discussed are the science of thermography, selecting the correct instruments, inspection techniques, applications, and training. For a broader view on troubleshooting, the EPRI report System and Equipment Troubleshooting Guideline, 1003093, [11] is available. It has a structured approach that will be helpful to any plant personnel engaged in the troubleshooting of plant systems and equipment. In the chaotic environment when a problem occurs and in the rush to return the system or component to service, the true root cause of the problem may be overlooked. This report provides guidance to help decrease the time needed to identify and restore the system to operating condition. It also will increase the probability that the complete cause will be found and that the actual maintenance required will be done.

3.2

Generic Steps for Shutdown

Table 3-1 presents a sequence of steps that are typically involved when shutting down a unit in preparation for a maintenance outage. 3-3

Unit Shutdown Table 3-1 Steps Typically Involved with the Shutdown of a Turbine-Generator

3.3

Step

Activity

1

Reduce superheat temperatures, make appropriate control adjustments to reduce heat input to the turbine.

2

Perform a slow load reduction.

3

Isolate the hydrogen system (appropriate spool pieces removed).

4

Purge the generator.

5

Isolate the seal oil system.

6

Drain the EHC reservoir.

7

Drain the stator cooling water system and prepare clearances.

Critical Engineering Concerns

The most important concern in the turbine shutdown process is to control the thermal stresses in the rotors and casings. Keeping the steam temperature and the turbine metal temperature within design limits controls the thermal stresses. The temperature mismatch design limits vary from machine to machine as a result of varying geometries of the components. Large diameter rotors have higher thermal stresses than smaller diameter rotors with identical temperature ramp rates. The same is true for shells. The greater the shell thickness, the larger the thermal stress for identical temperature ramp rates. Although the results of excessive thermal stresses might not be immediate, repeated cycling of high thermal stresses can eventually cause cracking. The thermal stresses are highest on the surface because of the stress that is caused as a difference between the average metal temperature and the surface temperature. Cracking occurs when thermal stress exceeds the yield strength of the material. During the shutdown process, the surface stress becomes tensile, and cumulative cycling of this tensile stress can cause the metal to tear. At temperatures above the rated temperature, the material’s yield strength drops considerably. This causes the risk of cracking to increase. Because there may be no external symptoms of high thermal stresses, it is important to follow the design temperature ramp rates while shutting the turbine down. One problem that can lead to high thermal stress during the shutdown process is water induction. This usually occurs in the high-temperature sections of the turbine and can be caused by reheat attemperator valves failing to close, feedwater heaters backing up, and water in shell drains backing up. Water detection thermocouples are installed in many turbines and should be monitored during the shutdown process to identify the presence of water in the turbine. Another concern during the shutdown process is the accumulation of chemical deposits in LP turbine blades. The moist steam in the LP turbines contains chemicals that may be harmful to the blade attachment and dampening areas. It is important to reduce the amount of moisture in the 3-4

Unit Shutdown

LP turbine during the shutdown process to reduce the amount of chemicals that are deposited in the critical blade areas. These chemicals corrode the metal and can change the frequencies at which the blades vibrate. A change in the blade vibration frequency can lead to a blade failure caused by high-cycle fatigue.

3.4

Parameters to Monitor

The parameters used to monitor the turbine shutdown process are: •

Superheated steam temperature and pressures

•

Turbine metal temperatures

•

Differential expansion

•

Vibration amplitudes

•

Feedwater heater levels

•

Lube oil temperature

•

Bearing metal temperatures

•

Automatic oil pump starting

•

Steam turbine drains

•

Condenser vacuum

•

Gland seal steam

•

Turning gear operation

It is important to ensure that the generator is purged of hydrogen prior to access or performing generator maintenance. Begin the generator purge after the turbine-generator is on turning gear. Isolate the hydrogen system when the purge process has begun. This should include verifying that the hydrogen system is “physically” prevented from leaking back into the generator by removing a section of pipe (spool piece) between the isolation station and the generator. The seal oil system should be isolated after the generator is purged and depressurized. The generator may fill with oil if the seal oil system is left in operation with the stator depressurized. These activities are completed prior to release of the generator for disassembly. Monitoring the superheated steam temperature and pressure is necessary to keep the thermal stresses in the rotor and casings within acceptable limits. The steam and metal temperature differentials must be maintained according to the manufacturer’s acceptable limits. The best way to maintain these temperatures is by using a turbine stress monitor. Stress monitors allow the operator to operate the turbine at the optimum stress level. Operating at optimum levels reduces the possibility of metal fatigue and saves money during starting and loading by ramping metal temperatures at optimum rates. The turbine differential expansion is a measure of the rotor relative to the turbine casing. The expansion of the rotor is much faster than the casing; therefore, it is possible for the rotor to 3-5

Unit Shutdown

contact the casing if the differential expansion is too great. Differential expansion is not a problem if the thermal ramp rates are kept within prescribed limits. The turbine rotor vibration amplitudes and phase angles must be monitored during operation and shutdown of the unit. Maintenance costs are reduced when rotor vibration levels are kept at low levels. Some causes of high vibration amplitudes are: •

Unbalance

•

Failure of a rotating component

•

Rubbing

•

Oil whipping

•

Misalignment

•

Thermal sensitivity

During the turbine coast-down, the vibration amplitudes will increase as the speed of the rotor train passes through critical speeds. It is important to note the vibration amplitudes as the rotors go through these speeds. Turbine vibration amplitude limits are set by the manufacturers and should be kept within these limits. The water level changes in the feedwater heater during the shutdown process and must be monitored to keep water in the heaters from backing up into the turbine casings. Water backing up into the turbine casings can cause high thermal stresses, which distort the casings and can cause severe rubbing. If the water level gets high enough, it can come in contact with the rotating blades that can cause the blades to break. The unbalance resulting from blades breaking can result in catastrophic damage to the turbine. Some turbines have thermocouples in the casings, located in the top and bottom of the casings, to monitor casing differential temperatures. A temperature differential of over 50°F (10°C) may be a result of water entering the lower half of the turbine casing. The lube oil temperature should be reduced as the turbine speed is reduced. The lube oil temperature should be between 80–90°F (26.6–32.2°C) when the unit is put on turning gear. The lube oil will not have the proper viscosity to support the rotors if the temperature is too high. The bearing metal temperature should be monitored during coast-down to detect wiped bearings. Bearings that are wiped cannot sustain the hydrodynamic oil film at low speeds. A sudden rise in bearing metal temperature will result during coast-down if a bearing is severely wiped. The adjacent bearings may also have a rise in metal temperature if they are overloaded because of a wiped bearing. The motor-driven oil pumps should be checked during shutdown of the turbine. These pumps should automatically start when the oil pressure falls below a set pressure. The pressure at which the oil pumps automatically start should be recorded and compared to the manufacturer’s recommended limits. Some of the automatic oil pumps are the turning gear (ac) oil pump and the emergency bearing (dc) oil pump. 3-6

Unit Shutdown

The steam drains should be opened during the shutdown process to keep water from entering the turbine. The turbine manufacturers have operating procedures that give the proper sequence of opening drains during the turbine shutdown process. The condenser should be kept under vacuum as long as possible during the turbine shutdown. By keeping the condenser under vacuum, the amount of chemical deposits plating out in the LP turbine will be reduced. If used, the LP hood sprays should be turned off as soon as possible to reduce the amount of moisture in the LP turbine. When the vacuum is broken, the gland seal steam should be turned off. If left on, the gland seal steam could also allow moisture into the LP turbine blading. As soon as the unit has reached zero speed, the turning gear motor should be started and the turning gear should be engaged. Hot turbines must be left on turning gear until the turbine is thoroughly cooled to keep from damaging internal components. Each manufacturer has prescribed limits for turning gear operation.

3.5

Opportunities to Reduce Shutdown Time

One opportunity to reduce shutdown time is clearing equipment as soon as possible. This may mean issuing “short” clearances. A short clearance is defined as shutting down and isolating one system so that maintenance can be performed on another system. An example of a short clearance is the EHC system being cleared so that turbine maintenance can begin without the possibility of the turbine re-accelerating from turning gear: A short clearance of the EHC system occurs when the following are completed: •

The EHC pump motors are “racked out.”

•

The EHC fluid supply to valves is isolated.

•

The EHC pump discharge valves are locked in a closed position.

•

The EHC fluid recirculation or bypass valve is open, preventing fluid flow to turbine valves.

A short clearance is followed with a full system clearance when maintenance can be performed on that system. Another opportunity to reduce shutdown time is through accelerated cooling of the turbine through both internal and external processes.

3.6

Practices That Have Been Used to Reduce Shutdown Time

The main tool used to shorten shutdown time is the turbine stress monitor. The stress monitor is used to determine the fastest shutdown possible, staying within the stress limits of the turbine casings and rotors. The stress monitor uses finite element analysis to determine the highest stressed component of the turbine and keeps the stresses at that location within their allowable limit. Stress monitoring is done by controlling the thermal ramp rates of the turbine during operation. 3-7

Unit Shutdown

If there is no turbine stress monitor installed on the turbine, the manufacturer’s operating instructions must be used to shut the turbine down. These instructions give limits for reducing load when bringing the turbine off-line. Many of the manufacturers’ instructions are conservative, as a result of the time during which they were written. Until the 1980s, the turbine manufacturers were not using finite element analysis routinely to design turbine components. This means that there can be areas where the actual stresses referred to by operating instructions are below the allowable stresses for the turbine. When bringing the turbine down for a planned maintenance inspection, the critical time is from full speed no load until the unit can be taken off turning gear. This period is usually about 48 hours as a consequence of the large mass of metal involved and the amount of insulation on the turbine casings. The length of time to cool the turbine until taking the unit off turning gear can be reduced by cooling the turbine rotors and casings while shedding load from the turbine. If the turbine is brought off-line while the casing temperatures are high, it will take much longer to get to the point where the unit can be taken off gear than if the casings were cooler coming off-line. This cooling period can be reduced substantially by reducing the temperature and pressure of the steam during the shutdown process. Cooling of the casings is performed by opening the highpressure steam control valves to wide open, lowering the main and reheat steam temperature and pressure, and letting the load decay. When the desired temperature is reached, the remaining load can be removed by closing the steam control valves. It is important to note the amount of superheat in the steam to keep water out of the turbine casings. The turbine manufacturers give allowable limits for steam temperature and pressure for shutting the turbine down. Some operations that can reduce the turbine casing temperature after the unit has been placed on turning gear are: •

Remove control valves from valve chests.

•

Remove video inspection port covers.

•

Remove reheat turbine crossover pipes.

•

Remove reheat turbine crossover pipes.

•

Open shell drains

•

Ventilate the casings at these locations using forced air

Air cooling of the turbine casings can reduce the turbine cooling period, but it must be monitored to ensure that the turbine metal temperature ramp rates are not exceeded. Areas to monitor while air cooling the turbine are: •

Casing temperature

•

Casing expansion

•

Differential expansion

•

Eccentricity

3-8

Unit Shutdown

Steam turbine manufacturers often include cooling curves that give the rate of cooling for the high-pressure section under normal operating conditions. These cooling curves should be used to determine the amount of time needed to cool the casings after the unit is tripped. The curves are generally found in the operations section of the turbine instruction manual. 3.6.1 Overspeed Trip Testing The turbine overspeed trip test is necessary to ensure that the turbine will not reach a speed that will damage the turbine or generator in the event that the load is lost while the steam admission valves are open. The overspeed trip test allows the turbine to reach speeds up to 112% of rated speed on some units. Rotor speeds above 100% of rated speed create high stress and can result in damage to the rotating components during overspeed trip testing. The main requirement for an overspeed trip test is that the rotor bore temperature is above the fracture appearance transition temperature (FATT). Damage can occur if high stresses are imposed to rotors below the FATT. Before a turbine overspeed trip test can be performed, all bore locations on the high temperature rotors must be at least 450°F (232.2°C). The cold end of the high temperature reheat rotors is the exhaust end where the steam enters the crossover; therefore, the crossover temperature must be at least 450°F (232.2°C) before overspeed trip testing the turbine. The overspeed trip test should be performed during shutdown while the rotor bore temperatures are still high. This is done at full speed with no load on the turbine. After the testing is complete, the unit can be brought down for maintenance. If the overspeed trip test is performed on a cold turbine, 25% load must be carried for a minimum of four hours to warm the high-temperature rotor bores to allow overspeed tests be performed. One way to reduce the outage duration is to perform the overspeed trip test while the unit is down for maintenance. This test can be performed by removing the shaft extension where the overspeed trip is located and having the overspeed trip set under simulated conditions. This requires that the shaft extension be spun up on a special lathe and have the trip speed recorded. This requires the shaft extension to be at the design operating temperature in an oil bath. The simulated overspeed trip test will keep the entire turbine train from undergoing the high stresses involved by performing an actual overspeed trip test, as well as saving time during a shutdown of the turbine. 3.6.2 Electrical Trips vs. Mechanical Trips Electrical control systems have three or more speed pickups located in the front pedestal that measure the speed of the turbine rotor. By controlling the speed with electronic speed pickups, the electrical control systems do not require mechanical devices and are, therefore, more reliable and easier to maintain. The electrical control system can measure acceleration as well as speed, and electrical controls are used for overspeed protection of the turbine.

3-9

Unit Shutdown

Mechanical control systems on older steam turbines can be upgraded to electrical control systems, and the controls can be more reliable. Electrical control systems can control speed, load, and overspeed much more accurately than mechanical control systems. Mechanical control systems have governors, speed relays, pre-emergency governors, gear drives, cup valves, bellows, and pilot valves. These components, with their connecting levers and linkages, require extensive maintenance. Electrical control systems have fewer moving parts and, consequently, require less maintenance. It is easier to simulate an overspeed trip with an electrical control system, which makes periodic overspeed testing of turbines much easier. Valve tests are also easier to perform with electrical control systems. Although electrical control systems are better than mechanical control systems, they are expensive to retrofit onto older turbines. The addition of electrical controls to older turbines is often justified by more accurate speed/load control, lower maintenance costs, ease of testing, and better reliability. 3.6.3 Boiler/Reactor Feed Pump Turbine Controls The feedwater systems in many nuclear plants use steam turbine-driven feedwater pumps, which are necessary to supply a large flow of feedwater at the required pressure with high reliability. This type of pump driver in the feedwater cycle effectively uses the plant steam cycle to economically drive a large horsepower pumping operation. To establish good maintenance on the turbine/pump is important, considering that nuclear records have indicated that turbine-driven feedwater pumps are a high contributor to plant derates and forced outages. These turbines use one of three control systems: mechanical/hydraulic control (MHC), electrical/hydraulic control (EHC), and electronic digital control (EDC). The EPRI report Feedwater Pump Turbine Controls and Oil System Maintenance Guide, 1003094, [12] is available to provide maintenance information for the feedwater pump turbine MHC oil systems. The guide is intended to assist nuclear power plant maintenance personnel in troubleshooting and maintaining the MHC system. It contains a reference for understanding the control philosophy, technical descriptions for the different elements within the control system, and also routine and preventive maintenance guidance to improve reliability.

3.7

Removal of Covers and Crossover Piping

Install platforms on the low-pressure exhaust hoods for the removal of the crossover pipes during the setup week prior to the outage. An example of access platforms is shown in Figure 3-2.

3-10

Unit Shutdown

Figure 3-2 Example of Access Platforms

Every other crossover flange bolt is removed as soon as the generator is taken off-line and the short EHC clearance is in place. Unit condition is off-line with the turbine-generator on turning gear. The remaining flange bolts are removed as soon as the condenser vacuum is “broken.” The condenser vacuum is broken within three to six hours after the unit is taken off-line. Therefore, crossover piping removal occurs 10–12 hours after the unit is taken off-line.

3.8

Valve Disassembly

Scaffold erection to support valve disassembly should be completed during the pre-outage week but may continue into the first week of the outage. Access to combined reheat valves (CRVs) and separately mounted control valves (CVs) is the first priority, with separately mounted stop valves (SVs) a lower priority. CRVs and CVs are removed as soon as resources are available; typically, this will occur within the first 24 hours after the unit is removed from service but no later than 36–48 hours. Removal of the valve components provides a cooling path for the turbine components. Valve linkage removal occurs first with scaffolding modification as a likely subsequent activity depending on the valve arrangement and the original scaffolding installation. Cooling air is forced into the CVs toward the HP turbine to facilitate cool-down. The CVs that provide steam flow to the lower HP shell are the first priority for cooling airflow. Additional airflow is provided as the CVs/main steam leads feeding the HP upper shell flanges are unbolted and separated. Linkage removal for separately mounted control valves is estimated at six hours per valve. The remainder of the control valve disassembly is estimated at eight hours per valve. Completion of valve removal is resource-dependent but is typically completed within the first week of the outage. Separately mounted stop valves are disassembled in conjunction with the control valves. Total disassembly time estimate is 16 hours per valve and includes lid removal, pressure seal head removal, disassembly, etc. SVs are also resource dependent for disassembly, but disassembly should be completed during the first weeks of the outage.

3-11

Unit Shutdown

3.9

Practices to Accelerate Cooling

The following are opportunities to remove heat input into the turbine during the shutdown process: •

Reduce superheat temperatures by approximately 100°F (37.7°C) approximately 12 hours prior to shutdown begins to reduce the heat input into the turbine and lower valve and HP turbine temperatures.

•

Lower the main turbine lube oil supply temperature as soon as the turbine is on turning gear.

•

Purge the generator as soon as the turbine is on turning gear.

•

Remove the HP and IP horizontal joint lagging as soon as the unit is off-line.

•

Install air hoses to blow air through the horizontal joint bolting of the HP and IP sections after the horizontal joint lagging is removed.

•

Remove valves and insert air-moving devices to provide a cooling flow through the turbine.

3.10 Operations Performed During Turning Gear Operations A distinction is made between maintenance activities performed while on turning gear and while off turning gear with the lube oil system still in operation. The lube oil flowing to the bearings provides cooling to both the bearing and the turbine rotor. Turbine-generator disassembly begins as soon as the unit is on turning gear and the appropriate clearances are in place for maintenance to begin. Disassembly while on turning gear is limited to non-oil wetted areas. This includes valves, crossover piping, and joint bolting. More maintenance and disassembly options may be exercised after the hotter HP and IP sections of the turbine have decreased in temperature. Off turning gear disassembly can begin in the oilwetted areas and other areas of turbine-generator sections when certain conditions exist in the hotter HP and IP sections. The following is the sequence of activities to put the unit on turning gear with hot HP and IP sections: 1. The turbine-generator is taken off turning gear when the first stage metal temperature is reduced to approximately 500°F (260°C). 2. The lube oil system is left on to cool the bearing. 3. The bearing metal temperatures are monitored not to exceed 250°F (121.1°C). 4. The time rate of change of the bearing metal temperatures is also monitored to predict the expected maximum bearing metal temperature. 5. The bearing metal temperatures will initially rise because rotor heat is conducted through the rotor and rejected at the bearing. 3-12

Unit Shutdown

6. If a bearing metal temperature curve for a specific bearing begins to rise above 225°F (107.2°C) and approach 250°F (121.1ºC): a. The unit is returned to turning gear. b. The unit remains on turning gear while the first stage metal temperature decreases 50°F (10ºF). c. The cycle is repeated until the bearing metal temperature has stabilized below 250°F (121.1°C). 7. The lube oil system is momentarily removed from service to install oil supply toggle blanks, as described in Section 3.11. 8. The lube oil system is returned to service to continue cooling the HP section and bearings. 9. The lube oil system remains in service until the first stage metal temperature is lowered to approximately 400°F (204.4°C). 10. The lube oil system is then removed from service, and the bearing metal temperatures are monitored as noted above. Figure 3-3 is a plot of shutdown activities showing main steam temperature, generation, first shell metal temperature, turbine speed, and one of the HP bearing metal temperatures. The turbine was taken off turning gear after approximately 15 hours after the unit was taken off line. The first stage metal temperature was approximately 520°F (271.1°C).

3-13

Unit Shutdown

Figure 3-3 Plot of Shutdown Activities

Cooling rates and the effect on the bearing metal temperatures will vary, depending on the amount of cooling acceleration methods used. Figure 3-4 plots two different occasions that were monitored during cool-down when the entire unit was not to be disassembled. The case represented by the dotted line used accelerated cooling techniques, but the case represented by the solid line did not. The “blips” on the solid line (at 10+ hours and 30+ hours) represent the bearing metal temperature of an HP turbine bearing while lube oil was removed from service. Lube oil “blanks” were installed in the generator feed line during the 10+ hour activity in order to isolate the generator from the lube oil supply. Generator disassembly could begin after the blanks were installed. Lube oil was then returned to service in order to continue cooling the turbine bearings.

3-14

Unit Shutdown

The lube oil was off for approximately two hours while the blanks were being installed. It is interesting to note that after the lube oil was shut off, it took approximately seven hours to fully develop a steady-state temperature in the HP bearing that was being monitored. Lube oil was removed from service at approximately 420°F (215.6°C) during the accelerated cooling procedure so that turbine maintenance could begin approximately 30 hours after shutdown. For the non-accelerated procedure, if lube oil was shut down at approximately 420°F (215.6°C) first stage metal temperature, turbine maintenance could have begun at 48 hours into the outage. The outage time saved between the accelerated case (see Figure 3-4) versus the non-accelerated case is 18 hours. Both cases are well within the acceptable range.

Figure 3-4 Plot of Accelerated vs. Non-Accelerated Cool-Down Rates

3.11 Lubrication Oil Blanking Blanking of selected oil lines can accelerate the disassembly process of the turbine-generator. Generator disassembly can begin within 24–36 hours after the unit is removed from service, that is, after all the necessary unit clearances have been taken, selected parts have been tagged to be left untouched, and the oil supply lines have been blanked. An example of a toggle blank is shown in Figure 3-5. The figure on the left is a standard orifice strainer. The orifice strainer is removed, and the device on the right is installed. The orifice strainer threaded retainer is replaced with a threaded retainer that is drilled and tapped. An “allthread” rod is used to apply pressure to the gasketed sealing plug. A machine swivel or similar device is used to attach the “all-thread” rod to the sealing plug. When the oil system is restarted, the flow of oil to the bearing is blocked at the gasket surface of the plug.

3-15

Unit Shutdown

Figure 3-5 Example of a Toggle Blank

3.12 Removal of Insulation Removable insulation sections are usually associated with: •

Horizontal joints of the HP and IP shells

•

Main steam inlet flanges

•

Valve covers – stop/control/reheat

•

Crossover flanges

The insulation covers are usually removed as soon as the unit is removed from service.

3.13 Lagging Removal The turbine appearance lagging is removed during the pre-outage week. Appearance lagging sections should be removed in pieces as large as possible. The interconnection between pieces and assembly flanges assists in strengthening the sections during transportation. Sections should be removed and placed in outdoor storage during the outage.

3-16

4

DISASSEMBLY AND RECORDING CLEARANCES

A significant portion of critical path time involves the unbolting and removal of turbine shells prior to the cleaning and inspection of the turbine. When the shells have been removed, many power plants still rely on tape measures, gauges, feelers, sliding parallels, and other manual tooling to record turbine axial and radial clearances. This process is time consuming and is often difficult, given the distractions on the turbine deck during the disassembly process. Managing the massive amounts of information that need to be systematically collected and recorded can be greatly enhanced with some type of rapid feedback mechanism, for example, correctly relating measurements taken during disassembly to appropriate unit design measurements can prevent problems during turbine re-assembly. This section of the guidelines identifies, reviews, and compiles the practices and techniques that are normally involved or should be undertaken during the disassembly phase of a turbinegenerator maintenance outage, leading up to the point where the unit is ready for cleaning and inspection. The information contained within this guideline is primarily designed to identify and describe alternative methods or approaches that have been used to reduce the time required in the unbolting and removal of the turbine inner and outer shell. Methods, tools, and practices that can accelerate the recording of clearances at the time of disassembly are then discussed. A more detailed review of alignment procedures is found in Volume 3.

4.1

Planning Lay-Down Areas

Locations to place each component or group of components removed from the turbine-generator are determined prior to the outage and expressed on the turbine deck lay-down plan. The laydown plan may not only include areas on the turbine deck but also satellite areas located away from the deck. Turbine deck lay-down plan preparation is best organized by first identifying the requirements for placing and servicing each component. This includes any special requirements for each component. Therefore, it is important to evaluate and research the total impact of component activity, whether it is by in-house personnel or vendor support. Knowing the support and area requirements will help to prevent logistical difficulties such as those listed in the following common examples: •

The turbine deck lay-down plan identifies a footprint of the rotor. The vendor arrives requiring at least double the rotor footprint for doing the rotor boresonic inspection.

•

The typical power supply is 440 volt, 60 amps, three-phase. The vendor arrives needing 220volt, 30-amp, single phase.

4-1

Disassembly and Recording Clearances

•

The turbine deck lay-down plan identifies a footprint of the component work area around the equipment. The vendor arrives with three large storage containers (“sea vans”) of tools and equipment.

Identifying with a checklist and working through a systematic approach will help to ensure the appropriate placement of each component and access to perform inspections, repairs, etc. The items contained on the checklist should identify all pertinent information required to help formulate the lay-down plan. Additional descriptions and details are included in subsequent subsections. Table 4-1 is an example checklist for preparing a lay-down plan; not all items pertain to a specific component, and all items may not be essential during the entire outage. An example of unique requirements is making provisions for restroom and eating locations to support a large vendor work force that will be on-site for a limited time. Table 4-1 Checklist for Preparing a Lay-Down Plan

X

HP rotor

33,000 lb (14,969 kg)

X

X

X X

LP hood

66,000 lb (29,937 kg)

X

X

Field

163,000 lb (73,936 kg)

X

4-2

X

X

X X

X

XX

X

X

XX

X

X

XXX

X

Comments Other Personnel

X

Support Machine Shop

X

Water, Drain

Work Area Overhead

100,000 lb (47,627 kg)

Electricity

Outdoor Lay-Down Area

HP outer upper shell

Utility Requirements Other, Lighting, Air

Weight

Lifting Option

Picker

Component

Indoors

Location & Size

Standard shell maintenance plus steam lead flange face machining and seal ring replacement. Requires scaffolding and work platform for face machining. Requires two laydown activities, boresonic and bucket in work center. Condenser seal bellows replacement plus standard maintenance.

X

X

X

X X

X X

Rewind requires retaining ring removal, coil handling, and storage, work platforms.


4.1.1 Material Handling Methods and Considerations One important consideration in the turbine deck lay-down plan is material handling needs, especially to ensure access to components after they have been set on the turbine deck. Some components are set only once using the overhead crane; others are set and then must be handled to clean, inspect, and repair. How these components are handled or manipulated must be reflected in the lay-down plan. Material handling needs include placement of supports, racks, cribbing, pickers, portable gantry cranes, and other equipment. For example, the HP outer upper shell is removed from the unit and placed on the turbine deck with the horizontal joint bolting still in place (the lower nuts are removed, the upper nuts are still fastened to bolts). The bolts and upper nuts are later removed for cleaning and NDE. Placement of the HP outer upper shell on the turbine deck lay-down plan should include consideration for removal of the joint bolting. The only available resource to remove the bolts may be the overhead crane if the shell is placed with limited access. Placing the shell in another location may allow for faster removal with smaller portable devices. 4.1.2 Component Disassembly Requirements Often components are removed during the turbine-generator disassembly that later require additional disassembly. This includes such components as valves, lube oil pumps, shell components, and generator fields. Knowing construction and work scope for a component provides insight into the additional disassembly requirements. As mentioned, the HP outer upper shell is removed from the turbine with the bolts still “loaded.” These fasteners require removal to inspect the fastener, the shell spot faces, and the geometry around the fastener locations. Therefore, consideration must be given when placing the HP outer upper shell to include not only the maintenance to be performed on the shell and access to the fasteners, but also access to and placement of the fastener racks. 4.1.3 Component Work Scopes and Work Centers Often inspection or repair personnel are required to perform their activities wherever the component is located. This requires transporting their equipment to that location and then performing the activity. Lighting, contamination control, access, and other conditions may not be the best in that setting. For multiple components with consistent work scopes, the work center concept is used. Components are moved in and out of a work center as the required activity is completed instead of the personnel and their equipment being moved. The work center includes all necessary support and access to perform the required activity. An evaluation of the activity requirements is needed to determine whether the work center is the best solution.

4-3


Factors to consider in the evaluation of whether a work center should be considered include: •

Number of times a component is handled

•

Support available to perform the required function

•

Utilities – lighting/power/air/water/drains

•

Proximity to other activities and resources

•

Cleanliness

•

Access

The following is an example of a rotor work center that allows the following different activities to be performed in a single setting: •

Rotor runout checks

•


•

Rotor body repairs

•

Bucket repairs

Multiple rotors can be addressed if equipment and personnel resources are available. Figure 4-1 shows an example of a work center layout. The work center is located in close proximity to power for all of the support equipment, to air supply for hand tools, and to sufficient lighting to be able to perform activities; it is organized to minimize personnel travel to complete the required activities. Work tables are sized both in strength and in surface area to perform the required work scope.

Figure 4-1 Example of a Work Center Lay-Out Plan

4-4


Another example of a work center is the diaphragm repair area. The diaphragm repair area should be self-sufficient. Considerations for self-sufficient workstations include the following: •

Utilities – lighting/air quality/power/argon/air

•

Work shelves for tool boxes

•

Welding screens between work stations

•

Access to diaphragms – racks/stands/rigging and lifting resources

•

Diaphragm layout equipment

The turbine deck lay-down plan would arrange the diaphragms in proximity to the diaphragm repair area and group them by turbine section and expected repair scopes. The diaphragms expected to be repaired and the lighter diaphragms are placed within easy lifting range if a picker or other portable lifting device is used. The larger and heavier LP diaphragms would be stationed at the perimeter of the diaphragm repair area. These diaphragms are usually repaired in the diaphragm rack. Any moving of these diaphragms is done with the overhead crane. Figure 4-2 shows an example of a turbine deck repair area with work center layouts to match expected work scopes.

4-5


Figure 4-2 Lay-Out Plan with Work Center Layouts to Match the Expected Work Scope

4-6


For a generator, it may not be practical to ship a field for rewinding to a maintenance facility designed for rewinds. Therefore, it becomes necessary to do the rewind on the turbine deck or in other plant location. The “real estate” requirement for a field rewind is probably greater than for any other single activity during an outage. The activities and facilities generally required to rewind a generator field are listed in Table 4-2: Table 4-2 Activities Required to Support a Generator Field Rewind Item Clean room

Activity Rotor support retaining ring removal Field disassembly and reassembly

Sand/bead blast area

Coil cleaning

“Sea vans”

Material and equipment storage

Wedge cleaning

Description One-and-one-half times the length and three times the width of the rotor Coil length and width plus work-around room

Work rooms Personnel facilities Equipment

Induction heating for coil removal and baking

As a rule of thumb, adequate space utilization planning is key to the successful rewind of a generator during an outage. Other possible candidates for work centers are: •

Bearings – inspection, repair, fitting

•

Valves

•

Sealing areas

•

Packing – interstage, shaft end

•

Spill strip

•

Oil deflectors

4.1.4 Component Weights and Floor Loading During normal operation, the turbine-generator components are assembled on a large steelreinforced-concrete structure called a “turbine pedestal.” The pedestal looks like a large table with multiple legs and is a separate structure from the turbine deck. One design consideration during the construction of the pedestal is supporting the weight of all the turbine-generator components. During an outage, these components are disassembled, removed from the pedestal, and placed on the turbine deck and other possible locations.

4-7


Like the pedestal, the turbine deck has been designed to carry loads that may be placed on it during an outage, but its loading capacity is probably less than the turbine pedestal. Therefore, it is important to evaluate the turbine deck loading and structural consequences while the turbine lay-down plan is being orchestrated and before turbine-generator components are disassembled and placed on the turbine deck. The plant design architectural and engineering (A/E) contractor should have supplied turbine deck loading design information used during the original construction of the turbine deck. Loading should be described as live loading in pounds per square foot (kg/m2). The turbine engineer should compare the original conditions of the turbine deck and supporting structure to the current turbine deck conditions to determine if any changes have been made that will impact the live loading capability of the turbine deck. Examples of changes to look for are: •

Storage of other components on the turbine deck

•

Installation of other equipment on the deck or on other levels beneath or above the turbine deck

•

Facility additions

Component weight and component footprint are both required to determine turbine deck loading. Component weights are typically supplied by or available from the turbine-generator manufacturer. If unavailable, calculation of the component volume and application of material density should be a conservative weight estimate. Component footprint is important in the analysis because some turbine components are large and may span structural members so that loading is changed from concentrated to uniform. The moment implied to a given span for a simply supported concentrated load at the center is twice the amount if that same load were uniformly distributed; correspondingly, the beam bending stress is twice that of the concentrated load. It is important to include all support equipment in the loading plan that will be used in and around the turbine-generator components during the outage maintenance activities. Figure 4-3 shows an example of a loading reference determined for the turbine deck that can be included on the turbine deck lay-down plan. The area displayed in the figure corresponds to the support grid of the turbine deck and the live loading that can be supported.

4-8


Figure 4-3 Example of Loading a Reference for a Turbine Deck

4.1.5 Tooling/Support Locations Tooling and support equipment should be located as close to the outage maintenance activities as possible. Proximity locations reduce travel time during these maintenance activities. Consideration should be given to creating satellite support locations on or near the turbine deck to perform such activities as machining and welding. Having a satellite machine shop on the turbine deck reduces waiting and travel time during many of the small job activities that occur during outage maintenance and machine assembly. The utility’s primary machine shop supports other outage activities and may not be able to support the turbine-generator machining priority. A satellite machine shop may be supplied by a vendor in the form of a trailer or sea van, or it may be temporarily installed equipment on the turbine deck by the utility. The minimum equipment associated with a satellite machine shop should be: •

12" (30.48 cm) lathe

•

Bridgeport-style mill

•

Surface grinder

•

All the support tooling, fixtures, and perishable tooling

•

200 lb. (90.7 kg) capacity jib crane, if enclosed

4-9


One hundred percent staffing of the satellite location is not be required if the satellite machine shop is utility supplied. Instead, a machinist will be required to staff the location and support the scheduled activities. An example of required machinist support is during alignment and key fitting of diaphragms and shells. Table 4-3 lists examples of tooling and support that should be considered in the turbine deck laydown plan. Table 4-3 Tooling and Support for Turbine Deck Lay-Down Plan Support

Tooling

Tool room

Consumables, rigging (slings – small chain falls, come-a-longs), gauges (dial indicators, micrometers, precision tools), extension cords, extension lights

Rigging

Cables, lifting eyes, shackles

Wrenches

Racks, hydraulic, heating rods for bolting extension

Lifting beams Machining facilities

Main, portable, satellite locations

Metal fabricator

Welding machines, welding supplies, welding screens

4.1.6 Power/Air/Water Requirements The following utilities should be identified on the turbine deck lay-down plan: •

Power – voltage/amperage/phase/breaker locations

•

Air

•

Water

•

Drains

Repair equipment needs should be matched to locations of utility resources. For example, NDE may require a 200-amp power source to mag-particle (magnetic particle) test a turbine rotor. Placement of the rotor and/or work center in proximity to the power supply should prevent delays during an outage if the rotor must be relocated for the inspection. The power supply may also be brought to the rotor location and/or work center before the outage if the requirement is identified in advance, thus reducing delays during the outage. 4.1.7 Personnel Needs (Restrooms, Eating Facilities) Turbine decks may be constructed without adequate restroom and eating facilities that are required to support outage work force requirements. Identification of the required work force that will be working on the turbine deck will help to evaluate the need for additional restroom and eating facilities. Having these in the right proximity to the turbine deck activities further reduces personnel travel time at lunch and breaks. 4-10


4.2

Features of the Basic Rigging Plan

The rigging plan should contain the utility’s standard lifting and rigging requirements (rigger’s handbook) and component-specific rigging information. The utility’s rigging manual should contain safe loading information for lifting eyes, shackles, cables, cable arrangements, and other rigging equipment. Component weight information should be available and should be presented on the turbine lay-down plan. A catalog of lifting devices should be available and should contain: •

Item identifier

•

Quantity available

•

Name

•

Description

•

Use

•

Specification as appropriate

The lifting crew, before the lift, should review each critical lift. The review should include what is being lifted, the equipment to be used, who is controlling the lift, and where the component is going. The following two EPRI reports provide extensive lifting and rigging programmatic and practical information: •

Lifting, Rigging, and Small Hoist Usage Program Guide, EPRI, Palo Alto, CA: 2003, 1007914.

•

Rigger’s Handbook, EPRI, Palo Alto, CA: 2004. 1009706.

4.2.1 Rigging/Lifting Drawings for Major Components The minimum requirements to be included on a lifting drawing are: •

The weight of the component

•

Location of the center of gravity

•

Lifting points

•

Dimensions of the component

Figure 4-4 is an example of a lifting drawing that shows minimum lifting requirements; Figure 4-5 is an example of a detailed rigging/lifting drawing.

4-11


Figure 4-4 Example of a Lifting Drawing

4-12


Figure 4-5 Example of a Detailed Rigging and Lifting Drawing

4-13


Some components may require more details to rig and perform the lift. A comprehensive drawing could include the following items: •

Equipment identification

•

Rigging orientation

•

Rigging equipment

•

Loading

•

Lifting and clearance details

•

Setting location and orientation

4.2.2 Rigging Devices, Lifting Bars, Wire Rope, Synthetic Slings, and Shackles Figure 4-6 shows examples of special rigging fixtures for performing maintenance on CRVs. In each case, special fixtures were designed to facilitate not only the maintenance activities but also enhanced safety and performance of rigging and lifting.

Figure 4-6 Rigging Fixtures for CRVs

4-14


Figure 4-7 shows another example of developing a fixture to assist the rigging and lifting of a valve component in preparation for a maintenance activity. The turbine engineer should be involved in observing existing practices and working with the maintenance staff to evaluate both the safety and performance of those practices. Often, enhancements can be made to either ensure a safe lift or improve the ease and performance of the lift.

Figure 4-7 Rigging Fixture for a Control Valve Actuator

Lifting beams are used with rotors. They require preparation for each lift. The preparation will usually involve setting the span for the lift points on the beam as they relate to the center mass of the load. Figure 4-8 shows a sketch of a modification to a lifting beam that allows the adjusting turnbuckle to remain attached to the beam between lifts. The turnbuckle weighed over 100 lb (45.4 kg) and was awkward to assemble and rig to the beam. A minor modification allowed the turnbuckle to remain in place after each lift, making the rigging safer and quicker.

Figure 4-8 Modification to a Lifting Beam That Allows the Turnbuckle to Remain Attached While Lifting

Synthetic slings are available as replacements for wire rope cables used for lifting turbinegenerator equipment. An example of when to replace an existing wire rope lifting cable with a synthetic sling is when lifting the generator field. A long, heavy wire rope is wound around the field for the lift. The cable is awkward and heavy, and part of the activity includes wrapping the cable by hand. The replacement synthetic slings are light and easy to maneuver, making them a safer rig. The wire rope cable is also used to lift one end of the field when the field is still in the 4-15


stator. The cable is worked around the field by hand. Again, this is an awkward and difficult activity. The activity becomes more manageable with the use of the synthetic sling. The EPRI report Guidelines for Using Synthetic Slings for Lifting and Rigging, 1007676, [13] is available to provide guidance on the use of high-performance synthetic slings and also the inspection and removal criteria for these slings. 4.2.3 Practical Methods for Efficient Handling of Certain Components Improvements to existing rigging and lifting methods are easy ways to improve rigging or fixture performance. The following four steps are involved in the evaluation and improvement process: 1. Observe the activity. 2. Interact with the personnel performing the activity. 3. Research industry improvements for the activity. 4. Redesign and/or integrate state-of-art improvements into the activity. An example of a modification to an existing method and rigging fixture is shown in Figure 4-9 for generator field support.

Figure 4-9 Example of a Generator Field Support Modification

In the example, the bracket is assembled to the generator end shield and is used to support the field when the bearings are not in place. Maintenance activities require some horizontal and vertical movement of the field and, at times, some rotation of the field. A vertical adjustment to 4-16


the field position with the existing bracket was accomplished using jacking bolts. However, horizontal (side-to-side) movement and any rotation proved to be difficult. Revisions to the bracket assembly included: 1. Low friction pads inserted into the inner ring to allow rotational movement 2. Installation of horizontal jacking bolts for horizontal movement adjustments 3. Insertion of bearing surfaces beneath vertical jacking bolts for ease of horizontal movement 4.2.4 Special Turbine Tools Data are accumulated beginning prior to the unit comes off-line and continuing until the unit is on-line. Data collection begins with obtaining turbine vibration and operating data prior to the unit’s coming off line. Positional and clearance measurements are taken as soon as the sections are disassembled and components exposed, and reassembly information is gathered and assessed as sections are assembled and completed. Critical repair, replacement, and alignment decisions are made from the information gathered. Therefore, it is essential that the data be accumulated and analyzed and timely, appropriate action taken. The following are the essential elements of data collection and analysis: 1. Recording – Accumulating information 2. Verification – Checking the data as reasonable and evaluating whether they are within tolerances 3. Presentation – Concise viewing of the data in a meaningful format 4. Comparison – Trending against historical information Often, some aspect of data collection occurs as part of the turbine outage critical path. Therefore, any effort to reduce time in the appropriate phase is beneficial. Automated data collection hardware and software are one way to reduce the amount of information that is read, written, and transcribed when taking clearance measurements. Electronic alignment gauges can help with the reading portion of data collection. A fully automated system would record the information and store it for download. Data are verified as either reasonable or within tolerance. “Reasonable” means that the readings make sense and are reflective of what was expected. Tolerance evaluation requires knowing the design size and tolerance and then comparing the readings. An automated system would compare the readings taken with the design nominal size and the applied tolerance. Readings out of tolerance are flagged for attention and disposition. The information is presented in a readable tabular or similar format. Data recorded are often compared to previous readings taken from the last inspection. A complete system would include the ability to compare and trend current and historical data. 4-17


4.3

Scheduling Overhead Crane Time

The primary material handling device on the turbine deck is the overhead crane. It is used to lift and transport turbine-generator components during disassembly, repairs, and reassembly. The greatest use of the overhead crane occurs during disassembly. The second dense use period is during reassembly. The best method to ensure effective use of the overhead crane is through a coordinator. The coordinator’s responsibility is to: •

Know the turbine-generator activity requirements - rigging plans/rigging preparation status

•

Set current activity priorities

•

Know where lifts/loads are going through the use of the turbine deck lay-down plan

•

Receive and schedule lift and transport requests

The coordinator then organizes the tasks with the crane operator for optimal utilization of the crane. The remote radio control of the overhead crane is a valuable asset during many of the transport periods. The remote control allows the crane operator to be on the turbine deck and interact with the turbine deck personnel while operating the crane. The crane operator becomes an effective resource in a multiskill/cross-skill environment. The crane operator may assist in rigging preparation and observing for clearances while operating the crane from the turbine deck. As a safety, precautionary note, if a utility has more than one radio controller (box) for the crane and if either box requires maintenance that will be done on-site, be sure that the crane is disabled.

4.4

Moving Without the Overhead Crane

Secondary lifting devices that support the turbine deck overhead crane are easily integrated into the turbine deck lay-down plan and maintenance activities. Pickers can be used outside the overhead crane lifting area in locations such as separately mounted control valves. Installation of jib cranes over valve locations can also supplement pickers in these locations. To effectively use pickers, portable gantry cranes, forklifts, and other lifting devices requires space planning on the turbine deck lay-down plan. Effective use of these secondary lifting devices reduces overhead crane priority conflicts.

4.5

Special Storage Considerations

Material handling of turbine-generator components includes how they are transported and what they are transported in. Design of the transport/storage devices should include an understanding of activities to be performed on the component while it is in the transport/storage device. An example of a design consideration is evaluating what maintenance activity can be performed

4-18


while the component is in a rack and then positioning the component at a working height in the rack. Therefore, design considerations should at least include: •

Ease of use

•

Access to component - single-item storage

•

Access to other components - multiple-item storage

4.5.1 Racks for Diaphragms Diaphragm transport/storage racks should place the diaphragms in a vertical position, as shown in Figure 4-10, with sufficient space between the diaphragms to allow access on both sides of the diaphragm.

Figure 4-10 Example of a Diaphragm Transport and Storage Rack

Typical activities that can be performed on a diaphragm while it is in the transport/storage rack are listed in Table 4-4. Table 4-4 Tooling and Support for Turbine Deck Lay-Down Plan Activity

Specifics

Sandblasting Cleaning Inspection

Steam path, body, diameters (when assembled), roundness (when assembled)

Repairs

Partitions (large diaphragm, few and minor), sealing areas (spill strip removal and installation, packing replacement installation, horizontal joint repairs), crush pin

Fasteners

Removal, thread repair

4-19


As shown in Figure 4-11, oil deflector racks can be constructed in a similar fashion as diaphragm racks. The advantage of using oil deflector racks is condensing the space requirement for oil deflector storage (vertical vs. horizontal) and access to the deflectors for measurements. The following oil deflector rack example groups the oil deflectors together for a particular standard. The oil deflectors are positioned so that workspace is available between the oil deflectors when they are assembled.

Figure 4-11 Example of an Oil Deflector Rack

A similar style rack can be constructed for packing casings. Racks potentially decrease diaphragm maintenance activities, reduce handling time, and reduce the space requirements on the turbine deck for diaphragm storage.

4-20


4.5.2 Valve Stands, Rotor Stands, Mandrels, Try Bars, and Stub Shafts Stands and fixtures are fabricated to accommodate specific valve maintenance activities. Figure 4-12 shows a simple fixture that holds a control valve stand in an inverted position to facilitate inspections and maintenance measurements.

Figure 4-12 Example of a Fixture Holding a Control Valve

Manual rotation of rotors frees overhead crane support. Fabricated rotor stands with rollers incorporated into the design as shown in Figure 4-13 allow hand rotation of the rotor when doing the following activities: •

Sandblasting

•

Inspections

•

Repairs

4-21


Figure 4-13 Example of a Fabricated Rotor Stand with Rollers

A bearing fitting mandrel as shown in Figure 4-14 can be machined to facilitate bearing fitting for both tilt pad and journal bearings. The individual tilt pads from a tilting pad bearing should be checked against a mandrel for proper curvature. The mandrel should be straight and round within 0.001" (0.0254 mm), with at least a 63 microinch (1.8 micrometers) surface finish. The mandrel diameter (B in sketch) should be equal to the actual rotor diameter plus the machined bearing clearance. Each pad fitted to the mandrel should have a minimum of 80% contact. Fitting is done by “bluing” the mandrel and then hand scraping the babbitt material at the contact points.

Figure 4-14 Example of a Bearing Fitting Mandrel to Check Tilt Pads

Cylindrical or elliptical bore bearings may also be fitted to a mandrel as shown in Figure 4-15. The objective of fitting these bearings is to ensure clearance at the sealing bore of the bearing to the rotor journal, which will prevent bearing contact to the rotor during operation. An elliptical bearing has a horizontal clearance that is greater than the vertical clearance. The ellipse is obtained by machining the bearing bore to the larger horizontal diameter (horizontal clearance plus the journal diameter) with shims inserted in the horizontal joints of the bearing. The shim thickness is equal to the horizontal clearance minus the vertical clearance. The shims are removed and the bearing is reassembled to machine the sealing bore.

4-22


Figure 4-15 Example of a Mandrel to Check Cylindrical or Elliptical Bearing Bores

The mandrel diameter for an elliptical bearing should be equal to the actual rotor diameter plus the machined bearing vertical clearance with a mandrel tolerance of +0.000"/-0.005" (+0.000/ -0.127 mm). The mandrel is “blued” and set into the bottom of the bearing. The indicated isolated contact spots of the seal bore are carefully hand-scraped using a babbitt shaving tool. A “try bar” is machined to check the alignment and wear of components that must maintain an axial relationship to one another. For example, a try bar can be machined and used to check the alignment and wear of a control valve sleeve that guides the control valve disc. The try bar is machined 0.002" (0.0508 mm) smaller than the associated bushing design diameter of the control valve stand. The tolerance for machining the try bar is ±0.001" (±0.0254 mm). The valve stem and crosshead are removed from the control valve stand and the try bar inserted. A dial indicator is set to sweep the inside diameter of the sleeve of the control valve balance chamber. The sleeve and disc are inspected and replaced as appropriate if the total dial indicator reading exceeds a set value. 4.5.3 Shell Racks, Supports, and Cribbing Figure 4-16 shows an example of a shell rack for a HP upper inner shell. The rack places and holds the shell in an inverted position. Inspection and maintenance may be performed to the shell internal areas, horizontal joint, and sealing bores with the shell in this position. The inlet expansion pipes are also positioned to be cleaned and inspected.

4-23


Figure 4-16 Example of a Rack for Holding an HP Upper Shell

Shells, casings, and hoods that are removed from the turbine are set in an elevated position on the turbine deck. The height of the elevated position may be set for convenience of inspection, maintenance of the horizontal joint, and access to the internal area of the shell, casing, or hood. Some components, such as the HP outer upper shell, can be removed from the turbine still “loaded” with horizontal joint bolts; the elevation of the shell is then determined by the length of the bolt protrusion. Figure 4-17 is an example of fabricated shell supports that are used to replace oak cribbing.

Figure 4-17 Example of a Fabricated Shell Support

The generator field and other large and heavy turbine-generator components are typically set on oak cribbing as either a temporary or a maintenance setting. Oak cribbing may not only be large, heavy, and awkward to manually position, but also its load bearing capability may be insufficient for heavy load settings. 4-24


Figure 4-18 is an example of a support that replaces oak cribbing when doing generator field removal from the stator. The removal procedure requires re-rigging the field at an interim removal position. The field must be lowered, temporarily supported, re-rigged, lifted, and then the removal process continues. A temporary support rig was fabricated for use instead of manually placing cribbing for the interim re-rig. The rig uses common “utility trailer” jacking roller assemblies that allow the rig to be rolled under the suspended field. After moving the temporary rig into position, the jacking roller assemblies are swung to a storage position and the centerline jack screw support is raised to contact the field as it is released for re-rigging.

Figure 4-18 Example of a Support for Generator Field Removal Without Cribbing

4.6

Bolt Removal Practices and Techniques

Many different shapes, sizes, and configurations of fasteners are used in the assembly of the turbine-generator. The largest diameter and longest are usually associated with assembly of the HP inner and outer shells. Other locations that use special access fastener features or tooling may present unique challenges for assembly. Although they look different, are different sizes, and require different assembly techniques, they have one thing in common: keeping the assembly closed and tight during its duty cycle. Assembly closure is a function of stretching the fastener and compressing the joint. The stretch imposed on the fastener is a result of the material used, the size of the fastener, the load applied during assembly, and an evaluation of the load applied in service. The fastener assembly design stress and required loading determine the allowable preload. Typical allowable steel alloy preload stress ranges are between 30,000 psi (206.85 MPa) (0.0010" stretch per inch of active body)(0.0254 mm per 2.54 cm of active body) and 45,000 psi (310.275 MPa) (0.0015" stretch per inch of active body) (0.0381 mm per 2.54 cm of active body). The techniques to impose the preload and close the assembly are as varied as the fastener types. Assembly methods used to stretch the fasteners are: •

Mechanical – turn of nut/sledge hammer

•

Heat – Flame/hot air/ cal rod/induction

•

Hydraulic – tensile direction/radial direction/reaction 4-25


The amount of stretch is determined by: •

Measurement – turn of nut/micrometer/ultrasonic

•

Torque – wrenches/mechanical/hydraulic

Each assembly method has its advantages and disadvantages. Cold stretching or using mechanical methods tend to gall the interface surfaces of the fastener, either the threads or the load-bearing surface. Hydraulically tensioned methods stretch the fastener without galling but require special fasteners. Thermal stretching requires the fastener to heat faster than the assembly and measuring the stretch requires cooling the fastener, which makes the time to complete the assembly cycle longer. Disassembling a hot assembly requires first cooling the assembly sufficiently to gain a fastener heating temperature differential advantage. Table 4-5 provides an accuracy comparison of the various preload methods. The most accurate and efficient method should be chosen for critical closing joints, for example, main steam inlet flanges. Tightening methods using power drivers are similar in accuracy to equivalent manual methods. Table 4-5 Comparison of Accuracy Between Different Preload Methods [14] Method

Accuracy

Method

Accuracy

By feel

±35%

Computer-controlled wrench below yield

±15%

Torque wrench

±25%

Computer-controlled wrench yield-point sensing

±8%

Turn-of-nut

±15%

Preload indicating washer

±10%

Bolt elongation

±3–5%

Strain gages

±1%

Ultrasonic sensing

±1%

Knowing the joint configuration and assembly process is important when during component disassembly. As an example, many HP and IP sections are designed with lower shells carried by the upper shell and with the lower shell virtually unsupported. However, when maintenance is performed, the lower shell is supported. “Maintenance” shims are inserted between the lower shell and turbine pedestal structure before removing the horizontal joint bolting. If the “maintenance” shims are not installed, the lower shell will drop when the horizontal joint is unbolted. The HP and IP outer and inner horizontal bolts are heated to disassemble the horizontal joint. Then cal-rod heaters are inserted into the center bores of the bolting; the heating causes the bolt to expand and lengthen so the nuts can be turned. The fastener should be cooled as soon as the nut is loose to minimize heat buildup in the joint. Loosen the fastener nut at least two full turns to prevent re-engaging the nut as the fastener cools. Horizontal joint distortion will normally open further in the center than at the outer axial positions. Therefore, starting the joint unbolting at both axial ends simultaneously and continuing toward the center allows the joint to open as the bolts are loosened without re-engaging the fasteners.

4-26


4.6.1 Identifying the Necessary Personnel for Unbolting the Turbine-Generator The number of personnel required for unbolting the turbine-generator depends on the process that is being used. Casing bolts are very large and must be heated to relax the bolt tension. The temperature of the casing bolt must be elevated to approximately 300°F (148.8°C) to relax the tension in the bolt. The most common method of relaxing the tension on the casing joint bolts is to use calorimeter (cal) rods to heat the bolts. Another method of relaxing the bolt tension is to use gas heaters. The fastest method for relaxing the bolt tension is to use induction heating. When using cal rods to relax the joint bolts, the mechanics work in pairs to remove the nuts. One mechanic works above the horizontal joint, while the other works below the joint. The cal rod method requires 30–45 minutes to relax the bolt tension, so many bolts are heated at once. Both sides of the casing (left and right) are worked concurrently; accordingly, four mechanics are needed for each casing. The cal rods can be shorted out while moving them, and it is often necessary to have an electrician available to repair shorted cal rods during the disassembly process. The cal rods should be in good working condition before starting the outage. For the cal rods to be effective, they must be matched to the bolt for length and diameter. The operator must take care while using cal rods so that the rods do not short out and cause an injury. The hot-gas bolt-heating method uses an oxy-acetylene torch, compressed air, and a special gas heating device. The torch heats the compressed air, which is then forced through a tube to the bottom of the bolt. The bottom of the bolt is sealed off so that the hot air rises back along the length of the bolt and escapes through an exhaust below the heating chamber of the tool. These gas bolt heaters are called “hot rods.” The time that this method takes to relax the bolt tension is between 10–30 minutes. One mechanic works above the horizontal joint, while the other works below the joint. Both sides of the casing (left and right) are worked concurrently; thus, four mechanics are needed for each casing. It is important to size the gas heater to the bolt to properly relax the bolt tension. It is also important to monitor the heat input and airflow to get the temperature correct. The operator must be extremely cautious while using the gas heater so that the torch does not start a fire. Induction bolt heating is the fastest method of relaxing the bolt tension. In induction heating, a rod is inserted into the center of the bolt and power is applied. The induction rod is sized so that the bolt extension is achieved within a few minutes. A small bolt can be elongated in two or three minutes, and a large bolt will take around five minutes to elongate. The induction heating method is very accurate, and after the power is turned off, the bolt does not elongate further. The induction rods are water cooled and have large power sources, which must be kept within 20 feet (6.1 m) of the rods. This method of heating requires one operator per power source and four mechanics to work each side of the turbine to remove the nuts from the bolts. Two power sources are used concurrently so that both sides of the turbine are worked together; as a result, the induction heating method of bolt relaxation requires two operators and eight mechanics per casing. 4-27


The operator must be careful not to overheat the bolt, so that the bolt temperature does not approach the tempering temperature. A timer shuts off the power source to ensure that the proper bolt extension is not exceeded. The low pressure (LP) turbine exhaust hoods do not require bolt heating and, therefore, can be unbolted quickly. The exhaust hood bolts are usually removed with pneumatic wrenches. Two mechanics can work concurrently on each hood to unbolt it. The crossover pipes require two mechanics per flange to unbolt. The crossover pipe flange bolts are small and can be removed with pneumatic, hydraulic, or knocker wrenches. The LP turbine casings also have small bolts that do not require heating to remove. Two mechanics can work on each side during the LP casing disassembly. Both sides of the casing should be worked concurrently, so four mechanics are needed for each LP casing. The steam leads have small bolts, and each lead should have two mechanics working to remove the bolts. Also the steam control valves can be worked using two mechanics per valve. The rotor couplings can be worked using two mechanics per coupling as well. Special coupling bolts allow the couplings to be disassembled quicker, but they still require two mechanics per coupling to operate the hydraulic tool. Generator bolting, like the LP hoods, does not require bolt heating and are a smaller diameter than turbine shell bolting. Typical sizes may range from only 1–2" (2.5–5.1 cm) diameter for end shield components. Therefore, disassembly can be quick, using pneumatic or hydraulic tools. Care must be taken on reassembly when preloading these fasteners. The fastener material strength is matched with the internal thread component that is usually plain carbon, non-alloy, low-temperature, structural grade steel. The corresponding fastener rating is equivalent to a Society of Automotive Engineers (SAE) Grade 5 bolting material (proof strength: 85 ksi [586 MPa]; UTS: 120 ksi [827 MPa]; YS: 92 ksi [634]). During an outage, it is easy to replace any lost or damaged SAE Grade 5 bolts with a higher strength fastener from plant stores. Often, SAE Grade 8 bolting material (proof strength: 120 ksi [827 MPa]; UTS: 150 ksi [1034 MPa]; YS: 130 ksi [896 MPa]) is used. If a stud-type bolt is replaced in this manner, the pre-load limit of the original bolt should be applied to avoid overstressing the threads. For a through-type bolt, the higher strength fastener can be pre-loaded to its prescribed standard. It is necessary to have a crane operator for the entire disassembly period. There may also be a designated rigger who works with the crane operator to supervise all crane lifts. The mechanics who are used to unbolt the turbine components also assist with the rigging, lifting, cribbing, and placing of turbine components. 4.6.2 Available Tools Needed Many special turbine and generator disassembly tools are included with the purchase of the unit. Examples are listed in Table 4-6. These tools are specific to the unit and must be kept in the powerhouse during the unit’s life. These special tools should be kept on the turbine deck and should be locked in metal boxes to ensure that they are available when needed. During a forced unit outage, it is important to be able to get to these tools quickly to begin the disassembly 4-28


process. It is imperative that the special tools are kept in good working order, and they should be inspected before and after each use. Each tool should be marked with the turbine serial number to avoid mixing them up with tools from adjacent units. Some special tools are too large to be kept in boxes and should be placed in designated areas. Each turbine-generator should have its own toolbox, and each toolbox should be clearly marked with the unit number and/or turbine serial number. If it is necessary to borrow a tool from another unit’s toolbox, the tool should be placed back in the original toolbox at the completion of the job. Special tools are designed and used to aid in the collection of data during the turbine inspection. These tools should be kept in the unit-specific toolbox for future outages. Table 4-6 Tooling and Support for Turbine Deck Lay-Down Plan Category

Specific Tools

Large special tools

Rotor-lifting beams, wire rope slings, generator field skidpans, generator stator trunions, bearing disassembly-lifting devices for generators and low pressure turbines

Toolbox tools

Casing jacks, casing guide bars, knocker wrenches, bolt heaters, bolt extensometers, special hydraulic wrenches and wrench, adapters, hydraulic coupling bolt tensioning tools, temporary rotor supports, temporary coupling bolts, coupling jacking bolts, crossover expansion joint lock bolts, valve try bars, valve lift measuring rods, EHC system flushing blocks and flushing valves, bearing mandrels, valve disassembly tools

Special generator tools

Temporary rotor supports, end bell sealant pump, hydrogen seal disassembly sockets and extensions, hydrogen line spool pieces

Designed unit-specific tools

Rotor temporary thrust, shaft extension alignment tools, valve seat lapping tools, oil line blanks, jack supports

Some turbines have temporary support keys that are bolted to the pedestals or standards next to the permanent keys. These temporary keys should be cleaned and bolted to the pedestals at the end of the outage. Turbine bolt disassembly is performed by heating the bolt to relax the bolt tension. Resistance heating has been used for many years to relax bolt tension. A newer and faster method of relaxing bolt tension is induction heating. Induction bolt heating is up to 10 times faster than resistance bolt heating. Induction heating is also used for generator retaining ring removal and other special heating requirements. Induction heaters have special safety devices installed to ensure that they do not heat the bolt past its unique tempering temperature. One other bolt tensioning device that is used for turbines and valves is the hydraulic wrench.

4-29


4.6.3 Useful Tools and Techniques for Different Applications The ability to effectively open a hot HP or IP section has been enhanced through the application of induction bolt heating. Cal rod heaters and flame/hot air heating have inherent thermal transfer limitations. The speed at which a fastener can be stretched without first cooling the joint/fastener has increased through the adaptation of induction heating. Induction heating uses a highfrequency device that excites molecular activity in the fastener, causing the fastener to increase in temperature and length. 4.6.4 Bolt Removal Sequence The removal of bolting on the turbine-generator should be performed in the correct sequence to keep from damaging the hardware and to allow for the fastest possible disassembly. Before the removal of bolting, many preliminary operations must be performed. A sequence of these possible activities is shown below: 1. Remove appearance lagging. 2. Install crossover scaffolding. 3. Locate shell pocket jacks and all required rigging. 4. Remove bolting insulation. 5. Remove LP manhole covers and install ventilation blowers. 6. Remove crossover piping. 7. Remove exhaust hoods. 8. Remove joint bolt steam shields in LPs. 9. Remove packing cover upper halves. 10. Record rotor radial position. 11. Remove axial shell keys. 12. Remove internal keys. 13. Transfer from running to building keys. 14. Install scaffolding or build decking to allow access to bolting. 15. Apply penetrating oil to joint bolting and internal fits. 16. Disassemble leak-off piping and mechanical linkages on shell-mounted valves. 17. Disassemble steam lead flanges and separate flanges by jacking and blocking. 18. Perform rotor thrust check. 4-30


19. Tap and lubricate jackscrew holes. 20. Observe internal bolting warning plates. 21. Disconnect all thermocouples on upper half of casings. During the cooldown period, arrangements are often made to air cool the turbine to reduce the amount of time that the turbine is on turning gear. Air cooling requires that access ports and drain valves on the turbine be opened so that air can be blown through these holes to assist with the cooling process. Steam control valves can also be removed to assist with the cooling process. These access ports and shell drains vary for each unit, and the engineer should determine the best means of air cooling for each turbine casing. Turbine casings are subject to thermal stresses, and relaxation of the metal occurs due to these stresses. Creep also causes distortion of the casings. The casing distortion is greater in the center of the casing than on the ends. The high stress on the bolting due to casing distortion requires the outer bolts to be removed first and then work toward the center. Body bound (fitted) bolts or tapered bolts must be removed before loosening any of the joint bolting. When unbolting casings with both vertical and horizontal joints, the vertical joint must be unbolted first. The process of unbolting the joint requires the loosening of bolts alternately from one side to the other, working from the center toward the ends of the casing. If the nut will not unscrew from the bolt after the bolt is relaxed by heating, the nut should be destructively removed. The fastest method for removing nuts is by the carbon arc (air arc) process. The carbon arc process allows the destruction of the nut without damaging the bolt. The lower nuts should be removed from studs, which allows the stud to be supported by the casing. The studs can later be removed from the upper casing after the casing has been supported on cribbing on the turbine deck. This reduces the outage duration by allowing the studs to be removed at a later time with other work performed. The turbine casing and joint bolts are very hot during the disassembly period, and the workers must take precautions to keep from being burned by the hot metal. The generator is a composite assembly, unlike HP and IP turbines where the rotors are separately supported in standards. The generator field is integrally supported within the assembly of the stator. Generator end shields are the components that are designed to withstand the gas pressure of the generator, seal the shaft, and carry the weight of the rotor. Therefore, during disassembly of the generator, the weight of the field must be transferred from the end shields and its components to the stator using temporary rigging. Precautions must be taken throughout disassembly and reassembly to protect the stator end windings and the field during rigging and transferring the weight of the field. A general sequence for the disassembly of a typical GE-type generator is shown in the list that follows: 1. Remove the appearance lagging (removed prior to outage start). 2. Open the bushing box. 3. Remove instrumentation/connections (vibration probes, thermocouples). 4-31


The following steps are applicable to both the turbine and exciter ends of the generator. It is assumed that the exciter has been removed, the turbine-generator coupling has been disassembled, and the generator has been purged of hydrogen. 4. Remove the outer oil deflector upper half on both ends. 5. Remove the bearing cap. 6. Remove the bearing upper half. 7. Remove the bearing upper half. 8. Remove the hydrogen seal upper half. 9. Remove the inner oil deflector. 10. Remove the fan nozzle ring segments. 11. Unbolt and support the fan nozzle ring. 12. Remove the fan segments. 13. Remove the air gap baffles. 14. Install the field supports. 15. Remove the outer oil deflector lower half. 16. Remove the bearing lower half. 17. Remove the hydrogen seal lower half. 18. Remove the inner oil deflector lower half. 19. Remove the gap baffle. 20. Remove the lower end shield oil piping. 21. Unbolt and lower the lower end shield. 22. Install the skid pan and shoe, and remove the field. 23. Remove the inner end shield. 24. Unbolt and remove the hydrogen cooler heads. 25. Remove the hydrogen coolers.

4-32


4.6.5 Required Inventory of Bolts Fastener usage should be reviewed as part of both the pre-outage and post-outage activities. A review of historical data should show the locations and types of fasteners that have been used. An analysis of usage should provide a list of what should be available during the upcoming outage. The matrix shown in Table 4-7 is derived from reviewing outage fastener usage. Each row represents a different fastener size for the fastener type and use listed. Not all fastener data are listed. The outage use information was reviewed and condensed to those fasteners that had high replacement requirements. It is interesting to note that the types of fasteners requiring replacement were in areas such as the diaphragm horizontal joint bolting, packing casing bolting, and small flange bolting. Typically, these locations use smaller fasteners that are expendable when stuck or easily replaced when damaged. Large fasteners for horizontal joint bolting require replacement on occasion but not at the percentage or frequency interval of the smaller bolting. Therefore, it is prudent to either stock, have available, or have identified and arranged quick turnaround resources before the outage for the smaller fastener requirements. Larger fasteners may require a different track. Inventory reduction of larger fasteners can be accomplished in a variety of ways. Usually, larger fasteners are unique in either size or material and, therefore, not readily available. Identifying fastener-manufacturing resources before the outage is an approach to reduce stock. The requirement to meet outage needs is the identification of replacement requirements early in the outage. Higher temperature fasteners may require a unique material specification or size; for that reason, these requirements should be identified and coordinated with the fastener manufacturer before the outage. Another alternative is stocking the material and supplying it to the fastener manufacturer.

4-33

Disassembly and Recording Clearances Table 4-7 Outage Fastener Usage Record Fastener Type

Use

# of Possible Uses (Each row represents a different fastener size.)

Historically Used

Socket head bolt

Diaphragm joints

28 34 8 28 16 6 6

10 21 6 13 6 3 4

Hex head bolt

Packing casing

32 48 8 8 40 16

3 6 8 3 4 4

Socket head cap screw

Bearing joint

4 4 4 4

3 4 4 3

Through stud

X-over flange

60 48 48

5 3 5

Tap stud

Valves

20 10 32 15

2 7 4 6

Through bolt

Leak-off flanges

16 20 16

5 4 4

A backup plan could be to identify and stock the largest fasteners in each material. Stocking the fasteners with the largest diameter and length can provide emergency material to remachine the larger fastener into the required smaller fastener.

4.7

Taking Axial and Radial Clearances and Their Use

Measurements taken during disassembly between stationary and rotating components provide an insight into machine condition. It is possible to miss or not recognize machine problems if opening measurements are not taken. Clearance readings are taken after the rotor has been set in the design reference axial position and the turbine lube oil system has been shut down with rotor couplings still assembled. The reference axial position is external to the steam path, and measurements should be at the same reference position as the last time the rotor was assembled. The reference position should be accessible even with an assembled section. A typical location for measuring the reference axial position is in the standard or bearing housing where the back 4-34


face of the coupling or a step on the rotor can be measured on both the left and right sides of the rotor. The accuracy and repeatability of all measurements are important to effectively describing the condition of the turbine. An alignment primer, dealing with both coupling alignment and internal alignment using a tight wire or other measurement instruments, can be found in Volume 3, Balancing and Alignment (1008856) [15] of this multivolume series. The primer covers significant issues that should be considered when such work is being performed. In addition, a user manual [16] for coupling alignment software (TGAlign) is available. Referred to later in this chapter, the program will calculate the optimum alignment of rotors in a multi-rotor system, while minimizing the number of bearing moves or by maximizing the number of bearing “no moves.” Rotor position, expected alignment, shim changes, and other information are provided, which can be used to significantly reduce outage time associated with coupling alignment during reassembly. There is both an automated and manual version of this software. The automated version calculates the best alignment given user-specified inputs and minimizes bearing moves to achieve it; the manual version allows the user to click bearing moves using a mouse and observe alignment changes as this is being done. Similar output reports are provided with both versions of the software. Additional discussion of TGAlign and general alignment procedures/practices can be found in Section 4.8. Clearance measurements are typically taken between the: •

Diaphragm and the wheel

•

Packing and the rotor

•

Spill strips and the rotor

Diaphragms are seated in the direction of the steam flow using wedges between the upstream side of the diaphragm and the shell to ensure diaphragm-to-shell contact when taking diaphragmto-wheel clearance measurements. Typically, most of the measurements are made only on one side of the steam path and referenced to the wheel (the rotating component). The following information is obtained from the diaphragm-to-wheel measurements or from observations made during the measuring: •

As-found axial position of the rotor in the steam path

•

Unusual transient expansions

•

Diaphragm dishing

•

Information regarding the need to reposition the rotor

Diaphragm-to-wheel positions are taken at a number of locations and may vary based on the manufacturer, type, and design of the steam path. Typically, the clearance tolerances are tighter for the upstream measurements than the downstream and are approximately ± 0.010" and ± 0.030" (±0.254 mm and ±0.762 mm), respectively. The actual design measurement should be 4-35


found on the rotor clearance drawing or from the last outage report. The following are typical diaphragm-to-wheel clearance measurements: •

•

Axial reading taken on the admission side of the bucket between the bucket cover admission side and the discharge side of the diaphragm outer setback face –

Taken on both left and right sides of the steam path

–

Information provided: ∗

Determine rotor-to-diaphragm axial alignment

∗

Verify bucket cover machining after bucket cover or bucket replacement

∗

Identify shell or casing twisting

∗

Used in conjunction with other axial readings to identify and monitor diaphragm dishing

Axial clearance taken at the base of the bucket vane section between either (1) or (2): (1) The bucket admission side axial sealing tooth integral to the bucket and the discharge side diaphragm inner set back face (2) The flat surface at the base of the bucket vane and the discharge side diaphragm inner setback face, if there is no axial seal

•

–

Taken on left side of the steam path

–


Used in conjunction with the axial bucket cover clearance to determine rotor to diaphragm axial alignment

∗

Verify bucket machining after bucket replacement

∗

Determine bucket drifting

∗


Axial reading taken from the bucket admission side to the discharge side of the diaphragm located at the bucket root radial seal –

Verify bucket machining after bucket replacement

–

Taken on the left side of the steam path

–

Information provided:

4-36

∗

Verify diaphragm machining

∗



•

•

•

•

Radial reading taken from the bucket admission side machined fit at the base of the vane to the integral spill strip incorporated in the diaphragm discharge side –

Taken on both left and right sides of the steam path

–


Verify diaphragm machining

∗

Verify sealing clearance

Axial reading taken between the rotor wheel admission side and the axial discharge side of the diaphragm at the packing fit –


–

Information provided: identify and monitor diaphragm dishing and distortion

Axial reading taken at the base of the bucket vane at the discharge side of the bucket to the diaphragm admission side –


–


Identify and monitor diaphragm dishing and distortion

∗

Used with packing readings

Axial reading taken between the rotor wheel axial discharge side and the axial admission side of the diaphragm at the packing fit –

Taken on the left side of the steam path

–


Identify and monitor diaphragm dishing and distortion

∗

Used with packing readings

The interstage packing rings are to be positioned to the steam sealing face in the packing groove in addition to the rotor position and diaphragms being set. The packing is positioned against the packing head or case steam seal face in end packing. All measurements are taken from the tip of the long tooth packing to the strike point on the rotor land. Two axial measurements are made, both on the left side (typically termed x and y readings) and both typically taken to assess packing and rotor position. One is referenced from the turbine end and the other from the generator end. (Older machines may require these readings to be taken on both the left and right sides, due to distortion.) These readings are used to assess the axial alignment of the packing to the rotor. A third reading is taken on both sides to measure the radial clearance. This reading is used to identify packing tooth wear and misalignment. Spill strip radial readings are taken on both left and right sides between the tip of the spill strip to the bucket cover. The purpose of the reading is to identify spill strip tooth wear. Readings are referenced to either the bucket cover admission or the discharge, depending on the stage sealing design. 4-37


4.8

Required Rotor Radial Position and Coupling Alignment Checks

Rotor radial position measurements are taken to determine where the rotor is positioned in relation to the stationary shells and oil deflector fits. The measurements are taken with the outer shells in place and set on the running shims and are usually taken with sliding parallel gauges. Oil deflector fit readings are normally taken with inside micrometers and are used to determine turbine tight wire set points and to track rotor radial position and bearing moves when shim changes are made to correct a coupling alignment problem. This information is critical. Every effort should be made to ensure its accuracy and repeatability in order to minimize the potential for rubs during the start-up of the unit. A four-point, four-position alignment check of the turbine-generator couplings has been the historically preferred method used to align the various turbine components to each other. The alignment check of a coupling consists of a rim and a face reading with the coupling halves separated from each other and in a free condition. As shown in Figure 4-19, the rim reading (which is used to determine the extent of vertical and horizontal offset of the coupling halves) is taken with a dial indicator mounted on one coupling half and reading to the other coupling half. This reading is taken at each 90-degree rotation of the coupling halves and should be verified as adding up. This means that the sum of the top and the bottom reading is equal to the sum of the left and right reading, within 1 mil (0.0254 mm). Readings should be taken at least two times to ensure that repeatability exists from one reading set to the other. If it does not, the readings should be taken until they agree from set to set. The face readings are taken to determine the vertical and horizontal angularity of the coupling halves. These readings are taken at the top, bottom, right, and left sides of the coupling for each 90-degree rotation of the couplings (a total of 16 readings). These readings should add up in a manner similar to the rim readings, that is, the average of the four top and bottom readings should be equal to the average of the four left and right readings, within 1 mil (0.0254 mm). Additionally, the face readings at each 90-degree rotation of the shaft should not reveal more than a 1-mil (0.0254 mm) vertical or horizontal angularity change. If more than this is experienced, either the accuracy of the reading should be challenged, or the coupling face has run out, causing such a change to take place.

4-38


Figure 4-19 Coupling Alignment Nomenclature

Readings are taken and compared to design values to determine bearing adjustments that may be required to align the rotors correctly relative to each other within specified alignment rim and face tolerances. The entire rotor train is evaluated before making a single move. Choosing the wrong component to move can result in multiple moves not only to obtain coupling alignment but also to maintain internal clearances. The bearings are shimmed to acquire the correct rotor position for coupling alignment. Vertical and horizontal alignment of the bearing is accomplished by changing the shims between the bearing casing and the support pads in the lower bearing half. TGAlign software (available in an English version [16] and an SI unit version [17]), developed by EPRI, is available as well as the alignment primer in Volume 3 to calculate the optimum alignment for a multiple rotor system. Optimization is achieved by minimizing the number of bearing moves or maximizing the extent of bearing “no moves” in order to achieve alignment. Using this software, the user can model the shaft system in advance of an outage, decide what rim and face limits are applicable, develop shim change input for the various bearings, and even perform trial cases to assess what the potential bearing vertical and horizontal “move limits” may be. During the outage (after the couplings are disassembled), the user enters as-found data. Output reports provide recommended vertical and horizontal bearing moves, expected and asfound radial position at oil bores or gland/shell bores, and shim change forms for each bearing. The software is available in both automated and manual versions. The automated version uses an optimization routine based on least square error and false position techniques to provide the best 4-39


achievable alignment with alignment limits while minimizing bearing moves to achieve it. The manual version requires that the user click a move at each bearing and view the new or current alignment as this process continues. Output reports are supplied similar to the automated version. User manuals for TGAlign, which include a tutorial and sample problems, can be found on disk 4 of this four-CD set. Typically, minimal bearing moves are made in a LP turbine because the stationary components are fixed; it would mean movement of the inner shells and packing/glands if major moves are required. Minimal moves are determined by as-left clearances in the diaphragms/blade rings and the packing/glands. The generator and exciter are aligned as assembled components, thus requiring no bearing move but movement of the complete assembly. The HP and IP sections on GE machines may be more tolerant of larger moves, but this depends on whether the shells and pedestals can be shimmed. If significant moves are made to the front standard or HP bearings, the internals of the front standard may require alignment. Siemens-Westimghouse-design HP and IP casings are typically aligned using vertical keys and centering beams that are doweled to the standards. This method does not lend itself to making moves to the shells because a significant shell move may require disassembly of the centering beam and re-doweling it. It is these factors that make the TGAlign software an excellent tool to solve alignment problems while minimizing the bearing moves necessary to achieve it. Where multiple sections are overhauled, alignment solutions can be sought in which certain bearings that are particularly difficult to adjust are left undisturbed. It should be noted that in many cases where single component inspections are regularly performed to a unit, the overall alignment might become so poor that a complete tight wire alignment of the unit becomes necessary. Outdoor units that experience sunlight year round tend to require a major realignment every second or third overhaul of the machine. The generator is aligned as an assembled component. The HP and IP sections are easier to align for larger movements; the entire section can be elevated by shimming the soleplates of the standards.

4.9

Checks to Assess Spare Rotor Compatibility

When ordering a spare rotor, the areas listed in Table 4-8 are important to ensure its compatibility with the existing casings. Options to make the new rotor compliant are shown, but it should be noted that these options may have limitations if the degree of deviation is too excessive to correct.

4-40

Disassembly and Recording Clearances Table 4-8 Checks to Determine Compatibility Between Original and Replacement Rotors Rotor Component

Coupling

Area

Modification Options to Facilitate Compatibility

•

Bolt circle

•

Line bore coupling holes.

•

Fastener bore diameter

•

Use replacement parts.

•

Spacer thickness

•

Machine or replace as necessary.

•

Rabbet fits

•

Machine or modify rabbet fit.

•

Journal diameter

•

Machine or weld build up rotor journals or increase/decrease bearing babbitt thickness.

•

Journal ground length

•

Modify active length of bearing.

•

Rotor diameter

•

Use replacement parts.

•

Rotor axial position

•

Machine the thrust bearing shims.

•

Rotor Diameter

•

Replace thrust bearing and shims.

•

Axial position

•

Replace thrust bearing and/or shims.

•

Diameter

•

Machine the rotor or modify the packing.

•

Number of lands

•

Replace or modify the packing.

•

Land geometry

•

Replace or modify the packing.

•

Diameter

•

Adjust as necessary.

•

Axial position

•

Adjust as necessary.

•

Axial position of buckets

•

Replace the thrust bearing shims.

•

Bucket covers

•

Machine the diaphragm, and/or modify the spill strips.

•

Total axial length

•

Skim cut coupling faces for minor corrections, or add coupling spacers.

Bearing journals

Oil deflectors Thrust bearing Interstage and end packing

Expansion detector Steam path

Total rotor

4-41

5

TURBINE-GENERATOR CONDITION ASSESSMENT

When the critical path of an outage schedule is extended, it is usually as a result of unplanned repair-replace-run decisions being made for certain critical components. Such components are identified as those that cannot be easily or inexpensively replaced, thereby avoiding a prolonged or unexpected delay to the critical path schedule. They are also fundamental to the reliable or efficient operation of the unit, that is, they must be eventually restored to a serviceable condition. It is at this phase that pre-bidding, contingency planning, and the existence of a sound management strategy for the problem at hand can significantly reduce the potential downtime. This section of the guidelines reviews and discusses the types of wear, damage, or fatigue problems that can be expected for different portions of the turbine-generator and discusses measures or contingency planning that should be considered in anticipation of their discovery. In addition to addressing typical problems for the major turbine-generator subsystems, dedicated turbine-generator technology (hardware and software) is referenced along with the basic information and possible sources that are required to support an application. Detailed procedures associated with the inspection and repair of turbine and generator components are found in Volume 2. The various components can be found in the following sections: •

Section 1, Bearings

•

Section 2, Diaphragm and rings

•

Section 3, HP nozzle box/plates

•

Section 4, Valves

•

Section 5, Rotor/buckets

•

Section 6, Shell/casings

•

Section 7, Steam deflectors

•

Section 8, Generators

Volumes 6 and 7 provide detailed inspection and assessment criteria for typical forms of damage associated with commonly operated types of HP, IP, and LP buckets. The EPRI report Turbine Steam Path Damage: Theory and Practice, TR-108943-V2, [1] provides a comprehensive reference on the current state of knowledge for major steam path damage. This report presents information on the importance of limiting steam path damage. There is a need to focus on this issue because failures of blades and disks in fossil and nuclear 5-1

Turbine-Generator Condition Assessment

turbines represent a serious loss of power. Problems other than shutdowns are efficiency losses that restrict operation and reduce the maximum capacity of the unit.

5.1

Cleaning Without Disassembly

While the unit is assembled, turbine cleaning is limited to removing chemical deposits from the turbine steam path. The chemicals, which are in solution in the steam, are often deposited throughout the boiler, steam lines, heaters, and turbine. These chemicals build up in the nozzle and blade passages over time and restrict the flow of steam through the turbine. The power output of the turbine is nearly proportional to the steam flow through the turbine. If the deposits build up significantly in the turbine, as much as 10% of the steam flow can be restricted. The power loss over time is usually exponential and can be as high as a 10% loss. The chemicals that are deposited in steam turbines are grouped into two categories: watersoluble and non-water-soluble. The water-soluble chemical deposits can be removed from the turbine when the turbine is shut down by reducing the steam temperature and pressure. This process allows wet steam to wash the chemical deposits from the blades. This process generally results in a recovery of a large percentage of the lost power. The non-water-soluble chemical deposits can be removed from the turbine by chemically cleaning the turbine while it is assembled or by disassembling the turbine and removing the chemical deposits by grit blasting. The most economical method of removing these deposits from the turbine steam path is chemical cleaning. Chemical cleaning is done by injecting chemicals into the HP turbine at an elevated temperature. The chemicals are carried within a foam to attach to the rotating components. This foam dissolves the chemical deposits from the steam path and the deposits go into solution. The turbine is filled to the bottom of the rotor with the foam and then put on turning gear during the foam cleaning process to remove the chemical deposits from the upper half of the components. The gland seals are put into service to keep any foam from escaping the casing. The foam is liquefied and then drained from the turbine casings through the shell drains. The chemical deposits are in solution as the liquid solvent drains from the turbine casing. The non-water-soluble element that causes the largest steam flow reduction is copper. Copper from heater and condenser tubing is deposited in the HP turbine as the steam temperature and pressure are reduced. Copper deposits in the steam can cause a 10% steam flow loss in as little as six weeks after a turbine major inspection. The chemical that is used to dissolve the copper during the chemical cleaning process is an ammonia-based solvent. Corrosion tests have been performed on turbine blades to ensure that the solvent will not cause stress corrosion cracking to occur after the unit returns to service after being chemically cleaned. To date, foam cleaning of the steam turbines is the most economical method of removing copper oxide deposits from the steam path. The foam cleaning process requires installation of mechanical connections to the inlet and exhaust of the HP. Blanks must be installed in the cold reheat steam lines, and chemical holding tanks must be installed. The first time the turbine is chemically cleaned, the cycle is long as a 5-2


result of the connections and tank installation. After these mechanical connections and tanks are installed, turbine chemical cleaning can be performed in approximately five days.

5.2

Recommended Inspection and Testing Techniques

Nondestructive testing is performed on turbine-generator components to aid in identifying conditions that may require the removal and replacement of the component, expose areas that require repair or refurbishment, or assist in evaluating the serviceability of the component. It is important to identify components that require corrective action early in the outage. Not all components can be cleaned and inspected during the first days of an outage; therefore, the priority and sequencing of inspections is important. The following considerations contribute to the NDE priority selection: •

Disassembly sequence

•

Cleaning sequence

•

Known and possible repair scopes

•

Repair duration

•

Reassembly sequence

Table 5-1 identifies typical components of a turbine-generator and lists the normally associated inspection method. Each component receives a visual inspection in addition to the methods listed. Nonmagnetic materials such as stellite, austenitic stainless steel, and Inconel, are inspected with dye penetrant testing (PT). They appear in the matrix usually in combination with another inspection technique for the balance of the component. Only selected areas of a component may be inspected. Inspections should focus on first “getting the big picture” and then focus on the specific areas. That is one reason why visual inspections are important elements of the total inspection process. Many times, damage is severe and obvious, and those areas may receive all the attention. However, damage to a component that might cause problems after being returned to service is subtle and easily overlooked. Observations and inspections should take into account the areas of a component that are subject to: •

Wear

•

Stress – tensile and bending

•

Cyclic loading

•

Component geometry - stress risers and hidden areas

•

In-service damage

•

Manufacturing defects or deficiencies

5-3

Turbine-Generator Condition Assessment Table 5-1 NDE Inspection Methods Used on Different Turbine-Generator Elements Rotor

HP

IP

LP

Field

Exciter

WFMT

WFMT

WFMT

WFMT

WFMT

WFMT = Wet florescent magnetic particle testing

WFMT

WFMT

WFMT

WFMT

WFMT

UT = Ultrasonic testing

WFMT

WFMT

WFMT

UT & WFMT

UT & WFMT

UT & WFMT

WFMT

WFMT

WFMT

Coupling

Journals

MT = Dry powder magnetic particle testing

Body

Bore Buckets Bucket pins

ECT = Eddy current testing

UT & WFMT

PT = Dye penetrant testing

UT

Tie wires

WFMT

Tie-wire holes

WFMT

Covers

WFMT

WFMT

WFMT

Tenons

WFMT

WFMT

WFMT

Stellite shields

PT

Titanium buckets Rotor Dovetails

HP

IP

LP

WFMT

WFMT

WFMT & UT

Fan rings

Exciter

WFMT

Main leads

PT

Fan blades

WFMT

Fan bolts

WFMT

Retaining rings

PT & ECT

Stationary Components

Diaphragms

Steam path

WFMT & PT

WFMT & PT

WFMT

WFMT & UT

Body

5-4

Field

Nozzle Box

Shell Outer

Shell Inner

PT

Casing

Packing and Casing Heads

Crossover

Turbine-Generator Condition Assessment Table 5-1 (cont.) NDE Inspection Methods Used on Different Turbine-Generator Elements Valves

SV

CV

RHSV

IV

WFMT

WFMT

WFMT

Horizontal joint

MT

MT

Vertical joint

MT

Radial fits

MT

Gib key fits

MT

Flanges

MT

WFMT

ID areas

MT

MT

MT

OD areas

MT

MT

MT

Seal rings

WFMT & PT

Pre-warming pipe

WFMT & PT

Body Anti-swirl baffle

IV

NRV

Ventilator Valve

Equalizer Valve

WFMT

WFMT

MT

MT

MT

WFMT

WFMT & PT

MT & PT

MT

IV

NRV

Ventilator Valve

Equalizer Valve

WFMT & UT

MT & UT

WFMT

WFMT

WFMT

WFMT

PT

PT

MT

MT

Cover

MT

Stand

WFMT & UT SV

CV

Studs

WFMT & UT

UT

Nuts

WFMT

WFMT

Spacers

WFMT PT

RHSV

WFMT

PT

WFMT PT

WFMT

Seat pin

UT

Seat pin welds

WFMT

Pressure seal head

MT

RHSV

Screen

Seat bolts

MT

CV

MT

Seat

Equalizer Valve

SV

WFMT

Valves

Ventilator Valve

MT

Inlet expansion pipes

Valves

NRV

WFMT, PT, UT

WFMT, PT, UT

5-5

Turbine-Generator Condition Assessment Table 5-1 (cont.) NDE Inspection Methods Used on Different Turbine-Generator Elements Valves

SV

Stem

CV

RHSV

IV

NRV

WFMT

PT

WFMT MT

Arm

MT WFMT

Disc

WFMT & PT

WFMT

WFMT

Flapper valve WFMT

Bypass valve

WFMT & PT

Linkage components

WFMT

WFMT

Crosshead

WFMT

WFMT

Springs

WFMT

Spring cans

WFMT MT

Balance arm

MT

Bushings

MT

Casing

Main Steam Lead Flange Bolts

Coupling Bolts

Crossover Flange

WFMT & UT

WFMT

UT & PT

WFMT

WFMT & UT

WFMT

WFMT

PT

WFMT

WFMT

WFMT

WFMT

WFMT

WFMT

WFMT

WFMT

Horizontal Joint

Spacers Nuts

PT

MT

Flange

Threads

5-6

PT

WFMT

Welds

Body

WFMT

MT & PT

Cap bolts

Fasteners

Equalizer Valve WFMT & PT

Shaft Cap

Ventilator Valve

WFMT

WFMT

Turbine-Generator Condition Assessment Table 5-1 (cont.) NDE Inspection Methods Used on Different Turbine-Generator Elements

Bearings

Babbitt bond

UT

UT

Babbitt bond - edge

PT

PT

Babbitt integrity

PT

Impellers

Pumps

PT & UT

Shafts

WFMT

Welds WFMT MT UT ECT PT

Piping

Hydrogen Seals

Other

MT & PT Wet florescent magnetic particle testing Dry powder magnetic particle testing Ultrasonic testing Eddy current testing Dye penetrant testing

Close visual inspection is the starting point for the evaluation of generator components. Most generator issues dealt with are mechanical or thermal in nature and often become electrical problems after the dielectric strength of the insulation is degraded. Mechanical issues do not always lend themselves to early detection by electrical test, but mechanical and thermal issues may produce some visible effect that is discernable early in the failing process. The advantage of early visible detection is normally that the condition is easier and less expensive to correct than if it is given enough time to become an electrical problem. Examples of mechanical problems are: •

Abrasion and chafing of insulation

•

Loose slot wedges or core iron

•

Movement seen in “taped” sections

•

Cracks in “hard” epoxy coatings

Table 5-2 presents a summary of visual inspections typically performed on generator components.

5-7


X

X

X

X

Stator wedges

X

X

X

X

Stator connections

X

X

X

X

X

X

High voltage bushings

X

X

X

X

X

X

X

Core end

X

X

X

X

X

X

Ventilation ducts

X

X

X

X

Laminations

X

X

X

X

Key bars

X

X

X

X

Field body wedges

X

X

X

X

X

X

Retaining rings

X

X

X

X

X

X

Fans

X

X

X

X

X

Field journals, sealing areas

X

X

X

X

X

Field windings

X

X

X

X

Collectors

X

X

X

X

X

X

X

X

X

X

Blocked Ventilation

Support system

X

Core Tightness

X

Shorting

X

Overheating

Movement/Vibration

X

Wear

Loose Components

X

Cracks

Debris and Cleanliness

Stator bars

Water Leaks

FOD

Table 5-2 Visual Inspection Methods Used on Different Generator Elements

X X

X X X

X X

X

X X X

X X X

X

X

5.2.1 Proof Test A variety of electrical tests are available to assist in discerning the electrical state of both the field and stator. One of the major test concerns is determining the condition or serviceability of the insulation. One common test to determine if the insulation will contain the applied voltage is the high-potential (HIPOT) proof test. Three areas of concern are associated with this test: what type of voltage to use, what voltage level to use, and will the test damage the insulation?

5-8


A more uniform search effect is obtained when using an alternating current (ac) voltage, direct current (dc) voltage being somewhat inconsistent. Direct current (dc) over-voltage testing can be used but requires a voltage level increase (approximately 70%) over ac test voltage levels. Choosing a voltage level above the operating voltage level establishes that at the time of the test the insulation has not degraded to that dielectric strength to contain the voltage. Some margin is then known to exist. The challenge is setting the test voltage level so that the test ensures a sufficient margin to handle operational transients without stressing the windings. The insulating material does not significantly deteriorate during “normal” operating conditions or during normal operating temperatures. Degradation of the insulating material typically is a result of concentrated effects of abrasion, over temperature, vibration, and thermal changes. Again, the test voltage should be set above the highest expected transient, for example, if the lightning arrestors are set for 120% voltage, then the test should be higher than that to allow for unknown or unpredicted transients. An actual test voltage may be 150% voltage to accommodate transients and unpredicted degradation. In the utility industry, the problem with the proof test is in the very nature of the test, and generator proof testing has been the subject of much debate. If a 150% voltage test is done and the insulation fails at a specifically weak area, the remainder of the insulation may have been able to withstand 400%. The unit may have been good to above the highest expected transient that was below the test voltage, but now the insulation is failed. The unit is no longer serviceable; whereas prior to the test, it might have lasted considerably longer. The advantage of doing the test versus finding the weak spot in operation is timing and being able to respond during a planned maintenance outage, not during a forced outage that would probably occur during a period of peak load operation. Therefore, because of the nature of the test and the possibility of an insulation breakdown, it would be prudent when planning the test to plan for the contingency of failure. Other tests are available to aid in the evaluation and determination of the insulation system to ensure serviceability. All require application of voltage across the insulation, but unlike a proof test that is done above the rated voltage level, the others are done below the rated voltage level. A proof test is a go/no-go (pass/fail) test, but the others may require interpretation of results by comparing them to unit age, previous tests, known or anticipated conditions, and other data. 5.2.2 Megger Test The “megger” is a test that measures insulation resistance. The megger (short for megohmmeter) is a high-range ohmmeter (10,000 MΩ or infinity) that contains a hand-operated or motor-driven DC generator and resistance indicator used to measure the high resistance values. Megger units are available in a number of voltage levels up to 2,500 volts; 500-volt or 1,000-volt units are typically used. The megger unit applies this potential and then measures the leakage. In a mechanical sense, this is similar to pressuring a piping system and checking the pipes for leakage by timing the pressure loss. Any conducting paths within the insulating system being tested result in current flow and a reduction in meter reading. A high reading does not necessarily 5-9


indicate that the equipment can withstand the operating or rated potential because the megger uses a potential much lower than the rated potential. The megger unit can be used to perform a dielectric absorption test. A dielectric absorption index of the insulating material is obtained when the megger test is run for a longer period of time; approximately 10 minutes is typically used. During this time, the megger unit will charge the high capacitance of the insulation wall (“polarize”), and if the system is clean and dry, the indicated reading will increase. The ratio of the 1 minute and 10 minute readings is known as the polarization index (PI). PIs above 2.5 for the stator and 1.25 for the field are considered acceptable. Recording and plotting the periodic resistance readings will show trends that may indicate impending insulation failures. 5.2.3 Doble Test Another insulating system test sometimes called a Doble test uses ac voltage to measure the loss in watts. This test is also known as: •

Power dissipation factor test

•

Power factor test

•

Capacitance-power factor test

The test measures both the capacitance and power factor of the insulation. The insulation power factor is a ratio of watts loss to the charging volt-amps expressed in a percentage (W/VA x 100%). The losses are a combination of: •

Power losses (resistance loss, I2R)

•

Corona losses

•

Ionization losses within the insulation

•

Losses due to the application of the ac voltage

A perfect insulator would be a perfect capacitor and, therefore, would have a power factor of zero and no internal losses. The Doble test is a relative test, trending changes in the power factor. A slow change over a long period of time is most likely normal, but a rapid increase in a short period of time would not be and would indicate a potential failure. Performing the Doble test at different voltage levels and at the same temperature and voltage levels of previous tests will aid in providing accurate comparisons of the test data. 5.2.4 Other Tests An ac impedance test is also a relative test done on field windings to determine the condition of the insulation. The test is performed at various voltage levels to check the impedance of the windings. The impedance is the vector sum of the inductive and capacitive reactance. The impedance in a field is mostly inductive. A shorted turn in the winding lowers the resistance of 5-10


the winding, resulting in a slight increase in current. But the main action is a change in inductive reactance. A change in this value, when compared to early tests at the same voltage levels, can indicate shorted turns in the windings or an increase in the number of existing shorted turns. The dc leakage test is another analytical tool to evaluate the insulation system. This test is performed by application of an increasing stepped dc voltage to some predetermined level or to a point where abnormalities are observed. The leakage is measured at each voltage. The two are plotted to obtain a leakage current curve. The shape and slope of the curve are observed and compared to other readings. Trends or changes in the curve can provide information regarding the state of the insulation. The current leakage is a function of insulation ground paths, but it is also affected by moisture and surface contamination. This test is used in conjunction with other test data to evaluate the overall condition of the insulating system. Additional tests can be performed to evaluate a specific area or function of the generator other than the insulating system. A field turn-to-turn test can be performed with the retaining rings removed to help identify the location of known shorted turns. The test requires a power source of low dc voltage and high current capabilities. The power source is applied to the field through the collector rings. The voltage drop on each turn is measured and compared. A low voltage drop when compared to the other turns indicates a shorted turn. This test indicates only shorted turns with the field at rest and does not locate any problems that would be evident when the field is at rated speed. A hydraulic integrity test can be performed on the water-cooled stator windings to determine the integrity of the hydraulic attachments to the water-cooled copper conductors. Both vacuum and pressure decay tests are performed after the windings have been dried. A vacuum is drawn on the windings, and then the windings are isolated. The vacuum is monitored and recorded every five minutes for approximately 2.5 hours. The leak rate is calculated after this time and should not exceed 3.0 ft3/day (0.085 m3/day). The pressurization test using dry compressed nitrogen or air is run for 24 hours while recording: pressure, temperature, and atmospheric pressure every hour. The leak rate is calculated at the end of the test period and should not exceed 1.0 ft3/day (0.028 m3/day). Exposed areas may be inspected with “snoop” during this test to facilitate finding leaks while under pressure. The air can also be replaced with helium or helium tracer during the pressure test. A helium “sniffer” can then be used to aid in finding any leak location. A shorted stator core lamination test can be used if there is evidence of damage to the laminations. Laminations are tested for shorts by using an electromagnetic core imperfection detection (EL-CID) test. The EL-CID test is usually done on large machines where a full level loop test is impractical. The EL-CID test uses low energy to excite the core, wrapping several turns around the core by passing cables through the bore and around the outside of the stator. A magnetic sensor (a magnetic potentiometer invented by Chattock and known as a chattock) is used to detect the level of magnetic flux on the core surface and determine the locations of the shorted laminations.

5-11


5.3

In Situ Inspection

5.3.1 Economic Incentives Imposed by Deregulation Turbine-generator (T-G) overhauls require complete disassembly to facilitate inspections of locations that are not accessible when the turbine-generator is assembled. A significant amount of the planned outage timeframe can be spent removing the turbine outer and inner shells. Often disassembly exposes unexpected damage in critical locations that requires either repair or component replacement, adding days or possibly weeks to the critical path. An unplanned extension to the outage can have the same financial impact as a forced outage—as much as a factor of 4–10 times the consequential lost generation cost of a planned outage. In a deregulated power production climate, the lost generation cost from a planned outage or an unplanned outage extension results in a lost opportunity to sell power. The lost sale may be as much as a factor of 10 greater than the incremental replacement energy cost. This moves the planned outage extension cost from a “soft” cost in a regulated environment to a “hard” cost in a deregulated environment. The motivation then is clearly to reduce the total time of planned outages for overhauls and minimize the occurrence of unplanned outage extensions. In situ inspection can contribute to both of these goals. One of the primary advantages of an in situ inspection is the minimal disassembly required to perform the inspection. An interim inspection of some turbine-generator locations can be implemented without removal of the inner and outer shells by accessing the machine internals. This is accomplished with an in situ inspection device inserted by means of alternative pathways into the unit. Similarly, in situ inspection can be used in advance of a planned outage to look at accessible turbine-generator areas and provide warning of unanticipated damage. As a result, repair and replacement activities can be more efficiently planned, minimizing the effects on the outage schedule. In a forced outage or in a situation where turbine damage is suspected, in situ inspection may provide a valuable first look for determination of damage type and extent in preparation for repair. For more information on in situ visual inspection, see the EPRI guide Interim Guidelines for In Situ Visual Inspection of Inlet and Outlet Turbine Stages: Part 2: Experiences, Approaches, and Improvements in Remote Visual Inspection, TR-114961 [18]. The guide’s focus is on remote visual inspection (RVI) for examining the early stages of high-pressure steam turbine rotors and the latter stages of low-pressure rotors. The most commonly deployed tool for turbine-generator in situ inspections is the video probe. Commercial systems that are sufficiently rugged for deployment as turbine-generator inspection tools are available from Olympus, Everest-VIT, and others. Variations of this tool have been used extensively for inspecting jet engine components and other rotating machinery.

5-12


5.3.2 Machine Access Access to the critical HP and LP locations is accomplished with minimal disassembly via main steam inlet flanges, governor or control valves, manways in the exhaust hood, or engineered inspection ports. Some of these pathways are challenging and may require accessory equipment to navigate. Deployment of a flexible video probe in a steam turbine may require the use of support mechanisms to deliver the probe to the area of interest. In the case of an HP rotor, the video probe has sufficient rigidity to be directed through the steam inlet piping to the vicinity of the nozzle box area. However, navigation of the nozzle box and stationary blades for access to the first stage rotor blades requires the use of a probe delivery device. Figure 5-1 shows an EPRI-sponsored video probe system being used to inspect the first stage buckets of a 550 megawatt, tandem compound, single-reheat, quadruple-flow steam turbine. The entry point was the separation between the first set of upper-quadrants steam inlet flanges, which were unbolted and separated approximately 4.5" (114.3 mm). The steam inlet pipe had a nominal diameter of 4" (101.6 mm), and the total path length to the area of interest was 15' (4.6 m). Although the initial path was horizontal for approximately 5' (1.5 m), it then transitioned to a 6' (1.8 m) vertical run through a 2' (0.6 m) radius curve. The inlet chamber of the nozzles was at the termination of the vertical path. Three nozzles were located in the in the upper half, and three were in the lower half. After the inlet chamber was reached, the path made a 90-degree bend out of the plane into the axial flow direction in the turbine, continuing approximately 2" (50.8 mm) in the axial direction to reach the first stage nozzle blade positions.

Figure 5-1 Access Path for Video Probe Delivery Device

5-13


A remotely operated delivery device allows the probe to traverse voids that the probe would otherwise fall into and makes it possible to lift the forward section of the probe for entry into elevated orifices such as the steam inlet of the nozzle box area. After the probe is inserted in close proximity to the stationary blades, the built-in articulation capabilities of the probe tip are sufficient to maneuver it between blades to the desired vantage point. Other less tortuous routes, such as those found in the LP section, may require only the use of semi-rigid plastic tubing or a similar device to guide the video probe to the inspection area. At least one utility has installed external ports for LP inspection to facilitate access to two adjacent rows of blades via a single port. This eliminates the need to put an operator on scaffolding between the inner and outer casing to access these areas. 5.3.3 Video Probe Systems Typically, the video probe systems can be operated on ac or dc power, deployed from a storage case, or worn on an accessory belt. The systems can be operated in stand-alone mode or used in conjunction with a VCR (to provide a record of the inspection), an external monitor (to allow a larger viewing audience), or other video device. Fixed-focus systems are designed with a large depth of field and do not require the operator to focus the probe lens. Optional, detachable tip optics are available to vary the field of view, depth of field, and direction of view, if required. Some systems offer an articulating probe tip that allows remote control of the tip optics (via a joystick device) for precise viewing of the area of interest. The flexibility of the probe shaft allows it to be manipulated around obstacles, eliminating the need for line-of-sight access to view a remote area. Video probe systems are also available with the capability to measure object length and depth. An on-screen point-to-point measurement (or other convention) provides an accurate length measurement of a damaged area or a distance measurement between areas of interest. Accurate depth measurements are typically determined using a shadow probe technique or a threedimensional stereo-image technique. Typical environmental limitations restrict the use of the video probe to a maximum temperature of 180°F (82°C), depending upon the system used. However, at least one manufacturer offers a device to air-cool the probe, extending the operational temperature range to approximately 500°F (260°C). Although the initial purchase price of a high-quality video probe system is not inexpensive, payback can be realized quickly in avoided turbine disassembly time and the associated lost generation costs. Commercial inspection services are also available, alleviating the need for capital equipment purchase by the utility. More information on the video probe delivery device for in situ visual inspection of steam turbine and combustion turbine machines is available in the EPRI report Demonstration of a Videoprobe Delivery Device for In Situ Inspection of Steam Turbine and Combustion Turbine 5-14


Machines, 1004002 [19]. The report includes the development and demonstration of two video probe delivery devices in an active steam turbine and combustion turbine machine. 5.3.4 Utility Experiences In situ inspection is being used by several utilities to evaluate critical locations in the first stage areas of HP rotors and the last stage areas of LP rotors. Typical detectable damage mechanisms include solid particle erosion in the HP and water droplet erosion in the LP section. Foreign object damage and cracking are also detectable. Examples obtained from the previously mentioned remote access probe system are shown in Figure 5-2.

Figure 5-2 Examples from Remote Video Probe In Situ Inspection

Access to selected areas of the LP rotor is typically gained via manways and access ports in the condenser hood. HP rotors are accessed by breaking the inlet steam line at the main steam flange or through an engineered access port in the inlet steam lead. As the technology continues to improve, utilities continue to implement probe delivery devices to more remotely accessible areas of interest. These devices have been fabricated both by inhouse utility staff and by inspection companies (or in cooperation with them). Designs range from simplistic to intricate and have been used with varying levels of success. It is reasonable to expect that probe delivery devices will continue to evolve and will further benefit from the involvement of inspection companies offering commercial services. The EPRI report Demonstration of a Videoprobe Delivery Device for In Situ Inspection of Steam Turbine and Combustion Turbine Machines, 1004002, [19] presents additional details on the system used as an illustration of the technology. The EPRI report Interim Guidelines for In Situ Visual Inspection of Inlet and Outlet Turbine Stages: Part 2: Experiences, Approaches, and Improvements in Remote Visual Inspection, 5-15


TR-114961, [18] is recommended as a detailed reference with more information on the state of the art for in situ inspection among utility users. Topics covered in the report include: •

In situ inspection considerations for HP and LP rotors

•

Degradation mechanisms

•

Utility experiences with in situ inspection

•

Gaining access to areas of interest

•

OEM and commercial vendor inspection services

•

Probe delivery systems

•

Recommendations for development

5.4

Accelerating Different Types of Inspections

Turbine-generator maintenance requires that many inspections be performed during disassembly, after disassembly is complete, and during re-assembly. These inspections are: •

Visual inspection

•

Dimensional inspection

•

Metallurgical testing

•

Electrical testing

•

Nondestructive testing

The type of testing must be determined before the outage, and each test must be completed at the proper time. The engineer should review and verify all test data for accuracy before proceeding with the turbine disassembly or assembly. This allows a second chance to obtain data if an error is found. It is important to be able to get to the equipment in order to perform the required tests and inspections without moving the equipment any more than necessary. There are many ways to perform inspections faster by using special tools, supports, and modular tenting. During the turbine disassembly, the alignment of the shafts must be recorded. These alignment checks were originally performed using precision mechanical measurements. Dial indicators measured radial coupling alignment, while sliding parallels and micrometers measured parallel coupling alignment. As lasers became more readily available, they were incorporated in the data collection process. Helium neon lasers have been used to speed up coupling alignment checks without the need for precision instruments. The rotors still need to be uncoupled to perform the laser alignment checks and many hours are still required to complete the alignment check of the entire rotor train. Strain gage alignment has been used to perform rotor alignment without uncoupling the rotors and is much faster than the other two methods. With strain gage alignment, the rotor train 5-16


alignment can be performed with the turbine and generator still hot and with the lube oil pumps running. The analyses that are required to perform strain gauge alignment are extensive and make the cost high, but the results can be worth the effort. After the upper turbine components are disassembled, the rotor-to-casing clearances must be recorded. These clearance checks were originally performed using precision measuring instruments. Better precision instruments have been developed, but these still generally require manual reading of the instrument and recording the data on a data sheet. In the most advanced systems, clearance measurements can now be measured with electrical instruments where data can be stored digitally and later downloaded into a computer. After the rotors are removed from the bearings, they should be set on motorized roller stands. The motorized rollers allow the rotors to be turned while inspections are performed, which reduces the inspection time. After the visual inspection, the motorized roller stands allow the rotors to be turned while blast cleaning and nondestructive testing is performed. Without motorized rollers, the work must stop to allow the rotor to be turned with a crane or by mechanical means. The stationary components can be small diaphragms (impulse design) or large blade rings with many stages (reaction design). If the turbine is of the impulse design, specially designed diaphragm racks should be used for visual inspection, blast cleaning, and nondestructive testing. Diaphragm racks can contain many diaphragms and allow access from both the admission and discharge sides of the diaphragm. Diaphragm racks allow the cleaning and inspections to be performed in batches and keep the diaphragms in sequential order. If diaphragm racks are not used and the diaphragms are laid on the floor, a crane must be used to turn the diaphragms over, which uses more crane time than if diaphragm racks were used. Because the crane is used more than any other tool during the turbine overhaul, if blade rings are set on end to give access to the blades while they are being blast cleaned and inspected, this can reduce both the demands on the crane and a potential source of delay in terms of cleaning. Monorails can be used to support the turbine components while the work force is performing visual inspections, blast cleaning, and nondestructive testing. The setup of a monorail is time consuming, and the monorail takes up a great deal of floor space. During the planning stage, the planner should determine if the use of a monorail system would benefit the outage in order to determine if it is worth the cost involved. Many nuclear units use monorail systems because of the large components that must be handled. 5.4.1 Defect Sizing and Implications of Results Defect detection and sizing is a critical element of nondestructive evaluation (NDE), especially if the defect is subsurface and cannot be directly observed and visually mapped. Most often, sizing and mapping of subsurface defects will be done with UT, while visual, MT, or PT methods are used for surface indications. On occasion, radiographic testing (RT) is used to map subsurface indications. Some of the constraints in sizing and mapping defects are listed in Table 5-3. 5-17

Turbine-Generator Condition Assessment Table 5-3 Sizing and Mapping Constraints Associated with NDE Item

Note

Indication/defect properties

Size: estimated versus true, location, shape, orientation, sharpness, type, repeatability,

Surface condition Part geometry Part complexity Metallurgical condition

Grain size, porosity, inclusion content, precipitate dispersion

Selection of NDE method Viewing conditions Operator performance PT variables

Pre-test cleaning, test conditions – temperature, type of penetrant, penetrant dwell time, penetrant removal, developer dwell time

MT variables

Magnetizing procedure (ac, dc, flux density, flux orientation), Permeability and retention of material

UT variables

UT equipment (transducers, amplifiers, display), transducer “shoes” (near-surface noise, reflection and retrieval angles), procedure (calibration, couplant, wave-length), flaw reflectivity

RT variables

Contrast and sharpness, equipment (output, source types, source size), film type and processing, procedure (energy, filters, exposure time, scattering, absorption)

It is generally beneficial to create an NDE test block prior to the outage and testing. A test block takes into account the material and part geometry and is used to determine the various correlation effects. For UT, the test block should also include defects of known size and location. Equivalent flatbottomed holes (EFBH) are often used as an artificial discontinuity. The echo indication from the EFBH is set at some convenient reference amplitude, and any indication is interpreted in reference to it. Machined notches are also used. The NDE procedure to search for indications is then developed and qualified. The ability to detect and size a material flaw directly impacts the ability to evaluate a component’s remaining useful life. The ability to identify clusters of indications is also used in evaluating components. Calibration blocks can be created to verify system operation before testing. For example, a calibration block may have an artificial discontinuity machined as the reference reflector and also have a surface the same contour as the rotor bore. Determining the size and location of indications is an essential part of evaluating a component’s condition and predicting its serviceability and remaining useful life. The five elements that support a component evaluation model are: •

Operating history and projected operation

•

Geometry

5-18


•

Material properties

•

Stress analysis

•

NDE

Applying operating history and material properties to a stress analysis of a component can provide the critical indication size to be searched for on initial inspection. Examples that are related to specific blade designs are provided in both Volumes 6 and 7 of this guidelines series [20, 21]. Further examples are shown in these volumes of how NDE results from the inspection can provide input into the stress analysis to determine useful remaining life. Consequently, locating, correctly sizing and reproducing results (in subsequent inspections) are important elements in an overall component evaluation program.

5.5

Cleaning Coated Versus Non-Coated Parts

Coatings are applied to protect the base material from the detrimental effects of erosion or corrosion. The coatings can be thermally sprayed, alloyed, galvanically, or vapor deposited onto the surface of the parent metal in a thin layer and, in most cases, are applied to the unassembled component. Coatings are often applied with service requirements equal to the life of the component; therefore, it is not often desirable to remove them during an outage. The conditions requiring coating removal would include repairing the base material or removing a damaged coating that, if left in place, might cause more damage to the base material. Nevertheless, cleaning a component prior to inspecting it during an outage is desirable. For non-coated parts, a variety of global and local processes are available. Table 5-4 identifies processes that can be used on both coated and non-coated components. Table 5-4 Cleaning Processes Used for Coated and Non-Coated Components Process

Coated

Non-Coated

Grit blasting Aluminum oxide

X

Glass bead

Reduced pressure

Hydroblast

X

X

Local processes Hand stoning

X

Abrasive cloth

X

Wire brushing Chemical cleaning

X

X X

5-19


5.6

Coating-Removal Techniques

Typically, a protective coating on a component is removed to facilitate repairs to the base materials. This may be the case with coated diaphragms. The coating can be completely removed during the grit blasting process or can be selectively removed during the repair process using abrasive discs. Preventing damage to surrounding areas or the base material is always a concern when removing coatings. The problem with grit blasting is possible ricochet damage if the blasting process is not closely monitored when a tenacious coating is being removed. Heat buildup is a concern when attempting to manually remove coatings. Using a new disc on a hard coating will break down the sharp abrasive disc material quicker than on the base metal. The cutting action is reduced; therefore, the discs should be changed often before they dull and cause localized overheating of the base metal.

5.7

Sampling and Analyzing Deposits

The consequence of corrosion to the back end of the turbine is the damage complement of what solid particle erosion represents to the front end of the turbine. Both damage mechanisms are a result of impurities being carried into the turbine. Solid particles carried into the turbine do erosive damage to the turbine components if the correct angle of attack and velocity are present. Impurities soluble in steam are carried to the back end of the turbine and deposited on the turbine blades as the steam loses its ability to hold the impurities in solution. Impurities come out of solution as the pressure and temperature of the steam decrease; therefore, deposit chemistry may be different along the steam path of the LP section. “Deposits in a pure impulse stage are on the stationary blades and not the rotating blades. As the percent stage reaction is increased, the impurities start to deposit on the rotating blades as well as the stationary blades. For a 50% reaction stage, the deposit is about equal on the rotating and stationary blades. “Some deposits are water-soluble and will not accumulate on stages operating in the wet region. The deposits on the last few stages in the LP turbine of fossil and nuclear units and in the HP turbine of the nuclear units are not water-soluble. In some fossil power plants, copper, which is not water soluble, will deposit in the HP turbine. During the overhaul, deposit samples should be collected and analyzed to assist the chemist in deciding on the proper boiler treatment.” [9, p. 418] Obtaining samples can begin as soon as the outsides of the LP section diaphragms are exposed. Observing the LP diaphragms in-place can reveal a deposit color span from the inlet to the last stage. Samples can be taken from both the diaphragm partition and the bucket surfaces. Using an envelope and a stainless steel spatula is an easy way to scrape the samples off the component. Samples should be adequately marked to reflect unit, date, and other general identifying information as well as location including stage, suction or discharge side, and stationary or rotating component. The down side of sampling during an outage is that the deposits have already occurred from the operating condition. On-line sampling can provide insights regarding the part of the operating cycle in which the contaminants are being carried into the section. 5-20


As outage intervals increase, significant damage may have already occurred by the time the component is inspected. Consequently, there is a benefit in monitoring both section inlet chemistry and discharge impurities. For example, NiCrMoV rotor steel, AISI 422 stainless steel, and AISI 403 stainless steel are all susceptible to stress corrosion cracking (SCC) if certain conditions are present. Discovering during an outage that SCC has progressed far past the incubation period is not a pleasant surprise. Instead, it is better to know and monitor for impurities such as sodium that could produce SCC for the materials and stresses present. A monitoring program should also include watching for other impurities such as chlorides that may cause corrosion fatigue or cycle fatigue that originates at a corrosion pit. A deposit-sampling program is important to identify either the cause of a corrosion-related problem or the potential for one; however, sampling is only one tool. It should be used in conjunction with a monitoring program.

5.8

NDE of Turbine-Generators and Collecting Boresonic Data

5.8.1 Turbine-Generator Nondestructive Evaluation Techniques Periodic nondestructive evaluation (NDE) of steam turbines and generators is necessary to ensure continued safe, reliable operation. Inspection of these components was introduced by the original equipment manufacturer (OEM) in the mid1950s, and today there are a number of vendors performing NDE inspections including OEMs and independents. Inspections range from ultrasonic inspections of the rotor bore surface (boresonic) and disk blade attachment to magnetic particle and dye penetrant inspections of rotor peripheral surfaces, blades, and blade attachments. There is a wide range of published literature on available NDE techniques; however, this material may not be easily accessed by the power plant engineer who often has to make decisions using limited information and in a short period. On the other hand, the NDE service provider is often not fully aware of the problem associated with a particular part of the turbine. They may suggest using inspection techniques that might be insensitive to the type of damage that is important or, alternatively, propose to use a technique that yields more data than are necessary to perform an adequate life assessment. The first course of action could lead to component failure, and the second may lead to unnecessary expense. The EPRI report NDE Guidelines for Fossil Power Plants, TR-108450, [22] is recommended as a more detailed reference of techniques for inspecting critical components in the power plants. Each section provides historical information about a component, damage mechanisms, typical inspection locations, recommended inspection techniques, required preparation and support requirements, estimated inspection time, permissible flaw sizes, recommended analytical techniques, references, and related literature. Section 4 of the report specifically addresses steam turbine inspection techniques and discusses rotor bore, turbine disks, attachments, and shaft outer surface inspections, as well as inspections of rotating blades including shrouds, tie wires, and tenons.

5-21


In addition to Section 4, EPRI guide Remote NDE Technology for Steam Turbines, 1006814, [23] identifies the potential for remote NDE technology for steam turbine inspections and the assessment of alternative surface preparation techniques for effective inspections. The report also refers to emerging NDE technologies that may be adaptable for remote inspections. 5.8.2 Collecting Boresonic Data Boresonic inspections are performed on both turbine and generator rotors. The typical OEM recommendation is to perform turbine rotor bore inspections after the first 10 years of service and subsequent inspections at an interval based on the inspection results, often equaling the initial inspection interval. Generator rotors are recommended for first inspection after the first 20 years of service or as a function of how frequently the generator is cycled on an annual basis. The information required to evaluate the results of a boresonic inspection is dependent on who is performing the inspection and what specific information they already possess. The four major groupings of information required to evaluate boresonic inspection results are: •

Inspection results

•

Rotor geometry

•

Material information

•

Operating data

If the rotor OEM is performing the boresonic inspection and evaluating the results, they will posses three of the four required areas of information. For example, the rotor OEM possesses the rotor geometry and all the original rotor non-aged material properties. To complete the assessment, the rotor OEM may need to acquire only a cursory view of operating data. If someone other than the rotor OEM is performing the boresonic inspection and evaluation, all the information required will need to be obtained. The inspection results are a product of multiple NDE activities, each playing a critical roll in the evaluation. Each NDE activity provides information for the rotor life analysis and remaining-life determination. Honing or polishing the bore to a 63-microinch (1.6 micrometers) finish or better before the inspection begins prepares the rotor bore. Sandblasting prepares the rotor periphery for inspection. The rotor bore is both visually and MT inspected. MT inspection will provide “at bore” discontinuities or very shallow subsurface discontinuities. Rotor bore discontinuities are extremely important because the maximum tangential stress occurs at the bore surfaces. The rotor stress reduces rapidly away from the bore. The bore UT will provide the most detailed information in the evaluation of the rotor. Near-surface and near-field noise effects limit UT data to distances no closer than 1/8–1/4" (3.5–6.4 mm) from the bore surface. Sound attenuation and rotor geometries tend to also limit the depth of the search to approximately 6" (152 mm). The rotor may also be UT inspected from the outer periphery for additional “look in” data. Information included with the mapping of any 5-22


UT-discovered indications and rotor geometry required to determine rim loads and metal temperatures for a stress analysis are itemized in Table 5-5. Table 5-5 Support Information Required to Interpret UT Data Radial distance from the bore surface Axial location from the rotor reference end Angular reference Three-dimensional size, numbers, and clustering information Rotor Geometry Required to Determine Rim Loads and Metal Temperatures Information That Should Be Included with Any UT-Discovered Indications

Bore Periphery

Rotor and stage seal geometry

Bore diameters, bore lengths and axial reference location, bottle bore transition taper and radius Rotor body diameter, length, and axial position, rotor wheel width, diameter, and axial location, bucket length and mass (total attached to wheel) Rotor body at seal, seal height, clearance, length of seal, number of teeth, axial clearance between seal and wheel, pressure drop across seal

If rotor and assembly drawings are available, much of the above information can be obtained prior to the outage and confirmed as necessary during the outage. Any “spare,” new, or used “N” (shaft end) packing end, interstage packing, seals, or buckets may provide sufficient steam path and stage loading modeling information prior to the outage. It may be necessary to obtain rotor bore samples to determine the rotor chemistry and material data. Samples may be taken from the rotor coupling face (non-aged) or rotor bore (service aged) at either single or multiple locations to provide creep information. The samples can provide a number of material properties: •

The rotor tensile property of yield strength may be used during analysis in fracture assessment in the plastic zone adjustment of the indication (crack), in flaw linking, ligament rupture, etc.

•

The rotor fracture toughness (KIC, a measure of critical stress intensity) data are used to determine critical crack size.

•

Charpy V-notch (used to provide fracture appearance transition temperature [FATT] data) and J-integral (parameter used to describe stress-strain field in plastic analysis of the yielded zone of a crack) specimens taken provide temperature-related toughness data.

•

Material creep properties are required for the higher temperature rotors that are operating above 40% of their melting temperature in absolute temperature (this range is typically for rotor stages > 900°F [> 482°C]). Creep damage (material plastic flow) is a function of the material, operating temperature, time, and stress.

Operating data may also be required for the rotor analysis. Operating data are used in the damage accumulation model of the analysis and the remaining life prediction. A history of steam temperature, pressure, rotor starts, ramp rates, operating projections, and other data provide the details for a remaining life assessment. Future or planned component utilization is also important 5-23


as an input for life prediction until the next planned inspection interval, or the data may be used to plan the next inspection period. 5.8.3 EPRI-Supported Rotor Boresonic Inspection Over the years, EPRI has undertaken many programs to evaluate the inspection technologies available to the industry. Probably the most recognized is the program to evaluate techniques for performing ultrasonic inspection from the bore surface (boresonic) of steam turbine and generator rotors. During the period immediately after the TVA Gallatin rotor failure in 1974—a failure that was ultimately determined as caused by a crack on the bore surface—organizations that had experience in rotor inspection began to develop and implement techniques for inspecting rotor forgings from the central bore hole. Prior to that time, only the OEM had been able to perform the inspection. During this period, the number of vendors performing the inspection increased, and although the inspections they were performing were similar in nature, variations did occur. Utilities that earlier had only their OEM to rely on to perform the inspection now had several vendors to choose from, and each claimed to be better than the last. In the early 1980s, EPRI developed a program to evaluate the inspection systems that were rapidly being deployed to meet the needs of the utility industry. A series of test blocks were designed with flaws fabricated in them to resemble the types of flaws thought to exist in rotor forging. To evaluate the test blocks, utilities would urge their vendors to participate in the program by performing a blind test of the test blocks and have their results evaluated and reported by EPRI. That program is still in effect today, and by the mid1990s, most of the domestic companies known to provide boresonic inspection services had participated. The following reports and system evaluations provide a good foundation for understanding boresonic capability as it is applied today. The EPRI report Rotor Boresonic Inspection Guidelines [24] is recommended as a detailed reference. It provides guidance for planning and implementing a viable rotor bore inspection program for steam turbine and generators. It also presents information useful to making a runretire decision on rotor use. Sections in the report cover: •

History, including the Gallatin failure

•

Rotor material

•

Boresonic inspection principles

•

Discussion of various inspection systems (from a survey)

•

Description of the boresonic performance demonstration plan

•

Conclusions and recommendations for performing an inspection

Also developed by EPRI in the 1980s was a boresonic inspection data evaluation DOS-based computer program, SAFER (Stress and Fracture Evaluation of Rotors), used to analyze the data obtained from turbine-generator boresonic inspections and evaluate the remaining life of these rotors. In 2004 EPRI released SAFER-PC (Stress and Fracture Evaluation of Rotors- Personal Computer), product number 1010003, with numerous upgrades. 5-24


SAFER-PC combines transient thermal-elastic finite element stress analysis, fracture mechanics, material property data, and the clustering and linking of surface defects identified from nondestructive examination (NDE) data to assess the remaining useful life (RUL) of steam turbine or generator rotors. SAFER-PC can also perform probabilistic analysis of remaining life and material creep. It includes modules that allow imported boresonic NDE data in ASCII format to generate a flaw file, and a flexible approach to curve-fitting fracture toughness data is also available. SAFER-PC’s powerful user interface enables the program to be run on a number of current operating systems, with a variety of options for displaying and archiving analysis results. SAFER-PC can be used to assess the remaining life of critical rotating equipment in lifeextension studies, potentially savings millions of dollars in replacement rotor costs. The program can be used to reduce the uncertainty in risk analyses of older turbine-generator rotors, reducing the possibility of rotor burst that is an issue involving both a safety and consequential cost. Many plants are being cycled more frequently with larger daily variations in steam inlet temperatures. SAFER-PC can evaluate the increased rate of damage associated with this mode of operation, enabling a more accurate assessment of the costs and benefits of flexible plant operation. The new version of SAFER, SAFER-PC Release 2.2, 1013044, [54] includes improvements to the user interface developed as a result of the May 2004 user training held in Charlotte, North Carolina, were formally incorporated in the official software release. 5.8.4 Boresonic System Evaluation Procedures A boresonic system evaluation begins with the member utility making a request to sponsor a particular inspection vendor. The evaluation blocks are then shipped to the participant where a series of 15–25 scans of the block is performed. At the end of the inspection phase of the program, the participant is provided with a map of the flaw locations. Included are several locations where either geometry reflections exist or there are no flaws at all. The boresonic measurements taken by the vendor that describe the flaws are sent to the EPRI NDE Center for statistical evaluation. The mean value and standard deviation for all scans are computed for each dimension included in the study for the 70-odd flaws in the blocks. A linear least squares fit of all the data, for each measured dimension, and for each defect type is then used to determine the best fit of the measured values versus the true dimension. The linear best fit is represented by a slope, intercept, correlation coefficient, and the root-mean-square (rms) error. The slope and the intercept are indicative of the systematic error. The correlation coefficient is a measure of the strength of the linear relationship between the true and indicated value. Standard deviation and rms error are measures of the spread and accuracy (relative to the best fit line), respectively, in the data.

5-25


Further details associated with specific inspection vendors can be found in the following EPRI reports: •

NEI Parsons Ltd. Boresonic Inspection System Evaluation, TR-102126, [25].

•

Northeast Inspection Services, Inc. Boresonic Inspection System Evaluation, TR-102256, [26].

•

WesDyne International UDRPS Boresonic Inspection System Evaluation, TR-106234, [27].

•

General Electric Company Boresonic Inspection System Evaluation, TR-107174, [28].

•

Reinhart & Associates, Inc. Boresonic Inspection System Evaluation, TR-108423, [29].

•

Boresonic System Performance Guide, TR-104355, [30] provides a comparison of all system evaluations prior to 1994.

5.8.5 Inspection of Boreless Rotors Nondestructive examination is generally less essential for solid (boreless) turbine rotors than for bored rotors because stresses are lower without a central bore hole. Occasionally, situations arise in which examination of a boreless turbine rotor is not only advisable but essential to maintain confidence in the rotor’s capacity for continued safe operation. Ultrasonic examination of rotors from their central bore holes has become an accepted in-service inspection method throughout the utility industry. Without a bore, ultrasonic examination of the rotor must be conducted from the outer periphery, a task that is made difficult by the periphery geometry and lack of a continuous, uniform surface from which to conduct the inspection. Boreless turbine rotors can be inspected reliably if the utility is willing to invest the time and effort needed to conduct multiple inspections from the limited surfaces that are available for transducer placement. Multiple direction angulation techniques must be used to inspect regions that are otherwise inaccessible. To maintain sensitivity, calibration-correction factors must be applied to account for the fact that the beam cannot be introduced orthogonally to the major dimension of the flaw, which, on the most conservative assumption, is assumed to lie in a radialaxial plane. Correction factors must also account for the possibility that the flaw does not lie in the center of the beam where sensitivity is optimized. Each test must be carefully designed to cover a specific region where normal inspection procedures cannot reach, and sensitivity corrections must be used to analyze the data and estimate reflector sizes properly. The EPRI report Guide for In-Service Ultrasonic Inspection of Boreless Turbine Rotors and Other Solid Shafts, TR-101836, [31] is recommended as a reference document. It presents details on methods of inspecting boreless rotors as well as determining appropriate inspection angles and corresponding sensitivity correction factors. 5.8.6 Inspection of Steam Turbine Disk Blade Attachments Although many innovative design changes have been developed to address stress corrosion cracking (SCC) of turbine disk keyways and bores, the blade attachment regions (disk rim) remain susceptible to SCC. Blade attachment designs are varied, and their geometrical shapes complicate in-service inspection. Accurate knowledge of the attachment geometry is needed to develop and apply reliable NDE, but this information is not always available. 5-26


The reliability of turbine disk blade attachments and the capability of in-service inspection methods to detect and accurately characterize cracking have received considerable attention from utilities. Although reliable NDE can be performed after blade removal, this approach is costly. It has created a strong incentive to develop reliable methods that do not require blade removal. The EPRI report Inspection of Turbine Disk Blade Attachment Guide, TR-104026-V1, [32] is recommended as a reference document. It introduces the topic of attachment NDE and describes conventional and advanced NDE methods and principles. It reviews the types of cracking and the potential crack locations in both axial and circumferential entry blade attachment designs. Current conventional NDE techniques and approaches are described including visual, liquid penetrant, magnetic particle, eddy current, and ultrasonic inspection. Application principles and inspection advantages and limitations are also presented. The guide features ultrasonic inspection because, at present, it is the only method available that is capable of examining the interior regions of the blade attachment. Complex design geometry introduces many opportunities for false calls during ultrasonic inspection. Reflections from the geometrical features of the various attachments can interfere with proper interpretation of inspection results. The report discusses these effects and the difficult problem of determining the geometry of blade attachments that is necessary for design and application of proper inspection procedures. An ultrasonic technique for measuring attachment geometry is also presented. EPRI report Steam Turbine Disk Blade Attachment Inspection Using Linear Phased Array Ultrasonic Technology, 1000122, [33] is also recommended as a reference. It provides a brief history of disk blade attachment inspection and the fundamental principles of ultrasonic linear phased array technology. In 1997, EPRI developed a technique to inspect steam turbine disk blade attachments using linear phased array technology. In 1998, a company to commercialize the technology was sought to make the technique available to utilities with turbines that incorporated the General Electric straddle-mount dovetail design. By the end of 1999, General Electric had commercialized the technology, had refined the technique, and was offering it to their utility customers. The cited report describes the development of the project as well as its status up to November 1, 1999. EPRI has developed a technique to inspect steam turbine disk blade attachments utilizing linear phased array technology. The EPRI guide Field Application for Ultrasonic Linear Phased Array Inspection of Straddle-Mount and Axial-Entry Disk Blade Attachments, 1000663, [34] provides a brief history of disk blade attachment inspection and the fundamental principles of ultrasonic linear phased array technology. It also describes the development of techniques for the inspection of straddle-mount and axial-entry disk blade attachments using this technology. The EPRI guide Ultrasonic Inspection of Steam Turbine Blade Roots, 1011680, [55] details the research findings, transducer designs, application methodology, and observed detection and sizing performance for the inspection of fir-tree root designs of large curved axial-entry configurations. Axial-Entry Blade Attachment NDE Performance Demonstration, 1011677, [56] consists of flaw detection and sizing performance of commercial inspection providers, using a blind test approach similar to that being undertaken currently for straddle-mount blade attachment designs. The final technical report provides test methodology and inspection performance results and comparisons, including guidance for specifying inspection services. 5-27


5.8.7 Inspection of Nonmagnetic Generator Retaining Rings Nonmagnetic retaining rings were introduced as an alternative to magnetic rings to minimize heat losses and improve generator efficiency. The predominant alloy, 18% manganese and 5% chromium (18-5), as well as other nonmagnetic alloys, were all found to be susceptible to SCC in the presence of moisture. Although relatively few catastrophic failures of nonmagnetic retaining rings have been reported, the economic consequences of a ring failure are too severe to ignore. Early detection of SCC in nonmagnetic retaining rings by NDE can mitigate such a catastrophe. NDE, however, has proven difficult because of the geometry of the ring and the method of assembling the ring on the rotor. The EPRI report Evaluation of Nonmagnetic Generator Retaining Rings, TR-104209, [35] is recommended as a reference document. It provides a road map to help inspectors evaluate approaches for the various inspection scenarios and detailed technical information for use in developing an effective retaining ring inspection program. Investigation of NDE techniques for retaining ring inspection revealed that no single inspection method or technique alone provides the high reliability required for retaining ring inspection. High reliability can be achieved only by implementing complementary methods or techniques to address the special considerations of a retaining ring inspection. In addition to its assessment of state-of-the-art NDE techniques, this investigation included an assessment of advanced techniques, resulting in recommendation of several for inclusion in retaining ring inspection programs. Retaining ring inspection requires considerable expertise to fully comprehend the capabilities and limitations of the various techniques. Inspections must be tailored to address various inspection situations including in-frame inspections, out-of-frame inspections with rings installed, and out-of-frame inspections with rings removed. Section 8.12 in Volume 2 of these guidelines contains a detailed procedure for removing, inspecting, and reinstalling generator retaining rings. EPRI report TR-102949 gives detailed methods to be used during operations, stand-by, and maintenance to keep generator retaining rings free from exposure to moisture.

5.9

Inspection of Shrunk-On Components

When the turbine experiences any vibration or balance problem, the cause can sometimes be related to the couplings. For this reason, a complete coupling inspection should be performed when balance problems exist. Shrunk-on couplings are used on turbine and generator shafts when it is not possible to use a solid coupling. The checks used for solid couplings should be performed when inspecting shrunk-on couplings. In addition to the solid coupling checks, there are special checks that should be performed when inspecting a shrunk-on coupling. Normal coupling checks are listed in Table 5-6.

5-28

Turbine-Generator Condition Assessment Table 5-6 Coupling Inspections – Disassembly and Reassembly After Disassembly Normal Inspections

Special Inspections

Coupling rim and face run-out

Locking key tightness

Face flatness

Bolt tightness on retainer plates

Visual inspection

Secure staking of retainer bolts

Magnetic particle inspection

Loose fits

Bolt elongation Bolt and hardware damage

Upon Reassembly

Locking plate damage

Face flatness

Windage cover damage

Rim and face run-out

Coupling spacer tightness

Loose fits

Coupling spacer gear tightness

Locking key tightness

Gear and spacer shifting

Retainer plate bolt tightness

Bolt hole scoring or galling

Secure staking of retainer plate bolts

Shrunk-on couplings should not be removed during normal maintenance. If the shrunk-on coupling needs to be removed, the manufacturer should be contacted, and a representative should be on-site to supervise the process. When a shrunk-on coupling is removed, the coupling should be inspected for fretting, dimensional checks, key tightness, keyway damage, and galling or scoring of any components. All retainer plate bolting should be inspected for damage. All bolting and shrunk-on rings should be magnetic particle tested.

5.10 Bearings – Journal and Thrust Types Understanding bearing construction, operation, damage mechanisms, and operational indicators will help the turbine engineer prepare and plan for outage contingencies. Because bearing repairs are typically performed off-site, inspections to document the condition of the bearing and journal should occur early in the outage cycle. Four critical steps are involved in the bearing repair process: 1. Incoming inspection and removal of the old babbitt 2. Liner preparation to receive the new babbitt 3. Casting the babbitt 4. Restoring dimensional integrity and final inspection 5-29


Each phase of the repair process can affect the quality and serviceability of the repaired bearing. Incomplete incoming inspections can cause delays in the final machining process. Improper preparation of the liner and improper tinning can result in disbonding of the babbitt. Improperly cast and cooled bearings can cause porosity, segregation, and disbonding. Improper preparation and lack of fusion can cause separation and dislodging during a minor repair. Improper machining can cause complete spin casting of the bearing again. Journal bearings and thrust bearings are the two types of bearings generally found in turbinegenerators. Journal bearings confine the rotor in the radial direction, support the rotor weight, and are usually located at the ends of each rotor. Some designs share a common bearing between rotors. The term journal is associated with the area of the rotor that is encircled by the bearing. While the journal bearing confines the rotor in the radial direction, it also allows the rotor to spin safely at high speeds on a wedge of oil. The bearing is lined with a soft material, usually tin-based babbitt. The babbitt can act as a sacrificial material if the harder rotor comes into contact with the bearing surface, and it also can absorb foreign particles too large to pass between the rotor journal and bearing babbitt without causing significant damage to the journal surface. Turbine-generator journal bearings are usually constructed in two halves that are split at the horizontal centerline. The halves are bolted together and use dowel pins in the horizontal joint to ensure alignment of the bearing halves. Journal bearing construction designs are usually tilting pad or elliptical. Tilting pad designs use either single or double tilting pads; the heaviest loaded pads are located in the bottom half of the bearing. The first step in forming the ellipse in an elliptical journal bearing is machining a cylindrical bore through the bearing with shims in the horizontal split line. The elliptical form is obtained by removing the shims when the bearing is assembled. The elliptical bearing has a primary loading zone in the bottom half of the bearing and a secondary zone in the upper half. The elliptical design with overshot grooves in the upper half passes more oil than a plain cylindrical bearing of comparable size; therefore, it should have fewer heating problems than a plain cylindrical bearing. Some elliptical designs are reduced in width and are designated as shortened elliptical bearings. Shown in Figure 5-3, elliptical and shortened elliptical bearings are a two-part construction. The inner bearing component, also known as the liner, contains the babbitt on the inside diameter and the outside is machined to a convex sphere also known as the ball. The outer component is the ring, and its inside diameter is machined to a concave ball seat.

5-30


Figure 5-3 Elliptical Bearing Construction

Turbine and generator rotors “sag” from the rotor weight distributed between the bearings. The ball seat allows alignment of the bearing assembly in the turbine pedestal to the sag geometry of the rotor journal. In an unbolted state, the upper ring has “ears” with a clearance between the ears and the horizontal split centerline of the bearing. After the bearing is aligned, the upper ring hold-down bolts in the ears are tightened. The tightening of the upper ring “pinches” the liner so that the bearing is locked in place. The amount of pinch is determined by the deflection of the “ears” as the ring hold down bolts are tightened. A thrust bearing absorbs and limits the axial movement or operating thrust of the rotor. The rotor contains integral collars that restrain the rotor to the limits imposed on it by the thrust bearing and the thrust bearing housing. Tilting pad and taper land thrust bearings are used in turbine / generators. Tilting pads come in a number of designs, but usually rely on six pads, three within each half of the bearing. The pads fit under lips machined in the bearing casing to prevent the pads from moving in a radial direction. Locating pins through the bearing housing into the pads prevent circumferential movement. To prevent seizing and to allow free tilting of the pads, the protruding pins have a smaller diameter than the holes in the pads. The tilting of each pad takes place between the back radius of the pads and the inner bore diameter of the casing in the region of the pins on a line contact. By making the back radius of the pads smaller than that of the housing produces the line contact. Tilting pads are self-aligning and therefore do not require bearing casing adjustment features like a ball seat of an elliptical bearing. Lubricant is provided to the bearing by flooding the bearing casing. Seal and drain orifices control lubricant flow out of the casing. Higher bearing temperatures are found on tilting pad thrust bearings because: •

Rotating journal forces oil away from the entrance spaces of the bearing

•

Constant churning of the oil in the flooded casing

•

Increased turbulence 5-31


Therefore, tilting pad thrust bearings have larger oil requirements and higher power losses. On the positive side, tilting pad bearings are an effective corrective measure for shaft instabilities. The increased bearing loads provide enhanced stability at light thrust bearing loads. The tapered land thrust bearing is comprised of two stationary plates that react with two collars on the rotor. The thrust plates are contained in a casing and are aligned to the rotating thrust collars. The surface of the thrust plates is babbitted and contoured to assist in the formation of the oil wedge between the rotating and stationary components. Oil is forced into the bearing and radial feed grooves provided between each of the contoured surfaces allow oil to be fed both at the base of the thrust plate and outwardly. The outer edge of the groove is damned to maintain a positive pressure within the bearing. Orifices in the oil feed pipes control the amount of oil entering each end of the bearing. The outer diameter of the assembly is spherically machined like an elliptical bearing to allow the thrust bearing assembly to be aligned to the rotor thrust collars. The thrust plates are pinned to the bearing assembly preventing rotation. Thrust transfer and axial movement is restricted by a tongue and groove machined between the bearing assembly and the standard. Table 5-7 lists a number of bearing conditions and damage mechanisms that may be found during an outage inspection.

5-32

Turbine-Generator Condition Assessment Table 5-7 Recommended Action for Bearing Damage Typically Found at Inspection Bearing Condition

Outage Activity

Remedial Action

Possible Consequence

Abrasion

Depending on severity:

Investigate lube oil and remove the contaminant and its source.

Scored rotor journal

Hand scrape Re-babbitt Corrosion

Re-babbitt

Investigate lube oil and remove the contaminant and its source.

Corroded rotor journal

Disbonding

UT inspection

Investigate the previous repair process.

Babbitt separation from liner and bearing wipe

Re-babbitt if unbonded area exceeds specifications Disbonding edge

PT inspection

Electrolysis


Re-babbitt if unbonded area exceeds specifications Hand scrape

Hot bearing Investigate the previous repair process.

Investigate the current source and inspect the shaft grounding system.

Minor repair

Hot bearing Scored rotor journal

Re-babbitt Excessive clearance


Bearing stability

Re-babbitt for elliptical Measure and re-shim for tilt pad Re-babbitt if required

Fatigue



Minor repair


Re-babbitt Lead contamination

Re-babbitt

Investigate the previous repair process/vendor.


Wiping


Any one or more combinations of the above conditions

Hot bearing

Hand scrape


Minor repair Re-babbitt Note: Any breakdown of the adhesion bond between the babbitt and the backing in the lower bearing half can begin to impact heat transfer and subsequent cooling through the bearing.

5-33


Pre-outage preparations that can be completed in anticipation of outage repairs are listed in Table 5-8. Table 5-8 Recommended Pre-Outage Preparations for Bearings System

Action

Journal bearing

Repair procedure prepared, minor repair - local tungsten inert gas (TIG) repair, major repair - re-babbitt, ball seat, qualified vendors selected, purchasing documents and process ready

Tilt pad bearing

Repair procedure prepared, minor repair - local TIG repair, major repair - rebabbitt all pads, qualified vendors selected, replacement pads, replacement hardware, purchasing documents and process ready

Journal repair

Repair procedure prepared, qualified vendors selected, purchasing documents and process ready

Thrust bearing

Repair procedure prepared (if parts unavailable), major repair - re-babbitt, qualified vendors selected, replacement parts, shims, thermocouples, thrust plates, purchasing documents and process ready

Proximity probes and data collection support software are excellent diagnostic and preparation tools. Unusual bearing conditions and circumstances can be “red flagged” before an outage, giving an early warning for inspection and preparation. Existing bearing thermocouples can provide limited information on a bearing condition. A bearing running hotter than normal may be the result of an operational change or the result of in-service wiping of the bearing. Babbitt can dislodge and limit journal movement within the bearing, causing increased loading and temperature. Unexpected reduction in the temperature of a hot bearing may be the result of a wipe or restriction clearing and the journal returning to normal position. A bearing improperly installed during an outage may provide operational information before the telltale wear pattern in the bearing is observed. Consequently, it is important for the turbine engineer to be aware of the bearing operating conditions as a forecasting tool for outage planning and preparation.

5.11 Stationary Components Figure 5-4 shows a typical diaphragm. The three major areas of a stationary system are listed in Table 5-9.

5-34


Figure 5-4 Diaphragm Construction

Table 5-9 Separate Areas That Form a Stationary System Steam Path

Structure or Body

Seals

Partitions

Ring and its components

Spill strips (removable, integral, insert)

Inner sidewall

Web and its components

Packing (addressed further in Section 5.13)

Outer sidewall

Each area is inspected during the outage to determine the exact repair scopes, but pre-outage planning can be accomplished by understanding the repair histories for each stage, wear, and damage mechanisms. Before the outage, the following should take place: •

The repair procedures are prepared.

•

Qualified vendors are selected.

•

Purchasing documents and process are ready. 5-35


Previous outage reports and repair recommendations should be the first in line of information used to create the work scope for diaphragm and nozzle repairs. That information can be confirmed or augmented by a review of each stage and the possible damage mechanisms associated with the stage. The following information is a review of damage mechanisms typically associated with diaphragms and nozzles: •

Solid particle erosion (SPE) is the result of very small particles having a very large economic effect on repairs and loss of turbine efficiency. The source of solid particle erosion is exfoliation of oxides from the inner surfaces of boiler tubes and steam piping. The oxide grows as these systems operate at elevated temperatures and the exfoliation occurs during lower loads. For a comprehensive study, see Reducing Solid Particle Erosion Damage in Large Steam Turbines [36]. The particles are carried to the turbine and do damage when the right flow and particle size distribution exists. The action is comparable to grit blasting the turbine components. The damage is most severe in supercritical units. Both diaphragm pressure side and suction side SPE can occur within the turbine. The primary effort to reduce the effects of SPE has been to combat the effects of SPE by coatings, increased set back, and partition re-designs. Damage from SPE tends to be limited to the HP section and first stages of the IP sections.

•

Water erosion caused by water droplets in the saturated steam is found in the wetter sections of the LP turbines. Component joints that have leakage paths can be heavily damaged from water erosion. Bucket tips, leading edges, and root trailing edges of the last stage buckets are also areas where water erosion is prevalent.

•

Foreign object damage (FOD) results when foreign objects either left within the steam path or introduced in the steam path come into contact with rotating and stationary components. FOD can result from weld slag or a tool left within the turbine; even turbine components themselves that come loose in service can cause dings, dents, and major damage. FOD can be found in any stage.

•

Deposits in the steam path are caused from boiler carry over, water treatment chemicals, and metals that can plate out on turbine buckets and diaphragm partitions. These deposits can block discharge areas causing a reduction of stage efficiency or creating initiation sites for corrosion damage. Stage conditions need to match the right steam conditions for the deposition of material to occur. The main corrosion mechanisms occurring in a turbine are corrosion fatigue (CF), stress corrosion cracking (SCC), and erosion-corrosion (EC). Pitting (P) and CF of blades and SCC of discs tend to dominate as the costliest problems. Corrosion in a turbine is complex and related to the environment including steam purity, moisture evaporation, crevice concentrations, oxides, pH, velocity, turbulence, “lay-up” duration and conditions, stress, stress concentrations and material properties. Metallic deposits can accumulate in the HP section, but corrosion deposits and P, CF, and SCC tend to occur in the latter stages of the LP section.

5-36


•

Cracking in the steam path is the start of breakage and the start of a component failure. Location, service environment, service requirements, etc. are evaluated when crack indications are found in steam path components. Run-repair-replace decisions for crack indications can occur anywhere in the steam path. Each turbine section is significant because of the potential problems that may result.

•

Component distortion is a common condition in the hotter turbine sections. Time, temperature, and stress on the steam path components influence the amount of distortion.

Table 5-10 presents a matrix that provides a review of damage mechanisms and corresponding planning options for each diaphragm area. Table 5-10 Recommended Action for Diaphragm Damage Typically Found at Inspection Location

Item

Discussion

Planning

Rings or webs

Centering pin fits

Some damage should be expected.

Include as a repair in the diaphragm repair procedure.

Rings or webs

Corrosion

Usually occurs in the LP section.

Rings or webs

Crush pins

Some repair/fitting will be required during outage, as a result of expected wear or physical damage.

Include as a repair in the diaphragm repair procedure for weld buildup

Fitting requires measuring the corresponding location in the shell and machining it to fit.

-or-

Repair includes welding and refitting for the clearance to the centering pin.

Repair information (material identification and work package) will be available for on-site utility repair

Rings or webs

Distortion dishing

HP and IP sections. This develops over time and should be anticipated.

Include as a repair option in the diaphragm repair procedure. It will require repair and re-machining.

Rings or webs

Distortion out of round

HP and IP sections. This develops over time and should be anticipated.

Include as a repair option in the diaphragm repair procedure. It will require repair and re-machining and may require replacement packing.

Rings or webs

Dowel pins

There is a low probability of in-service or disassembly damage.

Repair information (material identification and work package) are available for on-site utility repair.

The dowel pin requires removal if the horizontal joint is repaired. Rings or webs

Hook fit packing

There is a low probability that a repair will be required unless associated with dishing or out of round condition.

Include as a repair option in the diaphragm repair procedure. Machine support is required after repair buildup. Include in the pre-outage, development work package for spill strip hook fit configurations.

5-37

Turbine-Generator Condition Assessment Table 5-10 (cont.) Recommended Action for Diaphragm Damage Typically Found at Inspection Location

Item

Discussion

Planning

Structure

Hook fit Spill strip

SPE damage usually occurs in HP and IP sections.

Include as a repair option in the diaphragm repair procedure. Machine support is required after repair buildup. Pre-outage, development work package for spill strip hook fit configurations.

Rings or webs

Horizontal joint

Damage such as seal weld cracks, erosion, damaged keyways, and excessive opening can be anticipated.

Include as a repair in the diaphragm repair procedure.

Rings or webs

Horizontal joint bolts

Damage could possibly occur during disassembly.

Mixed sizes are available as spares.

Rings or webs

Horizontal joint keys

There is a high probability that higher temperature/pressure stages will require replacement.

Repair information (material identification and work package) is available for on-site utility repair.

This will require removal if the horizontal joint is repaired. Rings or webs

Rings or webs

Horizontal joint miscellaneou s hardware

There is a high probability that higher temperature/pressure stages will require replacement.

Horizontal joint threaded holes

Damage could possibly occur during disassembly.

Repair information (material identification and work package) is available for on-site utility repair.

This will require removal if the horizontal joint is repaired. Include as a repair option in the diaphragm repair procedure. -orRepair information (material identification and work package) is available for on-site utility repair.

Rings or webs

Rings or webs

5-38

Steam seal face and inserts

Support bars

Typical damage occurs from excessive movement and SPE. Significant damage may occur in the HP section from fretting, galling, and SPE.

Steam seal faces can be touched up and hand dressed if the damage is limited. Repair information (material identification and work package) is available for on-site utility repair.

There is a low probability of in-service mechanical damage, erosion, or corrosion.

Drilling and re-tapping if any work is done to high temperature diaphragms.

This may require disassembly for diaphragm alignment.

Replacement bars/shims should be stocked or material and machining process should be available during an outage.


Item

Discussion

Planning

Rings or webs

Welds

Although a low probability, some of the original factory welds may become distressed after time and require repair.

Pre-outage activity may be limited to understanding diaphragm construction and an awareness of repair options.

Repair may require mechanical securing and then welding. The amount of weld deposited may require stress relief. Seals

Spill strips removable

There is a high probability that replacements will be required for HP and IP section diaphragms.

A replacement can usually be ordered and received during an outage.

Damage includes erosion, corrosion (LP section), cracks, and FOD.

This requires early identification and correct part identification.

Approximately 50% of the heat rate loss associated with diaphragms is spill strip leakage losses. Seals

Spill strips integral

Located in the HP and IP sections. Damage of these strips includes erosion, cracks, and FOD.

Since this repair requires weld buildup and machining, early outage identification is helpful. Pre-outage planning includes work package development.

Seals

Spill strips insert

Located in the HP and IP sections. Damage of these strips includes erosion, cracks, and FOD.

Since this repair requires weld buildup and machining, early outage identification is helpful. Pre-outage planning includes work package development and part resource identification.

Steam path

Partition & sidewall damage

Surface damage includes: FOD, DPE, thinning (erosion), corrosion, and general in-service partition damage Generally, SPE occurs in HP and IP sections, and water erosion occurs in the LP section. Approximately one-third of heat rate loss associated with diaphragms is due to the surface condition of the partition. Trailing edge cracks are caused by differential cooling between heavier and thinner sections.

Include in the repair procedure. The general planning work scope should come from previous outage reports and recommendations. Pre-outage preparation should include compilation of diaphragm partition and machining dimensions. Plans to obtain data during the outage should be considered if the information is not available.

Fillet welds are structural in nature and weld cracks may result from differential thermal stress.

5-39


Item

Discussion

Planning

Steam path

Partial partitions at joints

The pins supporting these partial partitions may be damaged with the same mechanisms as full partitions.

Include in the repair procedure.

Steam path

Bridges

Bridges are structural in nature.

Include in the repair procedure.

Cracks and physical damage are typical discrepancies found.

5.12 Buckets/Blades Turbine buckets/blades are comprised of three basic sections: attachment, vane, and tip area (to include the bucket/blade area). The attachment of the buckets/blades to the rotor may be the same design and size for any number of stages on a rotor. The method in which the final bucket/blade is attached to close or complete a row may vary. The vane section and the tip configuration may be the distinguishing difference between rows of buckets/blades on a rotor. Vane sections are a combination of impulse and reaction designs. Most vane designs will differ from stage to stage restricting the interchangeability of stage from one turbine to another. An exception may be the L-0 and L-1 rows. Turbine stages are normally numbered with the first stage starting as the steam enters the turbine and continues in sequence until the last stage and steam exiting the turbine. An alternate method of identification usually used in the LP section of the turbine is to begin with the last row of buckets/blades and identify it as either the “L” stage or “L-0” stage, and then identify each preceding row in reference to the last stage. The next-to-last stage becomes “L-1,” then “L-2,” and so on as the reference moves against the steam flow. This is a useful convention because the L-0 and L-1 groupings share the same respective designs, operating conditions, and problems. Although turbines vary in number of stages, they can readily be identified and grouped according to last stage designation. Previous outage reports and repair recommendations are the first place to look for an outage action plan for bucket/blade replacements. External inspection access locations may also provide condition information before major outages. Understanding steam path damage mechanisms and having replacement component design information available prior to the outage should provide an edge against outage delays if the unexpected inspection finding occurs. Manufacturing of the buckets/blades would still be required if an outage inspection finding dictated replacements. It may not be practical to have design information created for all stages, but instead, a combination of complete design for priority stages, attachment details for shared attachments, and bucket cover and tip information will all help reduce the time required during an outage to make decisions and obtain replacements. Understanding bucket damage mechanisms and 5-40


sensitive stages will help in assessing which stages should have a design pool of information available. The following is a brief review of damage mechanisms typically associated with buckets/blades. Fatigue is widely classified as either high cycle or low cycle. High-cycle fatigue is associated with a high local stress in a moderate dynamic stress. Initiation may take a long time, but time to failure may be short after a crack begins. Growth may stop and restart as the dynamic stimulus is removed. Such intermittence may be the result of changes in operating conditions such as excessive condenser back pressure or partial arc operation. Low-cycle fatigue is associated with fewer cycles to failure and higher alternating strain ranges. Fewer cycles are required to initiate a crack and fewer cycles to propagate a crack than in highcycle fatigue. Often, fatigue is associated with some other initiating mechanism to create the stress riser. Stress concentrations may be formed as a result of: • • • • •

A geometrical change in the original design Created during the manufacturing process A maintenance process A heating or cooling process either during operation (for example, a rub) or repair A chemical attack such as pitting

Corrosion-assisted bucket/blade failures typically occur in the attachment area, but they are not limited to the attachment. Observing deposit buildup patterns before a rotor is grit blasted helps to identify possible locations of corrosion-assisted problems. Corrosion-assisted failures can also occur in cover/shroud areas, tie wire, or dampening attachment areas; anywhere that deposit buildup can occur. The presence of a corrosive environment can affect the material’s fatigue strength and, therefore, degrade the ability of the component to withstand the steady and dynamic stresses imposed on it. The bucket/blade and rotor material endurance limit can be significantly affected when a rotor is out of the turbine during an outage. Rotors left unprotected in moist outdoor environments can have local area corrosion accelerated. Physical damage to the exposed area of the bucket assembly occurs from three primary mechanisms: •

Erosion. Erosion within the steam path typically will take two forms: solid particle erosion (SPE) and water erosion. SPE damage is associated with the HP and IP section, and water erosion takes place on the outer-half leading edges of later LP stages. Covers and tenons are susceptible to both types of erosion. A general thinning of the vane section can also occur. SPE and water erosion tend to remove gross quantities of material and have very noticeable results; thinning is a gradual loss of material and is noticeable at the trailing edges.

•

Foreign object damage. Foreign object damage (FOD) is akin to erosion damage in that the rotating element is striking objects. The difference is the size of the objects. FOD damage can occur quickly and severely.

•

Rubs. Rubs occur in a radial or axial direction. Radial rubs can smear tenon and cover material or groove the root area of the bucket from the root spill strip. Axial rubs can also damage covers and root areas of the buckets. 5-41


Table 5-11 associates typical damage mechanisms to turbine sections. Table 5-11 Blade Damage Typically Found at Inspection Type

Attachment

Vane

Tip Area

Fatigue cracks

Notch keys Dovetail pins

Trailing edges Tie wire holes

Cover lifting Covers – predominately axial toward tenon

LCF

Notch area lifting

HCF

Notch area lifting Root radii

Creep

High temp. stages

Tie wire holes

Corrosion Pitting

Especially L-2 through L-0

Especially L-2 through L-0

SCC

Especially L-1

Especially L-1

Physical SPE

HP & IP sections

Tenons HP & IP Sections

Water erosion

L-1 through L-0 Leading edge Outer radius

L-3 through L-0 Covers Tenons

L-0 Trailing edge Inner radius Thinning FOD

Anywhere along vane section

Cover & tenon

Rub

Predominately radial. Concern if severe on: First HP & IP stages Last LP stages Evaluate axial

Predominately radial. Concern if severe on: First HP & IP stages Last LP stages Evaluate axial

Other

Fretting

EPRI report State-of-the-Art Weld Repair Technology for Rotating Components: Volume 2: Repair of Steam Turbine Blading, TR-107021-V2, provides weld repair details for turbine blading airfoils, erosion shields, tenons, and cover bands. Volume 2 of these guidelines, in Sections 5.2 and 5.3, also provides detailed procedures for blading tenon, tie-wire hole, and erosion shield repairs. 5-42


5.13 Rotors 5.13.1 Causes of Rotor Bowing First on the rotor problem list is rotor bowing. The following are causes for rotor bowing and are listed from the most common to the least common. 1. Severe rubbing 2. Water induction 3. Metallurgical •

Non-uniform material properties

•

Non-uniform residual stresses

5.13.1.1

Severe Rubbing

Rotor bowing caused by rubbing is a result of non-uniform local yielding and residual stresses. Rubbing occurs when the rotor body comes in contact with a stationary component such as oil deflectors, interstage packing, or end packing. The rub is usually a secondary effect of some other machine condition such as overly tight clearances or excessive vibration of the system. Rubs are usually transient in nature. For example, a rub on the interstage packing may eventually remove enough material to become a lighter rub and eventually eliminate itself. Rubs can be in either the radial or axial direction. A full annular type of rub would occur when the rotor is in continual contact with a stationary component. A partial contact rub is the more common of the two and can be either a single-point rub with the stationary component or a multi-point rub where contact is at multiple locations When the rub is a combination of impact and rubbing friction on the stationary component, the impact usually creates a secondary effect in the form of a rebounding motion. This type of rub will cause circumferential temperature gradients from the friction that is created and is usually more severe on one side of the rotor. If the rotor bows, it will do so gradually toward the rub or “high spot.” This is as a result of the fact that the hot area expands and yields in compression, which causes the rotor to bow toward the rub. A simplified sketch of the orbital motion of a rotor is shown in Figure 5-5 [37]. Note that the high spot always faces out. The high spot comes in contact with the stationary component, causing the rub.

5-43


Figure 5-5 Mechanics Describing Rubbing Process

The following is the sequence of a rub at constant rotational speed below the rotor first resonance speed: 1. Due to the rub, the shaft bows in the direction of the high spot and a new unbalance force occurs. 2. The original and rub-related unbalances add together, producing an “effective” unbalance force. 3. At a constant rotational speed, the phase lag between the effective force and response (high spot) is constant. This means the shaft has to rotate, yielding a new high spot. The magnitude of the rotor orbit also increases as the center of mass moves away from the center of rotation. This causes greater unbalance, causing the rotor to rub harder. 5-44


Severe vibration effects may occur during constant speed while the rotor is operated close to or below its first critical speed. Some turbines use vibration detection equipment where the response of the pickup falls off rapidly below 800 rpm and is virtually ineffective below 500 rpm. Therefore, it is difficult to detect potentially destructive levels of self-accelerating vibration from rubbing below 800 rpm when the vibration equipment detection capability is limited. Operation at a constant speed below the vibration equipment detection level should be avoided. Vibration levels for slow-speed balanced modern HP and IP rotors at 1000 rpm should be nearly zero. A 5 mil (0.127 mm) vibration should be unusually high for those rotors at 1000 rpm and may be indicative of a rub. Two conclusions result from the above: •

Operating turbine rotors at a constant speed below vibration equipment detection levels should be avoided.

•

Unusual vibration at slow speeds may indicate packing rubs, and the turbine should be returned to turning gear to “straighten out” the rotor. The rotor should not be operated at low speed to clear the rub.

Rubs occurring above the first critical speed will cause the center of mass to move toward the center of rotation and decrease the magnitude of unbalance. Very hard rubs above the first critical speed are required to excite the rotor. The effects of in-service rubs are reduced if the unit is operating at high load and high steam flow; the steam flow tends to cool the hot spot, reducing its effect. Having “pushed” through a rub to above the first critical speed is not insurance that the rub has cleared; it will probably be experienced again on a future coast-down. In most cases, the machining action of a rub will eventually provide the increased clearance for smooth operation. The exception to increasing clearances by rubbing is associated with non-metallic materials such as textolite and some packing designs that use a slant-tooth design. Slant-tooth design uses a different material, tends to flex out of the way instead of rub away, and increases its crosssection as it is rubbed. The consequences of increasing clearances by rubbing are: •

Reducing sealing efficiency at the rub location

•

Damage to the stationary component

•

Damage to the rotating component

It is important to minimize rotor deflections during the rubbing process to minimize the clearance increase caused by rubbing. The efficiency of the seal will be reduced because of the damage to the sealing profile, but reducing the amount of clearance opening can minimize the consequences. Several seal designs are currently available to withstand the effects of rotor deflections during operation. The rotor maintains a permanent bow if the overheating caused by the rub is severe enough that sufficient area is heated that has expanded and yields in compression. This helps move the rotor toward the rub. Then, as the rotor normalizes in temperature, the material in tension tends to bow the rotor in the opposite direction. 5-45


5.13.1.2

Bows Caused by Water Induction

Rotor bows caused by water induction result from a hot rotor being quenched so that it yields in tension, thereby causing the rotor to bow away from the cooled spot. As the rotor normalizes in temperature, the yielded material tends to bow the rotor in the opposite direction. Water induction into a turbine section can also cause distortion of shells, which “hump” into the rotor causing severe rubs. 5.13.1.3

Bows Caused by Metallurgical Problems

The least common cause of bowing is from metallurgical problems in the rotors. The cases are few but documented. Metallurgical bows are not well understood, but they are usually associated with high-temperature rotors and may be the result of non-uniform yield strength and material creep properties. Turbine manufacturers changed the heat treatment requirements for turbine rotor forgings in the early 1960s to control impurities and provide more uniform material properties. The progression of the bow is slow and, therefore, corrective action can easily be planned. 5.13.1.4

Corrective Actions

The following actions are available for bowed rotors: •

Balance to offset unbalance

•

Straighten mechanically or thermally

•

Heat lathe to straighten

•

Re-machine new compromised center of mass

Rotor run outs should be taken at each outage inspection on high-temperature rotors. Historical readings will help to plot any rotor bow and predict a growth rate. Run-outs should be taken early in the outage to provide a warning for any unexpected condition. In-service balancing information will also provide a warning of any changing condition. Requirements for in-service mid-span or static balance shots may be indicative of an increasing rotor bow. Rotors are manufactured to a run-out tolerance of one mil (0.0254 mm). Anything in the field that is 3 mils (0.0762 mm) TIR or less is considered acceptable and is only slightly bowed. Rotors with 6–7 mils (0.152–0.177 mm) TIR of bowing (between bearings) are considered to have a minor bow that should be correctable with slow-speed balancing. Rotors with 10 mil (0.254 mm) TIR or greater are considered severely bowed, and corrective action should be applied. The corrective action for a severely bowed rotor may be a combination of heat lathe straightening and machining. The heat lathe may remove a portion of the run-out ranging from 25% to 33%. The heat lathe also reduces residual stresses created during the bowing process.

5-46


A machining plan is developed after taking a comprehensive set of run-out readings. A new center is determined for the rotor. New diaphragm packing, end packing, coupling bolting, and resized journal bearings are the typical components required to install a re-machined rotor. 5.13.2 Other External Rotor Problems Other types of external rotor problems include: •

Seal area damage associated with rotor rubbing

•

Corrosion - seal areas/rotor body, especially the LP/bucket/blade attachments

•

Attachment creep in high-temperature rotors

•

Journal scoring

•

Oil deflector area scoring

•

Coupling bolt hole damage

Except for the possibly of journal damage, the external rotor damage would be determined during an outage. Damage and its extent are determined by visual inspection, NDE replication, MT, and UT during the outage. UT can be used to inspect rotor areas that are not available to direct sight inspection, such as the rotor dovetail with the bucket/blade installed. The type of repair needed would normally be machining of the damaged area and redesigning the corresponding component. An extreme repair would include a weld repair for the damaged area. Possible rotor body problems include cracks. Rotor cracks have been detected by using a vibration detection system that uses proximity probes. The information provided by the proximity probes, displayed in cascade, polar, 2X amplitude phase time (APHT) plots, and 2X orbits associated with APHT plots, are used to evaluate the rotor condition. The frequency of inservice rotor cracking is increasing because rotors are running longer between inspections and more units are being called upon for peaking duty. A transverse crack occurs most frequently with a slight variation of a cup shape occurring under a shrink fit and has the appearance of a tension fracture in ductile material. Torsional cracks appear less frequently than transverse cracks and are readily identifiable. Longitudinal and transverse symmetrical cracks are rare. The following are a few things to remember about cracked shaft detection: •

A cracked shaft is a bowed shaft.

•

A rotor system with an asymmetric shaft and a radial side-load force rotating at a speed near half of any resonant frequency may experience high 2X vibration amplitude and 2X phase shift.

•

In roughly 75% of the cases, the 2X component does not occur at operating speed.

Taking torsional coupled with lateral vibration measurements will assist in vibration analysis for rotor crack detection. 5-47


As a result of two generator shaft cracking events experienced at a large nuclear generating station in 2004, EPRI produced a technical report containing a tutorial on the subject. Generator Rotor Shaft Cracking Management Guide, 1011679, [61] includes a discussion of turbinegenerator shaft torsional dynamic behavior, sources of excitation from the generator or grid, locations of damage and mechanism involved, viability of ultrasonic testing for shafts with shrunk-on couplings, effects of unit uprates, and monitoring schemes.

5.14 Shaft Seals Typical damage that occurs to steam deflectors, interstage (diaphragm) packing, and shaft packing during operation is the following: •

Erosion – solid particle and water

•

Corrosion – chemical attack

•

Cracks – brittle

•

FOD

•

Electrolysis

•

Abrasion

A rub is the other damage that occurs to the rotor body shaft and diaphragm packing in addition to the above list. Since spill strip clearances are greater than rotor body sealing clearances, they do not normally rub. The predominant wear for spill strips is erosion. Each packing strip and each spill strip have a spring pushing on them to keep them in their smallest diameter position. These springs are inspected for freedom of movement and cracking when the sealing component is inspected. Unlike turbine seals, modern generator hydrogen seals made with steel backing and babbitted seal surfaces are designed to float. The seal moves “freely” with the rotating shaft radially but is restrained from rotating with the shaft. The hydrogen seal is made of two sealing rings. Oil is forced between the outer ring (air side) and the inner ring (gas side) at a pressure (typically 4.5 psi [31 kPa]) greater than the generator hydrogen pressure. Oil flows between the constricted space between the seal and the rotor, preventing hydrogen gas from leaking along the rotor. Smaller clearances are found in the hydrogen seals than in any other rotating sealing areas within the turbine-generator. If, for some reason, the rings are prevented from floating, damage to the hydrogen seal can occur by: •

Contact between the shaft and the seal

•

FOD or particles entrained in the oil trying to pass between the tighter clearances

•

Electrolysis

An offset seal will cause “burning” or “varnishing” from heat buildup and insufficient oil flow to cool the seal. Damage to the hydrogen seal will reduce sealing capability and cause hydrogen “consumption” to increase.

5-48


Some seals or deflectors are assembled to compensate for rotor sag. The seals or deflectors are assembled with equal clearance on each side, but biased to the vertical clearances. The top usually has two-thirds of the clearance, and the bottom portion has one-third of the clearance. For example, if the total seal clearance is 30 mils (0.76 mm): •

Each side is set at 15 mils (0.381 mm) clearance.

•

The top clearance is set at 20 mils (0.51 mm).

•

The bottom clearance set at 10 mils (0.25 mm) clearance.

Contact and damage to these seals or deflectors can occur if they are not assembled properly. Table 5-12 lists typical design clearances for sealing areas. The listed operating clearance is based on experience and falls on the outer tolerance edge of the design clearance. Maintaining design clearances requires that a machine be aligned within tolerances, but this does not account for the operating variables that can increase the sealing clearances. Table 5-12 Typical Seal Design Clearances with Field Tolerances Seal

Design Clearance

Field Tolerance

Operating Clearance

Spill strip

See the clearance diagram provided by the OEM.

± 15 mils (± 0.381 mm)

Root radial


± 10 mils (0.254 mm)

Root axial


± 10 mils (0.254 mm)

Diaphragm packing

15 mils (0.381 mm)

+10 to -5 mils (+0.254-0.127 mm)

25 mils (0.635 mm)

Steam packing

15 mils (0.381 mm)

+10 to -5 mils (+0.254-0.127 mm)

25 mils (0.635 mm)

Hydrogen seals 3600 rpm, babbitted steel

10 mils [< 20” Ø] (0.25mm)

± 1 mil (± 0.025 mm)

10–15 mils (0.25-0.38 mm)


12 mils [20” Ø] (0.30mm)

± 1 mil (± 0.025 mm)

15–20 mils (0.38-0.51 mm)


10 mils (0.25 mm)

± 1 mil (± 0.025 mm)

20 mils (max) (0.51 mm max)

Hydrogen seals 3600 rpm, bronze

8 mils (0.20 mm)

+1 –0 mils (+0.025 –0 mm)

Hydrogen seals 1800 rpm, bronze

3.5 mils (0.09 mm)

5-49

Turbine-Generator Condition Assessment Table 5-12 (cont.) Typical Seal Design Clearances with Field Tolerances Seal

Design Clearance

Field Tolerance

Operating Clearance

Air deflectors aluminum Alterrex

50 mils (1.27 mm)

+25 –0 mils (+0.64 – 0 mm)

Oil deflectors 1800/3600 rpm

20 mils [8-15” Ø] (0.51 mm)

+5 –0 mils (+0.13 –0 mm)

2 mils/inch Ø (0.02 mm/cm)


30 mils [15-21” Ø] (0.76 mm)

+5 –0 mils (+0.13 –0 mm)



40 mils [21-31” Ø] (1.02 mm)

+5 –0 mils (+0.13 –0 mm)



50 mils [31-40” Ø] (1.27 mm)

+5 –0 mils (+0.13 –0mm)


Oil deflectors Textolite exciter

25 mils (0.64 mm)

+5 –0 mils (+0.13 –0mm)

Oil deflectors aluminum exciter

15 mils (.38mm)

+5 –0 mils (+0.13 –0mm)

From experience, nominal clearance may be as high as 2 mils per foot (0.0508 mm per 30.48 cm) of rotor span between bearings. This value has been observed from many inspections and is an average row clearance after normal operation. A clearance of 34 mils (0.8636 mm) can be expected for a rotor with 17' (5.18 m) between bearing spans. Packing and spill strips are inspected for radial rubs. The corresponding rotor, bucket, and cover areas should also be inspected for severity of rub. Sharp edges and deep grooves should be addressed and blended. Some spill strip rubs are the result of a corner lifting on a bucket cover. The following is a list of conditions that might be found regarding rubs: •

A consistent rub around the circumference of the rotor may indicate tight clearances or that the rotor was bowed during operation.

•

The diaphragm may be out of round if sealing teeth are rubbed on the top and bottom.

•

Alignment may be the issue if the teeth are rubbed only on the top or bottom. It may be general alignment; it may be a single diaphragm out of alignment. It may be necessary to perform a tops-on/tops-off alignment procedure.

•

Rubbing only on the bottom of the rotor may indicate shell humping from water induction.

5-50


Axial ledges on wheels and bucket cover edges should be carefully inspected for axial rubs. The corresponding areas of the diaphragms should be inspected. The damaged area may require either hand blending or re-machining, depending on the severity of the rub. The high-low labyrinth teeth of packing and the corresponding rotor location should be inspected for axial rubs. Incorrect packing may be the cause of a single location rub or differential thermal growth. The repair may require re-machining a new labyrinth sealing area. New designs are available to increase both the sealing efficiency and the longevity of the seals. Packing is designed and in service that at no and low loads retracts from the sealing position and provides an addition clearance of approximately 60 mils (1.52 mm). The additional clearance is a benefit during startup when rotor vibrations may be excessive, which may be the case during a startup after an outage. The first roll or two may have higher than desirable vibration levels until the rotor is balanced for operation. EPRI report Evaluation of Replacement Interstage Seals for Turbine Upgrades, 1010214, [57] evaluates the typical economic benefits of improved interstage packing, identifies the various seal and packing design alternatives available, describes their functionality, and describes any O&M issues that have been observed in their use. Evaluation Tool for Cost Effective Steampath Upgrades, 1004565, [58] provides engineers with a basic understanding of the underlying principles of the new advanced designs of replacement steam path components and analysis tools for large turbines. The report will also include guidance on the relative value of various new design features on the overall improvement. The unique design issues associated with fossil and nuclear turbine performance will also be covered, as well as the overall plant cycle issues that are involved in upgrade or uprate decisions.

5.15 Valves 5.15.1 Stop Valves The stop valve primary function is to provide a second line of defense against energy from the boiler failure in the event of a control valve failure. The main stop valve also closes as a routine activity when the turbine is tripped. Some stop valve designs also incorporate a bypass valve that is used as low load control valve. The components that make up typical stop valves are: •

Lid

•

Disk assembly – cap/bypass valve/disk

•

Seat

•

Pressure seal head assembly – pressure seal head/bushings/valve stem

•

Steam strainer

•

Valve actuator – hydraulic components

5-51


Typical maintenance for stop valves addresses the wear areas of the valve. The primary wear areas of the stop valve assembly for high-pressure turbines are the bypass valve and the disk assembly. The primary wear mechanism is SPE, but water during startup can also do significant damage. Water can accumulate and erode the valve components if the drains that are incorporated in the valves are not functioning before and during startup. The bypass valves are used for full-arc admission during turbine starting. Bypass valves come in a variety of designs and configurations; they can be coated or uncoated; skirted or unskirted; solid stellite, overlay stellite, or no stellite. Upgrades for bypass valves and stems are provided to combat the effects of SPE. The upgrades include redesign of components, diffusion coatings, overlay coatings, material changes, etc. Other potential valve internal wear areas include stem bushings, disks, and seats. Intervals, methods, and details for the valve body (casing) internal inspections are typically recommended by the original equipment manufacturer. The typical internal areas to be inspected after grit blasting are: •

Intersections – valve inlet/outlet/equalizer

•

Connections – valve body/stop valve seat ledge region

•

Stop valve dam-to-casing welds

Internal inspections look for the effects of age and operation, typically displayed as cracks. Some components may need to be modified as operational changes take place (base load to cycling). Some of the internal areas that may require modification are sharp radius interfaces such as the steps in diameters of the lid. External connections of main stem piping should also be included in a comprehensive inspection program. The effects of age, operating temperature, local stresses and operating practices in the right combinations will be reflected as some level of creep damage. It is important to pay appropriate attention to valve casing inspections especially as units extend the intervals between major outage periods. Pre-outage planning should incorporate some level of preparation for crack indications from the outage inspection. The planning could include gathering and collecting the necessary information if a weld repair would be required for a main steam attachment weld. Condition Assessment Technology for Steam Valves, 1010211, [59] is a generic guide that describes methods and procedures for valve disassembly, assessment of condition and wear, and proper reassembly for long-term operation. The guide contains specific procedures for 12 commonly used steam valves in full-speed and half-speed turbines. 5.15.2 Control Valves Control valves provide the first line of defense against turbine overspeed during emergency conditions. The control valves control turbine speed and load by increasing or decreasing steam flow into the HP turbine. A typical control valve consists of: •

Stand assembly – stand/bushings/valve stem/disk

5-52


•

Seat – seat stellite/seat pins

•

Valve actuator – linkage/hydraulic components

Control valves are exercised continuously during operation; therefore, the greatest wear area is bushings. Bushings support and restrain the valve stem and are also found in each interface of the operating linkage. Control valves require the same internal and external inspection as stop valves, but in addition, the control valve seat stellite inlay and seat pin welds need to be inspected. The critical external weld inspection area is the weld to the main steam leads if the valves are separately mounted. Control valve condition assessment is covered in EPRI report 1010211 mentioned in the previous section. 5.15.3 Reheat Stop Valves The reheat stop valve (RHSV) is similar in maintenance activities to stop valves and serves similar functions. The RHSV provides emergency protection as the second line of defense against turbine overspeed from stored energy in the reheater. The intercept valve (IV) is the first defense. Control circuitry provides trip anticipation and valve actuation for the IV. Normal operation of both valves is wide open. Reheat valves can be either separate or combined into one valve called a combined reheat valve (CRV). Reheat stop valve condition assessment is covered in EPRI report 1010211 mentioned in the previous section. 5.15.4 Non-Return Valves The non-return valves (NRV) are located in the turbine steam extraction system. The turbine extractions provide steam to the unit condensate and feedwater heater systems. The available energy stored in the extraction piping and heaters is often sufficient to significantly contribute to turbine rotating speed during a turbine trip. The NRVs are comparable to a free swing or a power-assisted check valve. In acting as a free swing check valve, the flapper or disk allows flow to enter and freely move through the valve. The disk pivots downward as flow diminishes. The disk will seat if flow is stopped or if a flow reversal occurs. The power assistance is used for valve closure, and it causes the valve to close before flow reversal occurs. An NRV may be equipped with a single-acting spring to close the cylinder connected to the swing arm. Upon loss of signal or a turbine trip, air is removed from the cylinder, allowing the spring to close the valve at low flow and before reversal of flow. The NRV prevents a flow of steam to the turbine that would either cause or contribute to a turbine’s overspeed. The typical NRV shown in Figure 5-6 is not designed to handle reverse water flow, but it may be called upon to act as a line of defense against water induction, even though valve design does not guarantee tight closure. 5-53


Figure 5-6 Typical Non-Return Valve Construction

Typical maintenance requirements for this type of NRV address the following wear areas: •

Bushings for the swing arm shaft

•

Swing arm shaft

•

Disk and post assembly

•

Seat

•

Seals-double bearing covers-not external closure assistance/soft packing/mechanical seal

•

Operating cylinder

Seat and disk closure condition is important to the operation of the valve. Outage inspections typically reveal some amount of seat damage from disk closure impact or FOD. Often, the damage can be lapped out easily. Other times, either repair to the inlay or replacement of the valve is required. Seat inlays are usually made from stainless steel or a hard-face material like stellite. Sealing condition checks can be performed during non-major outage periods. By removing the lid during non-major outage periods, a visual internal inspection and a tissue paper test between the disk and seat can be performed, providing valve condition and sealing information.

5.16 Casings, Steam Chests, and Nozzle Chests The pressure-containing components of turbine sections are comprised of: •

Outer shells

•

Inner shells

•

Casings

•

Exhaust hoods

•

Nozzle boxes

5-54


The high-pressure section is comprised of thick-walled, high-quality alloy castings. The intermediate- and low-pressure sections may be made from castings of thinner section thickness, fabrications of welded construction, or combinations of both. The higher temperature materials will generally be a variation of 1.5% chromium, 1% molybdenum, and similar to ASTM standard materials for the same temperature and pressure service. Lower temperature materials may be cast steel or cast iron. Temperature, pressure, and service are considerations for the material selection. Repair welding can generally be done on steel and alloy castings. The appropriate weld procedure, consideration of component geometry, and thermal expansion are essential for serviceable repairs. Multiple shell construction is used as pressure boundaries, diaphragm carriers, and extraction locations between turbine stages. Unit construction and operation induces stress in the components as they are heated and cooled to meet operating conditions. The internal areas respond quicker than the external areas. The turbine rotor responds thermally much quicker than shells and if not warmed or cooled uniformly with the shells may cause axial rubs. The lower temperature section is not as susceptible to temperature stresses as the higher temperature section. Lower temperature sections are relatively lighter in construction and more flexible. However, thermal cycling of a unit has an impact on all the sections. The typical maintenance concerns of turbine casings from operation are: •

Distortion

•

Cracking

•

Erosion

•

Galling

Casing distortion is a common problem associated with service at elevated temperatures. The most common form of distortion is “clam shelling” or “smiling.” The horizontal joint is open toward the center of the section and closed at the outer edges when viewed along the axis of the machine. Another form of distortion is “humping,” where the horizontal joint is open on the ends, closed in the center at the outer flange, and open in the center of the inner flange. Shell distortion is often linked to water induction incidents. The effects of distortion range from a nuisance to disassembly/reassembly problems. Efforts may be made for thermally relieving some of the stresses or re-machining the shell. Planning preparation including resource identification and repair options can be evaluated as preparation for an outage if a section has experienced a water induction incident. Most cracking in high-temperature shells is a result of thermal stresses where stress concentrations, section changes, etc., respond to differential heating and cooling, causing high stresses. A typical repair for cracks is to grind out and blend them. Severe cracks require stitching, weld repair, or other action to restore the integrity of the shell. Shell geometry should be reviewed to reduce stress concentrations as preparation for increased cycling duty. Lowpressure and temperature sections also experience increased cracking from operational changes. Fabricated sections should also be reviewed for stress risers and pre-outage planning accomplished to address repairs and preventive measures. 5-55


Solid particle erosion occurs in higher pressure and temperature sections while water or steam erosion occurs in lower pressure and temperature sections. Welding and machining in higher temperature sections typically repair the erosion damage. Ductile filler materials are typically chosen for repair. Low-pressure and low-temperature sections can be repaired with material replacement products that can be cast. Pre-outage planning would include identifying resources and materials for repairs. Component assembly face galling may be the result of distortion, oxide buildup, tight clearances, or interference fits. Repair is typically cleaning and removing the torn material but weld repair and re-machining may be appropriate. Other problems that may be encountered while doing shell inspections are: •

Casting defects

•

Welding defects

•

Fabrication defects

Each defect should be evaluated for its impact on the serviceability of the component. Not all defects are harmless and not all are serious. An attempted repair may increase the scope of work without increasing the serviceability of the component. Therefore, considerations should be given to: •

The cause of the indication

•

The stresses in the area

•

Probability of propagation

•

History of the section and indication

•

Possible operation changes that might impact the indication

A brief list of things to consider when reviewing the need for a casing repair is provided in Table 5-13. Table 5-13 Casing Repair Issues

5-56

Item

Relevant Factors

Base Material

Composition, weld ability, wall thickness, minimum wall to retain pressure, allowable stress at temperature, operating stresses

Indication: General

Location (surface, subsurface, proximity changes), geometric, thermal, pressure

Indication: Weld

Geometry, depth, extent, orientation, type

Crack

Pinhole, casting flaw

History

NDE (methods, results), repairs, operating conditions, operation pattern

Repair Options

Mechanical, welding


5.17 Generator 5.17.1 Classifications Generators are classified not only by their capability but also by their speed (number of poles), type of cooling, number of coolers, type of coolant, coolant flow path, retaining ring attachment, and type of frame construction. Table 5-14 presents examples of combinations of cooling design and retaining rings: Table 5-14 Combined Cooling Designs with Retaining Rings Cooling Design

Retaining Ring Design

Diagonal flow

Body mounted

Radial flow

Body mounted

Conventional cooled

Spindle mounted

Conventional cooled

Body mounted

Direct cooled

Spindle mounted

Direct cooled

Body mounted

Nested within the generator identification are the types of auxiliary systems that support the generator. This identification system identifies additional equipment that may require pre-outage maintenance planning, outage inspection, repairs, etc. The coding may also help identify a “family” of generators that are experiencing very specific maintenance problems and require special planning before and attention during the outage. Generators can be broken down into two major areas: stator and field. The purpose of the generator inspection is to determine the condition of these two areas and evaluate them for continued reliable service. This may mean repairing conditions found during the outage or postponing action until a future outage. To accomplish this, each area will receive both mechanical inspection and electrical testing during the outage. The EPRI report Guide for On-Line Testing and Monitoring of Turbine Generators, 1006861, [38] describes a variety of generator on-line monitors and generator detectors. The guide is in the form of a spreadsheet where a user can specify the generator they are inspecting and then get extensive technical help in the form of a detailed failure mechanism and monitor description. These results can assist with defining the most appropriate on-line detection system. When considering the replacement of the generator rotor or stator, Sections 8 and 9 and Appendices E and F in Volume 4 of these Guidelines will guide the utility engineering and purchasing organizations through the process of procuring a generator stator rewind or an entirely new generator stator.

5-57


While preparing these procurement specifications, many engineers may not be entirely familiar with the terms and technical implications of these specifications. The following is a list of references that will further the technical understanding of these terms: •

G. Klempner and I. Kerszenbaum. Operation and Maintenance of Large Turbo-Generators. IEEE InterScience Series, Wiley Press, 2005.

•

M. G. Say. Alternating Current Machines. Pitman Publishing, 1978.

•

E. Fitzgerald and C. Kingsley. Electric Machinery. McGraw-Hill, 1971.

•

IEEE Guide for Operation and Maintenance of Turbine Generators. IEEE Std. 67-2005.

•

General Electric Company. Generators for Utility and Industrial Applications. GE Industrial Power Systems, GET-8022, October 1992.

5.17.2 Generator Stator The stator core serves a mechanical and an electrical purpose. The mechanical purpose is to support the stator winding. The electrical purpose is to provide a return path for the lines of magnetic flux induced by the field. A visual inspection of the stator core starts with carefully inspecting for signs of localized heating or damage of the core inner surface. The stator core is comprised of enameled insulated “punchings” that are assembled to a key bar. Overheating of the punchings can occur at the inner diameter (air gap) if enough punchings are damaged and are shorting together. In some cases, as few as two laminations shorted together would mean a repair and restacking of the core would be necessary. Hydrogen-cooled generators require paying particular attention to this when inspecting. An oxide builds up on the overheated area and limits conduction, eventually limiting the overheating in air-cooled generators, but in hydrogen-cooled generators, there is no oxygen to limit the process. Removing the damage with a de-burring tool and re-insulating the punchings can restore these areas. During their inspection, the windings can be tested to determine if they have been affected by thermal aging. Electrical insulation used in stator and rotor windings has a major impact on the reliability of large motors and generators. Insulation failure, whether direct or indirect, will result in machine failure, which leads to forced outages, reduced reliability, increased maintenance, and repair costs. EPRI report Testing of Stator Windings for Thermal Aging: Interim Results, 1004557, [39] deals with this issue by correlating thermal aging of stator coil/bar insulation to dielectric changes measured at frequencies other than 60 Hz. This project has not been completed, but the results so far have shown that measuring the dielectric changes in the test insulation with non-60 Hz techniques can identify aging. This project should be complete in 2003 and can help improve maintenance of stator windings. The punchings are also inspected for movement. Normally, clamping force from the stator clamping flange holds the punchings tightly together. The telltale sign is dusting or “greasing,” which is a dark, spotty accumulation if a punching is moving. Generator construction normally

5-58


limits access to the backside of the punchings and the attachment to the key bar. This area is inspected from the ends and ventilation areas to look for movement between the punchings and the key bars. Baffles can be either installed at the ends of the core or mounted to the inner end shield. The baffles should be inspected for cracking in the mounting hardware or the supports, vibration, or fretting, especially at any possible locations of contact with the windings. The attachment hardware should all be nonmagnetic. Stator windings pass through slots in the punchings and wedges retain the windings. The wedges are inspected for looseness or movement by using a small ball peen hammer and tapping the wedge, feeling and listening for changes in sound. Some wedge movement and fretting may be the result of slight movement of the core during normal operation. The corrective action will depend on the type of generator insulation and wedges. A numbering convention should be used to identify the wedges. Generally, a numbering convention begins at one end of the generator and numbers in ascending sequence along the length of the slot to the other end. The usual convention is to number from the turbine end to the collector end of the generator. The numbering convention will also include a radial orientation for the slot location. Typically, the radial location begins with a top bar referenced to one of the terminal connections and increases with reference to the rotation of the field. The stator windings have three areas of inspection: the slot portion through the core; the end winding area past the core; and the end windings support system. Borescopes are used to increase the range of the inspection when examining the stator windings. Excessive winding movement and vibration may be detectable by borescope examination through the ventilation ducts. Dusting on the side of the bar may be evidence of undesirable bar movement. Bar action may also cause chafing on the slot armor cutting through the armor. High-current generators are more susceptible to bar movement and vibration because the forces exerted on a bar during operation varies approximately as the square of the current. The type of insulation used in the construction of the bars is also a factor in how much movement and vibration may exist during operation. The end windings should be inspected for signs of relative movement that may be expressed as cracking in the taping. The copper bars expand at a different rate than the iron core; therefore, the copper bars may have a tendency to expand faster and more than the core as generator loading is changed. Insulation changes that better contain the windings have helped to reduce this condition. Inspection and repair requirements may extend beyond the end windings into the ends of the core if cracking conditions are found. Inspection of the end windings also includes looking for any looseness or relative movement between components. The condition of the stator winding insulation system for a turbine-driven generator can be checked by partial discharge (PD) and electromagnetic interference (EMI) on-line testing. These tests can offer advantages in avoiding prolonged generator shutdown for off-line tests and inspections. PD is a time domain measurement, and EMI measures activity with a frequency scan. Both tests evaluate high-frequency currents that flow as a result of electrical discharges 5-59


occurring within the structure. The EPRI report Assessment of Partial Discharge and Electromagnetic Interference On-Line Testing of Turbine Driven Generator Stator Winding Insulation Systems, 1007742, [40] evaluates the tests and gives an appraisal of their effectiveness. The results show that systems being able to monitor activity over time can add another dimension to the diagnostic process. Broken ties, loose or missing blocks, distortion, or cracking may all be evidence of high-level generator response to faults or system disturbances. These are repaired by securing, reinforcing, and re-taping. The end windings may also display signs of corona. Typically, these would be seen as whitish, brown, or yellowish accumulation of discolorations. Minor corona deposits are typically just cleaned off, but more intense activity may require providing “bridges” to dissipate the surface charge. Many later design generators must deal with stator bar liquid connection problems. Generally, the hose connections are inspected for movement, abrasion, fretting, cracks, or surface contamination. It is important to keep the hose surfaces clean because dirt or other substances on these surfaces can form a creepage path to ground. The corrosion of the brazed bar end connections is an additional problem you must be aware of. This area is inspected using a hydraulic integrity test (HIT). Leakage in this area may result in wet bars, ends, etc. A variety of repair methods are available today. Some repairs include epoxy injections that repair and seal the area from addition corrosion. It has been found that water-cooled generators have clip-to-strand leakage due to localized crevice corrosion as referred to above. EPRI has investigated this problem, and report Conversion to Deaerated Stator Cooling Water in Generators Previously Cooled w/ Aerated Water: Interim Guidelines, 1000069, [41] outlines how generator stator coolant water can be safely and economically converted from an oxygen-rich (aerated) to an oxygen-rich (deaerated) condition. With generator cooling systems, there are problems with recirculation and deposition of solid matter in the cooling water, which can lead to flow restrictions and inadequate cooling of electrical components. Depending on the magnitude of the flow restriction, various malfunctions may occur. One example of these is local overheating of a stator bar above the long-term temperature limit of electrical insulation. Another problem could be the loss of cooling of a stator bar that leads to overheating or melting of the bar. Due to unexpected problems, it is useful to have a process that monitors the system for flow restrictions and to have options for removing them. The EPRI report Guidelines for Detecting and Removing Flow Restrictions for Water-Cooled Stator Windings, 1004704, [42] gives guidance in this area. The guide reviews various approaches for detecting and removing flow restriction in hollow stator bar strands. It provides an appropriate procedure to conduct a visual inspection that is supported by mechanical means in order to provide the most reliable information. The guidelines will provide information relating to maintaining the system during outages and describe improved early monitoring and detection procedures.

5-60


The bushing box (attached to the lower portion of the generator) should be opened and the highvoltage bushing and stand-off insulators inspected. Both porcelain insulators should be inspected for damage, cracks, movement, and greasing. All hardware should be inspected for tightness and appropriate sealing. Leaking of asphalt material on the airside of the bushing box is an indication of high-voltage bushing overheating. Abrasion or FOD is the typical damage mechanism to the ID of babbitted steel hydrogen seals. Rings severely scored (> 0.005" [0.127 mm] deep) over 75% of the surface area should be replaced. Rings should also be replaced where the design clearance is worn beyond 1.5 times for 3600-rpm machines or two times for 1800-rpm machines. Air tightness test results or hydrogen consumption beyond design or expected values may also indicate excessive clearance. Electrolysis damage may also occur to hydrogen rings. The hydrogen seal casing is fastened to the outer end shield, and typically, the collector end hydrogen seal assembly is insulated from the outer end shield. The insulated hydrogen seal casing is assembled with insulating sleeves around the bolts and insulating washers under the bolt heads; no conduction paths should exist though the assembly. Insulation resistance should be checked with a megger and should be greater than 100,000 ohms. If megger readings are low, the assembly should be disassembled one bolt at a time to determine the possible shorted location. Oil deflectors should be checked for clearance to the shaft. The inner oil deflector should especially be checked if there is oil leakage into the generator. The inner oil deflector may also leak oil into the generator from a previous poor assembly or lack of seal to the bolting face or at the horizontal joint. Generator bearings may experience the same problems and would require the same repair techniques as turbine bearings; both issues are addressed and outlined in Section 5.10. An insulation requirement may be the one difference from the turbine bearings. One bearing, usually the collector end bearing, will be insulated. This bearing should be checked with a 500 volt megger, and a minimum of 100,000 ohms resistance is required Units with a hydrogen cooler should be inspected for signs of vibration damage or breakage to the structural supports strengthening the cooler. Repairs are made by: •

Protecting the tube bundles and fins

•

Taking precautions to reinforce the cooler structure by attaching the cooler to wide flange structural beams or “strong backs” to prevent distortion, sagging, etc. during the repairs

•

Weld repairing or strengthening and then weld repairing the damaged area

•

Recoating the structure

An inspection of the cooler support structure within the generator should be done if repeated cooler damage is observed. The cooler is designed to be equally supported along its entire length. If there are large changes in elevation between the support rails and the cooler openings or if the support structure is not level, the cooler may significantly deflect or vibrate in service causing cracking in the cooler bundle structure. 5-61


The EPRI report Generator Cooling System Operating Guidelines: Cooling System Maintenance and Performance Guidelines During Start-Up, Operation, and Shutdown, 1004004, [43] provides operating guidelines that apply to systems with either high or low dissolved oxygen (DO) concentrations. This report provides a cooling system maintenance and performance guide for application during startup, operation, and shutdown. An easy way to assess this condition is by stretching a wire between the cooler openings and evaluating the position of the support rails in relation to the cooler openings. The cooler support structure should have less than 1/8" (3.2 mm) deflection between the structure and the wire at any point. Modify the rails’ position or support structure as necessary. Another indication of cooler support structure issues may be reflected in the difficulty of cooler removal or insertion. The cooler may “hang-up” during these activities. The tube and fins of the cooler should be inspected for any signs of leaks. The cooler heads are inspected for corrosion. The cooler heads may require sandblast cleaning and then adding a corrosion-protection coating. The generator produces an electrical potential induced into the generator field during normal operation. Shaft grounding brushes are usually installed near the coupling between the turbine and generator to provide a ground path for the potential difference. Recent preliminary studies have shown that it is not only the generator contributing to the potential difference of the HP turbine to the generator rotor train, but the LP rotors also build up a potential as water droplets are stripped from the last stage buckets. The LP rotors may also retain a magnetic field as they age, induced by any repair welding on the rotor, induction heating, or by the MT inspection performed on the rotor. Residual magnetic fields should be inspected and, if significant, degaussed as an outage activity. Further studies of the turbine are being performed and should shed some light on the total impact and significance of LP rotor contribution to the total rotor train potential. If the potential difference were not grounded, it would seek a ground path though either the oil film of a bearing (or bearings) or the hydrogen seal. Electrolysis of either location would result. It is good maintenance practice to monitor the grounding brushes during normal operation to ensure that they are clean and in contact with the rotor. During an outage, they should be inspected, reassembled, and tested as soon as the unit is returned to service. 5.17.3 Generator Field The field collector rings should be checked for vibration prior to the outage to provide a preview of the collector ring condition. A dowel rod is used between the transducer and the brushes to obtain the collector ring vibration. Choose a brush location in approximately the same angular position as the other vibration pickups on the turbine-generator (yields approximately the same reference location and orientation for vibration equipment). A good operating collector ring and brushes will have a vibration level in the range of 2–3 mils (0.05–0.76 mm); up to 6 mils (0.15 mm) is satisfactory. Readings of 10–20 mils (0.25–0.50 mm) may be experienced when there are problems. Vibrations normally increase as the collector ring wears. The wear is usually seen as peaks and valleys caused by the different brushes. 5-62


Vibration may be caused by a condition known as “photographing” where the brush bounces and loses contact with the collector ring, resulting in an “image” of the brush on the surface of the collector ring. High vibrations may mean mechanical problems with the rings such as potentially loose parts or misalignments, but often this vibration is caused by the condition of the rings. It may be possible to balance the collector rings, but because the cause of the vibration is the condition of the rings, it is necessary to correct this vibration by machining or grinding the collector rings. Rings can be machined as long as there is sufficient spiral groove depth remaining (plan on replacing rings when this groove in a minimum 1/16” [1.6 mm] depth) after machining the rings to an 8 microinch (0.203 micrometer) finish. Collector rings may either be ground “in the machine” while on turning gear, in a rotor turning device during an outage, or “in the machine” at speed. Each process has its advantages and disadvantages; some of those are listed in Table 5-15. Table 5-15 Alternative Processes for Grinding Collector Rings Operation

Advantage

Disadvantage

Turning gear

Usually non-critical path. Done between getting on turning gear and unit startup at the end of the outage.

May be centrifugal effects on rings.

Rotor turning device

Non-critical path.

May be centrifugal effects on rings. Equipment availability.

At speed

Remove centrifugal effects on rings.

Critical path activity.

A review of brush wear rate may also provide information regarding the condition of the collector rings. Typical brush life is 3–6 months, and the brushes should wear at a rate of approximately 350 mils (8.9 mm) per 1,000 hours of operation. The corresponding wear rates of the collector rings should be 1 mil (0.3 mm) per 1,000 hours of operation. Excessive wear rates indicate poor performance of the brush-ring assembly. A collector ring wear rate of 5 mils (0.13 mm) per 1,000 hours of operation would indicate poor performance. Wear comes from both mechanical abrasion and electrical arcing. Minute electrical arcing begins to occur after the ring is worn a few mils and the brush contact begins to change. The brushes may tend to chatter and chip as brush temperature rises from the loss of contact if the condition worsens. The rings can be visually inspected after the field has been removed. The rings should be inspected for grooving, cutting, uneven wear, and surface coloration. Only minor surface damage from handling may be dressed and blended with a stone. A darkish-brown coloration on the collector rings is an indication of good brush-ring contact and operation. The coloration is from a film of hydroscopic brush material residue that has collected and is adhering to the collector ring surface. The composite film then acts as a lubricant between the brush and the ring, reducing wear. The collector rings sit outboard of the collector end outer end shield, and the field windings are inboard of the collector end inner end shield. There is a connection between the collector rings 5-63


and the field windings that is made through a conductor that passes through the field bore and then emerges between the fan ring and the field windings under the retaining ring. The bore conductor is connected to the main lead through a field terminal stud shown in Figure 5-7. There is a seal around the terminal stud on hydrogen-cooled units to prevent the hydrogen gas from leaking into the bore and exiting around the collector rings.

Figure 5-7 Terminal Stud Hydrogen Seal Construction

The seal is inspected for tightness as part of the outage inspection. If possible, check the hydrogen seal while the unit is still on turning gear and pressurized with hydrogen using a hydrogen “sniffer.” Certain main lead designs (solid lead, hollow and ventilated) experience a combination of highcycle and low-cycle fatigue in the 90-degree bend where the lead turns away from the field body and radially toward the windings. See Figure 5-8. The problem is a result of centrifugal loading caused by the main lead; the loading is transferred to the lead wedge and the #1 coil. Therefore, damage may also be seen in the lead wedge and the #1 coil end strap.

5-64


Figure 5-8 Location Susceptible to High-Cycle Fatigue and Low-Cycle Fatigue in Certain Main Lead Designs

These components are visually inspected with a borescope and red dye PT. The end turns can also be inspected with the retaining rings in place for distortion, loose or moved blocking, discoloration, or debris using articulating mirrors and borescopes. The retaining rings must be removed if damage is found. The retaining rings have been identified as the highest stressed component of either the turbine or the generator. Therefore, special care must be taken to prevent adding any stress risers from nicks or dings to the retaining rings. The outside diameter of the retaining ring may be PT or MT inspected with the retaining ring in place. But the ring must be removed to inspect the internal diameter with either PT or MT. UT techniques are being developed to inspect the condition of the inside diameter with the retaining ring in place. Current retaining ring removal practice uses high-frequency induction heating, but older methods include both flame heating and resistance blankets. Flame heating required additional protection to prevent flame impingement on the nonmagnetic retaining ring surface. The field slot wedges can be visually inspected with the retaining rings in place. The wedges are inspected for mechanical damage of nicks, gouges, etc., and electrical damage of overheating. Excessive circulating surface currents cause the overheating. The wedges may require removal if the overheating damage is severe. Good contact between the wedges and body is required to prevent overheating. Arcing and overheating reduce the conduction between the wedge and the body. The retaining rings must then be removed to remove the field slot wedges. The wedges are then removed, glass-bead cleaned, inspected, and reinstalled. Hydrogen-cooled generators use body-mounted fans on each end of the field to circulate hydrogen through the generator. The fans may either be single stage or multiple stages. Typically, single-stage fans are used with liquid-cooled stators, and multiple-stage fans are required for gas-cooled stators. The field-mounted fan segments should be inspected for tilting, gaps between the blade hubs and blades for single-stage fans, proper fan ring clearances, rubbing, and other problems while being 5-65


removed from the rotor. The segments should be numbered in the order of their removal and referenced to a specific rotor location. The removed fan segments should be inspected using an appropriate NDE method. Older units may have steel segments, but newer units are made from aluminum. The anticipated indications would be cracking or other mechanical damage. The rotor surface at the hydrogen seal areas, oil deflectors, and rotor journals should be inspected for damage, including grooving, scoring, and damage from previous assembly or disassembly. Minor damage may be “strap lapped,” but severe damage will require machining of the surface. Strap lapping cleans and polishes the rotor surfaces. The grit of a coarse grit emery paper is “broken down” first before using on the rotor. Straps 3/8–1/2" (9.5–12.7 mm) wide are wrapped one-and-one-half turns around the shaft and pulled back and forth. Strap lapping also enhances the oil-carrying capability of the rotor surface. 5.17.4 Generator Electrical Testing Electrical testing is performed to both generator components as a normal part of generator maintenance. Electrical testing can provide damage expectations and condition assessment when it is used as a diagnostic tool. During reassembly, electrical testing provides assurance that the assembled components will function as intended after the outage. Table 5-16 summarizes some of the tests that can be performed. Sections 5.17.4.1, 5.17.4.2, and 5.17.4.3 provide additional details on most of these electrical tests.

Assembly

Test

Diagnostic

Table 5-16 Generator Electrical Tests

Area

Condition Tested For

ac impedance

X

Field turn insulation

Turn shorts

Capacitance mapping

X

Stator water-cooled windings

Wet ground wall bar insulation

Copper resistance

X

Field and stator

Poor connections and opens

dc leakage current

X

Stator winding

Deterioration or contamination

Doble

X

Stator winding

Insulation integrity

EL CID

X

Stator core insulation

Weak or damaged core

Helium gas

X

X


Leak detection

Hi POT

X

X

Stator winding

Insulation integrity

HIT

X


Water leaks

Megger

X

Stator, field, bearing, H2 seal

Insulation: condition, assembly

Partial discharge

X

Stator windings

Localized deterioration

Stator assembly

Leak detection

Stator wedges

Loose wedges, losing tightness

Sniffer Wedge tightness

5-66

X

X X

X


An alternative to taking the generator field rotor from the stator to perform inspections is to use a limited access inspection (LAI). Limited access inspection (LAI) provides generator component assessments using robotic technology without removing the rotor. This type of testing is comparable and very often superior to conventional inspections with the rotor removed. The EPRI report Experience with Limited Access Generator Inspections: A Study of Inspections Done with Robotic Equipment and their Effectiveness as Compared with Conventional Inspections Where the Generator Rotor Is Removed, 1000100, [44] is a compilation of 68 LAIs from 1995– 1999 of two major OEMs (Siemens and General Electric) and original video tape of the inspections. The report lists the applications and capabilities of LAIs, demonstrates how LAIs compare to conventional assessments, and shows a cost comparison of LAIs versus conventional “rotor out” inspections. LAI has been accepted by the Nuclear Electric Insurance Limited (NEIL) as an equivalent rotor-out generator inspection. Applications and Capabilities of LAIs

The LAI is used to replace the routine and periodic rotor-out inspections where the rotor is physically removed from the stator by major disassembly of the end shields, bearings, oil deflectors, baffles, seals, etc. Conventional methods can possibly cause major damage to a rotor, and the inspection is time consuming and very costly. Although some disassembly is still required by LAIs, it is quite minimal compared to conventional methods and will vary depending on the LAI vendor, the size of the unit, the type of unit (nuclear or fossil), the manufacturer of the unit, and so on. LAIs have many of the same capabilities as conventional inspections. LAIs can still visually inspect a generator for “tell-tales” and “defects,” perform a stator slot and bar assessment, complete a stator end-winding inspection, and execute a rotor field visual inspection. The video records can now be recorded and archived for future reference. Very often, many specialists like to use a “touch and feel” method with some areas of the generator to better inspect components. Although LAIs do offer a similar capability, some say that it is not exactly comparable. Table 517 shows a comparison of LAI capabilities compared to conventional inspections. Note that the LAI has all of the same capabilities as the conventional rotor-out method.

5-67

Turbine-Generator Condition Assessment Table 5-17 Capabilities of LAI vs. Conventional Inspections Generator Component

5-68

LAI

Conventional Inspection

Wedges/Slots

-

-

Dusting/greasing

X

X

Tightness

X

X

Bar movement

X

X

Discharge (corona. . .)

X

X

Contamination

X

X

Wear/damage

X

X

Core

-

-

Dusting/greasing

X

X

Overheating/shorts

X

X

Wear/damage

X

X

Blocked Vent Ducts

X

X

Field

-

-

Surface Heating

X

X

Wedge movement

X

X

Vent holes

X

X

Contamination

X

X

Hardware

X

X

Retaining rings

X

X

Blocking/filler movement

X

X

End turn problems

X

X


Advantages and Disadvantages of LAIs

There is no doubt that LAIs will save maintenance costs when compared to rotor-out inspections. The amount of savings depends upon the individual plant’s situation and economics such as: •

Amount of disassembly required

•

Confined space restrictions

•

Amount of station support required

•

Length of inspection

•

Reassembly material required

•

Crane requirements

•

Rotor storage/protection

•

Rotor alignment

•

Risk of damage to rotor, stator, and other components

•

Risk of oil leak introduction

•

Foreign object material damage potential avoidance

LAIs have some small risks associated with it; however, they are smaller than the potential risk associated with pulling the rotor. (Table 5-18 presents a list of advantages and disadvantages of LAIs.) Issues such as a stuck robot inside the unit have not really presented themselves. Loose hardware falling off the robot and getting lost in the stator has been controlled by the use of standard industry locking devices (that is, safety wire, thread locking compound, plastic hardware, self-locking nuts, etc.). There have been some cases where the robot was unable to access the generator due to the baffling or other unusual dimensional access issues; however, these are usually the exception.

5-69

Turbine-Generator Condition Assessment Table 5-18 Summary of Advantages and Disadvantages of LAIs Advantages

Disadvantages

Better technology – cameras, wedge tappers, El Cid

Limited touch and feel capability in slots and on rotor body

Convenience

Exaggerated condition possible based on poor evaluation

Reduced cost

Evaluation more dependent on evaluator’s experience

Reduced outage duration

Possibility of compromised and damaged shaft insulation

Deferred rotor removal

Other inspections possibly overlooked (bearings and seals)

Potential damage from rotor removal eliminated

Interpretation and evaluation – too often simplistic – not enough relevant comments on condition

Permanent video record Frequently higher quality reports Outage interval extension facilitated Excellent application for mis-operation internal inspection More accurate tell-tale positioning data Better trending capability/records Decreased potential for foreign object damage Consistent with turbine LAI strategies Over 10 years of experience with LAI

LAIs should be strongly considered as a universal substitute for rotor-out inspections. LAIs, in addition to maintenance and operations history and standard tests, provide some of the essential ingredients for an overall comprehensive maintenance program. There may be extenuating cases where further investigation may require pulling the rotor after an LAI is performed based on the need for further inspection and testing of unique situations; however, this should be the exception.

5-70


5.17.4.1

Generator Stator Core Electrical Tests

5.17.4.1.1

EL-CID Testing

The EL-CID technique was originally devised as portable test equipment for inspection and repair of rotating electric machine stator cores. It was devised as a low excitation power alternative to the high power level stator core flux test, for looking for stator core inter-laminar insulation problems. Its application has been shown to be applicable to turbine generators, hydraulic generators, small generators and large motors. The subject of this book however, is confined to the class of large 2 and 4 pole, round-rotor machines, commonly referred to as Turbine-Driven Generators. The information contained in this section is a brief discussion of the EL-CID test technique and basic interpretation of results. Traditionally, stator core inter-laminar insulation testing has been done using the “Ring” or “Loop” flux test method, in which rated or near-rated flux is induced in the stator core yoke. This in turn induces circulating currents from the faulted area usually to the back of the core, at the core-to-keybar interface (see Figure 5-9). These circulating currents cause excessive heating in areas where the stator iron is damaged. The heat produced is generally detected and quantified using established infrared techniques. This method has been proven to be successful over the years, but requires a large power source and considerable time, manpower and resources to complete. Starting at the early 1980s, the EL-CID test has been developed as an alternative to the ring flux test. The technique is based on the detection of core faults by measuring the magnetic flux resulting from the current flowing in the fault area, at only three to four percent of rated flux in the core. Furthermore, the test usually requires only two or even one man to complete (using the latest version) in less than one eight-hour shift.

5-71


Figure 5-9 Flux Fault Current Path (Courtesy of IEEE © 2004)

5.17.4.1.1.1

EL-CID Test Procedure

The level of excitation to produce the desired flux in the stator core-back area is generally determined by a combination of the stator design parameters, and the power supply available to achieve the required flux level. For most generators, the standard 120 V AC (North America, etc.) or the 230 V AC (Europe, etc.) outlet, with a current capacity of 15 to 20 amperes is usually adequate. The characteristics of most stators are such that 4 to 7 turns of a #10 AWG insulated wire (2.5 mm2) can be used to carry the excitation current for the test. The winding is then energized to the required volts per turns, to produce approximately 3 to 4 percent of rated flux, usually corresponding to around 5 volts per meter across the stator iron. A Powerstat or Variac is best used for voltage and supply current control. The signal-processing unit of the EL-CID test equipment measures detected fault current (in QUAD mode) in mA. By theory and experimentation, a measurement of at least +/- 100 mA is required at 4% excitation of the core before it is considered that the core has significant damage affecting the inter-laminar insulation.

5-72


The excitation winding and power supply are set-up during the test as shown in Figure 5-10.

Figure 5-10 EL-CID Excitation Setup (Courtesy of IEEE © 2004)

5-73


The EL-CID equipment is set up as shown in Figure 5-11 (original analogue set), and Figure 5-12 (newer digital set).

Figure 5-11 EL-CID Analog Equipment (Courtesy of IEEE © 2004)

5-74


Figure 5-12 EL-CID Digital Equipment (Courtesy of IEEE © 2004)

In the older analogue sets, a separate coil is placed in the bore over undamaged iron as shown in Figure 5-11, to supply the reference signal. In the newer digital version, a CT (shown in Figure 5-12) is placed around the excitation winding to reference the supply signal. The CT was also an option on later analogue sets. The digital equipment uses a laptop computer to store the axial traces, whereas a plotter was used in the original version. The sensor head (chattock potentiometer) is pulled axially along the core at a speed slower than one meter every twenty seconds and always bridging two stator teeth as shown in Figure 5-13. (The slower speed is important, as the standard chattock coil has a magnetic sense area of only 4mm diameter, and both the Digital and Analogue systems have a definite time needed to record the Phase/Quad signals to sufficient resolution. The Digital set records the Phase and Quad values every 2mm. Any faster testing results in some missed test points in the Digital system or potential inaccuracy due to settling time on the Analogue system).

5-75


Figure 5-13 EL-CID Chattock Theory (Courtesy of IEEE © 2004)

The fault current signal is read directly off the signal processor meter, and input to a computer or chart recorder to trace out the readings as a function of the axial position along the stator core. When the sensor head is over undamaged iron, the meter should read zero if it is calibrated previous to the test for a condition where no fault current is circulating. In actual practice, no insulation system is perfect and some background signal is usually detected. In addition, the contact resistance of the core to keybar interface is not zero and can be found to vary between near 0 to 2 ohms. This also affects the EL-CID signal that is measured. Usually anywhere from a 0 to +/- 20 mA EL-CID signal (in Quad mode) is found to be normal when good core is measured. The above is somewhat similar to the rated flux test where the undamaged iron slowly heats up producing a background level due to eddy current losses in each lamination. During flux testing, this is recorded as the ambient core temperature rise. Where there is damaged or deteriorated core insulation, the core overheats and is detected as a hot spot above core ambient due to high fault currents circulating locally. In the EL-CID test, when the sensor head is placed over damaged core areas, the primary indication of a fault is obtained by detecting the flux produced by a current flowing in phase quadrature with respect to the excitation magnetizing current (the PHASE current). This flux is then converted back to an indicated current (the QUAD current), assumed to be flowing in the fault (see Figure 5-14). For this reason the QUAD current detected by the EL-CID processor is frequently referred to as the fault current (although for large faults the PHASE current may be affected as well, especially where the fault current path is highly inductive). The QUAD current is indicated on the signal processor meter and the traces recorded on the plotter (original analogue EL-CID equipment) or computer (newer digital EL-CID equipment). 5-76


Figure 5-14 EL-CID MMF Theory (Courtesy of IEEE © 2004)

5.17.4.1.1.2

EL-CID Experience

EL-CID has proven to be extremely reliable in detecting and locating core problems. It can cut the time and manpower requirements for core testing to within one eight-hour shift, where a flux test may have taken a few days to set up, and then a day to test, and another day to dismantle the test equipment. In the large majority of the EL-CID tests on turbo-generator machines, the experience has been that EL-CID is very reliable in determining that actual core faults or inter-laminar insulation deterioration exists. In other words, if a core defect exists, then EL-CID is likely to find it. And if the core is indicated to be defect-free by an EL-CID test, there is a very high probability that it actually is free of defects. Large signals may be found at tooth-top locations on the core, and only indicate a significant surface fault. Local surface faults are generally indicated by faults that show very localized signals, either high or low in magnitude and positive in polarity, if within the test coil span (assuming the standard EL-CID test set-up). Deeper faults can generally be seen over a larger scanning area, and also often become opposite in polarity as the sensor head gets away from the fault area. This is because the fault is outside the flux path of the chattock coil sensing the fault current, and the magnetic potential difference is reversed. Figure 5-15 shows a general basic interpretation of the EL-CID signals that can be expected to be seen based on fault location. The magnitudes in Figure 5-15 are only relative to one another, to give an idea of what might be expected for faults of roughly the same severity, at different locations. The peaks, and widths of the peaks, will vary from fault to fault as their size varies, and as they are more or less severe.

5-77


Attempts have been made to correlate EL-CID signal readings to temperatures that would be created in the defect area, during a flux test. The basic premise of the EL-CID test significance level of +/-100 mA is, that this level represents a 5 to 10ºC temperature rise that would be seen on flux tests, and therefore, just at the level of temperature rise where most OEMs and experienced stator core experts would carry out repairs to the core iron. There are a number of issues that makes questionable the assumption that correlates EL-CID’s signal to temperature. Firstly, many core testers carry out flux tests at widely differing flux levels. Some prefer to test at 100% of rated flux level while others test at about the 80% level. Different operators also apply the flux test over widely varying time periods. Yet, by all indications, all seem to work on the same temperature rise criteria. Obviously, a 10ºC rise at 100% of rated flux is much less significant than at 80% of rated flux. This is so because the 80% level is generally at the knee of the B-H curve and the curve is exponential. Increasing to 100% when the temperature rise is already 10ºC will increase the temperature in the fault. There is also the influence and undetermined significance of core-to-keybar contact resistance at the back of the core. The concern here is that the resistance can be generally measured to vary from near 0 to 2 ohms and may affect the EL-CID signal as well as the temperature measured during a flux test. For the low flux levels of the EL-CID test, it may be quite significant. This is one of the unknowns for which there is little data to support this statement, one way or another. But it should be noted that on ungrounded cores (i.e. cores with insulated keybars and infinite core to keybar contact resistance), the EL-CID and the flux test are both ineffective unless there are two faults in proximity, to allow circulating current to flow and hence be detected by either test. This has been well proven by actual tests done on such cores, where single faults do not show up until the core is artificially grounded at the back near the keybar that is behind the location of the fault.

5-78


Figure 5-15 EL-CID Signal Interpretation (Courtesy of IEEE © 2004)

Generally, there is only one keybar that is grounded on such core arrangements (for purposes of the stator ground fault relay), and the testing is effective in that lamination region only, for single faults. To test such a core arrangement by either EL-CID or flux test, the core must be purposely grounded at the back, between every keybar, circumferentially, and on every lamination axially. One can easily see the difficulty in this, as it is not even possible on most stator designs, because of the frame construction and arrangement. One has to consider this when purchasing a new stator. If a single core fault occurs, then the insulated core may allow operation where the grounded core would fail based on the progression of the fault. However, if two faults occur in the same proximity, then a much more severe fault may occur and go undetected until the effect of the failure causes additional collateral damage, which takes the machine out of service. This is generally a matter of user preference and both philosophies are sound, each in their own way. In addition, there is also the problem that core faults can manifest themselves in many forms and levels of severity. It is not uncommon for a surface iron smudge to show a very high EL-CID signal and yet not produce much heat when looked at under infrared in a flux test. And the opposite is also true. It is not uncommon for an EL-CID signal that is not much higher than the 5-79


manufacturer’s recommended significance level, to produce significant heat. In particular, with very small faults on the surface where EL-CID does not produce a significant signal, there are sometimes high spot temperatures detected by infrared, but there is insufficient power to cause damage. One advantage is that EL-CID can detect deep-seated faults, which may often not show as a particularly large temp rise on the surface, but can be quite damaging to the body of the core or adjacent conductor bar insulation. This is due to the fact that the attenuation of EL-CID signals is generally less than the attenuation of temperature rises with depth of fault. The difficulty in co-relating EL-CID and Flux test temperatures therefore comes from many issues as stated above and a number of other possible influences as listed below: •

Core-plate grade (i.e. grain oriented vs. non-oriented steels)

•

Lamination insulation grades

•

Axial length of the fault

•

Total size of the fault

•

Electrical resistance of the inter-laminar fault (i.e. deteriorated or fretted insulation type damage as opposed to hard contact, low resistance type faults)

•

Geometry differences in core structure from one machine to another

•

Limitations of the earlier EL-CID test equipment, in relation to the size of the chattock coil itself and the relative size of any fault being measured. (Current standard Chattock coils have only a 4mm diameter magnetic sense area, thus are able to detect very small faults, particularly if the suspected fault area is investigated/scanned slowly enough).

All these issues can have a significant effect on both the EL-CID signal seen, and the temperature produced during a flux test. Some are better known and quantified than others. Trying to correlate temperatures to EL-CID signals under so many variables is difficult, unless all of these parameters can be taken into account. In other words, the core under test must be well known to be able to make such a correlation. There is one other factor regarding EL-CID signal interpretation, and it has to do with readings taken in the Phase mode, as opposed to the normal Quad mode reading that Figure 11-8 is based on. Basically when a stator has (for example) 4 turns of an excitation winding and is carrying 12 amps, then it has an excitation level of 48 Ampere-Turns. When the EL-CID signal processor is set to Phase mode and a reading is taken from tooth centre to tooth centre across one slot, a signal of (48 A-T divided by 48 slots) 1 amp should be read. Generally, for most fault areas this is the reading that will be seen. However, in some cases, much higher current is read in the Phase mode than the simple magnetic potential based on excitation and slot geometry. One of the things that has been seen when this type of situation occurs, is that very high Quad readings are generally also present and the fault is usually at the bottom of the slot, or in the core yoke area. Correspondingly, there is not always much heat given off during flux testing, and the two tests do not always correlate when this occurs. There is very little experimental data on this point, and again it shows that some uncertainties remain in interpretation of EL-CID test results. It is 5-80


believed that Phase readings are also significant and should be factored into the test interpretation. Just what that interpretation should be is unclear to date, due to the difference in faults from case to case. Probably the main difficulty for the test interpreter is, when nothing is known about the core under test nor the type of fault found. Most often, the core defect is not visible, and what the tester is trying to determine is how deep it is and how severe it is. The general consensus of the people surveyed on this issue, is that more often than not, they cannot tell how severe a detected fault is, and thus require a flux test with infrared scan to help in that determination. The Ring Flux test remains the best test to determine the actual temperature rise of any fault, and if repairs are required. If the suspected fault is believed to be deep-seated from the EL-CID test result, the Ring Flux thresholds should be appropriately adjusted. Once the core is repaired, an EL-CID test can usually show that the repair is successful by the absence of a defect signal. This is perhaps the best value in EL-CID testing. There seems to be general consensus that if an EL-CID test is performed and no damage is found, then the core is defect free. EL-CID has gained good credibility in its ability to determine and locate the presence of faults, and to verify repairs when faults are found. The general consensus also appears to be that more work is required on EL-CID signal co-relation with temperature rise in fault locations. The general feeling to date is that both the EL-CID and Flux Testing together are still required to give the best information on any core defect found. 5.17.4.1.2

Rated Flux Test with Infra-Red Scan

The Rated Flux test is a high-energy test, used to check the integrity of the insulation between the laminations in the stator core. It is also commonly referred to as the “Ring Flux” test, in which near-rated flux (normally about 80%) is induced in the stator core yoke. This in turn induces circulating currents and excessive heating in areas where the stator iron is damaged (see Figure 5-9). The heat produced is detected and quantified using established infrared techniques. Flux is produced in the iron by looping a cable around the core in toroidal fashion (see Figure 516), and circulating a current at operating frequency. The flux required for the flux test is half the normal operating flux due to the difference in the way the flux is induced in operation (see Figure 5-17) from that of the flux test. The power supply for the cable is usually taken from two phases of one of the high voltage breakers (i.e. 4 kV) in the plant, or a portable motor generator set. The correct number of turns are looped around the core to produce the required level of flux. IEEE Std. 432 [11] provides the following expression to find the rated volts per turn required on the stator core: Voltage per turn of test coil = (1.05 * VLL)/(2 √3 x Kw * N)

Where: VLL Kw N

= = =

line-line voltage winding factor Number of turns/phase in series in the stator winding 5-81


Figure 5-16 Toroid Wrap (Courtesy of IEEE © 2004)

Figure 5-17 Operating Flux Pattern (Courtesy of IEEE © 2004)

5-82


From the above, the available power supply voltage is divided by the calculated volts per turn above, to give the correct number of turns to loop through the core. If the number of turns includes a fraction, then the next highest number is used, to reduce the flux level to below 100% or below rated. Using too high of a flux level can create core damage since there is no cooling on the core during the test. Once the number of turns is known, the current capacity is required to size the cable and ensure the power source can handle the current that will be drawn. Knowledge of the specific B-H characteristic of the subject core being tested is required for this. In cannot be stressed too highly that exact B-H characteristic of the stator core should be known in relation to the flux volts per turn, and the current that will be required from the power source (see Figure 5-18). In many cases it is unknown, and therefore the number of ampere-turns required must be estimated based on industry curves for the most likely grade of core-plate that would be used in the machine under test. A higher end and lower end core-plate grade are usually selected to provide a range of possible operating characteristics for the subject core. These are selected to provide a range of possible excitation requirements, based on B-H curves taken from small and large turbogenerator applications. From the winding configuration for the subject generator, the power supply available, and the BH curves, an estimate can be made for the number of turns required to achieve the required level of flux for the test. This is generally in the 70 to 90 percent range of rated flux. The current that would be flowing in the flux cable will depend on the actual B-H characteristic of the stator iron and therefore, this must be carefully estimated for safety of both personnel and the equipment. When the B-H curve is in doubt, adding a higher number turns will reduce the level of flux. Then it follows to successively remove turns and keep recording the current attained as the flux volts per turn increases. Successive voltage application in this manner can be made until a B-H curve is created and the proper number of turns found (see Figure 5-18).

5-83


Figure 5-18 B-H Curve Example (Courtesy of IEEE © 2004)

The flux test is set up as basically shown in Figure 5-19. The power supply is selected and connected as shown. The cable is wound through the stator bore the correct number of times, and connected back to the power supply. Protection for the test cable is set up to provide “ground fault” and “over-current”. The stator core, frame and the windings were all grounded for their protection and that of the test personnel. The CTs should also shorted at the terminals and grounded. Metering is set up to provide measurements of supply voltage and current. A single loop of cable is installed additionally, to measure the actual flux volts on the stator core during the test. This is done to provide an accurate measurement of the induce voltage across the core and the level of flux as well. In some cases, an infrared, non-reflecting mirror is used to monitor the temperature of the stator core when angled viewing from outside the stator bore is difficult (see Figure 5-20). The mirror provides a known surface to accurately measure the temperatures, so that the absolute and relative rise of temperatures in the core defect areas can be recorded.

5-84


Figure 5-19 Flux Test Electrical Setup (Courtesy of IEEE © 2004)

Figure 5-20 Flux Test Mirror Setup (Courtesy of IEEE © 2004)

5-85


Once the flux is established in the core, it is kept for at least thirty minutes to one hour. The temperature of the core should be maintained within values not significantly higher than those encountered during operation. Under these conditions, the temperature rises in the core are monitored and recorded while the existence of hot spots is investigated with infrared monitoring equipment (and possibly a non-reflecting mirror) (Figures 5-21 to 5-23).

Figure 5-21 Infrared Hot Spot – Bruce 7 (Courtesy of IEEE © 2004)

Figure 5-22 Infrared Hot-Spot Flux Test 1 (Courtesy of IEEE © 2004)

5-86


Figure 5-23 Infrared Hot-Spot Flux Test 2 (Courtesy of IEEE © 2004)

The temperature rises of the “good” core areas (ambient core temperature rise) are then compared to the temperature rise profile of any defective locations found. Once the defects are located and characterized, repair solutions can then be addressed. Figure 5-24 shows the relative experience in the industry with the typical types of core faults encountered, and how they appear during flux testing. It should be noted that these are general examples and may not be the case for a particular core tested. However, they show the general trend that the large majority of faults seem to follow.

5-87


Figure 5-24 Flux-Temperature Profiles (Courtesy of IEEE © 2004)

5.17.4.1.3

Core Loss Test

Stator core loss is a function of terminal voltage. The Open Circuit Saturation Curve for the core iron determines it. The core loss for any particular generator is always determined at the factory by the manufacturer, and is not a test that is generally done at site. The core loss is determined by the generator being coupled to, and driven by a calibrated motor. The friction and windage (mechanical) losses are calculated and separated out from the electrical losses, to provide a value of core loss for the stator [7]. If there is suspected wear of the inter-laminar insulation in the core, on a large scale, it may be possible that a core loss test could be done to compare the present value to the ‘as new’ value, to determine the extent of deterioration occurring. However, the serious challenge of driving the generator at site with a calibrated motor, for all practical purposes limits this test to the OEM’s factory. 5.17.4.1.4

Through-Bolt Insulation Resistance

There are a few manufacturers that provide through-bolts in their stators to pull the cores tight. These through-bolts are full-length bolts, inserted axially through the core, through holes in the core iron. There are many of them located symmetrically around the circumference of the core, a few inches below the stator winding slots. The ends are threaded and terminated at each end 5-88


through a pressure plate, where a nut is installed to maintain compression, after the core is pressed to a few hundred psi. The entire through-bolt assembly is insulated, generally by cured epoxy/glass tape wrap or a phenolic tube through the core, and an arrangement of insulators at the pressure plates and nuts. This is done to ensure that the through bolts do not create any short circuits across the stator core laminations and cause a core failure by circulating currents. To ensure that the insulation is in good condition, the insulation resistance of the through-bolts is checked by meggering at 500 V DC. A good reading should be in the hundreds of MΩ range. 5.17.4.1.5

Insulation Resistance of Flux Screens

Most large generators are provided with some form of flux screening for the stator core-end. This is to prevent overheating in the core-ends due to stray flux from the stator endwinding. When flux screens are used, they are insulated from the core end, to ensure that no additional circulating currents flow between the core and the flux screens, which would create additional un-wanted heating in the core-end. To ensure that the insulation is in good condition, the insulation resistance of the flux screens is checked by meggering at 500 V DC. A good reading should be in the hundreds of Mega-ohms range. 5.17.4.2

Generator Stator Winding Electrical Tests

Stator windings are comprised of materials with specific resistive and dielectric qualities. The materials used comprise: mica, Dacron tapes, glass tapes, asphalt binders, polyester resins and epoxy resin binders, and so on. There are also insulating, resistive and stress grading paints applied to various portions of the winding to ensure controlled distribution of the voltage on the individual stator conductor bars. All of the materials used, and their application, are done in such a manner as to ensure proper functioning and a reasonable degree of long term reliability of the winding. The stator winding insulation system is complex and requires a variety of tests to establish its present condition and expected long term reliability. Therefore, to fully test the stator winding, so that the best possible determination of the winding condition can be made, it is desirable to perform both AC and DC tests. DC tests are generally sensitive to the presence of cracks, moisture, particle contamination or a general degradation of the electrical creepage path. During DC application, the voltage is divided according to the DC leakage resistance. Basically, DC is used to test the conductivity of the insulation system. DC testing has the advantage that it less damaging to the insulation due to the absence of corona and partial discharges associated with AC. AC testing on the other hand applies the more realistic electrical stress to the winding, since it operates AC when in service. When the AC test voltage is applied, it is actually applied across several dielectric components of the winding insulation, which are effectively in series. 5-89


Therefore, the leakage current must go through each of the dielectrics until it reaches ground potential. Under AC, the voltage is therefore divided according to the relative permittivity of each of the dielectric materials. AC testing is in fact far more searching than DC. In addition to the conducting properties of the insulation, AC testing is also capable of determining the loss or power factor characteristics and the dielectric properties. In addition, the mechanical integrity of the insulation can be also be alluded to by the capacitance characteristics of the winding in terms of insulation de-lamination. Like with many other issues about testing insulation of large electric machines, experts and operators have different opinions about which one of the tow tests (DC and/or AC) is more convenient. Some only prefer DC tests, while other prefer AC testing. Still, others prefer using both. 5.17.4.2.1

Pre-Testing Requirements

If the stator winding is water cooled, it must be completely dried prior to all testing to obtain meaningful results. If there is stator cooling water left in the winding it will alter the test results and give a distorted picture of the insulation condition. All three phases must be isolated to ensure all testing is carried out on the stator winding only. This means that each phase should be completely separated at the neutral point and floated from ground. The line ends of the stator winding should be separated from the Isolated Phase Bus (or cables, in smaller units) just outside the generator, at the stator terminals. The generator current transformer windings should be shorted and grounded to avoid induced high voltage and possible discharge failure of the insulation. All instrumentation leads should be grounded to also avoid induced high voltage and possible discharge failure of the insulation. Before conducting any high-voltage testing of the unit, consult vendor and/or pertinent standards. 5.17.4.2.2

Series Winding Resistance

This test is used to measure the ohms resistance of the copper in each phase of the stator winding. Given the relatively low DC series resistance of windings of large machines, the measurement accuracy requires significance to a minimum of 4 decimal places. The purpose of the test is to detect shorted turns, bad connections, wrong connections and open circuits. Acceptable test results consist of the three resistance values (one per phase) to be balanced within a 0.5% error from the average. The test is very sensitive to differentials of temperature between sections of the winding. The machine should be at room temperature when the test is performed. 5-90


As with any other electrical test, the results should be compared with original factory data, if available. This test can be performed on stator and rotor windings. 5.17.4.2.3

Insulation Resistance (IR)

The purpose of this test is to measure the ohmic resistance between the conductors in each of the 3-phases and ground (i.e. the stator core). This test is generally regarded as an initial test to look for gross problems with the insulation system, and to ensure further high voltage electrical testing may “relatively” safely continue, in terms of danger of failing the insulation. Normally, the measurements of IR will be in the mega-ohm range for good insulation, after the winding is subjected to a DC test voltage usually done anywhere from 500 to 5000 V, for one minute. The minimum acceptable reading by IEEE Standard 43 [4] is (VLL in kV + 1) MΏ. The test is carried out with a “Megger” device. However, resistance bridges may also be employed. The DC test voltage level is usually specified based on: the operating voltage range of the machine, the particular component of the generator being tested, operator’s policy and previous experience, and knowledge of the present condition of the insulation in the machine. Although the readings obtained will be somewhat voltage-dependent, this dependency becomes insignificant for machines in which the insulation is dry and in good condition. This is why it is essential that the stator winding is completely dried before any testing, so that any poor readings will be due to a “real” problem, and not residual moisture from the stator cooling water. The readings are also sensitive to factors like humidity, surface contamination of the coils, and temperature. Readings should be corrected to a base temperature of 40oC by the following: R (40oC) = K * Rmeasured (oC) Where K is a temperature-dependent coefficient, which can be obtained from IEEE Std 43 (see Figure 5-25). The following equation can be used to obtain K to some degree of accuracy in lieu of the standard: K = 0.0635 * exp(0.06895 * Tmeasurement in oC) Insulation Resistance tests are performed on both stator and rotor windings, core-end flux screens, and core-compression or through-bolts as mentioned previously.

5-91


Figure 5-25 IR Versus Temperature (Courtesy of IEEE © 2004)

5-92


The insulation between the core-end flux screen and the stator core-end iron ensures that the flux screen maintains its capability to shield the core-end from axial flux, and keep the resulting circulating currents within the flux screen, without providing a current path to the core. The insulation between core-compression bolts and the iron keeps the through-bolts from shortcirculating the insulation between the core laminations. Otherwise, large eddy currents generated within the core would produce heat and temperatures, which could further damage the interlaminar insulation, as well as the insulation of the windings. Figure 5-26 shows typical IR behavior as a function of time.

Figure 5-26 Polarization Index Dryness Curve (Courtesy of IEEE © 2004)

5-93


5.17.4.2.4

Polarization Index (PI)

Insulation resistance is time-dependent as well as being a function of dryness. The amount of change in the IR measured during the first few minutes depends on the insulation condition, and the amount of contamination and moisture present. Therefore, when the insulation system is clean and dry, the IR value tends to increase as the charge is absorbed by the dielectric material in the insulation. When the insulation is dirty, wet or a gross insulation problem is present, the charge does not hold and the IR value will not increase, due to constant leakage current at the problem area. Therefore, the ratio between the resistance reading at 10 minutes and the reading at 1 minute produces a number or “Polarization Index” which is essentially used to determine how clean and dry the winding is (see Figure 5-27). Class B and F windings tend to show higher PI values than windings made of Class A insulation. It is also dependent on the existence of a semi-conducting layer. The recommended minimum PI values are as follows: Class A insulation: Class B insulation: Class F insulation:

1.5 2.0 2.0

The same Megger used for the IR readings should be used to determine the PI. The PI readings should be done on a per phase basis at the same voltage as the IR test, and can be used as a go/no-go test before subjecting the machine to subsequent high voltage tests, either AC or DC. The IR readings for the PI test should also be corrected to 40oC as in the IR test. Performing the high voltage tests on wet insulation may result in unnecessary failure of the insulation.

5-94


Figure 5-27 IR Versus Temperature – PI (Courtesy of IEEE © 2004)

5.17.4.2.5

Dielectric Absorption During DC Voltage Application

Dielectric absorption current characteristics can be used to measure the aging of the resin binder in the groundwall insulation. When applying DC voltage to insulation material, a time-dependent flow of current is established. This current has a constant component, called the conduction current or leakage current, and a transient component, called the absorption current.

5-95


Absorption current is a function of the polarization of the molecules in the binding material. The older the binding material, the more polarized it becomes, and the more absorption current flows. Therefore, this test is best used as a comparison test between the winding condition at different times, and between similar windings. Absorption current is also temperature dependent. This fact should be taken into consideration when performing the test and interpreting the results. Absorption current is also dependent on the amount of voids in the insulation. The dependence is inverse, i.e. an increase in the number of voids in the insulation, will tend to reduce the magnitude of absorption current. The contradictory effects regarding voids density and aging of the binding material, renders this test difficult to interpretation. It is best when used in conjunction with other dielectric tests, such as Partial Discharge and Dissipation Factor Tip-Up tests. 5.17.4.2.6

DC Leakage or Ramped Voltage

The DC leakage or ramped voltage test, is a controlled DC voltage application designed to test the winding in such a manner as to monitor the DC leakage current, at the same time the DC voltage is increased. The leakage current is plotted against the DC voltage applied to give early warning of any impending insulation breakdown. This helps in limiting damage by shutting down the test prior to a full breakdown occurring (see Figure 5-28). When applying DC voltage to the winding, a time-dependent flow of current is established. This current has a constant component, called the conduction or leakage current, and an initial component, called the charging or absorption current. Therefore, it is advisable to raise the voltage to the first level of the kV/min. rate, and hold for 10 minutes, to get beyond the charging phase of the voltage application, and test while dealing primarily with the leakage current. In this way, charging current influence on the leakage current rate of rise will be minimized. The final DC test voltage level is generally in the range of 125% to 150% of (VLL x 1.7) kV DC (ANSI Standard C50.10). The value actually chosen between 125% up to 150% of the test voltage is dependent on the age of the machine insulation, and knowledge of its general condition. The ramp rate is selected at 3% of the final test voltage level in kV DC/minute (IEEE Standard 95). The ramp rate usually is in the range of 1.5 to 2 KV per minute. Generally the ramping portion of the test is automated to allow a steady increase in the voltage. A DC Hi Pot set with the capability of a timed and steady voltage increase is required. If this is not possible with the equipment available, then a basic DC Hi Pot set can be used to raise the voltage in the pre-determined 3% voltage steps, holding each step for 1 minute.

5-96


Figure 5-28 DC Ramp (Courtesy of IEEE © 2004)

5.17.4.2.7

DC Hi-Pot

The DC Hi-Pot test is used to ascertain if the winding is capable of sustaining the required rated voltage levels (without a breakdown of the insulation), with a reasonable degree of assurance for capability to withstand over-voltages and transients, and maintain an acceptable insulation life. 5-97


The test consists of applying high voltage to the winding (the three phases together, or one at a time, with the other two grounded) for one minute. The recommended test voltage level is [(2 x VLL + 1000) x 1.7] kV DC for new windings (ANSI Standard C50.10). The recommended test voltage level for field-testing and maintenance purposes is 125% to 150% of (VLL x 1.7) kV DC (ANSI Standard C50.10). The value actually chosen for the test voltage is dependent on the age of the machine insulation, knowledge of its general condition, and the specific situation calling for a test. 5.17.4.2.8

AC Hi-Pot

The AC Hi-Pot test is also used to ascertain if the winding is capable of sustaining the required rated voltage levels (without a breakdown of the insulation), with a reasonable degree of assurance for capability to withstand over-voltages and transients, and maintain an acceptable insulation life. The test consists of applying high voltage to the winding (the three phases together, or one at a time, with the other two grounded) for one minute. The recommended test voltage level is (2 x VLL + 1000) kV AC for new windings (ANSI Standard C50.10). The recommended test voltage level for field-testing and maintenance purposes is 125% to 150% of VLL kV AC (ANSI Standard C50.10). The value actually chosen for the test voltage is dependent on the age of the machine insulation, knowledge of its general condition, and the specific reasons for the calling for a test. AC testing is generally done at power frequency of 60 Hz but may also be carried out at a low frequency of 0.1 Hz, which is the accepted industry standard. Generally the AC Hi-Pot is a “pass” or “fail” type of test. However, this is not always the case. There are often times when arcing can be heard and even seen (see Figure 5-29) and the test can be stopped until the problem area is repaired. Then retesting may be carried out to prove the repairs. Also, testing is usually done on water-cooled windings with the system drained and vacuum dried before voltage application. However, there are instances where good DC measurements have been recorded on two phases while one appears grounded, while the winding is technically “wet”. In such an instance, AC testing has been done as a next step, but this is a rare occasion. It is not recommended to proceed with this type of testing unless an expert is present to know how to handle this type of situation. One of the reasons to do a “wet” AC test would be when there appears to be no failure point that can be found and yet the winding will not hold DC voltage and 5-98


internal contamination of the stator winding hoses is suspected. Under dry conditions, the winding will pass high voltage testing and under wet conditions, the contamination will be conducting. Depending on the type of contamination and its conductivity, the hoses may glow under high voltage AC (see Figure 5-30).

Figure 5-29 Stator Hi-Pot Arcing (Courtesy of IEEE © 2004)

5-99


Figure 5-30 LKV G5 EE Hoseglow (Courtesy of IEEE © 2004)

5.17.4.2.9

Partial Discharge (PD) Off-line Testing

In principle, PD measurements are based on direct measurement of the pulses of high frequency current discharges created during the occurrence of partial discharges. Some off-line methods are based in a capacitive link between the whole of the winding and the measurement equipment. These set-ups allow the measurement of PD activity in whole windings, or one phase at a time. To measure the PD activity in smaller sections of the winding, methods based on an electromagnetic probe or pickup (which is mounted on a hand held electrically insulated stick) has been developed. One such probe is known as the TVA Probe and is used to traverse the entire length of a slot in the stator bore to search for localized sources of PD. Therefore, each slot is probed over its full length. The partial discharge tests are carried out from voltages below the inception voltage up to rated voltage. On-line partial discharge analysis can be performed by modern instrumentation and methods described in the following sections.

5-100


5.17.4.2.9.1

PD Monitoring by Capacitive Coupling

Partial discharge monitoring by capacitive coupling is generally an on-line test these days, but off-line measurements are also done on a regular basis. The test setup for off-line capacitive coupling is generally as shown in Figure 5-31.

Figure 5-31 PD Off-Line Capacitive Coupling (Courtesy of IEEE © 2004)

During operation of a generator, the voltage on the stator winding is graded according to the line to neutral connection. Thus, when an on-line test is performer, the bars near the neutral end of the machine are not subjected to high voltage, which represents the actual operating condition. In the off-line test, all stator bars are energized to the level of the test voltage applied and therefore, all may show PD activity. However, in the off-line test, the effects of vibration and bar forces are not in play. These issues are important to be taken into consideration when analyzing the test results and their implication on the condition of the unit. 5.17.4.2.9.2

PD Monitoring by Stator Slot Coupler

The Stator Slot Coupler (SSC) is basically a tuned antenna with two ports. The antenna is approximately 18 inches (46 cm) long and is embedded in an epoxy/glass laminate with no conducting surfaces exposed. SSCs are installed under the stator wedges at the line ends of the stator winding, such that the highest voltage bars are monitored for best PD detection. Since the SSC is also installed lengthwise in the slot at the core end, its two port characteristic gives it inherent directional capability. The problem of noise is virtually eliminated in the SSC. Although the SSC has a very wide frequency response characteristic that allows it to see almost any signal present in the slot where it is installed, it also has the characteristic of showing the true pulse shape of these signals. This gives it a distinct advantage over other methods, which cannot capture the actual nature of the PD pulses. Since PD pulses occur in the 1 to 5 nanoseconds range and are very distinguishable with the SSC, the level of PD activity can be more closely defined. 5-101


In addition, dedicated monitoring devices have been devised to measure the PD activity detected in the SSC. The capability for PD detection using the SSC and its associated monitoring interface is enhanced to include measurement in terms of the positive and negative characteristic of the pulses, the number of the pulses, the magnitude of the pulses, the phase relation of the pulses and the direction of the pulses (i.e. now from the slot or from the endwinding or actually under the SSC itself at the end of the slot). The other advantage of the SSC is that once it is installed, measurements may be taken at any time without the need for exposing live portions of the generator bus-work, for the purpose of making connections to the test equipment. 5.17.4.2.9.3

Corona Probing for PD

Partial discharge tests in general determine only the relative condition of the stator winding from the generator terminals. They do not locate specific sites of deterioration or damage in the winding. To do this, the winding must be locally scanned with special probes designed to detect localized sources of PD, while the winding is energized to the level of line-to-neutral voltage. There are a couple of variations of probe types, one based on radio frequency noise and the other on acoustical noise. (SSCs do provide some information about the location of the PD activity. The more SSCs installed in a particular winding, the higher the accuracy in determining the location of the offending bar). The “TVA Probe” gets its name from the Tennessee Valley Authority where it was first popularized. It is based on an earlier Westinghouse probe design, sensitive to RF signals produced by PD in the winding. It functions by picking up the RF energy radiated from active PD sites in the winding. The greater the PD, the greater the RF energy produced. The tip of the TVA probe employs a loop antenna similar to that used in an AM radio. The TVA antenna is tuned to about 5 MHz so that it is sensitive to near-field RF discharge. The output of the antenna is directed by a co-axial cable to a tuned RF amplifier and a peak-reading ammeter that is sensitive to peak PD pulses. The closer the antenna is brought to an RF (or PD) source, the higher the output on the meter. The “Ultrasonic Probe” functions based on acoustic noise produced by localized PD sites. The noise is similar to a crackling sound that one might hear when next to a high voltage overhead transmission line on a wet day. This noise is loudest in the ultrasonic frequency range around 40 kHz. A high directional microphone, sensitive to the 40 kHz noise, is used to locate the site of the PD discharges. Given that ultrasonic noise does not easily penetrate insulation, the ultrasonic probe test is primarily sensitive to surface PD, i.e. the sites of slot discharge and surface endwinding PD. 5.17.4.2.10

Capacitance Measurements

Capacitance measurements are also a method of measurement by which the quality of the insulation can be indicated. The measurements are, of course, done with AC voltage, and generally on a per phase basis. 5-102


Each phase of the stator winding is energized to line-to-neutral voltage, while the other two phases are grounded. The power factor of the winding is measured with a capacitance bridge to determine the value of the per-phase winding capacitance. Comparison of the measured capacitance to the factory measured values, and then successive capacitance readings, can aid in showing deterioration of the ground-wall insulation over time. 5.17.4.2.11

Dissipation/Power Factor Testing

The dissipation factor (or tan δ) is an AC test used to measure the bulk quality of the groundwall insulation, by measuring the dielectric loss (primarily due to partial discharges) per unit of volume of the insulation. Note:

(Dissipation Factor) DF = tan δ (Insulation Power Factor) IPF =

DF

. = sin δ

√ 1 + ( DF )2

Results are generally dependent on the type of the dielectric material in the insulation system. An increase in DF over the life of the winding can be attributed to an increase in internal voids, delaminations, and/or increased slot-coil contact resistance (i.e. deterioration of the semiconducting paint in the slot). The readings are a dimensionless quantity expressed in percent. The absolute values obtained are, again, a function of the type of insulation system being measured and are also directly affected by the temperature of the winding. Therefore, it is important that insulation power factor readings be taken at similar temperatures. The results are even more useful however, in relative terms by comparison of present readings to past readings. Successive measurements provide a scale of the deterioration rate of the insulation system over time. Therefore, when using dissipation factor as a function of time, it is important to maintain constant conditions during testing. DF readings are directly affected by the temperature of the winding and are also a function of the applied voltage. Therefore, comparisons with previous readings should be made on tests done at similar temperatures and the same voltage levels. Since dissipation factor readings are somewhat void dependent, the dissipation/insulation power factor ratio will increase with an increase in the amount of voids present in the insulation. This phenomenon is the base of the DF/IPF Tip-Up test. 5.17.4.2.12

Dissipation/Power Factor Tip-Up Test

The Dissipation Factor Tip-Up or ∆tanδ test looks at the void content in the insulation. That is to say, the dissipation factor will increase with an increase in the amount of voids or de-lamination present in the insulation. In addition, it also provides information on other ionizing losses in the form of partial and slot discharges.

5-103


The test is done by taking DF (or insulation power factor) measurements at different voltages. A set of readings is therefore obtained, which forms an ascending curve. A fast change of insulation power factor with increasing voltage tends to indicate a coil with many voids. The test is based on the fact that ionization, both internal and external to the insulation is voltage dependent. The test is done generally at 25 and 100 percent of the rated phase to neutral voltage. The Tip-Up value is the DF measurement at the higher voltage, minus the DF measurement at the lower voltage (IEEE Standard 286). Good readings for an epoxy/mica system, indicating minimal void content in the insulation, are typically less than 1%. Good readings for an asphalt system are generally in the 3% range (see Figure 5-32). This test will give a good evaluation of the winding as a group, however any bad coil that deviates greatly from the rest will not be discerned by this test. To ferret out individual bars, which may exhibit higher discharges, a Partial Discharge test can be done with the addition of manual probing for the location of the discharges if high levels are found to exist.

Figure 5-32 Dissipation Factor Tip-Up (Courtesy of IEEE © 2004)

5-104


5.17.4.3

Generator Rotor Electrical Testing

5.17.4.3.1

Winding Resistance

The field-winding series-resistance is measured to determine the ohms resistance of the total copper winding in the rotor. Given the relatively low DC series resistance of windings of large machines, the measurement accuracy requires significance to a minimum of 4 decimal places. The purpose of the test is to detect shorted turns, bad connections, wrong connections and open circuits. The machine should be at room temperature when the test is performed. As with most other electrical test, the results should be compared with original factory data, if available. 5.17.4.3.2

Insulation Resistance (IR)

The purpose of the IR test is to measure the ohmic resistance between the total rotor winding insulation and ground (i.e. the rotor forging). This test is generally regarded as an initial test to look for gross problems with the insulation system, and to ensure further high voltage electrical testing may (relatively) safely continue, in terms of danger of failing the insulation. Normally, the measurements of IR will be in the mega-ohm range for good insulation, after the winding is subjected to a DC test voltage usually done anywhere from 500 to 1000 V, for one minute. The minimum acceptable reading by IEEE Standard 43 is (Vf in kV + 1) MΩ. The test is carried out with a “Megger” device. The DC test voltage level is usually specified based on: the operating and field forcing voltage of the rotor, utility policy and previous experience, and knowledge of the present condition of the insulation in the rotor. It is essential that the rotor winding be completely dried before any testing, so that any poor readings will be due to a “real” problem and not residual moisture. The readings are also sensitive to factors like humidity, surface contamination of the coils, and temperature. Readings should be corrected to a base temperature of 40oC (see Figure 5-26). All of the above also applies to the rotor bore copper and collector rings. 5.17.4.3.3

Polarization Index (PI)

Insulation resistance is time dependent as well as being a function of dryness for rotor insulation, just as in the stator. The amount of change in the IR measured during the first few minutes depends on the insulation condition, and the amount of contamination and moisture present. 5-105


Therefore, when the insulation system is clean and dry, the IR value tends to increase as the dielectric material in the insulation absorbs the charge. When the insulation is dirty, wet or a gross insulation problem is present, the charge does not hold and the IR value will not increase, due to constant leakage current at the problem area. Thus, the ratio between the resistance reading at 10 minutes and the reading at 1 minute produces a number or “Polarization Index” which is essentially used to determine how clean and dry the winding is. The recommended minimum PI values are as follows: •

Class B insulation:

2.0

•

Class F insulation:

2.0

The same Megger used for the IR readings should be used to determine the PI. The PI readings should be done at the same voltage as the IR test and can be used as a go/no-go test before subjecting the rotor to subsequent high voltage tests, either AC or DC. The IR readings for the PI test should also be corrected to 40oC as in the IR test (see Figure 5-25). Performing the high voltage tests on wet insulation may result in unnecessary failure of the insulation. 5.17.4.3.4

DC Hi-Pot

The DC Hi-Pot test is used to ascertain if the winding is capable of sustaining the required rated voltage levels (without a breakdown of the insulation), with a reasonable degree of assurance for capability to withstand over-voltages and transients, and maintain an acceptable insulation life. The test consists of applying high voltage to the rotor winding for one minute. DC Hi-Pot testing on rotor windings is normally done between 1500 V up to approximately 10 times the rated field voltage. 5.17.4.3.5

AC Hi-Pot

The AC Hi-Pot test is also used to ascertain if the winding is capable of sustaining the required rated voltage levels (without a breakdown of the insulation) with a reasonable degree of assurance for capability to withstand over-voltages and transients, and maintain an acceptable insulation life. The test consists of applying AC high voltage to the rotor winding for one minute. AC Hi-Pot testing on rotor windings is also normally done at to 10 times the rated field voltage at line frequency of 60 Hz. 5.17.4.3.6

Shorted Turns Detection - General

Shorted turns in rotor windings are associated with turn-to-turn shorts on the copper winding, as opposed to turn to ground faults. 5-106


Rotor winding shorted turns, or inter-turn shorts can occur from: an electrical break down of the inter-turn insulation, mechanical damage to the inter-turn insulation allowing adjacent turn to turn contact, or contamination in the slot which allows leakage currents between turns. A project was implemented by EPRI that developed a traveling wave monitoring technique that can both detect and determine the location of shorted windings on-line without the installation of a sensing coil. The report On-Line Detection of Shorts in Generator Field Windings, TR-114016, [45] describes this project. When shorted turns occur, the total ampere-turns produced by the rotor are reduced, since the effective number of turns has been reduced by the number of turns shorted. The result is an increase in required field current input to the rotor to maintain the same load point, and an increase in rotor winding temperature. At the location of the short, there is a high probability of localized heating of the copper winding and arcing damage to the insulation between the turns. This type of damage can propagate and worsen the fault, such that more turns are affected, or the ground-wall insulation becomes damaged and a rotor winding ground occurs. One of the most noticeable effects of shorted turns is increased rotor vibration due to thermal effects. When a short on one pole of the rotor occurs, a condition of unequal heating in the rotor winding will exist between poles. The unequal heating may cause bowing of the rotor, and hence vibration. The extent and location of the shorted turns and the heating produced will govern the magnitude of the vibrations produced. One general relationship between the location of the shorted turn/turns and vibration is: •

Lower vibration is generally experienced when the short is on the Q-axis.

•

Higher vibration is generally experienced when the short is nearer the pole or D-axis.

Stated differently, the rotor is more prone to vibration due to shorted turns, if the shorts are located in the “small coils” rather than in the “large coils”. The “small coils” being those located closer to the pole-faces. The reasoning for the above is the lack of symmetry with faults nearer the pole face. There is an inherent unbalance in the geometry and heating effect on the rotor forging. Off-line methods for detecting shorted turns include winding impedance measurements as the rotor speed is varied from zero to rated speed, and RSO (Recurrent Surge Oscillation) tests, based on the principle of time domain reflectometry. In addition, a short of significant magnitude may be identified by producing an Open Circuit Saturation Curve, and comparing it to the design OC Saturation Curve. If the field current required to produce rated terminal voltage has increased from the original design curve, then a short would be likely present. The number of shorted turns may be identified by the ratio of the new field current value over the design field current value. All of the above methods of identifying shorted turns are prone to error and only indicate that a short exists. They do little to help locate which slot the short is in and require special conditions 5-107


for collecting the data or for testing. To better identify shorted turns, and to employ a method that works on-line, the search coil method has been perfected. Each OEM has their own version of a search coil method, but all work essentially in the same manner. 5.17.4.3.7

Shorted Turns Detection by Recurrent Surge Oscillation (RSO)

In the RSO method, a low voltage (a few volts) high-frequency (kHz range) surge wave is injected at each one of the collector rings. The two signals are then compared to determine if the same waveform is observed at each collector ring. If the waveform is identical, then no shorts are present. Variations in the two waveforms would indicate shorts to be present. This method is based on the principle of time domain reflectometry. This also has the advantage of allowing the rotor to be spun as well, while doing the measurements, to determine if the shorts are also speed sensitive. This test has the advantage of taking the mechanical loading effects into consideration. In the spinning RSO, there may be shorts that reveal themselves, which are not seen when the rotor is at rest, because at rest there is no mechanical load on the winding turns, other than their own weight. Because the RSO also works on a time of flight principle, the location of the coil number where the shorts are, as well as which pole, are also somewhat discernable by this method. Shorts nearer the sliprings show up as blips in the RSO pulse nearer the left side of the traces. And for the number of turns shorted at the particular location (i.e. the particular coil), the magnitude of the blip increases as more turns are shorted. In the “at-rest” test, the RSO is connected directly to the winding via the collector rings. Thus, only the winding impedance is seen by the high frequency, low voltage pulses sent by the RSO. In the “spinning” RSO test, to accommodate the moving rotor, the leads of the RSO must be connected to the brush rigging, and the connection to the winding is then implemented via the brushes-collector-rings. However, with this connection also anything connected towards the excitation equipment is “seen” by the pulses (e.g.: leads, contacts, field breaker, field resistor, excitation equipment). The principle of operation of the RSO is comparing the pulses inserted in each polarity terminal of the winding, and their reflections. The test is extremely sensitive to any asymmetry on the path of the pulses. From a point of view of the wave-impedance seen by the high-frequency pulses, the field winding is by nature very symmetrical, but the excitation system is anything but that. Therefore, in order to obtain any significant signature on the condition of the field-winding, the “noise” originating in the path towards the excitation must be reduced as much as possible. This is achieved by opening the excitation leads at a convenient location between the excitation system and the brush rigging. After the leads are open, only cables of almost exactly equal length are left connected to the brush rigging. The effect introduced by these cables is generally negligible. Figures 5-33 to 5-39 depict samples of RSO test-readings taken on a 2-pole turbo-generator rotor.

5-108


Figure 5-33 NO Shorted Turns Traces – Superimposed (Courtesy of IEEE © 2004)

Figure 5-34 NO Shorted Turns Traces – Separated (Courtesy of IEEE © 2004)

Figure 5-35 NO Shorted Turns Traces – Summed (Courtesy of IEEE © 2004)

5-109


Figure 5-36 RSO Single-Shorted Turn – Dual Superimposed Trace (Courtesy of IEEE © 2004)

Figure 5-37 RSO Single-Shorted Turn – Difference Trace (Courtesy of IEEE © 2004)

Figure 5-38 RSO Dual-Trace – Multi-Shorts (Courtesy of IEEE © 2004)

5-110


Figure 5-39 RSO Difference Trace – Multi-Shorts (Courtesy of IEEE © 2004)

5.17.4.3.8

Shorted Turns Detection by Open Circuit Test

Producing an Open Circuit Saturation Curve, and comparing it to the design Open Circuit Saturation Curve may identify a shorted turn condition of significant magnitude. If the field current required to produce rated terminal voltage has increased from the original design curve, then a short would be likely present (see Figure 5-40). The number of shorted turns may be identified by the ratio of the new field current value over the design field current value. However, due to the many number of turns in a typical rotor winding, the changes in open circuit voltage due to a single shorted turn in the field winding may go unnoticed since the measurement is too small for a positive identification. The open circuit stator voltage versus field current characteristics can be measured in all synchronous machines. This curve, taken with the machine spinning at synchronous speed, is unique for each machine. In principle, this test allows detecting shorted turns in brushless machines, where RSO techniques are too difficult to perform, and always entails partial disconnection of the rotor leads.

5-111


Figure 5-40 STD by Open Circuit (Courtesy of IEEE © 2004)

5.17.4.3.9

Shorted Turns Detection by Winding Impedance

Impedance measurements while the machine is decelerating or accelerating can also be used to detect a speed dependent shorted turn. Any sudden change in the readings may indicate a shorted turn being activated at that speed. A gradual change of impedance of more than 10% may also indicate a solid short (Figure 5-41).

5-112


Figure 5-41 STD by Impedance (Courtesy of IEEE © 2004)

5.17.4.3.10

Shorted Turns Detection by Low Voltage DC or Volt Drop

This test is designed to determine the existence of shorted turns in the rotor winding. The test is entirely different when performed on salient pole rotors than in cylindrical (round) rotors. In salient pole machines, a “pole drop” test is done. In this test, the resistance across each individual pole is measured by the V/I method, i.e., applying a voltage of around 100 to 120 volts, 60 Hz, to the entire winding, and then measuring the voltage drop across each pole. A pole with lower voltage drop will indicate a shorted turn or a number of shorted turns. In either salient pole or round rotor machines, the shorted turns are often speed dependent (i.e. they might disappear at standstill). To partially offset this phenomenon, it is recommended to repeat the pole drop test a few times with the rotor at several angles. The gravity forces exerted on the vertically located poles may activate some short circuits between turns, which might not show up when in, or close to, the horizontal position. In round rotors the individual windings are generally not accessible, unless the retaining-rings are removed. Therefore, detection of shorted turns in not always possible by this method. 5.17.4.3.11

Shorted Turns Detection by Low Voltage AC or ‘C’ Core Test

A “C” shaped, wound core is required to carry out this test, together with a voltmeter, wattmeter and single phase power supply (see Figure 5-42). Shorted turns are detected by sharp changes in the direction of wattmeter readings (see Figure 543). 5-113


In rotors with damper windings, or with the wedges short-circuited at the ends to form a damper winding, these have to be disconnected at the ends. This operation requires removal of the retaining-rings.

Figure 5-42 C-Core 1 (Courtesy of IEEE © 2004)

5-114


Figure 5-43 C-Core 2 (Courtesy of IEEE © 2004)

5.17.4.3.12

Shorted Turns Detection by Shorted Turns Detector (Flux Probe)

The flux probe is actually a search coil mounted on the stator core by various methods, but located strategically in the air gap. The search coil looks at the variation in magnetic field produced in the air gap by the rotor as it spins. The energized rotor winding and the slotted effect of the winding arc cause a sinusoidal signal to be produced in the winding face of the rotor. The pole face on the other hand has no winding and the signal is more flat since the variation in magnetic field is minimal. The magnitude of the sinusoidal peaks in the winding face is dependent on the ampere-turns produced by the winding in the various slots. If there is a short in a slot, then the peak of the signal for that affected slot will be reduced. The reduction will be dependent on the magnitude of the short. Therefore, as well as knowing which slot the short is in, an estimate of the number of shorted turns can be made fairly accurately. Problems due to saturation effects at full load can occur in analyzing the data and most OEM’s now have a dedicated monitor connected to the flux probe to automate the analysis process. This allows the flux probe and monitor to act as stand-alone sensor to alarm when a short turn is detected and notify the operator for investigation. 5-115


Probably the most effective method for the detection of shorted turns in solid rotors is the flux probe method. This device maps the flux of the machine as it rotates, indicating possible shorts as changes in the measured waveform. Its main advantage is that it works with the rotor on-line, capturing the speed dependent shorts. Its main disadvantages are the expertise required in analyzing the recorded waveforms, and the fact that the machine has to be de-energized and degassed for the installation of both core-mounted and wedge-mounted types of probes. New commercially available units intended for on-line continuous operation, include software, which analyses the waveform and alerts to a possible shorted-turn condition. 5.17.4.3.13

Field Winding Ground Detection by Split Voltage Test

The “split voltage” test is used locate rotor grounds as a percentage through the field winding. For this test to be effective, the resistance to ground of the fault must be less than 5% of the balance of the rotor insulation, and the voltmeter must have high input impedance, when compared to the ground fault. The retaining-rings should also be left on in case the ground is to one of the rings. The test is done by applying up to 150 Volts DC, ungrounded, across the sliprings. A measurement of DC voltage is then taken from the rotor coupling at the turbine end of the forging to one of the collector rings. The measurement is then made from the other collector ring and the same location on the rotor coupling at the turbine end. In this way, the two voltage measurements can be compared to estimate how far into the winding the ground has occurred. If the two measurements are equal, the rotor ground fault should be found in the middle of the winding. If there is less than 2% difference between the two readings, then the ground could possibly be at the collector rings. This test is very useful in helping to determine how much dismantling is required to find the ground. Depending on where the ground is located, it can obviously make a big difference in the time expended to find the fault (see Figure 5-44).

5-116


Figure 5-44 Rotor Ground – Split Voltage (Courtesy of IEEE © 2004)

5.17.4.3.14

Field Ground Detection by Current Through Forging Test

The “current through forging” test is another test used to locate rotor-winding grounds. In this particular application, the test is used to locate the actual “axial” position of the ground. The retaining-rings should be left on the rotor in case the ground is at one of the rings. For this test, a DC current of about 500 amps is put through the forging from the tip of the forging at the slipring end to the coupling at the other end. A DC ammeter is used to look for the ground position. This is done by attaching one lead of the ammeter to the most outboard slipring, and then using the other lead to probe along the axial length of the rotor forging. At the point where the ground is, the current should reduce to zero or if the current is not zero but only very low, then there will be a polarity change at the ground location (see Figure 5-45).

5-117


Figure 5-45 Rotor Ground – Current Through Forging (Courtesy of IEEE © 2004)

5.17.4.3.15

Shaft Voltage and Grounding

During operation, voltage may rise on the generator rotor shaft, unless the shaft is grounded. The sources of shaft voltage are well established and identified as: voltage from the excitation system due to unbalanced capacitive coupling, electrostatic voltage from the turbine due to charged water droplets impacting the blades, asymmetric voltage from unsymmetrical stator core stacking, and homopolar voltage from shaft magnetization. If these voltages are not drained to ground they will rise and break down the various oil films at the bearings, hydrogen seals, turning gear, thrust bearing, etc. The result will be current discharges and electrical pitting of the critical running surfaces of these components. Mechanical failure may then follow. Inadequate grounding of the rotor will also allow voltage to build on the generator rotor shaft. Inadequate grounding may be due to: a problem with the shaft grounding brushes from wear (requiring replacement brushes) or a problem with the associated shaft grounding circuitry if a monitoring circuit is provided. High shaft voltages can also be caused by severe local core faults of large magnitude, which impress voltages back on the shaft from long shorts across the core. Protection against shaft voltage buildup and current discharges is provided in the form of a shaftgrounding device, generally located on the turbine end of the generator rotor shaft. The most common grounding devices consist of a carbon brush or copper braid, with one end riding on the rotor shaft and the other connected to ground. 5-118


Shaft voltage and current monitoring schemes are also provided in many cases to detect the actual shaft voltage level and current flow through the shaft grounding brushes. This has the advantage of providing warning when the shaft grounding system is no longer functioning properly and requires maintenance. There are numerous monitoring schemes available and each OEM generally has its own system provided with the TG set when purchased. For older machines with only grounding and no monitoring, a monitoring system can usually be retrofit to the existing ground brushes. The OEM should be consulted when upgrading the shaft monitoring.

5.18 Excitation System The primary purpose of the excitation system is to provide excitation to the main generator. The main components of any main generator excitation system are: a power supply, a voltage regulator, and a generator field. The power supply, which can be electrical or mechanical, provides energy to drive the excitation. The electrical supply can be either a transformer taking power from the generator bus or a station auxiliary bus feeding a motor generator set exciter. The main generator field will convert the current supplied by the excitation system into a magnetic field. The lines of magnetic flux from the rotating generator field cut through the stator-mounted armature winding and induce an ac voltage in the windings. To control the current supplied to the generator field, a voltage regulator is used. The control of the field may be direct or indirect. An indirect approach controls the field current, and a direct approach controls the actual generator field current. There are other components in addition to the three mentioned above; they are discussed in the EPRI report Tools to Optimize Maintenance of Generator Excitation System, Voltage Regulator, and Field Ground Protection, 1004556 [46]. This report was developed because the cost of lost generation can greatly exceed the cost of repairing the excitation system. A low-cost high-benefit ratio is needed to maintain and improve reliability and availability with maintenance budgets the way they are in a plant provided will help plants benefit economically by using appropriate levels of PdM and PM tasks through equipment upgrades. For more information on generators, see the EPRI Power Plant Electrical Reference Series: Volume 1, Electrical Generators, EL-5036-V1 [47]. Each of the volumes in this series provides comprehensive and practical information regarding electric power apparatus and electrical phenomena. Volume 1 presents various excitation systems and their effects on generation operation for overexcited and underexcited field conditions. It also describes the basic construction of generators and information concerning the units. An EPRI report to be issued in January 2006, Excitation System Retrofit and ReplacementLessons Learned, 1011675, [60] will provide guidelines on avoiding technical and project management mistakes in the procurement and retrofit process. This guide will also document the best practices in replacing excitation systems in hydro, fossil, and nuclear plants. A generic specification will be published as part of the guide.

5-119


5.19 Using Data on Condition Assessment to Assess Risk of In-Service Failure As maintenance intervals increase, parts remain in service for longer periods, and the chances for inspection to reveal forms of damage increase. The data obtained on the condition of parts in the turbine or generator may be assessed either deterministically or probabilistically. In either approach, the basic objective is to calibrate the significance of wear or damage, as characterized by the type of NDE test, the strengths and limitations of which have been previously reviewed. A deterministic approach produces a result (in terms of time or cycles) that is subjective to the user’s selection of discrete input or factors. A probabilistic approach relies on statistical distributions to describe these same factors and, by their random combination, estimates the chances of a failure over the same scale of time or cycles. Examples of each are illustrated in Volumes 6 and 7 to guide the inspection and replacement of HP, IP, and LP blades Each approach has merits. A deterministic assessment using NDE data may weigh how much conservatism or factor of safety exists for a given component for a consistently applied operating scenario. It can identify where the weakest point occurs in a structure, which will have the least amount of tolerance to damage. For components where there is a vibratory stress imposed on a steady load (like rotating blades), it can be used to predict the point at which high-cycle fatigue will assume control of crack growth, leading to fracture. A probabilistic approach recognizes that the real world involves uncertainties: for example, variation between parts, the accuracy of different NDE techniques, the inherent variability in tolerances, material properties, and the operating stresses that occur within a part. It is generally a more valid method for weighing the options of run, repair, or replace that are faced by a maintenance engineer when inspection reveals damage that can be tolerated for a limited period. The fundamentals in a risk assessment are summarized as follows: •

Every component has inherent strength, selected by design to withstand an expected range of stress.

•

Conventional remaining life formulas use discrete terms or values to represent properties. Design formulas often include factors of safety.

•

In practice, both are random quantities. If applied in the life prediction formulation, the results generally produce a probability distribution as shown in Figure 5-46, where failure versus no failure is defined by the limit state function.

•

The population to the right of the limit state function has a low risk of failure.

5-120


Figure 5-46 Example of a Probability Distribution and Limit State Function

Component life is evaluated in two ways; (1) the number of cycles or time to initiate cracks, and/or (2) the remaining cycles or time for cracks to propagate to their critical size. As noted, if there is a dynamic stress present, then this needs to be factored into the assessment. In a probabilistic treatment of NDE data, each mechanism is evaluated using the same basic approach. As shown in Figure 5-47, results are produced by first coupling material properties (obtained from published specimen tests results) with field measurements (obtained during the outage). The operating history is represented in terms of start-stop cycles, hours in service or years of service, depending upon the type of damage mechanism that is being evaluated. For example, low-cycle fatigue or stress corrosion cracking would be evaluated on a scale of startstop cycles or years of service, whereas creep would be based on hours in service at high temperature. High-cycle fatigue life is generally measured in hours or days, particularly when dealing with turbine blades.

5-121


Figure 5-47 Basic Elements of a Probabilistic Analysis

In any assessment, stress is typically the most critical factor that is unknown to the operator. Unfortunately, until faced with a problem, many operators do not learn that it is often difficult or impossible to obtain stress from the designer and that independent analysis requires dimensional details from the component and time to perform the calculations. It is therefore becoming standard practice among many plants to reverse-engineer parts, such as blades, that they expect to replace or to maintain spares even though they may still rely on the OEM as a supplier. With this data in hand, the simulation is performed in advance of the outage so that the distribution of stress throughout the component is available prior to the outage. When each of the factors has been described, a Monte Carlo simulation is performed, which essentially means that the input factors are randomly combined within the selected life consumption formula. NDE data may be processed directly when it is available. Prior to an outage, incremental ranges of indication/crack sizes can be processed. These results are plotted either on a log scale or linear scale as a family of curves to show the relative change in risk that occurs as the size of an indication is increased and refined as necessary when actual data are taken.

5-122


To illustrate this approach and its application in condition assessment, assume that the previously mentioned technique in remote optical examination of the first row HP buckets was performed during a boiler inspection. A noticeable degree of solid particle erosion on the leading and/or trailing edges of the blades was identified. To make a quick determination of the risks involved in running the row in its present condition, a family of probability curves was produced in advance of the inspection As shown in Figure 5-48, these individual curves relate the risk of a failure to incremental notch sizes of 50–350 mils (1.27–8.89 mm). They are based on stress results obtained from a finite element analysis, using an erosion rate that was determined from the inspection records prior to when notches became visibly apparent. A hypothetical distribution of NDE results was applied to produce the initial set of curves that was easy to update if necessary when the actual results became available.

Figure 5-48 Example of SPE Inspection Criteria Using Series of Probability of Failure Curves

Inspection revealed no cracks, but random patterns of notch wear ranged from 90 to 225 mils (2.3 to 5.7 mm) on the trailing edge. The maximum size notch of 225 mils (5.7 mm) measured after six years is plotted to show the present status of the row. The change in probability is reflected for each subsequent year of continued operation, extended to the next six-year interval. In the example, the probabilities are also categorized using a hazard risk assessment classification matrix originally produced for the Department of Defense (MIL-STD-882C 5-123


“Military Standard System Safety Program Requirements,”) [48]. This classification can further facilitate the interpretation of results, beyond a comparison in the relative change in odds. When reflected in this manner, it quickly becomes apparent that the operator has a powerful tool by which the NDE data reflecting the present condition of the component can be assessed and extrapolated to support a run, repair, or replacement strategy. If combined with the costs of doing the maintenance versus deferring the maintenance, the financial outcome can further assist in identifying what the optimum time would be to replace the damaged blades. The following is noted regarding risk assessment as it relates to turbine-generators: 1. Many commercially available programs have evolved to the point where it is not the mathematics that limits the effectiveness or value of probabilistic applications. 2. The most important ingredient in any assessment is a fundamental understanding of the damage and/or failure process that is being evaluated. The probabilistic model needs to focus only on those factors that are relevant. 3. Any risk assessment should focus on individual types or forms of damage, rather than trying to treat all potential contributors/mechanisms together. The types of damage that affect turbine-generator components are varied, may occur at different times within the start-stop cycle, and affect different locations on the component. 4. A well-planned model should be capable of running millions of studies in a matter of minutes. This can allow the operator to consider “what if” scenarios in which the input parameters can be varied to test the sensitivity of the projected risk with regard to key assumptions. 5. Since the approach is meant to be component specific, valid stress results must be available as input to the probabilistic model. These results should be derived from finite element analysis, not design formulas that tend to approximate and/or include factors that do not reflect the stress field in regions of concentration (where damage naturally tends to form). A competently performed analysis should be able to produce very reasonable values of stress as input to the model, that is, with a minimum amount of uncertainty. 6. Most turbine-generator components rely on conventional materials that are well understood in terms of their mechanical behavior and for which there is ample published information to develop a statistical basis for input to the model. As more data are used in the model, the degree of uncertainty associated with this key parameter is reduced. It is important, however, not to mix data taken from different alloys or test conditions, but to segregate the information appropriately. 7. In terms of affecting the projected risks, the greatest source of uncertainty is often associated with the NDE data and how it is characterized. As a rule of thumb, the uncertainty increases and confidence decreases as the size of the indication approaches the detection limits of the sensor.

5-124


8. At present, most sensors cannot accurately characterize indications with any degree of certainty below 30–50 mils (0.762–1.27 mm). To compensate for this, many risk analyses presume damage exists of a magnitude just below this detectable threshold. It should be noted, however, that for some mechanisms (SCC and LCF), this assumption might represent a significant acceleration in the actual rate of crack formation and growth and thereby artificially increase the projected risk of failure. This is particularly true if the damage is occurring in regions of low stress. The last point is worth some further discussion. Figure 5-49 represents an example published by an OEM [49] in which test indications obtained by UT were compared via destructive analysis. The plot shows the ratio of measured sizes, based on UT, versus actual sizes. The range of scatter reflects the increased statistical uncertainty that would be introduced if used as input to a probabilistic analysis. The statistical uncertainty becomes more notable as the cracks approach the detection limits of the NDE technology. For application in a risk assessment, it is therefore important to scrutinize data obtained on the condition of a part to ensure that it is a valid representation of its actual condition.

Figure 5-49 Ratio of Actual Crack Sizes to Measured Crack Sizes

5-125


Additional information is provided in Volumes 6 and 7, the EPRI report Steam Turbine Disk Brittle Failure – Influencing Parameters and Probabilistic Analysis Demonstration, 1003264 [50]. The report describes a methodology for assessing the probability of disk brittle failure due to stress corrosion cracking. The probabilistic method features a finite-element-based approach to calculate stress intensity as a function of crack length for arbitrary crack geometries. The importance of key factors governing the probability of failure is demonstrated through a parametric study.

5-126

6

OIL FLUSHING

Oil flushing often represents a significant period of critical path time. The information presented within this guideline is primarily designed to identify and describe methods or approaches that have been used to perform these operations effectively. Methods, tools, and practices that can accelerate the flushing procedure are discussed for various systems found on different types of units. Practical approaches or modifications to present systems that would allow bearings to be isolated and drained on an individual basis are also discussed. This section of the guidelines identifies, reviews, and compiles practices and techniques that are normally involved or should be undertaken during the flushing and replacement of the turbinegenerator lubricants.

6.1

Preparations and Precautions for Flushing the System

Because the turbine lube oil is often contaminated during maintenance inspections, the oil system must normally be flushed. To flush the turbine lube oil system, the oil velocity must be increased, and the oil must be heated, cooled, and filtered so that contaminants can be removed from the system. The following information describes the necessary changes that must be made before the start of a turbine lube oil flush. 1. At the lube oil reservoir, perform the following activities before flushing: a. Drain and clean the lube oil reservoir. b. Remove and clean the oil cooler tube bundles. c. Install one clean oil cooler tube bundle in the cooler. d. Make provisions to heat and cool the oil in the oil cooler with the tube bundle installed. e. Set the oil cooler transfer valve to the cooler with the bundle installed. f. Install a fine mesh screen on the bayonet screens in the return oil sump in the reservoir. g. Fill the lube oil reservoir with clean oil. h. Make provisions to monitor the electrical loads on the lube oil pump motor during the flush.

6-1

Oil Flushing

i. On units with bearing oil relief valves, increase their setting so that they do not open during the flush. j. Clean and check all reservoir door seals. k. On units with temporary oil filtering skids, connect the skid to the reservoir, install new filtration cartridges, and make the appropriate electrical connections. 2. At all steam control valves for mechanical hydraulic control (MHC) units: (stop, throttle, control, governor, reheat stop, and intercept), perform the following activities before flushing: a. Disconnect the oil feed and drain lines to the servomotors. b. Install bypass jumpers from the oil feed line to the oil drain line. c. Install blanks on the servomotors where the oil lines were disconnected. 3. At the front pedestals, perform the following activities before flushing: a. Clean the interior of the front pedestal. b. Install a bypass jumper on the journal bearing (feed to drain) with the valve in the line. c. Install bypass jumpers on any mechanical components in the front pedestal, for example, gear feed lines, zero speed switches, and safety bearing feed lines. d. Install the pedestal cover. 4. At the journal and thrust bearings, perform the following activities before flushing: a. Install bypass jumpers on the bearing (feed to drain) with the valve in the line. b. Remove the strainer/orifices from the oil feed lines. c. Label the strainer/orifices and seal in plastic bags. d. Clean all bearing pedestals and install the pedestal covers. 5. At the thrust bearing wear detector, install bypass jumpers on the thrust bearing wear detector (feed to drain). 6. At the turning gear, install a bypass jumper on the turning gear (feed to drain). 7. At the generator, perform the following activities: a. Install blanks in the hydrogen seal feed and drain the line connections to the end bells. b. Install jumpers in the hydrogen seal (feed to drain) lines with the valve in line. 6-2

Oil Flushing

c. Remove the bearing oil feed line to the end bell, and cover the ends with plastic. d. Install a bypass jumper on the bearing (feed to drain) with the valve in line. 8. At the exciter, perform the following activities: a. Remove the bearing oil feed and drain lines, and cover the ends with plastic. b. Install a bypass jumper on the bearing (feed to drain) with the valve in line. The bypass jumpers allow the oil to bypass the bearings and mechanical devices during the oil flush. The valves in the bypass lines allow the oil flows to be maximized in each section during the flush. All ac oil pumps are operated during the flush to increase the oil velocities. The bypass jumper line valves are used to keep from overloading the oil pump motors. During the oil flush preparation period, all blanks that have been installed are recorded for future reference. All strainers, orifices, and piping that have been removed are to be kept in a central location to be installed at the completion of the flush.

6.2

Resources That Should Be Available While Flushing

During a turbine lube oil flush, resources are needed to ensure that the flush is completed in the shortest time possible while performing the flush in a safe manner. Lube oil is highly flammable, and the turbine should be kept as clean as possible during the flush. The system should be constantly monitored during the oil flush to verify that oil does not leak at any of the penetrations at the reservoir, pedestals, end bells, valve servos, or any of the temporary connections. Lube oil flushes are performed around the clock until the flush is completed. Continuous flushing requires resources to be available at all hours. During the flush, mechanics are required to: •

Monitor the oil system

•

Check motor loads

•

Make valve changes

•

Clean screens

•

Change filter elements

•

Stop oil leaks if found

The number of mechanics that are needed will depend on the size of the unit being flushed. Generally, two mechanics per shift are sufficient for a small turbine, and four mechanics per shift are sufficient for a large turbine.

6-3

Oil Flushing

A chemist is required during the oil flush to perform oil sampling and oil cleanliness tests. The chemist can be one of the station chemists, or an outside lab can perform the testing. The oil samples must be taken at regular intervals to determine the progress of the flush. One chemist must be available on each shift. The chemists should coordinate the testing so there is no need for their continuous involvement in the flush. Station operators are needed to •

Start and stop the lube oil pumps

•

Coordinate the heating and cooling of the oil

•

Give advice on the operation of the system

The operator might also choose to monitor the oil pump motor loads. One operator must be available on each shift. The control room operator might choose to have an auxiliary operator also available to perform some of the flushing duties. A field engineer (manufacturer’s representative) is required on each shift to direct the mechanics, chemists, and operators. The field engineer (technical director) determines the period for each segment of the flush, monitors the oil cleanliness, and coordinates the craft. The field engineer is usually the person responsible for the coordination of the entire oil flush. The field engineer is familiar with the turbine lube oil, control oil, and generator hydrogen oil systems. The field engineer knows the proper methods for setting up the flush, performing the flush, and returning the oil system to its proper operating condition after flushing is complete. If a union hall supplies the craft performing the flush, a supervisor to work with the craft will be required on each shift. Depending on the station, the supervisor may be able to perform the duties of one of the other craft involved with the flush.

6.3

Precautions While Flushing

During the oil flush, special precautions must be taken to ensure the safety of the personnel and the cleanliness of the oil system. Serious damage can occur if the lube oil catches on fire. Many plants have had serious oil fires that have resulted in total destruction of the turbine-generator set. The following precautions are to help the maintenance personnel keep the site safe while cleaning the turbine oil systems: •

Avoid any burning, welding, smoking, or open flame in the turbine areas during the flush. Hot oil vapors will ignite when exposed to open flame. Post signs around the turbine to this effect to alert others who might not be involved with the flush.

•

Do not exceed the nameplate rating on totally enclosed fan-cooled or explosion-proof motors. Open drip-proof motors may be operated continuously at 15% above rated amps for flushing.

•

Verify that all temporary hoses are secured before starting the pumps.

6-4

Oil Flushing

•

Do not remove the plastic pedestal covers during the flush unless necessary. These covers keep oil vapors in and dust and dirt out.

•

Make certain that extra fire extinguishers are readily available around the turbine, valves, generator, and oil reservoir.

•

Establish the proper emergency communications with the control room in the event that an emergency shutdown of the pumps is required.

•

When flushing the generator seal oil system, make sure that no oil backs up into the defoaming tanks.

•

Do not allow water to leak into the oil system during the flush. Water can cause oxidation in piping and pedestals and will contaminate the oil system.

•

Be careful while working around hot oil and hot water. During the flush, the oil must be heated to loosen contaminants from the system.

•

Limit the hot water to 190°F (87.7°C) for units with cast-iron water box heads and to 200°F (93.3ºC) for units with steel water box heads.

•

Ensure that all connections, flanges, etc., are thoroughly sealed to keep oil from leaking from the system during the flush.

•

Check for oil spills each time the oil pumps are started.

•

Have operators and crew communicate by using two-way radios during the flush. This will allow the pumps to be shut off quickly in case of an oil spill or an emergency.

•

Monitor oil filter differential pressure to keep the filter cartridges from collapsing. High differential pressures can develop quickly during an oil flush.

•

Monitor the return screens in the oil reservoir to keep oil from overflowing during the flush. Monitor oil levels in the pedestals to keep oil from overflowing at oil seals. Throttle the oil flow valves as needed in bearing bypass jumpers to keep the oil from overflowing at the pedestals.

•

Monitor the oil contamination level at regular intervals to complete the flush in the shortest time possible.

•

Flush the components in the correct sequence. Do not allow dirty oil to enter areas that have been previously flushed.

•

Always use lint-free rags when cleaning components. Lint from the rags can contaminate previously cleaned areas.

6.4

Oil Cleanliness Criteria

The cleanliness of lube oil systems can be measured using different methods. The approved method for Siemens-Westinghouse turbines is to circulate oil through a filter for 30 minutes. The filter is then taken to a chemistry lab and analyzed for contaminant levels. The approved method for General Electric turbines is to collect a 100-ml sample (grab sample) in a bottle from various locations. The samples are taken to a chemistry lab and analyzed for contamination levels. 6-5

Oil Flushing

The method for collecting samples using the filter method is as follows: 1. Protect the sample location from surrounding contaminants. 2. Isolate the strainer by closing the ball valve. 3. Rinse the strainer housing with solvent. 4. Open the strainer petcock, and drain the strainer housing. 5. Open the strainer housing. 6. Rinse down the strainer housing, and cap the interior with solvent. 7. Insert a clean sample screen (150 mesh). 8. Close the container. 9. Close the drain petcock. 10. Open the isolation ball valve. 11. Run the oil sample flow through the strainer for 30 minutes. 12. Close the isolation ball valve. 13. Open the drain petcock. 14. Rinse down the strainer housing with solvent before opening. 15. Open the housing, and remove the sampling strainer. 16. Place the sampling strainer into a clean container. 17. Close the strainer drain petcock. 18. Close the strainer housing. 19. Open the isolation valve to allow continuous flow. 20. Transport the containers to the designated location for sample counting and analysis. The method for collecting samples using the grab sampling method is: 1. Remove the cap and plastic film from a sample bottle. 2. Dip the container into the oil volume, or hold it under a flowing stream of oil. 3. The sample locations are at the pump level in the oil tank, in the detraining section of the oil tank, at the oil purification discharge in the main oil tank, and at the bearing header at the front standard. 6-6

Oil Flushing

4. Replace the film and cap on the bottle. 5. Wipe the outside of the container, and transport the containers to the lab for analysis. Determining whether the oil meets the cleanliness criteria after using the filter sample method is: 1. Wash the sampling strainer with a clean fluid, collecting all residue on a 200-mesh filter into a vacuum flask. 2. Remove the filter membrane and, using a 10X-scaled magnifier, scan the filter to determine the particle size and the number of particles in the 0.005–.010" (0.127–0.254 mm) range. 3. Do not attempt to move or rotate the particles while scanning. 4. Acceptable criteria are: no hard particles above 0.010" (0.254 mm) are allowed and less than five hard particles in the 0.005–0.010" (0.127–0.254 mm) range. 5. Soft particles may exceed the above criteria and are not considered harmful. 6. Soft particles can be readily crushed between the fingers and include lint, paper, sawdust, asbestos or other insulation, and tobacco. 7. Label and date all samples removed from the system to be compared with samples taken at a later date. The cleanliness criteria for the grab sampling method are summarized in Table 6-1. Table 6-1 Recommended Cleanliness Criteria Preferred

Maximum Allowed (Acceptable)

0.005–0.010 mm – less than 32,000

0.005–0.010 mm – less than 128,000

0.010–0.025 mm – less then 10.700

0.010–0.025 mm – less then 42,000

0.025–0.050 mm – less than 1,510

0.025–0.050 mm – less than 6,500

0.050–0.100 mm – less than 225

0.050–0.100 mm – less than 1,000

0.100–0.250 mm – less than 21

0.100–0.250 mm – less than 92

Greater than 0.250 mm – None

Greater than 0.250 mm – None

Shown are number of particles per 100 ml sample of oil

The procedure for counting the number of particles in the oil sample is outlined in the Society of Automotive Engineers, ARP-598A [51]. This procedure says to filter a given volume of oil through a membrane and to count and size the particles deposited on the membrane by using a microscope. Many independent testing labs perform oil analyses, and most large oil companies perform oil particle counts. The acceptable range for the maximum number of particles is similar to the SAE Class 6, and the preferred range for the maximum number of particles is similar to SAE Class 4 contamination levels. 6-7

Oil Flushing

A comparison of the cleanliness levels of turbine oil is provided by the International Organization for Standardization (ISO). The Solid Contamination Code used by ISO is assigned based on the number of particles greater than 5 microns per unit volume and greater than 15 microns per unit volume. ISO Code 16/13 is approximately equivalent to in service oil cleanliness recommendations provided by turbine manufacturers.

6.5

Heating and Cooling the Oil Without Damaging the Bearing

The lube oil should be heated during the flushing operation to increase the flow of the oil and to thermally shock the lube oil piping. The higher oil flow will allow turbulent flow to occur, which will help to dislodge debris that is lodged in the lube oil piping. The heating and cooling of the lube oil piping thermally shocks debris from the piping and allows it to be carried downstream into screens and filters where the debris can be removed. The heating of the oil must be done carefully to keep from damaging the oil or the oil system. During the flush, the turbine lube oil is usually heated in one of the lube oil coolers located at the oil reservoir. The oil coolers use cold water to cool the lube oil during operation of the turbine. One of the coolers should have cold water flowing through it and the other should have hot water flowing through it. This will allow the use of the cooler transfer valve to transfer from hot oil to cool oil during the flush. The methods used for heating the lube oil are: 1. Use hot water from an auxiliary supply. 2. Mix steam and water in a closed system, and then pipe the hot water to the cooler. 3. Mix steam and water in an open system, and pipe the hot water to the cooler. 4. Immerse cal rods in the lube oil reservoir. 5. Immerse a coil in the oil reservoir, and pass hot water through it. Some power stations have the ability to make hot water to use for heating. This hot water can be piped into the lube oil cooler heads to heat the lube oil. Care should be taken to ensure that the oil is heated in the prescribed manner to keep from damaging the oil. Steam and water can be mixed in closed or open systems to supply hot water to the oil cooler. If steam is used to heat water, care must be taken not to overpressure the system or to alloy steam into the oil cooler. Cal rods can be used to heat the oil directly by immersing them in the oil reservoir. These heaters must be the correct types to heat the oil properly. The main problem with the cal rods is that a suitable power supply is not always available.

6-8

Oil Flushing

The last method for heating the lube oil is to immerse a coil into the reservoir and pass hot water or steam through the coil. The size of a coil that is large enough to heat the oil is usually too big to fit into the oil reservoir through the openings at the top of the reservoir. The oil temperature should be brought up to 180°F (82.2°C) when heated. When using water to heat the oil, the water to oil temperature differential should be limited to 100°F (37.7°C) maximum. For coolers with steel water box heads, the water temperature should not exceed 200°F (93.3°C). For coolers with cast-iron water box heads, the water temperature should not exceed 190°F (87.7°C). The preferred method of heating oil is to pipe hot water to the oil cooler and use the cooler to heat the oil. The oil may be heated in one cooler while the system is being flushed using the other heater.

6.6

Minimizing the Use of External Piping While Flushing

Lube oil system cleanliness is essential after a turbine-generator outage and before the turbine is put on turning gear. The ideal lube oil supply has full flow filters installed that filter the lube oil going directly to the bearings. The only unprotected piping that must be cleaned is located between the filter and the bearing. A modified flush can be completed using the turning gear oil pump (TGOP), orifice strainer toggle blanks, valve, connecting pipe, hose, and 100 mesh filter bags. A modified TGOP flush can be completed as bearing standard assemblies are being completed and readied for closure. Orifice strainer toggle blanks are installed in all bearing locations. The orifice strainer toggle blank will prevent oil flow to a bearing and standard when the bearing is unassembled but will allow flushing in another area. The oil piping to the completed standard is flushed using the TGOP with either the orifice strainer in place or the toggle blank installed and unseated. The assembly shown in Figure 6-1 is also installed to allow oil flow through the piping and bearing lower half. A 100-mesh bag, acting as a tell-tale, is added to the end of the drain hose. The 100-mesh bag is the indicator for a clean line.

6-9

Oil Flushing

Figure 6-1 Oil Flushing Piping

The example provided references a system with full-flow filtration before the bearings. The bearings have temporary piping coming out at the horizontal joint to which is attached a 100mesh filter. A modified oil flush can be done without having this full-flow filtration before the oil inlet to the bearings.

6.7

Flushing Without an External Filter

During maintenance inspections, turbine lube oil flushes are often performed without the use of external filters. Flushing the turbine without external filters requires more time to clean the oil system, but it can be less expensive than with external filters. If external filter canisters are not used, some way to remove contaminants must be provided. In the past, fine mesh screen (100 mesh) has been used to catch the contaminants from the lube oil as the oil passes through the bearing strainers. This method of cleaning the oil is not effective because it reduces the volume of oil flowing through the piping. A more effective way to remove the contaminants from the oil is to install a bypass jumper around the bearing to increase the volume flow rate and to install a fine mesh filtration bag on the jumper where it exits the pipe in the bearing cavity. This method allows the flushing of a few bearings at a time, which allows the flows to be turbulent in the piping section that is being flushed. The filtration bag will have sufficient surface area to allow high volumes to flow while removing the contaminants from the oil. These filter bags can be made of nylon or cloth. The detraining section of the oil reservoir is also an area where contaminants can be recovered during an oil flush. The oil in the detraining section must pass through bayonet screens on its way back to the oil pumps. Fine (100 mesh) mesh should be placed on these bayonet screens during the oil flush to capture the large contaminants in the oil. The screens should be checked periodically to ensure that the oil does not flow over the screens as they become clogged with 6-10

Oil Flushing

particulate matter. It is recommended that the oil reservoir have two bayonet screens at the detraining section. This allows the oil to always have one fine screen to pass through while the other screen is being cleaned. One of the most important steps in the oil flush is to drain the oil from the reservoir and thoroughly clean the reservoir before beginning the flush. The oil reservoir has many areas where contaminants settle. During the flush, oil flows are increased, and these contaminants become suspended in the oil. As these contaminants travel throughout the oil system, they allow clean areas to become contaminated. Oil coolers often trap contaminants and should be cleaned before flushing. After the oil reservoir is cleaned, it should be filled with clean, filtered oil. The turbine oil that comes from the vendor frequently does not meet the cleanliness criteria and must be filtered prior to filling the reservoir. It is important that the oil purification system be placed in service during the flush to clean the oil in the reservoir. Some owners have permanently removed the bowser from the unit and have installed a kidney loop oil filtration system, which provides superior filtration of the oil. These kidney loop systems also remove more water from the oil than the bowser. The oil reservoir has doors with rubber gaskets that seal the doors to keep contaminants and water out of the oil. These gaskets should be cleaned and checked to ensure that they are working properly. The vapor extractor should be in operation during the oil flush to allow the oil system to work properly. Some turbines require the vapor extractor to be in operation when the oil pumps are on to keep from overflowing the bearing pedestals. Vapor extractors are used to keep moist air from contaminating the lube oil.

6.8

Techniques to Get Maximum Flow Through Piping

In Section 6.1, there was much discussion about the preparations that must be performed for a lube oil flush. An emphasis on the preparation for the oil flush discussed bypassing the components to enable getting a higher oil velocity in the pipe being flushed. The components that were bypassed had bypass jumpers installed from the feed lines to the drain lines (oil sump in the pedestal). The reason to bypass the components was to keep contaminants out of the clean component and to increase the flow at that location. The components that had bypass jumpers installed were: •

Bearings

•

Thrust bearing wear detector

•

Turning gear

•

Valve servos

•

Front pedestal mechanical components

•

Generator hydrogen seals

6-11

Oil Flushing

The bypass jumpers allow the oil to bypass the bearings and mechanical devices during the oil flush. The sequential valving of the bypass lines allows the oil flows to be maximized in each section during the flush. During the flush, the ac oil pumps on the reservoir are operated to increase the oil velocities. The bypass jumper line valves are also used to keep from overloading the oil pump motors. Another way to increase the flow of oil in the lube oil system is to install a supplemental high velocity flushing pump on the system. The supplemental oil pump is sized according to the main bearing feed header diameter. These pumps can deliver 2,000–5,000 gallons (7.57–18.93 kl) of oil per minute to allow the oil flow to become turbulent in the piping. The supplementary oil flushing pumps are necessary when the auxiliary oil pump motor is not large enough to flush the main bearing feed header. If the auxiliary oil pump does not have enough power to deliver the required flow at the proper pressure, the supplemental oil pump will produce a moderate reduction of the time required to perform the oil flush. The engineer must determine when it is economical to use a supplemental oil flushing pump. If a supplemental pump is required, the desirable type of pump is an electric-driven centrifugal pump. These pumps get their suction from the bottom of the oil reservoir and discharge into the top of the reservoir. There is a gate valve on the pump suction and discharge line and a bypass line around the pump to control the flow rate. On General Electric turbines, when the oil-driven booster pump is removed, the pump discharge can be connected to the plate where the booster pump is mounted. Two bypass lines with throttle valves are also connected to the booster pump plate. When using a supplemental pump, all connection piping must be cleaned before being connected to the reservoir. Flexible stainless steel connection piping is often used to connect supplemental pumps. The oil cooler maximum pressure must not be exceeded when using a supplemental oil pump. This pressure can be found on the cooler nameplate. One of the oil coolers will need to have the internals removed and blanks installed to allow for high oil flow through the cooler. Care must be taken to ensure that there are no leaks at the pump, reservoir, cooler, or piping when using a supplemental pump. Filtration skids are often employed when using supplemental pumps to allow for faster cleaning of the oil. These skids have two canisters that have differential pressure gauges installed to monitor the pressure differential across the filter. Many spare filter cartridges are needed when using filter skids.

6-12

7

ROTOR ALIGNMENT AND BALANCING

During reassembly of the turbine-generator, significant delays can be avoided by the way in which the engineer treats the massive amount of information needed to align bearings and couplings and to rebalance the rotor. Lack of semi-automated or automated means to collect, process, and relate clearance or alignment measurements to the original design specifications can cause problems to be missed until the process of turbine assembly begins. Inefficient management and processing of tight wire information can further contribute to lost time finding internal alignment and balancing solutions. This section of the guidelines presents a generic discussion of the advantages and limitations of different alignment techniques and practices currently applied within the industry. Included in this discussion is a review of techniques for automating the alignment process and the requirements for their application. The discussion proceeds to issues and techniques for automating the alignment process and the requirements for their application. The discussion continues with issues and techniques for balancing the rotor and criteria that can be used to decide allowable vibration limits. An alignment and a balancing primer are available in Volume 3 of this series. The alignment primer covers both coupling and tight wire alignment problems in detail. The balancing primer includes a discussion of issues associated with turbine-generator vibration diagnostics related to balancing. Also included in this series is guidance in the TGAlign (English and SI units versions) software developed by EPRI that optimizes the coupling alignment with a minimum number of bearing moves or no bearing moves. The EPRI report Shaft Alignment Guide, TR-112449, [52] has been developed to provide information on the fundamental causes and effects of misalignment on machinery and the fundamentals of shaft alignment.

7.1

Different Tight Wire Techniques

When performing internal alignment on turbine-generators there are four methods used to record alignment data: •

Tight wire

•

Arbors

•

Precision optical scopes

•

Helium Neon (He Ne) lasers 7-1

Rotor Alignment and Balancing

The tight wire method has been used for many years and is a method that is often used for turbine alignment. Many millwrights are familiar with this process, and many power stations have the special brackets and tools needed to perform tight wire alignment. When the tight wire method is used, a wire is set to special set points at the ends of the turbine casings. The wire is fixed at one end and has a weight suspended from the other end. Sag charts have been developed for specific wire diameters and wire weights. Most turbine maintenance engineers are trained in the tight wire alignment method and can supervise the data collection with ease. The limitations to using a tight wire for turbine component alignment are: •

It is easy to accidentally move the set points.

•

The wire sag must be compensated for.

•

The wire must be moved when installing lower components.

•

It is difficult to get tops-on readings.

The readings obtained with a tight wire are accurate within 0.001" (0.0254 mm), which is within the tolerance for alignment. When the wire is bumped, the set points must be checked to ensure that the wire has not moved. It is very easy to accidentally hit the wire and move the set point. During the tight wire alignment process, much time is spent setting the wire to the set points. The wire sag must be compensated for and can cause errors in the alignment process. Any time a lower component is installed, the wire must be removed and set up again after installing the component. If there are many component moves, the wire setup time can be a considerable amount of the alignment time. When it is necessary to take tops-on readings, it is difficult to get inside the casings to take the wire readings without moving the wire set points. There is also a limit to the number of internal components that can be installed during the topson readings when using a wire. The person taking the data must have enough room to take the wire readings, which is difficult with small diameter components. Another method of internal alignment data collecting is arbor alignment. This method requires an arbor be built specifically for the turbine casing that is being aligned. The arbor can have dial indicators mounted to it, or it can have proximity probes mounted to it to collect the alignment data. The preferred method for collecting data when using an arbor is to use proximity probes. The arbor with proximity probes allows for easy data collection when performing tops-on alignment. Limitations to using an arbor are: •

The arbor sag must be compensated for.

•

The arbor must be moved when installing lower components.

•

The arbor is heavy if not made from tubing or pipe.

7-2


•

Fabrication of an arbor requires a significant amount of time and may impact the outage critical path time if done during an outage.

•

Arbors are expensive.

•

An arbor may require modification for each turbine casing.

Data collection goes very quickly when using an arbor and proximity probes. Arbors can be saved for future use and, in some cases, can be modified to be used on more than one turbine casing. Precision optical scopes have been used for internal alignment with limited success. These scopes require special targets be made to collect the alignment data. There are limited resources available when using optical scopes, and this method is not very popular for large steam turbines. There is no need to compensate for sag when using an optical scope. The limitations for using an optical scope are: •

Limited resources are available.

•

They need a highly trained operator.

•

Special targets are required.

•

They are expensive.

•

They are affected by heat.

•

They are delicate and can be damaged easily.

Helium neon lasers are constantly being developed and improved for use in internal turbine alignment. Lasers are becoming the preferred method for internal alignment because they are very accurate and can shorten the time for performing the alignment. Lasers can be used to take flatness and perpendicularity measurements that are not possible with other methods. The laser can take joint flatness readings, casing fit readings, and radial position readings. Lasers can be set up for short or long distances for internal alignment purposes. The readings are easy to take once the laser is set up. There is no need to compensate for sag when using a laser. There is no need to move the laser when installing lower components, so alignment moves can be performed much faster. The limitations for using a laser are: •

Limited resources are available.

•

They need a highly trained operator.

•

Special targets are required.

•

The laser light can be deflected by heat and smoke.

7-3


7.2

Information Collected from the Unit

A comprehensive slow-speed balancing package should contain a complete vibration history and a record of the vibration readings before and after each in-service balance shot. Also, the type of shot—static or couple—should be recorded. In-service balance shot data provides specific information for each rotor balanced. The sensitivity and high spot numbers can be developed for each rotor. Rotor critical speeds should also be logged during startups. Rotor run-outs should be maintained, especially for rotors that have increasing bows. The run-outs can be plotted to provide a time-effect change of the run-out and assist in planning for refurbishment or replacement. Figure 7-1 shows a 10-year tracking of rotor bowing.

Figure 7-1 Ten-Year Record of Rotor Bowing

Rotor work done during the outage should be included in the balancing reference plan. The following is a typical slow-speed balancing process: 1. Determine the rotor weight, location of balancing planes, unbalance tolerances, etc., before slow-speed balancing. 2. For each balance plane, record the balance weight mass, angular location, and balance plane location for all (both factory and field) previously installed balance weights. Leave the factory weights in place, but remove and resolve the field balance weights. 3. Prepare the couplings for slow speed balance by measuring the coupling bolt hole fit diameters and, if the hole fits are not within 0.003" (.0762 mm) of the smallest diameter fit area, install appropriately sized shim stock the length of the fit area in the oversize bolt hole(s). For example, if the fit diameter of a single bolt hole was 10 mils (0.254 mm) larger than the remaining holes in the coupling, a piece of 5-mil (0.127-mm) stainless shim stock would be rolled to the fit diameter and cut to the length of the hole fit and installed in the hole. 7-4


4. Remove any coupling spacers before balancing except those that are bolted and doweled. 5. Rotate the rotor at a slow speed (typically around 200–300 rpm) to remove any temporary static bow. 6. Record the total indicator run-out (TIR) of the rotor at several planes including the mid-span of the rotor. Typically, run-out is recorded between each turbine stage, at the oil seal areas, the journals, and the couplings. It is not unusual to see rotor bow of less than 0.003" (0.0762 mm). 7. Use the “factory” grooves to balance the rotor during the slow-speed balancing process. Typically, the mid-span balance location is not used for LP rotor during slow-speed balancing. 8. After balancing to the specified criteria, compare the required weights and locations with the removed weights. 9. Install the appropriate weights. Use the mid-span location for HP and IP rotors, especially if they are bowed. (A bowed rotor is one with greater than 0.003" (0.0762 mm) TIR.) The slow-speed balance weight distribution for a bowed rotor is determined by the location (end planes or mid-span) of the bow in the rotor.

7.3

Automated and Semi-Automated Alignment Processes

The steam turbine alignment process consists of internal alignment (stationary components) and shaft alignment (couplings). The internal alignment consists of the alignment performed on casings, stationary blades and diaphragms, oil pump, and governor stand. Shaft alignment consists of the alignment of each turbine shaft (rotor or spindle) to its adjacent shaft. Computer programs can assist in the internal alignment process. These programs can determine the optimum placement of each component and can perform these calculations very quickly after the data have been entered into the program. The turbine manufacturers use computer programs to perform internal alignment on their equipment. This alignment software is available for purchase by turbine owners if they choose to perform the alignment themselves. The collection of alignment data has also been automated, and there are electronic devices that record and store data using computers. These data can be downloaded into automated alignment programs to speed up the alignment process. In addition, computer programs such as TGAlign can assist with the shaft alignment process and save considerable outage time when used on large multi-rotor machines as previously described. The program calculates the optimum bearing moves to achieve an expected alignment within user-specified alignment and move limits. Output reports specify radial positions at oil or gland bores along with shim changes for each bearing that is moved. Changes can be calculated very quickly for different alignment requirements. Previous methods for calculating bearing moves were performed by hand and could take hours. After the data are entered into TGAlign, the program can calculate alignment moves in seconds with no math errors. Lasers can be used to 7-5


assist with the collection of coupling alignment data. Before the use of lasers, these data were taken with micrometers, sliding parallels, and a dial indicator. During the shaft alignment process, the shafts must be turned to collect data. This process is complicated due to the weight of the turbine shafts and the need for the shafts to be stopped at a precise location with no binding in the coupling. A device called the Hutter Pin has been developed that assists with this process, and an ac inverter can be used to power the turbine turning gear. (See Volume 3, Section 3.2 for more details on the Hutter Pin). The Hutter Pin allows for concurrent rotation of both shafts without binding in the coupling. The ac inverter allows the turning gear to be operated as a variable speed motor. By operating the turning gear motor using the ac inverter, the shaft speed can be slowed to obtain better control, which aids in the data collection process. A shaft alignment method called strain gauge alignment allows the coupling alignment to be determined without separating the coupling halves. This method also is the only way to check shaft alignment while the unit is still hot. Strain gauge alignment is performed by measuring the strain in the turbine shaft near the coupling. The strain on the periphery of the shaft is directly related to the concentricity of the two turbine rotors. Strain gauge alignment requires modeling of the turbine rotors, the installation of strain gages on the shaft on each side of the coupling, electronic strain gauge data collecting, and software that analyses the data. This method for shaft alignment is very accurate and results in very low shaft vibration amplitudes. The limitations of the strain gauge alignment method are: •

Modeling of the rotors takes considerable time and effort.

•

Strain gauges must be designed and fit to each rotor.

•

The cost of modeling each turbine is expensive.

Modifications must be made at the pedestals to enable the recording of data. These modifications are required to provide access to the strain gauges when the unit is on turning gear. The cost of the installation is often offset by the benefits of getting more accurate coupling alignment and getting alignment data without separating the turbine couplings. This method allows the owner to check turbine shaft alignment if the unit is off-line for only 8–12 hours.

7.4

Slow-Speed Versus High-Speed Balancing

Slow-speed balancing should be performed on turbine rotors when significant work has been performed to the rotor. A slow-speed balancing procedure is found in Volume 3 that can assist a plant to direct or monitor this process. Significant work would include replacement of buckets/blades, bucket cover replacements, and tie wire replacements. Major work to the steam path does not include any local hand dressing of the buckets or covers. Balancing would also be required if any non-cylindrical machining were done to the rotor. The objective of slow-speed balancing is to get the rotor through the first rotor critical speed during startup after a major outage. Slow-speed balancing is easily completed at the utility 7-6


facility using portable equipment, but high-speed balancing is not often practical for turbine rotors. The time to ship the rotor to a high-speed balance location is often greater than the time required to high-speed balance the rotor during turbine startup. The probability of at-speed onsite balancing still exists even if the rotor was originally high-speed balanced off-site. The effect of the off-site high-speed balance may easily be offset by factors that did not exist where the rotor is balanced, such as assembly, bearing stiffness, loading, dampening factors, and cross effect. High-speed balance is practical for small, single-rotor turbines where field balancing is difficult and for rotors that cannot be field balanced to acceptable levels. The positive impact of a turbine rotor slow-speed balance is not realized in generator fields. Unlike turbine rotors, generator fields do not have a mid-span balance location. Slow-speed balance corrects for the first critical mode (graphically exaggerated in Figure 7-2) by placing weight in the appropriate opposite location to offset the “bow” or “loop.” The most effective spot for the weights is at the location of the bow, which is typically the mid-span location or in close proximity to it. The grooves for weight insertion into a generator field are located out toward the ends, outboard of the retaining rings and inboard of the bearings, generally in the fan ring or similar location. This location for balancing a rotor is commonly called the end plane. It can be seen that the mode shape of the second critical speed (in Figure 7-2) could be excited by the incorrect placement of weights that are attempting to compensate for the first critical mode. The weight placement to compensate for the first critical speed would place one weight opposite the second critical unbalance and opposite the first critical unbalance and may seem to be visually effective. But the second weight on the opposite end could end up being placed on top of the second critical unbalance location, exciting the rotor to greater unbalance and increased vibration. Most 3600-rpm generator fields operate above their second critical speed and below their third critical speed. They experience going through the third critical speed during overspeed conditions. Most 1800-rpm machines operate between the first and second critical speeds will run above second critical speed during an overspeed condition. The third critical speed may also be excited by weights placed in an end plane that attempt to correct for the first critical unbalance. Therefore, slow-speed balancing is not normally done to generator fields because of the reduced possibility of positive impact and the possibility of exciting the higher vibration modes.

7-7


Figure 7-2 Exaggerated Rotor Motion for the First Three Field Critical Speeds

7.4.1 Slow-Speed Balance Requirements/Considerations The manufacturer of the portable balance machine should provide certification of the machine’s balance capability for rotor speed and maximum weight. The machine should be sized to carry the largest rotor in both diameter and length. The vendor that supplies the portable machine should provide machine “footprint” and setup requirements as shown in Figure 7-3. The balancing machine must be lightweight and easy to install without special foundation requirements. Setup should be quick and easy without the need for extended calibration. The machine should be capable of sensitive low-speed balancing, which enhances safety and reduces power requirements. Rotor pedestals must be easy to move for various rotor configurations. The rollers should be self-aligning, which reduces setup time.

7-8


Figure 7-3 Low-Speed Portable Balance Machine

7.5

When Spin Balancing Is Required

Spin balancing of turbine and generator rotors is performed when the turbine is disassembled and the rotors have been removed from the machine. Spin balancing is necessary if any of the following are true: •

The turbine rotor has had bucket or blade work.

•

A rotor is discovered to be bowed.

•

The generator field has been rewound or has had the retaining rings removed.

•

The rotor balance has changed without any definite cause.

It is important to note that generator fields may require a compromise balance between the mechanical and electrical effects on the windings. All fields by nature have some degree of thermal sensitivity, but a field may bow excessively as loading increases (increase in field current); if the unbalance exceeds acceptable vibration limits, the field is identified as being thermally sensitive. The cause of the thermally induced bowing may be uneven temperature distribution within the field or axial forces associated with differential thermal growth between the copper windings and steel body not being evenly distributed. 7-9


Thermal sensitivity may be reversible or irreversible in operation. Reversible thermal sensitivity follows field current (load) both decreasing and increasing. A compromised balance may be required to offset the thermal vector and maintain the vibration within acceptable limits. Corrections for reversible thermal sensitivity may be done either off-site or in the stator if the causes and required balance information are known. Thermally sensitive rotors may be the result of a field rewind. If strict care is not taken during the field rewind, the windings may not be uniformly wound, insulation thickness, binding, uneven friction forces in the slots or under the retaining rings may all be causes of thermal sensitivity. Re-wedging to clean and repair wedges with improper reassembly or after a generator field rewind may also result in a thermally sensitive rotor if wedge tightness is not uniform. Irreversible thermal sensitivity follows an increasing field current but does not reduce with decreasing field current, or it may partially reduce and then “lock in.” This condition typically will limit loading and unit operation. Often, the unit must be taken off-line to turning gear operation to unlock the restrained forces. This condition typically cannot be compensated for with a balance program but requires field disassembly, rewinding, and then balancing. Most spin balancing is performed at low speeds and can be performed at the power plant using a portable balance machine. In some cases, the portable lathe that is used to machine the rotor can also perform the spin balance of the rotor. Low-speed spin balancing is done at speeds below 500 rpm, and the speed varies depending on the size of the rotor and the length of the blades. High-speed balancing of turbine and generator rotors is performed off-site in special balance chambers (or “pits”) or on-site during startup. Balance chambers are designed to spin the rotor at speeds up to the design overspeed of the rotor. For turbines, these speeds are up to 112% of rated speed and, for generator fields, up to 120% of rated speed. It is possible for some high-speed balance chambers to run the balance test at design conditions with heating of the generator field to determine if the field has any shorted windings. All high-speed balancing pits have the ability to pull vacuum to be able to spin rotors up to rated speed without overheating the blades. High-speed off-site balancing may not always be practical for these limiting factors: •

Travel time

•

Rotor size

•

Spin pit capacity

•

Spin pit schedule

•

Balancing duration

•

Rotor availability during the outage

The adverse effect of these factors may force high-speed balancing, which can be done only during the startup period of an outage.

7-10


High-speed balancing may be necessary any time a generator field is rewound. Balancing of the generator field in the stator is very difficult and can take a considerable amount of time and effort. Off-site high-speed balancing of turbine rotors is suggested if the unit is a large baseloaded unit, and the cost of lost generation due to downtime is high. Performing a high-speed balance is expensive, and it is difficult to transport rotors to the balance chambers. If the cost of lost generation is greater than the cost of the high-speed balance, a high-speed balance is recommended. Balance programs in the power plant after a maintenance inspection can take a considerable amount of time, and they are always on the critical path of the outage. A high-speed balance specification that can be used for a turbine, generator, or exciter rotor is provided in Volume 3. The specification includes guidance and acceptability requirements for unbalanced vibration of rotors balanced in a high-speed spin pit. Off-site high-speed balancing of small turbines or turbines that have low capacity factors is generally not recommended. It is usually more cost effective to perform a low-speed balance on the rotor and trim balance the unit when it is started. There may be special cases that require a high-speed balance of a small turbine, but normally, the cost prohibits this work. If many rows of blades are replaced or if the rotor is bowed and requires a lot of machining work, the investment for a high-speed balance may be justified. A high-speed balance should follow all generator field rewinds.

7.6

On-Line Balancing Devices

On-line balancing devices are widely used on smaller non-turbine applications, such as reactor coolant pumps, industrial fans, grinding spindles, machining centers, etc. This technology is being adapted to turbine-generators. For example, technology is currently available for an active balancing system for turbine application that corrects for imbalance while in operation. The obvious advantage of an active on-line balancing system is the time saved during startup and while on-line to correct unbalance conditions. An active on-line balancing system would also allow correction above and below rotor critical speeds, optimizing the critical speed transient vibration. Table 7-1 presents selected specifications of a high-speed turbomachinery active balancing system.

7-11

Rotor Alignment and Balancing Table 7-1 Specifications for an On-Line Active Balancing System Parameters

Range

RPM speed

500–15,000

Balancer capacity

Up to 200 oz-in. (14.40 kg/cm)

Temperature range

-67° to 302°F (- 55 to 150°C)

Humidity

10% to 90% non-condensing

Balance functions

Automatic multi-plane balancing Operator-initiated auto sequence Operator-confirmed individual step On-line system identification Automatic single-plane balancing Manual balance weight positioning

7.7

Potential Consequences of Not Balancing the Rotor

The objective for slow-speed balancing an individual rotor during an overhaul is to increase the probability that the rotor will pass through its critical speeds during startup and achieve running speed without tripping due to high vibration. The time necessary for high-speed balancing of the rotor after the overhaul has been completed should be reduced. When work has been done on a rotor during an overhaul, it is estimated that 50% of them do not make operating speed if no slow-speed balancing has been performed. It has also been estimated that rotors that have been slow-speed balanced during an outage have a 95% probability of reaching operating speed without a balance shot and that more than 80% of rotors do not need high-speed trim balancing during startup after the outage has been completed. In the machine, balance shots are normally done at rated speed conditions; therefore, the data to calculate a shot is at speed. It is much more difficult to calculate a balance shot before getting to rated speed. The reference information used to calculate a balance shot is: 1. Sensitivity in oz./mil (g/mm) is used to calculate the amount of weight to offset the imbalance. 2. The “high spot” number is used for the angular placement of the weights. The amount of weight required and the calculated angular component is obtained from plotting and resolving the imbalance vectors on polar graph paper. The imbalance vectors are the amplitude and angle reference of the rotor vibration readings. This information is not normally available at all the speed variations from turning gear to at speed and may be very difficult to obtain if the unit is vibrating severely at an off speed condition. The rotor must be held at that speed, and the vibration readings must be taken to calculate a balance shot with best guess sensitivity and high spot number. Slow-speed balancing helps the probability of obtaining rated speed after an outage. 7-12


7.8

Selecting Vibration Limits

There are many causes for turbine vibrations; many of which are discussed at greater length in the balance primer contained in Volume 3. Vibration limits are necessary to determine the proper time for turbine balancing. Vibration limits differ depending on whether the unit is starting up after a long maintenance inspection, or if the vibration amplitudes are increasing during operation. The turbine manufacturers give limits for steady-state conditions, critical speeds, maximum levels, and levels for well-balanced units. The following vibration limits are for mechanical unbalance and are measured peak to peak: •

For steady state conditions at high loads on 3600-rpm turbines, the turbine manufacturers recommend that the shaft vibration levels remain at 4.0 mils (0.10 mm) or below.

•

At critical speeds, the vibration levels should remain at 8 mils (0.20 mm) or below.

•

The maximum vibration level for a turbine shaft is 6 mils (0.15 mm).

•

A well-balanced unit should have vibration levels of 2 mils (0.05 mm) or less.

The vibration trip limits depend upon speed, reason for vibration, and length of time at the vibration level. The following trip limits are for 3600-rpm turbines: •

The turbine should be tripped if the speed is 800 rpm or less and the vibration level reaches 5 mils (0.13 mm).

•

For speeds between 800–2000 rpm, the turbine should be tripped if the vibration level reaches 10 mils (0.25 mm) or if the vibration level reaches 7 mils (0.18 mm) for two minutes.

•

For speeds between 2000–3600 rpm, the turbine should be tripped if the vibration level reaches 10 mils (0.25 mm) or if the vibration level reaches 7 mils (0.18 mm) for 15 minutes.

•

For 1800-rpm turbines, the trip limits are 2 mils (0.05 mm) higher than for 3600-rpm turbines due to their larger mass.

Steady-state vibration limits for 3600-rpm turbines vary by manufacturer. The vibration levels used most often for high loads for large steam turbines are as follows: •

Satisfactory operation – 3 mils (0.08 mm) or less

•

Alarm – 5 mils (0.13 mm)

•

Trip – 10 mils (0.25 mm)

When starting a turbine after a long maintenance inspection, it is normal to perform a balance program. Continuous recording equipment is installed on the unit that records vibration amplitudes and phase angles for each bearing and possibly for some of the couplings. Vibration levels are measured at varying loads, and the cause of any unbalance can be determined using the recorded data. The change in vibration amplitude and phase angle is used to determine what corrective actions are necessary. Some problems that cause high vibration levels during start up are: •

Rubbing

•

Misalignment 7-13


•

Water induction

•

Steam temperature variation

•

Faulty steam seal operation

•

Out-of-round bearing journals

7.9

Balance Limits

Out-of-machine slow-speed balance tolerances are a function of rotor weight, operating speed, rotor type, and applicable or chosen equipment standard. Rotors are classified as either rigid or flexible. A rotor is classified as rigid if it operates below any resonant frequency. A rule of thumb states that rotors that operate below 70% of their critical speed are considered rigid. Flexible rotors are those that operate above 70% of the first critical speed or, in general, operate above at least one resonant frequency. Therefore, slow-speed balancing is a rigid rotor mode activity. Table 7-2 provides a listing of some of the available standards that provide information regarding the balancing of equipment and the balancing of rotors.

7-14

Rotor Alignment and Balancing Table 7-2 Sources for Equipment and Rotor Balancing Standards International Organization for Standardization (ISO) Specification

Subject

Content

ISO 1925:1990

Mechanical vibration -- balancing -Vocabulary

Contains definitions of most balancing and balancing equipment terms

Mechanical vibration -- balancing quality requirements of rigid rotors

Classifies rotating work pieces and recommends balance tolerances

ISO 19401:1986

Part 1: determination of permissible residual unbalance ISO 19402:1997

Mechanical vibration – balance quality requirements of rigid rotors Part 2: balance errors

ISO 2953:1999

Mechanical vibration – balancing machines -- description and evaluation

ISO 2954: 1975

Mechanical vibration of rotating and reciprocating machinery -- requirements for instruments for measuring vibration severity

ISO 10814:1996

Mechanical vibration -- susceptibility and sensitivity of machines to unbalance

ISO 11342:1998

Mechanical vibration -- methods and criteria for the mechanical balancing of flexible rotors

Describes for a prospective balancing machine user how to specify requirements to a balancing machine manufacturer, including proposal requirements, and identifies how to test a machine to ensure compliance to the specification

American National Standard Institute ANSI S2.191989

Mechanical vibration -- balance quality requirements of rigid rotors

U.S. counterpart of ISO 1940/1-1986

Part 1, determination of permissible residual unbalance American Petroleum Institute ANSI/API Std 610-1995 Std 611

Centrifugal pumps for petroleum, heavy duty chemical and gas industry services

Contains vibration and balance limits

General purpose steam turbines for petroleum, chemical, and gas industry services

Contains vibration and balance limits

Society of Automotive Engineers ARP1134

Adapter interface - turbine engine blade moment weighing scale

Military Standards Mil Std-167-1

Mechanical vibration of shipboard equipment

Includes basis of acceptability criteria, methods, and limits

7-15


Each standard provides a different method to calculate the required balancing tolerance or the amount of residual unbalance in a rotor. Figure 7-4 is a plot of the impact of various standards on the amount of remaining unbalance.

Figure 7-4 Various Standards for Residual Unbalance

The following are examples of tolerances applied for slow-speed balancing: •

High-pressure rotor

18 ounce-inches/plane (12.96 gram-meters/plane)

•

Intermediate-pressure/reheat rotor


•

Low-pressure rotor


These tolerances are a slight modification from Mil. Std. 167-1 that states: oz-in = 4 W/N Where:

W= rotor weight in pounds for the plane

Example, for a two-bearing symmetrical rotor, W = Half of the total weight of the rotor N = The operation speed of the rotor, for greater than 1,000 rpm A balancing tolerance is applied because it is not necessarily reasonable to take a balance level down to loss of phase signal to ensure smooth rotor operation. Modern sensitive state-of-the-art balance equipment with microprocessor controls is capable of achieving residual unbalance levels below what is normally required for smooth rotor operation. Therefore, slow-speed balance tolerance is a combination of choosing the right residual unbalance level and the right balancing equipment. 7-16


7.10 Access to Turbine-Generator Rotors Access ports through the HP and IP shells for mid-span and end planes and access to LP rotor end plane locations through the condenser are provided for field balancing. Mid-span balance locations may be located through a multi-use location such as rotor pre-warming access. End plane locations in HP or IP section will usually just penetrate the lowest possible pressure location of the section. End plane access through shells is usually radial and axially angular. The balance access and the rotor balance location may not always line up in both cold and hot positions. Therefore, it is advantageous to observe rotor/shell locations during an outage and modify the access if required. Figure 7-5 shows a sketch of an offset modification to a shell bore. The modification is axial and provides sufficient angularity to catch the rotor balance plane in both the hot and cold positions.

Figure 7-5 Offset Modification to a Shell Bore

The generator field balancing locations are the most difficult to access of all turbine-generator locations. Access to the HP and IP section is from outside the shells and through the shells. The difficulty in accessing the HP and IP balance locations may be reduced by removal of the balance port fasteners or alignment of the balance location on the rotor through the shells. The LP rotor balancing location is typically accessed through an opening in the LP hood outer shell. The safety hazards in accessing the LP section may be air quality or elevated humid temperature, especially if the unit has just been shut down. The hazard in entering a generator 7-17


that has just been shut down to access balance locations is the H2 and CO2 that may be present. The generator casing must be cleared of H2 and purged of CO2 prior to entry. But the major difficulty in accessing the generator balance locations is logistical, as seen in Figure 7-6.

Figure 7-6 Access to Balance Grooves

The balance groove located on the fan ring must be accessed by entering the space between the outer and inner end shields. At least one segmented fan nozzle ring is then removed to access the balance groove. The space between the outer and inner end shields is very small. The person inserting the balance weights must be “not claustrophobic,” thin, and flexible. These are legitimate criteria because it is quite possible to get caught on interior fastener lock tabs while sliding through the limited space. Given the space, it can become extremely difficult to release caught clothing. All tools must be tied off to a retrieval string in case they are dropped. Therefore, the generator shot program is planned very carefully to minimize the number of balance shots required.

7.11 Turbine-Generator Balance Support When turbine-generator balancing program is performed, all of the necessary tools and equipment must be on hand before the unit startup. Equipment needed for balancing a turbinegenerator set includes: •

Continuous data collection equipment

•

Power cables, connector cables and rope

•

Atmosphere tester for both LP and generator balancing

•

Balance weights for each rotor and coupling

•

Weight installation tools

7-18


•

Lights and strobe or phase reference

•

Balance shot calculation software or a manual means of determining an appropriate balance shot

•

Safety harness and appropriate extraction equipment for LP balancing (if access to the LP balance location is considered a “confined space” or requires a “confined space” permit)

The equipment used to collect the vibration data varies for each machine. This equipment can gather data continuously or by manual means. If the data are collected manually many pieces of equipment must be checked out before startup. Most systems that are used to gather vibration data on large steam turbines are automatic. After they are set up, they can collect data continuously until they are disconnected. These systems use non-contact proximity probes to transmit the vibration amplitudes and a key phase reference on the shaft to determine the phase angle of the imbalance. It is important to make sure the cables are connected to the proper proximity probe and that they are calibrated to read correctly. This is done during the turbine outage to ensure that they will work during startup of the turbine. Balance weights for each rotor and coupling should be made before the balance program and should include all locking hardware. The balance planes on the rotors should have the weights consolidated during the outage to ensure that there will be sufficient room available if a balance weight needs to be installed. Balance weight installation tools should be checked to make sure that it is possible to install a weight in any location along the shaft if necessary. When installing balance weights, the engineer should be familiar with each rotor and should know how to install the weights. Rope will be needed to tie off weights and tools so they do not be lost if dropped. Lights should also be tied off so they will not be lost if dropped. The turning gear is used to rotate the rotor when installing balance weights. The engineer should be familiar with the operation of the turning gear and the allowable time limits for removing a turbine from turning gear operation when the unit is hot. After the balance weight is installed, the turbine must be rolled on the turning gear for a sufficient amount of time to allow the rotor eccentricity to return to an acceptable level prior to starting the turbine. The turbine engineer should be familiar with these limits before beginning the balancing program. The calculation of a balance shot is required if the rotor is determined to have mechanical unbalance. This can be done manually or by balance software. Most manufacturers use computer programs to plot balance shots. This software is programmed using high spot numbers, sensitivity to weight, pickup angles, equipment phase angle, and influence coefficients for other rotors that are coupled along the turbine train. All of these influences are necessary to plot a balance weight. If the balance weight is plotted manually, the balance engineer should be familiar with each of the influences and should know how to use them to plot a shot.

7-19


7.12 Turbine-Generator Balance Weights 7.12.1 Split-Weight Design Dovetail Weights When attempting to install dovetail-style weights during field balancing situations, you may experience the problem where access to the specific location on a rotor to install a dovetail weight is not available. Removal of previously installed balance weights to gain access to an access slot would be necessary. Figure 7-7 shows a typical split-weight dovetail design that can be used for fast access to the dovetail weight groove at any location, thus not requiring the removal of previously installed weights. Installing this type of weight can save significant time and effort in any individual balancing situation. The weight can be replaced with a standard onepiece weight when the rotor is removed during the next outage where the weights are consolidated during the slow-speed balance. Typical material for balance weights is 12-chrome stainless steel (AISI 403). This split-weight design balance weight uses a long set screw to go through a clearance hole in the top half of the weight assembly and screw into the threaded bottom half of the weight assembly. (See Figure 7-7 for details). By installing a nut (to function as a lock nut) on the exposed portion of the long set screw above the upper half weight, the upper half is fastened relative to the bottom half, and at the same time, the set screw is tightened in the bottom half weight against the rotor, locking the two pieces in the balance groove. Securing this style weight in the balance groove is somewhat of a “trial and error’ process, requiring several iterations of tightening the outer lock nut and then the overall set screw/nut assembly in place. When calculating the required weight size, remember to include the set screw and nut as part of the entire assembly. As an added precaution when installing the balance weight, the nut may be tack welded to the set screw and balance weight. Be sure to install Part B first in the balance weight groove before part A. See Figure 7-7.

7-20


Figure 7-7 Split-Weight Dovetail Weight

7-21


7.12.2 Tungsten-Style Weights Utilities have used balance weights made of tungsten, a material much heavier than the 12chrome stainless steel balance weight material (AISI 403) normally used. However, tungsten is not as resistant to erosion as 12-chrome stainless material and is more likely to lose mass during operation due to exposure to the harsh operating environment inside the turbine; therefore, some precautions should be taken when using this type of weight material. For the LP sections of a unit where moisture is present, dovetail-style tungsten weights can be employed to get more weight in a smaller location; however, the weight should be coated with cadmium to prevent water erosion of the tungsten material. There are companies in the United States that are capable of performing this coating process, which obviously would require some lead time prior to needing to install the weights in the unit. Use of tungsten material for plug-type weights in the HP and IP sections (and any LP sections that may use plug weights) of the unit is usually accomplished by drilling out (counter-boring) the standard field balance plug weight from the bottom side of the plug and then inserting the tungsten material into this counter bore with a size-to-size fit. The plug is then circumferentially seal welded at the tungsten/12-chrome interface to prevent the tungsten from falling out of the standard plug either during installation or removal. This process captures the tungsten material in an erosion-free atmosphere, while also giving the effect of more weight in the same size standard plug.

7-22

8

PRE–STARTUP CHECKS

Currently, the procedure for realigning hydraulic controls is slow, and relies heavily on the availability of an experienced controls engineer and staff of mechanics to relay valve strokes and hydraulic pressures. While the resetting of controls is still somewhat of an art, it is beneficial to establish the practices and procedures used to guide the performance of resetting the turbine controls and prepare a checklist of activities that should precede the return of the unit into service. This section of the guidelines provides a compilation of practices, procedures, and experiences relating to unit startup after overhaul. A review of advances in neural networking techniques that have been used to set boiler controls is included as an emerging technology that could possibly be adopted to automate the procedure by which control line-up problems are solved.

8.1

Steps to Minimize Startup Time

Before the turbine startup, the operator should review the starting procedure and become familiar with each item so that the operation of the turbine will go smoothly. The units in the power station seldom are identical, and each turbine will probably have variations in the starting procedure. It is helpful to create a startup document that identifies and summarizes critical turbine-generator elements to be observed during each startup process. The document should be organized to reflect the flow of startup activities and include: •

The applicable unit

•

Topic of concern

•

Source reference (for additional information or future verification)

•

Process variables

•

Limits

•

Definitions

•

Actions

The information presented in Table 8-1 shows examples of startup topics and relevant details that could be included in a startup document. Note that the applicable unit, primary reference, and other information are not included in this example.

8-1

Pre–Startup Checks Table 8-1 Recommended Outline for a Startup Document Topic

Details

Hydrogen – Air Leak Test

(a) The amount of hydrogen consumed during operation or air during testing is either absorbed into the seal oil or lost through leakage at the seals or other locations. (b) The test should be run with the gas temperature as steady as possible. (c) The generator should be allowed to thermally stabilize for 1–2 hours after filling with gas.

Seal Oil Flow (Absorption)

Gas Loss (Leakage)

Acceptable

Unacceptable

Acceptable

Unacceptable

5–15 gpm (18.9–56.78 Lpm)

<5 gpm (<18.9 Lpm) means tight seals that may be easily damaged.

<1,000 ft 3 (<28.317 m ) per day

3

>15 gpm (>56.78 Lpm) means seals are open and when combined with air side losses, the seal oil requirements may exceed the seal oil supply pump capacity.

3

>1000 cfm (>28.317 m per min). Measure seal oil flow and calculate leak rate. Typical leak rates 3 are 400–500 ft (11.327– 3 14.158 m ) per day 3

3

>2,000 ft (>56.634 m ) per day. Locate and seal loss areas. Design Gas Loss (Leakage) 3

3

300 ft (8.495 m ) per day at 32 psi (220.6 kPa) 3 3 400 ft (11.327 m ) per day at 47 psi (324.05 kPa) 3 3 500 ft (14.158 m ) per day at 62 psi (427.5 kPa) 3 3 600 ft (16.990 m ) per day at 77 psi (530.9 kPa) Turning Gear Operation

10:1 ratio of time off to time on up to eight hours of turning gear run time.

H2O Induction

50°F (10°C) temperature mismatch is considered H2O induction.

T/G Operation After H2O Induction Incident

For temporary rotor bow, 2–6 hours on gear to remove bow. Humped shell may need >24 hours.

8-2

Pre–Startup Checks Table 8-1 (cont.) Recommended Outline for a Startup Document Topic

Details Reduce set point to 75–80°F (24–27°C) 75–80°F (24–27°C) Raise set point to 90°F (32°C) 90°F (32°C) o 95 F° (35°C) (Off wobbulator at 3000 rpm) 100°F (38°C) 110–120°F (43–49°C); <50°F (10°C) [inlet to drain delta T]

Lube Oil Temperature

Unit trip Turning gear 2 hrs before rolling Starting Hold @ 1000 rpm Exceeding 3000 rpm Operating

Vibration Due to Rubbing

At or below first critical speed: Rubbing occurs at one spot; bowing occurs in the direction of the rub, which causes the rotor to bow quickly to large amplitudes. Trip at 8–10 mils (0.20-0.25 mm). Above first critical speed: Rubbing occurs some distance from the high spot. The effect of the bow is minimized because the rotor tends to continuously develop a new high spot. Supercritical rubs are thus usually characterized by unstable vibration amplitudes and constantly changing phase angles of vibration. Though relatively benign, such rubs should not be allowed to develop an excessive amplitude (journal vibration 8–10 mils (0.20-0.25 mm)) before tripping because deceleration through the first critical speed will necessarily be somewhat rougher. Trip if >5 mils (0.13 mm) 7 mils (0.18 mm) for 2 min, or >10 mils (0.25 mm) 7 mils (0.38 mm), for 15 min or >10 mils (0.25 mm) 12 mils (0.30 mm) max (at critical speeds)

Vibration Limits (Roll Up)

< 800 rpm 800–2000 rpm > 2000 rpm

Bearing Metal Temperature

Normal Temperature Ranges: °

°33

Tilt pad 180–220 F (82–104 C) Elliptical 170–190°F (77–88°C) Short elliptical 190–210°F (77–99°c) Alarm: Tilt pad at 225°F (107°C) Elliptical at 210°F (99°C) Maximum temperature: 250°F (121°C) Vacuum Breaking

It is recommended that vacuum not be broken until the unit has reached 2/3 (2400 rpm) of rated speed unless an emergency condition, such as high vibration, requires the unit to be slowed down as fast as possible.

8-3

Pre–Startup Checks Table 8-1 (cont.) Recommended Outline for a Startup Document Topic

Details

Wobbulator

Used to prevent the turbine from running at a constant speed (3000 rpm) when bucket critical speed might be experienced.

Oil Trip Test

<96% of rated speed = <3456 rpm (adjust if it exceeds 3456 rpm). One-half turn of the spindle will alter speed ~150–180 rpm. Counterclockwise rotation reduces speed; clockwise rotation increases speed.

Overspeed Testing

The turbine should not be overspeed tested until it has carried 25% or greater load for at least four hours. The warming period provides time to raise all rotors above their fracture appearance transition temperature (FATT). Rotor material is ductile above its FATT (like a rubber band) and is brittle (like glass) when it is below its FATT. Therefore, by ensuring that the rotors are above their respective FATT means any indications (cracks, pits, stress intensification, etc.) will “absorb” the additional energy created during the overspeed test. FATT Bore temperature is to be above FATT. HP 380°F (193°C) IP 280–345°F (138–174°C) LP 0–25°F (-17 to –4°C) LP 70°F (21°C) (refurbished rotors)

Generator Note One method to retain heat in the field is by isolating the closed cooling water (CCW) to the H2 coolers.

Amount of time off-line between soaking the rotor and the overspeed test is dependent on rotor material properties. Exercise the emergency governor with the oil trip test mechanism when the turbine rotor is initially coming to operating speed. This ensures the operation of the emergency governor. Test Requirements

8-4

Overspeed protection control (OPC) = 1 test Trip anticipator = 1 test, if within stated tolerances Load unbalance protection (LUP) = 1 test Mechanical overspeed = 2 tests, if within stated tolerances Backup overspeed test (BOT) = 1 test Mechanical trip handle at front standard = 1 test

Pre–Startup Checks

Before firing the boiler, perform the steps listed here as a way to reduce the turbine startup duration: 1. Check the oil level in the reservoir to make sure that it is at the proper level. 2. Heat the oil in the reservoir to 90°F (32.2°C) using the oil pumps. 3. Check the bearing header for proper pressure 4. Check the thrust wear detector for correct alarm and trip point settings 5. Check all valve position switches 6. Check all extraction non-return valves for the correct position. 7. Check the dc oil pumps for automatic operation 8. Reset the turbine to ensure that all valves operate correctly. 9. Start the generator hydrogen seal system. 10. Purge the air from the generator and fill with hydrogen When the unit is initially rolled on turning gear, the boiler should be fired. The turning gear should be operated for a minimum of four hours before starting the turbine. During this time, the HP and IP turbines can be pre-warmed. Each unit will have operating instructions for prewarming, and the pre-warming temperatures should be similar for all turbines. The HP turbines should be pre-warmed to 300°F (148.8°C) and the IP turbines should be pre-warmed to 130°F (54.4°C). The IP will be pre-warmed using the steam seals with the condenser backpressure at 5 in. Hg absolute (12.7 cm Hg absolute). During the pre-warming stage, the following items should be checked: •

Eccentricity of the HP rotor

•

Casing expansion detector

•

Differential expansion detector –

Rotor expansion detector

–

HP casing temperature

–

IP casing temperature

–

Condenser backpressure

The time required for the turbine start up varies depending on the initial temperature of the turbine casings. The turbine manufacturers give guideline turbine start rates for starting turbines for three types of start ups: cold, warm, and hot. The starting procedures are based on cyclic lifeexpenditure curves, and these may vary for each type of unit. 8-5

Pre–Startup Checks

Turbine stress monitors have been developed over the years that can determine the stress in the casings and can be used for starting and loading the turbine. These stress monitors allow the turbine to be started at the optimum rate without overstressing the turbine rotor or casings. The stress monitor can shorten the amount of time to start and load a unit if the starting and loading curves are conservative. Stress monitors can also be used for condition-based monitoring of the turbine components. Without the stress monitor, the operator has no way of knowing the actual stresses; therefore, the starting rate must be conservative.

8-6

9

POST-OUTAGE ACTIVITIES

After the unit is returned to service, there is a tendency to view the maintenance outage as being completed. In fact, whereas the overhaul activities are essentially completed, there is a unique opportunity to collect and document information that can be extremely relevant to the planning and preparation of the next maintenance outage. This section of the guidelines presents a generic discussion of the information that should be chronicled as input to the pre-outage planning phase for the next turbine outage. A checklist is presented of recommended activities that are best performed at the conclusion of an outage.

9.1

Post-Overhaul Engineering Reports

The outage is over, and the unit is back on-line. Now begins the process of accumulating, evaluating, sorting, logging, and reviewing the information compiled during the outage. The documentation of the outage work accomplished is an important element of the total work process. The documentation includes items collected or generated at the following stages of the outage process: 1. The outage process begins with the identification of the work to be performed: •

Operation issues

•

Previous outage recommendations

•

Industry-identified concerns

2. The work is planned: •

Work packages

•

Specifications/procedures

•

Purchase orders

•

Parts

3. A schedule is developed: •

Required activities integrated

•

Resources available

•

Timeframe 9-1


4. The outage occurs: •

Planned activities

•

Unplanned activities

5. Activities are performed and documented: •

Logs

•

Records

•

Measurements

•

Sketches

•

Reports

6. The documentation is used after the outage to analyze and evaluate the outage: •

Record of what occurred

•

Data collected

•

Resources used

•

Sequence of events

•

Calendar of events

•

Duration

•

Activities

•

Parts used

•

Performed as expected

•

Worked/didn’t work

•

Planning for next outage

The last step of an outage six-element life cycle is the evaluation and analysis of the outage through the information accumulated during the outage. To what extent the turbine-generator engineer (or others) evaluates and analyzes the outage determines what post-outage engineering reports are required. Information is accumulated during the outage to document and communicate what was found, what was being done, and what things need to be done in the future. This information may have taken the form of reports, logs, data sheets, updated drawings, etc. This information may have completed its useful purpose and may be left in its original state and stored or archived for historical reference. Or the information may be summarized, condensed, and accumulated with other information into another format or report that is used to evaluate or analyze the outage. Table 9-1 lists typical information resources and contents that would be accumulated during an outage. Matrix arrangement is by typical information sources, and the table identifies expected contents in that source of information. Contents may be grouped or appear in other sources depending on outage support, format, etc. Each source of information should clearly identify unit, outage, component, dates, person, or organization performing the activity. 9-2

Post-Outage Activities Table 9-1 Recommended Information to Be Collected After the Outage Is Complete Information Source

Contents

Technical direction

•

Brief narrative of job, summary of what was done

•

Inspection summary (what was found and disposition)

•

Recommendations

•

Parts used

•

Narrative by component grouping of what was found, what was done, and what was left

•

Component dimensional readings

•

As found

•

As left

•

Component clearance readings and calculations

•

As found

•

As left

•

Alignment and position readings

•

As found

•

As left

•

Test readings

•

Startup

•


•

Condition assessment

•

Measurements

•

Repairs

•

Recommendations

•

Repair duration

•


•

Measurements

•

NDE results

•

Material properties

•

Recommendations

•


•

Inspection findings, condition assessment

•

Efficiency calculations

•

Inspection recommendations

Diaphragm repairs

Boresonic inspection


9-3

Post-Outage Activities Table 9-1 (cont.) Recommended Information to Be Collected After the Outage Is Complete Information Source

Contents

Sealing area inspections

•


•

Inspection findings

•

Efficiency calculations

•

Inspection recommendations

•

Replacements

•

Repairs

•

Measurements

•

Replacement/repair duration

•

Failure mechanism

•

Measurements

•

Chemical analysis

•

Inspection findings

•

Disposition and cleared inspections

•

Equipment used

•

Method(s) used

•

Voltage

•

Current type (ac or dc)

•

Resistance values

•

Dry bulb temperature

•

Wet bulb temperature

•

Relative humidity

•

Component Temperature

•

Test readings

•

Time intervals

•

Comments

•

Orientation

•

Reference location

Bucket repairs

Bearing repairs

NDE Generator Tests

Maps

9-4


The turbine-generator engineer should at least maintain a summary reference engineering report of critical information, inspections, results, and recommendations that have occurred during past outages. As an example, bucket replacements and recommendations should be concisely tracked and displayed by unit, outage, rotor, and location. The advantages of summary concise information are: •

History at a glance

•

Trending

•

Forecasting/planning/outage preparation

Table 9-2 presents examples of several post-outage engineering reports and their contents. Each report contains the required outage identifiers of unit and year. Table 9-2 Examples of Post-Outage Engineering Reporting Engineering Report

Contents

Outage dates

• Outage type, dates and duration

Turbine deck lay-down plan

• Revisions to plan, especially work centers

Diaphragm repairs

• Type of repair by diaphragm

- Major - Minor • Repair hours per diaphragm • Other hours expended • Repair recommendations

Component locations (for spares)

• Component identification • Component serial number • Date installed • Repaired by

Bucket repairs and replacements

• Replacement by stage • Repair by stage • Recommendation by stage

Bearing repairs

• Repairs by location • Type of repair • Reason for repair • Babbitt chemistry • Repair facility

Rotor runouts

• Separate plot for each set of data taken • Runout readings plotted by location

9-5

Post-Outage Activities Table 9-2 (cont.) Examples of Post-Outage Engineering Reporting Engineering Report

Contents

Boresonic inspections

• Rotor location • Rotor serial number • Unit installation • Inspection date • Inspection recommendation interval • Next inspection due

Fasteners

• Stretches • Replacements

Main steam lead flange thickness

• Flange location • Flange readings • Minimum allowable thickness

Piping and uniquely tracked component inspections

• Location • Design information • Inspection dates • Recommended next inspection

Parts used

• Part description • Identification (Stock/part number) • Quantity used

Test results

• Hydrogen consumption • Indices • Comparison plots • Megger readings • Resistance readings • HIPOT pass/fail results

Startup

• Vibration data • Rotor criticals • Shot log • Balance data – sensitivity, high spot, etc. • Overspeed test data

9-6

Post-Outage Activities Table 9-2 (cont.) Examples of Post-Outage Engineering Reporting Engineering Report

Contents

Recommendations

• Component identification • Source of recommendation • Description for recommendation • Recommendation • Action required • Task assignment and completion date • Completion information

Purchase orders

• PO # and description • Vendor • Bid • Final PO amount

Work force

• Estimated hours • Actual hours expended

Budget

• Original amount • Actual spent

9.2

Documentation for Vendor Signoff

The job, project, and service are not only comprised of activities but also the documentation of those activities. The obvious activities that should be contained within the purchasing document are work scope and compliance with specifications. But there are times when a vendor borrows equipment, supplies, or other items from the utility. The purchasing document should clearly outline how borrowed items are accounted for, returned, and billed if necessary. The vendor signoff and final authorization of payment should be hinged with a signoff for return of all borrowed items and accounting for items supplied by the plant outside the scope as outlined within the purchasing document. Often, the only record required for the purchase order activity is the acknowledgement and submission of timesheets or completion signoff. The content of the completion record is often left undescribed and not tied into the purchasing document. Therefore, the historical record or final report of the activities performed may be left blank. The purchase order should not only include all the description and technical specifications to complete the job, but it should also contain the requirements for the final report. The requirements can include format, delivery schedule, and payment retention. Each purchased outage activity should be evaluated according to the need and complexity of the report required. For example, a comprehensive report would be required if technical direction were hired to

9-7


support the outage. Compare this to a machining activity on the turbine where the record of sizes could be contained in the technical direction report. Therefore, three purchasing document items have been described for signoff or authorization of job completion and final payment: •

Timesheets or documentation of work completed

•

Documentation of return of borrowed items

•

Acceptance of final report

9.3

Issues to Review for Future Planning

Each outage should be entered with a plan to obtain some additional information about the turbine-generator. The more information known about the turbine-generator components, the more information can be used in the planning process. Knowing part and machine internal information can help in planning for part/component replacements and future modifications prior to the next outage. Therefore, obtaining information about the machine can help in planning for the upcoming outage and can be used in conjunction with outage reports that provide information concerning what went on during the outage and recommendations for the future. Table 9-3 presents a listing of information that can be obtained during an outage and some possible uses for this information with regard to preparing for the next outage. Table 9-3 Uses for Engineering Information Obtained in the Outage Component Diaphragm

Steam path

Information

Use

Number of partitions

Contour gauge prefabrication

Partition shape Radial height Pitches Throats

Partition coupon prefabrication Repair specification preparation

Outer and inner sidewall Body

Weight

Machining information

Outside diameter

Seal face inserts

Packing bore

Coating information (diaphragm size being worked with)

Set back Seal face Ring thickness Appendage Total width Hook fits

9-8

Dimensions

Repairs

Post-Outage Activities Table 9-3 (cont.) Uses for Engineering Information Obtained in the Outage Component Rotor

Coupling

Information

Use

Number of holes

Bolt replacement

Bore diameter

Coupling bolt hold machining

Counter bore diameter and length OD Rabbet dimensions Journal

Diameter

Machining

Required length Packing

Seal configuration

Machining

Dovetails

Geometry

Machining

Buckets

Number per row

Replacements

Type of closure

Machining

Tip diameter Vane root diameter Vane width Radial seal platform diameter Axial seal Cross key diameter Vane geometry Covers

Grouping

Repairs

Width

Material

Thickness Diameter Fox holing Bore

Length

Inspection

Diameter

Machining

Transition Shells

Fits

Packing head or casing

Position

Machining

Width

Diaphragm seal face inserts

Dimensions

Repairs

9-9

Post-Outage Activities Table 9-3 (cont.) Uses for Engineering Information Obtained in the Outage Component Standard

Bearings

Information

Use

Size

Repairs

Length Type Oil deflectors

Number of teeth

Repairs

Tooth material ID Number of teeth per deflector Parts

Quantities

Replacements

Confirmation Changes Redesign Part number Pictures

Horizontal joints

Component orientation

Diaphragms Rotors Buckets Assembly Field

Coupling

Number of holes

Bolt replacement

Bore diameter

Coupling bolt hole machining

Counter bore diameter and length OD Rabbet dimensions Journal

Diameter

Machining

Required length Hydrogen seals

Rotor diameter

Replacement parts

Windings

Dimensions

Replacement parts

Wedges

Dimensions

Replacement parts

Collector rings

Diameter

Repair Replacements

Bore

Length

Inspection

Diameter

Machining

Transition

9-10


9.4

Recommendations for Planning Future Outages

Any recommendations for action to be taken during future outages should address the following issues: 1. Condition assessment of the component 2. Basis for the recommendation 3. Expected action a. Replacements b. Repairs 4. Utility history or experience 5. Industry trends The EPRI-developed Turbo-X computer program, Product Number 1001074, can aid personnel in the electric power industry by providing a decision analysis tool that combines engineering, economic, and risk analysis methods to optimize turbine-generator maintenance and inspection activities. The joint Program 65/NSTI Guide on Steam Turbine Generator Upgrade/Lessons Learned, 1011678, [62] was produced in 2005 as a web-based information repository. Information contained in this database was collected during 2005 from a series of plant visits/interviews and technical advisory group meetings, and focuses on lessons learned while performing steam turbine upgrades and the process for planning and executing steam turbine upgrades. This is a living database that allows members to contribute additional information following its release. Identification of the location of concern and priority of response are also critical information that should be included in a recommendation. Section 9.4.1 is an example of a detailed description of a problem, and the corresponding solution is in Section 9.4.2. 9.4.1 Problem Description The thrust bearing assembly was fully disassembled, inspected, and cleaned. The ball was blue contact checked, with 80% on the lower half and about the same on the upper half. The pinch check indicated 2 mils pinch (0.0508 mm) with a 3 mil (0.0762 mm) shim installed in the ring joint to produce the desired 1–2 mils (0.0254-0.0508 mm) loose. The torque check of the ball with the 3 mil (0.0762 mm) shim in the ring joint was 1800 ft/lb (2440 N•m). Note: The 3 mil (0.0762 mm) shim has been used on the horizontal joint, one on each side of the ring joint for several years to compensate for the tight pinch of the ball. The active generator end thrust plate was found with babbitt disbonding. The plate was replaced with a new one from plant stores. To use the new plate, the thermocouple holes were drilled and matched from the old plate to the new. Since the new plate was thicker than the old plate, the steel shim was ground down to obtain the design bearing oil clearance. 9-11


9.4.2 Solution Order a new spare generator end thrust plate for a spare for the upcoming unit major inspection to replace the spare generator end plate that was used this outage. With the bearing problems that have been present for some time in this station from static electrical charges in the LP sections, which are continually damaging bearings, it is advisable to have both a spare turbine and a generator end thrust plate on hand for the upcoming unit major inspection.

9.5

Inventory Decision Making

The following is a listing of information that is helpful when reviewing whether a part should be stocked: •

All locations where the part is used

•

Historical quantity actually used per year

•

Lead time

•

–

Off the shelf

–

Just in time

–

Long lead time

–

Purchase before outage, for outage [direct purchase, outage consumable]

Internal response time –

Identification of need

–

Purchasing

–

Tracking

–

Receiving

–

Delivery

•

Shelf life

•

Impact on outage

•

Use

•

•

–

Outage

–

Non-outage

Cost –

Item cost

–

Shipping cost [expedited, non-expedited]

Feedback

9-12


The data to be reviewed are primarily for the components either stocked or to be removed from stock in the utility warehouse. That information should be part of a master turbine-generator parts database. All parts identified associated with the turbine-generator and auxiliary equipment should be included in the master parts database. A unique identifier within the database identifies those parts that are part of warehouse stock. The review begins with the items currently stocked. The sequence of review can begin with: •

Items that have not been used in “x” number of years

•

Sequentially looking at each stocked item

•

Parts associated with a specific piece of equipment

•

Other systematic approaches

It is easiest to review all the pertinent data at one time. Spreadsheets and other forms of listed data may be helpful, but they may also not provide enough of the right information in the right location at the right time. Database forms can link information from various database tables and provide the critical part review information in one location. They can also provide quick links to additional part user and supplier information. The obvious advantage of stocking reviews is the potential reduction in inventory cost because parts are removed from stock that are infrequently used or no longer used. The potential down side of removing parts from stock is not having them when needed. The review process has to be accurate and flexible, parts may be: •

Removed

•

Increased in quantity

•

Decreased in quantity

•

Added

9.6

Integration with Maintenance Management Systems

The maintenance management system (MMS) used to support the outage should have contained at least the following information: •

Unique activity identifier

•

Equipment and component activity assigned to

•

Task description

•

Resources to complete task –

Number

–

Duration

9-13


•

Sequence –

Predecessor

–

Successor

–

Priority

–

Start/end dates

A comprehensive MMS would also include part information (BOMs) and provide cost information into a financial system. The post-outage review should include a discussion of: •

Pre-outage

•

Shutdown

•

Disassembly

•

Planned work

•

Inspections and unplanned work

•

Reassembly

•

Startup

Included in that discussion should be the topics of: •

What worked?

•

What did not work?

•

What hour estimates were off and why?

The post-outage activity should include a focused review of the tasks performed during the outage. Note that not all tasks require review. The review parameters may be set to include a review of only specific tasks that missed the planning estimate by a fixed percentage. The MMS plans would be revised from the inputs received during the post-outage review. The possible revisions to the MMS plan would include: •

Resource estimates

•

Task sequencing and scheduling

•

Task descriptions

Outage recommendations can also be reviewed and entered into the MMS system to support the standard outage plan or to create individual one-time-only activities. U.S. nuclear plants are implementing preventive maintenance (PM) tasks with little documented basis to support the tasks and their intervals. The EPRI report Preventive Maintenance Basis 9-14


Database Client Server, Version 6.0, 1009584, [53] provides utilities with PM information for a number of components. Tasks within the guide are divided according to three categories: •

Condition monitoring - to measure the progression toward failure so that the corrective action can be planned or indicated

•

Time-directed - to prevent failure by performing scheduled maintenance

•

Failure finding - to identify a failed condition so that corrective maintenance can be initiated

9-15

10

REFERENCES 1. Turbine Steam Path Damage: Theory and Practice. EPRI, Palo Alto, CA: 1999. TR-108943-V1 and V2. 2. EHC Tubing/Fittings and Air Piping Applications and Maintenance Guide. EPRI, Palo Alto, CA: 2000. 1000935. 3. Electrohydraulic Control (EHC) Fluid Maintenance Guide. EPRI, Palo Alto, CA: 2002. 100554. 4. General Electric Electrohydraulic Controls (EHC) Electronics Maintenance Guide. EPRI, Palo Alto, CA: 1997. TR-108146. 5. Steam Turbine Hydraulic Control System Maintenance Guide. EPRI, Palo Alto, CA: 1996. TR-107069. 6. Crane Maintenance and Application Guide: Maintenance and Application of Overhead Cranes. EPRI, Palo Alto, CA: 2000. 1000986. 7. Compressed Air System Maintenance Guide. EPRI, Palo Alto, CA: 2002. 1006677. 8. Foreign Materials Exclusion Guidelines, Revision 1. EPRI, Palo Alto, CA: 2005. 1009709. 9. K. C. Cotton. Evaluating and Improving Steam Turbine Performance, 2nd Edition. Cotton Fact, Inc., Rexford, NY, 1998. 10. Infrared Thermography Guide, Revision 3. EPRI, Palo Alto, CA: 2002. 1006534. 11. System and Equipment Troubleshooting Guideline. EPRI, Palo Alto, CA: 2002. 1003093. 12. Feedwater Pump Turbine Controls and Oil System Maintenance Guide. EPRI, Palo Alto, CA: 2001. 1003094. 13. Guidelines for Using Synthetic Slings for Lifting and Rigging. EPRI, Palo Alto, CA: 2003. 1007676. 14. Machinery’s Handbook, 26th Print Edition, “Fasteners,” Table 2: Accuracy Bolt Preload Application Methods. Industrial Press, 2000. 15. Guidelines for Reducing the Time and Cost of Turbine-Generator Maintenance Overhauls and Inspections: Volume 3, Balancing and Alignment. EPRI, Palo Alto, CA: 2003. 1008856. 16. Guidelines for Reducing the Time and Cost of Turbine-Generator Maintenance Overhauls and Inspections: Volume 3, TGAlign Computer Program Version 2.0 User’s Manual (English Units Version). EPRI, Palo Alto, CA: 2003. 1008827. 17. Guidelines for Reducing the Time and Cost of Turbine-Generator Maintenance Overhauls and Inspections: Volume 3, TGAlign Computer Program Version 1.0 User’s Manual (SI Units Version). EPRI, Palo Alto, CA: 2002. 1007537. 10-1

References

18. Demonstration of a Videoprobe Delivery Device for In Situ Inspection of Steam Turbine and Combustion Turbine Machines. EPRI, Palo Alto, CA: 2002. 1004002. 19. Interim Guidelines for In Situ Visual Inspection of Inlet and Outlet Turbine Stages: Part 2: Experiences, Approaches, and Improvements in Remote Visual Inspection. EPRI, Palo Alto, CA: 2000. TR-114961. 20. Guidelines for Reducing the Time and Cost of Turbine-Generator Maintenance Overhauls and Inspections: Volume 6, High-Pressure/Intermediate-Pressure Blade/Disk Design Audit and Inspection Procedures. EPRI, Palo Alto, CA: 2001. 1006087. 21. Guidelines for Reducing the Time and Cost of Turbine-Generator Maintenance Overhauls and Inspections: Volume 7, Low-Pressure Blade/Disk Design Audit and Inspection Procedures. EPRI, Palo Alto, CA: 2001. 1006088. 22. NDE Guidelines for Fossil Power Plants. EPRI, Palo Alto, CA: 1997. TR-108450. 23. Remote NDE Technology for Steam Turbines. EPRI, Palo Alto, CA: 2002. 1006814. 24. Rotor Boresonic Inspection Guidelines. EPRI, Palo Alto, CA: 1990. NP-6742-L. 25. NEI Parsons Ltd. Boresonic Inspection System Evaluation. EPRI, Palo Alto, CA: 1993. TR102126. 26. Northeast Inspection Services, Inc. Boresonic Inspection System Evaluation. EPRI, Palo Alto, CA: 1993. TR-102256. 27. WesDyne International UDRPS Boresonic Inspection System Evaluation. EPRI, Palo Alto, CA: 1996. TR-106234. 28. General Electric Company Boresonic Inspection System Evaluation. EPRI, Palo Alto, CA: 1997. TR-107174. 29. Reinhart & Associates, Inc. Boresonic Inspection System Evaluation. EPRI, Palo Alto, CA: 1997. TR-108423. 30. Boresonic System Performance Guide. EPRI, Palo Alto, CA: 1994. TR-104355. 31. Guide for In-Service Ultrasonic Inspection of Boreless Turbine Rotors and Other Solid Shafts. EPRI, Palo Alto, CA: 1992. TR-101836. 32. Inspection of Turbine Disk Blade Attachment Guide: Volume 1, Background and Inspection Principles. EPRI, Palo Alto, CA: 1994. TR-104026-V1. 33. Steam Turbine Disk Blade Attachment Inspection Using Linear Phased Array Ultrasonic Technology. EPRI, Palo Alto, CA: 2000. 1000122. 34. Field Application for Ultrasonic Linear Phased Array Inspection of Straddle-Mount and Axial-Entry Disk Blade Attachments. EPRI, Palo Alto, CA: 2000. 1000663. 35. Evaluation of Nonmagnetic Generator Retaining Rings. EPRI, Palo Alto, CA: 1994. TR104209. 36. “Reducing Solid Particle Erosion Damage in Large Steam Turbines,” GER-3478A, presented by W.J. Sumner, et al. at the 1985 American Power Conference.

10-2

References

37. Guide for On-Line Testing and Monitoring of Turbine Generators. EPRI, Palo Alto, CA: 2002. 1006861. 38. Testing of Stator Windings for Thermal Aging: Interim Results. EPRI, Palo Alto, CA: 2002. 1004557. 39. Assessment of Partial Discharge and Electromagnetic Interference On-Line Testing of Turbine Driven Generator Stator Winding Insulation Systems. EPRI, Palo Alto, CA: 2003. 1007742. 40. Conversion to Deaerated Stator Cooling Water in Generators Previously Cooled w/ Aerated Water: Interim Guidelines. EPRI, Palo Alto, CA: 2000. 1000069. 41. Guidelines for Detecting and Removing Flow Restrictions for Water-Cooled Stator Windings. EPRI, Palo Alto, CA: 2002. 1004704. 42. Generator Cooling System Operating Guidelines: Cooling System Maintenance and Performance Guidelines During Start-Up, Operation, and Shutdown. EPRI, Palo Alto, CA: 2002. 1004004. 43. Experience with Limited Access Generator Inspections: A Study of Inspections Done with Robotic Equipment and their Effectiveness as Compared with Conventional Inspections Where the Generator Rotor Is Removed. EPRI, Palo Alto, CA: 2000. 1000100. 44. On-Line Detection of Shorts in Generator Field Windings. EPRI, Palo Alto, CA: 1999. TR114016. 45. Tools to Optimize Maintenance of Generator Excitation System, Voltage Regulator, and Field Ground Protection. EPRI, Palo Alto, CA: 2002. 1004556. 46. Power Plant Electrical Reference Series: Volume 1, Electrical Generators. EPRI, Palo Alto, CA: 1987. EL-5036-V1. 47. “Military Standard System Safety Program Requirements,” Department of Defense, January 1993. MIL-STD-882C. 48. ORBIT, March 1993, Vol. 14, No.1, p. 9. 49. D.P. Timo, “General Electric Nuclear SCC Experience,” EPRI Seminar on Steam Turbine Disk Integrity, San Antonio, Texas, December 1983. 50. Steam Turbine Disk Brittle Failure: Influencing Parameters and Probabilistic Analysis Demonstration. EPRI, Palo Alto, CA: 2002. 1003264. 51. “Aerospace Recommended Practice,” Society of Automotive Engineers, ARP-598A. 52. Shaft Alignment Guide. EPRI, Palo Alto, CA: 1999. TR-112449. 53. Preventive Maintenance Basis. EPRI, Palo Alto, CA: 1998. TR-106857. 54. SAFER-PC Release 2.2. EPRI, Palo Alto, CA: 2006. 1013044. 55. Ultrasonic Inspection of Steam Turbine Blade Roots. EPRI, Palo Alto, CA: 2005. 1011680. 56. Axial Entry Blade Attachment NDE Performance Demonstration. EPRI, Palo Alto, CA: 2005. 1011677.

10-3

References

57. Evaluation of Replacement Interstage Seals for Turbine Upgrades. EPRI, Palo Alto, CA: 2005. 1010214. 58. Evaluation Tool for Cost Effective Steampath Upgrades. EPRI, Palo Alto, CA: 2006. 1004565. 59. Condition Assessment Technology for Steam Valves. EPRI, Palo Alto, CA: 2005. 1010211. 60. Excitation System Retrofit and Replacement-Lessons Learned. EPRI, Palo Alto, CA: 2006. 1011675. 61. Generator Rotor Shaft Cracking Management Guide. EPRI, Palo Alto, CA: 2005. 1011679. 62. Guide on Steam Turbine Generator Upgrade/Lessons Learned. EPRI, Palo Alto, CA: 2005. 1011678.

10-4

A

CONDITION ASSESSMENT DATA SHEETS

Presented in this appendix are 17 data sheet sets referenced in the discussion of an in-service condition assessment of a steam turbine-generator unit. Generally, each of the sets consists of three parts. The first provides a summary of available data collected from the system as a whole or from individual sections. The second sheet supplements the first by means of an interview with the specialist, engineer, or operator directly responsible for maintaining and monitoring the system. The third sheet summarizes an assessment of the present condition of system based on the information obtained from the data audit and the interview. Data Sheet #1 provides an overall review and assessment of the maintenance history for the unit. Data Sheets #2 through #14 repeat the data audit, interview, and condition assessment process for each of the major systems found in the turbine-generator unit: •

Turbine generation vibration

•

Bearing metal and oil temperatures

•

Section performance parameters

•

Start-up operation

•

Steam purity

•

Lubricating oil and EHC analysis

•

Pump start test results

•

Valve tightness test results

•

Turbine trips

•

Turbine monitoring instrumentation

•

Auxiliary system operation

•

Visual inspection

•

Generator-exciter condition

Data Sheet #15 is a checklist of 69 “out-of-limit” indicators to highlight potential problems or issues. Data Sheet #16 is a summary of the long-range maintenance plans for the individual systems, sections, and components included within the individual audits. Data Sheet # 17 is the summary of the information obtained and reviewed in the preceding series of documents. It provides a one-page synopsis that lists the components/systems and ranks their present condition. A-1

Condition Assessment Data Sheets

Table of Data Sheets Data Sheet #1: (a) Maintenance History Summary (Page 1 of 4) ................................................4 Data Sheet #1: (b) Modifications and Upgrades (Page 2 of 4).....................................................5 Data Sheet #1: (c) Forced Outage Issues and Root Causes (Page 3 of 4)..................................6 Data Sheet #1: (d) Potential Risk for Component Failure (Page 4 of 4).......................................7 Data Sheet #2: (a) Turbine-Generator Vibration Audit (Page 1 of 3) ...........................................8 Data Sheet #2: (b) Turbine-Generator Vibration Interview (Page 2 of 3) .....................................9 Data Sheet #2: (c) Turbine-Generator Vibration Assessment (Page 3 of 3) ..............................10 Data Sheet #3: (a) Bearing Metal and Oil Temperature Audit (Page 1 of 3) ..............................11 Data Sheet #3: (b) Bearing Metal and Oil Temperature Interview (Page 2 of 3) ........................12 Data Sheet #3: (c) Bearing Metal and Oil Temperature Assessment (Page 3 of 3) ...................13 Data Sheet #4: (a) Performance Information Audit (Page 1 of 3) ..............................................14 Data Sheet #4: (b) Performance Information Interview (Page 2 of 3) ........................................15 Data Sheet #4: (c) Performance Information Assessment (Page 3 of 3)....................................16 Data Sheet #5: (a) Start-Up Operation Audit (Page 1 of 3)........................................................17 Data Sheet #5: (b) Start-Up Operation Interview (Page 2 of 3)..................................................18 Data Sheet #5: (c) Start-Up Operation Condition Assessment (Page 3 of 3).............................19 Data Sheet #6: (a) Steam/Water Purity Monitoring (Fossil) Audit (Page 1 of 3).........................20 Data Sheet #6: (b) Steam Purity Monitoring Interview (Page 2 of 3)..........................................21 Data Sheet #6: (c) Steam Purity Monitoring Condition Assessment (Page 3 of 3).....................22 Data Sheet #7: (a) Lube Oil and EHC Analysis Audit (Page 1 of 3)...........................................23 Data Sheet #7: (b) Lube Oil and EHC Analysis Interview (Page 2 of 3).....................................25 Data Sheet #7: (c) Lube Oil and EHC Condition Assessment (Page 3 of 3) ..............................26 Data Sheet #8: (a) Pump Start Test Results Audit (Page 1 of 3) ...............................................27 Data Sheet #8: (b) Pump Start Interview (Page 2 of 3)..............................................................28 Data Sheet #8: (c) Pump Condition Assessment (Page 3 of 3) .................................................29 Data Sheet #9: (a) Valve Tightness and Test Results Audit (Page 1 of 3).................................30 Data Sheet #9: (b) Valve Tightness and Test Results Audit (Page 2 of 3).................................31 Data Sheet #9: (c) Valve Tightness Condition Assessment (Page 3 of 3) .................................32 Data Sheet #10: (a) Turbine Trip Test Results Audit (Page 1 of 3)............................................33 Data Sheet #10: (b) Turbine Trip Interview (Page 2 of 3) ..........................................................34 Data Sheet #10: (c) Turbine Trip Interview (Page 3 of 3) ..........................................................35 Data Sheet #11: (a) Turbine Instrumentation Survey Results Audit (Page 1 of 4) .....................36 Data Sheet #11: (b) Turbine Instrumentation Survey Interview (Page 3 of 4) ............................38 Data Sheet #11: (c) Turbine Instrumentation Condition Assessment (Page 4 of 4) ...................39 Data Sheet #12: (a) Generator-Exciter Inspection Audit (Page 1 of 3) ......................................40 Data Sheet #12: (b) Generator-Exciter Inspection Interview (Page 2 of 3) ................................41 Data Sheet #12: (c) Generator-Exciter Condition Assessment (Page 3 of 3).............................42

A-2


Data Sheet #13: (a) Auxiliary System Operating Information Audit (Page 1 of 3) ......................43 Data Sheet #13: (b) Auxiliary System Information Interview (Page 2 of 3).................................44 Data Sheet #13: (c) Auxiliary System Condition Assessment (Page 3 of 3) ..............................45 Data Sheet #14: (a) Visual Inspection Audit (Page 1 of 3).........................................................46 Data Sheet #14: (b) Visual Inspection Interview (Page 2 of 3)...................................................47 Data Sheet #14: (c) Visual Inspection Condition Assessment (Page 3 of 3)..............................48 Data Sheet #15: (a) Checklist of Out-of-Limit Events and Conditions (Page 1 of 4) ..................49 Data Sheet #15: (a) Checklist of Out-of-Limit Events and Conditions (Page 2 of 4) ..................50 Data Sheet #15: (a) Checklist of Out-of-Limit Events and Conditions (Page 3 of 4) ..................51 Data Sheet #15: (a) Checklist of Out-of-Limit Events-Conditions (Page 4 of 4) .........................52 Data Sheet #15: (b) Condition Assessment for Out-of-Limit Events (Page 1 of 1) .....................53 Data Sheet #16: (a) Current Long-Range Maintenance Plan for Unit (Page 1 of 3)...................54 Data Sheet #16: (b) Current Long-Range Maintenance Plan for Unit (Page 2 of 3)...................55 Data Sheet #16: (c) Current Long-Range Maintenance Plan for Unit (Page 3 of 3)...................56 Data Sheet #17: (a) Overall Unit Condition Assessment Form ..................................................57

A-3

Condition Assessment Data Sheets Data Sheet #1: (a) Maintenance History Summary (Page 1 of 4) Plant and Unit Number: Unit OEM: Design Rating: (MW)

Commercial Operation Date:

Unit MDC: (MW)

Date Last Inspected: MAINTENANCE HISTORY SUMMARY

Date

Component Inspected

Recommendations

Chronic Problems Yes

A-4

No

Condition Assessment Data Sheets Data Sheet #1: (b) Modifications and Upgrades (Page 2 of 4) Plant and Unit Number: Unit OEM: Design Rating: (MW)


Unit MDC: (MW)

Date Last Inspected:

MODIFICATIONS AND UPGRADES MADE TO IMPROVE PERFORMANCE OR RELIABILITY Date

Type of Upgrade (Describe)

Performance or Reliability Improvement (Identify Which)

A-5

Condition Assessment Data Sheets Data Sheet #1: (c) Forced Outage Issues and Root Causes (Page 3 of 4) Plant and Unit Number: Unit OEM: Design Rating: (MW)


Unit MDC: (MW)

Date Last Inspected: SIGNIFICANT FORCED OUTAGE ISSUES AND ROOT CAUSES

Date of Forced Outage

A-6

Part/Component Involved

Summary of Root Cause Responsible for Outage

Condition Assessment Data Sheets Data Sheet #1: (d) Potential Risk for Component Failure (Page 4 of 4) Plant and Unit Number: Unit OEM:

Date:

Design Rating: (MW)


Unit MDC: (MW)


COMPONENTS HAVING HIGH RISK OF FAILURE PRIOR TO NEXT OUTAGE Potential Risk of Failure Based on Past Maintenance History Component High

Medium

Low

A-7

Condition Assessment Data Sheets Data Sheet #2: (a) Turbine-Generator Vibration Audit (Page 1 of 3) Plant and Unit Number: Unit OEM:

Date of Audit:

Design Rating: (MW)


Unit MDC: (MW)

Date of Last Inspection TURBINE-GENERATOR VIBRATION AUDIT

Phase

Phase

2 Critical Vibration Amplitude

nd

1 Critical Vibration Amplitude

Frequency of Vibration

Amplitude

Y

Phase

Amplitude

Frequency of Vibration

X

Phase

Amplitude

Y

Phase

Location of Pickup

Amplitude

X

st

Full Load Vibration

Phase

Minimum Load Vibration

Notes: At minimum load and at full load, a frequency scan from 1x through 10x speed range should be recorded and attached to this sheet. Bode plots should be run if instrumentation is available. These aid in accurately locating the critical speed amplitudes and phase angles. Attach to this sheet a copy of roll-up and roll-down vibration if available.

A-8

Condition Assessment Data Sheets Data Sheet #2: (b) Turbine-Generator Vibration Interview (Page 2 of 3) Plant and Unit Number: Unit OEM:

Date of Interview:

Design Rating: (MW)


Unit MDC: (MW)

Commercial Operation Date: TURBINE-GENERATOR VIBRATION - OPERATOR INTERVIEW

No. 1

Does the turbine-generator frequently run in alarm? If so, which bearing?

No. 2

Does the turbine/generator or exciter have high vibration alarms during roll-up, roll-down or at minimum or full load? At what bearings do these alarms occur, and what speed does it occur?

No. 3

Has the unit experienced many vibration trips since the last overhaul? If so, how many? What bearing caused the trip, and how high was the vibration during the subsequent roll down?

No. 4

Was there suspected damage due to high vibration during roll down to turning gear? Where do you think the damage occurred?

No. 5

Have there been any step changes in vibration at any bearing? If so, what was the amplitude change that occurred?

No. 6

Have any operation changes (vibration, pressure, temperature, steam flow, efficiency, etc.) occurred since the high vibration event?

No. 7

What do you think the risk is (High, Medium, Low) for a failure given the above suspected damage?

No. 8

What are the vibration alarm and trip values for this unit? Are they based on filter-out or filter-in vibration?

A-9

Condition Assessment Data Sheets Data Sheet #2: (c) Turbine-Generator Vibration Assessment (Page 3 of 3) Plant and Unit Number: Unit OEM:

Date of Assessment:

Design Rating: (MW)


Unit MDC: (MW)


ASSESSMENT OF CURRENT TURBINE-GENERATOR VIBRATION CONDITION (BASED ON DATA AND INTERVIEWS)

Long Term

Immediate

Low

Moderate

Consequence If Condition Is Allowed to Continue As Is High

Potential Issues or Problems with Present Condition

Intermediate

Need for Action

Risk of Failure

Recommended Actions or Contingencies That Might Be Taken to Further Verify or Correct Potential Problem

FAILURE: Breakdown of the component or system to the point where it would force an outage. RISK: How certain do you feel that this may be a problem? ACTION: Immediate: Hours or days

A-10

Intermediate: 3–12 months

Long Term: Next outage

Condition Assessment Data Sheets Data Sheet #3: (a) Bearing Metal and Oil Temperature Audit (Page 1 of 3) Plant and Unit Number: Unit OEM:

Date of Audit:

Design Rating: (MW)


Unit MDC: (MW)

Date Last Inspected: BEARING METAL AND BEARING OIL TEMPERATURE AUDIT

Bearing Number

Bearing Metal At Maximum Load

At Minimum Load

Oil Temperatures At Maximum Load Oil Inlet

Oil Outlet

At Minimum Load Oil Inlet

Comments

Oil Outlet

A-11

Condition Assessment Data Sheets Data Sheet #3: (b) Bearing Metal and Oil Temperature Interview (Page 2 of 3) Plant and Unit Number: Unit OEM:

Date of Interview:

Design Rating: (MW)


Unit MDC: (MW)


BEARING METAL AND OIL TEMPERATURE CONDITION OPERATOR INTERVIEW No. 1

Have any bearings exceeded 220ºF (104ºC)? If so, did any other bearing metal temperatures rise after this occurred? (Identify bearing no. ___: from ___ degrees to ____degrees.)

No. 2

Did unit vibration increase after the above temperature spike occurred? If so, at what bearing and what was the vibration amplitude? (Identify bearing no. ____; Amplitude ______.)

No. 3

During the roll to speed or during a shutdown, has bearing vibration increased since the above event? If so, at what bearing? What is the new vibration during the roll down or roll to speed? (Identify bearing no. ___; New vibration _________.)

No. 4

Has anything other than the above occurred that you would consider being abnormal? (Identify.)

A-12

Condition Assessment Data Sheets Data Sheet #3: (c) Bearing Metal and Oil Temperature Assessment (Page 3 of 3) Plant and Unit Number: Unit OEM:

Date of Assessment:

Design Rating: (MW)


Unit MDC: (MW)


ASSESSMENT OF CURRENT BEARING CONDITION (BASED ON DATA AND INTERVIEWS)

Long Term

Immediate

Low

Moderate



Intermediate

Need for Action

Risk of Failure

Recommended Actions or Contingencies That Might Be Taken to Further Verify or Correct Potential Problem




A-13

Condition Assessment Data Sheets Data Sheet #4: (a) Performance Information Audit (Page 1 of 3) Plant and Unit Number: Unit OEM:

Date of Assessment:

Design Rating: (MW)


Unit MDC: (MW)


PERFORMANCE INFORMATION AUDIT (AT FULL LOAD – VALVES WIDE OPEN) Performance Parameter

Main steam flow - lbs/hr Throttle pressure - psia Throttle temperature - ºF First stage pressure - psia First stage temperature - ºF HP exhaust pressure - psia HP exhaust temp - ºF IP inlet pressure – psia IP inlet temperature - ºF LPA inlet pressure - psia LPA inlet temp - ºF LPA backpressure – in. Hg LPB inlet pressure - psia LPB inlet temp - ºF LPB backpressure – in. Hg LPC inlet pressure – psia LPC inlet temp - ºF LPC backpressure – in. Hg HP efficiency IP efficiency LPA efficiency LPB efficiency LPC efficiency HP throttle flow factor IP throttle flow factor LPA throttle flow factor LPB throttle flow factor LPC throttle flow factor

A-14

Measured Value

Measured Value (Last Assessment)

Deviation

Comments

Condition Assessment Data Sheets Data Sheet #4: (b) Performance Information Interview (Page 2 of 3) Plant and Unit Number: Unit OEM:

Date of Interview:

Design Rating: (MW)


Unit MDC: (MW)

Commercial Operation Date: PERFORMANCE SPECIALIST/ENGINEER INTERVIEW

No. 1

Has there been any significant change in section efficiencies since the last turbine overhaul or last condition evaluation of the unit? In what section did it occur and when?

No. 2

Regarding the following performance parameters, determine what changes have occurred since the last inspection or CA interview: (Note timing that should be identified as either Abrupt or Gradual.) PARAMETER

FROM

TO

% CHANGE

TIMING

(a) Steam flow (b) Throttle pressure (c) First stage pressure (d) Hot reheat pressure (e) LP inlet pressure (f) HP efficiency (g) IP efficiency No. 3

Did any of the above changes occur after any significant operating event on the unit? (Significant events in this case can be a sudden change in turbine vibration while at load, a full load trip, a high vibration during roll up or roll down, or a significant boiler/reactor water or steam chemistry upset.)

No. 4

Did any of the above changes occur after the feedwater heater level control problems, sudden opening of attemperator sprays, or other issues where the rotor and casing could have been thermally quenched?

A-15

Condition Assessment Data Sheets Data Sheet #4: (c) Performance Information Assessment (Page 3 of 3) Plant and Unit Number: Unit OEM:

Date of Assessment:

Design Rating: (MW)


Unit MDC: (MW)


ASSESSMENT OF CURRENT PERFORMANCE CONDITION (BASED ON DATA AND INTERVIEWS)

Long Term

Immediate

Low

Moderate



Intermediate

Need for Action

Risk of Failure

Recommended Actions or Contingencies That Might Be Taken to Further Verify or Correct Potential Problems


A-16



Condition Assessment Data Sheets Data Sheet #5: (a) Start-Up Operation Audit (Page 1 of 3) Plant and Unit Number: Unit OEM:

Date of Audit:

Design Rating: (MW)


Unit MDC: (MW)

Commercial Operation Date: Check Which Applies to Unit

Type of Operation

Base Load – 80% or Higher

Cycling

Frequent Start/Stop

SUMMARY OF START-STOP OPERATING HISTORY Type of Start

HP

IP

LPA

LPB

LPC

GEN

EXC

No. of cold starts No. of hot starts No. of warm starts Since Last Inspection

No. service hours Run to speed w/o synchronizing No. trips at 75% load or higher No. trips at 75% load or lower No. of cold starts No. of hot starts No. of warm starts

Since Commercial Operation

No. service hours No. trips at 75% load or higher No. trips at 75% load or lower Run to speed w/o synchronizing

A-17

Condition Assessment Data Sheets Data Sheet #5: (b) Start-Up Operation Interview (Page 2 of 3) Plant and Unit Number: Unit OEM:

Date of Interview:

Design Rating: (MW)


Unit MDC: (MW)

Date Last Inspected: START-UP OPERATION INTERVIEW (ABNORMAL EVENTS)

No. 1

Has the unit experienced situations where it operated outside the frequency range recommended by the OEM? How many times did this occur? For how many total hours has this occurred for this unit?

No. 2

Has the unit had problems with synchronizing out of phase with the grid? If so, how many times has this occurred? Do you recollect approximately how many degrees out of phase these were on average?

No. 3

Has the unit operated for any significant time at 5 inches Hg backpressure or higher? For how many hours did this occur since the last overhaul?

No. 4

Have there been any line switching events on the system that caused changes in normal operating parameters such as vibration? How many times has this occurred? What was the extent of the vibration change?

No. 5

Has the machine run for any significant time where three phase line voltage differences exceeded OEM recommendations? How many times did this happen? What was the estimated cumulative total time in hours?

No. 6

Has the unit operated where generator dew point exceeded OEM recommendations? For how many hours?

No. 7

Since the last overhaul, has the unit experienced water induction or similar events causing high vibration on the unit? How many times did this occur? How high was the vibration?

No. 8

Have there been any other abnormal operating events on the unit that affected performance or the method in which the unit is operated? Please explain?

A-18

Condition Assessment Data Sheets Data Sheet #5: (c) Start-Up Operation Condition Assessment (Page 3 of 3) Plant and Unit Number: Unit OEM:

Date of Assessment:

Design Rating: (MW)


Unit MDC: (MW)


ASSESSMENT OF CURRENT PERFORMANCE CONDITION (BASED ON DATA AND INTERVIEWS)

Long Term

Immediate

Low

Moderate

Consequence If Condition Allowed to Continue As Is High


Intermediate

Need for Action

Risk of Failure





A-19

Condition Assessment Data Sheets Data Sheet #6: (a) Steam/Water Purity Monitoring (Fossil) Audit (Page 1 of 3) Plant and Unit Number: Unit OEM:

Date of Audit:

Design Rating: (MW)


Unit MDC: (MW)

Commercial Operation Date: Check Which Applies to Unit

Type of water treatment

EPT - Equilibrium phosphate treatment

CT - Caustic treatment

PT - Phosphate treatment

OT - Oxygenated treatment

AVT - All volatile treatment SUMMARY OF STEAM/WATER PURITY MONITORING HISTORY Specify Frequency of Each Test at the Following Locations: C = continuous, O = on-line, G = grab sample daily, W = grab sample weekly Polisher Outlet or Economizer Inlet

Test Type

Main Steam or Reheat Steam

Condensate Pump Discharge

Other: (Blow Down, Treated Makeup)

Specific conductivity Cation conductivity Sodium Chlorides Silica pH Parameter Monitored

Typical Steam Limits in Fossil Plants EPT, AVT, OT

PT

Plant Criteria

CT

Sodium - Na

3 ppb

5 ppb

2 ppb

Chlorine - Cl

3 ppb

3 ppb

2 ppb

Sulfate (SO4)

3 ppb

3 ppb

2 ppb

Cation conduct.

< 0.15

< 0.3

< 0.3

Silica - SiO2

10 ppb

10 ppb

10 ppb

Total organic carbon - TOC

100 ppb

100 ppb

100 ppb

Feedwater chemistry limits

AVT (mixed metallurgy)

AVT (all ferrous)

Oxygenated treatment

pH @ 25C

8.8–9.1

9.2–9.6

8.0–8.5 (once through) 9.0-9.5 (drum)

Ammonia (ppm)

0.15 to 0.4

0.5–2.0

0.02–0.07 (once through) 0.3 -1.5 (drum)

Cation conductivity (uS/cm)

< 0.2 to <0.15

< 0.2 to < 0.1

< 0.15

Fe (ppb)

< 10 to < 5 (drum)

< 5 to < 2(drum)

< 5 to < 1 (drum)

Cu (ppb)

<2

<2

<1

Oxygen (ppb)

<5 to< 2 (drum)

1 to 10 (once thru)

30-150 (once through) 30–50 (drum)

SUMMARY OF OUT-OF-LIMIT CONDITIONS Purity Parameter

A-20

Extent Criteria Exceeded

How Long Exceeded

How Was It Resolved

Potential Impact on Turbine

Condition Assessment Data Sheets Data Sheet #6: (b) Steam Purity Monitoring Interview (Page 2 of 3) Plant and Unit Number: Unit OEM:

Date of Interview:

Design Rating: (MW)


Unit MDC: (MW)

Date Last Inspected: STEAM/WATER PURITY INTERVIEW

No. 1

Have there been any steam or water purity problems that could result in deposits or corrosion products being deposited in the turbine?

No. 2

How long did these events occur (hours, days weeks)? Have they been corrected?

No. 3

Have there been any significant condenser tube leaks that affected steam or water purity limits?

No. 4

Have there been any performance changes in the turbine that could be associated with the steam/water purity limits being exceeded?

A-21

Condition Assessment Data Sheets Data Sheet #6: (c) Steam Purity Monitoring Condition Assessment (Page 3 of 3) Plant and Unit Number: Unit OEM:

Date of Assessment:

Design Rating: (MW)


Unit MDC: (MW)


ASSESSMENT OF CURRENT STEAM/WATER CONDITION (BASED ON DATA AND INTERVIEWS)

Long Term

Immediate

Low

Moderate



Intermediate

Need for Action

Risk of Failure



A-22



Condition Assessment Data Sheets Data Sheet #7: (a) Lube Oil and EHC Analysis Audit (Page 1 of 3) Plant and Unit Number: Unit OEM:

Date of Audit:

Design Rating: (MW)


Unit MDC: (MW)

Commercial Operation Date: LUBE OIL TEST RESULTS Lube Oil Acceptance Criteria

Oil Sample Location

5–10 Microns

10–25 Microns

25–50 Microns

50–100 Microns

100–250 Microns

> 250 Microns

128,000 ppm*

42,000 ppm

6,500 ppm

1,000 ppm

92 ppm

None

Water % 1,000 ppm

Neutrality Number

Color

From main oil tank Other: specify From bearing header * All ppm designations here are per a 100-milliliter fluid sample size.

A-23

Condition Assessment Data Sheets Table 11-1 Summary of Operating Limits

EHC Test Results 1

Parameter

EPRI Limit of 4.0 max or monthly increase of 0.5

Color

Frequency

Reference

Achievable2

Comments

Monthly

4.4.3.1

1.5 (Light Tan)

ASTM D-1500 Color Criteria; OEM’s limits are included in Appendix H. Fluid Color Scale Comparison Chart is included in Appendix G5. System contamination measurement most important after breach of system

Viscosity

+/- 10% initial value

Monthly

4.4.3.2

N/A

Acidity (mg KOH/g)

< 0.1

Monthly

4.4.3.3

< 0.05

Chlorines (ppm)

< 50

Quarterly

4.4.3.4

< 10


Water (%, ppm)

< 0.1, 1000ppm

Monthly

4.4.3.5

< 0.05, 500ppm

2 main methods for improving this are dry air purge and vacuum dehydration

Mineral Oil 3 (%)

< 0.5

Quarterly

4.4.3.6

<0.1


Resistivity (G-Ohm-cm)

> 5 - 10

Monthly

4.4.3.7

> 20

Can cause erosion problems on stagnant areas of system, fluid types have different values

Particulate4

<2K/100 ml of 5-10 5 micron

Monthly

4.4.3.8

1K/100 ml of 5-10 micron5

EPRI value is a good starting point for developing fluid monitoring, but it has to have consistent sample methods and points

Individual Metals (per metal)

< 10 ppm

6 Months

4.4.3.9

< 2 ppm

Not a routine check, but indicative of degrading system, exclude phosporus and chromium. If particulate or acid #’s increase then increase the frequency of metal testing.

Foaming (Height/Colla pse time)

< 100 ml/ < 5 minute

12 Months

4.4.3.10

N/A

Collapse time is reported as time to get to nil foam height

Air Release

< 10 minutes

12 Months

4.4.3.11

< 8 minute

Should be performed with the system health check. With natural fluids < 5 minutes is achieveable.

B8

2 Years

4.4.3.12

B2/B3

Indicator of heat related problems

Hexane Test

6

NOTES: 1. Any one parameter out of the recommended values does not condemn a fluid or system. The collective data is what determines if a fuild or system is of concern. More than 2 parameters outside of the values would require evaluation to determine the total affect. Test methods are specified in Table 4-10 in section 4.4 of EPRI report 1004554. 2. Achievable values normally require system modifications and upgrades. 3. Some standard tests (GE) do not report only mineral oil, but generate a number that includes other non-soapontifiables (fluid degradation by products). 4. If this parameter doubles from one sample to the next then a new sample is needed per the EPRI sample procedure in section 4.2.2 of EPRI report 1004554. 5. ISO cleaniness code equivalent numbers are not available at this time due to changes in calibration test dust and the techniques which had been used in the most previous testing. 6. Rate according to ASTM D-2276 Appendix A3 B scale for aviation turbine fuels going from B-0 (white) to B-10 (very dark brown to black).

A-24

Condition Assessment Data Sheets Data Sheet #7: (b) Lube Oil and EHC Analysis Interview (Page 2 of 3) Plant and Unit Number: Unit OEM:

Date of Interview:

Design Rating: (MW)


Unit MDC: (MW)

Date Last Inspected: LUBE OIL AND EHC ANALYSIS INTERVIEW

No. 1

Has the lube oil water content or particle counts exceeded recommended limits? If so, how long were the limits exceeded?

No. 2

When was the last time the lube oil was tested by your lube oil supplier? What were the test results?

No. 3

Have there been any problems with the lube oil purification system? What kind of problem, and how long did they occur?

No. 4

Are there any issues or problems with the lube oil or lube oil system that could cause a forced outage on this unit?

No. 5

Has the EHC fluid exceeded the above-specified limit? What actions were taken? Did this correct the problem? If the problem was not corrected, how long has the problem been going on? What is the plan to correct the problem?

No. 6

Are there any problems with the EHC system that could cause a forced outage? Please describe in detail?

A-25

Condition Assessment Data Sheets Data Sheet #7: (c) Lube Oil and EHC Condition Assessment (Page 3 of 3) Plant and Unit Number: Unit OEM:

Date of Assessment:

Design Rating: (MW)


Unit MDC: (MW)

Commercial Operation Date: ASSESSMENT OF CURRENT LUBE OIL AND EHC CONDITION (BASED ON DATA AND INTERVIEWS)

Long Term

Immediate

Low

Moderate



Intermediate

Need for Action

Risk of Failure



A-26



Condition Assessment Data Sheets Data Sheet #8: (a) Pump Start Test Results Audit (Page 1 of 3) Plant and Unit Number: Unit OEM:

Date of Audit:

Design Rating: (MW)


Unit MDC: (MW)

Commercial Operation Date: PUMP START TEST RESULTS

Pump Type

Frequency of Pump Start Tests

Start Test Results

Plant Acceptance Criteria

Acceptance/Rejection Acceptable

Unacceptable

AC auxiliary oil pump Turning gear oil pump DC lube oil pump Main seal oil pump Recirculating seal oil pump DC seal oil pump Stator cooling pump EHC pump SPOT CHECK OF PUMP PRESSURES Pump Type

Pressure at skid

Pressure after filter

Pressure at turbine deck

Comments/Issues found

AC auxiliary oil pump Turning gear oil pump DC lube oil pump Main seal oil pump H2 and air side Recirculating seal oil pump DC seal oil pump Stator cooling pump EHC pump

A-27

Condition Assessment Data Sheets Data Sheet #8: (b) Pump Start Interview (Page 2 of 3) Plant and Unit Number: Unit OEM:

Date of Interview:

Design Rating: (MW)


Unit MDC: (MW)

Date Last Inspected: PUMP START-UP OPERATION INTERVIEW (ABNORMAL EVENTS)

No. 1

How frequently are start tests performed on the pumps noted above?

No. 2

Is a record maintained by plant operations or maintenance personnel of start test results and actions taken if they did not meet specified criteria? (Review test results.)

No. 3

Have there been any problems noted on the above pumps? What were these problems?

No. 4

Have the above problems been resolved?

No. 5

What PM or PdM is performed on the above pumps? Who is responsible for this work?

No. 6

Briefly review the PM/PdM program for these pumps, and look at work orders used for this effort. (Review what work is done and the frequency with which it is performed on each pump type.)

No. 7

Have there been any problems noted on the lubrication oil system, seal oil system, stator cooling system, or EHC system during the course of performing PM/PdM work on these systems that indicate they may not be operating within OEM expectations? (List all issues and discuss any concerns.)

A-28

Condition Assessment Data Sheets Data Sheet #8: (c) Pump Condition Assessment (Page 3 of 3) Plant and Unit Number: Unit OEM:

Date of Assessment:

Design Rating: (MW)


Unit MDC: (MW)


ASSESSMENT OF CURRENT PUMP CONDITION (BASED ON DATA AND INTERVIEWS)

Long Term

Immediate

Low

Moderate



Intermediate

Need for Action

Risk of Failure





A-29

Condition Assessment Data Sheets Data Sheet #9: (a) Valve Tightness and Test Results Audit (Page 1 of 3) Plant and Unit Number: Unit OEM:

Date of Audit:

Design Rating: (MW)


Unit MDC: (MW)

Commercial Operation Date: VALVE TIGHTNESS AND OPEN/CLOSE TEST RESULTS

Control Valves

If less than 1/6 rated speed: acceptable. If greater than 1/2 rated speed: unacceptable.

Acceptance Criteria

No sticking allowed when test is performed. If sticky, correct at next weekend shutdown.

Stop valves

No leakage.


Reheat Stop valves

Valve closes.


Intercept valves

Less than rated speed whenever closed against rated reheat pressure.


Nonreturn valves

Valves close when unit is tripped.

Valve will close when unit is tripped.

A-30

Not Acceptable

Open/Close Acceptance Criteria

Acceptable

Type of Valve

Not Acceptable

Acceptance Criteria (with Full Pressure Against Valve)

Acceptable

Tightness Test Acceptance Criteria

Condition Assessment Data Sheets Data Sheet #9: (b) Valve Tightness and Test Results Audit (Page 2 of 3) Plant and Unit Number: Unit OEM:

Date of Interview:

Design Rating: (MW)


Unit MDC: (MW)

Date Last Inspected: VALVE TIGHTNESS INTERVIEW

No. 1

How frequently are valve tightness and valve close tests performed on the unit?

No. 2

Do the specific valves meet the acceptance criteria noted above?

No. 3

Are there any valves noted above that take longer to close now than tests performed earlier to confirm the valve’s ability to close when called for by the control system?

No. 4

Does the plant keep track of the time it takes for a valve to close and trend this information in order to use it as a basis for maintenance inspection?

A-31

Condition Assessment Data Sheets Data Sheet #9: (c) Valve Tightness Condition Assessment (Page 3 of 3) Plant and Unit Number: Unit OEM:

Date of Assessment:

Design Rating: (MW)


Unit MDC: (MW)


ASSESSMENT OF CURRENT STEAM/WATER CONDITION (BASED ON DATA AND INTERVIEWS)

Long Term

Immediate

Low

Moderate



Intermediate

Need for Action

Risk of Failure



A-32



Condition Assessment Data Sheets Data Sheet #10: (a) Turbine Trip Test Results Audit (Page 1 of 3) Plant and Unit Number: Unit OEM:

Date of Audit:

Design Rating: (MW)


Unit MDC: (MW)

Commercial Operation Date: TURBINE TRIP TEST RESULTS

Type Test

Date Tested

Acceptable

Not Acceptable

Comments and Recommendations

Overspeed trip Minimum oil trip Vacuum trip Solenoid trip Thrust trip Shaft pump trip Others (list)

A-33

Condition Assessment Data Sheets Data Sheet #10: (b) Turbine Trip Interview (Page 2 of 3) Plant and Unit Number: Unit OEM:

Date of Interview:

Design Rating: (MW)


Unit MDC: (MW)

Date Last Inspected: TURBINE TRIP INTERVIEW (ABNORMAL EVENTS)

No. 1

How frequently does the turbine trip off-line?

No. 2

Is a record maintained by plant operations or maintenance personnel of trips and actions taken to meet specified criteria? (Review test results.)

No. 3

Have there been any problems noted on the above turbines? What were these problems?

No. 4

Have the above problems been resolved?

A-34

Condition Assessment Data Sheets Data Sheet #10: (c) Turbine Trip Interview (Page 3 of 3) Plant and Unit Number: Unit OEM:

Date of Assessment:

Design Rating: (MW)


Unit MDC: (MW)


ASSESSMENT OF CURRENT TRIP CONDITION (BASED ON DATA AND INTERVIEWS)

Long Term

Immediate

Low

Moderate



Intermediate

Need for Action

Risk of Failure





A-35

Condition Assessment Data Sheets Data Sheet #11: (a) Turbine Instrumentation Survey Results Audit (Page 1 of 4) Plant and Unit Number: Unit OEM:

Date of Audit:

Design Rating: (MW)


Unit MDC: (MW)

Commercial Operation Date: TURBINE INSTRUMENT SURVEY RESULTS PART 1: Expansion and Position Data at Minimum and Full Load Position Minimum Load

Location

Full Load

Control Valve No.

Front standard expansion

1

Mid standard expansion

2

DXD- front standard

3

DXD- mid standard

4

Rotor expansion

5

Thrust A

6

Thrust B

7

CV servo

8

Position at Minimum load

Position at Maximum Load

PART 2: System Oil Pressures Type Pressure Location Main oil pump discharge MOP suction At T-G centerline

Bearing header Seal oil air/gas Seal oil differential Stator cooling water MOP discharge MOP suction

At lube oil tank or skid

Bearing header Seal oil/gas Seal oil differential Stator cooling water

A-36

Values

Acceptable

Unacceptable? (State Reason)

Date Gage Was Last Calibrated


TURBINE INSTRUMENT SURVEY RESULTS (CONTINUED) PART 3: Water Induction Thermocouples Unit Load

Thermocouple Description

Upper TC Value

Lower TC Value

Acceptability Yes or No

Comments

PART 4: Start/Load Thermocouples Unit Load

Thermocouple Description

Thermocouple Value

Acceptable

Comments

A-37

Condition Assessment Data Sheets Data Sheet #11: (b) Turbine Instrumentation Survey Interview (Page 3 of 4) Plant and Unit Number: Unit OEM:

Date of Interview:

Design Rating: (MW)


Unit MDC: (MW)

Date Last Inspected: TURBINE INSTRUMENTATION INTERVIEW

No. 1

Do the thermocouple readings make sense, and are they reporting temperatures at expected values? Do any exhibit an unusual or excessive replacement rate?

No. 2

Are reported oil gage pressures consistent and within expected values? Do any exhibit calibrationrelated problems?

No. 3

Are shaft vibration pick-ups providing consistent readings within expected values for each of the bearings?

No. 4

Are the position and expansion meters reporting whether the rotor and casing expansion is smooth during start-up and ramp-to-load, or is sudden movement reported?

No. 5

Are the pressures and temperatures that are monitoring for steam leakage providing consistent readings within expected values?

A-38

Condition Assessment Data Sheets Data Sheet #11: (c) Turbine Instrumentation Condition Assessment (Page 4 of 4) Plant and Unit Number: Unit OEM:

Date of Assessment:

Design Rating: (MW)


Unit MDC: (MW)


ASSESSMENT OF CURRENT TURBINE INSTRUMENTATION CONDITION (BASED ON DATA AND INTERVIEWS)

Long Term

Immediate

Low

Moderate



Intermediate

Need for Action

Risk of Failure





A-39

Condition Assessment Data Sheets Data Sheet #12: (a) Generator-Exciter Inspection Audit (Page 1 of 3) Plant and Unit Number: Unit OEM:

Date of Audit:

Design Rating: (MW)


Unit MDC: (MW)

Commercial Operation Date: GENERATOR INSPECTION RESULTS

Component

Stator

Field

DC Exciters

Alterrex Exciters

Brushless Exciters

A-40

No.

Type of Inspection or Check to Perform or Review

1

Number of RTDs out of service

2

Full load RTD readings

3

Number of TCs out of service

4

Full load TC readings

5

End winding vibration readings versus expected

6

Partial discharge data

7

Stator leak monitoring results

8

Latest megger or hipot results

9

Hydrogen leakage test results

10

Liquid level detector alarms or other oil ingress issues

1

Full load amps and VARs comparison to design curves

2

Dew point readings

3

Collector ring brush vibration

4

Hydrogen seal megger reading

5

Insulated bearing megger reading

6

Shaft voltage test results from PM routes

7

Field megger readings

1

Commutator brush vibration

2

Commutator diameter

3

Commutator mica groove diameter

1

Collector brush vibration

2

Collector ring diameter

3

Bearing insulation megger reading

4

RTD readings

1

Bearing insulation megger reading

2

No. of blown fuses

3

RTD readings

Results

Acceptable

Not Acceptable

Condition Assessment Data Sheets Data Sheet #12: (b) Generator-Exciter Inspection Interview (Page 2 of 3) Plant and Unit Number: Unit OEM:

Date of Interview:

Design Rating: (MW)


Unit MDC: (MW)

Date Last Inspected: GENERATOR OPERATING INFORMATION INTERVIEW

No. 1

Have trends associated with dew point, hydrogen purity, vibration, or hydrogen consumption remained stable and constant? For how long?

No. 2

Have any loadings occurred beyond the reactive capability curves, or have any unintentional loading events occurred?

No. 3

Has there been any abnormal frequency operation?

No. 4

Have there been any operational mishaps, such as accidental overspeeds or synchronizing out of phase?

No. 5

Have there been an excessive number of full load or part load trips? Due to what?

No. 6

Has any motoring of the generator occurred?

A-41

Condition Assessment Data Sheets Data Sheet #12: (c) Generator-Exciter Condition Assessment (Page 3 of 3) Plant and Unit Number: Unit OEM:

Date of Assessment:

Design Rating: (MW)


Unit MDC: (MW)

Commercial Operation Date: ASSESSMENT OF CURRENT GENERATOR-EXCITER CONDITION (BASED ON DATA AND INTERVIEWS)

Long Term

Immediate

Low

Moderate



Intermediate

Need for Action

Risk of Failure



A-42



Condition Assessment Data Sheets Data Sheet #13: (a) Auxiliary System Operating Information Audit (Page 1 of 3) Plant and Unit Number: Unit OEM:

Date of Audit:

Design Rating: (MW)


Unit MDC: (MW)

Commercial Operation Date: AUXILLARY SYSTEM OPERATING INFORMATION SURVEY RESULTS

PART 1: Steam Seal System

Recorded Values

Criteria: (Values Noted May Vary with Each Unit)

Steam seal pressure

5 psi (34.5 kPa) typical

Vacuum (inches water)

3 to 5" water (0.7–1.2 kPa) typical

Any observed steam leakage at glands? Excessive leak-off from steam seal header?

PART 2: Hydrogen Seal Oil System

Pressure

Hydrogen cooler inlet gas temperature

N/A

Hydrogen cooler gas exit temperature

N/A

Temp.


Vacuum at vacuum tank

1" Hg (3.4 kPa) minimum to maintain 97% hydrogen purity. Can go as low as 26" Hg (88.0 kPa).

Temperature of vacuum pump separator tank

Will be hot if excessive water in lube oil and would need to be drained.

Hydrogen gas pressure and seal oil pressure differential

N/A

Delta P across main seal oil pump filter

N/A

PART 3: Stator Cooling Water System

Recorded Values

Varies with various units. Typical GE is 8 psi (55.2 kPa) with alarm at 2.5 psi (17.2 kPa).


Deionized water conductivity (µmhos/cm)

Alarm is at 0.5 µmhos/cm.

∆P H2 gas and stator cooling water pressure

Should have positive ∆P because water pressure should be lower than hydrogen gas.

Cooling water inlet temperature

Should be 40–45°C (104–113°F), alarm is at 47°C (116.6°F).

Bulk water outlet temperature

Alarm at max capability is at 78˚C (172.4°F); runback is at 83˚C (181.4°F).

Stator bar outlet temperatures for each bar monitored

Alarm is at 83˚C (181.4°F).

Stator bar temperatures

Alarm is at 78˚C (172.4°F).

Stator cooling water filter ∆P

8 psi (55.2 kPa) is the maximum allowed.

A-43

Condition Assessment Data Sheets Data Sheet #13: (b) Auxiliary System Information Interview (Page 2 of 3) Plant and Unit Number: Unit OEM:

Date of Interview:

Design Rating: (MW)


Unit MDC: (MW)

Date Last Inspected: AUXILLARY SYSTEM OPERATING INFORMATION INTERVIEW

No. 1

Does the generator have liquid level alarm problems? Is the problem due to oil or water ingress into the detectors? Does the unit have problems in maintaining hydrogen purity or hydrogen pressure?

No. 2

Does the unit have any problems with hydrogen leakage? If so, what is the daily hydrogen consumption compared to its design leakage?

No. 3

What are the results of operational tests performed on the seal oil system? How frequently are they performed? What are the results of preventive and predictive maintenance checks performed on the seal oil system?

No. 4

Does the generator have high vibration problems during startup or shutdown, during high load or low load?

No. 5

Has the stator cooling water system experienced any alarms due to (1) low flow, (2) low inlet pressure, (3) high inlet temperature, (4) high stator bar temperature, or (5) conductivity? What has been the frequency of each of these alarms? What was the root cause of these alarms?

No. 6

Has the unit experienced a low flow runback? If so, at what frequency? What has been identified as the root cause?

No. 7

What operational tests are performed on the stator cooling water system? What were the results of such tests? Has the failure of any operational test been resolved to your satisfaction?

No. 8

What equipment, instrumentation, and controls are included in your PM program? What is the frequency of inspection and the results of these inspections? Are there any problems that have not been resolved from the program? What do you believe the consequences can be from not having resolved them?

No. 9

How frequently do you calibrate instruments and controls used for operation functions? Typically, they are calibrated and tested at least annually.

No. 10

Who is responsible for determining the root cause of stator cooling system alarms or a low flow runback? Have any occurred? What was the cause?

No. 11

What stator cooling water components are included in the PdM program?

No. 12

Are there any known problems that could result in alarm, runbacks, or serious harm to the stator cooling water equipment?

A-44

Condition Assessment Data Sheets Data Sheet #13: (c) Auxiliary System Condition Assessment (Page 3 of 3) Plant and Unit Number: Unit OEM:

Date of Assessment:

Design Rating: (MW)


Unit MDC: (MW)

Commercial Operation Date: ASSESSMENT OF CURRENT AUXILLARY SYSTEM CONDITION (BASED ON DATA AND INTERVIEWS)

Long Term

Immediate

Low

Moderate



Intermediate

Need for Action

Risk of Failure





A-45

Condition Assessment Data Sheets Data Sheet #14: (a) Visual Inspection Audit (Page 1 of 3) Plant and Unit Number: Unit OEM:

Date of Audit:

Design Rating: (MW)


Unit MDC: (MW)

Commercial Operation Date: VISUAL INSPECTION RESULTS

Area Visually inspected st

HP inlet at 1 stage HP exhaust IP inlet

TURBINE

IP exhaust LPA inlet LPA exhaust: (L-0, L-1) LPB inlet LPB exhaust: (L-0, L-1) LPC inlet LPC exhaust: (L-0, L-1) Windings

GENERATOR

Retaining rings Through bolts Blocking Collector rings Brushes

A-46

Major Finding or Observation

Condition Assessment Data Sheets Data Sheet #14: (b) Visual Inspection Interview (Page 2 of 3) Plant and Unit Number: Unit OEM:

Date of Interview:

Design Rating: (MW)


Unit MDC: (MW)

Date Last Inspected: VISUAL INSPECTION INTERVIEW

No. 1

When was the last time a visual inspection was made of the last stage turbine blades? Was any noticeable erosion wear or damage found on any of the airfoils. What was the condition of the shrouds, lugs, and tie wires?

No. 2

When was the last time the 1 HP or 1 reheat blades were visually inspected? Was there any noticeable solid particle erosion or FOD? Was this apparent in the preceding inspection.

No. 3

When was the last time a visual inspection was performed on the generator components? What was their apparent condition?

st

st

A-47

Condition Assessment Data Sheets Data Sheet #14: (c) Visual Inspection Condition Assessment (Page 3 of 3) Plant and Unit Number: Unit OEM:

Date of Assessment:

Design Rating: (MW)


Unit MDC: (MW)


VISUAL ASSESSMENT OF CURRENT CONDITION (BASED ON DATA AND INTERVIEWS)

Long Term

Immediate

Low

Moderate



Intermediate

Need for Action

Risk of Failure



A-48



Condition Assessment Data Sheets Data Sheet #15: (a) Checklist of Out-of-Limit Events and Conditions (Page 1 of 4) Plant and Unit Number: Unit OEM:

Date of Interview:

Design Rating: (MW)


Unit MDC: (MW)

Date Last Inspected: AUDIT OF UNIT UPSETS – OUT-OF-LIMIT CONDITION OCCURRENCES Review the following with unit operators or other appropriate plant personnel.

No.

Event Description

How Many

How Long

Actions Taken. Does Problem Still Persist?

Potential Impact on T-G Reliability No

1

Generator motored

2

Generator dew point exceeded

3

Generator hydrogen purity exceeded

4

Stator winding vibration limit exceeded

5

Out-of-phase synchronization

6

Switching incidents affecting generator

7

Insulation resistance too low on bearing, H2 seal

8

Core monitor alarms requiring operator action

9

Stator coolant conductivity exceeded

10

H2 consumption exceeded maximum allowable

11

Hydrogen in watercooled stator

12

Generator rotor ground faults

13

Shaft voltage limit exceeded

14

Stator ground faults

15

Liquid level alarms and oil in stator

Yes

H–M–L

A-49

Condition Assessment Data Sheets Data Sheet #15: (a) Checklist of Out-of-Limit Events and Conditions (Page 2 of 4) No.

Event Description

How Many

How Long



16

Seal oil pressure low

17

Generator TC/RTD limits exceeded

18

Negative sequence alarms tripped

19

Failed seal oil pump start tests

20

Failed stator cooling pump start tests

21

Experienced condenser tube leaks

22

Exceeded valve test limits

23

Exceeded steam purity limits

24

Exceeded air in leakage limits

25

Experienced water induction incidents

26

Exceeded maximum back pressure for unit

27

Operated unit outside of ramp rate and of curves

28

Excessive partial- or full-load trips

29

AC or DC pump start failures

30

Exceeded lube oil/seal oil EHC contamination limits

31

Exceeded oil trip test limits

32

Exceeded overspeed trip test limits

33

Vibration too high at speed or criticals

34

Numerous balance shots needed since last outage

35

Main steam inlet temperature excursions

A-50

Yes

H–M–L

Condition Assessment Data Sheets Data Sheet #15: (a) Checklist of Out-of-Limit Events and Conditions (Page 3 of 4) No.

Event Description

How Many

How Long



36

Reheat steam inlet temperature excursions

37

HI-IP differential temperature exceeded

38

Crossover temperature excursions

39

HP or IP inlet pressure exceeds maximum allowable

40

DXD or RXD expansion limits exceeded

41

Thrust wear limit exceeded

42

Temperature excursion on thrust/journal bearing

43

Turning gear start/stop problems

44

High diff pressure across seal oil /lube oil/EHC filters

45

Steam seals blow during operation

46

Water in lube oil/seal oil/EHC

47

LP hood sprays do not operate properly

48

PM or PdM not performed as expected on unit

49

Start/load, water induction thermocouples fail

50

Excess run out: HP control rotor or extension shaft

51

Low lube oil pressure at centerline

52

High ∆P across stop or intercept valves

53

Low MOP suction or discharge pressure

54

EHC pump start test failure

Yes

H–M–L

A-51

Condition Assessment Data Sheets Data Sheet #15: (a) Checklist of Out-of-Limit Events-Conditions (Page 4 of 4) No.

Event Description

How Many

How Long



55

Low lube oil pressure

56

Low control or impeller oil pressure

57

Sudden change in HP performance

58

Sudden change in IP performance

59

Sudden change in LP performance

60

Unit erratic on load control

61

Valves stick or tend to hang up

62

Station batteries need PM or have other issues

63

MHC or EHC control problems or issues

64

Vibration problems at low load or during startup

65

Front standard is sticky or hangs up

66

Mid-standard is sticky or tends to hang up

67

Steam leaks around shells or HP flanges

68

Have any turbine shells been pumped to stop steam leaks?

69

Are the turbine CV crack and intercept points out of OEM spec.?

A-52

Yes

H–M–L

Condition Assessment Data Sheets Data Sheet #15: (b) Condition Assessment for Out-of-Limit Events (Page 1 of 1) Plant and Unit Number: Unit OEM:

Date of Assessment:

Design Rating: (MW)


Unit MDC: (MW)


ASSESSMENT OF CURRENT T-G CONDITION (BASED ON OUT-OF-LIMIT EVENTS)

Long Term

Intermediate

Need for Action Immediate

Low



Moderate

Risk of Failure





A-53

Condition Assessment Data Sheets Data Sheet #16 (a): Current Long-Range Maintenance Plan for Unit (Page 1 of 3) Plant and Unit Number: PAGE 1 Unit OEM:

Date of Assessment:

Design Rating: (MW)


Unit MDC: (MW)

Commercial Operation Date: CURRENT LONG-RANGE MAINTENANCE PLANS FOR UNIT

Component or System

TURBINES

HP turbine IP turbine LPA turbine LPB turbine

GENERATOREXCITER

LPC turbine Crawl through Field removal Voltage regulator calibration Hydrogen coolers Field removed Speed load changer Governor

CONTROL SYSTEM

Aux governor Trip anticipator Primary speed relay Secondary speed relay TV controller CV operator cylinder SV/TV operator cylinder IV operator cylinder RSV operator cylinder

LUBE OIL SYSTEM

Other control components (list)

A-54

Aux oil pump/motor TG oil pump/motor DC oil pump/motor Ejector/booster pump Oil tank and bowser Lift pumps Oil coolers

Date of Last Inspection

Year of Next Inspection

Inspection Frequency in Years

Comments as to Risks Based on Condition Assessment

Condition Assessment Data Sheets Data Sheet #16 (b): Current Long-Range Maintenance Plan for Unit (Page 2 of 3) Plant and Unit Number:

PAGE 2

Unit OEM:

Date of Assessment:

Design Rating: (MW)


Unit MDC: (MW)


STATOR COOLING

STEAM SEAL

SEAL OIL SYSTEM

PUMPS

VALVES

Component or System





Control or governor valves Intercept valves Stop or throttle valves Reheat stop valves Ventilator valve Blow down valve Equalizer valve Extraction non-return valves Main seal oil pump (air/gas) Recirculation seal oil pump Vacuum pump DC backup pump Detraining tanks and float trap Coolers and filters Main seal oil pump (air/gas) Recirculation seal oil pump Vacuum pump DC backup pump Detraining tanks and float trap Coolers and filters Diverter valve Regulator Strainers Exhauster fan and motors Pumps and motors Coolers and filters/strainers Change deionizing resin Regulators and flow meter

A-55

Condition Assessment Data Sheets Data Sheet #16 (c): Current Long-Range Maintenance Plan for Unit (Page 3 of 3) Plant and Unit Number:

PAGE 3

Unit OEM:

Date of Assessment:

Design Rating: (MW)


Unit MDC: (MW)


ALIGNMENT

Component or System

Individual turbine sections Tops on–tops off alignment

OTHER ACTIVITIES (LIST)

MISCELLANEOUS

MAJOR NDE

Turbine rotor boresonics

A-56

Generator rotor boresonics Retaining ring ultrasonic Turbine wheel dovetail UT/NDE Major unit oil flush Valve controls lineup Turning gear and motor Exhaust hood spray nozzles Pre-warming system valves





Condition Assessment Data Sheets Data Sheet #17: (a) Overall Unit Condition Assessment Form Plant and Unit Number Unit OEM:

Date of Assessment:

Design Rating: (MW)


Unit MDC: (MW)

Commercial Operation Date: CONDITION ASSESSMENT SUMMARY

Component or System

DEGRADATION Severe

Significant

Some

GOOD CONDITION

Comments

Recommendations:

A-57

B

TURBINE-GENERATOR OUTAGE REPORT

B.1

Outage Report Instructions

The basic principle behind this format is the flexibility to write the report as the outage progresses. If someone spends approximately one hour a day updating the report, at the end of the job the outage report is basically complete except for minor clerical details. I. Introduction Under introduction make sure to include off line date and time, turning gear date and time and return to service date and time. Use military hours (24-hour clock). List bulletins if used. If not, just say no bulletins were implemented during this outage. II. Name Plate Rating III. Outage Personnel Use only the lines you need. Correct A, B. C., etc. If you do not have an NDE person, you omit and go to the next one. IV. Summary of Recommendations Should be worded the same as in recommendations in the report. If you say normal inspection next outage or none, you don’t have to list. It is a good idea just to leave a full page and then when you complete the report, go back, copy, cut, paste and put your recommendations in from your recommendations in the report. Just remember if you cut and paste, include the component you are talking about in this section. V. Work Summary The turbine and generator are broken down into components. Each component is then broken down into the following sections (This does not include any data sheets. This is verbage): 1. Work scope – This includes what the original workscope was for that component. This can be written up before the outage actually starts. 2. Inspection – The “as found” condition of the component. B-1

Turbine-Generator Outage Report

3. Maintenance – What repairs were, if any, to the component. This may include more work than the original work scope called for. 4. Reassembly – The “as left” condition of the component. 5. Recommendations - Any recommendations for the next time this component is inspected. This section should also be copied to the “Summary of Recommendations” section. Make sure you input information in each section as work is being performed each day. This will make sure certain that information is not lost when the outage gets very busy. Go to the section you need and begin keying. What you don’t need, highlight and delete. VI. Data Sheets Make certain you put the exact title as it appears on the data sheet. Show As Found - As Assembled, R/S L/S - Coupling #. Make certain all date sheets are signed and dated. If you have your data sheets keyed and the names typed in, they still have to be signed. VII.

Test Data

All test data including NDE. VIII. Photos IX. Appendix You will always have a Replacement Parts Used List. You may have a Turbine Assessment Report, etc. Whatever does not qualify for the Contractors, Report section goes under Appendix. X. Contractors’ Reports List each contractor such as (so that their report will not be overlooked): A. WSI Inc. B. Welding Services Inc. If you do not have contractors, make a sheet showing none. If you have an OEM representative, make certain that he signs all data sheets.

B-2


B.2

Report Table of Contents _________ (Plant - Unit) __________Inspection (HP, IP, LP, Gen, Vlvs, etc) _________(Outage) __________(Dates of Outage) Page No.

I. Introduction

__

II. Name Plate Ratings

__

III. Outage Personnel

__

A. B. C. D. E.

Outage Engineer Maintenance Supervisors Foremen Turbine Assessment Group NDE Personnel

IV. Summary of Recommendations

__

V. Work Summary

__

A. HP Turbine 1. Outer Cylinder 2. Inner Cylinder/Blade Rings 3. Nozzle Block 4. Stationary Blading 5. Rotating Blading 6. Glands and Gland System 7. Rotor and Extension Shaft 8. Bearings, Pedestals and Thrust Bearing 9. Crossover/Crossunder Piping 10. Main Oil Pump 11. Auxiliaries (AC & DC Pumps, Lube Oil Coolers, etc.) 12. HP Other B. IP Turbine 1. Outer Cylinder 2. Inner Cylinder/Blade Rings 3. Stationary Blading

__ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ B-3


4. 5. 6. 7. 8. 9.

Rotating Blading Glands and Gland System Rotor and Extension Shaft Bearing, Pedestals and Thrust Bearings Crossover/Crossunder Piping IP Other

C. LP Turbine 1. Outer Cylinder 2. Inner Cylinder/Blade Rings 3. Stationary Blading 4. Rotating Blading 5. Glands and Gland System 6. Rotor and Extension Shaft 7. Bearing, Pedestals and Thrust Bearings 8. Crossovser/Crossunder Piping 9. Turning Gear 10. LP Other D. Generator 1. Collector Rings and Brush Rigging 2. Bearing Brackets 3. Outer Casing or Frame 4. Hydrogen Coolers 5. Hydrogen Seals and Bracket 6. Hydrogen Cooling System 7. Air Cooling System 8. Seal Oil System 9. Air Gap Baffling Cooling System 10. Generator Rotor - Mechanical 11. Generator Rotor - Electrical 12. Generator Stator - Electrical E. Exciter 1. Exciter - Mechanical 2. Exciter - Electrical 3. Commutator and Brushes F. Valves 1. Throttle Valves 2. Governor Valves

B-4

__ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __ __


3. Intercept Valves 4. Reheat Valves

__ __

G. Other

__

1. 2. 3. 4. 5. 6.

__ __ __ __ __ __

BFPT Extraction System & Piping Oil Flush Governing System/Hydraulic System Voltage Regulator Miscellaneous Turbine - Generator

VI. Data Sheets

__

VII.

__

Test Data

VIII. Photos

__

IX. Appendix

__

X. Contractors’ Reports

__

B-5


B.3

Blank Report Format _________(Plant - Unit) __________Inspection (HP, IP, LP, Gen, Vlvs, etc.) _________(Outage __________(Dates of Outage)

I. Introduction The unit was removed from service April 2, 1998, at 2340 hours for a scheduled/unscheduled outage. The work scope consisted of inspection of__________________________________ __________________________________________________________________________ The unit went on turning gear service (date) at

(date) at hours. The unit was returned to hours. (Use military hours.)

The following engineering bulletins were implemented during this outage. Start-Up

B-6


II. Name Plate Rating

III. Outage Personnel A. Outage Engineer B. Maintenance Supervisors C. Foremen D. Turbine Assessment Group E. NDE Personnel

B-7


IV. Summary of Recommendations

(Should be the same as in the report under recommendations for each component.)

B-8


V. Work Summary A. HP Turbine 1. Outer Cylinder a. b. c. d. e.

Work Scope Inspection Maintenance Reassembly Recommendations

2. Inner Cylinder/Blade Rings a. b. c. d. e.


3. Nozzle Block a. b. c. d. e.


4. Stationary Blading a. b. c. d. e.


5. Rotating Blading a. b. c. d. e.

Work Scope Inspection Maintenance Reassembly Recommendations B-9


V. A. HP Turbine - continued 6. Glands and Gland System a. b. c. d. e.


7. Rotor and Extension Shaft a. b. c. d. e.


8. Bearings, Pedestals, and Thrust Bearing a. b. c. d. e.


9. Crossover/Crossunder Piping a. b. c. d. e.


10. Main Oil Pump a. b. c. d. e.

B-10



V. A. HP Turbine - continued 11. Auxiliaries (AC & DC Pumps, Lube Oil Coolers, etc.) a. b. c. d. e.


12. HP Other a. b. c. d. e.


B. IP Turbine 1. Outer Cylinder a. b. c. d. e.







V. B. IP Turbine - continued 4. Rotating Blading a. b. c. d. e.


5. Glands and Gland System a. b. c. d. e.




7. Bearing, Pedestals, and Thrust Bearings a. b. c. d. e.



B-12



V. B. IP Turbine - continued 9. IP Other a. b. c. d. e.


C. LP Turbine 1. Outer Cylinder a. b. c. d. e.






4. Rotating Blading a. b. c. d. e.



C. LP Turbine (continued) 5. Glands and Gland System a. b. c. d. e.




7. Bearing, Pedestals, and Thrust Bearings a. b. c. d. e.




9. Turning Gear a. b. c. d. e.

B-14



C. LP Turbine (continued) 10. LP Other a. b. c. d. e.


D. Generator 1. Collector Rings and Brush Rigging a. b. c. d. e.


2. Bearing Brackets a. b. c. d. e.


3. Outer Casing or Frame a. b. c. d. e.


4. Hydrogen Coolers a. b. c. d. e.



D. Generator (continued) 5. Hydrogen Seals and Bracket a. b. c. d. e.


6. Hydrogen Cooling System a. b. c. d. e.


7. Air Cooling System a. b. c. d. e.


8. Seal Oil System a. b. c. d. e.


9. Air Gap Baffling Cooling System a. b. c. d. e.

B-16



D. Generator (continued) 10. Generator Rotor - Mechanical a. b. c. d. e.


11. Generator Rotor - Electrical a. b. c. d. e.


12. Generator Stator - Electrical a. b. c. d. e.


E. Exciter 1. Exciter - Mechanical a. b. c. d. e.


2. Exciter - Electrical a. b. c. d. e.



E. Exciter (continued) 3. Commutator and Brushes a. b. c. d. e.


F. Valves 1. Throttle Valves a. b. c. d. e.


2. Governor Valves a. b. c. d. e.


3. Intercept Valves a. b. c. d. e.


4. Reheat Valves a. b. c. d. e. B-18



G. Other 1. FWPT a. b. c. d. e.


2. Extraction System & Piping a. b. c. d. e.


3. Oil Flush a. b. c. d. e.


4. Governing System/Hydraulic System a. b. c. d. e.


5. Voltage Regulator a. b. c. d. e.


B-19


G. Other (continued) 6. Miscellaneous Turbine - Generator a. b. c. d. e.

B-20



VI. Data Sheets Prepare an index for each data sheet, whether 1 or 300. Be sure to show “as found,” as left, etc., where applicable. All data sheets must be signed by the person taking the readings: foreman, maintenance supervisor, OEM representative, or outage engineer. See Appendix C for the data sheets.

B-21


VII.

Test Data

Test data are to be placed here.

B-22


VIII. Photos Place photos two to a page indicating what the picture depicts - “as found,” “as left”, etc. Pasted, not taped.

B-23


IX. Appendix Replacement Turbine Parts Used List. (Turbine Assessment Reports, etc.) Any other information or reports that do not apply to Contractors’ Reports, for example, Turbine Assessment Reports.

B-24


X. Contractors’ Reports

B-25

C

DATA SHEETS

These forms are grouped into major categories as follows: I. Turbine Axial/Radial Clearances, Alignment, and Radial/Axial Position Sheet #1: “N” Wheel Clearance Record.............................................................................. C-7 Sheet #2: Wheel Clearance Record with Twist and Variation ............................................. C-8 Sheet #3: Turbine Generator Alignment Record – Tops Off ............................................... C-9 Sheet #4: Turbine Generator Alignment Record – Tops On ............................................. C-10 Sheet #5: Bolted Diaphragm Drop, Level, and Side Slip Check........................................ C-11 Sheet #6: “Barn Door” Latch Diaphragm – Axial Crush Pin Clearances............................ C-12 Sheet #7A: Spill Strip and Diaphragm Packing Clearance Data ....................................... C-13 Sheet #7B: Spill Strip and Diaphragm Packing Clearance Data ....................................... C-14 Sheet #8: Rotor Axial Position .......................................................................................... C-15 Sheet #9: HP Rotor Axial Position .................................................................................... C-16 Sheet #10: Steam Packing Butt Clearances ..................................................................... C-17 Sheet #11: Steam Packing Wear Measurements ............................................................. C-18 Sheet #12A: Diaphragm Clearance Record...................................................................... C-19 Sheet #12B: Diaphragm Clearance Record...................................................................... C-20 Sheet #12C: Diaphragm Clearance Record with Z and W Clearances ............................. C-21 Sheet #13: Interstage Packing Clearance Wear Measurements....................................... C-22 Sheet #14: Shell Arm Elevation Keys as Miked ................................................................ C-23 Sheet #15: LP Steam Gland ............................................................................................. C-24 Sheet #16: Rotor and Water Gland Dimensions ............................................................... C-25 Sheet #17: Water Gland Clearances ................................................................................ C-26 Sheet #18: LSB Radial Tip Clearances ............................................................................ C-27 Sheet #19: Axial/Radial Clearances – Curtis Blades ........................................................ C-28 Sheet #20: Reaction Blade Clearances ............................................................................ C-29 Sheet #21: Turbine Dummy Seal Clearances................................................................... C-30 Sheet #22: Packing Gland Dimensions (Sample) ............................................................. C-31 Sheet #23: Inboard Pedestal Base Plate Gibb Key Clearances........................................ C-32

C-1

Data Sheets

Sheet #24: Coupling Half to Pedestal – Axial Position ...................................................... C-33 Sheet #25: Assembled Coupling – Axial Position ............................................................. C-34 Sheet #26: Bearing Ring to Housing Check...................................................................... C-35 Sheet #27: Turning Gear (Sample)................................................................................... C-36 II. Turbine Bearings, Journals, Oil Seals/Deflectors, Seal Rings, and Coupling Data Sheet #28: Journal Bearing Clearance and Pinch ............................................................ C-37 Sheet #29: Bearing Tilt/Twist Checks ............................................................................... C-38 Sheet #30: Bearing Load Test .......................................................................................... C-39 Sheet #31: Bearing Fillet Clearances ............................................................................... C-40 Sheet #32: Journal Dimensions........................................................................................ C-41 Sheet #33: Bearing Orifice Inspection Checks.................................................................. C-42 Sheet #34: Thrust Bearing (Overhung)............................................................................. C-43 Sheet #35: Thrust Bearing (Straddle) ............................................................................... C-44 Sheet #36: Thrust Bearing (Independently Mounted-Tapered Land/CCW) Checks .......... C-45 Sheet #37: Thrust Bearing (Independently Mounted-Tapered Land/CW) Checks............. C-46 Sheet #38: Thrust Assembly (Sample) ............................................................................. C-47 Sheet #39: Thrust Bearing Thermocouple Measurements................................................ C-48 Sheet #40: Tilt Pad Bearing Oil Seal Ring and Shaft Dimensions..................................... C-49 Sheet #41: Thrust Cage Oil Seal Rings ............................................................................ C-50 Sheet #42: Bull Gear to Coupling Rabbet Fit Check ......................................................... C-51 Sheet #43: Coupling Eccentricity Runout.......................................................................... C-52 Sheet #44: Rotor Radial Runout Checks .......................................................................... C-53 Sheet #45: Coupling Inspection Checks ........................................................................... C-54 Sheet #46A: Coupling Alignment Data Sheet ................................................................... C-55 Sheet #46B: Rotor Coupling Alignment Check Summary ................................................. C-56 Sheet #47: Rotor Radial Position – Tight Wire vs. Shaft ................................................... C-57 Sheet #48: Oil Bore Radial Position.................................................................................. C-58 Sheet #49: Gland Bore Radial Position ............................................................................ C-59 Sheet #50: Rotor (Axial) Position Data ............................................................................. C-60 Sheet #51: Rabbet Fit of the No. 1 Coupling (Sample) ..................................................... C-61 Sheet #52: Rabbet Fit of the No. 2 Coupling (Sample) ..................................................... C-62 Sheet #53: Coupling Bolt Assembly Data ......................................................................... C-63 Sheet #54: Oil Deflector Check ........................................................................................ C-64

C-2

Data Sheets

Sheet #55: Oil Rings ........................................................................................................ C-65 Sheet #56: Rotor Oil Seal/Deflector Clearances (Sample)................................................ C-66 III. Cylinders, Shells, Rotors, and Blade Ring Dimensional Data Sheet #57: Cylinder Support Block and Liner Clearances................................................. C-67 Sheet #58: IP Turbine Inner Cylinder Bore Diameters ...................................................... C-68 Sheet #59: Bolt Stretch Chart ........................................................................................... C-69 Sheet #60: HP Cylinder Flange/Steam Line Flange.......................................................... C-70 Sheet #61: HP Inlet Steam Flange Bolt Stretch (Sample)................................................. C-71 Sheet #62: IP Turbine and Inner Cylinder Sleeve/Bore Diameter (Sample) ...................... C-72 Sheet #63: LP Inner Cylinder Bolting and Half Joint Layout (Sample) .............................. C-73 Sheet #64: Nozzle Inlet Ring Clearances ......................................................................... C-74 Sheet #65: HP Turbine Elevation Block Clearance (Sample)............................................ C-75 Sheet #66: IP Rotor Dimensions (Sample) ....................................................................... C-76 Sheet #67: HP Cylinder Feeler Gauge Readings (Sample) .............................................. C-77 Sheet #68: IP Rotor Runout (Sample) .............................................................................. C-78 Sheet #69: IP Cylinder No. 1 Blade Ring Dimensions (Sample) ....................................... C-79 Sheet #70A: IP Blade Ring Dimensions (Sample) ............................................................ C-80 Sheet #70B: IP Blade Ring Dimensions (Sample) – cont.................................................. C-81 Sheet #71: IP Rotor Dimensions (Sample) ....................................................................... C-82 IV. Controls and Front Standard Mechanisms Sheet #72: Main Operating Cylinder ................................................................................. C-83 Sheet #73: Pilot Valve Assembly...................................................................................... C-84 Sheet #74: Governor Drive ............................................................................................... C-85 Sheet #75: Speed Relay................................................................................................... C-86 Sheet #76: Pilot Valve and Bushing.................................................................................. C-87 Sheet #77: Pilot Valve Assembly...................................................................................... C-88 Sheet #78: Thrust Bearing Wear Detector ........................................................................ C-89 Sheet #79: Throttle Valve Servomotor.............................................................................. C-90 Sheet #80: Intercept Valve Servo Relays ......................................................................... C-91 Sheet #81: Intercept Valve Servo ..................................................................................... C-92 Sheet #82: Intercept Valve Servo and Test Piston............................................................ C-93 Sheet #83: Intercept Valve Servo Pilot Piston and Guide ................................................. C-94 Sheet #84: Reheat Valve Servo and Pilot Pistons ............................................................ C-95

C-3

Data Sheets

Sheet #85: Reheat Valve Servo Dump and Operating Pistons ......................................... C-96 Sheet #86: Auto Stop Trip Assembly – (Sample).............................................................. C-97 Sheet #87: Load Limit (Low Load) .................................................................................... C-98 Sheet #88: Load Limit (High Load) ................................................................................... C-99 Sheet #89: Auxiliary Governor........................................................................................ C-100 Sheet #90: Main Governor ............................................................................................. C-101 Sheet #91: Governing Valve Servomotor........................................................................ C-102 Sheet #92: Backup Pilot Valve Relay Assembly ............................................................. C-103 Sheet #93: Quill Shaft Inspection Form .......................................................................... C-104 V. Oil Pumps Sheet #94: Main Oil Pump – Simple Suction................................................................... C-105 Sheet #95: Main Oil Pump-Double Suction..................................................................... C-106 Sheet #96: Turbine Shaft Main Oil Pump........................................................................ C-107 Sheet #97: Auxilary Pump-Turbine Driven...................................................................... C-108 Sheet #98: Oil Pump-Motor Driven ................................................................................. C-109 Sheet #99: Oil Pump-Motor Driven ................................................................................. C-110 VI. Main Turbine Valves Sheet #100: Control Valve Stems and Bushings............................................................. C-111 Sheet #101: Control Valve Crossheads and Discs ......................................................... C-112 Sheet #102: Steam Chest Plug Dimensions ................................................................... C-113 Sheet #103: Governor Valve Lift Rods and Bushings ..................................................... C-114 Sheet #104: Governor Valve Seat Elevation................................................................... C-115 Sheet #105: Steam Chest Governor Valve Settings ....................................................... C-116 Sheet #106: Main Stop Valve ......................................................................................... C-117 Sheet #107: Main Stop Valve – Full Arc Bypass Controlled............................................ C-118 Sheet #108: Main Stop Valve – Bypass Type................................................................. C-119 Sheet #109: Throttle Valve/Intercept Valve Clearance (Sample) .................................... C-120 Sheet #110: Throttle Valve Clearance Data (Sample) .................................................... C-121 Sheet #111: Throttle Valve Squareness Check .............................................................. C-122 Sheet #112: Intercept Valve Clearance Data.................................................................. C-123 Sheet #113: Combined Reheat Stop-Intercept Valve...................................................... C-124 Sheet #114: Intercept Valve – Separately Mounted........................................................ C-125 Sheet #115: Intercept Valve – Shell Mounted................................................................. C-126

C-4

Data Sheets

Sheet #116: Reheat Stop Valve – Separately Mounted .................................................. C-127 Sheet #117: Reheat Stop Valve and Servomotor ........................................................... C-128 Sheet #118: Ventilator Valve .......................................................................................... C-129 Sheet #119: Emergency Blowdown Valve ...................................................................... C-130 Sheet #120: Valve Gasket Check................................................................................... C-131 Sheet #121: Screen and Valve Dimensions.................................................................... C-132 Sheet #122: Valve Couplings ......................................................................................... C-133 Sheet #123: Cam Rods .................................................................................................. C-134 Sheet #124: Control Valve Settings (Sample)................................................................. C-135 Sheet #125: Valve Gasket Compression ........................................................................ C-136 Sheet #126: Stem Seal Regulator .................................................................................. C-137 VII. Generator-Exciter Sheet #127: Generator Information – Sheet 1................................................................. C-138 Sheet #128: Generator Information – Sheet 2 ................................................................ C-139 Sheet #129: Hydrogen Seal Oil System Inspection ........................................................ C-140 Sheet #130: Hydrogen Seal Inspection .......................................................................... C-141 Sheet #131: Generator Hydrogen Seal Clearances........................................................ C-142 Sheet #132: Generator Seal Settings ............................................................................. C-143 Sheet #133: Generator Journal Diameters ..................................................................... C-144 Sheet #134: Generator Journal Diameters ..................................................................... C-145 Sheet #135: Hydrogen Gas System Inspection .............................................................. C-146 Sheet #136: Stator Cooling System Inspection............................................................... C-147 Sheet #137: Generator Air Gap Baffle Clearances ......................................................... C-148 Sheet #138: Generator Fan Clearances ......................................................................... C-149 Sheet #139: Blower Blade Clearances ........................................................................... C-150 Sheet #140: Exciter Armature Inspection Form .............................................................. C-151 Sheet #141: Exciter Reduction Gear Bearing and Shaft Dimensions.............................. C-152 Sheet #142: Exciter Bearing Inspection Form................................................................. C-153 Sheet #143: Exciter Pinion Gear Inspection Form .......................................................... C-154 Sheet #144: Exciter Bull Gear Inspection Form .............................................................. C-155 Sheet #145: Exciter Oil Seal Inspection Form ................................................................ C-156 Sheet #146: Exciter DC Motor/Generator Gap Inspection .............................................. C-157 Sheet #147: Exciter DC Drop Test Inspection Form ....................................................... C-158 Sheet #148: Exciter Seal to Journal Setting.................................................................... C-159

C-5

Data Sheets

Sheet #149: Generator/Exciter Rotor Seal and Collector Area ....................................... C-160 Sheet #150: Exciter Coupling Alignment Form ............................................................... C-161 VIII. Protective Device and Pre-Operational Checks Sheet #151: Protective Device and Pre-Operational Checks – Sheet 1 .......................... C-162 Sheet #152: Protective Device and Pre-Operational Checks – Sheet 2.......................... C-163 Sheet #153: Protective Device and Pre-Operational Checks – Sheet 3.......................... C-164 IX. Vibration and Balance Sheet #154: Vibration Data Sheets................................................................................. C-165 Sheet #155: Balance Weight Locations .......................................................................... C-166

C-6

Data Sheets Sheet #1: “N” Wheel Clearance Record Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________

Readings Taken By ________________________ Reviewed by Foreman ______________________ Outage Supervisor_________________________ Reviewed by O.E.M. ________________________ Outage Engineer __________________________

Date __________________ Turbine Serial No._________________________ Prepared by Sta. No

Left Side of Turbine 1L

2

3

4

Recheck

Right

1L

1R

Sta. No.

Date Date Date Date Date

_______________

Left Side of Turbine 1L

A

A

E

E

D

D

A

A

E

E

D

D

A

A

E

E

D

D

A

A

E

E

D

D

A

A

E

E

D

D

A

A

E

E

D

D

A

A

E

E

D

D

A

A

E

E

D

D

A

A

E

E

D

D

A

A

E

E

D

D

2

3

_____________ _____________ _____________ _____________ _____________

4

Recheck

Right

1L

1R

A = Actual, E = Expected, D = Difference

C-7

Data Sheets Sheet #2: Wheel Clearance Record with Twist and Variation Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



2

E N

A E

R

A E

S

A E

N

A E

J

A E

N

A E

J

A E

N

A E

J

A E

N

A E

J

A E

N

A E

J

A E

N

A E

J

A

E = Expected, A = Actual

C-8

3

4

5

6

7

8

Check 1L

1R

_______________ Max Twist

Exp. Twist

1L

Right

Max. Variation

Clear

Sta.

Clearance on Left Side of Turbine

Exp. Variation

Date __________________ Turbine Serial No._________________________ Prepared by

_____________ _____________ _____________ _____________ _____________

-

+

Data Sheets Sheet #3: Turbine Generator Alignment Record – Tops Off Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

C-9

Data Sheets Sheet #4: Turbine Generator Alignment Record – Tops On Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



C-10


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #5: Bolted Diaphragm Drop, Level, and Side Slip Check Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




Stage

Actual Drop Left Right Mils Mils

Lower Half Levelness Diameter Level Tol Inch Mils/Inch

_____________ _____________ _____________ _____________ _____________

_______________

Side Slip Actual Tol

C-11

Data Sheets Sheet #6: “Barn Door” Latch Diaphragm – Axial Crush Pin Clearances Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




Turbine Stage

_______________

Crush Pin Location 1 Slot(S) Diap(D) Clearance Slot(S) Diap(D) Clearance Slot(S) Diap(D) Clearance Slot(S) Diap(D) Clearance Slot(S) Diap(D) Clearance Slot(S) Diap(D) Clearance Slot(S) Diap(D) Clearance

C-12

_____________ _____________ _____________ _____________ _____________

2

Bottom 3

4

5

6

7

Top 8

9

10

Data Sheets Sheet #7A: Spill Strip and Diaphragm Packing Clearance Data Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

Note: See Sheet 7B.

C-13

Data Sheets Sheet #7B: Spill Strip and Diaphragm Packing Clearance Data Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________


Date __________________ Turbine Serial No._________________________ Prepared by Radial Clearances

Sta. No M

Z-1L

Z-1R

Z-2 L

A E D A E D A E D A E D A E D A E D A E D A E D A E D A E D A = Actual, E = Expected, D = Difference

C-14

Z-2 R

WL


_____________ _____________ _____________ _____________ _____________

_______________ Axial Clearances

WR

RL

RR

X

Y

Z-3

Z-4

XA

FIG(s)

Data Sheets Sheet #8: Rotor Axial Position Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Location

Thrusted to Governor Left

Right


_____________ _____________ _____________ _____________ _____________

_______________

Thrusted to Generator Left

Right

Comments

C-15

Data Sheets Sheet #9: HP Rotor Axial Position Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Comments

C-16


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #10: Steam Packing Butt Clearances Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________


Date __________________ Turbine Serial No._________________________ Prepared by Sta. No.

Ring No.

Top Left

Bottom Right

Left

Right

Clearances Left

Right


_____________ _____________ _____________ _____________ _____________

_______________ Machined Left

Right

Comments

C-17

Data Sheets Sheet #11: Steam Packing Wear Measurements Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Sta. No.

C-18

Ring. No.

X

Y

Radial Left Right

1

2


_____________ _____________ _____________ _____________ _____________

_______________

Packing Ring Height (Ht) 3 4 5 6

7

8

Data Sheets Sheet #12A: Diaphragm Clearance Record Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



_____________ _____________ _____________ _____________ _____________

TB Section ___________________________ Date __________________ Turbine Serial No._________________________ Prepared by

_______________

Note: See Sheets 12B and 12C.

C-19

Data Sheets Sheet #12B: Diaphragm Clearance Record Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



_____________ _____________ _____________ _____________ _____________

TB Section ___________________________ Date __________________ Turbine Serial No._________________________ Prepared by Sta. No

Wheel Discharge Side Clearances P

A

B

C

E A D E A D E A D E A D E A D E A D E A D E A D E A D E A D A = Actual, E = Expected, D = Difference

C-20

D

E

_______________

Wheel Admission Side Clearances G

H

I

J

K

L

L'L

L'R

V

Data Sheets Sheet #12C: Diaphragm Clearance Record with Z and W Clearances Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Date __________________ Turbine Serial No._________________________ Prepared by Sta.

XA

P

A

D

ZL

ZR

WL

WR

V

H

K

L'L

_____________ _____________ _____________ _____________ _____________

_______________ L'R

L

M

E A D E A D E A D E A D E A D E A D E A D E A D E A D E A D A = Actual, E = Expected, D = Difference

C-21

Data Sheets Sheet #13: Interstage Packing Clearance Wear Measurements Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Date __________________ Turbine Serial No._________________________ Prepared by Sta. No.

C-22

Ring No.

X

Y

Radial Left

Right

_____________ _____________ _____________ _____________ _____________

_______________

Packing Ring Height (Ht) 1

2

3

4

5

6

7

8

Data Sheets Sheet #14: Shell Arm Elevation Keys as Miked Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

High Pressure L.S. Gov. End

R.S. Gov. End

1 2 3 4 5 6 SHIM

1 2 3 4 5 6 SHIM L.S. Gov. End

R.S. Gov. End

1 2 3 4 5 6 SHIM

1 2 3 4 5 6 SHIM Intermediate Pressure L.S. Gov. End

1 2 3 4 5 6 SHIM

R.S. Gov. End 1 2 3 4 5 6 SHIM

C-23

Data Sheets Sheet #15: LP Steam Gland Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




Left Side ROW Gov End Outer Gland

A

B

1 2 3

Gov End Inner Gland

4 5 6 7

Gen End Inner Gland

8 9 10

Gen End Outer Gland

11 12

Note: Packing is to be wedged in direction of steam flow.

C-24

_____________ _____________ _____________ _____________ _____________

_______________

Right Side X

Y

A

B

X

Y

Data Sheets Sheet #16: Rotor and Water Gland Dimensions Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Gland No.

A

B

C

D


_____________ _____________ _____________ _____________ _____________

_______________

E

C-25

Data Sheets Sheet #17: Water Gland Clearances Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




No.

C-26

AL

AR

BL

BR

CL

CR

DL

DR

EL

ER

FL

FR

GL

_____________ _____________ _____________ _____________ _____________

_______________

GR

HL

HR

Data Sheets Sheet #18: LSB Radial Tip Clearances Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

Radial Clearance Blade No.

Gov. End

Blade No.

Gen. End

Top Bottom R.S. – Above Joint R.S. – Below Joint L.S. – Above Joint L.S. – Below Joint

C-27

Data Sheets Sheet #19: Axial/Radial Clearances – Curtis Blades Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




Radial DIM

Gen. L

Gen. R

Gov. L

Gov. R

DIM

Gen. L

Gen. R

DIM

I

Q

B

J

R

C

K

S

D

M

T

E

N

U

F

O

V

G

P

W

C-28

_______________

Axial

A

H

_____________ _____________ _____________ _____________ _____________

Gen. L

Gov. R

Data Sheets Sheet #20: Reaction Blade Clearances Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

Section ________ Spindle Set with K Dimension of _______ Spindle End Mic. _______

ROW

AL

AR

BL

BR

EL

ER

FL

FR

LL

LR

ML

MR

SL

SR

TL

TR

C-29

Data Sheets Sheet #21: Turbine Dummy Seal Clearances Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Date __________________ Turbine Serial No._________________________ Prepared by Actuals Left Side Position

C-30

Ring No.

Gov. X

Gen. Y

Radial*

_____________ _____________ _____________ _____________ _____________

_______________

Actuals Right Side Gov. X

Gen. Y

Radial*

Expected Gov. X

Gen. Y

Radial*

Data Sheets Sheet #22: Packing Gland Dimensions (Sample) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Packing/Gland Location #1 Outer #2 Outer #1 Inner #1 Inner #1 Inner #1 Inner #1 Inner #1 Inner #1 Inner HP Dummy HP Dummy HP Dummy HP Dummy HP Dummy HP Dummy HP Dummy HP Dummy LP Dummy LP Dummy LP Dummy LP Dummy LP Dummy #2 Inner #2 Inner #2 Inner #2 Inner #2 Inner #2 Inner #2 Outer #2 Outer #3 Outer #3 Outer #3 Inner #3 Inner #3 Inner #3 Inner #4 Inner #4 Outer #4 Outer #5 Outer #5 Outer #5 Inner #6 Inner #6 Outer #6 Outer

Row

A

B

C

D

E

F

Avg.


_____________ _____________ _____________ _____________ _____________

_______________

Shaft Diameter

Clear.

1 2 1 2 3 4 5 6 7 1 2 3 4 5 6 7 8 9 10 11 12 13 8 9 10 11 12 13 1 2 1 2 1 2 3 4 1 1 2 1 2 1 1 1 2

C-31

Data Sheets Sheet #23: Inboard Pedestal Base Plate Gibb Key Clearances Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



C-32


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #24: Coupling Half to Pedestal – Axial Position Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

C-33

Data Sheets Sheet #25: Assembled Coupling – Axial Position Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



C-34


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #26: Bearing Ring to Housing Check Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

C-35

Data Sheets Sheet #27: Turning Gear (Sample) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Comments

C-36


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #28: Journal Bearing Clearance and Pinch Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_______________

Inspections & Checks Ball Contact Check Ball Pinch Check Ball Torque Check Twist & Tilt Check Bearing Inspection Journal Inspection Babbit Inspection Bearing Number

Bearing Type

______ ______ ______ ______ ______ ______ ______

A-Dia.

B-Dia.

Code

Screen & Orifices Thermocouples Calib.

Forward or Turbine End C-Dia.

_____________ _____________ _____________ _____________ _____________

____ ___ ____ ____ ____ ____ ____

Aft or Generation End A-Dia.

B-Dia.

C-Dia.

X – Work Carried Out N – Not Done NA – Not Applicable V – Visual Inspection MP – Mag. Particle UT – Ultrasonic PT - Penetrant Journal Diameter

Shim Thickness

Lead Wire Size

C-37

Data Sheets Sheet #29: Bearing Tilt/Twist Checks Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

Tilt = OV – IV –OT + IT Bearing Number

OV

IV

OT

IT

Limits .0000 TO

Actual

Bearing Number

1

7

2

8

3

9

4

10

5

11

6

OV

IV

OT

Limits .0000 TO

Actual

12 Twist (Initial) = (OL – IL + IR – OR)/2

Bearing Number

OL

IL

IR

OR

Limits + or -

Twist (Recheck) Actual

Bearing Number

1

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

11

11

12

12

C-38

IT

OL

IL

IR

OR

Limits + or -

Actual

Data Sheets Sheet #30: Bearing Load Test Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Indicator Reading


_____________ _____________ _____________ _____________ _____________

_______________

Weight (lbs)

+0.000 +0.005 +0.010 +0.010 +0.005 +0.000 -0.005 -0.010 -0.010 -0.005 +0.000

C-39

Data Sheets Sheet #31: Bearing Fillet Clearances Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Bearing Number 1 2 3 4 5 6 7 8

C-40

A

B

C


_____________ _____________ _____________ _____________ _____________

_______________

D

Data Sheets Sheet #32: Journal Dimensions Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________


No. _________ Bearing Position A

0 Deg.

90 Deg.


_____________ _____________ _____________ _____________ _____________

No. _________ Bearing Diff.

Position

0 Deg.

90 Deg.

Diff.

A

B

B

C

C

D

D

E

E

F

F

G

G

H

H

I

I

J

J

K

K

L

L

M

M

N

N

O

O

P

P

Q

Q

R

R

Taper

Taper

*Average

*Average

C-41

Data Sheets Sheet #33: Bearing Orifice Inspection Checks Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Bearing No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

C-42

Orifice Size

Comments


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #34: Thrust Bearing (Overhung) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




Inspections & Checks Ball Contact Check Ball Pinch Check Ball Torque Check Parallelism Check Thrust Plate Inspection Collar to Shaft Fit Check Thrust Nut Torque

______ ______ ______ ______ ______ ______ ______

Check Threads on Rotor Babbitt Inspection Runner Inspection Wear Device Inspection Screens & Orifices Thermocouples Calib.

_____________ _____________ _____________ _____________ _____________

_______________

Code ____ ___ ____ ____ ____ ____ ____

X – Work Carried Out N – Not Done NA – Not Applicable C – See Comments V – Visual Inspection MP – Mag. Particle UT – Ultrasonic PT - Penetrant

Thrust Bearing Data A Shim B Plate C Shim D Plate E Runner T Total

F Casing T Total (F Minus T) Clearance (By Float) Clearance

Wear Device G Shim H Shim

Ball Torque (Ft-Lb)

C-43

Data Sheets Sheet #35: Thrust Bearing (Straddle) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




Inspections & Checks Ball Contact Check Ball Pinch Check Ball Torque Check Parallelism Check Thrust Plate Inspection Babbitt Inspection

______ ______ ______ ______ ______ ______

_____________ _____________ _____________ _____________ _____________

_______________

Code

Runner Inspection Wear Device Inspection Screens & Orifices Thermocouples Calib.

____ ____ ____ ____ ____


Thrust Bearing Data A Shim B Plate C Shim D Plate E Casing T Total

F Rotor T Total (F Minus T) Clearance (By Float) Clearance

Runout (.0005 TIR)

Seal Rings

G H

Turbine End Seal Diam. (J) Rotor Diam. (K)

Ball Torque (Ft-Lb)

C-44

Clearance

Generator End

Data Sheets Sheet #36: Thrust Bearing (Independently Mounted-Tapered Land/CCW) Checks Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

Land 1

2

3

4

5

6

7

8

9

10

11

12

OD

A B C D E Mean F G H J K ID L M N P Q Land has Thermocouple (Yes/No) Percent* *Actual width of land (flat) in percent of total land width.

C-45

Data Sheets Sheet #37: Thrust Bearing (Independently Mounted-Tapered Land/CW) Checks Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

Land 1 OD

2

3

4

5

A B C D E Mean F G H J K ID L M N P Q Land has Thermocouple (Yes/No) Percent* *Actual width of land (flat) in percent of total land width.

C-46

6

7

8

9

10

11

12

Data Sheets Sheet #38: Thrust Assembly (Sample) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

Thrust at Disassembly Thrust at Assembly Stack Check, Gov. Side Stack Check, Gen. Side Thrust Cage Movement A Position Readings

B Position Readings

C Position Readings

1 2 3 4 5 6

C-47

Data Sheets Sheet #39: Thrust Bearing Thermocouple Measurements Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Time*

RPM

Load (MW)

Thrust Thermocouple Temperatures (F) Turbine End

Generator End


_____________ _____________ _____________ _____________ _____________

_______________

Thrust Oil Temperatures (F) Inlet

Turb Drain

Gen Drain

*Fifteen Minute Increments

Comments: ____________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________

C-48

Data Sheets Sheet #40: Tilt Pad Bearing Oil Seal Ring and Shaft Dimensions Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Shaft Diameter

Seal Diameter


_____________ _____________ _____________ _____________ _____________

_______________

Measured Clearance

Design

(average seal average shaft)

0 Deg.

90 Deg.

Average

A

B

C

Average

Clearance

Clearance

#1 Gov #1 Gen #2 Gov #2 Gen

C-49

Data Sheets Sheet #41: Thrust Cage Oil Seal Rings Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




Axial Clearance Seal

Thrust Cage Groove Width Left Side

L/H Helix Gov. End R/H Helix Gen. End

C-50

Right Side

Right Side

_______________

Radial Clearance

Thickness of Oil Seal Ring Left Side

_____________ _____________ _____________ _____________ _____________

O.D. Shaft Diam. Clr.

A

B

I.D. Oil Seal Ring C

A

B

C

Clr.

Data Sheets Sheet #42: Bull Gear to Coupling Rabbet Fit Check Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

Turbine End Diameter of Male Fit Diameter of Female Fit

Generator End Diameter of Male Fit Diameter of Female Fit

C-51

Data Sheets Sheet #43: Coupling Eccentricity Runout Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



B Turbine End Coupling

C Generator End Coupling

Difference

Bolt #

A Turbine End Journal


_____________ _____________ _____________ _____________ _____________

_______________

B Generator End Journal

Difference

Comments: ____________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________

C-52

Data Sheets Sheet #44: Rotor Radial Runout Checks Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Date __________________ Turbine Serial No._________________________ Prepared by Rotor Identification _________________

_____________ _____________ _____________ _____________ _____________

_______________

Notes: 1. Mark positions 1-8 to agree with stamped degree marks on rotor as shown in Figure 1. 2. Set indicator to 0 at number 1 position. 3. Indicate both journals and five planes along body (between stages) of each rotor. See Figures 2, 3, and 4.

Rotor Checked:

In Unit Out of Unit

Check which end of rotor is at face plate if placed in lathe

Turbine Generator

Describe location of rotor supports

Turbine End ____________________ Generator End ____________________

Area Indicated Journal or Stage No.

Position Numbers 1 0°

2 45°

3 90°

4 135°

5 180°

6 225°

7 270°

8 315°

1 0°

A B C D E F G H J K L M N P

C-53

Data Sheets Sheet #45: Coupling Inspection Checks Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________


Date __________________ Turbine Serial No._________________________ Prepared by Rotor Identification _________________


_____________ _____________ _____________ _____________ _____________

_______________

Notes: 1. For radial runouts, set indicator to read “0” at the number 1 position. 2. Mark positions 1–8 to agree with stamped degree marks on rotor as shown in Figure 1.

Check which coupling

Turbine End Generator End

Position Numbers Area Indicator

1 0°

2 45°

1 0°

2 45°

3 90°

4 135°

5 180°

6 225°

7 270°

8 315°

1 0°

8 315°

1 0°

TE Journal GE Journal Coupling Periphery (A) Coupling Bolt Face (B) Coupling Back Face (C) Coupling Rabbet (D) Coupling Hub Dia. (E) Thrust Runner Runout Check (if applicable) Area Indicated

3 90°

4 135°

5 180°

TE Journal GE Journal

Location Coupling Face Flatness (B) Coupling Rabbet Dia. (D) Coupling Rabbet Depth (F)

C-54

Actual

Coupling Dimensional Check Comments

6 225°

7 270°

Data Sheets Sheet #46A: Coupling Alignment Data Sheet Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

C-55

Data Sheets Sheet #46B: Rotor Coupling Alignment Check Summary Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



C-56


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #47: Rotor Radial Position – Tight Wire vs. Shaft Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

Turbine Section _______________________

Location

ERAG Reading

Ideal Rotor Position

Shaft Readings

C-57

Data Sheets Sheet #48: Oil Bore Radial Position Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Comments:

C-58


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #49: Gland Bore Radial Position Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

Comments:

C-59

Data Sheets Sheet #50: Rotor (Axial) Position Data Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




Instrument

Travel forward From K

Travel Aft from K

_____________ _____________ _____________ _____________ _____________

_______________

Total Travel

Dial Indicator Mic Plate K Ref Bearing Fillet

NOTE: Thrust bearing disassembled.

Limiting Factor Forward from K Limiting Factor Aft from K

K MIC Plate Bearing Fillet

C-60

Location:

Turbine

Data Sheets Sheet #51: Rabbet Fit of the No. 1 Coupling (Sample) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

HP End Diameter of Male Fit Diameter of Female Fit

IP End Diameter of Male Fit Diameter of Female Fit

C-61

Data Sheets Sheet #52: Rabbet Fit of the No. 2 Coupling (Sample) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



C-62


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #53: Coupling Bolt Assembly Data Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

Coupling _________________________

Stud Hole

Coupling Hole Diameter TB. Side

Gear Spacer

Gen. Side

Stud Diameter

Clearance TB. Side

Gear Spacer

Gen. Side

1 (M) 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32

C-63

Data Sheets Sheet #54: Oil Deflector Check Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




Inspections & Checks Teeth Inspected Journals Inspected

Deflector Number

C-64

___ ___ ___ ___ ___ ___ ___

Forward or Turbine End B-Dia.

C-Dia.

_______________

Code

______ ______ ______ ______ ______ ______ ______

A-Dia.

_____________ _____________ _____________ _____________ _____________

Aft or Generator End A-Dia.

B-Dia.

C-Dia.

X – Work Carried Out N – Not Done NA – Not Applicable V – Visual Inspection MP – Mag. Particle UT – Ultrasonic PT - Penetrant

Journal Diameter

Vertical Clear

Data Sheets Sheet #55: Oil Rings Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




Inspections & Checks Teeth Inspected Journals Inspected

Deflector Number

___ ___ ___ ___ ___ ___ ___

Forward or Turbine End B-Dia.

C-Dia.

_______________

Code

______ ______ ______ ______ ______ ______ ______

A-Dia.

_____________ _____________ _____________ _____________ _____________

Aft or Generator End A-Dia.

B-Dia.

C-Dia.

X – Work Carried Out N – Not Done NA – Not Applicable V – Visual Inspection MP – Mag. Particle UT – Ultrasonic PT - Penetrant

Journal Diameter

Vertical Clear

C-65

Data Sheets Sheet #56: Rotor Oil Seal/Deflector Clearances (Sample) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Ring Location

C-66

Top

Bottom

Right Side

Left Side


_____________ _____________ _____________ _____________ _____________

_______________

Design Radial Clearance

Data Sheets Sheet #57: Cylinder Support Block and Liner Clearances Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Component

A

B

C

D


_____________ _____________ _____________ _____________ _____________

_______________

Design Clearance

Clearance

C-67

Data Sheets Sheet #58: IP Turbine Inner Cylinder Bore Diameters Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



C-68


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #59: Bolt Stretch Chart Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




Location

Bolt No.

Bolt Free Length

Req’d Stretch

Cold MIC Measure

Cold Full MIC Reading

Amount to Turn (Deg.)

Amount to Turn (Flats)

Stretch Measure

Total Stretch

_____________ _____________ _____________ _____________ _____________

_______________

Deg. Turned to Correct

Final Measure

Final Stretch

C-69

Data Sheets Sheet #60: HP Cylinder Flange/Steam Line Flange Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Steam Lead Gov. Side Left Female A

Male B

Difference

Female A Top

Bot

Bot

Gov

Gov

Gen

Gen Steam Lead Gen. Side Left Male B

_______________

Male B

Difference

Steam Lead Gen. Side Right Difference

Female A

Top

Top

Bot

Bot

Gov

Gov

Gen

Gen

C-70

_____________ _____________ _____________ _____________ _____________

Steam Lead Gov. Side Right

Top

Female A


Male B

Difference

Data Sheets Sheet #61: HP Inlet Steam Flange Bolt Stretch (Sample) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Bolt

Free Length


_____________ _____________ _____________ _____________ _____________

_______________

Cold Length

Heat Stretch

Total Stretch

Cold Length

Heat Stretch

Total Stretch

1 2 3 4 5 6 7 8

Side

Desired Stretch Amount

Bolt

Free Length

1 2 3 4 5 6 7 8

Number of Nuts Replaced Number of Bolts Replaced

C-71

Data Sheets Sheet #62: IP Turbine and Inner Cylinder Sleeve/Bore Diameter (Sample) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

Left – 0 Deg.

Left – 90 Deg.

Right – 0 Deg.

Right – 90 Deg.

Left – 0 Deg.

Left – 90 Deg.

Right – 0 Deg.

Right – 90 Deg.

A B C

A B C

C-72

Data Sheets Sheet #63: LP Inner Cylinder Bolting and Half Joint Layout (Sample) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

C-73

Data Sheets Sheet #64: Nozzle Inlet Ring Clearances Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________

Ring Location

C-74


A


B

_____________ _____________ _____________ _____________ _____________

Data Sheets Sheet #65: HP Turbine Elevation Block Clearance (Sample) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

C-75

Data Sheets Sheet #66: IP Rotor Dimensions (Sample) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________ Outside Diameter 0 90

1C 1R 2C 2R 3C 3R 4C 4R 5C 5R 6C 6R 7C 7R 8C 8R 9C 9R 10C 10R 11C 11R 12C 12R 13C 13R 14C 14R 15C 15R 16C 16R 17C 17R 18C 18R 19C 19R 20C 20R 21C 21R 22C 22R 23C 23R

C-76

Data Sheets Sheet #67: HP Cylinder Feeler Gauge Readings (Sample) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

C-77

Data Sheets Sheet #68: IP Rotor Runout (Sample) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Date __________________ Turbine Serial No._________________________ Prepared by Zero’s No. 1 Bolt Hole 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 As Received Final

C-78

0

45

90

135

_____________ _____________ _____________ _____________ _____________

_______________

180

225

270

315

Data Sheets Sheet #69: IP Cylinder No. 1 Blade Ring Dimensions (Sample) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

C-79

Data Sheets Sheet #70A: IP Blade Ring Dimensions (Sample) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



C-80


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #70B: IP Blade Ring Dimensions (Sample) – cont. Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

C-81

Data Sheets Sheet #71: IP Rotor Dimensions (Sample) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



C-82


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #72: Main Operating Cylinder Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




Inspections & Checks Dimensional Checks Ball and Socket Inspection Ring Inspection Housing Inspection Pilot Valves and Bushing

______ ______ ______ ______ ______ ______ ______

_____________ _____________ _____________ _____________ _____________

_______________

Code ____ ___ ____ ____ ____ ____ ____


Comments

C-83

Data Sheets Sheet #73: Pilot Valve Assembly Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Main Operating Cylinder Front Standard

Comments

C-84


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #74: Governor Drive Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Date __________________ Turbine Serial No._________________________ Prepared by Inspections & Checks Governor Worm & Gear ______ Pre-Emerg. Gov. Worm & Gear ______ Gov. Gear Drive Assembly ______ Pre-Emerg. Gov. Gear Drive Asm. ______ Gov. Shaft and Bearings ______ Pre-Emerg. Gov. Shaft & Bearings ______ Main Gears (BFP Drive Front End) ______ Main Gear Bearings (BFP Drive Front End) ______ Gov. Worm Bearings ______

Tach. Gen. Assembly Shaft Extension Pad Bearing Check Piping Connections Tooth Contact Backlash* Pinion Spline Condition Oil Passages Worm Alignment

_____________ _____________ _____________ _____________ _____________

_______________ Code

____ ___ ____ ____ ____ ____ ____ ____ ____ ____


Drive Shaft Clearances Measurement D*

Backlash

E

Bushing ID

Gov. Drive Shaft

Pre-Em. Gov. Drive Sh.

Shaft OD Clearance F

Bushing ID Shaft OD Clearance

G

Thrust Clearance

C-85

Data Sheets Sheet #75: Speed Relay Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Comments

C-86


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #76: Pilot Valve and Bushing Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




Inspections & Checks Speed Governor & PV Speed Gov. Bushing & Housing Bore Pre-Emerg. Gov. & PV Assm. Pre-Emerg. Gov. Bushing & Housing Bore Backup Gov. PV & Bushing

______ ______ ______ ______ ______

_____________ _____________ _____________ _____________ _____________

_______________

Code ____ ___ ____ ____ ____ ____ ____


C-87

Data Sheets Sheet #77: Pilot Valve Assembly Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Comments

C-88


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #78: Thrust Bearing Wear Detector Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Notes:


_____________ _____________ _____________ _____________ _____________

_______________

1. Physical damage to nozzles. Yes No 2. Pressure: Increasing _______ Decreasing _______ 3. Rotor thrusted __________________

Orifice Size A Orifice Size B P.S. Setting Inactive

PSI

P.S. Setting Active

PSI

X Dim. Y Dim.

C-89

Data Sheets Sheet #79: Throttle Valve Servomotor Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



C-90


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #80: Intercept Valve Servo Relays Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

Right Side Left Side

Gov. Relay A

Trip Relay

Cyl. Sleeve I.D. Valve O.D. Clearance

B

Cyl. Sleeve I.D. Valve O.D. Clearance

C-91

Data Sheets Sheet #81: Intercept Valve Servo Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



C-92


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #82: Intercept Valve Servo and Test Piston Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

Comments

C-93

Data Sheets Sheet #83: Intercept Valve Servo Pilot Piston and Guide Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Comments

C-94


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #84: Reheat Valve Servo and Pilot Pistons Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

Comments

C-95

Data Sheets Sheet #85: Reheat Valve Servo Dump and Operating Pistons Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Comments

C-96


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #86: Auto Stop Trip Assembly – (Sample) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

C-97

Data Sheets Sheet #87: Load Limit (Low Load) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



C-98


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #88: Load Limit (High Load) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

C-99

Data Sheets Sheet #89: Auxiliary Governor Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



C-100


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #90: Main Governor Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

C-101

Data Sheets Sheet #91: Governing Valve Servomotor Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



C-102


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #92: Backup Pilot Valve Relay Assembly Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

C-103

Data Sheets Sheet #93: Quill Shaft Inspection Form Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



1 Diam. TIR

Comments

C-104

2

3

4

5


_____________ _____________ _____________ _____________ _____________

_______________

6

7

Data Sheets Sheet #94: Main Oil Pump – Simple Suction Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




Inspections & Checks

_____________ _____________ _____________ _____________ _____________

_______________

Code

Mechanical Condition

______

______

X – Work Carried Out

Internal Clearances

______

______

N – Not Done

Ring Condition and Clearance

______

NA – Not Applicable

______

______

C – See Comments

______

V – Visual Inspection

______

MP – Mag. Particle

______

UT – Ultrasonic

______

PT - Penetrant

______ ______ ______ ______ ______

______

______

C-105

Data Sheets Sheet #95: Main Oil Pump-Double Suction Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Date __________________ Turbine Serial No._________________________ Prepared by Inspections & Checks

_____________ _____________ _____________ _____________ _____________

_______________ Code


______

______


Internal Clearances

______

______

N – Not Done

Bearing Condition and Clearance

______


______

______

C – See Comments

Steady Bearing Force and Movement Checks

______

______


______

______


______

______

UT – Ultrasonic

______

______

PT - Penetrant

C-106

Data Sheets Sheet #96: Turbine Shaft Main Oil Pump Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



A

Seal Ring L.H. Helix

B

Seal Ring R.H. Helix

C

Seal Ring L.H. Helix

D

Seal Ring R.H. Helix

E

Gov. Impeller Sleeve Turb. End. R.H. Helix Gov. Impeller Sleeve Gov. End. L.H. Helix R/S L/S R/S L/S R/S L/S R/S L/S R/S L/S R/S L/S R/S L/S R/S L/S R/S L/S R/S L/S R/S L/S R/S L/S R/S L/S R/S L/S R/S L/S

F H I J K L M N O P Q R S T U


_____________ _____________ _____________ _____________ _____________

_______________

I.D. O.D Clear. I.D. O.D. Clear. I.D. O.D. Clear. I.D. O.D. Clear. I.D. O.D. Clear. I.D. O.D. Clear.

Stub Shaft Runout

C-107

Data Sheets Sheet #97: Auxilary Pump-Turbine Driven Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________





_____________ _____________ _____________ _____________ _____________

_______________

Code


______

______


Internal Clearances

______

______

N – Not Done

Bearing Condition

______

______


______

______

C – See Comments

______

______


______

______


______

______

UT – Ultrasonic

______

______

PT - Penetrant

______

______

C-108

Data Sheets Sheet #98: Oil Pump-Motor Driven Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



_____________ _____________ _____________ _____________ _____________

C-109

Data Sheets Sheet #99: Oil Pump-Motor Driven Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________





_____________ _____________ _____________ _____________ _____________

_______________

Code

Impeller Inspection

______

Bearing Inspection

______


Wear Ring Inspection

______

Coupling Checked

______

N – Not Done

______

______


______

______

C – See Comments

______

______


______

______


______

______

UT – Ultrasonic

______

______

PT - Penetrant

______

______

Type: ____________________________ (TGOP, MSP, EBOP, etc.)

Bearing Clearance

A

B

C

D

Bearing ID Journal ID Clearance Thrust Wear Ring Clearance Wear Ring ID Impeller OD Clearance

C-110

Data Sheets Sheet #100: Control Valve Stems and Bushings Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________





_____________ _____________ _____________ _____________ _____________

_______________

Code

Disc Inspection

______

______


Stem Inspection

______

______

N – Not Done

Bushing Inspection

______

______


Stud Inspection

______

______

C – See Comments

Nut Inspection

______

______


Body Inspection

______

______


______

______

UT – Ultrasonic

______

______

PT - Penetrant

Note: Stem and bushing diameters should be recorded both before and after cleaning. Try bar diameters must be recorded. Valve Clearances

Valve No. _______ Try Bar Dia. _______ Valve No. _______ Try Bar Dia. _______ Valve No. _______ Try Bar Dia. _______ Valve No. _______ Try Bar Dia. _______

Before Cleaning

After Cleaning

Before Cleaning

After Cleaning

B

B

E

E

A

C

D

F

Bushing ID Stem OD Clearance Bushing ID Stem OD Clearance Bushing ID Stem OD Clearance Bushing ID Stem OD Clearance

Stem Runout Valve No. Valve No.

C-111

Data Sheets Sheet #101: Control Valve Crossheads and Discs Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________


Code

Seat Inspection

______

______


Disc Inspection

______

______

N – Not Done

Seat Contact Check

______

______


Stand Inspection

______

______

C – See Comments

Stud Inspection

______

______


Nut Inspection

______

______


______

______

UT – Ultrasonic

______

______

PT - Penetrant Crosshead Guide & Bushing Valve No.

No.

No.

No.

Bushing ID Guide OD Clearance Stem to Crosshead Clearance Valve No.

No.

No.

No.

Bushing/ Crosshead ID Stem OD Clearance Valve to Stem Clearance Valve No. Upper Sleeve ID (A) Upper Valve OD (A) Clearance Lower Sleeve ID (B) Lower Valve OD (B) Clearance Lift

C-112

No.

No.

No.

Data Sheets Sheet #102: Steam Chest Plug Dimensions Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________


Left Side 0 Deg. A

Chest I.D.

B

Ring O.D.

Left Side 90 Deg.

Right Side 0 Deg.


Right Side 90 Deg.

_____________ _____________ _____________ _____________ _____________

Design Clearance

Clearance C

Ring I.D.

D

Plug O.D. Clearance

C-113

Data Sheets Sheet #103: Governor Valve Lift Rods and Bushings Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



_____________ _____________ _____________ _____________ _____________

Lift Rod Diameter and Clearance A

D

Clearance

B

C

E

Clearance

Run-out A

Right Side

Gov. End Gen. End

Left Side

Gov. End Gen. End

C-114

B

C

Data Sheets Sheet #104: Governor Valve Seat Elevation Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________

Valve No.


Left Side

Valve No.


_____________ _____________ _____________ _____________ _____________

Right Side

C-115

Data Sheets Sheet #105: Steam Chest Governor Valve Settings Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________


Left Side Valve No.

C-116

Design Valve Travel

Design Valve Travel Adjusted for Seat Elevation


_____________ _____________ _____________ _____________ _____________

Right Side Actual Valve Travel

D Dim.

Valve No.

Design Valve Travel

Design Valve Travel Adjusted for Seat Elevation

Actual Valve Travel

D Dim.

Data Sheets

Sheet #106: Main Stop Valve Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________ Code

Seat Inspection

______

Body Inspection

______


Disc Inspection

______

Strainer Inspection

______

N – Not Done

Seat Contact Check

______

______


Stem Inspection

______

______

C – See Comments

Pressure Seal Head

______

______


Head Inspection

______

______


Stud Inspection

______

______

UT – Ultrasonic

Nut Inspection

______

______

PT - Penetrant

Valve Clearances

Valve No. ______ Try Bar Dia. ______ Valve No. ______ Try Bar Dia. ______

Before Clean

After Clean

Before Clean

After Clean

Before Clean

After Clean

Before Clean

After Clean

B

B

C

C

E

E

H

H

A

B

C

D

E

F

Bushing D Stem OD Clearance Bushing D Stem OD Clearance

Stem Runout Valve No. Valve No.

Bypass Valve Lift

Lift

Valve No. Valve No.

C-117

Data Sheets Sheet #107: Main Stop Valve – Full Arc Bypass Controlled Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________


Date __________________ Turbine Serial No._________________________ Prepared by By-Pass Location A B C

C-118


_____________ _____________ _____________ _____________ _____________

_______________ Valve Lift

Data Sheets Sheet #108: Main Stop Valve – Bypass Type Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

C-119

Data Sheets Sheet #109: Throttle Valve/Intercept Valve Clearance (Sample) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________

C-120



_____________ _____________ _____________ _____________ _____________

Data Sheets Sheet #110: Throttle Valve Clearance Data (Sample) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________


Design Clearance A

Left Valve


_____________ _____________ _____________ _____________ _____________

Right Valve

Bushing I.D. Stem O.D. Clearance

B


C


D


Stem Runout

A

B

C

D

Design

Left Side Right Side

C-121

Data Sheets Sheet #111: Throttle Valve Squareness Check Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________


Left Throttle Valve Left Side Clearances

C-122

Right Side

Gov. End


_____________ _____________ _____________ _____________ _____________

Right Throttle Valve Gen. End

Left Side

Right Side

Gov. End

Gen. End

Data Sheets Sheet #112: Intercept Valve Clearance Data Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________


Design Clearance A

Left Valve As Found


_____________ _____________ _____________ _____________ _____________

Right Valve As Left

As Found

As Left


B


C


Stem Runout

A

B

C

Design


Note: Was Stem Replaced?

Yes No

C-123

Data Sheets Sheet #113: Combined Reheat Stop-Intercept Valve Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Date __________________ Turbine Serial No._________________________ Prepared by Inspections & Checks Body Inspection Head Inspection Stem Inspection - Upper Stem Inspection - Lower Stud Inspection Nut Inspection Main Seat Inspection Intercept Valve Disc Inspection

______ ______ ______ ______ ______ ______ ______ ______


Left Side Valve Valve Clearances Bushing ID

B Try Bar Dia. ________

Bushing ID

D

Bushing ID

_______________ Code

Reheat Stop Valve Disc Inspection ____ Outer Disc Contact Check _______ Inner Disc Contact Check ____ Strainer Inspection ____ Linkage Inspection ____ Equalizer Valve ____ Inspection of Equalizer ____ Valve on #2 CRV ____ Pressure Seal Head ____

L Try Bar Dia. ________

_____________ _____________ _____________ _____________ _____________

Before Cleaning

After Cleaning

Right Side Valve Before Cleaning

After Cleaning

Crosshead OD Clearance Stem OD Clearance Stem OD Clearance

H Try Bar Dia. ________ J

E

Stem Runout Left Side Right Side Stem Length

C-124

Bushing ID Stem OD Clearance Bushing ID Stem OD Clearance Balance Chamber ID Seal Rings OD Clearance Ring Axial Clearance A

C

F

In.

G

I

K

Data Sheets Sheet #114: Intercept Valve – Separately Mounted Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________


Code

Body Inspection

______

Linkage Inspection

Head Inspection

______

Pilot Valve Inspection

Stem Inspection

______

Seat Contact Check

Stud Inspection

____ _______

X – Work Carried Out N – Not Done

____


______

____

C – See Comments

Nut Inspection

______

____


Seat Inspection

______

____


Disc Inspection

______

____

UT – Ultrasonic

Strainer Inspection

______

PT - Penetrant

Left Side Valve Valve Clearances A

Bushing ID

Try Bar Dia. ________

Stem OD

B

Guide Bushing ID

Before Cleaning

After Cleaning


After Cleaning

Clearance

Seal Ring OD Clearance C

Ring Axial Clearance


Bushing ID Stem OD Clearance

D

Bushing ID


Stem OD

E

Bushing ID


Stem OD

Stem Runout Left Side Right Side

Clearance

Clearance A

C

D

E

F

C-125

Data Sheets Sheet #115: Intercept Valve – Shell Mounted Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________


Code

Body Inspection

______

Linkage Inspection

Head Inspection

______

Pilot Valve Inspection

Stem Inspection

______

Seat Contact Check

Stud Inspection

____ _______


____


______

____

C – See Comments

Nut Inspection

______

____


Seat Inspection

______

____


Disc Inspection

______

____

UT – Ultrasonic

Strainer Inspection

______

PT - Penetrant Left Side Valve Valve Clearances

B Try Bar Dia. ________

Bushing ID

D Try Bar Dia. ________

Bushing ID

E

Guide Bushing ID

Before Cleaning

After Cleaning


Stem OD Clearance Stem OD Clearance

Seal Rings OD Clearance Ring Axial Clearance F

Bushing ID


Stem OD

G

Bushing ID


Stem OD

Stem Runout Left Right

C-126

Clearance

Clearance A

C

D

F

After Cleaning

Data Sheets Sheet #116: Reheat Stop Valve – Separately Mounted Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________


Code X – Work Carried Out

Head

______

Pressure Seal Head

____

Body Inspection

______

Rocker Arm Inspection

Stem Inspection

______

____


Stud Inspection

______

____

C – See Comments

Nut Inspection

______

____


Seat Inspection

______

____


Seat Contact Check

______

____

UT – Ultrasonic

Bypass Line Inspection

______

_______

N – Not Done

PT - Penetrant Left Side Valve Valve Clearances

Right Side Valve

Before Cleaning

After Cleaning

Before Cleaning

After Cleaning

C

E

F

G

Bushing ID B Try Bar Dia. ________

Stem OD Clearance Bushing ID

D Try Bar Dia. ________


F Try Bar Dia. ________


G Try Bar Dia. ________

Stem Runout

Stem OD Clearance

A


C-127

Data Sheets Sheet #117: Reheat Stop Valve and Servomotor Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________

C-128



_____________ _____________ _____________ _____________ _____________

Data Sheets Sheet #118: Ventilator Valve Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________ Code

____


Casing Inspection

______

Main Disc Inspection

Head Inspection

______

Internal Disc Inspection

_______

Stud Inspection

______

Piston & Ring Inspection

____


Nut Inspection

______

Air Cylinder Inspection

____

C – See Comments

Stem Inspection

______

Piston Rod Inspection

____


Main Seat Inspection

______

Piston Gasket Inspection

____


Internal Seat Inspection

______

Linkage & Spring Inspection

____

UT – Ultrasonic

N – Not Done

PT - Penetrant

C-129

Data Sheets Sheet #119: Emergency Blowdown Valve Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



C-130


_____________ _____________ _____________ _____________ _____________

_______________

Data Sheets Sheet #120: Valve Gasket Check Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



_____________ _____________ _____________ _____________ _____________

Gasket Thickness Bolts Replaced Valve Body Female Right Side

Valve Cover Male

Difference

Runout

1 2 3 4

Left Side

1 2 3 4

C-131

Data Sheets Sheet #121: Screen and Valve Dimensions Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________


Valve # _________ 0 Deg. A

I.D.

A

O.D.

B

O.D.

C D E

Body

E

Bonnet Plus Screen

C-132

180 Deg.


_____________ _____________ _____________ _____________ _____________

Data Sheets Sheet #122: Valve Couplings Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




Main Stop Left

Intercept Right

Left

_____________ _____________ _____________ _____________ _____________

_______________

Reheat Right

Left

Right

A B C Cylinder Lift Stem Clear

C-133

Data Sheets Sheet #123: Cam Rods Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



_____________ _____________ _____________ _____________ _____________


_______________

Bearing

Bearing

Bearing

Bearing

Bearing

Journal

Journal

Journal

Journal

Journal

Clear

Clear

Clear

Clear

Clear

Bearing

Bearing

Bearing

Bearing

Bearing

Journal

Journal

Journal

Journal

Journal

Clear

Clear

Clear

Clear

Clear

Runout Left to Right at the Bearing Area 1

2

3

4

5

Upper Cam Rod Lower Cam Rod

Comments: ____________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________

C-134

Data Sheets Sheet #124: Control Valve Settings (Sample) Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Date __________________ Turbine Serial No._________________________ Prepared by Valve No. Expected

When This Valve Is

This Valve Is Up .030"

#1

(T)

#2

#2

(B)

#3

#3

(T)

#4

#4

(B)

#5

#5

(B)

#6

#6

(T)

Total Travel

_____________ _____________ _____________ _____________ _____________

_______________

Piston Travel

Roller Clear

As Found As Left Expected As Found As Left Expected As Found As Left Expected As Found As Left Expected As Found As Left Expected As Found As Left Cold Settings Cam Clearances

(T) Top

Pad Clearances

(B) Bottom

Total Piston Stroke

Comments: __________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________

C-135

Data Sheets Sheet #125: Valve Gasket Compression Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



Date __________________ Turbine Serial No._________________________ Prepared by Main Stop Valve Left Right Male Female Male Female 0 90 180 270

_____________ _____________ _____________ _____________ _____________

_______________

Intercept Valve Left Right Male Female Male Female 0 90 180 270

Compression

Compression

Reheat Stop Valve Left Right Male Female Male Female

Control Valves No. 3 No. 4 Male Female Male Female

0 90 180 270

0 90 180 270

Male

Compression

Compression

Control Valves

Control Valves

No. 3 Female

Male

0 90 180 270

No. 4 Female

Male

No. 5 Female

Male

No. 6 Female

0 90 180 270 Compression

Compression

Comments: __________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________

C-136

Data Sheets Sheet #126: Stem Seal Regulator Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

C-137

Data Sheets Sheet #127: Generator Information – Sheet 1 Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

Generator Information Rating _____________ KVA Code __________ Stator No. ____________ Original Service Date _____________ Stator ____________ KV _________ AMPS _________ Max. H2 Press _________________________________ Stator Winding ____________ Slots ____________ Circuits ____________ Insulation

Asphalt

Micaral

Micaral II

Cooling

Conventional

Conductor

Single Pass

Double Pass

Cooling Type

Air

Hydrogen

Oil

Water

Support System

Conventional

Tetraloc

Modified Tetraloc

Blocking

Maple

Textolite

Felt

Ties

Flax.

Glass Cord.

Glass Roving

End Winding

Radius Strips

Sausages

Z-Rings

Series Loops

Liquid Cooled

Wedge

Flat

Split

Camelback

Sidesprings

None

90 Mil

200 Mil

Piggyback

Field No. _______________ Forging No. ______________ Volts _____________ Amps __________________ Speed _________________ RPM _____________________ Poles ___________________________________ Field Cooling

Conventional

Radial

Diagonal

Bushing Cooling

Conventional

Gas

Water

End Winding

Nose Rings

Tee Bolts

Inner Axials

Type of Inspection

Field Removed

Endshelds Removed

C-138

Other

Data Sheets Sheet #128: Generator Information – Sheet 2 Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

Comments Inner Oil Deflector Insulation

_______________________________________________________________

H2 Seal Holder Insulation

_______________________________________________________________

Upper and Lower Bearing Insulation _______________________________________________________________ Outer Oil Deflector Insulation

_______________________________________________________________

Insulated Coupling Insulation

_______________________________________________________________

Previous Vibration Problems in Field _______________________________________________________________

C-139

Data Sheets Sheet #129: Hydrogen Seal Oil System Inspection Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

Codes X – Work Carried Out



N – Not Done

C – See Comments

S – Satisfactory

U - Unsatisfactory

Inspections & Checks High Level Alarm on H2 Detraining Tank

_____

Gauge Calibration

_____

Seal Casing Assembly

_____

System Type:

Relief Valves

____

a.

Vacuum

Liquid Detectors & Alarms

____

b.

Scavenging

Auto Pump Start & Alarm Tests

____

Regulating Valves

____

Joint Clearances

_____

Oil Filters

____

Oil Grooves Clear?

_____

Main Seal Oil Pump

______

Emergency Seal Oil Pump

______

Gas Side Drain Float, Trap and Valve

______

Coolers

____

Vacuum Pump

______

Seal Oil Pressure Gauges at Unit CL

____

Drain Enlargement

______

Position

_____ _____ _____

Seal Measurements (To Nearest .001") Turbine End Collector End Air H2 Air H2

1 2 3 4 5 6 Average Seal Shaft Dia. H2 Seal Spring Measurements Turbine End Collector End Upper Lower Upper Lower Length (In. + 1/16) Wire Diameter Coil Diameter Gradient (#/In) Testing Data: A. Seal Oil Flow B. Hydrogen Pressure C. Unit Speed

C-140

__________ GPM __________ psi __________ RPM

Data Sheets Sheet #130: Hydrogen Seal Inspection Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

C-141

Data Sheets Sheet #131: Generator Hydrogen Seal Clearances Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



_____________ _____________ _____________ _____________ _____________

End Runout Flange Face

Groove Face

Diff.

Groove Width

1

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

9

9

10

10

Ring Width

Diff.

Ring Flatness

Average Clearance

A

B

C

H2 Seal Ring D E

Avg.

Journ.

Row 2 6 3

A

C

Labyrinth Seals D Avg.

Journ.

Clear.

Air Side H2 Side

C-142

Clear.

Data Sheets Sheet #132: Generator Seal Settings Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



_____________ _____________ _____________ _____________ _____________

Labyrinth Seal

Turbine End Clearance Left Side

Bottom

Right Side

A B C

Exciter End Clearance Left Side

Bottom

Right Side

A B C

Note 1 Insulated bolts torque to 368 ft-lbs. Torquing procedure begins on the bottom center/top center bolt and alternates side to side until reaching the horizontal joint. *** Three intervals (passes) should be used to reach the final torque. 1st pass = 100 ft-lbs 2nd pass = 275 ft-lbs 3rd pass = 368 ft-lbs

C-143

Data Sheets Sheet #133: Generator Journal Diameters Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



1

2

3

4


_____________ _____________ _____________ _____________ _____________

_______________

5

A B C

Comments: ____________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________

C-144

Data Sheets Sheet #134: Generator Journal Diameters Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



_____________ _____________ _____________ _____________ _____________

C-145

Data Sheets Sheet #135: Hydrogen Gas System Inspection Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________





_______________

Code

CO2 Supply Disconnection

H2 Supply Disconnection

_____________ _____________ _____________ _____________ _____________


Spool Piece Removal

______

Spool Piece Removal

_______

Bottles Disconnected

______

Bottles Disconnected

____


Purity Meter Calibration

______

____

C – See Comments

Purging Gas Analyzer Calibration ______

____


Annunciator Alarms and Drop to Control Room

____

S – Satisfactory

______

____

U - Unsatisfactory

Fan Differential Press Gauge

______

Calibration of All Gauges

______

Hydrogen Consumption

____

Design

Actual

Prior to Outage Air Test Equivalent Hydrogen Consumption Comments: __________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________

C-146

Data Sheets Sheet #136: Stator Cooling System Inspection Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________





_____________ _____________ _____________ _____________ _____________

_______________

Code

Main Coolant Pumps

______

Conductivity Meter and Cells

____


Reserve Coolant Pumps Start

______

Runback Circuit Verification

____

N – Not Done

Deionizer and Resin

______

Calibration of All Gauges

____


Storage Tank

______

Vacuum Breaker and Relief

____

C – See Comments

Filters and Strainers

______

Valve Operation

____


Coolers

______

System Protective Alarm Circuitry ____

S – Satisfactory

Proportioning Valve

______

Calibration of All Alarm Settings

U - Unsatisfactory

Additional Data:

Initial

____

Final

Water Conductivity

_______________________________________________

Resin Source

_______________________________________________

Resin Batch Number

_______________________________________________

Resin Replacement Data

_______________________________________________

Comments: __________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________ ___________________________________________________________________________________________

C-147

Data Sheets Sheet #137: Generator Air Gap Baffle Clearances Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________

C-148



_____________ _____________ _____________ _____________ _____________

Data Sheets Sheet #138: Generator Fan Clearances Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



_____________ _____________ _____________ _____________ _____________

C-149

Data Sheets Sheet #139: Blower Blade Clearances Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________

Top Left A B C D E F

C-150


Top Right

Bottom Left


_____________ _____________ _____________ _____________ _____________

Bottom Right

Data Sheets Sheet #140: Exciter Armature Inspection Form Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________

1

2


3

4

5

6


7

_____________ _____________ _____________ _____________ _____________

8

Diam. TIR

Comments: ____________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________

C-151

Data Sheets Sheet #141: Exciter Reduction Gear Bearing and Shaft Dimensions Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________


Casing Bore 1A 1B 1C 2A 2B 2C 3A 3B 3C 4A 4B 4C

C-152

BRG. O.D.

Seal Bore

Shaft O.D.

Clear


_____________ _____________ _____________ _____________ _____________

Parts Replaced

Data Sheets Sheet #142: Exciter Bearing Inspection Form Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________

Plane A


Plane B

Plane C


Accept

_____________ _____________ _____________ _____________ _____________

Reject

Inboard Middle Outboard

Comments: ____________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________

C-153

Data Sheets Sheet #143: Exciter Pinion Gear Inspection Form Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________


0 Deg.

90 Deg.

Diameter/Runout

Diameter/Runout

Accept


_____________ _____________ _____________ _____________ _____________

Reject

A B C D E

Comments: ____________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________

C-154

Data Sheets Sheet #144: Exciter Bull Gear Inspection Form Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________


0 Deg.

90 Deg.

Diameter/Runout

Diameter/Runout

Accept


_____________ _____________ _____________ _____________ _____________

Reject

A B C D E

Comments: ____________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________

C-155

Data Sheets Sheet #145: Exciter Oil Seal Inspection Form Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________

Blade Number

Plane A


Plane B

Plane C


Accept

_____________ _____________ _____________ _____________ _____________

Reject

1 2 3 4 Comments: ____________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________

C-156

Data Sheets Sheet #146: Exciter DC Motor/Generator Gap Inspection Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



_____________ _____________ _____________ _____________ _____________

Incoming Readings Position #1

Position #2

Position #3

Position #4

Position #3

Position #4

Drive End Opposite Drive End Final Readings Position #1

Position #2

Drive End Opposite Drive End

Comments: ____________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________

C-157

Data Sheets Sheet #147: Exciter DC Drop Test Inspection Form Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________

Shunt Winding

Position #1


Position #2


_____________ _____________ _____________ _____________ _____________

Position #3

Position #4

F5 – F6

F7 – F8

F1 – F2 F3 – F4 F5 – F6 F7 – F8 Megger Readings Shunt Winding

F1 – F2

F3 – F4

@ 500 VDC Comments: ____________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________

C-158

Data Sheets Sheet #148: Exciter Seal to Journal Setting Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



_____________ _____________ _____________ _____________ _____________

All readings taken viewing the pedestal facing the exciter. Top of Seal

Bottom of Seal

Left of Seal

Right of Seal

Inboard Seal Outboard Seal

Comments: ____________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________ _____________________________________________________________________________________________

C-159

Data Sheets Sheet #149: Generator/Exciter Rotor Seal and Collector Area Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________


Fit A B C D E F G H I J K L M N O P Q R

C-160

Size 0 Deg. 90 Deg.

Surface Condition


_____________ _____________ _____________ _____________ _____________

Recommended Action Turn

Polish

Data Sheets Sheet #150: Exciter Coupling Alignment Form Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



_____________ _____________ _____________ _____________ _____________

Incoming Alignment Readings Top Gap

Bottom Gap

Left Gap

Right Gap

Left Gap

Right Gap

0 deg. 90 deg. 180 deg. 270 deg.

Final Alignment Readings Top Gap

Bottom Gap

0 deg. 90 deg. 180 deg. 270 deg.

C-161

Data Sheets Sheet #151: Protective Device and Pre-Operational Checks – Sheet 1 Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________




_____________ _____________ _____________ _____________ _____________

_______________

Codes: X - Work Carried Out N - Not Done NA - Not Applicable Supervisory Instrument Checked and/or Calibrated

Thermostats Checked

_______

1. Eccentricity

_____________

1. Exhaust hood temperature

________

2. Differential expansion

_____________

2. Extration lines

________

3. Vibration probes

_____________

4. Shell expansion

_____________

Generator RTDs Checked

________

5. Speed/valve position

_____________

Stator Bars Coolant TCs Checked

________

Shaft Grounded Brushes Inspected

________

Vacuum Trip

Lube Oil System

________

1. Valves trip with vacuum trip _____________

1. Level alarm checked

________

2. Trip settings

2. Auto. sequential pump starting checked ________

1. High

__________ In. Hg Abs

2. Low

__________ In. Hg Abs

3. Low vacuum alarm setting

________ In. Hg Abs

3. Oil tank vacuum checked ______ In. H2O

________

4. Bearings sight flows checked

________

5. Extration relay dump valve checked

________

Thrust Wear Indicator 1. Trips checked

___________ Alarms checked

EHC System

2. Thrust wear detector (+) _________

Trip point

1. Auto. pump starting checked

________

(-) _________

Trip point

2. All alarms checked

________

3. All filters and dryers checked

________

4. Leak test coolers

________

Solenoid Trip Tested Remote Trips Valves Checked for Proper Operation 1. Main stop ______ 2. Control ______ 3. Reheat Stop ______ 4. Intercept ______ st ______ 5. 1 Extraction nd 6. 2 Extraction ______ 7. Blowdown ______ 8. Ventilator ______ 9. Equalizer ______ 10. Steam seal feed valve ______ 11. Steam seal unloading ______ 12. Steam seal diverting ______ 13. Exhaust spray ______ 14. Steam lead drains ______ 15. Non-return ______ Shell and Valve Thermocouple Checked _______

C-162

5. Fluid sample analyzed

________

6. Test high-pressure trip system

________

7. Test 24-volt DC system

________

8.

________

9.

Test mechanical trip valve Check for proper operation of valve operator

________

Seal Oil System 1. Auto. pump starting checked

________

2. Liquid level alarms checked

________

3. Press. and diff. alarms checked

________

4. Seal oil flows checked

________





_____________ _____________ _____________ _____________ _____________

_______________

Codes: X - Work Carried Out N - Not Done NA - Not Applicable Overspeed Governor 1. Tested ______ Date ____________________________ Witnessed By _________________________________ Trip Speeds ______________ Test 1 ________________ Test 2 ________________ Test 3 ________________ 2. Oil trip tested _____________ 3. Minimum oil tripping tested _________ Trip speed 4. Back-up overspeed tested _________ Trip speed 5. On-line governor tested/checked _________ (Exerciser) 6. Extraction non-return valves satisfactorily operated _______ Lube Oil System

Operating Governor 1. High speed stop

__________ RPM

2. Low speed stop

__________ RPM

3. Regulation

__________ %

2. IV half closed

___________

2. Shaft suction pump press.

___________

3. Hydraulic press. Stop Valves Leakage Checked

Pre-Emergency Governor 1. IV begin to close

1. Bearing header pressure

___________

__________ RPM

Control Valves Leakage Checked

___________

__________ RPM

Intercept Valves Leakage Checked

___________

Gen. RTDs Balanced on Cold Gas

___________

Underspeed Release

Stator Bar Coolant TCs

___________

1. Release

__________ RPM

1. At no liquid

Highest TC No.

___________ °F

2. Reset

__________ RPM

Capacity

Low TC No.

___________ °F

Highest TC No.

___________ °F

Low TC No.

___________ °F

Initial Press. Regulator 1. Rated stem press.

__________ psig

2. Valves start close

__________ psig

3. At no load setting

__________ psig

4. No load stop setting inches hydraulic stroke

__________

Thrust Wear Indicator 1. Trips checked _______ Alarms checked 2. Thrust wear detector

2. At full load

Shaft Voltage Check A. AC Voltage

______________ Volts

B. DC Voltage

______________ Volts

C. Measured at

______________

D. Type Meter

______________

(+) ________ Trip Point (-) ________ Trip Point

Bearing Temp. Rise 1. Cooler in _________ °F out ________ °F 2. Highest bearing no. _______ temp. _______ °F 3. Thrust bearing TE _______ °F GE ________ °F

C-163





_____________ _____________ _____________ _____________ _____________

_______________

Codes: X - Work Carried Out N - Not Done NA - Not Applicable

Stator Cooling System

Bearing and Hydrogen Seal Insulation Check

1. Auto. pump starting checked _____________

1. Bearing resistance

___________ ohms

2. Systems alarms checked

2. Hydrogen seal resistance

___________ ohms

3. Conductivity cells inspected _____________

3. Exciter coupling resistance

___________ ohms

4. Governor run back checked _____________

4. Inner and outer oil deflector

______ Inner ohms

_____________

______ Outer ohms Hydrogen System 1. Alarms all checked

_____________

2. Purity analyzer calibrated

_____________

3. System leak checked

_____________

4. Leakage ___________ cu. ft./day

C-164

Load/Speed

Filter

AMP

Angle

AMP

Angle

AMP

Angle

BRG

Gen End AMP

Angle

Coupling TB End

AMP

Angle

AMP

Angle

AMP

Angle

AMP

Angle


Data Sheets

_____________ _____________ _____________ _____________ _____________

C-165

Comments:______________________________________________________________________________________________ _______________________________________________________________________________________________________ Rotor Critical Speeds – ____________________________________________________________________________________ Frequency Scan -_________________________________________________________________________________________ Equipment Used - ________________________________________________________________________________________ Equipment Lag Angle -_____________________________________________________________________________________ Zero Ref Mark Color - _____________________________________________________________________________________ Inlet Oil Temp -___________________________________________________________________________________________

Gen End

Sheet #154: Vibration Data Sheets

TB End

BRG


Coupling

Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________

BRG

_______________

BRG


Date, Time

Data Sheets Sheet #155: Balance Weight Locations Plant ________________________ Unit ________________________ Outage No.______________________ As Found ________________ As Assembled ____________



_____________ _____________ _____________ _____________ _____________

Balance Plane Location_____________________________________ Mark Block if Weight is Installed

Mark Block if Weight is Installed

1

31

2

32

3

33

4

34

5

35

6

36

7

37

8

38

9

39

10

40

11

41

12

42

13

43

14

44

15

45

16

46

17

47

18

48

19

49

20

50

21

51

22

52

23

53

24

54

25

55

26

56

27

57

28

58

29

59

30

60

C-166

D

FOREIGN MATERIAL EXCLUSION GUIDANCE

D.1

Introduction and Purpose

The purpose of this appendix is to supplement the component-specific guidance provided in Section 2.11 of this report with programmatic guidance that plant/site personnel can use to develop or enhance FME programs. Operating experience clearly demonstrates that foreign material represents a real threat to personnel safety, radiological safety, nuclear safety, and plant reliability. Avoiding the consequences of events of this nature requires the implementation of controls and good work practices that effectively minimize the potential for foreign material intrusion. This appendix provides programmatic guidance for preventing the introduction of foreign material into plant systems and components, as well as measures to implement in the event that foreign material intrusion occurs. In general, this appendix provides guidance for establishing requirements that would prevent the introduction of foreign material, such as dirt, debris, and tools, into open systems or components. The program describes a method for controlling and accounting for materials, tools, and parts to preclude their uncontrolled introduction into an open system or component during maintenance, modification, or inspection activities. Additional guidance is provided to recover from the intrusion of foreign material. Preventing the introduction of foreign material into systems and components (electrical and mechanical) avoids the associated damaging effects such as corrosion, fuel damage, component malfunction or failure, chemistry changes, increased radiation levels, and personal injury. In general, an FME program should apply to systems and components of the plant for which intrusion of foreign material could result in degraded performance. The program should be used on piping, vessels, tubing, electrical equipment, and mechanical equipment where the introduction of foreign material could adversely affect the equipment. Normal good housekeeping practices apply to activities that will not introduce foreign materials. It should not be the intent of the FME program to institute additional controls on work activities that are procedurally controlled or that by their nature do not breach a system or increase the potential for foreign material intrusion.

D-1

Foreign Material Exclusion Guidance

D.2

Definitions

D.2.1 Glossary of Key Terms access control point – The single point of control for entry and exit of personnel and material for an FMEA zone. appropriate personnel – The immediate supervisor or other designated responsible employee. area owner – The individual or individuals assigned the responsibility for a work area. breach – To render the integrity of a component or system ineffective to the point where foreign material could enter. Breaches include physical openings in mechanical systems as well as cases where the interior of instrumentation or electrical equipment is exposed (for example, a switchgear cabinet door is opened; the cover to an electrical enclosure is removed; etc.). buffer zone – An area established immediately adjacent to critical or sensitive FMEAs as appropriate or practicable. This area is a zone that is maintained free from material that has the potential to be tracked or blown into the FMEA or to fall into it. This area should be monitored and controlled to prevent material (whether from flying debris from overhead or a nearby area) from entering the FMEA or stationary items from being tracked (or kicked) into it. Examples: Crane work overhead, welding or grinding near the barrier, portable dirt or wires carried by foot into the area. Debris in the buffer zone is not an FME violation, but it must be cleaned up or removed immediately upon identification. clean area – A space or enclosure such as a tent or a roped off or partitioned area in which the air is free from foreign particles (that is, no grinding, welding, or sand blasting). A clean plastic bag or sleeve meets the requirements for a small clean area. “cleaning as you go” – The process of cleaning up foreign material in local areas around particulate-producing operations such as machining, grinding, welding, or cutting that is accomplished while those activities are in progress (in addition to at the end of the task). cleanliness – The condition of removing contamination to an acceptable level and maintaining an acceptable level. cleanliness classification – The requirements and administrative controls to maintain system cleanliness during maintenance and modification activities. consumables – Items expended during work in the FMEA (for example, cleaning solvents) contamination – Any undesirable foreign material on the surface of an item, in the atmosphere, or in process liquids or gases. controlled plant equipment – Structures, systems, and components that are safety-related, whose functions impact the plant safety analysis, or that are subject to special considerations D-2


based upon management discretion (for example, considerations given to licensing basis, the Maintenance Rule, personnel safety, equipment availability, commercial risk, etc.). fail safe – A condition that exists when equipment or material cannot enter a system or component due to the equipment or material being too large to fit through any breaches or the equipment or material being securely mounted in place. Equipment or material that is breakable and/or contains easily dislodged parts small enough to enter a breach is generally not considered fail safe. flush or filter cloth – Cloth through which flushing fluid is passed to determine the acceptability of a system or component flush. flushing – As used in the context of this procedure, flowing fluid or gas through a component or system at adequate velocity to suspend and carry away anticipated contaminants. FME condition – An FME-related error that did not affect a system or component; this includes administrative errors. This category provides information to assess FME programmatic needs. FME device – An internal device (such as a temporary dam and cover, pipe plug, etc.) or external opening cover installed to prevent foreign material intrusion. FME event – A condition involving or resulting from inadequate implementation of FME program controls. FME events can often fall into various categories based upon their actual or anticipated consequences. FME monitor - An individual assigned to control access to a particular FMEA and to maintain logs for material and personnel accountability. FME significant event – An FME-related event that resulted in personnel injury, significant plant equipment damage, fuel failure, or loss of generation. FME vulnerability – An FME-related implementation error or as-found condition that—if not detected—could pose a risk of personnel injury, plant equipment damage, fuel failure, or loss of generation or that is the result of inappropriate human behavior during a work activity. This includes events that required evaluations in lieu of retrieval. FMEA boundary – A physical boundary established at or around a work area, usually consisting of barrier materials and signs visibly identifying the area as an FMEA. FMEA dedicated monitor – A person who is assigned responsibility for monitoring an FMEA. The dedicated monitor has no other assigned duties. The dedicated monitor’s duties are to log tools, materials, and so forth in and out of the FMEA zone and to ensure that personnel sign in and out of the FMEA zone according to the site or station procedures. FMEA tool and parts log – A log used to keep track of items, tools, and parts—including their condition—that are moved in and out of an FMEA. D-3


foreign material – Any material that is not part of a system or component as designed. Foreign material includes any item that could adversely affect the integrity or intended operation of the system or component, including dirt, debris, broken or missing parts, oil, slag, tools, rags, chemicals, lapping compounds, grinding particles, paint chips, tie wraps, lugs, stripped insulation, and leak sealant compounds. foreign material exclusion (FME) – The actions taken to prevent damage to plant systems and equipment as a result of the introduction of foreign material. These actions include the work planning process, controls on the performance of work, cleanup/foreign material removal, and work area close out. The requirements for foreign material exclusion are established herein and must be incorporated into the applicable procedures governing the work. foreign material exclusion area (FMEA) – An area at or around a system or component breach or a nuclear fuel storage/handling area that requires specific controls to prevent the introduction of foreign material during the performance of maintenance, modifications, testing, and/or inspections. The FMEA is an established area to control material, tools, and—in some instances—personnel movement in and around open systems or components. foreign material exclusion boundary – The boundary for the area that is subject to foreign material exclusion controls. The boundary may be defined by barrier tape as in the case of FMEAs or by an opening in a piece of equipment such as a valve bonnet flange or motor control center door. foreign material exclusion monitor – The individual responsible for controlling personnel, materials, and tools entering the FMEA. immediately retrievable – Foreign material (within a system or component) that meets all of the following criteria: –

The material can be observed.

–

Recovery will require no more than a momentary interruption in task performance.

–

Recovery efforts are unlikely to inadvertently result in the item migrating to a less accessible area.

–

Recovery of the item will not expose personnel to an industrial safety or radiological hazard (for example, items found in contaminated systems may be highly radioactive).

implementer – The individual or individuals assigned the responsibility for performing a work activity. loss of FME control – A condition deemed to exist whenever any of the following circumstances occurs: –

Foreign material is found within a component, enclosure, or system (including open-air systems such as the spent fuel pool).

–

Foreign material that is not immediately retrievable is introduced into a component, enclosure, or system (including open-air systems such as the spent fuel pool).

D-4


–

A component is found to be missing parts that most likely remain within a system.

–

Parts of tools or equipment used within an FMEA are identified as missing.

–

Material recorded on FME log sheets can not be accounted for.

–

Material that was not documented is found within an FMEA.

–

Internal FME barriers (for example, pipe dams) have failed, or FME barriers are damaged or missing while the FMEA is unattended.

–

External FME covers are damaged, removed, or displaced while an FMEA is unattended.

–

Control log discrepancies cannot be immediately resolved.

permanent FME area – Areas such as, but not limited to, spent fuel storage, drywell, torus, refuel floor including moisture separator, and reactor cavity with the head removed. power plant boundaries or equipment – Systems and components that perform a direct function in the production, transport, and storage of heat energy, electrical energy, or radioactive wastes. Also included are systems and components that monitor, control, protect, or otherwise support the above equipment. project FME plan – A plan detailing specific FME controls for a major or complex activity. Project FME plans are typically written documents but can also be captured electronically (for example, as in the work control system). A project FME plan should be formulated as early as possible to allow for potential changes to the design and planning for the work activity. A project FME plan typically contains both engineered FME controls as well as passive FME controls. Passive controls may include signs, barriers, ropes, etc. reconcile – To ensure that the FMEA log accurately lists the items in the FMEA. responsible lead person – The person in charge of and primarily accountable for the work activity being performed. self-monitor – An individual authorized by the appropriate personnel to control their own access to an FMEA 1 when no FME monitor is stationed there. small openings – Pipe diameter or component openings greater than 1/2" (13 mm) and up to 1" (25.4 mm) and oriented in a position facing upward from horizontal or pipe diameter/component openings greater than 1" (25.4 mm) and up to 2" (51 mm) in diameter in any other orientation. stop work order – The authority to temporarily interrupt a work activity to resolve a concern, for example, related to FME. stored items – Material kept in a locked cabinet in the FMEA (for example, special tools). temper film – Thin discoloration resulting from heat applied to the surface of a metal, usually from heat treatment, welding, grinding, flame cutting, or manufacturing heating processes. D-5


temporary cover – An item, which should meet the following requirements, that is used for sealing and protecting a system or component from the introduction of foreign material when the system or component is unattended: –

Is fire resistant or fire retardant

–

Is non-brittle, non-splitting, non-melting, and thick enough to avoid damage to underlying surfaces

–

Will not damage system or components

–

Will not deteriorate or decompose over time

–

Does not cause any chemical reaction

–

Has a fail-safe design

–

Is easily detectable and retrievable

D.2.2 Categorization of FME Areas In some cases, it may be beneficial to designate and categorize areas based on the rigor of the controls deemed necessary or the impact that foreign materials could have on system operation and reliability. Common FME area designations are as follows: FMEA 1 – An area where the highest level of FME controls is necessary to protect the station and personnel against major consequences resulting from foreign material intrusion. Areas classified as housekeeping zones I, II, or III are typically controlled as an FMEA 1. This includes the spent fuel pool, reactor containment building emergency sumps, new fuel vault (when fuel is present), and reactor cavity (when the reactor head is removed). FMEA 2 – An area where less stringent FME controls can be used to protect the station and personnel against the consequences resulting from foreign material intrusion. FMEA 2 controls typically consist of using good work practices that minimize the potential for foreign material intrusion and performing thorough close-out inspections to ensure that no foreign material is left within systems and components after task completion. D.2.3 Categorization of FME Events In some cases, it may be beneficial to designate and categorize—based on a number of factors— events resulting from FME. Common FME event designations are as follows: •

Level 1 FME event – A condition involving or resulting from inadequate implementation of FME program controls that results in major actual or imminent consequences to the station. Level 1 FME events include actual cases of foreign material intrusion resulting in: a. Lost-time accidents or restricted duty injuries b. Nuclear fuel cladding failure c. Reduced main generator output

D-6


d. Inoperable safety-related equipment e. Non-functional reliability-significant or safety-significant equipment f. Major damage to reliability-significant or safety-significant equipment, necessitating extensive repairs or replacement g. Extensions to the duration of an outage h. Expenditure of major resources for recovery i. Nonretrievable foreign material that has a high probability of resulting in a major consequence to the station (for example, items a–f above), as determined by an engineering evaluation •

Level 2 FME event – A condition involving or resulting from inadequate implementation of FME program controls that results in minor actual or imminent consequences to the station. Level 2 FME events include actual cases of foreign material intrusion resulting in: a. First aid being required or recordable personnel injuries b. Minor damage to reliability-significant or safety-significant equipment c. Damaged and/or nonfunctional low- or non-risk-significant equipment d. Noteworthy delays in task completion e. Expenditure of noteworthy resources for recovery f. Nonretrievable foreign material that could result in minor consequences to the station (for example, items a–c above), as determined by an engineering evaluation

•

Level 3 FME event – A condition involving or resulting from inadequate implementation of FME program controls that proved to be nonconsequential. Examples of Level 3 FME events include: a. Nonconsequential intrusion events (for example, did not damage or inhibit component operation; did not create noteworthy delays in task completion; did not require noteworthy resources to retrieve; poses no risk if not retrieved) b. Unsecured items inside an FMEA boundary, but external to a breach or open-air system (for example, the spent fuel pool, the reactor cavity area during refueling) c. Material found adrift in the reactor containment building after containment integrity has been established, but in insufficient quantity to affect emergency sump operability d. Failure to implement required FME controls/good work practices in the field, shop, or material storage areas e. Log-keeping discrepancies

D-7


D.3

Plant/Station Responsibilities

The purpose of this section of the appendix is to provide a listing of common responsibilities assigned to plant or station personnel associated with supporting and/or implementing the FME program. These responsibilities may vary, depending on site organizational structure and sitespecific procedures. D.3.1 FME Responsibilities for All Personnel The following responsibilities should be applicable to all site and station personnel regarding FME: •

Implement the FME program requirements, and use good work practices that minimize the potential for the intrusion of foreign material into plant systems and components.

•

Adhere to all FMEA postings and boundaries.

•

Do not disturb or remove FME covers and internal barriers without the authorization of the individuals responsible for the cover, unless an emergency necessitates.

•

Stop work and notify a supervision if a loss of FME control occurs or is likely to occur.

•

Maintain a clean work environment that reflects station core work practices.

•

Reinforce FME program requirements and the use of good FME work practices with peers and supplementary personnel.

•

Provide feedback via approved means (for example, lessons learned database, condition reporting process) to improve the FME program and associated work practices.

D.3.2 Typical Individual FME Responsibilities The following individual responsibilities are typical for site and station personnel regarding FME programmatic controls. They may vary depending on site organizational structure and sitespecific procedures. D.3.2.1

Plant Manager

The most important responsibility of the plant manager regarding FME is fostering a culture that focuses on the prevention of foreign material introduction into plant systems. Other plant manager responsibilities relating to FME are: •

Fosters a “focus on prevention” mindset among station personnel regarding FME

•

Establishes and communicates FME program requirements that encompass all activities directly related to and associated with plant systems and components

D-8


•

Holds individuals accountable to high standards of conduct in regard to adherence to FME program requirements and good FME work practices

•

Ensures that mechanisms are in place to monitor the effectiveness of the FME program

D.3.2.2

FME Program Management Sponsor

An FME program management sponsor has these responsibilities relating to FME: •

Ensures that the FME program is in line with industry standards

•

Ensures that FME program issues and trends are communicated to the management team and/or station personnel

•

Assesses the effectiveness of the FME program

•

Appoints an FME coordinator

D.3.2.3

FME Coordinator

An FME coordinator has these responsibilities relating to FME: •

Communicates FME program issues to the FME program management sponsor, including observations and trends of FME-related condition reports

•

Serves as the internal and external point of contact for FME program issues

•

Identifies FME program improvements via benchmarking activities and/or participation in industry working groups

D.3.2.4

FME Monitor/Self-Monitor

An FME monitor has these responsibilities relating to FME: •

Ensures that he/she is qualified to serve as an FME monitor (FMEM) prior to assuming duties

•

Inspects personnel, tools, and materials entering an FMEA 1 to ensure that access requirements are met

•

Inspects personnel, tools, and materials leaving an FMEA 1 to ensure that unsecured materials have not been inadvertently left within the system/component or in the vicinity of breaches

•

Ensures that FME logs are properly maintained and that any log-keeping discrepancies are resolved

•

Informs appropriate supervisory personnel if a loss of FME control occurs or is considered likely to occur

D-9


D.3.2.5

FME Area Owner

An FME area owner has these responsibilities relating to FME: •

Monitors responsible area(s) on a periodic basis to ensure compliance with the FME program

•

Coaches and provides positive reinforcement as appropriate

•

Implements a recovery plan to resume work after loss of FMEA control

D.3.2.6

Department Manager and/or Maintenance Manager

A department manager and/or maintenance manager has these responsibilities relating to FME: •

Implements the FME program

•

Ensures that station and supplemental personnel receive appropriate training on FME program requirements

•

Ensures that the causes of consequential FME-related events are identified

•

Ensures that appropriate corrective actions are implemented when FME program violations occur or weaknesses are identified

•

Conducts periodic work site observations to monitor compliance with FME program requirements and utilization of good FME work practices

D.3.2.7

Maintenance Work Supervisor

A maintenance work supervisor has these responsibilities relating to FME: •

Identifies appropriate FME controls for work activities

•

Conducts pre-job briefings as appropriate that address FME program requirements and work practices that will minimize the potential for intrusion

•

Ensures that inspections are performed to identify the presence of foreign material upon initially breaching a system and prior to final close out

•

Determines whether personnel may self-monitor while accessing an FMEA 1, based upon the job scope and whether the individual is a qualified FMEM

•

Assigns a qualified FMEM to control access to an FMEA 1 if personnel accessing the area will not self-monitor

•

Conducts job site observations to monitor compliance with FME program requirements and utilization of good FME work practices

•

Ensures that FME log-keeping discrepancies are resolved

•

Ensures that condition reports are generated when a loss of FME control occurs

D-10


D.3.2.8 Work Planning A work planning group has these responsibilities relating to FME: •

Analyzes feedback to improve future FME controls in work packages

•

Considers the availability of FME materials that may be needed to accomplish the task

D.3.2.9 Engineering An engineering group has these responsibilities relating to FME: •

Evaluates the individual and cumulative effect of foreign material not retrieved from systems or components

•

Provides assistance in determining the removal methods for foreign material not easily retrieved

D.3.2.10 Training A training group has these responsibilities relating to FME: •

Reinforces the use of FME practices in the classroom and laboratories

D.4

Establishing and Implementing FME Program Requirements

D.4.1 Introduction The requirements for foreign material controls are most often based on commercial risk factors, which are the potential for material intrusion, the ease of identification and removal, and the potential consequences from foreign material left in the system. Generally, tighter controls are imposed on work situations that involve greater risks. As noted in Figure D-1, foreign material exclusion should be considered in the work planning process. Maintenance work request planning should consider: •

The potential for foreign material introduction as a result of the work

•

Work practices to minimize the potential for foreign material intrusion

•

Cleaning and flushing requirements

Modifications and special procedures should also take into account foreign material exclusion in the implementing instructions as applicable.

D-11


Figure D-1 Foreign Material Exclusion Flowchart Courtesy of Exelon

Tools and equipment used inside an FME boundary should be inspected for loose or missing parts prior to entry and again upon removal. Tool inspections should consider the potential for the generation of loose parts during use, such as mushroomed heads on cold chisels. If practical, the same person should perform the entry and removal inspections. As a minimum, someone familiar with the tool or equipment must perform the inspections A pre-job briefing should typically be held prior to work in an FMEA and should include the FME controls applicable to the area. Repeat briefings should be at the discretion of the plant personnel, based on the need to reinforce the controls or to brief additional personnel. The loss of control of foreign material inside an FME boundary should be reported immediately to the responsible supervisor. Loss of control has occurred when the established barriers to foreign material intrusion have failed or are suspected to have failed. Examples include log discrepancies that cannot be immediately resolved, material items that cannot be accounted for, observed foreign material in an unexpected location, or other abnormal conditions involving foreign material.

D-12


Loose clear-plastic items, unless marked or colored so that they can be seen in a wet or dry system, should not be allowed in the FMEA. When practical, temporary covers should be installed over system or equipment openings during periods when no work is being performed to prevent foreign material intrusion. D.4.2 General Programmatic Guidance The FME program focus should be to use common sense methods to prevent foreign material from entering plant systems. Responsible workers should be the first line of defense to avoid events that could affect the safety and operability of the plant. Habitability, safety, radiation, security, equipment, and system requirements should be considered when establishing FME controls. However, some routine maintenance activities are typically exempt from FME controls, provided that cleanliness and normal good worker practices are observed in accordance with station procedures. Routine activities exempted from FME controls may include, but are not limited to, the following: •

Visual inspections of equipment, tag out of equipment

•

Operation of breakers

•

Opening cabinets or panels

•

Draining, filling, and venting of systems (small openings only)

•

Valve repacking

•

Traveling screen maintenance

•

Opening of cable tray covers or junction boxes

•

Obtaining samples

•

Testing or calibration of instrumentation that does not require a system breach

The FME control program should ensure that personnel restore and verify system cleanliness following work. This may range from a simple visual inspection to a complete system flush. Similarly, plant personnel should follow plant procedures to ensure that cleanliness requirements are met for the system being worked. The FME program should encourage the use of FME briefings. The supervisor or designee should brief personnel on appropriate FME job controls, considering the need for FME materials such as pipe plugs, covers, and caps that may be needed to accomplish the task. D.4.3 Sources of Foreign Material Contamination The FME control program should communicate to maintenance personnel common contaminants, which often include, but are not limited to, the following: •

Welding and gas cutting debris

•

Metal chips, shavings, and filings created by machining and repair operations D-13


•

Corrosion

•

Materials used for cleaning

•

Improper lubricants

•

Dirt, fly ash, coal dust

•

Contaminants found on shoes and clothing

•

Pens, rulers, coins, keys, and other typical contents of a shirt pocket.

•

Tools

•

Trash

The FME control program should also describe typical activities that produce foreign material, such as: •

Drilling, cutting, grinding, machining, filing, and lapping

•

Welding or thermal cutting activities

•

Lubricants or cutting oils

•

Use of tape, plugs, or seals that may leave a residue

•

Sandblasting

•

Sweeping or using air or water to clean

•

Any activity including equipment inspection and testing that requires opening a normally sealed component

D.4.4 Defining the Scope of Equipment Controlled by FME Procedures The FME control program should define the scope of equipment that will be controlled by FME procedures. Maintenance personnel, as well as contractors, should follow FME practices, particularly on systems and components that are critical to the power plant such as feedwater, condensate, steam, lubricating oil, turbine, and generator. These systems are likely to suffer component damage if contaminated by foreign material. The following list provides examples of critical components that should be included in the scope of a typical FME control program: •

All lube oil reservoirs

•

All piping systems

•

Boiler tubes, headers, and drums

•

Bulk storage tanks

•

Compressed air systems

•

Condensers

D-14


•

Electrical cabinets

•

Feedwater heaters

•

Flash tanks

•

Generators and seal oil systems

•

In-line flow elements

•

Large electric motors

•

Pumps

•

Switchgear

•

Transformers

•

Turbine shells and piping

D.4.5 Training and Qualification of Individuals The FME control program should define training requirements for site and station personnel as well as contractors. Training on FME should minimally be provided to independent contractor personnel as required. The first line supervisor may permit trainees or short-term employees to work under the direct supervision of qualified personnel. The qualified individual should then ensure that appropriate FME controls are maintained. A general knowledge of FME should be provided to personnel who have access to work areas. Group-specific training can be a useful tool for areas such as the refuel floor, turbine, or primary containment. These groups often encounter special FME needs. Interactive learning modules and mockups are a popular and practical way to coach and positively reinforce FME expectations. Continuing training maintains and enhances performance levels; consequently, continuing training topics such as the following should be considered: •

Observed weaknesses

•

Operating experience

•

Lessons learned from outage critiques

•

Training for infrequent or difficult tasks

•

Refresher training

•

Reinforcement of management expectations

D-15


D.5

Developing and Implementing FME Control Plans

Project coordinators should develop and implement FME control plans in support of major work activities or projects for which the likelihood and potential consequences of foreign material intrusion are moderate to high (for example, refueling, main generator repair activities). FME plans should be communicated to project participants in advance of project commencement and at appropriate times during the project. D.5.1 Factors to Consider When Developing an FME Control Plan Some factors to consider when developing a plan to control FME are as follows: •

Defining roles and responsibilities – Designate an appropriate individual to be responsible for reviewing and implementing the FMEA requirements, initiating corrective actions, and verifying system and component cleanliness prior to closure. Identify an individual with indepth system knowledge who is the best point of contact for the development of an FME retrieval plan if applicable.

•

Job duration – Jobs lasting more than one shift might suffer lapses in control due to omissions in turnovers or poor communication.

•

Work scope – The FME control plan should contain a description of the major FMEA work activities, including area setup and foreign material generation. Additionally, it should include a description of support activities, such as scaffold erection and dismantling, tool decontamination, foreign material generation, and waste collection.

•

Area rating – Areas rated high or moderate may require more planning to achieve the desired control than would be usual in a pre-job briefing.

•

Access control – A detailed description of the pre-work activities required to establish the FMEA might be as simple as establishing the area boundaries, or it might include fabrication or erection of enclosures. The plan should include a description of the boundaries, the point where the FME log will be maintained, and where the FME monitor will be stationed.

•

FME control – Measures to ensure exclusion of foreign material should be included. If applicable, describe measures to be taken as conditions change or if new issues arise. Areas requiring continued support from other groups, large quantities of tools, local FME tools, special prefabrication, or construction may require a plan to minimize delays. Detailed descriptions of the tools required to perform the work activities should include the number of tools, how the tools will be made fail safe, transportation of tools within the FMEA, and where the tools will be available. The use of non-fail-safe tools and an FME monitor, if applicable, should also be described in this section of the plan. If applicable, include plant or industry foreign material experience for the activity, system, or component.

•

Immediate actions – This plan describes actions that should be taken for foreign material intrusion and removal. This should include stopping work and who to contact before attempting to retrieve or remove the foreign material.

•

Control plan approval – The first line supervisor should approve control plans required by the plant or site FMEA categorization.

D-16


D.5.2 Typical Contents of an FME Control Plan FME plans should typically include the following information: •

Work scope

•

Activities within the work scope that warrant FME controls, based upon the probability of foreign material intrusion, the difficulty involved in detecting and/or retrieving any foreign material introduced, and the potential consequences to the plant or personnel if intrusion occurs

•

Location, arrangement, and construction of FMEA boundaries

•

When FMEAs will be established (for example, prior to breaches)

•

Personnel and material access requirements, log-keeping requirements

•

Specific FME controls and work practices that will be used to minimize the potential for foreign material intrusion (for example, removing major components for disassembly outside FMEA, use of temporary FME devices, etc.)

•

Applicable lessons learned and operating experience

•

Contingency plans in the event that foreign material intrusion occurs

•

Activities that will be exempt from FME controls and the basis for their exemption

•

FME close-out inspection/flushing requirements

D-17


Figure D-2 illustrates an example of how to document an FME plan.

Figure D-2 Example of an FME Plan Document Courtesy of Progress Energy

D-18


D.5.3 Establishing the FMEA The responsible supervisor should establish the FMEA boundary based on the potential for foreign material introduction. Potential foreign material that will remain in the FMEA should be inventoried and accounted for. The FMEA boundary should be as small as practical and should use physical barriers such as walls and equipment, where possible, with the remainder designated with FMEA barrier tape. The installation of temporary physical barriers or a clean enclosure should be considered if there is a strong potential for the introduction of dirt, debris, or other foreign material from adjacent areas. The use of special clothing, securing of ventilation systems, stopping adjacent work, or similar controls may also be required. FMEA barrier tape should be used, if available, to designate the FMEA boundary. If FMEA barrier tape is not available, an alternative tape can be used, or a permanent boundary can be marked. If an alternative tape is used, an FMEA boundary sign approximately 8 1/2 x 11" (21.6 x 27.9 cm) should be securely attached every 4–5' (1.2–1.5 m). Additional devices including pipes covers, duct tape, and polyethylene plastic film can also be used as boundary protection. The FMEA should have the applicable signs and attachments stationed as needed, and these may include a personnel log, material log, and responsibility sheet. Figures D-3 and D-4 are examples of typical FME boundary signs.

Figure D-3 Example of an FME Boundary Sign Courtesy of Progress Energy

D-19


Figure D-4 Example of an FME Boundary Sign Courtesy of Ontario Power Group

D.5.4 Determining Appropriate FME Controls for the Area Prior to performance of work activities, the supervisor should identify if FME controls are necessary, as well as the level of FME controls needed (for example, FMEA 1 or FMEA 2), if applicable. In some cases, a decision tree may be helpful to aid the supervisor in making this determination, which is based upon the following considerations: •

Whether the work will be performed in a housekeeping zone I, II, or III area, as specified in plant housekeeping procedures (if applicable)

•

The potential for foreign material intrusion during the activity

•

The difficulty involved in detecting and/or retrieving any foreign material introduced

•

The potential consequences if foreign material enters a system or component and is not retrieved.

When determining whether FME controls are necessary for a given task, the supervisor should also consider the potential for loose material associated with the task to enter unrelated equipment in the vicinity of the work. For example, the supervisor of a debris-producing activity such as grinding would need to consider the potential for debris to enter an adjacent motor through its casing vents, as well as any open vent valves in the vicinity. The use of tents, shelters, or drapes may be necessary if the task (for example, spray painting, drilling, grinding, insulating, or chemical cleaning) could generate airborne debris or corrosive fumes that could be introduced into systems or nuclear fuel storage areas. D-20


If an activity will be performed within an FMEA 1, the supervisor should determine whether personnel may self-monitor when accessing the area. Self-monitoring is typically reserved for non-intrusive activities such as routine tours, inspections, job walkdowns, and surveillance test performance. D.5.5 Establishing an FMEA Boundary An FMEA boundary should be erected prior to performing tasks requiring FMEA 1 controls. For tasks afforded FMEA 2 controls, use of an FMEA boundary is typically at the discretion of the job supervisor. Figure D-5 illustrates examples of denoting an FMEA boundary and establishing entry locations.

Figure D-5 Examples of FME Boundaries and Entry Locations Courtesy of Progress Energy

Prior to establishing an FMEA boundary, workers should remove non-essential materials and debris from the area that will be enclosed by the boundary, including overhead areas. Emergency personnel (for example, medical first responders or fire brigade personnel) and their equipment should have unhindered access to an FMEA during emergency situations. D.5.6 Installing the FMEA Boundary The FMEA boundary should be installed in accordance with plant and site procedures, taking into consideration the following guidance. The supervisor should ensure that the boundary is configured (for example, proper materials of construction, adequate dimensions) so that it D-21


provides adequate protection against intrusion of foreign material. If the area is large enough, then consideration may be given to having multiple access points. The job supervisor should ensure that one or more qualified FME monitors are stationed to control access to an FMEA 1, unless self-monitoring will be performed. Barriers are used as appropriate to designate the FMEA boundary. Temporary covers can be used as an FMEA boundary. To improve visibility, FME barrier decals can be used. Signs are recommended for large boundaries, but to improve visibility, FMEA boundary signs can be used in addition to the FMEA sign. Another option to improve visibility is the use of FMEA boundary tape. D.5.7 Conducting Pre-Job Briefings For any task having the potential to result in a Level 1 FME event, the job supervisor should perform a pre-job briefing that includes an overview of the FME plan. Specifically, the pre-job briefing may also include discussion of any FME controls for the task, the potential consequences of foreign material intrusion, and contingencies in the event that intrusion occurs. All personnel entering an FME area must be advised and an appropriate sign placed into or adjacent to the FME area stating that any inadvertent loss of tools, instruments, materials, and/or personal belongings inside the FME zone must be reported immediately.

D.6

Performance of Work Inside the FMEA

D.6.1 FMEA Entry Requirements Workers should ensure that the following activities are completed prior to commencing work in the vicinity of a breach and/or crossing an FMEA boundary: •

Fasten badges and dosimeters securely to the clothing. If tape is used to secure these items, do not tape over the audible or visual part of the dosimeter.

•

Remove loose items on the person, including removable jewelry (for example, wristwatches, necklaces, earrings), and place them in a secure area or inside taped pockets.

•

Verify that pockets are empty or taped closed.

•

Use a container with a fail-safe lid for items that are too small or numerous to attach lanyards or other control devices. Contents within a container should be inventoried before taking the container into the FMEA.

•

Fasten eyeglasses to the wearer with tape, nylon cord, or eyeglass retainer straps if the possibility exists of the glasses being introduced into the system.

•

Inspect all tools and materials that will be used in the vicinity of a breach for loose or missing parts. Record missing parts in the work document (or individual entry log), if utilized.

D-22


If accessing an FMEA 1, workers should complete the following additional activities prior to entry: •

Tape over zipper tabs and buttons if the possibility exists of their being introduced into the system as foreign material.

•

Determine whether tools are fail safe prior to their being transported across the FMEA boundary. If the tools are not fail safe, ensure that lanyards are attached that will be capable of preventing the loss of the tool.

•

Ensure that no black matting-like material is allowed in the FME 1 area without being tagged and tied off.

D.6.2 Use of Control Logs Control logs should contain enough information to ensure accountability of tools and equipment. Items with missing parts or damage could result in questionable accountability. Control logs should be considered for critical or large jobs, and typically, the following FME areas require control logs: •

Spent fuel pool

•

Torus

•

Reactor cavity with the head removed

•

Turbine with covers removed

If logging is required, tools, equipment, and material released from the hand and not to be permanently installed should be logged prior to entry into the FMEA. Items specifically controlled by procedures (electrical jumpers) and personal items (eyeglasses, dosimeters, hard hats, etc.) typically do not require logging. Reactor head and internals, blade guides, new nuclear fuel, and any other large item that would be conspicuous by its absence, likewise, typically would not require logging. Special precautions should be taken to track cloths, plastic bags, tape, tools, covers, and missing parts of tools and equipment. In this regard, the following precautions should be considered: •

Cloths (cleaning/wiping) should be logged by size and quantity (for example, wiping cloth large - Qty. 6).

•

Plastic bags should be logged by size, color, and quantity (for example, plastic bags - yellow - 6" x 18" - Qty. 4).

•

Bulk quantities of tape (for example, full or partial roll) should be logged.

•

Each tool should be logged separately. Tool boxes should be inventoried.

•

FME pipe covers or plugs should be logged.

•

Missing parts or damage to tools and equipment should also be noted to ensure accountability. D-23


The FME monitor/self-monitor should log all personnel and materials (for example, tools, supplies, test equipment) entering and exiting the FMEA 1 on the appropriate datasheet. Material that is inherently fail safe can be exempt from logging requirements. Each logged item should indicate a name and badge number denoting who is responsible for the material. Any non-failsafe items that will remain within the boundary for an FMEA 1 area should be logged on a datasheet (that is, an individual entry log). Figure D-6 illustrates an example of an individual entry log.

Figure D-6 Example of an Individual Entry Log Courtesy of South Texas Project

If items remaining inside the FMEA 1 are expected to remain inside the area for an extended period, the FME monitor/self-monitor may elect to log the items on a long-term placement log instead.

D-24


Figure D-7 illustrates an example of a long-term placement log.

Figure D-7 Example of a Long-Term Placement Log Courtesy of South Texas Project

Electronic logs may be used to record items within an FMEA 1, in lieu of datasheets. It is recommended that control logs be reconciled each shift while the FMEA is active; long-term tasks should be reconciled at least once every seven days. The log should also be reconciled just prior to job closure. Infrequently accessed permanent FMEA logs should be reconciled periodically. D.6.3 Monitoring the FMEA Monitors are typically used for jobs with high FMEA classifications, but they should also be considered for critical or large jobs. The FMEA monitor should establish and maintain housekeeping requirements suitable for the classification of the FMEA. They should also ensure that items not required for performance of the assigned work activity are kept outside the FMEA. An FMEA monitor should ensure that loose objects such as badges, glasses, and dosimetry devices are secured to prevent their entry into a breached system or component. They should understand and ensure that the FMEA requirements are met, and they should observe and correct poor FME habits of personnel within the area. The monitor may deny FMEA entry to individuals not associated with the work task or may stop work to ensure FME program compliance. The D-25


monitor should directly observe work activities, recognizing that complex tasks or large jobs may require additional FME monitors for assistance. Finally, the FMEA monitor should maintain and reconcile applicable logs. An FME monitor may control access to more than one entry point from a single station, provided that he/she is positioned in a location that facilitates effective implementation of access control requirements at each entry point. An FME monitor may perform other duties at the discretion of the job supervisor, as long as the proper control of access to the FMEA is not compromised. Establishment of the FMEA boundary should be recorded in the work document. D.6.4 Cleanliness and Readiness Inspections The FME lead, in concert with engineering, should conduct a cleanliness and readiness inspection prior to commencing FME operations and maintenance activities inside the FMEA. The following activities should be considered at this time: •

Typically, the FME area should be cleaned and left in a broom-clean workman-like manner. The FME lead should be allotted approximately 30 minutes to inspect the FME area and ensure that all items that have been introduced are listed on the inventory sheet for that area.

•

The FME engineer should ensure that a complete inventory of scaffold material, etc., has been completed and given to the FME technician at the entrance to the FME area.

•

The FME lead should post “Do Not Enter Signs” only on the exterior of emergency exit doors and add signs with the name of the individual to contact if someone needs to enter through the posted area.

•

The FME lead should inspect the area, ensure that a complete inventory of all materials for the work activity has been accomplished, and advise the FME engineer when they are ready to commence FME operations for that area.

D.6.5 Performance of Maintenance Activities Within the FMEA Personnel entering an FMEA should appropriately display their security badge and secure it to their clothing by at least two independent means. Taping of the security badge is allowed if the wearer deems it necessary. Jewelry (except wedding rings), watches, and wallets should have already been removed and secured before entering an FME area. All personnel entering the FME zone must be authorized in writing. All material that enters the FME area must be logged in, and it must be logged out when the final close-out audit is performed. All material that enters or leaves the FME area, including the rigging on a crane hook, must be accounted for. Any tools or equipment to be retained in a work area longer than the end of daily work shift should be considered long term, placed on the long-term placement log, and given a tag by the FME monitor. Materials to be maintained beyond one shift are designated as long-term materials and must be approved by the craft lead supervisor responsible for the equipment within the D-26


FMEA. This approval authority should not be delegated to any other individual. These materials should be given a numbered tag and accounted for separately in a long-term logbook. Craft toolboxes and tools are not considered long-term material and will be logged into and out of the FMEA. Workers should inspect the work area and remove potential sources of foreign material prior to initially breaching systems, components, or electrical equipment, and prior to removing temporary FME devices during work performance. Inspections should pay particular attention to overhead areas. If any materials that are brought into FME area must be subdivided, the respective craft foreman must approve the subdivision, and the FME monitor must be notified prior to their subdivision within that FME area. Subdivision of materials inside an FME area must be avoided if at all possible. If subdivision can not be avoided, each piece must be individually tagged after subdivision and identified within the long-term logbook. It is typically the responsibility of the person authorizing the initial access into the FME zone to ensure that the person requesting entry into the FMEA has signed the appropriate documentation and understands the rules for entry into the FMEA. He/she should authorize entry into the FMEA after they have determined that the person requesting entry has full knowledge of the FMEA rules. Upon breaching a system, component, or electrical equipment, workers should perform an initial inspection for any foreign material already present (for example, dirt, loose fasteners, etc.). Foreign material found within or entering a system during task performance that is determined to be immediately retrievable should be promptly removed from the system or component. Workers and/or FME monitors/self-monitors should inform the job supervisor personnel whenever a loss of FME control has occurred or is considered likely to occur. Additional guidance is provided in Section D.7 of this appendix. Workers should ensure that breaches are covered when unattended and whenever work is not actively in progress. FME devices, as described in Section D.6.9 of this appendix, may be used for this purpose; however, reinstalling access panels or closing cabinet doors may be more appropriate in certain cases. Prior to final closure of a breach, the job supervisor should ensure that appropriate personnel perform a thorough inspection to verify that no foreign material is present. When all breaches have been closed (for example, components reinstalled in the system, access covers reinstalled, panel doors closed), FME controls can be relaxed. The job supervisor should ensure that logs used to control work within the FMEA are completed with all discrepancies resolved. The job supervisor should ensure that the following records are included in the work package or transmitted separately for record retention: •

Datasheet (individual entry log)

•

Long-term placement log

•

Printed copies of electronic logs D-27


D.6.6 Examples of Good Work Practices Inside the FMEA The following section describes a number of good work practices that should be implemented when performing maintenance activities inside an FMEA. The list is not all inclusive, and the examples are provided for illustrative purposes only. Users of this report should recognize that not all of the examples may be applicable to a given work order. •

Cover all unattended openings into components.

•

Clean dirt, coal, fly ash, or any other form of debris from around covers, caps, and other devices before opening them for inspection or servicing.

•

When opening critical components, ensure that areas above these components are clean so that no debris will drop into openings of these components. If work will be done overhead while the component is open, cover the open component with tarps or other covering to prevent debris that is dislodged or dropped from entering the component.

•

Ensure that welding electrodes, stubs, and broken flux coating material is removed from components.

•

Clean the work area before beginning work; this may include washing down or vacuuming the area.

•

Orient work so that debris will not drop into components.

•

Cover openings on the main turbine, generator, hot well pumps, boiler circulating pumps, high-pressure boiler feed pumps, etc., during maintenance activities.

•

Ensure that all piping and tubing are free of foreign material before and after installation.

•

Do not introduce material that may produce corrosion into components.

•

Perform shot- and sandblasting only in areas that can be adequately cleaned.

•

Use only approved solvents for cleaning.

•

Use only approved lubricants.

•

Use only approved tapes, plugs, or seals. Some tapes may leave residue (adhesive) that can cause damage.

•

Use approved procedures when flushing systems.

•

Do not allow personal items such as jewelry, change, pens, and so on into the FMEA. No material should be allowed in the FMEA unless it is absolutely necessary.

•

Secure all tools, safety glasses, badges, gloves, and other loose items with lanyards, tape, or other devices.

•

Stage tools, parts, and materials outside the FMEA. Remove all packaging and other unnecessary material before entering the FMEA.

•

Inspect tools for parts that might come off during use. Look for items such as loose handles, splintered wood parts, and loose wire brush bristles. Clean all tools, materials, and parts before entering the FMEA.

D-28


•

Limit the use of clear materials, such as face-shield visors, in the FMEA. They will be difficult to see if they are misplaced. Clear materials should not be used near the spent fuel pool (that is, inside the handrails around the spent fuel pool, the new fuel storage vault, the cask handling vaults, and the fuel handling tool lay-down area). Likewise, do not use clear materials inside the reactor cavity (that is, inside the handrails around the reactor cavity, the lower internals storage area, and the in-containment storage area) due to the inherent difficulty in identifying their presence. Authorized exceptions to this requirement typically include: –

The clear plastic float used to improve water visibility for fuel handling operations, provided it is secured with a lanyard.

–

Items that have been permanently marked so that they are clearly distinguishable in water (for example, a face shield with a black mark around the perimeter).

•

Use vacuum or exhaust systems to remove any generated airborne debris from painting, blasting, grinding, etc.

•

When cutting wires, control the ends that are snipped off.

•

Control all metal debris (screws, connectors, wire strippings, etc.) in all electrical enclosures.

•

Account for all rags, cushions, cardboard, and other miscellaneous items that are used in an FME area.

•

Do not use excessive amounts of lubricants; the excess may collect dirt, ash, and other debris.

•

Follow approved welding practices for the removal of tubes and piping.

•

Ensure that all open pipes, tubes, or systems, 30" (76.2 cm) or less in diameter, regardless of whether they are new, to be re-used, or to be removed, have FME covers in place. This applies to material lying on the floor, hanging in place, or staged in racks, store rooms, or lay-down areas. The only exception is when the tube or pipe is completely disconnected from the system and color coded with bright orange or pink paint to indicate that it is scrap.

•

On vertical runs of tube or pipe, make the first cut at the bottom using an abrasive cutoff wheel or other nonthermal means. Insert a piece of sheet metal into the kerf created. The upper cut can then be made using a thermal method.

•

Perform maintenance activities in a manner that reduces the possibility of introducing foreign material into a system or component. –

Create no situations that cause a loss of a shutdown safety function.

–

When working in electrical enclosures with multiple doors or access openings, open only those doors or access areas required to perform the task.

–

Use caution when opening and working in control cabinets, relay cabinets, or junction boxes to ensure that tools, parts, dirt, debris, or filings do not fall into electrical equipment.

–

Ensure that metal shavings or debris does not enter plant systems or electronic components during drilling activities.

D-29


–

Ensure that the system or component in the field is protected to prevent entry of foreign material during removal of plant equipment for repair or bench calibration.

–

Ensure that FME practices are maintained while working on equipment in shop areas. Items awaiting maintenance should be protected for FME purposes with appropriate covers.

–

When adding or filling oil reservoirs, do not leave the filler cap or sight glass off when unattended.

•

Secure materials while transporting within the FMEA to the extent practical.

•

Do not use tie wraps with metal tabs in areas where dislodged tabs could come into contact with primary systems or nuclear fuel.

•

Do not use clear plastic around water-filled pools or cavities, for example, the spent-fuel pool, reactor cavity, or sumps when flooded.

•

Use visible colors for plastic and tape to the extent practical.

•

Use supplied FME covers to reduce waste volume.

•

Minimize the use of wire brushes because wire bristles fall out easily and will damage fuel if left in primary systems.

D.6.7 Implementing Graded FME Controls Major work activities on critical pieces of main turbine deck equipment pose opportunities to introduce unwanted foreign material into the equipment. This foreign material can challenge the reliable and safe operation of these critical pieces of equipment. To proactively reduce this threat of foreign material introduction, FME controls are exercised during critical equipment maintenance activities. To ensure that there is consistency in the application of these controls, the following guidance is provided to implement a graded FME program on the turbine deck. D.6.7.1

Implementing FME-2 Controls

These controls should be implemented through personal heightened awareness of the opportunities to introduce unwanted foreign material and the consequences of doing so. The controls include minimizing small loose items taken into the area, tethering tools and other equipment that could fall into the space with lanyards, taping pockets that contain small loose items, ensuring that badges are secured by two independent means, etc. Examples of when FME-2 controls should be implemented on the turbine deck include the following: •

Removal of manways on the main turbine outer cylinder covers

•

Removal of manways on the moisture separator reheater shell side or hemi-heads

D-30


•

Removal of the governor or throttle valves on the high-pressure turbine

•

Removal of the low-pressure turbine outer or inner cylinder covers

•

Removal of the high-pressure turbine upper casing

•

Opening of the exciter doghouse access doors or removing the exciter doghouse

•

Removal of the steam generator feed pump turbine (SGFPT) upper casing

•

Removal of the SGFPT lube oil reservoir cover or the HP/LP governor/stop valves

D.6.7.2

Implementing FME-1 Controls

These controls stringently monitor materials taken into and out of the subject space. The controls include determining the original condition of the subject space as controls are first implemented, using trained personnel to log workers and material taken in and out, allowing no loose material (watches, pens, and other personal items) on the workers, securing the space when work is not being performed, etc. Examples of when FME-1 controls should be implemented on the turbine deck include the following: •

Removal of a generator belly manway to permit generator crawlthrough

•

Removal of any upper manway that permits access into the main generator

•

Removal of the hydrogen cooler bundles

•

Removal of a bearing bracket that exposes an opening into the main generator

FME-1 controls may also be conservatively applied when restoring the exciter doghouse back onto its foundation. Application of FME-1 controls provides additional assurance of exciter integrity until the doghouse access doors are ready to be closed and locked. D.6.8 Ensuring Cleanliness Inside the FMEA D.6.8.1

General Guidance

The FMEA should be kept clean to prevent dirt and foreign objects from entering the turbinegenerator components and systems. The FMEA will not be used for parts or material storage or to conduct work that is not essential to outage work for material contained within the FMEA. The FME monitor station worktable should be kept clear and should be maintained in a clean and orderly fashion. Personal items are specifically forbidden to be stowed on the FME work table, but may be stored in specifically designated stowage zones.

D-31


Maintain cleanliness to minimize cleaning after repairs; consider using one or more of the following methods: •

Vacuum components or systems.

•

Wipe with lint-free cloths, either wet, dry, or tacky, as needed.

•

Use dams to minimize the spread of dirt and debris in the systems.

D.6.8.2

Cleanliness Control of Existing Systems and Components

This section applies to activities that open existing systems and components. It includes criteria for closing systems with new components, new portions of systems, and existing components. Users should recognize that serious personnel injury could occur if a system is opened without the proper boundary clearance. D.6.8.2.1

Opening of Existing Systems and Components by the Clean Cut Method

The work package should provide a way to capture fluid that will be released when the opening is made. Maintenance personnel should remove any loose debris in the vicinity where the cut is to be made. If a hard-wheel cutter is to be used, remove the cut debris from the surface with a clean cloth, paper towel, or vacuum cleaner. If the cutting tool to be used is not a hard-wheel cutter, then perform the cutting operation as follows: •

Erect screens, drapes, tents, blankets, and other covers, as required, to protect the surrounding equipment from debris generated by the cutting process.

•

Monitor the cutting area for discoloration (overheating), and perform the cutting operation to reduce as much base metal around the circumference of the pipe as possible without breaking through the inside diameter.

•

If indications of overheating are observed, then move the cutting tool to a new location around the circumference, or suspend the cutting operation until the metal cools.

•

Remove the cut debris from the surface with a clean cloth, paper towel, or vacuum cleaner.

•

Break through the inside diameter by mechanical means (for example, a tubing cutter or chisel). Note that the cleanliness of systems that have been in service will be degraded. The intent of the following inspection is to detect any unusual conditions.

•

Perform the opening cleanliness inspection, and record the “as-found” condition.

•

If the as-found inspection reveals unusual corrosion, erosion, foreign material, etc., then submit the as-found inspection results to the responsible supervisor for an evaluation.

D-32


D.6.8.2.2

Opening of Existing Systems and Components

The work package should provide a way to capture fluid that will be released when the opening is made. Maintenance personnel should perform an opening cleanliness inspection, and record the as-found conditions. If the as-found inspection reveals unusual corrosion, erosion, foreign material, etc., then submit the as-found inspection results to the responsible supervisor for an evaluation. D.6.8.2.3

Maintenance of Opened System

If an opened system is left unattended for any length of time, then maintenance personnel should install a cap, covering, etc., over the opening. If protective caps are removed to perform work and the orientation of the opening is such that foreign material entering the opening would be inaccessible for removal, then the following requirements should be observed prior to performing any activities that could generate foreign material: •

Secure all items small enough to fit inside the opening with a lanyard or other suitable means to the user or fixed framework.

•

Cut and prepare the pipe and components in a position to avoid contamination of crevices, blind holes, deadlegs, undrainable cavities, and inaccessible areas when possible.

•

When all work activities that generate foreign material are complete, remove the foreign material from internal and external surfaces with a clean cloth, paper towel, or vacuum cleaner.

D.6.9 Use of FME Devices D.6.9.1 General Guidance FME devices (for example, covers, internal barriers, and lanyards) should be used in any situation where they reduce the potential for foreign material intrusion, such as: •

Covering open/exposed mechanical and electrical components when they are not being actively worked on in the field.

•

Covering equipment (for example, valves, circuit breakers) removed from systems or switchgear, unless the equipment will be afforded a complete teardown and reassembly.

•

Covering open components or exposed electrical components when they are not being actively worked on in the shop and once equipment is ready for reinstallation in the plant.

•

Covering components stored in the warehouse that cannot be easily verified (that is, with the naked eye aided only by a flashlight) to be free of foreign material prior to installation in the plant.

•

Covering open vent and drain lines more than 1" (25.4 mm) in diameter with a breathable (for example, mesh screen) FME cover. Consideration should be given to installing a breathable FME cover on vent lines less than 1" (25.4 mm) in diameter if they are located in a high traffic area or if maintenance in the vicinity could introduce foreign material. D-33


D.6.9.2 External Temporary FME Covers Canvas soft covers, plastic pipe caps, and hard covers are typically used as external FME covers. Hard covers (for example, aluminum, polyurethane) should be used to cover breaches if soft covers would not prevent the entry of material that could conceivably impact them. Tape should not be used as an FME cover; however, it can be used to affix FME covers in place in oil-free environments. Herculite, Visqueen or equivalent materials can be used to cover openings if appropriate soft or hard covers are not available, provided that it is securely affixed in place. Shrink wrap and original material packaging that provides sufficient protection against foreign material intrusion may be utilized as FME covers while material is in storage. Hoses attached to vent and drain lines are considered adequate substitutes for breathable FME covers. Materials utilized as external FME covers should be: •

Clean and free of loose debris

•

Fire resistant/retardant (based upon the intended application)

•

Made of nonbrittle material

•

Sturdy enough to prevent entry of material that may impact them

•

Resistant to melting if used in high-temperature applications

•

Constructed of materials other than clear plastic

•

Unlikely to deteriorate or decompose during the period of installation

•

Highly visible and/or brightly colored to contrast with the item on which they are used

•

Unlikely to mark or mar the equipment on which it is installed

•

Unlikely to induce corrosion at the point of contact with hardware

•

Should not be used to clean up, stockpile, or transport material

•

Should not damage the adjacent system or component

•

Should not cause any chemical reaction

Whenever practical, FME caps and covers should be clearly marked as serving that purpose (for example, annotated FME, FME Barrier, etc.) using permanent markers, stickers, or other means. FME caps or covers used on vent paths (vent valves, open manways, etc.) on tanks or other structures that are subject to pressure changes should be capable of permitting venting. FME caps and covers should be installed in a manner that makes them unlikely to fall into the system or component during installation or removal. In some cases, it may be necessary to secure FME caps and covers with a lanyard. Care should be taken when removing FME caps and covers to prevent entry of foreign material that may have accumulated on or around the cap or cover. FME covers, when subject to high traffic, abrasion, or other situations that would cause them to fall off or become damaged (such as condensate or residual water draining out of the tube, pipe or system), should be made of steel, aluminum, or substantial plastic. For large-diameter D-34


openings (12" [30.5 cm] or larger), plywood, canvas, or nylon bags should be used. For openings subject to fire fall, grinding, arc air, or any other thermal operation, steel caps should be used. Large-diameter FME covers subject to the support of human weight should conform to OSHA standards. Staged pipe or conduit typically does not require capping or plugging if stored in a waterproof area or stored in a manner that will allow water to drain through. D.6.9.3

Internal Barriers

Internal barriers (for example, inflatable bladders or pipe dams) should possess the same attributes as external FME covers described in the preceding section. Internal barriers should be tethered externally whenever possible to increase their visibility and to avoid their inadvertent loss into the system during work activities. The installation and removal of internal barriers should be documented in the work package and/or on the FME log sheet, if utilized. Maintenance personnel should ensure that the system or component is clean prior to removing the internal barrier to prevent inadvertent introduction of foreign material upon barrier removal. Caution should be exercised when removing internal barriers because pressure from system inleakage may exist and can create a missile hazard. System leakage or draining could also result in a vacuum being drawn within the system so that FME devices could be inadvertently drawn into the system when de-tensioned. Water-soluble paper, if properly utilized, can be used as FME protection during tube or pipe joint preparation. Sponges can also be used as FME protection during tube or pipe joint operations as long as a sponge log is maintained and implemented. Water-soluble cones should not be used as FME prevention during joint preparation. Dams, plugs, or caps should be secured if they cannot be easily retrieved. Removable tape should be used instead of adhesives in contact with bare metal surfaces. Paperbacked (masking) tape is not recommended for use on metallic surfaces. Caution should be exercised to recognize that certain covers or filters used on ventilation systems can cause heat dissipation problems. Temporary filters, such as Scott Foam, should be installed over ventilation louvers and comparable openings on equipment, for example, electric motors, where heavy particulate matter might be present. Openings that are used for access can be provided with a clean room attachment, whereby local cleaning within the room will minimize the possibility of contamination entering through the opening.

D-35


D.6.9.4

Lanyards

D.6.9.4.1

Types and Composition of Lanyards

Lanyards should not be constructed of material that could chip, flake, peel off, or become dislodged. Each lanyard should be inspected and tested by hand to ensure that they are securely attached and are strong enough to resist the breaking force that would result when the attached item is dropped. Using materials that are easily decontaminated decreases the radiological waste generated. Radiological waste increases the cost of doing business and has a negative impact on the environment. Lanyards manufactured from corrosion-resistant steel wire are recommended for applications involving long-term exposure to harsh environments, such as water containing boric acid or spent fuel pools. Nylon lanyards should be discarded if they come into contact with boric acid crystals or borated water. Nylon lanyards should have the ends fused to prevent fraying. “Poly” rope has a history of deteriorating and should not be used in a water environment. D.6.9.4.2

Proper Use of Lanyards

For personnel safety reasons, lanyards should not be used near rotating equipment. Large and readily retrievable items typically do not require lanyards. Power cords should not be used as lanyards. Lanyards should be attached to tools used in an FMEA 1 that are not inherently fail safe. Lanyards provide a back-up method for preventing the loss of tools or materials. Tools or materials should not be allowed to “dangle” so that failure of the lanyard results in the loss of the tool or material. Lanyards of the shortest practical length should be used to minimize the dropping distance and limit the possibility of the dropped object causing damage. Tools or materials should not be suspended by an attached lanyard. Figure D-8 illustrates the proper use of a lanyard.

Figure D-8 Example of Lanyard Use Courtesy of Progress Energy

D-36


Lanyards should not be secured to small-diameter tubing or other equipment that could easily be damaged if the attached item is dropped. D.6.9.5

Control of Activities Producing Particulate Matter

If practical, the component should be removed from the system to minimize particulate contamination. Components that cannot be removed should be drained, wiped clean, and allowed to dry to the maximum extent practical. When grinding or sawing to sever a system component boundary, the actual penetration should be made by means that would introduce the least possible debris or foreign material into the system. If possible, tubing cutters, “clamshell” cutting machines, and portable lathes should be used to cut until the metal is thin; the actual breach should minimize particle loss into the system. Ventilation systems may introduce dirt and debris into the system or component and spread dirt and debris to other areas. The following control measures should be considered, as needed: •

Install temporary filters.

•

Redirect ducts or air flow.

•

Install enclosures such as glove bags or tents at the work site.

•

Install debris dams, plugs, or similar devices to prevent debris from entering the system during activities that could generate particulate matter.

•

Install a removable film or adhesive cloth to line a component cavity to aid in later cleanup.

Stellite debris generated from activities such as valve grinding or lapping are of particular concern because those particles can become highly radioactive after passing through the reactor. Good work practices and thorough close-out inspections are necessary to ensure that Stellite debris is not allowed to enter or remain inside primary plant systems.

D.7

Recovery of Loss of FMEA Control

D.7.1 Initiation of a Condition Report A condition report should be generated to document conditions constituting a loss of FME control, as defined in plant or site procedures; however, efforts to resolve the issue can proceed prior to initiating the condition report, if appropriate for the situation. If the loss of FME control involves unresolved log-keeping discrepancies (for example, unlogged items in an FMEA or logged items unaccounted for), the job supervisor should determine the likelihood of foreign material intrusion having occurred. If intrusion is possible, efforts to locate and recover the material should be implemented. The job supervisor may temporarily defer efforts to recover foreign material until a more appropriate point in the activity—if the material poses no imminent threat to personnel or equipment and a record of the material and its location is recorded in a condition report.

D-37


If foreign material intrusion has occurred and the material involved poses a threat to primary plant systems or fuel assemblies, plant operations should be immediately notified. D.7.2 FME Recovery Plan Plant personnel should not attempt recovery of foreign material that is not immediately retrievable until a written recovery plan has been formulated and approved by key stakeholders. Recovery plans should specify, as appropriate for the situation: •

Information currently known regarding the foreign material (for example, its location, identity, amount)

•

Why the foreign material is not considered immediately retrievable (for example, ALARA concerns, inaccessible location, potential to migrate further within the system)

•

The impact the material may have already had on the plant

•

Any measures that will be implemented to prevent the material from spreading or migrating to other areas (for example, installation of FME devices)

•

Measures to address any ALARA and/or industrial safety concerns associated with recovery efforts

•

How the material will be located (that is, use of borescopes, radiography, remotely operated video cameras, fiber optics, infrared thermography, etc.)

•

How the material will be recovered (that is, use of grappling devices, reach rods with attached adhesives or magnets, vacuuming, system flushes, radiography, robots, etc.).

•

Whether further inspection or disassembly of equipment is required to facilitate recovery efforts, and how this will be accomplished

•

A monitoring plan for ensuring that potentially impacted equipment is functioning normally following its return to service

Supervisors should initiate activities to recover foreign material that is not immediately retrievable in accordance with the recovery plan. The concurrence of the responsible department manager should typically be obtained prior to terminating unsuccessful efforts to retrieve foreign material. D.7.3 Foreign Material Retrieval Maintenance personnel should return the work package to the planner or supervisor for scope changes or additional requirements for post-recovery inspection and acceptance criteria, if appropriate. Foreign material may become highly contaminated after contact with certain systems or components. Retrieval should not be attempted on contaminated systems or components without specific approval by Health Physics.

D-38


Retrieval actions should not introduce more foreign material into the opening or cause the foreign material to penetrate even further into the system or component. Engineering may be consulted to assist in the retrieval method. Foreign material location may be determined by visual inspection, fiber-optic techniques, mirrors, or remotely operated TV cameras. If retrieval is not immediate, an action plan should be in place and scheduled to prevent retrieval activities from causing unnecessary outages or delays. The following methods for retrieving foreign material should be considered: •

Using special snakes with grapples

•

Using adhesives or magnets

•

Disassembling the component

•

Vacuuming

•

Flushing

•

Installing temporary screens or strainers to catch items if flushing is required

Important decisions the supervisor should weigh before any additional actions are initiated that could make the situation worse are: •

Can the foreign material be easily and reliably retrieved?

•

Could the foreign material reposition during recovery, and create a more difficult recovery?

•

Should a multi-discipline team be formed to direct the recovery?

•

Could the foreign material break apart during retrieval?

For foreign material that cannot be readily retrieved, the following actions should be considered: •

Observe the final location of the material dropped.

•

Record any appropriate remarks on the control log.

•

Report any loss or suspected loss of material within systems or components to supervision and operations as appropriate. This is a management expectation and an essential element of a quality FME program.

•

Return the work order to the planner or first line supervisor for a scope change to add additional requirements for post-recovery inspection and acceptance criteria.

•

Initiate a condition report according to the corrective action program for any loss or suspected loss of material in an FMEA. The condition report should document the condition, the foreign material quantity (2 bolts, 1 tie cable, etc.) to the extent practical, and any immediate corrective actions. If there is uncertainty, the supervisor or FME coordinator should be contacted for assistance.

D-39


D.7.4 Recovering Foreign Material After Returning the System to Service If foreign material will not be recovered from a system prior to its being returned to service, then the supervisor should open an action within the existing condition report for appropriate engineering personnel to perform an evaluation. Engineering should evaluate the potential impact of nonrecoverable foreign material in regard to personnel safety, nuclear safety, radiological safety, and plant reliability. The evaluation should include justification for returning systems or components to service despite the presence of the foreign material. As appropriate, the chemistry department may be consulted to determine the chemical effects of the material on system materials, equipment, or water chemistry. If foreign material has entered or could migrate into a primary plant system, the nuclear fuel and analysis organization should assess the potential impact to nuclear fuel.

D.8

Close Out of a Foreign Material Exclusion Area

If direct access to a system or component is not required, in most cases the FMEA may be temporarily closed. Maintenance personnel should review the FME control log, if applicable to ensure tool and material accountability, and return the log to the appropriate supervisor. Systems or components should be restored to their normal operational condition after work completion. If normal system configuration cannot be re-established, a temporary closure device should be installed over any opening not being actively used for work. If breached areas were not sealed with temporary covers while unattended, an independent inspection to verify that foreign material is not present should be performed. To the extent possible, maintenance personnel should ensure that unneeded tools, equipment, material, and debris are removed and good housekeeping requirements are met. Maintenance personnel should inspect the cleanliness of each item being closed as follows: •

Verify the absence of foreign material. If required, use a camera, fiber optics, mirrors, or other tools in areas where material could have fallen out of the direct line of sight (for example, transition areas from vertical to horizontal).

•

Verify that the cleanliness of the existing systems and components has not degraded beyond the as-found cleanliness.

•

If the cleanliness is unacceptable, submit the unacceptable results to the responsible supervisor for an engineering evaluation; or clean the unacceptable area, and verify that the cleanliness of the cleaned area is acceptable.

•

Document the cleanliness just prior to closing the system or component.

Work inside the drywell and torus should include good housekeeping practices on a task-by-task basis to support FME. Final close-out inspections provide an additional barrier to support FME.

D-40


Maintenance on building spray or systems that interface with the borated water storage tank could result in blockage of the reactor building spray header or associated nozzles. A loss of FME control in these areas requires a documented visual inspection or surveillance testing to validate operability. Tools should not be stored in control, instrument, buss, or breaker cabinets because tools can become missiles during a seismic event. The space above the FME areas should be inspected as appropriate for uncontrolled or loose material. Operational experience (OE) has shown that items have been dropped from cranes, scaffolding, and platforms into the FMEA. Systems or components with hidden areas are of a particular concern during final inspection because any item dropped or left behind may not be seen during a close-out inspection without further disassembly. Examples include any of the following: •

Valves or other components in vertical piping runs or above closed vessels

•

Primary side of a steam generator with nozzle dams removed

•

Electrical enclosures, for example, switchgears, motor control centers, or control cabinets

•

Open electrical conduits and buss ducts

•

Breakers, transformers, and motors

OE has shown that condensers are common places to find foreign material. If a turbine component or piping is opened above, allowing access to the condenser, a foreign material inspection should be performed. Maintenance personnel should remove any FMEA identification signs. The supervisor or designee should perform a final foreign material inspection and review the FME control log to ensure tool and material accountability; document these inspection results on the work package instructions, cleanliness data sheet, or the plant/site FME control plan.

D.9

References

1. FME Guidelines: Revision 1 of TR-106756. EPRI, Palo Alto, CA: 2005. 1009707. 2. Steam Generator Foreign Object Task Force Review Material. EPRI, Palo Alto, CA: 2006. 1012921. 3. Foreign Material Exclusion Program, Procedure MA-AA-716-008. Revision 2, Exelon Nuclear, Warrenville, IL. 4. Foreign Materials Exclusion Program, Procedures OPGP03-ZA-0014, Revision 7. STP Nuclear Operating Co., South Texas Project, Palacios, TX: 2005.

D-41


5. Turbine-Generator Foreign Materials Exclusion Zone Performance Guide, 8th Edition. STP Nuclear Operating Co., South Texas Project, Palacios, TX: 2005. 6. Foreign Material Exclusion Requirements for Outside Contract Construction Personnel. AmerenUE, St. Louis, MO: 2004. 7. Foreign Material Exclusion Program, Procedure MNT-NGGC-0007, Revision 6. Progress Energy, Nuclear Generation Group, Raleigh, NC. 8. FGD Foreign Material Exclusion, Procedure MNT-FGDX-00020, Revision 0. Progress Energy, Fossil Generation Department, Raleigh, NC: 2003. 9. Turbine Foreign Material Exclusion (FME), Procedure SA1-7 FME 0001 PS, Revision 0. FirstEnergy, Akron, OH: 2004. 10. Foreign Material Exclusion, Nuclear Procedure N-PROC-MA-0018, Revision 7. Ontario Power Generation, Pickering Nuclear Plant, Pickering, ONT: 2006.

D-42

SED

R I A L

LICE

N

M AT E

Export Control Restrictions

The Electric Power Research Institute (EPRI), with major

Access to and use of EPRI Intellectual Property is granted with the

locations in Palo Alto, California; Charlotte, North Carolina; and

specific understanding and requirement that responsibility for ensur-

Knoxville, Tennessee, was established in 1973 as an independent,

ing full compliance with all applicable U.S. and foreign export laws

nonprofit center for public interest energy and environmental

and regulations is being undertaken by you and your company. This

research. EPRI brings together members, participants, the Institute’s

includes an obligation to ensure that any individual receiving access

scientists and engineers, and other leading experts to work

hereunder who is not a U.S. citizen or permanent U.S. resident is

collaboratively on solutions to the challenges of electric power. These

permitted access under applicable U.S. and foreign export laws and

solutions span nearly every area of electricity generation, delivery,

regulations. In the event you are uncertain whether you or your com-

and use, including health, safety, and environment. EPRI’s members

pany may lawfully obtain access to this EPRI Intellectual Property, you

represent over 90% of the electricity generated in the United States.

acknowledge that it is your obligation to consult with your company’s

International participation represents nearly 15% of EPRI’s total

legal counsel to determine whether this access is lawful. Although

research, development, and demonstration program.

EPRI may make available on a case-by-case basis an informal assessment of the applicable U.S. export classification for specific EPRI

Together...Shaping the Future of Electricity

Intellectual Property, you and your company acknowledge that this assessment is solely for informational purposes and not for reliance purposes. You and your company acknowledge that it is still the obligation of you and your company to make your own assessment of the applicable U.S. export classification and ensure compliance accordingly. You and your company understand and acknowledge your obligations to make a prompt report to EPRI and the appropriate authorities regarding any access to or use of EPRI Intellectual Property hereunder that may be in violation of applicable U.S. or foreign export laws or regulations.

Program: Steam Turbines, Generators, and Balance-of-Plant

© 2007 Electric Power Research Institute (EPRI), Inc. All rights reserved. Electric Power Research Institute, EPRI, and TOGETHER...SHAPING THE FUTURE OF ELECTRICITY are registered service marks of the Electric Power Research Institute, Inc.

Printed on recycled paper in the United States of America

1014730

Electric Power Research Institute 3420 Hillview Avenue, Palo Alto, California 94304-1338 • PO Box 10412, Palo Alto, California 94303-0813 USA 800.313.3774 • 650.855.2121 • [email protected] • www.epri.com

Over Haul of steamTurbine

Recommend Documents