Hydropower Asset Management Using Condition Assessments and Risk-Based Economic Analyses

September 2006

Disclaimer This manual consists of information intended for internal use by the hydroAMP organizations. The tests, methods, and procedures described herein represent a consensus of subject matter experts within the partnership organizations. Any information regarding commercial products or firms may not be used for advertising or promotional purposes and is not to be construed as an endorsement. This document is considered public information and may be distributed or copied. Reprints or republications should include a credit substantially as follows: “hydroAMP (Hydropower Asset Management Partnership) Guidebook.”

Executive Summary

Hydropower Asset Management

Using Condition Assessments and Risk-Based Economic Analyses

Developed by the Hydropower Asset Management Partnership: Bureau of Reclamation, Hydro-Québec, U.S. Army Corps of Engineers, and

Bonneville Power Administration Background Aging and deteriorating hydroelectric powerplant equipment poses considerable risk to reliability and may result in low generating unit availability. Significant investment in replacing, repairing, and refurbishing hydroelectric generating and auxiliary equipment is required to assure the continued viability and cost-effectiveness of existing hydropower assets. Successful strategic planning for capital investments in hydropower facilities requires consideration and balancing of many factors, including the risk of equipment failure. The four organizations involved in the Hydropower Asset Management Partnership (hydroAMP) joined together to create a framework to streamline and improve the evaluation of the condition of hydroelectric equipment and facilities in order to support asset management and risk-based resource allocation. Condition Assessments Technical teams comprised of experts from the four hydroAMP organizations developed condition assessment guides for key hydroelectric powerplant components, falling into two classes. The first equipment class includes major power train components, such as circuit breakers, excitation systems, generators, governors, transformers, and turbines. The second class consists of auxiliary components, including batteries, compressed air systems, cranes, emergency closure gates and valves, and surge arresters. A two-tiered approach for assessing hydropower equipment condition was developed. Tier 1 of the assessment process relies on test and inspection results that are normally obtained during routine operation and maintenance (O & M) activities. Equipment age, O & M history, and other relevant Condition Indicators are evaluated and combined with the test results to compute a Condition Index. An additional, stand-alone indicator is used to reflect the quality of the information available for scoring the Condition Indicators. The Condition and Data Quality Indicators and the Condition Index for each piece of equipment are easily tracked using a Computerized Maintenance Management System or other database tools. The second, or Tier 2, phase of the condition assessment utilizes non-routine tests and inspections to refine the Condition Index obtained during the Tier 1 assessment. Tier 2 tests often require specialized expertise or instrumentation, depending on the problem or issue being investigated. A low Condition Index or Data Quality Indicator score from the Tier 1 assessment may indicate the need for a Tier 2 evaluation.

Individual equipment condition assessment results can be combined to develop an aggregated assessment of a complete power train unit as well as an entire generating station. These summary indices are designated Unit Index and Station Index, respectively. Analytical Tools The path that leads from a condition assessment to an investment decision is vitally important to the management of hydropower facilities. The analytical tools described in this Guidebook are intended to help decision makers develop and maneuver that path. These tools form a link between the technical tasks that make up a condition assessment and the economic and risk analyses that guide maintenance management and resource allocation. Two types of analyses are presented, designated Type 1 and Type 2. A Type 1 analysis considers equipment condition and cost alone – all that may be needed to make an investment decision in some cases. A more complex analytical approach, described as a Type 2 analysis, is useful for evaluating and prioritizing various investment scenarios. It uses all factors from Type 1 and introduces additional factors that relate to the possible consequences of undertaking or not undertaking a repair or replacement action (e.g., legal, regulatory, safety, environmental, and economic consequences). Several case studies and appendices with supporting information are provided to further describe the risk and economic analysis concepts. Data Management A hydroAMP database was developed to allow plants and organizations to input their equipment condition data into a single database in a standardized format. It also allows for individual plant and utility analysis and reporting. The database is real-time and web-accessible, and provides centralized data entry, storage, and retrieval for hydroAMP assessments. The database can be accessed through the internet at the following address: https://secure.bpa.gov/hydroAMP/. An account is required to access the database. Contact your organization’s hydroAMP coordinator to establish an account. Implementation The condition assessment tools and economic analyses described in this Guidebook are currently being implemented within the hydroAMP organizations. After an initial period of use (approximately 12 to 18 months), feedback from users will be solicited and used to improve and enhance the tools, processes, and results.

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Table of Contents

Page

Section I: Overview ................................................................................................ 1 Background................................................................................................... 1 Hydropower Asset Management Partnership (hydroAMP) ........................ 1 Strategic Goals.............................................................................................. 2 Principles ..................................................................................................... 2 Intended Users ............................................................................................. 3 General Methodology................................................................................... 4 Section II: Equipment Condition Assessment ....................................................... 6 Introduction ................................................................................................. 6 Tier 1 Assessment......................................................................................... 6 Tier 2 Assessment ........................................................................................ 7 Documentation ............................................................................................ 8 Unit and Station Indices .............................................................................. 8 Computerized Maintenance Management System (Maximo®)................... 11 Condition Assessment Database................................................................... 12 Section III: Tools for Prioritizing Projects Using a Risk Analysis Approach ................................................................. 14 Introduction ................................................................................................. 14 Types of Analyses ....................................................................................... 15 Type 1 Analysis ................................................................................. 15 Type 2 Analysis ................................................................................. 16 Section IV: Case Studies......................................................................................... 18 Introduction ................................................................................................. 18 Type 1 Analysis............................................................................................ 18 Type 2 Analysis ........................................................................................... 20 North Pacific Region Spare Transformer Project ........................................ 23 Conclusion ................................................................................................... 27

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Appendices Page

Appendix A: Key Terms......................................................................................... 29 Appendix B: Maximo® Loading Procedures ........................................................ 31 Introduction ................................................................................................. 31 Overview ...................................................................................................... 31 Procedures ................................................................................................... 33 Example: Long Description of Job Plans ..................................................... 34 Recording Set Point Values on Work Order ................................................ 36 Condition Assessment Report ...................................................................... 37 Appendix C: Example Economic Analysis of a Facility Upgrade – Generator and Turbine Replacement ........................................................... 40 Appendix D: hydroAMP Team Members and Contributors................................... 45 Appendix E: Equipment Condition Assessment Guides1 ...................................... 47

1 Due to the large number and size of the condition assessment guides, they are available as separate electronic files. For more information, contact your organization’s hydroAMP coordinator.

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List of Figures

Page

Figure I-1: Overall Flow of Equipment Assessment and Decision-Making Process ............................................................................................... 5 Figure B-1: Condition Monitoring Application .................................................... 33 Figure B-2: Job Plans ............................................................................................ 34 Figure B-3: Long Description of Job Plans............................................................ 35 Figure B-4: Work Order Tracking.......................................................................... 36 Figure B-5: Report Viewer..................................................................................... 37

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List of Tables

Page Table II-1: Condition Index Ratings of Equipment ............................................. 7 Table II-2: Condition Indices of Power Train Components ................................. 9 Table II-3: Component Weights ........................................................................... 9 Table II-4: Condition Ratings of Units and Station ............................................. 10 Table III-1: Risk Map ............................................................................................ 17 Table III-2: Beta Tables ......................................................................................... 17 Table IV-1: Factors for Type 1 Analysis (Case 1) ................................................ 19 Table IV-2: Factors for Type 1 Analysis (Case 2) ................................................ 20 Table IV-3: Failure Factors for Type 2 Analysis ................................................... 21 Table IV-4: Transformer Condition Assessment Guidelines ................................ 24 Table B-1: Equipment / Set Point Name List ....................................................... 38 Table C-1: Cost of Replacement Components for Each Unit .............................. 40 Table C-2: Comparison of Costs between Alternatives ....................................... 41 Table C-3: Increases in Benefits for Each Alternative ......................................... 42 Table C-4: Savings in Maintenance Costs ........................................................... 43 Table C-5: Summary of Results ........................................................................... 43

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Section I: Overview Background Successful strategic planning for capital investments in existing hydropower facilities requires consideration and balancing of many factors, including the risks and consequences of equipment failure. The hydropower community has long recognized the importance of assessing the condition of existing equipment in order to make informed and sound business decisions for the replacement of that equipment. Early attempts to develop condition assessment tools, however, were not completely successful. One formal approach for assessing the condition of hydroelectric equipment existed in the Corps of Engineers’ Repair, Evaluation, Maintenance and Rehabilitation (REMR) Research Program undertaken in the early 1990s. Prior to the REMR guidance, numerous test reports and memoranda had to be researched to make a determination of equipment condition. REMR was intended to provide guidance and a standard methodology for making condition assessments, and to consolidate the assessments into a uniform format. However, feedback from the projects using this tool indicated dissatisfaction with the REMR program for the following reasons:

• The equipment evaluation processes tended to be unwieldy, requiring too many tests, inspections, and measurements.

• The evaluation procedures and results were not properly validated and calibrated. • There was no convenient and consistent method to capture, retrieve, and utilize the data

being collected. As a result of this feedback, there were many discussions concerning the need to revise or rewrite the REMR guidance. Concurrent with these discussions within the Corps of Engineers (COE), other industry leaders were wrestling with this same issue, and in 2001, the Bureau of Reclamation (BOR) and Hydro-Québec (HQ) signed a formal partnership agreement to develop guidance for assessing the condition of their hydroelectric equipment. The Corps of Engineers’ Hydroelectric Design Center (HDC) was invited to participate in exploratory discussions in October 2001. The Bonneville Power Administration (BPA) joined the partnership shortly thereafter. Hydropower Asset Management Partnership (hydroAMP) Representatives from the four organizations met to discuss their respective goals and objectives. This resulted in a decision to collaborate in the development of hydropower asset management tools related to equipment condition assessments, investment prioritization methods, and evaluation of business risks. The Hydropower Asset Management Partnership (hydroAMP) identified the following concerns:

• A majority of critical equipment in hydroelectric facilities in North America is near or beyond its design life.

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• Equipment reliability contributes significantly to system generation availability. • The need for significant investment in repairing, refurbishing or replacing existing

generation and auxiliary equipment within hydroelectric projects is anticipated. • An opportunity exists to increase generation efficiency through investments in improved

control systems, operations, and equipment. • The process for identifying and prioritizing investments needs strengthening. • Establishment of an objective, consistent, and valid assessment process is critical. • Equipment condition assessment tools used in the past have been too complex and costly.

Strategic Goals The goal of hydroAMP was to create a framework to streamline, simplify, and improve the evaluation and documentation of hydroelectric equipment condition to enhance asset and risk management decision-making. The team recognized that equipment condition assessments support:

• Development of long-term investment strategies. • Prioritization of capital investments. • Coordination of O & M budgeting processes and practices. • Identification and tracking of performance goals.

Principles The partnership agreed that the following principles would be applied during development of the equipment condition assessment methodology. Specifically, the hydroAMP framework should:

• Be guided and managed through a collective team effort. • Be designed for fair and equitable application to all hydroelectric projects. • Result in an objective and repeatable assessment of the major equipment and critical

systems in the generation power train. • Start small (i.e., would not initially include all critical equipment and systems) and grow

over time as experience is gained. • Be streamlined to minimize the time and expense required for testing, evaluating data,

developing conclusions, and record keeping. • Rely on existing O & M records and routine inspections and tests applied at regular

intervals. • Be technically sufficient although not necessarily “perfect.” • Be field-tested and assessed periodically. • Be open to continuous improvement. • Be adaptable for different users, purposes, and situations.

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Intended Users This Guidebook was developed for use and implementation by all of the partnership agencies. Therefore, the hydroAMP tools were designed to be open and flexible to fit into existing maintenance, planning, budgeting, and decision-making structures. These processes are also intended to serve multiple users within an agency who may have distinct roles and responsibilities for hydropower asset management. Typical users of the hydroAMP tools include the following: On-Site Plant Staff. In general, these are the individuals who work with the equipment on a daily basis and will have a direct role in performing the equipment condition assessments. The information provided by the on-site staff is the foundation of the asset management process. Plant staff will typically:

• Perform Tier 1 equipment condition assessments. • Record the data in the maintenance management system. • Collaborate with technical specialists conducting Tier 2 tests or inspections. • Use equipment condition information to manage their operation and maintenance

activities. Plant or Facility Managers. These individuals may use the hydroAMP processes to:

• Support plant maintenance, rehabilitation, or replacement decisions. • Evaluate equipment condition assessment data and trends, in conjunction with other

business decisions factors, to recommend additional analyses for certain components or systems.

Technical Staff. This group consists of engineers, economists, environmentalists, biologists, and other staff and technical specialists who are responsible for preparing detailed evaluations and justifications for larger, more complex decision packages. They may use the risk-based methodologies to analyze data as requested by the decision makers. In summary, technical staff use equipment assessments and prioritization tools to:

• Justify Tier 2 analyses. • Support economic analyses. • Support risk analyses. • Support regional or multiple project analyses.

Asset Managers. These individuals may use the hydroAMP processes to:

• Prioritize competing investment needs. • Analyze various business cases or justifications for investment decisions. • Support decisions that consider tradeoffs between competing needs or conflicting

requirements.

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General Methodology The equipment condition assessment and decision-making process involves three distinct phases: Tier 1 assessment, Tier 2 assessment, and a Business Decision.2 Tier 1 represents the start of the condition assessment process and culminates in the determination of an equipment Condition Index. The Tier 1 assessment relies on test and inspection results that are normally obtained during routine operation and maintenance (O & M) activities. Equipment age, O & M history, and other relevant Condition Indicators are evaluated and combined with the test results to compute the Condition Index. The Condition Index is scored on a 0 to 10 numerical scale and results in a good, fair, or poor rating. An additional, stand-alone indicator is used to reflect the quality of the information available for scoring the Condition Indicators. Given the potential impact of poor or missing data, a Data Quality Indicator is rated as a means of evaluating and recording confidence in the final Condition Index. Additional information regarding equipment condition may be needed to improve the accuracy and reliability of the Condition Index. If so, Tier 2 inspections, tests, and measurements may be performed. These tests are considered non-routine and may require specialized expertise or test equipment. An outage and some disassembly of the component under test may also be required. Results of the Tier 2 analysis may either increase or decrease the score of the Condition Index. The Data Quality Indicator score may be revised during the Tier 2 assessment to reflect the availability of additional information or test data.

Condition assessment guides are available for the major power train components, i.e., circuit breakers, excitation systems, generators, governors, transformers, and turbines. Assessment guides have also been developed for important auxiliary equipment and systems including batteries, compressed air systems, cranes, emergency closure gates and valves, and surge arresters. It may be desirable to combine individual condition assessment results into an aggregated assessment representing the entire power train unit, or perhaps the entire generating station. Accordingly, a method for performing these calculations is presented in the Guidebook. The resulting summary indices are designated the Unit Index and Station Index, respectively. Condition assessments can also be used to identify condition trends in equipment types of different ages. This Guidebook outlines several approaches for evaluating risk and prioritizing hydropower investment opportunities. The simplest approach, a Type 1 analysis, uses Condition Indices and cost to prioritize, rank, and sort equipment needs. Alternatively, a more complex business case may be developed using a Type 2 analysis which takes into account legal, regulatory, safety, environmental, economic, and/or other concerns. Economic analyses may be done horizontally across an organization to determine replacement timing and order for similar types of equipment, for example, a transformer or circuit breaker replacement program. Condition assessment information can also be evaluated vertically using

2 Definitions of key terms are given in Appendix A

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the aggregated Unit Index or Station Index to identify the “weakest link” in the power production chain. The overall flow of the assessment and analyses processes are illustrated in Figure I-1.

Figure I-1: Overall Flow of Equipment Assessment and Decision-Making Process.

Start Tier 1 - Track trends in equipment performance and condition via routine periodic maintenance

Tier 1

Tier 2

Monitor & Adjust CI

Business Analysis/

Risk-BasedDecision

On-site maintenance, etc.

Is action required?

Complete

Business Justification and/or Record

Tier 2 - Additional tests and inspections, if needed

Is the action needed immediately?

Yes

Yes

Calculate Condition Index (CI) – Assign rating of Good, Fair, or Poor

No

Prioritize and Complete

Business Analysis (Risk of failure, economic

consequences, etc.)

Should investment be considered for action

during next cycle?

Tier 2 - Additional tests and inspections, if needed

No

No

Yes

Is the investment justified?

Yes

No

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Section II: Equipment Condition Assessment Introduction The hydroAMP technical teams have developed equipment condition assessment guides for the following major power train equipment and auxiliary components:

• Batteries • Circuit Breakers • Compressed Air Systems • Cranes • Emergency Closure Gates and Valves • Excitation Systems • Generators • Governors • Surge Arresters • Transformers • Turbines

The condition assessment guides are presented in Appendix E. Each guide is a stand-alone document developed for evaluating a specific piece of equipment or system. The guides are not intended to define component maintenance practices or provide detailed procedures for performing inspections, tests, or measurements. Utility-specific maintenance policies and procedures must be consulted for such information. The condition assessment process assumes that inspections, tests, and measurements are conducted on a schedule that provides accurate and current information needed by the assessment. In some cases, however, it may be necessary to acquire additional data prior to the assessment. Tier 1 Assessment The methodology outlined in the condition assessment guides is divided into two tiers or levels. A Tier 1 assessment relies on test and inspection results that are normally obtained by on-site staff as part of routine operation and maintenance or by examination of existing data. Each guide defines the Condition Indicators generally regarded by hydro plant engineers as providing the initial basis for assessing equipment condition. Generally, the following Condition Indicators are used to evaluate the equipment condition:

• Physical Inspection • Tests and Measurements • Operation & Maintenance History • Age or Number of Operations

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Numerical scores are assigned to each Condition Indicator using the guidelines provided. The scoring criteria may refer to conditions such as “normal” and “degraded.” These relative terms are intended to reflect industry-accepted levels for equipment of similar design, construction, or age operating in a similar environment, or to baseline or previous (acceptable) levels. In some situations, determination of the Condition Indicator scores is subjective and must rely on the experience and opinions of personnel conducting the maintenance or inspection. Weighting factors are applied to the Condition Indicator scores, which are then summed to compute the Condition Index. Weighting factors account for the fact that certain Condition Indicators reflect the actual equipment condition more than other indicators. The weighting factors also normalize the Condition Index to a score between 0 and 10 and result in a rating system as shown in the following table:

Table II-1: Condition Index Ratings of Equipment

Condition Index (CI)

7 ≤ CI ≤ 10 Good

3 ≤ CI <7 Fair

0 ≤ CI < 3 Poor An additional stand-alone indicator is used to denote the quality of the information available for scoring the Condition Indicators. Although reasonable efforts should be made to perform the Tier 1 tests and inspections, in some cases, data may be missing, out-of-date, or of questionable integrity. Any of these situations could affect the accuracy of the associated Condition Indicator scores as well as the validity of the overall Condition Index. Given the potential impact of poor or missing data, a Data Quality Indicator is assigned a value of 0, 4, 7, or 10 as a means of recording confidence in the final Condition Index. The more current and complete the assessment information, the higher the rating for this indicator. Tier 1 tests may indicate abnormal conditions that must be addressed immediately or that can be resolved via standard corrective maintenance solutions. To the extent that Tier 1 tests lead to immediate corrective actions being taken, appropriate adjustments to the Condition Indicator scores should be made and the new results used to compute a revised Condition Index. The Data Quality Indicator score may also be updated to reflect the availability of additional information or test data. Tier 2 Assessment As a result of the Tier 1 assessment, additional information may be required to improve the accuracy and reliability of the Tier 1 Condition Index or to evaluate the need for more extensive maintenance, rehabilitation, or equipment replacement. Therefore, each condition assessment guide describes a “toolbox” of Tier 2 inspections, tests, and measurements that may performed, depending on the specific issue or problem being pursued. A Tier 2 assessment is considered

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non-routine. Tier 2 inspections, tests, and measurements generally require specialized equipment or expertise, may be intrusive, or may require an outage to perform. For certain types of equipment, there are many tests that can provide information about different aspects of component condition. The choice of which tests to apply should be made based on the Tier 1 assessment as well as information obtained via review of O & M history, physical inspection, other test results, and company standards. Results of the Tier 2 analysis may either increase or decrease the Condition Index. In some cases, more than one Tier 2 test may be available to detect or confirm a single defect or state of deterioration. It is important to avoid over-adjusting the Condition Index simply because two or more tests confirm or disprove the same suspected problem. In the event that multiple tests are performed to assess the same problem or concern, the test with the largest adjustment would normally be used to recalculate the Condition Index. Since the Tier 2 tests are being performed by and/or coordinated with knowledgeable technical staff, the decision as to which test is more significant and how different tests overlap is left to the experts. An adjustment to the Data Quality Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment. Documentation The condition assessment results are recorded on the Condition Assessment Summary form at the end of each guide. The Tier 1 portion of the form contains a table listing the Condition Indicators with their respective weighting factors. The indicator scores are multiplied by the appropriate weighting factor and then summed to arrive at the Tier 1 Condition Index. In the Tier 2 section, the Condition Index may be adjusted by the results of the Tier 2 inspections, tests, and measurements. Substantiating documentation is beneficial to support findings of the condition assessment, particularly where a Tier 1 Condition Indicator score is low or where Tier 2 results in subtractions to the Condition Index. Test reports, photographs, O & M records, and other documentation are important to support the equipment condition assessment summary. Unit and Station Indices To assist facility managers and other decision-makers, the condition assessment results can be used to develop an aggregated assessment of a complete power train unit as well as an entire generating station. Strategic importance, lost revenues as a result of equipment failure, reliability criticality, forced outage rates, environmental concerns, and other factors are important considerations when developing Unit and Station Indices. To illustrate a method of determining Unit and Station Indices, consider the fictitious XYZ Hydropower Station. It has six (6) power train units, each consisting of the following components: generator, transformer, turbine, governor, exciter, and circuit breaker as shown in Table II-2. The condition indices for the power train components of the six units have been

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deliberately selected to illustrate different equipment condition scenarios. A single, distinct component has been designated as the “weak link” in each unit for this illustrative example. The condition color-coding scheme follows that of Table II-1.

Table II-2: Condition Indices of Power Train Components

Unit XYZ Hydropower Station

1 2 3 4 5 6 Generator 2.9 6.8 8.9 6.0 7.8 9.0 Transformer 5.0 6.0 2.3 7.3 5.4 4.0 Turbine 6.4 4.3 8.0 2.3 4.2 5.0 Governor 4.2 6.9 5.0 5.9 2.0 6.3 Exciter 8.4 2.9 6.0 6.7 7.0 3.5 Circuit Breaker 9.0 5.0 7.3 6.5 2.0 9.0 As shown in Table II-3 below, each component in the power train has been assigned a weight based on how critical it is to overall power production. The generator is deemed the most critical component and is weighted 0.30. The circuit breaker is the least critical component and is weighted 0.05. Although the specific component weight rating and scales selected for this example are appropriate, they may not reflect the best weighting for every situation. Therefore, it should be noted that the individual component weights may be varied as long as their sum equals 1.00.

Table II-3: Component Weights

Component Weight Generator 0.30 Transformer 0.25 Turbine 0.20 Governor 0.10 Exciter 0.10 Circuit Breaker 0.05 Sum 1.00

A condition threshold value or Condition Index Trigger Value has been set at 3.0, as shown in Table II-4. Accordingly, each component with a Condition Index of 3.0 or higher (i.e., a rating of fair or good) is given a modified component rating equal to the weight assigned to the component. For instance, a generator in fair or good condition is given a rating of 0.30. If the component’s Condition Index is less than 3.0 (poor), a rating of zero is assigned. The Unit Index is determined by summing the modified condition ratings, which is simply the sum of the

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weights for all components in either fair or good condition. As shown in Table II-4, higher Unit Indices result when the more critical components are in good or fair condition. A power train unit is considered to be in good condition if its Unit Index is greater than 0.85, in fair condition if its index is greater than 0.75 and less than or equal to 0.85, and in poor condition if its index is 0.75 or below. It should be recognized that the Unit Index rating does not affect the actions required to improve the condition of a poor reliability component since the failure of an individual component in the power train can result in a major forced outage. The Station Index represents the average of the Unit Indices.3 In this simplified example, the resulting Station Index is 0.83 [(0.7 + 0.9 + 0.75 + 0.8 + 0.85 + 1.0) ÷ 6], indicating that XYZ Hydropower Station is in fair condition.

Table II-4: Condition Ratings of Units and Station

Condition Index Trigger Value 3.0

Unit Modified Condition Ratings 1 2 3 4 5 6

Generator 0.00 0.30 0.30 0.30 0.30 0.30 Transformer 0.25 0.25 0.00 0.25 0.25 0.25 Turbine 0.20 0.20 0.20 0.00 0.20 0.20 Governor 0.10 0.10 0.10 0.10 0.00 0.10 Exciter 0.10 0.00 0.10 0.10 0.10 0.10 Breaker 0.05 0.05 0.05 0.05 0.00 0.05 Unit Index 0.70 0.90 0.75 0.80 0.85 1.00 Station Index 0.83

Unit and Station Ratings Good Fair Poor Unit Index >0.85 >0.75 and ≤0.85 ≤0.75 Station Index >0.85 >0.75 and ≤0.85 ≤0.75

3 The condition of the auxiliary components is not considered in the station index calculation.

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Computerized Maintenance Management System (Maximo®) The equipment condition assessment process can be easily adapted to a Computerized Maintenance Management System (CMMS) to:

• Store the Tier 1 equipment condition assessment procedures • Record and track Condition Indicator scores and weighting factors • Compute the equipment Condition Index • Store data for historical analyses

Maximo® is the CMMS that is currently being used by all of the hydroAMP partners. It serves as a tool for facility managers to understand the condition of their equipment and to better prioritize needed maintenance or replacement activities. It also serves to meet applicable facility condition assessment requirements. The equipment condition assessment procedure is loaded into Maximo® using the following three component applications: 1. Job Plan Application

A Job Plan application stores definitions that define the ratings that assess the condition of a class of power equipment. A Maximo® job plan has been created for each type of equipment (e.g., turbine, transformer).

2. Preventive Maintenance Application

A Preventive Maintenance (PM) application links the Job Plan from equipment classification (e.g., transformer) to a specific piece of equipment. After the PM record is established, the PM schedule is set to generate work orders on an annual interval.

3. Condition Monitoring Application

The Condition Monitoring application establishes and links measurement points to specific equipment. The condition assessment process rates equipment conditions using measurement point values entered in Condition Monitoring or on work orders.

When Maximo® is used to record condition assessment results, the supporting documentation (e.g., test reports, photographs, O & M records) should be attached to the work order. See Appendix B for a detailed description of loading the equipment condition assessment procedure into Maximo®.

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Condition Assessment Database Even though maintenance management systems such as Maximo® can be used to record the results of condition assessments, the hydroAMP team believed it was valuable to develop a hydroAMP database to store results arising from these assessments. The database has several important features; namely, accessibility through the internet, real-time updating of results, and tracking of trends in Condition Indicators and Indices over time. BPA engaged its information technology specialists to develop the database based on input from COE engineering and maintenance staff. While the hydroAMP database is currently hosted and maintained on BPA’s website (https://secure.bpa.gov/hydroAMP/), it is available for use by any participating hydroAMP organization for data input, storage, and retrieval. The site is password protected with access granted on a case-by-case basis. Database Input

The database and website use MSSQL and ASP.net technologies. Data entry is largely accommodated through pull-down menus with Condition Indices automatically calculated and ratings assigned. The database can be updated by simply logging onto the website and updating user entry forms within the system. All updates made in this fashion are available immediately via the reporting tools. We are in the development stage of creating a file updating standard and procedure that will allow for export of updates directly from any maintenance management system, such as Maximo®.

Website Menu Options:

• Condition Assessments – Input equipment condition data for Tier 1 assessment. • Equipment – Add, update and delete equipment for specific plants. • Reports – View and export condition assessment reports. • My Account – View and make changes to your account. • Help – Provides links and contacts for information.

Database Output

The hydroAMP website has been developed such that a number of reports can be generated directly by the system. These reports give summary information and are available directly through the user’s web browser. All reports are exportable in multiple formats depending upon user preference; HTML, PDF, Microsoft Excel, Tiff images, CSV, or XML. Database Users and Contacts

The hydroAMP database is available to operation and maintenance staff, plant managers, technical support staff, and investment decision makers of the hydroAMP organizations. The development of hydroAMP was initially funded by the partner organizations. Implementation and maintenance of hydroAMP is currently being funded by the COE, BOR, and BPA.

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Database Access

To access the hydroAMP database, and for security reasons, individuals wanting access to the system are required to open an account. The account will include a log-in, password, and permissions. The permissions involve two parameters – first, what actions you as a user will be performing (e.g., read, read/write, or management review) and secondly, which hydro projects/plants you have authorization to view and/or edit. All requests for access to this database, and for reporting problems or concerns, should be sent to the hydroAMP e-mail address hydroamp@bpa.gov and must include your full name, e-mail address, phone number, and the plants for which you are requesting access. The hydroAMP administrator will assign log-ins and passwords and respond to you via e-mail.

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Section III: Tools for Prioritizing Projects Using a Risk Analysis Approach Introduction In the preceding section, we presented detailed steps, including tests and inspections, to assess the condition of major power train equipment and auxiliary components at a hydro plant. These comprehensive condition assessments are a critical factor for planning maintenance and capital investments. But they are not the only factors. The path that leads from a condition assessment to an investment decision is an important part of managing large hydro plants for maximum benefit. The analytical tools described in this section are intended to help decision makers develop and maneuver that path. They are the link between the technical and engineering tasks that make up a condition assessment and the economic and risk analyses that guide maintenance management and investment decisions. There are several key factors to consider in these analyses, including cost, consequence, and risk. These factors, along with the condition assessment, inform program priorities and investment decisions. A cost-effectiveness analysis of a specific piece of equipment at a hydro plant is a complex undertaking. Benefit is derived from actions that lead to efficiency improvements (reduction in losses) and cost savings, or that avoid lost revenues. For reliability investments, the first two areas of benefit can be easily determined, but the benefits are typically small. The third area is more difficult to calculate. In the case of lost revenues, benefit is derived only from making the piece of equipment in question more reliable than the next least-reliable piece of equipment of the power train. Making this calculation and determining how to allocate the benefit among multiple investments on the power train is complicated and involves elements of subjectivity. A cost-effectiveness analysis on an entire generating unit or plant can more easily be done. An analyst can compare the expected future investments on all equipment components of a generating unit to the future avoided lost-revenue benefits to determine whether the investments would be cost effective overall. If so, investments when needed for individual equipment components can be deemed cost effective, as long as they are consistent with the expected future investments that were analyzed. There are several techniques and models available for doing unit or plant cost-effectiveness analyses. All require the marginal value of the unit or plant as an input. Some models attempt to optimize the timing of investments by minimizing the present value of future costs and lost revenues. These models require that assumptions be made about the probability and consequence of failure in order to determine the optimum timing for intervention. One such technique that derives an expected net present value of investing in a unit or plant using Monte Carlo simulation is outlined in Appendix C. In the following hydroAMP framework, we assume that each company has a process in place to determine whether anticipated future investments in units and plants are cost effective. That

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information is taken as an input into hydroAMP. We do not attempt to optimize the timing of investments, but do consider timing as it relates to risk management. What we outline here is a simple, easy to use, and low cost process for rating equipment condition and prioritizing investments using risk-management tools. It should be noted that the analytical tools laid out here are not intended to be prescriptive, and we have purposely avoided recommending a particular type of analysis for a specific piece of equipment or situation. Each plant owner has its own circumstances, regulatory and legal obligations, strategic goals, and preferences with regard to risk. Types of Analyses Two types of analysis, designated as Type 1 and Type 2 Analyses, are described below. They outline a Business Analysis/Risk-Based Decision prioritization process, and are illustrated through case studies in Section IV. Type 1 Analysis A Type 1 analysis considers equipment condition and cost alone, all that may be needed in some cases. For example, a compressor is a relatively inexpensive piece of equipment. If there is budget to do so, the best investment decision may be to replace a compressor that is in poor condition as soon as possible. The Type 1 analysis considers six cost and condition factors:

• Total Cost: Cost to repair or replace the equipment, including engineering, administration, and commissioning costs.

• Current-Year Cost: Portion of investment cost incurred in the current year. • Incremental Annual Maintenance: The increase or decrease in maintenance provided by

the investment dollars. • Achievability: Ability to undertake the project in the immediate timeframe. • Phase of the Project: Defined here as study (S), engineering (E), procurement (P), or

construction (C). • Condition Index: Derived from the most recent performance and Condition Indicators for

the equipment as outlined in Sections I and II. This type of analysis is often used for (but is not limited to) situations involving emergency repairs, failures, and auxiliary systems. Without budget and delivery constraints, investments can be prioritized simply using the condition rating. Where constraints exist, other factors need to be considered.

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Type 2 Analysis For more expensive pieces of equipment where there are several investment alternatives for improving reliability, additional factors need to be considered when setting priorities. A more complex analytical tool, described here as a Type 2 analysis, is useful for prioritizing a list of investments that affect generation. The Type 2 analysis uses all factors from Type 1 and introduces additional factors that relate to the consequence of undertaking or not undertaking a repair or replacement action. These factors, which may not be appropriate to every situation, are as follows:

• Marginal Value of Generation: Annual value attributed to the piece of equipment. This value is determined outside the hydroAMP framework and may include the value of energy and ancillary services.

• Total Outage Duration: For generation-affecting equipment, the length of time (in years) to restore a unit to service after failure, including both the time required to procure and to install equipment.

• Revenue at Risk: Marginal value of generation times the total outage duration. • Risk Map Score: A score (explained below) that measures the relative risk for a piece of

equipment given its condition rating and the consequence associated with its failure. • Other Business Factors: Factors important to the decision, including environmental,

legal, and safety considerations. • Priority Rank: Risk map score plus other business factors.

The risk map in Table III-1 is a tool that helps a plant/asset manager prioritize a portfolio of investment needs. As stated above, it measures the relative risk of a piece of equipment given its condition rating and the consequence associated with its failure. The consequence we use here is loss of revenue, but it could include other business factors. The map is laid out in a grid, with condition values on one axis and the consequence of failure on the other. Values in the grid are the sum of the corresponding beta values for condition and consequence shown in Table III-2. The values in this table are for illustration only and can be changed to meet the specific needs of each company.

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Table III-1: Risk Map

Condition Index

Condition Beta

0 to 0.9 10 11 12 13 14 15 16 17 18 19 20Risk Level

Results(Map #)

1 to 1.9 9 10 11 12 13 14 15 16 17 18 19 High17 - 20

2 to 2.9 8 9 10 11 12 13 14 15 16 17 18

3 to 3.9 6 7 8 9 10 11 12 13 14 15 16 Medium-High13 - 16

4 to 4.9 5 6 7 8 9 10 11 12 13 14 15

5 to 5.9 4 5 6 7 8 9 10 11 12 13 14 Medium9 - 12

6 to 6.9 3 4 5 6 7 8 9 10 11 12 13

7 to 7.9 2 3 4 5 6 7 8 9 10 11 12 Medium-Low5 - 8

8 to 8.9 1 2 3 4 5 6 7 8 9 10 11

9 to 10 0 1 2 3 4 5 6 7 8 9 10 Low1 - 4

1 2 3 4 5 6 7 8 9 10

Risk Level

Consequence Beta

Con

ditio

n Va

lues

Poo

rFa

irG

ood

High

Consequence

Low Medium-Low Medium Medium-High

Table III-2: Beta Tables

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Section IV: Case Studies Introduction Analyses described in Sections I, II, and III are illustrated through three (3) examples in this section. Examples 1 and 2 illustrating Type 1 and Type 2 Analyses, respectively, are theoretical in nature. Example 3 describes an actual spare transformer study for the North Pacific Region of the U.S. Army Corps of Engineers. Type 1 Analysis The following example illustrates how to use a Type 1 analysis to set investment priorities, given differing budget constraints: Type 1, Case 1: In Table IV-1, we show auxiliary systems in two plants that lend themselves to a Type 1 analysis. The current-year budget for investments is capped at $450,000. Decision criteria used to prioritize the investments are: (1) condition indices, (2) achievability, and (3) incremental annual maintenance costs. Because the surge arrestors in Plant A and Crane 1 in Plant B are in poor condition, they are priority items for action. The current-year budget request for these items is $365,000, leaving $85,000 available to address other needs. The second level of budget priority is for items in fair condition with high achievability. Crane 2 in Plant B requires a $100,000 investment in the current year, so there are insufficient funds to start that activity at this time. But Battery 5 in Plant B can be completed for $35,000, which is achievable in the current timeframe. Battery 5 in Plant B therefore gets a higher priority than Crane 2 in Plant B for the current year, which leaves $50,000 available for other investments. Since there are no other investments with high achievability, the next step is to look at items with potential for high maintenance cost savings. The largest potential is with Crane 1 in Plant A, which has a current-year cost of $50,000 and maintenance cost savings of $50,000 per year. This investment has a medium achievability level and can be funded with the remaining available dollars in the current-year budget. Final priorities for Type 1, Case 1, $450,000 current-year budget:

1. Arrestors at Plant A $15,000 2. Crane 1 at Plant B $350,000 3. Battery 5 at Plant B $35,000 4. Crane 1 at Plant A $50,000

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Table IV-1: Factors for Type 1 Analysis (Case 1)

Type 1, Case 2: In Table IV-2, we show the same conditions as in Case 1, but with a current-year budget of $480,000. Again, the first priority for investment is equipment in poor condition. The combined current-year requirement is $365,000 for the two items in this category, so there is $115,000 remaining for other investment needs. A high achievability project, Crane 2 at Plant B, can be funded with the remaining funds. It becomes number three on the priority list, which leaves $15,000 for other investments. The costs for either Compressor 1 at Plant A or Compressor 1 at Plant B are low enough to be funded with the remaining funds. But using the priorities we have set, the preferred alternative would be Compressor 1 at Plant A because it has a lower condition rating. Compressor 1 at Plant B is in good condition, so it is unlikely that an investment would be warranted even if funds were available. By coincidence, in this case the funding priority is consistent with the condition rating. Final priorities for Type 1, Case 2, $480,000 current-year budget:

1. Arrestors at Plant A $15,000 2. Crane 1 at Plant B $350,000 3. Crane 2 at Plant B $100,000 4. Compressor 1 at Plant A $15,000

The cases under the Type 1 analysis show a straightforward path to an investment decision. But not all decisions are that simple, and some require a more sophisticated treatment.

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Table IV-2: Factors for Type 1 Analysis (Case 2)

Type 2 Analysis The following example illustrates how to use a Type 2 analysis to set investment priorities under various budget constraints: Type 2, Case 1: In Table IV-3, we show power train equipment in three plants, plus a crane at one of the plants. The current-year budget for these investments is capped at $1 million. Decision criteria used to prioritize the investments are: (1) Priority Rank, (2) Risk Map Score, and (3) Condition Index. The first evaluation criterion is the priority rank, derived from the risk map score and other business factors. The highest priority for investment is Generator 1 at Plant B, with a priority rank of 15. It also has a risk map score of 15 (medium-high risk), derived from a condition beta of 8 and consequence beta of 7 (see Table III-2). The generator, however, has a current-year investment requirement that exceeds the budget, so it cannot be undertaken at this time. Next in the priority list is Transformer 4 at Plant B, with a risk map score and priority rank of 14 (medium-high risk). Allocating $500,000 for this in the current year leaves $500,000 available for other needs. There are no other investment needs with medium-high or higher risk, so from a condition versus revenue-at-risk perspective, the remainder of the portfolio (except for the generator that will need to be addressed in the near future) presents no significant risks for the company. There are still equipment components in poor condition, however, that could adversely affect revenues and

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other business objectives of the company. There is also enough current budget available to consider them. While Transformer 1 at Plant B has a higher risk map score due to the amount of revenue at risk, Transformer 2 at Plant A has an additional environmental problem that increases its priority rank by 2, making it the preferred investment alternative for the remaining $500,000. A rationale for investing in Transformer 1 at Plant B instead could also be made based on its higher revenue at risk. Final priorities for Type 2, Case 1, $1 million current-year budget:

1. Transformer 4 at Plant B $500,000 2. Transformer 2 at Plant A $500,000

Table IV-3: Failure Factors for Type 2 Analysis

Type 2, Case 2: The current-year budget is capped at $1.5 million.

There are two likely alternatives for investment with a $1.5 million budget: Generator 1 at Plant B, which would require the entire available budget for the year, or the three transformers that are in poor condition. The three transformers collectively represent more revenue at risk than the single generator, and there are additional environmental benefits associated with an investment in Transformer 2 at Plant A. As a result of the analysis, it is apparent that the transformers should receive the investment in the current year. The generator, however, would be a high priority in the next funding cycle, and the company should prepare an operational risk-management plan for the immediate timeframe.

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Final priorities for Type 2, Case 2, $1.5 million current-year budget:

1. Transformer 4 at Plant B $500,000 2. Transformer 2 at Plant A $500,000 3. Transformer 1 at Plant B $500,000

Type 2, Case 3: The current-year budget is capped at $2 million.

To minimize the overall outage time for Unit 1 at Plant B, it would make sense to address needs in the entire power train and invest in both the generator and transformer. It would also be desirable to seek an additional $180,000 for the current year in order to include work on the Unit 1 breaker since there would be an incremental lost-opportunity benefit of $240,000 for combining that project with work on the generator and transformer. Final priorities for Type 2, Case 3, $2 million current-year budget:

1. Generator 1 at Plant B $1,500,000 2. Transformer 1 at Plant B $500,000 3. Breaker 1 at Plant B $180,000 (if additional funds are available)

Type 2, Case 4: The current-year budget is capped at $3.5 million.

With $3.5 million to allocate toward investment needs, there are more options available to the plant/asset manager. The first four items listed in Table IV-3 have relatively high priority rankings and poor condition ratings, making them top priorities for investment. The total funding requirement for these items is $3 million in the current year. As in Case 3, Breaker 1 should be added to the priorities to coincide with generator and transformer work on Unit 1 at Plant B, leaving $320,000 available for other needs. There are safety issues associated with Crane 1 at Plant B, so a $300,000 investment in that item is the next priority. Final priorities for Type 2, Case 4, $3.5 million current-year budget:

1. Generator 1 at Plant B $1,500,000 2. Transformer 4 at Plant B $500,000 3. Transformer 2 at Plant A $500,000 4. Transformer 1 at Plant B $500,000 5. Breaker 1 at Plant B $180,000 6. Crane 1 at Plant B $300,000

The level of funding in Case 4 represents what a plant/asset manager would need to assure that the three generating plants shown in Table IV-3 deliver performance that is reliable, safe, and environmentally sound.

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North Pacific Region Spare Transformer Project Generator step-up (GSU) transformers connect the low voltage generators to the high voltage transmission system. Depending on plant configuration, the failure of a single GSU transformer can result in an outage of 1 to 4 generators. Procurement and manufacturing time for a large GSU can extend up to 18 months. In March 2002, Bonneville Power Authority, the federal power marketing agency for Corps of Engineers projects in the North Pacific Region (NPR), requested that HDC develop a spare GSU transformer purchase plan. The Spare Transformer Project covered 20 hydroelectric plants in the Portland, Seattle, and Walla Walla Districts. The study covered 155 transformers ranging from 115 to 500 kV, 13 to 385 MVA, and from 7 to more than 50 years old. The average age of the GSU transformers in the region is over 34 years old, and there are very few spares. The goals of the study were to:

• Assess the condition of the existing transformers • Determine the risk and economic consequences of failure due to lost generation for each

transformer with and without a spare available • Develop a prioritized Sparing and Placement Plan

Condition Assessment When the North Pacific Region Spare Transformer Project was initiated, a team of hydroAMP transformer experts was developing a transformer condition assessment guide. Although the guide was not yet complete, the technical team had identified the relevant Condition Indicators, test result thresholds, and rating criteria to be used to perform a transformer condition assessment. Table IV-4 provides an overview of the condition assessment process developed using recommendations of the technical group as well as other industry sources. The assessment utilizes the following information: Oil Analysis [dissolved gas analysis (DGA) and routine physical screening], Power Factor measurements, O & M History, and Age. For each of the Condition Indicators, test results were divided into four ranges and points were assigned to each range (more points for better test results). The condition assessment was performed using existing test records available from the project or district offices and from external inspections of the transformers. No special testing or internal inspections were performed. Five to ten years of test data were reviewed (when available) for the Oil Analysis and Power Factor tests to evaluate trends. An overall rating for each transformer was calculated using the following weighting factors provided by the technical group:

Oil Analysis 1.2 Power Factor 1.0 O & M History 0.8 Age 0.5

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Table IV-4: Transformer Condition Assessment Guidelines

TRANSFORMER CONDITION ASSESSMENT Score Condition Indicator

3 2 1 0 Oil Analysis* 1. Dissolved Gas Analysis

(DGA)

a. Generation Rate (ppm/month)

Total Dissolved Combustible Gas (TDCG) < 30 30-60 50-80 > 80

Individual CG < 10 < 15 < 25 > 50 Carbon Monoxide (CO) < 70 < 150 < 350 > 350

Acetylene (C2H2) 0 0 < 5 < 10 b. Level (ppm)

Hydrogen < 100 100-350 350-700 > 700 Oxygen < 5,000 5k-10k 10k-15k > 15k

Methane (CH4) < 75 75-200 200-400 > 400 Acetylene (C2H2) < 5 5-20 20-40 > 40

Ethylene (C2H4) < 30 30-60 60-100 > 100 Ethane (C2H6) < 30 30-60 60-100 > 100

Carbon Monoxide (CO) < 200 200-400 400-600 > 600 Carbon Dioxide (CO2) < 1,000 1k-3k 3k-5k > 5k

TDCG < 450 450-900 900-1,800 > 1,800 2. Oil Quality

Interfacial Tension (IFT) > 35 30-35 25-30 < 25 Acid Neutralization No. 0-0.05 0.05-0.15 0.15-0.5 > 0.5

Moisture 0-10 10-15 15-20 > 25 Furans 0-75 75-150 150-250 > 250

3. Power Factor (Doble)**

Normal (0.10 - 0.50)

Minor Degradation (0.50 - 0.80)

Significant Degradation (0.80 - 1.0)

Severe Degradation (> 1.0)

O & M History/ Physical Condition Normal

Some abnormal operations or

additional maintenance

Significant abnormal operations or

additional maintenance

Forced outages, major leaks, severe problems, sister unit

failures

Age (years) < 30 30-45 > 45 -

*Overall oil score is lowest of individual scores for each category. Weight "Level" scores less than "Generation Rate" scores by increasing individual gas "Level" scores by one point. In addition, if the Level of a gas is high but unchanged for 4 to 5 years, reduce weight of individual gas score for each such gas by increasing score by one point. **Values refer to percent power factor on overall tests. Review overall, excitation, and TTR results. Defer to test engineer's assessment if present on report.

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The outcome of the condition assessment was an adjective rating (Good/Fair/Poor) describing the overall condition of each transformer. These results were used in conjunction with the Economic Analysis described below to develop the Transformer Sparing Plan. The overall condition assessment score ranges and associated ratings were:

Good 8.0 to 10.0 Fair 4.0 to 7.9 Poor 0 to 3.9 Economic Analysis Including the Probability of Failure The simplified economic analysis was intended to determine for which projects at least one spare transformer was economically justified. For the purposes of this analysis, the economic benefit of having a spare transformer was defined as the difference in lost revenue between a long outage without a spare and a short outage with one. It was recognized that there are other costs involved with a transformer failure, including possible damage to adjacent equipment (e.g., bus work, structures, etc.), detrimental environmental impacts, and significant safety hazard to personnel. Having a spare GSU transformer does not mitigate these negative consequences nor do these consequences influence which projects should have spare transformers. Accordingly, these factors were not included in the analysis. BPA provided annual generation and revenue information for each project to support the economic analysis. Using this information and the configuration for each transformer (i.e., the number of generating units served), lost revenue per year for a failure of each transformer was calculated. To account for planned unit maintenance, baseline annual revenue assumed 90% plant availability. The lost revenue was calculated by subtracting the revenue produced by the plant less the unavailable units (due to the transformer outage) from the baseline revenue. An evaluation of the need for spare transformers must take into account some element of risk or probability of failure to properly balance the revenue saved by having a spare against the costs of procuring a spare. One measurement of the exposure to an extreme and relatively improbable event is the product of the potential cost of the event and the probability of that event occurring. For this analysis, the revenue expected to be saved (i.e., benefit gained) by having a spare transformer is used instead of the potential additional cost of the outage by not having a spare. The probability of failure within the next year for a transformer whose condition was rated Good was assumed to be 0.0095 based on recent similar study work performed. For the purposes of this analysis, the probability of failure was increased to 0.0105 and 0.0115 for transformers whose condition was rated Fair and Poor, respectively. Note that the probabilities assigned to the three transformer conditions were somewhat arbitrary, and no analyses were performed in this phase of the work to better quantify appropriate failure probabilities. However, a sensitivity study was performed to demonstrate that the ranking of results is relatively unaffected by assumed failure probabilities.

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The probability of a transformer failure at a particular project increases with the number of transformers at the project. Thus, the probability of a failure of any transformer among many identical units was calculated. The Expected Benefit (defined as the product of the probability of a transformer failure and the revenue saved by having a spare transformer) was calculated for each project. The estimated costs for spare transformers were developed from a review of the costs and MVA ratings of replacement transformers procured during the previous five years and from input from BPA personnel involved in purchasing transformers. The estimated costs for the spare transformers assumed that the spare has the same configuration as the original (single or three-phase). The estimates included design, manufacturing, shipping, erecting, testing costs, and all appurtenances. The estimates did not have allowances for constructing storage facilities, removing or repairing a damaged transformer, or any internal costs associated with procuring a spare transformer. To reflect the fact that in may cases a single spare transformer can serve as the spare for several banks of transformers, the estimated cost of the spare was divided by the number of transformers for which it would be a direct replacement. The ratio of the Expected Benefits to the Spare Transformer Costs per unit for each project or type of transformer was calculated; the greater the Benefit/Cost ratio, the more likely that one or more spare transformers would be economically justified. Benefit/Cost ratios ranged from 0.09 to 161. Ratios of one or greater suggested a spare should be considered. Based on the analysis, results for each project were divided into four categories as follows:

A – Project where one or more spare transformers appear justified and none exists B – Projects where one or more spare transformers appear justified and one exists C – Projects where no spare transformers appear justified and none exists D – Projects where no spare transformers appear justified and one exists

Spare Transformer Plan4 The study effort resulted in the development of a near-term plan to mitigate the failure of a GSU transformer for each of the projects included. The system-wide condition assessment and economic evaluation provided a basis for further analysis and indicated steps to be taken to improve the condition of the existing transformers. For those projects where spare transformers appear justified, the process to procure spares has begun.

4 Because of its length, the spare transformer plan is not included in this report. However, the complete plan is available from the Hydroelectric Design Center, U.S. Army Corps of Engineers, PO Box 2946, Portland, OR 97208-2946.

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Conclusion The preceding cases demonstrate how decision makers can use hydroAMP condition ratings and risk-management tools to prioritize a portfolio of investment needs. The overall unit and station condition information could also be used as an input to the hydroAMP risk analysis. As previously stated, the examples are illustrations and are not meant to prescribe an approach to setting investment priorities. Each plant owner has its own circumstances, regulatory and legal obligations, strategic goals, and preferences with regard to risk that must be applied to its investment decisions.

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APPENDICES

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Appendix A: Key Terms Asset Management – A systematic process of maintaining, upgrading, and operating physical assets cost-effectively. It combines engineering principles with sound business practices and economic theory, and provides tools to facilitate a more organized, logical approach to decision-making. Asset management provides a framework for handling both short- and long-range planning. (Asset Management Primer, U.S. Department of Transportation, Federal Highway Administration, Office of Asset Management, December 1999, page 7.) Availability – The annual percentage of time that a piece of equipment is available for power production. Capacity – The maximum rated output of a piece of equipment. Certainty – A condition where determinacy exists in the elements that characterize a situation. The likelihood of an event occurring and its consequences are known absolutely. Computerized Maintenance Management System (CMMS) – The CMMS produces scheduled preventative maintenance to perform the equipment condition assessment. The results of the assessments are captured in the condition monitoring section of the CMMS. The CMMS will be used to generate summary reports showing the equipment condition and the integrated facility assessment. Condition – The existing state of the component or equipment with respect to function and fitness. Condition Assessment – The process of objectively evaluating the condition of a piece of equipment or a system using a uniform process and guidelines. Condition Indicators – Individual components of an overall condition assessment. Typically standardized inspections and tests that are evaluated in a common manner. Condition Index – The outcome of a condition assessment. An overall numerical rating between 0 and 10 which describes condition, with higher numbers equating to better condition. Dependability (Reliability) – The probability that a piece of equipment will not perform satisfactorily. Efficiency – A measure of losses for a piece of equipment; equals output power divided by input power. Forced Outage – A forced outage occurs when a power plant component fails to perform satisfactorily and causes an unplanned interruption in power production.

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Functionality – A subjective evaluation of a piece of equipment or system with regards to its ability to perform the current intended function. Degradation of functionality can be caused by deterioration, changing requirements or obsolescence. Performance – Normally the combined evaluation of the efficiency and capacity of a piece of equipment. Planned Outage – A planned outage occurs when a piece of equipment is intentionally taken out of service to perform routine inspections or planned repairs, replacements, and rehabilitations. Reliability (of hydropower generating equipment) – The extent to which the generating equipment can be counted on to perform as originally intended. This encompasses the confidence in the soundness or integrity of the equipment based on forced outage experience and maintenance costs, the output of the equipment in terms of measured efficiency and capacity, unit availability and the dependability of the equipment in terms of remaining service life (retirement of the equipment). Risk – The exposure to a chance of loss or injury; the likelihood of adverse consequences. Expressions of risk are composed of the existence of unwanted consequences and the occurrence of each consequence expressed in the form of a probability. Uncertainty – A condition where indeterminacy exists in some of the elements that characterize a situation. Uncertainty may exist from either probability uncertainty, outcome uncertainty or any of the paths between the initiating event and the consequences.

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Appendix B: Maximo® Loading Procedure Introduction The development and implementation of Condition Assessment (CA) is driven by the need to monitor the condition of major power plant equipment and meet agency-mandated facility condition assessment requirements. The CA process will serve as a tool for facility managers to understand the condition of their equipment and to better prioritize needed maintenance or replacement activities. Once the CA process is set up in Maximo®, it will be integrated into the facilities’ normal maintenance procedures. Overview This document details the steps necessary to load the Power Equipment Condition Assessment process into Maximo®. This process assists facility Maximo® coordinators as they load CA job plans into their local database. This process makes the assessment more objective and utilizes information gathered during routine maintenance. Power Equipment Condition Assessment is loaded into Maximo® using three component applications and their screens:

1. Job Plan Application

A Job Plan stores definitions that define the ratings that assess the condition of a class of power equipment. A Maximo® job plan has been created for each class of equipment, e.g., turbine runner, transformer, etc. The Job Plan, along with its operation steps and measurement point names, is the first component of Maximo® that must be loaded. This part provides the information, screen images, and cut and paste text to facilitate the loading of condition assessment measurements.

2. Preventative Maintenance Application

A Preventative Maintenance (PM) links the Job Plan to a specific piece of equipment. The PM transforms the condition assessment process from equipment classification (e.g., transformer) to a specific piece of equipment. To load the PM, a user needs a Job Plan and the specific equipment number. After the PM record is established, the PM schedule is set to generate work orders on an annual interval.

3. Condition Monitoring Application

The Condition Monitoring application establishes and links measurement points to specific equipment. The condition assessment process rates equipment conditions using measurement point values entered in Condition Monitoring or on work orders. These points can be thought of as specific measurement points that measure a condition of equipment. The condition assessment process defines the name of measurement points.

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As an example for transformer condition assessment, a measurement point with a unique point number is created for a specific condition and given the point name “XFMR-AGE”. (The condition assessment process defines age as a measurement in the assessment process.) During the assessment process, the measurement point created above is loaded with a number that represents the condition of the equipment relative to its age. This number is defined in the Job Plan for the class of equipment. This number or scoring is loaded within the Condition Monitoring application or on the Actuals tab on PM work orders.

The sequence used to load condition assessment into Maximo® is:

1. Select the appropriate equipment. 2. Create measurement points for every Condition Assessment point identified.

Note: It is critical that each site use the exact measurement point name to ensure all the reports will work.

3. Enter the Job Plan. If it is possible, the Condition Assessment operational steps can be incorporated into existing Job Plans.

4. Create Preventive Maintenance Plans to schedule the assessment. It is important that Maximo® be set up correctly for condition assessment. When a work order is generated by the PM application, the Job Plan attached is automatically copied to the work order. Maximo® compares the Job Plan point names and the condition monitoring point names for measurement point names that match. When a match is found, Maximo® inserts the point number onto the work order. Using these points, the Maximo® Coordinator can easily record and store an equipment condition result as defined by the assessment process. It is critical that the point names are entered exactly as defined by the Power Equipment Condition Assessment process. You must create the condition monitoring point names prior to loading them into Job Plans. The Job Plan Application will not accept point names if they have not been saved in the Condition Monitoring application. The Maximo® report (CNDASSET) is available in the Condition Monitoring application. This report displays the current condition assessment points on all equipment setup for condition assessment measurements. For Power Equipment, condition points identified for Transformer, for example, are:

• XFMR-OIL • XFMR-PF • XFMR-OM • XFMR-AGE • XFMR-RD

A full list of point names is contained in Table B-1 at the end of this appendix.

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Procedures The following condition assessment example is for a transformer. The same steps will be needed for each piece of equipment. This section details the steps for establishing Condition Assessment. You will need to go into the Equipment Module and query for “Transformer” to get a complete list of transformer equipment numbers. This will need to be done for all equipment classifications (see Table B-1). Refer to the Condition Monitoring Application (Figure B-1).

Figure B-1: Condition Monitoring Application

Transformer – The “Point” will be a unique number assigned by Maximo® and will be associated with the specific piece of equipment. Go to INSERT, NEW MEASUREMENT POINT WITH AUTONUMBER. Type in the Description, assign the equipment number (location will automatically populate), then type in the associated point name from Table B-1. These point names must remain exactly as on Table B-1 for consistency throughout all Maximo® sites. Future reports will query from this field. Limits are not required for these set points. (The set point limits will accept a Null.)

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You will need to check the condition of this piece of equipment on an annual basis. If you have a current PM for that piece of equipment and plan on just adding to an existing Job Plan, enter the PM number now. Now you will need to add the Condition Indicator scoring to your job plan. (Refer to Figure B-2.)

Figure B-2: Job Plans

Go into the Job Plan Module and call up your job plan for this transformer. Go to INSERT, NEW ROW. Assign the row an Operational Step number. Tab to the Description column and type “Condition Indicator 1 – Transformer Oil”. In the long description, type in the scoring benchmarks from the Condition Assessment Guide. Example: Long Description of Job Plans Dissolved gas analysis is the most important factor in determining the condition of a transformer. Insulating oil analysis can identify internal arcing, bad electrical contacts, hot spots, partial discharge, or overheating of conductors, oil, tank, or cellulose. The "health" of the oil reflects the health of the transformer itself. (Refer to Figure B-3.)

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Figure B-3: Long Description of Job Plans

SAVE the record. These scoring benchmarks will be the same for each transformer. Once you have typed this information for the first piece of equipment, it can be copied and pasted into the long description for the next transformer. This will speed up the condition assessment process. Tab to Point Name and type in XFMR-OIL. This Point Name is the link to the condition measurement, the equipment number and the Job Plan (which is linked to the PM, which is also linked to the equipment). This point name must be the same as listed in Table B-1. Repeat these steps for Condition Indicators 2 through 5, adding the scoring benchmarks as stated in the Condition Assessment Guide. This transformer condition assessment is completed. This procedure will need to be accomplished for each transformer. Then repeat the procedure for each of the other equipment listed in Table B-1.

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Recording Set Point Values on Work Order When the condition assessment work order is generated, there will be a space on the work order for the maintenance person to enter each set point value. (Refer to Figure B-4.) When the work order is closed, the set point values will then be entered in the Maximo® work order module. This will associate the set point values with the appropriate equipment.

Figure B-4: Work Order Tracking

37

Condition Assessment Report

There will be a report that can be run annually that will:

• Calculate the condition of each equipment based on the set point values recorded. • Generate a list of the current condition of facilities equipment.

Refer to the Report Viewer (Figure B-5).

Figure B-5: Report Viewer

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Table B-1: Equipment / Set Point Name List

Equipment Point Name Unit of Measure

Turbine Turbine Age TURB-AGE NUMBER Turbine Physical Condition TURB-PHY NUMBER Turbine Operations TURB-OPS NUMBER Turbine Maintenance TURB-MNT NUMBER Transformer Transformer Oil XFMR-OIL NUMBER Transformer Power Factor XFMR-PF NUMBER Transformer Operations and Maintenance (O & M)

XFMR-OM NUMBER

Transformer Age XFMR-AGE NUMBER Transformer Data Quality Indicator XFMR-RD NUMBER Generator – Stator Stator O & M STAT-OM NUMBER Stator Physical Inspection STAT-PHY NUMBER Stator Insulation Resistance and Polarization Index

STAT-IR

NUMBER

Stator Winding Age STAT-AGE NUMBER Stator Data Quality Indicator STAT-RD NUMBER Generator – Rotor Rotor O & M ROTR-OM NUMBER Rotor Physical Inspection ROTR-PHY NUMBER Rotor Insulation Resistance and Polarization Index

ROTR-IR

NUMBER

Rotor Winding Age ROTR-AGE NUMBER Rotor Data Quality Indicator ROTR-RD NUMBER Circuit Breakers – Air Magnetic, Air Blast NUMBER Breaker Dielectric Test BKRA-DT NUMBER Breaker O & M BKRA-OM NUMBER Breaker Contact Resistance BKRA-CR NUMBER Breaker Number of Operations (Cycles) BKRA-CYC NUMBER Breaker Data Quality Indicator BKRA-RD NUMBER Circuit Breakers – Bulk Oil NUMBER Breaker Dielectric Test BKRB-DT NUMBER Breaker O & M BKRB-OM NUMBER Breaker Contact Resistance BKRB-CR NUMBER Breaker Number of Operations (Cycles) BKRB-CYC NUMBER Breaker Data Quality Indicator BKRB-RD NUMBER Circuit Breakers – SF6 NUMBER Breaker Dielectric Test BKR6-DT NUMBER Breaker O & M BKR6-OM NUMBER

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Breaker Contact Resistance BKR6-CR NUMBER Breaker Number of Operations (Cycles) BKR6-CYC NUMBER Breaker Data Quality Indicator BKR6-RD NUMBER Circuit Breakers – Vacuum NUMBER Breaker O & M BKRV-OM NUMBER Breaker Data Quality Indicator BKRV-RD NUMBER Governor Governor Age GOV-AGE NUMBER Governor O & M History GOV-OM NUMBER Governor Availability of Spare Parts GOV-SP NUMBER Governor Performance GOV-P NUMBER Governor Data Quality Indicator GOV-RD NUMBER Exciter Exciter Age EXC-AGE NUMBER Exciter O & M EXC-OM NUMBER Exciter Availability of Spare Parts EXC-SP NUMBER Exciter Power Circuitry Tests EXC-PCT NUMBER Exciter Control Circuitry Tests EXC-CCT NUMBER Exciter Data Quality Indicator EXC-RD NUMBER Battery Battery Visual Inspection BATT-VI NUMBER Battery Age BATT-AGE NUMBER Battery Routine Testing BATT-RT NUMBER Battery Data Quality BATT-RD NUMBER Surge Arrester Surge Arrester Thermal Imaging SA-TI NUMBER Surge Arrester Data Quality SA-RD NUMBER

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Appendix C: Example Economic Analysis of a Facility Upgrade – Generator and Turbine Replacement This is an example of an economic analysis applied to a hydropower scenario. In this example, the powerplant has four generating units that have reached a condition where replacing the generators and turbines are being considered. These components are still functional and could remain in operation indefinitely with continuous maintenance, but more efficient components are available and being considered. Other components, besides the generators and turbines, are in satisfactory condition or are included in the cost estimates for these replacement parts. This example reflects costs and benefits based on “real” cash flows, not reflecting any changes that would occur due to inflation. Therefore, the discount rate that is used is also a real discount rate, not including any inflationary component. The real discount rate of 3.1 percent, as suggested by Office of Management and Budget (OMB), Circular No. A-94, Appendix C for 2005, is used in this example. This is the rate for cost-effectiveness analysis for projects of 30 years or more. This rate changes every year, on or about February 1, and is appropriate for analyses in which inflation in costs is not considered. There are specified rates published by OMB for analyses that include inflation. The discount rate required in an economic analysis is dependent on many factors, however, these factors will not be considered here. The design engineers have provided two alternatives to consider. Alternative A provides a generator and turbine combination similar to original equipment, but due to engineering improvements leading to greater efficiency, this alternative will provide an increase in capacity of 1.5 megawatts (MW) per unit. Alternative B provides the powerplant with even more efficient components at a higher cost. Alternative B provides components that will increase capacity by 2 MW per unit. The gains for either alternative are due to improvements in both the generator and turbine, and are shown in one combined number. Table C-1 shows the costs of the replacement components. Alternative A requires a total expenditure of $5,100,000 per unit based on the costs of the generator ($2,300,000) and turbine ($2,800,000), as shown. Alternative B is more expensive, costing $7,100,000 per unit with more expensive components due to the greater cost of design and construction. Therefore, if alternative A is chosen, a total initial cost of $20,400,000 will be required to replace the four units, whereas the total initial cost for alternative B is $29,200,000. Each component will be paid for at the beginning of the year in which it will be installed.

Table C-1: Cost of Replacement Components for Each Unit

Component Alternative A Alternative B Generator Cost $ 2,300,000 $ 3,300,000 Turbine Cost $ 2,800,000 $ 3,800,000 Total Cost per Unit $ 5,100,000 $ 7,100,000

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The life of the turbines is assumed to be 50 years and the life of each generator is 25 years. The analysis will be performed based on the life of the turbines, but because the generators will wear out, they will need to be replaced after the first 25 years. This allows the analysis to be performed over the 50 year time horizon. All of the costs and benefits for these 50 years are discounted back to the beginning of the first year for benefit-cost analysis. Since the costs are incurred at the beginning of each year for the first four years, the present value (PV) of the initial costs for alternative A is $19,498,227. Additionally, the generators will need to be replaced again beginning in year 26. The present value of these replacements of four generators in years 26 through 29 is $4,099,078. The sum of the present values is $23,597,305. A summary of the analysis of costs is provided in Table C-2. The present value for alternative B is calculated in a similar way. For the initial installations, the present value is $27,144,590. The replacement generators in years 26 to 29 have a present value of $5,881,285, totaling $33,025,876 for the present value of costs for this alternative. These values are summarized in Table C-2. Note that the “Cost” column expresses costs without being discounted.

Table C-2: Comparison of Costs between Alternatives

Alternative A Alternative B Year Costs PV of Costs Costs PV of Costs

1 $ 5,100,000 $ 5,100,000 $ 7,100,000 $ 7,100,000 2 $ 5,100,000 $ 4,946,654 $ 7,100,000 $ 6,886,518 3 $ 5,100,000 $ 4,797,918 $ 7,100,000 $ 6,679,455 4 $ 5,100,000 $ 4,653,655 $ 7,100,000 $ 6,478,618

Subtotal $ 20,400,000 $ 19,498,227 $ 28,400,000 $ 27,144,590 26 $ 2,300,000 $ 1,072,164 $ 3,300,000 $ 1,538,322 27 $ 2,300,000 $ 1,039,926 $ 3,300,000 $ 1,492,068 28 $ 2,300,000 $ 1,008,658 $ 3,300,000 $ 1,447,205 29 $ 2,300,000 $ 978,330 $ 3,300,000 $ 1,403,690

Subtotal $ 9,200,000 $ 4,099,078 $ 13,200,000 $ 5,881,285 Total $ 29,600,000 $ 23,597,305 $ 41,600,000 $ 33,025,876

It is assumed that there are months during the year when water flows are lower and at least one unit is idle. The installation of the replacement components will be scheduled during this period so that there is no lost generation or spillage resulting from this activity. Other assumptions in this example include a constant plant factor of 45 percent. While plant factors change in most hydropower plants and these changes normally are modeled in an economic analysis, plant factors are assumed to be constant for this example. The economic value of the generation is also assumed to be constant and equal to $55 per megawatt hours (MWh).

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Given a plant factor of 45 percent, 8,760 hours in a year, and an increase in capacity of 1.5 MW per unit for alternative A, the increase in generation will amount to 5,913 MWh (0.45 × 8760 × 1.5). Assuming a value of $55/MWh, this equals $325,215 (5,913 × $55) annually per unit. A similar calculation for alternative B shows that the increase in generation will be 7,884 MWh (0.45 × 8760 × 2) equal to $433,620 (7,884 × $55) per unit. In addition, for each alternative there will be a savings in maintenance costs of $50,000 annually for each unit. This $50,000 reflects the costs that would occur keeping the original equipment operating. In each of the first four years, one unit is scheduled for replacement and assumed to be finished at the end of the year. Therefore, each unit adds value when it goes online. At the beginning of the second year, the benefits from one unit occur and are recognized in the analysis, as this is the first year of increased benefits. At the beginning of the third year, benefits from two units begin, continuing through the four units. The benefits for each alternative include both the increase in generation resulting from the new components plus the savings in maintenance costs. The increase in generation for each alternative is shown in Table C-3. For alternative A, the increase in generation is worth $325,215 per unit per year, as previously calculated. During the first year of operation (year 2), the benefits include the increased generation for one unit; in the second year of operation (year 3) the benefits include two units; the third year of operation (year 4) provides benefits from three units; and then for the remaining 46 years (years 5 through 50), the benefits result from the four units having been replaced. To properly compare benefits to costs, the present value of the benefits for 50 years needs to be discounted back to the current year. These discounted values are shown in Table C-3 as the present value of the benefits equaling $30,706,822. Similar benefits are shown for alternative B. The benefit resulting from each unit is $433,620 per year and the present value of 50 years of benefits is $40,942,430.

Table C-3: Increases in Benefits for Each Alternative

Years Alternative A Alternative B Benefits PV of Benefits Benefits PV of Benefits 2 $ 325,215 $ 315,436 $ 433,620 $ 420,582 3 $ 650,430 $ 611,904 $ 867,240 $ 815,872 4 $ 975,645 $ 890,258 $ 1,300,860 $ 1,187,011

5 through 50 $ 1,300,860 $ 28,889,224 $ 1,734,480 $ 38,518,965 Total $ 61,790,850 $ 30,706,822 $ 82,387,800 $ 40,942,430

In addition to the changes in generation resulting from the replaced components, benefits include the savings in maintenance costs of $50,000 per unit per year. The present value of these decreased costs total $4,721,003. These values are shown in Table C-4. The decreased maintenance costs are the same for both alternatives.

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Table C-4: Savings in Maintenance Costs

Years Decreased Maintenance Costs

Present Value of Decreased Maintenance Costs

2 $ 50,000 $ 48,497 3 $ 100,000 $ 94,077 4 $ 150,000 $ 136,872

5 through 50 $ 200,000 each year PV total for years 5-50: $ 4,441,558

Total $ 9,500,000 $ 4,721,003 The total benefit in the economic analysis is the sum of the present value of the increased generation shown in Table C-3 and the decreased maintenance costs shown in Table C-4 for each alternative. The total benefit for alternative A is $35,427,826 as shown in Table C-5. For alternative B, the total benefit is equal to $45,663,433. Table C-5 also shows the total of the present value of costs previously provided in Table C-2. Subtracting the present value of costs from the present value of benefits gives the net present value for each alternative. For alternative A, the net present value is $11,830,521. For alternative B, the net present value is $12,637,557. Table 5 also shows the benefit-to-cost (B/C) ratio often cited in studies. For alternative A, the B/C ratio is 1.50 whereas for alternative B the ratio is 1.38.

Table C-5: Summary of Results

Summary of Results: Alternative A Alternative B Present Value of Benefits $ 35,427,826 $ 45,663,433 Present Value of Costs $ 23,597,305 $ 33,025,876 Net Present Value $ 11,830,521 $ 12,637,557 B/C Ratio 1.50 1.38

The preferred alternative is the one that provides the highest net present value. At times, other methods are used in the decision process, including the B/C ratio, payback method, and internal rate of return. However, these methods are inferior to the net present value calculation. The B/C ratio has traditionally been a popular method, but has a fatal flaw when comparing two or more alternatives. This method shows the discounted benefits per dollar of discounted cost. One problem with the B/C ratio is the sensitivity to the definition of benefits and costs. A negative benefit can be considered a cost, which would affect the ratio, moving from the numerator to the denominator. A second problem is the size effect. As a project gets larger, the size of the discounted benefits may decrease for each additional dollar of cost, reducing the ratio. But if the added benefit is greater than the added cost, then this increase is beneficial and should be undertaken even if the B/C ratio is reduced. One situation where the B/C ratio is beneficial is when several projects are chosen; ranking them by the ratio allows implementation under a limited budgeting process.

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The payback method determines the length of time in years that the benefits take to pay back the cost of the project. The annual benefits are divided into the cost to determine this value. The alternative with the shortest payback becomes the preferred alternative. However, this method has problems since the method fails to consider the time value of money in the analysis and it fails to consider all the cash flows. The alternative that is shown to be inferior may have large positive cash flows beyond the payback period which are then ignored and not captured. Therefore, the payback method is not a good method for decision-making. The internal rate of return (IRR) method is the method that defines a discount rate that equates costs and benefits. The criterion requires that projects or alternatives are accepted where the IRR is greater than a default opportunity cost of capital or the alternative that shows the greatest IRR. However, this method may choose the alternative that should not be the preferred one. Values of benefits and costs may vary depending on the discount rate, as the mathematics assumes a single discount rate over the life of the project, implying reinvestments at the IRR. At different IRR values, then different alternatives will appear to be preferred. Also, the IRR method usually can provide multiple, conflicting results providing several viable rates of return where costs equal benefits. Net present value is the method that provides the correct choice for the preferred alternative. Acceptable projects are those that have a net present value greater than zero; those that provide benefits greater than the costs. When the projects are mutually exclusive, such as choosing one alternative among many, the preferred project is the one that provides the greatest net present value. In our example, while alternative A has a higher B/C ratio, it provides a lower net present value, so is the inferior choice and alternative B is preferred. Alternative B provides the greater amount of value; providing $807,036 higher value to society.

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Appendix D: hydroAMP Team Members and Contributors Ernie Bachman, Bureau of Reclamation (Governor Guide)

Steve Bellcoff, Bonneville Power Administration (Website Database)

James Boag, U.S. Army Corps of Engineers (Emergency Closure Gate and Valve Guide)

Bernard Bourgeois, Hydro-Québec (Guidebook)

James Calnon, U.S. Army Corps of Engineers (Compressed Air System Guide)

Ben Canno, Bureau of Reclamation (Circuit Breaker Guide)

Roger Cline, Bureau of Reclamation (Turbine Guide)

Jim Clune, Bonneville Power Administration (Guidebook, Compressed Air System Guide)

Scott Cotner, U.S. Army Corps of Engineers (Circuit Breaker Guide, Transformer Guide)

Marcos Ferreira, Bonneville Power Administration (Generator Guide)

Doug Filer, U.S. Army Corps of Engineers (Surge Arrester Guide)

Erin Foraker, Bureau of Reclamation (Guidebook, Turbine Guide)

John Germann, Bureau of Reclamation (Crane Guide)

Thierry Godin, Hydro-Québec (Excitation System Guide)

Phil Gruwell, U.S. Army Corps of Engineers (Excitation System Guide)

Sarah Jones, U.S. Army Corps of Engineers (Crane Guide)

Bill Joye, Bureau of Reclamation (Compressed Air System Guide)

James Kerr, U.S. Army Corps of Engineers (Emergency Closure Gate and Valve Guide)

Nathalie Laberge, Hydro-Québec (Guidebook, Governor Guide)

Francine Lefrançois, Hydro-Québec (Crane Guide)

Mark Lindstrom, U.S. Army Corps of Engineers (Crane Guide)

Deborah Linke, Bureau of Reclamation (Guidebook)

Duke Loney, U.S. Army Corps of Engineers (Guidebook, Compressed Air System Guide,

Turbine Guide)

Tom Manni, Bureau of Reclamation (Generator Guide)

Ken Maxey, Bureau of Reclamation (Guidebook)

Steve Melavic, Bureau of Reclamation (Emergency Closure Gate and Valve Guide)

Ronnie Murphy, Hydro-Québec (Guidebook)

Brian Moentenich, U.S. Army Corps of Engineers (Turbine Guide)

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Richard Nelson, U.S. Army Corps of Engineers (Guidebook)

Phat Vinh Nguyen, Hydro-Québec (Compressed Air System Guide)

Jim Norlin, U.S. Army Corps of Engineers (Guidebook)

Duc Ngoc Nguyen, Hydro-Québec (Generator Guide)

Gary Osburn, Bureau of Reclamation (Guidebook, Surge Arrester Guide, Plant Battery Guide,

Transformer Guide)

Shawn Patterson, Bureau of Reclamation (Excitation System Guide)

Abel Pereira, Bonneville Power Administration (Surge Arrester Guide, Transformer Guide)

Mark Pierce, U.S. Army Corps of Engineers (Generator Guide)

Lori Rux, U.S. Army Corps of Engineers (Guidebook, Generator Guide)

Mitch Samuelian, Bureau of Reclamation (Guidebook)

Jay Seitz, Bureau of Reclamation (Guidebook)

Phil Thor, Bonneville Power Administration (Guidebook, Generator Guide, Emergency Closure

Gate and Valve Guide)

Robert Thouin, Hydro-Québec (Turbine Guide)

Jean-Paul Rigg, Hydro-Québec (Guidebook)

Ginette Vaillancourt, Hydro-Québec (Governor Guide, Turbine Guide)

Rich Vaughn, U.S. Army Corps of Engineers (Governor Guide, Compressed Air System Guide)

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Appendix E: Equipment Condition Assessment Guides Condition Assessment Guides have been developed for the following equipment:

• Batteries • Circuit Breakers • Compressed Air Systems • Cranes • Emergency Closure Gates and Valves • Excitation Systems • Generators • Governors • Surge Arresters • Transformers • Turbines

Note: Due to the size of the condition assessment guides, they are available as separate

electronic files.

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September 2006 Hydro Plant Risk Assessment Guide Appendix E1: Generator Condition Assessment E1.1 GENERAL Hydroelectric generators are key components in the power train at hydroelectric powerplants and are appropriate for analysis under a condition assessment program. Unexpected generator failure can have a significant economic impact due to the high cost of emergency repairs and lost revenues during an extended forced outage. Determining the present condition of a generator is an essential step in analyzing the risk of failure. This appendix provides a process for arriving at a Generator Condition Index which may be used to develop a business case addressing risk of failure, economic consequences, and other factors. E1.2 SCOPE / APPLICATION The condition assessment methodology outlined in this appendix applies to hydroelectric generators, motor/generators, and motors rated 2 MW (megawatts) or higher. The condition assessment primarily focuses on the generator stator winding and core, rotor, and field and amortisseur windings. Auxiliary components such as fans, coolers, fire suppression systems, generator protection relays, etc. are not considered during this assessment. This appendix is not intended to define generator maintenance practices or describe in detail generator inspections, tests, or measurements. Utility-specific maintenance policies and procedures must be consulted for such information. E1.3 CONDITION AND DATA QUALITY INDICATORS, AND GENERATOR

CONDITION INDEX This appendix describes the condition indicators generally regarded by hydro plant engineers as providing the initial basis for assessing generator condition. The following indicators are used to separately evaluate the condition of the stator and rotor:

• Physical Inspection • Insulation Resistance and Polarization Index (stator and field windings) • Operation & Maintenance History • Age

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These condition indicators are initially evaluated using Tier 1 inspections, tests, and measurements, which are conducted by utility staff or contractors over the course of time and as a part of routine maintenance activities. Numerical scores are assigned to each stator and rotor condition indicator, which are then weighted and summed to determine the Stator and Rotor Condition Indices. The lower of the two indices is selected to represent the overall Generator Condition Index. An additional stand-alone indicator is used to reflect the quality of the information available for scoring the generator condition indicators. In some cases, data may be missing, out-of-date, or of questionable integrity. Any of these situations could affect the accuracy of the associated condition indicator scores as well as the validity of the overall Condition Index. Given the potential impact of poor or missing data, the Data Quality Indicator is used as a means of evaluating and recording confidence in the final Generator Condition Index. Additional information regarding generator condition may be necessary to improve the accuracy and reliability of the Generator Condition Index. Therefore, in addition to the Tier 1 condition indicators, this appendix describes a “toolbox” of Tier 2 inspections, tests, and measurements that may be applied to the Stator and Rotor Condition Indices, depending on the specific issue or problem being addressed. Tier 2 tests are considered non-routine. However, if Tier 2 data is readily available, it may be used to supplement the Tier 1 assessment. Alternatively, Tier 2 tests may be deliberately performed to address Tier 1 findings. Results of the Tier 2 analysis may either increase or decrease the score of the Generator Condition Index. The Data Quality Indicator score may also be revised during the Tier 2 assessment to reflect the availability of additional information or test data. The Generator Condition Index may indicate the need for immediate corrective actions and/or follow-up Tier 2 testing. The Generator Condition Index may also be used as an input to a computer model that assesses risk and performs economic analyses. Note: A severely negative result of ANY inspection, test, or measurement may be adequate in itself to require immediate de-energization or prevent re-energization of the generator, regardless of the Generator Condition Index score. E1.4 INSPECTIONS, TESTS, AND MEASUREMENTS Inspections, tests, and measurements should be conducted and analyzed by staff suitably trained and experienced in generator diagnostics. Qualified staff that is competent in these routine procedures may conduct the basic tests and inspections. More complex inspections and measurements may require a generator diagnostics expert. Inspections, tests, and measurements should be performed on a frequency that provides the accurate and current information needed by the assessment. Generator condition assessment may cause concerns that justify more frequent monitoring. Utilities should consider the possibility of taking more frequent measurements or installing on-line monitoring systems that will continuously track critical parameters. This will provide

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additional data for condition assessment and establish a certain amount of reassurance as generator alternatives are being explored. Details of the inspection, testing, and measurement methods and intervals are described in technical references specific to the electric utility. E1.5 SCORING Condition indicator scoring is somewhat subjective, relying on the experience and opinions of plant staff and generator experts. Relative terms such as “Results Normal” and “Degradation” refer to results that are compared to industry accepted levels; or to baseline or previously acceptable levels on this equipment; or to equipment of similar design, construction, or age operating in a similar environment. E1.6 WEIGHTING FACTORS Weighting factors used in the condition assessment methodology recognize that some Condition Indicators affect the Generator Condition Index to a greater or lesser degree than other indicators. These weighting factors were arrived at by consensus among generator design and maintenance personnel with extensive experience. E1.7 MITIGATING FACTORS Every generator is unique and, therefore, the methodology described in this guide cannot quantify all factors that affect individual generator condition. If the Generator Condition Index triggers significant follow-up actions (e.g., major repairs or a Tier 2 assessment), it may be prudent to first have the index reviewed by generator experts. Mitigating factors specific to the utility may affect the final Generator Condition Index and the final decision on generator replacement or rehabilitation. E1.8 DOCUMENTATION Substantiating documentation is essential to support findings of the assessment, particularly where a Tier 1 condition indicator score is less than 3 (i.e., less than normal) or where a Tier 2 test results in subtractions to the Generator Condition Index. Test reports, photographs, O & M records, and other documentation should accompany the Generator Condition Assessment Summary Form. E1.9 CONDITION ASSESSMENT METHODOLOGY The condition assessment methodology consists of analyzing each condition indicator individually to arrive at a condition indicator score. The scores are weighted and summed to determine the Condition Index. Condition Indices are developed separately for the stator and rotor. The lower of the Stator and Rotor Condition Indices is used to arrive at an overall

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Generator Condition Index. The Generator Condition Index is applied to the Generator Condition-Based Alternatives, Table 24, to determine the recommended course of action. The stator condition assessment focuses on the stator winding and core. Stator winding condition is evaluated using Tier 1 and Tier 2 tests. Assessment of the stator core is considered to be non-routine, and therefore, a Tier 2 evaluation. Rotor condition assessment comprises the rotor, and field and amortisseur windings. Rotor components are evaluated using both Tier 1 and Tier 2 tests. Reasonable efforts should be made to perform Tier 1 inspections, tests, and measurements. However, when data is unavailable to properly score a condition indicator, it may be assumed that the score is “Good” or numerically equal to some mid-range number such as 2. This strategy must be used judiciously to prevent erroneous results and conclusions. In recognition of the potential impact of poor or missing data, a separate Data Quality Indicator is rated as a means of evaluating and recording confidence in the final Generator Condition Index. E1.10 TIER 1 – INSPECTIONS, TESTS, AND MEASUREMENTS Tier 1 tests include those inspections, tests, and measurements that are routinely accomplished as part of normal operation and maintenance, or are readily discernible by examination of existing data. Tier 1 test results are quantified below as condition indicators that are weighted and summed to arrive at a Condition Index. Tier 1 tests may indicate abnormal conditions that can be resolved with standard corrective maintenance solutions. To the extent that Tier 1 tests result in immediate corrective maintenance actions being taken by plant staff, then adjustments to the condition indicators should be reflected and the new results used when computing the overall Tier 1 Condition Index. Tier 1 test results may also indicate the need for additional investigation, categorized as Tier 2 tests. E1.11 STATOR CONDITION INDICATORS Stator Condition Indicator 1 – Operation & Maintenance History During operation, large synchronous generators are continuously subjected to electrical, mechanical, thermal, and environmental stresses. These stresses act and interact in complex ways to degrade the machine’s components and reduce its useful life. Deterioration of the stator winding insulation is a leading factor for determining the serviceability of hydroelectric generators. Unexpected stator winding failure can result in forced outages and costly emergency repairs. Operation and maintenance history may provide a useful indication of stator condition. The operation and maintenance history of the generator should be reviewed by qualified personnel to make a subjective determination of scoring that encompasses as many operation and maintenance factors as possible under this indicator. Factors to consider include:

• Maintenance needs are increasing with time or problems are re-occurring; • Spare parts are becoming unavailable; • Frequent starts and stops; • Rapid loading ramp rates are used;

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• Operating outside of voltage rating (either higher or lower); • Sustained overloading; • Frequent rough-zone crossings; • Close-in lightning strikes; • Out-of-phase breaker closings; • Unbalanced phase operation; • Previous failures on this equipment related to the stator winding or core; • Failures or problems on equipment of similar design, construction, or age operating in

a similar environment. Results of stator winding O & M history are analyzed and applied to Table 1 to arrive at an appropriate Stator Condition Indicator Score.

Table 1 – Stator Winding Operation & Maintenance History Scoring

Results Stator Condition Indicator Score

Operation and maintenance normal. 3

Some abnormal operating conditions experienced and/or additional maintenance above normal occurring. 2

Significant operation outside normal and/or significant additional maintenance is required; forced outage occurs; outages are regularly extended due to maintenance problems; similar units are problematic.

1

Repeated forced outages; maintenance not cost effective; major electrical or mechanical failures; similar units have reached end-of-life.

0

Stator Condition Indicator 2 – Physical Inspection Several types of stator winding problems can be detected during the course of physical inspections, such as insulation cracks, bulging or puffy coils, surface corona, contamination, carbon tracks, winding movement, loose bracing and blocking, and loose wedges or slot fillers. Qualified personnel should make a subjective determination of scoring that encompasses as many inspection factors as possible under this indicator. Negligible evidence of aging, damage, and/or deterioration would lead to a “normal” rating, whereas a minor amount of wear and tear would be rated as “some deterioration.” If the deterioration observed is very obvious and widespread, a rating of “significant deterioration” is appropriate. At a minimum, the following areas should be inspected and the condition evaluated:

• Stator winding; • Stator winding wedges, packing, blocking, and bracing; • Circuit ring bus; • Main and neutral leads.

Results of the stator winding physical inspection are analyzed and applied to Table 2 to arrive at a Stator Condition Indicator Score.

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Table 2 – Stator Winding Physical Inspection Scoring

Results Stator Condition Indicator Score

Inspection results are normal. 3

Inspection shows some deterioration. 2

Inspection shows significant deterioration. 1

Inspection shows complete or imminent failure of stator winding components. 0

Stator Condition Indicator 3 – Insulation Resistance and Polarization Index Insulation resistance is defined as the quotient of the applied direct voltage over the measured current (R = V/I). For a high capacitance specimen such as a generator stator winding, an applied voltage step will result in a measured current that decays exponentially with time. Because of this time-dependency, insulation resistance is normally calculated and recorded one minute after the test voltage is applied. Insulation resistance measurements combine both surface and volume resistances, and are mainly used to detect moisture absorption, conductive contamination, degree of cure, and cracks or fissures. Insulation resistance tests are sensitive to specimen temperature and are often normalized to a standard temperature (typically 40°C) for analysis. Humidity and surface contamination can also affect the measurement. The insulation resistance of good insulation may range from hundreds to thousands of megaohms. Comparison of individual phases and trending over time are the best means of evaluating insulation condition. A polarization index test is similar to the insulation resistance test except that current readings are taken at two time intervals, normally one and ten minutes after application of the voltage step. The quotient of these two current readings (I1/I10) is termed the polarization index and gives an indication of insulation dryness, contamination, cure, and mechanical integrity. Since the polarization index is the ratio of two measurements made under identical conditions, it is less sensitive to temperature variations than is insulation resistance. However, normal polarization indices vary significantly for different types of insulation systems depending on the electrical properties of the constituent dielectric materials, making it difficult to define acceptable polarization index criteria. Therefore, trending of measurements over time and comparison between phases are typically necessary to assess insulation condition. Stator winding insulation resistance and polarization index test results should be analyzed and applied to Table 3 to arrive at a Stator Condition Indicator Score.

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Table 3 – Stator Winding Insulation Resistance and Polarization Index Scoring

Results Stator Condition Indicator Score Results are normal and similar to previous tests. 3

Results indicate minor decrease in insulation resistance or polarization index (e.g., factor of 2 decrease).

2

Results indicate significant decrease in insulation resistance or polarization index (e.g., factor of 10 decrease).

1

Insulation resistance or polarization index is below minimum acceptable values. 0

Stator Condition Indicator 4 – Winding Age The age of the generator stator winding is an important factor to consider when identifying candidates for replacement. Age is one indicator of remaining life and upgrade potential to state-of-the-art materials and designs. The design life of a stator winding rated 6.9 kV or higher is typically 25 to 35 years. For lower voltage windings, the design life is typically 35 years or more. It is important to recognize, however, that although age may be a useful indicator, the actual service life that can be realized varies widely depending on the specific equipment manufacturer and date of manufacture; the insulation system design, materials, and production methods; the quality of installation; and the generator’s operation and maintenance history. The stator winding age should be determined and applied to Table 4 to arrive at an appropriate Stator Condition Indicator Score.

Table 4 – Stator Winding Age Scoring

Age Stator Condition Indicator Score

< 20 years 3

≥ 20 and < 30 years 2

≥ 30 and < 40 years 1

≥ 40 years 0 E1.12 TIER 1 – STATOR CONDITION INDEX CALCULATIONS Enter the stator condition indicator scores from the tables above into the Stator Condition Assessment Summary form at the end of this document. Multiply each stator indicator score by its respective Weighting Factor, and sum the Total Scores to arrive at the Tier 1 Stator Condition

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Index. Attach supporting documentation. The Stator Condition Index may be adjusted by the Tier 2 stator inspections, tests, and measurements described later in this document. E1.13 TIER 1 – STATOR DATA QUALITY INDICATOR Stator Data Quality Indicator – Quality of Inspections, Tests, and Measurements The Stator Data Quality Indicator reflects the quality of the inspection, test and measurement results used to evaluate the stator condition under Tier 1. The more current and complete the results are, the higher the rating for this indicator. The normal testing frequency is defined as the organization’s recommended frequency for performing the specific test or inspection. Qualified personnel should make a subjective determination of scoring that encompasses as many factors as possible under this indicator. Results are analyzed and applied to Table 5 to arrive at an appropriate Stator Data Quality Indicator Score.

Table 5 – Stator Data Quality Scoring

Results Stator Data Quality Indicator Score All Tier 1 inspections, tests and measurements were completed within the normal testing frequency and the results are reliable.

10

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 6 and < 24 months past the normal testing frequency and results are reliable.

7

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 24 and < 36 months past the normal testing frequency, or some of the results are not available or are of questionable integrity.

4

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 36 months past the normal frequency, or no results are available or many are of questionable integrity.

0

Enter the Stator Data Quality Indicator Score from Table 5 into the Stator Condition Assessment Summary form at the end of this document.

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E1.14 ROTOR CONDITION INDICATORS Rotor Condition Indicator 1 – Operation & Maintenance History Operation and maintenance history may provide a useful indication of generator rotor condition. The operation and maintenance history of the rotor should be reviewed by qualified personnel to make a subjective determination of scoring that encompasses as many operation and maintenance factors as possible under this indicator. Factors to consider include:

• Maintenance needs increasing with time or problems are re-occurring; • Spare parts are becoming unavailable; • Operating outside of voltage rating (either higher or lower); • Sustained overloading; • Frequent rough-zone crossings; • Out-of-phase breaker closings; • Number of times unit has been subjected to over speed or runaway (usually

associated with load rejection); • Previous failures on this equipment related to the rotor or field winding; • Failures or problems on equipment of similar design, construction, or age operating in

a similar environment. Results of rotor O & M history are analyzed and applied to Table 6 to arrive at an appropriate Rotor Condition Indicator Score.

Table 6 – Rotor Operation & Maintenance History Scoring

Results Rotor Condition Indicator Score

Operation and maintenance normal. 3

Some abnormal operating conditions experienced and/or additional maintenance above normal is required.

2

Significant operation outside normal and/or significant additional maintenance is required; forced outage occurs; outages are regularly extended due to maintenance problems; similar units are problematic.

1

Repeated forced outages; maintenance not cost effective; major electrical or mechanical failures; similar units have reached end-of-life.

0

Rotor Condition Indicator 2 – Physical Inspection Several types of rotor problems can be detected during the course of physical inspections, such as overheating, loose and vibrating components, impact damage, and contamination. Qualified personnel should make a subjective determination of scoring that encompasses as many inspection factors as possible under this indicator. The following areas should be inspected and the deterioration should be evaluated:

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• Rotor hub, radial arms, and rim; • Field poles, keys, collars, and pole faces; • Field windings and interpole connections; • Field winding leads; • Amortisseur winding bars, shorting straps, and inter-connections; • Rim-mounted fan blades.

Results of the rotor physical inspection are analyzed and applied to Table 7 to arrive at a Rotor Condition Indicator Score.

Table 7 – Rotor Physical Inspection Scoring

Results Rotor Condition Indicator Score

Inspection results are normal. 3

Inspection shows some deterioration. 2

Inspection shows significant deterioration. 1

Inspection shows complete or imminent failure of field winding components. 0

Rotor Condition Indicator 3 – Insulation Resistance and Polarization Index Refer to “Stator Condition Indicator 3 – Insulation Resistance and Polarization Index” in section E1.11 above for a detailed description of insulation resistance and polarization index measurements. Results of the insulation resistance and polarization index tests are analyzed and applied to Table 8 to arrive at a Rotor Condition Indicator Score.

Table 8 – Field Winding Insulation Resistance and Polarization Index Scoring

Results Rotor Condition Indicator Score Results are normal and similar to previous tests. 3

Results indicate minor decrease in insulation resistance or polarization index (e.g., factor of 2 decrease).

2

Results indicate significant decrease in insulation resistance or polarization index (e.g., factor of 10 decrease).

1

Insulation resistance or polarization index is below minimum acceptable values. 0

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Rotor Condition Indicator 4 – Field Winding Age The age of the generator field winding is an important factor to consider when identifying candidates for replacement. Age is one indicator of remaining life and upgrade potential to state-of-the-art materials and designs. The design life (or life expectancy) of the insulation of field windings is 50 to 60 years. Although age is a useful indicator of remaining life and upgrade potential, it is also important to recognize that the actual service life that can be realized varies widely depending on the specific equipment manufacturer and date of manufacture; the insulation system design, materials, and production methods; the quality of installation; and the generator’s operation and maintenance history. The age of the field winding should be determined and applied to Table 9 to arrive at an appropriate Rotor Condition Indicator Score.

Table 9 – Field Winding Age Scoring

Age Rotor Condition Indicator Score

< 20 years 3

≥ 20 and < 30 years 2

≥ 30 and < 40 years 1

≥ 40 years 0 E1.15 TIER 1 – ROTOR CONDITION INDEX CALCULATIONS Enter the rotor condition indicator scores from the tables above into the Rotor Condition Assessment Summary form at the end of this document. Multiply each indicator score by its respective Weighting Factor, and sum the Total Scores to arrive at the Tier 1 Rotor Condition Index. Attach supporting documentation. The Rotor Condition Index may be adjusted by the Tier 2 rotor inspections, tests, and measurements described later in this document. E1.16 TIER 1 – ROTOR DATA QUALITY INDICATOR Rotor Data Quality Indicator – Quality of Inspections, Tests, and Measurements The Rotor Data Quality Indicator reflects the quality of the inspection, test and measurement results used to evaluate the rotor condition under Tier 1. The more current and complete the inspections, tests and measurements, the higher the rating for this indicator. The normal testing frequency is defined as the organization’s recommended frequency for performing the specific test or inspection.

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Qualified personnel should make a subjective determination of scoring that encompasses as many factors as possible under this indicator. Results are analyzed and applied to Table 10 to arrive at an appropriate Rotor Data Quality Indicator Score.

Table 10 – Rotor Data Quality Scoring

Results Rotor Data Quality Indicator Score All Tier 1 inspections, tests and measurements were completed within the normal testing frequency and the results are reliable.

10

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 6 and < 24 months past the normal testing frequency.

7

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 24 and < 36 months past the normal testing frequency, or some of the results are not available.

4

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 36 months past the normal frequency, or no results are available.

0

Enter the Rotor Data Quality Indicator Score from Table 10 into the Rotor Condition Assessment Summary form at the end of this document. E1.17 TIER 2 – STATOR INSPECTIONS, TESTS, AND MEASUREMENTS Tier 2 inspections, tests, and measurements generally require specialized equipment or expertise, may be intrusive, or may require an outage to perform. A Tier 2 assessment is not considered routine. Tier 2 inspections are intended to affect the Generator Stator Condition Index established using Tier 1 tests as well as confirm or disprove the need for more extensive maintenance, rehabilitation, or generator replacement. Note that there are many tests that can provide information about the various aspects of stator condition. The choice of which tests to apply should be made based on known information obtained via review of O & M history, physical inspection, other test results, and company standards as well as the Tier 1 assessment. Many of the following Tier 2 tests are used to detect or confirm a similar defect or state of deterioration. In the event that more than one Tier 2 tests are performed to assess the same problem or concern, then the test with the largest adjustment shall be used to recalculate the Stator Condition Index. It is important to avoid adjusting the Condition Index downward twice or more simply because multiple tests are completed for the same suspected problem. Since the Tier 2 tests are being performed by and/or coordinated with knowledgeable technical staff, the decision as to which test is more significant and how different tests overlap is left to the experts.

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For Tier 2 assessments performed, apply only the appropriate adjustment factors per the instructions above and recalculate the Stator Generator Condition Index using the Generator Condition Assessment Summary form at the end of this document. An adjustment to the Data Quality Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment. Test T2.S1: Ramped Voltage Test To conduct this test, an automatic high-voltage power supply (i.e., ramped voltage test set) is used to linearly increase the applied direct voltage from zero up to some maximum value at a constant ramp rate, typically 1 to 2 kV per minute. The current response versus applied voltage is measured and plotted, and the results are used to evaluate the condition of the insulation by noting deviations from the normal shape of the test curve. Any departure from a smooth curve could be an indication of insulation problems. Because the maximum test voltage is above the normal operating stress, the ramped voltage test also serves as a high-potential withstand test. Ramped voltage test results are analyzed and applied to Table 11 to arrive at a Stator Condition Index score adjustment.

Table 11 – Ramped Voltage Test Scoring Test Results Adjustment to

Stator Condition Index

Smooth, linear curve. Add 0.5

Curve slightly nonlinear, similar to previous test results.* No Change

Curve less linear than previous test results.* Subtract 0.5

Curve significantly less linear than previous test results.* Subtract 1.0

Test stopped early to avoid breakdown. Subtract 2.0

Failure during test. Subtract 5.0 *If no previous test results are available, compare to results of similar machines or to typical results. Test T2.S2: Partial Discharge Measurements Partial discharges are localized ionizations of the gaseous space surrounding or within a solid insulation. When the electric stress in the gas exceeds a critical value, a transient ionization, or partial discharge, occurs. The ionized gas contains electrons, ions, excited molecules, and free radicals. These chemically reactive species can affect and degrade the adjacent solid insulation. Although the damage caused by a single partial discharge (PD) event is minute, the cumulative effect of many discharges can eventually lead to insulation failure. There are several potential sites of partial discharges in high-voltage generator stator windings, such as between the surface of the slot portion of the winding and the grounded stator core, at

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either boundary of the voltage stress grading coating in the end turn area, in the winding overhang region where potential differences exist between adjacent coils separated by small air spaces, and internal to the insulation within voids, delaminations, or other defects. PD measuring equipment and data analysis methods have been developed to quantify the level of discharge activity and determine the source. Measurements may be made either on-line or off-line, and a variety of detection techniques are possible (e.g., corona probe, PDA, EMI). Since discharge measurements are greatly influenced by the specific measuring technique, the PD instrument manufacturer should be consulted to determine appropriate evaluation criteria. Partial discharge test results are analyzed and applied to Table 12 to arrive at a Stator Condition Index score adjustment.

Table 12 – Partial Discharge Test Scoring

Test Results Adjustment to Stator Condition Index

Low PD readings throughout the generator. Add 0.5

Few in number and low in magnitude. No Change

Numerous high PD readings. Subtract 0.5

Widespread and abnormally high PD readings. Subtract 1.0 Test T2.S3: Dissipation (or Power) Factor Measurements The dissipation factor, or tan δ, represents the losses in an insulation tested under sinusoidal voltage conditions. (Alternately, the power factor = cos θ is used to measure insulation losses. Typically, the numerical difference between tan δ and cos θ is negligible so that the terms dissipation factor and power factor are often used interchangeably.) Absolute values of tan δ as well as changes with respect to voltage are used to assess insulation quality and condition. When performing the test, several tan δ measurements are made over a range of applied voltages. For example, a typical test schedule would involve making measurements from 0.25 Un (where Un equals the rated phase-to-neutral voltage of the winding) through 1.25 Un, increasing the test voltage in increments of 0.25 Un. The tip-up, or Δ tan δ, is calculated by subtracting tan δ measured at 0.25 Un from tan δ at 1.0 Un. Relatively high values of tan δ and tip-up generally indicate the presence of voids, delaminations, or high conductivity. Normal tan δ measurements may vary depending on several factors, such as the type of dielectric materials comprising the insulation, the effect of the end winding voltage stress grading treatment, and specimen temperature and humidity. Given the difficulty in establishing absolute limits for tan δ measurements, trending over time and/or comparisons among identical machines are generally needed to analyze and interpret dissipation factor values. Dissipation factor results are analyzed and applied to Table 13 to arrive at a Stator Condition Index score adjustment.

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Table 13 – Dissipation Factor Scoring

Test Results Adjustment to Stator Condition Index

Tan δ and tip-up are below expected values. Add 0.5

Tan δ and tip-up are equal to expected values. No Change Tan δ or tip-up slightly exceed expected values. Subtract 0.5

Tan δ or tip-up somewhat exceed expected values or have increased since previous test. Subtract 1.0

Tan δ or tip-up significantly exceed expected values or have increased sharply since previous test.

Subtract 2.0

Test T2.S4: Ozone Monitoring The presence of ozone in an air-cooled hydrogenerator stator housing is usually an indication that high intensity electrical discharges are occurring in the machine. Discharges between the surfaces of the slot portion of the generator stator winding and the grounded stator core are referred to as slot discharges and result from defective or deteriorated semi-conductive slot treatment or because the stator coils are loose in their slots. Discharges which occur at either boundary of the voltage stress grading coating in the end turn area of the stator winding are often called grading coating discharges. Grading coating discharges normally result from deficiencies in the voltage stress grading system. If the resistivity of the voltage grading treatment is too high, discharges occur at the interface between the grading treatment and the semi-conductive slot paint. If the resistivity is too low, discharges occur at the upper boundary of the stress grading treatment, i.e., away from the stator core. Electrical activity can also occur in the end winding region where high potential differences exist, such as between adjacent line- and neutral-end coils or between line-end coils of different phases. These discharges are known as end winding discharges. End winding discharges vary according to winding design, geometry and spacing between coils, the type of surface treatment, and end winding cleanliness. Stator windings can also experience internal discharges due to voids in the groundwall insulation. These discharges are not likely to cause elevated ozone levels. All types of external discharges can cause air to ionize, producing ozone and other damaging by-products. In addition to the risk of a stator winding insulation failure resulting from intense electrical discharges, damage to the ferrous and rubber materials which are exposed to ozone can also be extremely serious. The following components are particularly susceptible to ozone: the iron stator core, brake ring, rotor shaft, hub, and rim laminations; air cooler fins and gaskets; unpainted water piping, and other exposed surfaces. Furthermore, normal leakage of stator housing air into the powerplant can result in increased background ozone levels in the plant work areas, prompting concern for worker health and safety. Ozone levels may vary depending on the particular location at which the measurement is taken within the machine, as well as generator terminal voltage, loading, temperature and relative

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humidity. Therefore, to the extent possible, repeat ozone measurements should be made under the same general conditions. Ozone results are analyzed and applied to Table 14 to arrive at a Stator Condition Index score adjustment.

Table 14 – Ozone Scoring

Test Results Adjustment to Stator Condition Index

Ozone levels < 0.05 ppm. Add 0.5

Ozone levels ≥ 0.05 and < 0.1 ppm. No Change

Ozone levels ≥ 0.1 and < 1.0 ppm. Subtract 1.0

Ozone levels ≥ 1.0 ppm. Subtract 2.0 Test T2.S5: Black Out Test This test is generally performed on generators with stator windings rated 6900 volts and above since machines with lower ratings are not likely to experience surface discharges during normal operation. The black out test may be performed with either the rotor in place or removed. However, removing the rotor improves visibility of surface discharges in the slot region. The test is typically conducted in the evening with the powerhouse lights off. A black plastic covering may be placed over the air housing to help eliminate outside light. An individual coil, group of coils, complete phase, or the entire stator winding is energized at rated voltage or slightly above while observers positioned inside the unit look for visual evidence of electrical discharges. Active areas of corona are noted with respect to slot number and location. Black out test results are analyzed and applied to Table 15 to arrive at a Stator Condition Index score adjustment.

Table 15 – Black Out Test Scoring

Test Results Adjustment to Stator Condition Index

Negligible corona. Add 0.5

Few locations and minor intensity. No Change

Several locations and moderate intensity. Subtract 1.0

Widespread, intense corona. Subtract 2.0

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Test T2.S6: High-Potential Withstand Test High-potential withstand tests are typically performed to provide some assurance that the winding insulation has a minimum level of electrical strength. Because the inherent withstand capability of sound insulation is well above the usual proof test value, failure during a test at an appropriate voltage indicates the insulation is unsuitable for service. Withstand tests are intended to search for flaws in the material and for manufacturing defects, and to demonstrate in a practical manner that the insulation has a minimum level of electrical integrity. A primary requirement of such a test is that it should be discerning and effective in detecting serious flaws at or below the minimum specified strength without damaging sound insulation. The applied test voltage may be power frequency, very low frequency (VLF), or direct voltage. Stator winding high-potential withstand test results are analyzed and applied to Table 16 to arrive at a Stator Condition Index score adjustment.

Table 16 – Stator Winding High-Potential Withstand Test Scoring

Test Results Adjustment to Stator Condition Index

Passed withstand test. Add 0.5

Failed withstand test. Subtract 5.0 Test T2.S7: Stator Core Inspection A stator core physical inspection may be done with the rotor in place although it is more convenient to examine the core with the rotor removed. The stator core should be examined for looseness and shifting. Core looseness should be checked with the knife test. Stator through bolt torque may also be checked. Any broken core laminations, laminations which protrude into the air gap, signs of fretting corrosion, bent core duct separators, or other evidence of core damage should be noted. Interlaminar insulation faults may result in severe overheating which could damage the stator winding at that location. Generally, defects at the core surface are easily observed while defects in the slot area or in the back iron are not detectible visually. If inspection panels are present on the stator frame wrapper, they should be removed to allow inspection of the back iron and stator frame. Stator core inspection results are analyzed and applied to Table 17 to arrive at a Stator Condition Index score adjustment.

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Table 17 – Stator Core Inspection Scoring

Test Results Adjustment to Stator Condition Index

Core condition appears very good. Add 0.5

No indication of core damage or deterioration. No Change

Minor core damage or deterioration. Subtract 0.5

Moderate core damage or deterioration. Subtract 1.0

Significant core damage or deterioration. Subtract 2.0 Test T2.S8: Wedge Tightness Evaluation Stator windings are wedged into the core slots and subjected to positive radial pressure to protect the winding from vibration-induced damage during normal operation and to keep coils/bars from being forced out of the slots during phase-to-phase short circuit conditions. This evaluation is used to determine the condition of the stator winding wedge system. The wedge system should be examined closely for loose, broken, or burnt wedges. To perform a comprehensive assessment with the rotor in place, one or two pole pieces must be removed in order to access the entire length of the stator core and the rotor must be rotated manually in order to inspect all wedges in every slot. A partial evaluation may be conducted by inspecting only those wedges that are within reach between the rotor poles. The wedge evaluation procedure requires careful visual inspection of the wedging system, including wedges and slot packing materials. The wedge system may be further examined by tapping the wedges with a blunt metallic instrument which rings or vibrates when hit against a solidly wedged slot. Loose wedges produce a dull sound when tapped. Commercial wedge tightness measuring tools are also available. Wedge systems utilizing under-wedge ripple springs may be evaluated using a depth gauge to measure the ripple spring compression. Regardless of the specific evaluation method used, wedge system condition is assessed based on the overall percentage of loose wedges as well as the number and location of loose wedges in any given slot. Stator core inspection results are analyzed and applied to Table 18 to arrive at a Stator Condition Index score adjustment.

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Table 18 – Wedge Tightness Scoring

Test Results Adjustment to Stator Condition Index

Rewedging completed within last < 5 years and no indication of loose wedges. Add 0.5

No indication of loose wedges. No Change

Few loose wedges. Subtract 0.5

Numerous loose wedges. Subtract 1.0

Widespread loose wedges. Subtract 2.0 Test T2.S9: Core Loop Test The stator core loop test, also known as the ring test or rated flux test, is performed on motor or generator stators to evaluate the integrity of the core laminations. Core damage may be caused by ingress of foreign bodies into the stator bore, excessive vibrations, or deterioration of the lamination insulation due to overheating or other aging processes. Inadvertent core damage may also occur during rewedging or removal of the rotor and/or stator coils. A bearing failure may also cause the rotor to rub and damage the stator core. The core loop test is used to detect damage, assess its severity, and indicate whether repair is required. The loop test is made by wrapping an excitation winding around the stator core and frame. A 60-Hz voltage is applied to the winding sufficient to induce a flux approximately equal to the rated operating flux density and produce normal axial voltage between laminations. Defective areas of the core or tooth insulation appear as “hot spots’ that can be detected via infrared thermal imaging. An area of iron exhibiting a temperature equal to or greater than 5 °C above the average core temperature is generally considered to be a hot spot. Core loop test results are analyzed and applied to Table 19 to arrive at a Stator Condition Index score adjustment.

Table 19 – Core Loop Test Scoring

Test Results Adjustment to Stator Condition Index

No visible hot spots. Add 0.5

One warm spot < 5 °C. No Change Two or more warm spots < 5 °C, or one hot spot ≥ 5 °C and < 10 °C. Subtract 0.5

Two or more hot spots ≥ 5 °C and < 10 °C. Subtract 1.0

One or more hot spots ≥ 10 °C. Subtract 2.0

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Test T2.S10: EL CID Test The Electromagnetic Core Imperfection Detector (EL CID) test is used to detect and evaluate known or suspected damage to the stator core lamination insulation. The main advantage of the EL CID test over the rated flux test is that it requires a much smaller capacity power supply for the excitation winding, since only 3 to 4 percent of rated flux needs to be induced in the core. The EL CID test operates on the basis that eddy currents will flow through failed or significantly aged core insulation. Using a special “Chattock coil,” a voltage signal is obtained that is proportional to the magnitude of eddy current flowing between laminations. The measured voltage is fed to a signal processor what gives an output in mA (milliamperes) that represents the axial component of the measured voltage. Relatively high readings indicate faulty insulation. The manufacturer of the EL CID test equipment states that output readings above 100 mA indicate significant core shorting. EL CID test results are analyzed and applied to Table 20 to arrive at a Stator Condition Index score adjustment.

Table 20 – EL CID Test Scoring

Test Results Adjustment to Stator Condition Index

No readings > 50 mA. Add 0.5

No readings > 100 mA. No Change

One reading > 100 mA and ≤ 200 mA. Subtract 0.5

Two or more readings > 100 mA and ≤ 200 mA. Subtract 1.0

One or more readings > 200 mA. Subtract 2.0 Test T2.S11: Other Specialized Diagnostic Tests Additional tests such as winding dissection, capacitance measurements, core bolt insulation resistance, winding conductor resistance measurements, and others may be applied to evaluate specific stator winding or core problems. Some of these diagnostic tests may be considered to be of an investigative research nature. When conclusive results from other diagnostic tests are available, they may be used to make an appropriate adjustment to the Stator Condition Index. E1.18 TIER 2 – STATOR CONDITION INDEX CALCULATIONS Enter the Tier 2 adjustments from the tables above into the Generator Condition Assessment Summary form at the end of this guide. Subtract the sum of these adjustments from the Tier 1 Stator Condition Index to arrive at the Net Stator Condition Index. Attach supporting documentation. An adjustment to the Data Quality Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment.

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E1.19 TIER 2 – ROTOR INSPECTIONS, TESTS, AND MEASUREMENTS Tier 2 inspections, tests, and measurements generally require specialized equipment or expertise, may be intrusive, or may require an outage to perform. A Tier 2 assessment is not considered routine. Tier 2 inspections are intended to affect the Rotor Condition Index number established using Tier 1 tests as well as confirm or disprove the need for more extensive maintenance, rehabilitation, or generator replacement. Note that there are many tests that can provide information about the various aspects of rotor condition. The choice of which tests to apply should be made based on known information obtained via review of O & M history, physical inspection, other test results, and company standards as well as the Tier 1 assessment. Many of the following Tier 2 tests are used to detect or confirm a similar defect or state of deterioration. In the event that more than one Tier 2 tests are performed to assess the same problem or concern, then the test with the largest adjustment shall be used to recalculate the Rotor Condition Index. It is important to avoid adjusting the Condition Index downward twice or more simply because multiple tests are completed for the same suspected problem. Since the Tier 2 tests are being performed by and/or coordinated with knowledgeable technical staff, the decision as to which test is more significant and how different tests overlap is left to the experts. For Tier 2 assessments performed, apply only the appropriate adjustment factors per the instructions above and recalculate the Rotor Generator Condition Index using the Generator Condition Assessment Summary form at the end of this document. Test T2.R1: High-Potential Withstand High-potential withstand tests are typically performed to provide some assurance that the winding insulation has a minimum level of electrical strength. Because the inherent withstand capability of sound insulation is well above the usual proof test value, failure during a test at an appropriate voltage indicates the insulation is unsuitable for service. Withstand tests are intended to search for flaws in the material and for manufacturing defects, and to demonstrate in a practical manner that the insulation has a minimum level of electrical integrity. A primary requirement of such a test is that is should be discerning and effective in detecting serious flaws at or below the minimum specified strength without damaging sound insulation. The applied test voltage may be power frequency, very low frequency (VLF), or direct voltage. Field winding high-potential withstand test results are analyzed and applied to Table 21 to arrive at a Rotor Condition Index score adjustment.

Table 21 – Field Winding High-Potential Withstand Test Scoring

Test Results Adjustment to Rotor Condition Index

Passed withstand test. Add 0.5

Failed withstand test. Subtract 5.0

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Test T2.R2: AC Pole Drop Test This test is performed on salient pole rotors to detect shorted turns in the field winding. The winding is energized at 120 V, 60 Hz and the voltage drop across each pole is measured. Poles with appreciably lower voltage drops may have shorted turns. The voltage drop across the immediately adjacent poles may be low as well due to the influence of the defective pole on the magnetic circuits of the adjacent poles. AC pole drop test results are analyzed and applied to Table 22 to arrive at a Rotor Condition Index score adjustment.

Table 22 – AC Pole Drop Test Scoring

Test Results Adjustment to Rotor Condition Index

Poles reinsulated within last < 10 years. Add 0.5

No indication of shorted turns. No Change

One pole with one shorted turn. Subtract 0.5

Two or more poles with one shorted turn. Subtract 1.0

One or more poles with multiple shorted turns. Subtract 2.0 Test T2.R3: Field Winding AC Impedance Due to the appreciable centrifugal forces that act on a rotor winding at rated speed, certain shorted turns may only be apparent when the rotor is revolving at or near rated speed. An impedance test can be performed while the machine is being shut down or brought up to speed to detect shorted turns that are only present under centrifugal forces. To perform the test, a 120 V, 60 Hz power supply is applied to the winding through the collector rings. The applied voltage and current are measured and the impedance is calculated over a range of rotational speeds. Field winding ac impedance test results are analyzed and applied to Table 23 to arrive at a Rotor Condition Index score adjustment.

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Table 23 – Field Winding AC Impedance Scoring

Test Results Adjustment to Rotor Condition Index

Difference between readings taken at rated speed and standstill is < 5%. No abrupt changes.

Add 0.5

Difference between readings taken at rated speed and standstill is ≥ 5% and < 10%. No abrupt changes.

No Change

Difference between readings taken at rated speed and standstill is ≥ 5% and < 10%, with abrupt change ≥ 5%.

Subtract 1.0

Difference between readings taken at rated speed and standstill is ≥ 10% and abrupt change is ≥ 5%.

Subtract 2.0

Test T2.R4: Other Specialized Diagnostic Tests Additional tests such as DC resistance measurements, temperature scanning, etc. may be applied to evaluate specific rotor problems. Some of these diagnostic tests may be considered to be of an investigative research nature. When conclusive results from other diagnostic tests are available, they may be used to make an appropriate adjustment to the Rotor Condition Index. E1.20 TIER 2 – ROTOR CONDITION INDEX CALCULATIONS Enter the Tier 2 adjustments from the tables above into the Generator Condition Assessment Summary form at the end of this guide. Subtract the sum of these adjustments from the Tier 1 Rotor Condition Index to arrive at the Net Rotor Condition Index. Attach supporting documentation. An adjustment to the Data Quality Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment. E1.21 GENERATOR CONDITION INDEX CALCULATIONS Choose the lower of the Net Stator Condition Index and Net Rotor Condition Index to represent the overall Generator Condition Index. Record the Data Quality Indicator score associated with the chosen Condition Index. Suggested alternatives for follow-up action, based on the Generator Condition Index, are described in the Generator Condition-Based Alternatives located in Table 24. E1.22 GENERATOR CONDITION-BASED ALTERNATIVES The Generator Condition Index – either modified by Tier 2 tests or not – may be sufficient for decision-making regarding generator alternatives. The Index is also suitable for use in a risk-

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and-economic analysis model. Where it is desired to consider alternatives based solely on generator condition, the Generator Condition Index may be directly applied to the Generator Condition-Based Alternatives table (Table 24).

Table 24 – Generator Condition-Based Alternatives

Generator Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat condition assessment as needed.

≥ 3.0 and < 7 (Fair) Continue operation but reevaluate O & M practices. Consider using appropriate Tier 2 tests. Repeat condition assessment process as needed.

≥ 0 and < 3.0 (Poor) Immediate evaluation including additional Tier 2 testing. Consultation with experts. Adjust O & M as prudent. Begin replacement/rehabilitation process.

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GENERATOR TIER 1 CONDITION ASSESSMENT SUMMARY

Date: _________________________ Location: ______________________________________

Gen. Identifier: ___________ Gen. Manufacturer: __________________ Yr. Mfd.: _________

Stator Winding Manufacturer: ____________________ Yr. Winding Installed: _____________

Stator Insulation Type: ________________ MVA: _______ PF: ______ Voltage: ___________

Field Winding Manufacturer: _____________________ Yr. Winding Installed: _____________

Field Insulation Type: __________________ Current: _____________ Voltage: ____________

Part A: Calculate the Tier 1 Stator Condition Index

Tier 1 Generator Stator Condition Summary (For instructions on indicator scoring, please refer to condition assessment guide)

No. Condition Indicator Score × Weighting Factor = Total Score

1 O & M History (Score must be 0, 1, 2, or 3) 1.18

2 Physical Inspection (Score must be 0, 1, 2, or 3) 1.18

3 Insulation Resistance and Polarization Index (Score must be 0, 1, 2, or 3)

0.58

4 Winding Age (Score must be 0, 1, 2, or 3) 0.39

Tier 1 Stator Condition Index (Sum of individual Total Scores)

(Condition Index should be between 0 and 10)

Tier 1 Stator Data Quality Indicator

(Value must be 0, 4, 7, or 10)

Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________

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Part B: Calculate the Tier 1 Rotor Condition Index

Tier 1 Generator Rotor Condition Summary (For instructions on indicator scoring, please refer to condition assessment guide)

No. Condition Indicator Score × Weighting Factor = Total Score

1 O & M History (Score must be 0, 1, 2, or 3) 1.18

2 Physical Inspection (Score must be 0, 1, 2, or 3) 1.18

3 Insulation Resistance and Polarization Index (Score must be 0, 1, 2, or 3)

0.58

4 Winding Age (Score must be 0, 1, 2, or 3) 0.39

Tier 1 Rotor Condition Index (Sum of individual Total Scores)

(Condition Index should be between 0 and 10)

Tier 1 Rotor Data Quality Indicator

(Value must be 0, 4, 7, or 10)

Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________

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Part C: Determine the Tier 1 Generator (Stator and Rotor) Condition Index To determine the Tier 1 Generator (Stator and Rotor) Condition Index, choose the lower of the Tier 1 Stator Condition Index and the Tier 1 Rotor Condition Index. Record the Data Quality Indicator associated with the chosen Condition Index. Generator Condition Index _____________ Data Quality Indicator _________________ (Attach supporting documentation.)

Generator Condition-Based Alternatives

Generator Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat condition assessment as needed.

≥ 3.0 and < 7 (Fair) Continue operation but reevaluate O & M practices. Consider using appropriate Tier 2 tests. Repeat condition assessment process as needed.

≥ 0 and < 3.0 (Poor) Immediate evaluation including additional Tier 2 testing. Consultation with experts. Adjust O & M as prudent. Begin replacement/rehabilitation process.

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GENERATOR TIER 2 CONDITION ASSESSMENT SUMMARY

Date: _________________________ Location: ______________________________________

Gen. Identifier: ___________ Gen. Manufacturer: __________________ Yr. Mfd.: _________

Stator Winding Manufacturer: ____________________ Yr. Winding Installed: _____________

Stator Insulation Type: ________________ MVA: _______ PF: ______ Voltage: ___________

Field Winding Manufacturer: _____________________ Yr. Winding Installed: _____________

Field Insulation Type: __________________ Current: _____________ Voltage: ____________

Part A: Calculate the Tier 2 Stator Condition Index

Tier 2 Stator Condition Summary

Adjustment to Tier 1 No. Tier 2 Test Stator Condition Index

T2.S1 Ramped Voltage Test T2.S2 Partial Discharge Measurements T2.S3 Dissipation Factor Measurements T2.S4 Ozone Monitoring T2.S5 Black Out Test T2.S6 High-Potential Withstand Test T2.S7 Stator Core Inspection T2.S8 Wedge Tightness Evaluation T2.S9 Core Loop Test T2.S10 EL CID Test T2.S11 Other Specialized Diagnostic Tests

Tier 2 Adjustments to Stator Condition Index

(Sum of individual Adjustments)

Tier 2 Stator Data Quality Indicator

(Value must be 0, 4, 7, or 10)

To calculate the Net Stator Condition Index (Value should be between 0 and 10), subtract the Tier 2 Adjustments from the Tier 1 Stator Condition Index: Tier 1 Stator Condition Index __________ minus Tier 2 Stator Adjustments __________ = ________________ Net Stator Condition Index

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Part B: Calculate the Tier 2 Rotor Condition Index

Tier 2 Rotor Condition Summary

Adjustment to Tier 1 No. Tier 2 Test Rotor Condition Index

T2.R1 High-Potential Withstand Test

T2.R2 AC Pole Drop Test

T2.R3 Field Winding AC Impedance

T2.R4 Other Specialized Diagnostic Tests

Tier 2 Adjustments to Rotor Condition Index (Sum of individual Adjustments)

Tier 2 Rotor Data Quality Indicator

(Value must be 0, 4, 7, or 10)

To calculate the Net Rotor Condition Index (Value should be between 0 and 10), subtract the Tier 2 Adjustments from the Tier 1 Rotor Condition Index: Tier 1 Rotor Condition Index __________ minus Tier 2 Rotor Adjustments __________ = ________________ Net Rotor Condition Index

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Part C: Determine the Tier 2 Generator (Stator and Rotor) Condition Index To determine the Net Generator (Stator and Rotor) Condition Index (Value should be between 0 and 10), choose the lower of the Net Stator Condition Index and the Net Rotor Condition Index. Record the Data Quality Indicator associated with the chosen Condition Index: Net Generator Condition Index _____________

Data Quality Indicator ______________

Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________

(Attach supporting documentation.)

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EXAMPLE

GENERATOR TIER 1 CONDITION ASSESSMENT SUMMARY

Date: 6-25-03 Location: Yellowtail Powerplant

Gen. Identifier: Unit Gen. Manufacturer: Westinghouse Yr. Mfd.: 1965

Stator Winding Manufacturer: National Electric Coil Yr. Winding Installed: 1983

Stator Insulation Type: Epoxilated Resin MVA: 65,789 kVA Voltage: 13.8 kV

Part A: Calculate the Tier 1 Stator Condition Index

Tier 1 Generator Stator Condition Summary (For instructions on indicator scoring, please refer to condition assessment guide)

No. Condition Indicator Score × Weighting Factor = Total Score

1 O & M History (Score must be 0, 1, 2, or 3) 2 1.18 2.36

2 Physical Inspection (Score must be 0, 1, 2, or 3) 3 1.18 3.54

3 Insulation Resistance and Polarization Index (Score must be 0, 1, 2, or 3)

2 0.58 1.16

4 Winding Age (Score must be 0, 1, 2, or 3) 2 0.39 0.78

Tier 1 Stator Condition Index (Sum of individual Total Scores)

(Condition Index should be between 0 and 10) 7.84

Tier 1 Stator Data Quality Indicator

(Value must be 0, 4, 7, or 10) 7

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Part B: Calculate the Tier 1 Rotor Condition Index

Tier 1 Generator Rotor Condition Summary (For instructions on indicator scoring, please refer to condition assessment guide)

No. Condition Indicator Score × Weighting Factor = Total Score

1 O & M History (Score must be 0, 1, 2, or 3) 3 1.18 3.54

2 Physical Inspection (Score must be 0, 1, 2, or 3) 3 1.18 3.54

3 Insulation Resistance and Polarization Index (Score must be 0, 1, 2, or 3)

3 0.58 1.74

4 Winding Age (Score must be 0, 1, 2, or 3) 3 0.39 1.17

Tier 1 Rotor Condition Index (Sum of individual Total Scores)

(Condition Index should be between 0 and 10) 10.00

Tier 1 Rotor Data Quality Indicator

(Value must be 0, 4, 7, or 10) 4

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Part C: Determine the Tier 1 Generator (Stator and Rotor) Condition Index To determine the Tier 1 Generator (Stator and Rotor) Condition Index (Value should be between 0 and 10), choose the lower of the Tier 1 Stator Condition Index and the Tier 1 Rotor Condition Index. Record the Data Quality Indicator associated with the chosen Condition Index: Generator Condition Index _____7.84__________

Data Quality Indicator ______7 __________

Evaluator: Armand Bird, Acting Electrical Foreman_ Technical Review: Tom Manni_________ Management Review: _________________ Copies to: _________________________________

(Attach supporting documentation.)

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Supporting Documentation

Date: 6-25-03 Location: Yellowtail Powerplant

Gen. Identifier: Unit Gen. Manufacturer: Westinghouse Yr. Mfd.: 1965

Stator Winding Manufacturer: National Electric Coil Yr. Winding Installed: 1983

Stator Insulation Type: Epoxilated Resin MVA: 65,789 kVA Voltage: 13.8 kV

Unit 1 Stator was given a rating of 2 on O & M History for the following reasons: Yellowtail is a remotely-controlled peaking plant with frequent use of AGC, thus resulting in fast ramp rates, frequent rough zone crossings, and abnormally high numbers of starts and stops. Records of quadrennial ramp tests indicate “snaking” which has been associated with possible delamination of the strands in the winding. The most recent ramp tests are acceptable and show no increasing signs of deterioration. Coupling capacitors have been installed to monitor partial discharge, but results have been questioned on their value. Insulation resistance or polarization index testing is not performed at Yellowtail, but D. C. Ramp testing is performed on a quadrennial schedule. The results of this test have indicated that no substantial increase in leakage is occurring. The resulting score of 2 is because the testing was not performed, but no abnormal results would be anticipated. Winding age was rated at 2 because the winding is on the border line between 20 and 30 years. Also, with the rapid ramp rates and abnormal starts and stops the winding is being subjected to thermal stresses undetectable by inspection or test.

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September 2006 Hydro Plant Risk Assessment Guide Appendix E2: Circuit Breaker Condition Assessment E2.1 GENERAL Circuit breakers are key components in the power train at hydroelectric powerplants and are appropriate for analysis under a condition assessment program. Circuit breaker failures can have a significant economic impact due to the high costs of equipment replacement and lost power generation during an extended repair outage. Determining the present condition of a circuit breaker is an essential step in analyzing the risk of failure. This appendix provides a process for arriving at a Circuit Breaker Condition Index which may be used to develop a business case addressing risk of failure, economic consequences, and other factors. E2.2 SCOPE / APPLICATION Circuit breakers are obtained from a variety of manufacturers, and there is a large variety of designs. Breaker specifications apply only to the particular circuit breaker being evaluated, and are not necessarily applicable to those produced by other manufacturers. Even within a single manufacturer, different models may not have the same design or specifications. Therefore, it is necessary to refer to the manufacturer’s specifications for each circuit breaker that is to be assessed. The breaker condition assessment methodology outlined in this appendix applies to metal-clad, station class, and freestanding circuit breakers. Breakers in these classes can be any of a variety of types of interrupters including air magnetic, air blast, bulk oil, SF6 gas (dual pressure and puffer), and vacuum. Due to design differences in the breakers, the inspections, tests, and measurements described in this appendix have varying applicability to the different types of breakers. The appropriate inspections, tests, and measurements for each type of breaker are described in section E2.10 below. This appendix is not intended to define circuit breaker maintenance practices or describe in detail circuit breaker condition assessment inspections, tests, or measurements. Utility maintenance policies and procedures, as well as manufacturer’s recommendations must be consulted for such information.

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E2.3 CONDITION AND DATA QUALITY INDICATORS AND CIRCUIT BREAKER CONDITION INDEX

This appendix describes four condition indicators generally regarded as a sound basis for assessing circuit breaker condition:

• Dielectric Condition • Operation and Maintenance History • Contact Resistance • Number of Operations

These condition indicators are initially evaluated using Tier 1 inspections, tests, and measurements, which are conducted by utility staff or contractors over the course of time and as a part of routine maintenance activities. Numerical scores are assigned to each condition indicator, which are then weighted and summed to determine the Circuit Breaker Condition Index. Only Operation and Maintenance History is used for assessing the condition of vacuum circuit breakers. This is explained further in the vacuum breaker section. An additional stand-alone indicator is used to reflect the quality of the information available for scoring the circuit breaker indicators. In some cases, data may be missing, out-of-date, or of questionable integrity. Any of these situations could affect the accuracy of the associated condition indicator scores, as well as the validity of the overall Condition Index. Given the potential impact of poor or missing data, the Data Quality Indicator is used as a means of evaluating and recording confidence in the final Circuit Breaker Condition Index. Additional information regarding circuit breaker condition may be necessary to improve the accuracy and reliability of the Circuit Breaker Condition Index. Therefore, in addition to the Tier 1 condition indicators, this appendix describes a “toolbox” of Tier 2 inspections, tests, and measurements that may be applied, depending on the specific issue or problem being addressed. Tier 2 tests are considered non-routine. However, if Tier 2 data is readily available, it may be used to supplement the Tier 1 assessment. Alternatively, Tier 2 tests may be deliberately performed to address Tier 1 findings. Results of the Tier 2 analysis may either increase or decrease the score of the Circuit Breaker Condition Index. The Data Quality Indicator score may also be revised during the Tier 2 assessment to reflect the availability of additional information or test data. The Circuit Breaker Condition Index may indicate the need for immediate corrective actions and/or follow-up Tier 2 testing. After review by qualified personnel, the Circuit Breaker Condition Index is suitable for use as input to a risk-based economic analysis. Note: A severely negative result of ANY inspection, test, or measurement may be adequate in itself to require immediate corrective action, regardless of the Circuit Breaker Condition Index score.

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E2.4 INSPECTIONS, TESTING, AND MEASUREMENTS Inspections, tests, and measurements should be conducted and analyzed by staff suitably trained and experienced in circuit breaker operation and maintenance. Inspections, tests, and measurements should be conducted on a frequency that provides the accurate and current information needed by the assessment. Circuit breaker condition assessment may cause concern that justifies more frequent monitoring, in which case utilities should consider the possibility of making more frequent inspections. This will provide additional data for condition assessment and establish a certain amount of reassurance as circuit breaker repair or replacement alternatives are being investigated. E2.5 SCORING Condition indicator scoring is somewhat subjective, relying on personnel experienced in assessing circuit breaker conditions. Relative terms such as “Results Normal” and “Deterioration” refer to results that are compared to industry accepted levels; or to baseline or previously acceptable levels on this equipment; or to equipment of similar design, construction, or age operating in a similar environment. E2.6 WEIGHTING FACTORS Weighting factors used in the condition assessment methodology recognize that some condition indicators affect the Circuit Breaker Condition Index to a greater or lesser degree than other indicators. These weighting factors were arrived at by consensus among circuit breaker design and maintenance personnel with extensive experience. E2.7 MITIGATING FACTORS Every circuit breaker is unique and, therefore, the methodology described in this appendix cannot quantify all factors that affect individual circuit breaker condition. It is important that the Circuit Breaker Condition Index arrived at be reviewed by engineering experts. Mitigating factors specific to the utility may determine the final Circuit Breaker Condition Index and the final decision on circuit breaker replacement or rehabilitation. E2.8 DOCUMENTATION Substantiating documentation is essential to support findings of the assessment, particularly where a Tier 1 condition indicator score is less than 3 or where a Tier 2 test results in subtractions to the Circuit Breaker Condition Index. Test results and reports, photographs, O & M records, or other documentation should accompany the Circuit Breaker Condition Assessment Summary form.

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E2.9 CONDITION ASSESSMENT METHODOLOGY The condition assessment methodology consists of analyzing each condition indicator individually to arrive at a condition indicator score; then the score is weighted and summed with scores from other condition indicators. The sum is the Circuit Breaker Condition Index. Reasonable efforts should be made to perform Tier 1 inspections, tests, and measurements. However, when data is missing to properly score the condition indicator, it may be assumed that the score is “Good” or numerically some mid-range number such as 2. This strategy must be used judiciously to prevent erroneous results and conclusions. In recognition of the potential impact of poor or missing data, a separate Data Quality Indicator is rated as a means of evaluating and recording confidence in the final Circuit Breaker Condition Index. E2.10 TIER 1 – INSPECTIONS, TESTS, AND MEASUREMENTS Tier 1 tests include inspections, tests, and measurements routinely accomplished as part of normal operation and maintenance, or are readily discernible by examination of existing data. Tier 1 results are quantified below as condition indicators that are weighted and summed to arrive at a Circuit Breaker Condition Index. Tier 1 inspections, tests, and measurements may indicate abnormal conditions that can be resolved with standard corrective maintenance solutions. The results from Tier 1 inspections, tests, and measurements may also indicate the need for additional investigation, categorized as Tier 2 inspections, tests, and measurements. Note: There are four different sub-sections below, each of which is written for a particular type of circuit breaker (air magnetic / air blast, oil tank, SF6, and vacuum). Use the sub-section describing the Tier 1 tests that are appropriate for the type of circuit breaker being evaluated. E2.10.a. Air Magnetic/Air Blast Circuit Breakers Air Magnetic breakers are air insulated, spring operated, and use magnetically contoured arc chutes to elongate and cool the arc. They are often installed in metal clad switchgear and can be removed entirely for maintenance. The dielectric condition of the breaker can be measured and trended by performing megger and power factor tests on the fully assembled breaker including the arc chutes. The main and arcing contacts should be inspected for signs of wear including pitting, scoring, or overheating and burning. It is normal to show more wear on the arcing contacts than the main contacts. All components of the operating mechanism should be checked for loose or broken parts, missing retainers or other hardware, excessive wear on moving parts, and for binding during movement. The fully assembled circuit breaker should be tested to determine breaker operation and timing is within original manufacturer tolerances. Air Blast breakers are air insulated and use high pressure air to operate the breaker and to elongate and cool the arc. They are often installed in station class switchgear and cannot be removed entirely for maintenance. The dielectric condition of the breaker can be measured and trended by performing megger and power factor tests on the fully assembled breaker including the arc chutes. The main and arcing contacts should be inspected for signs of wear including pitting, scoring, or overheating and burning. It is normal to show more wear on the arcing contacts than the main contacts. All components of the operating mechanism should be checked

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for loose or broken parts, missing retainers or other hardware, excessive wear on moving parts, and for binding during movement. The compressed air system and control valves should be checked for proper operation, including compressor run times and start/stop controls. The complete circuit breaker should be tested to confirm correct breaker operation and that timing is within original manufacturer tolerances. Air Magnetic/Air Blast Circuit Breaker Condition Indicator 1 – Dielectric Tests Power Factor testing of air magnetic or air blast breakers can evaluate the overall dielectric condition of the breaker including bushings, arc chutes, operating rods, etc. The results of these tests are analyzed and applied to Table 1 to arrive at a Condition Indicator Score.

Table 1 – Air Magnetic/Air Blast Dielectric Test Scoring

Results Condition Indicator Score Test results are normal. (Good - G)* 3 Test results show minor deterioration. (Deteriorated - D)* 2 Test results show significant deterioration. (Investigate - I)* 1 Test results show severe deterioration. (Bad - B)* 0

(May indicate serious problem requiring immediate evaluation, additional testing, consultation with experts, and remediation

prior to re-energization.)

* Doble insulation rating shown in parentheses. Air Magnetic/Air Blast Circuit Breaker Condition Indicator 2 – Operation and Maintenance History Operation and maintenance (O & M) history may indicate overall circuit breaker condition. O & M history factors that may apply are:

• Difficult or expensive to bring mechanism into compliance for timing and travel. Timing and travel measurements are taken with the circuit breaker removed from service. It is expected that a circuit breaker will not be returned to service until it has been adjusted or repaired to result in satisfactory timing and travel measurements. If these adjustments or repairs are frequent or expensive, they may indicate that the mechanism is worn out or not well designed.

• High number of fault current operations. If the data is available, the fault currents and durations can be used to estimate the interrupting duty the breaker has seen. In general, as the energy level of the interrupted fault increases, the stress on the breaker increases.

• Numerous forced outages or outage extensions to correct problems.

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• Excessive or frequent corrective maintenance. • Difficulty in obtaining or very high cost of spare or replacement parts

Qualified personnel should make a subjective determination of scoring that encompasses as many O & M factors as possible under this Indicator. Results are analyzed and applied to Table 2 to arrive at a Condition Indicator Score.

Table 2 – Air Magnetic/Air Blast Circuit Breaker O & M History Scoring

Results Condition Indicator Score

Operation and Maintenance are normal. 3

Some abnormal operating conditions experienced and/or additional maintenance above normal occurring. 2

Significant operation outside normal and/or significant additional maintenance is required; or forced outage occurs; or outages are regularly extended due to maintenance problems; or similar units are problematic.

1

Repeated forced outages; maintenance not cost effective; or severe mechanical problems; or similar units have failed. 0

Air Magnetic/Air Blast Circuit Breaker Condition Indicator 3 – Contact Resistance Tests Performing a contact resistance test on the breaker in the closed position can detect abnormal conditions that could result in overheating of the breaker contacts. The test can be performed using a Digital Low-Resistance Ohmmeter (DLRO). The DLRO forces large currents (50-100 A or more) through the contacts and precisely measures the voltage drop across the breaker. The test is also referred to as a millivolt drop test. Apply the test results to Table 3 to arrive at a Condition Indicator Score.

Table 3 – Air Magnetic/Air Blast Contact Resistance Test Scoring

Results Condition Indicator Score < 25 percent increase since last test AND below manufacturer recommended maximum resistance. 3

≥ 25 and < 75 percent increase since last test AND below manufacturer recommended maximum resistance. 2

≥ 75 percent increase since last test OR above manufacturer recommended maximum resistance.

1 (May indicate serious problem

requiring immediate evaluation, additional testing, consultation with experts, and remediation

prior to re-energization.)

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Air Magnetic/Air Blast Circuit Breaker Condition Indicator 4 – Number of Operations The number of operations that a breaker has been subject to is a measure of the used life of a breaker. Consideration should be given to treating the counter as “reset to zero” following a complete breaker overhaul or refurbishment. Records are analyzed and applied to Table 4 to arrive at a Condition Indicator Score.

Table 4 – Air Magnetic/Air Blast Operations Scoring

Results Condition Indicator Score

< 1,000 normal operations 3

≥ 1,000 and < 3,000 normal operations 2

≥ 3,000 and < 5,000 normal operations 1

≥ 5,000 normal operations 0 E2.10.b Oil Tank Circuit Breakers Oil tank circuit breakers have their contacts submersed in oil within a tank. They are normally freestanding. The operating mechanism is located outside the tank and is transmitted to the moving contacts through operating rods. There are several tests that can be performed on the insulating oil in the breaker including dielectric breakdown, water content, power factor, color, and interfacial tension. These tests can indicate when it is necessary to recondition the breaker oil. Since the normal operation of the breaker will degrade the oil and bulk tank oil breakers are directly vented to the atmosphere, poor test results do not necessarily indicate a problem with the breaker itself. Therefore, these tests are not included in the condition assessment for oil breakers. The dielectric condition of the breaker can be measured and trended by performing megger and power factor tests on the fully assembled breaker. The bushings themselves can also be power factor tested. The current carrying contacts of an oil breaker are not accessible during routine maintenance. Contact engagement may be discernible by measuring the travel of the operating mechanism (lift rod). All components of the operating mechanism should be checked for loose or broken parts, missing retainers or other hardware, excessive wear on moving parts, and for binding during movement. The complete circuit breaker should be tested to confirm correct breaker operation and that timing is within original manufacturer tolerances. Oil Tank Circuit Breaker Condition Indicator 1 – Dielectric Tests Power factor testing of the breaker can evaluate the overall dielectric condition of the breaker including bushings and interrupting grids. Low bushing power factors should not result in a lowered condition indicator for the entire breaker (since the bushing itself can be replaced).

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The results of these tests are analyzed and applied to Table 5 to arrive at a Condition Indicator Score.

Table 5 – Oil Tank Dielectric Test Scoring

Results Condition Indicator Score

Test results are normal. (Good – G)* 3

Test results show minor deterioration. (Deteriorated – D)* 2

Test results show significant deterioration. (Investigate – I)* 1

Test results show severe deterioration. (Bad – B)* 0 (May indicate serious problem

requiring immediate evaluation, additional testing, consultation with experts, and remediation

prior to re-energization.)

* Doble insulation rating shown in parentheses. Oil Tank Circuit Breaker Condition Indicator 2 – Operation and Maintenance History Operation and maintenance (O & M) history may indicate overall circuit breaker condition. O & M history factors that may apply are:

• Difficult or expensive to bring mechanism into compliance for timing and travel. Timing and travel measurements are taken with the circuit breaker removed from service. It is expected that a circuit breaker will not be returned to service until it has been adjusted or repaired to result in satisfactory timing and travel measurements. If these adjustments or repairs are frequent or expensive, they may indicate that the mechanism is worn out or not well designed.

• High number of fault current operations. If the data is available, the fault currents and durations can be used to estimate the interrupting duty the breaker has seen. In general, as the energy level of the interrupted fault increases, the stress on the breaker increases.

• Numerous forced outages or outage extensions to correct problems. • Excessive or frequent corrective maintenance. • Difficulty in obtaining or very high cost of spare or replacement parts.

Qualified personnel should make a subjective determination of scoring that encompasses as many operation and maintenance factors as possible under this Indicator. Results are analyzed and applied to Table 6 to arrive at a Condition Indicator Score.

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Table 6 – Oil Tank O & M History Scoring

Results Condition Indicator Score

Operation and Maintenance are normal. 3

Some abnormal operating conditions experienced and/or additional maintenance above normal occurring. 2

Significant operation outside normal and/or significant additional maintenance is required; or forced outage occurs; or outages are regularly extended due to maintenance problems; or similar units are problematic.

1

Repeated forced outages; maintenance not cost effective; or severe mechanical problems; or similar units have failed. 0

Oil Tank Circuit Breaker Condition Indicator 3 – Contact Resistance Tests Performing a contact resistance test on the breaker in the closed position can detect abnormal conditions that could result in overheating of the breaker contacts. The test can be performed using a Digital Low-Resistance Ohmmeter. The DLRO forces large currents (50-100 A or more) through the contacts and precisely measures the voltage drop across the breaker. The test is also referred to as a millivolt drop test. Apply the test results to Table 7 to arrive at a Condition Indicator Score.

Table 7 – Oil Tank Contact Resistance Test Scoring

Results Condition Indicator Score < 25 percent increase since last test AND below manufacturer recommended maximum resistance. 3

≥ 25 and < 75 percent increase since last test AND below manufacturer recommended maximum resistance. 2

≥ 75 percent increase since last test OR above manufacturer recommended maximum resistance.

1 (May indicate serious problem

requiring immediate evaluation, additional testing, consultation with experts, and remediation

prior to re-energization.) Oil Tank Circuit Breaker Condition Indicator 4 – Number of Operations The number of operations that a breaker has been subject to is a measure of the used life of a breaker. Consideration should be given to treating the counter as “reset to zero” following a complete breaker overhaul or refurbishment. Records are analyzed and applied to Table 8 to arrive at a Condition Indicator Score.

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Table 8 – Oil Tank Operations Scoring

Results Condition Indicator Score

< 250 normal operations 3

≥ 250 and < 750 normal operations 2

≥ 750 and < 1,500 normal operations 1

≥ 1,500 normal operations 0 E2.10.c SF6 Circuit Breakers SF6 breakers utilize sulfur hexaflouride gas to both insulate the current carrying parts and to aid in interrupting the arc. SF6 breakers can be installed in metal clad or station class switchgear as well as being freestanding. The dielectric condition of the breaker can be measured and trended by performing megger and power factor tests on the fully assembled breaker. The current carrying contacts of an SF6 breaker are not accessible during routine maintenance. Contact engagement may be discernible by measuring the travel of the operating mechanism. All components of the operating mechanism should be checked for loose or broken parts, missing retainers or other hardware, excessive wear on moving parts, and for binding during movement. The complete circuit breaker should be tested to confirm correct breaker operation and that timing is within original manufacturer tolerances. SF6 Circuit Breaker Condition Indicator 1 – Dielectric Tests Power factor testing of the breaker can evaluate the overall dielectric condition of the breaker including bushings. The results of these tests are analyzed and applied to Table 9 to arrive at a Condition Indicator Score.

Table 9 – SF6 Dielectric Test Scoring

Results Condition Indicator Score Test results are normal. (Good – G)* 3

Test results show minor deterioration. (Deteriorated – D)* 2

Test results show significant deterioration. (Investigate – I)* 1 Test results show severe deterioration. (Bad – B)* 0

(May indicate serious problem requiring immediate evaluation, additional testing, consultation with experts, and remediation

prior to re-energization.)

* Doble insulation rating shown in parentheses.

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SF6 Circuit Breaker Condition Indicator 2 – Operation and Maintenance History Operation and maintenance (O & M) history may indicate overall circuit breaker condition. O & M history factors that may apply are:

• Difficult or expensive to bring mechanism into compliance for timing and travel. Timing and travel measurements are taken with the circuit breaker removed from service. It is expected that a circuit breaker will not be returned to service until it has been adjusted or repaired to result in satisfactory timing and travel measurements. If these adjustments or repairs are frequent or expensive, they may indicate that the mechanism is worn out or not well designed.

• High number of fault current operations. If the data is available, the fault currents and durations can be used to estimate the interrupting duty the breaker has seen. In general, as the energy level of the interrupted fault increases, the stress on the breaker increases.

• Numerous forced outages or outage extensions to correct problems. • Excessive or frequent corrective maintenance. • Difficulty in obtaining or very high cost of spare or replacement parts.

Qualified personnel should make a subjective determination of scoring that encompasses as many operation and maintenance factors as possible under this Indicator. Results are analyzed and applied to Table 10 to arrive at a Condition Indicator Score.

Table 10 – SF6 O & M History Scoring

Results Condition Indicator Score

Operation and Maintenance are normal. 3

Some abnormal operating conditions experienced and/or additional maintenance above normal occurring.

2

Significant operation outside normal and/or significant additional maintenance is required; or forced outage occurs; or outages are regularly extended due to maintenance problems; or similar units are problematic.

1

Repeated forced outages; maintenance not cost effective; or severe mechanical problems; or similar units have failed.

0

SF6 Circuit Breaker Condition Indicator 3 – Contact Resistance Tests Performing a contact resistance test on the breaker in the closed position can detect abnormal conditions that could result in overheating of the breaker contacts. The test can be performed using a Digital Low-Resistance Ohmmeter (DLRO). The DLRO forces large currents (50-100 A or more) through the contacts and precisely measures the voltage drop across the breaker. The test is also referred to as a millivolt drop test. Apply the test results to Table 11 to arrive at a Condition Indicator Score.

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Table 11 – SF6 Contact Resistance Tests Scoring

Results Condition Indicator Score < 25 percent increase since last test AND below manufacturer recommended maximum resistance. 3

≥ 25 and < 75 percent increase since last test AND below manufacturer recommended maximum resistance. 2

≥ 75 percent increase since last test OR above manufacturer recommended maximum resistance.

1 (May indicate serious problem

requiring immediate evaluation, additional testing, consultation with experts, and remediation

prior to re-energization.) SF6 Circuit Breaker Condition Indicator 4 – Number of Operations The number of operations that a breaker has been subject to is a measure of the used life of a breaker. Consideration should be given to treating the counter as “reset to zero” following a complete breaker overhaul or refurbishment. Records are analyzed and applied to Table 12 to arrive at a Condition Indicator Score.

Table 12 – SF6 Operations Scoring

Results Condition Indicator Score

< 2,000 normal operations 3

≥ 2,000 and < 5,000 normal operations 2

≥ 5,000 and < 8,000 normal operations 1

≥ 8,000 normal operations 0 E2.10.d Vacuum Circuit Breakers Vacuum circuit breakers utilize a pair of main contacts encapsulated in a sealed vacuum bottle. The actual contact separation is very small as there is no medium that the arc would ionize to sustain itself after the contacts open. The dielectric condition of the breaker can be measured and trended by performing power factor tests on the fully assembled breaker. The current carrying contacts of a vacuum breaker are not accessible. The operating rod for the moving contact is scribed with a mark whose position with the contacts closed can be noted and compared to a reference mark. If the scribe mark and the reference mark are in alignment, the contacts have worn to the point of needing to be replaced. All components of the operating mechanism should be checked for loose or broken parts, missing retainers or other hardware, excessive wear on moving parts, and for binding during movement. The complete circuit breaker should be tested to confirm correct breaker operation and that timing is within original

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manufacturer tolerances. The vacuum level in the bottle can be checked by performing a hi-pot test on the bottle per the manufacturer’s instructions. There can be no partial vacuum loss so this is a go /no-go type of test. Vacuum circuit breakers have fewer components and lower operating forces than other types of breakers. When routine O & M testing indicates problems with vacuum breakers, the repair is very often to replace the suspect component. This includes almost all parts of the breaker including the vacuum bottle itself. Since the vast majority of detected problems with a vacuum breaker result in replacing the faulty component, the breaker is rarely returned to service in less than like new condition. Some of the Tier 1 tests performed for other types of breakers do not provide meaningful results for vacuum breakers. Dielectric test results, contact resistance, or the number of operations are not useful in determining whether the breaker is a good candidate for upgrade or replacement. For these reasons, the only condition indicator used for vacuum breakers is O & M History. Vacuum Circuit Breaker Condition Indicator 1 – Operation and Maintenance History Operation and maintenance (O & M) history may indicate overall circuit breaker condition. O & M history factors that may apply are:

• Difficult or expensive to bring mechanism into compliance for timing and travel. Timing and travel measurements are taken with the circuit breaker removed from service. It is expected that a circuit breaker will not be returned to service until it has been adjusted or repaired to result in satisfactory timing and travel measurements. If these adjustments or repairs are frequent or expensive, they may indicate that the mechanism is worn out or not well designed.

• High number of fault current operations. If the data is available, the fault currents and durations can be used to estimate the interrupting duty the breaker has seen. In general, as the energy level of the interrupted fault increases, the stress on the breaker increases.

• Numerous forced outages or outage extensions to correct problems. • Excessive or frequent corrective maintenance. • Difficulty in obtaining or very high cost of spare or replacement parts.

Qualified personnel should make a subjective determination of scoring that encompasses as many operation and maintenance factors as possible under this indicator. Results are analyzed and applied to Table 13 to arrive at a Condition Indicator Score.

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Table 13 – Vacuum O & M History Scoring

Results Condition Indicator Score

Operation and Maintenance are normal. 3

Some abnormal operating conditions experienced and/or additional maintenance above normal occurring. 2

Significant operation outside normal and/or significant additional maintenance is required; or forced outage occurs; or outages are regularly extended due to maintenance problems; or similar units are problematic.

1

Repeated forced outages; maintenance not cost effective; or severe mechanical problems; or similar units have failed. 0

E2.11 TIER 1 – CIRCUIT BREAKER CONDITION INDEX CALCULATIONS Enter the Circuit Breaker Condition Indicator scores from the tables above into the Circuit Breaker Condition Assessment Summary form at the end of this appendix. Multiply each condition indicator score by the Weighting Factor, and sum the Total Scores to arrive at the Tier 1 Circuit Breaker Condition Index. Attach supporting documentation. This index may be adjusted by the Tier 2 circuit breaker inspections, tests, and measurements described later in this document. E2.12 TIER 1 – CIRCUIT BREAKER DATA QUALITY INDICATOR The Circuit Breaker Data Quality Indicator reflects the quality of the inspection, test and measurement results used to evaluate the circuit breaker condition under Tier 1, as well as the age of the comparison between short circuit study results and the breaker interrupting rating. The more current and complete the results are, the higher the rating for this indicator. The normal testing frequency is defined as the organization’s recommended frequency for performing the specific test or inspection. Records are analyzed and applied to Table 14 to arrive at a Circuit Breaker Data Quality Indicator Score.

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Table 14 – Circuit Breaker Data Quality Scoring

Results Data Quality Indicator Score All Tier 1 inspections, tests and measurements were completed within the normal testing frequency and the results are reliable

AND comparison of breaker interrupting rating with short circuit study results was performed within the last < 5 years.

10

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 6 and < 24 months past the normal testing frequency and results are reliable

OR comparison of breaker interrupting rating with short circuit study results was performed ≥ 5 and < 10 years ago.

7

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 24 and < 36 months past the normal testing frequency, or some of the results are not available or are of questionable integrity

OR comparison of breaker interrupting rating with short circuit study results was performed ≥ 10 and < 15 years ago.

4

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 36 months past the normal frequency, or no results are available or many are of questionable integrity

OR comparison of breaker interrupting rating with short circuit study results was performed ≥ 15 years ago.

0

Enter the Circuit Breaker Data Quality Indicator Score from Table 14 into the Circuit Breaker Condition Assessment Summary form at the end of this document.

E2-16

E2.13 TIER 2 – INSPECTIONS, TESTS, AND MEASUREMENTS Tier 2 inspections, tests, and measurements generally require specialized equipment or training, may be intrusive, or may require an extended outage to perform. Tier 2 assessment is considered non-routine. Tier 2 inspections are intended to affect the Circuit Breaker Condition Index number established using Tier 1 but also may confirm or refute the need for more extensive maintenance, rehabilitation, or circuit breaker replacement. For circuit breakers, there are only two Tier 2 tests: interrupter inspection and a comparison of available short circuit current with the breaker’s interrupting rating. The comparison of the available short circuit currents and the breaker’s interrupting rating requires expert analyses and up-to-date short circuit studies. Because of the importance of the results of the comparison, the adjustment to the Circuit Breaker Condition Index for poor comparison results is significant. For Tier 2 assessments performed, apply only the appropriate adjustment factors per the instructions above and recalculate the Circuit Breaker Condition Index using the Circuit Breaker Condition Assessment Summary form at the end of this document. An adjustment to the Data Quality Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment. Test T2.1: Interrupter Inspection Performing an inspection of a breaker’s interrupter requires a significant outage of the breaker. The decision to perform an interrupter inspection would most likely be based on finding problems with the breaker’s timing and travel adjustments or with excessive contact resistance. An interrupter inspection would include disassembly of the breaker and inspection of all moving and stationary internal components. Results are analyzed and applied to Table 15 to arrive at a Condition Indicator Score.

Table 15 – Interrupter Inspection Scoring

Adjustment to Circuit Breaker Results Condition Indicator Score

Interrupter component wear and condition is normal. No Change

Interrupter components show signs of considerable wear, but components remain serviceable. Subtract 2.0

One or more interrupter components show excessive wear, with minimal life remaining. Subtract 4.0

One or more interrupter components show excessive wear or damage with questionable remaining life.

Subtract 6.0 (May indicate serious problem

requiring immediate consultation with experts, and remediation

prior to re-energization.)

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A circuit breaker cannot be safely returned to service with unresolved deficiencies in the internal mechanisms that affect the breaker’s performance. If the problems found can be repaired, the breaker should be repaired and the appropriate Tier I tests repeated. It may be appropriate to lower the O & M History indicator score based on the findings of the interrupter inspection and repair. Test T2.2: Circuit Breaker Ratings vs. Available System Fault Current Circuit breakers are chosen such that interrupting current ratings exceed the maximum available fault current, considering contributions from the generator and the connected system (which may include other generators on the same medium voltage bus). There is also an allowance provided for the system fault contribution to grow with time included in the calculations. Operating a circuit breaker under conditions exceeding the ratings of the breaker can result in failure of the breaker and considerable incidental damage to adjacent equipment and even to the generator itself. It is prudent to periodically review the adequacy of the circuit breaker’s ratings compared with the system growth in the area of the breaker. Therefore, the first step in assessing the condition of a circuit breaker should be comparing the interrupting current rating of the breaker with the present and projected system fault current that the breaker must be capable of interrupting. This will require an up-to-date system fault study in the area of the circuit breaker to provide the new and projected system contributions. Circuit breaker experts should be consulted when comparing the breaker ratings with the projected system fault currents. The first rating standards applicable to circuit breakers, developed in the 1940s and 1950s, were based on the highest current to be interrupted, including both the ac symmetrical current and the dc component at the instant of contact separation. This basis for the rating is referred to as “total current” rating. The method of rating circuit breakers was gradually changed (in the late 1960s and 1970s) to include only the ac symmetrical current at the point of contact separation. The “total current” standards were rescinded in 1986. The new basis is referred to as “symmetrical current” rating. Breakers rated using the old standards cannot be directly compared to breakers rated under the new standards. Note: If the fault currents that the breaker may be called on to interrupt exceed the rating of the breaker, steps must be taken to reduce the fault current to which the breaker is exposed and/or plans should be initiated to upgrade or replace the breaker. Current interrupting test rating results are analyzed and applied to Table 16 to arrive at a Circuit Breaker Condition Index score adjustment.

E2-18

Table 16 – Tier 2 Current Interrupting Rating Scoring

Adjustment to Circuit Breaker Test Results Condition Index Score Ratio of circuit breaker interrupting rating to available system fault current ≥ 1.1 No Change

Ratio of circuit breaker interrupting rating to available system fault current ≥ 0.9 and < 1.1

Subtract 3.0

Ratio of circuit breaker interrupting rating to available system fault current < 0.9

Subtract 6.0

Test T2.3: Other Specialized Diagnostic Tests Additional tests may be applied to evaluate specific circuit breaker problems. Some of these diagnostic tests may be considered to be of an investigative research nature. When conclusive results from other diagnostic tests are available, they may be used to make an appropriate adjustment to the Circuit Breaker Condition Index. E2.14 CIRCUIT BREAKER CONDITION INDEX CALCULATIONS Enter the Tier 2 adjustments from the tables above into the Circuit Breaker Condition Assessment Summary form at the end of this document. Subtract the sum of these adjustments from the Tier 1 Circuit Breaker Condition Index to arrive at the Net Circuit Breaker Condition Index. Attach supporting documentation. An adjustment to the Data Quality Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment. E2.15 CIRCUIT BREAKER CONDITION-BASED ALTERNATIVES After review by qualified personnel, the Circuit Breaker Condition Index – either modified by Tier 2 tests or not – may be sufficient for decision making regarding circuit breaker alternatives. The Index is also suitable for use in a risk-and-economic analysis model. Where it is desired to consider alternatives based solely on circuit breaker condition, the Circuit Breaker Condition Index may be directly applied to Table 17.

E2-19

Table 17 – Circuit Breaker Condition-Based Alternatives

Circuit Breaker Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat condition assessment as needed.

≥ 3.0 and < 7 (Fair) Continue operation but reevaluate O & M practices. Consider using appropriate Tier 2 tests. Repeat condition assessment process as needed.

≥ 0 and < 3.0 (Poor) Immediate evaluation including additional Tier 2 testing. Consultation with experts. Adjust O & M as prudent. Begin replacement/rehabilitation process.

E2.16 EXAMPLE CIRCUIT BREAKER CONDITION ASSESSMENT The following Tier 1 test results are for a hypothetical air magnetic circuit breaker and are reported from the breaker’s last routine maintenance work. The Condition Indicators for an air magnetic breaker are Dielectric Tests, Operations and Maintenance History, Contact Resistance, and Number of Operations. The raw data for each of the indicators is as follows.

• Dielectric Tests – Doble test reports indicate insulation rating for the breaker (all poles and arc chutes) is Good.

• Operations and Maintenance History – This breaker is 35 years old and occasionally

requires intervention by an electrician to close the breaker after it has been tripped due to mechanism misalignment. The misalignment is caused by excessive wear in the operating mechanism. Replacement parts are not available. Project staff have fabricated replacement components for the mechanism in the past.

• Contact Resistance Tests – The measured contact resistance was below the maximum

recommended by the manufacturer.

• Number of Operations – The breaker counter indicates a total of 1245 operations since the breaker was installed.

Data for Circuit Breaker Quality Indicator – The Doble tests were performed 6 months ago. The Contact Resistance test results are 30 months old and no previous results are on file. The last short circuit study was performed two years ago and the breaker rating was found to be in excess of the system requirements by a factor of 1.2. The results of the various tests above are compared to the appropriate tables to develop a Score for each Condition Indicator, with the following results:

E2-20

Table 18 – Circuit Breaker Example Results

Tier 1 Condition Indicator

Score

Dielectric Tests 3 Operations and Maintenance History 1 Contact Resistance Tests 3 Number of Operations 2

Tier 1 Data Quality Indicator

Score

Quality of Inspections, Tests, and Measurements 7

The raw Scores in Table 18 are then entered into the appropriate Condition Assessment Summary form which contains the Weighting Factors to account for the differing importance of the Tier 1 tests. (Refer to the following tables.) Note: No change in score results from the Current Interrupting Rating Indicator, a Tier 2 test, as the ratio of breaker interrupting rating to available system fault current is 1.2.

E2-21

EXAMPLE

AIR MAGNETIC/AIR BLAST CIRCUIT BREAKER TIER 1 CONDITION ASSESSMENT SUMMARY

Date: _January 4, 2003___________ Location: __River Plant___________ Circuit Breaker Identifier: __Example 1___ Manufacturer: __OEM______ Yr. Mfd.: ___1968__ Current Rating: _5000_A_______ Interrupting Rating: __50 kA______ Voltage: _13.8_kV__

Tier 1 Circuit Breaker Condition Summary (For instructions on indicator scoring, please refer to condition assessment guide)

No. Condition Indicator Score × Weighting Factor = Total Score

1 Dielectric Condition of Breaker (Score must be 0, 1, 2, or 3) 3 0.877 2.631

2 Operation and Maintenance History (Score must be 0, 1, 2, or 3)

1 1.3156

1.316

3 Contact Resistance (Score must be 1, 2, or 3) 3 0.702 2.106

4 Number of Operations (Score must be 0, 1, 2, or 3) 2 0.439 0.878

Tier 1 Circuit Breaker Condition Index

(Sum of individual Total Scores) (Condition Index should be between 0 and 10)

6.931

Tier 1 Data Quality Indicator

(Value must be 0, 4, 7, or 10) 7

Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________ (Attach supporting documentation.)

E2-22

Circuit Breaker Condition-Based Alternatives

Circuit Breaker Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat condition assessment as needed.

≥ 3.0 and < 7 (Fair) Continue operation but reevaluate O & M practices. Consider using appropriate Tier 2 tests. Repeat condition assessment process as needed.

≥ 0 and < 3.0 (Poor) Immediate evaluation including additional Tier 2 testing. Consultation with experts. Adjust O & M as prudent. Begin replacement/rehabilitation process.

E2-23

EXAMPLE

AIR MAGNETIC/AIR BLAST CIRCUIT BREAKER TIER 2 CONDITION ASSESSMENT SUMMARY

Date: _January 4, 2003___________ Location: __River Plant___________ Circuit Breaker Identifier: __Example 1___ Manufacturer: __OEM______ Yr. Mfd.: ___1968__ Current Rating: _5000_A_______ Interrupting Rating: __50 kA______ Voltage: _13.8_kV__

Tier 2 Circuit Breaker Condition Summary

Adjustment to Tier 1 No. Tier 2 Test Condition Index T2.1 Interrupter Inspection 0

T2.2 Current Interrupting Rating vs. Short Circuit Current Analysis 0

T2.3 Other Specialized Diagnostic Tests 0 Tier 2 Adjustments to Circuit Breaker Condition Index

(Sum of individual Adjustments) 0

Tier 2 Data Quality Indicator

(Value must be 0, 4, 7, or 10) 7

To calculate the Net Circuit Breaker Condition Index, subtract the Tier 2 Adjustments from the Tier 1 Circuit Breaker Condition Index: Tier 1 Circuit Breaker Condition Index __6.931__ minus Tier 2 Circuit Breaker Adjustments __0______ = _____6.931_______ Net Circuit Breaker Condition Index Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________

(Attach supporting documentation.)

E2-24

Table 19 – Circuit Breaker Condition Assessment Summary

Test Detects Tool Breaker Common Tests:

Megger and Power Factor Tests

Presence of dirt and moisture (tracking), Insulation deterioration, bushing insulation condition,

Electrical test equipment and experienced personnel

Contact Inspection

Pitted or scarred surfaces, embedded foreign material, discoloration, evidence of overheating

Experienced and qualified inspectors

Operating Mechanism Inspection

Missing, loose, or damaged parts; worn moving parts, binding during movement

Experienced and qualified inspectors

Overall Timing Misadjusted contacts or limits, worn or binding mechanisms, proper dashpot or shock absorber action, overall circuit breaker mechanical condition.

Circuit breaker timing analyzer and sensors/attachments

Infrared Scan (while breaker is in service)

Overheated connections, abnormal heating Thermographic camera and analysis software, experienced and qualified inspectors

Contact Resistance

Poor conducting surfaces, low contact pressure (weak springs)

Digital Low Resistance Ohmmeter or other high current source able to measure microvolt drops across contacts

Breaker Specific Tests:

Hi-pot Test Integrity of vacuum in interrupter Electrical test equipment and experienced personnel

Oil Physical and Chemical Tests

Moisture, degraded interfacial tension (IFT), acidity, color, dielectric strength, and power factor.

Requires laboratory analysis

SF6 Gas Analysis Density, moisture, purity Requires laboratory analysis

Interrupter Grid Inspection Deterioration of arc extinguishing parts Experienced and qualified inspectors

Compressed Air System

Adequate compressor performance, control valve condition, piping system leaks or damage

Experienced and qualified inspectors

E2-25

AIR MAGNETIC/AIR BLAST CIRCUIT BREAKER TIER 1 CONDITION ASSESSMENT SUMMARY

Date: ______________________ Location: ___________________

Circuit Breaker Identifier: _________ Manufacturer: ____________________ Yr. Mfd.: ______

Current Rating: ______________ Interrupting Rating: _____________ Voltage: ____________

Tier 1 Circuit Breaker Condition Summary (For instructions on indicator scoring, please refer to condition assessment guide)

No. Condition Indicator Score × Weighting Factor = Total Score

1 Dielectric Condition of Breaker (Score must be 0, 1, 2, or 3) 0.877

2 Operation and Maintenance History (Score must be 0, 1, 2, or 3)

1.316

3 Contact Resistance (Score must be 1, 2, or 3) 0.702

4 Number of Operations (Score must be 0, 1, 2, or 3) 0.439

Tier 1 Circuit Breaker Condition Index

(Sum of individual Total Scores) (Condition Index should be between 0 and 10)

Tier 1 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________ (Attach supporting documentation.)

E2-26

Circuit Breaker Condition-Based Alternatives

Circuit Breaker Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat condition assessment as needed.

≥ 3.0 and < 7 (Fair) Continue operation but reevaluate O & M practices. Consider using appropriate Tier 2 tests. Repeat condition assessment process as needed.

≥ 0 and < 3.0 (Poor) Immediate evaluation including additional Tier 2 testing. Consultation with experts. Adjust O & M as prudent. Begin replacement/rehabilitation process.

E2-27

AIR MAGNETIC/AIR BLAST CIRCUIT BREAKER TIER 2 CONDITION ASSESSMENT SUMMARY

Date: ______________________ Location: ___________________

Circuit Breaker Identifier: _________ Manufacturer: ____________________ Yr. Mfd.: ______

Current Rating: ______________ Interrupting Rating: _____________ Voltage: ____________

Tier 2 Circuit Breaker Condition Summary

Adjustment to Tier 1 No. Tier 2 Test Condition Index T2.1

Interrupter Inspection

T2.2 Current Interrupting Rating vs. Short Circuit Current Analysis

T2.3 Other Specialized Diagnostic Tests Tier 2 Adjustments to Circuit Breaker Condition Index

(Sum of individual Adjustments)

Tier 2 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

To calculate the Net Circuit Breaker Condition Index (Value should be between 0 and 10), subtract the Tier 2 Adjustments from the Tier 1 Circuit Breaker Condition Index: Tier 1 Circuit Breaker Condition Index __________ minus Tier 2 Circuit Breaker Adjustments __________ = ________________ Net Circuit Breaker Condition Index Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________

(Attach supporting documentation.)

E2-28

OIL TANK CIRCUIT BREAKER TIER 1 CONDITION ASSESSMENT SUMMARY

Date: ______________________ Location: ___________________

Circuit Breaker Identifier: _________ Manufacturer: ____________________ Yr. Mfd.: ______

Current Rating: ______________ Interrupting Rating: _____________ Voltage: ____________

Tier 1 Circuit Breaker Condition Summary (For instructions on indicator scoring, please refer to condition assessment guide)

No. Condition Indicator Score × Weighting Factor = Total Score

1 Dielectric Condition of Breaker (Score must be 0, 1, 2, or 3) 0.684

2 Operation and Maintenance History (Score must be 0, 1, 2, or 3)

1.282

3 Contact Resistance (Score must be 1, 2, or 3) 0.684

4 Number of Operations (Score must be 0, 1, 2, or 3) 0.684

Tier 1 Circuit Breaker Condition Index

(Sum of individual Total Scores) (Condition Index should be between 0 and 10)

Tier 1 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________ (Attach supporting documentation.)

E2-29

Circuit Breaker Condition-Based Alternatives

Circuit Breaker Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat condition assessment as needed.

≥ 3.0 and < 7 (Fair) Continue operation but reevaluate O & M practices. Consider using appropriate Tier 2 tests. Repeat condition assessment process as needed.

≥ 0 and < 3.0 (Poor) Immediate evaluation including additional Tier 2 testing. Consultation with experts. Adjust O & M as prudent. Begin replacement/rehabilitation process.

E2-30

OIL TANK CIRCUIT BREAKER TIER 2 CONDITION ASSESSMENT SUMMARY

Date: ______________________ Location: ___________________

Circuit Breaker Identifier: _________ Manufacturer: ____________________ Yr. Mfd.: ______

Current Rating: ______________ Interrupting Rating: _____________ Voltage: ____________

Tier 2 Circuit Breaker Condition Summary

Adjustment to Tier 1 No. Tier 2 Test Condition Index T2.1

Interrupter Inspection

T2.2 Current Interrupting Rating vs. Short Circuit Current Analysis

T2.3 Other Specialized Diagnostic Tests Tier 2 Adjustments to Circuit Breaker Condition Index

(Sum of individual Adjustments)

Tier 2 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

To calculate the Net Circuit Breaker Condition Index (Value should be between 0 and 10), subtract the Tier 2 Adjustments from the Tier 1 Circuit Breaker Condition Index: Tier 1 Circuit Breaker Condition Index __________ minus Tier 2 Circuit Breaker Adjustments __________ = ______________ Net Circuit Breaker Condition Index Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________

(Attach supporting documentation.)

E2-31

SF6 CIRCUIT BREAKER TIER 1 CONDITION ASSESSMENT SUMMARY

Date: ______________________ Location: ___________________

Circuit Breaker Identifier: _________ Manufacturer: ____________________ Yr. Mfd.: ______

Current Rating: ______________ Interrupting Rating: _____________ Voltage: ____________

Tier 1 Circuit Breaker Condition Summary (For instructions on indicator scoring, please refer to condition assessment guide)

No. Condition Indicator Score × Weighting Factor = Total Score

1 Dielectric Condition of Breaker (Score must be 0, 1, 2, or 3) 0.439

2 Operation and Maintenance History (Score must be 0, 1, 2, or 3)

1.316

3 Contact Resistance (Score must be 1, 2, or 3) 0.877

4 Number of Operations (Score must be 0, 1, 2, or 3) 0.702

Tier 1 Circuit Breaker Condition Index

(Sum of individual Total Scores) (Condition Index should be between 0 and 10)

Tier 1 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________ (Attach supporting documentation.)

E2-32

Circuit Breaker Condition-Based Alternatives

Circuit Breaker Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat condition assessment as needed.

≥ 3.0 and < 7 (Fair) Continue operation but reevaluate O & M practices. Consider using appropriate Tier 2 tests. Repeat condition assessment process as needed.

≥ 0 and < 3.0 (Poor) Immediate evaluation including additional Tier 2 testing. Consultation with experts. Adjust O & M as prudent. Begin replacement/rehabilitation process.

E2-33

SF6 CIRCUIT BREAKER TIER 2 CONDITION ASSESSMENT SUMMARY

Date: ______________________ Location: ___________________

Circuit Breaker Identifier: _________ Manufacturer: ____________________ Yr. Mfd.: ______

Current Rating: ______________ Interrupting Rating: _____________ Voltage: ____________

Tier 2 Circuit Breaker Condition Summary

Adjustment to Tier 1 No. Tier 2 Test Condition Index T2.1

Interrupter Inspection

T2.2 Current Interrupting Rating vs. Short Circuit Current Analysis

T2.3 Other Specialized Diagnostic Tests Tier 2 Adjustments to Circuit Breaker Condition Index

(Sum of individual Adjustments)

Data Quality Indicator

(Value must be 0, 4, 7, or 10)

To calculate the Net Circuit Breaker Condition Index (Value should be between 0 and 10), subtract the Tier 2 Adjustments from the Tier 1 Circuit Breaker Condition Index: Tier 1 Circuit Breaker Condition Index __________ minus Tier 2 Circuit Breaker Adjustments __________ = ________________ Net Circuit Breaker Condition Index Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________

(Attach supporting documentation.)

E2-34

VACUUM CIRCUIT BREAKER TIER 1 CONDITION ASSESSMENT SUMMARY

Date: ______________________ Location: ___________________

Circuit Breaker Identifier: _________ Manufacturer: ____________________ Yr. Mfd.: ______

Current Rating: ______________ Interrupting Rating: _____________ Voltage: ____________

Tier 1 Circuit Breaker Condition Summary (For instructions on indicator scoring, please refer to condition assessment guide)

No. Condition Indicator Score × Weighting Factor = Total Score

1 Dielectric Condition of Breaker (Score must be 0, 1, 2, or 3) _ _ _ _ 0

2 Operation and Maintenance History (Score must be 0, 1, 2, or 3)

3.333

3 Contact Resistance (Score must be 1, 2, or 3) _ _ _ _ 0

4 Number of Operations (Score must be 0, 1, 2, or 3) _ _ _ _ 0

Tier 1 Circuit Breaker Condition Index

(Sum of individual Total Scores) (Condition Index should be between 0 and 10)

Tier 1 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________ (Attach supporting documentation.)

E2-35

Circuit Breaker Condition-Based Alternatives

Circuit Breaker Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat condition assessment as needed.

≥ 3.0 and < 7 (Fair) Continue operation but reevaluate O & M practices. Consider using appropriate Tier 2 tests. Repeat condition assessment process as needed.

≥ 0 and < 3.0 (Poor) Immediate evaluation including additional Tier 2 testing. Consultation with experts. Adjust O & M as prudent. Begin replacement/rehabilitation process.

E2-36

VACUUM CIRCUIT BREAKER TIER 2 CONDITION ASSESSMENT SUMMARY

Date: ______________________ Location: ___________________

Circuit Breaker Identifier: _________ Manufacturer: ____________________ Yr. Mfd.: ______

Current Rating: ______________ Interrupting Rating: _____________ Voltage: ____________

Tier 2 Circuit Breaker Condition Summary

Adjustment to Tier 1 No. Tier 2 Test Condition Index T2.1

Interrupter Inspection

T2.2 Current Interrupting Rating vs. Short Circuit Current Analysis

T2.3 Other Specialized Diagnostic Tests Tier 2 Adjustments to Circuit Breaker Condition Index

(Sum of individual Adjustments)

Tier 2 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

To calculate the Net Circuit Breaker Condition Index (Value should be between 0 and 10), subtract the Tier 2 Adjustments from the Tier 1 Circuit Breaker Condition Index: Tier 1 Circuit Breaker Condition Index __________ minus Tier 2 Circuit Breaker Adjustments __________ = ________________ Net Circuit Breaker Condition Index Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________

(Attach supporting documentation.)

E3-1

September 2006 Hydro Plant Risk Assessment Guide Appendix E3: Governor Condition Assessment E3.1 GENERAL Speed governors are major elements of hydroelectric generating units and are appropriate for analysis under a condition assessment program. Unexpected governor failure can have a significant economic impact due to lost revenues during an extended forced outage. Determining the present condition of a speed governor is an essential step in analyzing the risk of failure. This appendix provides a process for arriving at a Governor Condition Index which may be used to develop a business case addressing risk of failure, economic consequences, and other factors. E3.2 SCOPE / APPLICATION The governor condition assessment methodology outlined in this appendix applies to mechanical, analog, and digital speed governors. This appendix primarily focuses on the governor control system and the governor valves. The components listed below are within the scope of this document. 1. Governor Control System (mechanical, analog or digital)

• Speed sensing devices • Speed adjustment • Speed droop • SSG (speed signal generator) or PMG (permanent magnet generator) • Restoring mechanism • Pilot valve

2. Governor Distributing Valves & Auxiliary Valve (if applicable) Servomotors and other auxiliary components such as pressure and sump tanks, pumps, oil filters, piping and hydraulic valves (other than the governor valves) are not considered during this assessment. This appendix is intended for application to each individual governor at a plant and not to an entire plant or to a family of governors at a plant. Each governor should be evaluated separately for condition rating and prioritizing investment needs.

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This appendix is not intended to define governor maintenance practices or describe in detail governor inspections, tests or measurements. Utility-specific maintenance policies and procedures must be consulted for such information. E3.3 CONDITION AND DATA QUALITY INDICATORS AND GOVERNOR

CONDITION INDEX This appendix describes the condition indicators generally regarded by hydro plant engineers as providing the initial basis for assessing governor condition. The condition assessment methodology consists of analyzing each condition indicator individually to arrive at a condition indicator score. The scores are weighted and summed to determine the Condition Index. An additional stand-alone indicator is used to reflect the quality of the information available for scoring the governor condition indicators. In some cases, data may be missing, out-of-date, or of questionable integrity. Any of these situations could affect the validity of the overall Condition Index. Given the potential impact of poor or missing data, the Data Quality Indicator is used as a means of evaluating and recording confidence in the final Governor Condition Index. Additional information regarding governor condition may be necessary to improve the accuracy and reliability of the Governor Condition Index. Therefore, in addition to the Tier 1 condition indicators, this appendix describes a “toolbox” of Tier 2 inspections, tests, and measurements that may be applied to the Governor Condition Index, depending on the specific issue or problem being addressed. Tier 2 tests are considered non-routine. However, if Tier 2 data is readily available, it may be used to supplement the Tier 1 assessment. Alternatively, Tier 2 tests may be deliberately performed to address Tier 1 findings. Results of the Tier 2 analysis may either increase or decrease the score of the Governor Condition Index. The Data Quality Indicator score may also be revised during the Tier 2 assessment to reflect the availability of additional information or test data. The Governor Condition Index is applied to the Governor Condition-Based Alternatives Table (Table 9) to determine the recommended course of action. The Governor Condition Index may indicate the need for immediate corrective actions and/or follow-up Tier 2 testing. The Governor Condition Index is also suitable for use as an input to the risk-based economic analysis model. Note: A severely negative result of ANY inspection, test, or measurement may be adequate in itself to require immediate de-energization or prevent re-energization of the governor, regardless of the Governor Condition Index score. E3.4 INSPECTIONS, TESTS, AND MEASUREMENTS Inspections, tests and measurements should be conducted and analyzed by staff suitably trained and experienced in governor diagnostics. More complex inspections and measurements may require an expert.

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Inspections, tests, and measurements should be performed on a frequency that provides the accurate and current information needed by the assessment. Details of the inspection, testing, and measurement methods and intervals are described in technical references specific to the electric utility. E3.5 SCORING Condition indicator scoring is somewhat subjective, relying on the experience and opinions of competent personnel. Relative terms such as “Results Normal” and “Degradation” refer to results that are compared to industry-accepted levels; or to baseline or previously acceptable levels on this equipment; or to equipment of similar design, construction, or age operating in a similar environment. E3.6 WEIGHTING FACTORS Weighting factors used in the condition assessment methodology recognize that some condition indicators affect the Governor Condition Index to a greater or lesser degree than other indicators. These weighting factors were arrived at by consensus among governor maintenance and engineering personnel with extensive experience. E3.7 MITIGATING FACTORS Every governor is unique and, therefore, the methodology described in this guide cannot quantify all factors that affect individual governor condition. If the Condition Index triggers significant follow-up actions (e.g., major repairs or a Tier 2 assessment), it may be prudent to first have the index reviewed by governor experts. Mitigating factors specific to the utility may affect the final Condition Index and the final decision on replacement or rehabilitation. E3.8 DOCUMENTATION Substantiating documentation is essential to support findings of the assessment, particularly where a Tier 1 Condition Indicator score is less than 3 (i.e., Normal) or where a Tier 2 analysis results in subtractions to the Governor Condition Index. Test reports, facility review reports, special exams, photographs, O & M records, and other documentation should accompany the Governor Condition Assessment Summary form. E3.9 CONDITION ASSESSMENT METHODOLOGY The condition assessment methodology consists of analyzing each condition indicator individually to arrive at a condition indicator score. The scores are weighted and summed to determine the Condition Index.

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Reasonable efforts should be made to perform Tier 1 inspections, tests, and measurements. However, when data is unavailable to properly score the Condition Indicator, it may be assumed that the score is “Good” or numerically equal to some mid-range number such as 2. This strategy must be used judiciously to prevent erroneous results and conclusions. In recognition of the potential impact of poor or missing data, a separate Data Quality Indicator is rated during the Tier 1 assessment as a means of evaluating and recording confidence in the final Governor Condition Index. E3.10 TIER 1 – GOVERNOR INSPECTIONS, TESTS, AND MEASUREMENTS The following condition indicators are used to perform a Tier 1 Condition Assessment:

• Age • Operation and Maintenance History • Availability of Spare Parts • Performance

The Tier 1 condition indicators are based on inspections, tests, and measurements conducted by utility staff over the course of time and as a part of routine maintenance activities. Numerical scores are assigned to each Tier 1 condition indicator, which are then weighted and summed to determine the Governor Condition Index.

Governor Condition Indicator 1 – Age

The age of the governor is among the factors to consider when identifying candidates for mechanical rehabilitation, partial replacement (digital retrofit), or complete replacement. Age is one indicator of remaining life and upgrade potential to current state-of-the-art materials and designs. As a governor ages, the mechanical parts become affected by wear and are more susceptible to internal leaks, thus affecting its performance. In the same way, the electronic parts are subjected to more deterioration due to overheating, excessive vibration, or contamination. Although actual service life varies depending on the manufacturer’s design, quality of assembly, materials used, and operation and maintenance history, the average expected life for a governor is most dependent on the technology used (mechanical, analog, or digital). Statistically, the average service life for a governor control system varies from 15 to 40 years depending upon the type of control system. The following tables are used to separately evaluate the age of mechanical, analog and digital governors. Depending on the governor type, apply the Governor Age to Table 1A, 1B, or 1C, whichever is appropriate.

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Table 1 – Age Scoring

Control System

Table 1A – Age Scoring

Mechanical Control System

Age Condition Indicator Score

< 25 years 3

≥ 25 and < 40 years 2

≥ 40 years 1

Table 1B – Age Scoring Analog Control System

Age Condition Indicator Score

< 20 years 3

≥ 20 and < 30 years 2

≥ 30 years 1

Table 1C – Age Scoring Digital Control System

Age Condition Indicator Score

< 10 years 3

≥ 10 and < 15 years 2

≥ 15 years 1

Condition Indicator 2 – Operation & Maintenance History Operation and maintenance (O & M) history provides useful information for determining the governor condition. Records should be examined to evaluate the amount of maintenance carried out in the past to keep the governor in operation and in good condition. The amount of preventive and corrective maintenance required and the occurrence of operational limitations play a role in determining the condition and reliability of a governor, and the need for capital investment.

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O & M history is reviewed and results are applied to Table 2 to arrive at an appropriate condition indicator score.

Table 2 – Operation & Maintenance History Scoring

Historical Results Condition Indicator ScoreNormal preventive and corrective maintenance (< 50 hours/year/unit) or no significant increase in preventive and corrective maintenance (less than 1.5 x baseline, as established by maintenance records).

3

Significant increase (over 1.5 x baseline) in preventive maintenance, but no significant increase in corrective maintenance, or operational constraints occurring rarely.

2

Significant increase (over 1.5 x baseline) in corrective maintenance or operational constraints occurring occasionally. 1

Repeated corrective maintenance or operational constraints. 0 Condition Indicator 3 – Availability of Spare Parts Availability of spare parts is an important factor to take into account when determining the need for upgrade and the serviceability of governors. Consideration shall be given only to wear parts or parts that can be reasonably expected to require future replacement or rehabilitation. This condition indicator is applicable to mechanical parts as well as electronic parts. The assessment of spare parts availability is applied to Table 3 to arrive at an appropriate condition indicator score.

Table 3 – Availability of Spare Parts Scoring

Availability Condition Indicator ScoreAll necessary mechanical and electronic parts are available from original supplier. 3

Necessary mechanical and electronic parts are no longer available from original supplier and must be obtained from alternate suppliers. 2

Some electronic and mechanical parts are not available at all and/or some mechanical parts must be reverse-engineered and manufactured by alternate suppliers.

1

Most mechanical and electronic parts are not available at all and/or there are significant obstacles to successful reverse-engineering of mechanical parts.

0

Condition Indicator 4 – Performance The performance of a speed governor is one of the leading indicators in determining its condition. Factors to consider in evaluating the performance may include:

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• Synchronization time and ability; • System stability; • Black start capability (if applicable); • Auto-synchronization capability (if applicable); • Ability to remote start (if applicable); • Accuracy and repeatability in response to load change and system disturbance; • Hunting problems.

Governor performance is analyzed and the results are applied to Table 4 to arrive at an appropriate condition indicator score.

Table 4 – Performance Scoring

Observations (Criteria) Condition Indicator ScoreOff-line and on-line response and stability normal, governor free from hunting, accuracy of frequency within < 0.2 Hz, synchronization time within the norm, and able to remote start.

3

Off-line and on-line response and stability are fair, occasional hunting problems, synchronization time and accuracy of frequency outside the norm, or remote start is difficult.

2

Poor off-line and on-line response and stability, re-occurring hunting problems, difficulty in synchronization, or unable to remote start. 1

A score of 3 should be given if all corresponding criteria are met. A score of 1 or 2 should be given if at least one of the corresponding situations occurs.

E3.11 TIER 1 – GOVERNOR CONDITION INDEX CALCULATIONS Enter the condition indicator scores from the tables above into the Governor Condition Assessment Summary form at the end of this document. Multiply each indicator score by its respective Weighting Factor, and sum the Total Scores to arrive at the Tier 1 Governor Condition Index. This index may be adjusted by the Tier 2 governor inspections, tests, and measurements described in section E3.13 of this document. Suggested alternatives for follow-up action based on the Governor Condition Index are described in the Governor Condition-Based Alternatives table (Table 9).

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E3.12 GOVERNOR DATA QUALITY INDICATOR The Governor Data Quality Indicator reflects the quality of the inspection, test, and measurement results used to evaluate the governor condition under Tier 1. The more current and complete the results are, the higher the rating for this indicator. The normal testing frequency is defined as the organization’s recommended frequency for performing the specific test or inspection. Qualified personnel should make a determination of scoring that encompasses as many factors as possible under this indicator. Results are analyzed and applied to Table 5 to arrive at an appropriate Governor Data Quality Indicator Score.

Table 5 – Data Quality Scoring

Results Data Quality Indicator Score All Tier 1 inspections, tests, and measurements were completed within the normal testing frequency and results are reliable. 10

One or more of the Tier 1 inspections, tests, and measurements were completed ≥ 6 and < 24 months past the normal testing interval and results are reliable.

7

One or more of the Tier 1 inspections, tests, and measurements were completed ≥ 24 and < 36 months past the normal testing interval, or some of the results are not available or are of questionable integrity.

4

One or more of the Tier 1 inspections, tests, and measurements were completed ≥ 36 months past the normal interval or many results are of questionable integrity or no results are available.

0

Enter the Governor Data Quality Indicator Score from Table 5 into the Governor Condition Assessment Summary form at the end of this document. E3.13 TIER 2 – GOVERNOR INSPECTIONS, TESTS, AND MEASUREMENTS The following condition indicators are used to perform a Tier 2 Condition Assessment:

• Leakage Test • Step Response Test • Physical Inspection

The Tier 2 condition indicators are based on selected appropriate inspections, tests, and measurements conducted by qualified personnel or experts and as a part of non-routine maintenance activities. Numerical scores are assigned to each Tier 2 condition indicator, which are used to adjust the Governor Condition Index determined in Tier 1, to arrive at a Revised Condition Index.

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Test T2.1: Leakage Test The rate of oil leakage is indicative of the condition of the valves in the governor system. The leakage test can determine the consumption of the main valve and the auxiliary valve. The consumption of the pilot valve is considered too small to show significant data. 1. The following test shows the leakage of the main valves:

Prior to doing this test:

• Scroll case must be empty; • Main valve should be blocked in its hydraulic centered position (this position is

achieved when the pressure is equal on each side of the servomotor piston or when there is no movement of the servomotor);

• Vibrator motor should be isolated by closing the appropriate valve; • Pilot valve should be isolated from incoming oil by closing the appropriate valve; • Auxiliary valve should be closed (the transfer valve is on the main valve).

The consumption of the main valve can be determined by the leakage rate read on the tank. For better accuracy, take a large change in oil (ΔH) or use computerized instrumentation. For a Kaplan runner, this test will provide the leakage of the two main valves combined. The piston of the runner must be isolated.

2. The following test shows the leakage of the auxiliary valve (if applicable):

Prior to doing this test: • Scroll case must be empty; • Gates must be moved to 50 % opening (this position is achieved when the pressure is

equal on each side of the servomotor piston); • Vibrator motor should be isolated by closing the appropriate valve; • Pilot valve should be isolated from incoming oil by closing the appropriate valve; • Main valve should be closed (the transfer valve in on the auxiliary valve).

The consumption of the auxiliary valve can be determined by the leakage rate read on the tank. For better accuracy, take a large change in oil level (ΔH) or use computerized instrumentation.

[ ]min/10493.6 22

galUST

dHrateLeakage −×××Δ

=π

where ΔH = change in oil level [inches] d = diameter of the tank [inches] T = time [seconds]

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Overall Leakage = Leakage from the main valves (including main valve for Kaplan runner) + Leakage from the auxiliary valve

Table 6 – Overall Leakage Rate Scoring

Adjustment to Observations (Criteria) Condition Index Score No significant increase on leakage rate from original value or previous data or that of comparable governors. No change

Small increase in the leakage rate. Subtract 1.0 Leakage rate has doubled (or more). Subtract 2.0 Test T2.2: Step Response Test In order to adequately evaluate a governor’s performance, its various settings (such as needle valve, compensating crank, restoring ratio on a mechanical governor) must be adjusted to their optimum values, given the current condition of the governor. A poorly performing governor may not be in bad condition, but just misadjusted. The various settings must be set to match the response of the governor to the rotating inertia of the generator and the inertia of the water column in the penstock. A properly adjusted governor in good condition will be able to maintain off-line speed stability within < 0.2 Hertz, allow the unit to be synchronized to the bus, allow the unit to be quickly loaded when operating on an infinite bus, and will be able to maintain frequency within < 0.2 Hertz when operating isolated. Making adjustments to simply reduce off-line hunting to make it easier to synchronize on-line many times will make the governor unresponsive on-line or unable to react quickly enough to maintain frequency if the unit should become isolated. Procedures for these adjustments for mechanical governors are found in Reclamations FIST Volume 2-3, Mechanical Governors for Hydroelectric Units. These procedures take into account the penstock geometry and rotating mass of the generator. If an optimum response can not be accomplished, major work or replacement of the governor may be required. Dead time and friction will be evident when performing the step response test. It can induce a significant time lag in the response. Any lag in movement from the time a step in speed set point is initiated and actual movement of the gates occurs is referred to as dead time and is usually a result of friction in the governor, restoring cable, in the servomotor, or wicket gate linkage. The response to a small (0.5 to 1%) speed changer step should be a smooth, regular curve. If the response shows any erratic movement, friction is likely someplace in the turbine control system. Likely places in the governor for friction are the dashpot, linkage pins and bearings, pilot valve and main valve. The motion of the main valve should also be observed during a step response. The motion of the dither of around 6 to 9 mils should always be evident. The motion following a speed step should be a quick initial movement and then a smooth movement back to center. Erratic movement during the step, or when at a steady state condition, usually indicates some problem with the main or pilot valves. After making required adjustments as described above, a step response test may be performed. This test will normally be performed off-line by inputting a speed step, but may be performed

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on-line by inputting a load step. The governor is evaluated by inputting a speed or frequency (or load) step of 1% minimum and 5% maximum and recording the response in speed (and/or load) versus time. For mechanical governors, it is acceptable to make the test easier by inputting the step with a sudden change of the speed adjust. It is preferred to compare the governor response to a computer simulation model of the governor. In the absence of a computer simulation, it is acceptable to compare the response to the typically recommended 0.7 critically damped system. The response should be similar to the response shown in Figure 1 for off-line testing. For on-line testing with a load step a response with higher damping and no overshoot is expected.

Figure 1. A 0.7 Critically Damped System

Table 7 – Step Response Scoring (After governor has been adjusted)

Adjustment to Observations (Criteria) Condition Index Score Off-line speed stability < 0.1 Hertz. Response to speed step correlates with computer simulation or is 0.7 critically damped. No Change

Off-line speed stability ≥ 0.1 and < 0.2 Hertz. Response to speed step is acceptable, but does correlate closely with computer simulation or is not 0.7 critically damped.

Subtract 0.5

Adjustment has no effect on governor response and unable to adjust governor to prepare for step response test or obtain a 0.7 critically damped response to speed step, or dead time and friction prevent an acceptable response.

Subtract 1.0

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Test T2.3: Physical Inspection The disassembly and physical inspection of the components of the governor can verify findings of other tests and determine if the governor can be restored or is a candidate for replacement. The type of governor will determine the course of action. Mechanical Governors The dashpot should be removed and checked for leakage by closing the needle and bypass and pushing the small dashpot plunger down as far as it can go and timing how long it takes to re-center. It should take at least 50 seconds to travel 0.125 inch. If the travel is faster than that, the dashpot requires repairs or replacement. The linkage pins and links should be checked for wear or binding. The main valve should be removed and inspected for signs of wear, chatter, or binding. Make sure the plunger moves freely in its bushing. Remove the plungers from the distributing valve and check condition of seats and piston rings. Remove the pilot valve and check for signs of binding and wear. Check the ball-head for broken springs, and that fly weights move freely. Digital and Analog Governors These governors have much fewer mechanical and hydraulic parts to be inspected. Mechanical inspection generally will be limited to the hydraulic governor head, which is usually comprised of a proportional valve and other associated solenoid control valves. The functions that had been performed by the ball-head, pilot valve, restoring cable, dashpot, and associated linkages are now accomplished by a programmable logic controller (PLC). Unit speed and gate position information is input electronically to the PLC instead of by mechanical means. Depending on the model, the proportional valves and other related control valves that are present may be “off-the-shelf” items which were purchased by the manufacturer and then assembled in a complete governor system. Any complete disassembly or maintenance of these valves should be done only after consulting the manufacturer’s manual or other factory information. Before turning off power to the governor, check that solenoids are picking up and moving the spool when energized. If not, remove the control valve end caps and determine if the spool moves freely. Inspect all accessible valve and pipe fittings for leakage. Trouble-shooting flow charts should be available from the manufacturer, and may help pin-point problems before resorting to disassembly. Once the problem has been identified, replacement of parts may be the best course of action instead of repair, if the parts are readily available.

Table 8 – Physical Inspection

Adjustment to Observations (Criteria) Condition Index Score

Damaged parts found and replaced with new parts. Governor response improved. Add 1.0

No damaged components found. No Change

Damaged parts found. New parts not available. Subtract 1.0

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Test T2.4: Other Specialized Diagnostic Tests

Additional tests may be applied to evaluate specific governor problems. Some of these diagnostic tests may be considered to be of an investigative research nature. When conclusive results from other diagnostic tests are available, they may be used to make an appropriate adjustment to the Governor Condition Index. E3.14 GOVERNOR CONDITION-BASED ALTERNATIVES The Governor Condition Index – either modified by Tier 2 tests or not – may be sufficient for decision-making regarding governor alternatives. The Condition Index is also suitable for use in a risk-based economic analysis model. Where it is desired to consider alternatives based solely on governor condition, the Governor Condition Index may be directly applied to the Governor Condition-Based Alternatives table (Table 9).

Table 9 – Governor Condition-Based Alternatives

Governor Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat condition assessment as needed.

≥ 3.0 and < 7 (Fair) Continue operation but reevaluate O & M practices. Consider using appropriate Tier 2 tests. Repeat condition assessment process as needed.

≥0 and < 3.0 (Poor) Immediate evaluation including additional Tier 2 testing. Consultation with experts. Adjust O & M as prudent. Begin replacement/rehabilitation process.

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GOVERNOR TIER 1 CONDITION ASSESSMENT SUMMARY

Date: ________________________ Location: ________________________________________

Gov. Identifier: _________________ Gov. Manufacturer: _______________________________

Yr. Manufactured: ______________________ Yr. Rehabilitated: _________________________

Gov. Control System: Mechanical Analog Digital

Tier 1 Governor Condition Summary

(For instructions on indicator scoring, please refer to condition assessment guide)

No. Condition Indicator Score × Weighting Factor = Total Score

1 Age (Score must be 1, 2, or 3) 0.17

2 Operation & Maintenance History (Score must be 0, 1, 2, or 3) 1.17

3 Availability of Spare Parts (Score must be 0, 1, 2, or 3) 0.83

4 Performance (Score must be 1, 2, or 3) 1.17

Tier 1 Governor Condition Index (Sum of individual Total Scores)

(Condition Index should be between 0 and 10)

Tier 1 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________ (Attach supporting documentation.)

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Governor Condition-Based Alternatives

Governor Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat condition assessment as needed.

≥ 3.0 and < 7 (Fair) Continue operation but reevaluate O & M practices. Consider using appropriate Tier 2 tests. Repeat condition assessment process as needed.

≥ 0 and < 3.0 (Poor) Immediate evaluation including additional Tier 2 testing. Consultation with experts. Adjust O & M as prudent. Begin replacement/rehabilitation process.

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GOVERNOR TIER 2 CONDITION ASSESSMENT SUMMARY

Date: ________________________ Location: ________________________________________

Gov. Identifier: _________________ Gov. Manufacturer: _______________________________

Yr. Manufactured: ______________________ Yr. Rehabilitated: _________________________

Gov. Control System: Mechanical Analog Digital

Tier 2 Governor Condition Summary

Adjustment to Tier 1 No. Tier 2 Test Condition Index

T2.1 Leakage Test

T2.2 Step Response Test

T2.3 Physical Inspection

T2.4 Other Specialized Diagnostic Tests

Tier 2 Adjustments to Governor Condition Index (Sum of individual Adjustments)

Tier 2 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

To calculate the Net Governor Condition Index (Value should be between 0 and 10), subtract the Tier 2 Adjustments from the Tier 1 Governor Condition Index: Tier 1 Governor Condition Index __________ minus Tier 2 Governor Adjustments __________ = ________________ Net Governor Condition Index Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________

(Attach supporting documentation.)

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September 2006 Hydro Plant Risk Assessment Guide Appendix E4: Excitation System Condition Assessment E4.1 GENERAL Excitation systems are key components in hydroelectric powerplants and are appropriate for analysis under a condition assessment program. Excitation system failure can have a significant economic impact due to high equipment costs as well as long lead times in procurement, manufacturing, and installation and lost revenues during an extended forced outage. An excitation system can be divided into two major subsystems: the low voltage system (control and electronics) and the high voltage system (excitation system supply transformer, rotating exciter, power bridge, supply breaker, field breaker, etc.). The high voltage portion of the excitation system will likely dictate the need for replacement of the entire system. The low voltage and electronic portion will play a key role if spare parts are no longer available and/or the equipment becomes obsolete. A failure of one or more components in a system may not necessitate the replacement of the entire system, only the affected components. Many excitation system abnormalities, especially in the low voltage control portion, are readily detected through regular maintenance and can be corrected without complete replacement of the excitation system. Individual electronic circuits can be replaced efficiently and cheaply if they are still supported by the manufacturer. However, if manufacturer support is not available, the costs may become substantial and a partial or complete replacement of the excitation system may be warranted. Determining the present condition of an excitation system is an essential step in analyzing the risk of failure. This appendix provides a process for arriving at an Excitation System Condition Index which may be used to develop a business case addressing risk of failure, economic consequences, and other factors. E4.2 SCOPE / APPLICATION The excitation system condition assessment methodology outlined in this appendix applies to fully static systems (SCR bridge rectifier supplying the required generator field voltage), rotating exciter systems incorporating electronic regulators and/or pilot exciters, and older magnetic amplifier type systems. This appendix is not intended to define excitation system maintenance practices or describe in detail excitation system condition assessment inspections, tests, or measurements. Utility maintenance policies and procedures must be consulted for such information.

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E4.3 CONDITION INDICATORS AND EXCITATION SYSTEM CONDITION INDEX This appendix describes five Condition Indicators generally regarded by engineers as providing a sound basis for assessing excitation system condition:

• Age • Operation and Maintenance History • Availability of Spare Parts • Power Circuitry Tests (excitation supply transformer, rotating exciter, rectifier

bridge, AC and DC circuit breakers, etc.) • Control Circuitry Tests (electronic circuits, power supplies, control logic, etc.)

These condition indicators are initially evaluated using Tier 1 inspections, tests, and measurements, which are conducted by utility staff or contractors over the course of time and as a part of routine maintenance activities. Numerical scores are assigned to each condition indicator, which are then weighted and summed to determine the Excitation System Condition Index. An additional stand-alone indicator is used to reflect the quality of the information available for scoring the Excitation System Condition Index. In some cases, data may be missing, out-of-date, or of questionable integrity. Any of these situations could affect the validity of the overall Condition Index. Given the potential impact of poor or missing data, the Data Quality Indicator is used as a means of evaluating and recording confidence in the final Excitation System Condition Index. The appendix also describes Tier 2 tests that may be applied to excitation systems depending on utility practice. Tier 2 tests are considered non-routine. However, if Tier 2 data is readily available, it may be used to supplement the Tier 1 assessment. Alternatively, Tier 2 tests may be deliberately performed to address Tier 1 findings. Results of the Tier 2 analysis may either increase or decrease the score of the Excitation System Condition Index. The Data Quality Indicator score may also be revised during the Tier 2 assessment to reflect the availability of additional information or test data. Note: A severely negative result of ANY inspection, test, or measurement may be adequate in itself to require immediate de-energization, or prevent re-energization, of the excitation system regardless of the Excitation System Condition Index score. E4.4 INSPECTIONS, TESTING, AND MEASUREMENTS Inspections, tests, and measurements should be conducted and analyzed by staff suitably trained and experienced in excitation system diagnostics. Qualified local staff members may perform some basic tests. More complex inspections and measurements may require an excitation system diagnostics “expert”.

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Inspections, tests, and measurements should be conducted on a frequency that provides the accurate and current information needed by the assessment. Excitation system condition assessment may cause concerns that justify more frequent monitoring. Utilities should consider the possibility of installing an on-line monitoring system that will continuously track critical quantities. This will provide additional data for condition assessment and establish a certain amount of reassurance as excitation system alternatives are being explored. E4.5 SCORING Excitation System Condition Indicator scoring is somewhat subjective, relying on excitation system condition experts. Relative terms such as “Results Normal” and “Degradation” refer to results that are compared to industry accepted levels; or to baseline or previous (acceptable) levels on this equipment; or to equipment of similar design, construction, or age operating in a similar environment. E4.6 WEIGHTING FACTORS Weighting factors used in the condition assessment methodology recognize that some Condition Indicators may affect the Excitation System Condition Index to a greater or lesser degree than other indicators. These weighting factors were arrived at by consensus among excitation system design and maintenance personnel with extensive experience. E4.7 MITIGATING FACTORS Every excitation system is unique and therefore the methodology described in this guide cannot quantify all factors that affect individual excitation system condition. It is important that the Excitation System Condition Index arrived at be scrutinized by engineering experts. Mitigating factors specific to the utility may determine the final Condition Index and the final decision on excitation system replacement. E4.8 DOCUMENTATION Substantiating documentation is essential to support findings of the assessment, particularly where a Tier 1 Condition Indicator score is less than 3 or where a Tier 2 test results in subtractions from the Excitation System Condition Index. Test results and reports, photographs, O & M records, or other documentation should accompany the Excitation System Condition Assessment Summary Form.

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E4.9 CONDITION ASSESSMENT METHODOLOGY The condition assessment methodology consists of analyzing each Condition Indicator individually to arrive at a Condition Indicator Score. The score is then weighted and summed with scores from other condition indicators to determine the Excitation System Condition Index. The Condition Index is applied to the Excitation System Condition-Based Alternatives table (Table 8) to determine the recommended course of action. Reasonable efforts should be made to perform Tier 1 inspections, tests, and measurements. However, when data is missing to properly score the Condition Indicator, it may be assumed that the score is “Good” or numerically some mid-range number such as 2. Caution: This strategy should be used judiciously to prevent misleading results. In recognition of the potential impact of poor or missing data, a separate Data Quality Indicator is rated as a means of evaluating and recording confidence in the final Excitation System Condition Index. E4.10 TIER 1 – INSPECTIONS, TESTS, AND MEASUREMENTS Condition Indicator 1 – Age During operation, excitation systems are continuously subjected to electrical, mechanical, thermal, and environmental stresses. Over time, these stresses act and interact in complex ways to deteriorate certain components in the excitation system and possibly leading to unexpected, catastrophic failure and forced outage. Age is one indicator of remaining life of the excitation system and is an important factor to consider when identifying candidates for replacement. The average life expectancy of previous excitation systems was about 30 years. However, it is difficult to predict life expectancy for newer digital systems where computer software/hardware may become obsolete in a few years and long-term experience with digital systems is not yet available. Accordingly, comparisons to average equipment age industry-wide may be of value. While age is a useful indicator of remaining life and upgrade potential, it is also important to recognize that the actual service life that can be realized varies widely depending on the specific manufacturer, date of manufacture, design, materials, production methods, quality of installation, material in the supply transformer and cables, and the operation and maintenance history. Qualified personnel should make a determination of scoring that encompasses as many aging factors as possible under this indicator. Results are analyzed and applied to Table 1 to arrive at a Condition Indicator Score.

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Table 1 – Age Scoring

Age Condition Indicator Score

< 10 years + 2

≥ 10 and < 20 years + 1

≥ 20 and < 30 years 0

≥ 30 and < 40 years - 3

≥ 40 years - 4 Condition Indicator 2 – Operation and Maintenance History

Operation and maintenance (O & M) history may indicate overall excitation system condition. O & M history factors that may apply are listed below. Depending on the age of the excitation system, some of the following items may not be applicable:

• Motor operated adjuster (motor and potentiometer condition); • Supply transformer maintenance history; • Power bridge maintenance history; • Circuit breakers (AC supply and DC field breakers) maintenance history; • Premature component failures; • Abnormally high temperatures in supply transformer (via infrared scanning); • Abnormally high temperatures in power bridge (via infrared scanning); • Abnormally high temperatures in bus bar connections (via infrared scanning); • Commutator pitting and/or premature brush failure; • Problems with auxiliary systems (airflow sensors, fans, control relays, etc.); • Deteriorated control and protection wiring and devices; • Increase in corrective maintenance or difficulty in acquiring spare parts; • Anomalies determined by physical inspection; • Previous failures on this equipment; • Known failures or problems with equipment of similar design, construction, or age

occurring on adjacent units or in other plants; • Frequent diagnostic or failure alarms or tripping.

Qualified personnel should make a subjective determination of scoring that encompasses as many operation and maintenance factors as possible under this indicator. Results are analyzed and applied to Table 2 to arrive at a Condition Indicator Score.

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Table 2 – Operation and Maintenance History Scoring

Results Condition Indicator Score

Operation and Maintenance are normal. + 2

Some additional maintenance above normal occurring.

+ 1

Significant additional maintenance is required; or forced outage or unit trip occurs; or outages are regularly extended due to maintenance problems; or similar units are problematic.

- 2

Repeated forced outages; maintenance not cost effective; or severe mechanical/electrical problems; or similar units have failed.

- 4

Condition Indicator 3 – Availability of Spare Parts Excitation systems consist of a large number of components and many spare parts are purchased when the systems are purchased and installed. In addition to the spare parts stored on the premises, the availability of replacement parts from the manufacturer is an important consideration. This applies particularly to electronic components, which tend to have short production life spans. A variety of factors may be considered when evaluating the availability of spare parts, such as the level of impact a component may have on the operation of the excitation system. Limited operation may be possible upon failure of some components, whereas others may be critical to operation. Peripheral systems necessary to program or diagnose digital systems should also be considered. Because computer software has a short life span, compatibility becomes difficult over time, and hardware and software standards become obsolete. Qualified personnel should make a determination of scoring that encompasses as many factors as possible under this indicator. Results are analyzed and applied to Table 3 to arrive at a Condition Indicator Score.

Table 3 – Availability of Spare Parts Scoring

Results Condition Indicator Score

Spare parts are readily available. + 2

Some spare parts are not readily available, but are still in production. 0

Some spare parts are not readily available or in production, but can be obtained on a limited basis or reproduced.

- 1

Spare parts are unavailable. - 3

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Condition Indicator 4 – Power Circuitry Tests Elements of the power circuit consist of various combinations of power transformers, DC or AC generators, amplidynes, circuit breakers, power cables, rectifier bridges, field flashing equipment, etc. Requirements for many of the elements will be included in standard plant equipment maintenance documents. For example, maintenance, performance, repair, or replacement schedules are usually specified in manufacturer's instruction and maintenance manuals. In cases where elements are found to be deficient, repair or replacement of a single component may be the most appropriate solution, although replacement of other components or entire systems may sometimes be appropriate. Qualified personnel should make a determination of scoring that encompasses as many factors as possible under this indicator. Results are analyzed and applied to Table 4 to arrive at a Condition Indicator Score.

Table 4 – Power Circuitry Scoring

Results Condition Indicator Score

Power circuit elements are normal. + 2

One power circuit element assessment indicates minor deficiencies. - 1

More than one minor deficiency in power circuit. - 2

Severe power circuit component deficiency. - 5 Condition Indicator 5 – Control Circuitry Tests Elements of the control circuit consist of various combinations of electronics, power supplies, control logic, relays, digital controllers, magnetic amplifiers, etc. In most cases, replacement of a single problematic component may be the most appropriate solution, although replacement of other components or entire systems may be necessary, depending on the level of integration versus modularity. Excitation system control circuits incorporate many critical functions of the generator operation, such as voltage regulation, limiters and protective functions, stabilizers, etc. Different components may have varying impacts on the operation of the excitation system. For example, limited operation may be possible upon failure of some components, whereas others may prevent operation of the generator. In fact, problems in excitation system control circuits are likely to manifest as generator misoperations. Thorough evaluation of control circuitry will likely have to be conducted by specialists, although it may be standard operating practice (possibly reinforced by national and/or regional reliability council requirements) to perform specialized, detailed testing of these systems on a periodic basis. The most current reports of such required tests may be valuable in this assessment.

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Attention should also be paid to whether the excitation system meets the stability requirements specified by the reliability councils, etc. More detailed testing of excitation systems is listed as a Tier 2 assessment. Qualified personnel should make a determination of scoring that encompasses as many factors as possible under this indicator. Results are analyzed and applied to Table 5 to arrive at a Condition Indicator Score.

Table 5 – Control Circuitry Scoring

Results Condition Indicator Score

Control circuitry is functioning normally, stability requirements met. + 2

Minor variations in functionality, stability requirements met. + 1

Major variations in functionality, or stability performance marginal. - 2

Elements of control circuits are non-functional, or stability requirements not met. - 5

E4.11 TIER 1 – EXCITATION SYSTEM CONDITION INDEX CALCULATIONS Enter the Condition Indicator Scores from the tables above into the Excitation System Condition Assessment Summary form at the end of this guide. Multiply each condition indicator score by its corresponding Weighting Factor, and sum the Total Scores to arrive at the Tier 1 Excitation System Condition Index. If the result yields a negative value, set the Condition Index score to zero. Suggested alternatives for follow up action, based on the Excitation System Condition Index, are described in the Excitation System Condition-Based Alternatives at the end of this guide. E4.12 TIER 1 – DATA QUALITY INDICATOR Data Quality Indicator – Quality of Inspections, Tests, and Measurements The Data Quality Indicator reflects the quality of the inspection, test and measurement results used to evaluate the condition of the excitation system. The more current and complete the results are, the higher the rating for this indicator. The normal testing frequency is defined as the organization’s recommended frequency for performing the specific test or inspection. Qualified personnel should make a determination of scoring that encompasses as many factors as possible under this indicator. Results are analyzed and applied to Table 6 to arrive at an appropriate Data Quality Indicator Score.

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Table 6 – Data Quality Scoring

Results Data Quality Indicator Score All Tier 1 inspections, tests and measurements were completed within the normal testing frequency.

10

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 6 and < 24 months past the normal testing frequency.

7

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 24 and < 36 months past the normal testing frequency, or some of the results are not available.

4

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 36 months past the normal frequency, or no results are available.

0

Enter the Excitation System Data Quality Indicator Score from Table 6 into the Excitation System Condition Assessment Summary form at the end of this document. E4.13 TIER 2 – INSPECTIONS, TESTS, AND MEASUREMENTS Tier 2 inspections, tests, and measurements generally require specialized equipment or training, may be intrusive, or may require an extended outage to perform. Tier 2 assessment is considered non-routine. Tier 2 inspections may affect the Excitation System Condition Index number established using Tier 1 and also may confirm or disprove the need for more extensive maintenance, rehabilitation, or excitation system replacement. Test T2.1: Detailed Control Circuitry Tests (Excitation System Realignment) An excitation system realignment is performed by excitation system specialists and includes detailed testing of most excitation system functions, such as regulators, limiters, protection, control functions, stability, etc. Results are analyzed and applied to Table 7 to arrive at an Excitation System Condition Index score adjustment.

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Table 7 – Detailed Control Circuitry Test Scoring

Adjustment to Test Results Excitation System Condition Index

Excitation system is fully operational with no significant functional abnormalities. Some readjustment may be necessary.

No Change

Excitation system is operational, but abnormalities are detected. Significant adjustment or repair is necessary.

Subtract 1.0

Excitation system has components that are not operational.*

To be determined by an excitation system specialist.

*May indicate a serious problem requiring immediate evaluation. Generator and power system reliability may be compromised. Test T2.2: Other Specialized Diagnostic Tests Additional tests may be applied to evaluate specific excitation system problems. Some of these diagnostic tests may be considered to be of an investigative research nature. When conclusive results from other diagnostic tests are available, they may be used to make an appropriate adjustment to the Excitation System Condition Index. E4.14 TIER 2 – EXCITATION SYSTEM CONDITION INDEX CALCULATIONS Enter the Tier 2 adjustments from the tables above into the Excitation System Condition Assessment Summary form at the end of this guide. Subtract the sum of these adjustments from the Tier 1 Excitation System Condition Index to arrive at the Net Excitation System Condition Index. If the result yields a negative value, set the Condition Index score to zero. Attach supporting documentation. An adjustment to the Data Quality Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment. E4.15 EXCITATION SYSTEM CONDITION-BASED ALTERNATIVES After review by an excitation system expert, the Excitation System Condition Index – either modified by Tier 2 tests or not – may be sufficient for decision making regarding excitation system alternatives. The Index is also suitable for use in a risk-and-economic analysis model. Where it is desired to consider alternatives based solely on excitation system condition, the Excitation System Condition Index may be directly applied to Table 8.

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Table 8 – Excitation System Condition-Based Alternatives

Excitation System Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat condition assessment as needed.

≥ 3.0 and < 7 (Fair) Continue operation but reevaluate O & M practices. Consider using appropriate Tier 2 tests. Repeat condition assessment process as needed.

≥ 0 and < 3.0 (Poor) Immediate evaluation including additional Tier 2 testing. Consultation with experts. Adjust O & M as prudent. Begin replacement/rehabilitation process.

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EXCITATION SYSTEM TIER 1 CONDITION ASSESSMENT SUMMARY

Date: ________________________ Location: ________________________________________

Excitation System Identifier: ____________ Manufacturer: ______________ Yr. Mfd.: _______

No. of Phases: ___________________ MVA: __________________ Voltage: ______________

Tier 1 Excitation System Condition Summary

(For instructions on indicator scoring, please refer to condition assessment guide)

No. Condition Indicator Score × Weighting Factor = Total Score

1 Age (Score must be 2, 1, 0, -3, or -4) 1

2 O & M History (Score must be 2, 1 ,-2, or -4) 1

3 Availability of Spare Parts (Score must be 2, 0, -1, or -3) 1

4 Power Circuitry Tests (Score must be 2, -1, -2, or -5) 1

5 Control Circuitry Tests (Score must be 2, 1, -2, or -5) 1

Tier 1 Excitation System Condition Index (Sum of individual Total Scores. A negative result should be set to a value of zero.)

(Condition Index should be between 0 and 10)

Tier 1 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

Evaluator: _________________________ Technical Review: __________________________

Management Review: ________________ Copies to: _________________________________

(Attach supporting documentation.)

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Condition-Based Alternatives

Excitation System Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat condition assessment as needed.

≥ 3.0 and < 7 (Fair) Continue operation but reevaluate O & M practices. Consider using appropriate Tier 2 tests. Repeat condition assessment process as needed.

≥ 0 and < 3.0 (Poor) Immediate evaluation including additional Tier 2 testing. Consultation with experts. Adjust O & M as prudent. Begin replacement/rehabilitation process.

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EXCITATION SYSTEM TIER 2 CONDITION ASSESSMENT SUMMARY

Date: ________________________ Location: ________________________________________

Excitation System Identifier: ____________ Manufacturer: ______________ Yr. Mfd.: _______

No. of Phases: ___________________ MVA: __________________ Voltage: ______________

Tier 2 Excitation System Condition Summary

Adjustment to Tier 1 No. Tier 2 Test Condition Index

T2.1 Detailed Control Circuitry Test T2.2 Other Specialized Diagnostic Tests

Tier 2 Adjustments to Excitation System

Condition Index (Sum of individual Adjustments)

Tier 2 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

To calculate the Net Excitation System Condition Index (Value should be between 0 and 10), subtract the Tier 2 Adjustments from the Tier 1 Condition Index: Tier 1 Excitation System Condition Index __________

minus Tier 2 Adjustments __________ = ______________

Net Excitation System Condition Index

Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________

(Attach supporting documentation.)

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September 2006 Hydro Plant Risk Assessment Guide Appendix E5: Transformer Condition Assessment E5.1 GENERAL Power transformers are key components in the power train at hydroelectric powerplants and are appropriate for analysis under a condition assessment program. Transformer failure can have a significant economic impact due to long lead times in procurement, manufacturing, and installation in addition to high equipment cost. According to the Electric Power Research Institute (EPRI), “Extending the useful life of power transformers is the single most important strategy for increasing life of power transmission and distribution infrastructures, starting with generator step-up transformers (GSU) at the powerplant itself.” (EPRI Report # 1001938.) Determining the present condition of a power transformer is an essential step in analyzing the risk of failure. This appendix provides a process for arriving at a Transformer Condition Index which may be used to develop a business case addressing risk of failure, economic consequences, and other factors. E5.2 SCOPE / APPLICATION The transformer condition assessment methodology outlined in this appendix applies to oil-filled power transformers (> 500 kVA) currently in operation. This guide is not intended to define transformer maintenance practices or describe in detail transformer condition assessment inspections, tests, or measurements. Utility maintenance policies and procedures must be consulted for such information. E5.3 CONDITION AND DATA QUALITY INDICATORS AND TRANSFORMER CONDITION INDEX The following four condition indicators are generally regarded by hydro powerplant engineers as providing a sound basis for assessing transformer condition:

• Insulating Oil Analysis (DGA and Furan) • Power Factor and Excitation Current Tests • Operation and Maintenance History • Age

These condition indicators are initially evaluated using Tier 1 inspections, tests, and measurements, which are conducted by utility staff or contractors over the course of time and as

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a part of routine maintenance activities. Numerical scores are assigned to each condition indicator, which are then weighted and summed to determine the Transformer Condition Index. An additional stand-alone indicator is used to reflect the quality of the information available for scoring the Transformer Condition Index. In some cases, data may be missing, out-of-date, or of questionable integrity. Any of these situations could affect the accuracy of the associated condition indicator scores as well as the validity of the condition index. Given the potential impact of poor or missing data, the Data Quality Indicator is used as a means of evaluating and recording confidence in the final Transformer Condition Index. Additional information regarding transformer condition may be necessary to improve the accuracy and reliability of the Transformer Condition Index. Therefore, in addition to the Tier 1 condition indicators, this Guide describes a “toolbox” of Tier 2 inspections, tests, and measurements that may be applied to the Transformer Condition Index, depending on the specific issue or problem being addressed. Tier 2 tests are considered non-routine. However, if Tier 2 data is readily available, it may be used to supplement the Tier 1 assessment. Alternatively, Tier 2 tests may be deliberately performed to address Tier 1 findings. Results of the Tier 2 analysis may either increase or decrease the score of the Transformer Condition Index. The Data Quality Indicator score may also be revised during the Tier 2 assessment to reflect the availability of additional information or test data. The Transformer Condition Index may indicate the need for immediate corrective actions and/or follow-up Tier 2 testing. The Transformer Condition Index is also suitable for use as an input to a risk-based economic analysis model. Note: A severely negative result of ANY inspection, test, or measurement may be adequate in itself to require immediate de-energization, or prevent re-energization, of the transformer regardless of the Transformer Condition Index score. E5.4 INSPECTIONS, TESTS, AND MEASUREMENTS The hierarchy of inspections, tests, and measurements is illustrated in Figure 1 (Transformer Condition Assessment Methodology). Table 16 briefly describes the activities related to conducting the transformer condition assessment. Inspections, tests, and measurements should be conducted and analyzed by staff suitably trained and experienced in transformer diagnostics. Qualified staff that is competent in these routine procedures may conduct the basic tests and inspections. More complex inspections and measurements may require a transformer diagnostics “expert”. This guide also assumes that inspections, tests, and measurements are conducted on a frequency that provides the accurate and current information needed by the assessment. Results of the transformer condition assessment may cause concerns that justify more frequent monitoring. Utilities should consider the possibility of taking more frequent measurements (e.g., oil samples) or installing on-line monitoring systems (e.g., gas-in-oil) that will continuously track critical quantities. This will provide additional data for condition assessment and establish

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a certain amount of reassurance as transformer alternatives are being explored. Inspection, testing, and measurement methods are specified in technical references specific to the electric utility. E5.5 SCORING Transformer condition indicator scoring is somewhat subjective, relying on transformer condition experts. Relative terms such as “Results Normal” and “Degradation” refer to results that are compared to industry accepted levels; or to baseline or previous (acceptable) levels on this equipment; or to equipment of similar design, construction, or age operating in a similar environment. E5.6 WEIGHTING FACTORS Weighting factors used in the condition assessment methodology recognize that some condition indicators affect the Transformer Condition Index to a greater or lesser degree than other indicators. These weighting factors were arrived at by consensus among transformer design and maintenance personnel with extensive experience. E5.7 MITIGATING FACTORS Every transformer is unique and, therefore, the methodology described in this appendix cannot quantify all factors that affect individual transformer condition. It is important that the Transformer Condition Index arrived at be scrutinized by engineering experts. Mitigating factors specific to the utility may determine the final Transformer Condition Index and the final decision on transformer replacement or rehabilitation. E5.8 DOCUMENTATION Substantiating documentation is essential to support findings of the assessment, particularly where a Tier 1 condition indicator score is less than 3 (i.e., less than normal) or where a Tier 2 test results in subtractions from the Transformer Condition Index. Test results and reports, photographs, O & M records, or other documentation should accompany the Transformer Condition Assessment Summary Form. E5.9 CONDITION ASSESSMENT METHODOLOGY The condition assessment methodology consists of analyzing each condition indicator individually to arrive at a condition indicator score. The scores are then weighted and summed to determine the Transformer Condition Index. The Transformer Condition Index is applied to the Transformer Condition-Based Alternatives, Table 15, to determine the recommended course of action.

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Reasonable efforts should be made to perform Tier 1 inspections, tests, and measurements. However, when data is unavailable to properly score a condition indicator, it may be assumed that the score is “Good” or numerically equal to some mid-range number such as 2. This strategy must be used judiciously to prevent erroneous results and conclusions. In recognition of the potential impact of poor or missing data, a separate Data Quality Indicator is rated as a means of evaluating and recording confidence in the final Generator Condition Index. E5.10 TIER 1 – INSPECTIONS, TESTS, AND MEASUREMENTS Tier 1 inspections, tests, and measurements are routinely accomplished as part of normal operation and maintenance, or are readily discernible by examination of existing data. Tier 1 test results are quantified below as condition indicators that are weighted and summed to arrive at a Transformer Condition Index. Tier 1 inspections, tests, and measurements may indicate abnormal conditions that can be resolved with standard corrective maintenance solutions. Tier 1 test results may also indicate the need for additional investigation, categorized as Tier 2 tests. Transformer Condition Indicator 1 – Insulating Oil Analysis Dissolved gas analysis is the most important factor in determining the condition of a transformer. Being performed more frequently than other tests, it may be the first indication of a problem. Insulating oil analysis can identify internal arcing, bad electrical contacts, hot spots, partial discharge, or overheating of conductors, oil, tank, or cellulose. The “health” of the oil reflects the health of the transformer itself. Dissolved gas analysis (DGA) consists of drawing transformer insulating oil samples from the transformer tank and sending the samples to a commercial laboratory for analysis. The most important indicators are the individual and total dissolved combustible gas (TDCG) generation rates, based on IEC and IEEE standards. Although gas generation rates are not the only indicator, they are reasonable for use in determining the condition indicator score. Furanic analysis may indicate a problem with the paper insulation which could affect transformer longevity. A baseline furanic analysis should be made initially and repeated if the transformer is overheated, overloaded, aged, or after changing or processing the oil. Physical tests such as interfacial tension (IFT), acidity, moisture content, and dielectric strength usually indicate oil conditions that can be remedied through various reclamation processes. Therefore, they are not indicative of overall transformer condition that would lead to replacement. Such tests do not affect the Insulating Oil Condition Indicator score. Results of the insulating oil analysis are applied to Table 1 to arrive at an appropriate Condition Indicator Score.

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Table 1 – Insulating Oil Analysis Scoring Results (See Notes 1 & 2) Condition Indicator Score {Total Dissolved Combustible Gas (TDCG) generation rate < 30 ppm (parts per million)/month AND all individual combustible gas generation < 10 ppm/month. Exceptions: CO generation < 70 ppm/month AND acetylene (C2H2) generation rate = 0 ppm.}

AND {2 FAL Furans < 150 ppb (parts per billion). (See Note 3)}

3

{TDCG generation rate ≥ 30 and < 50 ppm/month AND all individual combustible gas generation rates < 15 ppm/month. Exceptions: CO generation rate < 150 ppm/month AND C2H2 generation rate = 0 ppm.}

OR {2 FAL Furans ≥ 150 and < 200 ppb. (See Note 3)}

2

{TDCG generation rate ≥ 50 and < 80 ppm/month AND all individual combustible gas generation rates < 25 ppm/month. Exceptions: CO generation rate < 350 ppm/month AND C2H2 generation rate < 5 ppm/month.}

OR {2 FAL Furans ≥ 200 and < 250 ppb. (See Note 3)}

1

{TDCG generation rate ≥ 80 ppm/month AND any individual combustible gas generation rate > 50 ppm/month. Exceptions: CO generation ≥ 350 ppm/month AND C2H2 generation rate < 10 ppm/per month.}

OR {2 FAL Furans ≥ 250 ppb. (See Note 3)}

0

Note 1: The above DGA numbers are based on dissolved gas in oil generation rates and come from a combination of IEEE C57-104, IEC 60599 and Delta X Research’s Transformer Oil Analysis (TOA) software. Note 2: Any ongoing acetylene (C2H2) generation indicates an active arcing fault and the transformer may have to be removed from service to avoid possible catastrophic failure. A transformer may be safely operated with some C2H2 showing in the DGA. C2H2 sometimes comes from a one-time event such as a close-in lightning strike or through fault. However, if C2H2 is increasing more than 10 ppm per month, the transformer should be removed from service. Because acetylene generation is a critical indicator of transformer internal condition, each utility should establish practices in accordance with published standards and recommendations from transformer experts. Increases in gas generation should be monitored and corrective actions taken as appropriate. Increasing the frequency of DGA analysis and de-gasifying the transformer oil are potential alternatives to consider. Note 3: Furan limits in the table are for thermally upgraded paper. For non-thermally upgraded paper, i.e., rated 55 degrees C maximum, divide the lab test result Furan values by 3 before

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applying them to the table. Non-thermally upgraded paper emits approximately 3 times more Furans before a problem is indicated. Transformer Condition Indicator 2 – Power Factor and Excitation Current Tests Power factor insulation testing is important to determining the condition of the transformer because it can detect winding and bushing insulation integrity. Power factor and excitation current tests are conducted in the field on de-energized, isolated, and properly grounded transformers. Excitation current tests measure the single-phase voltage, current, and phase angle between them, typically on the high-voltage side with the terminals of the other winding left floating (with the exception of a grounded neutral). The measurements are performed at rated frequency and usually at test voltages up to 10 kV. The test detects shorted turns, poor tap changer contacts, and core problems. Results of the power factor and excitation current tests are analyzed and applied to Table 2 to arrive at an appropriate Condition Indicator Score.

Table 2 – Power Factor and Excitation Current Test Scoring

Test Results* Condition Indicator ScorePower factor results normal. (Good – G)

AND Normal excitation current values and patterns compared to other phases and prior tests.

3

Power factor results show minor degradation. (Deteriorated – D) OR

Minor deviation in excitation current values and patterns compared to other phases and prior tests. **

2

Power factor results show significant deterioration. (Investigate – I) OR

Significant deviation in current values and patterns compared to other phases and prior tests. **

1

Power factor results show severe degradation. (Bad – B) OR

Severe deviation in current values and patterns compared to other phases and prior tests. **

0 (May indicate serious

problem requiring immediate evaluation,

additional testing, consultation with experts,

and remediation prior to re-energization.)

* Doble insulation rating shown in parentheses. ** Be sure to account for residual magnetism and tap changer position.

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Transformer Condition Indicator 3 – Operation and Maintenance History Operation and maintenance (O & M) history may indicate overall transformer condition. O & M history factors that may apply are:

• Sustained overloading; • Unusual operating temperatures indicated by gauges and continuous monitoring; • Abnormal temperatures indicated by infrared scanning; • Nearby lightning strikes or through faults; • Abnormally high corona detected; • Abnormally high external temperatures detected; • Problems with auxiliary systems (fans, radiators, cooling water piping, pumps,

motors, controls, nitrogen replenishment system, and indicating and protection devices);

• Deteriorated control and protection wiring and devices; • Increase in corrective maintenance or difficulty in acquiring spare parts; • Anomalies determined by physical inspection* (e.g., incorrectly positioned valves,

plugged radiators, stuck temperature indicators and level gages, noisy oil pumps or fans, oil leaks, connections to bushings);

* External inspection or internal inspection not requiring untanking. • Previous failures on this equipment; • Failures or problems on equipment of similar design, construction, or age operating in

a similar environment. Qualified personnel should make a subjective determination of scoring that encompasses as many operation and maintenance factors as possible under this Indicator. Results of the O & M history are analyzed and applied to Table 3 to arrive at an appropriate Condition Indicator Score.

Table 3 – Operation and Maintenance History Scoring

History Results Condition Indicator Score

Operation and Maintenance are normal. 3

Some abnormal operating conditions experienced and/or additional maintenance above normal occurring.

2

Significant operation outside normal and/or significant additional maintenance is required; or forced outage occurs; or outages are regularly extended due to maintenance problems; or similar units are problematic.

1

Repeated forced outages; maintenance not cost effective; or major oil leaks and/or severe mechanical problems; or similar units have failed.

0

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Transformer Condition Indicator 4 – Age Transformer age is an important factor to consider when identifying candidates for transformer replacement. Age is one indicator of remaining life and upgrade potential to current state-of-the-art materials. During the life of the transformer, the mechanical and insulating properties of materials which are used for structural support and electrical insulation, especially wood and paper, deteriorate. Although actual service life varies widely depending on the manufacturer’s design, quality of assembly, materials used, operating history, current operating conditions, and maintenance history, the average expected life for an individual transformer in a large population of transformers is statistically about 40 years. Apply the transformer age to Table 4 to arrive at the Condition Indicator Score.

Table 4 – Age Scoring

Age Condition Indicator Score

< 30 years 3

≥ 30 and < 45 years 2

≥ 45 years 1

E5.11 TIER 1 – TRANSFORMER CONDITION INDEX CALCULATIONS Enter the condition indicator scores from the tables above into the Transformer Condition Assessment Summary form at the end of this document. Multiply each condition indicator score by the Weighting Factor, and sum the Total Scores to arrive at the Tier 1 Transformer Condition Index. E5.12 TIER 1 – TRANSFORMER DATA QUALITY INDICATOR The Transformer Data Quality Indicator reflects the quality of the inspection, test and measurement results used to evaluate the transformer condition under Tier 1. The more current and complete the inspections, tests, and measurements, the higher the rating for this indicator. The normal testing frequency is defined as the organization’s recommended frequency for performing the specific test or inspection. Qualified personnel should make a subjective determination of scoring that encompasses as many factors as possible under this indicator. Results are analyzed and applied to Table 5 to arrive at a Transformer Data Quality Indicator Score.

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Table 5 –Transformer Data Quality Scoring

Results Data Quality Indicator Score All Tier 1 inspections, tests and measurements were completed within the normal testing frequency and the results are reliable.

10

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 6 and < 24 months past the normal testing frequency and the results are reliable.

7

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 24 and < 36 months past the normal testing frequency, or some of the results are not available or are of questionable integrity.

4

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 36 months past the normal frequency, or no results are available or many are of questionable integrity.

0

Enter the Transformer Data Quality Indicator Score from Table 5 into the Transformer Condition Assessment Summary form at the end of this document. E5.12 TIER 2 – INSPECTIONS, TESTS, AND MEASUREMENTS Tier 2 inspections, tests, and measurements generally require specialized equipment or training, may be intrusive, or may require an extended outage to perform. A Tier 2 assessment is not considered routine. Tier 2 inspections are intended to affect the Transformer Condition Index number established using Tier 1 but also may confirm or refute the need for more extensive maintenance, rehabilitation, or transformer replacement. Note that there are many tests that can give information about the various aspects of transformer condition. The choice of tests should be made based on known information gathered by inspection history, other test results, company standards, and Tier 1 assessment. Many Tier 2 tests are used to detect or confirm a similar defect in the condition of the transformer. In the event that several Tier 2 tests are performed that assess the same condition issue, the test with the largest adjustment should be used in recalculating the Condition Index. Since Tier 2 tests are being performed by, and/or coordinated with, knowledgeable technical staff, the decision on which test is most significant and how these tests overlap in application is left to the experts. The important factor is to avoid adjusting the Condition Index downward twice or more simply because two or more tests are completed for the same suspected condition. For Tier 2 evaluations, apply only the applicable adjustment factors per the instructions above and recalculate the Transformer Condition Index using the Transformer Condition Assessment Survey Form at the end of this document. An adjustment to the Data Quality Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment.

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Test T2.1: Turns Ratio Test The transformer turns ratio (TTR) test detects shorts or severe tracking between turns of the same coil, which indicates insulation failure between the turns. These tests are performed with the transformer de-energized and may show the necessity for an internal inspection or removal from service. Results are analyzed and applied to Table 6 to arrive at a Transformer Condition Index adjustment.

Table 6 – Turns Ratio Test Scoring

Adjustment to Test Results Transformer Condition Index < 0.20 percent difference from nameplate voltage ratio (V1/V2) and compared to previous readings.

No Change

≥ 0.20 and < 0.50 percent difference compared to nameplate voltage ratio (V1/V2).

Subtract 1.0

≥ 0.50 percent difference compared to nameplate voltage ratio (V1/V2).

Subtract 5.0 (May indicate serious problem requiring immediate

evaluation, additional testing, consultation with experts, and remediation prior to re-energization.)

Test T2.2: Short Circuit Impedance Test Sometimes called Percent Impedance or Leakage Reactance, these tests are conducted in the field and compared to nameplate information, previous tests, and similar units to detect deformation of the core or windings caused by shipping damage, through faults, or ground faults. Some difference may be expected between nameplate and field test results because factory tests are conducted at full load current, normally not possible in the field. Field connections and test leads and jumpers also play a significant role in test results and it is impossible to exactly duplicate the factory test setup. Therefore, the I2R power losses may be different and cause different test results. By comparing percent-reactance to nameplate impedance, the differences caused by leads and connections can be eliminated. Because reactance is only the inductive component of the impedance, I2 R power losses are omitted in the test results. Results are analyzed and applied to Table 7 to arrive at a Transformer Condition Index score adjustment.

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Table 7 – Short Circuit Impedance Test Scoring

Adjustment to Test Results Transformer Condition Index

< 1 percent difference from nameplate impedance. No Change

≥ 1 and < 3 percent difference from nameplate impedance. (Minor degradation.) Subtract 0.5

≥ 3 and < 5 percent difference from nameplate impedance. (Significant degradation.) Subtract 1.0

≥ 5 percent difference from nameplate impedance. (Severe degradation.)

Subtract 5.0 (May indicate serious problem requiring immediate evaluation, additional testing,

consultation with experts, and remediation prior to re-energization.)

Test T2.3: Core-to-Ground Resistance (Megger) Test The transformer core is intentionally grounded through one connection. The core-to-ground resistance test can detect if this connection is loose. It can also detect whether there are other undesired and inadvertent, grounds. If the intentional core ground is intact, the resultant resistance should be very low. To check for unintentional core grounds, remove the intentional ground and megger between the core and the grounded transformer tank. This test should produce very high resistance, indicating that an unintentional ground is not present. This test is to supplement dissolved gas analysis that shows generation of hot metal gases (i.e., methane, ethane, and ethylene) and to indicate if a spurious, unintentional core ground is the problem. Experience can help locate the source of the problem. Results are analyzed and applied to Table 8 to arrive at a Transformer Condition Index adjustment.

Table 8 – Core-to-Ground Resistance Test Scoring

Adjustment to Test Results* Transformer Condition Index

≥ 1,000 megaohms. (Results normal.) No Change

≥ 500 and < 1000 megaohms. Subtract 0.5

≥ 200 and < 500 megaohms. Subtract 1.0

< 200 megaohms.

Subtract 5.0 (May indicate serious problem requiring immediate

evaluation, additional testing, consultation with experts, and remediation prior to re-energization.)

* With intentional ground disconnected.

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Test T2.4: Winding Direct-Current Resistance Measurement Careful measurement of winding resistance can detect broken conductor strands, loose connections, and bad contacts in the tap changer (DETC or LTC). Results from these measurements may indicate the need for an internal inspection. This information supplements dissolved gas analysis (DGA) and is useful when DGA shows generation of heat gases (i.e., ethane, ethylene, methane). These tests are typically performed with a micro-ohmmeter and or Wheatstone bridge. Test results are compared between phases or with factory tests. When comparing to factory tests, a temperature correction must be employed (IEEE P62). This test should be performed only after the rest of the routine electrical tests because it may magnetize the core, affecting results of the other tests. Results are analyzed and applied to Table 9 to arrive at a Transformer Condition Index adjustment.

Table 9 – Winding Direct-Current Resistance Measurement Scoring

Adjustment to Measurement Results Transformer Condition Index < 5 percent difference between phases or from factory tests. No Change

≥ 5 and < 7 percent difference between phases or from factory tests. Subtract 0.5

≥ 7 and < 10 percent difference between phases or from factory tests. Subtract 1.0

≥ 10 percent between phases or from factory tests.

Subtract 5.0 (May indicate serious problem requiring immediate evaluation, additional testing,

consultation with experts, and remediation prior to re-energization.)

Test T2.5: Ultrasonic and Sonic Fault Detection Measurements These assessment tests (sometimes called Acoustic Testing) are helpful in locating internal faults. Partial discharges (corona) and low energy arcing / sparking emit energy in the range of 50 megahertz (ultrasonic), well above audible sound. To make these measurements, sensors are placed on the outside of a transformer tank to detect these ultrasonic emissions which are then converted electronically to oscilloscope traces or audible frequencies and recorded. By triangulation, a general location of a fault (corona or arcing/sparking) may be determined so that an internal inspection can be focused in that location. These devices also can detect loose shields that build up static and discharge it to the grounded tank; poor connections on bushings; bad contacts on a tap changer that are arcing / sparking; core ground problems that cause sparking / arcing; and areas of weak insulation that generate corona. Sonic testing can detect increased core and coil noise (looseness) and vibration, failing bearings in oil pumps and fans, and nitrogen leaks in nitrogen blanketed transformers.

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Information gained from these measurements supplements dissolved gas analysis, and provides additional supporting information for de-energized tests such as core ground and winding resistance tests. In addition, these tests help pinpoint areas to look for problems during internal inspections. Performing baseline tests may provide comparisons for later tests. Experience can help locate the source of the problem. Results are analyzed and applied to Table 10 to arrive at a Transformer Condition Index adjustment.

Table 10 – Ultrasonic and Sonic Measurement Scoring

Adjustment to Measurement Results Transformer Condition Index

Results normal. No Change

Low level fault indication. Subtract 0.5

Moderate level fault indication. Subtract 1.0

Severe fault level indication. Subtract 2.0 Test T2.6: Vibration Analysis Vibration can result from loose transformer core and coil segments, shield problems, loose parts, or bad bearings on oil cooling pumps or fans. Vibration analyzers are used to detect and measure the vibration. Information gained from these tests supplements ultrasonic and sonic (acoustic) fault detection tests and dissolved gas analysis. Information from these tests may indicate maintenance is needed on pumps or fans mounted external to the tank. It may also show when an internal transformer inspection is necessary. If wedging has been displaced due to paper deterioration or through faults, vibration will increase markedly. This will also show if core and coil vibration has increased compared to baseline information. Experience can help locate the source of the problem. Results are analyzed and applied to Table 11 to arrive at a Transformer Condition Index adjustment.

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Table 11 – Vibration Analysis Scoring

Adjustment to Analysis Results Transformer Condition Index

Results normal. No Change

Low vibration. Subtract 0.5

Moderate vibration. Subtract 1.0

Severe vibration. Subtract 2.0 Test T2.7: Frequency Response Analysis Frequency Response Analysis (FRA) or Sweep Frequency Response Analysis (SFRA) can determine if windings of a transformer have moved or shifted. It can be done as a factory test prior to shipment and repeated after the transformer is received on site to determine if windings have been damaged or shifted during shipping. This test is also helpful if a protective relay has tripped or a through fault, short circuit, or ground fault has occurred A sweep frequency is generally placed on each of the high voltage windings and the signal is detected on the low-voltage windings. This provides a picture of the frequency transfer function of the windings. If the windings have been displaced or shifted, test results will differ markedly from prior tests. Test results are kept in transformer history files so they can be compared to later tests. Results are determined by comparison to baseline or previous measurements or comparison to units of similar design and construction. Results are analyzed and applied to Table 12 to arrive at a Transformer Condition Index adjustment.

Table 12 – Frequency Response Analysis Scoring

Adjustment to Test Results Transformer Condition Index

No deviation compared to prior tests. No Change

Minor deviation compared to prior tests. Subtract 2.0

Moderate deviation compared to prior tests. Subtract 3.0

Significant deviation compared to prior tests. Subtract 4.0

Severe deviation compared to prior tests.

Subtract 5.0 (May indicate serious problem requiring immediate evaluation, additional testing,

consultation with experts, and remediation prior to re-energization.)

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Test T2.8: Internal Inspection In some cases, it is necessary to open the tank, partially or fully drain the oil, and perform an internal inspection to determine transformer condition. These inspections must be performed by experienced staff with proper training. Sludging, loose wedges, loose coils, poor electrical connections on bushing bottoms, burned contacts on tap changers, localized overheating signified by carbon buildup, displaced wedging or insulation, and debris and other foreign material are general areas of concern. Photographs and mapping problem locations are good means of documenting findings. Note: Before entering and while inside the transformer, OSHA, state, local, and utility safety practices must be followed (e.g., “permitted confined space” entry practices). Results are analyzed and applied to Table 13 to arrive at a Transformer Condition Index adjustment.

Table 13 – Internal Inspection Scoring

Adjustment to Inspection Results Transformer Condition Index

Conditions normal. No Change

Minimal degradation. Subtract 0.5

Moderate degradation. Subtract 1.5

Severe degradation.

Subtract 5.0 (May indicate serious problem requiring immediate evaluation, additional testing,

consultation with experts, and remediation prior to re-energization.)

Test T2.9: Degree of Polymerization Winding insulation (cellulose) deterioration can be quantified by analysis of the Degree of Polymerization (DP) of the insulating material. This test gives an indication of the remaining structural strength of the paper insulation and is an excellent indication of the remaining life of the paper and the transformer itself. This requires analyzing a sample of the paper insulation in a laboratory to determine the deterioration of the molecular bonds of the paper. Results are analyzed and applied to Table 14 to arrive at a Transformer Condition Index adjustment.

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Table 14 – Degree of Polymerization Test Scoring

Adjustment to Test Results Transformer Condition Index ≥ 900 and no polymerization decrease. (Results normal.) No Change

≥ 600 and < 900. (Minimal polymerization decrease.) Subtract 0.5

≥ 200 and < 600. (Moderate polymerization decrease.) Subtract 1.5

< 200. (Severe polymerization decrease. Insulation has no mechanical strength; has reached end of life.)

Subtract 5.0 (May indicate serious problem requiring immediate evaluation, additional testing,

consultation with experts, and remediation prior to re-energization.)

Test T2.10: Other Specialized Diagnostic Tests Additional tests may be applied to evaluate specific transformer problems. Some of these diagnostic tests may be considered to be of an investigative research nature. When conclusive results from other diagnostic tests are available, they may be used to make an appropriate adjustment to the Transformer Condition Index. E5.13 TIER 2 – TRANSFORMER CONDITION INDEX CALCULATIONS Enter the Tier 2 adjustments from the tables above into the Transformer Condition Assessment Summary Form at the end of this appendix. Subtract the sum of these adjustments from the Tier 1 Transformer Condition Index to arrive at the total Transformer Condition Index. An adjustment to the Data Quality Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment. E5.14 TIER 2 – TRANSFORMER CONDITION-BASED ALTERNATIVES The Transformer Condition Index – either modified by Tier 2 tests or not – may be sufficient for decision-making regarding transformer alternatives. The Index is also suitable for use in a risk-and-economic analysis model. Where it is desired to consider alternatives based solely on transformer condition, the Transformer Condition Index may be directly applied to the Transformer Condition-Based Alternatives table on the Summary Form.

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Table 15 – Transformer Condition-Based Alternatives

Transformer Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat condition assessment as needed.

≥ 3.0 and < 7 (Fair) Continue operation but reevaluate O & M practices. Consider using appropriate Tier 2 tests. Repeat condition assessment process as needed.

≥ 0 and < 3.0 (Poor) Immediate evaluation including additional Tier 2 testing. Consultation with experts. Adjust O & M as prudent. Begin replacement/rehabilitation process.

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Problem?

Problem

Tier 1 Inspections, Tests, andMeasurements

Oil , Power Factor & Excitation, Routine O&M, Age

Repair, Rehab,Retest

Ultrasonic &Sonic

ContactFault

Detection

UltrasonicNon-Contact

FaultDetection

VibrationAnalysis

TurnsRatio Test

ProblemRepair,Rehab,Retest

ReplaceTransformer

Internal PartialDischarge, Arcing,

Sparking

MechanicalProblems

NitrogenLeaks

Core Shield Problems,Loose Parts

Shorted Winding

TC Contacts, BrokenStrands, Loose

Connections

Winding DCResistance

Measurements

NO

YES*

NO

YES

Return to RoutineInspection & Testing

Figure 1.

Transformer ConditionAssessmentMethodology

transcond 8/6/02

YES

NO

InternalInspection

Results of Inspections,Tests, and Measurementsare Quantified as ConditionIndicators Used to Arrive ata Transformer Condition

Factor.

Core toGround

ResistanceTest

Oil SludgingDisplaced Windings or Wedging

Loose WindingsBad ConnectionsConservator Leaks

Debris

Bad IntentionalGround Connection &Unintentional Ground

TransformerTripped or

Malfunctioned

Tier 2 Tests Below

* Severe problems may warrantimmediate de-enegization

Short CircuitImpedance(Leakage

Reactance)

FrequencyResponse

Degree ofPolymerization

Core / WindingDeformation

ShiftedWindings

Insulation Condition

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Table 16 – Transformer Condition Assessment

Test Detects Tool On-Line Tests:

Dissolved Gas Analysis Internal arcing; bad electrical contacts; hot spots; partial discharge; and overheating of conductors, oil, tank, and cellulose insulation. Requires laboratory analysis.

Oil Physical and Chemical Tests Moisture, degraded interfacial tension (IFT), acidity, furans, dielectric strength, and power factor. Requires laboratory analysis.

External Physical Inspection Oil leaks, broken parts, worn paint, defective support structure, stuck indicators, noisy operation, loose connections, cooling problems with fans, pumps, etc.

Experienced staff and binoculars.

External Temperatures (Main tank and load tap changer) Temperature monitoring with changes in load and ambient temperature. Portable temperature data loggers and software.

Infrared Scan Hot spots indicating localized heating, circulating currents, blocked cooling, tap changer problems, and loose connections. Thermographic camera and analysis software.

Ultrasonic (Acoustic) Contact Fault Detection

Internal partial discharge, arcing, sparking, loose shields, poor bushing connections, bad tap changer contacts, core ground problems, and weak insulation that is causing corona.

Ultrasonic detectors and analysis software.

Sonic Fault Detection Nitrogen leaks, vacuum leaks, core and coil vibration, corona at bushings, and mechanical & bearing problems in pumps and cooling fans.

Ultrasonic probe and meter.

Vibration Analysis Internal core, coil, and shield problems; loose parts and bad bearings. Vibration data logger.

Off-Line Tests: Doble Tests (bushing capacitance, insulation power factor, tip up, excitation current)

Loss of winding insulation integrity, loss of bushing insulation integrity, and winding moisture. Doble test equipment.

Turns Ratio Shorted windings. Doble test equipment or turns ratio tester.

Short Circuit Impedance Deformation of the core or winding. Doble or equivalent test equipment. Core-to-Ground Resistance (External test may be possible depending on transformer construction)

Bad connection on intentional core ground; and existence of unintentional grounds. Megger.

Winding DC Resistance Measurements Broken strands, loose connections, bad tap changer contacts. Wheatstone Bridge (1 ohm and greater),

Kelvin Bridge micro-ohmmeter (less than 1 ohm). Frequency Response Analysis Shifted windings. Doble or equivalent sweep frequency analyzer,

Internal Inspection Oil sludging, displaced winding or wedging, loose windings, bad connections, localized heating, debris and foreign objects. Experienced staff, micro-ohmmeter.

Degree of Polymerization Insulation condition (life expectancy). Laboratory analysis of paper sample.

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TRANSFORMER TIER 1 CONDITION ASSESSMENT SUMMARY

Date: __________________________ Location: _______________________________________

Transformer Identifier: ________________ Manufacturer: _________________ Yr. Mfd.: ______

No. of Phases: ________________ MVA: _____________ Voltage: _______________________

Tier 1 Transformer Condition Summary (For instructions on indicator scoring, please refer to condition assessment guide)

No. Condition Indicator Score × Weighting Factor = Total Score

1 Oil Analysis (Score must be 0, 1, 2, or 3)

1.143

2 Power Factor and Excitation Current Tests (Score must be 0, 1, 2, or 3)

0.952

3 Operation and Maintenance History (Score must be 0, 1, 2, or 3)

0.762

4 Age (Score must be 1, 2, or 3)

0.476

Tier 1 Transformer Condition Index (Sum of individual Total Scores)

(Condition Index should be between 0 and 10)

Tier 1 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________ (Attach supporting documentation.)

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Transformer Condition-Based Alternatives

Transformer Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat condition assessment as needed.

≥ 3.0 and < 7 (Fair) Continue operation but reevaluate O & M practices. Consider using appropriate Tier 2 tests. Repeat condition assessment process as needed.

≥ 0 and < 3.0 (Poor) Immediate evaluation including additional Tier 2 testing. Consultation with experts. Adjust O & M as prudent. Begin replacement/rehabilitation process.

Note: A Transformer Condition Index of zero strongly indicates that the transformer should not be re-energized until repair raises the condition index or the transformer is replaced.

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TRANSFORMER TIER 2 CONDITION ASSESSMENT SUMMARY

Date: __________________________ Location: _______________________________________

Transformer Identifier: ________________ Manufacturer: _________________ Yr. Mfd.: ______

No. of Phases: ________________ MVA: _____________ Voltage: _______________________

Tier 2 Transformer Condition Summary

Adjustment to Tier 2 Test Tier 1 Condition Index

T2.1 Turns Ratio Test

T2.2 Short Circuit Impedance Test

T2.3 Core-to-Ground Resistance (Megger) Test

T2.4 Winding DC Resistance Measurement

T2.5 Ultrasonic and Sonic Fault Detection Measurements

T2.6 Vibration Analysis

T2.7 Frequency Response Analysis

T2.8 Internal Inspection

T2.9 Degree of Polymerization

T2.10 Other Specialized Diagnostic Tests

Tier 2 Adjustments to Transformer Condition Index (Sum of individual adjustments)

Tier 2 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

To calculate the Net Transformer Condition Index (Value should be between 0 and 10), subtract the Tier 2 Adjustments from the Tier 1 Transformer Condition Index: Tier 1 Transformer Condition Index __________ minus Tier 2 Transformer Adjustments __________ = ________________ Net Transformer Condition Index

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Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________

(Attach supporting documentation.)

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September 2006 Hydro Plant Risk Assessment Guide Appendix E6: Turbine Condition Assessment E6.1 GENERAL The hydraulic turbine is a critical component of a hydroelectric powerplant but it may not be apparent that degradation of the condition of the turbine has occurred. Weld repairs, operation in a “rough zone,” and operation on Automatic Generation Control (AGC) all take their toll on the overall condition of the turbine. Efficiency losses are usually gradual and are not noticeable unless efficiency tests are performed. New turbine runners are often not considered unless a considerable uprate is possible or the existing runner is physically failing. Assessing the overall condition of the turbine may show that a replacement runner with a state-of-the-art hydraulic design, fabricated from modern materials and refurbishing other components, may provide economic benefits when compared to the current costs of repair and the efficiency of the existing runner. Determining the present condition of a turbine is an essential step in analyzing the risk of failure. This appendix provides a process for arriving at a Turbine Condition Index which may be used to develop a business case addressing risk of failure, economic consequences, and other factors. E6.2 SCOPE / APPLICATION The turbine assessment methodology outlined in this appendix applies to Francis, Kaplan, and propeller (reaction type) hydraulic turbines. The entire turbine is considered in this assessment tool, with the turbine runner as a major component. At the Facility Manager’s discretion, the assessments can be performed on individual turbines or a family of identical or near-identical turbines. This appendix is not intended to define turbine maintenance practices or describe in detail inspections, tests, or measurements. Utility-specific maintenance policies and procedures must be consulted for such information. E6.3 CONDITION AND DATA QUALITY INDICATORS, AND TURBINE

CONDITION INDEX This appendix describes the condition indicators generally regarded by hydro plant engineers as providing the basis for assessing turbine condition. The following four indicators are used in the initial, or Tier 1, assessment:

• Age • Runner Physical Condition • Operational Conditions/Restraints

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• Maintenance The Tier 1 condition indicators are based on the known turbine runner condition and/or inspections conducted by utility staff or contractors over the course of time and as part of routine maintenance activities. Numerical scores are assigned to each turbine condition indicator, which are then weighted and summed to determine the Turbine Condition Index. An additional stand-alone indicator is used to reflect the quality of the information available for scoring the turbine condition indicators. In some cases, data may be missing, out-of-date, or of questionable integrity. Any of these situations could affect the accuracy of the associated condition indicator scores as well as the validity of the overall Condition Index. Given the potential impact of poor or missing data, the Turbine Data Quality Indicator is used as a means of evaluating and recording confidence in the final Turbine Condition Index. Additional information regarding turbine condition may be necessary to improve the accuracy and reliability of the Turbine Condition Index. Therefore, in addition to the Tier 1 condition indicators, this appendix describes a “toolbox” of Tier 2 inspections, tests, and measurements that may be applied to adjust the Turbine Condition Index, depending on the specific issue or problem being addressed. Tier 2 tests are considered non-routine. However, if Tier 2 data is readily available, it may be used to supplement the Tier 1 assessment. Alternatively, Tier 2 tests may be deliberately performed to address Tier 1 findings. Results of the Tier 2 analysis may either increase or decrease the score of the Turbine Condition Index. The Data Quality Indicator score may also be revised during the Tier 2 assessment to reflect the availability of additional information or test data. The Turbine Condition Index may be used as the sole justification for replacing or rehabilitating a turbine. The Turbine Condition Index may also be used as an input to a computer model that assesses risk and performs economic analyses. Note: A severely negative result of ANY inspection, test, or measurement may be adequate in itself to require immediate corrective action, regardless of the Turbine Condition Index score. E6.4 INSPECTIONS, TESTS, AND MEASUREMENTS Inspections, tests, and measurements should be conducted and analyzed by staff suitably trained and experienced in turbine diagnostics. The more basic tests may be conducted by qualified staff that are competent in these routine procedures. More complex inspections and measurements may require a turbine diagnostics expert. Inspections, tests, and measurements should be conducted on a frequency that provides accurate and current information needed by the assessment. Turbine condition assessment may cause concerns that justify more frequent monitoring. Utilities should consider the possibility of taking more frequent measurements or installing on-line monitoring systems that will continuously track critical parameters. This will provide

E6-3

additional data for condition assessment and establish a certain amount of reassurance as turbine alternatives are being explored. E6.5 SCORING Condition indicator scoring is somewhat subjective, relying on the experience and opinions of plant staff and turbine experts. Relative terms such as “Results Normal” and “Deterioration” refer to results that are compared to industry-accepted levels; or to baseline or previous (acceptable) levels on this equipment; or to turbines of similar design, construction, or age operating in a similar environment. E6.6 WEIGHTING FACTORS Weighting factors used in the condition assessment methodology recognize that some Condition Indicators affect the Turbine Condition Index to a greater or lesser degree than other indicators. These weighting factors were arrived at by consensus among turbine design and maintenance personnel with extensive experience. E6.7 MITIGATING FACTORS Every turbine is unique and, therefore, the methodology described in this appendix cannot quantify all factors that affect individual turbine condition. Mitigating factors not included in this Guide may determine the final Turbine Condition Index and the final decision on turbine replacement or rehabilitation. If the Turbine Condition Index triggers significant follow-up actions (e.g., major repairs or a Tier 2 assessment), it may be prudent to first have the index reviewed by turbine experts. Mitigating factors specific to the utility may affect the final Turbine Condition Index and the final decision on turbine replacement or rehabilitation. E6.8 DOCUMENTATION Substantiating documentation is essential to support findings of the assessment, particularly where a Tier 1 condition indicator score is less than 3 (i.e., less than normal) or where a Tier 2 test results in subtractions to the Turbine Condition Index. Test reports, photographs, O & M records, and other documentation should accompany the Turbine Condition Assessment Summary form. E6.9 CONDITION ASSESSMENT METHODOLOGY The condition assessment methodology consists of analyzing each condition indicator individually to arrive at a condition indicator score. The score is then summed with scores from other condition indicators. The sum is the Turbine Condition Index. Apply the Turbine Condition Index to Table 17 – Turbine Condition-Based Alternatives to determine the recommended course of action. Each step is described below.

E6-4

E6.10 TIER 1 – INSPECTIONS, TESTS, AND MEASUREMENTS Tier 1 tests include those inspections, tests, and measurements that are routinely accomplished as part of normal operation and maintenance, or are readily discernible by examination of existing data. Tier 1 test results are quantified below as condition indicators that are weighted and summed to arrive at a Condition Index. Tier 1 tests may indicate abnormal conditions that can be resolved with standard corrective maintenance solutions. To the extent that Tier 1 tests result in immediate corrective maintenance actions being taken by plant staff, then adjustments to the condition indicators should be reflected and the new results used when computing the overall Tier 1 Condition Index. Tier 1 test results may also indicate the need for additional investigation, categorized as Tier 2 tests. E6.11 TURBINE CONDITION INDICATORS Turbine Condition Indicator 1 – Age Age is an important factor to consider when identifying candidates for turbine runner replacement or refurbishment. As a turbine ages, it becomes affected by fatigue and becomes susceptible to cracks. The effect of weld repairs over the years can be cumulative, increasing the likelihood of failure. Also, an older turbine has greater potential to be improved by state-of-the-art design and materials. Contours changed by weld repairs will change the hydraulics of the runner, reducing its efficiency. In addition, it has been found by a large number of field performance tests that turbine efficiency and capacity declines with age. Most decisions to commence rehabilitation are driven by economics, and efficiency and capacity gains have historically yielded most of the net benefits. Therefore, while age is not relevant when predicting a failure, it is relevant to rehabilitation decision-making. The in-service date will be used to determine turbine age. When looking at a family of turbines that were installed over a period of time at a specific facility, the average age should be used. The turbine runner age should be determined and applied to Table 1 to arrive at an appropriate Condition Indicator score.

Table 1 – Turbine Age Scoring Age Age (New/Full Rehabilitation) (Partial Rehabilitation) Condition Indicator Score

< 25 years < 15 years 3

≥ 25 and < 35 years ≥ 15 and < 25 years 2

≥ 35 and < 45 years ≥ 25 and < 35 years 1

≥ 45 years ≥ 35 years 0 A partial rehabilitation is defined as a new runner with the majority of remaining critical turbine components not restored, or an existing turbine repaired and the majority of remaining critical components restored. The remaining critical turbine components include:

E6-5

• Facing plates and gate end seals • Discharge ring • Gate mechanism (motors, shift ring, wicket gate locking mechanisms, bushings) • Main shaft bearing • Wicket gates

The intent of the age criterion for the turbine condition assessment is to indicate performance degradation. Turbine Condition Indicator 2 – Physical Condition The surface condition of the waterway is important, especially since it affects the efficiency and capacity of the machine. Areas in the waterway that see the highest velocities will have the largest effects on efficiency. The surface condition of metal components may deteriorate over time due to erosion, corrosion, operating in cavitation zones, and cavitation and cracking damage and repairs. The following can be evaluated through inspection of the turbine and its components: the runner, wicket gates, stay vanes, and discharge ring. The photographs in Annex A are intended to assist in evaluating the surface condition of the runner. Results of the physical inspection are analyzed and applied to Table 2 to arrive at condition indicator scores.

Table 2 – Physical Condition Scoring

Cracks

Results* Condition Indicator Score No Cracking 2 Inactive Cracks 1 Active Cracks 0

Cavitation and Surface Damage

Results Condition Indicator Score Good Surface/Minimal Cavitation Damage 2 Fair Surface/ Moderate Cavitation Damage 1 Poor Surface/Severe Cavitation Damage 0

Total

Physical Condition Score Sum of Cracks plus Cavitation and Surface Damage Condition Indicator Scores

* Active cracks are those cracks, which when measured, are growing over time. Inactive cracks

are cracks that appear and when re-measured at a later date, have not grown.

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Turbine Condition Indicator 3 – Operations Operational limitations play a role in determining the serviceability of equipment: the greater the limitations, the greater the impact to the power system leading to lost generation and sometimes spilling. Minimal operating restraints include operations to avoid minor rough zones. Moderate operating restraints would include last-on/first-off, hot bearings, large rough zones, high vibration, etc. Severe limitations include situations which make the turbine undesirable to operate such as a blade falling off, or the use of the head gate to stop the unit due to wicket gate leakage. This rating does not include environmental restrictions, such as minimum flows, up ramp, or maximum flow limitations. Operational limitations of the turbine are analyzed and applied to Table 3 to arrive at a Turbine Operational Limitations score.

Table 3 – Operational Limitations Scoring

Form of Operation Condition Indicator Score No operating restraints 1.5 Minimal operating restraints 1.0 Moderate operating restraints 0.5 Severe limitations, inoperable 0 Turbine Condition Indicator 4 – Maintenance The amount of corrective maintenance that either has been or must be performed is an indication of condition. No corrective maintenance is an indication that the turbine is in good shape. Small amounts of corrective maintenance would be repairs that could be completed during a unit preventative maintenance outage that is scheduled on a periodic basis. Moderate corrective maintenance is maintenance that extends the normal scheduled outage time to perform. Severe corrective maintenance is maintenance that requires scheduled or forced outages to perform. Results of turbine maintenance history are analyzed and applied to Table 4 to arrive at an appropriate Turbine Condition Indicator score.

Table 4 –Maintenance Scoring

Corrective Maintenance Condition Indicator Score

No corrective maintenance 1.5

Small amounts of corrective maintenance (e.g., less than 3 staff days per unit per year) 1.0

Moderate corrective maintenance that causes extensions of unit preventative maintenance outages 0.5

Severe corrective maintenance or forced outages 0

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E6.12 TIER 1 – TURBINE CONDITION INDEX CALCULATIONS Enter the turbine condition indicator scores from Tables 1 through 4 above into the Turbine Condition Assessment Summary form (at the end of this document). Multiply each indicator score by its respective Weighting Factor, and sum the total scores to arrive at the Tier 1 Turbine Condition Index. This index may be adjusted by the Tier 2 turbine inspections, tests, and measurements described later in this document. The Turbine Condition Index is suitable for use in risk-based economic analysis models. As in all decision-making related to life expectancy of existing equipment, there is a certain amount of uncertainty. Current condition is not a definitive indicator of remaining life; however, it is an important consideration and may be used to modify typical life expectancy curves and to arrive at a reasonable and defensible probability of continued life. E6.13 TIER 1 – TURBINE DATA QUALITY INDICATOR The Turbine Data Quality Indicator reflects the quality of the inspection, test, and measurement results used to evaluate the turbine condition under Tier 1. The more current and complete the inspections, tests, and measurements, the higher the rating for this indicator. The normal testing frequency is defined as the organization’s recommended frequency for performing the specific test or inspection. Qualified personnel should make a subjective determination of scoring that encompasses as many factors as possible under this indicator. Results are analyzed and applied to Table 5 to arrive at an appropriate Turbine Data Quality Indicator Score.

Table 5 – Turbine Data Quality Scoring

Data Quality Results Indicator Score All Tier 1 inspections, tests and measurements were completed within the normal frequency. 10

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 6 and < 24 months past the normal frequency. 7

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 24 and < 36 months past the normal frequency, or some of the results are not available.

4

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 36 months past the normal frequency, or no results are available.

0

Enter the Turbine Data Quality Indicator Score from Table 5 into the Turbine Condition Assessment Summary form at the end of this document.

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E6.14 TIER 2 – TURBINE INSPECTIONS, TESTS, AND MEASUREMENTS Tier 2 inspections, tests, and measurements require specialized personnel to inspect the turbine, interview plant O & M staff and, if necessary, perform a simplified field performance test. The work will require an outage to perform. A Tier 2 assessment is not considered routine. Tier 2 inspections may affect the Turbine Condition Index established using Tier 1. An adjustment to the Data Quality Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment. Hydraulic turbines, unlike generators and transformers, rarely fail catastrophically and do not really have a physical lifetime. They do have an economic lifetime, however. Because the performance of existing turbines degrades with time, and the value of energy and power and the performance of replacement units increase with time, there comes a point when it becomes more economical to rehabilitate or replace them than to continue to operate and maintain them. Families of identical or near-identical turbines at a plant should be evaluated as a group as opposed to individual units. A team consisting of the Plant O & M Representative(s) and Technical Support Staff should perform Tier 2 assessments. The tasks that need to be performed for Tier 2 are summarized as follows:

1. Technical support staff will be responsible to:

• Visit the plant to perform a physical inspection of a turbine and interview O & M staff.

• Determine current performance and perform a simplified field test, if necessary. • Review and, if necessary, adjust the Tier 1 Condition Index based upon the inspection

and comparison with the condition of other similar families of units.

2. Plant O & M Representative will be responsible to:

• Provide necessary assistance and information to Technical Support staff. • Assist in the assessment process.

For each Tier 2 test performed, add or subtract the appropriate amount to/from the Turbine Condition Index. Many of the following Tier 2 tests are used to detect or confirm a similar defect or state of deterioration. In the event that more than one Tier 2 tests are performed to assess the same problem or concern, then the test with the largest adjustment shall be used to recalculate the Turbine Condition Index. It is important to avoid adjusting the Condition Index downward twice or more simply because multiple tests are completed for the same suspected problem. Since the Tier 2 tests are being performed by and/or coordinated with knowledgeable technical staff, the decision as to which test is more significant and how different tests overlap is left to the experts.

E6-9

Test T2.1: Efficiency Test The efficiency of the turbine is probably the most important factor in determining if a turbine runner should be replaced. The efficiency test may show that the condition of the turbine has degraded to a point that its efficiency has been reduced significantly. Even if efficiency has not degraded, newer turbine designs are usually more efficient than those 30 years or older. In addition, many turbines were designed for best efficiency head in the mid-range of the reservoir elevation swing, but operational philosophy has changed. An efficiency increase and decreased cavitation can be gained from installing a replacement runner that is designed around a head range established from historical operations rather than original design data. Turbine efficiency test results are analyzed and applied to Table 6 to arrive at a Turbine Condition Index score adjustment.

Table 6 – Efficiency Test Scoring

Adjustment to Measured Efficiency Test Results Condition Index Score

Measured efficiency is ≥ 93% or < 2% less than original efficiency. Add 0.5 Measured efficiency is ≥ 91 and < 93% or ≥ 2 and < 3% less than original efficiency or efficiency not measured. No Change

Measured efficiency is < 91% or ≥ 3% less than original efficiency. Subtract 1.0 Test T2.2: Capacity Test The capacity of the turbine is another important factor in determining if a turbine runner should be replaced. As efficiency degrades over time, so does the maximum capacity of the machine. Tests may show that the condition of the turbine has degraded to a point that its capacity has been reduced significantly, sometimes more than 4 percent. Installing a new runner will restore maximum capacity to original output level. In some cases, a new runner may provide an opportunity to increase the capacity above the original design. Capacity test results are analyzed and applied to Table 7 to arrive at a Turbine Condition Index score adjustment.

Table 7 – Capacity Test Scoring

Adjustment to Measured Capacity Range Condition Index Score Lost < 2% of original capacity. Add 0.5 Lost ≥ 2 and < 4% of original capacity or capacity not measured. No Change

Lost ≥ 4% of original capacity. Subtract 0.5

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Test T2.3: Off-Design Conditions Test

Consideration of present conditions must be given. If there is a significant change in the flow rate or head from the original design condition, this can greatly impact the machine performance and lead to recurring maintenance issues. Test results from design conditions are analyzed and applied to Table 8 to arrive at a Turbine Condition Index score adjustment.

Table 8 – Off-Design Conditions Test Scoring

Adjustment to Changes in Design Conditions Condition Index Score No significant changes in flow rate or head from original design condition. No Change

Significant changes in flow rate or head since original design condition. Subtract 0.5

Test T2.4: Paint Film Quality Test A visual inspection should be made of the ferrous portions of the spiral case and extension, stay vanes, wicket gates, runner, discharge ring, head cover, and draft tube. The paint film quality will be scored and compared to that of other units. Paint Film Quality test results are analyzed and applied to Table 9 to arrive at a Turbine Condition Index score adjustment.

Table 9 – Paint Film Quality of Ferrous Wetted Surfaces Test Score

Adjustment to Paint Film Quality Test Condition Index Score Paint film is mostly intact (≥ 90% of the surface is intact). Add 0.5 The paint film is mostly absent but the steel surfaces have not yet suffered serious corrosion or erosion damage. No Change

Ferrous surfaces exhibiting extensive erosion or corrosion are observed (or need to be periodically repaired) in critical areas (stay vanes, wicket gates, around (or in) man-door or in spiral case or penstock).

Subtract 0.5

Test T2.5: Surface Roughness of Runner and Discharge Ring Test During the physical inspection, surface quality comparison gages or measurement tools will be used to determine the surface roughness. Although roughness can be caused from cavitation attack, erosion, corrosion or any combination of the three, this indicator is focused only on roughness caused by erosion and corrosion. Test T2.7 focuses on damage caused by cavitation.

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Surface quality comparison test results are analyzed and applied to Table 10 to arrive at a Turbine Condition Index score adjustment.

Table 10 – Surface Roughness of Runner and Discharge Ring Test Scoring

Adjustment to Surface Quality Condition Index Score

Good Add 0.5 Moderate No Change

Severe Subtract 0.5 Test T2.6: Cracking of Runner and Discharge Ring Test O & M personnel will be interviewed to determine and document the cracking repair history. If a cracking problem has been permanently solved (i.e., no cracks have occurred in the last 10 years), it will be scored as “minimal.” If cracking occurs, but in non-critical areas, it will be scored as “moderate.” See the sketches in Annex B. Critical areas are those labeled I and II. All other areas are considered non-critical. The cracking repair test results are analyzed and applied to Table 11 to arrive at a Turbine Condition Index score adjustment.

Test T2.7: Cavitation of Runner and Discharge Ring Test Both the average depth of the worst pitting and size of area of damage should be considered. Photographic evidence could be utilized in the event a physical inspection is not possible. The following areas will be inspected: Suction side of the vanes/blades near the band; pressure side of the vanes/blades near the leading edge; discharge ring,18 inches below the runner; and runner hub adjacent to blades. The cavitation damage test results will be analyzed and applied to Table 12 to arrive at a Turbine Condition Index score adjustment.

Table 11 – Cracking of Runner and Discharge Ring Test Scoring

Adjustment to Cracking During Last 10 Years Condition Index Score Minimal (i.e., none, or not active in non-critical areas and < 1” long) Add 1.0

Moderate (i.e., active but in non-critical areas and ≥ 1” and < 2” long)

No Change

Severe (i.e., active in critical areas or ≥ 2” long) Subtract 1.0

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Test T2.8: Condition of Remaining Parts and Systems Test In addition to the turbine runner, there are many other parts and systems which need to function to enable the turbine to operate satisfactorily. Each one by itself would not necessarily change the condition assessment score of the unit. However, taken together, an overall assessment can be made. The following is a list of other components and considerations:

• Gate mechanism (servo motors, shift ring, wicket gate locking mechanisms, bushings) • Guide bearings • Seals • Oil-head (if Kaplan) • Blade adjusting mechanism (if Kaplan) • Alignment/verticality • Concrete growth • Run-out • Vibration • Noise • Greasing system • Oil circulating pumps • Headcover drains or pumps • Vacuum breakers

Test results from the condition of all remaining parts and systems are analyzed and applied to Table 13 to arrive at a Turbine Condition Index score adjustment.

Table 12 – Cavitation Damage of Runner and Discharge Ring Test Scoring

Adjustment to Cavitation Damage Condition Index Score Minimal: Stainless – frosting only (in small areas) Carbon – frosting only (in small areas)

No Change

Moderate: Depth Area Stainless < 1/8” < 5%

Carbon < 3/8” < 5% Subtract 0.3

Severe: Depth Area Stainless ≥ 1/8” ≥ 5% Carbon ≥ 3/8” ≥ 5%

Subtract 0.6

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Table 13 – Condition of Remaining Parts and Systems Test Scoring Adjustment to Equipment Condition Condition Index Score All sub-systems are normal and there are no major issues in any of the listed areas. In general, very little maintenance is required. Add 0.2

Some sub-systems require frequent maintenance or do not operate well. Frequent minor maintenance is needed to keep the unit running well.

No Change

The unit runs but takes significant or frequent maintenance. Some more important components are damaged or broken. Subtract 0.7

Test T2.9: Environmental Improvement Test The primary environmental issues relative to turbines are losing oil or grease into the waterway, poor survival of fish passing through them, and low Dissolved Oxygen (DO) content of released water during portions of the year. Facilities without environmental issues score “No Change.” Environmental improvement test results are analyzed and applied to Table 14 to arrive at a Turbine Condition Index score adjustment.

Table 14 – Environmental Improvement Test Scoring

Adjustment to Environmental Conditions Condition Index Score There are no perceived environmental issues and rehabilitation of the turbine would have minimal positive effect on the environment. Little or no oil or grease is released into the environment and no DO improvements can be gained by a turbine replacement.

No Change

There is some history of negative impacts (occasional minor oil releases, some mortality of fish which transit the turbine, and most years, the desired dissolved oxygen content of released water is met or exceeded during all months).

Subtract 0.3

There are known negative impacts which regularly occur which can be mitigated by a turbine rehabilitation. Significant amounts of oil or grease are occasionally released into the environment. Or, DO improvements or fish passage survival improvements can be gained by a turbine replacement.

Subtract 0.6

Test T2.10: Operating Conditions Test Operating conditions are a good indicator of potential wear on a machine. Conditions such as the loading (base loaded or peaking), Automatic Generation Control (AGC), condensing, and the number of start/stops may lead to accelerated damage to units.

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Test results from the operating conditions are analyzed and applied to Table 15 to arrive at a Turbine Condition Index score adjustment.

Table 15 – Operating Conditions Test Scoring

Adjustment to Form of Operation (Annually) Condition Index Score Base loaded. Add 0.2 Peaking operation, AGC or < 100 start/stops or condensing cycles. No Change ≥ 100 start/stops or condensing cycles. Subtract 0.5 Test T2.11: Maintenance Test O & M staff should work with Engineering personnel to evaluate the past 5 to 10 years of maintenance records to determine the level of maintenance that has been required to keep the unit operational. Significant maintenance activities known to be needed in the near future shall also be considered. Given the individual nature of the equipment in each operating facility and variations in how it is operated and maintained, the specific factors considered in this evaluation may be somewhat different for each facility. The evaluation of past and upcoming maintenance is analyzed and applied to Table 16 to arrive at a Turbine Condition Index score adjustment.

Table 16 – Maintenance Test Scoring

Adjustment to Maintenance Performed Condition Index Score Normal maintenance. Add 0.2 Additional maintenance during normal outages. No Change Additional outages or extended outages needed to perform maintenance task or maintenance work deferred due to lack of time. Subtract 0.5

Test T2.12: Other Specialized Diagnostic Tests Additional tests may be applied to evaluate specific turbine problems. Some of these diagnostic tests may be considered to be of an investigative research nature. When conclusive results from other diagnostic tests are available, they may be used to make an appropriate adjustment to the Turbine Condition Index. E6.15 TIER 2 – TURBINE CONDITION INDEX CALCULATIONS Enter the Tier 2 adjustments from the tables above into the Tier 2 Turbine Condition Assessment Summary form at the end of this guide. Subtract the sum of these adjustments from the Tier 1 Turbine Condition Index to arrive at the Net Turbine Condition Index. Attach supporting

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documentation. An adjustment to the Data Quality Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment. E6.16 TURBINE CONDITION-BASED ALTERNATIVES The Turbine Condition Index – either modified by Tier 2 tests or not – may be sufficient for decision-making regarding turbine alternatives. The Index is also suitable for use in a risk-and-economic analysis model. Where it is desired to consider alternatives based solely on turbine condition, the Turbine Condition Index may be directly applied to Table 17 – Turbine Condition-Based Alternatives below.

Table 17 – Turbine Condition-Based Alternatives

Turbine Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat or update Tier 1 assessment during next scheduled maintenance outage.

≥ 3.0 and < 7 (Fair) Continue O & M without restriction. Schedule a Tier 2 assessment in 4 years or less.

≥ 0 and < 3.0 (Poor) Schedule a Tier 2 assessment in 1 year.

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TURBINE TIER 1 CONDITION ASSESSMENT SUMMARY

Date: ________________________ Location: ________________________________________

Turbine Identifier: ______________ Manufacturer: _________________Yr. Mfd.: ___________

Tier 1 Turbine Condition Summary

(For instructions on indicator scoring, please refer to condition assessment guide)

No. Condition Indicator Score x Weighting Factor = Total Score

1 Age (Score must be 0, 1, 2, or 3) 0.667

2 Physical Condition (Score must be 0, 1, 2, 3, or 4) 1.250

3 Operations (Score must be 0, 0.5, 1, or 1.5) 1.000

4 Maintenance (Score must be 0, 0.5, 1, or 1.5) 1.000

Tier 1 Turbine Condition Index (Sum of individual Total Scores)

(Condition Index should be between 0 and 10)

Tier 1 Turbine Data Quality Indicator

(Value must be 0, 4, 7, or 10)

Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________ (Attach supporting documentation.)

Turbine Condition-Based Alternatives

Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat or update Tier 1 condition assessment during next scheduled maintenance outage.

≥ 3.0 and < 7 (Fair) Continue O & M without restriction. Schedule a Tier 2 assessment in 4 years or less.

≥ 0 and < 3.0 (Poor) Schedule a Tier 2 assessment in 1 year.

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TURBINE TIER 2 CONDITION ASSESSMENT SUMMARY

Date: ________________________ Location: ________________________________________

Turbine Identifier: ______________ Manufacturer: _________________Yr. Mfd.: ___________

Tier 2 Turbine Condition Summary

Individual Adjustments No. Tier 2 Test to Tier 1 Condition Index T2.1 Efficiency

T2.2 Capacity

T2.3 Off-Design

T2.4 Paint Film Quality

T2.5 Surface Roughness

T2.6 Cracking

T2.7 Cavitation

T2.8 Condition of Remaining Parts

T2.9 Environmental

T2.10 Operating Conditions

T2.11 Maintenance

T2.12 Other Specialized Diagnostic Tests

Tier 2 Adjustments to Turbine Condition Index (Sum of Individual Adjustments)

(≥ 0 and ≤ 10)

Tier 2 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

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To calculate the Net Turbine Condition Index (Value should be between 0 and 10), subtract the Tier 2 Adjustments from the Tier 1 Turbine Condition Index: Tier 1 Turbine Condition Index __________ minus Tier 2 Turbine Adjustments __________ = ________________ Net Turbine Condition Index Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________

(Attach supporting documentation.)

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Annex A: Steel Conditions

Figure A-1: Stainless Steel – Fair Condition.

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Figure A-2: Stainless Steel – Poor Condition.

Figure A-3: Carbon Steel – Fair Condition (pitting).

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Figure A-4: Carbon Steel – Poor Condition.

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Figure A-5: Carbon Steel – Poor Condition.

Figure A-6: Carbon Steel.

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Figure A-7: Carbon Steel – Poor Condition.

Annexx B: Critical Areas

(As Referenced for Test T2.S6)

Figure B-1: Francis Runner Critical Areas.

Figure B-2: Kaplan Blade Critical Areas.

I – Most Critical, II – Less Critical, III – Least Critical

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September 2006 Hydro Plant Risk Assessment Guide Appendix E7: Surge Arrester Condition Assessment E7.1 GENERAL Surge arresters are key components in the power train at hydroelectric powerplants and are appropriate for analysis under a condition assessment program. Surge arresters protect other electrical equipment from high-energy surges caused by lightning strikes and circuit switching. Failure of an aging and ineffective arrester can leave critical and expensive equipment, such as transformers, exposed to the damaging effects of these surges. Power equipment cannot be operated safely without effective surge arresters. Surge arrester failure can be hazardous to staff and other equipment should the arrester fail explosively. Although procurement cost and time for arresters is not significant, the replacement cost and outage time for equipment collaterally damaged from an arrester explosion may be large. The economic impact from an extended outage resulting from an arrester explosion can be enormous. A strategy for dealing with ineffective or defective surge arresters is important to improving the reliability of the powerplant. Determining the present condition of a surge arrester is an essential step in analyzing the risk of failure. This appendix provides a process for arriving at a Surge Arrester Condition Index which may be used to develop a business case addressing risk of failure, economic consequences, and other factors. E7.2 SCOPE / APPLICATION The surge arrester condition assessment methodology outlined in this appendix applies to station-class arresters currently in operation. It addresses both gapped, silicon-carbide type and metal-oxide varistor (MOV) type arresters. This appendix is not intended to define surge arrester maintenance practices or describe in detail surge arrester condition assessment inspections, tests, or measurements. Utility maintenance policies and procedures must be consulted for such information. E7.3 CONDITION AND DATA QUALITY INDICATORS AND SURGE ARRESTER

CONDITION INDEX This appendix describes different methods for obtaining condition indices for both silicon-carbide and MOV type arresters. In the case of silicon-carbide type, the Surge Arrester Condition Index will always be zero, as described in the section below entitled “Tier 1 -

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Inspections, Tests, and Measurements.” In the case of metal-oxide type arresters, the primary condition indicator is thermal imaging. This indicator is evaluated using Tier 1 inspections, tests, and measurements conducted by utility staff or contractors over the course of time. A numerical score is assigned to the condition indicator and used to arrive at an overall Surge Arrester Condition Index for MOV type arresters. An additional stand-alone indicator is used to reflect the quality of the information available for scoring the Surge Arrester Condition Index. In some cases, data may be missing, out-of-date, or of questionable integrity. Any of these situations could affect the validity of the overall Condition Index. Given the potential impact of poor or missing data, the Data Quality Indicator is used as a means of evaluating and recording confidence in the final Surge Arrester Condition Index. The appendix also describes one Tier 2 test that may be applied to MOV type arresters depending on utility practice. If Tier 2 data is readily available, it may be used to supplement the Tier 1 assessment. Alternatively, Tier 2 tests may be deliberately performed to address Tier 1 findings. Results of the Tier 2 analysis may either increase or decrease the score of the Surge Arrester Condition Index. The Data Quality Indicator score may also be revised during the Tier 2 assessment to reflect the availability of additional information or test data. After review by a surge arrester expert, the Condition Index is suitable for use as an input to the risk and economic analysis model or may be used directly to determine replacement options. Note: A severely negative result of ANY inspection, test, or measurement may be adequate in itself to require immediate replacement regardless of the Surge Arrester Condition Index score. E7.4 INSPECTIONS, TESTING, AND MEASUREMENTS Inspections, tests, and measurements should be conducted and analyzed by staff suitably trained and experienced in surge arrester diagnostics and on a frequency that provides the accurate and current information needed by the assessment. E7.5 SCORING Condition indicator scoring is based on extensive experience by surge arrester maintenance staff and engineers over a significant period of time and on recognized practices in the hydroelectric industry. Relative terms such as “Results Normal” and “Degradation” refer to results that are compared to industry accepted levels; or to baseline or previous (acceptable) levels on this equipment; or to equipment of similar design, construction, or age operating in a similar environment.

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E7.6 WEIGHTING FACTORS Weighting factors used in the condition assessment methodology recognize that some Condition Indicators affect the Surge Arrester Condition Index to a greater or lesser degree than other indicators. These weighting factors were arrived at by consensus among surge arrester maintenance personnel and engineers with extensive experience. E7.7 MITIGATING FACTORS Every surge arrester is unique and, therefore, the methodology described in this appendix cannot quantify all factors that affect individual arrester condition. It is important that the Arrester Condition Index arrived at be scrutinized by engineering experts. Mitigating factors specific to the utility may determine the final Arrester Condition Index and the final decision on replacement. E7.8 DOCUMENTATION Substantiating documentation is essential to support findings of the assessment, particularly where surge arrester replacement is indicated. Test results should accompany the Surge Arrester Condition Assessment Summary Form at the end of this document. E7.9 CONDITION ASSESSMENT METHODOLOGY The condition assessment methodology consists of analyzing each condition indicator individually to arrive at a condition indicator score. The score is then weighted and summed with scores from other condition indicators. The sum is the Surge Arrester Condition Index. Reasonable efforts should be made to perform inspections, tests, and measurements. However, when data is missing to properly score a Condition Indicator, it may be assumed that the score is “Good” or numerically some mid-range number such as 2. Caution: this strategy should be used judiciously to prevent misleading results. In recognition of the potential impact of poor or missing data, a separate Data Quality Indicator is rated as a means of evaluating and recording confidence in the final Surge Arrester Condition Index. E7.10 TIER 1 – INSPECTIONS, TESTS, AND MEASUREMENTS Surge arrester design and construction has undergone major transformation in recent years. Prior to about 1985, arresters were of the gapped, silicon-carbide type. The condition of this type of arrester is difficult to determine through diagnostic testing and the arrester may fail without warning. Explosive arrester failure can be disastrous to other equipment. Many cases of unexpected arrester failure from undetected internal conditions have been experienced in recent years, causing significant damage to adjacent equipment and expensive forced outages. Older arresters may not have venting means, which makes them more vulnerable to failure. Gapped arresters also become more vulnerable after several operations.

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The general practice is to preemptively replace gapped, silicon-carbide type arresters based on age. Therefore, condition indicator scoring for these arresters intentionally arrives at an automatic Condition Index of zero, indicating a need to replace the arresters regardless of other test results. Subsequent to 1985, arresters were manufactured using metal oxide varistor (MOV) technology. MOV arresters do not experience the same kind of failure as the silicon-carbide arresters. However, MOV-type arresters can be affected by moisture ingress. Like the silicon-carbide type, it is difficult to determine the condition of MOV arresters through diagnostic testing. Currently, there is no known relationship between age and failure for MOV-type arresters. The following Condition Indicators only apply to MOV-type arresters. Condition Indicator 1 – Thermal Imaging (MOV-Type Arresters) Thermal imaging of arresters using infrared scanning equipment can detect abnormal heating patterns from leakage current, which may indicate imminent arrester failure. Infrared images are compared to previous images or to images of other arresters of similar age and construction. Differences in heating patterns or temperature differences between phases are of particular concern. Apply the thermal imaging measurements to Table 1 to arrive at the condition indicator score.

Table 1 – Thermal Imaging Scoring

Results Condition Indicator Score

Normal compared to previous or similar units. 3

Minor to moderate variation from previous tests or similar units. 2

Significant variation from previous tests or similar units.

0 (May indicate a serious problem requiring immediate evaluation, consultation, and

remediation prior to re-energization.) E7.11 TIER 1 – SURGE ARRESTER CONDITION INDEX CALCULATIONS Enter the condition indicator scores from the tables above into the Surge Arrester Condition Assessment Summary Form at the end of this document. Multiply each condition indicator score by the Weighting Factor and sum the total scores to arrive at the Tier 1 Surge Arrester Condition Index. This Index may be adjusted by the Tier 2 inspections, tests, and measurements described below. Suggested alternatives for follow-up action, based on the Surge Arrester Condition Index, are described in the Surge Arrester Condition-Based Alternatives (Table 4).

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E7.12 SURGE ARRESTER DATA QUALITY INDICATOR The Surge Arrester Data Quality Indicator reflects the quality of the inspection, test, and measurement results used to evaluate the arrester condition under Tier 1. The more current and complete the inspections, tests, and measurements, the higher the rating for this indicator. The normal testing frequency is defined as the organization’s recommended frequency for performing the specific inspection, test, or measurement. Qualified personnel should make a subjective determination of scoring that encompasses as many factors as possible under this indicator. Results are analyzed and applied to Table 2 to arrive at a Surge Arrester Data Quality Indicator score.

Table 2 – Surge Arrester Data Quality Scoring

Results Data Quality Indicator Score All Tier 1 inspections, tests and measurements were completed within the normal testing frequency and results are reliable.

10

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 6 and < 24 months past the normal testing frequency and results are reliable.

7

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 24 and < 36 months past the normal testing frequency, or some of the results are not available or are of questionable integrity.

4

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 36 months past the normal frequency, or no results are available or many are of questionable integrity.

0

Enter the Surge Arrester Data Quality Indicator Score from Table 2 into the Surge Arrester Condition Assessment Summary form at the end of this document. E7.13 TIER 2 – INSPECTIONS, TESTS, AND MEASUREMENTS Tier 2 inspections, tests, and measurements generally require specialized equipment or expertise, may be intrusive, or may require an outage to perform. A Tier 2 assessment is not considered routine. Tier 2 inspections are intended to affect the Surge Arrester Condition Index established using Tier 1 tests as well as confirm or disprove the need for more extensive maintenance, rehabilitation, or surge arrester replacement. For Tier 2 assessments performed, apply only the appropriate adjustment factors per the instructions above and recalculate the Surge Arrester Condition Index using the Surge Arrester

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Condition Assessment Summary form at the end of this document. An adjustment to the Data Quality Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment. Test T2.1: AC Insulation Tests (MOV-Type Arresters) AC insulation tests (Doble tests) for surge arresters include dielectric power (watts) loss and charging current. Such tests may provide some information regarding arrester condition but they cannot detect certain internal conditions that could lead to failure. Poor insulation test results indicate arrester replacement; fair or good insulation results do not necessarily mean arresters are reliable. Problems with arresters of similar design, construction, and age are important when considering replacement. Apply surge arrester test results to Table 3 to arrive at the Surge Arrester Condition Index adjustment.

Table 3 – AC Insulation Test Scoring

Adjustment to Results Arrester Condition Index

Normal. No Change

Minor to Significant Degradation; minor increase in power (watts) loss or charging current compared to prior tests or similar units.

Subtract 2.0

Severe Degradation; significant increase in power (watts) loss or charging current compared to prior tests or similar units.*

To be determined by a surge arrester specialist.

*May indicate a serious problem requiring immediate evaluation, consultation, and remediation prior to re-energization. Test T2.2: Other Specialized Diagnostic Tests Additional tests may be applied to evaluate specific surge arrester problems. Some of these diagnostic tests may be considered to be of an investigative research nature. When conclusive results from other diagnostic tests are available, they may be used to make an appropriate adjustment to the Surge Arrester Condition Index. E7.14 TIER 2 – SURGE ARRESTER CONDITION INDEX CALCULATIONS Enter the Tier 2 adjustments from the tables above into the Surge Arrester Condition Assessment Summary form at the end of this guide. Subtract the sum of these adjustments from the Tier 1 Surge Arrester Condition Index to arrive at the Net Surge Arrester Condition Index. Attach supporting documentation. An adjustment to the Data Quality Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment.

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E7.15 SURGE ARRESTER CONDITION-BASED ALTERNATIVES After review by a surge arrester expert, the Surge Arrester Condition Index is suitable for use in a risk-and-economic analysis model. The condition index may be deemed sufficient in itself for decision-making regarding surge arrester alternatives, in which case the Surge Arrester Condition Index may be directly applied to Table 4.

Table 4 – Surge Arrester Condition-Based Alternatives

Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat condition assessment as needed.

≥ 3.0 and < 7 (Fair) Continue operation but accelerate re-evaluation and plan for arrester replacement.

≥ 0 and < 3.0 (Poor) Replace surge arrester immediately.*

* Surge arresters should be replaced as a set, i.e., all three phases should be replaced

simultaneously. Surge arresters on opposite ends of a transmission line or on opposite sides of a transformer should be replaced simultaneously with arresters of the same material composition. This strategy will prevent voltage wave reflections due to dissimilar construction or the over dependence on the metal-oxide arresters.

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SURGE ARRESTER TIER 1 CONDITION ASSESSMENT SUMMARY

Date: ________________________ Location: ________________________________________

Arrester Identifier: ____________________ Phase: ___________

Manufacturer: _________________Yr. Mfd.: ___________

Silicone Carbide Gapped: _____ or Metal Oxide: _____ Voltage: ________ BIL: ____________

Surge Arrester Condition Summary*

(For instructions on indicator scoring, please refer to condition assessment guide) No. Condition Indicator Score × Weighting Factor = Total Score

1 Thermal Imaging* (Score must be 0, 2, or 3) 3.333

Tier 1 Surge Arrester Condition Index (Sum of individual Total Scores)

(Condition Index should be between 0 and 10)

*Condition indicators are used to score MOV type arresters only. For gapped, silicon-carbide type arresters, the Arrester Condition Index is zero (0).

Data Quality Indicator (Value must be 0, 4, 7, or 10)

Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________ (Attach supporting documentation.)

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Surge Arrester Condition-Based Alternatives

Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat condition assessment as needed.

≥ 3.0 and < 7 (Fair) Continue operation but accelerate re-evaluation and plan for arrester replacement.

≥ 0 and < 3.0 (Poor) Replace surge arrester immediately.**

** Surge arresters should be replaced as a set, i.e., all three phases should be replaced

simultaneously. Surge arresters on opposite ends of a transmission line or on opposite sides of a transformer should also be replaced simultaneously with arresters of the same material composition. This strategy will prevent voltage wave reflections due to dissimilar construction or the over dependence on the metal-oxide arresters.

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SURGE ARRESTER TIER 2 CONDITION ASSESSMENT SUMMARY

Date: ________________________ Location: ________________________________________

Arrester Identifier: ____________________ Phase: ___________

Manufacturer: _________________Yr. Mfd.: ___________

Silicone Carbide Gapped: _____ or Metal Oxide: _____ Voltage: ________ BIL: ____________

Tier 2 Surge Arrester Condition Summary (MOV type arresters only)

(For instructions on indicator scoring, please refer to condition assessment guide) No. Tier 2 Test Adjustment to Tier 1 Condition Index

T2.1 AC Insulation

T2.2 Other Specialized Diagnostic Tests

Tier 2 Adjustments to Surge Arrester Condition Index

(Sum of individual Adjustments)

Data Quality Indicator (Value must be 0, 4, 7, or 10)

To calculate the Net Surge Arrester Condition Index (Value should be between 0 and 10), subtract the Tier 2 Adjustments from the Tier 1 Surge Arrester Condition Index: Tier 1 Surge Arrester Condition Index __________ minus Tier 2 Surge Arrester Adjustments __________ = ________________ Net Surge Arrester Condition Index Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________

(Attach supporting documentation.)

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September 2006 Hydro Plant Risk Assessment Guide Appendix E8: Battery Condition Assessment E8.1 GENERAL Plant or station batteries are key components in hydroelectric powerplants and are appropriate for analysis under a condition assessment program. Plant batteries provide essential backup power for circuit breaker tripping and protective relay operation. Plant batteries often provide power for emergency lighting, fire detection / protection systems, and critical pumps and valves. Upon failure of either the normal alternating-current power or the battery chargers, the plant battery is the only remaining supply of energy to protect the plant and the power system during abnormal conditions. Failure of the plant battery can be catastrophic to powerplant equipment and systems, as well as a risk to the power system. If the battery cannot provide the needed energy when required, protective action cannot remove sources of fault energy or isolate the plant from the power system. Equipment in the power train may be damaged or destroyed, thus causing significant outage time and costs. Power system stability may be jeopardized if the plant cannot be disconnected from the system. The powerplant cannot be safely operated without a healthy plant battery. Many abnormal battery conditions detected through regular maintenance can be corrected. Under certain circumstances, individual cells may be replaced. However, some conditions indicate complete battery replacement. A strategy for detecting and dealing with failing plant batteries is important to improving the reliability of the powerplant. Determining the present condition of plant batteries is an essential step in analyzing the risk of failure. This appendix provides a process for arriving at a Plant Battery Condition Index which may be used to develop a business case addressing risk of failure, economic consequences, and other factors. E8.2 SCOPE / APPLICATION The powerplant battery condition assessment methodology outlined in this appendix applies to multi-cell, vented lead-acid (VLA) (often called “flooded” or “wet cell”) type and valve-regulated lead-acid (VRLA) type. This methodology may be used to determine alternatives for continued maintenance or battery replacement. This appendix is not intended to define plant battery maintenance practices or describe in detail plant battery condition assessment inspections, tests, or measurements. Utility maintenance policies and procedures must be consulted for such information.

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E8.3 CONDITION AND DATA QUALITY INDICATORS AND PLANT BATTERY CONDITION INDEX

The following three condition indicators are generally regarded by hydro powerplant engineers as providing a sound basis for assessing plant battery condition:

• Visual Inspection • Age • Routine testing

These condition indicators are initially evaluated using Tier 1 inspections, tests, and measurements, which are conducted by utility staff or contractors over the course of time and as a part of routine maintenance activities. Numerical scores are assigned to each condition indicator, which are then weighted and summed to determine the Plant Battery Condition Index. In addition, a stand-alone indicator is used to reflect the quality of the information available to score the Plant Battery Condition Index. In some cases, data may be missing, out-of-date, or of questionable integrity. Any of these situations could affect the accuracy of the associated condition indicator scores as well as the validity of the condition index. Given the potential impact of poor or missing data, the Data Quality Indicator is used as a means of evaluating and recording confidence in the final Plant Battery Condition Index. The appendix also describes Tier 2 inspections, tests, and measurements that may be applied depending on the specific problem being addressed. Tier 2 tests are considered non-routine. If Tier 2 data is readily available, it may be used to supplement the Tier 1 assessment. Alternatively, Tier 2 tests may be deliberately performed to address Tier 1 findings. Results of the Tier 2 analysis may either increase or decrease the score of the Plant Battery Condition Index. The Data Quality Indicator score may also be revised during the Tier 2 assessment to reflect the availability of additional information or test data. The methodology described in this appendix is valid only if a study of battery capacity versus present load has been performed and that the capacity is adequate. If capacity is not adequate, replacement is warranted and the condition methodology described herein is not applicable. Note: A severely negative result of ANY inspection, test, or measurement may be adequate in itself to require immediate replacement regardless of the Plant Battery Condition Index score. E8.4 INSPECTIONS, TESTING, AND MEASUREMENTS Inspections, tests, and measurements should be conducted and analyzed by staff suitably trained and experienced in plant battery diagnostics and on a frequency that provides the accurate and current information needed by the assessment. More complex inspections and measurements may require a battery diagnostics “expert”. Results of the battery condition assessment may cause concerns that justify more frequent monitoring. Utilities should consider the possibility of taking more frequent measurements or

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installing computerized battery monitors that will continuously track critical quantities and automatically perform tests. This will provide additional data for condition assessment and may provide a certain amount of reassurance in continuing to operate the battery as maintenance / replacement alternatives are being explored. E8.5 SCORING Battery condition indicator scoring is somewhat subjective, relying on battery condition experts. Relative terms such as “Results Normal” and “Degradation” refer to results that are compared to industry accepted levels; or to baseline or previous (acceptable) levels on this equipment; or to equipment of similar design, construction, or age operating in a similar environment. E8.6 WEIGHTING FACTORS Weighting factors used in the condition assessment methodology recognize that some Condition Indicators affect the Plant Battery Condition Index to a greater or lesser degree than other indicators. These weighting factors were arrived at by consensus among plant battery maintenance personnel and engineers with extensive experience. E8.7 MITIGATING FACTORS Every plant battery is unique and, therefore, the methodology described in this appendix cannot quantify all factors that may affect individual battery condition. It is important that the Plant Battery Condition Index arrived at be scrutinized by engineering experts. Mitigating factors specific to the utility may determine the final Plant Battery Condition Index and the final decision on replacement. E8.8 DOCUMENTATION Substantiating documentation is essential to support findings of the assessment. Test results should accompany the Power Battery Condition Assessment Summary Form. E8.9 CONDITION ASSESSMENT METHODOLOGY The condition assessment methodology consists of analyzing each condition indicator individually to arrive at a condition indicator score. The score is then weighted and summed with scores from other condition indicators. The sum is the Plant Battery Condition Index. Reasonable efforts should be made to perform Tier 1 inspections, tests, and measurements. However, when data is unavailable to properly score a condition indicator, it may be assumed that the score is “Good” or numerically equal to some mid-range number such as 2. This strategy must be used judiciously to prevent erroneous results and conclusions. In recognition of the potential impact of poor or missing data, a separate Data Quality Indicator is rated during the

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Tier 1 assessment as a means of evaluating and recording confidence in the Plant Battery Condition Index. E8.10 TIER 1 – INSPECTIONS, TESTS, AND MEASUREMENTS Tier 1 inspections, tests, and measurements are routinely accomplished as part of normal operation and maintenance, or are readily discernible by examination of existing data. Tier 1 test results are quantified below as condition indicators that are weighted and summed to arrive at a Plant Battery Condition Index. Tier 1 inspections, tests, and measurements may indicate abnormal conditions that can be resolved with standard corrective maintenance solutions. Tier 1 test results may also indicate the need for additional investigation, categorized as Tier 2 tests. Battery Condition Indicator 1 – Visual Inspection Visual inspection is an easy yet effective way to begin assessing battery condition. Battery cells should be in good condition even if the battery has been in service for many years. In the case of vented lead-acid batteries, inspection may include levels and colors of sedimentation at the bottom of the cells; condition of plates; level of electrolyte; condition of flame arresters; leaks, cracks, and corrosion of cell casing and terminals. For valve-regulated, lead-acid batteries, inspection should include looking for bulges, leaks, and cracks in cell casings and corrosion of cell terminals. Results of visual inspection are applied to Table 1 to arrive at an appropriate Condition Indicator Score.

Table 1 – Visual Inspection Scoring Results Condition Indicator Score

Inspection normal. 3

Minor degradation – no cracks or leaks, minimal corrosion; minimal sedimentation; normal electrolyte level. 2

Significant degradation – no cracks; few if any unrepairable leaks; moderate corrosion; moderate sedimentation; normal electrolyte level or needing minimal replacement.

1

Extreme degradation – cracks, leaks, or corrosion leaching into cell or cable; heavy sedimentation (quantity or size), consistently low electrolyte.

0

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Battery Condition Indicator 2 – Age Battery age is important as an indicator of remaining life. VLA batteries have life expectancies of about 20 years if properly maintained.1 VRLA batteries have significantly less life – typically 5 to 7 years2 – and must be maintained much more diligently than VLA batteries. Therefore, many utilities do not use VRLA batteries as plant batteries. Apply the battery age to either Table 2 or Table 3 to arrive at the Condition Indicator Score.

Table 2 – Age Scoring – Vented Lead-Acid

Age Condition Indicator Score

< 12 years (< 60% of expected life) 3

≥ 12 and < 16 years (≥ 60 and < 80% of expected life) 2

≥ 16 and < 20 years (≥ 80 and < 100% of expected life) 1

≥ 20 years (≥ 100% of expected life) 0

Table 3 – Age Scoring – Valve Regulated Lead-Acid

Age Condition Indicator Score

< 3 years (< 60% of expected life) 3

≥ 3 and < 5 years (≥ 60 and < 80% of expected life) 2

≥ 5 and < 7 years (≥ 80 and < 100% of expected life) 1

≥ 7 years (≥ 100% of expected life) 0 Battery Condition Indicator 3 – Routine Testing Utilities conduct routine testing of batteries as part of a scheduled maintenance program. Test types and frequency vary between utilities but often include the following tests and measurements: Vented Lead-Acid:

• Impedance or internal resistance test • Battery and cell float voltages • Specific gravity readings

1 The manufacturer should be consulted for life expectancy values for specific batteries. 2 Experience has shown that manufacturers’ VRLA life expectancy data may be overly optimistic.

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• Temperature readings • Connection resistance

Valve-Regulated Lead-Acid:

• Impedance test or internal resistance • Battery and cell float voltages • Temperature readings • Connection resistance

Qualified personnel should make a subjective determination of scoring that encompasses as many operation and maintenance factors as possible under this indicator. Results of Routine Testing are analyzed and applied to Table 4 to arrive at an appropriate Condition Indicator Score.

Table 4 – Routine Testing Scoring

Results Condition Indicator Score Results Normal: {Impedance/Internal Resistance: Less than 105% of baseline for multi-cell VRLA jars OR Impedance/Internal Resistance: Less than 115% of baseline for single-cell VLA or VRLA jars} AND Float Voltages: Less than +/- 0.5% difference from manufacturer’s data AND Specific Gravity: Less than - 0.005 difference from manufacturer’s data AND Temperature: Cell variance less than +/- 2 °F AND Connection Resistance: Less than 110% of baseline (VLA or VRLA) excluding long jumpers.*

3

Minimal Deviation from Normal: {Impedance/Internal Resistance: Less than 115% of baseline for multi-cell VRLA jars OR Impedance/Internal Resistance: Less than 125% of baseline for single-cell VLA or VRLA jars} AND Float Voltages: Less than +/- 1% difference from manufacturer’s data

2

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AND Specific Gravity: Less than - 0.010 difference from manufacturer’s data AND Temperature: Cell variance less than +/- 4 °F AND Connection Resistance: Less than 120% of baseline (VLA or VRLA) excluding long jumpers.* Significant Deviation from Normal: {Impedance/Internal Resistance: Less than 125% of baseline for multi-cell VRLA jars OR Impedance/Internal Resistance: Less than 135% of baseline for single-cell VLA or VRLA jars} AND Float Voltages: Less than +/- 2% difference from manufacturer’s data AND Specific Gravity: Less than - 0.015 difference from manufacturer’s data AND Temperature: Cell variance less than +/- 5 °F AND Connection Resistance: Less than 150% of baseline (VLA or VRLA) excluding long jumpers.*

1

Extreme Deviation from Normal: {Impedance/Internal Resistance: Greater than or equal to 125% of baseline for multi-cell VRLA jars OR Impedance/Internal Resistance: Greater than or equal to 135% of baseline for single-cell VLA or VRLA jars} OR Float Voltages: Greater than or equal to +/- 2% difference from manufacturer’s data OR Specific Gravity: Greater than or equal to - 0.015 difference from manufacturer’s data OR Temperature: Cell variance greater than or equal to +/- 5 °F OR Connection Resistance: Greater than or equal to 150% of baseline (VLA or VRLA) excluding long jumpers.*

0

* Connection resistance is not an indicator of battery capacity unless the resistance cannot be

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reduced by cleaning and re-torquing to manufacturer’s recommendations. The impedance test is a primary indicator of battery capacity. Regardless of the results of other routine tests (or age or visual inspection) or the Tier 1 Plant Battery Condition Index score, if the impedance test shows degradation per utility standards then an immediate capacity test as described in Tier 2 is indicated. E8.11 TIER 1 – PLANT BATTERY CONDITION INDEX CALCULATIONS Enter the condition indicator scores from the tables above into the Plant Battery Condition Assessment Summary form at the end of this document. Multiply each condition indicator score by the Weighting Factor, and sum the Total Scores to arrive at the Tier 1 Plant Battery Condition Index. E8. 12 PLANT BATTERY DATA QUALITY INDICATOR

The Plant Battery Data Quality Indicator reflects the quality of the inspection, test and measurement results used to evaluate the battery condition. The more current and complete the inspections, tests, and measurements, the higher the rating for this indicator. The normal testing frequency is defined as the organization’s recommended frequency for performing the specific inspection, test, or measurement. Qualified personnel should make a subjective determination of scoring that encompasses as many factors as possible under this indicator. Results are analyzed and applied to Table 5 to arrive at a Plant Battery Data Quality Indicator Score.

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Table 5 – Plant Battery Data Quality Scoring

Results Data Quality Indicator Score

All Tier 1 inspections, tests and measurements were completed within the normal testing time interval and the results are reliable.

10

Tier 1 inspections, tests and measurements were completed < 150 percent of the normal testing time interval and the results are reliable.

7

Tier 1 inspections, tests and measurements were completed ≥ 150 and < 200 percent of the normal testing time interval, or some of the results are not available or are of questionable integrity.

4

Tier 1 inspections, tests and measurements were completed ≥ 200 percent of the normal testing time interval, or no results are available or many are of questionable integrity.

0

Enter the Plant Battery Data Quality Indicator Score from Table 5 into the Plant Battery Condition Assessment Summary form at the end of this document.

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E8.13 TIER 2 – INSPECTIONS, TESTS, AND MEASUREMENTS Tier 2 inspections, tests, and measurements generally require specialized equipment or training, may be intrusive, or may require an extended outage to perform. A Tier 2 assessment is not considered routine. Tier 2 inspections are intended to affect the Plant Battery Condition Index established using Tier 1 but also may confirm or refute the need for more extensive maintenance, rehabilitation, or battery replacement. For Tier 2 assessments performed, apply the appropriate adjustment factor and recalculate the Plant Battery Condition Index using the Plant Battery Condition Assessment Summary form at the end of this document. An adjustment to the Data Quality Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment. Test T2.1: Battery Capacity Test The battery capacity or load test is generally regarded by hydro powerplant engineers as the only conclusive test for determining plant battery condition. The capacity test determines the battery’s ability to provide power over a predetermined period of time. If the battery cannot pass the test, replacement of the entire battery should be considered, possibly even required, in the interest of preventing the problems described above. Replacement of a failing battery should take place before the battery is required to respond in an emergency. The impedance test (see Tier 1) identifies batteries and cells that might not have sufficient capacity. The capacity test is clearly indicated for batteries that do not pass the utility’s impedance test. Despite popular myth, the capacity test in not destructive to the battery. A healthy battery will not be negatively affected by a load test. Capacity testing is supported by IEEE, NFPA, battery manufacturers, and most utility maintenance experts. It is the only effective way to measure the battery’s ability to meet an emergency demand. Whether the capacity test is regularly scheduled or triggered by Tier 1 tests, this guide assumes that test results are current and accurate. In some cases, it may be necessary to conduct the capacity test to complete this assessment. If Tier 1 tests score highly (i.e., a Tier 1 Condition Index of “Good”) and Tier 1 tests are current (i.e., a high Data Quality Indicator) and a Capacity Test has been performed recently, conducting the Capacity Test may not be necessary. The utility’s maintenance practice should be consulted. Results of the Battery Capacity Test are applied to Table 6 to arrive at an appropriate Condition Indicator Score.

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Table 6 – Battery Capacity Test

Test Results Adjustment to Tier 1 Condition Index

≥ 90% capacity No Change ≥ 80 and < 90% capacity Subtract 5.0

< 80% capacity Subtract 10.0 Note: New batteries often start with a capacity that may be as low as 90% of rated. This capacity will increase to 100% over the first 1 to 3 years of charging. This must be taken into account when applying Capacity Test results to Table 6. Test T2.2: Other Specialized Diagnostic Tests Additional tests may be applied to evaluate specific battery problems. When conclusive results from other diagnostic tests are available, they may be used to make an appropriate adjustment to the Plant Battery Condition Index. E8.14 PLANT BATTERY CONDITION INDEX CALCULATIONS Enter the Tier 2 adjustments from the tables above into the Plant Battery Condition Assessment Summary form at the end of this guide. Subtract the sum of these adjustments from the Tier 1 Plant Battery Condition Index to arrive at the Net Plant Battery Condition Index. Attach supporting documentation. An adjustment to the Data Quality Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment.

E8.15 PLANT BATTERY CONDITION-BASED ALTERNATIVES After review by a battery expert, the Plant Battery Condition Index is suitable for use in a risk-and-economic analysis model. The condition index may be deemed sufficient in itself for decision-making regarding plant battery alternatives, in which case the Plant Battery Condition Index may be directly applied to Table 7.

Table 7 – Plant Battery Condition Index-Based Alternatives

Plant Battery Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat this condition assessment process as needed.

≥ 3.0 and < 7 (Fair) Continue operation. Accelerate testing and plan for battery replacement.

≥ 0 and < 3.0 (Poor) Replace battery immediately.

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PLANT BATTERY TIER 1 CONDITION ASSESSMENT SUMMARY

Date: ________________________ Location: ________________________________________

Battery Identifier: ______________ Type: _________________

Location: ___________________ Manufacturer: ____________________ Yr. Mfd.: _________

No. of Cells: ____________ Voltage: __________________

Tier 1 Plant Battery Condition Summary

(For instructions on indicator scoring, please refer to condition assessment guide) No. Condition Indicator Score × Weighting Factor = Total Score

1 Visual Inspection (Score must be 0, 1, 2, or 3) 0.833

2 Age (Score must be 0, 1, 2, or 3) 0.833

3 Routine Testing (Score must be 0, 1, 2, or 3) 1.667

Tier 1 Plant Battery Condition Index (Sum of individual Total Scores)

(Condition Index should be between 0 and 10)

Tier 1 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________ (Attach supporting documentation.)

Plant Battery Condition Index-Based Alternatives

Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat this condition assessment process as needed.

≥ 3.0 and < 7 (Fair) Continue operation. Accelerate testing and plan for battery replacement.

≥ 0 and < 3.0 (Poor) Replace battery immediately.

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PLANT BATTERY TIER 2 CONDITION ASSESSMENT SUMMARY

Date: ________________________ Location: ________________________________________

Battery Identifier: ______________ Type: _________________

Location: ___________________ Manufacturer: ____________________ Yr. Mfd.: _________

No. of Cells: ____________ Voltage: __________________

Tier 2 Plant Battery Condition Summary

Adjustment to Tier 1 No. Tier 2 Test Condition Index

T2.1 Capacity Test (If capacity test is not required, enter zero)

T2.2 Other Specialized Diagnostic Tests

Tier 2 Adjustments to Plant Battery Condition Index (Sum of individual Adjustments)

Tier 2 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

To calculate the Net Plant Battery Condition Index (Value should be between 0 and 10), subtract the Tier 2 Adjustments from the Tier 1 Plant Battery Condition Index: Tier 1 Plant Battery Condition Index __________ minus Tier 2 Plant Battery Adjustments __________ = ________________ Net Plant Battery Condition Index Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________

(Attach supporting documentation.)

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September 2006 Hydro Plant Risk Assessment Guide Appendix E9: Crane Condition Assessment E9.1 GENERAL Cranes are key safety components to support the power train at hydroelectric powerplants. Crane failure can have a significant economic impact due to the high cost of emergency repairs and lost revenues during an extended outage. A crane failure risks an even greater impact to personal safety if an accident as a result of equipment failure should occur. Determining the present condition of a crane is an essential step in analyzing the risk of failure. This appendix provides a process for arriving at a Crane Condition Index which may be used to develop a business case addressing risk of failure, economic consequences, and other factors. E9.2 SCOPE / APPLICATION The condition assessment methodology outlined in this appendix applies to hydroelectric powerplant cranes. The condition assessment primarily focuses on overhead and gantry cranes used at the intake deck, generator/turbine room, and tailrace decks of hydroelectric powerplants. The appendix can be used to evaluate monorail hoists used for handling draft tube bulkheads/gates. This appendix is not intended to define maintenance practices or describe in detail inspections, tests, or measurements. Utility-specific maintenance policies, procedures, and guidelines must be consulted for such information. E9.3 CONDITION AND DATA QUALITY INDICATORS, AND CRANE CONDITION

INDEX This appendix describes the condition indicators generally regarded by hydro plant engineers as providing the initial basis for assessing the condition of the crane. The following indicators are used to separately evaluate the condition of the crane:

• Physical Condition • Design Criteria • Maintenance Requirements • Age

These condition indicators are initially evaluated using Tier 1 inspections, tests, and measurements, which are conducted by utility staff or contractors over the course of time and as

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a part of routine maintenance activities. Numerical scores are assigned to each condition indicator, which are then weighted and summed to determine the Crane Condition Index. An additional stand-alone indicator is used to reflect the quality of the information available for scoring the condition indicators. In some cases, data may be missing, out-of-date, or of questionable integrity. Any of these situations could affect the accuracy of the associated condition indicator scores as well as the validity of the overall Crane Condition Index. Given the potential impact of poor or missing data, the Data Quality Indicator is used as a means of evaluating and recording confidence in the final Crane Condition Index. Additional information regarding crane condition may be necessary to improve the accuracy and reliability of the Crane Condition Index. Therefore, in addition to the Tier 1 condition indicators, this appendix describes a “toolbox” of Tier 2 inspections, tests, and measurements that may be applied to the Crane Condition Index, depending on the specific issue or problem being addressed. Tier 2 analyses are considered non-routine. However, if Tier 2 data is readily available, it may be used to supplement the Tier 1 assessment. Alternatively, Tier 2 tests may be deliberately performed to address Tier 1 findings. Results of the Tier 2 analysis may either increase or decrease the score of the Crane Condition Index. The Data Quality Indicator score may also be revised during the Tier 2 assessment to reflect the availability of additional information or test data. The Crane Condition Index may indicate the need for immediate corrective actions and/or follow-up Tier 2 testing. The Crane Condition Index is also suitable for use as an input to the risk-and-economic analysis model. Note: A severely negative result of ANY inspection, test, or measurement may be adequate in itself to require immediate placing the crane out of service and requiring corrective action before returning the crane into service, regardless of the Crane Condition Index score. E9.4 INSPECTIONS, TESTS, AND MEASUREMENTS Inspections, tests, and measurements should be conducted and analyzed by staff suitably trained and experienced in the equipment being inspected. The more basic tests may be conducted by qualified staff that is competent in these routine procedures. More complex inspections and measurements may require an expert. Inspections, tests, and measurements should be conducted on a frequency that provides the accurate and current information needed by the assessment. Details of the inspection, testing, and measurement methods and intervals are described in technical references specific to the electric utility. E9.5 SCORING Condition indicator scoring is somewhat subjective, relying on the experience and opinions of experts. Relative terms such as “Results Normal” and “Degradation” refer to results that are

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compared to industry-accepted levels; or to baseline or previous (acceptable) levels on this equipment; or to equipment of similar design, construction, or age operating in a similar environment. E9.6 WEIGHTING FACTORS Weighting factors used in the condition assessment methodology recognize that some Condition Indicators affect the Crane Condition Index to a greater or lesser degree than other indicators. These weighting factors were arrived at by consensus among design and maintenance personnel with extensive experience. E9.7 MITIGATING FACTORS Every crane is unique and, therefore, the methodology described in this appendix cannot quantify all factors that affect individual condition. It is important that the Crane Condition Index arrived at be scrutinized by experts. Mitigating factors specific to the utility may determine the final Crane Condition Index and the final decision on replacement or rehabilitation of the system. E9.8 DOCUMENTATION Substantiating documentation is essential to support findings of the assessment, particularly where a Tier 1 Condition Indicator score is less than 3 or where a Tier 2 analysis results in subtractions to the Crane Condition Index. Test reports, facility review reports, special exams, photographs, O & M records, and other documentation should accompany the Crane Condition Assessment Summary Form. E9.9 CONDITION ASSESSMENT METHODOLOGY The condition assessment methodology consists of analyzing each condition indicator individually to arrive at a condition indicator score. The scores are weighted and summed to determine the Condition Index. Reasonable efforts should be made to perform Tier 1 inspections, tests, and measurements. However, when data is unavailable to properly score the Condition Indicator, it may be assumed that the score is “Good” or numerically equal to some mid-range number such as 2. This strategy must be used judiciously to prevent erroneous results and conclusions. In recognition of the potential impact of poor or missing data, a separate Data Quality Indicator is rated as a means of evaluating and recording confidence in the final Crane Condition Index. E9.10 TIER 1 – INSPECTIONS, TESTS, AND MEASUREMENTS Tier 1 includes those inspections, tests, and measurements that are routinely accomplished as part of normal operation and maintenance, or are readily discernible by examination of existing

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data. Tier 1 results are quantified below as condition indicators that are weighted and summed to arrive at a Condition Index. A Tier 1 analysis may indicate abnormal conditions that can be resolved with standard corrective maintenance solutions. In this case, the identified corrective action should be completed immediately; after which, adjustments can be made to the Condition Indicator and Condition Index. The Tier 1 results may also indicate the need for an additional investigation, categorized as a Tier 2 analysis. E9.11 TIER 1 – CRANE CONDITION INDICATORS Condition Indicator 1 – Physical Condition of Crane The known physical condition of the crane is a helpful indicator of crane reliability. This indicator is based on maintenance records and the most recent inspection reports only. Use the score of the worst component of the crane regardless of the overall or general condition of the crane. Results of the crane physical inspection are analyzed and applied to Table 1 to arrive at a Condition Indicator Score.

Table 1 – Crane Physical Condition

Results Condition 1

Indicator Score Excellent Condition:

• Crane surfaces and coatings are free of corrosion; • No structural damage or cracks; no loose bolts or rivets found; • Couplings are tight and properly aligned; • Moving parts are lubricated; • Gearbox oil is free from contaminants and moisture; • No groove wear on drums or sheaves; • Bearings have no wear and are well lubricated; • Oil seals do not leak; • Gears are properly aligned and have no wear; • Hoist ropes have no broken strands or deformation; • The rope is laying properly on the drum; • Limit switches are properly set and functioning properly; • Brakes have no wear and operate properly; there is no record of loads

slipping with the brakes applied; • No unusual noises or binding of any mechanism during operation; • Electrical components are clean and function properly; • Controls function properly; • Motors are clean and current draw is within limits; motor brushes and

rings show minimal wear; • Hooks or grapples are free of nicks, gouges and cracks and swivel freely;

hook latches function properly; • All wheels contact the rails, run smoothly and show no signs of wear; • Below-the-block lifting devices are in good condition; • Spare parts are readily available.

3

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Good Condition:

• Crane surfaces and coatings have minor defects or corrosion; • No structural damage or cracks; no loose bolts or rivets found; • Couplings are tight and properly aligned; • Moving parts are lubricated; • Gearbox oil has minor contaminants noted; • No groove wear on drums or sheaves; • Oil seals do not leak; • Gears are properly aligned and have no wear; • Hoist ropes have no broken strands or deformation; • The rope is laying properly on the drum; • Limit switches are properly set and functioning properly; • Brake pads have ≥ 50% of the lining left and operate properly; • No unusual noises or binding of the mechanism during operation; • Electrical components are clean and functional; • Controls function properly; • Motors are clean and current draw is within limits; motor brushes and

rings show minimal wear; • Hooks or grapples are free of nicks, gouges and cracks and swivel freely;

hook latches function properly; • All wheels contact the rails, run smoothly and have minimal wear; • Below-the-block lifting devices are in good condition; • Spare parts are somewhat available.

2

Fair Condition: • Crane surfaces and coatings have minor defects or corrosion; • Minimal structural damage with no cracks; • Couplings are tight and properly aligned; • Gearbox oil has minor contaminants or water is noted; • Some groove wear on drums or sheaves; • Oil seals have minor leaks; • Gears are misaligned but no major wear or damage to the gears; • Hoist ropes have broken strands within the allowable limit of ASME

B30.2; • Limit switches are properly set and functioning properly; • Brakes pads have ≥ 20% of the lining left and operate properly; • Some unusual noises are noted during operation; • Electrical components are dirty; • Controls have minor problems; • Motor current draw is excessive; • Hooks have minor defects and some wear; • All wheels contact the rails but have some wear noted; • There are multiple trouble reports on record such as repairs to the

electrical controls; • Spare parts are somewhat difficult to obtain.

1

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Poor Condition:

• There are serious concerns with the crane’s condition such as: • Operational restrictions or limits have been placed on the crane; • Major corrosion on the critical components; • Indication of frame skewing or ≥ 10% loose fasteners; • Wire rope corrosion, broken strands or deformation; • Brake pads have < 20% of the lining left; • Significant lubricating oil contamination; • Unusual noises or vibrations during operation; • Control problems; • Motors often trip out, vibrate or run hot; brittle or asbestos containing

wiring insulation; • Hooks and grapples have increased throat opening or are bent; have

cracks, nicks or gouges or abnormal wear; • Wheels do not contact rail or racking and binding of wheels occur during

travel; wheels are worn extensively; • Frequent trouble reports; • Spare parts are very difficult to obtain.

0

Note: A severely negative result of ANY inspection, test, or measurement may be adequate in itself to require immediate placing the crane out of service and requiring corrective action before returning the crane into service, regardless of the Crane Condition Index score. Condition Indicator 2 – Design Criteria This condition indicator only addresses the conformity of the crane design to current and future needs and to the requirements specified in current regulations and codes. Use the score of the most severe design criteria deficiency regardless of the overall or general condition of the crane. Design factors that may apply are:

• Crane capacity criteria (Can the crane lift the heaviest load without exceeding its rated capacity?);

• Crane duty criteria (Is the crane being used, or will be used, for more severe duty than for which it was designed? Is there an upcoming powerhouse rehabilitation requiring heavy crane usage?);

• Different handling needs (Is the crane being used, or does it need, to lift bulkier or different types of equipment than for which it was designed?);

• Regulations and crane codes requirements (Does the crane meet present standards and regulations, or are there deficiencies?).

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Table 2 – Design Criteria Scoring

Results Condition 2

Indicator Score • Heaviest lift < 100% of rated capacity. • Crane usage is appropriate for its duty classification. • Crane configuration is adequate for handling intended loads. • Crane has no regulation and code violations.

3

• Heaviest lift < 100% of rated capacity. • Crane usage is slightly higher than appropriate for its duty

classification. • Crane configuration is adequate for handling intended loads. • Crane has no regulation and code violations; however may

not have features required in new regulations and codes that are not required for older cranes.

2

• Heaviest lift is ≥ 100 and < 110% of rated capacity. • Crane usage is moderately higher than appropriate for its duty

classification. • Crane has minor handling deficiencies, may need

modifications to handle loads properly. • Crane has minor regulation and code violations. Also, may

not have features required in new regulations and codes that are not required for older cranes.

1

• Heaviest lift ≥ 110% of rated capacity. • Crane usage is considerably higher than appropriate for its

duty classification. • Crane has serious handling deficiencies, needs modifications

to handle loads properly. • Crane has major regulation and code violations.

0

Note: A severely negative result of ANY inspection, test, or measurement may be adequate in itself to require immediate placing the crane out of service and requiring corrective action before returning the crane into service, regardless of the Crane Condition Index score. Condition Indicator 3 – Maintenance Requirements This condition indicator addresses the amount of maintenance that the crane currently requires. A lack of maintenance will be reflected in the Condition Indicator for Physical Condition. The Maintenance Requirements Indicator is broken into 3 categories: Small, Moderate and Extensive.

• Small: A small amount of routine annual preventative maintenance is required for the crane.

• Moderate: Moderate levels of maintenance would include some corrective maintenance. • Excessive: Excessive maintenance is intended to include labor-intensive items. Frequent

repairs or abnormal wear to components would be considered excessive.

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Table 3 – Maintenance Requirements Scoring

Results Condition 3

Indicator Score Small 3

Moderate 2 Excessive 1

Condition Indicator 4 – Age of Crane Age is a factor to consider when assessing the condition of a crane. Rate the system on the oldest (not rehabilitated or refurbished) major component (mechanical equipment, crane structure, electrical equipment). Use the year a component was last completely rehabilitated or refurbished; otherwise, use the year it was put into service. Results of the age analyses are applied to Table 4 to arrive at an appropriate Crane Age Indicator Score.

Table 4 – Age of Crane

Results Condition 4

Indicator Score < 20 years 3

≥ 20 and < 35 years 2 ≥ 35 years 1

E9.12 TIER 1 – CRANE CONDITION INDEX CALCULATIONS Enter the Crane condition indicator scores from Tables 1-4 above into the Crane Assessment Summary Form at the end of this document. Multiply each indicator score by its respective Weighting Factor, and sum the total scores to arrive at the Tier 1 Crane Condition Index. This index may be adjusted by the Tier 2 Crane inspections, tests, and measurements described later in this document. E9.13 TIER 1 – CRANE DATA QUALITY INDICATOR The Crane Data Quality Indicator reflects the quality of the inspection, test and measurement results used to evaluate the crane condition under Tier 1. The more current and complete the results are, the higher the rating for this indicator. The normal testing frequency is defined as the organization’s recommended frequency for performing crane periodic inspection. Qualified personnel should make a subjective determination of scoring that encompasses as many factors as possible under this indicator. Results are analyzed and applied to Table 5 to arrive at a Crane Data Quality Indicator Score.

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Table 5 – Crane Data Quality

Results Crane Data Quality

Indicator Score The last crane periodic inspection was performed within the normal inspection frequency and results are reliable. 10

The last crane periodic inspection was performed < 36 months past the normal inspection frequency and results are reliable. 7

The last crane periodic inspection was performed ≥ 36 and < 60 months past the normal inspection frequency OR some of the results are not available or are of questionable integrity.

4

The last crane periodic inspection was performed ≥ 60 months past the normal inspection frequency OR many results are of questionable integrity or no results are available.

0

Enter the Crane Data Quality Indicator Score from Table 5 into the Crane Condition Assessment Summary form at the end of this document. E9.14 TIER 2 – CRANE INSPECTIONS, TESTS, AND MEASUREMENTS Tier 2 inspections, tests, and measurements require specialized personnel to inspect the cranes and interview plant O & M staff. A Tier 2 assessment is not considered routine. Tier 2 inspections may affect the Crane Index established using Tier 1. A team consisting of the Plant O & M Representative and Technical Support Staff should perform Tier 2 assessments. The tasks to be performed for Tier 2 are summarized below:

1. Technical support staff will be responsible to:

• Visit the plant to perform a physical inspection of the crane being evaluated and interview O & M staff.

• Determine current condition of the crane. • Review and, if necessary, adjust the Tier 1 Condition Index based upon the

inspection and comparison with the condition of other similar cranes.

2. Plant O & M Representative will be responsible to:

• Provide necessary assistance and information to Technical Support staff. • Assist in the assessment process.

For each Tier 2 test performed, add or subtract the appropriate amount to/from the appropriate Tier 1 Condition Indicator and recalculate the Crane Condition Index using the Crane Condition Assessment Summary form at the end of this document. An adjustment to the Data Quality

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Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment. Note: As in Tier 1 evaluations, any single condition that is severe enough could justify corrective action even if the overall condition index does not indicate as such. E9.5 TIER 2 – CRANE CONDITION INDICATORS The Tier 2 evaluation is divided up into sections:

• Structural Integrity • Mechanical Integrity • Electrical Integrity • Operation • Miscellaneous Deficiencies • Maintenance Escalation • Other Specialized Diagnostic Tests

Test T2.1: Structural Integrity The physical deterioration of the crane structure is likely to be from one or more of the following factors evaluated here:

• Corrosion • Yielding, Fracture, Fatigue, and Fabrication Discontinuities • Field Repair and Modification • Miscellaneous Damage or Condition

Test T2.1.1: Corrosion Corrosion typically causes the most damage to cranes. Special attention should be paid to critical areas such as welds, member interfaces, and connectors. Corrosion nodes should be chipped off to reveal the true extent of metal deterioration.

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Table 6 – Corrosion

Rating Adjustment to

Condition Index Score Good – Corrosion has not caused significant loss of cross sectional area for structural members, corrosion buildup has not caused separation in adjacent members, localized corrosion has not reduced weld areas significantly, protective coatings in good condition, little or no cavitation.

Add 1.0

Moderate – Small amounts of cross sectional area have been lost in some members, there is isolated plate separation caused by corrosion, some pitting, some weld area reduction in some welds, protective coating in fair condition.

No Change

Severe – Significant cross sectional area loss in critical members, widespread plate and/or member separation, significant weld size loss due to corrosion, significant pitting protective coating in poor condition.

Subtract 1.0

Test T2.1.2: Yielding, Fracture, Fatigue, and Fabrication Discontinuities Yielding and fracture of structural members and weldments can compromise structural integrity and deserve special attention. They can occur from a variety of causes including, but not limited to: impact, fatigue loading, material defect, and design overload. Fractures usually occur where there are local stress raisers. This occurs where there is a local geometry change. Examples of this are bolt/rivet holes, sharp inside corners, corrosion pits, and weldments. Cracking of weldments or base metals is particularly problematic where thick members are welded together or there are dimensioning errors. Improper welding techniques and welding in an inaccessible area can also lead to problematic discontinuities. Welding discontinuities take many forms and are usually identified by visual inspection. Weldments can also be tested by nondestructive methods if necessary.

Table 7 – Yielding, Fracture, Fatigue, and Fabrication Discontinuities

Rating Adjustment to

Condition Index Score Good – No visible yielding or buckling, there is little to no cracking near welds and/or stress concentrators. Any cracks have not propagated significantly.

Add 1.0

Moderate – May be slight yielding; cracking near stress concentrators or welds is intermittent with little or no propagation. Can justify the use of nondestructive testing on some welds.

No Change

Severe – Significant yielding or buckling in critical members, cracking in a sequence of welds, crack propagation in many cracks. Usually justifies the use of nondestructive testing on most welds.

Subtract 1.0

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Test T2.1.3: Field Repair and Modification Cranes that have been significantly modified in the field without proper engineering and quality control may be structurally compromised. Improper repairs include, but are not limited to:

• Replacing parts with lesser quality or strength parts than the crane was engineered for (bolts, skin plates, picking eyes, structural steel, etc.);

• Protective coatings that are improperly formulated or applied; • Cutting of beam webs or flanges; • Improper welding/rewelding.

Table 8 – Field Repair and Modification

Rating Adjustment to

Condition Index Score Good – No field repairs or modifications done without proper engineering analysis. No Change

Moderate – Some minor repairs, not likely to cause failure. Subtract 0.5 Severe – Major modifications that severely compromise the structural integrity of the crane. Subtract 1.0

Test T2.1.4: Miscellaneous Damage or Condition Any damage or condition that is not explicitly in the categories of corrosion, yielding, fracture, design discontinuities, improper field repair and modification, or unforeseen loadings.

Table 9 – Miscellaneous Damage or Condition

Rating Adjustment to

Condition Index Score Good No Change

Moderate Subtract 0.5 Severe Subtract 1.0

Test T2.2: Mechanical Integrity The integrity of the following mechanical components of the crane is evaluated here:

• Wire Rope/Chain • Drums and Sheaves • Gearbox, External Gearing, and Chain Sprockets • Bearings, Bushings, and Couplings • Wheels • Hooks and Load Blocks

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Test T2.2.1: Wire Rope/Chain Wire ropes and chain carry the load and must be in serviceable condition. Failure or these devices could cause significant economic and life safety impact. It is important to examine the entire length of wire rope, especially the underside of the rope that commonly comes in contact with the hoist drum or sheaves as the top of the rope can be in good condition while the bottom side can be severely worn. Other problems with wire rope include but are not limited to: corrosion (loss of cross sectional area) and broken wires, strands, and cores from abrasion, fatigue, deformation, and material defect. Traditionally, tests have been visual, but there is now a non-destructive test method called Magnetic Flux Leakage (MFL) test that can be performed on wire rope that will reveal deficiencies not easily identified by visual inspections. MFL may be justified for critical applications such as emergency closure cranes and hoists. Hoist chain is difficult to inspect and is not usually cost effective (if thought to be defective) as it can be easily replaced relatively inexpensively.

Table 10 – Wire Rope/Chain

Rating Adjustment to

Condition Index Score Good – Wire rope in good condition with no significant loss in cross sectional area, no broken wires, corrosion is superficial. Rope greased sufficiently. Chain in good condition, withstands proof loads.

No Change

Moderate – Few broken wires, no broken strands or cores. Corrosion and or lubrication could be better. Wire rope in serviceable condition. Minor wire kinking or crushing. Chain in marginal condition but withstands proof loads.

Subtract 0.5

Severe – Broken core or strands, neglected cable with significant corrosion, 15% or more reduction in cross sectional area reduction at any point in cable. Wire kinked or crushed severely. Chain in poor condition usually justifying replacement.

Subtract 1.0

Test T2.2.2: Drums and Sheaves Hoist drums and sheaves should be checked for wear and general operating condition. Structural deficiencies should have already been noted in the Structural Integrity section.

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Table 11 – Drums and Sheaves

Rating Adjustment to

Condition Index Score Good – Hoist drum in good condition, no major deficiencies. Wire rope is correctly secured to drum, wire rope is not over spooled when load blocks are in 100% up condition.

Add 0.5

Moderate – Drums and sheaves in service able condition with normal wear. No Change

Severe – Drum highly worn in groves, alignment incorrect, sheaves worn. Subtract 0.5

Test T2.2.3: Gearbox, External Gearing, and Chain Sprockets Gearbox should be operated through a full operation cycle and be observed for abnormal sounds that may indicate internal problems. Opening, draining, cleaning and inspection of gearbox internals may be justified. Lube oil may be sampled to test the condition. External leakage should also be noted.

Table 12 – Gearbox, External Gearing, and Chain Sprockets

Rating Adjustment to

Condition Index Score Good – Gearbox in good working condition. Gearbox internals (if inspected) are in good working order, gear tooth wear is minimal with even wear pattern, bushing and bearings are in good shape, and seals don’t leak externally. External gearing and chain sprockets are in good shape.

Add 0.5

Moderate – Gearbox is serviceable. Gearing (if inspected) is in good shape, no cracking, moderate tooth wear and/or uneven wear pattern. Some metal accumulation in bottom or gearbox. Gearbox, gearing, and chain sprockets serviceable for ≥ 7 to < 10 years.

No Change

Severe – Gearbox in poor condition. Extreme wear and/or cracking on teeth, substantial metal accumulation in gearbox, dirty or insufficient gear lube, seals leak extensively, bearings or bushings in poor condition. Gearbox, gearing, and chain sprockets serviceable for 0 to < 7 years.

Subtract 0.5

Test T2.2.4: Bearings, Bushings, and Couplings Bearings, bushings, and couplings are subject to normal wear and tear and are subject to a finite life span. Bearing and bushings (those inside gearbox were inspected as part of the Gearbox and External Gearing section) should be inspected where possible for wear, damage, installation error, and manufacture malfunction. Since this section rating could encompass many bearings and bushing, the rater should rate the overall condition of all the bearings, noting individual bearings, bushings, or couplings that need immediate repair.

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Table 13 – Bearings, Bushings, and Couplings

Rating Adjustment to

Condition Index Score Good – Bearings, bushings, and couplings are in good shape and need little or no attention. Add 0.5

Moderate – Some repair needed on individual bearings, bushings, and couplings. No Change

Severe – System wide poor condition of bearings, bushings, and couplings, easier to overhaul everything than attempt individual repair to select bearings, bushings and couplings.

Subtract 0.5

Test T2.2.5: Wheels Wheels are subject to normal wear and tear and are subject to a finite life span. Since this section rating could encompass many wheels, the rater should rate the overall condition of all the wheels, noting individual wheels that need immediate repair.

Table 14 – Wheels

Rating Adjustment to

Condition Index Score Good – Wheels are in good shape and need little or no attention. Add 0.5 Moderate – Wheels have wear, but still serviceable. No Change Severe – Wheels need replacing. Subtract 0.5 Test T2.2.6: Hooks and Load Blocks Hooks and load blocks are subject to normal wear and tear and are subject to a finite life span. Since this section rating could encompass several hooks and load blocks, the rater should rate the overall condition of all the hooks and load blocks, noting individual hooks or load blocks that need immediate repair.

Table 15 – Hooks and Load Blocks

Rating Adjustment to

Condition Index Score Good – Hooks and load blocks are in good shape and need little or no attention. Add 0.5

Moderate – Some repair needed on individual hooks and load blocks. No Change

Severe – Major repairs or replacement required. Subtract 0.5

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Test T2.3: Electrical Integrity The integrity of the electrical system of the crane is evaluated under these focus areas:

• Incoming Power Source • Power and Ancillary Systems Components • Control System Components • Availability of Spare Parts

Test T2.3.1: Incoming Power Source The crane’s incoming power source should be evaluated for overall condition and performance. Systems and equipment included in this part of the evaluation include the power supply feeder, runway conductors and collectors, and cable reel mechanisms, diesel generator sets or other devices used to transfer power to the crane.

Table 16 – Incoming Power Source

Rating Adjustment to

Condition Index Score Good – Power source functions continuously on the entire length of the crane’s runway. No power loss or nuisance trips due to loss of contact with power source or excessive voltage drop observed. Cable reel has enough cable available to service the entire runway from available outlets, and no splices or damaged areas are noted in the cable. Diesel generator set functions properly.

Add 0.5

Moderate – Power source functions continuously on ≥ 75% of the crane’s runway, and the < 25% of non-continuous operation occurs on sections of the runway where the crane does not perform frequent service. Cable reel mechanism is problematic or cable appears worn, but continues to deliver uninterrupted power to the crane. Diesel generator set requires routine to frequent maintenance.

No Change

Severe – Power source does not function continuously on the entire length of the runway. Nuisance trips are frequent. Runway conductors are misaligned, have excessive insulated expansion gaps, or experience excessive sag due to environmental or loading conditions. Cable reel mechanism is severely worn or damaged. Diesel generator set requires frequent maintenance or is poorly suited to the duty required.

Subtract 0.5

Test T2.3.2: Power and Ancillary Systems Components The integrity of the power and ancillary systems should be evaluated independently of other factors. Power system components as related to this assessment include power disconnect switches, breakers, and other power protective devices; power conductors, conduit, and raceways resident on the crane; and motors, brakes and motion control resistors. Ancillary systems include lighting equipment and other low-voltage (120 VAC) devices such as load cells and wind meters.

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Table 17 – Power and Ancillary Systems Components

Rating Adjustment to

Condition Index Score Good – Main power disconnect switch is operational and acts to remove power from the entire crane. Breakers and power contactors are sized appropriately and operate properly. Power conductors are in good overall condition, with no excessive wear, splices or damaged portions. Motors, brakes, and resistors do not exhibit excessive heating, whining, or grinding, and are adequate for their use. Lighting system adequately illuminates the crane, and other low-voltage equipment functions as designed.

Add 0.5

Moderate – Main power disconnect may or may not operate properly, but other safety measures are in place to remove power from the crane. Breakers and power contactors operate properly. Wiring is excessively worn or aged but does not pose safety hazard. Motors, brakes, and resistors function properly. Lighting system may or may not illuminate adequately, but can be marginally corrected by replacing lamps. Other low-voltage equipment functions as designed.

No Change

Severe – Main power disconnect does not operate properly. Several breakers or power contactors are not functioning properly or contacts are welded. Power and lighting conductors are damaged or severely aged, posing safety hazard. Motors exhibit excessive heating, whining, or grinding. Brakes fail to release completely, fail to hold the load while set, are missing parts, chatter, or show signs of excessive heating. Resistors are not functioning as designed, as evidenced by missing speed points or nuisance tripping during dynamic braking. Lighting system offers poor illumination and can not be corrected by replacing lamps. Low voltage equipment does not function properly.

Subtract 0.5

Test T2.3.3: Control System Components The integrity of the control system should be evaluated independently of other factors. Control system components as related to this assessment include operator’s control apparatus; control panels and enclosures; control conductors, conduit, and raceways resident on the crane; and limit switches and other control devices. It should be noted that live, 480 VAC, operator controls are considered somewhat of a potential safety hazard. While no safety standard prohibits 480 VAC operator controls on cab-operated cranes, there is an OSHA, as well as ASME, restriction against pendant controls having greater than 150 VAC or 300 VDC control circuit voltage. To be conservative, it is recommended that a crane that has operator control circuit voltage of greater than 150 VAC or 300 VDC be prohibited from receiving better than a “Moderate” rating for the Control System Components evaluation.

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Table 18 – Control System Components

Rating Adjustment to

Condition Index Score Good – Operator’s master switches and other control switches operate properly, with no “dead” speed points. Control panels and enclosures are clean, undamaged, and function as designed. Control panels and enclosures have adequate environmental ratings for their service (indoor, outdoor). Control wiring is in good overall condition. Limit switches and other control devices function as designed.

No Change

Moderate – Operator’s switches have one or two “dead” speed points but function as designed otherwise. Control panels and enclosures are dirty, slightly damaged, or do not have an adequate environmental rating for their service, but continue to function as designed. Control wiring is aged or worn but does not pose a safety hazard. Hoist and travel limit switches and other control devices do not function as designed, but may be replaced or repaired.

Subtract 0.5

Severe – Operator’s switches have more than two “dead” speed points or otherwise do not function properly. Control panels are dirty, damaged, do not have an adequate environmental rating, or otherwise do not function as designed. Control wiring is severely aged or worn and poses a safety hazard. Limit switches or other control devices do not function properly and can not be replaced or repaired.

Subtract 1.0

Test T2.3.4: Availability of Spare Parts Spare parts are essential to maintaining the health and integrity of the crane’s power, ancillary, and control systems components. As cranes age, their control systems may become technologically outdated, rendering spare parts impossible to find on short notice, or at all. Because powerhouses often do not have mobile cranes or other alternative methods available for moving large loads, it is essential for powerhouse cranes to have new spare parts available from multiple vendors. Spare parts addressed in this section include breakers, contactors, motors, electric brakes, limit switches, conductor and collector systems, control system electrical or electronic devices, and operator’s control switches.

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Table 19 – Availability of Spare Parts

Rating Adjustment to

Condition Index Score Good – All motors, brakes, electronic devices, and ≥ 75% of other spare parts of the types listed above are available and are either stored on-site or are readily available from three or more domestic vendors. Spare parts are not special-order items.

No Change

Moderate – All motors, brakes, electronic devices, and ≥ 75% of other spare parts are not available on-site but are readily available from two or three domestic vendors. Spare parts are not special-order items.

Subtract 0.5

Severe – Any hoist motor or hoist brake is not available on-site or from one or more vendors. Electronic devices and other spare parts are not available on-site, are not available by more than one domestic vendor, or are not available at all. Spare parts are special-order items only. Spare parts are available by international vendors only.

Subtract 1.0

Test T2.4: Operation Operation of crane in this section is concerned with overall system operation including misalignment, speed, and reliability.

Table 20 – Operation

Rating Adjustment to

Condition Index Score Acceptable – All hoists and travel drives operate smoothly, no vibrations or unusual noises, no control problems, no racking or binding.

No Change

Marginal – At least one hoist or travel drive operates with some vibration or unusual noises, some control problems, or some racking or binding.

Subtract 0.5

Unacceptable – At least one hoist or travel drive with severe vibration or unusual noises, severe control problems, or severe racking or binding.

Subtract 1.0

Test T2.5: Miscellaneous Deficiencies Any deficiencies not previously listed in the previous sections should be noted, the Tier 2 rater should use their judgment to assess a negative condition assessment adjustment to the Crane condition.

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Table 21 – Miscellaneous Deficiencies

Rating Adjustment to

Condition Index Score Good – Deficiency will not affect the safety or functionality of crane. No Change

Moderate – May affect the function of crane. Subtract 0.5 Severe – Will severely affect performance or structure of crane to the point where there is risk of significant economic or life loss. Subtract 1.0

Test T2.6: Maintenance Escalation Maintenance escalation for equipment is normal. Usually equipment is engineered for some finite service life rarely shortened but often exceeded. Maintenance history should be examined to determine maintenance escalation. Findings may justify performing a cost benefit analysis based on increased maintenance costs and anticipated downtime. A risk assessment based on safety may also be justified.

Table 22 – Maintenance Escalation

Rating Adjustment to

Condition Index Score Good – Maintenance escalation is less than expected. Add 0.5 Moderate – Maintenance escalation is in keeping with estimates, but is manageable by the project staff. No anticipated significant risk of system failure.

No Change

Severe – Maintenance escalation is dramatic, required maintenance has increased beyond the capacity of the project. Anticipated significant risk of system failure.

Subtract 0.5

Test T2.7: Other Specialized Diagnostic Tests Additional tests may be applied to evaluate specific crane problems. Some of these diagnostic tests may be considered to be of an investigative research nature. When conclusive results from other diagnostic tests are available, they may be used to make an appropriate adjustment to the Crane Condition Index. E9.16 TIER 2 – CRANE CONDITION INDEX CALCULATIONS Enter the Tier 2 adjustments from the tables above into the Crane Condition Assessment Summary form at the end of this guide. Subtract the sum of these adjustments from the Tier 1 Crane Condition Index to arrive at the Net Crane Condition Index. Attach supporting documentation. An adjustment to the Data Quality Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment.

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E9.17 CRANE CONDITION-BASED ALTERNATIVES After review by a crane expert, the Crane Condition Index is suitable for use in a risk-and-economic analysis model. The condition index may be deemed sufficient in itself for decision-making regarding crane alternatives.

Table 23 – Crane Condition-Based Alternatives

Generator Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat condition assessment as needed.

≥ 3.0 and < 7 (Fair) Continue operation but reevaluate O & M practices. Consider using appropriate Tier 2 tests. Repeat condition assessment process as needed.

≥ 0 and < 3.0 (Poor) Immediate evaluation including additional Tier 2 testing. Consultation with experts. Adjust O & M as prudent. Begin replacement/rehabilitation process.

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CRANE TIER 1 CONDITION ASSESSMENT SUMMARY

Date: _______________________________ Location: _________________________________

Name of Crane: ________________________________________________________________

Crane Manufacturer: __________________________ Yr. Installed: _______________________

Type of Crane: ________________________ Capacity of Crane: _________________________

Function of Crane: ______________________________________________________________

Tier 1 Crane Condition Summary

(For instructions on indicator scoring, please refer to condition assessment guide)

No. Condition Indicator Score x Weighting Factor = Total Score 1 Physical Condition

(Score must be 0, 1, 2, or 3) 3 1.2

2 Design Criteria (Score must be 0, 1, 2, or 3) 3 1.0

3 Maintenance Requirements (Score must be 1, 2, or 3) 3 0.8

4 Age (Score must be 1, 2, or 3) 3 0.333

Tier 1 Crane Condition Index (Sum of individual Total Scores)

(Condition Index should be between 0 and 10)

Tier 1 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________ (Attach supporting documentation.)

Crane Condition Index-Based Alternatives

Condition Index Suggested Course of Action ≥ 7.0 and ≤ 10 (Good) Repeat Tier 1 assessment during next periodic

inspection. ≥ 3.0 and < 7 (Fair) Schedule Tier 2 assessment within 2 years.

≥ 0 and < 3.0 (Poor) Perform crane repairs, if possible, and repeat Tier 1 assessment. Otherwise, schedule Tier 2 assessment as soon as possible.

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CRANE TIER 2 CONDITION ASSESSMENT SUMMARY

Date: _______________________________ Location: _________________________________

Name of Crane: ________________________________________________________________

Crane Manufacturer: __________________________ Yr. Installed: _______________________

Type of Crane: ________________________ Capacity of Crane: _________________________

Function of Crane: ______________________________________________________________

Tier 2 Crane Condition Summary

No. Tier 2 Test (Table No.)

Adjustment to Tier 1 Crane

Condition Index

Structural Integrity: T2.1.1 Corrosion (6) T2.1.2 Yielding, Fracture, Fatigue, and Fabrication Discontinuities (7) T2.1.3 Field Repair and Modification (8) T2.1.4 Miscellaneous Damage or Condition (9) Mechanical Integrity: T2.2.1 Wire Rope/Chain (10) T2.2.2 Drums and Sheaves (11) T2.2.3 Gearbox, External Gearing, and Chain Sprockets (12) T2.2.4 Bearings, Bushings, and Couplings (13) T2.2.5 Wheels (14) T2.2.6 Hooks and Load Blocks (15) Electrical Integrity: T2.3.1 Incoming Power Source (16) T2.3.2 Power and Ancillary Systems Components (17) T2.3.3 Control System Components (18) T2.3.4 Availability of Spare Parts (19) Miscellaneous Tests and Conditions: T2.4 Operation (20) T2.5 Miscellaneous Deficiencies (21) T2.6 Maintenance Escalation (22) T2.7 Other Specialized Diagnostic Tests

Tier 2 Adjustments to Crane Condition Index

(Sum of individual Adjustments)

Tier 2 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

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To calculate the Net Crane Condition Index (Value should be between 0 and 10), subtract the Tier 2 Adjustments from the Tier 1 Crane Condition Index: Tier 1 Crane Condition Index __________ minus Tier 2 Crane Adjustments __________ = ______________ Net Crane Condition Index Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________

(Attach supporting documentation.)

E10-1

September 2006 Hydro Plant Risk Assessment Guide Appendix E10: Compressed Air System Condition Assessment E10. 1 GENERAL Compressed air systems are key components at hydroelectric power plants. Compressed air system failure can have a significant economic impact due to the high cost of emergency repairs. Determining the present condition of a compressed air system is an essential step in analyzing the risk of failure. This appendix provides a process for arriving at a Compressed Air System Condition Index which may be used to develop a business case addressing risk of failure, economic consequences, and other factors. E10. 2 SCOPE / APPLICATION The condition assessment methodology outlined in this guide applies to hydroelectric power plant compressed air systems. The condition assessment primarily focuses on the compressors, air dryers, air tanks, control panels, and piping. Air systems covered are ≥ 175 psi (high pressure) for governor air supply and < 175 psi (low pressure) for station service air supply with desiccant or refrigerant air dryers. This appendix is not intended to define compressed air system maintenance practices or describe in detail inspections, tests, or measurements. Utility-specific maintenance policies and procedures must be consulted for such information. E10. 3 CONDITION AND DATA QUALITY INDICATORS,

AND COMPRESSED AIR SYSTEM CONDITION INDEX The following indicators are used to separately evaluate the condition of the compressed air system:

• Physical condition • Operation run time • Maintenance requirements • Age of compressed air system

These condition indicators are initially evaluated using Tier 1 inspections, tests, and measurements, which are conducted by utility staff or contractors over the course of time and as a part of routine maintenance activities. Numerical scores are assigned to each condition

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indicator, which are then weighted and summed to determine the Compressed Air System Condition Index. The Compressed Air System Condition Index may indicate the need for immediate corrective actions and/or follow-up testing. To the extent that Tier 1 tests result in immediate corrective actions being taken by plant staff, the condition indicator scores should be adjusted to reflect corrective actions taken and the modified scores used to revise the overall Compressed Air System Condition Index. An additional stand-alone indicator, the Data Quality Indicator, is used to reflect the quality of the information available for scoring the condition indicators. In some cases, data may be missing, out-of-date, or of questionable integrity. Any of these situations could affect the accuracy of the associated condition indicator scores as well as the validity of the overall Condition Index. Given the potential impact of poor or missing data, the Data Quality Indicator is used as a means of evaluating and recording confidence in the Compressed Air System Condition Index. Additional information regarding compressed air system condition may be necessary to improve the accuracy and reliability of the Compressed Air System Condition Index. Therefore, in addition to the Tier 1 condition indicators, this appendix describes a “toolbox” of Tier 2 inspections, tests, and measurements that may be applied, depending on the specific issue or problem being addressed. Tier 2 tests are considered non-routine. However, if Tier 2 data is readily available, it may be used to supplement the Tier 1 assessment. Alternately, Tier 2 tests may be deliberately performed to address Tier 1 findings. Results of the Tier 2 analysis may either increase or decrease the score of the Compressed Air System Condition Index. The Data Quality Indicator score may also be revised during the Tier 2 assessment to reflect the availability of additional information or test data. Note: A severely negative result of ANY inspection, test, or measurement may be adequate in itself to require immediate corrective maintenance actions, regardless of the Compressed Air System Condition Index score. E10. 4 INSPECTIONS, TESTS, AND MEASUREMENTS Inspections, tests, and measurements should be conducted and analyzed by staff suitably trained and experienced in compressed air system diagnostics. The more basic tests may be conducted by qualified staff that is competent in these routine procedures. More complex inspections and measurements may require a compressed air system diagnostics expert. Inspections, tests, and measurements should be performed on a frequency that provides the accurate and current information needed by the assessment. Details of the inspection, testing, and measurement methods and intervals are described in technical references specific to the electric utility.

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E10. 5 SCORING Condition indicator scoring is somewhat subjective, relying on the experience and opinions of plant staff and experts. Relative terms such as “Results Normal” and “Degradation” refer to results that are compared to industry accepted levels; or to baseline or previously acceptable levels on this equipment; or to equipment of similar design, construction, or age operating in a similar environment E10. 6 WEIGHTING FACTORS Weighting factors used in the condition assessment methodology recognize that some condition indicators affect the Compressed Air System Condition Index to a greater or lesser degree than other indicators. These weighting factors were arrived at by consensus among design and maintenance personnel with extensive experience. E10. 7 MITIGATING FACTORS Every compressed air system is unique and, therefore, the methodology described in this guide cannot quantify all factors that affect individual condition. It is important that the Compressed Air System Condition Index arrived at be scrutinized by experts. Mitigating factors specific to the utility may affect the final Compressed Air System Condition Index and the final decision on replacement or rehabilitation of the system. E10. 8 DOCUMENTATION Substantiating documentation is essential to support findings of the assessment, particularly where a Tier 1 condition indicator score is less than 3 (i.e., less than normal) or where a Tier 2 test results in subtractions to the Compressed Air System Condition Index. Test reports, photographs, O & M records, and other documentation should accompany the Compressed Air System Condition Assessment Summary form. E10. 9 CONDITION ASSESSMENT METHODOLOGY The condition assessment methodology consists of analyzing each condition indicator individually to arrive at a condition indicator score. The scores are then weighted and summed to determine the Condition Index. Reasonable efforts should be made to perform Tier 1 inspections, tests, and measurements. However, when data is unavailable to properly score a condition indicator, it may be assumed that the score is “Good” or numerically equal to some mid-range number such as 2. This strategy must be used judiciously to prevent erroneous results and conclusions. In recognition of the potential impact of poor or missing data, a separate Data Quality Indicator is rated during the Tier 1 assessment as a means of evaluating and recording confidence in the final Compressed Air System Condition Index.

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E10.10 TIER 1 – INSPECTIONS, TESTS, AND MEASUREMENTS Tier 1 tests include those inspections, tests, and measurements that are routinely accomplished as part of normal operation and maintenance, or are readily discernible by examination of existing data. Tier 1 test results are quantified below as condition indicators that are weighted and summed to arrive at a Condition Index. Tier 1 tests may indicate abnormal conditions that can be resolved with standard corrective maintenance solutions. To the extent that Tier 1 tests result in immediate corrective maintenance actions being taken by plant staff, then adjustments to the condition indicators should be reflected and the new results used when computing the overall Tier 1 Condition Index. Tier 1 test results may also indicate the need for additional investigation, categorized as Tier 2 tests. E10. 11 COMPRESSED AIR SYSTEM CONDITION INDICATORS Condition Indicator 1 – Physical Condition Compressed air system problems can often be detected during the course of physical inspections. Problems such as serious air, oil, and water leaks, excessive vibration and abnormal noise while operating, corrosion, warping, belt tension, or failures on control panels may be observed. The known physical condition of the compressed air system is a major indicator of overall system reliability. This indicator relies heavily on maintenance records and past inspection reports. Qualified personnel should make a determination of scoring that encompasses as many inspection factors as possible under this indicator. Table 1 provides guidance for assigning an appropriate Condition Indicator Score.

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Table 1 – Physical Condition Scoring

Physical Condition Inspection Results Indicator Score

Excellent Condition: Inspection results are normal. • No major air, oil, and water leaks. • No excessive vibration or abnormal noise during operation. • No evidence of heat, corrosion or warping. • No significant condensation or water problems in the compressed

air. • No loose or broken fasteners, no cracks in castings or sheet metal

shrouding. • Drive belt tensions are correct; belts are in good working condition. • No failures, alarms, abnormal changes in normal operating levels on

gauges or indicators and control panels. • Normal lubricating oil level and color. • Lubricating oil is not contaminated. • Air filters are clean. • No excess oil vapours or carbon residue in the air lines. • Pressures are maintained at the expected set point.

3

Good Condition: Inspection results show some deterioration of the criteria mentioned above. 2

Fair Condition: Inspection results show significant deterioration of the criteria mentioned above. 1

Poor Condition: Inspection results show extensive deterioration of the criteria mentioned above. 0

Condition Indicator 2 – Operation Run Time This condition indicator measures the compressor run time and compares it with expected run time to assess compressor performance and system integrity. It is assumed that an increase in run time indicates a reduction in performance due to worn compressor components (i.e., cylinder wear, ring wear, check valve leakage, or similar wear related effects). The information used to score this indicator should be gathered through normal maintenance activities.

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Table 2 – Operation Run Time Scoring

Operation Run Time Amount of Operating Hours Indicator Score

Compressor operating hours match the air consumption required (100%). 3

Compressor operating hours are somewhat increased but no change of air consumption required and no major air leaks (≥ 100 and < 120%). 2

Compressor operating hours are moderately increased but no change of air consumption required and no major air leaks (≥ 120 and < 150%). 1

Compressor operating hours are significantly increased but no change of air consumption required and no major air leaks (≥ 150%). 0

Condition Indicator 3 – Maintenance Requirements Assess the level of maintenance required for this equipment. This condition indicator addresses the amount of maintenance that the compressed air system currently requires. It does not address failure to perform maintenance since a lack of maintenance will be reflected in the condition indicator for Physical Condition. The Maintenance Requirements indicator has 3 levels: Minimal, Moderate, and Extensive, as shown in Table 3.

Table 3 – Maintenance Requirements Scoring Maintenance Condition Amount of Required Maintenance Indicator Score Minimal level: A small amount of routine preventive maintenance is required for the compressed air system. 3

Moderate level: Some corrective maintenance is necessary. 2

Extensive level: Frequent repairs, abnormal wear to components, and/or labor-intensive maintenance is required. 1

Condition Indicator 4 – Age of the Compressed Air System Assess the age of the components and enter the age in Table 4. If design life information is available, use the design life instead of age in Table 4. Use Table 4 to arrive at an appropriate Compressed Air System Age Indicator Score.

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Table 4 – Age Scoring

Age Age of the Equipment Indicator Score

< 25 years 3

≥ 25 and < 35 years 2

≥ 35 and < 45 years 1

≥ 45 years 0 E10.12 TIER 1 – COMPRESSED AIR SYSTEM CONDITION INDEX CALCULATIONS Enter the Compressed Air System Condition Indicator Scores from the tables above into the Compressed Air System Condition Assessment Summary form at the end of this document. Multiply each indicator score by its respective Weighting Factor, and sum the Total Scores to arrive at the Tier 1 Compressed Air System Condition Index. The index may be adjusted by the Tier 2 inspections, tests, and measurements described below. E10.13 TIER 1 – COMPRESSED AIR SYSTEM DATA QUALITY INDICATOR The Compressed Air System Data Quality Indicator reflects the quality of the inspection, test, and measurement results used to evaluate the compressed air system condition under Tier 1. The more current and complete the results are, the higher the rating for this indicator. The normal testing frequency is defined as the organization’s recommended frequency for performing the specific test or inspection. Qualified personnel should make a subjective determination of scoring that encompasses as many factors as possible under this indicator. Results are analyzed and applied to Table 5 to arrive at an appropriate Compressed Air System Data Quality Indicator Score.

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Table 5 – Compressed Air System Data Quality Scoring

Compressed Air System Data Quality Results Indicator Score All Tier 1 inspections, tests and measurements were completed within the normal testing frequency (e.g., within the last < 3 years) and the results are reliable.

10

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 1 and < 4 years past the normal testing frequency and the results are reliable.

7

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 4 and < 7 years past the normal testing frequency, or some of the results are not available or are of questionable integrity.

4

One or more of the Tier 1 inspections, tests and measurements were completed ≥ 7 years past the normal frequency, or no results are available or many are of questionable integrity.

0

Enter the Compressed Air System Data Quality Indicator Score from Table 5 into the Compressed Air System Condition Assessment Summary form at the end of this document.

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E10. 14 TIER 2 – INSPECTIONS, TESTS, AND MESUREMENTS If the Compressed Air System Condition Index is fair or poor, Tier 2 evaluations may be warranted. The Tier 2 evaluations are intended to be quantitative performance tests for the compressor and dryer. Tier 2 analysis improves assessment of the status or condition of air system components and should help equipment maintenance personnel assess the need for more extensive corrective maintenance, rehabilitation, or replacement. After Tier 2 assessments are performed, apply the appropriate adjustment factors as indicated in the tables below. Recalculate the Compressor Condition Index using the Compressor Condition Assessment Summary form at the end of this document. An adjustment to the Data Quality Indicator score may be appropriate if additional or newer information or test results were obtained during the Tier 2 assessment. Test T2.1: Compressor Performance Testing Compressor performance testing is intended to assess how well the compressor is working. Measurements usually require special test equipment that will vary depending on the utility or plant. Test T2.1.1: Compressor Air Flow Compressor air flow measurements indicate the functionality of the compressor while it is running, and exclude the effects from other system components that will bias the run time data.

Table 6A – Compressor Air Flow Scoring

Measured Results Adjustment to Air Flow Qread Rating Criteria Compressor Condition Index

Qread1

> 0.9 Qnom2 No change

0.8 Qnom ≤ Qread ≤ 0.9 Qnom Subtract 2.0 Qread < 0.8 Qnom Subtract 6.0

1. Qread is the air flow rate read from a flow meter connected to the discharge port of the compressor. Most compressors are rated in SCFM, cubic feet per minute of standard air, and the data from the meter must be normalized (converted) into SCFM.

2. Qnom is the rated output for the compressor, based either on service records or on manufacturer’s output rating.

Test T2.1.2: Compressor Air Temperature Compressor air temperature measures the effectiveness of the after coolers and/or excessive output temperatures while running.

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Table 6B – Compressor Air Temperature Scoring

Measured Results Air Temperature (last stage) Adjustment to Tread Rating Criteria Compressor Condition Index

Tread1

< 1.1 Tnom2 No change

1.1 Tnom ≤ Tread ≤ 1.2 Tnom Subtract 1.0

Tread > 1.2 Tnom Subtract 4.0

1. Tread is the temperature measurement taken at the discharge from the after cooler. It should be compared to historical data for the same compressor.

2. Tnom is the discharge air temperature when the compressor was new or in just-refurbished condition.

Test T2.1.3: Compressor Motor Current Compressor motor current provides information about the motor condition and input shaft power requirements.

Table 6C – Compressor Motor Current Scoring Measured Results ∆ I Current Drive Motor between Phases Adjustment to Rating Criteria Compressor Motor Condition Index

∆ I < 3% Inom No change

3% Inom ≤ ∆ I ≤ 5% Inom Subtract 1.0

∆ I > 5% Inom Subtract 4.0 Test T2.1.4: Compressor Lube Oil Analysis If Tier 1 testing indicates potential compressor problems that are not easily diagnosed, an oil analysis test program can provide additional information to help identify potential failure modes. As the compressor wears during normal operation, metallic particles up to roughly 15 microns in size will accumulate as a suspension in the oil. The particle size distribution and shape, oxidation, the nature of constituent elements found and especially the rate of change in the particle accumulation rate from one test to the next, are all important indicators of the type of wear occurring. Oil analysis tests should be performed by taking samples and sending them to a commercial oil analysis laboratory. The laboratory should be consulted for guidance when planning the testing procedure, and the results evaluation procedure should be adjusted to suit the equipment. If time

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allows, the analysis is enhanced if you run one sample, operate the machine for a measured amount of time, and then run another sample. Ferrography (analysis of the size, shape, concentration and size distribution of magnetic particles) should be specified in the oil analysis purchase order. Techniques and guidelines for the Ferrography evaluation process are found in the Wear Particle Atlas prepared for the Advanced Technology Office, Support Equipment Engineering Department, Naval Air Engineering Center, Lakehurst, NJ. Total Acid Number (ASTM D664), Viscosity (ASTM D445/446) and Water (ASTM D4928) should be included. The test report should include an Equipment Condition Rating (ECR) based on a three category classification system, with categories similar to Normal, Marginal, and Abnormal (Critical). A Normal ECR reflects that all contaminant tests return values and findings that fall within the bounds of normal equipment operating conditions, and the oil properties are within a range of 5% above the upper bound and 5% below the lower bound for new oil properties. A Marginal ECR reflects test results and findings that indicate the presence of wear particles or contaminants that are not found in equipment in good operating condition, or inadequate oil properties, but does not conclusively indicate an in-progress or imminent failure. An Abnormal or Critical ECR reflects a condition that requires immediate attention.

Table 6D – Compressor Lube Oil Analysis Scoring

Adjustment to Oil Condition Rating Compressor Condition Index

Normal No Change

Marginal Subtract 1.0

Critical Subtract 4.0 Test T2.2: Air Dryer Performance Testing Air dryer equipment may be desiccant type with or without external heated blowers for purging, or it may be refrigerant type. The function of the dryer is to depress the dew point temperature to a low enough level that moisture will not condense out in the downstream equipment that uses the compressed air. The following tests assess the condition of the dryer by looking at two factors: the dew point temperature depression and thinning of the tank walls due to corrosion and wear. Test T2.2.1: Air Dryer Dew Point The dew point temperature depression is the difference between the design dew point of the air entering the dryer and the average dew point of the air leaving the dryer. The loss of dew point depression is measured as the rise in dew point temperature over the life of the dryer expressed as a percentage of the original design dew point temperature depression. Dew point temperature

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measurements are computed from temperature, pressure and humidity (hygrometer) measurements.

Table 7A – Air Dryer Dew Point Scoring

Measured Results Air DewPoint DP read Adjustment to Rating Criteria Air Dryer Condition Index

80 % DewPoint read1< DP expected

2 ≤ 100 % DewPoint read No change

65% DewPoint read≤ DP expected ≤ 80 % DewPoint read Subtract 2.0

DPexpected < 65 % DewPoint read Subtract 4.0

1. DewPointread is the reading of dew point temperature depression taken during Tier 2 testing. 2. DPexpected is the normal dew point temperature depression from the manufacturer’s specifications

or from historical maintenance records of the equipment. Test T2.2.2: Air Dryer Wall Thickness Thinning of the tank walls is measured by non-destructive testing methods, including ultrasonic thickness gauges. Dryer tank wall thickness includes the desiccant tanks and any locations where abrasive wear may have concentrated local effects, such as the outside of the elbows on the tank outlets. Wall thickness measurements should be made for all desiccant tanks at several locations on each tank and piping. Similarly, the air receiver tanks can have loss of wall thickness and should be measured at several locations. The measurement showing the greatest amount of material loss should be used for scoring, both for dryer tanks and for air receiver tanks.

Table 7B – Air Dryer Wall Thickness Scoring Measured Results Thickness Tread Adjustment to Rating Criteria Air Dryer Tower Condition Index

Tread1 > 60 % T nominal

2 No change

Tread ≤ 60 % T nominal Subtract 4.0

1. Tread is the wall thickness reading. 2. Tnominal is the wall thickness for the dryer tank in new condition.

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Test T2.3: Air Receiver Tank Wall Thickness

Table 8 – Air Receiver Tank Wall Thickness Scoring

Measured Results Air Tank Thickness Tread Adjustment to Rating Criteria Air Tank Condition Index

Tread1 > 60 % T nominal

2 No change

Tread ≤ 60 % T nominal Subtract 4.0

1. Tread is the current or most recent thickness measurement for the receiver tank. 2. Tnominal is the wall thickness of the air receiver tank in new condition.

Test T2.4: Other Specialized Diagnostic Tests Additional tests may be applied to evaluate specific compressed air system problems. Some of these diagnostic tests may be considered to be of an investigative research nature. When conclusive results from other diagnostic tests are available, engineering judgment or relevant experience may be used to make an appropriate adjustment to the Compressed Air System Condition Index. E10.15 TIER 2 – COMPRESSED AIR SYSTEM CONDITION INDEX CALCULATIONS Enter the Tier 2 adjustments from the tables above into the Compressed Air System Condition Assessment Summary form at the end of this guide. Subtract the sum of these adjustments from the Tier 1 Compressed Air System Condition Index to arrive at the Net Compressed Air System Condition Index. Attach supporting documentation. An adjustment to the Data Quality Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment. E10.16 COMPRESSED AIR SYSTEM CONDITION-BASED ALTERNATIVES After review by a compressed air system expert, the Compressed Air System Condition Index is suitable for use in a risk-and-economic analysis model. The condition index may be deemed sufficient in itself for decision-making regarding Compressed Air System Condition-Based Alternatives, in which case the Compressed Air System Condition Index may be directly applied to Table 9.

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Table 9 – Compressed Air System Condition-Based Alternatives

Generator Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat condition assessment as needed.

≥ 3.0 and < 7 (Fair) Continue operation but reevaluate O & M practices. Consider using appropriate Tier 2 tests. Repeat condition assessment process as needed.

≥ 0 and < 3.0 (Poor) Immediate evaluation including additional Tier 2 testing. Consultation with experts. Adjust O & M as prudent. Begin replacement/rehabilitation process.

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COMPRESSED AIR SYSTEM TIER 1 CONDITION ASSESSMENT SUMMARY

Date: _________________________ Location: ______________________________________

System Working Pressure: ________________ psi

Use of Compressed Air System: □ Governor Oil Pneumatic Tanks

□ Generator Braking System

□ Air Circuit Breakers

□ Service Air

□ Turbine Depression

□ Turbine Air Injection

□ Other

Compressor: Manufacturer: _____________________________ Number of Stages: _________

Cooling System Type: _____________________ Motor: ________________ HP

Year Installed: ________________________ Nominal Flow: ____________ scfm

Nominal Temperature: _______________ Nominal Pressure: ________________

(last stage) (last stage)

Air Dryer: Manufacturer: _____________________ Type of Regeneration: ______________

Year Installed: ____________________

Nominal Wall Thickness – Dryer Tank: _________________

Dew Point Expected: _______________

Air Receiver: Manufacturer: _____________________ Year Installed: ____________________

Safety Valve Model: ________________ Valve Adjustment Pressure: _________

Nominal Wall Thickness – Receiver Tank: ____________________

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Tier 1 Compressed Air System Condition Summary

(For instructions on indicator scoring, please refer to condition assessment guide)

No. Condition Indicator Score × Weighting Factor = Total Score

1 Physical Condition (Score must be 0, 1, 2, or 3) 0.7

2 Operation Run Time (Score must be 0, 1, 2, or 3) 1.20

3 Maintenance Requirements (Score must be 1, 2, or 3) 1.00

4 Age (Score must be 0, 1, 2, or 3) 0.4

Tier 1 Compressed Air System Condition Index

(Sum of individual Total Scores) (Condition Index should be between 0 and 10)

Tier 1 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________ (Attach supporting documentation.)

Compressed Air System Condition-Based Alternatives

Generator Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat condition assessment as needed.

≥ 3.0 and < 7 (Fair) Continue operation but reevaluate O & M practices. Consider using appropriate Tier 2 tests. Repeat condition assessment process as needed.

≥ 0 and < 3.0 (Poor) Immediate evaluation including additional Tier 2 testing. Consultation with experts. Adjust O & M as prudent. Begin replacement/rehabilitation process.

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COMPRESSED AIR SYSTEM TIER 2 CONDITION ASSESSMENT SUMMARY

Date: _________________________ Location: ______________________________________

System Working Pressure: ________________ psi

Tier 2 Compressed Air System Condition Summary

Adjustment to No. Tier 2 Test Tier 1 Condition Index

T2.1.1 Compressor Air Flow T2.1.2 Compressor Air Temperature T2.1.3 Compressor Motor Current T2.1.4 Compressor Lube Oil Analysis T2.2.1 Air Dryer Dew Point T2.2.2 Air Dryer Wall Thickness T2.3 Air Receiver Tank Wall Thickness T2.4 Other Specialized Diagnostic Tests

Tier 2 Adjustments to Compressed Air Condition Index

(Sum of individual Adjustments)

Tier 2 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

To calculate the Net Compressed Air System Condition Index (Value should be between 0 and 10), subtract the Tier 2 Adjustments from the Tier 1 Compressed Air System Condition Index: Tier 1 Compressed Air System Condition Index __________ minus Tier 2 Compressed Air System Adjustments __________ = ____________ Net Compressed Air System Condition Index Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________

(Attach supporting documentation.)

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September 2006 Hydro Plant Risk Assessment Guide Appendix E11: Emergency Closure Gate and Valve Condition Assessment E11.1 GENERAL Emergency closure gates and valves are key safety components in the power train at hydroelectric powerplants. Unexpected failure can have a significant economic impact due to the high cost of emergency repairs and lost revenues during an extended forced outage. Failure of emergency closure equipment can also affect life safety. Determining the present condition of an emergency closure gate and valve is an essential step in analyzing the risk of failure. This appendix provides a process for arriving at an Emergency Closure Gate and Valve Condition Index which may be used to develop a business case addressing risk of failure, economic consequences, and other factors. E11.2 SCOPE / APPLICATION The condition assessment methodology outlined in this appendix applies to hydroelectric powerhouse emergency closure equipment. The condition assessment primarily focuses on the gates, valves, and associated operators (i.e., hoists, hydraulic cylinders, and valve operators). The appendix does not apply to closure systems that are not used for emergency purposes. In recognition that many organizations have facility safety review programs, it is intended that the assessments described herein fully utilize information provided by such reviews to avoid duplication of work and to minimize outage time. This information may be available in the form of comprehensive facility reviews, special examinations, maintenance databases, and operational reports. If the assessment requires an additional physical inspection, then it should be coordinated with the organization’s existing review program. This appendix is not intended to define maintenance practices or describe in detail inspections, tests, or measurements. Utility-specific maintenance policies, procedures, and guidelines must be consulted for such information. E11.3 CONDITION AND DATA QUALITY INDICATORS AND EMERGENCY

CLOSURE SYSTEM CONDITION INDEX This appendix describes the condition indicators generally regarded by hydro plant engineers as providing the initial basis for assessing the condition of the emergency closure system. The

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following indicators are used to separately evaluate the condition of the gates or valves and their associated operator:

• Age • Physical Condition – Gates/Valves • Physical Condition – Operators • Operations History • Maintenance History

These condition indicators are initially evaluated using Tier 1 inspections, tests, and measurements, which are conducted by utility staff or contractors over the course of time and as a part of routine maintenance activities. Numerical scores are assigned to each condition indicator, which are then weighted and summed to determine the overall Emergency Closure System Condition Index. An additional stand-alone indicator is used to reflect the quality of the information available for scoring the condition indicators. In some cases, data may be missing, out-of-date, or of questionable integrity. Any of these situations could affect the accuracy of the associated condition indicator scores as well as the validity of the overall Emergency Closure System Condition Index. Given the potential impact of poor or missing data, the Data Quality Indicator is used as a means of evaluating and recording confidence in the final Emergency Closure System Condition Index. Additional information regarding gate, valve and associated operator condition may be necessary to improve the accuracy and reliability of the Emergency Closure System Condition Index. Therefore, in addition to the Tier 1 condition indicators, this appendix describes a “toolbox” of Tier 2 inspections, tests, and measurements that may be applied to the Emergency Closure System Condition Index, depending on the specific issue or problem being addressed. Tier 2 analyses are considered non-routine. However, if Tier 2 data is readily available, it may be used to supplement the Tier 1 assessment. Alternatively, Tier 2 tests may be deliberately performed to address Tier 1 findings. Results of the Tier 2 analysis may either increase or decrease the score of the Emergency Closure System Condition Index. The Data Quality Indicator score may also be revised during the Tier 2 assessment to reflect the availability of additional information or test data. The Emergency Closure System Condition Index may indicate the need for immediate corrective actions and/or follow-up Tier 2 testing. The Emergency Closure System Condition Index is also suitable for use as an input to the risk-and-economic analysis model. Note: A severely negative result of ANY inspection, test, or measurement may be adequate in itself to require immediate corrective action, regardless of the Emergency Closure System Condition Index score. E1.4 INSPECTIONS, TESTS, AND MEASUREMENTS Inspections, tests, and measurements should be conducted and analyzed by staff suitably trained and experienced in the equipment being inspected. The more basic tests may be conducted by

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qualified personnel that are competent in these routine procedures. More complex inspections and measurements may require an expert. Inspections, tests, and measurements should be conducted on a frequency that provides the accurate and current information needed by the assessment. Details of the inspection, testing, and measurement methods and intervals are described in technical references specific to each electric utility. E11.5 SCORING Condition indicator scoring is somewhat subjective, relying on the experience and opinions of experts. Relative terms such as “Results Normal” and “Degradation” refer to results that are compared to industry-accepted levels; or to baseline or previous (acceptable) levels on this equipment; or to equipment of similar design, construction, or age operating in a similar environment. E11.6 WEIGHTING FACTORS Weighting factors used in the condition assessment methodology recognize that some condition indicators affect the Emergency Closure System Condition Index to a greater or lesser degree than other indicators. These weighting factors were arrived at by consensus among design and maintenance personnel with extensive experience. E11.7 MITIGATING FACTORS Every emergency closure system is unique and, therefore, the methodology described in this appendix cannot quantify all factors that affect individual condition. It is important that the Emergency Closure System Condition Index arrived at be scrutinized by experts. Mitigating factors specific to the utility may determine the final Emergency Closure System Condition Index and the final decision on replacement or rehabilitation of the system. E11.8 DOCUMENTATION Substantiating documentation is essential to support findings of the assessment, particularly where a Tier 1 condition indicator score is less than 3 (i.e., less than normal) or where a Tier 2 analysis results in subtractions to the Emergency Closure System Condition Index. Test reports, facility review reports, special examinations, photographs, O & M records, and other documentation should accompany the Emergency Closure System Condition Assessment Summary Form.

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E11.9 CONDITION ASSESSMENT METHODOLOGY The condition assessment methodology consists of analyzing each condition indicator individually to arrive at a condition indicator score. The scores are weighted and summed to determine the Condition Index. Reasonable efforts should be made to perform Tier 1 inspections, tests, and measurements. However, when data is unavailable to properly score the Condition Indicator, it may be assumed that the score is “Good” or numerically equal to some mid-range number such as 2. This strategy must be used judiciously to prevent erroneous results and conclusions. In recognition of the potential impact of poor or missing data, a separate Data Quality Indicator is rated as a means of evaluating and recording confidence in the final Emergency Closure System Condition Index. E11.10 TIER 1 – INSPECTIONS, TESTS, AND MEASUREMENTS Tier 1 includes those inspections, tests, and measurements that are routinely accomplished as part of normal operation and maintenance, or are readily discernible by examination of existing data. Tier 1 results are quantified below as condition indicators that are weighted and summed to arrive at a Condition Index. A Tier 1 analysis may indicate abnormal conditions that can be resolved with standard corrective maintenance solutions. The Tier 1 results may also indicate the need for an additional investigation, categorized as a Tier 2 analysis. E11.11 TIER 1 – EMERGENCY CLOSURE CONDITION INDICATORS Condition Indicator 1 – Age of Gates, Valves, and Operators Age is an important factor to consider when assessing the condition of an emergency closure system (gates, valves, and operator equipment). Rate the system on the oldest major component (gate, operator, controls). Use the year a component was last completely rehabilitated; otherwise, use the year it was put into service. Results of the age analyses are applied to Table 1 to arrive at an appropriate Emergency Closure System Age Indicator Score.

Table 1 – Age of Gate, Valve, and Operator

Emergency Closure System Age of the Equipment Age Indicator Score

< 20 years 3

≥ 20 and < 35 years 2 ≥ 35 and < 60 years 1

≥ 60 years 0

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Condition Indicator 2 – Physical Condition of Gates/Valves This section is divided into two parts:

• Gates • Valves

Select the primary device used for emergency closure purposes to base the evaluation on. Gates Typical types of closure gates included in this study are: Roller-mounted gates (Stoney, Caterpillar, Tractor, and Coaster), Wheel-mounted gates (fixed-wheeled gates), Ring Follower gates, Paradox gates, Ring-seal gates and Cylinder gates, i.e., any gate used for emergency closure purposes. The known physical condition of the emergency closure gates is a major indicator of overall system reliability. This indicator is based on maintenance records and past inspection reports only. Items to note from records with regard to the gates are: Have the wheels/rollers been inspected? Do all of the wheels/rollers move freely? What’s the condition of the wheels/rollers (corrosion, pitting)? Condition of bearings/bushings, overall structural soundness and condition of the gate (has the gate been inspected?), corrosion or damage to the gate, condition of coating, anode condition, condition of gate seals (nicks or abrasion on the seal or excessive leakage (50 gpm or more)), condition of sill plate and the embedded guide in the water passage (pitting, straightness, loosening). Qualified personnel should make a subjective determination of scoring that encompasses as many factors as possible under this indicator. Results are analyzed and applied to Table 2 to arrive at an appropriate Gate Condition Indicator Score.

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Table 2 – Gate Physical Condition Gate Condition Results Indicator Score Limited corrosion on gates, wheels, or rollers; wheels/rollers turn; coating is in good condition; anodes are in good condition; no cracked welds in structure or loose bolts/rivets; gate guides are in good condition; sill is in good condition; leakage past seals is minimal (< 25 gpm or < 1.6 liters/s).

3

Moderate corrosion on the gates, wheels, or rollers; most of the wheels/rollers turn; three-quarters of the anodes are left; no cracked welds in the structure or loose bolts/rivets; gate guides are in good condition; sill is in good condition; leakage past seals is minimal (< 25 gpm or < 1.6 liters/s).

2

Large areas of corrosion on the gates, wheels, or rollers; most of the wheels/rollers turn; one-half of the anodes are left; no cracked welds in the structure or loose bolts/rivets; gate guides are in good condition; sill is in good condition; leakage past seals is moderate (≥ 25 and < 50 gpm or ≥ 1.6 and < 3.2 liters/s).

1

Severe corrosion on the gates, wheels, or rollers; few of the wheels/rollers turn; coating is poor; one-quarter or less of the anodes are left; some cracked welds in the structure or loose or missing bolts/rivets; gate guides are in poor condition; sill is in poor condition; excessive leakage past the seals (≥ 50 gpm or ≥ 3.2 liters/s).

0

Valves

Types of valves generally used for emergency closure purposes are: Butterfly, Spherical, and Cone (plug) valves. The known physical condition of the emergency closure valves is a major indicator of overall system reliability. For this assessment, the valve will be looked at specifically. This indicator is based on maintenance records and past inspection reports only. Items to note from records with regard to the valves are: Condition of the inside of the valve. Is cavitation present? Condition of the valve seals and sealing surfaces, condition of bearings/bushings, condition of greasing system, overall structural soundness and condition, corrosion, damage to valve, condition of valve bypass. Qualified personnel should make a subjective determination of scoring that encompasses as many factors as possible under this indicator. Results are analyzed and applied to Table 3 to arrive at an appropriate Valve Condition Indicator Score.

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Table 3 – Valve Physical Condition Valve Condition Results Indicator Score Limited corrosion on leaf/plug and water passage; coating is in good condition; seals and seats are in good condition and properly adjusted with no or minimal leakage, bearing/pivot point lubrication is in good condition; the bypass is in good condition; valve is regularly exercised.

3

Moderate corrosion on leaf/plug and water passage; coating is in adequate condition; seals and seats are in adequate condition with minimal leakage; bearing/pivot point lubrication is in good condition; the bypass is in good condition; valve is regularly exercised.

2

Large areas of corrosion on leaf/plug and water passage; coating is less than adequate; seals and seats have some damage with minor leakage; bearing/pivot point lubrication is in adequate condition; the bypass has moderate corrosion; valve is regularly exercised.

1

Severe corrosion on leaf/plug and water passage; coating is poor; seals and seats are damaged allowing excessive leakage; bearing/pivot point lubrication is not functioning properly; the bypass has excessive corrosion; there is severe chattering, vibration, or binding during operation; the valve is either rarely exercised or is excessively exercised (i.e., ≥ 50 cycles per year).

0

Condition Indicator 3 – Physical Condition of Operators This section will be broken into two major categories:

• Gate Operators • Intake Valve Operators

Gate Operators Typical operators for emergency closure gates are generally either a hydraulic system or an electric-driven mechanical hoist.

• The hydraulic system consists of one or more hydraulic cylinders and all the other components typical to a hydraulic system.

• The electric-driven mechanical hoist is usually either a traveling hoist, such as a gantry crane, or a fixed hoist that is permanently installed for use with a particular gate. Both the traveling and fixed hoist may use wire rope or chain for lifting the gate.

As appropriate, use either the Hydraulic Hoist or Electric Hoist methodology to score the gate operator being evaluated.

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Hydraulic Hoist Items to examine or note from maintenance records with regard to the cylinders and hydraulic system include: seals (rod), stem packing, gate drift, corrosion on cylinder rod or case, condition of the hydraulic control panel (relief valves, check valves, four-way valve, lower/raise valve), gate location indicating devices, hydraulic system leaks, condition of the hydraulic pumping unit (HPU) and accumulators, condition of attachment mounts or beams, flexible hydraulic hoses, hydraulic couplings, general coating condition where applicable, condition of the hydraulic fluid, and replacement parts availability. Have the hydraulics been exercised on a regular basis? Results are analyzed and applied to Table 4 to arrive at an appropriate Gate Operator (Hydraulic Hoist) Physical Condition Indicator Score.

Table 4 – Gate Operator (Hydraulic Hoist) Physical Condition Hydraulic Hoist Condition Results Indicator Score Seals, stems, cylinders, hydraulic piping/valves/controls, and gate position indicators are updated or in good condition with replacement parts available; coating is in good condition; hydraulic oil is in good condition; hydraulic system has been tested and exercised regularly; no gate drift while suspended from the cylinder. No external oil leaks.

3

Seals, stems, cylinders, hydraulic piping/valves/controls, and gate position indicators are in good condition; protective coating is in adequate condition; hydraulic oil condition is adequate; hydraulic system has been tested and exercised regularly; no gate drift while suspended from the cylinder.

2

Seals, stems, cylinders, hydraulic piping/valves/controls, and gate position indicators are in adequate condition; coating is in adequate condition; hydraulic oil condition is contaminated or hasn’t been tested; hydraulic system has not been tested but is exercised regularly; no gate drift while suspended from the cylinder.

1

Seals, stems, cylinders, hydraulic piping/valves/controls, and gate position indicators are in poor condition; coating is in poor condition; hydraulic oil condition is contaminated or hasn’t been tested; hydraulic system has not been tested or exercised regularly; the gate drifts while suspended from the cylinder. External oil leaks into the water.

0

Electric-Driven Mechanical Hoist This section covers only fixed hoists. Items to examine or note from maintenance records include: condition of wire rope/chain, condition of sockets on wire ropes, linkages, gearbox condition, leaks, motors, brake condition and adjustment, motor controls, indicators, backup

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power supply, inspections, exercising of the system on a regular basis, wrap of rope/chain onto drums, replacement part availability. Results are analyzed and applied to Table 5 to arrive at an appropriate Gate Operator (Electric Hoist) Physical Condition Indicator Score. Note: Bridge and gantry cranes that are used for emergency closure shall not be inspected or rated using this section. Bridge and gantry cranes have specific inspection requirements that are described in applicable Federal, State, Provincial laws and regulations. See the Crane Condition Assessment Guide, Appendix E9.

Table 5 – Gate Operator (Electric Hoist) Physical Condition Electric Hoist Condition Results Indicator Score Hoist surfaces and coatings are free of corrosion; no structural damage or cracks; couplings are tight and properly aligned; moving parts are lubricated; gearbox oil is free from contaminants and moisture and tested regularly; no groove wear on drums or sheaves; bearings are checked for wear and lubrication; oil seals do not leak; gears are properly aligned and have no wear; the hoist ropes are inspected for broken strands, hoist chain is free of cracked, deformed, or severely corroded links; the rope/chain is laying properly on the drum; limit switches are properly set and functioning properly; hoist brakes have no wear and operate properly; no unusual noises or binding of the mechanism during operation; electrical components are clean and function; the hoist system has been tested and exercised regularly.

3

Hoist surfaces and coatings have minor defects or corrosion; no structural damage or cracks; couplings are tight and properly aligned. moving parts are lubricated; gearbox oil is not tested regularly or minor contaminates noted; no groove wear on drums or sheaves; oil seals do not leak; gears are properly aligned and have no wear; hoist ropes have no broken strands or evidence of corrosion; hoist chain has some corrosion but no cracks or deformed links; the rope/chain is laying properly on the drum; limit switches are properly set and functioning properly; hoist brake pads have ≥ 50% of the lining left and operate properly; no unusual noises or binding of the mechanism during operation; the electrical components are not very clean; the hoist system has been tested and exercised regularly.

2

Hoist surfaces and coatings have minor defects or corrosion; minimal structural damage with no cracks; couplings are tight and properly aligned; gearbox oil is not tested regularly or minor contaminates or water is noted; some groove wear on drums or sheaves; oil seals have minor leaks; gears are mis-aligned but no major wear or damage to the gears; hoist ropes have no broken strands or evidence of corrosion; hoist chain has moderate corrosion but no cracks or deformed links;

1

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limit switches are properly set and functioning properly; hoist brakes pads have ≥ 20 and < 50% of the lining left and operate properly; some unusual noises are noted during operation; the electrical components are not very clean; the hoist system has not been tested and exercised regularly; there are multiple trouble reports on record such as repairs to the electrical controls. There are serious concerns with the condition such as: major corrosion on the critical components, wire rope corrosion or broken strands; corroded or deformed chain links; < 20% of brake pads left; significant lubricating oil contamination; unusual noises or vibrations during operation; and frequent trouble reports.

0

Intake Valve Operators (Hydraulic or Electric)

Typical operators for emergency closure valves are:

• Hydraulic Cylinders • Rotary Hydraulic • Motor-Operated Actuators

Use Table 6 for evaluating the valve operator. Items to examine or note from maintenance records with regard to the intake valve operators include: availability and testing of backup power system (accumulator, engine/generator/batteries), hydraulic or motor system tested and repaired as needed, greasing system operable, retractable seals operable, closure in event of power failure, controls are updated or in excellent condition with replacement parts available, pressure differential indicators up/downstream of valve is operational, linkages in good condition, wear on stem.

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Table 6 – Intake Valve Operator (Hydraulic or Electric) Physical Condition

Intake Valve Condition Results Indicator Score Seals, stems, cylinders, hydraulic system, gate position indicators, and controls are in good condition with replacement parts available; backup power is available and tested regularly; slow-down mode has been tested and verified; pressure differential indicators up/downstream are operational and tested; operational testing performed on an annual basis; the system is exercised regularly.

3

Seals, stems, cylinders, hydraulic system, gate position indicators, and controls are updated or in good condition; backup power is available; slow-down mode functions but could use a minor adjustment; pressure differential indicators up/downstream are operational but not calibrated; the system is exercised frequently.

2

Seals, stems, cylinders, hydraulic system, gate position indicators, and controls are in fair condition; backup power is not regularly tested; slow-down mode functions but could use a minor adjustment; pressure differential indicators up/downstream are operational but not calibrated. The timed cycle of operation has changed slightly; the system is exercised rarely.

1

Seals, stems, cylinders, hydraulic system, gate position indicators, and controls are in poor condition; backup power is not available or not reliable; slow-down mode and limit switches are out of adjustment; pressure differential indicators up/downstream are not functioning; the timed cycle of operation has changed significantly; the system is never exercised.

0

Condition Indicator 4 – Operations History Normal operations are defined as meeting the requirements of the gate or valve’s operational design criteria. Examples of deficiencies include: excessive gate drift, significant changes in travel time and pressures, abnormal noise or vibration, changes to the configuration that would impact the availability of emergency closure within the originally-specified time period. Backup power or reliability of the power source is important for reliable operations of the device under emergency situations. Operational Criteria:

• Does the existing system design meet closure rate requirements (e.g., Army Corps of Engineers-required less than 10-minute closure for gates; less than 2-minute closure for valves)?

• Does the existing system design meet the unbalanced gate closure requirements? • Does the gate/valve position indicator work? • Does the remote closure capability (if present) operate correctly? • Does the annunciation system give adequate warning of a gate closure?

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• No abnormal noises. • No leaks of hydraulic oil or lube oil. • Does the backup power system for the emergency closure function? • Does the gate/valve drift in any position? (This assumes it is not latched or dogged.) • Has the opening or closing pressures (on hydraulic systems) changed from baseline?

Qualified personnel should make a subjective determination of scoring that encompasses as many factors as possible under this indicator. Results are analyzed and applied to Table 7 to arrive at an appropriate Operations History Condition Indicator Score.

Table 7 – Operations History Scoring Operations Condition Results Indicator Score Meets original operational criteria, tested as required, no known design and operational deficiencies. 2

System is functional, but may not meet all operating criteria. Tests as required have been performed. No known design deficiencies. 1

Does not meet original operational criteria or not tested as required or has a known design and operational deficiency. 0

Condition Indicator 5 – Maintenance History This condition indicator only addresses the amount of maintenance that the system currently requires. A lack of maintenance will be reflected in the Condition Indicator for Physical Condition. The Maintenance Indicator is broken into the following 3 categories:

• Small – It is assumed that a small amount of routine annual preventative maintenance is required for every gate or valve.

• Moderate – Moderate (normal) levels of maintenance would include some corrective maintenance.

• Excessive – Excessive maintenance is intended to include labor-intensive items. Frequent corrosion repairs or abnormal wear to components would be considered excessive.

Results are analyzed and applied to Table 8 to arrive at an appropriate Maintenance History Condition Indicator Score.

Table 8 – Maintenance History Scoring Maintenance Condition Amount of Required Maintenance Indicator Index Score

Small 2 Moderate 1 Excessive 0

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E11.11 TIER 1 – EMERGENCY CLOSURE SYSTEM CONDITION INDEX CALCULATIONS

Enter the Emergency Closure Systems condition indicator scores from the tables above into the Emergency Closure Systems Assessment Summary Form at the end of this document. Multiply each indicator score by its respective Weighting Factor, and sum the total scores to arrive at the Tier 1 Emergency Closure System Condition Index. E11.12 TIER 1 – EMERGENCY CLOSURE SYSTEM DATA QUALITY INDICATOR The Emergency Closure Systems Data Quality Indicator reflects the quality of the inspection, test, and measurement results used to evaluate the condition of the emergency closure system under Tier 1. The more current and complete the results are, the higher the rating for this indicator. A condition assessment schedule appropriate for scoring the Data Quality Indicator is shown in Table 9. Alternatively, an organization’s recommended or standard practice for performing the emergency closure system tests and inspections may be substituted for the time intervals given in the table. Results are analyzed and applied to Table 9 to arrive at an appropriate Emergency Closure System Data Quality Indicator Score.

Table 9 – Emergency Closure System Data Quality Indicator Scoring

Data Quality Years Since Last Condition Assessment Indicator Score

< 8 years 10 ≥ 8 and < 17 years 7 ≥ 17 and < 25 years 4

≥ 25 years 0 Enter the Emergency Closure System Data Quality Indicator Score from Table 9 into the Emergency Closure System Condition Assessment Summary form at the end of this document.

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E11.13 TIER 2 – INSPECTIONS, TESTS, AND MEASUREMENTS Tier 2 inspections, tests, and measurements require specialized personnel to interview plant O & M staff and inspect the emergency closure system. The work may involve an outage to perform a proper assessment. A Tier 2 assessment is not considered routine. Tier 2 inspections may affect the Emergency Closure System Condition Index established using Tier 1. A team consisting of the plant O & M representatives and technical specialists should perform Tier 2 assessments. The tasks to be performed for Tier 2 are summarized below:

1. Technical specialists will be responsible to:

• Visit the plant to perform a physical inspection of an emergency closure gate or valve.

• Interview plant O & M staff. • Determine current condition of the emergency closure system. • Review results and, if necessary, adjust the Tier 1 Condition Index based upon the

inspection and comparison with the condition of other similar emergency closure systems.

2. Plant O & M representatives will be responsible to:

• Provide necessary support and information to technical specialists. • Assist in the assessment process.

For each Tier 2 test performed, add or subtract the appropriate amount to/from the Emergency Closure System Condition Index. The Tier 2 evaluation is divided into different categories: Gates, Valves, and Gate and Valve Operators. When evaluating a particular emergency closure, only evaluate based on the applicable evaluation criteria (i.e., do not evaluate a gate using the valve criteria). If some evaluation criteria are unknown or cannot be inspected, do not adjust the score. An adjustment to the Data Quality Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment. Note: As in the case of Tier 1 evaluations, any single condition may be severe enough to justify immediate corrective action even if the overall condition index does not indicate such a response. Test T2.1: Gates Gates – Structural Integrity The physical deterioration of emergency closure gates is likely to result from one or more of the following factors:

• Corrosion • Yielding, Fracture, Fatigue, and Fabrication Discontinuities • Improper Field Repair and/or Modifications

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• Miscellaneous Damage or Other Conditions Test T2.1.1: Gates – Corrosion Corrosion typically causes the most damage to emergency closure gates. Special attention should be paid to critical areas such as welds, member interfaces, and connectors. Corrosion nodes should be chipped off to reveal the true extent of metal deterioration.

Table 11 – Corrosion

Adjustment to Results Condition Index Score

Good – Corrosion has not caused significant loss of cross-sectional area for structural members, corrosion buildup has not caused separation in adjacent members, localized corrosion has not reduced weld areas significantly, protective coatings in good condition, little or no cavitation.

Add 1.0

Moderate – Small amounts of cross-sectional area has been lost in some members, there is isolated plate separation caused by corrosion, some pitting, some weld area reduction in some welds, protective coating in fair condition, moderate cavitation.

No Change

Severe – Significant cross-sectional area loss in critical members, widespread plate and/or member separation, significant weld size loss due to corrosion, significant pitting protective coating in poor condition, severe cavitation damage.

Subtract 1.0

Test T2.1.2: Gates – Yielding, Fracture, Fatigue, and Fabrication Discontinuities Yielding and fracture of structural members and weldments can compromise structural integrity and deserve special attention. They can occur from a variety of causes including, but not limited to:

• Impact • Fatigue loading • Material defect • Design overload

Fractures usually occur where there are local stress raisers. This occurs where there is a local geometry change. Examples of this are bolt/rivet holes, sharp inside corners, corrosion pits, and weldments. Cracking of weldments or base metals is particularly problematic where thick members are welded together or there are dimensioning errors. Improper welding techniques and welding in an inaccessible area can also lead to problematic discontinuities. Welding discontinuities take many forms and are usually identified by visual inspection. Visual inspection however cannot locate many weld discontinuities such as incomplete joint penetration. Non-destructive testing on welds is the best way to determine weld condition.

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Table 12 – Yielding, Fracture, Fatigue, and Fabrication Discontinuities Adjustment to Results Condition Index Score Good – No visible yielding or buckling, there is little to no cracking near welds and/or stress concentrators. Any cracks have not propagated significantly.

Add 1.0

Moderate – May be slight yielding; cracking near stress concentrators or welds is intermittent with little or no propagation. Can justify the use of non-destructive testing on some welds.

No Change

Severe – Significant yielding or buckling in critical members, cracking in a sequence of welds, crack propagation in many cracks. Usually justifies the use of non-destructive testing on most welds.

Subtract 1.0

Test T2.1.3: Gates – Improper Field Repair and/or Modifications Gates that have been significantly modified in the field without proper engineering and quality control may be structurally compromised. Improper repairs include, but are not limited to:

• Replacing parts with lesser quality or strength parts than the gate was engineered for (bolts, skin plates, picking eyes, structural steel, etc.)

• Protective coatings that are improperly formulated or applied • Cutting of beam webs or flanges • Improper welding/rewelding

Table 13 – Improper Field Repair and/or Modifications

Adjustment to Results Condition Index Score Good – No field repairs or modifications done without proper engineering analysis. No Change

Moderate – Some minor repairs, not likely to cause failure. Subtract 0.5 Severe – Major modifications that severely compromise the structural integrity of the gate. Subtract 1.0

Gates – Functional Operation Test T2.1.4: Gates – Raising/Lowering Performance This evaluation criterion is based on the overall performance of the emergency closure system. The gate should lower and raise in a certain amount of time as specified by organizational standards. Performance tests should be implemented where reasonable. This section is concerned if the gate binds or hangs up in the gate slot due to dimensional alignment deficiencies, not the gate operator itself.

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Note: If the gate performs unacceptably and the reason relates to the gate operator itself, score a “No Change” for this section and make an adjustment in the Gates – Operators Performance section.

Table 14 – Raising/Lowering Performance Adjustment to

Results Condition Index Score Acceptable – Gates lower as designed in time specified by performance standards or design. No Change

Unacceptable – Gates severely bind or hang-up and/or do not raise and lower as designed in time specified by organizational performance standards or design specifications.

Subtract 1.0

Test T2.1.5: Gates – Slots, Seals, and Sealing Surfaces Sealing problems can arise from any number of conditions. Seals degrade over time and allow leakage. Some leakage is normal. Tier 1 assessment should have estimated leakage rate. Tier 2 assessment should be mainly concerned with the cause of leakage. Possible causes for gate leakage include:

• Seal worn or damaged • Sealing surface worn or damaged • Sealing surface corroded • Sealing surface not straight • Seal out of adjustment • Dimensional error of gate or gate slot • Damaged gate • Dam superstructure has moved over time, changing the dimensions of the intake • Obstruction(s) in gate slot • Cracked or missing concrete or grout around sealing surface

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Table 15 – Slots, Seals, and Sealing Surfaces

Adjustment to Results Condition Index Score Good – Seals are in good condition with less than normal leakage (< 25 gpm or < 1.6 liters/s), seal surfaces are parallel (to each other) and in good condition with minimal pitting and cavitation damage. Seal will function adequately for ≥ 10 years.

Add 0.5

Moderate – Seals and sealing surfaces are in serviceable condition with moderate leakage (≥ 25 and < 50 gpm or ≥ 1.6 and < 3.2 liters/s). There is some small dimensional discrepancy causing leakage. Seal will function adequately for ≥ 7 and < 10 years.

No Change

Severe – Large volume of leakage (≥ 50 gpm or ≥ 3.2 liters/s) caused by significant damage or dimensional discrepancy. Seal does not, or will function adequately for < 7 years.

Subtract 0.5

Test T2.1.6: Gates – Wheels, Rollers, Roller Chains, Bearings, and Bushings Gate rollers and bearings take on a variety of forms and suffer from wear, corrosion, and damage over many years of service. Rollers should rotate easily without excessive play. Excessive corrosion could lead to cracking or flat spots on rollers or wheels. Chain roller bushings should not have excessive wear, corrosion, or play. Chain links should be structurally sound. Slide gate bearing surfaces should be square to each other with a uniform wear pattern. Bearing surfaces should not have abnormal gouging or deep corrosion that could compromise function.

Table 16 – Wheels, Rollers, Roller Chains, Bearings, and Bushings Adjustment to Results Condition Index Score Good – Rollers rotate as designed, rollers do not have significant corrosion damage, are not cracked, and do not have abnormal play or flat spots. Bearings surfaces have uniform wear with no excessive grooves. Roller chains are structurally sounds with good bushing condition.

Add 0.5

Moderate – No major damage, some roller corrosion, some small flat spots, rollers rotate acceptably. Some uneven or moderate wear on bearings surfaces. Moderate to significant corrosion on roller chain links, some bushing wear. Some rollers cracked.

No Change

Severe – Significant roller damage including, but not limited to, cracking, pitting, and flat spots. Excessive play or bearing seizure of rollers. Bearing surfaces deeply grooved, galled, or unevenly worn. Severe corrosion and bushing wear on roller chain. Grout cracked or missing around bearing surfaces.

Subtract 0.5

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Test T2.2: Valves Valves – Structural Integrity The physical deterioration of emergency closure valves is likely to be from one or more of the following factors:

1) Corrosion 2) Yielding, Fracture, Fatigue and Fabrication Discontinuities 3) Field Repair and Modification 4) Miscellaneous Damage and Conditions

Test T2.2.1: Valves – Corrosion Some major contributing factors to corrosion are: the pH and ion concentration of the river, relative humidity of 40% or more, ineffective protective coatings (due to age, improper formulation, or improper application), cavitation, and malfunctioning or improperly maintained cathodic protection systems. Also, dissimilar metals in contact can cause a dielectric reaction and cause one of the metals (usually carbon steel) to corrode at an accelerated pace. For valves, cavitation is typically more significant than oxidation.

Table 17 – Corrosion

Adjustment to Results Condition Index Score

Good – Corrosion has not caused significant loss of cross-sectional area for structural elements, localized corrosion has not reduced weld area significantly, protective coating in good condition, little or no cavitation.

Add 1.0

Moderate – Small amounts cross-sectional area has been lost in some elements, there is isolated plate separation from corrosion, some pitting, some weld area reduction in some welds, protective coating in fair condition, moderate cavitation.

No Change

Severe – Significant cross-sectional area loss in critical members, significant weld size loss due to corrosion, significant pitting protective coating in poor condition, severe cavitation damage.

Subtract 1.0

T2.2.2: Valves – Yielding, Fracture, Fatigue, and Fabrication Discontinuities Yielding and fracture of structural members and weldments can compromise structural integrity and deserve special attention. They can occur from a variety of causes including, but not limited to: impact, fatigue loading, material defect, and design overload. Fractures usually occur where there are local stress raisers. This occurs where there is a local geometry change. Examples of this are bolt/rivet holes, sharp inside corners, corrosion pits, and weldments. Cracking of weldments or base metals is particularly problematic where thick members are welded together or there are dimensioning errors. Improper welding techniques

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and welding in an inaccessible area can also lead to problematic discontinuities. Welding discontinuities take many forms and are usually identified by visual inspection. Visual inspection however cannot locate many weld discontinuities such as incomplete joint penetration. Non-destructive testing on welds is the best way to determine weld condition.

Table 18 – Yielding, Fracture, Fatigue, and Fabrication Discontinuities Adjustment to Results Condition Index Score Good – No visible yielding or buckling, there is little to no cracking near welds and/or stress concentrators. Any cracks have not propagated significantly.

Add 1.0

Moderate – May be slight yielding; cracking near stress concentrators or welds is intermittent with small amount of propagation. Can justify the use of non-destructive testing on some welds.

No Change

Severe – Significant yielding or buckling in critical members, cracking in a sequence of welds, crack propagation in many cracks. Usually justifies the use of non-destructive testing on some welds.

Subtract 1.0

Test T2.2.3: Valves – Improper Field Repair and/or Modifications Valves that have been significantly modified in the field without proper engineering and quality control may be structurally compromised, depending on the magnitude of the modification or fix. Improper repairs include, but are not limited to:

• Replacing parts with lesser quality or strength parts than the valve was engineered for • Protective coatings that are improperly formulated or applied • Cutting of structural elements • Improper welding/rewelding

Table 19 – Improper Field Repair and/or Modifications

Adjustment to Results Condition Index Score Good – No field repairs or modifications done without proper engineering analysis. No Change

Moderate – Some minor repairs, not likely to cause failure. Subtract 0.5 Severe – Major modifications that severely compromise the structural integrity of the valve. Subtract 1.0

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Valves – Functional Operation Test T2.2.4: Valves – Actuation Performance Valve actuation performance is concerned with the timeframe and smoothness that an emergency closure valve can operate within. Emergency closure valves typically have some sort of performance standard stating that the valve must move from the completely open to completely closed position (usually in a runaway turbine condition) within a certain timeframe (e.g., less than 2 minutes for Army Corps of Engineers). Obviously, it is not reasonable to perform this test; however, best efforts should be made to assess the valve actuation performance. Note: If valve performs unacceptably and the reason relates to the valve operator itself, score a “No Change” for this section and make an adjustment in the Valves – Operators Performance section.

Table 20 – Actuation Performance Adjustment to

Results Condition Index Score Acceptable – Valve actuates from fully open to fully closed in the required timeframe. No Change

Unacceptable – Valve does not actuate from fully open to fully closed in the required timeframe. Performance based on some deficiency of the valve assembly.

Subtract 1.0

Test T2.2.5: Valves – Seals, Sealing Surfaces, and Packing Valve seals that seal the penstock can either be made of a resilient (i.e. rubber or nylon) or metal such as stainless steel or bronze. As with gates, some leakage is not necessarily indicative of a defective seal, but valves usually leak less since they usually have a smaller seal length than gates. Excessive leakage can be a sign of damage, wear, maladjustment, fabrication deficiency, or movement of the valve or valve body. Valve shaft trunnions also have a seal or packing that can leak for the same reasons. Packing will normally leak at a controlled rate even when new. Note: If sealing problems are related to bushing or bearing wear or damage, assess a condition adjustment based on the next section, Valves – Bearings and Bushings, so that the same problem is not scored twice.

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Table 21 – Seals, Sealing Surfaces, and Packing

Adjustment to Results Condition Index Score Good – Seals are in good condition with less than normal leakage (< 12.5 gpm or < 0.8 liters/s), seal surfaces are parallel (to each other) and in good condition with minimal pitting and cavitation damage. Seal will function adequately for ≥ 10 years.

Add 0.5

Moderate – Seals and sealing surfaces are in serviceable condition with moderate leakage (≥ 12.5 and < 25 gpm or ≥ 0.8 and < 1.6 liters/s). There are some small dimensional discrepancies or cavitation damage. Seal or seal surface can be adjusted for a better seal. Seal will function adequately for ≥ 7 and < 10 years.

No Change

Severe – Large volume of leakage (≥ 25 gpm or ≥ 1.6 liters/s) caused by significant damage or dimensional discrepancy. Seal will function adequately for < 7 years. Shaft trunnion seals or packing leak excessively. Seal or seal surface cannot be adjusted for a better seal.

Subtract 0.5

Test T2.2.6: Valves – Bearings and Bushings Valve bearings and bushings tend to have a limited amount of wear since they do not experience very many cycles per year of operation. Deficiencies are usually from improper installation, manufacturing or material defect, and/or lack of preventative maintenance. Bushings are very difficult to inspect while installed; usually the poor condition of a bushing is not known until total failure. A grade of moderate should be given unless bearings and bushings can be inspected directly.

Table 22 – Bearings and Bushings Adjustment to Results Condition Index Score Good – Bearings and bushings are in good shape with no apparent eccentric wear or misalignment. Add 0.5

Moderate – Bearings and bushings are worn in accordance with their age and are still in serviceable condition. No Change

Severe – Bearings and bushings are wearing eccentrically and/or are not installed concentrically with shaft. Apparent manufacture or material defect. Total failure.

Subtract 0.5

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Test T2.3: Gates and Valves Operators Operators – Structural Integrity Gate and valve operators are usually hydraulic cylinders, hydraulic hoists, or electric-driven hoists. This section is concerned with the structural integrity of the gate and valve operators including:

• Corrosion • Anchoring • Yielding, Fracture and Fatigue and Fabrication Discontinuities • Improper Field Repair and Modification • Miscellaneous Damage and Condition

Note: Bridge and gantry cranes that are used for emergency closure shall not be inspected or rated using this section. Bridge and gantry cranes have specific inspection requirements that are described in applicable Federal, State, Provincial laws and regulations. See Appendix E9: Crane Condition Assessment. Test T2.3.1: Operators – Corrosion Some major contributing factors to corrosion are: the pH and ion concentration of the river, relative humidity of 40% or more, ineffective protective coatings (due to age, improper formulation, or improper application), cavitation, and malfunctioning or improperly maintained cathodic protection systems. Also, dissimilar metals in contact can cause a dielectric reaction and cause one of the metals (usually carbon steel) to corrode at an accelerated pace.

Table 23 – Corrosion

Adjustment to Results Condition Index Score

Good – Corrosion is mainly superficial, hoist drums and sheaves are in good shape, little or no pitting, welds have not been reduced in area, corrosive protective coating is in serviceable condition.

Add 1.0

Moderate – There is some pitting and more sever corrosion. Protective coating needs some attention in the near future. Corrosion will not affect structural integrity for ≥ 7 and < 10 years.

No Change

Severe – Metal is deeply pitted and/or has reduced metal cross-sectional area significantly in structural elements such as lifting beams, anchor bolts, shafts, etc. Corrosion will likely effect structural integrity in < 7 years.

Subtract 1.0

Test T2.3.2: Operators – Anchoring For inspection purposes, it is very difficult to adequately assess if anchoring was properly designed and is adequate, however, portions of the anchoring can be inspected for failure.

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Table 24 – Anchoring

Adjustment to Results Condition Index Score

Good – Operators are solidly anchored with original equipment, concrete is not spalled near anchors, all anchors are present and in good condition. Epoxy or grout is in good shape.

Add 1.0

Moderate – Some deficiencies including a small amount of concrete spalling or missing grout or epoxy. Anchor bolts are present and in marginal condition. No apparent movement of operators.

No Change

Severe – Operators have visibly moved. Anchor bolts are loose, missing, or yielded. Additional anchors installed by project to help secure the operator, spalling and/or epoxy bonds broken.

Subtract 1.0

Test T2.3.3: Operators – Yielding, Fracture, Fatigue, and Fabrication Discontinuities Yielding, Fracture, Fatigue, and Fabrication Discontinuities will be consistent with those found in gates and valves. See descriptions in the corresponding Gates and Valves sections.

Table 25 – Yielding, Fracture, Fatigue, and Fabrication Discontinuities Adjustment to

Results Condition Index Score Good – No visible yielding or buckling, there is little to no cracking near welds and/or stress concentrators. Any cracks have not propagated significantly.

Add 1.0

Moderate – May be slight yielding; cracking near stress concentrators or welds is intermittent with small amount of propagation. Can justify the use of non-destructive testing on some welds.

No Change

Severe – Significant yielding or buckling in critical members, cracking in a sequence of welds, crack propagation in many cracks. Usually justifies the use of non-destructive testing on some welds.

Subtract 1.0

Test T2.3.4: Operators – Improper Field Repair and/or Modifications Valves that have been significantly modified in the field without proper engineering and quality control may be structurally compromised, depending on the magnitude of the modification or fix. Improper repairs include, but are not limited to:

• Replacing parts with lesser quality or strength parts than the valve was engineered for • Protective coatings that are improperly formulated or applied • Cutting of structural elements • Improper welding/rewelding

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Table 26 – Improper Field Repair and/or Modifications Adjustment to Results Condition Index Score Good – No field repairs or modifications done without proper engineering analysis. No Change

Moderate – Some minor repairs, not likely to cause failure. Subtract 0.5 Severe – Major modifications that severely compromise the structural integrity of the valve. Subtract 1.0

Hydraulic Operators – Functional Operation Test T2.3.5: Hydraulic Operators – Actuation Performance The operating performance of the gate or valve in this section is concerned with overall system performance directly affected by the gate or valve operator itself. Such issues can include misalignment, speed, and reliability. Note: If the gate or valve performs unacceptably, and the reason does not relate to the gate or valve operator itself, score a “No Change” for this section and make an adjustment in the corresponding Gates – Raising/Lowering Performance or Valves – Actuation Performance section.

Table 27 – Actuation Performance Adjustment to Results Condition Index Score Acceptable – Gate or valve actuates from fully open to fully closed in the required timeframe. No Change

Unacceptable – Valve does not actuate from fully open to fully closed in the required timeframe. Performance based on some deficiency of the hydraulic system.

Subtract 1.0

Test T2.3.6: Hydraulic Operators – Pistons Dirty hydraulic fluid can cause piston rod to gouge or wear prematurely, especially for pistons near the bottom of the hydraulic system. Chrome plated piston rods can corrode. Ceramic-coated pistons with an improperly applied coating can corrode underneath and chip off, which will cause a failure of the piston seals. Ceramic coatings are also brittle and can crack if the piston rod is flexed or impacted. Without taking piston apart, it is difficult to determine the condition of the internal parts. A drift test can be performed to estimate the performance of the unit. Cylinders that suspend loads under pressure naturally leak fluid through the internal seals over time, which causes the gates to drift; the hydraulic system automatically corrects this. This cycle is repeated many times, sometimes thousands of times per month, causing undo wear on a small a length of the piston stroke.

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Drift Test -- suspend the working load for one hour on a hydraulically isolated piston and determined the hydraulic fluid leaked through piston rings. The following performance estimates are rules of thumb:

N = V/(πDt) in terms of volume leaked [units = ml/(cm-h) = cm2/h] or

N = LD/(4t) in terms of length drifted [units = ml/(cm-h) = cm2/h] where

N = piston drift number V = fluid volume leaked (1 ml = 1 cm3) D = internal piston stroke diameter (cm) t = test time (hours) L = length of drift (cm)

Note: 11.64 ml/(cm-h) = 1 oz/(in-h) For resilient piston rings, leakage for a properly working piston should be very small [N < 2 ml/(cm-h)]; for cast iron rings, leakage is much more, on the order of N ≈ 40 ml/(cm-h). For multistage cylinders, the piston drift number applies to each stage individually; e.g., a 3-stage, telescoping cylinder with cast iron piston rings will have an allowable leakage limit of N = 3 times ≈ 40 ml/(cm-h) ≈ 120 ml/(cm-h) of cylinder drift.

Table 28 – Pistons

Adjustment to Results Condition Index Score

Good – Normal internal leakage, N < 40 ml/(cm-h) for cast iron piston rings, N < 2 ml/(cm-h) for resilient piston rings and packing. No noticeable scoring, cracking, or chipping on piston rods, corrosion minimal. No external leakage into a sensitive environment.

Add 0.5

Moderate – Some internal leakage, N ≥ 40 and < 200 ml/(cm-h) for cast iron piston rings and packing, N ≥ 2 and < 10 ml/(cm-h) for resilient piston rings. Some piston rod wear with no external leakage into a sensitive environment.

No Change

Severe – Large volume of internal leakage N ≥ 200 ml/(cm-h) for cast iron piston rings and packing, N ≥ 10 ml/(cm-h) for resilient piston rings and packing. Significant piston rod wear and danger of failure or significant external leakage into a sensitive environment.

Subtract 0.5

Test T2.3.7: Hydraulic Operators – Hydraulic Systems This rating adjustment applies to the entire hydraulic system other than the pistons themselves. Since hydraulic systems can be relatively simple or fairly complex, the rater must use their best judgment to rate the overall condition of the hydraulic system.

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Table 29 – Hydraulic Systems

Adjustment to Results Condition Index Score

Good – Overall condition indicates the need for little or no attention, leakage is minimal; valves, solenoids relays, and heat exchangers are in working condition. Fittings, lines and hoses are in good condition. Hydraulic fluid is clean and uncontaminated. Replacement parts are in stock or readily available.

Add 0.5

Moderate – Some attention required but system in service able condition. Some hoses and fittings worn and/or leaking. Some components are not working optimally. Hydraulic fluid is dirty. Replacement parts are hard to obtain.

No Change

Severe – System frequently needs repair; spare parts unavailable or very hard to find. Major leakage. Dirty or contaminated fluid. Overall condition poor.

Subtract 0.5

Test T2.3.8: Hydraulic Operators – Electric Motors Motors powering hydraulic systems may be tested in accordance with IEEE 112 if the motors a suspected of being deficient. IEEE 112 contains a multitude of tests, some which may not need to be performed. If the motor(s) is not tested, the score will not be adjusted.

Table 30 – Electric Motors Adjustment to Results Condition Index Score

Good – Performance passes given performance tests. No Change

Moderate – Some non-critical performance tests are failed (e.g., efficiency) but motor is in still serviceable condition. Subtract 0.5

Severe – Motor fails one or more critical test. Is deemed not serviceable and in need of repair or replacement. Subtract 1.0

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Test T2.3.9: Hydraulic Operators – Electric Controls

Table 31 – Electric Controls Adjustment to Results Condition Index Score Good – Control wiring is clean, with no excessive soil, fatigue, or wear apparent on insulation or jacket material. Wiring is securely connected to devices, or is loosely connected but can be corrected without spare parts or special tools. Control devices (pushbuttons, contactors, switches, coils) are clean and function as designed. Control enclosures are clean, with no excessive soil, corrosion, or physical damage.

No Change

Fair – Control wiring, enclosures, and devices are clean and in good overall condition, but spare parts are no longer available. Wiring insulation or jacket is polyvinyl chloride (PVC) compound.

Subtract 0.25

Moderate – Control wiring has minor wear, fatigue, or soil apparent on insulation or jacket material. Some control wiring appears loosely connected to devices, and cannot be corrected, or cannot be corrected without spare parts or special tools. Control devices (pushbuttons, contactors, switches, coils) are not clean or do not function as designed. Control enclosures have some soil, corrosion, or physical damage.

Subtract 0.5

Severe – Control wiring has wear, fatigue, or soil apparent on insulation or jacket material. Control wiring has become disconnected from corresponding devices, and cannot be corrected. Control devices (pushbuttons, contactors, switches, coils) do not function. Control enclosures have excessive soil, corrosion, or physical damage.

Subtract 1.0

Electric Operators – Functional Operation Test T2.3.10: Electrical Operators – Actuation Performance The operating performance of the gate or valve in this section is concerned with overall system performance directly affected by the gate or valve operator itself. Such issues can include misalignment, speed, and reliability. Note: If the gate or valve performs unacceptably, and the reason does not relate to the gate or valve operator itself, score a “No Change” for this section and make an adjustment in the corresponding Gates – Raising/Lowering Performance or Valves – Actuation Performance section.

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Table 32 – Actuation Performance Adjustment to

Results Condition Index Score Acceptable – Gate or valve actuates from fully open to fully closed in the required timeframe. (Takes < 2 minutes for valves and < 10 minutes for gates if requirement is not known.)

No Change

Unacceptable – Gate or valve does not actuate from fully open to fully closed in the required timeframe. (Takes ≥ 2 minutes for valves and ≥ 10 minutes for gates if requirement is not known.) Performance based on some deficiency of the electric-powered gate or valve operator.

Subtract 1.0

Test T2.3.11: Electrical Operators – Electric Controls

Table 33 – Electric Controls Adjustment to

Results Condition Index Score Good – Control wiring is clean, with no excessive soil, fatigue, or wear apparent on insulation or jacket material. Wiring is securely connected to devices, or is loosely connected but can be corrected without spare parts or special tools. Control devices (pushbuttons, contactors, switches, coils) are clean and function as designed. Control enclosures are clean, with no excessive soil, corrosion, or physical damage.

No Change

Fair – Control wiring, enclosures, and devices are clean and in good overall condition, but spare parts are no longer available. Wiring insulation or jacket is polyvinyl chloride (PVC) compound.

Subtract 0.25

Moderate – Control wiring has minor wear, fatigue, or soil apparent on insulation or jacket material. Some control wiring appears loosely connected to devices, and cannot be corrected, or cannot be corrected without spare parts or special tools. Control devices (pushbuttons, contactors, switches, coils) are not clean or do not function as designed. Control enclosures have some soil, corrosion, or physical damage.

Subtract 0.5

Severe – Control wiring has wear, fatigue, or soil apparent on insulation or jacket material. Control wiring has become disconnected from corresponding devices, and cannot be corrected. Control devices (pushbuttons, contactors, switches, coils) do not function. Control enclosures have excessive soil, corrosion, or physical damage.

Subtract 1.0

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Test T2.3.12: Operators – Electric Motors Motors powering electric-operated systems may be tested in accordance with IEEE 112 if the motors a suspected of being deficient. IEEE 112 contains a multitude of tests, some which may not need to be performed. If the motor(s) is not tested, the score will not be adjusted be given.

Table 34 – Electric Motors Adjustment to

Results Condition Index Score

Good – Performance passes given performance tests. No Change

Moderate – Some non-critical performance tests are failed (e.g., efficiency) but motor is in still serviceable condition. Subtract 0.5

Severe – Motor fails one or more critical test. Is deemed not serviceable and in need of repair or replacement. Subtract 1.0

Test T2.3.13: Electrical Operators – Electric Brakes

Table 35 – Electric Brakes Adjustment to

Results Condition Index Score Good – Brake and enclosure are clean, with no significant soil, corrosion, or physical damage. Brake actuator (coil or thruster) is clean, with no significant soil, corrosion, or physical damage, and functions as designed. Thruster unit has no leaks. Brake torque rating is ≥ 125% of motor torque rating, and if field-adjustable, is set to 100% or greater torque rating. Brake wheel and pads are in contact with each other for ≥ 80% of the wheel surface and exhibit minimal wearing.

No Change

Fair – Brake, enclosure, actuator, wheel, and pads are clean and in good overall condition, but spare parts are no longer available, or brake pads contain asbestos.

Subtract 0.25

Moderate – Brake and enclosure have some soil, corrosion, or physical damage. Brake actuator (coil or thruster) has some soil, corrosion, or physical damage, or does not function as designed. Thruster unit, if present, exhibits minimal leakage. Brake torque rating is ≥ 100 and < 125% of motor torque rating. Brake wheel and pads are in contact with each other for ≥ 50 and < 80% of the wheel surface and exhibit moderate wearing.

Subtract 0.5

Severe – Brake and enclosure have extensive soil, corrosion, or physical damage. Brake actuator (coil or thruster) has extensive soil, corrosion, or physical damage, or does not function as designed. Thruster unit, if present, exhibits leakage. Brake torque rating is < 100% of motor torque rating. Brake wheel and pads are in contact with each other for < 50% of the wheel surface or exhibit

Subtract 1.0

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extensive wearing. Extreme – Brake does not release, or is not able to hold load (slips). Subtract 1.5 Test T2.3.14: Electrical Operators – Wire Ropes and Chains Wire ropes and chain carry the load of emergency closure gates and must be in serviceable condition. Failure or these devices could cause significant economic and life safety impact. Hoists that are difficult to inspect often are not. It is important to examine the entire length of wire rope, especially the underside of the rope that commonly comes in contact with the hoist drum or sheaves as the top of the rope can be in good condition while the bottom side can be severely worn. Other problems with wire rope include, but are not limited to: corrosion (loss of cross-sectional area) and broken wires, strands, and cores from abrasion, fatigue, deformation, and material defect. Traditionally, tests have been visual, but there is now a non-destructive test method called Magnetic Flux Leakage (MFL) test that can be performed on wire rope that will reveal deficiencies not easily identified by visual inspections. MFL may be justified for critical applications such as emergency closures. Hoist chain is difficult to inspect and is not usually cost effective (if thought to be defective) as it can be easily replaced relatively inexpensively.

Table 36 – Wire Ropes and Chains

Adjustment to Results Condition Index Score

Good – Wire rope in good condition with no significant loss in cross-sectional area, no broken wires, corrosion is superficial. Rope greased sufficiently. Chain in good condition; withstands proof loads.

No Change

Moderate – Less than 12 randomly broken wires in one lay and/or < 4 broken wires in one strand in one lay. Less than 1/3 diameter loss from wear or corrosion in outside individual wires and/or < 10% loss in cross-sectional area at any point in rope. No crushing or kinking. Chain in marginal condition with < 10% loss in cross-sectional area; withstands proof loads. Wire ropes or chains should be replaced as soon as reasonably possible.

Subtract 0.5

Severe – 12 or more randomly broken wires in one lay and/or ≥ 4 broken wires in one strand in one lay. 1/3 or more diameter loss from wear or corrosion in outside individual wires and/or ≥ 10% loss in cross-sectional area at any point in rope. Wire crushed or kinked; evidence of heat damage. Chain in poor condition with ≥ 10% loss in cross-sectional area. Wire ropes or chains should be changed immediately before emergency closure is used.

Subtract 1.0

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Test T2.3.15: Electrical Operators – Power Screws Power screws are typically made of carbon or stainless steel with bronze mating nuts to avoid galling. They should be exercised and inspected for such things as: wear on mating surfaces (both screw and mating nut), straightness of screw, thread damage, corrosion, surface finish condition, and brake condition (if equipped).

Table 37 – Power Screws

Adjustment to Results Condition Index Score

Good – Power screw in good condition, no major deficiencies. Add 0.5 Moderate – Power screw in serviceable condition, no deficiencies that could compromise safety. No Change

Severe – Serious wear, defect or damage that could compromise proper operation of the gate or valve. Subtract 0.5

Test T2.3.16: Electrical Operators – Drums and Sheaves Hoist drums and sheaves should be checked for wear and general operating condition. Structural deficiencies should have already been noted in the Structural Integrity section.

Table 38 – Drums and Sheaves

Adjustment to Results Condition Index Score

Good – Hoist drum in good condition, no major deficiencies. Wire rope is secured to drum correctly; wire rope is not over spooled when gate is in the 100%-up condition.

Add 0.5

Moderate – Drums and sheaves in service able condition with normal wear. No Change

Severe – Drum highly worn in grooves, alignment incorrect, sheaves worn, cathodes not working correctly or used up. Subtract 0.5

Test T2.3.17: Electrical Operators – Gearboxes, External Gearing, and Chain Sprockets A gearbox should be operated through a full operation cycle and observed for abnormal sounds that may indicate internal problems. Opening, draining, cleaning, and inspection of gearbox internals may be justified. Lube oil may be sampled to test the condition. External leakage should also be noted.

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Table 39 – Gearboxes, External Gearing, and Chain Sprockets

Adjustment to

Results Condition Index Score Good – Gearbox in good working condition. Gearbox internals (if inspected) are in good working order, gear tooth wear is minimal with even wear pattern, bushing and bearings are in good shape, seals do not leak externally. External gearing and chain sprockets are in good shape.

Add 0.5

Moderate – Gearbox is serviceable. Gearing (if inspected) is in good shape, no cracking, moderate tooth wear and/or uneven wear pattern. Some metal accumulation in bottom of gearbox. Gearbox, gearing, and chain sprockets serviceable for ≥ 7 and < 10 years.

No Change

Severe – Gearbox in poor condition. Extreme wear and/or cracking on teeth, substantial metal accumulation in gearbox, dirty or insufficient gear lube, seals leak extensively, bearings or bushings in poor condition. Gearbox, gearing, and chain sprockets serviceable for < 7 years.

Subtract 0.5

Test T2.3.18: Electrical Operators – Bearings and Bushings Bearings and bushings are subject to normal wear and tear and are subject to a finite life span. Bearing and bushings (those inside gearbox were inspected as part of the section on Gearboxes, External Gearing, and Chain Sprockets) should be inspected where possible for wear, damage, installation error, and manufacture malfunction. Since this section rating could encompass many bearings and bushing, the rater should rate the overall condition of all the bearings, noting individual bearings or bushings that need immediate repair.

Table 40 – Bearings and Bushings

Adjustment to Results Condition Index Score

Good – Bearings and bushings are in good shape and need little or no attention. Add 0.5

Moderate – Some repair needed on individual bearings or bushings. No Change Severe – System wide poor condition of bearings and bushings, easier to overhaul everything than attempt individual repair to select bearings and bushings.

Subtract 0.5

Test T2.4: Miscellaneous Deficiencies Any deficiencies not listed in the previous sections should be noted. The Tier 2 rater should use their judgment to assess a negative condition assessment adjustment to the Gate, Valve, or Operator condition.

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Table 41 – Miscellaneous Deficiencies

Adjustment to Results Condition Index Score

Moderate – May affect the function of emergency closure system. Subtract 0.5 Severe – Will severely affect performance or structure of the emergency closure system to the point where there is risk of significant economic or life loss.

Subtract 1.0

Test T2.5: Annunciation Inspection of annunciation is concerned with any sensor that indicates position, condition, level, or status of the emergency closure gate, valve, or operator. Remote controlled plants may have more elaborate controls than a manned facility. Annunciation to be checked includes, but is not limited to:

• High/low level indicators • Gate or valve position indicators • Hydraulic pump run time indicators

Table 42 – Annunciation

Adjustment to

Results Condition Index Score Good – Annunciation is in proper working order. No Change Moderate – Annunciation works for the most part, fulfilling the requirements of the project. Any discrepancies can be easily fixed. Subtract 0.25

Severe – System wide failure of annunciation possibly compromising function or safety of the facility. Annunciation does not fulfill the current needs for emergency closure systems.

Subtract 0.5

Test T2.6: Maintenance Escalation Maintenance escalation for equipment is normal. Equipment is engineered for some finite service life that is rarely shortened but often exceeded. Maintenance history should be examined to determine maintenance escalation. Findings may justify performing a cost benefit analysis based on increased maintenance costs and anticipated downtime. A risk assessment based on safety may also be justified.

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Table 43 – Maintenance Escalation

Adjustment to

Results Condition Index Score Good – Maintenance escalation is less than expected. Equipment age is less than expected service life. Add 0.5

Moderate – Maintenance escalation is in keeping with estimates and is manageable by the project staff. No anticipated significant risk of system failure.

No Change

Severe – Maintenance escalation is dramatic, required maintenance has increased beyond the capacity of the project. Anticipated significant risk of system failure.

Subtract 0.75

Test T2.7: Other Specialized Diagnostic Tests Additional tests may be applied to evaluate specific emergency closure gate and valve problems. Some of these diagnostic tests may be considered to be of an investigative research nature. When conclusive results from other diagnostic tests are available, they may be used to make an appropriate adjustment to the Emergency Closure Gate and Valve Condition Index. E11.15 TIER 2 EMERGENCY CLOSURE SYSTEM CONDITION INDEX

CALCULATIONS Tier 2 scoring adjusts the Tier 1 score. There are four different scoring sheets; hydraulic-operated gates, electric-operated gates, hydraulic-operated valves, and electric-operated valves. Choose the one that best describes the particular emergency closures. Action may be required for a low overall score or for a low score in any one major category (Structural Integrity, Functional Operation, etc.). Note that any adjustments cannot lower any major category score to less than 0 or more than the highest possible Tier 1 weighted score. Attach supporting documentation. An adjustment to the Data Quality Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment. E11.16 TIER 2 EMERGENCY CLOSURE SYSTEM DATA QUALITY INDICATOR An adjustment to the Data Quality Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment. E11.17 EMERGENCY CLOSURE SYSTEM CONDITION-BASED ALTERNATIVES The Emergency Closure Systems Condition Index – either modified by Tier 2 tests or not – may be sufficient for decision-making regarding emergency closure systems alternatives. The Index is also suitable for use in a risk-and-economic analysis model. Where it is desired to consider alternatives based solely on generator condition, the Emergency Closure System Condition Index

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may be directly applied to the Emergency Closure Systems Condition Index-Based Alternatives table.

Table 44 – Emergency Closure Systems Condition Index-Based Alternatives Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat Tier 1 assessment during next outage.

≥ 3.0 and < 7 (Fair) OR

Condition Indicators #2 or #3 with weighted scores of 1 or less

Continue operation but reevaluate O & M practices. Schedule Tier 2 assessment within < 4 years.

≥ 0 and < 3.0 (Poor) OR

Condition Indicators #2 or #3 with weighted scores of 0

Consultation with experts. Adjust O & M as prudent. Schedule Tier 2 assessment within < 2 years.

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EMERGENCY CLOSURE GATES & VALVES TIER 1 CONDITION ASSESSMENT SUMMARY

Date: _________________________________ Location: _______________________________

Unit: ___________________ Type of Gate or Valve: __________________________________

Tier 1 Emergency Closure Gates & Valves Condition Summary (For instructions on indicator scoring, please refer to condition assessment guide)

No. Condition Indicator Score × Weighting Factor = Total Score

1 Age (Score must be 0, 1, 2, or 3) 0.8

2 Physical Condition – Gates

or Valves (Score must be 0, 1, 2, or 3)

1

3 Physical Condition – Operators (Score must be 0, 1, 2, or 3) 1

4 Operations History (Score must be 0, 1, or 2) 0.4

5 Maintenance (Score must be 0, 1, or 2) 0.4

Tier 1 Emergency Closure System Condition Index

(Sum of individual Total Scores) (Condition Index should be between 0 and 10)

Tier 1 Data Quality Indicator

(Value must be 0, 4, 7 or 10)

Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________ (Attach supporting documentation.)

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Emergency Closure System Condition Index-Based Alternatives

Condition Index Suggested Course of Action

≥ 7.0 and ≤ 10 (Good) Continue O & M without restriction. Repeat Tier 1 assessment during next outage.

≥ 3.0 and < 7 (Fair) OR Condition Indicators #2 or #3 with

weighted scores of 1 or less

Continue operation but reevaluate O & M practices. Schedule Tier 2 assessment within < 4 years.

≥ 0 and < 3.0 (Poor) OR Condition Indicators #2 or #3 with

weighted scores of 0

Consultation with experts. Adjust O & M as prudent. Schedule Tier 2 assessment within < 2 years.

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EMERGENCY CLOSURE SYSTEM TIER 2 CONDITION ASSESSMENT SUMMARY

Date: _________________________________ Location: _______________________________

Unit: ___________________ Type of Gate: __________________________________

Part I: Determine Adjustment to Tier 1 Emergency Closure System Condition Index.

Emergency Closure System – Gates with Hydraulic Operators

Adjustment to Tier 1 No. Tier 2 Test (Table No.) Condition Index Gates (Structural Integrity and Functional Operation): T2.1.1 Corrosion (11) T2.1.2 Yielding, Fracture, Fatigue, and Fabrication Discontinuities (12) T2.1.3 Improper Field Repair and/or Modifications (13) T2.1.4 Raising/Lowering Performance (14) T2.1.5 Slots, Seals, and Sealing Surfaces (15) T2.1.6 Wheels, Rollers, Roller Chains, Bearings, and Bushings (16) Hydraulic Operators (Structural Integrity and Functional Operation): T2.3.1 Corrosion (23) T2.3.2 Anchoring (24) T2.3.3 Yielding, Fracture, Fatigue, and Fabrication Discontinuities (25) T2.3.4 Improper Field Repair and/or Modifications (26) T2.3.5 Actuation Performance (27) T2.3.6 Pistons (28) T2.3.7 Hydraulic Systems (29) T2.3.8 Electric Motors (30) T2.3.9 Electric Controls (31) Miscellaneous Tests and Conditions: T2.4 Miscellaneous Deficiencies (41) T2.5 Annunciation (42) T2.6 Maintenance Escalation (43) T2.7 Other Specialized Diagnostic Tests

Tier 2 Adjustments to Condition Index (Sum of individual Adjustments)

E11-40

Tier 2 Data Quality Indicator (Value must be 0, 4, 7, or 10)

Go to Part II.

E11-41

EMERGENCY CLOSURE SYSTEM TIER 2 CONDITION ASSESSMENT SUMMARY

Date: _________________________________ Location: _______________________________

Unit: ___________________ Type of Gate: __________________________________

Part I: Determine Adjustment to Tier 1 Emergency Closure System Condition Index.

Emergency Closure System – Gates with Electric Operators

Adjustment to Tier 1 No. Tier 2 Test (Table No.) Condition Index

Gates (Structural Integrity and Functional Operation): T2.1.1 Corrosion (11) T2.1.2 Yielding, Fracture, Fatigue, and Fabrication Discontinuities (12) T2.1.3 Improper Field Repair and/or Modifications (13) T2.1.4 Raising/Lowering Performance (14) T2.1.5 Slots, Seals, and Sealing Surfaces (15) T2.1.6 Wheels, Rollers, Roller Chains, Bearings, and Bushings (16) Electric Operators (Structural Integrity and Functional Operation): T2.3.1 Corrosion (23) T2.3.2 Anchoring (24) T2.3.3 Yielding, Fracture, Fatigue, and Fabrication Discontinuities (25) T2.3.4 Improper Field Repair and/or Modifications (26) T2.3.11 Actuation Performance (32) T2.3.12 Electric Controls (33) T2.3.13 Electric Motors (34) T2.3.14 Electric Brakes (35) T2.3.15 Wire Ropes and Chains (36) T2.3.16 Power Screws (37) T2.3.17 Drums and Sheaves (38) T2.3.18 Gearboxes, External Gearing, and Chain Sprockets (39) T2.3.19 Bearings and Bushings (40) Miscellaneous Tests and Conditions: T2.4 Miscellaneous Deficiencies (41) T2.5 Annunciation (42) T2.6 Maintenance Escalation (43) T2.7 Other Specialized Diagnostic Tests

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Tier 2 Adjustments to Condition Index (Sum of individual Adjustments)

Tier 2 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

Go to Part II.

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EMERGENCY CLOSURE SYSTEM TIER 2 CONDITION ASSESSMENT SUMMARY

Date: _________________________________ Location: _______________________________

Unit: ___________________ Type of Valve: __________________________________

Part I: Determine Adjustment to Tier 1 Emergency Closure System Condition Index.

Emergency Closure System – Valves with Hydraulic Operators

Adjustment to Tier 1 No. Tier 2 Test (Table No.) Condition Index

Valves (Structural Integrity and Functional Operation): T2.2.1 Corrosion (17) T2.2.2 Yielding, Fracture, Fatigue, and Fabrication Discontinuities (18) T2.2.3 Improper Field Repair and/or Modifications (19) T2.2.4 Actuation Performance (20) T2.2.5 Seals, Sealing Surfaces, and Packing (21) T2.2.6 Bearings and Bushings (22) Hydraulic Operators (Structural Integrity and Functional Operation): T2.3.1 Corrosion (23) T2.3.2 Anchoring (24) T2.3.3 Yielding, Fracture, Fatigue, and Fabrication Discontinuities (25) T2.3.4 Improper Field Repair and/or Modifications (26) T2.3.5 Actuation Performance (27) T2.3.6 Pistons (28) T2.3.7 Hydraulic Systems (29) T2.3.8 Electric Motors (30) T2.3.9 Electric Controls (31) Miscellaneous Tests and Conditions: T2.4 Miscellaneous Deficiencies (41) T2.5 Annunciation (42) T2.6 Maintenance Escalation (43) T2.7 Other Specialized Diagnostic Tests

Tier 2 Adjustments to Condition Index (Sum of individual Adjustments)

E11-44

Tier 2 Data Quality Indicator (Value must be 0, 4, 7, or 10)

Go to Part II.

E11-45

EMERGENCY CLOSURE SYSTEM TIER 2 CONDITION ASSESSMENT SUMMARY

Date: _________________________________ Location: _______________________________

Unit: ___________________ Type of Valve: __________________________________

Part I: Determine Adjustment to Tier 1 Emergency Closure System Condition Index.

Emergency Closure System – Valves with Electric Operators

Adjustment to Tier 1 No. Tier 2 Test (Table No.) Condition Index

Valves (Structural Integrity and Functional Operation): T2.2.1 Corrosion (17) T2.2.2 Yielding, Fracture, Fatigue, and Fabrication Discontinuities (18) T2.2.3 Improper Field Repair and/or Modifications (19) T2.2.4 Actuation Performance (20) T2.2.5 Seals, Sealing Surfaces, and Packing (21) T2.2.6 Bearings and Bushings (22) Electric Operators (Structural Integrity and Functional Operation): T2.3.1 Corrosion (23) T2.3.2 Anchoring (24) T2.3.3 Yielding, Fracture, Fatigue, and Fabrication Discontinuities (25) T2.3.4 Improper Field Repair and/or Modifications (26) T2.3.11 Actuation Performance (32) T2.3.12 Electric Controls (33) T2.3.13 Electric Motors (34) T2.3.14 Electric Brakes (35) T2.3.15 Wire Ropes and Chains (36) T2.3.16 Power Screws (37) T2.3.17 Drums and Sheaves (38) T2.3.18 Gearboxes, External Gearing, and Chain Sprockets (39) T2.3.19 Bearings and Bushings (40) Miscellaneous Tests and Conditions: T2.4 Miscellaneous Deficiencies (41) T2.5 Annunciation (42) T2.6 Maintenance Escalation (43) T2.7 Other Specialized Diagnostic Tests

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Tier 2 Adjustments to Condition Index (Sum of individual Adjustments)

Tier 2 Data Quality Indicator

(Value must be 0, 4, 7, or 10)

Go to Part II.

E11-47

Part II: Calculate the Net Emergency Closure System Condition Index To calculate the Net Emergency Closure System Condition Index (Value should be between 0 and 10), subtract the Tier 2 Adjustments from the Tier 1 Emergency Closure System Condition Index: Tier 1 Emergency Closure System Condition Index __________ minus Tier 2 Emergency Closure System Adjustments __________ = __________ Net Emergency Closure System Condition Index Evaluator: __________________________ Technical Review: __________________________ Management Review: _________________ Copies to: _________________________________

(Attach supporting documentation.)

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Appendix A: Structural Deficiency Pictures

Root opening Incomplete penetration in CJP weld – can usually only be identified by non destructive testing methods

Notch from burning machine – example of fabrication or improper field modification

E11-49

Porosity

Crack at flange diaphragm plate

E11-50

Mi i fill t

Missing fillet weld

Improper profile

Cavitation & corrosion on weld

E11-51

Undercut

from corrosion

Substantial loss of weld area from corrosion

Moderate loss of weld area from corrosion

Weld performed by non-qualified welder