Epri Template For Maintenance Strategy.pdf

                     

EPRI TEMPLATE 

Circuit Cards - Bailey 7000 Series Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe Mild

X X

X

5

6

7

8

X

X

X

X

X X

X X

X X

X

2

X

X

X

X

X

Time Directed Task

Failure Codes

Comments

Perform Functional Test / Calibration Check

CD LC OC OP SH

No Comments

2Y

N/R

Clean Edge Connectors,Perform Visual Inspection

AR

AR

CN LC OP SC SH

Inspect card components for evidence of overheating, damage etc. (replace as necessary) AR (as required) perform anytime a card is removed from its slot,and to new card prior to installation. Care should be taken not to remove the coatings, or finish, on the card edges and connectors and always use approved methods and cleaning agents per manufacture

Replace Type 721 Circuit Cards

10Y

N/R

AG

Cards are obsolete and will require refurbishment.

Replace Type 722,723,and 754 circuit cards.

12Y

N/R

AG

Cards are obsolete and will require refurbishment.

Replace Type 755 circuit cards.

15Y

N/R

AG

Cards are obsolete and will require refurbishment.

Replace Type 701,704,and 750 circuit cards.

18Y

N/R

AG

Cards are obsolete and will require refurbishment.

Replace Type 711,724,740,744,745,and 752 (2 and 4 input) circuit cards.

20Y

N/R

AG

Cards are obsolete and will require refurbishment.

Replace Type 714,720,746,751,and 766 Cards are obsolete and will require 25Y N/R AG circuit cards. refurbishment. Bailey 7000 series cards are used numerous control systems throughout the Exelon fleet. NOTE 1: In the absence of data or information to justify extending or reducing the time based replacement of critical circuit cards, the replacement schedule has been established based on circuit card review and expert opinion that the majority of circuit card failures occur after the listed periodicity. NOTE 2: All cards shall be burned-in a minimum of 100 hours before being installed in a critical application (includes new, refurbished or repaired circuit cards). The burn in is a one time event unless the card has been modified since the last time it was burned-in. NOTE 3: Type 766 cards are populated exclusively by wire-wound resistors. Replacment is not recommended due to the extremely low probability of failure. Note 4: Failure data from Equipment Parts Reliability Data, EPRD-97 Note 5: Used the EPRD summary failure rate instead of the rate for a specific component type Note 6: Component failure rates selected were based on largest sample size available. Where the sample size deviation between entries was insignificant, the roll-up summary failure rate at the heading of the column was used. Note 7: The time based replacement schedule has been established considering all of the available information at the time. This information includes a Mean Time To Failure (MTTF) analysis as well as any available historical or operating experience. For a particular card or cards, the replacement schedule was established at XX years based on a MTTF value of XX years. The MTTF was rounded up to the next available even year to coincide with refueling frequencies and as a result of the over-conservatism associated with the way in which the MTTF is calculated. The MTTF calculations performed are known to be overly conservative due to the methodology used that assumes that any component failure results in card failure that would result in reactor SCRAM or transient. Note 10: Unless justified additionally, a maximum changeout frequency of 20 years has been established for all cards based on the concern that additional failures mechanisms affecting the cards may come into play after 20 years that were not considered in the MTTF calculation. Click for Calc Data This template is the controlled revision. Please refer to MA-AA-716-210 & MA-AA-716-210-1001 for additional guidance. SME Summary Exelon PCM Template SME Review and Approval for Circuit Cards The purpose of this review is to ensure that the scope and frequency of tasks prescribed by the PCM templates for Exelon wide circuit cards (prescribed in MA-AA-716-210-1001) is appropriate. The SME approval of the template means that they are confident that a site will minimize unexpected component failures (CM-U) and maximize component reliability if the site implements the template as prescribed. The Circuit Card PCM templates were created through the PMCEI process piloted in 2001. Consequently, all the circuit card PCM templates were evaluated and created using a standard process. Therefore, this document is applicable to all of the circuit card templates and will be the single review issued for those templates. The PMCEI process reviewed available failure history data for the circuit cards covered in the templates to determine if the PCM templates address the failure modes identified. The data included industry OPEX, EPRI, NMAC, and various Owner’s Group recommendations, where appropriate.

1

The PMCEI process was designed to ensure that the templates cover all of the anticipated and observed failure modes. Additionally, condition monitoring tasks identify the failure in its early stages, and that the time directed tasks contained in the PCM template prevents these failures from occurring. The process also reviewed available vendor recommendations for the circuit cards addressed by the templates. Vendor recommendations generally do not exist for circuit cards, the prevailing theory was that no actions were needed. In cases where vendor recommendations did exist, the PCM templates either meet or exceed the recommendations. In all cases, the PCM actions are more conservative in Scope and Frequency than the vendor recommendations. There are no NEIL insurance PM / inspection requirements included in the templates. The condition monitoring tasks involve previously established calibrations and surveillances and, therefore, clearly state what technology is to by used and what at what frequency the condition is to be monitored. Sufficient detail is specified for condition based monitoring. There are no critical subcomponents that need to be or are covered by a separate PCM template. Basis documents are included with each PCM file along with any calculations that were performed that help to form the basis of the PCM template. This completes the review of the PCM templates for Circuit Cards. Boundary Definition The boundary of an I&C component used for the purpose of this database, is defined to include only the I&C components themselves, and not any monitored or peripheral components or equipment. Basis For Template Tasks Perform Functional Test / Calibration Check: BASIS DOCUMENT This basis document identifies the thought process and background that resulted in the creation of the attached PCM template. This template was created as a result of the Plant Material Condition Excellence Initiative (PMCEI). The PMCEI project strove to identify every circuit card that could, by itself, cause any one of the following: Reactor SCRAM, Reactor or Generator transient, Generator derating, or entry in a 48 hour or less LCO leading to shutdown. A PCM template was then created for each circuit card identified by the PMCEI project. A primary focus of the PCM template creation for these circuit cards was to identify an expected lifetime for each card. A lifetime for a particular card was calculated by identifying all the subcomponents on that circuit card and then determining the individual failure rates for the subcomponents. The subcomponent failure rates were taken from published data bases. A overall circuit card failure rate was then determined based on the subcomponent failure rates. The calculations for each card are attached as separate worksheets. In some instances schematics or bill of materials were not available, so the lifetime of the circuit card was determined by comparing the function of the card to similar circuit cards. If no similar card was found, a maximum lifetime of 20 years was established as a reasonable assurance of reliability for critical cards. Many of the calculations result in lifetimes that exceed 50 and even a 100 years because of small subcomponent densities. However, it is recognized that the calculations only consider subcomponent failures and neglect corrosion, connectors, and other failure mechanisms. Consequently, after considerable review the expert panel determine that a reasonable expectation for the maximum life of any circuit card is 35 years. And, that the maximum replacement frequency for any critical card should be 30 years. The references listed at the end of this basis document were utilized heavily in the creation of this template. This 30 year critical card replacement is a testament to the unknowns and uncertainties impacting circuit card reliability after such a long operating history. The 30 year maximum attempts to limit the vulnerability of the plant to circuit card failures from the long term effects of corrosion, vibration, trace degradation, and all of a circuit card's failure mechanisms. Therefore, any circuit card with a calculation result that exceeded 30 years, was assigned a 30 year replacement frequency. This task is set to coincide with the normal refueling interval. The task is established to ensure that the critical cards are checked prior to unit start-up with the intent to identify and remove any cards that may fail during the operating cycle. It is recognized that simple board calibrations have little potential for predictive maintenance but until a predictive testing methodology is implemented this is the best that can be done. REFERENCES 1. EPRD-97, Electronic Parts Reliability Data, A Compendium of Commercial and Military Device Field Failure Rates, Volume 1 & 2, DOD Reliability Analysis Center, November 1996. 2. EPRI NP-1558, A Review of Equipment Aging Theory and Technology, Franklin Research Center, September 1980. 3. Reliability of Electronic Components, T.I. Bajenescu and M.I. Bazu, SpringerVerlag 1999. 4. IEEE Standard 500-1984, IEEE Guide to the Collection and Presentation of Electrical, Electronic and Sensing Component Reliability, 1984. 5. MIL-HDBK-217B, Reliability Prediction of Electronic Equipment, DOD September 1974. 6. MIL-HDBK-217B Supplement, Reliability Prediction of Electronic Equipment, DOD September 1976. 7. GE MARK I EHC system circuit card schematics. Clean Edge Connectors,Perform Visual Inspection: BASIS DOCUMENT This basis document identifies the thought process and background that resulted in the creation of the attached PCM template. This template was created as a result of the Plant Material Condition Excellence Initiative (PMCEI). The PMCEI project strove to identify every circuit card that could, by itself, cause any one of the following: Reactor SCRAM, Reactor or Generator transient, Generator derating, or entry in a 48 hour or less LCO leading to shutdown. A PCM template was then created for each circuit card identified by the PMCEI project. A primary focus of the PCM template creation for these circuit cards was to identify an expected lifetime for each card. A lifetime for a particular card was calculated by identifying all the subcomponents on that circuit card and then determining the individual failure rates for the subcomponents. The subcomponent failure rates were taken from published data bases. A overall circuit card failure rate was then determined based on the subcomponent failure rates. The calculations for each card are attached as separate worksheets. In some instances schematics or bill of materials were not available, so the lifetime of the circuit card was determined by comparing the function of the card to similar circuit cards. If no similar card was found, a maximum lifetime of 20 years was established as a reasonable assurance of reliability for critical cards. Many of the calculations result in lifetimes that exceed 50 and even a 100 years because of small subcomponent densities. However, it is recognized that the calculations only consider subcomponent failures and neglect corrosion, connectors, and other failure mechanisms. Consequently, after considerable review the expert panel determine that a reasonable expectation for the maximum life of any circuit card is 35 years. And, that the maximum replacement frequency for any critical card should be 30 years. The references listed at the end of this basis document were utilized heavily in the creation of this template. This 30 year critical card replacement is a testament to the unknowns and uncertainties impacting circuit card reliability after such a long operating history. The 30 year maximum attempts to limit the vulnerability of the plant to circuit card failures from the long term effects of corrosion, vibration, trace degradation, and all of a circuit card's failure mechanisms. Therefore, any circuit card with a calculation result that exceeded 30 years, was assigned a 30 year replacement frequency.

2

This task is very important, a rigorous visual inspection often catches potential failures more than testing. Additionally, connector anomalies account for the majority of circuit card related events. REFERENCES 1. EPRD-97, Electronic Parts Reliability Data, A Compendium of Commercial and Military Device Field Failure Rates, Volume 1 & 2, DOD Reliability Analysis Center, November 1996. 2. EPRI NP-1558, A Review of Equipment Aging Theory and Technology, Franklin Research Center, September 1980. 3. Reliability of Electronic Components, T.I. Bajenescu and M.I. Bazu, Springer-Verlag 1999. 4. IEEE Standard 500-1984, IEEE Guide to the Collection and Presentation of Electrical, Electronic and Sensing Component Reliability, 1984. 5. MIL-HDBK-217B, Reliability Prediction of Electronic Equipment, DOD September 1974. 6. MIL-HDBK-217B Supplement, Reliability Prediction of Electronic Equipment, DOD September 1976. 7. GE MARK I EHC system circuit card schematics. Replace Type 721 Circuit Cards: BASIS DOCUMENT This basis document identifies the thought process and background that resulted in the creation of the attached PCM template. This template was created as a result of the Plant Material Condition Excellence Initiative (PMCEI). The PMCEI project strove to identify every circuit card that could, by itself, cause any one of the following: Reactor SCRAM, Reactor or Generator transient, Generator derating, or entry in a 48 hour or less LCO leading to shutdown. A PCM template was then created for each circuit card identified by the PMCEI project. A primary focus of the PCM template creation for these circuit cards was to identify an expected lifetime for each card. A lifetime for a particular card was calculated by identifying all the subcomponents on that circuit card and then determining the individual failure rates for the subcomponents. The subcomponent failure rates were taken from published data bases. A overall circuit card failure rate was then determined based on the subcomponent failure rates. The calculations for each card are attached as separate worksheets. In some instances schematics or bill of materials were not available, so the lifetime of the circuit card was determined by comparing the function of the card to similar circuit cards. If no similar card was found, a maximum lifetime of 20 years was established as a reasonable assurance of reliability for critical cards. Many of the calculations result in lifetimes that exceed 50 and even a 100 years because of small subcomponent densities. However, it is recognized that the calculations only consider subcomponent failures and neglect corrosion, connectors, and other failure mechanisms. Consequently, after considerable review the expert panel determine that a reasonable expectation for the maximum life of any circuit card is 35 years. And, that the maximum replacement frequency for any critical card should be 30 years. The references listed at the end of this basis document were utilized heavily in the creation of this template. This 30 year critical card replacement is a testament to the unknowns and uncertainties impacting circuit card reliability after such a long operating history. The 30 year maximum attempts to limit the vulnerability of the plant to circuit card failures from the long term effects of corrosion, vibration, trace degradation, and all of a circuit card's failure mechanisms. Therefore, any circuit card with a calculation result that exceeded 30 years, was assigned a 30 year replacement frequency. The replacement frequency is determined based on the lifetime calculations and expert panel determinations. REFERENCES 1. EPRD-97, Electronic Parts Reliability Data, A Compendium of Commercial and Military Device Field Failure Rates, Volume 1 & 2, DOD Reliability Analysis Center, November 1996. 2. EPRI NP-1558, A Review of Equipment Aging Theory and Technology, Franklin Research Center, September 1980. 3. Reliability of Electronic Components, T.I. Bajenescu and M.I. Bazu, Springer-Verlag 1999. 4. IEEE Standard 500-1984, IEEE Guide to the Collection and Presentation of Electrical, Electronic and Sensing Component Reliability, 1984. 5. MIL-HDBK-217B, Reliability Prediction of Electronic Equipment, DOD September 1974. 6. MIL-HDBK-217B Supplement, Reliability Prediction of Electronic Equipment, DOD September 1976. 7. GE MARK I EHC system circuit card schematics. Replace Type 722,723,and 754 circuit cards.: BASIS DOCUMENT This basis document identifies the thought process and background that resulted in the creation of the attached PCM template. This template was created as a result of the Plant Material Condition Excellence Initiative (PMCEI). The PMCEI project strove to identify every circuit card that could, by itself, cause any one of the following: Reactor SCRAM, Reactor or Generator transient, Generator derating, or entry in a 48 hour or less LCO leading to shutdown. A PCM template was then created for each circuit card identified by the PMCEI project. A primary focus of the PCM template creation for these circuit cards was to identify an expected lifetime for each card. A lifetime for a particular card was calculated by identifying all the subcomponents on that circuit card and then determining the individual failure rates for the subcomponents. The subcomponent failure rates were taken from published data bases. A overall circuit card failure rate was then determined based on the subcomponent failure rates. The calculations for each card are attached as separate worksheets. In some instances schematics or bill of materials were not available, so the lifetime of the circuit card was determined by comparing the function of the card to similar circuit cards. If no similar card was found, a maximum lifetime of 20 years was established as a reasonable assurance of reliability for critical cards. Many of the calculations result in lifetimes that exceed 50 and even a 100 years because of small subcomponent densities. However, it is recognized that the calculations only consider subcomponent failures and neglect corrosion, connectors, and other failure mechanisms. Consequently, after considerable review the expert panel determine that a reasonable expectation for the maximum life of any circuit card is 35 years. And, that the maximum replacement frequency for any critical card should be 30 years. The references listed at the end of this basis document were utilized heavily in the creation of this template. This 30 year critical card replacement is a testament to the unknowns and uncertainties impacting circuit card reliability after such a long operating history. The 30 year maximum attempts to limit the vulnerability of the plant to circuit card failures from the long term effects of corrosion, vibration, trace degradation, and all of a circuit card's failure mechanisms. Therefore, any circuit card with a calculation result that exceeded 30 years, was assigned a 30 year replacement frequency. The replacement frequency is determined based on the lifetime calculations and expert panel determinations. REFERENCES 1. EPRD-97, Electronic Parts Reliability Data, A Compendium of Commercial and Military Device Field Failure Rates, Volume 1 & 2, DOD Reliability Analysis Center, November 1996. 2. EPRI NP-1558, A Review of Equipment Aging Theory and Technology, Franklin Research Center, September 1980. 3. Reliability of Electronic Components, T.I. Bajenescu and M.I. Bazu, Springer-Verlag 1999. 4. IEEE Standard 500-1984, IEEE Guide to the Collection and Presentation of Electrical, Electronic and Sensing Component Reliability, 1984. 5. MIL-HDBK-217B, Reliability Prediction of Electronic Equipment, DOD September 1974. 6. MIL-HDBK-217B Supplement, Reliability Prediction of Electronic Equipment, DOD September 1976. 7. GE MARK I EHC system circuit card schematics. Replace Type 755 circuit cards.: BASIS DOCUMENT This basis document identifies the thought process and background that resulted in the creation of the attached PCM template. This template was created as a result of the Plant Material Condition Excellence Initiative (PMCEI). The PMCEI project strove to identify every circuit card that could, by itself, cause any one of the following: Reactor SCRAM, Reactor or Generator transient, Generator derating, or entry in a 48 hour or less LCO leading to shutdown. A PCM template was then created for each circuit card identified by the PMCEI project. A primary focus of the PCM template creation for these circuit cards was to identify an expected lifetime for each card. A lifetime for a particular card was calculated by identifying all the subcomponents on that circuit card and then determining the individual failure rates for the subcomponents. The subcomponent failure rates were taken from published data bases. A overall circuit card failure rate was then determined based on the subcomponent failure rates. The calculations for each card are attached as separate worksheets. In some instances schematics or bill of materials were not available, so the lifetime of the circuit card was determined by comparing the function of the card to similar circuit cards. If no similar card was found, a maximum lifetime of 20 years was established as a reasonable assurance of reliability for critical cards. Many of the calculations result in lifetimes

3

that exceed 50 and even a 100 years because of small subcomponent densities. However, it is recognized that the calculations only consider subcomponent failures and neglect corrosion, connectors, and other failure mechanisms. Consequently, after considerable review the expert panel determine that a reasonable expectation for the maximum life of any circuit card is 35 years. And, that the maximum replacement frequency for any critical card should be 30 years. The references listed at the end of this basis document were utilized heavily in the creation of this template. This 30 year critical card replacement is a testament to the unknowns and uncertainties impacting circuit card reliability after such a long operating history. The 30 year maximum attempts to limit the vulnerability of the plant to circuit card failures from the long term effects of corrosion, vibration, trace degradation, and all of a circuit card's failure mechanisms. Therefore, any circuit card with a calculation result that exceeded 30 years, was assigned a 30 year replacement frequency. The replacement frequency is determined based on the lifetime calculations and expert panel determinations. REFERENCES 1. EPRD-97, Electronic Parts Reliability Data, A Compendium of Commercial and Military Device Field Failure Rates, Volume 1 & 2, DOD Reliability Analysis Center, November 1996. 2. EPRI NP-1558, A Review of Equipment Aging Theory and Technology, Franklin Research Center, September 1980. 3. Reliability of Electronic Components, T.I. Bajenescu and M.I. Bazu, Springer-Verlag 1999. 4. IEEE Standard 500-1984, IEEE Guide to the Collection and Presentation of Electrical, Electronic and Sensing Component Reliability, 1984. 5. MIL-HDBK-217B, Reliability Prediction of Electronic Equipment, DOD September 1974. 6. MIL-HDBK-217B Supplement, Reliability Prediction of Electronic Equipment, DOD September 1976. 7. GE MARK I EHC system circuit card schematics. Replace Type 701,704,and 750 circuit cards.: BASIS DOCUMENT This basis document identifies the thought process and background that resulted in the creation of the attached PCM template. This template was created as a result of the Plant Material Condition Excellence Initiative (PMCEI). The PMCEI project strove to identify every circuit card that could, by itself, cause any one of the following: Reactor SCRAM, Reactor or Generator transient, Generator derating, or entry in a 48 hour or less LCO leading to shutdown. A PCM template was then created for each circuit card identified by the PMCEI project. A primary focus of the PCM template creation for these circuit cards was to identify an expected lifetime for each card. A lifetime for a particular card was calculated by identifying all the subcomponents on that circuit card and then determining the individual failure rates for the subcomponents. The subcomponent failure rates were taken from published data bases. A overall circuit card failure rate was then determined based on the subcomponent failure rates. The calculations for each card are attached as separate worksheets. In some instances schematics or bill of materials were not available, so the lifetime of the circuit card was determined by comparing the function of the card to similar circuit cards. If no similar card was found, a maximum lifetime of 20 years was established as a reasonable assurance of reliability for critical cards. Many of the calculations result in lifetimes that exceed 50 and even a 100 years because of small subcomponent densities. However, it is recognized that the calculations only consider subcomponent failures and neglect corrosion, connectors, and other failure mechanisms. Consequently, after considerable review the expert panel determine that a reasonable expectation for the maximum life of any circuit card is 35 years. And, that the maximum replacement frequency for any critical card should be 30 years. The references listed at the end of this basis document were utilized heavily in the creation of this template. This 30 year critical card replacement is a testament to the unknowns and uncertainties impacting circuit card reliability after such a long operating history. The 30 year maximum attempts to limit the vulnerability of the plant to circuit card failures from the long term effects of corrosion, vibration, trace degradation, and all of a circuit card's failure mechanisms. Therefore, any circuit card with a calculation result that exceeded 30 years, was assigned a 30 year replacement frequency. The replacement frequency is determined based on the lifetime calculations and expert panel determinations. REFERENCES 1. EPRD-97, Electronic Parts Reliability Data, A Compendium of Commercial and Military Device Field Failure Rates, Volume 1 & 2, DOD Reliability Analysis Center, November 1996. 2. EPRI NP-1558, A Review of Equipment Aging Theory and Technology, Franklin Research Center, September 1980. 3. Reliability of Electronic Components, T.I. Bajenescu and M.I. Bazu, Springer-Verlag 1999. 4. IEEE Standard 500-1984, IEEE Guide to the Collection and Presentation of Electrical, Electronic and Sensing Component Reliability, 1984. 5. MIL-HDBK-217B, Reliability Prediction of Electronic Equipment, DOD September 1974. 6. MIL-HDBK-217B Supplement, Reliability Prediction of Electronic Equipment, DOD September 1976. 7. GE MARK I EHC system circuit card schematics. Replace Type 711,724,740,744,745,and 752 (2 and 4 input) circuit cards.: BASIS DOCUMENT This basis document identifies the thought process and background that resulted in the creation of the attached PCM template. This template was created as a result of the Plant Material Condition Excellence Initiative (PMCEI). The PMCEI project strove to identify every circuit card that could, by itself, cause any one of the following: Reactor SCRAM, Reactor or Generator transient, Generator derating, or entry in a 48 hour or less LCO leading to shutdown. A PCM template was then created for each circuit card identified by the PMCEI project. A primary focus of the PCM template creation for these circuit cards was to identify an expected lifetime for each card. A lifetime for a particular card was calculated by identifying all the subcomponents on that circuit card and then determining the individual failure rates for the subcomponents. The subcomponent failure rates were taken from published data bases. A overall circuit card failure rate was then determined based on the subcomponent failure rates. The calculations for each card are attached as separate worksheets. In some instances schematics or bill of materials were not available, so the lifetime of the circuit card was determined by comparing the function of the card to similar circuit cards. If no similar card was found, a maximum lifetime of 20 years was established as a reasonable assurance of reliability for critical cards. Many of the calculations result in lifetimes that exceed 50 and even a 100 years because of small subcomponent densities. However, it is recognized that the calculations only consider subcomponent failures and neglect corrosion, connectors, and other failure mechanisms. Consequently, after considerable review the expert panel determine that a reasonable expectation for the maximum life of any circuit card is 35 years. And, that the maximum replacement frequency for any critical card should be 30 years. The references listed at the end of this basis document were utilized heavily in the creation of this template. This 30 year critical card replacement is a testament to the unknowns and uncertainties impacting circuit card reliability after such a long operating history. The 30 year maximum attempts to limit the vulnerability of the plant to circuit card failures from the long term effects of corrosion, vibration, trace degradation, and all of a circuit card's failure mechanisms. Therefore, any circuit card with a calculation result that exceeded 30 years, was assigned a 30 year replacement frequency. The replacement frequency is determined based on the lifetime calculations and expert panel determinations. REFERENCES 1. EPRD-97, Electronic Parts Reliability Data, A Compendium of Commercial and Military Device Field Failure Rates, Volume 1 & 2, DOD Reliability Analysis Center, November 1996. 2. EPRI NP-1558, A Review of Equipment Aging Theory and Technology, Franklin Research Center, September 1980. 3. Reliability of Electronic Components, T.I. Bajenescu and M.I. Bazu, SpringerVerlag 1999. 4. IEEE Standard 500-1984, IEEE Guide to the Collection and Presentation of Electrical, Electronic and Sensing Component Reliability, 1984. 5. MIL-HDBK-217B, Reliability Prediction of Electronic Equipment, DOD September 1974. 6. MIL-HDBK-217B Supplement, Reliability Prediction of Electronic Equipment, DOD September 1976. 7. GE MARK I EHC system circuit card schematics. Replace Type 714,720,746,751,and 766 circuit cards.: BASIS DOCUMENT This basis document identifies the thought process and background that resulted in the creation of the attached PCM template. This template was created as a result of the Plant Material Condition Excellence Initiative (PMCEI). The PMCEI project strove to identify every circuit card that could, by itself, cause any one of the following: Reactor SCRAM, Reactor or Generator transient, Generator derating, or entry in a 48 hour or less LCO leading to shutdown. A

4

PCM template was then created for each circuit card identified by the PMCEI project. A primary focus of the PCM template creation for these circuit cards was to identify an expected lifetime for each card. A lifetime for a particular card was calculated by identifying all the subcomponents on that circuit card and then determining the individual failure rates for the subcomponents. The subcomponent failure rates were taken from published data bases. A overall circuit card failure rate was then determined based on the subcomponent failure rates. The calculations for each card are attached as separate worksheets. In some instances schematics or bill of materials were not available, so the lifetime of the circuit card was determined by comparing the function of the card to similar circuit cards. If no similar card was found, a maximum lifetime of 20 years was established as a reasonable assurance of reliability for critical cards. Many of the calculations result in lifetimes that exceed 50 and even a 100 years because of small subcomponent densities. However, it is recognized that the calculations only consider subcomponent failures and neglect corrosion, connectors, and other failure mechanisms. Consequently, after considerable review the expert panel determine that a reasonable expectation for the maximum life of any circuit card is 35 years. And, that the maximum replacement frequency for any critical card should be 30 years. The references listed at the end of this basis document were utilized heavily in the creation of this template. This 30 year critical card replacement is a testament to the unknowns and uncertainties impacting circuit card reliability after such a long operating history. The 30 year maximum attempts to limit the vulnerability of the plant to circuit card failures from the long term effects of corrosion, vibration, trace degradation, and all of a circuit card's failure mechanisms. Therefore, any circuit card with a calculation result that exceeded 30 years, was assigned a 30 year replacement frequency. The replacement frequency is determined based on the lifetime calculations and expert panel determinations. REFERENCES 1. EPRD-97, Electronic Parts Reliability Data, A Compendium of Commercial and Military Device Field Failure Rates, Volume 1 & 2, DOD Reliability Analysis Center, November 1996. 2. EPRI NP-1558, A Review of Equipment Aging Theory and Technology, Franklin Research Center, September 1980. 3. Reliability of Electronic Components, T.I. Bajenescu and M.I. Bazu, Springer-Verlag 1999. 4. IEEE Standard 500-1984, IEEE Guide to the Collection and Presentation of Electrical, Electronic and Sensing Component Reliability, 1984. 5. MIL-HDBK-217B, Reliability Prediction of Electronic Equipment, DOD September 1974. 6. MIL-HDBK-217B Supplement, Reliability Prediction of Electronic Equipment, DOD September 1976. 7. GE MARK I EHC system circuit card schematics.

5

Circuit Cards -GE Main Generator and Main Turbine Systems Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe Mild

X X

X

5

6

7

8

X

X

X

X

X X

X

X X

X

X X

X

X

X

X

Time Directed Task

Failure Codes

Comments

Perform Functional Test, / Calibration Check

CD LC OC OP SH

No Comments

2Y

N/R

Clean Edge Connectors,Perform Visual Inspection

AR

AR

CN CO DA LC OP SC SH

Inspect card components for evidence of overheating, damage etc. (replace as necessary) AR (as required) perform anytime a card is removed from its slot,and to new card prior to installation. Care should be taken not to remove the coatings, or finish, on the card edges and connectors and always use approved methods and cleaning agents per manufacture

Replace or Refurbish 44C300221G3, 44C300224G1, and 44C300339G1/G5

12Y

N/R

AG

No Comments

Replace or Refurbish 3S7932MA2376A1/A4 and 44C300222G1

20Y

N/R

AG

No Comments

Replace or Refurbish 1589K38G

25Y

N/R

AG

No Comments

Replace or Refurbish 44C300245G3, 1589K29G700, 1589K42G700, 30Y N/R AG No Comments 3S7700PB103A, 8080K42, and 8080K44 The BWR stations use a number of GE circuit cards in the Main Generator and Main Turbine Systems. These cards generally provide generator and turbine protection. Note 1: In the absence of data or information to justify extending or reducing the time based replacement of critical circuit cards, the replacement schedule has been established based on circuit card review and expert opinion that the majority of circuit card failures occur after the listed periodicity. Note 2: All cards shall be burned-in a minimum of 100 hours before being installed in a critical application (includes new,refurbished or repaired circuit cards). The burn-in is a one time event unless the card has been modified since the last time it was burned-in, either in a bench test rack or in the system. Note 3: Failure data from Equipment Parts Reliability Data, EPRD-97 Note 4: Used the EPRD summary failure rate instead of the the rate for a specific component type Note 5: Assumed 1N3253, 1N3254 were rectifer diodes Note 6: Used summary data for NPN signal transistor. Unable to identify TN103 type. Note 7: Ref. IEEE STD 500-194, pg. 162 Note 8: The time based replacement schedule has been established considering all of the available information at the time. This information includes a Mean Time To Failure (MTTF) analysis as well as any available historical or operating experience. For a particular card or cards, the replacement schedule was established at XX years based on a MTTF value of XX years. The MTTF was rounded up to the next available even year to coincide with refueling frequencies and as a result of the over-conservatism associated with the way in which the MTTF is calculated. The MTTF calculations performed are known to be overly conservative due to the methodology used that assumes that any component failure results in card failure that would result in reactor SCRAM or transient. Unless justified additionally, a maximum changeout frequency of 30 years has been established for all cards based on the concern that additional failures mechanisms affecting the cards may come into play after 30 years that were not considered in the MTTF calculation. Click for Calc Data This template is the controlled revision. Please refer to MA-AA-716-210 & MA-AA-716-210-1001 for additional guidance. SME Summary PCM Template SME Review and Approval for Circuit Cards The purpose of this review is to ensure that the scope and frequency of tasks prescribed by the PCM templates for wide circuit cards (prescribed in MA-AA-716-210-1001) is appropriate. The SME approval of the template means that they are confident that a site will minimize unexpected component failures (CM-U) and maximize component reliability if the site implements the template as prescribed. The Circuit Card PCM templates were created through the PMCEI process piloted in 2001. Consequently, all the circuit card PCM templates were evaluated and created using a standard process. Therefore, this document is applicable to all of the circuit card tUtiity emplates and will be the single review issued for those templates. The PMCEI process reviewed available failure history data for the circuit cards covered in the templates to determine if the PCM templates address the failure modes identified. The data included industry OPEX, EPRI, NMAC, and various Owner’s Group recommendations, where appropriate. The PMCEI process was designed to ensure that the templates cover all of the anticipated and observed failure modes. Additionally, condition monitoring tasks identify the failure in its early stages, and that the time directed tasks contained in the PCM template prevents these failures from occurring.

6

The process also reviewed available vendor recommendations for the circuit cards addressed by the templates. Vendor recommendations generally do not exist for circuit cards, the prevailing theory was that no actions were needed. In cases where vendor recommendations did exist, the PCM templates either meet or exceed the recommendations. In all cases, the PCM actions are more conservative in Scope and Frequency than the vendor recommendations. There are no NEIL insurance PM / inspection requirements included in the templates. The condition monitoring tasks involve previously established calibrations and surveillances and, therefore, clearly state what technology is to by used and what at what frequency the condition is to be monitored. Sufficient detail is specified for condition based monitoring. There are no critical subcomponents that need to be or are covered by a separate PCM template. Basis documents are included with each PCM file along with any calculations that were performed that help to form the basis of the PCM template. This completes the review of the PCM templates for Circuit Cards. Boundary Definition The boundary of an I&C component used for the purpose of this database, is defined to include only the I&C components themselves, and not any monitored or peripheral components or equipment. Basis For Template Tasks Perform Functional Test, / Calibration Check: BASIS DOCUMENT This basis document identifies the thought process and background that resulted in the creation of the attached PCM template. This template was created as a result of the Plant Material Condition Excellence Initiative (PMCEI). The PMCEI project strove to identify every circuit card that could, by itself, cause any one of the following: Reactor SCRAM, Reactor or Generator transient, Generator derating, or entry in a 48 hour or less LCO leading to shutdown. A PCM template was then created for each circuit card identified by the PMCEI project. A primary focus of the PCM template creation for these circuit cards was to identify an expected lifetime for each card. A lifetime for a particular card was calculated by identifying all the subcomponents on that circuit card and then determining the individual failure rates for the subcomponents. The subcomponent failure rates were taken from published data bases. A overall circuit card failure rate was then determined based on the subcomponent failure rates. The calculations for each card are attached as separate worksheets. In some instances schematics or bill of materials were not available, so the lifetime of the circuit card was determined by comparing the function of the card to similar circuit cards. If no similar card was found, a maximum lifetime of 20 years was established as a reasonable assurance of reliability for critical cards. Many of the calculations result in lifetimes that exceed 50 and even a 100 years because of small subcomponent densities. However, it is recognized that the calculations only consider subcomponent failures and neglect corrosion, connectors, and other failure mechanisms. Consequently, after considerable review the expert panel determine that a reasonable expectation for the maximum life of any circuit card is 35 years. And, that the maximum replacement frequency for any critical card should be 30 years. The references listed at the end of this basis document were utilized heavily in the creation of this template. This 30 year critical card replacement is a testament to the unknowns and uncertainties impacting circuit card reliability after such a long operating history. The 30 year maximum attempts to limit the vulnerability of the plant to circuit card failures from the long term effects of corrosion, vibration, trace degradation, and all of a circuit card's failure mechanisms. Therefore, any circuit card with a calculation result that exceeded 30 years, was assigned a 30 year replacement frequency. This task is set to coincide with the normal refueling interval. The task is established to ensure that the critical cards are checked prior to unit start-up with the intent to identify and remove any cards that may fail during the operating cycle. It is recognized that simple board calibrations have little potential for predictive maintenance but until a predictive testing methodology is implemented this is the best that can be done. REFERENCES 1. EPRD-97, Electronic Parts Reliability Data, A Compendium of Commercial and Military Device Field Failure Rates, Volume 1 & 2, DOD Reliability Analysis Center, November 1996. 2. EPRI NP-1558, A Review of Equipment Aging Theory and Technology, Franklin Research Center, September 1980. 3. Reliability of Electronic Components, T.I. Bajenescu and M.I. Bazu, SpringerVerlag 1999. 4. IEEE Standard 500-1984, IEEE Guide to the Collection and Presentation of Electrical, Electronic and Sensing Component Reliability, 1984. 5. MIL-HDBK-217B, Reliability Prediction of Electronic Equipment, DOD September 1974. 6. MIL-HDBK-217B Supplement, Reliability Prediction of Electronic Equipment, DOD September 1976. 7. GE MARK I EHC system circuit card schematics. 5. MIL-HDBK217B, Reliability Prediction of Electronic Equipment, DOD September 1974. 6. MIL-HDBK-217B Supplement, Reliability Prediction of Electronic Equipment, DOD September 1976. 7. GE MARK I EHC system circuit card schematics. Clean Edge Connectors,Perform Visual Inspection: BASIS DOCUMENT This basis document identifies the thought process and background that resulted in the creation of the attached PCM template. This template was created as a result of the Plant Material Condition Excellence Initiative (PMCEI). The PMCEI project strove to identify every circuit card that could, by itself, cause any one of the following: Reactor SCRAM, Reactor or Generator transient, Generator derating, or entry in a 48 hour or less LCO leading to shutdown. A PCM template was then created for each circuit card identified by the PMCEI project. A primary focus of the PCM template creation for these circuit cards was to identify an expected lifetime for each card. A lifetime for a particular card was calculated by identifying all the subcomponents on that circuit card and then determining the individual failure rates for the subcomponents. The subcomponent failure rates were taken from published data bases. A overall circuit card failure rate was then determined based on the subcomponent failure rates. The calculations for each card are attached as separate worksheets. In some instances schematics or bill of materials were not available, so the lifetime of the circuit card was determined by comparing the function of the card to similar circuit cards. If no similar card was found, a maximum lifetime of 20 years was established as a reasonable assurance of reliability for critical cards. Many of the calculations result in lifetimes that exceed 50 and even a 100 years because of small subcomponent densities. However, it is recognized that the calculations only consider subcomponent failures and neglect corrosion, connectors, and other failure mechanisms. Consequently, after considerable review the expert panel determine that a reasonable expectation for the maximum life of any circuit card is 35 years. And, that the maximum replacement frequency for any critical card should be 30 years. The references listed at the end of this basis document were utilized heavily in the creation of this template. This 30 year critical card replacement is a testament to the unknowns and uncertainties impacting circuit card reliability after such a long operating history. The 30 year maximum attempts to limit the vulnerability of the plant to circuit card failures from the long term effects of corrosion, vibration, trace degradation, and all of a circuit card's failure mechanisms. Therefore, any circuit card with a calculation result that exceeded 30 years, was assigned a 30 year replacement frequency. This task is very important, a rigorous visual inspection often catches potential failures more than testing. Additionally, connector anomalies account for the majority of circuit card related events. REFERENCES 1. EPRD-97, Electronic Parts Reliability Data, A

7

Compendium of Commercial and Military Device Field Failure Rates, Volume 1 & 2, DOD Reliability Analysis Center, November 1996. 2. EPRI NP-1558, A Review of Equipment Aging Theory and Technology, Franklin Research Center, September 1980. 3. Reliability of Electronic Components, T.I. Bajenescu and M.I. Bazu, Springer-Verlag 1999. 4. IEEE Standard 500-1984, IEEE Guide to the Collection and Presentation of Electrical, Electronic and Sensing Component Reliability, 1984. 5. MIL-HDBK-217B, Reliability Prediction of Electronic Equipment, DOD September 1974. 6. MIL-HDBK-217B Supplement, Reliability Prediction of Electronic Equipment, DOD September 1976. 7. GE MARK I EHC system circuit card schematics. 5. MIL-HDBK-217B, Reliability Prediction of Electronic Equipment, DOD September 1974. 6. MIL-HDBK-217B Supplement, Reliability Prediction of Electronic Equipment, DOD September 1976. 7. GE MARK I EHC system circuit card schematics. Replace or Refurbish 44C300221G3, 44C300224G1, and 44C300339G1/G5: BASIS DOCUMENT This basis document identifies the thought process and background that resulted in the creation of the attached PCM template. This template was created as a result of the Plant Material Condition Excellence Initiative (PMCEI). The PMCEI project strove to identify every circuit card that could, by itself, cause any one of the following: Reactor SCRAM, Reactor or Generator transient, Generator derating, or entry in a 48 hour or less LCO leading to shutdown. A PCM template was then created for each circuit card identified by the PMCEI project. A primary focus of the PCM template creation for these circuit cards was to identify an expected lifetime for each card. A lifetime for a particular card was calculated by identifying all the subcomponents on that circuit card and then determining the individual failure rates for the subcomponents. The subcomponent failure rates were taken from published data bases. A overall circuit card failure rate was then determined based on the subcomponent failure rates. The calculations for each card are attached as separate worksheets. In some instances schematics or bill of materials were not available, so the lifetime of the circuit card was determined by comparing the function of the card to similar circuit cards. If no similar card was found, a maximum lifetime of 20 years was established as a reasonable assurance of reliability for critical cards. Many of the calculations result in lifetimes that exceed 50 and even a 100 years because of small subcomponent densities. However, it is recognized that the calculations only consider subcomponent failures and neglect corrosion, connectors, and other failure mechanisms. Consequently, after considerable review the expert panel determine that a reasonable expectation for the maximum life of any circuit card is 35 years. And, that the maximum replacement frequency for any critical card should be 30 years. The references listed at the end of this basis document were utilized heavily in the creation of this template. This 30 year critical card replacement is a testament to the unknowns and uncertainties impacting circuit card reliability after such a long operating history. The 30 year maximum attempts to limit the vulnerability of the plant to circuit card failures from the long term effects of corrosion, vibration, trace degradation, and all of a circuit card's failure mechanisms. Therefore, any circuit card with a calculation result that exceeded 30 years, was assigned a 30 year replacement frequency. The placement frequencies determined based on the lifetime calculations and expert panel determinations. REFERENCES 1. EPRD-97, Electronic Parts Reliability Data, A Compendium of Commercial and Military Device Field Failure Rates, Volume 1 & 2, DOD Reliability Analysis Center, November 1996. 2. EPRI NP-1558, A Review of Equipment Aging Theory and Technology, Franklin Research Center, September 1980. 3. Reliability of Electronic Components, T.I. Bajenescu and M.I. Bazu, SpringerVerlag 1999. 4. IEEE Standard 500-1984, IEEE Guide to the Collection and Presentation of Electrical, Electronic and Sensing Component Reliability, 1984. 5. MIL-HDBK-217B, Reliability Prediction of Electronic Equipment, DOD September 1974. 6. MIL-HDBK-217B Supplement, Reliability Prediction of Electronic Equipment, DOD September 1976. 7. GE MARK I EHC system circuit card schematics. 5. MIL-HDBK217B, Reliability Prediction of Electronic Equipment, DOD September 1974. 6. MIL-HDBK-217B Supplement, Reliability Prediction of Electronic Equipment, DOD September 1976. 7. GE MARK I EHC system circuit card schematics. Replace or Refurbish 3S7932MA2376A1/A4 and 44C300222G1: BASIS DOCUMENT This basis document identifies the thought process and background that resulted in the creation of the attached PCM template. This template was created as a result of the Plant Material Condition Excellence Initiative (PMCEI). The PMCEI project strove to identify every circuit card that could, by itself, cause any one of the following: Reactor SCRAM, Reactor or Generator transient, Generator derating, or entry in a 48 hour or less LCO leading to shutdown. A PCM template was then created for each circuit card identified by the PMCEI project. A primary focus of the PCM template creation for these circuit cards was to identify an expected lifetime for each card. A lifetime for a particular card was calculated by identifying all the subcomponents on that circuit card and then determining the individual failure rates for the subcomponents. The subcomponent failure rates were taken from published data bases. A overall circuit card failure rate was then determined based on the subcomponent failure rates. The calculations for each card are attached as separate worksheets. In some instances schematics or bill of materials were not available, so the lifetime of the circuit card was determined by comparing the function of the card to similar circuit cards. If no similar card was found, a maximum lifetime of 20 years was established as a reasonable assurance of reliability for critical cards. Many of the calculations result in lifetimes that exceed 50 and even a 100 years because of small subcomponent densities. However, it is recognized that the calculations only consider subcomponent failures and neglect corrosion, connectors, and other failure mechanisms. Consequently, after considerable review the expert panel determine that a reasonable expectation for the maximum life of any circuit card is 35 years. And, that the maximum replacement frequency for any critical card should be 30 years. The references listed at the end of this basis document were utilized heavily in the creation of this template. This 30 year critical card replacement is a testament to the unknowns and uncertainties impacting circuit card reliability after such a long operating history. The 30 year maximum attempts to limit the vulnerability of the plant to circuit card failures from the long term effects of corrosion, vibration, trace degradation, and all of a circuit card's failure mechanisms. Therefore, any circuit card with a calculation result that exceeded 30 years, was assigned a 30 year replacement frequency. The placement frequencies determined based on the lifetime calculations and expert panel determinations. REFERENCES 1. EPRD-97, Electronic Parts Reliability Data, A Compendium of Commercial and Military Device Field Failure Rates, Volume 1 & 2, DOD Reliability Analysis Center, November 1996. 2. EPRI NP-1558, A Review of Equipment Aging Theory and Technology, Franklin Research Center, September 1980. 3. Reliability of Electronic Components, T.I. Bajenescu and M.I. Bazu, SpringerVerlag 1999. 4. IEEE Standard 500-1984, IEEE Guide to the Collection and Presentation of Electrical, Electronic and Sensing Component Reliability, 1984. 5. MIL-HDBK-217B, Reliability Prediction of Electronic Equipment, DOD September 1974. 6. MIL-HDBK-217B Supplement, Reliability Prediction of Electronic Equipment, DOD September 1976. 7. GE MARK I EHC system circuit card schematics. 5. MIL-HDBK217B, Reliability Prediction of Electronic Equipment, DOD September 1974. 6. MIL-HDBK-217B Supplement, Reliability Prediction of Electronic Equipment, DOD September 1976. 7. GE MARK I EHC system circuit card schematics. Replace or Refurbish 1589K38G: BASIS DOCUMENT This basis document identifies the thought process and background that resulted in the creation of the attached PCM template. This template was created as a result of the Plant Material Condition Excellence Initiative (PMCEI). The PMCEI project strove to identify every circuit card that could, by itself, cause any one of the following: Reactor SCRAM, Reactor or Generator transient, Generator derating, or entry in a 48 hour or less LCO leading to shutdown. A PCM template was then created for each circuit card identified by the PMCEI project. A primary focus of the PCM template creation for these circuit cards was to identify an expected lifetime for each card. A lifetime for a particular card was calculated by identifying all the subcomponents on that circuit card and then determining the individual failure rates for the subcomponents. The subcomponent failure rates were taken from

8

published data bases. A overall circuit card failure rate was then determined based on the subcomponent failure rates. The calculations for each card are attached as separate worksheets. In some instances schematics or bill of materials were not available, so the lifetime of the circuit card was determined by comparing the function of the card to similar circuit cards. If no similar card was found, a maximum lifetime of 20 years was established as a reasonable assurance of reliability for critical cards. Many of the calculations result in lifetimes that exceed 50 and even a 100 years because of small subcomponent densities. However, it is recognized that the calculations only consider subcomponent failures and neglect corrosion, connectors, and other failure mechanisms. Consequently, after considerable review the expert panel determine that a reasonable expectation for the maximum life of any circuit card is 35 years. And, that the maximum replacement frequency for any critical card should be 30 years. The references listed at the end of this basis document were utilized heavily in the creation of this template. This 30 year critical card replacement is a testament to the unknowns and uncertainties impacting circuit card reliability after such a long operating history. The 30 year maximum attempts to limit the vulnerability of the plant to circuit card failures from the long term effects of corrosion, vibration, trace degradation, and all of a circuit card's failure mechanisms. Therefore, any circuit card with a calculation result that exceeded 30 years, was assigned a 30 year replacement frequency. The placement frequencies determined based on the lifetime calculations and expert panel determinations. REFERENCES 1. EPRD-97, Electronic Parts Reliability Data, A Compendium of Commercial and Military Device Field Failure Rates, Volume 1 & 2, DOD Reliability Analysis Center, November 1996. 2. EPRI NP-1558, A Review of Equipment Aging Theory and Technology, Franklin Research Center, September 1980. 3. Reliability of Electronic Components, T.I. Bajenescu and M.I. Bazu, Springer-Verlag 1999. 4. IEEE Standard 500-1984, IEEE Guide to the Collection and Presentation of Electrical, Electronic and Sensing Component Reliability, 1984. 5. MIL-HDBK-217B, Reliability Prediction of Electronic Equipment, DOD September 1974. 6. MIL-HDBK-217B Supplement, Reliability Prediction of Electronic Equipment, DOD September 1976. 7. GE MARK I EHC system circuit card schematics. 5. MIL-HDBK-217B, Reliability Prediction of Electronic Equipment, DOD September 1974. 6. MIL-HDBK-217B Supplement, Reliability Prediction of Electronic Equipment, DOD September 1976. 7. GE MARK I EHC system circuit card schematics. Replace or Refurbish 44C300245G3, 1589K29G700, 1589K42G700, 3S7700PB103A, 8080K42, and 8080K44: BASIS DOCUMENT This basis document identifies the thought process and background that resulted in the creation of the attached PCM template. This template was created as a result of the Plant Material Condition Excellence Initiative (PMCEI). The PMCEI project strove to identify every circuit card that could, by itself, cause any one of the following: Reactor SCRAM, Reactor or Generator transient, Generator derating, or entry in a 48 hour or less LCO leading to shutdown. A PCM template was then created for each circuit card identified by the PMCEI project. A primary focus of the PCM template creation for these circuit cards was to identify an expected lifetime for each card. A lifetime for a particular card was calculated by identifying all the subcomponents on that circuit card and then determining the individual failure rates for the subcomponents. The subcomponent failure rates were taken from published data bases. A overall circuit card failure rate was then determined based on the subcomponent failure rates. The calculations for each card are attached as separate worksheets. In some instances schematics or bill of materials were not available, so the lifetime of the circuit card was determined by comparing the function of the card to similar circuit cards. If no similar card was found, a maximum lifetime of 20 years was established as a reasonable assurance of reliability for critical cards. Many of the calculations result in lifetimes that exceed 50 and even a 100 years because of small subcomponent densities. However, it is recognized that the calculations only consider subcomponent failures and neglect corrosion, connectors, and other failure mechanisms. Consequently, after considerable review the expert panel determine that a reasonable expectation for the maximum life of any circuit card is 35 years. And, that the maximum replacement frequency for any critical card should be 30 years. The references listed at the end of this basis document were utilized heavily in the creation of this template. This 30 year critical card replacement is a testament to the unknowns and uncertainties impacting circuit card reliability after such a long operating history. The 30 year maximum attempts to limit the vulnerability of the plant to circuit card failures from the long term effects of corrosion, vibration, trace degradation, and all of a circuit card's failure mechanisms. Therefore, any circuit card with a calculation result that exceeded 30 years, was assigned a 30 year replacement frequency. The placement frequencies determined based on the lifetime calculations and expert panel determinations. REFERENCES 1. EPRD-97, Electronic Parts Reliability Data, A Compendium of Commercial and Military Device Field Failure Rates, Volume 1 & 2, DOD Reliability Analysis Center, November 1996. 2. EPRI NP-1558, A Review of Equipment Aging Theory and Technology, Franklin Research Center, September 1980. 3. Reliability of Electronic Components, T.I. Bajenescu and M.I. Bazu, Springer-Verlag 1999. 4. IEEE Standard 500-1984, IEEE Guide to the Collection and Presentation of Electrical, Electronic and Sensing Component Reliability, 1984. 5. MIL-HDBK-217B, Reliability Prediction of Electronic Equipment, DOD September 1974. 6. MIL-HDBK-217B Supplement, Reliability Prediction of Electronic Equipment, DOD September 1976. 7. GE MARK I EHC system circuit card schematics. 5. MIL-HDBK-217B, Reliability Prediction of Electronic Equipment, DOD September 1974. 6. MIL-HDBK217B Supplement, Reliability Prediction of Electronic Equipment, DOD September 1976. 7. GE MARK I EHC system circuit card schematics.

9

Controllers - Electronic Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe Mild

X X

X

5

6

7

8

X

X

X

X

X X

X

X X

X

X X

X

X

X

X

Time Directed Task

Calibrations (perform calibrations check of component at minimum of 5 cardinal points. Recalibrate as necessary)

Perform dynamic calibration of all components with time-based functions (step input and x-y plot the output).

2Y 2Y 2Y 2Y 4Y 8Y 4Y 8Y

2Y 2Y 2Y 2Y 4Y 8Y 4Y 8Y

Failure Codes

Comments

CD OC OP

The actions regarding calibration may vary depending controller Manufacturer / Model Number. When practicable, perform a visual inspection of all modules and circuit cards for evidence of over-heating, leaking or out-dated electrolytic capacitors (replace as necessary). Feedback regarding adjustments to this PCM Template should be made by clicking the "Feedback/Comment" link.

CD OC OP SC

Always verify dial calibrations prior to adjustment. The actions regarding dynamic calibration may vary, depending on the controller manufacturer and model number. Check the manufacturer's recommendations regarding proper maintenance. Feedback regarding adjustments to this PCM Template should be made by clicking the "Feedback/Comment" link.

A general indication of when a refurbishment or replacement or is necessary is if the device is more difficult to calibrate or near the end-stops of Re-Build or Replace 10Y NA 15Y NA 15Y NA AR NA AG adjustment. Feedback regarding adjustments to this PCM Template should be made by clicking the "Feedback/Comment" link. NOTE 1: The PM activity recommended for electronic temperature controllers is to verify the controller actuates at the correct temperature. NOTE 2: Technical Specifications always take precedence over frequencies specified here.. This template was developed as the result of a systematic data search of past CM and PM activities. The frequencies suggested will provide adequate intervals to assess the condition of the probe. Click for Assessment Data This template is the controlled revision. Please refer to MA-AA-716-210 & MA-AA-716-210-1001 for additional guidance. SME Summary The expert groups identified the most common, i.e. dominant, failure locations and mechanisms for this equipment to be: Failure from aging of electrolytic capacitor due to dielectric breakdown, leakage, and internal shorts or open circuits. Industry References: 1. Instrumentation and Control Maintenance Experience Reference, EPRI NMAC TR-100856, December 1993. 2. GE EHC Electronics Maintenance Guide, EPRI NMAC TR-108146, December 1997. 3. Feedwater Instrument and Control Maintenance Guide, EPRI NMAC TR-105663, November 1995. 4. “Guidelines for Instrument Calibration Extension / Reduction Programs”, EPRI TR-103335, March 1994.

Boundary Definition The boundary of an analog electronic controller includes only the controller itself, and not any peripheral components or equipment, e.g. manual-auto stations. It applies only to a stand-alone off-the-shelf catalog type component. Not when the function performed as part of a

10

larger system. For example, it does not apply to a controller function within the EHC or Feedwater system. (Click "Assessment Data" below to view components included in this category). The scope of this template includes only individual electronic controllers, not entire control loops. Basis For Template Tasks Calibrations (perform calibrations check of component at minimum of 5 cardinal points. Recalibrate as necessary): The source for this template is the 2002 PCM assessment, which accessed fleet CM and PM activities from November 20, 2001 through November 20, 2002. A copy of the spreadsheet is attached. Calibration assures that the device is performing within specification, and confirms traceability to NIST standards in demonstrating the absolute accuracy of the output. The interval is not well determined by the failure timing data. Calibration is focused on correcting drift, especially when it can no longer be compensated by the controller, and also addressing longer term wearout failures of electronic subcomponents. Drift is primarily age-related; longer term wear-out failures of electronic subcomponents are addressed by detecting the decreasing ability to reset the drift. The degradation mechanisms addressed effectively are the aging processes causing drift and failure of electronic subcomponents. Because the controller will compensate for drift to some extent, calibration is less critical for controllers than for other I&C components. Calibration should include the following: · A visual inspection should be performed to check for tightness of the connections, general cleanliness, proper mechanical alignments, free movement of the mechanical assembly, corroded edge connectors, over heated components on printed circuit boards, leaking capacitors, and cracked terminations and cases. · Verify and adjust, as needed, the device's zero span. · Verify and adjust, as needed, the device's linearity hysteresis. · It is strongly suggested that a minimum 5 point calibration response check be performed, a 9 point check should be considered for more critical devices. Perform dynamic calibration of all components with time-based functions (step input and x-y plot the output).: The source for this template is the 2002 PCM assessment, which accessed fleet CM and PM activities from November 20, 2001 through November 20, 2002. A copy of the spreadsheet is attached. Re-Build or Replace: The source for this template is the 2002 PCM assessment, which accessed fleet CM and PM activities from November 20, 2001 through November 20, 2002. A copy of the spreadsheet is attached. Re-Build or Replace prevents end-of-life failures of electronic subcomponents. The interval is clearly determined by the failure timing data. If replacement parts are unavailable consider replacing the device. Re-Building or Replacing the controller can prevent failures from outright failure of sub-components, and also from drifts which can no longer be reset. Drift which can no longer be recalibrated and wearout failures of electronic subcomponents occur with an expected failure free interval of at least 10 years. The intervals of 10 and 15 years for critical components are sufficient to provide good protection from the longer term age-related failure mechanisms. Rebuild or Replace should consist of the following: - Inspection for damage, over heating of components, corrosion, evidence of air leakage, tightness and conditional of all electrical and mechanical connections, loose, or missing parts. - Replacement of electrolytic capacitors. - The entire device may be replaced with a refurbished or new device at this time.

11

Inverter (> or = 5 kVA) Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe

X X

X

Mild

5

6

7

8

X

X

X

X

X X

X

X X

X

X X

X

X

X

Condition Monitoring Task

X Failure Codes

Comments

2Y

OC

EPRI TR-106857-V22 Aplication Note 2.3.1

Time Directed Task

Failure Codes

Comments

Clean and Inspect

2Y

2Y

3Y

3Y

CD CN CO DA FD IB EPRI TR-106857-V22 LC OC OR Application Note 2.3.2

Component Replacement *

5Y

10Y

5Y

10Y

AG

EPRI TR-106857-V22 Application Note 2.3.3

Failure Codes

Comments

Thermography (includes visual on-line inspection)

1Y

1Y

2Y

Surveillance Task

Refer to the Molded Case Breaker Testing OC Circuit Breaker PCM Template. *Components that are replaced on a regular schedule are electrolytic capacitors, oil-filled CVT capacitors, input fuses, critical printed circuit boards, (including static switch control boards), power transistors manufactured for Danaher Power Solutions'' Inverters, muffin fans (but run-to-failure when design includes redundant fans), and internal batteries (if applicable). Commutating capacitors are not replaced on a regular schedule owing to their very rugged construction. For Westinghouse Instrument Inverters (including those in service at Byron/Braidwood), component replacement includes the Ferro-resonant Transformers on a 10 year frequency. In addition, the 1FU fuse within the Westinghouse 7.5KVA inverters is cycled due to a known anomaly (commutating short), that subsequently causes premature failure of the fuse. Based on this, the 1FU fuse should be replaced on a 3-6 year frequency. This template is the controlled revision. Please refer to MA-AA-716-210 & MA-AA-716-210-1001 for additional guidance. SME Summary This document captures the review of the Inverter PCM Template. This review was performed in accordance with Attachment 1 of the provided review instructions titled: “PCM Template Review Instructions”, dated 11-2-01. FAILURE MODES Failure history data was reviewed to identify reasonable, detectable failure modes associated with inverters. Failure data from MAROG, MWROG, OPEX, INPO (EPIX, NPRDS and OE) and EPRI reports were searched for Inverter failure information. This search revealed the most common failures as being caused by sub-component degradation or failure. Other external failure modes such as design deficiencies and poor maintenance practices were also identified, but are considered outside the scope of the PCM process. The most common subcomponents identified were as follows: · · · · · ·

Capacitors Circuit Cards Fuses Semi-conductors (SCR’s) Transformers Circuit breakers

Primary failure sources for inverters at MWROG plants included circuit cards, ferro-resonant transformers (Specific to Byron and Braidwood), capacitors and fuses. MAROG failure modes have been age related failures of SCR legs, circuit cards, and capacitors. The identified failure modes can be detected through each of the following measurable conditions. Due to the critical nature of the inverters, extensive monitoring and alarms are an integral part of the design. These elements provide continual monitoring of the inverter with the exception of temperature. However, because of high operating temperatures some newer designs have fan failure alarm circuit for blocked air filters, or muffin fan failure. Temperature conditions and temperature related capacitor and circuit card sub-component failures can be monitored through the thermography checks identified on the PCM template. · · · · ·

Inverter output goes low Inverter output goes high Inverter output drifts Inverter drifts out of synchronization Inverter elevated temperature

TEMPLATE REVIEW Overall, the scope and frequency identified in the PCM template is reasonable and conservative based on review of the identified references. The Braidwood May 2000 root cause report results were found implemented into the template for ferro-resonant transformer replacement. However, some minor changes were identified in order to improve and optimize the template. Bases for the recommended changes are provided below.

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· Addition of an “as required” check for internal batteries addresses a risk identified in NRC Information Notice IN 94-24, where failure of internal batteries caused loss of inverter vital power and critical plant components. · Static switch failures were identified as the cause for some inverter failures. The majority of these failures were due to control boards associated with the static switches. It is not clear if this failure is addressed within the PCM template. A note will be added to ensure this board is replaced as part of the critical printed circuit boards. RECOMMENDED PCM TEMPLATE CHANGES Although the present template is reasonable and conservative, the following changes are recommended to optimize resources, improve PCM results and address minor weaknesses. 1. Add “internal batteries” to the component replacement note. 2. Add a reference to the static switch control boards within the component replacement note. IMPLEMENTATION The revised PCM template should be implemented and data collected for several fuel cycles. The collected data can then be reviewed for PCM effectiveness and adjusted as necessary. REFERENCES 1. EPRI Report TR-106857 – V22: “Preventive Maintenance Basis, Volume 22: Inverters”, December 1997 2. EPRI Report TR-100491s: “UPS Maintenance and Application Guide”, September 1994 3. EPRI Report TR-112175: “Capacitor Application and Maintenance Guide”, August 1999 4. EPRI Report TR-1001257: “Capacitor Performance Monitoring Report”, December 2000 5. INPO NPRDS and EPIX component failure search results for failed inverters. 6. INPO Operating Experience search results for failed inverters. 7. INPO O&MR 71: “Inverter Capacitor Excessive Operating Temperatures”, August 1981 8. INPO O&MR 243: “Temperature Induced Inverter Failures”, April 1985 9. INPO Equipment Failure Experience Report: “Inverters”, 1999. 10. INPO Just in Time Operating Experience Report: “Inverter Maintenance”, 1999. 11. NRC Information Notice IN 84-80: “Plant Transients Induced by Failure of Non-Nuclear Instrumentation Power”, November 1984. 12. NRC Information Notice IN 84-84: “Deficiencies in Ferro-Resonant Transformers”, November 1984. 13. NRC Information Notice IN 87-24: “Operational Experience Involving Losses of Electrical Inverters”, June 1987. 14. NRC Information Notice IN 94-24: “Inadequate Maintenance Of Uninterruptible Power Supplies And Inverters”, March 1994. 15. ComEd OPEX search results for failed inverters. 16. MAROG failure search in PIMS. 17. Braidwood Root Cause Report (NTS# 456-200-99-SCAQ00001): “1PA19J Power Supply Inverter Failures, As a Result of Several Root Causes, Result In Loss of Annunciator Events with Two GSEP Unusual Event Entries”, February 26, 1999. 18. Braidwood Root Cause Report (AT# 28260): “Failure of Ferro-Resonant Transformer in Instrument Inverter 214 Due to Inadequate Preventive Maintenance”, May 4, 2000. 19. UtilityProcedure MA-AA-716-210: “Performance Centered Maintenance (PCM) Process”, Rev. 0 20. UtilityProcedure MA-AA-716-210-1001: “Performance Centered Maintenance (PCM) Templates”, Rev. 0 Added power transistors manufactured for Danaher Power Solutions'''' inverters to the component replacement text and associated note based on Limerick''''s experience documented in CR 219148.

Boundary Definition The boundary of a typical inverter for the purpose of this database is defined to include the following: · · · ·

Inverter Maintenance bypass switch Static switch, if installed Excluding the distribution panel

Regulated rectifiers, if present, and breakers, are excluded because PM for these can be found by referring to Battery Charger and Motor Control Center Basis For Template Tasks Thermography (includes visual on-line inspection): 2.3.1 Thermography Failure Locations and Causes: This task focuses on either a general temperature rise of the cabinet or, if access to the cabinet interior can be obtained, on individual hot components, typically on large input or output chokes, transformers, and loose connections, and may also indicate weak or loose fuse holders. The diagnostic indication is a temperature difference between two similar inverters with similar loads. Progression of Degradation to Failure: Although winding degradation is not anticipated for many years, it frequently (but not always) results in rising temperatures for some time before failure occurs. Degradation caused by cooling system failures, e.g. restricted air flow, may occur more rapidly but will be dependent on the power rating of the inverter. Loose connections will mostly be random events. Fault Discovery and Intervention: Thermography is most effective when the inverter cabinet doors can be opened during power operation. The effectiveness of thermography is in revealing differences in temperature between two similar inverters with similar loads. If the cabinet doors can not be opened only a general temperature indication can be obtained, and this will not be sensitive to small differences in individual component temperatures. The task needs to be performed in the normal operating mode, but also taking opportunities, when possible, to perform it for the bypass mode, and when switched to the alternate source of power. These variations will generally sample different sets of connections, although only

13

one such alignment can normally be addressed by any given thermography scan. Thermography is not universally regarded as an effective PM task for chargers and inverters because the relatively high proportion of random failures, and the speed of their progression to failure, diminish its overall effectiveness. When the cabinet doors can be opened, advantage should be taken of the opportunity to visually inspect the interior, in addition to performing the thermography scan. Typically, the visual inspection items listed under the “Clean and Inspect” task, should be performed each time the doors are opened. Clean and Inspect: 2.3.2 Clean and Inspect Failure Locations and Causes: The task addresses many items but is focused on the detection of overheating components that may be about to fail, on the calibration of printed circuit boards for metering and alarm functions, and on exercising the static switch and maintenance bypass switch. Overheating may occur to power semiconductor devices because of insufficient torque or heat transfer material mating them to their heat sinks, because of blocked air filters, or because of the restriction of air flow by foreign material. Foreign magnetic or conducting material such as bolts or washers may also fail input or output chokes by vibrating against winding insulation if dropped inside large open windings. Electrolytic and oil-filled capacitors may show signs of overheating or leakage before failure. Calibration of printed circuit boards and cycling of key switches are heavily relied on to address the expected failure modes of drift and aging, respectively. Progression of Degradation to Failure: The most important influences on the timing of this task are random failures of power semiconductors, random occurrence of leakage from electrolytic and oil-filled capacitors, and the random occurrence of degraded windings and loose connections on power transformers. The main age related process for this task is the drift of circuit boards. The need to periodically cycle the maintenance bypass and static switches requires a task interval much shorter than the expected life of these switches. Fault Discovery and Intervention: The recommended interval of 2 to 3 years appears to satisfy the above constraints while providing a reasonable interval between tasks. Most of the random events noted above occur individually on a scale of many years. However, because of the number of components subject to these effects there does not appear to be much scope for extending the interval for this task. Because overheating is a major factor in these component failures, the possible performance of thermography at a shorter interval, and an accompanying visual inspection for signs of overheating or cooling obstruction, take on additional importance. Clean and Inspect should include: · Verify proper operation of the maintenance bypass-switch · Inspect for loose, missing, or damaged parts and foreign material · Check all cables and connections for discoloration, cracks, other degradation · Check high power connections for tightness · Check that the silicon controlled rectifiers (SCR’s) are properly torqued to their heat sinks and that the proper contact grease is used, if accessible · Check for leakage or swelling of all electrolytic capacitors · Check printed circuit boards and relays for signs of degradation; replace as necessary · Clean and vacuum dust from cabinets and components · Visually inspect transformers and chokes for damage, insulation breakdown, loose connections, and the presence of foreign material · Clean ventilation filters; replace as necessary · Verify accuracy of meters, calibrate if required · Verify set points of alarm cards, adjust if necessary · Verify the proper operation of all local and remote lamps, and annunciators · Verify proper operation of static transfer switch, including timing test if desired · Inspect contactors, if present · Check the capacitance of the capacitor bank, if desired · Verify free rotation of cooling fans and that they are not clogged or dirty · Verify that output voltage, frequency, and waveform are within specification. Component Replacement *: 2.3.3 Component Replacement Failure Locations and Causes: Components that are replaced on a regular schedule are electrolytic capacitors, oil-filled CVT capacitors, input fuses, critical printed circuit boards, (including static switch control boards), power transistors manufactured for Danaher Power Solutions' Inverters, muffin fans (but Run-To-Failure when design includes redundant fans), and internal batteries (if applicable). Commutating capacitors are not replaced on a regular schedule owing to their very rugged construction. Progression of Degradation to Failure: These components experience mainly continuous degradation with the exception of printed circuit boards and electrolytic capacitors for which a significant random failure component exists due to overvoltage, manufacturing defects, and mistreatment. The life of printed circuit boards may be significantly reduced if flooded lead-acid batteries are situated in the same room, or even in the same enclosure, if proper charging conditions are not maintained. This is not usually the case in nuclear power plant applications. Capacitors and circuit boards are expected to have a life of a few years up to about 10 years, significantly dependent on temperature rise above design rating. Fuses have a life likely to exceed 10 years, and the small fans are expected to be failure free for about 10 years. Fault Discovery and Intervention: Despite the spread in expected lifetimes the replacement task can economically address all the component failures at about the same intervals. Large capacitors may have their capacitance trended over time to give indication of impending failure. They may also show signs of overheating or leaking before failure occurs. Fans are likely to give some indication of an impending failure, but fuses and circuit boards are more likely to fail without warning. Both of these components however, may show signs of degradation, sagging in the case of fuses, and overheating or aging of relays or electrolytic capacitors on printed circuit boards. The printed circuit boards are likely to fail before the fuses, and the other components provide some warning of degradation. This supports the basis for the inclusion of the visual inspection items during the Thermography and the Clean and Inspect tasks. Breaker Testing: No Basis At This Time

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Low Voltage Circuit Breaker Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe Mild

X X

X

5

6

7

8

X

X

X

X

X X

X

X X

X

X X

X

X

X

X

Time Directed Task Perform PM of GE Breaker --- Notes 1 & 2

Perform PM of Westinghouse DB Breaker - Note 2

Failure Codes 4Y

6Y

4Y

6Y

CN DA LC SC

CN DA LC SC

Comments Lubricate breaker and perform adjustments in accordance with OEM documents and NMAC guidelines. Refer to EPRI TR-106857-V3 Note 2.3.3. Lubricate breaker and perform adjustments in accordance with OEM documents and NMAC guidelines. Refer to EPRI TR-106857-V3 Note 2.3.3 Lubricate breaker and perform adjustments in accordance with OEM documents and NMAC guidelines. Refer to EPRI TR-106857-V3 Note 2.3.3

Perform PM of Westinghouse DS Breakers --- Notes 2 & 3

3Y

6Y

Perform PM of ABB Breaker --- Notes 2 & 4

4Y

6Y

Overhaul GE Breaker

16Y

16Y

AG CN DA DL Tear down and rebuild as necessary LC SC EPRI TR-106857-V3 Note 2.3.4

Overhaul Westinghouse DS and DB Breaker

16Y

16Y

AG CN DA DL Tear down and rebuild as necessary LC SC EPRI TR-106857-V3 Note 2.3.4

Overhaul ABB Breaker --- Note 4

12Y

12Y

AG CN DA LC SC

Tear down and rebuild as necessary EPRI TR-106857-V3 Note 2.3.4

Perform PM on switchgear breaker cubicles (GE) --- Note 1

4Y

6Y

DA LC

Clean/Inspect, check breaker to cubicle interfaces TR-106857-V3 Note 2.3.5

Perform PM on switchgear breaker cubicles (West DB)

4Y

6Y

DA LC

Clean/Inspect, check breaker to cubicle interfaces TR-106857-V3 Note 2.3.5

Perform PM on switchgear breaker cubicles (West DS)

3Y

6Y

DA LC

Clean/Inspect, check breaker to cubicle interfaces per MA-AP-EM-5-00101 EPRI TR-106857-V3 Note 2.3.5

Perform PM on switchgear breaker cubicles (ABB) --- Note 4

4Y

6Y

DA LC

Clean/Inspect, check breaker to cubicle interfaces EPRI TR-106857-V3 Note 2.3.5

Perform PM on switchgear bus (GE)

10Y

12Y DA LC

Clean/Inspect, check accessible bus connections

Perform PM on switchgear bus (West)

6Y

12Y DA LC

Clean/Inspect, check accessible bus connections

CN DA LC SC

CN DA LC SC

Lubricate breaker and perform adjustments in accordance with OEM documents and NMAC guidelines. Refer to EPRI TR-106857-V3 Note 2.3.3.

Clean/Inspect, check accessible bus connections Note 1: AK-25 breakers shall be maintained per MA-AB-725-110. AK-50 and AK-75 breakers shall be maintained per MA-AB-725-112. AKR30/50 breakers/cubicles shall be maintained per MA-AP-725-115 (DC) and MA-AB-725-116 (AC). Note 2: NMAC Guidance documents are NP-7410-V1-P1(ABB), TR-113736 (ABB), NP-7410-V1-P2 (GE), TR-112938(GE), NP-7410-V2-P3 (Westinghouse DB), NP-7410-V2-P4 (Westinghouse DS) and 1000246 (Westinghouse DS). Note 3: Westinghouse DS breakers shall be maintained per MA-AP-725-100. Breakers used as Reactor Trip Breakers shall be maintained per MA-AP-725-104. Note 4: Limerick Safety-Related Motor Control Center feed breakers are maintained on an 8-year overhaul, no PM basis to align with MCC outages.

Perform PM on switchgear bus (ABB)

8Y

12Y DA LC

This template is the controlled revision. Please refer to MA-AA-716-210 & MA-AA-716-210-1001 for additional guidance. SME Summary No SME Summary Available At This Time Boundary Definition The boundary of a Low Voltage Switchgear for the purpose of this database is defined to include the switchgear enclosure, circuit breaker, protective devices, and their accessories, as follows: · Switchgear enclosure including racking mechanism, busbar and insulation, cabinets, interlocks and switches, lightning arrestors, bus PTs (potential transformer) and bus CTs (current transformer), load CTs, and control wiring.

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· Circuit breaker including racking mechanism, truck, operating mechanism, main current components, arc chutes or arc quenching devices, and auxiliary switches and contacts. · Protective devices including relays, such as overcurrent, ground fault, control wiring, switches (e.g. auxiliary switches, control relay, trip coils), and local metering.

Basis For Template Tasks Perform PM of GE Breaker --- Notes 1 & 2: 2.3.3 Breaker - Detailed Inspection Failure Locations and Causes: The failure locations and failure causes addressed by the Detailed Inspection are the same as those addressed by the Visual Inspection. The main difference is that the Detailed Inspection includes a far more comprehensive set of tasks designed to be an effective way to thoroughly check the operating mechanism, main current components, and the racking mechanism for: 1) mechanically failed or damaged parts, loose connections and fasteners, 2) the condition of the lubricant, to cycle the operating mechanism so as to mix and distribute the lubricant, and to provide an opportunity to add lubricant to many more pivot points and bearings including the primary contacts, 3) to check for burn marks or discoloration that might indicate overheating of electrical components such as relays, coils and switches, 4) to replace parts known to be subject to wearout, 5) to perform general cleaning, 6) to check for tracking, burn marks, or deposition of material on arc quenching components, or other damage to them, and 7) to verify adjustments and operation of subcomponents (e.g. primary contacts and plating, puffer assembly) and the integral operation of the breaker. Parts that are loose, damaged, or missing may be seen directly, often where they should not be (e.g. on the cubicle floor), even by relatively inexperienced personnel. However, signs of material fatigue, abnormal wear, or material property changes can best be noted and assessed by having experienced people perform the detailed inspection. A relatively common problem area is the alignment of the prop mechanism, its centering and tightness. The condition of the lubricant is essential to proper operation. Inadequate lubrication is by far the dominant cause of breaker failures. Assessment of the condition of the lubricating grease should therefore be the prime objective of any inspection. Removal of arc chutes, phase barriers, inspection covers and relay/switch covers will facilitate a fairly thorough check of lubricant condition. However, the detailed inspection does not include extensive disassembly of the breaker; consequently, lubricant internal to bearings and bushings will not, in general, be accessible at the detailed inspection. Hard lubricant in thin films may not be visible at all, or may appear as a varnish-like layer. Contaminated switches and relay contacts make up a very large proportion of the failure causes and overhaul deficiencies noted in NPRDS failure events and NMAC data analysis. These contacts are not normally accessible during a visual inspection but should be more accessible at a detailed inspection when switch covers are removed. Electrical insulation and wiring is a much smaller contributor to breaker failure. In addition to visible damage to primary contacts, and deposits and tracking on arc quenching components, the arc contact tips may be damaged or broken off, and the puffer or the blowout coil may have failed. Progression of Degradation to Failure: The likelihood of damaged or failed mechanical parts and loose or missing fasteners is expected to depend on the number of operations of the breaker. This would indicate a continuous progression of these degradation mechanisms, regardless of whether they occur through normal wear, fatigue, or material property changes. Failures should occur only after a trouble free period corresponding to the OEM’s maximum recommended number of operations. A random contribution to failure times from loose fasteners is expected, but only after a similar trouble free period. If 2000 cycles is considered to be a generic OEM limit, the boundary between the template high and low duty cycle of 200 operations per year would imply that these failure causes do not require periodic inspection at low duty cycles more often than at a 10 year interval under nominal service conditions. Concern over inadequate lubrication may appear more quickly than this, in 3 to 10 years depending on service conditions. If heavy contamination of breakers with dust has occurred during the plant construction phase, or if service conditions involve high temperatures or significant dust or other contamination, e.g. salt and / or high humidity, this is likely to lead to lubrication failure in significantly less than 10 years. The lubricant can be expected to harden if a breaker is cycled scarcely at all in a period approaching 6 years. This period of inactivity would lead to a high likelihood of binding and a failure to close or open . The combination of normal operations, detailed and visual inspections, and the operability test once per operating cycle should ensure this failure cause is not encountered. Burn marks and discoloration are symptoms of overheating and may indicate degradation of electrical devices such as coils and relays. Failures of coils, relays and motor windings occur from current-time overload, although age, contamination and environmental factors may also play a part. Current-time overload occurs mainly as a result of energizing the devices for longer than the design intent and is almost always due to lubrication failure which causes the mechanism to move slowly or to seize up. Consequently the degradation mechanisms in the electrical devices themselves, which can be difficult to test for, are strongly coupled to the time scales and influences affecting lubrication. A trouble free period of operation may be expected, with burn marks and discoloration being visible signs of lubrication failure as well as indicating degraded coils and relays. Regardless of the lubricant condition, a measurement of the electrical resistance of coils and relays using an ohmmeter, if trended over time, will detect progressive failure of winding insulation and give an indication of the condition of these electrical devices. An insulation resistance test of insulation resistance to ground should be carried out on all subcomponents exposed to line potential. The condition of insulation can also be indicated by a dielectric test, recommended by Westinghouse but not frequently performed by utilities and not recommended here, owing to the possibility that the high potential may precipitate insulation breakdown. Switch and relay contact failures occur as a result of exposure to the service environment through oxidation and contamination, by wear through the plating, or from lack of contact pressure. High contact resistance may develop over time although a trouble-free period of 10 years should be obtained under mild service conditions. Switch and relay contact failure may be avoided by measuring the contact resistance at the detailed inspection. A contact resistance of up to 5 ohms (not the 0.1 ohms often quoted) can be tolerated without contact failure, as the passage of current will remove the contaminating film. Lack of use may also lead to contact failure, either because the contacts are not sufficiently wiped or surface contamination is not burned through. The recommended electrical cycling of the breaker should avoid this failure cause. Deposition of metals or a variety of glass-like materials, and moisture absorption on arc quenching components may lead ultimately to a failure to quench. These degradation mechanisms are clearly dependent on the number of cycles, age, and service conditions; normal operation should lead to a trouble-free period of approximately 10 years. Large fault current interruptions should each be accompanied by an inspection of the arcing contacts and arc chutes and thus should not interfere with the expected period of failure free operation. The absorption of moisture by arc chutes can also be indicated by a power factor test. Failures of the puffer and blowout coil should not occur before 4 to 5 years and tend to be randomly spread over a wide time scale after that period has passed. The condition of the main contacts should be assessed using a ductor test with the passage of a high current to burn off contaminating films, although the ductor test is not a good indicator if the plating is damaged. Damaged plating on main contacts should be visible. The ductor test also demonstrates that neither lubrication failure nor misadjustment or normal wear are affecting the condition of the main contacts. Fault Discovery and Intervention: All of the failure mechanisms discussed above progress continuously for a period of years before the failure point is reached. The minimum duration of this wearout characteristic is usually controlled by the service conditions that affect lubrication failure. Preventive maintenance (PM) within this period can identify and intercept all the failure mechanisms excepting those due to design, manufacturing, and installation defects, and maintenance error. These are excluded from consideration here because their random nature does not lend itself to being addressed by

16

regularly scheduled PM tasks, other than failure finding such as the operability test, trip tests, or calibration. An overhaul is necessary to completely clean out old lubricant and to renew lubricant at every point in the breaker within about 10 years for low duty cycle and mild service conditions. The detailed inspection should be performed in order to replace as much of the lubricant as possible at a shorter interval, about half the overhaul interval. In a Detailed Inspection, accessible pivot points and bearings can be lubricated, although they probably still can not be properly cleaned. Manual and electrical operation can help to distribute lubricant in all areas and mix it to prevent separation of its constituents. The “feel” of the operating mechanism during manual operation can indicate to an experienced person the general condition of the lubricant. Additionally, the time taken for the breaker to close is a direct indication of a sluggish mechanism. Asfound and as-left electrical close-timing tests may be supplemented by a trip load test or by a minimum control voltage test to detect a sluggish mechanism. If the breaker does not pass these tests a detailed inspection or overhaul will be necessary. A Detailed Inspection will typically be performed to ensure that critical breakers in severe service conditions ( e.g. high temperatures, high humidity, and salt laden air) can reach the scheduled overhaul at 8 years. In more normal conditions for critical breakers, detailed inspection can be combined in rotation with visual inspection and overhaul to provide flexibility on when the overhaul is performed (i.e. not strictly at 10 years). See Note 6 for a discussion of scheduling inspections. Calibration tasks for the protective devices, instantaneous overcurrent, timecurrent excess, overvoltage and undervoltage, as appropriate, should follow the requirements of technical specifications. These tasks help to ensure that the protective relays are not already out-of-specification (failed) when needed. Where there are no technical specification requirements the recommended period for calibration can be paired with that of the breaker detailed inspection. At this interval, experience shows that the relays are not usually sufficiently out-of-calibration to be in a failed state. Breaker Detailed Inspection should include: · Perform and record as-found electrical open/close and timing test · Perform pre-disassembly functional tests and visual inspection · Remove front covers, phase barriers (if present) and arc chutes · Replace lubricant where accessible · Generally clean and inspect all accessible parts and surfaces · Replace known parts subject to wearout or required by OEM · Verify adjustments · Perform manual operation · Inspect puffer and verify operation · Perform ductor test · Perform insulation resistance tests · Inspect for: pitting or corrosion on primary contacts; damaged, loose, or missing fasteners and setscrews; electrical tracking; cracked welds; rust or corrosion; cracked or burned arc chutes; hard lubricant; secondary control block damage or misalignment; worn or bent mechanical linkage, general cleanliness; wiring harness and protective relay damage. · Calibrate protective devices as required · Perform overcurrent trip test · Perform as-left electrical open/close and timing test Perform PM of Westinghouse DB Breaker - Note 2: 2.3.3 Breaker - Detailed Inspection Failure Locations and Causes: The failure locations and failure causes addressed by the Detailed Inspection are the same as those addressed by the Visual Inspection. The main difference is that the Detailed Inspection includes a far more comprehensive set of tasks designed to be an effective way to thoroughly check the operating mechanism, main current components, and the racking mechanism for: 1) mechanically failed or damaged parts, loose connections and fasteners, 2) the condition of the lubricant, to cycle the operating mechanism so as to mix and distribute the lubricant, and to provide an opportunity to add lubricant to many more pivot points and bearings including the primary contacts, 3) to check for burn marks or discoloration that might indicate overheating of electrical components such as relays, coils and switches, 4) to replace parts known to be subject to wearout, 5) to perform general cleaning, 6) to check for tracking, burn marks, or deposition of material on arc quenching components, or other damage to them, and 7) to verify adjustments and operation of subcomponents (e.g. primary contacts and plating, puffer assembly) and the integral operation of the breaker. Parts that are loose, damaged, or missing may be seen directly, often where they should not be (e.g. on the cubicle floor), even by relatively inexperienced personnel. However, signs of material fatigue, abnormal wear, or material property changes can best be noted and assessed by having experienced people perform the detailed inspection. A relatively common problem area is the alignment of the prop mechanism, its centering and tightness. The condition of the lubricant is essential to proper operation. Inadequate lubrication is by far the dominant cause of breaker failures. Assessment of the condition of the lubricating grease should therefore be the prime objective of any inspection. Removal of arc chutes, phase barriers, inspection covers and relay/switch covers will facilitate a fairly thorough check of lubricant condition. However, the detailed inspection does not include extensive disassembly of the breaker; consequently, lubricant internal to bearings and bushings will not, in general, be accessible at the detailed inspection. Hard lubricant in thin films may not be visible at all, or may appear as a varnish-like layer. Contaminated switches and relay contacts make up a very large proportion of the failure causes and overhaul deficiencies noted in NPRDS failure events and NMAC data analysis. These contacts are not normally accessible during a visual inspection but should be more accessible at a detailed inspection when switch covers are removed. Electrical insulation and wiring is a much smaller contributor to breaker failure. In addition to visible damage to primary contacts, and deposits and tracking on arc quenching components, the arc contact tips may be damaged or broken off, and the puffer or the blowout coil may have failed. Progression of Degradation to Failure: The likelihood of damaged or failed mechanical parts and loose or missing fasteners is expected to depend on the number of operations of the breaker. This would indicate a continuous progression of these degradation mechanisms, regardless of whether they occur through normal wear, fatigue, or material property changes. Failures should occur only after a trouble free period corresponding to the OEM’s maximum recommended number of operations. A random contribution to failure times from loose fasteners is expected, but only after a similar trouble free period. If 2000 cycles is considered to be a generic OEM limit, the boundary between the template high and low duty cycle of 200 operations per year would imply that these failure causes do not require periodic inspection at low duty cycles more often than at a 10 year interval under nominal service conditions. Concern over inadequate lubrication may appear more quickly than this, in 3 to 10 years depending on service conditions. If heavy contamination of breakers with dust has occurred during the plant construction phase, or if service conditions involve high temperatures or significant dust or other contamination, e.g. salt and / or high humidity, this is likely to lead to lubrication failure in significantly less than 10 years. The lubricant can be expected to harden if a breaker is cycled scarcely at all in a period approaching 6 years. This period of inactivity would lead to a high likelihood of binding and a failure to close or open . The combination of normal operations, detailed and visual inspections, and the operability test once per operating cycle should ensure this failure cause is not encountered. Burn marks and discoloration are symptoms of overheating and may indicate degradation of electrical devices such as coils and relays. Failures of coils, relays and motor windings occur from current-time overload, although age, contamination and environmental factors may also play a part. Current-time overload occurs mainly as a result of energizing the devices for longer than the design intent and is almost always due to lubrication failure which causes the mechanism to move slowly or to seize up. Consequently the degradation mechanisms in the electrical devices themselves, which can be difficult to test for, are strongly coupled to the time scales and influences affecting lubrication. A trouble free period of operation may be expected, with burn marks and discoloration being visible signs of lubrication failure as well as indicating degraded coils and relays. Regardless of the lubricant condition, a measurement of the electrical resistance of coils and relays using an ohmmeter, if trended over time, will detect progressive failure of winding insulation and give an indication of the condition of these electrical devices. An insulation resistance test of insulation resistance to ground should be carried out on all subcomponents exposed to line potential. The condition of insulation can also be indicated by a dielectric test, recommended by Westinghouse but not frequently performed by utilities and not recommended here, owing to the possibility that the high potential may precipitate insulation breakdown. Switch and relay contact failures occur as a result of exposure to the service environment through oxidation and contamination, by wear through the plating, or from lack of contact pressure. High contact

17

resistance may develop over time although a trouble-free period of 10 years should be obtained under mild service conditions. Switch and relay contact failure may be avoided by measuring the contact resistance at the detailed inspection. A contact resistance of up to 5 ohms (not the 0.1 ohms often quoted) can be tolerated without contact failure, as the passage of current will remove the contaminating film. Lack of use may also lead to contact failure, either because the contacts are not sufficiently wiped or surface contamination is not burned through. The recommended electrical cycling of the breaker should avoid this failure cause. Deposition of metals or a variety of glass-like materials, and moisture absorption on arc quenching components may lead ultimately to a failure to quench. These degradation mechanisms are clearly dependent on the number of cycles, age, and service conditions; normal operation should lead to a trouble-free period of approximately 10 years. Large fault current interruptions should each be accompanied by an inspection of the arcing contacts and arc chutes and thus should not interfere with the expected period of failure free operation. The absorption of moisture by arc chutes can also be indicated by a power factor test. Failures of the puffer and blowout coil should not occur before 4 to 5 years and tend to be randomly spread over a wide time scale after that period has passed. The condition of the main contacts should be assessed using a ductor test with the passage of a high current to burn off contaminating films, although the ductor test is not a good indicator if the plating is damaged. Damaged plating on main contacts should be visible. The ductor test also demonstrates that neither lubrication failure nor misadjustment or normal wear are affecting the condition of the main contacts. Fault Discovery and Intervention: All of the failure mechanisms discussed above progress continuously for a period of years before the failure point is reached. The minimum duration of this wearout characteristic is usually controlled by the service conditions that affect lubrication failure. Preventive maintenance (PM) within this period can identify and intercept all the failure mechanisms excepting those due to design, manufacturing, and installation defects, and maintenance error. These are excluded from consideration here because their random nature does not lend itself to being addressed by regularly scheduled PM tasks, other than failure finding such as the operability test, trip tests, or calibration. An overhaul is necessary to completely clean out old lubricant and to renew lubricant at every point in the breaker within about 10 years for low duty cycle and mild service conditions. The detailed inspection should be performed in order to replace as much of the lubricant as possible at a shorter interval, about half the overhaul interval. In a Detailed Inspection, accessible pivot points and bearings can be lubricated, although they probably still can not be properly cleaned. Manual and electrical operation can help to distribute lubricant in all areas and mix it to prevent separation of its constituents. The “feel” of the operating mechanism during manual operation can indicate to an experienced person the general condition of the lubricant. Additionally, the time taken for the breaker to close is a direct indication of a sluggish mechanism. Asfound and as-left electrical close-timing tests may be supplemented by a trip load test or by a minimum control voltage test to detect a sluggish mechanism. If the breaker does not pass these tests a detailed inspection or overhaul will be necessary. A Detailed Inspection will typically be performed to ensure that critical breakers in severe service conditions ( e.g. high temperatures, high humidity, and salt laden air) can reach the scheduled overhaul at 8 years. In more normal conditions for critical breakers, detailed inspection can be combined in rotation with visual inspection and overhaul to provide flexibility on when the overhaul is performed (i.e. not strictly at 10 years). See Note 6 for a discussion of scheduling inspections. Calibration tasks for the protective devices, instantaneous overcurrent, timecurrent excess, overvoltage and undervoltage, as appropriate, should follow the requirements of technical specifications. These tasks help to ensure that the protective relays are not already out-of-specification (failed) when needed. Where there are no technical specification requirements the recommended period for calibration can be paired with that of the breaker detailed inspection. At this interval, experience shows that the relays are not usually sufficiently out-of-calibration to be in a failed state. Breaker Detailed Inspection should include: · Perform and record as-found electrical open/close and timing test · Perform pre-disassembly functional tests and visual inspection · Remove front covers, phase barriers (if present) and arc chutes · Replace lubricant where accessible · Generally clean and inspect all accessible parts and surfaces · Replace known parts subject to wearout or required by OEM · Verify adjustments · Perform manual operation · Inspect puffer and verify operation · Perform ductor test · Perform insulation resistance tests · Inspect for: pitting or corrosion on primary contacts; damaged, loose, or missing fasteners and setscrews; electrical tracking; cracked welds; rust or corrosion; cracked or burned arc chutes; hard lubricant; secondary control block damage or misalignment; worn or bent mechanical linkage, general cleanliness; wiring harness and protective relay damage. · Calibrate protective devices as required · Perform overcurrent trip test · Perform as-left electrical open/close and timing test Perform PM of Westinghouse DS Breakers --- Notes 2 & 3: 2.3.3 Breaker - Detailed Inspection Failure Locations and Causes: The failure locations and failure causes addressed by the Detailed Inspection are the same as those addressed by the Visual Inspection. The main difference is that the Detailed Inspection includes a far more comprehensive set of tasks designed to be an effective way to thoroughly check the operating mechanism, main current components, and the racking mechanism for: 1) mechanically failed or damaged parts, loose connections and fasteners, 2) the condition of the lubricant, to cycle the operating mechanism so as to mix and distribute the lubricant, and to provide an opportunity to add lubricant to many more pivot points and bearings including the primary contacts, 3) to check for burn marks or discoloration that might indicate overheating of electrical components such as relays, coils and switches, 4) to replace parts known to be subject to wearout, 5) to perform general cleaning, 6) to check for tracking, burn marks, or deposition of material on arc quenching components, or other damage to them, and 7) to verify adjustments and operation of subcomponents (e.g. primary contacts and plating, puffer assembly) and the integral operation of the breaker. Parts that are loose, damaged, or missing may be seen directly, often where they should not be (e.g. on the cubicle floor), even by relatively inexperienced personnel. However, signs of material fatigue, abnormal wear, or material property changes can best be noted and assessed by having experienced people perform the detailed inspection. A relatively common problem area is the alignment of the prop mechanism, its centering and tightness. The condition of the lubricant is essential to proper operation. Inadequate lubrication is by far the dominant cause of breaker failures. Assessment of the condition of the lubricating grease should therefore be the prime objective of any inspection. Removal of arc chutes, phase barriers, inspection covers and relay/switch covers will facilitate a fairly thorough check of lubricant condition. However, the detailed inspection does not include extensive disassembly of the breaker; consequently, lubricant internal to bearings and bushings will not, in general, be accessible at the detailed inspection. Hard lubricant in thin films may not be visible at all, or may appear as a varnish-like layer. Contaminated switches and relay contacts make up a very large proportion of the failure causes and overhaul deficiencies noted in NPRDS failure events and NMAC data analysis. These contacts are not normally accessible during a visual inspection but should be more accessible at a detailed inspection when switch covers are removed. Electrical insulation and wiring is a much smaller contributor to breaker failure. In addition to visible damage to primary contacts, and deposits and tracking on arc quenching components, the arc contact tips may be damaged or broken off, and the puffer or the blowout coil may have failed. Progression of Degradation to Failure: The likelihood of damaged or failed mechanical parts and loose or missing fasteners is expected to depend on the number of operations of the breaker. This would indicate a continuous progression of these degradation mechanisms, regardless of whether they occur through normal wear, fatigue, or material property changes. Failures should occur only after a trouble free period corresponding to the OEM’s maximum recommended number of operations. A random contribution to failure times from loose fasteners is expected, but only after a similar trouble free period. If 2000 cycles is considered to be a generic OEM limit, the boundary between the template high and low duty cycle of 200 operations per year would imply that these failure causes do not require periodic inspection at low duty cycles more often than at a 10 year interval under nominal service conditions. Concern over inadequate lubrication may appear more quickly than this, in 3

18

to 10 years depending on service conditions. If heavy contamination of breakers with dust has occurred during the plant construction phase, or if service conditions involve high temperatures or significant dust or other contamination, e.g. salt and / or high humidity, this is likely to lead to lubrication failure in significantly less than 10 years. The lubricant can be expected to harden if a breaker is cycled scarcely at all in a period approaching 6 years. This period of inactivity would lead to a high likelihood of binding and a failure to close or open . The combination of normal operations, detailed and visual inspections, and the operability test once per operating cycle should ensure this failure cause is not encountered. Burn marks and discoloration are symptoms of overheating and may indicate degradation of electrical devices such as coils and relays. Failures of coils, relays and motor windings occur from current-time overload, although age, contamination and environmental factors may also play a part. Current-time overload occurs mainly as a result of energizing the devices for longer than the design intent and is almost always due to lubrication failure which causes the mechanism to move slowly or to seize up. Consequently the degradation mechanisms in the electrical devices themselves, which can be difficult to test for, are strongly coupled to the time scales and influences affecting lubrication. A trouble free period of operation may be expected, with burn marks and discoloration being visible signs of lubrication failure as well as indicating degraded coils and relays. Regardless of the lubricant condition, a measurement of the electrical resistance of coils and relays using an ohmmeter, if trended over time, will detect progressive failure of winding insulation and give an indication of the condition of these electrical devices. An insulation resistance test of insulation resistance to ground should be carried out on all subcomponents exposed to line potential. The condition of insulation can also be indicated by a dielectric test, recommended by Westinghouse but not frequently performed by utilities and not recommended here, owing to the possibility that the high potential may precipitate insulation breakdown. Switch and relay contact failures occur as a result of exposure to the service environment through oxidation and contamination, by wear through the plating, or from lack of contact pressure. High contact resistance may develop over time although a trouble-free period of 10 years should be obtained under mild service conditions. Switch and relay contact failure may be avoided by measuring the contact resistance at the detailed inspection. A contact resistance of up to 5 ohms (not the 0.1 ohms often quoted) can be tolerated without contact failure, as the passage of current will remove the contaminating film. Lack of use may also lead to contact failure, either because the contacts are not sufficiently wiped or surface contamination is not burned through. The recommended electrical cycling of the breaker should avoid this failure cause. Deposition of metals or a variety of glass-like materials, and moisture absorption on arc quenching components may lead ultimately to a failure to quench. These degradation mechanisms are clearly dependent on the number of cycles, age, and service conditions; normal operation should lead to a trouble-free period of approximately 10 years. Large fault current interruptions should each be accompanied by an inspection of the arcing contacts and arc chutes and thus should not interfere with the expected period of failure free operation. The absorption of moisture by arc chutes can also be indicated by a power factor test. Failures of the puffer and blowout coil should not occur before 4 to 5 years and tend to be randomly spread over a wide time scale after that period has passed. The condition of the main contacts should be assessed using a ductor test with the passage of a high current to burn off contaminating films, although the ductor test is not a good indicator if the plating is damaged. Damaged plating on main contacts should be visible. The ductor test also demonstrates that neither lubrication failure nor misadjustment or normal wear are affecting the condition of the main contacts. Fault Discovery and Intervention: All of the failure mechanisms discussed above progress continuously for a period of years before the failure point is reached. The minimum duration of this wearout characteristic is usually controlled by the service conditions that affect lubrication failure. Preventive maintenance (PM) within this period can identify and intercept all the failure mechanisms excepting those due to design, manufacturing, and installation defects, and maintenance error. These are excluded from consideration here because their random nature does not lend itself to being addressed by regularly scheduled PM tasks, other than failure finding such as the operability test, trip tests, or calibration. An overhaul is necessary to completely clean out old lubricant and to renew lubricant at every point in the breaker within about 10 years for low duty cycle and mild service conditions. The detailed inspection should be performed in order to replace as much of the lubricant as possible at a shorter interval, about half the overhaul interval. In a Detailed Inspection, accessible pivot points and bearings can be lubricated, although they probably still can not be properly cleaned. Manual and electrical operation can help to distribute lubricant in all areas and mix it to prevent separation of its constituents. The “feel” of the operating mechanism during manual operation can indicate to an experienced person the general condition of the lubricant. Additionally, the time taken for the breaker to close is a direct indication of a sluggish mechanism. Asfound and as-left electrical close-timing tests may be supplemented by a trip load test or by a minimum control voltage test to detect a sluggish mechanism. If the breaker does not pass these tests a detailed inspection or overhaul will be necessary. A Detailed Inspection will typically be performed to ensure that critical breakers in severe service conditions ( e.g. high temperatures, high humidity, and salt laden air) can reach the scheduled overhaul at 8 years. In more normal conditions for critical breakers, detailed inspection can be combined in rotation with visual inspection and overhaul to provide flexibility on when the overhaul is performed (i.e. not strictly at 10 years). See Note 6 for a discussion of scheduling inspections. Calibration tasks for the protective devices, instantaneous overcurrent, timecurrent excess, overvoltage and undervoltage, as appropriate, should follow the requirements of technical specifications. These tasks help to ensure that the protective relays are not already out-of-specification (failed) when needed. Where there are no technical specification requirements the recommended period for calibration can be paired with that of the breaker detailed inspection. At this interval, experience shows that the relays are not usually sufficiently out-of-calibration to be in a failed state. Breaker Detailed Inspection should include: · Perform and record as-found electrical open/close and timing test · Perform pre-disassembly functional tests and visual inspection · Remove front covers, phase barriers (if present) and arc chutes · Replace lubricant where accessible · Generally clean and inspect all accessible parts and surfaces · Replace known parts subject to wearout or required by OEM · Verify adjustments · Perform manual operation · Inspect puffer and verify operation · Perform ductor test · Perform insulation resistance tests · Inspect for: pitting or corrosion on primary contacts; damaged, loose, or missing fasteners and setscrews; electrical tracking; cracked welds; rust or corrosion; cracked or burned arc chutes; hard lubricant; secondary control block damage or misalignment; worn or bent mechanical linkage, general cleanliness; wiring harness and protective relay damage. · Calibrate protective devices as required · Perform overcurrent trip test · Perform as-left electrical open/close and timing test Perform PM of ABB Breaker --- Notes 2 & 4 : 2.3.3 Breaker - Detailed Inspection Failure Locations and Causes: The failure locations and failure causes addressed by the Detailed Inspection are the same as those addressed by the Visual Inspection. The main difference is that the Detailed Inspection includes a far more comprehensive set of tasks designed to be an effective way to thoroughly check the operating mechanism, main current components, and the racking mechanism for: 1) mechanically failed or damaged parts, loose connections and fasteners, 2) the condition of the lubricant, to cycle the operating mechanism so as to mix and distribute the lubricant, and to provide an opportunity to add lubricant to many more pivot points and bearings including the primary contacts, 3) to check for burn marks or discoloration that might indicate overheating of electrical components such as relays, coils and switches, 4) to replace parts known to be subject to wearout, 5) to perform general cleaning, 6) to check for tracking, burn marks, or deposition of material on arc quenching components, or other damage to them, and 7) to verify adjustments and operation of subcomponents (e.g. primary contacts and plating, puffer assembly) and the integral operation of the breaker. Parts that are loose, damaged, or missing may be seen directly, often where they should not be (e.g. on the cubicle floor), even by relatively inexperienced personnel. However, signs of material fatigue, abnormal wear, or material property changes can best be noted and assessed by having experienced people perform the detailed

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inspection. A relatively common problem area is the alignment of the prop mechanism, its centering and tightness. The condition of the lubricant is essential to proper operation. Inadequate lubrication is by far the dominant cause of breaker failures. Assessment of the condition of the lubricating grease should therefore be the prime objective of any inspection. Removal of arc chutes, phase barriers, inspection covers and relay/switch covers will facilitate a fairly thorough check of lubricant condition. However, the detailed inspection does not include extensive disassembly of the breaker; consequently, lubricant internal to bearings and bushings will not, in general, be accessible at the detailed inspection. Hard lubricant in thin films may not be visible at all, or may appear as a varnish-like layer. Contaminated switches and relay contacts make up a very large proportion of the failure causes and overhaul deficiencies noted in NPRDS failure events and NMAC data analysis. These contacts are not normally accessible during a visual inspection but should be more accessible at a detailed inspection when switch covers are removed. Electrical insulation and wiring is a much smaller contributor to breaker failure. In addition to visible damage to primary contacts, and deposits and tracking on arc quenching components, the arc contact tips may be damaged or broken off, and the puffer or the blowout coil may have failed. Progression of Degradation to Failure: The likelihood of damaged or failed mechanical parts and loose or missing fasteners is expected to depend on the number of operations of the breaker. This would indicate a continuous progression of these degradation mechanisms, regardless of whether they occur through normal wear, fatigue, or material property changes. Failures should occur only after a trouble free period corresponding to the OEM’s maximum recommended number of operations. A random contribution to failure times from loose fasteners is expected, but only after a similar trouble free period. If 2000 cycles is considered to be a generic OEM limit, the boundary between the template high and low duty cycle of 200 operations per year would imply that these failure causes do not require periodic inspection at low duty cycles more often than at a 10 year interval under nominal service conditions. Concern over inadequate lubrication may appear more quickly than this, in 3 to 10 years depending on service conditions. If heavy contamination of breakers with dust has occurred during the plant construction phase, or if service conditions involve high temperatures or significant dust or other contamination, e.g. salt and / or high humidity, this is likely to lead to lubrication failure in significantly less than 10 years. The lubricant can be expected to harden if a breaker is cycled scarcely at all in a period approaching 6 years. This period of inactivity would lead to a high likelihood of binding and a failure to close or open . The combination of normal operations, detailed and visual inspections, and the operability test once per operating cycle should ensure this failure cause is not encountered. Burn marks and discoloration are symptoms of overheating and may indicate degradation of electrical devices such as coils and relays. Failures of coils, relays and motor windings occur from current-time overload, although age, contamination and environmental factors may also play a part. Current-time overload occurs mainly as a result of energizing the devices for longer than the design intent and is almost always due to lubrication failure which causes the mechanism to move slowly or to seize up. Consequently the degradation mechanisms in the electrical devices themselves, which can be difficult to test for, are strongly coupled to the time scales and influences affecting lubrication. A trouble free period of operation may be expected, with burn marks and discoloration being visible signs of lubrication failure as well as indicating degraded coils and relays. Regardless of the lubricant condition, a measurement of the electrical resistance of coils and relays using an ohmmeter, if trended over time, will detect progressive failure of winding insulation and give an indication of the condition of these electrical devices. An insulation resistance test of insulation resistance to ground should be carried out on all subcomponents exposed to line potential. The condition of insulation can also be indicated by a dielectric test, recommended by Westinghouse but not frequently performed by utilities and not recommended here, owing to the possibility that the high potential may precipitate insulation breakdown. Switch and relay contact failures occur as a result of exposure to the service environment through oxidation and contamination, by wear through the plating, or from lack of contact pressure. High contact resistance may develop over time although a trouble-free period of 10 years should be obtained under mild service conditions. Switch and relay contact failure may be avoided by measuring the contact resistance at the detailed inspection. A contact resistance of up to 5 ohms (not the 0.1 ohms often quoted) can be tolerated without contact failure, as the passage of current will remove the contaminating film. Lack of use may also lead to contact failure, either because the contacts are not sufficiently wiped or surface contamination is not burned through. The recommended electrical cycling of the breaker should avoid this failure cause. Deposition of metals or a variety of glass-like materials, and moisture absorption on arc quenching components may lead ultimately to a failure to quench. These degradation mechanisms are clearly dependent on the number of cycles, age, and service conditions; normal operation should lead to a trouble-free period of approximately 10 years. Large fault current interruptions should each be accompanied by an inspection of the arcing contacts and arc chutes and thus should not interfere with the expected period of failure free operation. The absorption of moisture by arc chutes can also be indicated by a power factor test. Failures of the puffer and blowout coil should not occur before 4 to 5 years and tend to be randomly spread over a wide time scale after that period has passed. The condition of the main contacts should be assessed using a ductor test with the passage of a high current to burn off contaminating films, although the ductor test is not a good indicator if the plating is damaged. Damaged plating on main contacts should be visible. The ductor test also demonstrates that neither lubrication failure nor misadjustment or normal wear are affecting the condition of the main contacts. Fault Discovery and Intervention: All of the failure mechanisms discussed above progress continuously for a period of years before the failure point is reached. The minimum duration of this wearout characteristic is usually controlled by the service conditions that affect lubrication failure. Preventive maintenance (PM) within this period can identify and intercept all the failure mechanisms excepting those due to design, manufacturing, and installation defects, and maintenance error. These are excluded from consideration here because their random nature does not lend itself to being addressed by regularly scheduled PM tasks, other than failure finding such as the operability test, trip tests, or calibration. An overhaul is necessary to completely clean out old lubricant and to renew lubricant at every point in the breaker within about 10 years for low duty cycle and mild service conditions. The detailed inspection should be performed in order to replace as much of the lubricant as possible at a shorter interval, about half the overhaul interval. In a Detailed Inspection, accessible pivot points and bearings can be lubricated, although they probably still can not be properly cleaned. Manual and electrical operation can help to distribute lubricant in all areas and mix it to prevent separation of its constituents. The “feel” of the operating mechanism during manual operation can indicate to an experienced person the general condition of the lubricant. Additionally, the time taken for the breaker to close is a direct indication of a sluggish mechanism. Asfound and as-left electrical close-timing tests may be supplemented by a trip load test or by a minimum control voltage test to detect a sluggish mechanism. If the breaker does not pass these tests a detailed inspection or overhaul will be necessary. A Detailed Inspection will typically be performed to ensure that critical breakers in severe service conditions ( e.g. high temperatures, high humidity, and salt laden air) can reach the scheduled overhaul at 8 years. In more normal conditions for critical breakers, detailed inspection can be combined in rotation with visual inspection and overhaul to provide flexibility on when the overhaul is performed (i.e. not strictly at 10 years). See Note 6 for a discussion of scheduling inspections. Calibration tasks for the protective devices, instantaneous overcurrent, timecurrent excess, overvoltage and undervoltage, as appropriate, should follow the requirements of technical specifications. These tasks help to ensure that the protective relays are not already out-of-specification (failed) when needed. Where there are no technical specification requirements the recommended period for calibration can be paired with that of the breaker detailed inspection. At this interval, experience shows that the relays are not usually sufficiently out-of-calibration to be in a failed state. Breaker Detailed Inspection should include: · Perform and record as-found electrical open/close and timing test · Perform pre-disassembly functional tests and visual inspection · Remove front covers, phase barriers (if present) and arc chutes · Replace lubricant where accessible · Generally clean and inspect all accessible parts and surfaces · Replace known parts subject to wearout or required by OEM · Verify adjustments · Perform

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manual operation · Inspect puffer and verify operation · Perform ductor test · Perform insulation resistance tests · Inspect for: pitting or corrosion on primary contacts; damaged, loose, or missing fasteners and setscrews; electrical tracking; cracked welds; rust or corrosion; cracked or burned arc chutes; hard lubricant; secondary control block damage or misalignment; worn or bent mechanical linkage, general cleanliness; wiring harness and protective relay damage. · Calibrate protective devices as required · Perform overcurrent trip test · Perform as-left electrical open/close and timing test Overhaul GE Breaker: 2.3.4 Breaker - Overhaul The failure locations and failure causes addressed by the Overhaul are the same as those addressed by the Detailed Inspection. However, in an overhaul the breaker is completely dissassembled to give access to all parts for cleaning, inspection for damage and wear, and complete replacement of lubricant. Failure to do this results in wearout of the lubricant in parts inaccessible to the detailed inspection. In addition, an overhaul parts replacement kit should be used for small mechanical items like retainers, washers, nuts and bolts, bushings, gaskets and springs. Individual subcomponent replacement depending on make and model may also be necessary. The NMAC maintenance guides for low voltage circuit breakers and the appropriate vendor manuals should be consulted for parts to replace at the overhaul. Calibration tasks for the protective devices, instantaneous overcurrent, time-current excess, overvoltage and undervoltage, as appropriate, should follow the requirements of technical specifications. These tasks help to ensure that the protective relays are not already out-of-specification (failed) when needed. Where there are no technical specification requirements the recommended period for calibration can be paired with that of the breaker overhaul. At this interval, experience shows that the relays are not usually sufficiently out-of-calibration to be in a failed state. Breaker overhaul should include: · Perform and record as-found electrical open/close and timing test · Perform pre-disassembly functional tests and visual inspection-Complete disassembly of the breaker · Clean parts, visually inspect, measure, and record data on wearable parts · Replace parts (normal replacement as indicated by OEM or as indicated by historical records), including control fuses · Replace lubricant · Generally clean and inspect all parts and surfaces · Inspect puffer and verify operation · Perform ductor test · Perform insulation resistance tests · Inspect for: pitting or corrosion on primary contacts; damaged, loose, or missing fasteners and setscrews; electrical tracking; cracked welds; rust or corrosion; cracked or burned arc chutes; hard lubricant; secondary control block damage or misalignment; worn or bent mechanical linkage, general cleanliness; wiring harness and protective relay damage. · Calibrate protective devices · Perform overcurrent trip test · Perform and record as-left electrical open/close and timing test Overhaul Westinghouse DS and DB Breaker: 2.3.4 Breaker - Overhaul The failure locations and failure causes addressed by the Overhaul are the same as those addressed by the Detailed Inspection. However, in an overhaul the breaker is completely dissassembled to give access to all parts for cleaning, inspection for damage and wear, and complete replacement of lubricant. Failure to do this results in wearout of the lubricant in parts inaccessible to the detailed inspection. In addition, an overhaul parts replacement kit should be used for small mechanical items like retainers, washers, nuts and bolts, bushings, gaskets and springs. Individual subcomponent replacement depending on make and model may also be necessary. The NMAC maintenance guides for low voltage circuit breakers and the appropriate vendor manuals should be consulted for parts to replace at the overhaul. Calibration tasks for the protective devices, instantaneous overcurrent, time-current excess, overvoltage and undervoltage, as appropriate, should follow the requirements of technical specifications. These tasks help to ensure that the protective relays are not already out-of-specification (failed) when needed. Where there are no technical specification requirements the recommended period for calibration can be paired with that of the breaker overhaul. At this interval, experience shows that the relays are not usually sufficiently out-of-calibration to be in a failed state. Breaker overhaul should include: · Perform and record as-found electrical open/close and timing test · Perform pre-disassembly functional tests and visual inspection-Complete disassembly of the breaker · Clean parts, visually inspect, measure, and record data on wearable parts · Replace parts (normal replacement as indicated by OEM or as indicated by historical records), including control fuses · Replace lubricant · Generally clean and inspect all parts and surfaces · Inspect puffer and verify operation · Perform ductor test · Perform insulation resistance tests · Inspect for: pitting or corrosion on primary contacts; damaged, loose, or missing fasteners and setscrews; electrical tracking; cracked welds; rust or corrosion; cracked or burned arc chutes; hard lubricant; secondary control block damage or misalignment; worn or bent mechanical linkage, general cleanliness; wiring harness and protective relay damage. · Calibrate protective devices · Perform overcurrent trip test · Perform and record as-left electrical open/close and timing test Overhaul ABB Breaker --- Note 4: 2.3.4 Breaker - Overhaul The failure locations and failure causes addressed by the Overhaul are the same as those addressed by the Detailed Inspection. However, in an overhaul the breaker is completely dissassembled to give access to all parts for cleaning, inspection for damage and wear, and complete replacement of lubricant. Failure to do this results in wearout of the lubricant in parts inaccessible to the detailed inspection. In addition, an overhaul parts replacement kit should be used for small mechanical items like retainers, washers, nuts and bolts, bushings, gaskets and springs. Individual subcomponent replacement depending on make and model may also be necessary. The NMAC maintenance guides for low voltage circuit breakers and the appropriate vendor manuals should be consulted for parts to replace at the overhaul. Calibration tasks for the protective devices, instantaneous overcurrent, time-current excess, overvoltage and undervoltage, as appropriate, should follow the requirements of technical specifications. These tasks help to ensure that the protective relays are not already out-of-specification (failed) when needed. Where there are no technical specification requirements the recommended period for calibration can be paired with that of the breaker overhaul. At this interval, experience shows that the relays are not usually sufficiently out-of-calibration to be in a failed state. Breaker overhaul should include: · Perform and record as-found electrical open/close and timing test · Perform pre-disassembly functional tests and visual inspectionComplete disassembly of the breaker · Clean parts, visually inspect, measure, and record data on wearable parts · Replace parts (normal replacement as indicated by OEM or as indicated by historical records), including control fuses · Replace lubricant · Generally clean and inspect all parts and surfaces · Inspect puffer and verify operation · Perform ductor test · Perform insulation resistance tests · Inspect for: pitting or corrosion on primary contacts; damaged, loose, or missing fasteners and setscrews; electrical tracking; cracked welds; rust or corrosion; cracked or burned arc chutes; hard lubricant; secondary control block damage or misalignment; worn or bent mechanical linkage, general cleanliness; wiring harness and protective relay damage. · Calibrate protective devices · Perform overcurrent trip test · Perform and record as-left electrical open/close and timing test Perform PM on switchgear breaker cubicles (GE) --- Note 1: 2.3.5 Cubicle - Detailed Inspection Failure Locations and Causes: The racking mechanism is subject to lubrication failure, damaged and failed parts, and loose or missing fasteners. Inadequate lubrication is an important cause of failures in the cubicle as it was in the breaker, although the consequences are more likely to be extended maintenance time rather than a critical event such as breaker failure to close or to trip. Assessment of the condition of the lubricating grease should be the prime objective of a cubicle inspection. A visual check of the lubricant at accessible, and hence more frequently lubricated points, should be done but will not provide a reliable assessment of its condition at other points, such as bushings and bearings, which can only be lubricated at overhaul. Hard lubricant in thin films may not be visible at all, or may appear as a varnish-like layer. Parts that are loose, damaged, or missing may be seen directly, often where they should not be, even by relatively inexperienced personnel. However, signs of

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material fatigue, abnormal wear, or material property changes can best be noted and assessed by having experienced people perform the inspection. Relatively common problem areas are the alignment of the breaker interface with the cubicle, and alignment problems causing damage to contacts, and to primary and secondary disconnects and switches. Progression of Degradation to Failure: The aging of the lubricant is continuous in time and dependent on contamination, time, and temperature as it was for the breaker itself. Apart from heavy contamination which might have occurred during initial construction or during subsequent room maintenance, a failure free period of up to 10 years should be expected. Heavy contamination or extreme service conditions might shorten this period to as little as 2 years. Complete inactivity, i.e. where the racking mechanism is not actuated at all may lead to binding of the mechanism in as little as 3 to 5 years or as much as 8 to 10 years depending on the lubricant that has been used. Visual inspection and ease of operation are the methods available to detect aging of the lubricant. Since no disassembly is contemplated for this inspection only accessible points should be lubricated. Lubricant on primary contact stabs should also be replaced. The degradation mechanisms that lead to damaged and failed parts as well as to loose or missing fasteners will proceed continuously with the number of operations of the mechanism assuming no damage is caused by maintenance personnel in the process of racking the breaker in and out. Such damage has occurred often in the industry but is random in occurrence and should be controlled through training, not preventive maintenance. However, cubicle inspections should inspect for signs of such damage. The expected failure free period for these degradation mechanisms probably exceeds that for lubrication failure as quoted above. Fault Discovery and Intervention: The Cubicle Detailed Inspection may not be carried out at the same time as the Breaker Detailed Inspection, although it may be convenient to synchronize the inspections and overhauls. Inspection of buswork will be visual and by thermography as described in the thermography task for breaker and cubicle. Line and load side insulation should be visually inspected and have its insulation resistance tested. Cubicle Detailed Inspection should include: · Racking mechanism inspection and lubrication (where accessible with no major disassembly) · Breaker to cubicle interface measurements and adjustment · Bus-work inspection including joints, covers and insulation · Inspection of primary disconnects Cubicle Detailed Inspection should include: continued · Inspection of control wiring for fretting, wear, and damaged insulation, replace fuses · Inspection of shutters and switch interlocks · Inspection of fasteners for looseness and welds for cracking · Inspection and test of the CTs and PTs Cubicle Detailed Inspection should include: continued · Inspection of secondary contacts and disconnects · Inspect load side cables · Fuse drawer inspection (e.g. cleanliness, finger alignment, connections) Perform PM on switchgear breaker cubicles (West DB): 2.3.5 Cubicle - Detailed Inspection Failure Locations and Causes: The racking mechanism is subject to lubrication failure, damaged and failed parts, and loose or missing fasteners. Inadequate lubrication is an important cause of failures in the cubicle as it was in the breaker, although the consequences are more likely to be extended maintenance time rather than a critical event such as breaker failure to close or to trip. Assessment of the condition of the lubricating grease should be the prime objective of a cubicle inspection. A visual check of the lubricant at accessible, and hence more frequently lubricated points, should be done but will not provide a reliable assessment of its condition at other points, such as bushings and bearings, which can only be lubricated at overhaul. Hard lubricant in thin films may not be visible at all, or may appear as a varnish-like layer. Parts that are loose, damaged, or missing may be seen directly, often where they should not be, even by relatively inexperienced personnel. However, signs of material fatigue, abnormal wear, or material property changes can best be noted and assessed by having experienced people perform the inspection. Relatively common problem areas are the alignment of the breaker interface with the cubicle, and alignment problems causing damage to contacts, and to primary and secondary disconnects and switches. Progression of Degradation to Failure: The aging of the lubricant is continuous in time and dependent on contamination, time, and temperature as it was for the breaker itself. Apart from heavy contamination which might have occurred during initial construction or during subsequent room maintenance, a failure free period of up to 10 years should be expected. Heavy contamination or extreme service conditions might shorten this period to as little as 2 years. Complete inactivity, i.e. where the racking mechanism is not actuated at all may lead to binding of the mechanism in as little as 3 to 5 years or as much as 8 to 10 years depending on the lubricant that has been used. Visual inspection and ease of operation are the methods available to detect aging of the lubricant. Since no disassembly is contemplated for this inspection only accessible points should be lubricated. Lubricant on primary contact stabs should also be replaced. The degradation mechanisms that lead to damaged and failed parts as well as to loose or missing fasteners will proceed continuously with the number of operations of the mechanism assuming no damage is caused by maintenance personnel in the process of racking the breaker in and out. Such damage has occurred often in the industry but is random in occurrence and should be controlled through training, not preventive maintenance. However, cubicle inspections should inspect for signs of such damage. The expected failure free period for these degradation mechanisms probably exceeds that for lubrication failure as quoted above. Fault Discovery and Intervention: The Cubicle Detailed Inspection may not be carried out at the same time as the Breaker Detailed Inspection, although it may be convenient to synchronize the inspections and overhauls. Inspection of buswork will be visual and by thermography as described in the thermography task for breaker and cubicle. Line and load side insulation should be visually inspected and have its insulation resistance tested. Cubicle Detailed Inspection should include: · Racking mechanism inspection and lubrication (where accessible with no major disassembly) · Breaker to cubicle interface measurements and adjustment · Bus-work inspection including joints, covers and insulation · Inspection of primary disconnects Cubicle Detailed Inspection should include: continued · Inspection of control wiring for fretting, wear, and damaged insulation, replace fuses · Inspection of shutters and switch interlocks · Inspection of fasteners for looseness and welds for cracking · Inspection and test of the CTs and PTs Cubicle Detailed Inspection should include: continued · Inspection of secondary contacts and disconnects · Inspect load side cables · Fuse drawer inspection (e.g. cleanliness, finger alignment, connections) Perform PM on switchgear breaker cubicles (West DS): 2.3.5 Cubicle - Detailed Inspection Failure Locations and Causes: The racking mechanism is subject to lubrication failure, damaged and failed parts, and loose or missing fasteners. Inadequate lubrication is an important cause of failures in the cubicle as it was in the breaker, although the consequences are more likely to be extended maintenance time rather than a critical event such as breaker failure to close or to trip. Assessment of the condition of the lubricating grease should be the prime objective of a cubicle inspection. A visual check of the lubricant at accessible, and hence more frequently lubricated points, should be done but will not provide a reliable assessment of its condition at other points, such as bushings and bearings, which can only be lubricated at overhaul. Hard lubricant in thin films may not be visible at all, or may appear as a varnish-like layer. Parts that are loose, damaged, or missing may be seen directly, often where they should not be, even by relatively inexperienced personnel. However, signs of material fatigue, abnormal wear, or material property changes can best be noted and assessed by having experienced people perform the inspection. Relatively common problem areas are the alignment of the breaker interface with the cubicle, and alignment problems causing damage to contacts, and to primary and secondary disconnects and switches. Progression of Degradation to Failure: The aging of the lubricant is continuous in time and dependent on contamination, time, and temperature as it was for the breaker itself. Apart from heavy contamination which might have occurred during initial construction or during subsequent room maintenance, a failure free period of up to 10 years should be expected. Heavy contamination or extreme service conditions might shorten this period to as little as 2 years. Complete inactivity, i.e. where the racking mechanism is not actuated at all may lead to binding of the mechanism in as little as 3 to 5 years or as much as 8 to 10 years depending on the lubricant that has been used. Visual inspection and ease of operation are the

22

methods available to detect aging of the lubricant. Since no disassembly is contemplated for this inspection only accessible points should be lubricated. Lubricant on primary contact stabs should also be replaced. The degradation mechanisms that lead to damaged and failed parts as well as to loose or missing fasteners will proceed continuously with the number of operations of the mechanism assuming no damage is caused by maintenance personnel in the process of racking the breaker in and out. Such damage has occurred often in the industry but is random in occurrence and should be controlled through training, not preventive maintenance. However, cubicle inspections should inspect for signs of such damage. The expected failure free period for these degradation mechanisms probably exceeds that for lubrication failure as quoted above. Fault Discovery and Intervention: The Cubicle Detailed Inspection may not be carried out at the same time as the Breaker Detailed Inspection, although it may be convenient to synchronize the inspections and overhauls. Inspection of buswork will be visual and by thermography as described in the thermography task for breaker and cubicle. Line and load side insulation should be visually inspected and have its insulation resistance tested. Cubicle Detailed Inspection should include: · Racking mechanism inspection and lubrication (where accessible with no major disassembly) · Breaker to cubicle interface measurements and adjustment · Bus-work inspection including joints, covers and insulation · Inspection of primary disconnects Cubicle Detailed Inspection should include: continued · Inspection of control wiring for fretting, wear, and damaged insulation, replace fuses · Inspection of shutters and switch interlocks · Inspection of fasteners for looseness and welds for cracking · Inspection and test of the CTs and PTs Cubicle Detailed Inspection should include: continued · Inspection of secondary contacts and disconnects · Inspect load side cables · Fuse drawer inspection (e.g. cleanliness, finger alignment, connections) Perform PM on switchgear breaker cubicles (ABB) --- Note 4: 2.3.5 Cubicle - Detailed Inspection Failure Locations and Causes: The racking mechanism is subject to lubrication failure, damaged and failed parts, and loose or missing fasteners. Inadequate lubrication is an important cause of failures in the cubicle as it was in the breaker, although the consequences are more likely to be extended maintenance time rather than a critical event such as breaker failure to close or to trip. Assessment of the condition of the lubricating grease should be the prime objective of a cubicle inspection. A visual check of the lubricant at accessible, and hence more frequently lubricated points, should be done but will not provide a reliable assessment of its condition at other points, such as bushings and bearings, which can only be lubricated at overhaul. Hard lubricant in thin films may not be visible at all, or may appear as a varnish-like layer. Parts that are loose, damaged, or missing may be seen directly, often where they should not be, even by relatively inexperienced personnel. However, signs of material fatigue, abnormal wear, or material property changes can best be noted and assessed by having experienced people perform the inspection. Relatively common problem areas are the alignment of the breaker interface with the cubicle, and alignment problems causing damage to contacts, and to primary and secondary disconnects and switches. Progression of Degradation to Failure: The aging of the lubricant is continuous in time and dependent on contamination, time, and temperature as it was for the breaker itself. Apart from heavy contamination which might have occurred during initial construction or during subsequent room maintenance, a failure free period of up to 10 years should be expected. Heavy contamination or extreme service conditions might shorten this period to as little as 2 years. Complete inactivity, i.e. where the racking mechanism is not actuated at all may lead to binding of the mechanism in as little as 3 to 5 years or as much as 8 to 10 years depending on the lubricant that has been used. Visual inspection and ease of operation are the methods available to detect aging of the lubricant. Since no disassembly is contemplated for this inspection only accessible points should be lubricated. Lubricant on primary contact stabs should also be replaced. The degradation mechanisms that lead to damaged and failed parts as well as to loose or missing fasteners will proceed continuously with the number of operations of the mechanism assuming no damage is caused by maintenance personnel in the process of racking the breaker in and out. Such damage has occurred often in the industry but is random in occurrence and should be controlled through training, not preventive maintenance. However, cubicle inspections should inspect for signs of such damage. The expected failure free period for these degradation mechanisms probably exceeds that for lubrication failure as quoted above. Fault Discovery and Intervention: The Cubicle Detailed Inspection may not be carried out at the same time as the Breaker Detailed Inspection, although it may be convenient to synchronize the inspections and overhauls. Inspection of buswork will be visual and by thermography as described in the thermography task for breaker and cubicle. Line and load side insulation should be visually inspected and have its insulation resistance tested. Cubicle Detailed Inspection should include: · Racking mechanism - inspection and lubrication (where accessible with no major disassembly) · Breaker to cubicle interface measurements and adjustment · Bus-work inspection including joints, covers and insulation · Inspection of primary disconnects Cubicle Detailed Inspection should include: continued · Inspection of control wiring for fretting, wear, and damaged insulation, replace fuses · Inspection of shutters and switch interlocks · Inspection of fasteners for looseness and welds for cracking · Inspection and test of the CTs and PTs Cubicle Detailed Inspection should include: continued · Inspection of secondary contacts and disconnects · Inspect load side cables · Fuse drawer inspection (e.g. cleanliness, finger alignment, connections) Perform PM on switchgear bus (GE): No Basis Available At This Time Perform PM on switchgear bus (West): No Basis Available At This Time Perform PM on switchgear bus (ABB): No Basis At This Time

23

Medium Voltage Circuit Breakers Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe Mild

X X

X

5

6

7

8

X

X

X

X

X X

X

X X

X

X X

X

X

X

X

Time Directed Task

Perform PM of GE Breaker Note 1

Perform PM of Merlin Gerin Breaker

Perform PM of Westinghouse Breaker Note 1

4Y 4Y

6Y 6Y

5Y 5Y

5Y 5Y

3Y 3Y

6Y 6Y

Failure Codes

Comments

CN DA LC SC

Lubricate breaker and perform adjustments in accordance with MA-AB-725111 (Vertical) and MA-AB725-113 (Horizontal) Basis: EPRI TR-106857-V2 Section 2.3.3

CN DA LC SC

Lubricate breaker and perform adjustments in accordance with MA-AB-725114 (SBO) and MA-AB-725117 (AMHG) Basis: EPRI TR106857-V2 Section 2.3.3

CN DA LC SC

Lubricate breaker and perform adjustments in accordance with procedure MA-AA-725-102 and MA-AA723-401 Basis: EPRI TR106857-V2 Section 2.3.3

4Y 4Y

6Y 6Y

CN DA LC SC

Lubricate breaker and perform adjustments in accordance with OEM documents and NMAC guidelines EPRI TR-106857V2 Section 2.3.3

Overhaul GE Breaker

16Y

16Y

AG CN DA DL LC SC

Disassemble and rebuild as necessary. EPRI TR-106857V2 Section 2.3.4

Overhaul Merlin-Gerin Breaker

16Y

16Y

AG CN DA DL LC SC

Disassemble and rebuild as necessary. EPRI TR-106857V2 Section 2.3.4

Overhaul Westinghouse Breaker

16Y

16Y

AG CN DA DL LC SC

Disassemble and rebuild as necessary. EPRI TR-106857V2 Section 2.3.4

Overhaul ABB Breaker

10Y

12Y

AG CN DA DL LC SC

Disassemble and rebuild as necessary. EPRI TR-106857V2 Section 2.3.4

Perform PM of ABB Breaker Note 1

Perform PM on switchgear breaker cubicles (GE)

4Y 4Y

6Y 6Y DA LC

Clean/Inspect, check breaker to cubicle interface EPRI TR106857-V2 Note 2.3.5

Perform PM on switchgear breaker cubicles (West)

3Y 3Y

6Y 6Y DA LC

Clean/inspect, check breaker to cubicle interface MA-AAEM-5-00103 EPRI TR-106857V2 Note 2.3.5

Perform PM on switchgear breaker cubicles (ABB)

4Y 4Y

6Y 6Y DA LC

Clean/Inspect, check breaker to cubicle interfaces EPRI TR106857-V2 Note 2.3.5

Perform PM on switchgear bus (GE)

10Y

12Y DA LC

Clean/Inspect, check accesible bus connections

Perform PM on switchgear bus (West)

6Y

12Y DA LC

Clean/Inspect, check

24

accesible bus connections Cleant/Inspect check accessible bus connections Note 1: EPRI NMAC Guidance documents are: NP-7410-V2-P1 and TR-109642 (ABB HK Breakers) NP-7410-V2-P2 and TR109641 (GE Magne-Blast Breakers) NP-7410-V2-P3 and 1002758 (West DH and DHP Breakers)

Perform PM on switchgear bus (ABB)

8Y

12Y DA LC

 This template is the controlled revision. SME Summary No SME Summary Available At This Time Boundary Definition The boundary of a Medium Voltage Switchgear for the purpose of this database is defined to include the switchgear enclosure, circuit breaker, protective devices, and their accessories, as follows: · Switchgear enclosure including racking mechanism, busbar and insulation, cabinets, interlocks and switches, lightning arrestors, bus PTs (potential transformer) and bus CTs (current transformer), load CTs, reactor (if present), and control wiring. · Circuit breaker including racking mechanism (if attached to the circuit breaker), truck, operating mechanism, main current components, arc chutes or arc quenching devices including vacuum bottles, and auxiliary switches and contacts. · Electrical devices such as control wiring, switches (e.g. auxiliary switches, control relay, trip coils), and local metering.

Basis For Template Tasks Perform PM of GE Breaker Note 1 : 2.3.3 Breaker - Detailed Inspection Failure Locations and Causes: The failure locations and failure causes addressed by the Detailed Inspection are the same as those addressed by the Visual Inspection. The main difference is that the Detailed Inspection includes a far more comprehensive set of tasks designed to be an effective way to thoroughly check the operating mechanism, main current components, and the racking mechanism for: 1) mechanically failed or damaged parts, loose connections and fasteners, worn bushings and bearings, worn bushings and bearings, 2) the condition of the lubricant, to cycle the operating mechanism so as to mix and distribute the lubricant, to provide an opportunity to add lubricant to many more pivot points and bearings including the primary contacts, and to refresh lubricant in other areas (GE), 3) to check for burn marks or discoloration that might indicate overheating of electrical components such as relays, coils and switches, 4) to replace parts known to be subject to wearout (e.g. GE microswitches), 5) to perform general cleaning, 6) to check for tracking, burn marks, or deposition of material on arc quenching components, or other damage to them, and 7) to verify adjustments and operation of subcomponents (e.g. primary contacts and plating, puffer assembly) and the integral operation of the breaker. Parts that are loose, damaged, or missing may be seen directly, often where they should not be (e.g. on the cubicle floor), even by relatively inexperienced personnel. However, signs of material fatigue, abnormal wear (e.g. worn bushings), or material property changes can best be noted and assessed by having experienced people perform the detailed inspection. A relatively common problem area is the alignment of the prop mechanism, its centering and tightness. The condition of the lubricant is essential to proper operation. Inadequate lubrication is by far the dominant cause of breaker failures. Assessment of the condition of the lubricating grease should therefore be the prime objective of any inspection. Removal of arc chutes, phase barriers, inspection covers and relay/switch covers will facilitate a fairly thorough check of lubricant condition. However, the detailed inspection does not include extensive disassembly of the breaker; consequently, lubricant internal to bearings and bushings will not, in general, be accessible at the detailed inspection. Hard lubricant in thin films may not be visible at all, or may appear as a varnish-like layer. Contaminated switches and relay contacts make up a very large proportion of the failure causes and overhaul deficiencies noted in NPRDS failure events and NMAC data analysis. These contacts are not normally accessible during a visual inspection but should be more accessible at a detailed inspection when switch covers are removed. Electrical insulation and wiring is a much smaller contributor to breaker failure. In addition to visible damage to primary contacts, and deposits and tracking on arc quenching components, the arc contact tips may be damaged or broken off, and the puffer or the blowout coil may have failed. Progression of Degradation to Failure: The likelihood of damaged or failed mechanical parts and loose or missing fasteners is expected to depend on the number of operations of the breaker. This would indicate a continuous progression of these degradation mechanisms, regardless of whether they occur through normal wear, fatigue, or material property changes. Failures should occur only after a trouble free period corresponding to the OEM’s maximum recommended number of operations. A random contribution to failure times from loose fasteners is expected, but only after a similar trouble free period. If 2000 cycles is considered to be a generic OEM limit, the boundary between the template high and low duty cycle of 200 operations per year would imply that these failure causes do not require periodic inspection at low duty cycles more often than at a 10 year interval under nominal service conditions. Concern over inadequate lubrication may appear more quickly than this, in 3 to 10 years depending on service conditions. If heavy contamination of breakers with dust has occurred during the plant construction phase, or if service conditions involve high temperatures or significant dust or other contamination, e.g. salt and/or high humidity, this is likely to lead to lubrication failure in significantly less than 10 years.

25

The lubricant can be expected to harden if a breaker is cycled scarcely at all in a period approaching 6 years. This period of inactivity would lead to a high likelihood of binding and a failure to close or open. Cycling the operating mechanism maintains the lubricant in good condition. The combination of normal operations, detailed and visual inspections, and the operability test once per operating cycle should ensure this failure cause is not encountered. Burn marks and discoloration are symptoms of overheating and may indicate degradation of electrical devices such as coils and relays. Failures of coils, relays and motor windings occur from current-time overload, although age, contamination and environmental factors may also play a part. Current-time overload occurs mainly as a result of energizing the devices for longer than the design intent and is almost always due to lubrication failure which causes the mechanism to move slowly or to seize up. Consequently the degradation mechanisms in the electrical devices themselves, which can be difficult to test for, are strongly coupled to the time scales and influences affecting lubrication. A trouble free period of operation may be expected, with burn marks and discoloration being visible signs of lubrication failure as well as indicating degraded coils and relays. Regardless of the lubricant condition, a measurement of the electrical resistance of coils and relays using an ohmmeter, if trended over time, will detect progressive failure of winding insulation and give an indication of the condition of these electrical devices. An insulation resistance test of insulation resistance to ground should be carried out on all subcomponents exposed to line potential. The condition of insulation can also be indicated by a dielectric test, recommended by Westinghouse but not frequently performed by utilities and not recommended here, owing to the possibility that the high potential may precipitate insulation breakdown. Switch and relay contact failures occur as a result of exposure to the service environment through oxidation and contamination, by wear through the plating, or from lack of contact pressure. High contact resistance may develop over time although a trouble-free period of 10 years should be obtained under mild service conditions. Switch and relay contact failure may be avoided by measuring the contact resistance at the detailed inspection. A contact resistance of up to 5 ohms (not the 0.1 ohms often quoted) can be tolerated without contact failure, as the passage of current will remove the contaminating film. Lack of use may also lead to contact failure, either because the contacts are not sufficiently wiped or surface contamination is not burned through. The recommended electrical cycling of the breaker in a racked-in position should avoid this failure cause. Deposition of metals or a variety of glass-like materials, and moisture absorption on arc quenching components may lead ultimately to a failure to quench. These degradation mechanisms are clearly dependent on the number of cycles, age, and service conditions; normal operation should lead to a trouble-free period of approximately 10 years. Large fault current interruptions should each be accompanied by an inspection of the arcing contacts and arc chutes and thus should not interfere with the expected period of failure free operation. The absorption of moisture by arc chutes can also be indicated by a power factor test. Failures of the puffer and blowout coil should not occur before 4 to 5 years and tend to be randomly spread over a wide time scale after that period has passed. The condition of the main contacts should be assessed using a ductor test with the passage of a high current to burn off contaminating films, although the ductor test is not a good indicator if the plating is damaged. Damaged plating on main contacts should be visible. The ductor test also demonstrates that neither lubrication failure nor misadjustment or normal wear are affecting the condition of the main contacts. Fault Discovery and Intervention: All of the failure mechanisms discussed above progress continuously for a period of years before the failure point is reached. The minimum duration of this wearout characteristic is usually controlled by the service conditions that affect lubrication failure. Preventive maintenance (PM) within this period can identify and intercept all the failure mechanisms excepting those due to design, manufacturing, and installation defects, and maintenance error. These are excluded from consideration here because their random nature does not lend itself to being addressed by regularly scheduled PM tasks, other than failure finding such as the operability test, trip tests, or calibration. An overhaul is necessary to completely clean out old lubricant and to renew lubricant at every point in the breaker within about 10 years for low duty cycle and mild service conditions. The detailed inspection should be performed in order to replace as much of the lubricant as possible at a shorter interval, about half the overhaul interval. In a Detailed Inspection, accessible pivot points and bearings can be lubricated, although they probably still can not be properly cleaned. Manual and electrical operation can help to distribute lubricant in all areas and mix it to prevent separation of its constituents. The “feel” of the operating mechanism during manual operation can indicate to an experienced person the general condition of the lubricant. Additionally, the time taken for the breaker to close is a direct indication of a sluggish mechanism. As-found and as-left electrical close-timing tests may be supplemented by a trip load test or by a minimum control voltage test to detect a sluggish mechanism. If the breaker does not pass these tests consideration should be given to refreshing the lubricant in less accessible parts of GE breakers sparingly with an appropriate oil; otherwise a detailed inspection or overhaul will be necessary. A Detailed Inspection will typically be performed to ensure that critical breakers in severe service conditions ( e.g. high temperatures, high humidity, and salt laden air) can reach the scheduled overhaul at 8 years. In more normal conditions for critical breakers, detailed inspection can be combined in rotation with visual inspection and overhaul to provide flexibility on when the overhaul is performed (i.e. not strictly at 10 years). See Note 6 for a discussion of scheduling inspections. Breaker Detailed Inspection should include: · Manually operate the breaker · Perform as-found electrical test (open / close and timing) · Remove arc chutes, phase barriers, relay and switch covers, and inspection covers · Clean and replace lubricant where accessible and not requiring further disassembly · On GE breakers using red lubricant: refresh the lubricant at bearing and pivot points where it is impossible to replace it, using the approved synthetic oil · General cleaning and inspect all accessible parts and surfaces · Replace known parts subject to wearout (e.g. bushings, GE microswitches) · Verify adjustments · Inspect puffer and verify operation · Perform ductor test · Perform insulation resistance test · Inspect for: pitting or corrosion on primary contacts; missing, loose, or damaged parts, fasteners, and set screws; tracking on insulators; cracked welds; rust or corrosion; cracked or burned arc chutes, metal deposits or other deposits (melted asbestos, sand, Portland cement-like material) in the throat area; hard lubricant (may look like varnish); secondary control block damage or misalignment; worn or bent linkages; general cleanliness; condition of prop springs; wiring harness damage. · Perform as-left electrical test (open / close and timing)

26

Perform PM of Merlin Gerin Breaker: 2.3.3 Breaker - Detailed Inspection Failure Locations and Causes: The failure locations and failure causes addressed by the Detailed Inspection are the same as those addressed by the Visual Inspection. The main difference is that the Detailed Inspection includes a far more comprehensive set of tasks designed to be an effective way to thoroughly check the operating mechanism, main current components, and the racking mechanism for: 1) mechanically failed or damaged parts, loose connections and fasteners, worn bushings and bearings, worn bushings and bearings, 2) the condition of the lubricant, to cycle the operating mechanism so as to mix and distribute the lubricant, to provide an opportunity to add lubricant to many more pivot points and bearings including the primary contacts, and to refresh lubricant in other areas (GE), 3) to check for burn marks or discoloration that might indicate overheating of electrical components such as relays, coils and switches, 4) to replace parts known to be subject to wearout (e.g. GE microswitches), 5) to perform general cleaning, 6) to check for tracking, burn marks, or deposition of material on arc quenching components, or other damage to them, and 7) to verify adjustments and operation of subcomponents (e.g. primary contacts and plating, puffer assembly) and the integral operation of the breaker. Parts that are loose, damaged, or missing may be seen directly, often where they should not be (e.g. on the cubicle floor), even by relatively inexperienced personnel. However, signs of material fatigue, abnormal wear (e.g. worn bushings), or material property changes can best be noted and assessed by having experienced people perform the detailed inspection. A relatively common problem area is the alignment of the prop mechanism, its centering and tightness. The condition of the lubricant is essential to proper operation. Inadequate lubrication is by far the dominant cause of breaker failures. Assessment of the condition of the lubricating grease should therefore be the prime objective of any inspection. Removal of arc chutes, phase barriers, inspection covers and relay/switch covers will facilitate a fairly thorough check of lubricant condition. However, the detailed inspection does not include extensive disassembly of the breaker; consequently, lubricant internal to bearings and bushings will not, in general, be accessible at the detailed inspection. Hard lubricant in thin films may not be visible at all, or may appear as a varnish-like layer. Contaminated switches and relay contacts make up a very large proportion of the failure causes and overhaul deficiencies noted in NPRDS failure events and NMAC data analysis. These contacts are not normally accessible during a visual inspection but should be more accessible at a detailed inspection when switch covers are removed. Electrical insulation and wiring is a much smaller contributor to breaker failure. In addition to visible damage to primary contacts, and deposits and tracking on arc quenching components, the arc contact tips may be damaged or broken off, and the puffer or the blowout coil may have failed. Progression of Degradation to Failure: The likelihood of damaged or failed mechanical parts and loose or missing fasteners is expected to depend on the number of operations of the breaker. This would indicate a continuous progression of these degradation mechanisms, regardless of whether they occur through normal wear, fatigue, or material property changes. Failures should occur only after a trouble free period corresponding to the OEM’s maximum recommended number of operations. A random contribution to failure times from loose fasteners is expected, but only after a similar trouble free period. If 2000 cycles is considered to be a generic OEM limit, the boundary between the template high and low duty cycle of 200 operations per year would imply that these failure causes do not require periodic inspection at low duty cycles more often than at a 10 year interval under nominal service conditions. Concern over inadequate lubrication may appear more quickly than this, in 3 to 10 years depending on service conditions. If heavy contamination of breakers with dust has occurred during the plant construction phase, or if service conditions involve high temperatures or significant dust or other contamination, e.g. salt and/or high humidity, this is likely to lead to lubrication failure in significantly less than 10 years. The lubricant can be expected to harden if a breaker is cycled scarcely at all in a period approaching 6 years. This period of inactivity would lead to a high likelihood of binding and a failure to close or open. Cycling the operating mechanism maintains the lubricant in good condition. The combination of normal operations, detailed and visual inspections, and the operability test once per operating cycle should ensure this failure cause is not encountered. Burn marks and discoloration are symptoms of overheating and may indicate degradation of electrical devices such as coils and relays. Failures of coils, relays and motor windings occur from current-time overload, although age, contamination and environmental factors may also play a part. Current-time overload occurs mainly as a result of energizing the devices for longer than the design intent and is almost always due to lubrication failure which causes the mechanism to move slowly or to seize up. Consequently the degradation mechanisms in the electrical devices themselves, which can be difficult to test for, are strongly coupled to the time scales and influences affecting lubrication. A trouble free period of operation may be expected, with burn marks and discoloration being visible signs of lubrication failure as well as indicating degraded coils and relays. Regardless of the lubricant condition, a measurement of the electrical resistance of coils and relays using an ohmmeter, if trended over time, will detect progressive failure of winding insulation and give an indication of the condition of these electrical devices. An insulation resistance test of insulation resistance to ground should be carried out on all subcomponents exposed to line potential. The condition of insulation can also be indicated by a dielectric test, recommended by Westinghouse but not frequently performed by utilities and not recommended here, owing to the possibility that the high potential may precipitate insulation breakdown. Switch and relay contact failures occur as a result of exposure to the service environment through oxidation and contamination, by wear through the plating, or from lack of contact pressure. High contact resistance may develop over time although a trouble-free period of 10 years should be obtained under mild service conditions. Switch and relay contact failure may be avoided by measuring the contact resistance at the detailed inspection. A contact resistance of up to 5 ohms (not the 0.1 ohms often quoted) can be tolerated without contact failure, as the passage of current will remove the contaminating film. Lack of use may also lead to contact failure, either because the contacts are not sufficiently wiped or surface contamination is not burned through. The recommended electrical cycling of the breaker in a racked-in position should avoid this failure cause. Deposition of metals or a variety of glass-like materials, and moisture absorption on arc quenching components may lead ultimately to a failure to quench. These degradation mechanisms are clearly dependent on the number of cycles, age, and service conditions; normal operation should lead to a trouble-free period of approximately 10 years. Large fault current interruptions should each be accompanied by an inspection of the arcing contacts and arc chutes and thus should not interfere with the expected period of failure free operation. The absorption of moisture by arc chutes can also be

27

indicated by a power factor test. Failures of the puffer and blowout coil should not occur before 4 to 5 years and tend to be randomly spread over a wide time scale after that period has passed. The condition of the main contacts should be assessed using a ductor test with the passage of a high current to burn off contaminating films, although the ductor test is not a good indicator if the plating is damaged. Damaged plating on main contacts should be visible. The ductor test also demonstrates that neither lubrication failure nor misadjustment or normal wear are affecting the condition of the main contacts. Fault Discovery and Intervention: All of the failure mechanisms discussed above progress continuously for a period of years before the failure point is reached. The minimum duration of this wearout characteristic is usually controlled by the service conditions that affect lubrication failure. Preventive maintenance (PM) within this period can identify and intercept all the failure mechanisms excepting those due to design, manufacturing, and installation defects, and maintenance error. These are excluded from consideration here because their random nature does not lend itself to being addressed by regularly scheduled PM tasks, other than failure finding such as the operability test, trip tests, or calibration. An overhaul is necessary to completely clean out old lubricant and to renew lubricant at every point in the breaker within about 10 years for low duty cycle and mild service conditions. The detailed inspection should be performed in order to replace as much of the lubricant as possible at a shorter interval, about half the overhaul interval. In a Detailed Inspection, accessible pivot points and bearings can be lubricated, although they probably still can not be properly cleaned. Manual and electrical operation can help to distribute lubricant in all areas and mix it to prevent separation of its constituents. The “feel” of the operating mechanism during manual operation can indicate to an experienced person the general condition of the lubricant. Additionally, the time taken for the breaker to close is a direct indication of a sluggish mechanism. As-found and as-left electrical close-timing tests may be supplemented by a trip load test or by a minimum control voltage test to detect a sluggish mechanism. If the breaker does not pass these tests consideration should be given to refreshing the lubricant in less accessible parts of GE breakers sparingly with an appropriate oil; otherwise a detailed inspection or overhaul will be necessary. A Detailed Inspection will typically be performed to ensure that critical breakers in severe service conditions ( e.g. high temperatures, high humidity, and salt laden air) can reach the scheduled overhaul at 8 years. In more normal conditions for critical breakers, detailed inspection can be combined in rotation with visual inspection and overhaul to provide flexibility on when the overhaul is performed (i.e. not strictly at 10 years). See Note 6 for a discussion of scheduling inspections. Breaker Detailed Inspection should include: · Manually operate the breaker · Perform as-found electrical test (open / close and timing) · Remove arc chutes, phase barriers, relay and switch covers, and inspection covers · Clean and replace lubricant where accessible and not requiring further disassembly · On GE breakers using red lubricant: refresh the lubricant at bearing and pivot points where it is impossible to replace it, using the approved synthetic oil · General cleaning and inspect all accessible parts and surfaces · Replace known parts subject to wearout (e.g. bushings, GE microswitches) · Verify adjustments · Inspect puffer and verify operation · Perform ductor test · Perform insulation resistance test · Inspect for: pitting or corrosion on primary contacts; missing, loose, or damaged parts, fasteners, and set screws; tracking on insulators; cracked welds; rust or corrosion; cracked or burned arc chutes, metal deposits or other deposits (melted asbestos, sand, Portland cement-like material) in the throat area; hard lubricant (may look like varnish); secondary control block damage or misalignment; worn or bent linkages; general cleanliness; condition of prop springs; wiring harness damage. · Perform as-left electrical test (open / close and timing) Perform PM of Westinghouse Breaker Note 1: 2.3.3 Breaker - Detailed Inspection Failure Locations and Causes: The failure locations and failure causes addressed by the Detailed Inspection are the same as those addressed by the Visual Inspection. The main difference is that the Detailed Inspection includes a far more comprehensive set of tasks designed to be an effective way to thoroughly check the operating mechanism, main current components, and the racking mechanism for: 1) mechanically failed or damaged parts, loose connections and fasteners, worn bushings and bearings, worn bushings and bearings, 2) the condition of the lubricant, to cycle the operating mechanism so as to mix and distribute the lubricant, to provide an opportunity to add lubricant to many more pivot points and bearings including the primary contacts, and to refresh lubricant in other areas (GE), 3) to check for burn marks or discoloration that might indicate overheating of electrical components such as relays, coils and switches, 4) to replace parts known to be subject to wearout (e.g. GE microswitches), 5) to perform general cleaning, 6) to check for tracking, burn marks, or deposition of material on arc quenching components, or other damage to them, and 7) to verify adjustments and operation of subcomponents (e.g. primary contacts and plating, puffer assembly) and the integral operation of the breaker. Parts that are loose, damaged, or missing may be seen directly, often where they should not be (e.g. on the cubicle floor), even by relatively inexperienced personnel. However, signs of material fatigue, abnormal wear (e.g. worn bushings), or material property changes can best be noted and assessed by having experienced people perform the detailed inspection. A relatively common problem area is the alignment of the prop mechanism, its centering and tightness. The condition of the lubricant is essential to proper operation. Inadequate lubrication is by far the dominant cause of breaker failures. Assessment of the condition of the lubricating grease should therefore be the prime objective of any inspection. Removal of arc chutes, phase barriers, inspection covers and relay/switch covers will facilitate a fairly thorough check of lubricant condition. However, the detailed inspection does not include extensive disassembly of the breaker; consequently, lubricant internal to bearings and bushings will not, in general, be accessible at the detailed inspection. Hard lubricant in thin films may not be visible at all, or may appear as a varnish-like layer. Contaminated switches and relay contacts make up a very large proportion of the failure causes and overhaul deficiencies noted in NPRDS failure events and NMAC data analysis. These contacts are not normally accessible during a visual inspection but should be more accessible at a detailed inspection when switch covers are removed. Electrical insulation and wiring is a much smaller contributor to breaker failure. In addition to visible damage to primary contacts, and deposits and tracking on arc quenching components, the arc contact tips may be damaged or broken off, and the puffer or the blowout coil may have failed. Progression of Degradation to Failure: The likelihood of damaged or failed mechanical parts and loose or missing fasteners is expected to depend on the number of operations of the breaker. This would indicate a continuous progression of these degradation

28

mechanisms, regardless of whether they occur through normal wear, fatigue, or material property changes. Failures should occur only after a trouble free period corresponding to the OEM’s maximum recommended number of operations. A random contribution to failure times from loose fasteners is expected, but only after a similar trouble free period. If 2000 cycles is considered to be a generic OEM limit, the boundary between the template high and low duty cycle of 200 operations per year would imply that these failure causes do not require periodic inspection at low duty cycles more often than at a 10 year interval under nominal service conditions. Concern over inadequate lubrication may appear more quickly than this, in 3 to 10 years depending on service conditions. If heavy contamination of breakers with dust has occurred during the plant construction phase, or if service conditions involve high temperatures or significant dust or other contamination, e.g. salt and/or high humidity, this is likely to lead to lubrication failure in significantly less than 10 years. The lubricant can be expected to harden if a breaker is cycled scarcely at all in a period approaching 6 years. This period of inactivity would lead to a high likelihood of binding and a failure to close or open. Cycling the operating mechanism maintains the lubricant in good condition. The combination of normal operations, detailed and visual inspections, and the operability test once per operating cycle should ensure this failure cause is not encountered. Burn marks and discoloration are symptoms of overheating and may indicate degradation of electrical devices such as coils and relays. Failures of coils, relays and motor windings occur from current-time overload, although age, contamination and environmental factors may also play a part. Current-time overload occurs mainly as a result of energizing the devices for longer than the design intent and is almost always due to lubrication failure which causes the mechanism to move slowly or to seize up. Consequently the degradation mechanisms in the electrical devices themselves, which can be difficult to test for, are strongly coupled to the time scales and influences affecting lubrication. A trouble free period of operation may be expected, with burn marks and discoloration being visible signs of lubrication failure as well as indicating degraded coils and relays. Regardless of the lubricant condition, a measurement of the electrical resistance of coils and relays using an ohmmeter, if trended over time, will detect progressive failure of winding insulation and give an indication of the condition of these electrical devices. An insulation resistance test of insulation resistance to ground should be carried out on all subcomponents exposed to line potential. The condition of insulation can also be indicated by a dielectric test, recommended by Westinghouse but not frequently performed by utilities and not recommended here, owing to the possibility that the high potential may precipitate insulation breakdown. Switch and relay contact failures occur as a result of exposure to the service environment through oxidation and contamination, by wear through the plating, or from lack of contact pressure. High contact resistance may develop over time although a trouble-free period of 10 years should be obtained under mild service conditions. Switch and relay contact failure may be avoided by measuring the contact resistance at the detailed inspection. A contact resistance of up to 5 ohms (not the 0.1 ohms often quoted) can be tolerated without contact failure, as the passage of current will remove the contaminating film. Lack of use may also lead to contact failure, either because the contacts are not sufficiently wiped or surface contamination is not burned through. The recommended electrical cycling of the breaker in a racked-in position should avoid this failure cause. Deposition of metals or a variety of glass-like materials, and moisture absorption on arc quenching components may lead ultimately to a failure to quench. These degradation mechanisms are clearly dependent on the number of cycles, age, and service conditions; normal operation should lead to a trouble-free period of approximately 10 years. Large fault current interruptions should each be accompanied by an inspection of the arcing contacts and arc chutes and thus should not interfere with the expected period of failure free operation. The absorption of moisture by arc chutes can also be indicated by a power factor test. Failures of the puffer and blowout coil should not occur before 4 to 5 years and tend to be randomly spread over a wide time scale after that period has passed. The condition of the main contacts should be assessed using a ductor test with the passage of a high current to burn off contaminating films, although the ductor test is not a good indicator if the plating is damaged. Damaged plating on main contacts should be visible. The ductor test also demonstrates that neither lubrication failure nor misadjustment or normal wear are affecting the condition of the main contacts. Fault Discovery and Intervention: All of the failure mechanisms discussed above progress continuously for a period of years before the failure point is reached. The minimum duration of this wearout characteristic is usually controlled by the service conditions that affect lubrication failure. Preventive maintenance (PM) within this period can identify and intercept all the failure mechanisms excepting those due to design, manufacturing, and installation defects, and maintenance error. These are excluded from consideration here because their random nature does not lend itself to being addressed by regularly scheduled PM tasks, other than failure finding such as the operability test, trip tests, or calibration. An overhaul is necessary to completely clean out old lubricant and to renew lubricant at every point in the breaker within about 10 years for low duty cycle and mild service conditions. The detailed inspection should be performed in order to replace as much of the lubricant as possible at a shorter interval, about half the overhaul interval. In a Detailed Inspection, accessible pivot points and bearings can be lubricated, although they probably still can not be properly cleaned. Manual and electrical operation can help to distribute lubricant in all areas and mix it to prevent separation of its constituents. The “feel” of the operating mechanism during manual operation can indicate to an experienced person the general condition of the lubricant. Additionally, the time taken for the breaker to close is a direct indication of a sluggish mechanism. As-found and as-left electrical close-timing tests may be supplemented by a trip load test or by a minimum control voltage test to detect a sluggish mechanism. If the breaker does not pass these tests consideration should be given to refreshing the lubricant in less accessible parts of GE breakers sparingly with an appropriate oil; otherwise a detailed inspection or overhaul will be necessary. A Detailed Inspection will typically be performed to ensure that critical breakers in severe service conditions ( e.g. high temperatures, high humidity, and salt laden air) can reach the scheduled overhaul at 8 years. In more normal conditions for critical breakers, detailed inspection can be combined in rotation with visual inspection and overhaul to provide flexibility on when the overhaul is performed (i.e. not strictly at 10 years). See Note 6 for a discussion of scheduling inspections. Breaker Detailed Inspection should include: · Manually operate the breaker · Perform as-found electrical test (open / close and timing) · Remove arc chutes, phase barriers, relay and switch covers, and inspection covers · Clean and replace lubricant where accessible and not requiring further disassembly · On GE breakers using red lubricant: refresh the lubricant at bearing and pivot points

29

where it is impossible to replace it, using the approved synthetic oil · General cleaning and inspect all accessible parts and surfaces · Replace known parts subject to wearout (e.g. bushings, GE microswitches) · Verify adjustments · Inspect puffer and verify operation · Perform ductor test · Perform insulation resistance test · Inspect for: pitting or corrosion on primary contacts; missing, loose, or damaged parts, fasteners, and set screws; tracking on insulators; cracked welds; rust or corrosion; cracked or burned arc chutes, metal deposits or other deposits (melted asbestos, sand, Portland cement-like material) in the throat area; hard lubricant (may look like varnish); secondary control block damage or misalignment; worn or bent linkages; general cleanliness; condition of prop springs; wiring harness damage. · Perform as-left electrical test (open / close and timing) Perform PM of ABB Breaker Note 1: 2.3.3 Breaker - Detailed Inspection Failure Locations and Causes: The failure locations and failure causes addressed by the Detailed Inspection are the same as those addressed by the Visual Inspection. The main difference is that the Detailed Inspection includes a far more comprehensive set of tasks designed to be an effective way to thoroughly check the operating mechanism, main current components, and the racking mechanism for: 1) mechanically failed or damaged parts, loose connections and fasteners, worn bushings and bearings, worn bushings and bearings, 2) the condition of the lubricant, to cycle the operating mechanism so as to mix and distribute the lubricant, to provide an opportunity to add lubricant to many more pivot points and bearings including the primary contacts, and to refresh lubricant in other areas (GE), 3) to check for burn marks or discoloration that might indicate overheating of electrical components such as relays, coils and switches, 4) to replace parts known to be subject to wearout (e.g. GE microswitches), 5) to perform general cleaning, 6) to check for tracking, burn marks, or deposition of material on arc quenching components, or other damage to them, and 7) to verify adjustments and operation of subcomponents (e.g. primary contacts and plating, puffer assembly) and the integral operation of the breaker. Parts that are loose, damaged, or missing may be seen directly, often where they should not be (e.g. on the cubicle floor), even by relatively inexperienced personnel. However, signs of material fatigue, abnormal wear (e.g. worn bushings), or material property changes can best be noted and assessed by having experienced people perform the detailed inspection. A relatively common problem area is the alignment of the prop mechanism, its centering and tightness. The condition of the lubricant is essential to proper operation. Inadequate lubrication is by far the dominant cause of breaker failures. Assessment of the condition of the lubricating grease should therefore be the prime objective of any inspection. Removal of arc chutes, phase barriers, inspection covers and relay/switch covers will facilitate a fairly thorough check of lubricant condition. However, the detailed inspection does not include extensive disassembly of the breaker; consequently, lubricant internal to bearings and bushings will not, in general, be accessible at the detailed inspection. Hard lubricant in thin films may not be visible at all, or may appear as a varnish-like layer. Contaminated switches and relay contacts make up a very large proportion of the failure causes and overhaul deficiencies noted in NPRDS failure events and NMAC data analysis. These contacts are not normally accessible during a visual inspection but should be more accessible at a detailed inspection when switch covers are removed. Electrical insulation and wiring is a much smaller contributor to breaker failure. In addition to visible damage to primary contacts, and deposits and tracking on arc quenching components, the arc contact tips may be damaged or broken off, and the puffer or the blowout coil may have failed. Progression of Degradation to Failure: The likelihood of damaged or failed mechanical parts and loose or missing fasteners is expected to depend on the number of operations of the breaker. This would indicate a continuous progression of these degradation mechanisms, regardless of whether they occur through normal wear, fatigue, or material property changes. Failures should occur only after a trouble free period corresponding to the OEM’s maximum recommended number of operations. A random contribution to failure times from loose fasteners is expected, but only after a similar trouble free period. If 2000 cycles is considered to be a generic OEM limit, the boundary between the template high and low duty cycle of 200 operations per year would imply that these failure causes do not require periodic inspection at low duty cycles more often than at a 10 year interval under nominal service conditions. Concern over inadequate lubrication may appear more quickly than this, in 3 to 10 years depending on service conditions. If heavy contamination of breakers with dust has occurred during the plant construction phase, or if service conditions involve high temperatures or significant dust or other contamination, e.g. salt and/or high humidity, this is likely to lead to lubrication failure in significantly less than 10 years. The lubricant can be expected to harden if a breaker is cycled scarcely at all in a period approaching 6 years. This period of inactivity would lead to a high likelihood of binding and a failure to close or open. Cycling the operating mechanism maintains the lubricant in good condition. The combination of normal operations, detailed and visual inspections, and the operability test once per operating cycle should ensure this failure cause is not encountered. Burn marks and discoloration are symptoms of overheating and may indicate degradation of electrical devices such as coils and relays. Failures of coils, relays and motor windings occur from current-time overload, although age, contamination and environmental factors may also play a part. Current-time overload occurs mainly as a result of energizing the devices for longer than the design intent and is almost always due to lubrication failure which causes the mechanism to move slowly or to seize up. Consequently the degradation mechanisms in the electrical devices themselves, which can be difficult to test for, are strongly coupled to the time scales and influences affecting lubrication. A trouble free period of operation may be expected, with burn marks and discoloration being visible signs of lubrication failure as well as indicating degraded coils and relays. Regardless of the lubricant condition, a measurement of the electrical resistance of coils and relays using an ohmmeter, if trended over time, will detect progressive failure of winding insulation and give an indication of the condition of these electrical devices. An insulation resistance test of insulation resistance to ground should be carried out on all subcomponents exposed to line potential. The condition of insulation can also be indicated by a dielectric test, recommended by Westinghouse but not frequently performed by utilities and not recommended here, owing to the possibility that the high potential may precipitate insulation breakdown. Switch and relay contact failures occur as a result of exposure to the service environment through oxidation and contamination, by wear through the plating, or from lack of contact pressure. High contact resistance may develop over time although a trouble-free period of 10 years should be obtained under mild service conditions. Switch and relay contact failure may be avoided by measuring the contact

30

resistance at the detailed inspection. A contact resistance of up to 5 ohms (not the 0.1 ohms often quoted) can be tolerated without contact failure, as the passage of current will remove the contaminating film. Lack of use may also lead to contact failure, either because the contacts are not sufficiently wiped or surface contamination is not burned through. The recommended electrical cycling of the breaker in a racked-in position should avoid this failure cause. Deposition of metals or a variety of glass-like materials, and moisture absorption on arc quenching components may lead ultimately to a failure to quench. These degradation mechanisms are clearly dependent on the number of cycles, age, and service conditions; normal operation should lead to a trouble-free period of approximately 10 years. Large fault current interruptions should each be accompanied by an inspection of the arcing contacts and arc chutes and thus should not interfere with the expected period of failure free operation. The absorption of moisture by arc chutes can also be indicated by a power factor test. Failures of the puffer and blowout coil should not occur before 4 to 5 years and tend to be randomly spread over a wide time scale after that period has passed. The condition of the main contacts should be assessed using a ductor test with the passage of a high current to burn off contaminating films, although the ductor test is not a good indicator if the plating is damaged. Damaged plating on main contacts should be visible. The ductor test also demonstrates that neither lubrication failure nor misadjustment or normal wear are affecting the condition of the main contacts. Fault Discovery and Intervention: All of the failure mechanisms discussed above progress continuously for a period of years before the failure point is reached. The minimum duration of this wearout characteristic is usually controlled by the service conditions that affect lubrication failure. Preventive maintenance (PM) within this period can identify and intercept all the failure mechanisms excepting those due to design, manufacturing, and installation defects, and maintenance error. These are excluded from consideration here because their random nature does not lend itself to being addressed by regularly scheduled PM tasks, other than failure finding such as the operability test, trip tests, or calibration. An overhaul is necessary to completely clean out old lubricant and to renew lubricant at every point in the breaker within about 10 years for low duty cycle and mild service conditions. The detailed inspection should be performed in order to replace as much of the lubricant as possible at a shorter interval, about half the overhaul interval. In a Detailed Inspection, accessible pivot points and bearings can be lubricated, although they probably still can not be properly cleaned. Manual and electrical operation can help to distribute lubricant in all areas and mix it to prevent separation of its constituents. The “feel” of the operating mechanism during manual operation can indicate to an experienced person the general condition of the lubricant. Additionally, the time taken for the breaker to close is a direct indication of a sluggish mechanism. As-found and as-left electrical close-timing tests may be supplemented by a trip load test or by a minimum control voltage test to detect a sluggish mechanism. If the breaker does not pass these tests consideration should be given to refreshing the lubricant in less accessible parts of GE breakers sparingly with an appropriate oil; otherwise a detailed inspection or overhaul will be necessary. A Detailed Inspection will typically be performed to ensure that critical breakers in severe service conditions ( e.g. high temperatures, high humidity, and salt laden air) can reach the scheduled overhaul at 8 years. In more normal conditions for critical breakers, detailed inspection can be combined in rotation with visual inspection and overhaul to provide flexibility on when the overhaul is performed (i.e. not strictly at 10 years). See Note 6 for a discussion of scheduling inspections. Breaker Detailed Inspection should include: · Manually operate the breaker · Perform as-found electrical test (open / close and timing) · Remove arc chutes, phase barriers, relay and switch covers, and inspection covers · Clean and replace lubricant where accessible and not requiring further disassembly · On GE breakers using red lubricant: refresh the lubricant at bearing and pivot points where it is impossible to replace it, using the approved synthetic oil · General cleaning and inspect all accessible parts and surfaces · Replace known parts subject to wearout (e.g. bushings, GE microswitches) · Verify adjustments · Inspect puffer and verify operation · Perform ductor test · Perform insulation resistance test · Inspect for: pitting or corrosion on primary contacts; missing, loose, or damaged parts, fasteners, and set screws; tracking on insulators; cracked welds; rust or corrosion; cracked or burned arc chutes, metal deposits or other deposits (melted asbestos, sand, Portland cement-like material) in the throat area; hard lubricant (may look like varnish); secondary control block damage or misalignment; worn or bent linkages; general cleanliness; condition of prop springs; wiring harness damage. · Perform as-left electrical test (open / close and timing) Overhaul GE Breaker: 2.3.4 Breaker - Overhaul The failure locations and failure causes addressed by the Overhaul are the same as those addressed by the Detailed Inspection. However, in an overhaul the breaker is completely disassembled to give access to all parts for cleaning, inspection for damage and wear, and complete replacement of lubricant. Failure to do this results in wearout of the lubricant in parts inaccessible to the detailed inspection. It should be noted that overhaul intervals are strongly dependent upon the type of lubricant used. The template assumes that the Mobil 28 red lubricant is used for GE breakers, and standard OEM recommended lubricants for other manufacturers. In addition, an overhaul parts replacement kit should be used for small mechanical items like retainers, washers, nuts and bolts, bushings, gaskets and springs. Individual subcomponent replacement depending on make and model will also be necessary, e.g. replace the motor disconnect switch on all models, because these parts exhibit a fairly clear wearout behavior. The NMAC maintenance guides for medium voltage circuit breakers and the appropriate vendor manuals should be consulted for parts to replace at the overhaul. Breaker overhaul should include: · Complete disassembly, inspection, lubrication, and replacement of worn components · Perform as-found electrical open / close and timing test · Perform pre-disassembly: functional tests and visual inspection · Clean parts, visually inspect, measure, and record data on wearable parts · Replace parts (normal replacement as indicated by OEM or as indicated by historical records, e.g. bushings, motor disconnect switch on GE breakers) · Lubricate all necessary parts · Inspect puffer and verify operation · Perform ductor test · Perform insulation resistance test · Inspect for: pitting or corrosion on primary contacts; missing, loose, or damaged parts, fasteners, and set screws; tracking on insulators; cracked welds; rust or corrosion; cracked or burned arc chutes, metal deposits or other deposits (melted asbestos, sand, Portland cement-like material) in the throat area; hard lubricant (may look like varnish); secondary control block damage or misalignment; worn or bent linkages; general cleanliness; condition of prop springs; wiring harness damage. · Perform functional test · Perform as-left electrical open / close and

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timing test Overhaul Merlin-Gerin Breaker: EPRI TR-106857-V2 PM Basis for Medium Voltage Switchgear, Section 2.3.4 BreakerOverhaul The failure locations and failure causes addressed by the Overhaul are the same as those addressed by the Detailed Inspection. However, in an overhaul the breaker is completely disassembled to give access to all parts for cleaning, inspection for damage and wear, and complete replacement of lubricant. Failure to do this results in wearout of the lubricant in parts inaccessible to the detailed inspection. It should be noted that overhaul intervals are strongly dependent upon the type of lubricant used. The template assumes that the Mobil 28 red lubricant is used. In addition, an overhaul parts replacement kit should be used for small mechanical items like retainers, washers, nuts and bolts, bushings, gaskets and springs. Individual subcomponent replacement depending on make and model will also be necessary, e.g. replace the motor disconnect switch on all models, because these parts exhibit a fairly clear wearout behavior. The NMAC maintenance guides for medium voltage circuit breakers and the appropriate vendor manuals should be consulted for parts to replace at the overhaul. Breaker overhaul should include: · Complete disassembly, inspection, lubrication, and replacement of worn components · Perform as-found electrical open / close and timing test · Perform pre-disassembly functional tests and visual inspection · Clean parts, visually inspect, measure, and record data on wearable parts · Replace parts (normal replacement as indicated by OEM or as indicated by historical records, e.g. bushings, motor disconnect switches · Lubricate all necessary parts · Inspect puffer and verify operation · Perform ductor test · Perform insulation resistance test · Inspect for pitting or corrosion on primary contacts; missing, loose, or damaged parts, fasteners, and set screws; tracking on insulators; cracked welds; rust or corrosion; cracked or burned arc chutes, metal deposits or other deposits (melted asbestos, sand, Portland cement-like material) in the throat area; hard lubricant (may look like varnish); secondary control block damage or misalignment; worn or bent linkages; general cleanliness; condition of prop springs; wiring harness damage. · Perform functional test · Perform as-left electrical open / close and timing test Overhaul Westinghouse Breaker: 2.3.4 Breaker - Overhaul The failure locations and failure causes addressed by the Overhaul are the same as those addressed by the Detailed Inspection. However, in an overhaul the breaker is completely disassembled to give access to all parts for cleaning, inspection for damage and wear, and complete replacement of lubricant. Failure to do this results in wearout of the lubricant in parts inaccessible to the detailed inspection. It should be noted that overhaul intervals are strongly dependent upon the type of lubricant used. The template assumes that the Mobil 28 red lubricant is used for GE breakers, and standard OEM recommended lubricants for other manufacturers. In addition, an overhaul parts replacement kit should be used for small mechanical items like retainers, washers, nuts and bolts, bushings, gaskets and springs. Individual subcomponent replacement depending on make and model will also be necessary, e.g. replace the motor disconnect switch on all models, because these parts exhibit a fairly clear wearout behavior. The NMAC maintenance guides for medium voltage circuit breakers and the appropriate vendor manuals should be consulted for parts to replace at the overhaul. Breaker overhaul should include: · Complete disassembly, inspection, lubrication, and replacement of worn components · Perform as-found electrical open / close and timing test · Perform pre-disassembly: functional tests and visual inspection · Clean parts, visually inspect, measure, and record data on wearable parts · Replace parts (normal replacement as indicated by OEM or as indicated by historical records, e.g. bushings, motor disconnect switch on GE breakers) · Lubricate all necessary parts · Inspect puffer and verify operation · Perform ductor test · Perform insulation resistance test · Inspect for: pitting or corrosion on primary contacts; missing, loose, or damaged parts, fasteners, and set screws; tracking on insulators; cracked welds; rust or corrosion; cracked or burned arc chutes, metal deposits or other deposits (melted asbestos, sand, Portland cement-like material) in the throat area; hard lubricant (may look like varnish); secondary control block damage or misalignment; worn or bent linkages; general cleanliness; condition of prop springs; wiring harness damage. · Perform functional test · Perform as-left electrical open / close and timing test Overhaul ABB Breaker: 2.3.4 Breaker - Overhaul The failure locations and failure causes addressed by the Overhaul are the same as those addressed by the Detailed Inspection. However, in an overhaul the breaker is completely disassembled to give access to all parts for cleaning, inspection for damage and wear, and complete replacement of lubricant. Failure to do this results in wearout of the lubricant in parts inaccessible to the detailed inspection. It should be noted that overhaul intervals are strongly dependent upon the type of lubricant used. The template assumes that the Mobil 28 red lubricant is used for GE breakers, and standard OEM recommended lubricants for other manufacturers. In addition, an overhaul parts replacement kit should be used for small mechanical items like retainers, washers, nuts and bolts, bushings, gaskets and springs. Individual subcomponent replacement depending on make and model will also be necessary, e.g. replace the motor disconnect switch on all models, because these parts exhibit a fairly clear wearout behavior. The NMAC maintenance guides for medium voltage circuit breakers and the appropriate vendor manuals should be consulted for parts to replace at the overhaul. Breaker overhaul should include: · Complete disassembly, inspection, lubrication, and replacement of worn components · Perform as-found electrical open / close and timing test · Perform pre-disassembly: functional tests and visual inspection · Clean parts, visually inspect, measure, and record data on wearable parts · Replace parts (normal replacement as indicated by OEM or as indicated by historical records, e.g. bushings, motor disconnect switch on GE breakers) · Lubricate all necessary parts · Inspect puffer and verify operation · Perform ductor test · Perform insulation resistance test · Inspect for: pitting or corrosion on primary contacts; missing, loose, or damaged parts, fasteners, and set screws; tracking on insulators; cracked welds; rust or corrosion; cracked or burned arc chutes, metal deposits or other deposits (melted asbestos, sand, Portland cement-like material) in the throat area; hard lubricant (may look like varnish); secondary control block damage or misalignment; worn or bent linkages; general cleanliness; condition of prop springs; wiring harness damage. · Perform functional test · Perform as-left electrical open / close and timing test

32

Perform PM on switchgear breaker cubicles (GE): 2.3.5 Cubicle - Detailed Inspection Failure Locations and Causes: The racking mechanism is subject to lubrication failure, damaged and failed parts, and loose or missing fasteners. Inadequate lubrication is an important cause of failures in the cubicle as it was in the breaker, although the consequences are more likely to be extended maintenance time rather than a critical event such as breaker failure to close or to trip. Assessment of the condition of the lubricating grease should be the prime objective of a cubicle inspection. A visual check of the lubricant at accessible, and hence more frequently lubricated points, should be done but will not provide a reliable assessment of its condition at other points, such as bushings and bearings, which can only be lubricated at overhaul. Hard lubricant in thin films may not be visible at all, or may appear as a varnish-like layer. Parts that are loose, damaged, or missing may be seen directly, often where they should not be, even by relatively inexperienced personnel. However, signs of material fatigue, abnormal wear, or material property changes can best be noted and assessed by having experienced people perform the inspection. Relatively common problem areas are the alignment of the breaker interface with the cubicle, and alignment problems causing damage to contacts, and to primary and secondary disconnects and switches. Progression of Degradation to Failure: The aging of the lubricant is continuous in time and dependent on contamination, time, and temperature as it was for the breaker itself. Apart from heavy contamination which might have occurred during initial construction or during subsequent room maintenance, a failure free period of up to 10 years should be expected. Heavy contamination or extreme service conditions might shorten this period to as little as 2 years. Complete inactivity, i.e. where the racking mechanism is not actuated at all, may lead to binding of the mechanism in as little as 3 to 5 years or as much as 8 to 10 years depending on the lubricant that has been used. Visual inspection and ease of operation are the methods available to detect aging of the lubricant. Since no disassembly is contemplated for this inspection only accessible points should be lubricated although some refreshment of lubricant with oil might be possible for some models. Lubricant on primary contact stabs should also be replaced. The degradation mechanisms that lead to damaged and failed parts as well as to loose or missing fasteners will proceed continuously with the number of operations of the mechanism assuming no damage is caused by maintenance personnel in the process of racking the breaker in and out. Such damage has occurred often in the industry but is random in occurrence and should be controlled through training, not preventive maintenance. However, cubicle inspections should inspect for signs of such damage. The expected failure free period for these degradation mechanisms probably exceeds that for lubrication failure as quoted above. Fault Discovery and Intervention: The Cubicle Detailed Inspection may not be carried out at the same time as the Breaker Detailed Inspection, although it may be convenient to synchronize the inspections and overhauls. Inspection of buswork will be visual and by thermography as described in the thermography task for breaker and cubicle. Line and load side insulation should be visually inspected and have its insulation resistance tested. Cubicle Detailed Inspection should include: · Racking mechanism - inspect and lubricate · Breaker alignment interface - measure and adjust · Inspect buswork including tightness of joints and covers, and insulation condition · Inspect primary disconnects and lubricate if required · Inspect control wiring for fretting, wear, and damaged insulation · Inspect shutters are free to move · Operate and inspect switch interlocks · Inspect missing and lose fasteners · Inspect for cracked welds · Inspect and test CTs and PTs · Inspect secondary contacts and disconnects · Inspect and perform insulation resistance test on load side cables · Perform fuse drawer inspection (cleanliness, finger alignment, and integrity of connections) · Inspect cabinet heaters Perform PM on switchgear breaker cubicles (West): 2.3.5 Cubicle - Detailed Inspection Failure Locations and Causes: The racking mechanism is subject to lubrication failure, damaged and failed parts, and loose or missing fasteners. Inadequate lubrication is an important cause of failures in the cubicle as it was in the breaker, although the consequences are more likely to be extended maintenance time rather than a critical event such as breaker failure to close or to trip. Assessment of the condition of the lubricating grease should be the prime objective of a cubicle inspection. A visual check of the lubricant at accessible, and hence more frequently lubricated points, should be done but will not provide a reliable assessment of its condition at other points, such as bushings and bearings, which can only be lubricated at overhaul. Hard lubricant in thin films may not be visible at all, or may appear as a varnish-like layer. Parts that are loose, damaged, or missing may be seen directly, often where they should not be, even by relatively inexperienced personnel. However, signs of material fatigue, abnormal wear, or material property changes can best be noted and assessed by having experienced people perform the inspection. Relatively common problem areas are the alignment of the breaker interface with the cubicle, and alignment problems causing damage to contacts, and to primary and secondary disconnects and switches. Progression of Degradation to Failure: The aging of the lubricant is continuous in time and dependent on contamination, time, and temperature as it was for the breaker itself. Apart from heavy contamination which might have occurred during initial construction or during subsequent room maintenance, a failure free period of up to 10 years should be expected. Heavy contamination or extreme service conditions might shorten this period to as little as 2 years. Complete inactivity, i.e. where the racking mechanism is not actuated at all, may lead to binding of the mechanism in as little as 3 to 5 years or as much as 8 to 10 years depending on the lubricant that has been used. Visual inspection and ease of operation are the methods available to detect aging of the lubricant. Since no disassembly is contemplated for this inspection only accessible points should be lubricated although some refreshment of lubricant with oil might be possible for some models. Lubricant on primary contact stabs should also be replaced. The degradation mechanisms that lead to damaged and failed parts as well as to loose or missing fasteners will proceed continuously with the number of operations of the mechanism assuming no damage is caused by maintenance personnel in the process of racking the breaker in and out. Such damage has occurred often in the industry but is random in occurrence and should be controlled through training, not preventive maintenance. However, cubicle inspections should inspect for signs of such damage. The expected failure free period for these degradation mechanisms probably exceeds that for lubrication failure as quoted above. Fault Discovery and Intervention: The Cubicle Detailed Inspection may not be carried out at the same time as the Breaker Detailed Inspection, although it may be convenient to synchronize the inspections and overhauls. Inspection of buswork will be visual and by thermography as described in the thermography

33

task for breaker and cubicle. Line and load side insulation should be visually inspected and have its insulation resistance tested. Cubicle Detailed Inspection should include: · Racking mechanism - inspect and lubricate · Breaker alignment interface - measure and adjust · Inspect bus-work including tightness of joints and covers, and insulation condition · Inspect primary disconnects and lubricate if required · Inspect control wiring for fretting, wear, and damaged insulation · Inspect shutters are free to move · Operate and inspect switch interlocks · Inspect missing and lose fasteners · Inspect for cracked welds · Inspect and test CTs and PTs · Inspect secondary contacts and disconnects · Inspect and perform insulation resistance test on load side cables · Perform fuse drawer inspection (cleanliness, finger alignment, and integrity of connections) · Inspect cabinet heaters Perform PM on switchgear breaker cubicles (ABB): 2.3.5 Cubicle - Detailed Inspection Failure Locations and Causes: The racking mechanism is subject to lubrication failure, damaged and failed parts, and loose or missing fasteners. Inadequate lubrication is an important cause of failures in the cubicle as it was in the breaker, although the consequences are more likely to be extended maintenance time rather than a critical event such as breaker failure to close or to trip. Assessment of the condition of the lubricating grease should be the prime objective of a cubicle inspection. A visual check of the lubricant at accessible, and hence more frequently lubricated points, should be done but will not provide a reliable assessment of its condition at other points, such as bushings and bearings, which can only be lubricated at overhaul. Hard lubricant in thin films may not be visible at all, or may appear as a varnish-like layer. Parts that are loose, damaged, or missing may be seen directly, often where they should not be, even by relatively inexperienced personnel. However, signs of material fatigue, abnormal wear, or material property changes can best be noted and assessed by having experienced people perform the inspection. Relatively common problem areas are the alignment of the breaker interface with the cubicle, and alignment problems causing damage to contacts, and to primary and secondary disconnects and switches. Progression of Degradation to Failure: The aging of the lubricant is continuous in time and dependent on contamination, time, and temperature as it was for the breaker itself. Apart from heavy contamination which might have occurred during initial construction or during subsequent room maintenance, a failure free period of up to 10 years should be expected. Heavy contamination or extreme service conditions might shorten this period to as little as 2 years. Complete inactivity, i.e. where the racking mechanism is not actuated at all, may lead to binding of the mechanism in as little as 3 to 5 years or as much as 8 to 10 years depending on the lubricant that has been used. Visual inspection and ease of operation are the methods available to detect aging of the lubricant. Since no disassembly is contemplated for this inspection only accessible points should be lubricated although some refreshment of lubricant with oil might be possible for some models. Lubricant on primary contact stabs should also be replaced. The degradation mechanisms that lead to damaged and failed parts as well as to loose or missing fasteners will proceed continuously with the number of operations of the mechanism assuming no damage is caused by maintenance personnel in the process of racking the breaker in and out. Such damage has occurred often in the industry but is random in occurrence and should be controlled through training, not preventive maintenance. However, cubicle inspections should inspect for signs of such damage. The expected failure free period for these degradation mechanisms probably exceeds that for lubrication failure as quoted above. Fault Discovery and Intervention: The Cubicle Detailed Inspection may not be carried out at the same time as the Breaker Detailed Inspection, although it may be convenient to synchronize the inspections and overhauls. Inspection of buswork will be visual and by thermography as described in the thermography task for breaker and cubicle. Line and load side insulation should be visually inspected and have its insulation resistance tested. Cubicle Detailed Inspection should include: · Racking mechanism - inspect and lubricate · Breaker alignment interface - measure and adjust · Inspect bus-work including tightness of joints and covers, and insulation condition · Inspect primary disconnects and lubricate if required · Inspect control wiring for fretting, wear, and damaged insulation · Inspect shutters are free to move · Operate and inspect switch interlocks · Inspect missing and lose fasteners · Inspect for cracked welds · Inspect and test CTs and PTs · Inspect secondary contacts and disconnects · Inspect and perform insulation resistance test on load side cables · Perform fuse drawer inspection (cleanliness, finger alignment, and integrity of connections) · Inspect cabinet heaters Perform PM on switchgear bus (GE): No Basis Available At This Time Perform PM on switchgear bus (West): No Basis Available At This Time Perform PM on switchgear bus (ABB): No Basis Available At This Time

34

Air Operated Valves Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe Mild

X X

X

5

6

7

8

X

X

X

X

X X

X

X X

X

X

X X

X X

X

Condition Monitoring Task

Diagnostic Scan and Visual External Inspection (During Valve Stroke)

Failure Codes

AR AR AR AR NR NR NR NR

Time Directed Task

Replace Accessories

Valve Internal Inspection / Overhaul

Actuator Assembly Overhaul

4Y 6Y 4Y 8Y NR NR NR NR

AR AR AR AR AR AR AR AR

4Y 6Y 4Y 8Y NR NR NR NR

Surveillance Task

AL BK DF FG LB LC LD OC PL SB SK

Comments The AOV Program Valves shall be tested per the AOV Program requirements. This task employs the use of Flowscan or AirCEt per MA-AA-743-310. Calibration of Accessories will also be accomplished under this task. Documented visual inspections will be performed at the same time as any required diagnostic scans. In addition, visual inspections will be performed as part of established station operator rounds and system walkdown practices with noted unusual conditions being documented per the corrective action program.

Failure Codes

Comments

AG OR SL

Task includes replacement of solenoids, regulators, positioners, boosters, etc. This does not include replacement of limit switches. Frequencies for elastomer replacements to prevent failure due to elastomer degradation should be based on a review of elastomer capabilities, operating environment, maintenance history, and consideration of mechanical loading effects for the particular accessory.

AL BK CO LB PB PR RD SK

Action to be performed based on conservatively predicted or historical elastomer service life if valve includes internal elastomers. Valves that do not have internal elastomers will not receive periodic internal inspections. Valve internal work that is identified by Condition Monitoring Tasks shall be considered corrective maintenance. Inspections are to be performed on certain valves in raw water systems. These include butterfly valves that contain elastomers and/or have a taper pin connection between the shaft and disc. Also gate valves that have carbon steel internals in raw water service. See NOTE 5.

AG AL PB PR RD SB SK

Frequencies for elastomer replacements to prevent failure due to elastomer degradation should be based on a review of elastomer capabilities, operating environment, maintenance history, and consideration of mechanical loading effects for the particular valve or component design being reviewed. Overhaul consists of the change out of soft parts and inspection / replacement of mechanical components as necessary.

Failure Codes

Comments

Stroke Test (Timed Stroke, SOV and AG AL CB PB AR AR AR AR NR NR NR NR No Comments Limit Switch Actuation) RD SB SK NOTE 1: "Critical" is defined as valves which are Category I,II or III in the AOV Program per ER-AA-410-1000. Category IV valves are considered "Non-Critical". NOTE 2: "Duty Cycle High" is defined as valves normally used for process control. NOTE 3: "Severe Service Condition" is defined as being in an ambient temperature condition > 140 degrees F. or installed in a fluid medium > 400 degrees F. Other conditions such as corrosive, salt, spray, steam, high vibration or unclean process medium should be considered.

35

NOTE 4: Environmental Qualification (EQ) requirements override any activities indicated here. NOTE 5: Initial inspection frequency for valves with taper pin shaft/disc connections or carbon steel internals in raw water systems should occur after 10 years of service. Degradation rates for valves in this application vary greatly and site experience should be utilized to adjust frequency accordingly. This template is the controlled revision. SME Summary The SMEs thought that the EPRI guide represented a conscious decision by the guide developers and those in the industry that provided comments during its development to apply conservative PM periods for a recommended starting point. They also made a conscious decision to focus on valves deemed critical to plant operation. The SMEs believe that proper and uniform classification practices will assure that all valves that relate to safety functions or continued efficient plant operation should fall into classes 1 through 4. Any valves properly placed into classes 5 through 6 should allow the valves to be run to failure without impacting plant operation. There should not be a separate category beyond the template classifications that is designated as run-to-failure. Valves that fall into classes 5 through 8 may have PM task established for reasons beyond plant performance ( i.e. need to maintain on regular basis to avoid worker radiation dose or others). The SMEs also thought that a considerable amount of historical information is available to assign PM periods longer than those specified in the template. For AOVs, the actual method of performing the required function may or may not be related to elastomer performance and thus a thorough review of the particular valve function, mechanical design, and elastomers used is critical to specifying cost effective PM. Challenge Meeting Notes (June 26, 2002 teleconference)1. Neither procedure MA-AA-743-310 or site documents address visual external inspection in concunction with Diagnostic Scan. SMEs will develop simple visual inspection checklist and provide a request to Maintenance to add it to MA-AA-743-310. 2. It is understod that calibration of accessories will be accomplished in conjunction with the diagnostic scan even though calibration is defined in work documents as a seperate work activity. The meeting participants approved the template based on the changes made and the understanding from notes 1 & 2 above. Boundary Definition The boundary of an Air Operated Valve for the purpose of this database is defined to include valve body, actuator and accessories, as follows: · Valve body assembly, included only to the degree that its failure mechanisms are caused by actuator faults, or are detected by actuator PM tasks. · Actuator assembly, both piston and diaphragm actuators, with or without spring return · Manual operator · Accessories - Solenoid Operated Valve (SOV) - Positioner - Booster - Accumulators - Pressure Regulator / Filter Canister - Pneumatic Tubing - Pneumatic Switches - Limit Switches - E-P/I-P Transducer - Check Valves - Position Transmitters Not included are controllers, hand and automatic switches, and the instrument air isolation valve.

Basis For Template Tasks Diagnostic Scan and Visual External Inspection (During Valve Stroke): Frequencies may vary depending on history / trending and are integrated with AOV program requirements. Baseline and periodic testing of Category I valves will be determined by the Utility AOV Program. These requirements agree with EPRI TR-106857-V1 Application Note 2.3.4 for Diagnostic Scan. Diagnostic scans check the operability of all the accessories, the actuator, and the valve as a single integrated unit. As a minimum they provide a verification of the calibration data and the calibration process. This verification includes being within overall tolerances for the complete valve as a system. Although scheduled documented visual inspection is considered a cost effective measure by EPRI TR-106857-V1 no AOV engineer could identify a case where it would have prevented a component failure. A case where operator rounds did prevent a failure was noted. Based on the perceived need for additional resources to perform scheduled visual inspections and apparent lack of benefit, this requirement was eliminated other than being performed at the same time as any required diagnostic scans of AOVs. Replace Accessories : Generally Follows EPRI TR-106857-V1. Accessory replacement is motivated mostly by the need to address worn out or degraded soft goods within each accessory device or component. Deterioration of soft goods and also mechanical wear both lead to symptoms observable in diagnostics or to some degree by calibration drift. Because repair or refurbishment is not usually cost-effective for accessories, the recommended PM task is to replace them. Even though the removed accessories are not refurbished, a sample should be inspected for degradation that may indicate a need to adjust the current replacement interval. If calibration data is trended it may serve to show that the replacement interval should be adjusted. Solenoid Valves - Does not follow EPRI TR-106857-V7 Directly, which indicate 5Y for 1 & 3 and 10 Y for 2 & 4, but does follow the intent as addressed by the associated table note and 2.3.1. period was conservatively reduced to match 2 Y refuel cycles.

36

Regulators - Follows EPRI TR-106857-V1 directly for Air Supply filter replacement. Since most regulators and filters are combined in one unit it was thought by the SMEs that base requirements for replacement of the unit should follow the EPRI recommendation for filter replacement. Notes are included to allow increase of PM period based on elastomer evaluation and observed condition of the used filter when filter/regulator is replaced. Boosters - The EPRI frequency of 10Y for 1 & 2, and 12 Y for 3 & 4 is based on the low frequency of booster problems. Therefore the Utility frequency is conservative. The notes indicating use of the elastomer evaluation and consideration of mechanical effects will address any basis for variations. Valve Internal Inspection / Overhaul: Does not follows EPRI TR-106857-V1 directly, which indicates 10Y for 1 & 3 and 12 Y for 2 & 4, but does directly follow EPRI suggestion (per 2.3.10) that "the valve body assembly is a good candidate for maintenance through a 100% condition-based program". For carbon steel gate valves and butterfly valves with taper pin connections in raw water service experience (including MOV experience) has shown degradation rates vary but are often more rapid than other applications. Actuator Assembly Overhaul: Follows EPRI TR-106857-V1 directly except period for 1 & 3 were conservatively reduced from 5y to 4Y to correspond with 2 Y refuel cycles. - Note to use elastomer evaluation and to consider mechanical loading was included to allow adjustment of the PM period. This adjustment should be based on elastomers used and design loading (i.e. Piston actuator piston seals are likely to have a greater wear factor than diaphragm actuator elastomers due to sliding friction with the cylinder wall). Stroke Test (Timed Stroke, SOV and Limit Switch Actuation): Follows EPRI TR-106857-V7 (solenoid operated valves) directly except NR was used for classes 5-8 which matches EPRI TR-106857-V1 (Air-Operated valves)directly and is consistent with class 5-8 requirements for other tasks on the template . AR Frequency should be based on Tech. Specs., Operating Procedures, etc. Trending is performed per the IST Program with the results reviewed by the AOV Program Engineer. Frequency should also be based the particular type and model of solenoid valve installed (i.e. some solenoid valves have been know to stick due to assembly lubricant or compounds if not cycled at a sufficient frequency. The potential for sticking conditions may be affected by operating environment).

37

Centrifugal Air Compressor Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe

X X

X

6

7

8

X

X

X

X

X X

X

Mild

5

X X

X

X

X X

X X

X

Condition Monitoring Task

Failure Codes

Comments

Vibration Analysis

1M 3M 3M 3M 3M

AG BS DA DL FD FL GW IW LC

No Comments

AL BS CD FL GW IW OR SPH UD

No Comments

1M

1M

1M

Performance Trending

1M

1M

1M

1M 3M 3M 3M 3M

AG DE MB SPL

Oil Analysis

6M

6M

6M

6M 1Y 1Y 1Y 1Y

AG BS CO DA DL ER GW MS

No Comments

Operator Rounds

1S

1S

1S

1S 1D 1D 1D 1D

AL FD FG LC MB UD

No Comments

Failure Codes

Comments

Time Directed Task Calibration

Check Valve Inspection Fan Filter Clean / Inspect

Intake and Oil Filter Replacement

Major Overhaul

Minor Overhaul

6M

6M

6M

6M 1Y 1Y 1Y 1Y

3M

5Y

1Y

6M

3M

5Y

1Y

6M

6M

5Y

1Y

See basis

AG BF BK DF ER FD HB HP OR SK ST

See basis

AG BS DA MB

see basis

6M 3M 3M 6M 6M

DA

If inlet filter DP monitoring is possible filter change should occur when DP has increased 4-5" of water over baselineoperating-data (BOD. See EPRI/NMAC TR 108147

5Y

AG BF CO DA ER FD FG FL GL GW IW LC OR

Condition Monitoring tasks should be utilized to validate/extend major overhaul time interval (MTBR). See basis

DA ER GW IW

Dependent on maintenance history, condition monitoring technologies analysis clean impellers(dirt accumulation) . Functionally check inlet valvea and un-loading valves. Perform "surge" testing. Inspect, clean, fluish inter/after coolers and other heat exchanger raw water sides .

1.5Y 1.5Y 1.5Y 1.5Y 2Y 2Y 2Y 2Y 6M

AG BK CD CN DA DE LS OC SPH SPL ZO ZS

6M 6M 6M 6M 6M

1Y

5Y 5Y 7Y 7Y

1Y AR AR AR

This template is the controlled revision. Please refer to MA-AA-716-210 & MA-AA-716-210-1001 for additional guidance. SME Summary Template was based upon EPRI proposed Centrifugal Compressor template and ammended with operating/maintenance history and guidance derived from EPRI TR-108147: COMPRESSED AND INSTRUMENT AIR SYSTEM MAINTENANCE GUIDE, and EPRI Report 1009154: LIFE CYCLE MANAGEMENT PLAN FOR CONTROL AIR SYSTEM AND STATION AIR COMPRESSORS AT SALEM STATION, and EPRI Report 1006609: LIFE CYCLE MANAGEMENT PLANNING SOURCEBOOKS, VOLUME 1: INSTRUMENT AIR SYSTEMS. Boundary Definition The boundary of a typical centrifugal compressor for the purpose of this database is defined to include the following: All components on the compressor skid except the motor. This means all components from the inlet air filter up to the discharge valve, inclusive. Exclude the motor driver. Basis For Template Tasks

38

Vibration Analysis: Vibration Analysis has the objective of measuring long term degradation, often by detecting subtle changes, and assessing the health of the compressor. Record and trend vibration measurements to determine vibration characteristics of the compressor, including coupling, bearings, and compare with installed vibration monitoring equipment/readings. Vibration Monitoring and Analysis is important for effectively addressing buildup of contamination on impellers, wear of couplings, bearings, and impellers. Frequent (monthly) performance of this task guarantees adequate coverage of the randomly occurring failure modes it addresses. Performance Trending: Performance Trending is intended to verify normal compressor operation. Performance Trending has the objective of measuring long term degradation, often by detecting subtle changes, and assessing the health of the compressor. The monthly interval is consistent with the significant number of common and random failure modes addressed, although it is not completely determined by them. Performance Trending should include the following activitie as a minimum: Record and trend all temperatures, pressures, delta P's, and delta T's. Additionally record and trend vibration levels from the installed vibration monitoring system. Checks of of compressor load and unload times against baseline-operating-data (BOD). Observe load and unload pressure set points while checking load and unload frequencies Performance Trending is important for effectively addressing plugged inter-coolers and after-coolers, failed SOV's, Frequent (monthly) performance of this task guarantees adequate coverage of the randomly occurring failure modes it addresses. Performance Trending can detect large leaks of air, water, or oil, abnormal pressures or temperatures, alarms, clogged filters, and failed fans and electronic components. Oil Analysis: The objective of oil analysis is to ensure high quality lubrication of the compressor. The task interval is consistent with the failure mode data but is not completely determined by it. Oil Analysis should include: Analyze the oil for wear particles, water, and lubricity Check for signs of oil leakage. Oil Analysis is directed towards wear of bearings and gears, and the maintenance of high oil quality. It also provides an opportunity to detect water leaks from the lube oil cooler. Most of these failure modes are random in occurrence, and lube oil cooler leaks are quite common. experience and with the random failure modes addressed. Maintaining oil quality and care is key to the reliability of centrifugal compressors. This emphasizes the importance of the oil sampling program. Operator Rounds: Operator Rounds are intended to verify normal air system operation. Operator Rounds generally detects large leaks of air, water, or oil, as well as loose, damaged or missing fasteners, abnormal pressures or temperatures, alarms, clogged filters, and failed fans and electronic components. Operator Rounds are well suited to detecting failures such as clogged inlet air filters, leaks in intercoolers and after-coolers, control cabinet fan failures or clogged filters, a failed electronic controler, a leaking or plugged lube oil cooler, and leaking gaskets. These are just a few among the large number of failure modes which can be addressed with this task. This task is performed every shift when performed by operators. This frequency is sufficient to detect randomly occurring and short term wearout failure modes with high effectiveness. Calibration: Calibration has the objective of ensuring that inlet and bypass valves, actuators, auxiliaries, and transducers operate correctly to control integral operation of the compressor. The interval is meant to be a mean. There may be components that historically require calibration sooner and some maybe extended to a year or more dependent upon history. Calibration should include calibration of: Inlet throttle/ blow off or bypass control valve circuits (diaphragm actuator type) Valve position transducers Pressure and temperature transducers Calibration is focused on detecting and correcting drift in pressure and temperature transducers, and in valve position transducers, as well as linkage and gear binding of the inlet throttle valve (guide vane type). Check Valve Inspection: This task is focused entirely on ensuring proper operation of check valves, which protect the compressor against surging and reverse rotation. Check valve inspection consists of removing the cover plate and performing an internal inspection without dismantling the entire internals. Check Valve Inspection addresses the check valve failure modes of internal leakage and broken springs. These failure modes are the wearout kind with likely failure free periods of 2 years or more. Fan Filter Clean / Inspect: This task has the objective of ensuring that the controller cabinet fan and fan filter provide adequate, clean cooling air to the cabinet. The interval is consistent with the failure data but is not completely determined by it. Fan Filter Clean And Inspect requires the cabinet fan to be inspected for proper operation, and the fan filter for cleanliness. Fan Filter Clean And Inspect addresses only the controller cabinet vent fan - clogging and failure modes. These failure modes are common, and also develop on short time scales. The task interval is consistent with the relevant failure modes, although some extension may be possible if the local atmosphere has proved to be very clean. Intake and Oil Filter Replacement: The objective of this task is to keep the filters and demister clean and in good condition. The interval is completely determined by the failure mode data. Intake And Oil Filter Replacement focuses entirely on element type air intake filters, lube oil filter, and demister. Clogging failures of these filters and demister are wearout processes which develop on a time scale of 6 months to two years. The 3 month interval for critical compressors in severe service conditions is clearly necessary to protect against clogging of the filters. Major Overhaul: This task has the objective of inspecting almost all internal components and replacing end of life components. The interval is well defined by the underlying failure data. Overhaul consists of a complete tear down and inspection (for wear, damage, and contamination)/ replacement of compressor and lubrication system components. These should include: Clean and inspect: Oil strainers and oil pumps and orifices, for contamination and wear Valve actuators, and adjust Oil coolers Impellers, diffusers, nozzles, and volutes Main line coupling All bearing surfaces, and replace all bearings Bull and pinion gears and shaft Prelube and main shaft-driven oil pumps; it is also recommended to megger the pre-lube pump motor Drain traps Check-valves for leaks, broken springs, and worn surfaces Consider replacement of control relays Consider replacement of AMOT oil temperature control valves Reassemble all parts using new gaskets where appropriate. Overhaul addresses a very large range of failure mechanisms, which include dirt buildup on inlet nozzle and impellers, erosion of diffusers and the inlet nozzle, wear of the bull gear shaft and pinion shaft seals (air and oil), wear of oil line orifices, seal leaks in the main (shaft driven) lube oil pump, and clogged or stuck closed drain traps. These failure modes, and many others which are addressed, have wearout characteristics with failure free periods of 5 years or more. The task interval is well suited to the very large number of wearout failure modes which have 5 year or longer wearout periods. This interval should be correlated with run hours, not calendar time, and should occur at 40,000 to 50,000 hours of service. Minor Overhaul: history identifies the prudency of a "minor" overhaul, including flushing/cleaning of heat exchangers utilizing raw water as a cooling medium for when thermal analysis is not practical .

39

Check Valves Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe Mild

X X

X

5

6

7

8

X

X

X

X

X X

X

X X

X

X X

X

X

X

X

Condition Monitoring Task

Non-Intrusive (Diagnostics or In-Service Tests)

Failure Codes

2Y 4Y 6Y NR 2Y 6Y 8Y NR

Time Directed Task Internal Inspection for Valves with NonIntrusive or In-Service Tests

6Y 8Y 12Y NR 8Y AR AR NR

BK HB HP PO

Comments These tests may include the application of accoustics, ultrasonics, magnetics, leak rate tests, verification of forward flow or prevention of reverse flow, radiography and other documentable techniques.

Failure Codes

Comments

AG BK CO ER HP LC PO

This task may consist of a general inspection of internal condition and freedom of movement or a detailed dimensional inspection of internal components in accordance with

This task may consist of a general inspection of internal condition and freedom of movement or a detailed 4Y 6Y 8Y NR 4Y 8Y 12Y NR dimensional inspection of internal components in accordance with Note 1: "Critical" check valves are important to power production and system equipment reliability Note 2: "Duty Cycle High" applies to valves that are normally in service and/or are cycled frequently. "Duty Cycle Low" applies to valves that are normally in a standby condition. . Note 3: "Service Condition Severe" relates to valves that are most susceptible to wear or degradation as a result of physical design, orientation, system operating parameters, function, or materials. "Service Condition Mild" applies to valves that are not susceptible to wear or degradation. . Note 4: This template does not apply to those valves that are subject to inspections and tests performed under the Exelon Standard Check Valve Program, or Condition Monitoring Program for the IST Program valves. However, this PCM template may be used to establish initial (baseline) PM tasks and intervals for check valves within the Exelon Check Valve Program in accordance with ER-AA-400-1001.

Internal Inspection for Valves that do not have Non-Intrusive or In-Service Tests

AG BK CO ER HP LC PO

This template is the controlled revision. Please refer to MA-AA-716-210 & MA-AA-716-210-1001 for additional guidance. SME Summary The SME approach is based on a combination of EPRI guidance and extensive experience acquired through the implementation of SOER 86-03. This template may be used to establish baseline inspection and diagnostic test intervals in accordance with the guidance found in ER-AA-400-1001, Check Valve Monitoring and Preventive / Predictive Maintenance Program. Boundary Definition The boundary of a check valve includes the valve body assembly and all internal subcomponents involved with seating and other required functionality. Basis For Template Tasks Non-Intrusive (Diagnostics or In-Service Tests): EPRI TR-106857 - V5 Section 2.3.1 states in part; Diagnostic testing can detect oscillations of the disc and plug but are not effective in diagnosing the degree of wear, if any. A bent disc arm, or worn hinge pin, disc post hole or disc hinge pin hole might cause internal leakage so that acoustic testing could then become more effective. Although the degradation in these cases could be either continuous or random, it is felt that the failure times would most likely be random in all cases. In either case the diagnostic tests should be used to review and confirm the need for, or to defer the partial internal inspection, or to determine if overhaul is required. Internal Inspection for Valves with Non-Intrusive or In-Service Tests: EPRI TR-106857 - V5 Section 2.3.4 states in part; Partial Internal Inspection is performed to discover degradation from erosion, corrosion, wear, loose, damaged (i.e. misaligned, bent, distorted, cracked, chipped), or missing components, binding that restricts free movement, and the buildup of crud or debris on the body or disc seat areas. The inspection is capable of detecting such degradation affecting most parts of the valve, although the seat areas are difficult to inspect in-situ, and wear may not be discovered until it has progressed significantly. Verification of clearances per the vendor manual requires an overhaul. Of the above degradation mechanisms only erosion is likely to have a predictable failure free period of many years. The other mechanisms lead to random failure times over several years even though many of the mechanisms progress continuously in time. This is because the rates of progression are unknown and depend on many variables so that the failure times are unpredictable. Nevertheless, the graded PCM approach to scheduling routine inspections will provide sufficient intervention to prevent the vast majority of degradation induced check valve failures. Internal Inspection for Valves that do not have Non-Intrusive or In-Service Tests: EPRI TR-106857 - V5 Section 2.3.4 states in part; Partial Internal Inspection is performed to discover degradation from erosion, corrosion, wear, loose, damaged (i.e. misaligned,

40

bent, distorted, cracked, chipped), or missing components, binding that restricts free movement, and the buildup of crud or debris on the body or disc seat areas. The inspection is capable of detecting such degradation affecting most parts of the valve, although the seat areas are difficult to inspect in-situ, and wear may not be discovered until it has progressed significantly. Verification of clearances per the vendor manual requires an overhaul. Of the above degradation mechanisms only erosion is likely to have a predictable failure free period of many years. The other mechanisms lead to random failure times over several years even though many of the mechanisms progress continuously in time. This is because the rates of progression are unknown and depend on many variables so that the failure times are unpredictable. Consequently, the proposed inspection intervals are more frequent than those proposed for valves having a routine non-intrusive condition monitoring task. The proposed inspection interval for those valves with routine non-intrusive testing, is at least twice the nonintrusive test frequency.

41

DC Motors Component Classification Categories Yes

Critical Duty Cycle

1

2

3

4

X

X

X

X

No High

Service Condition

X

Low

X X

Severe

X

6

7

8

X

X

X

X

X X

X

Mild

5

X X

X

X X

X

X

X

X

Condition Monitoring Task

Failure Codes

Comments

Vibration Monitoring

6M

4Y

6M

4Y NR NR NR NR

OC

EPRI TR-106857-V11 Application Note 2.3.1

Insulation and Winding Resistance Test

3Y

4Y

3Y

4Y AR AR AR AR

IB

EPRI TR-106857-V11 Application Note 2.3.2

Time Directed Task External Visual Inspection Brush Maintenance

OPN OPN OPN OPN AR AR AR AR 6M

4Y

6M

4Y AR AR AR AR

Surveillance Task

Failure Codes

Comments

DA GL LC OR

EPRI TR-106857-V11 Application Note 2.3.3

BK CO DA ER FD

EPRI TR-106857-V11 Application Note 2.3.4

Failure Codes

Comments

EPRI TR-106857-V11 Application Functional Testing AR AR AR AR AR AR AR AR OC Note 2.3.5 * Critical No The template does not apply to the Run- To -Failure components;non-critical here means not critical but important enough to require some PM tasks. This template is the controlled revision. SME Summary No SME Summary Available At This Time Boundary Definition The boundary of a DC electric motor for the purpose of this database is defined to include the following: · Electric motor and motor shaft excluding the coupling · All power, sensing, and control cables up to but not including the DC breaker · Motor mounting and base · Internal motor heaters

Basis For Template Tasks Vibration Monitoring: 2.3.1 Vibration Monitoring Failure Locations and Causes: Vibration monitoring is very effective for addressing all the causes of wear in anti-friction bearings. Additionally, vibration monitoring addresses all causes of failures originating in the shaft, all causes of failures originating in the armature, and a worn or loose commutator. Cracks, weld failures, and deformation in the frame, enclosure and mounting, soft foot, and other deformation or misalignment causing or caused by failure of machine fits, are also likely to result in detectable vibration. Progression of Degradation to Failure: Most of the causes of bearing failure appear randomly over a period of several months up to 2 years. The appearance of wear and cracks in the shaft, all degradation mechanisms in the armature, and a worn or loose commutator, although random in occurrence times, are not expected within a few years. The onset of degradation in the frame, such as deformation, cracking, and soft foot share similar timing characteristics as for the shaft and armature. Progression to failure could be rapid if the vibration is close to a structural resonance, and could be almost immediate if caused by personnel error. Fault Discovery and Intervention: Vibration monitoring addresses a wide range of degradations in DC motors, only about a third of which are also covered by another task. This makes vibration monitoring a very important part of the PM program. Most of the degradations addressed by vibration monitoring lead to a fairly random occurrence of failures over a period of a few years to many years. However, continuously running motors are subject to much more rapid wear on the brushes, bearings, armature, commutator, and shaft than is the case for standby motors. Consequently, the suggested interval of 6 months for continuously running critical motors should be sufficiently frequent to permit vibration monitoring to detect almost all failures from the above degradation modes before they occur. Standby motors will generally have a much lower wear rate, although no wearout pattern is observable. Insulation and Winding Resistance Test: 2.3.2 Insulation and Winding Resistance Test Failure Locations and Causes: This task simply consists of measuring winding resistance, and insulation resistance. The detection of degraded insulation focuses on windings, feeder cables, motor leads, and space heaters. Winding resistance enables the detection of high resistance electrical connections, and shorts between turns. Progression of Degradation to Failure: Electrical insulation is subject to continuous degradation. The main causes of insulation degradation are excessive heat above the rated limit, excessive starts within a short period, winding movement and vibration, age, and contamination (which may be e.g. oil, moisture, salt). Although the initiation of these influences may be random, the degradation progresses relatively slowly and is expected to give a trouble free period of at least several years (exception could be high temperatures from excessive starts within a short period, which should be controlled by operational procedures). Problems with feeder cables, motor leads, connections, and lugs are likely to occur randomly on various time scales, shorter than those above. Fault Discovery and Intervention: Most of the degradations addressed by the measurement of winding and insulation resistance produce measurable

42

effects before failure on a time scale of a few years. Consequently these tests could be performed every 3 or 4 years and provide effective coverage for the degradation modes discussed above. These tests are usually the only means normally employed to discover the degradation Electrical off-line tests can only be conducted meaningfully when all parts of the motor are within 10° F of ambient temperature. The results of the tests should be recorded and compared to previous data to derive their maximum benefit: · Winding resistance · Insulation resistance External Visual Inspection: 2.3.3 External Visual Inspection Failure Locations and Causes: The external visual inspection focuses mainly on visible indications of leakage of grease, either from worn bearing seals, failed gaskets, or from the use of excessive grease. Other grease related problems such as degraded or insufficient grease, or the use of an incorrect type of grease, may also be observable. External visual inspection is also effective for detecting blocked air inlets. Damaged junction boxes, conduits, or seal flex might also be visible. Failed banding will usually be detectable during the inspection by the audible noise it produces. Improper length or position of brushes and excessive sparking between brushes and commutator are not generally observable without removing an inspection plate. Consequently these aspects of inspection are included in the brush maintenance task. The inspection also includes general observation for loose, missing, or damaged parts, and listening for unusual noises or vibrations, e.g. from mechanical interference between armature and stator. Progression of Degradation to Failure: All the above degradation mechanisms are random in time of onset but in most circumstances are expected to appear over periods of many months or years, and are not expected to lead to failures on short time scales. Fault Discovery and Intervention: The observation of leaks, clogged air inlets, loose or damaged conduits or seal flex, and the detection of audible noise, are simple tasks that can be covered by operator rounds, rather than by a scheduled PM task. Although it may be convenient to address the visual inspection items in operator rounds for critical motors, there does not appear to be a need to make these observations as often as every shift. External visual inspection should contain the following: · Inspect for general cleanliness · Inspect for blocked inlet air screens · Inspect for loose, damaged, or missing parts and bolts · Inspect for damaged conduit or seal flex · Inspect for loose / damaged ground wires · Inspect for damaged junction boxes and gaskets · Inspect for excessive grease · Listen for unusual noises or vibrations · Verify operation / status of motor heaters, if present Brush Maintenance: 2.3.4 Brush Maintenance Failure Locations and Causes: Brush Maintenance is an inspection of the brushes and commutator. A worn, corroded, or loose brush holder or commutator, is likely to be revealed by erratic operation and excessive sparking. To some degree, contaminated or degraded insulation may also be observable. Progression of Degradation to Failure: Worn brushes may lead to failures in just a few weeks in problem situations, although a much longer useful life is normally expected. Commutator problems usually show up on much longer timescales than brush problems, in years rather than weeks. Fault Discovery and Intervention: The condition of the brushes is therefore the key consideration that controls the task interval. Wear rates will be very dependent on the accumulated run time. Continuously running motors should have brush inspections at six month intervals unless operating history indicates otherwise. Standby motors could be inspected at 4 year intervals provided they are run or tested occasionally to prevent oxidation of the commutator / brush interface. Operating history is crucial to finding the appropriate intervals. Brush maintenance should contain the following: · All items from the External Visual Inspection · Inspect the condition of the commutator for grooving, excessive wear, and indications of high mica; refer to plant procedure or manufacturer’s technical manual for instruction for cleaning, polishing, or resurfacing of the commutator, if required · Inspect commutator for discoloration indicating loss of electrical contact with the brushes · Inspect the brushes for wear or grooving · Inspect the brushes for freedom of movement and for proper spring tension · Inspect brushes for proper operating length as prescribed by the manufacturer · Inspect the brush pigtail connection for tightness and any damaged · Inspect the commutator and brush housing for signs of excess carbon, clean if necessary · Inspect the condition of the brush rigging for loose, damaged, or missing parts, springs, brushes, and bolts · Inspect for loose or damaged brush leads and motor connections · Verify the brushes are the correct type as specified by plant procedures or the manufacturer · Inspect for the presence of grease on the commutator or brushes Functional Testing: 2.3.5 Functional Tests The functional test is a start / run test conducted as a post maintenance test on the motor to verify operability, proper rotation, and readiness for return to service and also frequently as a post maintenance test on the driven equipment. Other forms of functional testing are IST tests that verify the operability of stand-by equipments. The Functional test should be performed when: - Returning powered equipment to service - As per technical specifications or as a post maintenance test

43

Feedwater Heater Component Classification Categories 1 Critical Duty Cycle Service Condition

Yes

X

2

3

4

X

X

X

No High

X

Low Severe

X X

X

Mild

5

6

7

8

X

X

X

X

X X

X

X X

X

X

X X

X X

X

Condition Monitoring Task

Failure Codes

Comments

Performance Monitoring

1M

1M

CO FL

See EPRI TR-106857-V33 Application Note 2.3.1

NDE Inspection

6Y

12Y

CO ER

See EPRI TR-106857-V33 Application Note 2.3.2

Failure Codes

Comments

Time Directed Task

CO DA ER FD FL GL SeeEPRI TR-106857-V33 Application Internal Inspection 6Y 12Y OR Note 2.3.3 *Critical – No: The Template does not apply to the Run-To-Failure components; non-critical here means not critical but important enough to require some PM tasks. Service Conditions: For this template, severe service is defined as those feedwater heaters with steam on the shell side, and mild service is defined as those feedwater heaters with water on the shell side. This template is the controlled revision. Please refer to MA-AA-716-210 & MA-AA-716-210-1001 for additional guidance. SME Summary The boundary of feedwater heaters for the purpose of this database is defined to include the following: · Nozzle to nozzle, including shells and internal components · Excludes control systems and devices, safety relief valves, and insulation. · Excludes the main steam reheaters (MSR). The expert group identified the most common, i.e. dominant, failure locations and mechanisms for this equipment to be: · Tube failures · Shell Erosion · Mechanical failures of internal hardware Problems that have commonly occurred as a result of maintaining tube type heat exchangers include the following: · Tube degradation as a consequence of cleaning. Industry References: 1. EPRI TR 108009, “BOP Heat Exchange Condition Assessment Guide”, June, 1998. 2. ASME “Standards and Guides for Operation and Maintenance of Nuclear Power Plants”, OM-S/G-1994 , Part 11, Vibration Testing and Assessment of Heat Exchangers”.

Boundary Definition The boundary of feedwater heaters for the purpose of this database is defined to include the following: · Nozzle to nozzle, including shells and internal components · Excludes control systems and devices, safety relief valves, and insulation. · Excludes the main steam reheaters (MSR). Basis For Template Tasks Performance Monitoring: 2.3.1 Performance Monitoring Failure Locations and Causes: Performance Monitoring addresses the overall integral performance of the heater. Performance deterioration detectable by this task is likely to be caused by corrosion or cracking of the tubes,or scaling or other deposits,or changes in operating level. Progression of Degradation to Failure: Corrosion is caused by a variety of conditions which are all characterized by random occurrence times and the possibility of rapid deterioration. The randomness of these failure causes and their potential to develop quickly requires frequent Performance Monitoring. Fault Discovery and Intervention: Monthly Performance Monitoring is recommended for all feedwater heaters. Performance Monitoring should include: · Monitor, track, and trend the heater Terminal Temperature Difference (TTD) · Monitor, track, and trend the heater Drain Cooler Approach Temperature (DCA) · Monitor, track, and trend the DT across the heater · Monitor, track, and trend shell pressures · Monitor, track, and trend the position of the level control valves · Monitor, track, and trend the position of the liquid level All parameters should be monitored monthly with the exception of level control valve position. As long as heater level is trended monthly, level control valve position need only be monitored if there are problems maintaining desired level. NDE Inspection: 2.3.2 NDE Failure Locations and Causes: Non-Destructive Examination could include a variety of techniques, as

44

appropriate, but is generally focused on erosion (external and internal) and scaling of tubes, tube cracking or other defects, and the condition of the shell-side inlet nozzle. Among these, tube problems and shell erosion are the most common. Manufacturing or installation defects in tubes are dependent on this task for their detection prior to leaking. Progression of Degradation to Failure: The above failure causes are random in nature with a wide range of possible development times, depending on condition. The occurrence of these events might influence the frequency of NDE. Fault Discovery and Intervention: This task is not a significant additional effort once the heater has been opened up, and so is closely associated with the performance of the Internal Inspection. Although NDE Inspection is primarily a material condition assessment, the information it provides is predictive of future deterioration. For this reason, even though the suggested interval is 6 to 12 years, this is best interpreted as an average interval, with a sampling scheme that provides a more or less continuous assessment of condition. It is recommended that a full string of heaters (with the exception of drain coolers) be examined in each outage. In a plant with three strings of feedwater heaters, this will yield an average inspection interval of 6 years for each heater. Drain coolers would be examined every other outage, yielding an average inspection frequency of 12 years. However, if a specific heater is known to have an active degradation mechanism, that heater shall be inspected every outage. Also, any heater with suspected tube leaks shall be inspected. If testing shows no degradation mechanisms are active, the testing interval can be increased. Ultrasonic measurement of shell thickness should be performed on those heaters which may be susceptible to shell erosion. UT wall thickness examinations should also be made on shell operating vent piping subject to erosion. NDE could include the following: · Eddy current · Dye penetrant · Ultrasonic thickness · Borescope Internal Inspection: 2.3.3 Internal Inspection Failure Locations and Causes: This inspection is focused on detecting the extent of internal tube erosion, corrosion, and scaling. Progression of Degradation to Failure: The above failure causes are random in nature with a wide range of possible development times, depending on condition. The occurrence of these events might influence the frequency of Internal Inspection. Fault Discovery and Intervention: The information this task provides is a material condition assessment but is also predictive of future deterioration. For this reason, even though the suggested interval is 5 to 10 years, this is best interpreted as an average interval, with a sampling scheme that provides a more or less continuous assessment of condition. To achieve this it is beneficial to perform the task each outage on a portion of the heaters. As an example, consider a set of 18 high pressure heaters, of which 3 are examined each outage, starting with the first outage in a continuing cycle. Over the first 9 years of plant experience the average interval is then close to 5 years; over the first 18 years the average moves out to 7 years, and then to over 8 years in the third decade. Low pressure heaters would be examined every second outage so that the average intervals would be 10 years, then 14 years, then 16 years. This kind of sampling scheme is very stable, provides continuous feedback on equipment condition, starts close to the average intervals shown in the Template, provides early feedback early in the life of the equipment, and provides a significant degree of interval extension over the life of the heaters provided experience remains good. Internal inspection should include the following: · Inspect for evidence of erosion or corrosion. · Inspect the gaskets and channel heads for evidence of leakage. · Inspect for loose, missing or damaged fasteners. · If performance monitoring or other inspections indicate the need, perform a borescope inspection on a representative sample of tubes, and inspect the shell side, if possible. · Visually inspect for the presence,amount,and type of fouling. · Inspect condition of passive cathodic protection devices, if present. · If appropriate, determine the degree of fouling for the heater, in order to adjust the cleaning interval. · Verify that previously plugged tubes are still plugged (i.e. use the tube plug map). · Inspect welds between the pass partition and channel for evidence of failures. · Perform tube and shell pressure/vacuum test to detect suspected leaks in tubes or at the tube joints.

45

GE - High Pressure Main Turbine Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe

X X

X

Mild

5

6

7

8

X

X

X

X

X X

X

X X

X

X

X X

X X

Condition Monitoring Task

Pre-Shutdown Full Load Vibration and Analysis

Return to Service Full Load Vibration and Analysis

2Y

2Y

Time Directed Task

X Failure Codes

Comments

OC

Prior to Unit shutdown review vibration data. If no high vibration (less than 5 mills), take vibration data only, but no analysis for balance weight installation is required. Analysis is required for balance weight installation if pre-shudown vibration is greater than 5 mills.

OC

After startup when unit reaches full load,review vibration data. If no high vibration (less than 5 mills), take vibration data only, but no analysis for balance weight installation is required. Analysis is required for balance weight installation if post outage full load vibration is greater than 5 mills.

Failure Codes

Comments

Steam Seal Casing /Packing Head Inspection

10Y

BF ER SL

No Comments

Steam Path Inspection

10Y

ER OC

No Comments

Oil Deflector Inspection

10Y

FL OC OR

No Comments

Front Standard Component Inspection

6Y

CO ER GW IB OC

PMG Inspection

6Y

CD GW IB IW LB LS

Rotor NDE Inspections (Include Boresonic/Dovetail)

10Y

LC OC

No Comments

Diaphragm NDE Inspection

10Y

ER OC

No Comments

Thrust Bearing Inspection

6Y

ER OC

No Comments

Hydraulic Thrust Bearing Wear Detector 4Y Inspection

DE OC

For Sites using Poximity Probes, the probes are checked during their alignment (gap seting) after the Thrust Bearing is inspected and then reinstalled.

HydraulicThrust Bearing Wear Detector Inlet Strainer Inspection

2Y

DA

No Comments

Outer Shell Inspection

10Y

ER SL

No Comments

Bearing & Journal Inspections

10Y

ER OC

No Comments

Piping Face Flange Inspections

10Y

BF ER GL

No Comments

Coupling Faces & Spacer Visual Inspection

10Y

FD

No Comments

Bolting (Horizontal Joint/Coupling) & Sleeve NDE

10Y

AG FD OC

No Comments

As-Left Alignment Readings

10Y

OC

No Comments

Overspeed Functional Testing

2Y

OC

No Comments

Remote Shaft Voltage Test Mechanism Inspection

2Y

IB

Shaft Grounding Copper Braids or Brush 2Y Replacement

CD CN DA LC

2-When replacing Shaft Grounding Copper Braids/Brushes clean the shaft areas underneath the copper braids/Brushes. 3Replace Front Standard Grounding Brushes, if installed in the front standard.

Surveillance Task

Failure Codes

Comments

Hydraulic Thrust Bearing Wear Detector 1M Testing

OC SK

Shaft Voltage Measurement with

IB

7D

46

Remote Voltmeter Shaft Voltage Measurement with DC 7D IB Coupled Oscilloscope The inspection intervals are based upon: - Unit actual operating hours - HP section historical operational/maintenance data, industry experience - OEM recommendations REF: GE Turbine-Generator Manual for detailed instructions for the listed tasks. This template is the controlled revision. Please refer to MA-AA-716-210 & MA-AA-716-210-1001 for additional guidance. SME Summary

Boundary Definition GE High Pressure Turbine Assembly including Front Standard. Basis For Template Tasks Pre-Shutdown Full Load Vibration and Analysis: Historical operational/maintenance data, industry experience and OEM recommendations. Pre-Shutdown Vibration Analysis: This is a valuable tool to determine if any additional inspections are required and also allow you to monitor the effects of the maintenance after restart. This data has also been used to reduce the scope of work. Return to Service Full Load Vibration and Analysis: Historical operational/maintenance data, industry experience and OEM recommendations. Return to service Vibration data: this is to compare to the shutdown data to ensure that the work that was performed returned the equipment to the same or better operation. Steam Seal Casing /Packing Head Inspection: Historical operational/maintenance data, industry experience and OEM recommendations Steam seal casing inspection: this is a visual inspection of the horizontal joint for signs of steam leakage/erosion. Steam Path Inspection: Historical operational/maintenance data, industry experience and OEM recommendations. Steam path inspection: The steam path is checked by charting of the rotor prior to removal to determine the clearances and a visual inspection is performed for signs of wear/erosion and replaced as required. Oil Deflector Inspection: Historical operational/maintenance data, industry experience and OEM recommendations. Oil deflector inspection: Visual inspection for signs of wear or blockage of oil drain ports and also dimensional data to verify clearances and if required based on inspections restripping of the seals and remachining to the design dimensions. Front Standard Component Inspection: GE TIL 973-3. GE TURBINE VENDOR MANUAL Historical operational/maintenance data, industry experience and OEM recommendations. Front Standard Inspection: Visually examine check valve components and internals, oil pump and gears for wear, damage and defects such as cracks, erosion, pitting, corrosion, wear, fretting, or other discontinuities. Resistance check of insulating coupling based on OE from Dresdens failure. Dimensional data on journals and bearings and contact check of gear mesh. PMG Inspection: TIL 973-3, GE TURBINE VENDOR MANUAL Historical operational/maintenance data, industry experience and OEM recommendations. Following Components are included in the Front Standard Inspection: 1.Control rotor assembly (includes emergency overspeed governor assembly) 2.Quill shaft assembly (includes spline teeth, extention tube, insulators etc) 3.Main Shaft Gear (include bearings and gear teeth inspection) 4.Main Shaft Oil Pump (includes pump impeller, gear teeth, bearings, seal rings, housing) 5.Main Shaft Oil Pump Discharge Check Valve Assembly 7.Low Speed Switch Assembly 8.Trip and Reset Mechanism (includes mechanical trip valve, trip finger mechanism, breakdown linkage,torque shaft assembly etc) 9.Oil Spray Nozzle (feeding the main shaft gear assembly) 10.TSI instrumentation (includes speed pickups, eccentricity, differential expansion, shell expansion) Rotor NDE Inspections (Include Boresonic/Dovetail): Historical operational/maintenance data, industry experience and OEM recommendations. NDE/Inspections: HP Turbine Internal Rotor Inspections · Rotor Bore Plug(s) removal · Rotor Bore Power honing to surface finish to allow NDE Exams · Bore Visual Exam · Bore Magnetic Particle or Eddy Current Exam · Bore Ultrasonic Exam (Radial & Axial Beam) · Contingency Rotor Bore repairs · Rotor Bore Plug(s) installation HP Turbine External Rotor Inspections · Rotor Dovetail Phased Array Ultrasonic Exam (All Stages) · Contingency Dovetail repairs/Bucket cover repairs · Rotor to Bucket/blade gap measurements (Bucket Lift Inspection) · Rotor External Fluorescent Magnetic Particle Exam (Radial and Axial Magnetization) Diaphragm NDE Inspection: Historical operational/maintenance data, industry experience and OEM recommendations. Diaphragm NDE: a visual inspection is performed for signs of cracking/ erosion and they are sandblasted if they require repairs Thrust Bearing Inspection: Historical operational/maintenance data, industry experience and OEM recommendations. Thrust Bearing Inspection: a visual inspection for signs of wear and NDE of the Babbitt PT and UT to determine bonding and then dimensional data (geometry check). Based on results of inspections will determine if bearing needs to be replaced Hydraulic Thrust Bearing Wear Detector Inspection: Historical operational/maintenance data,industry experience and OEM recommendations. During maintenance inspection,the thrust bearing wear detector should be disassembled to assure that it is clean. All oil supply tubing and the strainer in the bearing feed line should be blown clean with dry air. On the thrust wear detector with the optional four or six pressure switch scheme it is important to check the pressure switch contacts seperately during a maintenance outage. Bad electrical contacts or burnt bellows might otherwise remain hidden. HydraulicThrust Bearing Wear Detector Inlet Strainer Inspection: The lube oil supply going the Thrust Bearing Wear Detector goes through this strainer. If the strainer becomes clogged, it can restrict the oil supply to the TBWD mechasim and can cause turbine trip based upon low lube oil pressure to the trip pressure switches PS11 & 12.

47

Outer Shell Inspection: Historical operational/maintenance data, industry experience and OEM recommendations. Outer Shell Inspection: this is a visual inspection of the horizontal joint for signs of steam leakage/erosion. Inspection of the fits for signs of galling. Bearing & Journal Inspections: Historical operational/maintenance data, industry experience and OEM recommendations. Bearing & journals: a visual inspection for signs of wear and NDE of the Babbitt PT and UT to determine bonding and then dimensional data. Based on results of inspections will determine if bearing needs to be babbitted. Journal is inspected for signs of scoring/wear and is also dimensionally checked. Piping Face Flange Inspections: Historical operational/maintenance data, industry experience and OEM recommendations. Piping Face and Flange Inspections: A visual inspection for signs of erosion and dimensional data on the gasket groves. Coupling Faces & Spacer Visual Inspection: Historical operational/maintenance data, industry experience and OEM recommendations. Coupling spacers and faces: visual inspection for signs burrs or surface imperfections due to stresses. Bolting (Horizontal Joint/Coupling) & Sleeve NDE: Historical operational/maintenance data, industry experience and OEM recommendations. Bolting: the bolting is cleaned and visually inspected for mechanical condition of the threads on the studs and nuts and also NDE inspected UT to verify no indications of cracking in the stud. The coupling bolts are also visually inspected for mechanical condition and NDE of the bolts and sleeves is performed MT. As-Left Alignment Readings: Historical operational/maintenance data, industry experience and OEM recommendations. As-left alignment readings: This is performed based on operation data taken during shutdown (vibration). We do verify the rotor is in the same relative position during reassembly and if operation data requires an actual alignment check then we would perform and align as required. Overspeed Functional Testing: GE TIL 1165-3 Historical operational/maintenance data, industry experience and OEM recommendations. Overspeed Functional Testing: This is a MEIL requirement Remote Shaft Voltage Test Mechanism Inspection: GE TIL 973-3, GEK 85253, in GE TURBINE VENDOR MANUAL. Shaft Grounding Copper Braids or Brush Replacement: GE TIL 973-3.GEK 72291B in GE TURBINE VENDOR MANUAL. Hydraulic Thrust Bearing Wear Detector Testing: To prevent the sticking of the GE hydraulic TBWD mechanism and to record the detector drift and make neccessary adjustments, if the trip margin drifts down to 10 mills. This greatly increases the probability of the false trip. The TBWD detector should be adjusted to obtain 20 mills in full load trip margin as long as no thrust problems are indicated. (REf. GEK 17812E) Shaft Voltage Measurement with Remote Voltmeter: TIL 973-3, GEK 72291B in GE TURBINE VENDOR MANUAL. Acceptance Criteia < 1 VDC Shaft Voltage Measurement with DC Coupled Oscilloscope: GE TIL 973-3, GEK 72291B in GE TURBINE VENDOR MANUAL. Acceptance Criteria: < 6 VAC 0-Peak

48

GE - Main Generator Component Classification Categories Yes

Critical Duty Cycle

1

2

3

4

X

X

X

X

No High

Service Condition

X

Low Severe

X X

X

Mild

5

6

7

8

X

X

X

X

X X

X

X X

X

X

X

X

X X

Condition Monitoring Task

X Failure Codes

Comments

1M

OC

REF: GEI-74489, OE-17248

Pre-Shutdown Machine Vibration/Dynamics Analysis

2Y

OC

No Comments

Flux Probe (on-line)

2Y

SH

Performed during power-down or power-up

Return to Service Full Load Vibration / Dynamics Analysis

2Y

OC

No Comments

Time Directed Task

Failure Codes

Comments

High Voltage Bushing External Visual Inspection

2Y

CN CO DA FD GL

No Comments

Line and Neutral Side Flexible Link Visual Inspection

2Y

CN CO LC

No Comments

Generator Bushing Box Internal Visual Inspection

2Y

CO DA GL

No Comments

High Voltage Bushing to Bushing Box Flanged Connection Bolt Torque Check

2Y/10Y

FG

No Comments

Field Collector Ring Brush Vibration and Temperature

Major or (MAGIC) Inspection

6Y/10Y

CO DA FD IB OC

Units with Generator on-line Monitoring Installed: MAGIC Inspection 6 Years, Dismantle Inspection 10 years. Units without Generator on-line Monitoring installed: Dismantle inspection 6 years.

Hydraulic Integrity Testing (HIT Skid)(includes knuckles)

2Y/6Y

AL CD IB

Units with SLMS Monitoring: 4/6 & 10 Years, Units without SLMS Monitoring: 2 Years.

Oil Deflector Inspection

6Y/10Y

OC SL

No Comments

Hydrogen Seal Inspection

6Y/10Y

AL OC SL

No Comments

Bearing & Journal Inspection

6Y/10Y

ER OC

No Comments

1M

IB OC

Ref: GEI 87016C

6Y10Y

AG OC

No Comments

Fan Inspections

6Y/10Y

AL DA LC OC

No Comments

Air Gap Baffle Measurements

6Y/10Y

OC

No Comments

CO FD OC

Inspection can be performed during LP (next to generator) inspection

Stator Bore and End-Windings Inspections 6Y/10Y

FD IB

No Comments

Cooling Water Hose and Nose Ring Visual 6Y/10Y Inspections

ER LC SL

No Comments

Stator Wedge Tightness Checks

FD OC

No Comments ELCID 6-10 year frequency. Megger every 2 years.

Bearing/H2 Seal/Lift Pump Pad Insulation Measurements Coupling Bolt & Sleeve NDE

Coupling Faces & Bolt Visual Inspections

6Y/10Y

6Y/10Y

Stator Electrical Tests (ElCid, Megger, Hipot, Copper Resistance, etc.)

6Y/10Y

OC

Stator RTD and Thermocouple Checks

6Y/10Y

CD OC

No Comments

Field Visual Inspection

6Y/10Y

DA IB

No Comments

Field Electrical Tests (Megger / PI / Cu Resistance / 60 Hz Impedance / Pole Balance)

6Y/10Y

IB OC

Megger / PI / Cu Resistance every 2 years. Remaining tests every major outage.

Stator Electrical Tests (Megger / PI / Cu Resistance / HiPot)

6Y/10Y Null Null Null Null Null Null Null IB

E - Coupling Inspection / Repack with New

2Y

DL SL

49

No Comments No Comments

Grease

E- Coupling Inspection (KOPFLEX COUPLING)

2Y/10Y

DL FD OC SL

The replacement frequency is based upon acceptable coupling alignment.In case of coupling misalignment, more frequent replacement of the disk packs may be required due to increased operating stresses.

Visually Inspect and Measure Gen. Field Collector Rings

2Y

OC

No Comments

Clean and Inspect Brush Holder Rigging (Clean Fan Enclosure)

2Y

CN DA FD

Ref:(NER) DR-03-075

Replace Field Collector Ring Brushes upon wear

AR

AG OC

Use Nationtal Carbon (NC) 634 Brushes as a replacement only.

Calibrate and Check Generator Liquid Level Detector Alarm & Piping

2Y

OC

No Comments

As-Left Coupling Alignment Readings

10Y

OC

No Comments

2Y

AL

To shorten the test time for the pressure test, GE's Reference Chamber Test should be performed.

6Y/10Y

CO

Perform each major outage

2Y/6Y

FG

2Y for generators with 18Mn - 5Cr rings.

2Y

DL

Oyster Creek Only

Generator Air Test Field Retaining Ring NDE Hydrogen Cooler Leak Testing Amplidyne Gear Drive Inspection

Review TILs and OEs 2Y No Comments The Inspection intervals are based upon: - Unit actual operating hours - Generator historical operational/maintenance data, industry experience and OEM recommendations. REF: GE Turbine-Generator Manual for detailed instructions for the listed tasks. MAGIC Inspection – The Miniature Air Gap Crawler is a remotely operated robotic crawler that is inserted into the generator air gap to perform internal inspections without having to remove the rotor. An on-board camera provides detailed images of the stator bore and rotor surfaces to assess mechanical distress, overheating, and stator wedge/coil abrasion (i.e. greasing or dusting). The crawler can also be fitted with a wedge tapping device that can provide quantitative data regarding wedge tightness condition. The MAGIC inspection is designed as a substitute for rotor-pull inspections. The HIT (Hydraulic Integrity Test) is a multi-purpose portable skid used to dry the stator winding internals for and to perform a pressure/vacuum test to assess leak integrity of internal water cooling circuit. For windings susceptible to crevice corrosion (1970-1986), a capacitance test of individual stator bar end arms is performed to check for wet insulation. A helium leak search is also done to identify and quantify leak locations. Leaks can lead to wet insulation and a subsequent ground fault. [note that MAGIC and HIT Tests are technically unrelated] ElCid (Electromagnetic Core Imperfection Detection ) testing is used to check the stator core iron inter-laminar insulation. It is done with the rotor out. Stator Winding and Rotor Winding megger and PI tests are done to assess the di-electric strength of the ground wall insulation. Stator windings can be proof-tested to values up to and above operating voltage using either AC or DC high voltage test sets. Stator AC testing is a go/ no-go test with no trending capability that requires a large test transformer set. DC high voltage testing uses a small portable test set and the results can be trended, but requires that the stator winding internals be dry (i.e use of HIT Skid). This template is the controlled revision. Please refer to MA-AA-716-210 & MA-AA-716-210-1001 for additional guidance. SME Summary No SME Summary Available At This Time Boundary Definition For the purpose of this template the boundary is defined as the Main Generator between the LP Turbine Coupling and Exciter coupling to the generator. Basis For Template Tasks Field Collector Ring Brush Vibration and Temperature: Per GEI-74489, the normal brush vibration level is 0 to 6 mills (usually 1 to 2 mills). The brushes should be checked daily for sparking, chattering etc with weekly checks of vibration,signs of overheating and general visual inspection. NOTE: After the weekly monitoring, the System Engineer may analyze the data trend and may extend the monitoring frequency for vibration and/or temperature. Pre-Shutdown Machine Vibration/Dynamics Analysis: Pre-Shutdown Vibration Analysis: This is a valuable tool to determine if any additional inspections are required and also allow you to monitor the effects of the maintenance after restart. This data has also been used to reduce the scope of work Flux Probe (on-line): Detects shorted field turns Return to Service Full Load Vibration / Dynamics Analysis: Return to service Vibration data: this is to compare to the shutdown data to ensure that the work that was performed returned the equipment to the same or better operation.

50

High Voltage Bushing External Visual Inspection: Look for indications of cracking and Viscasil Leaks, which would be predecessor to potential hydrogen leakage. Line and Neutral Side Flexible Link Visual Inspection: The purpose of this inspection is to look for evidence of Leaf cracking and signs of localized overheating. Generator Bushing Box Internal Visual Inspection: While inside of Bushing Box look for a loss of Viscasil around the bushings. Also look for evidence of overheating, and cracking. Inspect Standoff insulators and as much of the exposed internal winding as possible for defects.Record extent of oil contamination. Inspect for water/oil at bottom of hydrogen passage for water cooled bushings,also inspect for leaks. Check hydrogen passages at bottom of bushings for oil blockage (use mirror). High Voltage Bushing to Bushing Box Flanged Connection Bolt Torque Check: The flanged bolt connection torque check should be peformed intially 2 years after the gasket replacement and than every 10 years to compensate for gasket relaxation. Major or (MAGIC) Inspection : The MAGIC is a remote in-situ video inspection, without removing the generator field. It is recommended by OEM too be performed every 6 years. It consists of the following inspections: Visual Inspection, Stator Wedge Tightness Assessment, Retaining Ring NDE, Bar Jacking Etc. The purpose of the 6 year generator in-situ inspection, ie. MAGIC and HIT Skid, is to assess the Stator condition, ie. insulation, leaks, etc., and Field condition, and plan for repairs/replacements, if required, at the next 10 year generator major dismantle inspection when the field is removed. Hydraulic Integrity Testing (HIT Skid)(includes knuckles) : For Units with SLMS: The Hydraulic Integrity Testing (HIT Skid) is performed every 6 and 10 year generator outage. For Units without SLMS: The Hydraulic Integrity Testing (HIT Skid) is performed every 2 years. The HIT (Hydraulic Integrity Test) is a multi-purpose portable skid used to dry the stator winding internals for and to perform a pressure/vacuum test to assess leak integrity of internal water cooling circuit. For windings susceptible to crevice corrosion (1970-1986), a capacitance test of individual stator bar end arms is performed to check for wet insulation. A helium leak search is also done to identify and quantify leak locations. Leaks can lead to wet insulation and a subsequent ground fault. Its purpose is to check the integity of the stator bars for leaks. (Ref. GE TIL 1098-3R2). It consists of the following tests: Vacuum Decay, Pressure Decay, Helium Tracer Gas, Capacitance Mapping, Meggar Generator Windings from the High Voltage Bushings. The purpose of the 6 year generator in-situ inspection ie. MAGIC and HIT Skid, is to assess the Stator condition ie. insulation,leaks etc and Field condition,and plan for repairs/replacements if required, at the next 10 year generator major dismantle inspection, when the field is removed. Oil Deflector Inspection: Inspect for evidence of rubbing and seal damage. Hydrogen Seal Inspection: Inspection includes: fit of seal, seal bracket smooth, check spring for wear and proper elongation.Inspect seal rings for evidence of electrolysis,misalignment, abnormal wear etc. Measure the Seal Ring Clearance, to ensure within acceptable tolerance. Bearing & Journal Inspection: The purpose of this task is to inspect the bearings and journals for evidence of "smearing", overheating,electrolysis and loss of bond to bearing babbit. Measure bearing clearance. Bearing/H2 Seal/Lift Pump Pad Insulation Measurements : This task is performed to check the condition of the bearing/hydrogen seal/lift pump pad insulation material and prohibiting the shaft current from inducing bearing/hydrogen seal pitting and subsequent failure. The insulation resistance per GE should be 1 Megohm or greater with 500 volt megger. Coupling Bolt & Sleeve NDE: Bolting: the bolting is cleaned and visually inspected for mechanical condition of the threads on the studs and nuts and also NDE inspected UT to verify no indications of cracking in the stud. The coupling bolts are also visually inspected for mechanical condition and NDE of the bolts and sleeves is performed MT. Fan Inspections: The purpose of this task is to look for evidence of fan blade cracking. Air Gap Baffle Measurements: Air Gap Baffle measurement is performed to determine the running clearances between rotating and stationary parts.Also look for signs of rubbing or other discontinuities. Coupling Faces & Bolt Visual Inspections: A visual inspection performed to look for signs of burrs or surface imperfections due to operating stresses. Stator Bore and End-Windings Inspections: This inspection is done best with the rotor removed. It can be done on a best effort basis with the rotor in-place. Look for "greasing" which is caused by movement of stator bar, and dusting. Inspect blocking, ties and wedges. Inspect inner air baffles.Inspect end shield. Clean as required. Cooling Water Hose and Nose Ring Visual Inspections: The purpose of this inspection is to look for evidence of water leaks, and check the mechanical integrity of fluid connections. Stator Wedge Tightness Checks : Can be done with Magic or with rotor removed. Loose wedges are a precursor to stator winding movement/abrasion. Severe abrasion will lead to a ground fault. Stator Electrical Tests (ElCid, Megger, Hipot, Copper Resistance, etc.) : Electrical Testing is performed to determine the winding system. Stator Electrical Tests: Megger and PI (with 2500 Volt Megger) Initial DC Hipot with dry windings (immediately after disassembly to locate degraded insulation) Final AC or DC Hipot with dry windings or stator water running NOTE: IF GENERATOR IS CLOSEDUP NO HIPOT SHOULD BE PERFORMED, UNLESS CO2 IS PRESENT IN THE GENERATOR. ELCID Test checks stator core interlaminer insulation.

51

Stator RTD and Thermocouple Checks: Inspect wiring and connections for faults. RTD's that are no longer operable should be disconnected and wiring reconnected to spare RTD's. Field Visual Inspection: Can be performed with MAGIC or with rotor removed. Inspect for cracking, discoloration, and integrity.check end windings under retainer rings for insulation cracking,dirt etc.Look for signs of overheating and cracking. Inspect end windings for insulation discontinuities. Field Electrical Tests (Megger / PI / Cu Resistance / 60 Hz Impedance / Pole Balance): Megger and PI is performed to check the integrity of the Insulation in Field Winding. Field Electrical Tests: Megger and PI (with 500 Volt Megger) DC Resistance, AC Impedance, DC Hipot or (step voltage test) Stator Electrical Tests (Megger / PI / Cu Resistance / HiPot): To check the integrity of the Stator Insualtion. E - Coupling Inspection / Repack with New Grease: Inspect coupling internals (grids/teeth etc) for evidence of wear, seals for evidence of leakage and lack of lubricant.Repack coupling with approved grease and approved weight. E- Coupling Inspection (KOPFLEX COUPLING): Every 2 years: Visually inspect coupling disks packs for seperations/cracks. Every 10 Years Replace the coupling disk packs. Replace Faulk Coupling at next Alterex overhaul. Visually Inspect and Measure Gen. Field Collector Rings: Inspect for scoring, overheating,threading etc. Look for localized highspots.TIR should be performed. Measure the OD and depth of the grooves, as well as the taper in the axial direction of the OD of the rings to be able to anticipate whether or not there would be a need to replace or machine the rings next outage. Clean and Inspect Brush Holder Rigging (Clean Fan Enclosure): This task is performed to maintain the cleanliness and integrity of the brush holders and fan enclosure. All repairs to be performed as per manufacture recommendations.( Ref GEK45920A) Replace Field Collector Ring Brushes upon wear: The brushes should be inspected for tight pigtails sparking,overheating/discoloration,chatter,wear etc.The brush should be replaced if the pigtail is tight or the top of the brush is even with the top of brush holder. Calibrate and Check Generator Liquid Level Detector Alarm & Piping: Calibration is performed to ensure the functionality of level indicator and ensure that it will detect water/oil leaks inside of the generator cavity. This is particularly important for machines with 18M-5CR Retaining Rings. As-Left Coupling Alignment Readings: Take and record "As Left" coupling alignment readings to track movement of generator rotor and bearing wear. This data is very important to track the alignment of generator to turbine alignment and works hand in hand with vibration data to determine running vibration issues. Whenever rotor is to be removed for any reason good practice is to take a "as found" alignment reading prior to disassembly and removal. Previous "as left" readings can be used for this purpose if coupling has not been disturbed since last "as left reading was taken. Generator Air Test: To detect/repair potential leak paths for hydrogen outside the stator frame. Field Retaining Ring NDE: Perform Ultrasonic Testing to inspect inside surface (without removing ring) and Dye Penetrant to examine outside surface. Testing required for fields using rings made from the original 18Mn - 5 Cr material susceptible to IGSCC. Hydrogen Cooler Leak Testing: 6Y Insurance Requirement. Also, leaking H2 coolers can introduce moisture into the generator causing 18 Mn - 5 Cr retaining ring cracking (IGSC). Amplidyne Gear Drive Inspection: Gear reducer for DC shaft driven exciter. Inspect per site procedures. Review TILs and OEs: Review for applicability.

52

Gearbox Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe Mild

X X

X

5

6

7

8

X

X

X

X

X X

X

X X

X

X X

X

X

X

X

Condition Monitoring Task

Failure Codes

Comments

Vibration Monitoring

1M 1M 1M 1M 3M 3M 3M 3M

OC

No Comments

Oil Analysis

3M 18M 3M 18M 18M 18M 18M AR

DA MS OC

External Visual Inspection

1D 1D 1D 1D 1W 1W 1W 1W GL LC SL

Time Directed Task Partial Disassembly

AR AR AR AR

AR

AR

AR AR

No Comments No Comments

Failure Codes

Comments

GW

No Comments

Refurbishment AR AR AR AR AR AR AR AR BS GW LC No Comments 1. Perform vibration monitoring in accordance with requirements of site vibration monitoring program. 2. Perform lubricant analysis in accordance with requirements of site lubricant sampling and analysis program. This template is the controlled revision SME Summary SME Gearbox PCM Template Summary 1. Failure Modes A review of available failure history for Gearboxes was performed to identify the anticipated failure modes for this type of equipment. Available data indicates the following failure modes as being anticipated for this equipment: 1. 2. 3. 4. 5. 6.

Bearing degradation/failure Oil leakage Shaft Seal Failure Vibration (characteristic of degrading mechanical components, internal wear, damaged gears) Lubricant degradation Misalignment

Based upon the review of the anticipated failure modes, the team recommends that visual inspection for items such as oil level, leakage, overheating, excessive vibration etc. be conducted on a daily basis for critical equipment, and weekly for non critical equipment. This inspection activity should be conducted via normal operator rounds. The template relies heavily upon Condition Based Maintenance activities to assess the condition of the gearbox in order to determine the need for maintenance. Vibration analysis, Lube oil analysis and Performance Monitoring are all mature CBM technologies and can be relied upon to perform an assessment of the condition of the Gearbox. The CBM tasks defined in the template are adequate to detect the early stages of the anticipated failures identified above. The CBM tasks will not identify some infrequently experienced failures that are rapid in nature such as parts separating from the rotating elements. 2. Vendor Recommendations Due to the generic nature of these templates, review of vendor recommendations is not practical by the Corporate offices because of the shear number of gearbox supply vendors and those manuals are only available at the sites. It is expected that each site will review the applicable vendor documentation and take any specific vendor recommended maintenance into consideration when developing a PM program for a gearbox.

Boundary Definition This template applies to standalone type gearboxes typically in service in pump drive applications. This template is not applicable to Main Turbine and Pump Drive Turbine Front Standard Drive gearing, or to turbine turning gear assemblies. These are covered under the respective turbine PCM templates. Basis For Template Tasks Vibration Monitoring: Vibration monitoring is utilized to determine condition of bearings, shafting, gears and couplings/alignment of gearbox. Data should be recorded at same operating speed and should be taken at locations on the gearbox case at each end of each shaft in the gearbox.

53

Oil Analysis: Oil analysis is utilized to assess condition of gearbox lubricant, and to determine if abnormal wear is occuring to gears, bearings and shafting. External Visual Inspection: External visual inspection is performed to identify abnormal leakage, evidence of overheating or other evidence of distress. The external visual inspection is performed via the operators rounds. Partial Disassembly: Partial disassembly is normally required only if CBM technologies identify a potential fault within the gearbox, and futher investigation is warranted. In some cases plant Technical Specifications may require partial disassembly on a periodic basis for internal inspection. Refurbishment: Refurbishment is required only if a fault has been identified through CBM technologies, or through inspection during partial disassembly.

54

High and Medium Voltage Electric Motors Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe

X X

X

6

7

8

X

X

X

X

X X

X

Mild

5

X X

X

X X

X

X

X

X

Condition Monitoring Task Thermography

Vibration Monitoring

Oil Analysis Monitor Stator RTD's

Monitor Bearing Temperatures

Electrical Testing in accordance with UTILITY Motor Maint. Logic Tree

6M

3M

1Y

6M

6M

1Y

Failure Codes

Comments

1Y

BS DA DL LC SC

Increased frequency may be required if adverse conditions are discovered EPRI TR-106857-V10 Application Note 2.3.1

3M

6M

1Y

BS DL GW LC SC

Increased frequency may be required if adverse conditions are discovered. EPRI TR-106857-V10 Application Note 2.3.2

1Y

BS CO DA 1Y 18M 18M 18M 18M DL MS SC

Increased frequency may be required if adverse conditions are discovered. EPRI TR-106857-V10 Application Note 2.3.3

6M

6M

1Y

1Y

1Y

1Y

1Y

1Y

Cont Cont Cont Cont Cont Cont Cont Cont DA LC SC

Continuous Monitoring

Cont Cont Cont Cont Cont Cont Cont Cont BS LC SC

For motors with installed temperature probes and currently monitored, monitor temperature in relation to Alarm setpoint. For motors without installed probes, perform during thermography.

2Y

2Y

2Y

2Y

AR

AR

AR

AR

Time Directed Task

Refurbish Motor ( Note 1&2 )

Visual Inspection (during operator rounds)

Failure Codes

Comments

AR

AG BS DA IB MS SC SH

Perform in accordance with UTILITY Motor Maintenance Logic Tree (MA-AA-716-210-1002) Refer to EPRI Report TR-106857-V10. Application Note 2.3.11 Frequencty may be extended based on results of Partial Disassembly and inspection and Conditioned Based Task.

1W 1W 1W 1W

CO DA LC SC

Refer to EPRI report TR-106857V10 Application Note 2.3.8 Also, note any sudden changes or excessive unbalance in load currents.

10Y 15Y 10Y 15Y AR

1D

1D

1D

1D

Perform in accordance with UTILITY Motor Maintenance Logic CB DA IB LC Tree MA-AA-716-210-1002 EPRI MS SC SH TR-106857-V9 and V10 Application Note 2.3.4 and 2.3.6

AR

AR

Perform in accordance with UTILITY Motor Maintenance Logic BS DA DL Partial Disassembly and Inspection ( 20Y 20Y 20Y 20Y AR AR AR AR Tree ( MA-AA-716-210-1002). Note 3 ) LC SC Refer to EPRI report TR-106857V10 Application Note 2.3.9 Note 1: For Motors that are critical and cannot be tested in accordance with the Electrical Maintenance Logic Tree perform motor refurbishment on the stated frequency. Note 2: For Reactor Coolant Pump motors,motor refurbishment and motor disassembly and inspection (rotor pull with motor in containment)are to be performed on 20 year intervals. This will result in an alternating pattern of motor refurbishment and in-situ inspection every ten years. RCP motors have already received one disassembly/inspection. (3) Motor partial disassembly and inspection are to be performed on 20 year intervals for motors that are tested under the requirements of the Electrical Maintenance Logic Tree to determine dimensional checks of bearings,shaft fits,visual condition of stator winding/bracing/wedging and rotor, that cannot be determined by other diagnostic testing to dertermine if refurbishment/rewind is required. NOTE 1: For PWR Reactor Coolant Pump motors, motor refurbishments (swap with rebuilt spare) will be alternated with motor disassembly and in-situ inspection (rotor pull with motor in containment) every 10 years. This will result in an alternating pattern of either a motor refurbishment or in-situ inspection every 10 years. RCP motors have already received one disassembly / inspection. For BWR Recirculation Motors, the recommended refurbishment frequency is per the template. This template is the controlled revision. Please refer to MA-AA-716-210 & MA-AA-716-210-1001 for additional guidance. SME Summary

55

No SME Summary Available At This Time Boundary Definition The boundary of a high voltage electric motor for the purpose of this database is defined to include the following: · Electric motor and motor shaft excluding the coupling · All power, sensing, and control cables up to but not including the switchgear breaker · Motor mounting and base · Surge capacitors, if present · Bearing and stator cooling water connections excluding all valves and piping external to the motor’s shell or frame · Air filters, if present · Internal motor heaters · Detectors such as, temperature, corona, vibration, and alarms Basis For Template Tasks Thermography: 2.3.1 Thermography Failure Locations and Causes: The main application of thermography is to provide indication of the condition of power cable connections, and to compliment other indications of bearing wear from causes related to lubrication failure. Since the bearing temperature is directly measured by in-situ RTDs or thermocouples, thermography plays a backup role. Thermography can usually only give an indication of increased temperatures in the general region of the bearing casing, where this is accessible. Other indications of bearing wear are oil and vibration analysis, and motor current monitoring. Occasionally, thermography may also be useful in detecting blocked air passages. Progression of Degradation to Failure: The lubrication related causes of bearing wear appear randomly over a period of many months up to 2 years. Blocked air passages and high resistance electrical connections have a similar time scale. Fault Discovery and Intervention: None of the above causes is likely to fail the motor catastrophically on short time scales, so that a 6 month interval appears appropriate for thermography. This means that for safety related standby motors the thermography survey could be performed at the same time as surveillance testing. In the case of standby motors, thermography and the other on-line tests should be performed after the motor has been running at rated speed for four hours in order to reach a stable operating temperature and hence give valid measurements. In some instances, e.g. the impairment of the oil pumping action caused by excessive oil in vertical configuration bearings, the degradation could be sufficiently rapid that thermography at a 6 month interval would not be an effective method of detection. In any case, both direct bearing temperature indication and motor current are likely to be monitored continuously, i.e. observed every shift, and vibration and acoustic monitoring provide independent indications of bearing wear. Consequently, thermography is not a critical technology for detection of bearing wear in this class of motors. Thermography should include: · Inspection for unusual and unbalanced heating of the connections at the main motor and motor heater leads and their respective power cable interfaces · Unusual differences in exit air temperatures when compared to historical values · Inspection for unusual heating in motor bearing and windings that cannot be attributed to normal thermal patterns and temperatures Vibration Monitoring: 2.3.2 Vibration Monitoring Failure Locations and Causes: Vibration monitoring is very effective for addressing all causes of wear in bearings of all types. Additionally, vibration monitoring addresses all causes of failures originating in the shaft, in the rotor, including wound rotor windings, and in the frame, enclosure and mounting, including loose air baffles. Progression of Degradation to Failure: Most of the causes of bearing failure appear randomly over a period of several months up to 2 years. The appearance of cracks, wear, and bowing in the shaft, and all degradation mechanisms in the rotor, although random in occurrence times, are not expected within a few years. The onset of degradation in the frame, such as deformation, weld failures, cracking, and soft foot share similar timing characteristics as for the shaft and rotor, although the progression to failure could be rapid if the vibration is close to a structural resonance. Fault Discovery and Intervention: The suggested interval of 6 months should be sufficiently frequent to make vibration monitoring an effective detection method for a wide range of failure causes. Additionally, the frequency of vibration can provide specific diagnosis or focus further investigation in many instances. However, the random nature of occurrence of many of the degradation mechanisms that can in principle be detected requires this task to be performed at an interval which is no longer than 6 months. Oil Analysis: 2.3.3 Oil Analysis Failure Locations and Causes: Oil sampling and analysis is particularly directed at causes of bearing wear for all types of bearings. Also covered are all sources of wear for bearing seals. Other failure causes that affect oil quality are failed cooling coils in the oil distribution system, and all the causes of wear on the shaft (including cracks and bowing). Oil temperature above the rated limit can lead to degradation. Typical anti-friction bearing temperatures usually will not exceed 45° C above ambient; 2-pole motors usually will not exceed 50° C above ambient. Progression of Degradation to Failure: All the above degradation mechanisms are random in time of onset but in most circumstances are expected to appear over periods of many months or years, and are not expected to lead to failures on short time scales. Fault Discovery and Intervention: The interval of 1 year for oil analysis is thought to be sufficient to detect the onset of most of the failure causes. Monitor Stator RTD's: For motors with RTD's installed and currently monitored, monitor temperature in relation to setpoint. Monitor Bearing Temperatures: 2.3.5 Mechanical Tests - On-Line Failure Locations and Causes: The measurement of bearing temperatures and acoustic monitoring are very effective means of detection of practically all sources of bearing degradation for all types of bearings. Additionally, bearing temperature can be the means of detection of other failures or degradation in the oil distribution and bearing systems such as a blocked oil metering orifice, failed slinger rings, or a failed cooling coil, or failed seals. Consequently, the mechanical on-line task is focused principally on bearing systems and oil degradation through the measurement of bearing temperature. Bearing temperature may also detect wear on the shaft, deformation of the frame, or a loose rotor cage. Measurement of cooling water flow and pressure is an additional means to detect failed cooling coils, and is a part of the mechanical on-line measurements. Measurement of stator winding temperature provides detection of overheated windings, whether from local winding hotspots, increased mechanical load, or from clogged air filters, blocked air passages and screens, additional to what can be observed in the external visual inspection where all of these parts may not be accessible. Progression of Degradation to Failure: The causes of bearing wear appear randomly over a period of many months up to 2 years, but in some cases can produce rapid deterioration depending, for example, on the degree of mechanical loading. Frequent or continuous monitoring of bearing temperature can provide adequate coverage of even the rapidly developing degradation mechanisms, including damage to bearing seals. Less frequent degradations consisting of or leading to wear on the shaft, deformation of the frame, or a loose rotor cage are also covered by frequent bearing temperature monitoring. Winding

56

temperatures are also likely to be monitored continuously or at least more frequently than the performance of the mechanical on-line task because of the simplicity of the measurement. Winding temperature measurement also covers the clogging of air filters, screens, and air passages which can degrade significantly over a period of a few months. High winding temperatures above rated values from high temperature environments provide early indication of the likelihood of premature winding failure. Although the effect of elevated temperature on winding life is said to be well understood, predictable, and severe, winding failures from this source are expected only on a time scale of several years. Fault Discovery and Intervention: Frequent bearing temperature and winding temperature measurements provide effective coverage of all the degradation modes mentioned above. Providing these are performed frequently, the other parts of the mechanical on-line task may be performed at intervals of one or two years. The mechanical on-line tests include visual observation of arcing at brushes and slip rings although more detailed inspection of brushes is included in the mechanical off-line task, or may even constitute a more frequent separate task if there is a history of brush problems. In the case of standby motors, the mechanical on-line tests should be performed after the motor has been running at rated speed for four hours in order to be at a stable operating temperature. Mechanical Tests - On-Line should include: · All tasks found in the External Visual Inspection · Verification of name plate motor speed · Acoustic monitoring · Bearing temperature monitoring and trending · Winding temperature monitoring and trending · Inspection of motor slip ring and brushes for abnormal wear, if present · Monitor cooling water pressure and flow Electrical Testing in accordance with UTILITY Motor Maint. Logic Tree: 2.3.4 Electrical Tests - On-Line Failure Locations and Causes: The electrical on-line tests include a series of tests that are directed at detecting degraded or cracked rotor bars and shorting rings, loose connections on wound rotor windings, a loose rotor cage, broken, loose, or grounded switches, and other degraded electrical devices. Recent evidence of corona damage to stator windings in this class of motor suggests the inclusion of a partial discharge test. Motor current signature analysis may also detect defective insulation on stator laminations. Progression of Degradation to Failure: Degraded wound rotor connections, cracked rotor bars and shorting rings, or other broken, loose, or grounded electrical devices, have random occurrence times on a scale of a few years. Insulation on stator laminations continuously degrades and is expected to provide a failure free period that may approach 40 years although the degradation depends markedly on the degree of contamination, the temperature, vibration levels, and the quality and type of the stator lamination material and insulation (i.e. M19 steel and C5 insulation). Fault Discovery and Intervention: Most of the degradations addressed by this task produce measurable effects before failure on a time scale of a few years. The main exceptions could be some causes of failures of electrical devices such as switches which constitute a significantly higher proportion of motor failures than rotor problems according to NPRDS data. In the case of standby motors, the electrical on-line tests should be performed after the motor has been running at rated speed for four hours in order to be at a stable operating temperature. The partial discharge tests for corona damage requires the installation of appropriate couplers to take on-line data. Electrical Tests - On-Line should include some or all of the following; these tests should be trended and compared to historical data to derive their maximum benefit: · Motor current and power signature analysis · Power factor testing · Applied voltage and running current testing · Flux monitoring · Partial discharge 2.3.6 Electrical Tests - Off-Line Failure Locations and Causes: This task contains four main ingredients: measurements of winding resistance, insulation resistance, polarization index, and motor circuit evaluation. The task focuses primarily on detecting degraded insulation, whether associated with windings, bearings, feeder cables, or motor leads, the integrity of all electrical connections, and the detection of high resistance shorts and grounds in electrical components such as switches and surge capacitors. Progression of Degradation to Failure: Electrical insulation is subject to continuous degradation. The main causes of insulation degradation are excessive heat above the rated limit, excessive starts within a short period, winding movement and vibration, age, and contamination (which may be e.g. oil, moisture, salt). Although the initiation of these influences may be random, the degradation progresses relatively slowly and is expected to give a trouble free period of at least several years (exception could be high temperatures from excessive starts within a short period, which should be controlled by operational procedures). Insulation on stator laminations also degrades continuously and is expected to provide a failure free period that may approach 40 years. Problems with feeder cables, motor leads, connections, lugs, switches and electrical devices such as surge capacitors are likely to occur randomly on various time scales, shorter than those above. Measurement of winding resistance can detect shorts between turns, and ductor tests can be performed to evaluate the resistance of connections. Fault Discovery and Intervention: Most of the degradations addressed by off-line electrical testing produce measurable effects before failure on a time scale of a few years. Consequently the off-line tests could be performed every 2 or 3 years and provide effective coverage for the degradation modes discussed above. It is likely that only the first four items listed below would be included in every scheduled electrical off-line test. The remaining tasks could be included every other time. Electrical off-line tests can only be conducted meaningfully when all parts of the motor are within 10° F of ambient temperature. The tests should include some or all of the following; these tests should be trended and compared to historical data to derive their maximum benefit: · Winding resistance · Insulation resistance · Polarization indexing · Motor circuit evaluation · AC High Pot. · DC Step voltage · Surge testing · Power factor tip-up testing Refurbish Motor ( Note 1&2 ): 2.3.11 Refurbishment Failure Locations and Causes: This task is focused on the condition of rotor laminations, rotor bars, and retaining rings, wound rotor windings, and stator laminations and windings. In addition, the task enables checks on the shaft, and on the frame, enclosure and mounting for deformation, cracks, and weld failures. Frame and mounting degradations are also covered by vibration monitoring and by visual inspection. All the rotor degradations are also covered by vibration monitoring. Stator laminations, and winding degradation might also be revealed by a borescope examination but can be more fully examined during refurbishment. There do not appear to be any other degradation mechanisms that absolutely require a refurbishment to reveal the condition of the equipment, i.e. that are not also covered by one or more of the other tasks. Progression of Degradation to Failure: The refurbishment task provides protection from a large number of degradation mechanisms that can cause failures over a period of many years. Fault Discovery and Intervention: Although a significant number of these mechanisms are thought to initiate randomly or to progress erratically, the expert group thought that the combination of condition monitoring tasks described above, and other inspections (e.g. borescope), would lead to a minimum refurbishment interval of 10 years for the most critical motors, and up to 20 years for the least critical motors that are started infrequently. Exposure to heat, age, vibration and contamination should be a significant consideration when estimating these refurbishment intervals. It appears that refurbishment task intervals could benefit from adjustment based on multiple inputs about the condition and history of the equipment. However, the expert group were reluctant to state that refurbishment could become a fully on-condition task (i.e. As Required on the Template) because of the high cost of high voltage motors. Some utilities currently have the confidence in their condition monitoring programs and inspections to eliminate refurbishment as a regularly scheduled PM task. The foregoing analysis shows that all the failure causes should indeed be covered by condition monitoring and inspection. Refurbishment should include: · All tasks found in the Partial Refurbishment, plus · Inspect for any damaged, loose, or missing parts · Clean and inspect the rotor winding and core for: damaged or loose windings, end turns, ties, wedging, and rotor iron; missing end turns, ties and wedging; detached, loose or damaged shorting ring; test winding and insulation resistance · Retreat rotor to restore proper insulation and mechanical rigidity · Check the shaft for bowing and run-out · Verify insulation and electrical connections of rotor slip rings, if present · Resurface slip rings to proper micron finish · Inspect shaft bearing journals for wear, pitting, and damage;

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resurface, as required, to restore journals to proper micron finish · Balance the rotor · Clean and inspect the stator winding and core for: contamination, damaged or loose windings, end turns, blocking, wedging, ties, and stator iron; detached or loose surge ring; test winding and insulation resistance · Verify proper operation of winding RTDs · Clean air passages · Tighten end windings and retreat stator to restore proper insulation and mechanical rigidity · Inspect and test all supply cables, motor heaters, and alarms · Inspect and refurbish the anti-rotation device, as required · Inspect and test oil and air coolers Visual Inspection (during operator rounds): 2.3.8 External Visual Inspection Failure Locations and Causes: The external visual inspection focuses mainly on causes of visible indications of deterioration in oil quality, visible oil and grease leakage and low oil level, either from problems with wear of bearings or bearing seals, or from any failure in the oil distribution system. External visual inspection is also effective for detecting clogged air filters and blocked air passages or screens. Bearing temperature, motor current, and winding temperature are all likely to be either continuously recorded or observed every shift during operator rounds. These frequent observations are included in the external visual inspection task, both here and in Tables 3.1 and 3.2, although plants will have a separate procedure, possibly a part of operator rounds, for how they are observed, recorded or trended. Bearing temperature is a key indication for all causes of bearing wear, failures in the oil distribution system, and other failures that can affect the wear of bearings. Motor current can also detect some bearing failures but usually at a later stage of development than bearing temperature. Winding temperature is a useful indicator for clogged air filters, air passages, and winding insulation failure. Certain degradation processes in electrical circuits can also be observed, such as degraded insulation on feeder cables, and failed space heaters. The inspection also includes general observation for loose, missing, or damaged parts, and listening for unusual noises or vibrations. Progression of Degradation to Failure: All the above degradation mechanisms are random in time of onset but in most circumstances are expected to appear over periods of many months or years, and are not expected to lead to failures on short time scales. Fault Discovery and Intervention: In addition to the above discussion of bearing temperature, motor current, and winding temperature, some other items below are observable during normal operator rounds. Such items (e.g. oil level and color, unusual noises) are also assumed to be included as a formal part of operator rounds, so that operator rounds does not appear as a separate PM Strategy on the Template or in Tables 3.1, or 3.2. External Visual Inspection should include: · Inspect for: damaged, loose, missing or vibrating parts, externally visible oil leaks around bearings and bearing seals, external water leaks around water bearing and stator cooling interfaces, broken or loose grounding cables, damaged conduits and seal flex, damaged wiring and insulators, damaged junction boxes and their gaskets, blocked / clogged / plugged air filters and inlet air screens · Inspect bearing slinger rings for proper operation and movement · Verify proper oil level; oil should not be discolored · Inspect for plugged oil sight glass vent · Verify proper motor strip heater status indication · Listen for unusual noises Partial Disassembly and Inspection ( Note 3 ): 2.3.9 Partial Disassembly and Inspection Failure Locations and Causes: The primary motivation for partial disassembly is to inspect the condition of bearings or other components as required, i.e. when other diagnostic measurements indicate the need. A wide range of component locations is accessible during this task, as described in Tables 3.1, and 3.2, and is evident in the task content below. The task content shows that it is basically a detailed internal inspection. The degree to which internal areas of the motor can be accessed will depend greatly upon the motor type, design, and construction. This will therefore impact the amount of disassembly and inspection required for this task. Progression of Degradation to Failure: This is an on-condition task. Fault Discovery and Intervention: This is an on-condition task. Partial Disassembly should include: · All tasks found in the External Visual Inspection, plus · Removal of motor end covers and inspection plates and covers to allow access to motor bearings and windings without floating the rotor (i.e. rotor positioning and alignment are not to be affected by this inspection) · Check for any damaged, loose, or missing parts · Inspect bearings for abnormal wear, loss of babbitt, pitting, and indications of lubrication problems such as discoloration and scorching · Inspect the internal bearing insulation for integrity, damage, flash over, tracking, and proper insulation levels as recommended by the OEM · Inspect and test the bearing RTDs for damage and proper temperature indication · Perform a bearing journal and thrust runner inspection looking for indications of abnormal wear, proper RMS surface finish, proper alignment and positioning, and any damage · Inspect bearing seals for wear, alignment, and damage · Inspect the oil cooler, reservoir, and oil piping for leaking, mechanical integrity, fouling, cleanliness, pitting, corrosion, erosion, and damage · For horizontal motors remove and inspect the upper end turn air baffles for damage, electrical tracking, and cleanliness. With the air baffles removed inspect winding end turns for dusting, looseness, electrical tracking, mechanical integrity of the ties and blocking, and any damage to the windings. · For vertical motors inspect for indication of loose coil wedges · Inspect internal coating for integrity and damage · Inspect internal motor leads for degradation of or damage to the lead wire insulation · Motor rotor fans should be inspected for damaged, cracked, or missing blades, or loose hardware · Inspect the pawls and ratchet plates of any anti-rotation devices for damage and abnormal wear. If possible perform an uncoupled breakaway test on vertical motors employing an anti-rotation device. · Remove covers and inspect all junction and termination boxes and contents for damage, grounded wiring indications of electrical arcing or tracking, and the condition and tightness of connections and insulation systems · If present at the motor, inspect current transformers and or surge capacitors for leakage, damage and the proper tightness of the connections

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Horizontal Pumps Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe

X X

X

6

7

8

X

X

X

X

X X

X

Mild

5

X X

X

X X

X

X

X

X

Condition Monitoring Task

Failure Codes

Comments

Vibration Analysis@

1M 1M 1M 1M 3M 3M 3M 3M

OC

EPRI TR-106857-V13 Application Note 2.3.1

Performance Trending

6M 6M 6M 6M 6M 6M 18M 18M OC

EPRI TR-106857-V13 Application Note 2.3.3 Monitor in accordance with ERAA-2003

Oil Analysis

3M 18M 3M 18M 18M 18M 18M AR

DA FL OC

EPRI TR-106857-V13 Application Note 2.3.2

Time Directed Task

Failure Codes

Comments

Coupling Inspection

24M 5Y 24M 5Y

DA FD GL UD

EPRI TR-106857-V13 Application Note 2.3.5

CO ER

EPRI TR-106857-V13 Application Note 2.3.6 Time based inspection should be performed at frequency specified. If data is available from inspection of like equipment in similar service indicates more or less frequent inspections are required,then frequency of inspection should be adjusted accordingly.

AG CO ER IW NO OC

EPRI TR-106857-V13 Application Note 2.3.9 * Refurbishment of nonredundant (no installed spare), power production pumps (Condensate, Condensate Booster, Feedwater) should occur on the following time based schedule: - Condensate Pumps: 8 years - Condnensate Booster Pumps - 8 years - Feedwater Pumps - 10 years

DA FL OR

EPRI-TR106857-V13 Application Note 2.3.4 Oil change frequency may be modified by application of CBM technologies (Delta P. particle counts)etc.

Nozzle NDE Inspection

Refurbishment*

Oil Filter Change,Clean and Inspect

AR

AR

AR

AR

10Y AR 10Y AR 10Y AR 10Y AR

AR* AR AR* AR AR* AR AR* AR

24M AR 24M AR 24M AR 24M AR

External Visual Inspection

1D

1D

1D

1D 1W 1W 1W 1W

BF CO DA FD EPRI TR-106857-V13 Application Note GL LC OC 2.3.7 OR SL

Partial Dissassembly

AR

AR

AR

AR

BS FD GL OC OR PL SL

EPRI TR-106857-V13 Application Note 2.3.8

Failure Codes

Comments

AR

AR

AR

Surveillance Task

AR

EPRI TR-106857-V13 Application Note Functional Testing AR AR AR AR AR AR AR AR XX 2.3.10 * Refurbishment of non-redundant (no installed spare), power production pumps (Condensate, Condensate Booster, Feedwater) should occur on the following time based schedule: - Condensate Pumps: 8 years - Condensate Booster Pumps - 8 years - Feedwater Pumps - 10 years @ For canned/wet motor pumps, consider supplementing normal vibration monitoring with current monitoring. This template is the controlled revision. SME Summary PCM Template Review Rotating Equipment Team Pump PCM Templates (Vertical and Horizontal) 1. Failure Modes A review of available failure history for vertical and horizontal pumps was performed to identify the anticipated failure modes for this type of equipment.

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Available data indicates the following failure modes as being anticipated for this equipment: 1. 2. 3. 4. 5. 6. 7.

Bearing degradation/failure Oil leakage Mechanical seal leakage Packing leakage Vibration (characteristic of degrading mechanical components, internal wear or off normal operating conditions) Degraded performance due to internal wear Lubricant degradation

Horizontal Pumps Template Based upon the review of the Horizontal pump template the team has concluded that the tasks directed by the template do not adequately address the anticipated failure modes. The current PCM template specifies that visual inspection be conducted on an annual basis, which the team does not believe is frequent enough. The team recommends that visual inspection for items such as oil level, leakage, overheating, excessive vibration etc. be conducted on a daily basis for critical equipment, and weekly for non critical equipment. This inspection activity should be conducted via normal operator rounds. The template relies heavily upon Condition Based Maintenance activities to assess the condition of the pump in order to determine the need for maintenance. Vibration analysis, Lube oil analysis and Performance Monitoring are all mature CBM technologies and can be relied upon to perform an assessment of the condition of the pump. The CBM tasks defined in the template are adequate to detect the early stages of the anticipated failures identified above. The CBM tasks will not identify some infrequently experienced failures that are rapid in nature such as parts separating from the rotating element. The technologies (including the visual inspection frequencies) will identify that the failure had occurred and would allow the equipment to be removed from service prior to severe damage in all but the most extreme situation. There are several routine time based PM activities (Oil filter change and coupling inspection) that are currently on an 18 month frequency. The team recommends that a 24 month frequency be adopted for these activities unless site experience dictates otherwise. Additionally it is recommended based on our plant experience/history that time directed nozzle NDE inspection frequencies should be AR (as-required). A template revision request has been submitted to the MAROG PCM template coordinator to incorporate the changes discussed above. Vertical Pumps Template Based upon the review of the Vertical pump template the team has concluded that the tasks directed by the template do not adequately address the anticipated failure modes. The current PCM template specifies that visual inspection be conducted on an annual basis, which the team does not believe is frequent enough. The team recommends that visual inspection for items such as oil level, leakage, overheating, excessive vibration etc. be conducted on a daily basis for critical equipment, and weekly for non critical equipment. This inspection activity should be conducted via normal operator rounds. The template currently does not include the CBM activity for Lube Oil Analysis, which is an important requirement to assess the condition of any pump equipped with oil lubricated bearings. The template relies heavily upon Condition Based Maintenance activities to assess the condition of the pump in order to determine the need for maintenance. Vibration analysis, Lube oil analysis and Performance Monitoring are all mature CBM technologies and can be relied upon to perform an assessment of the condition of the pump. Once Lube Oil Analysis has been incorporated into the template the CBM tasks defined in the template will be adequate to detect the early stages of the anticipated failures identified above. The CBM tasks will not identify some infrequently experienced failures that are rapid in nature such as parts separating from the rotating element. The technologies (including the visual inspection frequencies) will identify that the failure had occurred and would allow the equipment to be removed from service prior to severe damage in all but the most extreme situation. There are several routine time based PM activities (Oil filter change and coupling inspection/lubrication for gear style couplings) that are also not included in this PCM template, which should be included in the next rev of the template. The team recommends that a 24 month frequency be adopted for these activities unless site experience dictates otherwise. A template revision request has been submitted to the MAROG PCM template coordinator to incorporate the changes discussed above. 2. Vendor Recommendations Due to the generic nature of these templates, review of vendor recommendations is not practical by the Corporate offices because of the shear number of pump supply vendors and those manuals are only available at the sites. In general the team’s experience has been that pump vendors will typically recommend routine lubrication and performance monitoring tasks, which we believe the PCM template adequately addresses. Additionally it should be understood that the generic templates were developed under the guidance of an expert panel comprised in part with pump vendors. The generic templates assume that specific pump reviews (site specific) would/will identify any specific vendor recommendations not in agreement with the template. 3. NEIL Insurance Requirements For rotating equipment NEIL provides guidelines that allow “credits” (premium discounts to be taken) when certain activities/programs are performed (vibration analysis, oil analysis, thermography etc) and it prescribes frequencies. However there are NEIL reporting requirements when certain levels are entered for specified equipment (specifically ECCS pumps and pumps w/drivers >1000 HP) The current templates provide for sufficient monitoring to satisfy the NEIL Requirements for reporting. 4. Condition Monitoring The PCM templates will contain adequate direction once Lube oil Analysis has been incorporated into the Vertical Pump Template. 5. Critical Subcomponents

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The team has concluded that there is currently no PCM template for Gearboxes, a critical subcomponent of many pumps throughout the Utiliy system. A draft gearbox PCM template has been submitted via the M&WC webpage. This template is composed primarily of condition monitoring tasks, which have been employed throughout the industry to monitor gearbox condition. Prepared By;

Boundary Definition The boundary of a horizontal pump for the purpose of this database is defined to include the following: · · · · · · ·

Coupling Discharge flange Inlet suction flange External lubrication system Cooling water injection input to seals and bearings Pump and its foundation Detectors, sensors, and alarms (e.g. bearing temperature and vibration)

Basis For Template Tasks Vibration Analysis@: 2.3.1 Vibration Analysis Failure Locations and Causes: Vibration Analysis has a wide scope of application to pumps, addressing sources of vibration in rotating parts as well as flow noise such as cavitation. These sources include: almost all causes of impeller wear, especially those caused by off-BEP operation (best efficiency point, otherwise known as the design point); bearing wear; general alignment problems, improper internal pump clearances, and erosion of interstage sealing. Degradations of diffusers, volutes, channel rings, the balancing device, wear rings and surfaces, a cracked and worn shaft, wear of geared pump/motor couplings, corrosion, erosion or other damage to internal flow paths of the pump casing or rotor, are also addressed by vibration monitoring. Other failure causes covered by this task are somewhat less important because they either do not influence the timing or they are not encountered as frequently. Progression of Degradation to Failure: Impeller wear and damage caused primarily by off-BEP operation, bearing wear, and erosion of the pump casing wear rings are the processes that either have random timing, or may deteriorate rapidly, and at the same time are commonly encountered. These are the failure locations that are most responsible for vibration monitoring being performed every month on critical pumps. The most significant failure mechanisms or causes promoting these failures are misalignment and imbalance. Other damage caused by off-BEP operation generally has a failure free period or random timescale of several years. A cracked or worn shaft, a worn coupling of the geared type, and internal pump casing flow path erosion/corrosion can also be expected to occur over time periods that are much longer than the short vibration monitoring intervals recommended. Other processes may occur randomly or deteriorate rapidly (e.g. deformation of the pump casing, failure of the gear drive oil pump, leaks from geared couplings), but they are much less likely to occur. Out-of-balance or improperly fitted pump/motor couplings, general alignment problems, and bearing wear caused by rough journals or rough runners are unlikely to be diagnosed by other PM tasks before they cause unacceptable degradation, making vibration monitoring a key line of defense for these problems. Fault Discovery and Intervention: The expert group recommended vibration monitoring every month for critical pumps, and every three months for less critical pumps. This measurement is only done if the pump is already running because it is not prudent to start an idle pump just to take vibration measurements. Standby pumps are usually monitored only in conjunction with performance testing for surveillance test purposes. It is very important that vibration monitoring on a particular pump should be performed with the pump at the same operating point each time. Note: For canned/wet motor pumps, consider supplementing normal vibration monitoring with current monitoring. Performance Trending: 2.3.3 Performance Trending Failure Locations and Causes: Performance Trending is performed using installed plant instrumentation where available, and addresses causes of failure and wear of the impeller, balance device, and wear rings, fixed breakdown bushings and some gaskets, pump casing leaks, and bearings. Some of these are diagnosed by trends in the operational characteristics of the pump (e.g. in relation to BEP and pump curve), some by additional parameter trends (e.g. balance line leak-off pressure and temperature), and some by the trend in bearing temperature. Many other degrading locations are also detected by performance trending but they do not influence the timing of the task (e.g. erosion of diffusers, volutes and channel rings), or they are not dominant failure causes (e.g. fouling of bearing cooling heat exchangers). Progression of Degradation to Failure: All of the important mechanisms addressed by performance trending are significant because they have predominantly random or short term occurrence times, and they are relatively common events. Although all of them have the possibility of being detected by additional tasks, these characteristics suggest frequent performance trending would be beneficial. Fault Discovery and Intervention: The interval for Performance Trending is 6 months for critical pumps and for non-critical pumps in severe conditions, and 18 months for non-critical pumps in mild conditions. More precise hydraulic assessment requires auxiliary instrumentation and would be performed much less frequently Performance Trending should include the following: Record · Any abnormal conditions · Pump bearing temperatures, if available · Suction pressure · Discharge pressure · Process fluid temperature · Motor current · RPM · Flow · Balance drum leak-off line pressure or flow · Fixed breakdown bushing leak-off temperature · Oil pressure or flow, and temperature Trend · DP versus flow · Motor current · Thrust bearing temperature · Balance drum leak-off line pressure or flow · Oil pressure or flow, and temperature Oil Analysis: 2.3.2 Oil Analysis Failure Locations and Causes: Oil analysis is focused on processes that result in wear particles or other contaminates entering the oil or processes that cause degradation of the oil. These include wear of the fixed breakdown bushing seals, failure of bearing seals, bearing wear, and failure or fouling of bearing cooling heat exchangers, or internal bearing coolers. Progression of Degradation to Failure: Mechanical seal leakage, and sources of bearing wear, are relatively common problems with timing aspects that suggest oil sampling should be frequent, at least for critical pumps subject to high rates of wear. It appears there are no failure locations and causes for which oil sampling and analysis is the only PM task available to address pump degradation. Fault Discovery and Intervention: The expert group recommended oil analysis every three months for continuously running critical pumps, and every eighteen months for non critical pumps. A non critical pump with a low duty cycle in mild conditions may only receive oil analysis if a problem is

61

suspected for other reasons, although some may be scheduled for oil analysis at 18 months, depending on conditions. The size of the oil reservoir and presence of sampling ports may be important in such a case, and may in fact be influential in setting oil sample intervals for pumps regardless of criticality and duty cycle. Coupling Inspection: 2.3.5 Coupling Inspection Failure Locations and Causes: As the name implies this task is focused entirely on inspection for lubrication leaks and wear of the geared type of pump/motor couplings. Progression of Degradation to Failure: Leaks are more important to the timing of this task than wear. Leaks caused by aging are not expected to occur before 5 to 10 years of service life, and wear of the coupling under normal conditions does not have a high probability of becoming excessive for several years. However, over greasing or loss of grease can cause rapid degradation at shorter times. Fault Discovery and Intervention: Continuously operating critical pumps are recommended to have a coupling inspection at 18 months. Standby critical pumps could go 5 years between inspections. Non critical pumps are expected to rely on indications from other tasks such as vibration analysis or thermography. Coupling Inspection should contain the following: · Inspect for signs of leaking lubricant · Inspect mating surfaces for cleanliness, wear, and integrity; record as-found and as-left conditions · Verify condition of lubricant looking for dirt, amount of lubricant, and indications of coupling wear; recharge with proper lubricant and quantity · Inspect gear teeth for wear and damage · Inspect non-metallic parts for condition and wear · Inspect bolting for damage · Ensure proper orientation during reassembly Nozzle NDE Inspection: 2.3.6 Nozzle NDE Inspection Failure Locations and Causes: This task is focused entirely on non-destructive examination of the pump casing, closure head, discharge nozzle, and discharge and suction flanges. Progression of Degradation to Failure: Erosion in these areas is not expected before several years of service life. Fault Discovery and Intervention: Continuously operating pumps have an NDE inspection at 10 years, especially for high energy flow pumps, or when there has been a history of erosion related problems. Standby pumps do not require an NDE inspection if there are no history of problems (e.g. erosion, cracking). There is no other backup task for the degradation addressed by the NDE inspection. Nozzle NDE Inspection should contain the following: · Remove insulation and replace when inspection is complete · Prepare surface for NDE inspection, refer to plant or vendor procedure · Perform ultrasonic test, measure pipe thickness looking for indications of wear, erosion, thinning, cracking, or damage Refurbishment*: 2.3.9 Refurbishment Failure Locations and Causes: Refurbishment is basically a corrective action that is not driven on a regular schedule. Because of the degree of disassembly many areas can be inspected as the task content listing shows. Progression of Degradation to Failure: The large number of degradation processes and conditions discoverable by refurbishment have a total effect of random occurrences, but they are all detectable by other means. Fault Discovery and Intervention: The intervals for refurbishment will be driven mainly by the need for corrective actions as indicated by condition monitoring tasks. It is expected that the condition monitoring tasks will be adequate for this purpose provided the pump is reasonably sturdy and does not have a poor performance history. There is an implied assumption that condition monitoring and inspection can provide enough advance warning so that failure can be avoided while delaying refurbishment to a convenient outage period. Refurbishment should include the following: · All items from the External Visual Inspection, the Oil Filter Change, Clean, and Inspect, and the Partial Disassembly, plus · Prior to removal and disassembly, check and record pump thrust, compare to historical · Perform radial clearance checks of bearings and impeller wear rings · Document as-found / as-left dimensions on machine fits, clearances, and motor and pump lift · Inspect and document condition of welds, piping, and hardware such as bolts and fasteners · In general replace all components beyond OEM tolerances and specifications; document wear and condition · Inspect for damage, wear, and deterioration of all gaskets, O-rings, and elastomers · Replace all gaskets, O-rings, and elastomers · Replace anti-friction bearings; inspect and document wear and condition · Inspect sleeve and thrust bearings; replace as necessary, document as-found and as-left conditions · Inspect casing, volute, diffuser, and barrel assemblies for thinning, cracking, and corrosion / erosion · Inspect shaft for damage, defects, run out, and radial position · Inspect impellers and wear rings for wear and damage; balance and size if required · Inspect interior of pump, nozzle, and fits for wear, erosion, damage, and proper clearances · Inspect stuffing box / gland for damage, corrosion, and wear · Replace / rebuild seals, if present · Replace packing, if present · Clean and check for fit and flatness of mating surfaces and joints · Inspect driver and pump coupling and coupling bolts, replace coupling lock washers, verify proper fit of key and key length · After reinstallation and prior to coupling, check and record uncoupled pump lift and motor thrust, compare to historical · Verify proper motor rotation before coupling Oil Filter Change,Clean and Inspect : 2.3.4 Oil Filter Change, Clean and Inspect Failure Locations and Causes: This task focuses entirely on the condition of the lubrication system. Items to observe are a clogged or failed filter or strainer, and contamination of the lubricant. Progression of Degradation to Failure: The key task is cleaning or changing the oil filter. Clogged filters are expected after a period of 2 to 5 years of continuous operation, and trends in oil pressure may give indication of progressive clogging. Although contamination of the oil can occur at any time, oil sampling will give advanced warning at a 6 month interval for continuously operating critical pumps. Fault Discovery and Intervention: Filter inspection is recommended as a scheduled task at 18 months for continuously operating pumps. Low duty pumps may have this task only on indication from oil pressure, oil color, or oil analysis. Oil Filter Change, Clean and Inspect should include the following: · Check for leaks · Verify proper operation · Check DP across the filter and clean the filter, or replace if necessary · Note condition of all components especially the filter External Visual Inspection: 2.3.7 External Visual Inspection Failure Locations and Causes: External Visual Inspection is primarily a method to discover leaking mechanical seals, gaskets or O-rings, excessive packing leakage, leaks in the pump casing, leaks from bearing seals; insufficient lubrication (low oil level); and a range of other conditions such as a clogged oil system filter (inferred from oil pressure); a loose, corroded or failed pump base, or audible noise from worn bearings. Progression of Degradation to Failure: Seal and excessive packing leaks, and lube oil system leaks are predominantly random occurrences, which are important because they influence the timing of the visual inspection, are relatively common occurrences, and have essentially no other early means of detection. These degradation mechanisms taken together tend to occur on a scale of one to a very few years. The large number of other degradation mechanisms covered by visual inspection also results in a combined random occurrence rate that benefits from relatively frequent visual inspection, even though many of the failure causes have backup from other tasks. Lubrication leaks from geared type couplings fall in this group. Other failure causes that are essentially dependent on visual inspection include damage to external pump casing penetrations, failed grout or base plate, deformed discharge or suction flanges, blocked oil breather caps and sight glass vents, and worn slinger rings. Fault Discovery and Intervention: The detection of seal and excessive packing leaks relies heavily on this task and on operator rounds, which will provide leak detection (and recognition of unusual noises) on a continuing basis; consequently the expert panel did not recommend a scheduled packing replacement task. External Visual Inspection should include the following: · Inspect for the general cleanliness and condition of all components · Inspection for loose, missing, or damaged bolts and parts · Inspection for abnormal noises and vibration, oil leaks, piping and flange leaks, damaged or missing insulation, abnormal pipe movement and damaged or misadjusted pipe hangers, and the general condition of expansion bellows · Inspect foundation for damage, missing or loose bolts/nuts, and damaged grout · Verify the

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presence of electrical ground straps · Verify the presence and condition of the coupling guard · If present, note Lubrication Flush System flow and pressure, and flush the filter if its DP warrants · Verify the proper operation and oil level of the oiler, if present · Verify the bearing temperatures are within normal operational limits and slinger rings are moving freely · Ensure that breather tube and sight glass vents are clear · Verify the equipment is tagged and properly identified For packing: · Verify proper leak-off rate · Verify that the gland bolts are not loose or damaged For seals: · Note and report any seal leakage · Verify that the gland bolts are not loose or damaged · Proper seal injection flow Partial Dissassembly: 2.3.8 Partial Disassembly Failure Locations and Causes: This task focuses principally on the condition of the mechanical seals and balancing device, bearings and bearing seals, the lubrication system including leaks in bearing cooling heat exchangers and internal bearing coolers, and packing and gasket failures. Progression of Degradation to Failure: Most of these effects are random, and lead to random failure times. This is an on-condition task where action is triggered by observations from other condition monitoring tasks which form multiple backup opportunities for detection for all of these failure mechanisms. Fault Discovery and Intervention: This is an on-condition task. It is expected that the condition monitoring tasks will be adequate for this purpose provided the pump is reasonably sturdy and does not have a poor performance history. There is an implied assumption that condition monitoring and inspection can provide enough advance warning so that failure can be avoided while delaying partial disassembly to a convenient outage period. Equipment Qualification requirements may also dictate a partial disassembly. Partial Disassembly should include the following: · All items from the External Visual Inspection and the Oil Filter Change, Clean, and Inspect tasks, plus Packing and Seals (general) · Inspect the shaft and shaft sleeve for defects or damage · Look for loose, missing, or damaged bolts, studs, nuts, and parts · Verify shaft run out · Clean and inspect stuffing box for wear, damage, and presence of corrosion Seals · Perform diagnostics on old seal, such as determine amount of seal face wear for wear rate evaluation, condition of elastomers, presence of any debris, condition of the spring, and the extent of the setscrew indentations into the shaft sleeve · Check seal injection piping condition and verify flow · Inspect seal flange to horizontal split case joint for proper engagement · Replace with new seal Packing · Inspect and note condition of removed packing and packing sleeve · Verify configuration of packing and lantern rings · Replace with new packing using correct configuration, material, and number of rings · Torque to proper value Bearings (general) · Inspect and note the general condition of the journal and cleanliness of the bearing housing · Inspect the condition of bearing RTD’s and thermocouples · Inspect the condition of any permanently mounted vibration probes or devices Sleeve Bearings · Inspect the condition of and verify against OEM specifications all fits and tolerances · Inspect integrity of the bearing housing and clean · Inspect the bearing journal for damage or wear · Inspect the bearing housing cleanliness and integrity · Record as-found / as-left dimensions on all machine fits · Verify the proper orientation of old and new bearings, and the bearing to housing fit · Inspect the condition and integrity of the bearing babbitt · Inspect all oil passages, slinger and flinger rings · Inspect oil seal(s) and verify for proper orientation · Verify the presence of housing to casing dowel pins, their fit, and final radial alignment AntiFriction Bearings · Before starting disassembly, verify proper oil level · Verify proper bearing preload where applicable · Verify bearing part numbers, both as-found and as-left · Perform as-found inspection of bearing condition, looking for indications of abnormal wear, damage, or fatigue. Also inspect new bearing for damage and freedom of movement prior to installation. · Ensure proper bearing orientation and installation procedures are followed · Inspect shaft and bearing housing condition and dimensions at the bearing interface, obtain proper dimensions from OEM technical manual · Inspect oil passages for clogging, slinger, and flinger rings for damage · Inspect oil seal and assure proper orientation · Verify housing to casing dowel pins, and final radial alignment Kingsbury Type Bearings · Verify as-found and as-left orientation · Record as-found and as-left end play, and that it is within specifications · Inspect shoe surface condition and babbitt integrity · Inspect shoe button for damage and wear · Verify anti-rotation pin integrity · Verify thrust disk to shaft fit · Verify proper thrust nut integrity, locking method, and torque · Verify thrust disk flatness, perpendicularity, and run out · Verify housing condition, cleanliness, and integrity · Verify housing to casing dowel pins, fits, and final radial alignment Coupling Removal and Reinstallation · Inspect mating surfaces for cleanliness, wear, and integrity; record as-found and as-left conditions · Verify that the as-found and as-left coupling gap is within OEM specifications · Verify lubricant condition, if applicable; relubricate using proper type and quantity · Inspect shim packs, if applicable; record number of shims and size · Inspect coupling gear teeth, if applicable, for wear and damage · Inspect non-metallic parts for condition and wear · Inspect bolting for damage · Ensure proper orientation during reassembly · Perform alignment check Functional Testing: 2.3.10 Functional Tests The functional test is a start / run test conducted as a post maintenance test on the motor to verify operability, proper rotation, and readiness for return to service and also frequently as a post maintenance test on the driven equipment. Other forms of functional testing are IST tests that verify the operability of stand-by equipments. The Functional test should be performed when: - Returning powered equipment to service - As per technical specifications or as a post maintenance test

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HVAC Centrifugal Chillers Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe Mild

X X

X

5

6

7

8

X

X

X

X

X X

X

X X

X

X

X

X

X

X

X

Refrigerant Analysis

1Y

1Y

1Y 1Y

CO MB MS

See NES-MS-02.6

Oil Analysis

1Y

1Y

1Y 1Y

BS MS

See NES-MS-02.6

Vibration Analysis

6M

1Y

6M 1Y

BS

See Note 4

External Inspections / Evaluations -- Level 1 Walkdowns

1D

1D

1D 1D

See NES-MS-02.6

External Inspections /Evaluations -- Level 2 Walkdowns

3M 3M

3M 3M

See NES-MS-02.6

External Inspections /Evaluations -Performance Evaluation

3M 3M

3M 3M

See NES-MS-02.6

Condition Monitoring Task

Failure Codes

Time Directed Task

Calibration & Testing of Controls -- Safety Trip Switches

Calibration & Testing of Controls -- Other than Safety Trip Switches & Indicators

2Y

2Y

2Y

4Y 4Y

2Y

4Y 4Y

Comments

Failure Codes

Comments

OC

Safety Trip Switches: (1) Oil Temp Low & High (2)Oil Press. Low (3) Condenser Refrigerant Press. High (4) Condenser Water Flow Low (5) Evaporator Refrigerant Press. Low (6) Evaporator Refrigerant Temp Low (7) Chilled Water Return or Supply Temp Low (8)Chilled Water Flow Low (9) Compressor Discharge Temp. High (10) Bearing Temp. High (11) Motor Winding Temp. High (12) Purge High Pressure Safety Switch.

OC

Controls and Timers: (1) Chilled Water Temp./Guide Vane Controller (2) Condenser Pressure /Water Flow Controller (3) Hot Gas Bypass Control (4)Start/Stop Sequence Program Timer (5) Time Delay Relay (6) Soft Loading Control /Load Limiter (7) Oil Heater Thermostat (8) Surge Protection (9) Purge Operating Pressure Control.

Calibration & Testing of Controls -Indicators

4Y

4Y

6Y 6Y

OC

Indicators: (1) Condenser Refrigerant Press. (2) Evaporator Refrigerant Press. (3) Condenser Refrigerant Temp. (4) Evaporator Refrigerant Temp. (5) Oil Filter Differerential Pressure (6) Oil Press. Indicator (7) Oil Reservoir Temp. (8) Bearing (oil) Temp. (9) Chilled Water Inlet/ Outlet Pressure (10) Condenser Water Inlet/Outlet Press. (11) Chilled Water Inlet/Outlet Temp. (12) Condenser Water Inlet/Outlet Temp. (13)Condenser Water Flow (14) Ammeter (15) Purge Dehydrator Press. Indicator.

Periodic Maintenance -- Change Oil and Oil Filter

1Y

2Y

1Y 2Y

BS DA

No Comments

Periodic Maintenance -- Change Refrigerant Filter or Filter/Drier

*

*

*

CO DA DX MS

*See Note 6

Periodic Maintenance -- Clean Condenser Tubes

2Y

2Y

2Y 2Y

FL

See Note 9

Periodic Maintenance -- Clean Oil Cooler Tubes ( water cooled)

2Y

2Y

2Y 2Y

FL

See Note 8

Periodic Maintenance -- Clean Evaporator Tubes

4Y

4Y

4Y 4Y

FL

See Note 9 and 10

Periodic Maintenance -- Change Pump Out

2Y

2Y

2Y 2Y

BS

No Comments

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*

Compressor Oil Internal Inspections -- State Inspection

AR

AR

AR AR

Internal Inspections -- GL 89-13 Condenser Inspection

AR

AR

AR AR

FL

See Note 7

Internal Inspections -- Condenser Tubes Eddy Current Test

2Y

2Y

2Y 2Y

CO FL

No Comments

Internal Inspections -- Evaporator Tubes Eddy Current Test

4Y

4Y

4Y 4Y

CO FL

No Comments

Internal Inspections -- Refrigerant Float Valve System

3Y

3Y

6Y 6Y

SC

No Comments

Internal Inspections -- Dehydrator/Purge Unit

2Y

2Y

2Y 2Y

SC

No Comments

Internal Inspections -- Compressor Journal &Thrust Bearings,Compressor Bull & Pinion Gears, Compressor Oil Seal, Motor End Bearing

3Y

3Y

6Y 6Y

BS SC

No Comments

Internal Inspections -- Guide Vane Linkage Assembly

3Y

3Y

6Y 6Y

SC

No Comments

3Y 3Y

MB

No Comments

Internal Inspections -- Compressor Motor Megger

18M 18M

See Note 7

Internal Inspections -- Relief Valve /Rupture Disc

AR

AR

AR AR

SC

See Note 7

Periodic Replacement of Critical Components - Start/Stop Program Timer ,and Oil Heater Thermostat

6Y

6Y

8Y 8Y

SC

No Comments

Periodic Replacement of Critical Components -- Relief Valve/Rupture 9Y 9Y 9Y 9Y SC See Note 11 Disc,Robert Shaw Temperature Modules SERVICE CONDITION - ALL CHILLERS ARE IN MILD ENVIRONMENT. COMPONENT CLASSIFICATION CATEGORIES SHALL BE DETERMINED AS PER PCM PROCESS MA-AA-716-210. Note 1: Refer to Standard NES-MS-02.6 for Guidelines on above PM tasks and the basis of frequencies specified. Note 2: The Frequencies given above are calendar based not operating time based. Note 3: If a PM task is dependent on being done during a refueling outage,and the frequency does not match the refueling cycle,the station can use the frequency based on the previous or next refueling cycle depending on the past performance. For example if the PM frequency is given as 2Y,and the refueling cycle is 18M,the station may choose to do the PM at 18M frequency if there have been related problems in the past, or 3Y if there have been no related problems in the past. Note 4: Each Machine shall have a baseline vibration analysis established, if not done already. Note 5: Condenser water flow control valves and actuators shall be maintained in accordance with the valve/actuator PCM template. Hydramotor actuators shall be maintained in accordance with the Hydramotor PCM template. Note 6: Frequency is every 4 months for high duty cycle negative pressure machines (R11,R113,R114). Frequency is every 8 months for low duty cycle negative pressure machines (R11,R113,R114). Frequency is yearly for high duty cycle positive pressure machines. Frequency is every 2 years for low duty cycle positive pressure machines. Note 7: These inspections shall be done as per the applicable code requirements and/or station commitments. Note 8: If the oil cooler is cooled by chilled water, the tube cleaning frequency shall be the same as for the evaporator tubes. Note 9: The evaporator and condenser tube cleaning and corresponding Eddy Current Test frequency is the same, so it can be done at the same time. Note 10: If Eddy Current Test inspection of the evaporator tubes indicates that the tube cleaning is not necessary, it may be deferred to the next Eddy Current Test window. Note 11: Robert Shaw Temperature Modules are recommended for periodic replacement based on focus assessment of chilled water systems,dated Jan. 7-25,2002 Note 12: All References to EPRI in the Basis description pertain to EPRI TR-106857 Vol. 19- Program Basis for Chillers and Compressors. Click for Tables This template is the controlled revision. Please refer to MA-AA-716-210 & MA-AA-716-210-1001 for additional guidance. SME Summary The frequencies given in the PCM template for various tasks are based on the recommendations of EPRI (TR-106857, Vol. 19), OEM (Carrier Manual for 19EA & 19CB Chillers), and good operating practices at Utility plants. They are calendar based and not operating time based. These frequencies in the template are the suggested starting point, and are subject to changes in the future, based on operating experience feedback from all stations. If a PM task is performed during a refueling outage and the recommended frequency does not match the refueling cycle, the station may use the frequency based on the previous or next refueling cycle depending on past performance. For example if the PM frequency is given as 2Y, and the refueling cycle is 18M, the station may choose to do the PM at 18M frequency if there have been related problems in the past, or 3Y if there have been no related problems in the past. In general, where these tasks are already being performed, the existing intervals could be used as the starting point provided a basis exists. Such a basis could be constructed from diagnostic data, past inspection data and failure history. Although, the PCM Process (MA-AA-716-210) may classify a chiller as non-critical (based on redundancy or LCO greater than 7 days), it is recommended that frequencies given for critical application may be used as a guideline, if the station considers a particular chiller reliability as being critical to plant operation based on past experience. In addition to PM guidelines given in this template, following are the guidelines for resolution of some of the common operating problems being experienced A. AIR & MOISTURE IN-LEAKAGE IN NEGATIVE PRESSURE CHILLERS.

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R11 and R113 refrigerants are at negative pressure when the temperature is below 70F and 115F respectively. Therefore, when the chiller is shutdown it could be at negative pressure depending on ambient conditions and water temperature in the exchangers. The negative pressure causes in-leakage of air and moisture in the machine, which results in degradation of oil and corrosion of internal components. This is particularly a concern when the chiller is shutdown, since the purge unit is also shut down with the machine and cannot remove the moisture. Therefore, following special precautions are recommended to minimize, or prevent in-leakage when the chiller has to be shutdown. 1)When the chiller is shutdown, chilled water and condenser water flow through the chiller should also be shutdown. The cold water temperature further aggravates the negative pressure, which increases the in-leakage. In case there is a chemistry problem, it should be resolved by other means in consultation with the Chemistry Department. 2)The purge unit, if independent, should be kept operational when the chiller is shutdown. 3)Ancillary means (such as heating blanket) should be considered for warming the refrigerant to maintain the chiller at positive pressure, when it is shutdown for long periods during winter conditions. Normally the OEMs have ancillary devices available for this purpose. B. OIL MIGRATION DURING LOW LOAD OPERATION IN WINTER. Lubricating oil is miscible with the refrigerant, and it is carried with the refrigerant to the remaining system and eventually returned to the compressor. During winter operation the refrigerant flow reduces due to reduction in load, resulting in lower refrigerant flow velocity. Due to low velocity, the refrigerant looses the capability of returning all the oil back to the compressor, and some of it remains trapped elsewhere in the machine, resulting in low oil level. Oil is then added to bring up the level in the oil sump, and when the load increases during summer months all the trapped oil comes back to the compressor resulting in high oil level. Both low and high oil level eventually result in a chiller trip. The sudden return of large quantities of oil in the form of liquid slugs can also damage the compressor, especially reciprocating type. All chillers may not have this problem if the load remains adequate during winter conditions, and if there are special design features such as oil skimmers to assist in oil return. However, if this problem is being observed, extra vigilance during the cold months by frequent inspection of oil level can avoid serious problems. Following practice is recommended 1) In fall, when the load starts to drop, inspect the oil level every 12 hours (this frequency may be adjusted based on past experience for a particular machine). If the oil level remains below the required mark for longer than 24 hours, add oil as required. This may be started when the cooling load drops below 30% of the unit capacity. 2) In spring, when the load starts to pick up, inspect the oil level every 12 hours (this frequency may be adjusted based on past experience for a particular machine). If the oil level remains above the required mark for longer than 24 hours, remove oil as required. This may be stopped when the load increases to about 50% of the unit capacity.

Boundary Definition The boundary of HVAC - Chillers and Compressors for the purpose of this database is defined to include the following: · · · · · · · ·

Condenser Evaporator Compressor Refrigerant metering device or expansion valve Relief device Controls and wiring Refrigerant load control system Exclude chilled and condenser water pumps, motors, and isolation valves

Basis For Template Tasks Refrigerant Analysis: Refrigerant Analysis: NES-MS-02.6 Section 6.1. Periodic refrigerant analysis is important to detect and control contaminants in the refrigerant, which can result in degradation / failure of the various components, and cause inefficient operation of the unit. Refrigerants should be tested for the following contaminants – Moisture, Acid, Particulate/solids, Organic matter (sludge, wax, tars), and Non-condensable gases. Acceptance criteria for each contaminant is as follows – MOISTURE (ppm by weight) : Refrigerant R11, R113 - Normal 0 to 20, Alert 20 to 30, Fault >30. Refrigerant R12, R114, R134a, R500 - Normal 0 to 20, Alert 20 to 25, Fault >25. Refrigerant R22 - Normal 0 to 30, Alert 30 to 40, Fault >40. (A)Alert Level Actions – 1) Increase frequency of sampling refrigerant to twice the normal. 2) Sample lubricating oil with next sample of refrigerant to check for any signs of degradation. 3) Check all potential causes of high moisture and fix as required. 4) Check moisture indicators rigorously. 5) Check for any signs of lubricating oil degradation. 6) Change filter dryers/desiccants as required. (B)Fault Level Actions – 1) Re-sample refrigerant to verify results. 2) Recycle and clean refrigerant on line. 3) Change all filter dryers/desiccants 4) If trend continues, schedule a shutdown of the chiller and fix leaks. ACID(ppm by weight) : All Refrigerants - Normal 0 to 0.8, Alert 0.8 to 1.0, Fault >1.0. (A) Alert Level Actions – 1) Increase frequency of sampling refrigerant to twice the normal. 2) Check all potential causes of high acid, and fix as required. 3) Change filter dryers/desiccants as required. (B) Fault Level Actions – 1) Re-sample refrigerant to verify results. 2) Recycle and clean refrigerant on line until acid concentration drops to acceptable level. 3) Change all filter dryers/desiccants. PARTICULATE/SOLIDS: All Refrigerants – Any visual presence of dirt, rust or other particulate contamination should be reported as alert condition. If particulate/solids are found, the refrigerant filter should be replaced. If the problem persists in-spite of changing the filter several times, on-line cleaning of the refrigerant may be required. ORGANIC MATTER (% by Volume) : All Refrigerants - Normal 0 to 0.1, Alert 0.1 to 0.2, Fault >0.2. (A) Alert Level Actions – 1) Increase frequency of sampling refrigerant to twice the normal. 2) Change refrigerant filters as required. (B) Fault Level Actions – 1) Re-sample refrigerant to verify results. 2) Recycle and clean refrigerant on line until organic matter drops to acceptable level. 3) Change all refrigerant filters. NON-

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CONDENSIBLE GASES(% by Volume) : All Refrigerants - Normal 0 to 5, Alert 5 to 10, Fault >10. (A) Alert Level Actions – 1) Review operating parameters to confirm high non-condensable gases. 2) Increase frequency of sampling refrigerant to twice the normal. 3) Check purge unit/dehydrator for proper operation. 4) Increase purge rate. Caution should be observed to avoid excessive loss of refrigerant due to purge unit inefficiency. (B) Fault Level Actions – 1) Re-sample refrigerant to verify results. 2) If acceptable levels are not achieved, shutdown the machine and repair the leaks or faulty purge operation, as applicable. 3) If the machine cannot be shutdown, recycle and clean refrigerant on line until it reaches acceptable level. GENERAL NOTE: A log of the periodic refrigerant analysis should be maintained for trending. Basis for the above acceptance criteria, and details of cause and effects of the various contaminants are discussed in NES-MS-02.6 and ASHRAE Refrigeration Handbook, 1998 Chapter 6. The frequency given for refrigerant analysis is based on EPRI. Past practices at Utility sites varied from 1Y to 1.5Y. Oil Analysis: Oil Analysis: NES-MS-02.6, Section 6.2. The oil analysis provides a “look inside” a compressor without disassembly. When unacceptable wear conditions develop inside the compressor, a corresponding detectable change in the characteristics of the oil will become evident. The results from oil analysis should be used in conjunction with vibration analysis and bearing temperatures to detect excessive bearing wear. The oil sample should be tested for the following properties: · Metal wear · Moisture · Acidity · Viscosity · Solid residue. The oil analysis shall be conducted as per Utility T&RM document MA-MW-716230-1001, which provides the acceptance criteria, trigger points and potential actions, and guidelines for testing and interpreting results. A log of the periodic oil analysis should be maintained to provide the trend. The frequency given for oil analysis is based on EPRI recommendations. Past practices at Utility sites varied from 0.5Y to 3Y. Vibration Analysis: Vibration Analysis: NES-MS-02.6 Section 6.3. Vibration analysis should be performed per the station vibration monitoring program. This analysis may be reinforced by thermography as required, to identify any abnormal bearing temperature conditions. The frequency given is based on EPRI and Utility wide review by all site SMEs. EPRI recommendation is 1Y frequency for all applications. Past practices at Utility sites doing vibration analysis varied from 0.25Y to AR for centrifugal compressors, and 1M to AR for condensing unit reciprocating compressors. External Inspections / Evaluations -- Level 1 Walkdowns: External Inspections - Level 1 Walkdowns: NES-MS-02.6 Section 6.4. Level 1 walk-down should be done on a daily basis and should include the following tasks: 1) Visually check refrigerant moisture indicator at inlet and outlet of filter/drier. Note: If outlet indicator shows wet, change cartridge within 2 days and continue changing every 2 days until outlet is dry. If it stays wet after 3 changes, assume a water leak and take corrective action. If both indicators are dry, change cartridge per PCM template. 2) Visually check oil level. 3) Visually check refrigerant level. 4) Visually check all control indicators & operating parameters are within normal operating range. Each chiller should have a checklist of the indicators and operating parameters to be checked, and the corresponding normal range. 5) Visually check that the compressor guide vane actuator position and current ampere reading are within normal operating range (normal range to be established by the site for each chiller). 6) Verify that noncondensable gas purge is not operating too frequently (normal frequency to be established by the site for each chiller). 7) Visually check for condenser water and chilled water leaks. 8) Visually check gaskets and oil seals for any evidence of refrigerant/oil leaks. 9) Verify general condition and performance of the unit. 10) Maintain a daily log of the above observations to show trends. The frequency given is based on past practices at Utility plants. See "Click for Tables" at bottom of template to view the recommended checklist for Level 1 Walkdown. External Inspections /Evaluations -- Level 2 Walkdowns: External Inspections - Level 2 Walkdowns: NES-MS-02.6 Section 6.4. Level 2 walk-down should include the following: 1) Take readings of the following operating parameters - Chilled water inlet and outlet temperature - Condenser water inlet and outlet temperature - Evaporator refrigerant pressure and temperature - Condenser refrigerant pressure and temperature - Chilled water flow and pressure drop - Condenser water flow and pressure drop. This data should be used by the System Engineer to do a performance evaluation. ·2) For positive pressure machines, check for refrigerant leaks at gaskets, seals, and joints by using an electronic leak detector. The common refrigerants at Utility plants that keep the machine at positive pressure are R12 & R22, R134a, and R500. R114 is a borderline case, which has the condenser at positive pressure while the evaporator may be negative or close to atmospheric. ·3) For negative pressure machines, verify the frequency of purge to be within acceptable range (if necessary do a leak test by raising the machine pressure - see OEM instructions). The common refrigerants at Utility plants that keep the machine at negative pressure are R11 & R113, while R114 is a borderline case (see above). · 4)This walkdown should include thermography of the control/electrical panels to determine the general condition of various control/electrical components. Higher than normal temperature of any control/electrical component can predict an impending failure. This would require a baseline to be established, by doing thermography on a normally operating unit. ·5) Maintain a log of the above observations to show trends. The frequency given is based on EPRI. External Inspections /Evaluations -- Performance Evaluation: External Inspections - Performance Evaluations: NES-MS-02.6, Section 6.5. Performance evaluation should be done by the System Engineer. It should basically involve review of the operating parameter readings taken for each chiller during the Level 2 Walk-down against the normal condition parameters to interpret any problems based on the guidelines provided in Table 1. The typical normal design parameters for various refrigerants used at Utility plants are given in Table 2. This evaluation would provide a good pulse on the chiller, and based on the trend it can provide valuable input on any specific maintenance/ repair needed, before a minor problem manifests into a chiller failure. See "Click for Tables" at bottom of template to view Table 1 and 2. Calibration & Testing of Controls -- Safety Trip Switches: Calibration & Testing of Safety Trip Switches: NES-MS-02.6. Section 6.7 A (e). EPRI has included calibration of all controls as a single item with frequency of 2Y for critical applications and AR for non-critical applications. The AR frequency in the past had resulted in some stations not doing any calibrations. The PCM template recommends specific frequencies for all applications. ·The frequency given is based on EPRI recommendations and past practices at Utility plants. Past practices at Utility plants varied from 2Y to 6Y Calibration & Testing of Controls -- Other than Safety Trip Switches & Indicators: Calibration & Testing of Controls & Timers: NES-MS-02.6.· Section 6.7 A (e). EPRI has included calibration of all controls as a single item with frequency of 2Y for critical applications and AR for non-critical applications. The AR frequency in the past had resulted in some stations not doing any calibrations. The PCM template recommends specific frequencies for all applications. The frequency given is based on EPRI recommendations and past practices at Utility plants. Past practices at Utility plants varied from 1.5Y to 6Y.

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Calibration & Testing of Controls -- Indicators: Calibration & Testing of Indicators: NES-MS-02.6.·Section 6.7 A (e). EPRI has included calibration of all controls as a single item with frequency of 2Y for critical applications and AR for non-critical applications. Considering that indicators are functionally not as important as safety switches, 2Y frequency is not necessary for indicators. The AR frequency in the past had resulted in some stations not doing any calibrations. The PCM template recommends specific frequencies for all applications. The frequency given is based on past practices at some Utility plants. Past practices at Utility plant varied from 4Y to 6Y. Periodic Maintenance -- Change Oil and Oil Filter: Periodic Maintenance -- Change Oil and Oil Filter: NES-MS-02.6. Section 6.7A (f). The frequency given is based on OEM recommendations. The past practices at Utility plants varied from 1Y to 3Y. Periodic Maintenance -- Change Refrigerant Filter or Filter/Drier: Periodic Maintenance -- Change Refrigerant Filter or Filter/Drier: NES-MS-02.6. Section 6.7A (f). The frequency given is based on OEM recommendations. The past practices at Utility plants varied from 1Y to 3Y Periodic Maintenance -- Clean Condenser Tubes: Utility plants Periodic Maintenance -- Clean Condenser Tubes: NES-MS-02.6. Section 6.7A (f). The operating practices at varied from 1Y to 4Y. Although, the OEM recommends a 1Y frequency, review with the Utility site SMEs concluded that a 2Y frequency is more appropriate as a general specification for all stations based on operating experience. Periodic Maintenance -- Clean Oil Cooler Tubes ( water cooled): Periodic Maintenance -- Clean Oil Cooler Tubes ( water cooled): NES-MS-02.6. Section 6.7A (f). The frequency given is the same as for condenser tubes, since usually same water is used for oil coolers. Use evaporator tubes cleaning frequency if chilled water is used. If the cooler is cooled by chilled water, the tube cleaning frequency shall be the same as for evaporator tubes. Periodic Maintenance -- Clean Evaporator Tubes: Periodic Maintenance -- Clean Evaporator Tubes: NES-MS-02.6. Section 6.7A (f). The frequency given is based on past practices at Utility plants, which varied from 3Y to 5Y. The OEM has no specific frequency recommendation Periodic Maintenance -- Change Pump Out Compressor Oil: Periodic Maintenance -- Change Pump Out Compressor Oil: NES-MS02.6. Section 6.7A (f). The frequency given matches with the major pump-down activities such as internal inspections dehydrator/purge unit. This was based on Utility operating experience, per review done by all site SMEs. Internal Inspections -- State Inspection: Internal Inspections -- State Inspection & GL 89-13 Condenser Inspections: NES-MS-02.6. Section 6.7A (g). Internal Inspections State inspection and GL 89-13 inspection frequencies should be as required, based on the current commitments at each station Internal Inspections -- GL 89-13 Condenser Inspection: Internal Inspections -- State Inspection & GL 89-13 Condenser Inspections: NES-MS-02.6. Section 6.7A (g). Internal Inspections State inspection and GL 89-13 inspection frequencies should be as required, based on the current commitments at each station Internal Inspections -- Condenser Tubes Eddy Current Test: Internal Inspections -- Condenser Tubes Eddy Current Test: NES-MS02.6. Section 6.7A (g). The frequency given is based on past practices at Utility plants (which varied from 1Y to 3Y) and it matches the condenser tube cleaning frequency. Internal Inspections -- Evaporator Tubes Eddy Current Test: Internal Inspections -- Evaporator Tubes Eddy Current Test: NESMS-02.6. Section 6.7A (g). The frequency given is based on past practices at Utility plants (which varied from 1Y to 6Y), and it matches the evaporator tube cleaning frequency. Internal Inspections -- Refrigerant Float Valve System: Internal Inspections -- Refrigerant Float Valve System: NES-MS-02.6. Section 6.7A (g). The frequency given is based on past practices at Utility plants, and to match compressor internal inspection frequencies requiring refrigerant evacuation which is needed for this inspection. Internal Inspections -- Dehydrator/Purge Unit: Internal Inspections -- Dehydrator/Purge Unit: NES-MS-02.6. Section 6.7A (g). Although, the frequency recommended by the OEM is 1Y, a review by all Utility site SMEs concluded that a 2Y frequency is more appropriate as a general specification for all stations based on the operating experience and past performance. Internal Inspections -- Compressor Journal &Thrust Bearings,Compressor Bull & Pinion Gears, Compressor Oil Seal, Motor End Bearing: Internal Inspections -- Compressor Journal &Thrust Bearings,Compressor Bull & Pinion Gears, Compressor Oil Seal, Motor End Bearing: NES-MS-02.6. Section 6.7A (g). The frequency given is based on past practices at Utility plants, which varied from 3Y to 9Y. Internal Inspections -- Guide Vane Linkage Assembly: Internal Inspections -- Guide Vane Linkage Assembly: NES-MS-02.6. Section 6.7A (g). The frequency given is based on operating experience and to match other internal inspections of compressor components. Internal Inspections -- Compressor Motor Megger: Internal Inspections -- Compressor Motor Megger: NES-MS-02.6. Section 6.7A (g). The frequency given is based on past practices at Utility plants, which varied from 1.5Y to 3Y. Internal Inspections -- Relief Valve /Rupture Disc: Internal Inspections -- Relief Valve /Rupture Disc: NES-MS-02.6. Section 6.7A (g). Inspection of relief valves and rupture disc shall be as required by the applicable codes and/or site commitments. The OEM recommends a periodic visual inspection of the outlet side of the relief valve/rupture disc by removing the outlet vent pipe, if it is removable. Periodic Replacement of Critical Components - Start/Stop Program Timer ,and Oil Heater Thermostat: Periodic Replacement of Critical Components - NES-MS-02.6. Section 6.7A (h). This includes components that have high duty cycles and/or have a critical function. The components included are also based on the existing practices at some Utility sites, and/or recommendation of some site SMEs. The frequencies given are based on past practices at some Utility sites and/or reasonable lifetime for these components.

68

Periodic Replacement of Critical Components -- Relief Valve/Rupture Disc,Robert Shaw Temperature Modules: Periodic Replacement of Critical Components - NES-MS-02.6. Section 6.7A (h). This includes components that have high duty cycles and/or have a critical function. The components included are also based on the existing practices at some Utility sites, and/or recommendation of some site SMEs. The frequencies given are based on past practices at some Utility sites and/or reasonable lifetime for these components. Robert Shaw Temperature Modules are recommended for periodic replacement based on Braidwood focus assessment of chilled water systems, dated Jan 7-25, 2002.

69

Hydraulic Valve - FW009 Component Classification Categories Yes

Critical Duty Cycle

1

2

3

4

X

X

X

X

No High

Service Condition

X

Low

X X

Severe

X

Mild

6

7

8

X

X

X

X

X X

X X

X X

X X

Time Directed Task

5

X

X X

X Failure Codes Comments No Comments

HYDRAULIC RESEVOIR Hydraulic Fluid - Sample Analysis (Notes 1 & 4)

9M

DA MS

No Comments

Replace Hydraulic Fluid (Notes 4 & 5)

3Y

AG DA

No Comments

Hydraulic Reservoir - Clean & Inspect (Notes 4 & 5)

9Y

CO DA FL

No Comments

Replace Pump Discharge Filter, Solenoid Valve Filter, and Internal Filters (Note 4)

9Y

DA FL

No Comments

Replace Solenoid Valves, Pilot Check Valves, Internal Relief Valve, Internal Check Valve, and Pressure Switches (Note 4)

9Y

AG

No Comments

Replace Elastomeric Seals, O-rings, and Back-up Rings (replace with solenoid valves) (Notes 2 & 4)

9Y

AG SL

No Comments

Replace Motor and Hydraulic Pump (Note 4)

18Y

AG

No Comments

Replace Fill Valve, Shut-off Valve, and Pressure Gauges (Note 4)

A/R

DF SC

No Comments

Replace Junction Box Seals (Note 4)

A/R

GL

No Comments

Calibrate Pressure Switch (Note 4)

3Y

OC

No Comments

Replace Piston Seal and Rod Seal (Notes 2 & 4)

9Y

AG SL

No Comments

Replace Check Valves and Pressure Switch (Note 4)

9Y

AG SC

No Comments

Replace Hydraulic/Pneumatic Cylinder (Note 4)

A/R

BF CO ER

No Comments

Replace Fill Valve and Shut-off Valve (Note 4)

A/R

DF

No Comments

18Y

AG

No Comments

HYDRAULIC/PNEUMATIC CYLINDER

PNEUMATIC RESEVOIR (BOTTLE) Replace Shut-off Valve (Note 4)

No Comments Notes: All external tapered pipe threads used for pressure tight connections shall be die cut and inspected in accordance with ANSI/ASME B1.20.1. (1) Fluid Analysis shall be performed at 60-day intervals until sustained quality over an 18-month fuel cycle demonstrates that 9-month frequencies are acceptable. Fluid Quality shall be maintained in accordance with Fyrquel 220 MLT specifications. (2) Elastometric seals shall be replaced when disturbed for reasons of corrective maintenance to other actuator components. (3) Perform Visual inspection of the nitrogen reservoir during any PM tasks performed between replacements. (4) Complete replacement at 9-year intervals with new or completely rebuilt actuators shall be considered. Inventory of two units per station. (5)During fluid replacements, the reservoir shall be checked for the formation of rust or evidence of corrosion. Correct if found.

Replace Pneumatic Reservoir (Bottle) (Notes 3 & 4)

A/R

AL CO

This template is the controlled revision. Please refer to MA-AA-716-210 & MA-AA-716-210-1001 for additional guidance. SME Summary This PCM Template was written in response to management requests to resolve a number of nagging problems that occurred over the past year on the actuators of these valves Boundary Definition The template addresses preventive maintenance for the FW009 valves at Braidwood & Byron. Each unit has four of these valves for a total of sixteen. Basis For Template Tasks

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HYDRAULIC RESEVOIR: No Basis At This Time Hydraulic Fluid - Sample Analysis (Notes 1 & 4): Vendor recommendation and Braidwood experience. Replace Hydraulic Fluid (Notes 4 & 5): Vendor recommendation and Braidwood experience. Hydraulic Reservoir - Clean & Inspect (Notes 4 & 5): Vendor recommendation and Braidwood experience. Replace Pump Discharge Filter, Solenoid Valve Filter, and Internal Filters (Note 4): Vendor recommendation and Braidwood experience. Replace Solenoid Valves, Pilot Check Valves, Internal Relief Valve, Internal Check Valve, and Pressure Switches (Note 4): Vendor recommendation and Braidwood experience. Replace Elastomeric Seals, O-rings, and Back-up Rings (replace with solenoid valves) (Notes 2 & 4): Vendor recommendation and Braidwood experience. Replace Motor and Hydraulic Pump (Note 4): Vendor recommendation and Braidwood experience. Replace Fill Valve, Shut-off Valve, and Pressure Gauges (Note 4): Vendor recommendation and Braidwood experience. Replace Junction Box Seals (Note 4): Vendor recommendation and Braidwood experience. HYDRAULIC/PNEUMATIC CYLINDER: No Basis Available At This Time Calibrate Pressure Switch (Note 4): Vendor recommendation and Braidwood experience. Replace Piston Seal and Rod Seal (Notes 2 & 4): Vendor recommendation and Braidwood experience. Replace Check Valves and Pressure Switch (Note 4): Vendor recommendation and Braidwood experience. Replace Hydraulic/Pneumatic Cylinder (Note 4): Vendor recommendation and Braidwood experience. Replace Fill Valve and Shut-off Valve (Note 4): Vendor recommendation and Braidwood experience. PNEUMATIC RESEVOIR (BOTTLE): No Basis Available At This Time Replace Shut-off Valve (Note 4): Vendor recommendation and Braidwood experience. Replace Pneumatic Reservoir (Bottle) (Notes 3 & 4): Vendor recommendation and Braidwood experience.

71

Low Voltage Electric Motors Component Classification Categories Yes

Critical Duty Cycle

1

2

3

4

X

X

X

X

No High

Service Condition

X

Low Severe Mild

X X

X

5

6

7

8

X

X

X

X

X X

X

X X

X

X X

X

X

X

X

Condition Monitoring Task

Failure Codes

Comments

6M 6M 6M 6M NR NR NR NR

BS DA DL LC SC

Increased frequency may be required if adverse conditions are discovered EPRI TR-106857-V8 Application Note 2.3.1

Vibration Monitoring (motor>200HP)

6M 6M 6M 6M NR NR NR NR

BS DL GW LC SC

Increased frequency may be required if adverse conditions are discovered. EPRI TR-106857-V8 Application Note 2.3.2

Oil Analysis (motors >200HP)

BS CO DA DL 1Y 1Y 1Y 1Y 18M 18M 18M 18M MS SC

Increased frequency may be required if adverse conditions are discovered. EPRI TR-106857-V8 Aplication Note 2.3.3

Electrical Testing ( Insulation Resistance , Winding Resistance, Surge Test) )

3Y 4Y 3Y 4Y AR

Thermography (motor >200 HP)

AR

AR

AR

Time Directed Task Brush Maintenance

3M 1Y 3M 1Y 3M

2Y

3M

2Y

External Visual Inspection

1Y 2Y 2Y 2Y NR NR NR NR

Surveillance Task Functional Testing

AR AR AR AR NR NR NR NR

CB DA IB LC MS SC SH

Perform in accordance with Exelon Motor Maintenance Logic Tree MA-AA-716-210-1002

Failure Codes

Comments

AG NO OP SC

Refer to EPRI report TR-106857V8 Application Note 2.3.5

CO DA LC SC

Refer to EPRI report TR-106857V8 Application Note 2.3.6

Failure Codes

Comments

OC

Refer to EPRI report TR-106857V8 Application Note 2.3.7.

This template is the controlled revision. SME Summary No SME Summary Available At This Time Boundary Definition The boundary of a low voltage (i.e. 600 V or less) electric motor for the purpose of this database is defined to include the following: · · · · · · ·

Electric motor and motor shaft excluding the coupling All connected cables up to but not including the supply device Motor mounting and base Bearing cooling water connections, if present, excluding all valves and piping external to the motor’s shell or frame Air filters, if present Internal motor heaters Detectors, if present, such as temperature, vibration, and alarms

The 600 V class of motors includes all AC motors rated 600V or less, but excludes DC motors in this voltage range. Basis For Template Tasks Thermography (motor >200 HP): 2.3.1 Thermography Failure Locations and Causes: The main application of thermography is to provide indication of the condition of exposed electrical connections, and to compliment other indications of bearing wear. Thermography plays a backup role when bearing temperature is directly measured by in-situ RTDs or thermocouples. Other indications of bearing wear are oil and vibration analysis. Thermography can usually only give an indication of increased temperatures in the general region of the bearing casing, where this is accessible. Additionally, thermography can detect clogged air passages and screens. Progression of Degradation to Failure: The lubrication related causes of bearing wear appear randomly over a period of many months up to 2 years. Blocked airways and high resistance electrical connections have a similar time scale. Fault Discovery and Intervention: None of the above causes is likely to fail the motor catastrophically on short time scales, so that a 6 month interval appears appropriate for thermography. In the case of standby motors, thermography should be performed after the motor has been running at rated speed for four hours in order to reach a stable operating temperature and hence give valid measurements. When thermocouples or RTDs are installed, direct bearing temperature indication is likely to be monitored frequently, and vibration monitoring provides an independent indication of bearing wear. Consequently, thermography is not a critical technology for detection of bearing wear in this class of motors. Thermography should include: · Inspection for unusual and unbalanced heating of the connections at the main motor and motor heater leads and their respective power cable interfaces · Unusual differences in exit air temperatures when compared to historical values · Inspection for

72

unusual heating in motor bearing and windings that cannot be attributed to normal thermal patterns and temperatures Vibration Monitoring (motor>200HP): 2.3.2 Vibration Monitoring Failure Locations and Causes: Vibration monitoring is very effective for addressing all causes of wear in bearings of all types. Additionally, vibration monitoring addresses all causes of failures originating in the shaft, mechanical failures in the rotor, including loose wound rotor windings, and in the frame, enclosure and mounting. Progression of Degradation to Failure: Most of the causes of bearing failure appear randomly over a period of several months up to 2 years. The appearance of cracks, wear, and bowing in the shaft, and all degradation mechanisms in the rotor, although random in occurrence times, are not expected within a few years. The onset of degradation in the frame, such as deformation, cracking, and soft foot share similar timing characteristics as for the shaft and rotor, although the progression to failure could be rapid if the vibration is close to a structural resonance. Fault Discovery and Intervention: The suggested interval of 6 months should be sufficiently frequent to make vibration monitoring an effective detection method for a wide range of failure causes. Additionally, the frequency of vibration can provide specific diagnosis or focus further investigation in many instances. However, the random nature of occurrence of many of the degradation mechanisms that can in principle be detected requires this task to be performed at an interval which is no longer than 6 months. Oil Analysis (motors >200HP): 2.3.3 Oil Analysis Failure Locations and Causes: Oil sampling and analysis is particularly directed at causes of bearing wear for all types of bearings. Also covered are all sources of wear for bearing seals. Other failure causes that affect oil quality are failed cooling coils and other components in the oil distribution system, and cracking and wear of the shaft. Oil temperature above the rated limit can lead to degradation. Typical anti-friction bearings usually will not exceed 45° C above ambient; 2-pole motors usually will not exceed 50° C above ambient. Progression of Degradation to Failure: All the above degradation mechanisms are random in time of onset but in most circumstances are expected to appear over periods of many months or years, and are not expected to lead to failures on short time scales. Fault Discovery and Intervention: The interval of 1 year for oil analysis is thought to be sufficient to detect the onset of most of the failure causes. Electrical Testing ( Insulation Resistance , Winding Resistance, Surge Test) ): 2.3.4 Electrical Tests - Off-Line Failure Locations and Causes: This task contains three main ingredients: measurements of winding resistance, insulation resistance, and motor circuit evaluation. The task focuses primarily on detecting degraded insulation, whether associated with windings, bearings, feeder cables, or motor leads, the integrity of all electrical connections, and the detection of high resistance, shorts, and grounds in electrical components such as motor heaters. Progression of Degradation to Failure: Electrical insulation is subject to continuous degradation. The main causes of insulation degradation are excessive heat above the rated limit, excessive starts within a short period, winding movement and vibration, age, and contamination (which may be e.g. oil, moisture, salt). Although the initiation of these influences may be random, the degradation progresses relatively slowly and is expected to give a trouble free period of at least several years (exception could be high temperatures from excessive starts within a short period, which should be controlled by operational procedures). Problems with feeder cables, motor leads, connections, lugs, and switches are likely to occur randomly on various time scales, shorter than those above. Measurement of winding resistance can detect shorts between turns. Fault Discovery and Intervention: Most of the degradations addressed by off-line electrical testing produce measurable effects before failure on a time scale of a few years. Consequently the off-line tests could be performed every 2 or 3 years and provide effective coverage for the degradation modes discussed above. It is likely that only the first three items listed below would be included in every scheduled electrical off-line test. The remaining tasks could be included every other time or as required. Electrical off-line tests can only be conducted meaningfully when all parts of the motor are within 10° F of ambient temperature. The tests should include some or all of the following; these tests should be trended and compared to historical data to derive their maximum benefit: · Winding resistance · Insulation resistance · Motor circuit evaluation · AC High Pot · DC Step voltage · Surge testing, generally recommended only for form wound 480V motors Brush Maintenance: 2.3.5 Brush Maintenance Failure Locations and Causes: Brush Maintenance is an inspection of the brushes and slip rings. A worn, corroded, or loose brush holder or slip ring, is likely to be revealed by erratic operation and excessive sparking. To some degree, degraded insulation may also be observable. Progression of Degradation to Failure: Worn brushes may lead to failures in just a few weeks in problem situations, although a much longer useful life is normally expected. Slip ring problems usually show up on much longer timescales than brush problems, in years rather than weeks. Fault Discovery and Intervention: The condition of the brushes is therefore the key consideration that controls the task interval. Wear rates will be very dependent on the accumulated run time. Continuously running motors should have brush inspections at three month intervals unless operating history indicates otherwise. Standby motors wound rotor motors are very uncommon and their brush inspection should be considered on an individual basis. Operating history is crucial to finding the appropriate intervals. The following should be included in brush inspection: · Inspect the slip rings for unusual wear, damage, or grooving · Inspect slip rings for discoloration indicating loss of electrical contact with the brushes · Inspect the brushes for wear or grooving · Inspect the brushes for freedom of movement and for proper spring tension · Inspect brushes for proper operating length as prescribed by the manufacturer · Inspect the brush pigtail connection for tightness and any damaged · Inspect the slip ring and brush housing for signs of excess carbon, clean if necessary External Visual Inspection: 2.3.6 External Visual Inspection Failure Locations and Causes: The external visual inspection focuses mainly on causes of visible indications of deterioration in oil quality, visible oil and grease leakage and low oil level, either from problems with wear of bearings or bearing seals, or from any failure in the oil distribution system. External visual inspection is also effective for detecting clogged air filters and blocked air passages or screens, and blocked oil breather caps. If detectors are present, bearing temperature may be monitored frequently, e.g. observed every shift during operator rounds. These frequent observations are included in the external visual inspection task, both here and in Tables 3.1 and 3.2, although plants will have a separate procedure, possibly a part of operator rounds, for how they are observed, recorded or trended. Bearing temperature is a key indication for all causes of bearing wear, failures in the oil distribution system, and other failures that can affect the life of bearings. Certain degradation processes in electrical circuits might also be observed , such as failed space heaters. The inspection also includes general observation for loose, missing, or damaged parts, and listening for unusual noises or vibrations, e.g. from mechanical interference between rotor and stator. Progression of Degradation to Failure: All the above degradation mechanisms are random in time of onset but in most circumstances are expected to appear over periods of many months or years, and are not expected to lead to failures on short time scales. Fault Discovery and Intervention: The interval of 1 year for the external visual inspection is thought to be sufficient to detect the onset of most of the visible failure causes. In addition to the above discussion of bearing temperature, some other items below are observable during normal operator rounds. Such items (e.g. oil level and color, unusual noises) are also assumed to be included as a formal part of operator rounds, so that operator rounds does not appear as a separate PM Strategy on the Template or in Tables 3.1, or 3.2. External Visual Inspection should include: · Inspect for: damaged, loose, missing or vibrating parts, externally visible oil leaks around bearings and bearing seals, external water leaks around bearing cooling interfaces, broken or loose grounding cables, damaged conduits and seal flex, damaged wiring and

73

insulators, damaged junction boxes and their gaskets, blocked / clogged / plugged air filters and inlet air screens · Inspect bearing slinger rings for proper operation and movement · Verify proper oil level; oil should not be discolored · Inspect for plugged oil sight glass vent · Verify proper motor strip heater status indication · Listen for unusual noises Functional Testing: 2.3.7 Functional Tests The functional test is a start / run test conducted as a post maintenance test on the motor to verify operability, proper rotation, and readiness for return to service and also frequently as a post maintenance test on the driven equipment. Other forms of functional testing are IST tests that verify the operability of stand-by equipments. The Functional test should be performed when: - Returning powered equipment to service - As per technical specifications or as a post maintenance test

74

Main Condenser Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe

X X

X

Mild

5

6

7

8

X

X

X

X

X X

X

X X

X

X

X X

X X

X

Condition Monitoring Task

Failure Codes

Comments

Performance Monitoring

1W

AL CO DA ER FL OC OR

EPRI TR-106857-V34 Note 2.3.1

NDE Inspection (1)

2Y

AG CO ER

See Note (1) May be performed at refuel.

Time Directed Task

Failure Codes

Comments

Waterbox Inspection

2Y

CO DA ER FL LC OR

EPRI TR-106857-V34 Note 2.3.3 May be performed at refuel.

Steam Side Inspection (2)

2Y

AG CO ER LC SC

See Note (2) May be performed at refuel.

Cleaning (3)

AR

DA FL

See Note (3) Perform at every refueling outage.

Main Turbine Expansion Joint Replacement

AR

AG

Based on Manufacturer's Recommendations

Circulating Water Piping Expansion Joint 2Y Inspection

AG

No Comments May be performed at refuel.

Circulating Water Piping Expansion Joint AR Replacement

AG

Based on Manufacturer's Recommendations.

Chemical Feed Equipment Monitoring (4) 2W

AL OC

See Note (4)

GW LC OR SC

Traveling Screen System Inspection

AR

Traveling Screen System Overhaul

AR

AG

Includes screen wash/trash collect

Flow Reversing Valves - Overhaul

AR

SC

See MOV PCM Template for basis and overhaul guidelines on large service and circulating water butterfly valves.

Online Cleaning System Inspection

2Y

SC

No Comments May be performed at refuel.

Online Cleaning System Overhaul

AR

AG

No Comments

Includes screen wash/trash collect

See Note (5) See MOV PCM Template for Basis and overhaul guidelines on large AR SC service and circulating water butterfly valves. (1)) Details provided in ER-AA-335-1007, Main Condenser NDE Test Program Guidelines and ER-AA-335-1006 Heat Exchanger Electromagnetic Testing (ET) Methodology. (2) Details provided in NES-MS-11.01,Main Condenser(Steam Side)& Hotwell Inspection and Closeout. (3) The use of metal scrapers for mechanical cleaning of tubes is prohibited without specific approval of ROG Engineering. (4) In addition to the availability of online monitoing instruments, there should be at a minimum a once per week check of feed equipment performance by the equipment cognizant technical personnel. Based on the current chemical supply contracts this will be performed by the applicable chemical vendor technical personnel. (5) This item refers to major system isolation valves that directly impact generation and cannot be repaired online. The overhaul frequency can be adjusted up or down as necessary to reflect industry/site experience with valve type/application, as found condition of similar valves, and severity of impact of failure of the valve, as permitted by the guidance provided in MA-AA-716-210. (6) This item should include instruments that are essential to monitoring system performance such as: condenser backpressure, circulating water temperature, circulating water pressure, and traveling screen water levels.

Major System Isolation Valves Overhaul (5)

This template is the controlled revision SME Summary 1. Failure Modes A review of available failure data from EPRI, INPO and NRC sources was performed to identify the most likely failure modes for Main Condensers. This review indicates that the following are the most likely failure modes: Structural Failures: 1. 2. 3. 4. 5.

Tube Failures Main Turbine expansion joint failures Manhole / gasket leaks Extraction Steam Bellows failures Baffle or shroud failures

75

Heat Transfer Loss 1. Macrofouling 2. Microfouling A review of this template reveals that with the addition of items for main turbine expansion joint inspection and replacement, all major failure mechanism will be addressed by this template. Tube failures are addressed by eddy current testing under NDE inspection. Main turbine expansion joint failures are addressed by the inspection and replacement activities. Manhole/ gasket leaks are addressed under NES-MS-11.01, Main Condenser (Steam Side) & Hotwell Inspection and Closeout. Extraction bellows failures are also addressed by NESMS-11.01, as are baffle or shroud failures. Macrofouling and microfouling are addressed by performance monitoring activities, cleaning, chemical feed equipment monitoring and traveling screen and amertap system inspections.

Boundary Definition The boundary of Main Condensers for the purpose of this database is defined to include the following: · Condensers, including: waterboxes · Hotwell · Tubes and tube sheets · Supports, cathodic protection · Expansion seal · Inlet and outlet nozzles · Turbine exhaust flange connection · Penetration bellows · Exclude feedwater heaters, the waterbox vacuum priming system, and instrumentation, and any equipment exhaust or suction piping and their penetrations

Basis For Template Tasks Performance Monitoring: 2.3.1 Performance Monitoring Failure Locations and Causes: Performance Monitoring addresses the overall integral performance of the condenser. Performance deterioration detectable by this task is likely to be caused by microbiologically induced corrosion, fouling of the tubes, scaling or the buildup of other deposits. Progression of Degradation to Failure: Corrosion and fouling are caused by a variety of conditions which are all characterized by random occurrence times and the likelihood of rapid deterioration on a time scale of weeks or months. The occurrence of these events, e.g. macrofouling, or microbiologically induced corrosion, usually indicates a chronic propensity to deteriorate in that manner over an extended time, or is caused by sudden changes in conditions. The randomness of these failure causes and their potential to develop quickly requires frequent Performance Monitoring. Fault Discovery and Intervention: Main condensers are considered to operate continuously in severe conditions. Performance monitoring every week is recommended to address the vulnerability to sudden onset and propagation of corrosion and fouling. Performance Monitoring should include the following: · Monitor, track, and trend tube side DP. · Monitor, track, and trend DT. · Monitor Impressed Cathodic Protection settings and performance. · Monitor, track ,and trend condenser cleanliness factor. · Sample fluids for the presence of cross contamination and trend · Monitor, track, and trend turbine back pressure. · Monitor and trend air in-leakage levels. NDE Inspection (1): EPRI TR-106857-V34 Note 2.3.2 NDE Inspection Failure Locations and Causes: Non-Destructive Examination could include a variety of techniques, as appropriate, but is generally focused on erosion and corrosion of tubes, and on tube defects and cracking. Among these, tube corrosion and cracking are quite common. Tube erosion may be external or internal. Progression of Degradation to Failure: The above failure causes are random in nature with a wide range of possible development times, depending on plant-specific conditions. The occurrence of these conditions might influence the frequency of NDE. Fault Discovery and Intervention: Although the task is primarily a material condition assessment, the information it provides is predictive of future deterioration. For this reason, it is beneficial to perform the task each outage to provide a continuous assessment of condition. There is not much scope for changing this interval except in the mildest conditions where plant history has repeatedly shown that degradation only slight at the suggested interval. NDE Inspection could include the following: · Eddy current · Ultrasonic thickness · Borescope Waterbox Inspection: EPRI TR-106857-V34 Note 2.3.3 Waterbox Inspection Failure Locations and Causes: The Waterbox Inspection is focused Waterbox Inspectionon detecting the extent of tube erosion, corrosion, fouling, scaling, and tube defects and cracking, and also on the detection of corrosion at the tube sheet and rolled tube joints. The task is essential for predictively identifying precursors to catastrophic or more expensive failures. The Waterbox Inspection will include leak testing (a pressure test), primarily to detect defects in tube joints. On-line leak detection (trace gas injection) is more likely to detect tubing cracking and tube defects than to detect defects in tube joints. Progression of Degradation to Failure: The corrosion and fouling processes of various kinds are all quite common in the industry and sometimes represent chronic conditions, or otherwise initiate randomly, often progressing rapidly. Although the deterioration is often erratic, the task does provide predictive information that can be used to adjust the cleaning interval. Fault Discovery and Intervention: The Waterbox Inspection is recommended to be performed at each refueling outage. There is not much scope for changing this interval except in the mildest conditions where plant history has repeatedly shown that degradation only slight at the suggested interval. Waterbox Inspection should include the following: · Inspect for evidence of erosion, corrosion, and cracks. · Inspect for presence of fouling. · Inspect the cathodic protection system for damage to anodes and supports; ensure proper settings and operation of impressed and sacrificial systems. · Perform a borescope examination on a representative sample of tubes. · Inspect o-rings for evidence of damage and deterioration. · Verify tube plugging map. · Determine the degree and type of fouling to adjust the cleaning interval. · Inspect waterbox and tube sheet liners and coatings. · If installed, inspect tube sleeve condition for evidence of wear, looseness, and

76

damage · Perform leak testing to look for evidence of tube leaks. Steam Side Inspection (2): EPRI TR-106857-V34 Note 2.3.4 Steam Side Inspection Failure Locations and Causes: This task focuses on the detection of cracks in structural hardware and in welds associated with internal devices such as penetration baffles, tube support plates, baffle plates, diffuser shields, and feed heater supports. In addition, it is possible to examine a limited number of condenser tubes and the spray piping for external erosion and cracking. Progression of Degradation to Failure: Most of the structural elements tend to be failure free for many years but welds in penetration baffles are subject to cracking at random times, and tube erosion and cracking is also likely to occur randomly. Fault Discovery and Intervention: The Hotwell Inspection will normally be performed each refueling outage at the same time as the Waterbox Inspection. There is not much scope for changing this interval except in the mildest conditions where plant history has repeatedly shown that degradation only slight at the suggested interval. Hotwell Inspection should include the following: · Inspect for presence of foreign materials and general cleanliness. · Inspect for evidence of erosion, corrosion, cracks, and weld failures of all internals and tubes. · Inspect for evidence of steam/fluid flow erosion. · Inspect condensate pit screening for looseness. · Inspect baffles for cracks and evidence of failure. · Inspect for loose, damaged , and missing tube stakes. · Inspect expansion joint and shield for wear and damage. · Inspect extraction steam expansion joints and piping shrouds for cracks. Cleaning (3): EPRI TR-106857-V34 Aplication Note 2.3.5 Cleaning Failure Locations and Causes: The primary objective of Cleaning is to remove corrosion, fouling and scaling material from the inner surface and out of the tubes so as to bring heat transfer performance back to specification. This is the only preventive task that prevents corrosion or slows its progression, maintains tube reliability, and extends the life of the tubes. Progression of Degradation to Failure: The corrosion, scaling, and fouling processes of various kinds are all quite common in the industry and sometimes represent chronic conditions, or otherwise initiate randomly, often progressing rapidly. Fault Discovery and Intervention: If cleaning is not performed regularly, as determined from plant experience, fouling and scaling advance to the point where it becomes essentially unmanageable and physically very difficult to remove. The recommended interval is AR in the Template because the appropriate schedule is very dependent on local conditions. The interval is less than 2 years for a significant fraction of plants, but may be longer in some cases. Cleaning should include the following: · Evaluate the type and degree of performance degradation and type of fouling. · Determine the appropriate cleaning method that provides the best results and limits damage to the condenser heat transfer materials. Current available options are: · mechanical devices (e.g. metal scrapers plastic scrapers, and nylon brushes) · hydrolasing · chemical cleaning · on-line cleaning Main Turbine Expansion Joint Replacement: Main Turbine Expansion Joint Replacement: The replacement period for the main Turbine Expansion Joints shall be in accordance with manufacturer’s recommended service life. The replacement period may be extended based upon station experience and the results of inspections and durometer readings. Circulating Water Piping Expansion Joint Inspection: No Basis At This Time Circulating Water Piping Expansion Joint Replacement: The replacement period for the Circulating Water Piping Expansion Joints shall be in accordance with manufacturer’s recommended service life. The replacement period may be extended based upon station experience and the results of inspections Chemical Feed Equipment Monitoring (4): EPRI TR-106857-V34 Application Note 2.3.6 Chemistry Monitoring, Chemical Treatment, Cathodic Protection, and Operator Rounds. Chemistry Monitoring, Chemical Treatment, and Cathodic Protection are considered to be important but routine activities in operations and maintenance of cooling systems in general, and do not require special discussion for condensers. That is, they are not considered to be specifically condenser PM tasks. Nevertheless, they are included in Table 3.1 for completeness. The interaction between Chemical Treatment and the plant specific service conditions means that the Chemical Treatment’s applied and their frequencies can influence the other tasks in the Template. Operator Rounds is included in Tables 3.1 and 3.2 as a PM task although it is performed essentially continuously so that it does not appear as a task with an interval in the Template. Operator Rounds may included such activities as detecting external leaks and monitoring operational parameters such as DT and DP, turbine back pressure, and air removal rate.

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Manual Valves Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe

X X

X

6

7

8

X

X

X

X

X X

X

Mild

5

X X

X

X X

X

X

X

X

Condition Monitoring Task

Assess integrety of valve internals nonintrusively by evaluation of stem free play, seat leakage, etc. (if possible), or through disassembly and inspection.

4Y 6Y 6Y 10Y 8Y 10Y 10Y 12Y

Time Directed Task

Failure Codes

Comments

CO DA DF ER LC ST

This task does not apply to valves that are classified as Run-to-Failure. Internal inspections are to be performed on valves in raw water systems. These include, but are not limited to butterfly valves that contain internal elastomers and/or taper pin connections between the shaft and disc. Also, gate valves that have carbon steel internals. When components are opened for internal inspection, visually inspect internals for corrosion, erosion, cracking, wear, pitting, MIC, clams, or other abnormalities. During internal valve inspections, the connecting piping should receive a similar condition assessment.

Failure Codes

Comments

Clean and lube stem, lube gearbox and remote linkage (as required), stroke valve, adjust packing. Externally inspect valve for evidence of leakage, corrosion, loose fastners, etc.

CO DA FG 4Y 6Y 6Y 10Y 8Y 10Y 10Y 12Y LB LC SL SM

Replace process diaphragm, adjust stroke (diaphragm valves)

*

*

*

*

*

*

*

*

Surveillance Task

No Comments

FG LD RD SL

* Frequency determined per NDIT MSD-94-408 (elastomer Guideline)

Failure Codes

Comments

Full stroke valve to verify operation N/A 2Y N/A 4Y N/A 6Y N/A 8Y LC PL SK No Comments MA-AA-716-210- 2.18 Pre-selected Nulls – Groups of components classified as not requiring Time Directed PM, Condition Monitoring PM, or Surveillance based upon their significance. Examples include equipment vents and drains, manual valves less than or equal to 2” nominal pipe diameter (other than diaphragm valves), root valves to instruments and by-pass valves used to equalize pressure across process lines or other excluded equipment noted on the PCM templates. All components within a group designated as a Pre-selected Null are classified as Run-to-Failure. This template is the controlled revision. SME Summary Condition Monitoring Task added to assess the integrety of the valve internals. Boundary Definition No Boundary Definition Available At This Time Basis For Template Tasks Assess integrety of valve internals non-intrusively by evaluation of stem free play, seat leakage, etc. (if possible), or through disassembly and inspection.: Valve failures have occurred due to corrosion and wear of carbon steel discs and lack of internal inspections of manually operated valves. Inspection frequency for valves containing elastomers shall be based on the Elastomer Evaluation Guide. Initial inspection for valves with either taper pin connections between shaft and disc, or carbon steel internals in raw water service should occur after ten years of service. Degradation rates for valves in such applications vary, and site experience should be utilized to adjust the inspection frequencies accordinbgly. Assessment of the connecting piping will identify any long term aging effects that require evaluation for corrective action. Clean and lube stem, lube gearbox and remote linkage (as required), stroke valve, adjust packing. Externally inspect valve for evidence of leakage, corrosion, loose fastners, etc.: No Basis At This Time Replace process diaphragm, adjust stroke (diaphragm valves): No Basis At This Time Full stroke valve to verify operation: No Basis At This Time

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Motor Operated Valves (Non GL 96-05 or EQ valves) Component Classification Categories 1 Critical Duty Cycle Service Condition

Yes

X

2

3

4

X

X

X

No High

X

Low Severe Mild

X X

X

5

6

7

8

X

X

X

X

X X

X

X X

X

X

X X

X X

X

Condition Monitoring Task

Failure Codes

Comments

Static Diagnostic Test

AR AR AR AR AR AR AR AR

DF GW LS SB SM ST TS

Diagnostics may be utilized to optimize the setup of important Balance of Plant Valves.

Motor Power Testing

AR AR AR AR AR AR AR AR

DF LS MB SB SM TS

May be performed in conjunction with Actuator Inspection or on a stand alone basis.

Time Directed Task

Actuator Inspection

(1) (1) (2) (2) 12Y 12Y 12Y 12Y

Failure Codes

Comments

CN DA LC MS PL SM

Actuator Inspection should include: main gearbox grease inspection, limit switch compartment and limit switch grease inspection, stem lube, packing retorque and actuator/valve general mechanical condition inspection. Motor Power testing may be performed as part of this task to assess electrical condition.

Stem Lube

(3) (3) (4) (4) (3) (3) (4) (4)

DA SB

Lubrication of the stem between Actuator Inspections is not a requirement, however, may be considered in some harsh applications. Accessible portions of the stem should be cleaned and lubricated.

Actuator Overhaul

AR AR AR AR AR AR AR AR

BK BS CH CO GW LC SM

Actuator overhaul should be scheduled as corrective maintenance based on results of the actuator inspection.

Inspections are to be performed on certain valves in raw water systems. These include butterfly valves that contain internal elastomers and/or have a taper pin AL BK LB PB Valve Internal Inspection / Overhaul AR AR AR AR AR AR AR AR connection between the shaft and disc. Also, PR RD SK gate valves that have carbon steel internals in raw water service. See NOTE 5. Internal inspections on other valve types shall be considered corrective maintenance. (1) Initial frequency should be set at the equivalent of 1 Refuel cycle longer than the longest PM interval for the GL 96-05 valve population. For a station on an 18 month cycle that has a maximum GL 96-05 actuator PM interval of 54 months (or 3RFO), the initial recommended interval would be 72 months or 4RFO. For a station on a 24 month cycle that has a maximum GL 96-05 actuator PM interval of 120 months (or 5RFO), the initial recommended interval would be 144 months or 6 RFO. . (2) Initial interval should be set at the equivalent of 2 Refuel cycles longer than the longest PM interval for the GL 96-05 population. The maximum interval for any station is set at 12 years. . (3) If a stand alone stem lube is performed due to severe service conditions, the initial interval should be one half of the corresponding Actuator Inspection. . (4) Same as Actuator PM. . NOTE 1: "Critical" valves are defined as those valves that if they failed to operate would be repaired on an expedited basis. "Critical" valves are those which are required to remotely reposition to place in/remove from service redundant or alternate trains of equipment or components, valves which could adversly effect power operation, power ascention, start of an outage or constitute a Maintenance Rule functional failure. "Non Critical" are valves that if they failed could be repaired in the next scheduled system or unit outage. A Run to Failure evaluation should be performed on all "Non Critical" valves. . NOTE 2: "High Duty Cycle" is defined as valves in modulating service, stroked under differential pressure more than once a quarter or stroked under static conditions more than once a week. . NOTE 3: "Severe Service Condition" is defined as being in an ambient temperature condition > 120 degrees F. or installed in a fluid medium > 400 degrees F. Other conditions such as corrosive, salt, spray, steam, high vibration or unclean process medium should be considered. . NOTE 4: MOVs that are in the GL 96-05 program are subject to the maintenance and testing requirements of the program per ER-AA-300.

79

. NOTE 5: Inspection frequency for valves containing elastomers shall be based on Elastomer Evaluation Guide NES-MS-06.17. Initial inspection frequency for valves with taper pin shaft / disc connections or carbon steel internals in raw water systems should occur after 10 years of service. Degradation rates for valves in this application vary greatly and site experience should be utilized to adjust this frequency accordingly. . NOTE 6: Service and operating conditions for MOVs vary greatly and shorter intervals may be established based on station maintenance history and industry operating experience. The Station MOV Program Engineer should review the need for establishing shorter intervals. This template is the controlled revision. Please refer to MA-AA-716-210 & MA-AA-716-210-1001 for additional guidance. SME Summary The SME approach is based on a combination of EPRI guidance and extensive experience acquired through the implementation of IEB 8503, GL 89-10 and GL 96-05 programs. Detailed guidance for GL 96-05 Program valves is contained in ER-AA-300 and associated documents. The basic strategy for valves outside the MOV Program is that GL 96-05 valves are permitted to have PM / Test intervals of up to 10 years and non-progam valves, which by definition have no safety function, as a group should not be maintained on a more frequent basis. Motor Power Testing is encouraged to assess the performance of the motor and valve / actuator assembly as an important predictive tool. Static diagnostic testing should be utilized to improve critical valve performance and to diagnose / setup important or problematic valves. Boundary Definition The boundary of an MOV for the purpose of this database is defined to include the MOV’s actuator and valve body assembly, and their accessories, as follows: Actuator: · Gear box · Switches (Limit and Torque) · Motor (not including motor power feed and control ) · Hand wheel · Wiring (internal to the operator) · Spring pack Valve Body · Guides · Packing · Seat · Stem / stem nut Basis For Template Tasks Static Diagnostic Test: Use of diagnostics for troubleshooting or to optimize the MOV performance on important valves is considered a good practice. Output thrust, torque, motor current and switch actuation points can be specifically monitored to assess the overall health of the MOV. Motor Power Testing: Obtaining Motor Diagnostics in conjunction with the Preventive Maintenance task is considered to be a good practice to assess the condition of the motor power circuit. Actuator Inspection: permits licensees to establish their own verification schedule for the condition of the lubricant. The recommended initial intervals has been made in the light of GL 96-05 inspection results and other utility experience. . Stem Lube: provides guidance on periodic maintenance and stem lubrication intervals Actuator Overhaul: The detailed inspection of the actuator requires essentially complete disassembly of all actuator and drive train subcomponents to the hardware level. This is equivalent to a refurbishment. Refurbishments are considered corrective maintenance and will be performed based on actuator inspection results. Valve Internal Inspection / Overhaul: Elastomer Evaluation Guide

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Positive Displacement Pumps Component Classification Categories 1 Yes

Critical Duty Cycle

X

2

3

4

X

X

X

No High

Service Condition

X

Low Severe

X X

X

6

7

8

X

X

X

X

X X

X

Mild

5

X X

X

X

X X

X X

X

Condition Monitoring Task

Failure Codes

Comments Reference EPRI PM Basis Database

Operator Rounds

1S 1S

Vibration Analysis

1M 1M

BS

Reference EPRI PM Basis Database

Performance Monitoring

3M 3M

OC

Reference EPRI PM Basis Database

Oil Analysis

6M 6M

CO DA ER MS

Reference EPRI PM Basis Database

Thermography

6M 6M

Reference EPRI PM Basis Database

Time Directed Task

Failure Codes

Comments

Oil Filter Replacement

6M 6M

DA FL OR

Reference EPRI PM Basis Database

Coupling Inspection

2Y 2Y

FD GL GW OC

Reference EPRI PM Basis Database

Internal Visual Inspection

2Y 2Y

Power End (Frame) Inspection

6Y 6Y

FD GL GW LC OC SL

Reference EPRI PM Basis Database

Fluid Cylinder Inspection

AR AR

DA ER GL LC OC PL SC SL

Reference EPRI PM Basis Database

Failure Codes

Comments

FD GL GW LC OC SC SL

Surveillance Task

Reference EPRI PM Basis Database

Functional Tests AR AR OC No Comment The shaded area indicates that no examples of positive displacement pumps were identified for these Template conditions. If a station were to identify a positive displacement pump that corresponded to a column in the shaded area, it would be necessary to develope a PM program, probably similar to those stated. The shaded area does not mean Run-To Failure. Some Positive Displacement Pumps are covered by other PCM templates (i.e., GE - Main Turbine EHC template covers EHC pumps, Fairbanks Morse Diesel template covers prelube pumps, etc...). This template is the controlled revision. Please refer to MA-AA-716-210 & MA-AA-716-210-1001 for additional guidance. SME Summary The following list of equipment was utilized by the expert panel to describe the typical boundary of a positive displacement pump. · · · · · · · ·

Pump, power end and fluid cylinder Suction Stabilizer Discharge Dampener Pump coupling Pump gear reducer Oil cooler heat exchanger Oil filters, if present Packing coolant/lubrication piping and supply tank

The expert group identified the most common, i.e. dominant, failure locations and mechanisms for this equipment to be: · · · ·

Packing leaks Damaged valve assemblies Damaged oil delivery components Cracked fluid cylinders

Industry References: 1. “Centrifugal and Positive Displacement Charging Pump Maintenance Guide”, EPRI (NMAC) TR-107252, October 1997. 2. EPRI PM Basis, Version 5.0 (4/30/03) 3. NRC Information Notice 94-29, “Charging Pump Trip During a Loss-of-Coolant Event caused by Low Suction Pressure”. 4. ASME OM Code-1995, “Code for Operation and Maintenance of Nuclear Power Plants”, Subsection ISTB, Part 6 - “Inservice Testing of Pumps in Light-Water Reactor Plants”.

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This template was last revised in January of 2004 to address user comments and incorporate the lastest recommendations for positive displacement pump preventative maintenance offered by EPRI in the PM Basis Database (see Industry References above) Boundary Definition The following list of equipment was utilized by the expert panel to describe the typical boundary of a positive displacement pump. · Pump, power end and fluid cylinder · Suction Stabilizer · Discharge Dampener · Pump coupling · Pump gear reducer · Oil cooler heat exchanger · Oil filters, if present · Packing coolant/lubrication piping and supply tank Basis For Template Tasks Operator Rounds: Operator Rounds Task Objective: Operator Rounds is focused on the observation of leaks, unusual noises, and loose, missing, or damaged components. Daily observation is effective for the large number of random degradation mechanisms addressed by the task. Task Content: Look for leaks of water or oil, any obviously loose, missing, or damaged fasteners and hardware, and listen for unusual noises. Verify that the oil delivery system and packing cooling system are operating within normal limits. Failure Locations and Causes: Operator Rounds provide a frequent opportunity to observe leaks of water or oil, to take account of unusual noises, and to observe any obviously loose, missing, or damaged fasteners and hardware. It also provides an opportunity to verify that the oil delivery system and packing cooling system are operating within normal limits. Progression of Degradation to Failure: A large number of these degradation mechanisms are random, and occur commonly. Fault Discovery and Intervention: The task is performed at least once per day. Vibration Analysis: Vibration Analysis Task Objective: This task mainly addresses the condition of couplings. The intervals are not directly determined by the failure mode data but many random mechanisms are addressed. Failure Locations and Causes: Vibration Analysis can be effective for detecting distorted and cracked shims in couplings, grid type coupling wear, and gear type coupling degradation. Progression of Degradation to Failure: Most of the protected degradation mechanisms are random. Fault Discovery and Intervention: The task should be moderately effective because the frequencies differ from pump vibrations which would otherwise predominate. Performance Monitoring: Performance Monitoring Task Objective: Performance Monitoring mainly addresses cracking and wear of the inlet (suction) and outlet (discharge) valves, valve seats and springs, and cracking of the fluid cylinder. The interval is strongly determined by the presence of commonly occurring wearout and random failure modes. Task Content: Performance Monitoring should include: * Measure and trend pump speed, suction and discharge pressures, and flow. Compare to previous values. Look for jagged response of valves during the pressure discharge test. * Note abnormal noises. * Inspect for oil and water leaks. * If visible, verify that the oil level is correct and that the oil is not discolored or "milky". * Verify that the oil temperatures and pressures are within specifications. * Verify that the packing coolant temperature is within specification and that the level of the supply tank is correct. Failure Locations and Causes: Performance Monitoring mainly addresses cracking and wear of the inlet (suction) and outlet (discharge) valves, valve seats and springs, and cracking of the fluid cylinder. Worn valve guides may also be detected but these are only likely to be common occurrences in specific applications. Progression of Degradation to Failure: All of the important mechanisms, except for worn valve guides, addressed by performance monitoring are significant because they have predominantly random or short term occurrence times on a scale of a few months to a few years, and they are relatively common events. Although all of them have the possibility of being detected by additional tasks, these characteristics suggest frequent performance trending would be beneficial. Fault Discovery and Intervention: The recommended interval for Performance Monitoring is 3 months. Even more frequent performance monitoring (i.e. weekly) would be needed to have a good chance of completely avoiding valve degradation. Because of the possibility of rapid valve degradation, this task may not avoid the necessity for taking a mid-cycle outage to repair the valves, when dependent upon a single pump, regardless of the interval at which it is performed. After refurbishment a typical value of efficiency is 95%, whereas valve replacement is indicated when the efficiency has fallen to around 87% (at least for Union model QX-300 Quintuplex). Oil Analysis: Oil Analysis Task Objective: This task is focused on detecting wear particles or other contaminants in the oil, and on oil quality. The interval is not determined very closely by the failure mode data. Failure Locations and Causes: Oil analysis is focused on processes that result in wear particles or other contaminants entering the oil and on degradation of the lubricating properties of the oil. This primarily addresses wear and scoring of the cross-head to cross-head surfaces and asymmetric wear of the main gear and pinion teeth, as well as deterioration of bearing oil seals, and wear of the oil pump, drive chain and sprockets in a pressure lubricated system. Wear of the crosshead pin and bearing, main crankshaft bearings, connecting rod bearings, pinion shaft and bearing, and thrust bearing, can also be detected. Progression of Degradation to Failure: Seal leakage, and sources of bearing and gear wear, are relatively common problems. Normal seal wear is expected over a period of 6 months to 1 year in service. Bearing wear and gear wear have timing aspects more coupled to the occurrence of random failures of the oil delivery system or other random events such as misalignment or cavitation, than to intrinsic wear rates through normal aging. This suggests that oil sampling should be more frequent than these random events which appear to occur over a time scale of a few years. There are no failure locations and causes for which oil analysis is the only PM task available but it is the most frequently implemented task for the above failure causes. Fault Discovery and Intervention: The expert group recommended oil analysis every six months for continuously running or alternated critical pumps. This assumes that analysis and evaluation are carried out in timely manner. Thermography: Thermography Task Objective: This task is focused on the detection of hot spots. The intervals are not directly determined by the failure mode data but many random mechanisms are addressed. Failure Locations and Causes: Thermography will detect hot spots which cause cylinder damage and degradation of packing cooling. Progression of Degradation to Failure: Most of the protected degradation mechanisms are random. Fault Discovery and Intervention: The task should be moderately effective whenever a direct view can be obtained.

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Oil Filter Replacement: Oil Filter Replacement Task Objective: This task is focused on clogging of the oil filter and contamination of the lubricant. The interval is not strongly determined by the failure mode data. Task Content: Oil Filter Replacement should include the following: * Check for leaks. * Verify proper operation. * Check DP across the filter and trend to provide a basis for interval extension. * Note condition of all components especially the filter and oil piping. Failure Locations and Causes: This task focuses entirely on the condition of the lubrication system. Items to observe are a clogged oil filter and contamination of the lubricant. Progression of Degradation to Failure: The key task is changing the oil filter. Clogged filters are expected after a period of 2 to 5 years of continuous operation, and trends in oil pressure may give indication of progressive clogging. Although contamination of the oil can occur at any time, oil sampling will give advanced warning at a 6 month interval. Fault Discovery and Intervention: Filter replacement is recommended as a scheduled task at 6 months for continuously operating or alternated pumps. Coupling Inspection: Coupling Inspection Task Objective: This task is focused entirely on inspection of the coupling. The task interval is not strongly determined by the failure mode data. Task Content: Coupling Inspection should contain the following: * Inspect for signs of leaking lubricant. * Inspect mating surfaces for cleanliness, wear, and integrity; Record as-found and as-left conditions. * Verify condition of lubricant looking for dirt, amount of lubricant, and indications of coupling wear; recharge with the proper lubricant and quantity. * Inspect gear teeth or shim packs for wear and damage. * Inspect non-metallic parts for condition and wear. * Inspect bolting for damage. * Ensure proper orientation during reassembly. * Perform an as-found / as-left alignment check. Failure Locations and Causes: As the name implies this task is focused entirely on inspection for lubrication leaks and wear of the flexible grid type and geared type of pump/motor couplings, and on distortion or cracking of the shims on the shim pack types. Progression of Degradation to Failure: Insufficient or improper lubrication and installation errors are more important to the timing of this task than normal wear. These sources of degradation can cause rapid deterioration at random times, usually with occurrence times on a scale of a few years. Fault Discovery and Intervention: Continuously operating critical pumps are recommended to have a coupling inspection at 2 years regardless of whether they run continuously or are alternated. Vibration monitoring will not give useful information on alignment or coupling wear because of the high intrinsic vibration levels with these pumps. Thermography would provide indication of a coupling running hot, but was not thought to be sufficiently applicable and cost-effective for inclusion in the PM program as a regularly scheduled task. Internal Visual Inspection: Internal Visual Inspection Task Objective: The main objectives of this task are to assess the condition of the oil pump drive chain and sprockets, the thrust bearing, main gear and pinion, and gaskets that are visible. The interval is not clearly determined by the failure mode data. Task Content: Internal Visual Inspection should include: * Before Shutting down the operating pump, verify that the oil temperatures and pressures are within specifications. * Inspect for obvious loose, missing, or damaged fasteners. * Note abnormal noises. * Inspect for oil and water leaks. * If visible, verify that the oil level is correct and that the oil is not discolored or "milky". * Verify that the packing coolant temperature is within specification and that the level of the supply tank is correct. * Perform a visual axial alignment inspection of the crank shaft. * Check tension and evidence of wear on oil pump drive chain and sprockets. * Inspect the integrity of oil lines, fittings, and mounting hardware. * Inspect the bull gear and pinion teeth for damage and abnormal wear. * Look for the presence of metallic fines in the oil reservoir. * Inspect for signs of leaking lubricant. * Inspect mating surfaces for cleanliness, wear, and integrity; Record as-found and as-left conditions. * Verify condition of lubricant looking for dirt, amount of lubricant, and indications of coupling wear; recharge with the proper lubricant and quantity. * Inspect gear teeth or shim packs for wear and damage. * Inspect non-metallic parts for condition and wear. * Inspect bolting for damage. * Ensure proper orientation during reassembly. * Perform an as-found / as-left alignment check. Failure Locations and Causes: Internal Visual Inspection is an internal inspection performed when the power end large inspection cover has been removed. The main objectives of this task are to assess the condition of the oil pump drive chain and sprockets, and the tightness of the oil pump mounting bracket in a pressure lubricated system, as well as to assess the condition of the thrust bearing, main gear and pinion, and gaskets that are visible. Progression of Degradation to Failure: The most time-critical of these degradation mechanisms is the condition of the oil pump drive chain and sprockets in a pressure lubricated system, and the degree of asymmetric wear on the main gear. Fault Discovery and Intervention: This task provides assurance that the Power End Inspection can be reached at 6 years without undue wear on the above components. The Expert Panel thought that a 2 year interval for the Internal Visual Inspection would provide this assurance in a cost-effective manner. Power End (Frame) Inspection: Power End (Frame) Inspection Task Objective: This task focuses principally on the condition of the oil delivery system and the components that depend on it. The interval may offer some opportunity for increase in some circumstances, especially if oil analysis is effective and reliable. Task Content: The Power End (Frame) Inspection should include: * Utilities may wish to consider performing the Fluid Cylinder Inspection at this time. * Look for the general condition of all components, signs of leakage, loose, missing, or damaged fasteners, oil supply lines, fittings, and hardware. * Perform all dimensional measurements and compare to OEM specifications. * Inspect crosshead pin and bearings for proper finish and evidence of wear. * Inspect the main crank shaft bearings and connecting rod bearings for evidence of wear. * Measure pinion to main gear backlash and compare to OEM specifications. * Inspect pinion gear and main gear for evidence of damage, cracking, scoring, pitting, or wear. * Inspect pinion shaft and bearings for evidence of wear. * If present, inspect the internal oil pump, drive chain and sprockets for evidence of wear; replace as necessary. * Inspect the integrity of the oil pump mounting bracket and hardware. * Measure the crank shaft thrust (end play) and compare to OEM specifications. * Inspect the thrust bearing for evidence of wear. * Inspect connecting rods for damage; oil holes should be free, open and of uniform diameter. * Inspect gasket surfaces for damage; replace all gaskets that were removed, disturbed, leaking, or damaged. * Perform a crank shaft inspection. * If there is evidence of packing leaks or scoring of the plunger or stub; verify the concentricity of crosshead and stub. * Inspect crosshead stub for evidence of damage. * Inspect crossheads for evidence of wear and scoring. * Inspect the crankcase breather and clean or replace as necessary. Failure Locations and Causes: This task focuses principally on the condition of the oil delivery system: oil pump, drive chain, and sprockets in a pressure lubricated system, or the gear driven external oil pump. Other important components addressed are the crosshead, including the crosshead to stub fit, bearings, crankshaft, gears, gaskets, and the oil heat exchanger, if present.. Progression of Degradation to Failure: Failures or deterioration of the oil delivery system are one of the dominant degradation mechanisms for these pumps, and lead to rapid deterioration in the other components examined in this inspection. Although the oil pumps may be expected to perform well for periods of up to 10 to 12 years from the perspective of normal wear and aging, random failures caused by improper assembly or poor lubricant quality may shorten this time to 5 to 6 years. In a pressure lubricated system the drive chain and sprockets appear to wear significantly faster than the pump so that these two components might be replaced at each Power End Inspection with the pump replaced at every other inspection. The oil heat exchanger, when present, does not appear to be the source of many failures, but oil heat exchangers in general are subject to random causes of leaks and fouling on a time scale of 5 to 10 years. The crosshead, bearings, crankshaft, and gears generally have lifetimes from normal wear in the upper part of the above range (8 to 10 years), but suffer in addition from random effects of poor lubrication, misalignment, incorrect assembly, and system dynamic effects related to hydraulic shock. Fault Discovery and Intervention: A task interval of 6 years adequately addresses the above

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failure mechanisms. Oil Sampling and the Internal Visual Inspection provide reasonable assurance of avoiding failures from random effects at earlier times. Fluid Cylinder Inspection: Fluid Cylinder Inspection Task Objective: The Fluid Cylinder Inspection provides an opportunity to inspect and repair cylinder head check valves, leaks from oil seals, leaks from packing, and cracked fluid cylinders, and to inspect the integrity of the packing cooling/lubricating system. The failure mode data clearly suggest that this task should be done on a time scale of one year or less. Task Content: Fluid Cylinder Inspection should include the following: * Look for the general condition of all components, signs of leakage, and loose, missing, or damaged fasteners. * Inspect for evidence of cylinder cracking. * Inspect the condition of all valve assemblies looking for evidence of wear and damage. * Inspect all gasket sealing surfaces; replace any damaged or leaking gaskets. * Drain coolant tank and ensure coolant flows freely, that the tank is free of debris, and does not leak. * Inspect packing cooling lines for leaks and damage. * Depressurize the pulsation stabilizing equipment, if applicable, and check that the pre-charge pressure is correct. * Inspect oil seals for evidence of leakage or damage; replace if necessary. * Inspect the condition of the crosshead stubs for evidence of wear, misalignment, and scoring. * Inspect for evidence of excessive packing leakage; if packing is replaced, inspect the stuffing box and plunger for evidence of abnormal wear and scoring. * If packing is not being replaced, inspect all visible parts of the plunger assembly without removing it. Failure Locations and Causes: The Fluid Cylinder Inspection provides an opportunity to inspect and repair cylinder head check valves, leaks from oil seals, leaks from packing, and cracked fluid cylinders, and to inspect the integrity of the packing cooling/lubricating system. This is an on-condition task which may be triggered by observation of leaks during operator rounds, by audible noise and results of performance monitoring with respect to worn or broken valves, and by leakage, performance monitoring, or loss of fluid inventory in the case of a cracked fluid cylinder. Progression of Degradation to Failure: Oil seals appear to have an expected life of about 6 months to one year, and inlet and outlet valves frequently fail over a period of several months to two years from a number of random causes, even though the disks and seats may have a normal life of about two years. Fluid cylinder cracks have occurred at several plants after in-service times of a few years, occasionally as soon as 1 year. Packing ages on a timescale of one year or longer (or possibly even less than 1 year for original braided packing) and leakage can be expected on a similar timescale. Wear of the inner bore of the stuffing box may be expected after a few years. Many random processes also contribute to packing and plunger wear so that the timing of packing leaks and associated damage to the stuffing box and plunger are essentially random on a scale of a few years. The packing cooling system is similarly affected by random failures. Fault Discovery and Intervention: The above degradation mechanisms and time scales suggest that the Fluid Cylinder Inspection is likely to be required after 1 year of operation. As discussed in Section 2.3.2, the deterioration rate of inlet and outlet valves is sufficiently rapid after onset, and the predictive capability of Performance Monitoring is sufficiently weak, that positive displacement pump outages in order to perform the Fluid Cylinder Inspection, may not be avoidable between refueling cycles unless a redundant pump is available. When a redundant pump is not available consideration should be given to scheduling the Fluid Cylinder Inspection as a time-directed task with an interval less than 6 years. Carrying out the Performance Monitoring task more frequently (perhaps weekly) does not avoid the problem. If good performance of packing, valves, and oil seals enables the Fluid Cylinder Inspection to be done only every 3 to 6 years, the valves, oil seals, plunger, and oil pump (if external) should be replaced regardless of condition, especially if a redundant pump is not available. Functional Tests: Functional Tests The functional test is a pump speed - flow correlation essentially equivalent to one part of performance monitoring, and only performed as part of a surveillance test for Class 1E pumps.

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Power Supplies Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe

X X

X

6

7

8

X

X

X

X

X X

X

Mild

5

X X

X

X X

X

X

X

X

Condition Monitoring Task

Failure Codes Comments

Check output voltage and, if applicable, AC current ripple.

18M 18M 18M 18M 3Y

3Y

5Y 5Y

CD OC OP

Adjust output Voltage as necessary.Replace power supply or output capacitors if ripple is out of specifications. If there is no visual indication or alarm to alert users that a power supply has failed, critical power supplies should be monitored more frequently

Record Power Supply Case Temperature

6M 6M 6M

1Y

1Y 1Y

OC

Monitor Power Supply Operating Temperature and trend versus expected life curve (Reference EPRI TR-112175 ).

6M

1Y

Time Directed Task

Failure Codes Comments

Perform visual inspection and cleaning 18M 18M 18M 18M 3Y

3Y

5Y 5Y

DA MS

Look for damaged/loose connections, signs of overheating or corrosion. Fuse holders carrying input/output current should also be checked. If applicable,verify cooling fans are providing adequate cooling.

Check auctioneering (only for circuits with redundant power supplies)

18M 18M 18M 18M 3Y

3Y

5Y 5Y

CD

Either remove fuse or adjust power supply output such that the redundant power supply takes the load.

Check overvoltage protection circuit*

18M 18M 18M 18M 3Y

3Y

5Y 5Y

CD

Perform this step only if the power supply has a resetable overvoltage protection circuit.

Check Line and Load Regulation*

18M 18M 18M 18M 3Y

3Y

5Y 5Y

CD

Perform on power supplies that power more than one instrument loop.

EL

Reforms electrolytic capacitor. Will prevent early failures when power supply is installed. Perform visual inspection,soft start**,and 1 hour burnin prior to installation in plant. Soft start should be performed in accordance with instructions provided in EPRI TR112175. AR - As Required (test before installing).

Energize spare power supplies

5Y

5Y

AR

AR

Replace all electrolytic capacitors or entire power supply

5Y

5Y 7.5Y 7.5Y 7.5Y 7.5Y 10Y 10Y AG EL

For Auctioneered power supplies in mild environments, these frequencies may be extended by alternating which power supply carries the load. Set the output of one power supply (primary) slightly higher than the redundant supply (backup). At the next required maintenance check, adjust the voltage on the power supplies so that the output voltage on the power supply which was the backup for the previous cycle is slightly higher than the voltage on the power supply that was the primary on the previous cycle. During the cycle that a power supply is a backup, current is at a minimum and heating of the electrolytic capacitors is reduced. Since temperature is a major factor in capacitor degredation, the expected life of the capacitor should be increased.

Replace input/output fuses*

5Y

5Y 7.5Y 7.5Y 7.5Y 7.5Y 10Y 10Y AG

Applies to fuses that supply input power or power supply output. Inspect and

85

replace fuse holders if indicated. Replace internal batteries

AR

AR

AR

AR

AR

AR AR AR

AG

Based on manufacturer's recommended battery life (Reference IN 94-02 ).

Perform visual inspection,soft start**, and 1 hour burn-in prior to installation Pre-Service Burn-in AR AR AR AR AR AR AR AR OC in plant. Soft start should be performed in accordance with instructions provided in EPRI TR 112175. * Perform these tasks only on power supplies that, per plant records, have a history of this problem. ** Soft start should only be performed as recommended by the power supply manufacturer due to potential of damaging the unit. This template is the controlled revision. Please refer to MA-AA-716-210 & MA-AA-716-210-1001 for additional guidance. SME Summary Power Supply PCM Template Review Failure Modes Failure modes identified per the above review include the following: · Capacitor were the most frequently identified sub-component failure · Reduced power supply life due to excessive operating temperatures/ inadequate cooling/ loss of cooling was the second leading cause of failure · Internal battery failures were a contributor to power supply loss of function · Semi-conductors (Diodes, transistors, rectifiers) · Voltage drift hi and lo was a contributor to failure · Infantile failure/shelf life failures due to capacitor electrolyte leakage, reforming, voltage shock (versus soft start) · Fuse failures due to fatigue, surges during crow-barring The identified failure modes can be detected through each of the following measurable conditions. Each of these conditions are checked by the PCM specified condition monitoring task except for elevated temperature, which will be added. · · · · ·

Power Power Power Power Power

supply supply supply supply supply

output goes low output goes high output drifts output becomes noisy elevated temperature

Based on the above review, the PCM template currently does not address the following failure modes: 1. Operating temperature concerns ( inadequate cooling, degraded/loss of cooling). 2. Replacement of internal batteries based on vendor recommended service life. 3. Soft start of power supplies that are being energized for periodic reforming of electrolytic, or for burn-in prior to being placed inservice, or post repair. Soft starts can potentially damage some power supplies and should only be performed if recommended by the specific power supply manufacturer. 4. Consideration of shelf life and service life in determining expected end-of-life expectancy for power supplies. RECOMMENDED PCM TEMPLATE CHANGES Review of vendor recommendations is not practical by the Corporate offices because of the shear number power supply vendors and those manuals are only available at the sites. Although the present template is reasonable and conservative, the following changes are recommended to optimize resources, improve PCM results and address minor weaknesses. 1. Increase the time directed task to energize spare power supplies from 1 year to 5 year. This is a more reasonable timeframe based on recent EPRI guidance on capacitors(see reference 2 below). Supply voltage should be applied via a soft start to prevent shock damage to the power supply. 2. Add a new event initiated task “power supply replacement “. Perform a visual inspection, a soft start, and 1 hour burn-in on each power supply pulled from storage prior to installation within a plant system. 3. Add a new condition-monitoring task to perform a temperature check of the power supply chassis using a spot pyrometer or thermography looking for elevated temperature. A trend of operating temperature and comparison with the operating temperature versus capacitor expected life should be used to determine appropriate frequency for capacitor changeout (reference Section 2, page 2-22 of EPRI TR 112175 for graph of capacitor life versus operating temperature). Six (6) months for critical components and twelve (12) months for non-critical. 4. Add a new “as required” task to inspect for and replace internal batteries in accordance with vendor recommendations. 5. Add a note allowing sites which have different fuel cycles to adjust the time duration as necessary. 6.Replacement of fuses: Only one case was noted that a fatigued fuse resulted in a loss of a power supply. This seems insufficient to warrant fuse replacement on such a frequent basis. IMPLEMENTATION The revised PCM template should be implemented and data collected for several fuel cycles. The collected data can then be reviewed for PCM effectiveness and adjusted as necessary. REFERENCES 1. EPRI/NMAC Report TR-107044s: “Instrument Power Supply Tech Note”, December 1996

86

2. EPRI Report TR-112175: “Capacitor Application and Maintenance Guide”, August 1999 3. EPRI Report TR-1001257: “Capacitor Performance Monitoring Report”, December 2000 4. INPO NPRDS component failure search results for failed power supplies. 5. INPO Operating Experience search results for failed power supplies. 6. NRC Information Notice IN 94-24: “Inadequate Maintenance Of Uninterruptible Power Supplies And Inverters”. Boundary Definition No Boundary Definition Available At This Time Basis For Template Tasks Check output voltage and, if applicable, AC current ripple.: No Basis At This Time Record Power Supply Case Temperature: No Basis At This Time Perform visual inspection and cleaning: No Basis At This Time Check auctioneering (only for circuits with redundant power supplies): Auctioneering is considered to be the redundant supply to which the primary tansfers to in the event of a failure. Check overvoltage protection circuit*: No Basis At This Time Check Line and Load Regulation*: No Basis At This Time Energize spare power supplies: No Basis At This Time Replace all electrolytic capacitors or entire power supply: No Basis At This Time Replace input/output fuses*: No Basis At This Time Replace internal batteries: No Basis At This Time Pre-Service Burn-in: No Basis At This Time

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Pressure Relief Valves - Spring Actuated Component Classification Categories 1 Critical Duty Cycle Service Condition

Yes

X

2

3

4

X

X

X

No High

X

Low Severe

X X

X

6

7

8

X

X

X

X

X X

X

Mild

5

X X

X

X X

X

X

X

X

Time Directed Task Set Point Verification

Failure Codes 10Y

10Y

10Y

BK BL BR DB FG NO 10Y OC SL SM

Surveillance Task

Failure Codes

Comments EPRI TR-106857-V18 Application Note 2.3.1 Comments

EPRI TR-106857-V18 Operability Test NR NR NR NR Application Note 2.3.2 This template identifies the recommended PM for all spring actuated relief valves. Shorter time directed set point or operability verification required by the Illnois Department of Nuclear Safety, the ISI program (as indicated by the ASME OM code), ASME Codes (i.e., Section IX) or insurance requirements, Also, operability tests for relief valves per ASME Section I and IV may be employed for time directed activities of less than 10 years, but set point verification should be validated at least every 10 years. This template does not cover pneumatic, solenoid, or hydraulic actuated power operated relief valves even if a portion of the valve provides a spring actuated relieving function. This template may be applied to spring actuated-piloted relief valves. Valves that should not to be set point verified per the manufacture's directions should be replaced in lieu of set point verification. This template is the controlled revision. SME Summary SME Summary for PCM Template "Pressure Relief Valves - Spring Actuated" SME Summary The basis of the template is direct use of EPRI TR-106857-V18 guidance. The Exelon template matches the EPRI template directly and references the notes for "Set Point Verification" and "Operability Test" included in the EPRI guide. These notes have been reproduced below in the Basis For Template Tasks section. The only additions to the EPRI guidance are the specific notes about IDNS, Code, IST, and NEIL requirements that may override the periods indicated on the template. This template has been in effect since November of 1998 in the MWROG (former ComEd plants) and has been effective at assuring proper operation of these type valves. Boundary Definition The boundary of a spring actuated pressure relief valves for the purpose of this database is defined to include the following: · Vent stack · Pressure relief valve body · Connection point to the piping · Nozzle and disk Basis For Template Tasks Set Point Verification: 2.3.1 Set Point Verification Failure Locations and Causes: The Set Point Verification for spring actuated safety relief valves in nuclear power plants is usually a bench test that measures the valve set point value. This is essentially a failure finding task. The main focus of this test is to detect bonding of the disk to nozzle interface (especially with bronze internals exposed to boric acid; otherwise general rusting), binding due to a corroded or bent valve stem or sticking bellows, and changes in the spring constant through the effect of set point memory. Other failure mechanisms such as being out-of-adjustment (e.g. because of failure of the cotter pin or wire retainer on the adjustment nut), corrosion of the valve body, and having misadjusted blowdown rings, loose bolting, or leaking bellows, may also be significant occasionally because of the randomness of occurrence and lack of other means of detection. Progression of Degradation to Failure: The above failure mechanisms have random failure times or failure free periods of a few years that are not substantially longer than the ten year period between scheduled tests. Fault Discovery and Intervention: The Set Point Verification test discovers existing failure conditions, and appears to be scheduled at intervals which in some cases may exceed the expected times to failure, especially where improper materials may be involved, in cases of misapplication, or where the significant factors may be manufacturer and application specific. The 10 year interval is specified by Section XI of the ASME Boiler and Pressure Vessel Code. The alternative of performing an operability test to add confidence that the valves could reach the ten year interval is compromised by the relatively high probability that safety relief valves will fail to reseat after lifting (i.e. without unacceptable leakage). An additional task which is part of Section XI IST requirements is an external visual inspection, quite separate from the set point verification, that is focused on checking for obvious leaks, corrosion and the integrity of bolting. This task provides little assurance, beyond what is accomplished by observations during operator rounds, that the valve will adequately reach the 10 year set point verification. On systems such as Control Air, and Emergency Diesel Starting Air which are continuously needed and difficult to isolate, but which are accessible during power operation, an operability test may be used instead of a set point verification for valves not controlled by the ASME code. If the valve lifts and reseats there is a relatively lower expectation of set point drift beyond tolerance. In such cases the operability test could be scheduled at a 10 year interval. Relief valves on non-critical systems frequently require failures of multiple pressure relief devices in order to fail to relieve pressure, or may be designed as multiple relief valve configurations, and may not have failure to reseat as a critical failure mode, so that the operability test would be a practical option. Set Point Verification should include the following: · Visually inspect

88

for loose, damaged, or missing hardware and parts, or corrosion · Perform set point verification test and compare to historical · Make adjustments as required · If set point verification was required because of leak-through and no seat damage is noted, the pilot valves should then be inspected for damage, wear, and proper operation · Perform a post set point leakage test to verify the valve reseats and holds pressure · Perform a bellow integrity test where applicable · At normal system operational temperature and pressure, verify the valve to be leak free both internally and externally Operability Test: 2.3.2 Operability Test Failure Locations and Causes: The Operability Test is a manual exercise to pop the valve open in place and to observe that it reseats. It mainly addresses the possibility of bonding at the disk to nozzle interface, but also provides an opportunity to visually examine the exterior of the valve at close quarters for leaks, corrosion, and bolting integrity. Progression of Degradation to Failure: This is not a scheduled task and is designated as “Not Recommended” on the Template because of the risk that the valve will not reseat properly. Fault Discovery and Intervention: This task is not recommended except in the following circumstances. On systems such as Control Air, and Emergency Diesel Starting Air which are continuously needed and difficult to isolate, but which are accessible during power operation, an operability test may be used instead of a set point verification for valves not controlled by the ASME code. If the valve lifts and reseats there is little expectation of set point drift beyond tolerance. Relief valves on non-critical systems frequently require failures of multiple pressure relief devices in order to fail to relieve pressure, or may be designed as multiple relief valve configurations, and may not have failure to reseat as a critical failure mode, so that the operability test would be a practical option. Operability Tests should include the following: · Visually inspect for loose, damaged, or missing hardware and parts, or corrosion · Manually actuate valve to verify it is free to lift from its seat and vents · Verify the valve reseats and does not leak internally or externally

89

Rotary Screw Air Compressor Component Classification Categories 1 Critical Duty Cycle Service Condition

Yes

X

2

3

4

X

X

X

No High

X

Low Severe

X X

X

Mild

5

6

7

8

X

X

X

X

X X

X

X X

X

X

X X

X X

X

Condition Monitoring Task

Failure Codes

Comments

Oil Analysis

3M 6M 3M 6M 6M 1Y 6M 2Y

CO DA MS OC

EPRI TR-106857-V15 Application Note 2.3.1

Vibration Analysis

3M 3M 3M 3M 3M 6M 3M 6M

OC

No Comments

Vibration Analysis - Shock Pulse Analysis

6M 6M 6M 6M 6M 1Y 6M 1Y

OC

EPRI TR-106857-V15 Application Note 2.3.3

Operator Rounds

1D 1D 1D 1D 1D 1W 1D 1W XX

Time Directed Task External Visual Inspection

Internal Inspection

Minor Overhaul

Failure Codes AL DA FD FL 1M 3M 1M 3M 1M 3M 1M 3M GL MS NO OC SL

General Note (8) Comments EPRI TR-106857-V15 Application Note 2.3.2 & General Note (2)

1Y 1Y 1Y 1Y 1Y 1Y 1Y 1Y

CO DA FD FL GL GW LC EPRI TR-106857-V15 Application Note 2.3.3 & General Note (3) MS MS OC SL

1Y 1Y 1Y 1Y 1Y 1Y 1Y 1Y

AG GL LD OC SC

General Note (4) & Valves: · Inspect/replace(Inlet throttle, Capacity slide control, Solenoids, Unloader, Relief) · Filter replacement: Air and Oil · Balance & Unloader piston: Inspection/diaphragm replacement · Unloader cylinder: Dismantle and inspect · Oil breather cleaning · Float valves/Drain traps: Clean/replace

Major Overhaul

2Y 2Y 2Y 2Y 2Y 3Y 2Y 3Y

AG GL LD OC SC

General Note (1,5,9) & Bearings: · Replace per shock pulse results · Inter, After, Blowoff cooler (Clean and Inspect) · Cooler pressure test · Cooler efficiency test · Motor to compressor alignment · Motor (inspect) · Crankcase, Oil pump, Oil screen: Clean/inspect/replace · Coupling: Inspect/align/lubricate/replace · Discharge check valve: Inspect/replace

Instrument Calibration

AR AR AR AR AR AR AR AR

OC

General Note(6)

Failure Codes

Comments

Surveillance Task

EPRI TR-106857-V15 Application Note 2.3.5 & Functional Tests AR AR AR AR AR AR AR AR XX General Note (7) Newer variable speed drive (VSD) units have fewer mechanical parts requiring inspection. For example, VSD units do not have inlet throttle valves and unloading pistons. (1) Large motor electrical testing is covered under a separate template. Inspection activity is to look for dirt and oil on windings and air screens. (2) External inspection is in addition to and more detailed than operator rounds. This should be performed by both maintenance and engineering personnel as a skid partnership. (3) Internal inspection may not be possible on many compressors that do not have inspection windows. Where major disassembly is required to perform internal inspection, then internal inspection can be replaced with overhaul at minor overhaul frequency. (4) Minor overhaul is applicable to compressors where internal inspection can validate not needing a major overhaul. When validation of not requiring a major overhaul can not be made, then major overhaul to be performed at minor overhaul frequency. (5) Major overhaul is more applicable to critical or large air compressors where replacement is not economically feasible. (6) Instrument Calibration is directed by calibration program. Calibration program should contain routine calibration on all temperature instrumentation , safety tripping devices, loading pressure switches, based on history of instrumentation remaining in tolerance. Critical equipment calibration may be required more frequently based on Tech Spec requirements. (7) Functional Tests: As directed by Tech. Specs. In addition, capacity tests should be performed on large compressors such as Instrument Air on an annual basis. Low duty cycle compressors should be manually started to verify operability as required. (8) Operator Rounds to include as applicable: Oil level and temperature, Cooling water temperature, Compressor operating parameters, Drain trap operation, identification of air, water, & oil leaks. Operator rounds should also check for unusual noise or vibration, and where applicable, load and unload times. (9) Cooling water quality to compressor will determine the inspection/cleaning frequency for aftercooler, intercooler, blowdown cooler as applicable. Heavily silted cooling water will require a cleaning activity at least yearly. Pressure testing to be performed at cleaning frequency. Cooler efficiency testing can be deferred based on cooling water and air temperature performance trending. This template is the controlled revision. SME Summary

90

PCM Review – Rotary Screw Compressors This document captures the review of the Rotary Screw Compressor PCM Template. This review was performed in accordance with Attachment 1 of the provided review instructions titled: “PCM Template Review Instructions”, dated 11-21-01. FAILURE MODES Failure history data was reviewed to identify reasonable, detectable failure modes associated with Rotary Screw compressors. Failure data from MAROG, MWROG, OPEX, INPO (EPIX, NPRDS and OE) and EPRI reports were searched for Compressor failure information. This search revealed the most common failures as being caused by sub-component degradation or failure. Other external failure modes such as design deficiencies and poor maintenance practices were also identified, but are considered outside the scope of the PCM process. The most common sub-components identified were as follows: · · · · · ·

Capacity Slide Control Valve Inlet Throttle valve Drain traps Inlet Air filter Oil Pump Bearings

TEMPLATE REVIEW Overall, the scope and frequency identified in the PCM template is lacking in specifics and overly conservative based on the ability to use predictive techniques and operator rounds to early identify problems. The template does not differentiate between critical and non-critical, high duty cycle vs. low duty cycle and severe vs. mild service conditions. The template, which stems from EPRI TR-106857-V15 appears to be focused on large compressors used for Instrument and Service Air systems and does not account for the use of Rotary Screw compressors in other smaller applications found in power plants. · Addition of Operator rounds as a significant mitigator of failure mechanisms. · Addition of Minor overhaul, which is more in line with the predicted failure mechanisms and more cost effective than a major overhaul. · Many small non-critical compressors may be economical to run to failure and only perform simple maintenance. RECOMMENDED PCM TEMPLATE CHANGES The present template has been enhanced to include Predictive techniques and also to include a minor overhaul activity. Based on failure mode chart included, the template PM tasks have been expanded and frequencies modified to account for different compressor uses and conditions. REVIEW OF VENDOR MANUALS AND OTHER SOURCES Maintenance recommendations for the major rotary screw compressor vendor were reviewed. Vendor manual provided maintenance recommendations but did not account for predictive technologies and performance monitoring. Therefore the maintenance and frequencies tend to be overly conservative. Proposed template balances vendor recommended maintenance with established predictive techniques. Other sources such as NEIL typically do not address compressors, as they are typically non-safety related and not critical to generation. IMPLEMENTATION The revised PCM template should be implemented and data collected for several years. The collected data can then be reviewed for PCM effectiveness and adjusted as necessary. ATTACHMENTS 1. Failure Analysis Chart for Rotary Screw Compressors REFERENCES 1. EPRI Report TR-106857 – V15: “Preventive Maintenance Basis, Volume 15: Rotary Screw Air Compressors”, July 1997 2. EPRI: Equipment Condition Monitoring Templates “Addendum to the Preventive Maintenance Basis TR106857, Volumes 1-38.” 3. EPRI Report TR-108147 Compressor and Instrument Air System Maintenance Guide March 1998 4. EPRI Report NP-7079 Instrument Air Systems- A Guide for Power Plant Maintenance Personnel December 1990 Vendor Manual for Atlas Copco Rotary Screw Compressors . Boundary Definition The boundary of a rotary screw air compressor for the purpose of this database is defined to include the following: · Outlet flange of the after cooler

91

· · · · · ·

Inlet air filter Compressor mounting and base Coupling Cooling water to the inlet cooling flange for after cooler Cooling water to the outlet cooling flange for after cooler Controls

Air dryers are not included.

Basis For Template Tasks Oil Analysis: 2.3.1 Oil Analysis Failure Locations and Causes: Oil sampling and analysis is particularly directed at causes of bearing wear, and wear of the bull gear, as well as monitoring the quality and proper type of the oil. Progression of Degradation to Failure: Although it is reasonable to expect many years of trouble free service from components such as bearings and gears, these components can also fail much earlier than their expected life due to random occurrences of lubrication failure or misalignment. Fault Discovery and Intervention: The interval of 6 months for oil analysis is chosen to give a high probability of detecting the onset of these failure causes. Vibration Analysis: Vibration Analysis Vibration analysis is capable of detecting degradation in rotating machinery very efficiently. Vibration analysis of rotary screw compressors is an effective means of identifying degradation trends prior to catastrophic component failure. A basic understanding of the compressor design is necessary to design an effective vibration analysis program. Machine design influences the vibration data collection point selection, frequency ranges of interest, and data collection intervals. A primary focus the vibration analysis program for rotary screw compressors is the assessment of the health of the compressor and driver bearings. Rotary screw compressors typically rely on anti-friction bearings to maintain rotor position and prevent contact between the rotors. Catastrophic failure of compressor bearings could result in damage the compressor rotor. Rotary screw compressors that do not rely on lubrication within the compression chamber for cooling and lubrication rely on timing gears to transmit power and maintain synchronizing of the rotors. An effect vibration program will provide an assessment of the health of the timing gears and related components. Progression of Degradation to Failure: Assuming proper assembly and lubrication anti-friction bearings in rotary screw compressors can be expected to last a number of years. It not unusually for vendor to recommended an end of life limit of 5 years or more. This value of course can vary greatly depending on a number of factors including operating RPM and service conditions. The vendor manual should be consulted to obtain guidance for recommended replacement frequency. Anti-friction bearings normally fail in the following order, race defects, ball or roller defects then cage defects (assuming the bearing was not installed with a defect). The vibration analysis program should be designed to detect the vibration characteristics of the failure of these components Fault Discovery and Intervention: Degradation of the components described above may also be discovered by internal inspections. However, vibration analysis is often more effective at detecting anti-friction component degradation in its early stages than visual examination. Vibration analysis of anti-friction bearings can also be effective in assessing the progress of bearing degradation and remaining component life. This capability provides a means for scheduling maintenance that optimizes component life with incurring unnecessary expense. Vibration Analysis - Shock Pulse Analysis: See the basis for vibration analysis for a broader discussion on this task. Shock pulse analysis is a specialized vibration analysis technique that is targeted at assessing the health of anti-friction bearings. This technique relies on detection of impacts (shock) that may indicate anti-friction bearing component degradation. For example, an impact could be produced as the bearing rolling element passes over a defect in the race. Shock pulse analysis is very effective at identifying this type of condition in its early stages. Assessing the health of anti-friction bearings in rotary screw air compressors and scheduling maintenance based on this assessment is an important part of maximizing maintenance expenditures. If a bearing fault went undetected eventually leading to catastrophic bearing failure, the compressor rotors may be irreparable damaged, requiring costly replacement. Operator Rounds: Operator Rounds have the usual function of observing fluid leaks, unusual noises, and loose or missing hardware. Fault Discovery and Intervention This task is performed every shift when performed by operators, or approximately monthly if performed by a system engineer. This frequency is sufficient to detect randomly occurring and short term wearout failure modes with high or medium effectiveness. Progression of Degradation to Failure Operator Rounds or System Engineer Walkdown generally detects large leaks of air, water, or oil, as well as loose, damaged or missing fasteners, abnormal pressures, alarms, clogged filters, clogged or stuck drain traps, and dew point measurements. Task Content Operator Rounds should include: · Observe leaks of oil, water, refrigerant, or air · Listen for unusual noises, especially for escaping air. Particular attention should be given to expansion joints and other components subject to fatigue or aging related degradation. · Observe loose or missing hardware External Visual Inspection: 2.3.2 External Visual Inspection Failure Locations and Causes: External Visual Inspection is performed to look for blocked or broken air filters, leaks of oil, cooling water, process air, or control air; proper oil level and oil usage rate (a low rate can reveal a clogged oil filter); loose, damaged, or missing fasteners and other parts, especially crushed oil or air lines and loose mounting bolts; and proper lubrication of couplings. Leaks can occur from many different locations such as oil from a leaking sight glass; water from failed gaskets or failed inter or after cooler tubes (that will affect the color of water in condensate traps); and air from leaking gaskets or loose tubing or fittings on pneumatic devices, a worn or cracked shaft seal (revealed by air leaking from the sump breather hole), or from a relief valve that has failed to reseat. Worn bearings may also be revealed by audible noise. Progression of Degradation to Failure: The diverse set of degradation processes leading to the above failures have a wide spread of failure times but some are expected to occur much sooner than others. In particular, loose fasteners and fittings, wear on couplings that have poor lubrication, and blocked or broken air filters, and low oil usage are items which can degenerate rapidly or have random occurrence times. Fault Discovery and Intervention: The recommended external visual inspection interval is one month to accommodate these failure mechanisms. Given the ability to observe most of the above items during operator rounds, there does not appear to be a rationale for performing the external visual inspection as frequently as at one month intervals. It is suggested that the interval could be extended to 3 months or longer, depending upon operating experience. Operator and System Engineer Rounds Many of the above items are visible to operators or other personnel on frequent rounds. This means that items such as oil level can be observed even more frequently than the above intervals for external visual inspection. An item that requires constant attention is the condition of condensate traps. The bypass should be opened to blowdown the trap to avoid clogging and sticking of the drain mechanism. The color of the water can indicate leaking cooler tubes. In

92

addition there are physical parameters that should be recorded and trended on a daily basis. These are the oil pressure (can detect a weak relief spring), the inter cooler pressure as an indicator of moisture in the inlet air, cooling water flow and temperature to indicate fouling of LP and HP screw element cooling ports, the inlet LP air temperature as an indicator of a stuck unloader valve, the pressure drop across the inlet air filter to reveal filter condition, and the inter and after cooler delta temperature trend that can indicate progressive plugging of cooling tubes. External Visual Inspection should include the following: · Inspect for: air (control / compressor), oil, and water leaks; clogged or excessively dirty inlet air filters and motor air intake screens; indications of high operating temperatures (e.g. discolored paint); unusual noises and odors; visual indication of vibration; and unusual color of the condensate water in the traps and that there is proper drainage (i.e. neither excessive nor none) · Ensure the oil levels and pressure are normal · Verify loading and unloading pressures are within specification · Verify the condensate is being discharged from intercooler and aftercooler · Record the DP and DT across the compressor filters and coolers, compare to historical, and trend for future comparisons · Inspect for loose, missing, or damaged parts, wiring, and tubing · Check that the vents and seal bleeds are clear and operating properly · Perform a coupling inspection for wear and leaking grease, if present · Inspect for LED indicator light failure on compressor electronic control panel, if present, replace if necessary · Inspect air filter for contamination or blockage, if accessible Internal Inspection: 2.3.3 Internal Inspection Failure Locations and Causes: The internal inspection provides an opportunity to replace intake air filters, and to look closely for oil leaking from locations such as the oil seal provided by the oil receiver element. Some types of coupling should be inspected at the internal inspection if the condition cannot be assessed at the external visual inspection, in order to guard against rapid deterioration that could follow a lack of lubrication, misalignment, or excessive wear. Progression of Degradation to Failure: Other items are inspected during this task, as shown in the task content below, but they are done because of the opportunity, not because the timing is critical, and many of the items are observable in the external visual inspection. In fact the lack of a specific driver for this task appears to make it a candidate for interval extension, or eventual elimination. Fault Discovery and Intervention: This task is performed at 4000 run hours according to vendor recommendations but it lacks a clear rationale. There may be a need to ensure that some components that might be replaced at the annual overhaul are capable of avoiding failure for the remaining period of time. These degradations would involve a worn or failed rolling diaphragm in the inlet throttle valve, and a worn and sticking unloader valve. An Internal Inspection should contain the following: · All items from the External Visual Inspection, plus · Inspect and clean air filter element · Clean and inspect oil receiver breather pipe and refill with the proper oil · Check the pressure drop across the breathing extension pipe and compare to historical · Inspect motor bearing and coupling for indications of loss of grease or oil · Ensure that the motor’s air intake are not clogged or dirty · Perform shock pulse measurement for bearing condition Minor Overhaul: Minor Overhaul Failure Location and Cause The overhaul is focused on inspection for wear of lubricated parts due to low oil quality, the replacement of the balance piston, and inspection of the unloader valve and the inlet throttle valve. Key candidates for replacement of these valves are elastomers such as the diaphragm in the unloader valve. Some other important items are the cleaning or replacement of inlet suction screens, the air filter, and oil filter, and the opportunity to check the coupling for wear and to relubricate it, to check alignment where applicable, and to clean out the condensate traps and feed lines. Fault Discovery and Intervention The key items of the balance piston, the unloader valve, and the inlet throttle valve suggest a minimum overhaul interval of 8000 run hours. If experience is favorable this might be extended. Progression of Degradation to Failure The need to replace the balance piston, and to inspect elastomers in the unloader valve and the inlet throttle valve are the main driving influences on the timing of the overhaul. Tasks addressing the screens, filters, traps and coupling have less influence on making the overhaul interval 8000 operating hours. Overhaul can be also important because it provides the only opportunity to observe some types and locations of degradation. Overhaul is the only task available to observe failed tube sheet baffles and to pressure test or perform eddy current testing on cooler tubes, to check alignment, and to check the torque on mounting bolts. These failure locations and mechanisms do not drive this task to be performed every 8000 operating hours, because failures are expected from them individually at times much longer than that. Task Content An Overhaul should contain the following: · Change all oil and oil filters · Clean float valves on the drain receivers/coolers · Replace the air filter element · Replace the unloader piston’s rolling diaphragm · Dismantle and inspect unloader cylinder parts for wear and damage · Inspect balance piston’s diaphragm for indications wear and loss of flexibility · Inspect HP discharge check valve for wear or sticking · Test safety valves and safety relief valves · Test pressure and temperature sensors · Check cooling efficiency of intercooler and aftercooler · Pressure test all coolers · Verify motor to compressor alignment · Check condition of coupling · Check condition of compressor elements · Inspect and clean air filter element · Clean and inspect oil receiver breather pipe and refill with the proper oil · Check the pressure drop across the breathing extension pipe and compare to historical · Inspect motor bearing and coupling for indications of loss of grease or oil · Ensure that the motor’s air intake are not clogged or dirty · Perform shock pulse measurement for bearing condition · Inspect for: air (control / compressor), oil, and water leaks; clogged or excessively dirty inlet air filters and motor air intake screens; indications of high operating temperatures (e.g. discolored paint); unusual noises and odors; visual indication of vibration; and unusual color of the condensate water in the traps and that there is proper drainage (i.e. neither excessive nor none) · Ensure the oil levels and pressure are normal · Verify loading and unloading pressures are within specification · Verify the condensate is being discharged from intercooler and aftercooler · Record the DP and DT across the compressor filters and coolers, compare to historical, and trend for future comparisons · Inspect for loose, missing, or damaged parts, wiring, and tubing · Check that the vents and seal bleeds are clear and operating properly · Perform a coupling inspection for wear and leaking grease, if present · Inspect for LED indicator light failure on compressor electronic control panel, if present, replace if necessary · Inspect air filter for contamination or blockage, if accessible Major Overhaul: Major Overhaul This task has the objective of inspecting almost all internal components and replacing end of life components. Failure Location and Cause Overhaul addresses a very large range of failure mechanisms, which include end of life of bearings, seals and rotors. Fault Discovery and Intervention The task interval is well suited to the very large number of wearout failure modes which have 2 year or longer wearout periods. This interval should be correlated with run hours, not calendar time. Results of condition monitoring tasks should be reviewed prior to planning of a major overhaul. Condition monitoring data should be used to identify component degradation trends and identify components approaching end of life. Progression of Degradation to Failure These failure modes, and many others which are addressed, have wearout characteristics with failure free periods of 2 years or more. Task Content Overhaul consists of a complete tear down and inspection (for wear, damage, and contamination)/ replacement of compressor and lubrication system components. These should include: Clean and inspect: Oil strainers and oil pumps and orifices, for contamination and wear Valve actuators, and adjust Oil coolers Rotor inspection/ replacement as necessary Main line coupling: inspection, alignment, replacement as necessary. All bearing surfaces, and replace all bearings as necessary (consult condition monitoring data) Bull and pinion gears and shaft Drain traps Check-valves for leaks, broken springs, and worn surfaces Consider replacement of control relays Consider replacement of AMOT oil temperature control valves Reassemble all parts using new gaskets where appropriate. Instrument Calibration: Calibration addresses drift in electronic and electrical instruments and control devices, and prevents

93

deterioration in integrated system performance. Collectively, the significant number of devices and failure mechanisms provide some support for a 2-year interval, at least for critical equipment. (See General Note 6) Failure Location and Cause Calibration addresses drift in electronic and electrical instruments and control devices, and prevents deterioration in integrated system performance by detecting degradation in pressure switches, relays, and solenoid valves. Calibration is vital for assuring the effectiveness of performance monitoring for detecting seal water flow and temperature anomalies. Fault Discovery and Intervention None of the above mechanisms individually appears to oblige calibration to be performed as frequently as every 2 years, but collectively the significant number of devices and failure mechanisms tends to support a 2 year interval, at least for critical equipment. In addition, degradation of electronic and electrical devices and pressure switches is not usually specifically addressed by other preventive tasks, increasing the reliance placed on calibration. For these reasons it would also be reasonable to perform calibration for non-critical pumps at 2 years or longer, instead of relying on operator rounds to detect failures. Progression of Degradation to Failure Drift of electrical and electronic devices may be expected to occur randomly on a scale of a few years, and random occurrences of shorts, open circuits, and loose connections may be expected on a similar time scale. Different failure mechanisms affecting pressure switches, such as leaking by, sticking, plugged orifices, burnt contacts, and failed sensors, occur randomly over several years. Task Content Items that are typically calibrated are: · Pressure switches · Relays · Electrical and electronic devices · Solenoids · Thermocouples Functional Tests: 2.3.5 Functional Tests The functional test is a start / load test conducted as a post maintenance test on the equipment to verify operability, and readiness for return to service. A similar functional test is performed as an IST test to verify the operability of stand-by equipments. The functional test should be performed when: - Returning powered equipment to service - As per technical specifications or as a post maintenance test

94

Solenoid Operated Valve - Generic Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe

X X

X

Mild

5

6

7

8

X

X

X

X

X X

X

X X

X

X X

X

X

X

X

Time Directed Task

Valve Body Bonnet- Elastomer Replacement

5Y 5Y 10Y** 10Y** NR NR NR NR

Surveillance Task

Failure Codes

Comments

AL BF CB DA DF GL SC SL

Replacement of the entire valve should be considered if determined to be the most economical approach to preventing failures due to elastomer degradation. This task also includes replacement of the coil if the coil is continuously operated near the coil insulation's rated temperature (see reference 1).

Failure Codes

Comments

One of the best SOV preventive maintenance techniques is periodic valve cycling. As a result of the variety of factors affecting SOVs, there cannot be one recommended cycling frequency. BK CB DA Functional Tests (Operability, Stroke AR AR AR AR AR AR AR AR DF LC LS RD The most revelant factor for selecting a Time, Leak) SK SL cycle frequency is operating experience. Other important factors are operating temperatures, valve design, and the level and types of process contamination. * Non- Critical here means not critical but important enough to require some PM tasks. ** First replacement after a new component type is installed should be 5 years; subsequently at 10 years if condition was good at 5 years. Equipment qualification, IST, or other program requirements take precedence over use of this template. This template should only be applied where the solenoid operated valve of concern is not addressed by another component template(i.e. air operated valves, air operated dampers, diesel generator systems, unique hydraulic operating actuators or systems). The template does not apply to the Run-To-Failure components. This template is the controlled revision. SME Summary Solenoid operated valves used in Exelon plants come in a wide range of designs and have a wide range of applications. PM for many of these SOVs are specified on other component templates such as air operated valve, damper, and diesel generator templates. This template should only be used when the solenoid valve of concern is not addressed on another template. The basis for this template is direct use of EPRI TR-106857-V7 (reference 2) plus use of the NMAC Solenoid Maintenance and Application Guide (reference 1, especially sections 4 and 8). This template is established as a generic template for solenoid operated valves for use where more specific guidance is not available. The user should be careful to check if a specific SOV is already addressed by requirements included on another component template before applying the requirements of this template. Due to the wide range of SOV designs and applications it is difficult to specify an appropriate PM frequency without knowing the details of the SOV design or application conditions. The PMs identified in this template assume that the fluid being controlled is clean enough to preclude concerns about clogging ports, damaging seats, or causing a condition which leads to mechanical binding. It also assumes that lubricants used as part of the manufacturers standard assembly practices will not dry out by normal aging or accelerated aging (due to heat from the process media, environmental conditions, or being baked by a continuously energized coil) and causing mechanical sticking or binding. When applying this template the following factors should be considered: 1. If the SOV is covered by EQ requirements, then those replacement or refurbishment requirements will take precedence over this template. 2. If an SOV is required to be stroked in support of equipment in the IST program, no additional functional test requirements should be applied. This is also true for stroke time or leak testing. 3. If use of this template is appropriate the person determining appropriate PM activities should consider the following: A. Is the solenoid continuously energized or operated frequently? What is the margin between the coil temperature and coil insulation temperature rating? B. What is the temperature of the media being controlled and what are the environmental conditions (ambient temperature range and radiation) for the installed location? C. Is the media being controlled compatible with the elastomers being used? D. Are there any lubricants or compounds that may harden or become sticky in service that may prevent proper operation? E. Is the media clean or are deposits likely to cause an operational problem over time? F. Is the SOV normally open or closed? G. What is the seat design (hard or soft seat)?

95

H. What is the history of operation of this SOV design in this or similar applications? The items of concern presented above are the result of past industry experience with solenoid valve functional failures. Guidance on coil insulation ratings, elastomer temperature limits, fluid compatibility, and radiation resistance may be found in references 1 and 3. For unique SOV designs such as Target Rock model 79, Valcor model V526, Dresser model 1525VX, Target Rock model 93V, etc., it is better to define PM activities based on manufacturer's recommendations. For purposes of this template use of definitions for Critical, Duty Cycle, and Service Condition included in reference 2 should be used. Although these definitions do not contradict the definitions included in MA-AA-716-210 the definition for duty cycle (shown below) is more specific to SOV type functions. Duty Cycle (par. 2.5.2 of reference 2) High - Normally energized OR >1000 cycles per year Low - Not normally energized AND <1000 cycles per year References: 1. NMAC " Solenoid Valve Maintenance and Application Guide", EPRI NP-7414, Research Project 2814-36, April 1992. 2. EPRI TR-106857-V7, "Preventive Maintenance Basis, Volume 7: Solenoid Operated Valves", July 1997. Boundary Definition The boundary of an SOV for the purpose of this database is defined to include the SOV’s actuator and valve body bonnet assembly, as follows: Actuator: · Coil · Switches · Electrical connections and wiring · Electrical conduit seal · Control box, e.g. timer, voltage drop device, electronic components. Body Bonnet Assembly: · Plunger · Seat and trim · Spring(s) · Elastomers, if present Basis For Template Tasks Valve Body Bonnet- Elastomer Replacement : This task is driven by the need to change elastomers before they wear out. However, the task also serves as an internal inspection during which the condition of other subcomponents can be ascertained. O-rings are subject to aging and sliding wear (but not all are exposed to sliding wear). Diaphragms are subject to cracking and sticking. All the degradation mechanisms for elastomers are influenced by temperature and radiation. The number of wear cycles is also a factor for O-rings subject to sliding wear. In mild conditions and low duty cycles a minimum trouble free period of 5 years is expected, which may be extended to 10 years if the condition is found good at replacement. Knowledge of the degradation rate is the primary factor limiting the extension of replacement intervals for non-EQ solenoid valves. Consequently it is important to inspect the condition of elastomers that are replaced to assist in establishing a more appropriate replacement interval. The intervals for severe service should follow the OEM recommendations or a calculated service life, available from some vendors, that allows for various influences. The Template interval of 5 years for severe service should be used if these sources of information are inadequate. Even for mild conditions, the first replacement of elastomers should be performed at 5 years, before the decision is made to extend the resultant interval to 10 years. The following task content for elastomer replacement shows that this provides an opportunity to inspect the condition of other components. Some of these, e.g. the coil, seat area and disk, can otherwise be addressed only by failure finding using the functional tests. If such functional tests are not conducted, the replacement of elastomers will be the only task that avoids a run-to-failure situation for these components. SOV valve body and bonnet elastomer replacement should include: · Inspect for external evidence of leaks or damage · Inspect plunger and valve seat area for evidence of damage and wear · Inspect for build-up of crud and plugged equalization ports · Measure spring(s) dimensions and compare to original specifications, springs may need replacement if SOV is in severe service conditions or it has been greater than 10 years since they were last replaced · Inspect magnets for damage, positioning, and retention of magnetic properties · Clean and inspect all surfaces · Replace all O-rings and diaphragm (if present) · Lap seat and disk area to required finishes · Inspect the coil, all electrical wiring and connections, and any electronic components for damage and any evidence of over heating · Adjust switch assembly for proper stroke, positioning, and function · Relubricate any surfaces where required · Check for proper fit on bolted bonnet assemblies If the solenoid valve is replaced, tear down of the solenoid valve that was in service can show the condition of elastomers and critical sliding or sealing surfaces. This information should be documented and can be used as a basis for extending PM periods. Functional Tests (Operability, Stroke Time, Leak): Operability- This task verifies the open / close cycling of the valve. This operability test is conducted from the control room and verifies the open / close cycling of the valve. It is a failure finding task that is the only cost-effective way to address functional loss of the coil, switches, wiring, insulation, electrical connections and electronic components. This test could also detect blocking of small diameter ports, required for internal pressure equalization in the valve, that can easily arise from small quantities of debris in the process fluid medium or from corrosion. In all these cases the operability test is the key task as other tasks are either not available or not cost-effective. An added value is to detect failures of diaphragms from either cracking or sticking. The test is therefore once again a failure finding exercise. However, most degradation of elastomers is accounted for by scheduled replacement so that an operability test is not a crucial defense in this case. Occasionally a buildup of crud on the valve seat and / or plunger can reach sufficient proportions to prevent the valve from reaching the close limit switch setting, especially on very short stroke valves. Therefore an operability test could also reveal such an event. However, leak tests are more effective at detecting crud buildup than the operability test. Thermography, coil impedance measurement, and coil energization / de-energization timing are potential methods to detect coil deterioration before failure but are rarely performed because coil failures are too infrequent to make such

96

monitoring cost-effective. They are not included in the recommended program. All the above failures except for diaphragm cracking or sticking can appear suddenly from random causes. They are manifestations of degradation that is either precipitated at random times (e.g. personnel error), or which leads to failures at random times even when the degradation is driven steadily and continuously, such as the effect of high ambient or process fluid temperature on coil insulation breakdown. The diaphragm failures anticipate a trouble free period of 5 years after which they may be replaced. The operability test could thus detect failures in a few diaphragms that may fail early. The dominant failures addressed by this task involve misadjusted switches which are brought about by personnel error, by the need for fine adjustments on some models due to the short stroke of the valve, and by the need to allow for the temperature difference between cold switch settings and higher temperature operation. Consequently the operability test is an important line of defense for SOV’s. The only other defense against failures of the coil, switches, wiring, insulation, electrical connections, electronic components, and blocked ports is the internal inspection during elastomer replacement that is not required for non-critical valves. Therefore the operability test could be a useful addition for low duty cycle non-critical valves which may not be apparent from its "As Required" status on the Template. The EPRI expert panel could not identify any "non-critical but important" valves of this kind, and were inclined to state "Not Required" for all tasks for non-critical valves. However, this would be equivalent to running these valves to failure. The fact that there may yet be some non-critical but important valves that require some minimal protection from being unavailable for long periods of time, leads to the AR designation for functional tests for these valves. It is assumed that higher duty cycle valves would not benefit as much from an operability test under these circumstances, and would be closer to a run-to-failure condition. Timed Stroke Test- The periodicity for this test is mandated by the IST program. This is a manually timed stroke test mandated for some SOV’s as an IST requirement. The manual timing is often difficult to perform as the valves move quickly, especially when the stroke is very short. The timing is thus not obtained with high precision and the results are not trended as a condition monitoring task but used as a go / no-go comparison with a predetermined acceptance time. The only failure location addressed by this test is the buildup of crud on the valve seat or plunger. The test is only likely to detect crud buildup in a minority of events, leak tests being far more effective. Failure times are expected to be random so there is no "good time" for this test. The periodicity for this test is mandated by the IST program. Leak Test- These tests detect internal leaks that occur as a result of changes in spring constant, crud buildup, and damaged seat(s). These leak tests consist of Appendix J required local leak rate testing, or ASME O&M code requirements for measuring the designed leak rate. Both these types of tests are treated together in this section. These tests detect internal leaks that occur as a result of changes in spring constant, especially in models where the springs are normally compressed. They also detect leaks at the valve / plunger seat area due to crud buildup, and those due to damage to the seat(s). Changes in spring constant are likely to develop continuously in time, influenced mainly by the local temperature (both ambient and process fluid medium), degree of compression, and the number of cycles of the valve. At least 10 years of trouble free service are anticipated under moderate conditions but the period is sensitive to the service conditions. Both the buildup of crud and physical damage to the seat area are a function of the quality and cleanliness of the process fluid medium; physical damage to the seat is also sensitive to the flow conditions. These degradation processes may proceed continuously or be precipitated by a sudden change in fluid quality or by an influx of debris, or by a change in system operation. Even when degradation is continuous, the failure time is likely to be random owing to lack of knowledge and control of the process. Consequently, even if a leak is within design limits these tests are essentially failure finding tasks with little predictive capability. The periodicity for leaks tests is mandated by Appendix J or ASME requirements respectively.

97

Vertical Pumps Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe

X X

X

6

7

8

X

X

X

X

X X

X

Mild

5

X X

X

X X

X

X

X

X

Condition Monitoring Task

Failure Codes

Comments

OC

EPRI TR-106857-V12 Application Note 2.3.1

Vibration Analysis@

1M 1M 1M 1M 3M 3M 3M 3M

Oil Analysis

3M 18M 3M 18M 18M 18M 18M 18M DA FL OC

EPRI-TR-106857-V13 Application Note 2.3.2

Performance Testing

6M 6M 6M 6M 18M 18M 18M 18M OC

EPRI TR-106857-V12 Application Note 2.3.2 Monitor in accordance with ERAA-2003

Time Directed Task AR

AR

AR

Comments

PL SL

EPRI TR-106857-V12 Application Note 2.3.3

Packing/Seal Replacement

AR

AR

AR

AR

External Visual Inspection

1D

1D

1D

1D 1W 1W 1W 1W

BF CO DA FD EPRI TR- 106857-V12 Application Note GL LC OC 2.3.4 OR SL

External Lubrication/Filter Clean and Inspect

AR

AR

AR

AR

AR

AR

AR

AR

DA FL OR

EPRI TR-106857-V12 Application Note 2.3.5

Coupling Inspection/Lubrication (gear 24M 5Y 24M 5Y type)

AR

AR

AR

AR

DA FD GL UD

EPRI-TR-106857-V13 Application Note 2.3.5

AG CO ER IW NO OC

EPRI TR-106857-V12 Application Note 2.3.6 * Refurbishment of nonredundant (no installed spare), power production pumps (Condensate, Condensate Booster, Feedwater) should occur on the following time based schedule: - Condensate Pumps: 8 years - Condnensate Booster Pumps - 8 years - Feedwater Pumps - 10 years

Failure Codes

Comments

Refurbishment*

AR

Failure Codes

AR* AR AR* AR AR* AR AR* AR

Surveillance Task

Functional Testing AR AR AR AR AR AR AR AR XX EPRI TR-106857 Application Note 2.3.7 * Refurbishment of non-redundant (no installed spare), power production pumps (Condensate, Condensate Booster, Feedwater) should occur on the following time based schedule: - Condensate Pumps: 8 years - Condensate Booster Pumps - 8 years - Feedwater Pumps - 10 years @ For canned/wet motor pumps, consider supplementing normal vibration monitoring with current monitoring. This template is the controlled revision. Please refer to MA-AA-716-210 & MA-AA-716-210-1001 for additional guidance. SME Summary PCM Template Review Rotating Equipment Team Pump PCM Templates (Vertical and Horizontal) 1. Failure Modes A review of available failure history for vertical and horizontal pumps was performed to identify the anticipated failure modes for this type of equipment. Available data indicates the following failure modes as being anticipated for this equipment: 1. 2. 3. 4. 5. 6. 7.

Bearing degradation/failure Oil leakage Mechanical seal leakage Packing leakage Vibration (characteristic of degrading mechanical components, internal wear or off normal operating conditions) Degraded performance due to internal wear Lubricant degradation

Horizontal Pumps Template

98

Based upon the review of the Horizontal pump template the team has concluded that the tasks directed by the template do not adequately address the anticipated failure modes. The current PCM template specifies that visual inspection be conducted on an annual basis, which the team does not believe is frequent enough. The team recommends that visual inspection for items such as oil level, leakage, overheating, excessive vibration etc. be conducted on a daily basis for critical equipment, and weekly for non critical equipment. This inspection activity should be conducted via normal operator rounds. The template relies heavily upon Condition Based Maintenance activities to assess the condition of the pump in order to determine the need for maintenance. Vibration analysis, Lube oil analysis and Performance Monitoring are all mature CBM technologies and can be relied upon to perform an assessment of the condition of the pump. The CBM tasks defined in the template are adequate to detect the early stages of the anticipated failures identified above. The CBM tasks will not identify some infrequently experienced failures that are rapid in nature such as parts separating from the rotating element. The technologies (including the visual inspection frequencies) will identify that the failure had occurred and would allow the equipment to be removed from service prior to severe damage in all but the most extreme situation. There are several routine time based PM activities (Oil filter change and coupling inspection) that are currently on an 18 month frequency. The team recommends that a 24 month frequency be adopted for these activities unless site experience dictates otherwise. Additionally it is recommended based on our plant experience/history that time directed nozzle NDE inspection frequencies should be AR (as-required). A template revision request has been submitted to the MAROG PCM template coordinator to incorporate the changes discussed above. Vertical Pumps Template Based upon the review of the Vertical pump template the team has concluded that the tasks directed by the template do not adequately address the anticipated failure modes. The current PCM template specifies that visual inspection be conducted on an annual basis, which the team does not believe is frequent enough. The team recommends that visual inspection for items such as oil level, leakage, overheating, excessive vibration etc. be conducted on a daily basis for critical equipment, and weekly for non critical equipment. This inspection activity should be conducted via normal operator rounds. The template currently does not include the CBM activity for Lube Oil Analysis, which is an important requirement to assess the condition of any pump equipped with oil lubricated bearings. The template relies heavily upon Condition Based Maintenance activities to assess the condition of the pump in order to determine the need for maintenance. Vibration analysis, Lube oil analysis and Performance Monitoring are all mature CBM technologies and can be relied upon to perform an assessment of the condition of the pump. Once Lube Oil Analysis has been incorporated into the template the CBM tasks defined in the template will be adequate to detect the early stages of the anticipated failures identified above. The CBM tasks will not identify some infrequently experienced failures that are rapid in nature such as parts separating from the rotating element. The technologies (including the visual inspection frequencies) will identify that the failure had occurred and would allow the equipment to be removed from service prior to severe damage in all but the most extreme situation. There are several routine time based PM activities (Oil filter change and coupling inspection/lubrication for gear style couplings) that are also not included in this PCM template, which should be included in the next rev of the template. The team recommends that a 24 month frequency be adopted for these activities unless site experience dictates otherwise. A template revision request has been submitted to the MAROG PCM template coordinator to incorporate the changes discussed above. 2. Vendor Recommendations Due to the generic nature of these templates, review of vendor recommendations is not practical by the Corporate offices because of the shear number of pump supply vendors and those manuals are only available at the sites. In general the team’s experience has been that pump vendors will typically recommend routine lubrication and performance monitoring tasks, which we believe the PCM template adequately addresses. Additionally it should be understood that the generic templates were developed under the guidance of an expert panel comprised in part with pump vendors. The generic templates assume that specific pump reviews (site specific) would/will identify any specific vendor recommendations not in agreement with the template. 3. NEIL Insurance Requirements For rotating equipment NEIL provides guidelines that allow “credits” (premium discounts to be taken) when certain activities/programs are performed (vibration analysis, oil analysis, thermography etc) and it prescribes frequencies. However there are NEIL reporting requirements when certain levels are entered for specified equipment (specifically ECCS pumps and pumps w/drivers >1000 HP) The current templates provide for sufficient monitoring to satisfy the NEIL Requirements for reporting. 4. Condition Monitoring The PCM templates will contain adequate direction once Lube oil Analysis has been incorporated into the Vertical Pump Template. 5. Critical Subcomponents The team has concluded that there is currently no PCM template for Gearboxes, a critical subcomponent of many pumps throughout the Exelon system. A draft gearbox PCM template has been submitted via the M&WC webpage. This template is composed primarily of condition monitoring tasks, which have been employed throughout the industry to monitor gearbox condition.

99

Boundary Definition The boundary of a vertical pump for the purpose of this database is defined to include the following: · · · · · · ·

Motor mounting or flange (excluding motor) Coupling Discharge flange or head Inlet suction flange or bell Pump and its mount External lubrication system is included Seal water injection system is excluded

Basis For Template Tasks Vibration Analysis@: 2.3.1 Vibration Analysis Failure Locations and Causes: Vibration Analysis has a wide scope of application to pumps, addressing sources of vibration in rotating parts as well as flow noise such as cavitation. These sources include: a cracked, misaligned, bent, or worn shaft; worn or failed line shaft couplings; cavitation, or recirculation that can damage the pump bowls or wear the impeller; rubbing or other component damage that can cause impeller wear; improper pump to motor coupling fit and balance; bearing wear; rough bearing journals; defects, corrosion, cracks or improper materials or installation of bearing retainers or spiders; worn or galled wear rings; failed, or clogged column piping; and a clogged pump suction strainer. Progression of Degradation to Failure: Shaft problems are unlikely to occur on short time scales but they are a key degradation process for pumps, together with wear or failure of line shaft couplings. These failure processes are not addressed by other PM tasks, apart from the ability of motor oil analysis to give a general indication of shaft wear. Cavitation or recirculation that causes impeller and bowl degradation are also dominant failure causes and they can arise suddenly. Sources of bearing wear are also relatively common problems with timing aspects that suggest vibration monitoring should be relatively frequent. Several of the other failures mentioned above are not common but also drive the vibration monitoring to be frequent. These are impeller wear and rubbing caused by other component wear, improper fit and balance of the pump to motor coupling, rough sleeve bearing journals, and defects, cracks and corrosion in bearing retainers and spiders. The other processes above have less influence on the timing of this task because they are not commonly encountered and have sufficient backup from other tasks. Fault Discovery and Intervention: The expert group recommended vibration monitoring every month for critical pumps, and every three months for less critical pumps. This measurement is only done if the pump is already running because it is not prudent to start an idle pump just to take vibration measurements. Standby pumps are usually monitored only in conjunction with performance testing for surveillance test purposes. It is very important that vibration monitoring on a particular pump should be performed with the pump at the same operating point each time. Vertical pumps with integrally motors should have vibration in the horizontal plane monitored at the position of the upper and lower motor flanges. Vibration monitoring of the motor bearings in most cases provides the only meaningful vibration data. The lower bearings may not be accessible for any monitoring. Note: For canned/wet motor pumps, consider supplementing normal vibration monitoring with current monitoring. Oil Analysis: 2.3.2 Oil Analysis Failure Locations and Causes: Oil analysis is focused on processes that result in wear particles or other contaminates entering the oil or processes that cause degradation of the oil. These include wear of the fixed breakdown bushing seals, failure of bearing seals, bearing wear, and failure or fouling of bearing cooling heat exchangers, or internal bearing coolers. Progression of Degradation to Failure: Mechanical seal leakage, and sources of bearing wear, are relatively common problems with timing aspects that suggest oil sampling should be frequent, at least for critical pumps subject to high rates of wear. It appears there are no failure locations and causes for which oil sampling and analysis is the only PM task available to address pump degradation. Fault Discovery and Intervention: The expert group recommended oil analysis every three months for continuously running critical pumps, and every eighteen months for non critical pumps. A non critical pump with a low duty cycle in mild conditions may only receive oil analysis if a problem is suspected for other reasons, although some may be scheduled for oil analysis at 18 months, depending on conditions. The size of the oil reservoir and presence of sampling ports may be important in such a case, and may in fact be influential in setting oil sample intervals for pumps regardless of criticality and duty cycle. Performance Testing: 2.3.2 Performance Trending Failure Locations and Causes: Performance Trending is performed using installed plant instrumentation where available, and addresses causes of failure of the impeller, pump bowls, and wear rings, leaks in column piping and some gaskets, and clogging of the suction strainer. Progression of Degradation to Failure: This task is focused on impellers that have a reduced outside diameter or other cavitation damage, and pump bowls damaged by cavitation or recirculation. These mechanisms can lead to unacceptable conditions randomly within months to a few years. Generally eroded or corroded pump bowls (i.e. not caused by cavitation) have a longer time scale but are unable to be assessed by other means. Leaking gaskets are not particularly common but occur randomly and have little backup from other tasks. The other mechanisms are less important because of their extended time scale of occurrence, or because they can also be detected by other tasks. Fault Discovery and Intervention: The expert panel recommended that the interval for Performance Trending should be 6 months for critical pumps and 18 months for non-critical pumps. More precise hydraulic assessment requires auxiliary instrumentation and would be performed much less frequently. There is an opportunity to explore interval extension, especially on critical pumps, to improve the cost-effectiveness of this task. Performance Trending should include the following: · Record - Abnormal conditions - Pump bearing temperatures, if available - Suction pressure or sump level - Discharge pressure - Process fluid temperature - Motor current - RPM - Flow · Trend - DP versus flow - Motor current Packing/Seal Replacement : 2.3.3 Packing / Seal Replacement Failure Locations and Causes: As the name implies this task is focused entirely on replacement of the packing and mechanical seal. Progression of Degradation to Failure: These items fail by a wide range of mechanisms, some of which are varieties of personnel error, and most of which have essentially random failure times. The result is that the failures are random, and seal failures amount to a dominant failure cause for pumps. The influence of packing wear is a major determinant of shaft wear which is also a dominant pump degradation mechanism. Fault Discovery and Intervention: For both seal and packing degradation other tasks also provide protection, and the failure incidence is not sufficiently consistent to require a regularly scheduled task. External Visual Inspection can detect increasing leakage, and vibration monitoring may give indication of a deteriorating seal. The Template shows the tasks should be done as required. Inspection and diagnostic examination of the old seal may enable interval extension if a regular replacement is desired. Such examination may also indicate the expected life for another pump in a similar

100

situation. Packing / Seal Replacement should include the following: · Inspect the shaft and shaft sleeve for defects or damage · Look for loose, missing, or damaged bolts, studs, nuts, and parts · Verify shaft runout · Clean and inspect stuffing box for wear, damage, and presence of corrosion For seals: · Perform diagnostics on old seal, such as determine amount of seal face wear for wear rate evaluation, condition of elastomers, presence of any debris, condition of the spring, and the extent of the setscrew indentations into the shaft sleeve · Check seal injection piping condition and verify flow · Replace with new correct seal For packing: · Inspect and note condition of removed packing and packing sleeve · Verify configuration of packing and lantern rings · Replace with new packing using correct configuration, material, and number of rings · Torque to proper value External Visual Inspection: 2.3.4 External Visual Inspection Failure Locations and Causes: External Visual Inspection is primarily a method to discover a leaking seal, packing, or gasket; insufficient lubrication (low oil level in oiler); and a range of other conditions such as a clogged or failed flush system filter (inferred from flow, pressure, or pressure drop); a loose or failed pump base, a cracked discharge head, or corroded motor mount, or audible noise from worn bearing retainers or spiders, or a clogged pump suction strainer. Progression of Degradation to Failure: Seal and packing leaks are essentially random occurrences, as are lubrication problems. These degradation mechanisms taken together tend to occur on a scale of one to a very few years, and the other mechanisms have similar timescales. The detection of seal and packing leaks relies heavily on this task. Fault Discovery and Intervention: Operator rounds will provide leak detection and recognition of unusual noises of a continuing basis. External Visual Inspection should include the following: · Inspect for the general cleanliness and condition of all components · Inspection for loose, missing, or damaged bolts and parts · Inspection for abnormal noises and vibration, oil leaks, piping and flange leaks, damaged or missing insulation, abnormal pipe movement and damaged or misadjusted pipe hangers, and the general condition of expansion bellows · Inspect pump mounting plate for damage, missing or loose bolts / nuts, and damaged grout · Verify the presence of electrical ground straps · Verify the presence and condition of the coupling guard · If present, note Lubrication Flush System flow and pressure, and flush the filter if its DP warrants · Verify the proper operation and oil level of the oiler, if present · Monitor pump bearing temperature, if accessible · Verify the equipment is tagged and properly identified For packing: · Verify proper leak-off rate · Verify that the gland bolts are not loose or damaged For seals: · Note and report any seal leakage · Verify that the gland bolts are not loose or damaged · Proper seal injection flow External Lubrication/Filter Clean and Inspect: 2.3.5 External Lubrication / Filter Clean and Inspect Failure Locations and Causes: This task focuses entirely on the condition of the external lubrication system. Items to observe are a clogged or failed filter, environmental effects such as freezing, and contamination of the lubricant. Progression of Degradation to Failure: Most of these effects are random, and lead to random failure times. This is an on-condition task where action is triggered by the above observations. Fault Discovery and Intervention: This is an on-condition task. External Lubrication / Filter Clean and Inspect should include the following: · Check for leaks · Verify proper operation · Check DP across the filter and clean / replace if necessary · Note condition of all components especially the filter Coupling Inspection/Lubrication (gear type): 2.3.5 Coupling Inspection Failure Locations and Causes: As the name implies this task is focused entirely on inspection for lubrication leaks and wear of the geared type of pump/motor couplings. Progression of Degradation to Failure: Leaks are more important to the timing of this task than wear. Leaks caused by aging are not expected to occur before 5 to 10 years of service life, and wear of the coupling under normal conditions does not have a high probability of becoming excessive for several years. However, over greasing or loss of grease can cause rapid degradation at shorter times. Fault Discovery and Intervention: Continuously operating critical pumps are recommended to have a coupling inspection at 18 months. Standby critical pumps could go 5 years between inspections. Non critical pumps are expected to rely on indications from other tasks such as vibration analysis or thermography. Coupling Inspection should contain the following: · Inspect for signs of leaking lubricant · Inspect mating surfaces for cleanliness, wear, and integrity; record as-found and as-left conditions · Verify condition of lubricant looking for dirt, amount of lubricant, and indications of coupling wear; recharge with proper lubricant and quantity · Inspect gear teeth for wear and damage · Inspect nonmetallic parts for condition and wear · Inspect bolting for damage · Ensure proper orientation during reassembly Refurbishment*: 2.3.6 Refurbishment Failure Locations and Causes: Refurbishment is basically a corrective action that is not driven on a regular schedule. Because of the degree of disassembly many areas can be inspected as the task content listing shows. However, some of the conditions discoverable during refurbishment have no other means of detection, so the task serves to discover these conditions. These include impeller vane thinning, deformation of the discharge head/motor mount, corroded line shaft couplings, damaged adjustment nut or plate on the pump/motor coupling, loose bolting on column piping, and erosion or corrosion of the pump suction strainer. Some pumps allow diver access to perform an inspection (sometimes using a borescope) in which it may be possible to identify cavitation and other damaged of the impellers and pump bowls, a clogged, corroded, or damaged suction strainer, and corroded column piping. These items have been included here in Refurbishment. Progression of Degradation to Failure: Deformation of the discharge head, corrosion of line shaft couplings and the pump suction strainer may not occur before 5 to 10 years, however, the other mechanisms have more random occurrences. Fault Discovery and Intervention: The intervals for refurbishment will be driven mainly by the need for corrective actions. There is an implied assumption that condition monitoring and inspection can provide enough advance warning so that failure can be avoided while delaying refurbishment to a convenient outage period. Refurbishment should include the following: · All items from the External Visual Inspection, Packing / Seal Replacement, and the External Lubrication / Filter Clean and Inspect plus, · Prior to removal and disassembly, check and record uncoupled pump lift and motor thrust, compare to historical · Document as-found / as-left dimensions on machine fits, clearances, and motor and pumps lifts · Inspect and document conditions including the presence of corrosion or erosion, of welds, column piping, protective coatings, the suction strainer, and hardware such as bolts, fasteners, and gaskets · In general replace all components beyond OEM tolerances and specifications; document wear and condition · Inspect for damage, wear, and deterioration of all gaskets, O-rings, and elastomers · Replace all gaskets, O-rings, and elastomers · Replace anti-friction bearings; inspect and document wear and condition · Inspect bowl assemblies for thinning, cracking, and corrosion / erosion · Inspect shaft for damage, defects, and runout · Inspect and clean the pump barrel · Inspect impellers and wear rings for wear, and damage; balance if required · Inspect bearing retainers and spiders · Inspect stuffing box / gland for damage, corrosion, and wear · Replace / rebuild seals, if present · Replace all packing, if present · Clean and check for fit and flatness of all mating surfaces and joints · Verify fit and tolerances of the motor mount · Inspect motor and pump coupling and coupling bolts, replace coupling lock washers, verify proper fit of key and key length · After reinstallation and prior to coupling, check and record uncoupled pump lift and motor thrust, compare to historical data · Verify proper motor rotation before coupling · Perform PMT of coupled motor and pump Functional Testing: 2.3.7 Functional Tests The functional test is a start / run test conducted as a post maintenance test to verify operability, proper rotation, and readiness for return to service and also frequently as a post maintenance test on the driven equipment. Other forms of functional testing are IST tests that verify the operability of stand-by equipments. The Functional test should be performed when: - Returning powered equipment to service - As per technical specifications or as a post maintenance test

101

Westinghouse- EH/DEH (Electrical, Electronics, Mechanical & Surveillance) Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe

X X

X

Mild

5

6

7

8

X

X

X

X

X X

X

X X

X

X X

X

X

X

Condition Monitoring Task

X Failure Codes

Comments

Pressure Switch Calibration

2Y

OC

No Comments

Valve Limit Switch Replacement

AR

CD ZO ZS

No Comments

Throttle Valve Safety Related Limit Switch Calibration

2Y

OC

No Comments

Pressure and Temperature Indicator Calibration

2Y

OC

No Comments

Operator Panel Indicator Calibration

2Y

OC

Perform During System Calibration

Actuator Wiring and Subcomponent Connection Inspection

AR

CD CN IB LC

No Comments

EHC Cabinet Cooling Fan Inspection

2Y

DA IW LC MB OP OR

No Comments

EHC Cabinet Cooling Fan Replacement

AR

AG

No Comments

EHC Cabinet Air Filter Inspection

2Y

DA FL OR

No Comments

Turbine Trip Test Solenoid Valve Replacement

5Y

AG

No Comments

Turbine Trip Solenoid Valve Replacement

3Y

AG

No Comments

Turbine Overspeed Protection Solenoid Valve 3Y Replacement-OPC 20-1 & 2

AG

No Comments

Vacuum Trip Latch Solenoid Valve Replacement-20 VTL

AR

AG

No Comments

Auto Stop Reset Solenoid Valve Replacement-20 ASR

AR

AG

No Comments

Main Turbine EH/DEH System Testing

2Y

OC

No Comments

DEH System Calibration

2Y

OC

Includes DEH Card Checkouts

HP Turbine 1st Stage Pressure Transmitter Calibration

2Y

OC

Turbine Impulse Pressure

Overspeed Protection Controller Loop Check

2Y

OC

Perform During System Calibration

Overspeed Protection Loop Calibration

2Y

OC

No Comments

Megawatt Transducer Calibration

2Y

OC

No Comments

Reheat Pressure Transducer Calibration

2Y

OC

No Comments

Power Supply Check and Calibration

2Y

OC

No Comments

Power Supply Ripple Output Check

2Y

OC

No Comments

Power Supply Rebuild/Replacement

8Y

AG

No Comments

Age Dependent Circuit Board Replacement

8Y

AG

No Comments

Servo Valve Replacement/Rebuilt

6Y

AG

See ComEd Spec NEC-99-7077

Servo Valve Filter Replacement

2Y

OR

No Comments

Throttle and Governor Valve Actuator Hydraulic Valve Replacement

6Y

SC SL

No Comments

Reheat Stop and Intercept Valve Actuator Hydraulic Valve Replacement

8Y

SC SL

No Comments

EH Fluid Cooler Replacement

2Y

CO ER OR

No Comments

EH Pump Suction Filter Element/Screen Inspection

2Y

DA FL

No Comments

EH Filter Replacement

2Y

OR

No Comments

EH Reservoir Particulate Filter Replacement

2Y

FL

With Fullers Earth Filter Change

Fullers Earth Filter Replacement

2Y

FL

Selexorb Acceptable

Check Valve Replacement/Rebuild

AR

DF

No Comments

Diaphragm Interface Valve Rebuild

8Y

LD

Replace Diaphragm

102

EH Fluid Reservoir Magnetic Plug Cleaning

2Y

FL

No Comments

Auto Stop Relief Valve Replacement

6Y

OC

No Comments

EH Pump Motor Air Intake and Exhaust Cleaning

AR

DA FL OR

No Comments

EH Pump Motor Service

5Y

OC

No Comments

EH Pump Motor Bearing Checks

2Y

OC

No Comments

EH Pump/Motor Coupling Grease Replacement

2Y

DL

No Comments

EH Pump Motor Control Center Clean and Inspect

AR

OC

No Comments

EH Accumulator Overhaul

10Y

SL

No Comments

Overspeed Trip Remote Relatch Mechanism Air Cylinder

AR

AL SL

For Leakage

Mechanical Overspeed Trip Device Inspection

8Y

OC

No Comments

Mechanical Trip Block Rebuild/Diaphragm Replacement

2Y

LD

No Comments

Non-Safety Related Valve Limit Switch Operational Check

Q

OC

Key: "M" designates monthly "Q" designates quarterly Performed During Valve Testing

Solenoid Valve Inspection

Q

OC

Perform During System Walkdown

System Piping, Tubing and Support Bracket Visual Inspection

Q

FD SC

See EHC System Walkdown Guide NES-G-05

EH System Leak Inspection

Q

FG GL PL SL

See EHC System Walkdown Guide NES-G-05

EH High Pressure Accumulator Charge Check

Q

OC

No Comments

EH Low Pressure Accumulator Charge Check

Q

OC

No Comments

EH Fluid Sampling

M

DA FL MS

No Comments

EH Pump and Motor Vibration Readings

Q

OC

No Comments

AG

EHC Hydraulic Fluid Maintenance requirements are identified in NESG-19.

Failure Codes

Comments

Hydraulic Fluid Maintenance

AR

Time Directed Task

Includes pressure compensator. Verify material compatibility EH Pump Rebuild/Replacement 15 Y AG requirements on new/rebuilt pump components to EH fluid. * Critical No Non-critical here means not critical but important enough to require some Pm tasks. The shaded area indicates that no examples of EH/DEH components could be identified for these Template conditions. If an EH/DEH component was identified that corresponded to a column in the shaded area it would be necessary to develope a PM program,probably similar to those stated. The shaded area does not mean Run-To-Failure. "Y" designates years "AR" designates as required "Q" designates quarterly This template is the controlled revision. Please refer to MA-AA-716-210 & MA-AA-716-210-1001 for additional guidance. SME Summary Revised to: · Split the existing combined Pump & Motor PM task into two individual tasks for the pumps and the motors each. The existing motor requirements will be retained. · The new pump PM task will reflect replacement with a new or rebuilt pump assembly on an interval of 15 calendar years including the pressure compensator. · Addition of a note requiring verification of material compatibility requirements on new/rebuilt pump components. Boundary Definition No Boundary Definition Available At This Time Basis For Template Tasks Pressure Switch Calibration : Pressure Switch Calibration Scope Includes: - EH Pump Header Discharge PS (63/MP) - EH Fluid Return PS (63/PR) - EH Pump Filter 1A & 1B Filter D/P Switch (63/MPF1 & 2) - EH Pump Discharge PS (63/LP & 63/HP) - EH PRessure Switch (1PS-EH024) - EH Pressure Switch (1PS-EH025) - EH Pressure Switch (1PS-EH026) - EH Pressure Switch (1PS-EH027) - EH Pressure Switch (1PS-EH028) - EH Pressure Switch (1PS-EH028) - Auto-Stop Oil Pressure Switches (63/AST-1, 63/AST-2 & 63/AM1) - Low Vacuum Pressure Switch (63/LV) - Thrust Bearing Pressure Switch (63/TB) - Low Lube Oil Pressure Switch (63/LBO) Valve Limit Switch Replacement: No Basis At This Time Throttle Valve Safety Related Limit Switch Calibration: No Basis At This Time

103

Pressure and Temperature Indicator Calibration : Indicator Calibration Scope includes: - A EH Pump Discharge Pressure Indicator B EH Pump Discharge Pressure Indicator - EH System Pressure Indicator - EH Oil Reservoir System Temperature Indicator - EH high Pressure Accumulator Pressure Indicator - EH Fullers Earth Filter Pressure Indicator - EH Containment Filter Pressure Indicator Operator Panel Indicator Calibration: No Basis At This Time Actuator Wiring and Subcomponent Connection Inspection: No Basis At This Time EHC Cabinet Cooling Fan Inspection: No Basis At This Time EHC Cabinet Cooling Fan Replacement: No Basis At This Time EHC Cabinet Air Filter Inspection: No Basis At This Time Turbine Trip Test Solenoid Valve Replacement : Turbine Trip Test Solenoid Valve Scope includes: - Diaphragm Interface Valve Test Solenoid (20/DVT) - Emergency Trip Test Solenoid (20/ETT) Turbine Trip Solenoid Valve Replacement : Turbine Trip Solenoid Valve Scope includes: - Auto-Stop Trip Solenoid 20-1/AST Coil Auto-Stop Trip Solenoid 20-2/AST - Emergency Trip Solenoid 20/ET Turbine Overspeed Protection Solenoid Valve Replacement-OPC 20-1 & 2: No Basis At This Time Vacuum Trip Latch Solenoid Valve Replacement-20 VTL: No Basis At This Time Auto Stop Reset Solenoid Valve Replacement-20 ASR: No Basis At This Time Main Turbine EH/DEH System Testing: No Basis At This Time DEH System Calibration: No Basis At This Time HP Turbine 1st Stage Pressure Transmitter Calibration: No Basis At This Time Overspeed Protection Controller Loop Check: No Basis At This Time Overspeed Protection Loop Calibration: No Basis At This Time Megawatt Transducer Calibration: No Basis At This Time Reheat Pressure Transducer Calibration: No Basis At This Time Power Supply Check and Calibration: No Basis At This Time Power Supply Ripple Output Check: No Basis At This Time Power Supply Rebuild/Replacement: No Basis At This Time Age Dependent Circuit Board Replacement : Age Dependent Circuit Boards Contain the following Sub-components: - Electrolytic Capacitors - Opto Isolators - 7300 Card resistors Servo Valve Replacement/Rebuilt: No Basis At This Time Servo Valve Filter Replacement: No Basis At This Time Throttle and Governor Valve Actuator Hydraulic Valve Replacement : Actuator Hydraulic Valve Replacement Scope Includes: Cylinder Disassembly and Overhaul - Shut Off Valve - Check Valves - Dump Valve O-Rings Reheat Stop and Intercept Valve Actuator Hydraulic Valve Replacement : Actuator Hydraulic Valve Replacement Scope Includes: - Cylinder Disassembly and Overhaul - Shut Off Valve - Check Valves - Dump Valve O-Rings EH Fluid Cooler Replacement: No Basis At This Time EH Pump Suction Filter Element/Screen Inspection : No Basis At This Time EH Filter Replacement : EH Filter Replacement Scope includes: - EH Fluid Return Filter - Discharge Filters EH Reservoir Particulate Filter Replacement: No Basis At This Time Fullers Earth Filter Replacement: No Basis At This Time Check Valve Replacement/Rebuild : Check Valve Replacement/Rebuild Scope includes: - Ball Check Valves - Spring Loaded Line Check Valves Diaphragm Interface Valve Rebuild : Exelon experiences and 2002 PCM Assessment results.

104

EH Fluid Reservoir Magnetic Plug Cleaning: No Basis At This Time Auto Stop Relief Valve Replacement: No Basis At This Time EH Pump Motor Air Intake and Exhaust Cleaning: No Basis At This Time EH Pump Motor Service : EH Pump Motor Service Scope includes: - Remove and Service Motor - EH Motor Bearings Replacement EH Pump Motor Bearing Checks: No Basis At This Time EH Pump/Motor Coupling Grease Replacement: No Basis At This Time EH Pump Motor Control Center Clean and Inspect: No Basis At This Time EH Accumulator Overhaul: No Basis At This Time Overspeed Trip Remote Relatch Mechanism Air Cylinder: No Basis At This Time Mechanical Overspeed Trip Device Inspection: Exelon experience. To be performed during HP turbine disassembly outages due to extent of disassembly already required to remove the HP rotor. Mechanical Trip Block Rebuild/Diaphragm Replacement: Exelon experience & OEM Recommendation. Due to diaphragm failures at Byron & Braidwood, SWPC recommends replacement every outage to prevent aging or fatigue induced by installation process. O-ring replacement should also be performed. Non-Safety Related Valve Limit Switch Operational Check: No Basis At This Time Solenoid Valve Inspection: No Basis At This Time System Piping, Tubing and Support Bracket Visual Inspection: No Basis At This Time EH System Leak Inspection: No Basis At This Time EH High Pressure Accumulator Charge Check: No Basis At This Time EH Low Pressure Accumulator Charge Check: No Basis At This Time EH Fluid Sampling: 5.4.1. EH Fluid Sampling Scope includes: - Chemical Analysis of Neutralization - Particle Count EH Pump and Motor Vibration Readings : EH Fluid Sampling Scope includes: - Chemical Analysis of Neutralization - Particle Count Hydraulic Fluid Maintenance: No Basis At This Time EH Pump Rebuild/Replacement: · Acceptable experiences with existing EH pump motor PM requirements. · Only one out of the eight EH pumps/pressure compensators between the Byron/Braidwood units has required adjustment to maintain system pressure requirements over their eleven years (44 equipment operating years) of service. · Even though stand-by back-up pump availability is designed into the system, a loss of or swap of an EH pump does represent a production risk to the unit. · Operation of the pumps is alternated on a monthly basis at each of the units. · Temperatures, speed and complexity of the pump internals are expected to result in mechanical wear over time even though the process fluid involved is an oil. · The required system pressure was successfully returned and maintained after only one adjustment of the Byron 2B EH pump pressure compensator as designed. · Dirt is the primary degradation mechanism for these pumps/pressure compensators and the condition of the EH hydraulic fluid cleanliness at Byron & Braidwood is among the best in the industry. · The estimated life of these pumps by the component OEM (MOOG) is 15 years based on their specific application. · The Siemens Westinghouse recommended inspection/rebuild PM interval of every four to five years for these components is not consistent with the experiences of our fleet. · Adjustment to pressure compensators is not an uncommon activity based upon a survey of similar industry applications (North Anna, Calvert Clifts, Surry, Waterford & Beaver Valley). Of these units, 38% have reported similar system pressure decay/compensator adjustments.

105

Westinghouse - Exciter Component Classification Categories Yes

Critical Duty Cycle

1

2

3

4

X

X

X

X

No High

Service Condition

X

Low Severe

X X

X

Mild

5

6

7

8

X

X

X

X

X X

X

X X

X

X

Time Directed Task

X X

X X

X Failure Codes

Comments

Pre-Shutdown Machine Vibration/Dynamics Analysis

2Y

OC

No Comments

General Condition Visual Inspections

8Y

CO DA ER FD GL IB LC SC

No Comments

Diode Wheel Assembly Visual Inspection

8Y

AG FD

No Comments

Rotating Element Banding Visual Inspection

8Y

AG FD

No Comments

Electrical Tests (Megger, Field Discharge Resistor, etc.)

8Y

CD IB OC OP

No Comments

Diode Wheel Fuse Checks

8Y

CD

No Comments

Bearing Insulation Measurements

8Y

IB

No Comments

Bearing& Journal Inspections

8Y

ER OC

No Comments

PMG Visual Inspection

8Y

CO ER GW IB OC

No Comments

Clean Assembly With Compressed Air

8Y

DA

No Comments

As-Left Alignment Readings

8Y

OC

No Comments

Voltage Regulator Electrical Checkouts/Calibrations

2Y

CD IB OC

No Comments

Return to Servive Full Load Vibration/Dynamics No 2Y OC Analysis Comments *Critical No Non-Critical here means not critical but important enough to require some PM tasks. The Shaded area indicates that no examples of Exciters could be identified for these Template conditions. If a Generator/Exciter was identified that corresponds to a column in the shaded area it would be necessary to develope a PM program, probably similar to those stated. The Shaded Area Does Not Mean Run-To-Failure. Application Notes: "Y" designates years. This template is the controlled revision. Please refer to MA-AA-716-210 & MA-AA-716-210-1001 for additional guidance. SME Summary Revised to incorporate PM bases. Boundary Definition No Boundary Definition Available At This Time Basis For Template Tasks Pre-Shutdown Machine Vibration/Dynamics Analysis : Historical operational/maintenance data - industry experience - OEM recommendations. Pre-Shutdown Vibration Analysis: This is a valuable tool to determine if any additional inspections are required and also allow you to monitor the effects of the maintenance after restart. This data has also been used to reduce the scope of work. General Condition Visual Inspections: Historical operational/maintenance data - industry experience - OEM recommendations. Signs of overheating or distress. Diode Wheel Assembly Visual Inspection: Historical operational/maintenance data - industry experience - OEM recommendations. A visual inspection of this area should be directed towards verification that no fuses are open circuited and that all of the components are properly secured within the wheel. Rotating Element Banding Visual Inspection: Historical operational/maintenance data - industry experience - OEM recommendations. Signs of looseness, cracking or degradation. Electrical Tests (Megger, Field Discharge Resistor, etc.): Historical operational/maintenance data - industry experience - OEM recommendations. Electrical shorts or grounds due to component degradation or insulation system breakdown.

106

Diode Wheel Fuse Checks: Historical operational/maintenance data - industry experience - OEM recommendations. A visual inspection of this area should be directed towards verification that no fuses are open circuited and that all of the components are properly secured within the wheel. Replace fuse per AIB 8712. Bearing Insulation Measurements: Historical operational/maintenance data - industry experience - OEM recommendations. The insulated stop dowel, bearing key insulation, and bearing support insulation should be checked for evidence of distress or cracks. The bearing seats should be checked to see that the bearings are self-aligning and ride properly in the bearing seat. Check the bearing pedestal insulation per OMM 049. Bearing& Journal Inspections: Historical operational/maintenance data - industry experience - OEM recommendations. Exciter bearings should be inspected on the bore surface for particles of dirt or debris embedded in the babbit surface or for grooving or scoring of the babbit. When evidence of this is found, it is reommended that the entire lubrication system be flushed out and the oil cleaned. Excessive wear or clearance of the bearings or gland seal rings relative to the journal diameter mayve indicate the need for rebabitting of the bearings. PMG Visual Inspection: Historical operational/maintenance data - industry experience - OEM recommendations. The wound core of the PMG should be checked for damage to the winding and shorting between laminations. Clean Assembly With Compressed Air: Historical operational/maintenance data - industry experience - OEM recommendations. Remove dirt & dust which could collect to form electrical paths. As-Left Alignment Readings: Historical operational/maintenance data - industry experience - OEM recommendations. As-left alignment readings: This is performed based on operation data taken during shutdown (vibration). Verify the rotor is in the same relative position during reassembly and if operation data requires an actual alignment check then perform and align as required. Swing check of exciter rotor. Voltage Regulator Electrical Checkouts/Calibrations: Historical operational/maintenance data - industry experience - OEM recommendations. Calibration of electronic cards/components. Replace if unstable readings experienced. Return to Servive Full Load Vibration/Dynamics Analysis: Historical operational/maintenance data - industry experience - OEM recommendations. Return to service Vibration data: this is to compare to the shutdown data to ensure that the work that was performed returned the equipment to the same or better operation.

107

Westinghouse - High Pressure Turbine Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe

X X

X

Mild

6

7

8

X

X

X

X

X X

X X

X X

X X

Time Directed Task

5

X

X X

X Failure Codes

Comments

Pre-Shutdown Machine Vibration/Dynamics Analysis

2Y

OC

No Comments

Steam Gland Seal Inspections

10Y

ER OC SL

No Comments

Steam Path Inspections

10Y

ER OC

No Comments

Oil Seal Inspection

10Y

FL OC OR

No Comments

Main Oil Pump Inspections

10Y

ER IW LC SL

No Comments

Rotor Inspections

10Y

LC OC

No Comments

Outer Cylinder Inspections

10Y

ER SL

No Comments

Bearing & Journal Inspections

10Y

ER OC

No Comments

Piping Flange Face Inspections

10Y

BF ER FD FG GL

No Comments

Coupling Faces & Spacer Visual Inspections

10Y

FD

No Comments

Bolting (Horiz.Joint / Flange / Coupling) & Sleeve NDE

10Y

AG FD OC

No Comments

As-Left Alignment Readings

10Y

OC

No Comments

Overspeed Functional Testing

2Y

OC

No Comments

Return to Service Full Load Vibration/Dynamics Analysis 2Y OC No Comments *Critical No Non-critical here means not critical but important enough to require some PM tasks. The Shaded area indicates that no examples of High Pressure Turbines could be identified for these Template conditions. If a HP Turbine was identified that corresponded to a column in the shaded area it would be necessary to develope a PM program, probably similar to those stated. The Shaded Area Does Not Mean Run-To-Failure. PM Application Note: "Y" designates calendar year. This template is the controlled revision. SME Summary Revised on 7/15/03 to: 1. Incorporate basis information. Boundary Definition No Boundary Definition Available At This Time Basis For Template Tasks Pre-Shutdown Machine Vibration/Dynamics Analysis: Historical operational/maintenance data - industry experience - OEM recommendations. Pre-Shutdown Vibration Analysis: This is a valuable tool to determine if any additional inspections are required and also allow you to monitor the effects of the maintenance after restart. This data has also been used to reduce the scope of work required during the outage. Steam Gland Seal Inspections: Historical operational/maintenance data - industry experience - OEM recommendations. Gland cases and seals are subject to steam erosion and corrosion during turbine operation. Visually inspect the inner and outer gland cases (fluorescent magnetic particle inspection as well), the gland case horizontal joint screws, and the inner and outer gland seal rings. Steam Path Inspections: Rotor blading and shrouds may be damaged by pitting or material erosion from solid particles or moisture in the steam, thermal fatigue from excessive cycling of load, vibration induced fatigue from poor steam flow or thermally induced creep from prolonged perdiods of high load service - they are susceptible to pitting, erosion, cracking, and separation. Recommended Inspection: 1. Visually inspect the blade path 2. Dust blast and NDE Oil Seal Inspection: Historical operational/maintenance data - industry experience - OEM recommendations. Under normal conditions there should be no leakage past the oil seal rings. Set clearances per specifications. Care must be taken, however, to ensure that the drain passages are clean and permit a free oil flow. The seals and in particular the oil drain passages should immediately be examined if an excess amount of oil is found escaping the from the bearing housing, along the rotor shaft. Main Oil Pump Inspections: Historical operational/maintenance data - industry experience - OEM recommendations. Main oil pump, impeller and associated seal rings are subject to wear during turbine service. Visually inspect the main oil pump, impeller, pump housing, oil seals, and impeller wear rings. Restore to appriopriate clearane specifications. Rotor Inspections: Historical operational/maintenance data - industry experience - OEM recommendations. Distortion (bowing and rubbing) and cracking can occur in the rotor bodies, both of which require maintenance. Rotor blading and shrouds may be damaged by pitting or material erosion from solid particles or moisture in the steam, thermal fatigue from excessive cycling of load, vibration induced fatigue from poor steam flow or thermally induced creep from prolonged perdiods of high load service - they are susceptible to pitting,

108

erosion, cracking, and separation. Recommended Inspection: 1. Visually inspect the blade path 2. Dust blast and NDE 3. Visually inspect the journal and gland areas for scoring, erosion, other damage Outer Cylinder Inspections: Historical operational/maintenance data - industry experience - OEM recommendations. Turbine operation can cause distortion, erosion, wear, and cracking to the outer cylinder and it's components. Visual and fluorescent magnetic particle inspection of the outer cylinder through bolts, nuts, and washers, as well as of the main and reheat inlet flange bolting. Bearing & Journal Inspections: Historical operational/maintenance data - industry experience - OEM recommendations. Visual inspection of bearings and journal for signs of wear, scoring, wiping, cracking, and pitting in the babbit, caused by abnormal operating conditions such as excessive vibration and insufficient, dirty, or hot lubricating oil. Piping Flange Face Inspections: Based upon Exelon experiences, industry information and OEM recommendations. Visually inspect for damage to sealing surfaces and parallelism to minimize joint leaks. Coupling Faces & Spacer Visual Inspections: Historical operational/maintenance data - industry experience - OEM recommendations. Visual and fluorescent magnetic particle inspection of coupling faces for signs burrs or surface imperfections due to stresses. The "as found" coupling alignment should be taken prior to removing the rotors (this may be accomplished by oil bore readings to the shaft recordings). Remove coupling spacers, check spindle travels to outside reference readings. Measure the gap between couplings to determine if new spacers are required. Bolting (Horiz.Joint / Flange / Coupling) & Sleeve NDE: Historical operational/maintenance data - industry experience - OEM recommendations. Bolting: the bolting is cleaned and visually inspected for mechanical condition of the threads on the studs and nuts and also NDE inspected UT to verify no indications of cracking in the stud. The coupling bolts are also visually inspected for mechanical condition and NDE of the bolts and sleeves is performed MT. As-Left Alignment Readings: Historical operational/maintenance data - industry experience - OEM recommendations. As-left alignment readings: This is performed upon reassembly of spindles or based on operation data taken during shutdown (vibration). Verify the rotor is in the same relative position during reassembly and if operation data requires an actual alignment check then perform and align as required. Oil bore clearance reading may be substituted for complete 16 point coupling checks upon engineering evaluation. Overspeed Functional Testing: Actual mecanical overspeed settings must be verified through testing every operating cycle or when maintenance is performed within the governor pedestal per NEIL Insurance requirements. Return to Service Full Load Vibration/Dynamics Analysis: Historical operational/maintenance data - industry experience - OEM recommendations. Return to service Vibration data: this is to compare to the shutdown data to ensure that the work that was performed returned the equipment to the same or better operation.

109

Westinghouse - Low Pressure Turbine Component Classification Categories Yes

Critical Duty Cycle

1

2

3

4

X

X

X

X

No High

Service Condition

X

Low Severe

X X

X

Mild

5

6

7

8

X

X

X

X

X X

X

X X

X

X

X X

X X

X

Time Directed Task

Failure Codes

Comments

Exhaust Hood Crawl Through Visual Inspection

2Y

CO ER LC SC

No Comments

Pre-Shutdown Machine Vibration/Dynamics Analysis

2Y

OC

No Comments

Exhaust Hood Inspection

8Y

CO ER OR

No Comments

Inner Cylinder Inspection

8Y

CO ER OR

No Comments

Steam Gland Seal Inspection

8Y

CO ER OR

No Comments

Oil Seal Inspection

8Y

CO ER OR

No Comments

Steam Path Inspection

8Y

CO ER OR

No Comments

Bearing & Journal Inspections

8Y

DL OC SC

No Comments

8Y

ER OC

No Comments

AG ER LC

See Note 1

Thrust Bearing Inspection Rotor Inspection

AR/8Y

Coupling Faces & Spacer Visual Inspection

8Y

FD LC

No Comments

Bolting ( Horizontal Joint/Coupling )& Sleeve NDE

8Y

AG BF CO ER FD OC

No Comments

Rupture Disc Replacement

8Y

AG AL

experiences of pin hole leaks developing over time resulting in condenser inlealage. Changes in condenser backpressure over time cause fatigue in discs due to changes in flexing amounts of the disc under vacuum. catastrophic failure will result in a turbine trip due to loss of condenser vacuum.

As- Left Alignment Readings

8Y

OC

No Comments

Return to Service Full Load Vibration/Dynamics Analysis

2Y

OC

No Comments

Turning Gear Inspection 8Y No Comments *Critical No Non -critical here means not critical but important enough to require some PM tasks. The shaded area indicates that no examples of Low Pressure Turbines could be identified for these Template conditions. If an LP Turbine was identified that corresponds to a colum in the shaded area it would be necessary to develope a Pm program, probably similar to those stated. The shaded area does not mean Run-To-Failure. PM Application Notes: "Y" designates calendar years "AR" designates as required PM Application Note 1: Rotor inspections include NDE for wheel bore cracking. Resulting turbine missle probability values calculated must be maintained within the requirements of the for turbine operation. This limitation may require LP turbine rotor wheel re-inspection prior to the next component 8year maintenance interval. If turbine missle generation probabilities support a re-inspection interval of greater than 8 years,the 8-year maximum maintenance interval will govern. This template is the controlled revision. Please refer to MA-AA-716-210 & MA-AA-716-210-1001 for additional guidance. SME Summary Revised to include Turning Gear inspection task based upon 2003 PCM Assessment item and also to include bases for tasks. One major TG component (HP, LP, or generator/exciter) is completely disassembled and inspected during every refueling outage. Boundary Definition No Boundary Definition Available At This Time Basis For Template Tasks Exhaust Hood Crawl Through Visual Inspection: Exelon experiences - Indusrty practices & OEM recommendations. Performed during every refueling outage. Visual inspection for signs of degradation of outer cylinder, flow guides, inner cylinder, thermoshield & last stage blades. Pre-Shutdown Machine Vibration/Dynamics Analysis : Historical operational/maintenance data - industry experience - OEM recommendations. Pre-Shutdown Vibration Analysis: This is a valuable tool to determine if any additional inspections are required and also allow you to monitor the effects of the maintenance after restart. This data has also been used to reduce the scope of work

110

Exhaust Hood Inspection: Historical operational/maintenance data - industry experience - OEM recommendations. Exhaust Hood Inspection: this is a visual inspection that is performed when the hood is removed. Inspect the structural supports and general overall condition for signs of erosion. Inner Cylinder Inspection: Historical operational/maintenance data - industry experience - OEM recommendations. Turbine operation can cause erosion, wear, and cracking to the inner cylinder and it's components. Remove casing and visually inspect cylinder for signs of erosion. Also inspect fit areas for signs of galling, horizontal joints for signs of steam leaks, and manway door sealing surfaces for signs of erosion. Inspect thermoshields for loose or missing parts caused by degradation from steam swirl (NOTE: loosen parts can enter the condenser below). Steam Gland Seal Inspection: Historical operational/maintenance data - industry experience - OEM recommendations. Gland cases and seals are subject to steam erosion and corrosion during turbine operation. Visually inspect the inner and outer gland cases (fluorescent magnetic particle inspection as well), the gland case horizontal joint screws, and the inner and outer gland seal rings. Oil Seal Inspection: Historical operational/maintenance data - industry experience - OEM recommendations. Under normal conditions there should be no leakage past the oil seal rings. Care must be taken, however, to ensure that the drain passages are clean and permit a free oil flow. The seals and in particular the oil drain passages should immediately be examined if an excess amount of oil is found escaping the from the bearing housing, along the rotor shaft. Steam Path Inspection: Historical operational/maintenance data - industry experience - OEM recommendations. Steam path inspection: The steam path is checked by charting of the rotor prior to removal to determine the clearances and a visual inspection is performed for signs of wear/erosion and replaced as required. Bearing & Journal Inspections: Historical operational/maintenance data - industry experience - OEM recommendations. Visual inspection of bearings and journal for signs of wear, scoring, wiping, cracking, and pitting in the babbit, caused by abnormal operating conditions such as excessive vibration and insufficient, dirty, or hot lubricating oil. Thrust Bearing Inspection: Historical operational/maintenance data - industry experience - OEM recommendations. Thrust bearings are subject to wear during turbine operation. Visually inspect babbited shoes, shoe retainer screw and clips, retainer ring thrust collar, leveling blocks, oil seal rings, and the shaft in the area of the oil seals. Rotor Inspection: Historical operational/maintenance data - industry experience - OEM recommendations. Distortion (bowing and rubbing) and cracking can occur in the rotor bodies, both of which require maintenance. Rotor blading and shrouds may be damaged by pitting or material erosion from solid particles or moisture in the steam, thermal fatigue from excessive cycling of load, vibration induced fatigue from poor steam flow or thermally induced creep from prolonged perdiods of high load service - they are susceptible to pitting, erosion, cracking, and serparation. Recommended Inspection: 1. Visually inspect the blade path 2. Dust blast and NDE 3. Visually inspect the journal and gland areas for scoring, erosion, other damage 4. Perform disc inspection Coupling Faces & Spacer Visual Inspection: Historical operational/maintenance data - industry experience - OEM recommendations. Visual and magnetic particle inspection of coupling faces for signs burrs or surface imperfections due to stresses. Bolting ( Horizontal Joint/Coupling )& Sleeve NDE: Historical operational/maintenance data - industry experience - OEM recommendations. Bolting: the bolting is cleaned and visually inspected for mechanical condition of the threads on the studs and nuts and also NDE inspected UT to verify no indications of cracking in the stud. The coupling bolts are also visually inspected for mechanical condition and NDE of the bolts and sleeves is performed MT. Rupture Disc Replacement: No Basis At This Time As- Left Alignment Readings: Historical operational/maintenance data - industry experience - OEM recommendations. As-left alignment readings: This is performed based on operation data taken during shutdown (vibration). Verify the rotor is in the same relative position during reassembly and if operation data requires an actual alignment check then perform and align as required. Oil bore clearance reading may be used based upon engineering evaluation. Return to Service Full Load Vibration/Dynamics Analysis: Historical operational/maintenance data - industry experience - OEM recommendations. Return to service Vibration data: this is to compare to the shutdown data to ensure that the work that was performed returned the equipment to the same or better operation. Turning Gear Inspection: Exelon experiences, industry practices & oEM recommendations. Visual inspection of gear train components for degradation and proper gear mesh. LaSalle experienced gear failure due to extended inspection intervals.

111

Westinghouse - Main Feedwater Pump Turbine Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe

X X

X

Mild

5

6

7

8

X

X

X

X

X X

X

X X

X

X

X

X

Condition Monitoring Task Oil Analysis Vibration Analysis

X

X X Failure Codes

Q 3M

Time Directed Task

Comments

DA MS OC

No Comments

OC

No Comments

Failure Codes

Comments No Comments

Pre-Shutdown Machine Vibration /Dynamics Analysis

2Y

OC

External Visual Inspection

M

ER FG GL IB SL

No Comments

Steam Path Inspection

8Y

AL BF CO ER FD GL GW LB OC SL

Complete Disassembly & Rebuild

Steam Valve Inspection

8Y

DE OC SL

No Comments

Control System Component Inspections

8Y

CD DE LB OC

No Comments

Diaphragm Interface Valve Rebuild

8Y

AG LD

Replace Diaphragm

Servo Valve Replacement

6Y

AG

No Comments

Steam Valve Actuator Rebuild

5Y

ER

No Comments

Bearing Oil Pump Rebuild

AR

GW

No Comments

Calibration (Pressure and Limit Switches)

AR

OC

No Comments

Steam Stop Valve Stroke Testing

M

OC

No Comments

Lube Oil Reservoir Level Alarm Testing

M

OC

No Comments

Lube Oil Pump Auto-Start Testing See Note 1

AR

OC

No Comments

Simulated Overspeed (Oil) Testing

Q

OC

No Comments

Uncoupled Actual Overspeed Testing See Note 8Y 2

OC

No Comments

Return to Service Full Load Vibration/Dynamics Analysis

2Y

OC

No Comments

Inspect Vapor Extractor

2Y

Repace Vapor Extractor Motor

8Y

AG

No Comments

Inspect Hydraulic Control Orifices

2Y

ER OR

No Comments

BF CO DA FG GL IW SL

No Comments

Servo Valve Strainer Replacement 2Y No Comments * Critical No Non-critical here means not critical but important enough to require some PM tasks. The shaded area indicates that no examples of Main Feedwater Pump Turbines could be identified for these Template conditions. If a Main Feedwater Pump Turbine was identified that corresponded to a columnin the shaded area it would be necessary to develope a PM program, probably similar to those stated. The shaded area does not mean Run-To-Failure. "Y" designates calendar year "M" designates calendar months "AR designates as required This template is the controlled revision. SME Summary Revised to: 1) Incporporate Vapor Extractor and control orifice tasks identified duing 2002 PCM Assessment activities. 2) Change DIV rebuild from 5 to 8 years 3) Include task to replace servo valve strainers every cycle. Boundary Definition No Boundary Definition Available At This Time Basis For Template Tasks Oil Analysis: No Basis At This Time Vibration Analysis: No Basis At This Time Pre-Shutdown Machine Vibration /Dynamics Analysis: No Basis At This Time

112

External Visual Inspection: No Basis At This Time Steam Path Inspection: No Basis At This Time Steam Valve Inspection: No Basis At This Time Control System Component Inspections: No Basis At This Time Diaphragm Interface Valve Rebuild: Exelon experience has identified not adverse consequences of a 6-year diaphragm replacement interval. Increased to 8-years to be consistent with turbine disassembly and control system inspections Servo Valve Replacement: No Basis At This Time Steam Valve Actuator Rebuild: Includes associated solenoid valves. Bearing Oil Pump Rebuild: No Basis At This Time Calibration (Pressure and Limit Switches): No Basis At This Time Steam Stop Valve Stroke Testing: No Basis At This Time Lube Oil Reservoir Level Alarm Testing: No Basis At This Time Lube Oil Pump Auto-Start Testing See Note 1: PM Application Note 1- Lube Oil Pump Auto-Start verification shall be performed prior to placing a Feed Pump Turbine On-line Simulated Overspeed (Oil) Testing: No Basis At This Time Uncoupled Actual Overspeed Testing See Note 2: PM Application Note 2- Actual turbine overspeed testing is required upon return to service every time a turbine dismantle inspection or maintenance on the trip mechanism is performed. Return to Service Full Load Vibration/Dynamics Analysis: No Basis At This Time Inspect Vapor Extractor: Exelon experience based upon corrective maintenance reviews identified during 2002 PCM Assessments. Repace Vapor Extractor Motor: Exelon experience based upon corrective maintenance reviews identified during 2002 PCM Assessments. Inspect Hydraulic Control Orifices: Remove and inspect for plugging based on Exelon experiences identified by corrective maintenance activities during 2002 PCM Assessment. Servo Valve Strainer Replacement: Exelon experiences to prevent servo valve failures.

113

Westinghouse - Main Generator Component Classification Categories Yes

Critical Duty Cycle

1

2

3

4

X

X

X

X

No High

Service Condition

X

Low Severe

X X

X

Mild

5

6

7

8

X

X

X

X

X X

X

X X

X

X

X X

X X

Condition Monitoring Task Pre-Shutdown Machine Vibration Dynamics Analysis

X Failure Codes Comments

2Y

OC

Time Directed Task

No Comments

Failure Codes Comments

Trend Generator End-Turn FOVF Levels

1W

High-Voltage Bushing Visual Inspection

2Y

DA LC SL

No Comments No Comments

Line and Neutral Side Flexible Link Visual Inspection

2Y

LC

No Comments

End-Turn FOVM Calibrations

2Y

No Comments

Generator Crawl Through Visual Inspections

2Y

No Comments

End-Turn FOVM Light Loss Checks

8Y

No Comments

Oil Seal Inspections

8Y

No Comments

Generator Gland Seal Maintenance

8Y

No Comments

Bearing & Journal Inspections

8Y

No Comments

Bearing Insulation Measurements

8Y

No Comments

Coupling Bolt& Sleeve NDE

8Y

No Comments

Blower Inspections

8Y

Air Gap Baffle Measurements

8Y

No Comments OC

No Comments

Coupling Faces & Nuts Visual Inspection 8Y

No Comments

Stator Bore and End-Windings Inspections

8Y

No Comments

Cooling Water Hose and Parallel Ring Visual Inspections

8Y

No Comments

Leadbox and Cooler Dome Visual Inspections

8Y

No Comments

Stator Wedge Tightness Checks

8Y

No Comments

Stator Core Tightness Checks

8Y

No Comments

Stator Electrical Tests (ElCid, Megger, Hipot, etc)

8Y

No Comments

End-Winding Support Brace Pre-Loading 8Y

Historical operational/maintenance data industry experience - OEM recommendations. To maintain acceptable end-turn vibration levels.

Stator RTD and Thermocouple Checks

8Y

No Comments

Generator Rotor Visual Inspections

8Y

No Comments

Generator Rotor Electrical Tests (PI/DC/AC/Turns/Poles)

8Y

No Comments

Generator Rotor Radial Lead Pressure Test

8Y

No Comments

As-Left Alignment Readings

8Y

OC

No Comments

Return to Service Full Load Vibration/Dynamics Analysis

2Y

OC

No Comments

Surveillance Task

Failure Codes Comments

Check for Shaft Grounding (shaft 1W No Comments voltage test) *Critical No Non- critical here means not critical but important enough to require some PM tasks. The shaded area indicates that no examples of Generators could be identified for these Template conditions. If a Generator/Exciter was idendified that corresponded to a column in the shaded area it would be necessary to develope a PM program, probably similar to those stated. The shaded area does not mean Run-To-Failure. Application Notes: "W" designates weeks. "Y" designates years. This template is the controlled revision.

114

SME Summary Revised to include task for turbine shaft voltage surveillance and also to include PM bases. Boundary Definition No Boundary Definition Available At This Time Basis For Template Tasks Pre-Shutdown Machine Vibration Dynamics Analysis: Historical operational/maintenance data - industry experience - OEM recommendations. Pre-Shutdown Vibration Analysis: This is a valuable tool to determine if any additional inspections are required and also allow you to monitor the effects of the maintenance after restart. This data has also been used to reduce the scope of work. Trend Generator End-Turn FOVF Levels: Exelon experiences - OEM recommendations. End-turn vibrations can result in fatigue failure of the coil end brazed joint causing electrical faults and potential catastrophic damage. High-Voltage Bushing Visual Inspection: Historical operational/maintenance data - industry experience - OEM recommendations. The generator bushings should be examined for any evidence of overheating, leakage or cracked porcelains. The internal ventilation passages on inner-cooled bushings should be checked for obstructions. Line and Neutral Side Flexible Link Visual Inspection: Historical operational/maintenance data - industry experience - OEM recommendations. Visual inspection for overheating. cracks and delamination. End-Turn FOVM Calibrations: Exelon experiences - OEM recommendations. End-turn vibrations can result in fatigue failure of the coil end brazed joint causing electrical faults and potential catastrophic damage. Accurate values to assess machine conditions are required based on past forced outage experiences. Generator Crawl Through Visual Inspections: Historical operational/maintenance data - industry experience - OEM recommendations. Perform a crawl through inspection of the generator per OMM 027. Visual inspection for oil intrusion, dusting, greasing, structural components and signs of looseness or degradation. End-Turn FOVM Light Loss Checks: Exelon experiences - OEM recommendations. End-turn vibrations can result in fatigue failure of the coil end brazed joint causing electrical faults and potential catestrophic damage. Accurate values to assess machine conditions are required based on past forced outage experiences. Oil Seal Inspections: Historical operational/maintenance data - industry experience - OEM recommendations. Oil seals need to be restripped. Generator Gland Seal Maintenance: Historical operational/maintenance data - industry experience - OEM recommendations. Excessive wear or clearance of the bearings or gland seal rings relative to the journal diameter may indicate the need for replacement of the gland seal ring. The gland seal rings should be checked for loosed or cracked babbit. Bearing & Journal Inspections: Historical operational/maintenance data - industry experience - OEM recommendations. Generator bearings should be inspected on the bore surface for particles of dirt or debris embedded in the babbit surface or for grooving or scoring of the babbit. When evidence of this is found, it is reommended that the entire lubrication system be flushed out and the oil cleaned. Excessive wear or clearance of the bearings or gland seal rings relative to the journal diameter mayve indicate the need for rebabitting of the bearings. Bearing Insulation Measurements: Historical operational/maintenance data - industry experience - OEM recommendations. The insulated stop dowel, bearing key insulation, and bearing support insulation should be checked for evidence of distress or cracks. The bearing seats should be checked to see that the bearings are self-aligning and ride properly in the bearing seat. Coupling Bolt& Sleeve NDE: Historical operational/maintenance data - industry experience - OEM recommendations. Bolting: the bolting is cleaned and visually inspected for mechanical condition of the threads on the studs and nuts and also NDE inspected UT to verify no indications of cracking in the stud. The coupling bolts are also visually inspected for mechanical condition and NDE of the bolts and sleeves is performed MT. Blower Inspections: Historical operational/maintenance data - industry experience - OEM recommendations. The stationary blower blade ring segments should be inspected for any damage or looseness of individual blades; looseness of the blade ring segments to the shroud and proper locking of the mounting hardward. Air Gap Baffle Measurements: Historical operational/maintenance data - industry experience - OEM recommendations. Proper clearance to generator rotor body and visual inspection for looseness or distress. Coupling Faces & Nuts Visual Inspection: Historical operational/maintenance data - industry experience - OEM recommendations. Visual and magnetic particle inspection of coupling faces for signs burrs or surface imperfections due to stresses. Stator Bore and End-Windings Inspections: Historical operational/maintenance data - industry experience - OEM recommendations. Visual inspection for overheating, looseness, dusting or greasing. Cooling Water Hose and Parallel Ring Visual Inspections: Historical operational/maintenance data - industry experience - OEM recommendations. The phase lead assemblies between the parallel rings and the stator coils should be examined for evidence of distress or overheating. The parallel ring clamping assembly and blocking between rings should be inspected for adequate tightness and evidence of looseness - which can permit undesirable vibrational frequencies and possible fatigue of the phase lead assemblies.

115

Leadbox and Cooler Dome Visual Inspections: Historical operational/maintenance data - industry experience - OEM recommendations. The generator lead box and neutral lead enclosure should be inspected for weld condition or distress, particularly if high vibration levels have been reported in these areas. Stator Wedge Tightness Checks: Historical operational/maintenance data - industry experience - OEM recommendations. Check for looseness. Stator Core Tightness Checks: Historical operational/maintenance data - industry experience - OEM recommendations. Factors which can affect the serviceability of stator cores include mechanical looseness; electrical, mechanical, or thermal degradation of the core material; damage incurred by improper disassembly and reassembly procedures; foreign objects left inside the machine. Stator Electrical Tests (ElCid, Megger, Hipot, etc): Historical operational/maintenance data - industry experience - OEM recommendations. Electrical shorts or grounds due to component degradation or insulation system breakdown. End-Winding Support Brace Pre-Loading : Historical operational/maintenance data - industry experience - OEM recommendations. Directed at identifying evidence of distress in the bracing components. Any looseness in the supports can lead to abrasion of the stator coil insulation and possible ground failure. Stator RTD and Thermocouple Checks: Historical operational/maintenance data - industry experience - OEM recommendations. These detection devices should be inspected for any distress of the element; condition of the cable connecting the detectors to the terminal board; tightness of the connections at the terminal board; insulation breakdown; and cracks or leaks in the vent tubes leading to the detector assembly. Generator Rotor Visual Inspections: Historical operational/maintenance data - industry experience - OEM recommendations. High currents may cause melting of the slot wedges and cracks to occure in the rotor body. The rotor body, its retaining rings, and its couplings should be examined for mechanical or thermal damage. Generator Rotor Electrical Tests (PI/DC/AC/Turns/Poles): Historical operational/maintenance data - industry experience - OEM recommendations. Electrical shorts or grounds due to component degradation or insulation system breakdown. Generator Rotor Radial Lead Pressure Test: Historical operational/maintenance data - industry experience - OEM recommendations. Prevention of hydrogen leaks from the generator internal environment. As-Left Alignment Readings: Historical operational/maintenance data - industry experience - OEM recommendations. As-left alignment readings: This is performed based on operation data taken during shutdown (vibration). Verify the rotor is in the same relative position during reassembly and if operation data requires an actual alignment check then perform and align as required. Return to Service Full Load Vibration/Dynamics Analysis: Historical operational/maintenance data - industry experience - OEM recommendations. Return to service Vibration data: this is to compare to the shutdown data to ensure that the work that was performed returned the equipment to the same or better operation. Check for Shaft Grounding (shaft voltage test): OEM recommendations & 2002 Dresden Front Standard failure due to electrolsis. To ensure proper electrical contact and clean dirt/glaze from copper braid surfaces.

116

Westinghouse - Turbine Governor Valve Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low

X X

Severe

X

6

7

8

X

X

X

X

X X

X

Mild

5

X X

X

X

X

Time Directed Task

X

X X

X Failure Codes

Comments

Functional Stroke Test

3M

OC

No Comments

Body/Bonnet Nuts and Washer Inspections

6Y

FD

No Comments

Body/Bonnet Gasket Sealing Area Inspection

6Y

CO ER GL SL

No Comments

Leak-off Flange Inspection

6Y

BF CO ER FD FG

No Comments

Body/Bonnet Studs NDE

6Y

CO ER OC

No Comments

Valve Seat NDE

6Y

CO DF ER OC

No Comments

Seating Contact Blue Check

6Y

DF OC

No Comments

Actuator Spring Inspection/Replacement

12Y

AG

No Comments

Muffler/Muffler Groove Inspection

6Y

ER OC

No Comments

Anti-Swirl Baffle NDE

6Y

CO ER OC

No Comments

Dash Pot Setting Measurement

6Y

OC

No Comments

Final Size Spring Actuator Stem Spacer

6Y

OC

No Comments

LVDT Alignment 6Y OC No Comments *Critical No Note Non-critical here means not critical but important enough to require some PM tasks. The shaded area indicates that no examples of Turbine Governor Valves could be identified for these Template conditions. If a governor valve was identified that corresponds to a colum in the shaded area it would be necessary to develop a PM program, probably similar to those stated. The shaded area does not mean Run-To-Failure. PM Application Notes: "M" designates months. "Y" designates years. This template is the controlled revision. SME Summary Revised to include actuator spring inspection during the 12 year interval so that complete replacement is not required pending inspection result. Boundary Definition No Boundary Definition Available At This Time Basis For Template Tasks Functional Stroke Test: No Basis At This Time Body/Bonnet Nuts and Washer Inspections: No Basis At This Time Body/Bonnet Gasket Sealing Area Inspection: No Basis At This Time Leak-off Flange Inspection: No Basis At This Time Body/Bonnet Studs NDE: No Basis At This Time Valve Seat NDE: No Basis At This Time Seating Contact Blue Check: No Basis At This Time Actuator Spring Inspection/Replacement: OEM Recommendation. Spring free length check information will indicate if relaxation or cracking conditions are present. Replacement decisions can be made based on inspection result. Muffler/Muffler Groove Inspection: No Basis At This Time Anti-Swirl Baffle NDE: No Basis At This Time Dash Pot Setting Measurement: No Basis At This Time Final Size Spring Actuator Stem Spacer: No Basis At This Time LVDT Alignment: No Basis At This Time

117

Westinghouse - Turbine Reheat Stop and Intercept Valve Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low Severe

X X

X

6

7

8

X

X

X

X

X X

X

Mild

5

X X

X

X

X

Time Directed Task

X

X X

X Failure Codes

Comments

Functional Stroke Test

1M

OC

No Comments

Valve Flange Face Inspections

8Y

BF ER OC

No Comments

Main Steam Piping Flange Inspections

8Y

BF ER OC SL

No Comments

Actuator Spring Housing Inspections

8Y

OC

No Comments

Actuator Spring Inspection

8Y

BK SPR

No Comments

Spherical Bearing Inspection

8Y

BS DL FD LB SK

No Comments

Carbon/Bellow Seal Packing Ring Replacements

8Y

AG PL SL

No Comments

Bellow Seal Gasket Replacements

8Y

GL

No Comments

Bellow Seal Insert Replacements

8Y

AG PL SC

No Comments

Component NDE 8Y CO ER OC No Comments *Critical No Non-critical here means not critical but important enough to require some PM tasks. The shaded area indicates that no examples of Turbine Reheat Stop& Intercept Valves could be identified for these Template conditions. If a reheat stop or intercept valve was identified that corresponded to a column in the shaded area it would be necessary to develope a PM program, probably similar to those stated. The shaded area does not mean Run-To-Failure. PM Application Notes: 1) "M" designates months "Y" designates years 2) It is acceptable to perform the 8Y Tasks on a 6 refueling outage interval for units on 18-month fuel cycles . This template is the controlled revision. SME Summary Revised to return testing interval from quarterly back to to monthly. Boundary Definition No Boundary Definition Available At This Time Basis For Template Tasks Functional Stroke Test: Exelon experience. Increase in sticking of the Skinner test solenoid valves was experienced at Byron/Braidwood shortly after extending the interval to quarterly. RSIV testing does not require a unit derate or inpact availability/capacity factors. Valve Flange Face Inspections: No Basis At This Time Main Steam Piping Flange Inspections: No Basis At This Time Actuator Spring Housing Inspections: No Basis At This Time Actuator Spring Inspection: No Basis At This Time Spherical Bearing Inspection: No Basis At This Time Carbon/Bellow Seal Packing Ring Replacements: No Basis At This Time Bellow Seal Gasket Replacements: No Basis At This Time Bellow Seal Insert Replacements: No Basis At This Time Component NDE: No Basis At This Time

118

Westinghouse - Turbine Throttle Valve Component Classification Categories Critical Duty Cycle Service Condition

Yes

1

2

3

4

X

X

X

X

No High

X

Low

X X

Severe

X

Mild

5

6

7

8

X

X

X

X

X X

X

X X

X

X

X

Time Directed Task

X

X X

X Failure Codes

Comments

Functional Stroke Test

3M

OC

No Comments

Body/Bonnet Nuts and Washer Inspections

6Y

FD

No Comments

Body/Bonnet Gasket Sealing Area Inspection

6Y

CO ER GL SL

No Comments

Leak-off Flange Inspection

6Y

BF CO ER FD FG

No Comments

Body/Bonnet Studs NDE

6Y

CO ER OC

No Comments

Valve Seat NDE

6Y

CO DF ER OC

No Comments

Seating Contact Blue Check

6Y

DF OC

No Comments

Pin-to-Pin Measurement

6Y

OC

No Comments

Dash Pot Setting Measurement

6Y

OC

No Comments

Actuator Spring Inspection/Replacement

12Y

AG

No Comments

LVDT Allignment 6Y OC No Comments *Critical No Non- critical here means not critical but important enough to require some PM tasks. The shaded area indicates that no examples of Turbine Throttle Valves could be identified for these Template conditions.If a throttle valve was identified that corresponded to a column in the shaded area it would be necessary to develope a PM program, probably similar to those stated. The shaded area does not mean Run-To-Failure. PM Application Notes : "M" desiginates months. "Y" designates years. This template is the controlled revision. Please refer to MA-AA-716-210 & MA-AA-716-210-1001 for additional guidance. SME Summary Revised to include actuator spring inspection during the 12 year interval so that complete replacement is not required pending inspection result. Boundary Definition No Boundary Definition Available At This Time Basis For Template Tasks Functional Stroke Test: No Basis At This Time Body/Bonnet Nuts and Washer Inspections: No Basis At This Time Body/Bonnet Gasket Sealing Area Inspection: No Basis At This Time Leak-off Flange Inspection: No Basis At This Time Body/Bonnet Studs NDE: No Basis At This Time Valve Seat NDE: No Basis At This Time Seating Contact Blue Check: No Basis At This Time Pin-to-Pin Measurement: No Basis At This Time Dash Pot Setting Measurement: No Basis At This Time Actuator Spring Inspection/Replacement: OEM Recommendation. Spring free length check information will indicate if relaxation or cracking conditions are present. Replacement decisions can be made based on inspection result. LVDT Allignment: No Basis At This Time

119