ML041610159

Questions and Responses - May 3, 2004 Summary of Telephone Conference on Between NRC & NMC Concerning Receipt of Aging Management Program Post - Audit RAIs Pertaining to Pt. Beach Nuclear Plant, Units 1 & 2, LRA

ML041610159
Person / Time
Site:	Point Beach
Issue date:	05/26/2004
From:	Morgan M NRC/NRR/DRIP/RLEP
To:	Nuclear Management Co
Morgan M, NRR/NRC/DRIP/RLEP, 415-2232
Shared Package
ML041610145	List: ML041610149 ML041610159
References
TAC MC2049, TAC MC2050
Download: ML041610159 (49)

Text

NRC Questions Responsible Response Rcd. No Quest. No Person Due Date 49 Audit 1 Bill Herrman Question Mr Faris asked: Do we ever do a pressure test of the CCW HX tubes?

Question Response We do not routinely perform pressure tests of the CCW HX tubes. It's conceivable that we we might do a tube leakage test with the SW end bell covers removed and CCW cut into the shell side if we suspected tube leakage, but this is not routinely performed.

Comment 50 Audit 1 Steve Schellin Question Inspector: Don Jarrell Date: 4-27-04*

Request: This element includes exceptions to NUREG-1801, "Generic Aging LessonsLearned (GALL)

Report,"Section XI.E2, "Electrical Cables Not Subject To 10CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits." The applicant states that: "The Cable Condition Monitoring Program only includes non-EQ electrical cables used in nuclear instrumentation circuits that are within the scope of license renewal and are installed in adverse localized environments, while the NUREG-1801 program applies to all non-EQ instrumentation circuits with sensitive, high voltage, low-level signals exposed to adverse localized environments such as radiation monitoring and nuclear instrumentation that are within the scope of license renewal."

Q1 Provide a technical justification for why all the above specified cables should not be included.

Question Response The only instrumentation circuits in-scope for license renewal with sensitive, high-voltage, low-level signals that are not EQ (they perform their safety function [reactor trip] at the start of an event) are the normal source, intermediate, and power range nuclear instrumentation (NI). These cables are included in the Cable Condition Monitoring Program. The post-accident monitoring wide range NI circuit cabling is EQ.

The cables for the radiation monitoring system instrumentation circuits with sensitive, high-voltage, low-level signals, which are exposed to adverse localized environments, that are in-scope for license renewal, are the EQ high-range radiation monitors (see Q3 response). EQ cables are managed by the EQ program Comment Friday, May 07, 2004 Page 1 of 49

Responsible Response Rcd. No Quest. No Person Due Date 51 Audit 1 Steve Schellin Question Inspector: Don Jarrell 4-27-04 Request: GALL: In this aging management program, routine calibration tests performed as part of the plant surveillance test program are used to identify the potential existence of aging degradation. When an instrumentation loop is found to be out of calibration during routine surveillance testing, trouble shooting is performed on the loop, including the instrumentation cable. The applicant proposes to eliminate the use of calibration as an indicator of the need for possible examination of cables for aging degradation based partially on experience recommendation in SAND96-0344.

Q2: Justify not using calibration trends as an indicator of potential instrumentation cable degradation. Is there a precedent for this practice?

Question Response Testing the NI cables determines the condition of the NI cable directly. Calibration results reflect performance of the entire circuit and indirectly include information on the cable, detectors, connectors, penetrations, and various electronics of the NI circuit. Therefore, it would be difficult, if not impossible, to obtain the current condition of the cable from only the calibration trend information. Furthermore, the calibration trend information would become invalid as various individual electronic components are replaced, modified, or repaired and the circuit configuration changes.

Comment 52 Audit 1 Steve Schellin Question Inspector: Don Jarrell Date: 04-27-04 Request: The applicant states that Electrical cables associated with radiation monitoring instrumentation within the scope of license renewal at PBNP are either environmentally qualified in accordance with 10 CFR 50.49 or not installed in adverse localized environments (e.g., radiation monitoring instrumentation associated with the Control Room).

Q3: The above statement needs to be verified. Explain how all radiation detector cables would either be EQ or do not run through adverse environments.

Question Response The radiation detectors within the scope of license renewal are limited to the high-range in-containment monitors, three per unit, and those radiation monitors that control the control room ventilation system configuration for post-accident conditions. The cables for the first are routed in conduit from the detectors in the containment to the containment penetrations and from these penetrations through the Primary Auxiliary Building (PAB) into the control building, where their electronics are located. All of this cable is the same and is EQ cable. The control building has a controlled environment (HVAC) for operator and electrical equipment climate control. The cables for the control room HVAC radiation monitors are within this controlled environment and the electrical equipment rooms, both of which are separate from the PAB HVAC areas and thus not subject to any adverse environments.

Comment Friday, May 07, 2004 Page 2 of 49

Responsible Response Rcd. No Quest. No Person Due Date 53 Audit 1 Steve Schellin Question Inspector: Don Jarrell Date: 04-27-04 Request: Manhole flooding and groundwater intrusion has been a long standing issue at PBNP and efforts were periodically taken to reduce the exposure of medium-voltage cables to water. In order to better understand the magnitude of the groundwater intrusion problem into the electrical manholes, a new call-up to inspect and pump the flooded manholes was initiated. The new call-up periodically inspects and pumps down the electrical manholes, as necessary. As part of the new call-up, the approximate water level in each manhole is recorded. The recording of the water level will provide the basis for any future changes in frequency to the call-up and any deletion of manhole inspections.

Q4: State the technical justification for changing the more than a few days to more than a few years with regard to the definition of prolonged exposure to significant moisture in your application.

Question Response Operating experience at Point Beach Nuclear Plant (PBNP) has shown that medium-voltage cables exposed to significant moisture for over 33 years have not degraded. Recent testing of these cables confirms that operating experience. All purchase orders for these cables were specified for direct burial.

To ensure that cables are not exposed to significant moisture for more than a few days it would be necessary to have a manhole inspection frequency equal to or less than that period. This is both impractical and not feasible in a seasonal climate such as experienced at PBNP. The monthly inspection period, and any as-found conditions requiring remediation actions, will limit exposure to significant moisture and address the expected annual fluctuations in ground water levels. In addition, a significant portion of the 13.8K VAC System cabling was installed in the late 1980s when that system was upgraded post-TMI. Those cables were made using more recent manufacturing methods and materials than the original plant medium-voltage cables. They will not reach even a 40-year exposure until halfway through the period of the extended license.

As stated in the scope of the PBD: "In order to better understand the magnitude of the groundwater intrusion problem into the electrical manholes, a new call-up to inspect and pump the flooded manholes was initiated. The new call-up periodically inspects and pumps down the electrical manholes, as necessary. As part of the new call-up, the approximate water level in each manhole is recorded. The recording of the water level will provide the basis for any future changes in frequency to the call-up and any deletion of manhole inspections."

Comment Friday, May 07, 2004 Page 3 of 49

Responsible Response Rcd. No Quest. No Person Due Date 54 Audit 1 Steve Schellin Question Inspector: Don Jarrell Date: 04-27-04 Request: GALL: A representative sample of accessible electrical cables and connections installed in adverse localized environments are visually inspected for cable and connection jacket surface anomalies, such as embrittlement, discoloration, cracking, or surface contamination. The technical basis for the sample selected is to be provided.The applicant states that: A representative sample of accessible electrical cables and connections installed in adverse localized environments are visually inspected for cable and connection jacket surface anomalies, such as discoloration, swelling, cracking, or surface contamination. This sample is based on the severity of the adverse localized environment, as compared to the plant design environment, and other criteria such as accessibility, availability, importance-to-safety, and/or prior inspection results.

Q8: What is the technical basis for the accessible electrical cables and connections installed in adverse localized environments sample selection and size?

Question Response The Cable Condition Monitoring Program has not yet been written and the technical basis will be determined at a later date when that work is performed. However, A representative sample will be chosen based on selection criteria based on the primary stressor(s) of concern [as noted in SAND96-0344, Section 6.3.3, Step 1], and on a standard statistical basis to be representative of accessible cables and plant areas in-scope for license renewal.

Comment 55 Audit 1 Steve Schellin Question Inspector: Don Jarrell Date: 04-27-04 Request: Exception to GALL: The applicant intends to test a sample of medium-voltage cables rather than test them all as is implied in the GALL report. The applicant states that: Medium-voltage cables at PBNP were ordered moisture resistant for direct buried or underground service, but are not used in direct buried applications. Medium-voltage cables used at PBNP are installed in conduit, duct packs/banks, or manholes, which provide a flow path to drain water (e.g., duct packs/banks are sloped). Further the applicant states that: Major portions of the higher medium-voltage (13.8K VAC) cables used at PBNP, which are more susceptible to water treeing, were replaced in 1988 with cables ordered moisture resistant for direct buried or underground service. In addition, the 13.8K VAC cables subject to submergence were successfully tested in 2003 using the Energized Partial Discharge Testing Methodology.

Q10: The medium voltage cables are still subjected to significant moisture as defined in GALL. What is the justification for going to sampling rather than full inspection? Are there precedents for sampling as stated above rather than inclusive testing for Medium-voltage cables?

Question Response Sampling is a valid method for determining the condition of a population of cables. Sampling is the accepted method for determining the condition of a large group of cables per the E1 GALL program and thus should be equally applicable for E3. Not all cables need to be tested in order to assess the condition of cables of the same or similar loading, materials, and construction in the same or similar environments.

In addition, not all medium-voltage cables are exposed to significant moisture since major portions of the 4160 VAC system are contained entirely within site buildings and may be accessible for visual inspection.

Comment Friday, May 07, 2004 Page 4 of 49

Responsible Response Rcd. No Quest. No Person Due Date 56 Audit 1 Steve Schellin Question Inspector: Don Jarrell Date: 04-27-04 Request: GALL: Operating experience has shown that adverse localized environments caused by heat or radiation for electrical cables and connections may exist next to or above (within three feet of) steam generators, pressurizers or hot process pipes, such as feedwater lines. These adverse localized environments have been found to cause degradation of the insulating materials on electrical cables and connections that is visually observable, such as color changes or surface cracking. These visual indications can be used as indicators of degradation. The applicant bases some actions (E2) on: Industry operating experience has also shown that visual inspections of non-EQ instrumentation circuit cables within the scope of license renewal are adequate to identify aging degradation, as documented in SAND96-0344, Aging Management Guideline for Commercial Nuclear Power Plants - Electrical Cable and Terminations. The applicant stated that: Electrical cables associated with radiation monitoring instrumentation within the scope of license renewal at PBNP are either environmentally qualified in accordance with 10 CFR 50.49 or not installed in adverse localized environments (e.g., radiation monitoring instrumentation associated with the Control Room).

Q13: How did you verify that statement as accurate in view of the plant layout?

Question Response The radiation detectors within the scope of license renewal are limited to the high-range in-containment monitors, three per unit, and those radiation monitors that control the control room ventilation system configuration for post-accident conditions. The cables for the first are routed in conduit from the detectors in the containment to the containment penetrations and from these penetrations through the Primary Auxiliary Building (PAB) into the control building, where their electronics are located. All of this cable is the same and is EQ cable. The control building has a controlled environment (HVAC) for operator and electrical equipment climate control. The cables for the control room HVAC radiation monitors are within this controlled environment and the electrical equipment rooms, both of which are separate from the PAB HVAC areas and thus not subject to any adverse environments.

Comment 57 Audit 1 Todd Mielke Question Inspector: Don Jarrell Date: 04-27-04 Request: Q1: All aboveground tanks were declared to be painted or coated. The two new (1994) diesel fuel oil storage tanks are encased in a plastic shell with an annulus between the tank and shell, and the tanks are both buried underground (and encased in concrete). The probability of significant tank exterior moisture for these new tanks is remote. What is the frequency of moisture accumulation checks on the tank to liner annulus? A liner has also been placed inside the tank to prevent interior corrosion that precludes ultrasonic thickness measurements on the tank bottom. Is a tank liquid bottom sample taken to look for water and corrosion products? Frequency?

Question Response Our assertion is that there is no aging effect on the exterior of these tanks, due to being encased in concrete. The lining is there as a fuel oil containment lining. This annulus is checked weekly (via PC 21 Part 4) to check for oil in the annulus.There is a coating (AMERCOAT 395) inside the below ground fuel oil storage tanks (T-175A&B). The oil is sampled quarterly per procedure TS-80. This sample is checked for water at the bottom of the tank, and is also analyzed for particulate and stability. This is all part of the Fuel Oil Chemistry Program, LR-AMP-002-FOCHEM.

Comment Friday, May 07, 2004 Page 5 of 49

Responsible Response Rcd. No Quest. No Person Due Date 58 Audit 1 Todd Mielke Question Inspector: Don Jarrell Date: 04-27-04 Request: The PBNP LRA states that caulking is not used at the interface edge between the tank and the concrete foundation for the Condensate Storage Tanks and above ground Fuel Oil Storage Tanks. This program credits the Tank Internal Inspection Program for thickness measurements of the inaccessible portions of Condensate Storage Tanks external surfaces (i.e., tank bottoms). Thickness measurements of the bottom of the above ground Fuel Oil Storage Tanks were performed in August of 2000 with no significant loss of material detected. GALL states that caulking or sealant in this manner is required to achieve the objective of mitigating corrosion.

Q3: Justify not using caulking based on

1) the lack of existing corrosion after 30+ years (specific as found loss fraction - can be + if documented) and

2) the level of assurance that the tank environmental conditions could not change and accelerate the corrosion rate.

Question Response We identified that there was no caulking between the tank and the concrete which could mitigate the aging effects on the bottom of the tank from the outside.

Therefore, we would need to monitor the thickness using UT measurements from within the tanks. This applies to two sets of tanks; 1) Above ground fuel oil storage tanks (T-32A&B) and 2) Condensate Storage tanks (T-24A&B)

1) T-32A&B are outdoor tanks, and were part of original construction. The tank bottoms were UT inspected in Aug. 2000. The original nominal thickness was 1/4". UT results varied from approximately

.260 to .270, which indicates that after the 30+ years that these tanks have been installed, we are currently above the BOL nominal thickness. Subsequent to these UT measurements, a polyester resin coating was installed inside the tank on the tank bottom and about 2 feet up the tank wall. No future UT measurements are deemed necessary due to no material loss detected over the first 30+ years of operation, we expect no environmental change in the next 30 years, and that the coating would need to be destroyed in order to do any future UT measurements.

2) T-24A&B are indoor tanks, and were part of original construction. Since no caulking is installed on these tanks, the bottoms will need to UT inspected to ensure no degradation is occurring. These tank bottoms will be inspected as part of the Tank Internals Inspection Program.

Comment Friday, May 07, 2004 Page 6 of 49

Responsible Response Rcd. No Quest. No Person Due Date 59 Audit 1 Todd Mielke Question Inspector: Don Jarrell Date: 04-27-04 Request: GALL states that: Periodic system walkdowns to confirm that the paint, coating, sealant, and caulking are intact is an effective method to manage the effects of corrosion on the external surface of the component. However, corrosion may occur at inaccessible locations, such as the tank bottom surface, and thickness measurement of the tank bottom is to be taken to ensure that significant degradation is not occurring and the component intended function will be maintained during the extended period of operation.In this section the PBNP LRA notes the "exception to the NUREG-1801 program is that thickness measurements of the inaccessible external surfaces (i.e., tank bottoms) of the above ground Fuel Oil Storage Tanks are not performed". The document adds that the reason for this is the recent thickness testing and refurbishment of the tanks with the addition of a polyester interior coating. Q4:

Although the fuel oil storage tanks have been thickness tested and coating added, the integrity of that coating and tanks must be monitored per GALL, or the justification for not meeting the programmatic requirements must be stated. State the justification for the above ground Fuel Oil Storage tank bottom inspections not meeting the GALL requirements. Will the internal bottoms of these tanks be visually inspected or sampled for water or corrosion?

Question Response T-32A&B are outdoor tanks, and were part of original construction. The tank bottoms were UT inspected in Aug. 2000. The original nominal thickness was 1/4". UT results varied from approximately .260 to .270, which indicates that after the 30+ years that these tanks have been installed, we are currently above the BOL nominal thickness. Subsequent to these UT measurements, a polyester resin coating was installed inside the tank on the tank bottom and about 2 feet up the tank wall. No future UT measurements are deemed necessary due to no material loss detected over the first 30+ years of operation, we dont expect the environment to change, and that the coating would need to be destroyed in order to do any future UT measurements.

The coating will protect the inside surface of the tank, but truly has no bearing on the external surface, other than the fact that the coating would need to be removed to do UT measurements. Therefore, inspections of the coating are not necessary to manage the external bottom of the tank, and the justification above deems future inspections of the external bottom to be unnecessary.

The internal bottom of the tank will be age managed by the Fuel Oil Chemistry Program.

Comment 60 Audit 1 Bill Herrman Question Inspector - Kent Faris 4/28/04 Request: There doesn't appear to be FAIs and/or activities in the OTINSP AMP in all of the identified LR system discussed in the LRH program description.

Question Response The association with the listed LR system was based on the possibility of needing the One-Time Inspection AMP for aging management. There is a possibility that some of the listed LR systems will not have an associated one-time inspection activity.

Comment Friday, May 07, 2004 Page 7 of 49

Responsible Response Rcd. No Quest. No Person Due Date 61 Audit 1 Bill Herrman Question Inspector - Kent Faris 4/28/04 Request - Explain the justification for combining the one-time and selective leaching GALL programs into the PBNP one-time Inspection AMP.

Question Response We do not expect to see much, if any selective leaching at PBNP. Therefore, we did not believe that a separate selective leaching AMP was warranted. If any selective leaching is identified, we will address it as needed.

Comment 62 Audit 1 Bill Herrman Question Inspector - Kent Faris 4/28/04 Request - Why doesn't the OTINSP program include neoprene? (Other sites have included this.)

Question Response There are no aging effects requiring management associated with neoprene. This is supported by plant Operating Experience.

Comment Friday, May 07, 2004 Page 8 of 49

Responsible Response Rcd. No Quest. No Person Due Date 63 Audit 1 Bill Herrman Question Inspector: Kent Faris Date: 4/28/04 Request: PBNP LRA Appendix B, AMP B2.1.13, One-Time Inspection Program, and LR-AMP-024-OTINSP, One-Time Inspection Program Basis Document for License Renewal, Rev 2, 4/14/2004, Section 4.0, Description of the Aging Management Program, pages 9-11, describes in general terms a methodology for performing one-time inspections. This description includes the identification of program elements for defining specific criteria for:*

Determination of appropriate inspection sample size,

• Identification of inspection locations,

• Selection of examination techniques,

• Acceptance criteria,

• Evaluation of test results to determine the need for additional inspections and other corrective actions, and

• Determination where the most severe aging effects would be expected to occur.

NUREG 1801, XI.M32, One-Time Inspection, Section 1, Scope of Program, recommends, "The program includes measures to verify that unacceptable degradation is not occurring, thereby validating the effectiveness of existing AMPs or confirming that there is no need to manage aging-related degradation for the period of extended operation." Section 3, Parameters Monitored, recommends, "The program monitors parameters directly related to the degradation of a component." NUREG 1801, XI.M32, Section 4, Detection of Aging Effects, further recommends, "The inspection includes representative sample of the system population, and where practical, focus on bounding or lead components most susceptible to aging due to time in service, severity of operating conditions, and lowest design margin." The One-Time Inspection Program Basis Document for License Renewal, Attachment 2, lists 24, yet to be written, implementing procedures which will define the specifics details of key program elements, described above, as they apply to managing the aging effects to various components in the 18 specified systems per AMP, B2.1.13, page B-135. Without the information that defines key program elements and the basis for its inclusion, which will be contained in the above 24 procedure, project team cannot determine if PBNP meets the intent of NUREG 1801, as defined in paragraph 2 above. Furthermore, the lack of this key element information and its basis prevents project team from ascertaining the acceptability of the exceptions to NUREG 1801 as defined by AMP B2.1.13.Provide a description of the methodology PBNP will use for defining specific criteria for:*

Determination of appropriate inspection sample size,

• Identification of inspection locations,

• Selection of examination techniques,

• Acceptance criteria,

• Evaluation of test results to determine the need for additional inspections and other corrective actions, and

• Determination where the most severe aging effects would be expected to occur.

Question Response The question is looking for more specific information as to the methodology that will be the basis behind selection criteria for individual inspections under the One-Time Inspection Program. We consider this to be detail that will be developed during the implementation phase. We will use the general guidance already delineated in the program description, but the methodology on how that will be done has not been developed yet. Please see Reference Plant SER, Section 3.0.3.7 on their One-Time Inspection Program.

The Staff Evaluation sub-section 3.0.3.7.2 concludes that the staff found their program acceptable. The Reference Plant program does not provide the further methodology details requested in this question, and is essentially the same as described in the PBNP One-Time Inspection Program.

Comment Friday, May 07, 2004 Page 9 of 49

Responsible Response Rcd. No Quest. No Person Due Date 64 Audit 1 Mark Ortmayer Question Inspector: Don Jarrell Date: 04-27-04 Request: This element includes exceptions to the corresponding NUREG-1801 aging management program element. The NUREG-1801 program description states that "Certain accelerated samples are tested every two years." The Boraflex Monitoring Program performs these tests at a minimum frequency of five years. Two SFP storage locations had received freshly discharged spent fuel assemblies each refueling for approximately 9 years, which has caused accelerated cumulative exposure levels to the bordering Boraflex panels. Four of these panels are tested during each scheduled surveillance. The results of the Boraflex areal density testing and Boraflex panel blackness testing are evaluated as part of the Boraflex Monitoring Program to determine if a change in test frequency or methodology is warranted.

Therefore, PBNP meets the intent of this NUREG-1801 aging management program element.

Q2 Is the intent of the enhanced 5 year inspections and criticality monitoring to render the 2 year inspection of coupons unnecessary? If so justify this approach with supporting analysis.

(Q3: What is the technical justification for dropping the two year coupon testing?)

Question Response In April of 1989, PBNP submitted a surveillance program to the NRC - which they approved in February 1990 - establishing blackness testing on 10 full length boraflex panels. Four of the panels included accelerated exposure - having received freshly discharged fuel assemblies during the previous 9 years, thereby receiving an accelerated gamma dose of 1.5E10 rads, which is equivalent to that received by the average panel in 30 years. Subsequent boraflex panel blackness testing has been performed/completed in August 1991, September 1996, and August 2001.PBNPs current licensing basis is such that we do not perform testing of "accelerated samples", however, as noted above, a number of full length panels are subjected to accelerated exposure.

Comment Friday, May 07, 2004 Page 10 of 49

Responsible Response Rcd. No Quest. No Person Due Date 65 Audit 1 Mark Ortmayer Question Inspector: Don Jarrell Date: 04-27-04 Request: Discussion: GALL: The periodic inspection measurements and analysis are to be compared to values of previous measurements and analysis to provide a continuing level of data for trend analysis.The applicant states: "A new procedure will be created for trending and analysis of the results of the Spent Fuel Pool silica sampling by using the EPRI RACKLIFE predictive code or its equivalent, and determination of panels with "accelerated" exposure during the period of extended operation. The results of this trending and analysis will be evaluated to determine if a change in Boraflex areal density test frequency or methodology is warranted. This element is consistent with the corresponding NUREG-1801 aging management program element."

It appears that the applicant is utilizing the silica level in the SFP as a correlation parameter with the damage that can be expected in the Boraflex and has (will) created a program to provide this correlation.

If so, this is an enhancement with the stated GALL monitoring and trending requirements.The experience with Boraflex panels indicates that coupon surveillance programs are not reliable. Therefore, Boraflex integrity is measured and correlated, through a predictive code, with the silica levels in the pool water during the period of extended operation.Additional statement: "The Boraflex Monitoring Program determines the amount of boron carbide released from the Boraflex panels in the spent fuel pool, by direct measurement of boron areal density and subsequent correlation with the levels of silica present through the use of a predictive code."

Q4: Will you use the silica trend as a trigger to cause blackness and areal density testing (in addition to the 5 year requirement) to be performed?

Question Response The current frequency for blackness and areal density testing is every five years. If the SFP silica sampling and trending indicates a boron areal density depletion trend to a value less than the acceptance criteria - maintaining the 5% subcriticality margin - then an evaluation will be performed, which may include the frequency for blackness and areal density testing being adjusted.

Comment Friday, May 07, 2004 Page 11 of 49

Responsible Response Rcd. No Quest. No Person Due Date 66 Audit 1 Mark Ortmayer Question Inspector: Don Jarrell Date: 04-27-04 Request: GALL: The frequency of the inspection and testing depends on the condition of the Boraflex, with a maximum of five years. Certain accelerated samples are tested every two years. Results based on test coupons have been found to be unreliable in determining the degree to which the actual Boraflex panels have been degraded. Therefore, this AMP includes: (1) performing neutron attenuation testing, called blackness testing, to determine gap formation in Boraflex panels; (2) completing sampling and analysis for silica levels in the spent fuel pool water and (3) trending the results by using the EPRI RACKLIFE predictive code or its equivalent on a monthly, quarterly, or annual basis (depending on Boraflex panel condition); and (4) measuring boron areal density by techniques such as the BADGER device. The applicant states that "The Boraflex Monitoring Program manages aging effects for the Boraflex material in the spent fuel racks. This program provides for

1) blackness testing and

2) areal density measurements of the Boraflex material in the spent fuel storage racks to confirm the in-service Boraflex performance. In addition,

3) tracking of the spent fuel pool silica levels provides a qualitative indication of boron carbide loss. The results of silica sampling will be trended and analyzed using a

4) predictive code. Neutron attenuation or blackness testing will be performed to determine gap formation, while areal density measurements will be used to ascertain the physical loss of boron carbide. 5)

Monitoring and analysis of criticality will also be performed to assure that the required 5% sub criticality margin is maintained. Based on the results of these inspections and analysis, appropriate measures will be taken to ensure the Boraflex will continue to perform its intended function. This program addresses the concerns described in NRC GL 96-04."

Q1: Applicant item 5 Monitoring and analysis of criticality appears to be an enhancement to the GALL requirements. What does it consist of, what is the advantage and why is it required?

Question Response From the results of the blackness testing, a calculation/analysis of the criticality margin is performed to ensure the 5% sub-criticality margin is met.Technical Specifications 3.7.12,Spent Fuel Pool Storage, addresses fuel assembly storage in the spent fuel pool. The wording will be revised.

Comment A commitment to include changes in an annual update to be considered here.

Friday, May 07, 2004 Page 12 of 49

Responsible Response Rcd. No Quest. No Person Due Date 67 Audit 1 John Thorgersen Question Inspector: T. Taylor Date: April 29, 2004 Request: During the review of the applicants AMP programs for CASS, it was determined that Point Beach used an analysis approach provided in a staff approved Westinghouse report titled "Aging Management Evaluation for Class 1 Piping and associated Pressure Boundary Components: WCAP-14575-A. Using the analysis methods provided by this document Point Beach determined that an AMP corresponding to NUREG-1801 AMP XI. M12 was not applicable. However, there is no linkage in the Appendix B LRA Table titled "B2.0 AGING MANAGEMENT PROGRAMS CORRELATION" to indicate that the analysis was conducted in Section 4.0. Does Point Beach plan to revise the LRA Table to indicate where a reviewer can find the analysis that Point Beach conducted for its CASS material?

Question Response PBNP LRA, Appendix B, Section B2.0, "Aging Management Programs Correlation," provides a table correlating the NUREG-1801 aging management programs to the PBNP programs. The explanation in this table as to why PBNP does not need an aging management program for thermal aging embrittlement of cast austentic stainless steel (CASS) that correlates to NUREG-1801,Section XI.M12 will be updated during the next annual update of the PBNP LRA to include a reference to PBNP LRA Sections 4.4.3 and 4.4.4 to indicate where a reviewer can find the analysis that PBNP conducted for its CASS material.

Comment A commitment to add this information to the LRA annual update to be considered.

Friday, May 07, 2004 Page 13 of 49

Responsible Response Rcd. No Quest. No Person Due Date 68 Audit 1 Jim Knorr Question Inspector: Mark Lintz Date: 04/29/04 Request: The NRC staff has traditionally used the term "enhancement" to identify those actions that make an aging management program (AMP) consistent with NUREG-1801 (GALL), and so uses this term in the audit plan. These actions are generally additionally identified as commitments by a license renewal applicant to the NRC.The term "enhancement", as used in all AMPs described in the Point Beach Nuclear Plant (PBNP) license renewal application (LRA), seems to be used with additional meanings. Based on conversations with PBNP staff, NRC staff has determined that the term "enhancement" seems to mean any one of the following.

1. An action that makes an AMP consistent with GALL

2. A new AMP or implementing program

3. A small and inconsequential change to an existing AMP The NRC staff cannot determine which one of the above meanings is to be applied when the term "enhancement" is found, in any given case, and so needs to know how to interpret this term.

1. Please clarify how the term "enhancement" is used, i.e., what meaning is intended, in consistent with GALL and plant-specific AMPs in the PBNP LRA.

2. Please provide information to describe how NRC staff can determine which meaning is intended.

3. Please clarify how associated commitments are identified.

4. Please clarify how these associated commitments are to be treated.

5. Please cite where these associated commitments are identified.

Question Response The term enhancement is used in the Enhancement summary statement at the beginning of each Aging Management Program description in Appendix B of the License Renewal Application.

These enhancements are required to satisfy the NUREG-1801 aging management program and/or Standard Review Plan requirements. The statement is used in the application to indicate those items that are needed to bring the AMP to the standard assumed in NUREG-1801 or the LR-SRP.

Associated commitments are listed at present in the commitment attachment to the License Renewal Application cover letter, The specific Application Commitments will be refined as part of the final list of commitments provided to the NRC prior to the issuance of the SER.

Each of the identified commitments will be completed prior to the period of extended operation unless otherwise noted in the commitment list Comment We believe the information in the Application is sufficient with this additionalinformation and therefore supplemental information on the docket will not be requiredt.

Friday, May 07, 2004 Page 14 of 49

Responsible Response Rcd. No Quest. No Person Due Date 69 Audit 1 John Thorgersen Question Inspector: Mark Lintz Date: 04/29/04 Request: In the Program description of Section B2.1.15 to Appendix B contained in the Point Beach LRA it states:" The Periodic Surveillance and Preventive Maintenance Program is an existing plant-specific program that manages aging effects for certain SSCs within the scope of license renewal. The program provides for inspection, examination, or testing of selected structures and components, including fasteners, for evidence of age-related degradation on a specified frequency based on operating experience or other requirements (e.g., Technical Specification or code requirements). Additionally, the program provides for replacement of certain components on a specified frequency based on operating experience. The Periodic Surveillance and Preventive Maintenance Program is also used to verify the effectiveness of other aging management programs.

It should be noted that surveillance and preventive maintenance activities associated with another aging management program are evaluated and identified as an implementing document as part of that program.

However, they are also subject to the applicable requirements and controls of the Periodic Surveillance and Preventive Maintenance Program, including the constraints placed on deferrals, cancellations, and frequency changes. [Control function]

Various surveillance and preventive maintenance activities are relied on to replace or manage the age-related degradation of structures and components within the scope of license renewal. The frequency of these predefined/recurring surveillance and preventive maintenance activities are specified by callups maintained in the Computerized History and Maintenance Planning System (CHAMPS). CHAMPS is a computer based program in which records of work performed on plant SSCs are initiated and managed. (It should be noted that CHAMPS is scheduled for replacement with a similar maintenance management system called EMPAC.)

Individual surveillance and preventive maintenance Work Orders for callups performed at regular intervals are forecast in CHAMPS from the controlled master callup files to support the long range scheduling of these requirements. Work Orders are records created in CHAMPS to assign, manage, track the status, and identify the scope of work. The work scope is identified directly by the callup or through reference to applicable Work Plans, drawings and approved procedures. Work Plans provide a formatted description of the work scope to be performed in implementing an activity."

Based on discussions with Point Beach personnel, this description does not clearly convey the scope and purpose of this aging management program (AMP). Based on discussions with Point Beach personnel, it is the NRC staffs understanding that this AMP has two functions, which are to provide:*

control criteria for 23 of the 27 AMPs listed in Appendix B of the LRA, and

• explicit action statements for certain components in the scope of license renewal These action statements have one or the other of the following purposes:

Identifies a replacement interval that is used as a basis for declaring that an aging management review (AMR) is not needed for the component.

Define maintenance or inspection activities to define the aging management program for specific components listed in the LRA Table 2s. (It was stated that this AMP was a catch-all repository for aging management actions that did not fit into other AMPs.)

Furthermore, NRC understood that if an AMR (Table 2) line item contained multiple AMPs that the associated AMP(s) would be expected to contained all the necessary aging management actions.

Therefore, the only B.2.1.15 attribute applicable to this associated AMP was the control function (Identified as [Control function] in the above quote.) The staff believes that the AMP does not provide clarity about how and when various portions of it are applied in each application.

The AMP scope and process is further obscured with use of vague terms such as "various surveillance and preventive maintenance activities", "selected structures and components", "callups", etc., that would not be well understood by the public or an uninitiated technical reviewer.

Please confirm or correct our understanding of the function and limits of the AMP.

In addition, please provide a clearly worded statement demonstrating:*

How this AMP relates to specific AMPs (i.e., by specific AMP number), including the scope of its relationship*

How an individual reading the AMP would identify specific inspection or replacement activities applicable to a specific AMR line item.*

The more precise meaning of vague terms in the AMP, such as "license renewal perspective based",

Friday, May 07, 2004 Page 15 of 49

Responsible Response Rcd. No Quest. No Person Due Date "callup", etc.

The NRC staff is continuing its audit of the B.2.1.15 AMP, and anticipates having additional questions to assure compliance with 10 CFR 54.21(a)(3).

Question Response In general, aging management programs are made up of distinct aging management activities that are performed in accordance with various plant implementing documents (e.g., procedures). These plant implementing documents provide the administrative controls for performing the aging management activity. Some of these activities may be required by the plant technical specifications (e.g., surveillance requirements), while others implement actions to maintain plant equipment based on manufacturer recommendations and good practices (e.g., preventive maintenance). Various surveillance and preventive maintenance activities have been credited and are relied on to replace or manage the age-related degradation of structures and components within the scope of license renewal at PBNP. These aging management activities are performed on a specified frequency or periodicity based on operating experience or other requirements (e.g., technical specifications, code requirements).

The frequency of these predefined/recurring surveillance and preventive maintenance activities are specified by call-ups maintained in the Computerized History and Maintenance Planning System (CHAMPS) at PBNP. Call-ups are another type of implementing document credited for license renewal at PBNP. Call-ups can be stand alone documents that contain all of the steps necessary to perform an aging management activity, simply reference other plant implementing documents (e.g., procedures), or a combination of the above. CHAMPS is a computer based program in which records of work performed on plant systems, structures and components (SSC) are initiated and managed. CHAMPS also maintains a record of the frequencies and provides a work planning tool for these call-ups.

Individual surveillance and preventive maintenance Work Orders for call-ups performed at regular intervals are forecast in CHAMPS from the controlled master call-up files to support the long range scheduling of these activities. Work Orders are records created in CHAMPS to assign, manage, track the status, and identify the scope of work. The work scope is identified directly by the call-up or through reference to applicable Work Plans, drawings, and approved procedures. Work Plans provide a formatted description of the work scope to be performed in implementing the activity.

The Periodic Surveillance and Preventive Maintenance Program provides the following:

1. Control criteria for aging management activities defined by call-ups credited in the Periodic Surveillance and Preventive Maintenance Program and 23 other aging management programs identified in Appendix B of the PBNP LRA.

2. A description of the activities defined by call-ups for certain structures and components within the scope of license renewal credited directly by the Periodic Surveillance and Preventive Maintenance Program.

These activities include:

• Replacement activities with a specified interval that are used as a basis for declaring that an aging management review (AMR) is not required in accordance with 10 CFR 54.21(a)(1).

• Aging management activities that ensure the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation in accordance with 10 CFR 54.21(a)(3).

A list of the 23 other aging management programs in Appendix B of the PBNP LRA that credit the Periodic Surveillance and Preventive Maintenance Program is provided in Table 1. As stated above, the Periodic Surveillance and Preventive Maintenance Program provides control criteria for aging management activities defined by call-ups credited by these programs. Aging management activities defined by call-ups are subject to the constraints described below regarding frequency changes, deferrals, and cancellations, and plant procedures will be revised accordingly to ensure that these requirements are met.

Surveillance and preventive maintenance activities (i.e., call-ups) credited for license renewal shall be completed within a grace period of 125% of their assigned interval, not to exceed 2 years. The frequency of surveillance and preventive maintenance activities that are credited for license renewal may be adjusted, or the activity deferred or canceled provided an evaluation is performed justifying the change from a license renewal perspective based on plant and industry operating experience. This evaluation will Friday, May 07, 2004 Page 16 of 49

Responsible Response Rcd. No Quest. No Person Due Date ensure that the effects of aging will be adequately managed so that the intended function(s) of structures and components within the scope of license renewal will be maintained consistent with the current licensing basis for the period of extended operation in accordance with 10 CFR 54.21(a)(3). An Action Request will be initiated for any surveillance or preventive maintenance activity credited for license renewal that is not completed within its allowed grace period, unless the activity has been properly deferred or cancelled.

The majority of surveillance and preventive maintenance activities (i.e., call-ups) are credited by aging management programs other than the Periodic Surveillance and Preventive Maintenance Program (Table 1). This was done in order to be consistent with the program usage identified in NUREG-1801, "Generic Aging Lessons Learned (GALL) Report." These surveillance and preventive maintenance activities are evaluated as a part of these other programs. As a result, the ten elements described in Appendix B of the PBNP LRA for these other programs contain all of the details relative to these aging management activities. Therefore, when one of these other programs is referenced in a specific AMR line item in the 3.x.2 tables in Section 3.0 of the PBNP LRA, the details of the aging management activities are fully described in Appendix B of the PBNP LRA for the corresponding program. Although the ten elements of the Periodic Surveillance and Preventive Maintenance Program are written to be applicable to any surveillance or preventive maintenance activity, it is primarily the constraints placed on deferrals, cancellations, and frequency changes (i.e., control function) that applies to these other programs.

The remaining surveillance and preventive maintenance activities (i.e., call-ups) are directly credited by the Periodic Surveillance and Preventive Maintenance Program. These activities are either replacement activities or aging management activities that could not be correlated to another aging management program. Components that are replaced on a specified interval (e.g., relief valves) do not require an AMR in accordance with 10 CFR 54.21(a)(1). In general, the effects of aging on a component are cumulative throughout its installed service life. One way to effectively mitigate these aging effects is to periodically replace the component on a specified interval to prevent age-related degradation leading to a loss of intended function. When a component is replaced in accordance with a specified time period, it is assumed that an appropriate replacement interval is established. In such cases, there is a high likelihood that the detrimental effects of aging will not accumulate during the replacement interval such that there is a loss of intended function, and therefore, no aging management is required. However, should a component no longer be replaced on a specified time period aging management would be required.

Therefore, these replacement activities were identified as part of the Periodic Surveillance and Preventive Maintenance Program so that they could be flagged as requiring replacement on a specified frequency based on operating experience. If the replacement is discontinued, an AMR must be performed and an aging management program credited, if appropriate.

The surveillance and preventive maintenance activities (i.e., call-ups) directly credited by the Periodic Surveillance and Preventive Maintenance Program for aging management are a collection of call-ups that could not be correlated to another aging management program. The AMR line items in the 3.x.2 tables in Section 3.0 of the PBNP LRA identify the component types, materials, environments, and aging effects being directly managed by the Periodic Surveillance and Preventive Maintenance Program. The surveillance and preventive maintenance activities that manage these aging effects are described in the ten elements of the Periodic Surveillance and Preventive Maintenance Program presented in Section B2.1.15 of Appendix B to the PBNP LRA. The ten elements of the Periodic Surveillance and Preventive Maintenance Program are written to be applicable to any surveillance and preventive maintenance activity, including the constraints placed on deferrals, cancellations, and frequency changes (i.e., control function).

The level of detail presented in the ten elements of the Periodic Surveillance and Preventive Maintenance Program is consistent with the level of detail provided in the Reference Plant LRA (Section B2.1.23) and found acceptable by the NRC in the Reference Plant SER (Section 3.0.3.8), which is cited here as precedence. Additional details of these activities are available onsite for audit by the NRC in the supporting documentation for the PBNP LRA.

TABLE 1 AGING MANAGEMENT PROGRAMS THAT CREDIT THE PERIODIC SURVEILLANCE AND PREVENTIVE MAINTENANCE PROGRAM LRA, App. B, Section No./Title B2.1.1 ASME Section XI, Subsections IWB, IWC and IWD Inservice Inspection Program B2.1.2 ASME Section XI, Subsections IWE & IWL Inservice Inspection Program B2.1.3 ASME Section XI, Subsection IWF Inservice Inspection Program Friday, May 07, 2004 Page 17 of 49

Responsible Response Rcd. No Quest. No Person Due Date B2.1.4 Bolting Integrity Program B2.1.5 Boraflex Monitoring Program B2.1.6 Boric Acid Corrosion Program B2.1.7 Buried Services Monitoring Program B2.1.8 Cable Condition Monitoring Program B2.1.9 Closed-Cycle Cooling Water System Surveillance Program B2.1.10 Fire Protection Program B2.1.11 Flow-Accelerated Corrosion Program B2.1.12 Fuel Oil Chemistry Control Program B2.1.13 One-time Inspection Program B2.1.14 Open-Cycle Cooling (Service) Water System Surveillance Program B2.1.16 Reactor Coolant System Alloy 600 Inspection Program B2.1.17 Reactor Vessel Internals Program B2.1.18 Reactor Vessel Surveillance Program B2.1.19 Steam Generator Integrity Program B2.1.20 Structures Monitoring Program B2.1.21 Systems Monitoring Program B2.1.22 Tank Internal Inspection Program B2.1.23 Thimble Tube Inspection Program B2.1.24 Water Chemistry Control Program Comment We will consider adding the list of programs credited by the PSPM program to the docket for License Renewal. by providing a letter containing supplemental information.

Friday, May 07, 2004 Page 18 of 49

Responsible Response Rcd. No Quest. No Person Due Date 70 Audit 1 Bill Herrman Question Inspector: Kent Faris Date: 4/29/04 Request: NUREG 1801 recommends both periodic visual examinations during the draining and cleaning of fuel tanks, as well as, periodic UT of areas in which contaminants may accumulate (i.e. the tank bottom).PBNPs Fuel Oil Chemistry Program, B2.1.12, does not require periodic visual examinations and UT of ALL tanks. The program requires different measures for different tanks and no tanks require both periodic visual inspection and UT as recommended by NUREG 1801. For instance:*

Above ground storage tanks are periodically drained and inspected.*

Day tanks for the Diesel Driven Fire Pump and Emergency Diesel Generators are periodically examined externally via UT.*

Gas Turbine Starting and Auxiliary Diesel fuel tanks will be drained and inspected prior to the end of the current license and the results used to determine the periodicity of future inspections.*

The Emergency Diesel Generator below ground storage tanks and the underground emergency fuel tank are drained and inspected if deemed necessary based on trends indicated by the results of the fuel oil analysis or as recommended by the System Engineer based on equipment operating experience.*

Internal tank inspections "MAY" include UT thickness measurements of the tank bottom.

The differing requirements for different tanks, limitations in using both visual inspections, as well as, UT, and lack of specificity related to what is meant by "periodically inspected" does not meet the intent of NUREG 1801.

In addition, criteria utilized in defining the necessity for UT and/or visual examination is unclear, as well, as UT and/or visual examinations ability (if performed) to detect the onset or presence of localized areas of material loss induced by water and/or sediment collection.

1) Justify the above deviations from NUREG 1801. (NUREG 1801 recommends UT of ALL tank bottoms, XI.M30, page 1 )

2) If tanks are not drained and cleaned on a regular frequency established by plant maintenance procedures as recommended by NUREG 1801, explain how UT and/or visual examinations (if performed) can detect the onset or presence of small localized areas of material loss induced by water and/or sediment collection (i.e. bottom of tanks).

3) Define the term "periodically" as used in B2.1.12. Is there a required frequency of performance for these inspections?

Question Response 1) Our interpretation of NUREG 1801,Section XI.M30 is that UT is an acceptable alternative to visual inspection and could be used when visual inspection of the inside or outside surfaces is not practical and/or would be more difficult to perform than a UT examination. With regard to the specific tanks listed in the question:

• The above ground storage tanks are located outside and sit on a concrete pad. The external surface of the tank bottom is not accessible for visual inspection and the internal surface of the tank bottom has been coated which precludes UT inspection from the inside of the tank. Visual inspection from the inside of the tank would only provide an assessment of the condition of the coating. UT thickness measurements taken prior to installation of the bottom coating indicate that no significant corrosion has occurred in over 30 years of operation. Therefore it is concluded that periodic UT measurements are neither practical nor necessary and that visual inspections of the inside surfaces of the tank when it is drained and cleaned will detect any degradation of the bottom coating which will result in any required additional inspections of the base metal and/or other corrective actions.

• The day tanks for the diesel driven fire pumps and emergency diesels have limited access for performing an internal visual inspection, but wall thickness can be easily determined via UT examination from the outside of the tank.

• The bottoms of the tanks for the Gas Turbine Starting and Auxiliary Diesel are close to the floor or other equipment and UT examination from the outside of the tank may be difficult in some areas. Access to the inside of the tank is only from the fill and drain openings, which makes UT from the inside, surface impractical. Therefore the tanks will be drained, cleaned if necessary, and visually inspected from the available openings. The as found condition of the tank will be used to determine the need to schedule future inspections and/or other corrective actions.

Friday, May 07, 2004 Page 19 of 49

Responsible Response Rcd. No Quest. No Person Due Date

• The emergency diesel generator below ground tanks T-175A &B and underground tank T-72 are only drained and inspected if deemed necessary based on the results of the fuel oil sample analysis or as recommended by the system engineer. This is deemed to be acceptable based on the inspection results of the above ground tanks T-32 A&B which are considered to be in a more severe environment and have shown no appreciable material loss in over 30 years of service. T-72 has also been UT examined and indicated no appreciable material loss in over 30 years of service. Significant degradation of the inside surfaces of T-175A&B and T-72, or conditions expected to cause such degradation, would be evidenced by the oil sample analysis results and/or identified by routine inspections or tests performed on supported equipment which are monitored by the system engineer. There are no expected aging effects for the outside surface of T-175A&B because they are encased in concrete. Therefore, if these tanks are drained, cleaned and inspected, a UT thickness measurement would not be required to monitor for external corrosion.

2) Visual internal tank inspections are expected to occur under conditions that allow the inspection to be effective. This would normally require the tank to be drained and cleaned. Some of the fuel oil tanks have sufficient access to the outside surfaces to allow a representative sample of locations to detect material loss. See response to Question 71 for explanation as to why some tanks are not drained and cleaned on a regular basis.

3) Periodic is intended to mean reoccurring/more than once. The Technical Requirmements Manual (TRM) 4.12 requires quarterly sampling and analysis of the EDG related fuel oil tanks and T-30, T-72, T32A/&B for particulate and stability. TRM 4.12 also requires quarterly removal of accumulated water from these tanks. The frequency of other specific sampling, inspections, or activities will be based on inspection or analysis results and operating experience.

Comment Friday, May 07, 2004 Page 20 of 49

Responsible Response Rcd. No Quest. No Person Due Date 71 Audit 1 Bill Herrman Question Inspector: Kent Faris Date: 4/29/04 Request: NUREG 1801, Fuel Oil Chemistry AMP, approach is two-fold:

1) Minimize conditions or environment conducive to tank corrosion by maintaining quality of existing oil and oil additions through sampling, water draining, oil additives etc. and by periodic draining and cleaning of tanks.

2) Verify oil quality is being maintained within limits that do not promote tank degradation by periodic visual and UT examination.The basis for the NUREG 1801 position is to minimize possible corrosion in areas of sediment and water collection by periodic cleaning of tank interior. PBNP, B2.1.12, Fuel Oil Chemistry Program, Pg. B-129, Preventive Actions indicates that PBNP does not periodically drain and clean all fuel oil tanks. PBNP indicates that the draining and cleaning of tanks would occur if determined to be necessary based on the trends indicated by the results of the fuel oil analysis or as recommended by the System Engineer based on equipment operating experience. Justify the deviation from NUREG 1801 recommendations. Also, under current program requirements, clarify the criteria for determining when the system engineer shall determine that the fuel oil tanks need to be drained and cleaned.

Question Response If tank wall/bottom thickness can be determined via UT measurements from outside the tank, there is no need to remove the tank (and associated equipment) from service, drain, clean, and inspect the inside of the tank. Periodic removal of free water and sediment via tank drain valves or via use of a bottom sample thief will minimize conditions and environment conducive to tank corrosion.

The emergency diesel generator below ground tanks T-175A &B and underground tank T-72 are only drained and inspected if deemed necessary based on the results of the fuel oil sample analysis or as recommended by the system engineer. This is deemed to be acceptable based on the inspection results of above ground tanks T-32 A&B which are considered to be in a more severe environment and have shown no appreciable material loss in over 30 years of service. Additionally, wall thickness measurements of T-72 indicate that no appreciable material loss has occurred in over 30 years of service.

Significant degradation of the inside surfaces of T-175A&B and T-72, or conditions expected to cause such degradation, would be evidenced by the quarterly particulate and stability oil sample analysis results and/or identified by routine inspections or tests performed on supported equipment which are monitored by the system engineer. There are no expected aging effects for the outside surface of T-175 A&B because they are encased in concrete.

There are no specific criteria for when a system engineer would decide to drain and inspect the underground fuel oil tanks. This determination would be based on engineering judgment based on the results of fuel oil sample results, quantity of water being drained from the tanks, observed conditions of plant equipment supplied from the fuel oil tanks, and other internal and external operating experience.

Comment Friday, May 07, 2004 Page 21 of 49

Responsible Response Rcd. No Quest. No Person Due Date 72 Audit 1 Brad Fromm Question Inspector: Steve Gosselin Date: April 28, 2004 Request: Gall XI.M17, Section 5, CHECWORKS or a similar predictive code is used to predict component degradation in the systems conducive to FAC, as indicated by specific plant data, including material, hydrodynamic, and operating conditions. LRA Section B2.1.11, page B 123, states CHECWORKS code is used to predict component degradation in systems susceptible to FAC. Plant data, including material composition, system flow characteristics, and operating conditions are also important in determining the remaining service life, which is recalculated after each inspection.

Are configuration controls in place to ensure that predictions are updated if operating practices change? Is there a feedback between trending results, calculation predications and operating practices?

Question Response Process guidance exists to ensure that FAC predictions include consideration of changes in operating practices / conditions. The PBNP FAC program implementing procedures contain expectations for consideration of abnormal system alignments, chemistry history, and maintenance conditions.

Communication tools exist for Operations, Maintenance, Chemistry, and System Engineers to report FAC issues, and changes in configuration to the FAC Engineer.

The FAC Engineer receives a quarterly report from the Chemistry Group of any chemistry trending outside of specification limits. Information from these sources are input into CHECWORKS such as flow rates, fluid flow time in components, and fluid chemistry to update the predictive model as configuration changes occur during the operating cycle.

Comment Friday, May 07, 2004 Page 22 of 49

Responsible Response Rcd. No Quest. No Person Due Date 73 Audit 1 Brad Fromm Question Inspector: Steve Gosselin Date: April 28, 2004 Request: LRA Section B2.1.11, page B-125 and 126 plant specific operating experience review refers to a single event involving a feedwater heater steam leak at PBNP Unit 1 in 1999 due to steam impingement and FAC. Subsequent to the failure, inspections were performed and repairs were made due to wall thinning. Unit 2 heater materials were FAC resistant and no wall thinning was noted. It is not clear from the discussion of this plant specific event that the PBNP FAC problem was effective to detect wall thinning in the Unit 1 feedwater heater prior to failure. In addition, it appears that wall thinning in the other heaters was only discovered examined after the first heater failed.

Why didnt the FAC program detect this condition? How was the program improved because of this event?

Has the FAC program identified thinning conditions that resulted in corrective actions being taken before the components function impacted?

Has the FAC program identified conditions that resulted in enhancements to the program?

Question Response The FAC Program did not detect this condition as feedwater heaters were not included within the scope of the program at the time. Immediately prior to this event, PBNP was evaluating industry OE on feedwater heater degradation. The timing of the industry OE did not allow for OE evaluation before the occurrence of the event. The FAC program was revised to include feedwater heaters within the scope of the program.

The FAC Program has identified component thinning conditions that has resulted in corrective actions being pursued prior to component failure. Two examples of this are thinning in the main feedwater pumps and heater drain tank pumps mini-recirculation lines. Thinning was discovered, inspection scope was expanded, and sections of the lines were replaced with more corrosion resistant materials.

The most common enhancements to the program are associated with scope additions resulting from FAC program findings, and industry OE. Program process improvements have also been made resulting from industry OE, and internal assessment recommendations.

Comment 74 Audit 1 Brad Fromm Question Inspector: Steve Gosselin Date: April 28, 2004 Request: LRA Section B2.1.11, a page B-125 state that the PBNP FAC program is continually upgraded based on industry experience and research, but fails to provide any examples.

Provide recent examples of upgrades or enhancements to the PBNP FAC program resulting from industry operating experience and research findings.

Question Response Industry OE is routinely received and evaluated for enhancements to the PBNP FAC Program. A recent example included industry OE regarding main steam piping erosion adjacent to the Steam Generator steam flow limiting devices. This specific area has been included within the program, and inspections are being performed on both PBNP units.

Comment Friday, May 07, 2004 Page 23 of 49

Responsible Response Rcd. No Quest. No Person Due Date 75 Audit 1 Brad Fromm Question Inspector: Steve Gosselin Date: April 28, 2004 Request: Gall XI.M17, Section 4, states that the extent and schedule of the inspections assure detection of wall thinning before the loss of intended function. LRA Section B2.1.11, page B-123, states that inspection schedule provides for timely detection of degradation of susceptible piping and components inspected each refueling outage. Prior to each outage the FAC Coordinator uses the CHECWORKS to select components for inspection. There are seven basic geometries that are of concern to be selected for inspection; they include straight pipe, elbow, tee, reducer, expander, nozzle, and orifice. All of these geometries are included in the inspection sample. The LRA states that the extent and schedule of inspections ensures detection of wall thinning before the loss of the intended function of the component.

The LRA suggests that the number of inspection locations and the extent of examination area is base primarily on CHECKWORK calculations. How are plant specific and industry experience considered and factored into the inspection program?

Question Response The PBNP FAC Program implementing procedures provide guidance to ensure that the FAC Engineer receives plant specific and industry related operating experience for review / evaluation, and incorporation into the FAC program as appropriate. Relevant FAC information generally results in PBNP specific inspections, and incorporation into the FAC program.

Comment 76 Audit 1 Brad Fromm Question Inspector: Steve Gosselin Date: April 28, 2004 Request: Gall XI.M17, Section 1, FAC program predicts, detects, and monitors in plant piping and other components, such as valve bodies, elbows and expanders. Valve bodies retaining pressure in relevant high-energy systems are also covered by the program. LRA Section B2.1.11 does not discuss valve bodies that retain pressure in the high-energy systems included in the FAC program.

Are valve bodies in FAC program high-energy systems covered by the PBNP FAC program? Are any valve bodies included in the inspection scope?

Question Response Valve bodies are included within the scope of the FAC program. Inspections are performed when the CHECKWORKS program flags the valve body for inspection.

In addition, when maintenance is performed on a valve contained within the scope of the FAC program, visual inspections are performed for evidence of FAC. The FAC Engineer is involved in the process to ensure that appropriate information is obtained, and follow-up measures are taken as necessary.

Comment Friday, May 07, 2004 Page 24 of 49

Responsible Response Rcd. No Quest. No Person Due Date 77 Audit 1 Brad Fromm Question Inspector: Steve Gosselin Date: April 28, 2004 Request: LRA Section B2.1.11, page B-121 and B-122 indicate that enhancements also include clarification of the program requirements for SG nozzles and reducers and that program procedures will be enhanced to add specific components to the scope of the program.

What additional components need to be added to the scope of the program? How do these changes ensure GALL compliance?.

Question Response The FAC program needs to be revised to specifically include the Steam Generator feedwater nozzles and their attached piping reducers. This is required as the result of the aging management review for the PBNP Steam Generators.

Comment 78 Audit 1 Brad Fromm Question Inspector: Steve Gosselin Date: April 28, 2004 Request: Gall XI.M17, Section 2, program is an analysis, inspection, and verification program; thus, there is no preventive action. However, the GALL notes measures can be taken that are effective in reducing FAC. They include monitoring of water chemistry to control pH and dissolved oxygen content, and selection of appropriate piping material, geometry, and hydrodynamic conditions, etc. LRA Section B2.1.11 states there are no preventive actions associated with the PBNP FAC program; but, does not discuss, or take credit for, any additional measures, activities, or operating practices in place to mitigate FAC in the affected systems.

Has PBNP implemented additional mitigation measures discussed in the GALL to reduce the FAC in the applicable high-energy systems?

Question Response PBNP has implemented additional mitigation measures such as rigorous chemistry controls (such as pH and dissolved oxygen), plant group (Operations, Engineering, Maintenance, and Chemistry) FAC feedback communication expectations, and design control considerations for piping erosion and corrosion.

Comment Friday, May 07, 2004 Page 25 of 49

Responsible Response Rcd. No Quest. No Person Due Date 79 Audit 1 Brad Fromm Question Inspector: Steve Gosselin Date: April 28, 2004 Request: The LRA takes exception to the IWB-2400 schedules for augmented examinations that require core support structures be inspected once during each 10-year interval. The LRA states that augmented examinations for cracking in components susceptible to cracking or loss of fracture toughness, and ultrasonic examinations of baffle-former bolts for cracking (if required) will be scheduled as either periodic, or one-time examinations. The applicant states that for RVI components susceptible to IASCC and irradiation embrittlement, the highest susceptibility components will be selected examination with respect to fluence, temperature and stress. If these leading components are found to be free of cracking, less susceptible components may not require examination. The scheduling of future augmented examinations will depend on the results of the initial examination. bounded by those used to demonstrate the resolution of the inspection technique.

What criteria will determine when a RVI component is assigned to either periodic or one-time examination categories? Also, how will the applicant ensure that the proposed alternative examination scope and inspection frequencies result equivalent component reliability when compared to the examination scope and inspection frequencies specified in the GALL?

Question Response The criteria for determining if a one-time inspection is adequate for a RVI component will be when a one-time inspection of a RVI component can ensure that the component will acceptably perform its function over the term of the extended license.

The flaw detection capability of the augmented / enhanced inspections coupled with their inspection frequency will be adequate to ensure acceptable component performance throughout the inspection interval.

Comment Friday, May 07, 2004 Page 26 of 49

Responsible Response Rcd. No Quest. No Person Due Date 80 Audit 1 Brad Fromm Question Inspector: Steve Gosselin Date: April 28, 2004 Request: Gall XI.M16 Section 4 states that inspection technique is capable of detecting the critical flaw size with adequate margin. The critical flaw size is determined based on the service loading condition and service degraded material properties. For non-bolted components augmented ISI may include enhancement of the visual VT-1 examination of Section XI IWA-2210. A description of such an enhanced visual VT-1 examination should include the ability to achieve a 0.0005-inch resolution, with the conditions (e.g., lighting and surface cleanliness) of the inservice examination bounded by those used to demonstrate the resolution of the inspection technique.

The applicant takes exception to the GALL recommendation that enhanced VT 1 examinations include the ability to achieve 0.0005-inch crack resolution. This applicants program does not specify any resolution requirements for enhanced VT-1 examinations, but rather requires that the examination methods be sufficient to detect a crack of such size that crack growth during the interval until the next examination will not result in a crack of critical size or larger.

How will the minimum detectable flaw size be determined? How will the critical flaw size be defined?

What is the basis for the margins applied to these calculated flaws and how will they be applied?

In the proposed program, are inspection frequencies allowed to longer then those specified in IWB-2400?

How will this be justified?

Will the program ensure that an alterative VT-1 resolution and inspection frequency proposed by the applicant result in equivalent component reliability (failure probability) as the VT-1 performance and inspection frequency recommended in the GALL?

Question Response The minimum detectable flaw size will be determined from the specific inspection technique.

Demonstration of the capabilities of the inspection technique will verify the capability for flaw detection.

The minimum flaw size required to be detected will be defined by analysis. The minimum flaw size required to be detected will be bounded by the capability of the inspection technique.

The critical flaw size will be determined by analysis. The critical flaw size is defined in ASME Section XI, Article IWA-9000. Industry accepted analysis techniques will be used to perform these evaluations.

The RVI Program augmented / enhanced inspections are not intended to replace the ASME Section XI required inspections. Thus, the inspections and frequencies defined in ASME Section XI, IWB-2400 will remain unchanged. If evaluations defining the augmented / enhanced inspection requirements determine that periodic inspections are necessary, then the inspections will be performed at least as frequent as the ASME Section XI inspection frequency.

The flaw detection capability of the augmented / enhanced inspections coupled with their inspection frequency will be adequate to ensure acceptable component performance throughout the inspection interval.

Comment Friday, May 07, 2004 Page 27 of 49

Responsible Response Rcd. No Quest. No Person Due Date 81 Audit 1 Brad Fromm Question Inspector: Steve Gosselin Date: April 28, 2004 Request: Gall XI.M13 Section 1 screening criteria is used to determine the susceptibility of CASS components to thermal aging on the basis of casting method, molybdenum content, and percent ferrite.

The screening criteria is applicable to RVI components made of SA-351 Grades CF3, CF3A, CF8, CF8A, CF3M, CF3MA, and CF8M with service conditions above 250°C (482°F). The screening criteria are not applicable to niobium-containing steels; such steels require evaluation on a case-by-case basis. LRA Section B.2.1.17, page B-171 states that the screening criteria described in GALL Section XI.M13 will be used.

Are there any CASS steel RVI components which the GALL XI.M13 screening criteria are not applicable?

Question Response To date, PBNP RVIs CASS materials have not been reviewed in relation to the GALL XI.M13 screening criteria. Thus, at this time it is not known if there are any CASS RVI components for which the GALL XI.M13 screening criteria are not applicable. This will be performed when the details of the Aging Management Program implementing documentation are set.

Comment 82 Audit 1 Brad Fromm Question Inspector: Steve Gosselin Date: April 27, 2004 Request: With regard to baffle bolts and split pins in PBNP 1 and 2, the applicant states that a determination will be made regarding the need for further examinations and/or component replacements.

The program elements for the baffle-former and barrel-former bolts and split pins are described in LRA Section B.2.1.17, page B-172.

What type of examination will be performed on susceptible slit pins? Will all susceptible spit pins either be examined or preemptively replaced?

Question Response The PBNP Unit 1 split pins have been replaced with Rev. B material. Per the GTR, WCAP-14577 Rev. 1-A, SCC of the replacement Unit 1 split pins is not considered significant due to design, installation, and material enhancements. Thus, no augmented examinations are currently planned for SCC SCC is a concern for the Unit 2 split pins due to design, installation, and material of construction. The Unit 2 split pins are scheduled for replacement during the spring 2005 Unit 2 refueling outage. The replacement Unit 2 split pins will include design, installation, and material enhancements. The resulting replacement configuration will be much more resistant to SCC. Thus, no augmented examinations are currently planned for SCC.

Comment Friday, May 07, 2004 Page 28 of 49

Responsible Response Rcd. No Quest. No Person Due Date 83 Audit 1 Brad Fromm Question Inspector: Steve Gosselin Date: April 27, 2004 Request: For both CASS and non-CASS the LRA states that the applicant will determine the size of crack that must be detected, appropriate examination technique, and examination periodicity necessary to ensure that the components will maintain the capability to perform their intended functions. The LRA does not discuss how the applicant intends to demonstrate the effectiveness of the proposed examination techniques.

How will PBNP demonstrate examination method effectiveness for non-CASS and CASS components?

How will PBNP determine examination periodicity necessary to ensure components will maintain the capability to perform their intended functions?

Question Response The effectiveness of the inspection technique will be demonstrated in the development of the specific process. For ASME driven inspections, the ASME demonstration criteria will be required. For non-ASME driven inspections, standard industry and vendor practices will be invoked.

PBNPs intent is to perform any necessary periodic supplemental inspections in conjunction with the ASME Section XI, IWB-2500, Examination Category B-N-3 inspection, which has a 10-year periodicity.

Evaluation(s) of detectable crack sizes, potential crack growth rates, and critical crack sizes will be required to ensure that acceptable component function and reliability is maintained during the period between periodic inspections.

Comment Friday, May 07, 2004 Page 29 of 49

Responsible Response Rcd. No Quest. No Person Due Date 84 Audit 1 Brad Fromm Question Inspector: Steve Gosselin Date: April 27, 2004 Request: The LRA states that the RVI program is credited by the "Bolting Integrity Program" for the inspection of bolting internal to the reactor vessel. The applicant states that, in addition to the requirements of ASME Section XI, Subsection NB, this program monitors for the loss of preload caused by stress relaxation of the bolted joints and specifically addresses cracking in baffle and barrel former bolts. Although the applicants Bolting Integrity Program (LRA Section B.2.1.4) credits this program for all bolting inside the reactor vessel, does not discuss how the activities in this program are consistent with the GALL XI.M18 program elements.

Please explain the basis for consistency of RVI program requirements for bolting internal to the reactor vessel with the requirements in GALL XI.M18 for bolting integrity aging management.

With the exception of cracking in baffle and barrel bolting, the applicant essentially relies on the inservice inspection specified in ASME Section XI, Subsection IWB for loss of preload caused by stress relaxation and other relevant degraded conditions.

Please explain and justify visual examinations will be able to assess loss of preload of bolted connections inside the reactor vessel.

Question Response The Bolting Integrity Program manages the aging effects for bolting. The Bolting Integrity Program is an umbrella program that contains generic bolting program requirements and also credits other aging management programs for performance of bolting inspections unique to the specific area. The Reactor Vessel Internals Program is a specific program credited by the Bolting Integrity Program. The Reactor Vessel Internals Program provides the requirements for inspection of the bolting contained in the reactor vessel internals package.

The Bolting Integrity Program, in conjunction with the credited sub-programs, was reviewed for consistency with the requirements of Gall XI.M18 for bolting integrity aging management. The consistency review results are discussed in Appendix B, Section 2.1.4 of the LRA.

Although the aging management review for the reactor vessel internals credited the Reactor Vessel Internals Program directly for managing the aging of RVI bolting, the Bolting Integrity Program is also applicable as the umbrella program to the Reactor Vessel Internals program for bolting aging management issues.

Section 4.1.2 of the GTR, WCAP-14577 Rev 1-A, discusses aging management for stress relaxation. The GTR states "Examination Category B-N-3 of ASME Section XI, Subsection IWB, provides requirements for the visual (VT-3) examination of accessible surfaces of PWR core support structures that can be removed from the reactor vessel. These requirements refer to the relevant conditions defined in IWB-3520.2, which include loose, missing, cracked, or fractured parts, bolting, or fasteners. Since the manifestation of excessive stress relaxation is expected to be loose, cracked, or missing bolts or fasteners and, in the case of spring relaxation, wear would become evident, the VT-3 examination is adequate for the detection of significant stress relaxation and loss of preload in these cases for those components that are accessible (e.g., support column bolts).

With the exception of the baffle/former and barrel/former bolts, the GTR concludes that visual (VT-3) inservice examination of reactor internals components (in accordance with the requirements of Examination Category B-N-3 of Section XI, Subsection IWB) that require adequate preload to perform their function assists in managing the effects of stress relaxation, provided that such components are accessible or can be rendered accessible by the removal of the core and/or other internals for the examination.

Comment Friday, May 07, 2004 Page 30 of 49

Responsible Response Rcd. No Quest. No Person Due Date 85 Audit 1 Brad Fromm Question Inspector: Steve Gosselin Date: April 27, 2004 Request: GALL XI.M16 Section 1 program scope includes managing the effects of crack initiation and crack growth embrittlement due to void swelling. With respect to loss of fracture toughness due to void swelling, the applicant states that examinations for void swelling will be performed, as necessary, based on the results of industry research and operating experience. The applicant also states that PBNP will participate in industry groups studying RVI materials degradation issues, such as the EPRI MRP RI-ITG and Westinghouse Owner's Group. PBNP will implement NRC approved industry activities resulting from the MRP, as appropriate, to manage any applicable aging effects identified through the EPRI MRP effort.

Will PBNP develop an aging management program for loss of fracture toughness and obtain NRC approval prior to the start of the extended license period?

Question Response A combination of the ASME Section XI, Subsections IWB, IWC, and IWD Inservice Inspection Program and the Reactor Vessel Internals Program will be used to manage loss of fracture toughness due to neutron irradiation embrittlemant and / or void swelling in susceptible RVI components.

PBNP will continue to participate in industry groups studying RVI materials degradation issues, such as the EPRI MRP RI-ITG and Westinghouse Owners Group, for the purpose of evaluating the significance of void swelling on selected PWR reactor vessel internals components. As new information and technology becomes available, the plant-specific Reactor Vessel Internals Program will be modified to incorporate enhanced inspections of appropriate components as necessary.

The revised Reactor Vessel Internals Program will be submitted to the NRC for review and approval prior to entering into the period of extended operation.

Comment We will consider including this commitment in the annual update to the LRA.

86 Audit 1 Brad Fromm Question Inspector: Steve Gosselin Date: April 27, 2004 Request: LRA Section B.2.1.17, pages B-168 and B-169 state that the PBNP program will address irradiation assisted stress corrosion cracking (IASCC) and irradiation embrittlement in non CASS components. The AMP does not discuss management of SCC.

Will the program include augmented inspections for SCC susceptible components?

Question Response The Generic Topical report (GTR), WCAP-14577 Rev. 1-A, concluded that degradation due to SCC is not a significant aging mechanism for RVI components in a primary water environment. Therefore, aging management for this aging mechanism is not required for the extended period of operation.

The PBNP Unit 2 split pins were identified as an exception to the above conclusion. The Unit 2 split pins are scheduled for replacement during the spring 2005 Unit 2 refueling outage. The replacement split pins will be constructed of a material much more resistant to SCC. Thus, no augmented examinations are currently planned for SCC.

Comment Friday, May 07, 2004 Page 31 of 49

Responsible Response Rcd. No Quest. No Person Due Date 87 Audit 1 Bill Herrman Question Inspector: Steve Gosselin Date: April 28, 2004 Request: The applicant states that portions of piping are impractical to examine. In these cases, supportive evidence is developed to demonstrate the status of the component's integrity or that the piping has not been degraded. For example, the service water underground piping from the circulating water pump house to the turbine hall is inaccessible and impractical to examine. This piping was declared exempt from examination, since radiography of the accessible and bounding pipe sections show minimal signs of degradation.

What extent of the components in this program impractical to examine? Does the program provide specific guidance when component inspections are not practical?

Question Response The underground portions of the Service Water System are estimated to be less than 200 linear ft, consisting of the supply piping between the pumphouse and the turbine building and the return piping under the turbine building floor. With the exception of localized areas where interference exists due to wall penetrations or pipe supports, virtually all of the remaining portions of the system are accessible for radiography or UT examination.

Comment 88 Audit 1 John Thorgersen Question Mark Lintz Preventive Action:

The activities for prevention and mitigation programs should be described. These actions should mitigate or prevent aging degradation.

Difference: The LRA states that there are no prevention activities. The only mitigation aspect that is described is replacement, which would eliminate the concern of aging of the replaced items, but does not seen to be a mitigation activity. The rest of the element is so vague and broadly stated that it is not helpful to the reviewer.

Question: What are the inspection, examination, and testing methods and types? What are the specific structures and components that are selected for the above inspections, examinations, and tests?What are the frequencies that are specified for the above inspections, examinations, and tests?What are the specific components that are selected for replacement, and on what basis are they selected?What are the frequencies that are specified for the replacement of these components?

Question Response See the response to NRC Question No. 69.

Comment Friday, May 07, 2004 Page 32 of 49

Responsible Response Rcd. No Quest. No Person Due Date 89 Audit 1 John Thorgersen Question Mark Lintz Preventive Action:

For condition or performance monitoring programs, they do not rely on preventive actions and thus, this information need not be provided. More than one type of aging management program may be implemented to ensure that aging effects are managed.

Difference: The program description of this AMP says that it "is also used to verify the effectiveness of other aging management programs" but does not identify these other programs. It also states that "surveillance and preventive maintenance activities associated with another aging management program are evaluated and identified as an implementing document as part of that program." The GALL states that more than one program may be required, but the LRA describes other programs only in the most broad manner. It is not clear to the reviewer what these other programs are, how they help to ensure that aging effects are being managed, and how they interact with this AMP.

Question: What other programs are associated with this AMP? What are the surveillance and preventative maintenance activities that are associated with these other programs? How does this AMP interact with these other programs?

Question Response See the response to NRC Question No. 69.

Comment 90 Audit 1 John Thorgersen Question Mark Lintz Parameters Monitored/Inspected:

The parameters to be monitored or inspected should be identified and linked to the degradation of the particular structure and component intended function(s).

Difference: Gall requires that parameters be identified and linked to the aging effect. The LRA does not identify any parameters nor link any to an aging effect. This element seems vague and incomplete, and does not help the reviewer.

Question: What are the parameters that are to be monitored and inspected?How are these parameters linked to the degradation of the intended function(s) a particular component or structure?Is the inspection, examination, or testing method or type that is performed on structures and components appropriate for the aging effect?What is the basis for the selection of the structure or component to be monitored?What is the basis for the selection of the components to be replaced?

Question Response See the response to NRC Question No. 69.

Comment Friday, May 07, 2004 Page 33 of 49

Responsible Response Rcd. No Quest. No Person Due Date 91 Audit 1 John Thorgersen Question Mark Lintz Parameters Monitored/Inspected:

For a condition monitoring program, the parameter monitored or inspected should detect the presence and extent of aging effects. Some examples are measurements of wall thickness and detection and sizing of cracks.

Difference: It is not stated that PBNP has a conditioning monitoring program, but it is assumed that it does. This element is stated in a vague and general way.

Question: Is the parameter that is monitored or inspected appropriate for the applicable aging effect, i.e.,

is it able to detect the presence and extent of that aging effect?

Question Response See the response to NRC Question No. 69.

Comment 92 Audit 1 John Thorgersen Question Mark Lintz Parameters Monitored/Inspected:

For prevention and mitigation programs, the parameters monitored should be the specific parameters being controlled to achieve prevention or mitigation of aging effects. An example is the coolant oxygen level that is being controlled in a water chemistry program to mitigate pipe cracking.

Difference: This element seems vague and incomplete. No parameter is identified.

Question: Are any parameters being monitored?Are those monitored parameters the specific parameters that are being controlled to achieve prevention or mitigation of aging effects?

Question Response See the response to NRC Question No. 69.

Comment Friday, May 07, 2004 Page 34 of 49

Responsible Response Rcd. No Quest. No Person Due Date 93 Audit 1 John Thorgersen Question Mark Lintz Detection of Aging Effects:

Detection of aging effects should occur before there is a loss of the structure and component intended function(s). The parameters to be monitored or inspected should be appropriate to ensure that the structure and component intended function(s) will be adequately maintained for license renewal under all CLB design conditions. This includes aspects such as method or technique (e.g., visual, volumetric, surface inspection), frequency, sample size, data collection and timing of new/one-time inspections to ensure timely detection of aging effects. Provide information that links the parameters to be monitored or inspected to the aging effects being managed.

Difference: This element seems vague and incomplete, and does not help the reviewer. GALL requires that the detection of aging effects should occur before the loss of the intended function of the structure or component, but the element does not provide any assurance that this will be accomplished. GALL requires that appropriate parameters be monitored or inspected, but this element does not provide assurance that this is the case. GALL requires that the intended function(s) be adequately maintained for the period of extended operation, but the LRA does not provide assurance that this will be the case. GALL requires that the parameter being monitored or inspected be linked to the aging effect being managed, but this element does not provide assurance that this will be the case. The LRA purports to give an example that shows "a consideration other than aging," yet that example distinctly demonstrates aging.

Question: Will the detection of aging effects be accomplished before the loss of the intended function(s) of the applicable structure or component?Are the appropriate parameters being monitored or inspected?Will the intended function(s) be maintained for the period of extended operation?Are the parameter being monitored or inspected be linked to the aging effect being managed?If the periodicity of most surveillance and preventive maintenance activities that are credited for license renewal is usually driven by considerations other than aging, is that periodicity adequate for the purposes of license renewal?As the given example does not adequately demonstrate a consideration other than aging, does a better example need to be provided?

Question Response See the response to NRC Question No. 69.

Comment Friday, May 07, 2004 Page 35 of 49

Responsible Response Rcd. No Quest. No Person Due Date 94 Audit 1 John Thorgersen Question Mark Lintz Detection of Aging Effects:

Nuclear power plants are licensed based on redundancy, diversity, and defense-in-depth principles. A degraded or failed component reduces the reliability of the system, challenges safety systems, and contributes to plant risk. Thus, the effects of aging on a structure or component should be managed to ensure its availability to perform its intended function(s) as designed when called upon. In this way, all system level intended function(s), including redundancy, diversity, and defense-in-depth consistent with the plants CLB, would be maintained for license renewal. A program based solely on detecting structure and component failure should not be considered as an effective aging management program for license renewal.

Difference: This element seems vague and incomplete, and does not help the reviewer. It includes terms that need explaining to the reviewer: "properly deferred or canceled" and "a license renewal perspective."

Question: How is it assured that a surveillance or preventive maintenance activity credited for license renewal that is not completed within its allowed grace period, is properly deferred or canceled?What does it mean to be "properly" deferred or canceled?What is "a license renewal perspective?"

Question Response See the response to NRC Question No. 69.

Comment 95 Audit 1 John Thorgersen Question Mark Lintz Detection of Aging Effects:

This program element describes "when," "where," and "how" program data are collected (i.e., all aspects of activities to collect data as part of the program).

Difference: This element seems vague and incomplete, and does not help the reviewer. It includes a term that needs explaining to the reviewer: "callups."

Question: Please define the term "callup."Please describe the when, where, and how that program data are to be collected.

Question Response See the response to NRC Question No. 69.

Comment Friday, May 07, 2004 Page 36 of 49

Responsible Response Rcd. No Quest. No Person Due Date 96 Audit 1 John Thorgersen Question Mark Lintz Detection of Aging Effects:

The method or technique and frequency may be linked to plant-specific or industry-wide operating experience. Provide justification, including codes and standards referenced, that the technique and frequency are adequate to detect the aging effects before a loss of SC intended function. A program based solely on detecting SC failures is not considered an effective aging management program.

Difference: This element seems vague and incomplete. It is not apparent to the reviewer that the stated GALL requirements are addressed in this element.

Question: Are the stated GALL requirements adequately addressed in this element, for the purposes of license renewal?

Question Response See the response to NRC Question No. 69.

Comment 97 Audit 1 John Thorgersen Question Mark Lintz Detection of Aging Effects:

When sampling is used to inspect a group of SCs, provide the basis for the inspection population and sample size. The inspection population should be based on such aspects of the SCs as a similarity of materials of construction, fabrication, procurement, design, installation, operating environment, or aging effects. The sample size should be based on such aspects of the SCs as the specific aging effect, location, existing technical information, system and structure design, materials of construction, service environment, or previous failure history. The samples should be biased toward locations most susceptible to the specific aging effect of concern in the period of extended operation. Provisions should also be included on expanding the sample size when degradation is detected in the initial sample.

Difference: This element seems vague and incomplete. It is not apparent to the reviewer that the stated GALL requirements are addressed in this element.

Question: Are the stated GALL requirements adequately addressed in this element, for the purposes of license renewal?

Question Response See the response to NRC Question No. 69.

Comment Friday, May 07, 2004 Page 37 of 49

Responsible Response Rcd. No Quest. No Person Due Date 98 Audit 1 John Thorgersen Question Mark Lintz Monitoring and Trending:

Monitoring and trending activities should be described, and they should provide predictability of the extent of degradation and thus effect timely corrective or mitigative actions. Plant-specific and/or industry-wide operating experience may be considered in evaluating the appropriateness of the technique and frequency.

Difference: This element seems vague and incomplete. It is not apparent to the reviewer that the stated GALL requirements are addressed in this element.

Question: Are the stated GALL requirements adequately addressed in this element, for the purposes of license renewal?

Question Response See the response to NRC Question No. 69.

Comment 99 Audit 1 John Thorgersen Question Mark Lintz Monitoring and Trending:

This program element describes "how" the data collected are evaluated and may also include trending for a forward look. This includes an evaluation of the results against the acceptance criteria and a prediction regarding the rate of degradation in order to confirm that timing of the next scheduled inspection will occur before a loss of SC intended function. Although aging indicators may be quantitative or qualitative, aging indicators should be quantified, to the extent possible, to allow trending. The parameter or indicator trended should be described. The methodology for analyzing the inspection or test results against the acceptance criteria should be described. Trending is a comparison of the current monitoring results with previous monitoring results in order to make predictions for the future.

Difference: This element seems vague and incomplete. It is not apparent to the reviewer that the stated GALL requirements are addressed in this element.

Question: Are the stated GALL requirements adequately addressed in this element, for the purposes of license renewal?

Question Response See the response to NRC Question No. 69.

Comment Friday, May 07, 2004 Page 38 of 49

Responsible Response Rcd. No Quest. No Person Due Date 100 Audit 1 John Thorgersen Question Mark Lintz Acceptance Criteria:

The acceptance criteria of the program and its basis should be described. The acceptance criteria, against which the need for corrective actions will be evaluated, should ensure that the structure and component intended function(s) are maintained under all CLB design conditions during the period of extended operation. The program should include a methodology for analyzing the results against applicable acceptance criteria. For example, carbon steel pipe wall thinning may occur under certain conditions due to erosion-corrosion. An aging management program for erosion-corrosion may consist of periodically measuring the pipe wall thickness and comparing that to a specific minimum wall acceptance criterion.

Corrective action is taken, such as piping replacement, before reaching this acceptance criterion. This piping may be designed for thermal, pressure, deadweight, seismic, and other loads, and this acceptance criterion must be appropriate to ensure that the thinned piping would be able to carry these CLB design loads. This acceptance criterion should provide for timely corrective action before loss of intended function under these CLB design loads.

Difference: This element seems vague and incomplete. It is not apparent to the reviewer that the stated GALL requirements are addressed in this element.

Question: Are the stated GALL requirements adequately addressed in this element, for the purposes of license renewal?

Question Response See the response to NRC Question No. 69.

Comment 101 Audit 1 John Thorgersen Question Mark Lintz Acceptance Criteria:

Acceptance criteria could be specific numerical values, or could consist of a discussion of the process for calculating specific numerical values of conditional acceptance criteria to ensure that the structure and component intended function(s) will be maintained under all CLB design conditions. Information from available references may be cited.

Difference: This element seems vague and incomplete. It is not apparent to the reviewer that the stated GALL requirements are addressed in this element.

Question: Are the stated GALL requirements adequately addressed in this element, for the purposes of license renewal?

Question Response See the response to NRC Question No. 69.

Comment Friday, May 07, 2004 Page 39 of 49

Responsible Response Rcd. No Quest. No Person Due Date 102 Audit 1 John Thorgersen Question Mark Lintz Acceptance Criteria:

It is not necessary to justify any acceptance criteria taken directly from the design basis information that is included in the FSAR because that is a part of the CLB. Also, it is not necessary to discuss CLB design loads if the acceptance criteria do not permit degradation because a structure and component without degradation should continue to function as originally designed. Acceptance criteria, which do permit degradation, are based on maintaining the intended function under all CLB design loads.

Difference: This element seems vague and incomplete. It is not apparent to the reviewer that the stated GALL requirements are addressed in this element.

Question: Are the stated GALL requirements adequately addressed in this element, for the purposes of license renewal?

Question Response See the response to NRC Question No. 69.

Comment 103 Audit 1 John Thorgersen Question Mark Lintz Acceptance Criteria:

Qualitative inspections should be performed to same predetermined criteria as quantitative inspections by personnel in accordance with ASME Code and through approved site specific programs.

Difference: This element seems vague and incomplete. It is not apparent to the reviewer that the stated GALL requirements are addressed in this element.

Question: Are the stated GALL requirements adequately addressed in this element, for the purposes of license renewal?

Question Response See the response to NRC Question No. 69.

Comment Friday, May 07, 2004 Page 40 of 49

Responsible Response Rcd. No Quest. No Person Due Date 104 Audit 1 John Thorgersen Question Mark Lintz Operating Experience:

Operating experience with existing programs should be discussed. The operating experience of aging management programs, including past corrective actions resulting in program enhancements or additional programs, should be considered. A past failure would not necessarily invalidate an aging management program because the feedback from operating experience should have resulted in appropriate program enhancements or new programs. This information can show where an existing program has succeeded and where it has failed (if at all) in intercepting aging degradation in a timely manner. This information should provide objective evidence to support the conclusion that the effects of aging will be managed adequately so that the structure and component intended function(s) will be maintained during the period of extended operation.

Difference: This element seems vague and incomplete. It is not apparent to the reviewer that the stated GALL requirements are addressed in this element.

Question: Are the stated GALL requirements adequately addressed in this element, for the purposes of license renewal?

Question Response See the response to NRC Question No. 69.

Comment 105 Audit 1 John Thorgersen Question Mark Lintz Operating Experience:

An applicant may have to commit to providing operating experience in the future for new programs to confirm their effectiveness.

Difference: This element seems vague and incomplete. It is not apparent to the reviewer that the stated GALL requirements are addressed in this element.

Question: Are the stated GALL requirements adequately addressed in this element, for the purposes of license renewal?

Question Response See the response to NRC Question No. 69.

Comment Friday, May 07, 2004 Page 41 of 49

Responsible Response Rcd. No Quest. No Person Due Date 106 Audit 1 Bill Roman Question Inspector: Steve Gosselin Date: April 28, 2004 Request: The initial representative examinations were based on approximately ten percent of the total piping length. Subsequent examinations are based on inspection results, equipment performance, system requirements, and recommendations from Operations, Maintenance, and Engineering.

What is the basis for the initial 10% scope? Please explain how the inspection results, equipment performance, system requirements, and recommendations from Operations, Maintenance, and Engineering are used to define examination scope and locations.

Question Response Open-Cycle Cooling Water Surveillance Program - Detection of Aging Effects Examination locations are selected by the SW ISI Program coordinator based upon portions of the SW System susceptible to degradation including low flow piping sections, stagnant flow sections, and high velocity sections. Results from the examinations are recorded in a SW ISI database. The database is used to document shot locations taken, wall thinning observed, blockage observed, and record corrective actions taken on problem areas observed during examination, as necessary.

In 2000 a new Service Water database was created and populated with a representative sample of piping components from the systems known to be susceptible to wall thinning and Flow Blockage. The initial examination sample size was based on approximately 10 percent of the total piping in the susceptible systems. The selection of the components locations was based on the following:

1.The evaluation of historical inspection locations and the RT inspection results contained in the previous Paradox software SW Database.

2.The selection of additional new locations identified during system engineer walk downs using current industry criteria as identified in the Service Water Program Document.

Between 2000 and 2002, Service Water inspections were performed on a quarterly basis in order to establish a current baseline for all of components in the initial population of components being monitored.

All of the database components that were included in the Service Water ISI Program representative sample have been inspected at least one time since 2000. Some of the components in this population have received up to two follow on inspections in that same time frame. With the inspection of the initial sample completed, the Service Water Program will now use this baseline data to identify and refine the normal inspection rotation schedule for future follow on inspections and piping component monitoring.

Comment 107 Audit 1 Bill Roman Question Inspector: Peter A. Penn, Brian J. Tucker Date: 4-27-04 Request: Regarding the following sentence in element 3, "The effects of corrosion are detectable by visual inspections, while the effects of selective leaching are detectable by visual inspections and/or hardness measurements." Please clarify.

Question Response Buried Services Monitoring Program - Parameters Monitored or Inspected. If there are any indications of selective leaching or if the condition is indeterminate, then a hardness test will be performed Comment We may consider a supplemental information letterr on the docket or commit to provide this clarification in the annual update to the LRA.

Friday, May 07, 2004 Page 42 of 49

Responsible Response Rcd. No Quest. No Person Due Date 108 Audit 1 Bill Roman Question Inspector: Steve Gosselin Date: April 28, 2004 Request: GALL XI.M20 Section 4 inspections for biofouling, damaged coatings, and degraded material condition are conducted. The GALL notes that visual inspections are typically performed and, when necessary, nondestructive testing, such as ultrasonic testing, eddy current testing, and heat transfer capability testing, is effective methods to measure surface condition and the extent of wall thinning.

LRA states that the Open-Cycle Cooling (Service) Water System Surveillance Program is credited for managing aging effects such as loss of material due to general, pitting, and crevice corrosion, MIC, and loss of heat transfer due to biological/corrosion product fouling (e.g., sedimentation, silting) caused by exposure of internal surfaces of metallic components in cooling water systems (e.g., piping, valves, heat exchangers) to raw, untreated (e.g., service) water and establishes a routine inspection and maintenance program that implements GL 89-13 requirements.

Are there any lined/coated piping? If so, does PBNP credit the presence of protective linings or coating as a corrosion inhibitor? Does the PBNP program address to possible degradation of the liners or coatings and its possible effect on the functionality of other components?

Question Response Open-Cycle Cooling (Service) Water System Surveillance Program - Detection of Aging Effects There is no lined/coated piping used in the Service Water System.

Comment 109 Audit 1 Mark Ortmayer Question Inspector: Peter A. Penn, Brian J. Tucker Date: 4-29-04 Request: PBNP LRA Section B2.1.2, ASME Section XI, Subsection IWE & IWL Inservice Inspection Program, page B-30, identifies and describes approved Relief Requests. The LRA states the following:

ERR-1 Seals and GasketsTable IWE-2500-1, Items E5.10 and E5.20 require seals and gaskets to be visually examined once each inspection interval. ERR-1 allows leak-tightness testing of seals and gaskets in accordance with 10 CFR 50, Appendix J, Option B, as required by Category E-P, Item E9.40, as an alternative to the visual inspection requirements.

Without a visual examination, please clarify how this new approach will allow for the detection of aging effects on the subject gasket and seals during the period of extended operation.

Question Response Relief Request ERR-1, Seals and Gaskets, pertains to seals and gaskets that are not accessible without disassembly. Affected seals and gaskets include some of the airlocks seals and certain style electrical penetrations. Those seals and gaskets that are visible without disassembly or are routinely disassembled will continue to receive the required VT-3 visual examination.

Comment Friday, May 07, 2004 Page 43 of 49

Responsible Response Rcd. No Quest. No Person Due Date 110 Audit 1 Mark Ortmayer Question Inspector: Peter A. Penn, Brian J. Tucker Date: 4-28-04 Request: PBNP LRA Appendix B Section B2.1.2, ASME Section XI, Subsection IWE & IWL Inservice Inspection Program, page 34, states "All concrete surfaces and concrete surfaces surrounding tendon anchorages are inspected for cracks, exposed reinforcing steel, corrosion or corrosion staining, drummy areas, settlement or deflections, scaling, and leaching/chemical attack."

Page B-35 states that "prior to an ILRT, a visual examination of 100% of the accessible interior and exterior surfaces of the containment is performed" Furthermore page B-36, Monitoring and Trending, states "Except in inaccessible areas, all concrete surfaces are monitored on a regular basis by the virtue of the examination requirements specified in the PBNP" IWL Containment Inspection Program""

Gall Report XI.S2ASME Section XI, Subsection IWL, Scope of Program, states "Subsection IWL exempts from examination portions of the concrete containment that are inaccessible (e.g., concrete covered by liner, foundation material, or backfill, or obstructed by adjacent structures or other components). 10 CFR 50.55a(b)(2)(viii) specifies additional requirements for inaccessible areas. It states that the licensee is to evaluate the acceptability of concrete in inaccessible areas when conditions exist in accessible areas that could indicate the presence of or result in degradation to such inaccessible areas."

Approved relief request LRR-2 General Visual Examination of Class CC (noted on LRA page B-31),

apparently introduces a different definition of inaccessible areas for concrete surfaces than noted in the Gall Report.

Please clarify & confirm ability of new inspection approach to inspect and detect degradation on concrete containment surfaces consistent with the descriptions in the PBNP LRA.

Question Response Relief request LRR-2, General Visual Examination of Class CC, was submitted to obtain relief from the examination requirements of IWL-2510(a)-performance of a VT-3C inspection. In the basis discussion, "inaccessible" was due to lack of walkways and platforms, etc and not due to IWL-1220(b), Items Exempt From Examination. Consequently, all accessible containment concrete surfaces are visually examined-either by a general visual or a VT-3C examination. LRR-2 was reviewed and approved by NRC in SER 2001-0003 on May 7, 2001.

Comment 111 Audit 1 Mark Ortmayer Question Inspector: Peter Penn, Brian Tucker Date: 4-27-04 Request: In the Structural Monitoring Program, Section 2.1.20 of the LRA, Bullets 2 and 4 within the scope of the structural monitoring program require clarification regarding the use of the word "containment". The actual containment structure is covered in section B2.1.2 (ASME,Section XI, Subsections IWE &IWL Inservice Inspection Program) of the LRA.

Question Response The 2nd bullet is dealing with the internal containment structures-non-pressure boundary, while the 4th bullet pertains to overhead cranes.See attached marked-up page B-201, for the proposed revisions. The wording will be revised.

Comment This change will be considered for the annual update.

Friday, May 07, 2004 Page 44 of 49

Responsible Response Rcd. No Quest. No Person Due Date 112 Audit 1 Mark Ortmayer Question Inspector: Peter Penn, Brian Tucker Date:4-27-04 Request: In the Structural Monitoring program, Section 2.1.20 of the LRA, degradation of steel edge supports and bracing for the masonry wall was not explicitly addressed in the "Scope of Program" element. Confirm that this is in the scope to verify consistency with GALL.

Question Response The steel edge supports and bracing for the masonry wall, are within the scope of License Renewal and are included in the 5th bullet on page B-201. It would be better to explicitly state that, therefore, steel edge supports and bracing will be added to the 1st bullet on that page. We have a marked-up page B-201 available for review.

Comment We will consider a commitment to update the LRA in the annual update.

Friday, May 07, 2004 Page 45 of 49

Responsible Response Rcd. No Quest. No Person Due Date 113 Audit 1 John Thorgersen Question Inspector Steven Gosselin Date 5/4/04 Table 4 of the FMP basis document states the steam generator tube sheet, steam generator feedwater nozzle locations are not evaluated for environmental effects. Please explain the basis for not including environmental fatigue effects in the FatiguePro stressed based fatigue usage calculations for the steam generator tube sheet, steam generator feedwater nozzles.

Question Response The Fatigue Monitoring Program described in Section B3.2 of Appendix B to the PBNP LRA is an existing program that is consistent with NUREG-1801, "Generic Aging Lessons Learned (GALL) Report,"Section X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary."Section X.M1 of NUREG-1801 requires that the effects of the reactor coolant environment on component fatigue life be evaluated and monitored for a sample of critical components that includes, as a minimum, those components selected in NUREG/CR-6260.

The impact of the effects of reactor coolant environment on component fatigue life has been evaluated for a sample of critical components, including the seven component locations selected in NUREG/CR-6260.

These critical components were determined to be acceptable for the period of extended operation, including the effects of reactor coolant environment.

The Fatigue Monitoring Program includes monitoring the number and severity of plant design transients and an on-going fatigue analysis of a sampling of component locations whose level of metal fatigue is expected to be most adversely affected by the combined effects of plant cycles and reactor water environment. The monitored population includes each of the component locations identified in NUREG/CR-6260 for older vintage Westinghouse plants as well as others.

Therefore, the Fatigue Monitoring Program described in Section B3.2 of Appendix B to the PBNP LRA satisfies the requirements of Section X.M1 of NUREG-1801 and no additional component locations are required to be evaluated or monitored for environmental fatigue effects.

The basis for not including the steam generator tubesheets and feedwater nozzles in the sample of critical components that are evaluated and monitored for environmental fatigue effects is as follows.

1. Both Units of the Point Beach Nuclear Plant were originally supplied with Westinghouse Model 44 Steam Generators. The originally supplied steam generators have been replaced in both PBNP units with upgraded Westinghouse replacement steam generators. The steam generator lower assemblies in PBNP Unit 1 were replaced with Westinghouse Model 44F steam generator lower assemblies, and modifications were made to the moisture separator equipment of the upper assemblies to improve thermal hydraulic performance. The Unit 1 replacement steam generators were placed into service in 1984. The entire steam generator assemblies in PBNP Unit 2 were replaced with Westinghouse Model 47F (47) steam generators. The Unit 2 replacement steam generators were placed into service in 1997. Therefore, the steam generator tubesheets in Unit 1, and the steam generator tubesheets and feedwater nozzles in Unit 2 will experience less than 60 years of operation.

2. The steam generator tubesheet is a 28-inch thick ASME-SA-508 carbon steel forging, weld clad on the primary coolant side with an Inconel alloy. Environmental fatigue effects on carbon and low alloy steels (Fen = 2.53) is less than the environmental fatigue effects on austenitic stainless steels (Fen = 15.35).

The projected end of license extension cumulative usage factor for the steam generator tube sheets in both Unit 1 and 2 is such that the environmentally adjusted cumulative usage factors would be much less than 1. Therefore, the steam generator tubesheets were not included in the sample of critical components that are evaluated and monitored for environmental fatigue effects.

3. The feedwater nozzles are forged carbon steel, welded into the upper shell of the S/G. The tubesheet, together with the U-tubes form the boundary between the primary and secondary sides of the steam generator. Therefore, the feedwater nozzles are not part of the reactor coolant pressure boundary and were not included in the sample of critical components that are evaluated and monitored for environmental fatigue effects.

Friday, May 07, 2004 Page 46 of 49

Responsible Response Rcd. No Quest. No Person Due Date Comment Friday, May 07, 2004 Page 47 of 49

Responsible Response Rcd. No Quest. No Person Due Date 114 Audit 1 John Thorgersen Question Inspector Steven Gosselin Date 5/4/05 The LRA Section B3.2, page B-244 states that the Fatigue Monitoring Program includes, among other pressurizer locations, the pressurizer surge line reducer weld as a monitored component. Table 4 of the FMP basis document refers to pressurizer surge line elbow but not the surge line reducer weld. Are these components the same? If not please explain. If they are, please explain the basis for not including environmental fatigue effects in the FatiguePro stressed based fatigue usage calculation Question Response Section B3.2 in Appendix B of the PBNP LRA states, in part, under the element Operating Experience:

"The Fatigue Monitoring Program includes the pressurizer surge line nozzle, the RCS hot leg surge line nozzle and the pressurizer surge line reducer weld as monitored components." The pressurizer surge line reducer weld is located at the pressurizer surge line elbow just below the pressurizer surge line nozzle.

Both terms (i.e., pressurizer surge line reducer weld/elbow) are used in the Fatigue Monitoring Program to refer to the same component location.

The Fatigue Monitoring Program described in Section B3.2 of Appendix B to the PBNP LRA is an existing program that is consistent with NUREG-1801, "Generic Aging Lessons Learned (GALL) Report,"Section X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary."Section X.M1 of NUREG-1801 requires that the effects of the reactor coolant environment on component fatigue life be evaluated and monitored for a sample of critical components that includes, as a minimum, those components selected in NUREG/CR-6260.

The impact of the effects of reactor coolant environment on component fatigue life has been evaluated for a sample of critical components, including the seven component locations selected in NUREG/CR-6260.

These critical components were determined to be acceptable for the period of extended operation, including the effects of reactor coolant environment.

The Fatigue Monitoring Program includes monitoring the number and severity of plant design transients and an on-going fatigue analysis of a sampling of component locations whose level of metal fatigue is expected to be most adversely affected by the combined effects of plant cycles and reactor water environment. The monitored population includes each of the component locations identified in NUREG/CR-6260 for older vintage Westinghouse plants as well as others.

Therefore, the Fatigue Monitoring Program described in Section B3.2 of Appendix B to the PBNP LRA satisfies the requirements of Section X.M1 of NUREG-1801 and no additional component locations are required to be evaluated or monitored for environmental fatigue effects.

The basis for not including the pressurizer surge line reducer weld/elbow in the sample of critical components that are evaluated and monitored for environmental fatigue effects is as follows.

An analysis was performed to compute stresses and associated fatigue usage for components in the PBNP Units 1 and 2 surge line and pressurizer for a projected 60 years of operation, including the effects of insurge/outsurge and environmental effects. The following locations in the surge line and pressurizer are monitored in FatiguePro:

• Hot Leg Surge Nozzle

• Pressurizer Spray Nozzle

• Pressurizer Surge Nozzle

• Pressurizer Heater Penetration Weld

• Pressurizer Water Temperature Instrument Nozzle FatiguePro was used to project 60-year CUFs for these locations. These locations were identified as candidate locations requiring an environmental fatigue evaluation. It was demonstrated that the surge line and lower head of the pressurizer are not fatigue-challenged, even after applying the most conservative environmental factors. The pressurizer heater penetration weld was shown to be the bounding location for fatigue in the surge line and pressurizer lower head.

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Responsible Response Rcd. No Quest. No Person Due Date The projected end of license extension cumulative usage factor for the pressurizer surge line reducer weld/elbow is such that applying a conservative environmental fatigue effects factor (Fen = 15.35) results in an environmentally adjusted cumulative usage factor much less than 1. The environmentally adjusted cumulative usage factor for the pressurizer surge line reducer weld/elbow is also bounded by the environmentally adjusted cumulative usage factor for the pressurizer heater penetration weld. As a result, the pressurizer heater penetration weld is considered a leading location for monitoring the effects of the reactor coolant environment for the pressurizer lower head and surge line.

The Fatigue Monitoring Program provides for corrective actions to prevent the fatigue usage factor from exceeding the design code limit of 1.0, including the effects of reactor coolant environment, or the cumulative number of plant cycles from exceeding the cyclic design basis during the period of extended operation. The Fatigue Monitoring Program uses FatiguePro to perform an analysis of each monitored component location using actual plant data, and to provide the basis for proactive action to maintain the cyclic design basis and the fatigue usage factors below code limits. Corrective actions include a review of additional affected component locations.

Therefore, the pressurzier surge line reducer weld/elbow was not included in the sample of critical components that are evaluated and monitored for environmental fatigue effects.

Comment Friday, May 07, 2004 Page 49 of 49