ML063050504

Email: (PA-LR) FW: Word Document of NRC LRA Programs Audit of Pilgrim

ML063050504
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Site:	Pilgrim
Issue date:	06/02/2006
From:	Ford B Entergy Corp
To:	Subbaratnam R NRC/NRR/ADRO
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.rd - FW: Word Document of NRC LRA Programs Audit of Pilgrim Page 1]

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"Ford, Bryan" <BFord@entergy.com>

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6/2/2006 4:17:03 PM FW: Word Document of NRC LRA Programs Audit of Pilgrim FYI Bryan Ford 508-830-8403 From: Ellis, Douglas Sent: Thursday, June 01, 2006 3:20 PM To: 'jad@nrc.gov' Cc: Ford, Bryan; Lach, David J; Mogolesko, Fred; Ellis, Douglas

Subject:

Word Document of NRC LRA Programs Audit of Pilgrim Jim - as you requested, find attached the MS Word document of the database questions and responses from the NRC Programs Audit last week.

Douglas Ellis, Pilgrim Licensing, 508.830.8160.

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NRC LRA Programs Audit of PNPS Number Status Request 137 Closed

[B.1.1-W-01, Boraflex Monitoring]

1. "The program relies on periodic inspection of the Boraflex, monitoring of silica levels in the spent fuel pool water, and analysis of criticality to assure that the required 5% subcriticality margin is maintained."

Response

As stated in LRA Section B.1.1, the Boraflex Monitoring Program is consistent with NUREG-1801,Section XI.M22 with no exceptions. Thus, the Boraflex Monitoring Program monitors all of these parameters.

NRC Auditor PNPS Lead Wen, Peter Potts, Lori For Boraflex Monitoring Program, the GALL Report identifies parameters to be monitored including: physical conditions of the Boraflex panels, such as gap formation and decreased boron area density, and the concentration of the silica in the spent fuel pool. Does applicant's Boraflex Monitoring Program monitor all of these parameters, especially, the areal density measurement?

Thursday, June 1, 2006 Page I of 82

Number Status Request 138 Accepted

[B.1.1-W-02, Boraflex Monitoring]

2. In the Operating Experience Section, PNPS implies that the required 5% subcritically margin was demonstrated through the gap measurement. Please provide details how the results of gap measurement demonstrated that the 5%

subcritically margin is maintained.

Response

NRC Audi LRA Section 8.1.1, Operating Experience, will be Wen, Peter revised to the paragraphs below to clarify that reactivity calculations performed after direct material surveillance (blackness testing) using bounding assumptions with regard to neutron attenuation capability of the Boraflex demonstrated that the 5% subcriticality margin is maintained.

This requires an amendment to the LRA.

Blackness testing was performed on Boraflex panels in the spent fuel storage racks during 1996 and 1998 to provide a baseline for development of the monitoring program.

Results of the 1996 testing showed shrinkage and gapping in the Boraflex. Analysis of the criticality design of the fuel pool based on the 1996 blackness test used bounding assumptions with regard to neutron attenuation capability of the Boraflex based on the observed gap sizes and locations and assumed levels of Boraflex erosion (thinning and edge loss). The analysis showed that the pool subcriticality margin was greater than 5%. Results of the 1998 testing showed about a 20% increase in average gap size, but overall shrinkage (gaps and end shortening) of the material was much less on a percentage change basis and was bounded by the criticality analysis assumptions. The report concluded that the Boraflex poison material in the spent fuel storage racks continues to perform its intended function.

The Boraflex Monitoring Program (with areal density measurement) at PNPS has been instituted recently. Therefore, there is no additional plant-specific operating experience.

itor PNPS Lead James, Gary Thursday, June 1, 2006 Page 2 of 82

Number Status Request 139 Closed

[B.1.1-W-03, Boraflex Monitoring]

3. The applicant states in the LRA that its Boraflex Monitoring Program is consistent with the program described in GALL Report Section XI.M22, Boreflex Monitoring. In the Detection of Aging Effects program element, the GALL Report states that:

Response

The RACKLIFE predictive model is used at PNPS. However, as the model is under development, the projected useful life of the Boraflex racks has not yet been determined.

Corrective actions would be initiated if test results find that the 5% subcriticality margin cannot be maintained because of current or projected degradation. Corrective actions consist of providing additional neutron-absorbing capacity by Boral or boron steel inserts, or other options which are available to maintain a subcriticality margin of 5%.

NRC Auditor Wen, Peter PNPS Lead Potts, Lori "The amount of boron carbides released from the Boraflex panel is determined through direct measurement of boron areal density and correlated with the levels of silica present with a predictive code. This is supplemented with detection of gaps through blackness testing and periodic verification of boron loss through areal density measurement techniques such as the BADGER device."

What predictive code is being used at PNPS? Based on the predictive code and trending of the SFP silica level what is the projected useful life of the

[B.1.1-W-04, Boraflex Monitoring]

4. As indicated in Table 3.3.2-13 of the LRA, PNPS identified that this AMP will be used in three line items (page 3.3-131). These three line items include managing neutron absorber aging effects of "loss of material," "change in material properties," and "cracking." All these three line items reference GALL Report item VII.A2-2. However, the aging effect identified by the GALL Report (VII.A2-2) is only "reduction of neutron-absorbing capacity/ Boraflex degradation." Please explain the discrepancies.

140 Accepted LRA Table 3.3.2-13 line items for neutron absorber aging effects "loss of material" and "cracking" will be changed to indicate that these aging effects are managed by the Water Chemistry Control - BWR Program. The line items will use note H, "Aging effect not in NUREG-1 801 for this component, material and environment combination."

This requires an amendment to the LRA.

Wen, Peter Potts, Lori Thursday, June 1, 2006 Page 3 of 82

Number Status Request 141 Accepted

[B.1.3-D-01, BWR CRD Return Line Nozzle Program]

1. A structural weld overlay was applied over a through wall Crack in a 182/82 weld using alloy 52 material without removing the flaw. What regulatory basis was used to install this overlay?

How will this be handled during the PEO?

What is the regulatory basis for reducing the examination volume?

Response

The CRD Return Line weld overlay was designed and installed in accordance with ASME Section XI Code Case N-504-2, "Alternate Rules for Repair of Class 1, 2 and 3 Austenitic Stainless Steel Piping" and Code Case N-638, "Similar and Dissimilar Metal Welding Using Ambient Temperature Machine GTAW Temper Bead Technique" and associated Relief Request PRR-36 and PRR-38. Both code cases were approved for use in NRC Regulatory Guide 1.147, Revision 13. ASME Section Xl Code Case N-504-2 allows a repair to be performed by either removing the flaw or reducing it to an acceptable size. The weld overlay approach, by design, reduces the flaw to an acceptable size.

The weld overlay assumes a flaw size through wall for 360 degrees around the component. The weld overlay is designed to structurally replace the cross-section of the underlying component such that no structural credit is taken for the remaining ligaments of the component.

Code Case N-504-2 is the basis for the design and implementation of the structural weld overlay repair method. Code Case N-638 is used for the application of the temper bead technique for repair welding of dissimilar metals using the GTAW process. Code Case N-638 provides the applicable procedure qualification requirements for welding with nickel-based alloys on a ferritic base metal, which in this case includes welding to both a P-No. 3 low alloy carbon steel nozzle and a P-No. 43 nickel-chrome alloy pipe cap.

It was necessary to take exceptions to the specific alloys described in the Code Case N-504-2 overlay repair method, which is based on the use of austenitic stainless steel alloys only. These specific exceptions are described in the Pilgrim Relief Request PRR-36.

Additionally, relief was requested, via Pilgrim Relief Request PRR-38, to use an alternative program for implementation of ASME XI Appendix VIII, Supplement 11 for ultrasonic examinations. The alternative program was implemented through the Performance Demonstration Initiative (PDI) program.

The CRD Return Line Nozzle N-10 weld overlay repair will continue to be inspected under the PNPS Inservice Inspection Program as a Category E weld in accordance with BWRVIP-75-A "Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedules" during PEO.

PNPS commits (Commitment #30) to perform a code repair of the CRD return nozzle to cap weld as needed if the installed overlay weld repair is not approved via accepted code cases, revised codes, or subsequent approval of relief requests.

The N-10 nozzle weld overlay was inspected to the maximum extent physically possible based on the geometric limitations of the nozzle and examination equipment used. The examination NRC Auditor PNPS Lead Davis, Jim Harizi, Phil Thursday, June 1, 2006 Page 4 of 82

volume is based on the component wall Number Status Request 142 Closed

[B.1.3-D-02, BWR CRD Return Line Nozzle Program]

2. Was relief requested to use Code Case N-504-2 to do the weld overlay? What exceptions have you taken to Code Case -504-2?

Do you meet the requirements for ASME Section XI non-mandatory Appendix Q?

How will this be handled during the period of extended operation (PEO) ?

Response

thickness; weld overlay thickness and structural length required. The N-10 Nozzle wall thickness is 0.578" and the required thickness for the N-10 weld overlay was 0.20" with a required structural axial length of 1" either side of the flaw. Based on these dimensions, the required length of the examination volume would be approximately 1-1/2". The length of the applied weld overlay on either side of the flaw was 1-3/4" and therefore provided sufficient length to allow full volumetric examination of the overlay.

The reduced examination volume for the CRD Return Line Nozzle to Vessel Weld is described in the LRA Appendix B.1.3. This reduction of the inspection volume for the adjacent base metal is now in accordance with ASME Code Case N-613-1, which has been approved for use by the NRC in Regulatory Guide 1.147 Rev.

14, "Inservice Inspjection Code Case Acceptability, ASME Section XI, Division 1".

This LRA information will be updated to reflect the current status of this Code Case approval.

A Relief Request to use Code Case N-504-2 for the CRD Return Line weld overlay was applied for and approved prior to startup of the N-10 Nozzle repair outage. The Pilgrim Relief Request, PRR-36, Entergy letter number 2.03.120 requested that Alloys 152/52 be allowed for weld overlay repair material and an alternate inspection plan be allowed in lieu of a hydrostatic pressure test.

The CRD Return Line Nozzle weld overlay repair was designed and installed in October of 2003 in accordance with the 1989 edition of ASME Section XI. ASME Section XI Non-Mandatory Appendix 0, "Weld Overlay Repair of Class 1, 2 and 3 Austenitic Stainless Steel Piping Weldments", was first published as part of the 2004 edition of ASME Section XI and therefore was not considered for the CRD Return Line Nozzle weld overlay modification.

The CRD Return Line Nozzle N-10"weld overlay repair will continue to be inspected under the PNPS Inservice Inspection Program as a Category E weld in accordance with BWRVIP-75-A "Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedules" The reduced volume inspection is in accordance with ASME Code Case N-613-1, which has been endorsed by the NRC in Regulatory Guide 1.147, "Inservice Inspection Code Case Acceptability, ASME Section XI, Division 1.."

NRC Auditor PNPS Lead Davis, Jim Harizi, Phil 143 Closed

[B.1.4-D-1, BWR Feedwater Nozzle Program]

1. For this program what is the regulatory basis for reducing the examination volume?

Davis, Jim Finnin, Ron Thursday, June 1, 2006 Page 5 of 82

Number Status Request 144 Closed

[B.1.5-J-01, BWR Penetrations]

1. LRA Appendix B.1.5 (BWR Penetrations) in the Operating Experience states that in January 2005 three 2.5" piping butt welds in SLC system piping [shop welds RPV-N14-T1 and RPV-N14-T2 and field weld RPV-14-2] were found'to be unidentified on inspection drawings and not included in the ISI weld population totals. It also states that weld RPV-1 4-2 was included in surface examinations of the N14 nozzle safe end weld and safe end extension piece performed in RFO11. It also states that corrective actions included adding the welds to the ISI weld population totals and performing a nozzle surface examination of weld RPV-N14-2 during RFO15.

QUESTION:

When was RFO1 1?

Explain the apparent inconsistency that weld RPV-N14-2 was not included in the ISI weld population until RFO15, yet it was included in the N14 surface examinations of N14 nozzle safe end weld

Response

RFO-1 1 was conducted in the February - April 1997 timeframe (2/15 - 4/14/97)

GE SIL 571 recommends that surface examinations be performed on small bore nozzle safe end extensions fabricated from 304 stainless steel. The SIL recommends that the entire safe end extension piece including the nozzle to safe end weld receive a surface examination. The fabrication of the nozzle and safe end extension assembly includes line boring of the nozzle/safe end extension assembly inner surfaces and machining of the outside surface to a flush condition. The extensive cold working during fabrication can sensitize the austenitic stainless steel extension piece such that IGSCC could occur in the base metal of the safe end extension as well as the weld heat affected zones. This machining also prevents the nozzle to safe end weld transition from being easily detected by an inspector. To ensure that the entire nozzle to safe end extension piece and the nozzle to safe end weld were examined in RFO1 1, ISI NDE inspectors were instructed by PNPS to perform a surface examination of the entire nozzle and safe end extension piece from the RPV outside wall out to the adjacent tee. As a result of this conservative approach, the RPV-N 14-2 weld was included by default in the surface examination boundary.

NRC Auditor PNPS Lead Jackson, Wilbur Finnin, Ron and safe end extension piece during RFO11.

Thursday, June 1, 2006 Page 6 of 82

Number Status Request 145 Closed

[B.1.5-J-02, BWR Penetrations]

2. LRAAppendixB.1.5 (BWR Penetrations) under Exceptions states that "surface examinations are not performed on instrument penetration nozzle weld6." It further states that inspections to monitor the effects of cracking on the intended function of instrument penetration nozzles (N15A/B and N16A/B) include enhanced visual (VT-2 with insulation removed) examinations during system pressure testing. It also states that a UT exam of the N16B safe end-to-reducer weld is performed every 10 years. However, ASME Section XI, Table IWB-2500-1 and BWRVIP-49 also recommend surface examinations.

QUESTION:

A surface examination is capable of finding indications with potential for failure before a through-wall leak can occur.

However, a VT-2 examination looks for signs of leakage.

Provide a more detailed discussion and justification of why PNPS's AMP B.1.5, with this exception, is adequate to manage the aging of these instrument nozzles during the extended period of operation.

What is meant by the phrase "enhanced visual...

examinations"? Exactly what is the enhancement?

Response

Regarding the N15A/B nozzles, the makeup capacity size exclusion provision in ASME XI IWB-1220(a) exempts these nozzles from code inservice surface examinations.

The N15A/B and N16A/B nozzles are also excluded from the recommendations of GE SIL 571 due to the replacement of the 304SS safe end extensions with Inconel extensions in RFO#7.

BWRVIP-49 recommends that surface examinations be performed per ASME XI IWB-2500 Category B-F requirements; however, Class 1 Category B-F and B-J welds at PNPS are inspected in accordance with the PNPS ISI Program. This program selects welds for examination based on a combined risk ranking that considers the risk of failure and the consequences of such a failure. This program selected one weld out of the four welds at the N16A and B nozzles, specifically weld RPV-N16B-R-2, for inspection. This weld was ultrasonically examined during RFO1 5 in 2005 with no indications detected.

Additionally, when the predominant damage mechanism is an I.D. initiated one such as IGSCC in this case, there is no benefit to performing a surface examination since the component would already be leaking if the flaw propagates to the surface. A liquid penetrant examination will not detect a subsurface flaw.

In this case, a VT-2 examination is the preferred examination as it is equivalent to a surface exam in this case, but is less time-consuming and results in reduced radiation exposure to inspection personnel.

An "enhanced" VT-2 examination is performed with insulation removed as discussed in BWRVIP-27A, "BWR SBLC/Core Plate delta-P Inspection and Flaw Evaluation Guidelines".

Periodic code system leakage tests do not require the removal of pipe insulation to perform VT-2 examinations for leakage. For partial penetration small bore nozzles such as the N15A/B, N16A/B and N14 nozzles, an enhanced VT-2 examination is more effective as it is more likely to detect leakage from a degraded partial penetration weld on the reactor vessel inner wall.

PNPS will continue to follow BWRVIP-27 guidelines during the period of extended operation including examinations in excess of code requirements for the N15A/B, N16A/B, and N14 nozzles.

NRC Auditor PNPS Lead Jackson, Wilbur Finnin, Ron Thursday, June 1, 2006 Page 7 of 82

I Number Status Request

Response

NRC Auditor PNPS Lead 146 Closed

[B.1.5-J-03, BWR Penetrations]

3. LRA Appendix B.1.5 (BWR Penetrations) includes an "Exception Note" stating that PNPS has implemented risk-informed ISI (RI-ISI) in accordance with ASME Section XI, Code Case N-578.

QUESTIONS:

1. Compare the number, type, frequency and extent of inspections required for instrument penetration nozzles N15A/B and N16A/B before implementation of RI-ISI and after implementation of RI-ISI.

2. Are N15A/B and N16A/B the only Pilgrim RPV instrument penetrations?

3. Please make available at the audit a copy of ASME Section XI, Code Case N-587.

1. The N15A/B nozzles are exempted from code Jackson, Wilbur Finnin, Ron inservice examination by the makeup capacity size exclusion provision as allowed by ASME XI paragraph IWB-1220(a). The N15A/B nozzles are subjected to steam conditions while the N16A/B and N14 nozzles are exposed to water service conditions. The makeup size exclusion calculation for PNPS excludes steam piping with an inside diameter less than 2.2 inches and water piping with an inside diameter of less than 1.1 inches. The PNPS makeup size exclusion calculation does not use ECCS systems as a basis for the calculation.

As stated in Table 3.1.2-1 of the LRA, cracking of the instrumentation nozzles is managed by a combination of the BWR Water Chemistry Program and the BWR Penetrations Program.

(Loss of material is managed by a combination of the BWR Water Chemistry and the Inservice Inspection Program). PNPS believes the existing combination of mitigation and inspections, with the ASME Code exclusions taken, provide acceptable aging management for the period of extended operation for the following reasons.

a. ASME Section XI IWB-2500, without exclusion, requires a surface examination of these components. As the aging effects of interest originate on the ID wall (exposed to treated water >140 F), these surface examinations would only detect a flaw once the flaw propagated thru-wall. The surface examinations would not detect any flaws that were not thru-wall.

b. The ISI program includes inspection of welds of the same material/environment combinations as the welds within the BWR Penetrations Program. These inspections will provide information on the aging of the subject components. If any indications are found on the similar component inspections, sample expansion will lead to inspection of more similar locations and if appropriate to the actual components in question. Inspection of representative sample locations is acceptable to confirm the aging of the component/environment combination.

c. As discussed in Question 145, PNPS performs an enhanced VT-2 of these penetrations. The enhancement is that the insulation is removed from the penetrations so that the penetration and welds are viewed directly and specifically during the leak test, insuring the detection of even very small amounts of leakage from this penetration.

PNPS believes this is the most effective way to monitor the condition of these specific components. Given the code surface exams will only detect thru-wall failures from the ID, these inspections will find the same thru-wall flaws that the surface exams would find.

Separate table was provided to the inspector which shows N15 and N16 nozzle inspection history.

Thursday, June 1, 2006 Page 8 of 82

Number Status

Request,

Response

2. The only instrument partial-penetration weld nozzles at Pilgrim are the N15A/B, N16A/B and N14 (SBLC/Core dP) nozzles.

NRC Auditor PNPS Lead 147 Closed

[B.1.5-J-04, BWR Penetrations]

4. GALL Program Description XI.M8 (BWR Penetrations) states that an applicant may use the guidelines of BWRVIP-62 for inspection relief for vessel internal components with hydrogen water chemistry, provided that such relief is submitted under the provisions of 10 CFR 50.55a and approved by the staff.

QUESTIONS Has Pilgrim implemented hydrogen water chemistry?

Has Pilgrim requested and/or obtained inspection relief for vessel internal components using the guidelines of BWRVIP-62? If so, describe the details of the inspection relief requested and/or granted.

Pilgrim is on Hydrogen Water Chemistry.

Pilgrim has not used or requested relief for vessel internal components. The industry is currently waiting for the NRC SER on this BWRVIP report which is being finalized by the NRC Jackson, Wilbur Finnin, Ron Thursday, June 1, 2006 Page 9 of 82

Number Status Request 148 Closed

[B.1.5-J-05, BWR Penetrations]

5. For PNPS AMP B.1.5 (BWR Penetrations), the description of the exception states that a UT exam of N16B safe end-to-reducer weld is performed every 10 years.

For this same AMP, the Operating Experience provides relatively recent (RFO15) examination results for weld RPV-N14-2 (SLC nozzle) and for instrument penetration nozzles. The Operating Experience also states that liquid penetranant examination of instrument penetration nozzle N15A in 1990 resulted in no recordable indications. The Operating Experience does not discuss results of the 10-year UT examinations of N16B safe end-to-reducer weld.

QUESTIONS:

1. Discuss results of the 10-year UT examination of N16B safe end-to-reducer weld.

2. For RPV-N14-2 and for instrument penetration nozzles, discuss the history of examination results that is earlier than RFO15.

Response

1. The N16B nozzle safe end to reducer weld RPV-N16B-R-2 was ultrasonically examined in RFO15 per the 3rd Interval ISI Program Plan and the PNPS Risk-Informed ISI Program.

Access was provided by the removal of the N16B concrete shielding blocks which were replaced after the examination was completed.

The Inconel to 316 stainless steel weld was examined using Appendix VIII methods for dissimilar metal welds with full code coverage achieved during the exam. No recordable indications were identified.

2. A summary table of inspections performed on the N15 and N16 nozzles is included in the response to Question B.1.5.3 above.

Leakage was discovered during power operations in 1986 at the socket weld on the 2 inch side of the N16A nozzle safe end extension to reducer (2xl) weld. A temporary sleeve repair was installed and all N15 and N16 safe end extensions were subsequently replaced with Inconel extensions during the next outage in 1987.

The SBLC N14 nozzle to safe end weld RPV-N14-1 was included in the Class 1 weld inspection sample and received a PT examination during the 3rd 10-year ISI interval until the Risk-Informed ISI Program was implemented in 2001. This weld was not included in the risk-informed weld sample population for examination. The weld received a surface examination in both RFO1 1 and RFO15 with no indications detected. Since an adequate ultrasonic procedure that allows depth sizing of indications is not currently available, weld RPV-N1 4-1 is scheduled for a surface examination every two outages starting with RFO15 in accordance with BWRVIP-27A recommendations. Enhanced VT-2 examinations for leakage were performed on this weld in both RFO14 and RFO15. This schedule of an enhanced VT-2 every outage and surface examination every other outage will continue going forward at least until an adequate UT procedure is available.

SBLC nozzle safe end extension to tee weld RPV-N14-2 is examined for leakage with VT-2 methods during the Class 1 system pressure test during every outage as required by code at

• the close of each refueling outage.

NRC Auditor PNPS Lead Jackson, Wilbur Finnin, Ron Thursday, June 1, 2006 Page 10 of 82

Number Status Request 149 Closed

[B.1.6-J.-01, BWR Stress Corrosion Cracking]

1. The PNPS LRA states that the implementing procedure for ASME Section XI inservice inspection and testing will be enhanced to specify that the guidelines of Generic Letter 88-01 or approved BWRVIP-75

'shall be considered" in determining sample expansions if indications are found in Generic Letter 88-01 welds:

QUESTIONS:

What is PNPS's current basis for determining sample expansion if indications are found in GL 88-01 welds?

In addition the guidelines in Generic Letter 88-01 or approved BWRVIP-75, what other considerations, if any, will PNPS use in determining sample expansion if indications are found in Generic Letter 88-01 welds?

150 Closed

[B.1.6-J-02, BWR Stress Corrosion Cracking]

2. Make available at the audit, in both hard copy and electronic format, the documents that compare the ten elements of PNPS AMP B13.6 (BWR Stress Corrosion Cracking) to the ten elements of GALL AMP XI.M7 (BWR Stress Corrosion Cracking).

Response

1. If cracking is detected in GL 88-01 Category A welds, the scope expansion rules of the PNPS Risk-Informed ISI Program in accordance with EPRI Topical Report TR-1 12657 will be used to determine scope expansion size and content.

Scope expansion caused by cracking detected in any other GL 88-01 category (B through G) will be determined by the scope expansion criteria of BWRVIP-75A used in conjunction with GL 88-01.

2. PNPS plans to use the scope expansion rules outlined in BWRVIP-75A and GL 88-01 for Category B through G welds. If cracking is detected in GL 88-01 Category A welds, the scope expansion rules of the PNPS Risk-Informed ISI Program in accordance with EPRI Topical Report TR-112657 will be used to determine scope expansion size and content.

Sample expansion addressed in section 2.5 of IGSCC report PNPS-RPT-05-008.

NRC Auditor Jackson, Wilbur PNPS Lead Finnin, Ron This information is available in LRPD-02 which was provided to the NRC at the beginning of the audit.

Jackson, Wilbur Finnin, Ron Thursday, June 1, 2006 Page I I of 82

Number Status Request 151 Closed

[B.1.6-J-03, BWR Stress Corrosion Cracking]

3. LRA Appendix B.1.6 (BWR Stress Corrosion Cracking) identifies an Exception to NUREG-1801. The exception is described as PNPS' use of the 1998 edition with 2000 addenda of ASME Section XI, Subsection IWB-3600 for flaw evaluation, while NUREG-1801 specifies the 1986 edition of ASME Section XI, Subsection IWB-3600 for flaw evaluation.

QUESTIONS:

Make available at the audit a copies of ASME Section XI, Subsection IWB-3600, the 1986 edition, and the 1998 edition with 2000 addenda.

Identify which specific subsections of IWB-3600 are different between the 1986 edition and 1998 edition with 2000 addenda of ASME Section Xl.

Response

Copies were made available during the audit.

Differences between paragraph IWB-3600 in the 1986 edition and the 1998 through 2000 addenda are listed below:

IWB-361 0 - The '98-2000 code has expanded this paragraph to include requirements for evaluating flaws in clad components.

Otherwise, no changes.

IWB-3641.2 - The '98-2000 code differs slightly from the '86 edition.

IWB3641.3 - The '98-2000 code differs slightly from the '86 edition.

IWB-3650 - This is a new paragraph in the later code for evaluation procedures and acceptance criteria for flaws in ferritic piping.

Table IWB-3641 Notes under the table have been expanded in the '98-2000 code.

Table data is the same.

Table IWB-3641-2

- Notes under the table have been expanded in the '98-2000 code.

Table data-is the same.

Table IWB-3641-5 Table is deleted from

'98-2000 code.

Table IWB-3641-6 Table is deleted from

'98-2000 code.

NRC Auditor PNPS Lead Jackson, Wilbur Woods, Steve Thursday, June 1, 2006 Page 12 of 82

Number Status Request 152 Accepted

[B.1.6-J-04, BWR Stress Corrosion Cracking]

4. The Standard Review Plan for License Renewal (NUREG-1800, Rev. 1),

Section 3.1.2.4, FSAR Supplement, states that "The

[summary] description [of the program in the FSAR supplement] should... contain any future aging management activities, including enhancements and commitments, to be completed before the period of extended operation."

Response

NRC Auditor PNPS Lead The enhancement, as stated in LRA Appendix B Jackson, Wilbur Finnin, Ron is 'The implementing procedure for ASME Section XI inservice inspection and testing will be enhanced to specify that the guidelines in Generic Letter 88-01 or approved BWRVIP-75 shall be considered in determining sample expansion if indications are found in Generic Letter 88-01 welds."

See Item # 320 for resolution.

PNPS LRA Appendix B.1.6 (BWR Stress Corrosion Cracking) identifies an enhancement to be initiated prior to the period of extended operation. The LRA states that

'The implementing procedure for ASME Section XI inservice inspection and testing will be enhanced to specify that the guidelines in Generic Letter 88-01 or Approved BWRVIP-75.

shall be considered in determining sample expansion if indications are found in Generic Letter 88-01 welds.

PNPS LRA UFSAR Supplement A.2.1.6 (BWR Stress Corrosion Cracking Program) does not include a description of the enhancement to PNPS' implementing procedure for ASME Section Xl inservice inspection.

QUESTION:

Include a description of the enhancement to PNPS' implementing procedure for ASME Section X1 inservice inspection in the UFSAR Supplement's description, A.2.1.6 (BWR Stress Corrosion Cracking Program).

Thursday, June 1, 2006 Page 13 of 82

Number Status Request 153 Closed

[B.1.7-J-01, BWR Vessel ID Attachment Welds]

1. For examination category B-N-2, ASME Section XI, Table IWB 2500-1, specifies VT-1 examinations for interior attachment welds within the beltline region. It specifies VT-3 examinations for interior attachment welds beyond the beltline region and for core support structure welds. The guidelines of BWRVIP-48 recommend more stringent inspections for certain attachments. Specifically, the guidelines recommend enhanced visual VT-1 examination of all safety-related attachments and those nonsafety-related attachments identified as being susceptible to IGSCC.

QUESTION:

Confirm that PNPS performs the more stringent inspections of applicable vessel ID attachment welds as recommended in BWRVIP-48.

Provide a descriptive list of the category B-N-2 vessel ID attachment welds that are inspected using the more stringent enhanced VT-1 examination techniques.

Response

PNPS follows the requirement of BWRVIP-48 (now BWRVIP-48-A) as approved by the NRC for inspections. These are:

- Jet pump riser brace - primary brace attachments

- Core Spray piping - primary bracket attachments

- Steam dryer support brackets NRC Auditor PNPS Lead Jackson, Wilbur Finnin, Ron 154 Closed

[B.1.7-J-02, BWR Vessel ID Attachment Welds]

2. Confirm PNPS AMP B.1.7 (BWR Vessel ID Attachment Welds) implements the evaluation guidelines of BWRVIP-14, BWRVIP-59 and BW RVI P-60 for evaluation of crack growth in stainless steel, nickel alloys and low alloy steels, respectively.

PNPS plant procedures require that flaws be evaluated in accordance with BWRVIP Inspection and Flaw Evaluation Guidelines for components that perform a safety function.

Subsequent BWRVIP correspondence that has been approved by the BWRVIP Executive Committee must also be considered when evaluating flaws. For components that do not perform a safety function, flaw evaluation shall be established by Design Engineering using the Condition Report process. Any flaw evaluation done by PNPS would consider all pertinent information available at that time, including the three BWRVIP documents identified in the question (and in NUREG-1801 Section XI.M4).

Jackson, Wilbur Finnin, Ron Thursday, June 1, 2006 Page 14 of 82

Number Status Request 155 Accepted

[B.1.8-J-01, BWR Vessel Internals]

1. The PNPS LRA states that top guide fluence is projected to exceed the threshold for IASCC prior to the period of extended period of operation.

The LRA states that PNPS AMP B.1.8 (BWR Vessel Internals) will be enhanced to inspect ten (10) percent of the top guide locations using enhanced visual inspection technique, EVT-1, within the the first 12 years of the period of extended operation, with one-half of the inspections (50 percent of the locations) to be completed within the first 6 years of the period of extended operation.

QUESTIONS:

Describe PNPS's plans for inspection of top guide locations during the final 8 years of the twenty-year period of extended operation.

If no inspections are planned for the final 8 years of operation, provide a technical basis for not continuing inspection of top guide locations during this part of the period of extended operation.

Response

As indicated in LRA Section B.1.8 under Enhancements, ten (10) percent of the top guide locations will be inspected using enhanced visual inspection technique, EVT-1, within the first 12 years of the period of extended operation, with one-half of the inspections (50 percent of locations) to be completed within the first 6 years of the period of extended operation. This enhancement will be revised to require inspection of an additional 5% of the top guide locations during the third 6 years of the period of extended operation.

This enhancement is Item 3 of the PNPS commitments for license renewal.

This requires an amendment to the LRA.

NRC Auditor PNPS Lead Jackson, Wilbur Finnin, Ron Thursday, June 1, 2006 Page 15 of 82

Number Status Request 156 Accepted

[B.1.8-J-02, BWR Vessel Internals]

2. The Standard Review Plan for License Renewal (NUREG-1800, Rev. 1),

Section 3.1.2.4, FSAR Supplement, states that "The

[summary] description [of the program in the FSAR supplement] should... contain any future aging management activities, including enhancements and commitments, to be completed before the period of extended operation."

PNPS LRA Appendix B.1.8 (BWR Vessel Internals Program) identifies an enhancement to be initiated prior to the period of extended operation. PNPS LRA UFSAR supplement A.2.1.8 (BWR Vessel Internals Program) does not describe this enhancement.

QUESTION:

Include a description of the enhancement to PNPS' AMP B.1.8 in the UFSAR Supplement's description of of this program.

Response

As stated in the letter submitting the license renewal application (letter number 2.06.003, dated 1/25/06), PNPS is committed to the programs listed in Appendix B, Section B.1 of the license renewal application. Enhancements to programs that are described in Appendix B of the LRA are, therefore, commitments. To facilitate tracking of the enhancements through the NRC review process and facilitate implementation once the renewed license is received, a list of specific commitments for license renewal has been developed. This list will be sent to the Staff under oath and affirmation and will be supplemented as necessary during the NRC review process.

Both Appendix B of the LRA and the list of commitments for license renewal include commitments to implement new programs and commitments to enhance existing programs before the period of extended operation.

Item 3 on the list of commitments for license renewal is the commitment to implement the enhancement to PNPS AMP B.1.8.

See Item #320 for resolution.

NRC Auditor PNPS Lead Jackson, Wilbur Finnin, Ron Thursday, June 1, 2006 Page 16 of 82

Number Status Request 157 Closed

[B.1.8-J-03, BWR Vessel Internals]

Response

A copy of BWRVIP-26 including table 3.2 was made available during the audit.

NRC Auditor PNPS Lead Jackson, Wilbur Okas, Pete

3. PNPS LRA Appendix B.1.8 (BWR Vessel Internals) identifies the following described exception to Scope of Program and Detection of Aging Effects: "Inspection of the four top guide hold-down assemblies and four top guide aligner assemblies is not performed at PNPS." An Exception Note states, "PNPS has a plant-specific analysis to account for plant-specific dynamic loading of the top guide hold-down and aligner assemblies, which concludes that less than 20% of the weld area on the top guide hold-down and aligner assemblies is needed to resist load.

Therefore, in accordance with Table 3.2 of BWRVIP-26, inspection of the four top guide hold-down assemblies and four top guide aligner assemblies is not performed at PNPS.

Questions:

Provide a staff-approved copy of BWRVIP-26, including Table 3.2, stating that inspection of the four top guide hold-down assemblies and four top aligners is not required if 20%

or less of the weld area is sufficient to resist vertical loads from the top guide during faulted events.

[B.1.8-J-04, BWR Vessel Internals]

4. Provide a status summary of current industry activities to develop a delivery system for ultrasonic testing of the hidden welds in PNPS' core spray system.

[B.1.8-J-05, BWR Vessel Internals]

5. Provide a status summary of current industry activities to develop a delivery system for ultrasonic testing of the hidden welds in PNPS' jet pump assemblies.

158 Closed The BWRVIP/ EPRI NDE center recently acquired blade probes to demonstrate UT capability. Plans for 2007 are to develop a white paper to document the inspection capability to examine the thermal sleeve welds. This project excludes tooling development as it is left to inspection vendors.

The BWRVIP/ EPRI NDE center recently acquired blade probes to demonstrate UT capability. Plans for 2007 are to develop a white paper to document the inspection capability to examine the thermal sleeve welds. This project excludes tooling development as it is left to inspection vendors.

Jackson, Wilbur Okas, Pete 159 Closed Jackson, Wilbur Okas, Pete Thursday, June 1, 2006 Page 17 of 82

Number Status Request 160 Closed

[B.1.8-J-06, BWR Vessel Internals]

6. LRA Appendix B.1.8 (BWR Vessel Internals, Operating Experience, states that "Previous visual and enhanced visual examinations of vessel internals revealed indications on core spray piping welds, and steam dryer leveling screw tack welds."

QUESTIONS:

When were the earlier indications on core spray piping welds and steam dryer level screw tack welds found?

What corrective actions were taken?

161 Closed

[B.1.8-J-07, BWR Vessel Internals]

7. GALL Section XI.M9 (BWR Vessel Internals), Element 4 (Detection of Aging Effects) states: 'The applicable and approved BWRVIP guidelines recommend more stringent inspections, such as enhanced VT-1 examinations or ultrasonic methods of volumetric inspection for certain selected components and locations:"

Response

Core spray piping welds 1 P5 and 3P5 in RF01 1, and Steam dryer level screw tack welds in RFO7.

Corrective action for the Core Spray piping 1 P5 and 3P5 UT weld UT indications that were found in 1997 (RFO11) and re-examined in 1999 consisted of the performance of flaw evaluations that accounted for both crack growth and leakage considerations. The flaw evaluations found the 1 P5 weld acceptable for continued operation for five cycles (RFO17) and the 3P5 weld acceptable for another six cycles (RFO18).

Corrective action taken in 1987 (RFO7) for the cracked steam dryer leveling screw tack welds consisted of a weld repair to the 35 and 215 degree azimuth screws. The two leveling screws were re-tacked in two places each per the disposition detailed in Nonconformance Report The PNPS BWR Vessel Internals program will perform the more stringent inspections in the BWRVIP Inspection and Evaluation Guidelines approved by the NRC for referencing for license renewal. Any exceptions to the approved BWRVIPs are discussed as exceptions to NUREG-1801.

Note that some of the specific BWRVIPs are considered part of sub-programs such as BWR Penetrations, BWR Vessel ID attachment welds, etc.; but all are implemented via the BWR Vessel Internals Program (NE 21.01) at the PNPS site.

NRC Auditor PNPS Lead Jackson, Wilbur Okas, Pete Jackson, Wilbur Okas, Pete QUESTION:

Confirm that PNPS AMP B.1.8 (BWR Vessel Internals) performs the more stringent inspections recommended in the applicable and approved BWRVIP guidelines, except as documented in PNPS LRA under the discussion of "Exceptions to NUREG-1801."

Thursday, June 1, 2006 Page 18 of 82

L.

l Number Status Request 162 Closed

[B.1.9-H-01, 10 CFR 50 Appendix J (XI.S4)]

1. The applicant is requested to address and discussion the test Option related to this program. What and when was the most significant experience related to this program do you have? What was your corrective and preventive actions did you take? When will be your next "periodic interval"?

163 Accepted

[B.1.10-P-01, Diesel Fuel Monitoring]

1. Provide justification for not cleaning and visually inspecting the security diesel generator fuel storage tank on a periodic basis.

Response

The PNPS program utilizes Option B and the guidance in NRC Regulatory Guide 1.163 and NEI 94-01. (Ref. Aging Management Program Evaluation Report LRPD-02, Section 4.8.B.5.b).

During the most recent integrated leakage testing of primary containment performed in 1995, as-found and as-left test data met all applicable test acceptance criteria. QA audits in 2000 and 2005 revealed no issues or findings that could impact effectiveness of the program.

(Ref. LRA B.1.9)

During as-found local leak ratetesting in the late 1990s, the main steam isolation valves and feedwater check valves experienced test failures. The MSIVs were modified and refurbished to improve seat leakage performance. Preventive maintenance to replace the soft seats on the feedwater check valves each refueling outage has improved the seat leakage performance.

The current ILRT periodic interval is fifteen years (no later than May 25, 2010) based on License Amendment 213 to the PNPS Facility Operating License which allowed a five year As stated in LRA Section B.1.10, the security diesel generator fuel storage tank is not periodically cleaned and inspected because the internals are inaccessible. The tank does not have manways. This is acceptable because the program enhancements described below will ensure that significant degradation is not occurring.

One enhancement listed in LRA Section B.1.20 is for periodic sampling of the security diesel generator fuel storage tank, near the bottom, to determine water content.

The other enhancement listed in LRA Section B.1.10 is to include periodic UT measurement on the bottom surface of the security diesel generator fuel storage tank. However, engineering evaluation after submittal of the LRA determined that UT is not feasible for this tank due to geometry. Therefore, this enhancement will be revised to add instrumentation to monitor for leakage between the two walls of the tank. This modification will be installed prior to the period of extended operation.

Item # 5 on the list of commitments for license renewal is the commitment to install instrumentation to monitor for leakage between the two walls of the security diesel generator fuel storage tank.

NRC Auditor Hoang, Dan PNPS Lead Ahrabli, Reza Pavinich, Wayne Potts, Lori Thursday, June 1, 2006 Page 19 of 82

Number Status Request 164 Closed

[B.1.10-P-02, Diesel Fuel Monitoring]

2. Provide justification for not using all ASTM specifications.

165 Accepted

[B.1.10-P-03, Diesel Fuel Monitoring]

3. Provide justification of the

"<= 60% of nominal thickness" acceptance criterion.

Response

The Diesel Fuel Monitoring Program makes use of the guidelines of ASTM D-2276 for determination of particulates in lieu of ASTM D-6217. ASTM D-2276 provides guidance on determining particulate contamination using a field monitor. It provides for rapid assessment of changes in contamination level without the time delay required for rigorous laboratory procedures. It also provides a laboratory filtration method using a 0.8 micron filter. ASTM D-6217 provides guidance on determining particulate contamination by sample filtration at an off-site laboratory. The acceptance criterion of D-2276 is 10 mg/liter while that of D-6217 is 24 mg/liter. Therefore, D-2276 criterion is more stringent than that of D-6217. Since ASTM D-2276 is an accepted method of determining particulates and is a method recommended by ASTM D-975, the D-2276 method'is used at PNPS.

The enhancement is being revised to, "Enhance the Diesel Fuel Monitoring Program to specify acceptance criterion for UT measurements of emergency diesel generator fuel storage tanks (T-126A&B)." This enhancement is item # 6 on the list of commitments for license renewal and will be completed prior to the period of extended operation.

This requires an amendment to the LRA.

No, as described in the Aging Management Program Evaluation Report, a periodic ultrasonic thickness (UT) measurement is performed on the bottom surface of the underground emergency diesel fuel oil storage tanks. During these inspections, UT measurements are made at several random locations on the bottom of these tanks.

In accordance with the corrective action program, an engineering evaluation into the cause will be performed if test acceptance criteria are not met and corrective actions will be implemented, to ensure that the intended function of the tanks can be maintained consistent with the current licensing basis for the period of extended operation. If appropriate to address the cause, biocide addition may be an element of the corrective action.

NRC Auditor PNPS Lead Pavinich, Wayne Pavinich, Wayne Potts, Lori Potts, Lori 166 Closed

[B.1.10-P-04, Diesel Fuel Monitoring]

4. Will all tank bottoms be subjected to 100% UT inspection?

167 Closed

[B.1.10-P-05, Diesel Fuel Monitoring]

5. If reduction of thickness is discovered during UT, will microbiological activity be monitored and biocide added in the future? If not, provide a justification for not doing so.

Pavinich, Wayne Pavinich, Wayne Potts, Lori Potts, Lori Thursday, June 1, 2006 Page 20 of 82

Number Status Request 168 Accepted

[B.1.10-P-06, Diesel Fuel Monitoring]

6. NUREG-1800, SRP for license renewal, section 3.X.3.4, FSAR Supplement, states the following:

As noted in Table 3.X-2, an applicant need not incorporate the implementation schedule into its FSAR. However, the reviewer should confirm that the applicant has identified and committed in the license renewal application to any future aging management activities, including enhancements and commitments to be completed before entering the period of extended operation. The staff expects to impose a license condition on any renewed license to ensure that the applicant will complete these activities no later than the committed date.

The enhancements identified in the B.1.10 write-up are not included in the FSAR Supplement Appendix A.2.1.10.

They should be in the UFSAR Supplement in order to address these commitments.

Response

As stated in the letter submitting the license renewal application (letter number 2.06.003, dated 1/25/06), PNPS is committed to the programs listed in Appendix B, Section B.1 of the license renewal application. Enhancements to programs that are described in Appendix B of the LRA are, therefore, commitments. To facilitate tracking of the enhancements through the NRC review process and facilitate implementation once the renewed license is received, a list of specific commitments for license renewal has been developed. This list will be sent to the Staff under oath and affirmation and will be supplemented as necessary during the NRC review process.

Both Appendix B of the LRA and the list of commitments for license renewal include commitments to implement new programs and commitments to enhance existing programs before the period of extended operation.

Items 4, 5, and 6 on the list of commitments for license renewal are the commitments to implement the enhancements described in LRA Section B.1.10 Close to item #320.

NRC Auditor PNPS Lead Pavinich, Wayne Potts, Lori Thursday, June 1, 2006 Page 21 of 82

Number Status Request 169 Accepted

[B.1.11-N-01, Environment Qualification (EQ) of Electrical Components Program]

1. The results of the environmental qualification of electrical equipment in LRA Section 4.4. indicate that the aging effects of the EQ of electrical equipment identified in the TLAA will be managed during the extended period of operation under 10 CFR 54.21(c)(1)(iii). However, no information is provided on the attribute of a reanalysis of an aging evaluation to extend the qualification life of electrical equipment identified in the TLAA. The important attributes of a reanalysis are the analytical methods, the data collection and reduction methods, the underlying assumptions, the acceptance criteria, and corrective actions.

Provide detail description on the important attributes of reanalysis of an aging evaluation of electrical equipment identified in the TLAA in the LRA or plant's basis document (under program description) to extend the qualification under.10 CFR 50.49(e).

Response

PNPS may perform reanalysis of an aging evaluation in order to extend the qualification of electrical components under 10 CFR 50.49(e) on a routine basis as part of the plant's EQ program.

As described in NUREG-1801, rev. 1, important attributes for the reanalysis of an aging evaluation include analytical methods, data collection and reduction methods, underlying assumptions, acceptance criteria, and corrective actions.

LRA Appendix B.1.11 will be revised to include the following:

EQ Component Reanalysis Attributes The reanalysis of an aging evaluation is normally performed to extend the qualification by reducing excess conservatism incorporated in the prior evaluation. Reanalysis of an aging evaluation to extend the qualification of a component is performed on a routine basis pursuant to 10 CFR 50.49(e) aspart of an EQ program. While a component life limiting condition may be due to thermal, radiation, or cyclical aging, the vast majority of component aging limits are based on thermal conditions.

Conservatism may exist in aging evaluation parameters, such as the assumed ambient temperature of the component, an unrealistically low activation energy, or in the application of a component (de-energized versus energized). The reanalysis of an aging evaluation is documented according to the station's quality assurance program requirements, which requires the verification of assumptions and conclusions. As already noted, important attributes of a reanalysis include analytical methods, data collection and reduction methods, underlying assumptions, acceptance criteria, and corrective actions (if acceptance criteria are not met). These attributes are discussed below.

Analytical Methods:

The analytical models used in the reanalysis of' an aging evaluation are the same as those previously applied during the prior evaluation.

The Arrhenius methodology is an acceptable thermal model for performing a thermal aging evaluation. The analytical method used for a radiation aging evaluation is to demonstrate qualification for the total integrated dose (that is, normal radiation dose for the projected installed life plus accident radiation dose). For license renewal, one acceptable method of establishing the 60-year normal radiation dose is to multiply the 40-year normal radiation dose by 1.5 (that is, 60 years/40 years). The result is added to the accident radiation dose to obtain the total integrated dose for the component. For cyclical aging, a similar approach may be used. Other models may be justified on a case-by-case basis.

Data Collection and Reduction Methods:

Reducing excess conservatism in the component service conditions (for example, temperature, radiation, cycles) used in the prior NRC Auditor PNPS Lead Nguyen, Duc Stroud, Mike Thursday, June 1, 2006 Page 22 of 82

Number Status Request

Response

aging evaluation is the chief method used for a reanalysis. Temperature data used in an aging evaluation is to be conservative and based on plant design temperatures or on actual plant temperature data. When used, plant temperature data can be obtained in several ways, including monitors used for technical specification compliance, other installed monitors, measurements made by plant operators during rounds, and temperature sensors on large motors (while the motor is not running). A representative number of temperature measurements are conservatively evaluated to establish the temperatures used in an aging evaluation. Plant temperature data may be used in an aging evaluation in different ways, such as (a) directly applying the plant temperature data in the evaluation, or (b) using the plant temperature data to demonstrate conservatism when using plant design temperatures for an evaluation. Any changes to material activation energy values as part of a reanalysis are to be justified on a plant-specific basis. Similar methods of reducing excess conservatism in the component service conditions used in prior aging evaluations can be used for radiation and cyclical aging.

Underlying Assumptions:

EQ component aging evaluations contain sufficient conservatism to account for most environmental changes occurring due to plant modifications and events. When unexpected adverse conditions are identified during operational or maintenance activities that affect the normal operating environment of a qualified component, the affected EQ component is evaluated and appropriate corrective actions are taken, which may include changes to the qualification bases and conclusions.

Acceptance Criteria and Corrective Actions:

The reanalysis of an aging evaluation could extend the qualification of the component. If the qualification cannot be extended by reanalysis, the component is to be refurbished, replaced, or re-qualified prior to exceeding the period for which the current qualification remains valid. A reanalysis is to be performed in a timely manner (that is, sufficient time is available to refurbish, replace, or re-qualify the component if the reanalysis is unsuccessful.

Pilgrim utilizes a reanalysis methodology in accordance with 10 CFR 50.49(e) that applies the important attributes in the GALL Report as appropriate. Reanalysis of aging evaluations in accordance with 10 CFR 50.49(e) is an acceptable AMP for license renewal under option 10 CFR 54.21 (c)(1)(iii).

NRC Auditor PNPS Lead Thursday, June 1, 2006 Page 23 of 82

Number Status Request 170 Closed

[B.1.11-N-02, Environment Qualification (EQ) of Electrical Components Program]

2. PNPS B.1.11 under operating experience, you have stated that the overall effectiveness of the EQ of electric components program is demonstrated by the excellent operating experience for systems, structures, and components in the program.

Discuss operating experience of the existing EQ program.

Show where an existing program has succeeded and where it has failed in identifying aging degradation in a timely manner.

171 Closed

[B.1.12-P-01, Fatigue Monitoring]

1. FSAR Supplement section A.2.1.12 references section 4.2.6 for location of the transient cycles that are tracked by this program.

However, section 4.2.6 addresses RPV Axial Weld Failure Probability. Should section 4.3.1, Table 4.3-2 be referenced instead?

172 Closed

[B.1.13.1-P-01, Fire Protection]

1. Provide justification why carbon dioxide fire suppression system is not subject to aging

Response

Under the EQ program, surveillance and maintenance activities are used to assure that equipment is maintained within its qualification basis and qualified life. The program provides that equipment shall be replaced, refurbished or re-qualified prior to exceeding its qualified life.

The overall effectiveness of the Environmental Qualification (EQ) of Electric Components Program is demonstrated by the excellent*

operating experience for systems, structures, and components in the program. The program has been subject to periodic internal and external assessments that have resulted in program improvement.

The Environmental Qualification (EQ) of Electric Components Program has been effective at managing aging effects. The Environmental Qualification (EQ) of Electric Components Program provides reasonable assurance that the effects of aging will be managed such that the applicable components will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation.

References:

ENN Engineering Assessment Report dated 3/1/01, and EQ Program Self-Assessment January 28, 2002 - February 01, 2002 The referenced 4.2.6 is FSAR Section 4.2.6 not LRA.

The carbon dioxide fire protection system is required for insurance purposes but is not required to protect safety-related systems.

Therefore the carbon dioxide fire protection system has no intended functions for 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(3). Also, since the system does not contain liquid that could leak and cause physical interaction with safety-related components that could prevent satisfactory accomplishment of a safety function, it also has no intended functions for 10 CFR 54.4(a)(2).

NUREG-1800, SRP for license renewal, Section A.1.2.3.4 states that Detection of Aging Effects (element 4) describes "when," "where," and "how" program data are collected. Therefore, the exception to inspection frequency for penetration seals was applied to element 4.

PNPS does not take exception to the parameters to be monitored or inspected for penetration seals. Therefore, the exception does not apply to element 3.

NRC Auditor Nguyen, Duc Das, Swapan PNPS Lead Patel, Erach Patel, Erach Patel, Erach Potts, Lori Potts, Lori Potts, Lori 173 Closed

[B.1.13.1-P-02, Fire Protection]

2. The exception taken for element 4 about the inspection frequency for penetration seals should also apply to element 3 for the same reason that it applies to element 4. Justify why this exception doe not apply to element 3.

Thursday, June 1, 2006 Page 24 of 82

Number Status Request 174 Accepted

[B. 1.13.1 -P-03, Fire Protection]

3. The two enhancements -

identified in B.1.13.1 write-up are not included in the FSAR Supplement Appendix A.1.13.

NUREG-1800, SRP for license renewal, section 3.X.3.4, FSAR Supplement, states the following:

As noted in Table 3.X 2, an applicant need not incorporate the implementation schedule into its FSAR. However, the reviewer should confirm that the applicant has identified and committed in the license renewal application to any future aging management activities, including enhancements and commitments to be completed before entering the period of extended operation. The staff expects to impose a license condition on any renewed license to ensure that the applicant will complete these activities no later than the committed date.

Response

As stated in the letter submitting the license renewal application (letter number 2.06.003, dated 1/25/06), PNPS is committed to the programs listed in Appendix B, Section B.1 of the license renewal application. Enhancements to programs that are described in Appendix B of the LRA are, therefore, commitments. To facilitate tracking of the enhancements through the NRC review process and facilitate implementation once the renewed license is received, a list of specific commitments for license renewal has been developed. This list will be sent to the Staff under oath and affirmation and will be supplemented as necessary during the NRC review process.

Both Appendix B of the LRA and the list of commitments for license renewal include commitments to implement new programs and commitments to enhance existing programs before the period of extended operation.

Items 7 and 8 on the list of commitments for license renewal are the commitments to implement the enhancements described in LRA Section B.1.13.1.

See Item #320 for closure for this Item.

NRC Auditor PNPS Lead Patel, Erach Potts, Lori The enhancements should be included in the Appendix A writeup.

Thursday, June 1, 2006 Page 25 of 82

Number Status Request 176 Accepted

[B.1.13.2-P-la, Fire Water Systerii]

1. NUREG-1800, SRP for license renewal, section 3.X.3.4, FSAR Supplement, states the following:

As noted in Table 3.X 2, an applicant need not incorporate the implementation schedule into its FSAR. However, the reviewer should confirm that the applicant has identified and committed in the license renewal application to any future aging management activities, including enhancements and commitments to be completed before entering the period of extended operation. The staff expects to impose a license condition on any renewed license to ensure that the applicant will complete these activities no later than the committed date.

a) The enhancement for wall thickness evaluation of fire protection piping is identified in the Appendix A write-up in the present tense, meaning the inspections are being performed. However, the enhancement is addressed in the Appendix B write-up is in the future tense, meaning the inspections will be performed in the future (before the end of the current operating term).

The Appendix A write-up should be revised to address this future commitment.

Response

As stated in the letter submitting the license renewal application (letter number 2.06.003, dated 1/25/06), PNPS is committed to the programs listed in Appendix B, Section B.1 of the license renewal application. Enhancements to programs that are described in Appendix B of the LRA are, therefore, commitments. To facilitate tracking of the enhancements through the NRC review process and facilitate implementation once the renewed license is received, a list of specific commitments for license renewal has been developed. This list will be sent to the Staff under oath and affirmation and will be supplemented as necessary during the NRC review process.

Both Appendix B of the LRA and the list of commitments for license renewal include commitments to implement new programs and commitments to enhance existing programs before the period of extended operation.

Item 11 on the list of commitments for license renewal is the commitment to implement the enhancement for fire water system wall thickness evaluations described in LRA Section B.1.13.

NRC Auditor PNPS Lead Patel, Erach Potts, Lori Thursday, June 1, 2006 Page 26 of 82

Number Status Request 177 Accepted

[B.1.13.2-P-lb, FireWater System]

NUREG-1800, SRP for license renewal, section 3.X.3.4, FSAR Supplement, states the following:

As noted in Table 3.X 2, an applicant need not incorporate the implementation schedule into its FSAR. However, the reviewer should confirm that the applicant has identified and committed in the license renewal application to any future aging management activities, including enhancements and commitments to be completed before entering the period of extended operation. The staff expects to impose a license condition on any renewed license to ensure that the applicant will complete these activities no later than the committed date.

Response

As stated in the letter submitting the license renewal application (letter number 2.06.003, dated 1/25/06), PNPS is committed to the programs listed in Appendix B, Section B.1 of the license renewal application. Enhancements to programs that are described in Appendix B of the LRA are, therefore, commitments. To facilitate tracking of the enhancements through the NRC review process and facilitate implementation once the renewed license is received, a list of specific commitments for license renewal has been developed. This list will be sent to the Staff under oath and affirmation and will be supplemented as necessary during the NRC review process.

Both Appendix B of the LRA and the list of commitments for license renewal include commitments to implement new programs and commitments to enhance existing programs before the period of extended operation.

Item 9 on the list of commitments for license renewal is the commitment to implement the enhancement to inspect hose reels for corrosion described in LRA Section B.1.13.2.

See Item #320 for closure for this Item.

NRC Auditor PNPS Lead Patel, Erach Potts, Lori b) The enhancement for revising procedures to include inspections of hose reels for corrosion is not addressed in the Appendix A write-up. The Appendix A write-up should be revised to address this future commitment.

178 Closed

[B.1.14-W-01, FAC]

1. How is the minimum allowable wall thickness defined in PNPS FAC program?

179 Closed

[B.1.14-W-02, FAC]

2. The FAC program includes the use of a predictive code.

Does PNPS belong to EPRI's CHECWORKS Users Group (CHUG), and CHECWORKS is being used?

For the initial evaluation of data at PNPS a screening of criteria of 0.875 of Tnominal is used to determine whether locations require further evaluation. If below this screening criteria the wear, wear rate and remaining service life are calculated in accordance with ENN-DC-315 section 5.6. PNPS uses the term minimum acceptable wall thickness (Taccept) in the FAC program. The term minimum acceptable wall thickness is defined as the maximum value of Tmin or Tcrit where Tmin is the minimum required global wall thickness based on hoop stress and Tcrit is the minimum required wall thickness per code of construction required to meet all design loading conditions.

Taccept is used in the calculation of the remaining service life which determines whether the component may be returned to service.

These definitions can be found in ENN-DC-315 in section 3.0.

As described in LRPD-02 section B.5.b CHECWORKS version 1.0F is being used at PNPS and PNPS is a member of the CHECWORKS Users Group.

Wen, Peter Wen, Peter Ivy, Ted Ivy, Ted Thursday, June 1, 2006 Page 27 of 82

Number Status Request

Response

From ENN-DC-315 rev. 1:

NRC Auditor PNPS Lead 180 Closed

[B.1.14-W-03, FAC]

Wen, Peter Ivy, Ted

3. If degradation is detected such that the measured wall thickness is less than the predicted thickness, explain how the sample size is increased to bound the thinning for the same inspection period.

5.9 DISPOSITION OF INSPECTION RESULTS

[1]

[2]

[3]

If Tpred is = 0.875 Tnom Evaluate for sample expansion (Reference section 5.12).

5.12 SAMPLE EXPANSION (1]

If a component is discovered that has a current or projected wall thickness less than the minimum acceptable wall thickness (Taccpt),

then additional inspections of identical or similar piping components in a parallel or alternate train shall be performed to bound the extent of thinning except as provided below. Reference section 5.12.2

[2] When inspections of components detects significant wall thinning and it is determined that sample expansion is required, the sample size for that line should be increased to include the following:

(a) Components within two diameters downstream of the component displaying significant wear or within two diameters upstream if the component is an expander or expanding elbow.

(b) A minimum of the next two most susceptible components from the relative wear ranking in the same train as the piping component displaying significant wall thinning.

(c) Corresponding components in each other train of a multi-train line with a configuration similar to that of the piping component Portions of the Main Steam system (Plant Heating; Reactor Vessel Vent Lines; portions of the Feedwater System (Recirculation lines to the Condenser - Feedwater clean-up line to the condenser); Feedwater Heater Start-up vent lines; portions of RCIC; and Portions of HPCI have been excluded. Inspections have been performed on some of these lines typically in response to operational issues such as valve leakage or orifice degradation occurring such that there is flow in the line during normal operation.

In RFO14 and RFO15 the Feedwater recycle line (FAC pt# 366) was inspected to verify that a leaking valve had not caused damage. The piping wall thickness was found to not have appreciably changed during the two inspections which provided evidence that significant wear of the piping had not and was not occurring. In RFO15 the RCIC minimum flow bypass line (FAC pt# 376) was inspected due to suspected valve leak by and the downstream piping was found to show no significant wear based on wall thickness.

181 Closed

[B.1.14-W-04, FAC]

4. In the Program Description, the applicant states that "This program applies to safety-related and nonsafety-related carbon steel components in systems containing high-energy fluids carrying two-phase or single-phase high-energy fluid >

2% of plant operating time."

Which piping systems are excluded from the FAC program scoping as a result of low operating time (i.e., < 2% of plant operating time)? Has any inspection ever been performed to make sure that there is no wear on these lines?

Wen, Peter Bechen, Gerry Thursday, June 1, 2006 Page 28 of 82

Number Status Request 182 Closed

[B.1.14-W-05, FAC]

Describe the experience of FAC program at PNPS and the ability of the inspection programs to detect wall thinning in a timely manner before the intended function of piping components has been lost:

1 Have components been identified that did not meet the minimum allowable wall thickness prior to replacement or loss of pressure retaining capacity?

2. What corrective actions have been taken, and to what extent have these measures been effective in eliminating or reducing the wall thinning?

3. What changes to the program have occurred to ensure that aging effects due to FAC have been successfully managed?

4. Provide evidence that the current aging management program has been effective to successfully mitigate and detect wall thinning during the time period addressed by the

Response

1. For example, in RFO14, FAC pt #319 and pt# 371 (1st point "B" operating vent line) were inspected and found below Taccept. This piping was upgraded with chrome-moly. FAC pt# 128.2 was inspected in RFO14 (Tscreen was less than required) and again in RFO15 to verify Tmin was not met. The issue is apparently due a low point on a socket weld and not FAC wear.

The affected piping is scheduled for replacement in RFO16.

Additionally, one of the 30" extraction steam lines to the 5th point heater was inspected in RFO13 and found to have a hole in it and was repaired. This piping is inside the condenser.

Additional inspections were performed and general FAC degradation was noted on most of the lines. The decision was made replace all of this piping with chrome-moly piping. The last of it is scheduled for replacement in RFO16.

In RFO14 FAC pt# 307 was inspected and found to have a wall thickness less than Tscreen.

Re-evaluation concluded the location was acceptable for operation thru RFO1 6. The component is currently scheduled for re-inspection in RFO16

2. Piping upgrade to FAC resistant material.

such as A335 Gr. P11 piping has been extremely effective in eliminating or reducing the loss of wall thickness. Additionally, in some cases, the degraded components have been replaced in-kind. Measures also include:

changing out leaking valves, changing out degraded restriction orifices, etc.

3. As documented in LRPD-05 section 4.1.14, a fleet wide procedure for the Entergy northeast plants has been developed that includes improvements based on industry and other Entergy Nuclear Northeast plant OE. For example, skid mounted piping is now included in the enhanced system susceptibility evaluation.

In addition, during RFO15, several FAC points were added to inspections, or re-inspected, in response to industry OE and the MIHAMA Japan failure.

4. As documented in LRPD-05 section 4.1.14, examinations between RFO13 and RFO14 and during RFO14 (April, 2003) and examinations between RFO14 and RFO15) and during RFO15 (April, 2005) detected 8 locations with decreased wall thickness. Of these 8 locations four were either replaced or repaired and the remainder were determined to be acceptable after reevaluation.

NRC Auditor PNPS Lead Wen, Peter Ivy, Ted Thursday, June 1, 2006 Page 29 of 82

Number Status Request 183 Closed

[B.1.15-P-01, Heat Exchanger Monitoring]

1. What method(s) will be used to detect localized corrosion?

Identify areas to be inspected and frequency of inspections for localized corrosion.

184 Closed

[B.1.15-P-02, Heat Exchanger Monitoring]

2. Provide additional details describing the methods that will be used establish sample size and frequency.

185 Closed

[B.1.15-P-03, Heat Exchanger Monitoring]

3. Provide details on data collection.

186 Closed

[B.1.15-P-04, Heat Exchanger Monitoring]

4. Provide details describing the methods to assess remaining component life for loss of material using inspection results such that timely mitigative action can be made.

Response

This is a new program and the details have not yet been developed. In accordance with LRPD-02 sections 3.2.B.3 and 3.2.B.4, where practical, eddy current inspections of shell-and-tube heat exchanger tubes will be performed to determine tube wall thickness.

Visual inspections will be performed on heat exchanger heads, covers and tube sheets where accessible to monitor surface condition for indications of loss of material such as areas where localized corrosion could occur (i.e.

stagnant/low flow areas). A potential approach for determining the inspection frequency would be that once the initial inspections are completed, the results would be used to determine the frequency to ensure that effects of aging are identified prior to loss of intended function. Inspection frequency will be dependent on the specific component operating parameters (process fluid, cooling medium, pressures, materials), maintenance history, licensing commitments, NEIL Loss Control Standards and OE.

A review of the specific component's mechanical design, environments, operating conditions and flow paths combined with its maintenance history, and internal and external OE will be used to determine the sample size and frequency. The sample size will most likely include peripheral tubes and areas within a particular heat exchanger that are more susceptible to wear, corrosion or damage, i.e.

adjacent to inlet/outlet nozzles and changes in flow direction and will consider industry best practices and EPRI recommendations. Once the initial inspections are completed, the results will be used to determine the frequency to ensure that effects of aging are identified prior to loss of intended function. Visual inspections of accessible heat exchangers will be performed on the same frequency as eddy current inspections.

Since this is a new program the details of data collection are not available. However, inspections will be performed either online or during refueling outages (dependent on the particular component). The data will be collected, analyzed and required actions taken at that time. The data will also be utilized for longer term trending and developing future action plans and will be maintained in accordance with site QA program requirements.

Because this is a new program exact details are not yet available. Wall thickness will be trended and projected to the next inspection.

Corrective actions will be taken if projections indicate that the acceptance criteria may not be met at the next inspection. Reference LRPD-02 section 3.2.B.6. Trend information along with OE will be utilized to determine the remaining component life.

NRC Auditor PNPS Lead Pavinich, Wayne Pavinich, Wayne Pavinich, Wayne Pavinich, Wayne Ivy, Ted Ivy, Ted Ivy, Ted Ivy, Ted Thursday, June 1, 2006 Page 30 of 82

Number Status Request 187 Closed

[B.1.15-P-05, Heat Exchanger Monitoring]

5. Provide more details on how acceptance criteria will be established.

188 Closed

[B.1.15-P-06, Heat Exchanger Monitoring]

6. Although this is a new program, provide operating experience with respect to heat exchanger wall thinning and other degradation resulting from adherence to GL 89-13.

Response

The minimum acceptable tube wall thickness for each heat exchanger to be eddy current inspected will be established based upon a component specific engineering evaluation based on code requirements, EPRI guidelines, and internal calculations. Wall thickness will be acceptable if greater than the minimum wall thickness for the component. The acceptance criterion for visual inspections of heat exchanger heads, covers and tubesheets will be no evidence of degradation that could lead to loss of function. If degradation is detected such that if not corrected it would lead to loss of intended function, a condition report will be written and the issue resolved in accordance with the. site corrective action program.

Reference LRPD-02 section 3.2.B.6 GL 89-13 requires inspection of one RBCCW heat exchanger each refuel outage. Service water side inspections have resulted in some minimal tube plugging and weld or belzona repair to washed out areas on the pass partition plate or tube sheet. Past inspections have also identified degraded gasket seating surfaces and tube inlet sleeve erosion that have required repairs. The copper nickel tube degradation is typically due to internal erosion caused by material wedged in the tube and is random in location. There has also been external tube damage in the area impacted by the shell side inlet flow due to vibration. This particular OE is included in the Service Water Integrity Program (SWIP) B.1.28 since it is a heat exchanger in the scope of the SWIP and the OE confirms the effectiveness of the SWIP. In accordance with NEI 95-10 the review of operating experience is used to either confirm the effectiveness of an existing program or identify new site specific aging effects. For new programs such as the Heat Exchanger Monitoring Program B.1.15, applying this as OE is not required.

NRC Auditor PNPS Lead Pavinich, Wayne Pavinich, Wayne Ivy, Ted Lane, Ken Thursday, June 1, 2006 Page 31 of 82

Number Status 189 Closed Request

[B.1.16.1-H-01, COi]

1. Pilgrim AMP B.1.16.1 identifies that the Containment Inservice Inspection (CII) program is a plant-specific program encompassing the requirements for the inspection of class MC. The applicant is requested to identify the document(s) that includes the evaluation of Pilgrim AMP B.1.16.1 to include additional MC supports. Please provide the following information related to:

(a) Identify the MC supports that are currently included in the existing inspection program.

(b) Identify the MC supports that will be added to the scope of this inspection program for the license renewal period.

(c) Specify the current inspection program and describe the current inspection details for the MC supports that are identified in (b) above.

(d) Confirm that, all MC supports will be included in the scope of this inspection program for the extended period of operation.

Response

a. Torus supports and RPV stabilizer supports.

The program document is PNPS-RPT--05-001.

All torus supports, earthquake ties and upper drywell stabilizer supports are scheduled for examination during the PNPS 4th ten-year inspection interval.

b.Torus supports and RPV stabilizer supports.

The program document is PNPS-RPT-05-001.

All torus supports, earthquake ties and upper drywell stabilizer supports are currently scheduled for examination during the PNPS 4th ten-year inspection interval. There are no other supports to add.

c. These are under the ASME Section XI program and require VT-3 inspection.

The Class MC supports at PNPS consist of 16 torus saddle supports, 4 torus earthquake ties and 8 upper drywell stabilizers. The original [WE program at PNPS was developed in accordance with the requirements ASME XI 1992 edition with 1992 addenda after the IWE section of the code was mandated in 1996. This edition of the code did not require inspection of Class MC supports. However, as a conservative measure, PNPS included a sample of 25% of the torus saddle supports, 25% of the earthquake ties, and 25% of the upper drywell stabilizers.

The current IWE Program at PNPS was developed in accordance with the 1998 edition with 2000 addenda of ASME XL. This code edition requires that 100% of the Class MC supports be examined during the ten year interval. Accordingly, all torus supports, earthquake ties and upper drywell stabilizer supports are currently scheduled for examination during the PNPS 4th ten-year inspection interval. The first examinations under the 4th interval IWE program will occur immediately prior to and during RFO1 6 in 2007.

The torus saddle supports and earthquake ties are accessible to inspection as they are located on the torus floor. Inspection of the upper drywell stabilizers requires the removal of bolted access hatches to perform the required visual inspections. These hatches constitute a portion of the primary containment pressure boundary and are tested in accordance with Appendix J requirements after each opening.

d. These are currently included in the 4Th interval ISI program which expires in June 2015.

The next interval will be updated and maintained as required by 10 CFR 50.55(a) and ASME Section requirements.

All torus supports, earthquake ties and upper drywell stabilizer supports continue to be examined in accordance with the PNPS IWE Program during the period of extended operation.

NRC Auditor PNPS Lead Hoang, Dan Pardee, Rich Thursday, June 1, 2006 Page 32 of 82

Number Status Request 190 Closed

[B.1.16.1-H-02, CIlI]

2. The applicant is requested to identify and provide the Inspection frequency against the AMP B.1.16.1. What is the cause for "Loose" torus anchor bolt found in 1999? Are there any other "loose and/or degraded" situations identified?

Are there any Preventive Action for the Torus shell wall (thin wall)? Provide an examination details, acceptance criteria, qualifications, and documentation.

Response

The condition discovered in 1999 involved two torus saddle support tie-down nuts. The anchor bolts themselves were not loose.

The loose condition of the two torus saddle support tie-down nuts was, discovered during a scheduled PNPS ]WE Program visual examination of containment supports in 1999.

Nonconformance Report NCR 99-19 and Problem Report PR 99.9102 were generated to document and investigate the condition.

Corrective actions included re-torquing the two loose tie-down nuts to 80 ft-lb and checking the tightness of a sample of the remaining tie down nuts. No other loose bolting conditions were identified. The tightness of the support tie-down nuts is unrelated to torus anchor bolt tension as the upper tie-down bolting connects the torus saddle support to the free upper end of the anchor bolt, and is not used to tension the anchor bolt to the concrete floor.

The cause of the two loose tie-down nuts found in 1999 may be indeterminate given the information available at this point in time.

Inadequate initial preload during installation of the torus saddle supports during the Torus Mark I containment modifications in 1980 is considered to be an unlikely cause due to the high level of QA oversight on the project which included direct OC inspection of anchor bolt installation and torquing process.

The loose bolting condition is not significant because the safety function of the torus saddle support tie-down bolting is to prevent vertical movement of the torus from a hydrodynamic event occurring during accident conditions. The 80 ft-lb torque for these nuts is intended to ensure the nuts remain in a flush condition with the saddle support bearing surface. As long as no gap exists between the tie-down nuts and the torus saddle support bearing surface, the support will perform the intended safety function. No gaps existed between the two loose nuts found in 1999 and saddle support surfaces.

In addition, unrelated to the condition discussed above, a corrosion assessment of torus saddle tiedown concrete anchor bolt assemblies was performed in 1999 and documented in supplier design document review form SUDDS/RF99-134. The assessment determined that ground water intrusion through the torus floor had not significantly degraded the tensile strength of the rock anchor bolts based on chemical testing of the groundwater.

PNPS monitors torus wall thickness via the inclusion of augmented UT thickness examinations in the PNPS IWE Program. These thickness examinations are performed at 8 locations distributed around the torus. Half of the inspections are performed at the torus vapor/water interface of the torus shell while the other half are performed at a location approximately halfway between the waterline and the lowest point on the torus shell. Torus shell thickness examinations are performed NRC Auditor PNPS Lead Hoang, Dan Pardee, Rich Thursday, June 1, 2006 Page 33 of 82

Number Status Request 191 Closed

[B.1.16.1-H-03, Cll]

3. The applicant is requested to address the results of the CII general walkdown of primary containment during April 2003 (RFO 14) and found some surface corrosion in the CRD penetration areas. What were your corrective and preventive action? Did a Root Cause Analysis was performed? Please provide your acceptance criteria, qualification? And/or any other means to support your conclusion?

Response

during each 40 month period (i.e. every other outage) while the plant is on-line. Comparison of UT results from 1999 and 2003 reveal no measurable change in wall thickness. These examinations will continue to be performed during the period of extended operation. The examinations are performed by qualified NDE technicians who are code certified to at least Level II in ultrasonic thickness measurement Results of the IWE General Visual Walkdown performed during RFO14 are evaluated and dispositioned in Condition Report CR-PNP-2003-01618. Newly reported corrosion around the CRD penetrations at the 270 degree azimuth at approximately 35 feet elevation in the drywell was re-checked visually by the IWE Responsible/Design Engineer and found acceptable. This was characterized as surface corrosion that was not considered significant by the Responsible/Design Engineer. Since the determination was that the corrosion was acceptable, no root cause analysis was performed and no corrective or preventive actions were required. Acceptance criteria for the General Visual Walkdown are detailed in procedure PNPS 2.1.8.7 and Entergy Engineering Standard ENN-EP-S-001, Section 5.

Conditions listed as requiring evaluation include, in part, peeling, flaking, blistering, cracking, checking, absence of coating, and rusting of the containment coating.

NRC Auditor PNPS Lead Hoang, Dan Pardee, Rich Thursday, June 1, 2006 Page 34 of 82

Number Status Request 192 Closed

[B.1.16.1-H-04, CII]

4. The applicant is requested to address and discussion the Operating Experience in detail found in 1999, the below-water regions of all 16 torus bays as well as the drywell to torus vent areas. Did your scope expansion was required due to unacceptable found? Do you have any Preventive Actions to prevent it from further damaged and/or recur? If yes, why it's not including into this program?

Response

PNPS performs desludging, inspection and coating repairs every other outage as part of the torus desludge project on torus below-water surfaces in accordance with a Preventive Maintenance (PM) task scheduled using the plant Master Surveillance Tracking Program (MSTP).

This task was performed most recently in the 1999 and 2003 outages. During the 1999 outage (RFO1 2), [WE visual examinations were also performed by certified divers in accordance with the PNPS IWE Program.

The 1999 [WE underwater visual examinations revealed the approximately 80% of the surfaces to be in fair good condition with sporadic coating defects (localized corrosion with pitting) identified in the remaining areas. Corrosion of the torus underwater surfaces is attributed to local zinc depletion in the zinc-rich protective coating. Pit depth measurements were taken and documented in the SG Pinney report and Problem Report PR 99.1345. All areas with pit depths measured at 0.032" and greater were recoated with a qualified coating. One pit exceeded the maximum allowable depth of 0.066 inches. This was determined to be a preservice gouge in the torus shell plate and was subsequently accepted by evaluation. None of the 1999 inspection results of torus underwater surfaces were considered significant (Ref. PR 99.1345 response). The current general corrosion rates determined from inspection data collected since 1991 will not result in pitting corrosion that would cause violating the general minimum wall thickness values for the torus shell by the end of the period of extended operation.

Preventive actions to prevent recurrence of pitting consists of coating repairs with qualified coatings and periodic inspections associated with the torus desludge project every other outage. The IWE VT-3 visual examination of submerged surfaces is also performed every 10 years in accordance with the PNPS IWE Program.

Augmented IWE visual examinations of selected portions of the drywell to torus vent system in 1999 revealed localized pitting due to degradation of the coating aggravated by standing water in the downcomer vent bowls (vent bowl drains had been cut and capped in a previousmodification for seismic considerations). The scope of the examinations was expanded to include all 8 vents. All pitting was evaluated and found to be acceptable. The surfaces were prepped and recoated with a qualified coating to prevent recurrence of the corrosion.

NRC Auditor PNPS Lead Hoang, Dan Pardee, Rich Thursday, June 1, 2006 Page 35 of 82

Number Status Request 193 Closed

[B.1.16.1-H-05, CII]

5. "The drywell coolers, including the fans, with their power and control system were tested during the pre-operational tests...". When was the last time this system underwent a functional test? A justification for an additional 20 years is needed for the staff to review.

Response

The drywell coolers are a continuous operating online system. Functional tests are not required because the system is constantly running and the drywell temperature is maintained below the tech spec limits:

LIMITING CONDITIONS FOR OPERATION 3.2 PROTECTIVE INSTRUMENTATION H. Drywell Temperature

1. The drywell temperature shall be maintained within the following limits when the reactor coolant temperature is above 212'F.

Above elevation 40' <=1 94°F Equal to or Below elevation 40' <=150°F SURVEILLANCE REQUIREMENTS 4.2 PROTECTIVE INSTRUMENTATION H. Drywell Temperature

1. When reactor coolant temperature is above 212°F, the drywell air temperature limits will be determined by reading the instruments listed in Table 3.2.H. These instruments shall be logged once per shift, and each reading compared to the limits of Section 3.2.H.1.

The drywell coolers are not required during an accident, and have no mission time or required temperature to meet and have no auto start functions.

Preventative maintenance is preformed during each refueling outages and coil cleaning is performed as required.

NRC Auditor PNPS Lead Hoang, Dan Ahrabli, Reza Thursday, June 1, 2006 Page 36 of 82

Number Status Request 194 Closed

[B.1.16.2-J-01, SI]

1. The LRA states that PNPS' AMP B.1.16.2 (Inservice Inspection) ISI Program is a plant-specific program encompassing ASME Section X1, Subsections IWA, IWB, IWC, IWD and IWF requirements. The LRA states that the ASME code edition and addenda used for the fourth interval is the 1998 edition with 2000 addenda. The LRA states that PNPS entered its fourth

[ten-year] ISI interval on July 1,2005.

QUESTIONS:

Clarify whether PNPS' AMP B.1.16.2 includes any exceptions or alternatives to the requirements of ASME Section XI, 1998 edition with 2000 addenda, granted oi imposed under the provisions of' 10 CFR 50.55a.

Response

The following table lists exceptions or alternatives related to inservice inspection at the Pilgrim Nuclear Power Station during the fourth ten-year interval, which expires on June 30, 2015. Technical justifications for these exceptions and alternatives is included in PNPS-RPT-05-001, which is available for on-site review.

PRR-2 Alternate Criteria for Class 1 Pressure Tests of Piping, Pumps, and Valves (Category B-P, Item Nos. B15.10, B15.50, B15.60, B15.70).

PRR-4 Relief from leakage testing of 1" and less vent and drain lines and valves. Category B-P, Items B15.50 and B15.70 require the system leakage test to include all ASME Code Class 1 components within the system boundary.

PRR-5 (Approved - NRC SER issued) Relief from Supplement 10 for examination of Category B-F dissimilar metal (DSM) welds. The Final Rule, 64 FR 51370, dated 09/22/1999, required Pilgrim to implement a program to comply with Supplement 10 by 11/22/2002.

Supplement 10 contains the qualification requirements for procedures, equipment, and personnel involved with examining DSM welds using ultrasonic techniques.

PRR-9 (Approved - NRC SER issued) Relief from ASME Code Section XI, Mandatory Appendix VIII, Supplement 11 for pressure retaining piping weld overlay examination.

PRR-10 Risk-Informed ISI (RI-ISI): Relief from Category B-F & B-J weld examinations.

The following exceptions or alternatives relate to components covered by BWRVIP programs.

PRR-11 (Approved - NRC. SER issued) Relief from code RPV shell-to-flange weld UT exam requirements conducted in accordance with Article 4 of ASME Section V, supplemented by the requirements of Table 1-2000-1.

PRR-15 Alternative Contingency Repair Plan for RPV nozzle safe-end and dissimilar metal piping welds using ASME Code Cases N-638 and N-504-2 with exceptions.

Previously approved 3rd interval exceptions or alternatives applicable to the 4th interval (expiration date 6/8/2012):

PRR-28 Alternative to exam requirements of RPV circumferential shell welds (Item B1.10 of Exam Category B-A).

PRR-39 Full structural weld overlay contingency repairs for the welds associated with austenitic RPV nozzle safe-end and dissimilar metal piping welds.

NRC Auditor PNPS Lead Jackson, Wilbur Pardee, Rich Thursday, June 1, 2006 Page 37 of 82

Number Status Request 195 Closed

[B.1.16.2-J-02, ISI]

2. The PNPS LRA, Appendix B. 1.16.2 (Inservice Inspection),

under Scope of Program, states, "The ISI Program manages cracking, loss of material, and reduction of fracture toughness of reactor coolant system piping, components, and supports.

LRA Table 3.2.1-3 identifies reactor recirculation pump casings and covers, main steamline flow restrictors and valve bodies (>= 4" NPS and <

4"NPS) made of CASS as subject to the aging effect of reduction of fracture toughness. The aging management program is either Inservice Inspection or One-Time Inspection.

The SRP-LRA (NUREG-1800, Rev.1), Appendix A.1.2.3.4 (Detection of Aging Effects),

states that the applicant should "Provide information that links the parameters to be monitored or inspected to the aging effect being managed."

QUESTIONS:

Discuss how the parameters to be monitored by the ISI Program or One-Time Inspection are linked to the aging effect of reduction in fracture toughness?

Which valves are subject to the aging effect of reduction in fracture toughness? (Please provide either valve numbers and drawing references or a functional description of the valves.)

Response

LRA Table 3.1.2-3 identifies reactor recirculation pump casings and covers and valve bodies >=4" NPS made of CASS as subject to the aging effect of reduction of fracture toughness. The aging management program is Inservice Inspection. As stated in NUREG-1 801, the ASME Section Xl inspection requirements are sufficient for managing the effects of loss of fracture toughness due to thermal aging embrittlement of CASS pump casings and valve bodies. The Inservice Inspection Program uses NDE techniques specified in ASME Section XI to monitor for the presence and extent of cracking which provides indication of reduction in fracture toughness for these CASS components.

LRA Table 3.1.2-3 identifies main steamline flow restrictors and valve bodies < 4"NPS made of CASS as subject to the aging effect of reduction of fracture toughness. The aging management program is One-Time Inspection.

The One-Time Inspection Program uses NDE techniques consistent with those specified in ASME Section XI to monitor for the presence and extent of cracking which provides indication of reduction in fracture toughness for these CASS components.

Since the One-Time Inspection Program is a new program, the list of valves subject.to the aging effect of reduction of fracture toughness has not yet been compiled. However, the One-Time Inspection program (described in LRA section B.1.23) will inspect a representative sample of CASS components exposed to treated water

>482 degrees F with emphasis on the most susceptible components.

NRC Auditor PNPS Lead Jackson, Wilbur Potts, Lori Thursday, June 1, 2006 Page 38 of 82

Number Status Request 196 Accepted

[B.1.16.2-J-03, ISI]

3. The SRP-LRA (NUREG-1800, Rev.1),

Appendix A.1.2.3.5 (Monitoring and Trending), Paragraph 2, states:.The parameter or indicator trended should be described. The methodology for analyzirng the inspection or test results against the acceptance criteria should be described.

PNPS LRA Appendix B.1.16.2 (Inservice Inspection), Section 5 (Monitoring and Trending),

does not describe the parameter(s) or indicator(s) being trended nor the methodology for analyzing the inspection or test results, either explicitly or by reference to specific standards tables.

QUESTONS:

For PNPS plant-specific AMP B.1.16.2, please provide a description of the parameter(s) or indicator(s) being trended and of the methodology for analyzing the inspection or test 197 Closed

[B.1.17-P-01, Instrument Air Quality]

1. Provide a list of components or systems that are subject to the Instrument Air Quality Program.

198 Closed

[B.1.17-P-02, Instrument Air Quality))

2. General questions. What commitments were made as a result of the PNPS response to NRC GL 88-14? What industry standards are used for preventative actions and detection of aging effects?

199 Closed

[B.1.17-P-03, Instrument Air Quality]

3. Provide details describing the methods that determine deteriorating air quality.

200 Closed

[B.1.17-P-04, Instrument Air Quality]

4. Provide the basis for the acceptance criteria for dew point, oil mist and particulate including any industry standards invoked.

Response

The parameter(s) or indicator(s) being trended and the methodology for analyzing the inspection or test results are in accordance with the requirements of ASME Section XI. As described in LRA Section B.1.16.2, the Inservice Inspection Program uses nondestructive examination (NDE) techniques to detect and characterize surface and subsurface flaws.

Therefore, the parameter being trended is the presence of a flaw indication.

Results are compared, as appropriate, to baseline data and other previous test results.

Indications are evaluated in accordance with ASME Section Xl. If the component is qualified as acceptable for continued service, the area containing the indication is reexamined during subsequent inspection periods. Examinations that reveal indications that exceed the acceptance standards are extended to include additional examinations in accordance with ASME Section Xl.

LRA Section B.1.16.2, attribute 5, Monitoring and Trending will be amended to include this clarification.

NRC Auditor Jackson, Wilbur PNPS Lead Potts, Lori Tubing and valve bodies are managed in the standby gas treatment system.

Piping, tanks, tubing, and valve bodies are managed in the instrument air system.

The responses to GL 88-14 are included in initial response letter BECo letter 89-010, Response to Generic Letter 88-14: Instrument Air Supply system Problems Affecting Safety Related Equipment, dated February 3, 1989, Docket 50-293 and supplementary response letter BECo letter 89-071, dated May 30, 1989 which outline commitments and applicable industry standards. A copy of this information is Deteriorating air quality is detected by trending of air quality test results, by procedure PNPS 7.1.69, System Air Quality Sampling in Section

8. A copy of this procedure is available for The instrument air systems are sampled and tested to the requirements of ANSI/ISA 7.3 per procedure PNPS 7.1.69, System Air Quality Sampling. A copy of this procedure is available for review.

Pavinich, Wayne Ivy, Ted Pavinich, Wayne Ivy, Ted Pavinich, Wayne Ivy, Ted Pavinich, Wayne Ivy, Ted Thursday, June 1, 2006 Page 39 of 82

Number Status Request 201 Accepted

[B.1.17-P-05, Instrument Air Quality]

5. NUREG-1800, SRPfor Ilicense renewal, section

• 3.X.3.4, FSAR Supplement, states the following:

As noted in Table 3.X-2, an applicant need not incorporate the implementation schedule into its FSAR. However, the reviewer should confirm that the applicant has identified and committed in the license renewal application to any future aging management activities, including enhancements and commitments to be completed before entering the period of extended operation. The staff expects to impose a license condition on any renewed license to ensure that the applicant will complete these activities no later than the committed date.

The enhancements identified in the B.1.17 write-up are not included in the FSAR Supplement Appendix A.2.1.19.

They should be in the UFSAR Supplement in order to address these commitments.

Response

As stated in the letter submitting the license renewal application (letter number 2.06.003, dated 1/25/06), PNPS is committed to the programs listed in Appendix B, Section B.1 of the license renewal application. Enhancements to programs that are described in Appendix B of the LRA are, therefore, commitments. To facilitate tracking of the enhancements through the NRC review process and facilitate implementation once the renewed license is received, a list of specific commitments for license renewal has been developed. This list will be sent to the Staff under oath and affirmation and will be supplemented as necessary during the NRC review process.

Both Appendix B of the LRA and the list of commitments for license renewal include commitments to implement new programs and commitments to enhance existing programs before the period of extended operation.

Item 13 on the list of commitments for license renewal is the commitment to enhance the Instrument Air Quality Program to include a sample point in the standby gas treatment and torus vacuum breaker instrument air subsystem in addition to the instrument air header sample points described in LRA Section B.1.1 See Item #320 for closure for this item.

NRC Auditor PNPS Lead Pavinich, Wayne Ivy, Ted Thursday, June 1, 2006 Page 40 of 82

Number Status Request

Response

NRC Auditor PNPS Lead 203 Accepted

[B.1.18-N-01, Metal Enclosed Bus Inspection]

1. PNPS AMP B.1.18, under Detection of Aging Affects, you have states that PNPS takes an exception to GALL XI.E4 by visual inspection of metal enclosed bus (MEB) bolted connections every 10 years. GALL XI.E4 under the same element states that as an alternate to thermography or measuring connection resistance of bolted connections, for the accessible bolted connections that are covered with heat shrink tape, sleeving, insulated boots, etc.

(emphasis added), the applicant may use visual inspection of insulation material to detect surface anomalies, such as discoloration, cracking, chipping or surface contamination.

When this alternate visual inspection is used to check bolted connections, the first inspection will be completed before the period of extended operation and every five years thereafter. NUREG-1833, Table IV, Justification for Changes in Aging Management Programs, states that since the visual inspection is less effective than testing, this inspection (visual) is to be performed once every five years instead of once every 10 years.

a. Are all bolted connections covered with heat shrink tape, sleeving, or insulated boots? If they are, justify the 10 years frequency vs. the five years as recomnmended by NUREG-180.1.

b. If they are not, justify the visual inspection vs GALL's recommended thermography and/or resistance connections.

Since MEB bolted connections are covered with Nguyen, Duc heat shrink tape or insulating boots per manufacturer's recommendations, a sample of accessible bolted connections will be visually inspected for insulation material surface anomalies. Internal portions of the MEBs will be inspected for cracks, corrosion, foreign debris, excessive dust buildup, and evidence of water intrusion. Bus insulation will be inspected for signs of embrittlement, cracking, melting, swelling, or discoloration, which may indicate overheating or aging degradation. Internal bus supports will be inspected for structural integrity and signs of cracks.

An inspection will occur before the end of the initial 40-year license term and every 5 years thereafter.

If degradation is found in the metal-enclosed bus materials, an engineering evaluation will be performed when the inspection acceptance criteria are not met in order to ensure that the intended functions of the metal-enclosed bus can be maintained consistent with the current licensing basis. This evaluation is performed in accordance with the Entergy corrective action process per procedure EN-LI-102. This procedure provides the stated elements to consider including the extent of the concern, the potential root causes for not meeting the test acceptance criteria, the corrective actions required, and likelihood of recurrence.

This engineering evaluation will determine the frequency of the next inspection, which will not exceed 5 years LRA Appendix A.2.1.20 will be revised to "5 years".

LRA Appendix B.1.18 will be revised to remove the exception to 5 years.

This requires an amendment to the LRA.

Stroud, Mike Thursday, June 1, 2006 Page 41 of 82

Number Status Request 204 Accepted

[B.1.18-N-02, Metal Enclosed Bus Inspection]

2. In LRA, Section B.1.18 you have states that the program attribute of the Metal-Enclosed Bus (MEB) Inspection program at PNPS will be consistent with the program attribute described in NUREG-1801,Section XI.E4, Metal Enclosed Bus Aging Management Program with an exception. The exception is to inspect MEB enclosure assemblies in addition to internal surfaces using the MEB Inspection Program. GALL XI.E4 referred structures monitoring program for inspecting the metal enclosure bus assemblies. In addition to inspecting the enclosure assemblies for loss of material due to general corrosion, GALL's structure monitoring program also requires inspecting the enclosure seals for hardening and loss of strength due elastomers degradation. Are these enclosure seals included in the scope of MEB inspection program? What is the acceptance criteria for inspecting the enclosure assemblies?

205 Closed

[B.1.18-N-03, Metal Enclosed Bus Inspection]

3. In LRA, Section B.1.18, under Operating Experience, you have stated that the Metal Enclosed Bus Inspection Program at PNPS is a new program for which there is no operating experience.

NUREG-1800, Rev. 1, Appendix A, Branch Technical Position RLSB-1 states that an applicant may have to commit to providing operating experience in the future for new program to confirm their effectiveness.

Describe how operating experience will be captured to confirm the program effectiveness or to be used to adjust the program as needed.

Response

The PNPS metal-enclosed bus program will visually inspect the enclosure assemblies for evidence of loss of material and enclosure assembly elastomers will be visually inspected and manually flexed.

Revise LRPD-02 to read as follows: (Section 3.3.B.6.b - Acceptance Criteria - add after first paragraph) The acceptance criteria for enclosure assemblies will be no loss of material due to general corrosion. The acceptance criteria for elastomers will be no hardening and loss of strength due to degradation.

NRC Auditor PNPS Lead Nguyen, Duc Stroud, Mike Operating Experience at PNPS is controlled by procedure EN-OP-100, Operating Experience Program. The program includes the following components:

Operating Experience - Information received from various industry sources that describe events, issues, equipment failures, that may represent opportunities to apply lessons learned to avoid negative consequences or to recreate positive experiences as applicable.

Internal Operating Experience - Operating experience that originates as a condition report or request from plant personnel which warrants consideration for possible Entergy-wide distribution. Internal OE can originate from any Entergy plant or headquarters.

Impact Evaluation - Analysis of an OE event or problem that requires additional information and research to determine impact or potential impact, as it relates to plant condition and/or configuration. Impact evaluations are typically documented with a condition report.

Condition report action items and corrective actions are used to confirm program effectiveness and to modify the program as needed.

Nguyen, Duc Stroud, Mike Thursday, June 1, 2006 Page 42 of 82

Number Status Request 206 Accepted

[B.1.19-N-01, Non-EQ Inaccessible Medium Voltage Cable Program]

1. GALL XI.E3 under Detection of Aging Effects recommends that the inspection for water collection should be performed based on actual plant experience with water accumulation in the manhole.

However, the inspection frequency should be at least once every two years.

LRPD-02, Rev. 1, Section 3.4, under the same attribute, states that inspection for water in collection in manholes and conduit occur at least once very two years. Explain how operating experience is considered in manhole inspection frequency.

207 Closed

[B.1.19-N-02, Non-EQ Inaccessible Medium Voltage Cable Program]

2. In AMP B1.19 under Operating Experience element, you have stated that the Non-EQ Inaccessible Medium-Voltage Cable Program at PNPS is a new program for which there is no operating experience. NUREG-1800, Rev. 1, Appendix A, Branch Technical Position RLSB-1 states that an applicant may have to commit to provide operating experience in the future for new program to confirm their effectiveness.

Describe how operating experience is captured to confirm the program effectiveness or to be used to adjust the program as needed.

Response

PNPS inspection for water accumulation in manholes is conducted by plant inspection. An engineering evaluation will be performed per EN-LI-102.

To clarify that the PNPS AMP is consistent with the GALL recommendation, LRPD-02 will be revised as follows: [Section 3.4.B.4.b -

Detection of Aging Effects - replace 2nd paragraph] The inspection will be based on actual plant experience with water accumulation in the manholes and the frequency of inspection will be adjusted based on the results of the evaluation, but the frequency will be at least once every two years.

NRC Auditor Nguyen, Duc PNPS Lead Stroud, Mike Operating Experience at PNPS is controlled by procedure EN-OP-100, Operating Experience Program. The program includes the following components:

Operating Experience - Information received from various industry sources that describe events, issues, equipment failures, that may represent opportunities to apply lessons learned to avoid negative consequences or to recreate positive experiences as applicable.

Internal Operating Experience - Operating experience that originates as a condition report or request from plant personnel which warrants consideration for possible Entergy-wide distribution. Internal OE can originate from any Entergy plant or headquarters.

Impact Evaluation - Analysis of an OE event or problem that requires additional information and research to determine impact or potential impact, as it relates to plant condition and/or configuration. Impact evaluations are typically documented with a condition report.

Condition report action items and corrective actions are used to confirm program effectiveness and to modify the program as needed.

Nguyen, Duc Stroud, Mike Thursday, June 1, 2006 Page 43 of 82

Number Status Request 208 Accepted

[B.1.20-N-01, Non-EQ Instrumentation Circuits Test Review Program]

1. In LRA, Section A.2.1.22, you have stated that for neutron flux monitoring system cables that are disconnected during instrument calibration, testing is performed at least once every 10 years. GALL XI.E2 recommends that the test frequency shall be determined by the applicant based on engineering evaluation, but the test frequency shall be at least once every ten years. Explain how engineering evaluation is considered in the test frequency.

209 Closed

[B.1.20-N-02, Non-EQ Instrumentation Circuits Test Review Program]

Response

To clarify that the PNPS AMP is consistent with the GALL recommendation, LRPD-02 will be revised as follows: [Section 3.5.A - Program Description -add after 2nd sentence] The first test of neutron monitoring system cables that are disconnected during instrument calibrations shall be completed before the period of extended operation and subsequent tests will occur at least every 10 years. In accordance with the corrective action program, an engineering evaluation will be performed when test acceptance criteria are not met and corrective actions, including modified inspection frequency, will be implemented to ensure that the intended functions of the cables can be maintained consistent with the current licensing basis for the period of extended operation.

Yes, the B.1.20 program includes both cables and connections for the instrument circuits that are in scope for license renewal.

NRC Auditor PNPS Lead Nguyen, Duc Nguyen, Duc Stroud, Mike Stroud, Mike

2. Confirm that the test include both cables and 210 Closed

[B.1.20-N-03, Non-EQ Instrumentation Circuits Test Review Program]

3. PNPS AMP B1.20 under Operating Experience element states that the Non-EQ Instrumentation Circuit Tests Review Program at PNPS is a new program for which there is no operating experience.

Explain how operating experience is captured to confirm the program effectiveness or to be used to adjust the program as needed.

Operating Experience at PNPS is controlled by procedure EN-OP-100, Operating Experience Program. The program includes the following components:

Operating Experience - Information received from various industry sources that describe events, issues, equipment failures, that may represent opportunities to apply lessons learned to avoid negative consequences or to recreate positive experiences as applicable.

Internal Operating Experience - Operating experience that originates as a condition report or request from plant personnel which warrants consideration for possible Entergy-wide distribution. Internal OE can originate from any Entergy plant or headquarters.

Impact Evaluation - Analysis of an OE event or problem that requires additional information and researchto determine impact or potential impact, as it relates to plant condition and/or configuration. Impact evaluations are typically documented with a condition report.

Condition report action items and corrective actions are used to confirm program effectiveness and to modify the program as needed.

Nguyen, Duc Stroud, Mike Thursday, June 1, 2006 Page 44 of 82

Number Status Request 211 Accepted

[B.1.21-N-01, Non-EQ Insulated Cables and Connections Program]

1. GALL XI.E1 under program description states that the program described herein is written specifically to address cables and connections at plants whose configuration is such that most (if not all) cables and connections installed in adverse localized environments are accessible.

This program, as described, can be thought of as a sampling program. Selected cables and connections from accessible areas (the inspection sample) are inspected and represent, with reasonable assurance, all cables and connections in the adverse localized environment.

If an acceptable condition or situation is identified for a cable or connection in the inspection sample, a determination is made as to whether the same condition or situation is applicable to other accessible or inaccessible cables or connections. As such, this program does not apply to plants in which most cables are inaccessible.

a. Provide a ball part percentage of in-scope cable and connections population installed in adverse localized environments that are accessible.

b. In LRA, Section B.1.21 you have stated that the a representative sample of accessible insulated cables and connections within the scope of license renewal will be visually inspected for cable and connection jacket surface anomalies such as embrittlement, discoloration, cracking or surface contamination. Explain the technical basis for cable sampling.

Response

a.

A ball park percentage of accessible in-scope cables and connections would be 80 to 85%.

b.

LRA Appendix B.1.21 will be revised to read as follows.

This program addresses cables and connections at plants whose configuration is such that most cables and connections installed in adverse localized environments are accessible: This program can be thought of as a sampling program. Selected cables and connections from accessible areas will be inspected and represent, with reasonable assurance, all cables and connections in the adverse localized environments. If an unacceptable condition or situation is identified for a cable or connection in the inspection sample, a determination will be made as to whether the same condition or situation is applicable to other accessible cables or connections. The sample size will be increased based on an evaluation per EN-LI-102

- Corrective Action Process.

This requires an amendment to the LRA.

Nguyen, Duc Stroud, Mike,

NRC Auditor PNPS Lead Thursday, June 1, 2006 Page 45 of 82

Number Status Request 212 Closed

[B.1.21-N-02, Non-EQ Insulated Cables and Connections Program]

2. In LRA, Section B.1.21 under Operating Experience element, you have stated that the Non-EQ Insulated Cables and Connection Program at PNPS is a new program for which there is no operating experience. Describe how operating experience will be captured to confirm the program effectiveness or to be.

used to adjust the program as needed.

Response

Operating Experience at PNPS is controlled by procedure EN-OP-100, Operating Experience Program. The program includes the following components:

Operating Experience - Information received from various industry sources that describe events, issues, equipment failures, that may represent opportunities to apply lessons learned to avoid negative consequences or to recreate positive experiences as applicable.

Internal Operating Experience - Operating experience that originates as a condition report or request from plant personnel which warrants consideration for possible Entergy-wide distribution. Internal OE can originate from any Entergy plant or headquarters.

Impact Evaluation - Analysis of an OE event or problem that requires additional information and research to determine impact or potential impact, as it relates to plant condition and/or configuration. Impact evaluations are typically documented with a condition report.

Condition report action items and corrective actions are used to confirm program effectiveness and to modify the program as needed.

1. As stated in LRA Section B.1.22, exception note 1, flash point is not determined for sampled oil because analysis of filter residue or particle count, viscosity, total acid/base (neutralization number), water content, and metals content provide sufficient information to verify the oil does not contain water or contaminants that would permit the onset of aging effects. PNPS monitors the % fuel dilution in diesel engine oils which is a more accurate method than flash point for identifying fuel leaks and oil dilution.

2. Provided a copy of procedure 3.M.3-61.3, Emergency Diesel Generator Quarterly Preventive Maintenance, showing that quarterly lube oil samples are sent to the laboratory.

Provided laboratory test results showing that %

dilution is measured in accordance with ASTM standards. Acceptance criterion is < 3 %Wt and is based on ALCO diesel engine owners' group chemistry guidelines.

The following will be added to LRA Section B.1.22 exception note. PNPS measures the %

fuel dilution in diesel engine oils which is a more accurate method than flash point for identifying fuel leaks and oil dilution. Acceptance criterion is < 3% Wt based on ALCO diesel engine owners' group chemistry guidelines.

This requires an amendment to the LRA.

NRC Auditor Nguyen, Duc PNPS Lead Stroud, Mike 213 Accepted

[B.1.22-P-01, Oil Analysis Program]

1. Provide justification for not monitoring the flashpoint of oil that is not regularly changed.

2. Provide the document that establishes the frequency of monitoring for and the acceptance criteria for the allowable % dilution.

Pavinich, Wayne Potts, Lori Thursday, June 1; 2006 Page 46 of 82

Number Status Request 214 Closed

[B.1.22-P-02, Oil Analysis Program]

2. Provide acceptance criteria for water and particulate contamination and viscosity and the basis of the limits.

215 Accepted

[B.1.22-P-03, Oil Analysis Program]

3. NUREG-1800, SRP for license renewal, section 3.X.3.4, FSAR Supplement, states the following:

As noted in Table 3.X-2, an applicant need not incorporate the implementation schedule into its FSAR. However, the reviewer should confirm that the applicant has identified and committed in the license renewal application to any future aging management activities, including enhancements and commitments to be completed before entering the period of extended operation. The staff expects to impose a license condition on any renewed license to ensure that the applicant will complete these activities no later than the committed date.

The enhancements identified in the B.1.22 write-up are not included in the FSAR Supplement Appendix A.2.1.24.

They should be in the UFSAR Supplement in order to address these commitments.

Response

As stated in the Aging Management Program Evaluation Report (AMPER), acceptance criteria resulting in re-sampling and increased sampling frequency include:

-- particulates - large ferrous or non-ferrous contamination or trend increasing levels viscosity - increase of 15% from viscosity grade

-- viscosity - decrease of 15% from viscosity grade

-- water content - > 2000 ppm (0.2% by volume)

The acceptance criteria are based on manufacturer's recommendations and industry As stated in the letter submitting the license renewal application (letter number 2.06.003, dated 1/25/06), PNPS is committed to the programs listed in Appendix B, Section B.1 of the license renewal application. Enhancements to programs that are described in Appendix B of the LRA are, therefore, commitments. To facilitate tracking of the enhancements through the NRC review process and facilitate implementation once the renewed license is received, a list of specific commitments for license renewal has been developed. This list will be sent to the Staff under oath and affirmation and will be supplemented as necessary during the NRC review process.

Both Appendix B of the LRA and the list of commitments for license renewal include commitments to implement new programs and commitments to enhance existing programs before the period of extended operation.

Items 18 and 19 on the list of commitments for license renewal are the commitments to implement the enhancements described in LRA Section B.1.22.

See Item #320 for closure for this Item.

NRC Auditor PNPS Lead Pavinich, Wayne Potts, Lori Pavinich, Wayne Potts, Lori Thursday, June 1, 2006 Page 47 of 82

Number Status Request 217 Closed

[B.1.23-P-01, One Time Inspection]

1. Provide a list of systems in element of "Scope of Activity", where One-Time Inspection will be performed.

Response

As described in LRA Section B.1.23, the One-Time Inspection Program includes several activities. The activities to confirmh the absence of aging effects identify the systems to which they apply. For instance, the activity for inspection of "Internal surfaces of buried carbon steel pipe on the standby gas treatment system discharge to the stack" inspects components in the standby gas treatment system.

The activity to verify effectiveness of the water chemistry control programs is applicable to many systems. The systems are not listed in LRA Section B.1.23. However, they may be found in the tables in LRA Section 3.0, Aging Management Review Results. In these tables, systems with line items containing one of the water chemistry control programs, (Water Chemistry Control - Auxiliary Systems, Water Chemistry Control - BWR, or Water Chemistry Control - Closed Cooling Water), have components included in the sample population for this one-time inspection activity.

As described in the Aging Management Program Evaluation Report (AMPER), the One-Time Inspection Program activity for inspection of small-bore piping in the reactor coolant system and associated systems that form the reactor coolant pressure boundary will inspect a statistically significant sample of welds of each material and environment combination in Class I piping less than or equal to 4" NPS. The initial population will include all Class I small-bore piping and actual inspection locations will be selected based on physical location, exposure levels, NDE techniques, and locations identified in Information Notice 97-46, Un-isolable Crack in High-Pressure Injection Piping.

As indicated in plant procedures, during the 4th ISI Interval, PNPS plans to.perform both VT-2 and PT examinations, at a minimum, of socket welds in accordance with the PNPS 4th Interval ISI Program Plan. The One-Time Inspection of small-bore piping does not exclude locations based upon geometry. Therefore, Class I small-bore piping socket welds will be selected for one-time inspection based on physical location and exposure levels.

NRC Auditor PNPS Lead Patel, Erach Potts, Lori 218 Closed

[B.1.23-P-02, One Time Inspection]

2. Identify how the sample of small piping welds, 4" and smaller will be picked for performing NDE inspection.

219 Closed

[B.1.23-P-03, One Time Inspection]

3. How will.PNPS handle the aging of socket welds?

Patel, Erach Patel, Erach Potts, Lori Potts, Lori Thursday, June 1, 2006 Page 48 of 82

Number Status Request 220 Accepted

[B.1.23-P-04, One Time Inspection]

4. NUREG-1800, SRP for license renewal, section 3.X.3.4, FSAR Supplement, states the following:

As noted in Table 3.X 2, an applicant need not incorporate the implementation schedule into its FSAR. However, the reviewer should confirm that the applicant has identified and committed in the license renewal application to any future aging management activities, including enhancements and commitments to be completed before entering the period of extended operation. The staff expects to impose a license condition on any renewed license to ensure that the applicant will complete these activities no later than the committed date.

Response

As stated in the letter submitting the license renewal application (letter number 2.06.003, dated 1/25/06), PNPS is committed to the programs listed in Appendix B, Section B.1 of the license renewal application. Therefore, programs that are described in Appendix B of the LRA are commitments. To facilitate tracking through the NRC review process and facilitate implementation once the renewed license is received, a list of specific commitments for license renewal has been developed. This list will be sent to the Staff under oath and affirmation and will be supplemented as necessary during the NRC review process.

Both Appendix B of the LRA and the list of commitments for license renewal include commitments to implement new programs and commitments to enhance existing programs before the period of extended operation.

Item 20 on the list of commitments for license renewal is the commitment to implement the One-Time Inspection Program as described in LRA Section B.1.2.

See Item #320 -for closure for this Item.

NRC Auditor PNPS Lead Patel, Erach Potts, Lori The One-Time Inspection program is a new program that will be implemented prior to period of extended operation.

Justify why this commitment is not included in the FSAR Supplement write-up in Appendix A. 1.25.

222 Closed

[B.1.24-P-01, Periodic Surveillance and Preventative Maintenance]

1. Provide any codes and standards used for detection of aging effects.

As indicated in LRA Section B.1.24, many of the Pavinich, Wayne Periodic Surveillance and Preventive Maintenance activities include visual or other non-destructive examinations of structures, systems and components. These examinations are performed in accordance with approved procedures that are consistent with ASME Section XI and 10 CFR 50 Appendix B.

Potts, Lori Thursday, June 1, 2006 Page 49 of 82

Number Status Request 223 Accepted

[B.1.24-P-02, Periodic Surveillance and Preventative Maintenance]

2. NUREG-1800, SRP for license renewal, section 3.X.3.4, FSAR Supplement, states the following:

As noted in Table 3.X-2, an applicant need not incorporate the implementation schedule into its FSAR. However, the reviewer should confirm that the applicant has identified and committed in the license renewal application to any future aging management activities, including enhancements and commitments to be completed before entering the period of extended operation. The staff expects to impose a license condition on any renewed license to ensure that the applicant will complete these activities no later than the committed date.

The enhancements identified in the B.1.24write-up are not included in the FSAR Supplement Appendix A.2.1.26.

They should be in the UFSAR Supplement in order to address these commitments.

Response

As stated in the letter submitting the license renewal application (letter number 2.06.003, dated 1/25/06), PNPS is committed to the programs listed in Appendix B, Section B.1 of the license renewal application. Enhancements to programs that are described in Appendix B of the LRA are, therefore, PNPS commitments. A list of specific commitments for license renewal will be developed to facilitate tracking and implementation of the enhancements through the NRC review process upon receipt of the renewed license. This list will be sent to the Staff under oath and affirmation and will be supplemented as necessary during the NRC review process. Both Appendix B of the LRA and the list of commitments for license renewal include commitments to implement new programs and commitments to enhance existing programs before the period of extended operation.

Item 21 on the list of commitments for license renewal is the commitment to implement the enhancements described in LRA Section B.1.24.

NRC Auditor PNPS Lead Pavinich, Wayne Potts, Lori 225 Closed

[B.1.24-P-04, Periodic Surveillance and Preventative Maintenance]

4. Provide trending methods.

Inspection and testing intervals are established such that they provide for timely detection of structures, systems and components degradation. Inspection and testing intervals are dependent on the material and environment and take into consideration industry and plant-specific operating experience and manufacturers' recommendations. Trending of degraded components occurs within the Corrective Action Program.

Pavinich, Wayne Potts, Lori Thursday, June 1, 2006 Page 50 of 82

Number Status Request 226 Closed

[B.1.25-J-01, Reactor Head Closure Studs]

1. The PNPS AMP B.1.25 (Reactor Head Closure Studs) states gives as examples of preventive measures to mitigate cracking "rust inhibitors, stable lubricants, appropriate materials."

QUESTIONS:

Response

Approved lubricants for RPV studs are Neo-Lube or equivalent. (Ref. Procedure 3.M.4-48)

The use of appropriate materials means that any replacement studs would be specified to be made from material that met all the requirements at the time of specification, and encompassed all the available operating experience. For example, no metal sheathed studs would be ordered and tensile strength would be specified.

NRC Auditor PNPS Lead Jackson, Wilbur Finnin, Ron 227

' Closed At PNPS what rust inhibitors and lubricants are approved for used on the reactor head closure studs, nuts, washers, and bushings?

What is encompassed by the words "appropriate materials"?:

[B.1.25-J-02, Reactor Head Closure Studs]

2. The PNPS LRA, AMP B.1.25 (Reactor Head Closure Studs),

Operating Experience states that volumetric examination of 18 reactor head closure studs and visual examination of 18 nuts and 18 washers was performed during RF015 (April, 2005).

QUESTIONS:

What is the fraction of total reactor head closure studs represented by the 18 studs examinde during RVO15?

Are all studs, nuts and washers examined during each 10-year ISI interval?

Are the studs, nuts and washers examined during RF015 original equipment that has been in use since initial startup of the plant? If not, what is the approximate average length of time that these items have been in used in operation.

There are 56 reactor head studs, so a sample of 18 is 1/3 of the studs (19, 19, 18).

Yes, all studs/nuts/washers are examined every 10 year interval.

The studs/nuts/washers currently installed at PNPS are original equipment.

Jackson, Wilbur Finnin, Ron Thursday, June 1, 2006 Page 51 of 82

Number Status Request 228 Closed

[B.1.25-J-03, Reactor Head Closure Studs]

3. The PNPS LRA, AMP B.1.25 (Reactor Head Closure Studs),

Operating Experience states that no new recordable indications were found for the studs, nuts and washers examined during RFO15.

Response

PNPS has not detected any recordable indications in any of the 56 RPV closure head studs.

NRC Auditor Jackson, Wilbur PNPS Lead Pardee, Rich QUESTIONS:

229 Closed What is the examination history related to earlier refueling outages? Have indications been found in previous examinations?

If indications were found, what corrective actions were taken?

[B.1.25-J-.04, Reactor Head Closure Studs]

4. RG 1.65 (Materials and Inspections for Reactor Vessel Closure Studs), which is referenced in and is a basis for GALL Program XI.M3 (Reactor Head Closure Studs), states that "visual and surface examinations may fail to reveal unacceptable defects, especially if the studs are examined in an untensioned condition." It also states that "a [volumetric examination]

technique has been developed in which a transducer is lowered into the stud bolt center hole and an ultrasonic radial scan is used for the ultrasonic examination."

QUESTIONS:

With regard to reactor head closure studs that are removed for examination, does PNPS perform the surface examination with the studs in a tensioned or untensioned condition?

Has PNPS performed any radial ultrasonic scans of its reactor vessel closure studs?

Since RFO15 (2005), PNPS has adopted the 1998 edition with 2000 addenda of ASME XI which requires either a surface exam or volumetric exam of RPV studs that are removed. PNPS elected to perform a volumetric examination on these four studs in RFO15 in the tensioned condition prior to their removal. No indications were detected in the four removed studs in 2005. The four studs adjacent to the fuel transfer chute are removed each refueling outage; these are the only studs that have been removed from the PNPS vessel.

PNPS currently performs ultrasonic examination of RPV studs from the top surface of the stud.

In the past, PNPS had performed this examination using a specially fabricated stud radial UT probe inserted into the stud's heater hole located on the stud's central axis. The technique currently in use utilizing the flat surface at the top of the stud is considered superior in the detection of flaws in RPV studs when compared to UT exams performed from the heater hole.

RPV studs at PNPS are examined utilizing a straight beam ultrasonic testing (UT) technique.

This method has been demonstrated and qualified by the Performance Demonstration Initiative (PDI) at the Electric Power Research Institute (EPRI) Nondestructive examination (NDE) Center. Examiners utilizing this qualified technique are also qualified by the PDI to perform this examination. This straight beam examination has been demonstrated by PDI to be capable of detecting a flaw of critical size.

All 56 RPV studs at PNPS are examined once per interval using this technique.

Jackson, Wilbur Pardee, Rich Thursday, June 1, 2006 Page'52 of 82

Number Status Request 230 Accepted

[B.1.27-W-01, Selective Leaching Program]

1. PNPS states in LRA B.1.27,Selective Leaching Program, that this AMP is a new program, and it will be initiated prior to the period of extended operation. Will the implementation of this AMP be included in the commitment list?

231 Closed

[B.1.27-W-02, Selective Leaching]

2. Provide a status of the implementation of this AMP, including scope of work, (planned) implementing procedures, parameters to be inspected and measured, and acceptance criteria.

232 Closed

[B. 1.28-H-01, Service Water Integrity]

1. Identify applications where components are not coated or lined and the materials of construction.

Response

Yes it is included. Item 23 of the commitment list states "Implement the Selective Leaching Program in accordance with the program as described in LRA Section B.1.27".

As described in section B.1.27, the selective leaching program will be consistent with NUREG-1801,Section XI.M33, Selection Leaching of Materials. Scope, parameters inspected/measured, and acceptance criteria along with other program attributes are available for your review in the Aging Management Program Evaluation Report LRPD-02, section 3.8.

Because this is a new program, the implementing procedures have not yet been developed, but will be in place prior to the period Piping

- The Salt Service Water Supply buried piping and sections of the supply and return wall penetration piping spools are constructed of Titanium, ASTM B381 GR. F2. These spools are not lined internally.

• Salt Service Water Small bore pipe (=2") Vents and Drain piping are constructed of ASTM B-466, 90-10 CUNI. These spools are not lined internally. These spools are bolted onto large bore Carbon Steel rubber lined pipe.

Valves

- Salt Service Water Pump Discharge 12" Check Valves are not lined internally. They are constructed of; (3) ASTM B-61 bodies, (2) are ASTM A-494 Gr. M35-1 bodies.

- Salt service Water Small bore (=2") Vent and Drain Valves are not lined internally. They are constructed of ASTM B-61 or ASTM B-62.

Pumps

- Salt Service Water Pumps are not lined internally. Their Column are constructed of; ASTM B-1 48-88 C95800 or ASTM B271-89 Alloy C95800.

Heat Exchangers

• The Closed Cooling Water (RBCCW &

TBCCW) Heat Exchangers, Salt Service Water side are not lined internally. They are constructed of ASTM SB-171-C70600, 90/10 CuNi.

NRC Auditor PNPS Lead Wen, Peter Wen, Peter Pavinich, Wayne Ivy, Ted Ivy, Ted Gaedtke, Joe Thursday, June 1, 2006 Page 53 of 82

Number Status Request 233 Closed

[B. 1.29.1 -H-01, Masonry Wall]

1. The program description for AMP B.1.29.1 in the Pilgrim LRA indicates that the scope of this program includes all masonry walls that perform an intended function in accordance with 10 CFR 54.4. The applicant is requested to provide the following information related to the scope of this program:

(1) Identify whether any additional masonry walls have been added to the scope of the current Pilgrim program as a result of the LR scoping and screening process, particularly in light of the requirement to consider regulated events in the LR assessment.

(2) If additional masonry walls have been added to the scope, explain how the requirements of I. E.Bulletin 80-11 have been applied to these walls, and describe any physical modifications that have/will be implemented to establish the evaluation bases.

(3) If additional masonry walls have been added to the scope, explain why this is not considered an enhancement to the current Pilgrim program.

Response

1. No additional masonry walls have been identified to be added to the scope of Pilgrim current masonry wall program as result of the LR scoping and screening process [Ref. Aging management program evaluation report LRPD-02, section 4.21.2].

2. Not applicable since no additional masonry walls have been added to the scope of Pilgrim current masonry wall program as result of the LR scoping and screening process [Ref. item (1) above].

3. Not applicable since no additional masonry walls have been added to the scope of Pilgrim current masonry wall program as result of the LR scoping and screening process [Ref. item (1) above].

NRC Auditor PNPS Lead Hoang, Dan Ahrabli, Reza Thursday, June 1, 2006 Page 54 of 82

Number Status Request 234 Closed

[B.1.29.1-H-02, Masonry Wall]

2. The program description for AMP B.1.29.1 in the Pilgrim LRA does not indicates that this program includes all of the guidances provided in I.E.

Bulletin 80-11, "Masonry Wall Design", and Information Notice 87-67, "Lessons learned from Regional Inspections of Licensee Actions in Response to I.E. 80-11 ". Also, what is your Visual examined frequency? The applicant is requested to provide and confirm to the above information related to this program.

Response

Pilgrim masonry wall program which is consistent with the program described in NUREG-1 801,Section XI.S5, Masonry Wall Program, includes the guidance and lessons learned from NRC Bulletin 80-1 land Information Notice 87-67. As indicated in Aging Management Program Evaluation Report LRPD-02, section 4.21.2, Operating experience shows that this program has been effective in managing aging effects with consideration for recommendations and lessons learned from Bulletin 80-11 and Information Notice 87-67.

Masonry walls are visually examined at frequency selected (at least once every 10 years) to ensure there is no loss of intended function between inspections. (Ref. Pilgrim procedure NE8.02, section 5, and Aging Management Program Evaluation Report LRPD-02, section 4.21.2)

PNPS Engineering Design Standards Manual MCSB03.104 defines the procedure to maintain the qualification of safety-related masonry block walls in accordance with the provisions of NRC Bulletin 80-11, Masonry Wall Design".

PNPS procedure NE8.02, "Structure Inspection and Condition Monitoring", Section 5.0 (last sentence, pg. 8) states "The inspection intervals are once every three years for accessible areas, once every ten years for normally inaccessible areas.

PNPS AMP B1.29.2 Structures Monitoring, Program Description states "Since protective coatings are not relied upon to manage the effects of aging for structures included in the Structures Monitoring Program, the program does not address protective coating monitoring and maintenance."

NRC Auditor Hoang, Dan PNPS Lead Ahrabli, Reza 235 Closed

[B.1.29.2-H-01, Structures Monitoring Program]

1. Since the program coatings are not relied upon to manage the effects of aging for structures included in the Structures Monitoring Program (AMP B.1.29.2). Please provide the following information related to this enhancement:

Hoang, Dan Ahrabli, Reza (a) What is your criteria and How are you going to qualify and monitor it under AMP B.1.29.2.

Thursday, June 1, 2006 Page 55 of 82

Number Status Request 236 Closed

[B.1.29.2-H-02, Structures Monitoring Program]

2. In the discussion of operating experience, four noteworthy incidences of degradation are noted: cracks, gaps, corrosion, and flaking coating.

For each of the first three incidences of degradation, please provide the plant documentation that describes the degradation, the assessment performed, the acceptance criteria applied, future monitoring recommendations, and any corrective action taken. Also describe the monitoring activities that are or will be conducted under the Structures Monitoring Program for each of the three regions.

Response

The following plant documents, were available for review: PDF Files: Item 236 (part 1), Item 236 (part 2), Item 236 (part 3), Item 236 (part 4),

and CR-PNP-2000-09246 CR-PNP-2000-09435 CR-PNP-2000-09448 CR-PNP-2001-09145 CR-PNP-2001-09700 CR-PNP-2004-03373 CR-PNP-2004-03981 Cracks, gaps and corrosion will be monitored as stated in LRPD-02 and Attachment 4-Structures Monitoring Program General Criteria (pg. 279). For Concrete, structures monitoring manages loss of material, cracking, and change in material properties, as identified in LRA tables 3.5.2-1 thru 3.5.2-6.The acceptance criteria is the absence of the following: cracks, excessive rust bleeding, staining or discoloration, abrasion, erosion, cavitation, spalling, scaling, !eaching, excessive settlement, corrosion of reinforcing, degraded waterproof membranes. For Steel, structures monitoring program manages the loss of material, as identified in LRA tables 3.5.2-1 thru 3.5.2-6. The acceptance criteria is the absence of the following: Pitting, beam/column deflection, cracks, flaking coatings, excessive rust, loose/missing bolts, peeling paint, wide spread corrosion. (also see commitment numbers 25 and 26 regarding this program) For Elastomers the aging effect managed is cracking,' change in material properties. The acceptance criteria will include the absence of cracks and gaps.

NRC Auditor PNPS Lead Hoang, Dan Kalb, Jeff Thursday, June 1, 2006 Page 56 of 82

Number Status Request 237 Closed

[B. 1.29.2-H-03, Structures Monitoring Program]

3. The Dresden/Quad Cities BWR units have a history of problems with containment penetration bellows, and the licensee has a long-term replacement program that will continue into the LR period.

The applicant is requested to address this industry operating experience and submit a specific technical basis why the Pilgrim containment penetration bellows are not subject to the aging effects and aging mechanisms observed at Dresden/Quad Cities.

Response

The Dresden/Quad Cities License Renewal Application (LRA) and Safety Evaluation Report (SER) provide a description of the Dresden/Quad Cities operating experience with their stainless steel bellows. The Dresden/Quad Cities review determined a total of 120 bellows were within the scope of license renewal. Of these 120 bellows, 24 bellows were identified as being degraded. The root cause was identified as stress corrosion cracking (SCC). From 1990 to 2003 Dresden/Quad Cities replaced or removed the degraded bellows from service. The SER states that several of the replaced bellows received metallurgical analysis. Analysis results from a couple of examples determined the presence of corrosive products, such as "magnesium salts", chlorides, fluorides, and sulfides. Also, these corrosive species are not typical of containment operating conditions. As a result, the SER concludes the corrosive species, leading to the site specific degradation of the bellows, were most probably introduced and contaminated during plant construction.

(Reference Dresden/Quad Cities SER pages 3-403 to 3-408)

Cracking due to SCC for the PNPS containment bellows is not an aging affect requiring management. There are no PNPS site specific operating experiences similar to that of Dresden/Quad Cities. In summary, the presence of corrosive products is necessary for SCC to exist. The normal environment for the PNPS drywell is dry and there has been no indication of contamination of the bellows during construction at PNPS. In addition, containment bellows for PNPS are not exposed to a corrosive environment. As such, SCC is not applicable to PNPS stainless steel bellows. (Ref. LRA paragraph 3.5.2.2.1.7)

NRC Auditor PNPS Lead Hoang, Dan Ahrabli, Reza Thursday, June 1, 2006 Page 57 of 82

Number Status Request 238 Accepted

[B.1.29.2-H-04, Structures Monitoring Program]

4. More information is needed about aging management of inaccessible concrete areas.

The applicant is requested to submit the dates and complete results (at specific locations/not averages or ranges) of all past groundwater monitoring tests. Discuss why the groundwater is non-aggressive, and/or aggressive, if applicable.

Confirm that the Pilgrim SMP credited for LR will inspect all inaccessible areas that may be exposed by excavation for any reason, whether the environment is considered aggressive or not, and also will inspect any inaccessible area where observed conditions in accessible areas, which are exposed to the same environment, show that significant concrete degradation is occurring.

Response

a. On October 27, 2005, groundwater samples were taken from a well located -3 feet from the foundation of the Pilgrim Station turbine building near the truck lock at the south side of the building. This well was installed in the late 90s to monitor for total petroleum hydrocarbons as a result of a transformer oil spill. The bottom of the well is -25 feet below ground surface and at the time the sample was taken, the depth to water was -16 feet. The sample was analyzed for chlorides, total phosphate, sulfate and pH.

The results were as follows:

" Chlorides: 420 ppm

• Total phosphate: 0.26 ppm

• Sulfate: 16 ppm

• pH: 6.2 The sampling was performed by SAIC Engineering, Inc. and the analysis was performed by R. I. Analytical Laboratories, Inc.

The recent test data shows PNPS ground water has remained non-aggressive (chloride <

500ppm, Sulfate < 1500 ppm and pH > 5.5).

b. Although it is expected that inaccessible areas are inspected when exposed by excavation for any reason, Pilgrim site procedure for "Structures Inspection and condition monitoring" will. be revised to require opportunistic inspections of inaccessible concrete areas when they become accessible (commitment 25). Expanding inspection to other areas (accessible or non-accessible) where significant concrete degradation is observed in the accessible area will continue to be part of corrective action program 8.0.3.

This requires an amendment to the LRA.

NRC Auditor PNPS Lead Hoang, Dan Kalb, Jeff Thursday, June 1, 2006 Page 58 of 82

Number Status Request 239 Closed

[B.1.29.2-H-05, Structures Monitoring Program]

5. The applicant is requested to address and discussion of operating experience in detail of pipe supports and cable trays found degradation in November 2004. Did your scope expansion was required due to unacceptable found?

Provide the following information related to this recent operating experience:

(a) Identify the system(s),

ASME Code Class, the initial sample size, and the percentage found to be unacceptable.

(b) Identify whether loss of material due to corrosion, loss of mechanical function, or both aging effects were observed.

Did the as-found unacceptable conditions compromise any intended functions?

(c) Identify the final sample size, after scope expansion, and the percentage found to be unacceptable.

(d) Identify the number of supports returned to service based solely on evaluation and the number of supports returned to service after repair.

(e) Describe the root cause evaluation and the corrective actions taken to prevent recurrence.

(f) Identify any additional inspections scheduled for the next inspection period.

Response

The discussion in the operating experience section (LPDR-05, pg. 41) of Pilgrim's LRA came from the System 56, Structures Maintenance Rule fourth quarter 2004 System Health Report. These items were however identified during System 56 walkdowns as part of the periodic inspections performed in accordance with PNPS procedure NE8.03, Structure Inspection and Condition Monitoring.

When degraded conditions were observed a WRT/MR was written to correct the condition.

MR # 04117586 MR # 04117332 MR # 04117319 MR # 04117320 MR # 04117318 MR # 04117334 MR # 04117333 MR # 04117590 MR # 04117591 MR # 04117313 MR # 04117279 MR # 04117272 MR # 04116777 MR # 04116773 MR # 04116774 MR # 04116775 MR # 04116776 (a) The affected systems vary with each component identified. All of the degraded conditions found occurred on non safety related conduits or pipe supports. None of the piping supports were ASME supports. There was no sample size since the various portions of the process buildings were walked down and inspected room by room.

(b) Some of the degraded conditions were due to corrosion and some were due to conditions other than aging effects, such as, bent rods.

See attached MRs. No as found conditions compromised any intended design function.

(c) There was no sample size and there was no scope expansion.

(d) The supports in question were evaluated and determined all needed repair or maintenance before returning back to service. Approximately 50% of the supports, on different systems, have been repaired and returned to service. The remaining will be returned to service when the repairs are complete. As noted in the response to part (a), the degraded supports were found on nonsafety-related conduits or piping.

(e) There was no root cause analyses performed and no additional corrective actions taken to prevent recurrence.

(f) No additional inspections have been identified for the next inspection period.

NRC Auditor PNPS Lead Hoang, Dan Kalb, Jeff Thursday, June 1, 2006 Page 59 of 82

Number Status Request 240 Accepted

[B.1.29.2-H-06, Structures Monitoring Program]

6. Considering the relatively short time period remaining before Pilgrim enters the license renewal period, the staff expects that considerable progress has already been made in developing and formally documenting the implementing procedures required for new AMPs, and for significant enhancements to existing AMPs. In light of this, please address each of the following questions regarding the current status of implementing procedures for this AMP:

(a) Provide the status of the implementing procedures for each enhancement to the existing Structures Monitoring Program.

(b) Provide the schedule for initiating each of the enhancements to the existing Structures Monitoring Program.

(c) Provide a sample of an implementing procedure for one enhancement to the existing Structures Monitoring Program.

(d) Provide the results of any enhanced inspections that have

Response

Since 6 years remain before PNPS enters the period of extended operation, implementing procedures required for new AMPs, and procedure revisions for enhancements to existing AMPs have not yet been developed.

Items 25 and 26 on the list of commitments for license renewal are the commitment to implement the enhancements to the Structures Monitoring Program described in LRA Section B.1.29.2..

To facilitate tracking of enhancements through the NRC review process and facilitate implementation, a list of specific commitments for license renewal has been developed. This list will be sent to the Staff under oath and affirmation and will be supplemented as necessary during the NRC review process.

Both Appendix B of the LRA and the list of commitments for license renewal include commitments to implement new programs and commitments to enhance existing programs before the period of extended operation.

NRC Auditor PNPS Lead Hoang, Dan Ahrabli, Reza 241 Closed

[B.1.29.2-H-07, Structures Monitoring Program]

7. Discuss PNPS use of Level III coatings and identify whether any Service Level III coatings are credited for corrosion protection for license PNPS AMP B1.29.2 Structures Monitoring, Program Description states "Since protective coatings are not relied upon to manage the effects of aging for structures included in the Structures Monitoring Program, the program does not address protective coating monitoring and maintenance."

Hoang, Dan Kalb, Jeff Thursday, June 1, 2006 Page 60 of 82

Number Status Request 242 Closed

[B.1.29.2-H-08, Structures Monitoring Program]

8. The scope of the enhancements listed for AMP B.1.29.2 are quite significant, and encompass several elements that would be expected to be part of an existing Structures Monitoring Program. Notable examples are the inclusion of anchors and the addition of loss of material due to corrosion of steel components to the current inspection criteria.

Consequently, the applicant is requested to:

(a) describe the scope of AMP B.1.29.2, including the structures and components in the scope of AMP B.1.129.2; the aging effects that are monitored; the inspection methods employed; and the inspection frequency; and (b) for the structures and components that will be added to the Structures Monitoring Program scope for license renewal, describe the aging management activities that are currently being implemented.

243 Closed

[B.1.29.2-H-09, Structures Monitoring Program]

9. The applicant has not addressed aging management of the portion of the drywell shell embedded in the drywell concrete floor. This area is inaccessible for inspection, but is potentially subject to wetting on both the inside and outside surfaces. Are they any inspections planned prior to the extended period of operation for this portion of the drywell shell?

Response

NRC Auditor PNPS Lead (a) The Structures Monitoring Program at PNPS Hoang, Dan is comparable to the program described in NUREG-1801,Section XI.S6, Structures Monitoring Program (SMP). The Structures Monitoring Program will be enhanced to clarify that the discharge structure, security diesel generator building, trenches, valve pits, manholes, duct banks, underground fuel oil tank foundations, manway seals and gaskets, hatch seals and gaskets, underwater concrete in the intake structure, and crane rails and girders are included in the program (commitment numbers 25 and 26). The structures, structural components and their aging effects requiring management under scope of SMP are included in LRA Tables 3.5.2-1 thru 3.5.2-6. Visual inspections of accessible plant structures are performed at three-year intervals and inspections of normally inaccessible (insulated or high radiation zone) areas are performed at ten-year intervals. Visual inspections of buried plant structures are performed when opportunistic excavation occurs. However, more frequent inspections may be performed based on past inspection results, industry experience, or exposure to a significant event (e.g. tornado, earthquake, fire, chemical spill).

(Ref. Aging Management Program Evaluation Report LRPD-02, section 4.21.1)

(b) Currently there are no aging management activities being implemented for structures and components that will be added to the Structures Monitoring Program for license renewal.

Ahrabli, Reza Aging management of drywell shell is provided by aging management program (AMP) B.16.1, "Containment Inservice Inspection (CII)". The inspections of buried plant structures and structural components (e.g., portion of drywell embedded in drywell concrete floor) are performed when they become accessible, inspection results of similar component show significant degradation, or operating experience warrants such inspections. (Ref. Aging Management Program Evaluation Report LRPD-02, section 4.14.2)

Hoang, Dan Ahrabli, Reza Thursday, June 1, 2006 Page 61 of. 82

Number Status-Request 244 Closed

[B. 1.29.3-H-01, Water Control Structures Monitoring Program]

1. Describe the "aggressive environment" and "water-flowing" environments for Reinforced Concrete Foundation, Slabs, and Reinforced Concrete Walls.

What is the plant-specific program to manage potential degradation?

245 Accepted

[B.1.29.3-H-02, Water Control Structures Monitoring Program]

2. Considering the relatively short time period remaining before Pilgrim enters the license renewal period, the staff expects that considerable progress has already been made in developing and formally documenting the implementing procedures required for new AMPs, and for significant enhancements to existing AMPs. In light of this, please address each of the following questions regarding the current status of implementing procedures for this AMP:

(a) Provide the status of the implementing procedures for each enhancement to the existing RG 1.127, Inspection of Water-Control Structures program.

Response

Aggressive environment is environment with pH less than 5.5 or chloride solution greater than 500 ppm, or sulfate solution greater than 1500 ppm (Ref. LRA section 3.5.2.2.2.4).

'Water-flowing" is considered flowing water at greater than 3 fps. (Ref. LRA section 3.5.2.2.2.4 and EPRI report 1002950 "Aging Effects for Structures and Structural Components (Structural Tools), section 3.3.1.4)

For concrete, structures monitoring manages loss of material, cracking, and change in material properties, as identified in LRA Tables 3.5.2-1 thru 3.5:2-6. The acceptance criteria is the absence of the following: cracks, excessive rust bleeding, staining or discoloration, abrasion, erosion, cavitation, spalling, scaling, leaching, excessive settlement, corrosion of reinforcing, degraded waterproof membranes.

Since 6 years remain before PNPS enters the period of extended operation, implementing procedures required for new AMPs, and procedure revisions for enhancements to existing AMPs have not yet been developed.

To facilitate tracking of enhancements through the NRC review process and facilitate implementation, a list of specific commitments for license renewal has been developed. Items 25 and 26 on the list of commitments for license renewal are the commitment to implement the enhancements to the Structures Monitoring Program described in LRA Section B.1.29.2.

This list will be sent to the Staff under oath and affirmation and will be supplemented as necessary during the NRC review process.

Both Appendix B of the LRA and the list of commitments for license renewal include commitments to implement new programs and.

commitments to enhance existing programs before the period of extended operation.

See item #320 for closure of this item.

Hoang, Dan Ahrabli, Reza NRC Auditor PNPS Lead Hoang, Dan Ahrabli, Reza (b) Provide the schedule for initiating each of the enhancements to the existing RG 1.127, Inspection of Water-Control Structures program.

(c) Provide a sample of an implementing procedure for one enhancement to the existing RG 1.127, Inspection of Water-Control Structures program.

(d) Provide the results of any enhanced inspections that may have already been completed.

Thursday, June 1, 2006 Page 62 of 82

Number Status Request 246 Accepted

[B.1.29.3-H-03, Water Control Structures Monitoring Program]

3. LRA Appendix B, Section B.O.5 identifies AMP B.1.29.3 as an existing program. The Program Description states that this AMP is part of the Structures Monitoring Program, and further states the program will be used to manage aging of water-control structures.

The scope of the enhancements listed for AMP B.1.29.3 encompass many of the elements that normally would be part of an existing inspection program for water-control structures.

Consequently, the applicant is requested to describe the scope of AMP B.1.29.3, including the structures and components in the scope of AMP B.1.29.3; the aging effects that are monitored; the inspection methods employed; and the inspection frequency.

247 Closed

[B.1.29.3-H-04, Water Control Structures Monitoring Program]

4. The applicant is requested to identify the document(s) that includes the evaluation of the Pilgrim program against the monitoring of trash racks. Does the Structures Monitoring Program is credited for aging management of trash racks?

248 Closed

[B.1.29.3-H-05, Water Control Structures Monitoring Program]

5. The applicant is requested to identify and provide the inspection frequency against the GALL AMP XI.S7. If greater.

than 5 years. Please explain why the inspection frequency is NOT identified as an exception to the GALL AMP.

Also provide the technical basis for concluding that Pilgrim frequency is sufficient for submerged portions of structures.

Response

The Water Control Structures Monitoring Program at PNPS is comparable, to the program described in NUREG-1801,Section XI.S7, RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants. The program includes visual inspections to manage loss of material and loss of form for water-control structures (breakwaters, jetties, and revetments). The water-control structures are of rubble mound construction with the outer layer protected by heavy capstone.

Parameters monitored include settlement (vertical displacement) and rock displacement.

These parameters are consistent with those described in RG 1.127. Inspections are performed on water-control structures every 5 years and following major storms. Program scope will be enhanced to include the east breakwater, jetties, and onshore revetments in addition to the main breakwater (commitment number 27). These added items as enhancements are not currently monitored under the existing program.

This requires an amendment to the LRA.

The trash racks are in scope of license renewal, but they are not subject to aging management review. The trash racks are intended to protect the traveling screens from large debris. The failure of the trash racks will not affect any license renewal function. (Ref. AMRC-03 "Aging Management Review of the Intake Structure" table 2.1-2). Accordingly, structures monitoring program is not credited for aging management of trash racks:

Inspections are performed on water-control structures at least every 5 years and following major storms. [Ref. Aging Management Program Evaluation Report LRPD-02, section 4.21.3.4(b)]

NRC Auditor Hoang, Dan.

PNPS Lead Ahrabli, Reza Hoang, Dan Hoang, Dan Ahrabli, Reza Ahrabli, Reza Thursday, June 1, 2006 Page 63 of 82

Number Status Request 249 Closed

[B.1.29.3-H-06, Water Control Structures Monitoring Program]

6. Per the Operating Experience discussion for B.1.29.3, Pilgrim has experienced degradation of the main breakwater Structure had Rock displacement in 2004.

Has the corrective action been completed? If not, why? If yes, provide the plant documentation that describes the degradation, the assessment performed, the acceptance criteria applied, future monitoring recommendations, and any preventive and/or corrective

Response

The corrective action has been completed. The Main Breakwater was repaired in October of 2005. The Main Breakwater was repaired, assessment performed, and condition resolved in accordance with the requirements of PNPS Specification C20-ER-Q-EO, Main Breakwater Repair. (Ref. MR # 04118760). The degradation of the Main Breakwater is documented in Condition Reports CR-PNP-2004-03933, CR-PNP-2005-00093, CR-PNP-2005-00450 and CR-PNP-2005-03018.

The Main Breakwater is monitored at PNPS using procedure PNPS 3.M.5-3, Main Breakwater Monitoring and Repair Procedure. The procedure provides methods for initiating and assessing the results for main breakwater surveys and repair of the main breakwater. In addition to scheduled walkdown inspections and detailed surveys, the wind speeds are monitored for determining the need for additional inspections.

The wind speeds at two separate met towers are monitored routinely. If any wind sensor indicates speed in excess of 50 MPH for two consecutive hours, a walkdown inspection of the breakwater is performed to assess any damage and repair as needed. Additional walkdown inspections are performed at the discretion of the design engineer for any suspicion of damage, regardless of wind speed.

a. Program scope will be enhanced to include the east breakwater, jetties, and onshore revetments in addition to the main breakwater (commitment number 27). No underwater supports are identified to be added to scope of this program for license renewal period. (Ref.

Aging Management Program Evaluation Report LRPD-02, section 4.21.3.B.1.b).

b. The Water Control Structures Monitoring Program at PNPS is comparable to the program described in NUREG-1801,Section XI.S7, RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants. The program includes visual inspections to manage loss of material and loss of form for water-control structures (breakwaters, jetties, and revetments). The water-control structures are of rubble mound construction with the outer layer protected by heavy capstone.

Parameters monitored include settlement (vertical displacement) and rock displacement.

These parameters are consistent with those described in RG 1.127. There are no underwater supports identified in scope of this program.

(Ref. Aging Management Program Evaluation Report LRPD-02, section 4,21.3.A)

c. No underwater supports are identified to be added to scope of this program for the license renewal period. (Ref. Aging Management Program Evaluation Report LRPD-02, section 4.21.3.B.1.b).

NRC Auditor PNPS Lead Hoang, Dan Ahrabli, Reza 250 Accepted

[B.1.29.3-H-07, Water Control Structures Monitoring Program]

The applicant is requested to confirm that Pilgrim AMP B.1.29.3 identifies an inspection of underwater supports for loss of material due to corrosion and loss of mechanical function. Provide the following information related to this request:

(a) Identify the specific underwater supports that will be added to the scope of the inspection program for the license renewal period, including the system name and ASME Code Class.

(b) Specify the current inspection program and describe the current inspection details for the underwater supports that are identified in (a) above.

(c) Confirm that, all ASME Code Class underwater supports will be included in the scope of the inspection program for the license renewal period.

Hoang, Dan Ahrabli, Reza Thursday, June 1, 2006 Page 64 of 82

Number Status Request 251 Closed

[B.1.30-W-01, System Walkdown]

1. PNPS states in LRA A.2.1.34, System Walkdown Program, that "Surfaces are inspected at frequencies to provide reasonable assurance that effect of aging will be managed such that applicable components will perform their intended function during the period of extended operation."

However, there is only limited information provided in the LRA B.1.30, "System Walkdown."

What is the frequency of inspection, and what are the inspection criteria for the current program?

Response

As stated in LRA Section B.1.30, the system Walkdown Program is consistent with the program described in NUREG-1801,Section XI.M36, External Surfaces Monitoring. The frequency of inspection and the acceptance criteria are consistent with those described in NUREG-1801,Section XI.M36. Further information is provided in Section 4.22 of the PNPS License Renewal Project Aging Management Program Evaluation Report, LRPD-02, "Aging Management Program Evaluation Report." A copy of this section of the report is available for on-site review.

NRC Auditor PNPS Lead Wen, Peter Potts, Lori System Walkdowns are performed in accordance with Entergy Procedure EN-DC-178, "System Walkdowns." A copy of this procedure was available for on-site review.

System inspections are conducted at least once per refueling cycle. This frequency is acceptable since aging effects are typically caused by long-term degradation mechanisms such as corrosion. Surfaces that are inaccessible or not readily visible during plant operations and refueling outages are inspected at such intervals that would ensure the components intended function is maintained.

The intervals of inspections may be adjusted as necessary based on plant-specific inspection results and industry experience. In addition, all plant personnel are required to identify adverse conditions via the corrective action process.

Since adverse conditions include those which the system walkdowns are intended to manage, aging effects may be identified through routine operations and maintenance activities.

System walkdown attributes are based on EPRI Technical Reports 1011223, "Aging Identification and Assessment Checklist - Electrical Components," January 2005, and 101124, "Aging Identification and Assessment Checklist - Civil and Structural Components," January 2005, and are consistent with NUREG-1801,Section XI.M36. Examples of Walkdown Attributes include:

Liquid on floor/components leaking Concrete or grout cracks Paint and preservation adequate Fasteners in place, in good condition, proper thread engagement Evidence of moisture entry on/in panels, conduits, or other components Hangers (loose, broken, improper fasteners, indications of improper motion, displacement)

In addition, System Engineers have received training on EPRI Technical Report 1007933, "Aging Assessment Field Guide," December 2003, and use the Guide during performance of their System Walkdowns.

Thursday, June 1, 2006 Page 65 of 82

Number Status Request 252 Closed

[B.1.30-W-02, System Walkdown]

2. PNPS states in LRA B.1.30

, 'System Walkdown," that this AMP is consistent with the program described in GALL Report Section XL.M36, "External Surfaces Monitoring."

The GALL Report XIM36 indicates that this AMP manages aging effects through visual inspection and monitoring of external surfaces for loss of material and leakage. The GALL Report further states in the Detection of Aging Effects program element, that "Surfaces that are inaccessible or not readily visible during plant operations and refueling outages are inspected at such intervals that would ensure the

• components intended function is maintained."

Discuss how PNPS plans to inspect inaccessible surfaces of components that are within the scope of license renewal.

253 Closed

[B.1.30-W-03, System Walkdown]

3. Provide some examples of actual plant-specific operating experience of how the problems were identified and appropriate actions taken to demonstrate and ensure the effectiveness of the existing System Walkdown Program.

254 Closed

[B.1.31-W-01, Thermal Aging and Neutron Irradiation Embrittlement of CASS]

1. What are the screening criteria used by PNPS to determine the susceptibility of CASS components to thermal aging and neutron irradiation embrittlement?

Response

Surfaces that are inaccessible or not readily visible during plant operations are inspected during refueling outages. Surfaces that are inaccessible or not readily visible during both plant operations and refueling outages are inspected at such intervals that would provide reasonable assurance that the effects of aging will be managed such that applicable components will perform their intended function during the period of extended operation.

Surfaces that are insulated are inspected when the external surface is exposed (i.e.,

maintenance) at such intervals that would provide reasonable assurance that the effects of aging will be managed such that applicable components will perform their intended function during the period of extended operation.

Corrosion of piping under insulation will be associated with discoloration of the external insulation or with visible degradation of the insulation which provided the pathway for the fluid to reach the piping. Consistent with NUREG-1801,Section XI.M36, staining on thermal insulation is a monitored parameter.

.NRC Auditor PNPS Lead Wen, Peter Trask, Tim As stated in LRA Section B.1.30, system walkdowns between 1998 and 2004 identified evidence of aging effects, including corrosion and leakage. Examples include fire water storage tank and diesel fire pump fuel oil day tank leakage, through-wall leakage on SSW piping, signs of corrosion in fan room and auxiliary bays, and through-wall leakage without loss of function on a drain line to the aux bay sump. Corrective actions were accomplished in accordance with the site Corrective Action Program. Related condition reports are available for on-site review.

The PNPS CASS program has not yet been developed. However, to ensure consistency with NUREG-1801, the screening criteria (casting method, molybdenum content, and ferrite content) given in Section XI.M13, Scope of the Program, would be used by PNPS to determine susceptibility to thermal aging.

Components exposed to more that 1017 n/cm2 (E>1 MeV) over the life of the plant will be included in the program as susceptible to neutron irradiation embrittlement.

Wen, Peter Wen, Peter Trask, Tim Finnin, Ron Thursday, June 1, 2006 Page 66 of 82

Number Status Request 255 Closed

[B.1.31-W-02, Thermal Aging and Neutron Irradiation Embrittlement of CASS]

2. As indicated in Table 3.1.2-2 of the LRA, PNPS identified three components: CRD Guide Tubes, Fuel Support Pieces and Jet Pump Assemblies are subject to the aging effect of loss of fracture toughness due to thermal aging and neutron irradiation embrittlement. Are any other CASS components in primary pressure boundary and reactor vessel internal subject to this aging effect?

Discuss the recent ISI inspection findings for those components that PNPS has identified to be subject to this aging effect.

[B.1.31-W-03, Thermal Aging and Neutron Irradiation Embrittlement of CASS]

256 Closed

3. As indicated in the description of LRA AMP B. 1.31, PNPS claims that its B.1.31 AMP will be consistent with the GALL Report Section XI.M13 AMP. The GALL Report states that for each "potentially susceptible" component, an applicant can implement either (a) a supplemental examination of the affected component as part of a 10-year ISI program during the license renewal term, or (b) a component-specific evaluation to determine the component's susceptibility to loss of fracture toughness.

Describe what kind of supplemental inspection will be used in PNPS for detecting the critical flaw size with adequate margin.

257 Accepted

[B.1.31-W-04, Thermal Aging and Neutron Irradiation Embrittlement of CASS]

4. PNPS states in LRA B.1.31, that this AMP is a new program, and it will be initiated prior to the period of extended operation. Will the implementation of this AMP be included in the commitment list?

Response

The CASS program comparable to NUREG-1801 Section XI.M13 is applicable only to the reactor vessel internals. The identified CASS components of the internals (guide tube, fuel support pieces, and pieces of the jet pump assemblies) are not subject to ISI, so there are no ISI results to date.

Outside the reactor vessel, the only CASS components are valve bodies, pump casings, and the main steam flow restrictors. PNPS has no CASS piping. The main steam flow restrictors are not pressure boundary parts, and hence they are not examined by ISI either.

Reduction of fracture toughness for CASS valves and pump casings are managed by ISI, not by a CASS program, as discussed in NUREG-1801 Section XI.M1 For those components that require inspection, PNPS will inspect them using enhanced visual examinations (EVT-1) capable of detecting 0.0005 inch resolution.

PNPS will perform either component specific evaluations or examinations of those components that are not eliminated by the screening criteria discussed in Question 254.

Component-specific evaluations may include mechanical loading analyses. Component examinations will be enhanced visual examinations (EVT-1). Evaluations/inspections will be performed by the first refueling outage in the period of extended operation.

Acceptance criteria for any flaws detected during these examinations will be evaluated in accordance with the applicable procedures of IWB-3500, and may include flaw evaluations performed according to the principles associated with IWB-3640 procedures for submerged arc welds (SAW), disregarding the Code restriction of 20% ferrite in IWB-3641(b)(1).

Yes, all new programs are included in the commitment list. Implementation of the Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel Program is commitment #29.

NRC Auditor Wen, Peter Wen, Peter Finnin, Ron PNPS Lead Finnin, Ron Wen, Peter Finnin, Ron Thursday, June 1, 2006 Page 67 of 82

r Number Status Request 258 Closed

[B.1.32.1-P-01, Water Chemistry Control - Auxiliary Systems]

1. Per SRP Appendix Al, section A1.2.3.4, the frequency of sampling water chemistry should be identified. PNPS Appendix B.1.32-1, element 4 does not identify the frequency. Identify the frequency.

260 Accepted

[B.1.32.3-P-01, Water Chemistry Control - Closed Cooling Water]

1. The exception taken for element 4 about the performance and functional testing should also apply to element 3 for the same reason that it applies to element 4.

Justify why this exception does not apply to element 3.

Response

Stator cooling water conductivity is monitored continuously using three conductivity elements with remote readouts and alarms. Dissolved oxygen is measured using a portable oxygen meter with a continuous local display. The oxygen meter is read weekly and the value is recorded. If the oxygen meter is out-of-service, a weekly grab sample is obtained and a chemical analysis is performed. Monthly copper analyses are performed to monitor for corrosion.

1. There are three installed plant conductivity elements (P&ID M275). They read out remotely and are alarmed for Operations. In addition, there is one portable conductivity meter kept in Sample Panel C-3006. The portable conductivity meter only has a local readout.

Normally, the portable meter satisfies procedure PNPS 7.8.1 grab sample requirement.

However, we are considering removing the portable meter from the sample panel and just use the installed conductivity elements. With three conductivity elements, there is more than enough monitoring.

2. The only oxygen meter is portable and located in Sample Panel C-3006. It only has a local readout. The oxygen meter continuously displays locally, but has no readout or alarms.

The oxygen meter is read weekly and the value is recorded. If the oxygen meter is out-of-service, a weekly grab sample is obtained and a chemical analysis is performed.

3. PNPS does not do corrosion products analyses. Only copper analyses are performed.

The exception in LRA Section B.1.32.3, which was applied to the detection of aging effects attribute (element 4) is equally applicable to the parameters monitored/trended attribute (element 3). The exception was discussed under Element 4 since it is more directly related to detection of aging effects.

LRA Section B.1.32.3 will be amended to indicate that the exception is applicable to both attribute 3, Parameters Monitored/Trended and attribute 4, Detection of Aging Effects.

This requires an amendment to the LRA.

NRC Auditor PNPS Lead Patel, Erach Smalley, Paul Patel, Erach Smalley, Paul Thursday, June 1, 2006 Page 68 of 82

Number Status Request 261 Closed

[Generic-J-01, Appendix B Aging Management Program]

1. In the PNPS LRA Operating Experience section for several AMPs (e.g. B.1.5; B.1.6; B.1.7; B.1.8; B.1.25) describes only the results of relatively recent inspection during RFO14 (April 2003) and RFO15 (April 2005).

In most cases, inspection results for these refueling outage are negative (no recordable indications). Then the LRA makes a statement such as "Absence of recordable indications on the vessel attachment welds provides evidence that the program is effective for managing aging of the component during the period of extended operation."

Response

SRP Section A.1.2.3.10 states, "Operating experience with existing programs should be discussed." To identify operating experience for license renewal, Entergy focused on operating experience with the existing programs rather than operating experience from the program that existed 10 to 15 years ago. Entergy did not own the plant 10 years ago. Entergy focused on operating experience from the existing programs rather than operating experience from the program that existed 10 to 15 years ago, because results of the earlier inspections do not provide information regarding existing program effectiveness. In addition, BWRVIP programs incorporate industry operating experience from the entire BWR fleet. The PNPS programs are based on NUREG-1 801 programs which are also based on industry experience.

NRC Auditor PNPS Lead Jackson, Wilbur Cox, Alan LR-SRP (NUREG-1800, Rev.

1) in Appendix A, Section A.1.2.3.10 (Branch Technical Position RLSB-1, Operating Experience) states that "the operating experience of aging management programs, including past corrective actions resulting in program enhancements or additional programs, should be considered.....

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."

QUESTION:

For those AMPs where only the negative inspection results of RFO14 and RFO15 inspections are presented in the LRA, please provide additional discussion of inspection results from earlier refueling outages (approximately 10-15 years of history). If historical inspection results have found indications at some times in the past, provide additional discussion of what corrective actions have been taken.

Thursday, June 1, 2006 Page 69 of 82

Number Status Request 262 Accepted

[Generic-J-02, Appendix B Aging Management Program]

2. The Standard Review Plan for License Renewal (NUREG-1800, Rev. 1),

Section 3.0.1, states that "Enhancements are revisions or additions to existing aging management programs that the applicant commits to implement prior to the period of extended operation."

Response

The intent of saying that enhancements will be initiated prior to the period of extended operation is that the enhancements will be fully implemented prior to the period of extended operation.

NRC Auditor PNPS Lead Jackson, Wilbur Cox, Alan This clarification will be provided in an amendment to the LRA.

In describing enhancements, the PNPS LRA typically says,

'The following enhancement will be initiated prior to the period of extended operation."

In describing an enhancement as something to be "initiated",

rather than "implemented", prior to the period of extended operation, the LRA wording appears is ambiguous with regard to whether the enhancement will be fully implemented prior to the period of extended operation.

QUESTION:

Clarify or resolve this ambiguity in the LRA description of enhancements.

298 Closed B. 1.16.2-J-04 Please provide a comparison of the number of category B-F weld inspections and category B-J weld inspections before and after implementation of risk-informed ISI.

See below for the number of B-F and B-J weld inspections before and after risk informed ISI (RISI) implementation:

Code Category B-F There are a total of 40 B-F welds in the ISI program. Before RISI implementation there were 40 weld exams and after RISI there are now 11 welds examined.

Code Category B-J There are a total of 598 B-J welds in the ISI program. Before RISI implementation there were 156 weld exams and after RISI there are now 60 welds examined.

In addition to ISI program welds, there are augmented IGSCC BWRVIP-75A program welds examined. For the IGSCC category B thru G welds examined per BWRVIP-75A there are 16 category B-F welds and 18 category B-J welds.

Jackson, Wilbur Potts, Lori Thursday, June 1, 2006 Page 70 of 82

Number Status Request 299 Closed Generic - N - 01 Provide brief description of all AC power sources and sequence of power transfer:

Response

Power to the New England Grid is provided via the Main Transformer and the 345kV switchyard.

The six 4.16kV busses are powered via the Unit Auxiliary Transformer (UAT).

Upon a unit trip, the 4.16kV buses are automatically fast transferred to the Start up transformer, the preferred source (SUT). On loss of SUT, the 4.16kV safety busses A5 and A6 are transferred to Emergency Diesel Generators (EDG) automatically after approximately 10 seconds. Loss of an EDG will result in a transfer of its respective 4.16kV bus automatically in approximately 12 seconds to the Shutdown Transformer (SDT) source. Upon loss of all AC power at PNPS, the Station Blackout Diesel (SBODG) is started manually from the Control Room in 10 minutes and manually loaded to the safety 4.16kV busses A5 or A6 as needed by Operations.

The secondary AC power, the Shutdown Transformer (SDT) is capable of supplying all require loads of one emergency AC 4.16kV bus A5 or A6 for the safe shutdown of reactor for postulated accidents per PNPS analysis. The SDT is capable of supplying both safety busses A5 and A6 loadings per PNPS analysis for normal shutdown.

NRC Auditor PNPS Lead Nguyen, Duc Das, Swapan 300 Closed Generic - N - 02 What is the capability of 23kV Shut down Transformer (SDT)

Source?

Nguyen, Duc Das, Swapan Thursday, June 1, 2006 Page 71 of 82

Number Status Request 302 Closed B.1.12-P-01 Review of AMPER 4.11 -

element 2, Preventive Actions (page 137)

In the comparison statement, PNPS states that PNPS preventive actions are not consistent with GALL Report and that the program only involves tracking of cycles, and does not include assessment of environmental fatigue. However, environmental fatigue is addressed by TLAA section 4.3.3, and therefore, PNPS is consistent with GALL Report.

Please clarify if PNPS is consistent with GALL for this element.

Response

The effects of the reactor coolant environment are not considered in the current fatigue monitoring program at PNPS. The CUFs given in Table 4.3-1 of the LRA are the basis for the current fatigue monitoring program, and these were calculated without considering environmental effects.

Section 4.3.3 of the LRA presents a conservative estimate of the effects of the reactor coolant environment on fatigue for PNPS. The results (the CUFs in Table 4.3-3 of the LRA) show that severallocations exceed 1.0 when the resulting Fen are applied. As stated in LRA Section 4.3.3:

"Prior to entering the period of extended operation, for each location that may exceed a CUF of 1.0 when considering environmental effects, PNPS will implement one or more of the following:

(1) further refinement of the fatigue analyses to lower the predicted CUFs to less than 1.0; (2) management of fatigue at the affected location by an inspection program that has been reviewed and accepted by the NRC (e.g.

periodic non-destructive examination of the affected locations at inspection intervals to be determined by a method acceptable to the NRC);

(3) repair or replacement of the affected locations."

Once this commitment is implemented (commitment #31), the allowable number of transient cycles will be inputs to the fatigue analyses that include consideration of the effects of the reactor coolant environment.

Therefore, during the period of extended operation, the Fatigue Monitoring Program will An exception was not identified for Attribute 6 in the original Aging Management Program since the exception addressed under Attribute 2 was considered adequate. For clarification, the Aging Management Program document, and the License Renewal Application will be revised as follows to also show an exception for attribute 6.

AMPER 4.11 - element 6. The final sentence will be changed to read "PNPS acceptance criteria are not consistent with NUREG-1 801 because the PNPS Fatigue Monitoring Program does not consider environmental fatigue effects."

LRA Section B.1.12 will be revised to add "6.

Acceptance Criteria" under the Attributes Affected column for the first exception listed.

Patel, Erach Finnin, Ron NRC Auditor PNPS Lead 303 Accepted B.1.12-P-02 Review of AMPER 4.11 -

element 6, Acceptance Criteria (page 137)

In the comparison to GALL element 6, PNPS states it is consistent with GALL.

However, the comparison statement does not address environmental fatigue. As written, this statement is inconsistent with GALL Report.

Please clarify how environmental fatigue is addressed by PNPS or justify why as written, this element is consistent with GALL Report.

Patel, Erach Finnin, Ron Thursday, June 1, 2006 Page 72 of 82

Number Status Request 304 Closed B.1.12-P-03 Review of AMPER 4.11 -

element 7, Corrective Actions (page 137)

In the comparison statement, PNPS states, "if the lifetime projection of CUE exceeds 1.0,

.. ', please explain what lifetime means. Is it 40 years or 60 years? This references PNPS procedure 1.3.118, section 7.0, where the lifetime is defined as 40 years. Will the procedure be revised to reflect 60-year life?

305 Closed B. 1.27-W-03 Selective Leaching

3. Industry operating experience has identified graphitization (removal of iron from cast iron) of submerged pump components from long-term immersion in saltwater environments. PNPS indicates in LRPD-02, Section 3.8, that this AMP is credited in both Salt Service Water System and the Circulation Water System. Has any pump, in these systems, been replaced as a result of selective leaching? If yes, please discuss how the problem was identified and the corrective action taken.

Response

Lifetime projections, as used in Section 7.0 of procedure PNPS 1.3.118, are projections based on 40 years of operation. The procedure extrapolates the actual transient cycles that have occurred to date to 40 years and shows that the projected number of cycles remains below the number of cycles used to calculate the CUrs for the vessel and appurtenances.

Hence, the fatigue analyses that calculated the CUrs remain valid. The procedure will be revised to extrapolate transient cycles to 60 years, and we will adjust CUrs accordingly, when the renewed license is approved.

Projections of cycles to 60 years are provided in Section 4.3.1 (Table 4.3-2) of the LRA.

Yes, PNPS took an aggressive approach to replace P-105A ("A" Circulating Sea Water Pump) in RFO1 5 (April 2005) as a result of OE from the Vendor (Flowserve) informing PNPS

- that a failure of a cast iron Circulating Water Pump occurred at the New Boston Fossil Station in 2004 due to graphitization. That pump was a similar design to PNPS with 6 additional years of submergence/operation in salt water. Six core samples of the pump casing were sent out to a materials lab for analysis and the results confirmed graphitization. Currently, there are plans to replace P-105B in RFO17 based on the core sample analysis obtained from P-105A columns. PNPS has also purchased, and has on-site the columns for P-105B overhaul/replacement. The new pump columns are cast iron enhanced with the addition of 3-5%

Nickel to improve strength and resistance to graphitization. The original columns were ASTM A48 CL 35 with 1.75-2.25% Nickel.

The Salt Service Water pumps are not cast iron.

The cast iron valve bodies (lined with rubber and Ni-Resist cast iron discs) originally installed on the SSW System have been replaced with cast steel lined with rubber and monel discs such that there are no cast iron components in the SSW system.

LRPD-02 will be revised as follows: (Section 3.3.B.6.b - Acceptance Criteria - add after first paragraph) The acceptance criteria for enclosure assemblies will be no loss of material due to general corrosion. The acceptance criteria for elastomers will be no hardening and loss of strength due to degradation.

NRC Auditor Patel, Erach Wen, Peter PNPS Lead Finnin, Ron Ivy, Ted 306 Accepted B.1.18-N-04 Provide acceptance criteria for inspecting enclosure assemblies or justify why acceptance criteria for enclosure assemblies is not necessary. Revise AMP B1.18 as appropriate.

Nguyen, Duc Stroud, Mike Thursday, June 1, 2006 Page 73 of 82

Number Status Request 307 Accepted B.1.19-N-03 GALL XI.E3, under scope of program, defines significant moisture as periodic exposures to moisture that last less than a few days (e.g., cable in standing water).

Significant voltage exposure is defined as being subjected to system voltage for more than twenty-five percent of the time. PNPS LRPD-02, Revision 1, under Scope of Program states that this program will include inaccessible (e.g., in conduit or direct buried) medium-voltage cables within the scope of license renewal that are exposed to significant moisture simultaneously with applied voltage. AMRE-01, Revision 2, Section 3.4.1.5, Non-EQ Inaccessible Medium-Voltage Cable Screening, states that the cable that are susceptible to water treeing are those exposed to significant moisture (submerged for years).

Revise AMP B1.19, under the scope of program, to be consistent with GALL's definition or explain how inaccessible medium-voltage cables exposed moisture for more than few days and less than years is not susceptible to water tree.

Response

LRPD-02 will be revised as follows: (Section 3.4.B.1.b - Scope of Program - replace first paragraph) This program applies to inaccessible (e.g. in conduit or direct buried) medium-voltage cables within the scope of license renewal that are exposed to significant moisture simultaneously with significant voltage.

Significant moisture is defined as periodic exposure to moisture that lasts more than a few days (e.g., cable in standing water). Periodic exposures to moisture that lasts less than a few days'(i.e., normal rain and drain) are not significant. Significant voltage exposure is defined as being subjected to system voltage for more than twenty-five percent of the time.

NRC Auditor PNPS Lead Nguyen, Duc Stroud, Mike Thursday, June 1, 2006 Page 74 of 82

Number Status Request

Response

NRCAuditor PNPSLead 308 Closed B.1.19-N-04 GALL XI.E3 under The intent of the PNPS AMP B.1.19 is to inspect Nguyen, Duc Stroud, Mike program description states, in for water in manholes and to test the in-scope part, that periodic actions such medium-voltage cables.

as inspecting for water collection in cable man holes, and draining water, as needed to prevent cable from being exposed to significant moisture. The above actions are not sufficient to assure water is not trapped elsewhere in the raceways. In addition to the above periodic actions, in-scope medium-voltage cables are tested to provide an indication of the condition of the conductor insulation. PNPS AMP B.1.19 under the same attribute states that periodic actions will be taken to prevent cables from being exposed to significant moisture, such as inspecting for water collection in cables manholes and conduit, and draining water, as needed. In scope medium-voltage cables exposed to significant moisture and voltage will be tested to provide an indication of the condition of the conductor insulation. It is clear to the team if periodic actions of manhole inspections are used to preclude cable testings.

Confirm that the intend of AMP B.1.19 is to inspect for water in manholes and to test all the in-scope medium-voltage 309 Accepted B.1.19-N-05 GALL XI.E3 under LRA Appendix B.1.19 will define medium voltage Nguyen, Duc Stroud, Mike program description defines cables as follows: For this program, medium medium-voltage is from 2 kV to voltage is from 2kV to 35kV.

35 kV. AMRE-01, Rev 2, lists medium This requires an amendment to the LRA.

voltage cables from 2kV to 23 kV. Provide definition of medium voltage in the LRA to be consistent with GALL or provide a justification of why water tree phenomenon is not applicable for inaccessible medium-voltage cable greater than 23 kV.

Thursday, June 1, 2006 Page 75 of 82

Number Status Request 310 Accepted B. 1.1 9-N-06 GALL XI.E3 under parameters monitored/inspected states that the specific type of test performed will be determined prior to the initial test and it to be a proven test for detecting deterioration of the insulation system due to wetting such as power factor, partial discharge test, or polarization index, as described in EPRI TR-103834-P1, or other testing that is state-of-the-art at the time the test is performed.

PNPS B.1.19 under the same attribute only states that the specific type of test performed will be determined prior to the initial test. Revise your AMP to be consistent with GALL or explain how you ensure that the test to be performed will be in accordance with industrial guideline or that is the state-of-the-art at the time the test is performed.

311 Accepted B.1.19-N-07 Do you currently inspect water in the man holes.

Are there any existing procedures for inspecting man holes. Provide a copy of these procedures.

312 Closed B.1.19-N-08 AMRE-01, Rev. 2, Page 71 of 87 provides a list of in-scope inaccessible medium-voltage cables that are in scope of AMP B.1.19.

However, itdoes not include service water cables. Explain why service water cables are not in-scope of AMP B.1.19.

Response

LRPD-02 will be revised as follows: (Section 3.4.B.3.b - Parameters Monitored/Inspected

-replace 2nd sentence) This program will state that the specific type of test to be performed will be determined prior to the initial test and is to be a proven test for detecting deterioration of the insulation system due to wetting as described in EPRI TR-103834-P1-2, or other testing that is state-of-the-art at the time the the test is performed.

Yes, though not a formal procedure, PNPS has an existing repetitive task and job plan for inspecting manholes. An example is provided.

PNPS will develop a formal procedure to inspect manholes for in-scope medium voltage cable.

Also, LRPD-02, section 3.4.B.10 - Operating Experience will be revised to discuss the process for considering plant operating experience that will be used during implementation of the Non-EQ Medium-Voltage Cable Program.

Since medium voltage cables are defined as 2kV to 35kV, the service water cables are not in scope because they run on a system voltage of 480 volts.

NRC Auditor PNPS Lead Nguyen, Duc Stroud, Mike Nguyen, Duc Stroud, Mike Nguyen, Duc Stroud, Mike Thursday, June 1, 2006 Page 76 of 82

Number Status Request 313 Closed B.1.20-N-04 GALL Xl.E2 under scope of program states that this program applies to electrical cables and connections (cable system) used in circuits with sensitive, high voltage, low-level signal such as radiation monitoring and nuclear instrumentation that are subject to an AMR.

PNPS AMP B.1.20 under the same attribute states that this program will include non-EQ electrical used in circuits with sensitive, high voltage, low-level signals, i.e., neutron flux monitoring instrumentation.

Explain why high range radiation monitor cables are not in scope of B.1.20.

314 Accepted B.1.20-N-05 GALL XI.E2 under parameter monitored/inspected states that the parameter monitored are determined from the specific calibration, surveillance or testing performed and are based on the specific instrumentation under surveillance or being calibrated, as documented in plant procedures. PNPS AMP B.1.20 under same attribute states that results from the calibrations or surveillance of components within the scope of license renewal will be reviewed. The parameters reviewed will be based on the specific instrumentation circuit under surveillance or being calibrated, as document in the plant calibration or surveillance procedures.

Response

The high-range radiation monitoring system monitors radiation levels inside containment (drywell and torus areas) during and following a design basis event. The monitors (RE1001-606A/B and RE1001-607A/B) are safety-related. The cables from the detectors to the cabinets in the control room are EQ (10 CFR 50.49) and therefore, are replaced based on qualified life, so are not subject to aging management review.

NRC Auditor PNPS Lead Nguyen, Duc Stroud, Mike

a. LRPD-02 will be revised as follows: (Section 3.5.B.3.b - Parameters Monitored/Inspected -

replace 2nd sentence) The parameters monitored are determined from the specific calibration, surveillances or testing performed and are based on the specific instrumentation circuit under surveillance or being calibrated, as documented in plant procedures.

b. LRPD-02 will be revised to read as follows:

(Section 3.5.B.3.b - Parameters Monitored/Inspected - add to 2nd sentence) The parameters monitored are determined from the specific calibration, surveillances or testing performed. The parameter for cable testing is determined from the plant procedures. Cable testing is performed by plant procedures on cables in-scope of license renewal that are disconnected during instrument calibration.

Nguyen, Duc Stroud, Mike

a. Why does the review of calibration results belong to parameter monitored/inspected attribute?

b. The parameter monitored/inspected for cable testing was not mentioned.

What is the parameter for cable testing. Confirm that cable testing will be perform on cables in scope of XI.E2 that are disconnected during instrumentation calibration.

Thursday, June 1, 2006 Page 77 of 82

Number Status Request 315 Accepted B.1.21-N-03 GALL XI.E1 under scope of program states that this inspection program applies to accessible electrical cables and connections within the scope of license renewal that installed in adverse localized environments caused by heat or radiation in the presence of oxygen. PNPS B.1.21 under the same element states that this program will include accessible insulated cables and connections installed in structures within the scope of license renewal and prone to adverse localized environments. What "in a structure" means? Why are structures included in the scope of non-EQ cables and connections AMP?

316 Accepted B.1.13.1-P-04

4. New question from site visit:

GALL report states that the periodic function test and inspection performed at least once every six months detects degradation of the halon/C02 fire suppression system before the loss of the component intended function. However, per review of LRPD-02, Rev.1, section 4.12.1.B.4.b, PNPS performs this test once each operating cycle, which is different than GALL report frequency. Please justify why this is not an exception to element 4, and if it is, please revise the LRA to include this exception.

Response

"In a structure" means inside the plant, not outside.

LRPD-02 will be revised to read as follows:

(Section 3.6.B.1.b - Scope of Program - add to scope) The program applies to accessible electrical cables and connections within the scope of license renewal that are installed in adverse localized environments caused by heat or radiation in the presence of oxygen.

NRC Auditor PNPS Lead Nguyen, Duc Stroud, Mike As indicated in the PNPS repetitive task database, functional testing of the cable spreading room Halon fire suppression system is performed annually and inspection of the system is performed at least once every six months. Therefore, LRA Section B.1.13.1 will be revised to include the following exception to the Detection of Aging Effects Attribute.

The NUREG-1801 program recommends that functional testing and inspection of the Halon fire suppression system occur at least once every six months. However, while PNPS performs inspections at least once every six months, functional testing is performed annually.

Exception note: The variation in functional test frequency is insignificant with relation to detection of aging effects because functional tests are designed to verify the operability of active system components. Since system inspections are performed at least once every six months, aging effects are identified prior to loss of passive component intended function.

This requires an amendment to the LRA.

Loss of material for fire barrier walls, ceilings, and floors is addressed in procedure PNPS 8.B.29, Section 8.2 [1]. This procedure section describes how each fire barrier is to be inspected. It directs inspectors to take note of any damaged portions of the barrier, and lists cracks/gaps/voids in walls as an example of damage to be noted. It further states that if a major defect exists in any barrier it will be evaluated and entered into the corrective action action process.

Patel, Erach Potts, Lori 317 Closed B.1.13.1-P-05

5. New question from site visit:

In element 3, GALL states that visual inspection of the fire barrier walls, ceilings, and floors examines any sign of degradation such as cracking, spalling, and loss of material caused by freeze-thaw, chemical attack, and reaction with aggregates. Procedure 8.B.29 addresses cracking, spalling, etc., however LOM is not addressed. Where is LOM addressed?

Patel, Erach Potts, Lori Thursday, June 1, 2006 Page 78 of 82

Number Status Request 318 Accepted B.1.13.1-P-06

6. New question from site visit:

The GALL AMP XI.M26 specifies approximately 10% of each type of seal should be visually inspected at least once every refueling outage (2 years). The exception taken in.

the LRA states inspection of approximately 20% of seals each operating cycle, with all accessible penetration seals being inspected at least once every five operating cycles (10 years). Please identify if each type of seal is included in this 20% sample.

319 Closed Please revise LRPD-02 pg 268, detection of aging effects for small bore piping inspection activity, to indicate that volumetric examinations are used to detect cracking in butt welds. Also revise LRPD-02 pg 267, scope of program for water chemistry inspection activity, to "A representative sample of susceptible components..."

Response

The exception in LRA Section B.1.13.1 will be revised to state: The NUREG-1801 program states that approximately 10% of each type of penetration seal should be visually inspected at least once every refueling outage. The PNPS program specifies inspection of approximately 20% of the seals, including at least one seal of each type, each operating cycle, with all accessible fire barrier penetration seals being inspected at least once every five operating cycles.

This requires an amendment to the LRA.

LRPD-02 pg 268, detection of aging effects for small bore piping inspection activity, will be revised to state: "Combinations of non-destructive examinations (including VT-1, enhanced VT-1, ultrasonic, and surface techniques) will be performed by qualified personnel following procedures that are consistent with Section XI of ASME B&PV Code and 10 CFR 50 Appendix B. Volumetric examinations are used to detect cracking in butt welds. Actual inspection locations will be based on physical accessibility, exposure levels, NDE techniques, and locations identified in NRC Information Notice 97-46".

LRPD-02 pg 267, scope of program.for water chemistry inspection activity, will be revised to state:

"A representative sample of susceptible components of each material and environment crediting water chemistry control programs for aging management will be inspected."

Program descriptions in Appendix A of the LRA will be revised, as applicable, to identify the commitment number(s) associated with the program.

The program descriptions in Appendix A for new or enhanced programs will be amended to include one of the following statements as applicable.

"License renewal commitment #

governs implementation of this program."

Or, "License renewal commitment #

specifies enhancement to this program."

This requires an amendment to the LRA.

NRC Auditor Patel, Erach PNPS Lead Potts, Lori Patel, Erach Potts, Lori 320 Accepted Generic P-01 Since Appendix A will be placed in the FSAR immediately if and when the license renewal application is approved, new programs should be presented in future tense, rather than present tense as currently presented.

Also, SRP-LR states that all enhancements to programs should be listed in Appendix A, UFSAR Supplement.

Patel, Erach Cox, Alan Thursday, June 1, 2006 Page 79 of 82

P Number Status Request 321 Accepted B.1.1-W-05 Please revise LRPD-02, Sections 4.1.B.2.b and 4.1.B.4.b to clarify that BADGER testing is an areal density measurement.

Response

LRPD-02, Sections 4.1.B.2.b and 4.1.B.4.b will be revised to clarify that BADGER testing is an areal density measurement.

Section 4.1.B.2.b will state:

Silica levels in the spent fuel pool water are monitored monthly.

(Ref. Attachment 9, 7.8.1)

Gap formation is measured by blackness testing, areal density (BADGER) is periodically measured and the RACKLIFE predictive model is used.

(Ref. CR-PNP-2004-00285)

PNPS preventive actions are consistent with NUREG-1801.

Section 4.1.B.4.b will state:

The amount of boron carbide released from the Boraflex panels is determined through correlation of the silica levels in the spent fuel pool water using the RACKLIFE code. Detection of gaps through blackness testing and periodic verification of boron loss through areal density measurements (BADGER) identify loss of material and cracking of the Boraflex panels.

(Ref. Attachment 9, 7.8.1 and CR-PNP-2004-00285)

This program is credited with managing the following aging effects.

• change in material properties (reduction in neutron-absorbing capacity) for Boraflex neutron absorber panels (AMRM 21)

PNPS detection of aging effects is consistent with NUREG-1801.

10 CFR 50.49 does not require actions that prevent aging effects.

LRPD-02 will be revised to read as follows:

(Section 4.10.B.2.b - Preventive Actions - add to end of first sentence) The program actions that could be viewed as preventive actions are the identification of qualified life and specific maintenance/installation requirements.

Reactor water hydrogen peroxide measurements, while they would be beneficial in determining the total oxidizing species affecting Stress Corrosion Cracking (SCC), are not practical. The results obtained through liquid sampling are inaccurate because of decomposition of hydrogen peroxide in the sample lines. No practical method exists for a BWR to obtain direct hydrogen peroxide measurements.

In accordance with BWRVIP-1 30, reactor water Electrochemical Corrosion Potential (ECP) and dissolved oxygen measurements are used at PNPS to determine whether oxidizing species including H202 have been reduced sufficiently to minimize IGSCC.

NRC Auditor PNPS Lead Wen, Peter Potts, Lori 322 Accepted B.1.1.11-N-03 Provide a description of preventive actions for the PNPS EQ Program.

323 Closed

[B.1.32.2-P-02]

GALL AMP XI.M2, element 3, Parameters Monitored/Inspected, lists monitoring of chlorides, sulfates, dissolved oxygen, and hydrogen peroxide.

However, LRPD-02, section 4.23.2.B.3.b, which performs a comparison of element 3 with the PNPS AMP, monitoring of hydrogen peroxide is not mentioned, and concludes that the PNPS AMP is consistent with this element. Please clarify if hydrogen peroxide is not monitored, how is PNPS consistent with this element?

Nguyen, Duc Stroud, Mike Patel, Erach Loomis, Larry Thursday, June 1, 2006 Page 80 of 82

Number' Status Request 324 Accepted

[B.1.32.3-P-02] The last sentence of exception note 1 states that "Passive intended functions of pumps, heat exchangers and other components will be adequately managed by the closed cooling water chemistry program through monitoring and control of water chemistry parameters." Isn't the one-time inspection program also used to verify effectiveness of the chemistry program? If so, should that be addressed as part of this exception note 1 justification?

325 Accepted

[B.1.32.1-P-02] Element 6-Acceptance Criteria states that conductivity should be maintained <0.3 S/cm. Is the unit correct? Should it be pS/cm? (per LRPD-02, Rev. 1, section 4.23.1.B.6) 326 Accepted

[B.1.32.2-P-01] GALL Chapter XI.M2 suggests that for "susceptible locations," a one-time inspection verification program may be appropriate.

Do you intend to implement a one-time inspection program for this water chemistry control program?

Furthermore, will a one-time inspection program be implemented for other water chemistry control programs? If so, please explain why this is not included in Appendix A for each of these water chemistry control programs.

Response

For clarity, LRA Section B.1.23.3, exception note 1 will be revised to state: "Passive intended functions of pumps, heat exchangers and other components will be adequately managed by the closed cooling water chemistry and one-time inspection programs through monitoring and control of water chemistry parameters and verification of the absence of aging effects."

Yes, this was a software conversion error.

Element 6 of LRA Section B.1.32.1 will be amended to correct the units of conductivity to pS/cm and delete the acceptance criteria for corrosion products. Corrosion product (copper) sampling is used to determine the type of copper oxide layer formed. Thus it is a diagnostic parameter without an acceptance criterion.

Yes, the one-time inspection program described in LRA Section B.1.23 includes inspections to verify the effectiveness of the water chemistry control aging management programs by confirming that unacceptable cracking, loss of material, and fouling is not occurring.

LRA Section 3 Table l's discussions provide the link between the One-Time Inspection and Water Chemistry Control Program for susceptible components. However, for clarity, LRA Appendix A descriptions for the Water Chemistry Control - BWR, Closed Cooling Water and Auxiliary Systems programs will be amended to provide a link to the One-Time Inspection Program activities to confirm the effectiveness of these programs.

This requires an amendment to the LRA.

NRC Auditor Patel, Erach Patel, Erach Patel, Erach PNPS Lead Potts, Lori Potts, Lori Potts, Lori Thursday, June 1, 2006 Page 81 of 82

Number Status Request 327 Accepted B.1.30-W-04 LRPD-02 identifies an enhancement to the System Walkdown Program that is not listed in the LRA. Please 328 Accepted GALL XI.E1, XI.E2, XI.E3, and XI.E4 indicates that operating experience has shown that degradation of metal enclosed bus, cables, and connections within the scope of El, E2, E3, and E4 may exist. Provide a discussion of industry and plant operating experience for these programs.

Response

The enhancement in LRPD-02 was identified after the LRA was submitted to NRC for review.

This enhancement will be added to LRA Section B.1.30 as follows.

Enhancements Attribute Affected 1. Scope of Program Enhancement Enhance system walkdown guidance documents to clarify license.renewal commitment. The commitment for license renewal is for periodic system engineer inspections of systems in scope and subject to aging management review for license renewal in accordance with 10 CFR 54.4(a)(1) and (a)(3).

Inspections shall include areas surrounding the subject systems to identify hazards to those systems. Inspections of nearby systems that could impact the subject systems will include SSCs that are in scope and subject to aging management review for license renewal in accordance with 10 CFR 54.4(a)(2).

This requires an amendment to the LRA.

The programs will be updated to include the following:

The XXX program is a new aging management program. Industry operating experience that forms the basis for the program is described in the operating experience element of the NUREG-1801 program description. PNPS plant-specific operating experience is consistent with the operating experience in the NUREG-1801 program description. Specifically, PNPS has experienced [insert PNPS component-specific OE similar to GALL OE].

Plant and industry operating experience with the methods planned for this program provides reasonable assurance that the program will be effective during the period of extended operation. The program is based on the program description in NUREG-1801, which in turn is based on relevant industry operating experience.

As such, operating experience indicates that implementation of the XXX program will provide reasonable assurance that effects of aging will be managed such that applicable components will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation.

This requires an amendment to the LRA.

NRC Auditor Wen, Peter PNPS Lead Potts, Lori Nguyen; Duc Stroud, Mike Thursday, June 1, 2006 Page 82 of 82

!K9ent+/-oward - Patch File

.Page 1

From:

Ram Subbaratnam To:

James Davis Date:

6/5/2006 9:05:18 AM

Subject:

Patch File

,,J Nuclear power plants release varying amounts of tritium, depending on the amount of liquid waste discharged via normal and abnormal release discharge paths and the type of reactor. In the United States, there are two basic types of operating reactors, a pressurized water reactor (PWR) and a boiling water reactor (BWR). PWRs typically have higher tritium releases than BWRs. In 2003, the average PWR released about 700 curies of tritium in liquid effluents and the average BWR released about 30 curies of tritium in liquid effluents.

The NRC is proactive and taking action in investigating incidents reported by various licensees about radiological leaks and spills. For example, the NRC has established a lessons learned task force to address inadvertent, unmonitored liquid radioactive releases from U.S. commercial nuclear power plants. This task force will review previous incidents and identify lessons learned from these events and determine what, if any changes are needed to the regulatory program.

The NRC will enter the findings from the lessons learned task force into its formal agency lessons learned program.

The NRC licensing process for nuclear power plants includes a thorough review of all the plant's radioactive, gaseous, liquid, and solid waste systems, components, and programs to ensure that radioactive material is safely controlled in accordance with NRC regulations. The licensing process, evaluated the plant's ability to safely handle, store, monitor, and discharge radioactive effluents in accordance with NRC requirements. These requirements include safety limits on radiation dose to plant workers and members of the public. During operation of the plant, the NRC continuously inspects licensee performance through. the use of Resident Inspectors stationed at each plant and the use of technical specialist inspectors from the NRC Regional offices. If there is an abnormal situation at a plant, the Resident Inspector and Regional Specialists become involved to assess the licensee's response to the situation to ensure NRC requirements are met.

As with any industrial facility, a nuclear power plant may deviate from normal operation with a spill or leak of liquid material. However, the design of the plant and the NRC inspection program provides reasonable assurance that even in abnormal situations, safety limits are met.

Radiological health hazard and biological effects due to exposure to very small amounts of ionizing radiation is thought to minimally increase the risk of developing cancer, and the risk increases as exposure increases. Tritium is one of the least dangerous radionuclides because it emits very weak radiation and leaves the body relatively quick. Since tritium is almost always found as water, if ingested, it goes directly into soft tissues and organs. The dose to these tissues are generally uniform and dependent on the tissues' water content. Sr-90, if ingested, tends to mimic calcium when it is in the body and therefore becomes concentrated in calcified tissues such as bones and teeth. If ingested in quantities that produce very large doses (about a thousand times higher than what we all receive from natural radiation), Sr-90 is known to increase the risk of bone cancer and leukemia in animals, and is presumed to do so in people.

Below these doses, there is no evidence of excess cancer.

Radiological environmental monitoring and effluent monitoring at nuclear power plants is required by U.S. Nuclear Regulatory Commission regulations. The monitoring of radioactive effluents and the environment around the nuclear power plant is important both for normal operations, as well as in the event of an accident. During normal operations, environmental monitoring verifies the effectiveness of in-plant measures for controlling the release of radioactive materials, and makes sure that the levels of radioactive materials in the environment do not exceed those originally anticipated prior to licensing the plant. For accidents, it allows an additional means for estimating doses to members of the general public. The principal regulatory basis for requiring environmental monitoring and effluent monitoring at nuclear power plants is contained in General Design Criteria 60, 61, and 64 of Appendix A of Title 10 of the Code of Federal Regulations Part 50. The criteria require that a licensee control, monitor, perform radiological evaluations of all releases, document and report all radiological effluents discharged into the environment. We also have specific criteria that requires power reactor licensees to keep the public dose from radioactive effluents as low as it reasonably achievable (ALARA). The ALARA criteria is contained in Appendix I of 10 CFR Part 50. This criteria is very clear what the NRC expects of power reactors concerning their effluent discharges. The licensee shall establish an appropriate surveillance and monitoring program to:

1. Provide data on quantities of radioactive material released in liquid and gaseous effluents.

2. Provide data on measurable levels of radiation and radioactive materials in the environment to evaluate the relationship between quantities of radioactive material released in effluents and resultant radiation doses to individuals from principal pathways of exposure.

3. Identify changes in the use of unrestricted areas (e.g., for agricultural purposes) to permit modifications in monitoring programs for evaluating doses to individuals from principal pathways of exposure. Results from the environmental and effluent monitoring programs are reviewed by the NRC during routine inspections, and if the data indicate that the relationship between the quantities of effluents and the calculated doses to individuals is significantly different than that assumed in the licensing calculations, then the NRC may modify the allowable quantities in the Technical Specifications for the nuclear power plant. Prior to licensing a nuclear power plant, the NRC staff. review the applicant's proposed radiological environmental program. The applicant conducts a pre-operational program at least two years prior to initial criticality of the reactor. The pre-operational program documents the background levels of direct radiation and concentrations of radionuclides that exist in the environment. It also provides an opportunity for the licensee to train personnel, and to evaluate procedures, equipment, and techniques. A licensee's pre-operational environmental monitoring program is reviewed by NRC staff in regard to the criteria contained in the NRC's Radiological Assessment Branch Technical Position, Revision 1, November 1979, "An Acceptable Radiological Environmental Monitoring Program." The Branch Technical Position (BTP) contains an example of an acceptable minimum radiological monitoring program. Highlights of the BTP include:

monitoring of air at the offsite locations where the highest concentrations of radionuclides are expected; placement of dosimeters in two concentric rings around the plant; water samples (i.e., surface, ground, and drinking) upstream and downstream; milk samples at locations where the highest doses are expected; and various food samples. Lower limits of detection for the various types of samples and nuclides are specified. The operational radiological environmental monitoring program is essentially a continuation of the pre-operational program. The minimum requirements of the program are specified in the Radiological Effluent Technical Specifications (RETS) that are required pursuant to 10 CFR 50.36a. In addition, more detailed information about the program is contained in the licensee's Offsite Dose Calculational Manual, which is

referenced in the plant's RETS. The RETS also require that the licensee submit: (1) an annual radiological environmental monitoring report which is designed to assess the impact of radiological effluent releases into the environment; and (2) a Special Report within 30 days of discovery of the event if predetermined levels of radioactivity are exceeded. The NRC also requires that the licensee participate in an Interlaboratory Comparison Program to ensure the accuracy and precision of the licensee's data. The results of licensee's radiological environmental monitoring and effluent release programs are required to be reported annually to the NRC, and are available to the public. Radiation Dose Limits C:\\temp\\Nuclear power plants release varying amounts of tritium.wpd