LR-N11-0016, Response to NRC Request for Additional Information RAI B.2.1.28-3, Dated January 3, 2011 & Other Updates to Aging Management Program Operating Experience Information from 2010 Refueling Outage

Response to NRC Request for Additional Information RAI B.2.1.28-3, Dated January 3, 2011 & Other Updates to Aging Management Program Operating Experience Information from 2010 Refueling Outage

ML110210677
Person / Time
Site:	Hope Creek
Issue date:	01/19/2011
From:	Davison P Public Service Enterprise Group
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
LR-N11-0016
Download: ML110210677 (16)

Text

PSEG RO. Box 236, Hancocks Bridge, NJ 08038-0236 0 PSEG Nuclear LLC JAN1 2011 10 CFR 50 10 CFR 51 10 CFR 54 LR-N11-0016 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Hope Creek Generating Station Facility Operating License No. NPF-57 NRC Docket No. 50-354

References:

Response to NRC Request for Additional Information RAI B.2.1.28-3, dated January 3, 2011, and other updates to Aging Management Program Operating Experience Information from the 2010 Refueling Outage, associated with the Hope Creek Generating Station License Renewal Application

1. Letter from Ms. Bennett Brady (USNRC) to Mr. Thomas Joyce (PSEG Nuclear, LLC) "REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE HOPE CREEK GENERATING STATION LICENSE RENEWAL APPLICATION FOR DRYWELL SHELL (TAC NO ME1832)",

dated January 3, 2011

2. E-mail from Ms. Bennett Brady (USNRC) to Mr. John Hufnagel (Exelon Nuclear) "Request for an Update of Information," dated December 21, 2010 In Reference 1, the NRC requested additional information and a commitment update associated with the ASME Section XI, Subsection IWE aging management program as a result of activities and inspection findings from the Hope Creek October 2010 refueling outage (RAI B.2.1.28-3). Enclosure A contains the response to this RAI. Enclosure B contains an update to the License Renewal Commitment list associated with this RAI response.

Document Control Desk LR-N11-0016 Page 2 of 2 In Reference 2, the NRC requested that PSEG Nuclear provide an update on the results of certain 2010 refueling outage activities associated with the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements and the Flow Accelerated Corrosion programs, such that this information may be included in the final Safety Evaluation Report. Enclosures C and D provide this information for the respective programs.

With the exception of the commitment update associated with the ASME Section XI, Subsection IWE aging management program discussed above, there are no additional new or revised regulatory commitments associated with this letter.

If you have any questions, please contact Mr. Ali Fakhar, PSEG Manager - License Renewal, at 856-339-1646.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on I Vt 1(

Sincerely, Paul J. Davison Vice President, Operations Support PSEG Nuclear LLC

Enclosures:

A. Response to Request for Additional Information RAI B.2.1.28-3 B. Update to License Renewal Commitment List C. Results of 2010 Refueling Outage Activities Associated with the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program D. Results of 2010 Refueling Outage Activities Associated with the Flow Accelerated Corrosion Program cc:

William M. Dean, Regional Administrator - USNRC Region I B. Brady, Project Manager, License Renewal - USNRC R. Ennis, Project Manager - USNRC NRC Senior Resident Inspector - Hope Creek P. Mulligan, Manager IV, NJBNE L. Marabella, Corporate Commitment Tracking Coordinator P. Duca, Hope Creek Commitment Tracking Coordinator

Enclosure A LR-N11-0016 Page 1 of 10 Enclosure A Response to Request for Additional Information RAI B.2.1.28-3 related to the ASME Section XI, Subsection IWE Aging Management Program associated with the Hope Creek Generating Station License Renewal Application RAI B.2.1.28-3 Note: To facilitate understanding, portions of the original LRA or text from RAI responses have been repeated in this Enclosure, with revisions indicated. Existing text is shown in normal font. Changes are highlighted with bolded italics for inserted text and e.,*keth,*.

.*h for deleted text.

Enclosure A LR-N11-0016 Page 2 of 10 RAI B.2.1.28-3

Background:

In a conference call on June 21, 2010 the applicant stated that the drains at the bottom of the drywell have been inspected previously and no debris were found that could clog the drains. Also, in response to RAI B.2.1.28-1, the applicant stated that Hope Creek will perform one-time UT thickness measurements of the drywell shell in the area below the penetration sleeve J13 to demonstrate that significant loss of material due to corrosion has not occurred on the drywell shell and therefore, it can be concluded that water is not trapped in the two inch annular space between the drywell shell and concrete shield wall. The applicant also stated in its response to RAI B.2.1.28-1 that UT thickness measurements taken from inside the drywell in 2007 and 2009 were greater than the nominal design thickness of the drywell shell.

Issue:

During the refueling outage in October 2010, the applicant observed leakage through penetrations J13 and J14. In addition, UT thickness measurements of the drywell shell in the area below penetrations J13 and J14 indicated an area of interest with slightly lower drywell shell thickness readings. Furthermore, the applicant determined that all of the four drains at the bottom of the drywell, including the one directly below penetration J13 and J14, were blocked.

Request:

The applicant is requested to provide the following information:

1. Plans and schedule for removing the blockage of the four drains at the bottom of the drywell. If the blockage cannot be removed, provide details of alternative measures such as conducting coredrills from inside the drywell or torus room to remove water that may be trapped in the annular space between the drywell shell and concrete shield wall.

2. Revision to enhancements 9 and 10 to increase the number and frequency of UT examinations to establish a corrosion rate and projected loss of drywell thickness before the period of extended operation. The staff believes that UT examination during each IWE inspection period (every other refueling outage) may not provide enough data points to establish the corrosion rate.

3. Plans and schedule for examination and investigation to find the source of the leakage, and repair of the leak.

PSEG Response:

1. The four drywell air gap drain lines were inspected in 2009 with a boroscope and were observed to be free from blockage. During the October 2010 refueling outage, the drywell air gap drain lines were inspected with a more sophisticated boroscope, which revealed that while the drain lines themselves were open, the smooth surfaces observed at the end of each of the four drain lines were apparently covers instead of the drywell shell. These covers prevented boroscope access into the air gap from the drain lines.

Enclosure A LR-N11-0016 Page 3 of 10 The covers may limit or prevent proper drainage of the drywell air gap. This unexpected configuration of the air gap drains has been entered into the corrective action program, with actions to restore drain line functionality planned for the current operating cycle.

Possible actions include removing the covers, or removing sufficient material from the covers such that water would drain from the drywell air gap.

The current plan is to initially investigate one of the drain line openings, in either the 1800 or 2700 azimuth drain line, in the first half of 2011 to better understand the configuration such that the four drain line openings can be properly cleared. The conditions at the bottom of the drywell air gap will also be evaluated. Containment penetrations J13 and J14 are within the 2100 to 2400 azimuths. To provide access for inspection, the drain line piping will be disassembled from the torus room side. The information obtained from the investigation and clearing of the first drain line opening will be used to plan and implement the restoration of the remaining three drain line openings. This plan will restore the functionality of the four air gap drains prior to flood-up of the reactor cavity during the next refueling outage in Spring 2012.

Visual inspections using a boroscope inserted through penetration sleeves at J13, J14, J19, J24 and J37 during the October 2010 refueling outage confirmed that there are no obstructions in the drywell air gap or around the penetrations that could retain water against the drywell shell. These five penetration sleeves are in the J13 penetration sleeve area. In addition these inspections observed no signs of accumulated water at the bottom of the air gap. Since there is confidence that the drains can be cleared, there are currently no plans to perform alternate measures such as coredrills. The inspected surfaces of the drywell shell and penetrations appeared in good condition.

As part of the response to this RAI, it was determined that the text in LRA Section 3.5.2.2.1.4, Loss of Material due to General, Pitting and Crevice Corrosion on Page 3.5-23 should be revised to reflect the additional information obtained during the October 2010 refueling outage. Therefore, LRA Section 3.5.2.2.1.4 is revised as shown below.

Original LRA text is shown in normal font, additions are shown in bold italics and deletions are shown with strikethroughs.

However, during the 2009 refueling outage, water was found trickling out of a Reactor Building concrete wall penetration sleeve from the drywell air gap region at Azimuth 225°, and pondcd on the torus room floor. Analysis of the water identified it as

,easto'wa*te.'refueling water. A review of past UT readings taken in 2007on the upper region, taken in 2007, of the drywell shell indicates no loss of material in the areas of reported water leakage indicatoc Rn lecs of matorial of the dry-Well shel!.

The water leakage stopped after the refueling cavity was drained at the end of the refueling outage. The suspected source of the water was at the reactor cavity seal plate area thc rofful bollow oFr incr. The air gap drain lines were inspected in 2009, there was no blockage in the drain piping. In the October 2010 refueling outage, water was found trickling out of the same penetration sleeve as in the 2009 refueling outage as well as an adjacent penetration sleeve. Analysis of the water again identified it as refueling water. Inspections performed in the October 2010 refueling outage using more sophisticated equipment identified the unexpected configuration of covers over the entrance to the drywell air gap drain lines. The smooth surfaces observed in 2009 at the end of the drain lines

Enclosure A LR-N11-0016 Page 4 of 10 were apparently covers instead of the drywell shell Additional inspections performed in the October 2010 refueling outage found no of standing water in the air gap region and the drywell shell showed no signs of corrosion.

The water leakage issue was entered into the corrective action process to determine cause of the leakage and corrective actions to prevent reoccurrence. The unexpected configuration of covers over the entrance to the drywell air gap drain lines was also entered into the corrective action process to evaluate and implement corrective actions to restore the functionality of the drain lines.

Augmented UT thickness measurements were taken during the October 2010 refueling outage to determine if leakage from the reactor cavity has resulted in external corrosion of the drywell shell. Thickness measurements were all above nominal plate thickness except the 1.500 inch thick plate under the J13 penetration area. This plate had UT readings below nominal plate thickness, but the average readings were above the plate minimum allowable manufacturing tolerance. These readings have been established as an area of interest for augmented inspections and will be re-examined in future outages.

Also on LRA page 3.5-24 the summary is revised as follows:

In summary, loss of material due to corrosion is insignificant for the Hope Creek drywell shell. Visual examinations conducted in accordance with ASME Section XI, Subsection IWE have not identified corrosion that reduces the shell thickness in accessible areas of the drywell. UT thickness measurements of the shell, at locations that have been identified in the industry as susceptible to corrosion, show that the measured thicknesses are greater than the nominal thicknesses except for one area. In this area of interest, the thickness is below nominal thickness but above the plate minimum allowable manufacturing tolerance. Also the conditions that can lead to significant loss of material in inaccessible areas of the drywell shell are not applicable to Hope Creek Mark I containment. That is, the containment has no "sand-pocket region". Potential leakage of water from the outer bellows area during refueling is removed by the reactor cavity seal rupture drain lines that are monitored by instrumentation designed to alarm in the Main Control Room in the event of leakage. A review of the alarm log for the past refueling outage showed no recorded initiation of the alarms during the refueling outage. There are also drains at the bottom of the air gap region at the junction of where the shell becomes embedded in concrete. In 2009, these drains were inspected; there was no blockage in the drain piping. of.tand.ing wator in the air ga Ic,.

and the dr.well shell sho'wd no signs of corrosioR. Inspections performed in 2010 with more sophisticated equipment identified the unexpected configuration of covers over the entrance to the drywell air gap drain lines. Additional inspections in 2010 found no standing water in the air gap region and the drywell shell showed no signs of corrosion. Also in 2010, the ASME Section XI, Subsection IWE program implemented augmented inspections for the area of interest where the measured thicknesses are below nominal thickness, that will be re-examined in future outages to ensure that drywell shell integrity is maintained through the period of extended operation. Additional detail regarding these

Enclosure A LR-N11-0016 Page 5 of 10 aging management activities may be found in Section B.2.1.28 of LRA Appendix B.

2.

UT thickness measurements were taken during the October 2010 refueling outage on the plate between the J13 penetration sleeve area and the drywell floor at Azimuth 2250.

A total of 79 measurements were taken, with between 7 and 9 measurements taken on ten different horizontal rows, with approximately one foot between each measurement location. The shell plate in this area is 1.500 inch nominal plate thickness. The average value for the thickness measurements on this plate was below the nominal plate thickness, but was above the plate minimum allowable manufacturing tolerance thickness of 1.490 inches. The individual and average thickness measurements on this plate were all above the plate thickness used in the design analysis (1.4375 inches).

The observed lower thickness readings on this plate may be due to manufacturing tolerance and not minor corrosion. However, since this plate is located in the area where the reactor cavity leakage has been identified, and UT thickness measurements indicate plate thickness below nominal at some locations, this area has been established as an area of interest for augmented inspections, and will be re-examined in future outages.

As a result of identifying an area of interest below the J13 penetration area during the October 2010 refueling outage, PSEG plans to repeat the UT thickness examinations at the 79 UT locations described above, for each of the next three refueling outages. This is in order to provide sufficient data over time to determine whether there is ongoing corrosion. If corrosion is ongoing, a corrosion rate will then be determined from these readings. If a significant corrosion rate is identified, such that the drywell shell thickness could approach the minimum design thickness prior to the end of the period of extended operation, the condition will be entered in the corrective action process for engineering evaluation and extent of condition determination. Enhancement 9 of the ASME Section XI, Subsection IWE program is being revised to incorporate these planned inspections into the IWE program commitment 28, as shown in Enclosure B. If it is determined that the corrosion rate is not significant and will not impact the drywell shell intended functions through the period of extended operation, then the number and frequency of additional UT thickness measurements in this area will be in accordance with ASME Section XI, Subsection IWE requirements. It should be noted that additional UT thickness measurements may be required in this area, based on Enhancement 10 of the ASME Section XI, Subsection IWE program.

Enhancement 9 of LRA Appendix A, Section A.2.1.28 (the UFSAR Supplement) and Appendix B, Section B.2.1.28 (the ASME Section XI, Subsection IWE Program) is also updated, as shown below. Existing text is shown in normal font, additions are shown in bold italics and deletions are shown with strikethroughs. Note that PSEG letter LR-N10-0190 added Enhancement 9 to the program, in response to Hope Creek RAI B.2.1.28-01.

9. Perform e e-time UT thickness measurements from inside the drywell in the aGGessible area of the drywell shell diFeetly below the J13 penetration sleeve area J1-3 to determine if there is a significant corrosion rate occurring in this area due to periodic exposure to reactor cavity leakage. Inspection and acceptance criteria will be in accordance with IWE-2000 and IWE-3000 respectively. UT

Enclosure A LR-N11-0016 Page 6 of 10 thickness measurements will be taken each of the next three refueling outages at the same locations as those examined in 2010. These UT thickness measurements will be compared to the results of the initial UT inspections performed during the October 2010 refueling outage and, if corrosion is ongoing, a corrosion rate will be determined for the drywell shell. In the event a significant corrosion rate is detected, the condition will be entered in the corrective action process for evaluation and extent of condition determination.

The specified UT thickness measurements to be taken over the next 3 refueling outages, in combination with the readings taken in the October 2010 refueling outage, will determine the actual corrosion rate of the drywell external surface in the area below penetration J13, which has been established as the only area of interest for potential drywell shell corrosion due to periodic exposure to reactor cavity leakage. The identified corrosion rate will be part of the basis for ongoing monitoring activities, including UT thickness measurements. Ongoing monitoring activities will be established at an appropriate frequency and in a sufficient number of locations to assure that the intended functions of the drywell are maintained consistent with the CLB for the period of extended operation. If the reactor cavity leakage cannot be repaired prior to entering the period of extended operation, then the monitoring activities and evaluations of the Final Interim Staff Guidance LR-ISG-2006-01 will be implemented in accordance with Enhancement 10. There is no need to revise Enhancement 10 to include UT thickness measurements each refueling outage because the drywell shell corrosion rate will be established following implementation of the revised Enhancement 9, and ongoing monitoring requirements will be established based on the identified corrosion rate well before entering the period of extended operation.

Also as part of the response to this RAI, the Operating Experience portion of LRA Appendix B, Section B.2.1.28 (ASME Section XI, Subsection IWE), on page B-1 32 is revised to include additional information obtained during the October 2010 refueling outage. A new operating experience item (#4) is added, shown below in bold italics.

4. During the 2009 refueling outage, a small water leak was found trickling out of Reactor Building concrete wall penetration sleeve J13 from the drywell air gap region at Azimuth 2250. Analysis of the water identified it as refueling water.

In the October 2010 refueling outage, water was found trickling out of the same penetration sleeve as in the 2009 refueling outage as well as an adjacent penetration sleeve. Analysis of the water again identified it as refueling water.

Approximately 350 UT thickness measurements were taken during the October 2010 refueling outage to determine if leakage from the reactor cavity has resulted in external corrosion of the drywell shell. Thickness measurements were all above nominal plate thickness except the 1.500 inch thick plate under the J13 penetration sleeve area. This plate had UT readings below nominal plate thickness, but the average readings were above the plate minimum allowable manufacturing tolerance (1.490 inches). This region of the drywell shell has been established as an area of interest for augmented inspections and will be re-examined in future outages.

The water leakage stopped after the refueling cavity was drained at the end of the refueling outage. The suspected source of the water was at the reactor

Enclosure A LR-N11-0016 Page 7 of 10 cavity seal plate area. Visual inspections using a boroscope inserted through penetration sleeves confirmed that there are no obstructions in the drywell air gap or around the penetrations that could retain water against the drywell shell. In addition these inspections observed no sign of accumulated water at the bottom of the air gap. The inspected surfaces of the drywell shell and penetrations appeared in good condition. The air gap drain lines were inspected in 2009 and observed to be open. However, during the drain line inspection in the October 2010 refueling outage performed using more sophisticated equipment, it was discovered that the entrance to the drain lines were covered from inside the air gap, potentially limiting or preventing proper drainage of the air gap region. The water leakage issue and potentially blocked air gap drains were entered into the corrective action process to determine corrective actions and resolve the condition.

This example provides objective evidence that the Corrective Action and ASME Section XI, Subsection IWE Programs are documenting, evaluating, and correcting conditions adverse to quality. The implementation of effective corrective actions resulted in enhancements to the ASME Section XI, Subsection IWE aging management program for detecting potential aging of the drywell shell.

3. Hope Creek has initiated numerous activities-to investigate the source of water leakage observed at the J13 penetration sleeve area. The activities are grouped chronologically, with activities planned prior to the October 2010 refueling outage listed first, followed by the activities performed during the October 2010 refueling outage and the activities planned prior to or during the upcoming Spring 2012 refueling outage. The activity descriptions include the current status for each of the planned or completed actions.

Some of these planned activities for leak investigation at the J13 penetration sleeve area were previously described in the Hope Creek response to RAI B.2.1.28-01 (PSEG letter LR-N10-0190) and are repeated here for completeness.

Activities planned prior to the October 2010 refueling outage Confirm the reactor cavity seal rupture drain lines are clear and the monitoring instrumentation is functioning properly (prior to cavity flood-up).

The reactor cavity seal rupture drain line inspection activities required a plant modification. The plant modification and subsequent inspection were delayed due to parts availability associated with the addition of a safety related valve and were rescheduled to after the October 2010 refueling outage. The plant modification was completed in December 2010. The inspection is scheduled to be performed during the current operating cycle prior to the Spring 2012 refueling outage.

Activities during the October 2010 Refueling Outaqe Monitor the penetration sleeve J13 area periodically for water leakage when the reactor cavity is flooded.

Enclosure A LR-N 11-0016 Page 8 of 10 The J13 penetration sleeve area was inspected daily for water leakage while the reactor cavity was flooded up. Water was observed leaking from the J13 and J14 penetration sleeves following reactor cavity flood up. The J14 penetration sleeve is horizontally adjacent to the J 13 penetration sleeve with centerlines offset by approximately 21 inches. The combined leak rate coming out of the sleeves was variable and ranged from approximately 4 to 106 drops per minute. Also, visual inspections using a boroscope revealed wetting of the inside surface of the concrete shield wall below the penetrations toward the bottom of the air gap. This wetting indicates leakage past the penetrations that could not be directly measured. However, a boroscope inspection of the bottom of the air gap below the penetration area after the leakage stopped showed no water pooling. Therefore, evaporation is preventing any long term wetting of the drywell shell at the bottom of the air gap. Based on these observations, the rate of water leakage past the penetrations is estimated to be comparable to that observed coming from the penetration sleeves.

Monitor the drywell air gap drain lines and the reactor cavity seal rupture drain lines periodically for water leakage when the reactor cavity is flooded up.

The drywell air gap drain lines were monitored daily for water leakage when the reactor cavity was flooded up. Monitoring continued after the drain line covers were discovered. No water was observed coming from the drywell air gap drain lines. Water leakage was only found pooling below the J13 penetration sleeve area at the bottom of the drywell shield wall in the torus room during the October 2010 refueling outage. The pooling was only present for a portion of the outage. See the response to item 1 above, for the condition of and corrective action plans associated with the air gap drain lines.

Obtain water leakage data, such as start of leakage, flow rate, and volume during the period when the reactor cavity contains water. Similarly, document reactor cavity water level at which the leakage stops during the drain down of the reactor cavity.

A sample of the leakage water was tested and was found to be consistent with refueling water chemistry. The leakage was observed at the J13 penetration sleeve area after the reactor cavity was completely filled with water. It is believed that the leakage is from a small defect in the seal plate area and a significant head of water above the defect is required for the leak to occur. The leak was initially observed at the J14 penetration sleeve. A few days later, water was observed at the J13 penetration sleeve as well as the J14 penetration sleeve. Later in the outage, water was observed only at the J13 penetration sleeve. No water has been observed at other penetration sleeves. The combined leak rate coming from the J13 and J14 penetration sleeves varied from approximately 4 to 106 drops per minute. The leakage stopped after the reactor cavity was drained.

Investigate whether the drywell to reactor cavity bellows assembly can be examined to locate a small leak.

Enclosure A LR-N 11-0016 Page 9 of 10 Visual inspection of the reactor cavity seal plate area was performed prior to reactor cavity floodup and after reactor cavity draindown. It was confirmed that NDE testing in this area would be difficult due to access limitations and dose concerns. The post-draindown inspection was recorded on video to assist in planning future inspections. The video will be reviewed to determine if NDE testing of this area is possible during the Spring 2012 refueling outage.

Perform visual inspection of the reactor cavity seal plates for signs of leakage.

Visual inspections of the reactor cavity seal plate area were performed in an attempt to identify the source of the water leakage. No evidence of a leak was observed. Similarly, the reactor cavity liner was visually inspected in an attempt to identify the source of the water leakage. No evidence of a leak was observed.

Boroscope the drywell air gap below penetration sleeve J13 for conditions that would prevent water leakage from reaching the drywell air gap drains.

The drywell shell, penetrations, and drywell air gap were inspected by a boroscope inserted through penetration sleeves J13 -J14, J19, J24 and J37 when the reactor cavity was flooded up. These five penetration sleeves are in the J13 penetration sleeve area. The drywell shell and penetrations visible from the boroscope examinations are in good condition and there are no obstructions in the drywell air gap or around the penetrations that could retain water against the drywell shell. In addition there was no observed water at the bottom of the drywell air gap below the J13 penetration sleeve area when examined following draining of the reactor cavity.

An engineering evaluation was completed and concluded that the water leakage and the drywell air gap drain blockage had no impact on the drywell design function. This evaluation supported operation through the Spring 2012 refueling outage. A new engineering evaluation will be required at this time to address the post-outage conditions.

Activities planned prior to or during the upcoming Spring 2012 refueling outage Confirm the reactor cavity seal rupture drain lines are clear and the monitoring instrumentation is functioning properly (prior to cavity flood-up).

Restore the functionality of the drywell air gap drains. See response to item 1 above for details.

Monitor the J13 penetration sleeve area daily for water leakage when the reactor cavity is flooded up.

Enclosure A LR-N11-0016 Page 10 of 10 Monitor the drywell air gap drain lines daily for water leakage when the reactor cavity is flooded up.

Boroscope the drywell air gap below the J13 penetration sleeve area for conditions of the drywell shell at the bottom of the air gap.

Perform ultrasonic thickness measurements of the drywell shell below the J13 penetration area and evaluate the results. See item 2 response above.

These planned activities for leak investigation at the J 13 penetration sleeve area are in accordance with the ASME Section Xl, Subsection IWE program enhancements referenced in the Hope Creek response to RAI B.2.1.28-01 (PSEG letter LR-N10-0190).

The source of leakage is postulated to be from a small crack or cracks in either the welds of the reactor cavity seal plates or the reactor cavity drain lines. Activities are planned to locate and repair the cracks, if practical. These areas in the reactor cavity are generally inaccessible and are high radiation areas. For inaccessible areas where visual inspections cannot be performed, other leak detection methods such as dye tracing will be investigated to assist in accurately locating the leakage in the reactor cavity seal plate area. Locating and repairing small cracks under these conditions will be challenging and may span over several refueling outages.

In summary, Hope Creek will continue to investigate the cause of reactor cavity water leakage and make repairs, if practical, to stop the leaks. If this cannot be achieved prior to the PEO, applicable aging management activities recommended in the Final Interim Staff Guidance LR-ISG-2006-01 and included as ASME Section XI, Subsection IWE program enhancements will be implemented to ensure loss of material in inaccessible areas of the drywell shell is effectively managed.

Enclosure B LR-N1 1-0016 Page 1 of 1 Enclosure B The following table identifies revisions made to license renewal commitment 28 as a result of this RAI. Pre-existing text, from the LRA or previous RAI packages, is formatted in normal font; new text is bold and italicized; deleted text is indicated with strikethroughs. Pre-existing text has been repeated here to provide context for the changes. Any other actions described in this submittal represent intended or planned actions. The intended or planned actions are described for the information of the NRC and are not regulatory commitments.

A.5 License Renewal Commitment List UFSAR NO.

PROGRAM COMMITMENT SUPPLEMENT ENHANCEMENT OR SOURCE OR TOPIC LOCATION IMPLEMENTATION (LRA APP. A)

SCHEDULE 28 ASME Section ASME Section Xl, Subsection IWE is an existing program that A.2.1.28 Program to be enhanced Section B.2.1.28 Xl, Subsection will be enhanced to include:

prior to the period of IWE extended operation.

9. Perform nen-time UT thickness measurements from Hope Creek letter inside the drywell in the aGGeesible area of the drywell Inspection schedule LR-N10-0190 shell di&9at4y below the J13 penetration sleeve area identified in commitment.

Hope Creek Letter J43 to determine if there is a significant corrosion LR-N10-0291 rate occurring in this area due to periodic RAI B.2.1.28-01 exposure to reactor cavity leakage. Inspection and acceptance criteria will be in accordance with IWE-Hope Creek letter 2000 and IWE-3000 respectively. UT thickness LR-Nll-0016 measurements will be taken each of the next three refueling outages at the same locations as those RAI B.2.1.28-3 examined in 2010. These UT thickness measurements will be compared to the results of the initial UT inspections performed during the October 2010 refueling outage and, if corrosion is ongoing, a corrosion rate will be determined for the drywell shell. In the event a significant corrosion rate is detected, the condition will be entered in the corrective action process for evaluation and extent of condition determination.

Enclosure C LR-N11-0016 Page 1 of 1 Enclosure C Results of 2010 Refueling Outage Activities Associated with the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Aging Management Program Introduction This Enclosure provides information requested in Reference 2 of this letter. Specifically, this Enclosure contains an update to the information provided in the Hope Creek Generating Station License Renewal Application (LRA) and subsequent correspondence related to the Hope Creek Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (E3) aging management program. This update is being provided to update the status of certain activities that were described in the Safety Evaluation Report with Open Items Related to the Hope Creek Generating Station.

Current Licensing Period Activities Hope Creek performed cable testing on some of the in-scope SBO recovery cables during the scheduled transformer outage in October 2010.

Baseline testing of the "B" channel of the SBO recovery 13kV cables (6 cables) was conducted using the tan delta method. The test results were evaluated to be acceptable. Testing on the "A" channel is scheduled for 2012, and follow-up testing on the "B" channel is scheduled in 2013.

Other 13kv cables (not in-scope for license renewal) were tested (9 cables) as part of the Hope Creek Cable Monitoring Program. The testing revealed a splice problem in a cable not in-scope for license renewal. The splice was replaced. The splice defect was from original construction, thus not age-related. This splice was not exposed to significant moisture.

Hope Creek performed an inspection of cable pit BX501 in October 2010. Some cables in the cable pit were found submerged. This condition was evaluated in the corrective action process.

The cable pit was dewatered. In addition, the switchyard cable manhole drainage system pump was repaired. No cable defects were observed for any cable in the cable pit. No concrete or cable support related issues or conditions adverse to quality were observed in the cable pit.

The results of this inspection, dewatering, and repair activity are being monitored so that further corrective actions can be planned, if necessary, to ensure that the in-scope SBO recovery cables are not exposed to significant moisture.

Enclosure D LR-N11-0016 Page 1 of 2 Enclosure D Results of 2010 Refueling Outage Activities Associated with the Flow Accelerated Corrosion Aging Management Program This Enclosure provides information requested in Reference 2 of this letter. Specifically, for the Flow-Accelerated Corrosion program, PSEG provides the following information to update the status of certain activities that were described in the Hope Creek Safety Evaluation with Open Items Related to the Hope Creek Generating Station.

The LRA Appendix B, Section B.2.1.11 Flow-Accelerated Corrosion program, operating experience section on pages B-62 and B-63 is being updated to reflect activities completed in the 2010 refueling outage as follows: (Note: Added text is shown in bold italics and deletions are shown with strikethrough text.)

2. As result of feedwater heater shell failures at other nuclear plants (OE-9941), as well as Salem Unit 1 plant experience with feedwater heaters (OE1 1020),

feedwater heater shell inspections were instituted at Hope Creek. In 2000, the

1. 5A, B & C feedwater heater shell area was replaced in the vicinity of the extraction steam inlet nozzles. A shell area was cut out of the heaters,-and was replaced with carbon steel plate roll-bonded with 0.125" stainless steel cladding on the inside diameter. The extraction steam inlet nozzle was also replaced with the same configuration. All feedwater heaters (except the #1 heaters) have been inspected at least once. The shell area around two of the four #1C feedwater heater extraction steam inlet nozzles were inspected in 2007, and no problem was identified. InspoctionR of the.. maining two extra.;ctio steam inlet nozzles for the

1. 1 C, and all the #!iA and-41 BR foodwator heaters extractfion 6toarn inlot nozzles are plane4d feF20! 0. Feedwater heater shell area adjacent to the remaining two extraction steam inlet nozzles for the #1C, and all the #1A and #1B feedwater heaters extraction steam inlet nozzles were inspected in 2010, and no problems were identified.

As a part of the feedwater heater shell FAC inspection program, stress evaluations are performed to obtain the allowable minimum wall thickness. This minimum allowable thickness is the basis for trending wall thinning and tracking when the next inspection is scheduled. The scope of the feedwater heater shell inspection project is to inspect every feedwater heater shell at least once in the vicinity of the extraction steam inlet nozzle. Wear rates are determined and wall thinning on the feedwater heaters are trended, and analyses are performed to determine appropriate inspections, which are scheduled prior to the shell reaching its minimum allowable wall thickness.

This example provides objective evidence that the FAC aging management program effectively monitors and trends the aging effects of FAC on piping and components. In addition this program takes corrective actions prior to loss of intended function, and the program uses industry operating experience to improve program implementation.

Enclosure D LR-N11-0016 Page 2.of 2

3. In 2004, the Hope Creek FAC program prompted a wall thickness inspection of feedwater heater nozzles in response to OE17919, "Inspection Identifies Holes in #2 Heater Extraction at LaSalle Unit 1 ". Based on ultrasonic testing (UT) and visual inspection, significant wall thinning downstream of the piping/nozzle weld for the #2A feedwater heater nozzles was discovered. Extent of condition evaluation determined that #2B and #2C feedwater heaters had experienced the same kind of wall thinning.

During internal weld repairs in April 2006, it was discovered that the nozzle had a stainless steel liner, which started at about 1/4" downstream of the pipe/ nozzle weld, rather than being fully extended. The wall thinning was found to be caused by steam cutting of the nozzle between the inner liner and the outer diameter, indicating the degradation to the nozzle would have been less severe had the liner been fully extended to the top of the nozzle. So far eleven out of the twelve nozzles for the #2 feedwater heaters (FWHs) have been repaired by internal weld build-up. A re evaluat.ion of the twelf" h nozzle's wall thic kne6G concluded that reaiF oe not required until RF1 6 outage (October 201 0). Replacem:ent of all three A,2 IHrS is planned forF RF=4 6

'utage. All three feedwater heaters were successfully replaced in RF 16 outage (October 2010). The new FWHs wil have extraction steam inlet nozzles fabricated with alloy steel, which is resistant to FAC. To correct the root cause of this problem, the Hope Creek FAC Program will continue to monitor FAC-susceptible feedwater heater nozzles and make repairs or replacements as warranted.

This example provides objective evidence that the FAC aging management program uses industry operating experience to investigate FAC related concerns and the program takes corrective actions prior to loss of intended function.