Text

Official Exhibit - ENT000619-00-BD01 - NL-08-127, Letter from F. Dacimo, Entergy, to NRC DCD, Additional Information Regarding License Renewal Application; Structural OE Clarifications, Clarifications for Electrical RAIs and Audit Questions
	ML15334A229
Person / Time
Site:	Indian Point
Issue date:	08/14/2008
From:	; Entergy Nuclear Operations
To:	; Atomic Safety and Licensing Board Panel
	SECY RAS
References
	RAS 28133, ASLBP 07-858-03-LR-BD01, 50-247-LR, 50-286-LR
	Download: ML15334A229 (31)
	v • d • e

United States Nuclear Regulatory Commission Official Hearing Exhibit In the Matter of: Entergy Nuclear Operations, Inc. ENT000619 (Indian Point Nuclear Generating Units 2 and 3)

ASLBP #: 07-858-03-LR-BD01 Submitted: August 10, 2015 Docket #: 05000247 l 05000286 Exhibit #: ENT000619-00-BD01 Identified: 11/5/2015 Admitted: 11/5/2015 Withdrawn:

Rejected: Stricken:

Other:

Entergy Nuclear Northeast Indian Point Eriergy Center 450 Broadway GSB P 0 Box 249 Brichanan NY 10511-0249 Tei (914) 788-2055 Fred R. Dacimo Vice President License Renewal August 14 2008 lndtan Point Un~ts2 & 3 Docket Nos 50-247 & 50-286 NL-08-127 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 SUBJECT Additional Information Regarding License Renewal Application -

Structural OE Clarifications, Clarifications for Electrical RAls and Audit Questions, License Renewal Ap~licationAmendment

Dear Sir or Madam:

Entergy Nuclear Operations, lnc is providing, in Attachments 1, 2, 3, and 4, additional information on structural OE clarifications, clarifications for electrical RAis and audit questions, Indian Point Energy Center (IPEC) License Renewal Application (LRA) Amendment, and revision 5 of the IPEC commitment list, pertaining to the License Renewal Application for lndian Point 2 and Indian Point 3. The additional information provided in this transmittal provides clarifications and additional information to previously submitted information in response to staff and audit questions.

There are no new commitments identified in this submittal. If you have any questions or require additional information, please contact Mr. R. Walpole, Manager, Licensing at (914) 734-6710.

I declare under penalty of perjury that the foregoing 1s true and correct Executed on /?/*a Fred R. Dacimo Vice President License Renewal

NL-08-127 Docket Nos. 50-247 & 50-286 Page 2 of 2 I , Operating Experience-Structures

2. Clarifications for Electrical RAls and Audit Questions 3, IPEC License Renewal Application Amendment

4. IPEC Commitment List Revision 5 cc: Mr. Bo M. Pham, NRC Environmental Project Manager Ms. Kimberly Green, NRC Safety Project Manager Mr. John P. Boska, NRC NRR Senior Project Manager Mr. Samuel J. Collins, Regional Administrator, NRC Region I Mr. Sherwin E. Turk, NRC Office of General Counsel, Special Counsel IPEC NRC Senior Resident Inspectors Office Mr. Paul D. Tonko, President, NYSERDA Mr. Paui Eddy, New York State Dept. of Public Service

ATTACHMENT 1 TO NL-08-127

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OPERATING EXPERIENCE STRUCTURES REGARDING LICENSE RENEWAL APPLICATION ENTERGY NUCLEAR OPERATIONS, INC

!NDiAI\! POINT NUCLEAR GENERATING UNIT NOS. 2 and 3 DOCKETS 50-247 and 50-286

fNDlAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL APPLICATION

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OPERATING EXPERIENCE STRUCTURES The following additional information is provided in response to the IPEC audit questions listed below.

Audit Question 27 IP2 Containment Steel Liner Behind Insulation Entergy addressed inspection of the containment steel liners in Audit Question 27. In summary it explained that in1973, a feedwater line leak heated a portion of the 1P2 containment liner causing localized deformation due to thermal expansion. The affected area was subsequently covered with thermal insulation. In response to Audit Question 27, Entergy indicated that it does not remove insulation to inspect the steel liner in this area, on the basis that the liner behind the insulation is considered inaccessible in accordance with ASME code Section XI-IWE.

In order to provide assurance that liner degradation is not occurring in this area, Entergy will remove insulation and perform a one-time inspection of a representative sample area of the IP2 containment liner affected by the 1973 event prior to entering the period of extended operation.

In April of 2000, during the first IPEC inspection required under the Containment Inservice Inspection (CII - IWE) Program, minor surface rust was noted on the IP2 containment liner. The condition existed on the liner at the juncture with the containment concrete floor slab. The cause was exposure to moisture as result of a service water line leak in 1980. The April 2000 inspections found several areas where the moisture barrier between the containment liner and the concrete floor slab was missing or not properly bonded.

In order to determine the extent of the IP2 condition, ten (10) insulation panels were removed to provide access to facilitate augmented inspection. With the insulation removed, light rust was noted. Thickness measurements showed no significant wall loss. Three subsequent inspections and thickness measurements of the containment liner in the same locations, the latest near the beginning of 2006, indicate that the area has remained dry, the corrosion is inactive, and the liner plate thickness is greater than the required thickness, As a result, the IP2 liner remains capable of performing its intended design function.

As shown in LRA Table 3.5.2-1, the moisture barrier at the juncture between the containment liner and the containment floor will continue to be inspected on both IP2 and IP3 in accordance with the requirements of ASME code section XI-IWE throughout the period of extended operation. The containment liner will continue to be inspected in accordance with the requirements of ASME code section XI-IWE, and tested in accordance with the requirements of IOCFR50, appendix J (Containment Leak Rate Test) to ensure the containment liner maintains its intended function during the period of extended operation.

However, in order to provide further assurance that liner degradation is not occurring in the same area on IP3, Entergy will perform a one-time inspection of sample iocations of the lP3 containment !her at the juncture with the concrete fioor slab, prior to entering the period of extended operation.

Audit Question 358 Water Control Structures Entergy addressed degradation of water control structures in response to Audit Question 358.

Specifically, Entergy explained that conditions of surface degradation of concrete in the water control structure had been identified during the first inspection under the IPEC Structures Monitoring Program in 1996. The evaluation performed under the corrective action program using ACI 201 acceptance criteria, determined that the identified surface degradation did not represent a structural concern that would prevent the water control structure from performing its intended function. Since then, re-inspection of the water control structure every five (5) years as part of the Structures Monitoring Program has confirmed that, despite the identified degradation, the water control structure remains capable of performing its license renewal intended function.

As indicated in LRA Table 3.5.2-2, under the Structures Monitoring Program Entergy will continue to monitor the structure in accordance with the requirements of 10CFR50.65 to ensure the structure maintains its intended function during the period of extended operation (PEO).

While the existing Structures Monitoring Program has demonstrated its effectiveness in assuring the water control structure remains capable of performing its intended function, the inspection of these degraded areas during the period of extended operation will be performed once per 3 years rather than the normal frequency of once per 5 years. This increased inspection frequency provides additional assurance that the effects of aging will be managed such that the water control structure maintains its ability to perform its intended function during the period of extended operation.

Audit Question 359 IP2 Reactor Cavity Entergy addressed plant-specific degradation of the 1P2 reactor refueling cavity in response to Audit Question 359. Entergy has observed leakage of the IP2 refueling cavity liner when flooded during refueling outages when the reactor is shut down (i.e., an average of less than 2 weeks each refueling cycle). This leakage is wholly contained within the containment.

Personnel have thoroughly evaluated the condition.

Evaluation of the condition considered immediate impacts of the leakage, as well as long term effects on potentially impacted structures within containment including the refueling cavity structure. Immediate impacts on refueling operations are small as the leakage is readily replaced with periodic makeup from the refueling water storage tank. The ieakage is entirely contained within and is collected in the lower elevation of the containment building from where it is pumped to the radioactive liquid waste processing system. As such, the leakage does not impact structures other than the refueling cavity. The impact of the leakage on the refueling cavity structure is discussed in the following paragraphs, Several studies have been performed to address the impacts of chemical attack on reinforced concrete. In 1966, Kuenning in a paper titled "Resistance of Portland Cement Mixtures and Chemical Attacks," reported that liquids with a pH of 5.3 and above will not cause a chemical attack on concrete. Kuenning also showed that borates will not adversely affect concrete.

Considering that the pH of the refueling cavity fluid is approximately 4.7, the chemical attack on concrete is minimat. Florida Power and Light (FP&L) reported in Test Report P522-1472, "Test Report Long Term Evaluation of Concrete Reinforcement Steel," that there are negligible effects on concrete from borated water with boron concentrations of around 2300 ppm when tested for a period of approximately eight years.

The impact of refueling cavity liner leakage also has been the subject of other evaluations at iP2. Results of core bore samples taken in 1993 and reported in Technical Report No. 8327, "Evaluation of Reactor Refueling Cavity Wall - lndian Point 2 Nuclear Power Plant," indicate a depth of penetration of borated water into the concrete of W or less. As concrete cover over reinforcing steel is in the 1 . 5 to 2 range, borated water penetration into the concrete is less than that required to expose the reinforcing steel to its effects, except at localized discontinuities such as, shrinkage cracks and construction joints that allow a path into the concrete.

In addition, in 1993, a report titled "Technical Report 8281 - Evaluation of Spent Fuel Pool Walls Indian Point 2 Nuclear Power Plant" discussed the evaluation of core samples from the east wall of the spent fuel pool storage pit taken to assess the effect of a 2 year leak on the concrete and reinforcing steel. The report documented concrete testing that showed the concrete had compressive strengths equal to or exceeding the design requirements. The conclusion of the report was that the borated water had minimal effect on the concrete and reinforcing steel.

Since the concrete used to construct ?he spent fuel pit walls met the same specification as the concrete used in the refueling cavity walls, this result applies to the refueling cavity walls.

The refueling cavity is a robust structure, with minimum wall thickness in the 4' range. The stress leveis in the concrete and reinforcement are low compared against capacities.

Considering that the borated water leakage is limited to the short duration when the cavity is iiiled during reiueiing outages, the overali exposure of the concrete to borated water is significantly shorter than that in the tests and studies discussed above; i.e., weeks versus years.

Based on the tests and evaluations, as well as the industry and IPEC experience discussed above, ongoing monitoring under the Structures Monitoring Program will manage the effects of aging such that the refueling cavity reinforced concrete structure remains capable of pefforming its intended function throughout the period of extended operation. There is no uncertainty about the ability of the ongoing structures monitoring program to ensure that potentially affected structures remain capable of performing license renewal intended functions throughout the period of extended operation. The Structures Monitoring Program credited for managing the effects of aging on the refueling cavity structure will provide reasonable assurance that the intended function will be maintained even if this condition is not corrected prior to entering the period of extended operation.

Notwithstanding the above, Entergy plans further efforts to preclude future leakage and eliminate the associated housekeeping concerns associated with fluid leakage in containment.

Because there is no structural concern due to the leakage, the repair efforts will be prioritized along with other initiatives according to importance to overall plant safety and availability of necessary site resources.

However, to provide additional assurance that the underlying concrete remains capable of performing its license renewal intended function throughout the period of extended operation, Entergy will perform a one-time inspection and evaluation of a sample of potentially affected refueling cavity concrete prior to the period of extended operation. The sample will be obtained by core boring the refueling cavity wail in an area that is susceptible to exposure to the borated water leakage. The inspection will include an assessment of embedded reinforcing steel.

Audit Question 360 IP2 Soent Fuel Pool Entergy addressed plant-specific degradation of the IP2 spent fuel pool in response to Audit Question 360. As indicated in the LRA, the Water Chemistry Control - Primary and Secondary Program, in conjunction with monitoring spent fuel pool water level in accordance with technical specifications, has managed and will continue to manage the effects of aging on the spent fuel pool liner ensuring the ability of the structure to fulfill its license renewal intended functions throughout the period of extended operation. Entergy has corrected all known sources of leakage from the spent fuel pool.

Furthermore, a one-time inspection of the accessible areas of the IP2 spent fuel pool was conducted beginning in 2006 providing additional assurance of the continued ability of the IP2 spent fuel pool to fulfill its license renewal intended function throughout the period of extended operation. Approximately 40% of the liner was accessible for the inspection. Inspection techniques included use of robotic cameras, general visual and vacuum box testing. Vacuum box testing was used on areas of the liner that were suspect based on the general visual and robotic camera inspections. None of the suspect areas in the spent fuel pool area failed the vacuum box test, indicating that none of the indications found were actually leaking. Identified indications were coated as a precautionary measure.

Essentially 10006 of the spent fuel pool transfer canal liner was inspected using the same techniques as used in the spent fuel pool with the addition of UT where applicable. The inspections discovered several indications and one weld defect in the transfer canal liner. The we!d defect failed the vacuum box test. The defect and ihe indications were repaired.

Evaluation concluded that the defect and indications were the result of poor construction practices and workmanship during initial construction activities. The combined inspections of the spent fuel pool and the spent fuel pool transfer canal completed in 2007 constitute an effective one-time inspection of the IP2 spent fuel pool liner.

The commitment for program enhancements listed under "Scope of Program" for the Structures Monitoring Program, pages 8-121 through 8-124 of the IRA, includes those areas and structures that are not explicitly listed in the Structures Monitoring Program procedure. The spent fuel pool (pit) structure is explicitly listed in the Structures Monitoring Program procedure and is being inspected. As discussed in LRA Section 2.4.3, "Fuel Storage Building I P m , and as shown in Table 2.4-3 and 3.5.2-3, "Floor slabs, interior walls, and ceilings", spent fuel pool (pit) is in the scope of license renewal and subject to aging management review. The Structures Monitoring Program will continue to require inspections on the IP2 spent fuel pool through the period of extended operation.

Groundwater monitoring for 1P2 and IP3 includes sampling from wells adjacent to the IP2 spent fuel pool. Samples are checked for sulfates, pH and chlorides and tritium. Entergy has committed to long term monitoring of site groundwater with the objective of assuring proper assessment and reporting of dose impact, identification of potential leaks to ground water, and the ongoing assessment of the long term monitored attenuation strategy (Ref. Letter dated May 15, 2008, titled "Remediation and Long Term Monitoring of Site Groundwater", from Mr. Joseph E. Poliock to USNRC- Document Control Desk.) The presence of tritium is a better indication of a leak from a spent fuel pool than the presence of boron. Tritium is a better indicator than boron because boron can be absorbed or partitioned into geologic materials. In addition, tritium is contained in the IP2 spent fuel pool in high concentrations relative to its detection limit (ratio of concentration to detection limit is greater for tritium than for boron).

The enhancement to the Structures Monitoring Program, "Detection of Aging Effects", shown in LRA Section B.1.36, page B-124, is revised to include tritium in the monitoring and evaluation of ground water samples. The revised program enhancement reads as follows.

Guidance to perform evaluation of groundwater samples will be added to the Structures Monitoring Program. To assess aggressiveness of groundwater to concrete, IPEC will obtain samples from 5 wells that are representative of the ground water surrounding below-grade site structures at least once every five years and perform an engineering evaluation of the results from those samples for sulfates, pH and chlorides. Additionally, to assess potential indications of spent fuel pool leakage, IPEC will sample for tritium in groundwater wells in close proximity to the IP2 spent fuel pool at least once every 3 months.

Audit Question 361 IP2 Containment Concrete Entergy addressed plant-specific degradation of the lP2 containment structure in response to Audit Question 361. The containment concrete structure is routinely inspected (general visual examination) and evaluated in accordance with the requirements of the Containment lnservice Inspection (CII - IWL) Program (Ref. LRA Table 3.5.2-1, line item: "Dome, cylinder wall, basemat"). CII - IWL Program meets the ASME Code,Section XI, Subsection IWL as 10 CFR 50.55a requires.

Concrete spalls on the containment were noted during the 2000 containment insewice inspection. In these areas, the exposed reinforcing steel is oxidized, forming a protective coating. These areas have been evaluated under the corrective action program. The evaluations have determined that the spalls occur at locations where cadweld sleeves have insufficient concrete cover. Cadweld splices have diameters larger than the bar and thus have the least amount of concrete cover. The spalied concrete locations are on the vertical cylinder wall of the containment precluding the possibility of standing water that could percolate through the concrete. The location on the vertical wall of containment precludes ready access to allow for repair of a condition determined to have no impact on the ability of the structure to perform its required function.

The 2005 CII-IWL inspection found little or no change of the condition observed in 2000. The identified areas show no signs of corrosion staining or deterioration and no indication that the degradation is progressing.

During the LRA review, Entergy committed to enhance the CII-IWL inspections during the period of extended operation through enhanced characterizing of the degradation (i.e., quantifying the dimensions of noted indications through the use of optical aids) (Ref. audit question 533). This better quantification will allow for more effective trending of degradation following future inspections. The enhancement includes obtaining critical dimensional data of degradation where possible through direct measurement or the use of scaling technologies for photographs, and the use of consistent vantage points for visual inspections. Implementation of this enhancement requires the continued use of optical aids to allow effective characterization of indications on the containment wall that are not accessible from the ground or from existing structures.

While Entergy has observed no progression of the containment concrete spall and rebar corrosion conditions during the most recent periodic inspections, the enhanced measures for characterizing degradation during the period of extended operation provide an effective means to detect potential future progression of the degradation such that corrective action to remedy the condition can be taken prior to loss of the license renewal intended function.

CLARIFICATIONS for ELECTRICAL RAIs and AUDIT QUESTIONS REGARDING LICENSE RENEWAL APPLICATION ENTERGY NUCLEAR OPERATIONS, INC INDiAN POINT NUCLEAR GENERATING UNIT NOS. 2 and 3 DOCKETS 50-247 and 50-286

INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL APPLICATION CLARIFICATIONS FOR ELECTRICAL RAls AND AUDlT QUESTIONS RAI 3.6.2.3-2 iP2 138KV Switchyard Cable In RAI 3.6.2.3-2 the staff asked Entergy to explain why an AMP is not required to manage the potential loss of dielectric strength leading to reduced insulation resistance and electrical failure of the 1P2 138 kV underground transmission cable. As stated in the RAI response letter dated 6/26/2008, there are no aging effects requiring management because the IP2 138 kV underground transmission cable is not susceptible to aging mechanisms from moisture intrusion and water treeing, elevated operating temperature, voltage stress, or galvanic corrosion. Nevertheless, routine maintenance is credited for verifying the absence of aging effects on the Indian Point Unit 2, 138 kV underground transmission cable.

RA13.6.2.3-2 Clarification LRA Section A.2.1.28 and 8.1.29 will be modified to add the 138 kV underground transmission cable, which is part of the Unit 2 offsite power path, to the Periodic Surveillance and Preventive Maintenance Program. The routine maintenance will use vendor recommended testing and inspections as stated in the amended text for LRA Sections A.2.2.28 and 8.1.29.

A.2.1.28 PERIODIC SURVEILLANCE AND PREVENTIVE MAINTENANCE PROGRAM, UFSAR Supplement, will be changed to add the 138 kV underground transmission cable. The section for surveillance testing and periodic inspections will be modified to add:

U2 offsite power feeder, 138 kV underaround transmission cable 8.1 29 PERIODIC SURVEILLANCE AND PREVENTIVE MAINTENANCE PROGRAM, Program Descr!pt!on,w!ll be changed to add the 138 kV underground transmission cable as follows:

U2 offsite power feeder On-Line: Visual inspection of external surfaces of 138 kV underaround termination and oroundina connections, transmission cable temperature measurement of above around parts to detect potential overheatina, and partial discharae testina.

LRA Section 8.1.22, NON-EQ BOLTED CABLE CONNECTIONS. Clarification Visual Inspections for a One- Time lnspections Program Amendment 3 to the LRA, in Entergy letter dated 3/24/2008, provided the following clarification for questions asked during the NRC audits and inspections.

ltems 63 and 563 ffrom Attachment 2 of Enterqy letter dated 3124120081 Item 63 is being revised to reflect discussion with the NRC Staff associated with draft LR-ISG-2007-02. I R A 8.1.22 addresses the plant specific AMP for non-EQ bolted cable connections. Based on discussion with the NRC Staff, the AMP discussion for using visual inspection is being clarified to further explain the types of connections and personnel safety issues of opening energized equipment.

An example of where visual inspection is acceptable is motor connections where the motor lead is connected to the field cable in a local junction box. Because of personnel safety practices the junction box cover would not be removed when the cable is energized, so thermography could only be performed with the junction box cover in place, which may not provide accurate results. Another example of using visual inspection would be in remote switchgear panels where the entire connection to the bus is covered with tape or an insulating boot. For both of these examples, contact resistance measurements would require the destructive examination of the connection. The Entergy policies for personnel safety for energized components at a potential greater than 600V, are to observe a restricted approach boundary, which would preclude the removal of a bolted cover from energized components at a potential of greater than 600V. The number of bolted connections that are greater than 600V are limited to large motor, transformer, or generator connections (less than 30 connections, which is 3 connections per phase for 10 motors) for both units, and 5 remote MCC for both units.

LRA Section 8.1.22 was previously revised with Amendment 1, Entergy Letter NL-07-153 dated 1211812007, and is not being changed by this clarification.

ltems 63 and 563 Additional Clarification Following a telephone conference call held on June 2, 2008 with the NRC, Entergy agreed that visual inspection would not be used for one-time inspections in the Indian Point Non-EQ Bolted Cable Connections Program. Based on this information, LRA Section 8.1.22 is hereby revised.

9.1.22 NON-EQ BOLTED CABLE CONNECTIONS PROGRAM, Detection of Aging Effects, is revised as foilows. This change supersedes the Amendment 1 revision in Entergy ieiter dated 12118/07.

A iepresen?atbe sample of electrical connections within the scope of license renewal, and subject :o aging management review will be inspected or tested prior to the period of extended operation to verify there are no aging effects requiring management during the perlcd of extended operation.

The factors considered for sample selection will be application (medium and low voltage), circuit loading (high loading), and location (high temperature, high humidity, vibration, etc.). The technical basis for the sample selected will be documented.

Inspection methods may include thermography, contact resistance testing, or other appropriate methods -ased on plant configuration and industry guidance. The one-time inspection provides additional confirmation to support industry operating experience that shows that electrical connections have not experienced a high degree of failures, and that existing installation and maintenance practices are effective.

Further Clarificationfor RAI 2.5-1 Offsite Power Components in Scope of License Renewal As stated in clarification to RAI 2.5-1 in the Entergy letter dated 3/21/2008, the offsite power paths, as shown in the figure attached to the response included the substation circuit breakers. The offsite power substation breakers shown in the revised figures in Entergy letter dated 312112008 include the support structures and control circuits for these substation breakers.

As stated in LRA Section 2.4.3, TransformerISwitchyard Support Structures, "These support structures include the transformer foundations and support steel, transformer pothead foundations and support steel, and foundations for the associated switchyard breakers." The support structures associated with the components shown in the revised LRA figures provided in letter 3/21/2008 for the offsite power path are included in the scope of license renewal as indicated in I R A Section 2.4.3.

LRA Section 2.5 states, "Specifically, the offsite power recovery path includes the station auxiliary transformers, the 138KV switchyard circuit breakers supplying the station auxiliary transformers, the circuit breaker-to-transformer and transformer-to-onsite electrical distribution interconnections, and the associated control circuits and structures." The control circuits associated with the components shown in the revised LRA figures provided in letter 3/21/2008 for the offsite power path are included in the scope of license renewal as indicated in LRA Section 2.5.

ATTACHMENT 3 TO NL-08-127 IPEC LICENSE RENEWAL APPLICATION AMENDMENT REGARDING LICENSE RENEWAL APPLICATION ENTERGY NUCLEAR OPERATIONS. INC iNDiAN POINT NUCLEAR GENERATING UNIT NOS. 2 and 3 DOCKETS 50-247 and 50-286

INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL APPLICATION AMENDMENT The LRA is revised as described below. (underline - added, strikethrough -

deleted)

LRA Section 4.2.5, Pressurized Thermal Shock, is revised as follows.

The projected 48 EFPY peak beltline fluence level at the cladibase metal interface of 1.560E+19 n/cm2was applied to all beltline materials. The resulting projected 48 EFPY RTp7s are shown in Table 4.2-4. All projected R T ~ values T ~ are within the established screening criteria for 48 EFPY with the exception of plate 82803-3, which exceeds the screening criterion by 9.9 F. Values of R T Nfor

~ the IP3 beltline materials at ?4 T and 3/4 T are summarized in Table 4.2-6.

As required by 10 CFR 50.61(b)(4), a plant-specific safety analysis for plate 82803-3 will be submitted to the NRC three years prior to reaching the FITprs screening criterion.

Alternatively, IP3 may choose to implement the revised PTS -rule 8-Therefore, the RTns TLAA will be adequately managed for the period of extended operation in accordance with 1 OCFR54.21(c)(l)(iii).

LRA Appendix A, Section A.3.2.1.4, Pressurized Thermal Shock, is revised as follows.

A.3.2.1.4 Pressurized Thermal Shock 10 CFR 50.61(b)(l) provides rules for protection against pressurized thermal shock events for pressurized water reactors. Licensees are required to perform an assessment of the projected values of reference temperature whenever a significant change occurs in projected values of the adjusted reference temperature for pressurized thermal shock (RTpis). The screening criteria for RTPT~ is 270°F for plates, forgings, and axial welds and 300°F for circumferential welds.

Adjusted reference temperatures are calculated for both Positions 1 and 2 by following the guidance in Regulatory Guide 1.99, Sections 1.I and 2.1, respectively, using copper and clickel content of beltline materials and end-of-life (EOL) best estimate fluence projections.

Ail projected R T ~ values T ~ are within the established screening criteria for 48 EFPY with the exception of plate 82803-3, which exceeds the screening criterion by 9.9"F.

As required by 10 CFR 50.61(b)(4jza plant-specific safety analysis for plate 82803-3 will be submitted to the NRC three years prior to reaching the RTpis screening criterion.

Alternatively, the site may choose to implement the revised PTS . . rule e v o r p when p a . :

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8.1.36 LRA Appendix 8,Section 8.1.36, Structures Monitoring, is revised as follows I1 Attributes Affected Enhancements

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/ 4. Detection of Aging Effects Guidance to perform evaluat~onof groundwater samples teaesw6 i

yea@ wtll be added to the Structures Monttor~ngProgram To assess aaaressiveness of aroundwater to concrete, lPEC mil obtarn samples from at least 5 wells that are representative of the ground water surrounding below-grade stte structures least once evew five vears and oerforrn an enqlneerrna evaluat~onof the results from

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[nose- S s a r n ~ l e 4Be-s for sulfates, pH and chlorides. Additionallv, to

/ assess ootential indications of soent fuel pool 1 leakaae. IPEC will samole for tritium in roundwater wells in close ~roximitvto the 1/ $2 soent fuel UOOI at least once eve, 3 months.

I A.2.1.35 Structures Monitoring Program I R A Appendix A, Section A.2.1.35, Structures Monitoring Program, is revised as follows, e Guidance to perform an evaluation of groundwater samples to assess aggressiveness of groundwater to concrete on a periodic basis (at least cmce every five years) will he added to the Structures Mclilitoring Program. The site will obtain samples from a 5 wells that representative of the groundwater surruiinding below-grade site structures-;and perform evaluation of the res~ilts from those samples for sulfates, pH and chlorides.

Additional!?. to assess ~otentiaiit~dicationsof spent fuei pool leakaee, fPEC will w ! e for tritiilm in crroundwater wells in close uroximitv to the lP'2 suent fuel pool at least oirce everv 3 months.

ATTACHMENT 4 TO NL-08-127 IPEC COMMITMENT LIST REVISION 5 REGARDING LICENSE RENEWAL APPLICATION ENTERGY b:UCLEAR OPERATIONS, INC

~RDIANPOINT NUCLEAR GENERATING UNIT NOS. 2 and 3 DOCKETS 50-247 and 50-286

List of Regulatory Commitments Rev. 5 The following table identifies those actions committed to by Entergy in this document.

Changes are shown as strikethroughs for dek&ms and underlines for additions.

the bottom surfaces of the condensate storage tanks, first ten years of the period of extended operation.

3A SECTIO AUDIT ITEIi

'2: A.2.1.8 Enhance the Diesel Fuel Monitoring Program to A.3.1.8 sptember 28.

nclude cleaning and inspection of the IP2 GT-1 gas 8.1.9 113

urbine fuel oil itorage tanks, IP2 and IP3 EDG fuel oil rudit item:

day tanks, IP2 SBOIAppendix R diesel generator fuel

'3: 128, 129, sil day tank, and IP3 Appendix R fuel oil storage tank 132.

ecember 12, 3nd day tank once every ten years.

115 491, 492, Enhance the Diesel Fuel Monitoring Program to 570 Include quarterly sampling and analysis of the IP2 SBOiAppendix R diesel generator fuel oil day tank, IP2 security diesel fuel oil storage tank, IP2 security diesel fuel oil day tank, and IP3 Appendix R fuel oil storage tank. Particulates, water and sediment checks will be performed on the samples. Filterable solids acceptance criterion will be less than or equal to 10mg/l. Water and sediment acceptance criterion will be less than or equal to 0.05%.

Enhance the Diesel Fuel Monitoring Program to include thickness measurement of the bottom of the following tanks once every ten years. IP2: EDG fuel oil storage tanks, EDG fuel oil day tanks, SBOIAppendix R diesel generator fuel oil day tank, GT-I gas turbine fuel oil storage tanks, and diesel fire pump fuel oil storage tank; IP3: EDG fuel oil day tanks, EDG fuel oil storage tanks, Appendix R fuel oil storage tank, and diesel fire pump fuel oil storage tank.

Enhance the Diesel Fuel Monitoring Program to change the analysis for water and particulates to a quarterly frequency for the following tanks. IP2: GT-1 gas turbine fuel oil storage tanks and diesel fire pump fuel oil storage tank; lP3: Appendix R fuel oil day tank and diesel fire pump fuel oil storage tank.

Enhance the Diesel Fuel Monitoring Program to specify acceptance criteria for thickness measurements of the fuel oil storage tanks within the scope of the program.

Enhance the D~eselFuel Mon~: rng Program to dlrect samples be taken and lnclude direct~onto remove water when detected.

Revise applicable procedures to direct sampling of the onsite portable fuel oil contents prior to transferring the contents to the storage tanks.

Enhance the Diesel Fuel Monitoring Program to direct the addition of chemicals including biocide when the sresence of biological activity is confirmed.

COMMITMENT IMPLEMENTATION^ SOURCE I RELATED I SCHEDULE ?A SECT10 AUDIT ITEI A.2.1.10 Enhance the External Surfaces Monitoring Program aptember 28, A.3.1.10 for IP2 and IP3 to include periodic inspections of 113 0.1.11 systems in scope and subject to aging management review for license renewal in accordance with 10 CFR

'3:

54.4(a)(I) and (a)(3). Inspections shall include areas ecember 12, j

surrounding the subject systems to identify hazards to lhose systems. lnspections 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).

I 13 eptember 28, NL-07-039 A.2.1.11 Enhance the Fatigue Monitoring Program for IP2 to A.3.1 .I1 monitor steady state cycles and feedwater cycles or 8.1.12, perform an evaluation to determine monitoring is not 4udit lten required. Review the number of allowed events and 164 resolve discrepancies between reference documents and monitoring procedures.

Enhance the Fatigue Monitoring Program for IP3 to include all the transients identified. Assure all fatigue ecember 12, analysis transients are included with the lowest I 15 limiting numbers. Update the number of design transients accumulated to date.

NL-07-039 A.2.1.12 Enhance the Fire Protection Program to inspect eptember 28, A.3.1.12 external surfaces of the IP3 RCP oil collection 0.1.13 systems for loss of material each refueling cycle Enhance the Fire Protection Program to explicitly state that the IP2 and IP3 diesel fire pump engine ecember 12, sub-systems (including the fuel supply line) shall be 315 observed while the pump is running. Acceptance criteria will be revised to verify that the diesel engine does not exhibit signs of degradation while running; such as fuel oil, lube oil, coolant, or exhaust gas leakage.

Enhance the Fire Protection Program to specify that the lP2 and IP3 diesel fire pump engine carbon steel exhaust components are inspected for evidence of corrosion and cracking at least once each operating cycle.

Enhance the Fire Protection Program for lP3 to visually inspect the cable spreading room, 480V switchgear room, and EDG room C02fire suppression system for signs of degradation, such as corrosion and mechanical damage at least once every six months.

PLEMENTATION SOURCE I RELATED 1 SCHEDULE %ASECROF PUDlT ITEM 2: A.2.1.13 Enhance the Fire Water Program to include inspection ?ptember28, A.3.1.13

)f IP2 and IP3 hose reels for evidence of corrosion. )3 I 8.1.14 4cceptance criteria will be revised to verify no ,udit Items

~flacceptablesigns of degradation. 3: 105,106 Enhance the Fire Water Program to replace all or test xember 12, 3 sample of IP2 and 1P3 sprinkler heads required for 115 10 CFR 50.48 using guidance of NFPA 25 (2002 3dition), Section 5.3.1.1 .I before the end of the 50-qear sprinkler head service life and at 10-year ntervals thereafter during the extended period of speration to ensure that signs of degradation, such as zorrosion, are detected in a timely manner.

Enhance the Fire Water Program to perform wall thickness evaluations of IP2 and IP3 fire protection piping on system components using non-intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material due to corrosion. These inspections will be performed before the end of the current operating term and at intervals thereafter during the period of extended operation. Results of the initial evaluations will be used to determine the appropriate inspection interval to ensure aging effects are identified prior to loss of intended function.

Enhance the Fire Water Program to inspect the internal surface of foam based fire suppression tanks.

Acceptance criteria will be enhanced to verify no significant corrosion.

'2: A.2.1.15 Enhance the Flux Thimble Tube lnspection Program eptember 28, A.3.1. I 5 for IP2 and IP3 to implement comparisons to wear 8.1 .I6 013 rates identified in WCAP-12866. Include provisions to compare data to the previous performances and '3:

perform evaluations regarding change to test tecember 12, frequency and scope. 015 Enhance the Flux Thimble Tube lnspection Program for lP2 and IP3 to specify the acceptance criteria as outlined in WCAP-12866 or other plant-specific values based on evaluation of previous test results.

Enhance the Flux Thimble Tube lnspection Program for lP2 and IP3 to direct evaluation and performance of corrective actions based on tubes that exceed or are projected to exceed the acceptance criteria. Also stipulate that flux thimble tubes that cannot be inspected over the tube length and cannot be shown by analysis to be satisfactory for continued service, must be removed from service to ensure the integrity of ihe reacior coolant system pressure boundary.

COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION in the scope of the program.

RHR heat exchangers RHR pump seal coolers Non-regenerative heat exchangers Charging pump seal water heat exchangers Charging pump fluid drive coolers Charging pump crankcase oil coolers Spent fuel pit heat exchangers Secondary system steam generator sample coolers Waste gas compressor heat exchangers

SBOIAppendix R diesel jacket water heat exchanger (IP2 only)

Enhance the Heat Exchanger Monitoring Program for lP2 and IP3 to perform visual inspection on heat exchangers where non-destructive examination, such as eddy current inspection, is not possible due to heat exchanger design limitations.

Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to include consideration of material-environment combinations when determining sample population of heat exchangers.

Enhance the Heat Exchanger Monitoring Program for iP2 and IP3 to establish minimum tube wall thickness for the new heat exchangers identified in the scope of t i e program. Establish acceptance criteria for heat exchanaers visuailv insoected to include no aging effects for lubrite sliding supports used in the steam generator and reactor coolant pump support

/ # 1 COMMITMENT ilMPLEMENTATlONl SOURCE I RELATED 1 the program.

A.2.1.19 A.3.1.19 the scope of bus inspected. 8.1.20 Audit Item:

124, 733, 519 least once every 10 years. The first inspection will occur prior to the period of extended operation and the acceptance criterron will be no significant loss of material.

Enhance the Metal-Enclosed Bus Inspection Program to add acceptance criteria for ME5 internal visual inspections to include the absence of indications of dust accumulation on the bus bar, on the insulators, and in the duct, in addition to the absence of indications of moisture intrusion into the duct.

Enhance the Metal-Enclosed Bus Inspection Program for IP2 and IP3 to inspect bolted connections at least once every five years if performed visually or at least once every ten years using quantitative measurements such as thermography or contact resistance measurements. The first inspection will occur prior to the period of extended operation.

The plant will process a change to applicable site procedure to remove the reference to "re-torquing" connections for phase bus maintenance and bolted connection maintenance.

NL-07-039 A.2.1.21

!mplement the Non-EQ Bolted Cable Connections A.3.1.21 Program for 1P2 and lP3 as described in IRA Section 8.1.22 B.1.22.

IP3:

December 12, 2015

7 COMMITMENT liMPLEMENTATlON SOURCE RELATED 1 SCHEDULE LRA SECTION AUDIT ITEN A.2.1.22 lmplement the Non-EQ Inaccessible Medium-Voltage A.3.1.22 Cable Program for IP2 and IP3 as described in LRA 8.1 '23 Section 8.1.23. Audit item This new program will be implemented consistent with '3: 173 the corresponding program described in NUREG- ecember 12, 1807 Section XI.E3, lnaccessible Medium-Voltage I 15 Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements.

A.2.1.23 Implement the Non-EQ Instrumentation Circuits Test A.3.1.23 eptember 28, Review Program for IP2 and lP3 as described in I R A 8.1.24 I 13 Section 8.1.24. Audit item This new program will be implemented consistent with '3: 173 the corresponding program described in NUREG- ecember 12, 1801 Section XI.E2, Electrical Cables and 315 Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits.

'2: A.2.1.24 Implement the Non-EQ Insulated Cables and A.3.1.24 eptember 28, Connections Program for IP2 and IP3 as described in 8.1.25 313 IRA Section 8.1.25. Audit item This new program will be implemented consistent with 173 the corresponding program described in NUREG- ecember 12, I801 Section XI.EI, Electrical Cables and 315 Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.

'2: A.2.1.25 Enhance the Oil Analysis Program for IP2 to sample A.3.1.25 eptember 28, and analyze lubricating oil used in the SBOJAppendix 8.1.26 013 R diesel generator consistent with oil analysis for other site diesel generators.

Enhance the Oil Analysis Program for IP2 and IP3 to sample and analyze generator seal 011and turbine hydraul~ccontrol 011.

Enhance the Oil Analysis Program for IP2 and IP3 to formalize preliminary oil screening for water and particuiates and laboratory analyses including defined acceptance criteria for all components included in the scope of this program. The program will specify corrective actions in the event acceptance criteria are not met.

Enhance the Oil Analysis Program for IP2 and lP3 to formalize trending of preliminary oil screening results as well as data provided from independent iaboratories.

1 1

COMMITMENT 1 SOURCE

~IMPLEMENTATI~N~

SCHEDULE RELATED LRA SECTION Implement the One-Time Inspection Program for 1P2 A.3.1.26 and IP3 as described in LRA Section B.1.27.

8.1.27 This new program will be implemented consistent with Audit item the corresponding program described in NUREG- 173 1801,Section XI.M32, One-Time Inspection.

A.2.1.27 Implement the One-Ttme lnspect~on- Small Bore A.3.1.27 Pip~ngProgram for IP2 and IP3 as descr~bedin LRA 8.1.28 Sectton 8.1.28.

Audit item This new program will be implemented consistent with IP3: 173 the corresponding program described in NUREG- December 12, 1801,Section XI.M35, One-Time Inspection of ASME 2015 Code Class I Small-Bore Piping.

IP2: A.2.1.28 Enhance the Periodic Suweillance and Preventive September 28, A.3.1.28 Maintenance Program for IP2 and lP3 as necessary 013 8.1.29 to assure that the effects of aging will be managed such that applicable components will continue to IP3:

perform their intended functions consistent with the December 12, current licensing basis through the period of extended 015 operation.

IP2: A.2.1.31 Enhance the Reactor Vessel Suweillance Program for September 28, A.3.1.31 1P2 and IP3 revising the specimen capsule withdrawal 2013 8.1.32 schedules to draw and test a standby capsule to cover the peak reactor vessel fluence expected IP3:

through the end of the period of extended operation.

December 12, Enhance the Reactor Vessel Surveillance Program for 2015 1P2 and IP3 to require that tested and untested specimens from all capsules pulled from the reactor vessel are maintained in storage.

IP2: A.2.1.32 Implement the Selective Leaching Program for IP2 September 28, A.3.1.32 and IP3 as described in LRA Section 8.1.33.

2013 B.1.33 This new program will be implemented consistent with Audit item the corresoondinq oroqrarn described in NUREG- 173 1801, section ~ 1 . i 3Selective 3 Leaching of Materials. l~ecember12, A.2.1.34 Enhance the Steam Generator Integrity Program for A.3.1.34 iP2 and IP3 to require that the results of the condition 8.1.35 monitoring assessment are compared to the operational assessment performed for the prior operating cycle with differences evaluated.

015

ir COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION Enhance the Structures Mon~torfngProgram to 25 e x ~ l i c i tspecffy l~ that the following structures are I included in the program Appendix R diesel generator foundation (lP3)

Appendix R diesel generator fuel oil tank vault (IP3)

Appendix R diesel generator switchgear and enclosure (IP3) city water storage tank foundation condensate storage tanks foundation (IP3) containment access facility and annex (lP3) discharge canal (IP2/3) emergency lighting poles and foundations (IP213) fire pumphouse (IP2) fire protection pumphouse (IP3) fire water storage tank foundations (lP213) gas turbine 1 fuel storage tank foundation maintenance and outage building-elevated passageway (IP2) new station security building (IP2) nuclear service building (IPI) primary water storage tank foundation (IP3) refueling water storage tank foundation (IP3) security access and office building (lP3) service water pipe chase (IP2/3) service water valve pit (lP3) superheater stack transformer/switchyard support structures (IP2) waste holdup tank pits (IP213)

Enhance the Structures Monitoring Program for lP2 and IP3 to clarify that in addition to structural steel and concrete, the following commodities (including their anchorages) are inspected for each structure as applicable.

cable trays and supports concrete portion of reactor vessel supports conduits and supports cranes, rails and girders equipment pads and foundations fire proofing (pyrocrete)

HVAC duct supports jib cranes manholes and duct banks rnanways, hatches and hatch covers monorails

COMMlTNIENT IIMPLEMENTATION~ SOURCE / RELATED I SCHEDULE ?A SECTIOI AUDIT ITEN new fuel storage racks r sumps, sump screens, strainers and flow barriers Enhance the Structures Monitoring Program for IP2 and IP3 to inspect inaccessible concrete areas that are exposed by excavation for any reason. IP2 and 1P3 will also inspect inaccessible concrete areas in environments where observed conditions in accessible areas exposed to the same environment indicate that significant concrete degradation is occurring.

Enhance the Structures Monitoring Program for 1P2 and IP3 to perform inspections of elastomers (seals, gaskets, seismic joint filler, and roof elastomers) to identify cracking and change in material properties and for inspection of aluminum vents and louvers to identify loss of material.

Enhance the Structures Monitoring Program for IP2 Audit ltem and IP3 to perform an engineering evaluation of -

360 groundwater samples to assess aggressiveness of groundwater to concrete on a periodic basis (at least once every five years). IPEC will obtain samples from at least 5 wells that are representative of the ground water surrounding below-grade site structures and perform an engineering evaluation of the results from those samples for sulfates, pH and chlorides.

Additionallv, to assess potential indications of spent fuel pool leakaae, IPEC will sample for tritium in groundwater wells in close proximitv to the iP2 spent fuel pool at least once even/ 3 months.

Enhance the Structures Monitoring Program for lP2 and iP3 to perform inspection of normally submerged concrete portions of the intake structures at ieast once every 5 years. Inspect the bafflingigrating partition and support platform of the IP3 intake structure at least once every 5 years.

-

Ff?lP~r-,e tea Srr~cturesMonitorina Proarm f?r IP2 4udit ltem 31;; I?? !c oo<crrn ~nspeciionof !he deara-ea araas -

358 of the water control structure once per 3 vears rather than the normal freauencv of once Der 5 wars durlnq the PEO.

Y COMNIlTMENT IIMPLEMENTATION SOURCE RELATED 1 SCHEDULE

-

LRA SECTION AUDIT lTEb IP2: A.2.1.36 Implement the Thermal Ag~ngEmbr~ttlementof Cast A.3.1.36 September 28, Austenitic Stainless Steel (CASS) Program for IP2 8.1.37 013 and IP3 as described in LRA Section 8.1.37. Audit item This new program will be implemented consistent with lP3: 173 the corresponding program described in NUREG- December 12, 1801,Section XI.MI2, Thermal Aging Embrittlement 2015 of Cast Austenitic Stainless Steel (CASS) Program.

lP2: A.2.1.37 Implement the Thermal Aging and Neutron Irradiation A.3.1.37 September 28, Embrittlement of Cast Austenitic Stainless Steel 8.1.38 2013 (CASS) Program for IP2 and IP3 as described in LRA Audit ttem Section 8.1.38. IP3: 173 This new program will be implemented consistent with December 12, the corresponding program described in NUREG- 2015 1801 Section XI.Ml3, Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel ICASS) Program.

IP2: A.2.1.39 Enhance the Water Chemistry Control -Closed A.3.1.39 September 28, Cooling Water Program to maintain water chemistry of 8.1.40 013 the lP2 SBOIAppendix R diesel generator cooling Audit item system per EPRl guidelines. 509 Enhance the Water Chemistry Control -Closed A.2.1.40 B.1.41 A.2.1.41 A.3.1.41 investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of A.2.2.1.2 A.3.2.1.2 4.2.3

t COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION AUDfT JTEA 4s required by 10 CFR 50.61(b)(4), IP3 will submit a A.3.2.1.4

>!ant-specificsafety anaiysis for plate 82803-3 to the 4.2.5 4RC three years prior to reaching the RTPTS

creening criterion. Alternatively, the site may choose o implement the revised PTS rule hen approved.-

'2: A.2.2.2.3 kt least 2 years prior to entering the period of eptember 28, A.3.2.2.3

?xtendedoperation, for the locations identified in LRA 011 4.3.3 rable 4.3-13 (IP2) and LRATabie 4.3-14 (IP3), under kudit item

he Fatigue Monitoring Program, IP2 and IP3 will

'3: 146 mplement one or more of the following:

lecember 12,

I) Consistent with the Fatigue Monitoring Program, 013 3etection of Aging Effects, update the fatigue usage

alculations using refined fatigue analyses to jetermine valid CUFs less than 1.0 when accounting

'or the effects of reactor water environment. This ncludes applying the appropriate Fen factors to vaiid CUFs determined in accordance with one of the iollowing:

1. For locations in LRA Table 4.3-13 (IP2) and LRA Table 4.3-14 (IP3), with existing fatigue analysis valid for the period of extended operation, use the existing CUF.

2. Additional piant-specific locations with a valid CUF may be evaluated. In particular, the pressurizer lower shell will be reviewed to ensure the surge nozzle remains the limiting component.

3. Representative CUF values f r m other plants, adjusted to or enveloping the IPEC plant specific external loads may be used ifdemonstrated applicable to IPEC.

4, An anaiysis using an NRC-approved version of the ASME code or NRC-approved alternative je.g., NRC-approved code case) may be performed to determine a vaiid CUF.

(2) Consistent with the Fatigue Monitoring Program, Corrective Actions, repair or replace the affected iocaticns before exceeding a CUF of 1.O.

April 30, 2008 2.1 .I .3.5 IF2 SBO /Appendix R diesei generator will be installed and operational by April 30, 2008. This Comolete committed change to the facility meets the requirements of 10 CFR 50.59(c)(l) and, therefore, a iicense amendment pursuant to 10 CFR 50.90 is not required.

.. -- -

I SCHEDULE AUMT ITEB I

Audit ltem Perform a one-time insoection of reoresentative samole area of IP2 containment liner affected bv the -

27 1973 event behind the insulation, arior to enterina the extended oeriod of ooeration, to assure liner dearadation is not occurrina in this area.

Perform a one-time insoection of reoresentative samole area of the IP3 containment steel liner at the juncture with the concrete floor slab, orior to enterina the extended oeriod of ooeration, to assure liner Audit ltem Perform a one-time lnsoection and evaluation of a samole of ootentiallv affected IP2 refuelina cavity -

359 concrete orior to the Deriod of extended ooeration.

The samole will be obtained bv core borina the refuelina cavitv wall in an area that is susceotible to GoosuFe 10 beraced water leakaae The lnsoect~on w~llinclude an assessment of embedded relnforc~nq Audit ltem IWL) Proaram to include insoections of the -

361 containment usina enhanced characterization of dearadation (i.e.. auantifvina the dimensions of noted indications throuah the use of o~ticalaids) durina the period of extended ooeration. The enhancement includes obtainina critical dimensional data of dearadation where oossible throuah direct measurement or the use of scalina technoloaies for