ML070100079
| ML070100079 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 12/13/2006 |
| From: | Ellis D Entergy Nuclear Generation Co |
| To: | Williamson A NRC/NRR/ADRO |
| References | |
| %dam200701, TAC 3698 | |
| Download: ML070100079 (28) | |
Text
Pery Bckbrg FW Rgrim License Renewal Application Amendment 10 P
From:
"Ellis, Douglas" <dellisi @ entergy.com>
To:
"Alicia Williamson" <ARW1 @nrc.gov>
Date:
12/13/2006 9:02:08 AM
Subject:
EW: Pilgrim License Renewal Application Amendment 10 Alicia and Perry - find attached pdf of Pilgrim LRA Amendment 10.
Alicia - The original plus CD of the MACCS2 input files are being sent to you via FedlEx because it was the RAI on MACCS2 that prompted the submittal of the CD. I assume you will enter the amendment plus CD as necessary into the NRC document system.
Perry - A copy of the amendment without CID is being mailed to you and others via U.S. Mail.
Doug Ellis, Pilgrim Licensing, 508.830.8160.
Original Message ---
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Sent: Wednesday, December 13, 2006 3:14 AM To: Ellis, Douglas
Subject:
Scan from a Xerox WorkCentre Pro Please open the attached document. It was scanned and sent to you using a Xerox WorkCentre Pro.
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Entergy Nuclear Operations, Inc.
Pilgrim Station 600 Rocky Hill Road Plyfoutlh. MA C02360 Stephen J. Bethay Direcior.NbirAssmn December 12, 2006 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001
SUBJECT:
Entergy Nuclear Operations, Inc.
Pilgrim Nuclear Power Station Docket No. 50-293 License No. DPR-35 License Renewal Application Amendment 10 Entergy letter, License Renewal Application, dated January 25, 2006 (2.06.003)
REFERENCE:
LETTER NUMBER:
2.06.094
Dear Sir or Madam:
In the referenced letter, Entergy Nuclear Operations, Inc. applied for renewal of the Pilgrim Station operating license. NRC TAC NO. MC9669 was assigned to the application.
This License Renewal -Application (LRA) amendment consists of four attachments. Attachment A contains the list of revised regulatory commitments. Attachment B contains the response to the RAI on LRA Section B.1.16.1 Containment Inservice Inspection,. conveyed in NRC letter dated November 7, 2006. Attachment C contains the response to the RAts on LRA Appendix E concerning Severe Accident Mitigation Alternatives, conveyed in NRC letter dated November 28, 2006, and for which a compact disc labeled PNPS MACCS2 Input Files is enclosed.
Attachment D contains changes to the LRA stemming from NRC Region I inspection of the LRA.
Please contact Mr. Bryan Ford, (508) 830-8403, if you have any questions regarding thisý subject.
I declare under penalty of perjury that the foregoing is true and correct. Executed on December 1Z~, 2006.
nL~ns C' Sincerely, StepenJ ha Director, Nuclear Safety ssessment DWE/dl Attachments: (as stated)
Enclosure:
Compact Disc labeled PNPS MACCS2 Input Files cc: see next page
Entergy Nuclear Operations, Inc.
Pilgrim Nuclear Power Station Letter Number: 2.06.094 Page 2 cc: with Attachments Mr. Perry Buckberg Project Manager Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Alicia Williamson Project Manager Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Susan L. Uttal, Esq.
Office of the General Counsel U.S. Nuclear Regulatory Commission Mail Stop 0-15 D21 Washington, DC 20555-0001 Sheila Slocum Hollis, Esq.
Duane Morris LLP 1667 K Street N.W., Suite 700 Washington, DC 20006
.66 without Attachments' Mr. James..Shea O0ff ice Of Nuclear Reactor. R'egulation U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Mr. Jack Strosnidler, Director Office of Nuclear Material and Safeguards U.S. Nuclear Regulatory Commission Washington, DC 20555-00001 Mr. Samuel J. Collins, Administrator Region I U.S. Nuclear Regulatory Commission 475 Allendale Road King of Prussia, PA 19406 NRC Resident Inspector Pilgrim Nuclear Power Station Mr. Joseph Rogers Commonwealth of Massachusetts Assistant Attorney General Division Chief, Utilities Division 1 Ashburton Place Boston, MA 02108 Mr. Matthew Brock, Esq.
Commonwealth of Massachusetts Assistant Attorney General Environmental Protection Division One Ashburton Place Boston, MA 02108 Diane Curran, Esq.
Harmon, Curran, and Eisenberg, L.L.P.
1726 M Street N.W., Suite 600.
Washington, DC 20036 Molly H. Bartlett, Esq.
52 Crooked Lane Duxbury, MA 02332
- Mr.,Robert Walker, Director Massach usetts' Department of Public Health Radiation Control Program Schrafft Center, Suite 1 M2A 529 Main Street Charlestown, MA 02129 Ms. Cristine McCombs, Director Massachusetts Emergency Management Agency 400 Worchester Road Framingham, MA 01702 Mr. James E. Dyer, Director Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, DC 20555-00001
ATTACHMENT A to Letter 2.06.094 (7 pages)
Revised List of Regulatory Commitments
Revised List of Regulatory Commitments The following table identifies those actions committed to by Entergy in this document.
Any other statements in this submittal are provided for information purposes and are not considered to be regulatory commitments.
- COMMITMENT IMPLEMENTATION SOURCE Related SCHEDULE LRA Section No./
_______Comments 1
Implement the Buried Piping and Tanks Inspection June 8, 2012 Letter B.1.2/ Audit Program as described in LRA Section B.1.2.
2.06.003 Item 320 2
Enhance the implementing procedure for ASME June 8, 2012 Letter B. 1..6/ Audit Section XI inservice inspection and testing to specify 2.06.003 Item 320 that the guidelines in Generic Letter 88-01 or approved BWRVIP-75 shall be considered in determining sample expansion if indications are found in Generic Letter 88-01 welds.___________
3 Inspect fifteen (115) percent of the top guide locations As stated in the Letters B.1.8/Audit using enhanced visual inspection technique, EVT-1, commitment 2.06.064 Items 155, within the first 18 years of the period of extended and 320 operation, with at least one-third of the inspections to 2.06.081 be completed within the first six (6) years and at least two-thirds within the first 12 years of the period of extended operations. Locations selected for examination will be areas that have exceeded the
___neutron fluence threshold.
4 Enhance the Diesel Fuel Monitoring Program to June 8, 2012 Letters B.1.10/Audit include quarterly sampling of the security diesel 2.06.003 Items 320, generator fuel storage tank. Particulates (filterable and 566 solids), water and sediment checks will be performed 2.06.089 on the samples. Filterable solids acceptance criteria wil be = 10 mg/I. Water and sediment acceptance; criteria will be =0.05%.
.5
- .Enhance the Diesel Fuel Monitoring Program to June 8, 2012 Letter, B.1.10/Akudit install instrumentation to monitor for leakage between 2.06.057 Items 155, the two walls of the security diesel generator fuel 320 storage tank to ensure that significant degradation is
____not occurring.
6 Enhanc e the Diesel Fuel Monitoring Program to June 8, 2012 Letter B.1.10/Audit specify acceptance criterion for UIT measurements of 2.06.003 Items 165, emergency diesel generator fuel storage tanks (T-320 1 26A&B).__
I
COMMITMENT IMPLEMENTATION SOURCE Related SCHEDULE LRA Section No./
Comments 7
Enhance Fire Protection Program procedures to state June 8, 2012 Letter B.1.1 3.1/
that the diesel engine sub-systems *(including the fuel 2.06.064 Audit Items supply line) shall be observed while the pump is 320, 378 running. Acceptance criteria will be enhanced to verify that the diesel engine did not exhibit signs of degradation while it was running; such as fuel oil, lube oil, coolant, or exhaust gas leakage. Also, enhance procedures to clarify that the diesel-driven fire pump engine is inspected for evidence of corrosion in the intake air, turbocharger, and jacket water system components as well as lube oil cooler.
The jacket water heat exchanger is inspected for evidence of corrosion or buildup to manage loss of material and fouling on the tubes. Also, the engine exhaust piping and silencer are inspected for evidence of internal corrosion or cracking._____________
8 Enhance the Fire Protection Program procedure for June 8, 2012 Letter B.1.13.1/
Halon system functional testing to state that the 2.06.003 Audit Item Halon 1301 flex hoses shall be replaced if leakage 320
___occurs during the system functional test.____________
9 Enhance Fire Water System Program procedures to June 8, 2012 Letter B. 1. 13.2/
include inspection of hose reels for corrosion.
2.06.003 Audit Item Acceptance criteria will be enhanced to verify no 320 significant corrosion.__
10 Enhance the Fire Wafter.System Program to state that June 8, 2012 Letter B-1.13.2/
ae sample of sprinkler heads will be inspected using 2.06.003 A'udit Item g)uidance of NEPA 25'(2002 Edition) Section 320 53.1' NFPA 25 also contains guidance to, repeat this sampling every 10 years -after initial field service
____ testing.___
11 Enhance the Fire Water System Program to state-that June 8, 2012 Letter
'B. 1 13.2/
wall thickness evaluations of fire protection piping will 2.06.003 Audit Item be performed on system components using non-
.320 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.
12 Implement the Heat Exchanger Monitoring Program June 8, 2012 Letter B.1.15/Audit
___as described in LRA Section B. 1. 15.
12.06.0031 Item 320 2
- COMMITMENT IMPLEMENTATION SOURCE Related SCHEDULE LRA Section No./
_____________Comments 13 Enhance the Instrument Air Quality Program to June 8, 2012 Letter B.1.17/Audit include a sample point in the standby gas treatment 2.06.003 Item 320 and torus vacuum breaker instrument air subsystem in addition to the instrument air header sample points.______
14 Implement the Metal-Enclosed Bus Inspection June 8, 2012 Letter B.1.18/Audit Program as described in LRA Section B.1.18.
.2.06.003 Item 320 15 Implement the Non-EQ Inaccessible Medium-Voltage June 8, 2012 Letter B.1.19/Audit Cable Program as described in LRA Section B.1.19.
2.06.003 items 311, Include developing a formal procedure to inspect 320
____manholes for in-scope medium voltage cable.
16 Implement the Non-EQ Instrumentation Circuits Test June 8, 2012 Letter B. 1.20/ Audit I__
Review Program as described in LRA Section B.1.20.
_______2.06.003 Item 320 17 Implement the Non-EQ Insulated Cables and June 8, 2012 Letter B.1.21/Audit Connections Program as described in LRA Section 2.06.003 Item 320 B.1.21.__
18 Enhance the Oil Analysis Program to periodically June 8, 2012 Letter B.1.22/Audit change ORID pump lubricating oil. A particle count 2.06.003 Item 320 and check for water will be performed on the drained oil to detect evidence of abnormal wear rates,
___contamination by moisture, or excessive corrosion.
19 Enhance Oil Analysis Program procedures for June 8, 2012 Letter B.1.22/IAudit security diesel and reactor water cleanup pump oil 2.06;003 Item 320 c>changes to obtain oil samples from the drained oil.
,,,,-Procedures for lubricating oil analysis will be
-enhanced to specify that a particle count and check fo -water-are..performed onloiI samplesfrmteie water pump diesel; security' diesel, and reactor water
___cleanup pumps.
20 Implement the One'-Time Inspection Program as June 8, 2012 Letter B.1.23/ Audit described in LRA Section B. 1.23. This includes
.2.06.003 Items 219, destructive or non-destructive examination of one (1) 320 socket welded connection using techniques proven by past industry experience to be effective for the identification of cracking in small bore socket welds.
Should an inspection opportunity not occur (e.g.,
socket weld failure or socket weld replacement), a susceptible small-bore socket weld will be examined either destructively or non -destructively prior to entering the period of extended operation.
21 Enhance the Periodic Surveillance and Preventive June 8, 2012 Letter B.1.24/ Auditi Maintenance Program as necessary to assure that 2.06.003 Item 320 the effects of aging will be managed as described in LRA Section B.1.24.
I I___
3
- COMMITMENT IMPLEMENTATION SOURCE Related SCHEDULE LRA Section No./
Comments 22 Enhance the Reactor Vessel Surveillance Program to June 8, 2Q.12 Letter B.1.26/ Audit proceduralize the data analysis, acceptance criteria, 2.06.003 Item 320 and corrective actions described in LRA Section B.1.26.
23 Implement the Selective Leaching Program in June 8, 2012 Letter B.1.27/Audit' accordance with the program as described in LRA 2.06.003 Item 320 Section B.1.27.
24 Enhance the Service Water Integrity Program June 8, 2012 Letter B.1.28/ Audit procedure to clarify that heat transfer test results are 2.06.003 Item 320 trended.________
25 Enhance the Structures Monitoring Program June 8, 2012 Letter B. 1. 29.2/
procedure to clarify that the discharge structure, 2.06.003 Audit Items security diesel generator building, trenches, valve 238, 320 pits, manholes, duct banks, underground fuel oil tank foundations, manway seals and gaskets, hatch seals and gaskets, underwater concrete in the intake structure, and crane rails and girders are included in the program. In addition, the Structures Monitoring Program will be revised to require opportunistic inspections of inaccessible concrete areas when they become accessible.
26 Enhance Structure~s Monitoring Program guidance for June 8, 2012 Letter B. 1.29.2/
performing structural examinations of elastomers,,,q:.r,ý 2.06.003 Audit Item (seals, gaskets, seismic joint filler, and roof 320 elastomers) to i~dentify cracking and. change in material pOrope~rti~es.
-27 Enac h
aer Control Structures Monitoring June 8, 2012
ýLetter B.1'29.3/
Program scope'to include the east breakwater, jetties,,
2.06.003 -Audit. Item-,
and onshore revetments in addition to the main 320 breakwater.
28 Enhance SystemWalkdown Program guidance June 8, 2012 Letter B. 1. 30/ Audit documents to perform periodic system engineer 2.06.057 Items 320, inspections of systems in scope and subject to aging 327 management review for license renewal in accordance with 10 CFR 54.4(a)(1) and (a)(3).
Inspections shall include areas surrounding the subject systems to identify hazards to those systems.
Inspections of nearby systems that could impact the subject systems will include SSCs that are in scope and subject to aging management review for license renewal in accordance with 10 CFR 54.4(a)(2).
29 Implement the Thermal Aging and Neutron Irradiation June 8, 2012 Letter B.1.31/Audit Embrittlement of Cast Austenitic Stainless Steel 2.06.003 Items 257,
___(CASS)
Program as described in LRA Section B.1.31.
320 4
- COMMITMENT IMPLEMENTATION SOURCE Related SCHEDULE LRA Section No./
______Comments 30 Perform a code repair of the CRD return line nozzle June 30, 2015 Letter B.1.3/ Audit to cap weld if the installed weld repair is not approved 2.06.057 Items 141, via accepted code cases, revised codes, or an 320 approved relief request for subsequent inspection intervals.________
31 At least 2 years prior to entering the period of extended operation, for the locations identified in NUREG/CR-6260 for BWRs of the PNPS vintage, PNPS will implement one or more of the following:
(1) Refine the fatigue analyses to determine valid CUFs less than 1 when accounting for the effects of reactor water environment. This includes applying the appropriate Fen factors to valid CUFs determined in accordance with one of the following:
- 1. For locations, including NUREG/CR-6260 locations, with existing fatigue analysis valid for the period of extended operation, use the existing CUE to determine the environmentally adjusted CUE.
- 2. More limiting PNPS-specific locations with a valid CUE may be added in addition to the NUREGICR-6260 locations.
- 3. Representative CUE values from other plants, adjusted to or enveloping the PNPS plant specific external loads may be used if demonstrated applicable to PNPS.
- 4. An analysis using an NRC-7approved version of the ASME code of NRC-approved alternativ~e (e.g., NRC-approved code case) may be performed to~determine a valid CUE.
(25'Manage 'the effects of aging-due to fatigue at the
-aff ected locations by an inspection -program that has been rvi6ewed eand. approved by thep NRC. (e.g., -pero o-destructive examination of the affected locations at finspcii~dn iintr-va:ýi6 tbedeferiniin-ed ýby a method acceptable to the NRC).
(3) Repair or replace the affected locations before exc'eedling a CUF of 1.0.
Should PINPS select the option to manage the aging effects due to environmental-assisted fatigue during the period of extended operation, details of the aging management program such as scope, qualification, method, and frequency will be submitted to the NRC at least 2 years prior to the period of extended operation.
June 8, 2012 June 8, 2010 for submitting the aging management program if PINPS selects the option of managing the affects of aging due to environmentally assisted fatigue.
Letters 2.06. 064 and 2.06.081 4.3.3/ Audit Items 302, 346 32 Implement the enhanced Bolting Integrity Program June 8, 2012 Letters Audit items described in Attachment C of Pilgrim License 2.06.064 364, 373, Renewal Application Amendment 5 (dated July 19, and 389, 390, 2006, 2.06.064).
2.06.081 432, 443, 470 5
- COMMITMENT IMPLEMENTATION SOURCE Related SCHEDULE LRA Section No./
_______Comments 33 PNPS will inspect the inaccessible jet pump thermal As stated in the Letter Audit Items sleeve and core spray thermal sleeve welds if and commitment 2.06.057 320, 488 when the necessary technique and equipment become available and the technique is demonstrated by the vendor, including delivery system.
34 Within the first 6 years of the period of extended June 8, 2018 Letter Audit Items operation and every 12 years thereafter, PNPS will 2.06.057 320, 461 inspect the access hole covers with UT methods, and Alternatively, PNPS will inspect the access hole 2.06.089 covers in accordance with BWRVIP guidelines should such guidance become available.
35 At least 2 years prior to entering the period of June 8, 2012 Letters Audit Item extended operation, for reactor vessel components, Jue8 00fr2.06.064 345 including the feedwater nozzles, PNPS will implement Junettn 8,200eo and one or more of the following:
subiting te2.06.081 (1) Refine the fatigue analyses to determine valid management CU~s less than 1. Determine valid CU~s based on program if PNPS numbers of transient cycles projected to be valid selects the for the period of extended operation. Determineopinf CU~s in accordance with an NRC-approved mngn h
version of the ASMVE code or NRC-approved manfcsfaging.th alternative (e.g., NRC-approved code case).
afetofgi.
(2) Manage the effects of aging due to fatigue at the affq~ted locations by an inspection program that has,been reviewed and approved by the NRC J
(e.g.; periodic non-destructive examination of the "16feted'locations at inspection intervals to ber d:66ierhined by a method acceptable to the NRC).
(3), Flepair of replac6 thafecte locations before
.4 ex~ceedingl a CUE of.1.0.............
Should PNPS select the option to manage the aging effects due to fatigue during the period of extenided operation, details of the aging management program such as scope, qualification, method, and frequency will be submitted to the NRC at least 2 years prior to
___the period of extended operation.____
36 To ensure that significant degradation on the bottom June 8, 2012 Letter Audit Items of the condensate storage tank is not occurring, a 2.06.057 320, 363 one-time ultrasonic thickness examination in accessible areas of the bottom of the condensate storage tank will be performed. Standard examination and sampling techniques will be utilized.__________________
6
- COMMITMENT IMPLEMENTATION SOURCE Related SCHEDULE LRA Section No./
Comments 37 The BWR Vessel Internals Program includes June 8, 2012 Letter A.2.1.8/
inspections of the steam dryer. Inspections of the 2.06.089 Conference steam dryer will follow the guidelines of BWRVIP-.1 39 call on and General Electric SIL 644 Rev. 1.
September 25, 2006 38 Enhance the Diesel Fuel Monitoring Program to June 8, 2012 Letter B.1.10/Audit include periodic ultrasonic thickness measurement of 2.06.089 Item 565 the bottom surface of the diesel fire pump day tank.
The first ultrasonic inspection of the bottom surface of the diesel fire pump day tank will occur prior to the period of extended operation, following engineering analysis to determine acceptance criteria and test locations. Subsequent test intervals will be
____determined based on the first inspection results.
39 Perform a one-time inspection of the Main Stack June 8, 2012 Letter B.1.23/
foundation prior to the period of extended operation.
2.06.094 Inspection
__________________________________Item 581 40 Enhance the Oil Analysis Program by documenting June 8, 2012 Letter B. 1.22/
program elements 1 through 7 in controlled 2.06.094 Inspection documents. The program elements will include Items 553, enhancements identified in the PNPS license renewal 589 application and subsequent amendments to the application. The program will include-periodic sampling for the parameters specifiedUnder the Parameters Monitored/inspected att(ilbute of NUIREG-
-1801 Section XI. M39, Lubrctn Oi 6nlss h
-controlled
-documents will specify appropriate, acceptance criteria and corrective actions in the~event.,,-...,.
accep~tance criteria are not met. The basis for acceptance criteria will be defined.__________________
- .41.
Enhance the Containment Inservice Inspection (CII)
June 8,'2012 Letter A.-2.1.17 and Program to require augmented inspection in 2.06.094 B-.1 -A6.1 accordance with ASME Section XI IWE-1240, of the drywell shell adjacent to the sand cushion following
___indications of water leakage into the annulus air gap.
I________________
7
ATTACHMENT B to Letter 2.06.094 (4 pages)
Response to Request for Additional Information on LRA Section B.1.16.1 Containment Inservice Inspection U
)
'I
B.1.1 6.1 Containment Inservice Inspection (C1I)
RAI B.1.16.1:
., In the Pilgrim Nuclear Power Station (PNPS) aging management program B.1.16.1 of the license renewal application (LRA), the applicant stated: "CII inspections during RFO 15 (April 2005) did not reveal evidence of loss of material. Absence of degradation provides evidence that the program is effective for managing the aging effect." In addition, in the LRA, Amendment 2 (ML061710422) under, "Ongoing Actions to Prevent Drywell Corrosion," PNPS stated, "Functional checks are performed each refueling outage on the flow switch associated with the bellows seal leakage monitoring system."
However, the recent NRC Region I inspection team observations indicated that:
- a. The flow switch in the bellows rupture drain had failed its surveillance in December 2005, and has not been fixed or evaluated. In addition, the flow switch also had been failed in 1999.
- b. Monitoring of other drains has been inconclusive and not well documented.
- c. The torus room floor has had water on the floor on multiple occasions.
Please provide a detailed discussion, including record, corrective actions taken, and preventive action in response to this plant specific operating experience and discuss its impact on the aging management of potential loss of material due to corrosion in the inaccessible area of the Mark I steel containment drywell shell, including the sand pocket region for the period of extended operation.
Response toRAIlB.1.1 6.1:,*...
'a.
On Dece~mber 28; 2005, the flow' switch-in the-bellows-rupture drain (FS-4803) failedftoO3/4.n S.S
'respond acceptably during testing.' During the test, water~is poured in'to an ýupstream -test_;
funnel. The Water normally flows Iinto the flow switch, actuates the-switch", and discharges t&6-the radwaste system. On this occasion, the flow switch did not alarm; the water fil~led the pip5ing until it overflowed the test funnel. This was caused by blockage of the passages around the perimeter of the-baff le of the f low switch. The apparent cause of the blockage was accumulation of crud and corrosion products from the test funnel and associated piping during routine testing.
Corrective actions The flow switch associated with the bellows rupture drain was replaced with a new switch on November 17, 2006.
Preventive actions Flow switches FS-4802 and FS-4806 are the same Peeco flow switches as FS-4803.
FS-4802 provides alarming functions for the vessel to drywell bellows rupture. FS-4806 provides alarming functions for fuel pool gate leakage. Maintenance requests were initiated to replace these flow switches.
A preventive maintenance task was established to replace flow switches FS-4802, FS-4803, and FS-4806 every 15 years.
Functional checks of the flow switch in the bellows rupture drain (FS-4803) are performed each refueling outage and repair, if necessary, is tracked under the work management process.
Impact on management of loss of material due to corrosion in the inaccessible areas of the containment drvwell shell If leakage occurred with the flow switch in the bellows rupture drain (FS-4803) failed, leakage would enter the 8" casings where it would be indicated by leakage from the four 3/" refueling bellows rupture tell-tale drains. Daily operator rounds have not detected leakage from these tell-tale drains.
If FS-4803 has failed and leakage is not detected from the 3/" refueling bellows rupture tell-tale drains before the 8" casings fill up and water rises above the 1/4" thick form plate that surrounds the ledge, leakage can overflow into the annulus air gap. A sheet metal cover plate shields the sand pocket against leakage from above. Four 4" annulus air gap drain lines direct water from above the sand pocket to the torus room floor. These drains are checked by IS! VT-2 certified inspectors for leakage twice every refuel outage, once after flooding up and again prior to flooding down, No leakage has ever been detected from these drains. Buckets placed under these annulus air gap drains in the 1980's are dry with no evidence of previous water accumulatio~n.
Since leakage has not been detected at the other drains and actions have been taken to preclude recurrence, the temporary inoperability of FS-4803 does not impact management of loss of material due to corrosion in the inaccessible areas of the containment drywell shell for the period of extended operationh.,
- b. The 4" annulus air gap. drains -located in" bays §2, 6, 10 and 14 of the torus room adjacent to the reactor pedestal discharge approximately. 6" above the floor (buckets are placed on the~
floor unerthe-,dra~ins)-. The four drains arekexamined for leakage-twice -during every ref ueling -outage as augmented exams-, rCidr, the station's :I WE, code containment inspection programn.- They are bchec~ked for leakage by.V-T-2 certified -examiners during Outageg once after flooding the refueling cavity and again prior to draining the refueling cavity at the close of the outage. Leakage, if present, would discharge into the buckets on the floor of the torus room as the drain lines are not directed to floor drains. Because of the buckets under the drains, leakage from the four annulus air gap drains (see response to c.) could not be mistaken for groundwater intrusion in the torus room.
Corrective actions See Preventive actions below for measures to improve the documentation of drain monitoring activities.
Preventive actions Surveillance of the four 3/" refueling bellows rupture tell-tale drains on the Reactor Building 74 foot elevation is performed and documented twice daily during reactor building operator rounds when in refueling mode. Visual observation of the tell-tale drains during operator rounds has not detected leakage.
, 2 2
Impact on management of loss of material due to corrosion in the inaccessible areas of the containment drvwell shell Preventive actions discussed above provide additional assurance that leakage into the annulus air gap will be prevented.
- c. In September 2006, standing water was observed in torus bays 6, 7, 10 and 13. Although dry, the appearance of the floor in bay 11 indicated it had been wet. Dampness and corrosion was in evidence around the Williams Rock Anchor baseplates at torus saddles 6, 10,.11, 12, 13, 14 & 15. There was no condensation on the torus itself, nor any obvious evidence of process system leakage.
The locations and extent of the observed conditions are consistent with conditions investigated and evaluated in 1996. At that time, a thorough investigation concluded that the most probable cause of water on the torus room floor was groundwater infiltration by-passing the membrane system that encapsulates the reactor building foundation. A test performed in 1996 demonstrated that water was emerging from the anchor bolt holes for the Williams Rock Anchors at the torus saddles. Buckets under the air gap annulus drains that continue to remain dry ensure that those drains are not contributing to the water observed on the floor.
Corrective actions None.
Preventive actions An assessment of the~it-orus saddle anchor bolts in 1999 concluded that active corrosion of the embedded anchor bolts was not occurring. These supports and associated bolting are inspected under the1 C.6ntainment Inservice Inspection Program to assure that effects of agin wil bemang~d uchthat they will continue to perform their intendled function consistent with the 'currbnt licensing basisf fr~the p~eriod of extended,operation.
-7;
-The. febasibility of pressure~ grouting the-.torus room-f loor or correcting the condition of floJ surface drainage to allow water to flow to the floor drains is being evaluated.
Impact on, management of loss of material due to corrosion in the inaccessible areas of the containment drvwell shell Since the water on the torus room floor is not attributed to refueling cavity leakage or leakage into the annulus air gap, this condition has no impact on management of loss of material due to corrosion in the inaccessible areas of the containment drywell shell for the periodl of extended operation. Collection buckets under the annulus air gap drains continue to remain dry.
Other Considerations The ongoing actions to prevent and identify drywell corrosion described in LRA Amendment 2 were assessed and strengthened by addition of an enhancement to assure the drywell shell adjacent to the sand cushion is inspected following indications of water leakage into the annulus air gap.
3
The condition of the sealant between the shield at the base of the annulus air gap and the drywell shell is uncertain because of its inaccessibility. Also due to. inaccessibility, the absence of residual moisture in the sand cushion following leakage cannot be confirmed.
For these reasons, augmented inspection of the drywell shell in the sand cushion area is warranted following indications of leakage into the annulus air gap.
If leakage is detected or suspected into the inaccessible area adjacent to the exterior of the drywell shell (the annulus air gap), PNPS will document and evaluate the condition in accordance with the corrective action program. Appropriate corrective actions to correct the cause of the leakage and to address the potential degradation of the drywell shell caused by the condition would be initiated. To assure corrective actions include augmented inspections performed in accordance with ASME Section XI IWE-1240, the Containment Inservice Inspection (CII) Program is enhanced to require augmented inspection of the drywell shell adjacent to the sand cushion following indications of water leakage into the annulus air gap.
This enhancement, License Renewal Commitment 41, requires the following revisions to the LRA.
LRA Section B.1.16.1, Containment Inservice Inspection (CII), is revised to include the following.
Enhancements The following enhancement will be implemented prior to the period of extended operation.
Attributes Affected Enhancements
- 3. Parameters monitored and Administrative controls are enhanced to inspected
'~require augmented inspection in accordance with ASME Section XI IWE-1240 of the drywell s~hell adjacent to the sand cushion' fdllowin'g indications of 'Water
_______________________leakageinto the annuiiisair gap.
LRA Section A.2.1.17, Inservice Inspec 'tion - Containment Inservice Inspection (CII)
Program, is revised to include the following statement.
."License Renewal Commitment 41 specifies an enhancement to this program."
4
ATTACHMENT C to Letter 2.06.094 (4 pages)
Response to Request for Additional Information on LRA Appendix E Concerning Severe Accident Mitigation Alternatives
NRC RAI 1:
Provide the complete MACCS2 user input file used for the revised calculations described in Entergy's July 5, 2006 response to RAls. This should include all files necessary to reproduce Entergy's calculations, i.e., the ATMOS, EARLY, CHRONO files, as well as any auxiliary input files containing meteorological data, dose conversion factors, food chain data, and site data.
This should be provided in 'the form of a CID. Also identify and discuss any changes made to the MACCS2 source code.
Response to RAI 1:
A complete set of user prepared files is provided in the enclosed compact disc (CID). The files include ATMOS, EARLY, CHRONO, meteorological data, dose conversion factors, food chain data, and site data with file names ATMBP1Q, EARBP1, CHRBP1, MET01iP, DOSIDATA, SAMP -A, and SITEP, respectively. In addition, a specific ATMOS file named ATMPS2Q is also included to reflect reduced source terms for the filtered containment vent case (SAMA 2).
No changes were made to the MACCS2 source code.
NRC RAI 2:
Provide updated versions of Environmental Report Tables E.1I-14 through E.11-16, based on the revised reactor core radionuclide inventories.
Response to RAI 2:
Updated Tables EA1-14, E.1 -15, and E.1 -116 are provided as follows:'
I
Table E.1-14 Updated PNPS Core Inventory (Becquerels)'
Nuclide Co-58 Co-60 Kr-85 Kr-85m Kr-87 Kr-88 Rb-86 Sr-89 Sr-90 Sr-91 Sr-92 Y-90 Y-91 Y-92 Y-93 Zr-95 Zr-97 Nb-95 Mo-99 Tc-99m Ru-i 03 Ru-105 RU-106 Rh-i 05 Sb-127 Sb-129 Te-1 27 Te-i 27mn
.Te-1 29 Te-i 29m Inventory 1.15E+16 1.37E+1 6 1.88E+16 6.84E+17 1.24E+1 8 1.68E+18 1.05E+1 5 2.08E+1 8 1.84E+1i7 2.71 E+i 8 2.83E+1 8 1.58E+1i7 2.54E+1 8 2.84E+1 8 3.23E+1 8 3.34 E+ 18 3.44E+1 8 3.16E+1 8 3.65E+1 8 3.1 5E+1 8 2.77E+1 8 1.85E+1 8 7.52E+1 7 1.38E+18 1.74E+1 7 6.06E+1 7 1.69E+1 7 2.27E+1 6 5.68E+1 7 1.49E+17 Nuclide Te-131m Te-i32 1-131 1-132 1-133 1 -134 1-135 Xe-133 Xe-i135 Cs-i 34 Cs-136 Cs-i 37 Ba-1 39 Ba-140 La-i 40 La-141 La-142 Ce-141 Ce-143 Ce-144 Pr-143 Nd-i47 Np-239 Pu-238 Pu-239 Pu-240 Pu-24i Am-241 Cm-242 Cmn-244 Inventory 2.87E+/-1 7 2.80E+1 8 1.94E÷18 2.85E+18 4.07E+1 8 4.45E+1 8 3.83E+1 8 4.07E+18 9.68E+17 3.97E+1 7 8.51 E+1 6 2.38 E+i17 3.75E+18 3.70E+18 3.77E+i18 3.48E+1i8 3.35E+1 8 3.36E+1 8 3.27E+1 8 2.18E+1 8 3.20E+1 8 1.43E+18 4.26E+1 9 2.96E+1,5 7.51 E+ 14 9.41 E+"14' 1.62E+17 1.65E+14, 4.35E+1 6 2.35E+15 VDerived from Reference E.1-21 for a power level of 2028 MW(t) w ith an increase of 25% for long half-life nuclides Sr-90, Cs-134, and Cs-137 to reflect the average core exposure at 2
Table E.1-15 Updated Base Case Mean PDR and QECR Values Off site Population Off site Population Economic Dose Risk Economic Cost Release Frequency Dose Cost (PDR)
Risk (OECR)
Mode
(/yr)
(person-sv)1
($)
.(person-rem/yr)
($IYr)
CAPB-I 9.51 E-08 5.77E-01 3.82E+06 5.49E-062 3.63E-01 CAPB-2 1.27E-08 1.21 E+02 7.18E+06 1.53E-04 9.08E-02 CAPB-3 2.39E-09 1.28E+02 7.31 E+06 3.06E-05 1.75E-02 CAPB-4 3.29E-09 1.50E+04 4.93E+09 4.94E-03 1.62E+01 CAPB-5 2.73E-09 1.92E+04 6.15E+09 5.24E-03 1.68E+01 CAPB-6 7.95E-09 1.60E+04 4.35E+09 1.27E-02 3.46E+01 CAPB-7 7.93E-09 1.78E+04 5.25E+09 1.41 E-02 4.16E+01 CAPB-8 2.06E-08 4.42E+04 1.68E+10
- 9. 1OE-02 3.46E+02 CAPB-9 9.25E-09 2.54E+04 9.26E+09 2.35E-02 8.56E+01 CAPB-10 8.53E-08 4.74E+04 1.72E+10 4.05E-01 1.47E+03 CAPB-1 1 4.35E-08 3.72E+04 1.29E+10 1.62E-01 5.61 E+02 CAPB-12 1.70E-06 1.18E+02 4.85E+06 2.01 E-02 8.25E+00 CAPB-1 3 2.30E-09 8.48E+03 8.36E+08 1.95E-03 1.93E+00 CAPB-14 2.26E-06 1.69E+04 4.96E+09 3.82E+00 1.12E+04 CAPB-15 2.12E-06 4.65E+04 1.80E+10 9.86E+00 3.82E+04 CAPB-16 1.18E-09 1.93E+04 6.28E+09 2.27E-03 7,40E+00 CAPB-17 6.91 E-09 5.12E+04 1.98E+10 3.54E-02 1.37E+02 CAPB-18 4.61E-10 2.58E+04 8.43E+09 1.19E-03 3.88E+00 CAPB-19 2.43E-08 5.72E+04 2.11 E+10 1,39E-01 5.12E+02 Totals 1.46E+01 5.26E+04
- 1. 1lsv 100 rem
- 2. 5.49E-06 (person-rem/yr) =9.51 E-08 (Iyr) x 5.77E-01 (person-sv) x 100 (rem/sv) 3
Table E.1 -16 Updated Summary of Offsite Consequence Sensitivity Results Population Dose (person-sv)
Ottsite Economic Cost ($)
Release Base Case 2-hr delayed Lower speed Base Case 2-hr delayed Lower speed Mode evacuation of evacuation evacuation of evacuation CAPB-1 5.77E-01 5.77E-01 5.77E-01 3.82E+06 3.82E+06 3.82E+06 CAPB-2 1.21 E+02 1.21 E+02 1.21 E+02 7.18E+06 7.18E+06 7.18E+06 CAPB-3 1.28E+02 1.28E+02 1.28E+02 7.31 E+06 7.31 E+06 7.31 E+06 CAPB-4 1.50E+04 1.51 E+04 1.51 E+04 4.93E+09 4.93E+09 4.93E+09 CAPB-5 1.92E+04 1.93E+04 1.93E+04 6.15E+09 6.15E+09 6.15E+09 CAPB-6 1.60E+04 1.61 E+04 1.61 E+04 4.35E+09 4.35E+09 4.35E+09 GAPB-7 1.78E+04 1.79E+04 1.79E+04 5.25E+09 5.25E+09 5.25E+09 CAPB-8 4.42E+04 4.49E+04 4.50E+04 1.68E+10 1.68E+10 1.68E+10 CAPB-9 2.54E+04 2.55E+04 2.56E+04 9.26E+09 9.26E+09 9.26E+09 CAPB-10 4.74E+04 4.77E+04 4.79E+04 1.72E+10 1.72E+10 1.72E+10 CAPB-1 1 3.72E+04 3.75E+04 3,76E+04 1.29E+10 1.29E+10 1.29E+10 CAPB-12
- 1. 18E+02'
- 1. 18 E+02
- 1. 19E+02 4.85E+06 4.85E+06 4.85E+06 CAPB-13 8.48E+03 8.48E+03 8.49E+03 8.36E+08 8.36E+i08 8,36E+08 CAPB-14 1.69E+04 1.69E+04 1.69E+04 4.96E+09 4.96E+09 4.96E+09 CAPB-15 4.65E+04 4.67E+04 4.69E+04 1.80E+10 1.80E+10 1.80E+10 CAPB-1 6 1.93E+04 1.94E+04 1.95E+04 6.28E+09 6.28E+09 6.28E+09 CAPB-17 5.12E+04 5.14E+04 5.17E+04 1,98E+10 1.98E+10 1.98E+10 CAPB-18 2.58E+04 2.59E+04 2.61 E+04 8.43E+09 8.43E+09 8.43E+09 CAPB-19 5.72E+04 5.75E+04 5.78E+04 2.11 E+10 2.11 E+1O0 2.11 E+1 0 4
ATTACHMENT D to Letter 2.06.094 (4 pages)
Changes to the LRA Stemming from NRC Region I Inspection of the LRA
Inspection item 526:
LRA Section B.1..15, attribute 4, Detection of Aging Effects, is revised as follows (underlined words added):
- 4. Detection of Aging Effects Loss of material is the aging effect managed by this program. Representative tubes within the sample population of heat exchangers will be eddy current tested at a frequency determined by internal and external operating experience to ensure that effects of aging are identified prior to loss of intended function. Visual inspections of accessible heat exchangers will be performed on the same frequency as eddy current inspections.
An appropriate sample population of heat exchangers will be determined based on operating experience prior to inspections. The sample population of heat exchangers will be determined based on the materials of construction of the heat exchanger tubes and the associated environments as well as the type of heat exchanger (for example, shell and tube type). At least one heat exchanger of each type. material and environment combination will be included in the sample population. Inspection can reveal loss of material that could result in degradation of the heat exchangers. Fouling is not addressed by this program.
Inspection items 553 and 589:
LRA Section B.1.22 is amended as follows (underlined words added, strike-outs deleted):
NUREG-1801 Consistency The Oil Analysis Program at PNPS is consistent with the program described in NUREG-1801,Section XI.M39, Lubricating Oil Analysis, with aR-eXeeptieR exceptions and enhancements.
Exceptions to NUREG-1 801 The Oil Analysis Program at PNPS is consistent with the program described in NUREG-1801,Section XI.M39, Lubricating Oil Analysis, with the following exeeptieR exceptions.*
Attributes Affected Exception
- 3. Parameters Monitored/Inspected
~
Flash point is not determined for sampled oil.'
- 3. Parameters Monitored/Inspected Neutralization number and fuel dilution are not monitored for every oil sample.2
- 1. Analyses of filter residue or particle count, viscosity, total acid/base (neutralization number),
water content, and metals content provide sufficient information to verify the oil is suitable for continued use.
- 2. The parameters monitored regularly (presence of moisture, abnormal wear products, and changes in viscosity) are those directly related to age-related degradation of components containing lube oil. As noted in the Mechanical Tools, aging effects are not observed in fuel oil and lubricating oil systems unless moisture or other contaminants are oresent. Therefore.
I
monitorina and trendina of particle count, water content and viscosity in lubricating oil provide reasonable assurance that effects of aoina will be manaaed such that applicable components will continue to perform their intended function consistent with the current licensing basis for the period of extended operation.
Enhancements The following enhancements will be initiated prior to the period of extended operation.
Attributes Affected Enhancements
- 1. Scope of Program The Oil Analysis Program will be enhanced to periodically change CRID pump lubricating oil. A particle ee+Uit check and E~heE~k analysis for water will be performed on the drained oil to detect evidence of abnormal wear rates, contamination by moisture, or excessive corrosion.
- 3. Parameters Procedures for security diesel and reactor Monitored/Inspected water cleanup pump oil changes will be enhanced to obtain oil samples from the drained oil. Procedures for lubricating oil analysis will be enhanced to specify that a particle GGOMi4 check and dheek analysis for water are performed on oil samples from the fire water pump diesel, security diesel, and reactor water cleanup pumps.
- 6. A6deptance Criteria The Oil Analysis Program will be enhanced to proceduralize the acceptance criteria and corrective actions described in this program-decriýtion:
-. Lcene.rene~wal.commitment 40 is added as follows:
Prior to the period of extended operation, the PNPS Oil Analysis Program will be enhanced by documenting program elements 1 through -7 in. controlled documents. The program elements will include enhancements identified in the PNPS license renewal application and subsequent amendments to the application. The program will include periodic sampling for the parameters specified under the Parameters Monitored/Inspected attribute of NUREG-1 801,Section XI.M39, Lubricating Oil Analysis.
The controlled documents will specify appropriate acceptance criteria and corrective actions in the event acceptance criteria are not met. The basis for acceptance criteria will be defined.
Inspection item 581:
PN PS, will perform a one-time inspection of the main stack foundation prior to the period of extended operation. License renewal commitment 39.
2
Inspection item 583:
The table in the program description of LRA Section BA1.23 is revised to include the following line item for verifying the absence of cracking for miscellaneous items not covered by a fatigue TLAA:
Inspection for mechanical One-time inspection activity will confirm that cracking due to fatigue fatigue is not occurring or is so insignificant that an aging management program is not warranted.
Inspection item 586:
Confirmation of the screening results for nonsaf ety-related SSCs connected to safety-related SSCs review of AMRM-30, Aging Management Review of Nonsafety-related Systems and Components Affecting Saf ety-related Systems, is being performed to assure that all components up to the seismic or equivalent anchor are represented in the summary tables. As a result of this effort, the following components are added to the summary tables:
Table 3.3.2-14-15: Heating Ventilation and Air Conditioning Systems Component
-Intended
-Material Environment Aging Effect Aging NUREG-Table
-Notes.'
Type Function Requiring Management 1801 Vol.
1 Item Presur
-- caron Air-idoo
-Management Programs 2 Item Fansur housbng Air - insteel System VILF2-2 3.3.1-A Fa husn.
ouday stel (e)Loss of material -
walkdown (A-1 )
-56 A___
Fnhousing Pressure Carbon Air -indoor Loss of material system V.13_
3.2.1-E Fan
-boundary I~ steel (int)
(E-25)
-32 E
Table 3.3.2-14-33: Standby Liquid Control System Component
-Intended
-Material Environment Aging Effect [
Aging
-- NUREG-Table
-Notes Type Function Requiring Management,.
.1801 Vol.
1 Item Mahagement.
Programs 2 Item, Tak Pressure SanesAir
- indoor VII.-15 3.3.1-A boundary
-steel.-J~
N--ne None1 (AP-17) 94 Tank Press~ure Stainless Air - indoor None None G
Additional Clarification:
LRA Table 3.3.2-3, Reactor Building Closed Cooling Water System (RBCCW) Summary of Aging Management Evaluation, is revised to add the following line items to address the Fuel Pool heat exchangers, Reactor Water Cleanup System (RWCU) demineralizer non-regeneration
'heat exchangers, and Recirculation pump seal water coolers, which were inadvertently omitted from the summary table.
Component 1Intended Material Environment Aging Effect Aging NuREG-Table Notes Type IFunction Requiring Management 1801 Vol.
1 Item Management Programs 2 Item Heat Pressure Stainless Treated water Loss of material Water ivIl.c2-1o 3.3.1-D exchanger boundary steel (ext)
Chemistry I(A-52) 50 (tubes)
Control -
Closed Cooling
~~~~~Water Heat Pressure Stainless Treated water Loss of material HeatH exchanger boundary steel (ext)
- wear Exchanger (tubes)
Monitoring____
3
Heat Pressure Stainless Treated water Loss of material Water VII.C2-10 3.3.1-D exchanger boundary steel
> 140'F (ext)
Chemistry (A-52) 50 (tubes)
Control -
Closed Cooling Water Heat Pressure Stainless Treated water Cracking Water VII.E3-2 3.3.1-D exchanger boundary steel
> 1400F (ext)
Chemistry (A-68)
.46 (tubes)
Control -
Closed Cooling Water Heat Pressure Stainless Treated water Loss of material Heat H
exchanger boundary steel
> 140*F (ext)
- wear Exchanger
_tbs Monitoring Heat Pressure Stainless Treated Water Loss of material Water VII C2-1 0 3.3.1-
-D exchanger boundary steel
> 2700'F (ext)
Chemistry (A-52) 50 (tubes)
Control -
Closed Cooling Water Heat Pressure Stainless Treated water Cracking Water VI1. E3-2 3.3.1-0 exchanger boundary steel
> 270' F (ext)
Chemistry (A-68) 46 (tubes)
Control -
Closed Cooling Water Heat Pressure Stainless Treated water Cracking -
One-time VII.E3-14 3.3.1-C exchanger boundary steel
> 270*F (ext) fatigue Inspection (A-62) 2 Heat Pressure Stainless Treated water Loss of material Heat H
exchanger boundary steel
> 270'F (ext)
-wear Exchanger
___es Monitoring LRA Section B.1.15, Heat Exchanger Monitoring, Program Description, third paragraph, is revised as follows (underlined words added, strike-outs deleted):
Representative tubes within the sample population of heat exchangers will be eddy current tested at a frequency determined by internal and external operating experience to ensure that effects of aging are identified prior to lo~ss of intended function. Along with each eddy current test, visual inspections will be perf&:rr"ýed on accessible heat exchanger heads, covers, and, tube' sheets to monitor s'urface condition for indications of loss of-material. he-6ample population of heat exchangers includes the RHR heat exchangers, RHR pump seal cooler heat exchangers, core spray pump motor thrusVýt' ~-
bearing lube oil coolers, HPCI gland seat condenser, HPCI turbine lube oil cooler, ROIC lube oil cooler, recirculation pump motor generator set fluid coupling oil and bearing coolers, CRD pump oil coolers, recirculation pump motor lube oil coolers, clean up recirculation pump lube oil coolers and stuffing box cooler, fuel pool heat exchangers, CRD pump thrust bearing 'coolers, recirculation pump seal water coolers, clean up demineralizer non-regeneration heat exchangers, and EDG lube oil coolers.
4