ML091700648

E-mail from J. Richmond of USNRC to D. Tifft of USNRC, Regarding Oc Draft IR for In-Process Review

ML091700648
Person / Time
Site:	Oyster Creek
Issue date:	01/09/2009
From:	Richmond J NRC Region 1
To:	Doug Tifft NRC Region 1
References
FOIA/PA-2009-0070, IR-08-007
Download: ML091700648 (28)

Text

A-Sarah Rich From: John Richmond, V-'S Sent: Friday, January b9, 2009 3:39 PM To: Doug Tifft Cc:. Richard Conte; Michael Modes

Subject:

OC Draft IR for In-Process Review Attachments: OC 2008-07 LRI rev-2.doc h~nuibif n Inthis macr was deleted In molance withhe Freedom of Information AcL Exemptions FOW/*PA -;;.*3 -

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CC: Richard Conte <Richard.Conte@nrc.gov>, Michael Modes

<Michael. Modes@nrc.gov>

Date: Fri, 9 Jan 2009 15:39:01 -0500

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OC Draft IR for In-Process Review Thread-Topic: OC Draft IR for In-Process Review Thread-Index: Aclymk31sRRtTG6/Th2f8AQm7z9yLA==

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AJ T. fH.. 6 8 Mr. Charles G. Pardee Chief Nuclear Officer (CNO) and Senior Vice President Exelon Generation Company, LLC 200 Exelon Way Kennett Square, PA 19348

SUBJECT:

OYSTER CREEK GENERATING STATION - NRC LICENSE RENEWAL FOLLOW-UP INSPECTION REPORT 05000219/2008007 Dear Mr. Pardee On December 23, 2008, the U. S. Nucle egdl1t,,,,ommi'iFn (NRC) completed an inspection at your Oyster Creek GeneratiStatiorl e;inclog,"*report documents the inspection results, which were discussed o* Decep, 3 .2O8, With Mr. T. Rausch, Site Vice President, Mr. M. Gallagher;,' ieePresident"Licese Renewa and other members of your staff in a telephone conference observed by represidtatives from the State of New Jersey.

An appeal of a licensing board decision regarding' the Oyster Creek application for a renewed license is pending befotre4 qnpe ibsn.s*io*

Co The NI concluded Oyster Creek should not enter the extendedpeeiod of opewatlon ithout directly observing continuing license renewal activities at OysterC*ke " 6,vefore, the NRC performed an inspection using Inspection Procedure (IP) 71 00§ Inspection for License Renewal" and observed Oyster Creek license It-Approv reneOtVactivities durinnq tje last refuel outage prior to entering the period of extended opera , i *  :

IP 71003 veifie.s license conditions added as part of a renewed license, license renewal commitments, seected aging management programs, and license renewal commitments revised after the':renewed license was granted, are implemented in accordance with Title 10 of the Code of Federal ,*.*pltions (CFR) Part 54, "Requirements for the Renewal of Operating Licenses for NuclearAPower Plants." Because the application for a renewed license remains under Commission review for final decision, and a renewed license has not been approved for Oyster Creek, the standards used to judge the adequacy of selected IP 71003 inspection samples do not apply. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel. The enclosed report records the inspector's observations, absent any conclusions of adequacy, pending the final decision of the Commissioners on the appeal of the renewed license.

f C. Pardee 3 In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records. (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web-site at http://www.nrc.,qov/NRC/ADAMS/index.html (the Public Electronic Reading Room).

Sincerely, Richard Conte, Chief Engineering Branch 1 Division of Reactor Safety Docket No. 50-219 License No. DPR-16

Enclosure:

Inspection Report No. 05000219/200800*7

':i:' >.  :.:: S'i:i'::.::...' *sS "" ' :' :

• C. Pardee 4 In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web-site at http:l/www.nrc.gov/NRC/ADAMS/index.html (the Public Electronic Reading Room).

Sincerely, Richard Conte, Chief Engineering Branch 1 Division of Reactor Safety Docket No. 50-219 License No. DPR-16

Enclosure:

Inspection Report No. 650002r9/2008007

• '\ . . .',".\ \ ,;  !*..:;:

SUNSI Review Complete: _ __eviewe Initials)

ADAMS ACCESSION NO1.~ _______

DOCUMENT NAME: C:\DoQ\,.OC LRI 2008-07\. Report\OC 2008-07 LRI rev-2.doc After declaring this document "AnzO ficial Agency Record" it will be released to the Public.

To receive a copy of this document, indicate in the box: "C" = Copy without attachment/enclosure "E" = Copy with attachment/enclosure "N" = No copy OFFICE RI/DRS RI/DRS RI/DRP RI/DRS NAME JRichmond/ RConte/ RBellamy/ DRoberts/

DATE / /09 / /09 / /09 / /09 OF CAL RE ORD CO

C. Pardee 2

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C. Pardee 3 Distribution w/encl:

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C. Pardee 4 Distribution w/encl: (VIA E-MAIL)

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U. S. NUCLEAR REGULATORY COMMISSION REGION I Docket No.: 50-219 License No.: DPR-16 Report No.: 05000219/2008007 Licensee: Exelon, LLC Facility: Oyster Creek Generating Station Location: Forked River, New Jersey J Dates: October 27 to.November 7, 2008 (on-site inspection)

November 13,i5, and 17, 2008 (on-site inspection)

November 16to December .23, 2008 (in-office review)

Inspectorsw J. Richmo~nd, Lead M. ModeqSenior Reactor Engineer G. Meyerý%6'ior Reactor Engineer T. 'Hara, Reator Inspector J. Heinly, Reactor Engineer J. Kulip, Resident Inspector, Oyster Creek Approved by: Richard Conte, Chief Engineering Branch 1 Division of Reactor Safety ii

SUMMARY

OF FINDINGS IR 05000219/2008007; 10/27/2008 - 12/23/2008; Exelon, LLC, Oyster Creek Generating Station; License Renewal Follow-up The report covers a multi-week inspection of license renewal follow-up items. It was conducted by five region based engineering inspectors. The inspection was conducted in accordance with Inspection Procedure 71003 "Post-Approval Site Inspection for License Renewal." Because the application for a renewed license remains under Commission review for final decision, and a approved for Oyster Creek,¶ renewed license has not been (b)(5) .The report(b)(5) documents the inspector observations, absent any conclusions of adequacy, pending the final decision of the Commissioners on the appeal of the renewed license.

2 REPORT DETAILS

4. OTHER ACTIVITIES (OA) 40A2 License Renewal Follow-up (IP 71003)

1. Inspection Sample Selection Process This inspection was conducted in order to observe AmerGen!'s ontinuing license renewal activities during the last refueling outage prior to Oyster Creek (OC) entering the extended period of operation. The inspection team selected a number of inspection samples for review, using the NRC accepted guidance based on their importance in the license renewal application process, as an opportunity to makedobservations on license renewal activities. Because the application for a renewed license remains under Commission review for final decision, and a renewed license has not been approved for Oyster Creek,c_ (b)(5)

Accordingly, the inspectors recorded observations wi,:thout any assessment of implementation adequacy or safety significance. Inspection observations were considered, in light of pending lC~o5!icense rrwal commitments and license conditions, as documented in NLREG-8 Safety tuation Report (SER) Related to the License Renewal of Oyster Creek Gehner~ng Statio;'," as well as programmatic performance under on0going implern ntation of 10 FPIR 50 current licensing basis (CLB) requirements.

The reviewed SER proposed: commitments and license conditions were selected based on several attributes includbug the risk s igificance using insights gained from sources such as the NRQ Signific Determination Process Risk Informed Inspection Notebook'~s,"' revisiott2;lhee extent an'driesu of previous license renewal audits and inspectils ofciging man:agement programs; the extent or complexity of a commitment;

• an the extent fiha bate.o inspection programs will inspect a system, structure, or

'component (SSC),o coM'o!ty group.

For each commitmet !,nd on a sampling basis, the inspectors reviewed supporting documents including bompleted surveillances, conducted interviews, performed visual inspection of structures and components including those not accessible during power operation, and observed selected activities described below. The inspectors also reviewed selected corrective actions taken as a consequence of previous license renewal inspections.

2. NRC Unresolved Item 10 CFR 50 existing requirements (e.g., current licensing basis (CLB) xxx USE words from PN

• The conclusions of PNO-1-08-012 remain unchanged

• An Unresolved Item (URI) will be opened to evaluate whether existin'g current licensing basis commitments were adequately performed and, if necessary, assess the safety significance for any related performance deficiency.

• The issues for follow-up include the strippable coating de-lamination, reactor cavity trough drain monitoring, and sand bed drain monitoring.

• The commitment tracking, implementation, and work control processes will be reviewed, based on corrective actions resulting from AmerGen's review of deficiencies and operating experience, as a Part 50 activity.

3. Detailed Reviews 3.1 Drywell Floor Trench Inspections

a. Scope of Inspection Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancements (5, 16, & 20), stated:

Perform visual test (VT) and ultrasonic test (UT) examinations of the drywell shell inside the drywell floor inspection trenches in bay 5 and bay 17 during the 2008 refueling outage, at the same locations that were examined in 2006. In addition, monitor the trenches for the presence of water during refuel~ing outages.

The inspectors independently performed direct field observations of the conditions in the trenches on multiple occasions during the outage and reviewed selected VT and UT examination records. The inspectors compared UT dataresults to licensee established acceptance criteria in Specification IS-318227-004, revision 14, Functional Requirements for Drywell Containment Vessel Tickness Examinations."

The inspectors reviewed Technical.Evajp.tion 330592,7.43, "Evaluation of 2008 UT Data of the Sand Bed Trenches," d.ted-1//8. The Evajuation determined that the UT thickness values satisfied minimurr. wall thi",,,,ssyalues*÷,general uniform thickness (e.g., average thickness of an area)4and fQl l'thinineed("'reas (e.g., areas 2 inches or less in diameter), as applicable. For UT data sets, such as 7x7 arrays (i.e., 49 UT readings in a 6 inch by 6 inch grid), the Evaluation calculated mean values, standard deviation, standard error, skewness, and kurtosis and determined that the data sets had a normal distribution. The Evaluation also compared the data set values to the corresponding 2006 values and concluded ithere were no significant differences and no observable on-gointgcorrosion. The insp ectors independently compared the UT data to thewcorresponding 2006 data values and to minimum thickness values established by d'*ign anal-i"'apd calculations.

.tihe inspectors reviewed Exelon UT examination procedures, interviewed nondestructive exmnation (NDE) technicians, reviewed NDE technician qualifications and certiffiations, and reviwed records of trench inspections performed during two forced plant outages during'tIhe last operating cycle.

b. Observations

• Remove & reinstall lower 6" of grout at bottom of Bay 5 trench

" Inspect caulk sealant (trench edge where concrete meets shell)

" Verify no water accumulation 3.2 Reactor Cavity Liner Strippable Coatinq

a. Scope of Inspection

J Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancement (2), stated:

A strippable coating will be applied to the reactor cavity liner to prevent water intrusion into the gap between the drywell shield wall and the drywell shell during periods when the reactor cavity is flooded. Refueling outages prior to and during the period of extended operation.

The inspector reviewed work order R2098682-06, "Coating application to cavity walls and floors."

b. Observations Strippable Coating De-lamination

• From Oct. 29 to Nov. 6, the strippable coating limited leakage into the cavity trough drain at less than 1 gallon per minute (gpm)

• On Nov. 6, the observed leakage rate in the cavity trough drain took a step change to 4 to 6 gpm

" Water puddles were subsequently identified in 4 sadn bed bays

• AmerGen identified several likely or contributing causes:

A portable water filtration unit was ffirQperly placed*in the reactor cavity, which resulted in flow discharged directly :on the strippable co6`4,

• An oil spill into the cavity may have affectfeýthe coatind;ý.itegrity No post installatiorflinsection of the coating had ben performed

• AmerGen stated follow-.up UTs w'll re-evaluate the drywell Siell next outage 3.3 Reactor Cavity Trouqh Drain: Iispection for Blockage

a. Scope of Inspectibn Propo6ed SER Append'x-A Item 27, ASME Section XI, Subsection IWE Enhancement (13), stated:

The reactor cavity concrete trough drain will be verified to be clear from blockage once per refuelihg cycle. Any identified issues will be addressed via the corrective action process. Once per refueling cycle.

The inspector reviewed a video recording record of a boroscope inspection of the cavity trough drain liie.

b. Observations See observations in section 2.4 below.

3.4 Reactor Cavity Trough Drain Monitoring

a. Scope of Inspection

J Proposed SER Appendix-A Item 27, ASME Section Xl, Subsection IWE Enhancement (3), stated:

The reactor cavity seal leakage trough drains and the drywell sand bed region drains will be monitored for leakage. Periodically.

The inspectors xxx In addition, the inspectors reviewed AmerGen's cavity trough drain flow monitoring plan and pre-approved Action Plan. AmerGen had established an administrative limit of 12 gpm on the cavity trough drain flow, based on a calculqtion which indicated that cavity trough drain flow of less than 60 gpm would not result in trough overflow into the gap between the drywell concrete shield wall and the drywell steel shell. The plan had pre-established actions at various cavity drain flow rates, as follows:

• If the cavity trough drain flow exceeds 5 gpm, then increase monitoring of the cavity drain flow to every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

a If the cavity trough drain flow exceeds- 12 0pm, then increase monitoring of the sand bed poly bottles to ;every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

• If the cavity trough draih owexceeds 12 'gpla...and any water is found in a sand bed poly bottle, then enter-and inspect thl6 snd bed bays.

b. Observations On Oct. 27, thecaOvity drain line was isolated to install a tygon hose to allow drain flow to be monitored,; :i;On Oct. 28, th: reactor cavity was filled. Drain line flow was monitored frequently durng,,cavity flod Mp and daiiy thereafter. On Oct. 29, a boroscope examination of th .drain 'a iclentified .,that tte isolation valve had been left closed.

When the drain line i4drdtion valve"ws'apened, about 3 gallons of water drained out, thenrthe drain:flow subsJded to about an'1/8 inch stream (less than 1 gpm).

On Nov. 6, the reactor cavit*y*iner strippable coating started to de-laminate. The cavity t,9gh drain flow tok a stehange from less than 1 gpm to approximately 4 to 6 gpm.

• MjrGen increased monitoring of the trough drain to every 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and sand bed poly bottles to every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. On Nov. 8, NDE technicians inside sand bed bay 11 identified dripping water. Subsequently, water puddles were identified in 4 sand bed bays. After cavity was drained, all sand bed bays were inspected; no deficiencies identified. The sand bed bays-were originally scheduled to have been closed by Nov. 2. In addition, on Nov. 15, after cavity was drained, water was found in the sand bed bay 11 poly bottle.

3.5 Drywell Sand Bed Region Drains Monitoring

a. Scope of Inspection Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancement (3), stated:

The sand bed region drains will be monitored daily during refueling outages.

There is one drain line for each two sand bed bays (five total). A poly bottle was attached via tygon tubing to a funnel hung below each drain line. AmerGen performed the drain line monitoring by checking the poly bottles.

The inspectors independently checked the poly bottles during the outage,,and accompanied AmerGen personnel during routine daily checks. The inspectors also reviewed the written monitoring logs.

b. Observations The sand bed drains were not directly observed and were not visible from the outer area of the torus room, where the poly bottles were located' After the: reactor cavity was drained, 2 of the 5 tygon tubes were found disconnected, laying on the floor. In addition, sand bed bay 11 drain poly bottle was empty during each daily. check until Nov.

15 (cavity was drained on Nov 12), when it was found full (greater than 4: gallons). Bay 11 was entered within a few hours, visually inspected, and found dry.

3.6 Moisture Barrier Seal Inspection (inside sand bed: bays)

a. Scope of Inspection Proposed SER Appendix-A Item 27; ASME'Secti*n Xl, S .bsection IWE Enhancements (12 & 21), stated:

Inspect the [moisture barrier] seal at the junction between the sand bed region concrete [sand bed floor] and the embedded drywell shell. During the 2008 refueling outage and every other retijeling outage thereafter.

The in.spectors perform*d the following:

• Indiendenity ihspected portions of the moisture barrier in 7 sand bed bays 9 Review4VIFT-1 examination records for each sand bed bay e Observed'AmerGerY; activities to evaluate the moisture barrier seals

b. Obs4:vations

• AmerGen idertified deficiencies in 7 of the 10 sand bed bays, including T Surface cirack .

• Partial separation of the seal from the shell, or the floor

• AmerGen determined the moisture barrier function was not impaired, because no cracks or separation fully penetrated the seal. All deficiencies were repaired.

Sand Bed Bay 3 Seal Crack and Rust Stain

" Observed activities to evaluate and repair the moisture barrier seal in Bay 3

• The seal had rust stains on the surface, below the identified crack

• When the seal was excavated, some drywell shell surface corrosion was identified

" Seal crack and surface rust were repaired

e Laboratory analysis determined there was inadequate epoxy cure, an original 1992 installation issue 2006 Inspection Did Not Identify Any Seal Cracks

• During 2006 seal inspections, no deficiencies were identified 3.7 Drywell Shell External Coatinqs Inspection (inside sand bed&bays)

a. Scope of Inspection Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancements (4 & 21), stated:

Perform visual inspections of the drywell external shell epoxy coating in all 10 sand bed bays. During the 2008 refueling outage and every other refueling outage thereafter.

The inspectors performed the f6lI10 fng'..

• Independently inspected-portions o6fýQte4,oxy co"ting in 7 sand bed bays

• Reviewedc VT-1 examinationrrecords-for 08ch,,§*nd bed bay

• Observed AmerGin's activities-to evaluate the epoxy coating in bay 11

b. Observations Sand Bed Bay 11 Blister.

" Observed4a"tivities to evaluate and repair blisters found in Bay 11 0 1mnall 114 inch broken blister identified, with a 6" rust stain

9. 3 smaller unbroJen blisters were identified by the NRC, during initial investigation

'* All 4 blisters werpwi'thin af42 inches square area, and all were evaluated and fixed

" For e xtet of condition, 64bays re-[inspected by different NDE level-Il S:" AmerGen reported that No deficiencies were identified

" AmerGen estimated corrosion of - 3 mils had occurred over about a 16 year period Sand Bed Bay 9 Coating Deficiency e AmerGen identified and re-coated a area approximately 8" x 8" area because of a difference in epoxy color which could have been indicative of only 2 layers instead of 3.

2006 Inspection Did Not Identify the Bay 11 Rust Stain or the Bay 9 Coating Deficiency

• AmerGen reviewed a 2006 video and identified the same 6" rust stain in the 2006 video of Bay 11 e CR 844815 stated the Bay 9 coating deficiency was most probably an original 1992 installation issue

• During the 2006 coatings inspection, these 2 deficiencies were not identified

3.8 Drywell Shell Thickness Measurements

a. Scope of Inspection Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancements (1, 9, 14, and 21), stated:

Perform full scope drywell inspections, including UT thickness measurements of the drywell shell, from inside and outside the drywell. During the 2008 refueling outage and every other refueling outage thereafter. This included:

• 19 locations inside the drywell, at the sand bed region elevation

• UT examinations in all 10 sand bed bays (drywell external, total 106 locations)

Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancements (7, 10, and 11 ) stated:

Conduct UT thickness measurements in the Upper regions of the drywell shell.

Prior to the period of ext4"dedo, Operation and two refueling outages later. This included:

locatiorst io.de the dryWeL, atelevations beteen 50to 87 foot

• 4 locationsisdthe drywei,2 at 23 foot elevation (bottom to middle spherical plate transition)

• 4.lctions inside the drywell, at.71 foot elevation (knuckle area)

• Observed actions to eV*Fate -.P(mygtainMent structural integrity

" Observed A frGen pefofA ell she 11' ti kness measurements

• Obs ,ryi field cbi[ction and-,cording of UT data

• "d AmerGe ..valuat6l* !UT data (2000 separate UT readings)

Revld UT examination, recorf4 ',.

R

• Reviewed AmerGen's T6chnical Et&uations of the UT data

b. Observations:

• AmerGen determined that all of the UT data satisfied acceptance criteria, based on current licensing basis design requirements, for the thickness of the steel plate o AmerGen did not identify any significant conditions affecting the drywell shell structural integrity

• AmerGen did not identify any on-going corrosion or corrosion trend, based on the UT examinations a AmerGen did not identify any statistically significant deviations from 2006 UT data values

i 3.9 Moisture Barrier Seal Inspection (inside drywell)

a. Scope of Inspection Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancement (17), stated:

Perform visual inspection of the moisture barrier seal between the drywell shell and the concrete floor curb, installed inside the drywell during the October 2006 refueling outage, in accordance with ASME Code.

The inspector reviewed structural inspection reports 187-001 and 187-002, performed by work order R2097321-01 on Nov 1 and Oct 29, respectively. The reports documented visual inspections of the perimeter seal between the concrete floor curb and the drywell steel shell, at the floor elevation 10 foot. In addition, the inspector reviewed selected photographs taken during the inp,e1ction

b. Observations None.

3.10 "B" Isolation Condenset Shell Inspectn,

a. Scope of Inspection...:,,!:.

Proposed SER Appendi*x*A item 24, One Time Inspection Program Item (2), stated:

To confirm the effectiveness of the ,Water Chemistry program to manage the loss of:-i,,terial Ojiccrack initiation and growth aging effects. A one-time UT inspectiowf9Q the "BIsolation Condenser shell below the waterline will be conducted isking for 0!tting corrosion. Perform prior to the period of extended operation.

The inspector obsered NDE examinations performed on the interior of the "B" isolation condenser shell, performed by work order C2017561-11. The inspector observed a visual inspecrtio of the shell interior, UT thickness measurements in two locations that were previously' tested in 1996 and 2002, additional UT testing in areas of identified pitting and corrosion, and spark testing of the final interior shell coating. The inspector reviewed the UT data records, and compared the UT data results to the established minimum wall thickness criteria for the isolation condenser shell, and compared the UT data results with previously UT data measurements from 1996 and 2002

b. Observations None.

3.11 Periodic Inspections

a. Scope of Inspection Proposed SER Appendix-A Item 41, Periodic Inspection Program, stated:

Activities consist of a periodic inspection of selected systems and components to verify integrity and confirm the absence of identified aging effects. Perform prior to the period of extended operation.

The inspectors observed the following activities:

• Condensate system pipe expansion joint inspection

" Switchgear fire barrier inspection

b. Observations None.

3.12 Circulating Water Intake Tunne,& ',Expansion Joint Inspection

a. Scope of Inspection Proposed SER App3tdre-A Item Program Enhancement (1),

stated: nPrgmEhnmt(1 Buildlh~s, structural ".bmponents and commodities that are not in scope of m aintpnce rule but have been detrmined to be in the scope of license renewal. i the,.prio*V of extended operation.

rn44ew29:'inspo*,

On.29t, tinspeQr directly observed the conduct of a structural engineering ection of Ircu ,water intake tunnel, including reinforced concrete wall and flVoor slabs, steel'lriers, e ded steel pipe sleeves, butterfly isolation valves, and tunpnel expansion jdtlss. mhe=pection was conducted by a qualified structural engineer. After the lnspection was completed, the inspector compared his direct observations with the documented visual inspection results.

b. Observations None.

3.13 Buried ESW Pipe Replacement

a. Scope of Inspection Proposed SER Appendix-A Item 63, Buried Piping, stated:

Replace the previously un-replaced, buried safety-related ESW piping prior to the period of extended operation. Perform prior to the period of extended operation.

The inspectors observed the following activities:

• Field work to remove old pipe and install new pipe

• Foreign material exclusion (FME) controls External protective pipe coating, and controls to ensure the pipe installation activities would not result in damage to the pipe coaing

b. Observations None.

3.14 Electrical Cable Inspection inside Drywell

a. Scope of Inspection Proposed SER Appendix-A Itemr34, Electrical Cable s and Connections, stated:

A representative sample o*accessible cables and connections located in adverse localized environnents will bh vi.ally ir ".cted at least once every 10 years for indicaions of accelerted ins'ibi aon aging. Perform prior to the period of extended '&rratflJp'_n.

The inspector, accompanied'eIctrical technicians and an electrical design engineer during a visu...nspection ofselected ele6trioal cables in the drywell. The inspector observed the ph6 JOb brjif Wk1t i§cisUssed inspection techniques and acceptance criteria.e .The insp 6idIrctly

' observed"the visual inspection, which included cables in raceways, ats-well aslb~es and connections inside junction boxes. After the inspection wascompletd, the inst* r compared his direct observations with the documented

$ visual inspection r'eults. 2i

b. Observations None.

3.15 Drywell Shell intmrnii'Coatincqs Inspection (inside drywell)

a. Scope of Inspection Proposed SER Appendix-A Item 33, Protective Coating Monitoring and Maintenance Program, stated:

The program provides for aging management of Service Level I coatings inside the primary containment, in accordance with ASME Code.

The inspector reviewed a vendor memorandum which summarized inspection findings

for a coating inspection of the as-found condition of the ASME Service Level I coating of the drywell shell inner surface. In addition, the inspector reviewed selected photographs taken during the coating inspection and the initial assessment and disposition of identified coating deficiencies. The coating inspector was also interviewed. The inspection was conducted on Oct. 30, by a qualified ANSI Level III coating inspector.

The final detailed report, with specific elevation notes and photographs, was not available before the end of this NRC inspection.

b. Observations None.

3.16 Inaccessible Medium Voltage Cable Test

a. Scope of Inspection Proposed SER Appendix-A Item 36, Inaccessible Medium Voltage Cables, stated:

In addition, the cable circuits will be testedAusing a proven test for detecting deterioration of the insuI~tlon system due to wýetting, such as power factor or partial discharge, as desjbed in EPRI TR-103834-P1-2, or other testing that is state of the art at the time the testltisperformed**erform prior to the period of extended operation.

The inspector reviewed the licensee's activities:to implement commitment item number xxx, of the NRC Safety Evaluation Report related to the Oyster Creek License Renewal. This commitment added fMedium-voltage cables M0081 and M0108 into the scope of OC license renewal. In addition, it required the jiq..eng.e to develop an aging management program consistent wjth:NUREG-18D1,,. Generic Aging Lessons Learned,"Section XI.E3.

N URE-01 Sectio'i'XE3, Iccessi ble Medium-Voltage Cables Not Subject To 10 CFR 50.4,0Environmental Qu*tification Requirements, recommended the licensee determine a spec t.ype of test to be rformed prior to the initial test [at the time just prior to or at the time of the pe i70t of extended oerations],* and that it should be a proven test for detecting deterioration of the insulation' system due to wetting, such as power factor, partial discharge, or polarization index, as described in EPRI TR-103834-P1-2. NUREG-1801 also recommended that the first test be completed before the period of extended operation.

The inspector observed field testing (work order xxx) of electrical cable xxx, 4 kV feeder cable to Bus xxx transformer xxx, and independently reviewed the test results. A Doble test of the transformer, with the cable connected to the transformer secondary, was performed, in part, to detect deterioration of the cable insulation. In addition, the inspector interviewed plant electrical engineering and maintenance personnel.

b. Observations None.

r .

3.17 Fatigue Monitoring Program

a. Scope of Inspection On the basis of a projection of the number of design transients, the licensee concluded, during the license renewal application process, the existing fatigue analyses of the RCS components remain valid for the extended period of operation (See NRC Safety Evaluation Report NUREG 1728 Section 4.3). Constellation however indicated that, prior to the expiration of the current operating license, a Fatigue Monitoring Program will be implementedlas a confirmatory program as discussed in Section B.3.2 of their original license renewal application.

The licensee proposed using the Fatigue Monitoring Program to provi[de assurance that the number of design cycles will not be exceeded during the period of extended operation. It was on this basis that the staff found licensee's Fatigue Monitoring Program provided an acceptable basis for monitoring the fatigue usage of reactor coolant system components, in accordance with the requirements of 10 CFR 54.21(c)(1 )(iii).

Subsequent to the application, the NRC staff became aware of a simplified assumption used in the EPRI program for fatigue monitoring called FatiguePtpi iThe inspector reviewed the current status of the fatigue monitoring program. fr the licensee. IThe inspector also determined if the computational shortcut was present in .tle*:eprogram and wh'aTesponse the licensee was planning to the NRC's concern that the PHpIfiifledassumptionr* ,ight result in a non-conservatie prognosis of fatigue. The inspector interVieWed the rpe opsible *egineer staff and reviewed the results of the fatigue programT:n place at thefacility..The:. nspector reviewed the procedures to0determine and computational methodologyYthestatus of current fatigue limits on reactor coolant system components.

b. Observation's None.

4 '*ommitment Manement Program

a. Sco*.eof Inspection The inspectors evaluated Exelon procedures used to manage and revise regulatory, commitments .4odet6rmine whether they were consistent with the requirements of 10 CFR 50.59, NRC Regulatory Issue Summary 2000-17, "Managing Regulatory Commitments," and the guidance in Nuclear Energy Institute (NEI) 99-04, "Guidelines for Managing NRC Commitment Changes." In addition, the inspectors reviewed the procedures to assess whether adequate administrative controls were in-place to ensure commitment revisions or the elimination of commitments altogether would be properly evaluated, approved, and reported to the NRC. The inspectors also reviewed AmerGen's current licensing basis commitment tracking program to evaluate its effectiveness. In addition, the following commitment change evaluation packages were reviewed:

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" Commitment Change 08-003, OC Bolting Integrity Program

" Commitment Change 08-004, RPV Axial Weld Examination Relief

b. Observations None.

40A6 Meetings, Including Exit Meeting Exit Meeting Summary The inspectors presented the results of this inspection to Mr. T. Rausch, Site Vice President, Mr. M. Gallagher, Vice President License Renewal, and other members of AmerGen's staff on December 23, 2008.

No proprietary information is present in this inspection report.

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A-1 ATTACHMENT SUPPLEMENTAL INFORMATION KEY POINTS OF CONTACT Licensee Personnel C. Albert, Site License Renewal

• J. Cavallo, Corrosion Control Consultants & labs, Inc.

M. Gallagher, Vice President License Renewal C. Hawkins, NDE Level III Technician J. Hufnagel, Exelon License Renewal J. Kandasamy, Manager Regulatory Affairs S. Kim, Structural Engineer R. McGee, Site License Renewal F. Polaski, Exelon License Renewal R. Pruthi, Electrical Design Engineer S. Schwartz, System Engineer P. Tamburro, Site License Renewal Leadt .

C. Taylor, Regulatory Affairs NRC Personnel S. Pindale, Acting Senior Resident InspectorOyster Creek"'*

J. Kulp, Resident Inspector, OysterCreek L. Regner, License Renewal Project anager NRR D. Pelton, Chief- License Renewal: Pojects Branclil M. Baty, Counsel for NAC, Staff J. Davis, Senioraterials Engineer, W NR,R .' ::.1ý

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R. Pi~i~y, State of New Jertey Deptment of Environmental Protection R. Zak, Staj of New Jerseyý Ppartm:t' of Environmental Protection M. Fallin, Cotellation License Renewal Manager R. Leski, Nine, Mile Point License Renewal Manager

wF I-A-2 LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened/Closed None.

Opened 05000219/2008007-01 URI xxx Closed None.

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A-3 LIST OF DOCUMENTS REVIEWED License renewal Progqram Documents Drawings Plant Procedures LS-AA-104-1002, 50.59 Applicability Review, Rev 3 LS-AA-110, Commitment Change management, Rev 6 Condition Reports (CRs)

• = CRs written as a result of the NRC inspection Maintenance Requests & Work Orders Miscellaneous Documents:.,.

NRC Documents lndustiy Documents

= docufi'fts referenced Wjthin NUREG-1801 as providing acceptable guidance for specific aging rahogement programs

- -r A-4 LIST OF ACRONYMS EPRI Electric Power Research Institute NDE Non-destructive Examination NEI Nuclear Energy Institute SSC Systems, Structures, and Components SDP Significance Determination Process TR Technical Report UFSAR Updated Final Safety Analysis Report 7

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