ML091980359

Draft Ltr. from R. Conte of USNRC to C. Pardee of Exelon Generation Company, Regarding Oyster Creek Generating Station - NRC License Renewal Follow-Up IR 0500219-2008007, Rev 3

ML091980359
Person / Time
Site:	Oyster Creek
Issue date:	06/17/2009
From:	Conte R Engineering Region 1 Branch 1
To:	Pardee C Exelon Generation Co
References
FOIA/PA-2009-0070 IR-08-007
Download: ML091980359 (27)

See also: IR 05000219/2008007

Text

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. Nuclear Regulatory Commission (NRC) completed an

inspection at your Oyster Creek Generating Station. The enclosed report documents the

inspection results, which were discussed on December 23, 2008, with Mr. T. Rausch, Site Vice

President, Mr. M. Gallagher, Vice President License Renewal, and other members of your staff

in a telephone conference observed by representatives from the State of New Jersey.

An appeal of a licensing board decision regarding the Oyster Creek application for a renewed

license is pending before the Commission. The NRC concluded Oyster Creek should not enter

the extended period of operation without directly observing continuing license renewal activities

at Oyster Creek. Therefore, the NRC performed an inspection using Inspection Procedure (IP)

71003 "Post-Approval Site Inspection'for License Renewal" and observed Oyster Creek license

renewal activities during the last refuel outage prior to entering the period of extended

operation.

IP 71003 verifies license conditions added as part of a renewed license, license renewal

commitments, selected 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 Regulations (CFR) Pert 54 "Reouirements for the Renewal of Ooeratino

Licenses for Nuclear Power Plants."E (b)(5)

(b)(5)

(b)(5) '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.

o WMthf Freedompo Inftomutl

_______. -______/t-

P

C. Pardee 3

In accordance with 10 CFR 2.390 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.gov/readincq-

rm/adams.html (the Public Electronic Reading Room).

We appreciate your cooperation. Please contact me at (610) 337-5183 if you have any

questions regarding this letter.

Sincerely,

Richard Conte, Chief

Engineering Branch 1

Division of Reactor Safety

Docket No. 50-219

License No. DPR-16

Enclosure: Inspection Report No. 05000219/2008007

w/Attachment: Supplemental Information

C. Pardee 4

In accordance with 10 CFR 2.390 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.gov/reading-

rm/adams.html (the Public Electronic Reading Room).

We appreciate your cooperation. Please contact me at (610) 337-5183 if you have any

questions regarding this letter.

Sincerely,

Richard Conte, Chief

Engineering Branch 1

Division of Reactor Safety

Docket No. 50-219

License No. DPR-16

Enclosure: Inspection Report No. 05000219/2008007

w/Attachment: Supplemental Information

SUNSI Review Complete: _ (Reviewer's Initials)

ADAMS ACCESSION NO.

DOCUMENT NAME: C:\Doc\_.OC LRI 2008-07\_. Report\OC 2008-07 LRIrev-3.doc

After declaring this document "An Official 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

OFF FIAL RErORD7PY

C. Pardee 3

Distribution w/encl:

C. Pardee

Distribution w/encl: (VIA E-MAIL)

U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket No.: 50-219

License No.: DPR-16

Report No.: 05000219/2008007

Licensee: Exelon Generation Company, LLC

Facility: Oyster Creek Generating Station

Location: Forked River, New Jersey

Dates: October 27 to November 7, 2008 (on-site inspection activities)

November 13, 15, and 17, 2008 (on-site inspection activities)

November 10 to December 23, 2008 (in-office review)

Inspectors: J. Richmond, Lead

M. Modes, Senior Reactor Engineer

G. Meyer, Senior Reactor Engineer

T. O'Hara, Reactor Inspector

J. Heinly, Reactor Engineer

J. Kulp, 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 and the Oyster Creek resident inspector. The

inspection was conducted in accordance with Inspection Procedure 71003 "Post-Approval Site

Insiection for License Renewal.'" (b)(5)

(b)(5)

(b)(5) "1The report documents the inspector observations, absent any conclusions OT

adequac7, pending the final decision of the Commissioners on the appeal of the renewed

license.

2

REPORT DETAILS

4. OTHER ACTIVITIES (OA)

4OA2 License Renewal Follow-up (IP 71003)

1. Inspection Sample Selection Process

This inspection was conducted in order to observe AmerGen's continuing 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 aq.lication Drocess, as an opportunity to make observations on license

renewal activities.L. (b)(5)

(b)(5)

Accordingly, the inspectors recorded observations, without any assessment of

implementation adequacy or safety significance. Inspection observations were

considered, in light of pending 10 CFR 54 license renewal commitments and license

conditions, as documented in NUREG-1875, "Safety Evaluation Report (SER) Related

to the License Renewal of Oyster Creek Generating Station," as well as programmatic

performance under on-going implementation of 10 CFR 50 current licensing basis (CLB)

requirements.

The reviewed SER proposed commitments and license conditions were selected based

on several attributes including: the risk significance using insights gained from sources

such as the NRC's "Significance Determination Process Risk Informed Inspection

Notebooks," revision 2; the extent and results of previous license renewal audits and

inspections of aging management programs; the extent or complexity of a commitment;

and the extent that baseline inspection programs will inspect a system, structure, or

component (SSC), or commodity group.

For each commitment and on a sampling basis, the inspectors reviewed supporting

documents including completed 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.

At the time of the inspection, AmerGen Energy Company, LLC was the licensee for

Oyster Creek Generating Station. As of January 8, 2009, the OC license was

transferred to Exelon Generating Company, LLC by license amendment No. 271

(ML082750072).

2. NRC Unresolved Item

e Observed actions to evaluate primary containment structural integrity

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 existing current licensing basis

commitments were adequately performed and, if necessary, assess the safety significance for

any related performance deficiency.

e 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 Reactor Refuel Cavity Liner Strippable Coating

a. Scope of Inspection

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

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 sand bed bays. AmerGen stated follow-up UTs would be

performed to evaluate the drywell shell during the next refuel outage. AmerGen

identified several likely or contributing causes, including:

9 A portable water filtration unit was improperly placed in the reactor cavity,

which resulted in flow discharged directly on the strippable coating.

" An oil spill into the cavity may have affected the coating integrity.

• No post installation inspection of the coating had been performed.

3.2 Reactor Refuel Cavity Seal Leakage Trbuqh Drain Monitoring

a. Scope of Inspection

Proposed SER Appendix-A Item 27, ASME Section XI, 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.

Reactor refuel cavity seal leakage is collected in a concrete trough and gravity drains

through a 2 inch drain line into a plant drain system funnel. AmerGen monitored the

cavity seal leakage daily by monitoring the flow in the trough drain line.

The inspectors independently checked the trough drain flow immediately after the

reactor cavity was filled, and several times throughout the outage. The inspectors also

reviewed the written monitoring logs.

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 calculation 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.

b. Observations

On Oct. 27, the cavity trough drain line, was isolated to install a tygon hose to allow drain

flow to be monitored. On Oct. 28, the reactor cavity was filled. Drain line flow was

monitored frequently during cavity flood-up, and daily thereafter. On Oct. 29, a

boroscope examination of the drain line identified that the isolation valve had been left

closed. When the drain line isolation valve was opened, about 3 gallons of water

drained out, then the drain flow subsided to about an 1/8 inch stream (less than 1 gpm).

On Nov. 6, the reactor cavity liner strippable coating started to de-laminate. The cavity

trough drain flow took a step change from less than, 1 gpm to approximately 4 to 6 gpm.

AmerGen 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

the 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.

The inspectors observed that AmerGen's pre-approved action plan was inconsistent with

the actual actions taken in response to increased cavity seal leakage. The plan did not

direct increased sand bed poly bottle monitoring, and would not have required a sand

bed entry or inspection until Nov 15, when water was first found in a poly bottle. The

pre-approved action plan directed:

• If the cavity trough drain flow exceeds 5 gpm, then increase monitoring of the

cavity drain flow from daily to every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

• If the cavity trough drain flow exceeds 12 gpm, then increase monitoring of the

sand bed poly bottles from daily 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 drain flow exceeds 12 gpm and any water is found in a

sand bed poly bottle, then enter and inspect the sand bed bays.

3.3 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 drains 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.

3.4 Reactor Cavity Trouqh Drain Inspection for Blockage

a. Scope of Inspection

Proposed SER Appendix-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 refueling 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 line.

b. Observations

See observations in section 2.4 below.

3.5 Moisture Barrier Seal Inspection (inside sand bed bays)

a. Scope of Inspection

Proposed SER Appendix-A Item 27, ASME Section XI, Subsection 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 refueling outage thereafter.

The inspectors directly observed as-found conditions of the moisture barrier seal in 5

sand bed bays, and as-left conditions in 3 sand bed bays. The inspectors reviewed VT

examination records for each sand bed bay, and compared their direct observations to

the recorded VT examination results. The inspectors reviewed Exelon VT examination

procedures, interviewed nondestructive examination (NDE) technicians, and reviewed

NDE technician qualifications and certifications.

The inspectors observed AmerGen's activities to evaluate and repair the moisture

barrier seal in sand bed bay 3.

b. Observations

The VT examinations identified moisture barrier seal deficiencies in 7 of the 10 sand bed

bays, including surface cracks and partial separation of the seal from the steel shell or

concrete floor. All deficiencies were entered into the corrective action program and

evaluated. AmerGen determined the as-found moisture barrier function was not

impaired, because no cracks or separation fully penetrated the seal. All deficiencies

were repaired.

The VT examination for sand bed bay 3 identified a seal crack and a surface rust stains

below the crack. When the seal was excavated, some drywell shell surface corrosion

was identified. A laboratory analysis of removed seal material determined the epoxy

seal material had not adequately cured, and concluded it was an original 1992

installation issue. The seal crack and surface rust were repaired.

The inspectors compared the 2008 VT results to the 2006 results and noted that in 2006

no deficiencies were identified.

3.6 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,

AmerGen performed a 100% visual inspection of the epoxy coating in the sand bed

region (total of 10 bays). The inspectors directly observed as-found conditions of the

epoxy coating in 7 sand bed bays, and the as-left condition in sand bed bay 11, after

coating repairs. The inspectors reviewed VT examination records for each sand bed

bay, and compared their direct observations to the recorded VT examination results.

The inspectors reviewed Exelon VT examination procedures, interviewed nondestructive

examination (NDE) technicians, and reviewed NDE technician qualifications and

certifications.

The inspectors directly observed AmerGen's activities to evaluate and repair the epoxy

coating in sand bed bay 11.

b. Observations

In bay 11, AmerGen identified one small broken blister, about 1/4 inch in diameter, with

a 6 inch surface rust stain, dry to the touch, trailing down from the blister. During the

initial investigation, an NRC inspector identified three additional smaller surface

irregularities (initially described as surface bumps) within a 1 to 2 square inch area, near

the broken blister, which were subsequently determined to be unbroken blisters. All four

blisters were evaluated and repaired.

To confirm the adequacy of the initial coating examination, AmerGen re-inspected 4

sand bed bays with a different NDE technician. No additional deficiencies were

identified. A laboratory analysis of the removed blisters determined approximately 0.003

inches of surface corrosion had occurred directly under the broken blister, and

concluded the corrosion had taken place over approximately a 16 year period. UT

dynamic scan thickness measurements from inside the drywell confirmed the drywell

shell had no significant degradation as a result of the corrosion under the four blisters.

During the final closeout of bay 9, AmerGen identified an area approximately 8 inches

by 8 inches where the color of the epoxy coating appeared different than the

surrounding area. Because each of the 3 layers of the epoxy coating is a different color,

AmerGen questioned whether the color difference could have been indicative of an

original installation deficiency. The identified area was re-coated with epoxy.

In follow-up, AmerGen reviewed a 2006 video of the sand beds, which had been made

as a general aid, not as part of an NDE examination. The 2006 video showed the same

6 inch rust stain in bay 11. The inspectors compared the 2008 VT results to the 2006

results and noted that in 2006 no deficiencies were identified.

3.7 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 refueling outages.

The inspectors observed non-destructive examination (NDE) activities and reviewed UT

examination records. In addition, the inspectors directly observed conditions in the

trenches on multiple occasions during the outage. The inspectors compared UT data to

licensee established acceptance criteria in Specification IS-318227-004, revision 14,

"Functional Requirements for Drywell Containment Vessel Thickness Examinations,"

and to design analysis values for minimum wall thickness in calculations C-1302-187-

E310-041, revision 0, "Statistical Analysis of Drywell Sand Bed Thickness Data 1992,

1994, 1996, and 2006," and C-1302-187-5320-024, revision 2, "Drywell External UT

Evaluation in the Sand Bed." In addition, the inspectors reviewed Technical Evaluation

(TE) 330592.27.43, "2008 UT Data of the Sand Bed Trenches,"

The inspectors reviewed Exelon UT examination procedures, interviewed NDE

4

technicians, reviewed NDE technician qualifications and certifications. The inspectors

also reviewed records of trench inspections performed during two non-refueling plant

outages during the last operating cycle.

b. Observations

TE 330592.27.43 determined the UT thickness values satisfied the general uniform

minimum wall thickness criteria (e.g., average thickness of an area) and the locally

thinned minimum wall thickness criteria (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 TE calculated statistical parameters and determined the data sets had a

normal distribution. The TE also compared the data set values to the corresponding

2006 values and concluded there were no significant differences and no observable on-

going corrosion.

During two non-refueling plant outages during the last operating cycle, both trenches

were inspected for the presence of water, and found dry.

During the initial drywell entry on Oct. 25, the inspectors observed that both floor

trenches were dry. On subsequent drywell entries for routine inspection activities, the

inspectors also observed the trenches to be dry. During the final drywell closeout

inspection on Nov. 17, the inspectors observed the following:

e Bay 17 trench was dry and had newly installed sealant on the trench edge

where concrete meets shell, and on the floor curb near the trench.

• Bay 5 trench had a few ounces of water in it. The inspector noted that within

the last day there had been several system flushes conducted in the immediate

area. AmerGen stated the trench would be dried prior to final drywell closeout.

• Bay 5 trench had the lower 6 inches of grout re-installed and had newly

installed sealant on the trench edge where concrete meets shell, and on the floor

curb near the trench.

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 [in the sand bed region], 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.

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 extended operation and two refueling outages later.

The inspectors observed non-destructive examination (NDE) activities and reviewed UT

examination records. The inspectors compared UT data results to licensee established

acceptance criteria in Specification IS-318227-004, revision 14, "Functional

Requirements for Drywell Containment Vessel Thickness Examinations," and to design

analysis values for minimum wall thickness in calculations C-1302-187-E310-041,

revision 0, "Statistical Analysis of Drywell Vessel Sand Bed Thickness Data 1992, 1994,

1996, and 2006," and C-1302-187-5320-024, revision 2, "Drywell External UT Evaluation

in the Sand Bed." In addition, the inspectors reviewed the Technical Evaluations (TEs)

associated with the UT data, as follows:

• TE 330592.27.42, "2008 Sand Bed UT data - External"

• TE 330592.27.45i "2008 Drywell UT Data at Elevations 23 & 71 foot"

" TE 330592.27.88, "2008 Drywell Sand Bed UT Data - Internal Grids"

The inspectors reviewed UT examination records for the following:

• Sand bed region elevation, inside the drywell

" All 10 sand bed bays, drywell external

" Various drywell elevations between 50 and 87 foot elevations

" Transition weld from bottom to middle spherical plates, inside the drywell

• Transition weld from 2.625 inch plate to 0.640 inch plate (knuckle area), inside

the drywell

The inspectors reviewed Exelon UT examination procedures, interviewed NDE

supervisors and technicians, and observed field collection and recording of UT data in

accordance with the approved procedures. The inspectors also reviewed NDE

technician qualifications and certifications.

b. Observations

TEs 330592.27.42, 330592.27.45, and 330592.27.88 determined the UT thickness

values satisfied the general uniform minimum wall thickness criteria (e.g., average

thickness of an area) and the locally thinned minimum wall thickness criteria (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 TEs calculated statistical parameters and

determined the data sets had a normal distribution. The TEs also compared the data

set values to the corresponding 2006 values and concluded there were no significant

differences and no observable on-going corrosion.

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 inspection

b. Observations

None.

3.10 One Time Inspection ProQram

a. Scope of Inspection

Proposed SER Appendix-A Item 24, One Time Inspection Program, stated:

The One-Time Inspection program will provide reasonable assurance that an

aging effect is not occurring, or that the aging effect is occurring slowly enough

to not affect the component or structure intended function during the period of

extended operation, and therefore will not require additional aging management.

Perform prior to the period of extended operation.

The inspector reviewed the program's sampling basis and sample plan. Also, the

inspector reviewed ultrasonic test results from selected piping sample locations in the

main steam, spent fuel pool cooling, domestic water, and demineralized water systems.

b. Observations

None.

3.11 "B" Isolation Condenser Shell Inspection

a. Scope of Inspection

Proposed SER Appendix-A Item 24, One Time Inspection Program Item (2), stated:

To confirm the effectiveness of the Water Chemistry program to manage the

loss of material and crack initiation and growth aging effects. A one-time UT

inspection of the "B" Isolation Condenser shell below the waterline will be

conducted looking for pitting corrosion. Perform prior to the period of extended

operation.

The inspector observed NDE examinations of the "B" isolation condenser shell

performed by work order C2017561-11. The NDE examinations included a visual

inspection of the shell interior, UT thickness measurements in two locations that were

previously tested in 1996 and 2002, additional UT tests 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.

3.12 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

• 4160 V Bus 1C switchgear fire barrier penetration inspection

b. Observations

None.

3.13 Circulatinq Water Intake Tunnel & Expansion Joint Inspection

a. Scope of Inspection

Proposed SER Appendix-A Item 31, Structures Monitoring Program Enhancement (1),

stated:

Buildings, structural components and commodities that are not in scope of

maintenance rule but have been determined to be in the scope of license

renewal. Perform prior to the period of extended operation.

On Oct. 29, the inspector directly observed the conduct of a structural engineering

inspection of the circulating water intake tunnel, including reinforced concrete wall and

floor slabs, steel liners, embedded steel pipe sleeves, butterfly isolation valves, and

tunnel expansion joints. The inspection was conducted by a qualified structural

engineer. After the inspection was completed, the inspector compared his direct

observations with the documented visual inspection results.

b. Observations

None.

3.14 Buried Emerqency Service Water Pipe Replacement

a. Scope of Inspection

Proposed SER Appendix-A Item 63, Buried Piping, stated:

Replace the previously un-replaced, buried safety-related emergency service

water piping prior to the period of extended operation. Perform prior to the

period of extended operation.

The inspectors observed the following activities, performed by work order C2017279:

• 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 coating

b. Observations

None.

3.15 Electrical Cable Inspection inside Drywell

a. Scope of Inspection

Proposed SER Appendix-A Item 34, Electrical Cables and Connections, stated:

A representative sample of accessible cables and connections located in

adverse localized environments will be visually inspected at least once every 10

years for indications of accelerated insulation aging. Perform prior to the period

of extended operation.

The inspector accompanied electrical technicians and an electrical design engineer

during a visual inspection of selected electrical cables in the drywell. The inspector

observed the pre-job brief which discussed inspection techniques and acceptance

criteria. The inspector directly observed the visual inspection, which included cables in

raceways, as well as cables and connections inside junction boxes. After the inspection

was completed, the inspector compared his direct observations with the documented

visual inspection results.

b. Observations

None.

3.16 Drywell Shell Internal Coatinqs 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 coating

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 at the time the inspector left the site.

b. Observations

None.

3.17 Inaccessible Medium Voltage Cable Test

a. Scope of Inspection

Proposed SER Appendix-A Item 36, Inaccessible Medium Voltage Cables, stated:

Cable circuits will be tested using a proven test for detecting deterioration of the

insulation system due to wetting, such as power factor or partial discharge.

Perform prior to the period of extended operation.

The inspector observed field testing activities for the 4 kV feeder cable from the auxiliary

transformer secondary to Bank 4 switchgear and independently reviewed the test

results. A Doble and power factor test of the transformer, with the cable connected to

the transformer secondary, was performed, in part, to detect deterioration of the cable

insulation. The inspector also compared the current test results to previous test results

from 2002. In addition, the inspector interviewed plant electrical engineering and

maintenance personnel.

b. Observations

None.

3.18 Fatigue Monitoring Program

a. Scope of Inspection

xxx what about SER Supplement 1

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 implemented as 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 provide 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 FatiguePro. The inspector reviewed the current

status of the fatigue monitoring program for the licensee. The inspector also determined if the

computational shortcut was present in the program and what response the licensee was

planning to the NRC's concern that the simplified assumption might result in a non-conservative

prognosis of fatigue. The inspector interviewed the responsible engineer staff and reviewed the

results of the fatigue program in place at the facility. The inspector reviewed the procedures

and computational methodology to determine the status of current fatigue limits on reactor

coolant system components.

b. Observations

None.

4. Commitment Management Program

a. Scope of Inspection

The inspectors evaluated Exelon procedures used to manage and revise regulatory

commitments to determine 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 annually 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:

" Commitment Change 08-003, OC Bolting Integrity Program

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

b. Observations

xxx describe factual detail of changes and explain basis to NOT notify NRC staff

None.

40A6 Meetin-gs, Includinq Exit Meeting

Exit Meeting Summary

xxx ADD ADAMS # for Exit Notes

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. NRC Exit Notes from the exit meeting are

located in ADAMS within package MLxxxx.

No proprietary information is present in this inspection report.

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 Lead

C. Taylor, Regulatory Affairs

NRC Personnel

S. Pindale, Acting Senior Resident Inspector, Oyster Creek

J. Kulp, Resident Inspector, Oyster Creek

L. Regner, License Renewal Project Manager, NRR

D. Pelton, Chief - License Renewal Projects Branch 1

M. Baty, Counsel for NRC Staff

J. Davis, Senior Materials Engineer, NRR

Observers

R. Pinney, State of New Jersey Department of Environmental Protection

R. Zak, State of New Jersey Department of Environmental Protection

M. Fallin, Constellation License Renewal Manager

R. Leski, Nine Mile Point License Renewal Manager

A-2

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened/Closed

None.

Opened

05000219/2008007-01 URI xxx

Closed

None.

E

A-3

LIST OF DOCUMENTS REVIEWED

License Renewal Program Documents

PP-09, Inspection Sample Basis for the One-Time Inspection AMP, Rev 0

Drawings

Plant Procedures

LS-AA-104-1002, 50.59 Applicability Review, Rev 3

LS-AA- 110, Commitment Change management, Rev 6

645.6.017, Fire Barrier Penetration Surveillance, Rev 13

Condition Reports (CRs)

• = CRs written as a result of the NRC inspection

00804754

Maintenance Requests & Work Orders

C20117279

Nondestructive Examination Records

NDE Data Report 2008-007-017

NDE Data Report 2008-007-030

NDE Data Report 2008-007-031

UT Data Sheet 21 R056

Miscellaneous Documents

NRC Documents

Industry Documents

• = documents referenced within NUREG-1801 as providing acceptable guidance for specific

aging management programs

4,

A

A-4

A-5

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