ML091980314

Draft Ltr. from D. Roberts of USNRC to C. Pardee of Exelon Generation Company, Regarding Oyster Creek Generating Station - NRC License Renewal Follow-Up Inspection Report 05000219-2008007, Rev 6a

ML091980314
Person / Time
Site:	Oyster Creek
Issue date:	06/17/2009
From:	Darrell Roberts Division of Reactor Safety I
To:	Pardee C Exelon Generation Co
References
FOIA/PA-2009-0070 IR-08-007
Download: ML091980314 (26)

See also: IR 05000219/2008007

Text

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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.The NRC's Reactor Oversight

Process mid-cycle

letter of September

2, 2008 informed you the NRC would be conducting

two license renewal inspections

prior to the period of extended operation.

The NRC conducted

the first inspection

using the guidance of Inspection

Procedure (IP) 71003 "Post-Approval

Site Inspection

for License Renewal" as a prudent measure to observe Oyster Creek license renewal activities

during the last planned refueling

outage prior to entering the period of extended operation.

The inspection

examined important

license renewal activities

conforming

to the Commission's

rules and regulations.

The inspectors

reviewed selected procedures

and records, observed activities, and interviewed

personnel.

This inspection

focused on the inservice

inspection

of the drywell containment.

Based on the results of the NRC's inspection, the NRC determined

there were no safety significant

conditions

affecting

current operations.

The NRC observed you are continuing

to implement

the proposed license conditions, and associated

commitments, recorded in NRC's Final Safety Evaluation

Report for License Renewal -NUREG 1845 (Volume 1: ML071290023

& Volume 2: ML071310246).

Because an appeal of a licensing

board decision about the Oyster Creek application

for a renewed license is pending before the Commission

your renewed license has not been issued and the proposed license conditions

and associated

commitments, made as a part of the license renewal application

are not in effect. [C (b)(5)y", report only records the inspector's

observations.

.As a consequence

the enclosed U'/ib 2-&*inM1an bti1 rcod Wasdeleedm

Wn wt h.wdo~fItO

C F O & W~ A 0 1 / /

C. Pardee 2 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.qov/readino-

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, Darrell Roberts, Director Division of Reactor Safety Docket No. 50-219 License No. DPR-16 Enclosure:

Inspection

Report No. 05000219/2008007

w/Attachment:

Supplemental

Information

C. Crane, President

and Chief Operating

Officer, Exelon Corporation

M. Pacilio, Chief Operating

Officer, Exelon Nuclear T. Rausch, Site Vice President, Oyster Creek Nuclear Generating

Station J. Randich, Plant Manager, Oyster Creek Generating

Station J. Kandasamy, Regulatory

Assurance

Manager, Oyster Creek R. DeGregorio, Senior Vice President, Mid-Atlantic

Operations

K. Jury,Vice

President, Licensing

and Regulatory

Affairs P. Cowan, Director, Licensing B. Fewell, Associate

General Counsel, Exelon Correspondence

Control Desk, AmerGen Mayor of Lacey Township P. Mulligan, Chief, NJ Dept of Environmental

Protection

R. Shadis, New England Coalition

Staff E. Gbur, Chairwoman

-Jersey'Shore

Nuclear Watch E. Zobian, Coordinator

-Jersey Shore Anti Nuclear Alliance P. Baldauf, Assistant

Director, NJ Radiation

Protection

Programs

C. Pardee 2 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/readinq-

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, Darrell Roberts, Director Division of Reactor Safety Docket No.License No.50-219 DPR-16 Enclosure:

Inspection

Report No. 05000219/2008007

w/Attachment:

Supplemental

Information

Distribution

w/encl: S. Collins, RA M. Dapas, DRA D. Lew, DRP J. Clifford, DRP R. Bellamy, DRP S. Barber, DRP C. Newport, DRP M. Ferdas, DRP, Senior Resident Inspector J. Kulp, DRP, Resident Inspector J. DeVries, DRP, Resident CA S. Williams, RI OEDO H. Chernoff, NRR R. Nelson, NRR G. Miller, PM, NRR J. Hughey, NRR, Backup ROPreportsResource@nrc.gov (All IRs)Region I Docket Room (with concurrences)

SUNSI Review Complete:

_ (Reviewer's

Initials)

Adams Accession

No.DOCUMENT NAME: G:\DRS\Engineering

Branch 1\Richmond\OC

2008-07 LR\_Report\OC

2008-07 LRIrev-6a.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 E RI/DRS Rj/DRP RI/DRS NAME JRichmond/

RConte/ RBellamy/

DRoberts/DATE 01/ /09 01/ /09 01/ /09 01/ /09 O .. F 7 AL. ..../ .....OFF71AL REC"73D C Y T /1P

U. S. NUCLEAR REGULATORY

COMMISSION

REGION I Docket No.: License No.: Report No.: Licensee: Facility: Location: Dates: Inspectors:

50-219 DPR-16 05000219/2008007

Exelon Generation

Company, LLC Oyster Creek Generating

Station Forked River, New Jersey 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)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. The inspection

was conducted

by five region based engineering

inspectors

and with assistance

from the Oyster Creek resident inspector.

The inspection

was conducted

using Inspection

Procedure (IP) 71003 "Post-Approval

Site Inspection

for License Renewal." In accordance

with the NRC's memorandum

of understanding

with the State of New Jersey, state engineers

from the Department

of Environmental

Protection, Bureau of Nuclear Engineering, observed portions of the NRC inspection

activities.

2 REPORT DETAILS Summary of Plant Status The Oyster Creek Generating

Station was in a scheduled

refueling

outage during the on-site portions of this inspection.

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).

4. OTHER ACTIVITIES (OA)40A5 License Renewal Follow-up (IP 71003)1.1 Purpose of Inspection

An appeal of a licensing

board decision about the Oyster Creek application

for a renewed license is pending before the Commission.

The NRC's Mid Cycle Performance

Review And Inspection

Plan for Oyster Creek, dated September

2, 2008 (ML082470569), indicated

the NRC would conduct two inspections (outage and non-outage) of the Oyster Creek license renewal activities

prior to the period of extended operation.

The NRC conducted

this inspection

using the guidance of Inspection

Procedure (IP) 71003 "Post-Approval

Site Inspection

for License Renewal." This inspection

was considered

a prudent measure in order to make observations

of Oyster Creek license renewal activities

during the last refuel outage prior to entering the period of extended operation.

Inspection

observations

were made of license renewal commitments

and license conditions

selected from NUREG-1875, "Safety Evaluation

Report (SER) Related to the License Renewal of Oyster Creek Generating

Station" (ML071290023

& ML071310246).

The inspection

included observations

of a number of license renewal commitments

which take advantage

of programs implemented

under the current license.Performance

in these cases was evaluated

using the criteria in 10 CFR 50.For license renewal activities, with in the context of 10 CFR 54, the report documents the inspector

observations

because the proposed license conditions

and commitments

are not in effect. These conditions

and commitments

are not in effect 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.1.2 Sample Selection

Process The SER proposed commitments

and proposed license conditions

were selected based on the risk significance

using insights gained from sources such as the NRC's"Significance

Determination

Process Risk Informed Inspection

Notebooks," the results of previous license renewal audits, and inspections

of aging management

programs.The inspectors

also reviewed selected corrective

actions taken as a result of previous

I ýlicense renewal inspections.

2. Assessment

of Current License Basis Performance

Issues Based on the NRC's evaluation

of the drywell shell ultrasonic

test (UT) thickness measurements, direct observation

of drywell shell conditions

both inside the drywell, including

the floor trenches, and outside the drywell, in the sand bed regions, condition and integrity

of the drywell shell epoxy coating, and condition

of the drywell shell moisture barrier seals, the NRC determined

Exelon provided an adequate basis to conclude the drywell primary containment

will remain operable throughout

the period to the next scheduled

examination, in the 2012 refueling

outage.As noted in the details of sections 3.1, 3.2, 3.3, and 3.4 below, a few current license basis issues were observed that may require licensee corrective

action.L b5 (b)(5)1~1...-.(b)(5) 'I The specific items for follow-up

include: (b)(5)-of

the strippable

coating, applied to the liner of the refueling

cavity, and(b)(5 7)]to monitor the entire length of former sand bed drain lines, visible from the torus Toom, and the subsequent

discovery

that two of the drain lines were not directly attached to the portion of the drain line exiting the concrete structure below the former sand bed, and I ((b)(5)L0 (b)(5)5000219/2008007-01:

License Renewal Follow-up)

RURI IP 71003 consists of a number of site visits to determine

the status of license renewal commitment

implementation.

During the next site visit, the NRC will follow up on Exelon's evaluation

and the repair of four small blisters in sand bed bay 11. Exelon stated that some blistering

was expected, and would be identified

during routine visual examinations.

The NRC staff will review Exelon's cause evaluation

after it is completed.

The drywell shell epoxy coating and the moisture barrier seal, both in the sand bed region, are barrier systems used to protect the drywell from corrosion.

The problems identified

and corrected

with these barriers had a minimal impact on the drywell steel shell. The projected

shell corrosion

rate remains very small, as confirmed

by the NRC staff review of Exelon's technical

evaluations

of the 2008 UT data. [ (b)(5)r (b)(5)I -(,,-

EI (b)(5 3. Detailed Review of License Renewal Activities

3.1 Reactor Refuel Cavity Liner Strippable

Coatinq a. Scope of Inspection

Proposed SER Appendix-A

Item 27, ASME Section XI, Subsection

IWE Enhancement

(2), stated, in part: 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 cavity liner strippable

coating limited cavity seal leakage into the cavity trough drain at less than 1 gallon per minute (gpm). On Nov. 6, in one localized

area of the refuel cavity, the liner strippable

coating started to de-laminate.

Water puddles were subsequently

identified

in sand bed bays 11, 13, 15, and 17 (see section 3.4 below for additional

details).

This issue was entered into the corrective

action program as Issue Report (IR) 841543. In addition, this item was included in a common cause evaluation

as part of IR 845297. Exelon's initial evaluations

identified

several likely or contributing

causes, including:

• A portable submerged

water filtration

unit was improperly

placed in the reactor cavity which resulted in flow discharged

directly on the strippable

coating.il spill into the cavity may have affected the coating integrity.

• No po t installation

inspection

of the coating had been performed.

3.2 Reactor Refuel Cavity Seal Leakage Monitoring

a. Scope of Inspection

Proposed SER Appendix-A

Item 27, ASME Section XI, Subsection

IWE Enhancement

(3), stated, in part: The reactor cavity seal leakage trough drains and the drywell sand bed region drains will be monitored

for leakage, periodically.

The inspectors

observed Exelon's cavity seal leakage monitoring

activities, performed by work order R2095857.

The inspectors

independently

checked the cavity trough drain flow immediately

after the reactor cavity was filled, and several times throughout

the

outage. The inspectors

also reviewed the written monitoring

logs.b. Observations

Exelon monitored

reactor refuel cavity seal leakage by monitoring

and recording

the flow in a 2 inch drain line from the cavity concrete trough to a plant radwaste system drain funnel which, in turn, drained to the reactor building sump.On Oct. 27, Exelon isolated the cavity trough drain line 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. The drain flow then subsided to about an 1/8 inch stream (less than 1 gpm). This issue was entered into the corrective

action program as Issue Report (IR)37647.3.3 Drywell Sand Bed Reqion Drain Monitorinq

a. Scope of Inspection

Proposed SER Appendix-A

Item 27, ASME Section XI, Subsection

IWE Enhancement

(3), stated, in part: The sand bed region drains will be monitored

daily during refueling

outages.The inspectors

observed Exelon's activities

to monitor sand bed drains, performed

by work order R2095857.

The inspectors

independently

checked drain line poly bottles and accompanied

Exelon personnel

during routine daily checks. The inspectors

also reviewed the written monitoring

logs.b. Observations

There is one sand bed drain line for every two sand bed bays (i.e., total of five drains for 10 bays). Exelon remotely monitored

the sand bed drains by checking poly bottles attached via tygon tubing to a funnel hung below each drain line. The tygon tubing which connected

a poly bottle to the funnel under the drain line was about 50 foot long.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.On Nov. 10, Exelon found 2 of the 5 tygon tubes disconnected

from their funnels and laying on the floor (bays 3 and 7). Exelon personnel

could not determine

when the tubing was last verified to be connected

to the funnel. Both tubes were reconnected.

This issue was entered into the corrective

action program as Issue Report (IR) 843209.xxx need IR ##On Nov. 15, during a daily check of sand bed bay 11 drain poly bottle, Exelon found the poly bottle full (greater than 4 gallons).

Exelon sampled the water, but could not positively

determine

the source based on radiolytic

or chemical analysis.

The inspectors

noted that Exelon had found the poly bottle empty during each check throughout

the outage, until Nov 15 (cavity was drained on Nov 12). The inspectors

also noted that the funnel, to which the tygon tubing was connected, had a capacity of about 6 gallons.Exelon entered bay 11 within a few hours, visually inspected

it, and found it dry, This issue was entered into the corrective

action program as Issue Report (IR) xxx.3.4 Reactor Cavity Seal Leakaqe Action Plan for 1 R22 a. Scope of Inspection

Proposed SER Appendix-A

Item 27, ASME Section Xl, Subsection

IWE Enhancement

(3), stated, in part: If leakage is detected [flow out of a sand bed drain], procedures

will be in place to determine

the source of leakage and investigate

and address the impact of leakage on the drywell shell.The inspectors

reviewed Exelon's pre-approved

cavity seal leakage action plan.b. Observations

For the reactor cavity seal leakage, Exelon established

an administrative

limit of 12 gpm flow in the cavity trough drain, 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.The inspectors

noted that Exelon's pre-approved

action plan, in part, directed the following

actions to be taken: 9 If the cavity trough drain flow exceeded 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 exceeded 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 />.9 If the cavity trough drain flow exceeded 12 gpm and any water is found in a sand bed poly bottle, then enter and inspect the sand bed bays.On Nov. 6, the reactor cavity liner strippable

coating started to de-laminate (see section 3.1 above). The cavity trough drain flow took a step change from less than 1 gpm to approximately

4 to 6 gpm. Exelon 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 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 />. The cavity trough drain flow remained at about 4 to 6 gpm until the cavity was drained on Nov. 12, when the drain flow subsided to zero.On Nov 8, personnel

working in sand bed bay 11 identified

dripping water. Water puddles were subsequently

identified

in sand bed bays 11, 13, 15, and 17. These issues were entered into the corrective

action program as Issue Report (IR) 842333. In addition, these items were included in a common cause evaluation

as part of IR 845297.The inspectors

noted that all sand bed bay work was originally

scheduled

to have been completed

and to have the bays closed out by Nov. 2.

On Nov 12, the cavity was drained. All sand bed bays were dried and inspected

for any water or moisture damage; no deficiencies

were identified.

Exelon stated follow-up ultrasonic

test (UT) examinations

will be performed

to evaluate the drywell shell during the next refuel outage.On Nov. 15, water was found in the sand bed bay 11 poly bottle (see section 3.3 above).The inspectors

observed that Exelon'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 inspectors

also noted that water had entered the gap between the drywell shield wall and the drywell shell at a much lower value of cavity seal leakage than Exelon had predicted.

3.5 Reactor Cavity Trough Drain Inspection

for Blockage a. Scope of Inspection

Proposed SER Appendix-A

Item 27, ASME Section XI, Subsection

IWE Enhancement

(13), stated, in part: 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.The inspector

reviewed a video recording

record of a boroscope

inspection

of the cavity trough drain line, performed

by work order R2102695.b. Observations

See observations

in section 3.2 above.3.6 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, in part: 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 purpose of the moisture barrier seal is to prevent water from entering a gap below the concrete floor in the sand bed region. Exelon performed

a 100% visual test (VT)inspection

of the seal in the sand bed region (total of 10 bays). The inspectors

directly observed as-found conditions

in portions of 6 sand bed bays, and as-left conditions

in 4

sand bed bays.The inspectors

reviewed VT inspection

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

to the recorded VT inspection

results. The inspectors

reviewed Exelon VT inspection

procedures, interviewed

non-destructive

examination (NDE)supervisors

and technicians, and observed field collection

and recording

of VT inspection

data. The inspectors

also reviewed a sample of NDE technician

visual testing qualifications.

The inspectors

observed Exelon's activities

to evaluate and repair the moisture barrier seal in sand bed bay 3.b. Observations

The inspectors

observed that NDE visual inspection

activities

were conducted

in accordance

with approved procedures.

The inspectors

verified that Exelon completed the inspections, identified

condition(s)

in the moisture barrier seal which required repair, completed

the seal repairs in accordance

with engineering

procedures, and conducted appropriate

re-inspection

of repaired areas.The VT inspections

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. Exelon determined

the as-found moisture barrier function was not impaired, because no cracks or separation

fully penetrated

the seal, All deficiencies

were entered into the corrective

action program and repaired (IRs are listed in the Attachment).

In addition, these items were included in a common cause evaluation

as part of IR 845297.xxx ADD IR ## for bay 3 seal The VT inspection

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 seal deficiencies

were identified

in any sand bed bay.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, in part: 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

observed portions of Exelon's activities

to perform a 100% visual inspection

of the epoxy coating in the sand bed region (total of 10 bays). In addition, the inspectors

directly observed as-found conditions

of the epoxy coating in portions of 6 sand bed bays, and the as-left condition

in sand bed bay 11, after coating repairs. The inspectors

also observed field collection, recording, and reporting

of visual inspection

data.The inspectors

reviewed VT inspection

records for each sand bed bay and compared their direct observations

to the recorded VT inspection

results. The inspectors

reviewed Exelon VT inspection

procedures, interviewed

non-destructive

examination (NDE)supervisors

and technicians, and observed field collection

and recording

of VT inspection

data. The inspectors

also reviewed a sample of NDE technician

visual testing qualifications.

The inspectors

directly observed Exelon's activities

to evaluate and repair the epoxy coating in sand bed bay 11. In addition, the inspectors

reviewed Technical

Evaluation

330592.27.46, "Coating Degradation

in Sand Bed bay 11." b. Observations

The inspectors

observed that NDE visual inspection

activities

were conducted

in accordance

with approved procedures.

The inspectors

verified that Exelon completed the inspections, identified

condition(s)

in the exterior coating which required repair, completed

the coating repairs in accordance

with engineering

procedures, and conducted

appropriate

re-inspection

of repaired areas.In sand bed bay 11, the NDE inspection

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, three additional

smaller surface irregularities (initially

described

as surface bumps) were identified

within a 1 to 2 square inch area near the broken blister. The three additional

bumps were subsequently

determined

to be unbroken blisters.

This issue was entered into the corrective

action program as IR 838833 and 839053. In addition, this item was included in a common cause evaluation

as part of IR 845297. All four blisters were evaluated

and repaired.On Nov. 13, the inspectors

conducted

a general visual observation (i.e., not a qualified VT inspection)

of the repaired area and the general condition

in bay 11. The inspectors

verified that Exelon's inspection

data reports appeared to accurately

describe the conditions

observed by the inspectors.

To confirm the adequacy of the coating inspection, Exelon re-inspected

4 sand bed bays (bays 3, 7, 15, and 19) with a different

NDE technician.

No additional

deficiencies

were identified.

In Technical

Evaluation

330592.27.46, Exelon determined, by laboratory

analysis using energy dispersive

X-ray spectroscopy, that the removed blister material contained

trace amounts of chlorine.

Exelon also determined

that the presence of chlorine, in a soluble salt as chloride, can result in osmosis of moisture through the epoxy coating. The analysis also concluded

there were no pinholes in the blister samples. In addition, the analysis determined

approximately

0.003 inches of surface corrosion

had occurred directly under the broken blister. Exelon concluded

that the

corrosion

had taken place over approximately

a 16 year period. In addition, UT dynamic scan thickness

measurements

under the four blisters, from inside the drywell, confirmed the drywell shell had no significant

degradation

as a result of the corrosion.

On Nov. 13, the inspectors

conducted

a general visual observation (i.e., not a qualified

VT inspection)

of the general conditions

in bay 5 and 9. The inspectors

observed that Exelon's inspection

data reports adequately

described

the conditions

observed by the inspectors.

xxx ADD IR ###, In follow-up, Exelon reviewed a 2006 video of the sand beds, which had been made as a general aid, not as part of an NDE inspection.

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 coating deficiencies

were identified

in any sand bed bay. This apparent deficiency

with the 2006 coating inspection

was entered into the corrective

action program as Issue Report (IR) xxx.During the final closeout of bays 3, 5, and 7, minor chipping in the epoxy coating was identified, and described

as incidental

mechanical

damage from personnel

entry for inspection

or repair activities.

All deficiencies

were entered into the corrective

action program and repaired (IRs are listed in the Attachment).

During the final closeout of bay 9, an area approximately

8 inches by 8 inches was identified

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, Exelon questioned

whether the color difference

could have been indicative

of an original installation

deficiency:

This issue was entered into the corrective

action program as IR 844815, and the identified

area was re-coated

with epoxy.3.8 Drywell Floor Trench Inspections

a. Scope of Inspection

Proposed SER Appendix-A

Item 27, ASME Section XI, Subsection

IWE Enhancements

(5, 16, & 20), stated, in part: 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

330592.27.43, "2008 UT Data of the Sand Bed Trenches." The inspectors

reviewed Exelon UT examination

procedures, interviewed

NDE supervisors

and technicians, reviewed a sample of NDE technician

UT qualifications, The inspectors

also reviewed records of trench inspections

performed

during two non-refueling

plant outages during the last operating

cycle.b. Observations

In Technical

Evaluation

330592.27.43, Exelon 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, the TE calculated

statistical

parameters

and determined

the data set distributions

were acceptable.

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.

The inspectors

independently

verified that the UT thickness

values satisfied applicable

acceptance

criteria.During two non-refueling

plant outages during the last operating

cycle, both trenches were inspected

for the presence of water and found dry by Exelon's staff and by NRC inspectors (NRC Inspection

Reports 05000219/2007003, 05000219/2007004, and memorandum

ML071240314).

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

observed the trenches to be dry. On one occasion, Exelon observed a small amount of water in the bay 5 trench, which they believed was from water spilled nearby on the drywell floor; the trench was dried and the issue entered into the corrective

action program as IR 843190. On Nov. 17, during the final drywell closeout inspection, the inspectors

observed the following:

9 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.xxx ADD IR ##9 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. Exelon stated the trench would be dried prior to final drywell closeout.9 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.3.9 Drywell Shell Thickness

Measurements

a. Scope of Inspection

Proposed SER Appendix-A

Item 27, ASME Section XI, Subsection

IWE Enhancements

I .(1, 9, 14, & 21), stated, in part: 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, & 11)stated, in part: 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

directly observed non-destructive

examination (NDE) activities

and the drywell shell conditions

both inside the drywell, including

the floor trenches, and in the sand bed bays (drywell external shell). The inspectors

reviewed UT examination

records and 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 330592.27.45, "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:

9 Sand bed region elevation, inside the drywell* All 10 sand bed bays, drywell external 9 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.The inspectors

also reviewed a sample of NDE technician

UT qualifications.

b. Observations

The inspectors

observed that NDE UT examination

activities

were conducted

in accordance

with approved procedures.

In Technical

Evaluations

330592.27.42, 330592.27.45, and 330592.27.88, Exelon determined

the UT thickness

values satisfied

the general uniform minimum wall

'V 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, the TEs calculated

statistical

parameters

and determined

the data set distributions

were acceptable.

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.

The inspectors

independently

verified that the UT thickness

values satisfied

applicable

acceptance

criteria.3.10 Moisture Barrier Seal Inspection (inside drywell)a. Scope of Inspection

Proposed SER Appendix-A

Item 27, ASME Section XI, Subsection

IWE Enhancement

(17), stated, in part: 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

No noteworthy

observations.

3,11 One Time Inspection

Progqram a. Scope of Inspection

Proposed SER Appendix-A

Item 24, One Time Inspection

Program, stated, in part: 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

No noteworthy

observations.

3.12 "B" Isolation

Condenser

Shell Inspection

a. Scope of Inspection

Proposed SER Appendix-A

Item 24, One Time Inspection

Program Item (2), stated, in part: 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 C2017561-1

1. 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

No noteworthy

observations.

3.13 Periodic Inspections

a. Scope of Inspection

Proposed SER Appendix-A

Item 41, Periodic Inspection

Program, stated, in part: 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

expansion

joints Y-2-11 and Y-2-12 inspection (WO R2083515)* 4160 V Bus 1C switchgear

fire barrier penetration

inspection (WO R2093471)b. Observations

No noteworthy

observations.

3.14 Circulating

Water Intake Tunnel & Expansion

Joint Inspection

a. Scope of Inspection

Proposed SER Appendix-A

Item 31, Structures

Monitoring

Program Enhancement

(1), stated, in part: 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

No noteworthy

observations.

3.15 Buried Emergqency

Service Water Pipe Replacement

a. Scope of Inspection

Proposed SER Appendix-A

Item 63, Buried Piping, stated, in part: 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

No noteworthy

observations.

3.16 Electrical

Cable Inspection

inside Drywell a. Scope of Inspection

Proposed SER Appendix-A

Item 34, Electrical

Cables and Connections, stated, in part: 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.

1!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

No noteworthy

observations.

3.17 Drywell Shell Internal Coatings Inspection (inside drywell)a. Scope of Inspection

Proposed SER Appendix-A

Item 33, Protective

Coating Monitoring

and Maintenance

Program, stated, in part: 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

No noteworthy

observations.

3.18 Inaccessible

Medium Voltage Cable Test a. Scope of Inspection

Proposed SER Appendix-A

Item 36, Inaccessible

Medium Voltage Cables, stated, in part: 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

0 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

No noteworthy, observations.

3.19 Fatigue Monitorinq

Program a. Scope of Inspection

Proposed SER Appendix-A

Item 44, Metal Fatigue of Reactor Coolant Pressure Boundary, stated, in part: The program will be enhanced to use the EPRI-licensed

FatiguePro

cycle counting and fatigue usage factor tracking computer program.The inspectors

interviewed

the fatigue program manager and determined

that the FatiguePro

program, although in place and ready-to-go, has not been implemented.

Exelon stated the FatiguePro

program will be implemented

after final industry resolution

of a concern regarding

a mathematical

summation

technique

used in FatiguePro.

The FatiguePro

program was evaluated

by the inspectors

in March of 2006 (Report 05000219/20006007).

The inspectors

determined

that Exelon's proposed implementation

had not changed in the interim.b. Observations

The inspectors

determined

that Exelon's proposed implementation

had not changed the since the NRC reviewed it in March of 2006.4. Proposed Conditions

of License a. Scope of Inspection

SER Section 1.7 contained

two outage related proposed conditions

of license: The fourth license condition

requires the applicant

to perform full scope inspections

of the drywell sand bed region every other refueling

outage.The fifth license condition

requires the applicant

to monitor drywell trenches every refueling

outage to identify and eliminate

the sources of water and receive NRC approval prior to restoring

the trenches to their original design configuration.

Proposed SER Appendix-A

Item 27, ASME Section XI, Subsection

IWE Enhancements

(1, 4, 9, 12, 14, & 21) implement

the proposed license condition

associated

with a full

scope drywell sand bed region inspection.

Proposed SER Appendix-A

Item 27, ASME Section XI, Subsection

IWE Enhancements

(5, 16, & 20) implement

the proposed license condition

associated

with the drywell trenches.b. Observations

For observations, see the applicable

sections above.5. Commitment

Management

Program a. Scope of Inspection

The inspectors

evaluated

current licensing

basis 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 Exelon'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

The inspectors

observed that the commitment

change activities

were conducted

in accordance

with approved procedures, Which required an annual update to the NRC with a summary of each change.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 Exelon's staff on December 23, 2008. NRC Exit Notes from the exit meeting are located in ADAMS within package ML0901120726.

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 M. McDermott, NDE Supervisor

R. McGee, Site License Renewal D. Olszewski, System Engineer 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, New Jersey State Department

of Environmental

Protection

R. Zak, New Jersey State 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 License Renewal Follow-up (Section 2.0)Closed None.

9, A-3 LIST OF DOCUMENTS

REVIEWED License Renewal ProQram Documents Drawings Plant Procedures

and Specifications

Incident Reports (IRs)* = IRs written as a result of the NRC inspection

Maintenance

Recuests (ARs) & Work Orders (WOs)Ultrasonic

Test Non-destructive

Examination

Records Visual Test Inspection

Non-destructive

Examination

Records NDE Certification

Records Miscellaneous

Documents NRC Documents Industry Documents* = documents

referenced

within NUREG-1 801 as providing

acceptable

guidance for specific aging management

programs

A-4 LIST OF ACRONYMS ASME American Society of Mechanical

Engineers EPRI Electric Power Research Institute NDE Non-destructive

Examination

NEI Nuclear Energy Institute SSC Systems, Structures, and Components

SDP Significance

Determination

Process TE Technical

Evaluation

UFSAR Updated Final Safety Analysis Report UT Ultrasonic

Test VT Visual Testing