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",

.As a consequence the enclosed U'

report only records the inspector's observations.

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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. 50-219

License No. 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

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OFF71AL REC"73D C Y

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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 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. 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 ý

license 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

1~

(b)(5)

1...-. I

(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

• t (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

( (b)(5)

L0 (b)(5) RURI

5000219/2008007-01: License Renewal Follow-up)

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 (,,-

I

(b)(5)

-

3.

EI

Detailed Review of License Renewal Activities

(b)(5

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 1R22

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

hours 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