ML090210106

IR 05000219-08-007; 10/27/2008 - 12/23/2008; Exelon, LLC, Oyster Creek Generating Station; License Renewal Follow-up

ML090210106
Person / Time
Site:	Oyster Creek
Issue date:	01/21/2009
From:	Darrell Roberts Division of Reactor Safety I
To:	Pardee C Exelon Generation Co, Exelon Nuclear
Conte R
Shared Package
ML090120714	List: ML090210106
References
FOIA/PA-2009-0070 IR-08-007
Download: ML090210106 (37)

See also: IR 05000219/2008007

Text

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION I

475 ALLENDALE ROAD

KING OF PRUSSIA, PA 19406-1415

January 21, 2009

Mr. Charles G. Pardee

Chief Nuclear Officer (CNO) and Senior Vice President

Exelon Nuclear

4300 Winfield Rd.

Warrenville, IL 60555

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.

First, this inspection was conducted using the guidance of Inspection Procedure (IP) 71003

"Post-Approval Site Inspection for License Renewal." Although IP 71003 is designated as a

"post-approval" inspection procedure, the NRC conducted this inspection as a prudent measure

absent a final NRC decision on license renewal. This inspection observed Oyster Creek license

renewal activities during the last planned refueling outage prior to entering the period of

extended operation. The license renewal application was the subject of a hearing and the

Atomic Safety and Licensing Board decision is being appealed to the Commission. Because a

renewed license has not been issued, the proposed license conditions and associated

regulatory commitments, made as a part of the license renewal application, are not in effect.

Accordingly, as related to license renewal activities, the enclosed report records the inspector's

factual observations.

Second, the inspection examined activities conducted under your current license as they relate

to safety and compliance with the Commissions rules and regulations. This portion of the

inspection focused on the inservice inspection of the drywell containment. The inspectors

reviewed selected procedures and records, observed activities, and interviewed personnel.

Based on the results of the NRC's inspection, the NRC did not identify any safety significant

conditions affecting current operations.

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/reading-

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

We appreciate your cooperation. Please contact Richard Conte of my staff at (610) 337-5183 if

you have any questions regarding this letter.

Sincerely,

/RA/ Original Signed By:

Darrell J. 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. Gallagher, Vice President License Renewal

M. Pacilio, Chief Operating Officer, Exelon Nuclear

T. Rausch, Site Vice President, Oyster Creek Nuclear Generating Station

P. Orphanos, 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, Exelon

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

Congressman C. Smith

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/reading-

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

We appreciate your cooperation. Please contact Richard Conte of my staff at (610) 337-5183 if

you have any questions regarding this letter.

Sincerely,

/RA/ Original Signed By:

Darrell J. 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 OA

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: JER/RJC (Reviewer=s Initials) Adams Accession No. ML090210106

DOCUMENT NAME: G:\\DRS\\Engineering Branch 1\\Richmond\\OC 2008-07 LR\\_Report\\OC 2008-07 LRI_rev-14.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

RI/DRP

RI/DRS

NAME

JRichmond/JER

RConte/RJC

RBellamy/RRB

DRoberts/DJR

DATE

01/20/09

01/20/09

01/20/09

01/20/09

OFFICIAL RECORD COPY

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 J. Conte, Chief

Engineering Branch 1

Division of Reactor Safety

Region I

ii

TABLE OF CONTENTS

SUMMARY OF FINDINGS.........................................................................................................iii

4.

OTHER ACTIVITIES (OA)...................................................................................................1

4OA5

License Renewal Follow-up (IP 71003)....................................................................1

1.

Inspection Overview .....................................................................................................1

1.1

Purpose of Inspection............................................................................................1

1.2

Sample Selection Process.....................................................................................1

2.

Assessment of Current Licensing Basis Performance Issues.......................................2

2.1

ASME,Section XI, Subsection IWE Program........................................................2

2.2

Issues for Follow-up ..............................................................................................2

3.

Detailed Review of License Renewal Activities.............................................................4

3.1

Reactor Refuel Cavity Liner Strippable Coating.....................................................4

3.2

Reactor Refuel Cavity Seal Leakage Monitoring ...................................................4

3.3

Reactor Cavity Trough Drain Inspection for Blockage ...........................................5

3.4

Drywell Sand Bed Region Drain Monitoring...........................................................5

3.5

Reactor Cavity Seal Leakage Action Plan for 1R22...............................................6

3.6

Moisture Barrier Seal Inspection (inside drywell) ...................................................8

3.7

Moisture Barrier Seal Inspection (inside sand bed bays).......................................8

3.8

Drywell Shell Internal Coatings Inspection (inside drywell) ....................................9

3.9

Drywell Shell External Coatings Inspection (inside sand bed bays).....................10

3.10 Drywell Floor Trench Inspections ........................................................................12

3.11 Drywell Shell Thickness Measurements ..............................................................13

3.12 One Time Inspection Program.............................................................................15

3.13 "B" Isolation Condenser Shell Inspection.............................................................15

3.14 Periodic Inspections ............................................................................................16

3.15 Circulating Water Intake Tunnel & Expansion Joint Inspection............................16

3.16 Buried Emergency Service Water Pipe Replacement..........................................17

3.17 Electrical Cable Inspection inside Drywell............................................................17

3.18 Inaccessible Medium Voltage Cable Test............................................................18

3.19 Fatigue Monitoring Program................................................................................18

4.

Proposed Conditions of License.................................................................................19

5.

Commitment Management Program...........................................................................19

4OA6

Meetings, Including Exit Meeting.............................................................................20

SUPPLEMENTAL INFORMATION...........................................................................................21

iii

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.

A.

NRC-Identified and Self-Revealing Findings

No findings of significance were identified.

B.

Licensee-Identified Violations

None.

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 Oyster Creek license was transferred to

Exelon Generating Company, LLC by license amendment No. 271 (ML083640373).

4.

OTHER ACTIVITIES (OA)

4OA5 License Renewal Follow-up (IP 71003)

1.

Inspection Overview

1.1

Purpose of Inspection

The NRC conducted this inspection using the guidance of Inspection Procedure (IP)

71003 "Post-Approval Site Inspection for License Renewal." The license renewal

application was the subject of a hearing and the Atomic Safety and Licensing Board

decision is being appealed to the Commission. Although IP 71003 is designated as a

"post-approval" inspection procedure, the NRC conducted this inspection as a prudent

measure absent a final NRC decision on license renewal. This inspection observed

Oyster Creek license renewal activities during the last refueling 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 were enhancements to exiting programs implemented under the current license.

When the performance of an existing program was evaluated by the inspectors, the

basis for the evaluation was the current licensing basis (CLB), and the license renewal

enhancements were not considered in the evaluation.

For license renewal activities, within the context of 10 CFR 54, the report only

documents inspector observations, because the proposed license conditions and

associated regulatory commitments were not in effect at the time of this inspection.

These proposed conditions and commitments were 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. Thus they are referred to in

this report as "proposed" conditions and commitments.

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

2

"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

license renewal inspections.

2.

Assessment of Current Licensing Basis Performance Issues

2.1

ASME,Section XI, Subsection IWE Program

Monitoring of the condition of the primary containment drywell is accomplished through

Exelons ASME Section XI, Subsection IWE monitoring program. The inspectors

determined Exelon provided an adequate basis to provide assurance that the drywell

primary containment will remain operable throughout the period to the next scheduled

examination (2012 refueling outage). This determination was based on the inspectors'

evaluation of the drywell shell ultrasonic test (UT) thickness measurements (Sections

3.10 & 3.11), direct observation of drywell shell conditions both inside the drywell

(Sections 3.6, 3.8, & 3.11), including the floor trenches (Section 3.10), and outside the

drywell in the sand bed regions (Sections 3.7 & 3.9), condition and integrity of the

drywell shell epoxy coating (Section 3.9), and condition of the drywell shell moisture

barrier seals (Sections 3.6 & 3.7). On a sampling basis, the inspectors observed that

the enhancements made as a result of license renewal activities were integrated into the

existing program for the drywell structural integrity.

The drywell shell epoxy coating and the moisture barrier seal, both in the sand bed

region, are barriers used to protect the drywell from corrosion. The problems identified

with these barriers (discussed in Sections 3.7 & 3.9) were corrected and had a minimal

impact on the drywell steel shell. The drywell shell corrosion rate remains very small, as

confirmed by the inspectors' review of Exelon's technical evaluations of the 2008 UT

data. The inspectors determined Exelon provided an adequate basis to conclude the

likelihood of additional blisters or moisture barrier seal issues will not impact the

containment safety function during the period before the next scheduled examination

(2012 refueling outage). This is based on the inspectors' direct observations of four

coating blisters and a number of moisture barrier seal issues, review of Exelon's repairs,

and direct observation of the general conditions of the drywell shell, both inside the

drywell and outside the drywell, in the sand bed regions, as well as the overall condition

and integrity of the drywell shell epoxy coating.

2.2

Issues for Follow-up

Introduction

The inspectors and Exelon identified a number of issues during the inspection with

potential implications on the current licensing basis (CLB). More information is required

in order to determine whether these issues are acceptable or are CLB performance

deficiencies.

3

Description

As noted in the detailed observations of this report, a number of issues were observed

which Exelon placed into its corrective action program. The specific issues for further

review include:

(1) Exelon applied a strippable coating to the refuel cavity liner to prevent water

intrusion into the gap between the drywell steel shell and the concrete shield

wall. The strippable coating unexpectedly de-laminated, resulting in increased

refuel cavity seal leakage. As a result, water entered the gap and subsequently

flowed down the outside of the shell and into four sand bed bays. In addition,

Exelon had established an administrative limit for cavity seal leakage that was

higher than the actual leakage rate at which water intrusion into the gap

occurred. (Sections 3.1 & 3.5)

(2) While the reactor cavity was being filled, Exelon frequently monitored the

cavity seal leakage by observing flow in the cavity trough drain line.

Subsequently, Exelon determined that the trough drain line had been left isolated

during a previous maintenance activity. As a result, cavity seal leakage had not

been monitored as intended. (Section 3.2)

(3) During the refueling outage, Exelon monitored for water leakage from the

sand bed bay drains by checking poly bottles connected via tygon tubing and

funnels to the sand bed drain lines. Exelon subsequently discovered that the

poly bottle tubing was not connected to the drain lines for two sand bed bays.

(Section 3.4)

(4) Exelon identified four blisters on the epoxy coating in one sand bed bay.

Exelon's evaluation to determine the cause of the blisters was still in-progress at

the time this inspection was completed. In addition, a video recording from 2006

appeared to indicate that one of the blisters existed at that time, but was not

identified during Exelon's 2006 visual inspection. (Section 3.9)

The inspectors will review these issues in a future inspection to determine whether the

individual issues are acceptable or constitute a CLB performance deficiency. The

inspectors' assessment will, in part, determine whether these items are consistent with

design specifications and requirements, the conduct of operations, and whether

appropriate administrative controls were utilized. (URI 05000219/2008007-01: Drywell

Sand Bed Water Intrusion, Drain Monitoring, and Coating Deficiency)

4

3.

Detailed Review of License Renewal Activities

3.1

Reactor Refuel Cavity Liner Strippable Coating

a.

Scope of Inspection

Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancement

(2), stated, 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. Prior to filling the reactor cavity with water.

The inspectors reviewed work order (WO) R2098682-06, "Coating Application to Cavity

Walls and Floors."

b.

Observations

The strippable coating is applied to the reactor cavity liner before the cavity is filled with

water to minimize the likelihood of cavity seal leakage into the cavity concrete trough.

This action is taken to prevent water intrusion into the gap (Figure A-3) between the

drywell steel shell and the concrete shield wall. (see Figure A-1 for general

arrangement)

From Oct. 29 to Nov. 6, the cavity liner strippable coating limited cavity seal leakage into

the cavity trough drain to 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 3.5 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.

• A small oil spill into the cavity may have affected the coating integrity.

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

3.2

Reactor Refuel Cavity Seal Leakage 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.

5

The inspectors directly observed Exelon's cavity seal leakage monitoring activities,

performed under WO 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 checking and recording the flow

in a two inch drain line from the cavity concrete trough to a plant radwaste system drain

funnel which, in turn, drained to the reactor building equipment drain tank. (See Figures

A-1 thru A-3)

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 a 1/8-inch stream (less than 1 gpm).

This issue was entered into the corrective action program as IR 837647.

3.3

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 inspectors reviewed a video recording of a boroscope inspection of the cavity

trough drain line, performed under WO R2102695.

b.

Observations

See observations in Section 3.2 above.

3.4

Drywell Sand Bed Region Drain Monitoring

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 directly observed Exelon's activities to monitor sand bed drains,

6

performed under WO 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 for the existence

of water in poly bottles attached via tygon tubing (approximately 50 foot long) to a funnel

hung below each drain line. The sand bed drains, funnels, and a majority of the tygon

tubing were not directly observable from the outer area of the torus room, where the

poly bottles were located. (see Figures A-1, A-4, & A-5)

On Nov. 10, Exelon found two of the five 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. The inspectors directly observed

that the torus room floor had standing water for most of the outage, due to other

identified system leaks. The inspectors noted that the standing water would have

prevented Exelon personnel from determining whether any water had drained directly

onto the floor from a sand bed drain during the time period that the tygon tubing was

disconnected. The inspectors also noted that bays 3 and 7 remained dry throughout the

outage, with no identified water intrusion (see observations in Section 3.5). Both tubes

were subsequently reconnected. This issue was entered into the corrective action

program as IR 843209.

On Nov. 15, during a daily check of the sand bed bay 11 drain poly bottle, Exelon found

the poly bottle nearly full. Chemistry collected about 4.3 gallons out of the poly bottle

and tubing. The inspectors noted that Exelon had found the poly bottle empty during

each check throughout the outage until Nov. 15, and had only noted water in the poly

bottle three days after the reactor refuel cavity had been drained. In addition, the

inspectors noted that the poly bottle had a capacity of about 5 gallons and the funnel

had a capacity of about 6 gallons, which suggested that the funnel had not overflowed.

Finally, the inspectors noted that Exelon entered bay 11 within a few hours of identifying

the water, visually inspected the bay, and found it dry. Exelon sampled the water, but

could not positively determine the source based on radiolytic or chemical analysis. This

issue was entered into the corrective action program as part of the common cause

evaluation IR 845297.

3.5

Reactor Cavity Seal Leakage Action Plan for 1R22

a.

Scope of Inspection

Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancement

(3), stated, in part:

If leakage is detected [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.

7

The inspectors reviewed Exelon's 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. (see Figures A-1 thru A-5)

The inspectors noted that Exelon's action plan, in part, directed the following actions to

be taken:

• 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 />.

• 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 IR 842333. In addition, these

items were included in a common cause evaluation as part of IR 845297.

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

Exelon for any water or moisture damage; no issues were identified. Exelon stated

follow-up ultrasonic test (UT) examinations will be performed during the next refuel

outage to evaluate the upper drywell shell for corrosion as a result of the water intrusion

into the sand bed bays.

On Nov. 15, water was found in sand bed bay 11 poly bottle (see Section 3.4 above).

The inspectors observed that Exelons action plan was inconsistent with the actions

taken in response to increased cavity seal leakage. The inspectors observed that the

actual actions taken were in response to visual indication that the strippable coating was

de-laminating, and later, in response to visual indication of water intrusion into a sand

bed bay. The inspectors noted that the action plan, as written, did not direct a sand bed

entry or sand bed internal inspection, because the cavity trough drain flow never

exceeded 12 gpm. The inspectors also noted that, if the sand bed bays had been

closed out by Nov. 2, as originally scheduled (before a coating problem was identified,

see Section 3.9), then Exelon personnel would not have been inside of bay 11 on Nov.

8, and therefore, would not have visually identified the water intrusion into bay 11.

8

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

calculated and, as a result, water intrusion into the sand bed region occurred at a value

below the threshold established in the action plan.

3.6

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.

The inspectors reviewed structural inspection reports 187-001 and 187-002, performed

under WO 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 10-foot elevation. In addition, the inspectors reviewed selected

photographs taken during the inspection, and directly observed portions of the moisture

barrier seal.

b.

Observations

The inspectors performed a general visual observation of the moisture barrier seal

inside the drywell on multiple occasions during the outage. For the areas directly

observed, the inspectors did not identify any significant problems or concerns.

3.7

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 inspectors directly observed portions of Exelon's activities to perform a 100% visual

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

performed independent field walkdowns to determine the as-found conditions in portions

of 6 sand bed bays, and as-left conditions in 4 sand bed bays. The inspectors made

general visual observations inside the sand bed bays to independently identify flaking,

peeling, blistering, cracking, de-lamination, discoloration, corrosion, or mechanical

damage.

9

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 directly observed field collection, recording, and

reporting of VT inspection data. The inspectors also reviewed a sample of NDE

technician visual testing qualifications.

The inspectors reviewed Exelon's activities to evaluate and repair the moisture barrier

seal in sand bed bay 3.

b.

Observations

The purpose of the moisture barrier seal is to prevent water from entering a gap below

the concrete floor in the sand bed region. The inspectors observed that NDE visual

inspection activities were conducted in accordance with approved procedures. The

inspectors noted 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 problems in 7 of the 10 sand bed

bays, including small 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 identified

problems were entered into the corrective action program and subsequently repaired

(IRs are listed in the Attachment). In addition, these items were included in a common

cause evaluation as part of IR 845297.

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

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

was identified. Exelon's 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 drywell shell surface were repaired. This issue

was entered into the corrective action program as IRs 839194, 841957, and 844288.

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

2006, no moisture barrier seal problems were identified in any sand bed bay.

3.8

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.

The inspectors reviewed a vendor memorandum which summarized the vendor

10

inspection findings for a coating inspection of the as-found condition of the ASME

Service Level I coating of the drywell shell inner surface. The final detailed report, with

specific elevation notes and photographs, was not available during the on-site portion of

this inspection. The inspectors reviewed selected photographs taken during the coating

inspection and the initial assessment and disposition of identified coating deficiencies.

The inspectors also interviewed the vendor coating inspector. The coating inspection

was conducted on Oct. 30, by a qualified ANSI Level III coating inspector.

b.

Observations

The inspectors performed a general visual observation of the drywell shell coating on

multiple occasions during the outage. The inspectors noted that Exelon's documented

inspection results were consistent with the conditions directly observed by the

inspectors. The inspectors did not identify any significant problems or concerns with

Exelon's inspection activities.

3.9

Drywell Shell External Coatings 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 directly 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). The inspectors

performed independent field walkdowns to determine the as-found conditions of the

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

11 after coating repairs. The inspectors made general visual observations inside the

sand bed bays to independently identify flaking, peeling, blistering, de-lamination,

cracking, discoloration, corrosion, or mechanical damage.

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 NDE supervisors and technicians, and

directly observed field collection, recording, and reporting 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 noted that Exelon completed the

11

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 IRs

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 of the repaired area

and the general condition of the epoxy coating and moisture barrier seal in bay 11. The

inspectors noted that Exelon's inspection data reports were consistent with the

conditions directly observed by the inspectors.

All sand bed bays had been inspected by the same NDE technician. 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 concerns or problems 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 on the surface of the drywell shell prior to the initial

application of the epoxy coating, 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 an approximately 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 of the general conditions in bay 5 and

9. The inspectors observed that Exelon's inspection data reports adequately described

the conditions directly observed by the inspectors.

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 problems were identified in any sand bed bay.

This inconsistency, between the results of the 2006 coating inspection and the 2007

inspection, was entered into the corrective action program as IR 839053.

During the final closeout of bays 3, 5, and 7, minor chipping in the epoxy coating was

identified, which Exelon described as incidental mechanical damage from personnel

entry for inspection or repair activities. All identified problems were entered into the

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

12

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.

3.10

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 directly observed NDE activities and reviewed UT examination records.

The inspectors independently performed field walkdowns to determine the conditions in

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

data to licensee established acceptance criteria in Specification IS-328227-004, 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, and 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) for the drywell shell, as applicable. For UT data sets, such as 7x7

arrays, the Technical Evaluation calculated statistical parameters and determined the

data set distributions were acceptable. The Technical Evaluation also compared the

data values to the corresponding values recorded by the 2006 UT examinations in the

same locations, and concluded there were no significant differences in measured

thicknesses and no observable on-going corrosion. The inspectors independently

verified that the UT thickness values satisfied applicable acceptance criteria.

13

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 ML071240008).

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 Exelon attributed to 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:

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

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

• Bay 5 trench had a few ounces of water in it. The inspectors 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. This issue was entered into the corrective action program as IR

846209 and IR 846240.

• 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.

3.11

Drywell Shell Thickness Measurements

a.

Scope of Inspection

Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancements

(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 NDE activities and independently performed field

walkdowns to determine the condition of the drywell shell 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

14

established acceptance criteria in Specification IS-328227-004, 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-foot & 71-foot"

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

The inspectors reviewed UT examination records for the following:

• Sand bed region elevation, inside the drywell

• All 10 sand bed bays, drywell external

• Various drywell elevations between the 50-foot 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 directly observed field collection, recording, and

reporting 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 addition, the inspectors performed a general

visual observation of the drywell shell general conditions on multiple occasions during

the outage.

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

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) for the drywell shell, as

applicable. For UT data sets, such as 7x7 arrays, the Technical Evaluations calculated

statistical parameters and determined the data set distributions were acceptable. The

Technical Evaluations also compared the data values to the corresponding values

recorded by the 2006 UT examinations in the same locations, and concluded there were

no significant differences in measured thicknesses and no observable on-going

corrosion. The inspectors independently verified that the UT thickness values satisfied

applicable acceptance criteria.

15

3.12

One Time Inspection Program

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

inspectors reviewed UT results from approximately 24 selected piping sample locations

in the main steam, spent fuel pool cooling, domestic water, and demineralized water

systems.

b.

Observations

The inspectors noted that for two UT sample locations, the measured piping thickness

did not satisfy the acceptance criteria, and the results were evaluated within the

corrective action program. The inspectors did not identify any significant problems or

concerns with Exelon's inspection activities.

3.13

"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 inspectors directly observed NDE examinations of the "B" isolation condenser shell

performed under WO C2017561-11. The NDE examinations included a visual

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

previously tested in 1996 and 2002, additional UT tests in areas of identified pitting and

corrosion, and spark testing of the final interior shell coating. The inspectors 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.

16

b.

Observations

The inspectors noted that the UT results satisfied the acceptance criteria for minimum

wall thickness. The inspectors did not identify any significant problems or concerns with

Exelon's inspection activities.

3.14

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 structures,

systems, and components to verify integrity and confirm the

absence of identified aging effects. Perform prior to the period of

extended operation.

The inspectors directly observed the following field 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

The inspectors noted that Exelon's documented inspection results were consistent with

the conditions directly observed by the inspectors. The inspectors did not identify any

significant problems or concerns.

3.15

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 Exelon structural

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

observations with the documented visual inspection results.

17

b.

Observations

The inspectors noted that Exelon's documented inspection results were consistent with

the conditions directly observed by the inspectors. The inspectors did not identify any

significant problems or concerns with Exelon's inspection activities.

3.16

Buried Emergency 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 directly observed the following activities, performed under WO

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

The inspectors did not identify any significant problems or concerns.

3.17

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.

The inspector accompanied electrical technicians and an electrical design engineer

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

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

acceptance criteria. The inspector directly observed the visual inspection activities,

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.

18

b.

Observations

The inspectors noted that Exelon's documented inspection results were consistent with

the conditions directly observed by the inspectors. The inspectors did not identify any

significant problems or concerns with Exelon's inspection activities.

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 inspectors directly observed field testing activities for the 4 kilovolts feeder cable

from the auxiliary transformer secondary to Bank 4 switchgear and independently

reviewed the test results. A Doble and power factor test of the transformer, with the

cable connected to the transformer secondary, was performed, in part, to detect

deterioration of the cable insulation. The inspectors also compared the current test

results to previous test results from 2002. In addition, the inspectors interviewed plant

electrical engineering and maintenance personnel.

b.

Observations

The inspectors noted that the cable test results satisfied the acceptance criteria. The

inspectors did not identify any significant problems or concerns with Exelon's test

activities.

3.19

Fatigue Monitoring 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 reviewed Exelon's proposed usage of the FatiguePro software program,

reviewed the list of high cumulative usage factor components, and interviewed the

fatigue program manager.

19

b.

Observations

The inspectors noted that the FatiguePro program, although in place and ready to go,

had 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.

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 for the specific ASME Section XI,

Subsection IWE Enhancements (Sections 3.7, 3.9, 3.10, & 3.11).

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.

20

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.

4OA6 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.

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, NRR

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

Drywell Sand Bed Water Intrusion, Drain

Monitoring, and Coating Deficiency (Section 2.2)

Closed

None.

LIST OF ACRONYMS

ANSI

American National Standards Institute

ASME

American Society of Mechanical Engineers

CLB

Current Licensing Basis

EPRI

Electric Power Research Institute

FME

Foreign Material Exclusion

IP

[NRC] Inspection Procedure

IR

[Exelon] Issue Report

gpm

Gallons per Minute

NDE

Non-destructive Examination

NEI

Nuclear Energy Institute

NRC

U. S. Nuclear Regulatory Commission

NRR

Office of Nuclear Reactor Regulation

OC

Oyster Creek

SER

[NRC] Safety Evaluation Report

SSC

Structures, Systems, and Components

SDP

Significance Determination Process

TE

Technical Evaluation

UFSAR

Updated Final Safety Analysis Report

URI

[NRC] Unresolved Item

UT

Ultrasonic Test

VT

Visual Testing

WO

Work Order

A-3

LIST OF DOCUMENTS REVIEWED

License Renewal Program Documents

2130-06-20364 Letter from AmerGen to the NRC, 10 CFR 54.21(b) Annual Amendment to OC

License Renewal Application (TAC No. MC7624), dated July 18, 2006

2130-07-20502 Letter from AmerGen to the NRC, 10 CFR 54.21(b) Annual Amendment to OC

License Renewal Application (TAC No. MC7624), dated July 9, 2007

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

Plant Procedures and Specifications

645.6.017, Fire Barrier Penetration Surveillance, Rev 13

ER-AA-330-008, Service Level I & Safety-Related Service Level III Protective Coatings, Rev. 6

ER-AA-335-004, Manual UT of Material Thickness & Interfering Conditions, Rev. 2

ER-AA-335-018, Detailed, General, VT-1, VT-1C, VT-3 and VT-3C Visual Examination of

ASME Class MC and CC Containment Surfaces and Components, Rev. 5

ER-OC-450, Structures Monitoring Program, Rev. 1

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

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

MA-AA-723-500, Inspection of Non EQ Cables and Connections for Managing Adverse

Localized Environments, Rev 2

RP-OC-6006, Reactor Cavity and Equipment Pit Leak Mitigation and Decontamination, Rev. 0

Specification SP 1302-32-035, Inspection and Minor Repair of Coating on Concrete & Drywell

Shell Surfaces in the Sand Bed Region, dated 2/24/93

Incident Reports (IRs)

• = IRs written as a result of the NRC inspection

330592

546915

547236

549432

557180

557898

804754

836362*

836367*

836395

836802

836814

836994

837188

837554

837613

837628

837647

837765

838148

838402

838509

838523*

838833

839028

839033

839053

839182

839185

839188

839192

839194

839204

839211

839214

839848

841543

841957

841957

842010

842323

842325

842333

842355

842357

842359

842360

842566

843190

843209

843380

843608

844815

845297

846240

939194

Work Orders (WOs)

WO C20117279

WO C2017279

WO C2017561-11

WO R2083515

WO R2088180-07

WO R2093471

WO R2094623

WO R2095467

WO R2095468

WO R2095469

WO R2095471

WO R2095857

WO R209585708

WO R2097321-01

WO R2098682-06

WO R2098683

WO R2102695

WO R2105179

WO R2105477

WO R2105479

WO R2105515

WO R2105516

WO R2117387

WO R21173870

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Ultrasonic Test Non-destructive Examination Records

1R21LR-001, 11 3 elevation, October 18, 2006

1R21LR-002, 50 2 elevation, October 18, 2006

1R21LR-026, 87 5 elevation, October 23, 2006

1R21LR-028, 87 5 elevation, October 23, 2006

1R21LR-029, 23 6 elevation, October 23, 2006

1R21LR-030, 23 6 elevation, October 24, 2006

1R21LR-033, 71 6 elevation, October 26, 2006

1R21LR-034, 71 6 elevation, October 26, 2006

1R22-LRA-019, 23' 6 elevation, November 5, 2008

1R22-LRA-020, 51' elevation, October 29, 2008

1R22-LRA-021, 50' 2 elevation, October 29, 2008

1R22-LRA-022, 50' 2 elevation, October 29, 2008

1R22-LRA-023, 51' elevation, October 30, 2008

1R22-LRA-024, 51' 10 elevation, October 29, 2008

1R22-LRA-030, 11' 3 elevation, October 30, 2008

1R22-LRA-039, 10' 3 elevation, November 3, 2008

1R22-LRA-040, 10' 3 elevation, November 3, 2008

1R22-LRA-050, 87' 5 elevation, November 4, 2008

1R22-LRA-057, 87' 5 elevation, November 4, 2008

1R22-LRA-058, 87' 5 elevation, November 4, 2008

1R22-LRA-061, 23' 6 elevation, November 5, 2008

1R22-LRA-064, 11' 3 elevation, November 3, 2008

1R22-LRA-065, 11' 3 elevation, November 3, 2008

1R22-LRA-067, 11' 3 elevation, November 4, 2008

1R22-LRA-068, 11' 3 elevation, November 4, 2008

1R22-LRA-071, 71' 6 elevation, November 3, 2008

1R22-LRA-073, 11' 3 elevation, November 5, 2008

1R22-LRA-074, 71' 6 elevation, November 5, 2008

1R22-LRA-077, 60' elevation, November 6, 2008

1R22-LRA-078, 11' 6 elevation, November 7, 2008

1R22-LRA-079, 71' 6 elevation, November 5, 2008

1R22-LRA-088, 23' 6 elevation, November 11, 2008

NDE Data Report 2008-007-017

NDE Data Report 2008-007-030

NDE Data Report 2008-007-031

UT Data Sheet 21R056

Visual Test Inspection Non-destructive Examination Records

1R21LR-024 , Bay 5, October 21, 2006

1R21LR-025, Bay 17, October 21, 2006

1R21LR-032, Bay 5, October 26, 2006

1R22-LRA-026, Bay 1, October 30, 2008

1R22-LRA-027, Bay 5, October 29, 2008

1R22-LRA-028, Bay 9, October 29, 2008

1R22-LRA-029, Bay 17, October 30, 2008

1R22-LRA-031, Bay 9, October 29, 2008

1R22-LRA-032, Bay 5, October 29, 2008

1R22-LRA-035, Bay 13, October 30, 2008

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1R22-LRA-036, Bay 1, October 30, 2008

1R22-LRA-037, Bay 13, October 30, 2008

1R22-LRA-038, Bay 17, October 30, 2008

1R22-LRA-046, Bay 11, October 31, 2008

1R22-LRA-047, Bay 11, October 31, 2008

1R22-LRA-048, Bay 15, October 31, 2008

1R22-LRA-049, Bay 15, October 31, 2008

1R22-LRA-050, Bay 19, October 31, 2008

1R22-LRA-051, Bay 19, October 31, 2008

1R22-LRA-052, Bay 3, October 31, 2008

1R22-LRA-053, Bay 3, October 31, 2008

1R22-LRA-054, Bay 7, October 31, 2008

1R22-LRA-055, Bay 7, October 31, 2008

1R22-LRA-082, Bay 5, November 7, 2008

1R22-LRA-083, Bay 15, November 8, 2008

1R22-LRA-084, Bay 19, November 8, 2008

1R22-LRA-091, Bay 19, November 8, 2008

NDE Certification Records

NDE Certification #0977 for Richard L. Alger, dated 10/29/08

NDE Certification #1421 for M. Kent Waddell, dated 10/29/08

Calculations

C-1301-187-E310-037, Drywell Corrosion, Rev 1

C-1302-187-5320-024, O. C. Drywell Ext. UT Evaluation in Sand Bed, Rev 2

C-1302-187-E310-037, Drywell Corrosion, Rev. 2

C-1302-187-E310-041, Statistical Analysis of Drywell Vessel Sand Bed Thickness Data 1992,

1994, 1996, and 2006, Rev. 0

Technical Evaluations

Tech Eval 00330592.27.42, 2008 Drywell Sand Bed UT Data - External Data

Tech Eval 00330592.27.43, 2008 UT Data of the Sand Bed Trenches

Tech Eval 00330592.27.45, 2008 Drywell UT Data at Elevations 23 and 71 foot

Tech Eval 00330592.27.46, 2008 Degradation Coating Found in Sand Bed Bay 11

Tech Eval 00330592.27.88, 2008 Sand Bed UT Data - Internal Grids

Miscellaneous Documents

00553792-02, Drywell Structural Integrity Basis from 1R21 Inspections

00725855-03, Oyster Creek License Renewal Commitment Implementation 2008 FASA 08-003, OC Bolting Integrity Program Commitment Change Evaluation, February 28, 2008 08-004, Oyster Creek LR Commitment Change for RPV Axial Weld Examination Relief for 60-

years of Operation, March 28, 2008

168-002 (R2114262), Structures and Components Monitoring Report, Intake Tunnel and

Expansion Joints, October 29, 2008

168-003 (R2120584-05), Structures and Components Monitoring Report, SW/ESW Piping at

Intake Structure Underdeck (North Side), November 3, 2008

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187-001 (R2097321-01), Structures and Components Monitoring Report, Drywell Internal

Structures, Above El. 23' - 0, November 1, 2008

1R22 Startup PORC, License Renwal Commitments and Inspection Status, Undated

Assessment of Oyster Creek's response to condition document IR 00842333, Undated

Chemistry Data for Sandbed Bay 17 Water, Reactor Water, Fuel Pool, RBCCW, TBCCW, and

Condensate Transfer, November 10 and 11, 2008

IS-328227-004, Functional Requirements for Drywell Containment Vessel Thickness

Examinations, Rev. 13

IS-328227-004, Specification for OC Functional Requirements for Drywell Containment Vessel

Thickness Examinations, Rev. 14

Letter from Williams Industrial Services to Oyster Creek Generating Station, Re: Brovo Iso

Condenser, Internal Coating Assessment, November 2, 2008

Letter from Williams Specialty Services to Mr. Pete Tamburro, Oyster Creek Generating Station,

Inspection of Safety Related Coating Systems Inner Surface of the Drywell Shell Elevations

23-6 and 46, November, 3, 2008

ML-DCS-104, The Instacote Application System, Rev. 8

OYS-20872, Letter from R. John Diletto, Exelon Power Labs to Tom Quintenz, Oyster Creek,

Material Analysis of Samples Removed from Oyster Creek Sand Bed Bay Nos. 11 & 3 in

Support of Drywell Exterior Liner Inspection Outage Activities, Oyster Creek, Dated

November 11, 2008

OYS-20872, Letter from R. John Diletto, Exelon Power Labs to Tom Quintenz, Oyster Creek,

Material Analysis of Samples Removed from Sand Bed Bay Nos. 11 & 3 in Support of Drywell

Exterior Liner Inspection Outage Activities, Oyster Creek, Dated November 7, 2008

OC Drywell Coating Status Update Report, Power Point Presentation, November 9, 2008

Oyster Creek Nuclear Generating UFSAR, Section 3.8.2.8, Drywell Corrosion, Rev. 15

PORC Meeting (08-16) Report, November 15, 2008

Reactor Cavity Leakage Action Plan for 1R22

SP 1302-32-035, Specification for Inspection and Minor Repair of Coating on Concrete & Drywell

Shell Surfaces in the Sandbed Region, Rev 0

Timeline of Documents Associated with the Strippable Coating on the Rx Cavity and Water

Leakage Monitoring Through the Drains, undated

Transformer Inspection and Test Results, Bank #4 Aux, November 3, 2008

White Paper on Water Leakage onto the Exterior Surface of the Drywell Shell, undated

NRC Documents

Generic Letter 87-05, Request for Additional Information Assessment of Licensee Measures to

Mitigate and/or Identify Potential Degradation of Mark I Drywells

Information Notice No. 86-99, Degradation of Steel Containments

RIS 2000-17, Managing Regulatory Commitments Made by Licensees to the NRC Staff,

September 21, 2000

Safety Evaluation Report, Related to the License Renewal of OC, March 2007

Safety Evaluation Report, Related to the License Renewal of OC Supplement 1, September 2008

Industry Documents

NEI 99-04, Guidelines for Managing NRC Commitments, Rev. 0

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Figure A-1, Cross Section of the Oyster Creek Drywell

Source: Oyster Creek September 2007 Evidentiary Hearing - Applicant Exhibit 40, AmerGen's

Oyster Creek Generating Station License Renewal ACRS Presentation, ML072820416

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Figure A-2, Oyster Creek Reactor Cavity Seal Detail

Source: Oyster Creek September 2007 Evidentiary Hearing - Applicant Exhibit 40, AmerGen's

Oyster Creek Generating Station License Renewal ACRS Presentation, ML072820416

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Figure A-3, Reactor Cavity Trough Drain Detail

Source: Oyster Creek September 2007 Evidentiary Hearing - Applicant Exhibit 40, AmerGen's

Oyster Creek Generating Station License Renewal ACRS Presentation, ML072820416

Gap Between Drywell Steel

Shell and Concrete Shield Wall

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Figure A-4, Oyster Creek Sandbed Region Detail Showing the Sandbed Drain Line

Source: Oyster Creek September 2007 Evidentiary Hearing - Applicant Exhibit 40, AmerGen's

Oyster Creek Generating Station License Renewal ACRS Presentation, ML072820416

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Figure A-5, Oyster Creek Drywell Arrangement Showing the Sandbed Drain Monitoring Using

Remote Poly Bottles

Source: Oyster Creek September 2007 Evidentiary Hearing - Applicant Exhibit 40, AmerGen's

Oyster Creek Generating Station License Renewal ACRS Presentation, ML072820416