ML090210106
| 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: |
| 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
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:
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
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 836802 838402 839192 842323 843380
546915 836814 838509 839194 842325 843608
547236 836994 838523* 839204 842333 844815
549432 837188 838833 839211 842355 845297
557180 837554 839028 839214 842357 846240
557898 837613 839033 839848 842359 939194
804754 837628 839053 841543 842360
836362* 837647 839182 841957 842566
836367* 837765 839185 841957 843190
836395 838148 839188 842010 843209
Work Orders (WOs)
WO C20117279 WO R2095857 WO R2117387
WO C2017279 WO R209585708 WO R21173870
A-4
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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Gap Between Drywell Steel
Shell and Concrete Shield Wall
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
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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