ML091980459
| ML091980459 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 06/17/2009 |
| From: | Darrell Roberts Division of Reactor Safety I |
| To: | Pardee C Exelon Generation Co |
| References | |
| FOIA/PA-2009-0070 IR-08-007 | |
| Download: ML091980459 (29) | |
See also: IR 05000219/2008007
Text
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G:\DRS\Engineering Branch 1\_LicRenewal\Oyster Creek\2008 Outage\InReport\OC 2008-07
LRI rev-7.doc
Mr. Charles G. Pardee
Chief Nuclear Officer (CNO) and Senior Vice President
Exelon Generation Company, LLC
200 Exelon Way
Kennett Square, PA 19348
SUBJECT: OYSTER CREEK GENERATING STATION - NRC LICENSE RENEWAL
FOLLOW-UP INSPECTION REPORT 05000219/2008007
Dear Mr. Pardee
On December 23, 2008, the U. S. Nuclear Regulatory Commission (NRC) completed an
inspection at your Oyster Creek Generating Station. The enclosed report documents the
inspection results, which were discussed on December 23, 2008, with Mr. T. Rausch, Site Vice
President, Mr. M. Gallagher, Vice President License Renewal, and other members of your staff.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commission's rules and regulations and with the conditions of your license.
Particular focus occurred on the inservice inspection of the drywell containment. Based on the
results of the NRC's inspection, the NRC staff identified that there were no safety significant
conditions with respect to the drywell containment that effected current operations.
With respect to 10 CFR 54 activities and the NRC staff's Final Safety Evaluation Report (SER)
for License Renewal - NUREG 1845 (Volume 1 ml 071290023 & Volume 2 ml 071310246), we
observed that you are implementing the proposed license conditions of that document and the
associated regulatory commitments 'as though they were in effect. As you well know, an appeal
of a licensing board decision regarding the Oyster Creek application for a renewed license is
pending before the Commission related to the adequacy of the aging management program for
the Oyster Creek drywell. The NRC's Reactor Oversight Process mid-cycle letter of September
2, 2008 indicated that we would be conducting inspections (outage and non-outage) related to
license renewal prior to the period of extended operations. The NRC is conducting these
inspections using the guidance of Inspection Procedure (IP) 71003 "Post-Approval Site
Inspection for License Renewal" as a prudent measure in order to take the opportunity to make
such observations of Oyster Creek license renewal activities during the last refuel outage prior
to entering the period of extended operations.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.' The enclosed report records the inspector's observations only. We are doing this
because the proposed license conditions and associated regulatory commitments made as a
part of the 10 CFR 54 application are notin effect. These conditions and commitments are not
in effect because the application for a renewed license remains under Commission review for
final decision, and a renewed license has not been approved for Oyster Creek
bibw~smt infthimecod was dellete M
accudeage, with the EeO~m of Inbform At&o
QQ-7 11
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C. Pardee 2
C. Pardee 2
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its
enclosure will be available electronically for public inspection in the NRC Public Document
Room or from the Publicly Available Records (PARS) component of NRC's document system
(ADAMS). ADAMS is accessible from the NRC Web-site at http://www.nrc.gov/readinq-
rm/adams.html (the Public Electronic Reading Room).
We appreciate your cooperation. Please contact me at (610) 337-5183 if you have any
questions regarding this letter.
L (b)(5)
Sincerely,
Darrell Roberts, Director
Division of Reactor Safety
Docket No. 50-219
License No. DPR-16
Enclosure: Inspection Report No. 05000219/2008007
w/Attachment: Supplemental Information
C. Crane, President and Chief Operating Officer, Exelon Corporation
M. Pacilio, Chief Operating Officer, Exelon Nuclear
T. Rausch, Site Vic6 President, Oyster Creek Nuclear Generating Station
J. Randicr, Plant Manager, Oyster Creek Generating Station
J. Kandasamy, Regulatory Assurance Manager, Oyster Creek
R. DeGregorio, Senior Vice President, Mid-Atlantic Operations
K. Jury,Vice President, Licensing and Regulatory Affairs
P. Cowan, Director, Licensing
B. Fewell, Associate General Counsel, Exelon
Correspondence Control Desk, AmerGen
Mayor of Lacey Township
P. Mulligan, Chief, NJ Dept of Environmental Protection
R. Shadis, New England Coalition Staff
E. Gbur, Chairwoman - Jersey Shore Nuclear Watch
E. Zobian, Coordinator - Jersey Shore Anti Nuclear Alliance
P. Baldauf, Assistant Director, NJ Radiation Protection Programs
C. Pardee 2
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its
enclosure will be available electronically for public inspection in the NRC Public Document
Room or from the Publicly Available Records (PARS) component of NRC's document system
(ADAMS). ADAMS is accessible from the NRC Web-site at http://www.nrc.qov/readinq-
rm/adams.html (the Public Electronic Reading Room).
We appreciate your cooperation. Please contact me at (610) 337-5183 if you have any
questions regarding this letter.
4jcV
(b)(5) Sincerely,
Richard Conte, Chief
Engineering Branch 1
Division of Reactor Safety
Docket No. 50-219
License No. DPR-16
Enclosure: Inspection Report No. 05000219/2008007
w/Attachment: Supplemental Information
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: _ (Reviewer's Initials) Adams Accession No.
DOCUMENT NAME: G:\DRS\Engineering Branch 1\Richmond\OC 2008-07 LR\_Report\OC 2008-07'LRIrev-6a.doc
After declaring this document "An Official Agency Record" it will., be released to the Public.
IDRv indicate in the box:"C" = COoV without~R/R
To receive a conv of this document, attachmentlenclosure E" =conY with attachmentlenclosure "N"' No conyOFC
OFIC R/DSRI/DRS RIIDRP R/R
NAME JRichmond/ RConte/ RBellamy/ DRoberts/
DATE 01/ /09 01/ /09 01/ /09 01/ /09
OFF*IIAL R D -JPY
C. Pardee 2
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket No.: 50-219
License No.: DPR-16
Report No.: 05000219/2008007
Licensee: Exelon Generation Company, LLC
Facility: Oyster Creek Generating Station
Location: Forked River, New Jersey
Dates: October 27 to November 7, 2008 (on-site inspection activities)
November 13, 15, and 17, 2008 (on-site inspection activities)
November 10 to December 23, 2008 (in-office review)
Inspectors: J. Richmond, Lead
M. Modes, Senior Reactor Engineer
G. Meyer, Senior Reactor Engineer
T. O'Hara, Reactor Inspector
J. Heinly, Reactor Engineer
J. Kulp, Resident Inspector, Oyster Creek
Approved by: Richard Conte, Chief
Engineering Branch 1
Division of Reactor Safety
ii
SUMMARY OF FINDINGS
IR 05000219/2008007; 10/27/2008 - 12/23/2008; Exelon, LLC, Oyster Creek
Generating Station; License Renewal Follow-up
The report covers a multi-week inspection of license renewal follow-up items. It was conducted
by five region based engineering inspectors and the Oyster Creek resident inspector. The
inspection was conducted in accordance with Inspection Procedure 71003 "Post-Approval Site
Inspection for License Renewal."
Even if we have a URI - do we not say no finding of significance were identified ????
Because the application for a renewed license remains under Commission review for final
decision, and a renewed license has not been aDoroved for Ovstpr .re.e.kC[ (b)(5)
(b)(5) J
In accordance with the NRC's memorandum of understanding with the State of New Jersey,
Department of Environmental Protection, Bureau of Nuclear Engineering, state engineers
observed portions of the NRC inspection activities.
This report documents inspection observations9 ???L (b)(5)
(b)(5) .
a
2
REPORT DETAILS
Summary of Plant Status
The Oyster Creek Generating Station was in a scheduled refueling outage during the on-site
portions of this inspection.
At the time of the inspection, AmerGen Energy Company, LLC was the licensee for Oyster
Creek Generating Station. As of January 8, 2009, the OC license was transferred to Exelon
Generating Company, LLC by license amendment No. 271 (ML082750072).
4. OTHER ACTIVITIES (OA)
40A5 License Renewal Follow-up (IP 71003)
1 Purpose of Inspection and Sample Selection Process
Background and Purpose
An appeal of a licensing board decision regarding the Oyster Creek application for a
renewed license is pending before the Commission related to the adequacy of the aging
management program for the Oyster Creek drywell. The NRC's Reactor Oversight
Process mid-cycle letter of September 2, 2008 indicated that we would be conducting
inspections (outage and non-outage) related to license renewal prior to the period of
extended operations. The NRC is conducting these inspections using the guidance of
Inspection Procedure (IP) 71003 "Post-Approval Site Inspection for License Renewal"
as a prudent measure in order to take the opportunity to make such observations of
Oyster Creek license renewal activities during the last refuel outage prior to entering the
period of extended operations.
Inspection observations were considered, in light of pending 10 CFR 54 license renewal
commitments and license conditions, as documented in NUREG-1875, "Safety
Evaluation Report (SER) Related to the License Renewal of Oyster Creek Generating
Station," (Volume 1 ml 071290023 & Volume 2 ml 071310246) as well as programmatic
performance under on-going implementation of 10 CFR 50 current licensing basis (CLB)
requirements.
Normally IP 71003 verifies that license renewal activities are implemented in accordance
with Title 10 of the Code of Federal Regulations (CFR) Part 54, "Requirements for the
Renewal of Operating Licenses for Nuclear Power Plants." The license renewal
activities are generally related to: 1) license conditions added as part of a renewed
license and the associated license renewal commitments; 2) selected aging
management programs and implementing procedures; 3) license renewal commitments
revised after the renewed license was granted; 4) need to revise the updated Safety
Analysis Report; and, 5) newly identified structures, systems and components. What
was not completed in this inspection for the reasons stated below was the
implementation of guidance sections 03.01 .b.1 and 03.01 .b.3 of the procedure which
calls for a review of appropriate actions and evaluation for enforcement and
significance. Also items-4) and 5) above were not applicable for this inspection.
For 10 CFR 54 activities, the report records the inspector's observations only. We are
doing this because the proposed license conditions and associated regulatory
commitments made as a part of the 10 CFR 54 application are not in effect, These
conditions and commitments are not in effect because the application for a renewed
license remains under Commission review for final decision, and a renewed license has
not been approved for Oyster Creek.
Sample Selection Process
The reviewed SER proposed commitments and license conditions were selected based
on several attributes including: the risk significance using insights gained from sources
such as the NRC's "Significance Determination Process Risk Informed Inspection
Notebooks," revision 2; the extent and results of previous license renewal audits and
inspections of aging management programs; the extent or complexity of a commitment;
and the extent that baseline inspection programs will inspect a system, structure, or
component (SSC), or commodity group.
For each commitment and on a sampling basis, the inspectors reviewed supporting
documents including completed surveillances, conducted interviews, performed visual
inspection of structures and components including those not accessible during power
operation, and observed selected activities described below. The inspectors also
reviewed selected corrective actions taken as a consequence of previous license
renewal inspections.
2. NRC Unresolved Item
3. Detailed Reviews
3.1 Reactor Refuel Cavity Liner Strippable Coating
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancement
(2), stated, in part:
A strippable coating will be applied to the reactor cavity liner to prevent water
intrusion into the gap between the drywell shield wall and the drywell shell during
periods when the reactor cavity is flooded. Refueling outages prior to and during
the period of extended operation.
The inspector reviewed work order R2098682-06, "Coating application to cavity walls
and floors."
b. Observations
From Oct. 29 to Nov. 6, the cavity liner strippable coating limited cavity seal leakage into
the cavity trough drain at less than 1 gallon per minute (gpm). On Nov. 6, in one 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 3.2 below for
additional details). This issue was entered into the corrective action program as Issue
Report (IR) 841543. Exelon's initial evaluations identified several likely or contributing
causes, including:
a A portable water filtration unit was improperly placed in the reactor cavity,
which res lted in flow discharged directly on the strippable coating.
SA (b)(5) i spill into the cavity may have affected the coating integrity.
N50 po' installation inspection of the coating had been performed.
3.2 Reactor Refuel Cavity Seal Leakage Monitoring
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancement
(3), stated, in part:
The reactor cavity seal leakage trough drains and the drywell sand bed region
drains will be monitored for leakage, periodically.
The inspectors observed Exelon's cavity seal leakage monitoring activities. 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.
In addition, the inspectors reviewed Exelon's cavity trough drain flow monitoring plan
and pre-approved Action Plan. Exelon had established an administrative limit of 12 gpm
on the cavity trough drain flow, based on a calculation which indicated that cavity trough
drain flow of less than 60 gpm would not result in trough overflow into the gap between
the drywell concrete shield wall and the drywell steel shell.
b. Observations
Exelon monitored reactor refuel cavity seal leakage by monitoring and recording the flow
in the drain line from the cavity concrete trough to a plant drain system funnel.
On Oct. 27, Exelon isolated the cavity trough drain line to install a tygon hose to allow
drain flow to be monitored. On Oct. 28, the reactor cavity was filled. Drain line flow was
monitored frequently during cavity flood-up, and daily thereafter. On Oct. 29, a
boroscope examination of the drain line identified that the isolation valve had been left
closed. When the drain line isolation valve was opened, about 3 gallons of water
drained out. The drain flow then subsided to about an 1/8 inch stream (less than 1
gpm). This issue was entered into the corrective action program as Issue Report (IR)
837647.
LI? (b)(5)
On Nov. 6, the reactor cavity liner strippable coating started to de-laminate. The cavity
trough drain flow took a step change from less than 1 gpm to approximately 4 to 6 gpm.
Exelon increased monitoring of the trough drain to every 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and 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 />. All sand bed bays were originally scheduled to be closed out
by Nov. 2. However, due to a coating problem, personnel working in sand bed bay 11
identified dripping water on Nov. 8. After the cavity was drained, all sand bed bays were
inspected for any water or moisture damage; no deficiencies were identified. Exelon
stated follow-up ultrasonic test (UT) examinations will be performed to evaluate the
drywell shell during the next refuel outage. In addition, on Nov. 15, after cavity was
drained, water was found in the sand bed bay 11 poly bottle. These issues were
entered into the corrective action program as Issue Report (IR) xxx.
The inspectors observed that Exelon's pre-approved action plan was inconsistent with
the actual actions taken in response to increased cavity seal leakage. The plan did not
direct increased sand bed poly bottle monitoring, and would not have required a sand
bed entry or inspection until Nov 15, when water was first found in a poly bottle. The
pre-approved action plan directed:
If the cavity trough drain flow exceeds 5 gpm, then increase monitoring of the
cavity drain flow from daily to every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
, If the cavity trough drain flow exceeds 12 gpm, then increase monitoring of the
sand bed poly bottles from daily to every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
9 If the cavity trough drain flow exceeds 12 gpm and any water is found in a
sand bed poly bottle, then enter and inspect the sand bed bays.
3.3 Drywell Sand Bed Region Drain Monitoring
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section X1, Subsection IWE Enhancement
(3), stated, in part:
The sand bed region drains will be monitored daily during refueling outages.
The inspectors observed Exelon's activities to monitor sand bed drains. 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).
Exelon remotely monitored the sand bed drains by checking poly bottles attached via
tygon tubing to a funnel hung below each drain line. The sand bed drains were not
directly observed and were not visible from the outer area of the torus room, where the
poly bottles were located.
On Nov. 10, Exelon found 2 of the 5 tygon tubes disconnected and laying on the floor
(bays 3 and 7). Exelon personnel could not determine when the tubing was last verified
to be connected to the funnel. Both tubes were reconnected. This issue was entered
into the corrective action program as Issue Report (IR) 843209.
xxx need IR ##
On Nov. 15, during a daily check of sand bed bay 11 drain poly bottle, Exelon found the
poly bottle full (greater than 4 gallons). Exelon sampled the water, but could not
positively determine the source based on radiolytic or chemical analysis. The inspectors
.noted that Exelon had found the poly bottle empty during each check throughout the
outage, until Nov 15 (cavity was drained on Nov 12). The inspectors also noted that the
funnel, to which the tygon tubing was connected, had a capacity of about 6 gallons. Bay
11 was entered within a few hours, visually inspected, and found dry. This issue was
entered into the corrective action program as Issue Report (IR) xxx.
3.4
3.4 Reactor Cavity Trough Drain Inspection for Blockage
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancement
(13), stated, in part:
The reactor cavity concrete trough drain will be verified to be clear from blockage
once per refueling cycle. Any identified issues will be addressed via the
corrective action process.
The inspector reviewed a video recording record of a boroscope inspection of the cavity
trough drain line, performed by work order R2102695.
b. Observations
xxx Fix the ref. number
See observations in section 3.4 below.
3.5 Moisture Barrier Seal Inspection (inside sand bed bays)
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancements
(12 & 21), stated, in part:
Inspect the [moisture barrier] seal at the junction between the sand bed region
concrete [sand bed floor] and the embedded drywell shell. During the 2008
refueling outage and every other refueling outage thereafter.
The purpose of the moisture barrier seal is to prevent water from entering a gap below
the concrete floor in the sand bed region. Exelon performed a 100% visual test (VT)
inspection of the seal in the sand bed region (total of 10 bays). The inspectors directly
observed as-found conditions in portions of 6 sand bed bays, and as-left conditions in 4
sand bed bays.
The inspectors reviewed VT inspection records for each sand bed bay, and compared
their direct observations to the recorded VT inspection results. The inspectors reviewed
Exelon VT inspection procedures, interviewed non-destructive examination (NDE)
supervisors and technicians, and observed field collection and recording of VT
inspection data. The inspectors also reviewed a sample of NDE technician visual
testing qualifications.
The inspectors observed Exelon's activities to evaluate and repair the moisture barrier
seal in sand bed bay 3.
b. Observations
The inspectors observed that NDE visual inspection activities were conducted in
accordance with approved procedures. The inspectors verified that Exelon completed
the inspections, identified condition(s) in the moisture barrier seal which required repair,
completed the seal repairs in accordance with engineering procedures, and conducted
appropriate re-inspection of repaired areas.
The VT inspections identified moisture barrier seal deficiencies in 7 of the 10 sand bed
bays, including surface cracks and partial separation of the seal from the steel shell or
concrete floor. Exelon determined the as-found moisture barrier function was not
impaired, because no cracks or separation fully penetrated the seal. All deficiencies
were entered into the corrective action program and repaired (IRs are listed in the
Attachment).
Xxx ADD IR ## for bay 3 seal
The VT inspection for sand bed bay 3 identified a seal crack and a surface rust stains
below the crack. When the seal was excavated, some drywell shell surface corrosion
was identified. A laboratory analysis of removed seal material determined the epoxy
seal material had not adequately cured, and concluded it was an original 1992
installation issue. The seal crack and surface rust were repaired.
The inspectors compared the 2008 VT results to the 2006 results and noted that in 2006
no seal deficiencies were identified in any sand bed bay.
3.6 Drywell Shell External Coatings Inspection (inside sand bed bays)
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section X1, Subsection IWE Enhancements
(4 & 21 ), stated, in part:
Perform visual inspections of the drywell external shell epoxy coating in all 10
sand bed bays. During the 2008 refueling outage and every other refueling
outage thereafter.
The inspectors observed portions of Exelon's activities to perform a 100% visual
inspection of the epoxy coating in the sand bed region (total of 10 bays). In addition, the
inspectors directly observed as-found conditions of the epoxy coating in portions of 6
sand bed bays, and the as-left condition in sand bed bay 11, after coating repairs. The
inspectors also observed field collection, recording, and reporting of visual inspection
data.
The inspectors reviewed VT inspection records for each sand bed bay and compared
their direct observations to the recorded VT inspection results. The inspectors reviewed
Exelon VT inspection procedures, interviewed non-destructive examination (NDE)
supervisors and technicians, and observed field collection and recording of VT
inspection data. The inspectors also reviewed a sample of NDE technician visual
testing qualifications.
The inspectors directly observed Exelon's activities to evaluate and repair the epoxy
coating in sand bed bay 11. In addition, the inspectors reviewed Technical Evaluation
330592.27.46, "Coating Degradation in Sand Bed bay 11."
b. Observations
The inspectors observed that NDE visual inspection activities were conducted in
accordance with approved procedures. The inspectors verified that Exelon completed
the inspections, identified condition(s) in the exterior coating which required repair,
completed the coating repairs in accordance with engineering procedures, and
conducted appropriate re-inspection of repaired areas.
In sand bed bay 11,.the NDE inspection identified one small broken blister, about 1/4
inch in diameter, with a 6 inch surface rust stain, dry to the touch, trailing down from the
blister. During the initial investigation, three additional smaller surface irregularities
(initially described as surface bumps) were identified within a 1 to 2 square inch area
near the broken blister. The three additional bumps were subsequently determined to
be unbroken blisters. This issue was entered into the corrective action program as IR
838833 and 839053; all four blisters were evaluated and repaired. On Nov. 13, the
inspectors conducted a general visual observation (i.e., not a qualified VT inspection) of
the repaired area and the general condition in bay 11. The inspectors verified that
Exelon's inspection data reports appeared to accurately describe the conditions
observed by the inspectors.
To confirm the adequacy of the coating inspection, Exelon re-inspected 4 sand bed bays
(bays 3, 7, 15, and 19) with a different NDE technician. No additional deficiencies were
identified. In Technical Evaluation 330592.27.46, Exelon determined, by laboratory
analysis using energy dispersive X-ray spectroscopy, that the removed blister material
contained trace amounts of chlorine. Exelon also determined that the presence of
chlorine, in a soluble salt as chloride, can result in osmosis of moisture through the
epoxy coating. The analysis also concluded there were no pinholes in the blister
samples. In addition, the analysis determined approximately 0.003 inches of surface
corrosion had occurred directly under the broken blister. Exelon concluded that the
corrosion had taken place over approximately a 16 year period. In addition, UT dynamic
scan thickness measurements under the four blisters, from inside the drywell, confirmed
the drywell shell had nb significant degradation as a result of the corrosion. On Nov. 13,
the inspectors conducted a general visual observation (i.e., not a qualified VT
inspection) of the general conditions in bay 5 and 9. The inspectors observed that
Exelon's inspection data reports adequately described the conditions observed by the
inspectors.
xxx ADD IR ##A
In follow-up, Exelon reviewed a 2006 video of the sand beds, which had been made as
a general aid, not as part of an NDE inspection. The 2006 video showed the same 6
inch rust stain in bay 11., The inspectors compared the 2008 VT results to the 2006
results and noted that'in 2006 no coating deficiencies were identified in any sand bed
bay. This apparent deficiency with the 2006 coating inspection was entered into the
corrective action program as Issue Report (IR) xxx.
During the final closeout of bays 3, 5, and 7, minor chipping in the epoxy coating was
identified, and described as incidental mechanical damage from personnel entry for
inspection or repair activities. All deficiencies were entered into the corrective action
program and repaired (IRs are listed in the Attachment).
During the final closeout of bay 9, an area approximately 8 inches by 8 inches was
identified where the color of the epoxy coating appeared different than the surrounding
area. Because each of the 3 layers of the epoxy coating is a different color, Exelon
questioned whether the color difference could have been indicative of an original
installation deficiency. This issue was entered into the corrective action program as IR
844815, and the identified area was re-coated with epoxy.
3.7 Drywell Floor Trench Inspections
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancements
(5, 16, & 20), stated, in part:
Perform visual test (VT) and ultrasonic test (UT) examinations of the drywell shell
inside the drywell floor inspection trenches in bay 5 and bay 17 during the 2008
refueling outage, at the same locations that were examined in 2006. In addition,
monitor the trenches for the presence of water during refueling outages.
The inspectors observed non-destructive examination (NDE) activities and reviewed UT
examination records. In addition, the inspectors directly observed conditions in the
trenches on multiple occasions during the outage. The inspectors compared UT data to
licensee established acceptance criteria in Specification IS-318227-004, revision 14,
"Functional Requirements for Drywell Containment Vessel Thickness Examinations,"
and to design analysis values for minimum wall thickness in calculations C-1302-187-
E310-041, revision 0, "Statistical Analysis of Drywell Sand Bed Thickness Data 1992,
1994, 1996, and 2006," and C-1302-187-5320-024, revision 2, "Drywell External UT
Evaluation in the Sand Bed." In addition, the inspectors reviewed Technical Evaluation
330592.27.43, "2008 UT Data of the Sand Bed Trenches."
The inspectors reviewed Exelon UT examination procedures, interviewed NDE
supervisors and technicians, reviewed a sample of NDE technician UT qualifications.
The inspectors also reviewed records of trench inspections performed during two non-
refueling plant outages during the last operating cycle.
b. Observations
In Technical Evaluation 330592.27.43, Exelon determined the UT thickness values
satisfied the general uniform minimum wall thickness criteria (e.g., average thickness of
an area) and the locally thinned minimum wall thickness criteria (e.g., areas 2 inches or
less in diameter), as applicable. For UT data sets, such as 7x7 arrays, the TE
calculated statistical parameters and determined the data set distributions were
acceptable. The TE also compared the data set values to the corresponding 2006
values and concluded there were no significant differences and no observable on-going
corrosion. The inspectors independently verified that the UT thickness values satisfied
applicable acceptance criteria.
During two non-refueling plant outages during the last operating cycle, both trenches
were inspected for the presence of water and found dry by Exelon's staff and by NRC
inspectors (NRC Inspection Reports 05000219/2007003, 05000219/2007004, and
memorandum ML071240314).
During the initial drywell entry on Oct. 25, the inspectors observed that both floor
trenches were dry. On subsequent drywell entries for routine inspection activities, the
inspectors observed the trenches to be dry. On one occasion, Exelon observed a small
amount of water in the bay 5 trench, which they believed was from water spilled nearby
on the drywell floor; the trench was dried and the issue entered into the corrective action
program as IR 843190. On Nov. 17, during the final drywell closeout inspection, the
inspectors observed the following:
e Bay 17 trench was dry and had newly installed sealant on the trench edge
where concrete meets shell, and on the floor curb near the trench.
xxx ADD IR##
e Bay 5 trench had a few ounces of water in it. The inspector noted that within
the last day there had been several system flushes conducted in the immediate
area. Exelon stated the trench would be dried prior to final drywell closeout.
- Bay 5 trench had the lower 6 inches of grout re-installed and had newly
installed sealant on the trench edge where concrete meets shell, and on the floor
curb near the trench.
3.8 Drywell Shell Thickness Measurements
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancements
(1, 9, 14, and 21), stated, 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, and 11)stated, in part:
Conduct UT thickness measurements in the upper regions of the drywell shell.
Prior to the period of extended operation and two refueling outages later.
The inspectors directly observed non-destructive examination (NDE) activities and the
drywell shell conditions both inside the drywell, including the floor trenches, and in the
sand bed bays (drywell external shell). The inspectors reviewed UT examination
records and compared UT data results to licensee established acceptance criteria in
Specification IS-318227-004, revision 14, "Functional Requirements for Drywell
Containment Vessel Thickness Examinations," and to design analysis values for
minimum wall thickness in calculations C-1 302-187-E310-041, revision 0, "Statistical
Analysis of Drywell Vessel Sand Bed Thickness Data 1992, 1994, 1996, and 2006," and
C-1302-187-5320-024, revision 2, "Drywell External UT Evaluation in the Sand Bed." In
addition, the inspectors reviewed the Technical Evaluations (TEs) associated with the
UT data, as follows:
" TE 330592.27.42, "2008 Sand Bed UT data - External"
" TE 330592.27.45, "2008 Drywell UT Data at Elevations 23 & 71 foot"
" TE 330592.27.88, "2008 Drywell Sand Bed UT Data - Internal Grids"
The inspectors reviewed UT examination records for the following:
9 Sand bed region elevation, inside the drywell
- All 10 sand bed bays, drywell external
- Various drywell elevations between 50 and 87 foot elevations
- Transition weld from bottom to middle spherical plates, inside the drywell
- Transition weld from 2.625 inch plate to 0.640 inch plate (knuckle area), inside
the drywell
The inspectors reviewed Exelon UT examination procedures, interviewed NDE
supervisors and technicians, and observed field collection and recording of UT data.
The inspectors also reviewed a sample of NDE technician UT qualifications.
b. Observations
The inspectors observed that NDE UT examination activities were conducted in
accordance with approved procedures.
In Technical Evaluations 330592.27.42, 330592.27.45, and 330592.27.88, Exelon
determined the UT thickness values satisfied the general uniform minimum wall
thickness criteria (e.g., average thickness of an area) and the locally thinned minimum
wall thickness criteria (e.g., areas 2 inches or less in diameter), as applicable. For UT
data sets, such as 7x7'arrays, the TEs calculated statistical parameters and determined
the data set distributions were acceptable. The TEs also compared the data set values
to the corresponding 2006 values and concluded there were no significant differences
and no observable on-going corrosion. The inspectors independently verified' that the
UT thickness values satisfied applicable acceptance criteria.
3.9 Moisture Barrier Seal Inspection (inside drywell)
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancement
(17), stated, in part:
Perform visual inspection of the moisture barrier seal between the drywell shell
and the concrete floor curb, installed inside the drywell during the October 2006
refueling outage, in accordance with ASME Code.
The inspector reviewed structural inspection reports 187-001 and 187-002, performed
by work order R2097321-01 on Nov 1 and Oct 29, respectively. The reports
documented visual inspections of the perimeter seal between the concrete floor curb
and the drywell steel shell, at the floor elevation 10 foot. In addition, the inspector
reviewed selected photographs taken during the inspection
b. Observations
No noteworthy observations.
3.10 One Time Inspection Proaram
a. Scope of Inspection
Proposed SER Appendix-A Item 24, One Time Inspection Program, stated, in part:
The One-Time Inspection program will provide reasonable assurance that an
aging effect is not occurring, or that the aging effect is occurring slowly enough
to not affect the component or structure intended function during the period of
extended operation, and therefore will not require additional aging management.
Perform prior to the period of extended operation.
The inspector reviewed the program's sampling basis and sample plan. Also, the
inspector reviewed ultrasonic test results from selected piping sample locations in the
main steam, spent fuel pool cooling, domestic water, and demineralized water systems.
b. Observations
No noteworthy observations.
3.11 "B" Isolation Condenser Shell Inspection
a. Scope of Inspection o
Proposed SER Appendix-A Item 24, One Time Inspection Program Item (2), stated, in
part:
To confirm the effectiveness of the Water Chemistry program to manage the
loss of material and crack initiation and growth aging effects. A one-time UT
inspection of the "B" Isolation Condenser shell below the waterline will be
conducted looking for pitting corrosion. Perform prior to the period of extended
operation.
The inspector observed NDE examinations of the "B" isolation condenser shell
performed by work order C2017561-11. The NDE examinations included a visual
inspection of the shell interior, UT thickness measurements in two locations that were
previously tested in 1996 and 2002, additional UT tests in areas of identified pitting and
corrosion, and spark testing of the final interior shell coating. The inspector reviewed
the UT data records, and compared the UT data results to the established minimum wall
thickness criteria for the isolation condenser shell, and compared the UT data results
with previously UT data measurements from 1996 and 2002
b. Observations
No noteworthy observations.
3.12 Periodic Inspections
a. Scope of Inspection
Proposed SER Appendix-A Item 41, Periodic Inspection Program, stated, in part:
Activities consist of a periodic inspection of selected systems and components to
verify integrity and confirm the absence of identified aging effects. Perform prior
to the period of extended operation.
The inspectors observed the following activities:
- Condensate expansion joints Y-2-11 and Y-2-12 inspection (WO R2083515)
- 4160 V Bus 1C switchgear fire barrier penetration inspection (WO R2093471)
b. Observations
No noteworthy observations.
3.13 Circulatinq Water Intake Tunnel & Expansion Joint Inspection
a. Scope of Inspection
Proposed SER Appendix-A Item 31, Structures Monitoring Program Enhancement (1),
stated, in part:
Buildings, structural components and commodities that are not in scope of
maintenance rule but have been determined to be in the scope of license
renewal. Perform prior to the period of extended operation.
On Oct. 29, the inspector directly observed the conduct of a structural engineering
inspection of the circulating water intake tunnel, including reinforced concrete wall and
floor slabs, steel liners, embedded steel pipe sleeves, butterfly isolation valves, and
tunnel expansion joints. The inspection was conducted by a qualified structural
engineer. After the inspection was completed, the inspector compared his direct
observations with the documented visual inspection results.
b. Observations
No noteworthy observations.
3.14 Buried EmerQency Service Water Pipe Replacement
a. Scope of Inspection
Proposed SER Appendix-A Item 63, Buried Piping, stated, in part:
Replace the previously un-replaced, buried safety-related emergency service
water piping prior to the period of extended operation. Perform prior to the
period of extended operation.
The inspectors observed the following activities, performed by work order C2017279:
" Field work to remove old pipe and install new pipe
" Foreign material exclusion (FME) controls
- External protective pipe coating, and controls to ensure the pipe installation
activities would not result in damage to the pipe coating
b. Observations
No noteworthy observations.
3.15 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
observed the pre-job brief which discussed inspection techniques and acceptance
criteria. The inspector directly observed the visual inspection, which included cables in
raceways, as well as cables and connections inside junction boxes. After the inspection
was completed, the inspector compared his direct observations with the documented
visual inspection results.
b. Observations
No noteworthy observations.
3.16 Drywell Shell Internal CoatinQs Inspection (inside drywell)
a. Scope of Inspection
Proposed SER Appendix-A Item 33, Protective Coating Monitoring and Maintenance
Program, stated, in part:
The program provides for aging management of Service Level I coatings inside
the primary containment, in accordance with ASME Code.
The inspector reviewed a vendor memorandum which summarized inspection findings
for a coating inspection of the as-found condition of the ASME Service Level I coating of
the drywell shell inner surface. In addition, the inspector reviewed selected photographs
taken during the coating inspection and the initial assessment and disposition of
identified coating deficiencies. The coating inspector was also interviewed. The coating
inspection was conducted on Oct. 30, by a qualified ANSI Level III coating inspector.
The final detailed report, with specific elevation notes and photographs, was not
available at the time the inspector left the site.
b. Observations
No noteworthy observations.
3.17 Inaccessible Medium Voltage Cable Test
a. Scope of Inspection
Proposed SER Appendix-A Item 36, Inaccessible Medium Voltage Cables, stated, in
part:
Cable circuits will be tested using a proven test for detecting deterioration of the
insulation system due to wetting, such as power factor or partial discharge.
Perform prior to the period of extended operation.
The inspector observed field testing activities for the 4 kV feeder cable from the auxiliary
transformer secondary to Bank 4 switchgear and independently reviewed the test
results. A Doble and power factor test of the transformer, with the cable connected to
the transformer secondary, was performed, in part, to detect deterioration of the cable
insulation. The inspector also compared the current test results to previous test results
from 2002. In addition, the inspector interviewed plant electrical engineering and
maintenance personnel.
b. Observations
No noteworthy observations.
3.18 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 interviewed the fatigue program manager and determined that the
FatiguePro program, although in place and ready-to-go, has not been implemented.
Exelon stated the FatiguePro program will be implemented after final industry resolution
of a concern regarding a mathematical summation technique used in FatiguePro. The
FatiguePro program was evaluated by the inspectors in March of 2006 (Report
05000219/20006007). The inspectors determined that Exelon's proposed
implementation had not changed in the interim.
b. Observations
The inspectors determined that Exelon's proposed implementation had not changed the
since the NRC reviewed it in March of 2006.
4. Commitment Manaqement Proqram
a. Scope of Inspection
The inspectors evaluated current licensing basis procedures used to manage and revise
regulatory commitments to determine whether they were consistent with the
requirements of 10 CFR 50.59, NRC Regulatory Issue Summary 2000-17, "Managing
Regulatory Commitments," and the guidance in Nuclear Energy Institute (NEI) 99-04,
"Guidelines for Managing NRC Commitment Changes." In addition, the inspectors
reviewed the procedures to assess whether adequate administrative controls were in-
place to ensure commitment revisions or the elimination of commitments altogether
would be properly evaluated, approved, and annually reported to the NRC. The
inspectors also reviewed Exelon's current licensing basis commitment tracking program
to evaluate its effectiveness. In addition, the following commitment change evaluation
packages were reviewed:
" Commitment Change 08-003, OC Bolting Integrity Program
" Commitment Change 08-004, RPV Axial Weld Examination Relief
b. Observations
The inspectors observed that the commitment change activities were conducted in
accordance with approved procedures, which required an annual update to the NRC
with a summary of each change.
40A6 Meetin-gs, Including Exit Meeting
Exit Meeting Summary
The inspectors presented the results of this inspection to Mr. T. Rausch, Site Vice
President, Mr. M.Gallagher, Vice President License Renewal, and other members of
Exelon's staff on December 23, 2008. NRC Exit Notes from the exit meeting are located
in ADAMS within package ML090120726.
No proprietary information is present in this inspection report.
A-1
ATTACHMENT
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
C. Albert, Site License Renewal
J. Cavallo, Corrosion Control Consultants & labs, Inc.
M. Gallagher, Vice President License Renewal
C. Hawkins, NDE Level III Technician
J. Hufnagel, Exelon License Renewal
J. Kandasamy, Manager Regulatory Affairs
S. Kim, Structural Engineer
M. McDermott, NDE Supervisor
R. McGee, Site License Renewal
D. Olszewski, System Engineer
F. Polaski, Exelon License Renewal
R. Pruthi, Electrical Design Engineer
S. Schwartz, System Engineer
P. Tamburro, Site License Renewal Lead
C. Taylor, Regulatory Affairs
NRC Personnel
S. Pindale, Acting Senior Resident Inspector, Oyster Creek
J. Kulp, Resident Inspector, Oyster Creek
L. Regner, License Renewal Project Manager, NRR
D. Pelton, Chief - License Renewal Projects Branch 1
M. Baty, Counsel for NRC Staff
J. Davis, Senior Materials Engineer, NRR
Observers
R. Pinney, New Jersey State Department of Environmental Protection
R. Zak, New Jersey State Department of Environmental Protection
M. Fallin, Constellation License Renewal Manager
R. Leski, Nine Mile Point License Renewal Manager
A-2
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened/Closed
None.
Opened
Closed
None.
0
A-3
LIST OF DOCUMENTS REVIEWED
License Renewal Program Documents
Drawings
Plant Procedures and Specifications
Incident Reports (IRs)
= IRs written as a result of the NRC inspection
Maintenance Reauests (ARs) & Work Orders (WOs)
Ultrasonic Test Non-destructive Examination Records
Visual Test Inspection Non-destructive Examination Records
NDE Certification Records
Miscellaneous Documents
NRC Documents
Industry Documents
- = documents referenced within NUREG-1 801 as providing acceptable guidance for specific
aging management programs
A-4
A-5
LIST OF ACRONYMS
ASME American Society of Mechanical Engineers
EPRI Electric Power Research Institute
NDE Non-destructive Examination
NEI Nuclear Energy Institute
SSC Systems, Structures, and Components
SDP Significance Determination Process
TE Technical Evaluation
UFSAR Updated Final Safety Analysis Report
UT Ultrasonic Test
VT Visual Testing