ML091980359
| ML091980359 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 06/17/2009 |
| From: | Conte R Engineering Region 1 Branch 1 |
| To: | Pardee C Exelon Generation Co |
| References | |
| FOIA/PA-2009-0070 IR-08-007 | |
| Download: ML091980359 (27) | |
See also: IR 05000219/2008007
Text
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 RENEWALFOLLOW-UP INSPECTION
REPORT 05000219/2008007
Dear Mr. Pardee On December 23, 2008, the
U. S. Nuclear Regulatory Commission (NRC) completed
aninspection 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 in a telephone
conference
observed by representatives
from the State of New Jersey.An appeal of a licensing board decision regarding the Oyster
Creek application
for a renewed license is pending before
the Commission.
The NRC concluded
Oyster Creek should not enter the extended period of operation
without directly observing
continuing
license renewal activitiesat Oyster Creek. Therefore, the NRC performed
an inspection using
Inspection
Procedure (IP)71003 "Post-Approval
Site Inspection'for
License Renewal" and observed Oyster Creek license renewal activities
during the last refuel outage prior to entering the period of extended operation.
IP 71003 verifies license conditions
added as part of a renewed license, license renewal commitments, selected aging management
programs, and license
renewal commitments
revised after the renewed license was granted, are implemented
in accordance
with Title 10 of the Code of Federal Regulations (CFR) Pert 54 "Reouirements
for the Renewal
of Ooeratino Licenses for Nuclear Power Plants."E (b)(5)(b)(5)(b)(5) 'The inspectors
reviewed selected procedures
and records, observed activities, and interviewed
personnel.
The enclosed report records the inspector's
observations, absent any conclusions
of adequacy, pending the final decision of the Commissioners
on the appeal of the renewed license.o WM thf Freedomp o Inftomutl_______. -______/t-
P C. Pardee 3 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/readincq-
rm/adams.html (the Public Electronic
Reading Room).We appreciate
your cooperation.
Please contact me at (610) 337-5183 if you have any questions
regarding
this letter.Sincerely, 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
C. Pardee 4 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 me at (610) 337-5183 if you have any questions
regarding
this letter.Sincerely, Richard Conte, Chief Engineering
Branch 1 Division of Reactor Safety Docket No.License No.50-219 DPR-16 Enclosure:
Inspection
Report No. 05000219/2008007
w/Attachment:
Supplemental
Information
SUNSI Review Complete:
_ (Reviewer's
Initials)ADAMS ACCESSION
NO.DOCUMENT NAME: C:\Doc\_.OC
LRI 2008-07\_.
Report\OC
2008-07 LRIrev-3.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 RI/DRS RI/DRP RI/DRS NAME JRichmond/
RConte/ RBellamy/
DRoberts/DATE //09 /09 / /09 / /09 OFF FIAL RErORD7PY
C. Pardee 3 Distribution
w/encl:
C. Pardee Distribution
w/encl: (VIA E-MAIL)
U. S. NUCLEAR REGULATORY
COMMISSION
REGION I Docket No.: License No.: Report No.: Licensee: Facility: Location: Dates: Inspectors:
50-219 DPR-16 05000219/2008007
Exelon Generation
Company, LLC Oyster Creek Generating
Station Forked River, New Jersey October 27 to November 7, 2008 (on-site inspection
activities)
November 13, 15, and 17, 2008 (on-site inspection
activities)
November 10 to December 23, 2008 (in-office
review)J. Richmond, Lead M. Modes, Senior Reactor Engineer G. Meyer, Senior Reactor Engineer T. O'Hara, Reactor Inspector J. Heinly, Reactor EngineerJ. 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 Insiection
for License Renewal.'" (b)(5)(b)(5)(b)(5) "1 The report documents
the inspector
observations, absent any conclusions
OT adequac7, pending the final decision of the Commissioners
on the appeal
of the renewed license.
2 REPORT DETAILS 4. OTHER ACTIVITIES (OA)4OA2 License Renewal Follow-up (IP 71003)1. Inspection
Sample Selection
Process This inspection
was conducted
in order to observe AmerGen's continuing license
renewal activities
during the last refueling
outage prior to Oyster Creek (OC) entering the extended period of operation.
The inspection
team selected a number of inspection
samples for review, using the NRC accepted guidance based on their importance
in the license renewal aq.lication
Drocess, as an opportunity
to make observations
on license renewal activities.L. (b)(5)(b)(5)Accordingly, the inspectors
recorded observations, without any assessment
of implementation
adequacy or safety significance.
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," as well as programmatic
performance
under on-going implementation
of 10 CFR 50 current licensing
basis (CLB)requirements.
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
programs;
the extent or complexity
of a commitment;
and the extent that baseline
inspection
programs will inspect a system, structure, orcomponent (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.
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).
2. NRC Unresolved
Item e Observed actions to evaluate primary containment
structural
integrity 10 CFR 50 existing requirements (e.g., current
licensing
basis (CLB)xxx USE words from PN* The conclusions
of PNO-1-08-012
remain unchanged" An Unresolved
Item (URI) will be opened to evaluate whether existing current licensing
basiscommitments were
adequately
performed
and, if necessary, assess the safety significance
for any related performance
deficiency.
e The issues for follow-up
include the strippable
coating de-lamination, reactor cavity trough drain monitoring, and sand bed drain monitoring.
- The commitment
tracking, implementation, and work control processes
will be reviewed, based on corrective
actions resulting
from AmerGen's
review of deficiencies
and operating experience, as a Part 50 activity.
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: 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. ObservationsFrom Oct.
29 to Nov. 6, the strippable
coating limited leakage into the cavity trough drain at less than
1 gallon per minute (gpm). On Nov. 6, the observed
leakage rate in the cavity trough drain took
a step change to 4 to 6 gpm. Water puddles were subsequently
identified
in 4 sand bed bays. AmerGen stated follow-up UTs would
be performed
to evaluate the drywell shell during the next refuel outage. AmerGen identified
several likely or contributing
causes, including:
9 A portable water filtration
unit was improperly
placed in the reactor cavity, which resulted in flow discharged
directly on the strippable
coating." An 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 Trbuqh Drain Monitoring
a. Scope of Inspection
Proposed SER Appendix-A
Item 27, ASME Section XI, Subsection
IWE Enhancement
(3), stated: The reactor cavity seal leakage trough drains and the drywell sand bed region drains will be monitored
for leakage. Periodically.
Reactor refuel cavity
seal leakage is collected
in a concrete trough and gravity drains through a 2 inch drain line into a plant drain system funnel. AmerGen monitored
the cavity seal leakage
daily by monitoring
the flow in the trough drain line.The inspectors
independently
checked the 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 AmerGen's
cavity trough drain flow monitoring
plan and pre-approved
Action Plan. AmerGen 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
On Oct. 27, the cavity trough drain line, was isolated 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, then the drain flow subsided to about an 1/8 inch stream (less
than 1 gpm).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.AmerGen 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 />. On Nov. 8, NDE technicians
inside sand bed bay 11 identified
dripping water. Subsequently, water puddles were identified
in 4 sand bed bays. After the cavity was drained, all sand bed bays were inspected;
no deficiencies
identified.
The sand bed bays were originally
scheduled
to have been closed by Nov. 2. In addition, on Nov. 15, after cavity was drained, water was found in the sand bed bay 11 poly bottle.The inspectors
observed that AmerGen's
pre-approved
action plan was inconsistent
withthe 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 />.* 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 Drains Monitoring
a. Scope of Inspection
Proposed SER Appendix-A
Item 27, ASME Section XI, Subsection
IWE Enhancement
(3), stated: The sand bed region drains will be monitored
daily during refueling
outages.There is one drain line for each two sand bed bays (five drains total). A poly bottle was attached via tygon tubing
to a funnel hung below each drain line. AmerGen performed
the drain line monitoring
by checking the poly bottles.The inspectors
independently
checked the poly bottles during the outage, and accompanied
AmerGen personnel
during routine daily checks. The inspectors
also reviewed the written monitoring
logs.b. Observations
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.
After the reactor cavity was drained, 2 of the 5 tygon tubes were found disconnected, laying on the floor. In addition, sand bed bay 11 drain poly bottle was empty during each daily check until Nov.15 (cavity was drained on Nov 12), when it was found full (greater than 4 gallons).
Bay 11 was entered
within a few hours, visually inspected, and found dry.3.4 Reactor Cavity Trouqh Drain Inspection
for Blockage a. Scope of Inspection
Proposed SER Appendix-A
Item 27, ASME Section XI, Subsection
IWE Enhancement
(13), stated: 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 thecorrective action
process. Once per refueling
cycle.The inspector
reviewed a video recording
record of a boroscope
inspection
of the cavity trough drain line.b. Observations
See observations
in section 2.4 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: 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 as-found conditions
of the moisture barrier seal in 5 sand bed bays, and as-left conditions
in 3 sand bed bays. The inspectors
reviewed VT examination
records for each sand bed bay, and compared their direct
observations
to the recorded VT examination
results. The inspectors
reviewed Exelon VT examination
procedures, interviewed
nondestructive
examination (NDE) technicians, and reviewed
NDE technician
qualifications
and certifications.
The inspectors
observed AmerGen's
activities
to evaluate and repair the
moisture barrier seal in sand bed bay 3.b. Observations
The VT examinations
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. All deficiencies
were entered into the corrective
action program and
evaluated.
AmerGen determined
the as-found moisture barrier
function was not impaired, because no cracks or separation
fully penetrated
the seal. All deficiencies
were repaired.The VT examination
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 deficiencies were
identified.
3.6 Drywell Shell External CoatinQs Inspection (inside sand bed bays)a. Scope of Inspection
Proposed SER Appendix-A
Item 27, ASME Section XI, Subsection
IWE Enhancements
(4 & 21), stated: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,AmerGen performed a 100% visual inspection
of the epoxy coating in the sand bed region (total of 10 bays). The inspectors
directly observed as-found
conditions
of the epoxy coating in 7 sand bed bays, and the as-left
condition
in sand bed bay 11, after coating repairs. The inspectors
reviewed VT examination
records for each sand bed bay, and compared
their direct observations
to the recorded VT examination
results.The inspectors
reviewed Exelon VT examination
procedures, interviewed
nondestructive
examination (NDE) technicians, and reviewed NDE technician
qualifications
and certifications.
The inspectors
directly observed AmerGen's
activities
to evaluate and repair the epoxy coating in sand bed bay 11.b. ObservationsIn bay 11, AmerGen 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, an NRC inspector
identified
three additional
smaller surface irregularities (initially
described
as surface bumps) within a 1 to 2 square inch area, near the broken blister, which were subsequently
determined
to be unbroken blisters.
All four blisters were evaluated
and repaired.To confirm the adequacy of the initial coating examination, AmerGen re-inspected
4 sand bed bays with a different
NDE technician.
No additional
deficiencies
were identified.
A laboratory
analysis of the removed
blisters determined
approximately
0.003 inches of surface corrosion
had occurred directly under the broken
blister, and concluded
the corrosion
had taken place over approximately
a 16 year period. UT dynamic scan thickness
measurements
from inside the drywell confirmed
the drywell shell had no significant
degradation
as a result of the corrosion
under the four blisters.During the final closeout of bay 9, AmerGen identified
an area approximately
8 inches by 8 inches 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, AmerGen questioned
whether the color difference
could have been indicative
of an original installation
deficiency.
The identified
area was re-coated
with epoxy.In follow-up, AmerGen reviewed a 2006 video of the sand beds, which had been made as a general aid, not as part of an NDE examination.
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 deficiencies
were identified.
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: 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 (TE) 330592.27.43, "2008 UT Data of the Sand Bed Trenches," The inspectors
reviewed Exelon UT examination
procedures, interviewed
4 technicians, reviewed NDE technician
qualifications
and certifications.
The inspectors
also reviewed records of trench inspections
performed
during two non-refueling
plant outages during the last operating
cycle.b. Observations
TE 330592.27.43
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 (i.e., 49 UT readings in a 6 inch by 6 inch grid), the TE calculated
statistical
parameters
and determined
the data sets had a normal distribution.
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.
During two non-refueling
plant outages during the last operating cycle, both
trenches were inspected
for the presence of water, and found dry.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
also observed the trenches to be dry. During the final drywell closeout inspection
on Nov. 17, 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.* 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. AmerGen 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: 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: 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
observed non-destructive
examination (NDE) activities
and reviewed UT examination
records. The inspectors compared
UT data results to licensee established
acceptance
criteria in Specification
IS-318227-004, revision 14, "Functional
Requirements
for Drywell Containment
Vessel Thickness
Examinations," and to design analysis values for minimum wall thickness
in calculations C-1302-187-E310-041, revision 0, "Statistical
Analysis of Drywell Vessel Sand Bed Thickness
Data 1992, 1994, 1996, and 2006," and C-1302-187-5320-024, revision 2, "Drywell External UT Evaluation
in the Sand Bed." In addition, the inspectors
reviewed the Technical Evaluations (TEs)associated
with the UT data, as follows:* TE 330592.27.42, "2008 Sand Bed UT data -External"* TE 330592.27.45i
"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:
- 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 in accordance
with the approved procedures.
The inspectors
also reviewed NDE technician
qualifications
and certifications.
b. Observations
TEs 330592.27.42, 330592.27.45, and 330592.27.88
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 (i.e., 49 UT readings in a 6 inch by 6 inch grid), the TEs calculated
statistical
parameters
and determined
the data sets had a normal distribution.
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.
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:
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
None.3.10 One Time Inspection
ProQram a. Scope of Inspection
Proposed SER Appendix-A
Item 24, One Time Inspection
Program, stated: The One-Time Inspection
program will provide reasonable
assurance
that anaging 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
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
None.3.11 "B" Isolation
Condenser
Shell Inspection
a. Scope of Inspection
Proposed SER Appendix-A
Item 24, One Time Inspection
Program Item (2), stated: 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
None.3.12 Periodic Inspections
a. Scope of Inspection
Proposed SER Appendix-A
Item 41, Periodic Inspection
Program, stated: 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
system pipe expansion
joint inspection
- 4160 V Bus 1C switchgear
fire barrier penetration
inspection
b. Observations
None.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: Buildings, structural
components
and commodities
that are not in scope of maintenance
rule but have been determined
to be in the scope of licenserenewal. 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
None.3.14 Buried Emerqency
Service Water Pipe Replacement
a. Scope of Inspection
Proposed SER Appendix-A
Item 63, Buried Piping, stated: 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
None.3.15 Electrical
Cable Inspection
inside Drywell a. Scope of Inspection
Proposed SER Appendix-A
Item 34, Electrical Cables and Connections, stated: 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
None.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: 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
None.3.17 Inaccessible
Medium Voltage Cable Test a. Scope of Inspection
Proposed SER Appendix-A
Item 36, Inaccessible
Medium Voltage Cables, stated: 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
None.3.18 Fatigue Monitoring
Program a. Scope of Inspection
xxx what about SER Supplement
1
On the basis of a projection
of the number of design transients, the licensee concluded, during the license renewal application
process, the existing fatigue analyses of the RCS components
remain valid for the extended period of operation (See NRC Safety Evaluation
Report NUREG 1728 Section 4.3). Constellation
however indicated
that, prior to the expiration
of the current operating
license, a Fatigue Monitoring
Program will be implemented
as a confirmatory
program as discussed
in Section B.3.2 of their original license renewal application.
The licensee proposed using the Fatigue Monitoring
Program to provide assurance
that the number of design cycles will not be exceeded during the period of extended operation.
It was on this basis that the staff found licensee's
Fatigue Monitoring
Program provided an acceptable
basis for monitoring
the fatigue usage of reactor coolant system components, in accordance
with the requirements
Subsequent
to the application, the NRC staff became aware of a simplified
assumption
used in the EPRI program for fatigue monitoring
called FatiguePro.
The inspector
reviewed the current status of the fatigue monitoring
program for the licensee.
The inspector
also determined
if the computational
shortcut was present in the program and what response the licensee was planning to the NRC's concern that the simplified
assumption
might result in a non-conservative
prognosis
of fatigue. The
inspector
interviewed
the responsible
engineer staff and reviewed the results of the fatigue program in place at the facility.
The inspector
reviewed the procedures
and computational
methodology
to determine
the status of current fatigue limits on reactor coolant system components.
b. Observations
None.4. Commitment
Management
Program a. Scope of Inspection
The inspectors evaluated
Exelon 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 AmerGen'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
xxx describe factual detail of changes and explain basis to NOT notify
NRC staff None.40A6 Meetin-gs, Includinq
Exit Meeting Exit Meeting Summary xxx ADD ADAMS # for Exit Notes 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 AmerGen's
staff on December 23, 2008. NRC Exit Notes from the exit meeting are located in ADAMS within
package MLxxxx.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 R. McGee, Site
License Renewal 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, State of New Jersey Department
of Environmental
Protection
R. Zak, State of New Jersey 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 xxx Closed None.
E A-3 LIST OF DOCUMENTS
REVIEWED License Renewal Program Documents PP-09, Inspection
Sample Basis for the One-Time Inspection
AMP, Rev 0 Drawings Plant Procedures
LS-AA-104-1002, 50.59 Applicability
Review, Rev 3 LS-AA- 110, Commitment
Change management, Rev 6 645.6.017, Fire Barrier Penetration
Surveillance, Rev 13 Condition
Reports (CRs)* = CRs written as a result of the NRC inspection
00804754 Maintenance
Requests & Work Orders C20117279 Nondestructive
Examination
Records NDE Data Report 2008-007-017
NDE Data Report 2008-007-030
NDE Data Report 2008-007-031
UT Data Sheet 21 R056 Miscellaneous
Documents NRC Documents Industry Documents*= documents
referenced
within NUREG-1801
as providing
acceptable
guidance for specific aging management
programs
4, A A-4
A-5 LIST OF ACRONYMS EPRI Electric Power Research Institute NDE Non-destructive
Examination
NEI Nuclear Energy Institute SSC Systems, Structures, and Components
SDP Significance
Determination
Process TR Technical