ML091980298
| ML091980298 | |
| 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: ML091980298 (26) | |
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-2.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
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 activities
at 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) Part 54, "Requirements for the Renewal of Operating
Licenses for Nuclear Power Plants."[ (b)(5)
(b)(5) Ex
(b)(5) `Tbe-inisit'ý-b ývewd selected procedures and records, observcod
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.
a*ccaionInce with t rofo kdofnm A&
ExempAio2________________
C. Pardee 3
In accordance with 10 CFR 2.790 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/NRC/ADAMS/index.html (the Public Electronic Reading Room).
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
I i
C. Pardee 4
In accordance with 10 CFR 2.790 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/NRC/ADAMS/index.html (the Public Electronic Reading Room).
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
SUNSI Review Complete: _ (Reviewer's Initials)
ADAMS ACCESSION NO.
DOCUMENT NAME: C:\Doc\_.OC LRI 2008-07\_. Report\OC 2008-07 LRIrev-2.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
OF rCALRECFRDC PY
2
C. Pardee
C. Pardee 3
Distribution w/encl:
C. Pardee 4
Distribution w/encl: (VIA E-MAIL)
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket No.: 50-219
License No.: DPR-16
Report No.: 05000219/2008007
Licensee: Exelon, LLC
Facility: Oyster Creek Generating Station
Location: Forked River, New Jersey
Dates: October 27 to November 7, 2008 (on-site inspection)
November 13, 15, and 17, 2008 (on-site inspection)
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. The inspection was conducted in accordance with.
Inspection Procedure 71003 "Post-Approval Site Inspection for License Renewal."[ (b)(5)
((b)(5). (b)(5e report documents t
inspector observations, absent any conclusions of adequacy, pending the final decision of the
Commissioners on the appeal of the renewed license.
2
REPORT DETAILS
4. OTHER ACTIVITIES (OA)
40A2 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 application process, as an opportunity to make observations on license
renewal activities.L (b)(5)
(b)(5)
(b)(5) 9
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 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
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 basis
commitments 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 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 independently performed direct field observations of the conditions in the
trenches on multiple occasions during the outage and reviewed selected VT and 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."
The inspectors reviewed Technical Evaluation 330592.27,43, "Evaluation of 2008 UT
Data of the Sand Bed Trenches," dated 11/8/08. The Evaluation determined that the UT
thickness values satisfied minimum wall thickness values for general uniform thickness
(e.g., average thickness of an area) and for locally thinned areas (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 Evaluation calculated mean values, standard
deviation, standard error, skewness, and kurtosis and determined that the data sets had
a normal distribution. The Evaluation 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 compared the UT data to
the corresponding 2006 data values and to minimum thickness values established by
design analysis and calculations.
The inspectors reviewed Exelon UT examination procedures, interviewed nondestructive
examination (NDE) technicians, reviewed NDE technician qualifications and
certifications, and reviewed records of trench inspections performed during two forced
plant outages during the last operating cycle.
b. Observations
" Remove & reinstall lower 6" of grout at bottom of Bay 5 trench
- Inspect caulk sealant (trench edge where concrete meets shell)
" Verify no water accumulation
3.2 Reactor Cavity Liner Strippable Coatingq
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. Observations
Strippable Coating De-lamination
e From Oct. 29 to Nov. 6, the strippable coating limited leakage into the cavity trough drain at
less than 1 gallon per minute (gpm)
e 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 identified several likely or contributing causes:
e 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
- AmerGen stated follow-up UTs will re-evaluate the drywell shell next outage
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:
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. 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.
3.4 Reactor Cavity Trough 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.
The inspectors xxx
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. The plan had pre-
established actions at various cavity drain flow rates, as follows:
9 If the cavity trough drain flow exceeds 5 gpm, then increase monitoring of the
cavity drain flow 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 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.
b. Observations
On Oct. 27, the cavity 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
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.
3.5 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 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.
3.6 Moisture Barrier Seal Inspection (inside sand bed bays)
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancements
(12 & 21), stated:
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 performed the following:
- Independently inspected portions of the moisture barrier in 7 sand bed bays
" Reviewed VT-1 examination records for each sand bed bay
" Observed AmerGen's activities to evaluate the moisture barrier seals
b. Observations
" AmerGen identified deficiencies in 7 of the 10 sand bed bays, including
- Surface cracks
- Partial separation of the seal from the shell, or the floor
" AmerGen determined the moisture barrier function was not impaired, because no cracks or
separation fully penetrated the seal. All deficiencies were repaired.
Sand Bed Bay 3 Seal Crack and Rust Stain
- Observed activities to evaluate and repair the moisture barrier seal in Bay 3
" The seal had rust stains on the surface, below the identified crack
" When the seal was excavated, some drywell shell surface corrosion was identified
- Seal crack and surface rust were repaired
- Laboratory analysis determined there was inadequate epoxy cure, an original 1992
installation issue
2006 Inspection Did Not Identify Any Seal Cracks
- During 2006 seal inspections, no deficiencies were identified
3.7 Drywell Shell External CoatinQs Inspection (inside sand bed bays)
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancements
(4 & 21), stated:
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 performed the following:
" Independently inspected portions of the epoxy coating in 7 sand bed bays
" Reviewed VT-1 examination records for each sand bed bay
- Observed AmerGen's activities to evaluate the epoxy coating in bay 11
b. Observations
Sand Bed Bay 11 Blisters
- Observed activities to evaluate and repair blisters found in Bay 11
- 1 small 1/4 inch broken blister identified, with a 6" rust stain
- 3 smaller unbroken blisters were identified by the NRC, during initial investigation
- All 4 blisters were within a 1-2 inches square area, and all were evaluated and fixed
- For extent of condition, 4 bays re-inspected by different NDE level-Il
- -- AmerGen reported that No deficiencies were identified
- AmerGen estimated corrosion of - 3 mils had occurred over about a 16 year period
Sand Bed Bay 9 Coatinq Deficiency
9 AmerGen identified and re-coated a area approximately 8" x 8" area because of a difference
in epoxy color which could have been indicative of only 2 layers instead of 3.
2006 Inspection Did Not Identify the Bay 11 Rust Stain or the Bay 9 Coating Deficiency
9 AmerGen reviewed a 2006 video and identified the same 6" rust stain in the 2006 video of
Bay 11
9 CR 844815 stated the Bay 9 coating deficiency was most probably an original 1992
installation issue
- During the 2006 coatings inspection, these 2 deficiencies were not identified
3.8 Drvwell Shell Thickness Measurements
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section XIl Subsection IWE Enhancements
(1, 9, 14, and 21), stated:
Perform full scope drywell inspections, 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. This included:
- 19 locations inside the drywell, at the sand bed region elevation
- UT examinations in all 10 sand bed bays (drywell external, total 106 locations)
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. This
included:
- 9 locations inside the drywell, at elevations between 50 to 87 foot
- 4 locations inside the drywell, at 23 foot elevation (bottom to middle spherical
plate transition)
- 4 locations inside the drywell, at 71 foot elevation (knuckle area)
" Observed actions to evaluate primary containment structural integrity
- Observed AmerGen perform drywell shell UT thickness measurements
" Observed field collection and recording of UT data
" Reviewed UT examination records
" Reviewed AmerGen's Technical Evaluations of the UT data
b. Observations
" AmerGen determined that all of the UT data satisfied acceptance criteria, based on current
licensing basis design requirements, for the thickness of the steel plate
9 AmerGen did not identify any significant conditions affecting the drywell shell structural
integrity
9 AmerGen did not identify any on-going corrosion or corrosion trend, based on the UT
examinations
- AmerGen did not identify any statisticallysignificant deviations from 2006 UT data values
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 "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 performed on the interior of the "B"isolation
condenser shell, performed by work order C2017561-1 1. The inspector observed a
visual inspection of the shell interior, UT thickness measurements in two locations that
were previously tested in 1996 and 2002, additional UT testing 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.
3.11 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
- Switchgear fire barrier inspection
b. Observations
None.
3.12 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 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
None.
3.13 Buried ESW Pipe Replacement
a. Scope of Inspection
Proposed SER Appendix-A Item 63, Buried Piping, stated:
0
Replace the previously un-replaced, buried safety-related ESW piping prior to
the period of extended operation. Perform prior to the period of extended
operation.
The inspectors observed the following activities:
" Field work to remove old pipe and install new pipe
a 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.
3.14 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.
3.15 Drywell Shell Internal Coatings 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
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 before the end of this NRC inspection.
b. Observations
None.
3.16 Inaccessible Medium Voltage Cable Test
a. Scope of Inspection
Proposed SER Appendix-A Item 36, Inaccessible Medium Voltage Cables, stated:
In addition, the 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, as described in EPRI TR-103834-P1-2, or other testing that is
state of the art at the time the test is performed. Perform prior to the period of
extended operation.
The inspector reviewed the licensee's activities to implement commitment item number xxx, of
the NRC Safety Evaluation Report related to the Oyster Creek License Renewal. This
commitment added medium-voltage cables M0089 and M0108 into the scope of OC license
renewal. In addition, it required the licensee to develop an aging management program
consistent with NUREG-1801, "Generic Aging Lessons Learned-,"Section XI.E3.
NUREG-1801 Section XI.E3, Inaccessible Medium-Voltage Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements, recommended the licensee determine a
specific type of test to be performed prior to the initial test [at the time just prior to or at the time
of the period of extended operations], and that it should be a proven test for detecting
deterioration of the insulation system due to wetting, such as power factor, partial discharge, or
polarization index, as described in EPRI TR-103834-P1-2. NUREG-1801 also recommended
that the first test be completed before the period of extended operation.
The inspector observed field testing (work order xxx) of electrical cable xxx, 4 kV feeder cable
to Bus xxx transformer xxx, and independently reviewed the test results. A Doble test of the
transformer, with the cable connected to the transformer secondary, was performed, in part, to
detect deterioration of the cable insulation. In addition, the inspector interviewed plant electrical
engineering and maintenance personnel.
b. Observations
None.
3.17 Fatique Monitorinq Proqram
a. Scope of Inspection
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 of 10 CFR 54.21(c)(1)(iii).
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 Manaqement Proqram
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 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
None.
40A6 Meetings, Including Exit Meeting
Exit Meeting Summary
The inspectors presented the results of this inspection to Mr. T. Rausch, Site Vice
President, Mr. M. Gallagher, Vice President License Renewal, and other members of
AmerGen'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
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
Closed
None.
A-3
LIST OF DOCUMENTS REVIEWED
License renewal Proqram Documents
Drawinqs
Plant Procedures
LS-AA-104-1002, 50.59 Applicability Review, Rev 3
LS-AA-1 10, Commitment Change management, Rev 6
Condition Reports (CRs)
- = CRs written as a result of the NRC inspection
Maintenance Reauests & Work Orders
Miscellaneous Documents
NRC Documents
Industry Documents
- = documents referenced within NUREG-1801 as providing acceptable guidance for specific
aging management programs
A-4
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 Report