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 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) 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 WMthf Freedompo 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. 50-219
License No. 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.: 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
Insiection for License Renewal.'" (b)(5)
(b)(5)
(b)(5) "1The 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 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.
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 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 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. Observations
From 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 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 />.
- 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 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.
3.5 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. Observations
In 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 NDE
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 330592.27.88, "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 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
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 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.
3.14 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 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 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
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
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 Report