ML091980313
| ML091980313 | |
| 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: ML091980313 (29) | |
See also: IR 05000219/2008007
Text
G:\DRS\Engineering Branch 1\_LicRenewal\Oyster Creek\2008 Outage\lnReport\OC 2008-07
LRI rev-6a.doc
Mr. Charles G. Pardee
Chief Nuclear Officer (CNO) and Senior Vice President
Exelon Generation Company, LLC
200 Exelon Way
Kennett Square, PA 19348
SUBJECT: OYSTER CREEK GENERATING STATION - NRC LICENSE RENEWAL
FOLLOW-UP INSPECTION REPORT 05000219/2008007
Dear Mr. Pardee
On December 23, 2008, the U. S. Nuclear Regulatory Commission (NRC) completed an
inspection at your Oyster Creek Generating Station. The enclosed report documents the
inspection results, which were discussed on December 23, 2008, with Mr. T. Rausch, Site Vice
President, Mr. M. Gallagher, Vice President License Renewal, and other members of your staff.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commission's rules and regulations and with the conditions of your license.
In addition, an appeal of a licensing board decision regarding the Oyster Creek application for a
renewed license is pending before the Commission. The NRC staff concluded Oyster Creek
should not enter the extended period of operation without directly observing continuing license
renewal activities at Oyster Creek. Therefore, the NRC staff 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 (CP.) Part 54, "Requirements for the Renewal of Operating
Licenses for Nuclear Power Plants.' (b)(5)
(b) (5) J*_. )
(b)(5) j-he 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.
accordance wit thFreedom of Informatn AOL
ExeF Pons 0_ __ _______
FOJAJP.,
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.qov/readinq-
rm/adams.html (the Public Electronic Reading Room).
We appreciate your cooperation. Please contact me at (610) 337-5183 if you have any
questions regarding this letter.
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: G:\DRS\Engineering Branch 1\Richmond\OC 2008-07 LR\_Report\OC 2008-07 LRIrev-6a.doc
After declaring this document "An Official Agency Record" it will be released to the Public.
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 JRI/DRP RI/DRS
NAME JRichmond/ RConte/ RBellamy/ DRoberts/
DATE //09 //09 1/09 1/09
OFFIAL REC D 7PY
C. Pardee 3
Distribution wlencl:
C. Pardee 4
Distribution w/encl: (VIA E-MAIL)
. I
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. Kuip, Resident Inspector, Oyster Creek
Approved by: Richard Conte, Chief
Engineering Branch 1
Division of Reactor Safety
ii
I .
SUMMARY OF FINDINGS
IR 05000219/2008007; 10/27/2008 - 12/23/2008; Exelon, LLC, Oyster Creek
Generating Station; License Renewal Follow-up
The report covers a multi-week inspection of license renewal follow-up items. It was conducted
by five region based engineering inspectors and the Oyster Creek resident inspector. The
inspection was conducted in accordance with Inspection Procedure 71003 "Post-Approval Site
Inspection for License Renewal."E (b)(5)
(b)(5)
(b)(5) 3ln accordance with the NRC's agreement with the State of New Jersey, state
engineers observed portions of the NRC's staff review. The report documents inspection
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 a-o~lication process, as an opportunity to make observations on license
renewal activities.L. (b)(5)
(b)(5)(b1--
(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
- 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.
- The issues for follow-up include the cavity liner 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.
10 CFR 50 existing requirements (e.g., current licensing basis (CLB)
The inspectors observed AmerGen's actions to evaluate primary containment structural
integrity. The inspectors concluded there were no safety significant conditions with respect to
the drywell containment that would prohibit plant startup.
In Bay 11, four small blisters (three of which were initially identified as bumps) on the coating,
including a small amount of surface rust under the blisters, were identified and repaired.
AmerGen reported that some blistering was expected, and would be identified during routine
visual examinations. The NRC staff will review AmerGen's apparent cause evaluation after it is
completed.
AmerGen's activities to monitor and mitigate water leakage from the reactor refueling cavity
onto the external surface of the drywell shell and into the sand bed regions are still under
evaluation.
The drywell shell epoxy coating and the moisture barrier seal, both in the sand bed region, are
barrier systems used to protect the drywell shell from corrosion. The problems identified with
these barriers had a minimal impact on the drywell steel shell and the projected shell corrosion
rate remains very small, as confirmed by NRC staff review of UT data.
Based on a review of the technical information, the NRC staff determined AmerGen has
provided an adequate basis to conclude the drywell primary containment will remain operable
during the period until the next scheduled examination, in the 2012 refueling outage.
3. Detailed Reviews
3.1 Reactor Refuel Cavity Liner Strippable Coating
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section X1, 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 cavity liner strippable coating limited cavity seal leakage into
the cavity trough drain at less than 1 gallon per minute (gpm). On Nov. 6, in one area of
the refuel cavity, the liner strippable coating started to de-laminate. Water puddles were
subsequently identified in sand bed bays 11, 13, 15, and 17 (see section 3.2 below for
additional details). This issue was entered into the corrective action program and initial
evaluations identified several likely or contributing causes, including:
- 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 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.
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).
This issue was entered into the corrective action program.
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 />. All sand bed bays were originally scheduled to be closed by
Nov. 2. However, due to a coating problem, personnel working in sand bed bay 11
identified dripping water on Nov. 8. After the cavity was drained, all sand bed bays were
inspected for any water or moisture damage; no deficiencies identified. AmerGen stated
follow-up UTs would be performed to evaluate the drywell shell during the next refuel
outage. In addition, on Nov. 15, after cavity was drained, water was found in the sand
bed bay 11 poly bottle. These issues were entered into the corrective action program.
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:
9 If the cavity trough drain flow exceeds 5 gpm, then increase monitoring of the
cavity drain flow from daily to every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
- If the cavity trough drain flow exceeds 12 gpm, then increase monitoring of the
sand bed poly bottles from daily to every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
9 If the cavity trough drain flow exceeds 12 gpm and any water is found in a
sand bed poly bottle, then enter and inspect the sand bed bays.
3.3 Drywell Sand Bed Reqion 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. These issues
were entered into the corrective action program.
3.4 Reactor Cavity Trough Drain Inspection for Blockage
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancement
(13), stated:
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, performed by work order R2102695.
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.
xxx check # of bays inspected
The purpose of the moisture barrier seal is to prevent water from entering a gap below
the concrete floor in the sand bed region. AmerGen performed a 100% visual
inspection of the seal in the sand bed region (total of 10 bays). The inspectors directly
observed as-found conditions of the seal in 5 sand bed bays, and as-left conditions in 3
sand bed bays.
The inspectors reviewed VT inspection records for each sand bed bay, and compared
their direct observations to the recorded VT inspection results. The inspectors reviewed
Exelon VT inspection procedures, interviewed non-destructive examination (NDE)
supervisors and technicians, and observed field collection and recording of VT
inspection data. The inspectors also reviewed a sample of NDE technician visual
testing qualifications.
The inspectors observed AmerGen's activities to evaluate and repair the moisture
barrier seal in sand bed bay 3.
b. Observations
The inspectors observed that NDE visual inspection activities were conducted in
accordance with approved procedures. The inspectors verified that AmerGen
completed the inspections, identified condition(s) in the moisture barrier seal which
required repair, completed the seal repairs in accordance with engineering procedures,
and conducted appropriate re-inspection of repaired areas.
The VT inspections identified moisture barrier seal deficiencies in 7 of the 10 sand bed
bays, including surface cracks and partial separation of the seal from the steel shell or
concrete floor. 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 entered into the corrective action program and repaired.
The VT inspection for sand bed bay 3 identified a seal crack and a surface rust stains
below the crack. When the seal was excavated, some drywell shell surface corrosion
was identified. A laboratory analysis of removed seal material determined the epoxy
seal material had not adequately cured, and concluded it was an original 1992
installation issue. The seal crack and surface rust were repaired.
The inspectors compared the 2008 VT results to the 2006 results and noted that in 2006
no seal deficiencies were identified in any sand bed bay.
3.6 Drywell Shell External Coatings Inspection (inside sand bed bays)
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section 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.
xxx WHICH bays did Tim go into the 1st week ??
[ may have been bays 1 & 11 & 13 ]
xxx Tim went into bays 5 & 9 & 11 on Nov 13.
xxx jer went into bays 11 & 15, and observed portions of bay 9 & 17
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 portions of 7 sand bed bays, and the as-left condition in sand bed bay
11, after coating repairs. The inspectors observed field collection, recording, and
reporting of visual inspection data.
The inspectors reviewed VT inspection records for each sand bed bay, and compared
their direct observations to the recorded VT inspection results. The inspectors reviewed
Exelon VT inspection procedures, interviewed non-destructive examination (NDE)
supervisors and technicians, and observed field collection and recording of VT
inspection data. The inspectors also reviewed a sample of NDE technician visual
testing qualifications.
The inspectors directly' observed AmerGen's activities to evaluate and repair the epoxy
coating in sand bed bay 11.
b. Observations
The inspectors observed that NDE visual inspection activities were conducted in
accordance with approved procedures. The inspectors verified that AmerGen
completed the inspections, identified condition(s) in the exterior coating which required
repair, completed the coating repairs in accordance with engineering procedures, and
conducted appropriate re-inspection of repaired areas.
I
In bay 11, the NDE inspection identified one small broken blister, about 1/4 inch in
diameter, with a 6 inch surface rust stain, dry to the touch, trailing down from the blister.
During the initial investigation, three additional smaller surface irregularities (initially
described as surface bumps) were identified within a 1 to 2 square inch area near the
broken blister. The three additional bumps were subsequently determined to be
unbroken blisters. This issue was entered into the corrective action program; all four
blisters were evaluated and repaired. On Nov. 13, the inspectors conducted a general
visual observation (i.e., not a qualified VT inspection) of the repaired area and the
general condition in bay 11. The inspectors verified that AmerGen's inspection data
reports appeared to accurately describe the conditions observed by the inspectors.
To confirm the adequacy of the coating inspection, AmerGen re-inspected 4 sand bed
bays (bays 3, 7, 15, and 19) with a different NDE technician. No additional deficiencies
were identified. A laboratory analysis of removed blister material identified trace
amounts of chlorine and concluded the presence of chlorine can result in osmosis of
moisture through the epoxy coating. The analysis also concluded there were no
pinholes in the blister samples. In addition, the analysis determined approximately
0.003 inches of surface corrosion had occurred directly under the broken blister, and
concluded the corrosion had taken place over approximately a 16 year period. UT
dynamic scan thickness measurements under the four blisters, from inside the drywell,
0
confirmed the drywell shell had no significant degradation as a result of the corrosion.
On Nov. 13, the inspectors conducted a general visual observation (i.e., not a qualified
VT inspection) of the general conditions in bay 5 and 9. The inspectors verified that
AmerGen's inspection data reports appeared to accurately describe the conditions
observed by the inspectors.
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 inspection. The 2006 video showed the same 6
inch rust stain in bay 11. The inspectors compared the 2008 VT results to the 2006
results and noted that in 2006 no coating deficiencies were identified in any sand bed
bay. This apparent deficiency with the 2006 coating inspection was entered into the
corrective action program.
xxx Check CRs >> did bay 4 have any mechanical damage ?
During the final closeout of bays 3, 5, and 7, minor chipping in the epoxy coating was
identified, and described as incidental mechanical damage from personnel entry for
inspection or repair activities. All deficiencies were entered into the corrective action
program and repaired.
During the final closeout of bay 9, an area approximately 8 inches by 8 inches was
identified where the color of the epoxy coating appeared different than the surrounding
area. Because each of the 3 layers of the epoxy coating is a different color, AmerGen
questioned whether the color difference could have been indicative of an original
installation deficiency. This issue was entered into the corrective action program, and
the identified area was re-coated with epoxy.
3.7 Drywell Floor Trench Inspections
a. Scope of Inspection ,
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancements
(5, 16, & 20), stated:
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
supervisors and technicians, reviewed a sample of NDE technician UT qualifications.
The inspectors also reviewed records of trench inspections performed during two non-
refueling plant outages during the last operating cycle.
b. Observations
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. The inspectors independently verified that the UT thickness values
satisfied applicable acceptance criteria.
During two non-refueling plant outages during the last operating cycle, both trenches
were inspected for the presence of water and found dry.
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.
9 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 Xl, 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:
43
Conduct UT thickness measurements in the upper regions of the drywell shell.
Prior to the period of extended operation and two refueling outages later.
The inspectors directly observed non-destructive examination (NDE) activities and the
drywell shell conditions both inside the drywell, including the floor trenches, and in the
sand bed bays (drywell external shell). The inspectors reviewed UT examination
records and compared UT data results to licensee established acceptance criteria in
Specification IS-318227-004, revision 14, "Functional Requirements for Drywell
Containment Vessel Thickness Examinations," and to design analysis values for
minimum wall thickness in calculations C-1 302-187-E310-041, revision 0, "Statistical
Analysis of Drywell Vessel Sand Bed Thickness Data 1992, 1994, 1996, and 2006," and
C-1302-187-5320-024, revision 2, "Drywell External UT Evaluation in the Sand Bed." In
addition, the inspectors reviewed the Technical Evaluations (TEs) associated with the
UT data, as follows:
" TE 330592.27.88, "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.
The inspectors also reviewed a sample of NDE technician UT qualifications.
b. Observations
The inspectors observed that NDE UT examination activities were conducted in
accordance with approved procedures.
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. The inspectors independently
verified that the UT thickness values satisfied applicable acceptance criteria.
3.9 Moisture Barrier Seal Inspection (inside drywell)
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancement
(17), stated:
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 Program
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.
3.1,1 "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
j
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 Circulating 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 Emergency 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:
9 Field work to remove old pipe and install new pipe
9 Foreign material exclusion (FME) controls
9 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 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 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
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 Do we need to describe factual detail of changes ??
xxx an annual summary of changes will be sent to NRC
Do we need to explain the basis to NOT notify NRC staff as part of the LRA ??
None.
40A6 Meetings, Including 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
M. McDermott, NDE Supervisor
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, New Jersey State Department of Environmental Protection
R. Zak, New Jersey State Department of Environmental Protection
M. Fallin, Constellation License Renewal Manager
R. Leski, Nine Mile Point License Renewal Manager
I
t
A-2
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened/Closed
None.
Opened
Closed
None.
4
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 and Specifications
LS-AA-104-1002, 50.59 Applicability Review, Rev 3
LS-AA-1 10, Commitment Change management, Rev 6
645.6.017, Fire Barrier Penetration Surveillance, Rev 13
Specification SP 1302-32-035, Inspection and Minor Repair of Coating on Concrete & Drywell
Shell Surfaces in the Sand Bed Region, dated 2/24/93
ER-AA-335-018, Detailed, General, VT-1, VT-1C, VT-3 and VT-3C Visual Examination of ASME
Class MC and CC Containment Surfaces and Components, Rev. 5
ER-AA-335-004, Manual Ultrasonic Measurement of Material Thickness and Interfering
Conditions, Rev. 2
Incident Reports (IRs)
- = IRs written as a result of the NRC inspection
00804754
00939194
00836395
00838523
00838509
00839848
Maintenance Requests (ARs) & Work Orders (WOs)
WO C20117279
WO R2088180-07
A-4
AR00837554837554AR00836367
AR00836362836362AR00837188
AR00836802836802AR00838148
AR00837765837765AR00836994
AR00838402838402AR00842360
AR00842359842359AR00842357
AR00842355842355AR00842333
AR00842323842323AR00841543
AR00839053839053AR00838509
AR00838833838833AR00839028
AR00839033839033AR00839182
AR00839185839185AR00839188
AR00839192839192AR00839194
AR00839204839204AR00839211
AR00839214839214Ultrasonic Test Non-destructive Examination Records
NDE Data Report 2008-007-017
NDE Data Report 2008-007-030
NDE Data Report 2008-007-031
UT Data Sheet 21R056
Visual Test Inspection Non-destructive Examination Records
1R22-LRA-084, Bay 19, 11/8/08
1R22-LRA-083, Bay 15, 11/8/08
1R22-LRA-082, Bay 7, 11/8/08
1R22-LRA-091, Bay 19, 11/8/08
1R22-LRA-026, Bay 1, 10/30/08
1R22-LRA-052, Bay 3, 10/31/08
1R22-LRA-027, Bay 5, 10/29/08
1R22-LRA-054, Bay 7, 10/31/08
1R22-LRA-028, Bay 9, 10/29/08
1R22-LRA-046, Bay 11, 10/31/08
'4 . ,~
t lit
A-5
1R22-LRA-035, Bay 13, 10/30/08
1R22-LRA-048, Bay 15, 10/31/08
1R22-LRA-029, Bay 17, 10/30/08
1R22-LRA-050, Bay 19, 10/31/08
NDE Certification Records
NDE Certification #1421 for M. Kent Waddell, dated 10/29/08
NDE Certification #0977 for Richard L. Alger, dated 10/29/08
Miscellaneous Documents
NRC Documents
Industry Documents
- = documents referenced within NUREG-1801 as providing acceptable guidance for specific
aging management programs
A-6
LIST OF ACRONYMS
ASME American Society of Mechanical Engineers
EPRI Electric Power Research Institute
NDE Non-destructive Examination
NEI Nuclear Energy Institute
SSC Systems, Structures, and Components
SDP Significance Determination Process
TE Technical Evaluation
UFSAR Updated Final Safety Analysis Report
UT Ultrasonic Test
VT Visual Testing