ML091980460
| ML091980460 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 06/17/2009 |
| From: | Darrell Roberts Division of Reactor Safety I |
| To: | Pardee C Exelon Generation Co |
| References | |
| FOIA/PA-2009-0070 IR-08-007 | |
| Download: ML091980460 (27) | |
See also: IR 05000219/2008007
Text
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-- THHEýRýEMPONý
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.
This inspection was conducted using the guidance of Inspection Procedure (IP) 71003 "Post-
Approval Site Inspection for License Renewal" as a prudent measure to observe Oyster Creek
license renewal activities during the last planned refueling outage prior to entering the period of
extended operation. The inspection examined important license renewal activities conforming
to the Commission's rules and regulations. The inspectors reviewed selected procedures and
records, observed activities, and interviewed personnel. This inspection focusedon the
inservice inspection of the drywell containment. Based on the results of the NRC's inspection,
the NRC determined there were no safety significant conditions affecting current operations.
Because your renewed license has not been issued, the proposed license conditions and
associated commitments, made as a part of the license renewal application, are not in effect.
The enclosed report records the inspector's observations.
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C. Pardee 2
In accordance with 10 CFR 2.390 of -the NRC's "Rules of Practice," a copy of this letter and its
enclosure will be available electronically for public inspection in the NRC Public Document
Room or from the Publicly Available Records (PARS) component of NRC's document system
(ADAMS). ADAMS is accessible from the NRC Web-site at http://www.nrc.,Qov/reading-
rm/adams.html (the Public Electronic Reading Room).
We appreciate your cooperation. Please contact me at (610) 337-5128 if you have any
questions regarding this letter.
Sincerely,
Darrell Roberts, Director
Division of Reactor Safety
Docket No. 50-219
License No. DPR-16
Enclosure: Inspection Report No. 05000219/2008007
w/Attachment: Supplemental Information
C. Crane, President and Chief Operating Officer, Exelon Corporation
M. Pacilio, Chief Operating Officer, Exelon Nuclear
T. Rausch, Site Vice President, Oyster Creek Nuclear Generating Station
J. Randich, Plant Manager, Oyster Creek Generating Station
J. Kandasamy, Regulatory Assurance Manager, Oyster Creek
R. DeGregorio, Senior Vice President, Mid-Atlantic Operations
K. JuryVice President, Licensing and Regulatory Affairs
P. Cowan, Director, Licensing
B. Fewell, Associate General Counsel, Exelon
Correspondence Control Desk, AmerGen
Mayor of Lacey Township
P. Mulligan, Chief, NJ Dept of Environmental Protection
R. Shadis, New England Coalition Staff
E. Gbur, Chairwoman - Jersey Shore Nuclear Watch
E. Zobian, Coordinator - Jersey Shore Anti Nuclear Alliance
P. Baldauf, Assistant Director, NJ Radiation Protection Programs
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C. Pardee 2
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its
enclosure will be available electronically for public inspection in the NRC Public Document
Room or from the Publicly Available Records (PARS) component of NRC's document system
(ADAMS). ADAMS is accessible from the NRC Web-site at http://www.nrc.-qov/readinq-
rm/adams.html (the Public Electronic Reading Room).
We appreciate your cooperation. Please contact me at (610) 337-5128 if you have any
questions regarding this letter.
Sincerely,
Darrell Roberts, Director
Division of Reactor Safety
Docket No. 50-219
License No. DPR-16
Enclosure: Inspection Report No. 05000219/2008007
w/Attachment: Supplemental Information
Distribution w/encl:
S. Collins, RA
M. Dapas, DRA
D. Lew, DRP
J. Clifford, DRP
R. Bellamy, DRP
S. Barber, DRP
C. Newport, DRP
M. Ferdas, DRP, Senior Resident Inspector
J. Kulp, DRP, Resident Inspector
J, DeVries, DRP, Resident OA
S. Williams, RI OEDO
H. Chernoff, NRR
R. Nelson, NRR
J. Hughey, NRR, Backup
ROPreportsResource@nrc.gov (All IRs)
Region I Docket Room (with concurrences)
SUNSI Review Complete: _ (Reviewer's Initials) Adams Accession No.
DOCUMENT NAME: C:\Doc\_.OC LRI 2008-07\_. Report\OC 2008-07 LRIrev-9.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
SOFFICE RI/DRS E RI/DRS RIDPRI/DRS
NAME JRichmond/ RConte/ RBellamy/ DRoberts/
DATE 01/ /09 01/ /09 01/ /09 01/ /09
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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. The inspection
was conducted by five region based engineering inspectors and with assistance from the
Oyster Creek resident inspector. The inspection was conducted using Inspection Procedure (IP) 71003 "Post-Approval Site Inspection for License Renewal." In accordance with the NRC's
memorandum of understanding with the State of New Jersey, state engineers from the
Department of Environmental Protection, Bureau of Nuclear Engineering, observed portions of
the NRC inspection activities.
A. NRC-Identified and Self-Revealing Findings
No findings of significance were identified.
B. Licensee-Identified Violations
None.
2
REPORT DETAILS
Summary of Plant Status
The Oyster Creek Generating Station was in a scheduled refueling outage during the on-site
portions of this inspection.
At the time of the inspection, AmerGen Energy Company, LLC was the licensee for Oyster
Creek Generating Station. As of January 8, 2009, the Oyster Creek license was transferred to
Exelon Generating Company, LLC by license amendment No. 271 (ML082750072).
4. OTHER ACTIVITIES (OA)
40A5 License Renewal Follow-up (IP 71003)
1.1 Purpose of Inspection
An appeal of a licensing board decision about the Oyster Creek (OC) application for a
renewed license is pending before the Commission. The NRC conducted this inspection
using the guidance of Inspection Procedure (IP) 71003 "Post-Approval Site Inspection
for License Renewal." This inspection was considered a prudent measure in order to
make observations of Oyster Creek license renewal activities during the last refuel
outage prior to entering the period of extended operation.
Inspection observations were made of license renewal commitments and license
conditions selected from NUREG-1 875, "Safety Evaluation Report (SER) Related to the
License Renewal of Oyster Creek Generating Station" (ML071290023 & ML071310246).
The inspection included observations of a number of license renewal commitments
which were enhancements to exiting programs implemented under the current license.
Performance of existing programs, absent of any associated license renewal
enhancement, was evaluated using the criteria in 10 CFR 50.
For license renewal activities, within the context of 10 CFR 54, the report documents the
inspector observations because the proposed license conditions and commitments are
not in effect. These conditions and commitments are not in effect because the
application for a renewed license remains under Commission review for final decision,
and a renewed license has not been approved for Oyster Creek.
1.2 Sample Selection Process
The SER proposed commitments and proposed license conditions were selected'based
on the risk significance using insights gained from sources such as the NRC's
"Significance Determination Process Risk Informed Inspection Notebooks," the results
of previous license renewal audits, and inspections of aging management programs.
The inspectors also reviewed selected corrective actions taken as a result of previous
license renewal inspections.
2. Assessment of Current License Basis Performance Issues
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t
The inspectors determined Exelon provided an adequate basis to conclude the drywell
primary containment will remain operable throughout the period to the next scheduled
examination (2012 refueling outage), This determination was based on the inspectors'
evaluation of the drywell shell ultrasonic test (UT) thickness measurements, direct
observation of drywell shell conditions both inside the drywell, including the floor
trenches, and outside the drywell, in the sand bed regions, condition and integrity of the
drywell shell epoxy coating, and condition of the drywell shell moisture barrier seals.
As noted in the details of sections 3.1, 3.2, 3.3, and 3.4 below, a few current licensing
basis issues were observed that may require licensee corrective action. Because the
following issues may be associated with performance deficiencies, an Unresolved Item
(URI) is being opened for NRC tracking. After the licensee has had sufficient time to
evaluate the issues and determine appropriate corrective actions, the NRC will review
the available information to determine there is a performance deficiency. The specific
items for follow-up include:
De-lamination of the strippable coating applied to the liner of the refuel cavity (as
discussed in Section 3.1); and
the discovery by boroscopic examination that the reactor vessel refueling cavity
trough drain line valve was in the closed position during a portion of time while
the drain flow was being monitored and the refuel cavity was flooded (as
discussed in Section 3.2); and
F (ob)(5) monitor the entire length of former sand bed drain lines, visible from the
torus Iom, and the subsequent discovery that two of the drain lines were not
directly attached to the portion of the drain line exiting the concrete shield wall
below the former sand bed (as discussed in Section 3.3); and
During the next site visit, the NRC will follow up on Exelon's evaluation and the
repair of four small blisters on the epoxy coating in sand bed bay 11. Exelon
stated that some blistering was expected, and would be identified during routine
visual examinations. The NRC staff will review Exelon's cause evaluation after it
is completed. (URI 0500021912008007-01: Drywell Sand Bed Water
Intrusion, Drain Monitoring, and Coating Deficiency)
IP 71003 consists of a number of site visits to determine the status of license renewal
commitment implementation.
The drywell shell epoxy coating and the moisture barrier seal, both in the sand bed
region, are barriers used to protect the drywell from corrosion. The problems identified
and corrected with these barriers had a minimal impact on the drywell steel shell. The
projected shell corrosion rate remains very small, as confirmed by the NRC staff review
of Exelon's technical evaluations of the 2008 UT data. Based on the NRC's direct
observation of the blisters, review of Exelon's repair, and direct observation of drywell
shell conditions both inside the drywell and outside the drywell, in the sand bed regions,
and the over all condition and integrity of the drywell shell epoxy coating, the NRC
determined Exelon provided an adequate basis to conclude the likelihood of additional
I
blisters will not impact the containment safety function during the period until the next
scheduled examination, in the 2012 refueling outage.
3. Detailed Review of License Renewal Activities
3.1 Reactor Refuel Cavity Liner Strippable Coating
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancement
(2), stated, in part:
A strippable coating will be applied to the reactor cavity liner to prevent water
intrusion into the gap between the drywell shield wall and the drywell shell during
periods when the reactor cavity is flooded. Prior to filling the reactor cavity with
water.
(b)(5)o7
The inspector reviewed work order (WO) 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
localized 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 3.4 below for additional details).. This issue was entered into the corrective
action program as Issue Report (IR) 841543. In addition, this item was included in a
common cause evaluation as part of IR 845297. Exelon's initial evaluations identified
several likely or contributing causes, including:
9 A portable submerged water filtration unit was improperly placed in the reactor
cavity, which resulted in flow discharged directly on the strippable coating.
"A il spill into the cavity may have affected the coating integrity,
" N:pos'tinstallation inspection of the coating had been performed.
3.2 Reactor Refuel Cavity Seal Leakage Monitoring
a.. Scope of Inspection.
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancement
(3), stated, in part:
The reactor cavity seal leakage trough drains and the drywell sand bed region
drains will be monitored for leakage, periodically.
The inspectors observed Exelon's cavity seal leakage monitoring activities, performed
by WO R2095857. The inspectors independently checked the cavity trough drain flow
immediately after the reactor cavity was filled, and several times throughout the outage.
The inspectors also reviewed the written monitoring logs.
b. Observations
Exelon monitored reactor refuel cavity seal leakage by checking and recording the flow
in a two inch drain line from the cavity concrete trough to a plant radwaste system drain
funnel which, in turn, drained to the reactor building sump.
On Oct. 27, Exelon isolated the cavity trough drain line to install a tygon hose to allow
drain flow to be monitored. On Oct. 28, the reactor cavity was filled. Drain line flow was
monitored frequently during cavity flood-up, and daily thereafter. On Oct. 29, a
boroscope examination of the drain line identified that the isolation valve had been left
closed. When the drain line isolation valve was opened, about 3 gallons of water
drained out. The drain flow then subsided to about an 1/8 inch stream (less than 1
gpm). This issue was entered into the corrective action program as IR 837647.
3.3 Drywell Sand Bed Region Drain Monitoring
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancement
(3), stated, in part:
The sand bed region drains will be monitored daily during refueling outages.
The inspectors observed Exelon's activities to monitor sand bed drains, performed by
WO R2095857. The inspectors independently checked drain line poly bottles and
accompanied Exelon personnel during routine daily checks. The inspectors also
reviewed the written monitoring logs.
b. Observations
There is one sand bed drain line for every two sand bed bays (i.e., total of five drains for
10 bays). Exelon remotely monitored the sand bed drains by checking for the existence
of water in poly bottles attached via tygon tubing (approximately 50 foot long) to a funnel
hung below each drain line. The sand bed drains, funnels, and a majority of the tygon
tubing were not directly observable from the outer area of the torus room, where the
poly bottles were located.
On Nov. 10, Exelon found two of the five tygon tubes disconnected from their funnels
and laying on the floor (bays 3 and 7). Exelon personnel could not determine when the
tubing was last verified to be connected to the funnel. The inspectors directly observed
that the torus room floor had standing water for most of the outage, due to other
identified system leaks. The inspectors noted that the standing water prevented Exelon
personnel from determining whether any water had drained directly onto the floor from a
sand bed drain during the time period that the tygon tubing was disconnected. Both
tubes were subsequently reconnected. This issue was entered into the corrective action
program as IR 843209.
xxx need IR # >> Exelon's not sure they wrote one specific for this
On Nov. 15, during a daily check of the sand bed bay 11 drain poly bottle, Exelon found
the poly bottle full (greater than 4 gallons). The inspectors noted that Exelon had found
the poly bottle empty during each check throughout the outage until Nov 15, and had
only noted water in the poly bottle three days after the reactor refuel cavity had been
drained. The inspectors also noted that the funnel, to which the tygon tubing was
connected, had a capacity of about 6 gallons. The inspectors also noted that Exelon
entered bay 11 within a few hours of identifying the water, visually inspected the bay,
and found it dry. Exelon sampled the water, but could not positively determine the
source based on radiolytic or chemical analysis. This issue was entered into the
corrective action program as IR xxx.
3.4 Reactor Cavity Seal Leakage Action Plan for 1 R22
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancement
(3), stated, in part:
If leakage is detected [flow out of a sand bed drain], procedures will be in place
to determine the source of leakage and investigate and address the impact of
leakage on the drywell shell.
The inspectors reviewed Exelon's pre-approved cavity seal leakage action plan.
b. Observations
For the reactor cavity seal leakage, Exelon established an administrative limit of 12 gpm
flow in the cavity trough drain, 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 inspectors noted that Exelon's pre-approved action plan, in part, directed the
following actions to be taken:
- If the cavity trough drain flow exceeded 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 />.
a If the cavity trough drain flow exceeded 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 exceeded 12 gpm and any water is found in a
sand bed poly bottle, then enter and inspect the sand bed bays.
On Nov. 6, the reactor cavity liner strippable coating started to de-laminate (see section
3.1 above). The cavity trough drain flow took a step change from less than 1 gpm to
approximately 4 to 6 gpm. Exelon increased monitoring of the trough drain to every 2
hours and 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 />. The cavity trough
drain flow remained at about 4 to 6 gpm until the cavity was drained on Nov. 12, when
the drain flow subsided to zero.
On Nov 8, personnel working in sand bed bay 11 identified dripping water. Water
puddles were subsequently identified in sand bed bays 11, 13, 15,,and 17. These
issues were entered into the corrective action program as IR 842333. In addition, these
items were included in a common cause evaluation as part of IR 845297. The
inspectors noted that all sand bed bay work was originally scheduled to have been
completed and to have the bays closed out by Nov. 2.
On Nov 12, the cavity was drained. All sand bed bays were dried and inspected for any
water or moisture damage; no deficiencies were identified. Exelon stated follow-up
ultrasonic test (UT) examinations will be performed to evaluate the drywell shell during
the next refuel outage.
On Nov. 15, water was found in the sand bed bay 11 poly bottle (see section 3.3 above).
The inspectors observed that actions taken in response to increased cavity seal leakage
were inconsistent with Exelon's pre-approved action plan. The plan did not direct
increased sand bed poly bottle monitoring for the given leakage rate, and would not
have required a sand bed entry or inspection until Nov 15, when water was first found in
a poly bottle (although these actions were taken as a result of the identification of the
dripping water identified on Nov. 8). The inspectors also noted that water had entered
the gap between the drywell shield wall and the drywell shell at a much lower value of
cavity seal leakage than Exelon had calculated.
3.5 Reactor Cavity Trougqh Drain Inspection for Blockage
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancement
(13), stated, in part:
The reactor cavity concrete trough drain will be verified to be clear from blockage
once per refueling cycle. Any identified issues will be addressed via the
corrective action process.
The inspector reviewed a video recording record of a boroscope inspection of the cavity
trough drain line, performed by WO R2102695.
b. Observations
See observations in section 3.2 above.
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, in part:
8
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 observed portions of Exelon's activities to perform a 100% visual test
(VT) inspection of the seal in the sand bed region (total of 10 bays). The inspectors
directly observed as-found conditions in portions of 6 sand bed bays, and as-left
conditions in 4 sand bed bays. The inspectors' general visual observations were made
to identify flaking, peeling, blistering, de-lamination, cracking, discoloration, corrosion,
mechanical damage, etc.
The inspectors reviewed VT inspection records for each sand bed bay, and compared
their direct observations to the recorded VT inspection results. The inspectors reviewed
Exelon VT inspection procedures, interviewed non-destructive examination (NDE)
supervisors and technicians, and observed field collection and recording of VT
inspection data. The inspectors also reviewed a sample of NDE technician visual
testing qualifications.
The inspectors observed Exelon's activities to evaluate and repair the moisture barrier
seal in sand bed bay 3.
b. Observations
The purpose of the moisture barrier seal is to prevent water from entering a gap below
the concrete floor in the sand bed region. The inspectors observed that NDE visual
inspection activities were conducted in accordance with approved procedures. The
inspectors verified that Exelon completed the inspections, identified condition(s) in the
moisture barrier seal which required repair, completed the seal repairs in accordance
with engineering procedures, and conducted appropriate re-inspection of repaired
areas.
The VT inspections identified moisture barrier seal deficiencies in 7 of the 10 sand bed
bays, including surface cracks and partial separation of the seal from the steel shell or
concrete floor. Exelon determined the as-found moisture barrier function was not
impaired, because no cracks or separation fully penetrated the.seal. All deficiencies
were entered into the corrective action program and repaired (IRs are listed in the
Attachment). In addition, these items were included in a common cause evaluation as
part of IR 845297.
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 drywell shell surface were repaired. This issue
was entered into the corrective action program as IRs 839194 and 841957.
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.
1
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, in part:
Perform visual inspections of the drywell external shell epoxy coating in all 10
sand bed bays. During the 2008 refueling outage and every other refueling
outage thereafter.
The inspectors observed portions of Exelon's activities to perform a 100% visual
inspection of the epoxy coating in the sand bed region (total of 10 bays). In addition, the
inspectors directly observed as-found conditions of the epoxy coating in portions of 6
sand bed bays, and the as-left condition in sand bed bay 11, after coating repairs. The
inspectors' general visual observations were made to identify flaking, peeling, blistering,
de-lamination, cracking, discoloration, corrosion, mechanical damage, etc. The
inspectors also observed field collection, recording, and reporting of visual inspection
data.
The inspectors reviewed VT inspection records for each sand bed bay and compared
their direct observations to the recorded VT inspection results. The inspectors reviewed
Exelon VT inspection procedures, interviewed NDE supervisors and technicians, and
observed field collection and recording of VT inspection data. The inspectors also
reviewed a sample of NDE technician visual testing qualifications.
The inspectors directly observed Exelon's activities to evaluate and repair the epoxy
coating in sand bed bay 11. In addition, the inspectors reviewed Technical Evaluation
330592.27.46, "Coating Degradation in Sand Bed bay 11V
b. Observations
The inspectors observed that NDE visual inspection activities were conducted in
accordance with approved procedures. The inspectors verified that Exelon completed
the inspections, identified condition(s) in the exterior coating which required repair,
completed the coating repairs in accordance with engineering procedures, and
conducted appropriate re-inspection of repaired areas.
In sand bed bay 11, the NDE inspection identified one small broken blister, about 1/4
inch in diameter, with a 6 inch surface rust stain, dry to the touch, trailing down from the
blister. During the initial investigation, three additional smaller surface irregularities
(initially described as surface bumps) were identified within a 1 to 2 square inch area
near the broken blister. The three additional bumps were subsequently determined to
be unbroken blisters. This issue was entered into the corrective action program as IRs
838833 and 839053. In addition, this item was included in a common cause evaluation
as part of IR 845297. 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 of the epoxy coating and
moisture barrier seal in bay 11. The inspectors verified that Exelon's inspection data
reports appeared to accurately describe the conditions observed by the inspectors.
To confirm the adequacy of the coating inspection, Exelon re-inspected 4 sand bed bays
(bays 3, 7, 15, and 19) with a different NDE technician. No additional deficiencies were
identified. In Technical Evaluation 330592.27.46, Exelon determined, by laboratory
analysis using energy dispersive X-ray spectroscopy, that the removed blister material
contained trace amounts of chlorine. Exelon also determined that the presence of
chlorine, in a soluble salt as chloride on the surface of the drywell shell prior to the initial
application of the epoxy coating, can result in osmosis of moisture through the epoxy
coating. The analysis also concluded there were no pinholes in the blister samples. In
addition, the analysis determined approximately 0.003 inches of surface corrosion had
occurred directly under the broken blister. Exelon concluded that the corrosion had
taken place over approximately a 16 year period. In addition, UT dynamic scan
thickness measurements under the four blisters, from inside the drywell, confirmed the
drywell shell had 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 inspect6rs observed that Exelon's inspection
data reports adequately described the conditions observed by the inspectors.
xxx ADD IR # >> Exelon doesn't think they wrote one specific for this
In follow-up, Exelon reviewed a 2006 video of the sand beds, which had been made as
a general aid, not as part of an NDE inspection. The 2006 video showed the same 6
inch rust stain in bay 11, The inspectors compared the 2008 VT results to the 2006
results and noted that in 2006 no coating deficiencies were identified in any sand bed
bay. This apparent deficiency with the 2006 coating inspection was entered into the
corrective action program as IR xxx.
During the final closeout of bays 3, 5, and 7, minor chipping in the epoxy coating was
identified, and described as incidental mechanical damage from personnel entry for
inspection or repair activities. All deficiencies were entered into the corrective action
program and repaired (IRs are listed in the Attachment).
During the final closeout of bay 9, an area approximately 8 inches by 8 inches was
identified where the color of the epoxy coating appeared different than the surrounding
area. Because each of the 3 layers of the epoxy coating is a different color, Exelon
questioned whether the color difference could have been indicative of an original
installation deficiency. This issue was entered into the corrective action program as IR
844815, and the identified area was re-coated with epoxy.
3.8 Drywell Floor Trench Inspections
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancements
(5, 16, & 20), stated, in part:
Perform visual test (VT) and ultrasonic test (UT) examinations of the drywell shell
A
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 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-1 302-187-E310-041,
revision 0, "Statistical Analysis of Drywell Sand Bed Thickness Data 1992, 1994, 1996,
and 2006," and C-1302-187-5320-024, revision 2, "Drywell External UT Evaluation in the
Sand Bed." In addition, the inspectors reviewed Technical Evaluation 330592.27.43,
"2008 UT Data of the Sand Bed Trenches."
The inspectors reviewed Exelon UT examination procedures, interviewed NDE
supervisors and technicians, reviewed a sample of NDE technician UT qualifications.
The inspectors also reviewed records of trench inspections performed during two non-
refueling plant outages during the last operating cycle.
b. Observations
In Technical Evaluation 330592.27.43, Exelon determined the UT thickness values
satisfied the general uniform minimum wall thickness criteria (e.g.,iayerage thickness of
an area) and the locally thinned minimum wall thickness criteria (e~g., areas 2 inches or
less in diameter) for the drywell shell, as applicable. For UT data sets, such as 7x7
arrays, the Technical Evaluation calculated statistical parameters and determined the
data set distributions were acceptable. The Technical 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 verified that the UT thickness values satisfied applicable acceptance
criteria.
During two non-refueling plant outages during the last operating cycle, both trenches
were inspected for the presence of water and found dry by Exelon's staff and by NRC
inspectors (NRC Inspection Reports 05000219/2007003, 05000219/2007004, and
memorandum ML071240314).
During the initial drywell entry on Oct. 25, the inspectors observed'that both floor
trenches were dry. On subsequent drywell entries for routine inspection activities, the
inspectors observed the trenches to be dry. On one occasion, Exelon observed a small
amount of water in the bay 5 trench, which they believed was from water spilled nearby
on the drywell floor; the trench was dried and the issue entered into the corrective action
program as IR 843190. On Nov. 17, during the final drywell closeout inspection, the
inspectors observed the following:
- 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. Exelon stated the trench would be dried prior to final drywell closeout.
This issue was entered into the corrective action program as IR 846240.
- 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.
3.9 Drywell Shell Thickness Measurements
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancements
(1, 9, 14, & 21), stated, in part:
Perform full scope drywell inspections [in the sand bed region], including UT
thickness measurements of the drywell shell, from inside and outside the drywell.
During the 2008 refueling outage and every other refueling outage thereafter.
Proposed SER Appendix-A Item 27, ASME Section Xl, Subsection IWE Enhancements
(7, 10, & 11) stated, in part:
Conduct UT thickness measurements in the upper regions of the drywell shell.
Prior to the period of extended operation and two refueling outages later.
The inspectors directly observed 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-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:
9 TE 330592.27.42, "2008 Sand Bed UT data - External"
9 TE 330592.27.45, "2008 Drywell UT Data at Elevations 23 & 71 foot"
9 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.
In Technical Evaluations 330592.27.42, 330592.27.45, and 330592.27.88, Exelon
determined the UT thickness values satisfied the general uniformn minimum wall
thickness criteria (e.g., average thickness of an area) and the locally thinned minimum
wall thickness criteria (e.g., areas 2 inches or less in diameter), as applicable. For UT
data sets, such as 7x7 arrays, the Technical Evaluations calculated statistical
parameters and determined the data set distributions were acceptable. The Technical
Evaluations 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.
3,10 Moisture Barrier Seal Inspection (inside drywell)
a. Scope of Inspection
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection iWE Enhancement
(17), stated, in part:
Perform visual inspection of the moisture barrier seal between the drywell shell
and the concrete floor curb, installed inside the drywell during the October 2006
refueling outage, in accordance with ASME Code.
The inspector reviewed structural inspection reports 187-001 and 187-002, performed
by WO R2097321-01 on Nov 1 and Oct 29, respectively. The reports documented
visual inspections of the perimeter seal between the concrete floor curb and the drywell
steel shell, at the floor elevation 10 foot. In addition, the inspector reviewed selected
photographs taken during the inspection
b. Observations
No noteworthy observations.
3.11 One Time Inspection Proqram
a. Scope of Inspection
Proposed SER Appendix-A Item 24, One Time Inspection Program, stated, in part:
The One-Time Inspection program will provide reasonable assurance that an
aging effect is not occurring, or that the aging effect is occurring slowly enough
to not affect the component or structure intended function during the period of
extended operation, and therefore will not require additional aging management.
Perform prior to the period of extended operation.
The inspector reviewed the program's sampling basis and sample plan.- Also, the
inspector reviewed ultrasonic test results from selected piping sample locations in the
main steam, spent fuel pool cooling, domestic water, and demineralized water systems.
b. Observations
No noteworthy observations.
3.12 "B" Isolation Condenser Shell Inspection
a. Scope of Inspection
Proposed SER Appendix-A Item 24, One Time Inspection Program Item (2), stated, in
part:
To confirm the effectiveness of the Water Chemistry program to manage the
loss of material and crack initiation and growth aging effects. A one-time UT
inspection of the "B" Isolation Condenser shell below the waterline will be
conducted looking for pitting corrosion. Perform prior to the period of extended
operation.
The inspector observed NDE examinations of the "B" isolation condenser shell
performed by WO C2017561-11. The NDE examinations included a visual inspection of
the shell interior, UT thickness measurements in two locations that were previously
tested in 1996 and 2002, additional UT tests in areas of identified pitting and corrosion,
and spark testing of the final interior shell coating. The inspector reviewed the UT data
records, and compared the UT data results to the established minimum wall thickness
criteria for the isolation condenser shell, and compared the UT data results with
previously UT data measurements from 1996 and 2002
b. Observations
No noteworthy observations.
3.13 Periodic Inspections
a. Scope of Inspection
Proposed SER Appendix-A Item 41, Periodic Inspection Program, stated, in part:
Activities consist of a periodic inspection of selected systems and components to
verify integrity and confirm the absence of identified aging effects. Perform prior
to the period of extended operation.
The inspectors observed the following activities:
- Condensate expansion joints Y-2-11 and Y-2-12 inspection (WO R2083515)
- 4160 V Bus 1C switchgear fire barrier penetration inspection (WO R2093471)
b. Observations
No noteworthy observations.
3.14 Circulatingi Water Intake Tunnel & Expansion Joint Inspection
a. Scope of Inspection
Proposed SER Appendix-A Item 31, Structures Monitoring Program Enhancement (1),
stated, in part:
Buildings, structural components and commodities that are not in scope of
maintenance rule but have been determined to be in the scope of license
renewal. Perform prior to the period of extended operation.
On Oct. 29, the inspector directly observed the conduct of a structural engineering
inspection of the circulating water intake tunnel, including reinforced concrete wall and
floor slabs, steel liners, embedded steel pipe sleeves, butterfly isolation valves, and
tunnel expansion joints. The inspection was conducted by a qualified Exelon structural
engineer. After the inspection was completed, the inspector compared his direct
observations with the documented visual inspection results.
b. Observations
No noteworthy observations.
3.15 Buried Emergency Service Water Pipe Replacement
a. Scope of Inspection
Proposed SER Appendix-A Item 63, Buried Piping, stated, in part:
Replace the previously un-replaced, buried safety-related emergency service
water piping prior to the period of extended operation. Perform prior to the
period of extended operation.
The inspectors observed the following activities, performed by WO C2017279:
- Field work to remove old pipe and install new pipe
- Foreign material exclusion (FME) controls
- External protective pipe coating, and controls to ensure the pipe installation
activities would not result in damage to the pipe coating
b. Observations
No noteworthy observations.
3.16 Electrical Cable Inspection inside Drywell
a. Scope of Inspection
Proposed SER Appendix-A Item 34, Electrical Cables and Connections, stated, in part:
A representative sample of accessible cables and connections located in
adverse localized environments will be visually inspected at least once every 10
years for indications of accelerated insulation aging. Perform prior to the period
of extended operation.
The inspector accompanied electrical technicians and an electrical design engineer
during a visual inspection of selected electrical cables in the drywell. The inspector
observed the pre-job brief which discussed inspection techniques and acceptance
criteria. The inspector directly observed the visual inspection, which included cables in
raceways, as well as cables and connections inside junction boxes. After the inspection
was completed, the inspector compared his direct observations with the documented
visual inspection results.
b. Observations
No noteworthy observations.
3.17 Drywell Shell Internal Coatings Inspection (inside drywell)
a. Scope of Inspection
Proposed SER Appendix-A Item 33, Protective Coating Monitoring and Maintenance
Program, stated, in part:
The program provides for aging management of Service Level I coatings inside
the primary containment, in accordance with ASME Code.
The inspector reviewed a vendor memorandum which summarized inspection findings
for a coating inspection of the as-found condition of the ASME Service Level I coating of
the drywell shell inner surface. In addition, the inspector reviewed selected photographs
taken during the coating inspection and the initial assessment and disposition of
identified coating deficiencies. The coating inspector was also interviewed. The coating
inspection was conducted on Oct. 30, by a qualified ANSI Level Ill 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
4-
No noteworthy observations.
3.18 Inaccessible Medium Voltage Cable Test
a. Scope of Inspection
Proposed SER Appendix-A Item 36, Inaccessible Medium Voltage Cables, stated, in
part:
Cable circuits will be tested using a proven test for detecting deterioration of the
insulation system due to wetting, such as power factor or partial discharge.
Perform prior to the period of extended operation.
The inspector observed field testing activities for the 4 kilovolts feeder cable from the
auxiliary transformer secondary to Bank 4 switchgear and independently reviewed the
test results. A Doble and power factor test of the transformer, with the cable connected
to the transformer secondary, was performed, in part, to detect deterioration of the cable
insulation. The inspector also compared the current test results to previous test results
from 2002. In addition, the inspector interviewed plant electrical engineering and
maintenance personnel.
b. Observations
No noteworthy observations.
3.19 Fatigue Monitoring Program
a. Scope of Inspection
Proposed SER Appendix-A Item 44, Metal Fatigue of Reactor Coolant Pressure
Boundary, stated, in part:
The program will be enhanced to use the EPRI-licensed FatiguePro cycle
counting and fatigue usage factor tracking computer program.
The inspectors reviewed Exelon's proposed usage of the FatiguePro software program,
reviewed the list of high cumulative usage factor components, and interviewed the
fatigue program manager.
b. Observations
The inspectors noted that the FatiguePro program, although in place and ready-to-go,
had not been implemented. Exelon stated the FatiguePro program will be implemented
after final industry resolution of a concern regarding a mathematical summation
technique used in FatiguePro.
4. ProDosed Conditions of License
a. Scope of Inspection
SER Section 1.7 contained two outage related proposed conditions of license:
The fourth license condition requires the applicant to perform full scope
inspections of the drywell sand bed region every other refueling outage.
The fifth license condition requires the applicant to monitor drywell trenches
every refueling outage to identify and eliminate the sources of water and receive
NRC approval prior to restoring the trenches to their original design
configuration.
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancements
(1, 4, 9, 12, 14, & 21) implement the proposed license condition associated with a full
scope drywell sand bed region inspection.
Proposed SER Appendix-A Item 27, ASME Section XI, Subsection IWE Enhancements
(5, 16, & 20) implement the proposed license condition associated with the drywell
trenches.
b. Observations
For observations, see the applicable sections above for the specific ASME Section XI,
Subsection IWE Enhancements.
5. Commitment Management Program
a. Scope of Inspection
The inspectors evaluated current licensing basis procedures used to manage and revise
regulatory commitments to determine whether they were consistent with the
requirements of 10 CFR 50.59, NRC Regulatory Issue Summary 2000-17, "Managing
Regulatory Commitments," and the guidance in Nuclear Energy Institute (NEI) 99-04,
"Guidelines for Managing NRC Commitment Changes." In addition, the inspectors
reviewed the procedures to assess whether adequate administrative controls were in-
place to ensure commitment revisions or the elimination of commitments altogether
would be properly evaluated, approved, and annually reported to the NRC. The
inspectors also reviewed Exelon's current licensing basis commitment tracking program
to evaluate its effectiveness. In addition, the following commitment change evaluation
packages were reviewed:
- Commitment Change 08-003, OC Bolting Integrity Program
" Commitment Change 08-004, RPV Axial Weld Examination Relief
b. Observations
The inspectors observed that the commitment change activities were conducted in
accordance with approved procedures, which required an annual update to the NRC
with a summary of each change.
40A6 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
Exelon's staff on December 23, 2008. NRC Exit Notes from the exit meeting are located
in ADAMS within package ML090120726.
No proprietary information is present in this inspection report.
A-1
ATTACHMENT
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
C. Albert, Site License Renewal
J. Cavallo, Corrosion Control Consultants & labs, Inc.
M. Gallagher, Vice President License Renewal
C. Hawkins, NDE Level III Technician
J. Hufnagel, Exelon License Renewal
J. Kandasamy, Manager Regulatory Affairs
S. Kim, Structural Engineer
M. McDermott, NDE Supervisor
R. McGee, Site License Renewal
D. Olszewski, System Engineer
F. Polaski, Exelon License Renewal
R. Pruthi, Electrical Design Engineer
S. Schwartz, System Engineer
P. Tamburro, Site License Renewal Lead
C. Taylor, Regulatory Affairs
NRC Personnel
S. Pindale, Acting Senior Resident Inspector, Oyster Creek
J. Kulp, Resident Inspector, Oyster Creek
L. Regner, License Renewal Project Manager, NRR
D. Pelton, Chief - License Renewal Projects Branch 1, NRR
M. Baty, Counsel for NRC Staff
J. Davis, Senior Materials Engineer, NRR
Observers
R. Pinney, New Jersey State Department of Environmental Protection
R. Zak, New Jersey State Department of Environmental Protection
M. Fallin, Constellation License Renewal Manager
R. Leski, Nine Mile Point License Renewal Manager
A-2
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened/Closed
None.
Opened
05000219/2008007-01 URI Drywell Sand Bed Water Intrusion, Drain Monitoring,
and Coating Deficiency (Section 2.0)
Closed
None.
,~, ,
A-3
LIST OF DOCUMENTS REVIEWED
License Renewal Program Documents
Drawinqs
Plant Procedures and Specifications
Incident Reports (113s)
- = IRs written as a result of the NRC inspection
Maintenance Requests (ARs) & Work Orders (WOs)
Ultrasonic Test Non-destructive Examination Records
Visual Test Inspection Non-destructive Examination Records
NDE Certification Records
Miscellaneous Documents
NRC Documents
Industry Documents
- documents referenced within NUREG-1801 as providing acceptable guidance for specific
aging management programs -
A-4
LIST OF ACRONYMS
ANSI American national Standards Institute
ASME American Society of Mechanical Engineers
CLB Current Licensing Basis
EPRI Electric Power Research Institute
FME Foreign Material Exclusion
IP [NRC] Inspection Procedure
IR [Exelon] Issue Report
gpm Gallons per Minute
NDE Non-destructive Examination
NEI Nuclear Energy Institute
NRC U. S. Nuclear Regulatory Commission
NRR [NRC] Nuclear Reactor Regulation
OC Oyster Creek
SER [NRC] Safety Evaluation Report
SSC Systems, Structures, and Components
SDP Significance Determination Process
TE Technical Evaluation
UFSAR Updated Final Safety Analysis Report
URI [NRC] Unresolved Item
UT Ultrasonic Test
VT Visual Testing
WO Work Order