ML042260078
| ML042260078 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 08/12/2004 |
| From: | Blough A Division Reactor Projects I |
| To: | Crane C AmerGen Energy Co |
| Eselgroth P W | |
| References | |
| EA-04-142 IR-04-003 | |
| Download: ML042260078 (45) | |
See also: IR 05000219/2004003
Text
August 12, 2004
Christopher M. Crane
President and Chief Executive Officer
AmerGen Energy Company, LLC
200 Exelon Way, KSA 3-E
Kennett Square, PA 19348
SUBJECT: OYSTER CREEK GENERATING STATION - NRC INSPECTION REPORT
05000219/2004003; PRELIMINARY GREATER THAN GREEN FINDING
Dear Mr. Crane:
On June 30, 2004, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at
your Oyster Creek Generating Station. The enclosed integrated inspection report documents
the inspection findings, which were discussed on July 15, 2004 with Mr. C. N. Swenson and
other members of your staff.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
Based on the results of this inspection, a finding was identified that appears to have a safety
significance that is preliminarily Greater Than Green. Section 4OA4 of the attached report
describes that finding which involves the failure to follow procedures when replacing cooling fan
drive belts of the No. 1 Emergency Diesel Generator (EDG) during a two-year overhaul in
April 2004. This preliminary safety significance was based on a conservative internal and
external initiating events risk analysis of the increase in core damage frequency (CDF) and
large early release frequency (LERF). The Preliminary Greater Than Green characterization
was due to the variability in the outcome of the analysis based on the potential ability of the #1
EDG to perform its safety function for a portion of its mission time.
Before the NRC makes a final decision on this matter, we are providing you an opportunity to
(1) present to the NRC your perspectives on the facts and assumptions, used by the NRC to
arrive at the finding and its significance, at a Regulatory Conference or (2) submit your position
on the finding to the NRC in writing. This will also provide you an opportunity to submit any
additional information concerning the significance of this finding, including the ability of the #1
EDG to perform its safety function, given the high vibrations and the loose cooling fan shaft
bearing bolts. Further, we understand that you may plan to use the results of your July 28,
2004 testing of a diesel generator at an Exelon non-nuclear facility, as a consideration in your
safety significance assessment of this finding at Oyster Creek. If you choose to do so, we
would expect you would include a clearly articulated and effectively supported applicability
Christopher M. Crane 2
analysis of that testing, since the diesel generator tested at the non-nuclear facility was not the
same as the #1 EDG at Oyster Creek.
If you request a Regulatory Conference, it should be held within 30 days of the receipt of this
letter and we encourage you to submit supporting documentation at least one week prior to the
conference in an effort to make the conference more efficient and effective. If a Regulatory
Conference is held, it will be open for public observation. The NRC will also issue a press
release to announce the conference. If you decide to submit only a written response, such a
submittal should be sent to the NRC within 30 days of the receipt of this letter.
Please contact Mr. Peter Eselgroth at (610) 337-5234 within 10 business days of the date of
this letter to notify the NRC of your intentions. If we have not heard from you within 10 days, we
will continue with our significance determination and enforcement decision and you will be
advised by separate correspondence of the results of our deliberations on this matter.
This preliminary Greater Than Green finding also involves an apparent violation of NRC
requirements for failing to follow procedures when replacing the cooling fan drive bolts for the
specific EDG. This violation is being considered for escalated enforcement action in
accordance with the General Statement of Policy and Procedure for NRC Enforcement
Actions (Enforcement Policy), NUREG-1600. The current Enforcement Policy is included on
the NRCs Website at http://www.nrc.gov/what-we-do/regulatory/enforcement.html. No Notice
of Violation is being issued for this inspection finding at this time, because the NRC has not
made a final determination in this matter. In addition, please be advised that the
characterization of the apparent violation described in the enclosed inspection report may
change as a result of further NRC review.
The enclosed report also documents two NRC-identified findings and one self-revealing finding
of very low safety significance (Green). These findings were determined to involve violations of
NRC requirements. However, because of the very low safety significance and because they
were entered into your corrective action program, the NRC is treating these findings as non-
cited violations (NCV) consistent with Section VI.A of the NRC Enforcement Policy.
Additionally, licensee-identified violations which were determined to be of very low safety
significance are listed in this report. If you contest the NCVs in this report, you should provide a
response within 30 days of the date of this inspection report, with the basis for your denial to the
U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C.
20555-0001; with copies to the Regional Administrator Region I; Director, Office of
Enforcement, U. S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the
NRC Inspector at the Oyster Creek Generating Station.
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
Christopher M. Crane 3
Room or from the Publicly Available Records (PARS) component of NRCs document system
(ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-
rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA by Brian E. Holian Acting For/
A. Randolph Blough, Director
Division of Reactor Projects
Docket No. 50-219
License No. DPR-16
Enclosure: Inspection Report 05000219/2004003
w/Attachment: Supplemental Information
cc w/encl:
Chief Operating Officer, AmerGen
Site Vice President, Oyster Creek Nuclear Generating Station, AmerGen
Plant Manager, Oyster Creek Generating Station, AmerGen
Vice President - Licensing and Regulatory Affairs, AmerGen
Manager Licensing - Oyster Creek, AmerGen
J. Fewell, Assistant General Counsel, Exelon Nuclear
Correspondence Control Desk, AmerGen
J. Matthews, Esquire, Morgan, Lewis & Bockius LLP
Mayor of Lacey Township
K. Tosch - Chief, Bureau of Nuclear Engineering, NJ Dept. of Env. Protection
R. Shadis, New England Coalition Staff
N. Cohen, Coordinator - Unplug Salem Campaign
W. Costanzo, Technical Advisor - Jersey Shore Nuclear Watch
E. Zobian, Coordinator - Jersey Shore Anti Nuclear Alliance
Christopher M. Crane 4
Distribution w/encl:
Region I Docket Room (with concurrences)
S. Collins, RA
J. Wiggins, DRA
P. Eselgroth, DRP
R. Barkley, DRP
R. Summers, SRI
C. Miller, OEDO
R. Laufer, NRR
D. Holody, EO, RI
D. Vito, ORA, RI
DOCUMENT NAME: C:\ORPCheckout\FileNET\ML042260078.wpd:
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
2)),& 5,'53 5,'53 5,'56 5,25$ 5,'53
(
1$0( 56XPPHUV5-6 3(VHOJURWK3:( :6FKPLGW:/6 '+RORG\'-+ $%ORXJK%H+IRU
'$7(
2)),&,$/5(&25'&23<
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket No.: 50-219
License No.: DPR-16
Report No.: 05000219/2004003
Licensee: AmerGen Energy Company, LLC (AmerGen)
Facility: Oyster Creek Generating Station
Location: Forked River, New Jersey
Dates: April 1, 2004 - June 30, 2004
Inspectors: Robert Summers, Senior Resident Inspector
Jeff Herrera, Resident Inspector
Aniello L. Della Greca, Senior Reactor Inspector
Suresh Chaudhary, Reactor Inspector
Brice Bickett, Reactor Inspector
Joseph Schoppy, Senior Reactor Inspector
Thomas Hipschman, Reactor Inspector
Steven Dennis, Reactor Inspector
Ronald Nimitz, Senior Health Physicist
Richard Barkley, P.E., Senior Project Engineer
Approved By: Peter W. Eselgroth, Chief
Projects Branch 7
Division of Reactor Projects
i Enclosure
CONTENTS
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iii
REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1R01 Adverse Weather Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1R02 Evaluations of Changes, Tests, or Experiments . . . . . . . . . . . . . . . . . . . . . . . . . 2
1R04 Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1R05 Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
1R06 Flood Protection Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
1R11 Licensed Operator Requalification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1R12 Maintenance Rule Implementation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1R13 Maintenance Risk Assessment and Emergent Work Evaluation . . . . . . . . . . . . 7
1R14 Personnel Performance During Non-routine Plant Evolutions . . . . . . . . . . . . . 8
1R15 Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
1R16 Operator Work-Arounds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
1R17 Permanent Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
1R19 Post Maintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
1R20 Refueling and Outage Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
1R22 Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
1R23 Temporary Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
1EP6 Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
2OS1 Access Control to Radiologically Significant Areas . . . . . . . . . . . . . . . . . . . . . 20
2PS2 Radioactive Material Processing and Transportation . . . . . . . . . . . . . . . . . . . 20
OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
4OA1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
4OA2 Problem Identification and Resolution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
4OA3 Event Follow-up . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
4OA4 Cross-Cutting Aspects of Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
4OA6 Meetings, including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
4OA7 Licensee-Identified Violations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
SUPPLEMENTAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
LIST OF DOCUMENTS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2
LIST OF ACRONYMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-3
ii Enclosure
SUMMARY OF FINDINGS
IR 05000219/2004003; 04/01/04 - 06/30/04; Oyster Creek Generating Station; Personnel
Performance During Non-Routine Plant Evolutions, Operator Work-Arounds, Surveillance
Testing, Event Follow-up.
This report covers a 13-week period of inspection by resident inspectors and announced
inspections by a regional senior health physics inspector, a senior operations engineer, a senior
reactor inspector, a reactor inspector and an emergency preparedness inspector. One
preliminary Greater Than Green finding and apparent violation, and three green findings
involving non-cited violations (NCV), were identified. The significance of most findings is
indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply
may be Green or be assigned a severity level after NRC management review. The NRC's
program for overseeing the safe operation of commercial nuclear power reactors is described in
NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.
A. NRC-Identified and Self-Revealing Findings
Cornerstone: Initiating Events
C Green. The inspectors identified a non-cited violation of the Oyster Creek
Quality Assurance Program for failure to adequately assess and correct plant
equipment that was the subject of operating experience information and prevent
a transient event that resulted in the trip of the D recirculation pump during four
loop full power operations on April 2, 2004.
This finding is greater than minor because it had an actual impact of tripping one
of four operating reactor recirculation pumps, and therefore could be reasonably
viewed as a precursor to a significant event. It increased the likelihood of a plant
scram due to resultant power operation in the buffer zone of the core power to
flow map where there is significantly reduced margin to the flow-biased high
power scram setpoint. It also resulted in operation of the remaining reactor
recirculation pumps at speeds that could result in pump damage without operator
action to reduce the speed and resultant core flow. This condition affects the
Initiating Events Cornerstone objective to limit the likelihood of those events that
upset plant stability and challenge critical safety functions during power
operations. The finding is of very low safety significance because it does not
contribute to: a primary or secondary system LOCA initiator, or both the
likelihood of a reactor trip and the likelihood that mitigation equipment or
functions will not be available, or the likelihood of a fire or internal/external flood.
This finding has a cross-cutting aspect of Problem Identification and Resolution
(PI&R) in that engineering evaluation of External Operating Experience and
corrective action implementation was inadequate to prevent a similar condition at
the site. (Section 1R14)
Cornerstone: Mitigating Systems
iii Enclosure
C TBD. A self-revealing apparent violation, having potential safety significance
greater than very low significance, was identified for failure to implement
appropriate procedural requirements for maintenance on the #1 Emergency
Diesel Generator (EDG) during an overhaul conducted April 26 - 30, 2004.
Technicians failed to follow written procedures to torque the cooling fan shaft
bearing bolts following fan belt replacement as prescribed by Technical
Specification 6.8.1. The poor maintenance practices led to the high vibrations
during surveillance testing and manual shutdown of the #1 EDG on May 17,
2004. The high vibrations increased the potential for a failure of the #1 EDG due
to loss of the skid-mounted cooling system. The final determination of risk
significance is pending potential additional information from AmerGen
concerning the ability of the #1 EDG to perform its safety function, given the high
vibrations and the loose cooling fan shaft bearing bolts.
The finding was more than minor because it affected the mitigation system
cornerstone objective to ensure the availability, reliability, and capability of
systems (emergency AC power) that respond to initiating events to prevent
undesirable consequences and the related attributes of equipment performance,
human performance and procedure quality. The finding was determined to have
a potential safety significance greater than very low significance using a
conservative assumption, based on initial information, that the #1 EDG would
have been unable to perform its safety function for 17 days (April 30 - May 17).
This assumption was made due to the large degree of uncertainty associated
with the ability of the #1 EDG to operate with the high vibrations and loose
cooling fan shaft bearing bolts The Phase 1 screening identified that a Phase 2
analysis was needed because the #1 EDG would have been inoperable in
excess of its Technical Specification Allowed Outage Time of 7 days.
Preliminary Phase 2 and Phase 3 evaluations resulted in a preliminary Greater
Than Green finding, considering the increase in both core damage frequency
and large early release frequency for internally and externally initiated losses of
offsite power. Also, this finding has a cross-cutting aspect of human
performance in that technicians failed to follow written procedures. (Section
4OA4)
C Green. A self-revealing event involving an inadvertent loss of shutdown cooling
resulted in a Green finding and non-cited violation (NCV) for failure to establish
and maintain appropriate procedural requirements for the operation of the
shutdown cooling system, as prescribed by Technical Specification 6.8.1 and the
Oyster Creek Operation Quality Assurance Plan (Quality Assurance Topical
Report) NO-AA-10, Rev. 72.
This finding is greater than minor because the procedural control deficiency
actually led to a loss of the normal shutdown decay heat removal capability and
affected the Mitigating Systems Cornerstone objective to ensure the availability,
reliability, and capability of systems that respond to initiating events to prevent
undesirable consequences. The inspector determined, in accordance with
IMC 0609, Appendix G, Shutdown Operations Significance Determination
Process, that the finding was of very low safety significance because: (1) the
reactor coolant temperature rise was very low and not considered a loss of
iv Enclosure
control event; and, (2) the deficiency did not: increase the likelihood that a loss of
decay heat removal would occur due to failure of the system itself or support
systems, or include decay heat removal instrumentation or vessel level
instrumentation such that degraded core cooling could not be detected, or
increase the likelihood of a loss of Reactor Coolant System (RCS) inventory or
RCS level instrumentation, or involve a design or qualification deficiency; or
result in an actual loss of safety function for risk-significant equipment with
respect to internal or external events. (Section 4OA3)
Cornerstone: Barrier Integrity
C Green. The inspectors identified a Green finding and non-cited violation (NCV)
for the licensees failure to identify a condition adverse to quality in accordance
with 10 CFR Part 50 Appendix B Criterion XVI and Oyster Creek Station
Procedure LS-OC-125, Corrective Action Program Procedure, Rev. 4, when a
secondary containment airlock door was found open, resulting in a momentary
violation of Technical Specification 3.5.B and Procedure 312.10, Secondary
Containment Control, Rev. 8.
This finding is greater than minor because the failure to timely identify the
condition adverse to quality for the airlock door, if left uncorrected, could have
led to a more significant event involving a failure of the airlock interlock. This
condition affects the Reactor Safety Barrier Integrity Cornerstone objective to
provide reasonable assurance that physical design barriers protect the public
from radionuclide releases from accidents or events. Since the finding only
adversely affects the radiological barrier function of the Standby Gas Treatment
System, it was determined to be of very low safety significance. This finding also
has a cross-cutting aspect of PI&R in that operators failed to properly initiate a
Corrective Action Process (CAP) report when the degraded and open airlock
door was discovered. (Section 1R16)
B. Licensee-Identified Violations
Violations of very low safety significance, which were identified by the licensee have
been reviewed by the inspectors. Corrective actions taken or planned by the licensee
have been entered into the licensees corrective action program. One licensee-identified
violation and associated corrective actions are listed in Section 4OA7 of this report.
v Enclosure
REPORT DETAILS
Summary of Plant Status
Oyster Creek began the integrated inspection period at 100% of Rated Thermal Power (RTP).
On April 1, 2004, power was reduced to 50% RTP to repair the D reactor recirculation pump
controls. On April 2, 2004, power was further reduced to 35% RTP to conduct a full closure test
of the MSIVs due to a partial closure test failure. On April 4, 2004, Oyster Creek returned to
100% RTP. On May 26, 2004, a planned shut down was commenced to begin a mid-cycle
maintenance outage to replace the A reactor recirculation pump motor. On May 27, 2004, a
reactor scram occurred from about 2% RTP due to spiking events on several IRM detectors.
Following completion of planned repairs to the reactor recirculation system and other off-line
activities, reactor start-up commenced on June 1. Oyster Creek returned to 100% RTP on
June 3, 2004, and remained at 100% for the remainder of the inspection period, except for
minor power reductions for testing.
1. REACTOR SAFETY
Cornerstones: Initiating Events/Mitigating Systems/Barrier Integrity
1R01 Adverse Weather Protection (IP 71111.01 - 1 Sample)
a. Inspection Scope
The inspectors reviewed Oyster Creeks seasonal readiness preparations to verify that
safety-related equipment would remain functional when challenged by summer weather
conditions. The inspectors reviewed the licensees seasonal readiness procedure (OP-
AA-108-109, Seasonal Readiness, Revision 1), seasonal check lists, and performed
walk downs to verify that the safety-related equipment would remain functional during
adverse weather conditions. The inspectors evaluated the condition of the Emergency
Service Water System, Service Water System, Recirculation Motor-Generator Set
Coolers, Circulating Water System, Electrical Switchyard, and Emergency Diesel
Generators prior to the onset of summer weather conditions.
The inspectors also reviewed a sample of deficiencies associated with AmerGens
summer readiness action item list to verify that problems were entered into the
corrective action program and appropriately addressed for resolution in a timely manner.
b. Findings
No findings of significance were identified.
Enclosure
2
1R02 Evaluations of Changes, Tests, or Experiments (IP 71111.02 - 21 Samples)
a. Inspection Scope
The inspectors reviewed six safety evaluations (SE) that were completed during the past
three years. The SEs reviewed were distributed among initiating event, mitigating
system, and barrier integrity cornerstones. These SEs were reviewed to verify that
changes to the facility or procedures as described in the Updated Final Safety Analysis
Reports (UFSAR) and changes to tests not described in the UFSAR were reviewed and
documented in accordance with 10 CFR 50.59, and that the safety issues pertinent to
the changes were properly resolved or adequately addressed. The reviews also
included the verification that the licensee had appropriately concluded that the changes
and tests could be accomplished without obtaining license amendments.
The following six safety evaluations were reviewed:
OC-2001-E-0007 UFSAR 3.5.1.3
OC-2001-E-0011 Addition of Maintenance Isolation Valves in a control rod drive
(CRD) Hydraulic Drive and Cooling Water Line, Rev. 1
OC-2002-E-0001 1MNCR O2001-1839 Disposition/Operability Assessment, Rev. 0
OC-2002-E-0003 Oyster Creek Increased Core Flow Implementation, Rev. 0
OC-2002-E-0004 Evaluation of 6 Hour Service Water Outage During 1R19, Rev. 1
OC-2002-E-0005 Procedure to Flush Core Spray and Flood Reactor Cavity
The inspectors also reviewed 15 screen-out evaluations for changes, tests and
experiments for which AmerGen determined that safety evaluations were not required.
This review was performed to verify that the licensees threshold for performing safety
evaluations was consistent with 10 CFR 50.59. The listing of screened-out evaluations
reviewed is provided in the Attachment.
In addition, the inspectors reviewed the administrative procedures that were used to
control the screening, preparation, and issuance of the safety evaluations to ensure that
the procedure adequately covered the requirements of 10 CFR 50.59. In conjunction
with this review, the inspectors also reviewed selected applicability review forms related
to plant changes (primarily procedure changes) for which the requirements of
10 CFR 50.59 did not apply.
b. Findings
No findings of significance were identified.
Enclosure
3
1R04 Equipment Alignment (IP 71111.04)
a. Inspection Scope
Partial System Walkdown. (71111.04Q - 2 Samples)
The inspectors performed two partial system walkdowns during this inspection period.
On April 30, 2004, the inspectors walked down the #2 EDG during the system outage on
the #1 EDG. On June 7, 2004, the inspectors walked down the #2 Core Spray (CS)
system during in-service testing of the #1 CS system. The inspectors verified that the
associated maintenance activities did not adversely affect redundant components. To
evaluate the operability of the selected train or system when the redundant train or
system was inoperable or out of service, the inspectors checked for correct valve and
power alignments by comparing positions of valves, switches, and electrical power
breakers to the system operating procedures, as well as applicable chapters of the
Complete System Walkdown. (71111.04S - 2 Samples)
This inspection activity represented two samples.
On June 10, 2004 the inspectors completed a detailed review of the alignment and
condition of the Isolation Condenser (IC) system. The inspector used AmerGens
procedures and other documents listed below to verify proper system alignment:
C Drawing No. GE 148F262, Emergency Condenser Flow Diagram," Rev. 51
C Procedure 307, Isolation Condenser system, Rev. 84
C Drawing No. 1083-131-19. Rev. B, Isolation Condenser Replacement Drywell
Penetration Piping and Isolation Valves
C Drawing No. 1083-131-19. Rev. A, Isolation Condenser Replacement 10 Inch
Penetration Pipe & Flued Collar Weldment
C General Arrangement Drawing No. 3E-153-02-005, Reactor Building Plan Floor
Elevation 95' -3", Rev. 7
C Drawing No. EI705, Appendix R Safe Shutdown Circuit Routing Reactor
Building El. 23' -6", Rev. 0
C Drawing No. EI707, Appendix R Safe Shutdown Circuit Routing Reactor
Building El. 75' -3", Rev. 0
The inspectors also verified electrical power requirements, labeling, hangers, support
installation, and associated support system status. The walkdowns also included
evaluation of system supporting structures against the following considerations:
C Piping and structural supports showed no visible signs of degradation or
leakage;
C Cabling and conduits showed no visible signs of degradation;
C Component foundations were not degraded;
C Valves showed no visible signs of degradation; and
Enclosure
4
C All deficiencies properly identified and dispositioned.
On June 16, 2004, the inspector conducted a detailed review of the alignment and
condition of the #1 Emergency Service Water (ESW) system. The inspectors used the
licensee procedures and other documents listed below to verify proper system
alignment:
C Drawing No. BR-2005, Emergency Service Water Flow Diagram
C Procedure 322, Service Water System, Rev. 58
C Procedure 310, Containment Spray System Operation, Rev. 82
The inspectors also verified electrical power requirements, labeling, hangers and
support installation, and associated support system status. The walkdowns also
included evaluation of system supporting structures against the following considerations:
C Piping and structural supports showed no visible signs of degradation or
leakage;
C Observed pump shaft packing lubricating water performed desired function;
C Observed interface with containment spray heat exchangers and that flow was
adequate and expected for current configuration;
C Component foundations were not degraded; and
C Flow and pressure in system was indicating properly.
b. Findings
No findings of significance were identified.
1R05 Fire Protection (IP 71111.05Q - 9 Samples)
a. Inspection Scope
The inspectors walked down accessible portions of the nine fire zones listed below due
to their potential to impact mitigating systems. Plant walkdowns included observations
of combustible material control, fire detection and suppression equipment availability,
and compensatory measures. As a part of the inspection, the inspectors had
discussions with fire protection personnel, and reviewed procedure 333, Plant Fire
Protection System, and the Oyster Creek Fire Hazards Analysis Report to verify that
the fire program was implemented in accordance with all conditions stated in the facility
license.
C TB-FZ-11F, Feedwater pumps, Elevs. 0'-6" and 3'-6"
C RB-FZ-1D, 51' Elevation
C RB-FZ-1C, 75' Elevation
C RB-FZ-1B, 95' Elevation
C FW-FA-18, Fire water pump house
C RB-FZ-1F4, NE Corner Room -19' Elevation
C OB-FZ-6A&6B, 480V switchgear rooms
Enclosure
5
C OB-FZ-4, Cable Spread Room, 36 Elevation
C OB-FZ-22A, New Cable Spread Room (Mechanical equipment Room)
Elev. 74-6"
b. Findings
No findings of significance were identified.
1R06 Flood Protection Measures (IP 71111.06 - 2 Samples)
1. External
a. Inspection Scope
The inspectors reviewed the Oyster Creek Individual Plant Examination of External
Events, Section 5.2, External Floods, TS and the UFSAR, Section 2.4.2 concerning
flood design considerations. The inspectors reviewed the procedure for Response to
Abnormal Intake Level, 2000-ABN-3200.32, Rev. 19 and a walkdown of the following
outside buildings was performed:
C Fire Diesel Pump Room
C Emergency Diesel Generator Rooms
C Intake Structure
C Standby Gas Treatment and Off-Gas Building Area
b. Findings
No findings of significance were identified.
2. Internal
a. Inspection Scope
The inspector verified that operator actions to mitigate flooding described in section
10.7. of the Oyster Creek Internal Flooding Analysis, dated November 1991, were
appropriately addressed in abnormal and emergency procedures. A walkdown of the
northeast corner room, which contains the #1 Containment Spray/Emergency Service
Water (CS/ESW) system pumps and heat exchangers, was also performed.
b. Findings
No findings of significance were identified.
Enclosure
6
1R11 Licensed Operator Requalification (IP 71111.11Q - 1 Sample)
a. Inspection Scope
This inspection activity represented one inspection sample. This inspection assessed
the LORT provided to the SROs and the ROs and the evaluation conducted on the
simulator on June 3, 2004. The inspectors assessed the proficiency of the operating
crew and verified that the evaluations of the crew identified and addressed operator
performance issues. The inspection activities were performed using NUREG-1021,
Rev. 8, Operator Licensing Examination Standards for Power Reactors, and Inspection
Procedure Attachment 71111.11, Licensed Operator Requalification Program.
The training included three scenarios and about four hours of testing/evaluation. The
inspectors assessed the simulator crews performance during each scenario. The
inspectors also assessed the evaluators assessment of the crew, to verify that operator
performance issues were identified and appropriate remediation was conducted to
address identified weaknesses. The following out-of-box simulation tests were
observed:
C SC-1D, RCS Flow Instrument Failure; Unisolable LOCA Outside Containment
C PC-5C, Electro-Magnetic Relief Valve Instrument Failure; RCS Leak; ATWS
C RPV-6D, Loss of CRD; ATWS; Loss of PCS
b. Findings
No findings of significance were identified.
1R12 Maintenance Rule Implementation (IP 71111.12Q - 3 Samples)
a. Inspection Scope
The inspectors selected three samples for review. The inspectors reviewed AmerGens
implementation of the maintenance rule as described in Oyster Creek procedure ER-
AA-310, Implementation of the Maintenance Rule. The inspectors verified that the
selected Systems, Structures and/or Components (SSCs) were properly classified as
(a)(1) or (a)(2) in accordance with 10 CFR 50.65. The inspectors reviewed Action
Requests (ARs), Corrective Action Program reports (CAPs), (a)(1) corrective action
plans and routine preventive maintenance activities. The inspectors also discussed the
current system performance, associated issues and concerns, and planned activities to
improve performance with the system engineers. In addition, unavailability data was
compared with control room log entries to verify accuracy of data and compliance with
(a)(1) goals. AmerGen trending data was also reviewed. The three SSCs reviewed
during the inspection period were as follows:
C Isolation Condenser system
C 125 VDC system
C Emergency Service Water system
Enclosure
7
The inspectors also reviewed the following documents:
C ER-AA-310-1003, Maintenance Rule - Performance Criteria Selection, Rev. 2
C ER-AA-310-1004, Maintenance Rule - Performance Monitoring, Rev. 1
C ER-AA-310, Implementation of the Maintenance Rule, Rev. 2
C OC-7 Functional Failure Definition for System 211 (Isolation Condenser system)
C Emergency Isolation Condenser System Health Report, 1st quarter 2004
C Topical Report 140, Rev. 0, Emergency Service Water and Service Water
System Piping Plan
C 125 VDC Maintenance Rule Performance Assessment - dated December 12,
2003
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessment and Emergent Work Evaluation (IP 71111.13 - 4
Samples)
a. Inspection Scope
The inspectors evaluated four on-line risk work activities and verified that the licensee
evaluated the risk associated with the inoperability of the system along with other
ongoing maintenance work. In addition, the inspectors reviewed work schedules, recent
corrective action documents, troubleshooting plans, repair and retest results, and control
room logs to verify that other concurrent planned and emergent maintenance or
surveillance activities did not adversely affect the plant risk already incurred with the out
of service components. The inspectors assessed AmerGens risk management actions
during shift turnover meetings, control room tours, and plant walkdowns. The inspectors
also used AmerGens on-line risk monitor to evaluate the risk associated with the plant
configuration and to assess AmerGens risk management. When appropriate, the
inspectors verified compliance with Technical Specifications (TS). The following
activities were reviewed:
C Heavy load lift risk during the planned maintenance on the #1 EDG during the
week of April 26, 2004
C #2 EDG protection during the planned maintenance on the #1 EDG during the
week of April 26, 2004
C The concurrent planned outage of the #2 EDG, the #1-1 turbine building closed
cooling water heat exchanger, and #1 combustion turbine on May 11, 2004
C Main Generator in manual voltage control due to the Amplidyne being removed
from service because of improper generator voltage regulation on June 10,
2004.
Enclosure
8
b. Findings
No findings of significance were identified.
1R14 Personnel Performance During Non-routine Plant Evolutions (IP 71111.14 - 2 samples)
a. Inspection Scope
For the two sampled non-routine events described below, the inspectors reviewed
operator logs and plant computer data to determine what occurred and how the
operators responded, and to determine if the response was in accordance with plant
procedures:
C On April 1, 2004, the inspectors observed the operator response to the D
Recirculation pump trip event. Operator actions consisted of reducing power to
approximately 55% and allowing the plant to stabilize under those conditions. An
investigation to the D Recirculation pump trip revealed that the 1-watt 4R
resistor on the Motor-Generator voltage regulator card failed due to temperature
effects from the power dissipation exceeding 1 watt. While at reduced power,
AmerGen replaced the failed resistor in the D Recirculation Motor-Generator
(MG) Set voltage regulator card in addition to replacing the other 4R resistors in
the remaining recirculation loops. The A 4R resistor was not replaced because
this pump was not in service and investigation of the A 4R resistor did not show
signs of degradation. (Subsequently, the 4R resistor in the A recirculation loop
MG set was replaced during the maintenance outage that began in
May 27, 2004, with the upgraded 2-watt design in order to prevent future failures
of the 4R resistor.)
C On May 27, 2004, the reactor scrammed during a plant shutdown. The Reactor
Protection System (RPS) responded to spiking on intermediate range monitor
channels 13 and 14 on RPS system 1 and channel 18 on RPS system 2,
resulting in a plant scram. Due to the plant being at approximately two percent
power, there was minimal impact on the plant from this scram. AmerGen formed
a team to determine the specific problem that was causing excessive noise on
the system, which resulted in the scram. This issue was documented in CAP
report O2004-1314. An Unresolved Item (URI) was identified for the multiple
channel spiking events affecting the intermediate range monitoring system
during the plant shutdown on May 27, 2004. This item will remain unresolved
pending the review of the licensees root cause analysis to determine if prior
corrective actions for the IRM spiking problems were ineffective. (URI
0500219/200400302)
b. Findings
Introduction. A Green NCV was identified for failure to implement the Oyster Creek
Operational Quality Assurance Plan (QA Topical Report, NO-AA-10, Rev. 72) to support
Enclosure
9
the activity requirement to assess operating experience information that involved the
recirculation pump Motor-Generator (MG) set voltage regulator card. This condition led
to a subsequent failure of the D MG set voltage regulator card and a trip of the
associated recirculation pump during four loop, full power operation on April 1, 2004.
Description. At 11:45 p.m. on April 1, 2004, the main control room received both a drive
motor lockout and drive motor breaker trip alarm and the subsequent trip of the D
Recirculation pump. Local investigation revealed no apparent cause for the breaker trip
in either the MG set room or the 4160V room. Power was reduced using recirculation
flow and control rods in accordance with abnormal operating procedures. Operators
inserted 16 CRAM array control rods to maintain power in the proper region of the
power-to-flow map. Reactor power was stabilized at approximately 52% power.
The licensees prompt investigation revealed that within the D MG set voltage regulator
control box, a burning smell was noticed and circuit card 1CB exhibited a discoloration
around the area of the 4R resistor. The resistor was blackened, showing signs of
surface cracking and the resistor color bands could not be read due to discoloration.
When an extent of condition walk down was performed, the other voltage regulator
boxes were inspected, and except for the A MG set, the remainder showed similar
signs. At the time of the event, the station had been running at 100% power, in a four
loop operating mode since August 29, 2003. This was a result of the A Recirculation
pump tripping on that date due to a suspected ground within the drywell.
Further document investigation indicated that in 1996 work orders were initiated to
refurbish all 5 voltage regulators and replace the field overload relays with a new style.
As part of this refurbishment, the system manager indicated a need to procure new
1CB, Mag Amp boards with two watt, 4R resistors, based on a review of a GE SIL that
was issued to all GE designed BWR 3/4s. The SIL directly calls out the marginal sizing
of the 4R resistor when recirculation speeds are increased beyond normal levels. The
licensees review of the work order documentation indicated that the system manager
believed that the cards purchased for the refurbishment had already been modified with
the two watt resistors by GE. This action was never completed and the 1CB Mag Amp
boards were installed on all five MG set voltage regulator cards with the original design,
one watt resistors. In addition, the licensees review of the procurement history
indicated that ten additional resistors were purchased for the specified work order, but
never installed on the circuit boards. The licensees field inspection of the purchased
resistors indicated that the purchased resistors were one watt and not two watt resistors
as specified in the procurement documentation.
The GE SIL identified that these 4R resistors, having a tolerance of only +/-5%, could fail
at higher generator speeds due to excessive temperature. That failure of this resistor
will cause the generator voltage to become unstable, and a subsequent MG set trip is
likely. The normal speed of the recirculation pumps is around 47 Hz, which requires the
4R resistor to dissipate 0.98 watts. During routine recirculation pump maintenance, a
higher speed demand would be required of the four remaining pumps. The four
remaining pumps operate between the speeds of 50 and 53 Hz when the plant is at
100% power in four loop operation. Calculations have indicated that when the MG set is
Enclosure
10
running at 50 Hz, the circuit is required to dissipate 1.1, watts and at speeds nearing 54
Hz, the circuit dissipates to 1.272 watts. On average, an MG set circuit would be
required to dissipate more than one watt approximately 25 days per year based on the
average time the plant is operated with only four MG sets. At the time of the failure,
Oyster Creek had been operating in four loop configuration for about 7 months.
Analysis. AmerGen failed to replace the voltage regulator 4R resistors with two watt
resistors as recommended by industry information and their engineering staff. This is a
performance deficiency in that the assessment activity of the operating experience
information provided by GE, required by Oyster Creek Quality Assurance Topical
Report, NO-AA-10, Rev. 72, Appendix F, failed to identify that the recirculation pump
MG sets could be continuously operated at a speed that could damage the voltage
regulator cards and cause a plant transient. Traditional enforcement does not apply for
this finding because it did not have any actual safety consequences or the potential for
impacting the NRCs regulatory function and was not the result of any willful violation of
NRC requirements.
This finding is greater than minor because it had an actual impact of tripping one of four
operating reactor recirculation pumps, and therefore could be reasonably viewed as a
precursor to a significant event. It increased the likelihood of a plant scram due to
resultant power operation in the buffer zone of the core power to flow map where there
is significantly reduced margin to the flow-biased high power scram setpoint. It also
resulted in operation of the remaining reactor recirculation pumps at speeds that could
result in pump damage without operator action to reduce the speed and resultant core
flow.
This condition affects the Initiating Events Cornerstone objective to limit the likelihood of
those events that upset plant stability and challenge critical safety functions during
power operations. The finding was determined to be of very low safety significance
(Green) using a Phase 1 analysis of the NRC Significance Determination Process (SDP)
for Reactor Inspection Findings for At-Power Situations, in that, it does not contribute to:
a primary or secondary system LOCA initiator, or both the likelihood of a reactor trip and
the likelihood that mitigation equipment or functions will not be available, or the
likelihood of a fire or internal/external flood. This finding has a cross-cutting aspect of
PI&R in that the engineering evaluation of External Operating Experience and resultant
corrective action implementation was inadequate to prevent a similar condition at the
site.
Enforcement. Oyster Creek Quality Assurance Topical Report (QATR), NO-AA-10, Rev.
72, Appendix F states that operating experience assessment is an activity within the
scope of the QATR. Contrary to these requirements AmerGen failed to properly
evaluate the recommendations to replace the 4R resistors in the MG set voltage
regulator reference board as stated in the GE SIL 586 Rev. 1. The AmerGen
assessment failed to evaluate the significance of continuously operating in a four loop
configuration that resulted in the 'D' recirculation pump trip transient on April 1, 2004.
This was entered into the AmerGen corrective action program under CAPs O2004-0785
Enclosure
11
and O2004-0821. This violation is being treated as a non-cited violation consistent with
Section VI.A of the NRC Enforcement Policy. (NCV 0500219/200400301)
1R15 Operability Evaluations (IP 71111.15 - 4 Samples)
a. Inspection Scope
The inspectors reviewed operability evaluations in order to verify that they were
performed as required by Oyster Creek procedure LS-AA-105, Operability
Determinations. The inspector assessed the accuracy of the evaluations, the use and
control of compensatory measures if needed, and appropriate action if a component
was determined to be inoperable. The inspectors verified that the technical specification
limiting conditions for operation were properly addressed. The four selected samples are
listed below:
C Main Steam Isolation Valve (MSIV) failure to pass 10% closure surveillance - On
April 3, 2004 during the performance of the MSIV 10% closure test, NSO3A &
NSO4A failed to respond as expected. The MSIVs were then declared
inoperable and subsequently tested using the full closure test. The full closure
test demonstrated the operability of the MSIVs. Engineering was directed to
evaluate the status of the 10% closure circuit and its effect on the MSIVs. This
issue was documented in CAP 2004-0795.
C #1 EDG #12 cylinder contamination - During the #1 EDG system outage, the #12
cylinder was observed to have signs of lube oil contamination. The system
engineer and the GE technical representative examined this issue and had
determined that the contamination had no effect on the performance of the #12
cylinder. The licensee and NRC inspectors examined the cylinder on April 28,
2004. The liner wall was visible through the air inlet ports; the exam revealed no
visible significant wear. The cross-hatching was clearly visible with ample oil
film. The results of chemical analysis of the film indicated a minute jacket water
leak which was determined to not affect operability. The licensee established a
monitoring plan to periodically sample, test, and trend the lube oil to determine if
the leakage increases. In addition, the licensee has scheduled an examination
of the #12 cylinder at the next EDG maintenance work window to reassess the
observed conditions. This issue was documented in CAP O2004-1032.
C E EMRV 125V DC ground - A soft electrical ground began to appear on the B
125 VDC negative circuit in January 2004; over time, the ground faded. On May
17, 2004, the ground indication suddenly changed from about 2 to 20 milliamps.
Troubleshooting narrowed the ground to a circuit associated with the E Electro
Magnetic Relief Valve (EMRV). The ground condition was determined to cause
the E EMRV to be degraded but operable. During the 1FO6 maintenance
outage 1000 psig drywell inspection, the E EMRV pilot valve was noted as
having a plume of steam from the exhaust port that was impinging on the Patel
connector for the solenoid operator. Both the C and E EMRVs had no steam
deflection elbow installed on the exhaust port as is the case for the A, B, and
Enclosure
12
D valves. Both the C and E valves were replaced and steam deflecting
elbows were installed on their exhaust ports. This issue was documented in
CAPs O2004-0159, O2004-0311, and O2004-1189. The operability evaluation
was documented in Oyster Creek Op Evaluation # OC-2004-OE-0002.
C ESW pipe leak - On May 12, 2004, while running ESW pump 52B, a leak was
observed from the weld on the ESW outlet from the 1-2 Containment Spray Heat
Exchanger. The engineering operability evaluation determined that a crack had
propagated through the toe of the weld between the reinforcement plate at the
ESW outlet nozzle and the pipe piece to the flange face. The apparent cause
was determined to be weld fatigue. Based on Technical Evaluation A2088856
E02, the subject nozzle would have maintained structural integrity with the
degraded condition, using the techniques of Code Case N-513. However, due to
the configuration, volumetric examinations were not successful in characterizing
the flaw. As a result, the seven day limiting condition for operation was entered
and the crack repaired within the allowed outage time. This evaluation was
documented in CAP O2004-1153.
b. Findings
No findings of significance were identified.
1R16 Operator Work-Arounds (IP 71111.16 - 1 Sample)
a. Inspection Scope
The inspectors reviewed the operator work-around database and a sample of the
associated corrective action items to identify conditions that could adversely affect the
operability of mitigating systems or impact operators in responding to initiating events.
The inspectors reviewed the licensees implementation of procedure OP-AA-102-103,
Operator Work-Around Program. The inspectors observed physical conditions of
equipment in the plant during routine tours to identify conditions that may challenge
operator actions in use of mitigating systems. The inspectors also reviewed the status
of the corrective actions described in CAP Nos. O2003-2320 and O2004-1157 which
identified specific problem resolutions relating to the reactor building airlock doors.
b. Findings
Operator Failure to Recognize Degraded Secondary Containment Airlock
Introduction. The inspector identified a Green finding and an NCV for failure to identify
a condition adverse to quality when a secondary containment airlock door was found
open resulting in a momentary violation of Technical Specification 3.5.B and Procedure
312.1, Secondary Containment Control, Rev. 8.
Description. On May 4, 2004, while on a tour of the Reactor Building Equipment Drain
Tank (RBEDT) room, the inspector and an accompanying radiation protection technician
Enclosure
13
discovered the secondary containment outer airlock door interlock unexpectedly
activated, preventing entry. The control room was notified and approval was given for
the technician to bypass the interlock to open the outer door. However, upon entry, the
technician found the inner door open. One door was immediately closed restoring the
secondary containment to a fully operable condition. The technician informed the
control room of the observed conditions. The inspector and technician completed the
tour of the RBEDT room and exited the area. Upon exit, the inner door was verified
closed. On May 5, 2004 the inspector returned to the RBEDT room outer door and
discovered the airlock door interlock again to be activated. This condition was reported
to the control room and the inner door was again found open.
At the time of this event, the reactor was at about 100% power, the drywell was locked
closed and inerted, no other degraded conditions were affecting primary or secondary
containment, and fuel handling operations were in progress in support of the CY 2004
ISFSI campaign.
Technical Specification 3.5.B.1 specifies that the secondary containment integrity be
maintained at all times when the reactor is not subcritical or when operations are being
performed in, above or around the spent fuel storage pool, that could preliminary cause
a release of radioactive materials during an event. Technical Specification 3.5.B.2
states that upon accidental loss of secondary containment integrity, restore integrity
within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. As noted above, the technician immediately closed one of the two doors
restoring secondary containment integrity as required by the technical specifications.
The secondary containment system includes the reactor building envelope, associated
dampers and valves, the airlock doors, and the Standby Gas Treatment System
(SGTS). The design of the secondary containment is to remain in a negative pressure
condition for all analyzed accidents for both power operation conditions and fuel
handling conditions. The airlock doors enable the SGTS to maintain a negative
pressure in the reactor building. Procedure 312.10, Secondary Containment Control,
specifies:
Operate Reactor Building Airlock doors as follows:
C Maintain at least one door at each opening to the reactor building closed
at all times.
C If at any time both doors at an opening to the reactor building are
unintentionally opened at the same time, then close at least one door and
report the incident to the shift supervisor to initiate repair to the airlock
interlock.
On May 13, 2004, subsequent to the inspector identifying this concern, CAP O2004-
1157 documented the failure to maintain secondary containment integrity for a short
time while both airlock doors were open (for the May 4 entry). This CAP also
documented the failure to note the condition in the operating logs and failure to
document the condition in a CAP when initially identified on May 4, 2004. Oyster Creek
Enclosure
14
procedure OP-OC-100, Conduct of Operations, requires, in part, that if it is discovered
that a technical specification limiting condition for operation could be exceeded, then the
Operations' Supervisor shall ensure specified actions are taken, including issuance of a
CAP in accordance with procedure LS-OC-125. Procedure LS-OC-125, Corrective
Action Program Process, Rev. 3, requires that a CAP be initiated for conditions adverse
to quality, including unplanned entries for technical specification actions for limiting
conditions for operation.
Subsequent review of the CAP and maintenance databases revealed that this door has
had several documented failures of the inner door automatic closure device since
CY2000. Several days after the inspectors identified the concern with the airlock door,
the FIN team investigated the door and determined that, in addition to the previously
identified condition of the door closing device, the door latching device was sticking,
resulting in the door latch not fully closing.
While the licensees CAP review identified that technical specification requirements were
met since at least one door was immediately closed, the review revealed that operations'
personnel did not demonstrate the appropriate sensitivity to secondary containment
control governed by procedure. Appropriate measures were not taken when personnel
trying to get in through the outer airlock door were told to override secondary
containment in order to open the door, nor was an appropriate log entry or CAP initiated
when it was known that both airlock doors were open at the same time.
The latch was repaired by the FIN team. The degraded door closing device is
scheduled to be repaired when parts are available. An Operator Challenge has been
created to track resolution of the airlock door degraded conditions. In addition, each
operating crew was briefed on the importance of maintaining secondary containment
integrity and the need to make appropriate log entries when challenges to containment
integrity are identified.
Analysis. The failure to document in the control room logs and in a CAP report that the
inner airlock door for the RBEDT room was found open on May 4, 2004, was a violation
of station procedures. Accurate record keeping is needed to identify degraded
conditions and effect corrective actions in a timely manner. This is a performance
deficiency. Traditional enforcement does not apply because the issue did not have any
actual safety consequences or potential for impacting the NRC regulatory function, and
was not the result of any willful violation of NRC requirements or AmerGen procedures.
This finding is greater than minor because the failure to timely identify the condition
adverse to quality for the airlock door, if left uncorrected, could have led to a more
significant event involving a failure of the airlock interlock. This condition affects the
Reactor Safety Barrier Integrity Cornerstone objective to provide reasonable assurance
that physical design barriers protect the public from radionuclide releases from
accidents or events. Also, this finding has a cross-cutting aspect of PI&R in that
operators failed to properly initiate a Corrective Action Process (CAP) report when the
degraded and open airlock door was discovered.
Enclosure
15
The airlock doors function to ensure secondary containment integrity and to support the
SGTS capability to maintain a negative pressure in the reactor building and minimize
ground level releases of radioactive materials. This issue was evaluated using IMC 0609 Appendix A, Significance Determination Process for At-Power Situations. Since
the finding only adversely affected the radiological barrier function associated with the
SGTS function, it was determined to be of very low safety significance (Green).
Enforcement. 10 CFR Part 50 Appendix B Criterion XVI, station procedures, LS-OC-
125, Corrective Action Program Procedure, and general operating procedures, OP-
OC-100, Oyster Creek Conduct of Operations, and OP-AA-111-101, Operating
Narrative Logs and Records, require timely identification and resolution of conditions
that adversely affect the performance of safety-related equipment. Contrary to these
requirements, a CAP report was not initiated for a condition adverse to quality that was
identified on the RBEDT room inner airlock door when the door latching device failed
open, causing a momentary loss of secondary containment integrity on May 4, 2004.
Operators failed to make a control room log entry to track the associated technical
specification required actions for the event. Because this condition is of very low
significance and has been entered into AmerGens corrective action program (CAP
O2004-1157), this violation is being treated as an NCV consistent with Section VI.A of
the NRC Enforcement Policy, issued May 1, 2000 (65FR25368).
(NCV 05000219/200400303)
1R17 Permanent Plant Modifications (IP 71111.17B - 10 Samples)
a. Inspection Scope
The inspectors reviewed ten risk-significant plant modification packages selected from
among the design changes that were completed within the past two years. The review
was to verify that: (1) the design bases, licensing bases, and performance capability of
risk significant structures, systems or components had not been degraded through
modifications; and, (2) modifications performed during increased risk configurations did
not place the plant in an unsafe condition.
The selected plant modifications were distributed among initiating event, mitigating
systems, and barrier integrity cornerstones. For these selected modifications, the
inspectors reviewed the design inputs, assumptions, and design calculations to
determine the design adequacy. The inspectors also reviewed field change notices that
were issued during the installation to confirm that the problems associated with the
installation were adequately resolved. In addition, the inspectors reviewed the post-
modification testing, functional testing, and instrument and relay calibration records to
determine readiness for operations. Finally, the inspectors reviewed the affected
procedures, drawings, design basis documents, and UFSAR sections to verify that the
affected documents were appropriately updated. For accessible components, the
inspectors also performed field observation of installed equipment to detect possible
abnormal installation conditions.
The following modifications were reviewed:
Enclosure
16
C ECR OC-01-00621, Crosstie ESW to Service Water to Allow Repairs
C ECR OC-01-00627, Replace Degraded Voltage Relay Timers
C ECR OC-01-00628, 480V Circuit Breaker Undervoltage Device Replacement
C ECR OC-02-00487, Replace Degraded Instrument Air Drying Towers C/D
C ECR OC-02-01441, Oyster Creek Drywell Vessel Corrosion Assessment
C ECR OC-03-00028, H430 - Modify SPF Cooling Discharge Lines with Anti-
Syphon Holes
C ECR OC-03-00088, J064 - A & B CRD Pump Breaker Modification, Rev. 3
C ECR OC-03-00364, Release Revision 1 of Calculation C-1302-810-5450-004
C ECR OC-03-00731, EDG Fuel Oil Priming Pump Addition for EDG2 CAP 02003-
1735
C ECR OC-03-00169, Revision of DC MOV Voltage Drop Calculation, C-1302-
730-5350-008, R4, Rev 0
b. Findings
No findings of significance were identified.
1R19 Post Maintenance Testing (IP 71111.19 - 5 Samples)
a. Inspection Scope
Five samples were selected for review by the inspectors. The inspectors reviewed and
observed portions of post maintenance testing associated with the below-listed five
maintenance activities because of their function as mitigating systems and their potential
role in increasing plant transient frequency. The inspectors reviewed the post
maintenance test documents to verify that they were in accordance with AmerGens
procedures and that the equipment was restored to an operable state. The following
activities were selected for review:
C D Recirculation pump MG set voltage regulator card 4R resistor - Post
maintenance testing was performed per work order C2007667 on April 5, 2004,
following failure of the D Recirculation pump MG set voltage regulator card 4R
resistor.
C #1 EDG cooling fan - Post maintenance testing was performed per work order
C2008008-04 and procedure 636.4.003, Diesel Generator #1 Load Test on
May 17, 2004, following failure of the EDG cooling fan shaft bolting.
C MSIV, NSO3A - Post maintenance testing was performed on June 1, 2004, per
work order C2007828 and procedure 602.4.004 (10% partial closure test)
following troubleshooting activities during 1FO6 as a result of a prior test failure
in April 2004 (CAP O2004-0795). The valve again failed the partial closure test.
The valve was immediately inspected by maintenance and engineering who
recommended lubricating the guide rods and adjusting the air exhaust port to
allow air to vent faster.
Enclosure
17
C MSIV, NSO3A - Post maintenance testing involving full-closure testing was
conducted on June 2, 2004, per work order A2086259 Eval 02 and procedure
602.4.005, following maintenance to lubricate and adjust the air venting
capability of the valve operator due to failing the 10% closure test on June 1.
C ESW piping tie in - Surveillance 607.4.016 and 607.4.017, Containment Spray
and Emergency Service Water System Operability and Quarterly In-Service
Test was performed after ESW piping tie into complete modification changes to
ESW piping during the week of May 30, 2004.
b. Findings
No findings of significance were identified.
1R20 Refueling and Outage Activities (IP 71111.20 - 1 Sample)
1FO6: Maintenance Outage to Replace the A Reactor Recirculating Water Pump
Motor
a. Inspection Scope
The inspectors observed outage maintenance activities for the 1FO6 maintenance
outage and verified those activities were performed in accordance with plant
procedures. In addition, during the outage, the inspectors reviewed the daily outage risk
assessments and verified the equipment alignments used to support the assessments.
The inspectors also monitored the availability of the decay heat removal system due to a
high decay heat condition throughout the maintenance outage. The inspectors
observed portions of the shutdown and cooldown on May 26 and 27, 2004. During the
reactor startup, the inspectors physically observed portions of the primary containment
(drywell) with plant operators to verify part of the RCS 1000 psig visual leakage
inspection. During the plant startup, which began on May 27, 2003, the inspectors
observed and verified adherence to procedure No. 201, Plant Startup. The inspectors
continued to observe control room startup activities until full power was achieved on
June 3, 2004.
b. Findings
On June 1, 2004, while restoring the shutdown cooling system to a normal, standby
readiness, a momentary loss of shutdown cooling occurred. This issue was followed up
by the inspector. Details of this event are described in Section 4OA3 of this report.
1R22 Surveillance Testing (IP 71111.22 - 6 Samples)
a. Inspection Scope
The inspectors observed and reviewed six Surveillance Tests (ST), focusing on
verification of the adequacy of the test as required by technical specifications to
Enclosure
18
demonstrate operability of the required system or component safety function. The
inspector observed pre-test briefings and portions of the ST performance for procedure
adherence, and verified that the resulting data associated with the ST met the
requirements of the plant technical specifications and the UFSAR. The inspector also
reviewed the results of past tests for the selected STs to verify that degraded or non-
conforming conditions were identified and corrected, if needed. The following six
activities were reviewed:
C Procedure No. 636.2.004, Diesel Generator Battery Discharge Test, completed
on April 26, 2004
C Procedure No. 619.3.008, Low Pressure Main Steam Line Functional Calibration
While Operating, completed on April 7, 2004
C Procedure No. 610.4.022, Core Spray System Surveillance, completed on
May 2, 2004
C Procedure No. 636.4.003, Diesel Generator #1 Load Test, completed on
May 17, 2004
C Procedure No. 602.4.003, Electromatic Relief Valve Operability Test,
completed on June 1, 2004
C Procedure No. 665.5.005, Drywell Airlock Leak Rate Test, completed on
June 2, 2004
b. Findings
During the testing of the #1 EDG on May 17, 2004, a human performance-related
finding was identified. See Section 4OA4 for the details of this finding.
1R23 Temporary Plant Modifications (IP 71111.23 - 2 Samples)
a. Inspection Scope
Two samples were selected for review by the inspectors. The inspectors reviewed a
Temporary Modification (TM) associated with the temporary routing of the signal cable
for the air ejector off gas radiation monitor . The inspectors reviewed the associated
implementing documents to verify the plant design basis and the system operability was
maintained, which included CC-AA-112, Temporary Configuration Changes, Rev. 6.
The inspectors also reviewed a TM associated with a temporary air connection to purge
the torus in support of the RCS 1000 psig inspection. The inspectors reviewed the
associated implementing documents to verify the plant design basis and the system
operability was maintained, which included CC-AA-112, Temporary Configuration
Changes, Rev. 6. The TM allowed for the inspection at 1000 psig reactor pressure by
purging the torus of nitrogen. The inspectors verified that the temporary modification
was removed in accordance with station procedures.
Enclosure
19
b. Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation (IP 71114.06 - 1 Sample)
a. Inspection Scope
The inspectors observed an emergency preparedness (EP) drill from the control room
simulator and the technical support center on May 6, 2004. The inspectors evaluated
the conduct of the drill and AmerGens performance related to emergency action level
classifications, notifications, and protective action recommendations. The drill contained
ten opportunities that are tracked by the NRC Drill/Exercise Performance (DEP)
performance indicator. The inspectors also reviewed several condition reports (CAP
Nos. 2004-1113, 2004-1114, 2004-1116, and 2004-1120) associated with EP areas for
improvement identified during the drill.
The inspectors reviewed the following documents:
- Oyster Creek EP Drill 5/6/04 Scenario, Rev. 2
- EP-OC-1010, Radiological Emergency Plan For Oyster Creek Generating
Station, Rev. 1
- EP-AA-125, Emergency Preparedness Self Evaluation Process, Rev. 2
b. Findings
No findings of significance were identified.
2. RADIATION SAFETY
Cornerstone: Occupational Radiation Safety
2OS1 Access Control to Radiologically Significant Areas (IP 71121.01 - 1 Sample)
a. Inspection Scope
The inspector toured areas controlled as High Radiation Areas and reviewed the
effectiveness of access control to these areas. The inspector physically inspected and
challenged three locked High Radiation Area access points to determine if access
controls were sufficient to preclude unauthorized entry.
b. Findings
No findings of significance were identified.
Enclosure
20
2PS2 Radioactive Material Processing and Transportation (IP 71122.02 - 1 Sample)
1. Inspection Planning/In-Office Inspection
a. Inspection Scope
The inspector reviewed the solid waste system description in the UFSAR and the recent
radiological effluent release report (2003) for information on the types and amounts of
radioactive waste.
b. Findings
No findings of significance were identified.
2. System Walkdown
a. Inspection Scope (71122.02 - sample not completed)
The inspector walked down selected accessible portions of the stations radioactive
liquid and solid waste collection, processing, and storage systems and locations to
determine if: systems and facilities were consistent with descriptions provided in the
UFSAR; to evaluate their general material conditions; and to identify changes made to
systems. Areas visually inspected were the high purity waste collection tank, floor drain
collector tank, waste neutralizer tanks, concentrated liquid waste tanks, chemical waste
de-watering filter (A&B), high purity waste filter and outdoor storage tanks (waste
sample tanks, chemical waste distillate and floor drain sample tanks). Also reviewed
and toured were various pump and building areas throughout the two radwaste facilities.
In addition, the inspector toured outdoor yard storage areas and toured the low-level
waste storage facility.
The inspector selectively reviewed the following topics:
C the status of non-operational or abandoned radioactive waste process equipment
and the adequacy of administrative and physical controls for those systems;
C changes made to radioactive waste processing systems and potential
radiological impact including conduct of safety evaluations of the changes, as
necessary;
C current processes for transferring radioactive waste resin and sludge to shipping
containers and mixing and sampling of the waste, as appropriate;
C radioactive waste and material storage and handling practices;
C sources of radioactive waste at the station, processing (as appropriate) and
handling of the waste; and,
Enclosure
21
C the general condition of facilities and equipment and licensee actions on
apparent deficient conditions, as appropriate.
The review was against criteria contained in the stations UFSAR, 10 CFR Part 20,
10 CFR 61, the Process Control Program (PCP), and applicable station procedures.
b. Findings
No findings of significance were identified.
3. Waste Characterization and Classification
a. Inspection Scope (71122.02 - sample not completed)
The inspector selectively reviewed the following topics:
C radio-chemical sample analysis results for radioactive waste streams and waste
types;
C the development of scaling factors for difficult to detect and measure
radionuclides;
C methods and practices to detect changes in waste streams;
C classification and characterization of waste relative to 10 CFR 61.55 and
C implementation of applicable NRC Branch Technical Positions (BTPs) on waste
classification, concentration averaging, waste stream determination, and
sampling frequency;
C current waste streams and their processing relative to descriptions contained in
the UFSAR and the stations approved PCP (RW-AA-100, Rev. 2);
C current processes for transferring radioactive waste resin and sludge discharges
into shipping/disposal containers to determine adequacy of sampling;
C revisions of the PCP and the UFSAR to reflect changes (as appropriate); and,
C implementation of Procedure RP-AA-605, 10 CFR61 Program, Rev. 0.
The review was against criteria contained in 10 CFR 20, 10 CFR 61, 10 CFR 71, the
UFSAR, the Process Control Program, applicable NRC Branch Technical Positions, and
AmerGens procedures.
b. Findings
Enclosure
22
No findings of significance were identified.
4. OTHER ACTIVITIES
4OA1 Performance Indicator Verification (IP 71151)
a. Inspection Scope
The inspectors reviewed the Performance Indicator (PI) data from January 2003 through
December 2003 for Emergency Diesel Generator Unavailability and for Scrams with a
Loss of Normal Heat Removal to verify their accuracy. The inspectors reviewed
AmerGens process for identifying and documenting the PI data as described in OC
procedures LS-AA-2040 Rev. 4, Monthly PI Data Elements for Safety System
Unavailability, and LS-AA-2003 Rev. 0, Use of the INPO Consolidated Data Entry
Database for NRC and WANO Data Entry, and compared the data using criteria
contained in NEI 99-02 Rev. 2 to verify it was properly dispositioned in the PI reports.
The inspectors also reviewed operator log entries for EDG out of service time and
interviewed the EDG system engineer to discuss the criteria used to determine EDG
unavailability.
b. Findings
No findings of significance were identified.
4OA2 Problem Identification and Resolution (IP 71152)
1. Routine Screening of Items Entered in the Licensees CAP Program
a. Inspection Scope (71152)
As required by Inspection Procedure 71152, Identification and Resolution of Problems,"
and in order to help identify repetitive equipment failures or specific human performance
issues for follow-up, the inspectors performed a daily screening of items entered into
AmerGens corrective action program. This review was accomplished by attending daily
screening meetings and management review meetings, and by accessing the licensees
computerized database.
b. Findings
No findings of significance were identified.
Enclosure
23
2. Identification and Resolution of Problems Associated with Select 10 CFR 50.59 Issues
and Plant Modifications
a. Inspection Scope
The inspectors reviewed corrective action process (CAP) reports associated with
selected 10 CFR 50.59 issues (Section 1R02) and plant modification issues
(Section 1R17) to ensure that the licensee was identifying, evaluating, and correcting
problems associated with these areas and that the planned or completed corrective
actions for the issues were appropriate. The inspectors also reviewed four audits and
self-assessment reports related to engineering activities, including 10 CFR 50.59 safety
evaluation and plant modifications at Oyster Creek.
The listing of the condition reports and self assessments reviewed is provided in
Attachment 1.
b. Findings
No findings of significance were identified.
3. Identification and Resolution of Problems Associated with Radioactive Waste Handling
a. Inspection Scope (71122.02 - sample not completed)
The inspector selectively reviewed assessments of the radioactive waste handling,
processing, storage, and shipping programs including the PCP. The inspector also
reviewed selected corrective action documents written since the previous inspection.
The following documents were reviewed:
C Chemistry, Radwaste, and Process Control Program audit # NOSA-OYS-04-04
(AR00214001), dated April 28, 2004
C Various Radwaste audit templates
C April 2004 Focused Self-Assessment (Report 4017-RE-027)
C Corrective Action Documents (CAPs: 2004-0334, 2004-1571, 2004-1572, 2004-
0429, 2004-0964, 2004-0968, 2004-0971, 2004-0972, 2002-1820).
The review used criteria contained in 10 CFR 20 Appendix G, 10 CFR 71.101, and
applicable station audit and surveillance procedures.
b. Findings
No findings of significance were identified.
4. Semi-Annual Review of Corrective Action Program Trends (IP 71152)
Enclosure
24
a. Inspection Scope (IP 71152 - 1 sample)
The inspectors performed a semi-annual review of common cause issues in order to
identify any unusual trends that might indicate the existence of a more significant safety
issue. This review included an evaluation of repetitive issues identified via the corrective
action process. The results of the trending review were compared with the results of
normal baseline inspections. In addition, the inspector reviewed the following
documents to determine if trends were identified that were not documented in the CAP
system:
C Oyster Creek Nuclear Safety Review Board Meeting, February 9 and 10, 2004
C Oyster Creek Nuclear Safety Review Board Observation Visit, October 22
thru 28, 2003
C Nuclear Oversight Quarterly Report, NOSPA-OC-04-1Q, January - March 2004
C Security Plan, FFD, Access Authorization, PADS Audit Report,
NOSA-OYS-04-02, February 23 - 27, 2004
C NOS Maintenance Functional Area Audit Report, NOSA-OYS-04-01,
March 8 - 19, 2004
b. Findings
No findings of significance were identified.
5. Annual Sample Review (IP 71152 - 1 sample)
a. Inspection Scope
Observations
The inspector reviewed AmerGens efforts to identify and correct problems with the
recirculation system to return the system to five (5) pump, automatic operation. These
efforts were successfully completed during a maintenance outage in late May/early June
2004, although additional troubleshooting was undertaken at the end of this inspection
period due to intermittent, small flow oscillations on the "C" MG set that prompted
AmerGen to temporarily place that MG set in manual.
The inspector discussed the current condition of the system with the responsible system
engineer as well as the basis for, and the adequacy of the corrective actions taken to
date to return the system to five (5) pump, automatic operation. He reviewed twelve
(12) corrective action program reports in 2002-2004 related to recirculation system
equipment issues, three A/Rs related to the "A" recirculation pump motor failure in
August 2003 and the replacement of the scoop tube positioner for the "C" MG set, and
long-term plans to maintain and improve the reliability of the system. The inspector
Enclosure
25
noted that AmerGens long-term improvement plans are tentative, but involve
refurbishing MG sets B, C, D & E between 2005 - 2008 ("A" was completed in June
2004) as well as replacing recirculation pump motors B & C by the end of 2008 ("D" &
"E" were purportedly replaced in the last decade while "A" was replaced in June 2004.)
AmerGen is also planning to replace the cooling coil inside the "A" and "E" recirculation
pump motors by the end of 2008 ("B", "C" & "D" pumps had their cooling coils replaced
in the recent past).
The inspector noted that pending the failure analysis and rebuilding of the "A"
recirculation pump motor, AmerGen does not have a spare recirculation pump in the
event of a future motor failure. Moreover, AmerGen also lacks a spare MG set or fluid
coupling positioner in the event of a future MG set equipment failure. Thus it will be
challenging to keep the recirculation system in five (5) pump, automatic operation until
AmerGens long-term reliability improvements are completed in 2008.
b. Findings
No findings of significance were identified.
6. PI&R Cross-cutting Aspects of Findings Described Elsewhere in the Report
The inspectors identified a non-cited violation of the Oyster Creek Quality Assurance
Program for failure to adequately evaluate operating experience information and correct
a condition affecting the recirculation pump voltage regulator card that resulted in the
trip of the D recirculation pump during four loop full power operation. This finding has a
cross-cutting aspect of PI&R in that the engineering evaluation of external operating
experience and corrective action implementation were inadequate to prevent a similar
condition at the site. (Section 1R14).
The inspectors identified a non-cited violation for failure to identify a condition adverse to
quality when a secondary containment airlock door was found open, resulting in a
momentary violation of Technical Specification 3.5.B.2. This finding has a cross-cutting
aspect of PI&R in that operators failed to initiate a CAP report for this condition as
required by the CAP Process Procedure. (Section 1R16)
4OA3 Event Follow-up (IP 71153)
a. Inspection Scope
The inspectors reviewed the following four events during the period. The review
consisted of observing plant parameters and status, including mitigating systems/trains
and fission product barriers; reviewing alarms/conditions preceding or indicating the
event; evaluating the performance of mitigating systems and licensee actions; and
confirming that the licensee properly classified the event in accordance with emergency
Enclosure
26
action level procedures and made timely notifications to NRC and state/county
governments, as required. The specific events reviewed included:
C ISFSI transfer truck hydraulic failure during spent fuel move on April 16, 2004
C 69 KV switchyard fire and voltage transient causing a loss of the 1E1 bus on
April 20, 2004
C Loss of Shutdown Cooling event on May 31, 2004
C 230 KV switchyard fire and voltage transient causing a loss of the 1E1 bus and
the S1B startup transformer on June 30, 2004
b. Findings
Inadequate Procedure Results in a Temporary Loss of Shutdown Cooling Capability
Introduction. A self-revealing event involving an inadvertent loss of shutdown cooling
resulted in a Green finding and an NCV for failure to establish and maintain appropriate
procedural requirements for the operation of the shutdown cooling system, as
prescribed by Technical Specification 6.8.1 and the Oyster Creek Operational Quality
Assurance Plan, NO-AA-10, Revision 72.
Description. On May 31, 2004, while the plant was in a cold shutdown condition and the
shutdown cooling system was in service, technicians were performing Attachment 305-8
of procedure 305, Shutdown Cooling System Operation. At the time, activities were in
progress to remove the bypass jumpers for the reactor recirculation loop temperature
shutdown cooling isolation logic in order to continue to restore the shutdown cooling
system to a standby readiness condition prior to commencing a reactor startup and
heat-up. The isolation logic bypass jumpers are normally installed during a plant
maintenance or refueling outage to prevent an inadvertent trip of the shutdown cooling
system due to a false trip signal. During the maintenance outage, the reactor
recirculation loop temperature circuitry had maintenance conducted on it that introduced
a trip signal into the logic. This trip signal was not reset as part of the maintenance.
Also, there were no indications or alarms associated with this trip function being in an
actuated state. When the technician removed the jumper as part of the system
restoration process (per Attachment 305-8), the previously actuated logic was no longer
bypassed and the shutdown cooling system tripped off.
Prior to commencing the activity to remove the bypass jumpers, operators verified that
associated temperature instrumentation was operable and that the indicated RCS
temperature was about 178 degrees with adequate margin to boiling and well below the
logic actuation temperature of 350 degrees. During the pre-evolution brief, operators
discussed the possibility that removing the jumpers could introduce an isolation trip of
shutdown cooling. This was not an expected condition of the activity, however, recovery
actions were discussed in case of the need. Operators responded to the trip of the
shutdown cooling system by verifying that the isolation trip was inadvertent, reset the trip
Enclosure
27
actuation logic, and then restored shutdown cooling to service. The system was
restored in about 14 minutes and RCS temperature increased by about 4 degrees. The
initial RCS temperature was 178 degrees, and the post-transient temperature was 181
degrees.
The loss of shutdown cooling resulted in an unplanned entry into a high outage risk
condition as determined by the licensees outage risk management program. At the
time of the event, the licensee had calculated outage risk to be Yellow due to the high
decay heat condition of the RCS. On May 31, 2004, the calculated time to boil was
about 95 minutes. The loss of the shutdown cooling system resulted in a calculated
Red shutdown risk condition as indicated by the licensees ORAM-Sentinel Model. The
licensee responded to this condition appropriately; however, certain communications
about the event were not timely. This condition was documented by the licensee in CAP
O2004-1392.
Analysis. Procedure 305, Attachment 305-8, Bypassing Isolation Interlocks for the
Shutdown Cooling System Isolation Valves, Restoration Section did not include an
appropriate step to ensure that the isolation logic was reset prior to removing the bypass
jumpers. This resulted in an unexpected trip of the shutdown cooling system on
May 31, 2004. This is a performance deficiency. Traditional enforcement does not
apply because the issue did not have any actual safety consequences or potential for
impacting the NRC regulatory function, and was not the result of any willful violation of
NRC requirements or AmerGen procedures. The finding was more than minor because
the procedural control deficiency actually led to a trip of the shutdown cooling system
isolation actuation logic and a resultant loss of the normal shutdown decay heat removal
capability.
In accordance with IMC 0609, Appendix G, Shutdown Operations Significance
Determination Process, the inspector determined that the finding was of very low safety
significance (Green) because: (1) while it resulted in an actual loss of the shutdown
cooling system, the resultant reactor coolant temperature rise was very low, and not
considered a loss of control event since the temperature rise (about 4 degrees) relative
to the margin to boil which was less than 0.2 times the final margin to boil (about 31
degrees); (2) per Appendix G, Attachment 1, Shutdown Operations Significance
Determination Process Phase 1 Operational Checklists for Both PWRs and BWRs,
Checklist 6, BWR Cold Shutdown or Refueling Operation; Time to Boil < 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />s: RCS
level < 23' Above Top of Flange, the deficiency involved an inadequate operating
procedure for the decay heat removal function while shutdown, [Checklist 6 Event I.B
(1)], that: (i) did not increase the likelihood that a loss of decay heat removal would
occur due to failure of the system itself or support systems; (ii) did not include decay
heat removal instrumentation or vessel level instrumentation such that degraded core
cooling could not be detected; (iii) did not increase the likelihood of a loss of RCS
inventory, or that could result in a loss of RCS level instrumentation; (iv) did not involve
a design or qualification deficiency; and, (v) did not result in an actual loss of safety
function for risk-significant equipment with respect to internal or external events.
Enclosure
28
The inspector noted that the operators prepared for the possible loss of the shutdown
cooling system as part of the evolution and carried out the appropriate steps to recover
the system with a minimal rise in RCS temperature while maintaining an adequate
margin to boil. AmerGen entered this finding into their corrective action program as
CAP O2004-1392.
Enforcement. Oyster Creek Technical Specification 6.8.1 requires that procedures be
established, implemented, and maintained, in part, for applicable procedures
recommended in Appendix A of Regulatory Guide 1.33 as referenced in the Oyster
Creek Operational Quality Assurance Program, NO-AA-10, Rev. 72. Appendix A of
Regulatory Guide 1.33 includes operating procedures for the Shutdown Cooling System.
Contrary to the above, Oyster Creek Procedure 305, Shutdown Cooling System
Operation, Rev. 83, Attachment 305-8, was not adequately established or maintained.
As such, it did not include the required actions to prevent an inadvertent isolation of the
Shutdown Cooling System while restoring the isolation interlock to a normal
configuration. This led to a loss of shutdown cooling on May 30, 2004. Because this
condition is of very low significance and has been entered into AmerGens corrective
action program (CAP O2004-1392), this violation is being treated as an NCV, consistent
with Section VI.A of the NRC Enforcement Policy, issued May 1, 2000 (65FR25368).
(NCV 05000219/200400304)
4OA4 Cross-Cutting Aspects of Findings
1. Human Error Involving Procedure Adherence Violation Results in a Loss of Emergency
Diesel Generator Capability
a. Inspection Scope (IP 71111.22)
During a review of a problem with the cooling system during the conduct of the #1 EDG
load test on May 17, 2004, the inspectors observed the physical condition of the cooling
system fan shaft support and associated bolting, interviewed workers who had
conducted maintenance on the diesel generator during a 2-year overhaul in April 2004,
reviewed AmerGens root cause investigation conducted per CAP O2004-1184, and
reviewed AmerGens technical evaluation of EDG functionality with the loose bolting as
documented in action request (AR) A2089090.
b. Findings
Introduction. A self-revealing apparent violation, having potential safety significance
greater than very low significance, was identified for failure to implement appropriate
procedural requirements for maintenance on the #1 EDG during an overhaul conducted
April 26 - 30, 2004, as prescribed by Technical Specification 6.8.1.
Description. On May 17, 2004, while the plant was at 100 % power, operators were
performing a loaded, operational surveillance test of the #1 EDG. After completing the
required loaded run, operators observed noise and vibration from the engine cooling fan
while the diesel was in its post-run cool-down cycle. Based on the observed condition,
Enclosure
29
the diesel was emergency stopped. An inspection revealed that the bolting on the
engine cooling system fan shaft pillow-block assembly had loosened, with one bolt
removed and the second nearly detached. Operators declared the diesel generator
inoperable and repairs commenced to replace the bolting.
A root cause review of the failure determined that maintenance conducted during a two-
year overhaul on April 26 - 30, 2004, had replaced the diesel cooling system fan drive
belts. AmerGens root cause investigation, as well as independent review by the
resident inspectors, determined that the technicians failed to follow written procedures to
torque the cooling fan shaft bearing bolts following fan belt replacement. The poor
maintenance practices led to the high vibrations during surveillance testing and manual
shutdown of the #1 EDG on May 17, 2004. The high vibrations increased the potential
for a failure of the #1 EDG due to loss of the skid-mounted cooling system. The final
determination of risk significance is pending potential additional information from
AmerGen concerning the ability of the #1 EDG to perform its safety function, given the
high vibrations and the loose cooling fan shaft bearing bolts.
Analysis. The performance deficiency was that AmerGen failed to implement
appropriate procedural requirements for the maintenance on the #1 EDG with respect to
the fastening of the cooling fan shaft bearing bolts. The finding was more than minor
because it affected the mitigation system cornerstone objective to ensure the
availability, reliability, and capability of systems (emergency AC power) that respond to
initiating events to prevent undesirable consequences, and the related attributes of
equipment performance, human performance, and procedure quality.
The inspectors conservatively assumed, based on initial information, that the #1 EDG
would have been unable to perform its safety function for 17 days (April 30 - May 17).
This assumption was made due to the large degree of uncertainty associated with the
ability of the #1 EDG to operate with the high vibrations and loose cooling fan shaft
bearing bolts.
Using the 17-day exposure time, the finding was preliminarily evaluated in accordance
with Inspection Manual Chapter 0609, Appendix A, "Significance Determination of
Reactor Inspection Findings for At-Power Situations." The Phase 1 screening identified
that a Phase 2 analysis was needed because the #1 EDG would have been inoperable
in excess of its Technical Specification Allowed Outage Time of 7 days.
The inspectors conducted a bounding Phase 2 evaluation using the Risk-Informed
Inspection Notebook for Oyster Creek Nuclear Generating Station, Revision 1. An
exposure time of greater than three days and less than thirty days was used.
Worksheet Table 3.5, LOOP, was evaluated using IMC 0609 Appendix A rule 1.6 for an
EDG finding. Operator recovery of the emergency AC power function using the nearby
First Energy Combustion Turbines was not credited (see note 1. on Table 3.5 ). The
SDP Phase 2 resulted in an internal event delta CDF in the mid E-6 range.
The NRC Headquarters SRA conducted a preliminary Phase 3 analysis, as discussed
below, for internal and external initiating events, indicated a delta CDF in the mid-E-6
Enclosure
30
range and a delta LERF in the mid-E-7 range. As such, the finding could be of low -
moderate safety significance (WHITE). However, due to the variability in the outcome of
the analysis based on the potential ability of the #1 EDG to perform for its safety
function for a portion of its mission time, the significance of this performance deficiency
is preliminarily characterized as Greater Than Green. Additional information from
AmerGen concerning the ability of the #1 EDG to perform its safety function would
facilitate more refined risk analysis. This information would include a clearly articulated
and effectively supported applicability analysis of testing conducted on an EDG not
exactly similar to the #1 EDG at Oyster Creek.
Delta CDF: The Oyster Creek SPAR model, updated with NUREG 5496 LOOP
initiating event frequencies and associated offsite power non-recovery
probabilities, was used. The #1 EDG was failed by setting the test and
maintenance term, EPS-DGN-TM-DG1, to true for a 17-day period, resulting in a
delta-CDF in the mid-E-6 range. The risk increase was dominated by a LOOP
with failure of the other diesel (Station Black Out (SBO) sequence) and the
failure to recover offsite power prior to core damage. The analysis also included
a review of external initiating events, finding that a LOOP caused by a fire
contributed in the low E-7 range to the delta CDF total. The other external events
(flooding, high winds, and earthquakes) did not contribute significantly to the total
increase in CDF.
Delta LERF: Revised Manual Chapter 0609, appendix H, Containment Integrity
Significance Determination Process, was used to evaluate the impact of this
performance deficiency on the Large Early Release Frequency (LERF). The
appendix H factors relevant to this issue involve SBO sequences that result in
reactor vessel breach with a dry containment floor. For such SBO sequences
Appendix H gives a multiplier of 1.0 at BWRs with a Mark 1 containment.
However, through discussions with the licensee, the analyst discovered several
factors that should be credited for LERF mitigation at Oyster Creek. Mitigation
possibilities include AC recovery and injection via core spray prior to vessel
breach, fire water injection, and a unique concrete berm in containment that
could be effective in containing core debris. By taking these factors into
consideration, the senior reactor analyst determined that a more appropriate
LERF multiplier would be 0.1. Therefore, the increase in LERF was estimated
at CDF * 0.1 or in the Mid-E-7 range.
Review of AmerGen Analysis: The SRA also reviewed the results of a
preliminary AmerGen risk analysis, which assumed that the #1 EDG was
inoperable for the 17 days. This review found that the SPAR results generally
reflect higher risk for this condition. However, the licensee model was non-
conservative relative to offsite power failure rates and recovery probabilities.
Adjusting the AmerGen result with the higher LOOP frequencies from NUREG
5496 would result in a Low-E-6 increase in CDF. The adjustments for LOOP
non- recovery probabilities would further increase the licensee results.
Therefore, it was concluded that AmerGens preliminary results were reasonably
consistent with the preliminary SDP results.
Enclosure
31
Enforcement. Oyster Creek Technical Specification 6.8.1 requires the licensee to
establish, implement, and maintain written procedures, in part, for maintenance that can
adversely affect the performance of safety-related equipment and for surveillance and
test activities of equipment that affects nuclear safety. Work Order (R2017655), the
Diesel Generator Inspection (24 Month) Surveillance Test (Procedure 636.1.010), and
maintenance instruction, M.I. 1200, were procedures required by TS 6.8.1, to control the
activities conducted during the 2-year overhaul of the #1 EDG completed on
April 30, 2004. On April 30, 2004, the technicians completed work on the #1 EDG
without fully implementing Maintenance Instruction 1200 requirements when replacing
the fan belts for the cooling system, in that specified torque values were not used when
returning the associated pillow-block bolting to its required configuration. This led to a
high vibration and imminent loss of the EDG cooling system on May 17, 2004. This
condition was evaluated as a preliminary Greater Than Green finding, pending
determination of the final safety significance. As such, this violation was treated as an
apparent violation. (AV 05000219/200400305)
4OA5 Other Activities
Offsite Power System Operational Readiness (TI 2515/156)
a. Inspection Scope
The inspectors interviewed station personnel in order to confirm the operational
readiness of offsite power systems in accordance with NRC requirements prescribed in
General Design Criterion 17 of 10 CFR 50, Appendix A; 10 CFR 50, Appendix B
Criterion XVI; plant technical specifications for offsite power systems, 10 CFR 50.63;
and 10 CFR 50.65(a)(4). The inspectors also evaluated the licensees response to
various questions concerning the maintenance rule, station blackout, corrective action,
and offsite power design robustness and quality.
b. Findings
No findings of significance were identified.
4OA6 Meetings, including Exit
Exit Meeting Summary
On July 15, 2004, the resident inspectors presented the inspection results to
Mr. C. N. Swenson, Senior Vice President and other members of licensee management.
The licensee acknowledged the findings presented. In addition, the resident inspectors
reviewed the findings and discussion from the visiting inspectors that were presented in
exit meetings conducted April 2, June 23 and July 7, 2004. The inspectors asked the
licensee whether any materials examined during the inspection should be considered
proprietary. No proprietary information was identified.
Enclosure
32
4OA7 Licensee-Identified Violations
The following violation of very low-safety significance (Green) was identified by the
licensee and is a violation of NRC requirements which meets the criteria of Section VI of
the NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.
C 10 CFR 20 Appendix G, requires that the licensee establish and implement a
Quality Assurance (QA) program to assure compliance with the requirements of
10 CFR 61.55. Contrary to this requirement, as of April 2004, the QA program
did not assure compliance with the waste radionuclide concentration
determination provisions of 10 CFR 61.55. Specifically, as of April 2004, a non-
representative method (single direct sampling) was used to determine
radionuclide concentrations in resin liners containing stratified resin from
different waste streams. In April 2004, a vendor audit identified that the use of
the direct sampling method resulted in underestimation of radionuclide
concentrations and thus curie content of spent resins shipped for shallow land
disposal (e.g., resin shipment No. OC4003-04-04 shipped March 9, 2004). (CAP
O2004-1572; O2004-1733)
ATTACHMENT: SUPPLEMENTAL INFORMATION
Enclosure
A-1
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
P. Bloss, BOP Systems Manager
A. Farenga, Radwaste Shipping Coordinator
D. Fawcett, Licensing Engineer
M. Godknecht, Maintenance Rule Coordinator
E. Harkness, Vice President, Projects
S. Hutchins, Electrical Systems Manager
J. Magee, Director, Engineering
M. Massaro, Plant Manager
D. McMillan, Director, Training
L. Newton, Manager, Chemistry & Rad Protection
J. ORourke, Assistant Engineering Director
J. Renda, Radiation Protection Manager
D. Slear, Manager, Regulatory Assurance
B. Stewart, Senior Licensing Engineer
C. Swenson, Site Vice President
G. Waldrep, Quality Assurance Manager
C. Wilson, Director, Operations
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
05000219/200400302 URI (Section 1R14) Review corrective actions for IRM spiking
that led to scram event on May 27, 2004.
05000219/200400305 AV (Section 4OA4) Human performance event - failure to
follow procedures led to failure of cooling system for EDG
- 1 on May 17, 2004.
Opened and Closed
05000219/200400301 NCV (Section 1R14) Ineffective evaluation of operating
experience information for reactor recirculation system
voltage control circuit - wrong wattage resistor installed.
05000219/200400303 NCV (Section 1R16) Failure to identify condition adverse to
quality for degraded latching mechanism on secondary
airlock door on May 4, 2004.
Attachment
A-2
05000219/200400304 NCV (Section 4OA3) Inadequate procedure for restoration of
the shutdown cooling system led to unexpected loss of
shutdown cooling on May 31, 2004.
LIST OF DOCUMENTS REVIEWED
(not previously referenced)
10 CFR 50.59 Screened-out Evaluations
OC-2002-S-0038 ECR 01-00828 - Isolation Condenser Vent Valve Replacement
OC-2002-S-0156 Reactor Water Cleanup Modification Contingency
OC-2002-S-0357 ECR OC 02-00676, ESW Pump Anti-Fouling Coating
OC-2002-S-0427 Repair of Service Water Pipe Downstream of RBCCW HX
OC-2003-S-0039 ECR 03-00098 - Remove Internals from Check Valve V-16, Rev. 0
OC-2003-S-0070 Temp Mod for Isolating HC-1-1 for Maintenance, Rev. 0
OC-2003-S-0167 ECR/DCP 03-00220 - MG Set Room Ventilation Change, Rev 0
OC-2003-S-0172 RBCCW System Pipe Support 541-1022 Off-Center, Rev. 1
OC-2003-S-0216 ESW I Underground Pipe Bypass Modification
OC-2003-S-0511 NRW Chlorine Booster Pump Mechanical Seal Upgrade, Rev. 0
OC-2004-S-0009 Control Rod Drive Reactor Head Cooling System-Installation of Cross
Connect Pipe to Reactor Head Vent System, Rev. 0,
OC-2004-S-0016 ECR 04-00020 Temporary Support of 8" DR-8 Pipe
OC-2004-S-0026 Replacement of Drain Tank 1-2 and 1-5 Instrumentation, Rev. 0
OC-2004-S-0036 Fuel Oil Transfer Line Tagged Out of Service More Than 90 Days, Rev. 0
OC-2004-S-0050 Deletion of Procedure 823.31, Rev 5
Action Requests
A2069334, A2008592, A2069438
Audits & Self-Assessments
NOSA-OC-03-05, NOS Engineering Design Control Audit Report, August 19, 2003
NOS Corporate Comparative Audit Report, 2003 Engineering Design Control, October 22, 2003
Focus Area Self-Assessment Report (Engineering Fundamentals), 3rd Quarter 2003
O2003-2497, Common Cause Analysis Report, February 16, 2004
Corrective Action Report Items
O1998-1274-1, O2000-07756, O2001-0711, O2001-0711-1, O2001-1839, O2002-0496,
O2002-0711, O2002-1059, O2003-0473, O2003-1735, O2004-0772*, O2004-0789*
O2002-1308, 02003-0616, 02003-1075, 02003-1270, 02003-1723, 02003-1930, 02003-2454,
02004-0008, 02004-0805, 02004-0821, 02004-1387, 02004-1438, 02004-1444
Calculations
Attachment
A-3
C-1302-241-E310-111 Factor of Safety Against Failure for the Containment Spray
Pumps 1-1 and 1-2, Rev. 0
C-1302-730-5350-008 Oyster Creek - Generic Letter 89-10 MOVs Voltage Drop
Calculation, Rev. 4
C-1302-862-E310-007 Diesel Generator Fuel Transfer Pump Inlet Pressure, Rev. 0
Drawings
DWG-01-00621-1 ESW/SW Cross-Connect Mod., Rev. 0
GE 223R0173, Sh 15 4160V System Electrical Elementary Diagram - P. T.
Undervoltage, Heater, D.C Supply & DG 1 Tie
GU 3W-241-A2-1000, Sh 2 ISI Configuration Drawing Containment Spray System, Rev. 5
Procedures
CC-AA-103, Rev. 5 Configuration Change Control
LS-AA-104, Rev. 3 Exelon 50.59 Review Process
LS-AA-104-1000, Rev. 1 50.59 Resource Manual
205.94.0, Rev. 0 RPV Floodup using Core Spray
Special 02-004, Rev. 0 SW 6 Hour Out Of Service Window in 1R19
LIST OF ACRONYMS
ADAMS Agencywide Documents Access and Management System
ALARA As Low As Is Reasonably Achievable
AmerGen AmerGen Energy Company, LLC
AR Action Request
CAP Corrective Action Process
CDF Core Damage Frequency
CFR Code of Federal Regulations
CRD Control Rod Drive
CS/ESW Containment Spray/Emergency Service Water
DEP Drill/Exercise Performance
ECR Engineering Change Request
EDG Emergency Diesel Generator
EMRV Electro Magnetic Relief Valve
ESW Emergency Service Water
IC Isolation Condenser
IMC Inspection Manual Chapter
IP Inspection Procedure
LERF Large Early Release Frequency
MG Motor-Generator
MSIV Main Steam Isolation Valve
Attachment
A-4
NCV Non-Cited Violation
NEI Nuclear Energy Institute
NRC Nuclear Regulatory Commission
PI Performance Indicator
PI&R Problem Identification & Resolution
PSIG Pounds per Square Inch Gauge
QATR Quality Assurance Topical Report
QA Quality Assurance
RBCCW Reactor Building Closed Cooling Water
RBEDT Reactor Building Equipment Drain Tank
RTP Rated Thermal Power
SDP Significance Determination Process
SE Safety Evaluation
SGTS Standby Gas Treatment System
SSCs Systems, Structures and/or Components
ST Surveillance Test
TS Technical Specification
UFSAR Updated Final Safety Analysis Report
URI Unresolved Item
WO Work Order
Attachment