ML033020363
| ML033020363 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 10/27/2003 |
| From: | Joel Munday NRC/RGN-II/DRP/RPB3 |
| To: | Young D Florida Power Corp |
| References | |
| FOIA/PA-2004-0277 IR-03-005 | |
| Download: ML033020363 (27) | |
See also: IR 05000302/2003005
Text
October 27, 2003
Mr. Dale E. Young, Vice President
Crystal River Nuclear Plant (NA1B)
ATTN: Supervisor, Licensing &
Regulatory Programs
15760 West Power Line Street
Crystal River, FL 34428-6708
SUBJECT:
CRYSTAL RIVER UNIT 3 - NRC INTEGRATED INSPECTION REPORT
Dear Mr. Young:
On September 27, 2003, the US Nuclear Regulatory Commission (NRC) completed an
inspection at your Crystal River Unit 3. The enclosed integrated inspection report documents
the inspection findings, which were discussed on September 29, 2003, with you and 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, there was one inspector identified finding 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 the violations were entered into your corrective action program, the NRC is
treating these violations as non-cited violations (NCVs) consistent with Section VI.A of the NRC
Enforcement Policy. Additionally, a licensee-identified violation which was determined to be of
very low safety significance is listed in Section 40A7 of this report. If you contest any of these
NCVs, you should provide a response within 30 days of the date of this inspection report, with
the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control
Desk, Washington DC 20555-001; with copies to the Regional Administrator Region II; the
Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington,
DC 20555-0001; and the NRC Resident Inspector at Crystal River Unit 3.
2
In accordance with 10 CFR 2.790 of the NRCs "Rules of Practice," a copy of this letter and its
enclosure will be available electronically for public inspection in the NRC Public Document
Room or from the Publicly Available Records (PARS) component of NRCs document system
(ADAMS). ADAMS is accessible from the NRC Web site at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Joel T. Munday, Chief
Reactor Projects Branch 3
Division of Reactor Projects
Docket No.: 50-302
License No.: DPR-72
Enclosure: Inspection Report 05000302/2003005
w/Attachment: Supplemental Information
cc w/encl: (See page 3)
3
cc w/encl:
Daniel L. Roderick
Director Site Operations
Crystal River Nuclear Plant (NA2C)
Electronic Mail Distribution
Jon A. Franke
Plant General Manager
Crystal River Nuclear Plant (NA2C)
Electronic Mail Distribution
Richard L. Warden
Manager Nuclear Assessment
Crystal River Nuclear Plant (NA2C)
Electronic Mail Distribution
Donald L. Taylor
Manager Support Services
Crystal River Nuclear Plant (NA2C)
15760 W. Power Line Street
Crystal River, FL 34428-6708
R. Alexander Glenn
Associate General Counsel (MAC - BT15A)
Florida Power Corporation
Electronic Mail Distribution
Steven R. Carr
Associate General Counsel - Legal Dept.
Progress Energy Service Company, LLC
Electronic Mail Distribution
Attorney General
Department of Legal Affairs
The Capitol
Tallahassee, FL 32304
William A. Passetti
Bureau of Radiation Control
Department of Health
Electronic Mail Distribution
Craig Fugate, Director
Division of Emergency Preparedness
Department of Community Affairs
Electronic Mail Distribution
Chairman
Board of County Commissioners
Citrus County
110 N. Apopka Avenue
Inverness, FL 36250
Jim Mallay
Framatome Technologies
Electronic Mail Distribution
Distribution wencl: (See page 3)
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Distribution w/encl:
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L. Slack, RII EICS
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PUBLIC
OFFICE
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SIGNATURE
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NAME
SNinh:vyg
SStewert
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NMerriweather
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DATE
10/22/2003
10/27/2003
10/27/2003
10/23/2003
10/23/2003
E-MAIL COPY?
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NO YES
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PUBLIC DOCUMENT
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OFFICIAL RECORD COPY DOCUMENT NAME: C:\\ORPCheckout\\FileNET\\ML033020363.wpd
Enclosure
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket No.:
50-302
License No.:
Report No.:
Licensee:
Florida Power Corporation
Facility:
Crystal River Unit 3
Location:
15760 West Power Line Street
Crystal River, FL 34428-6708
Dates:
June 29, 2003 - September 27, 2003
Inspectors:
S. Stewart, Senior Resident Inspector
R. Reyes, Resident Inspector
N. Merriweather, Senior Reactor Inspector (4OA5)
R. Schin, Senior Reactor Inspector (4OA5)
Approved by:
Joel T. Munday, Chief
Reactor Projects Branch 3
Division of Reactor Projects
SUMMARY OF FINDINGS
IR 05000302/2003-005, 06/29/2003 - 09/27/2003; Crystal River Unit 3; Fire Protection and
Event Followup.
The report covered a three month period of inspection by resident inspectors and an
announced inspection by region based engineering inspectors. Two Green non-cited Violations
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.
Inspector Identified and Self-Revealing Findings
Cornerstone: Mitigating Systems
Green. A self-revealing non-cited violation of Crystal River 3 Technical Specification 3.7.18 was identified. Following Train B chiller maintenance on
December 19, 2002, and Train A chiller maintenance on February 25, 2003,
neither train of control complex cooling was operable because control complex
chiller motor overload relays had been improperly set below their design values.
The problem was identified on June 11, 2003, when both chiller motors tripped
on overload current, when an overload current condition had not occurred.
The self-revealing finding is greater than minor safety significance because it
resulted in a loss of the control complex cooling safety function and affected the
availability and reliability of the Mitigating Systems Cornerstone of Reactor
Safety that is used to mitigate events. The finding is of very low safety
significance because the alternate non-safety Appendix R cooling system and
feedwater pump (FWP-7) were available to mitigate transients involving systems
that could be affected by the loss of cooling. (Section 4OA3)
Green. The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix R,Section III.G.2, Fire Protection of Safe Shutdown Capability, for
failure to protect certain electrical cables for safe shutdown equipment from fire
damage in three fire areas. The licensee has corrected related identified
procedural deficiencies and plans to resolve the noncompliance with cable
protection through licensing correspondence with the NRC.
This finding is greater than minor safety significance because it involved a lack of
required fire barriers for equipment relied upon for safe shutdown following a fire
and because it affected the objectives of the Mitigating Systems Cornerstone of
Reactor Safety. It affected the availability and reliability of systems that mitigate
initiating events to prevent undesirable consequences. The finding is of very low
safety significance because licensees proceduralized manual actions are
reasonably accomplishable and training would have enabled operators to
2
maintain the makeup function sufficiently to maintain reactor coolant system
process variables within acceptable ranges. Therefore, the inspectors identified
this issue as a Green finding as described in Inspection Procedure 71111.05,
Fire Protection. (Section 4OA5)
B.
Licensee Identified Violations
A violation of very low safety significance, which was identified by the licensee, has been
reviewed by the inspectors. Corrective actions taken or planned by the licensee have
been entered into the licensees corrective action program. The violation and corrective
action tracking number are listed in Section 4OA7 of this report.
REPORT DETAILS
Summary of Plant Status
Crystal River 3 operated at full power during the inspection period until September 6, 2003,
when a reactor power coastdown to refueling outage 13 was started. On September 14, 2003,
reactor power was reduced from 82 percent to 60 percent when a turbine throttle valve went
closed on a spurious signal. The control circuit for the valve was repaired and reactor power
was restored on the same day.
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity [Reactor-R],
1R01
Adverse Weather Protection
a.
Inspection Scope
The inspectors monitored the licensees preparations for Tropical Storm Henri on
September 3 to 6, 2003. The licensee activities were checked to assure that vital
systems and components were protected from severe weather in accordance with
licensee Emergency Instruction EM-220, Violent Weather. During the preparations, the
inspectors walked down portions of the following systems/areas to verify the licensees
mitigation strategy. The inspectors attended a licensee Violent Weather Committee
meeting and reviewed the readiness checklists to verify that preparations were being
tracked to completion. Nuclear condition reports were reviewed to verify that the
licensee was identifying and correcting weather protection issues.
Emergency Feedwater system including EFP-3 and EFP-2
Emergency Diesel Generator Systems
Site Switchyard and Berm areas
b.
Findings
No findings of significance were identified.
1R04
Equipment Alignment
.1
Partial Equipment Walkdowns
a.
Inspection Scope
The inspectors performed the following partial system walkdowns during this inspection
period. The inspectors reviewed the alignment of the selected risk-significant systems to
evaluate the readiness of the redundant trains while one train was out of service for
maintenance. The inspectors checked switch and valve positions using the alignments
specified in the listed operating procedures and checked electrical power alignment to
critical components. The inspectors reviewed applicable sections of the Crystal River 3
2
Final Safety Analysis Report to obtain design and operating requirements. Nuclear
condition reports were reviewed to verify that the licensee was identifying and correcting
component alignment issues.
Emergency Diesel Generator EDG-1B using Operating Procedure OP-707,
Operation Of The ES Emergency Diesel Generators, when EDG-1A was out of
service for testing on August 14, 2003.
B Service Water Train using OP-408, Nuclear Services Cooling System, and
Flow Drawing FD-302-601, Nuclear Services Closed Cycle Cooling, when A
service water train was out of service to replace a timing relay per work order 105120, on July 18, 2003. (NCR 98630)
120 volt AC Vital Distribution using Operating Procedure OP-700D, Operation Of
The 120 Volt AC Vital Buses, when inverter VBIT-1E was out of service for
calibration and circuit replacement on September 8, 2003.
b.
Findings
No findings of significance were identified.
.2
Complete System Walkdown: On July 22 and 23, the inspectors conducted a detailed
review of the alignment and condition of the operable B train, emergency core cooling
system, including raw water, decay heat, decay heat removal, and building spray
systems, during a scheduled A train maintenance outage. The inspectors used plant
drawings and procedures, and the operating procedures (OP) and surveillance
procedures (SP) listed below, as well as applicable chapters of the Final Safety Analysis
Report (FSAR), to verify proper system alignment:
4160 ES Bus 3B
Decay Heat Removal System
Reactor Building Spray System
Nuclear Services Cooling System
ECCS And Boration Flow Paths
The inspectors verified selected electrical power requirements, labeling, hangers and
support installation, and associated support systems status. Operating pumps were
examined to ensure that vibration was not excessive, pump leakoff was not excessive,
and the pumps were properly ventilated. The walk downs also included evaluation of
system piping and supports against the following considerations:
Piping and pipe supports did not show evidence of water hammer.
Oil reservoir levels indicated normal.
Snubbers did not indicate any observable hydraulic fluid leakage.
Component foundations were not degraded
3
A review of outstanding maintenance work orders was performed to verify that the
deficiencies did not significantly affect the system function. In addition, the inspectors
reviewed the condition report (CR) database to verify that the systems equipment
alignment problems were being identified and appropriately resolved.
b.
Findings
No findings of significance were identified.
1R05
Fire Protection
a.
Inspection Scope
The inspectors walked down the following risk-significant plant areas to verify that
control of transient combustibles and ignition sources were consistent with the licensees
Fire Protection Plan and 10 CFR Part 50, Appendix R. The inspectors also evaluated
the material condition, operational lineup, and operational effectiveness of fire protection
systems and assessed material condition of fire barriers used to contain fire damage.
The inspections were completed using the standards of the Crystal River Fire Protection
Plan; 10 CFR Part 50, Appendix R; the Florida Power Corporation Analysis of Safe
Shutdown Equipment; and the Final Safety Analysis Report. The inspectors reviewed
sections of OP-880, Fire Service System, and checked performance of SP-802, Fire
Hose Hydrostatic Test, and SP-800, Monthly Fire Extinguisher Inspection, to monitor the
operational condition of fire protection equipment. When applicable, the inspectors
checked that compensatory measures for fire system problems were implemented. The
inspectors observed performance of fire alarm checks done in accordance with
surveillance procedure SP-323, Evacuation and Fire Alarm Demonstration.
Boric Acid Storage Tank Areas
Backup Engineered Safeguards Transformer, Start-up Transformer, Auxiliary
Transformer, and the A, B, and C Step-up Transformer areas
480-Volt Switch Gear Rooms
A and B EDG Engine Rooms and Compressor Rooms
Decay Heat Vaults including decay heat pump and heat exchanger areas
Fire Pump House
- 3 Emergency Feed Pump Building
Auxiliary Intermediate Building and Turbine Building Intermediate Building Roof
area
Main control room
b.
Findings
No findings of significance were identified.
4
1R06
Flood Protection Measures
a
Inspection Scope
The inspectors walked down the turbine and auxiliary building areas, including the decay
heat removal pump vaults, to ensure that flood protection measures were in accordance
with specifications described in the Final Safety Analysis Report. Specific attributes that
were checked included sealing of penetrations between flood areas, operability of
watertight doors, and the operability of the sump pumps. Additional flood protection
checks were done during severe weather preparations and documented in Section
1R01. The inspectors verified that minor deficiencies involving watertight seals and
other flood protection issues were documented in the licensees corrective action
program and corrected.
b.
Findings
No findings of significance were identified.
1R11
Licensed Operator Requalification
a.
Inspection Scope
On July 29, 2003, the inspectors observed licensed operator actions on the plant
specific simulator to Licensed Operator Continuing Training exercise LOR-1-17, Decay
Heat Removal Operations and LOR-1-05, Loss of Decay Heat Removal. The session
involved crew using plant procedures to establish decay heat removal system operations
from a forced circulation - steam dump condition, shifting decay heat removal system
loops of operations, and a response to a complete loss of the decay heat removal
system. The inspectors specifically evaluated the following attributes related to
operating crew performance.
Clarity and formality of communication including crew briefings
Ability to take timely action to safely control the unit
Prioritization, interpretation, and verification of alarms including a loss of decay
heat removal pump alarm
Correct use and implementation of procedures AP-404, Loss of Decay Heat
Removal, and OP-404, Decay Heat Removal System Operation
Control board operation and manipulation, including operator actions such as
establishing decay heat removal system operation from a two reactor coolant
pump operation configuration
Oversight and direction provided by supervision, including ability to identify and
implement appropriate technical specification actions
Effectiveness of the training oversight and critique
b.
Findings
No findings of significance were identified.
5
1R12
Maintenance Effectiveness
a.
Inspection Scope
The inspectors reviewed the planned maintenance activities listed below to evaluate the
licensees implementation of the maintenance rule (10CFR50.65). The inspectors
checked that licensee personnel monitored unavailability of equipment important to
safety and trended key performance parameters. For the equipment issues described
in the work orders (WO) listed below, the inspectors reviewed the licensees
implementation of the Maintenance Rule (10CFR50.65) with respect to the
characterization of failures, the appropriateness of the associated a(1) or a(2)
classifications, and the appropriateness of either the associated a(2) performance
criteria or the associated a(1) goals and corrective actions. The inspectors checked if
the licensee maintained safety functions when equipment important to safety was out of
service for maintenance. The inspectors also periodically reviewed the licensees
implementation of 10 CFR 50, Appendix B and technical specification requirements
regarding safety system problems. The inspectors routinely checked that the licensee
promptly entered problems with plant equipment into the corrective action program or
the corrective maintenance program. The inspectors checked that the licensee
monitored work practices and when appropriate, documented work problems in the
corrective action program.
The inspectors reviewed the goal settings and verified corrective actions had been
completed for the Substation System which had been entered into the maintenance rule
a(1). On August 27, the inspectors attended the Maintenance Rule expert panel
meeting to assess the licensees goal settings on the SW pump and the Control
Complex Chillers which had entered into the maintenance rule a(1) as a result of
unavailability and functional failures, respectively.
NCR 76622, Reactor Trip Due to Opening of the Main Generator Output Breaker
a(1)
NCR 95966, Control Complex Chilled Water System Failures a(1)
NCR 105249, Hi Vibrations on Air Handling Fan AHF-8B a(2)
b.
Findings
No findings of significance were identified.
1R13
Maintenance Risk Assessments and Emergent Work Evaluation
a.
Inspection Scope
The inspectors reviewed the following work risk assessments to assess the
effectiveness of licensees risk assessment and emergent work evaluation in
accordance with plant procedural requirements. The inspectors reviewed daily
maintenance schedules and observed work controls to check risk management while
maintenance was conducted. The inspectors assessed operability of equipment using
technical specifications, the Final Safety Analysis Report, licensee procedures, and
regulatory information such as NRC Generic Letter 91-18, Revision 1, Information to
6
Licensees Regarding NRC Inspection Manual Section on Resolution of Degraded And
Nonconforming Conditions. The inspectors also reviewed maintenance schedules to
check that overall risk was minimized through preservation of safety functions such as
decay heat removal capability, reactor coolant system inventory control, electric power
availability, reactivity control, and primary containment control. The inspectors checked
if licensee personnel were managing risk by assuring that key safety functions were
preserved and that upon identification of an unplanned situation, the resulting emergent
work was evaluated by the licensee for risk and controlled as described in technical
specifications, licensee Compliance Procedure CP-253, Power Operations Risk
Assessment and Management, and Administrative Instruction AI-500, Conduct of
Operations. The inspectors checked that risk significant emergent work was
documented in the corrective action program and that risk management actions were
promptly initiated.
Work Week 03W27, Risk assessment for planned B train ECCS outage revised
for emergent repairs to raw water pump RWP-130 (NCR 98198)
Work Week 03W28, Risk assessment for the EGDG-1A engine surveillance,
revised to repair the EGDG-1B jacket cooling water heater relay after failure
(NCR 98987)
Work Week 03W29, Risk assessment for Emergency Core Cooling System train
outage and piping replacement per clearance 55395 and work order 228448;
Elevated Risk Condition Yellow
Work Week 03W31, Risk assessment for Inspection and Lubrication of auxiliary
steam valve ASV-204, revised when makeup pump MUP-1A was removed from
service to troubleshoot and repair the bearing thermocouople MU-36-TE per
Work Week 03W32, Risk assessment revised when the 1A Control Complex
Chiller failed a post-maintenance test after maintenance had been performed per
work request 222359-01
Work Week 03W35, Risk assessment for planned maintenance on battery
charger DPBC-1B revised when main generator output breaker 1661 opened
and required troubleshooting and repairs (NCR103415)
b.
Findings
No findings of significance were identified.
1R14
Personnel Performance During Non-routine Plant Evolutions
a.
Inspection Scope
For the non-routine event described below, the inspectors observed the activity,
reviewed operator logs and plant computer data to determine that the evolution was
conducted safely and in accordance with plant procedures.
7
Reactor power reduction and withdrawal of Axial Power Shaping Rods (APSR)
completed on August 13, 2003, using operating procedure OP-502A, End of
Cycle APSR Withdrawal and Operations Department Communication 0308-03,
APSR Withdrawal.
b.
Findings
No findings of significance were identified.
1R15
Operability Evaluations
a.
Inspection Scope
The inspectors reviewed the following degraded or nonconforming conditions to
determine if operability of systems or components important to safety was consistent
with technical specifications, the Final Safety Analysis Report, 10 CFR Part 50
requirements, and when applicable, NRC Generic Letter 91-18, Revision 1, Information
to Licensees Regarding NRC Inspection Manual Section on Resolution of Degraded and
Nonconforming Conditions. The inspectors monitored licensee nuclear condition reports
(NCRs), work schedules, and engineering documents to check if operability issues were
being identified at an appropriate threshold and documented in the corrective action
program, consistent with 10 CFR 50, Appendix B requirements, and licensee procedure
NGGC-200, Corrective Action Program. The inspectors checked that when plant
problems were identified, the resulting change in plant risk was identified and managed.
The following issues, including the related nuclear condition reports (NCRs), were
specifically checked:
NCR 97889, Debris Found In The Reactor Building
NCR 98198, Through wall leak in raw water Socket Weld Between Pipe And
Valve RWV-130
NCR 98511, Ultimate Heat Sink Temperature High
NCR103426, Small Leak in service water pipe downstream of service water heat
exchangers
NCR 100231, Service Water Heat Exchanger SWHE-1D, divider plate is
degraded
b.
Findings
No findings of significance were identified.
1R16
Operator Workarounds
a.
Inspection Scope
On July 10, there were four operator work arounds (OWA) listed in the licensee OWA
list. The inspectors reviewed the activities associated with Operator Work Around
(OWA) SCV-23 Temperature Controller, and discussed it in detail with Operations
personnel. The recent work that had been completed in which a new controller had
8
been installed was reviewed with engineering. The planned post maintenance tests
associated with installation of the new controller were reviewed as well. The inspectors
reviewed the OWA list with reactor operators to determine if they were familiar with the
OWA and the required operational activities relating to each OWA.
Cumulative Effects
The inspectors performed a semi-annual evaluation of the potential cumulative effects of
all outstanding OWAs. At the time of the inspection, there were four OWAs. The
inspectors evaluated all outstanding OWAs for their cumulative effects, and discussed
these potential effects with control room supervision and operators. Furthermore, the
inspectors reviewed the current OOS logs and walked down the control room and plant
areas to verify OWAs were being identified and properly entered into the corrective
action program.
b.
Findings
No findings of significance were identified.
1R20
Refueling and Outage Activities
a.
Inspection Scope
The inspectors reviewed the Crystal River Unit 3, Refuel 13 Outage Risk Assessment
for the refueling outage planned to begin on October 3, 2003. The inspectors checked
that the risk assessment was based on the licensees outage schedule and consistent
with licensee requirements in Administrative Instruction AI-504, Guidelines for Cold
Shutdown and Refueling. The inspectors verified that during evolutions identified as
high risk, plans had been established for maintaining key safety functions such as
electrical power, reactivity control, reactor inventory control, and decay heat removal.
The inspectors checked that the risk assessment included industry experience and
previous site-specific problems and had been reviewed by management.
b.
Findings
No findings of significance were identified.
1R23
Temporary Plant Modifications
a.
Inspection Scope
The inspectors reviewed temporary modifications listed below to ensure that they did not
adversely affect the operation of a system that was altered. The inspectors screened
temporary plant modifications for systems that were ranked high in risk for departures
from design basis and for inadvertent changes that could challenge the systems to fulfill
their safety function. The inspectors conducted plant tours and discussed system status
with engineering and operations personnel to check for the existence of temporary
modifications that had not been appropriately identified and evaluated.
9
Engineering Change EC 49716, Reduce flow induced vibration for main steam
safety valves, MSV-33 through 48, by using a clamp to connect adjacent coils of
valve springs
Engineering Change EC 48830, Perform a sealant injection to reduce or
eliminate external leakage from the pressure seal ring of Decay Heat Valve
DHV-4
b.
Findings
No findings of significance were identified.
1RST Post-Maintenance and Surveillance Testing - Pilot
This pilot inspection procedure combines both post-maintenance and surveillance
testing activities.
a.
Inspection Scope
The inspectors observed or reviewed the following post-maintenance and surveillance
testing activities for risk significant systems to check the following (as applicable): (1)
the effect of testing on the plant had been adequately addressed; (2) testing was
adequate for the maintenance performed; (3) acceptance criteria were clear and
demonstrated operational readiness; (4) test instrumentation was appropriate; (5) tests
were performed as written; and (6) equipment was returned to its operational status
following testing. The inspectors evaluated the licensee activities against the technical
specifications, the Final Safety Analysis Report, 10 CFR Part 50 requirements, licensee
procedures, and various NRC generic communications. The inspectors routinely
checked that post maintenance testing and surveillance testing issues were resolved
and documented in the licensees corrective action program.
Inservice test (IST) activities were reviewed to ensure testing methods, acceptance
criteria, and corrective actions were in accordance with the ASME Code,Section XI, and
Florida Power Corporation ASME Section XI, Ten Year Inservice Testing Program,
dated May 4, 1998.
Post- Maintenance Testing
Work Order 339430-01, MUP-1A Radial Inboard Bearing Thermocouple
Replacement, testing of thermocouple and oil leak test
Surveillance Procedure SP-375A, CHP-1 And Valve Surveillance, after
performing preventive maintenance on the 1A Chiller
Surveillance Procedure SP-206, Visual Examination for Leakage, after replacing
raw water spool piece RW-84, including RWV-133 using work order WO 228448
Work Order 456040, data collection and engineering evaluation of vibration
following repair of air handling fan AHF-8B
10
Surveillance Testing
SP-130, Engineered Safeguards Monthly Functional Tests, performed on July 7,
2003
SP-349B, EFP-2 And Valve Surveillance, performed on August 6, 2003 (IST)
SP-363, Fire Protection System Tests, performed on August 6, 2003
SP-521, Quarterly Battery Check for 3B1 and 3B2 Station Batteries performed
on August 25, 2003
b.
Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness (EP)
1EP6
Drill Evaluation
a.
Inspection Scope
On July 23, 2003, the inspectors observed the site emergency response organization
respond to a tabletop scenario of a security threat to the Crystal River Nuclear Plant.
The tabletop was held in the emergency offsite facility, and participants included
representatives of the Federal Bureau of Investigation, Florida Department of Law
Enforcement, Florida Division of Emergency Management, and Citrus County and Levy
County emergency management personnel. During this scenario, the inspectors
assessed the licensees ability to classify an emergent situation, and make timely
notification to state and federal officials in accordance with 10 CFR Part 50.72.
Emergency activities were checked to be in accordance with the Crystal River
Radiological Emergency Response Plan, Section 8.0, Emergency Classification System,
and 10 CFR Part 50, Appendix E.
b.
Findings
No findings of significance were identified.
4.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
.1
Initiating Event and Mitigating Systems Cornerstone
a.
Inspection Scope
The inspectors checked the accuracy of the performance indicators for reactor coolant
system activity and leakage. Performance indicator data submitted from June 2002, to
June 2003, was compared for consistency to data obtained through the review of
chemistry department records, monthly operating reports, and control room records.
Surveillance Procedure SP-317, Reactor Coolant System Water Inventory Balance and
11
Chemistry Department Procedure, CHA-263, Dose Equivalent Iodine were reviewed.
Data gathering using both procedures was monitored. During routine plant tours, the
inspectors checked proper controls for plant personnel exposure and radioactive
releases. The inspectors checked the licensees compliance with station procedure CP-
155, Fuel Integrity Program and Failed Fuel Action Plan.
b.
Findings
No findings of significance were identified.
4OA2 Problem Identification and Resolution
Routine Problem Review
a.
Inspection Scope
The inspectors selected the following nuclear condition report (NCR) for detailed review
and discussion with the licensee. The report was examined to verify whether problem
identification was timely, complete and accurate; safety concerns were properly
classified and prioritized for resolution; technical issues were evaluated and
dispositioned to address operability and reportability; root cause or apparent cause
determinations were sufficiently thorough; extent of condition, generic implications,
common causes, and previous history were adequately considered; and appropriate
corrective actions were implemented or planned in a manner consistent with safety and
technical specification compliance. The inspectors evaluated the report against the
requirements of the licensees corrective action program in Administrative Procedures
CAP-NGGC-0200, Corrective Action Program and 10 CFR 50, Appendix B. Nuclear
Condition Reports 68148 and 68365 involving non-conforming conditions with the
station batteries, the January to June 2003 System Health Report regarding DC Electric
Power System, and the licensees (10 CFR 50.65) maintenance rule event data base
were also reviewed.
Nuclear Condition Report 64202: During performance of surveillance procedure,
SP-522, Station Battery Inspection, the inspection criteria could not be met due
to connection cleanliness and copper contamination
b.
Findings and Observations
There were no significant licensee performance issues or NRC violations identified by
the inspectors regarding the condition report. The inspectors verified that the apparent
cause evaluation and initial corrective actions were appropriate and timely in relation to
the safety significance of the problem. Long term corrective actions were appropriately
planned to maintain system readiness.
12
4OA3 Event Followup
(Closed) Licensee Event Report 05000302/2003-001-00, Incorrectly Set Motor Overload
Relays Result in Loss of Both Control Complex Chillers
a.
Inspection Scope The inspectors reviewed the LER and the associated nuclear
condition report (NCR 95966) to verify that the cause of the June 11, 2003, failure of
both trains of control complex chillers had been identified and that the corrective actions
were reasonable. The failure was caused when technicians incorrectly calibrated the
chiller motor overload relays due to inadequate work instructions. CHHE-1A motor
overload relays had been incorrectly set on February 25, 2003, and CHHE-1B on
December 19, 2002. The two units operated successfully until June 11, 2003, when a
failed component on the 1B chiller initiated a transient that resulted in both machines
being concurrently tripped on overload. Maintenance was required to return the chillers
to operation. The inspectors reviewed the licensees corrective actions described in the
LER, reviewed the nuclear condition report, and discussed the status of continuing
corrective actions with appropriate personnel. Florida Power letter 3F0902-06, License
Amendment Request #271, Revision 1, Revised Improved Technical Specification 3.7.18, for Two Inoperable Control Complex Chillers, dated September 20, 2002, was
used in the inspectors review.
b.
Findings
Introduction: A Green self-revealing finding of TS 3.7.18 was identified for failure to
maintain two operable control complex cooling trains due to incorrectly calibrated chiller
motor overload relays.
Description: The licensee determined that the root cause of the failure of both control
complex chillers was the incorrect calibration of the chiller motor overload relays. The
incorrect calibration was attributed to inadequate work instructions.
Analysis: The inspectors determined that the licensee failed to meet the requirement of
Technical Specification, Limiting Condition for Operability (LCO) 3.7.18, that states:
Two Control Complex Cooling trains shall be operable, when on December 19, 2002,
and February 25, 2003, overload protection relays for CHHE-1B, and CHHE-1A,
respectively were set below the design range. Because the incorrect calibration resulted
in the failure to meet a technical specification requirement and was attributed to
inadequate work instructions, it was a performance deficiency. The finding was greater
than minor because it was associated with the equipment performance attribute of the
mitigating systems cornerstone and affected the cornerstone objective of equipment
reliability. Because the finding involved a loss of safety function for the safety related
control complex cooling system, a Phase 2, Significance Determination was completed
using NRC Manual Chapter 0609, Appendix A. The most dominant core damage
sequences involved plant transients. For this finding, the inspectors assumed that the
Emergency Feedwater Isolation and Control (EFIC) system could be affected by the
loss of room cooling, and further assumed that no loss of emergency feedwater function
would occur because 1) the redundant Appendix R cooling system was available for
alignment to the EFIC control system room coolers, and 2) alternate feedwater was
13
available using either the main feedwater system, or the Feedwater Pump FWP-7
system. The finding was determined to be of very low safety significance (Green).
Enforcement: Technical Specification LCO 3.7.18, requires Two Control Complex
Cooling Trains shall be Operable. A cooling train consists of a chiller, a chill water
pump, and ducting to deliver cooling to safety related areas. Contrary to the above,
following Train B chiller maintenance on December 19, 2002, and Train A chiller
maintenance on February 25, 2003, neither train of control complex cooling was
operable because control complex chiller motor overload relays had been improperly set
below their design values. The problem was identified on June 11, 2003, when both
chiller motors tripped on overload current, when a design overload current condition had
not occurred. The licensee entered Technical Specification 3.0.3, and initiated a plant
shutdown when the problem was found. Maintenance was promptly conducted and the
A train chiller was returned to service on the same day. Chiller CHHE-1B was repaired
and returned to service on June 13, 2003. Because the failure to maintain an operable
control complex cooling train requirement was of very low safety significance and had
been entered into the licensees corrective action program (NCR 95966), this violation is
being treated as a Non Cited Violation (NCV), consistent with Section VI.A of the NRC
Enforcement Policy: NCV 05000302/2003005-01, Failure to Maintain Two Operable
Control Complex Cooling Trains. At the end of the inspection period, in addition to
having returned both trains of equipment to service, the licensee had completed an
extent of condition review and had summarized the occurrence to maintenance
personnel to prevent similar problems. Additional corrective actions were being tracked
in the licensees corrective action program. The LER is closed.
4OA5 Other
(Closed) Unresolved Item (URI)05000302/2002005-01, Failure to Protect One Train of
Safe Shutdown Equipment From Fire Damage in Accordance with Appendix R, Section
III.G.2 (Three Examples)
a.
Inspection Scope
This inspection followed up on URI 05000302/2002005-01, which had been opened for
NRC review of the local manual operator actions for three fire areas. The licensee had
relied on these operator actions instead of physically protecting electrical cables for the
makeup (high pressure injection) and emergency electrical power systems from fire
damage. The URI also described a concern with unprotected cables for a fire service
valve that could potentially degrade the response of the fire brigade. The URI was also
open for NRC review of the overall safety significance of the potential finding.
During this inspection, the inspectors reviewed the potential findings that were described
in the URI and also reviewed the licensees proceduralized local manual operator
actions for the three fire areas of concern for feasibility, using the guidance of NRC
Inspection Procedure 71111.05, Enclosure 2. To accomplish this review, the inspectors
inspected the three fire areas of concern and walked down all of the local manual
operator actions for the three fire areas. The inspectors also reviewed cable routings of
concern in the three fire areas, design information for affected equipment, fire brigade
procedures, and records of previous fire drills in the fire areas of concern. In addition,
14
the inspectors discussed the plant design, procedures, and staffing with licensee
operators and engineers and evaluated the safety significance of identified deficiencies
and findings.
b.
Findings
Introduction. A Green non-cited violation (NCV) of 10 CFR 50, Appendix R,
Section III.G.2, Fire Protection of Safe Shutdown Capability, was identified for failure to
protect certain electrical cables for safe shutdown equipment from fire damage in three
fire areas.
Description. The inspectors identified that the licensee had failed to protect certain
electrical cables, for equipment that was relied upon for safe hot shutdown, from fire
damage. The affected equipment included:
Electrical control cables for makeup system motor-operated valves (MOVs)
MUV-23, -24, -25, and -26 (which were in parallel in the required flowpath) were
not protected from fire damage in fire areas CC-108-102 [hallway and remote
shutdown room on the 108 foot elevation of the control complex] and CC-108-
107 [3B 4160 volt engineered safeguard switchgear room on the 108 foot
elevation of the control complex]. At least one of these valves should have been
protected from fire damage because one was needed to establish and maintain
a makeup flowpath to the reactor coolant system (RCS) for safe hot shutdown.
Electrical control cables for makeup pump (MUP) 1A, 1B, and 1C were not
protected from fire damage in fire area CC-108-106 [battery charger room 3A on
the 108 foot elevation of the control complex]. MUP 1C should have been
protected as it was relied upon, per the licensees safe shutdown analysis and
procedures, to supply makeup to the RCS for safe hot shutdown.
Electrical control cables for MUP flow recirculation MOVs MUV-53 and MUV-257
(which were in series in the required flowpath and affected all three MUPs) were
not protected from fire damage in fire areas CC-108-102 and CC-108-107,
respectively. Both valves should have been protected from fire damage to
ensure that the MUP minimum flow recirculation flowpath would be available as
needed for safe hot shutdown.
After reviewing the potential effects of cable damage due to fire, the system design, and
the operating procedures, the inspectors found that even with these unprotected
electrical cables and some deficient operator actions, licensee procedures and training
would have enabled operators to maintain the makeup function as needed for safe
shutdown following a fire in fire areas CC-108-102, -106, or -107. [The deficient
operator actions involved locally manually repositioning MOVs that were vulnerable to
spurious actuations and failing to open the power supply breakers to the MOVs, leaving
the MOVs still vulnerable to spurious actuations.] The inspectors evaluated that with the
proceduralized operator actions, the makeup function would have been sufficient to
maintain reactor coolant system process variables within acceptable ranges. The
inspectors also noted that the licensee had corrected all of the identified deficient
operator actions in the current revision of the procedure. In addition, the licensee
15
planned to resolve the noncompliance with cable protection through licensing
correspondence with the NRC. These factors limited the safety significance of the
licensees failure to physically protect the cable from fire damage as required by 10 CFR 50, Appendix R,Section III.G.2.
The inspectors determined that some other concerns described in the URI should not be
considered as findings, as described below:
Electrical cables for emergency diesel generators (EDGs) 1A and 1B were not
protected from fire damage in fire area CC-108-106; however, the licensees
safe shutdown analysis and procedures did not rely on the EDGs. The licensee
had determined that offsite power would not be affected by a fire in fire area CC-
108-106 and would be available for safe shutdown. Inspector review of selected
electrical circuits did not identify any flaws in the licensees determination that
offsite power would be unaffected by the fire.
Electrical cables for fire service valve FSV-257 were not protected from fire
damage in the fire areas of concern. The inspectors verified that this could delay
the fire brigade by about three minutes in pressurizing a fire hose from a fire
station in the control building. However, by procedure and also by actual
practice during fire drills, the fire brigade brought a second fire hose that would
be pressurized from the turbine building. That hose would be unaffected by
FSV-257. Since the fire brigade needed only one hose, they would not be
delayed by damage to FSV-257 cables. The inspectors verified that the hose
from the turbine building, plus an additional 50 feet of hose from the fire brigade
cart, would provide sufficient length and water pressure to fight fires in all of the
fire areas of concern. The inspectors also verified that fire brigade response
time during drills was less than the acceptance criteria, such that a three-minute
delay to locally manually open FSV-257 would not result in the fire brigade being
considered degraded.
Analysis. The inspectors determined that the licensees failure to protect the electrical
cables for certain makeup system components from fire damage was a performance
deficiency because the licensee failed to comply with the requirements of 10 CFR 50, Appendix R,Section III.G.2. This finding is greater than minor safety significance
because it involved a lack of required fire barriers for equipment relied upon for safe
shutdown following a fire and because it affected the objectives of the Mitigating
Systems Cornerstone of Reactor Safety. The finding affected the availability and
reliability of systems that mitigate initiating events to prevent undesirable consequences.
The inspectors determined that manual actions are reasonably accomplishable and
licensee procedures and training would have enabled operators to maintain the makeup
function sufficiently to maintain reactor coolant system process variables within
acceptable ranges. Therefore, the inspectors identified this issue as a Green finding as
described in Inspection Procedure 71111.05, Fire Protection.
Enforcement. 10 CFR 50, Appendix R,Section III.G.2 requires in part that where cables
or equipment, that could prevent operation or cause maloperation due to hot shorts,
open circuits, or shorts to ground, of redundant trains of systems necessary to achieve
and maintain hot shutdown conditions are located within the same fire area outside of
16
primary containment, one of the following means of ensuring that one of the redundant
trains is free of fire damage shall be provided: a) physical protection by a three-hour fire
barrier, b) physical protection by a separation of more than 20 feet, with no intervening
combustibles or fire hazards, plus fire detectors and automatic suppression, or c)
physical protection by a one-hour fire barrier plus fire detectors and automatic
suppression.
Contrary to the above, the licensee failed to protect cables that could prevent operation
or cause maloperation due to hot shorts, of redundant trains of systems necessary to
achieve and maintain hot shutdown conditions, from fire damage by one of the
prescribed methods. This nonconforming design was identified by NRC inspectors in
July 2002 and had been in existence for years. Because this failure to protect cables is
of very low safety significance and has been entered into the licensees corrective action
program as Non-Conformance Report (NCR) No. 061781; this violation is being treated
as an NCV, consistent with Section VI.A of the NRC Enforcement Policy: NCV 0500302/2003005-02, Failure to Protect One Train of Safe Shutdown Equipment From
Fire Damage.
4OA6 Meetings, Including Exit
Exit Meeting Summary
The fire protection specialist inspectors presented their inspection results (Section
4OA5) to Mr. D. Young and other members of the licensees staff on September 12,
2003. The licensee acknowledged the findings presented. Proprietary information is
not included in the inspection report.
The resident inspectors presented the inspection results to Mr. Young and other
members of licensee management at the conclusion of the inspection on September 29,
2003. The inspectors asked the licensee whether any of the material examined during
the inspection should be considered proprietary. The licensee did not identify any
proprietary information.
4OA7 Licensee Identified Violation
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 Non-Cited
Violation.
Crystal River 3 Technical Specification 5.6.1, requires that the procedures
recommended in Regulatory Guide 1.33, Revision 2, Appendix A, be implemented. The
regulatory guide, in Paragraph 9.a, specifies procedures for performing maintenance on
safety related equipment. Crystal River 3, Work Order 456040 required for the post-
maintenance test on safety-related air handling fan, AHF-8B, vibration analysis by
engineering. Contrary to the above, on September 23, 2003, AHF-8B was returned to
service following maintenance under Work Order 456040, without completion of
vibration analysis by engineering. Instead, engineering evaluated the running AHF-8A
and reported the results to plant operators. The discrepancy was identified during the
17
next operations shift turnover, plant status review. The vibration analysis was then
conducted the same day, and when evaluated, it was determined to be unsatisfactory
for vibrations and re-work was authorized. The finding was of very low safety
significance because it was identified within a few hours of occurrence and the
redundant fan, AHF-8A, remained available. There was no actual safety consequence.
The occurrence is documented in the licensee corrective action program as NCR
105249.
Attachment
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee personnel:
J. Huegel, Acting Manager, Operations
S. Bernhoft, Supervisor, System Engineering
W. Brewer, Manager, Work Controls
R. Davis, Manager, Training
J. Franke, Plant General Manager
J. Kreuhm, Manager, Maintenance
D. Roderick, Director Site Operations
S. Glenn, Supervisor, Corrective Actions Program
S. Powell, Supervisor, Licensing
M. Rigsby, Radiation Protection Manager
J. Stephenson, Supervisor, Emergency Preparedness
J. Terry, Manager, Engineering
R. Warden, Manager, Nuclear Assessment
D. Young, Vice President, Crystal River Nuclear Plant
S. Young, Security Manager
NRC personnel:
J. Munday. Chief, Reactor Projects Branch 3, NRC Region II
J. Riveria-Ortiz, NRC Intern
LIST OF ITEMS OPENED AND CLOSED
Opened and Closed
Failure to Maintain Two Operable Control Complex
Cooling Trains (Section 4OA3)05000302/2003005-02
Failure to Protect One Train of Safe Shutdown
Equipment From Fire Damage (Section 4OA5)
Closed
Failure to Protect One Train of Safe Shutdown
Equipment From Fire Damage in Accordance with
Appendix R,Section III.G.2 (Three Examples)
(Section 4OA5)
05000302/2003-001-00
LER
Incorrectly Set Motor Overload Relays Result in
Loss of Both Control Complex Chillers (Section
4OA3)
2
LIST OF DOCUMENTS REVIEWED
Section 4OA5, Other
Procedures
AR-801, Fire System Annunciator Response, Rev. 17
AP-880, Fire Protection, Rev. 15
AP-880, Fire Protection, Rev. 19
Emergency Plan Implementing Procedure, EM-216, Duties of the Fire Brigade, Rev. 23
OP-880A, Appendix R Post-Fire Safe Shutdown Information, Rev. 0
OP-880A, Appendix R Post-Fire Safe Shutdown Information, Rev. 3
Drawings
E-213-013, 10 CFR 50 Appendix R Protected Raceways, Control Complex El. 108-0, Rev. 13
FD-302-661, Make-up & Purification, Sheet 2 of 5, Rev. 74
FD-302-661, Make-up & Purification, Sheet 3 of 5, Rev. 76
FD-302-661, Make-up & Purification, Sheet 4 of 5, Rev. 76
Analyses and Calculations
Crystal River Unit 3 Fire Hazards Analysis, Rev. 11
Crystal River 3 Individual Plant Examination of External Events, Rev. 1