IR 05000338/2003010
| ML033220570 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 11/18/2003 |
| From: | Ogle C NRC/RGN-II/DRS/EB |
| To: | Christian D Virginia Electric & Power Co (VEPCO) |
| References | |
| IR-03-010 | |
| Download: ML033220570 (23) | |
Text
ber 18, 2003
SUBJECT:
NORTH ANNA POWER STATION - NRC SAFETY SYSTEM DESIGN AND PERFORMANCE CAPABILITY INSPECTION REPORT NOS.
05000338/2003010 AND 05000339/2003010
Dear Mr. Christian:
On October 24, 2003, the Nuclear Regulatory Commission (NRC) completed a safety system design and performance capability inspection at your North Anna Power Station, Units 1 and 2.
The enclosed report documents the inspection findings which were discussed on October 24, 2003, with Mr. D. Heacock and other members of your staff.
This inspection was an examination of activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations, and with the conditions of your operating license. Within these areas, the inspection involved selected examination of procedures and representative records, observations of activities, and interviews with personnel.
Based on the results of the inspection, no findings of significance were identified.
In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Charles R. Ogle, Chief Engineering Branch 1 Division of Reactor Safety Docket Nos.: 50-338, 50-339 License Nos.: NPF-4, NPF-7
Enclosure:
(See page 2)
VEPCO 2 Enclosure: NRC Inspection Report Nos. 05000338/2003010, 05000339/2003010 w/Attachment: Supplemental Information
REGION II==
Docket Nos.: 50-338, 50-339 License Nos.: NPF-4, NPF-7 Report Nos.: 05000338/2003010 and 05000339/2003010 Licensee: Virginia Electric and Power Company (VEPCO)
Facility: North Anna Power Station, Units 1 & 2 Location: 1022 Haley Drive Mineral, Virginia 23117 Dates: October 6 - 10, 2003 October 20 - 24, 2003 Inspectors: N. Merriweather, Senior Reactor Inspector (Lead Inspector)
F. Jape, Senior Project Manager G. Laska, Operations Engineer K. Maxey, Reactor Inspector R. Moore, Senior Reactor Inspector C. Smith, Senior Reactor Inspector Accompanied by: J. Moorman, Team Leader, Region II N. Staples, Reactor Safety Intern, Region II Approved by: Charles R. Ogle, Chief Engineering Branch 1 Division of Reactor Safety Enclosure
SUMMARY OF FINDINGS
IR 05000338/2003-010, IR 05000339/2003-010; 10/06-10/2003 and 10/20-24/2003; North Anna
Power Station, Units 1 and 2; Safety System Design and Performance Capability Inspection.
This inspection was conducted by a team of regional inspectors. No findings of significance were identified. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.
NRC-Identified and Self-Revealing Findings
No findings of significance were identified.
Licensee-Identified Violations
None.
REPORT DETAILS
REACTOR SAFETY
Cornerstones: Initiating Events and Mitigating Systems
1R21 Safety System Design and Performance Capability
This team inspection reviewed selected components and operator actions that would be used to prevent or mitigate the consequences of a steam generator tube rupture (SGTR) event. Components in the main steam (MS) system, auxiliary feedwater (AFW)system, steam generator (SG) blowdown system, chemical and volume control system (CVCS), reactor coolant system (RCS), safety injection (SI) system, and radiation monitoring (RM) system were included. This inspection also examined supporting equipment, equipment which provides power to these components, and the associated instrumentation and controls. The SGTR event is a risk-significant event as determined by the licensees probabilistic risk assessment.
.1 System Needs
.11 Process Medium
a. Inspection Scope
The team reviewed the water sources for components and systems required for the mitigation of the SGTR event. These included the Reactor Water Storage Tank (RWST) and its refill capability, Volume Control Tank (VCT), and Emergency Condensate Storage Tank (ECST). The team reviewed the availability, reliability and adequacy of the water sources with respect to the anticipated water source requirements for the SGTR event. The team reviewed design criteria information, drawings, vendor manuals, and calculations to determine the minimum water levels for pump net positive suction head (NPSH) and tank volume to verify that the design and Updated Final Safety Analysis Report (UFSAR) accident analysis assumptions were consistent with system and equipment capability.
In addition to the above, the team reviewed calibration procedures and calibration records for the level instruments used on the CST, RWST, and VCT to verify that the procedures accurately incorporated set point values delineated in calculations of record.
b. Findings
No findings of significance were identified.
.12 Energy Sources
a. Inspection Scope
The team reviewed the air supply for pneumatically operated valves used to mitigate the SGTR event. The team reviewed the availability and reliability of the air supply as well as quality controls for the air system. The team reviewed valve design drawings, vendor manuals, and periodic air quality test results to verify that station air quality standards were consistent with vendor recommendations, regulatory guidance, and industry standards. Periodic tests which verified the air supply capacity of the assured air supply flasks for the SG power operated relief valves (PORVs) were reviewed.
The team reviewed the adequacy of voltage supplied to a select sample of pump motors and motor operated valves (MOVs) required to mitigate a SGTR event. The team performed a design review for probable common cause failure modes of MOVs that would result from inadequate equipment utilization voltage. The team reviewed design basis documents, calculations of record, vendor information, and approved design output drawings for the Unit 1 Class 1E 4160 volt alternating current (VAC) and 480 VAC electrical distribution system. The team reviewed electrical and mechanical calculations to verify the capability of selected Generic Letter (GL) 89-10 MOVs to perform their design function under steady state degraded voltage conditions and transient voltage starting conditions. The team reviewed the analysis of the Class 1E electrical distribution system to verify that sufficient starting and running voltages exist at the 4160 VAC and 480 VAC emergency busses to operate such loads as the high and low head safety injection pump motors, the residual heat removal (RHR) pump motors, the AFW pump motors, and the service water pump motors.
b. Findings
No findings of significance were identified.
.13 Instrumentation and Controls
a. Inspection Scope
The team reviewed electrical elementary diagrams in order to verify that the electrical controls and instrumentation systems required to mitigate a SGTR event operated in accordance with design bases document descriptions and were consistent with the UFSAR description. The team reviewed the controls for the centrifugal charging pumps (CCPs), the AFW pumps, the residual heat removal pumps, and selected MOVs associated with operation of these pumps. A review and evaluation of electrical elementary diagrams for selected radiation monitors was also performed in order to verify the equipment operating logic and to identify the sources of the power supplies.
The team reviewed surveillance procedures and calibration test records for process instrument channels monitoring SG narrow range and wide range level, SG pressure, SG flow, RCS pressure, pressurizer level, RCS temperature, CST low water level, and radiation monitors to verify that actions were prescribed consistent with the instrument design including setpoint documents.
b. Findings
No findings of significance were identified.
.14 Operator Actions
a. Inspection Scope
The team reviewed plant operating procedures, including emergency operating procedures (EOPs), abnormal operating procedures (APs), and annunciator responses (ARs) that would be used in the identification and mitigation of a SGTR event. The team reviewed the procedures to verify that they were written clearly and unambiguously, and were technically adequate. The procedures were also reviewed for consistency with the UFSAR description of a SGTR event and the Westinghouse Owners Group Emergency Response Guidelines. The step deviations identified from the Westinghouse Owners Group Emergency Response Guidelines were reviewed to verify that they were justified and reasonable.
The team conducted discussions with licensed operators and reviewed job performance measures and training lesson plans pertaining to SGTR events to ensure that training was consistent with the procedures. In addition, the team observed a simulator scenario of a SGTR event to verify that operator training and procedural guidance were adequate to identify a SGTR event and implement post-event mitigation strategies. The operator action times for performance of SGTR event mitigation activities were compared to the times assumed in the accident analysis.
b. Findings
No findings of significance were identified.
.15 Heat Removal
a. Inspection Scope
The team reviewed the reliability and availability of cooling for equipment required to mitigate the SGTR event. This included cooling water to AFW pumps, SI pumps, and CCPs. The team reviewed vendor manuals, design documentation, drawings, and surveillance and test procedures to verify the vendor recommendations for equipment operation were satisfied.
The team reviewed operator actions that may have to be performed to assure that adequate heat removal capability would be available to mitigate a SGTR event.
Examples of procedures reviewed included those for refilling of the RWST and placing the RHR system in service.
b. Findings
No findings of significance were identified.
.2 System Condition and Capability
.21 Installed Configuration
a. Inspection Scope
The team performed field inspections of accessible SGTR mitigation mechanical equipment in AFW, CVCS, MS, SI, and SG blowdown systems to assess general material condition, identify degraded conditions, and verify the installed configuration was consistent with design drawings and design inputs to calculations. Additionally, the team assessed potential flooding and missile impacts on SGTR mitigation equipment.
The team also performed field inspections of portions of the Class 1E electrical distribution system, including 4160 VAC switchgear, 480 VAC load centers, 480 VAC MCCs, and 125 volts direct current batteries. The team also inspected selected radiation monitoring installations used to mitigate a SGTR event and vital bus Inverters 1-I and 1-II.
The team examined the material condition of the level instruments on the CST and the protection and routing for redundant sensing lines. This review was performed to verify that the observable material condition was acceptable and that redundant instrumentation sensing lines were adequately routed and protected to prevent common cause failure of the instruments.
b. Findings
No findings of significance were identified.
.22 Operation
a. Inspection Scope
The team reviewed operating procedures, system lineups, system drawings and walked down selected portions of the MS, AFW, CVCS, SI, RM, instrument air, and electrical power systems to verify that system alignments were consistent with design and licensing basis assumptions.
The team performed walkdowns of selected tasks to verify that human factors in the procedures and in the plant (e.g., clarity, lighting, noise, accessibility, labeling) were appropriate to support effective use of the procedures. Specifically, the team walked down procedure performance, with radiological control technicians and chemistry personnel, that would be used to help operators identify the SG involved in the SGTR event; and walked down, with an operator, the EOP requirement to manually operate a SG PORV on the intact SGs by manually opening the appropriate valves.
In addition, the team reviewed the operator work-around program to ensure that degraded equipment conditions, that could adversely impact control room operators during a SGTR event, were properly identified and prioritized. The team also reviewed the licensees adverse weather program to assess the protection against adverse weather for significant structures, systems, and components used in the mitigation of a SGTR event.
b. Findings
No findings of significance were identified.
.23 Design
a. Inspection Scope
Mechanical Design The team reviewed mechanical design calculations, specifications, and the UFSAR accident analysis to identify the design criteria which defined the required capacity and capability of SGTR mitigation mechanical equipment. Surveillance test procedures and equipment monitoring activities were also reviewed to verify the design criteria were appropriately translated into acceptance criteria. The team reviewed NPSH calculations for the AFW, and charging pumps to verify that adequate NPSH was available from each of the applicable water sources. Design changes were reviewed to verify that system and equipment design functions were appropriately evaluated and maintained.
Design changes reviewed included replacement of charging pump casings, heads and seal housings; replacement of a turbine driven AFW pump recirculation flow orifice; a SG blowdown system upgrade; and replacement of main steam safety valve (MSSV)mounting bolts.
Electrical, Instrumentation and Controls Design The team reviewed excerpts from calculations of record and approved design output drawings of Unit 1 Class 1E 4160 VAC and 480 VAC electrical distribution systems, and conducted discussions with the licensees engineering personnel, in order to verify that the degraded voltage relay setpoint values of voltage magnitude and time delays were consistent with values incorporated in the North Anna Technical Specifications for Units 1 and 2. Calculation EE-0373, 4.16 KV Degraded Voltage and Loss of Voltage Relay Safety Limits, demonstrated that negative voltage margin could exist at the 480 V buses during both non-accident and accident conditions. The effects of the negative voltage margin at the 480 V buses on the operation of GL 89-10 MOVs, was reviewed and evaluated by the inspectors. Additionally, the inspectors discussed this issue with the licensees engineering staff. The inspectors also reviewed engineering transmittal ET CEE 98-0019, Revision 1, Voltage Profile Analysis North Anna Power Station, Units 1 and 2, and discussed the increase in 4160 V motor slip caused by the motors having less than nominal terminal voltage under certain conditions. The analysis concerning the capability of risk significant 4160 V motors and 480 V MOVs to perform their design function, addressed in the engineering transmittal under degraded voltage conditions, was evaluated by the inspectors.
The team reviewed design changes that the licensee made to the 120 VAC Vital Bus inverters for Unit 1. A review and evaluation of Design Change 01-159, was performed to verify that replacement of the 20KVA Inverter 01-VB-INV-01, and 15KVA Inverter 01-VB-INV-02, was consistent with design and licensing basis requirements. The scope of the review included an evaluation of the replacement inverters KVA ratings, the voltage and frequency specification for the inverters output, and the required value of the DC input power supply voltage range. The battery sizing calculation was reviewed to verify the capability of the class 1E 125 VDC batteries to support the inverter loads.
The team reviewed instrument setpoint calculations for radiation monitoring instruments and selected level instrument channels to verify that plant instrument calibration procedures have accurately incorporated setpoint values delineated in the calculations of record.
The team reviewed calculations of record and motor vendor information for selected 4160 VAC pump motors to verify that they were adequately sized with positive margin based on the actual mechanical load demand. The team reviewed pump performance curves in order to determine the mechanical load demand and required motor break horsepower (BHP) rating. Additionally, the team reviewed the licensees analysis of the emergency diesel generator loads to verify that it correctly incorporated the identified BHP values for the pump motors. The team also reviewed motor load current data taken during pump surveillance tests for selected 4160 V class 1E motors to verify that the motors were operating satisfactorily within design requirements.
b. Findings
No findings of significance were identified.
.24 Testing and Inspection
a. Inspection Scope
The team reviewed valve stroke time testing, MOV torque and limit switch settings, and post maintenance testing to verify that the tests and inspections were appropriately verifying that the assumptions of the licensing and design bases were being maintained and that performance degradation would be identified. The team also reviewed calibration test records for selected radiation monitors to verify that acceptance criteria specified in the procedures were met.
The team reviewed records of completed surveillance tests, preventive maintenance, and inspections, that were performed for Unit 1 Station Batteries. The reviews were performed in order to verify that battery related problems were being adequately corrected, and that the capacity of the 125 VDC class 1E batteries was adequate to supply and maintain the required emergency loads during a design basis accident. The team conducted interviews with licensee engineering personnel and reviewed selected plant procedures to verify that accepted industry practices and the requirements of the Technical Specifications had been correctly incorporated in the plant procedures.
The team reviewed the records of the Unit 1 motor driven AFW pump and valve surveillance test, and the combined CCP 1B head verification and high head safety injection branch flow verification. The reviews were performed to verify that operability of the equipment had been demonstrated and that the requirements of the Technical Specifications were being met.
b. Findings
No findings of significance were identified.
.3 Selected Components
.31 Component Degradation
a. Inspection Scope
The team reviewed inservice test program trending data, maintenance and testing documentation, calibration records, work orders, plant issue reports, and deviation reports to assess the licensees actions to verify and maintain the safety function, reliability and availability of selected components. The Maintenance Rule functional failures of selected components for the past 5 years were also reviewed. Additionally, the team reviewed potential common cause failure mechanisms due to flooding, maintenance, parts replacement and modifications. Examples of components reviewed included MOVs, air operated valves, relief valves, check valves, radiation monitors, and pumps. A list of components reviewed is included in the Attachment.
b. Findings
No findings of significance were identified.
.32 Equipment/Environmental Qualification
a. Inspection Scope
The team reviewed environmental specifications and test reports for VCT level transmitters to verify that the instruments were suitable for their application.
b. Findings
No findings of significance were identified.
.33 Equipment Protection
a. Inspection Scope
The team reviewed the freeze protection provision for the RWST instrument lines to verify the system was adequately monitored and maintained to protect vulnerable piping.
For SG PORVs, MSSVs, turbine driven AFW pumps, and CCPs, the team reviewed the equipment specifications to verify the design was adequate for anticipated ambient conditions and system application.
b. Findings
No findings of significance were identified.
.34 Operating Experience
a. Inspection Scope
The team reviewed the licensees applicability evaluations and corrective actions for industry experience issues related to turbine driven AFW pumps, MOVs, check valves, and instrument air system failures. The team also reviewed the licensees evaluations of operating experience reports applicable to the SGTR event to verify that applicable insights from those reports had been applied to the appropriate components.
The team specifically reviewed the following events:
- N-2003-3475, Steam Generator Tube Degradation at Diablo Canyon.
- N-2003-3165-E1, Steam Generator Sludge Lance Tube Wear
- IN 03-05, Failure To Detect Freespan Cracks in PWR Steam Generator Tubes.
- OE 15901, Steam Generator Sludge Lance Damage to U-Tubes
- IN 02-21-SI, Axial Outside-Diameter Cracking Affecting Thermally Treated Alloy 600 Steam Generator Tubing
b. Findings
No findings of significance were identified.
.35 Steam Generator Inservice Inspection
a. Inspection Scope
The team performed a limited-scope review of the inservice inspection program for the SGs to verify that SG tubes were being inspected as required by Technical Specifications and procedures. The periodic self assessment of the SG monitoring and inspection program, as described in NEI 97-06, was reviewed to verify the assessment covered all of the objectives of the self-assessment plan.
b. Findings
No findings of significance were identified.
.36 Foreign Material Exclusion (FME) Control Program And Loose Parts Monitoring
a. Inspection Scope
The team reviewed procedural guidelines and performance records for the loose parts monitoring system to verify that these systems were operational and were being used to monitor for loose parts in the RCS. In addition, the team reviewed records of foreign material control activities to verify that this program was being utilized. The documents reviewed were:
- VPAP-1302, Foreign Material Exclusion Program, Revision 18
- ICP-1-VLPM-1, Vibration and Loose Parts Monitor, Revision 19
- 1-PT-28, Vibration and Loose Parts Monitoring Functional (ITS-Channel Operational) Test, Revision 011
- SEAP-0002, Shift Technical Advisor, Revision 7
- FSAR Section 5.2.5.3, Loose Parts Monitoring, Revision 39
b. Findings
No findings of significance were identified.
.4 Identification and Resolution of Problems
a. Inspection Scope
The team reviewed selected system health reports, maintenance records, work-around list, surveillance test records, calibration test records, and plant issue reports to verify that design problems were identified and entered into the corrective action program. The team reviewed plant issue reports related to selected SGTR mitigation equipment to assess the scope of the licensees extent-of-condition reviews and the adequacy of the corrective actions.
b. Findings
No findings of significance were identified.
OTHER ACTIVITIES
40A6 Meetings, Including Exit The lead inspector presented the inspection results to Mr. D. Heacock, and other members of the licensee staff, at an exit meeting on October 24, 2003. The licensee acknowledged the findings presented. Proprietary information is not included in this inspection report.
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- J. Davis, Director, Station Operations and Maintenance
- D. Heacock, Site Vice President
- J. Leberstien, Supervisor, Licensing
- B. Morrison, Supervisor, Nuclear Engineering
- A. Royal, Manager, Nuclear Training
- J. Scott, Supervisor, Nuclear Training - Operations
- W. Shura, Supervisor, Nuclear Training - Technical Support
- B. Standley, Supervisor Nuclear Engineering
- M. Whalen, Supervisor Licensing
NRC (attended exit meeting)
- J. Moorman, Team Leader, NRC Region II
- M. Morgan, Senior Resident Inspector
LIST OF ITEMS
OPENED, CLOSED AND DISCUSSED
None.