IR 05000338/2001005
| ML021210558 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 04/25/2002 |
| From: | Landis K NRC/RGN-II/DRP/RPB5 |
| To: | Christian D Virginia Electric & Power Co (VEPCO) |
| References | |
| 05000338/01-05, 05000339/01-05 | |
| Download: ML021210558 (25) | |
Text
April 25, 2002
SUBJECT:
NORTH ANNA POWER STATION - NRC INTEGRATED INSPECTION REPORT NOS. 50-338/01-05 AND 50-339/01-05
Dear Mr. Christian:
On March 30, 2002, the NRC completed an inspection at your North Anna Power Station, Units 1 and 2. The enclosed report documents the inspection findings which were discussed on April 10, 2002, with Mr. D. Heacock 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 selective procedures and records, observed activities, and interviewed personnel.
No findings of significance were identified.
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//
Kerry D. Landis, Chief Reactor Projects Branch 5 Division of Reactor Projects Docket Nos.: 50-338, 50-339 License Nos.: NPF-4, NPF-7
Enclosures:
NRC Integrated Inspection Reports Nos. 50-338/01-05, 50-339/01-05
REGION II==
Docket Nos.:
50-338, 50-339 License Nos.:
50-338/01-05, 50-339/01-05 Licensee:
Virginia Electric and Power Company (VEPCO)
Facilities:
North Anna Power Station, Units 1 & 2 Location:
1022 Haley Drive Mineral, Virginia 23117 Dates:
December 30, 2001 through March 31, 2002 Inspectors:
M. Morgan, Senior Resident Inspector J. Canady, Resident Inspector R. Aiello, Senior Operations Engineer, RII (Section 1R11.1)
B. Crowley, Senior Reactor Inspector, RII (Section 4OA5.1)
Gerard Laska, Operations Engineer, RII (Section 1R11.1)
Approved by:
K. Landis, Chief, Reactor Projects Branch 5 Division of Reactor Projects Attachment:
Supplemental Information
SUMMARY OF FINDINGS IR 05000338-01-05, IR 05000339-01-05, on 12/30/01-03/30/2002, Virginia Electric and Power Co., North Anna Power Station Units 1 & 2. Resident Inspector Integrated Report.
The inspection was conducted by the resident inspectors and regional senior reactor inspector, senior operations engineer and operations engineer. No findings of significance were identified. The significance of findings is indicated by their color (Green, White, Yellow, Red)
using IMC 0609 Significance Determination Process (SDP). Findings for which the SDP does not apply are indicated by No Color or by the severity level of the applicable violation. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described at its Reactor Oversight Process website at http://www.nrc.gov/NRR/OVERSIGHT/ASSESS/index.html.
A.
Inspector Identified Findings None B.
Licensee Identified Violations None
Report Details Summary of Plant Status Unit 1 and Unit 2 began the inspection period at 100% power and operated at or near this power level for the remainder of the inspection period.
1.
REACTOR SAFETY Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity 1R04 Equipment Alignment a.
Inspection Scope The inspectors performed partial walkdowns of systems, structures, and components (SSC) to determine if they were correctly aligned in accordance with appropriate procedures and drawings. The partial walkdowns were performed on a redundant train/system while the other was out of service. The following SSCs were assessed for their correct alignment:
2A Service Water Pump, (0-OP-49.1A, Valve Checkoff - Service Water);
Unit 1 Boric Acid Tanks and Transfer Pumps, (1-OP-8.3A, Valve Checkoff -
Chemical and Volume Control System-Boric Acid Transfer, and plant drawing 11715-FM-095A); and,
Unit 2A Component Cooling Water Subsystem, (1-OP-51.1A, Valve Checkoff -
Component Cooling Water-Auxiliary Building, Fuel Building, Decontamination Building, and Main Steam Valve House, and plant drawing 11715-FM-079A).
b.
Findings No findings of significance were identified.
1R05 Fire Protection a.
Inspection Scope The inspectors assessed the implementation of the fire protection program using NAPS Appendix R Report and Virginia Power Administrative Procedure (VPAP)-2401, Fire Protection Program. The inspectors checked the control of transient combustibles and the material condition of the fire detection and fire suppression systems in the following areas:
Unit 1 and Unit 2 Emergency Diesel Generator Rooms;
Unit 1 Motor Driven and Turbine Auxiliary Feedwater House Areas;
Unit 1 and Unit 2 Vital Battery Rooms (1-I/1-III and 2-I/2-III respectively);
Unit 1 and Unit 2 Vital Battery Rooms (1-II/-IV and 2-II/2-IV respectively);
Unit 1 Cable Vault and Tunnel areas; and,
Unit 2 Cable Vault and Tunnel areas.
b.
Findings No findings of significance were identified.
1R11 Licensed Operator Requalification
.1 Biennial Review a.
Inspection Scope The inspectors reviewed the facility operating history since the last requalification program inspection for indications of licensed operator performance weaknesses. The inspectors also reviewed the previous biennial written examinations for two crews and evaluated their effectiveness in providing a basis for assessing operator knowledge of material covered in the requalification training program. Examination quality, licensee effectiveness in integrating industry, plant and student feedback into the requalification training program, and examination development methodology were evaluated as well.
The inspectors observed annual dynamic simulator examinations (three scenarios) for two operator teams to assess the adequacy of the licensees evaluation of operator knowledge and abilities. During these observations, the inspectors assessed licensee evaluator effectiveness in pinpointing operator performance deficiencies requiring supplemental training. The inspectors also evaluated and observed portions of the walkthrough examination administered during this requalification segment to assess evaluator performance.
The inspectors reviewed and evaluated the licensees remedial training program for operator deficiencies identified during the previous year. The inspectors also reviewed a sample of on-shift licensed operator qualification records, watchstanding records and medical records to ensure compliance with 10CFR 55.59, Requalification and 10CFR 55.53, Conditions of License. The following items were also reviewed as part of the inspection effort:
North Anna Training Center, FIG 04, Develop Evaluation Components, Licensed Operator Requalification (LORP);
North Anna Training Center, FIG 09, Administer the LORP Exam banks, Licensed Operator Requalification (LORP);
North Anna Annual Written Examination for the past Exam Cycle; and,
North Anna Annual Operating Examination for Current Exam Cycle.
b.
Findings No findings of significance were identified.
.2 Resident Review a.
Inspection Scope On March 27, the inspectors observed the C shift operators and supervisors during sessions of simulator training. The training sessions involved the following: 1) a simulated gas binding of the seal water return heat exchanger line and the subsequent activities to bypass the line, 2) a simulated loss of the number 2B reactor coolant pump seal during plant shutdown, and 3) a loss of the B automatic feedwater regulating valve during the final stages of the plant shutdown. The inspectors assessed the use of three-way communications, crew command and control, and the use of the phonetic alphabets.
b.
Findings No findings of significance were identified.
1R12 Maintenance Rule (MR) Implementation a.
Inspection Scope The inspectors reviewed implementation of the Maintenance Rule (10 CFR 50.65) using VPAP 0815, Maintenance Rule Program, and Engineering Transmittal (ET) CEP-97-0018, North Anna Maintenance Rule Scoping and Performance Criteria Matrix. The reviews focused on the characterization of failures, the appropriateness of the associated a(1) or a(2) classification, and the appropriateness of either the associated a(2) performance criteria or the associated a(1) goals and corrective actions. The plant issues and associated equipment issues reviewed were:
N-2000-2600 - Unit 1 and 2 Control Room Bottle Air System Failure to Meet Acceptance Criteria - Design change date extension and impact on a(1) status;
N-2001-3604 - Unit 2A Steam Dump Fails Open - Repeated failures/Unavailability exceeded, placed in a(1); Maintenance status of steam dump problems in general;
N-2001-3117 - Unit 1B Main Transformer Fire Protection Deluge System Failures
- Removed from a(1) Status;
N-2001-2306 - Unit 1C Charging Pump Exceeds Unavailability Hours - Placed into a(1) Status; Maintenance status of charging pumps in general for seal leakage, motor failures, and exceeding unavailability hours;
N-2001-3552 - Unit 2B Feedwater Heater Hi Hi Level without Alarm - Date extended for returned to a(2), reliability of replacement level switch; and,
N-2000-2733 - Unit 1C Main Control Room Chiller - Returned to a(2) status.
b.
Findings No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control a.
Inspection Scope The inspectors reviewed the licensees scheduled or emergent work activities to assess the management of plant risk. The inspectors evaluated if the assessments of risk were performed in accordance with requirements of 10CFR50.65 (a)(4) and plant procedures.
Additionally, the inspectors reviewed the licensees actions to minimize the probability of initiating events, maintain the functional capability of mitigating systems, and maintain barrier integrity. The risk impact of performing the following work activities was assessed:
Work Order 00455489-01; Unit 2 High Head Safety Injection Pump Maintenance Activities;
Work Order 00462819-01; Unit 2 A Motor Driven Auxiliary Feedwater Pump Maintenance Activities;
Design Change Package 00-003; A Service Water Header Isolation/Modification and Repair Work Activities;
Work Order 00461325-01; Service Water Spray Array Header Cleaning and Repairs;
Work Order 00449932-01; 1A Instrument Air Compressor Motor Bearings Lubrication; and
Work Order 00459939-01; 1A Instrument Air Compressor Blower Oil Change and Filter Cleaning Activities.
b.
Findings No findings of significance were identified.
1R14 Nonroutine Plant Evolutions a.
Inspection Scope The inspectors reviewed control room logs, abnormal/operation procedures, and held discussions with operations personnel associated with the following non-routine evolutions: 1) temperature monitoring of Unit 2 B reactor coolant pump stator following temporary corrective actions for mitigating temperature increases, 2) operator response to a loss of all individual rod position indications on Unit 1, and 3) the placing of the bearing cooling system into the infrequently used operational mode of lake to lake cooling for Units 1 and 2.
December 22, 2001 Reactor Trip Following a December 22, 2001, Unit 2 turbine trip/reactor trip, the inspectors reviewed control room logs and applicable unit emergency procedures. The inspectors also reviewed unit post-trip conditions and interviewed operations personnel on December 22. The Unit 2 reactor trip occurred following a trip of the main turbine due to a loss of the turbines electro-hydraulic control (EHC) system power supply. The causes of the event were determined to be an initial failure of a diode in the primary EHC control
power supply circuitry and a subsequent failure of the backup turbine control power supply switch.
The inspectors noted that operations personnel responded to the trip in accordance with emergency procedures and their post-trip activities/responses were performed in an appropriate and expected manner. The inspectors concurred with the licensees assessment that the trip was uncomplicated and that the on-shift crews trip and post-trip activities were appropriate.
b.
Findings No findings of significance were identified.
1R15 Operability Evaluations a.
Inspection Scope The inspectors evaluated the technical adequacy of operability evaluations to ensure that operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The reviewed operability evaluations were described in the following plant issues:
N-2002-0023 - Unexpected Temperature Indications on the Unit 2 B RCP -
Increased temperature did not affect pump operability;
N-2002-0155 - Unit 1A Charging Pump Unexpected Pressure and Flow Parameter Changes during Performance of PT on the C Charging Pump -
Operability not affected per vendor information, expected response with new rotating element;
N-2002-0267 - Unit 1 B Charging Pump Gear Box Cooler - Degraded gear box cooler head studs did not affect operability of component;
N-2002-0353 - Unit 1 H EDG Turbo-charger Unbalanced Check Valve Failed to Fully Open at 2200 KW - Since valve opened fully at 2600 KW without oscillation, the emergency mode operability was not affected; and,
N-2002-0585 - Unit 2 B High Head Safety Injection Pump Seal Leakage - Seal repaired and pump was returned to operable status following PMT b.
Findings No findings of significance were identified.
1R16 Operator Work-Arounds (OWAs)
a.
Inspection Scope Procedure 0-GOP-5.3, Review of Operator Work-Arounds, described methods for determining the cumulative and aggregate effects of OWAs/distractions. The inspectors
assessed 94-OWA-B01A, Operations performance of manual calculations due to unavailability of Plant P-250 computer problems, for conformance to 0-GOP-5.3.
b.
Findings No findings of significance were identified.
1R17 Permanent Plant Modifications a.
Inspection Scope The inspectors reviewed design change package (DCP)00-003 and witnessed portions of its implementation. The modification upgraded/replaced the service water pump discharge piping in the service water pump house and repaired coating in the service water main headers. The inspectors reviewed the associated 10 CFR 50.59 documentation and assessed the DCP impact on plant risk and technical specifications requirements.
b.
Findings No findings of significance were identified.
1R19 Post-Maintenance Testing a.
Inspection Scope The inspectors reviewed the following post-maintenance test (PMT) procedures and activities associated with repair or replacement of the following components to determine if the procedures and test activities were adequate to verify operability and functional capability of the equipment:
Unit 1 B Service Water Pump Testing (1-PT-75.2B.1, Service Water Pump (1-SW-P-1B));
Unit 1 A Motor Driven Auxiliary Feedwater Pump Testing (1-PT-71.2Q A Motor-Driven AFW Pump and Valve Test);
Unit 2 B Block Shunt Pushbutton for B Reactor Trip Breaker Replacement/Testing (2-PT-36.1B, Train B Reactor Protection and ESF Logic Channel Functional Test);
Unit 1 A Service Water Pump Discharge Valve to B Header Testing (0-MOP-49.09, Removing Service Water No. 2(B) Supply and No.3(B) Return Headers from Service and Returning to Service); and,
Unit 2 B Charging Pump Testing (2-PT-14.2, Charging Pump 2-CH-P-1B).
b.
Findings No findings of significance were identified.
1R22 Surveillance Testing a.
Inspection Scope For the surveillance tests listed below, the inspectors examined the test procedure and either witnessed the testing and/or reviewed test records to determine whether the scope of testing adequately demonstrated that the affected equipment was functional and operable:
1-PT-213.9, Valve Inservice Inspection (Safety Injection System);
1-PT-71.2Q, A Motor-Driven AFW Pump and Valve Test;
1-PT-14.1, Charging Pump 1-CH-P-1A;
1-PT-36.9.1H, Degraded Voltage/Loss of Voltage Functional Test: 1H Bus;
2-PT-57.1B, Emergency Core Cooling Subsystem-Low Head Safety Injection Pump (2-SI-P-1B);
1-PT-213.7B, Valve Inservice Inspection (B Train of Recir Spray System); and,
1-PT-63.1B, Quench Spray System - B Subsystem.
b.
Findings No findings of significance were identified.
1R23 Temporary Plant Modifications a.
Inspection Scope The inspectors reviewed the details of the following temporary modifications (TM) to determine whether system operability/availability was affected, configuration control was maintained, and the associated safety evaluation adequately justified implementation:
TM 1143 - Removal of plates from the Unit 2 B RCP to mitigate problems associated with high stator temperatures; and
0-GOP-4.2, Extreme Cold Weather Operations - Procedurally controlled temporary modification for the use of temporary portable heaters in the EDG and SBO diesel rooms for extreme cold weather conditions.
b.
Findings No findings of significance were identified.
Cornerstone: Emergency Preparedness 1EP6 Drill Evaluation a.
Inspection Scope
On February 6, the inspectors witnessed portions of the licensees emergency planning training drill in the Technical Support Center (TSC). The inspectors observed that
access control and accountability of personnel was maintained. It was also noted that the command and control functions of the TSC director were being implemented during the conduct of the drill. Additionally, the inspectors monitored a radio notification of the drill scenario status to local authorities. The inspectors noted that the drill was graded and appropriate objectives were evaluated to support the performance indicator, Drill and Exercise Performance.
b.
Findings
No findings of significance were identified.
4.
OTHER ACTIVITIES 4OA3 Event Followup
.1 (Closed) Licensee Event Report (LER) 50-339/2001-004-00: technical specification missed surveillance due to test procedure error. The inspectors reviewed the licensees corrective actions associated with a missed Unit 2 surveillance due to an incorrect valving configuration for Type C testing of low head safety injection (LHSI) hot leg isolation valves 2890A/B. The incorrect valving configuration was the result of a procedural error. The procedure incorrectly required the equalizing valves between the double discs to be closed when performing the Type C test. This configuration invalidated the test results, thus making the technical specification surveillance tests invalid. The licensees corrective actions included revising the Unit 2 Type C test procedure to require the opening of the equalizing valves during the test. Testing of the affected Unit 2 valves was successfully performed following the revision of the procedure. The Unit 1 procedure for the Type C testing had the correct configuration for the manual equalizing valves. No new findings were identified in the inspectors review.
This is a minor violation not subject to formal enforcement. This item was placed in the licensees corrective action program as plant issue N-2001-3491.
.2 (Closed) LER 50-339/2001-005-00: automatic reactor trip due to turbine control system power supply failure. The inspectors reviewed licensee corrective actions associated with the Unit 2 reactor trip and post-trip items. The equipment failures which initiated the trip, an initial failure of a primary control power diode and a subsequent failure of the backup power supply switch to switch-over and supply back-up power, were thoroughly examined by the licensee. After replacement and testing of both the diode and backup power supply switch, the unit was returned to full power operation. Additional licensee corrective actions included further assessment of the existing turbine control system power supply and initiation of equipment changes that will upgrade the present EHC power supply. This item was placed in the licensees corrective action program as plant issue N-2001-3600.
4OA5 Other
.1 (Closed) Temporary Instruction (TI) 2515/145, Circumferential Cracking of Reactor Pressure Vessel Head Penetration Nozzles (NRC Bulletin 2001-01) - Unit 1
a.
Inspection Scope On October 2-4, 2001, the inspectors observed activities relative to inspection of the Unit 1 reactor vessel head penetrations (VHPs) in response to NRC Bulletin 2001-01.
The inspection included review of nondestructive examination (NDE) procedures and assessment of NDE personnel training and qualification. In addition to the observation and assessment of in-process visual (VT) and eddy current (ET) examinations documented in NRC Integrated Inspection Report No. 50-338/01-03, the inspectors discussed the ultrasonic (UT) techniques and inspection results with licensee and NDE contractor personnel. The activities were examined to verify licensee compliance with regulatory requirements and gather information to help the NRC staff identify possible further regulatory positions and generic communications. Specifically, the inspectors reviewed selected UT data for penetrations 31, 50, and 52.
Documents reviewed included:
Westinghouse Field Services Procedure ISI-UT-002, Revision 0-P1, FC2, Time of Flight Ultrasonic Inspection of Reactor Vessel head Penetrations;
Licensee Letter Serial 01-490 dated August 31, 2001, Response to NRC Bulletin 2001-01;
Licensee Letter Serial 01-490A dated November 5, 2001, Response to NRC Bulletin 2001-01; and,
Qualification and Training Records for NDE Examiners.
b.
Findings In accordance with NRC Bulletin 2001-01, Unit 1, with less than 5 Effective Full Power Years (EFPY) from the Oconee 3 plant, would have a high susceptibility to primary water stress corrosion cracking (PWSCC) and would need a qualified visual examination or a qualified volumetric examination of 100% of the VHPs. In response to the Bulletin, the licensee proposed to perform an effective visual (VT-2) inspection for evidence of leakage. In addition, ET inspections from under the head on the OD and ID of the penetrations and the OD of the J-Groove welds were proposed. Surface breaking indications discovered by ET would be further investigated using ultrasonic (UT)
inspection techniques capable of sizing cracks, contingent upon qualification of the UT technique.
Inspector observations of VT and ET activities are detailed in NRC Integrated Inspection Report No. 50-338/01-03. As noted in that report, the VT-2 examination identified 34 penetrations for further evaluation. These penetrations were prioritized for ET examination based on inspecting first those VHPs of more concern based on the VT examination results. Two separate ET procedures were used. ET inspection of the J-Groove weld surface was performed for twenty-six of the 34 nozzles. ET inspection of the nozzle ID was performed for 25 of the 34 nozzles. The remainder of the 34 nozzles were dispositioned based on further evaluation of the VT-2 inspection results. The ET inspections resulted in axial weld surface indications in a number of nozzle J-Groove welds, which were dispositioned by VT and liquid penetrant (PT) as weld construction flaws at the J-Groove to clad interface. In addition, ET indications were identified on the ID of 8 nozzles. All indications were orientated in the axial direction. The nozzles with
ET ID indications were ultrasonic (UT) inspected in accordance with procedure ISI-UT-002, Revision 0-P1, FC-2, Time of Flight Ultrasonic Inspection of Reactor Vessel Head Penetrations. The UT showed the indications to be very shallow with good location and length correlation between UT results and ET results.
Further description and resolution of the inspection results is summarized in VEPCO Letter Serial No. 01-490A dated November 5, 2001.
Inspections were being performed in accordance with approved procedures with trained and qualified inspection personnel. UT examiners had significant UT experience, including experience inspecting VHPs.
Other inspection results of the TI inspection on Unit 1 were previously documented in NRC Integrated Inspection Report No. 50-338/01-03.
.2 (Closed) TI 2515/146, Hydrogen Storage Locations The inspectors reviewed the Updated Final Safety Analysis Report and walked down the plant to identify areas where bulk hydrogen gas was stored. The inspectors determined that all bulk hydrogen storage was greater than 50 feet from ventilation intakes, safety related water tanks, and safety-related or risk-significant SSCs.
.3 Review of Institute of Nuclear Power Operations (INPO) Report The inspectors reviewed the March 5, 2002, INPO report for the plant evaluation conducted in June 2001.
4OA6 Meetings
.1 Exit Meeting Summary
The inspectors presented the inspection results to Mr. D. Heacock, Site Vice President, and other members of the licensees staff on April 10, 2002. The inspectors asked the licensee whether any of the material examined during the inspection should be considered proprietary. No proprietary information was identified.
.2 Annual Assessment Meeting Summary On March 19, 2002, the NRCs Chief of Reactor Projects Branch 5 and the Senior Resident Inspector assigned to the North Anna Power Station (NAPS) met with Virginia Electric and Power Company to discuss the NRCs Reactor Oversight Process (ROP)
and the NAPS annual assessment of safety performance for the period of April 1, 2001 -
December 31, 2001. The major topics addressed were: the NRCs assessment program, the results of the NAPS assessment, and the NRCs Agency Action Matrix.
Attendees included NAPS site management, members of site staff, Corporate management and staff, and members of the local news media.
This meeting was open to the public. Information used for the discussions of the ROP is available from the NRCs document system (ADAMS) as accession number ML020600179. ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Attachment SUPPLEMENTAL INFORMATION KEY POINTS OF CONTACT Licensee D. Christian, Senior Vice President and Chief Nuclear Officer K. Barnette, Supervisor, Site Industrial Safety/Fire Protection J. Crossman, Supervisor, Nuclear Engineering J. Davis, Director, Station Nuclear Safety and Licensing M. Dunston, Manager, Site Services C. Funderburk, Director, Station Operations and Maintenance D. Heacock, Site Vice President E. Hendrixson, Manager, Station Engineering P. Kemp, Manager, Nuclear Oversight L. Lane, Manager, Operations T. Maddy, Manager, Station Security F. Mladen, Manager, Maintenance Q. Parker, Maintenance Rule Coordinator W. Renz, Director, Security and Emergency Preparedness H. Royal, Manager, Nuclear Training A. Stafford, Manager, Radiological Protection ITEMS CLOSED 50-339/2001-004-00 LER Technical specification missed surveillance due to test procedure error (Section 4OA3.1)
50-339/2001-005-00 LER Automatic reactor trip due to turbine control system power supply failure (Section 4OA3.2)
2515/145 (Unit 1)
TI Circumferential Cracking of Reactor Pressure Vessel Head Penetration Nozzles (NRC Bulletin 2001-01)
(Section 4OA5.1)
2515/146 (Units 1 and 2)
TI Hydrogen Storage Locations (Section 4OA5.2)