IR 05000390/2003007
| ML033430186 | |
| Person / Time | |
|---|---|
| Site: | Watts Bar  |
| Issue date: | 08/05/2003 |
| From: | Ogle C NRC/RGN-II/DRS/EB |
| To: | Scalice J Tennessee Valley Authority |
| References | |
| IR-03-007 | |
| Download: ML033430186 (30) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION ust 5, 2003
SUBJECT:
WATTS BAR NUCLEAR PLANT - NRC SAFETY SYSTEM DESIGN AND PERFORMANCE CAPABILITY INSPECTION REPORT 05000390/2003007 AND 05000391/2003007,
Dear Mr. Scalice:
On July 11, 2003, the NRC completed a safety system design and performance capability inspection at your Watts Bar 1 & 2 reactor facilities. The enclosed report documents the results of that inspection. The results were discussed with Mr. Larry S. Bryant and other members of your staff during an exit meeting on July 11, 2003.
This 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 procedure and records, observed activities, and interviewed personnel.
Based on the results of this 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.: 50-390, 50-391 License No.: NPF-90 and Construction Permit No.: CPPR-92
Enclosure:
(See page 2)
TVA 2 Enclosure: Inspection Report 05000390, 391/2003007 w/Attachment Supplement Information
REGION II==
Docket Nos.: 50-390, 50-391 License Nos.: NPF-90, CPPR-92 Report No.: 05000390/2003007 and 05000391/2003007 Licensee: Tennessee Valley Authority (TVA)
Facility: Watts Bar Nuclear Plant, Units 1 & 2 Location: 1260 Nuclear Plant Road Spring City TN 37381 Dates: June 23-27, 2003 and July 7-11, 2003 Inspectors: F. Jape, Senior Project Manager (lead)
M. Merriweather, Reactor Inspector S. Walker, Reactor Inspector M. Maymi, Reactor Inspector B. Holland, Contractor Approved by: Charles R. Ogle, Chief Engineering Branch 1 Division of Reactor Safety Enclosure
SUMMARY OF FINDINGS
IR 05000390/2003-007, IR 05000391/2003-007; 06/23-27/2003 and 07/07-11/2003; Watts Bar
Nuclear Plant, Units 1 and 2; Safety System Design and Performance Capability Inspection.
This inspection was conducted by regional reactor inspectors and a contractor. 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,
Rev. 3, dated July 2000.
A. Inspector 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 included review of 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), main feedwater (MFW),auxiliary feedwater (AFW), steam generator (SG) blowdown (SGBD), emergency core cooling (ECCS), reactor coolant system (RCS), and radiation monitoring (RM) systems were included. The inspection also covered supporting equipment, equipment that 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 safety analysis.
.1 System Needs
.11 Process Medium
a. Inspection Scope
The team reviewed selected ECCS and AFW net positive suction head and water source calculations, licensing and design basis information, drawings, vendor manuals, operating/lineup procedures, and surveillance procedures. The team walked down accessible portions of the systems in the plant. The reviews and walkdowns were conducted to verify that system design, Technical Specifications (TS), and Updated Final Safety Analysis Report (UFSAR) assumptions were consistent with the actual capability of systems and components required to mitigate a SGTR event. This review included the refueling water storage tank (RWST) and its refill capability, the condensate storage tank (CST) and its refill capability, the essential raw cooling water (ERCW) supply to the AFW pumps, and mini-flow flow paths for AFW and ECCS pumps. The review also included the ability of the steam generator power-operated relief valves (SG PORVs) and the steam dump valves to support RCS cooldown, and the ability of the charging pumps and pressurizer power-operated relief valves (PORVs)and safety valves to provide feed and bleed cooling to the RCS.
The team also reviewed performance curves and NPSH information for the safety injection pumps to verify there was adequate NPSH for these pumps when taking suction from the RWST, and to verify the adequacy of design assumptions.
The team reviewed maintenance and calibration records for the radiation monitoring channels listed below:
- Condenser Vacuum Pump Air Exhaust (1-LRP-90-119)
- Steam Generator Blowdown (1-LRP-90-120, -121)
- Main Steam (1-LRP-90-421,-422,-423,-424)
The maintenance and calibration records were reviewed to determine the current performance capability of the radiation detection equipment. The setpoints for the radiation monitor alarms were reviewed to verify that they were established in accordance with setpoint guideline procedures and design output documents. The surveillance and annunciator response procedures were also reviewed to determine if they were adequate for monitoring steam generator tube rupture leakage.
The team reviewed instrument installations associated with the CST level, RWST level, and AFW suction pressure to verify that the instruments were designed, constructed and operated in accordance with design and licensing basis documents. The team conducted field inspections of the instrument installations to verify that the instrument tubing, sensors, and supports were in good material condition and that heat tracing was installed when required. The location of the instruments was checked against scaling and setpoint documents. The team also reviewed appropriate design basis documents, TS, system flow diagrams, instrument uncertainty calculations, calibration and surveillance test procedures, and calibration test records to verify that the instruments had the proper range and accuracy needed to perform their safety function. The applicable reference documents reviewed are listed in the Attachment.
b. Findings
No findings of significance were identified.
.12 Energy Sources
a. Inspection Scope
The team reviewed valve lineup procedures and walked down the energy sources of selected mechanical components needed during a SGTR event to verify that selected portions of the system alignments were consistent with the design basis assumptions, performance requirements, and system operating procedures. The team verified by control room walkdowns and equipment status reviews that required energy sources were available for mitigation of the SGTR event. Among the lineups reviewed were the steam supply to the turbine driven AFW pump, selected valve alignments for the AFW and SI systems, and electrical alignments for the 6.9 kilo volt (KV) shutdown boards.
The team reviewed SG PORVs nitrogen backup supply sizing calculations, corrective maintenance history, related problem evaluation reports (PERs) and surveillance testing to verify the accessibility and reliability of the nitrogen backup supply; and to verify the adequacy of their design and maintenance.
The team also reviewed the turbine driven AFW pumps steam supply trap inspections to verify the reliability of the steam supply, and the adequacy of maintenance.
The team reviewed voltage drop calculations for a sample of safety-related buses and loads such as motors, valve operators and respective controls, inverters, and chargers to verify that adequate voltage would be available at the end device during worst case minimum grid operating voltage conditions. The team also reviewed surveillance records for bus voltage readings to verify that these checks were being performed in accordance with the requirements specified in design and license basis documents.
Additionally, the team conducted walkdown inspections of selected electrical equipment (see Attachment) including the 120 volt alternating current
- (ac) vital inverters, 125 volt direct current
- (dc) distribution boards, 125 volt dc station batteries and associated battery chargers to verify that the equipment was operable and in good material condition, with no alarms present, and the voltage indications were within the normal expected band. The ground detection system of the 125 volt dc system was also examined on the dc distribution boards to verify that there were no grounds on the system. The specific components reviewed are listed below:
- AFW Pump Motors (1A & 1B)
- ERCW Pump Motor (A-A, B-A, F-B, E-B)
- Charging Pump Motors (1A & 1B)
- Vital Battery Chargers I through V
- Spare Battery Chargers VI & VII
- Main Steam Isolation Valves (MSIV; 1-FCV-1-4, 11)
- MSIV Bypass Valves (1-FCV-1-147 & 149A, -148 & 149B)
- DC Distribution Boards
- MFW Isolation Valves (1-FCV-3-33A & -47B)
- Steam Flow to TDAFW Isolation Valves (1-FCV-1-17A & -18B)
- BIT Outlet Valves (1-FCV-63-25B & -26A)
- Steam Generator Blowdown Valves (1-FCV-1-181 & 183A, -182 &184B)
- Vital Inverters
- 125 VDC Vital Batteries
b. Findings
No findings of significance were identified.
.13 Instrumentation and Controls
a. Inspection Scope
The team reviewed surveillance and calibration records of the instrument loops listed below to verify that the instruments and associated loop components were being properly calibrated and tested in accordance with calibration procedures and TS. The calibration records were also reviewed to verify that instrument out of tolerance conditions were properly evaluated by the licensee for impact on system performance and if applicable, were entered into the corrective action program.
- SG Narrow Range Level (1-L-3-38, 39, 42)
- SG Wide Range Level (1-L-3-43)
- Steam Generator Pressure (1-P-1-2A)
- Reactor Coolant System Pressure (1-P-68-63)
- Pressurizer Level (1-L-68-320)
- Hot and Cold Leg RCS Temperature (1-T-68-1, 18)
- Refueling Water Storage Tank Level (1-L-63-50, 51)
- Condensate Storage Tank Level (1-LT-2-230, 233)
- Pressure Switches (1-PS-3-139A, B, D, and 1-PS-3-144A, B, D)
- AFW Flow (1-F-3-147A,B)
- High Pressure Injection Flow (1-F-63-170)
- Pressure Switches (1-PS-46-13, -40)
- Pressurizer Pressure (1-LPP-68-322, -340)
The team reviewed electrical control schematics of the control systems for AFW, steam generator PORVs, and pressurizer PORVs to verify that the control systems were in accordance with their design bases, and would be functional to provide desired control during accident/event conditions.
b. Findings
No findings of significance were identified.
.14 Operator Actions
a. Inspection Scope
The team reviewed procedures, including emergency operating instructions (EOIs) ,
abnormal operating instructions (AOIs), and annunciator response instructions (ARIs)that would be used in the identification and mitigation of a STGR event. The procedure review was done to verify that the procedures were consistent with the UFSAR description of a SGTR event and the owners group guidelines, step deviations were justified and reasonable, and the procedures were written clearly and unambiguously.
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. Operator action times for performance of SGTR event mitigation activities were compared to the times assumed in accident analysis.
b. Findings
No findings of significance were identified.
.15 Heat Removal
a. Inspection Scope
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 CST and RWST.
The team reviewed documentation for selected equipment to assess the reliability and availability of cooling for equipment required to mitigate a SGTR event. The equipment reviewed included the lube oil coolers used to cool the safety injection pumps (SIPs) and AFW pumps. AFW pumps lube oil coolers surveillance testing results, lube oil cooler vendor manual, lube oil preventive maintenance records, and cooler corrective maintenance history were reviewed to verify the adequacy of the maintenance and surveillance acceptance criteria. The team also reviewed SIPs lube oil cooler inspection, cleaning and eddy current testing (ECT) maintenance records to verify adequacy of maintenance and frequency.
b. Findings
No findings of significance were identified.
.2 System Condition and Capability
.21 Installed Configuration
a. Inspection Scope
The team performed field walkdowns of selected mechanical and electrical components including the SIPs, AFW pumps, steam dump valves, main steam isolation valves (MSIVs), main steam safety valves (MSSVs), SG PORVs, chemical and volume control system (CVCS), ERCW, and feedwater (FW) regulating valves. The purpose of the walkdowns was to assess general material condition and identify any degraded condition of components that could be used to mitigate a SGTR event.
Additionally, the team assessed the potential impact of external events on SGTR mitigation equipment; including flooding, high energy line breaks, and tornados. The team also inspected selected controls and indicators for these systems for appropriate human factors such as labeling, arrangement, and visibility.
b. Findings
No findings of significance were identified.
.22 Operation
a. Inspection Scope
The team reviewed system operating and lineup procedures, system drawings and walked down selected portions of the MS, MFW, AFW, SGBD, CVCS, SI, RM, RHR, controlled air (CA), 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 EOI requirement to manually isolate a stuck open SG PORV on the ruptured SG by closing the appropriate block valve.
In addition, the team reviewed the operator workaround 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
The team reviewed instrument loop uncertainty calculations for the following monitoring instruments to verify that plant instrument calibration procedures had accurately incorporated set point values delineated in the calculations.
- Condensate Storage Tank Level (1-LT-2-230, -233)
- Refueling Water Storage Tank Level (1-LT-63-50, -51)
- AFW Suction Pressure (1-PS-3-139A, -B, -D, and 1-PS-3-144A, -B, -D)
- Condenser Vacuum Pump Exhaust Rad Monitor (1-LRP-90-119)
- Steam Generator Discharge Rad Monitor (1-LRP-90-421, -422, -423, -424)
The team reviewed two temporary plant modification packages (1-01-010-003 & 1-02-2-68) to verify that the changes had been appropriately reviewed for impact on plant safety and approved in accordance with the change control program and that the changes did not impact plant performance.
The team reviewed selected operations procedures associated with SGTR event response and mitigation to verify design and licensing assumptions were incorporated, as appropriate, into procedures. One example was procedural guidance to isolate the ruptured SG if the MSIV for the faulted SG failed to close by closing the remaining three MSIVs for the intact SGs.
The team reviewed calculations, corrective maintenance, and preventive maintenance for the RCS, AFW, and MS systems to verify that these activities were maintaining the assumptions of the licensing and design bases. During these reviews, the team focused on potential common mode failure vulnerabilities that could be introduced by design or maintenance activities. These included the review of the AFW pump mini-flow orifice design adequacy. The team reviewed AFW pump mini-flow orifice and ERCW strainer sizing documentation to verify ERCW strainer size was smaller, which prevents the possibility of AFW pump mini-flow orifice clogging.
The team reviewed analytical limits calculations for the AFW pump pressure switches, which perform the ERCW swap over function, to verify that the AFW pump suction transfer set point is adequate and to verify these were designed and operated in accordance with design and licensing basis documents.
b. Findings
No findings of significance were identified.
.24 Testing and Inspection
a. Inspection Scope
The team reviewed selected TS and records of completed surveillance tests, performance tests, inspections, and preventive maintenance; and walked down selected components of the MS, MFW, AFW, SGBD, CA, RM, CVCS, SI, and RHR to verify the tests and inspections were appropriately verifying that the assumptions of the licensing and design basis were being maintained. This review included, in part, quarterly testing of AFW, CVCS, SI, and RHR pumps, pump discharge pressures, valve stroke times, check valve operation, and analysis of pump and motor bearing vibration indications.
The team reviewed records of completed surveillance tests, performance tests, inspections, and preventive maintenance; and walked down the 125 VDC vital station batteries and the emergency diesel generator (EDG) 125VDC batteries to verify that the battery capacity was adequate to supply and maintain in operable status, the required emergency loads for the design basis duty cycle. Engineering standards and vendor manuals were referenced to ensure proper methodologies were being incorporated into the licensees program. Additionally, the team conducted interviews and reviewed several procedures to verify requirements established by the TS and bases were identified and met.
b. Findings
No findings of significance were identified.
.3 Selected Components
.31 Component Degradation
a. Inspection Scope
Instrumentation The team reviewed the 5-year maintenance history for the instrument components listed below to determine their current performance capability to mitigate a steam generator tube rupture event.
- SG Narrow Range Level (1-L-3-38, 39, 42)
- SG Wide Range Level (1-L-3-43)
- Steam Generator Pressure (1-P-1-2A)
- Reactor Coolant System Pressure (1-P-68-63)
- Pressurizer Level (1-L-68-320)
- Hot and Cold Leg RCS Temperature (1-T-68-1, 18)
- Condensate Storage Tank Level (1-LT-2-230, 233)
- Refueling Water Storage Tank Level (1-L-63-50, -51)
- Pressure Switches (1-PS-3-139A, B, D, and 1-PS-3-144A, B, D)
- AFW Flow (1-F-3-147A,B)
- HPI Flow (1-F-63-170)
- Annunciator Inverter (1-PNL-055-L236)
- Pressure Solenoid Valves (1-PSV-1-6A, -6B, -6C)
- Level Control Valve (1-LCV-3-164)
Specifically, the team reviewed each components maintenance history by reviewing selected work order summaries and trends of component performance data, to verify that unexpected degradation had not been found, and that performance problems had not reappeared.
Mechanical Components The team reviewed system health reports as well as, preventive and corrective maintenance records to verify that components that could be relied upon to mitigate a SGTR event were not degrading to unacceptable performance levels and were monitored for degradation. Problem event reports, performance trending, and system testing for selected components were also reviewed to assess the licensees actions to verify and maintain the safety function, reliability and availability of selected components.
Selected components included the SG PORVs, MSIVs, MSIVs pressure regulators, MSSVs, steam dump valves, SG blowdown valves, and pressurizer PORVs. Specifically the team reviewed selected components related PERs, corrective maintenance work orders and history, completed surveillance testing procedures, functional testing, and in service testing (IST) trending. These were reviewed to verify surveillance requirements were being met, to verify the adequacy of the acceptance criteria, to verify valves and their design were being maintained and problems were being identified and addressed.
Electrical Components The team reviewed system status reports, corrective maintenance records, problem evaluation reports, and performance trending of the 480 V switchgear and motor control centers (MCCs), and 120 VAC and 125 VDC vital electrical systems to verify that components that could be relied upon to mitigate a SGTR event were not degrading to unacceptable performance levels.
The team reviewed the 5-year maintenance history for the following electrical and mechanical components listed below to determine their current performance capability to mitigate a SGTR event.
- ERCW Pumps (A-A, B-A, F-B, E-B)
- ERCW Pump Feeder Breakers
- Charging Pump Motors (1A & 1B)
- AFW Pump Motor (1A & 1B)
- BIT Outlet Valves (1-FCV-63-25B & -26A)
- 6.9 kV Shutdown Board Switchgear
- Main Steam Isolation Valves (MSIV; 1-FCV-1-4, 11)
- MSIV Bypass Valves (1-FCV-1-147 & 149A, -148 & 149B)
- Pressurizer PORVs (1-PCV-68-334 & -340A)
- MFW Isolation Valves (1-FCV-3-33A & -47B)
- Steam Generator Blowdown Valves (1-FCV-1-181 & 183A, -182 &184B)
- ERCW to Motor Driven Pump (MDP) Suction (1-FCV-116A & B)
- ERCW to Turbine Driven Pump (TDP) Suction (1-FCV-136A & B, -179A & B)
Specifically the team reviewed:
- each components maintenance history by reviewing selected corrective-maintenance and preventive-maintenance work order summaries and trends of component performance data, to verify that unexpected degradation had not been found, and that performance problems had not reappeared; and
- each components preventive-maintenance schedule, to verify that the schedule was based either on vendor recommendations or appropriate industry experience.
b. Findings
No findings of significance were identified.
.32 Equipment/Environmental Qualification
a. Inspection Scope
The team conducted in-plant walkdowns to verify that the observable portion of selected mechanical components and electrical connections to those components were suitable for the environment expected under all conditions, including high energy line breaks.
The team specifically verified, by procedure review and component walkdown that appropriate freeze protection was provided for CST-A and the RWST.
The team reviewed main steam line break peak pressure, and mass and energy release analyses for the valve vaults where the SG PORVs, MSSVs, and MSIVs are located to verify equipment design assumptions were adequate.
b. Findings
No findings of significance were identified.
.33 Equipment Protection
a. Inspection Scope
The team conducted in-plant walkdowns to verify that there was no observable damage to installations designed to protect selected components from potential effects of high winds, flooding, and high or low outdoor temperatures.
b. Findings
No findings of significance were identified.
.34 Operating Experience
a. Inspection Scope
The team reviewed the licensees dispositions 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 recent operator lesson plans to verify that applicable significant operating experience report insights were being incorporated into operator lesson plans and training. The specific operator training plans reviewed are listed in the Miscellaneous Documents section of the Attachment to this report.
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 TS and procedures.
b. Findings
No findings of significance were identified.
.36 Foreign Material Exclusion (FME) Control Program
a. Inspection Scope
The team reviewed procedural guidelines and performance records for the loose parts monitoring system to verify this system was operational and being used to monitor for loose parts in the RCS.
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, surveillance test records, calibration test records, self-assessment reports, and problem evaluation reports to verify that conditions adverse to quality for systems, structures, components, and/or processes that would be associated with mitigation of a SGTR event were being identified and entered into the licensees corrective action program.
Other examples of issues reviewed included trip mechanisms on the 480 V switchgear, and resistance measurements for vital and EDG batteries. In addition, the team reviewed work orders on risk significant equipment to evaluate failure trends (e.g.,
ERCW feeder breakers). The team also reviewed the licensees performance in the identification of procedural deficiencies.
b. Findings
No findings of significance were identified.
OTHER ACTIVITIES
4OA6 Meetings, Including Exit
The lead inspector presented the inspection results to Mr. L. Bryant, and other members of the licensee staff, at an exit meeting on July 11, 2003. The licensee acknowledged the findings presented. Proprietary information is not included in this inspection report.
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee personnel
- L. Bryant, Plant Manager
- J. Bushnell, Licensing
- R. Evans, Operations Training
- D. Hall, RADCON
- B. Hunt, Shift Manager
- B. Mays, Licensing
- P. Pace, Licensing Manager
- R. Rieger, System Engineer
- S. Robertson, Design Engineering
- R. Scarlett, Unit Supervisor
- B. Selewski, System Engineer
- S. Tuthill, Chemistry
- T. Wallace, Operations Manager
- J. Young, Operations
NRC personnel
- (attended exit meeting)
- H. Christensen, Deputy Director, Division of Reactor Safety, NRC Region II
- M. King, Acting Senior Resident Inspector
- J. Reece, Resident Inspector
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
None.