IR 05000259/2007007
| ML080250374 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 01/25/2008 |
| From: | Binoy Desai NRC/RGN-II/DRS/EB1 |
| To: | Campbell W Tennessee Valley Authority |
| References | |
| IR-07-007 | |
| Download: ML080250374 (32) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
ary 25, 2008
SUBJECT:
BROWNS FERRY NUCLEAR PLANT - NRC COMPONENT DESIGN BASES INSPECTION REPORT 05000259/2007007, 05000260/2007007, AND 05000296/2007007
Dear Mr. Campbell Jr.:
On December 14, 2007, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your Browns Ferry Nuclear Plant Units 1, 2 and 3. The enclosed inspection report documents the inspection findings which were discussed on December 14, 2007, with Mr. B.
OGrady and other members of your staff.
The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.
Based on the results of this inspection, the inspectors identified two findings of very low safety significance (Green). These two findings were determined to involve violations of NRC requirements. However, because of their very low safety significance and because they are entered into your corrective action program, the NRC is treating these findings as Non-Cited Violations (NCVs) consistent with Section VI.A.1 of the NRCs Enforcement Policy. If you contest any of these NCVs you should provide a response within 30 days of the date of this inspection report, with the bases for your denial, to the United States Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001, with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, U. S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Browns Ferry.
TVA 2 In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) 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/
Binoy B. Desai, Chief Engineering Branch 1 Division of Reactor Safety Docket Nos.: 50-259, 50-260, 50-296 License Nos.: DPR-33, DPR-52, DPR-68
Enclosure:
Inspection Report 05000259/2007007, 05000260/2007007, and 05000296/2007007 w/Attachment: Supplemental Information
REGION II==
Docket Nos.: 50-259, 50-260, 50-296 License Nos.: DPR-33, DPR-52, DPR-68 Report No.: 05000259/2007007, 05000260/2007007, 05000296/2007007 Licensee: Tennessee Valley Authority Facility: Browns Ferry Nuclear Plant, Units 1, 2 & 3 Location: P. O. Box 2000, Decatur, AL 35609 Dates: November 13, 2007 through December 14, 2007 Inspectors: D. Jones, Senior Reactor Inspector (Team Leader)
C. Stancil, Resident Inspector R. Taylor, Reactor Inspector L. Bradford, Reactor Inspector, in training R. Patterson, Reactor Inspector, in training J. Leivo, Contract Inspector H. Anderson, Contract Inspector Approved by: Binoy B. Desai, Chief Engineering Branch 1 Division of Reactor Safety Enclosure
SUMMARY OF FINDINGS
IR 05000259/2007007, 05000260/2007007, 05000296/2007007; 11/13/07 - 12/14/07; Browns
Ferry Nuclear Plant, Units 1, 2 and 3; Component Design Bases Inspection.
This inspection was conducted by a team of seven NRC inspectors, which included two NRC inspectors in training, one resident inspector, and two NRC contract inspectors. Two findings of very low significance were identified during this inspection and were classified as non-cited violations. The significance of most 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 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, (ROP) Revision 4, dated December 2006.
NRC-Identified and Self-Revealing Findings
Cornerstone: Mitigating Systems
- Green.
The inspectors identified a Green non-cited violation of 10 CFR 50.55a(g)4 Codes and Standards. Specifically, the licensee failed to perform required code inspections of accessible portions of safety-related piping. The licensee entered this issue into their corrective action program.
This finding is more than minor because if left uncorrected it would become a more significant safety concern. The failure to perform required inspections of safety-related piping could have allowed undetected through-wall flaws to remain in-service.
These undetected flaws could grow in size until leakage from the piping degrades system operation, or if sufficient general corrosion occurs, a gross rupture or collapse of the piping could occur. The finding is of very low safety significance because the finding did not represent a loss of safety function. The cause of the finding is related to the cross-cutting element of problem identification and resolution under the operating experience aspect of the corrective action component P.2(b).
[Section 1R21.4]
- Green.
The inspectors identified a Green non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action. Specifically, the licensee failed to correct a cable submergence issue which resulted in the failure of a safety-related cable.
This finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding is of very low safety significance because the finding was not a design or qualification deficiency, and did not represent a loss of safety function because the redundant train was available. The cause of the finding is related to the cross-cutting element of problem identification and resolution under the licensee thoroughly evaluates problems aspect of the corrective action component P.1(c). [Section 1R21.5]
Licensee-Identified Violations
None
REPORT DETAILS
REACTOR SAFETY
Cornerstones: Mitigating Systems and Barrier Integrity
1R21 Component Design Bases Inspection
.1 Inspection Sample Selection Process
The team selected risk significant components and operator actions for review using information contained in the licensees Probabilistic Risk Assessment (PRA). In general, this included components and operator actions that had a risk achievement worth factor greater than two or Birnbaum value greater than 1 X10E-6. The components selected were located within the emergency equipment cooling water system, residual heat removal service water system, high pressure safety injection, reactor core isolation cooling, 4160 VAC electrical system, and 480 VAC electrical system. The sample selection included 18 components, four operator actions, and four operating experience items. Additionally, the team reviewed four modifications by performing activities identified in IP 71111.17, Permanent Plant Modifications, Section 02.02.a. and IP 71111.02, Evaluations of Changes, Tests, or Experiments.
The team performed a margin assessment and detailed review of the selected risk-significant components to verify that the design bases have been correctly implemented and maintained. This design margin assessment considered original design issues, margin reductions due to modification, or margin reductions identified as a result of material condition issues. Equipment reliability issues were also considered in the selection of components for detailed review. These included items such as failed performance test results, significant corrective action, repeated maintenance, maintenance rule (a)1 status, Regulatory Issue Summary 05-020 (formerly Generic Letter 91-18) conditions, NRC resident inspector input of problem equipment, system health reports, industry operating experience and licensee problem equipment lists.
Consideration was also given to the uniqueness and complexity of the design, operating experience, and the available defense in depth margins. An overall summary of the reviews performed and the specific inspection findings identified are included in the following sections of the report.
.2 Results of Detailed Reviews
.2.1 D3 Emergency Equipment Cooling Water (EECW) Pump
a. Inspection Scope
The team reviewed design criteria documents, safety analysis report, technical specifications, technical requirements manual, and applicable plant calculations and evaluations, procedures, and drawings to identify the design bases requirements of the EECW pumps. The team examined equipment history documentation to verify that the design bases had been maintained. The team examined records of surveillance testing, maintenance and modification activities, and applicable corrective actions to verify that potential degradation was being monitored and prevented or corrected. The team reviewed the availability of water from the suction source under routine service as well as the extremes of high and low water conditions. These reviews included: available water levels; water temperatures and associated instrumentation; the provision of adequate pump NPSH; submergence protection; and adequate minimum flow protection to verify that the pump was capable of performing its function under design bases conditions. The reviews also included verification of related aspects of hydraulic models and calculations which demonstrated the capability of the pumps to provide system flows and developed heads in accordance with design bases requirements in servicing emergency equipment cooling loads. The team reviewed the licensees establishment, review, and maintenance of pump performance and test criteria which included the use of instrument uncertainty. The team reviewed the inservice testing program to verify that ASME Code requirements were met. The team also conducted field walkdowns of portions of the pump, system piping, and associated supporting equipment to verify, by visual observation of reasonably accessible locations, that the installed configuration and material condition were consistent with the design bases and plant drawings.
b. Findings
No findings of significance were identified.
.2.2 A2 Residual Heat Removal Service Water (RHRSW) Pump
a. Inspection Scope
The team reviewed design criteria documents, safety analysis report, technical specifications, technical requirements manual, and applicable plant calculations and evaluations, procedures, and drawings to identify the design bases requirements of the RHRSW pumps. The team examined equipment history documentation to verify that the design bases had been maintained. The team examined records of surveillance testing, maintenance and modification activities, and applicable corrective actions to verify that potential degradation was being monitored and prevented or corrected. The team reviewed the availability of water from the suction source under routine service as well as the extremes of high and low water conditions. These reviews included: available water levels; water temperatures and associated instrumentation; the provision of adequate pump NPSH; submergence protection; and adequate minimum flow protection to verify that the pump was capable of performing its function under design bases conditions. The reviews also included verification of related aspects of hydraulic models and calculations which demonstrated the capability of the pumps to provide system flows and developed heads in accordance with design bases requirements in servicing residual heat removal cooling loads. The team reviewed the licensees establishment, review, and maintenance of pump performance and test criteria which included the use of instrument uncertainty. The team reviewed the inservice testing program to verify that ASME Code requirements were met. The team also conducted field walkdowns of portions of the pump, system piping, and associated supporting equipment to verify, by visual observation of reasonably accessible locations, that the installed configuration and material condition were consistent with the design bases and plant drawings.
b. Findings
No findings of significance were identified.
.2.3 Unit 1 Reactor Core Isolation Cooling (RCIC) Pump
a. Inspection Scope
The team reviewed design criteria documents, safety analysis report, technical specifications, technical requirements manual, and applicable plant calculations and evaluations, procedures, and drawings to identify the design bases requirements of the RCIC pump. The team examined equipment history documentation to verify that the design bases had been maintained. The team examined records of surveillance testing, maintenance and modification activities, and applicable corrective actions to verify that potential degradation was being monitored and prevented or corrected. The team reviewed the availability of water from the condensate system, as well as from the torus to meet design bases requirements. These reviews included: available water levels; water temperatures and associated instrumentation; transfer of suction from the condensate system to the torus; provision of adequate pump NPSH; submergence protection; and adequate minimum flow protection to verify that the pump was capable of performing its function under design bases conditions. The reviews also included verification of related aspects of evaluations and calculations which demonstrated the capability of the pump to provide system flows and developed heads in accordance with design bases requirements in the respective calculations. The team reviewed the licensees establishment, review, and maintenance of pump performance and test criteria which included the use of instrument uncertainty. The team reviewed the inservice testing program to verify that ASME Code requirements were met. The team also conducted field walkdowns of portions of the turbine, pumps, system auxiliaries (cooling, lubrication, etc.), minimum flow provisions, steam lines, valves, and ventilation by visual observation of reasonably accessible locations, to verify that the installed configuration and material condition of the pumps were consistent with the design bases and plant drawings.
b. Findings
No findings of significance were identified.
.2.4 Unit 1 RCIC Steam Supply Valve
a. Inspection Scope
The team reviewed the design criteria documents, safety analysis report, and applicable motor operated valve and electrical distribution calculations, evaluations, and procedures to identify the design bases requirements of the Unit 1 RCIC steam supply valve. The team examined selective representative equipment history documentation related to the valve to verify that design bases have been maintained; that cabling requirements have been met during cable replacement; and that MOV testing and periodic testing of the steam supply valve have been performed demonstrating the design bases capability of the valve. The team examined records and test data to verify that valve performance against design bases criteria was being monitored. The team also conducted field walkdowns of reasonably accessible portions of the RCIC steam line and valve to confirm the installed configuration and material conditions were consistent with the design bases and plant drawings.
b. Findings
No findings of significance were identified.
.2.5 Unit 1 High Pressure Coolant Injection (HPCI) Pump
a. Inspection Scope
The team reviewed design criteria documents, safety analysis report, technical specifications, technical requirements manual, and applicable plant calculations and evaluations, procedures, and drawings to identify the design bases requirements of the HPCI pump. The team examined equipment history documentation to verify that the design bases had been maintained. The team examined records of surveillance testing, maintenance and modification activities, and applicable corrective actions to verify that potential degradation was being monitored and prevented or corrected. The team reviewed the availability of water from the condensate system, as well as from the torus to meet design bases requirements. These reviews included: available water levels; water temperatures and associated instrumentation; transfer of suction from the condensate system to the torus; provision of adequate pump NPSH; submergence protection; and adequate minimum flow protection to verify that the pump was capable of performing its function under design bases conditions. The reviews also included verification of related aspects of evaluations and calculations which demonstrated the capability of the pump to provide system flows and developed heads in accordance with design bases requirements in the respective calculations. The team reviewed the licensees establishment, review, and maintenance of pump performance and test criteria which included the use of instrument uncertainty. The team reviewed the inservice testing program to verify that ASME Code requirements were met. The team also conducted field walkdowns of portions of the turbine, pump, system auxiliaries (cooling, lubrication, etc.), minimum flow provisions, steam line, valves, and ventilation by visual observation of reasonably accessible locations, to verify that the installed configuration and material condition of the pump were consistent with the design bases and plant drawings.
b. Findings
No findings of significance were identified.
.2.6 Unit 1 HPCI Steam Supply Valve
a. Inspection Scope
The team reviewed design criteria documents, safety analysis report, and applicable motor operated valve and electrical distribution calculations, evaluations, and procedures to identify the design bases requirements of the Unit 1 HPCI steam supply valve. The team examined selective representative equipment history documentation related to the valve to verify that design bases have been maintained, that cabling requirements have been met during replacement of specific cables, and that MOV testing and periodic testing of the steam supply valve have been performed demonstrating the design bases capability of the valve. The team examined records and test data to verify that valve performance against design bases criteria was being monitored. The team also conducted field walkdowns of reasonably accessible portions of the HPCI steam lines and valves to verify the installed configuration and material conditions were consistent with the design bases and plant drawings.
b. Findings
No findings of significance were identified.
.2.7 HPCI Start Logic
a. Inspection Scope
The team reviewed electrical elementary and logic diagrams for the HPCI pump initiation logic to verify that the pump initiation logic, valve permissives and interlocks were consistent with the system operational requirements described in the UFSAR. The team also reviewed the design of instrument loops and energy sources to verify that electrical signals from Reactor Vessel Low-Water Level and Primary Containment (Drywell) High Pressure indications would be available and unimpeded during accident/event conditions. Design drawings and other design documents were reviewed to verify that the as-built instruments range, accuracy, power supplies and setpoints were in accordance with design bases documents. Time delays and associated tolerances for relays were also reviewed to determine whether the scheme would perform properly and would avoid spurious trips. The team also reviewed instrument calibration and functional test records to verify that instrument loops performed as expected and were calibrated in accordance with the calibration program procedures and the Technical Specifications, where applicable. The team walked down those instruments that were accessible to verify that they were in good material condition and had been located and oriented in accordance with design documents.
b. Findings
No findings of significance were identified.
.2.8 RCIC Start Logic
a. Inspection Scope
The team reviewed electrical elementary and logic diagrams for the RCIC pump initiation logic to ensure that the pump initiation logic, valve permissives and interlocks were consistent with the system operational requirements described in the UFSAR. The team also reviewed the design of instrument loops and energy sources to verify that electrical signals required for initiation would be available and unimpeded during accident/event conditions. Design drawings and other design documents were reviewed to verify that the as-built instruments range, accuracy, power supplies and setpoints were in accordance with design bases documents. Time delays and associated tolerances for relays were also reviewed to determine whether the scheme would perform properly and would avoid spurious trips. The team also reviewed instrument calibration and functional test records to verify that instrument loops performed as expected and were calibrated in accordance with the calibration program procedures and the Technical Specifications, where applicable. The team walked down those instruments that were accessible to verify that they were in good material condition and had been located and oriented in accordance with design documents.
b. Findings
No findings of significance were identified.
.2.9 1B Residual Heat Removal (RHR) Room Cooler
a. Inspection Scope
The team reviewed the design requirements of the RHR Room Coolers including portions of the UFSAR, Technical Specifications, flow diagrams, and electrical & control schematics to identify the heat removal requirements and capability of the room coolers to remove the required heat load. Heat load calculations and associated RHR flow requirements were reviewed to verify that the design bases has been maintained. In addition flow balance tests and associated test deficiencies and resolutions were reviewed to verify that potential degradation was being monitored and prevented or corrected. The team also conducted a walkdown of the fans and motors to assess the systems overall operability and condition.
b. Findings
No findings of significance were identified.
.2.10 1B Core Spray (CS) Room Cooler
a. Inspection Scope
The team reviewed the design requirements of the CS Room Coolers including portions of the UFSAR, Technical Specifications, flow diagrams, and electrical & control schematics to identify to identify the heat removal requirements and capability of the room coolers to remove the required heat load. Heat load calculations and associated CS flow requirements were reviewed to verify that the design bases have been maintained. In addition flow balance tests and associated test deficiencies and resolutions were reviewed to verify that potential degradation was being monitored and prevented or corrected. The team also conducted a walkdown of the fans and motors to assess the systems overall operability and condition.
b. Findings
No findings of significance were identified.
.2.11 2A RHR Heat Exchanger (HX)
a. Inspection Scope
The team reviewed the HX specification information, design bases information and supporting calculations to identify the heat removal requirements and capability of the HX to remove the required heat load. The review included examining the tube plugging limits, the bases for the limits, and assessing the number of tubes presently plugged. The maintenance, inspection, and performance testing were reviewed to verify the capability of the HX to remove the design heat load as well as to verify the adequacy of flow testing for both the shell side and tube side of the HX. The team reviewed the licensee's use of the fouling factor parameter, the correct use of the design temperature of the ultimate heat sink and the projection of test results to accident parameters to assess their capability to identify the HX's performance degradation. In addition, the team verified that sufficient margins exist. The team reviewed the trending of the performance of the HX as well as the frequency of the thermal testing and schedule for visual inspection and cleaning to verify that potential degradation was being monitored and prevented or corrected. The team reviewed the station's overall implementation of GL 89-13, Service Water System Problems Affecting Safety-Related Equipment, to verify that requirements applicable to the RHR HX were addressed.
b. Findings
No findings of significance were identified.
.2.12 2A RHR Heat Exchanger Outlet Valve (FCV-23-34)
a. Inspection Scope
The team reviewed the design bases documentation, supporting calculations, drawings, and the UFSAR to identify the design bases function of valve FCV-23-34. Modification and corrective action history of the flow control valve was reviewed to verify that component degradation was being monitored and prevented or corrected. The team reviewed the corrective maintenance history of the valve assembly to assess its reliability to position the valve for decay heat removal and accident conditions. Service history records for preventative maintenance and surveillance program documentation governing this component were examined to ensure that indications of degraded performance were being identified, evaluated and trended. Additionally, the vendors manual was reviewed to verify that the valve was being operated and maintained in accordance with industry and manufacturer's recommendations. The team walked down the valve to assess the valves operability and condition.
b. Findings
No findings of significance were identified.
.2.13 3B Diesel Generator (DG) Heat Exchanger
a. Inspection Scope
The team reviewed the HX specification information, design bases information and supporting calculations to identify the heat removal requirements and capability of the HXs to remove the required heat load. The review included examining the tube plugging limits, the bases for the limits, and assessing the number of tubes presently plugged.
The maintenance, inspection, and performance testing were reviewed to verify the capability of the HX to remove the design heat load as well as to verify the adequacy of flow testing for both the shell side and tube side of the HX. The team reviewed the licensee's use of the fouling factor parameter, the correct use of the design temperature of the ultimate heat sink and the projection of test results to accident parameters to assess their capability to identify the HX's performance degradation. In addition, the team verified that sufficient margins exist. The team reviewed the trending of the performance of the HX as well as the frequency of the thermal testing and schedule for visual inspection and cleaning to verify that potential degradation was being monitored and prevented or corrected. The team reviewed the station's overall implementation of GL 89-13, Service Water System Problems Affecting Safety-Related Equipment, to verify that requirements applicable to the DG HX were addressed.
b. Findings
No findings of significance were identified.
.2.14 1A / 2A 4160 Volts Alternating Current (VAC) Unit Boards
a. Inspection Scope
The team reviewed design criteria documents, safety analysis report, technical specifications, calculations and drawings to identify the design and licensing bases for the 4160 VAC unit boards associated with serving the preferred (offsite) sources of power to safety-related loads. The team selectively reviewed bus and breaker ratings, specifications, load flow calculations, and protective device settings, to confirm that the unit boards would be capable of supplying necessary loads for mitigating design bases events and for achieving safe shutdown in accordance with the design bases. The team reviewed the governing PM procedures, the latest PM records for a sample of unit board circuit breakers, system health reports and the corrective action history to assess the effectiveness of maintenance and consistency with vendor recommendations. The team also performed non-intrusive visual inspections of the unit boards, to assess material condition and vulnerability to hazards (flooding, seismic interactions, and missiles).
b. Findings
No findings of significance were identified.
.2.15 4160 VAC Shutdown Bus No. 1
a. Inspection Scope
The team reviewed design criteria documents, safety analysis report, technical specifications, calculations and drawings to identify the design bases for the 4160 VAC shutdown buses associated with serving the preferred (offsite) sources of power to safety-related loads. The team selectively reviewed bus and breaker ratings, specifications, load flow calculations, and protective device settings, to confirm that the shutdown bus would be capable of supplying necessary loads for mitigating design bases events and for achieving safe shutdown in accordance with the design bases. In addition, the team selectively reviewed schematic diagrams for the automatic transfer of the 4160 VAC shutdown board to the alternate shutdown bus upon loss of the primary shutdown bus, to confirm that functional requirements were satisfied, and that no credible common cause failures were evident in the circuit design. The team also selectively reviewed test procedures to confirm there was no potential for undetectable failures that could have significant consequences. The team reviewed the governing PM procedures, the latest PM records for a sample of shutdown bus circuit breakers, system health reports and the corrective action history to assess the effectiveness of maintenance and consistency with vendor recommendations. The team selectively reviewed operating procedures, to confirm that load management requirements levied by electrical loading calculations had been correctly translated into the operating procedures for the shutdown buses. The team also performed non-intrusive visual inspections of the 4160 VAC shutdown boards, to assess visible material condition and vulnerability to hazards (flooding, seismic interactions, and missiles).
b. Findings
No findings of significance were identified.
.2.16 480 VAC Reactor Motor Operated Valve (MOV) Board 1A / 1B
a. Inspection Scope
The team selectively reviewed board and breaker ratings, load flow calculations, degraded voltage calculations, and protective device settings, to confirm that the MOV boards would be capable of supplying the necessary loads for mitigating design bases events and for achieving safe shutdown in accordance with the design bases. The team reviewed the governing PM procedures, the latest PM records for a sample of MOV board circuit breakers, system health reports and the corrective action history to assess the effectiveness of maintenance and consistency with vendor recommendations. The team also performed non-intrusive visual inspection of the MOV boards, to assess visible material condition and vulnerability to hazards (flooding, seismic interactions, and missiles).
b. Findings
No findings of significance were identified.
.2.17 RHRSW Pump A2 Motor and Cable
a. Inspection Scope
The team reviewed design criteria documents, safety analysis report, technical specifications, calculations and drawings to identify the design bases functions of the component. The team reviewed the schematic diagrams to verify that the pump motor control circuits were consistent with the design bases functional requirements. The team reviewed electrical load flow calculations, nameplate data, and brake horsepower calculations to confirm that the brake horsepower required by the pump was within the motor rating and was consistent with design inputs to the electrical calculations. The team reviewed the protective device settings for the pump motor and confirmed that the circuit breaker ratings and protective devices trip settings were consistent with the design bases. The team reviewed the AC voltage calculations to confirm that adequate voltage would be provided at the motor terminals under design bases conditions. To assess the effectiveness of preventive maintenance (PM) and consistency with vendor recommendations, the team selectively reviewed the documentation supporting the evaluation and refurbishment of the B3 motor, and discussed the most recent motor bearing oil analysis of the remaining RHRSW motors with cognizant licensee staff. The team also selectively reviewed the governing PM procedures and results of the last PMs performed for the motors. The team also performed a walkdown of the pump motors and environs located in the intake pumping structure to assess observable material condition of the pump motors, vulnerability to hazards (external or internal flooding, weather phenomena, seismic interactions, and missiles), and to assess the effectiveness of design features, such as flood doors and sump pumps.
To assess the potential for degradation of the underground medium voltage motor feeder cables as a result of long-term submergence or wetting, the team reviewed the drawings showing the routing of the motor feeder cables through an underground duct bank, and performed walkdowns and visual inspections of the two manholes and the conduit entering the intake pumping structure. The team also reviewed the licensees corrective actions, including functional evaluations, failure analyses, laboratory testing, and design changes, taken in response to a failure of the cable serving the A2 motor on February 11, 2007.
b. Findings
Unresolved Item: Degraded Flood Protection Doors for the Intake Cooling Structure During system walkdown, the team observed degraded watertight doors at the intake cooling structure which houses the residual heat removal service water (RHRSW) and emergency equipment cooling water (EECW) pumps. Subsequent licensee evaluation of the four watertight doors determined that three of the four were degraded. With the doors closed, gaps up to 1/2 inch existed between the door seal and door frame. The licensee initiated work orders to repair the doors and initiated PER 133899.
The UFSAR (Section 12.2.7.1.2) states in part that the doors provide flood protection against the probable maximum flood (PMF) of 572.5 feet. For the PMF, the licensee located a TVA corporate calculation (GEN-CEB-CDQ-0999-98-00-01) which states the PMF is 569.2 feet, not 572.5 feet.
This item is unresolved pending the following:
The licensees acceptance of the 1998 calculation as their design basis for the PMF.
The inspectors review of the new design basis for the PMF.
Using the revised PMF, the inspectors review and inspection of the licensees evaluation of the potential impact of the degraded doors.
This item is identified as URI 05000259/2007007-03, 05000260/2007007-03 and 05000296/2007007-03, Degraded Flood Protection Doors for the Intake Cooling Structure.
.2.18 EECW Pump D3 Motor and Feeder Cable
a. Inspection Scope
The team reviewed design criteria documents, safety analysis report, technical specifications, calculations and drawings to identify the design bases functions of the component. The team reviewed the schematic diagrams to verify that the pump motor control circuits were consistent with the design bases functional requirements. The team reviewed electrical load flow calculations, nameplate data, and brake horsepower calculations to confirm that the brake horsepower required by the pump was within the motor rating and was consistent with design inputs to the electrical calculations. The team reviewed the protective device settings for the pump motor and confirmed that the circuit breaker ratings and protective devices trip settings were consistent with the design bases. The team reviewed the AC voltage calculations to confirm that adequate voltage would be provided at the motor terminals under design bases conditions. The team also reviewed the governing PM procedures and results of the last PMs performed for the motor. The team performed a walkdown of the pump motors and environs located in the intake pumping structure to assess observable material condition of the pump motors, vulnerability to hazards (external or internal flooding, weather phenomena, seismic interactions, and missiles), and to assess the effectiveness of design features, such as flood doors and sump pumps. To assess the potential for degradation of the medium voltage motor feeder cables as a result of long-term submergence or wetting, the team performed walkdowns and visual inspections of the underground cable tunnel from the turbine building to the intake pumping structure.
b. Findings
No findings of significance were identified.
.3 Review of Low Margin Operator Actions
a. Inspection Scope
The team performed a margin assessment and detailed review of a sample of risk significant and time critical operator actions. Where possible, margins were determined by the review of the assumed design bases and safety analysis report response times and performance times documented by job performance measure results within operator time critical task verification tests. For the selected operator actions, the team performed a walk through of associated Emergency Operating Instructions , Abnormal Operating Procedures , Annunciator Response Procedures, and other operations procedures with appropriate plant operators and engineers to assess operator knowledge level, adequacy of procedures, availability of special equipment when required, and the conditions under which the procedures would be performed. Detailed reviews were also conducted with risk assessment engineers, engineering safety analysts, training department leadership, and through observation and utilization of a simulator training period to further understand and assess the procedural rationale and approach to meeting the design bases and safety analysis report response and performance times. Operator actions in response to the following events were reviewed:
- Aligning RHR for suppression pool cooling
- Aligning Unit 1 RHR crosstie to supply Unit 2
- Isolating EECW flooding in the Reactor Building
b. Findings
No findings of significance were identified.
.4 Review of Industry Operating Experience (OE)
a. Inspection Scope
The team reviewed selected OE issues from domestic and foreign nuclear facilities for applicability at the Browns Ferry Nuclear Plant to determine the need for a detailed review. The issues that received a detailed review by the team included:
- IN 2007-06, Potential Common Cause Vulnerabilities in Essential Service Water (ESW) Systems
- NRC GL 2007-01, Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients
- IN 2006-15, Vibration-Induced Degradation and Failure of Safety-Related Valves
b. Findings
Introduction:
The team identified a violation of 10 CFR 50.55a(g)4 for failing to perform visual inspections as required by the ASME code for piping associated with the residual heat removal service water and emergency equipment cooling water systems.
Description:
Sections of the discharge piping for the residual heat removal service water (RHRSW) and emergency equipment cooling water (EECW) pumps are located in piping vaults below the associated pump rooms. The RHRSW and EECW piping enters the vaults via floor penetrations, turns ninety degrees and exits the vaults via wall penetrations. Access to the vaults is through bolted manhole covers which are located on the floors of the pump rooms. All eight vaults were observed to be full of water, two were identified during the teams walkdown as well as the remaining six during the licensees subsequent inspection.
The licensees investigation (PER 135201) determined that the water was entering the vaults from either structural joints, or the joints at the end of the sleeves where the piping goes horizontally through the vault wall. The licensees inspection of the piping revealed minor surface corrosion which included pitting. The licensee has planned corrective actions to perform base metal evaluations to confirm that no significant degradation exists and to apply a protective coating for the immersed piping. Additionally, the licensee plans to consider actions to seal the vaults from water intrusion.
ASME Section XI, IWA-5241(a) requires visual examinations (VT-2) of accessible external exposed surfaces of pressure retaining piping. Through interviews, the team determined that the licensee does not perform periodic inspections of the vaults and has never performed the required VT-2 examinations. The VT-2 examinations were not performed because the licensees ISI program has always deemed the areas to be inaccessible because of the bolted manhole covers. The team determined that the vaults are accessible because during the inspection the licensees staff removed two of the bolted man-hole covers with minimal effort in the presence of the inspectors. The licensees lack of inspections in the vaults resulted in the failure to identify the flooded vaults and degraded piping.
Additionally, the team determined that the licensees review of IN 2007-06, Potential Common Cause Vulnerabilities in Essential Service Water Systems was a missed opportunity to identify the need to inspect the piping. The IN documented two events at foreign operating reactors in which external corrosion of piping located in vaults caused catastrophic losses of essential service water.
Analysis:
The licensees failure to conduct ASME required VT-2 inspections by determining that the piping vaults were inaccessible is a performance deficiency. This finding is more than minor because if left uncorrected it would become a more significant safety concern. The failure to perform inspections of the piping could have allowed undetected through-wall flaws to remain in-service. These undetected flaws could grow in size until leakage from the piping degrades system operation, or if sufficient general corrosion occurs, a gross rupture or collapse of the RHRSW and EECW piping sections could occur. The inspectors determined that the finding is of very low safety significance (Green) using the SDP because the finding is not a design or qualification deficiency, it did not represent a loss of safety function, it did not represent an actual loss of safety function of a single train for greater than the TS allowed outage time, and the finding was not potentially risk significant due to external events. The finding directly involved the cross-cutting area of PI&R under the operating experience aspect of the corrective action component, in that the licensee failed to implement and institutionalize operating experience that addressed external corrosion of piping located in vaults
Enforcement:
10 CFR 50.55a(g)4 Codes and Standards states in part that ASME code class components must meet the requirements of Section XI of the ASME Boiler Pressure Vessel Code to the extent practical within the limitations of design, geometry and materials. Contrary to the above, for the 2nd inspection interval (5/92 - 5/01) to the 1986 Edition of the ASME code, Browns Ferry did not perform required inspections for accessible portions of safety-related piping. Because this finding is of very low safety significance and because it was entered into the licensees corrective action program as PER 135201, this violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000259/2007007-01, 05000260/2007007-01 and 05000296/2007007-01, Failure to Perform ASME Inspections of Safety-Related Piping.
.5 Review of Permanent Plant Modifications
a. Inspection Scope
The team reviewed four modifications related to the selected risk significant components in detail to verify that the design bases, licensing bases, and performance capability of the components have not been degraded through modifications. The adequacy of design and post modification testing of these modifications was reviewed by performing activities identified in IP 71111.17, Permanent Plant Modifications, Section 02.02.a.
Additionally, the team reviewed the modifications in accordance IP 71111.02, Evaluations of Changes, Tests, or Experiments, to verify the licensee had appropriately evaluated them for 10 CFR 50.59 applicability. The following modifications were reviewed:
- DCN T40220C, Impeller Replacement - Allow Replacement of the A2, C1, C2, A1 RHRSW Pump Impellers with an Improved Design and Material Type, Rev. C, 10/29/99
- DCN No. 50851A, Add Weights up to 1500 Lbs. to the Top of Each of the RHRSW Pump Motors, Rev. A, 11/7/01
- EDC 50548A, Calculations for Replacement DG Jacket Water Heat Exchangers, Rev. A.
b. Findings
Introduction:
The NRC identified a Green non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, for failure to correct a previously identified cable submergence issue which resulted in the failure of a safety-related cable for a residual heat removal service water pump.
Description:
In 2001, the licensee identified standing water in man-hole 15 (HH15)which contains the safety-related Division I cables for residual heat removal service water (RHRSW) and emergency equipment cooling water (EECW) pumps. The licensee determined that the cables were not qualified for continued submergence. To keep the cables dry, the licensee installed a level activated sump pump in HH-15 (DCN 50868).
On February 11, 2007 the feeder cable for the A2 RHRSW pump which traverses HH15 failed. Laboratory testing determined that the cause of the failed cable was water treeing. Water treeing is an industry issue where the submergence of medium voltage cables results in moisture induced degradation of the insulation. The licensees investigation (PER 119773) stated that the root cause of the water treeing was inadequate drainage of water from the duct bank. Additionally, another licensee investigation (PER 119954) stated that the Division I cables showed evidence of being continually submerged. The cables submergence was determined to be caused by the inadequate implementation of the 2001 modification (DCN 50868). The modification was inadequate because the sump pump configuration could not remove all water from the man-hole. Therefore, the Division I cables were subject to submergence during the period of 2001 through 2007.
In March 2007, as part of the corrective actions for the failed cable the licensee initiated a modification (DCN 68803) to install another sump pump in HH15. During an inspection of HH15, the team observed standing water in the manhole and the submergence of cables. The licensee determined that the sump pump was not functioning properly because the recently implemented modification (DCN 68803) had installed piping that interfered with the operation of the float mechanism which controls the start and stop function of the pump.
Additionally, the team determined through the review of elevation drawings and walkdowns that HH15 and its associated sump pump are not located at the lowest point in the duct bank. Therefore, even if the sump pump operates as intended the cables will be subjected to submergence from HH15 to junction box 4915 (JB 4915) which is located at the lowest point of the duct bank. The team also noted that DCN 68803 included an action to install a drain in junction box 4915. This licensee deleted this action from the DCN without developing alternative means to remove water from the lowest point of the duct bank. The team concluded that the licensees corrective actions have been ineffective in removing water from the duct bank since 2001.
Analysis:
The inspectors determined that the failure to take appropriate corrective actions to address water intrusion in the safety-related cable duct banks was a performance deficiency. The inspectors concluded that the finding is greater than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined that the finding is of very low safety significance (Green) using the SDP because the finding is not a design or qualification deficiency, it did not represent a loss of safety function because the redundant train was available, it did not represent an actual loss of safety function of a single train for greater than the TS allowed outage time, and the finding was not potentially risk significant due to external events. The finding directly involved the cross-cutting area of PI&R under the licensee thoroughly evaluates problems aspect of the corrective action component, which includes conducting effectiveness reviews of corrective actions to ensure that problems are resolved. On two occasions the licensee failed to identify the ineffectiveness of corrective actions in removing water from the duct bank P.1(c).
Enforcement:
10 CFR 50 Appendix B, Criterion XVI, Corrective Action, states, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, defective material and equipment and non-conformances are promptly identified and corrected. Contrary to the above, the licensee failed to correct a previously identified water intrusion which resulted in a failed cable on February 11, 2007. Because this finding is of very low safety significance and because it was entered into the licensees corrective action program as PER 135132, this violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy:
NCV 05000259/2007007-02, 05000260/2007007-02 and 05000296/2007007-02, Corrective Actions for Cable Submersion Were Not Effective.
OTHER ACTIVITIES
4AO6 Meetings, Including Exit
Exit Meeting Summary
On December 14, 2007, the team presented the inspection results to Mr. OGrady, site vice president, and other members of the licensee staff. The team returned all proprietary information examined to the licensee. No proprietary information is documented in the report.
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- C. Boschetti, Supervisor, Electrical Design Engineering
- J. Davenport, Licensing
NRC
- B. Desai, Chief, Engineering Branch 1, RII
- R. Bernhard, Senior Reactor Analyst
ITEMS OPENED, CLOSED, AND DISCUSSED
Open/Closed
- 05000259/2007007-01, NCV Failure to Perform ASME Inspections of Safety-Related
- 05000260/2007007-01, Piping. (Section 1R21.4)
- 05000259/2007007-02, NCV Corrective Actions for Cable Submersion Were Not
- 05000260/2007007-02, Effective. (Section 1R21.5)
- 05000296/2007007-02 Open
- 05000259/2007007-03, URI Degraded Flood Protection Doors for the Intake
- 05000260/2007007-03, Cooling Structure. (Section 1R21.2.17)