IR 05000348/2004006
| ML040890719 | |
| Person / Time | |
|---|---|
| Site: | Farley  |
| Issue date: | 03/18/2004 |
| From: | Ogle C NRC/RGN-II/DRS/EB |
| To: | Stinson L Southern Nuclear Operating Co |
| References | |
| IR-04-006 | |
| Download: ML040890719 (30) | |
Text
rch 18, 2004
SUBJECT:
JOSEPH M. FARLEY NUCLEAR PLANT - NRC SAFETY SYSTEM DESIGN AND PERFORMANCE CAPABILITY INSPECTION REPORT NOS.
05000348/2004006 AND 05000364/2004006
Dear Mr. Stinson:
On February 13, 2004, the Nuclear Regulatory Commission (NRC) completed a safety system design and performance capability inspection at your Farley Nuclear Plant, Units 1 and 2. The enclosed report documents the inspection findings which were discussed on February 13, 2004, with Mr. R. Johnson and other members of your staff. Following completion of additional reviews in the Region II office, a final exit was held by telephone with Mr. D. Grissette and other members of your staff on March 15, 2004.
This inspection was an examination of activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations, and with the conditions of your operating license. Within these areas, the inspection involved selected examination of procedures and representative records, observations of activities, and interviews with personnel.
Based on the results of this inspection, no findings of significance were identified. However, one licensee-identified violation, which was determined to be of very low safety significance, is listed in Section 4OA7 of this report. If you contest this non-cited violation, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Farley site.
SNC 2 In accordance with 10 CFR 2.390 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/
Charles R. Ogle, Chief Engineering Branch 1 Division of Reactor Safety Docket Nos.: 50-348, 50-364 License Nos.: NPF-2, NPF-8
Enclosure:
NRC Inspection Report Nos. 05000348/2004006, 05000364/2004006 w/Attachment: Supplemental Information
REGION II==
Docket Nos.: 50-348, 50-364 License Nos.: NPF-2, NPF-8 Report Nos.: 05000348/2004006 and 05000364/2004006 Licensee: Southern Nuclear Operating Company, Inc.
Facility: Farley Nuclear Plant Location: 7388 N. State Highway 95 Columbia, AL 36319 Dates: January 26-30, 2004 and February 9-13, 2004 Inspectors: J. Moorman, Lead Inspector C. Smith, Senior Reactor Inspector R. Telson, Resident Inspector, Sequoyah Nuclear Plant R. Cortes, Reactor Inspector R. Taylor, Reactor Inspector Intern F. Jape, Senior Project Manager (Week 1 only)
Approved by: Charles R. Ogle, Chief Engineering Branch 1 Division of Reactor Safety Enclosure
SUMMARY OF FINDINGS
IR 05000348/2004-006, 05000364/2004-006; 01/26-30/2004 and 02/09-13/2004;
Joseph M. Farley Nuclear Plant, Units 1 & 2; Safety System Design and Performance Capability Inspection.
This inspection was conducted by a team of regional inspectors and a visiting resident inspector. No findings of significance were identified. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.
NRC-Identified and Self-Revealing Findings
No findings of significance were identified.
Licensee-Identified Violations
A violation of very low safety significance, which was identified by the licensee, has been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. This violation and corrective action tracking numbers are listed in Section 4OA7 of this report.
REPORT DETAILS
REACTOR SAFETY
Cornerstones: Initiating Events and Mitigating Systems
1R21 Safety System Design and Performance Capability
This team inspection reviewed selected components and operator actions that would be used to prevent or mitigate the consequences of a steam generator tube rupture (SGTR) event. Components in the main steam (MS), auxiliary feedwater (AFW), steam generator (SG) blowdown, chemical volume and control (CVCS), reactor coolant (RCS),and radiation monitoring systems were included. This inspection also covered supporting equipment, equipment which provides power to these components, and the associated instrumentation and controls. The SGTR event is a risk-significant event as determined by the licensees probabilistic risk assessment.
.1 System Needs
.11 Process Medium
a. Inspection Scope
The team reviewed the AFW and high head safety injection (HHSI) net positive suction head (NPSH) and water source calculations, licensing and design basis information, operating/lineup procedures, drawings, surveillance procedures and vendor manuals.
The review included the refueling water storage tank (RWST), the condensate storage tank (CST), including vortexing considerations, and minimum-flow flowpaths for AFW and HHSI pumps. The review also included the ability of the SG atmospheric relief valves (ARVs) to support RCS cooldown, and the ability of the HHSI pumps to provide cooling of the RCS. The team also conducted field walkdowns of the systems in the plant with primary emphasis on Unit 1. 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 equipment required to mitigate an SGTR event.
The team conducted field walkdowns of Unit 1 electrical components determined to be risk-important for the SGTR event. These walkdowns were conducted to verify that system design, TS, and UFSAR assumptions were consistent with the actual capability of systems and equipment required to mitigate an SGTR event. Components reviewed included feed breaker DF02 from Bus 1F; Load Center 1D; Station Service Transformer 1D and its supply breaker; the supply breaker to motor control center (MCC) 1U; feed breaker DG02 from Bus 1G; Load Center 1E; Station Service Transformer 1E and its supply breaker; MCC 1V and its supply breaker; and Bus 1.
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 components to verify that selected portions of the systems alignment were consistent with the design basis assumptions, performance requirements, and system operating procedures. Among the lineups reviewed were the steam supply to the turbine-driven AFW pump and the sources of air for air operated valves (AOVs) such as the SG ARVs. The team also reviewed the testing and maintenance history for the SG ARVs, including the availability, and reliability of alternate air sources for proper operation of these valves to verify that the system design basis assumptions were consistent with the actual capability of the system.
The team reviewed appropriate test and design documents to verify that the 125 Volts direct current (V dc) and 4.16 kiloVolt alternating current (kV ac) power sources for the AFW and HHSI systems electric pumps and motor-operated valves would be available and adequate in accordance with design basis documents. The team also reviewed MCC design documents to verify appropriate sizing for selected MCC components.
b. Findings
No findings of significance were identified.
.13 Instrumentation and Controls
a. Inspection Scope
Secondary Side Radiation Monitors The team reviewed completed surveillance test records for the main steam relief and SG ARV discharge radiation monitors, the AFW pump turbine exhaust radiation monitor, the condenser air ejector gas radiation monitor, and the steam generator blowdown liquid radiation monitor. These reviews were conducted to verify that these radiation monitors were sufficiently accurate to comply with licensing and design bases requirements as demonstrated by the as-found and final values documented on the calibration data sheets.
Emergency Feed Water Suction Sources The team reviewed calibration records for the RWST and CST level instruments, the main steam line pressure transmitters, steam generator wide range and narrow range level instruments, steam generator pressure instruments, and the pressurizer level instruments. This review was conducted to verify that these instruments were sufficiently accurate to demonstrate compliance with the plants licensing bases as shown by the as-found and as-left conditions. The review was also conducted to verify that the plant calibration procedures had correctly incorporated the tolerances identified in the loop uncertainty calculation for instruments.
b. Findings
No findings of significance were identified.
.14 Operator Actions
a. Inspection Scope
The team reviewed the Emergency Operating Procedures (EOPs) used to mitigate an SGTR to determine if the specified operator actions were consistent with the accident analysis and Westinghouse Owners Group (WOG) guidelines. The team compared the SGTR EOP to the WOG guidelines and step-deviation document to verify that the Farley EOP was consistent with the guidelines and that any deviations were analyzed.
The team observed licensed plant operators perform the SGTR EOP and abnormal operating procedures on the plant simulator in response to a simulated steam generator tube leak followed by an SGTR. This review was conducted to verify that the SGTR mitigation strategy in the EOPs would be implemented and that assumptions and results specified in the UFSAR and the WOG Guidelines would be met. This observation was also conducted to verify that control board indication and plant alarms provided adequate information to the operators to support procedurally required decisions that would result in successful event mitigation.
b. Findings
No findings of significance were identified.
.15 Heat Removal
a. Inspection Scope
The team reviewed design calculations, drawings, surveillance and test procedures, and operating data for selected equipment to assess the reliability and availability of cooling for equipment required to mitigate an SGTR event. The team also conducted field walkdowns of the equipment to verify that operating conditions were consistent with design assumptions. The equipment reviewed included HHSI and AFW pumps and testing of these pumps at both full and minimum flow conditions. The team also verified that test results demonstrated adequate cooling of the pumps bearings and that room coolers for the low head safety injection and HHSI pumps were adequate to ensure room cooling during design basis events.
The team reviewed historical temperature data for the Unit 1 station battery rooms to verify that the room temperatures remained within allowable temperature limits specified for the batteries.
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 components in the HHSI, AFW, MS, service water (SW), and component cooling water (CCW) systems to assess observable material condition and the installed configuration of components. Particular attention was placed on verifying that selected valves and components in these systems were in their required position and that the configuration was consistent with design drawings.
The team also inspected selected controls and indicators for appropriate human factors considerations, such as labeling arrangement and visibility.
The team performed field walkdowns of the CST and RWST level instruments. These walkdowns were performed in order to assess the observable material condition and to inspect the installed configurations for compliance with approved instrument installation drawings. The team also verified that the installed instruments were provided with freeze protection in accordance with the requirements shown on the installation drawings.
The team performed field walkdowns of selected portions of the 125 V dc and 4.16 kV ac systems to verify that the installed configuration was consistent with design basis information, to assess observable material condition, installation configuration, and identify degraded conditions of those components that could be used to mitigate an SGTR event. The team also inspected selected controls and indicators 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 performed field walkdowns of selected components specified in the SGTR EOP for which local operation was required, to verify that operators could adequately determine component status and that the components could be operated under conditions that would exist during an SGTR event. These components included the TDAFW steam supply AOVs, their isolation valves, and the associated air system valves. The team performed field walkdowns of the SG ARV discharge lines to verify that radiological survey points specified by Procedure FNP-0-RCP-25, Health Physics Activities During A Radiological Accident, were appropriately marked, readily visible, and accessible for local radiation monitoring.
The team reviewed the quality control documentation for the primary-to-secondary leak rate determination computer program to verify that the program was developed, tested, and maintained using quality control standards.
b. Findings
No findings of significance were identified.
.23 Design
a. Inspection Scope
Mechanical Design The team reviewed vendor manuals for the HHSI and AFW pumps, vendor manuals for selected check valves, the UFSAR, and the TS to verify that vendor recommendations and licensing basis requirements had been appropriately translated into the design calculations and surveillance requirements. In addition, NPSH calculations and head curve data for both the AFW and HHSI pumps were reviewed to verify that adequate water levels were available in the CST and RWST. Vortexing considerations were also reviewed.
The team reviewed records of design changes and preventive maintenance; and performed field walkdowns of selected components in the HHSI, SW, CCW, MS, and AFW 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.
Electrical Design The team reviewed emergency diesel generator loading calculations for both loss of off-site power and safety injection scenarios to assess the adequacy to provide electrical power for selected components required to mitigate an SGTR event.
The team reviewed portions of document A-181987 Motor Starter Control Documentation of an Engineering Judgment addressing the operability of MCC 1V, compartment S2 with an undersized control power transformer. This review was conducted to verify that minimum operable voltage design bases and design assumptions had been appropriately translated into design calculations and procedures.
Instrumentation and Control The team reviewed design change package (DCP) S001-9562-0-003, Rescale RWST Level Transmitters & Delete Alarms, and document A-508666, Scaling for RWST Level Loops. The reviews were performed to verify that main control room indications and set point alarms associated with rescaling of the RWST level transmitters had been correctly incorporated into plant calibration and operation procedures. The team also reviewed completed surveillance tests performed in accordance with the requirements of TS SR 3.5.4.2 for the RWST in order to verify that Required Value criteria delineated in the calibration procedures for indications and alarms were consistent with the values documented in the set point and scaling document and the loop uncertainty calculation.
The team evaluated DCP No. B95-2-8865-1-005, R60 Radiation Detector Enhancement and the associated 10 CFR 50.59 evaluation to verify that the design changes were consistent with the plant licensing and design bases.
b. Findings
No findings of significance were identified.
.24 Testing and Inspection
a. Inspection Scope
The team reviewed records of completed surveillance tests, performance tests, inspections, and predictive maintenance; and performed field walkdowns of selected components in the HHSI, AFW and MS systems to verify that the tests and inspections were appropriately verifying that the assumptions of the licensing and design bases were being maintained. This review included testing of pump discharge pressures and flowrates during full and recirculation flow conditions, valve stroke times, motor operated valve (MOV) torque and limit switch settings, and check valve operation; and analysis of pump bearing oil and vibration. A more detailed list of the components is provided in the
.
The team evaluated test records, including preventive maintenance and performance tests results for 125 V dc batteries 1A and 1B to verify that the batteries were capable of meeting design basis load requirements. The team also reviewed performance test results for several motor operated valve controllers to verify that motor operated valves would perform under design minimum voltage conditions. A more detailed list of the components reviewed is provided in the Attachment.
b. Findings
No findings of significance were identified.
.3 Selected Components
.31 Component Degradation
a. Inspection Scope
The team reviewed system health reports, Maintenance Rule functional failures, maintenance records, condition reports, and performance trending of selected components in the HHSI, MS, SW, AFW and MS systems to verify that components that were relied upon to mitigate an SGTR event were not degrading to unacceptable performance levels. Among the selected components were AOVs, MOVs, check valves, room coolers and pumps. A more detailed list of components reviewed is provided in the Attachment. The team verified the turbine driven AFW steam supply piping for inclusion of steam traps that would compensate for water accumulation in the piping system and prevent occurrences of water hammer or pump overspeed trip events.
The team reviewed system health reports, corrective maintenance records, condition reports, and performance trending of selected components in the electrical distribution and control systems to verify that components that could be relied upon to mitigate an SGTR event were not degrading to unacceptable performance levels. The selected components included motor operated valve controllers, 125 V dc station batteries and chargers.
The team reviewed preventive maintenance and testing records for 125 V dc batteries and chargers as well as the testing records for MOV controllers to verify the program was being implemented. Additionally, the team examined corrective maintenance records for selected 4.16 kV circuit breakers to assess the licensees corrective actions to maintain the safety function, reliability, and availability of the components in the system. Also, the team reviewed commercial grade dedication packages for selected Class 1E electrical components to evaluate their technical adequacy and to verify that quality assurance requirements were being met.
The team also reviewed an NRC-prompted engineering determination of operability addressing an undersized control power transformer (CPT) in safety-related Motor Control Center (MCC) 1V, Cell S2, the controller for the Unit 1 Accumulator Discharge Motor-Operated Valve (MOV) Q1E21MOV8808B, along with related design basis and component testing documents, to verify that minimum voltage design bases and design assumptions had been appropriately translated into design calculations, plant configuration, and testing procedures.
b. Findings
Undersized Control Power Transformers (CPTs) in Safety-Related Motor Control Center
Introduction:
The team identified an unresolved item related to the adequacy of plant design basis documents and performance of contactors in safety-related MOV starters under minimum design voltage conditions.
Description:
On January 27, 2004, during an equipment walkdown, the team observed a deficiency tag attached to MCC 1V, Cell S2, the controller for Q1E21MOV8808B. This valve is the Unit 1 Accumulator Discharge MOV. The deficiency tag, dated July 5, 2003, identified that the installed 200 volt-amp CPT was undersized according to document A-181987, Fuse Replacement Manual for Unit 1, And Unit 1 & Unit 2 Shared Safety Related Equipment. Document A-181987 indicated that the correct CPT size was 250 volt-amps. Based on a review of historical documents, the team determined that a condition report (CR) had not been generated for this non-conforming condition. As a consequence, an engineering operability determination had not been performed to assess the impact of the undersized CPT on component performance under design minimum voltage conditions nor had the cause or extent of the condition been evaluated. Following team questions on the lack of an operability determination and extent of condition review, these issues were placed into the licensees corrective action program on January 29, 2004 as CRs 2004000377 and 2004000378.
The licensee confirmed that the installed CPT was undersized and replaced it with a 250 volt-amp CPT on January 30, 2004. An operability evaluation of the original deficiency was completed on February 4, 2004. The team reviewed the operability evaluation and discussed it with engineering personnel. According to licensee calculations, the MCC remained operable under design minimum voltage conditions. However, little margin remained for actual contactor performance to vary from the pickup voltage used in design basis calculations. The team requested the licensee to provide contactor testing data to verify that actual contactor performance met or exceeded design basis assumptions.
On February 10, 2004 the licensee provided test data for the affected contactors that was obtained in an October 1992 performance of electrical maintenance Procedure FNP-0-EMP-1513.01, ITE Magnetic Starters and Overload Relays. The data indicated pickup voltages of 86.1 and 90.7 volts. The two values reflect the use of two sets of contactors, one set to open the MOV and the other to close the MOV. The test acceptance criteria for pickup voltage was no greater than 80 percent of 120 volts, or 96 volts. The team observed that, while the contactors satisfied the test acceptance criteria, the criteria and the as-tested performance did not appear to satisfy the design basis requirement that starter contacts pick-up at no more than 85.2 volts. The team requested documentation addressing the bases for the 96 volt test acceptance criteria, the 85.2 volt design voltage, and an explanation of the apparent inconsistency between the design basis document, test acceptance criteria, and as-tested component performance. On February 12, 2004 the licensee initiated CR 2004000589 which documented that the basis for and purpose of the Procedure FNP-0-EMP-1513.01 testing methodology and acceptance criteria were unclear.
The licensee informed the team that Procedure FNP-0-EMP-1513.01 evaluated the contactor minimum pickup voltage by applying a continuously increasing voltage until the contactor was observed to actuate. This voltage was recorded as the minimum pick-up voltage. The licensee stated that in actual operation, the contactor would receive a step application of voltage that would, by design, be greater than or equivalent to 85.2 volts under the most limiting voltage conditions. The licensee further stated that, due to the inductive nature of contactor coils, a step application of voltage would result in contactor pickup at a lower voltage as compared with the application of a slowly increasing voltage. There was a 13 percent difference between the design pickup voltage (85.2 volts) and test acceptance criteria pickup voltage (96 volts) and a six percent difference between the higher as-tested pickup voltage (90.7 volts) and the design pickup voltage. The team requested the licensee to provide objective evidence that the test method employed would produce minimum pickup voltage values with that much error. The data provided to the team by the licensee to support this determination was inconclusive.
The team also reviewed contactor test data for the open and closed contactors of four additional safety-related MOV starters. Of these, three of the eight tests for contactor pickup voltages were above 85.2 volts. The team noted that there was significant variability in the tested contactor pickup voltages. The test-observed pick-up voltages ranged from approximately 61 to 91 volts in the five MOV starters reviewed by the team.
Fifty percent of the tested contactors reviewed tested with pick-up voltages higher than the design-specified 85.2 volts.
The team conducted a limited extent-of-condition review by performing a plant walkdown of five additional MCCs to evaluate the as-found configuration with regard to installed fuses and CPTs. Of these five MCCs, only one was of a size similar to the MCC for Valve Q1E21MOV8808B (ie. specified for a 250 volt-amp CPT). The team observed that it was also incorrectly configured with an (undersized) 200 volt-amp CPT. The licensee initiated CR 2004000594 to evaluate the operability of the associated MOV and to perform an extent of condition review. The licensee determined this MCC was operable.
The team reviewed specifications for contactor pickup voltage in the contactor vendor manual and engineering information provided by the vendor, as well as contactor pickup voltage data from testing performed by Southern Company Services. The applicable ITE vendor manual stated that for Size 3, 120 Vac starters, the pickup voltage was 78%
(93.6 volts) when using a CPT and was 69% (82.8 volts) when not using a CPT. This indicated that contactor pickup voltages would typically be higher when contactors were energized with a CPT (similar to the installed configuration at Farley) than when energized using line voltage. A performance evaluation test of Size 3 starters documented in Southern Company Services Project No.92-076, Agastat Relay and ITE Contactor Performance Evaluation, indicated an average pickup voltage of 81.66 volts (68%). This evaluation did not state if the test was performed with or without the use of a CPT. Engineering information provided by the vendor when the contactors were purchased stated that the contactor minimum pickup voltage was 71% (85.2 volts).
However, this information did not state whether the 71% value was determined with or without using a CPT. The team could not determine if the contactors currently installed in Size 3 starters would pickup at the 78% voltage stated in the vendor manual or if they would pick up at 71% voltage as stated in the engineering information provided by the vendor. As a result, the team could not ensure that the selection of 85.2 volts (71%) as the design minimum pickup voltage was acceptable Pending the licensees determination of the applicability of Procedure FNP-0-EMP-1513.01 test results to the actual contactor performance and the acceptability of using 85.2 volts as the design minimum contactor pickup voltage, this issue is identified as Unresolved Item 05000348/2004006-01; 05000364/2004006-01, Adequacy of Plant Design Basis Documents and Performance of Contactors in Safety-related MOV Starters Under Minimum Design Voltage Conditions.
.32 Equipment/Environmental Qualification
a. Inspection Scope
The team performed field walkdowns to observe whether the selected electrical components and connections to those components appeared to be suitable for the environment expected under all conditions, including high energy line breaks. Specific attention was paid to the potential operating environment for safety-related MCCs 1V and 1U.
b. Findings
No findings of significance were identified.
.33 Equipment Protection
a. Inspection Scope
The team performed field walkdowns of selected components in the HHSI, AFW, MS, service water (SW), component cooling water (CCW), 125 V dc and 4.16 kV ac systems to verify that the components were adequately protected from potential effects of flooding, high winds, missiles, 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 disposition of operating experience reports related to the SGTR events SGTR-related issues. The documents reviewed are listed in the
.
b. Findings
No findings of significance were identified.
OTHER ACTIVITIES
4OA2 Problem Identification and Resolution
a. Inspection Scope
The team reviewed selected system health reports, maintenance rule reports, condition requests, surveillance tests, and maintenance work orders to verify that the licensee had appropriately identified and resolved problems.
b. Findings
No findings of significance were identified.
4OA6 Meetings, Including Exit
The lead inspector presented the inspection results to Mr. R. Johnson, and other members of the licensee staff, at an exit meeting on February 13, 2004. Following completion of additional reviews in the Region II office, a final exit was held by telephone with Mr. D. McKinney, Farley Licensing Services Manager and Mr. D. Grissette, General Manager, Farley Plant, on March 15, 2004. The licensee acknowledged the findings presented. Proprietary information is not included in this inspection report.
4OA7 Licensee-Identified Violations
The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a Non-Cited Violation.
- 10 CFR 50 Appendix B, Criterion III, Design Control, requires that design bases be correctly translated into specifications, drawings, procedures and instructions. Design document FTG-J-001, Project Technical Guide for Instrumentation and Controls Design Criteria, Section 11.3, Scaling Processes and Guidelines specifies requirements to ensure that scaling for pressure, level, and flow instruments shall include appropriate hydrostatic head correction and density compensation factors.
Contrary to the above, Calculation SJ-98-1693-001, Calculation to establish the set point uncertainty for the RWST level loops, did not include density compensation for the concentration of boric acid solution in the Refueling Water Storage Tank. This was identified in the licensees corrective action program as condition report 2003800303. This finding is of very low safety significance because it did not affect the operabilty of the Refueling Water Storage Tank.
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- B. Arens, Unit Supervisor
- R. Badham, Administrative Manager
- M. Coleman, Outage and Modifications Manager
- P. Crone, Licensing Supervisor
- R. Fucich, Maintenance Superintendent
- R. Johnson, Assistant General Manager - Operations
- J. Kale, Licensing Engineer
- D. Lisenby, Engineering Manager
- D. McKinney, Services Manager, Corporate Licensing
- C. Nesbitt, Training Manger
- B. Oldfield, Quality Assurance Supervisor
- R. Rogers, Engineering Support Supervisor
- J. Seay, Licensing Engineer
NRC (attended exit meeting)
- R. Fanner, Resident Inspector
- C. Patterson, Senior Resident Inspector
LIST OF ITEMS
OPENED, CLOSED AND DISCUSSED
Opened
- 05000348/2004006-01 URI Adequacy of Plant Design Basis Documents and
- 05000364/2004006-01 Performance of Contactors in Safety-related MOV Starters Under Minimum Design Voltage Conditions (Section .31)
ATTACHMENT