IR 05000335/2003009
| ML040150116 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 01/13/2004 |
| From: | Ogle C NRC/RGN-II/DRS/EB |
| To: | Stall J Florida Power & Light Co |
| References | |
| IR-03-009 | |
| Download: ML040150116 (27) | |
Text
January 13, 2004
SUBJECT:
ST. LUCIE NUCLEAR PLANT - NRC PLANT DESIGN - PILOT INSPECTION REPORT NOS. 05000335/2003009 AND 05000389/2003009
Dear Mr. Stall:
On December 19, 2003, the Nuclear Regulatory Commission (NRC) completed a plant design -
pilot inspection at your St. Lucie Plant, Units 1 and 2. The enclosed report documents the inspection findings which were discussed on December 19, 2003, with Mr. R. Hughes and other members of your staff.
This inspection was an examination of activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations, and with the conditions of your operating license. Within these areas, the inspection involved selected examination of procedures and representative records, observations of activities, and interviews with personnel.
Based on the results of the inspection, no findings of significance were identified.
In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Charles R. Ogle, Chief Engineering Branch 1 Division of Reactor Safety Docket Nos.: 50-335, 50-389 License Nos.: DPR-67, NPF-16
Enclosure:
(See page 2)
Florida Power & Light Company
Enclosure:
NRC Inspection Report Nos. 05000335/2003009, 05000389/2003009 w/Attachment: Supplemental Information
REGION II==
Docket Nos.:
50-335, 50-389 License Nos.:
05000335/2003009 and 05000389/2003009 Licensee:
Florida Power & Light Company (FPL)
Facility:
St. Lucie Nuclear Plant, Units 1 & 2 Location:
6351 South Ocean Drive Jensen Beach, FL 34957 Dates:
December 1-5, 2003 December 15-19, 2003 Inspectors:
J. Moorman, Senior Reactor Inspector (Lead Inspector)
R. Cortes, Reactor Inspector P. Fillion, Reactor Inspector (Week 2 only)
F. Jape, Senior Project Manager (Week 1 only)
K. Maxey, Reactor Inspector (Week 1 only)
N. Merriweather, Senior Reactor Inspector M. Thomas, Senior Reactor Inspector A. Vargas, Reactor Inspector (Week 1 only)
Accompanied by:
H. Christensen, Deputy Director, Division of Reactor Safety R. Rodriguez, Reactor Inspector Intern D. Mas-Peneranda, Reactor Inspector Intern C. Ogle, Chief, Engineering Branch 1 Approved by:
Charles R. Ogle, Chief Engineering Branch 1 Division of Reactor Safety
SUMMARY OF FINDINGS
IR 05000335/2003-009, 05000389/2003-009; 12/01-05/2003 and 12/15-19/2003; St. Lucie
Nuclear Plant, Units 1 and 2; Plant Design - Pilot, Enclosures 1, 2, and 3.
This inspection was conducted by a team of regional inspectors. No findings of significance were identified. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.
NRC-Identified and Self-Revealing Findings
No findings of significance were identified.
Licensee-Identified Violations
None.
REPORT DETAILS
REACTOR SAFETY
Cornerstones: Initiating Events and Mitigating Systems 1R.DS Plant Design - Pilot (71111.DS)1R.DS1 Safety System Design and Performance Capability (71111.DS, Enclosure 1)
This team inspection reviewed selected components and operator actions that would be used to prevent or mitigate the consequences of a steam generator tube rupture (SGTR) event. Components in the main steam (MS) system, auxiliary feedwater (AFW)system, steam generator (SG) blowdown system, chemical and volume control system (CVCS), reactor coolant system (RCS), safety injection (SI) system, and radiation monitoring (RM) system were included. This inspection also examined supporting equipment, equipment which provides power to these components, and the associated instrumentation and controls. The SGTR event is a risk-significant event as determined by the licensees probabilistic risk assessment.
.1 System Needs
.11 Process Medium
a. Inspection Scope
The team reviewed the AFW and selected emergency core cooling systems (ECCS) 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 tank (RWT), the condensate storage tank (CST), the alternate AFW water supply from the Unit 2 CST, vortexing considerations, and minimum-flow flowpaths for AFW and ECCS pumps. The review also included the ability of the main steam atmospheric dump valves (ADVs) to support RCS cooldown, and the ability of the high pressure safety injection (HPSI) pumps and pressurizer power operated relief valve (PORV) to provide feed and bleed cooling of the RCS. The team also conducted field walkdowns of these systems in 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 reviewed power sources for radiation monitoring instrumentation that would be used to mitigate an SGTR to verify that they were not subject to common cause failure.
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 alignments 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 (1C) and the feed water lineup from the AFW pumps (1A, 1B and 1C) to verify consistency with the system design. The team also reviewed the testing and maintenance history for the ADVs and the accessibility for the operators to manually operate the valves if instrument air were unavailable. This was done to verify that the actual capability of the system was consistent with the system design basis assumptions.
The team reviewed appropriate test and design documents to verify that the 125 Volts direct current (V dc) and 4.16 kiloVolts alternating current (kV ac) power sources for the AFW and HPSI systems motors and valves would be available and adequate in accordance with design basis documents. The team reviewed the 125 V dc battery load study, battery charger sizing calculation, and voltage drop study to verify that the dc system was capable of providing sufficient power during an SGTR event.
The team reviewed electrical control wiring diagrams, interviewed licensee engineers, performed walkdowns, and reviewed surveillance and calibration test records in order to verify that the electrical controls and instrumentation systems for the auxiliary feedwater actuation system, SG atmospheric dump valves, and the pressurizer PORVs were capable of operating in accordance with design bases document descriptions to mitigate an SGTR event. The team also examined several process variable indicators and recorders in the Unit 1 main control room, including radiation monitors, which would be used by operators during SGTR mitigation to verify that the instruments had the proper range and were functional with no significant outstanding work requests pending.
b. Findings
No findings of significance were identified.
.13 Operator Actions
a. Inspection Scope
The team reviewed emergency operating procedures (EOPs), off-normal operating procedures, annunciator response procedures, and operating procedures that would be used for identification and mitigation of an SGTR event. The procedure review was done to verify that the procedures were consistent with the UFSAR description of an SGTR event and with the owners group guidelines, any 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 an SGTR event to ensure that training was consistent with the procedures. In addition, the team observed simulation of an SGTR event on the plant simulator and walked down portions of applicable procedures to verify that operator training, procedural guidance, and instrumentation were adequate to identify an SGTR event and implement post-event mitigation strategies.
b. Findings
No findings of significance were identified.
.14 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 walked down the equipment to verify that operating conditions were consistent with design assumptions.
The equipment reviewed included HPSI and AFW pumps and testing of these pumps at both full and minimum flow conditions. The team also reviewed the shutdown cooling (SDC) valves coming off the RCS hot leg for availability after system depressurization to residual heat removal conditions.
The team reviewed historical temperature data for the Unit 1 station battery rooms to verify that the minimum and maximum room temperatures were within the 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 HPSI, AFW, and MS systems. One purpose of the walkdowns was to assess general material condition, installation configuration, and identify degraded conditions of components that could be used to mitigate an SGTR event. Particular attention was placed on verifying that selected valves and components in the AFW and HPSI systems were in their required position and were consistent with design drawings. Additionally, the team assessed the potential impact of external events on SGTR mitigation equipment; including flooding, missiles, high energy line breaks, and hurricanes. The team also inspected selected controls and indicators for appropriate human factors such as labeling arrangement and visibility.
The team walked down portions of the 125 V dc and 4.16 kV ac systems to verify that the installed configuration was consistent with design basis information. The team visually inspected the 4.16 kV ac switchgear and panels and the 125 V dc batteries and battery chargers, dc distribution panels, and dc switchgear to evaluate observable material condition.
The team inspected the as-built installation of the Unit 1 CST water level channels to verify that the instruments and sensing lines were routed and separated in accordance with the instrument installation details. The team also examined the freeze protection provided for the instruments and sensing lines to verify that it was consistent with the cold weather design requirements. The team performed walkdown inspections of the pressurizer PORVs, steam jet air ejector radiation monitor, and SG blowdown radiation monitor control circuits to verify that the control circuit components (e.g., fuses, switches, and contactors) were consistent with design output documents. The team also reviewed several indicators and recorders in the main control room to verify that the displayed parameters had ranges consistent with design requirements and were appropriate for the applications.
b. Findings
No findings of significance were identified.
.22 Operation
a. Inspection Scope
The team walked through, with a licensed operator, the Unit 1 EOP actions to locally operate the SG atmospheric dump valves, isolate a ruptured SG, and swap the AFW pumps suction from the Unit 1 CST to the Unit 2 CST. The team reviewed the EOP actions to verify that human factors in the procedures and in the plant (e.g., clarity, lighting, accessibility, labeling) were adequate to support effective use of the procedures. The team also discussed selected tasks with health physics and chemistry personnel (who would be involved with operators to identify the SG with the ruptured tube) to verify that their tasks were procedurally controlled and they received training on the procedures.
The team walked down portions of the AFW, HPSI, and MS systems to verify that the system alignments were consistent with design and licensing basis assumptions, and they would be available for operators to mitigate an SGTR event. During the walkdowns, the team compared valve positions with those specified in the AFW, HPSI, and MS systems piping and instrumentation drawings and operating procedure lineups; and observed the equipment material condition to verify that it would be adequate to support operator actions to mitigate an SGTR event.
b. Findings
No findings of significance were identified.
.23 Design
a. Inspection Scope
Mechanical Design The team reviewed the HPSI and AFW pump vendor manuals, 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 pump curve data were reviewed to verify that adequate water levels were available in the CST and RWT; and that vortexing had been addressed.
The team reviewed records of completed design changes, corrective maintenance, and preventive maintenance for the HPSI 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, Instrumentation and Controls Design The team reviewed the battery sizing calculation for the Unit 1 class 1E 125V dc electrical distribution system to assess its adequacy to provide power for selected components required to mitigate an SGTR event.
The team reviewed the uncertainty calculation and the calibration test records for the CST level channels to verify that the instruments had the proper range and accuracy for CST low level and low-low level alarms as required by operational procedures, TS, and setpoint documents. The team also reviewed the CST fabrication drawings and measured the elevation of the CST level transmitters to verify that the assumptions used in the loop uncertainty calculation were appropriate. The plant change and modification package that replaced several of the obsolete indicators in the Unit 1 main control room was reviewed to verify that the modification package required the replacement indicators to be seismically qualified.
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 walked down selected components of the HPSI, AFW and MS systems to verify that the tests and inspections appropriately verified that licensing and design bases assumptions were being maintained. This review included tests 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; inspection of MOV operator components and grease; and analysis of pump bearing oil and vibration.
The team evaluated surveillance 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 calibrations for the overcurrent and undervoltage protective relays to support proper operation of safety buses 1A-3 and 1B-3.
The team reviewed surveillance procedures and calibration test records of Unit 1 process instrument channels monitoring SG narrow range level, SG pressure, AFW flow, RCS pressure and temperature, pressurizer level, condenser air ejector radiation, steam line radiation, and SG blowdown radiation to verify that actions were prescribed consistent with the instrument design including setpoint documents, the Offsite Dose Calculation Manual, and TS.
b. Findings
No findings of significance were identified.
.3 Selected Components
.31 Component Degradation
a. Inspection Scope
The team reviewed system health reports, corrective maintenance records, condition reports, and performance trending of selected components in the HPSI, RCS, AFW and MS 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 HPSI pumps, AFW pumps, HPSI MOVs (V3654, V3656, HCV-3616, 3626, 3636 & 3646); HPSI check valves (V3401, 3410, 3427, 3414, 3113, 3123, 3133 & 3143); AFW flow control valves (V09124, V09108, MV-09-9 thru 12); SDC MOVs (V3480, 3481, 3651 & 3652); pressurizer PORVs (V1402 and 1404); MS ADVs (HCV-08-2A & 2B) and main steam isolation valves (HCV-08-1A &1B). In addition, the team examined the Unit 1 turbine driven AFW steam supply piping for inclusion of steam traps that would prohibit water accumulation in the piping system and prevent occurrences of water hammer or pump overspeed trip events.
The team reviewed preventive maintenance records for 125 V dc batteries and chargers as well as AFW pump motors and MOVs to verify the program was being implemented.
Additionally, the team examined preventive maintenance records for selected 4.16 kV circuit breakers to assess the licensees actions to verify and maintain the safety function, reliability, and availability of the components in the system. Also, the team reviewed replacement activities as well as commercial 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 reviewed all documented failures of 4.16 and 6.9 kV circuit breakers on both units that occurred from January 1, 2001, to the date of this inspection. The root cause evaluation for 1B HPSI pump circuit breaker failure which occurred on April 10, 2002, was reviewed in detail. In cases where the root cause investigation was not complete at the time of this inspection, the status of the investigation and preliminary conclusions were discussed with a cognizant engineer. As part of the circuit breaker failure review, the team examined outdoor switchgear where a number of failures had taken place. A 4.16 kV circuit breaker was examined in the maintenance training facility. Portions of manufacturers instruction manuals, control circuit diagrams, preventive maintenance procedures and troubleshooting procedures were reviewed. The main objective of this review was to verify that the licensee was meeting the requirements of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, with regard to the circuit breaker failures.
The review also addressed the inspection procedure requirement to evaluate potential common cause failure modes and equipment degradation.
The team reviewed the maintenance history of selected process monitoring instrumentation and radiation monitors to assess the licensees actions to verify and maintain the safety function, reliability, and availability of the components in the system.
The specific work orders and other related documents reviewed are listed in the attachment.
b. Findings
No findings of significance were identified.
.32 Equipment/Environmental Qualification
a. Inspection Scope
During walkdowns, a primary focus for the team was to observe whether the selected mechanical components and electrical connections to those components appeared to be suitable for the environment expected under all conditions, including high energy line breaks.
The team reviewed environmental qualification documentation for watt transducers for safety-related switchgear to verify that environmental qualification test reports demonstrated the instruments were suitable for their application.
b. Findings
No findings of significance were identified.
.33 Equipment Protection
a. Inspection Scope
The team conducted equipment walkdowns to observe whether the selected components appeared to be 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 dispositions of operating experience reports related to the SGTR events at Palo Verde and Indian Point Nuclear Stations to verify that applicable insights from those reports had been applied to plant procedures and operator training.
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 rule reports, condition reports, surveillance tests, and maintenance work orders to verify that the licensee had appropriately identified and resolved problems.
The team reviewed corrective action documents related to the 125 V dc and 4.16 kV ac systems to verify that the licensee was identifying issues and entering them into their corrective action program.
The team reviewed corrective maintenance work orders and condition reports on instrument power supply failures to evaluate failure trends and to verify that appropriate corrective action had been taken to resolve the problem. The team also reviewed a Unit 2 condition report involving air in the HPSI flow transmitters to verify that appropriate corrective action had been planned to prevent this problem from occurring on Unit 1.
b. Findings
No findings of significance were identified.
1R.DS2 Permanent Plant Modifications (71111.DS, Enclosure 2)
a. Inspection Scope
The team evaluated design change packages for seven modifications, in all three cornerstone areas, to verify that the modifications did not degrade system availability, reliability, or functional capability. The team reviewed attributes such as: energy requirements can be supplied by supporting systems; materials and replacement components were compatible with physical interfaces; replacement components were seismically qualified for application; Code and safety classification of replacement system, structures, and components were consistent with design bases; modification design assumptions were appropriate; post-modification testing established operability; failure modes introduced by the modification were bounded by existing analyses; and appropriate procedures or procedure changes had been initiated. For selected modification packages, the team reviewed the as-built configuration to verify that it was consistent with the design documentation.
Documents reviewed included procedures, engineering calculations, modifications, work orders, site drawings, corrective action documents, applicable sections of the UFSAR, supporting analyses, TS, and design basis documentation. The samples reviewed are listed below:
- PCM 02073, Rev 0, Control Room Door Replacement of Unit 2
- CM 03091, Rev 0, Abandonment of Unit 2 Boronometer
- CM 00042, Setpoint Change for listed valves
- PCM 00071, Rev 0 Actuator Mod
b. Findings
No findings of significance were identified.
1R.DS3 10 CFR 50.59 Safety Evaluations (71111.DS, Enclosure 3)
a. Inspection Scope
The team reviewed selected samples of evaluations to verify that the licensee had appropriately considered the conditions under which changes to the facility or procedures may be made, and tests conducted, without prior NRC approval. The team reviewed evaluations for seven changes. The team verified, through review of additional information, such as calculations, supporting analyses and drawings that the licensee had appropriately concluded that the changes could be accomplished without obtaining a license amendment. The seven evaluations reviewed are listed below:
- SENS-97-006, Performance of Full Core Refueling Offloads, Rev 5
- PCM 02142, Unit 2 Cycle 14 Fuel Reload, Rev 1
- SENS-02-010, Containment Purge System Isolation Valves, Rev 0
- SEF-J-02-009, Evaluation of Higher Operating Limit for Silica in the RCS, Rev 1
- PCM 02014, St. Lucie Unit 1 Cycle 18 Reload, Rev 0
- PCM 99170, Removal of Unit 2 Spent Fuel Storage Cell Blocking Devices, Rev 2
- PCM 02042, Replacement of the Unit 2 DDPS and SOER and Installation of a Plant Data Network, Rev 1 The team also reviewed samples of design and engineering packages and procedure changes for which the licensee had determined that evaluations were not required. This review was performed to verify that the licensees conclusions to screen out these changes were correct and consistent with 10 CFR 50.59. The 12 screened out changes reviewed are listed below:
- MSP 03065, Replacement of Personnel Airlock Outer Door Operator Coupling, Rev 0
- PSM 03055, Temporary Turbine Lube Oil Conditioner for Moisture Removal, Suppl 0
- MSP 03030,. PDIS-2216 Snubber Installation, Rev 0
- MSP 02093, Pressurizer Spray Bypass Valves V1236, V1237 Replacement, Rev 0
- PCM 02088, Condenser Door Installation, Suppl 0
- MSP 02087, FCV-9011/9021 Positioner Change, Rev 0
- PCM 02001M, Eberline Medium Range Gas Detector Upgrade for Low-Fail Alarms, Suppl 0
- PCM 02015M, Functional Removal of the 2A/2B Manual Voltage, Suppl 0 Regulator
- PCM 02062M, HPSI/CCW Pump Motor EDG Load Block Swap, Suppl 0 The team also reviewed the results of the licensees recent quality assurance audit reports of engineering activities and condition reports related to the 10 CFR 50.59 process. The documents are listed in the Attachment.
b. Findings
No findings of significance were identified.
4. OTHER ACTIVITIES
40A6 Meetings, Including Exit The lead inspector presented the inspection results to Mr. Hughes, and other members of the licensee staff, at an exit meeting on December 19, 2003. The licensee acknowledged the findings presented. Proprietary information is not included in this inspection report.
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- K. Frehafer, Licensing Engineer
- R. Hanke, Maintenance
- J. Heinhold, Secondary Chemistry Supervisor
- J. Hoffman, Design Engineering Manager
- R. Hughes, Site Engineering Manager
- B. Jefferson, Site Vice-President
- K. Jennings, Performance Improvement Department Supervisor
- A. Locke, Chemistry Supervisor
- M. Norris, Health Physics Supervisor
- W. Parks, Operations Support Manager
- T. Patterson, Licensing Manager
- L. Porro, Simulator Engineering Section Supervisor
- V. Rubano, Engineering Project Manager
NRC (attended exit meeting)
- H. Christensen, Deputy Director, Division of Reactor Safety
- T. Ross, Senior Resident Inspector
- S. Sanchez, Resident Inspector
LIST OF ITEMS
OPENED, CLOSED AND DISCUSSED
None.