IR 05000302/2003002
| ML031611183 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 06/10/2003 |
| From: | Ogle C NRC/RGN-II/DRS/EB |
| To: | Young D Florida Power & Light Co |
| References | |
| IR-03-002 | |
| Download: ML031611183 (29) | |
Text
une 10, 2003
SUBJECT:
CRYSTAL RIVER NUCLEAR PLANT - NRC INSPECTION REPORT NO.
50-302/2003-02
Dear Mr. Young:
On May 22, 2003, the Nuclear Regulatory Commission (NRC) completed a safety system design and performance capability inspection at your Crystal River facility. The enclosed report documents the inspection findings which were discussed on May 22, 2003, with you 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.
No findings of significance were identified during this inspection.
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 No.: 50-302 License No.: DPR-72
Enclosure:
(See page 2)
FPC 2 Enclosure: NRC Inspection Report No. 50-302/03-02 w/Attachment: Supplemental Information
REGION II==
Docket No.: 50-302 License No.: DPR-72 Report No.: 50-302/03-02 Licensee: Florida Power Corporation Facility: Crystal River Unit 3 Location: 15760 West Power Line Street Crystal River, FL 34428-6708 Dates: May 5-9, 2003 May 19-22, 2003 Inspectors: J. Moorman, Senior Reactor Inspector (Lead Inspector)
F. Jape, Senior Project Manager N. Merriweather, Senior Reactor Inspector R. Schin, Senior Reactor Inspector M. Giles, Resident Inspector, Catawba Nuclear Station R. Cortés, Reactor Inspector Accompanied by: C. Casto, Director, Division of Reactor Safety D. Mas-Peneranda, Inspector Trainee N. Giglio, Summer Student Approved by: Charles R. Ogle, Chief Engineering Branch 1 Division of Reactor Safety Enclosure
SUMMARY OF FINDINGS
IR 05000302/2003-02; Florida Power Corporation; on 5/5-9/03 and 5/19-23/03;
Crystal River Unit 3; safety system design and performance capability inspection.
This inspection was conducted by a team of regional and resident 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.
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), emergency feedwater (EFW),steam generator (SG) blowdown, make-up (MU), 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 selected emergency core cooling systems (ECCS) and EFW net positive suction head and water source calculations, licensing and design basis information, drawings, vendor manuals, operating/lineup procedures, and surveillance procedures. The team also walked down the systems in the plant. The reviews and walkdowns were conducted to verify that system design, Improved Technical Specifications (ITS), and Updated Final Safety Analysis Report (UFSAR) assumptions were consistent with the actual capability of systems and equipment required to mitigate a SGTR event. This review included the borated water storage tank (BWST) and its refill capability, the emergency feedwater tank, alternate EFW supplies, and min-flow flowpaths for EFW and ECCS pumps. The review also included the ability of the main steam atmospheric dump valves (ADVs) and turbine bypass valves (TBVs) to support RCS cooldown, and the ability of the high pressure injection (HPI) pumps and pressurizer power operated relief valve (PORV) and safety valves to provide feed and bleed cooling of the RCS.
The team reviewed the level instrumentation of the condensate storage tank, emergency feed water tank, and borated water storage tank to verify that they were designed, constructed and operated in accordance with design and licensing basis documents. The team performed walk down inspections of the instrument installations to verify that 1) instrument tubing and sensors were located, scaled and calibrated in accordance with loop uncertainty documents, 2) redundant instruments and tubing were adequately spaced and protected, 3) heat tracing was installed where required, and 4)redundant channels were powered by redundant power sources. The team also reviewed appropriate design basis documents, ITS sections, UFSAR sections, system flow diagrams, instrument uncertainty calculations, calibration and surveillance test procedures, and calibration test records to verify that the instruments had the proper range and accuracy needed to perform their safety function. The applicable reference documents reviewed are listed in the Attachment.
The team reviewed maintenance and calibration records for the condenser vacuum exhaust radiation monitor (RM-A12) to verify that surveillance and annunciator response procedures were adequate for monitoring steam generator tube rupture leakage. The maintenance history of the radiation monitor was reviewed to determine the current performance capability of the radiation detection equipment. The team reviewed the setpoints for the radiation monitor alarms to verify that they were established in accordance with setpoint guideline procedures.
b. Findings
No findings of significance were identified.
.12 Energy Sources
a. Inspection Scope
The team reviewed valve lineup procedures and walked down the energy sources of selected mechanical components needed during a SGTR to verify that selected portions of the system 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 EFW pump (EFP-2), the fuel oil and starting air for the diesel driven EFW pump (EFP-3) and the backup air bottle for the ADVs to verify that the lineups were consistent with the system design. The team also reviewed calculations for the amount of backup air required for the ADVs and the accessibility of the backup air bottles during a SGTR event.
The team reviewed voltage drop calculations for a sample of safety-related loads such as motors, valve operators, inverters, and radiation monitors to verify that adequate voltage would be available at the end device during worst case minimum grid operating voltage conditions. The team also reviewed calibration procedures and calibration data records of the motor feeder breakers and protective relays to verify that they were correctly established in accordance with setpoint calculations. The setpoint calculations were reviewed to verify that they had correctly considered such things as motor starting times during reduced voltage conditions in developing the overcurrent setpoints. The team also reviewed surveillance records on breaker alignment checks and bus voltage readings to verify that these checks were being performed in accordance with the requirements specified in the ITS. The specific components reviewed are listed below:
- AFW Pump Motor (FWP-7)
- DC Pump Motors (DCP-1A, 1B)
- EFW Pump Motor (EFP-1)
- Make-up Pump Motors (1A, 1B, 1C)
- SW Pump Motors (SWP-1A, 1B)
- Make-up Valves (MUV-23,24,25,26,58,73)
- AFW Control Valves (FWV-216, 217)
- EFW Valves (EFW- 11, 14, 32, 33, 55, 56, 57, 58)
- Radiation Monitor (RM-A12, RM-G25, 26,27, 28 -RI)
- Pressurizer PORV (RCV-10)
- Main Steam Valves (MSV-25,26)
- Vital Inverters (VBIT-1A, 1B, 1C, 1D, 1E)
b. Findings
No findings of significance were identified.
.13 Instrumentation and Controls
a. Inspection Scope
The team reviewed surveillance and calibration records of the instrument loops listed below to verify that the instruments and associated loop components were being properly calibrated and tested in accordance with calibration procedures and the ITS.
The calibration records were also reviewed to verify that instrument out of tolerance conditions were properly evaluated by the licensee for impact on system performance and, if applicable, entered into the corrective action program.
- OTSG Steam Presssure (MS-106-PT thru 113-PT)
- Narrow Range RCS Pressure (RC-3A-PT1, PT2; RC-3B-PT1, PT2)
- Wide Range RCS Pressure (RC-3A-PT3, PT4; RC-3B-PT3)
- Low Range RCS Pressure (RC-147-PT, RC-148-PT)
- Hot Leg RCS Temperature (RC-4A-TE2, TE3; RC-4B-TE2, TE3)
- Pressurizer Level (RC-1-LT1, LT3)
- Make-up Tank Level (MUT-14-LT1, LT2)
The team reviewed electrical control schematics of the EFW flow control system, SG PORVs, EFW motor driven and steam driven pumps, and pressurizer PORV to verify that the control systems were in accordance with their design bases and would be functional and provide desired control during accident/event conditions.
b. Findings
No findings of significance were identified.
.14 Operator Actions
a. Inspection Scope
The team reviewed procedures, including Emergency Operating Procedures (EOPs),
Abnormal Procedures (APs), and Operating Procedures (OPs), that would be used in the identification and mitigation of a SGTR event. This procedure review was done to verify that the procedures were consistent with the UFSAR description of a 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 matrixes pertaining to SGTR events to ensure that the training was consistent with the procedures. In addition, the team observed two simulator scenarios of a SGTR event to verify that procedural guidance was adequate to identify a SGTR event, and implement post-event mitigation strategies.
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 a SGTR event. The team also walked down the equipment to verify that operating conditions were consistent with design assumptions.
The equipment reviewed included equipment used to cool the HPI and EFW pumps; the EFP-3 diesel/pump room ventilation fans; and the EFP-3 diesel/pump battery ventilation fan.
b. Findings
No findings of significance were identified.
.2 System Condition and Capability
.21 Installed Configuration
a. Inspection Scope
The team performed field walkdowns of selected mechanical components in the HPI, decay heat (DH), EFW, main feedwater (FW), condensate (CD), and main steam (MS)systems. One purpose of the walkdowns was to assess general material condition and identify degraded conditions of components that could be used to mitigate a SGTR event. Additionally, the team assessed the potential impact of external events on SGTR mitigation equipment; including flooding, high energy line breaks, and hurricanes or tornados. The team also inspected selected controls and indicators for these systems for appropriate human factors such as labeling, arrangement, and visibility.
The team performed field walkdowns of the motors, valves, and instruments identified in the Attachment, to verify that:
- the configuration of each component in its system was consistent with the corresponding piping and instrument diagram;
- equipment and instrumentation elevations will support the design function;
- sloping of piping and instrument tubing appeared adequate;
- required equipment protection barriers (such as walls) and systems (such as freeze protection) were in place and intact;
- adequate physical separation and/or electrical isolation had been provided;
- oil levels were obvious in motors;
- no signs of oil leaking or draining from motor operated valves; and
- electrical conduits, fittings, and boxes were in good physical condition.
b. Findings
No findings of significance were identified.
.22 Operation
a. Inspection Scope
The team reviewed system operating/lineup procedures and system drawings and walked down selected portions of the HPI, DH, EFW, FW, CD, and MS systems to verify that system alignments were consistent with design and licensing basis assumptions.
The team performed walkdowns of selected tasks to verify that human factors in the procedures and in the plant (e.g. clarity, lighting, noise, accessibility, labeling) were appropriate to support effective use of the procedures. Specifically, the team reviewed procedures used to align a ruptured once-through steam generator (OTSG) to the hotwell, and the makeup to the BWST from the spent fuel pool.
In addition, the team reviewed the operator workaround program to ensure that degraded equipment conditions, that could adversely impact control room operators during a SGTR event, were properly identified and prioritized. The team also reviewed the licensees adverse weather program to assess the protection against adverse weather for significant structures, systems and components used in the mitigation of a SGTR event.
b. Findings
No findings of significance were identified
.23 Design
a. Inspection Scope
The team reviewed records of completed design changes, corrective maintenance, and preventive maintenance; and walked down selected components of the HPI, DH, RCS, EFW, FW, CD, and MS systems to verify that these activities were maintaining the assumptions of the licensing and design bases. During these reviews, the team focused on potential common mode failure vulnerabilities that could be introduced by design or maintenance activities.
The team reviewed instrument loop uncertainty calculations for the following monitoring instruments to verify that plant instrument calibration procedures had accurately incorporated set point values delineated in the calculations.
- Condensate Storage Tank Level (CD-67-LT)
- Emergency Feedwater Tank Level (EF-98-LT, EF-99-LT)
- BWST Level (DH-7-LT, DH-37-LT)
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 HPI, DH, RCS, EFW, FW, CD, 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, 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 reviewed the surveillance testing and test records for the 125/250 VDC station batteries to verify that the battery capacity was adequate to supply and maintain in operable status, the required emergency loads for the design basis duty cycle.
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, action requests, and performance trending of selected mechanical components in the HPI, DH, RCS, EFW, FW, CD, and MS systems to verify that components that could be relied upon to mitigate a SGTR event were not degrading to unacceptable performance levels.
The selected components reviewed included:
- HPI pumps
- EFW pumps
- HPI check valves (MUV-1, 7, 11, 36, 37, 42, 43, & 160 to 164)
- DH MOVs (DHV-3, 4, & 41)
- MS ADVs (MSV-25 & 26)
- MS TBVs (MSV-9, 10, 11, 14)
- Main steam isolation valves (MSIVs) (MSV-411 to 414)
- Main feed isolation valves (MFIVs) (FWV-29 to 33, 36, 14, 15, 28)
- Main steam safety valves (MSSVs) (MSV-33 to 48)
- EFW tank (EFT-2) vacuum breakers and relief valves.
The team reviewed the 5-year maintenance history for the electrical components listed below to determine their current performance capability to mitigate a SGTR event.
- EFW Pump Motor (FWP-7)
- DC Pump Motors (DCP-1A, 1B)
- EFW Pump Motor (EFP-1)
- Make-up Pump Motors (1A, 1B, 1C)
- SW Pump Motors (SWP-1A, 1B)
- Make-up Valves (MUV-23,24,25,26,58,73)
- EFW Control Valves (FWV-216, 217)
- EFW Valves (EFW- 11, 14, 32, 33, 55, 56, 57, 58)
- Radiation Monitors (RM-A12, RM-G25, 26,27, 28 -RI)
- Pressurizer PORV (RCV-10)
- Main Steam Valves (MSV-25,26)
- Vital Inverters (VBIT-1A, 1B, 1C, 1D, 1E)
Specifically the team reviewed:
- each components maintenance history by reviewing selected corrective-maintenance and preventive-maintenance work order summaries and trends of component performance data, to verify that unexpected degradation had not been found, and that performance problems had not reappeared; and
- each components preventive-maintenance schedule, to verify that the schedule was based either on vendor recommendations or appropriate industry experience.
b. Findings
No findings of significance were identified.
.32 Equipment/Environmental Qualification
a. Inspection Scope
The team conducted in-plant walkdowns to verify that the observable portion of selected mechanical components and electrical connections to those components were suitable for the environment expected under all conditions, including high energy line breaks.
b. Findings
No findings of significance were identified.
.33 Equipment Protection
a. Inspection Scope
The team conducted in-plant walkdowns to verify that there was no observable damage to installations designed to protect selected components from potential effects of high winds, flooding, and high or low outdoor temperatures.
b. Findings
No findings of significance were identified.
.34 Operating Experience
a. Inspection Scope
The team reviewed the licensees dispositions of operating experience reports applicable to the SGTR event to verify that applicable insights from those reports had been applied to the appropriate components. The specific operating experience reports reviewed are listed in the Action Request section of the Attachment to this report.
b. Findings
No findings of significance were identified.
.35 Once-Through Steam Generator Inservice Inspection
a. Inspection Scope
The team performed a limited-scope review of the inservice inspection program for the OTSGs to verify that OTSG tubes were inspected and to determine if there were obvious omissions or inaccuracies in the data for the OTSG tube inspections.
b. Findings
No findings of significance were identified.
.36 Foreign Material Exclusion Control Program
a. Inspection Scope
The team reviewed the procedural guidelines for cleanliness requirements during maintenance with systems open to verify that controls existed to prevent the introduction of foreign material. These guidelines included a method for controlling and accounting for material, tools and parts. The team reviewed a portion of the accountability control log used during refueling outage in October 2001 to verify that records were kept as required.
b. Findings
No findings of significance were identified.
.4 Identification and Resolution of Problems
a. Inspection Scope
The team reviewed selected system health reports, maintenance records, surveillance test records, calibration test records, precursor cards, and action requests to verify that design problems were identified and entered into the corrective action program.
Examples of issues reviewed included instrument out of tolerance conditions, copper contamination of station batteries, and battery charger tripping problems. The team reviewed selected SGTR mitigation equipment problems identified in the licensees corrective action program to assess the adequacy of the corrective actions to prevent recurrence and the scope of broadness reviews to other plant equipment. In addition, the team reviewed work orders on risk significant equipment to evaluate failure trends.
The team also reviewed the licensees performance in the identification of procedural deficiencies.
b. Findings
No findings of significance were identified.
4. Other Activities
40A6 Meetings, Including Exit The lead inspector presented the inspection results to Mr. D. Young, and other members of the licensee staff, at an exit meeting on May 22, 2003. The licensee acknowledged the findings presented. Proprietary information is not included in this inspection report.
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- M. Bishara, Superintendent of Technical Services
- M. Donovan, Supervisor, Reactor Systems
- R. Fuller, Superintendent of Plant Operations Assessment
- D. Porter, Superintendent of Operations Support
- J. Terry, Manager of Engineering
- E. Welch, Supervisor, Mechanical Maintenance
- D. Young, Site Vice President, Crystal River
NRC (attended exit meeting)
- C. Casto, Director, Division of Reactor Safety, NRC Region II
- R. Reyes, Resident Inspector
- S. Stewart, Senior Resident Inspector
LIST OF ITEMS
OPENED, CLOSED AND DISCUSSED
None.