IR 05000250/2004008
| ML042110359 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 07/23/2004 |
| From: | Ogle C Division of Reactor Safety II |
| To: | Stall J Florida Power & Light Co |
| References | |
| IR-04-008 | |
| Download: ML042110359 (40) | |
Text
uly 23, 2004
SUBJECT:
TURKEY POINT NUCLEAR PLANT - NRC SAFETY SYSTEM DESIGN AND PERFORMANCE CAPABILITY INSPECTION REPORT NOS.
05000250/2004008 AND 05000251/2004008
Dear Mr. Stall:
On June 24, 2004, the Nuclear Regulatory Commission (NRC) completed a safety system design and performance capability inspection at your Turkey Point Nuclear Plant, Units 3 and 4.
The enclosed report documents the inspection findings which were discussed on June 24, 2004, with Mr. M. Pearce 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.
This report documents one NRC-identified finding of very low safety significance (Green)
involving a violation of NRC requirements. However, because of the very low safety significance and because it is entered into your corrective action program, the NRC is treating the finding as a non-cited violation (NCV) consistent with Section VI.A of the NRC Enforcement Policy. If you contest the NCV in this report, 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 2; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Turkey Point Nuclear Plant.
FPL 2 In accordance with 10 CFR 2.390 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.: 50-250, 50-251 License Nos.: DPR-31, DPR-41
Enclosure:
NRC Inspection Report Nos. 05000250/2004008, 05000251/2004008 w/Attachment: Supplemental Information
REGION II==
Docket Nos.: 50-250, 50-251 License Nos.: DPR-31, DPR-41 Report Nos.: 05000250/2004008 and 05000251/2004008 Licensee: Florida Power & Light Company (FPL)
Facility: Turkey Point Nuclear Plant, Units 3 & 4 Location: 9760 S. W. 344th Street Florida City, FL 33035 Dates: June 7-10, 2004 and June 21-24, 2004 Inspectors: J. Moorman, Lead Inspector C. Smith, P.E., Senior Reactor Inspector R. Cortes, Reactor Inspector R. Taylor, Reactor Inspector R. Rodriguez, Reactor Inspector W. Holland, Contract Operations Inspector Accompanying Personnel: C. Fong, Co-op student Approved by: Charles R. Ogle, Chief Engineering Branch 1 Division of Reactor Safety Enclosure
SUMMARY OF FINDINGS
IR 05000250/2004-008, 05000251/2004-008; 06/07-10/2004 and 06/21-24/2004; Turkey Point
Nuclear Plant, Units 3 & 4; Safety System Design and Performance Capability Inspection.
This inspection was conducted by a team of regional inspectors and a contract inspector. One Green finding of very low safety significance was identified during this inspection and was classified as a non-cited violation (NCV). 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 management review. The NRC's 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
Cornerstone: Mitigating Systems
Green: A non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, was identified for failure to implement configuration control measures for the calculation of record for the steam generator water high-high level overfill protection function instrument uncertainty calculation. This resulted in Calculation WCAP-12745,
Westinghouse Set point Methodology for Protection Systems, Turkey Point Units 3 & 4 Thermal Uprate Project, Revision 1, dated December 1995, not containing the correct Allowable Value for the steam generator high-high level protection function set point.
This finding is greater than minor because inadequate design control for engineering calculations can propagate incorrect information into subsequent plant modifications.
This could eventually result in plant operation outside of analyzed conditions, which could affect the availability, reliability, and capability of mitigating systems to respond to initiating events and prevent undesirable consequences. This finding is of very low safety significance because it is a design deficiency that did not result in a loss of system function per Generic Letter 91-18. (Section 1R21.23)
Licensee-Identified Violations
None.
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), safety injection (SI), 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 conducted system walkdowns, observed instrument indications, and reviewed selected operations surveillances to verify that the process medium for the main feedwater (MFW), AFW, CVCS, boron addition, and MS systems would be available and unimpeded during accident/event conditions. Reviews were based on the Updated Final Safety Analysis Report (UFSAR) system descriptions and Technical Specification (TS) requirements.
Specifically, the team reviewed procedures used by operators associated with refilling of the refueling water storage tank (RWST); reviewed the common valves associated with flow paths to the AFW pumps from the condensate storage tanks (CSTs) to verify proper configuration control; reviewed valve line-ups to verify that the CST on the non-accident unit could be used, if necessary, for the accident unit; and reviewed MFW recovery procedures to verify they were up-to-date and directed use of MFW through the bypass lines.
The team reviewed the AFW and SI net positive suction head (NPSH) and water source calculations, operating/lineup procedures, drawings, licensing and design basis information, surveillance procedures, and vendor manuals. The review also included the RWST, the CST, minimum-flow flowpaths for AFW and SI pumps, and vortexing considerations. The team reviewed AFW common cause failure possibilities with an emphasis on steam supply valves (MOV-3-1403, -1404, -1405 and CV-3-10-381, -382, -
383), discharge check valves (20-143, -243, -343), and AFW flow control valves (FCVs)(CV-3-2816, -2817, -2818, -2833, -2832, -2831).
b. Findings
No findings of significance were identified.
.12 Energy Sources
a. Inspection Scope
The team conducted walkdowns, and control room and equipment status reviews of selected energy sources to verify availability during accident/event conditions. Reviews were based on design basis documents, system operating procedures, TS, and UFSAR requirements. Systems of focus included instrument air, pressurizer power operated relief valves (PORVs), and the process radiation monitoring system.
Specifically, the team assessed selected portions of valve lineup procedures, reviewed procedures for operation of back-up nitrogen supplies to the SG steam dump to atmosphere valves (SDAVs) and the pressurizer PORVs to verify that they would accomplish the stated task; and assessed applicable system lineups for MODE of operation by control room walkdowns (equipment status based on control board indication).
The team reviewed appropriate test and design documents to verify that the 4160 volt alternating current (VAC) and 600VAC power sources, as well as 125 volt direct current (VDC) power sources, were adequate to meet minimum voltage specifications for electrical equipment during and following an SGTR event. Among the reviewed components were the SI pump motors and the boric acid transfer pump motors, as well as, the Unit 3 standby steam generator feedwater (SSGFW) pump motor. Specific valves reviewed were:
- Pressurizer PORV solenoid valves
- Steam Generator SDAV solenoid valves
- Boric Acid Transfer MOVs
- MFW bypass line valves Additionally, the team reviewed the power supplies for the steam generator blowdown, main steam line, and condenser air ejector radiation monitors to verify conformity with RG 1.97, Instrumentation for Light-Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident.
The team walked down the energy sources of selected components to verify that selected system alignments were consistent with the design basis assumptions, performance requirements, and system operating procedures. The team reviewed valve lineup procedures for the steam supply to the turbine-driven AFW pumps and the sources of instrument air for the air operated valves (AOVs) such as the steam generator SDAVs (CV-3-1606, -1607, -1608), main steam isolation valves (MSIVs)(POV-3-2604, -2605, -2606), pressurizer PORVs (PCV-3-455C, -456), and AFW FCVs. The team also reviewed the testing and maintenance history for these AOVs to verify that the system design basis assumptions were consistent with the actual capability of the system.
b. Findings
No findings of significance were identified.
.13 Instrumentation and Controls
a. Inspection Scope
Auxiliary Feed Water Suction Sources The team reviewed the instrument uncertainty calculation for the RWST level instruments to verify that the recommendations of NRC Information Notice 83-03, Calibration of Liquid Level Instruments, dated 01/28/1983, had been incorporated into the calculation for density compensation of the borated water. The review was also performed to verify the accuracy of the level instruments for satisfying TS requirements and to determine the following instrument uncertainties:
- (1) the total loop uncertainty associated with the RWST high and low alarm;
- (2) the total loop uncertainty associated with the RWST main control room indication, and
- (3) the total loop uncertainty associated with the TS minimum indicated volume required for operability of the RWST.
The team reviewed plant change/modification PC/M 99-048 that was prepared by the licensee to rescale the RWST level instruments to account for the density compensation discussed in NRC Information Notice 83-03. The team also reviewed additional scaling requirements implemented by Plant Change/Modification 99-048 to provide a consistent zero gallon reference.
Steam Generator Level (Narrow Range) Channel Calibration The team reviewed the plant procedures used for performing steam generator narrow range level instrumentation calibration to verify correct acceptance criteria as delineated in the instrument uncertainty calculations of record. The team reviewed completed data sheets for Unit 3 steam generator level (narrow range) protection instrumentation sets 1, 2, and 3. The team also evaluated the results of the calibration activities for several instrument channels in terms of satisfying the acceptance criteria specified in the following procedure sections of the steam generator level calibration procedures:
- (1) Section 6.2, Loop Power supply LQ-4x5 Check and Calibration;
- (2) Section 6.9, Signal Isolator LM-4x5 Check and Calibration;
- (3) Section 6.10, Recorder, Indicator and Computer Signal Conditioner Check and Calibration; and Section 6.11, As-found Overall Rack Accuracy. The team also reviewed the completed data sheets for the calibration of the Unit 3 steam generator level (narrow range) protection instrumentation set III, instrument channels L-476, 486, and 496 performed under work order number 32006593 01 dated March 3, 2003 to verify that the acceptance criteria of the calibration procedure were satisfied. Refer to the Attachment for a list of the steam generator level calibration procedures reviewed.
b. Findings
No findings of significance were identified.
.14 Operator Actions
a. Inspection Scope
The team reviewed plant operating procedures, emergency operating procedures (EOPs), off-normal operating procedures (ONOPs), and annunciator response procedures (ARPs) that would be used in the identification and mitigation of the SGTR event. The teams focus was on SGTR mitigation strategy (ruptured SG identification/
isolation, RCS cooldown, RCS depressurization) to stop leakage from the RCS to the environment.
Specifically, the team reviewed the operating, EOP, ONOP, and ARP procedures to verify that they were available to operators, were consistent with the UFSAR description of an SGTR event, and were consistent with EOP writers guide requirements. This review was also conducted to verify that procedures called out in EOPs were properly referenced and maintained; that ONOP and EOP steps requiring health physics (HP)monitoring of radiation levels during SGTR mitigation could be properly performed and that chemistry procedures for sampling to support mitigation of an SGTR event could be properly performed. The team reviewed the SG leak monitoring program and associated procedures for consistency with Electric Power Research Institute guidelines, to verify that operators were provided with information on very low SG primary to secondary leakage rates and that procedures were in place for plant shutdown prior to exceeding established limits. The team reviewed information in procedures used to correlate radiation monitor readings with primary-to-secondary leakage to ensure that the correlation was valid. The team reviewed alarm setpoints, annunciator functions, and ARPs for consistency with UFSAR, EOPs, and operator training lesson plans. In addition, the team reviewed selected operations procedures (EOPs and surveillances)associated with SGTR event response to verify EOP setpoint document information had been incorporated, as appropriate, into procedures. The team reviewed applicable procedures to verify that they provided proper direction on use of cooldown and depressurization consistent with calculations and/or requirements. Further, the team reviewed radiation monitors and setpoints to ensure consistency with ARPs/EOPs. The reviews included the following radiation monitors:
- Condenser air ejector radiation monitors (RAD-3/4-15 and RAD-3/4-6417)
- S/G blowdown radiation monitor (RAD-3/4-19)
- Main steam line radiation monitor (RAD-6426)
Additionally, the team reviewed accident analysis assumptions to verify that they had been implemented into appropriate procedures and could be accomplished as described. The team observed operator performance of procedures during the simulator demonstration of an SGTR event to verify that the procedures were performed as required by administrative requirements (EOP Users Guide) and were consistent with owners group procedure guidelines. The team reviewed SGTR EOPs to verify that step deviations from the Westinghouse Owners Group emergency response guidelines were justified. The team reviewed selected training lesson plans for the SGTR event to evaluate consistency with EOPs. The team specifically reviewed the EOPs to verify that they directed refill of RWST when required and referenced the appropriate procedure(s).
The team also verified that actions by operators to conduct the EOP action to manually isolate a stuck open SG SDAV could be accomplished when required.
The team observed crew performance of SGTR event mitigation on the plant simulator.
The following actions were observed by the team:
b. Findings
No findings of significance were identified.
.15 Heat Removal
a. Inspection Scope
The team reviewed design calculations, drawings, and surveillance test procedures for selected equipment to assess the reliability and availability of cooling for equipment required to mitigate an SGTR event. The team conducted field walkdowns of the equipment to verify that operating conditions were consistent with design assumptions.
The equipment reviewed included SI and AFW pumps and testing of these pumps at both full and minimum flow conditions. The team also reviewed design calculations and machinery history to verify that the SI pump jacket water cooler had adequate capacity to remove heat from the mechanical seals and the thrust bearing housing during design basis accidents.
b. Findings
No findings of significance were identified.
.2 System Condition and Capability
.21 Installed Configuration
a. Inspection Scope
The team performed field inspections of the Hagan instrument racks associated with Unit 3 steam generators level (narrow range) protection instrumentation sets I, II, and III.
The instrument racks installation was compared to as-built instrument installation drawings. Additionally, the instrument racks were evaluated in connection with aging and end-of-life related problems. Failures of instrument rack components that have occurred and the corrective actions taken for resolution of the equipment aging problems were discussed with the licensees engineering personnel to determine the extent of condition and corrective actions taken.
The team performed field walkdowns of selected portions of the AFW, MS, FW, CVCS, SG blowdown, SI and process radiation monitoring systems to assess observable material condition and the installed configuration of components. This review was also conducted to verify that selected valves and components in these systems were in their required position and that the configuration was consistent with design drawings. For the SI, AFW, and MS systems, particular attention was placed on verifying selected valves and components that could cause a common mode failure in these systems. The team also reviewed human factors items in the walkdown areas (e.g. lighting, noise, accessability, labeling) to verify proper consideration had been given to these areas for SGTR mitigation actions.
The team reviewed system health reports for selected systems and met with selected system engineers to discuss system design basis and to evaluate identified degraded components.
The team walked down portions of the 125VDC and 480VAC systems to verify that the installed configuration was consistent with design basis information. Also, the team visually inspected 480VAC Motor Control Centers 3B and 3C, as well as, the 125VDC vital batteries 3A and 3B along with their respective chargers, inverters and DC distribution panels to evaluate observable material condition.
The team reviewed condition reports for the CST and RWST to determine if water supplies to AFW and SI systems would be obstructed by foreign material or tank degradation.
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 or main control room operation was required to verify that operators could adequately determine component status and that the components could be operated. These components included the backup nitrogen supplies for AFW flow control valves, turbine driven AFW steam supply motor operated valves MOVs, the manual isolation valves for the SG SDAV flowpaths, and the SG SDAVs.
The team conducted walkdowns with appropriate HP and/or Chemistry personnel to observe performance of actions required by ONOPs and EOPs to verify that the actions could be conducted under conditions that would exist during an SGTR event. Team focus areas included chemistry sampling and HP surveys that would be used to help operators identify which SG was ruptured. Another aspect reviewed was post-accident RWST make-up using the CVCS and boron addition system. The team performed field walkdowns of the boric acid transfer pumps, boric acid tanks, and selected valves between the boric acid tanks and the volume control tank to verify that operators could operate the system during an SGTR event.
b. Findings
No findings of significance were identified.
.23 Design
a. Inspection Scope
Mechanical Design The team reviewed the TS, the UFSAR, and vendor manuals for the AFW and SI pumps to verify that vendor recommendations and licensing basis requirements had been appropriately translated into the surveillance requirements and design calculations. The team also reviewed operating experience (OE) applicability for the AFW FCVs and minimum-flow lines potential for failure and isolation, respectively. NPSH calculations and head curve data for both the AFW and SI pumps was reviewed to verify that adequate water levels were available and vortexing was considered for both the CST and RWST. In addition, the team reviewed the pressurizer PORV backup nitrogen accumulator volume and regulator setting controls to verify that backup nitrogen would be available if needed.
The team reviewed records of preventive maintenance and performed field walkdowns of selected components in the SI, 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.
The team also reviewed the standby steam generator feedwater system machinery history, completed surveillances, oil analysis and valve lineup flow path to verify proper maintenance of the system and availability during SGTR. A more detailed list of components reviewed in this section is provided in the Attachment.
Electrical Design The team reviewed the battery sizing calculation for the Units 3 and 4 class 1E 125VDC electrical distribution system to assess the adequacy of the batteries to provide power for selected components required to mitigate an SGTR event.
Instrument Uncertainty Calculations The team reviewed the steam generator level (narrow range) protection instrument uncertainty calculation of record, and set point and scaling documents, to verify that the instruments were sufficiently accurate to comply with the set point requirements delineated in Technical Specification Table 3.3.3, Item 5C, Steam Generator Water Level High-High.
b. Findings
Introduction The team identified a green non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, in that the licensee failed to establish control of instrument uncertainty Calculation WCAP-12745, Westinghouse Set point Methodology for Protection Systems, Turkey Point Units 3 & 4 Thermal Uprate Project, Revision 1, dated December 1995.
Description The nominal trip set point value for initiation of the steam generator high-high level protection function is listed in TS Table 3.3-3. The TS table also provides an Allowed Value for the trip set point. The calculations of record which established these values were: 1) Westinghouse Thermal Uprate Calculation CN-TSS-94-54, dated July 17, 1995, that determined the setpoint, and; 2) Calculation WCAP-12745, Westinghouse Set point Methodology for Protection Systems, Turkey Point Units 3 & 4 Thermal Uprate Project, Revision 1, dated December 1995 that determined setpoint uncertainty and established the values for use in the TS. The team compared Calculation WCAP-12745 to the TS and determined that the Allowable Value listed in Calculation WCAP-12745 was 80.9% of the steam generator narrow range span while TS table 3.3-3 listed an Allowed Value for the trip set point as 81.9%. This represented a non-conservative discrepancy between the plants licensing and design bases for the steam generator overfill protection function and the value listed in TS table 3.3-3.
In discussions with the licensees engineering personnel, the team determined that the original calculation of record that established the set point value for this protection function was Calculation PTN-BFJ1-93-019, prepared by FP&L in 1993. This calculation was subsequently replaced by Westinghouse Thermal Uprate Calculation CN-TSS-94-54, issued in July 17,1995. Several revisions of Calculation CN-TSS-94-54 were issued by Westinghouse. Revision 7, was issued on July 17, 1995 and determined an Allowable Value of 80.9% of the narrow range for the steam generator overfill protection function set point drift. Revision 6A, issued subsequently on September 26, 1995, determined an Allowable Value of 81.9% of the narrow range span for the steam generator overfill protection function set point drift.
In December 1995, Westinghouse issued WCAP-12745, Revision 1 using the Allowable Value of 80.9% of the narrow range for the steam generator overfill protection function set point from Revision 7 of Calculation CN-TSS-94-54 instead of the Allowable Value of 81.9% from Revision 6A.
3 of Procedure STD-F-004, FPL / WEC Design Interface Procedure, Revision 16 administers and controls the design interface between FP&L and Westinghouse. Section 5.22 of this procedure requires that design integration be achieved by using specific tools. Among the tools listed is a calculation index. This calculation index lists Engineering and Contractor calculations and is searchable by combinations of input fields. It is the responsibility of the FP&L Engineering organization to ensure that each design activity is integrated into any changes to the existing plant configuration. Failure to do so can result in conflicting designs, redundant designs, or exceeding Design Bases parameters with cumulative changes. For Calculation WCAP-12745, Westinghouse Set point Methodology for Protection Systems, Turkey Point Units 3 & 4 Thermal Uprate Project, Revision 1, the licensee failed to insure all design activities were integrated such that the calculation was maintained up to date.
The team concluded that the licensee failed to establish configuration control of the instrument uncertainty calculations of record, and this failure resulted in the discrepancy between the TS and WCAP-12745 for the steam generator water level high-high protection function set point Allowable Value. The licensee initiated condition report 2004-3487-CR and entered this performance deficiency in the corrective action program. The licensee also performed an operability assessment by reviewing records of the past four surveillance performed for the steam generators protection sets I, II, and III analog channel tests. The more restrictive acceptance criteria for the Allowable Value listed in WCAP-12745 was used during this review. The review included data for both Units 3 and 4. All as-found data was within the Allowable Value listed in WCAP-12745. The licensee also performed an extent of condition review for condition report 2004-3487-CR by completing an initial review of Technical Specification Reactor Protection System (RPS) and Engineered Safety Features Actuation System (ESFAS)set points against applicable instrument uncertainty calculations of record. No discrepancies with RPS or ESFAS set points were identified between the technical specification, the set point drawings, and the calculations of record.
Analysis This finding is associated with the design control attribute of the mitigating system cornerstone. It is greater than minor because inadequate design control for engineering calculations can propagate incorrect information into subsequent plant modifications.
This could eventually result in plant operation outside of analyzed conditions, which could affect the availability, reliability, and capability of mitigating systems to respond to initiating events and prevent undesirable consequences. This finding is of very low safety significance (Green) because it is a design deficiency that did not result in loss of system function per Generic Letter 91-18.
Enforcement 10 CFR 50 Appendix B, Criterion III, Design Control, requires, in part, that measures shall be established for the identification and control of design interfaces and for coordination among participating design organizations. These measures shall include the establishment of procedures among participating design organizations for the review, approval, release, distribution and revision of documents involving design interfaces. Attachment 3 of Procedure STD-F-004, FPL / WEC Design Interface Procedure, Revision 16 administers and controls the design interface between FP&L and Westinghouse. Section 5.22 of this procedure requires that design integration be achieved by using specific tools. Contrary to the above, from December 1995, the licensee failed to implement configuration control measures for the calculation of record for the steam generator water high-high level overfill protection function. The licensee entered this issue into their corrective action program as 2004-3487-CR. Because the identified design deficiency is of very low safety significance and the issue has been entered into the licensees corrective action program, this violation is being treated as a non-cited violation (NCV), consistent with Section VI.A of the NRCs Enforcement Policy:
NCV 05000250, 251/2004008-01, Failure to Implement Configuration Control of Steam Generator Water High-high Level Instrument Uncertainty Calculation of Record.
.24 Testing and Inspection
a. Inspection Scope
Steam Generator Level (Narrow Range) Channel Operational Tests The team reviewed data sheet records for Units 3 and 4 steam generator protection set 1, 2, and 3 analog channel tests that were completed for several quarters. The reviews were performed to verify that the analog operational tests demonstrated that the instruments were sufficiently accurate to comply with the plants licensing bases as shown by the as-found and as-left conditions. The reviews were also performed to verify that the plant surveillance procedures had correctly incorporated acceptance criteria and instrument uncertainties that were specified in the instrument loop uncertainty calculations of record.
The team reviewed the 125VDC batteries (3A, 3B, 4A & 4B) surveillance test records to verify that the batteries were capable of meeting design basis load requirements. The team also reviewed calibrations for the overcurrent protective relays to support proper operation of 4160VAC safety buses 3A and 3B. Additionally, the team reviewed inservice test performance data for SI pump motors 3A, 3B, 4A and 4B to verify that the motor current and vibrations under full load conditions were consistent with the manufacturers guidelines.
The team reviewed records of preventive maintenance, surveillance tests, maintenance history, and performed field walkdowns of selected components in the SI, AFW, and MS systems to verify that the tests and inspections were appropriately verifying that the assumptions of the design and licensing bases were being maintained. This review included testing of SI and AFW pumps discharge pressures and flowrates during full and recirculation flow conditions, relief valve pressure set points, check valve operation; and analysis of pump bearing oil. A more detailed list of the components 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 condition report CR-02-0475, prepared on March 19, 2002, which determined that a failed Hagan Analog Computer, FM-4-476 was the cause of the failure of flow indicator FI-4-485. Additionally, the team reviewed the generic implications for the reliability of the Hagan instrument rack components with respect to the age-related failure mode identified in CR-02-0475. The team evaluated the short term and long term corrective actions for this issue.
The team reviewed preventive maintenance records for 125VDC batteries to assess the licensees actions to verify and maintain the safety function, reliability, and availability of the components in the system.
The team reviewed systems with Maintenance Rule functional failures, maintenance records, condition reports, vendor bulletins, and performance trending of selected components in the SI, AFW, MS, standby steam generator feedwater system, demineralizer, instrument air, and nitrogen backup 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, Main Steam Safety Valves (MSSVs), check valves, pumps, and air compressors. A more detailed list of components reviewed is provided in the Attachment.
The team reviewed the licensees analysis that justified the absence of oxygen control methods for the CST to determine if the tank could be operated with acceptably low levels of oxygen. The team also reviewed the turbine driven AFW pump steam supply piping for inclusion of steam traps. In addition, the team reviewed surveillance tests for the MSIVs to verify that stroke time requirements were met.
b. Findings
No findings of significance were identified.
.32 Equipment Protection/Loose Parts Monitoring
a. Inspection Scope
The team performed field walkdowns of selected components in the SI, MS, and AFW systems to verify that the components were adequately protected from the potential effects of missiles, flooding, high winds, impacts from other equipment and scaffolding as well as high or low outdoor temperatures.
The team reviewed current work orders and other records for the metal impact monitor system (MIMS) to determine if the system was operational and was being used by the licensee to monitor for loose parts in the RCS and SGs consistent with the licensing and design basis for the plant. The team reviewed with operators in the control room how the MIMS was used based on annunciator response requirements. The team reviewed applicable ARPs and ONOPs to evaluate plant response to MIMS alarms.
b. Findings
No findings of significance were identified.
.33 Component Inputs/Outputs
a. Inspection Scope
The team reviewed MOV operator torque requirements calculations for the Unit 3 SI discharge MOVs as well as the Boric Acid Transfer MOVs and evaluated their capability to perform their design safety function under degraded voltage conditions.
b. Findings
No findings of significance were identified.
.34 Environmental Qualification
a. Inspection Scope
The team reviewed preventive maintenance records for selected Class 1E electrical equipment to verify that environmental qualification test report requirements, where applicable, were being adequately implemented.
The team reviewed environmental qualification requirements in the vendor manuals for major components in the AFW, MS, and SI systems. The team then performed field walkdowns of the components to assess suitability of the environment in terms of temperature and humidity anticipated under accident conditions, including high energy line breaks.
b. Findings
No findings of significance were identified.
.35 Operating Experience
a. Inspection Scope
The team reviewed the licensees dispositions of operating experience reports applicable to the SGTR event to verify that applicable insights from those reports had been applied to the appropriate components. The team specifically reviewed recent operator lesson plans to verify that applicable significant operating experience report insights were being incorporated into operator lesson plans and training. The specific operating experience documents reviewed are listed in the Operating Experience Documents section of the Attachment to this report.
b. Findings
No findings of significance were identified.
.4 Identification and Resolution of Problems
a. Inspection Scope
The team reviewed the adequacy of plant change/modification PC/M-00006. This plant modification was developed and implemented by the licensee to correct a problem with the Westinghouse 7100 Hagan comparators. This was a component level design change for the steam generator narrow range level loop instrumentation.
The team reviewed a sample of Condition Reports (CRs) initiated over the past three years for systems, structures, or components, and/or processes required to mitigate an SGTR event to confirm that the licensee was adequately identifying, evaluating, and dispositioning adverse conditions. In addition, open operator workaround and temporary alteration lists were reviewed to determine if the open items would hinder operators during response to an SGTR event. The specific documents reviewed are listed in the
.
b. Findings
No findings of significance were identified.
OTHER ACTIVITIES
4OA6 Meetings, Including Exit
The lead inspector presented the inspection results to Mr. M. Pearce and other members of the licensee staff at an exit meeting on June 24, 2004. The licensee acknowledged the findings presented. Proprietary information is not included in this inspection report.
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- P. Barnes, Mechanical Design Engineer
- S. Chaviano, Design Engineering Manager
- C. Connelly, Health Physics Supervisor
- M. Constable, Quality Assurance
- P. Czaya, Licensing Engineer
- R. Earl, Corrective Action Supervisor
- G. Mendoza, Chemistry Supervisor
- K. Mohindrou, Senior Engineering Project Manager
- M. Murray, Emergency Planning Supervisor
- W. Parker, Licensing Manager
- M. Pearce, Plant Manager
- D. Russell, Operations Training Supervisor
- T. Scott, Operations
- B. Stamp, Assistant Operations Manager
NRC (attended exit meeting)
- H. Christensen, Deputy Director, Division of Reactor Safety
LIST OF ITEMS
OPENED, CLOSED AND DISCUSSED
Opened and Closed
- 05000250/2004008-01 NCV Failure to Implement Configuration Control of Steam
- 05000251/2004008-01 Generator Water High-high Level Instrument Uncertainty Calculation of Record. (Section1R.21.23 )