IR 05000369/2004002

IR 05000369-04-002 & IR 05000370-04-002, on January 26-30 & February 9-13, 2004, McGuire Units 1 & 2. Safety System Design and Performance Capability Inspection

ML040710390
Person / Time
Site:	Mcguire, McGuire
Issue date:	03/11/2004
From:	Ogle C NRC/RGN-II/DRS/EB
To:	Gordon Peterson Duke Energy Corp
References
IR-04-002
Download: ML040710390 (31)

Text

rch 11, 2004

SUBJECT:

MCGUIRE NUCLEAR STATION - NRC SAFETY SYSTEM DESIGN AND PERFORMANCE CAPABILITY INSPECTION REPORT NOS.

05000369/2004002 AND 05000370/2004002

Dear Mr. Peterson:

On February 13, 2004, the Nuclear Regulatory Commission (NRC) completed a safety system design and performance capability team inspection at your McGuire Nuclear Station. The enclosed report documents the inspection findings which were discussed on February 12, 2004, with Mr. T. Harrall and other members of your staff. Following completion of additional review in the Region II office, a final exit was held by phone with Mr. T. Harrall and other members of your staff on March 3, 2004.

The inspection examined activities conducted under your licenses as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your licenses. The inspection team reviewed selected procedures and records, observed activities, and interviewed personnel.

This report documents one NRC-identified finding of very low safety significance (Green). The finding was determined to be a violation of NRC requirements. However, because of the very low safety significance and because it was entered into your corrective action program, the NRC is treating this finding as a non-cited violation (NCV) consistent with Section VI.A of the NRC Enforcement Policy. If you deny this non-cited violation, you should provide a response within 30 days of the date of this inspection report, to the United States Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, D.C. 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 McGuire facility.

In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the

DEC 2 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.: 50-369, 50-370 License Nos.: NPF-9, NPF-17

Enclosure:

NRC Inspection Report 05000369/2004002 and 05000370/2004002 w/Attachment: Supplemental Information

REGION II==

Docket Nos.: 50-369, 50-370 License Nos.: NPF-9, NPF-17 Report Nos.: 05000369/2004002 and 05000370/2004002 Licensee: Duke Energy Corporation Facility: McGuire Nuclear Station, Units 1 & 2 Location: 12700 Hagers Ferry Road Huntersville, NC 28078 Dates: January 26 - 30, 2004 February 9 - 13, 2004 Inspectors: N. Merriweather, Senior Reactor Inspector (Team Lead )

J. Leivo, Instrumentation and Control Systems Contractor J. Fuller, Reactor Safety Intern R. Moore, Senior Reactor Inspector R. Rodriguez, Reactor Safety Intern M. Thomas, Senior Reactor Inspector Approved by: Charles R. Ogle, Chief Engineering Branch 1 Division of Reactor Safety Enclosure

SUMMARY OF FINDINGS

IR 05000369/2004-002, 05000370/2004-002; 01/26-30/2004 and 02/09-13/2004; McGuire

Nuclear Station, Units 1 and 2; Safety System Design and Performance Capability Inspection.

This inspection was conducted by a team of inspectors from the NRC Region II office with assistance from a contractor specializing in instrumentation and controls. The team identified one Green non-cited violation. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649,

Reactor Oversight Process, Revision 3, dated July 2000.

Cornerstone: Mitigating Systems

Green.

The team identified a non-cited violation of 10 CFR 50, Appendix B, Criterion III,

Design Control requirements. The licensee had failed to identify and evaluate the impact on design of sloping the impulse lines for the containment pressure transmitters downward from the containment towards the transmitters without low point drain legs installed. This configuration was a deviation from the licensees design requirements, and introduced the potential for water intrusion in the instrument impulse lines during normal operation and accident conditions. In response to this condition, the licensee performed an operability evaluation and entered the finding into their corrective program (Problem Investigation Process (PIP) Report No. M-04-00713).

The finding is greater than minor because it affects the design control attribute of the mitigating systems cornerstone objective, in that the formation of a loop seal would have the potential to affect the performance capability of instruments used for automatic initiation of engineered safety features, containment pressure control, and post-accident monitoring. The finding was determined to be of very low safety significance (Green)because it is a design deficiency that will not result in loss of automatic initiation of engineered safety features, containment pressure control, or post-accident monitoring capability (loss of function). (Section 1R21.21. b).

Licensee-Identified Violations

None.

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events and Mitigating Systems

1R21 Safety System Design and Performance Capability

Except as noted below, the inspection team focused on Unit 2 systems and components and operator actions required to prevent or mitigate the consequences of a steam generator tube rupture (SGTR) event. The inspection team also examined the licensees steam generator (SG) surveillance program, secondary water chemistry controls, foreign material exclusion controls, loose parts monitoring, and steam generator leakage monitoring controls and procedures. Additionally, the team reviewed the licensees applicability evaluations and corrective actions for industry operating experience issues related to SGTR events.

.11 Process Medium

a. Inspection Scope

The team reviewed the availability, reliability, and adequacy of water sources required for the mitigation of an SGTR event. These included the refueling water storage tank (RWST), volume control tank (VCT), condensate storage tank (CACST), and the assured service water (RN) suction source. Design criteria information, drawings, vendor manuals, and calculations to determine the pump net positive suction head (NPSH) and tank volume were reviewed to verify that design and Updated Final Safety Analysis (UFSAR) accident analysis assumptions were consistent with system and equipment capabilities. The team evaluated the available primary and secondary water source volumes with respect to the anticipated water source requirements for the SGTR event.

b. Findings

No findings of significance were identified.

.12 Energy Sources

a. Inspection Scope

The team reviewed appropriate test and design documents to verify that the 4160 volt and 600 volt alternating current (VAC) power sources, as well as the 125 volt direct current (VDC) power sources, were adequate to meet minimum voltage specifications for electrical equipment during and following an SGTR event. The Unit 2 safety related 4160 VAC pump motors reviewed for voltage adequacy were safety injection (NI),chemical and volume control (NV), residual heat removal (ND), and RN. Specific valves reviewed for adequacy of voltage, included the Unit 2 steam supply air operated valves (AOVs) to turbine driven auxiliary feedwater pump (TDCAP) and SG auxiliary feedwater (CA) isolation motor operated valves (MOVs), as well as, the standby nuclear service water pond (SNSWP) supply and discharge B isolation MOVs and ND inlet isolation MOVs.

The team reviewed the 125 VDC battery sizing calculation, and voltage drop study to verify that the 125 VDC electrical distribution system was capable of providing reliable power during an SGTR event.

In addition to the above, the team reviewed the quality controls for the air systems required for operation of Unit 2 AOVs (i.e., the TDCAP steam supply valves 2SA-48ABC, -49ABC; and SG PORVs 2SV-1AB, -7ABC, -19AB). Specifically, valve design drawings, vendor manuals, and periodic air quality test results were reviewed to verify that plant air quality standards were consistent with vendor recommendations, regulatory guidance, and industry standards. Alternate air and gas sources for operation of AOVs were also assessed, including the capacity and availability of the diesel air compressors.

b. Findings

No findings of significance were identified.

.13 Instrumentation and Controls

a. Inspection Scope

The team reviewed the Unit 2 instrumentation that is used by operators for detection of primary to secondary leakage and an SGTR event, as well as selected control circuits used for SGTR mitigation. Instrumentation used for detection included the main steam (SM) line N-16 radiation monitors, SM line radiation monitors (area monitors strapped to the four main steam lines), condenser air ejector radiation monitor, SG blowdown sample isolation radiation monitor, and SG narrow range level instruments. For these instruments, the team reviewed the SGTR accident analysis, design basis documents, calculations, design documents, and vendor documents establishing the basis for calibration and alarm setpoints, to confirm that the calibration, setpoints, and emergency operating procedure (EP) action levels were consistent with the design and licensing basis.

For controls used in SGTR mitigation, the team reviewed the instrument detail drawings and elementary diagrams for the control circuits for the steam generator power operated relief valves (PORVs), the pressurizer PORVs, and the automatic isolation of the steam generator blowdown sample line. The objective of the drawing review was to confirm that the circuits implemented the functional requirements levied by the design and licensing basis.

The specific documents reviewed are included in the Attachment to this report.

b. Findings

No findings of significance were identified.

.14 Operator Actions

a. Inspection Scope

The team reviewed plant operating procedures (OPs), including EPs, abnormal operating procedures (APs), and annunciator response procedures that would be used in the identification and mitigation of an SGTR event. Specific procedures reviewed included:

• AP/2/A/5500/010, NC System Leakage Within Capacity of Both NV Pumps, Rev. 14

• EP/1/A/5000/E-3, Steam Generator Tube Rupture, Rev. 12

• EP/2/A/5000/E-0, Reactor Trip or Safety Injection, Rev. 18

• EP/2/A/5000/E-3, Steam Generator Tube Rupture, Rev. 10

• OP/2/A/6100/010Q, Annunciator Response for Panel 2RAD-1, Rev. 34

• OP/2/A/6100/010R, Annunciator Response for Panel 2RAD-2, Rev. 27

• OP/2/A/6100/010S, Annunciator Response for Panel 2RAD-3, Rev. 11 The review was done to verify that the procedures were consistent with the UFSAR description of an SGTR event and with the Westinghouse Owners Group Emergency Response 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 a 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. The local manual operator action times for performance of SGTR event mitigation activities were reviewed for consistency with accident analyses and operator training.

b. Findings

No findings of significance were identified.

.15 Heat Removal

a. Inspection Scope

The team reviewed the reliability and availability of cooling for equipment required to mitigate the SGTR event. This included cooling water to the CA, NI, and NV Pumps.

Vendor manuals, design documentation, drawings, and surveillance and test procedures, were reviewed to verify the vendor recommendations for equipment operation were satisfied.

b. Findings

No findings of significance were identified.

.21 Installed Configuration

a. Inspection Scope

The team performed field walk downs of accessible SGTR mitigation equipment in the CA, NV, SM, NI, instrument air (VI), and steam generator blowdown systems to assess general material condition, identify degraded conditions, and verify the installed configuration was consistent with design drawings and design inputs to calculations.

Additionally, the team assessed potential flooding and missile impact on SGTR mitigation equipment. The team performed a walkdown of the discharge side of the 2A motor driven CA pump to ensure that pipe supports and snubbers were installed per design drawings.

The team walked down portions of the 125V DC and 4160V AC electrical distribution systems to verify that the installed configurations were consistent with design basis information. The team visually inspected the 4160V AC vital switchgears and panels, and the 125V DC batteries and battery chargers and distribution panels to evaluate material condition.

The team walked down the Unit 2 main steam line N-16 radiation monitors, Unit 1 & 2 main steam line radiation monitors, Unit 1 & 2 condenser air ejector radiation monitors, and Unit 2 steam generator blowdown sample isolation radiation monitor and the associated control room indicators and setpoints, to confirm that the instrument configurations were consistent with the design and licensing basis. The team also confirmed that the taps for the RWST level instruments were located so as to preclude adverse velocity effects on the measurement.

The team reviewed the installation detail drawings for containment pressure and containment sump level field instrumentation. These instruments are relied upon, in part, to determine whether the event is a loss of coolant accident (LOCA) or an SGTR event. The objective of the review was to confirm that design basis failure modes and effects on the installed configurations had been adequately considered with respect to normal and accident conditions. For both units, the team visually inspected all of the containment pressure transmitters and impulse line tubing from the reactor building/containment annulus penetrations to the transmitters, to confirm that the impulse lines were adequately separated, and were sloped or drained to preclude loop seals or blockage of the lines.

b. Findings

Introduction:

The team identified a Green, non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion III, Design Control requirements. Prior to the inspection, the licensee had not identified and evaluated the potential impact of sloping of the impulse lines of the containment pressure transmitters downward from the containment towards the transmitters without providing drain legs. This configuration was a deviation from the licensees design requirements, and introduced the potential for water intrusion during normal operation and accident conditions.

Description:

During the inspection, prior to an announced NRC walkdown, the licensee identified that the impulse line tubing for the four redundant channels of the Unit 1 & 2 containment pressure transmitters was sloped downward, rather than upward, from the containment to transmitters. For Unit 2, no drain legs were provided, as required by the licensees design drawings when the upward slope requirements could not be satisfied.

The licensee had not previously analyzed the potential effects of this deviating configuration on the performance of the instruments.

Licensee Drawing No. MCID-2499-NS.01, Revision 1, Instrument Detail - Reactor Building Containment Pressure, contains detailed design requirements for all of the 14 safety-related containment pressure transmitters. Note 11 of the drawing stipulates:

Tubing should be sloped upward from tap to transmitters. If this is not possible, a drain leg should be provided by lengthening the test tee and plug at the transmitter.

During the inspection, the team requested the licensee show how this design requirement had been satisfied, and to identify what measures the licensee used to ensure that the impulse lines would not be blocked or sealed. In response, the licensee determined from walkdowns during the inspection that the slope requirements had not been satisfied, and that for Unit 2, the required drain legs had not been installed. The licensee also determined that a low point sag existed for one channel of instrument tubing within the containment annulus of Unit 1.

The licensee entered this issue into their corrective action program as Problem Investigation Process report (PIP) M-04-00713, dated 2/12/2004, and performed an operability evaluation. The evaluation analyzed the potential for water intrusion during normal and accident operation. The evaluation was supported by detailed walkdowns of all containment pressure instrument lines and by two calculations.

Calculation MCC-1223.13-00-0021, Containment Pressure Instrument Sensing Line Condensation during a Loss of Coolant Accident, Revision 1, dated 2/17/2004, determined that the total moisture in the tubing from the initial air and steam introduced into the line following a large break LOCA would be 1.9 inches of water per 100 feet of impulse line tubing. From the results of this calculation and detailed walkdowns, the licensee prepared and issued calculation MCC-1381.17-00-0120, PIP-M-04-0713 NS Containment Pressure Instrumentation Line Operability Evaluation, Revision 1, dated 2/23/2004, to determine the approximate column of water expected in the impulse lines during a LOCA, and determined, based on the as-found impulse line geometry, that the volumes of water introduced into the containment pressure sensing lines during a LOCA would be insufficient to cause blockage in any of the associated channels. This result supported the licensees conclusion that the Unit 1 & 2 containment pressure transmitters and associated sensing lines were operable, and were degraded/non-conforming.

To assess the licensees operability evaluation, the team performed a walkdown of all containment pressure transmitters and associated impulse lines outside of the reactor building wall, and subsequently performed an in-office review of calculations MCC-1223.13-00-0021 and MCC-1381.17-00-0120 cited above. Based on this review, the team agreed with the licensees conclusion that the Unit 1 & 2 containment pressure transmitters and associated sensing lines were not vulnerable to the effects of a loop seal, and therefore were operable and degraded/non-conforming.

Analysis:

The finding is greater than minor because the degraded/non-conforming condition affected the design control attribute of the mitigating systems cornerstone objective. Specifically, for engineered safety features actuation and containment pressure control and integrity, the containment pressure instrumentation and associated tubing that supports these cornerstone objectives was in a configuration that deviated from the design requirements.

The finding was determined to be of very low safety significance (Green) because it is a design deficiency that will not result in loss of automatic initiation of engineered safety features, containment pressure control, or post-accident monitoring capability. This determination was based on review of the licensees operability evaluation, NRC Generic Letter 91-18 (Rev. 1) guidance on degraded and nonconforming conditions, and the Significance Determination Process (SDP) Phase 1 Screening Worksheet question number 1 under Mitigating Systems.

Enforcement:

10 CFR 50, Appendix B, Criterion III, Design Control, requires in part, that design control measures shall include provisions to assure that appropriate quality standards are specified and included in design documents and that deviations from such standards are controlled. Licensee Drawing No. MCID-2499-NS.01, Revision 1, Instrument Detail - Reactor Building Containment Pressure, contains detailed design requirements for all of the 14 safety-related containment pressure transmitters. Note 11 of the drawing stipulates:

Tubing should be sloped upward from tap to transmitters. If this is not possible, a drain leg should be provided by lengthening the test tee and plug at the transmitter.

Contrary to the above requirements, the NRC identified on February 12, 2004, that since initial startup of the units, the design requirements for slope and drain legs for the safety-related containment pressure impulse lines had not been fully satisfied, and the licensee had not evaluated the impact of this deviation on the performance of the containment pressure channels. Because this violation was of very low safety significance and the licensee entered the finding into their corrective action program as PIP No. M-04-00713, this violation is being treated as a NCV, consistent with Section VI.A of the NRC Enforcement Policy. This finding is identified as NCV 05000369,370/2004002-01, Deviation from Design Requirements for Line Slope and Drain Legs for Containment Pressure Transmitter Impulse Lines Was not Identified or Evaluated.

.22 Operation

a. Inspection Scope

The team walked down accessible portions of CA and SM systems (which included the steam supply valves 2SA-48ABC and 2SA-49ABC to the TDCAP; and SM valves 2SV-1AB, 2SV-7ABC, 2SV-13AB, 2SV-19AB, 2SV-25, 2SV-26, 2SV-27, 2SV-28) to verify that the system alignments were consistent with design and licensing basis assumptions, and to verify that the systems would be available for operators to mitigate an SGTR event. During those walkdowns, the team compared valve positions with those specified in the CA and SM systems piping and instrumentation drawings and operating procedure lineups; and observed the equipment material condition to determine if it would be adequate to support operator actions to mitigate an SGTR event.

The team walked through, with an operator, Unit 1 and Unit 2 EP actions to locally operate the SM power operated relief valves (PORV) and PORV isolation valves and isolation of the steam supply from the affected SG to the TDCAP. The team reviewed the EP 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.

b. Findings

No findings of significance were identified.

.23 Design

a. Inspection Scope

Mechanical Design Review The team reviewed design calculations, specifications, and UFSAR accident analysis to identify the design criteria which defined the required capacity and capability of SGTR mitigation equipment. Surveillance test procedures and equipment monitoring activities were reviewed to verify the design criteria was appropriately translated into acceptance criteria. The team reviewed NPSH calculations for the NI and centrifugal charging pumps from the RWST to verify that adequate NPSH was available. Design changes were reviewed to verify that system and equipment design functions were appropriately evaluated and maintained. Design changes reviewed included replacement of actuators on TDCAP steam supply valves, as well as replacement of actuator springs on main steam isolation valves and steam generator blowdown isolation valves. The team also reviewed a design changes associated with replacement of a failed mechanical snubber and hydraulic snubber.

Electrical, Instrumentation and Controls Design Review The team reviewed the battery sizing calculation for the Unit 1 Class 1E 125 VDC electrical distribution system to assess the adequacy of the batteries to provide power for selected components required to mitigate a SGTR event. Additionally, the team examined the voltage adequacy calculation for the Unit 2 steam supply air operated valves (AOVs) to TDCAP and SG CA isolation MOVs, as well as, the ND inlet isolation MOVs.

The team reviewed a sample of temporary and permanent plant design changes impacting instrumentation and control systems to confirm that the design changes were in accordance with the design and licensing basis. Design changes reviewed included replacement of the Unit 2 condenser air ejector radiation monitor, revision of the SG level operator aide computer setpoint, as well as removal of the CA speed controls on both units. A list of the modifications reviewed are included in the Attachment to this report.

b. Findings

No findings of significance were identified.

.24 Testing and Inspection

a. Inspection Scope

The team reviewed valve stroke time testing of MOVs 1SM-5AB, 2SM-1AB, 2SV-1AB, and 2SV-7ABC, as well as, MOV torque and limit switch settings and post-maintenance testing to verify that the tests and inspections were appropriately verifying that the assumptions of the licensing and design bases were being maintained and that performance degradation would be identified.

The team evaluated the 125 VDC batteries (i.e., EVCA, EVCB, EVCC, and EVCD)surveillance test records, including preventive maintenance and performance tests results, to verify that the batteries were capable of meeting design basis load requirements. The team reviewed calibration records for the overcurrent and undervoltage protective relays on safety buses 2ETA and 2ETB to verify that the relays were set in accordance with calibration procedures and setpoint documents.

The team reviewed surveillance test procedures and completed test results related to reactor coolant system leakage, primary to secondary leakage, and operator time critical task verification to verify that testing was being performed in accordance with applicable Technical Specification requirements, UFSAR commitments, and the McGuire Nuclear Station Selected Licensee Commitments Manual (SLC).

The team reviewed a sample of the records of the last two calibrations and channel operational tests for selected SGTR related instruments, as well as containment sump level instruments, to confirm that acceptance criteria were satisfied or that appropriate corrective actions had been taken. The team observed the operation of these instruments during an SGTR simulator exercise to qualitatively confirm simulator fidelity.

b. Findings

No findings of significance were identified.

.31 Component Degradation

a. Inspection Scope

The team reviewed maintenance and testing documentation, performance trending, and equipment history as identified by In-Service Test program trending, work orders, and PIP reports, to assess the licensees actions to verify and maintain the safety function, reliability and availability of selected components. Additionally reviewed were potential common cause failure mechanisms due to flooding, maintenance, parts replacement and modifications. The Maintenance Rule Functional Failures for the selected components for the past 5 years were reviewed. The selected components included MOVs, air operated valves, relief valves, check valves, solenoid valves and pumps. A specific list of components reviewed is included in the Attachment to this report.

The team reviewed the licensees secondary water chemistry control program, to ensure that the critical secondary water chemistry parameters, as stated in Chapter 10.4 of the UFSAR, are monitored and controlled to inhibit secondary side steam generator corrosion and associated tube degradation. The team assessed the licensees program for adherence to appropriate vendor recommendations and industry guidance in this area.

The team reviewed preventive maintenance records for 125 VDC batteries and chargers, as well as CA pump motors, to assess the licensees actions to verify and maintain the safety function, reliability, and availability of the components in the system.

The team visually inspected the Unit 2 main steam line N-16 radiation monitors, Unit 1 &

2 main steam line radiation monitors, Unit 1 & 2 condenser air ejector radiation monitors, Unit 2 steam generator blowdown sample isolation radiation monitor, and all of the containment pressure transmitters and impulse line tubing from the reactor building/containment annulus penetrations to the transmitters, to confirm that the visible material condition of the impulse lines, instruments, supports, and connections was adequate.

b. Findings

No findings of significance were identified.

.32 Equipment/Environmental Qualification

a. Inspection Scope

The team reviewed preventive maintenance records for selected Class 1E electrical equipment to verify that environmental qualification requirements were being implemented during mentioned activities. Specifically, while reviewing calibration procedures for steam generator level transmitters included in the licensees environmental qualification program, the team confirmed that appropriate requirements were included for replacement of O-ring seals as required to maintain qualification.

b. Findings

No findings of significance were identified.

.33 Equipment Protection

a. Inspection Scope

For both units, the team visually inspected the SM line N-16 radiation monitors, SM line radiation monitors, condenser air ejector radiation monitor, and steam generator blowdown sample isolation radiation monitors to confirm that the instruments and connections were not vulnerable to the effects of design basis events for which they were credited to be functional, including the effects of extreme ambient temperatures and background dose rates.

In addition to the above, the team reviewed the equipment specifications for the SG PORVs, main steam safety valves, TDCAPs, and NV pumps to verify the design was adequate for anticipated ambient conditions and system application.

b. Findings

No findings of significance were identified.

.34 Component Inputs/Outputs

a. Inspection Scope

The team reviewed selected CA and RN MOV operator requirements calculations and evaluated the capability of the MOVs to perform their design function under degraded voltage conditions. The specific MOVs reviewed are discussed in Section 1R21.12.a.

b. Findings

No findings of significance were identified.

.35 Operating Experience

a. Inspection Scope

The team reviewed the licensees applicability evaluations and corrective actions for industry experience issues related to TDCAPs, VI system failures, CA re-circulation flow orifice fouling, fouling of Catawbas component cooling water heat exchangers, ND heat exchanger partition plate design, failures of safety-related valves due to linestarter relay degradation, as well as transformer reliability issues and other SGTR events to verify that applicable insights from those reports had been applied to plant procedures and operator training. The specific documents reviewed are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

.36 Steam Generator Inspection

a. Inspection Scope

The team performed a limited-scope review of the SG surveillance program in order to ensure that SG tubes were being inspected as required by Technical Specifications and plant procedures.

b. Findings

No findings of significance were identified.

.37 Foreign Material Exclusion (FME) Control Program And Loose Parts Monitoring

a. Inspection Scope

The team reviewed procedures and performance records for the Loose Parts Monitoring System (LPMS) to verify that the system was operational and was being used to monitor for loose parts in the reactor coolant system and steam generators. The team assessed the licensees program for adherence to appropriate industry recommendations, and selective licensing commitments. The team reviewed completed test procedures for channel operability, channel calibration, and daily operations surveillance tests. In addition, the team held discussions with appropriate engineering personnel, and reviewed procedures and PIPs regarding FME program controls, cleanliness requirements, and material accountability.

b. Findings

No findings of significance were identified.

.4 Identification and Resolution of Problems

a. Inspection Scope

The team screened and reviewed a sample of Unit 2 PIPs initiated over the past three years, to confirm that the licensee was adequately identifying, evaluating, and dispositioning adverse conditions regarding the main steam line N-16 monitors, main steam line monitors, condenser air ejector monitor, steam generator blowdown sample isolation monitor, steam generator narrow range level instruments, control circuits for the SG PORVs, and control circuits for the pressurizer PORVs. The team reviewed selected system health reports, maintenance records, surveillance test records, calibration test records, and PIPs to verify that design problems were identified and entered into the corrective action program. The team also reviewed PIPs related to other selected SGTR mitigation equipment to assess the scope of the licensees extent-of-condition reviews and the adequacy of the corrective actions. The specific documents reviewed are listed in the Attachment.

b. Findings

No findings of significance were identified.

4OA6 Meetings, Including Exit

The lead inspector presented the inspection results on February 12, 2004, and in a subsequent conference call on March 3, 2004, to Mr. T. Harrall, and other members of the licensee staff. The licensee acknowledged the findings presented. Proprietary information is not included in this inspection report.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

A. Batts, Instrumentation and Controls Engineer

S. Bradshaw, Superintendent, Plant Operations

J. Bramblett, Chemistry Manager

S. Brown, Manager, Engineering

M. Costella, Radiological Engineering

K. Crane, Regulatory Compliance

S. Hackney, Operations Procedures Group

T. Harrall, Station Manager

T. Henrickson, Secondary Chemistry

D. Homce, Reactor Engineering

R. Johansen, System Engineer

J. Kammer, Safety Assurance Manager

P. Keller, Radiation Monitoring System Engineer

J. Nolin, Operations Support

T. Pederson, System Engineer

R. Pope, Operations Training

S. Schultz, Manager, Radiological Engineering

F. Setzer, Air Operated Valve Engineer

J. Thomas, Manager, Regulatory Compliance

K. Thomas, Manager, RES Engineering

B. Travis, Superintendent, Work Control

M. Vanhoy, Instrumentation and Controls Engineer

M. Weiner, Operations Procedures Group

T. Welch, Valves/Heat Exchangers Engineering Supervisor

M. Wilder, Regulatory Compliance

NRC (attended exit meeting)

J. Brady, Senior Resident Inspector

C. Ogle, Chief, Engineering Branch 1, NRC Region II

S. Walker, Resident Inspector

LIST OF ITEMS

Opened and Closed

05000369,370/2004002-01 NCV Deviation from Design Requirements for Line Slope and Drain Legs for Containment Pressure Transmitter Impulse Lines Was not Identified or Evaluated (Section 1R21.21. b)