IR 05000250/2009004

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IR 05000250-09-004 05000251-09-004; 07/01/2009 - 09/30/2009; Turkey Point Nuclear Plant, Units 3 & 4; Routine Integrated Report
ML093010642
Person / Time
Site: Turkey Point  NextEra Energy icon.png
Issue date: 10/28/2009
From: Marvin Sykes
NRC/RGN-II/DRP/RPB3
To: Nazar M
Florida Power & Light Co
References
IR-09-004
Download: ML093010642 (21)
v • d • e


Text

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION II

ber 28, 2009

SUBJECT:

TURKEY POINT NUCLEAR PLANT - INTEGRATED INSPECTION REPORT 05000250/2009004 AND 05000251/2009004

Dear Mr. Nazar:

On September 30, 2009, the US Nuclear Regulatory Commission (NRC) completed an inspection at your Turkey Point Units 3 and 4. The enclosed integrated inspection report documents the inspection findings which were discussed on October 2, 2009, with Mr. M. Kiley and other members of your staff.

The inspection examined activities conducted under your license as they related to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Based on the results of this inspection, no findings of significance were identified. However, licensee identified violations which were determined to be of very low safety significance are listed in this report. NRC is treating these violations as Non-cited Violations consistent with Section VI.A.1 of the NRC Enforcement Policy because of the very low safety significance of the issues and because they are entered into your corrective action program. If you wish to contest these NCVs, 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 20555-001; 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 Turkey Point.

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

FP&L 2 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/

Marvin D. Sykes, Chief Rector Projects Branch 3 Division of Reactor Projects Docket Nos.: 50-250, 50-251 License Nos.: DPR-31, DPR-41

Enclosure:

Inspection Report 05000250/2009004 and 05000251/2009004

_________________________ G SUNSI REVIEW COMPLETE OFFICE RII:DRP RII:DRP RII:DRP RII:DRP RII:DRP SIGNATURE SON SMS MCB RJR1 MDS NAME SNinh SStewart MBarillas RReyes MSykes DATE 10/28/2009 10/28/2009 10/28/2009 10/28/2009 10/27/2009 10/ /2009 10/ /2009 E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO

FP & L 3

REGION II==

Docket Nos.: 50-250, 50-251 License Nos.: DPR-31, DPR-41 Report No.: 05000250/2009004, 05000251/2009004 Licensee: Florida Power & Light Company (FP&L)

Facility: Turkey Point Nuclear Plant, Units 3 & 4 Location: 9760 S. W. 344th Street Florida City, FL 33035 Dates: July 1 to September 30, 2009 Inspectors: J. Stewart, Senior Resident Inspector M. Barillas, Resident Inspector R. Reyes, Resident Inspector, Crystal River 3 Approved by: M. Sykes, Chief Reactor Projects Branch 3 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000250/2009-004, 05000251/2009-004; 7/1/2009 - 9/30/2009; Turkey Point Nuclear

Power Plant, Units 3 and 4; routine integrated report.

The report covered a three month period of inspection by resident inspectors. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, and Revision 4, dated December 2006.

A. Inspector Identified & Self-Revealing Findings None

Licensee Identified Violations

Violations of very low safety significance, identified by the licensee, have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. These violations and corrective actions are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status:

Unit 3 operated at full power throughout the inspection period.

Unit 4 operated at full power throughout the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity (Reactor-R)

1R04 Equipment Alignment

.1 Partial Equipment Walkdowns

a. Inspection Scope

The inspectors conducted three partial alignment verifications of the safety-related systems listed below. These inspections included reviews using plant lineup procedures, operating procedures, and piping and instrumentation drawings, which were compared with observed equipment configurations to verify that the critical portions of the systems were correctly aligned to support operability. The inspectors also verified that the licensee had identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers by entering them into the corrective action program.

  • September 15, 2009; 3B Emergency Diesel Generator operability in accordance with 3-OSP-023.1, Attachment 4, during the 3A 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> run test.

b. Findings

No findings of significance were identified.

.2 Complete System Walkdown

a. Inspection Scope

The inspectors conducted a detailed review of the alignment and condition of the Unit 4 residual heat removal (RHR) system to verify that the existing alignment of the system was consistent with the design. To determine the correct system alignment, the inspectors reviewed the plant Technical Specifications (TS), procedures, drawings, and the Final Safety Analysis Report (FSAR). Plant drawing 5614-M-3050 - Residual Heat Removal System and procedure, 4-OP-050 - Residual Heat Removal System were specifically used in conducting the walkdown. The inspectors walked down the system and reviewed the following:

  • Valves were correctly positioned and did not exhibit leakage that would impact the functions of any given valve.
  • Electrical power was available as required.
  • Major system components were correctly labeled, lubricated, cooled, ventilated, etc.
  • Hangers and supports were correctly installed and functional.
  • Essential support systems were operational.
  • Ancillary equipment or debris did not interfere with system performance.
  • Tagging clearances were appropriate.
  • Valves were locked as required by the locked valve program.

Design and equipment issues were reviewed to determine if the identified deficiencies significantly impacted the systems functions. Items included in this review were the system health reports, the system description, pump vibration data, condition reports and outstanding maintenance work orders (WOs). In addition, the inspectors reviewed the licensees corrective action program to ensure that the licensee was identifying and resolving equipment alignment problems in a timely manner.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

a. Inspection Scope

.1 Fire Area Walkdowns

The inspectors toured the following six plant areas during this inspection period to evaluate conditions related to control of transient combustibles and ignition sources.

The material condition and operational status of fire protection systems including fire barriers used to prevent fire damage or fire propagation were also checked. The inspectors reviewed these activities against provisions in the licensees procedure 0-ADM-016, Fire Protection Plan, and 10 CFR Part 50, Appendix R. The licensees fire impairment lists were routinely reviewed. In addition, the inspectors reviewed the condition report database to verify that fire protection problems were being identified and appropriately resolved. The Fire Protection Program Health Report dated 6-30-2008 was reviewed. The following areas were inspected:

  • Unit 4 CCW heat exchanger room when multiple spurious alarms were set off in the control room
  • Unit 3 A and B EDG areas when deluge was out-of-service and a continuous fire watch was posted as a compensatory measure
  • Unit 4 480V Load Center Rooms
  • Unit 4 A EDG Oil Transfer Pump Room
  • Unit 3 A 4160 volt switchgear room
  • Intake area including intake cooling pump area

b. Findings

No findings of significance were identified.

.2 Annual Fire Drill

a. Inspection Scope

On September 2, 2009, the inspectors observed the licensee fire brigades response to a simulated fire at the Unit 4B 4160 Switchgear room. Control room communications to the plant fire brigade and announcement of fire location, sounding of alarms, and simulated notifications to NRC were observed from the control room. The inspectors verified that the drill was administered in accordance with licensee procedures FPAD-027, Fire Brigade and Mutual Aid Drill Scenario Development and 0-ONOP-016.10, Pre-Fire Plan Guidelines and Safe Shutdown Manual Actions. The inspectors checked the brigades communications, ability to set-up and execute fire operations, and their use of fire fighting equipment. The inspectors verified that the licensee implemented the aspects as described below when the brigade simulated the firefighting activities and during the post-drill critique.

  • The brigade, including the fire brigade leader, consisted of a minimum of five team members.
  • The team members acquired and donned the appropriate turnout gear.
  • Self contained breathing apparatus (SCBA) were available and properly used.
  • Control Room personnel verified and announced the fire location. The fire alarm was sounded and fire brigade personnel were dispatched.
  • Fire brigade leader maintained control. Members were briefed (including potential hazards), discussed plan of attack, received individual assignments, and performed communications checks.
  • Fire brigade arrived at the scene in a timely manner, taking the appropriate access route specified in the strategies and procedures.
  • Command and control was established near the fire location.

Communications were established with the control room personnel.

  • Communications were effective between the control room, command post, plant operators and fire brigade members.
  • Fire hose lines were capable of reaching the fire area; the lines were laid out without flow restrictions and were simulated as being charged. Use of additional fire equipment (i.e., foam cart) was simulated.
  • The fire brigade arrived with sufficient fire fighting equipment to perform its fire fighting duties.
  • The drill scenario was followed and the drill acceptance criteria were met.
  • A post-drill critique was held to identify strengths and weaknesses.
  • All fire-fighting equipment associated with the drill was returned to a state of readiness following completion of the drill.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

.1 Internal Flooding

a. Inspection Scope

The inspectors conducted walkdowns of the following two areas which included checks of the sumps to ensure that flood protection measures were in accordance with design specifications. The inspectors reviewed the Updated Final Safety Analysis Report, Appendix 5F, and Internal Plant Flooding that discussed the protection of areas containing safety-related equipment that may be affected by internal flooding. Specific plant attributes that were checked included structural integrity, sealing of penetrations, control of debris, and operability of sump systems. Manhole inspections were completed, including checking for accumulated water and cable integrity problems.

When water was identified in the manhole, the inspectors verified that safety related components were not adversely affected.

  • 4A and 4B 4160 switchgear rooms
  • U3 emergency diesel room flood barriers
  • Manholes 406, 418, 419 (direct inspection)
  • Manholes 350, 324, 351, 720, 721, 722 (review of records)

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review

a. Inspection Scope

On August 3, 2009, the inspectors observed and assessed licensed operator continuing training requalification in the plant specific simulator. The simulated events were done using Nuclear Training Department Lesson Plan 750207605, Auto Rod Insertion/Loss of Coolant Accident. The inspectors observed the operators use of procedures 3-EOP-E-0, Reactor Trip and Safety Injection; 3-EOP-E-1, Loss of Reactor or Secondary Coolant; and 3-ONOP-028, Reactor Coolant System Malfunction. The operators actions were checked to be in accordance with licensee procedures. Event classifications were checked for proper classification and simulated notification in accordance with licensee procedures 0-EPIP-20101, Duties of the Emergency Coordinator; and 0-EPIP-20134, Offsite Notifications and Protective Action Recommendations. The licensee simulated emergency plan notifications. The simulator board configurations were compared with actual plant control board configurations concerning recent plant modifications. The inspectors specifically evaluated the following attributes related to operating crew performance and the licensee evaluation:

  • Clarity and formality of communication
  • Ability to take timely action to safely control the unit
  • Prioritization, interpretation, and verification of alarms
  • Correct use and implementation of off-normal and emergency operating procedures; and emergency plan implementing procedures
  • Control board operation and manipulation, including high-risk operator actions
  • Oversight and direction provided by supervision, including ability to identify and implement appropriate technical specification actions and emergency plan classification and notification
  • Overall crew performance and interactions
  • Evaluators critique and findings

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed three equipment problems and associated condition reports to verify that the licensees maintenance efforts met the requirements of 10 CFR 50.65 (Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants) and station procedure NAP-415, Maintenance Rule Program Administration.

The inspectors efforts focused on maintenance rule scoping, characterization of maintenance problems and failed components, risk significance, determination of (a) (1)classification, corrective actions, and the appropriateness of established performance goals and monitoring criteria. The inspectors also interviewed responsible engineers and observed some of the corrective maintenance activities. The inspectors checked that when operator actions were credited to prevent failures, the operator was dedicated at the location needed to accomplish the action in a timely manner, and that the action was governed by applicable procedures. Furthermore, the inspectors verified that equipment problems were being identified and entered into the corrective action program. The inspectors used licensee engineering procedure EDI-ENG-025, Management and Administration of Maintenance Rule Processes, and the applicable system health reports in the reviews. During this inspection period, the inspectors reviewed the licensees Maintenance Rule (a)(3) Periodic Assessment (2008-848), dated May 28, 2009, to verify that the licensee evaluated failure prevention against the objective of minimizing unavailability.

  • Unit 3 System 028, control rod drive and rod position indication. The inspectors reviewed the June 30, 2009 system health report and CR 2007-17324, Unit 3 shutdown due to multiple rod position indication failures which included the 10 CFR 50.65 a(1) action plan. Work Order 37013419 was checked to verify that splices in the rod position cabling had been replaced with connectors in accordance with Action 23 of the plan.
  • Unit 3 and Unit 4 Steam Generator Blowdown, System 075C, including CR 2008-18474, written after the Unit 3, C blowdown isolation valve failed to shut on demand on June 1, 2008. The a(1) action plan and the system health report were reviewed by the inspectors. Change authorization request CAR 08-071 to install larger air accumulators was reviewed.
  • Unit 3 system 072, Main Steam Isolation valve POV-3-2606 failure to close. The inspectors reviewed CR 2009-13568 and Attachment 4 of NAP-415 for the MR classification associated with the MSIV. The corrective actions associated with the failure were reviewed.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors completed in-office reviews and control room inspections of the licensees risk assessment of seven emergent or planned maintenance activities. The inspectors verified the licensees risk assessment and risk management activities using the requirements of 10 CFR 50.65(a)(4); the recommendations of Nuclear Management and Resource Council 93-01, Industry Guidelines for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, Revision 3; and Procedures 0-ADM-068, Work Week Management and 0-ADM-225, On Line Risk Assessment and Management. The inspectors also reviewed the effectiveness of the licensees contingency actions to mitigate increased risk resulting from the degraded equipment. The inspectors evaluated the following risk assessments during the inspection:

  • July 27: Unit 3 risk with intake cooling water basket strainer BS-3-1403 out of service for mechanical cleaning
  • August 3: Unit 4 risk after failure of POV-4-1400 to close during surveillance test 4-OSP-206.2, Quarterly Valve Inservice Test
  • August 11: Unit 4 risk after failure of 4B emergency diesel generator to develop normal fuel oil pressure during 4-OSP-023.1, Diesel Generator Operability Test (CR 2009-22839)
  • September 23: Unit 3 and Unit 4 risk management when the Unit 4 startup transformer was removed from service for preventive maintenance
  • September 30: Unit 3 risk management during intake cooling water valve stroking per 3-OSP-019.3, Intake Cooling Water Manual Valve Operability Test

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

For the seven operability evaluations described in the condition reports (CR) or as listed below, the inspectors evaluated the technical adequacy of licensee evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors reviewed the final safety analysis report to verify that the system or component remained available to perform its intended function. In addition, when applicable, the inspectors reviewed compensatory measures implemented to verify that the plant design basis was being maintained. The inspectors also reviewed a sampling of condition reports to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations.

  • CR 2009-9437, Operability of Unit 3 source range monitor, N-3-31, following troubleshooting and repair under work order 39006513
  • CR 2009-20055, control room annunciator and loss of cooling fans for Unit 3 startup transformer during deluge system work, amperage limits for the Unit 3 startup transformer were verified using 3-ONOP-092.3, Startup Transformer Malfunction
  • CR 2009-19512, Operability of Unit 3B EDG when hot engine alarm was received during surveillance run
  • CR 2009-21885, operability of control room enclosure when control room unfiltered inleakage resulted greater than acceptance criteria in 0-OSP-025.4, Control Room Inleakage Test
  • CR 2009-25713, Operability of isolation function for Unit 3 blowdown isolation valve CV-3-6275B after air leakage was identified in multiple locations. The licensee confirmed operability using 3-OSP-206.2, Quarterly Valve Stroking
  • CR 2009-23949, Operability of Unit 3 3C intake cooling water pump when differential pressure readings required the pump to be place in alert in accordance with the inservice testing program

b. Findings

No findings of significance were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

For the six post maintenance tests listed below, the inspectors reviewed the test procedures and either witnessed the testing and/or reviewed test records to determine whether the scope of testing adequately verified that the work performed was correctly completed and demonstrated that the affected equipment was functional and operable.

The inspectors verified that the requirements of Procedure 0-ADM-737, Post Maintenance Testing, were incorporated into test requirements. The inspectors reviewed the following work orders (WO) and/or surveillance procedures (OSP):

  • Unit 3 and 4, WO 37027495-01, AFW MOV 6459B inspection and operator overhaul. PMT was completed using 0-GME-102.14, Accelerated MOVATS testing of safety related limitorque motor operated valve actuators, section 6.27
  • Unit 3 & Unit 4, WO 36026475, AFW MOV 6459B valve overhaul. PMT was completed using 4-OSP-075.2, AFW Train 2 Operability Verification
  • Unit 3, WO 38006779-01, 125VDC/120VAC 3B vital inverter 24 month inspection.

PMT was completed using procedure 0-PME-003.3.

  • Unit 3 & Unit 4, WO 39017785, Electric Driven Fire Pump repair leaking fitting and annual PM, 0-OSP-016.1, Electric Driven Fire Pump Annual Surveillance Test

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors either reviewed or witnessed the following six surveillance tests to verify that the tests met the Technical Specifications, the UFSAR, the licensees procedural requirements and demonstrated the systems were capable of performing their intended safety functions and their operational readiness. In addition, the inspectors evaluated the effect of the testing activities on the plant to ensure that conditions were adequately addressed by the licensee staff and that after completion of the testing activities, equipment was returned to the positions/status required for the system to perform its safety function. The tests reviewed included an inservice test (IST) and one reactor coolant system leakage detection surveillance per unit. The inspectors verified that surveillance issues were documented in the corrective action program.

  • Unit 4: 4-OP-047, Section 7.14, Determination of Charging Pump Primary and Secondary Packing Leakage (used to support reactor coolant leakage determinations)
  • Unit 3: Reactor Coolant System Leak Rate Calculation, 3-OSP-041.1, Level 1 RCS leak investigation due to increase in RCS leakage attributed to 3A charging pump
  • Unit 3, ICW Manual Valve Operability Test, 3-OSP-019.3

b. Findings

No findings of significance were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation

.1 Simulator Based Training Evolution

On August 10, 2009, the inspectors observed licensee simulator based licensed operator requalification training that included evaluation of licensed operator event classification and state notification. Results of the training are used by the licensee as inputs into the Drill/Performance and Emergency Response Organization Drill Participation Performance Indicators. FPL Nuclear Training Department Lesson Package 750207605 included a Site Area Emergency after a RCS leakage/LOCA. The Site Area Emergency was made in accordance with licensee procedure 0-EPIP-20101, duties of the Emergency Coordinator. The inspectors observed the licensees event declaration and simulated notification to the State of Florida. At the conclusion of the drill, the inspectors discussed the drill with plant staff and observed the licensee evaluators critique.

b. Findings

No findings of significance were identified.

1EP7 Emergency Preparedness Component, of the Force-on-Force Exercise Evaluation

Main article: IP 71114.07

a. Inspection Scope

On August 5 the inspectors observed licensee performance during a site emergency preparedness exercise. The inspectors observed event management, including event classification and notification activities to be in accordance with the licensees procedure 0-EPIP-20101, Duties of the Emergency Coordinator, revision August 4, 2009. The activities were simulated in the Operations Support Center by an Emergency Coordinator (shift manager), a unit supervisor, and a communicator. The inspectors also observed the post-exercise critique to verify that all weakness areas were identified by licensee evaluators. The inspectors verified that the licensee documented the exercise issues in the corrective action program.

This inspection constitutes one sample as defined by Inspection Procedure 71114.07.

b. Findings

No findings of significance were identified.

OTHER ACTIVITIES

4OA1 Performance Indicator Verification

Initiating Events and Mitigating Systems Cornerstones

a. Inspection Scope

The inspectors checked licensee submittals for the performance indicators (PIs) listed below for the period July 1, 2008, through June 30, 2009, to verify the accuracy of the PI data reported during that period. Performance indicator definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Rev.

5 and licensee procedure 0-ADM-032, NRC Performance Indicators Turkey Point, were used to check the reporting for each data element. The inspectors checked licensee event reports (LERs), operator logs, plant status reports, condition reports (CRs), system health reports, and performance indicator data sheets to verify that the licensee had identified the cumulative safety system unavailability and required hours, as applicable.

The inspectors interviewed licensee personnel associated with performance indicator data collection, evaluation, and distribution.

  • Unit 3 Unplanned Scrams per 7000 Critical Hours
  • Unit 3 Unplanned Scrams with Complications
  • Unit 3 Safety System Functional Failures
  • Unit 3, MSPI High Head Safety Injection
  • Unit 3, MSPI Cooling Water Support Systems
  • Unit 4 Unplanned Scrams per 7000 Critical Hours
  • Unit 4 Unplanned Scrams with Complications
  • Unit 4 Safety System Functional Failures
  • Unit 4, MSPI Emergency AC Power
  • Unit 4, MSPI High Head Safety Injection
  • Unit 4, MSPI Cooling Water Support Systems

b. Findings

No findings of significance were identified.

4OA2 Problem Identification and Resolution

.1 Daily Review

a. Inspection Scope

As required by Inspection Procedure 71152, Identification and Resolution of Problems, and to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed a screening of items entered daily into the licensees corrective action program. This review was accomplished by reviewing daily printed summaries of condition reports and by reviewing the licensees electronic condition report database. Additionally, a reactor coolant system unidentified leakage was checked on a daily basis to verify no substantive or unexplained changes.

b. Findings

No findings of significance were identified.

.2 Annual Sample Review

a. Inspection Scope

The inspectors selected the following condition report for detailed review and discussion with the licensee. The condition report was reviewed to ensure that an appropriate evaluation was performed and appropriate corrective actions were specified and prioritized. Other attributes checked included disposition of operability, resolution of the problem including cause determination and corrective actions. The inspectors evaluated the condition report in accordance with the requirements of the licensees corrective actions process as specified in NAP-204, Condition Reporting.

  • CR 2009-10284, Damage to Rod control cluster Assembly D-6, root cause evaluation and corrective actions
  • The inspectors reviewed the cumulative effects of the operator workarounds that were in place to verify that those effects could not increase an initiating event frequency, affect multiple mitigating systems, or affect the ability of operators to properly respond to plant transients and accidents. The inspectors also reviewed operator workarounds to verify that the licensee was identifying operator workaround problems at an appropriate threshold and entering them in the corrective action program. The inspectors used licensee procedures ODI-CO-040, Operator Workarounds and Operator Burdens, and NAP-402, Conduct of Operations in conducting the inspection.

b. Findings

No findings of significance were identified.

4OA3 Event Follow-up

.1 (Closed) Licensee Event Report (LER) 50-251/2008-004-01 and 50-251/2008-004-00,

Undervoltage Trip Time Delay Relays Cause Loss of Function On September 8, 2008, the licensee identified through a failed surveillance test, that the undervoltage time delay for Channel B of the Unit 4 reactor protection system (RPS) was inoperable. The delay failure could not be immediately repeated. In their investigation of the failed test, the licensee found that the time delay requirement of less than two seconds from an undervoltage condition to a reactor trip may have been inoperable from July 14, 2008, until corrected on October 11, 2008, longer than the allowed Technical Specification limiting condition for operation. The cause was attributed to a faulty time delay relay due to a manufacturing defect where the wrong sized spring was used. As corrective action, the licensee implemented a temporary modification that altered the circuitry used to time-delay the undervoltage function, assigning one relay in each of the two circuits to an annunciation only function. The other relay was replaced with a more reliable model to assure the trip time delay function. Also, procedures were revised to include review of the plant sequence of events following relay testing to verify proper timing. The inspectors verified that the SOE timing check had been implemented in 4-OSP-049.1, Reactor Protection System Logic Test and checked that the circuit modification remained in place. Exceeding the technical specification allowed outage time was a finding of more than minor significance because the reliability of the reactor protection trip function was affected, in that the time delay undervoltage trip may not have responded as designed to an undervoltage condition. The finding affected the Mitigating System cornerstone and was considered to have very low safety significance because redundant trips, such as reactor coolant system low flow, were available and fully functional. The likelihood of an event leading to core damage was not affected.

The licensee identified finding involved a violation of Technical Specification Table 3.3-1 (Unit 20) and Technical Specification 3.0.3. The enforcement aspects of the violation are provided in Section 4OA7 of this report. The LERs are closed.

.2 (Closed) Licensee Event Report (LER) 50-250/2008-003-01 and 50-250/2008-003-00,

Inoperable Steam Generator Blowdown Containment Isolation Valve in Excess of Technical Specification Required Isolation Time (including Supplement)

On June 1, 2008, the 3C steam generator blowdown isolation valve failed to close during a loss of instrument air closure test. The valve is normally closed using instrument air and has an accumulator as a backup for the non-safety related air supply. The failure was documented in condition report 2008-18474. On June 9 the licensee found the need to invoke technical specification requirements and the secondary system blowdown valve penetration was isolated. In evaluating the failure, the licensee identified design problems associated with the blowdown isolation function, including a very low air reserve margin. Additionally, the valve test procedure did not direct operators to invoke technical specification 3.5.4 on a test failure, leading to slow response to isolate the penetration. The licensee later identified that the vulnerability could affect single train auxiliary feedwater operation and reclassified the failure as an event that could have prevented the fulfillment of the auxiliary feedwater safety function.

As corrective action, the licensee identified and corrected a small air leak on the control piping. The test documentation was changed to directly imply technical specification requirements if a test failure occurred by moving the test to 3/4-OSP-206.2, Quarterly Inservice Valve Testing. A design modification CAR-08-071, was initiated to improve the design margin of the blowdown valve accumulators to assure the ability to close the blowdown valves on a loss of instrument air. The licensee identified finding regarding implementation of technical specification requirements was more than minor because the reliability of systems used to mitigate initiating events was affected. The finding was of very low safety significance because redundant systems to both provide auxiliary feedwater and to isolate the blowdown system remained available. The Mitigating Systems cornerstone was affected. The enforcement aspects of the violation are discussed in Section 4OA7 of this report. The LERs are closed.

OTHER ACTIVITIES

4OA5 Other Activities

4OA6 Meetings, Including Exit

Exit Meeting Summary

The resident inspectors presented the inspection results to Mr. Kiley and other members of licensee management on October 2, 2009. The inspectors asked the licensee whether any of the material examined during the inspection should be considered proprietary information. The licensee did not identify any proprietary information.

4OA7 Licensee Identified Violations

The following violations of very low safety significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600 for being dispositioned as NCVs:

  • Technical Specification Table 3.3-1, functional Unit 20, requires the reactor trip system trip logic to be operable. Technical specification 3.0.3 requires that action be taken within one hour to place the unit in Hot Standby within the next six hours. Contrary to the above, for the period from July 14 2008, until October 11, 2008, reactor trip system logic for undervoltage protection was not operable, and action was not taken to shutdown the unit as required. When discovered on October 11, 2008, an investigation was initiated, the reactor protection trip logic circuitry was altered and relays were replaced to restore the system to an operable configuration. The issue was documented in the licensees corrective action program as Condition Report 2009-28058. This finding was of very low safety significance because redundant reactor protection features remained available to assure safety should an undervoltage condition occur.
  • Technical Specification 3.6.4 requires each containment isolation valve be Operable or, either restore the valve to operable status or isolate the affected penetration within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> by use of at least one closed manual valve. Contrary to the above, on June 1, 2008, secondary system containment isolation valve CV-3-6275C failed a stroke test, was declared inoperable, and the affected penetration was not closed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> as required. When identified by the licensee during investigation of the failed test, on June 9, Technical specification 3.6.4 was invoked and the penetration was isolated by closing a manual isolation valve. The issue was documented in the corrective action program as CR 2008-18474. The finding was of very low safety significance because manual isolation of the penetration remained available, if needed in an event, and redundant mitigating trains of auxiliary feedwater remained available.

ATTACHMENT: SUPPPLEMENTAL INFORMATION

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

J. Antignano, Fire Protection Supervisor
R. Coffey, Maintenance Manager
J. Hamm, Engineering Manager
S. Shafer, Assistant Operations Manager
M. Kiley, Site Vice-President
K. OHare, Performance Improvement Manager
L. Hardin, Emergency Preparedness Manager
R. Wright, Operations Manager
P. Ruben, Acting Plant General Manager
M. Crosby, Quality Manager
N. Bach, Chemistry Manager
C. Cashwell, Radiation Protection Manager
R. Tomonto, Licensing Manager

NRC personnel

M. Sykes, Branch Chief, DRP
C. Christensen, Deputy Director, DRS

LIST OF ITEMS OPENED, CLOSED AND DISCUSSED

Closed

50-251/2008-004-01 LER Undervoltage Trip Time Delay Relays Cause Loss of Function

50-251/2008-004-00 LER Undervoltage Trip Time Delay Relays Cause Loss of Function

50-250/2008-003-01 LER Inoperable Steam Generator Blowdown Containment Isolation

Valve in Excess of Technical Specification Required Isolation

Time

50-250/2008-003-00 LER Inoperable Steam Generator Blowdown Containment Isolation

Valve in Excess of Technical Specification Required Isolation

Time

Attachment

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