IR 05000250/2013003
| ML13211A151 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 07/30/2013 |
| From: | Rich D W NRC/RGN-II/DRP/RPB3 |
| To: | Nazar M Florida Power & Light Co |
| References | |
| IR-13-003 | |
| Download: ML13211A151 (29) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION REGION II 245 PEACHTREE CENTER AVENUE NE, SUITE 1200 ATLANTA, GEORGIA 30303
-1257 July 30 , 2013 Mr. Mano Nazar Executive Vice President Nuclear and Chief Nuclear Officer Florida Power and Light Company P.O. Box 14000 Juno Beach, FL 33408
-0420
SUBJECT: TURKEY POINT NUCLEAR GENERATING UNITS 3 AND 4 - NRC INTEGRATED INSPECTION REPORT 05000250/201 3 003 AND 05000251/201 3 003
Dear Mr. Nazar:
On June 30, 201 3, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Turkey Point Nuclear Generating Units 3 and 4. The enclosed integrated inspection report documents the inspection results, which were discussed on July 11, 2013, with Mr. Kiley and other members of your staff.
The inspection examined activities conducted under your license as they related to safety and compliance with the Commission's rules and regulations and with the conditions of your license. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.
One NRC identified finding of very low safety significance (Green) w as identified during this inspection.
The finding w as determined to involve a violation of NRC requirements.
Additionally, a licensee-identified violation which was determined to be of very low safety significance is listed in this report.
The NRC is treating these violations as n on-cited violations (NCV s) consistent with Section 2.3.2 of the Enforcement Policy.
If you contest the violations or significance of 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
20555-0001; with copies to the Regional Administrator Region IV; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555
-0001; and the NRC Resident Inspector at Turkey Point Nuclear Generating Units 3 and 4. Enclosure If you disagree with the cross
-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this report, with the basis of your disagreement, to the Regional Administrator, Region II and the NRC Resident Inspector at Turkey Point Nuclear Generating Units 3 and 4.
In accordance with 10 CFR 2.
390 of the NRC's "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 NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading
-rm/adams.html (the Public Electronic Reading Room
).
Sincerely,
/RA/
Daniel W. Rich, Chief Reactor Projects Branch 3 Division of Reactor Projects Docket Nos.
50-250, 50-251 License Nos. DPR
-31 , DPR-41 Enclosure: Inspection Report 05000250/201 3 00 3, 05000251/201 3 003 w/Attachment: Supplemental Information cc w/encl: (See page 3)
_________
________________ SUNSI REVIEW COMPLETE FORM 665 ATTACHED OFFICE RII:DRP RII:DRP RII:DRP RII:DRP SIGNATURE Via email Via email /RA/:SRS /RA/:DWR NAME THoeg MBarillas SSandal DRich DATE 7/23/2013 7/24/2013 7/23/2013 7/29/2013 7/ /2013 7/ /2013 7/ /2013 E-MAIL COPY?
YES NO YES NO YES NO YES NO YES NO YES NO YES NO cc w/encl.
Alison Brown Nuclear Licensing Florida Power & Light Company Electronic Mail Distribution
Larry Nicholson Director Licensing Florida Power & Light Company Electronic Mail Distribution Michael Kiley Site Vice President Turkey Point Nuclear Plant Florida Power and Light Company Electronic Mail Distribution Neil Batista Emergency Management Coordinator Department of Emergency Management and Homeland Security Electronic Mail Distribution Paul Freeman Vice President Organizational Effectiveness Florida Power & Light Company Electronic Mail Distribution Peter Wells Vice President Outage Support CFAM Florida Power & Light Company Electronic Mail Distribution
Robert J. Tomonto Licensing Manager Turkey Point Nuclear Plant Florida Power & Light Company Electronic Mail Distribution
Eric McCartney Plant General Manager Turkey Point Nuclear Plant Florida Power and Light Company Electronic Mail Distribution Cynthia Becker (Acting) Chief Florida Bureau of Radiation Control Department of Health Electronic Mail Distribution
Senior Resident Inspector Turkey Point Nuclear Generating Station U.S. Nuclear Regulatory Commission 9762 SW 344th St.
Florida City, FL 33035 James Petro Managing Attorney
-Nuclear Florida Power & Light Company Electronic Mail Distribution
County Manager of Miami
-Dade County 111 NW 1st Street, 29th Floor Miami, FL 33128 George Gretsas City Manager City of Homestead Electronic Mail Distribution Letter to Mano Nazar from Dan Rich dated July 30, 2013.
SUBJECT: TURKEY POINT NUCLEAR GENERATING UNITS 3 AND 4 - NRC INTEGRATED INSPECTION REPORT 05000250/2013 003 AND 05000251/2013003 DISTRIBUTION: C. Evans L. Douglas OE Mail RIDSNRRDIRS RidsNrrPMTurkeyPoint Resource
Enclosure U.S. NUCLEAR REGULATORY COMMISSION REGION II Docket Nos: 50-250, 50-251 License Nos: DPR-31 , DPR-41
Report No: 05000250/201 3 00 3, 05000251/201 3 003 Licensee: Florida Power & Light Company (FP&L)
Facility: Turkey Point Nuclear Generating Units 3 & 4 Location: 9760 S. W. 344th Street Homestead, FL 33035
Dates: April 1 to June 30, 2013 Inspectors: T. Hoeg, Senior Resident Inspector M. Barillas, Resident Inspector Approved by: D. Rich, Chief Reactor Projects Branch 3
Division of Reactor Projects
Enclosure
SUMMARY OF FINDINGS
IR 05000250/201 3 00 3, 05000251/201 3 00 3; 0 4/01/2013 - 06/3 0/201 3; Turkey Point
Nuclear Generating, Units 3 & 4; Operability Determinations The report covered a three month period of inspection by resident inspectors. One Green non-cited violation was identified
. The significance of the inspection finding w as identified by its color (Green, White, Yellow, or Red) and determined using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process
," (SDP) dated June 2, 2011.
The cross-cutting aspect was determined using IMC 0310, "Components Within the Cross-Cutting Areas ," dated October 28, 2011.
All violations of NRC requirements were dispositioned in accordance with the NRC's Enforcement Policy dated January 28, 2013.
The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4.
Cornerstone: Mitigating Systems
- Green.
The NRC identified a non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, "Corrective Action," for the licensee's failure to identify and correct a through wall pressure boundary leak on the 3A component cooling water (CCW) pump casing vent piping that affected system operability. The inspectors determined that the licensee's failure to identify and correct a through wall leak on an ASME Code Class pressure boundary was a performance deficiency.
The condition was entered in the licensee corrective action program (C AP) as action request 01883690 and the pipe was replaced.
The performance deficiency was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, because it was associated with the mitigating systems cornerstone attribute of equipment performance and adversely affected the cornerstone objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the inspectors determined that the licensee's failure to identify a system pressure boundary leak precluded evaluations and repairs necessary to assure the reliability of the component cooling water system. The inspectors evaluated the finding using IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, Tables 2 and 3, dated June 19, 2012, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2 for the Mitigating Systems Cornerstone, dated June 19, 2012.
The inspectors answered " yes" to the Exhibit 2 question A.1 because the system maintained its functionality. As a result, the inspectors determined the finding to be of very low safety significance (Green).
This finding was associated with a cross-cutting aspect in the corrective action program component of the problem identification and resolution area. Specifically, the licensee failed to consider the potential for system pressure boundary leakage when evaluating the operability of the component cooling water system P.1(c). (Section 1R15)
=
Licensee-Identified Violations===
One violation of very low safety significance was identified by the licensee and reviewed by the NRC. Corrective actions taken or planned by the licensee have been entered into the licensee's corrective action program. This violation and the corrective action t racking number are listed in Section 4OA7 of this report.
REPORT DETAILS
Summary of Plant Status
Unit 3 began this inspection period at 95 percent rated thermal power (RTP) and reached 100 percent RTP on April 15 where it remained until May 10 when it was shut down to Mode 3 for planned maintenance on the secondary plant
. Unit 3 returned to RTP on May 24 where it remained through the end of this inspection period.
Unit 4 began the inspection period in a scheduled refueling and extended power uprate outage in Mode 3. Unit 4 entered Mode 2 on April 6 and Mode 1 on April 14. Unit 4 returned to 100 percent RTP on May 24 where it remained through the end of this inspection period.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity (Reactor
-R) 1R01 Adverse Weather Protection
.1 Hurricane Season Preparations
and AC Power System Summer Readiness
a. Inspection Scope
During the month s of May and June, the inspectors reviewed and verified the status of licensee actions taken in accordance with their procedural requirements prior to the onset of hurricane season.
The inspectors reviewed the licensee completed administrative procedures 0-ADM-116, Hurricane Season Readiness and OP-AA-102-1002, Seasonal Readiness. The inspectors performed site walk downs of the systems or areas listed below to determine if the licensee had made the required preparations in accordance with their procedures
. Condition reports (CRs) were reviewed to determine if the licensee was identifying and resolving conditions associated with adverse weather preparedness.
Switchyard and Startup Transformer AC systems (AC Systems Sample)
Unit 3 and Unit 4 intake cooling water structures Unit 3 and Unit 4 component cooling water (CCW) systems Unit 3 and Unit 4 intake cooling water (ICW) systems Unit 3 and Unit 4 turbine and auxiliary buildings
b. Findings
No findings were identified.
.2 External Flooding Preparations
a. Inspection Scope
The inspectors performed walkdown inspections of Unit 3 and Unit 4 reactor auxiliary buildings, including doors, flood protection barriers, penetrations and the integrity of the perimeter structure. The inspectors verified the licensee had implemented surveillance procedure 0-SMM-102.1, Flood Protection Stop Log and Penetration Seal Inspection, to ensure that vulnerabilities had been identified and evaluated by the licensee. In addition, the inspectors walked down the Unit 3 and Unit 4 emergency diesel generators (EDG) and fuel oil tanks, auxiliary feedwater (AFW) pump areas and the turbine buildings.
The inspectors also reviewed the applicable Updated Final Safety Analysis Report (UFSAR) sections, Technical Specifications, and other licensing basis documents regarding external flooding and flood protection, including specific plant design features to mitigate the maximum flood level. Corrective Action Program (CAP) documents and work orders (WO) related to actual flooding or water intrusion events over the past year were also reviewed by the inspectors to ensure that the licensee was identifying and resolving severe weather related issues that caused or could lead to external flooding of safety related equipment.
b. Findings
No findings were identified.
1R04 Equipment Alignment
.1 Partial Equipment Walk downs
(Quarterly)
a. Inspection Scope
The inspectors conducted four 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.
Auxiliary feed water (AFW) Train II while Train I was out of service 4A and 4B emergency containment coolers while 4C was out of service A and B AFW pumps while C was out of service 3B containment spray train while 3A was out of service
b. Findings
No findings were identified.
.2 Equipment Alignment (Semi
-annual)
a. Inspection Scope
The inspectors conducted one complete system alignment walk down of the 4A emergency diesel generator (EDG) while the 4B was out of service for testing.
The inspectors conducted a detailed review of the alignment and condition of the 4A EDG system to verify its capability to meet its design basis function.
The inspectors utilized licensee procedures 4-N OP-022 , Emergency Diesel Generator Fuel Oil System, 4-N OP-023, Emergency Diesel Generator, and drawing 5614-M-3022 , 4B EDG Fuel System Drawing, as well as other licensing and design documents to verify the system alignment was correct. During the walkdown, the inspectors verified, as appropriate, that:
- (1) valves were correctly positioned and did not exhibit leakage that would impact their function,
- (2) electrical power was available as required,
- (3) major portions of the system and components were correctly labeled, cooled, and ventilated,
- (4) hangers and supports were correctly installed and functional,
- (5) essential support systems were operational,
- (6) ancillary equipment or debris did not interfere with system performance,
- (7) tagging clearances were appropriate, and
- (8) valves were locked as required by the licensee's locked valve program.
Other items reviewed included the operator workaround list, the temporary modification list, system health reports, system description, and outstanding maintenance work requests and work orders.
In addition, the inspectors reviewed the licensee's CAP to ensure that the licensee was identifying and resolving equipment alignment problems.
b. Findings
No findings were identified.
1R05 Fire Protection
.1 Fire Area Walk downs
a. Inspection Scope
The inspectors toured the following five plant areas to evaluate conditions related to control of transient combustibles, ignition sources, and the material condition and operational status of fire protection systems including fire barriers used to prevent fire damage and propagation. The inspectors reviewed these activities using provisions in the licensee's procedure 0
-ADM-016, Fire Protection Plan, and 10 CFR Part 50, Appendix R. The licensee's 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 inspectors accompanied fire watch roving personnel on a tour of fire protection impairments and risk significant fire areas to assure monitoring of area status and to verify proper identification and handling of transient combustibles. The following areas were inspected:
Unit 3 and common computer room zone 62 3A emergency diesel day tank room zone 75 Auxiliary feed water pump area zone 84 4B residual heat removal room zone 16 4A switchgear room zone 68
b. Findings
No findings were identified.
.2 Fire Protection - Drill Observation
a. Inspection Scope
On April 17, the inspectors observed an announced fire drill that took place in the power block area near the 3A emergency diesel generator fuel oil transfer pump. The drill was observed to evaluate the readiness of the plant fire brigade to fight fires. The inspectors verified that the licensee staff identified deficiencies, openly discussed them in a self
-critical manner at debrief, and took appropriate corrective actions as required. Specific attributes evaluated were:
- (1) proper wearing of turnout gear and self-contained breathing apparatus,
- (2) proper use and layout of fire hoses,
- (3) employment of appropriate firefighting techniques,
- (4) sufficient firefighting equipment brought to the scene,
- (5) effectiveness of command and control,
- (6) search for victims and propagation of the fire into other plant areas,
- (7) smoke removal operations,
- (8) utilization of pre
-planned strategies,
- (9) adherence to the pre
-planned drill scenario, and
- (10) drill objectives.
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification
Program
.1 Resident Inspector Quarterly Review
a. Inspection Scope
On June 17, 2013, the inspectors assessed licensed operator performance in the plant specific simulator during a licensed operator continuing training scenario. The training scenario was started at with Unit 3 at 50 percent power and steady state conditions. Event simulations were accomplished using Simulator Evaluation PTN 7 50207600 , Turbine Trip with Loss of Auxiliary Feed Water and Steam Generator Feed Pumps. Operators responded to the event using off-normal procedure 3
-ONOP-071.2 for steam generator tube leakage. Emergency procedures used by the crew to safely mitigate the events included 3
-EOP-E-0, Reactor Trip and 3
-EOP-ES-0.1 , Reactor Trip Response, 3
-ONOP-046.1, Emergency Boration, and 3
-EOP-FR-H.1, Loss of Secondary Heat Sink. The inspectors specifically checked that the simulated emergency classification of Site Area Emergency was done in accordance with licensee procedure, 0
-EPIP-20101, Duties of the Emergency Coordinator.
The simulator board configurations were compared with actual plant control board configurations concerning recent power up rate modifications. The inspectors specifically evaluated the following attributes related to operating crew performance and the post-scenario 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 shift supervisor, including ability to identify and implement appropriate technical specifications actions and emergency plan classification and notification Crew overall performance and interactions Evaluator's control of the scenario and post
-scenario evaluation of crew performance
b. Findings
No findings were identified.
.2 Control Room Observations
a. Inspection Scope
The inspectors observed the following two focused control room observations and assessed licensed operator performance in the plant and main control room, particularly during periods of heightened activity or risk and where the activities could affect plant safety. These observations routinely included surveillance testing, response to alarms, communications, and coordination of activities. These observations were conducted to verify operator compliance with station operating protocols, such as use of procedures, control and manipulation of components, and communications. On May 8, 2013, the inspectors did a focused observation which included Unit 4 extended power up rate power ascension from 87 percent power to 89 percent power per 3
-GOP-301, Hot Standby to Power Operation. Specifically, the inspectors verified the operators used the Reactivity Maneuver Plan provided by reactor engineering for a one percent per hour power change rate. The inspectors verified that operators borated and moved rods in a controlled manner to meet Technical Specification limits for axial flux deviation. The inspectors observed power ascension from 89 percent power to 92 percent power on May 9, 2013.
The inspectors focused on the following attributes in the conduct of operations that were appropriate:
Operator compliance with and use of procedures Control board manipulations Communication between crew members Use and interpretation of plant instruments, indications and alarms Use of human error prevention techniques Documentation of activities, including initials and sign
-offs in procedures Supervision of activities, including risk and reactivity management Additionally, the following two periods of heightened activity or risk were also observed by the inspectors: April 19, unusual event declared on Unit 4 due to loss of offsite power during third harmonic relay testing and reactor trip. June 25, Unit 3 extended power uprate ramp test from 90 to 100 percent.
b. Findings
No findings were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors reviewed the following two systems and associated equipment problems documented in condition reports to verify that the licensee's maintenance efforts met the requirements of 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, and licensee administrative procedure 0
-ADM-728, Maintenance Rule Implementation. 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 verified that equipment problems were being identified and entered into the corrective action program. The inspectors used licensee maintenance rule database, system health reports, and the corrective action program as sources of information for the tracking and resolution of issues. The Unit 3 reactor coolant system was selected due to a recent reactor coolant pump seal failure in February 2013 affecting a(2) system performance criteria and potential to be placed in a(1) monitoring.
The Unit 3 component cooling water system was selected due to its risk significance and the number of unavailability hours recorded over the last 12 months.
Unit 3 reactor coolant system Unit 3 component cooling water system
b. Findings
No findings 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 licensee's risk assessment of four emergent or planned maintenance activities. The inspectors verified the licensee's 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 WM-AA-1000, Work Activity Risk Management, and O-ADM-225, On Line Risk Assessment and Management. The inspectors also reviewed the effectiveness of the licensee's contingency actions to mitigate increased risk resulting from the degraded equipment and the licensee assessment of aggregate risk using FPL procedure OP
-AA-104-1007, Online Aggregate Risk. The inspectors evaluated the following six risk assessments during the inspection period: 3A emergency diesel generator (EDG), diesel driven standby feed water pump, and 3A load center air conditioning unit out of service (OOS)3C steam generator flow control valve and 3B steam generator feed water pump OOS Unit 4 reactor protection system steam flow and feed flow channel IV OOS during AFW Train II surveillance testing 3A charging pump, 3A component cooling water (CCW) heat exchanger, 3A high head safety injection pump OOS 3A CCW pump, R11 and R12 radiation monitors, 3A containment spray pump, and MOV-3-1405 OOS 4A EDG, 4B emergency containment cooler, 4A CCW pump OOS
b. Findings
No findings were identified.
1R15 Operability Determinations and Functionality Assessments
a. Inspection Scope
For the six operability evaluations described in the action requests (AR) 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 UFSAR to verify that the system or component remained available to perform its intended function. In addition, when applicable, the inspectors reviewed compensatory measures 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.
AR 1833263, nuclear instrument system power range allowance with NI
-303 mete r accuracy AR1867728, 4A EDG ventilation fan 4V63A failed to auto
-start AR 1768189, low o il level in A AFW governor AR 1864215, evaluate operability due to multiple AFW steam leaks AR 1880602, 3A component cooling water pump casing vent leak AR 1881208, C AFW pump increased vibration
b. Findings
Introduction:
A Green NRC identified non
-cited violation (NCV) of 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, was identified when the licensee failed to identify and correct a through wall pressure boundary leak on the 3A component cooling water (CCW) pump casing vent piping that affected system operability.
Description:
On June 7, 2013, the licensee initiated action request (AR) 01880602, to assess leakage from a 0.75 inch diameter vent pipe installed on the 3A CCW pump casing associated with vent valve 3
-703Q. The AR noted that the leakage was from the threaded mechanical joint connection that attached the pipe to the pump casing and was leaking approximately 100 drops per minute (DPM). The licensee concluded the leakage did not adversely affect the functional capability of the pump to provide cooling to the CCW system. The licensee's conclusion was based on the leak rate being less than the system surge tank makeup capability in order to maintain an adequate net positive suction head on the pump and was not considered by the licensee to represent a condition adverse to quality. The Unit 3 senior reactor operator reviewing the AR for immediate operability concluded the pump was operable based on the leak rate only and did not require a prompt operability determination to be performed as described in licensee procedure EN
-AA-203-1001, Operability Determinations and Functionality Assessments..
On June 19, 2013, the inspectors walked down the 3A CCW pump to monitor and assess any changes in the leak rate and to determine if the licensee's description of the leak and corrective actions were commensurate with risk and safety. During the walk down, the inspectors noted that the leak was spraying water in a steady stream and appeared to be worsening from the 100 DPM leak rate described in the subject AR. The inspectors observed that the damaged pipe was covered in epoxy paint and no external corrosion or wear was evident to support a conclusive determination of mechanical joint leakage. The inspectors noted that the pipe appeared to have a through wall pressure boundary leak requiring a code flaw evaluation and were concerned that system pressure boundary leakage represented a condition adverse to quality th at had not been addressed by the licensee's immediate operability determination or subsequent corrective actions. The inspectors reported their observations to the shift manager and engineering director who later confirmed the leak may be through wall and was getting worse. On the afternoon of June 19, 2013, the shift manager declared the 3A CCW pump inoperable due what appeared to be a through wall leak on the vent piping that could not be evaluated for structural integrity in its current condition. On June 20, 2013, the vent pipe was removed from the pump casing and a non-destructive evaluation (NDE) dye penetrant test confirmed a through wall crack located on a pipe thread where it was fastened to the pump casing using. On June 21, 2013, the vent pipe was replaced with a new assembly and the pump was returned to service. The condition was entered in the licensee's corrective action program as action request 01883690 for evaluation and development of further corrective actions.
Analysis:
The inspectors determined that the licensee's failure to identify and correct a through wall leak on an ASME c ode class pressure boundary component was a performance deficiency. The performance deficiency was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, because it was associated with the mitigating systems cornerstone attribute of equipment performance and adversely affected the cornerstone objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the inspectors determined that the licensee's failure to identify a system pressure boundary leak precluded evaluations and repairs necessary to ensure the reliability of the component cooling water system. The inspectors evaluated the finding using IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, Tables 2 and 3, dated June 19, 2012, and Appendix A, The Significance Determination Process (SDP) for Findings At
-Power, Exhibit 2 for the Mitigating Systems Cornerstone, dated June 19, 2012.
The inspectors answered "yes" to the Exhibit 2 question A.1 because the system maintained its functionality. As a result, the inspectors determined the finding to be of very low safety significance (Green). This finding was associated with a cross-cutting aspect in the corrective action program component of the problem identification and resolution area. Specifically, the licensee failed to consider the potential for system pressure boundary leakage when evaluating the operability of the component cooling water system P.1(c).
Enforcement:
10 CFR Appendix B, Criterion XVI, Corrective Action, requires in part that measures shall be established to assure conditions adverse to quality are promptly identified and corrected.
Contrary to the above, on June 7, 2013, the licensee identified that the 3A CCW pump casing vent pipe was leaking 100 drops per minute, but failed to identify the leak was a through wall pressure boundary leak requiring a code flaw evaluation for operability. This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy, because it was of very low safety significance (Green) and was entered in the licensee's corrective action program as AR 1883690. The affected pipe was replaced on June 21, 2013, and a licensee engineering evaluation was being performed for potential reportability at the close of this inspection period. (NCV 05000250/2013003
-01, Failure to Promptly Identify and Correct a Pressure Boundary Through Wall Leak on the 3A CCW Pump Casing Vent Pipe)
1R18 Plant Modifications
a. Inspection Scope
The inspectors reviewed the following temporary plant modification. Each temporary system alteration (TSA) was performed in accordance with licensee procedure 0-ADM-503, Temporary System Alterations. The inspectors reviewed the 10 CFR 50.59 screening an d technical evaluation to verify that the modification had not affected system operability or availability. The inspectors reviewed associated plant drawings and UFSAR documents impacted by this modification and discussed the changes with licensee personnel to verify that the installation was consistent with the modification documents. The inspectors walked down available portions of the modification to determine if it was installed in the field as described in the subject TSA. Additionally, the inspectors verified that problems associated with modifications were being identified and entered into the CAP.
TSA EC 270962, Unit 3 and Unit 4 temporary main steam line radiation monitors
b. Findings
No findings were identified.
1R19 Post Maintenance Testing
.1 Resident Inspector Baseline
a. Inspection Scope
For the two post maintenance tests and associated work orders (WO), the inspectors reviewed the test procedures and either witnessed the testing 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 operable. The inspectors used licensee procedure 0
-ADM-737, Post Maintenance Testing, in their assessments.
WO 40069744, control room emergency ventilation filtration system WO 40058468, MOV-4-869, High head safety injection isolation valve motor operator planned maintenance
b. Findings
No findings were identified.
.2 Extended Power Uprate Modifications Inspection Procedure (IP) 71004
a. Inspection Scope
For the six post maintenance tests listed below, the inspectors reviewed the test procedures and either witnessed the testing 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 operable. The inspectors used licensee procedure 0
-ADM-737, Post Maintenance Testing, in their assessments for the following six inspection samples:
Unit 4, EPU, 4
-PTP-072.6, 4A main steam isolation valve test as part of extended power uprate modification covered under engineering change EC 246883 Unit 4, EPU, 4
-PTP-072.7, 4B main steam isolation valve test as part of extended power uprate modification covered under engineering change EC 246883 4-PTP-072.2, section 4.6.9, 10%
l oad changes, at the 30 percent reactor power plateau to verify plant response per extended power uprate modifications 4-PTP-074.17, 87, 95, 100 percent reactor power leading edge flow meter (LEFM) power ascension test for modification EC 242439 per extended power uprate modifications 4-PTP-072.2, EPU return to service testing, 50, 87, 92, 95, 98, and 100 percent reactor power plateau testing to verify plant response per extended power uprate modifications Unit 4 EPU, T 143-04, hot leg injection alternate flow path modification EC 249722
b. Findings
No findings were identified.
1R20 Refueling and Other Outage Activities
Unit 4 Refueling and Extended Power Uprate (EPU) Outage 27
a. Inspection Scope
Outage Planning, Control and Risk Assessment During daily outage planning activities by the licensee, the inspectors reviewed the risk reduction methodology employed by the licensee during various refueling outage (RFO) meetings including Outage Control Center (OCC) morning meetings, Operations Daily Team Meetings, and Schedule Performance Update Meetings. The inspectors examined the licensee implementation of shutdown safety assessments in accordance with procedure ADM
-051, Outage Risk Assessment and Control, to verify whether a defense in depth concept was in place to ensure safe operations and avoid unnecessary risk. In addition, the inspectors regularly monitored outage planning and control activities in the OCC and interviewed responsible OCC management during the outage to ensure system, structure, and component configurations and work scope were consistent with TS requirements, site procedures, and outage risk controls.
Outage Activities The inspectors examined outage activities to verify that they were conducted in accordance with TS, licensee procedures, and the licensee's outage risk control plan.
Some of the more significant inspection activities accomplished by the inspectors were as follows:
Walked down selected safety
-related equipment clearance orders Verified operability of RCS pressure, level, flow, and temperature instruments during various modes of operation Verified electrical systems availability and alignment Verified shutdown cooling system and spent fuel pool cooling system operation Evaluated implementation of reactivity controls Verified controls in place to prevent inventory loss Reviewed control of containment penetrations Examined foreign material exclusion (FME) controls put in place inside containment (e.g., around the refueling cavity, near sensitive equipment and RCS breaches) and around the spent fuel pool (SFP)
Verified workers fatigue was properly managed Monitoring of Heatup and Startup Activities
The inspectors examined applicable technical specifications, license conditions and verified administrative prerequisites were being met prior to mode changes. The inspectors also reviewed measured RCS leakage rates, and verified containment integrity was properly established. The inspectors performed a containment closeout inspection prior to reactor plant startup to verify no evidence of leakage or debris left in the containment that could affect plant operations. The results of low power physics testing were discussed with Reactor Engineering and Operations personnel to ensure that the core operating limit parameters were consistent with the design. The inspectors witnessed portions of the RCS heat up, reactor startup, and power ascension.
Corrective Action Program The inspectors reviewed action requests (AR) generated during the outage to evaluate the licensee's threshold for initiating ARs. The inspectors reviewed ARs to verify priorities, mode holds, and significance levels were assigned as required. Resolution and implementation of corrective actions of several ARs were also reviewed for completeness. The inspectors routinely reviewed the results of Quality Assurance (QA) daily surveillances of outage activities.
Reactor Startup and Mode Changes On April 6, 2013, the inspectors observed the Unit 4 reactor startup and turbine synchronization to the electrical grid and associated Mode changes. The inspectors reviewed the recorded reactor startup physics data in order to determine it was as calculated by the licensee reactor engineering staff. The inspectors determined the startup and Mode changes were performed in accordance with licensee procedures 0-OSP-040.16, Initial Criticality After Refueling Outage and Nuclear Design Verification, and 4
-GOP-301, Mode 3 to Power Operations.
b. Findings
No findings were identified.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors either reviewed or observed the following six surveillance tests to verify that the tests met the TS, the UFSAR, the licensee's 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 alignment required for the system to perform its safety function. The inspectors verified that surveillance issues were documented in the CAP. Inspections of extended power up rate (EPU) testing were performed under NRC Inspection Procedure 71004 guidance.
In-Service Tests: 3-OSP-050.2A, MOV-3-861A In-service Stroke Test 3-OSP-050.2A, 3A Residual Heat Removal Pump Code Run Surveillance Tests:
4-OSP-089.1, Unit 4 Turbine Overspeed Trip Test for 4R27 Extended Power Uprate Return to Service Testing 3-OSP-075.6, AFW Train I and Backup Nitrogen Test 3-OSP-023.1, 3A Emergency Diesel Generator Fast Start Test Containment Isolation Valve Leak Test:
4-OSP-51.5, Local Leak Rate Test Containment Penetration 35, (CIV sample)
b. Findings
No findings were identified.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
a. Inspection Scope
The inspectors checked licensee submittals for the performance indicators (PIs) listed below for the period April 1, 2012 thru March 31, 201 3, 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, and licensee procedure 0
-ADM-032, "NRC Performance Indicators Turkey Point," were used to check the reporting for each data element. The inspectors checked operator logs, plant status reports, condition reports, system health reports, and PI data sheets to verify that the licensee had identified the required data, as applicable. The inspectors interviewed licensee personnel associated with performance indicator data collection, evaluation, and distribution.
On May 22, 2013, the inspector observed reactor coolant sampling in accordance with licensee procedure 0-NCZP-046.4, Obtaining a Reactor Coolant Demineralizer Sample. The inspectors reviewed the following performance indicators for unit 3 and unit 4:
Barrier Integrity Unit 3 reactor coolant system leakage Unit 4 reactor coolant system leakage Unit 3 r eactor coolant system activity Unit 4 reactor coolant system activity
b. Findings
No findings were identified.
4OA2 Problem Identification
and Resolution (IP 71152)
.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 licensee's corrective action program. This review was accomplished by reviewing daily printed summaries of CRs and by reviewing the licensee's electronic CR database. Additionally, reactor coolant system unidentified leakage was checked on a daily basis to verify no substantive or unexplained changes. Documents reviewed are listed in the attachment.
b. Findings
No findings were identified.
.2 Annual Sample:
Root Cause Evaluation Associated With Incorrect Fluke Used to Calibrate Eagle 21 Channels
a. Inspection Scope
The inspectors selected AR 01836648 , "Incorrect Fluke Used to Calibrate Eagle 21 Channels," for a more in
-depth review of the circumstances and the corrective actions that followed. On January 3, 2013, the licensee discovered that the wrong multi
-meter test device was used during the performance of quarterly surveillance procedures 3
-SMI-041.11A and 3-SMI-041.104. The quarterly surveillance test performed a pressurizer high level reactor protection system instrument operational test that rendered the pressurizer level instrument transmitter LT
-459 high level set point out of specification when returned to service. As a result, LT
-459 was inoperable for a period of approximately 30.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> and not in compliance with technical specification 3.3.1, Reactor Trip System Instrumentation, which required an inoperable channel be placed in the tripped condition within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of discovery
. This particular event is discussed in further detail in section
4OA3 and 4OA7 of this
inspection report.
The inspectors reviewed the licensee's evaluation of the event and the associated corrective actions taken or planned. The inspectors reviewed licensee performance attributes associated with complete and accurate information of the problem, 10 CFR 50.72 reporting requirements, identification of the root and contributing causes, and planning or completion of assigned corrective actions. The inspectors interviewed plant personnel and evaluated the licensee's administration of this selected condition report in accordance with their corrective action program as specified in licensee procedures PI-AA-204, "Condition Identification and Screening Process," and PI-AA-205, "Condition Evaluation and Corrective Action."
b. Findings and Observations
No inspector findings were identified. The licensee determined the root cause of the event was due to failure of maintenance technicians to adhere to standards for procedure use and verbatim compliance. As a result, a reactor protection system pressurizer level instrument LT-459 was returned to service outside its required set point. The inspectors noted that the licensee identified contributing causes to be that there is no formal process for placing new test equipment in service and that there was a knowledge gap among I&C technicians regarding the use of test equipment and how it can impact plant equipment. This licensee identified violation is further discussed in section
4OA7 of this report.
Immediate corrective actions for this event included a maintenance department human performance event review , an extent of condition review to determine if the Fluke Model 8846A had been used in other applications, and reinforcement of procedure adherence and verbatim compliance.
.3 Unit 4 Extended Power Uprate (EPU) Identification and
Resolution of Problems (IP 71004)
a. Inspection Scope
The inspector reviewed selected corrective action program (CAP) action requests (AR) generated by the licensee during an extended power up rate project being performed on Unit 4 during a scheduled refueling outage. The inspectors verified that problems were being properly identified, appropriately characterized, and entered into the CAP. The inspectors reviewed corrective action program documents that were issued during the second quarter of 201 3, including the following risk significant systems:
intake cooling water, component cooling water, high h ead safety injection system, containment spray system, and emergency diesel generator. Where possible, the inspectors reviewed selected ARs, verified corrective actions were planned or implemented, and attended meetings where CRs were screened for significance to determine whether the licensee was identifying, accurately characterizing, and entering problems into the CAP at an appropriate threshold.
The inspectors conducted plant walk downs of equipment associated with the aforementioned systems and other plant areas to assess the material condition and to look for any deficiencies that had not been previously entered into the CAP. Control room walk downs were performed to assess proper function of new EPU control and instrumentation equipment and to verify that deficiencies were documented in the control room deficiency logs.
The inspectors reviewed site trend reports to determine if the licensee effectively trended identified issues and initiated appropriate corrective actions when adverse trends were identified associated with EPU projects. The inspectors attended plant meetings to observe management oversight functions of the corrective action process. These included the CR screening meetings and management review committee meetings.
b. Findings and Observations
No findings were identified. The inspectors determined that the licensee was effective in identifying problems and entering them into the CAP and there was a low threshold for entering issues into the CAP associated with the EPU project. This conclusion was based on a review of the requirements for initiating CRs as described in licensee procedure PI-AA-204, "Condition Identification and Screening Process," and PI-AA-205, "Condition Evaluation and Corrective Action." Trending was generally effective in monitoring equipment performance. Site management was actively involved in the CAP and focused appropriate attention on significant plant issues associated with the EPU project.
4O A3 Event Followup (IP 71153)
.1 (Closed) LER 05000250/2013-001-00, Procedure Noncompliance Causes Incorrect
Instrument Setting and a Condition Prohibited by Technical Specifications On January 3, 2013, the licensee discovered that the wrong multi
-meter test device was used performing surveillance procedures 3
-SMI-041.11A and 3-SMI-041.104. The quarterly surveillance test performed a pressurizer high level reactor protection system instrument operational test that rendered the pressurizer level instrument transmitter LT-459 high level set point out of specification when returned to service. As a result, LT
-459 was inoperable for a period of approximately 30.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> and not in compliance with technical specification 3.3.1, which requires an inoperable channel be placed in the tripped condition within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of discovery.
The function of the pressurizer high level protection instrument is to provide a reactor trip when two of three instruments reach a high level trip set point of 92 percent.
The surveillance procedure specified the use of a Fluke Model 8842A multi
-meter. The maintenance technicians used a Fluke Model 8846A multi
-meter which had different impedance characteristics than the Model 8842A and had not been evaluated for use in this application. The operational test with the wrong meter resulted in unsatisfactory results requiring a calibration. The calibration of the instrument with the wrong meter resulted in resetting the instrument trip set point at 92.262 percent level which exceeded the technical specification limit of 92.2 percent. The licensee determined the root cause of the event was due to failure of maintenance technicians to adhere to standards for procedure use. Corrective actions included an event of condition review by maintenance personnel, an extent of condition review to determine if the Fluke Model 8846A had been used in other applications, and to review and reinforce procedure adherence and verbatim compliance. This event was associated with a violation of very low safety significance and the enforcement aspects are discussed in Section
4OA7 of this report.
This LER is closed.
.2 Personnel Performance During Unplanned Plant Operations
a. Inspection Scope
On April 19 and April 20, the inspectors reviewed personnel performance during and after an unplanned Unit 4 automatic reactor trip. The licensee was performing a harmonic relay power ascension test after the extended power uprate outage. Unit 4 was at approximately 30 percent reactor power with the auxiliary transformer supplying the safety
-related 4 kilovolt (kV) busses. The test required lowering the Unit 4 main generator output voltage. As the voltage was being lowered for the test, the degraded voltage relays actuated which resulted in a reactor trip and sequencing of the 4 kV buses from the auxiliary transformers to the emergency diesel generators. The inspectors obtained an understanding of plant status, equipment and personnel performance associated with the reactor trip and post trip actions to place the reactor plant in a safe condition. The inspectors reviewed plant data recorders, operator logs, interviewed operators, attended post trip review meetings, and verified emergency operating procedure compliance.
b. Findings
No findings were identified.
4OA5 Other Activities
.1 Quarterly Resident Inspector Observations of Security Personnel and Activities
a. Inspection Scope
During the inspection period the inspectors conducted observations of security force personnel activities to ensure that the activities were consistent with the licensee security procedures and regulatory requirements relating to nuclear plant security. These observations took place during both normal and off
-normal plant working hours. These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors' normal plant status reviews an d inspection activities.
b. Findings
No findings were identified.
.2 Independent Spent Fuel Storage Facility (ISFSI) Walk down (IP 60855.1)
a. Inspection Scope
On May 20, 2013, the inspector conducted a walk down of the ISFSI protected area per inspection procedure 60855.1, "Operation of an ISFSI at Operating Plants." The inspectors observed each cask building temperature indicator and passive ventilation system to be free of any obstruction allowing natural draft convection decay heat removal through the air inlet and air outlet openings. The inspectors observed associated cask building structures to be structurally intact and radiation protection access controls to the ISFSI area to be satisfactory.
b. Findings
No findings were identified.
4OA6 Meetings
Exit Meeting Summary
The resident inspectors presented the inspection results to Mr. Kiley and other members of licensee management on July 11, 201 3. 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 violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meet the criteria of the NRC Enforcement Policy for being dispositioned as a n on-cited violation:
Turkey Point Unit 3 and 4 Technical Specification 6.8.1.a requires, in part, that written procedures shall be implemented as referenced in Florida Power and Light (FPL) Quality Assurance Topical Report (QATR).
FPL QATR sta tes that Regulatory Guide 1.33, Quality Assurance Program Requirements, is applicable in establishing procedural controls.
Regulatory Guide 1.33 states in part, that safety related activities will be covered by written procedures.
Turkey Point instrumentation and controls maintenance procedures 3-SMI-041.11A, Pressurizer Level Protection Operational Test Channel I LT- 459 and 3-SMI-041.104, Pressurizer Level Protection Channel I Loop Calibration LT- 459 both specified the use of a Fluke Model 8842A multimeter designed for the application. Contrary to the above, the maintenance technicians used a Fluke Model 8846A multi
-meter which had different impedance characteristics than the Model 8842A and had not been evaluated for use in this application. The operational test with the wrong meter resulted in unsatisfactory results requiring an instrument calibration. The calibration and return to service of the instrument with the incorrect Fluke meter resulted in resetting the instrument set point to 92.262 percent level, which exceeded the technical specification limit of 92.2 percent. This finding is of very low safety significance because it did not affect the function of other systems used to shutdown the reactor, did not add positive reactivity, or result in mismanagement of reactivity by the operators as screened in IMC 0609 Appendix A, Exhibit 2, Section C, Reactivity Control Systems. This event is documented in the licensee corrective action program as action request number 0 1836648.
ATTACHMENT: SUPPPLEMENTAL INFORMATION KEY POINTS OF CONTACT Licensee personnel:
C. Cashwell, Radiation Protection Manager F. Banks, Quality Manager P. Czaya, Licensing
M. Epstein, Emergency Preparedness Manager J. Garcia, Engineering Director M. Jones, System Engineering Manager M. Kiley, Site Vice
-President N. Rios, Chemistry Manager E. McCartney, Plant General Manager S. Mihalakea, Licensing J. Pallin, Maintenance Manager
D. Sluzka, Work Controls Manager R. Tomonto, Licensing Manager R. Smith, Engineering
C. Domingos, Engineering Director M. Wayland, Operations Director B. Stamp, Training Manager NRC personnel:
D. Rich, Chief, Branch 3, Division of Reactor Projects J. Hanna, Senior Risk Analyst, Division of Reactor Safety S. Sandal, Senior Project Engineer L. Lake, Senior Reactor Inspector B. Collins, Reactor Inspector R. Williams, Reactor Inspector T. Hoeg, Senior Resident Inspector M. Barillas, Resident Inspector LIST OF ITEMS OPENED, CLOSED AND DISCUSSED Opened and Closed 05000 250/201 3 0 03-01 NCV Failure to Promptly Identify and Correct a Pressure Boundary Through Wall Leak on the 3A CCW Pump Casing Vent Pipe (Section 1R15)
Closed 05000250/2013001
-00 LER Procedure Noncompliance Causes Incorrect Instrument Setting and a Condition Prohibited by Technical Specifications (Section 4OA3.1)
Discussed N one LIST OF
DOCUMENTS REVIEWED
Condition Reports
01878800 01883355
01883356 01883464
01884509 01883549 01883551 01883693 01883700
01884529 01882342 01882551
01882573 01880806
01862096 01880869 01881089 01880526 01880619
01866785 01877487 01877611 01877685 01863928
01864206 1R01 Adverse Weather Protection
0-ONOP-103.3, Severe Weather Preparations
0-EPIP-20101, Duties of the EC
0-OSP-102.1, Flood Protection
0-EPIP-20106, Natural Emergencies
1R05 Fire Protection
0-ONOP-016.10, Pre
-Fire Plan Guidelines and Safe Shutdown Manual Actions
Attachment
1R12 Maintenance Effectiveness
Unit 3 System Health Report for the Reactor Coolant System Unit 3 System Health Report for Component Cooling Water System 1R15 Operability
Evaluations
EN-AA-203-1001, Operability Determinations and Assessments
0-ADM-226, Operability Screening for Condition Reports
LIST OF ACRONYMS
CAP Corrective Action Program
CCW Component Cooling Water
CFR Code of Federal Regulations
EAL Emergency Action Level
ISFSI Independent Spent Fuel Storage Installation
IST Inservice Testing
NAP Nuclear Administrative Procedure
NCV Non-Cited Violation
NRC Nuclear Regulatory Commission
PI Performance Indicator
U3 Unit 3 U4 Unit 4 UFSAR Updated Final Safety Analysis Report
WO Work Order