IR 05000250/2013004

IR 05000250-13-004, 05000251-13-004; 07/01/2013 - 09/30/2013; Turkey Point Nuclear Generating Units 3 & 4; Problem Identification and Resolution, Follow-up of Events and Notice of Enforcement Discretion

ML13304A619
Person / Time
Site:	Turkey Point
Issue date:	10/31/2013
From:	Gregory Kolcum NRC/RGN-II/DRP/RPB3
To:	Nazar M Florida Power & Light Co
References
IR-13-004
Download: ML13304A619 (45)

Text

October 31, 2013

SUBJECT:

TURKEY POINT NUCLEAR GENERATING UNITS 3 AND 4 - NRC INTEGRATED INSPECTION REPORT 05000250/2013004 AND 05000251/2013004

Dear Mr. Nazar:

On September 30, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Turkey Point Nuclear Generating Units 3 and 4. On October 10, 2013, the NRC inspectors discussed the results of this inspection with Mr. Kiley and other members of your staff.

NRC inspectors documented five findings of very low safety significance (Green) in this report.

Four of these findings involved violations of NRC requirements. The NRC is treating these violations as noncited violations (NCVs) consistent with Section 2.3.2.a 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 U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator Region II; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Turkey Point Nuclear Generating Units 3 and 4.

If you disagree with a cross-cutting aspect assignment or a finding not associated with a regulatory requirement in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for 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 Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, 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 NRCs Public Document Room or from the Publicly Available Records (PARS) component of the NRC's Agencywide Documents Access and Management 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/

Gregory J. Kolcum, Acting Chief

Reactor Projects Branch 3

Division of Reactor Projects

Docket Nos. 50-250, 50-251 License Nos. DPR-31, DPR-41

Enclosure:

Inspection Report 05000250/2013004, 05000251/2013004

w/Attachment: Supplemental Information

REGION II==

Docket Nos:

50-250, 50-251

License Nos:

DPR-31, DPR-41

Report No:

05000250/2013004, 05000251/2013004

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:

July 1, 2013 to September 30, 2013

Inspectors:

T. Hoeg, Senior Resident Inspector

M. Endress, Resident Inspector

R. Reyes, Resident Inspector (Section 4OA3)

R. Taylor, Senior Project Inspector (Sections 4OA2, 4OA3)

A. Klett, Project Manager (Section 4OA3)

W. Pursley, Health Physicist (Section 2RS1)

J. Rivera, Health Physicist (Sections 2RS1, 4OA1)

M. Riches, Project Engineer (Section 4OA5)

Approved by:

Gregory J. Kolcum, Acting Chief Reactor Projects Branch 3 Division of Reactor Projects

Enclosure

SUMMARY OF FINDINGS

IR 05000250/2013004, 05000251/2013004; 07/01/2013 - 09/30/2013; Turkey Point Nuclear

Generating Units 3 & 4; Problem Identification and Resolution, Follow-up of Events and Notice of Enforcement Discretion

The report covered a three month period of inspection by the resident inspectors, regional health physicists, and project inspectors from the region and headquarters. Five Green findings were identified including four non-cited violations. The significance of inspection findings are identified by their 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 aspects were determined using IMC 310, components Within the Cross-Cutting Areas, dated October 28, 2011. All violations of NRC requirements were dispositioned in accordance with the NRCs Enforcement Policy dated July 9, 2013. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision

Cornerstone: Initiating Events

Green: A self-revealing non-cited violation of Technical Specification 6.8.1, Procedures, was identified for the licensees failure to maintain an adequate procedure for venting the 3B steam generator feed pump (SGFP). Specifically, the licensee had failed to remove temporary instructions in Section 5.4 of procedure 3-NOP-074, Steam Generator Feedwater System, to jumper the contacts on the 3B SGFP breaker such that the breaker appeared open to the auxiliary feedwater (AFW) actuation logic, and as a result, AFW was inadvertently actuated and had to be secured by operators during a start of the 3B SGFP from the control room. The licensee entered the issue into the corrective action program as action request 1855704 and took corrective actions to revise 3-NOP-074 by removing the jumper installation steps from the procedure.

The inspectors determined that the performance deficiency was more than minor because it was associated with the procedure quality attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, the failure to remove the procedural instructions for installing a jumper in the 3B SGFP control circuit resulted in an inadvertent AFW actuation and required operators to take action to temporarily secure the ability of AFW to feed the steam generators. The inspectors determined the finding was of very low safety significance (Green) because the finding did not result in a reactor trip and a loss of mitigation equipment relied upon to transition the plant to a stable shutdown condition. The finding was associated with a cross-cutting aspect in the resources component of the human performance area because the licensee failed to ensure an accurate and up-to-date procedure was maintained for operation of the feedwater system H.2(c). (Section 4OA2)

Green: A self-revealing non-cited violation of Technical Specification 6.8.1, Procedures, was identified for the licensees failure to implement Section 2.0 of procedure 3-NOP-074, Steam Generator Feedwater System, for starting the 3A steam generator feedwater pump (SGFP).

Specifically, the licensee failed to implement 3-NOP-074 and ensure that a second condensate pump (CP) was running before starting a second SGFP which resulted in a loss of normal feedwater to the steam generators and an actuation of auxiliary feedwater (AFW). Operators took action to secure AFW flow to the steam generators to limit plant cool down and opened the reactor trip breakers to obtain additional reactivity shut down margin. Operators also took action to start the A standby steam generator feed pump (SBSGFP) to maintain level in the SGs and both trains of AFW were returned to operable standby status. The licensee entered the issue into their corrective program as action request 1856476.

The inspectors determined that the performance deficiency was more than minor because it was associated with the human performance attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, the failure to ensure that a second CP was running prior to starting 3A SGFP resulted in the trip of the running SGFP 3B and AFW actuation in response to the loss of normal feedwater supply. The inspectors determined the finding was of very low safety significance (Green) because the finding did not result in a reactor trip and a loss of mitigation equipment relied upon to transition the plant to a stable shutdown condition. The finding was associated with a cross-cutting aspect in the work practices component of the human performance area because the licensee failed to ensure proper supervisory oversight of work activities related to nuclear safety and prevent the loss of running SGFPs H.4(c). (Section 4OA2)

Green: A self-revealing finding was identified due to the licensees failure to provide adequate work instructions for throttling the Unit 3 gland seal steam bypass valve. As a result of the licensees inadequate work instructions, an operator opened the spill bypass valve on the gland seal steam system until system steam pressure dropped and allowed air in-leakage through the turbine gland seals. This resulted in a reactor trip and the main condenser was unavailable for reactor decay heat removal until vacuum could be restored. The licensee entered this issue into their corrective action program as action request 1847369 and revised the system operating procedure to address operation of the bypass line around the spillover control valve.

The inspectors determined the performance deficiency was more than minor because it was associated with the configuration control attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, the failure to provide adequate work instructions for the operation of the gland seal steam spillover bypass valve resulted in a reactor trip with the main condenser unavailable for reactor decay heat removal until vacuum could be restored. The inspectors screened the finding and determined that the finding was a transient initiator contributor which required a detailed risk analysis because the finding resulted in a reactor trip with a loss of condenser vacuum. A bounding analysis was performed by a regional Senior Reactor Analyst who concluded that the finding resulted in an increase in core damage frequency of less than 1E-6/year and, therefore, was a Green finding of very low safety significance. The finding was associated with a cross-cutting aspect in the work control component of the human performance area because the licensee did not adequately incorporate the need for planned contingencies, compensatory actions or abort criteria to ensure that throttling the gland seal steam spillover bypass valve would not result in a reactor trip and loss of the main condenser H.3(a). (Section 4OA2)

Green: The inspectors identified a self-revealing non-cited violation of the limiting condition for operation specified by Unit 3 Technical Specification (TS) 3.4.9.3, Overpressure Mitigating Systems, which occurred as a result of the licensees failure to locally verify the closed position of manual valve 3-990 in accordance with OP-AA-100-1000, Conduct of Operations. The licensees failure to locally verify the closed position of manual valve 3-990 resulted in an unisolated high pressure safety injection flow path to the RCS for eight hours and 40 minutes which was greater than the TS 3.4.9.3 allowed outage time of four hours. Compliance with the TS was restored when the licensee isolated the flow path at the completion of in-service testing on February 28, 2013. Additionally, the licensee took corrective actions to fix the reach rod assembly and revised the procedures for verifying valve position and work order planning. The issue was entered into the licensees corrective action program as action request 1852222.

The performance deficiency was more than minor because it was associated with the configuration control attribute of the initiating events cornerstone and adversely impacted the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during shutdown operations. Specifically, the performance deficiency resulted in an open high pressure flow path to the reactor coolant system that degraded the overpressure mitigating systems ability to prevent a low temperature overpressure (LTOP)event. The inspectors assessed the finding using the initiating events cornerstone and evaluated the significance of the finding using Appendix G, Shutdown Operations Significance Determination Process, of Manual Chapter 0609. The inspectors determined that the finding required a detailed risk assessment because it was associated with a non-compliance with an LTOP technical specification. A Senior Reactor Analyst in NRC headquarters determined that the risk significance of the issue was very low (i.e., Green). The dominant accident sequence was an over-pressurization event caused by an inadvertent safety injection actuation, where the power-operated relief valves fail resulting in a through wall crack of the reactor coolant system.

The finding was associated with a cross-cutting aspect in the resources component of the human performance area because the licensee failed to ensure that the work package contained adequate instructions for installation of roll pins instead of set screws in the reach rod assembly for valve 3-990 H.2(c). (Section 4OA3)

Cornerstone: Mitigating Systems

Green: A self-revealing non-cited violation of the limiting condition for operation specified by Unit 4 Technical Specification (TS) 3.4.9.3, Overpressure Mitigating System, was identified due to the inoperability of a reactor coolant system (RCS) power-operated relief valve (PORV)for longer than the TS allowed outage time (AOT) of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Specifically, the licensee failed to control the wiring configuration of the pressure comparator circuit for PORV PCV-4-456 and, as a result, the PORV would not have automatically responded to an overpressure event. The licensee corrected the wiring configuration error upon discovery and entered this issue into the corrective action program as action request 1868533.

The inspectors determined the performance deficiency was more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and adversely impacted the objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to control the wiring configuration of PCV-4-456 resulted in the PORV being unable to automatically respond to an RCS overpressure event. The inspectors assessed the finding in the mitigating systems cornerstone and evaluated the significance using Manual Chapter 0609,

Appendix G, Shutdown Operations Significance Determination Process. The inspectors determined that the finding required a detailed risk assessment because it was associated with a non-compliance with low temperature overpressure (LTOP) Technical Specifications. A Senior Reactor Analyst in NRC headquarters determined that the risk significance of the issue was very low (i.e., Green). The dominant accident sequence was an over-pressurization event caused by the pressurizer heaters, where the remaining PORV fails resulting in a through wall crack of the reactor coolant system. This finding was associated with a cross-cutting aspect in the work practices component of the human performance area because the licensee had not effectively communicated expectations regarding procedural compliance, and as a result, personnel did not implement procedural requirements to maintain plant configuration using wiring lift and land sheets; causing leads that affected the operability of PORV PCV-4-456 to not be re-landed H.4(b). (Section 4OA3)

REPORT DETAILS

Summary of Plant Status

Both Unit 3 and Unit 4 began this inspection period at 100 percent of full rated thermal power (RTP) where they remained through the end of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

==1R04 Equipment Alignment

Partial Equipment Walkdowns (Quarterly)

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.

• Auxiliary feed water (AFW) Train I while Train II was out of service (OOS)

• 3A emergency diesel generator while the 3B EDG was OOS

• 4A emergency diesel generator while the 4B EDG was OOS

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 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 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 pipe and valve room fire zone 40

• Unit 4 pipe and valve room fire zone 30

• Unit 4 component cooling water pump room fire zone 47

• 4A Battery Room zone 109

• 3A 4160 volt switchgear zone 71

b. Findings

No findings were identified.

==1R07 Heat Sink Performance

a. Inspection Scope

==

The inspectors verified heat exchanger performance monitoring and testing of the component cooling water system safety related heat exchangers for Unit 4. The licensees testing verified adequate heat transfer from the component cooling water system to the intake cooling water system. The inspectors checked that monitoring and trending of heat exchanger performance was done at an appropriate interval and that the licensee verified the operational readiness of the system should it be needed for accident mitigation. The inspectors walked down portions of the cooling systems for integrity checks and to assess operational lineup and material condition. On a routine frequency, the inspectors monitored the licensees maintenance associated with heat exchanger cleaning and fouling prevention including the 4C heat exchanger cleaning on August 5, 2013. The inspectors reviewed the following performance test results required by technical specifications.

• 4-OSP-030.4, Unit 4 A/B/C CCW Heat Exchanger Performance Test

b. Findings

No findings were identified.

==1R11 Licensed Operator Requalification Program

==

.1 Resident Inspector Quarterly Review

a. Inspection Scope

On September 16, 2013, the inspectors assessed licensed operator performance in the plant simulator during a licensed operator continuing training scenario. The training scenario was started with the unit at 100 percent power and steady state conditions.

Event simulations were accomplished using Simulator Evaluation PTN 750204300, Steam Generator Tube Rupture and Loss of Offsite Power. Operators responded to the simulation using off-normal procedures 3-ONOP-041.5, Pressurizer Control Malfunction, 3-ONOP-071.2, Steam Generator Tube Leakage, and 3-ONOP-004.2, Loss of 4kV Bus.

Emergency procedures used by the crew to safely mitigate the events included 3-EOP-E-0, Reactor Trip, 3-EOP-ES-0.1, Reactor Trip Response, and 3-EOP-E-3, RCS Cooldown and Depressurization. The inspectors specifically checked that the simulated emergency classification of Alert 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 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 shift supervisor, including ability to identify and implement appropriate technical specification actions and emergency plan classification and notification

• Crew overall performance and interactions

• Evaluators 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 performed the following focused control room observation and assessed licensed operator performance. This observation was conducted to verify operator compliance with station operating guidelines, such as use of procedures, control and manipulation of components, and communications. On September 9, 2013, the inspectors did a focused observation on Unit 4 consisting of a reactor coolant system primary water dilution per 0-OP-046, Chemical Volume Control System Boron Concentration Control. Specifically, the inspectors observed the reactor operators performing the pre job brief per 0-ADM-200, Attachment 7, Planned Reactivity Manipulations for Maintaining Steady State Plant Conditions and verified the operators complied with the applicable procedure for the evolution.

The inspectors focused on the following conduct of operations attributes as appropriate:

• Operator compliance 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

b. Findings

No findings were identified.

==1R12 Maintenance Effectiveness

a. Inspection Scope

==

The inspectors reviewed the following equipment problem, component cooling water system, and periodic evaluation report 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 licensee procedure ER-AA-100-2002, Maintenance Rule Program Administration. The inspectors 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 selected corrective maintenance activities. The inspectors verified that equipment problems were being identified and entered into the corrective action program. The inspectors used the licensees maintenance rule data base, system health reports, and the corrective action program as sources of information on tracking and resolution of issues.

• AR 01898332, 4B emergency diesel generator immersion heater malfunction

• Unit 3 component cooling water system

• Maintenance Rule (a)(3) Periodic Evaluation Report for 4/1/11 - 3/31/13

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 licensees risk assessment of four 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; 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 licensees 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 four risk assessments during the inspection period:

• 3B emergency diesel generator (EDG), 3B component cooling water heat exchanger, and the A and B standby feed water pumps out of service (OOS)

• B control room ventilation and 4B intake cooling water pump OOS

• B auxiliary feed water pump, 3C charging pump, and the 3B emergency containment cooler OOS

• C auxiliary feed water pump, 3B intake cooling water pump, and the 4B emergency diesel generator 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 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.

• AR 1888705, Intake cooling water system turbine cooling water isolation valve POV-4-4883 leaks by its seat

• AR 1894720, 3C intake cooling water pump flow low

• AR 1897667, 4B component cooling water pump casing leak

• AR 1898332, 4B emergency diesel generator immersion heater malfunction

• AR 1900652, B auxiliary feed water pump Terry turbine casing drain line check valve installed backwards

• AR 1897621, Unit 4 B steam pressure protection channel III lag time outside technical specification allowable value

b. Findings

No findings were identified.

==1R18 Plant Modifications

a. Inspection Scope

==

The inspectors reviewed the following permanent plant modifications. The inspectors reviewed the 10 CFR 50.59 screening and technical evaluation to verify that the modifications had not affected system operability or availability. The inspectors reviewed associated plant drawings and UFSAR documents impacted by the modifications 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 modifications to determine if they were installed in the field as described in the associated documents. Additionally, the inspectors verified that problems associated with modifications were being identified and entered into the licensee corrective action program.

• JPN-PTN-SECJ-93-001, Breaker Bump Covers for Unit 3/4 480 Volt MCC Cabinets and Unit 3/4 A&B EDG Governor Control Switches

• WO 38010135, Replacement of 4B EDG Engine RPM Tachometer

b. Findings

No findings were identified.

==1R19 Post Maintenance Testing

a. Inspection Scope

==

For the five 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. The inspectors reviewed the following work orders (WO):

• WO 40189040, POV-4-4883 actuator adjustment

• WO 40259466, 3C intake cooling water pump motor replacement

• WO 40251577, 4B component cooling water pump casing vent replacement

• WO 40175599, B auxiliary feed water pump Terry turbine overhaul

• WO 40248995, 4B charging pump fluid drive maintenance

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 technical specification requirements, the final safety analysis report descriptions, the licensees procedural requirements, and demonstrated the systems were capable of performing their intended safety functions for 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 normal operating status required for the system to perform its safety function. The inspectors verified that surveillance issues were documented in the CAP.

In-Service Tests:

• 3-OSP-019.1, 3B Intake Cooling Water Pump In-service Test

• 3-OSP-075.2, AFW Train II and Backup Nitrogen Test

• 0-OSP-76.6, AFW Train I and Backup Nitrogen Test

Surveillance Tests:

• 3-OSP-063.2B, Unit 3 Containment Isolation System Train B Logic Test

• 3-OSP-55.1, Emergency Containment Cooler Operational Test

Reactor Coolant System Leakage Detection Test:

• 4-OSP-041.1, Unit 4 Reactor Coolant System Leak Rate Calculation

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation

a. Inspection Scope

On August 1, 2013, the inspectors observed an emergency preparedness drill and performance of the licensees emergency response organization. The drill included a simulated Unit 3 component cooling water pump motor explosion, a high radiation condition in containment, an anticipated transient without a trip (ATWS), and fuel cladding damage, requiring a Site Area Emergency declaration and notification to State of Florida, county officials, and the NRC per licensee procedure 0-EPIP-20101, Duties of the Emergency Coordinator. The scenario progressed to the reactor failing to trip manually and a large break loss of coolant accident requiring a General Emergency declaration and an additional notification to the State of Florida and the NRC. The inspector observed the crew in the plant simulator including simulated implementation of emergency procedures and staff in the Technical Support Center (TSC) using the event classification guidelines and emergency response procedures. During the drill, the inspectors observed the simulator and TSC staff verify that emergency classification and notifications were made in accordance with the licensee emergency plan implementing procedure 0-EPIP-20101. The inspector attended the licensees post-drill critique meeting. The licensees critique items were reviewed and inspector observations were discussed with the licensee to verify that drill issues were identified and captured in the corrective action program.

b. Findings

No findings were identified.

RADIATION SAFETY

(RS)

Cornerstones: Occupational Radiation Safety and Public Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

Hazard Assessment and Instructions to Workers: During facility tours, the inspectors directly observed labeling of radioactive material and postings for radiation areas, high radiation areas (HRA)s, Locked High Radiation Areas (LHRA)s, and Very High Radiation Areas (VHRA)s established within the radiologically controlled area (RCA) of the Unit 3 (U3) and Unit 4 (U4) auxiliary buildings, and radioactive waste (radwaste) processing and storage locations. The inspectors independently measured radiation dose rates or directly observed conduct of licensee radiation surveys for selected RCA areas, including the Independent Spent Fuel Storage Installation (ISFSI). The inspectors reviewed survey records for several plant areas including surveys for alpha emitters, discrete radioactive particles, airborne radioactivity, and pre-job surveys for upcoming tasks. The inspectors also discussed changes to plant operations that could contribute to changing radiological conditions since the last inspection. For selected significant outage jobs on U4 (PTN was not in an outage at the time of the inspection), the inspectors reviewed records of pre-job briefings, radiation work permit (RWP) details, and interviewed health physics (HP) supervisors and staff to assess effectiveness of radiological control requirements for minimizing exposures to workers.

Hazard Control and Work Practices: The inspectors evaluated access barrier effectiveness for selected LHRA locations and discussed procedural guidance for LHRA and VHRA controls with HP supervisors. The inspectors reviewed implementation of controls for the storage of irradiated material within the spent fuel pool (SFP) and the radiological controls and access for the Independent Spent Fuel Storage Installation (ISFSI). Established radiological controls (including airborne controls) were evaluated for selected work performed during the U4 Refueling Cycle 27 Outage (U4R27) tasks including reactor sump and steam generator (SG) maintenance completed in March of 2013. In addition, the inspectors reviewed licensee controls for areas where dose rates could change significantly as a result of plant shutdown and refueling operations.

Through limited, direct observations and interviews with licensee staff, the inspectors evaluated occupational workers adherence to selected RWPs and HP technician proficiency in providing job coverage. Electronic dosimeter (ED) alarm set points and worker stay times were evaluated against area radiation survey results for potential HRA tasks involving significant dose rate gradients. The inspectors evaluated use and placement of whole body and extremity dosimetry to monitor worker exposure during bottom mounted instrumentation work in the reactor sump during U4R27. The inspectors also evaluated worker responses to dose and dose rate alarms during selected work activities by reviewing licensee investigation reports.

Control of Radioactive Material: The inspectors observed surveys of material and personnel being released from the RCA using small article monitor (SAM), personnel contamination monitor (PCM), and portal monitor (PM) instruments. The inspectors reviewed calibration records for selected release point survey instruments and discussed equipment sensitivity, alarm setpoints, and release program guidance with licensee staff.

The inspectors evaluated the appropriateness of radionuclide sources used for detector testing and calibration. The inspectors also reviewed records of leak tests on selected sealed sources and discussed nationally tracked source transactions with licensee staff.

Problem Identification and Resolution: The inspectors reviewed and assessed Corrective Action Program (CAP) documents associated with radiological hazard assessment and exposure control. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with PI-AA-204, Condition Identification and Screening Process, Rev. 20 and PI-AA-205, Condition Evaluation and Corrective Action, Rev 20. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results.

Radiation protection activities were evaluated against the requirements of Updated Final Safety Analysis Report (UFSAR) Section 11; Technical Specifications (TS) Sections 6.8, Procedures and Programs and 6.12, HRA; 10 CFR Parts 19 and 20; and approved licensee procedures. Licensee programs for monitoring materials and personnel released from the RCA were evaluated against 10 CFR Part 20 and IE Circular 81-07, Control of Radioactively Contaminated Material. Documents reviewed are listed in Section 2RS1 and 4OA1 of the report Attachment.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

.1 Mitigating Systems

a. Inspection Scope

The inspectors checked licensee submittals for the performance indicators (PIs) listed below for the period July 1, 2012, thru June 31, 2013, 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 reviewed operator logs, plant status reports, condition reports, licensee event 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.

• Unit 3 Safety System Functional Failures

• Unit 4 Safety System Functional Failures

b. Findings

No findings were identified.

.2 Occupational and Public Radiation Safety

a. Inspection Scope

Occupational Radiation Safety Cornerstone: The inspectors reviewed the Occupational Exposure Control Effectiveness PI results for the Occupational Radiation Safety Cornerstone from December 1, 2012, through June 30, 2013. For the assessment period, the inspectors reviewed electronic dosimeter (ED) alarm logs and selected Action Request (AR) / Condition Request (CR) documents related to controls for exposure significant areas and events. The inspectors also reviewed licensee procedural guidance for collecting and documenting PI data. Documents reviewed are listed in the Attachment.

Public Radiation Safety Cornerstone: The inspectors reviewed the Radiological Control Effluent Release Occurrences PI results for the Public Radiation Safety Cornerstone from December 1, 2012, through June 30, 2013. For the assessment period, the inspectors reviewed cumulative and projected doses to the public and ARs related to Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual issues.

The inspectors also reviewed licensee procedural guidance for collecting and documenting PI data. Documents reviewed are listed in the Attachment.

The inspectors completed two of the required samples specified in IP 71151.

b. Findings

No findings 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 action requests and by reviewing the licensees electronic action request 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 Two AFW Actuations

a. Inspection Scope

The inspectors selected the Root Cause Evaluation (RCE), AFW Actuations, for a more in-depth review of the circumstances and the corrective actions that followed. For the first event, on March 11, 2013, while Unit 3 was in operational Mode 2, in reactor startup and attempting to vent the 3B Steam Generator Feed Pump (SGFP), AFW actuated when the 3B SGFP control room switch was taken to the start position. The cause of the actuation was due to an inadequate procedure that allowed jumpers to be placed on the 3B SGFP resulting in the AFW auto-start logic being made-up upon starting 3B SGFP. There was no significant reactor coolant system cool down or loss of steam generator water level as a result of the event. There was also no reactor trip. For the second event, on March 13, 2013, while Unit 3 was in Mode 3, hot standby and attempting to vent the 3A SGFP, AFW actuated when the 3A SGFP control room switch was taken to the start position. The actuation was caused by the SGFP/CP logic sending a signal to actuate AFW when two SGFPs are running with only one CP running. There was no significant RCS cool down or loss of steam generator water level as a result of the event. The reactor was manually tripped by the operators in order to ensure enough reactivity shutdown margin remained for the corresponding RCS temperature.

The inspectors reviewed the licensees evaluation of the events 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 licensees administration of this RCE and associated corrective action reports 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

March 11, 2013 AFW Actuation Event

Introduction:

A Green self-revealing non-cited violation of Technical Specification 6.8.1, Procedures, was identified for the licensees failure to maintain an adequate procedure for venting the 3B steam generator feed pump (SGFP). Specifically, the licensee had failed to remove temporary instructions in Section 5.4 of procedure 3-NOP-074, Steam Generator Feedwater System, that required the contacts on the 3B SGFP breaker to be jumpered such that the breaker appeared open to the auxiliary feedwater (AFW)actuation logic. As a result, AFW was inadvertently actuated and had to be secured by operators during a start of the 3B SGFP from the control room.

Description:

On March 11, 2013, with Unit 3 in Mode 2, the steam generators were being fed by the standby steam generator feed pumps (SBSGFPs). Operators secured the 3A SGFP and prepared the 3B SGFP to run and feed the steam generators. Since maintenance had previously been performed on 3B SGFP during the outage, operators vented the pump using Section 5.4 of procedure 3-NOP-074, Steam Generator Feedwater System. Section 5.4 of the procedure contained instructions to install jumpers on the contacts for 3B SGFP breaker so that the breaker would appear to be open and not defeat the AFW auto-start logic. After the jumpers were installed on the 3B SGFP breaker, the 3B SGFP control room switch was taken to start and AFW inadvertently actuated. Auxiliary feedwater actuated because the control logic responded to indications of an open breaker for both 3A and 3B SGFPs with one SGFP switch in the mid-start position. The operators then took action to restore from the actuation of AFW by securing the AFW flow control valves. Auxiliary feedwater was restored to its normal operable standby status within 30 minutes of securing the AFW flow control valves. Level was maintained in the steam generators throughout the event by the running SBSGFPs and there was a negligible cool down of the reactor coolant system as a result of the AFW actuation. The instructions to install jumpers in the control circuit for the 3B SGFP were added to procedure 3-NOP-074 in September 2012 to temporarily support testing of the feedwater system during the startup of Unit 3 from its extended power uprate outage. The licensee had subsequently failed to take action to remove the procedural steps that required the installation of the jumpers after the 2012 testing was completed. The licensee entered the issue into their corrective program as action request 1855704 and took corrective action to remove the jumper installation steps from 3-NOP-074 Section 5.4.

Analysis:

The licensees failure to maintain procedure 3-NOP-074 Section 5.4 and ensure that the correct procedural steps were in place was a performance deficiency.

The inspectors screened the performance deficiency using Manual Chapter 0612, Appendix B, Issue Screening (September 7, 2012) and determined that the performance deficiency was more than minor because it was associated with the procedure quality attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, the failure to remove the procedural instructions for installing a jumper in the 3B SGFP control circuit resulted in an inadvertent AFW actuation and required operators to take action to temporarily secure the ability of AFW to feed the steam generators. The inspectors evaluated the significance of the finding using Manual Chapter 0609, Appendix A, Exhibit 1, Transient Initiators (June 19, 2012). The inspectors determined the finding was of very low safety significance (Green) because the finding did not result in a reactor trip and a loss of mitigation equipment relied upon to transition the plant to a stable shutdown condition.

The finding was associated with a cross-cutting aspect in the resources component of the human performance area because the licensee failed to ensure an accurate and up-to-date procedure was maintained for operation of the feedwater system. H.2(c)

Enforcement:

Technical Specification 6.8.1 requires that procedures required by the FPL Quality Assurance Topical Report (QATR) be maintained. The QATR includes procedures listed in Appendix A of NRC Regulatory Guide 1.33, Revision 2, dated February 1978, which lists the Feedwater System that includes feedwater pumps to the steam generators. The licensee implements this requirement using procedure 3-NOP-074, Steam Generator Feedwater System. Contrary to the above, from September 2012 until March 11, 2013, the licensee failed to maintain procedure 3-NOP-074 by removing temporary instructions to jumper the contacts for the 3B SGFP breaker, and as a result, AFW was inadvertently actuated due to the jumper installation. The licensee took action to remove the jumper installation steps from 3-NOP-074. This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy. This violation was entered into the licensees corrective action program as action request 1855704. (NCV 05000250/2013004-01, Inadequate Procedure to Vent 3B SGFP Results in AFW Actuation)

March 13, 2013 AFW Actuation Event

Introduction:

A Green self-revealing non-cited violation (NCV) of Technical Specification 6.8.1, Procedures, was identified for the licensees failure to implement Section 2.0 of procedure 3-NOP-074, Steam Generator Feedwater System, for starting the 3A steam generator feedwater pump (SGFP). Specifically, the licensee failed to ensure that a second condensate pump (CP) was running before starting a second SGFP which resulted in a loss of normal feedwater to the steam generators and an actuation of auxiliary feedwater (AFW).

Description:

On March 13, 2013, with Unit 3 in Mode 3, the 3B SGFP and the 3A CP were in operation with preparations being made to run the 3A SGFP per 3-NOP-074.

Feedwater system control logic required two running CPs to support the operation of two running SGFPs. The precautions and limitations (Section 2.0) of procedure 3-NOP-074 stated that for each running SGFP, there needs to be one running CP. Operators started the 3A SGFP (the second SGFP) to vent the pump casing and suction header through the minimum flow recirculation line without starting a second CP. The feedwater control logic then tripped the 3B SGFP and AFW actuated due to the loss of the normal feedwater supply to the steam generators. Within one minute operators took manual control of feedwater and closed all AFW flow control valves and feedwater regulating valves to limit reactor coolant system cool down. Operators then opened the reactor trip breakers via the manual reactor trip switch to obtain additional reactivity shut down margin. Operators started the 3A standby steam generator feed pump (SBSGFP) to maintain level in the steam generators and restored both trains of AFW to operable standby status. Level in the steam generators reached 38 percent and did not reach the trip set point of 16 percent. The licensee entered the issue into their corrective program as action request 1856476.

Analysis:

The licensees failure to implement procedure 3-NOP-074 and ensure that at least two CPs were running prior to starting a second SGFP was a performance deficiency. The inspectors screened the performance deficiency using Manual Chapter 0612, Appendix B, Issue Screening (September 7, 2012) and determined that the performance deficiency was more than minor because it was associated with the human performance attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, the failure to ensure that a second CP was running prior to starting 3A SGFP resulted in the trip of the running SGFP 3B and AFW actuation in response to the loss of normal feedwater supply. The inspectors evaluated the significance of the finding using Manual Chapter 0609, Appendix A, Exhibit 1, Transient Initiators (June 19, 2012). The inspectors determined the finding was of very low safety significance (Green) because the finding did not result in a reactor trip and a loss of mitigation equipment relied upon to transition the plant to a stable shutdown condition. The finding was associated with a cross-cutting aspect in the work practices component of the human performance area because the licensee failed to ensure proper supervisory oversight of work activities related to nuclear safety and prevent the loss of running SGFPs. H.4(c)

Enforcement:

Technical Specification 6.8.1 requires that procedures required by the FPL Quality Assurance Topical Report (QATR) be implemented. The QATR includes procedures listed in Appendix A of NRC Regulatory Guide 1.33, Revision 2, dated February 1978, which lists the Feedwater System that includes feedwater pumps to the steam generators. The licensee implements this requirement using procedure 3-NOP-074, Steam Generator Feedwater System, which states in its precautions and limitations that for each running SGFP, there needs to be one running CP. Contrary to the above, on March 13, 2013, operators started a second SGFP with only one CP running which resulted in a trip of the in service SGFP and actuation of AFW in response to the loss of normal feedwater supply to the steam generators. Operators took action to secure AFW flow to the steam generators to limit plant cool down and opened the reactor trip breakers to obtain additional reactivity shut down margin. Operators also took action to start the A SBSGFP to maintain level in the SGs and both trains of AFW were returned to operable standby status. This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy. This violation was entered into the licensees corrective action program as action request 1856476. (NCV 05000250/2013004-02, Failure to Follow Procedure to Switch Running SGFPs Results in AFW Actuation)

.3 Annual Sample:

Root Cause Evaluation Associated With Unit 3 Reactor Trip Due to Loss of Condenser vacuum

a. Inspection Scope

The inspectors selected the Root Cause Evaluation (RCE), Unit Reactor Trip Due to a Loss of Condenser Vacuum, for a more in-depth review of the circumstances and the corrective actions that followed. On February 11, 2013, while Unit 3 was at 99 percent reactor power, a loss of condenser vacuum occurred resulting in an automatic unplanned reactor trip. The cause of the actuation was due to an unexpected response from the gland seal steam system during operation of the associated spillover bypass valve for maintenance.

The inspectors reviewed the licensees evaluation of the events 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 licensees administration of this RCE and associated corrective action reports 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

Introduction:

A Green, self-revealing finding was identified due to the licensees failure to provide adequate work instructions for throttling the Unit 3 gland seal steam bypass valve. As a result of the licensees inadequate work instructions, an operator opened the spillover bypass valve on the gland seal steam system until system steam pressure dropped and allowed air in-leakage through the turbine gland seals. This resulted in a reactor trip and the main condenser was unavailable for reactor decay heat removal until vacuum could be restored.

Description:

On February 11, 2013, with Unit 3 operating in Mode 1 at 99 percent power, a field operator was sent to install a clearance on the Unit 3 turbine gland sealing steam spillover control valve (CV-3-3725) for maintenance. The clearance called for throttling open the normally closed Unit 3 gland seal steam spillover bypass valve (3-90-005), then closing the inlet and outlet spillover isolation valves. The clearance did not provide specific instructions on the throttle position for the Spillover Bypass Valve, which was left to skill of the craft. The control room operators directed the field operator to maintain a pressure band of 3.5 to 5 pounds per square inch gage (psig) using valve 3-90-005. This pressure band corresponded to the direction provided in system operating procedure 3-NOP-89.01, Turbine Gland Seals and High Pressure Cylinder Heating, Section 4.1.1, for placing the gland seal steam system in service under low power conditions. Procedure 3-NOP-89.01 did not provide a pressure range for the system at full power conditions. The correct gland seal steam system pressure for system conditions was later determined to be greater than 5 psig. In an attempt to achieve the 3.5 to 5 psig pressure band, the field operator throttled 3-90-005 to approximately 60 percent open. As a result, steam pressure at the gland seals on the low pressure turbines was too low to prevent air in-leakage and condenser vacuum began to lower.

Vacuum continued to lower until the condenser low vacuum turbine trip set-point was reached which caused an automatic turbine trip followed by a reactor trip. Normal reactor decay heat removal by dumping steam to the main condenser was unavailable due to the loss of condenser vacuum; however the licensee was able to control cooldown using the atmospheric dump valve until condenser vacuum could be reestablished. The licensee entered this issue into their corrective action program as action request 1847369 and conducted a root cause evaluation (RCE). The RCE determined the root cause to be ineffective operational standards; specifically the use of a clearance to direct throttling the spillover bypass valve (rather than an operating procedure) was inappropriate. The licensee also determined that operating procedure, 3-NOP-89.01, did not provide adequate direction for bypassing the spillover control valve. The licensee revised the system operating procedure to address operation of the bypass line around the spillover control valve and performed a common cause analysis (action request 1857078) to identify other potential enhancements to the sites operational standards.

Analysis:

The licensees use of inadequate work instructions to control the throttled position of the main turbine gland seal steam system was a performance deficiency.

Specifically, the licensee used the steam pressure band for startup of gland seal steam system (3 to 5 psig per 3-NOP-89.01 Section 4.1.1) in an attempt to maintain gland seal steam pressure by throttling the gland seal steam spillover bypass valve after the system had already been placed into service and the unit was operating at full power conditions. The inspectors determined the performance deficiency was more than minor using IMC 0612, Appendix B, Issue Screening (September 7, 2012), because the performance deficiency was associated with the configuration control attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, the failure to provide adequate work instructions for the operation of the gland seal steam spillover bypass valve resulted in a reactor trip with the main condenser unavailable for reactor decay heat removal until vacuum could be restored. The inspectors performed an initial screening of the finding using NRC Inspection Manual Chapter (IMC) 06 and determined that the finding was a transient initiator contributor which required evaluation using Exhibit 1, Initiating Events Screening Questions of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power (July 19, 2012). This screening determined that a detailed risk analysis was required because the finding resulted in a reactor trip with a loss of condenser vacuum. A bounding analysis was performed by a regional Senior Reactor Analyst using the NRC Turkey Point risk model. The finding was modeled as a non-recoverable loss of condenser heat sink. The dominant sequence was a turbine trip/reactor trip with loss of secondary heat removal (main condenser and main feedwater not available) followed by loss of the auxiliary feedwater system, operator failure to utilize standby steam generator feedwater and operator failure to implement feed and bleed. The availability of mitigating equipment moderated the risk. The result of the SDP risk analysis was an increase in core damage frequency of less than 1E-6/year and, therefore, was a Green finding of very low safety significance. The finding was associated with a cross-cutting aspect in the work control component of the human performance area because the licensee did not adequately incorporate the need for planned contingencies, compensatory actions or abort criteria to ensure that throttling the gland seal steam spillover bypass valve would not result in a reactor trip and loss of the main condenser H.3(a).

Enforcement:

This finding does not involve enforcement action because no violation of a regulatory requirement was identified. The licensee entered this issue into the corrective action program as AR 1847369. Because this finding does not involve a violation and is of very low safety significance, Green, it is identified as a FIN 05000250/2013004-03, Failure to Provide Adequate Instructions during Maintenance on the Gland Seal Steam System.

.4 Annual Sample Review of Operator Workarounds

a. Inspection Scope

The inspectors reviewed the licensees operator workaround (OWA) program described in Florida Power and Light fleet procedures OP-AA-108, Oversight and Control of Operator burdens and Turkey Point specific procedure ODCI-CO-040, Oversight and Control of Operator Burdens, to verify the licensee was identifying workarounds at the appropriate threshold, entering them into their corrective action program, and planning or taking appropriate corrective actions. The inspectors performed an evaluation of the potential cumulative effect of all open operator burdens.

b. Findings and Observations

No findings were identified. The inspectors determined the licensee was identifying and screening potential equipment deficiencies at an appropriate level. The deficiencies that were determined to meet a predetermined threshold based on watch stander impact were placed on an operator burden aggregate impact list maintained by the shift technical advisor (STA). The STA and operating crews routinely reviewed the list to maintain it up to date and to determine if a negative aggregate impact exists. The inspectors reviewed the list and determined a number of open operator burdens were documented including nine on Unit 3 and ten on Unit 4. The inspectors reviewed the associated operator burden screening checklists to determine completeness and accuracy. The inspectors determined that none of the equipment deficiencies on the aggregate impact lists were screened out as an operator work around classification on either unit. Two deficiencies on Unit 3 and one deficiency on Unit 4 were screened as operator challenges to non-safety related secondary plant systems. The inspectors determined there was no aggregate impact on either unit from the operator challenges and the conditions were entered in the licensee corrective action program with corrective actions being planned or scheduled to repair the deficiencies.

4OA3 Event Follow-up

Inspection Scope

Using IP 71153, inspectors followed up on the following licensee event reports (LERs) to evaluate licensee performance related to the events, the accuracy of the LERs, and the appropriateness of corrective actions. Inspectors conducted walk-downs of affected equipment, in-office reviews of corrective action, modification, and design documents, and interviewed personnel from the licensees operations, design, and licensing departments. The inspectors evaluated the licensees compliance with its operating license and applicable regulations.

.1 (Closed) LER 05000250/2013-006-00, Reactor Protection and Auxiliary Feed Water

System Actuations

On March 13, 2013, with Unit 3 in mode 3, the AFW system actuated while attempting to vent 3A SGFP. In order to facilitate planned work on SGFP power supplies, feed water supply was to be swapped from the operating 3B SGFP to the 3A SGFP. With the 3A condensate pump (CP) and 3B SGFP running, the 3A SGFP was started for a one minute run to fully vent the suction header and pump casing. Once the 3A SGFP was taken to START, the operating 3B SGFP tripped causing AFW to actuate. The 3B SGFP tripped because the SGFP protection logic ensures that at least two CPs are operating when two SGFPs are operating. AFW actuated because of the trip of the operating 3B SGFP which was aligned to the SGs. The AFW actuation added cooler water into the SGs reducing RCS temperature. Operators opened the reactor trip breakers via the manual reactor trip switch to obtain additional shutdown margin.

Operators started 3A SBSGFP to maintain level in the SGs. The licensees root cause analysis is documented in AR 01856476. The inspectors determined that the finding constitutes a violation of very low safety significance and the enforcement aspects are discussed in Section 4OA2 of this report. This LER is closed.

.2 (Closed) LER 05000250/2013-002-00, Automatic Reactor Trip Due to Low Condenser

Vacuum

The LER documented that on February 11, 2013, while Unit 3 was operating at 99 percent power an unplanned automatic reactor trip occurred while gland sealing steam spillover bypass valve was being throttled in preparation for calibration of the actuator.

The licensee determined the cause of the trip to be ineffective implementation of operational standards, as demonstrated by improper monitoring of plant parameters during manipulation of the spillover bypass valve and utilizing an equipment clearance in lieu of an operating procedure when bypassing the gland seal spillover valve. A contributing cause was determined to be poor execution of the work order screening process. Corrective actions included; the revision of NOP-89.01, Turbine Gland Seals and High Pressure Cylinder Heating (to include guidance for bypassing spillover valves), enhancement of operational standards under the licensees Operations Step Change Plan and corrective action program action request 01857078. The inspectors reviewed the LER and the root cause evaluation (action request 1847369) documenting this event. The inspectors determined that this event was associated with a finding of very low safety significance. The enforcement aspects of this event are discussed in Section 4OA2 of this report. This LER is closed.

.3 (Closed) LER 05000250/2013-005-00, Reactor trip Due to Turbine Header Pressure

Spike While Testing Turbine Control Valves

On March 3, 2013, at 1431, Unit 3 experienced an automatic reactor trip from approximately 3 percent power. The turbine was offline and undergoing testing following

1. 3 Turbine Control Valve (TCV) position indication repair. Post-maintenance testing and calibration was being performed on the newly installed valve position indicator while the # 3 control valve was incrementally exercised from fully closed to fully open. During the final checks of the testing, the #3 TCV was being opened from full closed to full open when turbine 1st stage pressure on PT-3-477 spiked high causing indicated turbine power to exceed the P-7 set point (10 percent power) which enabled the At Power Trips on the Reactor Protection System (RPS). With an input into RPS for the turbine trip (i.e., 2/2 turbine stop valves closed) already met and the P-7 interlock satisfied, the RPS logic to actuated and caused the reactor trip.

The licensees analysis, which was documented in action request (AR) 1856035, identified the root cause to be a failure to recognize the risk associated with TCV testing to cause a pressure transient of sufficient magnitude to cause a reactor trip while cycling the #3 TCV. The licensees actions to address this event include the following procedure changes for both units: NOP-089.01, Turbine Gland Seals and High Pressure Cylinder Heating, to allow testing of the control valves with requirements that the main steam isolation valves be closed when TCV testing in Mode 2 or Mode 3; 0-ADM-737, Post-Maintenance Testing Procedure, to ensure that the main steam header is depressurized prior to cycling the TCV; added precautions to GOP-301, Hot Standby to Power Operations, to identify that TCV testing can lead to pressure spikes and reactor trip if P-7 is enabled with turbine loaded and reactor trip breakers closed. The inspector determined that the event did not challenge critical safety functions during power operations; therefore, this event was of minor significance in accordance with NRC Manual Chapter 0612. The LER is closed.

.4 (Closed) LER 05000251/2013-001-00, Power Operated Relief Valve Inoperable for

Greater Than Allowed Outage Time Due to Lifted Leads

On March 10, 2013, while Unit 4 was in Mode 5, the overpressure mitigating system (OMS) was placed in service. On March 23 the licensee identified two leads in an equipment rack that were lifted and taped. The leads supplied a pressure comparator circuit which provided control power to a power operated relief valve (PORV) that was required for operability in Mode 5, and on March 24, the licensee re-landed the leads.

As a result of the lifted leads one PORV had been inoperable for longer than the Technical Specification (TS) allowed outage time (AOT).

a. Inspection Scope

In addition to reviewing the LER, the inspectors reviewed the licensees root cause evaluation (RCE), Unit 4 technical specifications, and the plant procedures governing configuration control. The inspectors verified the timeline of events associated with the LER and the immediate and subsequent corrective actions taken by the licensee to address the issue.

b. Findings

Introduction:

A Green, self-revealing, non-cited violation of the limiting condition for operation specified by Unit 4 Technical Specification (TS) 3.4.9.3, Overpressure Mitigating System, was identified due to the inoperability of a reactor coolant system (RCS) power-operated relief valve (PORV) for longer than the TS allowed outage time (AOT) of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Specifically, the licensee failed to control the wiring configuration of the pressure comparator circuit for PORV PCV-4-456 and, as a result, the PORV would not have automatically responded to an overpressure event.

Description:

During the Unit 4 extended power uprate outage, the licensee modified the main feed water (MFW) regulating valves which required work in control room equipment racks 4QR6, 4QR7 and 4QR8. On February 23, 2013, the H1 and N1 wiring leads at terminals 11 and 12 in equipment rack 4QR6 were lifted to support the modifications.

The lifted leads de-energized the pressure comparator circuit (PC-4-403A) that provided control power to PORV PCV-4-456 and rendered the valve inoperable. The RCS was being maintained depressurized via an RCS vent and the PORVs were not required by TS to be operable at that time.

On March 10, 2013, while Unit 4 was in Mode 5, the RCS vent path was secured. With the RCS vent path secured TS 3.4.9.3 required two operable PORVs to meet the limiting condition for operation (LCO). Due to the lifted wiring leads in rack 4QR6, PCV-4-456 would not have been able to automatically respond to an RCS overpressure event and, therefore, the TS 3.4.9.3 LCO was not met. On March 23, 2013, while the residual heat removal (RHR) interlocks were being restored in preparation for entering Mode 4, MOV-4-750, started to close. An operator stationed at the breaker for MOV-4-750 noticed the valve starting to close and immediately opened the breaker. The operators verified residual heat removal pump amperes and flow rate were stable and entered the issue into the corrective action program as action request 1868533. While conducting the investigation to determine the reason RHR loop suction valve received a signal to close, the licensee found the H1 and N1 lifted leads in equipment rack 4QR6. On March 24, 2013, the lifted leads were re-landed by the licensee. The licensee performed a prompt operability determination which revealed that the lifted leads enabled the auto-closure interlocks on MOV-4-750 and also removed power to the pressure comparator circuit which in turn provided control power to PORV PCV-4-456. Consequently, the lifted leads caused PCV-4-456 to be inoperable.

The licensee also determined that neither the modification documents nor the implementing work orders provided instructions for the lifting of leads in equipment racks 4QR6, 4QR7 or 4QR8. Licensee procedure 0-ADM-747, Maintenance Alteration Process, describes the requirements to ensure configuration control when the alterations are not controlled by other approved procedures or the work control process.

This procedure specifically describes the required controls for lifting and landing leads on daisy-chained power circuits as was the case for wiring leads H1 and N1. The licensees investigation identified that the use of lift and land sheets to control wiring configuration as required by 0-ADM-747 had not been implemented during the modification work in equipment racks 4QR6, 4QR7 and 4QR8. The licensee concluded there was inadequate procedure compliance by personnel performing the work which resulted in the lifted leads not being re-landed. The licensee did not identify any other safety-related equipment, other than PCV-4-456, that had been adversely affected by the failure to implement the requirements of 0-ADM-747.

Analysis:

The failure to use lift and land sheets as required by 0-ADM-747, Maintenance Alteration Process, to control the wiring configuration of PORV PCV-4-456 was a performance deficiency that resulted in the valves inoperability. The inspectors determined the performance deficiency was more than minor using IMC 0612, Appendix B, Issue Screening (September 7, 2012), because it was associated with the equipment performance attribute of the mitigating systems cornerstone and adversely impacted the objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to control the wiring configuration of PCV-4-456 resulted in the PORV being unable to respond automatically to an RCS overpressure event. The inspectors assessed the finding using the mitigating systems cornerstone in Table 2 of Manual Chapter 0609.04, Significance Determination Process Initial Characterization of Findings (June 19, 2012). The inspectors evaluated the significance of the finding using Checklist 2 in Attachment 1 of Appendix G, Shutdown Operations Significance Determination Process, (February 28, 2005) of Manual Chapter 0609. The inspectors determined that the finding required a detailed risk assessment because it was associated with a non-compliance with a low temperature over-pressure (LTOP) Technical Specification. A Senior Reactor Analyst in NRC headquarters performed a detailed risk evaluation of the issue as they had the requisite expertise to analyze a shutdown condition. The analyst determined that the risk significance of the issue was very low (i.e., Green). The dominant accident sequence was an over-pressurization event caused by the pressurizer heaters, where the remaining PORV fails resulting in a through wall crack of the reactor coolant system.

This finding was associated with a cross-cutting aspect in the work practices component of the human performance area because the licensee had not effectively communicated expectations regarding procedural compliance, and as a result, personnel did not implement requirements to maintain plant configuration using wiring lift and land sheets; causing leads that affected the operability of PORV PCV-4-456 to not be re-landed

H.4(b).

Enforcement:

The Unit 4 LCO for TS 3.4.9.3 requires in part (during Modes 4, 5 and 6)that two PORVs be operable if the RCS is not being maintained depressurized by an RCS vent path. Required action c of the TS states that with one PORV inoperable in Modes 5 or 6 with the reactor vessel head on, either; 1) restore the inoperable PORV to operable status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; 2) complete depressurization and venting of the RCS through at least a 2.2 square inch vent within a total of 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br />; or 3) complete depressurization and venting of the RCS through at least one open PORV and associated block valve within a total of 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br />. Contrary to the above, from March 10 to March 24, 2013, with Unit 4 in Mode 5, the reactor vessel head in place and PORV PCV-4-456 inoperable; the licensee failed to satisfy the requirements of TS 3.4.9.3 LCO for a period of 14 days, which was longer than the AOT of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, as a result of lifted leads in the PCV-4-456 pressure comparator circuit that rendered the PORV inoperable.

On discovery, the licensee took corrective action to meet the LCO by re-landing the two wiring leads which returned PORV PCV-4-456 to an operable status. This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy. This violation was entered into the licensees corrective action program as action request 1868533. (NCV 05000251/2013004-04, Power Operated Relief Valve Inoperable for Greater Than Allowed Outage Time Due to Lifted Leads)

.5 (Closed) LER 05000250/2013-004-00, Safety Injection Path Not Isolated Due to Manual

Valve Out of Position

On April 29, 2013, the licensee submitted LER 2013-004-00 (ADAMS Accession No. ML13128A312) to the NRC for an event that occurred on February 27, 2013, which resulted in a condition prohibited by the Technical Specifications (TSs). On February 27 and 28, 2013, with Unit 3 in Mode 5, the licensee performed in-service testing (IST) on motor-operated valves (MOVs) in the reactor coolant system (RCS) hot leg safety injection lines. These safety injection flow paths were believed to be isolated. However, when stroking the MOVs, the licensee observed pressurizer level increases. Further investigation after the MOV testing was completed revealed that a manual valve (Valve 3-990) upstream of the MOVs was not closed after maintenance performed on the valve on February 25, 2013, because of failures in the reach rod assembly, which is an extension of the valve operator that allows remote valve operation.

a. Inspection Scope

During the week of July 29, 2013, inspectors followed up on this LER. The inspectors reviewed the licensees root cause evaluation (action request 1852222) for this event.

The licensees root cause stated that the direct cause of the event was that the reach rod for the Valve 3-990 was installed incorrectly. Two of the required roll pins were missing, which caused the reach rod failure during valve cycling. The licensees corrective actions included: fixing the reach rod, updating operations procedures for determining valve indication, updating procedure QI-3-PTN-1, updating the work order planning process to add verifications for reach rod connections, and initiating work requests to ensure that reach rods for other valves are inspected for missing pins.

b. Findings

Introduction:

The inspectors identified a Green, self-revealing, non-cited violation of the limiting condition for operation (LCO) specified by Unit 3 Technical Specification (TS)3.4.9.3, Overpressure Mitigating Systems, which occurred as a result of the licensees failure to locally verify the closed position of manual valve 3-990. The licensees failure to locally verify the closed position of manual valve 3-990 resulted in an unisolated high pressure safety injection flow path to the RCS for eight hours and 40 minutes which was greater than the TS 3.4.9.3 allowed outage time (AOT) of four hours.

Description:

Valve 3-990 is a manual gate valve in the Unit 3 RCS piping between the high head safety injection pumps and the RCS hot legs. The valve was installed with a reach rod attached to the valve operator to allow operators to operate the valve remotely from the roof of the auxiliary building. During installation of the reach rod assembly in 2012, the licensee used set screws instead of installing the roll pins provided by the vendor at two connection points along the reach rod assembly. Without the roll pins in place, the ability of the reach rod assembly to transmit the torque necessary to open and close the valve was degraded. From February 23 - 25, 2013, the licensee performed maintenance on valve 3-990. As part of the post-maintenance testing, two operators were assigned to cycle the valve, with one operator stationed on the auxiliary building roof at the remote operator and the other operator stationed locally at the valve.

However, the locally stationed operator left the valve area prior to completion of the final required valve closure operation. It was at this point that the reach rod set screws slipped and failed to transmit the necessary torque to close the valve. As a result, valve 3-990 was inadvertently left in the open position by the licensee following the completion of maintenance on February 25, 2013. Licensee procedure OP-AA-100-1000, Conduct of Operations, Attachment 6, Equipment Manipulation and Status, Section 3.0, Expectations, step 17, requires the position of valves operated remotely via remote operators (e.g. chain operators, reach rods, etc.) to have their position verified locally following operation.

On February 27 and 28, 2013, with Unit 3 in Mode 5, the licensee performed in-service testing (IST) of the hot leg safety injection valves, MOV-3-866A and -866B, located downstream of Valve 3-990. At 5:50 pm on February 27, 2013, the MOVs were energized. With the MOVs electrically energized and valve 3-990 not closed, the hot leg safety injection flow path was no longer isolated per the requirements of the LCO for TS 3.4.9.3. During Modes 4, 5 and 6, the LCO for TS 3.4.9.3, Overpressure Mitigating Systems, requires the high pressure safety injection flow paths to the RCS to be isolated by either closed valves with the power removed or by locked closed manual valves. If the LCO cannot be met, the required actions are to restore isolation of these flow paths within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The hot leg safety injection flow paths (including valve 3-990) were believed to be isolated. However, during the stroking of MOV-3-866A pressurizer level increased approximately 0.6 percent. The licensee initially misdiagnosed the cause of the pressurizer level increase and continued with the test. An increase of 0.3 percent in pressurizer level was observed during the stroking of MOV-3-886B. Following completion of IST, the MOVs were closed and power was removed at 2:30 am on February 28, 2013, at which point the licensee was once again in compliance with the LCO for TS 3.4.9.3. The total time that Unit 3 was not in compliance with the LCO was 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and 40 minutes. The licensee entered this issue into the corrective action program as action request 1852222.

Analysis:

The licensees failure to locally verify the closed position of manual valve 3-990 as required by OP-AA-100-1000, Conduct of Operations, was a performance deficiency. This resulted in the licensee failing to satisfy the requirements of the LCO for TS 3.4.9.3, which requires the high pressure safety injection flow paths to the RCS to be isolated or else restore isolation of these flow paths within four hours. The performance deficiency was more than minor because it was associated with the configuration control attribute of the initiating events cornerstone and adversely impacted the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during shutdown operations. Specifically, the performance deficiency resulted in an open high pressure flow path to the RCS that degraded the overpressure mitigating systems ability to prevent a low temperature overpressure (LTOP) event. The inspectors assessed the finding using the initiating events cornerstone in Table 2 of Manual Chapter 0609.04, Significance Determination Process Initial Characterization of Findings (June 19, 2012). The inspectors evaluated the significance of the finding using Checklist 2 of Attachment 1 (May 25, 2004) to Appendix G, Shutdown Operations Significance Determination Process, (February 28, 2005) of Manual Chapter 0609. The inspectors determined that the finding required a detailed risk assessment because it was associated with a non-compliance with a low temperature over-pressure (LTOP)technical specification. A Senior Reactor Analyst in NRC headquarters performed a detailed risk evaluation of the issue as they had the requisite expertise to analyze a shutdown condition. The analyst determined that the risk significance of the issue was very low (i.e., Green). The dominant accident sequence was an over-pressurization event caused by an inadvertent safety injection actuation, where the power-operated relief valves fail resulting in a through wall crack of the reactor coolant system. The finding was associated with a cross-cutting aspect in the resources component of the human performance area because the licensee failed to ensure that the work package contained adequate instructions for installation of roll pins instead of set screws in the reach rod assembly for valve 3-990 H.2(c).

Enforcement:

The LCO for TS 3.4.9.3 requires, in part, that the high pressure safety injection flow paths to the RCS to be isolated or else restore isolation of these flow paths within four hours. Contrary to this requirement, the licensee failed to meet the LCO as a result of the licensees failure to isolate the hot leg safety injection flow path through manual valve 3-990 to the RCS for a period of approximately eight hours and 40 minutes during performance of IST on February 27 and 28, 2013. The licensee restored compliance with the LCO once the MOVs were closed and de-energized at the completion of testing on February 28, 2013. Additionally, the licensee fixed the reach rod assembly and revised the procedures for verifying valve position and work order planning. This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy. This violation was entered into the licensees corrective action program as action request 1852222. (NCV 05000250/2013004-05, Safety Injection Flow Path Not Isolated Due to Manual Valve Out of Position)

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 and inspection activities.

b. Findings

No findings were identified.

.2 Independent Spent Fuel Storage Facility (ISFSI) Walk down (IP 60855.1)

a. Inspection Scope

On September 6, 2013, the inspector conducted a walk down of the ISFSI controlled access fenced-in cask 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 and security access controls to the ISFSI area to be satisfactory.

b. Findings

No findings were identified.

.3 Completion of Inspection Activity associated with Inspection Procedure (IP) 71004,

Power Uprate

All inspection samples have been completed for the extended power uprates (EPUs) on Units 3 and 4 as required by IP 71004, Power Uprate. A table in the Attachment to this report summarizes the samples that were inspected during the EPU project for each unit. The table is organized by the inspection procedure used to conduct the inspection activities and identifies the inspection reports where the samples are documented as well as the applicable units.

.4 Review of Institute of Nuclear Power Operations (INPO) Evaluation Report

The inspectors reviewed the INPO evaluation report for an evaluation performed during the weeks of September 17 and September 24, 2012. The inspectors reviewed the report to ensure that issues identified were consistent with the NRC perspectives of licensee performance and to verify if any significant safety issues were identified that required further NRC follow-up.

4OA6 Meetings

Exit Meeting Summary

The resident inspectors presented the inspection results to Mr. Kiley and other members of licensee management on October 10, 2013. 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.

ATTACHMENT: SUPPPLEMENTAL INFORMATION KEY POINTS OF CONTACT

Licensee personnel:

F. Banks, Quality Manager H. Cameron, Operations C. Cashwell, Radiation Protection Manager T. Conboy, Plant General Manager P. Czaya, Licensing C. Domingos, Engineering Director M. Epstein, Emergency Preparedness Manager J. Garcia, Engineering Director A. Katz, Maintenance Manager M. Kiley, Site Vice-President S. Mihalakea, Licensing N. Rios, Chemistry Manager D. Sluzka, Work Controls Manager R. Smith, Engineering B. Stamp, Training Manager R. Tomonto, Licensing Manager M. Wayland, Operations Director T. Wall, Operations

NRC personnel:

G. Kolcum, Acting Chief, Division of Reactor Projects J. Hanna, Senior Reactor Analyst, Division of Reactor Projects G. MacDonald, Senior Reactor Analyst, Division of Reactor Projects S. Sandal, Senior Project Engineer, Division of Reactor Projects

LIST OF ITEMS OPENED, CLOSED AND DISCUSSED

Opened and Closed 05000250/2013004-01 NCV Inadequate Procedure to Vent 3B SGFP Results in AFW Actuation (Section 4OA2.2)05000250/2013004-02 NCV Failure to Follow Procedure to Switch Running SGFPs Results in AFW Actuation (Section 4OA2.2)05000250/2013004-03 FIN Failure to Provide Adequate Instructions during Maintenance on the Gland Seal Steam System (Section 4OA2.3)05000251/2013004-04 NCV Power Operated Relief Valve Inoperable for Greater Than Allowed Outage Time Due to Lifted Leads (Section 4OA3.4)05000250/2013004-05 NCV Safety Injection Flow Path Not Isolated Due to Manual Valve Out of Position (Section 4OA3.5)

Closed

05000250/2013-002-00 LER

Automatic Trip Due to Low Condenser

Vacuum (Section 4OA3.2)

05000250/2013-004-00 LER

Safety Injection Flow Path Not Isolated

Due to Manual Valve Out of Position

(Section 4OA3.5)

05000250/2013-005-00 LER

Reactor Trip Due to Turbine Header

Pressure Spike While Testing Turbine

Control Valves (Section 4OA3.3)

05000250/2013-006-00 LER

Reactor Protection and Auxiliary

Feedwater System Actuations Due to

Trip of Operating Feedwater Pump

(Section 4OA3.1)

05000251/2013-001-00 LER

Power Operated Relief Valve Inoperable

for Greater Than Allowed Outage Time

Due to Lifted Leads (Section 4OA3.4)

LIST OF

DOCUMENTS REVIEWED

Action Requests

01828950

01829809

01832367

01833518

01834147

01837814

01838924

01842537

01852222

01852229

01852456

01852876

01854517

01855081

01858018

01870215

01893814

01893895

01894629

01899148

01899243

01899679

01899679

01899851

01904623

01904758

01904887

01900375

01900486

01902040

01903140

01903178

01907623

01907650

01907659

01908701

01908857

01909041

01909047

01909069

01834334

01843974

01846151

01846886

01850426

01850785

01851121

01851969

01883607

01885198

01888974

01889026

01889155

01891590

01891814

01892325

01895614

01894175

01894720

01895339

01895488

01897667

01897692

01899098

01905083

01905090

01905281

01905382

01907450

01907457

01907462

01907604

Section 1R04: Equipment Alignment

4-OP-023, Emergency Diesel Generator

Section 1R05: Fire Protection

0-ONOP-016.10, Pre-Fire Plan Guidelines and Safe Shutdown Manual Actions

0-SME-104.01, Self-Contained, Battery Powered, Emergency Lighting Quarterly

Performance Test, Rev. 4

0-SME-104.2, Self-Contained, Battery Powered, Emergency Lighting Performance Test,

Rev. 6

WO 40168637, Test Smoke Detector Circuits, 12/16/12

Section 1R12: Maintenance Effectiveness

SAQH-01863440, Maintenance Rule (a)(3) Periodic Assessment, 8/14/13

Unit 3 System Health Report for Component Cooling Water System

Section 1R15: Operability Evaluations

EN-AA-203-1001, Operability Determinations and Assessments

0-ADM-226, Operability Screening for Condition Reports

Section 1R18: Plant Modifications

MRA 38010135-02, EDG Tachometer SPE-4-3406B Mounting Instructions, 1/22/09

4-PME-023.2, Emergency Diesel Generator Electrical Maintenance

ENG-QI-1.0, Design Control

ENG-QI-4.5, Specifications

JPN-PTN-SECJ-93-001, Engineering Evaluation for Specification SPEC-C-013, 11/15/01

SPEC-C-013-39000773, Request for Specification Clarification for Unit 3/4 A&B EDG

Governor Control Switch Protective Covers, 1/13/09

SPEC-C-013-39017463, Request for Specification Clarification for Installation of Alternate

Plexiglas handle covers for 480V MCC, 7/13/09

WO 39000773, Fabricate and Install Protective Cover for EDG Governor Control Switches,

3/9/09

WO 94007897, Fabricate and Install Bump Covers, 4/11/94

WO 94007888, Fabricate and Install Bump Covers, 4/11/94

WO 94007891, Fabricate and Install Bump Covers, 4/11/94

Section 2RS01: Radiological Hazard Assessment and Exposure Controls

Procedures and Guidance Documents

0-ADM-023, Inventory Control and Accounting of Radioactive Sources, Rev. 2

0-HPA-001, Radiation Work Permit Initiation and Termination, Rev. 3

0-ADM-600, Radiation Protection Manual, Rev. 1

0-ADM-605, Control of Radioactive Material, Rev. 1

RP-SR-100-1002, Radiation Worker Instruction and Guideline, Rev 5

0-HPS-021.3, Identification, Survey, and Release of Material for Unrestricted Use, Rev. 5

0-HPS-023, Environmental Radiation Monitoring, Rev. 0A

RP-TP-102-1000, Alpha Monitoring, Rev 0

RP-SR-103-1001, Posting Requirements for Radiological Hazards, Rev. 5

RP-SR-103-1002, High Radiation Area Controls, Rev. 2

RP-TP-103-1002, High Radiation Area Controls, Rev 2

RP-TP-103-3001, ISFSI Radiological Controls, Rev 3

RP-TP-103-1001, Posting Requirements for Radiological Hazards, Rev 1A

RP-TP-107-1001, Storage of Highly Radioactive Material in the Reactor Cavity or Spent Fuel

Pool, Rev. 1

RP-TP-102-1002, Hard to Detect Radionuclides and Contamination Controls, Rev 1

Records and Data Reviewed

Quick Hit Self-Assessment Report #01833337, Radiological Work Practices, 06/12/13

Quick Hit Self-Assessment Report #01847911, 2012 Respiratory Protection Program Annual

Review, 02/28/13

Quick Hit Self-Assessment Report #01858186-01, SOER01-1 Unplanned Radiation Exposures

from Highly Radioactive In-Core Components, 03/27/13

Non-outage Very High Radiation (VHRA) & Locked High Radiation Area (LHRA) Locations 2013

Locked High Radiation Area (LHRA) Lock Check Log, 06/12/2013

Radiation Protection Work Plan 13-001, Guidelines for Performing Unit 4 Power Ascension

Surveys at EPU Conditions, Rev 0, 05/06/2013.

EC 250312, 72.212 Evaluation Report for the Turkey Point Nuclear Plant ISFSI Units 3 and 4,

Rev 0

Appendix A to Certificate of Compliance No. 1030, NUHOMS HD System Generic Technical

Specifications, Amendment 1.

Turkey Point Nuclear Oversight Report, PTN-13-006-ISFSI Audit, 06/25/13

2013 NSTS Annual Inventory Reconciliation, Dated 01/17/2013

Radioactive Source Leak Test Results, Dated 04/26/2013

PTN 2012 Environmental and Radiation Controlled Area Radiation Level Results Log

HP 44:54.1 Log #13-5395, U4 Equip Hatch Survey 06/23/2013

HP 44:54.1 Log #13-5389, U4 Equip Hatch Survey 06/26/2013

HP 48:92.12 Log #13-1725, ISFSI Installation Pad Survey 01/31/2013

HP 46:92.12 Log #12-10008, ISFSI Installation Pad Survey 09/19/2012

HP 48:92.12 ISFSI Installation Pad Survey 03/04/2013

Standard Map Survey Report (SMSR) PTN-M-20130719-11, U3 Charging Pump Room,

07/19/2013

SMSR PTN-M-20130711-2, Change out 3A SWI Filter, 07/11/2013

SMSR PTN-M-20130727-8, Aux Bldg 4 & 2 Elevations, 08/02/2013

SMSR PTN-M-20130614-4, North Filling Room, 06/14/2013

SMSR PTN-M-20130711-7, North Filling Room Monthly, 07/17/2013

SMSR PTN-M-20130622-2, DSW Weekly, 07/01/2013

SMSR PTN-M-20130622-2, DSW Weekly, 07/01/2013

Air Calculation Sheet, (ACS) A/S Log Ref No. P0-13-3209, RWST Waste Tent, Dated

07/05/2013

ACS, A/S Log Ref No. P0-13-1310, RWST Waste Tent, Dated 07/05/2013

ACS, A/S Log Ref No. P0-13-3225, U3 Charging Pump Room Boundary, Dated 07/11/2013

ACS, A/S Log Ref No. P0-13-3224, Change Out 3A SWI Filter, Dated 07/11/2013

ACS, A/S Log Ref No. P0-13-3242, U4 CPR I/S SWI Filter Cubicle, Dated 07/25/2013

RWP No. 13-0006, Charging Pump Work, Rev 1

RWP No. 13-0007, Filter Changeouts, Rev 1

RWP No. 13-0008, Locked High Radiation Area Work, Rev 0

RWP No. 13-0030, U4 Auxiliary Bldg Post EPU Outage Power Ascension RP Surveys, Rev 0

RWP No. 12-4023, Reactor Sump - Legacy Boron Cleaning and Repairs, Task 1 - Reactor

Sump Outside/Topside Support, Rev. 7

RWP No. 12-4023, Reactor Sump - Legacy Boron Cleaning and Repairs, Task 2 - Reactor

Sump Liner Inspections-Eng/ISI, Rev. 7

RWP No. 12-4023, Reactor Sump - Legacy Boron Cleaning and Repairs, Task 3 - Reactor

Sump Water Cleaning - Pressure Washing and Setup, Rev. 7

RWP No. 12-4023, Reactor Sump - Legacy Boron Cleaning and Repairs, Task 4 - Reactor

Sump Under Vessel Surface Prepping, Sponge Blasting and Support Work, Rev. 7

RWP No. 12-4023, Reactor Sump - Legacy Boron Cleaning and Repairs, Task 5 - Reactor

Sump Under Vessel Coatings and Support Work, Rev. 7

RWP No. 12-4023, Reactor Sump - Legacy Boron Cleaning and Repairs, Task 6 - Reactor

Sump Overhead Under Vessel Coatings on Scaffolding and Support Work, Rev. 7

RWP No. 12-4023, Reactor Sump - Legacy Boron Cleaning and Repairs, Task 7 - Reactor

Sump Outside/Topside Sump Support - Bladder Installation, Removal in Hot/Cold Leg

Penetrations and Support Work, Rev. 7

Section 4OA1: PI Verification

Procedures and Guidance Documents

0-ADM-032, NRC Performance Indicators Turkey Point, Rev. 4A

Records and Data Reviewed

0-NCOP-006, Gas Gamma Beta Dose Summary Sheet, January 2012 through December 2012

0-NCOP-006, Gas Gamma Beta Dose Summary Sheet, January 2013 through June 2013

0-NCOP-006, Iodine Dose Summary Sheet, December 2012

0-NCOP-006, Iodine Dose Summary Sheet, June 2013

0-NCOP-006, Liquid Dose Summary Sheet, January 2012 through December 2012

0-NCOP-006, Liquid Dose Summary Sheet, January 2013 through June 2013

Liquid Dose Summary (By Organ), 4th Quarter 2012

Liquid Dose Summary (By Organ), 1st Quarter 2013

Liquid Dose Summary (By Organ), 2nd Quarter 2013

Liquid Dose Summary (By Organ), July 2013

Summation Table 5, Annual Radioactive Effluent Release Report, Doses Due To Iodine,

Tritium, Particulates, and Noble Gases, January 2012 through December 2012

Section 4OA3: License Event Reports

RCE/AR1852222

LER-2013-004-00

MDI-701.1, Maintenance Department Instructions for PWO Planning and Assembly of Work

Packages, Revision 7

PI-AA-100-1005, Root Cause Analysis, Revision 7

0-ADM-737, Post Maintenance Testing, Revision 9

OP-AA-100-1000, Conduct of Operations, Revision 10

ODI-CO-018, Valve Manipulation Expectations, Revisions 9/2/8 and 7/30/13

QI-3-PTN-1, Design Control, Revision 13

3-OSP-206.1, Inservice Valve Testing - Cold Shutdown, Revisions 5 and 6

TI-09-143-01, Hot Leg Injection Alternative Flow Path-MOV-3-869 single point vulnerability,

Revision 0

EC-247012, PCM-09143 Modifications to the Normal Hot Leg Recirculation Flowpath for

Extended Power Uprate, Revision 8

Work Orders 40069461-08, 40217784-01 and -02, 40219321-01 and -03,

Work Requests 94072965, 94072966, 94072967

EXTENDED POWER UPRATE (EPU) INSPECTION SUMMARY

Inspection

Procedure

Sample

Inspection Report

(ML Number)

U-3,

U-4,

Both

49001

Reviewed Erosion Corrosion and Flow-accelerated

Corrosion controls for the following:

Unit 3 High pressure extraction steam system

Unit 4 Feedwater heater drains system

Integrated

Inspection Report

05000250/2012003,

05000251/2012003

(ML12213A232)

Both

71004

Reviewed the following sections of the safety

evaluation report (SER):

2.2.4, Safety-related Valves and Pumps

2.3.2, Electrical - Offsite

2.3.3, Electrical - AC Onsite Power System

2.4.1, Reactor Protection, Safety System

Actuation, and Control Systems

2.5.1.4, Fire Protection

2.6.5, Containment Heat Removal

2.7.3, Control Room Area Ventilation

Both

Reviewed the following sections of the SER:

Section 4.0, Regulatory Commitments

Section 5.0, Recommended Areas of Inspection

Both

Observed power ascension activities.

Integrated

Inspection Report

05000250/2012005,

05000251/2012005

(ML13030A208)

U-3

Inspection

Procedure

Sample

Inspection Report

(ML Number)

U-3,

U-4,

Both

71111.04

Conducted a walkdown of the following system:

Sodium tetraborate (NaTB) basket system

Integrated

Inspection Report

05000250/2012003,

05000251/2012003

(ML12213A232)

U-3

71111.11

Conducted simulator training evaluations of accident

scenarios at EPU conditions during five consecutive

quarters.

Integrated

Inspection Report

05000250/2012003,

05000251/2012003

(ML12213A232)

05000250/2012004,

05000251/2012004

(ML12304A087)

05000250/2012005,

05000251/2012005

(ML13030A208)

05000250/2013002,

05000251/2013002

(ML13115A425)

05000250/2013003,

05000251/2013003

(ML13211A151)

Both

71111.17

Reviewed the following Engineering Change (EC)

packages:

EC 247012, Modifications to the Normal Hot Leg

Recirculation Flowpath for EPU

EC 242442, Fast Acting Feedwater Isolation

Valve Upgrade

EC 246924, EPU - Pressurizer Safety Valve

Setpoint Change

EC 246874, EPU - Main Steam Isolation Valve

Upgrade

EC 273225, Emergency Containment Cooler Auto

Start

EC 247048, Plant Documentation Changes

Resulting from Westinghouse Setpoint Scaling

Revision

EC 275011, AFW Rotating Element and Pump

Replacement

EC 247008, Reduce EDG Generator Volt &

Frequency

EC 247006, Removal of AFW Stops

Integrated

Inspection Report

05000250/2012003,

05000251/2012003

(ML12213A232)

U-3

Inspection

Procedure

Sample

Inspection Report

(ML Number)

U-3,

U-4,

Both

71111.19

Reviewed post-maintenance testing for the following

modifications:

EC 275011, Unit 3: 3-OSP-075.7, Auxiliary

Feedwater Train 2 Backup Nitrogen Test.

EC 242442, Unit 3: 3-PTP-074.13, Test of Main

Feedwater Isolation Valve

EC 242442, Unit 3: 3-PTP-074.13, Test of Main

Feedwater Isolation Bypass Valve

EC 247012, Unit 3: Test Instruction (TI)-09-143-

01, Hot leg Injection alternate flowpath.

Integrated

Inspection Report 05000250/2012003,

05000251/2012003

(ML12213A232)

U-3

EC 275011, Common: 0-OSP-075.11, Auxiliary

Feedwater In-service Test following P2B pump

replacement

Both

EC 273225, Unit 3: 3-OSP-203.2, Train B

Engineered Safeguards Integrated Test

Integrated

Inspection Report 05000250/2012005,

05000251/2012005

(ML13030A208)

U-3

Unit 3 EPU, 3-PTP-074.4, Leading Edge Flow

Meter (LEFM) Commissioning Test

Integrated

Inspection Report 05000250/2013002,

05000251/2013002

(ML13115A425)

U-3

EC 249722, Unit 4 EPU, T-09-143-04, hot leg

injection alternate flow path modification

05000250/2013003,

05000251/2013003

(ML13211A151)

U-4

Monitored the following transient tests:

Planned power change from 180 MWe to 112

MWe with all systems in automatic

05000250/2012004,

05000251/2012004

(ML12304A087)

U-3

EC 246883, Unit 4, EPU, 4-PTP-072.6, 4A main

steam isolation valve test

EC 246883, Unit 4, EPU, 4-PTP-072.7, 4B main

steam isolation valve test

Integrated

Inspection Report 05000250/2013003,

05000251/2013003

(ML13211A151)

U-4

Performed the following power ascension activities:

Reviewed Unit 3 EPU, 3-PTP-072.2, 3R26

Extended Power Update Return to Service

Testing

Reviewed power ascension data at various power

plateaus including vibration, LEFM and NSSS

data

Integrated

Inspection Report 05000250/2013002,

05000251/2013002

(ML13115A425)

U-3

Inspection

Procedure

Sample

Inspection Report

(ML Number)

U-3,

U-4,

Both

Performed the following power ascension activities:

Monitored power ascension activities at various

power levels.

Reviewed power ascension data at various power

plateaus including vibration, LEFM and NSSS

data

Integrated

Inspection Report 05000250/2013003,

05000251/2013003

(ML13211A151)

U-4

71111.19

71111.22

Observed the following transient tests:

3-OSP-089.1, Turbine Generator Overspeed Trip

Test

3-OSP-203.2, Section 7.3, Loss of Offsite Power

Coincident with Safety Injection

Integrated

Inspection Report 05000250/2012004,

05000251/2012004

(ML12304A087)

U-3

4-OSP-089.1, Turbine Generator Overspeed Trip

Test

Integrated

Inspection Report 05000250/2013003,

05000251/2013003

(ML13211A151)

U-4

71152

Reviewed Action Requests (ARs) related to the EPU

project

Integrated

Inspection Report 05000250/2012003,

05000251/2012003

(ML12213A232)

05000250/2012004,

05000251/2012004

(ML12304A087)

05000250/2012005,

05000251/2012005

(ML13030A208)

05000250/2013002,

05000251/2013002

(ML13115A425)

05000250/2013003,

05000251/2013003

(ML13211A151)

Both

LIST OF ACRONYMS

ACS

Air Calculation Sheet

AR

Action Request

CAP

Corrective Action Program

CCW

Component Cooling Water

CFR

Code of Federal Regulations

CR

Condition Report

CY

Calendar year

EAL

Emergency Action Level

ED

Electronic Dosimeter

EP

Emergency Preparedness

HP

Health Physics

HRA

High Radiation Area

ISFSI

Independent Spent Fuel Storage Installation

IST

Inservice Testing

LHRA

Locked High Radiation Area

NAP

Nuclear Administrative Procedure

NCV

Non-Cited Violation

NRC

Nuclear Regulatory Commission

OA

Other Activities

OS

Occupational Radiation Safety

PCM

Personnel Contamination Monitor

PI

Performance Indicator

PM

Portal Monitor

PS

Public Radiation Safety

PTN

Turkey Point Nuclear Station

QC

Quality Control

RCA

Radiological Controlled Area

RG

Regulatory Guide

Rev.

Revision

RS

Radiation Safety

RWP

Radiation Work Permit

SAM

Small Article Monitor

SFP

Spent Fuel Pool

SG

Steam Generator

TLD

Thermoluminescent dosimeter

TS

Technical Specification

TYRA

Three Year Rolling Average

U3

Unit 3

U4

Unit 4

UFSAR

Updated Final Safety Analysis Report

U4R27

U4 Refueling Cycle 27 Outage

VHRA

Very High Radiation Area

WO

Work Order