IR 05000445/2012005

IR 05000445-12-005, 05000446-12-005; 09/27/2012 - 12/31/2012; Comanche Peak Nuclear Power Plant, Units 1 and 2 Integrated Resident and Reigional Report; Operability Evaluations

ML13042A290
Person / Time
Site:	Comanche Peak
Issue date:	02/11/2013
From:	Webb Patricia Walker NRC/RGN-IV/DRP/RPB-A
To:	Flores R Luminant Generation Co
Walker W
References
IR-12-005
Download: ML13042A290 (71)

Text

U N IT E D S TA TE S N U C LE AR R E GU LA TOR Y C OM MI S S I ON R E G IO N I V 1600 EAST LAMAR BLVD AR L I NG TO N , TE X AS 7 60 1 1 - 4511 February 11, 2013 Rafael Flores, Senior Vice President and Chief Nuclear Officer Luminant Generation Company, LLC Comanche Peak Nuclear Power Plant P.O. Box 1002 Glen Rose, TX 76043 Subject: COMANCHE PEAK NUCLEAR POWER PLANT - NRC INTEGRATED INSPECTION REPORT 05000445/2012005 AND 05000446/2012005

Dear Mr. Flores:

On December 31, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Comanche Peak Nuclear Power Plant, Units 1 and 2, facility. The enclosed inspection report documents the inspection results which were discussed on January 15, 2013, with Mr. K. Peters, Site Vice President, and other members of your staff.

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

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

One self-revealing finding of very low safety significance (Green) was identified during this inspection. This finding was determined to involve a violation of NRC requirements. The NRC is treating this violation as a non-cited violation (NCV), consistent with Section 2.3.2 of the Enforcement Policy.

If you contest the non-cited violation, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Comanche Peak Nuclear Power Plant, Units 1 and 2.

If you disagree with a cross-cutting aspect assignment 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 IV; and the NRC Resident Inspector at the Comanche Peak Nuclear Power Plant, Units 1 and 2. In accordance with 10 CFR 2.390 of the NRC's Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs Agencywide Document 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/

Wayne C. Walker, Chief Project Branch A Division of Reactor Projects Docket Nos.: 05000445:05000446 License Nos.: NPF-87; NPF-89 Enclosure: Inspection Report 05000445/2012005 and 05000446/2012005 w/Attachments: 1. Supplemental Information 2. Request for Information for the Occupational Radiation Safety Inspection 3. Request for Information for the Inservice Inspection 4. Request for Information for the Occupational Radiation Safety Inspection cc w/encl: Electronic Distribution

SUMMARY OF FINDINGS

IR 05000445/2012005, 05000446/2012005; 9/27/2012 - 12/31/2012; Comanche Peak Nuclear

Power Plant, Units 1 and 2 Integrated Resident and Regional Report; Operability Evaluations.

The report covered a 3-month period of inspection by resident inspectors and announced baseline inspections by region-based inspectors. One Green non-cited violation was identified.

The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609, Significance Determination Process. The cross-cutting aspect is determined using Inspection Manual Chapter 0310, Components Within the Cross-Cutting Areas. Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

Cornerstone: Mitigating Systems

Green.

The inspectors reviewed a self-revealing non-cited violation of Technical Specification 5.4.1.a for the failure of the licensee to follow procedure and properly replace diesel generator governor oil. As a result, foreign material was introduced into the governor and caused a diesel generator start failure. The licensee replaced the governor to correct the problem. The licensee entered the finding into the corrective action program as Condition Report CR-2012-006280.

The licensees failure to follow procedure and properly replace the diesel generator governor oil was a performance deficiency which resulted in a diesel generator start failure. The finding was more than minor because it was associated with the human performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences. Using NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, the finding screened to a detailed risk evaluation because it represented an actual loss of function of a single train for greater than its technical specification allowed outage time. A senior reactor analyst evaluated the risk and determined that the risk was of very low safety significance. The finding has a human performance cross-cutting aspect associated with work control, in that, the job site conditions impacted the human performance of the work activity H.3b]. (Section 1R15)

Licensee-Identified Violations

None.

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at approximately 100 percent power. On November 2, 2012, operators initiated a manual reactor trip as a result of a reactor coolant pump 4 lower motor bearing high temperature. The unit was cooled to Mode 5 to repair the motor bearing. On November 11, 2012, operators performed a reactor startup and closed the main generator output breakers, placing Unit 1 on the grid. On November 12, 2012, the unit returned to approximately 100 percent power and operated at approximately 100 percent power for the remainder of the reporting period.

Unit 2 began the inspection period at approximately 100 percent power. On October 6, 2012, the operators shut down Unit 2 to begin a scheduled refueling outage. On November 2, 2012, the outage ended when the main generator output breakers were closed and Unit 2 was placed on the grid. On November 6, 2012, the unit returned to approximately 100 percent power and operated at that power level for approximately 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> before reducing power to 49 percent as a result of high sodium levels in the steam generators. On November 11, 2012, after steam generator sodium levels improved and repairs to the auxiliary condensers were completed, the unit returned to approximately 100 percent power. On November 17, 2012, the unit experienced an automatic reactor trip as a result of a low steam generator level. The low level was the result of a transient initiated by the heater drain system. The licensee repaired the heater drain system and commenced a reactor startup the same day. On November 18, operators closed the main generator output breakers and the unit returned to approximately 100 percent power the following day. On November 20, 2012, operators initiated a manual runback of the turbine to 900 megawatts, approximately 75 percent power, as a result of a transient of the heater drain system. The licensee returned the unit to approximately 100 percent power the same day and operated at approximately 100 percent power for the remainder of the reporting period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

a. Inspection Scope

The inspectors performed a review of the licensees adverse weather procedures for seasonal extreme low temperatures. The inspectors verified that weather-related equipment deficiencies identified during the previous years were corrected prior to the onset of low temperatures and evaluated the implementation of the adverse weather preparation procedures and compensatory measures.

The inspectors focused on plant-specific design features and the licensees procedures used to mitigate or respond to adverse weather conditions. The inspectors placed additional emphasis on the diesel generators and the Unit 1 feedwater control system.

The inspectors reviewed the Final Safety Analysis Report and performance requirements for systems selected for inspection, and verified that procedures were appropriate.

Specific documents reviewed during this inspection are listed in the attachment. The inspectors also reviewed corrective action program items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into the corrective action program.

These activities constitute completion of one readiness for seasonal adverse weather sample as defined in Inspection Procedure 71111.01-05.

b. Findings

No findings were identified.

1R04 Equipment Alignments

.1 Partial Equipment Walkdowns

a. Inspection Scope

The inspectors performed partial system walkdowns of the following risk-significant systems:

October 24, 2012, Unit 2, reactor coolant pump backseat leakoff during refueling outage November 6, 2012, Unit 1, diesel generators during an orange ORAM (outage risk assessment and management) condition November 8, 2012, Unit 1, reactor coolant pump 4 oil collection system November 15, 2012, Unit 1, auxiliary feedwater pump 1-02 and the turbine driven auxiliary feedwater pump when auxiliary feedwater pump 1-01 was unavailable during maintenance The inspectors selected these systems based on their risk significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors focused on discrepancies that could affect the function of the system and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Final Safety Analysis Report, technical specification requirements, outstanding work orders, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program with the appropriate significance characterization.

These activities constitute completion of four partial system walkdown samples as defined in Inspection Procedure 71111.04-05.

b. Findings

No findings were identified.

.2 Complete System Walkdown

a. Inspection Scope

The inspectors performed a complete system walkdown of the Unit 1 train B safety chill water system and the Unit 2 480 Volt bus 2EB3 to verify the functional capability of the system. The inspectors selected these systems because they were considered both safety-significant and risk-significant in the licensees probabilistic risk assessment. The inspectors walked down the systems to review mechanical and electrical equipment line-ups, electrical power availability, system pressure and temperature indications, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. The inspectors reviewed a sample of past and outstanding work orders to determine whether any deficiencies significantly affected the systems function. In addition, the inspectors reviewed the corrective action program database to ensure that system equipment-alignment problems were being identified and appropriately resolved. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of two complete system walkdown samples as defined by Inspection Procedure 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Quarterly Fire Inspection Tours

a. Inspection Scope

The inspectors conducted fire protection walkdowns in the following risk-significant plant areas:

October 24, 2012, Unit 2, fire zone 2CA101, containment November 5, 2012, Unit 1, reactor coolant pump motor oil collection system November 15, 2012, Unit 1, fire zone AF33, train A component cooling water pump room November 15, 2012, Unit 2, fire zone AE32, train A component cooling water pump room November 20, 2012, transformer XST2A yard area The inspectors reviewed areas to assess if licensee personnel had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant; effectively maintained fire detection and suppression capability; maintained passive fire protection features in good material condition; and had implemented adequate compensatory measures for out of service, degraded or inoperable fire

protection equipment, systems, or features, in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants individual plant examination of external events or their potential to affect equipment that could initiate or mitigate a plant transient. The inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use, that fire detectors and sprinklers were unobstructed, that transient material loading was within the analyzed limits, and fire doors, dampers, and penetration seals appeared to be in satisfactory condition.

These activities constitute completion of five quarterly fire protection inspection samples as defined in Inspection Procedure 71111.05-05.

b. Findings

No findings were identified.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors performed internal flood protection walkdowns of the following plant areas:

Unit 1, train B emergency core cooling system pumps and corridor Uninterruptible power supply air conditioning units The inspectors verified the adequacy of flood control measures. The inspectors reviewed the Final Safety Analysis Report, the flooding analysis, and plant procedures to assess susceptibilities involving internal flooding. The inspectors reviewed the corrective action program to determine if licensee personnel identified and corrected flooding problems. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of two internal flood protection measures inspection samples as defined in Inspection Procedure 71111.06-05.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

Completion of Sections

.1 through .5, below, constitute completion of one inservice

inspection activities sample as defined in Inspection Procedure 71111.08-05.

.1 Inspection Activities Other Than Steam Generator Tube Inspection, Pressurized Water

Reactor Vessel Upper Head Penetration Inspections, and Boric Acid Corrosion Control (71111.08-02.01)

a. Inspection Scope

The inspectors observed 36 nondestructive examination activities and reviewed one nondestructive examination package that included five types of examinations.

The inspectors directly observed the following nondestructive examinations:

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Steam Generator Steam Generator 4, main steam Magnetic Particle nozzle to vessel weld. TCX-2-1100-4-11 Main Feedwater Main feedwater pipe support.

Magnetic Particle TCX-2-2402-H3 Main Feedwater Main feedwater pipe support.

Magnetic Particle TCX-2-2203-H1 Main Feedwater Main feedwater pipe support.

Magnetic Particle TCX-2-2203-H2 Reactor Coolant Reactor coolant pump motor 2-03 Penetrant flywheel. TCX-RCPCPX-03 Safety Injection Support. TCX-2-2582-H3.

Penetrant

Description:

SI-2-031-430-S32A Chemical Volume MOV-2-8402A. Joints TUX 8-1, Radiograph and Control 9-1, and 10-1 Chemical Volume MOV-2-8402A. Joints TUX 7-1 and Radiograph and Control FW-11 Steam Generator Steam Generator 4, auxiliary Ultrasonic feedwater nozzle to vessel weld.

TCX-2-1100-4-10 Examination angle-0° Steam Generator Steam Generator 4, auxiliary Ultrasonic feedwater nozzle to vessel weld.

TCX-2-1100-4-10 Examination angle-45° Steam Generator Steam Generator 4, auxiliary Ultrasonic feedwater nozzle to vessel weld.

TCX-2-1100-4-10 Examination angle-60° Reactor Coolant Reactor upper head penetration Ultrasonic examination. Penetrations 63 and 65 Reactor Coolant

Description:

Pipe to pipe.

Ultrasonic ID #: TXC-1-4500-3

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Reactor Coolant

Description:

Pipe to pipe.

Ultrasonic ID #:TXC-1-4500-2 Steam Generator Steam Generator 4, lower head to Ultrasonic tubesheet weld. TCX-1-3100-4-1 Examination angle-0° Steam Generator Steam Generator 4, lower head to Ultrasonic tubesheet weld. TCX-1-3100-4-1 Examination angle-45° Steam Generator Steam Generator 4, lower head to Ultrasonic tubesheet weld. TCX-1-3100-4-1 Examination angle-60° Main Steam Branch connection to flange - Ultrasonic TXC-2-2200-37 Main Steam Branch connection to flange - Ultrasonic TXC-2-2200-30 Main Steam Branch connection to flange - Ultrasonic TXC-2-2200-39 Main Steam Branch connection to flange - Ultrasonic TXC-2-2200-40 Reactor Coolant Steam Generator 4 - inlet nozzle Ultrasonic (hot leg) inner radius. TCX-1-3100-4A Reactor Coolant Steam Generator 4 - outlet nozzle (cold Ultrasonic leg) inner radius. TCX-1-3100-4B Reactor Coolant Unit 2 - Hot Leg, Loop 1 Visual Azimuth 202°, nozzle to safe-end Reactor Coolant Unit 2 - Hot Leg, Loop 2 Visual Azimuth 337°, nozzle to safe-end Reactor Coolant Unit 2 - Hot Leg, 3Loop 3 Visual Azimuth 22°, nozzle to safe-end Reactor Coolant Unit 2 - Hot Leg, Loop 4 Visual Azimuth 158°, nozzle to safe-end Reactor Coolant Steam Generator 1 - Channel Head Visual Drain Reactor Coolant Steam Generator 2 - Channel Head Visual Drain Reactor Coolant Steam Generator 3 - Channel Head Visual Drain Reactor Coolant Steam Generator 4 - Channel Head Visual Drain

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Safety Injection Support TCX-2-2582-H3 Visual

Description:

SI-3-031-430-S32A Reactor Coolant Reactor upper head. Robotic visual Visual examination.

Main Feedwater Main feedwater pipe support.

Visual TCX-2-2203-H1 Main Feedwater Main feedwater pipe support.

Visual TCX-2-2203-H2 Main Feedwater Main feedwater pipe support.

Visual TCX-2-2402-H3 The inspectors reviewed records for the following nondestructive examinations:

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Reactor Coolant Reactor vessel lower head - Visual System bottom mounted instrumentation penetrations.

During the review and observation of each examination, the inspectors verified that activities were performed in accordance with the ASME Code requirements and applicable procedures. The inspectors also verified that the qualifications of nondestructive examination technicians performing the inspections were current.

The inspectors observed the following welding activities:

SYSTEM WELD IDENTIFICATION WELD TYPE Chemical Volume 3 inch - pipe to pipe Tungsten Inert Gas and Control Weld FW TXU 7-1 Welding (GTAW)

Chemical Volume 3 inch - elbow to pipe Tungsten Inert Gas and Control Weld FW-11 Welding (GTAW)

The inspectors reviewed records for the following welding activities:

SYSTEM WELD IDENTIFICATION WELD TYPE Chemical Volume 3 inch - pipe to valve Tungsten Inert Gas and Control Weld FW TUX 8-1 Welding (GTAW)

Chemical Volume 3 inch - pipe to valve Tungsten Inert Gas and Control Weld TUX 9-1 Welding (GTAW)

Chemical Volume 3 inch - pipe to elbow Tungsten Inert Gas and Control Weld TUX 10-1 Welding (GTAW)

The inspectors verified, by review, that the welding procedure specifications and the welder had been properly qualified in accordance with ASME Code,Section IX, requirements. The inspectors also verified, through observation and record review, that essential variables for the welding process were identified, recorded in the procedure qualification record, and formed the bases for qualification of the welding procedure specifications. Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements for Section 02.01.

b. Findings

No findings were identified.

.2 Vessel Upper Head Penetration Inspection Activities (71111.08-02.02)

a. Inspection Scope

The inspectors reviewed the results of the licensees bare metal visual inspection of the reactor vessel upper head penetrations, and verified that there was no evidence of boric acid challenging the structural integrity of the reactor head components and attachments. The inspectors also verified that the required inspection coverage was achieved and limitations were properly recorded. The inspectors reviewed the results of the licensees volumetric inspection of the reactor vessel head and confirmed that the inspection met Code Case N-729-1. The inspectors also verified that the required inspection coverage was achieved and limitations were properly recorded. The inspectors verified that the personnel performing the inspection were certified examiners to their respective nondestructive examination method. Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements for Section 02.02.

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control Inspection Activities (71111.08-02.03)

a. Inspection Scope

The inspectors evaluated the implementation of the licensees boric acid corrosion control program for monitoring degradation of those systems that could be adversely affected by boric acid corrosion. The inspectors reviewed the documentation associated with the licensees boric acid corrosion control walkdown as specified in Procedure STA-737, Boric Acid Corrosion Detection and Evaluation, Revision 6. The inspectors verified that the visual inspections emphasized locations where boric acid leaks could cause degradation of safety-significant components, and that engineering evaluation used corrosion rates applicable to the affected components and properly assessed the effects of corrosion induced wastage on structural or pressure boundary integrity. The inspectors confirmed that corrective actions taken were consistent with the

ASME Code, and 10 CFR 50, Appendix B requirements. Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements for Section 02.03.

b. Findings

No findings were identified.

.4 Steam Generator Tube Inspection Activities (71111.08-02.04)

a. Inspection Scope

The technical specifications require, in part, that for the Unit 2 model D5 steam generators (alloy 600 thermally treated) inspect 100 percent of the tubes at sequential periods of 120, 90, and, thereafter, 60 effective full power months.

At the last inspection, refueling outage 2RF12, which took place in the spring of 2011, the steam generators had completed 180 effective full power months from the first inservice inspection of the steam generators. The required 100 percent inspection scope was completed during that refueling outage. The current refueling outage, 2RF13, falls into the second sequential period; therefore, the steam generators were not required to be inspected. No primary side inspections were performed. Therefore, the inspectors determined this section of Inspection Procedure 71111.08 was not applicable.

These actions constitute completion of the requirements for Section 02.04.

b. Findings

No findings were identified.

.5 Identification and Resolution of Problems (71111.08-02.05)

a. Inspection scope

The inspectors reviewed 37 condition reports which dealt with inservice inspection activities and found the corrective actions for inservice inspection issues were appropriate. From this review the inspectors concluded that the licensee has an appropriate threshold for entering inservice inspection issues into the corrective action program and has procedures that direct a root cause evaluation when necessary. The licensee also has an effective program for applying industry inservice inspection operating experience. Specific documents reviewed during this inspection are listed in the attachment.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 Quarterly Inspection of Licensed Operator Requalification Program

a. Inspection Scope

On November 26, 2012, the inspectors observed a crew of licensed operators in the plants simulator during requalification training. The inspectors assessed the following areas:

Licensed operator performance The ability of the licensee to administer the evaluations The modeling and performance of the control room simulator The quality of post-scenario critiques Follow-up actions taken by the licensee for identified discrepancies These activities constitute completion of one quarterly inspection of licensed operator requalification program sample as defined in Inspection Procedure 71111.11-05.

b. Findings

No findings were identified.

.2 Quarterly Observation of Licensed Operator Performance

a. Inspection Scope

The inspectors observed the performance of on-shift licensed operators in the plants main control room. At the time of the observations, the plant was in a period of heightened activity. The inspectors assessed the operators adherence to plant procedures and other operations department policies. The inspectors observed the operators performance of the following activities:

October 15, 2012, Unit 2, control of core offload October 27, 2012, Unit 2, midloop activities November 1, 2012, Unit 2, reactor startup November 20, 2012, Unit 1, recovery from unit runback These activities constitute completion of one quarterly observation of licensed operator performance sample as defined in Inspection Procedure 71111.11-05.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors evaluated the following risk significant systems, components, and degraded performance issues:

Service water intake structure, structural monitoring Unit 1 train B safety chill water system The inspectors reviewed events where ineffective equipment maintenance had resulted in failures and independently verified the licensee's actions to address system performance or condition problems in terms of the following:

Implementing appropriate work practices Identifying and addressing common cause failures Scoping of systems in accordance with 10 CFR 50.65(b)

Characterizing system reliability issues for performance Charging unavailability for performance Trending key parameters for condition monitoring Ensuring proper classification in accordance with 10 CFR 50.65(a)(1) or (a)(2)

The inspectors verified appropriate performance criteria for structures, systems, and components classified as having an adequate demonstration of performance through preventive maintenance, as described in 10 CFR 50.65(a)(2), or as requiring the establishment of appropriate and adequate goals and corrective actions for systems classified as not having adequate performance, as described in 10 CFR 50.65(a)(1).

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.

These activities constituted completion of two maintenance effectiveness samples as defined in Inspection Procedure 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the licensees evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:

October 3, 2012, Unit 2, refueling outage October 9, 2012, Unit 2, containment integrated leakage rate test October 17, 2012, Unit 2, bus 2EA2 while protected with defense-in-depth postings November 6, 2012, Unit 1, forced outage

The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that licensee personnel performed risk assessments as required by 10 CFR 50.65(a)(4)and that the assessments were accurate and complete. When licensee personnel performed emergent work, the inspectors verified that the licensee personnel promptly assessed and managed plant risk. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed the technical specification requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.

These activities constitute completion of four maintenance risk assessments and emergent work control inspection samples as defined in Inspection Procedure 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

CR-2011-005478, Units 1 and 2, water in control room air conditioning unit X-04 due to clogged drain CR-2012-006280, Unit 2, foreign material in diesel generator governor CR-2012-011513, Unit 1, blackout sequencer 1-02 partial actuation CR-2012-012553, Unit 1, auxiliary feedwater pump 1-01 outboard pump bearing oil darker than normal The inspectors selected these operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that technical specification operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the technical specifications and Final Safety Analysis Report to the licensees evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of four operability evaluation inspection samples as defined in Inspection Procedure 71111.15-05.

b. Findings

Introduction.

The inspectors reviewed a Green self-revealing non-cited violation of Technical Specification 5.4.1.a for the failure of the licensee to follow procedure and properly replace diesel generator governor oil. As a result, foreign material was introduced into the governor and caused a diesel generator start failure. The licensee replaced the governor to correct the problem.

Description.

On June 20, 2012, the licensee initiated a surveillance test of diesel generator 2-01. During the test, the engine started to crank but the engine speed would not exceed 200 revolutions per minute and after approximately 100 seconds, operators shut down the diesel generator. Normal speed for the engine is 450 revolutions per minute. A few hours later and as part of troubleshooting, operators performed a normal slow start of the diesel engine. The governor output shaft did not move for the first 30 seconds and then moved. The engine reached rated speed at 55 seconds and appeared to be operating correctly. During a slow start, the diesel generator would reach rated speed in approximately 38 seconds.

The licensees apparent cause evaluation determined that the cause of the diesel generator failure to start was a failure of the mechanical governor to function on the demand start. The failure of the governor was the result of a soft particle stuck either in the governor pilot valve or an internal check valve.

The inspectors reviewed the apparent cause evaluation and determined that maintenance personnel replaced the governor oil on April 11, 2011. Procedure MSM-C0-3367, Emergency Diesel Engine Governor Maintenance, Revision 4, provides written instructions for performing maintenance of diesel generator governors. Step 5.1 and the caution prior to Step 8.4.6 required, in part, to exercise extreme care to prevent the entry of foreign material into clean systems and that the cleanliness of governor internals is of upmost importance to governor operation. Erratic governor behavior and failure has been caused by contamination of governor oil system. On April 11, 2011, the licensee failed to exercise extreme care to prevent the entry of foreign material into the governor. As a result, foreign material was introduced into the governor and that caused a diesel generator start failure. The licensee replaced the governor and returned the diesel generator to operation.

The inspectors performed a walkdown of the governor and determined that the confined area near the governor created a challenge to keep foreign material from entering the governor. The inspectors determined that the governor oil replacement was the likely cause of the introduction of foreign material into the governor.

Analysis.

The licensees failure to follow procedure and properly replace the diesel generator governor oil was a performance deficiency which resulted in a diesel generator start failure. The finding was more than minor because it was associated with the human performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences. Using NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, the finding screened to a detailed risk evaluation because it represented an

actual loss of function of a single train for greater than its technical specification allowed outage time.

A senior reactor analyst performed a detailed evaluation of the finding. Diesel generator 2-01 failed to start after a period of seven days from the previous successful start. The analyst assumed that once the diesel generator was up to rated speed and voltage, the degraded governor oil had no effect on the engines reliability. Therefore, the change in risk is restricted to the 7-day period and is further reduced to 3.5 days to reflect a T/2 assumption. The standardized plant analysis risk model, Revision 8.22, was run at a truncation of 1.0E-11, average test and maintenance, and diesel generator 2-01 fail-to-start set to TRUE, indicating that the performance deficiency had a common cause potential. The resulting delta-core damage frequency was 2.31E-4.

For a 3.5 day exposure, the incremental conditional core damage probability was 2.2E-6.

The analyst noted that two mitigating factors were not included in the standardized plant analysis risk model result. First, the alternate power generators are not modeled. These units have been evaluated in the past to result in a mitigation factor of greater than one order of magnitude for diesel generator failures. Second, the manner of the failure was such that the diesel generator started successfully without any corrective action other than a repeated attempt to start. Thus, the recovery factors in the standardized plant analysis risk model, which are based on average failure states, are overly-bounding for this case. The analyst qualitatively determined that the internal events incremental conditional core damage probability would be below 1.0E-7 when these factors are taken into consideration. There are no external events that would result in a significant increase in the significance. The senior reactor analyst concluded that the risk of the diesel failure was of very low safety significance.

The finding has a human performance cross-cutting aspect associated with work control, in that, the confined job site conditions impacted the human performance of the work activity H.3b].

Enforcement.

Technical Specification 5.4.1.a requires, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A. Regulatory Guide 1.33, Revision 2, Appendix A, Item 9.a, requires, in part, that maintenance that can affect the performance of safety-related equipment should be performed in accordance with written procedures. Procedure MSM-C0-3367, Emergency Diesel Engine Governor Maintenance, Revision 4, provides written instructions for performing maintenance of diesel generator governors. Step 5.1 and the caution prior to Step 8.4.6 required, in part, to exercise extreme care to prevent the entry of foreign material into clean systems and that the cleanliness of governor internals is of upmost importance to governor operation. Erratic governor behavior and failure has been caused by contamination of governor oil system.

Contrary to the above, on April 11, 2011, the licensee failed to implement written procedures as required by Technical Specification 5.4.1.a. Specifically, the licensee failed to implement Procedure MSM-C0-3367 and exercise extreme care to prevent the entry of foreign material into the governor when replacing the governor oil. As a result, foreign material was introduced into the governor and caused a diesel generator start failure. The licensee replaced the governor and returned the diesel generator to operation. Because the violation was of very low safety significance and was

documented in the licensees corrective action program as Condition Report CR-2012-006280, it is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy: NCV 05000446/2012005-01, Foreign Material in Diesel Generator Governor Causes Start Failure.

1R18 Plant Modifications

a. Inspection Scope

The inspectors reviewed the plant modification of the auxiliary feedwater pump constant level oilers and the associated level indicating gauges. The inspectors reviewed Final Design Authorization FDA-2012-000089-01-02, the Final Safety Analysis Report, and technical specifications to ensure the modification did not affect operability of the auxiliary feedwater pumps. The inspectors observed the installation of the modification and the subsequent post modification testing.

These activities constitute completion of one plant modifications inspection sample as defined in Inspection Procedure 71111.18-05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the following post-maintenance activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

October 23, 2012, Unit 2, service water pump 2-02 testing following pump replacement October 29, 2012, Unit 2, main steam isolation valve 2-02 testing following valve maintenance October 31, 2012, Unit 2, safety injection pump 2-01 testing following pump replacement October 31, 2012, Unit 1, blackout sequencer 1-02 testing following relay and power supply replacement November 29, 2012, Unit 1, motor driven auxiliary feedwater pump 1-01 testing following pump outer bearing oil replacement The inspectors selected these activities based upon the structure, system, or component's ability to affect risk. The inspectors evaluated the activities to ensure the testing was adequate for the maintenance performed, the acceptance criteria were clear, and the test ensured equipment operational readiness.

The inspectors evaluated the activities against technical specifications, the Final Safety Analysis Report, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them into the corrective action program and that the problems were being corrected commensurate with their importance to safety. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of five post-maintenance testing inspection samples as defined in Inspection Procedure 71111.19-05.

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

The activities below constitute completion of two refueling and other outage activities samples as defined in Inspection Procedure 71111.20-05.

.1 Unit 2 Refueling Outage

a. Inspection Scope

The inspectors reviewed the outage safety plan and contingency plans for the Unit 2 refueling outage, conducted October 6, 2012, through November 2, 2012, to confirm that licensee personnel had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. During the refueling outage, the inspectors observed portions of the shutdown and cooldown of the reactor and monitored licensee controls over the outage activities listed below:

Configuration management, including maintenance of defense-in-depth, is commensurate with the outage safety plan for key safety functions and compliance with the applicable technical specifications when taking equipment out of service Clearance activities, including confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication, accounting for instrument error Status and configuration of electrical systems to ensure that technical specifications and outage safety plan requirements were met, and controls over switchyard activities Monitoring of decay heat removal processes, systems, and components

Verification that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system Reactor water inventory controls, including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss Controls over activities that could affect reactivity Refueling activities including fuel handling Startup and ascension to full power operation, tracking of startup prerequisites, walkdown of the containment to verify that debris had not been left which could block emergency core cooling system suction strainers, and reactor physics testing Licensee identification and resolution of problems related to refueling outage activities Licensees management of fatigue Specific documents reviewed during this inspection are listed in the attachment.

b. Findings

No findings were identified.

.2 Unit 1 Reactor Coolant Pump Outage

a. Inspection Scope

The inspectors reviewed the outage safety plan and contingency plans for the Unit 1 reactor coolant pump outage, conducted November 2, 2012, through November 11, 2012, to confirm that licensee personnel had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. During the outage, the inspectors observed portions of the shutdown and cooldown of the reactor and monitored licensee controls over the outage activities listed below:

Configuration management, including maintenance of defense-in-depth, is commensurate with the outage safety plan for key safety functions and compliance with the applicable technical specifications when taking equipment out of service Clearance activities, including confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing Status and configuration of electrical systems to ensure that technical specifications and outage safety plan requirements were met, and controls over switchyard activities Monitoring of decay heat removal processes, systems, and components

Verification that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system Reactor water inventory controls, including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss Controls over activities that could affect reactivity Startup and ascension to full power operation, tracking of startup prerequisites, and walkdown of the containment to verify that debris had not been left which could block emergency core cooling system suction strainers Licensee identification and resolution of problems related to outage activities Licensees management of fatigue Specific documents reviewed during this inspection are listed in the attachment.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the Final Safety Analysis Report, procedure requirements, technical specifications, and corrective action documents to ensure that the surveillance activities listed below demonstrated that the systems, structures, and components tested were capable of performing their intended safety functions.

Containment Isolation Valve Test October 9, 2012, Unit 2, containment integrated leakage rate test in accordance with Procedure PPT-S2-7014, Containment Integrated Leakage Rate Test, Revision 1 Reactor Coolant System Leakage Detection Surveillance Testing December 6, 2012, Unit 2, water inventory balance in accordance with Procedure OPT-303, Reactor Coolant System Water Inventory, Revision 13 Routine Surveillance Testing October 4, 2012, Unit 1, auxiliary feedwater pump 1-01 inservice test in accordance with Procedure OPT-206A, AFW System, Revision 29 October 19, 2012, Unit 2, train B undervoltage relay calibration in accordance with Procedure MSE-S2-0603B, Unit 2 Train B Undervoltage Relay Calibration and Response Time Surveillance Test, Revision 4

December 5, 2012, Unit 2, diesel generator 2-01 24-hour load run in accordance with Procedure OPT-214B, Diesel Generator Operability Test, Revision 16 The inspectors either witnessed or reviewed test data to verify that the significant surveillance test attributes were adequate to address the following:

Preconditioning Evaluation of testing impact on the plant Acceptance criteria Test equipment Procedures Jumper and lifted lead controls Test data Testing frequency and method demonstrated technical specification operability Test equipment removal Restoration of plant systems Fulfillment of ASME code requirements Updating of performance indicator data Reference setting data Annunciators and alarms setpoints Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of five surveillance testing inspection samples (one containment isolation valve test sample, one reactor coolant system leakage detection surveillance test sample, and three routine surveillance testing samples) as defined in Inspection Procedure 71111.22-05.

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The inspectors performed an in-office review to verify that no changes to the site emergency plan or emergency plan implementing procedures were submitted to the NRC in calendar year 2012 that required a detailed review according to the requirements of Inspection Procedure 71114.04.

These activities constitute completion of one emergency action level and emergency plan changes sample as defined in Inspection Procedure 71114.04-05.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Public Radiation Safety and Occupational Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

This area was inspected to:

(1) review and assess licensees performance in assessing the radiological hazards in the workplace associated with licensed activities and the implementation of appropriate radiation monitoring and exposure control measures for both individual and collective exposures,

(2) verify the licensee is properly identifying and reporting occupational radiation safety cornerstone performance indicators, and

(3) identify those performance deficiencies that were reportable as a performance indicator and which may have represented a substantial potential for overexposure of the worker.

The inspectors used the requirements in 10 CFR Part 20, the technical specifications, and the licensees procedures required by technical specifications as criteria for determining compliance. The inspectors interviewed the radiation protection manager, radiation protection supervisors, and radiation workers. The inspectors performed walkdowns of various portions of the plant, performed independent radiation dose rate measurements, and reviewed the following items:

Performance indicator events and associated documentation reported by the licensee in the occupational radiation safety cornerstone The hazard assessment program, including a review of the licenses evaluations of changes in plant operations and radiological surveys to detect dose rates, airborne radioactivity, and surface contamination levels Instructions and notices to workers, including labeling or marking containers of radioactive material, radiation work permits, actions for electronic dosimeter alarms, and changes to radiological conditions Programs and processes for control of sealed sources and release of potentially contaminated material from the radiologically controlled area, including survey performance, instrument sensitivity, release criteria, procedural guidance, and sealed source accountability Radiological hazards control and work coverage, including the adequacy of surveys, radiation protection job coverage, and contamination controls; the use of electronic dosimeters in high noise areas; dosimetry placement; airborne radioactivity monitoring; controls for highly activated or contaminated materials (non-fuel) stored within spent fuel and other storage pools; and posting and physical controls for high radiation areas and very high radiation areas Radiation worker and radiation protection technician performance with respect to radiation protection work requirements

Audits, self-assessments, and corrective action documents related to radiological hazard assessment and exposure controls since the last inspection Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of the one radiological hazard assessment and exposure controls sample as defined in Inspection Procedure 71124.01-05.

b. Findings

No findings were identified.

2RS2 Occupational ALARA Planning and Controls

a. Inspection Scope

This area was inspected to assess performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA). The inspectors used the requirements in 10 CFR Part 20, the technical specifications, and the licensees procedures required by technical specifications as criteria for determining compliance. The inspectors interviewed licensee personnel and reviewed the following items:

Site-specific ALARA procedures and collective exposure history, including the current 3-year rolling average, site-specific trends in collective exposures, and source-term measurements ALARA work activity evaluations/postjob reviews, exposure estimates, and exposure mitigation requirements The methodology for estimating work activity exposures, the intended dose outcome, the accuracy of dose rate and man-hour estimates, and intended versus actual work activity doses and the reasons for any inconsistencies Records detailing the historical trends and current status of tracked plant source terms and contingency plans for expected changes in the source term due to changes in plant fuel performance issues or changes in plant primary chemistry Radiation worker and radiation protection technician performance during work activities in radiation areas, airborne radioactivity areas, or high radiation areas Audits, self-assessments, and corrective action documents related to ALARA planning and controls since the last inspection Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of the one occupational ALARA planning and controls sample as defined in Inspection Procedure 71124.02-05.

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

a. Inspection Scope

This area was inspected to verify the licensee is assuring the accuracy and operability of radiation monitoring instruments that are used to:

(1) monitor areas, materials, and workers to ensure a radiologically safe work environment; and

(2) detect and quantify radioactive process streams and effluent releases. The inspectors used the requirements in 10 CFR Part 20, the technical specifications, and the licensees procedures required by technical specifications as criteria for determining compliance.

During the inspection, the inspectors interviewed licensee personnel, performed walkdowns of various portions of the plant, and reviewed the following items:

Audits, self-assessments, and corrective action documents related to radiation monitoring instrumentation since the last inspection Selected plant configurations and alignments of process, postaccident, and effluent monitors with descriptions in the Final Safety Analysis Report and the offsite dose calculation manual Select instrumentation, including effluent monitoring instrument, portable survey instruments, area radiation monitors, continuous air monitors, personnel contamination monitors, portal monitors, and small article monitors to examine their configurations and source checks Calibration and testing of process and effluent monitors, laboratory instrumentation, whole body counters, postaccident monitoring instrumentation, portal monitors, personnel contamination monitors, small article monitors, portable survey instruments, area radiation monitors, electronic dosimetry, air samplers, continuous air monitors Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of the one radiation monitoring instrumentation sample as defined in Inspection Procedure 71124.05-05.

b. Findings

No findings were identified.

2RS6 Radioactive Gaseous and Liquid Effluent Treatment

a. Inspection Scope

This area was inspected to:

(1) ensure the gaseous and liquid effluent processing systems are maintained so radiological discharges are properly mitigated, monitored, and evaluated with respect to public exposure;

(2) ensure abnormal radioactive gaseous or liquid discharges and conditions, when effluent radiation monitors are out-of-service, are controlled in accordance with the applicable regulatory requirements and licensee procedures;

(3) verify the licensees quality control program ensures the radioactive

effluent sampling and analysis requirements are satisfied so discharges of radioactive materials are adequately quantified and evaluated; and

(4) verify the adequacy of public dose projections resulting from radioactive effluent discharges. The inspectors used the requirements in 10 CFR Part 20; 10 CFR Part 50, Appendices A and I; 40 CFR Part 190; the offsite dose calculation manual, and licensee procedures required by the technical specifications as criteria for determining compliance. The inspectors interviewed licensee personnel and reviewed and/or observed the following items:

Radiological effluent release reports since the previous inspection and reports related to the effluent program issued since the previous inspection Effluent program implementing procedures, including sampling, monitor setpoint determinations and dose calculations Equipment configuration and flow paths of selected gaseous and liquid discharge system components, filtered ventilation system material condition, and significant changes to their effluent release points, and associated 10 CFR 50.59 reviews Selected portions of the routine processing and discharge of radioactive gaseous and liquid effluents (including sample collection and analysis)

Controls used to ensure representative sampling and appropriate compensatory sampling Results of the inter-laboratory comparison program Effluent stack flow rates Surveillance test results of technical specification-required ventilation effluent discharge systems since the previous inspection Significant changes in reported dose values A selection of radioactive liquid and gaseous waste discharge permits Part 61 analyses and methods used to determine which isotopes are included in the source term Offsite dose calculation manual changes Meteorological dispersion and deposition factors Latest land use census Records of abnormal gaseous or liquid tank discharges Groundwater monitoring results Changes to the licensees written program for indentifying and controlling contaminated spills/leaks to groundwater

Identified leakage or spill events and entries made into 10 CFR 50.75 (g)records, if any, and associated evaluations of the extent of the contamination and the radiological source term Offsite notifications and reports of events associated with spills, leaks, or groundwater monitoring results Audits, self-assessments, reports, and corrective action documents related to radioactive gaseous and liquid effluent treatment since the last inspection Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of the one radioactive gaseous and liquid effluent treatment sample, as defined in Inspection Procedure 71124.06-05.

b. Findings

No findings were identified.

2RS7 Radiological Environmental Monitoring Program

a. Inspection Scope

This area was inspected to:

(1) ensure that the radiological environmental monitoring program verifies the impact of radioactive effluent releases to the environment and sufficiently validates the integrity of the radioactive gaseous and liquid effluent release program;

(2) verify that the radiological environmental monitoring program is implemented consistent with the licensees technical specifications and/or offsite dose calculation manual, and to validate that the radioactive effluent release program meets the design objective contained in Appendix I to 10 CFR Part 50; and

(3) ensure that the radiological environmental monitoring program monitors non-effluent exposure pathways, is based on sound principles and assumptions, and validates that doses to members of the public are within the dose limits of 10 CFR Part 20 and 40 CFR Part 190, as applicable. The inspectors reviewed and/or observed the following items:

Annual environmental monitoring reports and offsite dose calculation manual Selected air sampling and thermoluminescence dosimeter monitoring stations Collection and preparation of environmental samples Operability, calibration, and maintenance of meteorological instruments Selected events documented in the annual environmental monitoring report which involved a missed sample, inoperable sampler, lost thermoluminescence dosimeter, or anomalous measurement Selected structures, systems, or components that may contain licensed material and has a credible mechanism for licensed material to reach ground water

Records required by 10 CFR 50.75(g)

Significant changes made by the licensee to the offsite dose calculation manual as the result of changes to the land census or sampler station modifications since the last inspection Calibration and maintenance records for selected air samplers, composite water samplers, and environmental sample radiation measurement instrumentation Interlaboratory comparison program results Audits, self-assessments, reports, and corrective action documents related to the radiological environmental monitoring program since the last inspection Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of the one radiological environmental monitoring program sample as defined in Inspection Procedure 71124.07-05.

b. Findings

No findings were identified.

2RS8 Radioactive Solid Waste Processing, and Radioactive Material Handling, Storage,

and Transportation (71124.08)

a. Inspection Scope

This area was inspected to verify the effectiveness of the licensees programs for processing, handling, storage, and transportation of radioactive material. The inspectors used the requirements of 10 CFR Parts 20, 61, and 71 and Department of Transportation regulations contained in 49 CFR Parts 171-180 for determining compliance. The inspectors interviewed licensee personnel and reviewed the following items:

The solid radioactive waste system description, process control program, and the scope of the licensees audit program Control of radioactive waste storage areas including container labeling/marking and monitoring containers for deformation or signs of waste decomposition Changes to the liquid and solid waste processing system configuration including a review of waste processing equipment that is not operational or abandoned in place Radio-chemical sample analysis results for radioactive waste streams and use of scaling factors and calculations to account for difficult-to-measure radionuclides Processes for waste classification including use of scaling factors and 10 CFR Part 61 analysis

Shipment packaging, surveying, labeling, marking, placarding, vehicle checking, driver instructing, and preparation of the disposal manifest Audits, self-assessments, reports, and corrective action reports radioactive solid waste processing, and radioactive material handling, storage, and transportation performed since the last inspection Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of the one radioactive solid waste processing, and radioactive material handling, storage, and transportation sample as defined in Inspection Procedure 71124.08-05.

b. Findings

No findings were identified.

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, and Occupational Radiation Safety

4OA1 Performance Indicator Verification

.1 Data Submission Issue

a. Inspection Scope

The inspectors performed a review of the data submitted by the licensee for the third quarter 2012 performance indicators for any obvious inconsistencies prior to its public release in accordance with NRC Inspection Manual Chapter 0608, Performance Indicator Program.

This review was performed as part of the inspectors normal plant status activities and, as such, did not constitute a separate inspection sample.

b. Findings

No findings were identified.

.2 Mitigating Systems Performance Index - Emergency ac Power System (MS06)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index emergency ac power system performance indicator for Units 1 and 2 for the period from the third quarter 2011 through the second quarter 2012. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, mitigating systems performance index derivation reports, condition reports, and NRC integrated inspection reports to validate

the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable Nuclear Energy Institute guidance. The inspectors also reviewed the licensees condition report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified.

These activities constitute completion of two mitigating systems performance index emergency ac power system samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.3 Mitigating Systems Performance Index - High Pressure Injection Systems (MS07)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index high pressure injection systems performance indicator for Units 1 and 2 for the period from the third quarter 2011 through the second quarter 2012. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, condition reports, mitigating systems performance index derivation reports, and NRC integrated inspection reports to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable Nuclear Energy Institute guidance. The inspectors also reviewed the licensees condition report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified.

These activities constitute completion of two mitigating systems performance index high pressure injection system samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.4 Mitigating Systems Performance Index - Heat Removal System (MS08)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index heat removal system performance indicator for Units 1 and 2 for the period from the third quarter 2011 through the second quarter 2012. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02,

Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, condition reports, mitigating systems performance index derivation reports, and NRC integrated inspection reports to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable Nuclear Energy Institute guidance. The inspectors also reviewed the licensees condition report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified.

These activities constitute completion of two mitigating systems performance index heat removal system samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.5 Mitigating Systems Performance Index - Residual Heat Removal System (MS09)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index residual heat removal system performance indicator for Units 1 and 2 for the period from the fourth quarter 2011 through the third quarter 2012. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, and NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 50.73, definitions and guidance were used. The inspectors reviewed the licensees operator narrative logs, operability assessments, maintenance rule records, maintenance work orders, condition reports, and NRC Integrated Inspection reports to validate the accuracy of the submittals. The inspectors also reviewed the licensees condition report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of two mitigating systems performance index residual heat removal system samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.6 Mitigating Systems Performance Index - Cooling Water Systems (MS10)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index cooling water systems performance indicator for Units 1 and 2 for the period from the fourth quarter 2011 through the third quarter 2012. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions

and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, mitigating systems performance index derivation reports, condition reports, and NRC integrated inspection reports to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable Nuclear Energy Institute guidance. The inspectors also reviewed the licensees condition report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of two mitigating systems performance index cooling water systems samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.7 Occupational Exposure Control Effectiveness (OR01)

a. Inspection Scope

The inspectors reviewed performance indicator data for the third quarter of 2011 through the third quarter of 2012. The objective of the inspection was to determine the accuracy and completeness of the performance indicator data reported during these periods. The inspectors used the definitions and clarifying notes contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, as criteria for determining whether the licensee was in compliance.

The inspectors reviewed corrective action program records associated with high radiation areas (greater than 1 rem/hr) and very high radiation area non-conformances.

The inspectors reviewed radiological, controlled area exit transactions greater than 100 mrem. The inspectors also conducted walkdowns of high radiation areas (greater than 1 rem/hr) and very high radiation area entrances to determine the adequacy of the controls of these areas.

These activities constitute completion of one occupational exposure control effectiveness sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.8 Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual

Radiological Effluent Occurrences (PR01)

a. Inspection Scope

The inspectors reviewed performance indicator data for the third quarter of 2011 through the third quarter of 2012. The objective of the inspection was to determine the accuracy

and completeness of the performance indicator data reported during these periods. The inspectors used the definitions and clarifying notes contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, as criteria for determining whether the licensee was in compliance.

The inspectors reviewed the licensees corrective action program records and selected individual annual or special reports to identify potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose.

These activities constitute completion of one radiological effluent technical specifications/offsite dose calculation manual radiological effluent occurrences sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensees corrective action program at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. The inspectors reviewed attributes that included: the complete and accurate identification of the problem; the timely correction, commensurate with the safety significance; the evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent of condition reviews, and previous occurrences reviews; and the classification, prioritization, focus, and timeliness of corrective actions. Minor issues entered into the licensees corrective action program because of the inspectors observations are included in the attached list of documents reviewed.

These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure, they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees corrective action program. The inspectors accomplished this through review of the stations daily corrective action documents.

The inspectors performed these daily reviews as part of their daily plant status monitoring activities, so these reviews did not constitute any separate inspection samples.

b. Findings

No findings were identified.

.3 Semi-Annual Trend Review

a. Inspection Scope

The inspectors reviewed the licensees corrective action program and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors focused on plant transients. The inspectors reviewed documents and interviewed personnel to determine if the licensee completely and accurately identified problems in a timely manner commensurate with its significance, evaluated and dispositioned operability issues, considered the extent of condition, prioritized the problem commensurate with its safety significance, identified appropriate corrective actions, and completed corrective actions in a timely manner commensurate with the safety significance of the issue.

These activities constitute completion of one semi-annual trend review inspection sample as defined in Inspection Procedure 71152-05.

b. Findings and Observations

No findings were identified.

The inspectors observed that the units have experienced several plant transients in the recent months. On November 2, 2012, Unit 1 operators initiated a manual reactor trip as a result of a reactor coolant pump 4 lower motor bearing high temperature. On November 6, 2012, Unit 2 operators reduced power to 49 percent as a result of high sodium levels in the steam generators. On November 17, 2012, Unit 2 operators experienced an automatic reactor trip as a result of a low steam generator level. The low level was the result of a transient initiated by the heater drain system. On November 20, 2012, Unit 2 operators initiated a manual runback of the turbine to 900 megawatts, approximately 75 percent power, as a result of a transient of heater drain system. The licensee initiated condition reports for the above transients.

.4 Operator Workarounds

a. Inspection Scope

The inspectors reviewed the Unit 2 cumulative effects of the operator workarounds and burdens to determine the reliability, availability, and potential for incorrect operation of systems or components. The inspectors verified the ability of operators to respond in a correct and timely manner to plant transients and accidents, and if the licensee has identified and implemented appropriate corrective actions associated with operator workarounds.

These activities constitute completion of one operator workarounds sample as defined in Inspection Procedure 71152-05.

b. Findings

No findings were identified.

4OA3 Event Followup

The activities documented below constitute completion of two event followup samples as defined in Inspection Procedure 71153.

.1 Unit 1 Manual Reactor Trip

a. Inspection Scope

On November 2, 2012, operators manually tripped the reactor as a result of a high motor bearing temperature on reactor coolant pump 4. The inspectors responded to the control room to access the operators performance and procedure usage. The inspectors performed a walkdown of the control boards to verify appropriate equipment response following the trip. The inspectors discussed the trip with operations management and the control room staff.

b. Findings

No findings were identified.

.2 Unit 2 Automatic Reactor Trip

a. Inspection Scope

On November 17, 2012, the unit experienced an automatic reactor trip as a result of a low steam generator level. The low level was the result of a transient initiated by the heater drain system. The inspectors responded to the control room to access the operators performance and procedure usage. The inspectors performed a walkdown of the control boards to verify appropriate equipment response following the trip. The inspectors discussed the trip with operations management and the control room staff.

b. Findings

No findings were identified.

4OA5 Other

.1 (Closed) NRC Temporary Instruction 2515/177, Managing Gas Accumulation in

Emergency Core Cooling, Decay Heat Removal and Containment Spray Systems (NRC Generic Letter 2008-01)

As documented in NRC Inspection Reports 05000445/2010003; 2011003; 2011004 and 05000446/2010003; 2011003; 2011004, the inspectors completed activities associated with Temporary Instruction 2515/177.

.2 (Closed) NRC Temporary Instruction 2515/187, Inspection of Near-Term Task Force

Recommendation 2.3 Flooding Walkdowns

a. Inspection Scope

The inspectors verified that the licensees walkdown packages for the safe shutdown impoundment riprap, service water intake structure north wall, and the service water pipe tunnel contained the elements as specified in Nuclear Energy Institute 12-07 Walkdown Guidance.

The inspectors accompanied the licensee on their walkdowns of the safe shutdown impoundment riprap, service water intake structure north wall, and the diesel generator fuel oil storage tank covers. In addition, the inspectors independently performed a walkdown of the service water pipe tunnel. For each of the walkdowns, the inspectors confirmed that the licensee verified the following flood protection features, as applicable:

External visual inspection for indications of degradation that would prevent its credited function from being performed Reasonable simulation Critical structure system and component dimensions were measured Available physical margin was determined Flood protection feature functionality was determined using either visual observation or by review of other documents The inspectors verified that noncompliances with current licensing requirements, and issues identified in accordance with the 10 CFR 50.54(f) letter, Item 2.g of Enclosure 4, were entered into the licensee's corrective action program. In addition, issues identified in response to Item 2.g that could challenge risk significant equipment and the licensees ability to mitigate the consequences will be subject to additional NRC evaluation.

b. Findings

No findings were identified.

4OA6 Meetings

Exit Meeting Summary

On October 18, 2012, the inspectors presented the results of the first radiation safety inspection to Mr. K. Peters, Site Vice President, and other members of the licensee staff.

The licensee acknowledged the issues presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary.

No proprietary information was identified.

On October 19, 2012, the inspectors presented the inspection results of the review of inservice inspection activities to Mr. K. Nickerson, Director, Site Engineering, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

On December 7, 2012, the inspectors presented the results of the second radiation safety inspection to Mr. K. Peters, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

On January 15, 2013, the inspectors presented the resident inspection results to Mr. K. Peters, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors acknowledged review of proprietary material during the inspection. No proprietary information has been included in the report.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

R. Flores, Senior Vice President and Chief Nuclear Officer

T. Gilder, Director, Performance Improvement

D. Goodwin, Director, Engineering Support

T. Hope, Manager, Nuclear Licensing

B. Kidwell, Manager, Emergency Preparedness

F. Madden, Director, Oversight and Regulatory Affairs

B. Mays, Vice President, Engineering and Support

K. Nickerson, Director, Site Engineering

B. Patrick, Director, Maintenance

K. Peters, Site Vice President

S. Sewell, Director, Organizational Effectiveness

M. Smith, Director, Operations

S. Smith, Plant Manager

K. Tate, Manager, Security

D. Wilder, Director, Plant Support

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000446/2012005-01 NCV Foreign Material in Diesel Generator Governor Causes Start Failure (Section 1R15)

Closed

2515/177 TI Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (NRC Generic Letter 2008-01) (Section 4OA5.1)

2515/187 TI Inspection of Near-Term Task Force Recommendation 2.3 Flooding Walkdowns (Section 4OA5.2)

Attachment 1