IR 05000361/2012003

IR 05000361-12-003, 05000362-12-003; 03/25/2012 - 06/23/2012; San Onofre Nuclear Generating Station, Units 2 and 3, Integrated Resident and Regional Report; Fire Protection, Maintenance Effectiveness, Plant Modifications, Problem Identifica

ML12220A053
Person / Time
Site:	San Onofre
Issue date:	08/06/2012
From:	Ryan Lantz NRC/RGN-IV/DRP/RPB-D
To:	Peter Dietrich Southern California Edison Co
References
IR-12-003
Download: ML12220A053 (58)

Text

UNITE D S TATE S NUC LEAR REGULATOR Y C OMMI S SI ON ust 6, 2012

SUBJECT:

SAN ONOFRE NUCLEAR GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000361/2012003 and 05000362/2012003

Dear Mr. Dietrich:

On June 23, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your San Onofre Nuclear Generating Station Units 2 and 3 facility. The enclosed inspection report documents the inspection results which were discussed on June 22, 2012, with you and other members of your staff.

The inspections 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.

Four NRC identified findings and one self-revealing finding of very low safety significance (Green) were identified during this inspection. Four of these findings were determined to involve violations of NRC requirements. Further, a licensee-identified violation which was determined to be of very low safety significance is listed in this report. The NRC is treating these violations as non-cited violations (NCV) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest these non-cited violations, 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 San Onofre Nuclear Generating Station.

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 San Onofre Nuclear Generating Station.

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

Ryan E. Lantz, Chief Project Branch D Division of Reactor Projects Docket Nos.: 50-361, 50-362 License Nos.: NPF-10, NPF-15 Enclosure: Inspection Report 05000361/2012003 and 05000362/2012003 w/Attachments:

1. Supplemental Information 2. Information Request for inspection activities documented in 71111.07 3. Information Request for inspection activities documented in 71111.17 cc w/ encl: Electronic Distribution

SUMMARY OF FINDINGS

IR 05000361/2012003, 05000362/2012003; 03/25/2012 - 06/23/2012; San Onofre Nuclear

Generating Station, Units 2 and 3, Integrated Resident and Regional Report; Fire Protection,

Maintenance Effectiveness, Plant Modifications, Problem Identification and Resolution.

The report covered a 3-month period of inspection by resident inspectors and announced baseline inspections by region-based inspectors. Four Green non-cited violations and one Green finding of significance were 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 identified a non-cited violation of License Condition 2.C.(14) and the Updated Fire Hazards Analysis for the failure of the licensee to maintain the 3-hour penetration fire seal that separated redundant post-fire safe shutdown equipment. Specifically, prior to May 25, 2012, the licensee failed to maintain the 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> fire barrier between fire areas 2-SE-(-15)-138 and 2-SE-(-

15)-139. The issue was entered into the licensees corrective action program as Nuclear Notification NN 202003184.

The performance deficiency is more than minor, and therefore a finding, because it was associated with the external factors attribute (i.e. fire) of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using Inspection Manual Chapter 0609.04, Phase 1

- Initial Screening and Characterization of Findings, the finding was determined to require additional evaluation under Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process. Using Inspection Manual Chapter 0609, Appendix F, Attachment 2, Table A2.2, the inspectors concluded the penetration fire seal represented a moderate A degradation of the fire confinement element of the fire protection program. Using the supplemental screening for fire confinement findings, the inspectors concluded that the finding was of very low safety significance (Green) because the degraded penetration fire seal provided a minimum of 20 minutes of fire protection and no fire ignition sources or combustible materials would have caused direct flame impingement on the fire barrier. This finding has a cross-cutting aspect in the area of human performance associated with the resources component because the licensee failed to ensure that personnel were adequately trained to inspect this type of penetration H.2(b)(Section 1R05).

Green.

The inspectors reviewed a self-revealing non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure of maintenance personnel to implement procedures associated with foreign material exclusion controls while performing maintenance activities on safety-related 120Vac inverter equipment. Specifically, between October 2009 and April 2012, maintenance personnel failed to follow Procedure SO123-FO-1,

Site Foreign Material Exclusion Control Program, Revision 6, and Procedure SO123-I-1.18, Foreign Material Exclusion (FME) Control, Revision 18, to prevent the introduction of a metal air filter frame that was left inside an energized electrical cabinet. This issue was entered into the licensees corrective action program as Nuclear Notification NN 201958287.

The performance deficiency is more than minor, and therefore a finding, because it is associated with the Mitigating Systems Cornerstone attribute for human performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, maintenance personnel failed to prevent the introduction of foreign material into the energized electrical cabinet of inverter 2Y004.

The resident inspectors performed the initial significance determination for the inverter finding. The inspectors used the NRC Inspection Manual 0609,

Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings. The finding screened to a Phase 2 significance determination because it involved a potential loss of safety function. A Region IV senior reactor analyst performed a Phase 2 significance determination and attempted to use the pre-solved worksheet from the Risk Informed Inspection Notebook for the San Onofre Nuclear Generating Station, Revision 2.01a. However, the pre-solved worksheet did not include this inverter. Therefore, the analyst performed a bounding Phase 3 significance determination. The bounding change to the core damage frequency was 1.1E-8/yr, and therefore, determined to be of very low safety significance. The small population of affected equipment (included in the probabilistic risk assessment model) helped to minimize the safety significance.

The contributing core damage sequences involved a seismic event and a consequential failure of auxiliary feedwater flow control and bypass valves to one steam generator. This finding has a cross-cutting aspect in the area of problem identification and resolution associated with the corrective action program component because maintenance personnel failed to have an appropriate threshold for identifying issues associated with a degraded air filter and its impact to foreign material exclusion controls to ensure there would be no adverse impact to system operability P.1(a)(Section 1R12.1).

Green.

The inspectors identified a non-cited violation of 10 CFR Part 50,

Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure of maintenance personnel to implement procedures associated with foreign material exclusion controls while performing maintenance activities on safety-related 120Vac inverter equipment. Specifically, on June 8, 2012, maintenance personnel failed to follow Procedure SO123-FO-1, Site Foreign Material

Exclusion Control Program, Revision 6, and Procedure SO123-I-1.18, Foreign Material Exclusion (FME) Control, Revision 18, when maintenance personnel failed to implement adequate foreign material exclusions controls during inverter 2Y004 troubleshooting activities. This issue was entered into the licensees corrective action program as Nuclear Notification NN 202016714.

The performance deficiency is more than minor, and therefore a finding, because it is associated with the Mitigating Systems Cornerstone attribute for human performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, maintenance personnel failed to implement adequate controls, as required, to prevent the introduction of foreign materials during troubleshooting and repair activities associated with electrical cabinet of inverter 2Y004. Using Checklist 4 from the Manual Chapter 0609,

Appendix G, Shutdown Operations Significance Determination Process, Phase guidance, the finding is determined to have very low safety significance because all safety function guidelines were met, and thus, the finding did not require a quantitative assessment. This finding has a cross-cutting aspect in the area of human performance associated with the work practices component because the expectations regarding procedural compliance, and that personnel follow procedures were not effectively communicated to maintenance personnel regarding foreign material exclusion controls for unattended and opened electrical components H.4(b)(Section 1R12.2).

Green.

The inspectors identified a finding for the failure to follow the battery testing procedure for non-class 1E batteries. Specifically, licensee personnel failed to implement the non-class 1E battery testing procedure, SO23-I-9.96,

Non-1E Battery Bank Performance Test, Revision 5, for Unit 2 battery 2B011 during refuel R2C17 when the battery is greater than 85% of its expected service life. The licensee submitted and approved an outage scope change request to test the battery during the current outage, and generated Nuclear Notification NN 201997619, to determine when battery 2B011 testing can be performed during the outage. The issue was entered into the licensees corrective action program as Nuclear Notification NN 201994131.

The performance deficiency is more than minor, and therefore a finding, because it was associated with the human performance attribute of the Mitigating Systems Cornerstone, and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was determined to have very low safety significance (Green) since it did not meet any of the greater than green criteria in Table 4A of Manual Chapter 0609, Attachment 04. The finding had a cross-cutting aspect in the human performance area, associated with the decision-making component because the licensee did not use conservative assumptions to demonstrate that the battery would maintain minimum capacity until the next refueling outage H.1(b)(Section 4OA2).

Cornerstone: Barrier Integrity

Green.

The inspectors identified a non-cited violation 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure of engineering personnel to follow Procedure SO123-XXIV-10.1, Engineering Design Change Process - NECPs, Revision 28, to change the design, through physical plant modifications, of a facility used to handle radioactive material.

Specifically, on February 2, 2012, engineering personnel issued as-built engineering change package NECP 800841701 which physically modified the design of the fuel reconstitution gantry crane with no turnover when an issued for construction engineering change package with turnover was required. This issue was entered into the licensees corrective action program as Nuclear Notification NN 202026584.

The performance deficiency is more than minor, and therefore a finding, because it would become a more significant safety concern if left uncorrected since handling fuel with improperly modified equipment could result in fuel barrier damage. This finding cannot be evaluated by the significance determination process because Manual Chapter 0609, Significance Determination Process,

Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, and Appendix G, Shutdown Operations Significance Determination Process, do not apply to the spent fuel pool. This finding affects the Barrier Integrity Cornerstone and is determined to be of very low safety significance by NRC management review because it was a deficiency that did not result in the actual degradation of spent fuel. This finding has a cross-cutting aspect in the area of human performance associated with the work practices component because the expectations regarding procedural compliance, and that personnel follow procedures were not effectively communicated to Design Engineering, Nuclear Fuels Management, and Project Management Organization personnel H.4(b)(Section 1R18).

Licensee-Identified Violations

A violation of very low safety significance or severity level IV that was identified by the licensee has been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. This violation and associated corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 2 began the inspection period shutdown for refueling outage R2C17 and remained shutdown for the duration of the inspection period.

Unit 3 began the inspection period shutdown for forced outage F3C16 and remained shutdown for the duration of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Summer Readiness for Offsite and Alternate-ac Power

a. Inspection Scope

The inspectors performed a review of preparations for summer weather for selected systems, including conditions that could lead to a loss-of-offsite power and conditions that could result from high temperatures. The inspectors reviewed the procedures affecting these areas and the communications protocols between the transmission system operator and the plant to verify that the appropriate information was being exchanged when issues arose that could affect the offsite power system. Examples of aspects considered in the inspectors review included:

• The coordination between the transmission system operator and the plants operations personnel during off-normal or emergency events

• The explanations for the events

• The estimates of when the offsite power system would be returned to a normal state

• The notifications from the transmission system operator to the plant when the offsite power system was returned to normal During the inspection on June 19, 2012, the inspectors focused on plant-specific design features and the procedures used by plant personnel to mitigate or respond to adverse weather conditions. Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant-specific procedures. 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 their corrective action program in accordance with station corrective action procedures.

These activities constitute completion of one readiness for summer weather affect on offsite and alternate-ac power sample as defined in Inspection Procedure 71111.01-05.

b. Findings

No findings were identified.

1R04 Equipment Alignment

Partial Walkdown

a. Inspection Scope

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

• May 11, 2012, Unit 3, shutdown cooling system while in mid-loop conditions

• June 18, 2012, Unit 3, train A emergency diesel generator starting air and receivers

• June 21, 2012, Unit 2, train A saltwater cooling system The inspectors selected these systems based on their risk significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could affect the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, UFSAR, technical specification requirements, administrative technical specifications, 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 inspected 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. Specific documents reviewed during this inspection are listed in the attachment.

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

b. Findings

No findings were identified.

1R05 Fire Protection

Quarterly Fire Inspection Tours

a. Inspection Scope

The inspectors conducted fire protection walkdowns that were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:

• May 10, 2012, Unit 3, emergency diesel generator building

• June 1, 2012, Unit 2, all accessible areas of the safety equipment building

• June 20-21, 2012, Units 2 and 3, auxiliary control building

• June 21, 2012, Unit 3, safety equipment building, rooms 6-14 and 16-26 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 with later additional insights, their potential to affect equipment that could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. Using the documents listed in the attachment, 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. The inspectors also verified that minor issues identified during the inspection were entered into the licensees corrective action program.

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

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

b. Findings

Introduction.

The inspectors identified a Green non-cited violation of License Condition 2.C.(14) and the Updated Fire Hazards

Analysis.

Specifically, the licensee failed to maintain the 3-hour penetration fire seal that separated redundant post-fire safe shutdown equipment.

Description.

On May 25, 2012, the inspectors observed a degraded penetration fire seal for a penetration separating Fire Areas 2-SE-(-15)-138 and 2-SE-(-15)-139, Unit 2 shutdown cooling heat exchanger train A and train B rooms. Specifically, the inspectors identified that degraded ceramic blanket fill material did not provide a 3-hour rated fire barrier, as required by the Updated Fire Hazards

Analysis.

Technical Discussion of Seal Detail SE-10, required the penetration fire seal to have a minimum depth of 12 inches to provide a 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> rated fire barrier in the 18-inch thick wall. The licensee confirmed the bottom of the penetration had 12 inches of ceramic material and the top had 6 inches of ceramic material, therefore, the penetration seal did not provide a 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> rated fire barrier.

The licensee initiated Nuclear Notification NN 202003184 and Fire Impairment 12050087 immediately for a continuous fire watch in the Unit 2 shutdown cooling heat exchanger rooms. The licensee has restored the penetration fire seal to the 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> rated fire barrier per the design documentation. The licensee performed an inspection of this fire seal in November 2011, and did not identify the degraded condition. The licensee concluded the deficiency was not identified due to lack of in-depth training on this type of penetration fire seal.

Analysis.

The failure to ensure the penetration fire seal maintained the required 3-hour fire barrier between the shutdown cooling heat exchanger rooms was a performance deficiency. The performance deficiency is more than minor, and therefore a finding, because it was associated with the external factors attribute (i.e. fire) of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using Inspection Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings. the finding was determined to require additional evaluation under Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process. Using Inspection Manual Chapter 0609, Appendix F, Attachment 2, Table A2.2, the inspectors concluded the penetration fire seal represented a moderate A degradation of the fire confinement element of the fire protection program. Using the supplemental screening for fire confinement findings, the inspectors concluded that the finding was of very low safety significance (Green)because the degraded penetration fire seal provided a minimum of 20 minutes of fire protection and no fire ignition sources or combustible materials would have caused direct flame impingement on the fire barrier. This finding has a cross-cutting aspect in the area of human performance associated with the resources component because the licensee failed to ensure that personnel were adequately trained to inspect this type of penetration H.2(b).

Enforcement.

License Condition 2.C.(14) requires, in part, that the licensee shall implement and maintain in effect all provisions of the approved fire protection program.

This program shall be as described in the Updated Fire Hazards Analysis through Revision 3 as revised by letters to the NRC dated May 31, July 22, and November 20, 1987 and January 21, February 22, and April 21, 1988. The Updated Fire Hazards Analysis requires that Fire Area/Zone 2-SE-(-15)-138 and Fire Area/Zone 2-SE-(-15)-139 are constructed of 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> rated reinforced concrete except for the barrier to 2-SE-(-15)-

136. Contrary to the above, the licensee did not implement and maintain the 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> rated barrier as described in the Updated Fire Hazards

Analysis.

Specifically, prior to May 25, 2012, the licensee failed to maintain the 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> fire barrier between fire areas 2-SE-(-15)-138 and 2-SE-(-15)-139. Because this finding is of very low safety significance and has been entered into the licensees corrective action program as Nuclear Notification NN 202003184, this violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000361/2012003-01, Degraded Fire Barrier Separating Unit 2 Shutdown Cooling Heat Exchanger Rooms.

1R07 Heat Sink Performance

1. Annual Heat Sink Inspection

a. Inspection Scope

The inspectors reviewed licensee programs, verified performance against industry standards, and reviewed critical operating parameters and maintenance records for the Unit 2 engineered safety features switchgear train B room emergency air conditioning unit. The inspectors verified that performance tests were satisfactorily conducted and reviewed for problems or errors, and the licensees heat exchanger inspections and maintenance were adequately performed. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one heat sink inspection sample as defined in Inspection Procedure 71111.07-05.

b. Findings

No findings were identified.

2. Triennial Heat Sink Inspection

a. Inspection Scope

The inspectors reviewed licensee programs to verify heat exchanger performance and operability for the following heat exchangers:

• Unit 2, trains A and B shutdown cooling heat exchangers

• Unit 3, train A diesel generator jacket water cooler The inspectors verified whether testing, inspection, maintenance, and chemistry control programs are adequate to ensure proper heat transfer. The inspectors verified that the periodic testing and monitoring methods utilized proper industry heat exchanger guidance. Additionally, the inspectors verified that the licensees chemistry program ensured that biological fouling was properly controlled between tests. The inspectors reviewed previous maintenance records of the heat exchangers to verify that the licensees heat exchanger inspections adequately addressed structural integrity and cleanliness of their tubes. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of two triennial heat sink inspection samples as defined in Inspection Procedure 71111.07-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

Quarterly Review of Licensed Operator Requalification Program

a. Inspection Scope

On May 30, 2012, the inspectors observed a crew of licensed operators in the plants simulator during just in timing training prior to Unit 2 Mode 4 entry. 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 licensed operator requalification program sample as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk significant systems:

• April 24, 2012, Unit 2, 120Vac vital bus power supply inverter 2Y004 failure The inspectors reviewed events such as where ineffective equipment maintenance has resulted in valid or invalid automatic actuations of engineered safeguards systems 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)

• Verifying 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 constitute completion of one quarterly maintenance effectiveness sample as defined in Inspection Procedure 71111.12-05.

1. Foreign Material Found in Electrical Equipment

Introduction.

The inspectors reviewed a self-revealing Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure of maintenance personnel to implement procedures associated with foreign material exclusion controls while performing maintenance activities on safety-related 120Vac inverter equipment.

Description.

On April 24, 2012, engineering and maintenance personnel began an investigation into a series of inverter 2Y004 failures. The first failure occurred on April 24, 2012, when the control room received multiple alarms indicating failure of the class 1E 120 Vac Channel D electrical bus. Initial investigation by operations personnel determined the failure was caused by a blown power fuse associated with inverter 2Y004. After further investigation maintenance personnel discovered a long metallic object, identified as a broken top section of the front right hand fan filter frame, inside the inverter 2Y004 cabinet. The metallic frame section was found resting on the voltage feedback board and in contact with a choke filter output coil. Key components impacted by the metal foreign object were tested satisfactory and the inverter 2Y004 was returned to service after replacing fuses and troubleshooting on April 30, 2012.

The licensees investigation determined the foreign object (metallic filter frame section)was introduced sometime after the October 2009, refueling interval clean and inspection of inverter 2Y004. The filter frame was broken off during a quarterly filter change out by maintenance personnel. There is no evidence that the missing filter frame was identified by the personnel involved with the filter change out. The inspectors interviewed several of the technicians and supervision personnel and could not determine when the filter change out occurred that resulted in the metal frame being left inside the operating and energized electrical cabinet. Maintenance personnel failed to identify that a section of the air filter metal frame had been damaged and a piece of the broken frame was left inside the cabinet. Change out of air filters is completed on a quarterly frequency, while the inverter is energized and without opening the inverter cabinet panels.

The condition was evaluated by engineering personnel who concluded the metal object found inside the inverter 2Y004 cabinet was non-magnetic (i.e. aluminum) and therefore would not impact the AC output or the safety-related equipment being powered by inverter 2Y004. In addition, engineering and maintenance personnel tested the inverter output under as found conditions and confirmed the inverter output was not impacted by the aluminum air filter frame. The licensee determined that the unexpected trip of inverter 2Y004 was not caused by the foreign material.

Analysis.

The failure of maintenance personnel to follow procedures for the control of foreign material was performance deficiency. The performance deficiency is more than minor, and therefore a finding, because it is associated with the Mitigating Systems Cornerstone attribute for human performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, maintenance personnel failed to prevent the introduction of foreign material into the energized electrical cabinet of inverter 2Y004.

The resident inspectors performed the initial significance determination for foreign material introduced into safety-related electrical cabinet finding. The inspectors used the NRC Inspection Manual 0609, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings. The finding screened to a Phase 2 significance determination because it involved a potential loss of safety function. A Region IV senior reactor analyst performed a Phase 2 significance determination and attempted to use the pre-solved worksheet from the Risk Informed Inspection Notebook for the San Onofre Nuclear Generating Station, Revision 2.01a. However, the pre-solved worksheet did not include this inverter. Therefore, the analyst performed a bounding Phase 3 significance determination.

The analyst noted that inverter 2Y004 provided 120Vac control and instrumentation power to a few auxiliary feedwater containment isolation valves, control power to the train B auxiliary feedwater flow control valve to steam generator number 2, instruments and controls associated with fail-safe reactor trip circuits (Channel D), and certain valve indications. If the inverter failed during a seismic event, operators could recover power to the affected 120Vac bus by using safety related bypass power from bus Q062. This recovery action would take about 1.0 hour0 days <br />0 hours <br />0 weeks <br />0 months <br /> to implement, provided bus Q062 was available.

The analyst used the NRCs Standardized Plant Analysis Risk (SPAR) model for the San Onofre Nuclear Generating Station, Revision 8.22, to assess the findings significance.

The analyst performed a bounding risk assessment for this finding. The analyst noted that, if inverter 2Y004 failed, most equipment safety functions (modeled in the SPAR model) were unaffected by the failure. However, it appeared possible that auxiliary feedwater valve HV-4731 (flow control valve to steam generator number two) could fail closed. The analyst noted that bypass motor-operated valve HV-4715 could be used as a recovery measure to permit flow to the steam generator. This valve was already included in the SPAR model. The analyst also noted seismic events could induce transients and losses of offsite power. Therefore, the analyst considered only the transient and loss of offsite power sequences in this analysis.

Transients: The analysis solved only the transient sequences to obtain a baseline core damage frequency associated with transients. The analyst assumed that the nominal frequency for the seismic induced transients already in the SPAR model exceeded a seismic-only induced transient frequency. The nominal case core damage frequency was 1.08E-6/year. The analyst performed a second transients run with valve HV-4731 failed closed. The core damage frequency increased to 1.09E-6. Therefore, for a one year exposure period, with the inverter failing in an unrecoverable manner in response to any transient, the change to the core damage frequency (delta-CDF) was 1E-8. No further analysis was performed for the transient cases.

Losses of Offsite Power: The analyst performed a similar calculation for the seismic induced loss of offsite power (LOOP) frequencies. However, this portion was more complex because the analyst had to adjust the offsite power recovery values because seismic induced losses of offsite power are not considered recoverable within the SPAR mission time. First the analyst calculated the nominal conditional core damage probability for a seismic induced grid loss of offsite power. The basic event IELOOPGR was set to 1.0. All offsite power non-recovery probabilities were set to 1.0.

The core damage frequency, assuming one full year of exposure, was 1.89E-4. Next, the analyst performed a similar calculation with valve HV-4731 failed closed. The conditional core damage probability was 1.90E-4. The incremental conditional core damage probability was therefore 1.0E-6. Next, the analyst multiplied this value by the seismic induced loss of offsite power frequency. The NRCs Risk Assessment of Operational Events Handbook, Volume 2, Revision 1.01 specified a seismic induced loss of offsite power initiating event frequency of 2.03/year for San Onofre Nuclear Generating Station. Therefore, the delta-CDF for one full year of exposure:

Delta-CDF = 1.0E-6*2.0E-3 = 1.0E-9.

The bounding change to the core damage frequency was therefore 1.1E-8/yr. The small population of affected equipment, (included in the SPAR model) helped to minimize the findings safety significance. The contributing core damage sequences involved a seismic event and a consequential failure of the one auxiliary feedwater flow control valve as well as the failure of one bypass valve.

External Events

Analysis:

Since the change to the core damage frequency was less than 1.0E-7, determination of the external events contribution was not required.

Large Early Release Frequency: Since the delta-CDF was less much less than 1.0E-7, the change to the large early release frequency (LERF) could not be greater than that value. Therefore, the LERF was of very low safety significance.

Because the delta-CDF was less than 1E-6 and the finding was not a significant contributor to the LERF, the finding was of very low safety significance (Green).

This finding has a cross-cutting aspect in the area of problem identification and resolution associated with the corrective action program component because maintenance personnel failed to have an appropriate threshold for identifying issues associated with a degraded air filter and its impact to foreign material exclusion controls to ensure there would be no adverse impact to system operability P.1(a).

Enforcement.

10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Procedure SO123-FO-1, Site Foreign Material Exclusion Control Program, Revision 6, and Procedure SO123-I-1.18, Foreign Material Exclusion (FME) Control, Revision 18, required controls for foreign material exclusion to prevent the introduction of foreign material into electrical equipment, components, or systems.

Contrary to the above, between October 2009 and April 2012, maintenance personnel failed to follow Procedures SO123-FO-1 and SO123-I-1.18. Specifically, maintenance personnel failed to prevent the introduction of a metal air filter frame that was left inside an energized electrical cabinet. Because the finding is of very low safety significance and has been entered into licensees corrective action program as Nuclear Notification NN 201958287, this violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000361/2012003-02, Failure to Maintain Foreign Material Exclusion Controls in Safety-Related Components.

2. Failure to Implement Foreign Material Exclusion Controls During Maintenance

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure of maintenance personnel to implement procedures associated with foreign material exclusion controls while performing maintenance activities on safety-related 120Vac inverter equipment.

Description.

On May 1, 2012, inverter 2Y004 was returned to service following troubleshooting and subsequently failed after only about 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> of operation. The inverter was removed from service to continue troubleshooting and repairs. On June 8, 2012, the inspectors noted during a tour that the maintenance activities on the safety-related 120Vac inverter were in progress, including a test resistor bank which was wired into the safety-related cabinet. Electrical cables were routed out of the rear of inverter 2Y004 and through opened cabinet panels. The inspectors noted there were no maintenance or licensee personnel present in the area. The inspectors contacted a maintenance supervisor before leaving the area to express concerns with the potential lack of foreign material exclusion controls.

Procedure SO123-I-1.18, Foreign Material Exclusion (FME) Control, Revision 18, required openings to equipment be kept covered. Specifically, unattended and opened electrical components should be covered or controlled to prevent inadvertent entry of foreign materials. In addition, Procedure SO123-FO-1, Site Foreign Material Exclusion Control Program, Revision 6, stated that foreign material exclusion program provisions were to be applied to all plant systems and components when exposed during maintenance, operation, testing, inspection, and modification. Specifically, Controls for FME SHALL be implemented to PREVENT the introduction of foreign material into electrical equipment, components, or systems. Nuclear Notification NN 202016714 documented the inspectors observation and concern. Inverter 2Y004 was returned to service on June 14, 2012, following the completion of troubleshooting.

Analysis.

The failure of maintenance personnel to follow procedures for the control of foreign material was a performance deficiency. The performance deficiency is more than minor, and therefore a finding, because it is associated with the Mitigating Systems Cornerstone attribute for human performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, maintenance personnel failed to implement adequate controls, as required, to prevent the introduction of foreign materials during troubleshooting and repair activities associated with electrical cabinet of inverter 2Y004. Using Checklist 4 from the Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process, Phase 1 guidance, the finding is determined to have very low safety significance because all safety function guidelines were met, and thus, the finding did not require a quantitative assessment.

This finding has a cross-cutting aspect in the area of human performance associated with the work practices component because the expectations regarding procedural compliance, and that personnel follow procedures were not effectively communicated to maintenance personnel regarding foreign material exclusion controls for unattended and opened electrical components H.4(b).

Enforcement.

10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Procedure SO123-FO-1, Site Foreign Material Exclusion Control Program, Revision 6, and Procedure SO123-I-1.18, Foreign Material Exclusion (FME) Control, Revision 18, required controls for foreign material exclusion to prevent the introduction of foreign material into electrical equipment, components, or systems.

Contrary to the above, on June 8, 2012, maintenance personnel failed to follow Procedures SO123-FO-1 and SO123-I-1.18. Specifically, maintenance personnel failed to implement adequate foreign material exclusion controls during inverter 2Y004 troubleshooting activities. Because the finding is of very low safety significance and has been entered into licensees corrective action program as Nuclear Notification NN 202016714, this violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000361/2012003-03, Failure to Maintain Foreign Material Exclusion Controls During Maintenance.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed licensee personnel's 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:

• May 28, 2012, Unit 3, 480V 3B03 bus outage to replace breaker 3A0311

• May 29-30, 2012, Units 2 and 3, switchyard electrical grid voltage high due to low load 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. Specific documents reviewed during this inspection are listed in the attachment.

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

b. Findings

No findings were identified.

1R15 Operability Evaluations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed the following assessments:

• April 4, 2012, Units 2 and 3, auxiliary feedwater pump turbine equalizer piping nonconforming condition described in Nuclear Notifications NNs 201938947 and 201938956

• May 4, 2012, Unit 2, train B emergency diesel generator spurious alarms on negative phase sequence relay The inspectors selected these operability and functionality assessments based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure technical specification operability was properly justified and to verify 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 UFSAR 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. 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 two operability evaluations inspection samples as defined in Inspection Procedure 71111.15-05.

b. Findings

No findings were identified.

1R18 Plant Modifications

Permanent Modifications

a. Inspection Scope

The inspectors reviewed key affected parameters associated with energy needs, materials, replacement components, timing, heat removal, control signals, equipment protection from hazards, operations, flow paths, pressure boundary, ventilation boundary, structural, process medium properties, licensing basis, and failure modes for the permanent modifications listed below.

• April 8, 2012, Unit 3, negative phase current protective auxiliary relay (146x)permanent modification associated with emergency diesel generator train A

• June 23, 2012, Unit 2, completed review of spent fuel reconstitution gantry crane modifications The inspectors verified that modification preparation, staging, and implementation did not impair emergency/abnormal operating procedure actions, key safety functions, or operator response to loss of key safety functions; postmodification testing will maintain the plant in a safe configuration during testing by verifying that unintended system interactions will not occur; systems, structures and components performance characteristics still meet the design basis; the modification design assumptions were appropriate; the modification test acceptance criteria will be met; and licensee personnel identified and implemented appropriate corrective actions associated with permanent plant modifications. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of two samples for permanent plant modifications as defined in Inspection Procedure 71111.18-05.

b. Findings

Introduction.

The inspectors identified a Green non-cited violation 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure of engineering personnel to follow design control procedures for making facility modifications.

Description.

The inspectors reviewed Nuclear Notification NN 201853034 that questioned the appropriate design change process to modify the spent irradiated fuel reconstitution gantry crane. The nuclear notification described that structural modifications to the crane were completed on February 2, 2012, using an as-built engineering change notice instead of an issued for construction (ISCO) engineering change package (NECP) with the appropriate turnover to inspect and document the installed design change. Procedure SO123-XXIV-10.1, Engineering Design Change Process - NECPs, Revision 28, defined that as-built engineering change notices were used to change drawings or documents to be consistent with current plant configurations and issued for construction NECPs were used for configurations that were approved but did not yet exist in the plant.

The inspectors reviewed the work order history for the reconstitution gantry crane and determined that the need for a design modification was identified on October 16, 2011, when the crane hook caught on the seismic support cables creating a nuclear safety issue. Subsequently, an ISCO NECP was developed to make the design modifications.

Plans were made to perform the equipment modifications at the completion of reactor core offload on January 27, however, due to inconsistencies between the seismic analysis and both the planned ISCO NECP and actual crane configuration, ISCO NECP 800828274 was not able to be implemented as planned. Alternatively, in order to minimize the impact to the schedule for fuel reconstitution, Design Engineering, Nuclear Fuels Management, and the Project Management Organization agreed to a plan to make the necessary modifications to the crane while disassembled using the work authorization process, reassemble the crane at the spent fuel pool for use, then process the equipment changes as an as-built engineering change notice to update drawings and calculations as if the configuration already existed in the plant. This alternate approach eliminated the turnover because the reassembled crane would conform to the as-built drawings. The justification used by design engineering personnel to eliminate the turnover, as documented in Nuclear Notification NN 201853034, was that the crane was a temporary structure, did not have a Functional Location (FLOC), and did not lift loads greater than 1500 pounds.

The inspectors reviewed Procedure SO123-XXIV-10.9, Design Process Flow and Controls, Revision 8, and observed that the design control measures applied to any changes inside or outside the protected area where the modification affects the design or function of a facility that handles, processes, and treats radioactive materials. No exemption was identified that allowed engineering personnel to not follow the program requirements if the structure was not permanent plant equipment or for structures that only lifted loads up to 1500 pounds. The inspectors also reviewed Procedure SO123-XX-5, Work Clearance Application / Work Clearance Document / Work Authorization Record (WAR), Revision 43, and observed that a turnover was required prior to returning plant equipment to service if the equipment was reconfigured or modified unless specific authorization to bypass the turnover was provided. Further, Procedure SO123-XXIV-10.9, stated, in part, to process as-built NECPs to document changes that do not require a turnover, and to generate ISCO NECPs for physical plant modifications that require a turnover in accordance with Procedure SO123-XXIV-10.1.

Based on the inspectors review of the design and work control procedure requirements, the inspectors concluded that the reconstitution gantry crane was used to handle radioactive material and that the modifications completed on February 2, 2012, affected the seismic design of the equipment, and therefore, the justification used by design engineering personnel to eliminate the turnover was inappropriate. Further, the inspectors concluded that an as-built engineering change notice was not an acceptable design control process since the crane was physically reconfigured, and thereby required a turnover prior to returning the equipment to service to be used for fuel reconstitution. An ISCO NECP should have been used to ensure that a turnover (partial or final) provided the confidence that the modified crane was installed correctly, and would not adversely impact spent fuel handled by the crane or stored in the spent fuel pool.

The inspectors reviewed the common cause evaluation, dated May 17, 2012, associated with Nuclear Notification NN 201917601 used to analyze a significant number of NECP turnover issues that had been captured in the corrective action program. The inspectors noted that Nuclear Notification NN 201853034 was one of the 58 corrective action documents reviewed as part of the common cause evaluation. The common cause evaluation binned the issues raised by Nuclear Notification NN 201853034, regarding reconstitution gantry crane modifications without a turnover, in the procedure compliance category which was also consistent with the inspectors conclusions. In June 2012, Design Engineering management informed the inspectors that they disagreed with the conclusions of the common cause evaluation and the inspectors, and maintained that the design control process was followed with the reconstitution gantry crane modifications, even though their actions were not supported by procedure requirements.

On June 15, following numerous discussions with licensee management regarding the observed differences between engineering practices and design control program requirements, Nuclear Notification NN 202026584 was initiated to evaluate the procedure compliance issues.

Analysis.

The failure of engineering personnel to follow procedures to modify facilities that handle radioactive material was a performance deficiency. The performance deficiency is more than minor, and therefore a finding, because it would become a more significant safety concern if left uncorrected since handling fuel with improperly modified equipment could result in fuel barrier damage. This finding cannot be evaluated by the significance determination process because Manual Chapter 0609, Significance Determination Process, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, and Appendix G, Shutdown Operations Significance Determination Process, do not apply to the spent fuel pool. This finding affects the Barrier Integrity Cornerstone and is determined to be of very low safety significance by NRC management review because it was a deficiency that did not result in the actual degradation of spent fuel. This finding has a cross-cutting aspect in the area of human performance associated with the work practices component because the expectations regarding procedural compliance, and that personnel follow procedures were not effectively communicated to Design Engineering, Nuclear Fuels Management, and Project Management Organization personnel H.4(b).

Enforcement.

10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Procedure SO123-XXIV-10.1, Engineering Design Change Process - NECPs, Revision 28, provided the detailed requirements for the design change process. Procedure SO123-XXIV-10.1, Attachment 1, Engineering Design Process Applicability, stated, in part, that the requirements were applicable to any changes inside or outside the protected area where the modification affects the design or function of facilities used to handle, process, or treat radioactive materials. Procedure SO123-XXIV-10.9, Design Process Flow and Controls, Revision 8, required, in part, that ISCO NECPs be generated in accordance with Procedure SO123-XXIV-10.1 for physical plant modifications requiring turnover. Contrary to the above, on February 2, 2012, engineering personnel failed to follow Procedure SO123-XXIV-10.1 to change the design, through physical plant modifications, of a facility used to handle radioactive material. Specifically, engineering personnel issued as-built engineering change package NECP 800841701 which physically modified the design of the fuel reconstitution gantry crane with no turnover when an ISCO NECP with turnover was required. Because the finding is of very low safety significance and has been entered into the licensees corrective action program as Nuclear Notification NN 202026584, this violation is being treated as a non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000361/2012003-04, Failure to Follow Design Control Procedures.

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:

• April 14, 2012, Unit 2, reactor vessel heated junction thermal couple channel A, improper indication and mis-wiring

• April 16, 2012, Unit 3, train A emergency diesel generator post maintenance testing following relay replacement The inspectors selected these activities based upon the structure, system, or component's ability to affect risk. The inspectors evaluated these activities for the following (as applicable):

• The effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed

• Acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate The inspectors evaluated the activities against the technical specifications, the UFSAR, 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 in 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 two 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

.1 Refueling Outage

a. Inspection Scope

The inspectors reviewed the outage safety plan and contingency plans for the Unit 2 refueling outage (R2C17), which started January 9, 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 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

• 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

• Maintenance of secondary containment as required by the technical specifications

• Licensee identification and resolution of problems related to refueling outage activities Specific documents reviewed during this inspection are listed in the attachment.

Refueling Outage R2C17 was still in progress at the end of this inspection period.

Consequently, these activities constitute only a partial completion of one refueling outage and other outage inspection sample as defined in Inspection Procedure 71111.20-05.

b. Findings

No findings were identified.

.2 Forced Outage

a. Inspection Scope

The inspectors reviewed the outage safety plan and contingency plans for the Unit 3 forced outage (F3C16), which started January 31, 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 forced outage, the inspectors 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

• 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

• 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

• Maintenance of secondary containment as required by the technical specifications

• Licensee identification and resolution of problems related to refueling outage activities Specific documents reviewed during this inspection are listed in the attachment.

The forced outage F3C16 was still in progress at the end of this inspection period.

Consequently, these activities constitute only a partial completion of one forced outage and other outage inspection sample as defined in Inspection Procedure 71111.20-05.

b. Findings

No findings were identified.

1R21 Component Design Basis Inspection Follow-up

125Vdc Battery 2B008

a. Inspection Scope

On October 24, 2008, the NRC Region IV office issued a triennial Component Design Basis Inspection Report 05000361; 05000362/2008010 that documented an Unresolved Item (URI) regarding the omission of the Station Black-Out (SBO) Profile and corresponding test duration of 240 minutes during battery service testing for safety-related battery 2B008. The inspection team generated a Task-Interface Agreement (TIA 2009-002) for resolution of the issue and after an initial answer decided to review the case in greater detail. The final response to the TIA was completed on April 26, 2012, and was documented in TIA 2011-014 closure memorandum, docketed in ADAMS as ML12109A349.

b. Observations and Findings

(Closed) Unresolved Item 05000361;05000362/2008010-03, Omission of Station Blackout Profile During Battery Service Tests During the period of time that the TIA was in review, San Onofre Nuclear Generating Station (SONGS) had four permanently installed safety-related 125Vdc batteries. Two of the batteries were smaller in capacity at 1200 Amp-hours (including 2B008) and the other two were 1800 Amp-hour capacity. The licensee submitted and received approval to replace the two smaller batteries (which were the most-limiting for an SBO event and the concern of the CDBI team in 2008) with two 1800 Amp-hour batteries. This work was completed and the station informed the NRC that they had started testing these four batteries to the SBO profile. The NRC concluded in the TIA response that testing to the SBO profile as part of the Technical Specifications was not required. However, SONGS was informed in various formal communications from the NRC that they needed to test the batteries to the most limiting conditions that the batteries would experience until the Improved Technical Specifications project was completed. SONGS did not do this until it was pointed out by the Component Design Basis Inspection team in 2008 that it was a potential concern. However, this was not a regulatory commitment by the station and, therefore, this Unresolved Item is closed with no finding.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the UFSAR, procedure requirements, and technical specifications to ensure that the surveillance activities listed below demonstrated that the systems, structures, and/or components tested were capable of performing their intended safety functions. 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/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

• Engineering evaluations, root causes, and bases for returning tested systems, structures, and components not meeting the test acceptance criteria were correct

• Reference setting data

• Annunciators and alarms setpoints The inspectors also verified that licensee personnel identified and implemented any needed corrective actions associated with the surveillance testing.

• April 7, 2012, Unit 3, train A emergency diesel generator semi-annual surveillance Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one surveillance testing inspection sample as defined in Inspection Procedure 71111.22-05.

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP4 Emergency Action Level and Emergency Plan Changes (IP 71114.04)

a. Inspection Scope

The NSIR headquarters staff performed an in-office review of the latest revisions of various Emergency Plan Implementing Procedures (EPIPs) located under ADAMS accession numbers ML12103A036 and ML12129A458 as listed in the Attachment.

The licensee transmitted the EPIP revisions to the NRC pursuant to the requirements of 10 CFR Part 50, Appendix E, Section V, Implementing Procedures. The NRC review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, this revision is subject to future inspection. The specific documents reviewed during this inspection are listed in the Attachment.

These activities constitute completion of one sample as defined in Inspection Procedure 71114.04 05.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on April 4, 2012, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the control room, technical support center, and emergency operating facility to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures.

The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the corrective action program. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the attachment.

These activities constitute completion of one sample as defined in Inspection Procedure 71114.06-05.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Data Submission Issue

a. Inspection Scope

The inspectors performed a review of the performance indicator data submitted by the licensee for the 1st Quarter 2012 performance indicators for any obvious inconsistencies prior to its public release in accordance with 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 Units 2 and 3 for the period from the second quarter 2011 through the first quarter 2012. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, mitigating systems performance index derivation reports, issue reports, event reports, and NRC integrated inspection reports for the period of March 25, 2011, through March 24, 2012, 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 NEI guidance. The inspectors also reviewed the licensees issue 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 -

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 Units 2 and 3 for the period from the second quarter 2011 through the first quarter 2012. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports for the period of March 25, 2011, through March 24, 2012, 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 NEI guidance. The inspectors also reviewed the licensees issue 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 -

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 Units 2 and 3 for the period from the second quarter 2011 through the first quarter 2012. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, mitigating systems performance index derivation reports, and NRC integrated inspection reports for the period of March 25, 2011, through March 24, 2012, 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 NEI guidance. The inspectors also reviewed the licensees issue 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 -

heat removal system samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.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 and, as such, did not constitute any separate inspection samples.

b. Findings

No findings were identified.

.3 Selected Issue Follow-up Inspection

a. Inspection Scope

During a review of items entered in the licensees corrective action program, the inspectors recognized a corrective action item documenting the issue listed below. The inspectors considered the following during the review of the licensees actions: (1)complete and accurate identification of the problem in a timely manner;

(2) evaluation and disposition of operability/reportability issues;

(3) consideration of extent of condition, generic implications, common cause, and previous occurrences;

(4) classification and prioritization of the resolution of the problem;

(5) identification of root and contributing causes of the problem;

(6) identification of corrective actions; and

(7) completion of corrective actions in a timely manner.

• April 27, 2012, Units 2 and 3, completed review of corrective action implementation associated with deficiencies identified in Nuclear Notification NN 201443248

• June 23, 2012, Units 2 and 3, completed review of Nuclear Notification NN 201786533 describing condition of non-class 1E battery 2B011 not having an annual performance test. The inspectors reviewed documents associated with the non-class 1E battery banks 2B011 and 3B011 dealing with capacity testing requirements. The review focused on the battery age and the capacity testing periodicity. The inspectors reviewed selected condition reports documenting outage scope addition forms, scheduled testing preventative maintenance documents, capacity testing procedures, battery sizing calculation, and maintenance rule scoping criteria associated with the batteries, as well as held telephonic discussions with licensee personnel, including the battery system engineer.

These activities constitute completion of two in-depth problem identification and resolution samples as defined in Inspection Procedure 71152-05.

b. Findings

Introduction.

The inspectors identified a Green finding for failure to follow battery testing procedure for a non-class 1E battery that has exceeded 85% of expected service life.

Specifically, licensee personnel failed to implement non-class 1E battery testing Procedure SO23-I-9.96, Non-1E Battery Bank Performance Test, Revision 5, for Unit 2 battery 2B011 during refueling outage R2C17 when the battery was greater than 85% of its expected service life. The licensee submitted and approved an outage scope change request to test the battery during the current outage, and generated Nuclear Notification NN 201997619, to determine when battery 2B011 testing could be performed during the outage.

Description.

Non-class 1E battery 2B011 exceeded 85% of the expected service life in 2010. The battery is designed for a 20 year service life, with the 85% service life corresponding to 17 years in service. The battery exceeded this 17 year service life in June 2010. The non-class 1E batteries are sized with design inputs from industry guideline document IEEE 450, IEEE Recommended Practice for Maintenance, Testing, and Replacement of Large Lead Storage Batteries for Generating Stations and Substations. This industry guideline is written to address all large stationary batteries, and does not distinguish between safety-related and non-safety-related batteries. The 85% service life corresponds to battery characteristics known as the inverted bathtub curve in which battery capacity begins to decrease rapidly due to age related effects.

These age related effects may not be identified during routine weekly, monthly, or quarterly maintenance checks.

Section 5.2(3) of IEEE 450-1980 states, in part, [a]nnual performance tests of battery capacity should be given to any battery that shows signs of degradation or has reached 85% of the service life expected for the application. For this battery, once the 85%

service life date was reached, the capacity testing frequency is expected to change from a 5 year periodicity to every refuel cycle periodicity for nuclear plant applications.

Additionally, battery testing Procedure SO23-I-9.96, PM Requirement Battery - Non-1E Battery Bank Performance Test, Revision 5, was written to meet the requirements for performing battery performance testing according to IEEE 450-1980, Section 5.2(3), and other sections.

On June 1, 2010, the Unit 2 battery 2B011 exceeded the 17 year service date corresponding to 85% expected service life. On December 28, 2011, in preparation for refueling outage R2C17, an outage scope change request Nuclear Notification NN 201786533 Task 1, was generated to perform the capacity testing during the refueling outage in accordance with the battery testing procedure and IEEE guidance. The outage scope change request was cancelled because maintenance work order NMO 800824644 to test the battery was scheduled to be performed on February 16, 2012, with the unit online. The licensee later determined that this online schedule date was a default date which was applied when the NMO was created, and not an actual planned schedule date. During the planning process for the online testing of the non-class 1E battery, the licensee determined the testing should not be performed online, and cancelled the NMO to battery replacement in the subsequent refueling outage R2C18, scheduled in 2013.

The last time the battery was tested was in 2009. At that time, the measured capacity was 97.5% and had dropped 2.5% from the previous test 5 years earlier in 2004. Based on characteristics of batteries greater than 85% of expected service life, the rate of capacity drop is expected to increase and is unknown unless testing is performed on a more frequent schedule every refuel. This issue was entered into the licensees corrective action program as Nuclear Notification NN 201994131.

Analysis.

The failure to follow the battery testing procedure for non-class 1E batteries was a performance deficiency. The performance deficiency is more than minor and is associated with the human performance attribute of the Mitigating Systems Cornerstone, and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was determined to have very low safety significance in Phase 1 of the significance determination process since it did not meet any of the greater than green criteria in Table 4A of Manual Chapter 0609, Attachment 04. This finding has a cross-cutting aspect in the area of human performance associated with the decision-making component because the licensee did not use conservative assumptions to demonstrate that the battery would maintain minimum capacity until the next refueling outage H.1(b).

Enforcement.

This finding does not involve enforcement action because no regulatory requirement violation was identified. Because this finding does not involve a violation and has very low safety significance, it is identified as FIN 05000361/2012003-05, Failure to Follow Battery Testing Procedure for Battery Exceeding 85% Service Life.

4OA3 Follow-up of Events and Notices of Enforcement Discretion

.1 Event Follow-Up

a. Inspection Scope

The inspectors reviewed the below listed events for plant status and mitigating actions to:

(1) provide input in determining the appropriate agency response in accordance with Management Directive 8.3, NRC Incident Investigation Program,

(2) evaluate performance of mitigating systems and licensee actions; and

(3) confirm that the licensee properly classified the event in accordance with emergency action level procedures and made timely notifications to NRC and state/governments, as required.

• April 20, 2012, Unit 2, electrical fire in charcoal filter A361 deluge valve panel 2L319 and notice of unusual event emergency declaration

• On April 23, 2012, at 10:37 am, a 3.9 magnitude earthquake occurred approximately 15 miles from SONGS. The United States Geologic Survey (USGS) stated that the epicenter was about 3 miles west of San Juan Capistrano, California. At approximately the same time of the earthquake, operations personnel in the control room received a phone call from a work control supervisor reporting he felt ground motion at his desk in the work process center. The work process center is outside the control room and located in temporary trailers inside the protected area. The control room personnel did not feel ground motion and contacted the USGS for further information. USGS personnel confirmed a 3.9 Magnitude earthquake had occurred. No ground motion was detected by the plant seismic accelerometers and no seismic alarms were received in the control room. The inspectors on site did not feel the ground motion but were notified of the event by control room personnel. The inspectors immediately toured sections of the plant and talked with several plant personnel to confirm that ground tremors did not have an adverse affect on the plant. The inspectors determined by general consensus that ground motion had not been readily felt by plant personnel.

Documents reviewed by the inspectors are listed in the attachment.

These activities constitute completion of two inspection samples as defined in Inspection Procedure 71153-05.

b. Findings

No findings were identified.

.2 Event Report Review

a. Inspection Scope

The inspectors reviewed the below Licensee Event Report and related documents to assess:

(1) the accuracy of the Licensee Event Report;

(2) the appropriateness of corrective actions;

(3) violations of requirements; and

(4) generic issues.

(Closed) Licensee Event Report 05000362/2011-003-00, Wiring Error in Charging Pump Motor Circuitry Results in Loss of Fire Isolation On June 8, 2011, the licensee identified a mis-wired fire isolation switch for the Unit 3 train A charging pump motor control circuitry. In this condition, a hot short on the indication portion of the Unit 3 train A charging pump motor control circuitry would energize the trip function causing a loss of control to the credited charging pump. The wiring error could have impacted plant safety in the event of a fire in fire areas designated as being alternative shutdown areas, but would not have affected other normal and emergency modes of operation.

The licensee determined that the wiring error had occurred during the initial installation of the fire isolation switch in 1981. Corrective actions to address this error included correcting the wiring error and the associated electrical drawings for the charging pump motor control circuitry to the approved configuration. The licensee performed hourly fire watches in Unit 3 until June 14, 2011, when the Unit 3 train A charging pump motor control circuitry was confirmed to be wired properly. The licensee also performed an extent of condition to confirm that the Unit 2 credited charging pump wiring diagram was correct and put a work order in place to perform a field verification of the Unit 2 charging pump control circuitry.

This performance deficiency was more than minor, and therefore a finding, because it was associated with the protection against external events (fire) attribute of the Mitigating Systems Cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

The inspectors evaluated the significance of this finding using Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process, because the performance deficiency affected fire protection defense-in-depth strategies involving post fire safe shutdown systems. However, the screening processes in Appendix F were found to be inadequate to screen this finding. A senior reactor analyst consulted with the licensees PRA staff and obtained the risk analysis that was used to supplement the LER (PRA Report PRA-11-008). The licensee used its fire PRA for this analysis, and the analyst observed that several influential, bounding assumptions were made. The licensees result was a delta-CDF of 1.0E-7 and a delta-LERF of less than 1.0E-9. The analyst determined that refinement of the analysis would decrease the significance by at least an additional order of magnitude, and, accordingly, determined that the performance deficiency was of very low safety significance (Green).

This licensee-identified finding involved a violation of License Condition 2.C(14), Fire Protection. The enforcement aspects of the violation are discussed in Section 4OA7.

This LER is closed.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On May 31, 2012, a regional inspector presented the final heat sink inspection results to Mr. D.

Bauder, Vice President and Station Manager, and other members of the licensee staff.

On June 12, 2012, a regional inspector presented final inspection results telephonically to Mr. D.

Axline, Project Manager, Nuclear Regulatory Affairs.

On June 22, 2012, the resident inspectors presented the quarterly inspection results to Mr. P.

Dietrich, Senior Vice President and Chief Nuclear Officer, and other members of the licensee staff.

On July 2, 2012, the regional inspectors presented the inspection results for the License Event Report review to Mr. R. Treadway, Manager, Nuclear Regulatory Affairs, and other members of the licensee staff.

On July 5, 2012, the inspectors presented the results of the selected issue follow up inspection activities to Mr. R. Treadway, 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.

4OA7 Licensee-Identified Violations

The following finding of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of Section 2.3.2 of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a non-cited violation.

• License Condition 2.C (14), Fire Protection, requires the licensee to implement and maintain in effect all provisions of the approved fire protection program. The approved fire protection program requires the licensee to meet the requirements of 10 CFR Part 50, Appendix R, Section III.G.3, which requires that alternative or dedicated shutdown capability and its associated circuits, independent of cables, systems or components in the area, room, or zone under consideration, should be provided where the protection of systems whose function is required for hot shutdown does not satisfy the requirement of 10 CFR Part 50, Appendix R, Section III.G.2. Contrary to the above, from original installation in 1981 to June 8, 2011, the licensee failed to provide an alternative shutdown capability that was independent of cables, systems, or components in alternative shutdown areas.

Specifically, the licensee mis-wired a switch needed for fire isolation for the Unit 3 train A charging pump motor control circuitry. In this condition, a hot short on the indication portion of the Unit 3 Train A charging pump motor control circuitry would energize the trip function causing a loss of control to the credited charging pump. This issue was determined to have very low safety significance by a senior reactor analyst because of the low probability of an Anticipated Transient Without Scram (ATWS) and fire-induced Loss of Coolant Accident (LOCA) event, the limited accident mitigating function of credited charging pumps, and the availability of High Pressure Safety Injection (HPSI) to mitigate a small loss of coolant accident. This issue was identified in the licensees corrective action program as Nuclear Notification NN 201456724.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

T. Adler, Manager, Maintenance/Systems Engineering

B. Arbour, Manager, Operations Training

J. Armas, Senior Nuclear Engineer, Maintenance/System Engineering

D. Axline, Project Manager, Nuclear Regulatory Affairs

D. Bauder, Vice President, Station Manager

C. Cates, Manager, Recovery

B. Corbett, Director, Performance Improvement

J. Davis, Manager, Plant Operations

D. Dick, Technician, Health Physics

P. Dietrich, Senior Vice President and CNO

G. Fausett, ALARA Coordinator, Health Physics

O. Flores, Director, Nuclear Oversight

T. Gallaher, Manager, Corrective Action Program

S. Genschaw, Manager, Human Performance & Industrial

D. Inouye, Engineer, Fluid Processing Programs

G. Johnson, Jr., Manager, Maintenance/Systems Engineering

K. Johnson, Manager, Design Engineering

L. Kelly, Engineer, Manager, Nuclear Regulatory Affairs

G. Kline, Director, Engineering and Technical Services

M. Lewis, Manager, Health Physics

D. Lindbeck, Manager, Emergency Planning

J. Madigan, Director, Nuclear Safety Culture

A. Mahindrakar, Senior Nuclear Engineer, Maintenance Engineering

T. McCool, Plant Manager

L. Pepple, Supervisor, Emergency Response Training Program

N. Quigley, Manager, Maintenance/System Engineering

R. Richter, Senior Nuclear Engineer, Fire Protection

M. Russell, Health Physicist, Health Physics

M. Stevens, Engineer, Nuclear Regulatory Affairs

R. St. Onge, Director, Nuclear Regulatory Affairs

R. Treadway, Manager, Nuclear Regulatory Affairs

S. Vaughan, ALARA Manager, Health Physics

D. Yarbrough, Director, Plant Operations

K. Yhip, Project Manager, Regulatory Performance

NRC Personnel

M. Runyan, Senior Reactor Analyst

G. Replogle, Senior Reactor Analyst

Attachment 1

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000361/2012003-01 NCV Degraded Fire Barrier Separating Unit 2 Shutdown Cooling Heat Exchanger Rooms (Section 1R05)

05000361/2012003-02 NCV Failure to Maintain Foreign Material Exclusion Controls in Safety-Related Components (Section 1R12.1)

05000361/2012003-03 NCV Failure to Maintain Foreign Material Exclusion Controls During Maintenance (Section 1R12.2)

05000361/2012003-04 NCV Failure to Follow Design Control Procedures (Section 1R18)

05000361/2012003-05 FIN Failure to Follow Battery Testing Procedure for Battery Exceeding 85% Service Life (Section 4OA2)

Closed

05000361/2008010-03 URI Omission of Station Blackout Profile During Battery Service

05000362/2008010-03 Tests (Section 1R21)

05000362/2011-003-00 LER Wiring Error in Charging Pump Motor Circuitry Results in Loss of Fire Isolation (Section 4OA3)