IR 05000361/2012002

IR 05000361-12-002, 05000362-12-002; 01/01/2012 - 03/24/2012; San Onofre Nuclear Generating Station, Units 2 and 3, Integrated Resident and Regional Report; Equipment Alignment, Operability Evaluations and Functionality Assessments, Refueli

ML12129A562
Person / Time
Site:	San Onofre
Issue date:	05/08/2012
From:	Ryan Lantz NRC/RGN-IV/DRP/RPB-D
To:	Peter Dietrich Southern California Edison Co
Lantz R
References
EA-11-261, EA-12-028 IR-12-002
Download: ML12129A562 (66)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION May 8, 2012

SUBJECT:

SAN ONOFRE NUCLEAR GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000361/2012002 and 05000362/2012002

Dear Mr. Dietrich:

On March 24, 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 April 3, 2012, with you and other members of your staff.

On March 16, 2012, an NRC Augmented Inspection Team was chartered to evaluate the steam generator tube integrity issues at Units 2 and 3. Inspection activities associated with the Unit 3 steam generator tube leak and Units 2 and 3 steam generator tube wear issues are continuing, and the results will be documented in publicly available NRC Inspection Report 05000361; 05000362/2012007.

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.

Two NRC identified findings and one self-revealing finding of very low safety significance (Green) were identified during this inspection. These findings were determined to involve violations of NRC requirements. Further, licensee-identified violations which were determined to be traditional enforcement Severity Level IV violations and violations of very low safety significance are listed in this report. The NRC is treating these violations as non-cited violations (NCVs) 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:

NRC Inspection Report 05000361/2012002 and 05000362/2012002 w/Attachments:

1. Supplemental Information 2. Information Request for inspection activities documented in 71124.01, 71124.02 cc w/ encl: Electronic Distribution

SUMMARY OF FINDINGS

IR 05000361/2012002, 05000362/2012002; 01/01/2012 - 03/24/2012; San Onofre Nuclear

Generating Station, Units 2 and 3, Integrated Resident and Regional Report; Equipment Alignment, Operability Evaluations and Functionality Assessments, Refueling and Other Outage Activities.

The report covered a 3-month period of inspection by resident inspectors and announced baseline and focused-baseline inspections by resident and region-based inspectors. Three Green non-cited violations 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: Initiating Events

Green.

The inspectors reviewed a self-revealing non-cited violation of Technical Specification 5.5.1.1 for the failure of operations personnel to follow Procedure SO23-3-1.8, Draining the Reactor Coolant System to a Reduced Inventory Condition, Revision 32, Attachment 13, Reduced Inventory Condition RCS Perturbation Control. Specifically, on February 8, 2012, operations personnel failed to document potential reactor coolant system perturbations and the measures, controls, and enhanced monitoring used to prevent perturbations.

Consequently, work activities performed by heath physics personnel were not appropriately documented and controlled which resulted in a reactor coolant system perturbation while in reduced inventory conditions. The issue was entered into licensees corrective action program as Nuclear Notification NN 201848706.

The performance deficiency is more than minor, and therefore a finding, because it was associated with the Initiating Events Cornerstone attribute of configuration control and affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Additionally, the failure to appropriately control work activities that could impact reactor coolant system inventory while in reduced inventory conditions, if left uncorrected, would have the potential to lead to a more significant safety concern. Using the Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process, Phase 1 guidance, a Phase 2 analysis is required because the finding increased the likelihood of a loss of reactor coolant system inventory during reduced inventory conditions as a result of inadequate controls implemented to avoid operations that could lead to perturbations in reactor coolant system level control. The finding was evaluated using the Phase 2 guidance in IMC 0609,

Appendix G, as applied to Worksheet 2. Using the applicable tables and accounting for the availability of mitigating equipment, two sequences of value 8 and 9, respectively, were identified. This resulted in a determination of very low significance (Green). This finding has a cross-cutting aspect in the area of human performance associated with the work control component because health physics personnel failed to appropriately communicate and coordinate work activities with operations personnel to ensure there would be no impact to plant operations H.3(b)(Section 1R20).

Cornerstone: Mitigating Systems

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 operations personnel to follow Procedure SO123-XV-1.20, Seismic Controls,

Revision 4. Specifically, between March 2 and March 6, 2012, operations personnel failed to follow Procedure SO123-XV-1.20, and allowed tools and equipment in the vicinity of safety-related shutdown cooling components in the room for shutdown cooling heat exchanger train B that could have become an operability hazard during a seismic event. The issue was entered into licensees corrective action program as Nuclear Notifications NNs 201884141 and 201910392.

The performance deficiency is more than minor, and therefore a finding, because it was associated with the Mitigating Systems Cornerstone attribute for protection against external events and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Manual Chapter 0609, Appendix M,

Significance Determination Process Using Qualitative Criteria, was used since Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process, does not specifically address the particular condition in cold shutdown, in which time to boil is greater than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The management review was performed using the Manual Chapter 0609, Appendix G,

Attachment 1, Phase 1 guidance, to establish a bounding analysis. Using the bounding analysis, the finding is determined to have very low safety significance because the finding did not represent a potential loss of both trains of the shutdown cooling system. This finding has a cross-cutting aspect in the area of problem identification and resolution associated with the corrective action program component because operations and Project Management Organization personnel failed to have an appropriate threshold to identify that tools and equipment in the vicinity of safety-related shutdown cooling components needed to be addressed to ensure there would be no adverse impact to system operability P.1(a)(Section 1R04).

Green.

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

Appendix B, Criterion XVI, Corrective Action, for the failure of maintenance and engineering personnel to promptly correct a degraded condition associated with safety-related equipment. Specifically, since December 1988, the licensee failed to address long-term pump bearing oil leaks on safety-related component cooling water pumps, and deferred effective corrective actions with temporary gasket sealant. The licensee has issued work orders to install larger size O-rings and remove the sealant material from the outside of the bearing housing. The issue was entered into licensees corrective action program as Nuclear Notification NN 201840078.

The performance deficiency is more than minor, and therefore a finding, because it is associated with the design control attribute of the Mitigating Systems Cornerstone and affects the associated cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, engineering personnel determined it was acceptable to use applications of gasket sealant to temporarily repair oil leaks, and delay permanent repairs on CCW pump bearing housings.

Using the Manual Chapter 0609, Significance Determination Process, Phase 1 Worksheets, the finding is determined to have very low safety significance because it was not a design or qualification deficiency confirmed not to result in loss of operability or functionality; did not result in a loss of system safety function; did not represent an actual loss of safety function of a single train for greater than its technical specification allowed outage time; was not an actual loss of safety function of one or more non-technical specification trains of equipment designated as risk significant per 10 CFR 50.65 for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. This finding was determined not to have a cross-cutting aspect because it is not reflective of current performance (Section 1R15).

Licensee-Identified Violations

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

REPORT DETAILS

Summary of Plant Status

Unit 2 began the inspection period at 83.2 percent power in their coastdown to refueling outage U2C17. On January 9, 2012, the unit was shutdown for the refueling outage and remained shutdown for the duration of the inspection period.

Unit 3 began the inspection period at essentially full power. On January 31, 2012, the unit was shutdown due to a steam generator tube leak. The unit remained shutdown for the duration of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

Since thunderstorms with potential high winds were forecast in the vicinity of the facility for February 27, 2012, the inspectors reviewed the plant personnels overall preparations/protection for the expected weather conditions. On February 27, 2012, the inspectors walked down the intake structure and areas adjacent to electrical transformers systems because their safety-related functions could be affected, or required, as a result of high winds or tornado-generated missiles or the loss of offsite power. The inspectors evaluated the plant staffs preparations against the sites procedures and determined that the staffs actions were adequate. During the inspection, the inspectors focused on plant-specific design features and the licensees procedures used to respond to specified adverse weather conditions. The inspectors also toured the plant grounds to look for any loose debris that could become missiles during a tornado. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant. Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and performance requirements for the systems selected for inspection, and verified that operator actions were appropriate as specified by plant-specific procedures. The inspectors also reviewed a sample of corrective action program items to verify that the licensee identified adverse weather issues at an appropriate threshold and dispositioned them through the corrective action program in accordance with station corrective action procedures. Specific documents reviewed during this inspection are listed in the attachment.

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

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Partial Walkdown

a. Inspection Scope

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

• January 13, 2012, Unit 2, shutdown cooling system

• March 5, 2012, Unit 2, shutdown cooling system while in lowered reactor coolant system inventory conditions

• March 7, 2012, Unit 3, steam generator E088 and E089 nozzle dam alignments 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

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 operations personnel to follow Procedure SO123-XV-1.20, Seismic Controls, Revision 4, and allowed tools and equipment in the vicinity of safety-related shutdown cooling components in the room for shutdown cooling heat exchanger train B that could have become an operability hazard during a seismic event.

Description.

On March 2, 2012, operations personnel restored shutdown cooling system train B to operable and implemented barrier controls per Procedure SO23-XX-35, Protected Equipment, Revision 7, to protect the technical specification required equipment per shutdown defense-in-depth risk strategies. These actions were taken to prepare for draining the refueling cavity to lowered inventory conditions in the reactor coolant system for reactor head installation. On March 5, 2012, while Unit 2 was in a lowered inventory condition in the reactor coolant system, the inspectors performed a partial equipment alignment of shutdown cooling system train B. Upon entering the room for shutdown cooling heat exchanger train B, the inspectors observed a significant amount of tools and equipment in the area. Specifically, the inspectors noted a vacuum, ladder, scaffold equipment, loose floor grating, and miscellaneous tools that did not appear to be restrained in accordance with Procedure SO123-XV-1.20.

The inspectors proceeded to the control room to inform operations personnel of the observed conditions at approximately 1545 hours0.0179 days <br />0.429 hours <br />0.00255 weeks <br />5.878725e-4 months <br />, including the concerns regarding potential operability impact to safety-related equipment from inadequate seismic controls. Subsequently, the Unit 2 control room supervisor and shift manager initiated immediate actions to address the inspectors concerns and documented the condition in Nuclear Notification NN 201884141. On March 6, the inspectors reviewed the control room logs and noted that shutdown cooling train B had been declared inoperable due to the seismic control issues on March 5, at 2330 hours0.027 days <br />0.647 hours <br />0.00385 weeks <br />8.86565e-4 months <br /> following engineering review of the area. Consequently, operations personnel entered Technical Specification 3.9.5, Shutdown Cooling (SDC) and Coolant Circulation - Low Water Level, Condition A, to immediately initiate action to restore shutdown cooling train B to operable status. On March 6, at 0005 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, shutdown cooling train B was declared operable following removal and securing of equipment in the room for shutdown cooling heat exchanger train B, and operations personnel exited the technical specification limiting condition for operation.

The inspectors inquired further into why it took operations personnel approximately eight hours to address the observed seismic control issues since there appeared to be a lack of timeliness in responding to the operability concerns. The inspectors noted that the operator actions did not appear timely, consistent with the expectations for receiving a report of abnormal conditions from the field. Specifically, OSM-5, Operator Rounds, Revision 19, stated, When receiving a report from the field of an abnormal indication or unexpected situation, the Control Room Team must own it until it is resolved or validated to not be a problem. Additionally, the timeliness did not seem consistent with the guidance in Procedure SO123-XV-52, Operability Determinations & Functionality Assessments, Revision 23. Finally, it appeared that a lack of urgency was evident for a potential operability issue that could require technical specification actions to:

Immediately initiate action to restore SDC loop to operable status, or, immediately initiate actions to establish 20 feet of water above the top of reactor vessel flange. On March 23, 2012, operations personnel initiated Nuclear Notification NN 201910392 to document the inadequate, and untimely, response to the seismic control issues. The nuclear notification documented that the lack of timeliness was a result of miscommunications during shift turnover and between operations workgroups, and poor assumptions by operations personnel that the tools and equipment would not impact operability.

The licensees investigation determined that the tools and equipment were in the room for shutdown cooling heat exchanger train B when operations personnel declared the system operable, and installed the defense-in-depth barrier tape for the protected equipment on March 2, 2012. Further, on March 4, the Project Management Organization identified that the room for shutdown cooling heat exchanger train B needed to be cleaned up as soon as possible. However, operations and Project Management Organization personnel failed to recognize that the tools and equipment were in a location that was not in compliance with Procedure SO123-XV-1.20, and consequently, could have become an operability hazard during a seismic event until identified by the inspectors on March 5, 2012.

Analysis.

The failure of operations personnel to follow procedures to appropriately implement seismic controls to protect safety-related structures, systems, and components was a performance deficiency. The performance deficiency is more than minor, and therefore a finding, because it was associated with the Mitigating Systems Cornerstone attribute for protection against external events and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Manual Chapter 0609, Appendix M, Significance Determination Process Using Qualitative Criteria, was used since Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process, does not specifically address the particular condition in cold shutdown, in which time to boil is greater than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The management review was performed using the Manual Chapter 0609, Appendix G, Attachment 1, Phase 1 guidance, to establish a bounding analysis. Using the bounding analysis, the finding is determined to have very low safety significance because the finding did not represent a potential loss of both trains of the shutdown cooling system. This finding has a cross-cutting aspect in the area of problem identification and resolution associated with the corrective action program component because operations and Project Management Organization personnel failed to have an appropriate threshold to identify that tools and equipment in the vicinity of safety-related shutdown cooling components needed to be addressed 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-XV-1.20, Seismic Controls, Revision 4, provided guidance to prevent tools and equipment from becoming a hazard to safety-related components during a seismic event. Contrary to the above, between March 2 and March 6, 2012, operations personnel failed to prevent tools and equipment from becoming a hazard to safety-related components during a seismic event.

Specifically, the licensee allowed tools and equipment in the vicinity of safety-related shutdown cooling components in the room for shutdown cooling heat exchanger train B that could have become an operability hazard during a seismic event. Because the finding is of very low safety significance and has been entered into licensees corrective action program as Nuclear Notifications NNs 201884141 and 201910392, this violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the NRC

Enforcement Policy: NCV 05000361/2012002-01, Failure to Maintain Seismic Controls in Safety-Related Areas.

.2 Complete Walkdown

a. Inspection Scope

On January 25, 2012, the inspectors performed a complete system alignment inspection of the Unit 2 saltwater cooling water system train B to verify the functional capability of the system. The inspectors selected this system because it was considered both safety significant and risk significant in the licensees probabilistic risk assessment. The inspectors inspected the system to review mechanical and electrical equipment line ups, electrical power availability, system pressure and temperature indications, as appropriate, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. The inspectors reviewed a sample of past and outstanding work orders to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the corrective action program database to ensure that system equipment-alignment problems were being identified and appropriately resolved. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one complete system walkdown sample 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:

• January 23, 2012, Unit 2, containment building

• February 14, 2012, Unit 2, emergency diesel generator building

• March 2, 2012, Unit 2, penetration building

• March 7, 2012, Unit 3, containment building 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

No findings were identified.

1R08 Inservice Inspection Activities

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

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

a. Inspection Scope

The inspectors observed four nondestructive examination activities and reviewed eight nondestructive examination activities that included four types of examinations. The inspectors also reviewed one examination with relevant indications that had been accepted by licensee personnel for continued service.

The inspectors directly observed the following nondestructive examinations:

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Reactor Coolant 4-inch Sch 120 Elbow-to-Pipe (212- Ultrasonic (UT)

System 17UT-040) Examination Reactor Coolant 3-inch Sch 120 Pipe-to-Elbow (212- Ultrasonic (UT)

System 17UT-041) Examination Reactor Vessel Head Reactor Vessel Closure Head Studs Ultrasonic (UT)

1. 1-20 (211-17UT-039) Examination Shutdown Cooling Snubbers for Valves 2HV9336A and Visual (VT-3)

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE System 2HV9336B (211-17VT-072) Examination The inspectors reviewed records for the following nondestructive examinations:

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Reactor Coolant Hot Leg Drain DM Weld (WOL-106) UT Phased Array System Examination Reactor Coolant Hot Leg Shutdown Cooling DM Weld UT Phased Array System (WOL-105) Examination Reactor Coolant Hot Leg Surge DM Weld (WOL-104) UT Phased Array System Examination Shutdown Cooling Guide & Y-Stop Welded Lugs (211- Penetrant (PT)

System 17PT-021) Examination Containment Shell Liner Plate (211-17UT-025) Ultrasonic (UT)

Examination Reactor Coolant CEDM Nozzle 3 Omega Seal Weld Penetrant (PT)

System Examination Pneumatic Test Reactor Coolant CEDM Nozzle 9 Omega Seal Weld Penetrant (PT)

System Examination Pneumatic Test Reactor Coolant CEDM Nozzle 11 Omega Seal Weld Penetrant (PT)

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

The inspectors observed 6 welds on the reactor coolant system pressure boundary. The inspectors directly observed a portion of the following welding activities:

SYSTEM WELD IDENTIFICATION WELD TYPE Reactor Coolant CEDM Nozzle 3 Omega Seal Weld Machine Gas System Tungsten Arc Welding (GTAW)

Reactor Coolant CEDM Nozzle 9 Omega Seal Weld Machine Gas System Tungsten Arc Welding (GTAW)

Reactor Coolant CEDM Nozzle 11 Omega Seal Weld Machine Gas System Tungsten Arc Welding (GTAW)

Emergency Core 6-inch piping, Weld ML Gas Tungsten Arc Cooling System Welding (GTAW)

Emergency Core 6-inch piping, Weld MX Gas Tungsten Arc Cooling System Welding (GTAW)

Emergency Core 24-inch piping Gas Tungsten Arc Cooling System Welding (GTAW)

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

These actions constitute completion of the requirements for Section 02.01.

b. Findings

No findings were identified.

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

a. Inspection Scope

During the U2C17 refueling outage, the licensee replaced the reactor vessel head and its associated attachments. All related nondestructive testing inspections are

documented in this report in Section 4OA5, Other Activities, under Reactor Vessel Head Replacement Inspection (71007).

These actions constitute completion of the requirements for Section 02.02.

b. Findings

No findings were identified.

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

a. Inspection Scope

The inspectors evaluated the implementation of the licensees boric acid corrosion control program for monitoring degradation of those systems that could be adversely affected by boric acid corrosion. The inspectors reviewed the documentation associated with the licensees boric acid corrosion control walkdown as specified in Procedure SO23-XV-85, Boric Acid Corrosion Control Program (BACCP), Revision 7.

The inspectors also reviewed the visual records of the components and equipment. The inspectors verified that the visual inspections emphasized locations where boric acid leaks could cause degradation of safety-significant components. The inspectors also verified that the engineering evaluations for those components where boric acid was identified gave assurance that the ASME Code wall thickness limits were properly maintained. The inspectors confirmed that the corrective actions performed for evidence of boric acid leaks were consistent with requirements of the ASME Code. Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements for Section 02.03.

b. Findings

No findings were identified.

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

a. Inspection Scope

An NRC inservice inspection team was onsite from January 30 through February 10, 2012. The inspectors observed the acquisition of eddy current (ECT) data, interviewed ECT data analysts, reviewed expanded scope inspections, observed tube repair activities, and witnessed one in situ pressure test of a degraded steam generator tube.

The following tube degradation mechanisms were identified:

• Antivibration bar wear

• Tube support plate wear

• Retainer bar wear

• Foreign object wear

• Tube to tube wear

On March 16, 2012, an NRC Augmented Inspection Team was chartered to evaluate the steam generator tube integrity issues at Units 2 and 3. Observations and findings associated with the steam generator tube wear issues will be documented in publicly available NRC Inspection Report 05000361; 05000362/2012007.

b. Findings

No findings were identified

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

a. Inspection Scope

The inspectors reviewed 11 nuclear notifications which dealt with inservice inspection activities and found the corrective actions for inservice inspection issues were appropriate. The specific nuclear notifications reviewed are listed in the Documents Reviewed section. From this review, the inspectors concluded that the licensee has an appropriate threshold for entering inservice inspection issues into the corrective action program and has procedures that direct a root cause evaluation when necessary. The licensee also has an effective program for applying industry inservice inspection operating experience. Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements of Section 02.05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

On February 14, 2012, the inspectors observed a crew of licensed operators in the plants simulator during requalification training. The inspectors assessed the following areas:

• Licensed operator performance

• The ability of the licensee to administer the evaluations

• The modeling and performance of the control room simulator

• The quality of post-scenario critiques

• Follow-up actions taken by the licensee for identified discrepancies [and/or for operators who failed the evaluation]

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:

• January 18-20, 2012, Units 2 and 3, saltwater cooling heat exchanger performance and condition monitoring

• February 6, 2012, Unit 2, train A component cooling water surge tank, backup nitrogen regulator 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 two quarterly maintenance effectiveness samples as defined in Inspection Procedure 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed 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:

• January 5, 2012, Unit 3, return alignment of inverter 3Y012 to normal power supply breaker Q069

• January 15-16, 2012, Unit 2, heavy lift activities including reactor head replacement and storage

• January 30, 2012, Units 2 and 3, electrical bus 2A04 outage The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that licensee personnel performed risk assessments as required by 10 CFR 50.65(a)(4)and that the assessments were accurate and complete. When licensee personnel performed emergent work, the inspectors verified that the licensee personnel promptly assessed and managed plant risk. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed the technical specification requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met. Specific documents reviewed during this inspection are listed in the attachment.

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

b. Findings

No findings were identified.

1R15 Operability Evaluations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed the following issues:

• January 5, 2012, Unit 2, unexpected safety injection/essential chill water train B alarm condition

• January 23, 2012, Unit 2, component cooling water pump P024 bearing leak

• February 1-2, 2012, Unit 3, vibration and loose parts monitor 3L194 for steam generator E088 functional assessment after numerous spurious alarms

• March 8, 2012, Unit 2, lack of tornado protection for refueling water storage tanks

• March 8, 2012, Unit 3, function assessment of important to safety equipment including steam generator nozzle dams

• March 9, 2012, Unit 2, assessment of the potential effects of foreign material in the reactor coolant system

• March 9-12, Unit 3, safety injection tank T009 operability evaluation of separation between tank and containment cooling duct structural support 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 seven operability evaluations inspection samples as defined in Inspection Procedure 71111.15-05.

b. Findings

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the failure of maintenance and engineering personnel to implement timely corrective actions associated with a long-term problem of bearing housing oil leaks on the safety-related component cooling water pumps. Although the licensee had identified a potential long-term problem, the licensee routinely permitted application of gasket sealant to manage a degraded condition.

Description.

On January 23, 2012, inspectors performed a review of an operability determination for safety-related component cooling water (CCW) pumps. Nuclear Notification NN 201816465 documented a problem concerning the history of oil leaks

and unavailability of CCW pumps. Oil leaks from both inboard and outboard bearing housings had caused delays in returning the CCW pumps to service after repairs because of the long cure times associated with gasket sealant sometimes referred to as RTV. The inspectors reviewed the operability determination to ensure operability was properly justified and that the safety-related component remained capable of performing its design function.

On January 25, 2012, inspectors completed a search of corrective actions and identified several nuclear notifications on CCW pumps concerning oil leaks from the bearing housings. Inspectors also completed a system walkdown and noted excessive use of the RTV or gasket sealant on all the CCW pumps. The inspectors also noted Nuclear Notification NN 200458930, written on June 10, 2009, documented a problem associated with Unit 2 train B CCW pump 2P026 because of excessive oil leaks from the pumps outboard bearing housing. Engineering personnel described the rate of oil leakage required operator action every 19 days and concluded the pump was in a degraded condition. The immediate operability determination concluded the pump was operable and the oil leak was small enough that any increase in leakage would be noted and actions taken to refill the oil reservoir during routine operator rounds. Nuclear Maintenance Order NMO 800420412 planned to work on the CCW pump during the next Unit 2 refueling outage. In July 2009, maintenance personnel investigated and repaired the oil leak on the outboard bearing housing. The repair was completed using maintenance practice that included removal of old sealant and application of a new coating. Additionally, Nuclear Maintenance Order NMO 800322181 was developed to replace the bearing housing O-rings. In December 2009, there were no signs of an active leak and engineering personnel requested approval to defer repairs after the refueling outage and until permanent repairs could be made. Because of long-term problems of oil leakage from the bearing housings, engineering personnel had been planning various actions. These actions included assessing bearing housing dimensions, reapplying gasket sealant, or installing different size of O-rings. During the scheduled refueling outage U2C16, the licensee deferred the permanent repairs and decision was made to reapply the gasket sealant on the pump bearing casing to stop excessive oil leakage, without dismantling the bearing housing.

On January 27, 2012, the inspectors met with engineering personnel to discuss the engineering and maintenance issues associated with the safety-related CCW pumps and bearing housing oil leaks. During this discussion the inspectors were informed that oil leaks, depending on the magnitude, could challenge the operability of the pumps.

The condition identified in 2009 was repaired using gasket sealant to temporarily seal the outside of the bearing housing and this temporary repair was permitted by Maintenance Procedure SO23-I-8.148, Goulds Model 3415 Pump Overhaul, Revision 18.

In 1988, the use of gasket sealant on the outside of pump bearing housings was procedurally formalized in Maintenance Procedure SO23-I-8.148, as part of a general procedure change to clean up the procedure, help with pump reassembly steps, and correct typo errors. The licensee completed a change to Maintenance Procedure SO23-I-8.148, in accordance with 10 CFR 50.59 change process, to permit gasket sealant material to be applied in any amount, under the direction of maintenance

supervisor, to seal oil leaks. This change was considered good housekeeping practice to manage excessive oil leakage. The appropriateness of the engineering evaluations permitting unlimited use of the gasket sealant was questioned by the inspectors and this concern was documented in Nuclear Notification NN 201840078. The licensee, in response to the inspectors questions, determined that the original 10 CFR 50.59 screen done in 1988 was inadequate and required updating since the original assessment did not consider design functions associated with the gasket sealant or impact on the CCW pumps oil bearing housing design. The inspectors concluded that routine use of gasket sealant had been inappropriately used by the licensee to defer corrective actions that could address permanent repairs of the oil leak on Unit 2 CCW pump 2P026.

Analysis.

The failure of maintenance and engineering personnel to implement timely corrective actions to correct long-term CCW pump bearing housing oil leaks was a performance deficiency. The performance deficiency is more than minor, and therefore a finding, because it is associated with the design control attribute of the Mitigating Systems Cornerstone and affects the associated cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, engineering personnel determined it was acceptable to use applications of gasket sealant to temporarily repair oil leaks, and delay permanent repairs on CCW pump bearing housings. Using the Manual Chapter 0609, Significance Determination Process, Phase 1 Worksheets, the finding is determined to have very low safety significance because it was not a design or qualification deficiency confirmed not to result in loss of operability or functionality; did not result in a loss of system safety function; did not represent an actual loss of safety function of a single train for greater than its technical specification allowed outage time; was not an actual loss of safety function of one or more non-technical specification trains of equipment designated as risk significant per 10 CFR 50.65 for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. This finding was determined not to have a cross-cutting aspect because it is not reflective of current performance.

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected. Contrary to the above, since December 2009, the licensee failed to promptly correct a degraded condition associated with safety-related CCW pumps. Specifically, the licensee failed to address long-term pump bearing oil leaks on safety-related equipment, and deferred effective corrective actions with temporary gasket sealant. The licensee has issued work orders to install larger size O-rings and remove the sealant material from the outside of the bearing housing. Because the finding is of very low safety significance and has been entered into licensees corrective action program as Nuclear Notification NN 201840078 this violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000361/2012002-02, Failure to Implement Timely Corrective Actions on Safety-Related Pumps.

1R18 Plant Modifications

Temporary Modifications

a. Inspection Scope

To verify that the safety functions of important safety systems were not degraded, the inspectors reviewed the following temporary modifications:

• January 24-27, 2012, Unit 2, damping values for replacement reactor vessel head

• January 25-26, 2012, Unit 2, spent fuel pool cooling pump temporary power The inspectors reviewed the temporary modifications and the associated safety-evaluation screening against the system design bases documentation, including the UFSAR and the technical specifications, and verified that the modification did not adversely affect the system operability/availability. The inspectors also verified that the installation and restoration were consistent with the modification documents and that configuration control was adequate. Additionally, the inspectors verified that the temporary modification was identified on control room drawings, appropriate tags were placed on the affected equipment, and licensee personnel evaluated the combined effects on mitigating systems and the integrity of radiological barriers.

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

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

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

• February 6, 2012, Unit 2, train A emergency diesel generator post-maintenance testing

• February 23, 2012, Unit 2, completed review of return to service testing for emergency diesel generator 2G002 following overhaul and generator 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:

• 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 (U2C17), 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 observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below.

• Configuration management, including maintenance of defense-in-depth, is commensurate with the outage safety plan for key safety functions and compliance with the applicable technical specifications when taking equipment out of service.

• Clearance activities, including confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing.

• Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication, accounting for instrument error.

• Status and configuration of electrical systems to ensure that technical specifications and outage safety-plan requirements were met, and controls over switchyard activities.

• Monitoring of decay heat removal processes, systems, and components.

• Verification that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system.

• Reactor water inventory controls, including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss.

• Controls over activities that could affect reactivity.

• Maintenance of secondary containment as required by the technical specifications.

• Refueling activities, including fuel handling and sipping to detect fuel assembly leakage.

• Licensee identification and resolution of problems related to refueling outage activities.

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

Refueling Outage U2C17 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 (U3C16), 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 observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below.

• Configuration management, including maintenance of defense-in-depth, is commensurate with the outage safety plan for key safety functions and

compliance with the applicable technical specifications when taking equipment out of service.

• 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.

• Startup and ascension to full power operation, tracking of startup prerequisites, walkdown of the drywell (primary containment) to verify that debris had not been left which could block emergency core cooling system suction strainers, and reactor physics testing.

• Licensee identification and resolution of problems related to refueling outage activities.

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

The forced outage U3C16 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

Introduction.

The inspectors reviewed a self-revealing Green non-cited violation of Technical Specification 5.5.1.1 for the failure of operations personnel to follow Procedure SO23-3-1.8, Draining the Reactor Coolant System to a Reduced Inventory Condition, Revision 32, Attachment 13, Reduced Inventory Condition RCS Perturbation Control.

Specifically, work activities performed by heath physics personnel were not appropriately controlled which resulted in a reactor coolant system (RCS) perturbation while in reduced inventory conditions.

Description.

On February 8, 2012, during forced outage F3C16, operations personnel were draining the RCS for nozzle dam installation per Procedure SO23-3-1.8, Draining the Reactor Coolant System to a Reduced Inventory Condition, Revision 32. At a reactor coolant level of approximately 36 inches, the draindown was stopped for steam generator manway removal. During the manway removal, operations personnel

observed an unexpected loss of RCS inventory as indicated by a lowering level.

Operations personnel entered Abnormal Operating Instruction SO23-13-15, Loss of Shutdown Cooling, Revision 25, as a result of the RCS perturbation. Control room operators became aware that the unexpected draining was due to health physics personnel pumping water out of the hot leg bowl for steam generator 3E089 to prepare for tube inspections. Health physics personnel were directed to stop the pumping evolution and remove the pump nozzle from the steam generator bowl area. The RCS level stabilized at approximately 35 inches and operations personnel exited Abnormal Operating Instruction SO23-13-15. Overall, the inadvertent RCS draindown lasted 14 minutes with level dropping from 35.8 inches to 35.3 inches and resulted in a loss of 248 gallons of inventory that was pumped to the containment normal sump.

Procedure SO23-3-1.8, Attachment 13, Reduced Inventory Condition RCS Perturbation Control, provided the mechanism for documenting potential RCS perturbations and the measures, controls, and enhanced monitoring to use for preventing RCS perturbations.

The inspectors reviewed Procedure SO23-3-1.8, Attachment 13, and observed that the steam generator bowl water removal activity was not identified by operations personnel as a work activity that could impact RCS inventory. Consequently, operations personnel failed to provide adequate controls to ensure that the pumping activity by health physics personnel would not cause an RCS perturbation.

The correct sequence for pumping water out of the steam generator bowls was scheduled to be performed at an RCS level of 20.7 inches when level was below the steam generator bowl to hot leg interface. Health physics personnel used Health Physics Guideline HPPG-SO23-G-10.4, Primary Steam Generator Work, for instructions on how residual water in the steam generator bowl was removed. The health physics guideline did not have adequate controls over the work activity, such that, the activity was not flagged by Procedure SO23-3-1.8, Attachment 13, and there were no requirements to communicate with operations personnel and obtain permission prior to pumping water from the steam generator bowls to the containment sump. Health physics personnel communicated with their health physics counterparts in the outage control center prior to commencing the activity, however, due to a misunderstanding of plant conditions and the correct sequence for the activity, they began pumping water from the steam generator bowl when RCS level was at approximately 36 inches.

Analysis.

The failure of operations personnel to follow procedures to appropriately control reactor coolant system perturbation while in reduced inventory conditions was a performance deficiency. The performance deficiency is more than minor, and therefore a finding, because it was associated with the Initiating Events Cornerstone attribute of configuration control and affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Additionally, the failure to appropriately control work activities that could impact reactor coolant system inventory while in reduced inventory conditions, if left uncorrected, would have the potential to lead to a more significant safety concern. Using the Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process, Phase 1 guidance, a Phase 2 analysis is required because the finding increased the likelihood of a loss of reactor coolant system inventory during reduced inventory conditions as a result of inadequate

controls implemented to avoid operations that could lead to perturbations in reactor coolant system level control. The finding was evaluated using the Phase 2 guidance in IMC 0609, Appendix G, as applied to Worksheet 2. Using the applicable tables and accounting for the availability of mitigating equipment, two sequences of value 8 and 9, respectively, were identified. This resulted in a determination of very low significance (Green). This finding has a cross-cutting aspect in the area of human performance associated with the work control component because health physics personnel failed to appropriately communicate and coordinate work activities with operations personnel to ensure there would be no impact to plant operations H.3(b).

Enforcement.

Technical Specification 5.5.1.1 requires, in part, that written procedures be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.

Regulatory Guide 1.33, Quality Assurance Program Requirement (Operations),

Appendix A, Section 3, Procedures for Startup, Operation, and Shutdown of Safety-Related Systems, recommends procedures for draining the reactor coolant system.

Procedure SO23-3-1.8, Draining the Reactor Coolant System to a Reduced Inventory Condition, Revision 32, Attachment 13, Reduced Inventory Condition RCS Perturbation Control, provided instructions to safely drain the reactor coolant system to the proper level for equipment maintenance, and to document potential reactor coolant system perturbations and the measures, controls, and enhanced monitoring used to prevent perturbations. Contrary to the above, on February 8, 2012, operations personnel failed to ensure work activities performed by health physics personnel were appropriately documented and controlled which resulted in a reactor coolant system perturbation while in reduced inventory conditions. Because the finding is of very low safety significance and has been entered into licensees corrective action program as Nuclear Notification NN 201848706, this violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000362/2012002-03, Failure to Control Work Activities and Prevent RCS Perturbations.

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.

• January 4, 2012, Unit 2, main steam safety valve testing

• January 12, 2012, Unit 2, train A engineered safeguards feature system testing

• February 23, 2012, Unit 2, containment purge exhaust penetration 19 local leak rate testing Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of three surveillance testing inspection samples 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 (IP71117.04)

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 number ML12061A253 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.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Public Radiation Safety and Occupational Radiation Safety

2RS0 1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

This area was inspected to:

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

(2) verify the licensee is properly identifying and reporting Occupational Radiation Safety Cornerstone performance indicators, and

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

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

• Performance indicator events and associated documentation reported by the licensee in the Occupational Radiation Safety Cornerstone

• The hazard assessment program, including a review of the licensees evaluations of changes in plant operations and radiological surveys to detect dose rates, airborne radioactivity, and surface contamination levels

• Instructions and notices to workers, including labeling or marking containers of radioactive material, radiation work permits, actions for electronic dosimeter alarms, and changes to radiological conditions

• Programs and processes for control of sealed sources and release of potentially contaminated material from the radiologically controlled area, including survey performance, instrument sensitivity, release criteria, procedural guidance, and sealed source accountability

• Radiological hazards control and work coverage, including the adequacy of surveys, radiation protection job coverage, and contamination controls; the use of electronic dosimeters in high noise areas; dosimetry placement; airborne radioactivity monitoring; controls for highly activated or contaminated materials (non-fuel) stored within spent fuel and other storage pools; and posting and physical controls for high radiation areas and very high radiation areas

• Radiation worker and radiation protection technician performance with respect to radiation protection work requirements

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

These activities constitute completion of the one required sample as defined in Inspection Procedure 71124.01-05.

b. Findings

No findings were identified.

2RS0 2 Occupational ALARA Planning and Controls

a. Inspection Scope

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

• Site-specific ALARA procedures and collective exposure history, including the current 3-year rolling average, site-specific trends in collective exposures, and source-term measurements

• ALARA work activity evaluations/postjob reviews, exposure estimates, and exposure mitigation requirements

• The methodology for estimating work activity exposures, the intended dose outcome, the accuracy of dose rate and man-hour estimates, and intended versus actual work activity doses and the reasons for any inconsistencies

• Records detailing the historical trends and current status of tracked plant source terms and contingency plans for expected changes in the source term due to changes in plant fuel performance issues or changes in plant primary chemistry

• Radiation worker and radiation protection technician performance during work activities in radiation areas, airborne radioactivity areas, or high radiation areas

• Audits, self-assessments, and corrective action documents related to ALARA planning and controls since the last inspection Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of the one required sample as defined in Inspection Procedure 71124.02-05.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

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 4th Quarter 2011 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 Unplanned Scrams per 7000 Critical Hours (IE01)

a. Inspection Scope

The inspectors sampled licensee submittals for the unplanned scrams per 7000 critical hours performance indicator for Units 2 and 3 for the period from the first quarter 2011 through the fourth quarter 2011. 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, and NRC integrated inspection reports for the period of January 1, 2011 through December 21, 2011 to validate the accuracy of the submittals.

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 unplanned scrams per 7000 critical hours samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.3 Unplanned Power Changes per 7000 Critical Hours (IE03)

a. Inspection Scope

The inspectors sampled licensee submittals for the unplanned power changes per 7000 critical hours performance indicator for Units 2 and 3 for the period from the first quarter 2011 through the fourth quarter 2011. 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, maintenance rule records, event reports, and NRC integrated inspection reports for the period of January 1, 2011 through December 21, 2011 to validate the accuracy of the submittals. 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 unplanned transients per 7000 critical hours samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.4 Unplanned Scrams with Complications (IE04)

a. Inspection Scope

The inspectors sampled licensee submittals for the unplanned scrams with complications performance indicator for Units 2 and 3 for the period from the first quarter 2011 through the fourth quarter 2011. 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, and NRC integrated inspection reports for the period of January 1, 2011 through December 31, 2011 to validate the accuracy of the submittals. 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 unplanned scrams with complications samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.5 Occupational Exposure Control Effectiveness (OR01)

a. Inspection Scope

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

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

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

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

b. Findings

No findings were identified.

.6 Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual

Radiological Effluent Occurrences (PR01)

a. Inspection Scope

The inspectors reviewed performance indicator data for the fourth quarter of 2011. The objective of the inspection was to determine the accuracy and completeness of the performance indicator data reported during these periods. The inspectors used the definitions and clarifying notes contained in NEI Document 99-02, Regulatory

Assessment Performance Indicator Guideline, Revision 6, as criteria for determining whether the licensee was in compliance.

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

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

b. Findings

No findings were identified.

4OA2 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(s) 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.

• January 31 to March 10, 2012, Units 2 and 3, steam generator inspection activities and focused baseline inspection following steam generator tube leak Specific documents reviewed by the inspectors are listed in the attachment.

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

b. Observations and Findings

An NRC inservice inspection team was onsite from January 30 through February 10, 2012, during a normally scheduled refueling outage. The licensee satisfactorily completed the steam generator inspections as required by Technical Specification 5.5.2.11, Steam Generator Program, but as a result of the steam generator tube leak in Unit 3, the licensee decided to expand the original inspection scope of the Unit 2 steam generators to address the wear mechanism found in Unit 3.

The licensee conducted an additional review of previously collected eddy current bobbin data of 1,000 tubes in each Unit 2 steam generator, in similar locations to freespan wear

indications found in Unit 3. The licensee did not identify any freespan indications during this inspection.

The licensee also performed visual inspections of both steam generators from the secondary manways in order to inspect the upper bundle and retainer bar locations, and from the transition cone handholes, in an effort to identified any tube to tube, or tube to ABV wear. These inspections did not reveal any wear indications or abnormal conditions.

On January 31, 2012, the main control room operators at Unit 3 received secondary plant system radiation alarms. The operators responded in accordance with their alarm response procedures and diagnosed a steam generator tube leak from the 3E088 steam generator. The operators evaluated the leakage to be about 82 gallons per day. As directed by plant procedures, the operators conducted a rapid power reduction to 35 percent power, and then manually tripped the reactor. Unit 3 had been in operation for approximately one year.

During the period of February 11_16, 2012, the NRC conducted onsite inspection activities on Unit 3. The inspection focused on reviewing the following licensees actions:

(1) efforts to evaluate the condition of Unit 3 Steam Generator (SG) 3E88 in order to identify the leaking tube and determine the cause of the leak,

(2) inspection activities of the Unit 3 steam generators to assure regulatory and procedural compliance, and

(3) evaluations performed for the continued operation of the Unit 3 steam generators through the remainder of the operating cycle. The inspectors observed the acquisition of eddy current test (ECT) data, conducted daily meetings with management, and verified that the expanded scope inspections met technical specification requirements, EPRI guidelines, and NRC regulations.

The licensee completed a leakage test of SG 3E088 per Procedure SO23-9-3, Steam Generator Tube Leak Test, Revision 14, and identified one tube leaking at Row 106, Column 78. The licensee subsequently confirmed the location after performing ECT bobbin examinations of the leaking tube and 18 surrounding tubes. The leak location was identified near the center of the tube bundle in a region two inches downstream of the anti-vibration bar (AVB) B04 on the hot leg side. The ECT bobbin inspection results revealed that the leak had occurred at the middle of a 20-inch long axial freespan indication. Similar indications were found on the 18 adjacent tubes that were inspected.

The licensee made the decision to expand the scope to 100 percent bobbin examinations of both steam generators as a way of bounding the tube wear mechanism.

At the conclusion of the bobbin inspections, the licensee identified a bounding area of approximately 200 tubes in SG 3E088 with wear indications at the freespan and tube support plates. A similar area was indentified in SG 3E089 but with smaller indications overall. The licensee decided to use a rotating probe inspection method for depth sizing of the indications. At the time of the inspection the licensee was in the process of initiating these inspections with a site specific validated sizing technique.

At the conclusion of the inspection, the licensee continued with their original and additional scope inspections that included:

(1) special interest indications in the cold and

hot leg,

(2) U-bend special interest indications in the cold and hot leg, and

(3) U-bend inspections of cold and hot leg using a +Point probe.

On March 16, 2012, an NRC Augmented Inspection Team was chartered to evaluate the steam generator tube integrity issues at Units 2 and 3. Additional observations and findings associated with the Unit 3 steam generator tube leak and Units 2 and 3 steam generator tube wear issues will be documented in publicly available NRC Inspection Report 05000361; 05000362/2012007.

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.

• January 31, 2010, Unit 3, plant shutdown due to steam generator E088 tube leak Documents reviewed by the inspectors are listed in the attachment.

These activities constitute completion of one inspection sample as defined in Inspection Procedure 71153-05.

b. Findings

On March 16, 2012, an NRC Augmented Inspection Team was chartered to evaluate the steam generator tube integrity issues at Unit 3. Observations and findings associated with this event are documented in NRC Inspection Report 05000361; 05000362/2012007.

.2 Event Report Review

a. Inspection Scope

The inspectors reviewed the below Licensee Event Reports 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.

1. (Closed) Licensee Event Report 05000361; 05000362/2010-006-00, Breakers Left in

Non-Seismically Qualified Condition Result in Condition Prohibited by Technical Specifications

This issue was reviewed by the inspectors and results of the review are documented in Section 4OA7 of this inspection report as licensee identified violations. This licensee event report is closed.

2. (Closed) Licensee Event Report 05000361; 05000362/2011-002-00, Dual Unit Automatic Reactor Trip on High Pressurizer Pressure Due to Grid Disturbance This issue was reviewed by the inspectors, and the results of the review are documented in Section 4OA3 of NRC Inspection Report 05000361; 05000362/2011004, with no findings identified during the review. A violation of minor significance was identified during the review of this event as documented in the licensee event report. Specifically, Technical Specification 3.8.1, AC Sources - Operating, limiting condition for operation requires that AC electrical sources shall be operable in Modes 1 through 4. If one required offsite circuit is inoperable, the required action is to perform Surveillance Requirement 3.8.1.1 for the required operable offsite circuit within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. Contrary to the above, September 8, 2011, following automatic reactor trips on both units due to a grid disturbance, operations personnel failed to verify the remaining offsite circuit within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> as required by Technical Specification 3.8.1. The verification was performed approximately 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> late with satisfactory results. This failure to comply with technical specifications constitutes a violation of minor significance that is not subject to enforcement action in accordance with the NRCs Enforcement Policy. This issue was entered into licensees corrective action program as Nuclear Notification NN 201638629.

This licensee event report is closed.

4OA5 Other Activities

1. Design and Planning Inspections

The inspectors used the guidance in Inspection Procedure 71007, Reactor Vessel Head Replacement Inspection, to perform the following reactor vessel head design and planning inspection activities.

Engineering and Technical Support Inspections were conducted by resident and regional office-based specialist inspectors to review engineering and technical support activities performed prior to, and during, the reactor vessel head replacement outage. This review verified that selected design changes and modifications to structures, systems, and components described in the UFSAR for transporting the new and old reactor vessel heads were reviewed in accordance with 10 CFR Part 50.59. Additionally, key design aspects and modifications associated with the reactor vessel head replacement were also reviewed. Finally, the inspectors determined if the licensee had confirmed that the existing reactor vessel head conformed to design requirements and that there were no fabrication deviations from design requirements.

Lifting and Rigging The inspectors reviewed engineering design, modification, and analysis associated with reactor vessel head lifting and rigging activities. This included:

(1) crane and rigging equipment;

(2) reactor vessel head component drop analysis;

(3) safe load paths; and

(4) load laydown areas.

Radiation Protection The inspectors reviewed radiation protection program controls, planning, and preparation in:

(1) ALARA planning;

(2) dose estimates and tracking;

(3) exposure and contamination controls;

(4) radioactive material management;

(5) radiological work plans and controls;

(6) emergency contingencies; and

(7) project staffing and training plans.

This review was performed as part of the baseline inspections conducted during the

==1R17 outage and additional information is documented in Sections 2RS01 and 2RS02 of this report.

==

2. Reactor Vessel Head Fabrication Inspections at Licensee Facility

The inspectors used the guidance in Inspection Procedure 71007, Reactor Vessel Head Replacement Inspection, to perform the following reactor vessel head fabrication inspection activities.

Heat Treatment The inspectors verified that the material heat treatment used to enhance the mechanical properties of the reactor vessel head material carbon, low alloy, and high alloy chromium steels is conducted per ASME code and approved vendor procedures consistent with the applicable ASME Code, Section III, requirements. Also, inspections were performed to verify that adequate heat treatment procedures were available to assure that requirements associated with the following areas were met:

(1) furnace atmosphere;

(2) furnace temperature distribution and calibration of measuring and recording devices;

(3) thermocouple installation;

(4) heating and cooling rates;

(5) quenching methods; and

(6) record and documentation requirements.

Nondestructive Examination (NDE)

Inspections were conducted to ensure the manufacturing control plan included provisions for monitoring NDE to ascertain that the NDE was performed in accordance with applicable code, material specification, and contract requirements.

Welding The inspectors reviewed the documentation for the weld overlay welding operations that established a layer of stainless steel cladding on the inside of the reactor vessel head to determine if it was accomplished per design. The inspectors also selected a sample of control rod drive mechanism flange-to-nozzle welds and reviewed the following items:

(1) certified mill test reports of the flange, weld material rods, and control rod drive mechanism nozzles;

(2) certified mill test reports for the welding material for the reactor

vessel head cladding;

(3) cladding weld records, weld rod material control requisitions, traceability of weld material rods, weld procedure qualification, welder qualifications, and nonconformance reports;

(4) control rod drive mechanism nozzle cladding welding inspection records, weld rod material control requisitions, traceability of weld material rods, weld procedure qualification, welder qualifications, and nonconformance reports;

(5) control rod drive mechanism to nozzle welding and welds inspection records, weld rod material control requisitions, traceability of weld material rods, weld procedure qualification, welder qualifications, and nonconformance reports; and

(6) NDE procedures, NDE records of the welds, NDE personnel qualifications, and certification of the NDE solvents.

Procedures Inspections were completed to ensure that repair procedures had been established and that these procedures were consistent with applicable ASME code, material specification, and contract requirements by verifying:

(1) repair welding was conducted in accordance with procedures qualified to Section IX of the ASME code;

(2) all welders had been qualified in accordance with Section IX of the ASME code;

(3) records of the repair were maintained; and

(4) that requirements had been established for the preparation of certified material test reports and that the records of all required examinations and tests were traceable to the procedures to which they were performed.

Code Reconciliation The inspectors reviewed the required documentation, supplemental examinations, analysis, and ASME code documentation reconciliation to ensure that the original ASME code N-Stamp remains valid, and that the replacement head complies with appropriate NRC rules and industry requirements. The inspectors also ensured that the design specification was reconciled and a design report was prepared for the reconciliation of the replacement head, verifying that they were certified by professional engineers competent in ASME code requirements.

Quality Assurance Program Inspections were conducted to ensure that:

(1) machining was carried out under a controlled system of operation;

(2) a drawing/document control system was in use in the manufacturing process; and

(3) part identification and traceability was maintained throughout processing and was consistent with the manufacturers quality assurance program. In addition, the inspectors ensured that only the specified drawing and document revisions were available on the shop floor and were being used for fabrication, machining, and inspection.

Compliance Inspection The inspectors verified that the original ASME Code, Section III, data packages for the replacement reactor vessel head were supplemented by documents included in the ASME Code, Section XI, (pre-service inspection) data packages; examined selected manufacturing and inspection records of the finished machined reactor vessel head; and verified compliance with applicable documentation requirements.

3. Reactor Vessel Head Removal and Replacement Inspections

The inspectors used the guidance in Inspection Procedure 71007, Reactor Vessel Head Replacement Inspection, to perform the following reactor vessel head removal and replacement inspection activities:

Lifting and Rigging The inspectors reviewed preparations and procedures for rigging and heavy lifting including crane and rigging inspections, testing, equipment modifications, laydown area preparations, and training for the following activities:

• Area preparation for the outside systems

• Lattice boom crawler crane assembly, disassembly, and operation

• Hydraulic gantry lift system

• Outside bridge and trolley transfer system

• Elevated cantilevered handling device installation and use

• Reactor vessel head lift rig and polar crane

• Downender/upender fixture

• Old reactor vessel head removal

• New reactor vessel head placement

• Transport of old reactor vessel head to storage location Major Structural Modifications The inspectors observed that there were no major structural modifications that were made to facilitate reactor vessel head replacement.

Containment Access and Integrity The inspectors observed there were no modifications to the existing containment access structure or integrity to allow for the reactor vessel head to be removed and installed.

The new and old reactor vessel head were moved in and out of containment using the existing equipment hatch.

Outage Operating Conditions The inspectors reviewed and observed the establishment of operating conditions including:

(1) defueling;

(2) reactor coolant system draindown;

(3) system isolation;

(4) safety tagging;

(5) radiation protection controls;

(6) controls for excluding foreign materials in the reactor vessel;

(7) verification of the suitability of reinstalled (reused)components for use; and

(8) the installation, use, and removal of temporary services.

Section 1R20 of this report documents additional activities that were performed during the outage.

Storage of Removed Reactor Vessel Head The inspectors reviewed the radiological safety plans and observed the transport, storage, and radiological surveys of the old reactor vessel head to its onsite storage location. This review was performed as part of the baseline inspections conducted during the 2R17 outage and additional information is documented in Section 2RS02 of this report.

4. Reactor Vessel Head Post Installation Verification and Testing Inspections The inspectors used the guidance in Inspection Procedure 71007, Reactor Vessel Head Replacement Inspection, to perform the following post installation verification and testing inspection activities. Selective inspections were performed of the following areas:

(1) containment testing;

(2) licensee=s post installation inspections and verifications program and its implementation;

(3) reactor coolant system leakage testing and review of test results;

(4) procedures required for equipment performance testing to confirm the design and to establish baseline measurements; and

(5) preservice inspection of new welds.

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On February 10, 2012, the inspectors presented the inspection results of the review of inservice inspection activities to Mr. D. Bauder, Station Vice President, and other members of the licensee staff. The licensee staff acknowledged the issues presented.

On February 17, 2012, the inspectors presented the results of the radiation safety inspections to Mr. T. McCool, Plant Manager, and other members of the licensee staff. The licensee acknowledged the issues presented.

On April 3, 2012, the inspectors presented the quarterly inspection results to Mr. P. Dietrich, Senior Vice President and Chief Nuclear Officer, 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. All proprietary information identified was handled appropriately.

4OA7 Licensee-Identified Violations

The following Severity Level IV violations and violations of very low safety significance (Green)were identified by the licensee and are violations of NRC requirements which meet the criteria of the NRC Enforcement Policy for being dispositioned as non-cited violations.

1. The inspectors reviewed a Severity Level IV non-cited violation committed by a

radiography boundary guard for leaving his boundary post without approval. San Onofre Nuclear Generating Station Technical Specification 5.5.1.1.a requires procedures to be established, implemented, and maintained covering the applicable procedures recommended by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.

Regulatory Guide 1.33, Quality Assurance Program Requirements (Operation),

Appendix A, Typical Procedures for Pressurized Water Reactors and Boiling Water Reactors, Section 7.e, includes radiation protection procedures for access control to radiation areas. Procedure SO123-VII-20.10.7, Radiography Health Physics Controls, section 6.1.3.2 states that Radiography boundary guard duties are to guard the boundary and prevent personnel from crossing the posted Radiation Area boundary for radiography.

Contrary to the above, on November 29, 2010, a radiography boundary guard did not guard the radiography boundary. Specifically, the radiography boundary guard left the radiography boundary post between radiographic shots without being properly relieved.

This issue was documented in the licensees corrective action program as Nuclear Notification NN 201219666. This violation is being treated as a non-cited violation in accordance with Section 2.3.2 of the NRC Enforcement Policy because the licensee identified the violation and promptly reported it to the NRC, it was an isolated action of an employee in a low-level position without management involvement, it was not caused by a lack of management oversight, and the licensee took appropriate remedial action commensurate with the circumstances.

2. Technical Specifications 3.8.1, AC Sources - Operating, limiting condition for operation

requires that AC electrical sources shall be operable in Modes 1 through 4. Technical Specification 3.8.9, Distributions Systems - Operating, limiting condition for operation requires that AC and DC electrical power distribution systems shall be operable in Modes 1 through 4. If one required offsite circuit is inoperable for greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, or one AC electrical power distribution system is inoperable for greater than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, the required action is to place the unit in Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

Contrary to the above, on September 2, 2010, operations personnel failed to comply with required action of Technical Specification 3.8.9 limiting condition for operation to restore train A Class 1E 4kV bus 3A04 (AC electrical power distribution system) to operable status or place the unit in Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />; and on September 5, 2010, operations personnel failed to comply with required action of Technical Specification 3.8.1 limiting condition for operation to restore bus 3A04 feeder breaker from the reserve auxiliary transformer (AC electrical source) to operable status or place the unit in Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. A Phase 3 evaluation was performed by a senior reactor analyst since the finding screened as potentially risk-significant due to a seismic initiating event. Using the San Onofre SPAR model, the delta-CDF for Bus 3A04 being non-functional was 5.2E-7/yr. The exposure period for this finding was 10.7 days over the TS 3.8.1 AOT and 13.37 days over the TS 3.8.9 allowed outage time. Therefore, this finding was determined to have very low significance (Green). This issue was entered into licensees corrective action program as Nuclear Notification NN 201113611.

3. Technical Specification 3.8.9, Distributions Systems - Operating, limiting condition for

operation requires that AC and DC electrical power distribution systems shall be operable in Modes 1 through 4. If one AC electrical power distribution system is inoperable for greater than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, the required action is to place the unit in Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Contrary to the above, on October 4, 2010, operations personnel failed to comply with required action of Technical Specification 3.8.9 limiting condition for operation to restore train A Class 1E 4kV bus 2A04 (AC electrical power distribution system) to operable status or place the unit in Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. A Phase 3 evaluation was performed by a senior reactor analyst since the finding screened as potentially risk-significant due to a seismic initiating event. Using the San Onofre SPAR model, the delta-CDF for Bus 3A04 being non-functional was 5.2E-7/yr. The exposure period for this finding was 10.7 days over the TS 3.8.1 AOT and 13.37 days over the TS 3.8.9 allowed outage time. Therefore, this finding was determined to have very low significance (Green). This issue was entered into licensees corrective action program as Nuclear Notification NN 201113611.

4. The inspectors reviewed a Severity Level IV problem consisting of two non-cited

violations committed by an instrumentation and control technician for attempting to readjust a potentiometer to its original position without proper documentation and failing to notify the control room of a plant status control error. Technical Specification 5.5.1.1.a requires procedures to be established, implemented, and maintained covering the applicable procedures recommended by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Regulatory Guide 1.33, Quality Assurance Program Requirements (Operation), Appendix A, Typical Procedures for Pressurized Water Reactors and Boiling Water Reactors, Section 1.c, includes typical safety-related activities that should be accomplished in accordance with written procedures, such as equipment control.

Procedure SO123-XV-15 , Maintaining Plant Status Control, Section 6.4.1 requires that plant manipulations are only made via an approved tracking document and Section 6.6.1 requires that the Shift Manager must be informed of any actual or suspected plant status control error.

Contrary to the above, on March 28, 2011, plant manipulations were made without an approved tracking document and the Shift Manager was not informed of an actual plant status control error. Specifically, an Instrumentation and Control technician manipulated the Channel A potentiometer without an approved tracking document and failed to notify the Shift Manager of the plant status error. This was entered into the licensees corrective action program as NN 201393301. The licensee subsequently verified the operability of both Channels A and B and took actions to prevent potential cross-train errors for future instrumentation and control work. This violation is being treated as a non-cited violation in accordance with Section 2.3.2 of the NRC Enforcement Policy because the licensee identified the violation and promptly reported it to the NRC; it was an isolated action of an employee in a low level position without management involvement; it was not caused by a lack of management oversight; and, the licensee took appropriate remedial action commensurate with the circumstances.

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

G. Fausett, ALARA Coordinator, Health Physics

O. Flores, Director, Nuclear Oversight

T. Gallaher, Manager, Corrective Action Program

K. Gallion, Manager, Onsite Emergency Preparedness

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, Senior Director Engineering and Technical Services

M. Lewis, Manager, Health Physics

J. Madigan, Director, Site Recovery

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 Assurance

S. Vaughan, ALARA Manager, Health Physics

D. Yarbrough, Director, Plant Operations

K. Yhip, Project Manager, Regulatory Performance

NRC Personnel

M. Runyan, Senior Reactor Analyst

Attachment 2

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000361/2012002-01 NCV Failure to Maintain Seismic Controls in Safety-Related Areas (Section 1R04)

05000361/2012002-02 NCV Failure to Implement Timely Corrective Actions on Safety-

Related Pumps (Section 1R15)

05000362/2012002-03 NCV Failure to Control Work Activities and Prevent RCS Perturbations (Section 1R20)

Closed

05000361/2010-006 LER Breakers Left in Non-Seismically Qualified Condition Prohibited by

05000362/2010-006 Technical Specifications (Section 4OA3)

05000361/2011-002 LER Dual Unit Automatic Reactor Trip on High Pressurizer Pressure

05000362/2011-002 Due to Grid Disturbance (Section 4OA3)