IR 05000498/2011003

IR 05000498-11-003, 05000499-11-003; on 04/01/2011 06/30/2011; South Texas Project Electric Generating Station, Units 1 and 2, Integrated Resident and Regional Report; Fire Protection; Risk Assessments

ML112160300
Person / Time
Site:	South Texas
Issue date:	08/04/2011
From:	Webb Patricia Walker NRC/RGN-IV/DRP/RPB-A
To:	Halpin E South Texas
References
IR-11-003
Download: ML112160300 (55)

Text

UNIT ED STAT ES NU C LE AR RE G UL AT O RY C O M M I S S I O N

REGION IV

6 12 EAST LAMAR BL VD , S U I T E 4 0 0 A R L I N G T O N , T E X A S 7 6 0 1 1 -41 25 August 4, 2011 EA-11-084 Mr. Edward D. Halpin, President and Chief Executive Officer STP Nuclear Operating Company P.O. Box 289 Wadsworth, TX 77483 Subject: SOUTH TEXAS PROJECT ELECTRIC GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000498/2011003 AND 05000499/2011003

Dear Mr. Halpin:

On June 30, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your South Texas Project Electric Generating Station, Units 1 and 2, facility. The enclosed integrated inspection report documents the inspection findings, which were discussed on July 7, 2011, with Mr. David Rencurrel, Senior Vice President Units 1 and 2, and other members of your staff.

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

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

Based on the results of this inspection, two violations, one NRC-identified and one self-revealing, were evaluated under the significance determination process as having very low safety significance (Green). The NRC has determined that violations are associated with these findings. Additionally, one licensee-identified violation, which was determined to be of very low safety significance, is listed in this report. However, because of the very low safety significance and because they were entered into your corrective action program, the NRC is treating these findings as noncited violations, consistent with Section 2.3.2 of the NRC Enforcement Policy.

If you contest the violations or the significance of the noncited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C.

20555-0001, with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 612 E. Lamar Blvd, Suite 400, Arlington, Texas, 76011-4125; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the facility. In addition, if you disagree with the cross-cutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region IV, and the NRC Resident Inspector at the facility.

STP Nuclear Operating Company -2-In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response, will be made available electronically for public inspection in the NRC Public Document Room or from the NRCs document system (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html. To the extent possible, your response should not include any personal privacy or proprietary, information so that it can be made available to the public without redaction.

Sincerely,

/RA/

Wayne Walker, Chief Project Branch A Division of Reactor Projects Dockets: 50-498 50-499 Licenses: NPF-76 NPF-80

Enclosure:

NRC Inspection Report 05000498/2011003 and 05000499/2011003 w/Attachment: Supplemental Information

REGION IV==

Docket: 05000498, 05000499 License: NPF-76, NPF-80 Report: 05000498/2011003 and 05000499/2011003 Licensee: STP Nuclear Operating Company Facility: South Texas Project Electric Generating Station, Units 1 and 2 Location: FM521 - 8 miles west of Wadsworth Wadsworth, Texas 77483 Dates: April 1 through June 30, 2011 Inspectors: M. Brooks, Physical Security Inspector K. Clayton, Senior Operations Engineer J. Dixon, Senior Resident Inspector J. Dykert, Project Engineer P. Jayroe, Project Engineer B. Tharakan, CHP, Resident Inspector Approved By: Wayne Walker, Chief, Project Branch A Division of Reactor Projects-1- Enclosure

SUMMARY OF FINDINGS

IR 05000498/2011003, 05000499/2011003; 04/01/2011 - 06/30/2011; South Texas Project

Electric Generating Station, Units 1 and 2, Integrated Resident and Regional Report; Fire Protection; Risk Assessments.

The report covered a 3-month period of inspection by resident inspectors and an announced baseline inspection by a region based inspector. Two Green noncited violations, one NRC-identified and one self-revealing, of very low safety 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 NRCs 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 noncited violation of 10 CFR 50.65(a)(4) for the failure to perform an adequate risk assessment to manage the increase in risk of performing activities in the switchyard. On September 26, 2010, the licensee removed 345 kVac circuit breaker Y530 from service for planned replacement. The replacement activities were performed by a contractor, however, the details of the work package were not provided to the licensee nor were they discussed. As a result of incorrect terminations, on September 30, 2010, when the work was completed and the contractors were performing testing, a false differential condition was sensed resulting in all the north bus breakers opening. This resulted in a loss of power to the standby transformer for Unit 1, de-energizing the train B engineered safety features bus.

The loss of offsite power to the train B bus resulted in an engineered safety features actuation that started the train B standby diesel generator and actuated train B safety-related equipment. The licensees corrective actions included:

(1) revising the switchyard management procedure to provide more detailed instructions for utilizing the switchyard coordinator in providing oversight and directing of switchyard activities; (2) specific instructions as to points of contact, details of switchyard work to be performed; and (3) specifying coping strategies and integrating the work control process with the management of switchyard activities.

This finding was more than minor because it affected the Initiating Events Cornerstone attribute of protection against external factors and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. This deficiency directly resulted in loss of offsite power to the train B engineered safety features bus. The inspectors performed the significance determination using NRC Inspection Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings, dated January 10, 2008, because it affected the Initiating Events Cornerstone while the plant was at power. Because the finding affects the licensees assessment and management of risk the Phase 1 worksheet sent the inspectors to Attachment K, Maintenance Risk Assessment and Risk Management Significance Determination Process, dated May 19, 2005. This finding was determined to be of very low safety significance because it only impacted performance of risk managed actions not taken and the incremental core damage probability risk assessment increase of 6.3 E-13 was less than the 1 E-6 threshold. In addition, this finding had human performance cross-cutting aspects associated with work practices in that the licensee did not ensure supervisory and management oversight of work activities, including contractors, such that nuclear safety is supported H.4(c)(Section 1R13).

Cornerstone: Mitigating Systems

Green.

The inspectors identified a noncited violation of license condition 2.E,

Fire Protection Program, because of an inadequate procedure that resulted in the licensee failing to establish compensatory fire watches in eight fire zones with degraded fire detection equipment. On March 2, 2011, the inspectors reviewed fire impairments to ensure adequate compensatory actions were being implemented. The inspectors identified that fire watches were not implemented in several areas where the fire detection system was degraded because Procedure 0PGP03-ZF-0018, Fire Protection System Functionality Requirements, Revision 14, did not require a fire watch until greater than 50 percent of the fire detection functionality within the fire zone was degraded.

The inspectors determined that the licensee failed to correctly copy the licensing basis NUREG-0452 technical specification requirements into the procedure. The licensees corrective actions included: (1) posting an hourly fire watch; (2) changing the procedure to correctly reflect licensing basis requirements; and (3) providing training to fire safety and operations personnel.

The finding was more than minor because it was associated with the Mitigating Systems Cornerstone attribute of procedure quality and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences, because the lack of compensatory measures could result in a delayed response to a fire. The inspectors performed the significance determination using NRC Inspection Manual Chapter 0609, Appendix F, dated February 28, 2005, because the finding affected fire protection defense-in-depth strategies, as described in NRC Inspection Manual Chapter 0609.04, Table 3b, Phase 1 - Initial Screening and Characterization of Findings, dated January 10, 2008. The finding was assigned to the fixed fire protection systems category with a degradation rating of moderate because compensatory measures were not in place for unoccupied fire areas that had greater than 10 percent degradation of fire detection equipment.

Because the finding was a programmatic weakness where multiple fire areas lacked compensatory measures and it had a moderate degradation rating, the finding required a Phase 3 analysis be performed by a senior reactor analyst.

The senior reactor analyst determined that the finding was of very low safety significance because there were no identified dominant core damage sequences, and, therefore, there was no quantifiable change to the core damage frequency.

The functional fire detectors helped to mitigate the risk. This finding did not have cross-cutting aspects because the licensee had not made changes to this procedural requirement within the last 3 years, and therefore, was not indicative of current licensee performance (Section 1R05).

Licensee-Identified Violations

A violation of very low safety significance, which was identified by the licensee, has been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. This violation and corrective action tracking numbers (condition report numbers) are listed in Section 4OA7.

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at 100 percent rated thermal power and remained there until April 2, 2011, when the unit shut down for Refueling Outage 1RE16. Unit 1 commenced a reactor start up (Mode 2) and started to raise reactor power (Mode 1) on May 7, 2011. The unit shut the main generator output breaker on May 8, 2011, and achieved 100 percent rated thermal power on May 10, 2011. The unit remained there until May 14, 2011, when a loss of a low pressure heater drip pump caused the unit to reduce power to 89 percent rated thermal power. The unit returned to 100 percent rated thermal power on May 15, 2011, and remained there for the remainder of the inspection period.

Unit 2 began the inspection period at 100 percent rated thermal power and remained there for the remainder of the period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness

1R01 Adverse Weather Protection

.1 Summer Readiness for Offsite and Alternate-ac Power

a. Inspection Scope

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

Coordination between the transmission system operator and the plants operations personnel during off-normal or emergency events Explanations for the events Estimates of when the offsite power system would be returned to a normal state Notifications from the transmission system operator to the plant when the offsite power system was returned to normal During the inspection, the inspectors focused on plant-specific design features and the procedures used by plant personnel to mitigate or respond to adverse weather conditions. Additionally, the inspectors reviewed the Updated Final Safety Analysis Report and performance requirements for systems selected for inspection, and verified

that operator actions were appropriate as specified by plant-specific procedures.

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

The inspectors reviews focused specifically on the following plant systems:

June 30, 2011, Units 1 and 2, 13.8 kVac unit auxiliary and standby transformers, 4160 Vac engineered safety features transformers, and standby diesel generators trains A, B, and C These activities constitute completion of one readiness for summer weather affect on offsite and alternate-ac power sample as defined in Inspection Procedure 71111.01-05.

b. Findings

No findings were identified.

.2 Readiness to Cope with External Flooding

a. Inspection Scope

During the week of April 18, 2011, the inspectors evaluated the design, material condition, and procedures for coping with the design basis probable maximum flood.

The evaluation included a review to check for deviations from the descriptions provided in the Updated Final Safety Analysis Report for features intended to mitigate the potential for flooding from external factors. As part of this evaluation, the inspectors checked for obstructions that could prevent draining, checked that the roofs did not contain obvious loose items that could clog drains in the event of heavy precipitation, and determined that barriers required to mitigate the flood were in place and operable.

Additionally, the inspectors performed an inspection of the protected area to identify any modification to the site that would inhibit site drainage during a probable maximum precipitation event or allow water ingress past a barrier. The inspectors also reviewed the abnormal operating procedure for mitigating the design basis flood to ensure it could be implemented as written. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one external flooding sample as defined in Inspection Procedure 71111.01-05.

b. Findings

No findings were identified.

1R04 Equipment Alignments

.1 Partial Walkdown

a. Inspection Scope

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

April 15, 2011, Unit 2, standby diesel generator 22 train B April 15, 2011, Unit 2, essential chilled water system train B June 15, 2011, Unit 1, auxiliary feedwater system train A June 21, 2011, Unit 1, safety injection system train A 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, Updated Final Safety Analysis Report, 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 four partial system walkdown samples as defined in Inspection Procedure 71111.04-05.

b. Findings

No findings were identified.

.2 Complete Walkdown

a. Inspection Scope

On April 28, 2011, the inspectors performed a complete system alignment inspection of the Unit 1 train A residual heat removal system 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 lineups, 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.

.3 System Walkdown Associated with Temporary Instruction 2515/177, Managing Gas

Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems

a. Inspection Scope

On April 28, 2011, the inspectors conducted a walkdown of Unit 1 train A residual heat removal system in sufficient detail to reasonably assure the acceptability of the licensees walkdowns (Temporary Instruction 2515/177, Section 04.02.d). The inspectors also verified that the information obtained during the licensees walkdown was consistent with the items identified during the inspectors independent walkdown (Temporary Instruction 2515/177, Section 04.02.c.3).

In addition, the inspectors verified that the licensee had isometric drawings that describe the residual heat removal system configurations and had acceptably confirmed the accuracy of the drawings (Temporary Instruction 2515/177, Section 04.02.a). The inspectors verified the following related to the isometric drawings:

High point vents were identified High points that do not have vents were acceptably recognizable Other areas where gas can accumulate and potentially impact subject system operability, such as at orifices in horizontal pipes, isolated branch lines, heat exchangers, improperly sloped piping, and under closed valves were acceptably described in the drawings or in referenced documentation Horizontal pipe centerline elevation deviations and pipe slopes in nominally horizontal lines that exceed specified criteria were identified All pipes and fittings were clearly shown

The drawings were up-to-date with respect to recent hardware changes and that any discrepancies between as-built configurations and the drawings were documented and entered into the corrective action program for resolution The inspectors verified that piping and instrumentation diagrams accurately described the subject systems; that they were up-to-date with respect to recent hardware changes; and any discrepancies between as-built configurations, the isometric drawings, and the piping and instrumentation diagrams were documented and entered into the corrective action program for resolution (Temporary Instruction 2515/177, Section 04.02.b).

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

This inspection effort counts toward the completion of Temporary Instruction 2515/177, which will be closed in a later inspection report.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 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:

April 15, 2011, Unit 2, electrical auxiliary building electrical penetration areas trains A, B, and C, fire zones Z006, Z031, and Z046 April 15, 2011, Unit 2, isolation valve cubicle train C, fire zones Z403 and Z406 June 1, 2011, Unit 1, control room envelope heating, ventilation, and air conditioning room train C, fire zone Z049 June 1, 2011, Unit 2, control room envelope heating, ventilation, and air conditioning room train C, fire zone Z049 The inspectors reviewed areas to assess if licensee personnel had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant; effectively maintained fire detection and suppression capability; maintained passive fire protection features in good material condition; and had implemented adequate compensatory measures for out of service, degraded or inoperable fire protection equipment, systems, or features, in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to affect equipment that could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. Using the

documents listed in the attachment, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees corrective action program.

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

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

b. Findings

Introduction.

The inspectors identified a noncited violation of license condition 2.E for an inadequate fire protection program Procedure 0PGP03-ZF-0018, Fire Protection System Functionality Requirements, Revision 14, because the procedure did not require compensatory measures be implemented for degraded fire detection equipment.

Description.

On March 2, 2011, the inspectors reviewed the licensees compensatory actions for fire impairments and the procedures requiring implementation of compensatory actions. The inspectors interviewed licensee fire safety personnel about why there were no compensatory actions implemented for the degraded fire detection equipment for the respective fire impairments. The licensee explained that according to Procedure 0PGP03-ZF-0018 a fire watch was not required to be implemented until greater than 50 percent of the fire detection equipment in any fire zone was degraded.

The inspectors inquired further to understand the basis for the 50 percent criteria. The licensee stated that the fire protection program was implemented in accordance with Chapter 9 of the licensees Updated Final Safety Analysis Report which stated the fire protection program implemented the requirements of NUREG-0452, Revision 5. The inspectors reviewed the Updated Final Safety Analysis Report, Procedure 0PGP03-ZF-0018, and NUREG-0452, Standard Technical Specifications for Westinghouse Pressurized Water Reactors, Revision 5. NUREG-0452 required that with any, but not more than half of the total fire detection equipment in any fire zone inoperable, restore the inoperable equipment to operable status within 14 days or within the next hour establish a fire watch patrol to inspect the zones at least once per hour.

Procedure 0PGP03-ZF-0018, required that if the minimum number of operable detection instruments was less than the minimum in Addendum 4 of the procedure, then within the hour establish a fire watch. The minimum number listed in Addendum 4 was 50 percent of the total, and, therefore, was not similar to the licensing basis requirement.

The inspectors determined that Procedure 0PGP03-ZF-0018, Fire Protection System Functionality Requirements, Revision 14, was not adequate because it failed to correctly incorporate the licensing basis requirements of NUREG-0452. The inspectors determined that this error took place during the transition of requirements from technical specifications to licensee procedures and has been in the licensees procedure since Revision 0, which was issued on December 11, 1986. The licensees corrective actions included posting an hourly fire watch; changing the procedure to correctly reflect

licensing basis requirements; and providing training to fire safety and operations personnel.

Analysis.

The failure to copy the licensing basis requirement to implement compensatory actions for degraded fire detection equipment into fire protection program procedures was a performance deficiency. The finding was more than minor because it was associated with the Mitigating Systems Cornerstone attribute of procedure quality and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences because the lack of compensatory measures could result in a delayed response to a fire.

The inspectors performed the significance determination using NRC Inspection Manual Chapter 0609, Appendix F, dated February 28, 2005, because the finding affected fire protection defense-in-depth strategies, as described in NRC Inspection Manual Chapter 0609.04, Table 3b, Phase 1 - Initial Screening and Characterization of Findings, dated January 10, 2008. The finding was assigned to the fixed fire protection systems category with a degradation rating of moderate because compensatory measures were not in place for unoccupied fire areas that had greater than 10 percent degradation of fire detection equipment. Because the finding was a programmatic weakness where multiple fire areas lacked compensatory measures, and it had a moderate degradation rating, the finding required a Phase 3 analysis be performed by a senior reactor analyst. The analyst used Inspection Manual Chapter 0609, Appendix F, to evaluate the significance of the performance deficiency. The finding involved the failure to take the required compensatory measure in response to multiple nonfunctional fire detectors in multiple areas of the plant. The required compensatory measure was an hourly roving fire watch and the exposure period was the maximum period of 1 year for any given fire area. The failure to establish the hourly fire watch had the potential to impact the fire nonsuppression probability because the identification and response to a fire could be delayed. The fire detector failures were not part of this performance deficiency. Therefore, the analyst evaluated the difference in risk between establishing the hourly watch, as required, and not implementing the fire watch requirement for 1 year.

Only one step in the Appendix F significance determination process (step 2.7) had the potential to make a quantitative change to the core damage frequency from the failure to establish the hourly fire watch. Appendix F, Attachment 8, Guidance for Fire Non-Suppression Probability Analysis, Section 2.7.1, Fire Detection Analysis, stipulated that the time for fire detection from a roving fire watch should be half of the fire watch duration. For a 1-hour roving fire watch, this duration would be 30 minutes.

However, the significance determination process assumes that absence of any other means of detection, a maximum fire detection time of 15 minutes will be assumed (see page F8-3). That means that other plant personnel would likely identify the fire in approximately 15 minutes - even without the establishment of the hourly fire watch.

Consequently, there was no quantifiable increase to the core damage frequency from the performance deficiency. Therefore, the finding was of very low safety significance (Green). Nonetheless, the fire watches clearly provided some unquantifiable added protection against fires. Since there was no quantifiable change to the core damage frequency, there were no identified dominate core damage sequences. The functional fire detectors help to mitigate the risk. This finding did not have cross-cutting aspects

because the licensee had not made changes to this procedural requirement within the last 3 years, and, therefore, was not indicative of current licensee performance.

Enforcement.

South Texas Project Nuclear Operating Company, Units 1 and 2, license condition 2.E, requires, in part, that the licensee implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report. Chapter 9, Section 9.5.1.6.1 of the Updated Final Safety Analysis Report, Revision 15, required, in part, that the functional capability of the fire protection systems required to protect safe shutdown capability is assured through implementation of an administrative program equivalent to the requirements of NUREG-0452, Standard Technical Specifications for Westinghouse Pressurized Water Reactors, Revision 5.

Technical Specification 3.3.3.8, required, in part, that with any but not more than one-half of the total in any fire zone, restore the inoperable fire detection instrument to operable status within 14 days or within the next 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> establish a fire watch patrol.

Contrary to the above, on March 2, 2011, the inspectors identified that licensee Procedure 0PGP03-ZF-0018, Fire Protection System Functionality Requirements, Revision 14, failed to implement the requirement to establish a fire watch patrol when any required fire detection instrument was inoperable. Since the violation was of very low safety significance and was documented in the licensees corrective action program as Condition Report 11-2003, it is being treated as a noncited violation consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000498/2011003-01 and 05000499/2011003-01, Inadequate Fire Protection System Functionality Procedure Results in Failure to Establish Fire Watches.

.2 Annual Fire Protection Drill Observation

a. Inspection Scope

On June 28, 2011, the inspectors observed a fire brigade activation for a simulated fire in the Unit 1 train C safety-related switchgear room in the electrical auxiliary building 60 foot elevation. The observation evaluated the readiness of the plant fire brigade to fight fires. The inspectors verified that the licensee staff identified deficiencies, openly discussed them in a self-critical manner at the drill debrief, and took appropriate corrective actions. Specific attributes evaluated were:

(1) proper wearing of turnout gear and self-contained breathing apparatus;

(2) proper use and layout of fire hoses;

(3) employment of appropriate firefighting techniques;

(4) sufficient firefighting equipment brought to the scene;

(5) effectiveness of fire brigade leader communications, command, and control;

(6) search for victims and propagation of the fire into other plant areas;

(7) smoke removal operations;

(8) utilization of preplanned strategies;

(9) adherence to the preplanned drill scenario; and

(10) drill objectives.

These activities constitute completion of one annual fire protection inspection sample as defined in Inspection Procedure 71111.05-05.

b. Findings

No findings were identified.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors reviewed the Updated Final Safety Analysis Report, the flooding analysis, and plant procedures to assess susceptibilities involving internal flooding; reviewed the corrective action program to determine if licensee personnel identified and corrected flooding problems; inspected underground bunkers/manholes to verify the adequacy of sump pumps, level alarm circuits, cable splices subject to submergence, and drainage for bunkers/manholes; and verified that operator actions for coping with flooding can reasonably achieve the desired outcomes. The inspectors also inspected the areas listed below to verify the adequacy of equipment seals located below the flood line, floor and wall penetration seals, watertight door seals, common drain lines and sumps, sump pumps, level alarms, and control circuits, and temporary or removable flood barriers.

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

May 19, 2011, Units 1 and 2, Class 1E electrical manholes June 30, 2011, Unit 2, standby diesel generator building These activities constitute completion of one flood protection measures inspection sample and one bunker/manhole sample as defined in Inspection Procedure 71111.06-05.

b. Findings

No findings were identified.

1R08 In-service Inspection Activities

Completion of Sections

.1 through .5, below, constitutes completion of one sample as

defined in Inspection Procedure 71111.08-05.

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

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

a. Inspection Scope

The inspectors observed three nondestructive examination activities and reviewed seven nondestructive examination activities that included two types of examinations.

The licensee did not identify any relevant indications accepted for continued service during the nondestructive examinations.

The inspectors directly observed the following nondestructive examinations:

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Feedwater 18-FW-1029-AA2 (lugs) Magnetic Particle Reactor Coolant 12-RC-1125.8 - BB1 (pipe) Ultrasonic

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Reactor Coolant 12-RC-1221.13 - BB1 (pipe) Ultrasonic The inspectors reviewed records for the following nondestructive examinations:

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Reactor Coolant PZR Relief Nozzle to Shell (N4A) Ultrasonic Reactor Coolant PZR Nozzle Radius (N4A) Ultrasonic Reactor Coolant PZR Relief Nozzle to Shell (N4B) Ultrasonic Reactor Coolant PZR Nozzle Radius (N4B) Ultrasonic 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 the qualifications of all nondestructive examination technicians performing the inspections were current.

The inspectors reviewed two welds on the reactor coolant system pressure boundary.

The inspectors reviewed records for the following welding activities:

SYSTEM WELD IDENTIFICATION WELD TYPE Reactor Coolant RC-053B valve replacement Gas Tungsten Arc Reactor Coolant RC-071C valve replacement Gas Tungsten Arc 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 process were identified, recorded in the procedure qualification record, and formed the bases for qualification of the welding procedure specifications. Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements for Section 02.01.

b. Findings

No findings were identified.

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

a. Inspection Scope

The licensee was not required to inspect the reactor vessel head under ASME Code Case N-729-1 because it was replaced during the last outage.

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 0PGP03-ZE-0033, Revision 12. 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

The inspectors assessed the in situ screening criteria to assure consistency between assumed nondestructive examination flaw sizing accuracy and data from the EPRI examination technique specification sheets. No conditions were identified that warranted in situ pressure testing.

Because no new damage mechanisms have been found in the steam generators, a 50 percent review of all tubes in all four steam generators was performed during this outage. In addition, the inspectors reviewed both the licensee site-validated and qualified acquisition and analysis technique sheets used during this refueling outage and the qualifying EPRI examination technique specification sheets to verify that the essential variables regarding flaw sizing accuracy, tubing, equipment, technique, and analysis had been identified and qualified through demonstration.

The inspection procedure specified comparing the estimated size and number of tube flaws detected during the current outage against the previous outage operational assessment predictions to assess the licensees prediction capability. The number of identified indications fell within the range of prediction and was consistent with

predictions from the vendor for the previous outage. The licensee had not plugged any tubes during this outage when the inspectors exited this inspection on April 15, 2011.

The inspection procedure specified confirmation that the steam generator tube eddy current test scope and expansion criteria meet technical specification requirements, EPRI guidelines, and commitments made to the NRC. The inspectors evaluated the recommended steam generator tube eddy current test scope established by technical specification requirements and the licensees degradation assessment report. The inspectors compared the recommended test scope to the actual test scope and found that the licensee had accounted for all known flaws and had, as a minimum, established a test scope that met technical specification requirements, EPRI guidelines, and commitments made to the NRC. Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements of Section 02.04.

b. Findings

No findings were identified.

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

a. Inspection scope

The inspectors reviewed 18 condition reports which dealt with inservice inspection activities and found the corrective actions for inservice inspection issues were appropriate. The specific condition reports 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 June 8, 2011, the inspectors observed a crew of licensed operations personnel in the plants simulator to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

Licensed operator performance Crews clarity and formality of communications Crews ability to take timely actions in the conservative direction Crews prioritization, interpretation, and verification of annunciator alarms Crews correct use and implementation of abnormal and emergency procedures Control board manipulations Oversight and direction from supervisors Crews ability to identify and implement appropriate technical specification actions and emergency plan actions and notifications The inspectors compared the crews performance in these areas to pre-established operator action expectations and successful critical task completion requirements.

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:

June 30, 2011, Units 1 and 2, fire protection system 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 licensees actions to address system performance or condition problems in terms of the following:

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

Characterizing system reliability issues for performance

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

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

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

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

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed licensee personnels 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:

November 25, 2010, Unit 1, switchyard work on the north bus resulting in a loss of power to the standby transformer April 1 through May 8, 2011, Unit 1, Refueling Outage 1RE16, including review of Operating Experience Smart Sample (OpESS) FY2007-03, Crane and Heavy Lift Inspection, supplemental guidance for Inspection Procedure 71111.20 Week of June 6, 2011, Unit 1, planned activities on train B including entering the configuration risk management program for exceeding the front stop on inverter 1203, and Unit 2 planned activities on train A resulting in Yellow risk assessment

Week of June 13, 2011, Unit 1, planned activities on train C resulting in Yellow risk assessment, and working on a degraded steam generator power operated relief valve on train B resulting in cross-train work, and Unit 2 planned activities on train B 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 licensees 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 four maintenance risk assessments and emergent work control inspection samples as defined in Inspection Procedure 71111.13-05.

b. Findings

Introduction.

The inspectors reviewed a self-revealing Green noncited violation of 10 CFR 50.65(a)(4) for the failure to perform an adequate risk assessment to manage the increase in risk of performing activities in the switchyard.

Description.

On September 26, 2010, the licensee removed 345 kVac circuit breaker Y530 from service for planned replacement. The replacement activities were performed by a contractor with approved work scope by the licensee. However, the details of the work package were not provided to the licensee nor were they discussed.

While lifting the old breaker from its foundation an associated termination box was damaged. During the installation of the new termination box the contractor reinstalled two of the electrical wires incorrectly. The replacement of the termination box was not within the scope of the original work plan, but became necessary when it was damaged.

The contractors did not communicate this change in work scope to either their supervision or the licensee and since neither the contractor nor the licensee had someone supervising the activities, the termination box was replaced without knowledge of the contractors supervision or the licensees switchyard coordinator.

As a result of the incorrect terminations, on September 30, 2010, when the work was completed and the contractors were performing testing a false differential condition was sensed resulting in all the north bus breakers opening. This resulted in a loss of power to the standby transformer for Unit 1, de-energizing the train B engineered safety features bus. The loss of offsite power to the train B bus resulted in a loss of offsite power engineered safety features bus actuation and starting the train B standby diesel generator and automatic actuation of train B safety-related equipment. All equipment

functioned as expected and required. The north bus was restored in approximately 5 minutes and the standby transformer for Unit 1 was restored in approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

The licensee performed a root cause and determined that their procedure for managing switchyard activities, Procedure 0PGP03-XS-0001, Switchyard Management, Revision 0, was not being followed properly and should be enhanced in other areas to more clearly define roles and expectations. The licensees corrective actions included:

revising the switchyard management procedure to provide more detailed instructions for utilizing the switchyard coordinator in providing oversight and directing of switchyard activities, specific instructions as to points of contact, details of switchyard work to be performed, and specifying coping strategies and integrating the work control process with the management of switchyard activities.

Analysis.

The failure to perform an adequate risk assessment for managing maintenance activities in the switchyard was a performance deficiency. This finding was more than minor because it affected the Initiating Events Cornerstone attribute of protection against external factors and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. This deficiency directly resulted in loss of offsite power to the train B engineered safety features bus. The inspectors performed the significance determination using NRC Inspection Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings, dated January 10, 2008, because it affected the Initiating Events Cornerstone while the plant was at power. Because the finding affects the licensees assessment and management of risk the Phase 1 worksheet sent the inspectors to Attachment K, Maintenance Risk Assessment and Risk Management Significance Determination Process, dated May 19, 2005. This finding was determined to be of very low safety significance (Green) because it only impacted performance of risk managed actions not taken and the incremental core damage probability risk assessment increase of 6.3 E-13 was less than the 1 E-6 threshold. In addition, this finding had human performance cross-cutting aspects associated with work practices in that the licensee did not ensure supervisory and management oversight of work activities, including contractors, such that nuclear safety is supported H.4(c).

Enforcement.

Title 10 CFR 50.65(a)(4), requires, in part, that before performing maintenance activities, the licensee shall assess and manage the increase in risk from the proposed activities. The licensee uses Procedure 0PGP03-XS-0001, Switchyard Management, Revision 0, to assess and manage the risk from switchyard activities.

Contrary to this, on September 30, 2010, during online maintenance, Procedure 0PGP03-XS-0001 was not adequately followed, it also did not provide adequate risk assessment and management, resulting in an inadequate risk assessment of activities which resulted in de-energizing the north bus in the switchyard, which resulted in a loss of power to the standby transformer for Unit 1, and subsequently the train B engineered safety features bus. Since this violation was of very low safety significance and was documented in the licensees corrective action program as Condition Report 10-21452, it is being treated as a noncited violation consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000498/2011003-02, Inadequate Risk Assessment for Switchyard Activities.

1R15 Operability Evaluations

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

April 19, 2011, Unit 1, control rod drive mechanism o-rings missing from some connectors at the disconnect plate, and messenger cables that had turnbuckle assemblies with loose and missing hardware April 20, 2011, Unit 1, residual heat removal pump 1C after dropping a face shield into the reactor cavity that was drawn into the suction of the pump May 3, 2011, Units 1 and 2, reactor coolant system after identification of formation of metaborite in the train C residual heat removal system of Unit 1 May 5, 2011, Unit 1, residual heat removal system pump 1A suction piping from reactor coolant system loop 1 in contact with biological shield penetration sleeve May 6, 2011, Unit 1, metaborite formation in train C residual heat removal system hot leg injection creates potential void June 30, 2011, Units 1 and 2, 4160 Vac and 480 Vac maximum voltage limits to ensure operability of safety related systems The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that technical specification operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the technical specifications and Updated Final Safety Analysis Report to the licensee personnels evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors also 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 six operability evaluations inspection samples as defined in Inspection Procedure 71111.15-05.

b. Findings

No findings were identified.

.2 Operability Evaluations Associated with Temporary Instruction 2515/177, Managing

Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems

a. Inspection Scope

The inspectors reviewed the following issue associated with the scope of Generic Letter 2008-01, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems.

May 6, 2011, Unit 1, metaborite formation in train C residual heat removal system hot leg injection creates potential void The inspectors verified that the licensee has acceptably identified the gas intrusion mechanisms that apply to the licensees plant. If the licensees evaluation was incomplete, the inspectors verified that corrective actions were placed into the corrective action program (Temporary Instruction 2515/177, Section 04.02.e).

In addition, the inspectors verified that the licensees void acceptance criteria were consistent with the Office of Nuclear Reactor Regulations void acceptance criteria.

If the void acceptance criteria were not met, then the inspectors verified that the licensee has justified the deviations. Also, the inspectors confirmed that:

(1) the licensee addressed the effect of pressure changes during system start up and operation since such changes could significantly affect the void fraction from the initial value; and

(2) the range of flow conditions evaluated by the licensee was consistent with the full range of design basis and expected flow rates for various break sizes and locations (Temporary Instruction 2515/177, Section 04.02.f). Specific documents reviewed during this inspection are listed in the attachment.

This inspection effort counts toward the completion of Temporary Instruction 2515/177, which will be closed in a later inspection report.

b. Findings

No findings were identified.

1R18 Plant Modifications

.1 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:

April 13, 2011, Unit 1, temporary power to spent fuel pool cooling water pump 1B

April 30, 2011, Unit 1, temporary thermocouples installed on train C safety injection hot leg injection piping to monitor temperatures for boric acid crystal formation that was discovered in residual heat removal train C pump suction The inspectors reviewed the temporary modifications and the associated safety-evaluation screening against the system design bases documentation, including the Updated Final Safety Analysis Report 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. Specific documents reviewed during this inspection are listed in the attachment.

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.

.2 Permanent Modifications

a. Inspection Scope

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

April 30, 2011, Unit 1, design change packages to remove insulation from the train C safety injection hot leg injection piping, and to install a manual isolation valve into the safety injection test header to minimize the potential for the formation of boric acid crystals like were discovered in the residual heat removal train C pump suction May 6, 2011, Unit 1, design change package to ensure that the steam generator power operated relief valves fail closed on a loss of power The inspectors verified that modification preparation, staging, and implementation did not impair emergency/abnormal operating procedure actions, key safety functions, or operator response to loss of key safety functions; postmodification testing will maintain the plant in a safe configuration by verifying that unintended system interactions will not occur; systems, structures, and components performance characteristics still meet the design basis; the modification design assumptions were appropriate; the modification

test acceptance criteria will be met; and licensee personnel identified and implemented appropriate corrective actions associated with permanent plant modifications. Specific documents reviewed during this inspection are listed in the attachment.

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

b. Findings

No findings were identified.

.3 Permanent Plant Modifications Associated with Temporary Instruction 2515/177,

Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems

a. Inspection Scope

The following engineering design package associated with the scope of Generic Letter 2008-01, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems, was reviewed and selected aspects were discussed with engineering personnel:

April 30, 2011, Unit 1, design change packages to remove insulation from the train C safety injection hot leg injection piping, and to install a manual isolation valve into the safety injection test header to minimize the potential for the formation of boric acid crystals similar to those discovered in the residual heat removal train C pump suction The inspectors verified that the licensing basis verification documents have either been updated or are in the process of being updated to reflect the modifications associated with the licensees resolution of Generic Letter 2008-01 (Temporary Instruction2515/177, Section 04.01). The verified documents included technical specifications, technical specification bases, Updated Final Safety Analysis Report, and licensee controlled documents and bases, such as the Technical Requirements Manual.

In addition, the inspectors verified that the drawings were up-to-date with respect to recent hardware changes and that any discrepancies between as-built configurations and the drawings were documented and entered into the corrective action program for resolution (Temporary Instruction 2515/177, Section 04.02.a.6).

Similarly, the inspectors verified that piping and instrumentation diagrams accurately described the subject systems, that they were up-to-date with respect to recent hardware changes, and any discrepancies between as-built configurations, the isometric drawings, and the piping and instrumentation diagrams were documented and entered into the corrective action program for resolution (Temporary Instruction 2515/177, Section 04.02.b).

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

This inspection effort counts toward the completion of Temporary Instruction 2515/177, which will be closed in a later inspection report.

b. Findings

No findings were identified.

1R19 Postmaintenance Testing

a. Inspection Scope

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

April 26, 2011, Unit 2, control room emergency ventilation train B makeup filtration unit damper failed to stroke close May 6, 2011, Unit 1, turbine-driven auxiliary feedwater pump 14 major overhaul including turbine rotor replacement May 12, 2011, Unit 1, standby diesel generator 12 following ultra low sulfur fuel injector pumps o-ring replacement The inspectors selected these activities based upon the structure, system, or components 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 Updated Final Safety Analysis Report, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with postmaintenance 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 three postmaintenance testing inspection samples as defined in Inspection Procedure 71111.19-05.

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

The inspectors reviewed the outage safety plan and contingency plans for the Unit 1 Refueling Outage 1RE16, conducted April 3 through May 8, 2011, 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 operations personnel 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 Start up and ascension to full power operation, tracking of start up 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.

These activities constitute completion of one refueling outage and other outage inspection sample as defined in Inspection Procedure 71111.20-05.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the Updated Final Safety Analysis Report, procedure requirements, and technical specifications to ensure that the surveillance activities listed below demonstrated that the systems, structures, and/or components tested were capable of performing their intended safety functions. The inspectors either witnessed or reviewed test data to verify that the significant surveillance test attributes were adequate to address the following:

Preconditioning Evaluation of testing impact on the plant Acceptance criteria Test equipment Procedures Jumper/lifted lead controls Test data Testing frequency and method demonstrated technical specification operability Test equipment removal Restoration of plant systems Fulfillment of ASME Code requirements Updating of performance indicator data

Engineering evaluations, root causes, and bases for returning tested systems, structures, and components not meeting the test acceptance criteria were correct Reference setting data Annunciators and alarms setpoints The inspectors also verified that licensee personnel identified and implemented any needed corrective actions associated with the surveillance testing.

April 27, 2011, Unit 1, residual heat removal pump 1C comprehensive test reference value measurement for inservice testing May 1, 2011, Unit 1, containment emergency sump 1B to safety injection train B pumps suction outside reactor containment isolation valve 1-SI-MOV-0016B May 16, 2011, Unit 1, reactor coolant system leakage detection following Refueling Outage 1RE16 June 7, 2011, Unit 1, 125 Vdc Class 1E B train battery June 27, 2011, Unit 2, standby diesel generator 23 Specific documents reviewed during this inspection are listed in the attachment.

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

b. Findings

No findings were identified.

1EP6 Drill Evaluation

Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on June 22, 2011, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the simulator, technical support center, and the operations support center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures.

The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying

weaknesses and entering them into the corrective action program. As part of the inspection, the inspectors reviewed the drill package.

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

b. Findings

No findings were identified.

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 first 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 1 and 2 for the period from the second quarter 2010 through the first 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 April 2010 through March 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 during this inspection are described in the attachment.

These activities constitute completion of one unplanned scrams per 7000 critical hours sample per unit as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.3 Unplanned Scrams with Complications (IE02)

a. Inspection Scope

The inspectors sampled licensee submittals for the unplanned scrams with complications performance indicator for Units 1 and 2 for the period from the second quarter 2010 through the first 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 April 2010 through March 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 during this inspection are described in the attachment.

These activities constitute completion of one unplanned scrams with complications sample per unit as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.4 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 1 and 2 for the period from the second quarter 2010 through the first 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 April 2010 through March 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 during this inspection are described in the attachment.

These activities constitute completion of one unplanned transients per 7000 critical hours sample per unit as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

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

.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 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees corrective action program and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors focused their review on repetitive equipment issues, but also considered the results of daily corrective action item screening discussed in Section 4OA2.2, above, licensee trending efforts, and licensee human performance results. The inspectors nominally considered the 6-month period of January through June 2011, although some examples expanded beyond those dates where the scope of the trend warranted.

The inspectors also included issues documented outside the normal corrective action program in major equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments.

The inspectors compared and contrasted their results with the results contained in the licensees corrective action program trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.

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

b. Findings and Observations

No findings were identified. However, the inspectors did make the following observations:

The licensee continues to struggle with human error prevention techniques being implemented in accordance with the safety significance of the task at hand. The inspectors review of the first 6 months of human performance issues with safety-related or risk-significant equipment can be primarily attributed to three groups: operations, outage, and maintenance. Examples of events that have occurred include:

(1) maintenance personnel failed to follow the surveillance procedure for local/remote switch testing and pulled the wrong fuse; the dual verifier failed to catch the mistake; and once identified, the maintenance personnel replaced the wrong fuse and removed the correct fuse of his own accord;

(2) maintenance personnel failed to maintain a questioning attitude while performing a preventative maintenance work order on an inverter and did not question the voltage being high out of band;

(3) maintenance personnel were not familiar with performing a preventative maintenance work order on the feedwater booster pump and tripped the pump, they also did not recognize a less than

adequate caution statement;

(4) operations failed to perform a required technical specification surveillance for offsite power availability within the required timeframe while standby diesel generator 22 was inoperable for planned maintenance;

(5) outage operations personnel failed to prepare an adequate equipment clearance order package for work on the chemical and volume control system, in addition maintenance personnel accepted the inadequate clearance order and work commenced on a valve that still had power to the solenoid; and

(6) operations failed to follow procedural guidance and continued to purify the spent fuel pool during a transfer of water from the radioactive holding tank to the refueling water storage tank, the procedure requires purification to be secured. If this trend continues, the licensee could initiate more significant events that result in plant transients, or even injury to personnel. The licensee is performing a common cause analysis on human performance station level clock resets to determine any corrective actions that would mitigate or prevent these events from occurring. The licensee has captured this common cause as Condition Report 11-9925.

.4 Selected Issue Follow-up Inspection

a. Inspection Scope

During a review of items entered in the licensees corrective action program, the inspectors recognized several corrective action items documenting human performance issues within the operations department. The inspectors performed a focused review of the operations department to determine if the licensee had appropriately captured and documented the underlying issues in the corrective action program. The inspectors focused on procedural usage and adherence, training, communications, and questioning attitude. The inspectors started by reviewing the licensees corrective actions from the Identification and Resolution of Problems Semi-Annual Trend Review, that was documented in NRC Inspection Report 05000498/2010005 and 05000499/2010005, related to failing to adhere to procedural usage requirements. The inspectors reviewed the licensees programs to improve operations performance including: high intensity simulator training, crew performance review boards, department and crew clock resets, back to basics program, implementation of circle/slash place keeping, and other human error prevention techniques. The licensee captured these items and others in various condition reports which the inspectors reviewed to determine if the timeliness of corrective actions was commensurate with the safety significance. While the inspectors have seen improvement in the specific concern raised in the previous semi-annual trend review, the inspectors have continued to observe human performance errors that could be prevented by focused attention on human error prevention techniques, see Section 4OA2.3, above, for a semi-annual trend review that the inspectors are concerned with. Specific documents reviewed during this inspection 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. Findings

No findings were identified.

4OA3 Event Follow-up

.1 Fire in Unit 1 High Pressure Turbine Enclosure on Governor Valve Insulation

On May 7, 2011, at 5:43 p.m., the licensee experienced a small electrohydraulic control fluid fire on the high pressure main turbine MOOG valve for governor valve 4. The fire was extinguished at 5:48 p.m.; since it was less than 15 minutes, the requirements for an emergency declaration were not satisfied. Earlier in the day, the MOOG valve had started to leak and as a result the electrohydraulic control system had to be shut down to allow repairs. Approximately 20 gallons of fluid leaked out onto the insulation in the area of governor valve 4. Based on lessons learned from a previous fluid leak that resulted in a small fire, the licensee staged two fire brigade members to monitor the maintenance activities. The two members discharged water to put the fire out. Unit 1 continued to operate at 14 percent rated thermal power the entire time and Unit 2 was unaffected.

The two fire brigade members remained on the scene until the oil soaked insulation and the remaining electrohydraulic control fluid that leaked out were cleaned up. The cause of the leak was four of five hydraulic connections on the MOOG valve were not properly tightened. The licensee verified the connections on the other control and throttle MOOG valves and no other leaks were identified. The licensee tightened the connections, verified no leaks, and continued with power escalation.

.2 (Closed) Licensee Event Reports 05000498/2010-002-00, 01 and 02, Contract

Employee Failed to Report Arrest On February 3, 2010, while conducting a 5-year reinvestigation on a contract employee, access authorization discovered that derogatory information meeting the South Texas Project unescorted access denial criteria existed at the time access was granted on March 7, 2007. In summary, the licensee identified that a contract employee omitted an arrest on his personal history questionnaire and criminal history self disclosure form.

During the licensees 5-year reinvestigation, this omission was discovered. The licensee took immediate corrective actions that included suspending the individuals access while an investigation was conducted. This licensee-identified finding involving the failure to provide complete and accurate information is being considered a violation of 10 CFR 50.9. The enforcement aspects of the violation are discussed in Section 4OA7.

In addition, the NRC is taking enforcement actions with the individual involved in providing the inaccurate information to the licensee. These licensee event reports are closed. Specific documents reviewed during this inspection are listed in the attachment.

.3 (Closed) Licensee Event Report 05000498/2010-004-00, North Switchyard Bus

De-energization Resulting in Loss of Offsite Power ESF Actuation on Train 1B This licensee event report discussed a Unit 1 switchyard activity that resulted in a transient to the north bus causing the protective relays to actuate to de-energize the north bus. The north bus was providing power to the standby transformer and

subsequently to the train B safety-related switchgear resulting in the train B standby diesel generator starting to supply power. The inspectors reviewed this licensee event report and determined that it satisfactorily described the event, root cause, and corrective actions. The event and enforcement aspects of this licensee event report are discussed in detail in Section 1R13 of this report. This licensee event report is closed.

4OA5 Other Activities

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

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

a. Inspection Scope

As documented in Sections 1R04, 1R15, and 1R18, the inspectors confirmed the acceptability of the described licensees actions. This inspection effort counts toward the completion of Temporary Instruction 2515/177, which will be closed in a later inspection report.

b. Findings

No findings were identified.

.2 (Closed) NRC Temporary Instruction 2515/183, Followup to the Fukushima Daiichi

Nuclear Station Fuel Damage Event

a. Inspection Scope

The inspectors assessed the activities and actions taken by the licensee to assess its readiness to respond to an event similar to the Fukushima Daiichi nuclear plant fuel damage event. This included:

(1) an assessment of the licensees capability to mitigate conditions that may result from beyond design basis events, with a particular emphasis on strategies related to the spent fuel pool, as required by NRC Security Order Section B.5.b, issued February 25, 2002, as committed to in severe accident management guidelines, and as required by 10 CFR 50.54(hh);

(2) an assessment of the licensees capability to mitigate station blackout conditions, as required by 10 CFR 50.63 and station design bases;

(3) an assessment of the licensees capability to mitigate internal and external flooding events as required by station design bases; and

(4) an assessment of the thoroughness of the walkdowns and inspections of important equipment needed to mitigate fire and flood events, which were performed by the licensee to identify any potential loss of function of this equipment during seismic events possible for the site.

b. Findings

Inspection Report 05000498/2011008 and 05000499/2011008 (ML11133A128)documented detailed results of this inspection activity. Following issuance of the report, the inspectors conducted detailed follow-up on selected issues. No findings were identified during this follow-up inspection.

.3 (Closed) NRC Temporary Instruction 2515/184, Availability and Readiness Inspection of

Severe Accident Management Guidelines (SAMGs)

On May 20, 2011, the inspectors completed a review of the licensees severe accident management guidelines, implemented as a voluntary industry initiative in the 1990s, to determine:

(1) whether the severe accident management guidelines were available and updated,

(2) whether the licensee had procedures and processes in place to control and update its severe accident management guidelines,

(3) the nature and extent of the licensees training of personnel on the use of severe accident management guidelines, and

(4) licensee personnels familiarity with severe accident management guideline implementation.

The results of this review were provided to the NRC task force chartered by the Executive Director for Operations to conduct a near-term evaluation of the need for agency actions following the Fukushima Daiichi fuel damage event in Japan. Specific results for South Texas Project Electric Generating Station were provided as 12 to a memorandum to the Chief, Reactor Inspection Branch, Division of Inspection and Regional Support, dated May 26, 2011 (ML111470264).

4OA6 Meetings

Exit Meeting Summary

On April 15, 2011, the inspectors presented the inspection results of the review of inservice inspection activities to Mr. D. Rencurrel, Senior Vice President Units 1 and 2, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors returned all proprietary materials to the licensee at the end of the inspection.

On July 7, 2011, the inspectors presented the inspection results to Mr. D. Rencurrel, Senior Vice President Units 1 and 2, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

On July 8, 2011, the inspectors telephonically presented the results of the contract employee licensee event report closeout inspection to Mr. C. Bowman, General Manager, Nuclear Safety Assurance, and other members of the licensee staff who acknowledged the issues presented.

The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance was identified by the licensee and is a violation of NRC requirements which meet the criteria of Section 2.3.2 of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a noncited violation.

The licensee identified a Severity Level IV noncited violation of 10 CFR 50.9(a) for failure to provide information that was complete and accurate in all material respects regarding access authorization documentation required to be maintained by the licensee in accordance with 10 CFR 73.56(h)(1). Specifically, on March 7, 2007, the personal

history questionnaire and criminal history self disclosure forms utilized by the South Texas Project reviewing official in making trustworthy and reliability determinations did not contain valid information regarding prior legal actions by an applicant. This information was material because it was used by the NRC in the performance of regulatory duties.

The finding was more than minor because it impacted the NRCs ability to perform its regulatory function. Specifically, the licensee failed to ensure that personnel provide complete and accurate information to the NRC. This event is documented in the licensees corrective action program as Condition Report 10-2265. Because the violation involved the act of a low-level individual, it is being characterized as a Severity Level IV noncited violation.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Ashcraft, Quality Sr. Consulting Specialist

M. Berg, Manager, Design Engineering

C. Bowman, General Manager, Nuclear Safety Assurance

J. Calvert, Manager, Training

R. Dunn Jr., Manager, Fuels and Analysis

R. Engen, Site Engineering Director

T. Frawley, Manager, Operations

R. Gangluff, Manager, Projects and Knowledge Transfer

E. Halpin, President and Chief Executive Officer

W. Harrison, Manager, Licensing

G. Hildebrant, Manager, Plant Protection

G. Janak, Manager, Operations Division, Unit 1

B. Jenewein, Manager, Systems Engineering

J. Lovejoy, Manager, I&C Maintenance

N. Mayer, Manager, Projects

R. McNiel, Manager, Maintenance Engineering

J. Mertink, Plant Management Knowledge Transfer

J. Milliff, Manager, Operations Division, Unit 2

C. Murry, Manager, Outage and Major Projects

J. Paul, Engineer, Licensing Consultant

L. Peter, Plant General Manager

J. Pierce, Manager, Operations Training

G. Powell, Vice President, Tech Support and Oversight

M. Reddix, Manager, Security

D. Rencurrel, Senior Vice President, Units 1 and 2

M. Ruvalcaba, Manager, Testing and Programs

R. Savage, Engineer, Licensing Staff Specialist

M. Schaefer, Manager, Maintenance

L. Spiess, NDE Program Manager

K. Taplett, Senior Engineer, Licensing Staff

D. Tran, Quality Assurance

D. Zink, Supervising Engineering Specialist

Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000498/2011003-01 NCV Inadequate Fire Protection System Functionality Procedure

05000499/2011003-01 Results in Failure to Establish Fire Watches (Section 1R05)

05000498/2011003-02 NCV Inadequate Risk Assessment for Switchyard Activities (Section 1R13)

Closed

05000498/2010-002-00 LER Contract Employee Failed to Report Arrest (Section 4OA3)

05000498/2010-002-01

05000498/2010-002-02

05000498/2010-004-00 LER North Switchyard Bus De-Energization Resulting in Loss of Offsite Power ESF Actuation on Train 1B (Section 4OA3)