IR 05000498/2011002

IR 05000498-11-002, 05000499-11-002, on 01/01/11 - 03/31/2011, South Texas Project, Units 1 & 2, NRC Integrated Inspection Report

ML111290816
Person / Time
Site:	South Texas
Issue date:	05/09/2011
From:	Webb Patricia Walker NRC/RGN-IV/DRP/RPB-A
To:	Halpin E South Texas
References
IR-11-002
Download: ML111290816 (54)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION REGI ON I V 612 EAST LAMAR BLVD, SUITE 400 ARLINGTON, TEXAS 76011-4125 May 9, 2011 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 05000498/2011002 AND 05000499/2011002

Dear Mr. Halpin:

On March 31, 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 April 7, 2011, with Mr. Kevin Richards, Senior Vice President, 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, three self-revealing and one NRC identified findings 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. 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.a of the NRC Enforcement Policy.

If you contest these 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 05000498/2011002 and 05000499/2011002 w/Attachment: Supplemental Information

REGION IV==

Docket: 05000498, 05000499 License: NPF-76, NPF-80 Report: 05000498/2011002 and 05000499/2011002 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: January 1 through March 31, 2011 Inspectors: L. Carson II, Senior Health Physicist K. Clayton, Senior Operations Engineer J. Dixon, Senior Resident Inspector P. Goldberg, Reactor Inspector N. Greene, Health Physicist G. Guerra, CHP, Emergency Preparedness Inspector R. Latta, Senior Reactor Inspector M. Phalen, Senior Health Physicist, NRC Region III B. Rice, Reactor Inspector B. Tharakan, CHP, Resident Inspector Approved By: Wayne Walker, Chief, Project Branch A Division of Reactor Projects-1- Enclosure

SUMMARY OF FINDINGS

IR 05000498/2011002, 05000499/2011002; 01/01/2011 - 03/31/2011; South Texas Project

Electric Generating Station, Units 1 and 2, Integrated Resident and Regional Report;

Operability Evaluations; Surveillance Testing.

The report covered a 3-month period of inspection by resident inspectors and announced baseline inspections by regional based inspectors. Four Green noncited violations 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 Technical Specification 6.8.1.a, for the failure to follow surveillance test Procedure 0PSP03-SP-0006R, Train R Reactor Trip Breaker TADOT,

Revision 21, because operators did not block a reactor trip signal during the performance of the test. On August 20, 2010, operators inadvertently skipped a page in the test procedure, and at 3:25 p.m., the Unit 1 reactor tripped automatically from 100 percent power. The reactor trip was uncomplicated and the inspectors responded to the site to ensure the plant was in a safe condition.

The licensees corrective actions included providing additional supervisory oversight for the test and implementing new place-keeping methods.

This finding was more than minor because it was associated with the Human Performance attribute of the Initiating Events Cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown, as well as power operations, because it resulted in a reactor trip from 100 percent power.

The inspectors performed the significance determination using NRC Inspection Manual Chapter 0609, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, dated January 10, 2008, because the finding affected the Initiating Events Cornerstone while the plant was at full power.

The finding was determined to be of very low safety significance because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available. In addition, this finding had human performance cross-cutting aspects associated with work practices, in that, the licensee did not communicate human error prevention techniques, such as self-checking and proper documentation of activities, commensurate with the risk of the assigned task such that work activities are performed safely

H.4(a)(Section 1R22).

Cornerstone: Mitigating Systems

Green.

The inspectors reviewed a self-revealing noncited violation of 10 CFR Part 50, Appendix B, Criteria V, Instructions, Procedures, and Drawings, for the failure to follow Procedure 0POP11-SI-0001,

Safety Injection/Containment Spray Pump Online Isolation and Restoration,

Revision 0. During the performance of a surveillance test on Unit 2 high head safety injection pump 2C, air was vented from the flushing line vent valve. The acceptance criterion was that no air be vented. The source of the air was from a maintenance activity performed August 16-19, 2010. During the maintenance, the equipment clearance order boundary was moved from the discharge valve to the subsequent downstream valve. As a result, during restoration it was not recognized that this new boundary introduced approximately 7 feet of vertical piping that could not be vented. Corrective actions included venting using a high point downstream of the boundary valve; ensuring that the station is aware of the procedure and the reason behind the creation of the procedure to address the Generic Letter 2008-01 concerns, so that impact of changes to the work scope can be appropriately controlled and evaluated; and changing the wording of the procedure to not allow moving the boundary outside of the discharge valve while at power.

This finding was more than minor because it affected the Mitigating Systems Cornerstone attributes of Human Performance and 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. This deficiency directly resulted in the high head pump containing a void in the system following maintenance after it was returned to an operable status. The inspectors performed the significance determination using NRC Inspection Manual Chapter 0609, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, dated January 10, 2008, because it affected the Mitigating Systems Cornerstone while the plant was at power. The finding was determined to be of very low safety significance because it was not a design or qualification deficiency; it did not result in the loss of a system safety function; it did not represent a loss of a single train for greater than technical specification allowed outage time; it did not represent a loss of one or more nontechnical specification risk-significant equipment for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; and it did not screen as potentially risk significant due to seismic, flooding, or severe weather. In addition, this finding had human performance cross-cutting aspects associated with work control in that the licensee did not incorporate actions to address the impact of changes to the work scope H.3(b)

(Section 1R15).

Green.

The inspectors identified a Green noncited violation of 10 CFR Part 50,

Appendix B, Criteria V, Instructions, Procedures, and Drawings, for the failure to follow Procedure 0PGP03-ZX-0002, Condition Reporting Process,

Revision 38. On January 13, 2011, the licensee wrote Condition Report 11-1261 which states, in part, Twenty-six transfer switches required by Technical Specification 3.3.3.5, Remote Shutdown System, appear to not be listed.

Procedure 0PGP03-ZX-0002, step 4.3.2 states, in part, that conditions that may have an impact on the operability of a technical specification related system shall be screened as yes or indeterminate. The corrective action program supervisor that screened this condition report marked the operability as No. The inspectors questioned the licensee on January 14 and 18, 2011, as to why no immediate operability determination had been performed. The licensees corrective actions determined that an immediate and subsequent prompt operability determination was warranted. The inspectors interviewed the supervisor and determined that the supervisor did not use conservative assumptions and adopt a requirement to demonstrate that the proposed action is safe in order to proceed when screening the issue for operability.

This finding was more than minor because it affected the Mitigating Systems Cornerstone attributes of Human Performance and 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. Specifically, the failure to recognize that risk-significant equipment is in a potentially inoperable condition and, as such, may not be able to perform its specified safety function would not be recognized and accounted for by operators. The inspectors performed the significance determination using NRC Inspection Manual Chapter 0609, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, dated January 10, 2008, because it affected the Mitigating Systems Cornerstone while the plant was at power. The finding was determined to be of very low safety significance because it was not a design or qualification deficiency; it did not result in the loss of a system safety function; it did not represent a loss of a single train for greater than technical specification allowed outage time; it did not represent a loss of one or more nontechnical specification risk-significant equipment for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; and it did not screen as potentially risk significant due to seismic, flooding, or severe weather. In addition, this finding had human performance cross-cutting aspects associated with decision making in that the licensee did not use conservative assumptions and adopt a requirement to demonstrate that the proposed action is safe in order to proceed H.1(b)(Section 1R15).

Green.

The inspectors reviewed a self-revealing noncited violation of 10 CFR Part 50, Appendix B, Criteria XVI, Corrective Action, for the failure to assure that conditions adverse to quality were corrected in a timely manner, or that an evaluation to justify a longer completion time beyond the first available opportunity was performed. On June 2, 2008, steam generator power operated relief valve 1A failed to stroke full closed as part of surveillance testing. The operability determination concluded that the steam generator power operated relief valves were operable but nonconforming. On August 25, 2010, steam generator power operated relief valve 1D failed to stroke closed as part of surveillance testing. This new prompt operability determined that the previous operability was flawed. It did not consider all functions associated with the valves, in particular, the dose mitigation function. It was also determined that the licensee failed to adequately track an operable but nonconforming condition to ensure resolution in a timely manner. The licensee has since updated the design modification timeline to install the failed closed circuitry in both units during the respective 2011 refueling outages.

This finding was more than minor because it affected the Mitigating Systems Cornerstone attributes of Design Control and Equipment Performance and affected the cornerstone objective to ensure that availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The deficiency resulted in the Updated Final Safety Analysis Report Chapter 15 Accident Analysis dose calculations being nonconservative if the relief valves would fail to go closed on loss of power. The inspectors performed the significance determination using NRC Inspection Manual Chapter 0609, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, dated January 10, 2008, because it affected the Mitigating Systems Cornerstone while the plant was at power. The finding was determined to be of very low safety significance because it was a design or qualification deficiency confirmed not to result in loss of operability or functionality. In addition, this finding had problem identification and resolution cross-cutting aspects associated with the corrective action program in that the licensee did not thoroughly evaluate the problem such that the resolutions address causes, and did not properly evaluate for operability conditions adverse to quality P.1(c)(Section 1R22).

Licensee-Identified Violations

None

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at 100 percent rated thermal power and essentially remained there for the duration of the inspection period.

Unit 2 began the inspection period at 100 percent rated thermal power and remained there until January 26 when the unit down powered to 47 percent rated thermal power to replace main turbine electrohydraulic auto stop relays. The unit returned to 100 percent rated thermal power on January 27 and essentially remained there for the remainder of the inspection period.

REACTOR SAFETY

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

1R01 Adverse Weather Protection

Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

Since extreme cold conditions were forecast in the vicinity of the facility for February 1-11, 2011, the inspectors reviewed overall preparations/protection for the expected weather conditions. On February 1-3, and February 8-10, 2011, the inspectors inspected the Unit 1 and Unit 2 essential chilled water and essential cooling water systems because their safety-related functions could be affected as a result of the extreme cold conditions forecast for the facility. The inspectors observed insulation, throttle valve position, system flow rates, heat trace circuits in affected areas, space heater operation, and weatherized enclosures to ensure operability of affected systems.

The inspectors reviewed licensee procedures and discussed potential compensatory measures with control room personnel. The inspectors focused on plant managements actions for implementing the stations procedures for ensuring adequate personnel for safe plant operation and emergency response would be available. Specific documents reviewed during this inspection are listed in the attachment.

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

b. Findings

No findings were identified.

1R04 Equipment Alignments

Partial Walkdown

a. Inspection Scope

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

• January 13, 2011, Unit 1, essential chilled water train A

• January 21, 2011, Unit 1, safety injection system train B

• March 23, 2011, Unit 2, essential cooling water 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, UFSAR, technical specification requirements, administrative technical specifications, outstanding work orders, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also inspected accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.

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

b. Findings

No findings were identified.

1R05 Fire Protection

Quarterly Fire Inspection Tours

a. Inspection Scope

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

• March 23, 2011, Unit 1, boric acid tank and transfer pump rooms, Fire Zone 108

• March 23, 2011, Unit 1, mechanical auxiliary building elevation 41 feet locker rooms and clothing issue area, Fire Zone 147

• March 30, 2011, Unit 2, boric acid tank and transfer pump rooms, Fire Zone 108

• March 30, 2011, Unit 2, mechanical auxiliary building elevation 41 feet locker rooms and clothing issue area, Fire Zone 147 The inspectors reviewed areas to assess if licensee personnel had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant; effectively maintained fire detection and suppression capability; maintained passive fire protection features in good material condition; and had implemented adequate compensatory measures for out of service, degraded or inoperable fire protection equipment, systems, or features, in accordance with the licensees fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to affect equipment that could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. Using the documents listed in the attachment, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees corrective action program. Specific documents reviewed during this inspection are listed in the attachment.

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

b. Findings

No findings were identified.

1R07 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed licensee programs, verified performance against industry standards, and reviewed critical operating parameters and maintenance records for the train A standby diesel generator jacket water, lube oil, and turbo charger intercooler heat exchangers. The inspectors verified that performance tests were satisfactorily conducted for heat exchangers/heat sinks and reviewed for problems or errors; the licensee utilized the periodic maintenance method outlined in EPRI Report NP 7552, Heat Exchanger Performance Monitoring Guidelines; the licensee properly utilized biofouling controls; the licensees heat exchanger inspections adequately assessed the state of cleanliness of their tubes; and the heat exchanger was correctly categorized under 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants. Specific documents reviewed during this inspection are listed in the attachment.

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

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Quarterly Review

a. Inspection Scope

On March 8-10, 2011, during the licensees first time implementation of high intensity training, the inspectors observed two crews of licensed operators 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.

.2 Annual Inspection

a. Inspection Scope

The inspectors reviewed the annual operating test results for 2010. Since this was the first half of the biennial requalification cycle, the licensee was not required to administer a written examination. These results were assessed to determine if they were consistent with NUREG 1021, Operator Licensing Examination Standards for Power Reactors, guidance and Manual Chapter 0609, Appendix I, Operator Requalification Human Performance Significance Determination Process, thresholds. The inspectors verified all failures were properly remediated and passed a retake operating test before being returned to shift duties.

The inspectors completed one sample.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

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

• March 23, 2011, Units 1 and 2, fire alarm and detection system (FA)

• March 25, 2011, Units 1 and 2, nuclear instrument system (NI)

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 two quarterly maintenance effectiveness samples as defined in Inspection Procedure 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed licensee 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:

• January 10-18, 2011, Unit 1, large train A work week including essential cooling water pump 1A pump replacement and standby diesel generator 11 5-year inspection

• February 1-10, 2011, Unit 1 and 2, licensees efforts to mitigate risks due to extremely cold weather that resulted in low ultimate heat sink temperature and rolling blackouts in Texas due to low electrical grid capacity

• March 7-11, 2011, Unit 1 and 2, planned maintenance on Unit 1 A train including first time evolution of train A remote shutdown system operability testing, and Unit 2 D train

• March 28-31, 2011, Unit 1, planned maintenance on Unit 1 D train and pre-outage activities in preparation for Refueling Outage 1RE16 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

No findings were identified.

1R15 Operability Evaluations

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• October 28, 2010, Unit 2, high head safety injection pump 2C void following maintenance

• January 13, 2011, Units 1 and 2, remote shutdown system surveillance testing

• January 27, 2011, Unit 1, standby diesel generator 13 fuel oil leakage

• February 24, 2011, Unit 1, engineered safety features load center E1A1 and reactor containment fan cooler 12A fuses not fully engaged

• March 14, 2011, Unit 2, safety injection accumulator 2A leakage

• March 29, 2011, Unit 1, auxiliary feedwater 14 trip throttle valve impact space and linkage spring out of tolerance 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 UFSAR 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.

.1 High Head Safety Injection Pump 2C Void Following Maintenance

Introduction.

The inspectors reviewed a self-revealing Green noncited violation of 10 CFR Part 50, Appendix B, Criteria V, Instructions, Procedures, and Drawings, for the failure to follow Procedure 0POP11-SI-0001, Safety Injection/Containment Spray Pump Online Isolation and Restoration, Revision 0.

Description.

On September 25, 2010, during the performance of surveillance test Procedure 0PSP03-SI-0014, ECCS Valve Checklist, Revision 12, on Unit 2 high head safety injection pump 2C, air was vented from the flushing line vent valve. The acceptance criterion was that no air be vented. The licensee performed a root cause and determined that the source of the air was from a maintenance activity performed August 16-19, 2010. The licensee created a new procedure for performing maintenance on the safety injection system to address concerns from NRC Generic Letter 2008-01, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems. The new Procedure, 0POP11-SI-0001, captured the concern over the difficulty of venting the piping downstream of the high head safety injection pump discharge valves if it was drained for maintenance. The procedure instructs the use of the high head safety injection pump discharge valve as the boundary for at-power maintenance. The first time that maintenance was performed after the procedure was issued was in February 2010 on the 2A high head safety injection pump.

However, the new procedure was not used because personnel were not aware that the procedure existed. This event did not result in air entrainment because the discharge valve was used as the boundary. During the 2C high head safety injection pump maintenance, the equipment clearance order boundary was moved from the discharge valve to the subsequent downstream valve (SI-206C); again, personnel were not aware that the procedure existed. As a result, when the system was restored, it was not recognized that this new boundary introduced approximately 7 feet of vertical piping that could not be vented using the valves listed on the equipment clearance order.

Therefore, when the system was restored on August 19, 2010, it did not adequately vent the vertical piping downstream of the discharge valve. The licensees corrective actions included: venting using a high point downstream of the boundary valve (SI-206C) to ensure that all the air was removed from the system, and venting on a more frequent basis with pump runs between venting to ensure confidence that all the air had been removed. The licensee has ensured that the station is aware of the procedure and the reason behind the creation of the procedure, to address the Generic Letter 2008-01 concerns, so that impact of changes to the work scope can be appropriately controlled and evaluated. Additionally, the licensee has changed the wording of Procedure 0POP11-SI-0001 to not allow moving the boundary outside of the discharge valve while at power.

Analysis.

The failure to use the procedure for online isolation or restoration of the high head safety injection pump 2C was a performance deficiency. This finding was more than minor because it affected the Mitigating Systems Cornerstone attributes of Human Performance and 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. This deficiency directly resulted in the

high head pump containing a void in the system following maintenance after it was returned to an operable status. The inspectors performed the significance determination using NRC Inspection Manual Chapter 0609, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, dated January 10, 2008, because it affected the Mitigating Systems Cornerstone while the plant was at power. The finding was determined to be of very low safety significance (Green) because it was not a design or qualification deficiency; it did not result in the loss of a system safety function; it did not represent a loss of a single train for greater than technical specification allowed outage time; it did not represent a loss of one or more nontechnical specification risk-significant equipment for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; and it did not screen as potentially risk significant due to seismic, flooding, or severe weather. In addition, this finding had human performance cross-cutting aspects associated with work control in that the licensee did not incorporate actions to address the impact of changes to the work scope

H.3(b).

Enforcement.

Title 10 CFR Part 50, Appendix B, Criteria V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented procedures of a type appropriate to the circumstances and shall be accomplished in accordance with these procedures. Procedure 0POP11-SI-0001, Safety Injection/Containment Spray Pump Online Isolation and Restoration, Revision 0, step 1.1 states that this procedure provides for online maintenance instructions for safety injection pumps removal and return to service. Contrary to this, on August 19, 2010, during online maintenance, Procedure 0POP11-SI-0001 was not used; this resulted in the failure of the surveillance test performed on September 25, 2010, due to air being vented from the system. Since this violation was of very low safety significance and was documented in the licensees corrective action program as Condition Report 10-20988, it is being treated as a noncited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000499/2011002-01, Inadequate Restoration Results in Void in High Head Safety Injection Pump 2C.

.2 Remote Shutdown System Surveillance Testing

Introduction.

The inspectors identified a Green noncited violation of 10 CFR Part 50, Appendix B, Criteria V, Instructions, Procedures, and Drawings, for the failure to follow Procedure 0PGP03-ZX-0002, Condition Reporting Process, Revision 38.

Description.

On January 13, 2011, while researching surveillance procedure development to test the local remote transfer switch noncontinuity to ensure safe shutdown is achievable from outside the control room, the licensee wrote Condition Report 11-1261 to document the procedure writers concern about 26 additional switches. The condition report states Twenty-six transfer switches required by Technical Specification 3.3.3.5, Remote Shutdown System, appear to not be listed. These switches should be evaluated for applicability for Technical Specification 3.3.3.5. These switches are presently not listed in CREE 10-14083-8 and are not tested in 0PSP03-ZG-0005. Procedure 0PGP03-ZX-0002, Condition Reporting Process, Revision 38, step 4.3.2 states, in part, that conditions that may have an impact on the operability of a technical specification related system shall be screened as yes or indeterminate. The corrective action program supervisor that screened this condition report marked the operability as No. Additionally, Procedure 0POP01-ZQ-0022, Plant

Operations Shift Routines, Revision 63, step 3.4.7 states, in part, that the oncoming shift manager SHALL ensure that during the nightly condition report review all safety-related items that need an operability determination are identified. Both of these checks failed to identify that the condition should have received an immediate operability determination. The inspectors questioned the licensee on January 14 and 18, 2011, as to why no immediate operability determination had been performed, but was not given a response until the licensee wrote Condition Report 11-1652 on January 19, 2011, to document that the supervisor incorrectly marked the operability review field as No versus Indeterminate. The licensees corrective actions included performing an immediate followed by a subsequent prompt operability review. The inspectors interviewed the corrective action program supervisor and determined that the supervisor did not use conservative assumptions and adopt a requirement to demonstrate that the proposed action is safe in order to proceed when screening the issue for operability.

Additionally, the shift manager also did not demonstrate conservative assumptions in that they appear to have assumed that this condition was bounded by the previously written evaluation even though the condition report stated that the previous evaluation did not encompass the additional switches.

Analysis.

The failure to follow Procedures 0PGP03-ZX-0002 and 0POP01-ZQ-0022 when screening the additional transfer switches for operability impact was a performance deficiency. This finding was more than minor because it affected the Mitigating Systems Cornerstone attributes of Human Performance and 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. Specifically, the failure to recognize that risk-significant equipment is in a potentially inoperable condition and, as such, may not be able to perform its specified safety function would not be recognized and accounted for by operators. The inspectors performed the significance determination using NRC Inspection Manual Chapter 0609, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, dated January 10, 2008, because it affected the Mitigating Systems Cornerstone while the plant was at power. The finding was determined to be of very low safety significance (Green) because it was not a design or qualification deficiency; it did not result in the loss of a system safety function; it did not represent a loss of a single train for greater than technical specification allowed outage time; it did not represent a loss of one or more nontechnical specification risk-significant equipment for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; and it did not screen as potentially risk significant due to seismic, flooding, or severe weather. In addition, this finding had human performance cross-cutting aspects associated with decision making in that the licensee did not use conservative assumptions and adopt a requirement to demonstrate that the proposed action is safe in order to proceed H.1(b).

Enforcement.

Title 10 CFR Part 50, Appendix B, Criteria V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented procedures of a type appropriate to the circumstances and shall be accomplished in accordance with these procedures. Procedure 0PGP03-ZX-0002, Condition Reporting Process, Revision 38, step 4.3.2 states, in part, that conditions that may have an impact on the operability of a technical specification related system shall be screened as yes or indeterminate. Contrary to this, on January 13, 2011, the corrective action program supervisor did not screen the condition report as

yes or indeterminate; this resulted in the failure to perform an immediate operability determination for 6 days. Since this violation was of very low safety significance and was documented in the licensees corrective action program as Condition Report 11-1652, it is being treated as a noncited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000498/2011002-02 and 05000499/2011002-02, Failure to Perform an Immediate Operability Determination.

.2 Operability Evaluations associated with Temporary Instruction (TI) 2515/177, Managing

gas accumulation in emergency core cooling, decay heat removal, and containment spray systems.

a. Inspection Scope

The inspectors reviewed the following issues associated with the scope of GL 2008-01, Managing gas accumulation in emergency core cooling, decay heat removal, and containment spray systems:

• October 28, 2010, Unit 2, high head safety injection pump 2C void following maintenance

• March 14, 2011, Unit 2, safety injection accumulator 2A leakage The inspectors verified that the licensee has acceptably identified the gas intrusion mechanisms that apply to the licensees plant. In addition, the inspectors verified that the licensees void acceptance criteria were consistent with the Office of Nuclear Reactor Regulations (NRR) void acceptance criteria. Also, the inspectors confirmed that

(1) the licensee addressed the effect of pressure changes during system startup 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.

Documents reviewed are listed in the Attachment to this report.

This inspection effort counts towards the completion of TI 2515/177 which will be closed on a later Inspection Report.

b. Findings

No findings were identified.

1R17 Evaluations of Changes, Tests, or Experiments and Permanent Plant

Modifications (71111.17)

a. Inspection Scope

The inspectors reviewed the effectiveness of the licensees implementation of evaluations performed in accordance with 10 CFR 50.59, Changes, Tests, and Experiments, and changes, tests, experiments, or methodology changes that the licensee determined did not require 10 CFR 50.59 evaluations.

The inspectors reviewed 6 evaluations required by 10 CFR 50.59; 15 changes, tests, and experiments that were screened out by licensee personnel; and 9 permanent plant modifications. Documents reviewed are listed in the attachment.

The inspectors verified that, when changes, tests, or experiments were made, evaluations were performed in accordance with 10 CFR 50.59 and licensee personnel had appropriately concluded that the change, test, or experiment can be accomplished without obtaining a license amendment. The inspectors also verified that safety issues related to the changes, tests, or experiments were resolved. The inspectors reviewed changes, tests, and experiments that licensee personnel determined did not require evaluations and verified that the licensee personnels conclusions were correct and consistent with 10 CFR 50.59. The inspectors also verified that procedures, design, and licensing basis documentation used to support the changes were accurate after the changes had been made.

In the inspection of modifications, the inspectors verified that supporting design and license basis documentation had been updated accordingly and was still consistent with the new design. The inspectors verified that procedures, training plans, and other design basis features had been adequately accounted for and updated. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of 6 samples of evaluations; 15 samples of changes, tests, and experiments that were screened out by licensee personnel; and 9 samples of permanent plant modifications as defined in Inspection Procedure 71111.17-04.

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:

• January 16, 2011, Unit 1, essential cooling water pump 1A pump replacement

• January 17, 2011, Unit 1, train A standby diesel generator 5-year inspection

• January 18, 2011, Unit 1, rod control in-hold-out switch replacement

• March 7, 2011, Unit 2, auxiliary feedwater pump 24 Terry turbine maintenance

• March 18, 2011, Unit 2, replacement of a failed channel one reactor coolant system average temperature summing amplifier card

The inspectors selected these activities based upon the structure, system, or components ability to affect risk. The inspectors evaluated these activities for the following (as applicable):

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

• Acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate The inspectors evaluated the activities against the technical specifications, the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with 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 five postmaintenance testing inspection samples as defined in Inspection Procedure 71111.19-05.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

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

• Preconditioning

• Evaluation of testing impact on the plant

• Acceptance criteria

• Test equipment

• Procedures

• Jumper/lifted lead controls

• Test data

• Testing frequency and method demonstrated technical specification operability

• Test equipment removal

• Restoration of plant systems

• Fulfillment of ASME Code requirements

• Updating of performance indicator data

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

• Reference setting data

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

• November 23, 2010, Units 1 and 2, steam generator power operated relief valves operability test

• January 7, 2011, Unit 1, train S, solid state protection system and reactor trip breaker test

• January 16, 2011, Unit 1, essential chiller 12A and essential chilled water pump 11A inservice test

• February 8, 2011, Unit 1, essential cooling water pump 1A inservice test

• March 19, 2011, Unit 1, train A remote shutdown system operability test 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.

.1 Steam Generator Power Operated Relief Valves Operability Test

Introduction.

The inspectors reviewed a Green self-revealing noncited violation of 10 CFR Part 50, Appendix B, Criteria XVI, Corrective Action, for the failure to assure that conditions adverse to quality were corrected in a timely manner, or that an evaluation to justify a longer completion time beyond the first available opportunity was performed.

Description.

On June 2, 2008, steam generator 1A power operated relief valve failed to stroke full closed as part of surveillance testing. The licensee generated

Condition Report 08-9382 to document the condition. Operations requested a prompt operability determination which was completed under Condition Report 08-9595 on June 6, 2008. The operability determination concluded that the steam generator power operated relief valves were operable but nonconforming. The proposed plan of action to restore compliance was completed on May 28, 2009, and it recommended two actions:

prepare a conceptual study to determine extent of modification necessary to change circuitry to make valves fail closed, and to present the conceptual design to management for approval. However, since no work order was opened to track the design changes, there was no tracking tool for ensuring either the deficiency was corrected or that a justification was performed to allow operation beyond the first available opportunity. For Unit 1, the first available opportunity was October 2009 during a refueling outage, and for Unit 2, it was October 2008 and then again in April 2010 during refueling outages. The available documentation does not explain the delay between the prompt operability and the completion of the plan of action. In February 2010 the design modification to make the valves failed closed was approved by management and is planned for October 2012 in Unit 1 and October 2011 for Unit 2.

However, the licensee did not perform an evaluation to justify continued operation beyond the first available opportunity. On August 25, 2010, steam generator 1D power operated relief valve failed to stroke closed as part of surveillance testing and was captured as Condition Report 10-18357. Operations requested a prompt operability determination which was completed as part of Condition Report 10-18770. This new prompt operability determined that the previous operability was flawed, and it did not consider all functions associated with the valves, in particular, the dose mitigation function. It was also determined that the licensee failed to adequately track an operable but nonconforming condition to ensure resolution in a timely manner. The licensee has since updated the design modification timeline to install the failed closed circuitry in both units during the respective 2011 refueling outages. The inspectors determined that the licensee failed to properly disposition an operable but nonconforming condition and failed to thoroughly evaluate a condition adverse to quality to ensure timely resolution.

Analysis.

The failure to implement timely corrective actions, or perform an evaluation to justify a longer completion time beyond the first available opportunity was a performance deficiency. This finding was more than minor because it affected the Mitigating Systems Cornerstone attributes of Design Control and Equipment Performance and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The deficiency resulted in the UFSAR Chapter 15 Accident Analysis dose calculations being nonconservative if the relief valves would fail to go closed on loss of power. The inspectors performed the significance determination using NRC Inspection Manual Chapter 0609, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, dated January 10, 2008, because it affected the Mitigating Systems Cornerstone while the plant was at power. The finding was determined to be of very low safety significance (Green) because it was a design or qualification deficiency confirmed not to result in loss of operability or functionality. In addition, this finding had problem identification and resolution cross-cutting aspects associated with the corrective action program in that the licensee did not thoroughly evaluate the problem such that the resolutions address causes, and did not properly evaluate for operability conditions adverse to quality P.1(c).

Enforcement.

Title 10 CFR Part 50, Appendix B, Criteria XVI, Corrective Action, requires, in part, that measures shall be established to assure that conditions adverse to quality, such as nonconformances, are promptly corrected. Contrary to the above, from June 2008 until September 2010, the licensee failed to establish measures to assure that conditions adverse to quality, such as nonconformances, were promptly corrected. Specifically, the licensee failed to establish timely and adequate corrective actions to address the steam generator power operated relief valves nonconforming condition of not failing in the closed position upon a loss of power as assumed in the UFSAR Chapter 15 Accident Analysis, or perform an evaluation to justify a longer completion time beyond the first available opportunity. Since this violation was of very low safety significance and was documented in the licensees corrective action program as Condition Report 10-18770, it is being treated as a noncited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000498/2011002-03 and 05000499/2011002-03, Untimely Corrective Action to Correct Nonconforming Steam Generator Power Operated Relief Valve Condition.

.2 Solid State Protection System and Reactor Trip Breaker Test

Introduction.

The inspectors reviewed a Green self-revealing noncited violation of Technical Specification 6.8.1.a, for the failure to follow surveillance test Procedure 0PSP03-SP-0006R, Train R Reactor Trip Breaker TADOT, Revision 21, because operators did not block a reactor trip signal during the performance of the test.

Description.

On August 20, 2010, at approximately 3:00 p.m., Unit 1 reactor operators commenced the performance of a surveillance test on the train R solid state protection system using Procedure 0PSP03-SP-0006R, Train R Reactor Trip Breaker TADOT, Revision 21. At 3:25 p.m., the Unit 1 reactor tripped automatically from 100 percent power due to a human performance error during the performance of the surveillance test. The test was performed by a reactor operator, designated as the test coordinator, and a senior reactor operator, designated to provide supervisory oversight and dual verification of certain steps in the procedure, and two plant operators that performed actions at the reactor trip breakers. The test coordinator and senior reactor operator performed steps 5.3.1 through 5.3.3 in the solid state protection system train R cabinet, then the test coordinator directed the plant operators to perform step 5.3.4 to ensure that the reactor trip breaker train R bypass breaker was closed. Once this was completed, the test coordinator proceeded to complete steps 5.3.5 through 5.3.8 as applicable.

At this point, the test coordinator inadvertently turned two pages in the procedure and skipped the page that contained steps 5.3.9 through 5.3.11. Neither the test coordinator nor the senior reactor operator recognized, at the time, the page was skipped. This was a critical error because step 5.3.10 of the procedure blocks the reactor trip signal and step 5.3.11 verifies the block is turned on. As the operators continued on in the procedure, they reached step 5.3.17, which initiated a reactor trip signal, and since the block was not turned on, the signal tripped the turbine first which in turn tripped the reactor from 100 percent power at 3:25 p.m. The reactor trip was uncomplicated and the reactor was placed in a safe condition in Mode 3, hot standby. The NRC inspectors responded to the reactor trip and verified that the reactor was in a safe condition in Mode 3.

The licensee relieved the operators involved in the event until a complete post-trip review and a root cause investigation of the event could be performed. The licensee identified two organizational root causes:

(1) place-keeping standards for the site were not adequate, and

(2) supervisory oversight during the performance of the procedure became ineffective when the senior reactor operator became involved in the process and performed some of the actions in the procedure. The inspectors interviewed the individuals involved with the event and reviewed the licensees root cause investigation, procedures, corrective actions, and observed subsequent testing of the reactor trip breakers. The inspectors determined that a violation of Technical Specification 6.8.1.a had occurred because the operators failed to follow the procedure steps and made critical errors by skipping steps that would have prevented the reactor trip. The inspectors determined that if the licensee had adequately communicated human error prevention techniques such as self-checking, place-keeping methods, and proper documentation of work activities to the operators, this event may have been prevented.

The licensees corrective actions included providing additional supervisory oversight for the test and implementing new place-keeping methods.

Analysis.

The failure to perform critical steps in the surveillance test procedure was a performance deficiency and a finding. This finding was more than minor because it was associated with the human performance attribute of the Initiating Events Cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown, as well as power operations, because it resulted in a reactor trip from 100 percent power. The inspectors performed the significance determination using NRC Inspection Manual Chapter 0609, 0609.04, Phase 1 - Initial Screening and Characterization of Findings, dated January 10, 2008, because the finding affected the Initiating Events Cornerstone while the plant was at full power. The finding was determined to be of very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available. In addition, this finding had human performance cross-cutting aspects associated with work practices in that the licensee did not communicate human error prevention techniques, such as self-checking and proper documentation of activities, commensurate with the risk of the assigned task such that work activities are performed safely H.4(a).

Enforcement.

Technical Specification 6.8.1.a requires, in part, that written procedures shall be established, implemented, and maintained covering the activities referenced in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Section 8(l) of Appendix A of Regulatory Guide 1.33 requires procedures for reactor protection system tests. Licensee Procedure 0PSP03-SP-0006R, Train R Reactor Trip Breaker TADOT, Revision 21, step 5.3.10, required operators to turn, but DO NOT DEPRESS, Turbine Trip Switch S128 to the Push to Test position. Contrary to the above, on August 20, 2010, step 5.3.10 of the surveillance procedure was not performed because the operators inadvertently skipped over the page that contained step 5.3.10. The failure to perform this step resulted in an automatic reactor trip from 100 percent power. The licensees immediate corrective actions were to relieve the operators from duty until a full investigation was concluded, and to implement additional place-keeping methods, provide training on the place-keeping methods to all operations and maintenance personnel, and provide additional supervisory oversight for all subsequent uses of this surveillance procedure. Since this violation was of very low safety significance and was

documented in the licensees corrective action program as Condition Report 10-17990, it is being treated as a noncited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000498/2011002-04, Failure to Follow Reactor Protection System Procedure Results in Automatic Reactor Trip.Cornerstone: Emergency Preparedness

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The inspectors performed an in office review of Revision ICN 20-10 to the South Texas Project Electric Generating Station Emergency Plan, submitted February 14, 2011. The changes related to the relocation of the joint information center including deleting the letter of agreement for the previous location. The change also added satellite phone communications to the technical support center and emergency operations facility, added site public address speakers to the joint information center, made organizational title changes, changed to satellite television instead of cable television, and made minor editorial changes.

The revision was compared to the previous revision, to the criteria of NUREG 0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1, and to the standards in 10 CFR 50.47(b) to determine if the revision adequately implemented the requirements of 10 CFR 50.54(q). This review was not documented in a safety-evaluation report and did not constitute an approval of the licensees changes; therefore, this revision is subject to future inspection.

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

b. Findings

No findings were identified.

1EP6 Drill Evaluation

Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on March 2, 2011, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the control room simulator, technical support center, operations support center, emergency operations facility, and the joint information 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, the critique package and Condition Report 11-4178 which documents drill deficiencies.

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

b. Findings

No findings were identified.

2RS0 4 Occupational Dose Assessment

a. Inspection Scope

This area was inspected to:

(1) determine the accuracy and operability of personal monitoring equipment,

(2) determine the accuracy and effectiveness of the licensees methods for determining total effective dose equivalent, and

(3) ensure occupational dose is appropriately monitored. The inspectors used the requirements in 10 CFR Part 20, the technical specifications, and the licensees procedures required by technical specifications as criteria for determining compliance. During the inspection, the inspectors interviewed licensee personnel, performed walkdowns of various portions of the plant, and reviewed the following items:

• External dosimetry accreditation, storage, issue, use, and processing of active and passive dosimeters

• The technical competency and adequacy of the licensees internal dosimetry program

• Adequacy of the dosimetry program for special dosimetry situations such as declared pregnant workers, multiple dosimetry placement, and neutron dose assessment

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

These activities constitute completion of the one required sample as defined in Inspection Procedure 71124.04-05.

b. Findings

No findings were identified.

2RS0 5 Radiation Monitoring Instrumentation

a. Inspection Scope

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

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

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

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

• Selected plant configurations and alignments of process, post-accident, and effluent monitors with descriptions in the Final Safety Analysis Report and the offsite dose calculation manual

• Select instrumentation, including effluent monitoring instrument, portable survey instruments, area radiation monitors, continuous air monitors, personnel contamination monitors, portal monitors, and small article monitors to examine their configurations and source checks

• Calibration and testing of process and effluent monitors, laboratory instrumentation, whole body counters, post-accident monitoring instrumentation, portal monitors, personnel contamination monitors, small article monitors, portable survey instruments, area radiation monitors, electronic dosimetry, air samplers, and continuous air monitors

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

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

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 In-depth Review of Operator Workarounds

a. Inspection Scope

During the week of March 21, 2011, the inspectors reviewed the Units 1 and 2 operator workarounds, as well as the cumulative effects of the workarounds to:

(1) determine if the functional capability of the system is affected;

(2) determine if

multiple mitigating systems could be affected;

(3) evaluate the effect of the operator workaround on the operators ability to implement, respond correctly and timely to abnormal or emergency operating procedures; and

(4) verify that the licensee has identified and implemented appropriate corrective actions associated with operator workarounds. Specific documents reviewed during this inspection are listed in the attachment.

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

b. Findings

No findings were identified.

4OA3 Event Follow-up

.1 (Closed) Licensee Event Report LER 05000498/2010-003-00, Unit 1 Reactor Trip

During Surveillance Testing This LER discussed a Unit 1 reactor trip during surveillance testing. The inspectors reviewed this LER and determined that it satisfactorily described the event, root cause, and corrective actions. The event and enforcement aspects of this LER are discussed in detail in Section 1R22. This LER is closed.

4OA5 Other Activites

.1 (Open) NRC TI 2515/177, Managing Gas Accumulation in Emergency Core Cooling,

Decay Heat Removal and Containment Spray Systems (NRC Generic Letter 2008-01)

As documented in Section 1R15, the inspectors confirmed the acceptability of the described licensees actions. This inspection effort counts towards the completion of TI 2515/177 which will be closed on a later Inspection Report.

4OA6 Meetings

Exit Meeting Summary

On January 11, 2011, the inspectors discussed the inspection results of the licensed operator requalification program annual operating test with Mr. T. Hurley, Operations Training Requalification Supervisor. The licensee acknowledged the results. The inspectors confirmed that proprietary information was not provided or examined during the inspection.

On March 10, 2011, the inspectors presented the results of the radiation safety inspections 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 asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

On March 16, 2011, the inspectors conducted a telephonic exit meeting to present the results of the in office inspection of changes to the licensees emergency plan to Mr. G. Hildebrant, Manager, Plant Protection, and other members of the licensees staff. The licensee acknowledged the issues presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

On March 17, 2011, the inspectors presented the preliminary inspection results of the evaluation of changes and plant modifications to Mr. R. Engen, Site Engineering Director, and other members of the licensees staff. The licensee acknowledged the issues presented. While some proprietary information was reviewed during this inspection, no proprietary information was included in this report.

On April 7, 2011, the inspectors presented the inspection results to Mr. K. Richards, Senior Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

R. Aguilera, Manager, Health Physics

C. Albury, Supervising Engineer, Configuration Management

J. Ashcraft, Quality Sr. Consulting Specialist

A. Barnett; System Engineer

M. Berg, Manager, Design Engineering

C. Bowman, General Manager, Nuclear Safety Assurance

J. Calvert, Manager, Training

D. Cobb, STP Employee Concerns Program (EAP) Manager

R. Dunn Jr., Manager, Nuclear Fuel and Analysis

L. Earls, PhD, CHP; Consulting Engineer and Inspection Coordinator

R. Engen, Site Engineering Director

M. Foster, Operations Support

T. Frawley, Manager, Operations

E. Halpin, President and Chief Executive Officer

E. Harper, Design Engineering Department

W. Harrison, Manager, Licensing

G. Hildebrandt, Manager, Plant Protection

D. Hoppes, Nuclear Fuels Analysis and Design

K. Howard, Design Engineering Department

G. Janak, Manager, Operations Division, Unit 1

B. Jenewein, Manager, Systems Engineering

R. Kersey, Design Engineering

S. Korenek, Emergency Preparedness

J. Lovejoy, Manager, I&C Maintenance

N. Mayer, Manager, Projects

A. McGalliard, Manager, Performance Improvement

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

M. Oswald, Supervising Engineer, Configuration Management

J. Paul, Engineer, Licensing Consultant

L. Peter, Plant General Manager

C. Pham, Materials Engineering Department

J. Pierce, Manager, Operations Training

G. Powell, Vice President, Tech Support and Oversight

B. Quarles, Engineering Administrative Services

M. Reddix, Manager, Security

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

K. Reynolds, Staff Nuclear Chemist

K. Richards, Senior Vice President

M. Ruvalcaba, Manager, Testing and Programs

Attachment

R. Savage, Engineer, Licensing Staff Specialist

M. Schaefer, Manager, Maintenance

W. Schultz, Design Engineering

K. Scoggins; Supervisor, Metrology Lab

W. Sotos, Design Engineering Department

K. Taplett, Senior Engineer, Licensing Staff

D. Whiddon, Supervisor, Quality

J. Winters; Senior Engineering Specialist Consultant

D. Zink, Supervising Engineering Specialist

NRC Personnel

J. Dixon; Senior Resident Inspector

B. Tharakan, Resident Inspector

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

Inadequate Restoration Results in Void in High Head

05000499/2011002-01 NCV Safety Injection Pump 2C (Section 1R15)

05000498/2011002-02 Failure to Perform an Immediate Operability Determination NCV

05000499/2011002-02 (Section 1R15)

Untimely Corrective Action to Correct Nonconforming

05000498/2011002-03 NCV Steam Generator Power Operated Relief Valve Condition

05000499/2011002-03 (Section 1R22)

Failure to Follow Reactor Protection System Procedure

05000498/2011002-04 NCV Results in Automatic Reactor Trip (Section 1R22)

Closed

05000498/2010-03-00 LER Unit 1 Reactor Trip During Surveillance Testing Attachment