IR 05000498/2010003

IR 05000498-10-003, 05000499-10-003 on 04/01/10 - 06/30/10 for South Texas Project Electric Generating Station, Units 1 and 2, Integrated Resident and Regional Report, Operability Evaluations, Identification and Resolution of Problems

ML102170042
Person / Time
Site:	South Texas
Issue date:	08/04/2010
From:	Webb Patricia Walker NRC/RGN-IV/DRP/RPB-A
To:	Halpin E South Texas
References
IR-10-003
Download: ML102170042 (82)

Text

August 4, 2010

Mr. Edward 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 05000498/2010003 AND 05000499/2010003

Dear Mr. Halpin:

On June 30, 2010, 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 8, 2010, with Mr. Tim Powell, Vice President, Engineering, 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.

This report documents three NRC-identified findings, two Severity Level IV and one of very low safety significance (Green). Two of these findings were determined to involve violations of NRC requirements. However, because of the very low safety significance and because they are entered into your corrective action program, the NRC is treating these findings as noncited violations, consistent with Section VI.A.1 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 South Texas Project Electric Generating Station, Units 1 and 2, facility. In addition, if you disagree with the crosscutting 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 South Texas Project Electric Generating Station, Units 1 and 2, facility.

UNITED STATES NUCLEAR REGULATORY COMMISSION R E GI ON I V 612 EAST LAMAR BLVD, SUITE 400 ARLINGTON, TEXAS 76011-4125

STP Nuclear Operating Company

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In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, and its enclosure, will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records component of NRCs document system (ADAMS).

ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Wayne Walker, Chief Project Branch A Division of Reactor Projects

Dockets: 50-498 50-499 Licenses: NPF-76 NPF-80

Enclosure:

NRC Inspection Report 05000498/2010003 and 05000499/2010003 w/Attachment: Supplemental Information

REGION IV==

Docket:

05000498, 05000499 License:

NPF-76, NPF-80 Report:

05000498/2010003 and 05000499/2010003 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, 2010 Inspectors:

T. Buchanan, Reactor Inspector J. Dixon, Senior Resident Inspector M. Hayes, Resident Inspector, Columbia Generating Station N. Hernandez, Project Engineer R. Kopriva, Senior Reactor Inspector L. Ricketson, P.E., Senior Health Physicist D. Stearns, Health Physicist B. Tharakan, CHP, Resident Inspector B. Tindell, Resident Inspector, Comanche Peak Accompanied By:

C. Denissen, Reactor Inspector in-training (NSPDP)

Approved By:

Wayne Walker, Chief, Project Branch A Division of Reactor Projects

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Enclosure

SUMMARY OF FINDINGS

IR 05000498/2010003, 05000499/2010003; 04/01/2010 - 06/30/2010; South Texas Project

Electric Generating Station, Units 1 and 2, Integrated Resident and Regional Report; Operability Evaluations; Identification and Resolution of Problems.

The report covered a 3-month period of inspection by resident inspectors and announced baseline inspections by region based inspectors. Three NRC-identified findings, two Severity Level IV noncited violations, and one Green finding of significance were identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609, Significance Determination Process. 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: Mitigating Systems

• Severity Level IV. The inspectors identified a Severity Level IV noncited violation of 10 CFR 50.73(a)(1) for not submitting the required licensee event reports within 60 days after discovery of the failure of Unit 1 main steam isolation valve 1D to fully close. On September 17, 2009, Unit 1 main steam isolation valve 1D was discovered to be inoperable due to construction of a scaffold that blocked the valve from fully closing. As a result of prompting by the inspectors, the licensee concluded that the event should have been reported as a safety system functional failure per 10 CFR 50.73(a)(2)(v)(C). Consequently, the licensee submitted revision 1 to the licensee event report on March 25, 2010. As a corrective action the licensee established a reportability review board, plans to conduct training, and plans to update station procedures to better ensure events are reviewed against all reporting requirements. This issue was entered in the corrective action program as Condition Reports 09-21021 and 09-20125.

The failure to make a required NRC report was considered a performance deficiency. This finding is more than minor because the NRC relies on licensees to identify and report conditions or events meeting the criteria specified in the regulations in order to perform its regulatory function. Because this issue affected the NRCs ability to perform its regulatory function, it was evaluated using the traditional enforcement process. Traditional enforcement violations are not screened for crosscutting aspects. The inspectors concluded that the failure to make a required licensee event report was a Severity Level IV violation using Section IV.A.3 and Supplement I Paragraph D.4, of the NRC Enforcement Policy, dated March 16, 2005 (Section 1R15).

• Severity Level IV. The inspectors identified a Severity Level IV noncited violation of 10 CFR 50.73(a)(1) for not submitting the required licensee event reports within 60 days after discovery that the fire water supply header was isolated to fire areas in Unit 2 where the fire hazard analysis credits water suppression for the achievement of safe shutdown in the event of a fire. Following prompting by the inspectors, the licensee determined that the impact to the safe shutdown equipment should have been reported as an unanalyzed condition per 10 CFR 50.73(a)(2)(ii)(B). As a corrective action the licensee established a reportability review board, plans to conduct training, and plans to update station procedures to better ensure events are reviewed against all reporting requirements. This issue was entered into the licensees corrective action program as Condition Reports 09-20106 and 09-20125.

This finding is more than minor because the NRC relies on licensees to identify and report conditions or events meeting the criteria specified in the regulations in order to perform its regulatory function. Because this issue affected the NRCs ability to perform its regulatory function, it was evaluated using the traditional enforcement process. Traditional enforcement violations are not screened for crosscutting aspects. The inspectors concluded that the failure to make a required licensee event report was a Severity Level IV violation using Section IV.A.3 and Supplement I Paragraph D.4, of the NRC Enforcement Policy, dated March 16, 2005 (Section 1R15).

Green.

The inspectors identified a Green finding for the failure to identify specific design parameters and the impact of changes on the anticipated transient without scram mitigation system actuation circuitry (AMSAC) in accordance with station Procedure 0PGP04-ZE-0309, Design Change Package, Revision 6. In 1999, the licensee performed a design change review to replace steam generators in Unit 1 and 2. In conjunction with steam generator replacement, the licensee switched from using Logic 2 (low main feedwater flow) of the generic AMSAC design to Logic 1 (low steam generator water level) of the generic AMSAC design. However, the licensee failed to identify and evaluate the impacts to the C-20 permissive disarming time delay setting, which was required to be changed from 260 seconds to 360 seconds for Logic 1 (low steam generator water level). The licensees corrective action plan is to update the C-20 permissive disarming time delay setting with a site specific value. This issue was entered into the licensees corrective action program as Condition Report 10-3630.

The finding is more than minor because the reduced time delay may have affected the availability of AMSAC to perform its function to initiate auxiliary feedwater when necessary and therefore affected the Mitigating Systems Cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Using Phase 1 of the Significance Determination Process as described in Inspection Manual Chapter 0609, Attachment 4, dated January 10, 2008, the finding was determined to be of very low safety significance because it was a design deficiency that did not result in the loss of functionality. The finding did not have any crosscutting aspects because it occurred more than three years ago and is not indicative of current licensee performance in that the licensee has significantly improved their design review process since the performance deficiency occurred (Section 4OA2).

Licensee-Identified Violations

None

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at 100 percent rated thermal power and remained there until May 26, 2010, when the unit reduced power to 89 percent rated thermal power to maintain condenser vacuum following a main condenser water box tube leak. On May 29, the unit was returned to 100 percent rated thermal power and essentially remained there for the remainder of the inspection period.

Unit 2 began the inspection period in Refueling Outage 2RE14, which commenced on March 27. The unit went critical, and closed the main generator output breaker on May 1. On May 5, the unit achieved 100 percent rated thermal power 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

.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:

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

• The explanations for the events

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

• The notifications from the transmission system operator to the plant when the offsite power system was returned to normal During the inspection, the inspectors focused on plant-specific design features and the procedures used by plant personnel to mitigate or respond to adverse weather conditions. Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and performance requirements for systems selected for inspection, and

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

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

The inspectors reviews focused specifically on the following plant systems:

• June 3, 2010, Units 1 and 2, 345 kV switchyard (north and south bus),13.8 kV unit auxiliary transformers, and 4160 V emergency safeguards features transformers 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 for Seasonal Extreme Weather Conditions

a. Inspection Scope

The inspectors performed a review of the adverse weather procedures for seasonal extremes (e.g., extreme high temperatures, extreme low temperatures, or hurricane season preparations). The inspectors verified that weather-related equipment deficiencies identified during the previous year were corrected prior to the onset of seasonal extremes; and evaluated the implementation of the adverse weather preparation procedures and compensatory measures for the affected conditions before the onset of, and during, the adverse weather conditions.

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 UFSAR and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant-specific procedures. Specific documents reviewed during this inspection are listed in the attachment. The inspectors also reviewed corrective action program items to verify that plant personnel were 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 25, 2010, Units 1 and 2, isolation valve cubicle rooms - which contain auxiliary feedwater pumps, main steam safety valves, and main feedwater isolation valves These activities constitute completion of one readiness for seasonal adverse weather sample as defined in Inspection Procedure 71111.01-05.

b. Findings

No findings were identified.

1R04 Equipment Alignments

.1 Partial Walkdown

a. Inspection Scope

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

• April 29, 2010, Unit 2, residual heat removal train 2C

• June 10, 2010, Unit 1, essential cooling water train B 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 two partial system walkdown samples as defined in Inspection Procedure 71111.04-05. Also, additional activities were performed during this system walkdown that were associated with Temporary Instruction (TI) 2515/177, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems. This activity is described in bullet

.3 of this

section.

b. Findings

No findings were identified.

.2 Complete Walkdown

a. Inspection Scope

On April 29, 2010, the inspectors performed a complete system alignment inspection of the Unit 2 high head safety injection system train 2C to verify the functional capability of the system. The inspectors selected this system because it was considered both safety significant and risk significant in the licensees probabilistic risk assessment.

The inspectors inspected the system to review mechanical and electrical equipment line ups, electrical power availability, system pressure and temperature indications, as appropriate, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. The inspectors reviewed a sample of past and outstanding work orders to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the corrective action program database to ensure that system equipment-alignment problems were being identified and appropriately resolved.

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

These activities constitute completion of one complete system walkdown sample as defined in Inspection Procedure 71111.04-05. Also, additional activities were performed during this system walkdown that were associated with TI 2515/177, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems. This activity is described in bullet

.3 of this section.

b. Findings

No findings were identified.

.3 System Walkdown Associated with TI 2515/177, Managing Gas Accumulation in

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

a. Inspection Scope

On April 29, 2010, the inspectors conducted a walkdown of the Unit 2 residual heat removal system train 2C and the high head safety injection system train 2C in sufficient detail to reasonably assure the acceptability of the licensees walkdowns (TI 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 (TI 2515/177, Section 04.02.c.3).

In addition, the inspectors verified that the licensee had isometric drawings that describe the Unit 2 residual heat removal system train 2C and the high head safety injection system train 2C system configurations and had acceptably confirmed the accuracy of the drawings (TI 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 (TI 2515/177, Section 04.02.b).

Documents reviewed are listed in the attachment to this report.

This inspection effort counts toward the completion of TI 2515/177 which will be closed in a later inspection report. See Section 4OA5 for additional information.

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:

• June 6, 2010, Unit 1 and Unit 2, fire pump house, Fire Zones Z801, Z802, Z803, and Z804

• June 6, 2010, Unit 2, standby diesel generator 21, Fire Zone Z502

• June 22, 2010, Unit 1, train A control room heating, ventilation, and air conditioning equipment room, Fire Zone Z005

• June 22, 2010, Unit 1, train B control room heating, ventilation, and air conditioning equipment room, Fire Zone Z039 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 fire hazards analysis report and the fire preplans, 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.

.2 Annual Fire Protection Drill Observation

a. Inspection Scope

On June 9, 2010, the inspectors observed a fire brigade activation for an oil fire near the Unit 2 auxiliary transformer. 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 UFSAR, 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 10, 2010, Units 1 and 2, class 1E electrical manholes

• June 25, 2010, Unit 1, electrical auxiliary building 10 foot elevation 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.

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 Unit 2 component cooling water/essential cooling water heat exchangers for trains A and C. 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.

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, Boric Acid Corrosion Control (71111.08-02.01)

a. Inspection Scope

The inspectors reviewed four types of nondestructive examination activities and two welds on the reactor coolant system pressure boundary associated with the Unit 2 refueling outage. The inspectors also reviewed five examinations with relevant indications, including one relevant indication that had been accepted by licensee personnel for continued service.

The inspectors directly observed the following nondestructive examinations:

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Auxiliary Feedwater System Auxiliary feedwater system piping to steam generator 2C, lugs attached to pipe:

8-AF-2012-GA2[C]/25PL1-25PL8 8-AF-2012-GA2[C]/27PL1-27PL8 Magnetic Particle Testing Safety Injection Safety injection suction piping from refueling water storage tank, pipe lugs for support hanger:

24-SI-2101-UB2/8PL1-8PL8 Penetrant Testing Residual Heat Removal Residual heat removal pump 2B suction motor operated valve body to bonnet lip seal weld Penetrant Testing Reactor Coolant System Pressurizer surge line - 16 inch pipe to pipe welds: 16-RC-2412-NSS Weld 2 (reactor coolant system 101880)

Ultrasonic Testing

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Reactor Coolant System Pressurizer surge line - 16 inch pipe to pipe welds: 16-RC-2412-NSS Weld 3 (reactor coolant system 101890)

Ultrasonic Testing Reactor Coolant System Pressurzer safety valve nozzle N-3, nozzle to safe-end and safe-end to pipe weld overlay Ultrasonic Testing Reactor Coolant System Pressurizer surge line nozzle N-1, nozzle to safe-end and safe-end to pipe weld overlay Ultrasonic Testing Residual Heat Removal Residual heat removal pump 2B suction motor-operated valve body to bonnet lip seal weld Visual Testing - 1 Component Cooling Water Heat Exchanger Component cooling water heat exchanger support structure:

CC CLG HTX/CCX3A Visual Testing - 3 The inspectors reviewed records for the following nondestructive examinations:

SYSTEM IDENTIFICATION EXAMINATION TYPE Reactor Coolant System Pressurizer spray nozzle N-2, nozzle to safe-end and safe-end to pipe weld overlay Ultrasonic Testing Reactor Coolant System Pressurizer relief nozzle N-4A, nozzle to safe-end and safe-end to pipe weld overlay Ultrasonic Testing Reactor Coolant System Pressurizer safety nozzle N-4B, nozzle to safe-end and safe-end to pipe weld overlay Ultrasonic Testing Reactor Coolant System Pressurizer safety nozzle N-4C, nozzle to safe-end and safe-end to pipe weld overlay Ultrasonic Testing Reactor Coolant System Reactor coolant pump casing weld RCP-2C-PC Visual Testing - 1 During the review and observation of each examination, the inspectors verified that activities were performed in accordance with ASME Boiler and Pressure Vessel Code requirements and applicable procedures. None of the above observed or reviewed

nondestructive examinations identified any relevant indications and cognizant licensee personnel stated that no relevant indications were accepted by the licensee for continued service. The inspectors also verified the qualifications of all nondestructive examination technicians performing the inspections were current.

The inspectors reviewed five relevant conditions identified on nondestructive examination reports for Code Class 1 and 2 systems during Refueling Outage 2RE13.

Corrective actions, including repair or replacement of the component were taken on four of the five relevant conditions. The last relevant condition was acceptable per the code.

EXAMINATION CATEGORY ITEM NUMBER ITEM DESCRIPTION EVALUATION OF DESCRIPTION C-C C3.30 Residual heat removal pump 2A integrally welded attachment, DWG. B-RHRP-2 CR-08-15937 Flaw indication.

Table IWB-3514-2 states flaw length of 1/8 inch is allowable per code The inspectors directly observed a portion of the following welding activities:

SYSTEM WELD IDENTIFICATION WELD TYPE Reactor Coolant System Rigid sway strut - Component ID.

DCN 0901340, Drawing # RC-9123-RR0001, Revision 4 Manual Shield Metal Arc Welding Reactor Coolant System Residual heat removal pump 2B suction motor operated valve body to bonnet lip seal weld (RH0061B)

Manual Gas Tungsten Arc Welding The inspectors reviewed records of the following welding activities:

SYSTEM WELD IDENTIFICATION WELD TYPE Reactor Coolant System Reactor coolant pump 2D seal 1 injection throttle valve, 2R172TCV0032D Manual Gas Tungsten Arc Welding 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 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

No vessel upper head penetration inspection was performed this outage due to the replacement of the Unit 2 reactor pressure vessel head during this outage. The required inspections for the new reactor vessel head have been performed and documented in Section 4OA5.

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-0133, Boric Acid Corrosion Control Program, Revision 2, and Procedure 0PGP03-ZE-0033, RCS Pressure Boundary Inspection for Boric Acid Leaks, Revision 10. The inspectors reviewed visual records of components and equipment containing boric acid leaks and performed walkdowns of residual heat removal pump 2C and the associated valve room and portions of the Chemical and Volume Control System. 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 the 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 steam generators were not required to be inspected during Refueling Outage 2RE14. South Texas Project Electric Generating Station Technical Specification 6.8.3.o., The Steam Generator Program, establishes the criteria for inspection of the steam generators. Per Technical Specification 6.8.3.o., The program shall be established and implemented to ensure that steam generator tube integrity is maintained. In addition, the program shall include the following provisions: Inspect 100 percent of the tubes at sequential periods of 144, 108, 72, and, thereafter, 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspections of the steam generators. The steam generators were replaced in the fall of 2002, during Refueling Outage 2RE09. The licensee completed a full, 100 percent inspection of the steam generators in the spring of 2004, Refueling Outage 2RE10.

In addition, the program requires the licensee to inspect 50 percent of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50 percent by the refueling outage nearest the end of the period. Inspection of 50 percent of the tubes was performed in the last Refueling Outage 2RE13. Per their program, the next interval for any steam generator inspection will be during the spring of 2013, Refueling Outage 2RE16.

These actions constitute completion of the requirements for Section 02.04.

b. Findings

No findings were identified.

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

a. Inspection scope

The inspectors reviewed 13 condition reports which dealt with inservice inspection activities and found the corrective actions were appropriate. From this review, the inspectors concluded that the licensee has an appropriate threshold for entering 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 operating experience. Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements for Section 02.05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

On June 23, 2010, 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.

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

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:

• May 20, 2010, Units 1 and 2, rod control and rod indication related to replacement reactor vessel heads and anomalies associated with outward rod movement

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:

• April 1 through May 1, 2010, Unit 2 Refueling Outage 2RE14 and Unit 1 emergent activities on turbine-driven auxiliary feedwater pump 14 which required entry into the configuration risk management program for exceeding the front stop

• May 28, 2010, Unit 1, rod control cabinet 1AC regulation card replacement due to failure that resulted in shutdown bank A group 1 and control bank C group 1 being declared inoperable

• June 7, 2010, Unit 2, standby diesel generator 21 5-year maintenance overhaul 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 three maintenance risk assessments and emergent work control inspection samples as defined in Inspection Procedure 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• May 18, 2010, Unit 2, reactor coolant pump 2C boric acid leak evaluation

• June 23, 2010, Unit 1, main steam isolation valve 1D failing to fully close as a result of scaffolding

• June 23, 2010, Unit 2, isolation of fire protection main ring header to three fire areas with redundant safe shutdown equipment where automatic suppression is credited

• June 29, 2010, Unit 1 and Unit 2, Beacon computer code used for power distribution measurements required two vendor recommended changes for increased accuracy 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 five operability evaluations inspection samples as defined in Inspection Procedure 71111.15-05.

b. Findings

(1) Main Steam Isolation Valve 1D

Introduction.

The inspectors identified a Severity Level IV noncited violation of 10 CFR 50.73(a)(1) for not submitting the required licensee event reports (LERs) within 60 days after discovery of the failure of Unit 1 main steam isolation valve 1D to fully close. For further information see NRC Inspection Report 05000498/2009005 Sections 4OA3 and 4OA7.

Description.

On September 17, 2009, Unit 1 main steam isolation valve 1D was discovered to be inoperable due to construction of a scaffold, built on September 14, 2009, that blocked the valve from fully closing. The scaffold was removed later in the day on September 17, 2009. The technical specification for the main steam isolation valves allows for one valve to be inoperable, but open, and operation at full power to continue for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, or the Configuration Risk Management Program requirements are met, or be in at least hot standby within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. The licensee correctly identified that the condition of violating the technical specification existed since the valve was inoperable for greater than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, however, the licensee failed to further evaluate the condition for other applicable reporting requirements. As a result, on Revision 0 of the LER the licensee only reported the failure to comply with the technical specification. The inspectors continued to question the licensee further as the LER stated that the main steam valves safety function was to close and that the valve would have failed to fully close. As a result, the licensee re-evaluated the reportability and concluded that the event should have also been reported as an LER for a safety

system functional failure per 10 CFR 50.73(a)(2)(v)(C). Consequently, the licensee submitted Revision 1 to the LER on March 25, 2010, to document the safety system functional failure. Since this finding also impacted the safety system functional failure performance indicator that is reported to the NRC, they also had to make a revision to the previously submitted performance indicator data. As a result of failing to report to the NRC for both the LER and the performance indicator, the inspectors used the traditional enforcement process. The inspectors determined that the underlying cause of the failure to recognize the need to report the event as a safety system functional failure was the licensees less than thorough evaluation of reporting requirements. During the licensees initial reportability review, they acknowledged the technical specification reporting requirement and then failed to review the event against the other reporting requirements thinking that this was not necessary as the event was already determined to be reportable. Had the licensee thoroughly evaluated the root cause report that was used in generating Revision 0 of the LER, the licensee should have reasonably concluded that even though the root cause report only listed the technical specification violation that enough information was provided to determine that the safety function was also affected.

Analysis.

The failure of South Texas Project Nuclear Operating Company to make a required NRC report was considered a performance deficiency. This finding is more than minor because the NRC relies on licensees to identify and report conditions or events meeting the criteria specified in the regulations in order to perform its regulatory function. Because this issue affected the NRCs ability to perform its regulatory function, it was evaluated using the traditional enforcement process. As a corrective action the licensee established a reportability review board, plans to conduct training, and plans to update station procedures to better ensure events are reviewed against all reporting requirements. Traditional enforcement violations are not screened for crosscutting aspects. The inspectors concluded that the failure to make a required LER was a Severity Level IV violation using Section IV.A.3 and Supplement I Paragraph D.4, of the NRC Enforcement Policy, dated March 16, 2005.

Enforcement.

Title 10 CFR 50.73(a)(1) requires, in part, that the licensee submit an LER for any event of the type described in this paragraph within 60 days after the discovery of the event. Title 10 CFR 50.73(a)(2)(v)(C) requires, in part, the licensee to report any event or condition that could have prevented the fulfillment of the safety function to control the release of radioactive material. Contrary to the above, on November 16, 2009, when the licensee submitted Revision 0 of the LER, the licensee failed to report the event as a safety system functional failure within 60 days after discovery of the event; the licensee corrected the deficiency with Revision 1 dated March 25, 2010. The licensees immediate corrective actions were to review the last 3 years of LER submittals and significant events to ensure that all other reporting requirements were met. Because this finding is of very low safety significance and has been entered into the corrective action program as Condition Reports 09-21021 and 09-20125, this violation is being treated as a noncited violation consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000498/2010003-01, Failure to Submit a Licensee Event Report for a Safety System Functional Failure Associated with a Main Steam Isolation Valve.

(2) Isolation of Fire Protection Main Ring Header to Unit 2

Introduction.

The inspectors identified a Severity Level IV noncited violation of 10 CFR 50.73(a)(1) for not submitting the required LER within 60 days after discovery of the fire water supply header isolated to fire areas in Unit 2 where the fire hazards analysis report credits water suppression for the achievement of safe shutdown in the event of a fire. See NRC Inspection Report 05000499/2008004 Section 4OA2 for additional information.

Description.

On July 7, 2008, both Units 1 and 2 control rooms received fire detection system alarms due to reduced pressure in the fire protection main ring header. Two separate equipment clearance orders were hung without establishing proper configuration controls, and as a result, a majority of the fire protection main ring header was isolated to both Units 1 and 2. The more significant impact was to Unit 2 as this condition adversely impacted three fire areas containing redundant safe shutdown equipment. No fire areas in Unit 1 containing safe shutdown equipment were impacted.

The fire hazards analysis report credits the availability of water suppression in these Unit 2 fire areas for safe shutdown in the event of a fire. The fire protection to Unit 2 was restored roughly 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> later. As part of the licensees investigation into the event, they determined that a lack of equipment clearance order control resulted in two separate work orders for the fire protection main ring header being implemented at the same time without considering the resulting impact. As a result, the licensee changed the equipment clearance order procedures and process to prevent this issue from occurring again. However, the licensee did not consider all reportability aspects of this event until prompted by the inspectors. Upon re-evaluation, the licensee determined that the impact to the safe shutdown equipment should have been reported as an unanalyzed condition per 10 CFR 50.73(a)(2)(ii)(B). The licensees staff had a misconception that reportability typically referred to technical specification violations. This resulted from the licensee not continuing to provide training to individuals who make reportability determinations. The licensee does have some initial training, but no continuing training and since reportability calls are infrequently performed, the licensee failed to ensure that the required skills and proficiency were maintained. As a corrective action, the licensee established a reportability review board, plans to conduct training, and plans to update station procedures to better ensure events are reviewed against all reporting requirements.

Analysis.

The failure of South Texas Project Nuclear Operating Company to make a required NRC report was considered a performance deficiency. This finding is more than minor because the NRC relies on licensees to identify and report conditions or events meeting the criteria specified in the regulations in order to perform its regulatory function. Because this issue affected the NRCs ability to perform its regulatory function, it was evaluated using the traditional enforcement process. Traditional enforcement violations are not screened for crosscutting aspects. The inspectors concluded that the failure to make a required LER was a Severity Level IV violation using Section IV.A.3 and Supplement I Paragraph D.4, of the NRC Enforcement Policy, dated March 16, 2005.

Enforcement.

Title 10 CFR 50.73(a)(1) requires, in part, that the licensee submit an LER for any event of the type described in this paragraph within 60 days after the discovery of the event. Title 10 CFR 50.73(a)(2)(ii)(B) requires, in part, the licensee to report any event or condition that resulted in the nuclear power plant being in an unanalyzed condition. Contrary to the above, on July 6, 2008, when the licensee became aware of the event, the licensee failed to report the event as an unanalyzed condition within 60 days after discovery of the event. The licensee corrected the deficiency with this LER submittal dated March 11, 2010. The licensees immediate corrective actions were to review the last 3 years of LER submittals and significant events to ensure that all other reporting requirements were met. Because this finding is of very low safety significance and has been entered into the corrective action program as Condition Reports 09-20106 and 09-20125, this violation is being treated as a noncited violation consistent with Section VI.A of the NRC Enforcement Policy:

NCV 05000499/2010003-02, Failure to Submit a Licensee Event Report for an Unanalyzed Condition Associated with Fire Water.

1R18 Plant Modifications

.1 Temporary Modifications

a. Inspection Scope

To verify that the safety functions of important safety systems were not degraded, on May 26, 2010, the inspectors reviewed the temporary modification identified as alternate makeup to the fire water storage tank.

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

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

b. Findings

No findings were identified.

.2 Permanent Modifications

On May 4, 2010, the inspectors reviewed key 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 modification identified as the installation of additional heat shields on the Unit 2 reactor vessel head applied to the outermost control rod drive mechanism penetrations.

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

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

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 1, 2010, Unit 1, auxiliary feedwater pump 14, turbine-driven pump overspeed tappet stem replacement

• April 16, 2010, Unit 2, engineered safety features transformer E2B replacement

• May 28, 2010, Unit 1, rod control cabinet 1AC regulation card replacement due to failure that resulted in shutdown bank A group 1 and control bank C group 1 rods being declared inoperable

• June 23, 2010, Unit 2, pressurizer safety relief valve 450, 451, and 452 replacement

• June 24, 2010, Unit 2, reactor coolant pump 2D seal package replacement

• June 30, 2010, Unit 2, standby diesel generator 5-year inspection and surveillance

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 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 six 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 2 2RE14 refueling outage, conducted March 27 through May 1, 2010, 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 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.

• Additionally, the inspectors performed Inspection Procedure 71007 for the Unit 2 reactor vessel head replacement as described in Section 4OA5.

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

.1 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the UFSAR, procedure requirements, and technical specifications to ensure that the four 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 15, 2010, Unit 2, residual heat removal train 2C pressure relief valves, which required system draining and subsequent vent and fill (TI 2515/177)

• April 30, 2010, Unit 2, main steam isolation valve 2A stem to pilot poppet valve replacement

• May 14, 2010, Unit 2, reactor coolant system leakage detection surveillance following Refueling Outage 2RE14

• June 24, 2010, Unit 1, turbine-driven auxiliary feedwater pump 14 inservice test Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of four surveillance testing inspection samples as defined in Inspection Procedure 71111.22-05. Also, additional activities were performed during the review of the residual heat removal train C testing that were associated with TI 2515/177, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems. This activity is described in bullet

.2 of this

section.

b. Findings

No findings were identified.

.2 Surveillance Testing Associated with TI 2515/177, Managing Gas Accumulation in

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

a. Inspection Scope

When reviewing the Unit 2 residual heat removal train 2C fill and vent following maintenance on two pressure relief valves, which required draining the 2C residual heat removal heat exchanger, the inspectors verified that the procedures were acceptable for

(1) testing with shutdown operation, maintenance, and subject system modifications;

(2) void determination and elimination methods; and

(3) postevent evaluation.

The inspectors reviewed procedures used for conducting surveillances and determination of void volumes to ensure that the void criteria was satisfied and will be reasonably ensured to be satisfied until the next scheduled void surveillance (TI 2515/177, Section 04.03.a). Also, the inspectors reviewed procedures used for filling and venting following conditions which may have introduced voids into the subject systems to verify that the procedures acceptably addressed testing for such voids and provided acceptable processes for their reduction or elimination (TI 2515/177, Section 04.03.b). Specifically, the inspectors verified that:

• Gas intrusion prevention, refill, venting, monitoring, trending, evaluation, and void correction activities were acceptably controlled by approved operating procedures (TI 2515/177, Section 04.03.c.1)

• Procedures ensured the system did not contain voids that may jeopardize operability (TI 2515/177, Section 04.03.c.2)

• Procedures established that void criteria were satisfied and will be reasonably ensured to be satisfied until the next scheduled void surveillance (TI 2515/177, Section 04.03.c.3)

• The licensee entered changes into the corrective action program as needed to ensure acceptable response to issues. In addition, the inspectors confirmed that a clear schedule for completion is included for corrective action program entries that have not been completed (TI 2515/177, Section 04.03.c.5)

• Procedures included independent verification that critical steps were completed (TI 2515/177, Section 04.03.c.6)

The inspectors verified the following with respect to surveillance and void detection:

• Specified surveillance frequency was consistent with technical specification requirements (TI 2515/177, Section 04.03.d.1)

• Surveillance frequencies were stated or, when conducted more often than required by technical specifications, the process for their determination was described (TI 2515/177, Section 04.03.d.2)

• Surveillances methods were acceptably established to achieve the needed accuracy (TI 2515/177, Section 04.03.d.3)

• Surveillance procedures included up-to-date acceptance criteria (TI 2515/177, Section 04.03.d.4)

• Procedures included effective follow-up actions when acceptance criteria are exceeded or when trending indicates that criteria may be approached before the next scheduled surveillance (TI 2515/177, Section 04.03.d.5)

• Measured void volume uncertainty was considered when comparing test data to acceptance criteria (TI 2515/177, Section 04.03.d.6)

• Venting procedures and practices utilized criteria such as adequate venting durations and observing a steady stream of water (TI 2515/177, Section 04.03.d.7)

• An effective sequencing of void removal steps was followed to ensure that gas does not move into previously filled system volumes (TI 2515/177, Section 04.03.d.8)

• Qualitative void assessment methods included expectations that the void will be significantly less than allowed by acceptance criteria (TI 2515/177, Section 04.03.d.9)

• Venting results were trended periodically to confirm that the systems are sufficiently full of water and that the venting frequencies are adequate. The inspectors also verified that records on the quantity of gas at each location are maintained and trended as a means of pre-emptively identifying degrading gas accumulations (TI 2515/177, Section 04.03.d.10)

• Surveillances were conducted at any location where a void may form, including high points, dead legs, and locations under closed valves in vertical pipes (TI 2515/177, Section 04.03.d.11)

• The licensee ensured that systems were not preconditioned by other procedures that may cause a system to be filled, such as by testing, prior to the void surveillance (TI 2515/177, Section 04.03.d.12)

• Procedures included gas sampling for unexpected void increases if the source of the void is unknown and sampling is needed to assist in determining the source (TI 2515/177, Section 04.03.d.13)

The inspectors verified the following with respect to filling and venting:

• Revisions to fill and vent procedures to address new vents or different venting sequences were acceptably accomplished (TI 2515/177, Section 04.03.e.1)

• Fill and vent procedures provided instructions to modify restoration guidance to address changes in maintenance work scope or to reflect different boundaries from those assumed in the procedure (TI 2515/177, Section 04.03.e.2)

The inspectors verified the following with respect to void control:

• Void removal methods were acceptably addressed by approved procedures (TI 2515/177, Section 04.03.f.1)

• The licensee had reasonably ensured that the residual heat removal pump is free of damage following a gas-related event in which pump acceptance criteria was exceeded (TI 2515/177, Section 04.03.f.2)

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 in a later inspection report.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

Training Observations

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on May 26, 2010, 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, and the emergency operations facility to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector-observed weaknesses with those identified by the licensee staff in order to

evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the corrective action program. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the attachment.

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

b. Findings

No findings were identified.

2RS0 1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

This area was inspected to:

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

(2) verify the licensee is properly identifying and reporting occupational radiation safety cornerstone performance indicators, and (3)identify those performance deficiencies that were reportable as a performance indicator and which may have represented a substantial potential for overexposure of the worker.

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

• Performance indicator events and associated documentation reported by the licensee in the occupational radiation safety cornerstone

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

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

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

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

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

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

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

b. Findings

No findings were identified.

2RS0 2 Occupational ALARA Planning and Controls

a. Inspection Scope

This area was inspected to assess performance with respect to maintaining occupational individual and collective radiation exposures ALARA. The inspectors used the requirements in 10 CFR Part 20, the technical specifications, and the licensees procedures required by technical specifications as criteria for determining compliance.

During the inspection, the inspectors interviewed licensee personnel and reviewed the following items:

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

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

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

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

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

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

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

b. Findings

No findings were identified.

2RS0 3 In-Plant Airborne Radioactivity Control and Mitigation

a. Inspection Scope

This area was inspected to verify that in-plant airborne concentrations are being controlled consistent with ALARA to the extent necessary to validate plant operations as reported by the performance indicator and to verify that the practices and use of respiratory protection devices onsite do not pose an undue risk to the wearer. The inspectors interviewed licensee personnel and reviewed the following:

• The licensees use, when applicable, of ventilation systems as part of its engineering controls

• The licensees respiratory protection program for use, storage, maintenance, and quality assurance of National Institute for Occupational Safety and Health certified equipment, qualification and training of personnel, and user performance

• The licensee=s capability for refilling and transporting self-contained breathing apparatus air bottles to and from the control room and operations support center during emergency conditions, status of self-contained breathing apparatus staged and ready for use in the plant and associated surveillance records, and personnel qualification and training

• Self-assessments, audits, corrective actions, and reports related to the respiratory protection program and devices Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of the one sample as defined in Inspection Procedure 71124.03-05.

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 2010 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 2009 through the first quarter 2010. 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 2009 through March 2010 to validate the accuracy of the submittals.

The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of 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 2009 through the first quarter 2010. 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 2009 through March 2010 to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of 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 2009 through the first quarter 2010. 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 2009 through March 2010 to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

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

b. Findings

No findings were identified.

.5 Occupational Exposure Control Effectiveness (OR01)

a. Inspection Scope

The inspectors reviewed performance indicator data for the third quarter 2009 through the fourth quarter 2009. The objective of the inspection was to determine the accuracy and completeness of the performance indicator data reported during these periods. The inspectors used the definitions and clarifying notes contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, as criteria for determining whether the licensee was in compliance.

The inspectors reviewed corrective action program records associated with high radiation area (greater than 1 R/hr) and very high radiation area nonconformances. The inspectors reviewed radiological, controlled area exit transactions greater than 100 millirems. The inspectors also conducted walkdowns of high radiation areas (greater than 1 R/hr) and very high radiation area entrances to determine the adequacy of the controls of these areas.

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

b. Findings

No findings were identified.

.6 Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual

Radiological Effluent Occurrences (PR01)

a. Inspection Scope

The inspectors reviewed performance indicator data for the third quarter 2009 through the fourth quarter 2009. The objective of the inspection was to determine the accuracy and completeness of the performance indicator data reported during these periods. The inspectors used the definitions and clarifying notes contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, as criteria for determining whether the licensee was in compliance.

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

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

b. Findings

No findings were identified.

4OA2 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 2010 through June 2010, 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. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one semiannual 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 operations department has had multiple instances of failing to adhere to procedural usage. Examples include: incorrect operation of the Unit 1 turbine-driven auxiliary feedwater pump governor, not arming anticipated transient without scram mitigation system actuation circuitry (AMSAC) before reaching 40 percent rated thermal power, operation of hydrazine valves without any direction, valve position verification issues with essential cooling water and containment purge, Unit 2 turbine-driven auxiliary feedwater acceptance criteria not satisfied, failing to follow prescribed radiation work permits, and performance of activities without the knowledge of the unit supervisor resulting in a violation of technical specifications. All these examples are captured under various condition reports in the licensees corrective action program. The inspectors noted that these events could not be correlated to any particular classification.

The errors were made by both experienced and inexperienced operators as well as by multiple crews on both units. The inspectors expressed some concern due to the recent movement and promotion of senior reactor operators and reactor operators between various positions, on and off shift, and crews. As a result, the

licensee opened a roll-up condition report using these, and other examples to determine if a common cause of the errors exists.

.4 Selected Issue Follow-up Inspection

a. Inspection Scope

During a review of items entered in the licensees corrective action program, the inspectors recognized a corrective action item documenting an operating experience review of an industry event for applicability to the South Texas Project. The inspectors focused on three recent industry events: reactor head replacement lessons learned, presence of vapor in emergency core cooling system in Modes 3/4, and AMSAC implementation. The inspectors reviewed corrective actions documents, procedures, design change packages, design basis documents, the UFSAR, technical specifications, and interviewed station personnel to understand the design specification and the implementation of the systems reviewed. For the reactor head replacement lessons learned and presence of vapor in emergency core cooling system in Mode 3/4, the inspectors determined that the licensee had adequately captured them in the corrective action program and had performed appropriate evaluations to determine the applicability of the events to the station. However, upon review of AMSAC, the inspectors determined that the licensee had not followed the NRC approved Westinghouse requirements for the generic AMSAC design after the steam generators were replaced in each unit. See below for more details and the enforcement aspects of this finding.

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

Introduction.

The inspectors identified a Green finding for the failure to identify specific design parameters and the impact of changes on the AMSAC in accordance with station Procedure 0PGP04-ZE-0309, Design Change Package, Revision 6. When the licensee switched the generic AMSAC design from Logic 2 (low main feedwater flow) to Logic 1 (low steam generator water level), they failed to identify and evaluate the disarming time delay parameter, which should have been changed from 260 seconds to 360 seconds.

Description.

In February 2010, the inspectors reviewed the recent AMSAC operating experience at other nuclear plants, and questioned the licensee about AMSAC implementation at the South Texas Project. The licensee provided information about the AMSAC design and stated that when they replaced steam generators in 2001 for Unit 1 and in 2002 for Unit 2, they switched from using generic AMSAC design Logic 2 (low main feedwater flow) to generic AMSAC design Logic 1 (low steam generator water level). Both AMSAC logics are explained in the Westinghouse document WCAP-10858-P-A, for Generic AMSAC Design, Revision 1, which was approved by the NRC. During original licensing of Units 1 and 2, the licensee committed to implementing the Generic AMSAC Design. On November 23, 1999, the licensee issued

Design Change Package 99-8241-3, to support the steam generator replacement project and to provide justification for changing AMSAC design logic from low feedwater flow initiating signals to low steam generator water level initiating signals. The Generic AMSAC Design document describes a permissive signal, C-20, which arms and disarms AMSAC when reactor power is above and below 40 percent, respectively. According to the Generic AMSAC Design, the disarming signal is supposed to have a delay of approximately 360 seconds so that AMSAC can stay armed long enough to perform its function to initiate auxiliary feedwater to the steam generators, if required.

The inspectors further questioned the licensee about the discrepancy between the Westinghouse value of 360 seconds for the disarming time delay and the time delay the licensee had implemented of 260 seconds. The inspectors reviewed the UFSAR, the supplemental safety evaluation report for AMSAC, and the licensees procedures and determined that the design as implemented by the licensee was not in accordance with the approved licensing basis. Specifically, in 1999, when the licensee issued the design change package, the licensee failed to identify the change to the value of the disarming time delay and the impact of these changes on the function of AMSAC as required by the licensees Procedure 0PGP04-ZE-0309, Design Change Package, Revision 6, Step 4.2.2. Because AMSAC is not a safety-related system, the inspectors considered this to be a performance deficiency and a finding, but not a violation of regulations.

Analysis.

Failure to perform an adequate design change review and identify the impacts of the changes to AMSAC is a performance deficiency. The finding is more than minor because the reduced time delay may have affected the availability of AMSAC to perform its function to initiate auxiliary feedwater when necessary, and therefore affected the Mitigating Systems Cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Phase 1 of the Significance Determination Process as described in Inspection Manual Chapter 0609, Attachment 4, dated January 10, 2008, the finding was determined to be of very low safety significance (Green) because it was a design deficiency that did not result in the loss of functionality. The finding did not have any crosscutting aspects because it occurred more than three years ago and is not indicative of current licensee performance in that the licensee has significantly improved their design review process since the performance deficiency occurred.

Enforcement.

The performance deficiency was not a violation of regulatory requirements because AMSAC is not a safety-related system. The licensee entered this issue into their corrective action program as Condition Report 10-3630. Because this finding was not a violation of regulatory requirements and has very low safety significance, it is identified as FIN 05000498;499/2010003-03, Inadequate Design Change Review of AMSAC."

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

.1 (Closed) LER 05000498/2009-002-01, Main Steam Isolation Valve Blocked from

Closing Revision 0 of this LER was closed in NRC Inspection Report 05000498/2009005 Section 4OA3. Enforcement aspects were documented in Section 4OA7 of NRC Inspection Report 05000498/2009005. No new technical information is provided in Revision 1 of this LER. Revision 1 was submitted to document the safety system functional failure of main steam isolation valve 1D not being able to fully close to satisfy its safety function. The basis for this determination was provided in Revision 0 of the LER; the licensee failed to recognize the additional reporting requirement. The inspectors reviewed the LER, the root and apparent cause reports about the failure to submit the event as a safety system functional failure, interviewed personnel, and reviewed the corrective action program actions to assess the adequacy of the licensees investigation and corrective actions. The enforcement aspects of this violation are documented in Section 1R15 of this report. This LER is closed.

.2 (Closed) LER 05000498/2010-001-00, Unit Shutdown Required by Technical

Specifications On January 6, 2010, during monthly control rod surveillance testing, control rod C-5 had been determined to be inoperable, but trippable, because the control rod could not be moved in the out direction but still could be inserted into the core. During the subsequent monthly surveillance test on February 3, 2010, a second control rod, B-12, was determined to be inoperable, but trippable, because it also could not be moved in the out direction. The licensee attempted to realign the control rod but was unsuccessful and consequently Unit 1 entered Technical Specification 3.0.3 and the unit was shut down to Mode 3. The inspectors reviewed the LER, the root cause investigation report, the technical specifications, surveillance tests, return to service testing of the new control rod drive mechanisms, and interviewed personnel to ensure that the licensees root cause investigation was thorough. The root cause report determined that the most probable cause of the control rods not moving in the out direction and being declared inoperable, but trippable, was corrosion products originating from the fabrication and passivation process of the new control rod drive mechanism latch assemblies. It should be noted that the corrosion products are part of the normal passivation process associated with new components. The amount of corrosion products that are believed to have been released that has interfered with reliable outward control rod movement is what was not expected. As part of the purchase agreement with Westinghouse for the replacement reactor vessel head, Westinghouse did not recommend and South Texas did not specify for the new control rod drive mechanisms to be passivated prior to installation. Previous Westinghouse experience on other replacement reactor vessel heads did not indicate that this was a necessary process, nor did industry operating experience indicate that this would be a concern beyond the initial return to service testing. There was some industry operating experience where other utilities that replaced reactor vessel heads had experienced some control rod mis-stepping or a dropped control rod, but they all occurred during the initial return to service testing or during the first monthly/quarterly control rod surveillance test. To address these

concerns Westinghouse recommended five cold and hot full length excursions of the control rods. There was one international operating experience that determined the problem was not having the latch mechanisms passivated as the root cause, but the conditions that led to that event were substantially different and would not have led Westinghouse or South Texas to perform any different testing or purchase requirement.

In fact, South Texas did ask Westinghouse for further clarifying information on the return to service testing as a result of differences between what Westinghouse recommended and what Mitsubishi Heavy Industries recommend for control rod excursions. Mitsubishi was the manufacturer of the latch mechanisms. Mitsubishi recommended 25 full length excursions. As a result, Westinghouse and Mitsubishi agreed upon five hot and cold excursions as being adequate and was documented as such in a letter to South Texas.

Additionally, since the control rod drive mechanisms were replaced as like for like, there was nothing to indicate during the design change package review that this chemistry issue of passivating the latch mechanisms would be of concern. Therefore, the inspectors determined that a performance deficiency did not exist because the licensee could not have reasonably foreseen and corrected the condition. The licensee conducted a total of 13 control rod drops, and 6 full length exercises to be able to declare the rods operable again. In addition, to address the continuing concern of corrosion products the licensee is performing control rod movement on an increased schedule, twice a week, to ensure the continued reliable operation of the control rods.

The licensee has captured this event in Condition Report 10-1954. This LER is closed.

.3 (Closed) LER 05000499/2010-002-00, Unanalyzed Condition Regarding the Fire

Protection System The inspectors reviewed the LER, the root and apparent cause reports, the Fire Hazards Analysis Report, interviewed personnel, and walked down the Unit 2 fire protection system to ensure that the licensee had implemented appropriate corrective actions.

As a result of further questioning from the inspectors on the reportability of the July 7, 2008, event, where both Units 1 and 2 control rooms received fire detection alarms due to reduced pressure in the fire protection main ring header, the licensee re-evaluated the reportability. The cause of the event was an improper equipment clearance order that isolated the main ring header from Unit 2. The licensee failed to recognize that this event adversely impacted three fire areas that contained redundant safe shutdown equipment, and as a result should have been reported within 60 days of discovery of the event as an unanalyzed condition that significantly degraded plant safety. The enforcement aspects of this violation are documented in Section 1R15 of this report. This LER is closed.

4OA5 Other Activities

.1 Unit 2 Reactor Vessel Head Replacement Inspection

a. Inspection Scope

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

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

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

(1) crane and rigging equipment,

(2) reactor vessel head component drop analysis,

(3) safe load paths, and

(4) load lay-down areas.

Radiation Protection The review of radiation protection program controls, planning, and preparation in:

(1) ALARA planning,

(2) dose estimates and tracking,

(3) exposure and contamination controls,

(4) radioactive material management,

(5) radiological work plans and controls,

(6) emergency contingencies, and

(7) project staffing and training plans. This review was performed as part of the baseline inspections conducted during the 2RE14 outage, which is documented in Section 2RS01, 2RS02, and 2RS03 of this report.

Security Considerations and Adverse Impact to Other Unit The inspectors observed security controls and reviewed security plans to verify that any potential adverse impacts on Unit 1 (the operating unit) caused by Unit 2 outage activities were minimized. The inspectors made frequent observations of security actions to verify that the licensee had implemented the appropriate controls for affected vital and protected area barriers during the reactor head replacement activities.

(2) Reactor Vessel Head Fabrication Inspections at Licensee Facility The inspectors used the guidance in Inspection Procedure 71007 to perform the following reactor vessel head fabrication inspection activities.

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

(1) furnace atmosphere,

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

(3) thermocouple installation,

(4) heating and cooling rates,

(5) quenching methods, and

(6) record and documentation requirements.

Non-Destructive Examination (NDE)

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

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

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

(2) certified mill test reports for the welding material for the reactor vessel head cladding;

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

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

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

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

Procedures Inspections were completed to ensure that repair procedures had been established and that these procedures were consistent with applicable ASME Code, material

specification, and contract requirements by verifying:

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

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

(3) records of the repair were maintained, and

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

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

Quality Assurance Program Inspections were conducted to ensure that machining was carried out under a controlled system of operation, a drawing/document control system was in use in the manufacturing process, and that part identification and traceability was maintained throughout processing and was consistent with the manufacturers quality assurance program. In addition, the inspectors ensured that only the specified drawing and document revisions were available on the shop floor and were being used for fabrication, machining, and inspection.

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

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

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

• Area preparation for the outside systems

• Lattice boom crawler crane assembly, disassembly, and operation

• Hydraulic gantry lift system

• Outside bridge and trolley transfer system

• Elevated cantilevered handling device installation and use

• Reactor vessel head lift rig and polar crane

• Downender/upender fixture

• Old reactor vessel head removal

• New reactor vessel head placement

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

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

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

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

(1) defueling;

(2) reactor coolant system draindown;

(3) system isolation;

(4) safety tagging;

(5) radiation protection controls;

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

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

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

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

Storage of Removed Reactor Vessel Head The inspectors reviewed the radiological safety plans and observed the transport, storage, and radiological surveys of the old reactor vessel head to its onsite storage location.

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

(1) containment testing,

(2) licensees post installation inspections and verifications program and its implementation,

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

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

(5) preservice inspection of new welds.

b. Findings

No findings were identified.

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

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

a. Inspection Scope

On April 29, 2010, the inspectors conducted a walkdown of the Unit 2 residual heat removal train 2C and high head safety injection system train 2C in sufficient detail to reasonably assure the acceptability of the licensees walkdowns (TI 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 (TI 2515/177, Section 04.02.c.3).

In addition, the inspectors verified that the licensee had isometric drawings that describe the high head safety injection and residual heat removal system for Unit 2 system configurations and had acceptably confirmed the accuracy of the drawings (TI 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 (TI 2515/177, Section 04.02.b).

Additionally, the inspectors reviewed the corrective action program for identification and resolution of problems or operability concerns associated with the emergency core cooling systems and did not identify any events requiring follow-up inspection.

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 in a later inspection report.

b. Findings

No findings were identified.

.3 (Closed) TI 2515/179, Verification of Licensee Responses to NRC Requirement for

Inventories of Materials Tracked in the National Source Tracking System Pursuant to Title 10, Code of Federal Regulations, Part 20.2207 (10 CFR 20.2207)

a. Inspection Scope

An NRC inspection was performed to confirm that the licensee has reported their initial inventories of sealed sources pursuant to 10 CFR 20.2207 and to verify that the National Source Tracking System database correctly reflects the Category 1 and 2 sealed sources in custody of the licensee. Inspectors interviewed personnel and performed the following:

• Reviewed the licensees source inventory

• Verified the presence of any Category 1 or 2 sources

• Reviewed procedures for and evaluated the effectiveness of storage and handling of sources

• Reviewed documents involving transactions of sources

• Reviewed adequacy of licensee maintenance, posting, and labeling of nationally tracked sources

b. Findings

No findings were identified.

.4 (Closed for Unit 2) TI 2515/172, Reactor Coolant System Dissimilar Metal Butt Welds

The inspectors previously performed TI 2515/172 baseline inspections at South Texas Project, Unit 2, during the spring 2007 Refueling Outage 2RE12, and in October of 2008, during Refueling Outage 2RE13. The results of those inspections are documented in NRC Inspection Reports 05000499/2007003 and 05000499/2008005, respectively.

a. Inspection Scope

Portions of TI 2515/172 were performed at South Texas Project Unit 2, during Refueling Outage 2RE14 in March and April of 2010. The inspectors reviewed the following Unit 2 dissimilar welds:

7. Four reactor pressure vessel (RPV) outlet nozzle to safe-end welds (hot legs)

(RPV2-N1ASE, RPV2-N1BSE, RPV2-N1CSE, RPV2-N1DSE)

8. Four reactor pressure vessel cold leg inlet nozzle to safe-end welds

(RPV2-N2ASE, RPV2-N2BSE, RPV2-N2CSE, RPV2-N2DSE)

Licensees Implementation of the Material Reliability Program-139 Baseline Inspections (03.01)

The inspectors reviewed records of examination activities associated with Material Reliability Program-139. The baseline inspections of the pressurizer dissimilar metal butt welds for Unit 2 were completed during the spring 2007 Refueling Outage 2RE12.

Baseline inspections for dissimilar metal butt welds that are greater than or equal to 4-inch National Pipe Standard and less than or equal to 14-inch nominal pipe size and exposed to temperatures equivalent to the hot leg were volumetrically inspected during October 2008 during Refueling Outage 2RE13. Also included were dissimilar metal butt welds larger than 14-inch nominal pipe size exposed to temperatures equivalent to the hot leg. Baseline inspections for dissimilar metal butt welds that are exposed to temperatures equivalent to the cold leg were volumetrically inspected during April 2010, during Refueling Outage 2RE14. During Refueling Outage 2RE14, the inspectors observed performance and reviewed records of all the structural weld overlay nondestructive examination activities associated with the licensees pressurizer structural weld overlay mitigation effort. Also, the ultrasonic nondestructive examination activities associated with all of the reactor vessel inlet (cold legs) and outlet (hot legs)nozzles were either observed or records reviewed. The licensee elected to reinspect the outlet (hot leg) nozzles again in order to restart the clock on their 10-year inservice inspection plan.

At present, the licensee has not planned any deviations from the baseline inspection requirements of Material Reliability Program-139, and all other applicable dissimilar metal butt weld inspections were scheduled in accordance with Material Reliability Program-139 guidelines.

Volumetric Examinations (03.02)

The licensee performed ultrasonic nondestructive testing on all of the unmitigated dissimilar metal butt welds on the reactor vessel inlet (cold leg) nozzles and all of the outlet (hot leg) nozzles. The reactor vessel nozzle safe-end to pipe welds are not dissimilar metal welds, but were included in the inspection scope. The inspectors did witness two ultrasonic examinations performed on the reactor vessel inlet (cold leg) and one ultrasonic examination performed on the reactor outlet (hot leg) nozzle to safe-end and safe-end to pipe welds.

1. RPV loop B outlet nozzle to safe-end at 338 degrees (RPV2-N1BSE) and

RPV loop B outlet nozzle safe-end to pipe at 338 degrees (29-RC-2201-01)

2. RPV loop A inlet nozzle to safe-end at 247 degrees (RPV2-N2ASE) and

RPV loop A inlet nozzle safe-end to pipe at 247 degrees (27.5-RC-2103-07)

3. RPV loop B inlet nozzle to safe-end at 293 degrees (RPV2-N2BSE) and

RPV loop B inlet nozzle safe-end to pipe at 293 degrees (27.5-RC-2203-05)

During Refueling Outage 2RE14, the inspectors witnessed two ultrasonic examinations performed on the mitigated pressurizer nozzle to safe-end welds (weld overlaid). All of the pressurizer nozzle safe-end to pipe welds are not dissimilar metal welds, but were included in the inspection scope.

1. Pressurizer surge nozzle to safe-end (PRZ-2-N1-SE-WOL) and

Pressurizer surge nozzle N1 safe-end to pipe [1-WOL (N1)]

2. Pressurizer safety nozzle to safe-end (PRZ-2-N3-SE-WOL) and

Pressurizer safety nozzle N3 safe-end to pipe [1-WOL (N3)]

The inspectors reviewed all eight records for all of the reactor vessel inlet (cold leg) and outlet (hot leg) nozzle to safe-end and safe-end to pipe welds. The reactor vessel nozzle safe-end to pipe welds are not dissimilar metal welds, but were included in the inspection scope. Since the weld overlap and volumetric inspections included that section of the piping, inspection coverage met the requirements of Material Reliability Program-139 and no relevant conditions were identified during these examinations.

1. RPV loop A outlet nozzle to safe-end at 202 degrees (RPV2-N1ASE) and

RPV loop A outlet nozzle safe-end to pipe at 202 degrees (29-RC-2101-1)

2. RPV loop B outlet nozzle to safe-end at 338 degrees (RPV2-N1BSE) and

RPV loop B outlet nozzle safe-end to pipe at 338 degrees (29-RC-2201-1)

3. RPV loop C outlet nozzle to safe-end at 22 degrees (RPV2-N1CSE) and

RPV loop C outlet nozzle safe-end to pipe at 22 degrees (29-RC-2301-1)

4. RPV loop D outlet nozzle to safe-end at 158 degrees (RPV2-N1DSE) and

RPV loop D outlet nozzle safe-end to pipe at 158 degrees (29-RC-2401-1)

5. RPV loop A inlet nozzle to safe-end at 247 degrees (RPV2-N2ASE) and

RPV loop A inlet nozzle safe-end to pipe at 247 degrees (27.5-RC-2103-7)

6. RPV loop B inlet nozzle to safe-end at 293 degrees (RPV2-N2BSE) and

RPV loop B inlet nozzle safe-end to pipe at 293 degrees (27.5-RC-2203-5)

7. RPV loop C inlet nozzle to safe-end at 67 degrees (RPV2-N2CSE) and

RPV loop C inlet nozzle safe-end to pipe at 67 degrees (27.5-RC-2303-6)

8. RPV loop D inlet nozzle to safe-end at 113 degrees (RPV2-N2DSE) and

RPV loop D inlet nozzle safe-end to pipe at 113 degrees (27.5-RC-2403.6)

The certification records of ultrasonic examination personnel were reviewed for those personnel that performed the examinations of the mitigated pressurizer nozzle to safe-end weld overlays. All personnel records showed that they were qualified under the EPRI Performance Demonstration Initiative.

No deficiencies were identified during the nondestructive examinations.

Weld Overlays (03.03)

There were no weld overlays performed during Refueling Outage 2RE14. The licensee performed nondestructive examinations on all of the pressurizer nozzle to safe-end weld overlays during Refueling Outage 2RE14. All of the pressurizer nozzle to safe-end welds had been overlaid previously in Refueling Outage 2RE12 NRC Inspection Report 05000499/2007003. All of the pressurizer nozzle safe-end to pipe welds are not dissimilar metal welds, but were included in the inspection scope. There were no deficiencies previously identified in the completed pressurizer full structural weld overlays.

The inspectors reviewed all six of the records for all of the pressurizer nozzle to safe-end welds, and nozzle safe-end to pipe welds (all weld overlaid). Inspection coverage met the requirements of Material Reliability Program-139 and no relevant conditions were identified during these examinations.

1. Pressurizer surge nozzle to safe-end (PRZ-2-N1-SE-WOL) and

Pressurizer surge nozzle N1 safe-end to pipe [1-WOL (N1)]

2. Pressurizer spray nozzle to safe-end (PRZ-2-N2-SE-WOL) and

Pressurizer spray nozzle N2 safe-end to pipe [14-WOL (N2)]

3. Pressurizer safety nozzle to safe-end (PRZ-2-N3-SE-WOL) and

Pressurizer safety nozzle N3 safe-end to pipe [1-WOL (N3)]

4. Pressurizer relief nozzle to safe-end (PRZ-2-N4A-SE-WOL) and

Pressurizer relief nozzle N4A safe-end to pipe [1-WOL (N4A)]

5. Pressurizer safety nozzle to safe-end (PRZ-2-N4B-SE-WOL) and

Pressurizer safety nozzle N4B safe-end to pipe [1-WOL (N4B)]

6. Pressurizer safety nozzle to safe-end (PRZ-2-N4C-SE-WOL) and

Pressurizer safety nozzle N4C safe-end to pipe [1-WOL (N4C)]

The certification records of ultrasonic examination personnel were reviewed for those personnel that performed the examinations of the mitigated pressurizer nozzle to safe-end weld overlays. All personnel records showed that they were qualified under the EPRI Performance Demonstration Initiative.

No deficiencies were identified during the nondestructive examinations.

Mechanical Stress Improvement (03.04)

The licensee did not employ a mechanical stress improvement process.

Inservice Inspection Program (03.05)

The licensee has prepared a Material Reliability Program-139 inservice inspection program. During the review of the licensees categorization of the six mitigated pressurizer nozzle to safe-end weld overlays, the inspectors identified that the licensee had categorized the weld overlays as Category B in accordance with Material Reliability Program -139, Revision 0. The licensee had not updated the categorization change identified in Material Reliability Program-139, Revision 1, where all of the pressurizer nozzle to safe-end weld overlays should have been categorized as Category F. The licensee acknowledged the error and has written Condition Report 08-8788-14 which states: Revise Inservice Inspection Program Plan, Appendix I, Section 1.5, Paragraph 4, to change the category classification from B to F, reference MRP-139, Table 6-1, Note 7. Also review applicable procedures for any required updates. The licensee is currently in the process of reviewing their last 10-year inservice inspection program for any program deficiencies. Their review of the pressurizer weld overlays had not taken place and was scheduled to be completed after the current Refueling Outage 2RE14. The licensee had performed all of the required inspections as identified in Category F, and, therefore, was not delinquent in performing any required examinations.

The inspectors review determined that the inlet (cold leg) and outlet (hot leg) nozzle dissimilar metal butt welds were appropriately categorized in accordance with Material Reliability Program-139 requirements. The inservice inspection frequencies are consistent with the inservice inspection frequencies called for by Material Reliability Program-139.

b. Findings

No findings were identified.

4OA6 Meetings

Exit Meeting Summary

On April 13, 2010, the inspectors presented the results of the inservice inspection to Mr. G. Powell, Vice President, Engineering, and other members of the licensee staff. The

licensee acknowledged the issues presented. The inspectors acknowledged review of proprietary material during the inspection which had been or will be returned to the licensee.

On April 16, 2010, the inspectors presented the results of the radiation protection inspection to Mr. D. Rencurrel, Senior Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified. On April 30, 2010, the inspectors presented additional information to Mr. W. Harrison, Manager, Licensing, by telephone.

On July 8, 2010, the inspectors presented the inspection results to Mr. G. Powell, Vice President, Engineering, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

R. Aguilera, General Supervisor, Health Physics

J. Ashcraft, Manager, Health Physics

M. Berg, Manager, Design Engineering

C. Bowman, General Manager Oversight

J. Calvert, Manager, Training

J. Cook, Supervisor, Engineering Projects

R. Dunn Jr., Manager, Fuels and Analysis

R. Engen, Site Director, Engineering

T. Frawley, Manager, Operations

R. Gangluff, Manager, Chemistry, Environmental and Health Physics

E. Halpin, President and Chief Executive Officer

W. Harrison, Manager, Licensing

G. Hildebrandt, Manager, Plant Protection

G. Janak, Manager, Operations Division, Unit 1

B. Jenewein, Manager, Systems Engineering

J. Lovejoy, Assistant Maintenance Manager

N. Mayer, Manager, Outage and Projects

A. McGalliard, Manager, Performance Improvement

R. McNiel, Manager, Maintenance Engineering

J. Mertink, Manager, Maintenance

J. Milliff, Manager, Operations Division, Unit 2

R. Nieman, Site Authorized Nuclear Inspector (ANII)

J. Paul, Engineer, Licensing Consultant

L. Peter, Plant General Manager

J. Pierce, Manager, Operations Training

J. Pointon, Supervisor, Health Physics

G. Powell, Vice President, Engineering

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, I&C Maintenance

S. Shojaei, Engineer, Testing Programs

K. Silverthorne, Work Control

L. Spiess, Supervisor, Testing Programs

T. Sullivan, Radwaste Supervisor, Health Physics

K. Taplett, Senior Engineer, Licensing Staff

M. Tomek, ALARA Supervisor, Health Physics

J. Williams, Engineer, Testing Programs

C. Younger, Testing Programs

D. Zink, Supervising Engineer

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000498/20100003-01 NCV Failure to Submit a Licensee Event Report for a Safety System Functional Failure Associated with a Main Steam Isolation Valve (Section 1R15)

05000499/2010003-02 NCV Failure to Submit a Licensee Event Report for an Unanalyzed Condition Associated with Fire Water (Section 1R15)

05000498/2010003-03

05000499/2010003-03 FIN Inadequate Design Change Review of AMSAC (Section 4OA2)

Closed

05000498/2009-002-01 LER Main Steam Isolation Valve Blocked from Closing (Section 4OA3)

05000498/2010-001-00 LER Unit Shutdown Required by Technical Specifications (Section 4OA3)

05000499/2010-002-00 LER Unanalyzed Condition Regarding the Fire Protection System (Section 4OA3)