IR 05000498/2009002

IR 05000498-09-002, 05000499-09-002 01/01/2009 - 04/04/2009; South Texas Project Electric Generating Station, Units 1 and 2, Integrated Resident and Regional Report; Maintenance Risk Assessments, Operability Evaluations, and Surveillance Te

ML091140521
Person / Time
Site:	South Texas
Issue date:	04/24/2009
From:	Webb Patricia Walker Division Reactor Projects I
To:	Halpin E South Texas
References
IR-09-002
Download: ML091140521 (38)

Text

UNITED STATES NUC LE AR RE G UL AT O RY C O M M I S S I O N R E GI ON I V 612 EAST LAMAR BLVD , SU I TE 400 AR LI N GTON , TEXAS 76011-4125 April 24, 2009 Mr. Edward D. Halpin, Executive Vice President and Chief Nuclear Officer STP Nuclear Operating Company South Texas Project P.O. Box 289 Wadsworth, TX 77483 Subject: SOUTH TEXAS PROJECT ELECTRIC GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000498/2009002 AND 05000499/2009002

Dear Mr. Halpin:

On April 4, 2009, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your South Texas Project Electric Generating Station, Units 1 and 2, facility. The enclosed integrated inspection report documents the inspection findings, which were discussed on April 9, 2009, with Mr. J. Sheppard, President and Chief Executive Officer, 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 two NRC identified and one self-revealing finding of very low safety significance (Green). All 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 these violations or the significance of the noncited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 612 E. Lamar Blvd, Suite 400, Arlington, Texas, 76011-4125; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the South Texas Project Electric Generating Station, Units 1 and 2, facility. In addition, if you disagree with the characterization of 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 South Texas Project Electric Generating Station. The information you provide will be considered in accordance with Inspection Manual Chapter 0305.

STP Nuclear Operating Company -2-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 C. Walker, Chief Project Branch A Division of Reactor Projects Dockets: 50-498 50-499 Licenses: NPF-76 NPF-80

Enclosure:

NRC Inspection Report 05000498/2009002 and 05000499/2009002 w/Attachment: Supplemental Information

REGION IV==

Docket: 05000498, 05000499 License: NPF-76, NPF-80 Report: 05000498/2009002 and 05000499/2009002 Licensee: STP Nuclear Operating Company Facility: South Texas Project Electric Generating Station, Units 1 and 2 Location: FM521 - 8 miles west of Wadsworth Wadsworth, Texas 77483 Dates: January 1 through April 4, 2009 Inspectors: J. Adams, Reactor Inspector J. Dixon, Senior Resident Inspector S. Graves, Reactor Inspector B. Larson, Senior Operations Engineer C. Ryan, Reactor Inspector W. Sifre, Senior Reactor Inspector B. Tharakan, CHP, Resident Inspector Approved By: Wayne Walker, Chief, Project Branch A Division of Reactor Projects-1- Enclosure

SUMMARY OF FINDINGS

IR 05000498/2009002, 05000499/2009002 01/01/2009 - 04/04/2009; South Texas Project

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

Maintenance Risk Assessments, Operability Evaluations, and Surveillance Testing The report covered a 3-month period of inspection by resident inspectors and announced baseline inspections by regional based inspectors. Three Green noncited violations of very low safety significance were identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609, Significance Determination Process. 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

Green.

The inspectors reviewed a self-revealing noncited violation of 10 CFR 50.65(a)(4), for the failure to assess and manage risk from an emergent maintenance work activity on the solid state protection system during the Unit 2 refueling outage that resulted in a loss of the residual heat removal system. Specifically, on October 25, 2008, the licensee planned an emergent maintenance activity to replace a general logic card on the solid state protection system without adequately assessing the risk to the plant. Consequently, when the logic card was removed, the low steam pressure safety injection actuation signal became unblocked and resulted in the loss of the operating residual heat removal system pumps. The licensees immediate corrective action was to restore the residual heat removal system to operation and enter the issue into their corrective action program.

The finding was more than minor because it was associated with the Mitigating Systems cornerstone attribute of equipment performance and adversely affected the cornerstone objective of availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using the Phase 1 screening criteria of Inspection Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process, Attachment 1, Checklist 4, the finding screened to a Phase 2 quantitative analysis because no residual heat removal loops were in operation. The finding was determined to be of very low safety significance because the Phase 2 screening by the senior reactor analyst concluded that the conditional core damage probability from this event was approximately 1E-08. In addition, this finding had human performance crosscutting aspects associated with decision making H.1(a) because the licensee failed to make risk-significant decisions using a systematic process to ensure safety is maintained, and did not formally define authority and roles for key personnel responsible for implementing these risk-significant decisions (Section 1R13).

Green.

The inspectors identified a noncited violation of Technical Specification 3.7.3 for an inadequate reportability review on the Train A component cooling water low-level actuation switch which failed during surveillance testing. On October 14, 2008, during the 18-month surveillance test,

Unit 2 component cooling water Train A was determined to be inoperable due to the failure of system valves to actuate to their designated positions. The inspectors continued to ask questions related to the event and discovered that the last time the switch was manipulated was January 22, 2008, during a calibration procedure. After the inspectors questioned the reportability, engineering reviewed it and determined that the calibration procedure did not have a functional check of the switch internal contacts before restoration.

Engineering concluded that, as a result of the switch not being functionally checked after the calibration, that the wire must have become disconnected during the restoration section of the procedure. Consequently, from January 22, 2008 through October 16, 2008, the Train A component cooling water low-low level switch was inoperable and therefore reportable. The licensee performed a root cause of the event itself and an apparent cause for operations inappropriately applying time of discovery for the initial reportability review under Condition Reports 08-15541 and 08-19420, respectively.

The finding was more than minor because, if left uncorrected, it would have the potential to lead to a more significant safety concern in that inadequate operability/reportability reviews could result in a degraded system being returned to service, and it affected the Mitigating Systems cornerstone attribute of human performance and the objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using the Significance Determination Process Phase 1 worksheets from Inspection Manual Chapter 0609, the finding was determined to have very low safety significance because it did not result in the actual loss of safety function of one or more trains and it did not screen as risk significant due to seismic, flooding, fire, or severe weather. In addition, this finding had Problem Identification and Resolution crosscutting aspects associated with the corrective action program P.1(c) because the licensee failed to thoroughly evaluate for operability and reportability conditions adverse to quality (Section 1R15).

Green.

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

Appendix B, Criteria V, Instructions, Procedures, and Drawings, for the inadequate surveillance Procedure 0PSP05-CC-0001, FCI CCW Surge Tank Compartment Level Switch Calibration, Revision 7. On October 14, 2008, during the 18-month surveillance test, Unit 2 component cooling water Train A was determined to be inoperable due to the failure of system valves to actuate to their designated positions. Troubleshooting determined that a loose wire was the reason for the inoperability. The wire was restored and the train returned to operable status on October 16, 2008. From January 22 through October 16, 2008, the Train A component cooling water low-low level switch was inoperable. Since this procedure is applicable to all trains of both units, the licensee verified that all other trains low-low level switches on both units were either surveillance tested after the last calibration procedure or were functionally checked using a temporary procedure to ensure operability.

The finding was more than minor because it was similar to several examples in Inspection Manual Chapter 0612, Appendix E, where the system was returned to service without being fully operable, and it affected the Mitigating Systems cornerstone attribute of procedure quality and the objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using the Significance Determination Process Phase 1 worksheets from Inspection Manual Chapter 0609, the finding was determined to have very low safety significance because it did not result in the actual loss of safety function of one or more trains and it did not screen as risk significant due to seismic, flooding, fire, or severe weather. This issue had no crosscutting aspects because the last revision to the procedure was too long ago (2005) to be indicative of current performance (Section 1R22).

Licensee-Identified Violations

None

REPORT DETAILS

Summary of Plant Status

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

Unit 2 began the inspection period at 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

1R04 Equipment Alignments

.1 Partial Walkdown

a. Inspection Scope

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

• March 4, 2009, Unit 2, component cooling water Train A

• April 2, 2009, Unit 2, safety injection system 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, Updated Final Safety Analysis Report, technical specification requirements, administrative technical specifications, outstanding work orders, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down 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.

b. Findings

No findings of significance 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:

• February 10, 2009, Unit 1, channel I distribution and battery rooms, Fire Zones 003 and 084

• February 10, 2009, Unit 2, channel I distribution and battery rooms, Fire Zones 003 and 084

• March 19, 2009, Unit 1, channel III distribution and battery rooms, Fire Zone 043

• March 20, 2009, Unit 2, channel III distribution and battery rooms, Fire Zone 043 The inspectors reviewed areas to assess if licensee personnel had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant; effectively maintained fire detection and suppression capability; maintained passive fire protection features in good material condition; and had implemented adequate compensatory measures for out of service, degraded or inoperable fire protection equipment, systems, or features, in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to affect equipment that could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. Using the documents listed in the attachment, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees corrective action program.

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

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

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

.1 Quarterly Inspection

a. Inspection Scope

On February 19, 2009, the inspectors observed a crew of licensed operators in the plants simulator to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being

conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• Licensed operator performance

• Crews clarity and formality of communications

• Crews ability to take timely actions in the conservative direction

• Crews prioritization, interpretation, and verification of annunciator alarms

• Crews correct use and implementation of abnormal and emergency procedures

• Control board manipulations

• Oversight and direction from supervisors

• Crews ability to identify and implement appropriate technical specification actions and emergency plan actions and notifications The inspectors compared the crews performance in these areas to pre-established operator action expectations and successful critical task completion requirements.

These activities constitute completion of one quarterly licensed-operator requalification program sample as defined in Inspection Procedure 71111.11.

b. Findings

No findings of significance were identified.

.2 Annual Operating Test

a. Inspection Scope

On January 13, 2009, the inspector conducted an in-office review of the results of the Annual Operating Test. The inspector evaluated the following:

• Ninety-four operators (31 reactor operators and 63 senior reactor operators)were examined during this testing cycle of the requalification training program

• Eighteen crews (10 operating and 8 staff) were examined on the facilitys simulator All of the crews passed the dynamic simulator scenarios and all but one reactor operator passed all portions of the Annual Operating Test. The reactor operator was successfully remediated prior to returning to license duties.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

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

• March 30, 2009, Units 1 and 2, solid state protection system overall health 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 of significance 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:

• October 25, 2008, Unit 2, emergent maintenance work activity to replace a circuit card on the solid state protection system causes a safety injection signal that results in a temporary loss of residual heat removal system

• January 12-16, 2009, Units 1 and 2, planned and emergent work on Unit 1 Train A and Unit 2 Train D including the Dow-Velasco Line 18 outage impacts on the main generator

• February 23-27, 2009, Units 1 and 2, planned and emergent work on Unit 1 Train C and Unit 2 Train B including an unquantified maintenance risk assessment on Unit 1, unplanned work on Unit 1 Essential Chiller 12B, and unexpected conditions on Unit 2 steam generator power operated relief valves

• March 2-5, 2009, Units 1 and 2, planned and emergent work on Unit 1 Train D and Unit 2 Train C including unquantified maintenance risk assessment on Unit 2, and unexpected low oil temperature on Essential Chiller 12B

• March 23-27, Unit 1, planned work on Unit 1 Train C including first time evolution of replacing the 125 volt dc Train C E1C11 batteries at power using the risk managed technical specification configuration risk management program to extend the allowed outage time beyond the front stop 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 five maintenance risk assessments and emergent work control inspection samples as defined in Inspection Procedure 71111.13-05.

b. Findings

Introduction.

The inspectors reviewed a self-revealing Green noncited violation of 10 CFR 50.65(a)(4), for the failure to assess and manage risk from an emergent maintenance work activity on the solid state protection system during the Unit 2 refueling outage that resulted in a loss of the residual heat removal system.

Description.

On October 25, 2008, at approximately 11:44 p.m., a safety injection actuation signal was initiated in Unit 2 when a general logic card was removed from the solid state protection system for maintenance. This resulted in the loss of the residual heat removal system when both the running residual heat removal pumps tripped offline.

Unit 2 was in Mode 5 near the end of a refueling outage, and preparations were being

made to enter Mode 4. Earlier in the day, a test switch on the solid state protection system failed to operate as expected during the performance of a surveillance test. The licensee determined that a failed general logic Card A416 caused the test switch to fail the surveillance. Plans were started on dayshift to replace the logic card and later turned over to the nightshift for completion of the work package. During the turnover meeting, partial work package instructions were provided to the nightshift planner. The nightshift planner had limited experience with the solid state protection system and relied upon the notes from the turnover meeting and a non-detailed discussion with the instrumentation and controls manager to complete the work package. The work package was reviewed by the night shift instrumentation and controls coordinator who also had limited experience with the solid state protection system. Due to the reviewers unfamiliarity with the solid state protection system, the package was not thoroughly reviewed for technical accuracy. Instead, the technical review consisted of verifying that the night shift planner had correctly incorporated the meeting notes into the work package. During the planning of this maintenance activity, persons with technical knowledge of the solid state protection system were not consulted to perform a technical review of the work instructions, nor was there a plant procedure to control, assess, and manage the risk associated with emergent maintenance work during an outage.

The inspectors reviewed the licensee event report, the root cause analysis, procedures, turnover meeting notes, the work package, technical specifications, and interviewed key licensee personnel involved in the event. The inspectors determined that during a refueling outage the licensee did not have a formal process or procedure that defined roles and responsibilities for planning, assessing, evaluating, reviewing, approving, managing, and implementing risk-significant emergent maintenance work activities.

Prior to the start of the refueling outage, the licensee completed a shutdown risk assessment to review the schedule and planned outage activities to ensure they maintained adequate defense-in-depth for key safety functions. During the refueling outage, the licensee relied upon a daily 8:30 a.m. meeting to assess and manage emergent work that was not in the planned outage schedule. However, outside of these two processes for assessing and managing risk, the licensee did not have a process to review time critical emergent maintenance work during an outage. As a result, on October 25, 2008, Unit 2 lost the residual heat removal system when the low steam pressure block was removed during the logic Card A416 replacement.

No water was injected into the reactor coolant system because the safety injection pumps were secured as required by technical specifications for the current plant configuration. However, the signal started the engineered safety features load sequencer and emergency diesel generators, and caused the running Train A and C residual heat removal pumps to trip offline. The licensee implemented immediate corrective actions to restore the residual heat removal pumps. Operators manually restarted the Train A residual heat removal pump within 4 minutes and the Train C residual heat removal pump within 6 minutes after being tripped offline. The licensee also revised the work instructions to configure the solid state protection system so that the logic cabinets would be out of service and the actuation trains would be placed in test to perform the maintenance to replace logic Card A416. Long term corrective actions include developing a plant procedure to specify requirements for addressing emergent work during outages.

The inspectors determined that the licensee violated the requirements of 10 CFR 50.65(a)(4) to adequately assess and manage the risks of this corrective maintenance activity. Specifically, the licensee failed to review the work instructions and

the surveillance procedure in sufficient technical detail to assess and manage the risks to the plant in its current configuration.

Analysis.

The failure to adequately assess and manage the risk of corrective maintenance on the solid state protection system was a performance deficiency. The finding was more than minor because it was associated with the Mitigating Systems cornerstone attribute of equipment performance and adversely affected the cornerstone objective because it affected the availability, reliability, and capability of the residual heat removal system to respond to initiating events to prevent undesirable consequences.

Using the Phase 1 screening criteria of Inspection Manual Chapter 0609 Appendix G, Shutdown Operations Significance Determination Process, Attachment 1, Checklist 4, the finding screened to a Phase 2 quantitative analysis because no residual heat removal loops were in operation. The finding was determined to be of very low safety significance (Green) because the Phase 2 screening by the senior reactor analyst concluded that the conditional core damage probability from this event was approximately 1E-08. In addition, this finding had human performance crosscutting aspects associated with decision making H.1(a) because the licensee failed to make risk-significant decisions using a systematic process to ensure safety is maintained, and did not formally define authority and roles for key personnel responsible for implementing these risk-significant decisions.

Enforcement.

10 CFR 50.65(a)(4), requires, in part, that, before performing maintenance activities (including corrective maintenance), the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. Contrary to this, on October 25, 2008, the licensee failed to assess and manage the increase in risk from corrective maintenance activities to the solid state protection system that resulted in the loss of the residual heat removal system when an inadvertent safety injection actuation signal was initiated as a result of the maintenance.

Since this violation is of very low safety significance and it has been entered into the licensees corrective action program as Condition Report 08-16598, this violation is being treated as a noncited violation consistent with Section VI.A.1 of the Enforcement Policy: NCV 05000499/2009002-01, Failure to Assess and Manage Outage Maintenance Risk Activities.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• October 14, 2008, Unit 2, component cooling water surge tank Train A low-low level switch failure to actuate during surveillance testing

• January 27, 2009, Unit 2, Standby Diesel Generator 21 lubricating oil leak

• January 29, 2009, Unit 2, power range Nuclear Instrument NI-42 Detector A milli-amp switch not operating properly resulting in erratic output indication

• February 26, 2009, Unit 2, main steam power operated relief valve actuator oil stratification

• March 9, 2009, Unit 1, incorrect integrated computer system cables installed in the power block

The inspectors selected these potential operability issues based on the risk-significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that technical specification operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the technical specifications and Updated Final Safety Analysis Report to the licensees evaluations, to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. 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

Introduction.

The inspectors identified a Green noncited violation of Technical Specification 3.7.3 for an inadequate reportability review on the Train A component cooling water low-level actuation switch which failed during surveillance testing.

Description.

On October 14, 2008, during the 18-month surveillance test, Unit 2 component cooling water Train A was determined to be inoperable due to the failure of system valves to actuate to their designated positions. This test was conducted on component cooling water Train A surge tank low-low level Switch 4503C which actuates the valves required to mitigate a system leak. Troubleshooting determined that a loose wire on Switch 4503C Terminal 6 was the reason for the inoperability. The wire was restored and the train returned to operable status on October 16, 2008. The shift supervisor immediately recognized the impact to the system and declared the system inoperable. However, the shift supervisor did not consider the impact to past operability.

His log entry states, Condition is not reportable. Loose wire did affect operability and system was declared inoperable at time of discovery. Did not exceed LCO time from time of discovery. As part of his assessment, he did not consider or ask the follow up questions about the loose wire, i.e., why was it loose, did it occur as part of this activity, when was the last time this wire was manipulated, etc. The inspectors continued to ask questions related to the event and discovered that the last time the switch was manipulated was January 22, 2008, during a calibration procedure. As a result of the long time span, the inspectors continued to ask the licensee about past operability and reportability until the licensee opened a reportability review on November 13, 2008.

During this engineering review of the reportability, it was determined that the calibration procedure, Procedure 0PSP05-CC-0001, FCI CCW Surge Tank Compartment Level Switch Calibration, Revision 7, did not have a functional check of the switch internal contacts before completion of the procedure. This is important as the unique method in which the low-low level switch is calibrated. For the switch to be calibrated, a circuit board is removed from its plug and test leads are connected. The circuit board is then reinstalled and calibrated. Upon completion of the calibration the circuit board is removed from its plug and the test leads are removed and the circuit board is reinstalled.

Upon reinstallation there was no functional check of the wires (internal switch contacts)that were manipulated to ensure connectivity, and, therefore, ensure that the

low-low level switch would actuate. Engineering concluded that as a result of the switch not being functionally checked after the calibration that the wire must have become disconnected during the restoration section of the procedure. Consequently, from January 22, 2008 through October 16, 2008, the Train A component cooling water low-low level switch was inoperable. This exceeds the technical specification allowed outage time for the component cooling water system and as a result was reportable. The licensee performed a root cause of the event itself and an apparent cause for operations inappropriately applying time of discovery for the initial reportability review under Condition Reports 08-15541 and 08-19420, respectively. For additional enforcement actions associated with this finding, see Sections 1R22 and 4OA3 of this report.

Analysis.

The inspectors determined that the failure to perform an adequate reportability review for the inoperable Train A component cooling water system was a performance deficiency. The finding was more than minor because, if left uncorrected, it would have the potential to lead to a more significant safety concern in that inadequate operability/reportability reviews could result in a degraded system being returned to service, and it affected the Mitigating Systems cornerstone attribute of human performance and the objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using the Significance Determination Process Phase 1 worksheets from Inspection Manual Chapter 0609, the finding was determined to have very low safety significance (Green)because it did not result in the actual loss of safety function of one or more trains and it did not screen as risk-significant due to seismic, fire, flooding, or severe weather. In addition, this finding had Problem Identification and Resolution crosscutting aspects associated with corrective action program P.1(c) because the licensee failed to thoroughly evaluate for operability and reportability conditions adverse to quality.

Enforcement.

Technical Specification 3.7.3 requires, in part, that three component cooling water loops shall be operable during Modes 1, 2, 3, and 4 operation, and with only two loops operable restore three loops within 7 days or apply the configuration risk management program or shutdown. Contrary to the above, from January 22, 2008 through October 16, 2008, the licensee operated in Modes 1, 2, 3, and 4 without all three loops operable or without taking the appropriate measures listed in the technical specification. Since this violation is of very low safety significance and was documented in the licensees corrective action program as Condition Report 08-19420, it is being treated as a noncited violation consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000499/2009002-02, Inadequate Reportability Misses an Inoperable Component Cooling Water Train.

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

Modifications (71111.17)

a. Inspection Scope

The inspectors reviewed the effectiveness of the licensees implementation of evaluations performed in accordance with 10 CFR 50.59, Changes, Tests, and Experiments, and changes, tests, experiments, or methodology changes that the licensee determined did not require 10 CFR 50.59 evaluations. The inspection procedure requires the review of 6 to 12 licensee evaluations required by 10 CFR 50.59, 12 to 25 changes, tests, or experiments that were screened out by the licensee and 5 to 15 permanent plant modifications.

The inspectors only reviewed two evaluations required by 10 CFR 50.59 because they were the only evaluations performed since the last performance of this inspection. The

inspectors also reviewed 27 changes, tests, and experiments that were screened out by licensee personnel and 11 permanent plant modifications. Document numbers of the evaluations, changes, and modifications reviewed are listed in the attachment. Three of the modifications reviewed were associated with the Unit 1 reactor head replacement.

These modifications are listed below:

• DCP 07-1640-1, Reactor Vessel Head, Control Rod Drive Mechanism, Core Exit Thermocouple Column, and Reactor Vessel Water Level Indication System housing replacement

• DCP 07-1640-6, Core Exit Thermocouples, Control Rod Drive Mechanisms, and Digital Rod Position Indication Head Cable Assemblies Replacement

• DCP 07-1640-12, Relocation of four Control Rod Drive Mechanism assemblies and associated guide tubes in the reactor vessel upper internals package The inspectors verified that when changes, tests, or experiments were made, that evaluations were performed in accordance with 10 CFR 50.59 and that licensee personnel had appropriately concluded that the change, test or experiment can be accomplished without obtaining a license amendment. The inspectors also verified that safety issues related to the changes, tests, or experiments were resolved. The inspectors reviewed changes, tests, and experiments that licensee personnel determined did not require evaluations and verified that the licensee personnels conclusions were correct and consistent with 10 CFR 50.59. The inspectors also verified that procedures, design, and licensing basis documentation used to support the changes were accurate after the changes had been made.

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

These activities constitute completion of two evaluations; 27 changes, tests, or experiments; and 11 permanent plant modification samples as defined in Inspection Procedure 71111.17-05.

b. Findings

No findings of significance were identified.

1R18 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following temporary modification to verify that the safety functions of important safety systems were not degraded:

• March 5, 2009, Unit 1, temporary enclosure to serve as the control room envelope boundary to allow upgrading of one of the control room envelope boundary doors

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

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

b. Findings

No findings of significance were identified.

1R19 Postmaintenance Testing

a. Inspection Scope

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

• January 26, 2009, Unit 2, low head safety injection Pump 2B breaker replacement

• January 29, 2009, Unit 2, component cooling water Pump 2B breaker cell switch replacement due to pump failing to secure from the control room handswitch

• February 2, 2009, Unit 2, reactor vessel water level Train C circuit board failure

• February 5, 2009, Unit 1, reactor coolant system wide range pressure Transmitter P0406 design change package replacement due to transmitter failure

• March 13, 2009, Unit 1, control room boundary envelope Door 365 design change package replacement to an automatic door

• March 23-27, Unit 1, replacing the 125 volt dc Train C E1C11 batteries The inspectors selected these activities based upon the structure, system, or components ability to affect risk. The inspectors evaluated these activities for the following (as applicable):

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

• Acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate

The inspectors evaluated the activities against the technical specifications, the Updated Final Safety Analysis Report, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with postmaintenance tests to determine whether the licensee was identifying problems and entering them in the corrective action program and that the problems were being corrected commensurate with their importance to safety. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of six postmaintenance testing inspection samples as defined in Inspection Procedure 71111.19-05.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the Updated Final Safety Analysis Report, procedure requirements, and technical specifications to ensure that the five 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:

• October 14, 2008, Unit 2, component cooling water surge tank Train A low-low level switch actuation

• January 21, 2009, Unit 1, component cooling water surge tank Train B low-low level switch calibration

• February 4, 2009, Unit 1, control room emergency air cleanup system test

• February 17, 2009, Unit 2, Standby Diesel Generator 21 operability test

• March 5, 2009, Unit 2, component cooling water supply to reactor containment fan cooler Train C outside reactor containment isolation valve inservice test Specific documents reviewed during this inspection are listed in the attachment.

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

b. Findings

Introduction.

The inspectors identified a Green noncited violation of 10 CFR Part 50, Appendix B, Criteria V, Instructions, Procedures, and Drawings, for the inadequate surveillance Procedure 0PSP05-CC-0001, FCI CCW Surge Tank Compartment Level Switch Calibration, Revision 7.

Description.

On October 14, 2008, during the 18-month surveillance test, Unit 2 component cooling water Train A was determined to be inoperable due to the failure of system valves to actuate to their designated positions. This test was conducted on component cooling water Train A surge tank low-low level Switch 4503C which actuates the valves required to mitigate a system leak. Troubleshooting determined that a loose wire on Switch 4503C Terminal 6 was the reason for the inoperability. The wire was restored and the train returned to operable status on October 16, 2008. The previous time that the switch was manipulated was January 22, 2008, during a calibration procedure. The calibration procedure, Procedure 0PSP05-CC-0001, FCI CCW Surge Tank Compartment Level Switch Calibration, Revision 7, did not have a functional check of the switch internal contacts before completion of the procedure. This is important as the unique method in which the low-low level switch is calibrated. For the switch to be calibrated, a circuit board is removed from its plug and test leads are connected. The circuit board is then reinstalled and calibrated. Upon completion of the calibration the circuit board is removed from its plug and the test leads are removed and the circuit board is reinstalled. Upon reinstallation there was no functional check of the wires (internal switch contacts) that were manipulated to ensure connectivity, and, therefore, ensure that the low-low level switch would actuate. Consequently, from January 22, 2008 through October 16, 2008, the Train A component cooling water low-low level switch was inoperable. Since this procedure is applicable to all trains of both units, the licensee verified that the condition was not applicable on another train by verifying the

low-low level switches were either surveillance tested after the last calibration procedure or were functionally checked using a temporary procedure. For additional enforcement actions associated with this finding, see Sections 1R15 and 4OA3 of this report.

Analysis.

The inspectors determined that the failure to ensure that the surveillance procedure had adequate acceptance criteria for returning the component cooling water system to service was a performance deficiency. The finding was more than minor because it was similar to several examples in Inspection Manual Chapter 0612, Appendix E, where the system was returned to service without being fully operable and it affected the Mitigating Systems cornerstone attribute of procedure quality and the objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using the Significance Determination Process Phase 1 worksheets from Inspection Manual Chapter 0609, the finding was determined to have very low safety significance (Green) because it did not result in the actual loss of safety function of one or more trains and it did not screen as risk-significant due to seismic, flooding, or severe weather. This issue had no crosscutting aspects because the last revision to the procedure was too long ago (2005)to be indicative of current performance.

Enforcement.

10 CFR Part 50, Appendix B, Criteria V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented procedures of a type appropriate to the circumstances and shall include appropriate acceptance criteria. Contrary to this, on January 22, 2008, while performing Procedure 0PSP05-CC-0001, Revision 7, the component cooling water Train A system was returned to operable without all required equipment functioning, because the acceptance criteria of the procedure did not have functional checks of the internal switch contacts associated with low-low tank level. Since this violation is of very low safety significance and was documented in the licensees corrective action program as Condition Report 08-15541, it is being treated as a noncited violation consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000498/2009002-03 and 05000499/2009002-03, Inadequate Surveillance Test for Component Cooling Water.

1EP7 Force-on-Force (FOF) Exercise Evaluation

a. Inspection Scope

On February 4, 2009, the inspectors observed licensee performance during the Force-on-Force exercise evaluation in the control room simulator. This drill was in conjunction with an inspection scheduled and observed by the NRCs Office of Nuclear Security and Incident Response and documented in Inspection Report 05000498/2008201 and 05000499/2008201. The inspectors observed communications, event classification, and event notification activities by the simulated control room staff. The inspectors reviewed the emergency preparedness-related corrective actions from the previous inspection conducted by the NRCs Office of Nuclear Security and Incident Response to determine whether they had been completed and adequately addressed the cause of the previously-identified weakness. The inspectors also observed portions of the post-drill critique to determine whether their observations were also identified by the licensees evaluators. The inspectors verified that minor issues identified during this inspection were entered into the licensees corrective action program.

This inspection constitutes one sample as defined by Inspection Procedure 71114.07.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator Verification

.1 Data Submission Issue

a. Inspection Scope

The inspectors performed a review of the data submitted by the licensee for the fourth Quarter 2008 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 of significance 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 of significance 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 of significance were identified.

.3 Selected Issue Follow-up Inspection

a. Inspection Scope

During the weeks of March 9-13 and March 23-26, 2009, the inspectors reviewed the Units 1 and 2 operator workarounds, as well as, the cumulative effects of the workarounds to:

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

(2) determine if multiple mitigating systems could be affected;

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

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

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

b. Findings

No findings of significance were identified.

4OA3 Event Follow-up

.1 (Closed) LER 05000499, 2008-001-00, Incorrectly Stored Fuel Assembly in U2 Spent

Fuel Pool On October 16, 2008, while preparing for fuel movements in the Unit 2 spent fuel pool the licensee discovered an incorrectly stored fuel assembly. The licensee promptly moved the assembly to an allowed location and checked the remainder of the assemblies in both Units 1 and 2 spent fuel pools to ensure there were no other incorrectly stored assemblies. None were identified. Since the misplaced assembly was a Category 11 and the technical specification allowed for a Category 9, Category 9 is more reactive than Category 11, the as-found configuration was bounded by the safety analysis. Therefore, this failure to comply with Technical Specification 5.6.1.4 constitutes

a violation of minor significance that is not subject to enforcement action in accordance with Section IV of the NRCs Enforcement Policy. The licensee documented the issue in Condition Report 08-15715. This licensee event report is closed.

.2 (Closed) LER 05000499/2008-002-00, Valid Actuation of Safety Systems

The inspectors reviewed the valid actuation of safety systems event that occurred when a logic card in the solid state protection system was removed for maintenance during the Unit 2 refueling outage on October 25, 2008, which resulted in the loss of the residual heat removal system. The inspectors interviewed the individuals involved in the event to gain an understanding of the conditions and circumstances leading up to, during, and after the event to assess licensee actions. The inspectors reviewed the licensees root cause investigation report to assess the detail and thoroughness of the investigation and proposed corrective actions. The inspectors also reviewed the event for reportability in accordance with NUREG 1022, Event Reporting Guidelines, to ensure the licensee had made the required notifications. The enforcement aspects of this event are documented in Section 1R13 of this report. This licensee event report is closed.

.3 (Closed) LER 05000499/2008-003-00, Inoperable Component Cooling Water Train

The inspectors reviewed the failure of the Unit 2 component cooling water Train A surge tank low-level switch to actuate. On October 14, 2008, during the 18-month surveillance test, Unit 2 component cooling water Train A was determined to be inoperable due to the failure of system valves to actuate to their designated positions. Troubleshooting determined that a loose wire on Switch 4503C Terminal 6 was the reason for the inoperability. The inspectors reviewed the licensees root cause and apparent cause evaluations of the event, and interviewed the individuals involved to gain an understanding of the conditions surrounding the event. In addition, the inspectors assessed the thoroughness of the licensees completed and proposed corrective actions. The inspectors also reviewed the event for reportability in accordance with NUREG 1022, Event Reporting Guidelines, to ensure the licensee had made the required notifications. The enforcement aspects of this event are documented in Sections 1R15 and 1R22 of this report. This licensee event report is closed.

4OA5 Other Activities

.1 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

During the inspection period, the inspectors performed observations of security force personnel and activities to ensure that the activities were consistent with South Texas Project Electric Generating Station security procedures and regulatory requirements relating to nuclear plant security. These observations took place during both normal and off-normal plant working hours.

These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors normal plant status review and inspection activities.

b. Findings

No findings of significance were identified.

.2 (Closed) Unresolved Item 05000498,05000499/2007007-07, Effect of Standby Diesel

Generator Technical Specification Voltage Variation on Supplied Equipment

a. Inspection Scope

An unresolved item was identified during a Component Design Basis Inspection (See Inspection Report 05000498/2007007 and 05000499/2007007) associated with differences in the available voltage levels supplied by either the standby diesel generators or offsite power to safety-related loads during design basis conditions.

Specifically, design analysis credits the nominal value of 4160 VAC as being supplied to loads from offsite power during design basis events in which offsite power is available.

Technical Specification 3/4.8.1 lists an allowable range of values for the standby diesel generator terminal voltage between 3744 VAC to 4576 VAC, which is +/- 10 percent of the nominal 4160 VAC. These values were derived from various sources, including guidance in Regulatory Guide 1.9, Revision 2, Selection, Design, and Qualification of Diesel-Generator Units Used as Standby (Onsite) Electric Power Systems at Nuclear Power Plants, NUREG-1431, Standard Technical Specifications for Westinghouse Plants, and ANSI Standard C84.1, American National Standard for Electric Power Systems and Equipment - Voltage Ratings (60 Hertz). The design analysis credits the maximum voltage variations based upon offsite power supplies, which were analyzed to vary less than the technical specification allowed steady state variation for the standby diesel generators. The licensee believes the topic of diesel generator voltage variation to be an industry generic issue.

The team reviewed the Technical Specification Basis documents associated with this issue, interviewed licensee personnel involved in the analysis, operation and maintenance of the standby diesel generator system, interviewed licensee personnel involved with design engineering associated with the standby diesel generators and reviewed 18-month surveillance test data for Standby Diesel Loss of Offsite Power-Engineered Safeguards Features Actuation Tests. Standby Diesel Loss of Offsite Power-Engineered Safeguards Features Actuation Tests duplicate, as close as practicable, the electrical conditions the standby diesel generator system would encounter during a design basis event in which offsite power would not be available, including terminal voltage swings due to loading and unloading Engineered Safeguards Features loads. Also, the team analyzed real-time data for the voltage and frequency values associated with the sequencing of Engineered Safeguards Features loads onto the standby diesel generator during the latest surveillance test.

The licensee informed the team of their participation in an industry program, directed by NEI, known as the Regulatory Issue Resolution Process. This program is currently in the early stages of development, but is designed to enhance resolution of industry generic issues. The licensee has submitted the standby diesel generator voltage variation issue as a topic. Further industry discussion with the NRC will take place involving this issue.

The team also discussed the rationale behind the assumption and use of nominal voltage values during a design basis event. It is generally recognized that the application of design basis event loads onto offsite power sources could cause minor, damped perturbations in the available local grid voltages whereas sequential loading of Engineered Safeguards Features loads onto standby diesel generators could cause more pronounced and longer-lived damped perturbations. This performance would be expected, and is considered normal transient behavior of these systems under these conditions. The inspectors verified the standby diesel generators performed appropriately during the surveillance testing and recognize the tested response of the

standby diesel generator system would be similar to that during a design basis event.

The team found reasonable assurance that the voltage variations of the standby diesel generator system adequately bound the voltage values expected during design basis events and believe no additional analysis is required. This unresolved item is closed.

b. Findings

No findings of significance were identified.

.3 Unit 1 Reactor Vessel Head Replacement Project

a. Inspection Scope

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

During this inspection period, the inspectors reviewed the licensees schedule and plans for the design, fabrication and installation of the Unit 1 replacement reactor vessel head. The inspectors reviewed key design aspects and modifications for the replacement reactor vessel, including transporting the old and new heads in and out of the reactor containment building. See Section 1R17 of this report for details of the inspection scope and the documents reviewed.

b. Findings

No findings of significance were identified.

4OA6 Meetings

Exit Meeting Summary

On March 18, 2009, the inspectors presented the inspection results to Mr. J. Sheppard, President and Chief Executive Officer, and other members of his staff. The inspectors reviewed some proprietary information and verified that none would be included in this report.

On April 9, 2009, the inspectors presented the inspection results to Mr. J. Sheppard, President and Chief Executive Officer, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Ashcraft, Manager, Health Physics

M. Berg, Acting Testing and Programs Manager

C. Bowman, General Manager Oversight

D. Cobb, STP Employee Concerns Program Manager

J. Cook, Engineering Project Supervisor

R. Dunn Jr., Supervisor, Configuration Control and Analysis

T. Frawley, Manager, Plant Protection

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

E. Halpin, Executive Vice President and Chief Nuclear Officer

E. Harper, Design Engineering, Instrumentation and Controls

W. Harrison, Manager, Licensing

G. Hildebrant, Manager, Operations Support

K. House, Manager, Design Engineering

R. Howe, Design Engineering

G. Janak, Manager, Operations Division, Unit 1

B. Jenewein, Manager, Systems Engineering

R. Kersey, Engineering Supervisor

D. Leazar, Manager, Fuels and Analysis

J. Lovejoy, Assistant Maintenance Manager

A. McGalliard, Manager, Performance Improvement

R. McNiel, Manager, Maintenance Engineering

J. Mertink, Manager, Operations

B. Migl, Engineering Supervisor

J. Milliff, Manager, Operations Division, Unit 2

W. Moore, Design Engineering, Areva

J. Morris, Licensing Engineer

H. Murray, Manager, Maintenance

M. Oswald, Supervising Engineer

J. Paul, Engineer, Licensing Staff Specialist

L. Peter, Plant General Manager

J. Pierce, Manager, Operations Training

J. Pineda, Design Engineering, Electrical

G. Powell, Vice President, Engineering

M. Reddix, Manager, Security

D. Rencurrel, Senior Vice President Units 1 and 2

R. Savage, Engineer, Licensing Staff Specialist

M. Schaefer, Manager, I&C Maintenance

J. Sheppard, President and Chief Executive Officer

K. Taplett, Senior Engineer, Licensing Staff

D. Towler, Manager, Quality

D. Widdon, Quality

C. Younger, Engineering Supervisor

D. Zink, Supervising Engineer

Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

Failure to Assess and Manage Outage Maintenance Risk

05000499/2009002-01 NCV Activities Resulting in the Loss of the Residual Heat Removal System (Section 1R13)

Inadequate Reportability Misses an Inoperable Component

05000499/2009002-02 NCV Cooling Water Train (Section 1R15)

05000498/2009002-03 Inadequate Surveillance Test for Component Cooling Water NCV

05000499/2009002-03 (Section 1R22)

Closed

Incorrectly Stored Fuel Assembly in U2 Spent Fuel Pool

05000499/2008-01-00 LER (Section 4OA3)

05000499/2008-02-00 LER Valid Actuation of Safety Systems (Section 4OA3)

05000499/2008-03-00 LER Inoperable Component Cooling Water Train (Section 4OA3)

05000498/2007007-07 Effect of Standby Diesel Generator Technical Specification URI

05000499/2007007-07 Voltage Variation on Supplied Equipment (Section 4OA5)