Text

IR 05000269-08-003, 05000270-08-003, 05000287-08-003; 04/01/2008 - 06/30/2008; Oconee Nuclear Station, Units 1, 2, and 3; Inservice Inspection
	ML082070188
Person / Time
Site:	Oconee
Issue date:	07/25/2008
From:	Steven Rose; NRC/RGN-II/DRP/RPB1
To:	Baxter D; Duke Energy Carolinas, Duke Power Co
References
	IR-08-003
	Download: ML082070188 (31)
	v • d • e

July 25, 2008

SUBJECT:

OCONEE NUCLEAR STATION - INTEGRATED INSPECTION REPORT 05000269/2008003, 05000270/2008003, AND 05000287/2008003

Dear Mr. Baxter:

On June 30, 2008, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Oconee Nuclear Station. The enclosed report documents the inspection results which were discussed on July 8, 2008, with you and members of your staff.

The inspection examined activities conducted under your licenses as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your licenses. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

This report documents one NRC-identified finding of very low safety significance (Green) which was determined to be a violation of NRC requirements. In addition, one licensee identified violation is also listed in this report. However, because of their very low safety significance and because they are entered into your corrective action program, the NRC is treating these findings as non-cited violations (NCVs), consistent with Section VI.A of the NRC Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the United States Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Oconee facility.

DPC

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's 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/

Steven D. Rose, Acting Chief Reactor Projects Branch 1 Division of Reactor Projects

Docket Nos.: 50-269, 50-270, 50-287 License Nos.: DPR-38, DPR-47, DPR-55

Enclosure:

NRC Integrated Inspection Report 05000269/2008003, 05000270/2008003, 05000287/2008003 w/Attachment: Supplemental Information

REGION II==

Docket Nos:

50-269, 50-270, 50-287

License Nos:

DPR-38, DPR-47, DPR-55

Report Nos:

05000269/2008003, 05000270/2008003, 05000287/2008003

Licensee:

Duke Power Company, LLC

Facility:

Oconee Nuclear Station, Units 1, 2, and 3

Location:

7800 Rochester Highway

Seneca, SC 29672

Dates:

April 1, 2008 - June 30, 2008

Inspectors:

A. Hutto, Senior Resident Inspector E. Riggs, Resident Inspector

L. Lake, Senior Reactor Inspector (Section 1R08)

R. Chou, Reactor Inspector (Section 1R08)

B. Collins, Reactor Inspector - in training (Section 1R08)

R. Mackowski, Reactor Inspector - in training (Section 1R08)

Approved by:

Steven D. Rose, Acting Chief

Reactor Projects Branch 1

Division of Reactor Projects

Enclosure SUMMARY OF FINDINGS

IR 05000269/2008003, 05000270/2008003, 05000287/2008003; 04/01/2008 -

06/30/2008; Oconee Nuclear Station, Units 1, 2, and 3; Inservice Inspection.

The report covered a three-month period of inspection by the onsite resident inspectors, one regional senior reactor inspector, and three regional reactor inspectors. One Green non-cited violation (NCV) was identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using IMC 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

A.

NRC Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

Green. The inspectors identified a Green non-cited violation (NCV) of 10 CFR 50.55a(g)(4) for the failure to perform periodic leakage testing of Class 1 portions of low pressure injection system during the third inspection interval of the Unit 1 Inservice Inspection Program as required by Section XI of the American Society of Mechanical Engineers (ASME) Code for the third 10-year Inservice Inspection interval. The licensee entered this issue into their Corrective Action Program (CAP) for resolution.

This finding is more than minor because it affected the Equipment Performance attribute of the Mitigating Systems Cornerstone objective, in that there were no additional measures taken to perform the required pressure testing (or obtain regulatory relief within the time limits of the regulation) to ensure the availability, reliability, and capability of a system that responds to initiating events to prevent undesirable consequences.

This finding is of very low safety significance because it was not a design issue resulting in a loss of operability, did not represent an actual loss of a systems safety function, did not result in exceeding a Technical Specification (TS) allowed outage time, and did not affect external event mitigation. This finding has a cross-cutting aspect of Work Control in the area of Human Performance, as identified in NRC Manual Chapter 0305, Section 06.07 [H.3.(b)]. (Section 1R08.1)

B.

Licensee-Identified Violations

A violation of very low safety significance (Green) was identified by the licensee and reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees CAP. The violation and corrective actions are listed in Section 4OA7 of this report.

Enclosure Report Details

Summary of Plant Status

Unit 1 began the report period at 73 percent rated thermal power (RTP) and the 1A1 Reactor Coolant Pump (RCP) secured due to a service water leak into one of the pumps oil reservoirs.

On April 12, 2008, the unit was shutdown from 73 percent RTP for the 1 End-of-Cycle (EOC)-24 refueling outage. On May 31, 2008, Unit 1 was taken critical following outage activities. It achieved 100 percent RTP on June 4, 2008, where it remained through the end of the inspection period.

Unit 2 began the report period in Mode 3, following an automatic trip from 100 percent RTP on March 31, 2008. On April 2, 2008, Unit 2 was taken critical and achieved 100 percent RTP on April 3, 2008, where it remained through the end of the inspection period.

Unit 3 began the report period at 100 percent RTP. On June 21, 2008, the unit was reduced to 88 percent RTP for turbine valve movement testing and was returned to 100 percent RTP later the same day, where it remained through the end of the inspection period.

1.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

.1 Hot Weather Preparations

a.

Inspection Scope

The inspectors observed the condition and readiness of the room cooling equipment for the Units 1, 2, and 3 Low Pressure Injection (LPI) pump rooms to ensure that the ability to maintain ambient temperatures in these rooms consistent with post accident design basis assumptions is preserved during hot weather conditions. The inspectors walked down the applicable portions of the Low Pressure Service Water (LPSW) system to verify appropriate flows and temperatures were being maintained. The inspectors also observed the material condition of the LPSW piping, coolers and air handling equipment in the LPI pump rooms to ensure that the licensee was maintaining this equipment at the appropriate level. The inspectors took temperature measurements in the rooms during hot weather conditions to verify that the appropriate ambient conditions were being maintained. Documents reviewed are listed in the Attachment to this report.

b.

Findings

No findings of significance were identified.

Enclosure

.2 External Flooding Preparations

a. Inspection Scope

The inspectors performed a walkdown of the Standby Shutdown Facility (SSF) to examine its external flood protection features and barriers. This included the flood walls, the watertight door at the South entrance of the SSF, accessible cable and piping penetrations and seals, structural integrity of the building with regard to external flooding, and the buildings floor drain and sump system. Documents reviewed are listed in the Attachment to this report.

b.

Findings

No findings of significance were identified.

.3 Evaluation of Summer Readiness of Offsite and Alternate AC Power Systems

a. Inspection Scope

The inspectors reviewed the licensees procedures and measures designed to monitor and maintain availability and reliability of both the offsite AC power system (grid) and the onsite alternate AC power systems prior to the onset of summer weather conditions and the resulting higher load demand on the grid. This included the review of the licensees station, Nuclear Division and Power Delivery group procedures defining the coordination of activities that could impact the on-site and offsite AC power systems and the communication protocols established between the Power Delivery group and licensee to verify that the appropriate information is exchanged when issues arise that could impact the AC power systems. The inspectors also discussed the implementation of the procedural guidance with personnel from Operations, Engineering and Work Control.

The documents reviewed during this inspection are listed in the Attachment to this report.

b. Findings and Observations

No findings of significance were identified.

1R04 Equipment Alignment

Partial Walkdown

a.

Inspection Scope

The inspectors conducted partial equipment alignment walkdowns to evaluate the operability of selected redundant trains or backup systems while the other train or system was inoperable or out of service. The walkdowns included, as appropriate, reviews of plant procedures and other documents to determine correct system lineups,

Enclosure and verification of critical components to identify any discrepancies which could affect operability of the redundant train or backup system. Documents reviewed are listed in the Attachment to this report. The following systems were included in this review:

Unit 1 decay heat drop line and LPI pumps and coolers while the steam generators were not available for decay heat removal prior to defueling

3B Reactor Building Spray (RBS) train with the 3A RBS train out-of-service (OOS)

for maintenance

Keowee Hydro-electric Unit (KHU)-2, underground power path, CT-4 and CT-5 transformers with the KHU step up transformer OOS for preventive maintenance (PM)

b.

Findings

No findings of significance were identified.

1R05 Fire Protection

Fire Area Walkdowns

a.

Inspection Scope

The inspectors conducted tours in selected areas of the plant to assess whether combustibles and ignition sources were properly controlled, and that fire detection and suppression capabilities were intact. The inspectors selected the areas based on a review of the licensees safe shutdown analysis and the probabilistic risk assessment based sensitivity studies for fire-related core damage sequences. Documents reviewed are listed in the Attachment to this report. The following areas were inspected during this inspection period:

Unit 1, 2 and 3 Control Rooms (2)

Unit 1 Reactor Building (1)

Turbine Building Basement (1)

b.

Findings

No findings of significance were identified.

1R06 Flood Protection Measures

Internal Flooding - Turbine Building

a.

Inspection Scope

The inspectors reviewed Problem Investigation Process report (PIP) O-08-2465, which documents the results of an inspection of the main condenser waterboxes expansion joint internal seals during the Unit 1 EOC-24 refueling outage (RFO). The internal

Enclosure expansion joint seals were installed on the inlet and outlet condenser waterboxes during the Unit 1 EOC-21 RFO in the Fall of 2003. They serve as the primary seals, while the rayon reinforced rubber expansion joints that have been in service for over 30 years act as secondary seals. Both seals are inspected each RFO. The inspectors discussed the inspection results with engineering and the expansion joint manufacturer, which included the discovery of several small, inward bulges on the condenser inlet waterbox seal sleeves and several backing ring retention bands inside several condenser inlet waterboxes that had slipped out of position, to assess their significance and to verify the adequacy of the planned corrective actions.

b.

Findings

No findings of significance were identified.

1R08 Inservice Inspection (ISI) Activities

.1 Non-Destructive Examination (NDE) Activities and Welding Activities

a.

Inspection Scope

From April 14 - 25, 2008, the inspectors reviewed the implementation of the licensees ISI program for monitoring degradation of the reactor coolant system (RCS) boundary and risk significant piping boundaries. Documents reviewed are listed in the Attachment of this report. The inspectors activities consisted of an on-site review of NDE and welding activities to evaluate compliance with the applicable edition of the ASME Boiler and Pressure Vessel Code,Section XI (Code of record: 1998 Edition with 2000 Addenda), and to verify that indications and defects (if present) were appropriately evaluated and dispositioned in accordance with the requirements of the ASME Code,Section XI acceptance standards. The inspectors review of NDE activities specifically covered examination procedures, NDE reports, equipment and consumables certification records, personnel qualification records, and calibration reports (as applicable) for the following examinations:

Ultrasonic examinations (UT) of weld 1-PSL-1, Reactor Coolant System, ASME Class 1, 10.75-inch diameter pipe-to-safe end weld (Risk Informed ISI)

UTs of Reactor Pressure Vessel (RPV) Head Bolts 1-RPV-25-203-37, 38, 65, and 40

Magnetic Particle examinations of weld 1-03-0-551-R12, snubber attachment weld to pipe on feed water system. Inspectors observed examination and calibration

Visual examination (VT-2) of pressurizer bottom mounted heater penetrations and sleeves

Visual Examinations (VT-3) of supports 53A-0-479A-H1, Revision D1

The inspectors review of welding activities specifically covered the welding activity listed below in order to evaluate compliance with procedures and the ASME Code. The inspectors reviewed the work order, repair and replacement plan, weld data sheets, welding procedures, procedure qualification records, welder qualification records, and NDE reports.

Enclosure

Weld Process Control Sheet for 1-FDW-0342-62 and 1-FDW-0150-17; Replacement Weld on Branch Connection in Recirculation Line off Emergency Feedwater (EFW)

Pumps

Weld Traveler 900757-N6 Revision 0, Pressurizer Surge Nozzle 14-Inch Safe End to Pipe Weld Overlay

b.

Findings

Introduction: The inspectors identified a Green non-cited violation (NCV) of 10 CFR 50.55a(g)(4) for failure to perform the required periodic pressure test on Class 1 portions of the Low Pressure Injection (LPI) system during the third 10-year ISI interval in accordance with the 1989 Edition of the ASME Code,Section XI. The licensee was committed to this Code Edition for the third interval. The unit is currently in the fourth ISI interval and the one-year period allowed to submit for regulatory relief following the third interval has expired. The failure to perform this pressure test constitutes a violation of the ASME Code.

Description: ASME Section XI, IWB-5000 requires Class 1 systems to be pressure tested each refueling outage. The test includes a system leakage test conducted prior to startup; at a pressure not less than 100 percent rated reactor power, and with a test boundary corresponding to the reactor coolant boundary with all valves in the position required for normal reactor startup. During pressurization, a visual examination for leakage (VT2) is conducted by examining the external exposed surfaces for evidence of leakage and is required to be extended to the second closed valve at the system boundary. The Class 1 pressure retaining boundary not pressurized when system valves are in their position for normal reactor startup shall be pressurized and examined at or near the end of the inspection interval.

Portions of the Oconee LPI system at the Class 1 boundary consist of two valves, in series, which are normally closed during reactor startup and are designed with no vent, drain, or test connections between the two valves. Therefore, this portion of the LPI system can not be pressurized during system leakage tests and VT2 examinations.

The licensee had determined that it is not practical to perform this test because the design of this portion of the LPI system is such that it is not pressurized during the pressure tests required by ASME Section XI. On December 21, 2004, the licensee had submitted a request for relief from these code requirements for the third inspection interval, and subsequently retracted the request on July, 6, 2006. The licensee subsequently re-submitted a request for relief on April 21, 2008. This relief request was not accepted because it was submitted beyond the allowable 12 month period after the end of the third interval.

Analysis: The inspectors determined that the licensees failure to submit a relief request within the 12 month period after the end of the third inspection interval resulted in the operation of Unit 1 in violation of 10 CFR 50.55a(g)(4). This performance deficiency is more than minor because it affected the attribute of the Reactor Safety Mitigating Systems Cornerstone, in that there were no additional measures taken to either perform the required pressure tests or obtain relief from these requirements within the time limits

Enclosure of the regulation. There has been no evidence of boundary leakage that would call into question the operability of these portions of the LPI system. The licensee plans to address this condition during the current (fourth) inspection interval by submitting a request for relief from these pressure test requirements or performing the tests near the end of the interval. This finding is more than minor because it affects the Equipment Performance attribute of the Mitigating Systems cornerstone objective of ensuring availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding is of very low safety significance because it was not a design issue resulting in a loss of operability, did not represent an actual loss of a systems safety function, did not result in exceeding a TS allowed outage time, and did not affect external event mitigation. Because the licensee did not monitor the timeliness of re-submitting the relief request within the third interval and the 12-month grace period, this finding has a cross-cutting aspect of Work Control in the area of Human Performance, as identified in NRC Manual Chapter 0305, Section 06.07

[H.3.(b)].

Enforcement: 10 CFR 50.55a(g)(4) requires the implementation of an in-service inspection program that meets the requirements of ASME Section XI. ASME Section XI, IWB-5000 requires Class 1 systems to be pressure tested each refueling outage.

Contrary to the above, measures were not implemented to perform the required periodic pressure test on Class 1 portions of the LPI system during the third 10-year ISI interval in accordance with the 1989 Edition of Section XI. Because this failure to comply with 10 CFR 50.55a(g)(4) is of very low safety significance and has been entered into the licensee's Corrective Actions Program as PIP 0-08-02523, this violation is being identified as an NCV, consistent with Section VI.A.I of the NRC Enforcement Policy:

NCV 05000269/2008003-01, Required Pressure Tests Not Performed.

.2 Pressurized Water Reactor Vessel Upper Head Penetration Inspection Activities

a.

Inspection Scope

Examination activities in compliance with the regulatory requirements of NRC Order EA-03-009, although scheduled, where not available during the time of these inspections.

b.

Findings

No findings of significance were identified.

.3 Boric Acid Corrosion Control (BACC) Inspection Activities

a.

Inspection Scope

The inspectors reviewed the licensees BACC program activities to ensure implementation with commitments made in response to NRC Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary, and applicable industry guidance documents. Specifically, the inspectors performed an on-site record review of procedures and the results of the licensees containment walk-down inspections performed during the Unit 1 Spring 2008 outage. The inspectors also

Enclosure interviewed the BACC program owner and conducted an independent walk-down of the reactor building to evaluate compliance with licensees BACC program requirements and verify that degraded or non-conforming conditions, such as boric acid leaks identified during the containment walk-down, were properly identified and corrected in accordance with the licensees BACC and Corrective Action Programs.

The inspectors reviewed a sample of engineering evaluations completed for evidence of boric acid found on systems containing borated water. The inspectors selected the following evaluations for review:

PIP 0-08-01933, Items Noted on Unit 1 EOC-24 ENG/MNT Mode 3 Shutdown Reactor Building Tour

PIP 07-06548, Level 2 Assessment: Boric Acid Corrosion Program Execution Effectiveness Review

PIP 0-07-01092, Items Noted on Unit 1 Reactor Building Tour (Mode 3)

PIP 0-07-02186, U2 Engineering/Maintenance RB Tour Results (Mode 3)

PIP 0-08-01933, U1EOC 24 ENG/MNT Mode 3 Shutdown RB Tour

PIP 0-08-02407, Items Noted on U1EOC24 RFO NRC Inspection (Boric Acid Walk-down)

b. Findings

No findings of significance were identified.

.4 Steam Generator (SG) Tube ISI

a.

Inspection Scope

On April 14 - 18, 2008, the inspectors reviewed activities, plans, condition monitoring and operational assessments, the pre-outage degradation assessment, and procedures for the inspection and evaluation of the steam generator Inconel Alloy 690TT tubing for Unit 1 SGs A and B to determine if the activities were being conducted in accordance with TS and applicable industry standards. Data gathering, analysis, and evaluation activities were reviewed. The inspectors reviewed data results for tubes at SG A -

R91C126, R96C123, R93C120, R89C120, R58C04, and R95C125; SG B - R62C02, R63C01, R65C125, R65C127, R66C131, R69C122, R69C124, R70C124, R71C122, and R71C120 to verify the adequacy of the licensee=s primary, secondary, and resolution analyses. The licensee did not perform the inspection for the secondary side of the SGs during this outage. The inspectors reviewed a PIP in the office which was a summary of the licensee steam generator inspection results for this outage. The inspectors also reviewed equipment, data operators, and analysts certifications and qualifications, including medical exams. Documents reviewed are listed in the Attachment to this report.

b.

Findings

No findings of significance were found.

Enclosure

.5.

Identification and Resolution of Problems

a.

Inspection Scope

The inspectors performed a review of ISI-related problems, including welding, BACC, and SG inspections that were identified by the licensee and entered into the CAP as PIPs. The inspectors reviewed the PIPs to confirm that the licensee had appropriately described the scope of the problem and had initiated corrective actions. The inspectors performed this review to ensure compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action documents reviewed are listed in the Attachment to this report.

b.

Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification

Simulator Training

a.

Inspection Scope

The inspectors observed licensed operator simulator training on June 24, 2008. The simulator scenario began with a reactor coolant pump seal failure followed by a main steam line break. Subsequently, a large break loss of coolant accident occurred resulting in a general area emergency. The inspectors observed crew performance in terms of communications; ability to take timely and proper actions; prioritizing, interpreting, and verifying alarms; correct use and implementation of procedures, including the alarm response procedures; timely control board operation and manipulation, including high-risk operator actions; and, oversight and direction provided by the shift supervisor, including the ability to identify and implement appropriate TS actions and properly classify the simulated event.

b.

Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a.

Inspection Scope

The inspectors reviewed the licensees effectiveness in performing routine maintenance activities. This review included an assessment of the licensees practices pertaining to the identification, scoping, and handling of degraded equipment conditions, as well as common cause failure evaluations. For each item selected, the inspectors performed a detailed review of the problem history and surrounding circumstances, evaluated the extent of condition reviews as required, and reviewed the generic implications of the

Enclosure equipment and/or work practice problem. For those structures, systems, and components (SSCs) scoped in the Maintenance Rule per 10 CFR 50.65, the inspectors verified that reliability and unavailability were properly monitored and that 10 CFR 50.65 (a)(1) and (a)(2) classifications were justified in light of the reviewed degraded equipment condition. Documents reviewed are listed in the Attachment to this report.

The inspectors reviewed the following items:

PIP O-08-2739, 1B LPI Pump Test Stopped Due to Low Developed Head

PIPs O-08-2640 and O-08-3887, Self Contained Battery Emergency Lights Failed to Meet Performance Criteria of IP/0/B/3000/020

b.

Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessment and Emergent Work Evaluations

a.

Inspection Scope

The inspectors evaluated the following attributes for the selected SSCs and activities listed below: (1) the effectiveness of the risk assessments performed before maintenance activities were conducted; (2) the management of risk; (3) that, upon identification of an unforeseen situation, necessary steps were taken to plan and control the resulting emergent work activities; and (4) that maintenance risk assessments and emergent work problems were adequately identified and resolved.

Critical Activity Plan for KHU Main Step Up Transformer Major PMs

Critical Activity Plan for Unit 1 RCP seal work while RCPs are on back-seat and Unit 1 RCS Level is 350 - 370

Critical Activity Plan for Wet Tap on B Chiller Piping

Unit 1 EOC-24 Outage Risk Review

Critical Activity Plan for SSF Monthly PMs During Unit 1 EOC-24 RFO

Critical Activity Plan for Investigation and Repair of 3HPSW-75 Seat Leak

b.

Findings

No findings of significance were identified.

1R15 Operability Evaluations

a.

Inspection Scope

The inspectors reviewed selected operability evaluations affecting risk significant systems, to assess, as appropriate: (1) the technical adequacy of the evaluations; (2) whether continued system operability was warranted; (3) whether other existing degraded conditions were considered; (4) if compensatory measures were involved, whether the compensatory measures were in place, would work as intended, and were

Enclosure appropriately controlled; and (5) where continued operability was considered unjustified, the impact on TS limiting condition for operations. Documents reviewed are listed in the Attachment to this report. The inspectors reviewed the following operability evaluations:

PIP O-08-0295 and PIP O-08-2551, B SA Compressor Engine Oil Level too High

PIP O-08-1502, Waterhammer During 1A LPI Pump Start

PIP O-08-3021, 3A LPI Pump Casing Vent Pipe Leak

PIP O-08-2998, EFW Snubber Support Pulled Out of Wall

PIP O-08-1753, Unit 2 Reactor Coolant Makeup Pump Declared Inoperable Due to Low Shutdown Margin Resulting in a Red ORAM Risk Condition

PIP O-08-2656 and PIP O-08-3459, Missing Insulation From RBS and LPI Piping

PIP O-08-3297, 1RC-163 Failed Stroke Time Test

b.

Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing (PMT)

a.

Inspection Scope

The inspectors reviewed PMT procedures and/or test activities, as appropriate, for selected risk significant systems to assess whether: (1) the effect of testing on the plant had been adequately addressed by control room and/or engineering personnel; (2) testing was adequate for the maintenance performed; (3) acceptance criteria were clear and adequately demonstrated operational readiness consistent with design and licensing basis documents; (4) test instrumentation had current calibrations, range, and accuracy consistent with the application; (5) tests were performed as written with applicable prerequisites satisfied; (6) jumpers installed or leads lifted were properly controlled; (7) test equipment was removed following testing; and (8) equipment was returned to the status required to perform its safety function. Documents reviewed are listed in the Attachment to this report. The inspectors observed testing and/or reviewed the results of the following tests:

OP/0/A/1106/029, Control Room, Equipment Room, Cable Room Chiller A following Unit 1 outage maintenance in the 1TE Switchgear

PT/1/A/0600/012, Turbine Driven EFW Pump Test following outage maintenance

PT/2/A/0204/007, 2A RBS Pump Test following pump lubrication

MP/1/A/1310/052, RCP Seal - Unit 1 - Bingham - Type RCRW 950B-3 Static Fitness Test following redesign and replacement of the Unit 1 RCP seals

PT/1/A/0600/015, Control Rod Movement PT following joystick replacement

PT/0/A/0711/001, Unit 1 Zero Power Physics Test following the Unit 1 EOC-24 refueling outage

b.

Findings

No findings of significance were identified.

Enclosure

1R20 Refueling and Outage Activities

a.

Inspection Scope

The inspectors conducted reviews and observations for selected outage activities to ensure that: (1) the licensee considered risk in developing the outage plan; (2) the licensee adhered to the outage plan to control plant configuration based on risk; (3) that mitigation strategies were in place for losses of key safety functions; and (4) the licensee adhered to operating license and TS requirements. Between April 12, 2008, and June 4, 2008, the following activities related to the Unit 1 EOC-24 refueling outage were reviewed for conformance to applicable procedures, and selected activities associated with each evaluation were witnessed:

Outage risk management plan/assessment

Clearance activities

Reactor coolant system instrumentation

Plant cooldown

Mode changes from Mode 1 (power operation) to No Mode (defueled)

Shutdown decay heat removal and inventory control

Containment closure

Refueling activities

Plant heatup/mode changes from No Mode to Mode 1

Core physics testing

Power Escalation

b.

Findings

No findings of significance were identified.

1R22 Surveillance Testing

a.

Inspection Scope

The inspectors witnessed surveillance tests and/or reviewed test data of the risk-significant SSCs listed below, to assess, as appropriate, whether the SSCs met TS, Updated Final Safety Analysis Report (UFSAR), and licensee procedure requirements.

In addition, the inspectors determined if the testing effectively demonstrated that the SSCs were ready and capable of performing their intended safety functions.

PT/1/A/0151/019, Penetration 19 Leak Rate Test (CIV)

PT/3/A/0600/012, Turbine Driven Emergency Feedwater Pump Test (IST)

PT/1/A/0251/024, High Pressure Injection (HPI) Full Flow Test (IST)

PT/3/A/0290/004, Turbine Stop Valve Test

PT/0/A/0400/004, SSF Diesel Engine Service Water Pump Test (IST)

Enclosure

b.

Findings

No findings of significance were identified.

4.

OTHER ACTIVITIES

4OA2 Identification and Resolution of Problems

.1 Daily Screening of Corrective Action Reports

In accordance with Inspection Procedure (IP) 71152, "Identification and Resolution of Problems, and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed daily screening of items entered into the licensees corrective action program. This review was accomplished by reviewing copies of PIPs, attending daily screening meetings, and accessing the licensees computerized database.

.2 Semi-Annual Trend Review

a. Inspection Scope

As required by IP 71152, "Identification and Resolution of Problems," the inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screenings discussed in Section 4OA2.1 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the six month period of January 2008, through June 2008, although some examples expanded beyond those dates when the scope of the trend warranted. The review also included issues documented outside the normal CAP in major equipment problem lists, plant health team vulnerability lists, focus area reports, system health reports, self-assessment reports, maintenance rule reports, and Safety Review Group Monthly Reports. The inspectors compared and contrasted their results with the results contained in the licensees latest quarterly trend reports. Corrective actions associated with a sample of the issues identified in the licensees trend report were reviewed for adequacy.

b. Assessment and Observations

No findings of significance were identified. In general, the licensee has identified trends and has appropriately addressed the trends with their CAP.

Enclosure

4OA3 Event Follow-up

.1 Plant Events

a.

Inspection Scope

The inspectors evaluated the events listed below to assess the overall impact on the plant and mitigating actions. As appropriate, the inspectors: (1) observed plant parameters and status, including mitigating systems/trains; (2) determined alarms/conditions preceding or indicating the event; (3) evaluated performance of mitigating systems and licensee actions; and (4) confirmed that the licensee properly classified, if applicable, the event in accordance with emergency action level procedures and made timely notifications to NRC and state/county governments as required.

PIP O-08-1626, Unit 2 Turbine Trip/Reactor Trip due to low condenser vacuum signal on March 31, 2008

PIP O-08-1940, Unit 1 Reactor Coolant Pump high vibrations and seal failures during shutdown on April 12-13, 2008

PIP O-08-2056, Unit 1 Loss of inventory while on decay heat removal on April 15, 2008

b.

Findings

On April 15, 2008, Unit 1 experienced a generator lockout, which caused a loss of normal power through the back charged main transformer to main feeder bus (i.e., N breakers and generator output breakers PCB 21 and 20 opened). This caused a momentary loss of power to the LPI and low pressure service water (LPSW) pumps, and AP-26 (Loss of Decay Heat Removal) was entered by the operators. The main feeder bus (MFB) power was restored in 1.8 seconds via the slow transfer logic from the E breakers (as expected) and power to the LPI and LPSW pumps was restored (non-load shed). MFB re-energization should have re-energized motor control center (MCC) 1XP, but did not, as the alternate feeder breaker to 1XP tripped on high in-rush current. MCC 1XP supplies power to air operated valves 1HP-8 (Unit 1 Purification Demineralizer Inlet Isolation), 1HP-17 (1A Letdown Filter Inlet Isolation) and 1HP-18 (1B Letdown Filter Inlet Isolation). These valves closed due to the loss of power to each valves respective control solenoid valve, which isolated the letdown flow path. The valves should have reopened upon the restoration of power, but the loss of power to MCC 1XP prevented this from occurring. The isolation of the letdown flow path coupled with the LPI pump restart caused 1HP-43 (letdown line relief valve) to lift open as the relief valve now saw LPI pump discharge pressure. This resulted in a loss of RCS inventory to the Mixed Waste Holdup Tank (MWHUT).

Operators initiated makeup to the LPI system from the borated water storage tank (BWST) by throttling 1LP-21 (BWST isolation) and 1LP-96 (LP Supply to Purification IX block) was closed to isolate LPI from the purification lineup per AP-26. This allowed 1HP-43 to shut and effectively stop the inventory loss. Specifically, RCS level dropped from 70 to 54 inches on LT-5 (approximately 2000 gallons of inventory was dumped to

Enclosure

MWHUT). Level was restored to 79 inches on LT-5 approximately 30 minutes from initiation of the event.

The generator lockout was a result of ongoing automatic voltage regulator (AVR)

preventive maintenance, IP/0/B/2005/001, Main Generator Automatic Voltage Regulator Maintenance and Channel Transfer, where as part of the AVR procedure, the AVRs measuring unit board (part of each AVR channel) was replaced and powered up.

Unrecognized by the procedure, this power up resulted in the actuation of the K31 relay in the AVR, which sends a lockout signal to the main generator. The root cause was determined to be a failure of procedure preparers and reviewers of IP/0/B/2005/001, to recognize the system interaction between the AVR trip circuitry and the backcharge power path. This issue is unresolved pending further NRC review of the licensees procedures, operator actions, and risk management associated with this event. This item is identified as URI 05000269/2008003-02, AVR Maintenance Procedure Resulted in a Loss of Inventory While on Decay Heat Removal. This issue is in the licensees corrective action program as PIP O-08-2056.

.2 (Closed) Licensee Event Report (LER) 05000270/2008-01-00, Unit 2 Reactor Trip Due to Indication of Loss of Vacuum During Calibration of a Condenser Pressure Transmitter.

On March 31, 2008, while operating at 100 percent RTP with calibration of the units condenser vacuum pressure transmitters in progress, the unit automatically tripped. The inspectors reviewed the licensees root cause of the event. The event was caused by an indicated loss of condenser vacuum, which resulted in a turbine trip and subsequent reactor trip. The indicated loss of vacuum was most likely caused by a combination of an obstruction in the pressure transmitters tubing and leakage of the 2B condenser pressure transmitter isolation valves. This resulted in an indicated loss of condenser vacuum, which satisfied the vacuum trip logic and automatically tripped the turbine. The main turbine trip caused the reactor to trip automatically. No performance deficiencies were identified. The licensee entered this issue into their corrective action program as PIP O-08-1626. This LER is considered to be closed.

4OA5 Other Activities

.1 Quarterly Resident Inspector Observations of Security Personnel and Activities

a.

Inspection Scope

The inspectors toured areas and observed security force personnel and security related activities, as listed below, to ensure that the activities were consistent with licensees 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, activities and areas did not constitute additional inspection samples. Rather, they were considered an integral part of the inspectors' normal plant status review and inspection activities.

Enclosure

Multiple tours of the Central and Secondary Security Alarm Stations, as well as observation of the operation of each station

Tours of selected security officer response posts

Multiple tours of the Personnel Access Portal (PAP), as well as observation of screening operations conducted at the PAP

Security Force exercises

Multiple tours of the Main Checkpoint, as well as observation of screening operations

Security force shift turnover activities

b.

Findings

No findings of significance were identified.

.2 (Closed) URI 05000269,270,287/2006002-03, Survivability of Main Steam Safety Valves (MSSVs) During an Event Requiring SSF Auxiliary Service Water (ASW) System. This URI was opened pending further inspection and assessment to address excessive cycling of MSSVs during an SSF event indicated by the licensees thermal hydraulic analyses (PIP O-05-3770), as the original operability assessment did not demonstrate that these valves would remain functional. As a result, the licensee contracted the testing of a spare MSSV, subjecting the valve to 1000 lift cycles under representative plant conditions following an SSF event. The results of this test showed that the valve remained in good condition with minimal seat leakage that would not affect SSF operability. The licensee also addressed the possibility of the MSSV sticking open as a result of the excessive lifting. The licensee was able to demonstrate through simulator validations of existing procedures, and through initial RETRAN analyses of bounding worst case main steam line break scenarios, that the SSF would remain functional during the course of a plant cooldown that would result from one stuck open MSSV in each main steam line. Based on the inspectors review of the licensees evaluations listed above, no performance deficiency was identified associated with the URI.

Consequently, NRR will perform a review of the effects of additional SSF operational scenarios with a compromised main steam pressure boundary as part of the licensees recent tornado and high energy line break mitigation license amendment requests, this URI is considered closed.

4OA6 Management Meetings (Including Exit Meeting)

.1 Exit Meeting Summary

The inspectors presented the inspection results to Mr. David Baxter, Site Vice President, and other members of licensee management at the conclusion of the inspection on July 8, 2008. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any of the material examined during the inspection should be considered proprietary. No proprietary information was identified.

.2 Annual Assessment Meeting Summary

On April 10, 2008, the Acting Chief of Reactor Projects Branch 1, and the Resident

Enclosure Inspectors assigned to the Oconee Nuclear Station (ONS) met with Duke to discuss the NRC's Reactor Oversight Process (ROP) and the NRC's annual assessment of ONS safety performance for the period of January 1, 2007 - December 31, 2007. The major topics addressed were the NRC's assessment program and the results of the ONS assessment. The meeting was open to the public. A listing of meeting attendees (ML081980652) and information presented during the meeting (ML081980646) are available from the NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at www.nrc.gov/reading-rm/adams.html.

4OA7 License Identified Findings

The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which met the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a NCV.

NRC Order EA 03-009 Paragraph C. (5).E requires for each inspection of the reactor vessel head required in the order, the licensee shall submit a report detailing the inspection results within 60 days after returning the plant to operation. Contrary to these requirements, the licensee did not submit a 60 day report for Unit 3 head inspections conducted during the last refueling outage, which ended December 23, 2007. This finding is determined to be of very low safety significance because the deficiency was identified, examinations that met the requirements of NRC Order 03-009 were performed, and the report was subsequently submitted on April 22, 2008.

The licensee entered the finding into their corrective action program as PIP 08-01635.

ATTACHMENT: SUPPLEMENTAL INFORMATION

Attachment SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

K. Alter, Mechanical Balance of Plant Engineering Supervisor E. Anderson, Superintendent of Operations S. Batson, Engineering Manager D. Baxter, Site Vice President D. Brewer, Safety Assessments Manager R. Brown, Emergency Preparedness Manager E. Burchfield, Reactor and Electrical Systems Manager T. Coleman, ISI Coordinator C. Curry, Mechanical/Civil Engineering Manager P. Culbertson, Maintenance Manager G. Davenport, Compliance Manager P. Downing, SG Manager B. Edge, I & C Engineering Supervisor R. Fruedenberger, Safety Assurance Manager J. Gilreath, SGISI Coordinator M. Glover, Station Manager L. Hekking, Boric Acid Coordinator D. Hubbard, Training Manager T. King, Security Manager B. Meixell, Technical Specialist P. North, Shift Operations Manager J. Smith, Technical Specialist J. Smith, Regulatory Compliance J. Steely, Continuing Training Supervisor S. Thomas, Safety Analysis Engineering Supervisor J. Twiggs, Radiation Protection Manager J. Weast, Regulatory Compliance D. Williams, Modification Engineering Manager

NRC

S. Rose, Acting Chief, Reactor Projects Branch 1 L. Olshan, Project Manager, NRR

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened 05000269/2008003-02 URI AVR Maintenance Procedure Resulted in a Loss of Inventory While on Decay Heat Removal (Section 4OA3.1)

Attachment

Opened and Closed 05000269/2008003-01 NCV Required Pressure Tests Not Performed (Section 1R08.1)

Closed

05000270/2008-01-00 LER Unit 2 Reactor Trip Due to Indication of Loss of Vacuum During Calibration of a Condenser Pressure Transmitter (Section 4OA3.2)

05000269,270,287/2006002-03 URI Survivability of Main Steam Safety Valves (MSSVs) During an Event Requiring SSF Auxiliary Service Water (ASW) System (Section 4OA5.2)

DOCUMENTS REVIEWED

Section 1R01: Adverse Weather Protection

Hot Weather PIP O-08-0657, AHU1-8 needs to be repaired prior to summer PIP O-08-1258, Seasonal checks of various AHUs needs to be rescheduled from 08W11 to 08W19 due to procedural requirement that requires warmer weather Selected Licensee Commitments (SLC) 16.6.14, Control of HPI and LPI/RBS pump Room Temperatures OSC-6667, Auxiliary and Turbine Building Loss of Cooling/ Ventilation Analysis OSS-0254.00-00-1039, Design Basis Specification for Low Pressure Service Water System Drawing OFD-124B-1.6 and 3.6, Low Pressure Service Water System (Aux. Bldg. Air Handling Units)

External Flooding UFSAR Section 2.4, Hydrologic Engineering, UFSAR Section 9.6, Standby Shutdown Facility (SSF)

SLC 16.9.21, SSF External Flood Protection, SSF ASW Design Basis Documents Section 2.2.5, Design Events, SSF ASW Design Basis Documents Section 2.3.13, Flood

Evaluation of Summer Readiness of Offsite and Alternate AC Power Systems AP/1,2,3 /A/1700/034, Degraded Grid AP/1,2,3/A/1700/011, Recovery From Loss of Power OP/1,2,3/A/1106/040, Generator Voltage Schedule EP/1,2,3/A/1800/001, Emergency Operating Procedure - Blackout PT/0/A/0610/026, Electrical System Weekly Surveillance PT/1,2/A/2200/001, KHU-1, -2 Weekly Surveillance PT/1,2/A/2200/002, KHU-1, -2 Bi-Monthly Surveillance PT/1,2/A/2200/003, KHU-1, -2 Quarterly Surveillance

Attachment

OP/0/A/2000/041, KHS - Modes of Operation

Section 1R04: Equipment Alignment

OP/0/A/2000/041, KHS - Modes of Operation TS 3.8.1 and bases, AC Sources - Operating OSS-0254.00-00-2005, Design Basis Specification for Keowee Emergency Power UFSAR Section 8.3.1.1.1, Keowee Hydro Station SLC 16.8.6, Lee/Central Alternate Power System OSS-0254.00-00-1034, Design Basis Specification for the Reactor Building Spray System Drawing OFD-103A-3.1, Flow Diagram of Reactor Building Spray System (Unit 3)

OSS-0254.00-00-1028, Design Basis Specification for Low Pressure Injection and Core Flood System Drawing OFD-102A-1.1, Flow Diagram of Low Pressure Injection System (Borated Water Supply & LPI Pump Suction)

Drawing OFD-102A-1.2, Flow Diagram of Low Pressure Injection System (LPI Pump Discharge)

Section 1R05: Fire Protection

UFSAR Section 9.5.1, Fire Protection System Design Basis Specification OSS-0254.00-00-4008, Fire Protection

Section 1R08: Inservice Inspection Activities

Procedures

Areva 03-1275114-011, Eddy Current Data Management Guidelines, Rev. 011 Areva 03-9020586-001, Requirements for the Preparation of Automated Eddy Current Data Analysis Program, Rev. 001 Areva 03-9032829-003, Eddy Current Guidelines for Oconee Nuclear Station Replacement Once-Through Steam Generators (ROTSG), Rev. 003 Areva 54-ISI-400-15, Multi-Frequency Eddy Current Examination of Tubing, July 2006 Duke Power NDE Procedures Manual-Volume 23-NDE25, Magnetic Particle Examination Duke Power NDE Procedures Manual-Volume 4-NDE-B Training, Qualification and Certification of Nondestructive Examination Personnel Duke Energy NDE-66-Visual Examination (VT3) of Hangers, Restraints, Supports, and Snubbers Duke Energy NDE-68-VT-2, Visual Examination for leakage Duke Energy Nuclear System Directive 307, Quality Standard Manual Oconee Nuclear Site Directive S.D.2.1.9-ASME Section XI Repair/Replacement Duke Power NDE Procedures Manual-Volume 4-NDE600, Ultrasonic Examination of Similar Metal Welds in Ferritic and Austenitic Piping Duke Power NDE Procedures Manual-Volume 4-PDI-UT-6PDI, Generic Procedure for the Manual Ultrasonic Examination of Reactor Pressure Vessel Welds Duke Power NDE Procedures Manual-Volume 4-NDE830, Ultrasonic Examination of Cast Austenitic Welds Using Refracted Longitudinal Waves

Attachment

Duke Power NDE Procedures Manual-Volume 4-PDI-UT-2-PDI, Generic Procedure for Ultrasonic Examination of Austinitic Pipe Welds QAP 8.0, Rev. 11. WSI Procedure: Control and Issue of Weld Filler Material.

QAP 8.1, Rev. 7. WSI Procedure: Material Receiving and Control.

QAP 9.6, Rev. 11. WSI Procedure: Liquid Penetrant Inspection.

QAP 9.16, Rev. 4. WSI Procedure: High-Temperature Liquid Penetrant Inspection (100°F -

350°F).

QAP 9.21, Rev. 2. WSI Procedure: Liquid Penetrant Inspection (Alloy 690 Weld Overlay).

NDEMAN-PDI-UT-6, Rev. F. Generic Procedure for the Manual Ultrasonic Examination of Reactor Pressure Vessel Welds.

NDEMAN-NDE-600, Rev. 017. Ultrasonic Examination of Similar Metal Welds in Ferritic and Austenitic Piping.

MP/0/A/1140/013 A-CRDM - Flanges and Motor Tubes - Visual Inspection MP/0/A/1150/029 Rev. 3-Reactor Vessel - Head Penetrations - Visual Inspection

Condition Reports

PIP O-08-02311, ONS 1EOC24 Steam Generator Eddy Current (ET) Inspection and Its Associated Reporting Requirements and Control Document Updates PIP 0-08-02521, NRC identified concern with Filler material and receiving procedure provided by Welding Services PIP 0-08-02523, NRC identified two requests for relief as untimely during unit 1 ISI inspection PIP 0-08-01635, Oconee did not submit a report detailing the results of the Unit 3 reactor pressure vessel head inspection within 60 days after returning the unit to operation PIP 0-99-00737, NRC staff position that ESF system must withstand single active failure PIP 0-08-02358, ESF branch connection does not meet Code requirements PIP 0-08-02261, ESF existing weld found to be partial penetration weld when full penetration is required PIP O-08-01933, Items Noted on U1EOC24 ENG/MNT Mode 3 Shutdown Reactor Building Tour.