IR 05000269/2009003
| ML092090670 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 07/28/2009 |
| From: | Bartley J NRC/RGN-II/DRP/RPB1 |
| To: | Baxter D Duke Energy Carolinas |
| References | |
| IR-09-003 | |
| Download: ML092090670 (29) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
uly 28, 2009
SUBJECT:
OCONEE NUCLEAR STATION - INTEGRATED INSPECTION REPORT 05000269/2009003, 05000270/2009003, AND 05000287/2009003
Dear Mr. Baxter:
On June 30 2009, 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 9, 2009, with Mr. Preston Gillespie, Station Manager, and other 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.
Based on the results of the inspection, one self-revealing finding of very low safety significance (Green) was identified which was determined to be a violation of NRC requirements. Also, two licensee identified violations, which were determined to be of very low safety significance, are listed in this report. 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 non-cited violations (NCVs), consistent with Section VI.A.1 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. 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 II, and the NRC Resident Inspector at Oconee. The information you provide will be considered in accordance with Inspection Manual Chapter 0305.
DEC 2 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/
Jonathan H. Bartley, 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 05000269/2009003, 05000270/2009003, and 05000287/2009003 w/Attachment: Supplemental Information
REGION II==
Docket Nos: 50-269, 50-270, 50-287 License Nos: DPR-38, DPR-47, DPR-55 Report Nos: 05000269/2009003, 05000270/2009003, 05000287/2009003 Licensee: Duke Energy Carolinas, LLC Facility: Oconee Nuclear Station, Units 1, 2 and 3 Location: Seneca, SC 29672 Dates: April 1, 2009 through June 30, 2009 Inspectors: A. Hutto, Senior Resident Inspector E. Riggs, Acting Senior Resident Inspector G. Ottenberg, Resident Inspector R. Chou, Reactor Inspector (Section 1R18)
R. Carrion, Senior Reactor Inspector (Section 1R08 and 4OA5)
E. Michel, Senior Reactor Inspector (Section 1R08)
Approved by: Jonathan H. Bartley, Chief Reactor Projects Branch 1 Division of Reactor Projects Enclosure
SUMMARY OF FINDINGS
IR 05000269/2009-003, 05000270/2009-003, 05000287/2009-003; 04/01/2009 - 06/30/2009;
Oconee Nuclear Station, Units 1, 2, and 3; Refueling and Outage Activities.
The report covered a three-month period of inspection by the resident inspectors and three region based reactor inspectors. 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.
Cornerstone: Initiating Events
- Green.
A self-revealing non-cited violation (NCV) of Technical Specification 5.4.1 was identified for the failure to adequately implement the procedural requirements for draining the RCS to 100 inches in the pressurizer, resulting in draining approximately 4100 gallons more RCS inventory than desired.
The finding was considered to be more than minor because it was associated with the initiating events cornerstone attribute of human performance and affected the objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions. The finding was determined to be of very low safety significance (GREEN) based on the availability of diverse level indications and their associated low level alarms, and it was estimated that an additional 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> of draining would be required to approach midloop conditions. This finding has a cross-cutting aspect of personnel follow procedures (H.4(b)),
as described in the Work Practices component of the Human Performance cross-cutting area.
Two violations of very low safety significance (Green), which were identified by the licensee, have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. These violations and corrective actions are listed in Section 4OA7 of this report.
REPORT DETAILS
Summary of Plant Status
Unit 1 began the report period at 100 percent rated thermal power (RTP). On April 29, the unit was reduced to approximately 85 percent RTP to replace the breaker for the 1D1 heater drain pump due to an electrical ground. The unit was returned to 100 percent RTP later the same day where it remained through the end of the inspection period.
Unit 2 operated at 100 percent RTP for the entire inspection period.
Unit 3 began the report period at 100 percent RTP. On April 24 the unit was shutdown for a scheduled refueling outage. The unit was restarted on May 20 and placed online on May 21.
On May 21, during power escalation activities, the unit experienced an automatic reactor trip from 42 percent RTP. The unit was restarted on May 22 and placed online on May 25. The unit achieved 100 percent RTP on May 26, where it remained through the end of the inspection period.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
1R01 Adverse Weather Protection
a. Inspection Scope
The inspectors assessed the licensees response to a severe thunderstorm warning and tornado watch issued for the area surrounding the Oconee Nuclear Station on April 20.
The inspectors ensured that operations personnel entered Abnormal Procedure (AP),
AP/0/A/1700/006, Natural Disaster, initiated Enclosure 5.4, Severe Weather, and reviewed Enclosure 5.1, Tornado Information. The inspectors also ensured that the Keowee Hydro Station operators entered AP/0/A/2000/001, Keowee Hydro Station -
Natural Disaster, as required.
b. Findings
No findings of significance were identified.
1R04 Equipment Alignment
a. Inspection Scope
Partial Walkdown. The inspectors conducted partial equipment alignment walkdowns of the following three systems to evaluate the operability of selected redundant trains or backup systems while the other train or system was inoperable or out-of-service (OOS).
The walkdowns included, as appropriate, reviews of plant procedures and other documents to determine correct system lineups, 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.
- Unit 2, A and B high pressure injection (HPI) pumps while the C pump was OOS for pump lubrication and replacement of the 2HP-56 valve operator
- Unit 2, low pressure injection (LPI) / decay heat removal function for mid-loop
b. Findings
No findings of significance were identified.
1R05 Fire Protection
a. Inspection Scope
Fire Area Walkdowns The inspectors conducted tours in the four following plant areas 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.
- Turbine Building Basement (1)
- Unit 1 and 2 LPI Hatch Area (1)
- Unit 3 Reactor Building (RB) (1)
- Standby Shutdown Facility (SSF) (1)
b. Findings
No findings of significance were identified.
1R06 Flood Protection Measures
a. Inspection Scope
Internal Flooding. The inspectors reviewed the licensees commitments to address High Energy Line Break (HELB) induced flooding as part of the licensees HELB licensing reconstitution project (letter submitted to the NRC dated November 18, 2008, ADAMS Accession No. ML083330276). The inspectors walked down the newly installed Auxiliary Building HELB flood control barriers and flood outlet device located in the Unit 1, 2 and 3 East Penetration Rooms and on the Auxiliary Building Third Floor. The inspectors verified the adequacy of the flood barriers and observed the overall condition of the barriers to verify there were no gaps between sealing surfaces, gaskets were in good condition and that barrier gates were secure. The inspectors also observed the condition of the East Penetration Room Flood Outlet Devices to verify that there were no obstructions that would prevent the devices from performing their flood control function.
The inspectors verified that the barriers and flood outlet device had been added to Site Directive 3.2.16, Control of Passive Design Features.
b. Findings
No findings of significance were identified.
1R08 In-service Inspection (ISI) Activities
a. Inspection Scope
ISI Activities. 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 during the Unit 3 refueling outage. The inspectors activities consisted of an on-site review of nondestructive examination (NDE) activities to evaluate compliance with the applicable edition of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section XI (the Code of record for the Fourth 10-year ISI interval was 1998 Edition through 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 directly observed NDE activities and reviewed examination procedures, NDE reports, equipment and consumable certification records, personnel qualification records, and calibration reports (as applicable) for the following examinations:
Ultrasonic Testing (UT)
- Weld 3-53A-15-57, Elbow to Pipe on 10-Diameter Stainless Steel Low Pressure Injection Line (Class 2)
Magnetic Particle Testing (MT)
- Welds on Lugs of Pipe Support 03.H4.1.0012 for 24-Diameter Feedwater Supply to Steam Generator 3B (Class 2)
Liquid Penetrant Testing (PT)
- Weld 3LP-223-6, Pipe to Elbow on 10-Diameter Stainless Steel Low Pressure Injection Line (Class 2)
- Weld 3LP-223-7, Elbow to Pipe on 10-Diameter Stainless Steel Low Pressure Injection Line (Class 2)
PWR Vessel Upper Head Penetration Inspection Activities. The licensee conducted a bare metal walkdown inspection of the reactor vessel head per its internal procedures to monitor the condition of the reactor vessel head. While there was no indication of leakage from any of the control rod drive mechanism penetrations, some chemical deposits were noted on the head in several locations. The licensee noted that leakage from the insulation of the component cooling system above the reactor head had dripped onto the reactor head. Because the chemical composition of the deposits could not be readily determined, a sample was collected and sent to an offsite laboratory for analysis.
The inspectors reviewed Problem Investigation Process (PIP) O-09-02628 which documented these events. The laboratory report stated that a detailed examination showed the bulk of the flakes to be sodium molybdate, but with a sulfur-rich material clinging to the flakes and that very little boron was observed in the deposit sample.
Boric Acid Corrosion Control (BACC) Inspection Activities. 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 Components in PWR Plants, and applicable industry guidance documents. Specifically, the inspectors performed a record review of procedures and the results of the licensees Mode 3 containment walkdown inspections performed during the Spring 2009 outage, including generated PIP documents and their subsequent engineering evaluations.
The inspectors conducted an independent walkdown of the reactor building to evaluate compliance with the licensees BACC program requirements and verify that degraded or non-conforming conditions, such as boric acid leaks identified during the Mode 3 or 4 containment walkdown, were properly identified and corrected in accordance with the licensees BACC and corrective action programs.
Steam Generator (SG) Tube Inspection Activities. The inspectors reviewed the Unit 3 SG tube eddy current testing (ECT) examination activities to ensure compliance with Technical Specifications (TS), applicable industry standards, SG Program Procedures, and ASME Code Section XI requirements. The inspectors reviewed examination status reports and discussed them with the site lead Level III analyst to ensure that all tubes with indications were appropriately screened for in-situ pressure testing. No in-situ pressure testing was required during the outage. The inspectors reviewed examination results available while on-site, and the previous Condition Monitoring and Operational Assessment to confirm the licensees ability to predict future tube performance. In addition, the inspectors reviewed the latest Degradation Assessment (DA) report to identify the scope of the inspection and verify that it addressed potential degradation areas, plant-specific degradation history, and applicable operating experience. The inspectors verified that appropriate inspection scope expansion criteria were applied based on inspection results of active and new degradation mechanisms. Since the only active degradation mechanism was tube wear due to interaction between the tube and tube support plates, and a 100 percent bobbin inspection was performed, there was no need for scope expansion. In relation to the tube repair methods, the inspectors reviewed the licensees implementation of the tube repair criteria to ensure that it was consistent with plant TS. No primary-to-secondary leakage was identified during the previous operating cycle. In addition, the inspectors reviewed documentation to ensure that data analysts, ECT probes, and equipment configurations were qualified to detect the expected types of SG tube degradation. The inspectors selected a sample of site-specific Examination Technique Specification Sheets for acquisition and analysis to ensure that their qualification was consistent with industry standards. No secondary side examinations were completed, as justified in the licensees DA. The inspectors also observed and interviewed the licensees contractor during a portion of data acquisition activities to ensure compliance with industry standards for data quality. SG3 Tubes, Row 105 - Column 109 and Row 77 - Column 131, were reviewed for analysis with a Qualified Data Analyst.
Identification and Resolution of Problems. The inspectors performed a review of ISI-related problems, including BACC and SG tube inspection activities that were identified by the licensee and entered into the corrective action program as PIP documents. The inspectors reviewed the PIPs to confirm that the licensee had appropriately described the scope of the problem and had initiated corrective actions. The review also included the licensees consideration and assessment of operating experience events applicable to the plant. 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 by the inspectors are listed in the report attachment.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification
a. Inspection Scope
Simulator Training The inspectors observed licensed operator simulator training on February 25, 2009. The simulator scenario involved a reactor coolant pump high vibration condition, which resulted in a RCP seal failure followed by a stuck open pressurizer (PZR) relief valve. The scenario concluded with a steam generator tube failure.
The inspectors observed crew performance in terms of communications between the operators; 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.
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 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. The inspectors reviewed the following items:
- Unit 3 Turbine Bypass Valve Issues
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 six 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. Documents reviewed are listed in the
.
- Risk Management Actions during IP/0/A/0250/010, Low Pressure Service Water (LPSW) and RB Auxiliary Cooler System Instrument Calibrations
- Critical Activity Plan for Unit 3 Electrical Generator Rotor Movement
- 3EOC24 Refueling Outage Risk Assessment
- Emergent Work for PIP O-09-2304, Unexpected Increase in Letdown Storage Tank Level During Addition of 2B Bleed Holdup Tank for Reactivity
- Revision 1 of the Complex Activity Plan for OD 5000947, Trenching and Underground Ductbank for Protected Service Water Building
- Revision 2A of the Complex Activity Plan for OD 500948, Relocation of Underground Commodities for Protected Service Water Building
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations
a. Inspection Scope
The inspectors reviewed six 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 appropriately controlled; and
- (5) where continued operability was considered unjustified, the impact on TS limiting condition for operations (LCOs). Documents reviewed are listed in the
. The inspectors reviewed the following operability evaluations:
- PIP O-09-1994, Keowee Hydro Equipment is in Need of Overhaul/Refurbishment
- PIP O-09-2302, SSF Fuel Oil Day Tank is Offscale High and in Alarm
- PIP O-09-3017, Unit 3, 4160V Main Feeder Bus 1 and 2 Voltage High
- PIP O-09-3451, 1FDW-41 Valve Demand From Integrated Control System has Reached approximately 100 Percent
- PIP O-09-4247, Keowee Inlet Cooling Water Temperature Issues
b. Findings
No findings of significance were identified.
1R18 Plant Modifications
.1 Auxiliary Building Wall Modification
a. Inspection Scope
The inspectors reviewed portions of the licensee responses and progress reports to NRC, the NRC information requests, and the safety evaluation for IE Bulletin 80-11, Masonry Wall Design. The purpose of the bulletin was to ask the licensee to identify the facility masonry walls which might impact the safety-related systems, establish a re-evaluation program, and submit a written report upon completion of the re-evaluation.
The inspectors reviewed PIPs O-09-01358 and O-09-01902, pictures taken from the cut of concrete block or brick walls, and calculations related to the wall design in order to evaluate the difference between the original assumption of full-fill mortar between the bricks or blocks in side by side on the design calculations and the responses to the IE Bulletin and voids found or identified in the pictures from the cut-out of walls. The inspectors reviewed the evaluation which confirmed that the brick or block walls with voids in the mortar could still fulfill intended design requirements to transfer the enough shear forces from one brick to another brick to resist the natural disaster.
The inspectors walked down the Unit 2 Auxiliary Building to review a missing concrete beam in the West Penetration Room Wall. The beam existed in Units 1 & 3, but not in Unit 2. The licensee determined the wall was operable. The inspectors discussed the problem with the responsible engineers and reviewed the adequacy of the operability evaluation for this degraded wall and a proposal to reinforce a portion of this wall with steel channel. The inspectors reviewed a licensee submittal dated November 18, 2008, ADAMS Accession No. ML083330276, which proposed to add a Fiber Reinforced Polymer (FRP) Layer on the outside of the outside wall of the Auxiliary Building to resist the tornado leeward pressure which will create a bending moment, as well as install new girt siding reinforcement . The inspectors also discussed the new girt siding reinforcement and modification related to the addition of the FRP layer with the licensee engineers. This inspection activity does not constitute a full inspection sample, as the removal of auxiliary building siding, inspection of the walls exterior, and installation of the FRP is not complete.
b. Finding No findings of significance were identified.
.2 Protected Service Water (PSW) Ductbank and Building Construction
a. Inspection Scope
The inspectors reviewed the specification and procedure for the design, installation, inspection, and testing of concrete placed or to be placed on PSW ductbank and building, which was part of licensee commitments made in HELB license amendment requests dated November 18, 2008, ADAMS Accession No. ML083330276. The inspectors reviewed the documents, PIP reports, Nonconformance Reports, and testing records for the air content, slump, weight, temperature, and compressive strength related to the PIPs and other random samples. The compressive test results were reviewed and verified that the cured concrete had a strength of a minimum 4,000 pounds per square inches after the concrete was cured. The inspectors also reviewed the document which inspected the concrete ready-mix plant facility including the certifications for the trucks, weight scales, and the material storage location prior to the concrete initial placement to make sure that the mix plant had met the facility requirements in the specification. The inspectors reviewed the compressive test stresses for the mix samples prepared prior to the initial concrete placement to verify that the concrete mix will achieve the design stress requirements.
The inspectors walked down the PSW ductbank route and the building site to review the completed concrete bank and the excavation activities for the ductbank and building.
The inspectors discussed the rebar installation with the engineers and verified that no issues were identified related to the rebar installation in the ductbank. This inspection activity does not constitute a full inspection sample, as the construction of the PSW building and ductbank was still in progress.
b. Findings
No findings of significance were identified.
1R19 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed six post-maintenance test 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. The inspectors observed testing and/or reviewed the results of the following tests:
- PT/3/A/0203/006A, 3C LPI Pump Test following installation of the cyclone separator modification
- PT/2/A/0600/028 (2MS-93 Nitrogen Supply Leakage Test) and PT/2/A/0152/015 (Main Steam System Valve Stroke Test) following the replacement of 2N-318 (2MS-93 nitrogen supply)
- TT/3/A/3117/002, LPSW Waterhammer Prevention (WPS) System Boundary Valve Leakage Test following the installation of the Unit 3 LPSW WPS modification
- PT/0/A/0711/001, Unit 3 Zero Power Physics Test following the 3EOC24 refueling outage
- PT/2/A/0600/012, Unit 2 Turbine Driven Emergency Feedwater (TDEFW) Pump Test following adjustment of 2N-319 (2MS-93 nitrogen supply)
b. Findings
No findings of significance were identified.
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 24, 2009, and May 20, 2009, the following activities related to the 3EOC-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
Introduction:
A Green self-revealing NCV of TS 5.4.1 was identified for the failure to implement the procedural requirements for draining the RCS to 100 inches in the pressurizer resulting in draining approximately 4100 more gallons of RCS inventory than desired.
Description:
On April 26, 2009, Unit 3 performed a PZR cooldown and lowered level in the RCS loops to 100 inches indicated PZR level per OP/3/A/1103/005, Enclosure 4.1, PZR Cooldown and RCS Drain to 100 inches PZR Level. The operators calculated the expected volume to be drained and the corresponding BHUT level which was determined to be approximately 89 inches. A note in the procedure specified that the expected BHUT level shall not be exceeded. The procedure instructs the operators to drain the RCS to the band of 100 - 110 inches and to continue to drain as necessary until the level stabilizes or until the expected BHUT level is reached.
The operators determined that PZR level had stabilized and recorded the final BHUT level of 81 inches. Over the course of the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, as PZR temperature decreased, PZR level continued to increase as the established PZR vent path was not adequate to prevent vacuum formation in the pressurizer which caused RCS inventory to be pulled into the PZR. In response to the increasing PZR level, the operators performed a series of additional drain evolutions to maintain the desired PZR level; however, the operators failed to comply with the requirement to not exceed the expected BHUT level. When PZR relief valve 3RC-68 was removed as part of the scheduled outage activities, an additional vent path was established and level in the PZR rapidly decreased from 109 inches to 76 as it equalized with the level in the RCS loops. The operators promptly entered AP/3/A/1700/002, Excessive RCS Leakage, and restored PZR level to the desired 100-110 inch band. Diverse RCS level indicators 3LT-5A and B were put in service right at the time that the level change was occurring and actual RCS level was indicated to be approximately 85 inches. The licensee determined that approximately 4100 additional gallons was drained from the RCS as a result of the additional draining evolutions.
Analysis:
The inspectors determined that the licensee=s failure to adequately implement the procedural requirements for draining the RCS was a performance deficiency. The finding was considered to be more than minor because it was associated with the initiating events cornerstone attribute of human performance and affected the objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions in that excess RCS inventory was drained from the RCS. The significance of this finding was evaluated using IMC 0609, Appendix G, Shutdown Operations, and determined to be of very low safety significance (Green) based on the availability of diverse level indications and their associated low level alarms and that it was estimated that an additional 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> of draining would be required to approach midloop conditions. This finding has a cross-cutting aspect of personnel follow procedures (H.4(b)), as described in the Work Practices component of the Human Performance cross-cutting area in that operators exceeded the expected BHUT level of
89.
Enforcement:
TS 5.4.1 requires that procedures shall be established, implemented and maintained covering the applicable procedures recommended in Regulatory Guide (RG)1.33. RG 1.33, Appendix A, Section 3, Procedures for Startup, Operation, and Shutdown of Safety Related PWR Systems, recommended procedures for draining of the RCS. Contrary to the above, on April 26, 2009, the licensee failed to adequately implement procedure OP/3/A/1103/005, Enclosure 4.1, PZR Cooldown and RCS Drain to 100 inches PZR Level such that approximately 4100 additional gallons of RCS coolant was inadvertently drained to the BHUT. Because the finding was determined to be of very low safety significance and has been entered into the licensee=s corrective action program as PIP O-09-2630, this violation is being treated as a NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000287/2009003-01, Failure to Adequately Implement Procedures for Draining the Reactor Coolant System.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors witnessed six surveillance tests and/or reviewed test data of the risk-significant SSCs listed below, to assess, as appropriate, whether the SSCs met TS, 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. Documents reviewed are listed in the
.
Routine Surveillances
- PT/2/A/0290/004, Unit 2 Turbine Stop Valve Test
- PT/3/A/0610/001J, Emergency Power Switching Logic Functional Test
- PT/1/A/0230/015, HPI Motor Cooler Flow Test Containment Isolation Valves
- PT/3/A/0151/005B, Penetration 5B Leak Rate Test In-Service Test
- PT/0/A/0400/005, SSF Auxiliary Service Water Pump Test
- PT/3/A/0203/006A, 3C LPI Pump Test - Recirculation
b. Findings
No findings of significance were identified.
OTHER ACTIVITIES
4OA2 Identification and Resolution of Problems
.1 Daily Screening of Corrective Action Reports
In accordance with 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 Focused Review
a. Inspection Scope
The inspectors performed an in-depth review of PIP O-09-1644, Unit 2 TDEFW Pump Recirc Line Leak. The sample was within the mitigating systems cornerstone and involved risk significant systems. The inspectors reviewed the actions taken to determine if the licensee had adequately addressed the following attributes:
- Complete, accurate and timely identification of the problem
- Evaluation and disposition of operability and reportability issues
- Consideration of previous failures, extent of condition, generic or common cause implications
- Prioritization and resolution of the issue commensurate with safety significance
- Identification of the root cause and contributing causes of the problem
- Identification and implementation of corrective actions commensurate with the safety significance of the issue.
b. Findings
No findings of significance were identified.
.3 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 Corrective Action Program (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 2009, through June 2009, 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. Findings and Observations
No findings of significance were identified. In general, the licensee has identified trends and has appropriately addressed the trends with their CAP.
4OA3 Event Followup
Unit 3 Automatic Reactor Trip The inspectors evaluated one licensee event for plant status and mitigating actions. As appropriate, the inspectors:
- (1) observed plant parameters and status, including mitigating systems/trains and fission product barriers;
- (2) determined alarms/conditions preceding or indicating the event;
- (3) evaluated performance of mitigating systems and licensee actions;
- (4) confirmed that the licensee properly classified the event in accordance with emergency action level procedures and made timely notifications to NRC and state/county governments, as required (10 CFR Parts 20, 50.9, 50.72); (5)communicated details regarding the event to management, risk analysts and others in the Region and Headquarters as input to their determining the need for an IIT, AIT, or SIT. This event was documented in PIP O-09-3845, Anticipatory Unit 3 Trip Received Unexpectedly.
b. Findings
No findings of significance were identified.
4OA5 Other Activities
.1 NRC Temporary Instruction (TI) 2515/172, Reactor Coolant System Dissimilar Metal Butt
Welds
a. Inspection Scope
The inspectors reviewed the licensees activities related to the inspection and mitigation of dissimilar metal butt welds in the RCS to ensure that the licensee activities were consistent with the industry requirements established in the Materials and Reliability Program (MRP) document MRP-139, Primary System Piping Butt Weld Inspection and Evaluation Guideline, Revision 1. The inspectors activities took place during this refueling outage and included discussions with the licensees program owner. The licensee is on track to implement the guidelines of MRP-139. There are no Alloy 82/182 butt welds greater than 14 inches nominal pipe size (NPS) and exposed to temperatures equivalent to the hot leg for Units 1, 2 or 3. Therefore, the required volumetric inspection of such welds does not apply to any of the Oconee units. Furthermore, the licensee is planning to volumetrically inspect Alloy 82/182 butt welds greater than 4 inches NPS that are exposed to temperatures equivalent to the cold leg by December 2010, as required by the MRP-139 guidelines. The inspections are scheduled to begin with the next cycle of outages, beginning with Unit 1 in the Fall of 2009, continuing with Unit 2 in the Spring of 2010, and concluding with Unit 3 in the Fall of 2010. Note that previous TI 2515/172 inspection activities were documented in IR 05000269, 270, and 287/2008004 and 05000269, 270, and 287/2008005.
b. Findings and Observations
No findings of significance were identified.
.2 HELB Commitments
a. Inspection Scope
The inspectors reviewed the status of licensee commitments made as part of a HELB license amendment request dated November 18, 2008, ADAMS Accession No.
ML083330276. The licensees HELB commitments, 1H through 10H, for Units 1, 2 and 3 were reviewed by the inspectors for compliance to the ASME Code Section IX requirements. Cognizant licensee engineers were interviewed, ODNS-351, Analysis of Postulated High Energy Line Breaks Outside of Containment, Revision 0, was reviewed, the licensees ISI program was reviewed for inclusion of the specific HELB piping and supports, and results of non-destructive examinations performed earlier were reviewed. HELB Commitments 1H through 10H for Units 1, 2, and 3 had either been completed or were planned for future completion.
b. Findings and Observations
No findings of significance were identified.
.3 Quarterly Resident Inspector Observations of Security Personnel and Activities
a. Inspection Scope
During the inspection period the inspectors conducted observations of security force personnel and activities to ensure that the activities were consistent with licensee 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 reviews and inspection activities.
b. Findings
No findings of significance were identified.
.4 Institute of Nuclear Power Operations (INPO) Plant Assessment Report Review
The inspectors reviewed the final report for the INPO plant assessment of Oconee Nuclear Station conducted in August 2008. The inspectors reviewed the report to ensure that issues identified were consistent with the NRC perspectives of licensee performance and to verify if any significant safety issues were identified that required further NRC follow-up.
4OA6 Management Meetings (Including Exit Meeting)
.1 Exit Meeting Summary
The inspectors presented the inspection results to Mr. Preston Gillespie, Station Manager, and other members of licensee management at the conclusion of the inspection on July 9, 2009. 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 May 7, 2009, the NRCs Chief of Reactor Projects Branch 1, and the Resident Inspectors, met with Mr. Dave Baxter and other members of the licensee staff to discuss the NRCs annual assessment of Oconees safety performance for the period of January 1 through December 31, 2008. The annual assessment results were previously provided to the licensee by a letter dated March 4, 2009.
On May 7, 2009, the Resident Inspectors held a Category 3 meeting for members of the public and local officials. This Category 3 public meeting provided an open house public forum to fully engage the public in a discussion of regulatory issues related to the NRCs ROP and annual assessment of the Oconee Nuclear Station safety performance for the period January 1 through December 31, 2008. The presentation material used for discussions and the list of attendees is available from the NRCs document system (ADAMS) as accession number ML091280311. ADAMS is accessible from the NRC Web site at http://www/nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
4OA7 Licensee Identified Violations
The following violations of very low safety significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as non-cited violations (NCVs).
- 10 CFR 50.55a(g)(4) and ASME Section XI require conditions that do not meet the acceptance criteria of IWA 3000 to be repaired or replaced in accordance with the requirements of Section XI, IWA 4000 prior to putting the line in service. Contrary to this, the licensee identified during a performance of PT/2/A/0600/012, TDEFW Pump Test, that a pinhole leak in the Unit 2 TDEFW pump minimum flow recirculation line weld was not repaired as scheduled prior to putting the line in service. The finding was determined to be of very low safety significance (Green) because the finding did not result in loss of operability or functionality of the system. The licensee entered the finding into their corrective action program as PIP O-09-01644.
- TS 5.4.1, requires that procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide (RG) 1.33. RG 1.33, Appendix A, Section 3h, requires procedures for startup, operation, and changing modes of operation of spent fuel pool cooling. Contrary to the above, the licensee failed to adequately implement their procedure for pumping down the Unit 3 fuel transfer canal (FTC), resulting in a loss of Unit 3 SFP inventory into the Unit 3 FTC. The loss of SFP inventory was identified by the control room operators prior to the low level alarm by observing that an unexpected reduction of SFP cooling flow had occurred and entered the appropriate abnormal procedure.
The finding was determined to be of very low safety significance (Green) because the finding did not result in a loss of SFP inventory greater than 10 percent of SFP volume. The licensee entered the finding into their Corrective Action Program as PIP O-09-03447.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- B. Abellana, LPSW Systems Engineer
- K. Alter, MCE/BOP 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
- C. Curry, Mechanical/Civil Engineering Manager
- P. Culbertson, Maintenance Manager
- P. Downing, SG Manager
- R. Fruedenberger, Safety Assurance Manager
- P. Gillespie, Station Manager
- M. Glover, General Manager of Projects
- J. Kammer, Modification Engineering Manager
- T. King, Security Manager
- B. Meixell, Acting Regulatory Compliance Manager
- S. Severance, Regulatory Compliance
- J. Smith, Regulatory Compliance
NRC
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
- 05000287/2009003-01 NCV Failure to Adequately Implement Procedures for Draining the Reactor Coolant System (Section 1R20).
Discussed
TI 2515/172, Reactor Coolant System Dissimilar Metal Butt Welds (DMBWs)