IR 05000269/1999005
| ML15261A421 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 09/10/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15261A419 | List: |
| References | |
| 50-269-99-05, 50-270-99-05, 50-287-99-05, NUDOCS 9909210049 | |
| Download: ML15261A421 (22) | |
Text
U.S. NUCLEAR REGULATORY COMMISSION REGION 11 Docket Nos:
50-269, 50-270, 50-287, 72-04 License Nos:
DPR-38, DPR-47, DPR-55, SNM-2503 Report Nos:
50-269/99-05, 50-270/99-05, 50-287/99-05 Licensee:
Duke Energy Corporation Facility:
Oconee Nuclear Station, Units 1, 2, and 3 Location:
.
7800 Rochester Highway Seneca, SC 29672 Dates:
July 4 - August 14, 1999 Inspectors:
M. Scott, Senior Resident Inspector S. Freeman, Resident Inspector E. Christnot, Resident Inspector D. Billings, Resident Inspector D. LaBarge, Senior Project Manager (Section E3.1)
G. Wiseman, Reactor Inspector (Section F2)
Approved by:
C. Ogle, Chief, Projects Branch 1 Division of Reactor Projects Enclosure 9909210049 990910 PDR ADOCK 05000269 PDR
EXECUTIVE SUMMARY Oconee Nuclear Station, Units 1, 2, and 3 NRC inspection Report 50-269/99-05, 50-270/99-05, and 50-287/99-05 This integrated inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a six-week period of resident inspection. [Applicable template codes and the assessment for items inspected are provided below.]
Operations
Unit 1 experienced a plant trip due to a loss. of main feedwater pumps. This resulted from an instrumentation tubing installation error that had been introduced during a 1996 modification. Further Nuclear Regulatory Commission (NRC) review of this issue will be conducted during review of the associated Licensee Event Report (LER). (Section 01.2;
[NEG - 2A, 3A])
A non-cited violation was identified for failure to update the Updated Final Safety Analysis Report to include the latest description of the turbine building emergency high level alarm. (Section 02.3; [NCV - 4A])
While the instrumentation would detect an actual flood, weaknesses existed in the test procedure for the turbine building emergency high level alarm. (Section 02.3; [NEG 2B])
A non-cited violation was identified for two licensed operators who failed to complete the job performance measures portion of their operating exam prior to resuming licensed duties. (Section 05.1; [NCV - 1C, 31])
- A non-cited violation was identified for a single failure vulnerability which existed in both trains of the low temperature overpressure. protection system from November 7, 1983, until May 14, 1998. (Section 08.1; [NCV - 4A])
A non-cited violation was identified for failure of the licensee to take timely corrective actions in response to a single failure vulnerability which was identified in the low temperature overpressure protection system on June 4, 1997. The corrective actions to mitigate this condition were not rmplemented until May 1998. (Section 08.1; [NCV - 5B, 5C])
A non-cited violation was identified for a single failure vulnerability which existed between four and five years on each of the Oconee units involving a common low pressure service water chart recorder and flow indicator. (Section 08.2; [NCV - 4A])
A non-cited violation was identified for untimely corrective actions involving a failure of safety-related low pressure service water instrumentation. (Section 08.2; [NCV - 5A, Maintenance
The Keowee Hydro-Electric Plant outage was well planned; was-well coordinated; and had management, supervisory, and technical support. The applicable Technical Specifications and Selected Licensee Commitments were adhered to at all time (Section M1.2; [POS - 3A, 4B])
During a recheck, several Unit 1 main steam relief valves were found out-of-tolerance within two days of their last adjustment. Further NRC review of this issue will be performed during review of the associated LER. (Section M1.3; [NEG - 2A1)
- A non-cited violation was identified for failure to perform a manual quadrant power tilt surveillance within the required surveillance interval during a planned Unit 1 computer outage. (Section M8.1; [NCV - 2B])
A non-cited violation was identified for failure to perform required surveillances on some Unit 2 snubbers. This failure was attributed to inadequate controls on the snubber surveillance program. (Section M8.2; [NCV - 2BJ)
A non-cited violation was identified for a Unit 1 snubber which exceeded its surveillance interval due to an inappropriate procedure change. (Section M8.3; [NCV - 2B])
Engineerin
The licensee's annual reports of updates to the Updated Final Safety Analysis Report and changes made pursuant to 10 CFR 50.59 met regulatory requirements and were a significant improvement over previous submittals. (Section E3.1; [POS - 4A, 41])
A non-cited violation was identified for an inadequate procedure during repairs to a fire barrier. A reactor trip occurred as a result of this inadequate procedure. (Section E8.1;
[NCV - 3A])
Plant Support
Appropriate quality assurance processes were applied to penetration seal inspection and repair procedures to ensure that repair foam materials were installed per design requirements. Safety evaluation documentation for fire protection procedure changes was complete and reached reasonable conclusions concerning whether the changes would compromise plant safety and whether an unreviewed safety question was involved. (Section F2.1; [POS - 3C, 4B])
The penetration seal and fire barrier project modification package accurately incorporated the regulatory commitments for the fire ratings and locations of NRC committed to fire barriers into the plant fire barrier boundary drawings; design specifications; and penetration seal equipment data base. Documentation for the plant modification and related safety evaluations were technically adequate and of good quality with no unreviewed safety questions being identified. (Section F2.2; [POS - 4A])
The fire barrier penetration seals met designs that were either supported by tested configurations or justified by appropriate engineering evaluations. The penetration seal inspection and repair work was performed in accordance with approved procedures and field documentation was maintained for important penetration seal design parameter The licensee's engineering analysis methods have established a basis that these "as built" penetration seal designs would accomplish their intended function to confine a fire and preclude its spread from the compartment of fire origin. (Section F2.3; [POS - 41])
Visual inspection of nine penetration seals installed in fire barriers that separated risk significant plant areas indicated that the seals were in good physical condition. (Section F2.3; [POS - 2A])
A fire risk observation was discussed related to the turbine building fire detector placement.that reduced the effectiveness of the system to promptly sense and alarm a fire condition. A National Fire Protection Association compliant system design may influence a reduction of the core damage frequency in the Probabilistic Risk Assessment studies. The licensee initiated a Problem Investigation Process report to evaluate this item. (Section F2.4; [MISC - 2A, 4A])
Report Details Summary of Plant Status Unit 1 began the period in a scheduled refueling outage. The unit went critical on July 6, 1999, for zero power physics testing but tripped from 15 percent power on July 7, 1999, due to a loss of main feedwater. Following repairs, the unit went critical again on July 8, 1999, and increased to 15 percent power where the main generator was placed on line. The generator was taken off line on July 9, 1999, due to main turbine vibration problems. Following repairs, the generator was placed on line again on July 12, 1999, and the unit returned to 100 percent power on July 15, 1999. The unit remained at 100 percent power for the rest of the inspection perio Unit 2 began and ended the period at 100 percent powe Unit 3 began and ended the period at 100 percent powe All three units decreased power on August 13, 1999, due to problems with control area chiller The power was decreased to 86 percent in preparation for a required Improved Technical Specification (ITS) 3.0.3 unit shutdown. One chiller train was returned to service and the units exited the ITS 3.0.3 and returned to 100 percent power on August 14, 199. Operations
Conduct of Operations 0 General Comments (71707)
Using Inspection Procedure (IP) 71707, the inspectors conducted frequent reviews of ongoing plant operations. In general, the conduct of operations was professional and safety-conscious; specific events and noteworthy observations are detailed in the sections belo.2 Unit 1 Loss of Feedwater and Resultinq Reactor Trip Inspection Scope (71707)
On July 7, 1999, at 1:10 a.m., Unit 1 tripped from 15 percent power, due to a loss of feedwater. The inspectors responded to the site and observed post-trip operator activities. The inspectors observed and reviewed the post-trip reviews, corrective actions, and evaluations performed by licensee personne Observations and Findinqs On July 7, 1999, Unit 1 experienced a reactor trip due to a loss of feedwater flow. The 1A main feedwater pump (MFP) had been started due to problems with the 1B MF When the 1 B MFP was isolated for valve repair work, the 1A MFP unexpectedly tripped causing a reactor trip on low MFP discharge pressur When the 1B MFP was isolated, the low suction pressure alarm annunciated for the 1A MFP and not the 1 B MFP. The licensee's review indicated that this was due to the fact that the non-safety related impulse instrument tubing had been reversed between the suction piping and suction pump trip pressure switches for the two MFPs during a plant modification in 1996. Hence, isolation of the 1 B MFP suction caused a loss of suction trip on the 1A MFP. PIP 1-099-2868 was initiated following the trip and the licensee plans to conduct a root cause analysis of the trip. The licensee plans to issue Licensee Event Report (LER) 50-269/99-005, Loss Of Feedwater Reactor Trip Due to Mis-Routed Instrument Line The emergency feedwater (EFW) pumps started as expected on loss of both MFPs and anticipated transient without scram (ATWS) actuation circuitry. Main Steam Relief Valve (MSRV) 1MS-10, stayed open longer than expected. This required the control room operators to operate the steam bypass valves to the condenser to reduce main steam header pressure to 920 pounds per square inch gauge (psig) to allow the valve to resea (The MSRVs normally reseat at about 970 psig.) When the inspectors arrived, 1MS-10 had reseated and maintenance personnel had been notified of the proble Maintenance personnel and the inspectors observed that four of the sixteen MSRVs were still weeping steam after the trip, contrary to previous trip observations. Main steam header pressure was being maintained at approximately 956 psig. Additional licensee staff were called in to investigate the MSRV problems. This is discussed further in Section M1.3 of this report. Except as noted above, inspector review of available trend information and direct observation confirmed normal plant response for the tri Conclusions Unit 1 experienced a plant trip due to a loss of main feedwater pumps. This resulted from an instrumentation tubing installation error that had been introduced during a 1996 modification. Further Nuclear Regulatory Commission (NRC) review of this issue will be conducted during review of the associated LE.3 Overtime Procedures and Controls Inspection Scope (71707)
The inspectors reviewed the overtime reports for the Unit 1 refueling outage and interviewed personnel involved in the tracking and reporting of overtim Observations and Findings The inspectors identified that the records of overtime worked and overtime requested did not match. The inspectors were unable to determine if actual hours worked had been exceeded for safety related work. The inspectors discussed this issue with licensee management. Additional NRC review of this issue will be completed following licensee resolution of the inspectors concerns. This item is identified as Inspector Followup Item (IFI) 50-269/99-05-01: Deficiencies Identified in Overtime Reporting During Unit 1 Refueling Outag Conclusions The inspectors identified deficiencies in overtime reporting during the Unit 1 refueling outage that will be followed as an IF.4 10 CFR 50.72 Notification of Improved Technical Specification (ITS) Required Shutdown (71707)
On August 13, 1999, at 4:59 p.m., the Train B control area chiller was discovered to be shutdown. The licensee entered ITS Limiting Condition for Operation (LCO) 3.7.16 for one chiller out of service. Licensee personnel attempted to start the Train A chiller. The Train A chiller subsequently tripped, causing both chillers to be declared inoperable at 5:28 p.m. This placed all three Oconee units in an ITS LCO 3.0.3 required shutdown condition. The ITS LCO 3.0.3 required the units to be in hot shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and cold.shutdown within 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />. At 6:18 p.m., the NRC was notified pursuant to 10 CFR 50.72 of a shutdown commenced in accordance with ITS. Operations commenced the power decrease at 6:25 p.m. while troubleshooting continued on the chillers. At 10:40 p.m., the Train B chiller was returned to service and the ITS LCO 3.0.3 was exited leaving the units in a 30-day LCO per ITS 3.7.16 for one chiller out of service. At 11:00 p.m., the units commenced increasing power and returned to 100 percent power at
3:34 a.m., on August 14, 1999. Pending additional NRC review of this issue, this is identified as Inspector Followup Item 50-269,270,287/99-05-12: Review of initiation of Unit Shutdown Due to Loss of Control Room Chiller Operational Status of Facilities and Equipment 0 Operations Clearances (71707)
The inspectors reviewed the following clearances during the inspection period:
0-3-9-2352 3B RBS Pump
0-3-9-2354 3B RBS Pump Header Isolation The inspectors observed that the associated clearances were properly prepared and authorized, and that tagged components were in the required positions with the appropriate tags in plac.2 Turbine Building Flood Protection Measures (71707)
The inspectors walked down the doors between the turbine and auxiliary buildings, the condensate coolers, the condenser circulating water (CCW) discharge valves, the condenser water box outlet valves, and the turbine building basement drain. These items were consistent with the Updated Final Safety Analysis Report (UFSAR) and Selected Licensee Commitments (SLC). Equipment operability, material condition, and housekeeping were acceptable in all case.3 Turbine Building Emerqency Hiqh Level Alarm Inspection Scope (71707)
UFSAR Section 3.4.1 and SLC 16.9.11 provided for an emergency high level alarm to detect flooding and protect safety-related equipment in the turbine building basemen The inspectors walked down the switches, reviewed the drawings, and reviewed the test procedure associated with this alar Observations and Findings The description of the turbine building emergency high level alarm in the UFSAR did not match the actual design and installation in four cases. First, the UFSAR described the logic for actuating the alarm as "2 out of 3", meaning that any combination of two switches out of three would actuate the alarm. However, the actual installed logic was "2 out of 4." Secondly, the UFSAR described the range of the alarm as "0 to 7 feet", but the actual alarm switches were floats that operated over approximately six inches at two discreet levels in the turbine building basement. Thirdly, the UFSAR stated that emergency procedures would be entered "upon receipt of a turbine building flood 'alert'
alarm from detectors mounted at elevation 775 feet 6 inches." The inspectors found that the emergency procedures were entered when the alarm sensed 775 feet 6 inches however, this was called the emergency high level. The alert alarm actually occurred 2 feet lower. Finally, the UFSAR stated that there was a statalarm in each control room; however, the inspectors found that a statalarm only existed in the Unit 1/2 control roo The Unit 3 control room relied on a computer alarm. The licensee's UFSAR Upgrade Project had previously identified the question about the range of the switches and had documented it in the corrective actions to PIP 0-098-5940. The licensee subsequently entered the remaining questions into the corrective actions for PIP 0-098-594 This high level alarm modification was installed in 1984 and the UFSAR has been incorrect since installation. The UFSAR description of the alarm was drafted from a preliminary version of the design. The design was changed during implementation, but the licensee failed to ensure the UFSAR was revised accordingl The inspectors determined that the three differences between the UFSAR description and the actual design of the turbine building emergency high level alarm not previously recognized by the licensee constituted a failure to update the UFSAR and was a violation of 10 CFR 50.71(e). This Severity Level IV violation is being treated as a NCV, consistent with Appendix C of the NRC Enforcement Policy and is identified as NCV 50 269/99-05-02: Failure to Properly Update the UFSAR. This violation is in the licensee's corrective action program as PIP 0-098-594 The inspectors reviewed procedure IP/O/B/0235/003, Turbine Basement Water Level Alarm System Check, Revision 4, and SLC 16.9.11, Turbine Building Flood Protection Measures, for testing of the turbine building emergency high level switches. Th inspectors determined that the licensee's testing methodology did not test all combinations of turbine building emergency high level switches which could result in an alarm. The inspectors could not identify any requirement for such testing of these non safety-related switches. However, this shortcoming in the licensee's testing program was identified to the licensee. The licensee satisfactorily tested the remaining combinations of two switches out of four and entered corrective actions into PIP 0-099 3075 to change procedure IP/0/B/0235/003 to test all switch combination Conclusions A non-cited violation was identified for failure to update the UFSAR to include the latest description of the turbine building emergency high level alar While the instrumentation would detect an actual flood, weaknesses existed in the test procedure for the turbine building emergency. high level alar.4 Retraction of 10 CFR 50.72 Notification on Low Pressure Iniection (LPI)
Overpressurization Inoperability (71707)
On June 30, 1999, the licensee informed the NRC pursuant to 10 CFR 50.72 that portions of the low pressure injection (LPI) system could be pressurized above values previously evaluated. This had the potential to cause certain valves in the-system to become inoperable due to their inability to operate against the postulated differential pressure. This issue was discussed in Inspection Report (IR) 50-269,270,287/99-0 On July 28, 1999, the licensee retracted the 10 CFR 50.72 notification following detailed engineering analysis of the subject valves. The engineering analysis concluded that the motor operator for the subject valves had sufficient torque to overcome the postulated differential pressure. The inspectors reviewed associated Oconee Station Calculation OSC-5892 and PIP 0-099-2755. The inspectors identified no issues or discrepancie Operator Training and Qualification 0 Failure to Perform Job Performance Measures Inspection Scope (71707)
The inspectors reviewed training documentation and interviewed individuals regarding a (JPMs) prior to standing licensed dutie b. Observation and Findinqs On July 7, 1999, the licensee identified that two licensed individuals, one senior reactor operator and one reactor operator, had not completed their annual operator trainin Specifically, they had not completed the JPM examination portion of the training. The examination period ended on June 8, 1999. The two operators had performed licensed duties on approximately 16 occasions since the exam cycle ended. Once this discrepancy was realized, both operators were removed from licensed duties, the JPM examination was completed satisfactorily for both operators, and the operators were returned to licensed duties. The procedure used by training to track completion of the examination cycle was revised to ensure all parts of the examination cycle were completed. A note was added stipulating that an operator would be removed from active duty until satisfactory completion of the examinatio CFR 55.53h states that the licensee shall complete a requalification program as described by 10 CFR 55.59. Contrary to the above, two individuals did not complete the requalification program. Specifically, the two individuals did not complete the JPM portion of their operating exam prior to the end of the requalification exam cycle on June 8, 1999. This Severity Level IV violation is being treated as a NCV, consistent with Appendix C of the NRC Enforcement Policy and is identified as NCV 50-269,270,287/99 05-03: Failure to Complete Operator Requalification Program Requirements. This violation is in the licensee's corrective action program as PIP 0-099-290 Conclusions A non-cited violation was identified for two licensed operators who failed to complete the job performance measures portion of their operating exam prior to resuming licensed dutie Miscellaneous Operations Issues (92901, 92700)
0 (Closed) LER 50-269/98-009-00, 01, 02: Low Temperature Overpressure Protection System Technically Inoperable Due to a Design Oversight This issue was initially discussed in Inspection Report (IR) 50-269,270,287/98-09, Section 01.2. Following NRC review of the circumstances and the corrective actions, two violations of NRC requirements have been identifie The first violation involves 10 CFR 50 Appendix B, Criterion Ill, Design Control and Technical Specifications. This criterion requires in part, that measures shall be established to ensure that the design basis is correctly translated into specifications, drawings, procedures, and instructions. Technical Specification (TS) 3.1.2.9, requires in part that two trains of the Low Temperature Overpressure Protection (LTOP) system shall be operable. TS 3.1.2.9.5c states in part, that if the second train of LTOP is inoperable, the second train shall be restored to operable status or compensatory measures shall be provided to monitor for initiation of an LTOP event within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, or within 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> the reactor coolant system (RCS) shall be depressurized and a vent path shall be opened. Inherent to this requirement in the TS bases for the LTOP system is that LTOP must meet single failure criteri From November 7, 1983, to May 14, 1998, the licensee failed to ensure that the LTOP design basis for single failure was translated into procedures and specification Specifically, a single failure vulnerability was identified involving the common 0-600 psig low range pressure transmitter. This transmitter feeds the essential. high pressure alarms in the passive LTOP train, as well as the power operated relief valve (PORV) low setpoint in the active LTOP train. This resulted in the licensee not being in compliance with 10 CFR 50 Appendix B, Criterion 1Il, and thus not in compliance with TS when entry was made into an LTOP condition. A review of records did not identify any instances
where the low range pressure transmitter was inoperable. Accordingly, this Severity Level IV violation is being treated as a NCV, consistent with Appendix C of the NRC Enforcement Policy and is identified as NCV 50-269/99-05-04: Failure to Assure Adequate Design Control for the LTOP System. This violation is in the licensee's corrective action program as PIP 1-097-1967 and 0-098-255 The second violation involves 10 CFR 50 Appendix B, Criterion XVI, Corrective Actio This criterion states in part, that measures shall be established to assure that conditions adverse to quality are promptly correcte Contrary to the above, corrective actions were not timely following the identification of a single failure vulnerability of the LTOP system on June 26, 1997. The corrective actions to mitigate this condition (i.e., declaring the passive train of LTOP inoperable) were not implemented until May 14, 1998. During this eleven-month interval, approximately 60 days were spent with LTOP in service with both trains susceptible to this single failure vulnerability. This Severity Level IV violation is being treated as a NCV, consistent with Appendix C of the NRC Enforcement Policy ahd is identified as NCV 50-269/99-05-05:
Failure to Implement Timely Corrective Actions for LTOP Vulnerability. This violation is in the licensee's corrective action program as PIP 1-097-1967 and 0-098-2552. The subject LER is close.2 (Closed) LER 50-269/98-013-00, 01: Limiting Condition for Operation Exceeded on the Low Pressure Service Water System Due to Inadequate Design Interface This issue was initially discussed in IR 50-269,270,287/98-10, Section 02.6. Following NRC review of the circumstances and the corrective actions, two violations of NRC requirements have been identifie The first violation involves 10 CFR 50, Appendix B, Criterion Ill, Design Control, which requires in part, that measures shall be established to ensure that the design basis is correctly translated into specifications, drawings, procedures, and instruction UFSAR Section 9.2.2, Cooling Water Systems, states that the low pressure service water (LPSW) system is designed so that no single failure will impair emergency safeguards operation. The safety-related LPSW post accident monitoring flow instrumentation is required to provide an indication of low pressure injection (LPI) cooler shell side flow in the control room when throttling is required following a design basis accident. If the flow is not throttled and an LPSW pump is lost, LPSW net positive suction head and LPSW flow to other safety-related loads may be inadequat Contrary to the above, from April 1994 on Unit 1, June 1993 on Unit 2, and December 1993, on Unit 3, the licensee failed to ensure that the LPSW design basis for single failure was translated into procedures and specifications. Specifically, the modification to install the safety-related LPSW flow instrumentation and chart recorder did not identify a single failure vulnerability. Subsequently, during repair activities on October 3, 1998, a single failure vulnerability was identified involving the common chart recorder power supply and instrument indication. Emergency Operating Procedure guidance uses this flow instrument indication to throttle LPSW flow to protect the LPSW pumps from pump runout. For the pumps to be in jeopardy, both controllers and one of the LPSW pumps would have to be inoperable. This would cause the operators to be unable to throttle flow and could result in pump runout of the only available LPSW pump. This concern is somewhat mitigated by the fact that additional instrumentation is available in the form of Moore controllers associated with the control of LPSW-251/252. These controllers are not safety-related due to not being seismically qualified. They are powered from a safety-related power supply and are available for operator use in the control room. The licensee plans to initiate a modification that will remove the chart recorder from the instrument loop and thus remove the single failure vulnerability. This modification is planned to be completed for all three units by October 11, 1999. The licensee has
initiated instrumentation checks and operator training to identify instrumentation failures until such time as the modifications are complete. Accordingly, this Severity Level IV violation is being treated as a NCV, consistent with Appendix C of the NRC Enforcement Policy and is identified as NCV 50-269/99-05-06: Failure to Assure Adequate Design Control for the LPSW Indication. This violation is in the licensee's corrective action program as PIP 0-098-465 The second violation references 10 CFR 50 Appendix B, Criterion XVI, Corrective Actio This criterion states in part, that measures shall be established to assure that conditions adverse to quality are promptly correcte Following the initial identification of a pen failure in the LPSW chart recorder, the extent of condition was not determined. Approximately 3 weeks later during the above mentioned repair activities on the chart recorder, it was recognized by the licensee that the safety-related A train LPSW flow indicator to the LPI cooler was also inoperable in conjunction with the pen failure, due to a failed square root extractor circui Consequently, the delay of approximately 3 weeks in corrective action led to a failure to recognize and enter the required 72-hour TS LCO. This was a violation of 10 CFR 50 Appendix B, Criterion XVI, in that the condition adverse to quality was not promptly identified. This Severity Level IV violation is being treated as a NCV, consistent with Appendix C of the NRC Enforcement Policy and is identified as NCV 50-269/99-05-07:
Failure to Promptly Identify and Correct Failure of the LPSW Instrumentation. This violation is in the licensee's corrective action program as PIP 0-098-465. Maintenance M1 Conduct of Maintenance M General Commerts Inspection Scope (62707, 61726)
The inspectors observed all or portions of the following maintenance activities:
PT/0/A/0711/01 Zero Power Physics Testing (Unit 1), Revision 35
OP/0/A/1102/26 Enclosure 4.1, Pre-job Briefing for Startup, Revision 24
WO 97103477 Implement Installation Procedure for NSM ON-22998
PT/0/A/O811/01 Power Escalation Test, Revision 24
PT/1/A/1103/15 Reactivity Balance Procedure (Unit 1), Revision 50 TN/2/A/2998/0/AL1 Replace Vital Instrument and Control Batteries 2A/B, Revision 1,. for Modification NSM ON-22998
PT/0/A/0620/16 Keowee Hydro Emergency Start Test, Revision 26
IP/0/A/4980/87F ABB/Westinghouse HU and HU-1 Relay Test, Enclosures 4.37, 38, & 39, Keowee Main Transformer Relays 87T X, Y, & Z Differential Phase, Revision 6
TN/5/Al 939/MM/1 E Installation of Modification OE-1 1939, Replace Keowee Main Transformer Differential Phase Relays, Revision 0
TN/1/A/2983/0/AL1 Installation of Electrical Components Associated With the 7kV Power System Upgrade, Revision 0
- WO 98184326-01 Repair/Replace Unit 1 RPS Channel B High Temperature Bistable
IP/0/A/0100/001 Controlling Procedure for Electrical and I&C Troubleshooting and Corrective Maintenance, Revision 17
IP/0/A/0305/001F Channel B RC Temperature Instrumentation Calibration, Revision 35
IP/O/B/0276/002 ATWS Mitigation System AMSAC/DSS Logic Test, Revision 14
.WOs 98151537&38 Inspection of Keowee Units 1 and 2 Turbines/Generators
WO 98170851 Perform Partial Discharge Test of the Six Keowee 13.8kV Underground Cables
WO 98155065 Replace Stress Cone on Cable CT4H2A at Transformer CT4
WO 98180642 Troubleshoot and Repair Unit 1 Pressurizer Level Observations and Findings In general, the inspectors found the work performed under these activities to be professional and thorough. All work observed was performed with the work package
.present and in use. Technicians were experienced and knowledgeable of their assigned tasks. Quality control personnel were present when required by procedure. When applicable, radiation control measures were in plac Conclusions The inspectors concluded that the maintenance and surveillance activities listed above were completed thoroughly and professionall M Keowee Maintenance Outage Inspection Scope (62707)
The inspectors observed and reviewed the Keowee Hydro-Electric Plant (KHP) Units 1 and 2 maintenance and modification outages. The inspectors attended the Plant Operations Review Committee meeting that approved the outage schedule. The outage activities were from August 6, 1999, to August 10, 199 Observations and Findings The outage consisted of inspections of the generators, the turbines, and the penstocks partial discharge testing of the six 13.8 kilovolt underground cables; installation of the out of tolerance voltage/frequency and the seismic modifications; and preventive maintenance on disconnect switches and breakers. The inspectors observed that the outage was well planned; was well coordinated; and had management, supervisory, and technical support. The operators ensured that the applicable ITS and SLC conditions were adhered to at all times. Minor discrepancies were observed by the inspectors and discussed with the license Conclusions The Keowee Hydro-Electric Plant outage was well planned; was well coordinated; and had management, supervisory, and technical support. The applicable technical specifications and selected licensee commitments were adhered to at all time M Unit 1 MSRV Set Point Problems Inspection Scope (62707)
During recovery from a reactor trip on July 7, 1999, the licensee performed setpoint checks on the Unit 1 MSRVs. The inspectors observed these check Observations and Findinqs The MSRVs had been set two days prior to the trip as a part of the return to power from the refueling outage. Maintenance personnel tested the valves in place using a pressure assist device in conjunction with main steam header pressure. The valve maintenance supervisor and the inspectors observed the wor The as-found set points for six of the sixteen MSRVs tested were found to be outside of the acceptance criteria. This was documented and evaluated in PIP 1-099-2898. Of the six, one valve setpoint was found to be high (1MS-3 was 0.8 psig high) and the reminder were low. The IMS-1 0 valve setpoint was found at 1048.4 psig, which is below the minimum setpoint acceptance criterion of 1054 psig. Of the five valves found below their setpoint, this was the lowest. To return the valves within setpoint tolerance, the maintenance crew correctly reset the valve The PIP evaluation indicated that the valves would have performed their safety function The licensee evaluated the existing test data and condition on the MSRVs for the other two units and found them acceptable. The inspectors had observed proper operation of the MSRVs on the other units during unit trips since the last MSRV setpoint checks for each of the units. Additional NRC review of this issue will be performed during review of LER 50-269/99-005, Loss of Feedwater Reactor Trip Due to Mis-Routed Instrument Line Conclusions During a recheck, several Unit 1 main steam relief valves were found out of tolerance within two days of their last adjustment. Further NRC review of this issue will be performed during review of the associated LE M8 Miscellaneous Maintenance Issues (92902, 92700)
M (Closed) LER 50-269/98-017-00: Inadequate Work Planning Results in Missed Surveillance This LER was initially discussed in IR 50-269,270,287/98-11, Section 01.5. The original write-up described the loss of the computer as a normal, planned outage. Review of the LER closeout package and the associated PIP 1-098-5708, disclosed that although the computer outage was planned, the subsequent problems in restoring the computer were not foreseen. Operations was notified at 5:50 p.m. that the computer would not be available for the 6:00 p.m. quadrant power tilt (QPT) surveillance. TS 3.5.2.4.g stated that QPT shall be monitored on a minimum frequency of once every two hours during power operation above 15 percent full power. Operations called out reactor engineering personnel to perform the QPT calculation. The engineer arrived at approximately 6:30 p.m. and completed the calculation at 7:35 p.m. This delay in completing the calculation was due to problems with obtaining data from the computer. As a result of these delays,
the two hour surveillance due at 6:00 p.m. was not completed within the specified surveillance interval as required. The 8:00 p.m. surveillance was completed successfully. The computer was successfully restarted at 9:43 p.m. The corrective actions were to complete the surveillance manually, repair the computer, and enhance the procedur This constituted a failure to complete a surveillance as required by TS 3.5.2.4.g. This Severity Level IV violation is being treated as a NCV, consistent with Appendix C of the NRC Enforcement Policy and is identified as NCV 50-269/99-05-08: Failure to Complete QPT Surveillance in Required Time. This violation is in the licensee's corrective action program as PIP 1-098-5708. This LER is close M (Closed) LER 50-270/98-004-00: Technical Specification Snubber Surveillance Interval Exceeded Due to an Inadequate Process This item was identified on July 16, 1998, by the licensee during reviews as part of their Recovery Plan. They discovered that some TS surveillance tests for some Unit 2 snubbers were incorrectly coded in the scheduling software. As a result, the scheduling was coded as condition-driven rather than date-driven. The review indicated that Unit 2 tests of snubbers required by TS 4.18.3 and 4.18.5 were performed one month beyond the maximum allowed snubber surveillance interval. The root cause was an inadequate process for control of changes to data in the surveillance program, including surveillance frequency. A contributing cause was the use of the wording, at least once every refueling outage, that implied condition-driven rather than date-driven. The licensee restored compliance by completing the surveillance on the Unit 2 snubbers in questio No failures were observed. This Severity Level IV violation is being treated as a NCV, consistent with Appendix C of the NRC Enforcement Policy and is identified as NCV 50-269/99-05-09: Failure to Perform Snubber Surveillance Within the Allowed Interva This violation is in the licensee's corrective action program as PIP 0-098-3595. This LER is close M (Closed) LER 50-269/98-014-00: Hydraulic Snubber Deleted From Surveillance Procedure Due to Inappropriate Action This event occurred when the licensee inappropriately changed a surveillance procedure and caused the inspection of a safety-related snubber to exceed its surveillance interva Upon discovery, the licensee immediately declared the affected snubber and system inoperable and inspected the snubber. The inspection determined that the snubber was acceptable and the licensee declared it operable. Further evaluation determined the root cause to be an improper self check of the procedure changes and a failure to follow directives associated with the procedure revision and review proces The licensee subsequently added the snubber to the affected procedure and counseled the individuals involved. The licensee has also undertaken a review of piping support calculations in order to verify that all snubbers have been listed in procedures. Any future snubber additions or deletions in the procedures will be accompanied by an associated modification package. The licensee has also developed qualified reviewer checklists to ensure independence while reviewing procedure The inspectors reviewed the cause determination and corrective actions, determining that the root cause determination and corrective actions were appropriate. However, the inspectors determined that a violation of 10 CFR 50, Appendix B, Criterion V, occurred because the procedure used to inspect the snubbers did not properly list all snubbers to be inspected. This Severity Level IV violation is being treated as a NCV, consistent with Appendix C of the NRC Enforcement Policy and is identified as NCV 50-269/99-05-10:
Inadequate Procedure Results in Missed Surveillance. This violation is in the licensee's corrective action program as PIP 5-098-4850. This LER is close III. Engineering E3 Engineering Procedures and Documentation (37551)
E Updates to Updated Final Safety Analysis Report and Chanqes. Tests. and Experiments Performed In Accordance With 10 CFR 50.59 (for 1998)
By letter dated June 30, 1999, pursuant to 10 CFR 50.71 (e), Duke Energy Corporation (Duke) submitted the 1998 Update to the Updated Final Safety Analysis Report (UFSAR)
for the Oconee Nuclear Station (ONS), Units 1, 2, and 3. In another letter dated June 30, 1999, pursuant to 10 CFR 50.59(b)(2), Duke submitted an annual report that described the facility changes, tests, and experiments subject to the requirements of 10 CFR 50.59 that were completed between January 1, 1998, and December 31, 1998, at ON The Nuclear Reactor Regulation (NRR) Licensing Project Manager conducted an in house review of the UFSAR submittal. The UFSAR changes that were reviewed were appropriately addressed by the licensee.. In addition, the amendments that were processed during 1998 that indicated UFSAR changes would be needed were adequately addressed in the submittal. Therefore, this submittal satisfies the reporting requirements of 10 CFR 50.71(e).
The NRR Licensing Project Manager also conducted an in-house review of the 10 CFR 50.59 submittal and discussed specific comments with the licensee and the resident inspectors. The responses were found to be acceptable. The submittal satisfies the reporting requirements of 10 CFR 50.59(b)(2).
Both annual reports are a significant improvement over the annual reports submitted in previous year E8 Miscellaneous Engineering Issues (37551, 92903)
E (Closed) LER 50-270/98-007-00: Reactor Trip on Loss of Main Feedwater Pumps Due to a False High Steam Generator Level This event was initially discussed in IR 50-269,270,287/98-10, Section 01.3.. The licensee issued PIP 2-098-5261 to identify the root cause and corrective actions. The identified root cause of the event was inadequate procedural guidance for the work performance proces TS Section 6.4.1 required, in part, that written procedures with appropriate instructions shall be provided for corrective maintenance which could affect nuclear safety. NSD 703, Administrative Instructions for Station Procedures, Revision 18, required, in part, that procedures be written in the degree of detail necessary for performing a required function or action, in adequate detail to ensure accurate results, and sufficient data shall be required by the procedure to ensure that the intent of the procedure is fulfille Contrary to the above, the procedure, MP/0/A/1705/027A, Fire Protection Fire Barrier Penetration Mechanical and Electrical Installation and Repair Using Dow Corning PR 855 Semkit, Revision 7 did not contain adequate instructions to prevent the insertion of a fiberboard retainer into a plant instrumentation cable. Specifically, the procedure lacked the instructions to insert the retainers only by hand. This resulted in an individual using a hammer to inadvertently force a retainer into an instrumentation cable and subsequently causing a unit trip. This Severity Level IV violation is being treated as a NCV, consistent with Appendix C of the Enforcement Policy and is identified as NCV 50-270/99-05-11:
Inadequate Procedure for Fire Barrier Repair Resulted in a Reactor Trip. The licensee established compliance through procedure changes and additional training following repairs to the uni IV. Plant Support Areas RI Radiological Protection and Chemistry Controls R Radiological Protection (71750)
The inspectors periodically toured the radiological control area (RCA) during the inspection period. Radiological control practices were observed and discussed with radiological control personnel, including RCA entry and exit, survey postings, locked high radiation areas, and radiological area material conditions. The inspectors concluded that radiation controls were implemented as required by procedure and procedural requirements were adhered to by plant personne S1 Conduct of Security and Safeguards Activities S General Comments (71750)
During the period, the inspectors toured the protected area and noted that the perimeter fence was intact and not compromised by erosion or disrepair. Isolation zones were maintained on both sides of the barrier and were free of objects which could shield or conceal an individual. The inspectors periodically observed personnel, packages, and vehicles entering the protected area and verified that necessary searches, visitor escorting, and special purpose detectors were used as applicable prior to entry. Lighting of the perimeter and of the protected area was acceptable and met illumination requirement F2 Status of Fire Protection Facilities and Equipment F Penetration Seal Inspection Repair, and Configuration Review Inspection Scope (92904)
During a May 1998, Fire Protection Triennial Audit, fire barrier silicone foam penetration seal deficiencies similar to seal problems discussed in NUREG-1 552 were found. Based on these observations the licensee developed a fire protection penetration seal and fire barrier project to conduct a 100 percent inspection of the plant penetration seals and fire barner The purpose of this inspection was to evaluate the adequacy of the licensee's penetration seal inspection and repair procedures as well as evaluate the effectiveness of the engineering analysis methods used to establish that silicone foam penetration seal designs met their design basis. This review included selected maintenance inspection and repair procedures, 10 CFR 50.59 safety screening evaluations, and engineering evaluations prepared to support changes made to the maintenance procedure used to perform inspection and repairs of fire barrier penetration seal Observations and Findings The inspectors reviewed penetration seal inspection and repair procedure MP/1/A/1705/018, associated 10 CFR 50.59 safety screening evaluations and calculation OSC-7375 and verified that appropriate quality assurance processes were applied to the inspection and repair procedures. The procedures provided for the removal of damming materials to allow Quality Control (QC) inspections of the silicone foam installation following the foam cure process to ensure that repair foam materials were installed per design requirement Revision 31 of procedure MP/1/A/1705/018 was approved to add specific acceptance criteria and reference information for the surface examination of silicone foam cell
structure and allow repairs to fire penetration seals. The new inspection acceptance criteria allowed restricted proportions of lower quality non-optimum foam cell structure as described in Figures 1 and 2 of the Dow Corning Silicone Foam Cell Structure Comparison Chart, Figures 1 to 6. The procedure allowed up to 5 percent of seal area of Figure 1 and up to 25 percent of seal area of Figure 2 to be non-optimum foam cell structures without repair The MP/1/A/1705/018 safety screening evaluation documentation stated that according to Dow Corning Corporation, their Silicone Foam Cell Structure Comparison Chart was intended to provide guidance for determining whether or not cured silicone foam complies with Dow Corning Product Specifications. The chart was not intended to imply that cell structure in the lower quality non-optimum foam cell structure range (Figures 1 and 2) would result in unacceptable performance of the material for a specific end use application (e.g., a fire seal), but rather serves as an indication that the cured material may not be in compliance with product specification data. Therefore, the new acceptance values for lower quality non-optimum foam cell structure would not necessarily mean that the material will not perform as a rated fire seal and were based on successful fire test results discussed in a fire barrier penetration seal fire endurance Fire Test 89-00 The inspectors reviewed fire barrier penetration seal Fire Test 89-006. This review determined that the testing included three small scale penetration seal test specimens that used 100 percent of lower quality non-optimum foam cell structure. These test specimens successfully passed a 180-minute fire endurance and fire hose stream exposure test. The inspector noted that the test was conducted to accepted industry test standards; however, the test specimens were small scale and not clearly representative of Oconee's larger size silicone foam penetration On March 18, 1999, Duke sponsored an experimental prototype full scale fire test of various fire barrier penetration seal configurations more representative of penetration seal sizes installed in the plant. The test was conducted at Omega Point Laboratorie The test was intended for 3-hour duration. The test was terminated at 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, 40 minutes due to failure of several penetration seals with an experimental configuratio The subsequent flame-through corrupted the thermocouple bank such that subsequent data would have been invalid on the remaining penetration seals being teste The licensee described that the test assembly included a test specimen of a representative size of those installed in the plant. This penetration test specimen was constructed of 100 percent lower quality non-optimum foam cell structure as described in Figure 2 of the Cell Structure Comparison Chart. The licensee stated that the preliminary test results indicated that the temperature on the unexposed side of this penetration after 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, 40 minutes furnace exposure was substantially lower than the minimum temperature acceptance criteria for the Oconee facilit The licensee's preliminary evaluation of the test results (the final laboratory test report had not been issued) stated that while this cannot be extrapolated to full qualification as a 3-hour fire barrier, it demonstrates that the temperature on the unexposed side was below ignition temperature of combustible material (cable insulation) adjacent to fire barriers at Oconee. The licensee also concluded that additional margin was inherent because the Oconee penetration seals have a minimum foam depth greater than that of the test assembly. Duke fire protection management stated that they were confident that the fire barrier penetration seals at Oconee would accomplish their intended function to prevent fire propagation across a fire barrier as established by NUREG-1 55 The inspectors determined that the preliminary results of the licensee's silicone foam penetration seal fire endurance testing program has provided new insights into silicone foam penetration seal technology regarding fire endurance performance of penetration seals that use lower quality non-optimum foam cell structure. The final test report and
licensee's conclusions identifying this new information will be reviewed by the NRC fire protection staff and management during a meeting with Duke fire protection management on August 25, 1999. The purpose of the meeting is to present the finalized fire test report and discuss the results and conclusion Conclusions The inspectors concluded that appropriate quality assurance processes were applied to penetration seal inspection and repair procedures to ensure that repair foam materials were installed per design requirements. The safety evaluation documentation for fire protection procedure changes was complete and reached reasonable conclusions concerning whether the changes would compromise plant safety and whether an unreviewed safety question was involve F Review of Design Change and Plant Modification for the Penetration Seal and Fire Barrier Proiect Inspection Scope (92904)
The inspectors reviewed minor modification ONOE-1 3494 to assess the quality and to evaluate how effectively the fire protection program requirements for the fire ratings and locations of NRC committed fire barriers were incorporated into the plant drawings, the design specifications and the Equipment Data Base (EDB) for penetration seal Observations and Findinqs Modification ONOE-1 3494 was being implemented to improve traceability of penetration seal documentation. This was to satisfy the corrective actions identified in PIP-0-098 2620 and PIP-0-096-0347. No fieldwork was performed by the modificatio The documents reviewed by the inspector were the above PIPs; the modification package; fire protection program design specification; penetration seal specifications and calculations; fire barrier boundary; drawings; and related UFSAR entries. Interviews were conducted with engineering personnel concerning the completion status of the penetration seal and fire barrier project. The modification package, as appropriate, included markups to the UFSAR and listed affected drawings and procedures that required revision. The inspector also determined that the penetration seal and fire barrier project was about 80 percent complet Conclusions The inspectors concluded that the penetration seal and fire barrier project modification package accurately incorporated the regulatory commitments for the fire ratings and locations of NRC committed to fire barriers into the plant fire barrier boundary drawings; design specifications; and penetration seal equipment data base. Documentation for the plant modification and related safety evaluations were technically adequate and of good quality with no unreviewed safety questions being identifie F Review of Design Basis of Penetration Seals Inspection Scope (64704)
The inspectors compared "as-built" fire barrier penetration seals to fire endurance test configurations. This comparison was made to verify that the penetration seals which were audited were qualified by appropriate fire endurance tests, representative of the design and construction of the firoe endurance test specimens. An assessment was made of the quality of the licensee's engineering evaluations and their supporting technical justification for the sampled silicone foam, silicone elastomer, insulated steel
pipe, oversize pipe, and instrument tubing steel plate type penetrations to determine whether they were properly resolved by engineering evaluation During plant walkdowns, the inspectors observed the installed configurations of selected accessible fire barrier penetration seals to confirm that the licensee had established an acceptable design basis for those seals installed in fire barriers that separated risk significant plant areas. The review of documentation associated with the inspection and repair work conducted for these penetration seals was included in the inspectio Observations and Findings The inspectors reviewed DPS-1435.0o-99-002, calculation OSC-7350, and qualification type fire endurance tests. The inspector assessed the licensee's engineering evaluations and their supporting technical justification for the sampled silicone foam installed in floors and walls in the Unit 1, Unit 2 and Unit 3 turbine building, auxiliary buildings, control complex, and East-West penetration room The inspectors' review focused on verifying that the design of the "as-built" configurations were adequately bounded by appropriate fire endurance tests and justified by the licensee's engineering evaluation The inspectors verified that the penetration seal inspection and repair work was performed in accordance with approved procedures and field documentation was maintained for important penetration seal design and installation parameters. The fire barrier penetration seals were representative of approved engineering design configurations and were bounded by tested configurations that met the acceptance criteria of the American Society for Testing and Materials (ASTM) E-814, Institute for Electrical and Electronics Engineers (IEEE) Standard 634-1978, and ASTM E-1 1 Additionally, the inspector reviewed the licensee's engineering evaluations for several unique configurations identified during the penetration seal and fire barrier project inspections which did not meet the approved engineering design configurations. The inspector verified that the deviations between the seal configurations and established testing for silicone elastomer, insulated steel pipe, oversize pipe, and instrument tubing steel plate type penetrations were resolved by engineering evaluations in accordance with NRC Generic Letter 86-1 Nine mechanical and electrical penetration configurations installed in fire barriers that separated risk significant plant areas as identified in the licensees Probabilistic Risk Assessment (PRA) of December 1990, and subsequent Individual Plant Examination of External Events (IPEEE) risk assessment submitted to the NRC on December 28, 1995, were visually inspected. For those fire barrier penetration seal designs sampled by the inspector, no deficiencies were identified. The penetration seals were properly labeled and identified in the plant penetration seal engineering database. The inspector did not identify any penetrations with missing, loose, broken, or unsupported damming board materia Conclusions The inspectors determined that the fire barrier penetration seals met designs that were either supported by tested configurations or justified by appropriate engineering evaluations. The penetration seal inspection and repair work was performed in accordance with approved procedures and field documentation was maintained for important penetration seal design parameters. The licensee's engineering analysis methods have established a basis to these "as-built" penetration seal designs would accomplish their intended function to confine a fire and preclude its spread from the compartment of fire origin. Visual inspection of nine penetration seals installed in fire
barriers that separated risk significant plant areas indicated that the seals were in good physical conditio F Review of the Design and Installation of Fire Detection and Alarm Features in the Turbine Building Inspection Scope (64704)
Fire detection and alarm systems are one element of the fire protection program defense in depth (DID) concept at nuclear power plants. During plant tours, the inspector observed and reviewed the installation.and placement of fire detectors in risk significant fire areas to assess their effectiveness to promptly detect fires that might occur in the are Observations and Findings The inspectors reviewed selected portions of the plant fire PRA and subsequent IPEEE risk assessment. These assessments state that fire events contribute to about 5 percent total plant annual core-melt frequency. The dominant fire scenario for the Oconee PRA is the large turbine building fire. The core damage frequency (CDF) resulting from this scenario is 4.5E-06/y During tours of risk significant plant areas, the inspector observed that the placement of the smoke detectors in the turbine building did not provide full fire area coverage, exceeded the recommended detector spacing of National Fire Protection Association (NFPA) 72-1976, and were installed lower than the ceiling on the top of cable trays shielded from floor coverage. Therefore, they may not detect fires in their incipient stage The inspectors' review of the pre-Appendix R and pre-IPEEE NRC Safety Evaluation Reports (SERs) dated August 11, 1978, determined that the current detector arrangement had NRC approved deviations from NFPA 72 standards for fire detector placement and coverage. The NRC review conducted in 1978 considered that, while these conditions reduced the effectiveness of the system to respond to a fire condition rapidly, the fire detection and alarm system in conjunction with the safe shutdown system satisfied the objectives of the NRC's fire protection program guidanc However, because of the open layout of the turbine building, the inspectbr questioned the technical basis that supported the previous NRC approval of these deviations in that the fire detection and alarm system effectiveness may be a factor in the particular dominant fire scenario for the Turbine Building. A NFPA compliant system design may influence a reduction of the CDF in the PRA fire studies. The licensee initiated PIP 0-099-3061 to evaluate this ite Conclusions A fire risk observation was discussed related to the turbine building fire detector placement that reduced the effectiveness of the system to promptly sense and alarm a fire condition. A NFPA compliant system design may influence a reduction of the CDF in the PRA studies. The licensee initiated a PIP to evaluate this ite V. Management Meetings O
X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on August 19, 1999. The licensee acknowledged the findings presented. No proprietary information was identified to the inspector Partial List of Persons Contacted Licensee L. Azzarello, Design Basis Engineering Manager T. Coutu, Superintendent of Operations T. Curtis, Mechanical System/Equipment Engineering Manager G. Davenport, Operations Support Manager B. Dobson, Engineering Work Control Manager J. Forbes, Station Manager W. Foster, Safety Assurance Manager T. Hartis, Recovery Plan Coordinator D. Hubbard, Modifications Manager C. Little, Civil, Electrical & Nuclear Systems Engineering Manager W. McCollum, Site Vice President, Oconee Nuclear Station B. Medlin, Superintendent of Maintenance M. Nazar, Manager of Engineering L. Nicholson, Regulatory Compliance Manager J. Smith, Regulatory Compliance J. Twiggs, Manager, Radiation Protection Other licensee employees contacted during the inspection included technicians, maintenance personnel, and administrative personne NRC
. LaBarge, Senior Project Manager Inspection Procedures Used IP37551 Onsite Engineering IP40500 Effectiveness of Licensee Process to Identify, Resolve, and Prevent Problems IP61726 Surveillance Observations IP62707 Maintenance Observations IP64704 Fire Protection Program IP71707 Plant Operations IP71750 Plant Support Activities IP92904 Followup-Plant Support IP90712 In-Office Review of Written Reports of Nonroutine Events at Power Reactor Facilities IP92700 Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP92901 Followup - Plant Operations IP92902 Followup - Maintenance IP93702 Prompt Onsite Response to Events at Operating Power Reactors Items Opened, Closed, and Discussed Opened 50-269/99-05-01 IFI Deficiencies Identified in Overtime Reporting During Unit 1 Refueling Outage (Section 01.3)
50-269/99-05-02 NCV Failure to Properly Update the UFSAR (Section 02.3)
50-269,270,287/99-05-03 NCV Failure to Complete Operator Requalification Program Requirements (Section 05.1)
50-269/99-05-04 NCV Failure to Assure Adequate Design Control for the LTOP System (Section 08.1)
50-269/99-05-05 NCV Failure to Implement Timely Corrective Actions for LTOP Vulnerability (Section 08. 1)
50-269/99-05-06 NCV Failure to Assure Adequate Design Control for the LPSW Indication (Section 08.2)
50-269/99-05-07 NCV Failure to Promptly Identify and Correct Failure of the LPSW Instrumentation (Section 08.2)
50-269/99-05-08 NCV Failure to Complete QPT Surveillance in Required Time (Section M8.1)
50-270/99-05-09 NCV Failure to Perform Snubber Surveillance Within the Allowed Interval (Section M8.2)
50-269/99-05-10 NCV Inadequate Procedure Results in Missed Surveillance (Section M8.3)
50-270/99-05-11 NCV Inadequate Procedure Resulted in a Reactor Trip (Section E8.1)
50-269,270,287/99-05-12 IFI Review of Initiation of Unit Shutdown Due to Loss of Control Room Chillers (Section 01.4)
Closed 50-269/98-009-00, 01, 02 LER Low Temperature Overpressure Protection System Technically Inoperable Due to a Design Oversight (Section 08.1)
50-269/98-013-00, 01 LER Limiting Condition for Operation Exceeded on the Low Pressure Service Water System Due to Inadequate Design Interface (Section 08.2)
50-269/98-017-00 LER Inadequate Work Planning Results in Missed Surveillance (Section M8.1)
50-270/98-004-00 LER Technical Specification Snubber Exceeded Due to an Inadequate Process (Section M8.2)
50-269/98-014-00 LER Hydraulic Snubber Deleted From Surveillance Procedure Due to Inappropriate Action (Section M8.3)
50-270/98-007-00 LER Reactor Trip on Loss of Main Feedwater Pumps Due to a False High Steam Generator Level (Section E8.1)
Discussed 50-269/99-005 LER Loss of Feedwater Reactor Trip Due to Mis-Routed Instrument Lines (Section 01.2, M1.3)
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List of Acronyms AC Alternating Current ASTM American Society for Testing and Materials ASW Auxiliary Service Water ATWS Anticipated Transient Without Scram CCW Condenser Circulating Water CDF Core Damage Frequency CFR Code of Federal Regulations DC Direct Current DID Defense In Depth EFW Emergency Feedwater ES Engineered Safeguards IEEE Institute for Electrical and Electronics Engineers IFI Inspector Followup Item IP Inspection Procedure IPEEE Individual Plant Examination of External Events IR
Inspection Report
Improved Technical Specifications
KHP
Keowee Hydro-Electric Plant
kV
Kilovolt
LCO
Limiting Condition for Operation
LER
Licensee Event Report
Low Pressure Injection
Low Pressure Service Water
Low Temperature Overpressure Protection
Main Feedwater Pump
Main Steam Relief Valve
Non-Cited Violation
National Fire Prevention Association
Notice of Enforcement Discretion
NRC
Nuclear Regulatory Commission
Nuclear Reactor Regulation
NSD
Nuclear Site Directive
Oconee Station Calculation
Problem Investigation Process
Power Operated Relief Valve
Pounds Per Square Inch Gauge
Quality Control
QPT
Quadrant Power Tilt
Reactor Building Spray
Radiological Control Area
Selected Licensee Commitment
TS
Technical Specifications
Updated Final Safety Analysis Report
Unresolved Item
Work Order