IR 05000269/1991026
| ML16148A570 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 10/25/1991 |
| From: | Belisle G, Binoy Desai, Harmon P, Poertner W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16148A569 | List: |
| References | |
| 50-269-91-26, 50-270-91-26, 50-287-91-26, NUDOCS 9111200024 | |
| Download: ML16148A570 (12) | |
Text
4 8 REO UNITED STATES o
NUCLEAR REGULATORY COMMISSION o
.,
REGION II
101 MARIETTA STREET, ATLANTA, GEORGIA 30323 C1 Report Nos.:
50-269/91-26, 50-270/91-26 and 50-287/91-26 Licensee:
Duke Power Company P. 0. Box 1007 Charlotte, NC 28201-1007 Docket Nos.:
50-269, 50-270, 50-287, 72-4 License Nos.:
DPR-38, DPR-47, DPR-55, SNM-2503 Facility Name:
Oconee Nuclear Station Inspection Conducted: August 26 - September 28, 1991 Inspector: /__
P. E. Harmon, Senior Resident Inspector Date Signed B. B., Desai, Rdsident Inspector Date Signed 9. K. Poertner, /,esident Inspector Date Signed Approved by:
10e2~
G. A. Belisle,--4 n Chief DdeSge Date Signed Division of Reactor Projects SUMMARY Scope:
This routine, resident inspection was conducted in the areas of operations, surveillance testing, maintenance activities, and inspection of open item Results: The licensee's performance during the Unit 1 refueling outage was observed closely by the resident staff and Region II personnel during the inspection perio The outage included several incidents and errors of a significant natur Two separate incidents during the inspection period, an unmonitored heatup of the RCS with the reactor vessel fueled and the head removed,' and an inadvertent overpressurization of a portion of the LPI system, resulted in an Augmented Inspection Team (AIT) being sent to the site. In addition to the two incidents investigated by the AIT, several other incidents 91112000o24 91.1025 PDR ADOCjK, o5000L269
during the period indicate programmatic weaknesses and lack of effective management control for outage-related activitie As a result of concerns for the licensee's performance, a Confirmation of Action Letter was issued by the NRC requiring the licensee to provide increased management oversight of startup activities, to investigate the events and report the findings and corrective actions to the NRC staff, to evaluate.the effects of the overpressurization event, and to meet with the NRC prior to restarting the uni The events investigated by the AIT will be described in NRC Inspection Report No. 50-269/91-28. One aspect of the heatup event, the question of whether an unintended mode change occurred when RCS temperature exceeded 140 degrees, is still under discussion. This item will be tracked as an unresolved item (paragraph 2.c).
Other events during the inspection period are described in this report and include an apparent violation with two examples for failure to follow procedures involving the isolation of component cooling water with energized control rod drive mechanisms and failure to maintain pressurizer water level within required limits, (Paragraphs 2.e and 2.f respectively). Also discussed are: a second instance this outage of loss of all excore nuclear instrumentation (Paragraph 2.g); lack of work coordination during an RCS level increase (Paragraph 2.i); and continuing concerns with the clarity and condition of. the spent fuel pool and transfer canal water (Paragraph 2.k).
An Unresolved Item concerning the operability of the HPI system due to design errors incorporated into LDST operating curves is described in Paragraph REPORT DETAILS 1. Persons Contacted Licensee Employees
- H. Barron, Station Manager D. Couch, Keowee Hydrostation Manager
- T. Curtis, Compliance Manager
- J. Davis, Technical Services Superintendent
- D. Deatherage, Operations Support Manager
- B. Dolan, Design Engineering Manager, Oconee Site Office
- W. Foster, Maintenance Superintendent T. Glenn, Engineering Supervisor
- 0. Kohler, Compliance Engineer C. Little, Instrument and Electrical Manager
- H. Lowery, Chairman, Oconee Safety Review Group
- B. Millsap, Maintenance Engineer M. Patrick, Performance Engineer D. Powell, Station Services Superintendent
- G. Rothenberger, Integrated Scheduling Superintendent
- Sweigart, Operations Superintendent Other licensee employees contacted included technicians, operators, mechanics, security force members, and staff engineer NRC Resident Inspectors/Region Personnel
e Harmon
P c
Poertner
- B. Desai
- A. Herdt
- Attended exit intervie. Plant Operations (71707)
a. General The inspectors reviewed plant operations throughout the reporting period to verify conformance with regulatory requirements, Technical Specifications (TS), and administrative controls. Control room logs, shift turnover records, temporary modification log and equipment removal and restoration records were reviewed routinel Discussions were conducted with plant operations, maintenance, chemistry, health physics, instrument & electrical (I&E), and performance personne Activities within the control rooms were monitored on an almost daily basi Inspections were conducted on day and on night shifts, during weekdays and on weekend Some inspections were made during shift
change in order to evaluate shift turnover performanc Actions observed were conducted as required by the licensee's Administrative Procedure The complement of licensed personnel on each shift inspected met or exceeded the requirements of T Plant tours were taken throughout the reporting period on a routine basis. The areas toured included the following:
Turbine Building Auxiliary Building CCW Intake Structure Independent Spent Fuel Storage Facility Units 1, 2 and 3 Electrical Equipment Rooms Units 1, 2 and 3 Cable Spreading Rooms Units 1, 2 and 3 Penetration Rooms Units 1, 2 and 3 Spent Fuel Pool Rooms Unit 1 Containment Station Yard Zone within the Protected Area Standby Shutdown Facility Keowee Hydro Station During the plant tours, ongoing activities, housekeeping, security, equipment status, and radiation control practices were observe b. Plant Status Unit 1 remained off-line in a scheduled End of Cycle (EOC)
refueling outage for the.entire reporting period. At the end of the reporting period preparations were in progress to commence low power physics testin Unit.2 operated at power for the entire reporting perio Unit 3 operated at power for the entire reporting perio c. Inadvertent Heatup while Shutdown On September 7, 1991, an inadvertent heatup from about 110 degrees to 187 degrees F of the Unit 1 RCS occurre Unit 1 had recently been refueled and the Low Pressure Injection (LPI)
system was in service removing decay hea The heatup occurred when the LPI trains were swapped to accommodate VOTES testing of certain valves in the LPI system. Following the LPI train swap, the Low Pressure Service Water (LPSW) flow through the decay heat cooler was not properly aligned by shift personnel, causing the heat sink to be los The heatup was initially noticed by non-licensed operators (NLOs)
in the reactor 0II building who saw a significant amount of steam coming from the reactor vesse They notified the control -room and the heatup was terminated by aligning the other train of the LPI system to remove decay hea The heatup had gone unnoticed for approximately four hours before it was noticed by the nonlicensed operator An Augmented Inspection Team (AIT)
was dispatched to the site on September 9 to gain a clearer understanding of the event. Details o this event will be documented in NRC Inspection Report No. 50-269/91-2 The inadvertant heatup caused Reactor Coolant System (RCS)
temperature to increase above the limiting temperature for Refueling Shutdown, 140 degree The licensee's position is that since fuel was not being moved and core alterations were not in progress, the plant was not in Refueling Shutdown, but rather in Cold Shutdow Cold Shutdown has a limiting RCS temperature of less than 200 degree The TS do not specifically tie the operating mode of Refueling Shutdown to the condition of having the reactor vessel head detensioned or removed, and the licensee has traditionally applied the requirements of Refueling Shutdown to periods of actual core manipulations. When not moving fuel or core internals, the operating conditions automatically revert to Cold Shutdow The inspectors believe this. interpretation to be in erro After discussing the concerns with the inspectors and reviewing standardized TS, the licensee agreed to publish an interpretation consistent with the standard TS version of when Refueling Shutdown is in effect, and to initiate TS changes as necessary. The adequacy of the present form of Oconee TS is under review by the NRC and will be discussed with the licensee at a meeting on October 9 at NRC headquarter The question of whether a mode change occurred in this instance described above will be tracked as Unresolved Item (URI)
269,270,287/91-26-03, Unintended Mode Change d. Inadvertent Overpressurization of LPI System On September 20, 1991, an inadvertent overpressurization of the Unit 1 LPI system occurred during startup activitie The overpressuri zation occurred as a result of the LPI system not being placed in the switchover mode prior to exceeding 125 psig RCS pressur Upon completion of a test of the 1B High Pressure Injection (HPI)
pump, enroute to starting the reactor coolant pumps, the.RCS was pressurized by energizing the pressurizer heater The licensed operators on Unit 1 failed to refer to the controlling procedure for Unit startup which required the LPI system to be aligned in the switchover mode prior to exceeding 125 psig RCS pressur An abnormal increase in the high activity waste tank level and a decreasing pressurizer level were noted by the control room operator and a leak in the LPI or HPI system was suspected. The LPI suction
relief valve was found to have lifted and approximately 12,000 gallons of coolant leaked out of the RCS during the course of the even A controlled depressurization was initiated using the auxiliary spray and the leak was stoppe The AIT (see paragraph 2.c) was reactivated to investigate the event, especially in view of the September 7 event and the failure of the corrective actions taken as a result of the September 7 heatup even Details of both events will be documented in NRC Inspection Report No. 50-269/91-28. A Confirmation of Action Letter (CAL) documenting the actions the licensee was required to take as a result of the two events on Unit 1 was issued on September 20, 1991. The CAL required the licensee to take the following actions:
1. Immediately provide 24-hour operational oversight using management personnel on-shift until the NRC agrees this coverage is no longer necessar. Investigate the facts and circumstances associated with the September 20, 1991, overpressurization event and report the results of this investigation and corrective actions taken for this and the September 7, 1991, loss of shutdown event to the NRC staf. Perform and complete an engineering evaluation of the overpressurization of the low pressure injection piping to determine the effect this had on the low pressure piping
.system. Do not restart the unit (i.e. achieve criticality) prior to meeting with the NRC to discuss these issue The circumstances associated with the events were discussed with the NRC during a meeting held in the Region II office on September 2 The engineering evaluation performed on the LPI piping did not indicate any adverse effect on the LPI piping. Permission to achieve criticality was granted on September 2 The 24-hour management oversight was still in effect as of the end of this report perio e. Securing Component Cooling Water with Control Rods Energized On September 10, 1991, after completion of Control Rod Drive (CRD)
coupling of the Group 8 CRDs on Unit 1, the operating Component Cooling (CC)
pump was secured to allow work on the component cooling pump breaker The work on the pump breakers was scheduled to begin on day shift September 1 When the pump was secured the Group 8 rods were still energize Approximately eight minutes after securing the operating CC pump, a computer alarm was received indicating high temperature on control rod L12. The stator showed a
III5 temperature of approximately 153 degrees and increasin The CC system was restarted and kept in service until temperatures returned to normal at which time the CRD breakers were opened to deenergize the CRD system and the CC system was secure Review of this event determined that the operator performing the.evolution did not utilize a procedure to secure the CC system the first time the system was secured. Operating Procedure OP/1/A/1104/08, Enclosure 3.4, Shutdown of Component Cooling System, specifically requires that all CRDs be deenergized prior to securing the CC system. The failure to meet the procedural requirements of OP/1/A/1104/08 prior to securing the component cooling system is identified as example 1 of Violation 50-269/91-26-01, Failure To Follow Procedure f. Pressurizer Overfill On September 16, 1991, pressurizer level increased from a level of 380 inches to the off-scale value of 400 inches (the location of the top level tap), while the steam generator inlet handhole was ope The handhole elevation is several inches above the 400 inch elevation and there was no actual spill out of the opening. Operators did not have clear guidance to control pressurizer level at a specific value, but the procedure in effect, OP/1/A/1103/02, Filling and Venting the RCS, cautioned against raising level above 390 inche At the time of the event, operators were in the process of filling the lB core flood tan When the off-going shift turned over to the oncoming shift at 7 p.m.,
level was remarked as being high at 396.7 inches, but it was thought that a slight decrease in RCS temperature would bringthe level back down. The oncoming crew reduced RCS temperature from 109 degrees to 103 degrees, but the level continued to increase to 399 inches, which is effectively off-scale hig At approximately 10 p.m.,
the Control Room Operator (CRO)
brought the high level condition to the attention of the Unit Supervisor, and an NLO was dispatched to check the lineup for the core flood tank fil The core flood tank fill was stopped at 10:27 p.m. with pressurizer level at 400 inche Loop drains were opened to reduce the level to 370 inche The handholes were checked to verify that RCS level had not been increased above the level of the handholes which would have resulted'in water being spilled out the openin Effective measures were not implemented to reduce the level and to keep it on-scale on the single operable level instrument until after the level had risen above the top ta Procedural requirements to maintain level below 400 inches insure the level stays on-scale, and below the handhole leve Level was allowed to increase over two operating shifts to greater than 400 inche This is example 2-of Violation 50-269/91-26-01, Failure To Follow Procedure g. Loss of Source Range Nuclear Instruments On September 17, 1991, at approximately 3:20 a.m. both source range Nuclear Instruments (NIs) were deenergized on Unit 1 when a tagout to work on the 1CB-4 control rod drive breaker shunt trip was performe Unit 1 was in cold shutdown conditions during the event. The tagout deenergized all four Reactor Protection System (RPS) channels. The nuclear instruments are powered from the RPS system and when the RPS channels were deenergized the source range nuclear instruments failed lo The control room operator noticed that the NI channels had failed low and the nonlicensed operators performing the tagout were contacte The tags were removed and the RPS channels were reenergize The source range instruments were deenergized for approximately 20 minute The inspectors expressed considerable concern with respect to the control of work activities that could affect essential indications while the unit is in an outage, especially since the source range nuclear instruments had been deenergized earlier in the outage due to failure on the part of maintenance personnel to follow procedures. This previous event is documented in NRC Inspection Report Nos. 269,270,287/91-18 and resulted in a violation for failure to follow procedure resulting in the loss of both NIs.. The tagout had been reviewed by the operations staff and the control room operators prior to hanging the tag Based on the previous event, the inspectors believe that this review of the tagout should have identified that the source range nuclear instruments would be deenergized. Review of the TS determined that source range nuclear instrumentation is not specifically required when the unit is in a cold shutdown conditio The inspectors had discussed this issue with the licensee during the previous inspection period and had been told that source range nuclear instruments were not required by the technical specifications, but a source range channel would always be operable when a unit is in cold shutdow The inspectors believe that the operability requirements with respect to nuclear instrumentation for all plant conditions should be incorporated into the Technical Specifications. A meeting was held on October 9, 1991, between.the NRC and the licensee to discuss the adequacy of the licensee's Technical Specification h. Keowee Hydro Unit 2 Failure to Star On September 6, 1991, at approximately 8:54 p.m. the Unit 2 control room was notified by the Keowee hydro operator that Keowee Unit 2 had not automatically started when the hydro operator tried to bring the unit on line per the request of the load dispatche An operability test was performed on Keowee Unit 1 by control room personnel within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> as required by the Technical Specifications. An investigation by the licensee determined that the problem was cause by a malfunctioning relay coi.l that prevented the generator field breaker
from staying closed in, and that this condition would have prevented the hydro unit from starting on an emergency start signal. The relay was replaced and Keowee hydro Unit 2 was tested and declared operable at approximately 1:00 a.m. on September 7, 199 i. Potential Spill in the Unit 1 Incore Tan On September 12, 1991, during preparations to drain the reactor coolant system (RCS) to reduced inventory conditions, the pressurizer level indications did not agree within five inches of the level indicated on LT-5, the RCS draindown level instrument, as required by the controlling draindown procedur LT-5 was indicating approximately 80 inches and pressurizer level indicated approximately 70 inche The operators decided to raise level to 100 inches on LT-5 to see if pressurizer level would track the level increas During the fill evolution, a maintenance supervisor entered the control room and requested that operations stop making up to the RCS because he had personnel in the incore tank and the RCS boundary was ope The operators secured the fill evolution at 94 inches as indicated on LT-No water was spilled into the incore tank, however, if level had been increased to 100 inches the potential would have existed for water to have been spilled in the incore tan The inspectors were in the control room during the event and determined that none of the operators on shift knew that the RCS pressure boundary was opened in the incore tank. The inspectors also determined that the operations staff were not aware that the RCS pressure boundary was opened in the incore tan Operations was aware that personnel were in the incore tank, but they thought that all work had been completed on the incores and that the pressure boundary was intac A shift incident report was written by operations to document the potential spill and to investigate the circumstances. The inspectors expressed concern that operations had lost configuration control of maintenance activities ongoing in the incore tank that had opened the RCS pressure boundar The inspectors will review the licensee's actions related to the shift incident repor j. Letdown Storage Tank (LDST) Pressure/Level Curve On September 19, 1991, the licensee determined that the operating curve for maximum pressure/level in the LDST was nonconservativ The purpose of the curve is to ensure that hydrogen from the LOST is not released into the suction of the high pressure injection pumps when the pumps are aligned to the Borated Water Storage Tank (BWST)
during the injection mode of. operation since the LDST does not isolate on an injection signa The LDST and BWST are parallel sources of water to the HPI pumps during the injection mode of operatio The source with the higher pressure will initially provide suction to the HPI pumps until the two sources equalize pressure then they provide a parallel suction sourc The licensee determined that, assuming all three HPI pumps operating, the previous
operating curve would not have prevented hydrogen intrusion into the suction of the HPI pumps under all BWST level conditions prior to switchover to the recirculation phase of operatio The licensee also determined that the new LDST pressure/level curve was nonconservative if a single failure of one of the BWST suction valves was assumed. The single failure would result in all three HPI pumps being aligned through one suction flowpath to the BWST and would result in a lower dynamic suction pressure at the HPI pump suction The licensee's immediate corrective actions were to replace the existing LDST pressure/level curve with the newly generated curve and to revise the emergency operating procedures to require that the HPI system be placed in the piggy-back mode of operation if one of the
.BWST suction valves to the HPI pumps failed to open on an injection signa The HPI piggy-back mode of operation aligns the discharge of the.low pressure injection pumps to the suction of the HPI pumps. In this mode of operation the pressure at the HPI pump suctions is greater than the maximum pressure allowed in the LDST and hydrogen intrusion could not occu The decision to use the new curve and place the HPI system in the piggy-back mode of operation if a BWST suction valve did not open was based on operational consideration Hydrogen intrusion would not occur until BWST level dropped to less than 25 feet, assuming a single failure of a BWST suction valve, and sufficient time was available to align the HPI system in the piggy-back mode of operation prior to reaching this level in the BWST. The inspectors reviewed the licensee's short term corrective actions and held discussions with licensee personnel concerning the adequacy of the licensee's revie At the end of this inspection period, the licensee could not document the basis of the original LDST pressure/level curve and was still reviewing possible corrective action Pending further review by the licensee and the NRC this item is identified as Unresolved Item 269,270,287/91-26-02, LDST Pressure/Level Curve k. Spent Fuel Pool and Transfer Canal Water Clarit During the refueling outage on Unit 1 the inspectors observed water clarity problems in the Spent Fuel Pool (SFP)
and Transfer Canal an witnessed portions of the activities associated with handling fuel in the Spent Fuel Pool and the Transfer Cana During the fuel handling activities observed, the clarity of the water required the operators to use underwater cameras in the vessel to determine core location The inspectors could not see the top of the fuel assemblies in the core when looking into the reactor vessel from the fuel handling bridge and could just barely see the fuel assemblies in the SFP. The inspectors have discussed this issue with the licensee for the past three refueling outages and have been told that water clarity is not a requirement for handling fuel and that as long as core locations can be determined by underwater cameras all requirements for fuel handling are me During the fuel handling activities on Unit 1 th purification system was not aligned during most of the fuel handling activities due to maintenance activities to support the outage
schedule and fuel handling activities had to be suspended for a period of time because the operators on the fuel handling bridge could not determine core locations even with underwater camera While the inspectors agree that no specific requirements for water clarity exist, the inspectors are still concerned about the continued poor water quality during refueling outage Within the areas inspected, no violation with two examples of failure to follow procedures were identifie. Surveillance Testing (61726)
Surveillance tests were reviewed by the inspectors to verify procedural and performance adequacy. The completed tests reviewed were examined for necessary test prerequisites, instructions, acceptance criteria, technical content, authorization to begin work, data collection, independent verification where required, handling of deficiencies noted, and review of completed work. The tests witnessed, in whole or in part, were.inspected to determine that approved procedures were available, test equipment was calibrated, prerequisites were met, tests were conducted according to procedure, test results were acceptable and system restoration was complete Surveillances reviewed and witnessedin whole or in part:
IP/2/A/400/13 125 VDC I&C Battery Bank 2 Daily Surveillanc PT/1/A/0610/01J Emergency Power Switching Logic Functional Tes PT/O/A/610/06 100KV Power Supply from Lee Statio PT/1/A/230/18 PORV Operability Tes PT/1/A/230/18 HPSW to HPI Motor Cooler Flow Tes Within the areas reviewed, licensee activities were satisfactor No violations or deviations were identifie. Maintenance Activities (62703)
Maintenance activities were observed and/or reviewed during the reporting period to verify that work was performed by qualified personnel and that approved procedures in use adequately described work that was not within the skill of the trade. Activities, procedures, and work requests were examined to verify; proper authorization to begin work, provisions for fire, cleanliness, and exposure control, proper return of equipment to service, and that limiting conditions for operation were me Maintenance reviewed and witnessed in whole or in part:
WR 53045 Determine Valve Position Upon Loss of IA for 1CCW 2 WR 57845 Perform Test on GE Relay WR 91013809 Replace 1TC-2 Voltmete WR 53954 Replace 1LP-18 Springpac Within the areas reviewed, licensee activities were satisfactor No violations or deviations were identifie. Inspection of Open Items (92700)(92701)(92702)
The following open item was reviewed using licensee reports, inspection, record review, and discussions with licensee personnel, as appropriate:
(Closed) LER 287/91-06, Equipment Failure While Performing Testing Results in Control Rod Group Drop and Subsequent Automatic Reactor Tri This event was reviewed in NRC Inspection Report Nos. 50-269,270,287/91-1 Based on this review and review of the Licensee Event Report this item is close. Exit Interview (30703)
The inspection scope and findings were summarized on October 2, 1991, with those persons indicated in paragraph 1 abov The inspectors described the areas inspected and discussed in detail the inspection finding The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspectio Item Number Description/Reference Paragraph 269/91-26-01 Violation - Failure to follow procedure, two examples, paragraphs 2.e and,270,287/91-26-02 Unresolved Item - LDST pressure/level curves, paragraph,270,287/91-26-03 Unresolved Item - Unintended Mode change, Paragraph II