IR 05000341/1998006
| ML20248J554 | |
| Person / Time | |
|---|---|
| Site: | Fermi  |
| Issue date: | 06/03/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20248J549 | List: |
| References | |
| 50-341-98-06, 50-341-98-6, NUDOCS 9806090188 | |
| Download: ML20248J554 (25) | |
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l U.S. NUCLEAR REGULATORY COMMISSION REGION lil Docket No:
50-341 License No:
NPF-43 Report No:
50-341/98006(DRP)
Licensee:
Detroit Edison Company i
Facility:
Enrico Fermi, Unit 2 I
Location:
6400 N. Dixie Highway Newport, MI 48166 Dates:
March 17 - April 27,1998 Inspectors:
G. Harris, Senior Resident inspector C. O'Keefe, Resident inspector Approved by:
Bruce L. Burgess, Chief Reactor Projects Branch 6
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i 9906090198 990603 PDR ADOCK 05000341 G
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EXECUTIVE SUMMARY Enrico Fermi, Unit 2 NRC Inspection Report 50-341/g8006(DRP)
This inspection included aspects of licensee operations, maintenance, engineering, and plant.
support. The report covers a six-week period of resident inspection.
Operations Operators maintained a professional atmosphere in the control room.~ Operators were
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observed to be generally focused, and peer checking was frequently performed.' A new
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policy was implemented to conduct heightened level of awareness briefings for the three
- most significant evolutions each shift, and to conduct a critique of one of them. Despite j
generally good operator performance, one isolated operator error occurred which resulted l
' in the tripping of both fuel pool cooling pumps. (Section 01.1)
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Operators aggressively identified equipment concems and assisted in the prompt -
resolution of problems. Operators responded in an appropriate and conservative manner to each problem encountered. (Section 01.2)
Maintenance The inspectors observed that maintenance work was parformed within the bounds of the
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work instructions. Work instructions and documentation were generally complete and accurate. Technicians were knowledgeable of their assigned tasks. Pre-job walkdowns were performed sufficiently in advance of the work, and were generally effective in enabling the licensee to identify and avoid potential problems. One concem was identified by the inspectors involving inadequate fall protection at a job site. In addition, a concem was identified with inconsistent valve stroke time testing. (Section M1.1)
Based on material condition assessment, the inspectors concluded that equipment is
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being properly maintained. The licensee was effective in identifying and documenting equipment problems. Maintenance resources were appropriately focused on systems specified as important within the maintenance rule. The average age of work requests and the number of control room deficiencies were slightly high, but the work that had not yet been completed was not adversely impacting plant operations. (Section M1.2)
i Local indications on four of the six average power range monitor (APRM) channels were
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adjusted improperly during a calibration by a trainee due to inadequate oversight. The i
error was identified by a nuclear engineer not directly involved with the calibration.' The inspectors identified procedural weaknesses, including lack of a requirement to verify that power level was adjusted correctly and inconsistencies in verification methods between the reactor engineering APRM calibration procedure and a similar APRM calibration -
. procedure performed by maintenance personnel. (Section M1.3)
The inspectors concluded that the independent Safety Engineering Group (ISEG)
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- assessment of switcnyard programs was both broad and detailed. The assessment report described numerous deficiencies, incomplete corrective actions from switchyard events of the past year, and numerous recommendations for areas to improve. The
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report, and ISEG involvement in site activities overall, represented an improvement in ISEG effectiveness. (Section M7.1)
Enoineerina During safety system outages and surveillance testing, inspectors observed that system
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engineers were frequently monitoring work performance and progress. System engineer involvement was less prevalent for non-safety systems. (Section M1.1)
The inspectors concluded that the licensee did not permanently correct a deficiency in~a
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dedicated shutdown procedure that could have caused the inadvertent draining of the condensate storage tank. This could have potentially impacted the ability to bring the reactor to a cold shutdown condition during a postulated fire as defined in 10 CFR 50, Appendix R. Further evaluation was needed to determine if additional discrepancies exist within the dedicated shutdown procedure and the licensee's corrective actions.
(Section E1.1)
System engineering personnel provided close support during troubleshooting and
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investigations of several significant equipment problems. The 24-hour coverage helped minimize the time spent in limiting condition for operations action statements and provided for timely resolution of the problems. When needed, Generic Letter 91-18 l
evaluations were appropriately performed. (Section E2.1)
The inspectors concluded that the two pnmary programs utilized by the licensee to track
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system performance, namely the System Health Repor' and the Maintenance Rule Programs, did not securately reflect system performance for the hydrogen injection system. Licensee management attention was closely focused on system reliability and efforts to improve the system, but the licensee did not question the good" system performance reported by these tracking systems. In response to the inspectors'
identifying this disparity, the licensee was reclassifying the system in both programs.
(Section E2.2)
The inspectors concluded that the licensee's effectiveness followup assessment of the
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safety evaluation process was adequate and detailed. Continued attention was needed to address previously identified deficiencies, but the inspectors noted improvements in safety evaluation quality. Recent improvement efforts appeared to be effective in this area. (Section E7.1)
Plant Support No significant plant support issues are discussed in this report.
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Report Details Summary of Plant Status Unit 2 was at 96 percent power for the majority of the inspection period except for a planned reduction to 57 percent power on April 18-19,1998, for turbine valve testing and control rod pattern adjustment. The plant operated most of this inspection period with one reactor recirculation pump scoop tube locked due to a controller anomaly and concem for a potential uncontrolled reactivity excursion.
1. Operations
Conduct of Operations 01.1 General Comments (71707)
Using inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. Operators maintained a professional atmosphere and effectively limited the quantity of work brought to the control room. Operators were generally focused, and peer checking was frequently performed. A recent operations department policy was implemented to conduct heightened level of awareness briefings for the three most significant evolutions each shift, and to conduct a critique of one of them. Despite generally good operator performance, one notable operator error occurred on April 3, when the wrong motor operated valva (MOV) was shut. Instead of checking fully shut a let down valve from the fuel pool cooling system, the combined pump suction valve was shut. This tripped both fuel pool cooling pumps for a short time, but did not result in a noticeable change in fuel pool temperature. The inspectors considered this an isolated personnel error. Specific events and noteworthy observations are detailed in the sections below.
O1.2 Operators Aaoressivelv Questioned Ecuipment Operability a.
Inspection Scope (71707)
The inspectors observed how the plant staff responded to several emergent problems affecting equipment covered by Technical Specifications (TS),
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Observations and Findinos Operations personnel were observed to aggressively pursue equipment operability issues during this inspection period. In one instance, the Division 2 Primary Containment Oxygen Monitor exhibited spiking. Following sensor replacement, minor spiking was again observed, so operators requested an Engineenng Functional Analysis (EFA).
When spiking was subsequently observed outside the limits set by the EFA, operators immediately declared the channelinoperable and additionalinvestigations were pe formed. Operations personnel remained closely involved in all troubleshooting and planning during this work.
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Similar1y, operations personnel conservatively stopped work during the high pressure coolant injection (HPCI) system outage on April 21, when plant support engineering staff notified operators about an issue which potentially affected the operability of the low pressure coolant injection (LPCI) loop select logic. Since this could result in entry into a significantly shorter limiting condition for operation (LCO) action statement (multiple emergency core cooling systems (ECCS) inoperable), the Nuclear Shift Supervisor directed that HPCI work be stopped, equipment placed in a working condition, and a review of possible required testing be conducted, based on the limited work performed.
The LPCI question was resolved within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, and HPCI work was resumed.
Operators promptly identified an anomaly affecting the speed controller for the
"B" Reactor Recirculation Pump. The pump was observed to slow five percent, with a corresponding reactor power reduction Operators promptly locked the scoop tube and deenergized the scoop tube positioner in order to avoid an uncontro!!ed power increase if the controller should retum to its original setting. System engineering and maintenance personnel prepared a temporary modification to permit several weeks of non-intrusive controller monitoring. This required the assignment of a licensed operator forlocal manual speed controlif needed. A planned power reduction was conservatively delayed two weeks in order to avoid having to control power through local control while monitoring was completed. Operator training was conducted in the simulator for various transients to assure adequate response with one scoop tube locked. With the assistance of the vendor, the licensee evaluated the potential impact of unbalanced recirculation loop flows which could ocer from an automatic reactor recirculation pump runback, and concluded that the condition was acceptably bounded by TS.
Following replacement of the main lube oil temperature control valve in the general service water system, operators alertly identified that the new valve was further open than the old valve that was replaced. The licensee verified the design and concluded that the valve positions should have been similar for the same heat load. The licensee determined that lube oil cooler plugging was the cause for the different valve positions and promptly corrected the condition.
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Conclusions Operators aggressively identified equipment concems and assisted in the prompt resolution of problems. Operators responded in an appropriate and conservative manner to each problem encountered.
O2 Operational Status of Facilities and Equipment O2.1 Enaineered Safety Feature (ESF) System Walkdowns (71707)
The inspectors used Inspection Procedure 71707 to walk down accessible portions of the following ESF safety feature systems:
i Division 1 and 2 Emergency Equipment Cooling Water System
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Primary Containment Monitoring System
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Standby Liquid Control System
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Average Power Range Monitoring (APRM) System
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High Pressure Coolant injection (HPCI) System
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Control Center Heating, Ventilation and Air Conditioning System (CCHVAC)
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Divisions 1 and 2 Switchgear
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Divisions 1 and 2 Standby Gas Treatment
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Reactor Building Heating Ventilation Air Conditioning
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Emergency Diesel Generator (EDG) No.11
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Divisione 1 and 2 Core Spray System
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Non-Interruptible Air Supply System
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Equipment operability, material condition, and housekeeping were acceptable in all cases. Several minor discrepancies were brought to the licensee's attention and were corrected. As discussed in Section M1.3, the inspectors identified a lack of permanent labeling inside the APRM and Rod Block Monitor (RBM) cabinets. The inspector's concem with this issue was somewhat mitigated by the licensee's practice of using procedules with diagrams to assist in component recognition, but the lack of permanent labels contributed to a personnel error, as discussed in Section M1.3. The inspectors identified small packing leaks in three heating steam supply valves in the CCHVAC system. The standby liquid control system was in adequate working condition, but a significant portion of the system piping was observed to have damaged lagging. The material condition of plant equipment is further discussed in Section M1.2.
Miscellaneous Operations issues (92700)
08.1 (Closed) Violation 50-341/97014-03: This violation concemed the licensee's failure to conduct verification checks every eight hours when an EDG was declared inoperable per TS. Licensee corrective action included the conduct of small group sessions with all operators to emphasize the importance of TS compliance. In addition, computer software was introduced to provide an alarm for reminding operators of situational surveillance with short time durations. The inspectors determined that the licensee's corrective actions were adequate. This item is considered closed.
08.2 (Closed) Licensee Event Report 50-341/97011-00: This LER discussed the licensee's failure to recognize that LCO 3.3.1 required the Turbine Stop Valve and Turbine Control Valve Fast Closure scram functions to be operable prior to entry into Operational Condition 1. The appiicable requirements were misinterpreted since initial plant operation. Reactor power remained below 30 percent power during this event; therefore, the accident analysis assumptions were met. The licensee's corrective actions included clarifying the procedure, updating the surveillance and tracking data base, and inclusion of the event in operator requalification training. The inspectors determined the corrective actions were acceptable. This item is closed.
08.3 (Closed) Licensee Event Report 50-341/96014: Operators failed to recognize and implement the required LCO actions for deenergizing Bus 72ED until after the allowable outage time had expired. One of the ultimate heat sink reservoir cross-tie valves failed to open on demand. The motor-operator failed in a way such that the motor-operator and valve position indication changed state as expected, but the valve did not stroke. All four cross-tie valves were inspected and modified to preclude additional failures. Operator training was conducted on the event. The inspectors verified that procedure changes were implemented to require a verification when cross-tying reservoirs such that a level change must be observed. Corrective actions appeared adequate, and were verified by
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the inspectors to be complete. The safety significance of this event was low because the plant was in cold shutdown. This item is closed.
08.4 (Closed) Licensee Event Repor150-341/94006: Fuel handling with less than the required number of operable source range monitors (SRMs) and interrnediate range monitors (IRMs). One SRM (of four) and three IRMs (of eight) had their cables damaged during work under the reactor vessel. The damage was not recognized because the core was offloaded at the time. The first four fuel bundles were loaded in the core adjacent to SRM "B" to establish the required minimum count rate, but no increase was noted in indicated count rate. Fuel was then loaded adjacent to SRM "C," and a count rate of four counts /second was indicated with one new bundle and one irradiated adjacent bundle.
Fuel loading was stopped to investigate why SRM "B" had not responded in a similar manner to SRM "C." The required surveillance were verified current for SRM "B." An inspection of the system identified that the detector cable under the reactor vessel was l
damaged. The safety significance of one SRM being inoperable in this particular instance was low because criticality with only the first seven fuel bundles loaded in the core was not possible. All control rods adjacent to fuel remained fully inserted during this event.
Fuel loading resumed after SRM "B" was repaired. The damaged IRM cable problems were then identified after about one-third of the core had been loaded. During this time, three control rods were individually withdrawn and reinserted one notch each for testing.
All SRMs remained operable for criticality monitoring. Technical Specification 3.3.1 required that a minimum of three IRMs per channel be operable while in Operational Mode 5 (refueling), or else core alterations must be suspended within one hour and all insertable control rods shall be inserted. Contrary to TS 3.3.1, core alterations took place with less than three operable IRMs in a channel, and insertable control rods were withdrawn, which was a violation. The safety significance of having less than the i
minimum required operable IRMs during core alterations was low Decause indications of inadvertent criticality would be available on the SRMs, with the other five IRMs providing backup indication if power approached the intermediate range. Therefore, this non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy.
(NCV 50-341/98006-01)
The licensee took actions to improve cable routing under the reactor vessel to attempt to avoid damage. Training was routinely conducted for personnel performing under vessel work to ensure location awareness of important equipment. The inspectors verified that a procedural requirement was added to check SRM and IRM connector integrity prior to j
core alterations. This item is closed.
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11 Maintenance M1 Conduct of Maintenance M1,1 General Comments On the Conduct of Work a.
Inspection Scope (62707)
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The inspectors observed all or portions of the following work activities:
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Division 2 Control Air Compressor Auto Start Test
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Division 2 Primary Containment Monitoring System (PCMS) Calibration
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HPCI Shaft Component Torque Checks
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Division 2 PCMS Pump Wear Checks and Solenoid Operated Valve Replacement
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Division 2 CCHVAC Pressure Controller Troubleshooting
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HPCI MOV Motor Pinion Inspections
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~ APRM Calibrations
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ECCS (LPCI Mode) Division 2 Logic Functional Test
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Division 2 LPCI and Suppression Pool Cooling / Spray Pump and Valve Operability
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Test HPCI Vacuum Breaker Check Valve Test
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Diesel Generator Service Water Fuel Oil Tank and Starting Air Operability
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Test-EDG No.11 Nuclear Steam Supply Shutoff System - HPCI Turbine Exhaust Diaphragm
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- Pressure Division 1 Channel C Calibration Functional Test Nuclear Steam Supply System - HPCI Turt>ine Exhaust Diaphragm Pressure
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Division 2 Channel 13 Calibration Functional Test EDG No.13 Start and Load Test
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Logic System Functional Test of Division 2 EDG ECCS Emergency Start Circuits E
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and Auto Trip / Bypass Circuit Division 2 Residual Heat Removal (RHR) Cooling Tower Fan Operability
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Radweste Effluent Radiation Monitor Function Test Channel Function Test of Division 14160 Volt Bus 65F and 14ED Undervoltage l
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Circuits Turt>ine Steam Valve Test
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CCHVAC - Chlorine Detector Division 1 Channel Calibration Functional Test
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Division 1 Standby Gas Treatment System Filter and Secondary Containment
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l Damper Operability Test Drywell Cooling Fans 1 and 2 Operability Test l-
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Operability of 480V Swing Bust 72CF Automatic Throwover Scheme
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Findinos and Observations The inspectors observed that maintenance work was performed within the bounds of the work instructions. Work instructions and documentation were generally complete and accurate. Technicians were knowledgeable of their assigned tasks. Pre-job walkdowns were performed sufficiently in advance of the work, and were general y effective in enabling the licensee to identify and avoid potential problems. During safety system n
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outages and surveillance testing, the inspectors observed that system engineers were
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frequently monitoring work performance and progress.
The inspectors observed the performance of Surveillance 24.204.06, "LPCI and Suppression Pool Cooling / Spray Pump and Valve Operability Test." The test included stroke time testing for the Division 2 RHR heat exchanger and inlet / outlet valves. The inspectors noted that the inlet valve stroke was timed in both directions while the outlet valve stroke was timed only in the open direction. The licensee was unable to explain why the valves were tested differently, so the inspectors will continue to evaluate whether stroke time testing in the close direction was required to ensure valve operability. This issue will be tracked as an Unresolved item (URI). (URI 50-341/98006-02)
On April 16, instrumentation and control (l&C) personnel were conducting an RBM calibration when a half scram occurred unexpectedly. An electricaljumper used to simulate reactor power touched a power supply component in the RBM chassis. This caused the affected APRM indication to increase, actuating one channel of the reactor protection system. The test leads had retractable conductors, so a minimum part of the conductor was exposed. In response to this event, the licensee decided to tape over the exposed portion of jumper conductors when not in use as an extra precaution. No damage to either the RBM or APRM occurred duing this event. The inspectors concluded that reasonable precautions had been taken, and that this was an isolated problem. The event had no safety significance.
During work on E4150-F008, the inspectors were concemed with the industrial safety practices. The valve was located in the overhead above a stairwell leading down to the HPCI room. However, workers were using a scaffold which was still tagged as "in approval," and which did not have a platform around all the areas required for work.
Workers were observed to climb on the empty scaffold frame without a hamess. Work was stopped until the discrepancies were corrected when the inspectors raised this concem.
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Conclusions The inspectors observed that maintenance work was performed within the bounds of the work instructions. Work instructions and documentation were generally complete and accurate. Technicians were knowledgeable of their assigned tasks. Pre-job walkdowns l
were performed sufficiently in advance of the work, and were generally effective in
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enabling the licensee to identify and avoid potential problems. One concem was l
identified by the inspectors involving inadequate fall protection at a job site. In addition, a l
concem was identified with inconsistent valve stroke time testing.
M1.2 Review of Material Condition and Maintenance Effectiveness
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Inspection Scope (62707)
The inspectors conducte(' a material condition assessment by conducting extensive system walkdowns to identify deficiencies. The inspectors reviewed the quantity, age and cumulative impact to plant operations of outstanding work.
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Findinas and Observations The inspectors conducted extensive inspections of equipment material condition, paying
. particular attention to the systems included within the scope of the maintenance rule.'
The inspectors noted that most equipment deficiencies were already documented in the work control system. The inspectors identified only minor deficiencies that had not been o
previously identified by the licensee.
The inspectors reviewed the outstanding work for several systems, and concluded that the work did not adversely impact system functionality, and was not excessively old. The inspectors noted that most areas were clean and welllit. High standards of house keeping were evident throughout the plant.
The number of control room equipment deficiencies that affected routine operations needed some attention. The licensee used a separate three level prioritization scheme to categorize and resolve the outstanding deficiencies. Although the licensee continued to place emphasis in this area, the inspectors noted that the numbers of control room l:
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instrument indicators with deficiencies consistently exceeded station management l
expectations. The inspectors concluded that the ability to operate the plant safely was not adversely impacted, but the timeliness of repair activities for important control room (t equipment and indicators was of concem.
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The backlog of non-outage corrective maintenance work requests remained low and
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continued to slowly decline. As a measure of the overall material condition, this was consistent with field observations made by the inspectors. The number of outstanding work requests appeared to be at reasonable levels. The inspectors noted that the licensee appeared to be placing the majority of its maintenance resources on critical plant safety and maintenance rule systems. The inspectors noted that a portion of the -
non-outage corrective maintenance backlog was greater than one year old (approximately 10 percent). Station management has placed additional attention on resolving old work l
requests.
l Some scheduling and coordination problems have contributed to schedule non-adherence. For example, painting in the reactor building caused nine work activities to be postponed, including standby gas treatment system runs and reactor building ventilation system work, due to concems about possible charcoal filter damage from the paint fumes. This was a case where unscheduled work caused scheduled work to be postponed, c.
Conclusions A material condition assessment performed by the inspectors, with the assistance of regional specialists, concluded that equipmerit is being properly maintained. The
' licensee was effective in identifying and documenting equipment problems. Maintenance resources were appropriately focused on systems specified as important within the maintenance rule. The average age of work requests and the number of control room
' deficiencies were slightly high, but the work that had not been completed was not adversely impacting plant operations.
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M1.3 - Incorrect Avermoe Power Ranoe Monitor Adiustment a.
Inspection Scopes (61726. 61705)
The inspectors conducted an independent followup on a personnel error during a power level (gain) adjustment on APRMs. The individuals involved and a reactor engineering supervisor were interviewed. Calibration procedures used by l&C and reactor engineering groups were reviewed and compared. Technical Specification surveillance requirements were also reviewed.
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Findinas and Observations i
l On April 18, reactor engineering personnel adjusted APRM gains in order to make the
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APRM output match the reactor heat balance calculation results. This type of adjustment j
was required several times during the weekend because control rod position changes
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affected local flux distributions, and thus changed indicated power. A station nuclear engineer (SNE) trainee adjusted four channels of APRM under the supervision of a qualified SNE. When another SNE noted that expected changes in the computer indication of APRM outputs did not occur, the second SNE went to the relay room where
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the APRM cabinets were located to question the personnel making the adjustments, and identified that the trainee was adjusting the wrong potentiometer. The error was documented in Condition Assessment Resolution Document (CARD) No. 98-13288.
The licensee determined that the adjusted potentiometer, located just above the correct potentiometer, changed only the meter reading inside the cabinet. Operators verified that control room and computer indication of APRM output did not change as a result of the
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incorrect adjustment. The local meter was then recalibrates before making the necessary APRM adjustments.
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The inspectors observed subsequent APRM gain adjustments, and noted that the APRM i
cabinets contained many handwritten labels and very few permanent ones. Instead, procedures for operating the equipment contained cabinet diagrams to help locate the components to be adjusted. The inspectors also noted that the procedure in use, 54.000.06, APRM Calibration," required no verification that the correct adjustment was made. An acceptance criteria check would have identified the correct adjustment only if l
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optional steps to check the control room and computer indications were performed.
Thus, an error could potentially go undetected until the next weekly check. The inspectors determined that APRM gain adjustments were normally performed by the duty i
SNE without any assistance, improving the chance that any potential error could go unnoticed.
The inspectors reviewed the work control system manpower requirements for both the weekly APRM calibration procedure performed by SNEs and the semiannual APRM calibration performed by l&C personnel. The l&C procedure assigned two technicians
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and included independent verifications that data were acceptable, while the reactor engineering procedure required an SNE, and included no data verification.
The inspectors were concemed that the weekly APRM calibration required by TS 4.3.1.1-1.2, Note (d), which directly adjusted the power signal used by the reactor protection system, was not verified by a second individual. Additionally, the procedure
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I contained steps that determined whether the correct power level signal, used by operators for controlling power level, was within tolerance. The inspectors noted that these steps were optional and were not performed until all channel adjustments were completed. In this case, four channels were improperly adjusted before the error was identified. The inspectors verified that the surveillance requirement was satisfied by the existing procedure, even without the optional steps, but the lack of verification of all indications was considered a poor practice.
In response to the inspectors' concems, the licensee agreed to remove the note stating the check of control room and computer indication of APRM power was optional, effectively making them mandatory. Additionally, a step was to be added to verify control room indication before unbypassing the APRM channel under adjustment. The licensee was in the procese of reviewing other reactor engineering procedures to ensure adequate verifications were procedura!ized.
The licensee's event investigation was prompt and adequate, but did not question the methodology of the procedure. The inspectors determined that the specific event was of no safety significance because the error was identified immediately and because the error affected only local indication. However, making changes to indicated power was not treated in accordance with the significance that the adjustment had with respect to reactor safety.
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Conclusions Localindications on four of the six APRM channels were adjusted improperly during a calibration by a trainee due to inadequate supervision. The error was identified by a nuclear engineer not directly involved with the calibration. The inspectors identified procedural weaknesses, which were addressed by the licensee, including lack of a requirement to verify that the power level was adjusted correctly and inconsistencies in verification methods between the reactor engineering APRM calibration procedure and a similar APRM calibration procedure performed by maintenance personnel.
M7 Quality Assurance in Maintenance Activities M7.1 Independent Safety Enaineerina Group (ISEG) Assessment of Switchyard Condition and Corrective Actions a.
Inspection Scope (40500)
The inspectors reviewed a self-assessment performed by ISEG. The assessment covered switchyard design, procedures, drawings, equipment performance and material conaition, preventive and corrective maintenance, spare parts, programs, and a limited sample of corrective actions from recent events. The results of the self-assessment, documented in ISEG Report No.98-007, were discussed with participating ISEG members in addition, the inspectors observed ISEG daily activities and discussed the changes being implemented.
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Eindinos and Observations The ISEG assessment was broad in scope, and appeared to envelope all the switchyard
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failures which led to a reverse power trip of the main generator (1/97), a plant trip on load rejection (2/98), unplanned power reducticns due to high temperature electrical connections (8/97 and 10/97), breaker trips due to operation of the wrong switch (3/97),
and an unintentional isolation of a breaker air supply (12/97). From a limited sample of completed corrective actions, the ISEG team identified that five of the major corrective actions were not completed, despite being reported as complete.
- The inspectors noted that ISEG Report No.98-007 reflected a significant improvement l
over past ISEG practices in that numerous recommendations were made for the issues identified. Previously, ISEG was hesitant to forward recommendations in order to avoid compromising the independent role of the ISEG. The inspectors concluded that the recommendations in ISEG Report No.98-007 were sufficiently broad to avoid the loss of l
independence.
The inspectors' discussed the ISEG findings with ISEG members and determined that the findings were detailed and numerous. The report concluded that many of the corrective actions were not complete as reported, and that additional actions were needed to improve the material condition, documentation of issues, and administrative controls associated with plant switchyards. The report highlighted a persistent low sensitivity to switchyard-related equipment problems despite recent history, citing two problems which required prompting to document on a CARD.
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The inspectors observed routine ISEG interactions with the site staff, and noted that j
ISEG improved their involvement and visibility in daily activities. An ISEG member was I
observed to have attended most moming operations tumover briefs. Additionally, ISEG
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was assigned to supply a member to each event response team to assist in event assessment. Thus, the overall effectiveness and timely involvement of ISEG was considered imprcved.
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Conclusions The inspectors concluded that the ISEG assessment of switchyard programs was both broad and detailed. The assessment report detailed numerous deficiencies, incomplete corrective actions from switchyard events of the past year, and numerous.
recommendations for areas to improve..The report, and ISEG involvement in site activities overall, represented an improvement in ISEG effectiveness.
M8 Miscellaneous Maintenance issues (92902)
M8.1. (Closed) Violation 50-341/97003-07: The inspectors identified three issues concoming inadequate procedures. The first issue involved a work request that contained inadequate instructions for post-maintenance testing of an MOV associated with the reactor core isolation cooling (RCIC) system to ensure valve operability. The licensee reviewed work documents for other valves of similar designs to determined whether they were property tested following maintenance, in addition, maintenance procedures for MOV maintenance and testing were verified to contain adequate controls. Training was 13-
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conducted for electrical and mechanical planners, electrical maintenance personnel, and component engineers conceming the need for enhanced functional testing of
I motor-operated valves following any work inside the MOV limit switch compartment.
The second issue involved preventive maintuence instructions that did not contain l
l adequate procedural steps to ensure proper realignment of an EDG air compressor following oil replacement. The work instructions for obtaining oil samples from EDG starting air compressors were revised to include instructions to remove the compressor from service while taking the oil sample and to notify the control room prior to deenergizing the compressor. Several hundred jobs were reviewed by operations, l
maintenance, chemistry and radiation protection personnel, and system engineering to ensure clear instructions and equipment status controls. Several additionaljobs were
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determined to need further clarification.
The third issue involved a maintenance procedure that did not contain adequate instructions to ensure that newly installed batteries received proper pre-installation checks to ensure that new cells would perform their intended function. The problem battery cells were replaced with fully charged cells. The appropriate maintenance procedure was identified and revised to specify the proper pre-installation checks.
The inspectors reviewed the licensee's corrective action and determined it to be adequate. This item is considered closed.
M8.2 (Closed) Violation 50-341/97005-02: Work on a safety-related spare motor control center fused disconnect switch was performed without an approved work instruction.
Specifically, electricians cleaned and lubricated defective parts and put them back in a spare switch outside the scope of their work package. Corrective actions included reinforcement of work pau age expectations, preparation of a maintenance department instruction, training on corrective actions, and revision of work instructions to require a quality control hold point whenever a quality control inspection report identified an unsatisfactory step in a work document. In addition, a stand down meeting was held to review human performance issues. The inspectors considered the licensee's corrective action to be adequate. This item is considered closed.
M8.3 (Closed) Licensee Event Report 50-341/95002-00: Valve E51-F062 closed due to personnel error. During the performance of a surveillance test in accordance with Surveillance Procedure, " Nuclear Steam Supply Shutoff System-RCIC Steam Line
Pressure, Division 1 Functional Test," the RCIC Turbine Exhaust Line Vacuum Outboard I
isolation Valve, E51 F062, closed when Relay E51K63 was inadvertently energized. The cause of the event was personnel error by the I&C repairman. A contributing factor was the location of the terminal block being used in the surveillance to monitor relay contact performance. The terminal block was installed in a manner that made it difficult to observe. Since 260 vdc may have been applied across the relay, which was designed for 130 vde, the relay was replaced and the surveillance reperformed. In addition, a lessons teamed meeting was held to discuss the event and root cause. The valve was reopened and plant conditions remained stable throughout the event. The licensee's corrective actions appeared adequate. This item is considered closed.
M8.4 (Closed) Violation 50-341/96007-02: FalNre to properly restore all EDG No.11 ventilation dampers following maintenance. The licensee concluded that the root cause of the
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problem was a lack of configuration control, in that no structured process existed to ensure all dampers were retumed to service. The blocked damper was unblocked and retumed to service. The inspectors noted that the licensee had developed a maintenance procedure for blocking and unblocking RHR Complex Dampers. This item is considered closed.
M8.5 IClosed) Violation 50-341/96007-06: Poor documentation of maintenance activities related to Equipment Drain Sump D073 pump outlet valve. During a review by NRC inspectors, several questionable entries, including changes in step sequences without initialing and dating changed steps, were identified. The missing initials and t.iates were the result of an oversight by a maintenance supervisor. The event was determined not to be representative of a wide spread deficiency. Corrective actions included reinforcing management expectations through shop meetings and group discussions, enhancing the method to keep maintenance personnel informed of new procedural requirements and changes to existing requirements, conducting a self-assessment to review maintenance procedure adherence, and performing training sessions on the issue. The inspectors
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determined the licensee's corrective actions to be effective. This item is considered closed.
M8.6 (Closed) Violation 50-341/95012-02(a): Unanalyzed test load connected in parallel with safety-related battery, rendering the battery inoperable. This violation was caused by an inadequate maintenance procedure. The procedure had sufficient detail in a previous
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revision, but some of the detail had been removed and the procedure was not validated when revised. Workers failed to obtain supervisory guidance to resolve which of two possible test methods should be used, and rendered the battery inoperable and damaged l
the test equipment as a result. A management meeting was held among the licensee l
ar,d Region lli to discuss the significance of this event on December 19,1995. This event was the subject of site wide meetings with the plant manager, and small group
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case study sessions among all groups involved with the work control process. Battery charger maintenance procedures were revised to improve the level of detail and clarify the test method. As discussert in Section M8.7, the procedure review was too narrowly
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focused and resulted in a subsequent violation. This item is considered closed.
M8.7 (Closed) Violation 50-341/96010-03: Inadequate corrective actions to prevent inadvertently rendering 130/260V Battery inoperable during maintenance.
l Violation 50-341/95012-02(a) had been issued earlier because a 130/260V safety-related
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battery charger due to inadequate work instructions. Subsequently, maintenance personnel inadvertently deanergized half of the Division 1 130/260V DC system while attempting to restore the system following battery capacity testing. The system was deenergized becausa the work instructions contained insufficient detail to ensure the test battery was properiy installed to supply the bus while the installed battery was tested, and a line fuse was inadvertently not installed. When the DC bus was deenergized, several valves lost power and shut, which was reported as an ESF actuation in LER 50-341/96016. The safety significance was minor because the plant was shutdown, and no required function was affected. Corrective actions for the earlier violation were inadequate because they were focussed on preventive maintenance, and did not extend to surveillance testing. The inspectors verified that battery surveillance procedures were I
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revised to incorporate lessons leamed from the two events, and the level of detail appeared to be adequate. This item is considered closed.
M8.8 (Closed) Licensee Evont Report 50-341/96016-00 and Revision 01: Unplanned ESF actuation due to loss of power to DC bus. As discussed above, the safety significance of this event was minor due to the existing plant conditions. Corrective actions were verified to be complete and appropriate. This item is considered closed.
M8.9 - (Closed) Violation 50-341/95012-02(b): Inadequate corrective actions for safety battery rack corrosion. As documented in inspection Report 50-341/95012, the licensee corrected the corrosion and painted the racks to avoid further problems. Battery cleanliness was stressed to operators, the system engineer, and electrical maintenance personnel. The weekly battery inspection procedure was enhanced. The inspectors observed the condition of the batteries during routine inspections, and noted improved battery cleanliness. The battery racks were in good condition, free of corrosion and paint defects. This item is considered closed.
111. Enaineerina E1 Conduct of Engineering E1.1 Potential for inadvertent Drainina of CST Due to Hot Shorts a.
Inspection Scope (37551)
The inspectors conducted a followup inspection on Licensee Event Report (LER)
Nos. 50-341/96019 and 50-341/98003, regarding the potential for draining the condensate storage tank (CST) due to hot shorts caused by a plant fire. The inspectors reviewed TS, the Updated Final Safety Analysis Report (UFSAR), station license, training manual technical documentation, and Abnormal Operating Procedure No. 20.000.16,
" Control of the Plant From the Dedicated Shutdown Panel." The inspectors also interviewed system engineering personnel. Corrective actions for each LER were evaluated.
b.
Observations and Findinas The licensee identified that a combination of multiple hot shorts caused by a fire could potentially open a drain path to the hotwell and cause a loss of the CST inventory. The CST water was required for use by the auxiliary feedwater system to bring the reactor to a cold shutdown condition in a 10 CFR 50, Appendix R, scenario. This was the subject of Deviation Event Report No. 96-1662 and LER No. 50-341/96019. A temporary change notice (TCN) was written to revise Abnormal Operating Procedure No. 20.000.18, to isolate the CST. The TCN was subsequently incorporated in a regular prosedure revision, but different valves were used to isolate the CST. The licensee F srformed a corrective actions effectiveness review and discovered that the new valve jineup would isolate the CST from the hotwell, but not the condensate retum tank and did not prevent.
all potential CST drain paths.
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The TCN action was changed to use more accessible valves. However, the proposed change was not reviewed for the potential for hot shorts before being incorpomted in the procedure. The identified deficiency was appropriately reported as required by the Station Operating License as documented in LER No. 50 341/98003.
Further NRC evaluation is needed to determine whether the licensee has addressed all potential drain paths and whether other discrepancies exist in the licensee's fire hazard analysis. The issue will be tracked as an Unresolved item. (URI 50-341/98006-03)
c.
Conclusion The inspectors concluded that the licensee did not permanently correct a deficiency in the stations dedicated shutdown procedure that could have mused the inadvertent draining of the CST. This could have potentially impacted the ability to bring the reactor to a cold shutdown condition during a postulated fire as defined in 10 CFR 50, Appendix R.
Further evaluation was needed to determine if additional discrepancies exist within the l-dedicated shutdown procedure and the licensee's corrective actions.
l E1.2 Non-Safety Related Traversina incore Probe FIP) Shear Valve Power Supolv a.
Inspection Scope (37551)
The inspectors reviewed the UFSAR, TS, CARD No. 98-10616. "TIP Shear Valve Power l
Supply Not Safety-Related," design basis documentation, neutron monitoring instrumentadon, safety evaluation (SE) report, Regulatory Guide 1.11, " Instrument Lines Penetrating Primary Reactor Containment,". General Electric NEDC [ Nuclear Energy Division Class C Document] 22253, " Boiling Water Reactor Owner's Group Evaluation of i
Containment isolation Concems (October 1982)," the engineering functional analysis l
(EFA), and interviewed system engineering personnel.
b.
Observations and Findinas As a result of followup to an industry issue, the licensee identified that the TIP shear valve power supply was non-safety related. The shear valve was a containment isolation valve that provided backup to the TIP ball valve because the ball valve might not be closeable if the TIP could not be retracted. The shear valve was included to provide the capability to shear the TIP and isolate the line.
The inspectors noted that the licensse's operability determination used NEDC 22253,
" Boiling Water Reactor Owner's Group Evaluation of Containment isolation Concems," as a basis for operability. That report classified the TIP system tubing as instrument lines, subject to the acceptance criteria of Regulatory Guide 1.11," Instrument Lines Penetrating Primary Reactor Containment." That report also justified the use of a non-safety related power supply for the TIP shear valves, because the 130 volt DC power supply from a balance of plant battery, was considered very reliable.
l The inspectors reviewed the issue and determined that there was not a safety concem.
However, the inspectors identified that the plant design did not exactly match the design l
assumed in the NEDC 22253 repolt. For instance, the NEDC report assumed that the TIP system was designed to General Design Criterion 56, but the inspectors identified
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that the UFSAR stated the TIP system was designed to General Design Oriterion 54. In addition, the inspectors noted that the licensee took credit for design features in the operability determination that were not present in the current TIP system design. For example, the TIP purge isolation feature was referenced in the operability determination, but the inspectors determined that feature was blanked off.
The inspectors were concemed that the discrepancies were not recognized or accounted for in the licensee's EFA, so the inspectors could not evaluate whether the discrepancies irnpacted the conclusion reached by the liceasee, that the shear valve was operable.
This will be tracked as an inspector followup item pending additional justification in the licensee's EFA. (IFl 50-341/98006-04)
c.
Conclusions The inspectors reviewed the licensee's EFA to justify operability of the TIP shear valve with a non-safety related power supply and identified some discrepancies. It remains unclear whether the discrepancies would impact the TIP system operability.
E2 Engineering Support of Facilities and Equipment E2.1 Enaineerina Support Durina Emeraent Eauipment Problems a.
Inspection Scope (37751)
The inspectors observed how plant staff responded to several emergent problems affecting equipment covered by TS b.
Observations and Findinas During this inspection period, engineering personnel were observed to work closely with operations and maintenance personnel to resolve several important equipment probicms.
Teams were formed to provide around-the-clock coverage to address each issue.
FollowinD completion of the work scheduled for the HPCI system outage on April 22, the auxiliary oil pump unexpectedly cycled off, on several occasions, at the conclusion of a system run. System engineers worked closely with maintenance and operations personnel to cotouet troubleshooting. Tr.e anomaly was compared to two similar past problems. The problem identified was promptly addressed, although the licensee considered the system degraded but operable per Generic Letter 91-18 and continued to perform monitoring since the problem could not be replicated.
Spiking was observed on the Division 2 primary containment oxygen monitor. The system engineer coordinated troubleshooting efforts, vendor investigation, and a survey of industry experience to locate the source of the spiking. The inspectors concluded that an adequate EFA was written to declare the instrument operable, but degraded, provided the limited spiking did not significantly change. When a single ltrge spike subsequently occurred, the system was declared inoperable and an additional investigation was conducted. The problem appeared to have been corrected when a freshly refurbished sensor was installed. An emergency TS change was granted on April 3, to allow a longer out-of service time for the instrument, consistent with the permanent TS change request
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l which had been previously submitted. The overall response to this issue was thorough ano coordinated.
Engineering and maintenance personnel worked closely while evaluating a reactor recirculation pump speed controller anomaly. The inspectors reviewed the temporary modification installed to address this anomaly and concluded that it achieved its intent of providing non-intrusive circuit monitoring while continuing to provide required control room indications.
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Conclusions System engineering personnel provided close support during troubleshooting and
investigations of several significant equipment problems. The 24-hour coverage helped l
minimize the time spent in LCO action statements and provided for timely resolution of l
the problems. When needed, Generic Letter 91-18 evaluations were appropriately performed.
E2.2 Poor Hydroaen inlection System Performance Not Documented a.
Inspection Scopes (37751. 92903. 71750)
The inspectors noted that the hydrogen injection system, used to implement hydrogen water chemistry, had tripped repeatedly during the 10 months that the system had been in operation. The inspectors reviewed system performance documentation, maintenance history, and vendor manuals. System health reports and maintenance rule documentation were reviewed and discussed with the system engineer and senior I
licensee management. The effects of a system trip were discussed with the chemistry personnel.
b.
Findinas and Observations The hydrogen injection system was placed in service in July 1997. The syste n tripped nine times starting with initial testing. Causes for the trips included two failed fuses, excessive pressure instrument drift, moisture intrusion, offgas oxygen instrument spiking, and low power level. In the latter case, the system tripped as designed when reactor power was lowered to 31 percent, but the system operating procedure erroneously indicated that the system was to be removed from service near 20 percent power.
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The inspectors noted thet the most recent system health report (fourth quarter of 1997)
stated that the system was in good health, with no outstanding issues. In fact, the system had never had a single deficiency recorded against it in system health reports.
This did not appear to be an accurate representation. The system was in operation only
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24 percent of the time since July 1997. The system was rated " good"in every category in every report, but the inspectors noted that the system appeared to meet the following descriptions from the system health report form:
Maintenance Rule Performance
Satisfactory: System performance criteria has been met, but shows unacceptable trend.
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Chemistry Performance Indicator
Satisfactory: An adverse trend in chemistry monitoring parameters that does not hinder performance or require immediate action.
Component Monitoring
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Poor:
Cumulative or repetitive component failures or an adverse trend that hinders system performance affecting system operation where reliability and availability is affected requiring immediate action.
Chemistry personnel stated that each time the hydrogen injection system tripped, a significant reactor water chemistry transient occurred which changed conductivity and sulfate content and released radioactive isotopes from the oxide layer of piping back into the coolant. Thus, each trip led to an adverse trend in chemistry monitoring parameters.
The inspectors noted that the system was within the maintenance rule scope, but the system had a plwt level performance criterion of <2 scrams. Thus, the maintenance rule program was noused to monitor system performance.
Following the most mcent system trip, system engineers led a detailed system review by a multi-disciphned team which included a review of system design, configuration, i
preventive maintenance, spare parts, procedures, SEs, historical performance, and treatment under the maintenance rule. B,ased on the review of system problems, the licensee concluded that failures were not repetitive, but were caused by a variety of j
problems. Plant management told the inspectors that the system would not be restarted l
until adequate steps had been taken to ensure system reliability, i
As a result of the inspectors' questions and the licensee's review in progress, system
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engineers revised the system health status from " good" (the highest rating) to " poor" (the lowest rating). The licensee also reclassified the system as (c)(1) within the maintenance rule, indicating the need for increased maintenance attention.
c.
Conclusions
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The inspectors concluded that the two primary programs utilized by the licensee to track system performance, namely tne System Health Report and the Maintenance Rule Piograms, did not accurately reflect system performance for the hydrogen injection I
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system. Licensee management attention was closely focused on system reliability and efforts to improve the system, but the licensee did not question the " good" system
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performance reported by these tracking systems. In response to the inspectors'
identifying this disparity, the licensee has reclassified the system in both programs.
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E7 Quality Assurance in Engineering Activities E7.1. Enaineerina Self-Assessment Epfety Review and Evaluation Proaram Followuo Surveillance a.
InsDeClion ScoDe (40500)
The inspectors reviewed licensee Nuclear Quality Assurance (NQA) Surveillance Report No. 98-0103, " Safety Review and Evaluation Program Followup Surveillance." The inspectors inte: viewed system engineering personnel to discuss findings in the report.
The inspectors independently reviewed SEs to assess the accuracy of NQA conclusions, b.
Observations and Findinas The licensee conducted an effectiveness followup on selected findings from Audit No. 97-0103, " Safety Review and Evaluation Program." The previous audit had assessed the SE and preliminary evaluation (PE) process as effective.
The NQA assessment concluded that although the process had improved, the number and type of problems identified during the surveillance indicated the need for additional attention in this area. The report recommended increased attention to detail, reestablishment of an independent oversight function, and continuing with implementation of self-assessments in the PE and SE process.
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All PE screenings evaluated as part of the audit reached the conclusion that an SE was needed. The inspectors reviewed a sample 'of these pes and SEs and determined that they were correctly evaluated. The inspectors reviewed two recent safety evaluations and noted improvement in detail and thoroughness. In addition, the inspectors noted that the number of licensee personnel qualified to perform and approve SEs was reduced to ensure thu those personnel performing the evaluations remained proficient. Additional training was provided to personnel to improve the quality of evaluations and ensure adequate knowledge of the licensing basis of the plant.
c.
Conclusions The inspectors concluded that the licensee's effectiveness followup assessment of the SE process was adequate and detailed. Continued attention was needed to address
_ previously identified deficiencies, but the inspectors noted improvements in SE quality.
Recent improvement efforts appeared to be effective in this area.
IV. Plant Support l
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R8 Miscellaneous Radiation Protection and Chemistry issues R8,1 ' (Closed) Unresolved item 50-341/97003-14: Untimely restoration of unfettered access.
On-shift operations personnel found a visiting inspector's key card outside the control room door. Security and the Nuclear Shift Supervisor were immediately notified. In accordance with procedures the inspector's key card was made inactive and was b
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i reactivated after security verified that there had been no improper use of the security badge. This item is considered closed.
V Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on April 27,1998. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
i X3 Management Meeting Summary l
On April 1,1998, C. Carpenter, Director, Project Directorate lil-1, Office of Nuclear Reactor Regulation, visited Fermi for site orientation and to discuss general plant performance.
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PARTIAL LIST OF PERSONS CONTACTED Licensee D. Bergmooser, Supervisor, Electrical Group, System Engineering S. Booker, Maintenance Superintendent P. Borer, Assistant Vice President, Nuclear Generation D. Cobb, Operations Superintendent R. Cook, Compliance Supervisor, Nuclear Licensing J. Davis, Director, Nuclear Training R. DeLong, Superintendent, System Engineering T. Dong, Supervisor, NSS Group, System Engineering R. Eberhardt, Superintendent, Outage Management P. Fessler, Assistant Vice Prt -ident, Nuclear Operations K. Hlavaty,' Assistant Superin, adent, Operations
. K. Howard, Superintendent, Plant Support Engineering L J. Moyers, Director, NQA W. O'Connor, Assistant Vice President, Nuclear Assessment
- N. Peterson, Director, Nuclear Licensing J. Plona, Technical Manager K. Schneider, NSS, Operations S. Stasek, Supervisor, ISEG J. Thorson, Supervisor, Reactor Engineering W. Tucker, Nuclear Fuels Group Supervisor NRC C. Carpenter, Direc'or, Project Directorate lll-1, NRR
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H. Garg, l&C Branch, NRR L. Gundrum, Backup Fermi 2 Project Manager, NRR A. Kugler, Fermi 2 Project Manager, NRR J. Kukrick, Containment System Branch, NRR B. Marcus, l&C Branch, NRR C. Schulten, TS Branch, NRR
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e INSPECTION PROCEDURES UPED IP 37551:
Onsite Engineering
' IP. 40500:
Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Froblems IP 61705:
Calibration of Nuclear instrumentation Systems IP 61726:
Surveillance Observations IP 62707:
Maintenance Observation IP 71707:
Plant Operations IP 71750:
Plant Support Activities IP 92902:
Followup - Engineering IP 92903:
Followup - Maintenance L
ITEMS OPENED AND CLOSED Opened
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50-341/98006-01 NCV Failure to Have Required Number of SRMs/lRMs Operable While Loading Fuel 50-341/98006-02 URI inconsistent Valve Stroke Time Testing for RHR Valves 50-341/98006-03 URI Dedicated Shutdown Procedure inadequacies 50-341/98006-04 IFl Additional EFA Justification for TIP Shear Valve Operability Closed 50-341/98006-01 NCV Failure to Have Required Number of SRMs/lRMs Operable While Loading Fuel
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50-341/94006-00 LER Failure to Have Required Number of SRMs/lRMs Operable While Loading Fuel 50-341/95002-00 LER Valve Closed Due to Personnel Error 50-341/35012-02a VIO Unanalyzed Load Rendered Safety Battery inoperable 50-341/95012-02b VIO - Inadequate Corrective Actions for Safety Battery Rack Corrosion 50-341/96007-02 VIO EDG Ventilation Damper Configuration Control Inadequacy 50-341/96007-06 V!O Poor Documentation of Maintenance Activities Related to Equipment Drain Sump 50-341/96010-03 VIO Inadequate Corrective Actions to Prevent Rendering Safety Battery inoperable During Maintenance -
50-341/96014-00 LER Failure to Cross-tie Ultimate Heat Sink Reservoirs as Required 50-341/96016-00 LER Unplanned ESF Actuation Due to Loss of DC Bus 50-341/96016-01 LER Unplanned ESF Actuation Due to Loss of DC Bus 50-341/97003-07 VIO Inadequate Maintenance Procedures 50-341/97003-14 URI Untimely Restoration of Unfettered Access-
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50-341/97005-02-
.VIO Work on Safety-Related Spare Switch Without Approval 50-341/97011 00 LER Failure to Reco9nize TSV and TCV Fast Closure Scram Functions to be Operable Prior to Entry into Operational Condition 1-50-341/97014-03-VIO Licensee's Failure to Conduct Verification Checks On inop EDG 24-
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s LIST OF ACRONYMS USED
APRM Average Power Range Monitor CARD Condition Assessment Resolution Document CCHVAC Control Center Heating Ventilation Air Conditioning CFR Code of Federal Regulations -
. Condensate Storage Tank EDG Emergency Diesel Generator
- ECCS Emergency Core Cooling System EFA.
Engineering Functional Analysis
- ESF Engineered Safety Feature HPCI High Pressure Coolant inje<", ion l&C Instrumentation and Control IFl Inspection Followup Item IRM Intermediate Range Monitor ISEG Independent Safety Engineering Group
- LCO Limiting Condition for Operation LER Licensee Event Report LPCI Low Pressure Coolant injection System I
' MOV Motor Operated Valves NCV Non-Cited Violation NEDC Nuclear Energy Division Class C Document NQA Nuclear Quality Assurance NRC Nuclear Regulatory Commission NRR Office of Nuclear Reactor Regulation PCMS Priraary Containment Monitoring System PE Preliminary Evaluation RBM Rod Block Monitor RCIC
. Reactor Coolant Isolation System RHR Residual Heat Removal
. SE Safety Evaluation
- SNE Station Nuclear Engineer SRM
. Source Range Monitor TCN Temporary Change Notice TIP Traversing incore Probe TS Technical Specification UFSAR Updated Final Safety Analysis Report URI Unresolved item
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