IR 05000324/1993023
| ML20045H872 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 06/24/1993 |
| From: | Christensen H, Prevatte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20045H869 | List: |
| References | |
| 50-324-93-23, 50-325-93-23, NUDOCS 9307220044 | |
| Download: ML20045H872 (4) | |
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UNITED STATES --
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'M NUCLEAR REGULATORY COMMisSIOiB
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o REGION il '
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101 MARIETTA STREET,N.W.
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ATLANTA, GEORGI A 30323 -
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Report Nos.:
50-325/93-23.and 50-324/93-23 Licensee: Carolina Power and Light Company-
P. O. Box 1551 Raleigh, NC 27602 -
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Docket.Nos.:
50-325 and 50-324 License Nos.:. DPR-71 and DPR-62
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Facility Name: Brunswick 1 and 2 l
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Inspection Conducted:-May 1 - June 4, 1993 Lead Inspector:
4 /2 9 /93 R.'L. Prevatte, Senior R defInspector Dite-Si~gned Other Inspectors:
D. J. - Nel son, P. M. Byron,.R. E. Carroll, J. E..Tedrow, P. G. Humphrey, C. W. Rapp,
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M. T. Markley, B. L. Holbrook, G. A. Harris,
i D. P. Loveless, R. A. Musser, E. Christnot,
[C.A.Hughey,R.D.Starkey,D.R.' Taylor, '
an R. P. Carrion
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Approved By:
/// V 4[2/9k H.0./Christensen, Chief.
Dite8 Signed Reactor (Projects Section IA j
Division of Reactor. Projects
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s SUMMARY Scope:
-f This special safety team inspection by the resident inspectors (augmented by.
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additional supporting inspectors) involved thel areas of maintenance
observation, surveillance observation, operational safety verification, outage activities and plant restart,' onsite review committee, and review of outstanding Licensee Event Reports.
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Results:
j Unit I remained in a forced outage that began on April 21, 1992. Unit 2
achieved 100% power on-May 28,- 1993.
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A non-cited violation involving the failure to place a high steam flow instrument in the trip position within the Technical Specification time l
requirements was identified,~ paragraph 4.
. a Weaknesses were identified concerning: the ability to' track and control-
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outstanding work activities, paragraph 2; maintaining adequate numbers of spare parts and consumables for failure prone equipment, paragraph 2; and
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9307220044 930624.
.PDR ADOCK 0500
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failure of post-maintenance testing to detect faulty wiring modifications /
installations in balance of plant equipment, paragraph 3.
Strengths were identified during Unit 2 restart in the areas of: pre-job briefings; operator communications; planning and preparation for activities /
tests; shift turnovers; shift management coverage; and management assessments and involvement.
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REPORT DETAILS 1.
Persons Contacted Licensee Employees R. Anderson - Vice-President, Brunswick Nuclear Project
- K. Ahern, Manager - Operations Support and Work Control
- G. Barnes, Manager - Shift Operations, Unit 2 M. Bradley, Manager - Brunswick Project Assessment M. Brown - Plant Manager, Unit 1
- S. Callis - On-Site Licensing Engineer R. Godley, Supervisor - Regulatory Compliance J. Hefley, Manager - Maintenance, Unit 2
- C. Hinnant - Director of-Site Operations G. Hicks, Manager - Training J. Leininger, Manager - Nuclear Engineering Department (0nsite)
P. Leslie, Manager - Security
- W. Levis, Manager - Regulatory Compliance
- G. Miller, Manager - Technical Support (Interim)
D. Moore, Manager - Maintenance, Unit 1 R. Poulk, Manager - License Training C. Robertson, Manager - Environmental & Radiological Control J. Simon, Manager - Operations Unit 1 (Interim)
R. Tart, Manager - Radwaste/ Fire Protection
- J. Titrington, Manager - Operations, Unit 2
- C. Warren, Plant Manager - Unit 2
- G. Warriner, Manager - Control and Administration E. Willett, Manager - Project Management Other licensee employees contacted included construction craftsmen, engineers, technicians, operators, office personnel and security force members.
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NRC Personnel
- H. Christensen, Chief, Reactor Projects Section lA P. Skinner, Chief, Reactor Projects Section 3B F. Cantrell, Chief, Reactor Projects Section IB J. Crlenjak, Chief, Reactor Projects Branch 4
- Attended the exit interview.
Acronyms and initialisms used in the report are listed in the last paragraph.
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2.
Maintenance Observation (62703)
The inspectors observed maintenance activities, interviewed personnel, and reviewed records to verify that work was conducted in accordance with approved procedures, Technical Specifications, and applicable industry codes and standards. The inspectors also verified that: redundant components were operable; administrative controls were followed; tagouts were adequate; personnel were qualified; correct replacements parts were
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used; radiological controls were proper; fire protection was adequate; quality control hold points were maintained; adequate post-maintenance testing was performed; and independent verification requirements were implemented. The inspectors independently verified that selected equipment was properly returned to service.
Outstanding work requests were reviewed to ensure that the licensee gave priority to safety-related maintenance. The inspectors observed / reviewed portions of the following maintenance. activities:
WR/JO 93-AREll Perform Turbine Trip and Troubleshooting Using 2-0P-26 WR/JO 93-ARCE1 Repair Efforts for Above and Below Seat Drain Lines on MSR Low Pressure Stop Valve WR/JO 93-AQAA1 Troubleshoot Cause of Oil From Cylinder 6R on EDG No. 2 WR/JO 93-AQAA2 Repair of Damaged Cylinder on EDG No. 2 WR/JO 93-AQZF4 Repair of Unit 2 H2/02 Analyzer Sample Pump on 2-CAC-AT-4409 WR/JO 93-ARSW1 Repair Control Rod 38-31 Hydraulic Control Unit WR/JO 93-ALFN1 Modify Building Steel Baseplate In Accordance with PM 92-082 and Sketch SK-92082-C-1014 WR/JO 92-AQRJ1 Corrective Maintenance on EHC Meter / Relay WR/JO 93-ASAK1 Corrective Maintenance on Main Steam High Flow Transmitter 2-821-PDTM-N009B WR/J0s 93-ARPH1 Circuit Fuse Removals II,J1 & J2 WR/JO 93-ASLIl Troubleshoot and Repair RWL Indicators 2-821-LT-
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N025A and B EDG No. 2 On May 3, the inspector was observing the preparations for the j
performance of the-EDG No.-2 Monthly Load Test (PT 12.2.b). The cylinder
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venting petcocks are opened prior to barring the engine so that it will j
be pre-lubricated prior to operation. When the maintenance mechanic i
opened the petcock for cylinder 6R, oil discharged onto the catwalk and adjacent floor area. The shift supervisor declared EDG No. 2 inoperable and WR/JO 93-AQAA1 was written to perform troubleshooting.
Investigation revealed that the 6R cylinder liner was scored along its length and one i
of the compression rings had a small piece of material missing. WR/JO AQAA2 was written to repair the damaged cylinder. The licensee replaced
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the head, piston, cylinder liners and connecting rod bearings. -In dddition, the remaining 15 cylinder liners were visually inspected for scoring. The inspector observed the cylinder repair and noted that the work was well controlled and maintenance personnel were appropriately using procedures. There was adequate engineering, QC and management support.
EDG No. 2 was declared operable on May 7.
The inspector viewed the damaged cylinder liner and observed the area where the cylinder liner was significantly scored, as well as several other areas with minor scoring. The inspector also observed that the intake valve stem area had significantly greater carbon buildup then the exhaust valve. The top of the piston also had ertensive carbon buildup.
The licensee, with concurrence from the vendor, concluded that lubricating oil was drawn to the head area during the exhaust stroke of the piston via the scored area in the cylinder liner.
Subsequent inspection of EDG No. 2 and the other three EDGs did not reveal oil in the cylinders. The inspector concluded that the licensee performed an adequate root cause review and that there was no evidence of a generic
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issue.
Drvwell Hydrocen/0xvaen (H2/02) Monitors At 2:02-a.m., on May 12, 1993, the licensee began nitrogen inerting of the drywell. On May 13, the licensee experienced equipment problems with the drywell H2/02 monitors, 2-CAC-AR-4409 and 4410.
I&C testing per 2-MST-CAC27Q, CAC Div. II H2/02 Channel Calibration, was unsuccessful in correcting the problems. The licensee declared both channels inoperable and entered an 8-hour limiting condition for operation (LCO). The drywell was confirmed to be inerted through chemistry sampling. Actual oxygen concentration was 1.45 %.
Efforts to restore the monitors to-operable status within the TS time limits were unsuccessful and Unit 2 was placed in the Startup mode at 8% reactor power.
Problems noted during this activity included: weak coordination of personnel, inadequate spare parts / material availability, and weak contingency planning for equipment known to be susceptible to failure.
Approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> was spent preparing the emergent work tickets.
There were seven spare monitor pumps that had previously failed and had not been rebuilt. Onsite sealant material (RTV) needed for pump reassembly had been previously exposed to freezing temperature conditions and was restricted from use by a quality control (QC)' hold.
Replacement RTV had to be procured from the CP&L Harris plant. The inability to maintain an adequate number of spare parts and consumables for failure prone equipment is-considered a weakness.
The licensee returned the first monitor to service on May 14, using a monitor removed from Unit 1.
The other monitor pump was rebuilt and
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returned to service later the same day. The licensee had previously inerted the drywell prior to power ascension activities without experiencing any problems.
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Emeroency AC Power On May 3,1993, while EDG No. 2 was inoperable, the inspector observed a condition that could have affected the operability of the switchgear for emergency AC power, bus E-1; thus, two E busses could have been simultaneously affected. The inspector discovered that one of the supporting I-beams for the equipment monorail. hoist alove the E-1 switchgear did not have any anchor bolts installed at its west diesel generator building wall attachment point. The inspector also noted that there was no one working on the anchor bolts. This condition created the potential that the hoist could fall on the E-1 switchgear as a result of a design basis earthquake (DBE). The inspector alerted control room personnel and returned to the E-1 switchgear room with the Unit 1 SCO.
Workers were then present and the SCO directed that they reassemble the affected component. The workers reinserted the anchor bolts which restored the hoist to its original condition.
The inspector determined that the anchor bolt work was being performed under WR/JO 93-ALFN1, which was approved on April 28, 1993. The work was to modify the building steel baseplate in accordance with PM 92-082 and drawing SK-92082-C-1014. The WR/JO stated that the work was at the 2 foot elevation and that the support steel would not be inoperable due to the modification. The inspector found that a work control center walkdown was not performed on this job.
The WR/JO lists the location as 10 feet south of column line 8D and 0 feet 6 inches West of column line U.
However, drawing SK-92082-C-1014 lists the location as elevation 60 feet.
The work had started six days after receiving SR0 (senior reactor operator) approval. Operations was under the belief that work which was not initiated within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> required re-approval by the SRO.
The inspector was unable to find this requirement in procedures and neither could the licensee. The inspector determined that unless a tracking LC0 was initiated, the licensee had no mechanism to review outstanding work when emergent issues occurred. The licensee recognized the weaknesses in the ability of the work control process to track and control work after it had been released to the field.
Two procedural changes were initiated to provide remedial action for this issue.
Special Procedure 2SP-93-019, Unit 2 Startup and Power Ascension, was revised to address stopping high risk work or work which could distract operations personnel until emergent activities are completed.
In addition, all previously approved work items for both units will be
reviewed by-the Unit 2-SRO when emergent-high-risk-items arise. Also, OPLP-24, Plant Program Work Management Process, was revised (Revision 1)
to require a review of outstanding work for common systems or changing plant conditions.
It also added the requirement that approved work not
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initiated within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> requires reapproval.
The inspector believes that a reviewer would not have recognized the j
significance of the outstanding work from the description on the WR/J0.
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The reviewer does a computer review and relies on the listed description l
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of work to be performed to make his determination. The inspector discussed this concern with the licensee and they are taking action to enhance the WR/JO to more accurately describe the work.
Main Steam Hiah Flow Transmitter 2-821-PDTM-N009B On May 23, 1993, during maintenance on the transmitter, an RPS Channel B Trip Cabinet Trouble alarm was received.
The alarm was caused by I&C technicians removing the transmitter in accordance with WR/JO 93-ASAKl.
The work scope for the WR/JO had been expanded to replace the transmitter. The additional work scope was approved by the work control center SRO.
However, it appears that Unit 2 control room personnel (Unit 2 SCO and CDs) were not made aware of the approval to remove the transmitter and, therefore, did not expect the alarm. Shift personnel informed the inspector that the I&C technicians were instructed to inform the operators prior to commencing the removal of the transmitter.
However, due to poor communications, the technicians removed the transmitter without first informing the operating shift. The technicians involved were subsequently counseled.
Although violations and deviations were not identified, several weak practices were noted.
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Surveillance Observation (61726)
The inspectors observed surveillance testing required by Technical Specifications.
Through observation, interviews, and record review the inspectors verified that:
tests conformed to Technical Specification requirements; administrative controls were followed; personnel were qualified; instrumentation was calibrated; and data was accurate and complete. The inspectors independently verified selected test results and proper return to service of equipment.
The inspectors witnessed / reviewed portions of the following Unit 2 test activities:
PT.40.2.6 Turbine Overspeed Trip Test PT 24.1.2 Service Water Miscellaneous Valve Operability Test PT-08.2.2C LPC1/RHR System Operability Test Loop-A MI-10-519F 2A Reactor Feed Pump Turbine Overspeed Test and Lever
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Adjustments for Mechanical Hydraulic Control System
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PM 89-03 EHC MSPS Calibration Pressure Regulator Testing MST-APRM27Q APRM 12% Rod Block Channel Functional Test and Calibration
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- MST-APRM11W APRM (Channel A, C, & E) Channel Functional Test (RPS Inputs)
PT-9.2 HPCI System Operability Test, Unit 2 MST-HPCI 39R HPCI Initiation Response Time Test OPT-12.2C No. 3 Diesel Generator Monthly Load Test MST-APRM12W 12 Month APRM Functional Test PT-37.2.1 Reactor Feed Pump Turbine Governor and Trip Mechanism Test PT-37.2.3 Reactor Feed Pump Turbine Thrust Bearing Wear Test PT-8.2.2b LPCI/RHR System Operability Test - Loop B PT-10.1.1 RCIC System Operability Test - Flow Rates at 1000 psi 9 MST-RPS 11W MSL HI RAD Functional Test MST-HPCI 27M HPCI and RCIC CST Low Water Level Instrument Channel Test OP-09.1 TIP Detector Response Check PM 89-073 Partial Arc Conversion PT-13.1 Reactor Recirculation Jet Pump Operability MST-RPS-28R Main Steam Line Background Radiation Calculation and Setpoint Calibration (without HWC)
2-MST-AMI27M AMI Suppression Pool Temp Monitor Channel Functional Test MST-PCIS22M PCIS Low Main Steam Line Pressure Trip Unit. Channel Calibration PT-37.2.2 Reactor Feed Pump Turbine Stop Valve Test OP-26
- Turbine Bypass Valve Testing l
PT-14.2.1 Single Rod Scram Insertion Times Test
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PT-14.1 Weekly Control Rod Operational check MST-RHR23R RHR-LPCI ADS CS LL3, HPCI RCIC LL2 DIV II INST CHAN Calibration of 2-821-LT-N013B
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PT-50.14 TIP Tube LPRM Configuration Verification MST-ATWS 21M ATWS Reactor Water low Level 2 Trip Unit Channel Calibration PT-08.2.2B LPCI/RHR System Operability Test - Loop B OSP-91-073 Drywell Outboard Isolation Valves Operability Test 9 (Unit 2)
Testina Diesel Generator No. 3 On May 10,1993, EDG No. 3 was started for its routine monthly Technical Specification (TS) surveillance in accordance with PT 12.2C, No. 3 Diesel Generator Monthly Load Test, Rev. 50. This start required that the AC powered fuel oil booster pump be de-energized to prevent it from contributing to the engine driven fuel oil pump's ability to deliver fuel to the engine on start. The booster pump is not available on dead bus automatic diesel starts assumed during accident conditions. This was an issue that had been previously revealed as a result of slow start times on EDG No. 3 (See Inspection Report 325,324/91-16).
Corrective actions at that time included procedure revisions to disable the fuel oil booster pump except for two monthly tests each year. The booster pump is allowed to run twice a year to ensure its continued availability.
During the engine starting sequence, the operator failed to turn the booster pump off until after the prestart actuation, but before the engine roll. This allowed the booster pump to momentarily run, fill, and pressurize the fuel oil system. This invalidated the starting time measurement.
Both the inspector and the SCO monitoring the surveillance observed the actuation of the booster pump. The inspector observed that fuel cil pressure was approximately 25 psi at the start of engine roll.
Subsequently, the inspector questioned the 500 about the validity of the starting time measurement and informed him of the fuel oil pressure existing after the pump was secured. The SCO agreed that the start was invalid, but stated that the engine load and run would be continued and a subsequent start would be preformed to obtain a valid starting time.
Ultimately this was accomplished with no significant difference in starting times; therefore, the observed invalid start was not safety significant.
The inspector considered the error in the starting sequence to be due to personnel error that was contributed to by misleading steps in thr:
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surveillance procedure.- The licensee initiated action-to have the
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procedure revised. As the error was detected and resolved without safety significance, the inspector considered that no violation occurred.
RCIC System Testina During the performance of the RCIC operability test, reactor pressure decreased when the RCIC turbine was started.
Pressure fell below the initial prerequisite pressure band of 920 - 1020 psig (actual pressure
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i was 910 psig).. Auxiliary operators noted this discrepancy and promptly i
informed the control room. Affected portions of the test procedure were then re-performed.
Also during the performance of RCIC testing, the system engineer noted that the RCIC vacuum pump discharge valve to the suppression pool (2-E51-F002) was locked open.. This valve was intended to be closed as indicated by: temporary modification 2-92-0065, to help minimize potential oxygen introduction into the suppression pool. Due to miscommunications
between Technical Support and Operations and conflicting documents, this
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valve had been returned to the normal locked open position.
Since the
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vacuum pump had not yet been operated, little oxygen had been allowed to
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enter the suppression pool via this pathway. The licensee subsequently established an equipment clearance (2-93-01315) on this valve to maintain
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it in the closed position.-
Improvements in the temporary modification.
process which have been made since implementing temporary modification 2-92-0065, should preclude occurrence-of similar problems.
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On May 18, the inspector observed I&C technicians performing surveillance
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2MST-RCIC 23M, RCIC Turbine Exhaust Diagram High Pressure Ir.strument
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Channel Calibration. at the 17 foot elevation, and-observed that they.were
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using a Heise gauge in the horizontal position. The licensee was queried as to the position for which the gauge was calibrated. The licensee informed the inspector that the gauge was calibrated in the vertical position. They checked the calibration of the Heise gauge which the
technicians used in both the horizontal and vertical positions. The
gauge was in calibration in the vertical position and determined to be in calibration in the range.in which it was being used while horizontal.
It was not in calibration at the upper ranges of the instrument while horizontal. The I&C technicians designed and had constructed a stand for
the Heise gauges so that they will be used in the position in which they were calibrated. The inspector asked the licensee if there was any other instrumentation which was operated in a position other than its calibrated position. The licensee agreed to investigate this item and correct any identified deficiencies.
HPCI System Doerability Test
During this test, the operator seemed unsure of how to control HPCI speed-when initially starting the turbine. The procedure had a typographical error-in reference to RTGB meter 603 vs 602 and also had steps out of i
sequence. The verification of suction pressure was before isolation of
i the discharge path. With the discharge path open, the' demineralized water would pass directly to the CST and the suction header would not
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pressurize. After questioning, a temporary change was completed to reverse these steps.
Operators performing the test were generally satisfied with the quality of the procedure.
They stated that procedure errors or significant i
impediments to procedure use are usually quickly dispositioned via the
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procedure retision request process in accordance with Operating Instruction C1-28, Preparation and Review of Operations procedures, j
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Communications with local operators was difficult. The control room i
operator appeared to be overriding other communications by pushing the talk button and cutting out the local operator. Also, other control. room operators were unable to talk to the control room operator since he was wearing a headset.
y During the second start of HPCI,.a drain pot high level alarm was received. The F001 valve was opened which interlocked the F028 valve
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l closed. With the F028 valve closed, the drain trap could.not be drained.
The procedure did not have steps to drain the trap if needed.. The SR0s
on-shift did not want to temporarily change the PT to allow draining of-
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the drain trap and this resulted in rerunning the PT after draining the
condensation from the drain trap. The PT was completed satisfactory.
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APRM Functional Testina I&C identified a typographical problem with procedure MST-APRM-12W, in that a procedure step incorrectly identified a lead that was to be lifted. The terminal was correctly identified but the wire number was incorrect.
It was learned that the procedure had been previously-
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performed (during the time the unit was operating),.but the discrepancy had not been identified or corrected. The'I&C technician initiated temporary procedure change No.93-115 to correct the procedure.
The same
- procedure failed to include steps to verify that APRM setdown was reset.
This caused _ the I&C technicians to believe the procedure.could not.be correctly performed.
During the test,.the APRM was tripping at a voltage equal to 90 percent power instead of tripping at a voltage equal to the
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normal high power trip setpoint. After performing the test a second
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time, the I&C technician reported the problem to the operations SRO. The
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SR0 knew the APRM setdown was not reset. Once the setdown was reset, the test was correctly performed.
The I&C technician initiated a procedure change to add the required steps.
Turbine Testina Activities Several problems with plant modification 89-073, electrohydraulic control system (EHC), were identified during turbine valve testing and turbine roll activities. One modification change installed a ground leg wire to
an existing relay card to place a bias on the turbine control valves to
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hold them closed while performing turbine chest warming.- During the.
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turbine control test, the valves would not stay hard closed and were chattering.
Investigation found that the modification design had failed
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to include the above relay-wiring H The post-modification-testing failed
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to identify this discrepancy. Additionally, a visual inspection during
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the test had also failed to identify the problem. A problem involving
the incorrect retermination of 4 leads was also identified. This work
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was completed by a CP&L I&C technician and verified by a GE field
engineer. A new Turbine Supervisory Instrumentation cable was also _
installed by this modification. The termination in the front standard of
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the turbine was connected to the right terminal numbers, but on an incorrect terminal block. The post modification testing failed to
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10 identify any of these discrepancies. This item was performed by two contract workers. The lack of quality in the installation activities and the failure of post modification testing to detect faulty wiring is a weakness. The licensee conducted investigations, system walkdowns and reverified many of the activities associated with the above modifications. A sequence of events were developed to correct the identified problems before and during the turbine overspeed testing activities. The licensee also initiated two different adverse condition reports (ACRs93-159 & 160) to further identify the root cause and provide appropriate corrective actions.
TIP Testina While performing PT 50.14, a reactor operator discovered that he had inserted rod 42-15 in lieu of designated rod 46-15. The discovery was made when the operator went to withdraw rod 46-15 and found it at position 48. Rod 42-15 was at position 36. The purpose of the rod withdrawals during this test is to alter the flux shape in the vicinity of a TIP tube.
Rods adjacent to the TIP tube are used for t.M s purpose.
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Rod 42-15 is also adjacent to the D4 TIP tube; therefore, the test did
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was not invalidated. The operator received extensive counseling on this mistab The inspector concluded that the TIP system was operating satisfactorily, and the actions in response to the personnel error were appropriate.
Service Water Header Operability Test On May 12, 1993, the inspector reviewed licensee authorization of plant activities in the work control center (WCC). During that time, the
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inspector observed the WCC SRO initiate a tracking LC0 for valve 2-SW-V201 which had failed PT-24.1.1-2 the night before and was pending repair per WR/JO 93-AQYDI. The SRC inadvertently wrote the paperwork to be completed on Unit I rather t ian Unit 2.
The licensee caught the error when the SR0 informed the Unit I control room of the LC0 entry.
Low Pressure Coolant In.iection (LPCI) System Operability Test On May 12, 1993, the licensee performed LPCI system operability testing per PT-18.2.2-C.
This activity included a QC inspection of system
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leakage and vibration monitoring. At the conclusion of the test some water was noted by the inspector in the collecting bowl. The licensee considered this to have been present at the beginning of the test since no appreciable leakage was observed. The vibration monitoring resulted in the "C" residual heat removal-(RHR)' pump being placed in the high alert range for inservice testing purposes. Consequently, the. pump is required to be tested at twice the periodicity of the normal program.
The RHR B'and D pumps are already in increased testing due to high vibration. The equipment's overall performance met test acceptance criteria.
However, the licensee has not resolved the root cause of the high vibration anomalies and the resultant operator work-arounds.
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Violations and deviations were not identified.
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4.
Operational Safety Verification (71707)
The inspectors verified that Units 1 and 2 were operated in compliance with Technical Specifications and other regulatory requirements by direct observations of activities, facility tours, discussions with personnel, reviewing of records and independent verification of safety system status.
The inspectors verified that control room manning requirements of 10 CFR 50.54 and the Technical Specifications were met. Control operator, shift supervisor, clearance, STA, d=ily and standing instructions and jumper / bypass logs were reviewed to obtain information concerning operating trends and out of service safety systems to ensure that there were no conflicts with Technical Specification Limiting Conditions for Operations.
Direct observations of control room panels and instrumentation and recorded traces important to safety were conducted to verify operability and that operating parameters were within Technical Specification limits. The inspectors observed shift turnovers to verify that system status continuity was maintained.
The inspectors also verified the status of selected control room annunciators.
Operability of a selected Engineered Safety feature division was verified weekly by ensuring that: each accessible valve in the flow path was in its correct position; each power supply and breaker was closed for
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components that must activate upon initiation signal; there was not leakage of major components; there was proper lubrication and cooling water available; and conditions did not exist which could prevent fulfillment of the system's functional requirements.
Instrumentation essential to system actuation or performance was verified operable by observing on-scale indication and proper instrument valve lineup, if accessible.
The inspectors verified that the licensee's llP policies and procedures were followed. This included observation of HP practices and a review of area surveys, radiation work permits, posting and instrument calibration.
Overall licensee implementation of radiological work practices was good; however, as discussed later in this section, several significant departures were observed.
The inspectors verified by general observations that:
the security organization was properly mtnned and security personnel were capable of performing their assigred functions; persons and packages were checked prior to entry into the PA; vehicles were properly authorized, searched and escorted within the PA; persons within the PA displayed photo identification badges; personnel in vital areas were authorized; effective compensatory measures were employed when required; and security's response to potential threats or alarms was adequate.
i The inspectors also observed plant housekeeping controls, verified position of certain containment isolation valves, checked clearances and
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verified the operability of onsite and offsite emergency power source '
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Radiological Work Practices On May 17, 1993, an NRC inspector observed several deficient radiological work practices. These deficiencies occurred during operations clearance activities to return the "2B" reactor feed pump (RFP-28) to service per clearance 2-93-00617. The cognizant A0 improperly issued an alarming / integrating dosimeter to the inspector for use in accessing posted high radiation areas (HRAs) around the condenser. At the
" breezeway" radiation protection control point, it became apparent that neither the A0 nor the cognizant HP technician were familiar with the proper use of the electronic dosimeters.
Neither individual could explain accurately in which mode the dosimeters were operating (dose rate or accumulated dose) nor could they identify alarm setpoints. The A0 could only state that he must leave the area if it alarmed. An HP supervisor responded to the location and recognized the error in the A0 issuing the dosimeter. Only HP personnel are qualified and allowed by-procedures to issue dosimetry.
It was apparent that both individuals lacked appropriate training in using these devices.
The A0 used a blanket radiation work permit (RWP-002) provided for exclusive use by operators.
It did not require an ALARA briefing to access HRAs. The inspector used RWP-1383 which required a briefing, an alarming dosimeter, and an integrating dose rate meter. After the confusion regarding dosimetry use, neither the HP technician nor his supervisor-required the A0 to review radiological survey results. They did not recognize the need to inform the A0 regarding the radiological hazards _ because his RWP did not require it, even though he lacked adequate understanding of monitoring instrumentation.
In this case, the A0's alarming dosimeter was not set to function as an integrating dose rate instrument for assessing the radiological conditions in the area.
Upon returning to the control room, the inspector questioned an SR0 and A0 on the operation of the dosimeters. The A0 responded incorrectly
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regarding alarms and setpoints. The SR0 stated he did not know rather than guess incorrectly.
The licensee examined other alarming / integrating dosimeters available for use in the A0 office.
Four other dosimeters were found not to be set for dose rate monitoring.
Licensee questioning identified additional deficiencies in A0 knowledge regarding proper dosimetry use. As immediate corrective action, the licensee removed all alarming dosimeters from the A0 office until appropriate training could be completed. The licensee's preliminary review of training indicated that personnel had a
been given training during-a safety meeting in 1989. No-subsequent G
training was provided.
The licensee has been taking credit for dosimeter calibration as purchased from the manufacturer. The dosimetry system performs a source check each time the device is issued. However, the acceptance criteria for this check is 25%. The licensee was unable to resolve questions regarding the technical merit of using these dosimeters as survey
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instruments in high energy fields such as the high N-16 gamma
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environments around the turbine condenser. These dosimeters have G-M detectors which are particularly vulnerable to erratic response in mixed radiation fields.
The above issues were subsequently reviewed by a regional health physics inspector and the results are documented in Inspection Report 325,324/93-28.
General Emoloyee TraininQ The inspector reviewed the training given to licensee and contractor personnel to provide them with the knowledge and skills needed to work safely in a nuclear plant environment. The training requirement and description are contained in the General Employee Training Instruction, TI-30, Volume I.
This training is provided in two courses, General Employee Training (GET) Levels I and II. GET Level I, required for permanent site employees and individuals on long-term assignment, consists of training in the following areas:
o CP&L's Fitness for Duty Program o Plant description and security e Personnel and industrial safety
- CP&L's Chemical Control Program o Emergency Preparedness e Quality Performance (includes overall objectives, NRC inspections and investigations, Quality Check Program, and Corporate Quality Assurance Program)
e Fundamentals of Radiation and Basic Plant Operation Successful completion of GET Level I is a prerequisite for GET Level II, which is required for individuals who need unescorted access to the protected area. GET Level II consists of training in the following areas:
- Ionizing radiations and unit of measure e Biological effects of radiation e Radiation dose limits and dosimetry e Radiation area posting and radiation control methods e ALARA e Radiation work permits e Contamination areas and contamination control methods e Contamination control techniques (donning and removing protective clothing)
e Practical exercises-(including proper dress-out techniques,
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instrument use, and frisking procedures)
Following instruction in both Level I and Level II, successful completion of a written exam on each area with a score of at least 80% is required.
If an individual fails, he must attend retraining and be reexamined.
In addition to the above, a practical exam is given in the area of Radiation Protection Practices. All personnel are provided retraining on an annual basis.
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Individuals who have received radiation protection training at other nuclear (non-CP&L) plants, may be exempted from initial GET training at CP&L if they meet the following conditions:
- The individual must complete an affidavit documenting successful completion of GET in the past three years.
e The individual receives all study information provided for GET Level I and II training for review.
e The individual successfully passes the Level I and II exams.
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e The individual successfully completes the practical examination on radiation protection.
If the individual fails any of the above, they will be required to repeat
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that section.
The inspector has completed the licensee's GET program and has received this training at other sites. This program appears to be consistent with other nuclear sites. The inspector's observation of past GET classes found that the training conducted in all areas appeared to be adequate to familiarize an individual with the knowledge and skills needed to work safely at a nuclear plant.
ACR Review In the course of an inspection during the week of June 15-19, 1992, the inspector reviewed ACR 92-370, concerning wrong heat numbers on structural plate material.
From about 10:00 p.m. until about 1:00 a.m.,
the inspector interviewed cognizant licensee personnel, examined procedures concerning material handling and the operation of the Outage Management Organization, and toured the fabrication shop and the area where the plate material was stored to see how business was conducted during the night shift.
The inspector concluded that, although the wrong heat numbers were used, the material in question (structural plate material) was not used in the Brunswick plant, but rather scrapped. Therefore, there was no direct safety significance as a result of the incident.
Defective HPCI Annunciator On May 4,-1993,-the inspector observed that the Unit 2 HPCI control room annunciator 2-A-1 3-2, HPCI Lube Oil Cooler Outlet Temp. Hi, was identified as being defective by the existence of a trouble tag sticker for WR/JO 90-AAGUI posted on the control board.
In February 1993, the inspector had discovered the above open WR/JO during backlog review and had also determined that control room personnel were unaware that the annunciator was not functional. At that time, no trouble ticket sticker or other indicator was in place to identify the unavailability of the annunciator (see Inspection Report 325,324/93-10). As a result, the
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above trouble tag was placed and licensee management stated that the condition would be repaired prior to Unit 2 restart. Since Unit 2 restart was in progress on May 4, the inspector inquired as to why the condition had not been corrected. HPCI had undergone some startup testing and was considered operable for the current plant conditions.
The licensee determined that the repair had been completed, but the trouble tag had been mistakenly left in place. The inspector concluded that the status of the annunciator had changed from being disabled, to being identified as unreliable, but being fully functional. The inspector verified that actual high temperature conditions had not occurred and therefore, no direct safety significance existed because of the mis-identified annunciator status. The trouble tag was promptly removed by the shift supervisor.
Inoperable Main Steam line Flow Instrument At 12:30 p.m., on May 22, 1993, during a back panel tour, the reactor-operator noticed the Main Steam Line (MSL) D High Flow Instrument (2-821-PDTM-N009B-1) was inoperable /downscale. The unit SR0 was informed of the observation. He reviewed Technical Specification 3.3.2, including Table 3.3.2-1 and Operating Instruction 01-18, Definition of Instrument Channels and Trip Systems for Selected Instruments, Revision 28. The unit SR0 determined that the appropriate action was to place one trip system in the tripped condition within one hour in accordance with the actions required by Technical Specification 3.3.2.
He discussed his assessment with the startup SR0 and the STA who concurred with the assessment. A review of 0I-18 indicated that the failed trip unit is
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associated with trip channel B1 and the appropriate action is to pull i
fuse A71B-F38. The unit SR0 discussed his assessment with the shift supervisor who concluded that only a tracking LCO was necessary and that the instrument did not need to be placed in a tripped condition. The shift supervisor's decision prevailed and Tracking LC0 T2-93-0511 was written and WR/JO 93-ASAK1 was initiated to repair the flow transmitter.
At 7:25 p.m., during turnover, the oncoming unit SR0 reviewed the Tracking LCOs and questioned if it should not be an active LCO and that
the trip instrument should be placed in a tripped condition. He discussed his concern with the oncoming startup SRO, shift supervisor and STA. They concurred with his proposed actions after reviewing the appropriate documents. At 7:30 p.m., the flow instrument was placed in the tripped condition by removing Fuse A71 B-F3B in accordance with 01-18 which inserted a half Group I trip signal to the
"B" trip system.
Tracking LC0 T2-93-0511 was canceled and Active LC0 A2-93-0513 was initiated.- The MSL-flow transmitter was' repaired and-the operators reset the one half Group 1 isolation at 3:12 p.m., on May 23. ACR 93-165 was
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written to document this event. This is a violation (324/93-23-01):
l Failure to Implement Technical Specification Action 3.3.2.b.
This violation will not be subject to enforcement action because the licensee's efforts in identifying and correcting the violation meet the criteria specified in Section VII.B of the Enforcement Policy.
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The licensee's corrective actions for this event included:
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Briefing the SR0s and STAS on recent events.
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Briefing the shift supervisors on the management elements of this event.
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Counselling the involved shift supervisor.
In addition, the following additional corrective actions are planned:
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Revising the next phase of License Operator Requalification training to provide:
- SR0 and STA review of LER events for last 10 years involving Technical Specification errors
- Practical test of Technical Specification applications
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A NAD assessment of Operations Technical Specification Compliance in the third quarter of 1993.
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INP0 team training to be conducted for all crews in the third quarter of 1993.
5.
Outage Activities and Plant Restart (71707)(71715)
May 3-10, 1993 In support of power ascension testing below the 15% hold point, reactor power level during this period ranged from 4% to 12%.
Generally, operator communications were good. Repeat backs were used to ensure information was understood. However, the level of background noise (e.g., plant computer typers during control rod movements, plant'
page usage during substantial Unit I activities, etc...) sometimes required that the operators repeat information because other persons did not understand what was said.
At 11:00 a.m., on May 4, 1993, a reduction in main condenser vacuum
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occurred while placing the steam Jet air ejectors in service. To correct the lowering vacuum, control board operators started the 2A and 28 mechanical vacuum pumps. A subsequent main turbine trip signal was generated on low condenser vacuum and the 2A vacuum pump also tripped.
Since the main turbine was on the' turning gear and-was in the warmup process, only the warmup steam supply source was isolated by the trip signal. Approximately seven minutes after the 2B vacuum pump was started, auxiliary operators discovered that the 2B pump had not been lined up for service and was isolated. The 2B vacuum pump was subsequently secured.
Starting an isolated pump is a minor example of poor system alignment control.
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On May 7, 1993, between the time of 1:51 a.m. to 4:42 a.m., the Unit 2 reactor pressure was raised from approximately 250 psi to 500 psi.
As reactor pressure was raised, containment isolation valve leakage allowed the B loop RHR pump discharge piping from the pump check valves to the normally shut LPCI inboard injection valve (2-Ell-F015B) to become pressurized in excess of the keep fill system pressure. Control room operators were not aware of this condition.
At approximately 7:10 a.m., a health physics technician notified the control room of a leak on the B loop RHR heat exchanger. Operators were dispatched to assess the condition. At approximately 7:15 a.m., the inspector entered the control room, became aware of the reported leak, and observed that the B RHR heat exchanger pressure was approximalaly 400 psi. This was pointed out to the operators as the likely reason for the leak and indicated that the F015B valve and 2-E11-V508, Injection Check Valve, were probably leaking. The leakage from the heat exchanger was reported to be from a flange type joint and was estimated at 1/4 to 1/2 gpm.
Sample analysis confirmed the leakage to be from the primary side of the heat exchanger.
Emergency Response Facility Information System (ERFIS)
data revealed the heat exchanger pressure rise took place over several hours beginning shortly after the increase in reactor pressure.
Operators vented the heat exchanger which lowered the pressure to that of the keep fill system (approximately 65 psi) and the heat exchanger leak stopped. Over several hours the heat exchanger pressure slowly increased above 100 psi, indicating that inleakage was still occurring; but was not sufficient to cause the heat exchanger leak to return.
Ultimately, the F0158 valve was cycled closed and the inleakage appeared to stop. No
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repair attempts were made on the heat exchanger flange based on no leakage at normal pressures during the suppression pool cooling mode, the relatively small leak volume at the elevated pressure, and the complexity of disassembly to permit the repair.
EER 93-0405 addressed the primary containment isolation operability of the F0158 valve. The PCIS function of the valve was unaffected based on acceptable 10 CFR 50, Appendix J, LLRT results for testing conducted on February 19, 1993.
Leakage of 0.090 scfh was measured at 50 psig air with acceptable limits of 13.32 scfh.
In addition, a water test at 1000 psig was conducted with results less than the maximum acceptable leakage of 5 gpm. The inspector considered the EER conclusions to be reasonable.
The elevated heat exchanger pressure accompanying a controlled reactor pressure increase reasonably should have been observed and diagnosed.
i The elevated pressure existed through a shift turnover and board walkdowns by all Unit 2 shift operators without definitive recognition until revealed by the reported leak and the NRC inspector.
During interviews subsequent to the event, operators stated that close attention was given to pressure indications as reactor pressure was raised.
For example, the HPCI and RCIC steam pressure instruments were
monitored to ensure they indicated the change.
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a m eness was demonstrated during startup on May 5, 1993, when reactor vessel level instrumert B21-LT-N031B was diagnosed as being out of calibration based on observed differences with other instruments. These examples indicate that operators routinely verify expected parameter changes, but (as with the RHR heat exchanger pressure) tend to give insufficient attention to seek unexpected results.
May 10-17. 1993 At the beginning of this period, the plant was at 12% reactor power. On May 14, 1992, the NRC authorized the licensee to increase reactor power beyond the 15% hold point. On May 15, 1993, the licensee rolled the turbine and phased the generator to the grid. The inspection segment concluded with the reactor at 30% power and 180 MWe.
Activities of the Unit 1 and Unit 2 main control room, work control center, clearance center and plant operators were monitored. On-shift supervision was always present and seemed to keep abreast of the past, current, and upcoming activities.
Communications, command and control were readily visible.
Communications between and among individuals were generally clear, concise and correct. There was one instance when a Unit 2 reactor operator, assisting I&C in performing a surveillance test, did not inform the second reactor operator that certain alarms would be actuated as part of the test. This was questioned by the second operater and the problem was corrected.
Repeat backs were conducted for face-to-face communications, as well as telephone and radio communications.
Overall, control room decorum was good. Work activities in the main control room were kept to a minimum and traffic was kept to the minimum possible. The shifts were adequately staffed and yet not overly crowded.
Operator knowledge of plant conditions and systems being operated was adequate.
Nearly every job began with a pre-job brief.
Generally the SR0 on shift would hold a meeting with the principle participants and_ go over in detail the activities to be performed.
Procedures to be utilized were reviewed, precautions, limitations, and past industry experiences, where applicable, were also reviewed._ The principle engineer for the activity would also discuss the more complicated tasks when necessary.
The inspectors observed that the operators utilized and followed procedures for the evolutions being performed. Alarm response procedures were routinely utilized. Operators consistently announced annunciator alarms and changes-to system controls;-however,-they were sometimes slow
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to clear acknowledged annunciators.
Shift turnover and briefings were good and considered a strength.
Oncoming and offgoing operators were observed to walk the boards and
verify system lineups.
SR0s maintained good cognizance of plant status i
and reactor operator (RO) response to system performance was good.
However, SR0s occasionally became too involved in control board
activities. Documentation of shift operating history was adequat.
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Logbooks were legible but limited in detail.
Operators were knowledgeable of ongoing work. However, logbooks were frequently completed with late entries.
LCOs were found to be correct for the plant conditions and no time restraints or TS requirements were violated during this pase of power ascension.
Involvement by licensee management was good.
Senior licensee management was routinely observed in operations shift turnover and evolution briefings. Management was appropriately involved in overseeing activities to assess equipment problems. Additionally, the licensee's temporary startup organization had a positive influence in reducing the coordination impact on the operating shift.
Auxiliary operator (A0) performance was inconsistent. The inspectors observed A0s perform routine surveillance rounds in both the reactor and turbine buildings.
Some A0s were very conscientious in completing their duties. They effectively identified offnormal conditions and initiated corrective actions.
Others demonstrated a tolerance for poor practices (e.g., storage of tools and spare parts on and inside breakers and backpanels, trouble tickets obstructing instrument gauges, etc...) and lacked a proper questioning attitude.
May 17-24. 1993 During this period, Unit 2 ascended from 29% power to 60% power. The NRC Hold Point at the 35% power level was released at 8:11 p.m., on May 22, 1993, by the NRC Regional Administrator and the plant continued the power ascension program. The decision to go above 60% power was made on May 24, 1993, at 11:30 a.m.
The activities monitored by the. inspectors included operator conduct in the control room and performance of surveillances and other work activities by the operators.
For the most part, pre-job briefings and communications were good.
It was noted that there was a good exchange of information between the operators and with other organizations.
Activities were conducted in a professional manner, with self-checking and independent verification being appropriately performed.
Some abnormalities were experienced during the power ascension and are documented as follows:
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At the 29% power level the unit experienced a problem in that the Turbine Stop Valve / Control. Valve Fast Closure-By-Pass did not arm.
This was evaluated and determined that the first stage steam chest pressure did not reach the required pressure for the reset. A Temporary Modification was implemented to arm the circuit by removing the fuses in the circuit until the pressure was sufficient to reset the switches.
At that time the Temporary Modification was removed.
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At approximately 12:30 p.m., on May 22, 1993, an operator noted a that the 'D' Main Steam High Flow indicator was downscale. The operators failed to identify that it was required per Technical Specification 3.3.2.
As a result, the Action Statement was not entered until the following shift turnover at 7:31 p.m. when the on-coming shift identified that the instrument was required per the Technical Specifications (see Section 4 of this report).
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On May 21, 1993, the inspector observed a plastic catch system routing water leakage from the overhead above Battery 2B-2 into a mop bucket. The shift supervisor stated that the water was coming from a leak in the wall, and was only present during hard rains.
The inspector verified that WR/JO 93-ANLH1 had been written to repair the leak and was scheduled for repair.
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During a power decrease on May 24, 1993, the inspector noted on the ERFIS that Control Rod 42-35 was out of position as compared with the other rods in its group. The inspector informed the nuclear engineer. This condition was corrected and the power reduction continued. A few moments later, the inspector noted on ERFIS that Control Rod 18-11 was out of position. The reactor operator and the nuclear engineer had verified that the rod was in Position 18 when it had actually settled to Position 20. Again the condition was corrected by inserting Control Rod 18-11 to Position 18. The inspector discussed this conditica with the Unit 2 Operations Manager. He investigated the event and informed the inspector that the operator had not verified that the rod had settled prior to selecting a new control rod for insertion. The operator instead saw the Position 18 indication, signed the procedure verifying that the rod was in that position, and then selected a new rod without reverifying the rod position after it had settled. The Unit 2 Operations Manager addressed the operating crew during the shift turnover, and stressed the need for attention to detail.
May 24-31. 1993 During this period, the inspectors observed control room activities involving the power ascension from 60% to 100% power. Variances (increases and decreases) in reactor power were conducted in support of EHC system testing.
Overall, the conduct of control room personnel and responses to changing plant conditions were considered good.
Shift turnover briefings were conducted in a professional manner.
Noise levels-in the control room
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eere kept to a minimum.
Priorities for upcoming shift activities were emphasized to all personnel. Attention to detail and the importance of self-verification during the performance of duties was emphasized during every briefing.
On May 28, during a power increase from 96% to 98% power via control rod withdrawal, one rod (26-35) appeared to double notch with single notch withdrawal selected. However, the operator prevented further occurrence
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21 by utilizing the emergency rod in notch override. A trouble ticket was initiated per 2-0P-07, Rev. 52. All other rods selected for movement were completed without a problem.
EHC system testing on May 29, closed a TCV at 75% reactor power. When the TCV was released to open, a severe transient was imposed upon the Unit 2 reactor. Significant pressure and indicated power fluctuations occurred.
The unit received a 1/2 scram on the APRM to flow set down, the main turbine-generator fluctuated over a 150 MWE range, and the pressure surges were noted.
The unit subsequently settled out and the operators performed a post transient critique. Operator response was considered good.
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At 100% power, the No. 3 TCV was oscillating excessively at 85% open.
Test personnel indicated that at 100% power, the No. 3 TCV should be full open with the No. 4 TCV controlling steam pressure. An investigation was still in progress by the licensee at the end of this period.
June 1 - 4. 1993 During this period, Unit 2 was operated at 100% power and returned to normal operations.
Observed full power evolutions (i.e., replacement of
"B" TIP detector, LPRM calibration, core power distribution, reactivity checks, core flow calibration, and main steam line radiation monitor set point adjustment) were considered to be performed well.
The licensee's management assessment meeting for assessment hold point No. 7 (return to normal operations) was also observed.
In the meeting, each unit manager addressed his unit's readiness for a release for unrestricted operations including all significant equipment and/or personnel problems that have occurred since the 60% power assessment point. The corrective actions and/or resolutions for these items were discussed in detail. The depth and detail of the management assessment were considered a strength.
On June 3,1993, a teleconference call was conducted between the licensee, the Region II Administrator, and the NRC restart staff concerning the completion of the startup and power ascension plan. The licensee discussed the problems that had been encountered during power ascension testing on TCV-3 and the inability to perform monthly control valve testing above 65% power. The licensee stated that the oscillations observed on TCV-3 was the result of the turbine not achieving design steam flow. This -prevented TCV-3 from fully opening and allowing TCV-4 to control-steam flow. -The licensee stated that this oscillation had no
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impact on safe operation, but may result in some accelerated wear on the EHC accumulators.
The licensee currently has a test study underway to determine if this accumulator wear will be excessive.
Results on this are anticipated by mid-June. The licensee also has the turbine vendor reviewing data to determine if additional adjustments need to be made to the electronic controls for the turbine control valves.
This may also involve testing to determine if installed equipment is accurately measuring feedwater flow. The licensee is developing a plan for this and
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other testing if needed to correct the control valve oscillations and determine the appropriate power level for monthly control valve testing.
At the conclusion of this conference, the Regional Administrator released the plant for return to normal operations at approximately 4:00 p.m..
The licensee's augmented staffing was returned to normal and the NRC's 24-hour control room observation was terminated on June 4,1993, with augmented inspection continuing.
Startu_g and Power Ascension Summary The licensee completed the startup and power ascension test plan on June 4, 1993. This testing started when restart permission was received from the Regional Administration on April 27, 1993. The reactor was taken critical on April 29, 1993. The license's plans were for a 40 day startup and power ascension program with two, five day contingency outages for repairs after operations at 35% and 100% power. The startup and power ascension plan appeared to have been well researched and prepared. The majority of testing was performed as planned with some minor adjustments for equipment failures and repairs. The only major equipment failures were the 2B reactor feed pump (which required-approximately 10 days to rebuild), the failure of EDG No. 2 (involving a scored cylinder liner which resulted in cylinder rebuild), and the failures of CAC 4409 and 4410 monitors.
Only minor leaks were observed in fluid systems and the planned contingency outages were not utilized.
Some operator errors and mispositioned valves were identified during the startup; however, the number of errors decreased and appropriate corrective and remedial action was taken by management and supervision to correct these items.
Overall plant and personnel performance was effective throughout startup and power ascension. The majority of pre-job briefings were well organized and effective. Operator communicatius was considered an overall strength.
Shift turnovers were detailed and effective.
Shift management coverage provided effective oversite and coordination of activities. The startup and power ascension program was considered a strength, being both well planned and effective.
The management assessments conducted at each assessment and decision point were observed by the staff and found to be very open and frank, with emphasis on resolving problems. They provided effective feedback to all levels of management.
6.
Onsite Review Committee (40500)
The inspectors attended selected Plant Nuclear Safety Committee (PNSC)
meetings conducted during the period. The inspectors verified that the meetings-were conducted in accordance with Technical Specification
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requirements regarding quorum membership, review process, frequency and personnel qualifications. Meeting minutes were reviewed to confirm that decisions and recommendations were reflected in the minutes and followup of corrective actions was completed.
There were no concerns identified relative to the PNSC meetings attended.
The resolution of safety issues presented during these meetings was considered to be acceptabl.-.
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7.
Review of Licensee Event Reports (92700)
(Closed) LER l-92-005, Reactor Scram During Stop Valve Testing. On February 29, 1992, a reactor scram occurred during surveillance testing of TSV 2.
The surveillance simulated closure of one TSV in the "Al" RPS trip logic while the second TSV in this logic channel was stroked allowing a response time measurement of the half scram function actuation. However, during the test, TSVs 1 and 3 also closed due to a condition which de-energized the "B1" RPS logic and initiated a full.
Investigation by the licensee into the cause of the TSVs 1 and 3 closure concluded the most likely cause to be due to a spurious failure of a master / slave circuit. The circuit is normally bypassed during testing such that it prevents the other TSVs from closing when TSV 2 is closed. To address the above problem and other equipment related pr7blems identified following the scram, the licensee initiated the following actions:
A temporary test switch was installed on the Unit 1 TSV master / slave
circuit to allow disabling the circuit during testing (EER 92-053).
e Maintenance Work Request 92-AEYQ1 was initiated to replace the test logic portion of the master / slave circuit. The currently installed mercury-wetted relay boards are being replaced with newly manufactured ones. No modification to the suspected failed components are planed.
- A sticking limit switch on TSV 2 was replaced.
e Plant Modification 91-012 was prepared to replace and upgrade the
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remaining TSV limit switches.
Other actions were taken which included evaluating the need for procedure improvements and training. The above actions appear to adequately address the problems identified as a result of the scram.
(Closed) LER l-92-003, Unit 1 Primary Uninterruptable Power Supply Internal Failure Results in a Reactor Scram. The failure of UPS specific components were repaired or replaced prior to unit restart. The-licensee expanded their corrective action to provide for generic replacement of several failed parts on other UPS units in Units 1 and 2.
The replacement of UPS parts, with the exception of three Modulation Index Cards (MIC), was discussed and evaluated in Inspection Report 325,324/
92-42. The remaining MIC cards were replaced and tested in May 1993, under WR/JO 92-BBPZ1. - In addition to-the replacement of-UPS electrical components, the corrective actions also covered enhancements in the system and annunciator procedures for UPS units. The inspector verified that these procedural enhancements had been completed. During the UPS failure, the licensee also experienced problems operating the feedwater startup level control valves. This was attributed to debris in the instrument air system which caused the actuator to stick.
Instrument air filters were added to the operators under plant modification 89-001 for Unit 1 and 89-002 for Unit 2.
The inspector verified that these
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modifications had been completed on both units. Accordingly, it appears that the above UPS failure has been adequately addressed.
(Closed) LER 1-91-07, Improper Overcurrent Relay Setting Results in Generator Trip / Reactor Scram from 100% power. The event occurred as a result of an overcurrent relay not being returned to the correct setting-after calibration. Several equipment deficiencies were identified during the recovery from this event. These included:
e Failure of the 1A recirculation pump motor generator field breaker to latch. An investigation determined that the timer was faulty, so it was replaced.
These breakers are scheduled for inspection of proper contact spring pressure and overhaul in accordance with GE SIL 448 and NRC Information Notice 91-15.
- Binding of the 1A recirculation pump discharge valve (1-B32-F031A).
This thermal binding problem was fixed and training was provided to operators to increase their awareness of this potential occurrence.
This training included vendor and industry information on this item.
The licensee has a modification (PIDG0119A) to upgrade the discharge valves and provide a final solution on this problem. This item is scheduled for completion in 1996, e Thermal cycling of the B feedwater line as a result of cycling the startup level control valve. A NED analysis determined that this cycling had negligible effect on the structural integrity of this line.
- A cooldown rate of 170 degrees F/hr as measured on the reactor bottom head drain line. A technical support review (conducted as required by the TS action statement) determined that this did not exceed the margin to brittle fracture.
In addition, the affected relay was set correctly and the relays which had been calibrated by this maintenance group on Units 1 and 2 were visually verified to ensure that they had been returned to the correct setting after their last calibration. An additional review of the work done by this maintenance group also performed a HPES evaluation on this event.
These actions appear adequate to address the above problem.
(Closed) LER 2-91-012, Component Failure of the Reactor Water Cleanup
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System Outlet Flow (Return to the Reactor) Differential Pressure Transmitter Resulted in a Cleanup Leak Hi-Hi Alarm and Subsequent Initiation of an Engineered-Safety-Feature Isolation Signal.
The above resulted from the failure of a Rosemount 1153 differential pressure transmitter.
This component was new and had been in service approximately two weeks when the failure occurred..Since the unit was in
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cold shutdown, the component was not required.
It was jumpered out to i
permit the return of the RWCU system to service. The component was subsequently replaced and the defective one sent to the vendor to determine the cause of failure. The vendor's analysis was unable to identify any problems with the transmitter. This unit appears to be i
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operating satisfactorily at the present.
The circuitry involved will be replaced during system upgrades planned for the next refueling outage under modifications PM 91-038 and PM 91-039.
Since all corrective actions stated in the LER are complete, this item is closed.
(Closed) LERs 1-90-14 and 1-91-11, Unit 1 ESF/RPS Actuations Due To An Electrical Protection Assembly (EPA) Printed Logic Board (PLB) Failure on EPA Breakers 2 and 5, Respectively.
GE analysis of the PLB from EPA-5 revealed a defective electrolytic capacitor (C-II) as the cause of the failure.
Industry experience indicates that the electrolytic capacitors (C-11 and C-12) on other EPA Group 2 PLBs (GE part No. 147D8652G002) are subject to such failures after six years past their manufacture date.
According to the licensee, GE has indicated that Group 10 PLBs (GE part No.147D8652G010) are not susceptible to the same capacitor failures experienced with the earlier Group 2 PLBs.
The inspector confirmed that EPA 1-6 on both units either had Group 10 PLBs or Group 2 PLBs within the six year time frame.
As the remaining Group 2 PLBs are to be replaced before exceeding the six year time frame, and no further such failures have occurred, these LERs are closed.
(Closed) LER l-92-002, Automatic ESF Actuation of the Control Building Emergency Air Filtration (CBEAF) System Due to Simultaneous Fire Alarms in Two Cross Zones of the Control Building. The alarms were caused by cooking in the control room kitchen and a person smoking in the secondary alarm station (SAS).
As detector sensitivity (directly affected by detector cleanliness) prevented the immediate resetting of the kitchen alarm, the control building and local fire alarm panel had been placed in
" silence" and forgotten until the SAS alarm completed the CBEAF actuation logic.
Silencing the panel alarm also prevented the remaining detectors in the affected fire detection zone from initiating an alarm.
Licensee evaluation of the event revealed two key issues:
(1) an LC0 (i.e.,
hourly zone fire watch) was not initiated as required when the panel alarm was silenced; and (2) fire detectors had never been cleaned on a regular basis.
The inspector verified the licensee's corrective actions, which included:
incorporation of this event into operator training; issuance of a preventive maintenance procedure to check detector sensitivity and clean accordingly (0PM-DET-005, Sensitivity Check for Pyrotronics Ionization Detectors); prohibition of smoking in the SAS; and revision of 0 APP UA-27, Annunciator Procedure for Panel UA-27, to address actions for minimizing CBEAF actuations due to nuisance alarms. After confirming that the periodicity of OPM-DET-005 is to be determined once initial performance is completed,-the inspector considered the licensee's corrective actions to be appropriate.
(Closed) LER 2-91-018, Reactor Building Ventilation Isolation and Standby Gas Train Start Due To Low Level 2 Actuation Caused By Reactor Level Instrumentation Reference leg Perturbation.
This event occurred as the result of a hydraulic perturbation when an I&C technician returned a reactor pressure indicator to service without first venting the test pressure.
Since this instrument shared a common reference leg with the i
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reactor water level instrumentation, the pressure perturbation was sufficient to generate a reactor water low level 2 signal that resulted in the above actuations.
Since the unit was in a refueling outage with the reactor vesscl head removed, this event posed only minimal safety significance.
To verify the cause and gain a better understanding of the above event, the licensee developed a special procedure to recreate it. This event, the circumstances surrounding it, and the preventive measures were incorporated into I&C training. The personnel responsible were-additionally counselled on this event. A HPES evaluation was performed and the results were also incorporated into the above training to increase technician awareness of the potential for this and similar events.
(Closed) LER 2-91-11, Potential Leakage Past Reactor Water Cleanup System Primary Containment Inlet Isolation Valves May Have Resulted in a Primary Containment Penetration Not Being Completely Isolated. This event was identified while returning RWCU to service. Testing by the licensee verified that with a differential pressure across the inboard and outboard valve, the valves would adequately seat.
Problems associated with indicating lights were fixed and further investigation revealed a generic problem with the double disc gate valves used in this and.some similar installations. The above valves were local leak rate tested during the subsequent outage and repaired as needed. The licensee submitted a 10 CFR 21 report on the Anchor Darling Valves for this and similar installations. 'The valve manufacturer has provided service as requested by the licensee to re-machine and rebuild parts as necessary on problem valves and in stock replacement parts for these type valves.
The inspector will continue to monitor the licensee's LLRT program for additional failures and to determine the full effectiveness of the
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vendor's and licensee's corrective actions.
(Closed) LER 2-91-05, ESF Actuation caused by. Voltage Regulator Transient with Failure of Primary Containment Isolation Solenoid Operated Valves.
This event occurred while switching the main generator voltage regulator i
from automatic to manual as a part of a routine operational test. When the transfer occurred, a momentary voltage dip resulted in a half scram, DG auto start, and several group and half group PCIS isolations. The Group 2 isolation sent a closure signal to the outboard drywell floor / equipment drain (DW&ED) valve 2-G16-F004, which failed to close.
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Operations transferred the voltage regulator back to automatic and recovered from the voltage transient.- The F004 valve was declared inoperable. This required closing the-inboard isolation-valve F003.
This valve required four attempts to close. As a result, both of these ASCO solenoid valves were changed out and satisfactorily retested.
Extensive troubleshooting of the generator voltage regulator identified i
several minor connection problems. These were repaired and the manual and automatic voltage regulator circuit boards and setpoint
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potentiometers were replaced. An open circuit resistor was also replaced on the automatic circuit.
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After replacement of the DW&ED valves, the licensee performed extensive testing to determine the cause of the failure. The licensee secured the services of a consultant to provide additional testing for root cause.
The licensee and consultant determined the root cause to be gelling of Dow Corning 550 lubricant used in assembly of the ASCO actuator, as well as foreign material / residue from manufacture / assembly. The manufacturer disagreed with the conclusion. The license has completed the corrective actions stated in the LER. They have increased the frequency of cycling Unit 1 and Unit 2 ASCO normally energized solenoid valves to weekly.
They have additionally placed these valves in an annual replacement cycle until an industry solution can be developed for this problem. A FACTS action item (93B9079) has been developed and sent to NED to find and implement a long-term solution.
In addition, the licensee continues to pursue long-term aging tests on sample valves at the Harris E&E Center.
The licensee has indicated that they will change out ASCO normally energized valves on Units 1 and 2 when an acceptable substitute becomes available, and will continue the above testing and annual like-replacement until that time. The inspector considers these actions adequate to preclude similar events.
8.
Exit Interview (30703)
The inspection scope and findings were summarized on June 4 with those persons indicated in paragraph 1.
The inspectors described the areas inspected and discussed in detail the inspection findings addressed below and in the summary. Dissenting comments were not received from the licensee.
Proprietary information is not contained in this report.
Item Number Description / Reference Paraaraoh 324/93-23-01 NCV - Failure to Implement a Technical Specification Action, paragraph 4.
9.
Acronyms and Initialisms AC Alternating Current ALARA As Low As Reasonable Achievable A0 Auxiliary Operator A0G Augmented Offgas Panel APRM Average Power Range Monitor ASCO Automatic Switch Company ATWS Anticipated Transient Without Scram CAC Containment Atmospheric Control
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CBEAF Control Building Emergency-Air Filters =
C0 Control Operator CP&L Carolina Power & Light Company CST Condensate Storage Tank CV Control Valve DBE Design Basis Earthquake DW&ED Drywell Floor and Equipment Drain E&E Energy & Environment ECCS Emergency Core Cooling System
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4 EDG Emergency Diesel Generator EER Engineering Evaluation Report EHC Electro Hydraulic Control System EPA Electrical Protection Assembly ERFIS Emergency Response Facility Information System ESF Engineered Safety Feature F
Degrees Fahrenheit FACTS Facility Automated Commitment Tracking System GE General Electric Company GET General Employee Training GP General Procedure
HP Health Physics HPCI High Pressure Coolant Injection HPES Human Performance Evaluation System HRA High Radiation Area I&C Instrumentation and Control INP0 Institute of Nuclear Power Operations 10E Industry Operating Experience LC0 Limiting Conditions for Operation
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LER Licensee Event Report LLRT Local Leak Rate Test LPCI Low Pressure Coolant Injection LPRM Local Power Range Monitor MIC Modulation Index Card MSL Main Steam Line
MSPS Main Steam Pressure Switch MST Maintenance Surveillance Test NAD Nuclear Assessment Department NCV Non-cited Violation NED Nuclear Engineering Department NRC Nuclear Regulatory Commission OP Operating Procedure PA Protected Area
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PCIS Primary Containment Isolation System PLB Printed Logic Board PM Plant Modification
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PMG Permanent Magnet Generator PMTR Post Maintenance Testing Requirements PNSC Plant Nuclear Safety Committee PSIG Pounds Per Square Inch Gauge PT Periodic Test
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QA Quality Assurance QC Quality Control
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RCIC-Reactor Core Isolation Cooling i
RFP Reactor Feed Pump RHR Residual Heat Removal R0 Refueling Outage RP Radiation Protection
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RPS Reactor Protection System RPV Reactor Pressure Vessel i
RTGB Reactor Turbine Gauge Board i
RWP Radiation Work Permit
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. Secondary Alarm Station SCO Senior Control Operator SP Special Procedure
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SR0 Senior Reactor Operator STA Shift Technical Advisor TCV Turbine Control Valve
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TIP Traversing In-Core Probe TS Technical Specification TSV Turbine Stop Valve UPS Uninterruptable Power Supply WCC Work Control Center WR/JO Work Request / Job Order
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