IR 05000171/1993003
| ML20035D002 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 04/02/1993 |
| From: | Anderson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20035D001 | List: |
| References | |
| 50-171-93-03, 50-171-93-3, 50-277-93-03, 50-277-93-3, 50-278-93-03, 50-278-93-3, NUDOCS 9304120027 | |
| Download: ML20035D002 (21) | |
Text
l
_._ _.
__
.
.
.
.. _ _
.
_ _._
. _ _ _ _
_ _ _
i I
.
U. S. NUCLEAR REGULATORY COMMISSION i
REGION I
Docket / Report No.
50-277/93-03 License Nos. DPR-44 50-278/93-03 DPR-56 50-171 Licensee:
Philadelphia Electric Company Peach Bottom Atomic Power Station P. O. Box 195 Wayne, PA 19087-0195 Facility Name:
Peach Bottom Atomic Power Station Units 1,2, and 3 Dates:
February 23 - March 29,1993 Inspectors:
J. J. Lyash, Senior Resident Inspector M. G. Evans, Resident Inspector F. P. Bonnett, Resident In tor B. S. Norris, Projec En m r Approved By:
/<
f4 9J C. J. Anliefson/ thief Date Reactor Projects Section 2B Division of Reactor Projects
9304120027 930405 PDR ADOCK 05000171
-.
., -
-
... - -. _ -.,., - ___.....
, -, -. _... _.. _ _.
,... -
. ~, -
....
. -
I
.
EXECUTIVE SUMMARY Peach Bottom Atomic Power Station Inspection Report 93-03
,
Plant Operations During a severe winter storm shift management displayed a cautious approach to the ongoing i
Unit 3 startup, sensitivity to personnel issues such as fatigue, and provided thorough updates on plant status and equipment problems to the NRC Resident Inspectors. The licensee's security staff appropriately implemented their contingency plans in response to problems, with the intrusion detection systems, created by the storm (Section 2.4).
During the period, a Unit 2 condensate pump tripped unexpectedly, resulting in feedwater pump trips and a reactor vessel low water level automatic scram. Following the scram, the high pressure coolant injection (HPCI) system initiated and injected, prompting declaration of an Unusual Event. Operator response to the scram was good, and the licensee performed a thorough investigation of the event. The reason for the condensate pump trip was not deter-mined conclusively. However, mis-operation of a valve control switch by an operator trainee l
was considered a possible cause (Section 2.1).
l In recovering from the scram discussed above, the Reactor Operator did not reset the HPCI initiation signal when securing the HPCI system from service. This oversight did not result in l
any operational problem, but did indicate some confusion regarding the proper application of HPCI operating procedures (Section 2.1).
Maintenance and Surveillance The licensee reduced Unit 3 power to facilitate repair of a defective main turbine master trip solenoid. While at reduced power, the 'C' reactor feedwater pump tripped due to a failed vibration sensor. The 'B' fecawater pump controller also failed. An automatic reactor vessel low water level scram occurred a short time later due to the loss of feedwater flow. The control room staff acted promptly to return the feedwater system to service, and to stabilize the plant (Section 2.2).
The licensee discovered that a relay in the HPCI auxiliary oil pump start circuit had failed.
This condition rendered the HPCI system inoperable for about eight hours. The licensee had experienced two other failures of this type of relay during the last year, in a limited population.
The licensee initiated short and long-term actions to address this apparent component reliability problem (Section 2.3).
The licensee identified that the containment atmospheric control (CAC) oxygen analyzer was out of calibration low. A narrow range calibration had not been performed following the recent plant startup. The staff took appropriate actions to evaluate the actual containment oxygen ii
i level, and also found that flow through the 'A' containment atmospheric dilution oxygen analyzer had degraded. The licensee corrected these physical problems, and initiated a review of procedure changes to ensure timely calibration of the CAC analyzer in the future (Section 2.5).
While performing planned preventive maintenance on a nonsafety-related electrical bus, a technician mistakenly opened an energized potential transformer compartment. This action caused an inservice condensate pump and reactor recirculation pump to trip, and a runback on the second recirculation pump. A plant scram occurred several hours later during recovery from this event (Section 4.1).
The licensee had previously received an Exigent Technical Specification Change to allow continued operation with one inoperable Unit 2 safety relief valve (SRV). During the inspection period, the licensee replaced the problem SRV and sent it offsite for testing (Section 4.3).
Engineering and Technical Suonort Stroke testing of Unit 2 main steam isolation valves (MSIV) indicated that inboard valve 80A had an unacceptably long closure time. The licensee's Technical and Maintenance staff, working with the valve vendor, identified the cause as internal binding due to inadequate clearance between the main poppet and valve bore. The licensee developed and implemented alterations to resolve the problem on valve 80A, implemented similar changes on valve 80C,
'
and reviewed the data associated with the remaining potentially affected valves (Section 4.2).
Assurance of Ouality As discussed above, a plant scram caused by a personnel error during performance of a bus cleaning maintenance activity and an unexpected condensate pump trip during recovery from that error occurred. Equipment problems associated with containment oxygen analyzers and a relay in the high pressure coolant injection system also led to some system operability concerns.
Investigations and corrective actions in response to these events were thorough and well focused. The licensee had previously intiated several programs to strengthen performance, that are responsive to these concerns. The occurrence of these events reinforces the importance of these ongoing efforts.
During the period, an inspector performed a special safety inspection of Peach Bottom Unit 1.
The licensee has established a program to monitor and maintain important Unit I structures and barriers.
iii
..
.
,-- _
-
... - --
.
.
.
.
..
- _ _.
.. _ _
_ -
_.
.
.
TABLE OF CONTENTS Page EXECUTIVE SUMMARY ii
......................................
1.0 PLANT OPERATIONS REVIEW
.............................
2.0 FOLLOW-UP OF PLANT EVENTS............................ 1 2.1 Unusual Event Declared Following a Unit 2 Reactor Scram
.........
2.2 Unit 3 Reactor Scram Due to Loss of Feedwater................ 2 2.3 Unit 2 High Pressure Coolant Injection System Declared Inoperable
....
2.4 Licensee Actions in Response to a Severe Winter Storm............
2.5 High Oxygen Concentration In the Unit 2 Containment During Power Operati on........................................ 6 3.0 SURVEILLANCE TESTING OBSERVATIONS..................... 7 4.0 MAINTENANCE ACTIVITY OBSERVATIONS.................... 8 4.1 Unit 2 Recirculation Pump Trip Due to Maintenance Personnel Error
...
4.2 Unit 2 Main Steam Isolation Valve Repair.................... 9 4.3 Unit 2 Safety Relief Valve Replacement I1
....................
5.0 RADIOLOGICAL CONTROLS..............................
6.0 PHYSICAL SECURITY
.................................
7.0 INSPECTION OF PEACH BOTTOM UNIT 1.....................
8.0 PREVIOUS INSPECTION ITEM UPDATE......................
9.0 M ANAG EMENT MEETINGS...............................
iv
, - _ _
... -.
_
. -.
...
,,
, _ _. _. _ _ _ _, _. _. _ _ _ _ _ _ _,. _ _. _... _ _ _. _.. _. _ _ _. _.
_
DETAILS 1.0 PLANT OPERATIONS REVIEW (71707)*
The inspectors completed NRC Inspection Procedure 71707, " Operational Safety Verification,"
by directly observing safety significant activities and equipment, touring the facility, and interviewing and discussing items with licensee personnel.
The inspectors independently verified safety system status and Technical Specification (TS) Limiting Conditions for Operation (LCO), reviewed corrective actions, and examined facility records and logs.
Both units began the inspection period operating at 100% power. During the second week of the period, Unit 2 scrammed due to a loss of feedwater. During the shutdown, the licensee made a drywell entry to replace the '71B' safety relief valve (SRV) and to perform corrective maintenance to the inboard 'A' and 'C' main steam isolation valves (MSIV). Unit 2 retumed to power on March 16, 1993, and remained at full power for the remainder of the inspection period.
About one week following the Unit 2 shutdown, Unit 3 scrammed due to a loss of feedwater.
The licensee made a drywell entry to repair several failed nuclear instruments. Unit 3 restarted on March 12, 1993, and remained at power until the end of the inspection period. During the start-up, the licensee responded to a failed bellows alarm on the '70' SRV. The licensee inspected the SRV, and vented minor moisture from 'he outer bellows area to correct the problem. A load drop was conducted late in the inspection period to clean the lube oil coolers for the reactor recirculation motor-generator sets.
2.0 FOLLOW-UP OF PLANT EVENTS (93702, 71707)
During the report period, the inspectors evaluated licensee staff and management response to plant events to verify that the licensee had identified the root causes, implemented appropriate corrective actions, and made the required notifications. Events occurring during the period are discussed individually below.
2.1 Unusual Event Declared Following a Unit 2 Reactor Scram On March 2,1993, at 6:40 p.m., an unplanned Unit 2 reactor scram occurred. The unit was operating at about 70% reactor power before the event, and operators were preparing to place the '2A' condensate pump in service. During performance of this activity, the '2C' condensate pump tripped unexpectedly. I.oss of the condensate pump caused a low reactor feedwater pump (RFP) suction pressure condition, and both inservice RFPs tripped. Reactor water level fell to below the Low Level scram setpoint, causing an automatic reactor scram. Vessel water level decreased briefly to -50 inches, causing an emergency core cooling system (ECCS) initiation and dual reactor recirculation pump trip. The high pressure coolant injection (HPCI) and
The inspection procedure from NRC Manual Chapter 2515 that the inspectors uml as guidance is parenthetically listed for each report sectio _ ___
,
l
reactor core isolation cooling (RCIC) systems initiated and injected to the reactor vessel. The licensee declared an Unusual Event (UE) due to the initiation and injection of ECCS in response to a valid signal. The licensee quickly returned one feedwater pump to service, and established reactor vessel water level control using the main condensate and feedwater system. They terminated the UE at 7:08 p.m., after the plant was stable and all isolation and initiation signals had been reset. The licensee notified the NRC of this event via the Emergency Notification System (ENS).
The licensee investigated the '2C' condensate pump trip, but could not determine the cause conclusively. At the time of the event, the reactor operator (RO) and an RO trainee (under instruction), were placing the 'A' condensate pump in service per system operating procedure (SOP) SO 5.1.B-2, " Placing Second and Third Condensate Pumps in Service." Data available after the scram showed that the "2C Condensate Pump Breaker Trip," and the " Condensate Header IAw Pressure" alarms were received. No electrical protective relay actuated to cause the trip, as indicated by the absence of protective relay flags at the breaker compartment. The licensee performed troubleshooting and testing on March 4, and verified that the protective relays and the breaker trip logic worked correctly. The only additional breaker trip signal is generated by closure of the pump suction valve. The inspector interviewed the RO and the RO trainee after the event. Both individuals stated that while the trainee had mistakenly closed the
'2C' condensate pump suction valve during the event, they believed it was after the RO had informed the trainee that the pump had tripped. The licensee was unable to confirm or refute the sequence described by the operators. The '2C' condensate pump was returned to service and operated without further incident.
The inspector reviewed GP-18, " Scram Review Procedure Check List," and attended the Plant Operations Review Committee (PORC) meeting on March 8, during which the event was discussed and the check list reviewed. At that time, PORC was concerned that the oversight of the trainee during the activities preceding the event did not meet management expectations. The PORC decided that additional guidance should be provided to the operating shifts, prior to plant restart, regarding conduct and control of on-shift training. On March 23, the inspector ques-tioned licensee management regarding the status of this guidance, and found that it had not been issued prior to the plant restart on March 15 due to a communication problem within the Operations Department. The inspector has reviewed licensee follow-up to PORC directives on several occasions in the past, with no deficiencies noted. The weakness in implementing the specific PORC directive regarding trainee oversight appears to be an isolated incident. The licensee issued Required Reading package RE-93-08A to the shifts on March 25. The inspector reviewed this package and found it to be appropriate.
2.2 Unit 3 Reactor Scram Due to Loss of Feedwater On March 7,1993, at 7:22 p.m., Unit 3 scrammed due to a loss of feedwater and subsequent reactor vessel low water level condition. The licensee had reduced reactor power to 23% to repair the master trip solenoid valve in the main turbine electro-hydraulic control system. The
'3C' RFP was in service, the '3B' RFP was in standby, and the '3A' RFP was running at the
_
i low speed stop of the motor gear unit. At this low power level periodic vibration alarms were
)
occurring on the '3C' RFP. The operators were taking actions to address the alarms when the
'
'3C' RFP tripped due to sensed high vibration. The RO immediately attempted to place the
'3B' RFP in service, but noticed that the pump controller had failed. Reactor level was decreasing as the RO attempted to place the '3A' RFP in service. Reactor water level fell to below the low level scram setpoint, causing an automatic reactor scram. The RO quickly restored reactor vessel water level control using the '3A' RFP. The licensee stabilized the plant and reset all initiation and isolation signals. The licensee notified the NRC of this event via the ENS.
The licensee inspected the '3C' RFP and determined that the pump had tripped on a false high vibration signal. Rough areas on the turbine shaft near the turbine outboard bearing had damaged the vibration probe tip. The rough areas may have developed as a result of poor lubrication caused by an incorrectly positioned oil nozzle. The licensee determined that the nozzle was improperly aligned during the last refueling outage in the Fall of 1991. The licensee i
repositioned the oil nozzle, and modified the vibration sensor mounting configuration to allow i
'
the tip to ride on a smooth portion of the turbine shaft. The shaft roughness will be addressed during the next refueling outage. The vibration probes and spray nozzles for the remaining Unit 3 RFPs were inspected and found to be satisfactory.
The licensee performed troubleshooting and testing on the '3B' RFP manual / automatic (M/A)
controller located on the control room panel. The licensee verified that the feedwater control logic up to the input of the controller worked correctly, and that the failure was isolated to the controller. The controller is a Moore Products Mycro 352 M/A controller. It functions as an j
input terminal to the digital feedwater control system (DFCS) computer chassis. The controller
'
provides a read out of the feedwater control system to the operator, but does not affect the DFCS, except when a change in bias is demanded by the operator. The DFCS tracks and holds
'
the most recent rational control signal for feedwater control. If the DFCS computer receives an invalid input signal, the computer will defer back to the most recent rational signal in memory. This DFCS design permits the removal, repair, and return to service of any discrete component while at power. The licensee determined that when the operators were attempting
to place the '3B' RFP inservice and the M/A controller failed, the DFCS had deferred back to the previous valid signal. The licensee replaced the controller, and returned the failed compo-nent to the manufacturer for evaluation. The results of the manufacturer's evaluation are expected about June 1993. This is the first failure of this kind to occur, and the licensee remains confident in the performance and reliability of the DFCS.
i The inspector reviewed GP-18, " Scram Review Procedure Check List," and attended the j
PORC meeting on March 8, during which the event was discussed and the check list reviewed.
'
The inspector reviewed the actions taken to troubleshoot and repair the '3C' RFP vibration problem, and the failed '3B' RFP M/A controller, and found them to be appropriate.
i
.
.
.
- - -
l
.
i 2.3 Unit 2 High Pressure Coolant Injection System Declared Inoperable
,
On March 3,1993, with the unit in cold shutdown, the licensee discovered that the HPCI system had been inoperable for about eight hours immediately following the Unit 2 reactor scram described in Section 2.1 During the scram on March 2, the HPCI system automatically initiated and injected to the vessel. After the HPCI turbine was secured, the auxiliary oil pump
,
(AOP) was left running for about one hour to ensure proper lubrication until the turbine shaft came to a complete stop. The RO then manually secured the AOP and placed the handswitch in ' Auto'. However, in removing the HPCI system from service the RO had not reset the initiation signal, and relay 23A-K24 remained energized. With the 23A-K24 relay energized and the AOP control switch in the ' Auto' position, the AOP should have continued to run. The l
fact that the AOP stopped when it was secured with an active initiation signal present, indicates that the pump start circuit was defective. Without an operable AOP, the HPCI system was
,
unable to automatically perform its safety function from the time the AOP was secured, until the reactor pressure dropped below 105 psig.
The licensee did not recognize this condition until later that day, when it was noticed by the I
System Manager (SM). The SM informed shift management of the condition. The AOP was successfully started after several attempts by the RO. The licensee performed pick-up and drop-out testing of all contactor coils and relays in the AOP motor controller. The licensee found i
that the time armature acceleration (TA) relay, which drops out starting resistance to the AOP motor armature, was operating intermittently. The TA relay is normally energized when the AOP is not running. In this state, the TA relay auxiliary contacts are closed. The auxiliary
'
contacts are in series with the coil for the main line contactor which starts the pump motor.
The licensee concluded that the mis-operation of the TA relay prevented the main contactor
!
from pulling in. The licensee replaced the TA relay, retested the AOP response and declared it operable.
The inspector expressed concern that this was the third incident caused by the mis-operation of this type of relay within the past year. Licensee management was aware of this issue, and directed the Technical Department to evaluate HPCI system performance and to make recom-mendations for improvements. Recommendations being developed included upgrading the motor controllers, new flow controllers, and installation of improved oil system piping and instrument racks. The licensee is developing a temporary plant alteration (TPA) to jumper the TA relay auxiliary contacts in all HPCI and RCIC motor controllers as a short-term corrective action to prevent further TA relay mis-operation. This TPA will exist until the individual controller is replaced or upgraded.
The inspector interviewed licensed operators, reviewed SOPS, and reviewed the HPCI logic schematic drawings to determine the causal factors that contributed to this event. The inspector concluded that the licensee had adequately evaluated the hardware failure associated with the incident. The inspector asked a number oflicensed operators how the HPCI system is normally secured following an automatic initiation and vessel injection. A majority of the operators from j
memory demonstrated that they would have shutdown the HPCI system per SO 23.2.A-2,
.
-_
_
.
.
.-
. ~
.__._,. - - -- -,
.-
__
..
..
.-
..
.
.
-
.-
"HPCI System Shutdown and Return To Standby From Operation." This procedure gives direction to the operators for securing the HPCI system if an initiation condition is present and the HPCI system is not required to be in service to provide vessel level control. The inspector determined that the implementation of this procedure during a normal scram was not appropri-ate. The system shutdown procedure described in SO 23.7.A-2, "HPCI System Automatic Initiation Response," specifically applies to occasions when HPCI injection is not necessary to maintain vessel level and the initiation condition no longer exists. Procedure SO 23.7.A-2 directs the operator to reset the system initiation logic prior to HPCI system shutdown. The inspector noted from the operators responses, that the operators who shutdown the HPCI system using procedure SO 23.2. A-2, did not reset the initiation logic when they simulated securing the AOP. The fact that the operator did not reset the initiation signal when securing HPCI did not contribute to this event. However, it does indicate some confusion concerning HPCI SOP application.
The inspector discussed the operator responses with Operations Department management. The licensee agreed that a weakness existed in the operators awareness of the existing SOP differ-ences for HPCI system shutdown for specific plant conditions. They further stated that most operator training concentrates on higher level scenarios, and a HPCI shutdown with initiation conditions present are reviewed more frequently. The licensee agreed to review HPCI SOPS and system shutdown during the current licensed operator requalification training. The licensee also directed the technical staff to review the HPCI SOPS for the purpose of improving the current procedure format. The inspector considered these actions to be adequate.
2.4 Licensee Actions in Response to a Severe Winter Storm During the inspection period the plant was subjected to a severe winter storm, resulting in high winds and substantial snow accumulation. At the time of the storm Unit 2 was in cold shut-down and was preparing for startup, and Unit 3 was operating at low power and proceeding with startup from a forced outage. On March 12, 1993, the inspectors reviewed the licensee's preparations for coping with the impending storm, and discussed them with licensee manage-ment and staff. The inspector found that the licensee's preparations included: 1) securing or
)
protecting externally located equipment and structures that might be affected by high winds; 2)
'
augmenting the operations, radiological controls, maintenance and security staff on-duty during the expected storm arrival time; 3) discussing potentially relevant Emergency Action Levels and their interpretation, and 4) reviewing the plans for Unit 3 power ascension and Unit 2 startup.
The inspector concluded that the licensee had adequately prepared for the expected weather conditions.
Beginning on the evening of March 12, and continuing until the afternoon of March 14, the inspector maintained periodic telephone contact with the control room staff. The items dis-cussed on each telephone call included: 1) the local status of the storm and any impact on plant operation; 2) the affect of the storm on offsite power reliability; 3) the performance and physical condition of the onsite staff; 4) Unit 3 power ascension progress and any related equipment problems, and 5) the status of impediments to site access and plans to address them.
-
l
.
i l
l
On March 14, about 1:00 a.m., the licensee informed the NRC via the ENS, that snow accumu-
,
l lation and drifting had prevented access to the site during the preceding eight hours. The licensee was able to maintain acceptable staffing levels using the onsite personnel, including rotation of individuals off-duty to allow adequate rest. The msponse of the licensee staff, particularly operations shift management, during the event was commendable. During discus-sions with the inspector, shift management displayed a cautious approach to the Unit 3 startup, sensitivity to personnel issues such as fatigue, and freely shared information on plant status and equipment problems. The licensee's security staff appropriately implemented their contingency plans in response to problems with the intrusion detection systems created by the storm. Some of the security protected area boundary compensatory measures implemented due to the snow accumulation remained in affect for several days.
l
'
The NRC elected to staff the Region I Incident Response Center (IRC) during the storm. The inspectors provided plant status briefings to the responsible NRC Region I management in support of periodic conference calls held by NRC management in the IRC to review the status of all operating units.
2.5 High Oxygen Concentration In the Unit 2 Containment During Power Operation At 5:35 p.m. on March 23,1993, the licensee initiated a calibration of the containment atmo-sphere control (CAC) oxygen analyzer, after a local drywell oxygen grab sample showed that the analyzer was reading about 1.5% lower than the grab sample results (2.6% versus 1.1%).
The calibration verified that the oxygen analyzer was reading 1.5% low. Following calibration of the analyzer, drywell oxygen concentration was between 2.1 and 2.3% and torus oxygen concentration was between 3.4 and 3.6%. When the calibration was completed, the "Drywell High Oxygen" alarm in the control room was received as expected (setpoint is 3.5%). At 8:00 p.m., on March 23, the Unit 2 RO placed the containment atmosphere dilution (CAD) analyzers in service to provide additional oxygen concentration monitoring capability. The CAD analyz-ers require a four hour warm-up before use. At 12:00 a.m., the in-service CAD analyzers indicated that drywell oxygen concentration was between 2.3 to 2.4%, which agreed with the CAC analyzer. However, torus oxygen concentration indicated 4.6% on the 'D' CAD analyzer and 5.4% on the 'A' CAD analyzer. Unit 2 was operating at about 100% power. The TS re-
quire that primary containment oxygen concentration be maintained below 4% with the unit in the run mode. The purpose of this limit is to preclude the creation of a combustible hydrogen-l oxygen mixture following a design basis accident. If this limit cannot be met, the plant must l
be placed in cold shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The licensee initiated a plant shutdown at 12:20 l
a.m. on March 24, and informed the NRC of the event via ENS. The licensee performed l
containment inerting activities in parallel with the plant shutdown. By about 5:00 a.m. on
'
March 24, the licensee had reduced primary containment oxygen concentration to less than 4%,
and terminated the plant shutdown.
At the time of this event, the licensee verified that the 'A' and 'B' instrument air backup valves l
and manual bypass valves were closed, and the service air supply to the drywell was isolated.
l
!
._ __
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. _ _
The Unit 2 plant operator round sheets indicated that the 'A' nitrogen compressor had been running approximately two hours per day. Based on this, the licensee concluded that the increase in oxygen concentration had not been caused by instrument air intrusion to containment but was consistent with that observed during normal operation.
The licensee had inerted the containment on March 16 and 17, during plant start up, per procedure SO 7.B.1.A-2, " Containment Atmosphere Inerting."
Following completion of inerting, Step 4.23 of SO 7.B.1.A-2 directs operations to notify I&C technicians to perform Routine Test RT-I-07D-210-2, " Containment Oxygen Analyzer Calibration and Drain Pot Draining." Performing this RT gives the licensee added assurance that the CAC oxygen analyzer is functioning properly on the narrow range. However, the oxygen analyzer was not calibrated following completion of the inerting. The inspector interviewed the Unit 2 RO and the I&C technicians on shift on March 17 and reviewed applicable logs. The inspector was unable to confirm whether Operations had appropriately notified I&C regarding performance of RT-I-07D-210-2. If the test had been performed, the licensee would likely have identified the increasing oxygen earlier. In response to this weakness the licensee plans to add performance of the RT to the plant start-up procedure, GP-2, as a signed step.
During the inerting process following discovery of the elevated oxygen levels, the 'A' CAD analyzer did not respond properly. Licensee investigation identified that the analyzer flow was not adequate and declared it inoperable. Subsequent calibration of the 'D' CAD analyzer indicated that it was reading about 2% high. Based on the observed CAD analyzer inaccura-cies, the re-calibrated CAC analyzer reading of 3.6% and the drywell grab samples data, the licensee concluded that the 4% TS limit was not violated. After the close of the inspection period the licensee retracted their ENS report for this event. The licensee had been aware 4 CAC analyzer reliability problems. In response, they have implemented a program of weekly confirmatory grab samples. In addition, the licensee has developed a modification to replace the CAC and CAD analyzer with new equipment. The new system will include redundant instruments continuously inservice. This modification will be installed during the next outage.
The inspector concluded that the licensee had taken appropriate action.
3.0 SURVEILLANCE TESTING OBSERVATIONS (71707)
The inspectors observed conduct of surveillance tests to verify that approved procedures were being used, test instrumentation was calibrated, qualified personnel were performing the tests, and test acceptance criteria were met. The inspectors verified that the surveillance tests had been properly scheduled and approved by shift supervision prior to performance, control room operators were knowledgeable about testing in progress, and redundant systems or components were available for service as required. The inspectors routinely verified adequate performance of daily surveillance tests including instrument channel checks and jet pump and control rod j
operability. The inspectors found the licensee's activities to be acceptable.
. -
.
. -
i l
l
'
4.0 MAINTENANCE ACTIVITY OBSERVATIONS (62703,93702)
The inspectors observed podions of ongoing maintenance work to verify prop:r implementation of maintenance procedures and controls. The inspectors veri 6ed proper implementation of administrative controls including blocking permits, fire watches, and ignition source and radiological controls. The inspectors reviewed maintenance procedures, action requests (AR),
l work orders (WO), item handling reports, radiation work permits (RWP), material certifica-tions, and receipt inspections. During observation of maintenance work, the inspectors veri 6ed
'
appropriate QA/QC involvement, plant conditions, TS LCOs, equipment alignment and turn-over, post-maintenance testing and reportability review. The inspectors found the licensee's activities to be generally acceptable. Three of the major maintenance activities evaluated by the inspectors are discussed in detail in the following sections.
4.1 Unit 2 Recirculation Pump Trip Due to Maintenance Personnel Error On March 2,1993, at about 11:00 a.m., the Unit 2 '2A' reactor recirculation pump and '2A'
l condensate pump tripped while the Unit was operating at 100% power. The trip of the conden-j l
sate pump with the reactor at greater than 90% power, caused a 60% run back of the '2B'
reactor recirculation pump and reactor level increased to +33 inches. Per Operational Tran-i sient Procedure OT-112, " Recirculation Pump Control," the RO inserted all Table One control l
rods, and at 11:05 a.m. reactor power was stable at 40%. The shift quickly identified that the
!
recirculation and condensate pump trips had been caused by a maintenance worker at the #1 j
13kv auxiliary bus, and began preparations for restarting the '2A' recirculation pump. At 12:00 j
p.m., the '2A' recirculation pump was restarted. The inspector observed activities associated with the restart of the pump and found the shift's actions to be acceptable.
The maintenance worker, an electrician assigned to the Transmission & Distribution Services Department - Hi-Volt Group, was given the task to doble test the #2 start-up bus (00A005)
potential transformer (PT) located in #1 auxiliary bus compartment 14. The worker had just completed similar doble testing of the #2 SU-B bus (00A03C) pts (two transformers located in
,
!
the same PT drawer). He then located the #2 start-up bus PT drawer (XPT-2-53-0114L). This drawer was found open and red tagged as part of the clearance to perform maintenance on the
- 2 start-up bus. The maintenance worker expected to see two transformers as with the just i
completed testing at the #2 SU-B bus. Seeing only one transformer in the open drawer, he l
opened the PT drawer (XIrr-2-53-0114U), located directly above XPT-2-53-0114L. Several seconds after opening this drawer, he heard relays operate and several breakers trip, and he
!
immediately re-closed the drawer. Opening the #1 auxiliary bus PT drawer simulated a bus under-voltage which caused all rotating equipment on the bus to shed. The '2A' recirculation and condensate pumps were in service being fed by the bus and tripped.
The inspector interviewed the maintenance worker following the event. There is a warning label on the front of drawer XPT-2-53-0114U which states that " opening this door will cause a bus under-voltage trip." The worker stated that while scoping out thejob, he was looking for
_
a second PT to doble test, and assumed that all drawers in that cabinet were de-energized.
After opening the drawer, he saw the sign and realized that the drawer was energized.
The licensee investigated the event (RE/EIF 2-93-087) and preliminarily identified the causes as being 1) failure of the worker to determine what effect his actions would have if he opened the IYr drawer, and 2) there was no formal method in affect to inform a worker from an outside work group of the equipment boundaries and job scope. A generic implication of the event was that the work groups not assigned to the station may not be sufficiently familiar with station equipment and its physical arrangement. In response to the event, the Electrical Maintenance Foreman held a discussion with his work group to stress the importance of self-checking, using this event as an example of insufficient self-checking. The licensee is considering additional corrective actions which include, locking of PT drawers to prevent inadvertent removal, and including specific instruction and sign off steps on bus maintenance WOs that equipment has been identified and job scope discusse<1 with the outside work group. The inspector reviewed the WO for cleaning of the 13kV bus (R0044097), Maintenance Procedure M-054-002, and RE/EIF 2-93-087. The inspector discussed the investigation results and preliminary corrective actions with licensee personnel. The inspector found the licensee's actions in response to this event to be acceptable, and had no further questions.
4.2 Unit 2 Main Steam Isolation Valve Repair On March 2,1993, the licensee was placing Unit 2 in a cold shutdown condition following the scram described in Section 2.1.
During the cooldown, the licensee cycled the inboard and outboard MSIV to collect stroke time data. During the test the inboard MSIV 80A took over 18 minutes to pick up the full closed limit switch. This stroke time was not within the accept-able closure time of three to five seconds. The licensee continued the plant cooldown and deter-mined that a drywell entry was required to inspect the MSIV.
The inboard MSIV 80A was one of two MSIVs that failed a quarterly stroke time ST during the planned Unit 2 shutdown in January 1993 (Inspection Report 50-277/278 92-32). During that
test, the MSIV 80A never indicated full closed and the MSIV 80C took about 47 minutes to i
close. At that time the licensee removed and rebuilt the valve operator air manifold and
inspected MSIV externals during valve operation. The MSIVs retested satisfactorily. The
,
licensee proposed an interim MSIV testing program that included additional stroke time testing.
i
]
The licensee planned to return to the quarterly test frequency if all test results were satisfactory.
During the current shutdown, the Shift Manager made the decision to stroke the MSIVs. The i
'
j test was not part of the interim testing program, but an initiative of the Shift Manager to collect
empirical valve data at similar plant conditions to those during the MSIV stroke time testing
performed in January. All of the MSIVs, except the 80A, stroked satisfactorily.
i During the last Unit 2 refueling outage, the licensee had replaced the MSIV poppets on the four inboard MSIVs with a new nose-guided poppet assembly. The new poppet has an extend nose
,
guide design that enhances valve seating and ensures a better leak tightness. The licensee had to build-up the stellite seating surface in the valve body for the MSIV 80C and had to com-
..
.
--
pletely replaced the stellite surface in the MSIV 80A valve body. The licensee machined the new poppets to custom fit them for each individual MSIV. The valve vendor specified that the clearances between the poppet nose and the valve body be 0.010 to 0.015 inches. The actual as-left clearances for MSIV 80A and 80C were 0.010 inches. These were the two MSIVs that displayed the slow closure times.
In response to the most recent failure, the licensee disassembled MSIVs 80A and 80C and inspected the poppet, air manifold, and actuator piston. A representative from the MSIV vendor, Atwood and Morrill Co., was present for the valve inspection and collection of as-found valve component dimensions and clearances. The licensee and vendor representative reviewed the mapping data for the MSIV and determined that the clearances between the valve poppet and valve body were tighter than expected. The licensee concluded that the inadequate clearances on these two valves caused them to bind just before reaching the full close position.
This binding occurred only under no-flow conditions, and during plant cooldown. Flow through these valves would have helped to seat the poppet. The licensee believes that during plant cooldown, thermal considerations aggravated the clearance problem, making binding more likely.
The licensee machined the MSIV 80A and 80C poppets to provide.020 inches clearance between the poppets and valve bore, reassembled the valve, and performed kx:al leak-rate testing (LLRT). The MSIV 80C initially failed its LLRT. Further inspection by the licensee found a small flaw in the upper bore area that was interfering with the poppet, preventing it from attaining a proper seat. The licensee was also required to lap the seating surfaces. The MSIV 80C was reassembled and retested satisfactorily. Although the licensee had not experi-enced any problems with MSIVs 80B and 80D, they reviewed the mapping data to assess the clearances. The licensee determined that sufficient clearances existed for those MSIVs, and that disassembly was not required.
The licensee performed as-left stroke time testing and found all of the MSIVs to be satisfactory.
MSIV stroke time testing was also performed prior to the restart of Unit 2 and during power ascension with satisfactory results. The licensee concluded that the tight clearances between the poppet nose guide and valve body were the cause of the MSIV slow closure times, and that the actions taken during the outage had resolved the problem. The licensee does not intend to
.
continue with accelerated MSIV surveillance testing due to the extent of the correct maintenance performed, valve information obtained, and vendor recommendations.
The inspectors, with assistance from an NRC Region I specialist, reviewed the engineering change request for the poppet replacement, applicable drawings, and technical information relevant to the Atwood and Morrill MSIVs. The inspectors observed portions of the mainte-nance activities during the troubleshooting, valve repair, and testing phases. The inspectors also inspected the internals of the disassembled MSIVs in the drywell and reviewed the licensee's conclusions. All of the maintenance activities were well managed and planned, and carefully performed. The inspectors concluded that the licensee had taken reasonable action to evaluate and correct the cause of the slow MSIV closure times, and to ensure acceptable performance.
.
4.3 Unit 2 Safety Relief Valve Replacement During the Unit 2 outage, the licensee replaced the '71B' SRV. The SRV had brought in a failed bellows alarm during the Unit 2 start-up on January 17, 1993. Based upon their investi-gation of the bellows problem and vendor recommendations, the licensee applied for and received an Exigent TS Change to relax the 30 day TS LCO for one failed SRV, The TS change allowed the licensee to continue plant operations until the next shutdown of reasonable duration requiring a drywell entry, not to exceed February 28,1994. After removing the valve,
the licensee sent it to Westinghouse Corporation for as-found inspection and evaluation for the actual cause of the failure. The licensee anticipates the results of the evaluation by the end of May. The new SRV was installed and tested satisfactorily during the Unit 2 power ascension.
The inspectors made a tour of the Unit 2 drywell before startup and inspected the new SRV.
The SRV electrical connections were properly made-up and its insulation was properly installed.
The inspectors had no further questions at this time.
l 5.0 RADIOLOGICAL CONTROLS (71707)
The inspectors examined work in progress in both units to verify proper implementation of health physics (HP) procedures and controls. The inspectors monitored ALARA implemen-tation, dosimetry and badging, protective clothing use, radiation surveys, radiation protection instrument use, and handling of potentially contaminated equipment and materials. In addition, the inspectors verified compliance with RWP requirements. The inspectors reviewed RWP line entries and verified that personnel had provided the required information. The inspectors
,
!
observed personnel working in the RWP areas to be meeting the applicable requirements and individuals frisking in accordance with HP procedures. During routine tours of the units, the inspectors verified a sampling of high radiation area doors to be locked as required. All activities monitored by the inspectors were found to be acceptable.
l 6.0 PHYSICAL SECURITY (71707)
The inspectors monitored security activities for compliance with the accepted Security Plan and
.
associated implementing procedures. The inspectors observed security staffing, operation of the l
Central and Secondary Access Systems, and licensee checks of vehicles, detection and assess-ment aids, and vital area access to verify proper control. On each shift, the inspectors observed protected area access control and badging procedures. In addition, the inspectors routinely l
inspected protected and vital area barriers, compensatory measures, and escort procedures. The
!
inspectors found the licensee's activities to be acceptable.
l l
l l
.
l
.
7.0 INSPECTION OF PEACH BOTTOM UNIT 1 Peach Bottom, Unit 1 (PB1), was a 40 Mwe high-temperature gas-cooled reactor (HTGk), built by Philadelphia Electric Company (PECo), as a prototype to demonstrate the feasibility of a large HTGR commercial power plant. PB1 began commercial operation in June 1967, operated j
thorough two fuel cycles, and ceased operation on October 31, 1974. A Possession Only License (POL) was issued to PECo in July 1975, at which time " decommissioning" activities were started; decommissioning was complete in January 1978. For PB1, decommissioning involved placing the systems and structures in a SAFSTOR condition until such time that Peach Bottom Units 2/3 (PB2/3) are ready for decommissioning. Under SAFSTOR, the facility is maintained in a condition that allows it to be safely stored and subsequently decontaminated, at a later date, to a level that permits release for unrestricted use. Much of the office space outside of the exclusion arcs is used for administrative and training support to PB2/3 activities.
During the period, an inspection was conducted by the NRC of activities at PBl. The purpose of the inspection was to verify that the requirements of the PB1 License and TS had been incorporated into the appropriate programs and procedures, and to determine if those programs and procedures were being properly implemented.
The as-found conditions of the unit were consistent with the requirements of the PB1 License and TS (through Amendment 7). The inspector identified no discrepancies. At the time of decommissioning, a fence was erected around the containment vessel and the spent fuel building to establish an exclusion area. Areas within the exclusion area have been decontaminatd or rendered inaccessible by barriers, areas outside of the exclusion area are decontaminated and void of radioactive material. All systems within the exclusion area are depressurized, de-energized (except for lighting energized during routine inspections), and drained of all fluids (oil, water, refrigerant). The administration of PB1 activities is in accordance with PB2/3 controls.
The inspector toured all accessible areas of PBl. Radiological and security controls were consistent with the " Final Report on Decommissioning of Peach Bottom Unit 1 [ July 1978]."
The radiological postings appeared to be the originals from 1978. No fire hazards were identified. The inspector questioned when the inaccessible areas of the exclusion area had last been toured to determine the status of security barriers, fire hazards, and radiological conditions and if periodic tours were warranted. Licensee representatives stated that those areas had been decontaminated and cleared of combustible materials during the initial decommissioning program. They determined that there was no justification for re-opening the areas.
The inspector identified two routine inspections required by the PB1 TS. The inspections have been incorporated into the PB2/3 surveillance program. The inspector reviewed the latest Surveillance Test (ST) for each and found them to be complete and in accordance with the TS:
" Monthly - Unit One Water Intrusion Inspection," ST-H-099-965-2, Rev. O, inspects accessi-
ble areas within the containment building for water accumulatio ____ __ ______________ ___
l
.
- " Unit One Exclusion Area Semi-Annual Inspection," ST-H-099-960-2, Rev. 2, inspects the exclusion area barriers for integrity, conducts a radiological survey of accessible areas, and
,
changes the high efficiency particulate filter on the containment breather penetration.
One minor administrative deficiency was identified during the review of the STs. The TS required that an administrative procedure be developed for notification of reportable events.
The two STs referenced different procedures for this reporting function. ST-H-099-965-2, issued in August 1992, referenced the correct procedure, LR-C-6, Rev 0, " Identification and Evaluation of Potentially Reportable Items and Events of Potential Public Interest," which was issued in February 1992. However, ST-H-099-960-2, issued in December 1992, referenced NA-020R001, a procedure of the same name which was superseded by LR-C-6. This was identified to the on-Shift Supervisor, who stated that the discrepancy would be corrected.
Fire Protection was a site-wide function, with PB1 contained in the Peach Bottom Fire Protec-tion Program. The fire brigade was required by the PB2/3 TS, comprised of PB2/3 on-shift personnel. The fire brigade was trained in the specifics of responding to a fire in PB1, there was portable fire fighting equipment at PB1, and a fire water standpipe was near the entrance to the exclusion area.
There was confusion on the part of the licensee as to whether or not the fire alarm pull-boxes inside containment are energized. The Safety Analysis Report (SAR) (Section 3.10.26) states that all electrical service is disconnected except for listed specific needs; yet, the Fire Protection Supervisor stated that he thought the pull-boxes were always energized. The licensee initiated a nonconformance report to document the discrepancy, and stated that the pull-boxes would be de-energized, or the SAR would be revised.
In accordance with the " Decommissioning Plan / Safety. Analysis Report," submitted to the NRC in July 1974, access to the exclusion area is via locked gates. Once inside the exclusion area, i
'
access to the containment vessel or the spent fuel building is via a second locked door. Due to the defueled condition of the plant, the prospect of radiological sabotage is minimal; the security fencing limits the access to radiologically contaminated areas.
The PECo Emergency Plan does not specifically address potential PB1 events. Events such as a fire at PB1 would not automatically direct the PB2/3 Shift Supervisor to initiate an Emergency Classification. The licensee evaluated this issue and concluded that PB1 had been considered in preparing the plan, but that a decision was made that its inclusion was not needed. An event at PB1 would be evaluated and classified in the same manner as events at other locations outside the switchyard.
The Quality Assurance / Quality Control (QA/QC) organization includes PB1 in the scheduled audit and inspection plans for the site. The routine surveillances are frequently monitored by QC, and QA performs an annual audit of the activities at PBl. The inspector reviewed the last audit report (A0167265, " Unit 1 Technical Specifications" [01/21-31/92]) and found that it was compliance oriented. The inspectors identified no significant deficiencies during the audi.
The inspector concluded that the licensee had established an adequate program to monitor the physical condition of important Unit 1 structures, in accordance with the facility licensee.
8.0 PREVIOUS INSPECTION ITEM UPDATE (92702, 92701)
(Closed) Unresolved Item 91-27-01, Evaluate Licensee Corrective Actions in Resoonse to Several Solenoid Operated Valve Reliability Problems.
During August,1991, the licensee reported that the RCIC system was inoperable due to a I
failure of a room cooler cooling water inlet valve to open on demand. The solenoid operated valve (SOV) that ports air to the inlet valve failed to change state when de-energized. Follow-up NRC inspection and licensee review identified several concerns. The inspector reviewed several of these concerns and updated this unresolved item in Inspection Report 50-277 and 50-278/92-04. At that time, the inspector found that the licensee was implementing adequate corrective actions to address the issues. However, the item remained open pending inspector review of 1) the finalized modification replacing the ASCO Model 206-832 SOVs that had exhibited the sticking problem, 2) the results of emergency diesel generator (EDG) air start system air quality testing and 3) licensee engineering review and disposition of SOV walkdown results. The inspector reviewed each of these items during the current inspection as discussed below.
The licensee had previously concluded that the SOV failures were due to break down of the silicon lubricant used during fabrication, causing adhesion between the plug nut and core. The failures occurred in normally energized SOVs because heat generated by the coil accelerated lubricant breakdown. The inspector reviewed Engineering Change Request (ECR)92-144 and Procurement Engineering Group (PEG) engineering evaluation No. 11689439. The licensee concluded that ASCO solenoid valve model X206-380-3RF, a lube-less version, was an accept-
,
able replacement for either model 206-832-3RF or 206-380-3RF. The licensee identified 30
,
applications in Unit 2 and 3 requiring lube-free construction due to their normally energized configuration during system operation. The inspector verified through review ofinformation in the Plant Information Management System (PIMS) that the licensee had replaced 29 of these valves. The one remaining valve, Unit 3 recirculation sample valve, SV-3-02-039, located in the drywell, was scheduled to be replaced during the next Unit 3 forced outage requiring a
,
drywell entry (WO C0139837).
The licensee performed an air quality test for the E-3 EDG starting air on October 1,1992.
Parameters tested included moisture content, particulate concentration and hydrocarbon concen-tration. The inspector forwarded the results of this air quality test to an NRC specialist in the NRC Office for Analysis and Evaluation of Operational Data, who did not identify any con
-
. -.
.
-
..
_. _. _
__
__
_
.
cerns. The licensee has not experienced a failure to start due to poor air quality, nor have any cylinder liner anomalies been attributed to poor starting air quality. The licensee blows down the starting air reservoirs for each EDG to rid them of accumulated oil and moisture daily per procedure SO 52A.8.A, " Diesel Generator Daily Shutdown / Pre-Start Inspection." The inspec-tor witnessed performance of this procedure for the E-1 and E-2 EDGs on March 23 and noted that no moisture had accumulated in the air start system.
The licensee performed an in-plant walkdown of all solenoid operated valves to identify mmu-facturer, model, installation configuration and other important design informatica.
The information was evaluated onsite. All immediately apparent discrepancies were documented using nonconformance reports (NCR). The results of the walkdown and the generated NCRs were sent to the licensee's corporate engineering organization for review and disposition. The inspector reviewed samples of the data collected during the walkdowns, the NCRs, and NCR dispositions. The licensee's documentation, assessment and final dispositions for the sample reviewed were acceptable.
(Closed) Unresolved Item 92-07-01, Control of Troubleshootine Activities.
i On March 16,1992, during performance of a HPCI surveillance test, the HPCI turbine exhaust line inboard isolation drain valve, AO-2-23-137, did not indicate closed when required. During troubleshooting, the System Manager (SM) exceeded the boundaries of the Troubleshooting
)
Control Form (TCF), by adjusting the valve stroke. Going beyond the approved TCF scope resulted in the valve being inoperable until a local leak rate test was completed. Procedure A-42.1, " Temporary Circuit Modifications During Troubleshooting Activities of Plant Equipment or Verification of Equipment Operability," requires that the individual responsible for imple-menting the approved troubleshooting follow the step-by-step methods and the specified bound-aries and scope of the TCF. The SM was newly assigned and had extensive experience with valves at a fossil plant, but had worked only briefly at Peach Bottom on balance-of-plant systems.
The inspector reviewed the licensee's Event Investigation Report (2-92-085) for this event. The licensee found that the SM had no formal training involving the TCP process and that there was no requirement for the SM to complete training or to be task qualified before performing the work. The SM and Shift Engineer involved had failed to recognize the change in the work scope and communicate it back to shift management for approval. Licensee immediate correc-tive action included coaching of the personnel involved and discussion of the event at a Techni-cal Section All Hands Meeting. The licensee also added troubleshooting training to the Techni-cal Staff Continuing Training Program. A summary of the event was provided to operations personnel, regarding the proper verification of valve indication problems, through Required Reading Package RE-92-26B on October 28, 1992. In response to other initiatives in the Technical Section, the licensee developed a " System Manager Qualification Guide." The Guice was approved on December 24,1992, and provides direction for training and evaluation of selected SM tasks. The inspector verified that the Guide includes specific task for performing system or equipment troubleshooting. The inspector also reviewed specific direction provided
-
-.
l l
a
\\
.
)
to task evaluators from Techaical Section management regarding what constituted acceptable performance of the troubleshooting task to allow signing of the Qualification Guide. Based on this review, the inspector found the licensee's actions in response to this issue to be acceptable.
(Closed) Violation 92-13-02, Failure to Operate The Reactor Water Clean-up System In Accordance With Procedures.
On July 27,1992, control room operators aligned the Unit 2 reactor water clean-up (RWCU)
system in a configuration that was not in accordance with the SOP. The operators were recovering from a recirculation pump trip and attempting to maintain the vessel dome to bottom head drain temperature differential limit of 145 degrees F. The operators aligned the RWCU system with three pumps in service and the demineralize bypass valve partially open. The resultant elevated RWCU system flow caused a high flow actuation of the primary containment isolation system which isolated the RWCU system.
The licensee has experienced several events in the past where system operation was not consis-tent with the SOP. In response to these discrepancies, the licensee Operations Department management issued a letter and met with each operating shift to communicate management's expectations concerning procedure usage. The licensee emphasized the importance of proper procedural adherence, and the need to submit procedure requests for activities not contained in a procedure and for procedure improvements. The licensee requested inputs from operations personnel to identify routine plant evolutions that are performed without procedural guidance, evaluated each of these inputs, and initiated appropriate procedure revisions. The licensee also revised Section 9, " Procedures and Operator Aids," of the Operations Manual (OM) to provide direction for operations personnel with respect to actions to be taken in the absence of a procedure.
The inspector reviewed the OM revision and the compiled list of evolution:, that may need enhanced procedural guidance. The licensee received about 65 submittals that have been priori-tized in order of their importance. The list is being evaluated by the Technical Department.
Procedures will be prepared by the Technical staff and submitted for Operations review throughout the remainder of the year. The inspector interviewed operations personnel regarding procedural adherence. All operators interviewed demonstrated that they were aware of manage-ment expectations regarding procedural adherence and were knowledgeable of the procedure generation and revision process found in Administrative Procedure AA-C-5, " Preparation and Control of Procedures." In addition, a special NRC assessment of operating activities, includ-ing operator reference to and use of procedure, was conducted during the week of March 22, 1993. The results of that inspection indicated good procedure application, and will be docu-mented in Inspection Report 50-277/50-278 90-08. The inspector found the licensee's actions in response to this issue to be acceptable.
l lL ;
,
,
-
9.0 MANAGEMENT MEETINGS (71707)
The Resident Inspectors provided a verbal summary of preliminary findings to the Peach Bottom Station Plant Manager at the conclusion of the inspection. During the inspection, the Resident Inspectors verbally notified licensee management concerning preliminary findings. The inspec-
,
tors did not provide any written inspection material to the licensee during the inspection. This report does not contain proprietary information. The inspectors also attended the entrance and exit interviews for the following inspections during the report period:
Dale Subject Report No.
Insoector 2/22-26/93 Access Control 93-05 Limroth 3/8-12/93 Requalification Exam 93-02 Florek 3/22-26/93 Operations 93-08 Hansell 3/22-26/93 Security 93-07 Della Ratta
_
__