IR 05000101/2002013
| ML17164A640 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna, 05000101  |
| Issue date: | 03/13/1995 |
| From: | Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17164A639 | List: |
| References | |
| 50-387-95-02, 50-387-95-2, 50-388-95-02, 50-388-95-2, NUDOCS 9503200028 | |
| Download: ML17164A640 (20) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION Inspection Report Nos.
License Nos.
Licensee:
REGION I
50-387/95-02; 50-388/95-02 NPF-14; NPF-22 Pennsylvania Power and Light Company 2 North Ninth Street Allentown, Pennsylvania 18101 Facility Name:
Susquehanna Steam Electric Station Inspection At:
Inspection Conducted:
Inspectors:
Salem Township, Pennsylvania January 1,
1995 February 13, 1995 M. Banerjee, Sen Re dent pector, SSES D. J.
ai, id r,
SSES Approved By:
lt le eactor Projects Section N
. 2A, 3 rs fs ate Scope:
Resident Inspector safety inspections were performed in the areas of plant operations; maintenance and surveillance; engineering; and plant support.
Initiatives selected for inspection were supplemental decay heat removal system installation, and licensee's troubleshooting and maintenance of ex-core neutron monitors.
Findings:
Performance during this inspection period is summarized in the Executive Summary.
Details are provided in the full inspection report.
9503200028 9503f3 PDR ADOCK 05000387
Operations EXECUTIVE.SUNDRY Susquehanna Inspection Reports 50-387/95-02;;50-388/95-02 January 1,
1995 February 13, 1995 The licensee operated the plant in a safe and reliable manner.
A Notice of Enforcement Discretion (NOED), requested by the licensee regarding an inoperable
"B" ex-core monitor, was granted on February 6, 1995.
The NOED permitted continued operation of the facility with the "B" ex-core monitor inoperable.
Section 2.3 pertains.
Naintenance/Surveillance The inspector observed that maintenance personnel performed work correctly during installation of the supplemental decay heat removal (SDHR) system.
However, the inspector identified continued administrative weaknesses regarding proper hot work practices.
Repeated maintenance on ex-core monitors did not result in reliable equipment.
In order to improve engineering support of ISC maintenance, the licensee is establishing a group of ISC engineers under nuclear systems engineering.
Section 3. 1.2 pertains.
Engineering/Technical Support Good questioning attitude and capability of licensee's engineering organization was reflected in identification and resolution of an engineering deficiency report.
During the process, the licensee identified a need for improved guidance in operability determination, and initiated action to address this matter.
Safety Assessment/Assurance of guality The inspector found the Plant Operation Review Committee (PORC) review of the safety evaluation for the design and operation of the supplemental decay heat removal (SDHR) system was critical and focused on safety.
Four Licensee Event Reports (LERs) are closed during this inspection period.'
SUMMARY OF FACILITY ACTIVITIES Susquehanna Unit 1 Sumaary The inspection period began on January. 1, 1995 with Unit 1 at 100X power.
Several minor power reductions were performed throughout the period to facilitate on-line Hydraulic Control Unit (HCU) maintenance.
On January 21, at approximately 11:05 a.m., Unit 1 experienced a very short electrohydraulic control (EHC) transient which resulted in turbine control valve and bypass valve movement.
The licensee performed an investigation and replaced an electrical power supply.
On February 9 another EHC perturbation occurred.
Section 3. 1.3 pertains.
On February 10, reactor power was reduced to 80X to perform a control rod sequence exchange.
Unit 1 was operating at 100X power at the completion of the inspection report period.
Susquehanna Unit 2 Summary Unit 2 operated throughout the inspection period at 100X power except for minor power reductions for routine surveillance testing.
On February 6, the NRC issued a Notice of Enforcement Discretion (NOED) when the "B" Ex-core Monitor could not be repaired and restored to an operable status within the seven days allowed by the Limiting Condition for Operation Action Statement.
Section 2.3 pertains.
On February 8, an Unplanned Engineered Safety Feature (ESF) actuation occurred when a non-licensed operato}
hung a tag on the wrong breaker.
The opening of the incorrect breaker caused a normally open primary containment isolation valve to close.
The licensee determined the ESF actuation was invalid but reportable per
CFR 50.72.
The inspectors will assess licensee corrective actions during their review of the Licensee Event Report (LER).
On February ll, the licensee conservatively made a 24-hour notification when, as a result of using incorrect flow instrument calibration curves, actual reactor power, although within instrument tolerance, was
.024X higher than indicated.
The licensee determined that, based on the error, reactor power may have slightly (approximately
.7 Mwt) exceeded its licensed core thermal power limit of 3441 Mwt averaged over a shift.
Pending final corrective action, the licensee reduced power by one Megawatt thermal.
2.
PLANT OPERATIONS (71707, 92901, 93702, 40500)
2.1 Plant Operations Review The inspectors observed the conduct of plant operations and independently verified that the licensee operated the plant safely and according to station procedures and regulatory requirements.
The inspectors conducted regular tours of the following plant areas:
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Control Room
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Emergency Diesel Generator Bays
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Control Structure
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Protected Area Perimeter
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Unit 1 and 2 Reactor Buildings
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Security Facilities
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Unit 1 and 2 Turbine Buildings
Control room indications and instrumentation were independently observed by NRC inspectors to verify plant conditions were in compliance with station operating procedures and Technical Specifications.
Alarms received in the control room were reviewed and discussed with operators; operators were found cognizant of control board and plant conditions.
Control room and shift manning were in accordance with Technical Specification requirements.
During plant tours, logs and records were reviewed to ensure compliance with station procedures, to determine if entries were correctly made, and to verify correct communication of equipment status.
These records included various operating logs, turnover sheets, blocking permits, and bypass logs.
The inspector observed plant housekeeping controls including control and storage of flammable material and other potential safety hazards.
Posting and control of radiation, high radiation, and contamination areas were appropriate.
Workers complied with radiation work permits and appropriately.
used required personnel monitoring devices.
The inspectors performed 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> of backshift and deep backshift inspections during the period.
The deep backshift inspections covered licensee activities between 10:00 p.m.
and 6:00 a.m.
on weekdays, and weekends and holidays.
2.2 Use of Overtime The SSES overtime policy is governed by Procedure NDAP-00-0650, Rev 1, Conduct of Site Support.
The procedure implements the plant Technical Specification requirements for limiting overtime (OT) for unit staff who perform safety-related activities.
The procedure also requires that any deviation from the limitations be documented and approved by the VP -
Nuclear Operations or his designee using the OT limit deviation form.
The inspector reviewed the licensee's overtime records including the time cards and deviation forms on a sample basis from October through December 1994 for the operations shift personnel including reactor operators, senior reactor operators, auxiliary operators and key maintenance personnel.
The inspector noted that use of OT for this time period was minimal, deviation forms were filled in as required and approved by the VP - Nuclear Operations, indicating adequate control of use of overtime at SSES.
The inspector concluded the licensee met the Technical Specification requirement for limiting overtime.
2.3 Ex-core Neutron Detectors - Notice of Enforcement Discretion On January 30, 1995, the Unit 2 "B" Ex-core Neutron flux indicator failed reading off-scale high.
This was the fifth failure of the 'B'onitor in the last two months.
See Section 3. 1.2 for a review of 18C troubleshooting on this instrument.
Plant Technical Specifications require two ex-core monitors to be operable when the plant is operating.
When one monitor is inoperable, the plant Technical Specifications (TS) require that the inoperable monitor be returned to operable status within seven days or the plant be placed in hot shutdown within twelve hours.
During troubleshooting the licensee replaced various components in the "B" ex-core monitor that are located outside containment and
determined that the detector that provides input to the log power indication had failed.
Since a containment entry was required to repair or replace the detector, PP8L submitted a request for enforcement discretion to the NRC on February 6, 1995.
This submittal requested that Unit 2 be allowed to operate with one operable ex-core monitor until the next shutdown of sufficient duration that allows for containment entry, not to exceed the seventh refueling and inspection outage.
The ex-core monitoring system is comprised of two separate and redundant channels.
Detectors are mounted inside the containment but outside the biological shield.
This post-accident monitoring instrument provides indication and alarms in the control room.
It also provides information to the SPDS, plant computer, and the shutdown margin monitor.
The information and analysis provided in GE report NEDO-31558 for a wide range of events including an anticipated transient without scram (ATWS), concluded that the operators would have multiple inputs available to them from the neutron flux monitoring instrumentation including the Sos, IRMs, LPRHs and APRHs to determine reactor power and confirm reactor shutdown if ex-core monitoring system was not available.
Additionally, the NE00 report concluded that core power can be determined from other plant variables to ensure accomplishment of reactivity control even if the neutron monitoring systems were not available.
It was also noted that the SSES emergency operating procedures do not address the ex-core monitors.
Based on this, a safety evaluation report dated November 28, 1994, issued by the NRC indicated that the licensee should review their neutron monitoring instruments and may request removal of this instrument from the post-accident monitoring Technical Specification.
As compensatory measures in the request for enforcement discretion, PPEL committed to:
(1) ensure onsite availability of spare parts for needed maintenance on "A" channel, (2) make changes to the alarm response and surveillance procedures as needed, and (3) conduct an operator training (hot box)
on inoperability of "B" channel and re-emphasize the availability of alternate means of reactivity indication.
By letter dated February 8, 1995, NRC approved the enforcement discretion as requested.
The resident inspectors verified that the compensatory measures discussed in PP8L's February 6, 1995 letter had been implemented.
The "B" ex-core monitor had been deenergized.
A hot box training memorandum was issued as stated to the control room shift personnel as required reading and temporary procedure changes were made to the surveillance procedure as stated in the PP&L letter.
The inspector verified that the control room operators were knowledgeable of the status of the "B" ex-core monitor and other inputs available to them for reactor power determination.
An inventory of spare parts for the 'A'x-core monitor was prepared to ensure parts availability.
The components replaced during the last several failure and repair were returned to the vendor for troubleshooting.
The inspector concluded the--
.
safety significance of inoperable 'B'x-core monitor was small.
The compensatory measures were appropriately implemented.
See Section 3.3 for inspector's assessment of the licensee's maintenance and troubleshooting of the "B" ex-core monito.
NINTENANCE AND SURVEILLANCE (62703, 61726, 92902, 40500)
3. 1 Naintenance Observations The inspector observed and/or reviewed selected maintenance activities to determine that the work was conducted in accordance with approved procedures, regulatory guides, Technical Specifications, and industry codes or standards.
The following items were considered, as applicable, during this review:
Limiting Conditions for Operation were met while components or systems were removed from service; required administrative approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and quality control hold points were established where required; functional testing was performed prior to declaring the involved component(s)
oper able; activities were accomplished by qualified personnel; radiological controls were implemented; fire protection controls were implemented; and the equipment was verified to be properly returned to service.
Maintenance observations and/or reviews included:
WA 43722, Install New Bonnet with Larger Disk Stop and Remove Manual Operating Handle on Core Spray System Division 2, dated January 17,-
1995.
MA 50076, PSV 12648 Containment Instrument Gas 1500 Header Relief Valve Pressure Setpoint Test, dated January 18, 1995.
WA 46197, Electrohydraulic Control System Pressure Setpoint Bias Adjustment, dated January 25, 1995.
WA 56091, Remove and Replace Power Supply for Electrohydr aulic Control System, dated January 27, 1995.
WA 43567, Installation of. Supplemental Decay Heat Removal (SDHR) Service Water Tie-in Piping at Fuel Pool Cooling (FPC) Heat Exchanger
"A",
dated February 9, 1995.
WA 43564, Install Supplemental Decay Heat Removal (SDHR) Service Mater Inlet Piping, dated February 9, 1995.
3.1.1 Supplemental Decay Heat Removal System Installation The inspector observed portions of the supplemental decay heat removal system (SDHR) permanent piping modification installation.
Of the portions observed, maintenance personnel generally performed the work per procedure.
Although without consequence, the inspector identified some examples where administrative policies were not followed.
During hot work, a weld guard was not placed on the floor as required.
The fire watch, who was present, did not fill out the hourly fire watch log.
Additionally, maintenance personnel did not reinstall temporary cleanliness covers installed on some openings which were not actively being worked.
When notified, maintenance personnel promptly
corrected the inspector identified minor deficiencies.
The'nspector verified secondary containment was maintained per station procedures during the observed portions of installation.
3. 1.2 Ex-core Neutron.Nonitor - Troubleshooting The ex-core neutron detectors at both units have a history of failures and erratic indication.
After Unit 2 startup from the last refueling outage in July 1994, eight investigative maintenance work authorizations (WAs) were prepared to troubleshoot and repair problems with the "B" ex-core monitor.
Five of these WAs were initiated between December 1994 and January 1995.
After the "B" ex-core monitor log power range indication was found to be reading upscale on January 30, 1995, the licensee did extensive troubleshooting and replaced various components in the system located outside the containment and determined that one of the four detectors located inside the containment had failed.
The licensee based this conclusion on their observation that the log power range indication circuit worked when another detector output was connected to it.
The replaced components were returned to the vendor for further troubleshooting.
See Section 2.3 for licensee's request for an enforcement discretion.
The inspector discussed licensee's troubleshooting with various personnel in maintenance, guality Assurance and Nuclear Systems Engineering.
The licensee indicated that the system performance did not meet their expectations.
The licensee stated that a recent vendor audit finding done by an industry joint group (NU PIC) indicated some problem with the vendor's (Gammametric)
program for commercial dedication and controls applied during the manufacturing process.
Because of this, gA put restrictions requiring pre-inspection and/or observation testing prior to procurement.
As no equipment was purchased from Gammametric in 1993 and 1994, the existing spare parts were considered acceptable and restrictions imposed on future procurement were considered adequate.
The inspector reviewed several of the eight work authorizations (WAs) initiated between July 1994 and January 1995 on "8" ex-core monitor and noted that although the work followed the overall procedural guidance of NDAP-gA-502, Work Authorization System, Rev 4, these investigative WAs, except for the last one, did not have a work plan.
The block on the WA form for engineering review was also not checked.
Nuclear system engineering was contacted late, after many troubleshooting and repair attempts.
The inspector noted that the 18C engineers, who provide good expertise in the area of IKC
'components and equipment, did not provide a wider system based consideration.
The inspector concluded that safety significance of inoperable
"8" ex-core monitor was small.
The history of ex-core monitor repair indicated that the licensee's efforts on correcting the problem did not address the root cause of failures and hence did not result in a reliable system.
The corrective maintenance performed at the component level also did not meet management expectations of a comprehensive approach to optimize system performance, address the root causes and implement lasting corrective action.
The inspector noted that the licensee is currently establishing an 18C systems engineering group within nuclear systems engineering to enhance engineering support of I&C maintenanc.1.3 Electrohydraulic Control System Troubleshooting On January 21, 1995, Unit 1 experienced a transient when the main turbine control valves started to close and bypass valves 1,
2 and 3 opened.
This transient was of short duration (approximately one second),
and the APRHs spiked to approximately 107X.
The licensee concluded that thermal power increase was less than 1X for a very short duration.
Normally, the vital uninterr uptable power supply (UPS) provides power to one -22V DC electrohydraulic control system (EHC) power supply unit (house power).
The backup -22V DC power supply gets its power from the permanent magnet generator (PHG) mounted on the turbine shaft.
The licensee determined that the -22 V DC house power supply drifted low and the -22V DC PMG power supply took control.
The licensee believed that this transfer, which was supposed to be bumpless, ini'tiated the transient.
The inspector observed the Unit
EHC -22V DC house power supply change out on January 28, 1995.
The power supply replacement was categorized as a special, infrequent or complex tests/evolution (SICT/E), because of the consequences of a turbine trip without the house power supply.
As the PHG could only supply power down to approximately 1650 rpm, under such an event, the operators would loose the ability to control reactor pressure and cooldown using the bypass valves.
The evolution was performed under work authorization MA 56091, Remove and Replace Power Supply, dated January 27, 1995; and MA 46197, EHC Pressure Setpoint Bias Adjustment, dated January 25, 1995.
Administrative, technical and operational guidance was provided in TP-193-031, Unit
EHC -22V DC house power supply change out, Rev 0.
The inspector reviewed the procedure and work packages, attended the briefing given to the operations and work crew by the Manager Nuclear Operations and the Test Director, and observed parts of the maintenance work.
The inspector concluded the evolution was well-planned and performed in a deliberate and controlled manner following the requirements of NDAP-gA-0320, Special, Infrequent or Complex Tests/Evolutions, Rev.
1.
The briefings, conducted prior to the evolution, were done very well, and addressed the items required by NDAP-gA-0320 in proper detail.
Coordination and communication between the work location (lower relay room)
and the control room were very good.
Supervisory oversight and involvement at these'ocations were excellent.
Tests performed by PP8L on the replaced power supply did not identify any problems.
The power supply unit was sent to the vendor for further troubleshooting.
However, on February 9, another EHC perturbation that lasted less than one second occurred.
The licensee established a team with in-house personnel and a
GE technical expert to determine root cause of these two events.
At the end of the inspection cycle, licensee's investigation was ongoing.
The inspectors will review licensee's corrective actions at the completion of these activitie.2 Surveillance Observations The inspector observed and/or reviewed the following surveillance tests to determine that the following criteria, if applicable to the specific test, were met:
the test conformed to Technical Specification requirements; administrative approvals and tagouts were obtained before initiating the surveillance; testing was accomplished by qualified personnel in accordance with an approved procedure; test instrumentation was calibrated; Limiting Conditions for Operations were met; test data were accurate and complete; removal and restoration of the affected components was properly accomplished; test results met Technical Specification and procedural requirements; deficiencies noted were reviewed and appropriately resolved; and the surveillance was completed at the required frequency.
Surveillance observations and/or reviews included:
SI-258-002, Scram Discharge Volume High Water Level Trip quarterly Functional Test for Channels LSH-C12-2N013A, B, C, and D, dated February 10, 1995.
3.2. 1.Observation of Scram Time Testing The inspector observed performance of the surveillance, SR-155-002, R10, Scram Time Heasurement of Rods following Haintenance or Modification, after HCU on-line maintenance on January 4,
1995 for control rods 26-27 and 26-35, from the HCU location, and on January 12, 1995 for control rods 34-03 and 30-35 from the control room.
Good communication between work group at the HCU and control room operators was observed.
Reactor engineering support was very good.
Appropriate limiting conditions for operations were entered and shift supervision at the control room provided good over sight.
4.
ENGINEERING (71707, 37551, 92903, 40500)
4. 1 High Pressure Core Injection (HPCI) System Operability A
The licensee's Emergency Operating Procedure (EOP) requires bypassing the HPCI automatic suction transfer logic on higher suppression pool (SP) level so that HPCI pump continues taking suction from the non-safety related condensate storage tank (CST)
as long as it is available.
The bypass is consistent with BWR owner group emergency procedure guidelines and addressed the concern with higher SP temperature, in mitigation of an ATWS event.
Also, higher cooling water temperature to the HPCI pump journal bearings were identified as a
concern.
Following a review of a planned, but not yet implemented, modification to remove the HPCI system pump suction auto transfer logic, the Nuclear Technology group initiated an engineering deficiency report EDR 94-046 on August ll, 1994 over a concern that bypassing the auto transfer logic would"'llow the SP level to increase above the point (25'7") where the HPCI turbine exhaust piping may become flooded in the event of a HPCI trip (see Combined Inspection Report 50-387/94-17 and 50-388/94-18).
During a small break LOCA (SBLOCA) with a loss of offsite power the primary SP letdown path (SP filter
pump to condenser) will not be available.
To reduce the SP level the operator could initiate SP letdown using the RHR system as directed by the EOPs.
Based on this EOP directed guidance, the EDR was dispositioned with a plan requiring a formal calculation of the letdown capacity.
However, this calculation, completed in January 1995, showed that the letdown capacity is 170.5 ibm/sec,,
much less than the rate at which a SBLOCA could add water to the SP, thus SP level will increase.
During such a scenario, if HPCI system should trip on high reactor vessel level (level fluctuations are expected as the reactor is manually depressurized, and the HPCI turbine is operated at reduced speed)
a subsequent HPCI start with the flooded steam exhaust piping could damage the piping due to water hammer and render HPCI inoperable, or could delay its restart.
The design basis requirements for HPCI is to 1) supply reactor coolant makeup during a
SBLOCA such that fuel design limits are not exceeded, 2) transfer heat from the reactor, and 3) allow complete plant shutdown by maintaining reactor inventory until it is depressurized such that low pressure ECCS system can be placed into operation.
The FSAR section 6.3.2.2.1 and the basis for plant TS require that HPCI be able to automatically transfer to the SP upon high SP level or low CST level and-be able to perform its design basis function taking suction from the SP.
The FSAR in Section 6.3.3.7.6 discusses a SBLOCA analysis with failure of HPCI at the onset of the event.
The peak clad temperature for this event remains well within the acceptance limits of 2200'.
To evaluate the effect of HPCI operation on the plant response during a SBLOCA, the licensee performed a
bounding calculation using the SABRE code.
This code was developed in-house by PP8L and benchmarked against standard industry codes.
A limiting break size of.025 ft'as assumed.
This analysis showed that at about 50 minutes into the event, the SP level will exceed 25'7".
By this time, the reactor pressure would decrease to approximately 600 psi, and fuel temperature would be close to the coolant saturation temperature.
If HPCI was to trip on higher reactor vessel level, the HPCI functions could be satisfied by other systems (blow down by ADS and SRVs, and subsequent low pressure ECCS injection).
The SSES operating procedure for HPCI provides instructions to the operator on HPCI restart with water in the steam exhaust line.
Additionally, there are multiple alarms alerting the operators about a potential for water intrusion into the steam exhaust line and the licensee's calculation showed that it would take about four hours after the steam exhaust line drain pot high level alarm, for water to impede turbine exhaust path.
Although the licensee implemented an interim change to plant procedures to prohibit HPCI suction from the SP, if water temperature exceeded 140'F, later calculations showed that peak SP temperature will remain below 140'F for a SBLOCA.
Therefore, no concern over HPCI failure due to high SP temperature exists.
The licensee further concluded that higher SP level will not impose unacceptable hydrodynamic loads on the containment during blowdown.
This is because as the height of the water column inside SRV tailpipes increases with SP level, the reactor pressure also decreases such that the effect of these two factors work in opposite direction to maintain hydrodynamic loads within the design value.
Hence, the licensee concluded that HPCI was capable of performing its design basis functions.
The licensee is discussing the potential generic implication of the subject with BMR owners grou The inspector noted that final disposition of the EDR was delayed due to the licensee's use of an EOP directed step, which later turned out to not completely address the problem and hence required further work.
The inspector noted some licensee confusion relative to applicability of the process for operability determination which resulted in increased time to reach a final conclusion.
The licensee's subsequent assessment indicated lack of clear guidance on use of licensing basis and EOPs in operability determination resulted in this delay.
As a result, the licensee is developing a nuclear department procedure to establish clear guidance on operability determination.
The inspector concluded identification and resolution of the EDR reflected a
good questioning attitude and capability of the engineering organization, however, lack of clear guidance extended the time required to perform an operability determination.
5.
PLANT SUPPORT (71750, 71707, 92904, 40500)
5.1 Radiological and Chemistry Controls During routine tours of both units, the inspectors observed the implementation of selected portions of PP&L's radiological controls program to ensure:
the utilization and compliance with radiological work permits (R'WPs); detailed descriptions of radiological conditions; and personnel adherence to RWP requirements.
The inspectors observed adequate controls of access to various radiologically controlled areas and use of personnel monitors and frisking methods upon exit from these areas.
Posting and control of radiation contamination areas, contaminated areas and hot spots, and labelling and control of containers holding radioactive materials were verified to be in accordance with PPKL procedures.
Health Physics technician control and monitoring of these activities was satisfactory.
Overall, the inspector observed an acceptable level of performance and implementation of the radiological controls program.
5.2 Security Implementation of the physical security plan was routinely observed in'arious plant areas with regard to the following:
protected area and vital area barriers were well maintained and not compromised; isolation zones were clear; personnel and vehicles entering and packages being delivered to the protected area were properly searched and access control was in accordance with approved licensee procedures; security access controls to vital areas were maintained and persons in vital areas were authorized; security posts were adequately staffed and equipped, security personnel were alert and knowledgeable regarding position requirements, and written procedures were available; and adequate illumination was maintained.
Licensee personnel wer e observed to be properly implementing and following the physical security plan.
6.
SAFETY ASSESSMENT/EQUALITY VERIFICATION (40500, 90700, 90712, 92700)
6.1 Licensee Event Reports The inspector reviewed LERs submitted to the NRC office to verify that details of the event were clearly reported, including the accuracy of the description of the cause and the adequacy of corrective action.
The inspector determined
whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted onsite follow up.
The following LERs were reviewed and closed:
bnit
LER 94-013-00 Unplanned Closure of HPCI Steam Isolation Valve (ESF);
HPCI Declared Inoperable
. On August 25, 1994, with Unit 1 at 100X power, the high pressure coolant injection (HPCI) system steam supply outboard isolation valve unexpectedly closed during performance of residual heat removal (RHR) equipment area temperature instrument calibrations due to a human error.
The licensee determined the isolation was reportable.
NRC Inspection Report 50-387/94-16 documented the event as an unresolved item.
The NRC will assess licensee corrective actions during a future inspection.
~Uit 2 LER 94-005-00 Technical Specification Required Shutdown Due to Check Valve Surveillance Failure On March 14, 1994, with Unit 2 at 99X power, a reactor instrumentation line excess flow check valve failed its surveillance test when the valve would not seat.
The affected instrumentation line was isolated.
This rendered the 17 jet pump inoperable.
The action statement for the inoperable jet pump flow instrument required being in at least hot shutdown within twelve hours.
The licensee completed the shutdown within eight hours of entering the action statement.
Subsequent licensee disassembly and inspection did not conclusively determine the cause.
The valve was replaced and subsequently tested satisfactorily.
PPEL concluded no safety consequences resulted from the event.
The inspector agreed with the licensee's reportability analysis and safety assessment.
The corrective.actions for the failure were adequate.
Although the root cause could not be determined, the licensee disassembly and inspection of the valve internals represented a reasonable attempt to determine the cause.
The inspector had no further questions.
LER 94-007-00 Fuel Loaded in Reactor Core quadrant with Inoperable Source Range Monitor On May 7, 1994, the licensee determined fuel was loaded into a core quadrant with the associated source range monitor (SRM) inoperable.
NRC Inspection Report 50-388/94-11 documented the event as an unresolved item.
The NRC will assess the effectiveness of the licensee's long-term corrective actions at a
later inspectio Unplanned ESF Actuation Due to Fault on ESS 480 Volt Bus On October 24, 1994, an Engineered Safeguard System (ESS)
480 volt motor control center (HCC) 2B236 tripped when a seismic restraining chip fell onto energized bus work causing a phase-to-phase fault.
This resulted in an unplanned engineered safety feature (ESF) actuation when containment isolation valves for reactor building chilled water automatically closed.
NRC Inspection Report.50-388/94-23 reviewed this event.
The licensee investigation revealed a shorter than required screw was utilized for the (12" vice %" length) seismic restraining clip and the possibility of others existed.
The inspector questioned Nuclear Systems Engineering (NSE)
personnel whether the seismic qualification was affected since the LER did not address this aspect.
Subsequently, PP&L performed a calculation that showed the shorter screw did not affect the seismic qualification of the affected HCC breaker.
However, the calculation also identified that missing clips, stripped screws or stripped screw holes are not acceptable for seismic qualification.
The inspector will continue to assess the licensee's resolution of seismic qualification issue for other 480 volt HCC's.
6.2 Plant Operations Review Committee (PORC) Neeting The 'inspector observed portions of PORC Heeting 95-016 which approved the 50.59 safety evaluation for the oper ation and design of the supplemental decay heat removal.(SDHR)
system.
PORC members critically questioned the effluent radiation monitoring aspects of the modification.
The PORC chairman asked probing questions which resulted in PORC comments adding clarity to the safety evaluation bases for the effluent radiation monitoring and sampling requirements for system operation.
The monitoring and sampling requirements were consistent with those required by current Technical Specifications for the service water effluent radiation monitor.
The inspector found the PORC review of the 50.59 safety evaluation clearly demonstrated a strong safety perspective.
7.
HANAGEHENT AND EXIT NEETINGS (30702)
7.1 Resident Exit and Periodic Neetings The inspector discussed the findings of this inspection with PP&L station management throughout the inspection period to discuss licensee activities and areas of concern to the inspectors.
At the conclusion of the reporting period, the resident inspector staff conducted an exit meeting summarizing the preliminary findings of this inspection.
Based'on NRC Region I review of this report and discussions held with licensee representatives, it was determined that this report does not contain information subject to'0 CFR 2.790 restrictions.
7.2 Other NRC Activities On January 29 February 3,
1995, an NRC Region I Senior Operations Engineer performed an inspection of the Operator Licensing Program.
Inspection results will be documented in NRC Inspection Reports 50-387/95-03 and 50-388/95-0 On February 5 10, 1995, an NRC Region I Radiation Specialist performed an inspection in Maintaining Occupational Exposures ALARA.
Inspection results will be documented in NRC Inspection Reports 50-387/95-04 and 50-388/95-04.
On February 6, 1995, a meeting was held in Region I between NRC and PP8L to discuss the SSES Security Pla Il