IR 05000387/1994022
| ML17164A467 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 12/14/1994 |
| From: | Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17164A466 | List: |
| References | |
| 50-387-94-22, 50-388-94-23, NUDOCS 9412270093 | |
| Download: ML17164A467 (19) | |
Text
Inspection Report Nos.
License Nos.
Licensee:
Facility Name:
Inspection At:
Inspection Conducted:
Inspectors:
UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION I
50-387/94-22; 50-388/94-23 NPF-14; NPF-22 Pennsylvania Power and Light Company 2 North Ninth Street Allentown, Pennsylvania 18101 Susquehanna Steam Electric Station Salem Township, Pennsylvania October ll, 1994 November 21, 1994 M. Banerjee, Senior Resident Ins~t r, SSES D. J.
Ma n ',
Re den s ector'
Approved By:
te, se Re tor Projects Section No. 2A, 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 plant management walkdowns, and Emergency Plan Offsite Agency annual training conducted by the licensee to maintain emergency preparedness.
Findings:
Performance during this inspection period is summarized in the Executive Summary.
Details are provided in the full inspection report.
Violation:
One non-cited violation was identified when operators mispositioned a control rod during a control rod sequence exchange.
9412270093 94i2f4 PDR
- DOCK 05000387
Operations EXECUTIVE SUMMARY Susquehanna Inspection Reports 50-387/94-22; 50-388/94-23 October ll, 1994 November 21, 1994 I
On October 8, 1994, Unit 2 control room operators inadvertently mispositioned a control rod while performing a control rod sequence exchange.
Following mispositioning, the operators initiated recovery action without first contacting shift supervision and reactor engineering.
This was contrary to plant management expectations and station procedure.
Section 2.2 pertains.
Maintenance/Surveillance During the period, a reportable unplanned engineered safety feature (ESF)
actuation occurred on Unit 2 during performance of planned breaker maintenance.
Electricians were removing the 'A'tandby liquid control (SBLC)
pump motor breaker when a seismic restraining clip fell onto energized bus bars which resulted in the loss of the 480 MCC.
Operators and electricians responded to the plant challenge promptly.
The event caused containment pressure and temperature to increase.
The bus was restored and containment parameters were returned to normal.
The preliminary Event Review Team (ERT)
findings were thorough and comprehensive.
The inspector identified the licensee safety assessment did not address the seismic qualification impact, if any, of having a shorter than required restraining clip hold down screw.
The licensee agreed to assess seismic qualification impact in this final resolution.
Section 3.2 pertains.
The inspector performed TI 2515/125, Foreign Naterial Exclusion Controls during the period.
The objective was to determine whether licensees have implemented effective procedures to prevent foreign material from inadvertently entering safety systems.
The inspector found PP&L had implemented effective procedures, although past documented and evaluated examples of introduction of foreign material suggests the need for performance improvements in this regard.
Section 3.4 pertains.
Plant Support An annual partial participation emergency plan exercise was conducted on October 25, 1994.
The licensee successfully demonstrated their ability to implement the emergency plan.
However, the use of the simulator control room operators as exercise referees was questioned by the NRC inspector regarding the exercise objectives of demonstrating the integrated capability and training.
This finding is currently being evaluated by the licensee.
Section 5.3 pertains.
Safety Assessment/guality Ve'rification The inspector observed a good example of management oversight in the field.
Operations and Maintenance department managers performed a thorough walkdown of specific areas of the plant.
The inspector found this recent initiative a strength.
Section 6.2 pertain EXECUTIVE SUMMARY.
TABLE OF CONTENTS
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SUMMARY, OF FACILITY ACTIVITIES..................
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PLANT OPERATIONS (71707, 92901, 93702, 40500)
2.1 Plant Operations Review
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2.2 Hispositioned Control Rod
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MAINTENANCE AND SURVEILLANCE (62703, 61726, 92902, 40500)
3.1 Maintenance Observations 3.2 Safety Related 480V Motor Control Center (HCC) Fault 3.3 250 Volt DC Battery Charger Maintenance
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3.4 (Closed)
Foreign Material Exclusion Controls TI-2515/125 3.5 Surveillance Observations
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ENGINEERING (71707, 37551, 92903, 40500)
4.1 Inspection Activity.
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PLANT SUPPORT
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5. 1 Radiological and Chemistry Controls
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5.2 Security 5.3 Emergency Preparedness Exercise
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5.4 Emergency Planning Offsite Agency Trai SAFETY ASSESSMENT/OUALITY VERIFICATION (40500, 92700)
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6.1 Licensee Event Reports 6.2 Management Walkdown
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MANAGEMENT AND EXIT MEETINGS 7. 1 Resident Exit and Periodic Meetings
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7.2 Other NRC Activities
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Details 1.
SUNNARY OF FACILITY ACTIVITIES Susquehanna Unit 1 Sumary Throughout the inspection period, Unit 1 operated at essentially 100X of rated thermal power with the exception of minor power reductions for surveillance testing.
I Susquehanna Unit 2 Summary Unit 2 operated at full power throughout the inspection period with the exception of three unplanned power reductions and minor power reductions for surveillance testing.
On October 17,<, n unplanned downpower to 60X was required to repair a condenser tube-ak in the 'A'ow pressure (LP)
condenser.
On October 24, a 480 ~"
- motor control center (HCC) was inadvertently de-energized while '~ ~moving the 'A'tandby liquid control pump breaker for preventive maintenance (PH).
Operators reduced power to 80X.
The HCC de-energized when a seismic restraining clip fell and caused a phase to phase short circuit.
The event constituted an unplanned ESF actuation when drywell cooling valves automatically isolated on loss of the HCC.
The licensee made the required NRC notification.
Section 3.2. pertains.
On November 21, the last day of the inspection period, an unplanned downpower to 60X was necessary to repair an 'A'ow pressure condenser tube leak.
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:
Control Room
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Emergency Diesel Generator Bays Control Structure
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Protected Area Perimeter Unit 1 and 2 Reactor Buildings
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Security Facilities Unit 1 and 2 Turbine Buildings Engineered Safeguards Service Water Pump House 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 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> of deep backshift and 4.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> of 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 Mispositioned Control Rod During a Unit 2 control rod sequence exchange on October 8, 1994, the plant control operators (PCOs) erroneously positioned control rod 18-31 to 00 (full-in) from position 16.
The sequence exchange sheet required the rod to be moved to position 48 (full-out).
The operators immediately discovered the error and to correct the error started withdrawing it.
However, a rod block was generated from the rod block monitor, that stopped the rod movement at position 20.
Immediately after the rod block was generated, the reactor engineer came back to the control room inner circle and realized that rod 18-31 was mispositioned.
The control rod was withdrawn to its intended full out position upon reactor engineer's direction and shift supervision was informed.
The shift supervision then informed operations management.
SOOR 94-536 was written.
The licensee's procedure NDAP-(A-0338, Reactivity Management and Control Program, Rev 1, Section 6.7.4 requires that a mispositioned control rod be inserted to full-in position and reactor engineering be contacted for evaluation of the core prior to recovery.
No control rod movement can occur until reactor engineering completes this evaluation.
During the event the PCOs made two errors, first by moving rod 18-31 to position 00 instead of position 48 as required by the sequence exchange sheets, and second by withdrawing the rod from position 00 to 20 without reactor engineering evaluation.
Both of the operators involved in this event were temporarily relieved of licensed duties.
The licensee established an Event Review Team (ERT), that included the involved operators, to review the event, identify root causes and develop corrective actions.
The team concluded the causes of the errors were inadequate communication, including failure to use repeat backs, failure to follow chain of command and inadequate training on definition of mispositioned control rod.
The proper chain of command was not followed, because shift supervision was not notified of the event prior to recovery.
In addition, the operator pushing the rod control buttons, did not completely read the pull sheet.
The team also concluded that the operators had taken a reflex instinctive action of attempting to correct the error by moving the rod out.
A document called "Hot Box" number 94-102 was issued to all licensed personnel and reactor engineering, as required reading.
This document defined mispositioned control rod and steps to be taken per procedure NDAP-gA-0338, acceptable communication practices for reactivity control manipulations, and the required chain of command to emphasize that all recovery actions must be through the shift supervisor.
Additionally, the importance of holding a
briefing session (tailboard) before every planned reactivity manipulation to emphasize the work at hand, responsibilities, communication expectations, possible problems and recovery actions were also discussed in the hot box document.
Operations management discussed oversight expectations with shift supervisors.
The involved operators presented the lessons learned from the event to the other operations personnel during morning shift briefings.
The licensee is also planning to reinforce effective communication practices in continuing training, revise the rod sequence exchange sheets for human factor improvements and revise the appropriate operating procedures to include the NDAP-gA-0338 action items.
To minimize the unit supervisors involvement in day-to-day plant work control activities, a separate work control center is being implemented.
This is expected to allow more time for and improve oversight functions of shift supervision.
The licensee's safety assessment indicated that the event did not adversely affect the fuel or core thermal limits, and an adequate margin was maintained to the preconditioning envelope.
Hence, the integrity of the fuel was maintained at all times.
Off-gas sampling did not indicate any increased activity.
Primary coolant activity remained normal.
The inspector reviewed the ERT report and discussed the event with the involved operations personnel including the operators.
The inspector directly observed the "lessons learned" briefing delivered to the plant operations personnel by the involved operators.
The inspector also reviewed the licensee's deficiency items list for the past two years and concluded that corrective actions from these deficiencies could not have reasonably been expected to prevent this event.
The inspector noted that increased supervisory oversight would have been appropriate during this reactivity change evolution as the operator moving the control rod was performing the rod sequence exchange evolution for the first time.
Additionally, procedural guidance on mispositioned control rod was not readily available to the operators performing the sequence exchange.
The inspector concluded that the licensee's response to this self-disclosing event was appropriate and comprehensive.
The involved operators showed a very high degree of integrity and accountability in being able to learn from the event and succinctly discuss the lessons learned voluntarily with the rest of the operations personnel.
However, the event reflected a potential weakness in the licensee's method of ensuring the applicable procedural requirements for reactivity control were followed.
This procedure violation is not being cited as it met the criteria VII.B.(2) of 10 CFR 2, Appendix C.
3.
NAINTENANCE AND SURVEILLANCE (62703, 61726, 92902, 40500)
3.1 Haintenance 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)
operable; 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 40917, Investigate Damaged Bus Bar From Motor Control Center (MCC)
2B236 Section 80, dated October 24, 1994.
WA 44247, Clean/Rebuild PCV 12643, Removed from System, dated October 19, 1994.
WA 43764, Replace Trolley Rail for Unit 2 Refueling Platform, dated November 7.
WA 34585, Replace Unit I 'A'RD Pump with Rebuilt Pump Due to Degrading Discharge Pressure, dated November 16.
3.2 Safety Related 480V Notor Control Center (NCC) Fault On October 24, 1994, an unplanned Engineered Safety Feature (ESF) actuation occurred on Unit 2 during performance of planned breaker maintenance.
During removal of the 'A'tandby Liquid Control (SBLC)
Pump Motor Breaker, 28236-081, from the cubicle, a seismic restraining clip came loose and fell into the 480 volt motor control center (MCC).
A phase to phase arc resulted, which caused the loss of 480 V MCC 2B256.
Control room operators received multiple control room alarms.
Reactor water cleanup (RWCU) system and reactor building chilled water (RBCW) to the drywell isolated.
The licensee determined the isolation (primary containment isolation function) of drywe11 cooling valves, which occurred due to loss of MCC 2B236, constituted an ESF actuation, and thus was reportable.
The isolation of RWCU was not considered reportable since the isolation was not caused by the ESF portion of RWCU isolation logic.
Drywell temperature and pressure, initially 124'F and 0.4 psig respectively, began to increase.
Additionally, reactor recirculation pump motor temperatures began to rise.
Operators entered off-normal procedure ON-217-001 to respond to the loss of the 480V MCC.
Reactor power was reduced to 80X by reducing recirculation flow per alarm response procedures in order to minimize recirculation pump motor temperature increase.
V Electricians, after verifying the bus de-energized, removed breaker 2B236-082A (immediately below 'A'BLC pump breaker) for drywell cooling fan 2V415A and removed the seismic retaining clip which fell.
Electricians visually inspected the bus work and noted some minor damage on the bus bar associated with drywell fan 2V415A.
Consequently, the breaker was not reinstalled.
Following an assessment of the bus bar damage and containment conditions, operators re-energized the MCC and loads were subsequently restored.
Maximum average drywell temperature peaked at 149.85'F (EOP entry condition is 150'F),
drywell pressure peaked at 0.95 psig and recirculation motor temperatures
peaked at 195'F.
Containment conditions were promptly restored to normal.
Operators were standing by ready to scram the reactor prior to reaching EOP entry conditions for drywell pressure (1.72 psig).
Electrical maintenance reinstalled drywell fan 2V415A following further inspection of the bus bars.
PP8L documented the event on SOOR 94-551 and formed an Event Review Team (ERT)
to evaluate the event.
The ERT determined that during removal of the breaker, the seismic clips were loosened and repositioned out, of the way.
The involved electrician did not re-tighten the hold down screw before pulling the breaker out and the hold down screw for the seismic clip was shorter than required (8's
%" length).
The seismic clip fell when the breaker was pulled to the disconnect position.
The ERT determined that some electricians did re-tighten hold down screws prior to breaker removal.
This was because of prior experience with falling seismic clips.
This maintenance practice was not required, proceduralized nor covered in training.
The ERT identified the following root causes:
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Failure by work group personnel to capture and communicate prior experience, in that seismic clips had fallen off of MCC cubicle buckets previously during maintenance activities.
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A shorter than required screw had been installed on the clip that fell and its screw hole had been stripped.
It could not be determined how or why the shorter screw had been installed.'he licensee did determine from drawings obtained from the vendor (Cutler-Hammer)
a note required an existing short screw be removed and replaced with a longer screw for right hand seismic clips.
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The seismic clip and screw assembly (original design) is not a captive design (i.e., kept from falling by a lanyard, screw 'dead-zone'r longer length screw design)
and is made of conductive material.
The ERT recommended preliminary corrective actions included:
Repair the damaged bus work in MCC 28236 during the next Unit 2 refueling outage.
Inspect all Unit 2 and Unit I safety related MCCs for proper seismic clip hold down screw size.
Review MCC bucket removal and reinstallation sequence to identify any other components that could fall and to identify the need, if any, for using special tools.
Revise the Maintenance work procedure and related training program modules/guides to address seismic clip removal/reinstallation requirements.
Revise the Electrical Maintenance Work Practices training module to include this event as an example of the need for capturing and communicating work-related experience ~
Conduct non-routine training on this event for all electrical maintenance personnel.
Review the seismic clip design with respect to captive design, material composition and seismic requirement issues.
The inspector concluded operators responded well to the loss of MCC 2B236.
Plant conditions were promptly assessed and actions to restore drywell conditions to normal were appropriate.
The inspector reviewed off-normal procedures and concluded operators followed procedures correctly.
The inspector found the contingent action plan to scram the reactor prior to high drywell pressure EOP entry conditions was prudent.
Although EOP entry conditions were not reached, the event resulted in degraded plant conditions which the inspector considered a challenge to plant safety systems and operators.
The ERT had not finalized conclusions at the end of the report period.
However, the inspector considered the preliminary ERT conclusions and recommended cor rective actions appeared thorough, comprehensive and directed at preventing recurrence.
The inspector found the ERT's safety assessment did not address whether the shorter than required screw affected the seismic-qualification of the affected breakers.
The licensee will assess the seismic qualification impact in the final SOOR resolution which is near completion.
The inspector will continue to assess licensee resolution of this matter.
3.3 250 Volt DC Battery Charger Maintenance The Unit 2 250 volt DC Class '1E'ystem has two 50X battery chargers (2D653A and 2D653B) in Division I.
However, the voltage on the chargers was found to have dropped to 260.5V.
The licensee's procedure OP-288-001 requires that the charger output voltage be maintained between 261 to 267V.
'The licensee initiated a troubleshooting work authorization WA V40931 on November 7, 1994.
Initial investigation determined that the problem was with the 'A'harger.
The plant Technical Specification Section 3.8.2. 1 requires that with one of the required battery chargers inoperable, the operability of its associated battery bank be demonstrated by performing a surveillance within one hour, and at least once per eight hours thereafter.
The licensee took the 'A'harger out-of-service to perform the maintenance, and the required battery surveillance was performed well within one hour.
The electricians replaced an amplifier board.
The charger no longer exhibited oscillation.
The task was completed well within the required time frame.
The inspector questioned the job supervisor, who indicated that various battery charger components, including the amplifier board, are periodically replaced as part of a preventive maintenance program, and also that the failure history of the amplifier board does not indicate that a change of this program is needed at this time.
The inspector observed the unit supervisor's briefing of the electricians, control of equipment status, battery testing and the electrician's replacing the amplifier board.
The inspector concluded the electricians were knowledgeable about battery charger operation and appeared to have the required experience to investigate using the investigative work authorization
(WA) which did not have any specific guidance on work steps.
The control room supervision provided appropriate oversight function, and the plant operators provided the required assistance in equipment status control.
The inspector noted that procedure OP-288-01 Rev 12, 250V DC system used to shutdown the battery charger 2D653A did not provide any guidance in terms of transferring its loads to the parallel charger 2D653B.
Instead, the procedure instructed all major loads be shutdown.
However, the electricians successfully transferred the load to 2653B.
The inspector considered that the battery charger maintenance task was successfully completed with appropriate coordination between operations staff and maintenance.
3.4 (Closed)
Foreign Naterial Exclusion Controls TI-2515/125 The inspector performed Temporary Instruction TI 2515/125, Foreign Material Exclusion Controls during the period.
The objective was to determine whether the licensee has implemented effective procedures to prevent foreign material from inadvertently entering safety systems during maintenance, refueling outages and routine operations.
The NRC has issued a number of generic communications regarding emergency core cooling system (ECCS) strainer clogging by debris.
Information Notice (IN) 93-34 and its supplements alerted licensee's to the potential for loss of ECCS cooling function due to a combination of operational and post-LOCA debris in containment.
The inspector reviewed licensee work control procedures and practices to determine if provisions exist to address materials, parts and tool accountability to ensure loose items are not left inside structures, systems or components after the work activity is complete.
Specifically, the inspector reviewed the following Nuclear Department Administrative Procedures:
NDAP-gA-309 Primary Containment Access and Control, NDAP-gA-500, Conduct of Maintenance, NDAP-(A-502, Work Authorization System, NDAP-gA-503 Housekeeping Control and NDAP-RA-506, Foreign Material Exclusion.
The procedures clearly articulated expectations, responsibilities, requirements and methods for control of material, material accountability and system cleanliness during all work activities including maintenance, refueling, outages and routine operations.
Specific locations discussed were suppression chamber, refueling floor, reactor cavity, fuel pool and safety systems.
The inspector found that the cleanliness and housekeeping controls were applicable for all pertinent activities.
Although the licensee removes all radiological postings prior to containment closeout, no specific procedural steps currently address removal of the radiological postings.
The inspector reviewed prior Significant Operating Occurrence Reports (SOORs)
and Nonconformance Reports (NCRs) to determine if there had been any instances where foreign material was found in systems.
Especially where debris was dropped into the suppression pool.
The inspector noted there were examples of documented foreign material intrusion.
To date in 1994 there were nine NCRs and three SOORs documenting foreign material intrusion.
There were
NCRs since 1989 which documented debris which fell into the suppression pool.
Examples of debris include:
rubber boot, 10" pipe wrench, 6" adjustable wrench, I" ball valve and fitting, 6" of '/i" diameter nylon tubing, 6" lock wire pliers, 50'rain hose.
The licensee dispositioned the NCRs to remove
the equipment or determined by analysis that the debris would not result in exceeding designed strainer clogging.
The ECCS strainers are designed for 50X clogging.
Procedures require an oper ability/reportability analysis for each introduction of foreign material.
The inspector found, through discussions with plant personnel, the licensee inspected the suppression pools in each unit to verify no construction debris was present prior to initial reactor startup.
I The inspector concluded, based on document review and personnel observations, the licensee documented foreign material intrusion events and removed the foreign material or analyzed the effect.
The NRC previously identified an example where cleanliness procedures were not followed during hydraulic control unit (HCU) maintenance during a refueling outage (see NRC Inspection Report 50-387/94-06).
Overall, the inspector observed maintenance activities were performed following the housekeeping and cleanliness requirements.
The inspector noted, based on previous primary containment drywell inspections, that the drywell to suppression chamber downcomers, were not labeled 'A'one boundaries.
NDAP-gA-309 requires all but 20 drywell to suppression chamber downcomers be capped to prevent foreign material from entering the suppression pool.
The licensee procedures require putting temporary screens at these 20 downcomer openings to prevent debris from entering the suppression pool.
It is typical outage practice to route various drain hoses through the screens.
During the last U2 refueling outage a
50'rain hose fell into the suppression pool.
The hose was subsequently removed.
The licensee is currently evaluating improvements to this practice.
Although the licensee is highly confident of suppression pool cleanliness, plans are under development to have divers survey and remove debris from both suppression pools during the next set of refueling outages in 1995.
The inspector considered overall foreign material exclusion controls were effective.
When foreign material intrusion did occur, the licensee documented the occurrence.
Notwithstanding the excellent documentation of the events, the history suggests the need for performance improvement in the implementation of the cleanliness and housekeeping controls.
The documented loss of cleanliness events did not affect safety system operation.
The licensee's corrective actions associated with NCRs adequately addressed the foreign material aspects, but did not address the ineffective performance and actions to prevent recurrence.
PPSL is evaluating methods to improve plant personnel performance regarding effective implementation of foreign material controls.
The inspector considered the initiative to have divers inspect both suppression pools a strength.
Based on this inspection TI 2515/125 is closed.
3.5 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 was 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-150-201, Monthly Functional Test of Reactor Core Isolation Cooling (RCIC) Steam Supply Pressure Channels PSL-E51-1N019A,B,C,D, dated October 12, 1994.
S0-151-002, 'B'oop quarterly Core Spray Flow Verification, dated October 28, 1994.
S0-024-001, 'A'onthly Diesel Generator Operability Test, dated October 31, 1994.
SM-006-007, 480 V Bus 08565 18 Month Undervoltage Channel Calibration and Functional Test, dated November 2, 1994.
4.
ENGINEERING (71707, 37551, 92903, 40500)
4.1 Inspection Activity The inspector periodically reviewed engineering and technical support activities during this inspection period; The on-site Nuclear Systems Engineering (NSE) organization, along with Nuclear Technology in Allentown, provided engineering resolution for problems during the inspection period.
NSE generally addressed the short term resolution of engineering problems; and interfaced with the Nuclear Technology and Modifications organization to schedule modifications and design changes, as appropriate, and to provide long term corrective action.
In addition, Reactor Engineering in Nuclear Operations organization provided day-to-day support for safe reactor operation.
The inspector verified on a sample basis that problem resolutions were thorough and timely.
In addition, the inspector reviewed short term actions to ensure that they provided reasonable assurance that safe operation could be maintained.
Licensee actions were acceptable.
5.
PLANT SUPPORT (71750, 71707, 92904, 40500)
5.1 Radiological and Chemistry Controls During routine tou} s 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 (RWPs); 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 various 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 were observed to be properly implementing and following the physical security plan.
5.3 Emergency Preparedness Exercise An off-year Emergency Preparedness Exercise was conducted at Susquehanna Unit I on October 25, 1994.
The inspectors reviewed the exercise objective and scenario, and observed the performance of the emergency response personnel at the simulator control room, technical support center (TSC), operators support center (OSC),
and the emergency operations facility (EOF).
The inspectors also attended the licensee's critique of the exercise.
Activation and utilization of the emergency response organization and the emergency response facilities were generally consistent with the emergency plan (EP)
and EP implementing procedures.
Overall, good facility management, and command and control were noted.
The accident assessment, classification, and protective action decision-making were appropriate.
The inspectors noted that the plant announcements and the Emergency Director's status briefings were not clearly audible at the TSC.
The 1'icensee's self-critique identified similar areas for improvement regarding the public address system.
The inspectors noted that although the functional areas were adequately manned, a
spectroscopy analyst's position at the EOF was not staffed until the later part of the exercise.
Mhen questioned, the licensee explained that this did not impact the exercise performance, as the scenario did not call for a spectroscopy analysis of the samples.
However, the licensee is pursuing the cause for this delay to see if any corrective actions are needed.
Also during the scenario review, the inspectors noted that the simulator control room operators performed the functions of the referees.
As a result, they were given the exercise scenario prior to the exercise.
The licensee indicated that the control room operators were not graded for their performance at this exercise as the licensed operator's requalification program annual EP walk through training was considered as adequate EP training.
The licensee indicated that the use of control room operators as referees during the exercise was a change from the prior practice and was
implemented to improve conduct of the EP exercise.
The inspectors reviewed the requalification program EP walk through exercise lesson plan for licensed operators, and discussed the subject with regional EP inspectors.
The inspectors concluded that during the exercise, PP&L successfully demonstrated their ability to implement the Emergency Plan and take adequate on-site protective measures in an emergency.
The licensee's critique was good.
However, the new practice of using the simulator control room operators as referees was questioned regarding EP training requirements.
CFR 50, Appendix E in Section F.2.b requires that the EP program shall provide for training and exercising of personnel responsible for accident assessment, including control room shift personnel, and that the training shall include a
specialized initial training and periodic retraining.
Also NUREG 0654, Rev I, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Section N. I.a explains an exercise as an event that tests the integrated capability and major portions of the basic elements existing within the EP plan and organization.
It was not evident that the lesson plan incorporated in the licensed operator requalification program meets the training requirement of the regulation, and if the subject change meets above expressed intent of NUREG 0654.
This item will remain unresolved pending further review of the licensee's basis for the change (URI 94-22-01).
5.4 Emergency Planning - Offsite Agency Training An annual training for federal, state and local offsite support organizations was conducted on November 18, 1994.
This training is required by the SSES Emergency Plan (EP) to maintain emergency preparedness.
The inspector attended part of the training program, and toured the new Media Operations Center (MOC) together with other participants.
PP&L also maintains a near site MOC at the Energy Information Center which it plans to discontinue using.
The inspector found the training was well attended by FEMA, state and local risk county government agencies.
The presentation topics included recent changes to the EP program and facilities, planning for the upcoming ingestion pathway exercise, and sought comments from offsite agency personnel for enhancement of the program.
Interaction with offsite agency personnel generated new ideas for coordination of efforts to further improve the program.
The new MOC is a state of the art facility, and is described in a prior NRC Combined Inspection Report (50-387/94-19 and 50-388/94-20).
The inspector concluded the licensee's annual training was effective in maintaining emergency preparedness, and good coordination and cooperation between the licensee and the offsite organization.
SAFETY ASSESSNENT/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 correcti.ve 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:
Unit 1 94-012-00 Loss of Fire Detection/Suppression
- Condition Prohibited by Technical Specification On August 2, 1994, the simplex fire protection system was disabled by a lightning strike to the site.
NRC Inspection Report 50-387/94-16 documented this event.
94-014-00 Loss of Fire Detection/Suppression
- Condition Prohibited by Technical Specification On August 18, 1994, the simplex fire protection system was disabled by a lightning strike to the site.
NRC Inspection Report 50-387/94-16 documented this event.
94-015-00 Postulated Failures of Standby Gas Treatment System (SGTS) Are Outside the Design Basis On September 12, 1994, the licensee concluded either of two newly postulated single failure events in conjunction with a design basis Loss of Coolant Accident (LOCA) could cause the plant to be outside its design basis.
NRC Inspection Report 50-387/94-20 documented this event.
6.2 Nanagement Nalkdown During the period the inspector observed the Manager Nuclear Operations and Manager Nuclear Maintenance perform a plant walkdown.
The walkdown is a
periodic activity that was initiated by both managers recently whereby a
thorough walkdown of specific areas of the plant is performed together.
The refueling floor and the control structure areas were toured.
The inspector observed management identify deficiencies for correction.
They interacted with personnel on the refueling floor performing maintenance activities.
The inspector concluded this activity demonstrated good visible management oversight in the field.
The interaction with personnel was beneficial since it provided an opportunity for two-way communications between management and station personnel.
The inspector considered the initiative to perform a routine field walkdown of this detailed nature a strengt.
NNAGENENT AND EXIT MEETINGS (30702)
7.1 Resident Exit and Periodic Meetings The inspector discussed the findings of this inspection with PP8L 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 10 CFR 2.790 restrictions.
7.2 Other NRC Activities On October 20, 1994, the NRC Region I Regional Administrator visited the plant and met with PP&L management.
On October
28, 1994, an NRC Region I Senior Reactor Engineer performed TI 2515/122, Evaluation of Rosemount Pressure Transmitter Performance.
Inspection results will be documented in NRC Inspection Reports 50-387/94-23 and 50-388/94-24.
On October 31 - November 4, 1994, an NRC Region I Radiation Specialist conducted a radwaste inspection.
Inspection results will be documented in NRC Inspection Reports 50-387/94-24 and 50-388/94-25.