IR 05000387/1995020
| ML17158A937 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 10/12/1995 |
| From: | Anderson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17158A935 | List: |
| References | |
| 50-387-95-20, 50-388-95-20, NUDOCS 9510190145 | |
| Download: ML17158A937 (22) | |
Text
Inspection Report Nos.
License Nos.
Licensee:
Facility Name:
Inspection At:
Inspection Conducted:
Inspectors:
UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION I
50-387/95-20'0-388/95-20 NPF-14; NPF-22 Pennsylvania Power and Light Company 2 North Ninth Street Allentown, Pennsylvania 18101 Susquehanna Steam Electric Station Salem Township, Pennsylvania August 6, 1995 - September 18, 1995 M. Banerjee, Senior Resident Inspector, SSES B. McDermott, Resident Inspector, SSES Approved By:
n erso
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Reactor Projects Section No. 2B, ate 95iOi90i45 95iOi2 PDR ADOCK 05000387
EXECUTIVE SUMMARY Operations Susquehanna Inspection Reports 50-387/95-20; 50-388/95-20 August 5, 1995 - September 18, 1995 In accordance with Technical Specifications, operators shutdown the Unit 2 reactor in response to an unacceptable as-found local leak rate test on the primary containment nitrogen/purge air supply valves.
The inspector observed that the shutdown was well controlled by the Plant Control Operators and that good oversight was provided by both the Unit Supervisor and the Shift Supervisor.
Use of an additional Unit Supervisor to handle administrative requirements was noted as a good initiative that effectively limited distraction of the team-performing the shutdown and improved the overall safety of the evolution.
On September 14th and.15th, the "B" ESW and Unit 2 "B" Core Spray pump breakers failed to cycle, respectively, on manual start attempts.
The breakers were replaced and the licensee was developing a detailed plan for further investigation and to inspect all
KV breakers.
Maintenance/Surveillance On August 22, 1995, the general purpose grapple separated from the Unit 2 refuel floor jib crane cable during movement of a new fuel bundle from the new fuel vault to the spent fuel pool.
The bundle fell through approximately
feet of water and came to rest in the fuel preparation machine.
After reviewing the recovery procedure, safety evaluation, root cause assessment and the actual recovery work, the inspector concluded that the detailed plan was executed in a safety conscience manner.
The inspector observed the licensee's troubleshooting and replacement of the
"C" ESW pump breaker in response to the two delayed manual starts in July and again on September 7,
1995.
The inspector noted that the workers had the required paperwork for the breaker replacement, but had not received Operation's authorization to proceed with the breaker replacement.
The inspector considered this human performance error a maintenance weakness.
Engineering/Technical Support The reactor protection system (RPS)
power supply electrical protection assembly (EPA) circuit breakers experienced repetitive trips for unknown causes between 1984 and 1991 that resulted in actuations of Engineered Safety Features.
Due to the long standing nature of this problem and ineffective corrective actions the NRC previously issued a corrective action violation.
The inspector found that the system engineer currently is tracking multiple indicators of system and component performance in order to identify and correct degradation prior to breaker failures.
The licensee has taken appropriate corrective actions for this violation that can reasonably be expected to 'improve the reliability of the RPS power supplie EXECUTIVE SUMMARY (Continued)
An apparent failure of a standby liquid control local flow indicator (rotometer) during a quarterly flow surveillance was reviewed along with the licensee's decision to change the flow instrument used to satisfy the.
inservice test criteria.
Several questions remain regarding the as-found calibration check of the local instruments and the calibration requirements for the ultrasonic flow instrument that was substituted for completion of the surveillance.
Pending the.rotometer calibration check results and the licensee's final evaluation regarding calibration of the ultrasonic flow
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transducers, this item will be unresolved.
(URI 50-388/95-20-02)
Plant Support Observations regarding Security and Health Physics performance of routine activities during this inspection period did not identify any problems.
Safety Assessment/equality Verification The inspector reviewed the licensee's safety evaluation for the Transformer
on-line maintenance and concluded that appropriate compensatory measures had been taken.
The temporary procedure provided a detailed plan and through description of the required compensatory measures.
The recovery procedures were excellent and covered a range of potential adverse effects.
Operator simulator training and compensatory measures for this unique plant configuration were considered a strength.
The on-line maintenance was handled in a safety conscious manner with appropriate management and engineering oversight to ensure an event free evolution.
The inspector observed several licensee management meetings relative to the dropped new fuel bundle.
The inspector noted good PP8L management emphasis on performing the recovery evolution in a safe and methodical manner.
A good questioning attitude was observed regarding the recovery methodology and the event review team findings.
Very good management oversight was observed throughout this evolution.
A number of licensee managers and supervisors were observed during meetings on recent 4 KV circuit breakers failures.
The inspector noted that the site management team had given this issue a very high priority and was pursuing corrective actions in a time frame commensurate with its safety significance.
The corrective action team (CAT) team's early discussion of the breaker failures and communication with the corporate engineering organization were effective in initiating an organizational response to the emerging issu TABLE OF CONTENTS EXECUTIVE SUMMARY.
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SUMMARY OF FACILITY ACTIVITIES..................
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PLANT OPERATIONS 2. 1 Plant Operations Review
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2.2 Unit 2 Shutdown Due To Excessive LLRT Leakage
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2.3 Emergency Service Water (ESW)
Pump Start Failure
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MAINTENANCE AND SURVEILLANCE 3. 1 Maintenance Observations 3. 1. 1 New Fuel Bundle Dropped 3. 1.2 Emergency Service Water Replacement
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ENGINEERING 4.1 (CLOSED) VIO 50-387/92-06-01 Reliability of RPS Power Supplies 4.2 Standby Liquid Control IST Flow Indication
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PLANT SUPPORT
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6.
SAFETY ASSESSMENT/OUALITY VERIFICATION 6. 1 Startup Bus On-line Haintenance
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6.2 Observation Of Licensee Management Oversight
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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.
SUMHARY OF FACILITY ACTIVITIES Susquehanna Unit 1 Summary Unit 1 remained at 100X power throughout most of the inspection period.
On August 21st power was reduced by 5X to perform main turbine valve testing.
Power was reduced to 70X on September 5th for main steam isolation valve (HSIV) exercising, waterbox cleaning, reactor recirculation motor generator (HG) set brush replacement, scram time testing, and a control rod sequence exchange.
There were no NRC reportable events for Unit 1 during this inspection period.
Susquehanna Unit 2 Summary Unit 2 was operated at or near 100X power until September 13th.
Hinor power reductions were made on August 14th and 27th to compensate for high condenser backpressure and for control rod adjustment, respectively.
On September 13th, a local leak rate test, encompassing five containment purge supply system valves, found leakage in excess of the Technical Specification (TS)
requirement for all Type B and Type C containment penetrations combined.
As a
result, the primary containment was declared inoperable and a TS'equired shutdown was initiated.
Required NRC notifications were made, and the plant was in hot shutdown in less than 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, followed by cold shutdown within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The Unit 2 7th Refueling'nd Inspection Outage began two days earlier than planned as a result of the failed LLRT test.
2.
PLANT OPERATIONS (71707, 92901, 93702)'.
Plant Operations Review The inspectors routinely observed the conduct of plant operations to independently verify that the licensee operated the plant safely, and according to station procedures and regulatory requirements.
Control room indications and plant systems were independently observed by NRC inspectors to verify that plant conditions were in compliance with station operating procedures and TS.
Control room alarms and bypass indication system (BIS) warnings were routinely reviewed and discussed with operators; Operators were cognizant of control board indications and plant conditions.
Control room and shift manning were in accordance with TS requirements.
Specific observations relative to the operator performance during the Unit 2 TS required shutdown are discussed below in Section 2.2.
On August 25, 1995, PP8L made an NRC notification based on what appeared to be the failure of several engineered safety features to actuate (EN 29236).
Specifically, a main steam line drain valve did not close, and two HVAC Zone III exhaust radiation monitors did not trip down scale, as expected during a
'he inspection procedure from NRC Hanual Chapter 2515 that the inspector used as guidance is parenthetically listed for each report sectio preplanned half scram resulting from a momentary loss of power to the 'B'PS bus.
By design, the RPS buses are momentarily de-energized during transfer to their alternate power supplies due to the "break before make" transfer switch.
After further review,'he licensee determined'hat the steam line drain valve did not isolate because the momentary power loss was not of sufficient duration for seal-in of the valve's isolation logic relay.
Further review of the Zone III radiation monitors'esign bases showed that the downscale trip, which did not occur during this evolution, is not included in the FSAR list of ESF actuation signals for the Zone III ventilation system.
Further, the momentary loss of power to the radiation monitors is not a valid actuation signal and invalid ESF actuations of reactor building ventilation systems are exempt from reporting requirements.
For these reasons, the licensee retracted the NRC notification.
The inspector noted that the licensee is currently working on a modification that will provide a bumpless transfer from the normal RPS supply to the alternate using a temporary static transfer switch.
The inspectors conducted regular tours of the various plant areas and periodically reviewed logs and records 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.
The inspectors performed 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, weekends, and holidays..
2.2 Unit 2 Shutdown Due To Excessive LLRT Leakage On September 13, 1995, the licensee found excessive leakage during local leak rate testing (LLRT) of the Unit 2 containment nitrogen/purge air supply valves.
The test boundary was comprised of the inboard and outboard valves in the parallel purge air lines entering the containment and the suppression, chamber, and a single nitrogen supply line valve.
The purge supply valves have resilient material and were being tested for a leakage rate of less than 0.05 L. (equal to 15.9 standard liters per minute [SLH]) in accordance with TS 4.6. 1.8.2.
The as-found leak rate was greater than 200 SLN and exceeded the acceptance criteria by a factor of 10.
The as-found leakage from this test alone exceeded the TS limit of 0.6 L, (or 190.7 SLM) leakage limit for all Type B and Type C tests combined.
Consequently, the licensee entered the TS action statement for the inoperable Primary Contai.nment Integrity (TS 3.6.1.1).
The action statement for this TS allows one hour to restore primary containment, or take the plant to hot shutdown in the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and cold shutdown within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
After initial efforts to adjust the valves were unsuccessful, the licensee concluded t'hat plant shutdown would be necessary.
At that point, an additional Plant Control Operator (PCO)
and Unit Supervisor (US) were added to the shift to support the shutdown and reduce administrative burdens on the operators directly controlling and monitoring
the shutdown.
Unit 2 was scrammed from 16X power on September 13th at ll:30
. p.m. in accordance with plant procedures.
All control rods fully inserted.
Reactor vessel water level was effectively controlled by operators, and no ECCS actuation setpoints were reached.
Plant systems responded as expected to the manual scram with only a few minor exceptions.
The inspector reviewed the LLRT results and monitored the licensee's activities up to and including the plant shutdown.
The inspector observed that the plant shutdown was well controlled by the PCOs and that good
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oversight was provided by both the US and Shift Supervisor (SS).
The licensee's augmented shift compliment was noted as a good initiative that effectively limited distraction of the operators and improved the overall safety of the shutdown evolution.
2.3 Emergency Service Water (ESW)
Pump Start Failure The "C" ESW pump experienced delayed manual starts twice in July and then on September 7,
1995.
In July, the control room hand switch was replaced and the pump was successfully operated 'approximately 40 to 50 times with no delay until September 7th when the problem reoccurred.
During troubleshooting on September 9, the licensee observed intermittent problems with starting the pump.
The licensee's investigation of the control logic did not identify any problem with relay actuation and the root cause was suspected to be failure of the latching mechanism to close on the first attempt.
Subsequently, the breaker was replaced, the pump was run, and the system was declared operable.
On September 14 and 15, the "B" ESW and Unit 2 "B" Core Spray pump breakers failed to cycle, respectively,
.on manual start attempts.
The "B" ESW pump breaker indicated an intermittent high contact resistance on the spring charging motor cut-off swi.tch.
The 2B Core Spray pump was successfully started after the breaker was racked out and in again indicating a possible alignment problem.
The breakers were replaced and the licensee was developing a detailed plan to inspect all
KV breakers and perform further investigation.
The licensee's assessment concluded that there was no common root cause of all of the failures, and given the large number of past successful operations of these
KV Westinghouse type to-50-250 breakers, no adverse oper ability impact was foreseen.
Operations instituted an interim compensatory measure to perform a manual rack in and rack out of the breaker if it fails to perform an emergency function.
The inspector concluded that the root cause of the breaker failures was not fully understood, and had to await completion of the licensee's investigation.
The licensee's investigation plan and corrective action implementation schedule included prioritization of breaker inspection based on the safety significance of the breakers'pplication.
The inspectors will continue to follow the licensee's progress regarding root cause assessment and corrective action.
MAINTENANCE AND SURVEILLANCE (62703, 61726, 92902)
3.1 Maintenance Observations The inspector observed and/or reviewed selected maintenance activities to evaluate whether 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:
ME-2RF-007 Removal Of Dropped Fuel Bundle, August 25, 1995 WA C53236 Install Supplemental Decay Heat Removal Piping, August 18, 1995 WA C53237 CH-TP-082 Operation Of SAIC Model 101 Fluorotracer Analyzer Skid, August 30, 1995 Based on observation of selected portions of the above maintenance, the inspector concluded that the work was conducted and completed appropriately, with due concern for plant safety and procedures.
3. 1. 1 New Fuel Bundle Dropped On August 22, 1995, the general purpose grapple on the Susquehanna Unit 2 refuel floor jib crane separated from its cable during movement of a new fuel bundle from the new fuel vault to the spent fuel pool.
Prior to this problem 42 fuel bundles
.were moved during this outage without a problem.
The bundle fell through approximately 18 feet of water and came to rest in the fuel preparation machine (new fuel elevator).
The general purpose grapple had unthreaded from the hoist cable terminal used to secure the tool to the jib crane's cable end.
Insufficient torque on a locknut allowed the grapple to unthread due to rotation of the grapple, relative to the cable, while moving the fuel bundle.
The licensee's weekly check to ensure the grapple was securely attached to the hoist cable did not identify the impending separation since the grapple had been in use for only two days.
After immediate actions were taken to prevent the bundle from falling further into the spent fuel pool, the licensee formed teams to oversee the recovery of the bundle and to investigate the root causes of the event.
After PORC review and approval of a recovery procedure and safety evaluation, the fuel bundle was successfully remove The licensee's review of industry information regarding similar events found that on May 31, 1974, General Electric (GE) issued SIL 082,
"Securing Mechanical Cable Terminals", in response to a general purpose grapple becoming detached from its jib crane while the grapple was attached to an irradiated fuel bundle.
Repeated rotation of the grapple and fuel bundle relative to the cable apparently loosened the cable end from the grapple.
The jib crane cable end had been attached to the grapple using the "cable terminal," or swivel, specified by GE for this application.
The SIL recommended that the threaded connections at both ends of the cable terminal be secured with a locknut and that the viewing ports on the cable terminal and tool be used to verify adequate thread engagement.
However, the SIL did not provide information regarding the torque necessary to prevent the threaded cable connections from unthreading when the load is rotated.
The licensee's root cause team found that the locknut had not been secured with sufficient torque to preclude the grapple from unthreading itself during rotation of the grapple relative to the cable.
Using a 600 lb. test weight PP&L found that, for their components, a minimum torque of 13.5 ft-lbs on the locknut was required to prevent unthreading of the cable end from the grapple after the load was rotated.
Procedure changes were subsequently made that require the use of a chemical locking compound on the terminal threads and torquing the locknut to 25 ft-lbs.
In addition, a shiftly requirement has been added to confirm the appropriate thread engagement by visually checking the inspection port and confirming match marks painted across the stud, locknut, and grapple.
The safety significance of the dropped new fuel bundle is bounded by the FSAR Chapter 15 accident analysis that assumed the drop of a spent fuel bundle into the reactor core from a height of 30 feet, impacting four additional spent fuel bundles.
There were no radiological consequences from the dropped new fuel bundle and no spent fuel was involved.
No fuel bundles (new or irradiated)
were located
'in the spent fuel pool rack adjacent to where the new
, fuel bundle fell.
The licensee currently plans'o disassemble the recovered bundle and return the individual fuel rods to the vendor for damage analysis.
PP8L has reported this event to the industry via the Nuclear Network and GE is considering a
supplemental SIL regarding torque requirements for locknuts on cable terminals.
The inspector observed the post event condition of the dropped bundle and impact of the dropped bundle on the fuel pool.
The licensee's response to the event was closely monitored including: the immediate actions taken; the development, review, and PORC approval of a recovery procedure and safety evaluation; and the management oversight of recovery and event review teams.
Extensive time and effort were dedicated to the activities of the two teams in order to execute the recovery safely and effect corrective actions.
Based on independent reviews and observation of the recovery effort, the inspector concluded that a detailed and well thought out plan was executed in a safety conscience manner.
The inspector concluded that the licensee's approach to recovery and assessment of this event demonstrated a strong safety perspective and an effective root cause investigatio. 1.2 Emergency Service Water (ESW)
Pump Breaker Replacement The inspector observed the licensee's troubleshooting and replacement of the
"C" ESW pump breaker on September 9,
1995, that was performed under Work Authorization (WA) S51203.
Prior to the breaker troubleshooting, additional investigation of the pump start circuitry was performed under two other WAs.
The pump had experienced two delayed manual starts in July and a delayed start on September 7,
1995.
The inspector noted the control room operators entered appropriate TS action statement.
The electrical maintenance personnel performing the troubleshooting and breaker replacement were knowledgeable about the breaker, and Nuclear Systems Engineering was providing appropriate oversight.
During trouble shooting activities the inspecto}
observed good communication between the Nuclear Plant Operator present at the breaker and the control room PCOs.
However, the inspector found that the WA for breaker replacement did not have Operation's authorization, and the US was not contacted before the breaker was replaced.
Upon notice, the maintenance personnel obtained the appropriate authorization.
The inspector considered this human performance error a
maintenance weakness.
3.2 Surveillance Observations The inspector observed and/or reviewed the following surveillance tests to determine whether the following criteria, if applicable to the specific test, were met:
the test conformed to TS 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 were properly accomplished; test results were appropriately communicated with regard to TS 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:
TP-054-076 Emergency Service Water Flow Balance, August 10, 1995 SE-024-201 DG Air Start Check Valve IST, August 17, 1995 SI-280-311 Calibration Of Reactor Vessel Level Switches, September 6,
1995 SE-259-041 LLRT Of Containment Purge Supply Valves, September 13, 1995 Based on observation of selected portions of the above surveillances, the inspector concluded that they were completed with appropriate consideration for safe plant operation and administrative contro.
ENGINEERING (71707, 37551, 92903)
4.1 (CLOSED) VIO 50-387/92-06-01 Reliabi1 ity of RPS Power Supplies The Reactor Protection System (RPS)
power supplies demonstrated continued and repetitive problems between 1984 and 1991 that resulted in actuations of Engineered Safety Features.
The NRC inspectors identified 34 distinct Electrical Protection Assembly (EPA) breaker trips documented in the deficiency reporting system of that time (Significant Operating Occurrence Reports).
These EPA breaker trips resulted in loss of normal power to the RPS bus and the accompanying half scram with isolations and the licensee was not addressing trips due to spurious or unknown causes.
Because of the long standing nature of this recurring problem, the NRC considered it a significant condition adverse to quality and a corrective action violation was issued.
In response to the violation, PP&L committed to short term corrective actions that included installing additional ventilation for the EPA enclosures, revising setpoint calibration procedures, incorporating
"lessons learned" from previous trips, and replacing EPA components prior to end-of-life.
These short term actions were effective in increasing the reliability of the RPS power supplies, but did not preclude them entirely.
The long term corrective actions identified by. PP8L included installing an improved version of the EPA logic cards and providing forced ventilation for the EPA enclosures.
Implementation of these modifications was completed in the Unit 2 6th Refueling and Inspection Outage and in the Unit 1 8th Refueling and Inspection Outage.
Since the implementation of the long term actions, the EPA cards have not had any spurious actuations.
The inspector reviewed:
the licensee's response to the violation; documentation regarding implementation of the corrective actions; and field verified the EPA cabinet cooling modifications.
The inspector found that the system engineer currently is tracking multiple indicators of system and component performance in order to identify and correct future degradation prior to its resulting in failures.
The inspector concluded the licensee has taken appropriate corrective actions for this violation that can reasonably be expected to improve the reliability of the RPS power supplies.
Based on the inspector's review of the licensee's corrective actions, this violation is closed.
4.2 Standby Liquid Control IST Flow Indication On July 25, 1995, the Unit 2 Standby Liquid Control (SBLC) system was taken out of service for planned preventive maintenance.
The work scope included replacement of the local flow indicator (rotometer)
used for flow measur ement during IST surveillances.
The licensee considered periodic replacement of the rotometer a proactive step to preclude recurrence of past rotometer failures.
Following the maintenance, the quarterly SBLC flow surveillance (SO-253-004)
was run using the rotometer to demonstrate a flow greater than the 41.2 gpm required by TS 4. 1.5.c.
Test data taken during SO-253-004 includes'he IST pump flow value from the rotometer and non-IST flow data from the ultrasonic flow detector displayed in the control room.
On July 25, the 'A'ump flow
registered at 42.0 gpm on the rotometer and 43.0 gpm in the control room.
However, the 'B'ump flow registered 40.5 gpm at the rotometer and 43:0 gpm in the control room.
After operators took actions to eliminate the possibility of flow diversion from the 'B'ump and no change was observed on the rotometer, they concluded that the rotometer had failed.
To verify their conclusion, the 'A'ump was again tested and this time the rotometer'ndicated 39.0 gpm with the ultrasonic still showing 43.0 gpm.
The rotometer was then replaced and the surveillance was re-run for both pumps.
During this test both pumps failed the surveillance based on the rotometer indicated flow of 39.5 gpm, however, the ultrasonic flow meter indicated flow for both pumps at 43.0 gpm.
Based on 'the history of rotometer failures and the consistent ultrasonic flow readings since 1993, the licensee dismissed the low rotometer indications as being erroneous.
A PORC meeting was held and the licensee concluded that the ultrasonic flow meter met the ASME OM Code instrumentation requirements and was therefore acceptable to substitute for the suspect rotometer.
The surveillance results were then considered acceptable based on the ultrasonic flow data and the procedure was signed off.
The inspector reviewed the licensee's actions and related documentation, read the vendor's manual, and discussed the use of the ultrasonic flow indication with cognizant licensee personnel.
The inspector noted that the licensee's records since 1993 show the ultrasonic flow measurement device has provided conservative flows relative to the rotometer.
Further, the inspector considered that the sequence of events during the test and the licensee's past experience with the rotameter could indicate a problem with the rotometer, but did not consider this evidence conclusive.
The licensee decided to return both rotometers to the vendor for a calibration check to confirm their conclusion that the rotometer had failed.
Since PP&L does not typically use ultrasonic flow measuring devices for IST testing, the inspector researched the calibration of the instrument in more detail.
The inspector found that PP8L is calibrating the "instrument loop" to a criteria of + 1.5X error. 'his calibration includes the transmitter output current (4-20 mA) and corresponding indicator response but does not include the measuring device (ie. the transducer/controller package).
Review of NUREG 1482,
"Guidelines for Inservice Testing at Nuclear Power Plants,"
Response 5.5-7, revealed that neither the NRC nor the ASME OM Committee have taken a
position on this particular issue.
However, response 5.5-7 also indicates that PPRL's position is not consistent with industry practice.
The licensee's evaluation in response to the inspector's questions concluded that the tolerance of the transducer/controller package is analogous to a flow orifice and does not have to be considered in the loop accuracy.
The licensee based their conclusion on interpretation of the NUREG 1482 discussion regarding flow orifices and analog instrumentation, since no details are provided regarding ultrasonic flow instrument calibration requirements.
The inspector concluded that the adequacy of, the licensee's engineering judgement regarding use of the ultrasonic flow data rather than the rotometer data would be determined by the rotometer vendor's as-found calibration check.
In addition, the question regarding the qualification of the ultrasonic flow
instrument for IST testing (ie, an accuracy of + 2X of indicated flow) needs further licensee evaluation and potentially an IST relief request.
During discussions with NRR staff regarding calibration of ultrasonic flow devices, it was noted that such relief requests have been granted to other utilities.
Pending the rotometer calibration check results and the licensee's final evaluation regarding calibration of the ultrasonic flow transducers, this item will be unresolved.
(URI 50-388/95-20-02)
5.
PLANT SUPPORT (71750, 71707, 92904)
5. 1 Radiological and Chemistry Controls During routine tours of both units, the inspectors observed the implementation of selected portions of PP8L'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 areas, contaminated areas and hot spots, and labelling and control of containers holding radioactive materials were verified to be in accordance with PP8L 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 PP8L's implementation of the physical security program was verified on a
periodic basis, including the adequacy of, staffing, entry control, alarm stations, and physical boundaries.
These inspection activities were conducted in accordance with NRC inspection procedure 71707.
The inspector reviewed.
access and egress controls throughout the period.
No significant observations weve made.
6.
SAFETY ASSESSMENT/EQUALITY VERIFICATION (90700, 90712)
6. 1 Stavtup Bus On-line Naintenance In June 1995 PP8L began receiving momentary annunciations of the
"13 KV BUS 20 NEG PHASE SEg".
The licensee's investigation into the cause of these annunciations found intermittent problems with a potential circuit that supplies a bus undervoltage relay.
An open failure of this circuit will result in the trip of startup bus 20.
PP&L was concerned because a subsequent loss of startup bus 10 during peak electrical demand would scram both Susquehanna units and could potentially effect the stability of the PJH grid.
Significant work associated with startup bus 10 is planned for the Unit 2 fall outage.
The changes being implemented will harden the offsite power supply, improving the original 230 KV switchyard arrangement.
PP&L eval'uates all on-line maintenance work to determine whether the associated risk is acceptable.
The licensee determined that on-line maintenance for startup bus 20 was acceptable based the following considerations:
1) The calculated increase in core damage probability associated with removing the bus for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, accounting for the mitigating measures imposed, was about IX.
2) The startup bus 20 work window was performed to correct a problem in a potential detection circuit and that would reduce the chance of an unplanned loss of bus 20.
3) The work was performed in a controlled manner that included contingencies to harden the grid should startup bus 10 trip and mitigative measures to control the'isk.
Mitigating measures included restrictions on safety and non-safety related equipment that were more severe than TS requirements.
These restrictions ensured that no work would be performed on risk significant structures, systems or components (SSCs), functionally redundant or cross divisional SSCs, or SSCs used for trip response.
The inspector reviewed the licensee's safety evaluation for this evolution and concluded that appropriate compensatory measures had been taken.
The SICT/E Analysis (TP-003-004, Revision 0) provided a detailed and thorough description of the required plant conditions and sequence o'f events.
The recovery procedures were excellent and covered a range of potential adverse effects.
The safety assessment for the bus 20 was comprehensive and gave due consideration to the potential for dual unit scram and subsequent impact on the grid.
Compensatory measures were determined based upon the accident sequences identified in the IPE and enginee}ing judgement.
These measures were reduced to checklists to make them more user friendly.
In addition, the operating crews scheduled during this work window were given special simulator training to improve their understanding of the plant's electrical response to a loss of startup bus 10 and the compensatory measures associated with the unusual electrical configuration.
The inspector concluded that this on line maintenance was handled in a safety conscious manner with appropriate management and engineering oversight to ensure an event free evolution and adequate compensatory measures.
6.2 Observation Of Licensee management Oversight The inspector observed several licensee management meetings relative to the dropped new fuel bundle.
The inspector noted the PP&L managers stressed that performing the recovery evolution in a safe and methodical manner was paramount.
A critical and questioning attitude was observed regarding the recovery methodology, safety assessment, and the event review team findings.
The inspector concluded that very good management oversight was demonstrated during this evolution.
A number of licensee managers and supervisors were observed during meetings on recent
KV circuit breakers failures.
The issue of overall breaker reliability and adequacy of preventive maintenance was questioned during the Corrective Action Team meetings.
Although the license had not completed their root cause investigation at the close of this inspection period, the inspector noted that the site management team had given this issue a'very high priority
and was pursuing corrective actions in a time frame commensurate with its safety significance.
The CAT team's early discussion of the breaker failures was effective in initiating an organizational response to the emerging issues.
7.
MANAGEMENT AND EXIT MEETINGS (71707)
7. 1 Resident Exit and Periodic Meetings The inspector discussed the findings of this inspection with PP8L station management throughout the inspection period to ensure timely communication of emerging concerns.
At the conclusion of the reporting period, the resident inspection staff conducted an exit meeting summarizing the preliminary findings of this inspection.
The licensee did not express any disagreement with any of the inspection findings.
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
CFR 2.790 restrictions.
7.2 Other NRC Activities On August 21, 1995, the NRC SALP Board convened in the Region I office to assess the nuclear safety performance of the Susquehanna Steam Electric Station, Units 1 and 2, during the period from February 27, 1994 to August 5, 1995.
The Boards, assessment was approved by the Region I Administrator and transmitted by letter dated September 20, 1995.
There were no Region based NRC inspections during this period.