IR 05000387/1993009

Insp Repts 50-387/93-09 & 50-388/93-09 on 930511-0628.One non-cited Violation Noted Re Inoperable Fire Doors.Major Areas Inspected:Plant Operations,Radiation Protection, Surveillance & Maint & Safety Assessment

ML17157C415
Person / Time
Site:	Susquehanna
Issue date:	07/20/1993
From:	Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17157C414	List: IR 05000387/1993009 ML17157C413
References
50-387-93-09, 50-387-93-9, 50-388-93-09, 50-388-93-9, NUDOCS 9308020002
Download: ML17157C415 (32)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION I

Inspection Report Nos.

50-387/93-09; 50-388/93-09 License Nos.

NPF-14; NPF-22 Licensee:

Pennsylvania Power and Light Company 2 North Ninth Street Allentown, Pennsylvania 18101 Facility Name:

Inspection At; Susquehanna Steam Electric Station Salem Township, Pennsylvania Inspection Conducted:

May 11, 1993 - June 28, 1993 Inspectors:

G. S. Barber, Senior Resident Inspector, SSES D. J. Mannai, Resident Inspector, SSES B. J. M'Dermott, Reactor Engineer, DRP Approved By:

J. Wh', Chief Reactor Projects Section No. 2A, D te In ecti n Summa:

This inspection report documents routine and reactive inspections (during day and backshift hours) of station activities, including: plant operations; radiation protection; surveillance and maintenance; and safety assessment/quality verification.

One non-cited violation was identified concerning inoperable fire doors on each unit. Findings and conclusions are summarized in the Executive Summary.

Details are provided in the full inspection report.

930S020002 930723 PDR ADQCK 050003S7

PDR

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EXECUTIVE SUMMARY Susquehanna Inspection Reports 50-387/93-09; 50-388/93-09 May 11, 1993

- June 28, 1993 Operations (30702, 71707, 71710)

The inspector identified three operational deficiencies that should have required a work authorization to assure sufficient follow-up and corrective action.

The licensee agreed with the inspector's conclusion and provided on shift training to ensure adequate follow up corrective action for future occurrences.

Section 2.2.1 pertains.

Two control rods were mispositioned as a result of a failure of rod position indicators to function properly.

The licensee formed an Event Review Team (ERT) to fully address this issue.

Their review was comprehensive and thorough.

Minor weaknesses were noted in their definition of the rod position indication system, the ERT's follow up of conflicting indications, and the licensee's willingness to accept the unevaluated effects of an oxide layer buildup on CRD internals.

Overall, the licensee's evaluation was very good.

Section 2.2.2 rtains.

pe Maintenance/Surveillance (61726, 62703)

The licensee generally exercised good control of maintenance and surveillance activities.

No scrams or engineered safety feature (ESFs) actuations were attributable to maintenance or surveillance activities during the inspection period.

Safety Assessment/Assurance of Quality (40500, 90712, 92700, 92701)

During the period, the inspector reviewed the licensee's response to a 10 CFR 21 notification that was issued by the emergency diesel generator (EDG) vendor (Cooper-Bessemer).

The 10 CFR 21 notification concerned a defect in the fuel oil supply swing check valves.

The defect concerns a disk hold-down nut that backed offthe threaded fastener, causing the disk to become disconnected from its hinge resulting in restricted fuel fiow to the,individual cylinder fuel pumps.

The licensee inspected the check valves on all five EDGs and implemented vendor recommended corrective actions.

The inspector concluded the licensee's timely corrective actions were a strength.

Section 8.2 pertains.

During the period, the inspector closed Temporary Instruction (Ti) 2515-119, Water Level Instrumentation Errors During and After Depressurization Transients.

The inspector reviewed actions taken at Susquehanna to ensure operator training and guidance had been provided for significant depressurization events.

The areas reviewed included

implementation of generic guidance, operator training, procedures, and safety parameter display system (SPDS).

The inspector found that PP&L had appropriately taken actions regarding the reactor water level instrumentation errors and that operators had sufficient knowledge of the phenomenon and potential effects.

Section 8.3 pertains.

The inspector reviewed five Licensee Event Reports during the period.

One non-cited violation was identified concerning inoperable fire doors on each unit.

Section 8.1 pertain TABLEOF CONTENTS EXECUTIVE SUMMARY e

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SUMMARYOF OPERATIONS................

1.1 Inspection Activities...................

1.2 Susquehanna Unit 1 Summary.............

2.

OPERATIONS

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2.1 Inspection Activities...................

2.2 Inspection Findings and Review of Events 2.2.1 Operational Deficiency Correction......

2.2.2 Lost Control Rod Position Indication During Rod Exercismg

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Weekly Control

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.3 RADIOLOGICALCONTROLS 3.1 Inspection Activities................

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3.2 Inspection Findings

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4.

MAINTENANCE/SURVEILLANCE 4.1 Maintenance and Surveillance Inspection Activity.

4.2 Maintenance Observations...............

4.3 Surveillance Observations 4.4 Inspection Findings

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EMERGENCY PREPAREDNESS 5.1 Inspection Activity.............

5.2 Inspection Findings

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ECURITY

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S 6.1 Inspection Activity...............................

6.2 Inspection Findings 7.

ENGINEERING/TECHNICALSUPPORT 7.1 Inspection Activity......~........................

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8.2 8.3 SAFETY ASSESSMENT/QUALITYVERIFICATION.............

8.1 Licensee Event Reports (LER), and Open Item (Ol) Follow up 8.1.1 Licensee Event Reports 8.1.2 Open Items...............................

Cooper Bessemer Part 21 Report......................

(Closed) Temporary Instruction (Tl) 2515/119 - Water Level Instrumentation Errors During and After Depressurization Transients

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TABLEOF CONTENTS (CONTINUED)

9.

MANAGEMENTAND EXIT MEETINGS

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9.1 Resident Exit and Periodic Meetings.................

9e2 Inspections Conducted By Region Based Inspectors........

9.3 Management Meeting License Mid-Term SALP Self-Assessment

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I.

SUlVMARYOF OPERATIONS Details 1.1 Inspection Activities The purpose of this inspection was to assess licensee activities at Susquehanna Steam Electric Station (SSES) as they related to reactor safety and worker radiation protection.

Within each inspection area, the inspectors documented the specific purpose of the area under review, the scope of inspection activities and findings, along with appropriate conclusions.

This assessment is based on actual observation of licensee activities, interviews with licensee personnel, measurement of radiation levels, independent calculation, and selective review of applicable documents.

Abbreviations are used throughout the text.

Attachment 1 provides a listing of these abbreviations.

1.2 Susquehanna Unit 1 Summary Unit 1 began the inspection period at 100% power.'n May 11, power was reduced to 95%

to minimize main condenser back pressure.

The circulating water system was unable to provide sufficient cooling to the main condenser due to a high ambient temperature and one circulating water pump out of service.

Power was returned to 100% on the same day.

On May 14, power was reduced to 98% per shift supervision direction.

During the performance of SO-156-001, "Weekly Exercising of Control Rods for Operability," control rod 30-31 was inserted several times and control rod 30-35 once without indication of rod motion or position change for either control rod.

Repairs were made to a power supply in the control rod position indication system.

An event review team was formed.

Section 2.2.2 pertains.

A downpower was conducted on the weekend of May 21 to perform a control rod sequence exchange.

A core calculation was run and the core's proximity to thermal and preconditioning limits was closer than predicted.

Rod pattern adjustments were performed throughout the week to improve margins to these limits.

On May 28, reactor power was lowered to 85% to perform a control rod sequence exchange since the rod pattern adjustments that were performed throughout the week changed certain fuel assemblies end-of-cycle burnup targets enough to necessitate the downpower.

This sequence exchange was successful in resolving the core concerns.

The licensee concluded that no violation of licensing, regulatory, or vendor recommended limits occurred.

Power was returned to 100%

on May 29.

The licensee documented this occurrence on SOOR 93-165.

Operators conducted several other routine power reductions during the period to facilitate control rod pattern adjustments, surveillance testing, and maintenance.

No reactor scrams or ESP actuations occurred during the inspection period.

Unit 1 finished the inspection period at 100%.

1.3 Susquehanna Unit 2 Summary Unit 2 began the inspection period at 100% power.

On May 11, power was reduced to 99%

to minimize main condenser back pressure.

The circulating water system was unable to provide sufficient cooling to the main condenser due to a high ambient temperature and one circulating water pump out of service.

Power was returned to 100% the same day.

On May 18, power was reduced to 70% to make repairs to the isophase bus duct cooling fans.

The fan belts had degraded to the point of causing insufficient cooling to the isophase bus and were replaced.

Power was returned to 100% on May 19 at 6:00 a.m..

On May 19, at 8:32 a.m., power was automatically reduced to 70% when an unanticipated runback to 45% speed occurred on the Unit 2 reactor recirculation pumps.

The runback occurred due to a loss of circulating water pump trip input signal.

Electrical Maintenance was preparing to defeat the reactor recirculation runback interlock for a loss of circulating water pump "A" prior to testing the pump.

While removing the protective cover on the interlock relay, the relay contacts closed, giving the trip input signal. The relay wiring was electrically correct; however, the wiring layout prevented the relay cover from fitting properly.

This created the potential for the relay contacts to close during cover removal.

The wiring was corrected and the runback signal was reset at 1:45 p.m..

The plant responded to the runback per design.

Power was returned to 100% on May 20.

SOOR 93-157 documented this occurrence.

On June 6, at 2:40 a.m., power was reduced to 87% due to a Minimum Generation Emergency implemented by the Power Control Center (PCC).

Power was returned to 100%

at 12:03 p.m..

Operators conducted several other routine power reductions during the period to facilitate control rod pattern adjustments, surveillance testing, and maintenance.

No reactor scrams or ESF actuations occurred during the inspection period.

Unit 2 finished the inspection period at 100%.

2.

OPERATIONS 2.1 Inspection Activities The inspectors verified that the facility was operated safely and in conformance with regulatory requirements.

Pennsylvania Power and Light (PP&L) Company management control was evaluated by direct observation of activities, tours of the facility, interviews and discussions with personnel, independent verification of safety system status and Limiting Conditions for Operation, and review of facility records.

These inspection activities were conducted in accordance with NRC inspection procedure 7170 The inspectors performed 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> of deep backshift inspections during the period.

These deep backshift inspections covered licensee activities between 10:00 p.m. and 6:00 a.m. on weekdays, and weekends and holidays.

2.2 Inspection Findings and Review of Events 2.2.1 Operational Deficiency Correction During the period, the inspector reviewed control room logs to assess whether operational deficiencies received adequate follow up corrective action.

Three plant problems were identified where follow up actions were not adequately performed or documented.

On May 18, at 1:30 p.m., during the performance of a quarterly calibration of reactor pressure channels for the core spray (CS) and low pressure coolant injection (LPCI)

permissives (SI-280-301 step 6.6.19) a Division 2 Safety Relief Valve (SRV) open alarm annunciated and cleared immediately.

Operators checked tailpipe temperatures and the acoustic monitor and noted normal indications.

No work authorization (WA)

was written to investigate and the system engineer was not contacted.

On May 23, at 3:30 a.m., a fire watch reported a smoke smell in Unit 2, elevation 779', area 34, near the Zone IIIheater panel.

A nuclear plant operator (NPO) was sent to investigate and found a burnt wire inside a Zone IIIheater panel (ZC277A) ~

The heaters from this panel were subsequently deenergized.

No WA was written for this item since an operator believed it was already addressed by a deficiency tag.

The deficiency tag was for a different problem.

The deenergized heaters were not yellow tagged.

On May 24, at 11:06 a.m., the Unit 1 drywell equipment drain tank (DEDT) high level alarm was received.

Operators noted that both DEDT drain valves were open and level continued to increase.

Level was initiallydecreasing then began to increase.

The radwaste control room was,contacted and a special test procedure (TP-069-041)

for liquid radwaste (LRW) surge tank cleaning was suspended.

Level in DEDT then began to decrease to normal level.

No WA was written. No follow up was performed.

In these three examples, the inspector identified the following weakness in the licensee's follow up corrective action.

No WAs were initiated for any of these examples.

The licensee subsequently issued WAs for these deficiencie The work groups (maintenance, instrumentation & control (I&C), etc.) and system engineering were not made aware of these problems.

Early communication with the work groups could have provided focused investigation and correction of deficiencies, while contact with system engineering would have assured a review for design adequacy and system performance trending.

The inspector noted a system interaction during his review of the May 24 DEDT high level that was not addressed by the licensee.

With both DEDT drain valves opened, level in the tank increased.

The inspector determined that the special test procedure to clean the LRW surge tanks (TP-069-041) effectively pressurized the LRW suction piping to pressures above the head supplied by various inputs to radwaste, including the DEDT. The inspector noted, by analyzing the level trend, that the DEDT check valve was leaking past its seat, allowing the tank to backfill through the open drain valves.

Level increased rapidly until TP-069-041 was suspended.

In addition, this interaction was a precursor event to a May 28 spill that was caused by back pressure that resulted from TP-069-041.

This was documented in SOOR 93-164.

The inspector identified these findings to operations management on May 26.

The licensee generally agreed with the inspector's conclusions.

On shift training (Hot Box Summary 93-35) was conducted to highlight the importance of proper follow up corrective action.

The inspector considered the licensee's actions for these concerns were appropriate.

The inspector willcontinue to review licensee performance in this area as a part of the ongoing resident inspection program.

2.2.2 Lost Control Rod Position Indication During Weekly Control Rod Exercising On May 14, at 12:43 p.m., during weekly control rod exercising per SO-156-001, the licensee discovered that control rod 30-31 was unknowingly inserted from the full out position (position 48) to position 36, and rod 30-35 was inserted from position 48 to position 46 without control rod position indication changing.

During the test, no change in rod movement was observed on either the standby information panel (SIP) 1C652 or on the display control system (DCS) CRT 1C651.

Both rods indicated full out (position 48). In addition, the insert, withdraw, settle lights on the 1C651 did not illuminate during rod movement.

Based on the above, the surveillance was halted and rods 30-31 and 30-35 were determined to be at positions 38 and 46, by an OD-7 computer printout and the full in/full out display.

Reactor engineering was immediately contacted and confirmed that core power was less than 3293 MW'nd that no core limits were exceeded throughout the event.

Conservative licensee actions were initiated to restore the rods to their pre-exercise positions.

Adequate precautions were implemented and both rods were fully withdrawn. I&Cwas contacted to investigate the SIP and DCS 4 rod display failure to update.

I&Cdiscovered a faulty 5 VDC power supply that tripped a DC buffer card to cause the 4 rod display to freeze at position 48.

Also, a bad 28 VDC power supply was discovered for the operator rod select module

lamp.

After they were replaced, the 4 rod display for both the SIP and DCS and the rod select module lamp was successfully returned to service.

Offgas and primary coolant samples confirmed normal activity. SOOR 93-153 was written and an Event Review Team (ERT) was initiated to identify the root causes of this event and to propose corrective action.

The ERT interviewed the operators involved and reconstructed a detailed timeline of the event.

A cause and effect chart was constructed from the timeline and the four listed root causes were identified.

1.

The 4 Rod Group 5 VDC power supply drifted, causing the buffer card to trip on high voltage.

This caused the SIP and CRT rod positions to "freeze" in their pre-exercise position, i.e., position 48.

2.

The operators did not recognize that rod movement occurred.

3.

Operators were conditioned to expect multiple insert/withdrawal attempts would be required to move rods.

4.

There was no audible or visual alarms to indicate that rod position indication was not updating properly.

The inspector reviewed the ERT's findings and recommendations and noted that the ERT's proposed actions to prevent recurrence appeared to fully address the four identified causes.

In addition, the ERT provided an excellent six element safety assessment for the event.

The inspector reviewed the ERT's actions and identified the following:

TS 3.1.3.7 requires the rod position indication system (RPIS) to be operable.

The licensee concluded, in SOOR 93-153, that the RPIS system was operable because an OD-7 (computer display of rod positions) was requested and received after the event occurred.

However, during the event, there were seven notch changes without either the DCS or SIP RPIS changing from position 48.

One stated purpose of SO-156-001 was to verify the RPIS operable during rod movement.

OD-7 is only used once during SO-156-001 to confirm the starting positions of all control rods.

There is no further requirement to use OD-7, and, per SO-156-001, RPIS operability is based on the changing position indication from the SIP and DCS CRT.

Thus, TS 3.1.3.7 could have been entered for rod 30-31 and rod 30-35 until their actual positions could be confirmed by OD-7. The licensee concluded this was unnecessary since OD-7 immediately confirmed their mispositioning when it was requested.

Since the event was of short duration (2'h minutes), the inspector accepted this licensee position.

However, SO-156-001 does not require verifying rod movement by using OD-7.

During SO-156-001, when rod 30-31 was initiallynotched, drive water flow increased and other supporting control rod drive hydraulic indications supported the porting of high pressure drive water to the insert side of the rod's drive piston.

The operators

believed the 'rod did not move since RPIS did not change.

However, they did not enter ON-155-001, Stuck Control Rod even though drive water flow changes occurred.

In their conclusion, the ERT did not emphasize the importance of resolving this apparent conflict between the drive water fiow indications and RPIS by highlighting this as an associated causal factor.

In addition, the inspector questioned the lack of Local Power Range Monitor (LPRM) response for the insertion of the core's central control rod (30-31) one-fourth its length of travel.

The licensee has agreed to evaluate this item further.

Operators were conditioned to expect that multiple insert and withdraw commands were needed for rods at position "00" and "48". Their explanation for this is the buildup of an oxide layer on the CRD internals.

Their willingness to accept this as an acceptable anomaly is of concern.

This was not highlighted in the ERT's review nor was the impact of this considered on such factors, such as rod scram time, control rod operability, etc.

The licensee has agreed to evaluate this concern further.

Notwithstanding the above, the inspector found that the licensee's overall ERT did a thorough job of reviewing this event.

Their root cause evaluation was thorough and completed in a timely manner.

Allsignificant safety concerns were evaluated.

Based on the licensee's agreement to follow up the identified concerns, the inspector had no further questions on this event.

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RADIOLOGICALCONTROLS 3.1 Inspection Activities PP&L's compliance with the. radiological protection program was verified on a periodic basis.

These inspection activities were conducted in accordance with NRC inspection procedure 71707.

3.2 Inspection Findings Observations of radiological controls during maintenance activities and plant tours indicated that workers generally obeyed postings and Radiation Work Permit requirements.

The controls were acceptable.

4.

MAINTFWANCE/SURVEILLANCE 4.1 Maintenance and Surveillance Inspection Activity On a sampling basis, the inspector observed and/or reviewed selected surveillance and maintenance activities to ensure that specific programmatic elements described below were being met.

Details of this review are documented in the following sections.

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4.2 Maintenance 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.

These observations and/or reviews included:

WA 33728, Removal of Water from HPCI Lube Oil Sump, dated May 11.

WA 33729, HPCI Valve HV-155F001 Seat Leakage Investigation, dated May 11.

WA 30830, Calibration Check of Reactor Core Isolation Cooling Pump Discharge Pressure Switch, dated June 3.

WA 30297, Replace Lube Oil and Fuel Hoses on the "A" Diesel Generator, dated June 3.

WA 33842, HPCI Steam Admission Valve (HV155F001) Repair, dated June 16.

4.3 Surveillance Observations The inspector observed and/or reviewed the following surveillance tests to determine that the following criteria, ifapplicable 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.

These observations and/or reviews included:

SI-183-215, Monthly Functional Test of MSIV Leakage Control System FSH-E32-IN653B,F,P, dated May 1 SM-024-002, 18 Month Emergency Diesel Generator "A" Inspection, dated June 3 to June 18.

SO-253-004, Quarterly Verification of Standby Liquid Control Suction Flow Path, dated June 15.

SO-152-002, Quarterly Verification of High Pressure Coolant Injection System Flow, dated June 19.

4.4 Inspection Findings The inspector reviewed the listed maintenance and surveillance activities.

The review noted that work was properly released before its commencement; that systems and components were properly tested before being returned to service and that surveillance and maintenance activities were conducted properly by qualified personnel.

Where questionable issues arose, the inspector verified that the licensee took the appropriate action before system/component operability was declared.

The inspectors had no further questions on the listed activities.

5.

EMI<WGENCY PREPAREDNESS 5.1 Inspection Activity

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The inspector reviewed licensee event notifications and reporting requirements for events that could have required entry into the emergency plan.

5.2 Inspection Findings No events were identified that required emergency plan entry.

6.

SECURITY 6.1 Inspection Activity PP&L'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.

6.2 Inspection Findings The inspector reviewed access and egress controls throughout the period.

These controls were acceptabl.

ENGINEERING/TECHNICALSUPPORT 7.1 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 interacted with the Nuclear Modifications organization to schedule modifications and design changes, as appropriate, to provide long term corrective action.

The inspector verified that problem resolutions were thorough and directed at preventing recurrence.

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.

8.

SAFETY ASSESSMKÃT/QUALITYVERIFICATION 8.1 Licensee Event Reports (LER), and Open Item (OQ Follow up 8.1.1 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:

Qni~l 92-019-00 Fire Doors Inoperable - Operations Prohibited by Technical Specifications On October 20, 1992, several Unit 1 fire doors failed the six-month fire door inspection surveillances due to excessive gaps around fire doors.

After further investigation, the licensee determined that the excessive gaps had existed without detection for longer than the six-month inspection interval.

Several past fire door surveillances were incorrectly signed offas operable when some of the doors were inoperable due to excessive gaps.

As corrective actions, the licensee revised the applicable surveillance procedures to clearly state acceptance criteria for fire door operability, to provide direction on actions to follow when acceptance criteria are not met, and to provide direction on how to inspect the fire doors.

The licensee concluded that the safety consequences of the excessive door gaps were low, since fire detection and/or suppression exists for the affected fire zones.

However, the deficient gaps may have allowed some fire doors to be prematurely forced open in the event

of a fire. The inspector agreed with the licensee's safety assessment.

The inspector reviewed the revised procedures and a completed fire door surveillance.

The licensee's corrective actions were acceptable.

The failure to adequately inspect fire doors to ensure operability is an apparent violation of TS 3.7.7.

This violation willnot be subject to enforcement action because the licensee's effort in identifying and correcting the violation met the criteria specified in Section VII.Bof 10 CFR Part 2, Appendix C.

93-003-00 Postulated Events Could Result in Exceeding Plant's Electrical Design Basis On March 29, licensee engineering evaluations concluded that two postulated accident scenarios could render class 1E equipment inoperable.

The loss of one offsite power source (prior to or concurrent with specific sized line break of main steam or recirculation pump discharge piping inside containment) could have resulted in overlapping starts of ECCS and other plant equipment.

The overlapping starts could suppress voltage long enough to result in transfer of class 1E from the remaining offsite power to the emergency diesel generators.

Upon this transfer, emergency service water pumps, which supply cooling water to the EDGs and other safety-related equipment, would trip and not automatically restart per design.

Since the design basis assumes no operator action for ten minutes, degradation of the EDGs could have occurred.

The licensee determined these postulated events represented a

condition outside the design basis of the plant.

NRC Inspection Report 50-387/93-04 reviewed this issue.

The licensee took corrective action by performing a temporary modification to defeat the automatic restart feature of the "D" condensate pump after a LOCA shed signal is received.

Licensed operators received training describing the postulated scenarios and the temporary modification to defeat the auto restart feature of the "D" condensate pump.

A permanent modification to defeat the auto restart feature is planned.

The licensee is also performing a root cause analysis to determine why the postulated events were not fully considered at the time degraded grid protective relay setpoints were raised in March 1991.

The inspector agreed with the licensee's reportability determination.

Corrective actions taken or planned were appropriate.

93-004-00 Isolation Logic Relay - Operation Prohibited by Technical Specification During Retest On April23, the licensee replaced relay B21H-K51 in the Main Steam Isolation Valve Logic due to degraded performance.

This relay provides a half isolation signal to all of the inboard MSIVs. In order to perform the required functional and operability testing, the affected trip system was taken out of the tripped condition required by TS Action Statement 3.3.2 Action B. As a result TS 3.0.3 was entered, which constitutes a condition prohibited by Technical Specification The inspector concluded that the licensee's decision to replace the relay was prudent, The inspector agreed with the reportability determination.

On two separate occasions non-licensed operators, during rounds, observed the indicating light from the "A" inboard MSIV DC pilot solenoid valve power not illuminating. Subsequent investigation showed one set of contacts lacked continuity.

Short-term actions for both occurrences was to clean the contacts.

Long-term action was replacement of the K51 relay.

Additionally, the licensee is developing a routine preventative maintenance procedure for that type of relay.

Current TS contains no provision for allowing an isolation trip signal to be reset to allow performance of post-maintenance testing needed to restore the system to an operable status.

The licensee is pursuing such revisions as part of the NRC Generic Technical Specification Improvement Program.

~nit 2 93-002-00 Fire Doors Inoperable - Operation Prohibited by Technical Specifications On January 13, 1993, several Unit 2 fire doors failed the six-month fire door inspection surveillances due to excessive gaps around fire doors.

The licensee determined that shift supervision notification was not made within the required LCO action time and that the excessive gaps had existed without detection for longer than the six-month inspection interval. After further review, the licensee identified four Technical Specification fire doors which were not included in the daily and six-month surveillance procedures, and thus, were not inspected.

These doors were originally included in the inspection surveillances.

However, the doors were not included in a January 1988 drawing, listing all required fire doors as defined by Appendix R studies.

As a result, the doors were then removed from the surveillance procedures.

As corrective action, the six-month surveillance procedure willbe revised to clearly state the acceptance criteria and the need to report fire door deficiencies involving operability in a timely manner.

The four missed fire doors have been included in revised daily and six-month surveillance procedures and the fire door drawings have been similarly revised.

The licensee concluded that the safety consequences of the excessive door gaps were low, since fire detection and/or suppression exists in the affected fire zones.

However, the deficient gaps may have allowed some fire doors to be prematurely forced open in the event of a fire. The licensee also concluded that the safety consequences of the failure to promptly notify the control room and of the missed surveillances were minimal. The inspector agreed with the licensee's safety assessment.

The inspector determined that the licensee's actions to prevent recurrence were acceptable.

The failure to adequately inspect fire doors to ensure operability is an apparent violation of TS 3.7.7.

This violation willnot be subject to enforcement action because the licensee's effort in identifying and correcting the violation met the criteria specified in Section VII.Bof 10 CFR Part 2, Appendix Operability Testing Following Instrument Repair Required Entry into LCO 3.0.3 On May 24, the licensee entered Technical Specification 3.0.3 following repair of a leaking fitting on the reference leg of reactor vessel level switch LIS-24221C.

The licensee performed the repair due to increased awareness of the potential effects of reference leg leaks on reactor water level.

The level switch provides signals to the Containment Isolation Logic for Drywell Cooling, Reactor Building Closed Cooling Water and Containment Instrument Gas systems.

In order to perform the required functional and operability. testing,, the affected trip system was taken out of the tripped condition required by Technical Specification 3.3.2 Action B. Technical Specification 3.0.3 was entered when TS 3.3.2 could not be met.

The inspector agreed with the licensee's reportability determination and concluded that actions to repair the reference leg leak were prudent.

S.1.2 Open Items 8.2 Cooper Bessemer Part 21 Report On November 11, 1992, Cooper Bessemer, manufacturer of the emergency diesel generators (EDG) at Susquehanna, issued a 10 CFR 21 notification concerning a defect in the fuel oil supply system swing check valves in the KSV Emergency Standby Generator System.

The defect concerns a disk hold-down nut that backed off the threaded fastener, causing the disk to become disconnected from its hinge, allowing the disk to float within the valve body.

The check valve was installed between the duplex fuel oil filter and the fuel oil supply header.

This resulted in restricted fuel oil flow to the individual cylinder fuel pumps causing loss in engine power and inability to maintain generator electrical load.

The event occurred twice at Houston Light and Power (HL&P) Company's South Texas Project in October 1992.

HL&P investigated and determined the check valve hold-down nut had not been staked to its threaded fastener thus allowing it to back off. The check valves affected by this notification were three different sizes (3/4", 1-1/4", 1-1/2") of the same design made by the same manufacturer.

Not all Cooper EDG installations employ all three check valves.

PP&L was affected by the 10 CFR 21 notification and as such were sent a copy of the notification by the vendor.

PP&L, in response to the Part 21 notification, inspected the fuel oil supply check valves for all the EDGs.

The licensee began the inspection of the check valves in December 1992 and completed the inspections and corrective actions for all five EDGs by May 1993.

At Susquehanna, two check valves were inspected on EDGs

"A","B","C"and "D". Three check valves were inspected on the "E" EDG.

Cooper Bessemer recommended the check valve internals be removed from the check valve since the valve is required only in applications in which the fuel oil day tank is located below the EDG. At Susquehanna the fuel oil day tank is located below the EDG and thus the check valve is required.

Cooper-Bessemer recommended locking or staking the hold down nuts for those sites which must have the internals installe The licensee disassembled and inspected the affected check valves on all five EDGs.

The inspection revealed that the disk hold-down nut on some check valves were not staked.

Maintenance staked the hold-down nuts on the affected check valves.

Cooper-Bessemer plans to modify quality inspection plans to verify nuts are staked and locked.

The licensee plans to inspect applicable spare check valves in the warehouse and lock and stake, as necessary.

The inspector concluded that the licensee response was appropriate and was considered a

strength.

The inspections and corrective actions were performed in an extremely timely fashion.

Due to PP&L's involvement with Cooper Owner's Group the notification was sent directly to the EDG System Engineer and was not coordinated through PP&L's Industry Event Review Program (IERP). PP&L will ensure that any future Cooper Part 21 notifications are formally entered into the IERP system.

The inspector had no further questions and considers this issue closed.

8.3 (Closed) Temporary Instruction (Tl) 2515/119 - Water Level Instrumentation Errors During and After Depressurization Transients Background The NRC and the nuclear industry have recognized that non-condensible gases may become dissolved in the reference leg of BWR water level instrumentation and lead to a false high level indication after a rapid depressurization event (Reference Information Notice 92-54 and Generic Letter 92-04).

The dissolved gases, which can accumulate over time during normal operation, can rapidly come out of solution during depressurization and displace water from instrument reference legs.

A reduced reference leg level willresult in a false high level indication.

This is important to safety because water level signals actuate automatic safety systems and level indication is used to determine operator action during and after an event.

Scope The inspector reviewed actions taken at SSES to ensure that operator guidance and training has been provided for significant depressurization events.

NRC Inspection Manual TI-2515/119 provided guidance for this inspection.

During the review the inspector referenced the BWR Owners Group (BWROG) guidance to operators provided in letters, dated August 19, 1992 and October 16, 1992; Information Notice 92-54 "Level Instrumentation Inaccuracies Caused by Rapid Depressurization";

Generic Letter (GL) 92-04 "Resolution of the Issues Related to Reactor Vessel Water Level Instrumentation in BWRs Pursuant to 10 CFR 50.54(f)"; and PP&L's response to GL 92-0 Implementation of Generic Guidance The licensee has adopted the operator guidance provided by the BWROG in letters to Plant Operations Superintendents date August 19, 1992 and October 16, 1992, with one exception.

PP&L uses an ATWS mitigation strategy that does not require control of water level at a precise location (2/3 core height or TAF). Instead, their strategy controls water level between -80 and -110 inches on the wide range level indication.

Therefore, operators were not trained on the BWROG's technique for determining actual level using a bias between the indicated fuel zone level and the wide range instrument variable leg tap elevation.

The inspector concluded that PP&L's exception to the BWROG guidance was consistent with their ATWS mitigation strategy, and that the omission of the unnecessary training was acceptable at this time. PP&L and other utilities have deviated from the approved Emergency Protective Guidelines, Revision 4, guidance regarding power and level control.

The Reactor Systems Branch of NRR is currently evaluating this generic issue.

Operator Training The formal training of licensed operators began with a technical presentation on the phenomenon by an Instrumentation and Control (1&C) engineer during continuing operator training, Cycle 5 (8/31/92 - 10/9/92).

During Cycle 6 (10/12/92 - 11/20/92) requalification training, operators received detailed training on the applicable off-normal procedure (ON-145/245-004, Reactor Water Level Anomaly). This ON describes the potential effects of reference leg offgassing on reactor vessel indication and provides guidance for assuring adequate core cooling.

Currently, there are three pre-programmed simulator scenarios that model the failure of reactor water level instruments, involve rapid depressurization and lead the operators to enter the EOP for reactor vessel flooding. The licensed operator requalification program requires operators train on at least two of these scenarios each year.

The BWROG guidance, excluding the information discussed above, is currently being incorporated into the licensed operator training program.

Training on the phenomenon has and willcontinue to be covered during training on ON 145-004.

In addition, training on the reference leg offgassing was added to the unit of instruction for Mitigating Core Damage.

PP&L approved the revision of this unit of instruction on July 12, 1993.

After discussions with the licensee s training staff, review of video-taped training, and review of simulator scenarios, the inspector concluded that the training met the intent of the BWROG recommendations.

Based on interviews with operators and shift supervision, the inspector concluded that licensed operators had sufficient knowledge of the phenomenon and potential effect Procedures

The licensee reviewed Emergency Operating Procedures (EOPs) and determined that they did not conflict with the BWROG recommendations.

Following review of the BWROG guidance, the licensee added three EOP steps prompting operators to evaluate ifreactor water level can be determined. Iflevel cannot be determined, the EOPs direct operators to the flooding procedure.

Overall, the training has heightened the operator's awareness of potential mid-scale indication failures.

This is important since the EOPs themselves do not provide specific guidance for deciding "iflevel can be determined."

The operators and unit supervisor make this decision based on the situation and their training.

As always, if operators observe level indication anomalies that cannot be resolved (instruments not in agreement, trending in opposite directions, etc..) and the level cannot be determined, the EOPs direct operators to the flooding procedure.

This action was part of the EOPs prior to the heightened sensitivity to non-condensible gases and is independent of the phenomenon that caused the level to be indeterminate.

The inspector reviewed ON 145-004 and determined that it provided acceptable guidance for individual reactor water level instrument failures.

The guidance addresses the use of instruments in all plant conditions.

This procedure also provides contingencies for using instruments when conditions outside their calibrated bands exist.

The inspector noted that the procedure discussed the non-condensible gas phenomenon and provided guidance for assuring that reactor water level is above the top of active fuel, to assure adequate core cooling.

Based on the changes to the EOPs and interviews with operators and shift supervision, the inspector observed that the new guidance does not significantly change the operator response to level indication failures.

The inspector considered this acceptable since, as an operational consideration, reference leg offgassing is one of several failure mode for operators to consider when evaluating whether water level can be determined.

The inspector did not identify any problems with the licensee's evaluation of the EOPs and concluded the licensee's ON procedure adequately addressed the potential for reference leg offgassing.

Safety Parameter Display System (SPDS)

The SPDS provides indication of reactor vessel level, and is designed to calculate level such that the indicated value is accurate, reliable, and insensitive to the variation of individual instrument channels.

The SPDS is designed to provide process variables that are more accurate and reliable that individual instrument channels by:

Checking for unreasonable signals due to common mode failure or out of service equipment.

Ensuring proper processing of offscale readings.

Utilizing information provided by overlapping signal ranges for various instruments.

Processing redundant instruments in the same signal range to provide the most accurate value of the process variabl SPDS willautomatically exclude data that is outside of expected ranges from level calculations and flag the data for operator information.

In addition to signals from six level instrument ranges, the level algorithm receives SPDS data for drywell temperature, core flow, and reactor vessel pressure.

These inputs provide indication of potential instrument inaccuracies caused by elevated temperatures near instrument condensate pots, core flow, and reactor coolant temperature.

The SPDS level algorithm does not specifically check for conditions indicative of reference leg offgassing.

However, the algorithm selects instrument signals within normal operating ranges.

An out of range signal willcause the program to notify the operator and switch to another set of instruments for level indication.

Level signals are selected by the algorithm on the basis of a prioritization scheme.

Priority is assigned to all signal ranges based on their instrument accuracy, number of signals, and instrument qualification. In some cases, such as a suspected common mode failure, lower priority signals may be used but must be confirmed by other valid signals.

In an indeterminate case, or ifan unconfirmed signal is selected, the display color changes and the operator is notified.

Summary PP&L has accepted the BWROG suggested operator guidance regarding potential water level indication inaccuracies caused by evolution of non-condensible gases from level instrument reference legs, with the one exception discussed above.

Licensed operators, system engineers, and I&C technicians have all received training on the phenomenon.

The operators are given at least two simulator scenarios annually that involve the loss of vessel level instruments and rapid depressurization.

Operation's procedures (ON 145-004 and EOPs)

have been revised based on the BWROG guidance.

The inspector found the licensee's actions with respect to this issue acceptable based on the guidance provided in TI-2515/119.

The inspector felt that the licensee's effort in training of engineers and I&C technicians on this issue was a good initiative.

On the basis of operator interviews, the inspector concluded that the training had provided sufficient information for operators to consider when assessing whether water level can be determined.

The inspector had no further questions.

This inspection closes TI-2515/119.

9.

MANAGEMENTAND EXITMEETINGS 9.1 Resident Exit and Periodic Meetings

The inspector discussed the findings of this inspection with station management throughout and at the conclusion of the inspection period.

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 restriction e

~

~

9.2 Inspections Conducted By Region Based Inspectors Date 6/7 - 6/10 subject Radwaste

~inn ection

~Re r~N 93-10 R~eortin

~In gec~tr J. Noggle 9.3 Management Meeting License Mi-Teer SALP Self-Assessment On May 27, NRC and PP&L management met for the Licensee's Mid-Term SALP self-assessment presentation.

PP&L management discussed their self-assessment in all SALP functional areas.

The presentation was informative and there was a meaningful exchange of information between NRC and PP&L management.

The list of meeting attendees is included in Attachment A reviati n List I

ATTACHMENT 1 AD ADS ANSI ASME CAC CFR CIG CRDM CREOASS CS DEDT DG DX ECCS EDG EDR EP EPA EQ ERT ESF ESW EWR FO FSAR HL&P HVAC ILRT I&C JIO LCO LER LLRT LOCA LOOP LPCI MSIV NCR NDI NPE NPO

- Administrative Procedure

- Automatic Depressurization System

- American Nuclear Standards Institute

- American Society of Mechanical Engineers

- Containment Atmosphere Control

- Code of Federal Regulations

- Containment Instrument Gas

- Control Rod Drive Mechanism

- Control Room Emergency Outside Air Supply System

- Core Spray

- Drywell Equipment Drain Tank

- Diesel Generator

- Direct Expansion

- Emergency Core Cooling System

- Emergency Diesel Generator

- Engineering Discrepancy Report

- Emergency Preparedness

- Electrical Protection Assembly

- Environmental Qualification

- Event Review Team

- Engineered Safety Features

- Emergency Service Water

- Engineering Work Request

- Fuel Oil

- Final Safety Analysis Report

- Houston Light and Power Company

- Heating, Ventilation, and Air Conditioning

- Industry Event Review Program

- Integrated Leak Rate Test

- Instrumentation and Control

- Justifications for Interim Operation

- Limiting Condition for Operation

- Licensee Event Report

- Local Leak Rate Test

- Loss of Coolant Accident

- Loss of Offsite Power

- Low Pressure Coolant Injection

- Main Steam Isolation Valve

- Non Conformance Report

- Nuclear Department Instruction

- Nuclear Plant Engineering

- Nuclear Plant Operator

NQA NRC NSE OI OOS PC PCC PCIS PMR PORC PSID QA RBCCW RCIC RG RHRSW RPS RWCU SGTS SI SO SOOR SPDS SPING SRV TS TSC WA

- Nuclear Quality Assurance

- Nuclear Regulatory Commission

- Nuclear Systems Engineering

- Open Item

- Out-of-Service

- Protective Clothing

- Power Control Center

- Primary Containment Isolation System

- Plant Modification Request

- Plant Operations Review Committee

- Pounds Per Square Inch Differential

- Quality Assurance

- Reactor Building

- Reactor Building Closed Cooling Water

- Reactor Core Isolation Cooling

- Regulatory Guide

- Residual Heat Removal

- Residual Heat Removal Service Water

- Reactor Protection System

- Reactor Water Cleanup

- Standby Gas Treatment System

- Surveillance Procedure, Instrumentation and Control

- Surveillance Procedure, Operations

- Significant Operating Occurrence Report

- Safety Parameter Display System

- Sample Particulate, Iodine, and Noble Gas

- Safety Relief Valve

- Technical Specifications

- Technical Support Center

- Work Authorization

ATTACHMENT2 Susquehanna

- Self Assessment Meeting May 27, 1993 Pennsylvania Power and Light Company (PP&L)

'.

Byram, Senior Vice President, Nuclear H. Woodeshick, Special Assistant to the President - Susquehanna G. Stanley, Vice President - Nuclear Operations - SSES G. Jones, Vice President - Nuclear Engineering J. Miltenberger, Manager Nuclear Safety Assessment Group T. Dalpiaz, Manager, Nuclear Plant Services H. Palmer, Jr. Manager Nuclear Operations G. Miller, Manager, Nuclear Technology E. Figard, Manager, Nuclear Maintenance A. Sabol, Manager, Nuclear Quality Assurance J. Kenny, Supervisor, Nuclear Licensing D. Hagan, Supervisor, Health Physics R. Wehry, Nuclear Compliance T. Bannon, Project Engineer D. M'Gann, Supervisor Nuclear Compliance Nuclear Regulatory Commission (NRC)

J. White, Chief, DRP E. Imbro, Deputy Director, DRS R. Clark, NRR W. Lanning, Acting Deputy Director, DRP G. Barber, Senior Resident Inspector, Susquehanna E. Wenzinger, Chief, DRP R. Cooper, Director, DRSS E. M'Cabe, Chief EP N. Blumberg, DRS R. D'Priest, DRS H. Williams, DRS W. Hodges, Director, DRS Other D. Ney, PA DER/BRP