IR 05000387/1989036

Insp Repts 50-387/89-36 & 50-388/89-35 on 891224-900210.No Violations Noted.Major Areas Inspected:Plant Operations, Physical Security,Plant Events,Surveillance & Maint

ML17157A093
Person / Time
Site:	Susquehanna
Issue date:	03/14/1990
From:	Swetland P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17157A092	List: IR 05000387/1989036 ML17157A091
References
50-387-89-36, 50-388-89-35, NUDOCS 9003290009
Download: ML17157A093 (65)

Text

Report Nos.

License Nos.

Licensee:

U. S.

NUCLEAR REGULATORY COMMISSION

REGION I

50-387/89-36; 50-388/89-35 NPF-14; NPF-22 Pennsylvania Power and Light Company 2 North Ninth Street Al 1 entown, Penn syl vani a 18101 Facility Name:

Inspection At:

Inspection Conducted:

Inspectors:

Susquehanna Steam Electric Station Salem Township, Pennsylvania December 24, 1989 - February 10, 1990 G.

S. Barber, Senior Resident Inspector, SSES J.

R. Stair, Resident Inspector, SSES R. L. Nimitz, Sr. Radiation Specialist, DRSS Approved By:

Ins ection Summar

P. Swetland, Ch ef Reactor Projects Section.No.

2A, z/i~ Vo Date Areas Ins ected:

Routine inspections were conducted in the following areas:

plant operations, physical security, plant events, surveillance, and maintenance.

Results:

During this period, Operations Department personnel generally conducted activities in a professional manner and operated the plant safely.

Routine review of maintenance and surveillance activities noted good control and performance.

A Unit 1 Reactor Scram occurred on December 24 due to a loss of offsite power.

Operator and equipment response to the scram was appropriate.

A Unit 1 forced shutdown was performed on February 1,

due to an Electrohydraulic Control System (EHC) oil leak at a main.turbine control valve fitting.

Licensee control of the evolution was satisfactory.

The cause of. the leak was due to the use of an oversized 0-ring in the servo-valve fitting.

9003 DOCK 0~00 S

290009 900316 PDR A

PDC

During Unit 1 startup on February 3, an Alert was declared due to a loss of shutdown cooling (SDC) with reactor coolant temperature exceeding 200 degrees F.

The loss of SDC resulted from a failure of the "B" RPS bus due to a ground fault.

Temperature was stabilized at approximately 250 degrees F during the event and SDC was returned to service about 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> later.

Onsite and offsite emergency response organizations were activated per the emergency plans.

Licensee actions were directed toward plant safety.

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Unit 2 Reactor Scram occurred on February 6, due to a spurious phase fault sensed in the 500 KV 'switchyard.

Operator and equipment response to the scram was appropriate.

NRC management review of a licensee contested Violation (50-387/89-01, item A.2)

involving failure to reduce control rod drive (CRD) flow to 20-25 gpm following a plant trip resulted in withdrawal of that part of the violation.

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review of Radiation Protection and Chemistry was performed, No violations were identified.

An NRC regional temporary instruction (TI) on GE AK-F-225 circuit breaker concerns and a

NRC headquarters TI on Fitness for Duty were close TABLE OF CONTENTS 1.0 Introduction and Overview Page

~ 1 NRC Staff Activities (30703, 40500, 71707, 90712, 92701)

1.2 Unit 1 Summary 1.3 Unit 2 Summary 2.0 Routine Periodic Inspections (71707)

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2.1 Scope of Review 2.2 Penetration Seal Surveillance Overdue - Unit 2 2.3 Reactor Water Cleanup System Isolation - Unit 1 (93702)

3.0 Surveillance and Maintenance Activities 3.1 Surveillance Observations (61726)

3.2 Maintenance Observations (62703)

4.0 Licensee Reports

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4. 1 In-office Review of Licensee Event Reports (90712, 92700)

4.2 Review of Significant Operating Occurrence Reports (90712, 92720)

5.0 Reactor Scram Due to an Electrical Fault - Unit 1 (93702).

6.0 Shutdown Due to an Electrohydraulic Control System (EHC) Leak - Unit

(71707)

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7.0 Loss of Shutdown Cooling; Alert Declared - Unit 1 (93702, 82701)

8.0 Reactor Scram Due to Load Rejection - Unit 2 (93702)

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9.0 (Closed)

Temporary Instruction 2515/104, Fitness for Duty:

Inspection of Initial Training Programs

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10.0 (Closed)

Regional Temporary Instruction 86-02 Inspection of General Electrical Type AK-F-2-25, Circuit Breakers (71707)

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11.0 Excessive Vessel Cooldown Violation Modification Unit 2 ( 92702 )

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12.0 Followup on Previous Inspection Items (92701; 92702)

12.1 (Closed)

Unresol ved Item (50-388/89-25-01)

12.2 (Closed) Violation (50-388/89"25-02)

12.3 (Updated) Violation (50-388/89-25-03)

12.4 (Closed) Violation (50-388/89-25-04)

12.5 (Update) Violation (50-388/89-25-05)

12.6 (Closed)

Unresolved Item (50"387/89-28-05; 50-388/89-26-05)

12.7 (Update) Violation (50-387/89-28-01; 50-388/89-26-01)

12.8 (Update) Violation (50-387/89-28-02; 50-388/89-26-02)

13.0 Radiation Protection and Chemistry (83750).

13.1 Organization and Staffing 13. 2 Radi ol og ica 1 Control s 13.3 Audits 14.0 Management Meeting - Reportabi lity of Engineering Deficiencies (30702)

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UNR 50-387/89-24-01 (Common), Reportability of MSIV Closure and Leak Detection Sensitivity Concerns 15.0 Resident Monthly Exit Meeting (30703)

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1)ETAILS Introduction and Overview NRC Resident Staff Activities The purpose of this inspection was to assess licensee activities at Susquehanna Steam Electric Station (SSES) related to reactor safety and worker radiation protection.

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

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

Unit 1 Summar At 8:23 a.m.

on December 24, a Unit 1 Reactor Scram from 100 percent power occurred due to an offsite electrical fault.

Plant response to the scram was normal.

Full power was restored on December 28 following restoration of the 230KV switchyard.

See Section 5.0 for details.

Full power was maintained until February 1, when a controlled shutdown was performed due to an electrohydraulic control (EHC) system leak on a one inch line to the number four control valve.

Cold Shutdown was reached at 2:40 a.m.

on February 2.

The unit remained in Cold Shutdown until repairs to the EHC line were made.

Startup commenced on February 3, when a loss of shutdown cooling (SDC) occurred due to a ground fault on the "B" Reactor Protection System (RPS)

Bus and an Alert emergency action level was declared.

The Alert was terminated shortly after midnight on February 4 when SDC was reestablished.

See Section 7.0 for details.

Modifications to both RPS buses were completed during the week of February 5 and the unit was placed in startup on February 10, at 1:00 a.m.

The reactor was brought critical at 3:40 a.m.

on February 10, but power ascension was delayed due to problems with the Rod Drive Control System (RDCS).

Startup recommenced on February ll, after repairing the RDCS.

The.generator was placed on line at 1:11 p.m.

on February 11.

Unit,2 Summar Unit 2 operated at full power until a drain cooler relief valve leak occurred on the "B" Feedwater string on January'23.

Power was reduced to 75 percent in order to isolate the string and perform repairs.

Full power was restored on January 24 and was sustained until an automatic scram occurred on February 6.

The scram occurred while work was being performed in the 500KV switchyard.

A breaker opened resulting in a turbine trip and reactor scram.

See Section 8.0 for details.

This was the first automatic scram at Unit 2 in 1026 days of operatio 'The unit remaimed shutdown pending repairs in the 500KV switchyard and installation of the same RPS bus modification that was performed in Unit 1 prior to the February 10 restart.

The unit'emained shutdown through the end of the inspection period.

2.0 Routine Periodic Ins ections The inspectors periodically inspected the facility to evaluate the safety of plant operation and to determine the licensee's compliance with the general operating requirements of the Technical Specifications (TS) in the following areas:

review of selected plant parameters for abnormal trends; plant status from a maintenance/modification viewpoint, including plant housekeeping and fire protection measures; control of ongoing and special evolutions, including control room personnel awareness of these evolutions; control of documents, including logkeeping practices; implementation of radiological controls; implementation of the security plan, including access control, barrier integrity, and badging practices; control room operations during regular and backshift hours, including frequent observation of activities in progress, and periodic reviews of selected sections of the unit supervisor'

log, the control room operator's log and other control room daily logs; followup items on activities that could affect plant safety or impact plant operations;

, areas outside the control room; and, selected licensee planning meetings.

The inspectors conducted weekend/holiday inspections on January 12, from 2:00 a.m. to 6:00 a.m.,

February 2, from 2:00 a.m. to 6:00 a.m.,

February 3, from 6:30 p.m. to midnight, and February 4, from 12:00 a.m.

to 2:00 a.m..

The inspectors reviewed the following specific items in more detail:

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2.2 Penetration Seal Surveillance Oue Date Exceeded - Unit 2 On December 29, 1989 with Unit 2 operating in Condition 1 at 100 percent power, the licensee identified that the unit had operated in a condition prohibited by the Technical Specifications in that surveillance require-ment 4.7.7.1 requiring an 18 month inspection of fire barriers (penetration seal portion) had'not been completed within the allowances (1.25 x the surveillance frequency) of Technical Specification 4.0.2.

The licensee had been in the process of generating a

CFR 50 Appendix R data-base list of each type of sealed penetration, to allow a major revision to the surveillance procedure.

The inspection method was being altered from 100 percent of all penetrations to a 10 percent sample of each type of sealed penetration per Technical Specification 4.7.7. 1.

Failures in the first sample group require an expanded surveillance sample size.

When the surveillance commencement date arrived in mid-July 1989, the surveillance was commenced using the old method.

Since the database list was nearing completion, the surveillance was temporarily suspended on July 25 pending completion of documents for the new method.

The revisions were subse-quently completed and the surveillance was restarted.

The initial sample resulted in four (4) type "A" seals being found inoperable.

Compensatory actions were taken and an additional 10 percent sample (48 seals) of type

"A" seals were chosen for inspections The additional sample, however, was not inspected prior to the overdue date for the surveillance (December 27, 1989).

Administrative procedure AD-gA-906 included a section which allowed conduct of expanded samples after the surveillance overdue date.

This was deter-mined to be in conflict with Technical Specification 4.0.2.

This error was not recognized until December 29, 1989 at which time Technical Specifi-cation 4.0.3 was entered which allows 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to perform a missed surveillance.

When personnel determined that the surveillance could not be completed within the 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, all type "A" seals in the Unit 2 Reactor Building which had not been inspected were declared inoperable and compensatory firewatches were established within one hour.

The additional (48) type "A" seal inspections were successfully completed on January 8,

1990.

The licensee determined the cause of this event to be procedural error.

The administrative procedure (AD-gA-906) has been revised to delete the incorrect statement allowing inspection of additional samples after the required date.

The licensee also clarified the surveillance procedures and new database.

The revised surveillance procedures and the new database are currently in place.

Future performances of this surveillance will be scheduled for implementation approximately two months prior to the surveillance due date.

This will allow adequate time for additional inspections, if required, to be completed prior to the overdue dat, v l

Although the licensee determined that the root cause of this event was 'due to a procedural error, it appears that lack of attention by management also contributed to the cause.

Closer attention to detail could have identified the procedural deficiency and/or the incompleted surveillance in time to schedule and complete the surveillance prior to its overdue date.

However, credit is given to the licensee for the identification, reporting and correction of this event.

The failure to complete the penetration seal surveillance within the required time interval is considered a licensee identified violation per

CFR 2.

(NON 50-388/89-35-01).

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Reactor Water Cleanu S stem Isolation Unit

At 1:30 p.m.

on February 3, while in cold shutdown and preparing to return the unit to service, a Reactor Water Cleanup System (RWCU)

isolation occurred.

Investigation by the licensee found that power was lost to the 208/120V AC instrument distribution panels 1Y218 and 1Y219.

This occurred because the uninterruptible power supply (UPS) panel 10240 inverter output breaker opened.

The breaker opened due to the UPS sensing undervoltages on its normal and alternate 480 volt supplies, and its backup battery which contained a failed cell.

The 480 volt undervoltages were caused by a large power fluctuation when the "B" reactor recirculation pump motor-generator set was started.

As a result of the loss of 1Y218, the RWCU system outboard isolation valve (HV-144-F004) closed.

The closure of F004 also led to the closure of the inboard isolation valve (HV-144-F001) due to a high differential flow signal.

Additional functions/instrumentation lost included the full core display, control rod drive system flow, various reactor vessel level indications, and the neutron flux recorders'ince the power fluctuation was momentary, the UPS was returned to its normal power supply and the output breaker closed restoring power to 1Y218 and lY219.

The bad battery cell was also replaced and the battery was returned to service.

The licensee believes that this failure sequence was an isolated case in that the simultaneous low voltage condition on both buses supplying power to the UPS on the start of a reactor recirculation pump motor generator set is not a normal occurrence.

Additionally, the UPS and its loads are non safety related and are not required for safe shutdown of the plant.

The licensee is developing a

UPS battery test to be incorporated into the existing semi-annual preventive maintenance activity for the UPS in order to provide greater assurance of the batteries'perability.

The licensee's experience with these batteries is limited due to the new gel

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type electrolyte which they contain.

Testing at six month intervals will allow a trending of failure rates in order to determine an appropriate replacement frequency.

The licensee made the required 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> notification to the NRC per 10 CFR 50.72 at 5:26 p.m.

on February 3,

and notified the NRC resident inspector.

The inspector had no further questions on this event.

3.0 Surveillance and Maintenance Activities 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.

3.1 Surveillance Observations The inspector observed and/or reviewed the below listed survei llance tests to determine that the following criteria, if applicable to the specific test, were met:

the test conformed to Technical Specification requirements; administrative approvals and tagouts were obtained before initiating the surveillance; testing was accomplished by qualified personnel in accordance with an approved procedure; test instrumentation was calibrated; Limiting Conditions for Operations were met; test data was accurate and complete; removal and restoration of the affected components was properly accomplished; test results met Technical Specification and procedural requirements; deficiencies noted were reviewed and appropriately resolved; and the surveillance was completed at the required frequency.

These observations and/or reviews included:

S0-151-002, Quarterly Core Spray System Flow Verification, performed on January 11, 1990.

S0-249-002, Quarterly Residual Heat Removal System Flow Verification, performed on January 10, 1990.

S0-131-003, Rod Worth Minimizer Operability Demonstration, performed on February 1,

1990.

S0-156-006, Rod Sequence Control System Rod Motion Block During a Power Reduction, performed on February 1,

1990.

TP-250-006, Reactor Core Isolation Cooling Pump Performance Test, performed on February 1,

1990.

No unacceptable conditions were identifie.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 admini strative 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 perfor'med 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'nd/or reviews included:

Cleaning and inspection of Reactor Building Chilled Mater Heat Exchanger 2K206B per WA P92196, performed on January 8,

1990.

The Eighteen Month Inspection of Diesel Generator OG501E per SM-024-002 and WA A93343 which was observed on January 10, 1990.

Replacement of Control Structure Fan OV105 Inboard Bearing, performed per WA S03010 on February 1,

1990.

Division II Swing Bus Motor-Generator Set 1G203 Annual and 6 Year Preventive Maintenance performed per WA P93868 and MA P93791 on February 1, 1990.

No inadequacies were noted.

4.0 Licensee Re orts 4. 1 In-office Review of Licensee Event Re orts LERs The inspector 'reviewed LERs submitted to the NRC to verify that the details of the event were clearly reported, including the accuracy of 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 followup ~

The following LERs were reviewed:

Unit 1 89-025 89-027 Reactor Water Cleanup System Isolation Due to Steam Leak Detection High Temperature Signal.

This event was reviewed in NRC Inspection Report 50-387/89-34.

Generator Load Reject Caused by Switchyard Problems Results.in Automatic Reactor Scram.

This event is reviewed in Section 5.0.

Unit 2 88"015-01 Plant Operations With Surveillance= Requirements Not Performed Within Their Allowed Intervals.

This event was reviewed in I

NRC inspection Report 50-388/88-19.

89"010-01 Main Steam Line Penetrations Exceed Maximum Allowable Leak Rate During Regularly Scheduled Local Leak Rate Testing.

This event was reviewed in NRC Inspection Report 50-388/89-27.89-016 Fire Barrier Surveillance Not Completed Within Technical Specification 4.0.3.

This event is reviewed in Section 2.2.89-017 Unplanned ESF Actuation During Surveillance Testing Due to a Failed Relay.

This event was reviewed in NRC Inspection Report 50-388/89-33.

No inadequacies were noted.

4.2 Si nificant 0 eratin Occurrence Re orts Significant Operating Occurrence Reports (SOORs)

are provided for problem identification and tracking, short and long term corrective actions, and reportability evaluations.

The licensee uses SOORs to document and bring to closure problems identified that may not warrant an LER.

The inspectors reviewed the following SOORs during the period to ascertain whether:

additional followup inspection effort or other NRC response was warranted; corrective action discussed in the licensee's report appears appropriate; generic issues are assessed; and, prompt notification was made, if required:

1-89-376; 1-89-378; 1-89-379)

1-89-380; 1-90-002; 1-90-003; 1"90-004; 1-90-005; 1-90-011; 1-90-012; 1-90-013; 1-90-014; 1-90-018; 1"90-019; 1-90-021; 1-90-023; 1"90"029; 1-90-030; 1"90-031; 1-90-032; 1-90-037; 1-90-038; 2-89-233; 2-90-001; 2"90-005; 2"90-006; 2-90-007; 2-90-008; 2-90-012; 2"90-013; 2"90-014; 2"90-017; 1"89-381 1-90-007; 1-90-015; 1-90-024; 1-90-034; 2-90-002; 2-90-009'-90-018; 1-89"382; 1-90"009; 1-90"016; 1"90-027; 1-90-035;

.2-90-003'-90-010; 2-90-019; 1-90-001; 1-90"010; 1-90"017; 1-90-028; 1-90-036; 2-90-004; 2-90-011; 2-90"02 'The following SOORs required inspector,followup:

1-89-377 documented a Unit 1 Reactor Scram due to an offsite electrical fault.

See Section 5.0 for details.

1-90-020 documented a Unit 1 shutdown due to an Electrohydraulic Control System oil leak.

See Section 6.0 for details.

1-90-025 documented a Reactor Water Cleanup System Isolation due to a power fluctuation.

See Section 2.3 for details.

1-90-026 documented a failure of the "B" RPS Bus resulting in an emergency action level Alert being declared.

See Section 7.0 for details.

2-89-234 documented the failure to complete a penetration fire seal surveillance within the required time frame.

See 2.2 for details.

2-90-016 documented a Unit 2 Reactor Scram due to a phase fault.

See Section 8.0 for details.

5.0 Reactor Scram Due to an Electrical Fault - Unit

The licensee reported that a Unit 1 reactor scram occurred due to an offsite electrical fault at 8:23 a.m.,

December 24.

The Unit 1 230kv switchyard services are supplied by a 12kv offsite line from a local gas company (UGI) and by a small supporting diesel generator (OG) located in the 230 kv switchyard.

These station services supply the switchyard lighting and heating, SF6 circuit breaker compressors and other miscel-laneous loads.

The licensee was informed by UGI that an automobile accident downed one phase of the 12kv line that,fed the Unit 1 230kv switchyard.

This ground fault tripped the 12kv supply and started the support DG.

This DG was rated to supply at least 700 amps on a continuous basis.

The diesel started at approximately 6:30 a.m.

and initially supplied all station services loads until it tripped prematurely at a load of approximately 300 amps.

This interrupted electrical power to the SF6 gas compressors which are an integral part of each switch yard breaker.

The SF6 gas is used to cool and quench the arc generated when the breakers open.

When the gas pressure bled down to the trip point, the east and west bus breakers of the breaker and a half scheme tripped which forced the entire electrical output of the Unit 1 generator through the Jenkins line.

This, in turn, over loaded the Jenkins line, tripping its breaker which generated a load rejection signal.

The main generator output breaker tripped and the turbine tripped.

A reactor scram was generated due to turbine control valve fast closure.

Two safety relief valves (SRVs)

lifted and reseated due to the load rejection.

Both reactor recirculation (recirc)

pumps tripped, as designed, on low reactor water level.

No emergency core cooling systems (ECCS) actuated nor were they require Plant response to the scram was normal.

The licensee reported the scram per

CFR 50.72 (b)(2)(ii).

In addition, two followup ENS calls were made for the press releases for the shutdown and subsequent startup.

6.0 The root cause of this event was external.

However, the standby support diesel generator's inability to carry rated load propagated the effects of the initial fault.

Previous s'crams have been caused by reliability problems in the offsite electrical distribution system.

Offsite system reliability should be reviewed to prevent unnecessary challenges to plant equipment.

The inspector discussed this concern with licensee management at the exit meeting.

The inspector had no further questions on this issue.

Shutdown Due to an Electroh draulic Control S stem EHC Leak - Unit 1 At 8:34 a.m.

on February 1,

a leak from the EHC System was discovered emanating from a Servo valve fitting in the one-inch fluid actuator supply (FAS) line to the number 4 main turbine control valve.

A power reduction was commenced at 8:55 in order to shutdown the unit and repair the leak.

The leak was estimated at less than 2 gpm.

A controlled shutdown was performed by manually inserting individual control rods prior to a manual reactor scram at 17 percent power at 1:50 p.m. It became necessary to cooldown below hot shutdown conditions, when it was discovered that the EHC leak could not be isolated from the turbine bypass system and control of the turbine bypass valves is needed for decay heat removal in hot shutdown.

Cold Shutdown was entered at 2:40 a.m.

on February 2.

The licensee previously installed a modification on Unit 2 which allowed the EHC piping to the main turbine controls to be isolated without disabling the turbine bypass system.

This same modification is planned for Unit 1.

The shutdown was reported to the NRC per

CFR 50.72 due to issuing a press release.

Investigation by the licensee found that the leak resulted from a failed

"0" ring in the fluid actuating supply line connection to the servo-valve.

The "0" ring was determined to be the wrong size for the fitting.

The licensee inspected both units and found two additional fittings with the wrong size "0" rings which were replaced.

The reason the wrong sized "0" rings were used was that the previous "0" rings were replaced during construction in 1983, when a plant modification to convert to full arc admission, was installed using a standard Parker "0" ring kit instead of the General Electric supplied "0" ring kit.

The licensee determined that this error would be prevented by current maintenance/

modification practices.

The inspector had no further questions on this event.

7.0 Loss of Shutdown Coolin

. Alert Declared - Unit 1 During a plant startup on February 3, 1990 at 5:53 p,m., the licensee declared an Alert condition due to a loss of shutdown cooling with

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reactor temperatures exceeding 200 degrees F.

No radioactivity was released off site during the event and no personnel contaminations occurred.

The Senior Resident Inspector monitored activities throughout the event and noted that the licensee'

actions were appropriate and directed toward plant safety.

The licensee issued a Press Release for the Alert and for the termination of actions under the Emergency Plan.

A special inspection was conducted by Region I to review licensee actions in response to this event.

See NRC Special Inspection Report 50-387/90-05; 50-388/90-05 for details.

The inspector attended a critique conducted by the licensee on February 16, 1990 to assess their response to the Alert declared on February 3.

This critique was attended by representatives from Pennsylvania Emergency Management Agency, Pennsylvania Bureau of Radiation Protection, representatives of Luzerne and Columbia counties, the Federal Emergency Management Agency, and plant management and staff.

The inspector noted that the licensee performed a critical review of the event, including reviewing the incident, assessing the response and identifying areas of concern.

They concluded that the Emergency Response Organization was well prepared to respond to an emergency.

Areas identified by the licensee for improvement include the interface with offsite officials and media and some of the content and implementation of emergency response procedures.

No significant deficiencies in their response were identified.

The licensee committed to address all areas identified for improvement.

No further inadequacies were noted.

8.0 Reactor Scram Due to Load Re ection - Unit 2 A reactor scram occurred at 9:06 a.m.,

February 6 due to a load rejection from full power.

A main generator power/load unbalance signal caused a

turbine trip and subsequent reactor scram.

Investigation by the licensee identified a high resistance states link connection to a ground fault relay on one of the three differential current transformers sensing output to the Wescoville line.

This resulted in a spurious fault being sensed on that phase which caused the Wescoville bus breaker to open, forcing the entire generator output through the Sunbury line.

This, in turn, over-loaded the Sunbury line, tripping its breaker which generated a load rejection signal.

The main generator output breaker tripped and the turbine tripped.

A Reactor Scram was generated due to turbine control valve fast closure.

Three safety relief valves (SRVs) lifted and reseated due to the load rejection.

Both reactor recirculation pumps tripped, as designed, on low reactor water level.

No emergency core cooling systems actuated, nor were they required.

Plant response to the scram was normal.

The licensee reported the scram per

CFR 50.72(b)(2)(ii).

The root cause of the scram was equipment failure.

During a realignment of the 500kv switchyard to support maintenance, the electrical alignment was altered such that twice the current passed through the faulty states link.

The licensee postulated that the high resistance connection at the link caused a voltage drop which resembled a phase to ground fault, and generated the differential current trip.

The licensee is reviewing main-tenance practices and monitoring capability to prevent future recurrence.

No further inadequacies were noted.

9.0 Closed Tem orar Instruction 2515/104 Fitness for Dut.:

Ins ection of Initial Trainin Pro rams On June 7,

1989, the commission published the final rule and statement of policy on fitness for duty (FFD) programs, with an effective date of January 3,

1990.

Appropriate FFD awareness training for employees and training for supervisors and escorts is required by the rule, with all initial training to be completed prior to assignment of duties within the scope of 10 CFR 26, with the exception of new supervisors, who will be trained within three months of their initial assignment.

Temporary Instruction (TI) 2515/104 provided the inspection criteria to evaluate licensee FFD training.

Three types of training were reviewed per the TI.

They were Policy Awareness Training for all employees, FFD Training for supervisors and FFD Escort Training.

The inspector attended the escort training.

The inspector evaluated the other training activities by interviewing instructors and attendees, reviewing lesson plans and handouts, and by reviewing selected attendance records.

The lesson plans and handouts clearly stated the licensee'

policy and procedures for dealing with FFD, including, what is expected of employees with regard to FFD and what happens if an employee does not adhere to the FFD program.

The function of the medical review officer and the employee assistance programs was also emphasized.

Supervisors were counseled on drug recognition and behavioral observation techniques, including, what action to take if they suspected an employee was abusing alcohol or drugs on the work site or prior to coming to work.

A videotape of the Senior (SR) Vice President (VP) was presented during the general employee and supervi sory training.

The SR VP overviewed the FFD program and emphasized PP&L's commitment to a drug free work place.

Escorts received training in drug recognition and their responsibi lities in accordance with the FFD program.

Licensee sample cutoff levels were equivalent to or more conservative than those required per

CFR 26.

No unacceptable conditions were identifie.2 10.0 The transition into the new FFD program was performed with minimal impact since the licensee had a preexisting program.

The publication of

CFR 26 caused the licensee to strengthen certain program aspects and to include a

new requirement for random drug testing with dignity.

The licensee is committed to FFD as evidenced by their appointment of a dedicated full time staff and the construction of an access processing facility to provide employees'and contractors expedient walk through service.

No inadequacies were noted.

This TI is closed.

Closed Re ional Tem orar Instruction 86-02 RI-86-02 Ins ection of General Electrical GE T

e AK-F-2-25 Circuit Breakers Region I issued RI-86-02 to inspect the use of GE AK-F-2-25 circuit breakers.

There were three documented failures of these circuit breakers to trip over a three year period at the Pilgrim Nuclear Generating Station.

These failures resulted when internal binding in the trip linkage prevented the trip coil from performing its function.

Inherent in these failures was that this binding would also have prevented the Abnormal Transient without a Scram.(ATWS) trip coil from operating.

Thus, inspections were necessary to verify proper maintenance and oversight of these breakers to minimize the likelihood of failure to trip incidents.

The inspector reviewed the guidelines of RI-86-02 for both Susquehanna units and found that these breakers are used in 8 different locations for both units.

The "A" and "B" Recirculation (Recirc)

Pump Motor Generator (MG) set field breakers (1C062A/B and 2C062A/B) and the Main Generator Excitation and Regulator Circuits (1G103A/B and 2G103A/B) use these breakers.

All of these breakers are DC field breakers.

The inspector noted that these breakers are subject to two different types of maintenance:

cleanings and overhauls.

These activities are controlled by the licensee's Work Authorization (WA) and maintenance procedure program.

The physical cleaning and light inspection is performed per MT-GE-014, DC Switchgear Inspection and Breaker Maintenance Step 5. 1 and Preventative Maintenance (PM)

WA E1744-01.

Breaker overhaul is conducted per MT-GE"014 and a

PM WA.

MT-GE-014 provides comprehensive instructions for both breaker cleaning and overhaul.

Procedure checklists require recording and adjusting critical parameters from the applicable vendor manual.

The licensee stated that no failures to trip have occurred on any of the listed breakers for the life of the plant.

In addition, breaker overhauls are performed with GE service personnel present.

The ATWS Recirc Pump Trip (RPT) function is performed by a different set of breakers which are not subject to the previously mentioned failure The inspector noted that the licensee's maintenance of these breakers is thorough and comprehensive.

Procedures are used extensively.

All breaker problems are promptly investigated and since there is no history of the noted problem, this regional TI is closed.

11.0 Excessive Vessel Cooldown Violation Modification - Unit 1 Inspection Report 50-387/89-01 reviewed the licensee's actions during an excessive vessel cooldown event that occurred on January 12, 1989.

Since the event was not discovered until January 16, 4 days later, during the subsequent startup, the NRC conducted an enforcement conference and issued a Notice of Violation on May 12, 1989.

The licensee responded to'he violation on June 12, 1989 in PLA-3204; and contested example 2 of Violation A of the Notice.

Violation Item A.2 stated that:

"Technical Specification 6.8.1 requires that written procedures important to safety shall be established and implemented.

SSES Emergency Operating Procedure EO-100-101 (Attachment A), "Scram",

specifies that CRD (Control Rod Drive) flow shall be decreased to 20-25 gpm following a reactor scram if a reactor recirculation pump cannot be started.

Contrary to the above, on January 12, 1989, following a reactor scram, flow remained at least 60 gpm, although neither reactor recirculation pump could be started."

The licensee responded as follows:

"PP&L does not concur that a violation occurred.

Following the Reactor Scram on January 12, Operations personnel properly implemented EO-100-101.

The procedure step requiring CRD flow to be reduced comes after it is determined that a Recirculation Pump can not be started.

This condition did not exist following the January 12th scram.

When the pump restart step was ultimately reached in the EO sequence, it was started on a first attempt.

Therefore, no corrective action is necessary."

The inspector discussed this response with the licensee and reviewed the reactor scram procedure, E0-100-101, to determine if the licensee's response was accurate.

This procedure directs the operator to start the recirculation pumps before reducing CRD flow.

This cooling flow reduction to 20-25 gpm is only required if a recirculation (recirc)

pump can not be started.

Operators believed that the pumps could be started

" 14

- with the normal time delays needed to establish initial conditions.

Thus, even if they had chosen to proceed ahead in the procedure, CRD flow would not have been reduced since the procedure asks

"Can a recirc pump be started."

The answer would be "yes" and the cooling flow reduction step would be bypassed.

This violation cited the licensee for failing to follow procedures.

In addition, the violation also intended to identify that, in this case, the licensee was slow to perform procedure steps which exacerbated the cooldown.

However, the current wording of the affected step would direct the operator to bypass the CRD flow reduction step.

The licensee has recognized that procedure improvements are necessary to assure that CRD flow is promptly controlled to minimize thermal stratification.

The licensee has submitted specific changes to be included in the next EOP revision, Those changes have not yet been implemented.

Nonetheless, it is apparent that operators followed existing steps of procedure EO-100-101 'herefore, example A-2 of Violation A of Inspection Report 50-387/89-01 will be withdrawn.

The correct and timely implementation of revisions to EO-100"101 will be followed under unresolved item 387/89-36-02.

12.0 Followu on Previous Ins ection Items 12.1 The inspector reviewed licensee action, if applicable, on previous inspection findings to ensure that the licensee took appropriate action in response to NRC findings or by self initiative, and that the licensee's actions were adequate and timely:

Closed Unresol ved Item 50-388/89-25-01 12.2 The licensee was to provide additional information to support the adequacy of the dose assessment for the individual who received an unplanned exposure of the upper left area of the chest.

The information to be provided was the licensee's evaluation of the presence of all beta emitting radionuclides in the source and the calibration information for the exoelectron dosimeter which was used, in part, to determine the dose to the individual.

The licensee provided adequate documentation that demonstrated that all approp-riate radionuclides, including beta emitters, were factored into the dose assessment.

The licensee also provided information to demonstrate that the exoelectron dosimeter was properly calibrated.

This item is closed.

Closed Violation 50-388/89-25-02 Licensee personnel did not perform radiation surveys to ensure compliance with 10 CFR 20, The inspector reviewed the implementation of the corrective actions outlined in the licensee's December 1, 1989, letter to the NRC.

The inspector's review found that the licensee implemented the corrective actions outlined in the letter.

The corrective actions included review of all standing radiation work permits (RWPs) for adequacy,. revision of the

~ l F

I

0

12.3 chemistry sampling standing RWP to provide for appropriate radiation surveys, and revision of the chemistry sampling standing RWP to provide for use of alarming dosimeters.

The licensee also provided radiological training to appropriate chemistry technicians.

This training included the need to perform radiation surveys of chemistry samples.

T5is item is closed.

U dated Violation 50-388/89-25-03 12.4 The licensee did not inform chemistry personnel of radiological concerns during chemistry sampling as required by 10 CFR 19.12.

The inspector reviewed the implementation of the corrective actions outlined in the licensee's December 1,

1989, letter to the NRC.

The inspector found that the licensee implemented the corrective actions outlined in the letter.

The corrective actions included evaluation of the control of all site contractors, development of a Nuclear Department Instruction (NDI) for control of contractors, and improved control over chemistry sampling station access keys.

The licensee remains to train appropriate station personnel in the new NDI.

The training in the NDI is scheduled to be completed by March 31, 1990.

The implementation of the training will be reviewed during a subsequent inspection.

Closed Violation 50-388/89-25-04 12.5 The licensee's chemistry personnel did not adhere to the chemistry sampling radiation work permit as required by procedures..

The inspector reviewed the implementation of the cor rective actions outlined in the licensee's December 1,

1989, letter to the NRC.

The inspector found that the licensee implemented the corrective actions outlined in the letter.

The licensee reviewed this item with chemistry personnel, evaluated the adequacy of standing radiation work permits, reviewed chemistry work practices, and provided training of appropriate chemistry personnel in radiological matters.

This item is closed.

U dated Violation 50-388/89-25-05 The licensee did not establish procedures for certain chemistry sampling activities.

The inspector reviewed the implementation of the corrective actions outlined in the licensee's December 1,

1989, letter to the NRC.

The licensee implemented the corrective actions.

The inspector found that the licensee reviewed the management control of all contractors, ensured all contractors were properly controlled, and established a

Nuclear Department. Instruction (NDI) for control of contractors.

The licensee has yet to train personnel in the NDI. The training is scheduled to to be completed by March 31, 1990.

The implementation of the licensee's commitment to train personnel in the new NDI will be reviewed during a subsequent inspectio,i

~

~

I

12.6 Closed Unresolved Item 50-387/89-28-05 50-388/89-26-05 12.7 NRC to review the licensee's evaluation and corrective actions on a

self-assessment finding that all area radiation monitors (ARMs) at the station were not being periodically calibrated.

The inspector's review indicated the licensee had properly calibrated all ARMs. The licensee also established an 18 month preventative maintenance program for checking and calibrating the ARMs. This item is closed.

U dated Violation 50-387/89-28-01 50-388/89-26-01 12.8 Licensee personnel did not document radiation surveys as required by 10 CFR 20.

The inspector reviewed the implementation of the corrective actions outlined in the licensee's December 20, 1989, letter to the NRC.

The inspector found that the licensee documented the surveys and trained personnel on the requirement to document radiation surveys.

The licensee has not yet revised the procedure for diving operations.

The procedure revision is scheduled to be completed by March 31, 1990.

Also, the licensee will include the need to document surveys in the training program for contractor radiation protection technicians.

The implementation of the procedure revision and contractor technician training will be reviewed during a subsequent inspection.

U dated Violation 50-387/89-28-02 50-388/89-26-02 13.0 Licensee personnel did not adhere to radiation protection postings as required by procedures.

The inspector reviewed the implementation of the corrective actions outlined in the l,icensee's December 20, 1989 letter to the NRC.

The inspector found that the licensee counseled involved personnel and issued notices to personnel on December 13, 1989, and January 17, 1990 regarding the need to adhere to plant postings.

The licensee implemented the corrective actions as outlined.

However, at the time of the inspection the licensee had not yet discussed the need to adhere to plant postings with personnel during pre-outage meetings.

The discussion is scheduled to occur before the beginning of the Unit 1 outage (September 1990). This was consistent with the licensee's commitments.

The discussions of plant posting adherence with all station personnel prior to the outage will be reviewed during a subsequent inspection.

Radiation Protection'and Chemistr 13.1 Or anization and Staffin The inspector reviewed the organization and staffing of the radiological controls organization against criteria contained in the licensee's Technical Specifications.

The following observations were discussed with licensee personnel:

The licensee'

current radiation protection supervisor is attending plant certification training. This extensive training provides

" detailed knowledge of plant systems.

The individual acting in the position of radiation protection supervisor meets Technical Specification qualification requirements.

The licensee performed two assessments of the Chemistry organization.

The licensee concluded that the organization could be enhanced to improve performance.

The licensee is currently reorganizing the chemistry department.

13.2 Radiolo ical Controls The inspector toured the facility during the inspection.

The inspector reviewed general radiation protection practices including: the posting, barricading, and access control (as appropriate)

to radiation, high radiation and airborne radioactive material areas; control of radioactive and contaminated ma'terial, worker practices such as proper frisking and use of dosimeters; and adherence to radiation work permits.

No violations were identified.

The following matters were brought to the licensee's attention:

The inspector identified several emergency exit doors leading from the diesel generator building into the Unit 1 condensate storage tank (CST) area.

The CST is a radiological controlled area (RCA).

The doors were not identified as an RCA boundary.

The doors were immediately posted as such.

The licensee's procedures only require that the main entrances to the radiological controlled area be posted as a "Caution Radioactive Materials Area." The inspector informed the licensee that

CFR 20 requires that each room or area be identified as a

radioactive materials area if they meet the criteria specified therein.

The licensee indicated that the procedure would be revised as appropriate and that each room or area, as appropriate, would be separately posted as a radioactive materials area by February 16, 1989.

The inspector reviewed the radiological controls provided for on going work on the Unit 1 reactor water cleanup pump seals.

The inspector considered the radiological controls to be good.

The inspector did note that the seals were repaired on a frequent basis.

The frequent repairs contribute to a significant portion of the aggregate exposure of station maintenance personnel (e.g.,

25 percent for 1989).

The licensee is aware of the problems with the seals and is taking action to address the frequent repairs.

The inspector noted that the action appears to be encountering some delays associated with engineering revie The inspector tours noted a need for additional licensee attention to the area of contamination controls.

The inspector noted material such as hoses and electrical cables running from contaminated areas to clean areas.

The hoses an'd cables were not secured to prevent inadvertent contamination of clean areas.

The inspector observed material in contaminated areas protruding out of the boundary of the contaminated area into clean areas.

Also, the inspector noted that fr'iskers were not readily available to personnel upon exiting con-taminated work areas.

This hampered timely frisking of the personnel to quickly detect potential contamination.

The licensee indicated these matters would be reviewed.

13.3 Audits The inspector reviewed the licensee'

gA survei 1 lances and audits of the radiation protection program.

The inspector considered the surveillances to be performance based and of generally good quality.

Summaries of surveillance findings are provided to station management for their review.

The inspector review of the most recent gA audit (audit 89-067 dated September I, 1989) indicated the audit covered all major functional areas of the radiation protection program.

However, the audit principally focused on review of documentation.

Little apparent review of actual ongoing work activities was noted.

The inspector indicated that although the 'audits did cover appropriate areas, additional observation of ongoing activities would, enhance the quality of the audits.

The licensee indicated this matter would be reviewed.

14.0 Mana ement Meetin

- Re ortabilit of En ineerin Deficiencies A management meeting was conducted beween the NRC and the licensee on December 19, at the NRC Region I office, to discuss reportabi lity of engineering deficiencies.

The meeting was necessary to understand the licensee's reporting threshold for these deficiencies.

The NRC had previously conducted an inspection to review reportability which was documented in NRC Inspection Report 50"387/89-24.

The NRC concluded that the licensee established too high of a threshold for reportabi lity of engineering deficiencies and it was agreed that the licensee would present their rationale in a management meeting.

During the meeting, the licensee discussed the material provided as Attachment A to this report.

The licensee also recognized the need to put into place a specific program to resolve questions or concerns regarding the plant's design basi s.

The licensee created a program to

address these concerns and calls it the Engineering Deficiency Program.

It is intended to address concerns that don't conveniently fit into other corrective action programs, such as the Non Conformance Report and SOOR programs.

The program would address these concerns and provide immediate operabi lity/reportabi lity determinations.

The licensee stated that they would use

CFR 50.9 to initially report engineering issues that had questionable reportability.

When it is determined that an issue is reportable per 10 CRF 50.72 or 50.73, then the appropriate notifications would be made and a Licensee Event Report (LER) would be written.

At the meeting the licensee agreed to document the leak detection sensitivity issue in a

CFR 50.9 report and the Main Steam Isolation Valve (MSIV)

closure issue in an LER.

14.1 The NRC agrees that the licensee should improve the timeliness of its notification to NRC on reportable matters.

CFR 50.9 reports submitted by the licensee will be reviewed by the NRC but should not be substituted for those conditions covered by other regulations.

The NRC will view 10 CFR 50.9 reports as a licensee initiative to provide early notification of issues that might be otherwise reportable.

Closed UNR 50-387/89-24-01 Common Re ortabilit of MSIV Closure and Leak Detection Sensitivit Concerns The above unresolved item documented the need for the licensee to reevalu-ate the reportability of slow MSIV stroke times and the lack of timely steam leak detection.

The leak detection system was designed to provide timely detection and isolation for a

gpm leak.

The licensee found the actual time for leak detection to be wel.,l in excess of 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br />.

A 10 CFR 50.9 report was issued for the lack of leak detection system sensi-tivity.

The licensee is continuing to evaluate whether this issue was reportable under

CFR 50.72 and 50.73.

The inboard MSIV closure times would have been slow if the MSIVs were required to close with springs alone against maximum containment pressure.

The licensee determined that the slow MSIV closure issue was reportable.

An LER was issued for the slow MSIV closure.

The failure to report this condition in a "timely" manner constitutes a violation which will not be cited because the criteria of 10 CFR 2 Appendix C Section V.A were met (NON 387/89-36-01 (Common)).

This unresolved item is closed.

15.0 Resident Monthl Exit Meetin The inspector discussed the findings of this inspection with station management 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 ATTACHMENT A AGENDA PP8cL MEETING WITH NRC DESIGN ISSUES REPORTABILITY

INTRODUCTION

BASIS FOR REPORTING DESIGN ISSUES AL MALE RAY HARRIS

NEW ENGINEERING DISCREPANCY PROGRAM AL MALE

PROCESS FOR REPORTING DESIGN ISSUES JIM KENNY

CONCLUSION JIM KENNY

I I

INTROD UCTION

- 0 CONSER VATIVE SAFETY CULTURE VOLUNTARY SHUTDOKVS FOR S'IGLVIFICAIVT ISSUES AGGRESSIVE INVESTIGATION OF TECHNICAL ISSUES

OPEIV COMMUNICATIONS WITH NRC

DOCUMENTED APPROACH TO REPOR TABILITY

ISSUE IS THRESHOLD FOR REPORTABILITY, NOT SAFETY

a~

REPORTABILITY OF DESIGN ISSL'ES'

INTEiVT OF 50. 72/50 78 I.iVCLUDES CONSIDER.4.TIOLV OF SAFETY SIGNIFICAsVCE

PLANT ~FUST BE OUTSIDE DESIGN BASIS POTEiVTIAL IS NOT REPORTABLE UNDER 50. 72/50.78

PP&I. BASIS FOR REPORTING DESIGN ISSUES

NEW 50.72/50.73 EFFECTIVE 1984

WORKSHOPS AND NUREGS PROVIDED CLARIFICATION

THRESHOLD FOR DESIGN ISSUES NOT CLEAR

SAFETY SIGNIFICANCE DETERMINED TO APPLY NUREG EXAMPLES DISCUSSION WITH HEBDON CONSISTENT WITH 50,59

DOCUMENTED APPROACH - FOLLOWED CONSISTENTLY

CONSERVATIVE AND CORRECT REPORTING

-FROM NUREG-1022 Para raph 50.73(a) (2) ( f f ) requf res r eportfng of:

"Any event or condition that resulted fn the condition of the nuclear power plant, fncludfng fts principal safety barriers, befng seriously degraded, or that resulted fn the nuclear power plant being:

(A)

In an unanal zed condftfon that sf nfffcantl com romised lant sa e

(B)

In a condition that was outsfde the desi n basis of the lant or (C)

In a condftfon not covered by the plant's operating and emergency procedures."

This ara ra h re ufres events to be re rted where the lant, fncludfn fts r inc a

sa et arr ers.

was ser ous ra e

or n an unana yze con >>on.

or exeap e, sma vo s

n sys ems esfgne o remove ea rom e reac or core which have been previously shown through analysfs not to be safety sfg-nfffcant need not be reported.

However, the accumulation of voids that could inhibit the ability to adequately remove heat fran the reactor core, particularly under natural circulation conditions, would constitute an unanal zed condition and must be reported.

In addition, voiding fn fnstrunent lines that results i 1 an erroneous indication causing the operator to sfgnfffcantly misunderstand the true condition of the plant fs also an n

ed n f fon and must be reported.

The Ceanf ssfon reco nfzes that the licensee may use en fneerin Jud nt and ex er ence to e

rm ne e

er an unana ze con on ex s e

.

is not nte at 5 paragrap app y m nor var a ons n

n v

ua parameters, or to problems concerning single pieces of equipment.

For example, at any tice, one or more safety-related components may be out of service due to testing, mafntenance, or a fault that has not yet been repaired.

Any t~ivial single faflure or minor error in performfng surveillance tests could produce a situation fn which two or more often unrelated, safety-related components are out-of-service.

Technically, this is an n nal zed condf tion.

However, these events should be reported only ff they fnvo ve unctfona y related caaponents or if they si ni ficantl com reaf se lant safet

.

PRON NUREG-1022 Finally, this paragraph also includes maCerial ( e.g., metallurgical, chemical)

problems that cause abnormal degradation of the principal safety barriers (f.e., the fuel cladding, reactor coolant system pressure boundary, or the contafnnent).

ddf tfonal exam les of situations fncluded in thf s paragraph are:

(a)

Fuel claddin failures in the reactor or in the storage pool Chat exce expec e

va ues, Chat are unfque or widespread, or that resulted fraa unexpected factors.

(b)

Reactor coolant radioactfvf t levels. that exceeded Technical Specificatfon limits for iodine spikes or, radioactivity levels at a

8MR air gector monitor that exceeded the Technical Specification lfmfts, (c)

Cracks and breaks in pfping, the reactor'vessel, or moor components reactor coolant pumps, valves, etc.)

(d)

Sf nfficant weldfn or material defects fn the primary coolant system.

.(e)

Serfous tern rature or ressure transients ( e.g., transients that violate the p ant s

ec n ca pec cat ons

.

(f)

Loss of relief and/or safet valve o erabflft during test or operation suc at e nm er o oper e va ves s

ess than requfred by the Technical Specifications).

( g)

Loss of contafeaent function or inte r it (e.g., containment leakage races exc ng e au or

@ed m ts

.

FROM NUREG-1022 TITLE:

DROPPED CONTROL ROD WITH'SUBSEQUENT REACTOR TRIP RESULTING IN AN UNSCHEDULED SHUTDOWN While at 100K power, the unit experienced a dropped cont~ol rod with a subsequent automatic load reduction to 70%,

Rod recovery procedures were unsuccessful and flux tilt parameters required operator action to further reduce unit load.

At about 400 MWe, a full runback occurred resulting in an increase in system pressure and a high pressure reacto~ trip.

The No.

Reactor Coolant Pump failed to transfer from the auxiliary transformer to tne station'transformer and tripped.

Upon attempting restart of the RCP, the licensee detected high vibration on the motor's lower radial bearing.

'dditionally, No.

22 Control Rod Drive MG Set wiped its inboard generator.

bearing and Steam Generator (SG) water chemistry samples indicated a primary to secondary leak in the No.

SG.

The leak rate and activity measured in the SG did not exceed the Technical Specification limits.

Comments:

1.

The event is reportable because the reactor tripped [50.73(a)(2)(iv)].

2.

The event is not reportable because of the high activity in the Steam Generator.

The activity level did not exeed the Technical Specification limit and a sin le steam enerator tube failure is an anal zed situation that is within the desi n basis of the lant [50.73(a)(2)(ii)].

3.

The fact that a control rod was dropped and could not be recovered aoes not make the event reportable unless the drop resulted from serious or generic material problems with common mode or generic implications

[50 73(a)(2)(v)).

4.

The problems with the No.

23 Reactor Coolant Pumps and the No.

Contre'Od OriVe MG Set dO nOt make the eVent repOrtable unleSS they had COmmOn mode or generic implications [50.73(a)(2)(v)3.

C-4

TITLE:

. L(N CONTAINMENT PRESSURE

~~~ "lUREG-1022 Ouring a plant cooldown, containment pressure decreased belo~ negative 12 inches of water.

Containment cooling was being supplied by three CAR fans in fast with normal and emergency RBCCW cooling.

Containment cooling was not changed to match decreasing heat loads during the cooldown.

Containment temperature dropped from 103 to 90 degrees F.

CAR fans were shifted to slow with normal RBCN flow only.

Containment pressure increased above'egative 12 inches of water within 10 minutes.

Operators have been cautioned to balance containment cooling with neat lcacs during heatups and cooldowns.

Coneent:

This event is not re ortable if no Technical Specification limits were violat~

[50. 73(a)(2)(i )(8)] and the condition was not outside the desi n basis of :ne plant [50. 73(a)(2)(ii )(8)].

C-2I

TITLE:

CONTROL RDD FAILURE Mhfle at 97 percent po~er, turbine load reduction was initiated in response to a stem generator feed pump low suction pressure alarm.

After initial rod motion, "control rod urgent failure" was annunciated and the rods could not be moved.

Boratfon was initiated to reduce T

.

High pressure in the steam av>>'enerator caused a safety valve to open.

It failed to reseat due to fouling of the manual operatfng arm.

primary pressure reached 2320 psfg and was reduced by spray.

A spray valve failed to reseat, reducing pressure to 2140 pSig befOre manual preSSure COntral waS effeCted.

At 2: 10 a.m.,

the plant was stable at 46 percent power.

The safety value was reseated.

Boa control was restored by replacing the firing circuit and a failed fuse.

During the transient, T

exceeded the LCO limit of 582 degrees F for five minutes, peaking at 592 degrees F.

The plant is limited to less than 50 percent power for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> due to accumulated axial flux difference (AFO) penalty minutes.

Secondary parameters were recorded and will be evaluated to determine the cause of the initiating loss of feedwater suction pressure.

Canments:

1.

The event is reportable because the combination of actfve failures during the event resulted in the plant being in an unanal zed condition that si niffcantl com romised lant safet

[50. 73(a)(2)(fi)A)).

2.

The event would not be reportable if the failure of the rods to move wou!a not have prevented the fulfillment of a safety function (50.73(a)(2)(u}.

3.

The event fs reportable because the operation was prohibited by the Technfcal Specifications (i.e.,

an LCO limit (T greater than 582'~)

ave was exceeded)

[50. 73(a)(2)(i )(B)).

C-25

FROM'HURZG-10 22 TITLE:

HIGH ENERGY LINE 8REAK RESTRAINTS NOT INSTALLEO Whfl~ at power, the plant was notified by the Architect/Engineer that the control rod drive system, raeactor water cleanup system, reactor core fsolatfor cooing system, and auxiliary steam system dfd not hove the high energy line break restraints required in the Final Safety Analysis Report (FSAR) supple-ment 15A.

The high energy lfne break reatrafnts were omitted from four plant systems during construction due to Ar chftect/Engineer design oversight.

Caaeent:

The event is reportable because it is an event or condition that was oUtside the desi n basis of the plant and is an unanal zed condition that si nificant!

com romised plant safet

[50. 73(a}(2)(if)(A) and (S)].

C-50

TITLE:

HVAC WEU5 fDVND.l1EfECTIVE

. PRON NUBEG-1'022 Ouring a refueling outage, it is discovered that all of the HVAC welds are undersized or are otherwise inadequate because of a major breakdown in quality aSSuranCe (gA) during COnStruCtiOn that OCCurred yearS earlie~.

AS far aS the licensee knows, the NRC has not identified the problem at this particular plant.

The HAVAC system is used to provide control room habitability during accident conditions and therefore has a safety function.

Cosment:

The eVent ia repartable beCauae it iS an eVent Or COnditian chat uaa Outaina the desi n basis or the lant and is an unanai ed condition that si n antis.

com romises lant safet

[50. 73(a}(2)(ii)(A) and (8)].

FROM NUREG-1022F SUPPLEMENT

4,0 4.l pal a r aph 50,73 a

2 ii, Unanal zed Conditions. "'""'"

'een in an unanal zed condition.

But we never operated

>n that condition and we prevented suc operation by administrative proce-dures.

is that reportable?

Answer:

No.

The event is not re ortable if the lant was never in an unanal zed condition.

However, in reviewing the reportabi lity of each s> tuat on, p ease carefully revi ew all criteria of 50. 73 since the si tuati on may be reportable under a different cri teri a.

4.2 lf we update our docket with updated infonsation on the plant~desi n

basis or accident analysis and we have an event or condition wnich was outside the ori inal FSAR but not outside of the updated informat on; do we nave to submit an LER?

Answer:

No.

An LER is not required if the event or condition is within tne design or licensing basis as currently docketed and approved by tne IIR FROM NUREG-1022, SUPPLEMENT

l o. 3 4e are aware that a recent generic analysis of the rod drop acci".ent appliCable tO Our plant indiCated that thiS eVent wOuld eXCeed tne value given in tne FSAR.

Further, the analysis indicated that the condition was fu I ly acceptable and did not result in a serious tnrea to tne plant.

[s an LER required?

AnSWer:

The COnditiOn wOuld be repOrtable aS an LER if the anal Zed rOd drO ad actua occurre and cause t e p an o

e in a

cond> tion outside the desi n basis o

the ant.

suc an even a

not occurre the ana sis alone ~ould not be re ortable as an LER but may be reportable un er ot er requi rements.

t e condition were reported as an LER, then the generic analysis should be discussed and referenced in the assessment of the safety consequences of the event

[see 50.73(b )(3) EÃGIPEERljVG DlSCREPANC Y PROGR43f

DESIGN BASIS

ENGI)VEERING DISCREP.4ECIES

EfVGISEERING DISCREPAEC Y MANAGENEiVT

CHARACTERISTICS OF ENGISEERI.'VG DISCREP4NCIES

FREQUE.VTLY EVOLVE OVER TI3fE

HARDH'ARE, OR SAFETY, IMPACT sVOT CERTAIN

CHANGING PERCEPTIOLV OF SIGLVIFICA.VCE

SIGNIFICANT EFFORT FREQUENTLY CONFIRMS ADEQUACY OF ORIGINAL HARD8'ARE

SUS UEHANNA DESIGN BASIS'

LICENSING DOCU3fEiVTS SUCH AS FSAR, FPRR, SER

REFERENCED CODES AsVD STANDARDS

TECH SPECS

DESIGN CALCULATIONS

TEST REPORTS

CONTROLLED DRA O'INGS

DESIGN SPECIFICA TIONS

PPd'eL DESIGN STANDARDS

ENGINEERING PRA CTICE

ENGINEERING DISCREPANCIES DISCREPANCIES BETH'EEN DESIGN BASES, SUCH AS:

PIPING ANALYSIS DOES NOT (PATCH KR!8'ONFLICT BETWEEN DRAWINGS EQ TEST RES ULT DOES NQ T MEET ACCIDENT ANALYSIS DESIGN DRAB'INGS DO NOT MATCH DESIGN STANDARD LACE OF FORMAL ANALYSIS FOR WATERHAMMER

IDENTIFICATIOiVOF DESIGN ISSUES

BROAD EXTE.VT OF DESIGN BASIS PROVIDES SIGNIFICANT OPPORTViVITIES TO IDENTIFYDISCREPANCIES

QUALIFIED STAFF WITH A QUESTIONING ATTITUDE

AGGRESSIVE IDENTIFICATION

CONSERVA TIVE RESOLUTION

EXANPIES OF DESIGN DISCREPANCIES REACTOR BUILDING HVAC RHR O'A TERHAiV3fER FUEL ANALYSES STEAM LEAKDETECTION ELECTRICAL SEPARA TION iVSIV CLOSURE VACUUMBREAKERS BATTERY LOADS

s ~

E

ENGINEERING DISCREPANCY MANAGEMENT

UNIQUE 3fECHANIS4f -TO IDE)VTIFY dc TRACE

PROCESS INCLUDES:

IDENTIFICATION DOCUMENTATION CLASSIFICATION S CREENING

- TRACKING ASSESSMENT DISPOSITIONING RESOL UTION CLOSEOUT

PROCESS FEEDS:

NCRs WHEN HARDWARE IMPACT IS LIEELY REPORTABILITY-E-VALUATION

-

'=-- 'OPERABILITY~EVALUATIOiV PROCESS INCLUDES:

CLASSIFICATION/PRIORITIZATION URGENCY MAGNITUDE OF EFFORT NOTIFICATIONS PERIODIC REVIEW OF BACKLOG RE EVALUATIONOF PRIORITY CUMULATIVEIMPACT OF OPEN ITEMS CLOSURE OF LOW PRIORITY ITEMS ASSESSMENT OF RESOURCE ALLOCATIOV DOCUMENTED.CLOSURE

DISCREPA NCY S'S TEM S TATUS

DRAFT PROCEDURE UNDER REVIEW'

PROCESS O'ILL BE IN PLACE BY 1/02/90

.J

> ~

PROCESS FOR REPORTING DESIGN ISSUES

ASSURE PROPER COMMUNICATIOIVS AND REPOR TING FOR DESIGN ISS UES

EVOLVING PROCESS NUMARC IIVITIATIVE INFORMATION NOTICE

ENGINEERING DISCREPANC Y PROGRAM O'ILL CAPTURE DESIGN ISSUES

50 72./50. 78 FOR EVENTS/OPERABILITY CONCERNS 50.9 FOR OTHER ISSUES O'CTUAL EVENT/OPERABILITYIS KEY TO REPORTABILITYPER 50.72/50 78.

MUST BE ACTUAL EVENT DRIVEN ABILITYTO PERFORM SAFETY FUNCTION UNREVIEB'ED SAFETY qUESTIONS (50.5S)

OTHER DESIGN ISSUES O'ILL BE EVALUATED FOR REPORTABILITY VIA 50.9 CHALLENGE TO ADEQUACY OF DESIGN GENERIC IMPLICATIONS SUBSTANTIAL RESOURCES TO ADDRESS

AS 50.9 ISSUE EVOLVES, 50.7Z/50.73 W'ILL BE REASSESSED

FLOWCHART FOR EVALUATING ENG INEER ING I S SUE S FOR REPORTAB I LITY Engineering Issue Engineer ing Saiety Concern2 Set Work Priority Yes Operability h 50.59 Test Fails 50o72/50.73 Reports Passes Challenge to Adequacy oi Design2 Generic Iaplications2 Substantial Resources to Address or Resolve2 No Li Ceni P1 ant S tmCC'pen to Reviee With Residents 50.9 Report

CONCLUSION 0 HERE TO DISCUSS REPORTABILITY OF DESIGN ISSUES

REPORTABILITY CRITERIA ARE BEING REVISED TO L08'ER THE THRESHOLD-AND MEET NEW NRC EXPECTATIONS 0 PP8cL HAS A STRONG SAFETY CULTURE AND A HISTORY OF AGGRESSIVE AND CONSERVATIVE RESPONSE TO SAFETY ISSUES SAFETY IS NOT AN ISSUE 0 PROGRAM FOR EVALUATING REPORTABILITY WAS BASED ON NRC CRITERIA 0 NEED FOR A STRONGER INTERNAL PROGRAM FOR CAPTURING, EVALUATING, AND CLOSING ENGINEERING ISSUES IS BEING MET BY A NEW ENGINEERING DISCREPANCY PROGRAM