IR 05000387/1994004
| ML17158A198 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 03/25/1994 |
| From: | Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17158A197 | List: |
| References | |
| 50-387-94-04, 50-387-94-4, 50-388-94-04, 50-388-94-4, NUDOCS 9404040049 | |
| Download: ML17158A198 (30) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION I
Inspection Report Nos.
50-387/94-04; 50-388/94-04 License Nos.
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:
January 1, 1994 - February 26, 1994 Inspectors:
G. S. Barber, Senior Resident Inspector, SSES D. J. Mannai, sideribJnsp r', SSES Approved By:
J hite, Chief eactor Projects Section No. 2A, Date In ti 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; engineering and technical support; and safety assessment/quality verification. The inspector identified eight non-cited violations during Licensee Event Report (LER) review.
Findings and conclusions are summarized in the Executive Summary.
Details are provided in the full inspection report.
9404040049 940328 PDR ADOCK 05000387 Q
EXECUTIVESUMMARY Susquehanna Inspection Reports 50-387/94-04; 50-388/94-04 January 1, 1994 - February 26, 1994 Operations (30702, 71707, 71710)
The Unit 2 reactor scrammed at 1:50 a.m., January 20 due to high stator water cooling temperatures.
One Safety Relief Valve (SRV) acoustic monitor did not reset properly.
(Section 2.2.2 pertains).
The plant was stabilized in hot shutdown.
The cause of the scram was flow induced vibration that caused a mechanical failure of the temperature indicating controller (TIC) linkage for a three way valve (TCV-20183) that regulates flow through the SC heat exchanger.
A degradation of an air line occurred prior to the scram that may have not been fully investigated.
Section 2.2.1 pertains.
During the Unit 2 scram, which occurred on January 20, seven SRVs opened and reseated (Section 2.2.1 pertains).
During the investigation after the scram, the licensee received a acoustic monitor alarm for the "S" SRV. All other indications supported that the SRV was closed.
Investigation identified a bad charge converter.
The licensee considered the effects of a reactor shutdown, containment deinerting and entry, subsequent repair activity, and that the governor had declared a power emergency for the entire state on January 19 and requested enforcement discretion to continue Unit 2 startup.
Discretion was granted and the licensee proceeded with startup.
Section 2.2.2 pertains.
The inspector toured the Unit 1 drywell during final closeout activities.
Management oversight and involvement was good.
The inspector found the final conditions of drywell good regarding housekeeping and cleanliness.
Section 2.2:3 pertains.
Safety Assessment/Assurance of Quality (40500, 90712, 92700, 92701)
The inspector reviewed 18 Licensee Event Reports (LER) during the period.
Eight non-cited violations were identified. Two of the LERs reviewed remain (Unit-1: 93-012-00; Unit-2:
93-008-00) open pending assessment of supplementary information.
The inspector discovered some weaknesses between corrective actions documented in the LER, as compared to the corrective measures documented for the events in Significant Operation Occurrence Reports (SOOR), which were generally more comprehensive and subject to more thorough assessment.
The licensee willtake actions to address this disparity.
Section 6.1 pertain The inspector observed portions of the Plant Operations Review Committee (PORC) meeting for Unit 1 startup following the 7'efueling and Inspection Outage.
The agenda was thorough and comprehensive.
The inspector found station management maintained a strong questioning attitude.
Section 6.2 pertains.
During the period, the inspector reviewed the licensee's cold weather program to protect safety related equipment from the effects of cold weather.
The inspector determined the licensee effectively implemented a cold weather protection program.
The inspector found some weaknesses regarding deficiency documentation and corrective action.
Section 6.3 pertain SUMMARYOF OPERATIONS 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, independent calculation, and selective review of applicable documents.
1.2 Susquehanna Unit 1 Summary Unit 1 began the inspection period in Condition 5 in an extended Unit 1 T Refueling Outage.
On January 2, an Engineered Safety Feature (ESF) actuation occurred during LOCA-LOOP testing when the 'C'mergency Diesel Generator started automatically.
Section 6.1 pertains.
Condition 4 was entered when the (Reactor Pressure Vessel) RPV head was tensioned on January 8.
On January 19, Unit 1 entered Condition 2 and went critical on January 20.
Condition 1 was entered and the generator output breaker closed on January 22.
Following power ascension testing, the unit was returned to 100% power on January 31.
A downpower was performed to conduct single loop testing and effect reactor feed pump repairs from February 11 through 15.
Power was returned to 100% on February 16 and remained at 100% at the conclusion of the inspection period.
1.3 Susquehanna Unit 2 Summary Unit 2 began the inspection period with power ascension in progress.
The unit was returned from an unplanned shutdown caused by unidentified drywell leakage exceeding TS limits.
The unit returned to 100% power on January 3. A downpower to 60% power was performed to repair a 'C'ondenser waterbox tube leak on January 4. Unit 2 returned to 100% power on January 6.
On January 20, Unit 2 reactor scrammed due to a turbine/generator trip on high stator cooling water temperature.
Section 2.2.1 pertains.
The
'S'afety Relief Valve (SRV) was declared inoperable during reactor startup.
NRC enforcement discretion allowed the unit to continue startup due to the weather related power emergencies.
Section 2.2.2 pertains.
The unit went critical and entered Condition 1 on January 21.
The main generator output breaker was closed on January 22.
Unit 2 returned to 100% power on January 24. A downpower to 70% was performed on February 19 to perform RF-OTP-057, "Determination of Defective Fuel Rod Location".
The licensee performed this test to determine the location of a fuel bundle with a minor leak.
The licensee suspected a minor leak since the off-gas release rate was slightly elevated combined with chemistry analysis.
The suspect bundles willbe sipped during the upcoming refueling outage.
During the downpower on February 20, the licensee discovered an Electro Hydraulic Control (EHC) fluid leak at ¹3 turbine control valve (CV) servo.
Power was
reduced to 18% and the turbine taken off the line to repair the EHC leak.
The generator output breaker was closed on February 20 and the unit returned to 100% on February 21.
The unit remained at 100% at the conclusion of the inspection period.
2.
OPERATIONS E
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 71707.
The inspectors performed 15.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> of deep backshift inspections during the period.
These deep backshift inspections covered licensee activities during 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 Reactor Scram/Turbine Trip due to High Stator Cooling Water Temperature-Unit 2 On January 20, at 1:50 a.m., a Unit 2 reactor scram/turbine trip occurred due to high stator cooling (SC) water temperature.
Immediately after the scram, reactor water level dropped from +35 inches (normal level) to +2 inches.
Level 3 (+10 inch) isolations occurred and were verified completed by on-shift operators.
The initial turbine trip simulated a load rejection transient which caused a rapid pressure increase (peak pressure = 1083 psig) which resulted in seven safety relief valves (SRVs A,B,C,D,H,R,S) momentarily opening.
All SRVs subsequently closed.
The "S" SRVs acoustic monitor did not reset properly (Section 2.2.2 pertains).
Main steam radiation levels and containment parameters trended properly for the scram.
Other than the "S" SRV acoustic monitor, there was no anomalous conditions for the scram.
Operators were successful at stabilizing the plant in hot shutdown per EO-200-102, RPV control.
The NRC was notified at 5:01 a.m., January 20 in accordance with 10 CFR 50.72.
This event was documented in SOOR 94-062.
The inspector responded to the control room at 5:20 a.m., shortly after the scram occurred and confirmed that the plant was stable in hot shutdown.
The inspector also observed that operators were actively following off-normal and emergency operating procedures.
Except as previously noted, all safety related equipment appeared to have operated per design.
A minor balance-of-plant (BOP) problem was identified.
The main turbine turning gear did not engage when required, This condition was resolved late The cause of the scram was a mechanical failure of the temperature indicating controller (TIC) linkage for a three way valve (TCV-20183) that regulates flow through the SC heat exchanger.
The linkage failure resulted in all SC flow bypassing the heat exchanger.
This loss of cooling capability caused an immediate heatup and subsequent turbine trip on high temperature.
The licensee identified this failure on January 21 while troubleshooting TCV-20183.
The licensee has also noted excessive vibration when the SC system operated and noted it as a potential contributor to the linkage failure.
During troubleshooting, the actual failure was traced to a worn arm in the linkage.
The licensee subsequently replaced the arm and is evaluating modifications to address this issue.
Inspector Conclusion The inspector noted good initial response by operators during the scram.
Procedural adherence was evident and communications were effective.
The licensee's troubleshooting was successful at identifying the faulty component.
The licensee identified the root cause of this event as flow induced vibration in SOOR 94-062.
However, two weeks earlier, a vibration induced problem was discovered with an instrument air line supplying the TIC. It was degraded and could have failed in service but it was detected during a system walkdown.
At the time, there was no additional investigation to identify other degraded components.
Thus, the licensee missed an opportunity to evaluate the effects on other components prior to the scram.
The licensee plans to take vibration data at the failure location to assess its significance.
A modification is planned that will relocate the TIC away from the SC HX skid. Ifimplemented, this would eliminate any future failure due to flow induced vibration.
The inspector had no further questions.
2.2.2 Inoperable SRV Acoustic Monitor - Unit 2 A Unit 2 scram occurred on January 20 in which seven SRVs opened and reseated (Section 2.2.1 pertains).
During the investigation after the scram, the licensee received a acoustic monitor alarm for the "S" SRV at 6:05 a.m., January 21. Allother indications supported that the SRV was closed.
Reactor pressure was stable at 163 psig, suppression pool temperature was stable at 81'F, and "S" SRV tailpipe temperature was 135'F.
Thus, the acoustic monitor was declared inoperable and Technical Specifications (TS) 3.3.7.5 and 3.4.2 were entered.
After the licensee confirmed the valve was closed, an investigation (WA V46048) was begun to determine the root cause of the alarm.
The licensee determined that the acoustic monitor charge converter (VT-24180B8) bias voltage was below specification. It was 8 VDC versus a 10 VDC minimum.
Previous measurements taken in May, 1993 confirmed a 17 VDC output.
Thus, the licens'ee believed that the most likely cause for the alarm was a degradation of the charge converter for the "S" SRV.
Its repair/replacement would require a containment entr The licensee considered the effects of a reactor shutdown, containment deinerting and entry, subsequent repair activity, with regard to the Power Emergency Declaration made by the Governor of Pennsylvania on January 19.
Consequently, the licensee requested enforcement discretion to continue Unit 2 startup, in view of the emergency situation existing at the time.
In a January 21 conference call, the licensee described their rationale for requesting enforcement discretion.
After careful consideration, the NRC granted enforcement discretion for TS 3.0.4, 3.3.7.5 and 3.4.2 to allow unit startup.
The licensee formally documented their rationale in a January 24 submittal.
The NRC documented the enforcement discretion in a January 27 letter.
Amendment 100 relative to this matter was approved later in a January 31 letter.
Licensee Event Report 94-003-00 documented this as a reportable event.
Section 6.1 pertains.
The inspector reviewed the licensee's actions to address the inoperable SRV acoustic monitor and found them prudent and reasonable for the circumstances.
The cold weather during the week of January 19 placed excessive demands on available generation. The inoperability of the acoustic monitor constituted a minor loss of accident detection instrumentation that was adequately compensated for by other available indications, alarms, and procedures.
The actual risk of an open SRV being undetected was minimal and, thus, the granting of discretion was appropriate.
The licensee's actions adequately addressed the inoperable acoustic monitor.
The inspector had no further questions.
2.2.3 Unit 1 Drywell Closeout The inspector independently toured the drywell during final licensee closeout at the conclusion of the Refueling Outage.
The licensee performed the closeout in accordance with NDAP-QA-309, Primary Containment Access and Control.
The inspector observed the Day Shift Supervisor and Manager of Nuclear Maintenance actively involved with the final drywell closeout.
The licensee found some residual foreign material in the drywell. The inspector also found some foreign material that required removal.
The licensee promptly removed the debris during the final containment walkdown.
The inspector concluded that the licensee properly performed the closeout in accordance with the procedure.
The inspector determined the Primary Containment Closeout Checklist was properly completed.
Management oversight and involvement during the closeout was good.
Notwithstanding the minor amount of industrial debris found during the closeout tour, the licensee maintained good housekeeping and cleanliness.
The inspector observed that physical condition of the systems was good.
The inspector had no further questions.
3.
MAINTENANCE/SURVEILLANCE 3.1 Maintenance Inspection Activity On a sampling basis, the inspector observed and reviewed selected maintenance activities to ensure that specific programmatic elements described below were being met.
Details of this review are documented in the following section i 3.2 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 33911, Remove/Reinstall Overspeed Governor on the 'E'mergency Diesel Generator, dated January 3, 1994.
WA 30408, Remove/Reinstall Calibrated Fuel Injection Pumps on the 'E'mergency Diesel Generator, dated January 31.
WA 40190, Reactor Level MSIV 'C'ypass Logic Switch Troubleshooting, dated January 31.
WA 35518, Clean and Inspect Reactor Building Swing Bus MG-Set, dated February 25, 1994.
3.3 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:
SO-151-002, 92 Day Flow Verification - Core Spray System, dated January 1, 199 SR-100-008, in Sequence Critical and Shutdown Margin Demonstration, dated January 20.
SR-155-001, Scram Time Measurement of all Operable Control, dated January 24.
SI-251-201, Monthly Functional Test of Drywall Pressure Channels for Core Spray HPCI LPCI Permission, dated February 9.
SE-054-001, 18 Month Emergency Service Water Logic Functional Test, dated February 10.
3.4 Inspection Findings The inspector reviewed the listed maintenance 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 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.
4.
ENGINEERING/TECHNICALSUPPORT 4.1 Inspection Activity The inspector periodically reviewed engineering and technical support activities during this inspection period.
The on-site Nuclear Systems Engineering (NSE) organization, along with Nuclear Technology in Allentown, provided engineering resolution for problems during the inspection period.
NSE generally addressed the short term resolution of engineering problems; and interfaced with the Nuclear 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.
5.
PLANT SUPPORT 5.1 Radiological Controls 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.
Observations of radiological controls during maintenance activities and plant tours indicated that workers generally obeyed postings and Radiation Work Permit requirements.
No significant observations were mad '7 5.2 Emergency Preparedness The inspector reviewed licensee event notifications and reporting requirements for events that could have required entry into the emergency plan.
No events were identified that required emergency plan entry.
5.3 Security 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.
The inspector reviewed access and egress controls throughout the period.
No significant observations were made.
6.
SAFETY ASSESSMENT/QUALITY VERIFICATION 6.1 Licensee Event Reports The inspector reviewed LERs submitted to the NRC office to verify that details of the event were clearly reported, including the accuracy of the description of the cause and the adequacy of corrective action.
The inspector determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted onsite follow up.
The following LERs were reviewed:
Unit 1 93-007-00 Voluntary Report - Potential Plugging of ECCS Suction Strainers by Containment Debris As a result of the licensee response to NRC Bulletin 93-02, Debris Plugging of Emergency Core Cooling Suction Strainers, the licensee submitted a voluntary LER, dated July 2, 1993, to the NRC, Although the licensee determined no reportable conditions existed, it was prudent to provide the results of their analysis given the potential generic safety significance of the issue.
The licensee determined that no fibrous air filters or temporary materials existed.
However, the licensee determined that some sources of debris are known to exist which could result in
, ECCS suction strainer plugging.
The sources include fibrous insulation, unqualified paintings/castings and corrosion products.
Based on this, PP&L established a plan to assess and correct conditions that could result in ECCS strainer clogging.
These actions include removal of fibrous insulation, painting/coating evaluations, and corrosion product reduction.
The licensee is evaluating the
i development of ECCS strainer flushing procedures.
Licensee efforts regarding this issue are continuing.
The inspector agreed with the licensee's reportability determination.
The inspector found the licensee's response conservative and prudent.
PP&L's handling of the issue was considered a strength.
93-011-00 1A201 4KV Bus Momentarily De-energized - Unplanned ESF Actuation On September 12, 1993, an unplanned ESF actuation occurred on Unit 1 when the 1A Engineered Safeguards System (ESS) bus momentarily de-energized during the monthly degraded voltage channel functional surveillance test.
The event was initiated when the circuit test switch was taken to the test position which caused the normal feeder breaker to open indicating malfunctioning test circuitry. The licensee verified proper system response.
Once the normal power supply was restored, the licensee restored the equipment to its normal alignment.
The event was determined to be reportable as an unplanned invalid ESF actuation.
The licensee was not able to determine the root cause of the event.
However, it appears that the trip signal was transmitted to the trip relays prior to the expected blocking of the signal.
The failure to block the trip signal was most likely caused by malfunctioning of the blocking relay, timing relay, or the test switch.
Following troubleshooting activities which did not identify the cause, the surveillance was performed twice satisfactorily.
The licensee planned further testing of the component and will submit an update ifadditional information is discovered.
The licensee has modified the surveillance test procedure to install jumpers to ensure blocking of the signal is completed prior to the trip signal being generated.
The licensee willperform the surveillance in this manner until the root cause is determined.
The inspector considered these actions adequate.
93-012-00 Operation Prohibited Technical Specifications Entry into 3.0.3 On September 24, 1993, the Unit 1 control room operators received alarms for "Residual Heat Removal Injection Permissive Loop 'B'eactor Low Pressure" and "Reactor Recirculation Loop 'B'ischarge Valve and Closure".
Instrumentation and Control group discovered that Emergency Core Cooling Systems Low Pressure Permissive Switch was in the tripped condition with the low pressure side bellows leaking transducer fluid.
This switch provides inputs to core spray, reactor recirculation system and RHR system logics.
Control room operators then entered Technical Specification Action Statement 3.3.3.b for inoperable ECCS actuation instrumentation.
Operators reviewed the actuation logic associated with the switch and declared Division II core spray and RHR LPCI inoperable.
Technical Specifications 3.5.1 for ECCS does not cover an inoperable division of core spray and RHR LPCI and Technical Specification 3,0.3 was entered as a failure to meet Technical Specification 3.5.1.
Power reduction was started and efforts to replace the
switch were pursued concurrently.
Replacement and testing were completed prior to reaching the six hour time limit to be in Condition 2.
LCO actions were exited and the power reduction was stopped at 23%.
The licensee found the transducer leaking fluid from the low pressure side of the bellows assembly.
The exact cause of the failure was not known, but the licensee suspected cyclic fatigue from monthly depressurization and repressurization during surveillance testing.
The failed switch was returned to the manufacturer for failure analysis.
The licensee determined the condition to be reportable as an entry in TS 3.0.3.
The inspector agreed with the licensee's reportability determination.
Although the licensee did not determine the exact cause of failure, the licensee suspected cyclic fatigue.
Corrective action included vendor failure analysis.
The licensee will submit a supplemental LER detailing the results of the failure analysis.
93-013-00 Unplanned ESF Actuation - Primary Containment Isolation Valve Closure On September 21, 1993, control room operators received the "RCIC Steamline Logic
'B'igh Differential Pressure" and "RCIC Out-of-Service" alarms.
The RCIC steam line isolated during performance of excess flow check valve testing.
At the time of the event RCIC was in a standby alignment.
The 18 month functional test of excess flow check valves for RCIC isolation was being performed.
The RCIC steam line inboard isolation valve closed isolating the RCIC steam supply and generated a RCIC turbine trip signal closing the trip and throttle valve. All systems functioned as required following the instrument channel trip on logic 'B'igh differential pressure which was being tested at the time of the event.
The isolation occurred during restoration from the test.
The licensee determined the most probable cause of the isolation was the result of an I&C technician repositioning the valves too rapidly during restoration.
This resulted in creating a momentary high differential pressure condition sensed by the RCIC steam line isolation logic.
The licensee determined the condition reportable as an unplanned ESF actuation.
Licensee immediate corrective action included resetting RCIC to restore the system to an operable status.
Action to prevent recurrence consisted of I&C personnel reviewing the event at a shop meeting with emphasis on the proper instrument valving.
The inspector agreed with the reportability determination.
However the inspector considered the actions to prevent recurrence documented in the LER were weak.
The inspector, subsequently, found the licensee has initiated a more comprehensive corrective action plan as a part of the licensee SOOR resolution proces Operation Prohibited by Technical Specifications At 9:50 a.m. on September 28, 1993, with Unit 1 in Condition 5, (refueling) the refuel one-rod-out interlock was declared inoperable and Technical Specification 3.9.1 was entered for the purpose of performing Technical Specification surveillance requirement one-rod-out interlock testing.
Technical Specification 3.9.1 states that when the reactor mode switch is locked in the refuel position, a control rod shall not be withdrawn unless the interlock is operable.
However, in order to verify operability of the interlock a control rod must be withdrawn.
The licensee determined the cause of the event was procedural non-compliance.
Although not required by Technical Specifications to be performed to change from mode 4 to mode 5, Operating Procedure G0-100-005, "Plant Shutdown From Minimum Power Operation or Scram to Cold Shutdown" contained a step which required a performance of the surveillance prior to entering into Condition 5 from Condition 4.
Operations Personnel missed this step prior to entering Condition 5.
Operating Procedure GO-100.006, "Cold Shutdown, Refueled and Refueling, which actually is used to perform the mode change from Condition 4 to Condition 5, and the surveillance procedure did not contain any direction to perform the interlock test prior to entering Condition 5.
The licensee revised procedures to ensure consistency for performance of the surveillance requirement prior to entering Condition 5.
Operations will review the event with all operations personnel to emphasize importance of procedural compliance.
The licensee reported the event as a condition prohibited by Technical Specifications.
The inspector agreed with the licensee's reportability determination.
Placement of the mode switch into the refuel position without the one-rod-out interlock being operable constituted an operation prohibited by Technical Specifications.
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.
93-015-00 Administratively Inoperable Refueling Platform Used to Move Fuel On October 31, 1993, the licensee determined that the Unit 1 refueling platform main hoist had been used to offload 38 fuel bundles from the Unit 1 reactor while the main hoist interlocks were administratively inoperable.
Main hoist interlocks were not tested following the replacement of the grapple rendering the main hoist administratively inoperable.
The licensee discovered this while reviewing refueling problems. during the NRC Augmented Inspection Team inspection.
The licensee reported this as a condition prohibited by Technical Specification 3.9.6.
NRC Inspection Report 50-387/93-80 documented this event.
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 Condition Prohibited by Technical Specifications On November 5, 1993, the licensee identified a surveillance deficiency while revising a surveillance test procedure.
The licensee found the procedure for verification of the reactor mode switch in the refuel position interlocks did not require a second licensee operator verifying that all control rods remained fully inserted when the mode switch was placed in the startup position during the test.
Since the procedure did not require a second person verification, the licensee did not perform the verification. This constituted a condition prohibited by plant Technical Specifications.
The licensee reported the event as a condition prohibited by Technical Specification 4.9.
The licensee determined the cause to be personnel error.
A review of historical data revealed that the second operator verification had never been procedurally incorporated.
The licensee revised the procedure.
The surveillance procedure review checklist willbe enhanced to require verification that the procedure completely matched the scope of the TS.
The inspector agreed with the licensee's reportability determination.
The inspector questioned the licensee ifother surveillance procedures were reviewed for similar problems.
The licensee reviewed other surveillances and found no similar problems.
This violation will not 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.
94-001-00 Emergency Diesel Generator (EDG) 'C'nplanned Automatic Start On January 2 an unplanned automatic start of the 'C'DG occurred during performance of the "18 Month Diesel Generator 'B'nd 'D'uto Start and ESS Busses '1B'nd '1D'.
Energization on Loss of Offsite Power with a LOCA - Plant Shutdown" surveillance test.
The licensee determined the event was reportable as an unplanned ESF actuation.
The
'C'DG started and operated per design.
The 'C'DG was shutdown and returned to standby status once operations verified power remained available to the '1C'nd '2C'SS busses.
The utilitydetermined the cause was failure to perform the procedural steps in the required order.
The procedure was reviewed and deemed adequate.
A thorough briefing was held prior to the test.
The failure to perform the steps properly was attributed to inadequate training for the person assisting the test director.
The person assisting the test director performed steps without authorization.
Due to a misunderstanding states links were opened with the key lock switch not in the Division II test position.
This switch blocks the start signal to the EDG for testing purposes.
Consequently, when the states links were opened out of order, the 'C'DG automatically started.
Nuclear Systems Engineering is evaluating the scope of training for personnel who assist the test director.
In this event, a qualified test director directed the test, but the person assisting did not require training or qualificatio The inspector agreed with the reportability determination.
The inspector noted the licensee actions planned to prevent recurrence in SOOR process were more thorough and comprehensive than stated on the LER. The licensee plans to have sufficient corrective actions in place prior to the Unit 2 6 Refueling and Inspection Outage.
94-002-00 Fire Watches Not Performed During An Area Evacuation On January 22, 1994, with Unit 1 in Condition 1 at 20% power, an unexpected chemical reaction occurred while adding chemicals to the Reactor Building Closed Cooling Water System.
The chemical reaction resulted in irritating fumes and the licensee evacuated the affected elevation of the reactor building. The area was evacuated for approximately three and one half hours while recovery from the event was completed.
During this time, hourly fire watches in place for inoperable barriers were not performed.
The licensee determined the event was reportable as a condition prohibited by Technical Specifications.
Investigation revealed that only an area in close proximity to the tank was affected.
Once air samples were complete, the area was declared safe for inhabiting.
The licensee is addressing the cause of the chemical condition event in a separate station operating occurrence report (SOOR).
This violation will not 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.
Unit 2 93-003-00 4.16kv Bus Undervoltage Relays Not Channel Checked On June 3, 1993, the licensee discovered that the Unit 1 4.16kv bus undervoltage relays were not channel checked during performance of the "Shiftly Surveillance Operating Log" while Unit 1 was in the defueled condition.
Since the Unit 1 4.16kv busses supply Engineered Safety Feature (ESF) equipment common to both units.
The Technical Specifications surveillance requirements were not being met for Unit 2 in conditions 1,2,3,4 and 5 with Unit 1 defueled.
The licensee discovered this during a required periodic review of the Unit 1 surveillance.
The Unit 1 shiftly surveillance was revised to include the channel check of the 4.16kv undervoltage relays with Unit 1 in the defueled condition.
The licensee determined the cause of the event was a procedural inadequacy with the Unit 1 shiftly surveillance operating log when a separate listing was developed for the surveillance requirements with the reactor in a defueled condition.
The change was made in May of 1985.
The licensee developed a separate attachment since many requirements are not applicable with the reactor in a defueled condition. It was not recognized that the Unit 1 4.16kv bus undervoltage relays were required to be channel checked in the defueled condition for the common ESF equipment powered by those busse The licensee reported the missed surveillance as a condition prohibited by Technical Specifications.
The licensee revised the shiftly surveillance operating log to require the channel check.
The Daily and Weekly Surveillance and Operating Logs for both units were reviewed and no other reportable conditions were found.
Actions to prevent recurrence include training operations staff and licensed personnel.
A broader review of unit specified surveillances that check common equipment will also be performed.
The inspector agreed with the licensee's reportability determination.
The inspector determined that the surveillance procedure preparation checklist should be revised to include this attribute.
The licensee agreed to review the issue further.
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.
93-005-00 Operation Prohibited by Technical Specification On August 8, 1993, with Unit 2 at 47% power, the required hydrogen sampling of the condenser offgas treatment system was not completed within four hours of the previous sample as required by Technical Specification 3.3.7.11 Action 110.
This TS required grab samples be obtained once every four hours and analyzed within the following four hours when the required in-line hydrogen analyzers are inoperable.
Eight previous samples were taken and analyzed satisfactorily.
The chemistry technician was unable to perform the next sample due to a pressure indication failure which is utilized to determine the sample volume.
The licensee subsequently, restored the in-line analyzers to an operable status.
The licensee is performing a comprehensive evaluation of hydrogen analyzers to determine ifimprovements to the system can be made.
The licensee reported the event as a condition prohibited by Technical Specifications.
The inspector agreed with the licensee's reportability determination and considered corrective actions adequate.
This violation will not 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.
93-006-00 Main Steam High Flow Switch Required Entry into Technical Specification 3.0.3 On November 6, 1993, with Unit 2 in Condition 1 at 100% power, the 'A'ain Steam Line High Flow Switch (FIS-B21-2N006B) Lower Switch Assembly was replaced due to erratic indication during replacement of the flow switch, the trip function of the switch was placed in the tripped condition.
In order to perform subsequent functional and operability testing, the affected trip function was removed from the tripped condition with the switch administratively inoperable and the trip function not in the tripped condition.
Action Statement 3.3,2.b was no longer met and Technical Specification (TS) 3.0.3 was entered.
Entry into TS 3.0.3 constitutes a condition prohibited by TS and is, thus, reportable.
The licensee determined the cause of the event was due to mechanical binding of components
within the flow switch lower switch assembly due to wear.
The SSES Technical Specifications, as written, do not permit for a trip signal to be reset to allow performance of TS surveillances needed to restore the system to an operable status.
Such provisions are being pursued as a part of the NRC generic Technical Specification improvement program.
The inspector agreed with the licensee's reportability determination and considered the licensee's root cause determination and corrective action adequate.
93-007-00 Unplanned ESF Actuation Due to Spurious Auto-Transfer of HPCI Suction Valves On November 10, 1993, with Unit 2 in Condition 1 at 100% power, the High Pressure Coolant Injection (HPCI) system pump suction automatically swapped from the condensate storage tank (CST) (normal suction) to the suppression pool during performance of surveillance testing.
Allequipment functioned per design.
The licensee determined the cause of the event was an inadequate procedure.
The procedure did not provide sufficient detail for lowering the water level in the float chamber to confirm instrument reset.
ISAAC technicians drained the chamber to the suppression pool instead of a rad container via the test connection.
This resulted in sufficient level increase in the 'B'nstrument float chamber (which is in parallel with the 'A'nd whose trip function was still intact) to actuate the switch and cause HPCI suction to transfer from the CST to the suppression pool.
The licensee reported the event as an unplanned ESF actuation.
The licensee revised the surveillance procedure to specify draining to a rad container via the test connection.
I&C engineers willbe trained to emphasize need for procedures to contain sufficient detail and emphasize the importance of work activity reviews.
Other HPCI surveillance procedures willbe reviewed for similar problems.
The inspector noted the corrective action excluded reviewing Reactor Core Isolation Cooling (RCIC) surveillance for similar problems.
The licensee agreed to review the RCIC surveillances for similar problems.
The licensee agreed to review the RCIC suryeillances for similar problems.
The RCIC system also has an autoswap feature from CST suction to suppression pool suction.
The inspector had no additional questions.
93-008-00 Condition Prohibited by Technical Specifications On November 24, 1993, with Unit 2 in Condition 1 at 100% power and Unit 1 defueled in Condition 5 at 0% power, the licensee reviewed degraded grid modifications and post modification testing completed during the Unit 1 7'efueling outage.
The licensee discovered that the Unit 2 93% degraded grid auxiliary load shed circuitry had not been tested following completion of circuitry modifications done during the outage.
This resulted in Unit 2 being operated in a condition prohibited by Technical Specifications in that portions of the 93% 4.16kv ESS Bus undervoltage protection scheme which ties to Unit 1 had not been declared operable.
Since all four Unit 2 4.16kv ESS Buses were affected, entry into
LCO 3.0.3 was required.
This also constitutes a condition prohibited by TS.
Upon discovery of the untested portion of the plant auxiliary load shed scheme testing was completed within the allowable 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> time frame of TS 4.0.3 and LCO 3.0.3 was cleared.
The licensee formed an Event Review Team (ERT) to investigate the cause of the event and other deficiencies identified during the modification implementation.
The cause of the event and subsequent actions to prevent recurrence willbe provided in a supplemental LER.
The inspector agreed with the reportability determination and will assess the licensee's root cause determination.
Final closeout of this LER is continued upon review of the licensee's supplement to the report, which is expected to discuss recent cause and corrective measures to prevent recurrence.
The licensee has taken some interim corrective actions prior to the Unit 2 Refueling Outage.
Since the SOOR resolution has not yet been completed, the inspector concluded the licensee's resolution of the matter was slow.
93-009-00 Unit Shutdown Due to Drywell Unidentified Leakage Exceeding Limits On December 11, 1993, with Unit 2 in Condition 1 at 15% power, Unit 2 completed a shutdown required by plants'echnical Specifications after unidentified drywell leakage exceeded the TS 3.4.3.2 limitof five gpm and the limitof two gpm increase within any four hour time period.
The cause of the event was due to leakage from a cracked Reactor Building Closed Cooling Water (RBCCW) pipe on the outlet from the internal heat exchanger of the 2A reactor recirculation pump.
The licensee determined the event was reportable in that Unit 2 completed a shutdown required by Plant's Technical Specifications.
NRC Inspection Report 50-387/93-22 documented this event.
94-001-00 Condition Prohibited by Technical Specifications (LCO Action 3.0.3)
On January 3, 1994, with Unit 2 in Condition 1 at 98% power, 18 Month Surveillance Test SE-124-207, "18 Month Emergency Diesel Generators 'B'nd 'D'uto Start and Engineered Safety System (ESS Buses)
1B and 1D Energization on Loss of Offsite Power with a LOCA Plant Shutdown" was performed on Unit 1 while shutdown.
As part of the test, the undervoltage start signals from the 1B and 1D ESS buses to the 1B and 1D EDGs are disabled with the undervoltage start signals (degraded voltage protection) disabled, ESS buses 1B and 1D (2 load groups) are cpnsidered not energized per Technical Specification 3.8.3.
Since Unit 2 TS 3.8.3.1 required that Unit 1 ESS loads remain energized for common A.C. distribution system loads and only contains provisions for one load group being de-energized, LCO 3.0.3 on Unit 2 was entered.
The licensee determined the event to be reportable as a condition prohibited by TS.
The cause of the LCO action 3.0.3 was due to 18 month surveillance testing on Unit 1 during its seventh refueling outage.'lthough TS requires the load groups be considered not energized, the load groups remained energized during the time the LCO was in effect.
The licensee TS performing reviews to determine if procedure testing methods and/or TS amendments can eliminate the need for entry into TS 3.0.3.
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.
94-002-00 Reactor Scram Following Turbine Trip on Loss of Generator Stator Cooling On January 20, 1994, at approximately 1:50 a.m., with Unit 2 at 100% power, a reactor scram occurred, per design, when the main turbine tripped due to a loss of Main Generator Stator Cooling.
The licensee reported the condition as an Unplanned Engineered Safety Feature actuation when the Reactor Protection System (RPS) initiated an automatic scram.
Section 2.2.1 pertains.
94-003-00 Operation Prohibited by Technical Specifications On January 21, 1994, with Unit 2 starting up in Condition 2 at 0% power, the acoustic monitor for the 'S'ain Steam Relief Valve (MSRV) was declared inoperable.
Due to weather related emergency circumstances, the NRC granted enforcement discretion to allow the licensee to continue with the startup of Unit 2 with the 'S'RV acoustic monitor inoperable.
The licensee determined the condition reportable as a condition prohibited by Technical Specifications.
The licensee willprovide a supplemental LER once the final determination of the acoustic monitor failure is completed.
The inspector noted the LER did not identify any previous LERs involving failure of MSRV acoustic monitors.
Further review by the inspector revealed, in fact, there were at least two 1983 LERs documenting failed acoustic monitors.
The licensee stated that their review has traditionally been initiated with 1984 LERs.
The inspector is evaluating the issue further.
Section 2.2.2 pertains.
LER Conclusion The inspector noted that in the case of several LERs, the documented corrective actions and actions to prevent recurrence in the LER were weak.
This was apparently due to the SOOR resolution associated with the event was not being completed when the LER was submitted.
This resulted in the LER portraying weak corrective actions.
The LER documented apparently weak corrective action when, in fact, the SOOR resolution corrective actions were more comprehensive and thorough.
The inspector concluded this was due to the LER being submitted in the required 30 days while the SOOR resolution process performed per NDAP-QA-0724 allowed 45 days for resolution.
However, the inspector discovered, in many cases, the SOOR resolution was not completed within the time limit specified in the Licensee Administrative Procedure.
The inspector discussed this observation with the licensee.
The licensee agreed to resolve this disparity between the LER documented corrective actions and those corrective actions which actually were taken or planned.
The inspector considered this a process weakness.
The licensee has efforts underway to improve the timeliness of SOOR resolution.
LERs 93-012-00 (Unit-1) and 93-008-00 (Unit-2) remain open pending review of supplementary information. Allothers are considered close.2 Plant Operations Review Committee Meeting (PORC) for Plant Startup The inspector observed portions of the startup PORC meeting following the Unit 1 Refueling Outage.
Presentations were clear and concise.
Station management was well represented and actively participated in the meeting.
The agenda was comprehensive and thorough.
Outstanding issues related to startup were clearly identified and aggressively pursued.
The Scram Action Item list was covered in great detail.
Organizations responsible for the meeting also focused on incorporating lessons learned from problems encountered during the outage prior to the March 1994 Unit 2 Refueling Outage.
The inspector concluded the required quorum and committee membership was present in accordance with Technical Specifications.
The PORC members maintained a healthy questioning attitude throughout the meeting.
PORC members asked probing questions during the various presentations.
The inspector had no further questions.
6.3 Cold Weather Preparation and Operation Background During the period the inspector reviewed the licensee's Cold Weather Preparations to protect safety related systems from the effects of cold weather to determine ifthe licensee has implemented an effective program.
The NRC issued Bulletin 79-24 "Frozen Lines" in September 1979 which documented several events where plants experienced frozen lines in various systems during cold weather.
The inspector reviewed licensee procedures, Preventative Maintenance activities, operator logs and licensee response to NRC IE Bulletin 79-24.
Licensee Program The licensee, in response to Bulletin 79-24, identified cold weather vulnerabilities.
The licensee installed insulation in the Residual Heat Removal Service Water (RHRSW) and the Emergency Service Water (ESW) Valve Vault as well as space heating.
The plant staff prepared off-normal and operating procedures in response to the bulletin. The inspector specifically reviewed ON-00-001, "Cold Weather Operations" and OP-185-(285)-001,
"Freeze Protection System Operation".
The inspector also reviewed the licensee's Preventative Maintenance program and procedures for freeze protection and winterization of the HVAC cooling systems.
Cold Weather Problems The licensee did experience some cold weather related problems this winter. The licensee experienced problems with portions of fire protection system freezing in non-safety related areas of the plant, reactor building ventilation heater design deficiencies, non-safety related heat, trace problems, and falling ice impacting RHR steam line blowout tamper panel.
The
impact of the events were minimal and did not significantly affect plant operation or adversely affect safety.
The licensee properly documented the problems on Station Operating Occurrence Reports (SOORs).
One exception was the fire protection system freezing problems which were not documented in any station deficiency program.
The inspector reviewed records indicating that condensate storage level indication had frozen repeatedly in the past (1983, 1984, 1985, 1987, 1991, 1993) due to heat trace problems.
Nuclear System Engineering (NSE) investigated the frozen CST level indication in 1993 and found the heat trace sensor installed in the wrong location.
Corrective actions taken in the winter of 1993 have been effective based on CST level indication not freezing during the extreme cold this winter.
Inspector Conclusion The inspector found the licensee off-normal procedure for cold weather operations adequate.
However, the procedure lacked clear guidance on following the procedure during sustained cold weather operations.
Specifically, whether to complete and sign-off the procedure on a daily basis.
The inspector verified, on a sampling basis, the presence of heat tracing, space heaters, properly set thermostats and the presence of insulation.
The inspector checked various heat trace circuits and found them operating properly.
The inspector found the freeze protection system operating procedure adequate, The inspector toured affected areas during extremely cold weather conditions and found conditions acceptable with regard to prevention of freezing.
The inspector verified that the licensee inspects and tests heat tracing circuits prior to cold weather.
Notwithstanding the fire protection freezing example, the inspector concluded the licensee properly documented the weather related deficiencies identified this winter using the SOOR process.
The inspector concluded that the licensee's cold weather program was satisfactory.
There were some areas identified to the licensee for improvement.
The inspector considered the repetitive nature of the CST level indication freezing, until NSE involvement, indicative of a lack of comprehensive root cause determination and subsequent corrective action that would have prevented recurrence.
However, once involved, NSE implemented appropriate corrective actions to prevent recurrence of frozen CST level indication.
The engineer, when questioned, demonstrated knowledge of all the past events dating back to 1983.
System engineer knowledge of this problem was excellent.
The inspector had no further questions.
7.
MANAGEMENTAND EXIT MEETINGS 7.1 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.2 Inspections Conducted By Region Based Inspectors 01/03/94 - 01/07/94 01/15/94 - 02/19/94 01/10/94 - 01/14/94 gab't Safety Engineering Safeguards
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