IR 05000461/1998004

Insp Rept 50-461/98-04 on 980213-16.No Violations Noted. Major Areas Inspected:Operations & Maint

ML20217D627
Person / Time
Site:	Clinton
Issue date:	03/20/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20217D624	List: IR 05000461/1998004 ML20217D621
References
50-461-98-04, 50-461-98-4, NUDOCS 9803300113
Download: ML20217D627 (23)

Text

.

,

U.S. NUCLEAR REGULATORY COMMISSION REGIONlil Docket No: 50-461 License No: NPF-62 Report No: 50-461/98004(DRS)

Licensee: lilinois Power Company Facility: Clinton Nuclear Power Station Location: Route 54 West Clinton,IL 61727 Dates: February 13 - 16,1998 inspectors: E. Duncan, Lead Inspector J. Neisler, Electrical Engineering Specialist D. Muller, Operator Licensing Specialist

!

I Approved by: John M. Jacobson, Chief, Lead Engineers Branch

!

,

i l

.

9803300113 980320

.PDR ADOCK 05000461 G pm

_m

.

.

EXECUTIVE SUMMARY Clinton Nuclear Power Station, Unit 1 NRC Inspection Report 50-461/98004 Qwrations

. Operator response to a loss of shutdown cooling event on February 13,1998, was generally good. One weakness identified was an emphasis on restoration of the division 2 nuclear system protection system (NSPS) bus as the sole success path for the restoration of shutdown cooling. (Section 01.1)

-.' Operations personnel failed to take prompt actions to address a potential division 2 emergency diesel generator (EDG) overload event which occurred on February 11, 1998. In particular, the shift resource manager (SRM) and "B" control room operator (CRO) failed to conservatively reduce EDG loading during a surveillance test when indications of an overload condition were identified. (Section 01.2)

. Procedures used to address the loss of shutdown cooling event failed to provide adequate instructions which unnecessarily challenged operators to respond to the even (Section 03.1)

. Some operators were not adequately knowledgeable regarding the operation of the 1 division 2 NSPS bus static switch as well as the consequences of the loss of the NSPS

.

bus on plant indications and logic inputs. (Section 04.1)

. Some operators exhibited significant knowledge deficiencies regarding the configuration, operation, and availability of the division 2 NSPS bus and the associated supporting equipment following the loss of shutdown cooling event. This was the result of inadequate communication of the contingencies established should a loss of the NSPS bus recur. (Section 04.2)

.

. Licensee personnel failed to adequately assess the risk involved with tagging out the division 2 NSPS regulating transformer and, as a result, failed to develop contingency plans for the potentialloss of the division 2 NSPS bus. (Section 07.1)

Maintenance

]

. The licensee failed to correct deficiencies associated with the division 2 NSPS inverter despite repeated failures. (Section M1.1)

!

!

!

2 i

!

l

.

.

Report Details Summarv of Plant Status The following plant conditions existed during the division 2 EDG potential overload event on February 11,1998, and prior to the loss of shutdown cooling event on February 13,199 . The reactor was in cold shutdown, mode . The "A" RHR system was operating in the shutdown cooling mod . The reactor water cleanup (RWCU) system was recirculating reactor coolant from the RHR loops and reactor pressure vessel (RPV) bottom head drain back to the RP . The RWCU system was aligned for letdown to radwaste to compensate for the flow of water into the RPV from the control rod drive hydraulic (CRDH) syste . Operations 01 Conduct of Operations 0 Loss of Shutdown Cooling Event Insoection Scone The inspectors reviewed the circumstances surrounding a February 13,1998, loss of shutdown cooling event. Inspection activities include )

. Reviews of logs, alarm printouts, and other documentation that were maintained during the even . Interviews with operating crew members who responded to the even . Observance of licensee post-event fact finding meetings and critique . Reviews of licensee documents used during the fact finding meetings and critique . Reviews of procedures used by operators during the even Observations and Findings Background - Inverter Ooerations and Power Sucolies The loss of shutdown cooling event was initiated by the loss of the division 2 nuclear system protection system (NSPS) 120V altemating current (Vac) bus. One of the effects of the loss of the division 2 NSPS bus was the automatic isolation of numerous l containment isolation valves, including RHR and RWCU containment isolation valve )

While this bus was de-energized, the containment isolation signal remained " sealed in,"

and the affected containment isolation valves could not be reopened from the control room hand switche The division 2 NSPS bus had two power supplies: (1) safety-related 125 Volt DC (Vdc)

via the division 2 NSPS DC to altemating current (AC) inverter, and (2) safety-related l

i

.

480 Vac via the division 2 NSPS 480 Vac to 120 Vac regulating transformer. The division 2 NSPS bus static switch was used to select which power source supplied the division 2 NSPS bus. Normally, the static switch was selected to the output of the NSPS inverter. If a fault was sensed on the AC (output) side of the inverter, the transfer switch automatically shifted to the regulating transformer output, even if there was no 120 Vac output power from the transformer. There was no automatic transfer feature back from the regulating transformer to the inverte The initial condition of the division 2 NSPS bus power supply components prior to the event was as follows:

. The NSPS bus was energized via the NSPS inverte . The static switch was selected to the inverte . The NSPS regulating transformer was de-energized and tagged out-of-service for maintenance. The only work on the regulating transformer that had been performed since it was tagged out-of-service was the removal of access covers for a visual inspectio Secuence of Events i

The inspectors reviewed logs, alarm printouts, and other documentation; interviewed {

cognizant individuals who responded to the loss of shutdown cooling; and developed the following sequence of events:

THHg Event Descriotion 3:42 am A loss of the division 2 NSPS bus occurred due to an unexpected transfer of the static switch from the inverter to the regulating transformer (which was de-energized for maintenance). The control room received multiple alarms associated with the loss of division 2 NSPS power. The RWCU inboard containment isolation valves closed and the RWCU pumps tripped automatically on low flow due to the loss of NSPS bus powe l 3:43 am The control room crew tripped the "A" RHR pump, based on the shift supervisor's observation that the shutdown cooling inboard suction isolation valve,1E12-F009, was not fully open. The control room crew also shut the RHR "A" shutdown cooling return valve. Shutdown cooling was no longer provided since both RHR and RWCU were no longer in operatio :43 am The control room crew observed that RPV water level was out of the administrative band of 90 to 100 inches (104 inches) cnd was increasin This was due to the loss of letdown flow when RWCU isolated with CRDH still adding water inventory to the RPV. The crew tripped the "A" CRDH pump to minimize any further level increas .

.

3:45 am With reactor coolant system (RCS) temperature at about 106 degrees Fahrenheit, the control room crew entered Clinton Power Station (CPS)

procedure 4006.01, " Loss of Shutdown Cooling," and began to record RPV heatup log data. The crew diagnosed the plant conditions as a loss of division 2 NSPS power, and a field operator was dispatched to

'

investigate. The crew verified that the appropriate division 2 containment isolation valves were closed per CPS 4001.02C001, " Automatic Isolation Checklist."

3:52 am The field operator reported back to the control room that the division 2

'

NSPS static switch had shifted to the regulating transformer which was

- tagged out-of-servic :55 am. The shift supervisor directed electrical maintenance personnel to restore the regulating transformer, so that the out-of-service tags could be cleared. The shift supervisor determined that the inverter was an ]

unreliable and unavailable power sourc )

3:59 am The control room crew attempted to establish an alternate means of shutdown cooling, utilizing the main steam line drains. However, the crew was unable to open the main steam line drain inboard isolation valve from the control room hand switch due to the loss of tho division 2 NSPS bu :11 am The shift supervisor declared an ALER :15 am Efforts were initiated to re-install the access covers on the regulating transformer and clear the associated out-of-service tags. Actions were directed by the shift supervisor to prepare to re-energize the division 2 l NSPS bus in accordance with CPS 3509.01, " Instrument Power System." !

CPS 3509.01 required the completion of a bus outage checklist designed ,

'

to remove all loads from the bus to prevent inadvertent pump starts and valve repositioning when the bus was re-energized. This was an extensive checklist which required local breaker manipulations, fuse removals, switch manipulations, and the installation of various jumper :35 am State and local notifications of the ALERT were completed 5:03 am The division 2 NSPS bus outage checklist was complete :37 am The regulating transformer access covers were re-installed and the out-of-service tags were cleared. The division 2 NSPS bus was re-energized via the regulating transformer. Actions were directed by the shift supervisor to restore the division 2 NSPS bu :50 am RWCU restoration actions were initiate .______m___ ___-

.

.

. i 6:24 am The "A" RWCU pump was started and RPV water recirculation was restored, 6:26 am The "B" RWCU pump was starte ,

li 6:33 am RWCU letdown to radwaste was restored and RPV water level was lowered from about 104 inches to 97 inche :00 am Component cooling water was verified to be properly aligned to the RWCU non-regenerative heat exchanger. The RWCU system was verified to be providing shutdown cooling. The crew exited CPS 4006.01,

" Loss of Shutdown Cooling." Preparations wers made for restoring RHR

"A" shutdown cooling. Part of these preparations included the performance of a fill and vent of the train "A" RHR system. This was l

'

performed due to the presence of the RHR "A" pump low discharge pressure alar :03 am The "A" CRDH pump was re-starte :17 am The train "A" RHR fill and vent evolution was completed. A momentary RHR "A" low discharge pressure alarm was received immediately after the evolution was terminated. The control room crew discussed whether or not the train "A" RHR fill and vent should be re-performed. Shift j turnover activities were also in progress. The crew decided that since the alarm was only received momentarily that they could continue to restore RHR train "A" without an additional fill and ven :57 am Just prior to starting the "A" RHR pump, the crew received the RHR "A" low discharge pressure alarm. The shift supervisor directed the performance of another train "A" RHR fill and ven During the performance of this second fill and vent evolution, an error was identified in the fill and vent procedure and the evolution was suspende :45 am The procedure error was corrected, and the fill and vent evolution was complete :44 am The "A" RHR pump was started and RHR shutdown cooling was restored. Final RCS water temperature was about 109 degrees fahrenheit, which represented a heatup of about 3 degrees during the 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> that RHR was not available for shutdown coolin :04 am The ALERT was terminated.

'

.

l I

Time to Boit Data Evaluation  :

As indicated in the sequence of events, no shutdown cooling was provided from 3:43 am when the division 2 NSPS bus was de-energized, until RWCU was restored at 6:24 am, a period of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and 41 minutes. In addition, RHR shutdown cooling was unavailable for about 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> during which time RCS temperature increased from about j 106 degrees fahrenheit to about 109 degrees fahrenheit which equated to an average j heatup rate of about one-half a degree per hour. The inspectors also noted that for roughly half of this 6-hour period RWCU was providing some shutdown cooling via the RWCU non-regenerative heat exchanger, in addition, time to boil curves indicated that boiling would not occur for at least 41 hours4.74537e-4 days <br />0.0114 hours <br />6.779101e-5 weeks <br />1.56005e-5 months <br />. The inspectors reviewed these curves and concluded that they were extremely conservative since the plant conditions assumed for the generation of these curves was essentially " worst case" and did not reflect actual plant conditions. In any event, the inspectors concluded that a significant amount of time was available to the licensee to restore shutdown cooling prior to boiling in the .

vesse Ooerator Event Resoonse The inspectors reviewed the actions of operations personnel in response to this event i and concluded that overall, operator response to the event was good. Actions to trip the

"A" RHR pump when the shift supervisor identified that the RHR suction isolation valve, 1E12-F009, was not fully open were particularly good. Subsequently, the licensee determined that with the loss of the division 2 NSPS bus, the "A" RHR pump would not ,

have automatically tripped. Therefore the actions of the crew prevented the "A" RHR i pump from running without a suction path and avoided potential pump damag j One weakness identified by the inspectors during shutdown cooling restoration activities was an emphasis on restoration of the division 2 NSPS bus as the sole success path for the restoration of shutdown cooling. The inspectors identified that shutdown cooling could have been more expeditiously restored if the crew had simply Iccally opened the RHR suction isolation valve, and proceeded with the fill and vent of RHR, rather than expending resources to restore power to the NSPS bus to allow remote valve operatio However, considoring the amount of time available to the operators prior to core boiling, the inspectors concluded that the actions of the crew in response to the event were goo c. Conclusions The inspectors concluded that operator response to this event was generally good. One weakness identified was an emphasis on restoration of the division 2 NSPS bus as the sole success path for the restoration of shutdown coolin .

.

01.2 Potential Division 2 Emergency Diesel Gerierator (EDG) Overload Event Insoection Scone The inspectors reviewed the circumstances surrounding a potential division 2 EDG overload event which occurred on February 11,1998. Inspection activities included:

. A review of licensee docurnents associated with a February 13,1998, licensee post-event critiqu . Interviews and discussions with licensee engineering personne . Interviews with the control room crew members and the shift resource manager (SRM) on shift during the even * Reviews of Clinton Power Station (CPS) procedures CPS 9080.01, " Diesel Generator 1 A(B) Operability - Manual and Quick Start Operability," revision 42, and CPS 1401.01, " Conduct of Operations," revision 2 Observations and Findings

. Seauence of Events The inspectors reviewed documentation, interviewed cognizant personnel, and developed the following sequence of events:

During their oncoming shift turnover, the February 11,1998 midnight shift control room crew received direction to perform CPS 9080.01, " Diesel Generator 1 A(B) Operability -

Manual and Quick Start Operability" for the division 2 EDG. The surveillance was being performed to meet routine semi-annual testing requirements and to demonstrate operability following maintenance activities which replaced the division 2 EDG air-start solenoids. Shortly following shift turnover, the control room crew took actions to clear the out-of-service tags on the division 2 EDG, and to prepare the division 2 EDG for surveillance testing. These actions were completed by about 3:00 am on February 1 Ilmg Event Descriotion 3:15 am A 10-minute briefing, observed by the NRC resident inspector, was held for the planned division 2 EDG surveillance tes :45 am Communications were established between personnel in the division 2 EDG room and the control roo :54 am The division 2 EDG was started by the "B" CRO from the control room in accordance with CPS 9080.01, " Diesel Generator 1 A(B) Operability -

Manual and Quick Start Operability." Desired voltage and frequency within the surveillance time limits were obtained and no unusual indications were identifie _

.

.

3:56 am The "B" CRO obtained satisfactory EDG response to the manipulation of governor and voltage regulator hand switche :03 am The "B" CRO successfully paralleled the EDG with offsite power and commenced loading the EDG at about 1000 kilowatts (KW) per minute in accordance with CPS 9080.0 :08 am The "B" CRO established full load conditions: 4050 KW and 2250 kilovolt-amperes reactive (KVAR) by control room indications. The EDG was required to remain fully loaded for at least 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to meet surveillance testing requirement :05 am The shift resource manager (SRM), a licensed senior reactor operator, entered the division 2 EDG room and identified that the local KW meter indicated 4500 KW. The SRM believed that this was excessive, checked the local operator's copy of CPS 9080.01, and verified that the required loading was 4000 to 4100 KW by control room KW meter indication. The SRM, local operator, and resident inspector exited the EDG room and I

briefly discussed the local KW meter indication. The SRM informed the resident inspector that the local KW meter was not the meter used during the surveillance, but that the meter should be working properly and that the meter should be checked. The SRM directed the local operator to inform the control room of the local KW meter reading. The SRM, local operator, and resident inspector re-entered the division 2 EDG room and re-verified that the local KW meter indicated 4500 K :10 am The SRM exited the EDG room. The local operator informed the "B" CRO that the local KW meter indicated 4500 KW. The "B" CRO noted that the control room KW meter indicated 4100 KW. As directed by the

"B" CRO, the local operator recorded local EDG reading l l

5:14 am The "B" CRO unloaded the division 2 EDG to 600 KW. As directed by the

"B" CRO, the local operator reported back that the local KW meter was )

also reading 600 KW. The "B" CRO continued unloading the ED I 5:17 am With the EDG at 200 KW, the "B" CRO opened the division 2 EDG output breaker and commenced a normal EDG cooldown. The "B" CRO j reported to the line assistant shift supervisor (LASS) the discrepancy '

between local KW and control room KW meter indication :27 am The division 2 EDG was shutdown, following a normal 10-minute cooldow l 6:00 am The SRM initiated a maintenance work request to investigate the local l KW meter indication discrepancy. The control room crew discussed the possibility that the division 2 EDG was overloade !

.

.

6:30 am The shift supervisor informed system engineering personnel of the potential division 2 EDG overload conce Insoector Review The inspectors interviewed the SRM and "B" CRO and determined that both individuals believed that the local meter reading of 4500 KW was in error and, as a result, failed to consider the possibility that the indication may be accurate. This was due, in part, to the surveillance procedure itself which relied upon the control room indication for the data of record and contributed to the failure to adequately consider the local indication as a source of informatio Procedure CPS 1401.01, " Conduct of Operations," revision 28, required that indications which are provided to monitor plant parameters shall be believed, unless verified faulty by two alternate independent means, or through maintenance troubleshooting.10 CFR 50, Appendix B, Criterion V," Instructions, Procedures, and Drawings, required,in part, that activities affecting quality shall be prescribed by documented procedures, and shall be accomplished in accordance with those procedures. The failure to rely upon local indications of a division 2 EDG overload condition without verification by two independent means as required by CPS 1401.01 was an example where the requirements of 10 CFR 50, Appendix B, Criterion V, were not met and was a violatio However, because significant NRC enforcement action was taken for a programmatic breakdown in procedure adherence and the criteria in Section Vll.B.2, " Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions"(Enforcement Policy),

NUREG-1600 were met, a Notice of Violation is not being issued (NCV50-461/98004-01). Conclusions )

I The inspectors concluded that the SRM did not adequately pursue indications that the division 2 EDG was operating above maximum rated load. In addition, the "B" CRO failed to conservatively reduce the EDG loading or immediately inform shift management of the potential overload conditio Operations Procedures and Documentation O3.1 Procedure Review - Loss of Shutdown Coolina Event Insoection Scoce The inspectors reviewed the following procedures that were used to address the loss of shutdown cooling event:

. CPS 4006.01, " Loss of Shutdown Cooling," revision 1;

. CPS 3312.01,"RHR," revision 28; ,

i

l i

a

-

.

l

. CPS 3509.01, " Instrument Power System," revision 13, including associated bus checklists;

. CPS 4001.02, " Automatic Isolation," revision 13, including associated checklist In addition, the inspectors reviewed control room logs, and conducted interviews with operations personnel who responded to the even b. Observations and Findings The inspectors reviewed the procedures discussed above and identified the following issues:

CPS 4006.01. " Loss of Shutdown Cooling." Procedure Review The inspectors reviewed CPS 4006.01 and identified that the procedure failed to direct operators to refer to time to boil curves. The inspectors concluded that this was a procedure weakness since one of the primary concerns during a loss of shutdown cooling is the prevention of boiling in the RP The inspectors also noted that during the event operators did refer to the time to boil curves, despite the absence of this direction in CPS 4006.0 CPS 3312.01. "RHR." Procedure Review The inspectors reviewed CPS 3312.01 and verified that as discussed in the sequence of events, there was an error in the RHR fill and vent section of the procedur Specifically, step 8.2.5.4 of the procedure directed operators to locally open 1E12-F085A, the water leg pump supply valve to RHR train "A". However, operators identified that this step was not adequate since during shutdown cooling operations the water leg pump would pump suppression pool water into the RHR system and have the undesirable effects of RPV water quality degradation, suppression pool inventory reduction and RPV water addition. As a result, operators generated procedure deviation request 98-0115 to close 1E12-F085A prior to starting the "A" RHR pum CFR 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings," requires, in part, that activities affecting quality be prescribed by procedures which are I appropriate to the circumstances. The failure to have an adequate procedure to fill and vent the RHR system prior to the restoration of shutdown cooling was an example where the requirements of 10 CFR 50, Appendix B, Criterion V were not met and was a i violation. However, because this violation was based upon activities prior to the events

'

leading to the current extended plant shutdown and satisfies the criteria in Section Vll.B.2," Violations identified During Extended Shutdowns or Work Stoppages," of the i

" General Statement of Policy and Procedures for NRC Enforcement Actions" 1 (Enforcement Policy), NUREG-1600, a Notice of Violation is not being issued (NCV50-461/98004-02).

. I Following restoration from the loss of shutdown cooling event, operations personnel developed Temporary Procedure Deviation (TPD) 98-0116 which provided specific i actions on how to restore shutdown cooling if division 2 NSPS power was lost agai {

This TPD basically directed operators, upon a loss of the division 2 NSPS bus, to perform the following actions to restore shutdown cooling:

- Trip the "A" RHR pump;

. Shut the "A" RHR shutdown cooling return valve; ,

. Open the breaker for shutdown cooling isolation valve 1E12-F009; {

. Locally open 1E12-F009; l

. Perform a fill and vent of train "A" RHR (if required);

• Start the "A" RHR pump; and

. Open the RHR "A" shutdown cooling return valv The inspectors reviewed this TPD and concluded that the planned actions were an l appropriate and expeditious means for restoring shutdown coolin Conclusions The inspectors concluded that procedures used to address the loss of shutdown cooling event failed to provide adequate instructions which unnecessarily challenged operators to respond to the event. In particular, the inspectors concluded that the fill and vent section of the RHR procedure was inadequate and, as a result, slowed efforts to restore RHR shutdown cooling. The inspectors also concluded that a TPD to address a loss of division 2 NSPS power prescribed an appropriate and expeditious means to restore shutdown coolin Operator Knowledge and Performance 04.1 Ooerator Knowledge Assessment - Loss of Shutdown Cooling Event Insoection Scoce The inspectors discussed the loss of shutdown cooling event with operators who responded to the event to assess operator knowledge level. In particular, the inspectors questioned operators on the operation of the NSPS inverter static switch, as well as the overall operation and reliability of the division 2 NSPS bu ,

1 Observations and Findings The inspectors discussed the loss of shutdown cooling event with cognizant operator Following that discussion, operator knowledge deficiencies regarding the operation of the NSPS static switch, and the consequences of a loss of the division 2 NSPS bus l were identified and are discussed belo ;

.

.

s Knowledge Deficiency Regarding the NSPS Static Switch During the licensee post-event critique, operators on shift during the event discussed the fact that there was some initial confusion as to why the division 2 NSPS bus was q lost. The inspectors determined that the reason for the confusion was a knowledge I deficiency regarding the operation of the division 2 NSPS static switch. Specifically, operators did not understand that the static switch would automatically transfer from the inverter to the regulating transformer although the regulating transformer was de-energize Knowledge Deficiency Regarding the Effects of a Loss of the Division 2 NSPS Bug The inspectors determined that two effects of a loss of division 2 NSPS power were not entirely understood by operators during the event as discussed below:

RHR Pumo Trio Logic The inspectors identified that operators did not fully understand the trip interlock logic associated with the RHR pump and whether or not the "A" RHR pump would automatically trip as a result of the shutdown cooling inboard suction isolation valve, 1E12-F009, going closed. In particular, there was confusion as to whether the RHR pump trip signal was generated as soon as the valve was not full open, or when the valve was fully closed. Although the operators tripped the RHR "A" pump, they did not pursue the reason that the pump did not automatically trip as the isolation valve close The inspectors brought this concern to the licensee's attention and it was subsequently determined that the RHR pump trip logic was de-energized when the division 2 NSPS bus was de-energized. However, the inspectors concluded that licensee personnel failed to exhibit a questioning attitude with respect to this conditio Emergency Core Cooling Svstem (ECCS) Room High Temoerature Alarms The inspectors also identified that initially operators did not realize that ECCS room high temperature alarms received during the event were due to the loss of the division 2 NSPS bus. As a result, confusion regarding the source of the alarms unnecessarily distracted operators from responding to the even The inspectors concluded that the effects of a loss of the division 2 NSPS bus on alarm indications and RHR pump trip logic was not well understood and distracted operators during the even Conclusions The inspectors concluded that operators were not adequately knowledgeable regarding

. the operation of the division 2 NSPS inverter static switch or of the consequences of the loss of the NSPS bus on plant indications and logic inputs. The inspectors also l

_ ____ __a

I

.

.

t concluded that although these deficiencies unnecessarily distracted operators during shutdown cooling restoration activities, the impact was not significant since core decay heat was minima O4.2 Loss of Shutdown Cooling Ooerator Knowledge Assessment insoection Scooe The inspectors reviewed licensee documents which discussed how operators were to be made aware of the loss of shutdown cooling event and what actions operators were expected to take if a loss of the division 2 NSPS bus occurred. In addition, the inspectors conducted interviews with operators on shift on February 15,1998, to determine if the actions discussed above had been adequately disseminate Observations and Findinas As discussed in section O3.1, following the restoration of shutdown cooling, the licensee approved TPD 98-0116 which provided specific direction on the actions to take if division 2 NSPS power was lost. This TPD basically directed operators, upon a loss of the division 2 NSPS bus, to perform the following actions to restore shutdown cooling:

. Secure the "A" RHR pump;

. Shut the "A" RHR shutdown cooling return valve;

. Open the breaker for shutdown cooling isolation valve 1E12-F009;

. Locally open 1E12-F009;

. Perform a fill and vent of RHR train "A"(if required);

. Start the "A" RHR pump; and

. Open the RHR "A" shutdown cooling return valv In addition, the inspectors determined that a February 13,1998 memorandum written shortly after shutdown cooling was restored provided a summary of the status of the shutdown cooling isolation valve, the availability of the division 2 NSPS bus, and stated that the RHR procedure had been revised to include actions to be taken in the event that the division 2 NSPS bus was de-energized. Also, the memorandum directed operations personnel to review the revised RHR procedure and directed management to brief operators at the earliest opportunit The inspectors reviewed the memorandum and identified the following weaknesses:

. The memorandum did not adequately discuss the consequences of a loss of the division 2 NSPS bu . The memorandum did not direct a review of the loss of shutdown cooling procedur . The memorandum did not provide information regarding the current status and availability of the division 2 NSPS bus inverte .

The inspectors concluded that the memorandum did not provide sufficient information to adequately inform operators of the current condition and availability of the division 2 NSPS bus, and the consequences of a loss of the bu Ooerator Interviews The inspectors conducted individual interviews with the "A" and "B" CRO, line assistant shift supervisor (LASS) and shift supervisor assigned to the February 15,.1998, dayshift to assess whether operators were cognizant of the event and actions to respond to a loss of the division 2 NSPS bus as outlined in the revised RHR procedure and February 13 memorandum. The following weaknesses were identified:

)

"B" CRO Interview Results The inspectors interviewed the "B" CRO and determined that although the operator recognized the need to secure the "A" RHR pump, other actions identified by the operator to address a loss of the division 2 NSPS bus were not consistent with the direction contained in the revised RHR procedure, but rather focused on restoration of RWC Upon further review, the inspectors determined that although the operator was aware of the February 13 memorandum and the revised RHR procedure, the operator had not been briefed on the event, had not read the memorandum, and had not reviewed the revised RHR procedur "A" CRO interview Results The inspectors interviewed the "A" (at the controls) CRO and determined that similar to the "B" CRO, the "A" CRO was aware that the RHR procedure had been revised, but had not reviewed the revised procedure. In addition, the "A" CRO was completely unaware that a memorandum had been written concerning the event. Also, the inspectors determined that upon a loss of the division 2 NSPS bus, the "A" CRO was not aware that the shutdown cooling isolation valve would close resulting in a loss of shutdown cooling. Instead, the "A" CRO stated that he would monitor critical plant parameters, since shutdown cooling may be lost depending upon the sequence in which division 2 components, including the shutdown cooling isolation valve, de-energize The inspectors also determined that although the "A" CRO recognized the need to i secure the "A" RHR pump, other actions identified by the operator to address a loss of 1 the division 2 NSPS bus were not consistent with the direction contained in the revised RHR procedure, but instead focused on restoration of NSPS powe Line Assistant Shift Suoervisor (LASS) Interview Results The inspectors interviewed the LASS with questions similar to those presented to the j

"A" CRO and "B" CRO. In this case, however, the inspectors determined that the LASS l

,

!

l l

l

__

.

$

had reviewed the memorandum and the revised RHR procedure, and understood the actions specified to restore shutdown coolin However, a significant knowledge deficiency was identified. Specifically, when l

'

questioned regarding the effects of a loss of the division 2 NSPS regulating transformer, the LASS responded that the static switch would automatically transfer to the inverter which may provide power to the bus and therefore not result in a loss of shutdown cooling. The inspectors concluded that this was an incorrect response since there was no automatic transfer feature of the static switch from the regulating transformer to the inverter, but only from the inverter to the regulating transformer. In addition, the inverter ,

had been isolated from divisicn 2 NSPS bus after the event had occurred and was {

unavailabl ]

I Finally, the inspectors determined that although the LASS had read the February 13 memorandum regarding the event, the LASS failed to ensure that the operators under his supervision had been briefed on the event and understood the actions to be taken in the event of a loss of the division 2 NSPS bus as directed in the revised RHR procedur Shift Suoervisor Interview Results The inspectors interviewed the shift supervisor and determined that the shift supervisor had read both the memorandum and the revised procedure, and understood the availability and operation of the division 2 NSPS bus and related components, such as the inverter and regulating transforme However, the inspectors also identified that the shift supervisor failed to ensure that the crew understood the loss of shutdown cooling event, including the actions to be taken if a division 2 NSPS bus power supply failure occurre Procedure CPS 1401.01, " Conduct of Operations," revision 28, required that each shift member, including the shift supervisor, LASS, and CROs review the main control room journal and night orders / memorandum prior to, or shortly after, assuming shift duties. In addition, CPS 1401.01 required that each shift member be adequately briefed prior to assuming shift responsibilities, and that it is the responsibility of the shift supervisor and LASS to take whatever action is necessary to accomplish this turnover.10 CFR 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings, required, in part, that activities affecting quality shall be prescribed by documented procedures, and shall be accomplished in accordance with these procedures. The failure to ensure that the February 15 dayshift operating crew was adequately briefed on the loss of shutdown cooling event was an example where the requirements of 10 CFR 50, Appendix B, Criterion V, were not met and was a violation. However, because this violation was based upon activities prior to the events leading to the current extended plant shutdown and satisfies the criteria in Section Vll.B.2, " Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions"(Enforcement Policy), NUREG-1600, a Notice of Violation is not being issued (NCV50-461/98004-03).

. Conclusions The inspectors concluded that some operators exhibited significant knowledge deficiencies regarding the configuration, operation, and availability of the division 2 NSPS bus and supporting equipment. In particular, the shift supervisor was the only person on the February 15,1998, dayshift crew who completely understood both the availability of power to the division 2 NSPS bus and the actions to be taken in the event of a loss of shutdown cooling. This was due,in part, to poor communications between the shift supervisor and the LASS to the rest of the crew, as well as poor communications between upper station management and shift managemen Quality Assurance in Operations 07.1 Loss of Shutdown Cooling Precursors Insoection Scooe The inspectors reviewed the operating history and maintenance activities conceming the division 2 NSPS inverter and regulating transformer that occurred prior to the loss of shutdown cooling event. In particular, the inspectors reviewed the risk assessments performed by the licensee to evaluate planned maintenance activities on the regulating transformer, Observations and Findings The inspectors reviewed the operating history of the division 2 NSPS inverter and identified a long history of problems including spurious transfers of the static switch from the inverter to the regulating transformer. Licensee personnel recalled that when this condition was discovered, the common practice was to verify that the inverter was operating properly, and then manually transfer the static switch back to the inverte Licensee personnel also recalled that these occurrences were occasionally, but not consistent ly, documented in condition report In January 1998, the licensee conducted troubleshooting of the NSPS inverter. During this period, the NSPS bus was powered from the regulating transformer. This troubleshooting resulted in a list of the most probable causes and possible solutions for the spurious static switch transfers. During this troubleshooting, a spurious transfer of the static switch could not be re-created. Various tests were performed and circuit cards replaced. Post-maintenance testing (PMT) was started on February 10,1998. The inverter PMT consisted of running the inverter for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> while monitoring its performance remotely by means of a video camera. The result of the PMT was that during the 24-hour period, no inverter problems were identified. As a result, engineering personnel concluded that the inverter was *available and reliable," even though the troubleshooting and testing activities had not positively determined that the problem had been correcte {

.

Since December of 1997, the licensee had scheduled corrective maintenance for the division 2 NSPS regulating transformer to address lug and soldering quality concern For various reasons, including the questionable availability of the division 2 NSPS inverter, this maintenance was delaye On February 11,1998, the inverter was placed on the NSPS bus with the static switch selected to the inverter. On February 12, the division 2 NSPS regulating transformer was de-energized and tagged out-of-service in preparation for regulating transformer maintenance. Therefore, at this time, the only power source available to the division 2 NSPS bus was the inverter. With the inverter PMT completed, licensee personnel believed that the inverter was a reliable source of power for the division 2 NSPS bu On February 13, a spurious transfer of the static switch to the de-energized regulating transformer occurred, and caused the loss of the division 2 NSPS bus and subsequent loss of shutdown coolin The inspectors reviewed the licensee's decision to perform maintenance on the regulating transformer with a potentially unreliable inverter and determined that licensee personnel did not fully consider the reliability of the division 2 NSPS inverter, the adequacy of the inverter maintenance and testing to correct potential inverter problems, and the risk and consequences associated with reliance on the inverter as a sole source of power to the division 2 NSPS bus. The inspectors also concluded that, as a result, the licensee failed to implement contingency plans for a potential loss of the division 2 NSPS bu CFR 50, Criterion V, " Instructions, Procedures, and Drawings," required, in part, that activities affecting quality shall be prescribed by documented procedures appropriate to the circumstances and shat; be accomplished in accordance with those procedure Procedure CPS 1151-09, " Methodology for Outage Safety Reviews," revision 0, required that outage safety reviews ensure that higher risk evolutions are clearly identified in the schedule, and that adequate contingency plans and mitigating procedures are developed. The failure of the licensee to identify the maintenance on the regulating transformer as a high risk evolution in the schedule and have contingency plans and mitigating procedures in place as required by CPS 1151-09 was an example where the requirements of 10 CFR 50, Appendix B, Criterion V, were not met and was a violatio However, because significant NRC enforcement action was taken for a programmatic breakdown in procedure adherence, and the criteria in Section Vll.B.2, " Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions"(Enforcement Policy), NUREG-1600 were met, a Notice of Violation is not being issued (NCV50-461/98004-04).

c. Conclusions The inspectors concluded that as a result of not asking fundamental questions concerning the operational status of the division ? tSPS inverter, the licensee failed to adequately assess the risk involved with tagging out the division 2 NSPS regulating transformer. Additionally, due to a lack of knowledge concerning the operational status of the division 2 inverter, the licensee failed to develop contingency plans for the

,

.

.

potentialloss of the division 2 NSPS bus. Although the inverter troubleshooting and ,

testing activities had not positively identified that the spurious transfer of the static switch problem had been corrected, the licensee de-energized and tagged out-of-service the regulating transformer. As a result, when the static switch spuriously {

transferred to the regulating transformer, the division 2 NSPS bus was de-energized i which resulted in a loss of shutdown coolin Ij 11. Maintenance M1.1 NSPS Inverter Transfer to Alternate Bus I

' Insoection Scooe The inspectors examined equipment, reviewed specifications, inverter failure history and i work requests to evaluate licensee and equipment performance associated with the loss of shutdown cooling even Observations and Findings i

As discussed in section 07.1, the inspectors reviewed the operating history of the l division 2 NSPS inverter and identified a long history of problems including the spurious transfer of the static switch from the inverier to the regulating transformer. At the end of the inspection the licensee had not identified a root cause for the spurious transfers of the inverter to the regulating transforme l The inspectors concluded that although the licensee has been aware of problems with the division 2 NSPS inverter for a number of years, corrective actions to address the problem were not adequate.10 CFR 50, Appendix B, Criterion XVI, " Corrective Action,"

required, in part, that measures shall be established to assure that conditions adverse to quality, such as failures and malfunctions, are promptly identified and corrected. The failure to correct deficiencies associated with the division 2 NSPS inverter was an example where the requirements of 10 CFR 50, Appendix B, Criterion XVI were not met and was a violation. However, because this violation was based upon activities prior to the events leading to the current extended plant shutdown and satisfies the criteria in Section Vll.B.2," Violations identified During Extended Shutdowns or Work Stoppages,"

of the " General Statement of Policy and Procedures for NRC Enforcement Actions" (Enforcement Policy), NUREG-1600, a Notice of Violation is not being issued (NCV50-461/98004-05(DRS)). Conclusion The inspectors concluded that the licensee failed to correct deficiencies associated with the division 2 NSPS inverter despite repeated failure .

.

' M1.2 Potential Division 2 Emergency Diesel Generator Overload Event inspection Scone The inspectors reviewed test results and interviewed cognizant licensee' personnel regarding the potential overload of the division 2 EDG during surveillance testing on February 11,1998.- Observations and Findings As discussed in section 01.2, on February 11,1998 the midnight shift control room crew received direction to perform CPS 9080.01, " Diesel Generator 1 A(B) Operability -

Manual and Quick Start Operability" for the division 2 EDG. Subsequently, the EDG was started and loaded to 4050 KW as indicated on the control room KW mete However, about 50 minutes after fully loading the EDG, the SRM identified that the EDG

_

local control panel indicated that the division 2 EDG was loaded to 4500 K The inspectors reviewed the loading specifications associated with the EDG and identified the following ratings:

Time at Load Rating

. Continuous 3875 KW

. 2000 hours0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> 4126 KW

. 200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br /> 4185 KW  !

• 30 minutes 4342 KW The inspectors concluded that the local panel indication of 4500 KW Indicated that the EDG exceeded its 30-minute ratin The inspectors identified that to determine which of the two indications was accurate, the licensee performed calibrations on both the control room KW meter and the division 2 EDG local panel KW meter. The results of this testing indicated that both meters were within calibration. In addition, the licensee performed a visual Inspection of the division 2 EDG. No deficiencies were noted. At the end of the inspection, the licensee was formulating additional testing plans to determine whether the division 2 EDG was overloaded. This is an inspection followup item pending further NRC review (IFl 50-461/98004-06(DRS)). Conclusion The inspectors concluded that the division 2 EDG may have exceeded its maximum

' 30-minute load rating. This is an inspection followup item pending further NRC revie i l

!

!

.

.

V. Management Meetings X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on January 16,1998. The licensee acknowledged the findings presented and did not identify any proprietary informatio I

.

I

. . . . .. .. .. . . .

. .. . _. .

.

.

PARTIAL LIST OF PERSONS CONTACTED G. Hunger, Manager, CPS W. Romberg, Manager, Nuclear Station Engineering Department R. Phares, Manager, Nuclear Safety and Performance improvement G. Baker, Manager, Quality Assurance W. Maguire, Director, Operations W. Carsky, Director, Design Engineering J. Sipek, Director, Licensing M.- Tacelowski, Supervisor, Operations Services J. Domitrovich, System Engineering C. Phillips, Maintenance Planning G. Smith, Electrical Maintenance

'l INSPECTION PROCEDURES USED IP 93702 Prompt Onsite Response to Events at Operating Power Reactors ITEMS OPENED, CLOSED OR DISCUSSED Ooened 50-461/98004-01 NCV Failure to Rely on Local EDG Indication 50-461/98004-02 NCV Inadequate RHR Fill and Vent Procedure 50-461/98004-03 NCV Inadequate Crew Briefing 50-461/93004-04 NCV Failure to Evaluate Risk Prior to Maintenance i 50-461/98004-05 NCV Inadequate Corrective Actions for NSPS Inverter Failures i 50-461/98004-06 IFl Potential Division 2 Emergency Diesel Generator Overload j i

.

.-

LIST OF ACRONYMS USED

~

AC Alternating Current

-

CPS Clinton Power Station CR . Condition Report CRDH- Control Rod Drive Hydraulic .

CRO Control Room Operator DC- Direct Current DRS Division of Reactor Safety EA' Enforcement Action ECCS Emergency Core Cooling System EDG Emergency Diesel Generator IFl Inspection Followup item

'KVAR- Kilovoit-Amperes Reactive KW Kilowatt LASS Line Assistant Shift Supervisor NCV Non-Cited Violation NSPS Nuclear System Protection System PDR Public Document Room RCS Reactor Coolant System RH Residual Heat Removal PMT Post-Maintenance Test RPV Reactor Pressure Vessel RWCU Reactor Water Cleanup SRM Shift Resource Manager-TPD Temporary Procedure Deviation TS Technical Specifications V Volts Vac Volts Altemating Current Vdc Volts Direct Current VIO Violation

!

'

i' .<

J- -