IR 05000346/1998012

Insp Rept 50-346/98-12 on 980624-29.No Violations Noted. Major Areas Inspected:Review of Licensee Response & Recovery from Damage Caused by 980624 Tornado,Operations & Plant Support

ML20237D039
Person / Time
Site:	Davis Besse
Issue date:	08/14/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20237D037	List: IR 05000346/1998012 ML20237D036
References
50-346-98-12, NUDOCS 9808250003
Download: ML20237D039 (28)

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, U. S. NUCLEAR REGULATORY COMMISSION REGION lil Docket No: 50-346 License No: NPF-3

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Report No: 50-346/98012(DRP)

Licensee: Toledo Edison Company Facility: Davis-Besse Nuclear Power Station Location: 5501 N. State Route 2 Oak Harbor, OH 43449 -

Dates: June 24 - 29,1998 Inspectors: T. Kozak, Team Leader R. Gardner, Chief, Engineering Specialists Branch 2 D. Mc Neil, Reactor Engineer i M. Sielby, Reactor Engineer j S. Campbell, Senior Resident inspector K. Zellers, Resident inspector J. Lennartz, SRI, Palisades Nuclear Plant l J. Maynen, Rl, D.C. Cook Nuclear Plant B. Fuller, RI, D.C. Cook Nuclear Plant G. Harris, SRI, Fermi Nuclear Plant D. Butler, Reactor Engineer J. Neisler, Reactor Engineer S. Burgess, Senior Reactor Analyst Approved by: Thomas J. Kozak, Chief Reactor Projects Branch 4

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PDR ADOCK 05000346 4 G PDR a

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t EXECUTIVE SUMMARY Davis-Desse Nuclear Power Station  !

i NRC Team Inspection Report 50-346/98012(DRP)

This report covers the dates June 24 - 29,1998, during which a team inspection was conducted to review the licensee's response and recovery from damage caused by a tomado which struck the site on June 2 Operations -

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Although the National Weather Service issued a severe thunderstorm waming approximately I 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> prior to the tomado touchdown onsite, the station was not formally notified of the I I

approaching storm. The inspectors' prior experience has shown that nuclear stations located in NRC Region lil generally rely on load dispatchers for notification of severe storms but have rarely been formally notified of approaching severe storms. The inspectors concluded that an effective system for notifying stations of severe storms should allow for better preparation for possible l

storm consequences, such as a loss of offsite power (Section 01.1).

l l As the operators leamed of the severe storm in the area, they executed their responsibilities in a

professional, business-like manner. Their communication practices, annunciator response, l procedural compliance, and panel monitoring were good. The command and control during and -

l following the event was excellent. The operators' actions were effective in ensuring the plant

[ was in a safe condition. The crew's event response indicated they were well trained for such an event (Section 01.1).

All known equipment anomalies and storm damage which occurred were documented and entered into the licensee's corrective action program. The team concluded that the licensee performed a methodical, comprehensive review of the event and its consequences. Repair activities were professionally accomplished and at no time did it appear that workers were schedule-driven (Section O2.1). .

The resolution of technicalisse.es was generally performed in a thorough fashion. However, engineers did not obtain the necessary information from those involved when Circuit Breaker ABDC1 failed to close which led to an inaccurate resolution of the issue. This was L

identified in the licensee's management review of the startup issues and resolved prior to plant restart activities (Section 02.1).

The licensee's emergency response and outage organizations provided appropriate safety focus for the station personnel during the resolution of storm damage and equipment issues. The teamwork displayed by the organizations indicated that they had been well trained for such an event (Section O2.1).

l I The team concluded that operators generally effectively tracked and met Technical Specification l requirements throughout the event. One unresolved item conceming invoking 10 CFR 50.54x

was identified (Section 04.1).

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Plant Support The team concluded that the plant staff appropriately classified a tomado striking the facility as an Alert in accordance with the emergency plan. Due to the severe weather, which damaged communications lines and caused hazardous road conditions near the plant, several steps of the emergency plan were not completed within the expected time frame. However, the inspectors conc'uded that the delay did not impact the operators' ability to safely control the plant (Section P1,1).

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Report Details Summary of Plant Status At 7:46 p.m. eastem time on June 24,1998, with the plant operating at approximately 99 percent power, a severe thunderstorm waming was issued for Ottawa County, Ohio by the National Weather Service. This was upgraded to a tomado waming at 8:40 p.m. when a tomado was spotted approximately 11 miles northwest of Port Clinton, Ohio. At 8:41 p.m. a tomado was spotted onsite near the cooling tower. Lighting strikes and the tomado caused damage in the

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station's switchyard, a loss of all offsite power sources, and a subsequent reactor trip at

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8:47 p.m. An Alert was declared at 9:18 p.m. based on the licensee's Emergency Action Level (EAL) 8-B-2, tomado onsite. A 13-member special inspection team was dispatched to the site starting at approximately 11:30 p.m. on June 24. The plant remained in hot shutdown for the remainder of the inspection period, l. Operations 01 Conduct of Operations l

01.1 Operator Actions Prior to and Durina a Loss of Offsite Power

. Inspection Scope (71707)

The inspectors reviewed the licensee's actions subsequent to leaming of a severe storm approaching the plant and developed a detailed sequence of events which is included as Attachment 1 to this repor Observations and Findings Station security personnel have an Ottawa County Tone Alert Radio which the Ottawa j l County Sheriff's Dispatcher activates for various adverse weather conditions. The radio was not activated after the severe thunderstorm warning was issued on June 24,1998, by the National Weather Service. However, a security officer informed the Shift l Supervisor (SS) shortly before the tomado was spotted onsite that he noticed severe weather was approaching the station. After the notification and in accordance with station policy, the SS directed an auxiliary operator to close the turbine building roof vents so that rain would be prevented from entering the turbine buildin At approximately 8:36 p.m., a phone call waming of severe weather was received in the control room from an off-duty control room operator who lived a short distance from the station. At 8:40 p.m., switchyard Air Circuit Breaker (ACB) 34561 opened due to a lightning strike and switchyard ACB 34562 cycled open three times and eventually stayed open. The Control Room Senior Reactor Operator (SRO) ordered operators to start Component Cooling Water (CCW) Pump 1 and both Emergency Diesel Generators (EDG)

from the control room. Both the CCW Pump 1 and EDG 2 started, but EDG 1 failed to

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start. The SRO directed the operators to start EDG 1 locally which was successfully j completed shortly thereafter. The EDGs were not paralleled to the offsite power source but were set at idle speed. At 8:41 p.m., the control room operators were notified of a funnel cloud onsite near the cooling towe .

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I At approximately 8:47 p.m., security guards saw multiple funnel clouds above the strEon and retumed to the personnel process center for protection. One of the funnel clouds '

touched down either near to or in the switchyard which caused damage to switchyard equipment and a loss of offsite power (LOOP). The LOOP caused the main generator to disconnect from the grid which initiated a power / load unbalance runback of the turbin The unbalance caused an increase in reactor pressure and a reactor trip subsequently i occurred on high reactor coolant system pressure. All control rods inse 1ed into the cor ;

Both EDG 1 and EDG 2 automatically connected to and reenergized their respective '

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electrical buses. The SS ordered operators to manually initiate the Steam and Feedwater Line Rupture Control System (SFRCS). All SFRCS equipment performed as designed '

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including the actuation of the two turbine driven auxiliary feedwater (TDAFW) pumps to supply auxiliary feedwater to the steam generators for removal of reactor core heat. The ]

LOOP caused a loss of power to the reactor coolant pumps so forced reactor cooling was  ;

unavailable. Natural circulation of cooling water automatically occurred. The main steam safety valves (MSSV) lifted in response to increasing secondary system pressure and the atmospheric relief valves were opened by operators to control steam pressure. One MSSV lifted below its setpoint and did not fully reseat. The valve eventually reseated as header pressure was reduced. The operators' actions were effective in ensuring the plant was in a stable, safe conditio i The SS declared an Alert at 9:18 p.m. based on EAL 8-B-2, tomado onsite. At =

11:38 p.m. the control room received confirmation that the Technical Support - 1 Center (TSC) and Operations Support Center (OSC) were staffed. At 11:53 p.m., a plant ,

cooldown was commenced. Offsite notifications were hampered by the loss of a fiber- >

optic phone line to the station. Only tne microwave phone link was availabl The NRC Davis-Besse resident inspector (RI) was unable to establish contact with the j control room after the storm passed and reported to the station to assess the situatio Upon arrival in the control room, the RI briefed the Headquarters Operations Officer on the plant status and surrounding damage. The Senior Resident inspector (SRI) also reported to the station, monitored activities in the TSC, and updated NRC regional and *

a headquarters responders on the circumstances surrounding the event. At 10:01 p.m., the NRC Headquarters Emergency Operations Center (EOC) was activated in the standby mode of operation. The NRC Region til incident Response Center (IRC) was fully staffed

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and available at the time the EOC was activated. Staff in both the EOC and the IRC provided 24-hour monitoring of the event. Also starting at 11:30 p.m., an inspection team was dispatched to the site from the Region lli office. The NRC downgraded its emergency response status from the standby to the monitoring mode at 2:11 a.m. on June 25 based on the piant being in a stable condition and the licensee maintaining full control of plant operations. At 1:30 p.m. on June 26, the NRC exited the monitoring mode and retumed to normal operations. No radioactive material was released from the plant as a result of the even Communications between operators during and after the event were effective. Operators

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were noted to be thorough in their execution of procedures. The inspectors noted that multiple procedures were being executed concurrently without a decrease in safety focus by control room operators. Shift management personnel held lengthy j discussions conceming correct execution of procedures, compliance with Technical Specifications (TS), and the best sequence of events to maintain the plant in a safe ,

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Conclusions Although the National Weather Service issued a severe thunderstorm waming approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> prior to the tomado touchdown onsite, the station was not formally notified of the approaching storm. The inspectors' prior experience has shown that nuclear stations located in NRC Region lli generally rely on load dispatchers for notification of severe storms but have rarely been formally notified of approaching severe storms. The inspectors concluded that an effective system for notifying stations of severe storms should allow for better preparation for possible storm consequences, such as a loss of offsite powe As the operators leamed of the severe storm in the area, they executed their responsibilities in a professional, business-like manner. Their communication practices, annunciator response, procedural compliance, and panel monitoring were good. The command and control during and following the event was excellent. The operators'

actions were effective in ensuring the plant was in a safe condition. The crew's event response indicated they were well trained for such an even Operational Status of Facilities and Equipment O2.1 Eauloment Problems. Damaae Assessment. and Recoverv Actions

a. Inspection Scope (71707)

The team monitored the licensee's efforts to assess various equipment challenges and the damage which occurred during the storm. The team followed the guidance in NRC Inspection Manual Chapter (MC) 0350, " Staff Guidance for Restart Approval." The MC provides guidelines for approving restart of a nuclear power plant after, in part, an invo'untary shutdown as a result of damage from natural disasters such as a tomado and provides a list of tasks and issues from which a plant-specific restart plan was develope A restart panel was formed which included members from NRC Region lli and the Office ;

of Nuclear Reactor Regulation. A plant-specific restart list was also developed and forwarded to the licensee on June 27,1998. A review of recovery actions was conducted and a restart list describing how each issue was dispositioned is included as Attachment 2 to this repor b. Observations and Findinos Equipment Anomalies After the reactor trip, operators reviewed annunciators and indicators in the control room !

to assess plant conditions. The following equipment problems were deemed to be the most significant encountered and resolved during the LOOP and/or the recovery activities. Other issues and their resolution are included in the restart issues lis * As noted above, EDG 1 had to be started locally after it did not start from the control room. The licensee determined that remote EDG start switch, HS 11478, located in the main control room, had bad switch contacts. The switch contact block was replaced and the problem was resolved. Despite the bad switch

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l contacts, the diesel generator would have automatically started had an automatic start signal been generate .. After the LOOP, the licensee recognized that 120 Vac electrical distribution bus YAU was deenergized. This bus has an uninterruptable power supply. At 10:53 p.m., it was reported that the static transfer switch for YAU was not working. The SS directed auxiliary operators to place the static transfer switch for YAU in the BYPASS TEST position which reenergized YAU. The licensee determined that the static transfer switch had swapped to its altamate power supply during the event. The altemate power supply was not powered and the -

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switch did not retum to its normal power supply which had not lost power. The licensee determined a frequency circuit board in the associated inverter was overly sensitive to inverter output distortion and replaced i The failure of the static switch and resultant loss of YAU was thought to be the cause of condensate system resin being released to the hotwell. The resin subsequently caused high sulfates in the secondary system. In addition, the failure of the static switch was thought to have caused allinput to be lost to the plant process computer multiplexer. The multiplexer provides input into the Safety Parameter Display System which gives critical plant parameters such as reactor coolant pressure and temperature and gives a graphical display following a plant trip to ensure these parameters are within limits. Other means were available in -

the control room to monitor these parameter l

. Prior to the event, TDAFW Pump 1 was tagged out for minor maintenance. The j maintenance on TDAFW Pump 1 had been completed prior to the event and the l pump was placed in a ready condition for its quarterly surveillance test. Although I the pump operated when SFRCS was initiated, operators manually started the motor driven feed pump (MDFP) and transferred the feedwater supply to the MDFP in the auxiliary feedwater mode at approximately 9:20 p.m. TDAFW Pump 1 was fully functional at all times during the event and was declared '

i operable at 11:00 a.m. on June 2 . The control room emergency ventilation system (CREVS) Train 1 automatically swapped from the water-cooled mode to the air-cooled mode immediately after the manual start of the system. The CREVS is manually started in the water-cooled mode but will swap to the air-cooled mode if compressor discharge pressure rises to 160 psig as sensed at the compressor. The licensee had previously documented the inadvertent swap over issue in 1996 and determined that the discharge pressure increase occurred during startup due to high temperature service water supplied to the water cooled condenser. The service water initially delivered to the CREVS during very warm days has resulted in a l pressure increase above the air-cooled swap over point before the warm service water is finally flushed by the water from the service water header. The team reviewed the licensee's evaluation and determined that the CREVS operated propedy in the air-cooled mode and also when the system was reset to the water-cooled mode once operators determined, per procedure, that the water-cooled mode was operable. The system functioned per design and remained operable at all times during the even l l

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L * Included in the equipment lost due to the LOOP was the spent fuel pool (SFP)

. cooling system. The licensee monitored the temperature in the SFP as it l - increased due to the lack of cooling. The SFP temperature was 110*F at the time i of the event.' Contingency plans for cooling the SFP were developed in case the temperature rose above 150*F. The SFP cooling system was restored when l offsite power was regained. The maximum temperature measured in the SFP was 137'F. There were no problems with the water level while cooling was unavailabl .

. The maximum room temperature for the EDGs for operability is 120*F per the '

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operating procedure. Operators noted that the room temperature for both EDGs l increased with time as the EDGs were running. The EDG 1 room temperature ,

i eventually rose above the operability limit. The following sequence of events occurred conceming EDG room temperature:

June 25 8:17 The doors leading to the outside from both EDG rooms were

opened in an attempt to add cooler air to the room The temperature in EDG 1 room rose to 122*F, EDG 1 was

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10:25 declared inoperable, and TS 3.0.3 was entere :37 Operators determined that the EDG 1 room ventilation recirculation

! damper had failed open which limited the amount of outside air i available to cool the room. Two portable fans were hooked up and tumed o :03 The recirculation damper was mechanically disconnected and

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12:32 The room temperature decreased to 119'F, EDG 1 was declared operable, and TS 3.0.3 was exited.

l 1:13 The EDG 1 room temperature again increased to 122*F, EDG 1 was declared inoperable, and TS 3.0.3 was re-entered.

l 3:30 The doors leading to the EDG 1 room from the plant were blocked open and additional por1able fans were installe :40 The EDG 1 room temperature stabilized at 114*F. Although the l temperature had decreased below the operability limit, EDG 1 was not declared operable due to questions about the ventilation syste Although EDG 1 was technically inoperable, it remained functional and continued running throughout this sequence of events. The ventilation system was designed to maintain eac,h EDG room at 120*F assuming 95'F outside. air temperatur The air at the ventilation inlet was measured at 100*F. The vendor had previously indicated that temporary operation of the EDGs above 120'F would not result in

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the failure of the EDG or its components. The licensee determined that the ventilation was operating as designed with rated flow and declared EDG 1 operable at 3:40 a.m. on June 26. The licensee subsequently determined that the most limiting component in the EDG rooms was in the control circuit and the limiting temperature was 132* . The ventilation recirculation damper in the EDG 2 room also failed slightly open so the licensee mechanically disconnected it and put it in the fully closed positio The maximum recorded temperature in the EDG 2 room was 113* "

. At 11:04 p.m. on June 25, after offsite power was restored and while transferring Busses D1/D2 from EDG 2 to the A bus (supplied by offsite power), EDG 2 fault and EDG 2 frequency alarms were received. The frequency increased to 65 hz because EDG.2 control had shifted from the electronic govemor to the hydraulic govemor, The frequency was lowered to 60 hz, and the EDG was successfully shut down and declared inoperable. The licensee concluded that Relay R3 Contact 8/11 failed to open and caused the electronic govemor to fail. The licensee replaced and successfully tested a new R3 relay. In addition, the licensee tested the electronic govemor by verifying proper operation with the EDG paralleled to offsite power. The EDG was then declared operabl . At about 9:00 p.m. on June 25, while attempting to transfer Bus C1/C2 supply -

from EDG 1 to the B bus via Circuit Breaker ABDC1, the breaker failed to close.

': The transfer was accomplished via a dead bus transfer shortly thereafter. Initially the licensee believed that the breaker had failed to close due to a control switch to sync-switch alignment problem. Procedure steps were enhanced to clarify which panel to use to perform the breaker manipulations. During management review of the resolution, the licensee determined that the initial response was incorrec The operator that performed the breaker manipulations stated that closing of the breaker was performed locally rather than from the main control roo '

Troubleshooting activities were begun on June 29. The licensee identified a mechanical clearance problem between the tripping trigger cam and the trip plunger. The com was touching the trip plunger pin when there should have been some clearance. Procedure No. DB-ME-09104, "13.8KV and 4.16KV Westinghouse DHP Breakers," and DB-OP-01000 R01, "Oporation of Station Breakers," contained steps to verify that the tripping and closing cams were not l

touching their trip plunger pin. The clearance was specified as 0.010 inch in DB-ME-09104. Procedure DB-OP-01000 RO1 only required the operator to verify that the cam to pin had clearance. Where pin to cam contact was identified, the procedure required the operators to notify the control room to contact Electrical Maintenance. The licensee inspected other breakers that were in the open racked in position. One other breaker (HX02A) also had no cam to pin clearanc However, this breaker successfully operated during the event. The license indicated that Breaker ABDC1 would undergo a thorough inspection and evaluation to conclusively establish the root cause of the breaker failure. The licensee replaced Breaker ABDC1 with a spare. This breaker was successfully teste >

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• Prior to the event, Station Vent Monitor RE 4598AA was out-of-service for calibration and normal control room ven'ilation Train 2 was running. When the LOOP occurred, normal ventilation was lost and CREVS Trains 1 and 2 were manually started. At 11:40 p.m. on June 25, after one offsite power source was retumed to service, normal ventilation Train 2 was started. The CREVS system continued to operate. At 2:31 a.m. on June 26, Vent Monitor RE 4598BA alarmed high and normal ventilation Train 2 was automatically shut down. Vent j Monitor RE 4598BA was located near a hole in the turbine building roof, which l was caused by the tomado, and became wet from rain water which entered the -

turbine building through the hole. Tine alarm spiked many times over the next

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several hours and at 12:40 p.m. was declared inoperable. With both RE 4598BA i and 4090AA inoperable, TS 3.0.3 was entered. After troubleshooting, engineering personnel determined that the monitor would function as designed and was .

spiking in a conservative direction due to the wet conditions. After drying efforts were initiated, no additional spikes were observed. The monitor was declared operable at 3:00 p.m. and TS 3.0.3 was exite Etc.m Damage Onsite storm damage mainly occurred in the switchyard and to the turbine building roo Temporary repairs were made to the turbine building roof hole, which was approximately 8 by 20 feet. However, water from the heavy rains entered the turbine building and r effected some nonsafety-related cable trays and a motor control center. This did not effect any equipment important to safety. ' As mentioned in Section O2.1, the water did effect a station vent radiation monitor. These problems were eliminated after the roof was repaired and the vent monitor was dried ou The switchyard uses five 345kV air-blast circuit breakers. The breaker arrangement consists of three breaker bays between the east (J) and west (K) switchyard bu Breaker connections are used to form a ring bus. Three offsite transmission lines enter the switchyard and three tie lines connect to the plant. The offsite transmission lines go ,

to Bayshore and LeMoyne substations and the third line connects to the Ohio Edison Company system. One plant tie line was connected to each startup transformer and the third line connected to the main transformer. All three offsite transmission lines were damaged during the storm with the Bayshore line being most effected as 11 towers were either damaged or dow In the switchyard, the tomado caused damage to 10 tap connections in the form of i

broken connections to the motor-operated disconnects for the LeMoyne, Bayshore, and {

Ohio Edison lines as well as the motor-operated disconnects to the main and both startup i transformers. The plant relied upon the EDGs until sufficient repairs were made to j enable re-energization of a startup transforme High wind velocities stressed the whip lines from the 3d5kV lines down to the top of the porcelain towers which support the contact points fo; th s motor-operated disconnect {

. wiper contacts. The cast aluminum jaw to which the vtaip lines bolt are the first rigid point 1 I

that the high voltage lines contact and must dampen any reverberations that wind might induce onto the high voltage lines. All 10 tap connection failures were at this poin e

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All 36-phase taps that were susceptible to wind damage were inspected; there were no signs of cracks in the other 26-tap connections. To restore the switchyard, all 10 of the broken phase connections were repaired by disassembling each connection and tungston inert gas welding the broken aluminum castings and reassemblin All six motor-operated disconnects were cycled to ensure adequate contact engagement and smooth operation of the disconnect. All five circuit breakers were cycled closed and ;

back open to verify proper operation. After the yard had been re-energized, the licensee performed a thermography survey to identify any hot connections that were due to loose i connections. No problem connections were identified, v ,

The offsite transmission lines were repaired by company transmission and distribution personnel. The Ohio Edison line was reenergized at 7:26 p.m. on June 25. The LeMoyne line was reenergized at 11:30 a.m. on June 26. The Bayshore line was not retumed to service by the end of the inspection perio Development of Restart issues List The licensee assessed the equipment problems and damage experienced during and subsequent to the event and captured the issues on a list entitled " Problems Encountered During the C/24/98 Reactor Trip." The items were prioritized into the following categories:

plant stability, restart issue, issues needing more information, and non-issues. The team *

performed an independent review of the storm damage and equipment problems and compared its issues with the licensee's. From this review, the team determined that 19 items needed to be resolved prior to plant restart. All of the issues had been, captured

. by the licensee; however, the team concluded that some of the items that were prioritized at a lower level should have been prioritized as restart items by the licensee based on the information that was available to the team at the time. The team gained agreement with licensee management representatives on the items, the restart list was approved by the NRC restart panel, and the list was forwarded to the license *

The licensee's emergency response organization (ERO) was in effect until the retum of the second offsite power line. After this, the ERO transitioned into an outage organization. These organizations prioritized and tracked the resolution of the item Routine briefings of the organizations were conducted by the Emergency / Outage Directo Plant safety and effective resolution of the items was emphasized at each briefin Although plant restart was the ultimate goal for the licensee, at no time did this become an overriding factor in the resolution of the items. Each item on the restart list was adequately resolved and the team informed the licensee that no outstanding issues remained as of 12:00 p.m. on June 29. The licensee commenced plant restart activities later that day.

! Conclusions All known equipment anomalies and storm damage that occurred were documented and

entered into the licensee's corrective action program. The team concluded that the  ;

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licensee performed a methodical, comprehensive review of the event and its consequences. Repair activities were professionally accomplished and at no time did it appear that workers were schedule-drive . 1

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$ I The resolution of technicalissues was generally performed in a thorough fashio l However, engineers did not obtain the necessary information from those involved when 1 Circuit Breaker ABDC1 failed to close which led to an inaccurate resolution of the issu This was identified in the licensee's management review of the restart issues and l resolved prior to plant restart activitie '

l l The licensee's emergency response and outage organizations provided appropriate l safety focus for the station personnel on effective resolution of storm damage and l equipment issues. The teamwork displayed by the organizations indicated that they had been well trained for such an event.

l 04 Operator Knowledge and Performance 04.1 Technical Specification Entry. Exit. and Comoliance l

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l Insoection Scope (71707)

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The team observed activities in the control room and the TSC throughout the course of

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the event and evaluated operators' performance relative to entering, exiting, and meeting TS requirement ' Observations and Findinas Technical Specifications Entered and Exited During the event, control room operators entered and exited multiple TS conditions as documented below:

. TS 3.0.3 (EDG 1 room temperature reached 122'F {EDG 1, all off-site power supplies INOPERABLE} and RE 4598AA and BA inoperable)

. TS 3.9.12 (storage pool ventilation required suspension of fuel handling operations until ventilation was restored).

. TS 3.8.1.1, Action D (required restoration of at least one offsite power, source within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or place the plant in Hot Standby in the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />)

. TS 3.6.5.2 (restore shield building integrity within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />)

. TS 3.7.1.3 (Iow Condensate Storage Tank level)

Licensed operator tracking of TS issues was considered good. Even though multiple TSs were entered (some were entered, exited and re-entered), control room operators were j always awara of which TSs were in force and, in all but one case, made decisions to 1 comply with the conditions imposed by the TS TS 3.0.3 Not Met,10 CFR 50.54x Invoked l At 9:53 p.m. on June 24, the SS directed operators to commence a plant cooldown.

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circulation cooldown was conducted. The maximum cooldown rate for a natural circulation cooldown allowed by the licensee's procedures was 10*F/hr. Technical Specification 3.0.3 was entered at 1:13 p.m. on June 25 due to EDG 1 being inoperable and having no offsite power sources operable. Although a procedure change was considered to allow up to a 50*F/hr cooldown so that the TS requirement of cooling down to below 280*F within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> could be met, this change was not completed. The licensee's concem was that cooling down below 350*F would reduce the steam available to drive the TDAFW pumps should they be needed in case the MDFP became unavailable. The requirements of TS 3.0.3 were not met and operators invoked 10 CFR 50.54x (not able to comply with station TS, an emergency exists, and immediate '

" J action is required to protect the health and safety of the public) to stop the plant cooldown '

at approximately 350*F. The team was unable to evaluate all available information to determine if the decision to invoke 10 CFR 50.54x was correct. Therefore, this issue will be reviewed during a future inspection and is designated as an unresolved item I I

(URl 50-346/98012-01). Conclusions l The team concluded that operators generally effectively tracked and met TS requirements throughout the event. One unresolved item conceming invoking 10 CFR 50.54x was identifie ~

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IV. Plant Support l l

P1 Conduct of EP Activities  ;

i P Emeroency Plan Imolementatio_0 a .' Inspection Scope (71750)

The inspectors reviewed the licensee's implementation of the Emergency Pla Observations and Findinas

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On June 24,1998, at 9:18 p.m., after a LOOP occurred and tomado damage was j reported, the Shift Supervisor declared an Alert in accordance with the Emergency Pia Due to the severe weather, the primary offsite notification system (the Davis-Besse 4-way ringdown) and the NRC emergency notification system were damaged. Using backup commercial lines, the licensee notified Ottawa County and the NRC of the emergency at 9:24 p.m. and 9:36 p.m., respectively. The required notifications to Lucas County and the State of Ohio were attempted, but not completed within 15 minutes, due to phone line l damage in the area. The emergency notifications were completed by Ottawa County for i

the license In accordance with the Emergency Plan, the licensee activated the TSC, the Emergency Control Center (ECC), and the OSC. On June 24,1998, at 11:38 p.m., the TSC and OSC were manned. The Emergency Plan required that these facilities be activated within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of the event declaration. The inspectors interviewed several members of the licensee's emergency response organization (ERO). They explained that hazardous road

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l conditions near the plant impeded the timely arrival of some members of the ERO The inspectors observed control room operations and interviewed several operators and determined that the delay in activating the TSC and OSC did not impair the licensee from l taking actions necessary to stabilize the plant.

l l On June 26,1998, at 2:00 a.m., the Alert was downgraded to an Unusual Event. The downgrade was based on the restoration of offsite power to the plant through one of the

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three offsite power lines. On June 26,1998, at 1:58 p.m., the emergency situation was terminated based on the restoration of a second source of offsite power. Following the l termination of the event, the TSC, ECC, and OSC were deactivated, and an outage '

l organization was established.

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The inspectors reviewed the use of the Emergency Plan and determined that the initial event was appropriately classified as an Alert in accordance with Section 8.B.2 of the Emergency Plan. The inspectors also concluded that the subsequent downgrade and event termination decisions followed the guidance in the Emergency Pla Conclusions i The team concluded that the plant staff appropriately classified a tomado striking the facility as an Alert in accordance with the emergency plan. Due to the severe weather which damaged communications lines and caused hazardous road conditions near the e plant, several steps of the emergency plan were not completed within the expected time l frame. However, the inspectors concluded that the delay did not impact the operators'

l ability to safely control the plant.

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l V. Manaaement Meetinas X1 Exit Meeting Summary l

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The inspectors presented the inspection results to members of licensee management at the

! conclusion of the inspection on June 29,1998. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

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PARTIAL LIST OF PERSONS CONTACTED Licensee

"J. H. Lash, Plant Manager R. E. Donnellon, Director, Engineering Services

, D. L. Esholman, Manager, Plant Operations l

J. L. Freels, Manager, Regulatoy Affairs J. L. Michaelis, Manager, Maintenance

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C. A. Price, Manager, Business Services '

. W. J. Molpus, Manager, Nuclear Training H. W. Stevens, Manager, Nuclear Safety and inspections F. L. Swanger, Manager, Design Basis Engineering G W. Gillespie, Superintendent, Chemistry i R. A. Greenwood, Supervisor, Radiation Protection S. W. Roberts, Shift Supervisor, Plant Operations R. C. Hovland, Senior Engineer, Plant Engineering

, J. M. Vetter, Nuclear Auditor, Quality Assurance

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G. M. Wolf, Senior Engineer, Regulatory Affairs l

A. Conway, Student, Regulatory Affairs E  !

L l M. Depas, Deputy Director, Division of Reactor Projects, Rlli L C. Carpenter, Directorate ill-1-Director, NRR L J. Hopkins, Project Manager, NRR A. Hansen, Project Manager, NRR L

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INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 61726: Surveillance Observations IP 62707: Maintenance Observation IP 71707: Plant Operations IP 71750: Plant Support Activities IP 90712: In-Office Review of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92700: Onsite Follow-up of Written Reports of Nonroutine Events at Power Reactor

Facilities IP 92901: Followup - Plant Operations IP 92902: Followup - Maintenance IP 92900: Followup - Engineering IP 93702: Prompt Onsite Response to Events at Operating Power Reactors

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ITEMS OPENED, CLOSED, AND DISCUSSED Opened URI 50-346/98012-01 Appropriateness of invoking 10 CFR 50.54 *

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LIST OF ACRONYMS AND INITIALISMS USED ACB Air Circuit Breaker CCW Component Cooling Water CREVS Control Room Emergency Ventilation System CFR Code of Federal Regulations ECC Emergency Control Center ]

EDG Emergency Diesel Generator j EAL Emergency Action Level j EOC Emergency Operations Center '

ERO Emergency Response Organization '

ESF Engineered Safety Feature l&C Instrumentation and Controls IFl inspection Followup item IR inspection Report IRC Incident Response Center LOOP Loss of Offsite Power MC Manual Chapter MDFP Motor Driven Feed Pump MSSV Main Steam Safety Valve '

MWO Maintenance Work Order NCV Non-Cited Violation  !

NRC Nuclear Regulatory Commission OSC Operations Support Center PCAQR Potential Condition Adverse to Quality Report PDR Public Document Room RI Resident inspector SFP Spent Fuel Pool SFRCS Steam and Feedwater Line Rupture Control System SRI Senior Resident inspector SRO Senior Reactor Operator 4 SS Shift Supervisor TDAFW Turbine Driven Auxiliary Feedwater Pump TSC Technical Support Center TS Technical Specification URI Unresolved item USAR Updated Safety Analysis Report i i

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Attachment 1 Sequence of Events On June 24,1998, a tomado struck the Davis-Besse Nuclear Power Station causing damage in the station's switchyard. The initial damage assessment in the switchyard indicated Circuit Breaker ACB 34620 had one broken connector, ACB 34621 had 2 broken connectors, and ACB 34622 had 1 broken connector. There was some visible damage to ACBs 34623,34624 and 34625. This combination of broken connectors and dama0ed circuit breakers, in addition to the damage to the offsite transmission lines, resulted in a loss of all off-site power supplies to the station. The following is a sequence of significant events: *

~2036 A phone call from a control room operator living a short distance from the station was received in the control room waming of severe weather. Station security forces informed the Shift Supervisor (SS) that severe weather was moving toward the plan The SS and one auxiliary operator went to the turbine building roof to shut the roof vent Prior to reaching the roof, the SS was called to the control roo ACB 34561 opened due to a lightening strike (connects station to Bayshore). Air Circuit Breaker 34562 cycled several times, stayed open (connects station to K { West) bus). -

The main generator was still connected to the J (East} bu The Control Room Senior Reactor Operator (SRO) ordered operators to start Component Cooling Water (CCW) Pump 1 and both Emergency Diesel Generators (EDGs). EDG 2 started, EDG 1 failed to start from the control room signal. EDG 1 was successfully started from its local panel. The SS arrived in the control room immediately after CCW Pump 1 starte Departing security guards saw multiple funnel clouds above the station and retumed to the personnel process center for protection. A tomado touched dawn in or near to the switchyard causing a loss of off-site electrical power supplie The SS observed the LeMoyne switchyard breaker trip. This caused a totalloss of off-site power which resulted in a reactor trip. Control room operators executed post-trip action The SS ordered operators to manually initiate Steam and Feedwater Line Rupture Control System (SFRCS). All SFRCS equipment performed correctl The static transfer switch associated with 120 vac electrical distribution bus YAU failed resulting in a loss of power tr, bus YA Technical Specification ( rS) 3.9.12 (storage pool ventilation) was entered (suspend fuel handling operations until ventilation is restored).

2048 The plant process computer provided multiple indication of a loss of off-site electrical power and a reactor scram. (Loss of all condensate pumps, low EHC pressure, C1 & D1

bus loads transferred to EDG 1, EDG 2, multiple reactor protection initiation signals).

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l 2058 : The Control room received a report of a large hole in the turbine building roof and that '

several roof vents were ripped of Contro! room operators restored power to Bus D2 from EDG 2 and started the emergency instrument air compresso The Station Emergency Director declared an ALERT. (EAL 8-B-2; Tomado on site)

2120 Control room operators transferred the Motor C4iven Feed Pump (MDFP) to the Auxiliary Feed Water (AFW) mode. (AFW Pump 1 was tagged out for a mini-outage to replace

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lube oil and lubricate the pump.)

2202 Cooling water flow to the control room emergency ventilation system (CREVS) could not be maintained. CREVS 1 was placed in the air cooled mode, q 2216 The cooling water isolation valve to the CREVS was manually opened, CREVS 1 was shifted to water cooled mod l 2218 The Main Steam Line (MSL) #1 MSSV reseated. The valve was slightly leaking after a l lif The SS entered TS 3.8.1.1, Action D. The TS required restoration of at least one offsite -

l power source within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or place the plant in Hot Standby in the next 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> The control room received a report that the static transfer switch for YAU was not working. The SS directed operators to place the static transfer switch for YAU in BYPASS TEST. This resulted in electrical power to YA The control room received confirmation that the Technical Support Center (TSC) and

- Operations Support Center (OSC) were manne The SS directed operators to commence a plant cooldown. The maximum allowed cooldown rate by procedure was 10*F/h Reactor Coolant System (RCS) temperature was 540' Operators acknowledged RCP diagnostic alarms for all four reactor coolant pumps (RCPs). Diagnostic alarms were for high vibration. Engineers believed the alarms were from having all four pumps coasting down concurrently with the loss of off-site powe Operators restored power to Bus C2 from EDG 1.

l l 0800 RCS temperature was 487'F. RCS pressure was less than the minimum pressure required by Curve 3 of Figure CC1.14 for Natural Circulation Cooldown. Pressurizer heaters were energized to increase reactor pressur l 0900 Control room operators entered and began executing the steps of DB-OP-02355, "CTRM EVS Emergency Load Shed Abnormal Procedure." The backup plant computer was shut ;

down to comply with the procedur ;

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0906 Door 204 was propped open to provide' additional cooling to the makeup pump roo Door 204 is a fire, high energy line break, flood, and shield building door. Technical Specification 3.6.5.2 for shield building integrity was entered. (Restore shield building integrity within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.) An hourly fire watch was established in the makeup pump roo EDG 1 room temperature reached 122*F, entered T.S. 3. EDG 2 room temperature reached 102* *

1037 A local operator reports the EDG 1 room recirculation damper appeared to be failed open causing the high room temperature. The OSC was directed to correct the conditio Door 219 was blocked open to pump the west end of the service water tunnel. A continuous fire watch was established at Door 21 The control room was notified by the load dispatcher that the off-site ends of the Ohio Edison, LeMoyne, and Bayshore lines were isolate The control room was informed that the recirculation damper in the EDG 1 room was shut, ventilation was no longer in a recirculation mod EDG 1 room temperature was 119'F. Operators exit TS 3.0.3 for the inoperable EDG . EDG 1 room temperature was 122*F. Technical Specification 3.0.3 entere RCS temperature was 437'F. RCS cooldown rate was 2*F/h . Door 219 was closed and the fire watch secure EDG 2 ventilation recirculation damper was fully closed to provide maximum cooling for ,

EDG 2 roo gallons of fuel oil was added to EDG 2 Week Tan The Ohio Edison line from offsite was reenergize Operators were not able to meet the requirements of T.S. 3.0.3 (be in Hot Shutdown within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> from the time EDG 1 was declared inoperable). Operators invoked 10 CFR 50.54x (not able to comply with station technical specification, emergency exists, and immediate action is required to protect the health and safety of the public). I 2030 During the next hour control room operators energized Busses E2, E3, E4, E6, F2, F3, F4, and F Control room operators transferred Bus C1 to C2 and unloaded EDG 1. EDG 1 was L shutdown. Circuit Breaker ABDC1 failed to close upon demand.

l Cooling was restored to the SFP when SFP 2 was starte !

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2240 Control room operators restored E2/F2 MCCs, started #1,2,4, and 5 turbine building roof fans, and #1 spent fuel pool cooling pum EDG 2 FAULT and EDG 2 FREQUENCY alarms were received while shutting down EDG 2. EDG 2 control shifted to the mechanical govemor and successfully shutdow The Ohio Edison line was declared OPERABLE. (EDG 1 was INOPERABLE but functional.)

0000 RCS temperature was 371*F, RCS cooldown rate was 10*F/h [

0145 Control room operators started 2-2 and 2-1 Reactor Coolant Pumps (RCPs).

0200 The control room received confirmation that the event classification was downgraded to a Notification of Unusual Event, EAL Control Room EVS Load Shed Abnormal Procedure was exite t 0228 Auxiliary Feedwater Pump 2 was shut dow Auxiliary Feedwater Pump 1 was shut dow .

0611 Control room operators closed ACB 34563. Start Up Transformer 01 was energized from the LeMoyne Lin RCS temperature was 359*, RCS cooldown rate was 0* l 1130 The SS declared a second off-site AC source operabl j i

1300 The control room received documentation that wind direction and wind speeds are not available from the Met towe ,

1330 Entered TS 3.7.1.3 for low Condensate Storage Tank leve The control room received confirmation that the Emergency Director had exited from the Unusual Event.

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AttichmInt 2 RESTART ISSUES UST The Restart issues List for Devis-Besse Nuclear Power Station specifies the items that the NRC considered as necessary to be addressed prior to plant restart. These items were derived from the NRC's review of inspection activitie i i

ISSUE DISPOSITION STATUS j 1 Switchyard Breakers The inspectors reviewed Updated Safety Analysis Closed Report (UFSAR) Section 8.2, *Offsite Power System," '

345kV Breaker 34562 System Desenption No. SD-0088,' System Description opened and closed many for the 345kV System," and discussed the design times startmg at about 2040 aspects of the switsyard protection scheme with the on 6/2 engmeermg staff. The licensee concluded and the f '

inspectors verified that the cycling of Breaker No. 34562 during the storm was according to desig Rlli inspectors agree this item was recolve #1 Emer.gency Diesel The inspectors reviewed Potential Condition Adverse Closed Generator (EDG) Manual to Quality Report (PCAQR) No. 98-1291, MWO J Start from the Control Room No.1-96-0686, and appropriate electrical schematic The licensee concluded that the contacts for the switch The #1 EDG did not start were defective resultmg in intermittent failure to from the control room at property close. Corrective schons ireciuded 2044 on 6/25. The #1 EDG replacement of the switch contact block and did respond to a local subsequent testng of the repaired switch. Rl'l 1 manual start at 2046 on inspectors agree this item was resolve l 6/2 J 3 Control Room Emergency The control room emergency ventilation system Closed Ventiation System (CREVS) (CREVS) Train 1 automatically swapped from the water-cooled mode to the air-cooled mode

At 2202 on 6/25, Service immediately after te manual start of the system (this Water (SW) 2627 would not shuts valve SW2927). The inspectors reviewed the stay open while starting #1 licensee's evaluation and determined that the CREVS CREVS, therefore #1 re".,ponded to a valid signs! to switch to the air-cooled CREVS was placed in the mode. The system functioned per design and air-cooled mode. At 2216, remained operable at al times during the even on 6/25, SW 2927 was opened and #1 CREVS was The inspectors concluded that the CREVS automatic placed in the water-cooled swap over from the water-cooled to the air-cooled mod mode was appropriate based on the increased service l

water temperature sensed at the CREVS compresso Operators property assessed the condition and retumed the system to the water cooled modo per l

! procedure. At no time was the CREVS unable to perform its safety functions and both the air- and water-cooled condensers were available. Rlll inspectors agree this item was resolve ,

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ISSUE DISPOSITION STATUS 4 Control Rod Group 7 The position indication signal to the Integrated Control Closed Position Indication System (ICS) Data Acquisition and Analysis System (DAAS) comes from C4801T (C,RD Patch Panet) on Group 7 position to Cable ALCRD270. This is a Rod Position Indication Integrated Control System (RPI) signal which is expected to stay at the rod stayed at 89% after the position just prior to the trip as the RPI signal changes reactor tri only with the rotation of the Control Rod Drive Mechanisms (CRDMs). Prior to latching rods per DB-OP-06402,'CRD System Operating Procedure,'

control room operators will reset RPI to ensure RPI ,

and Absolute Position Indication (API) read within 2 percent. The ICS DAAS point for Group 7 will be checked to verify it resets to O percent. The equipment responded correctly. Ritt inspectors agree this item was resolve #2 Atmospheric Vent Valve The licensee concluded that the I/P converter failed Closed (AVV)(ICS 11 A) resulting in the #2 AAV remaining in the 10-14 percent open position with 0 percent demand. The inspectors When placed in AUTO, #2 concluded that the replacement of the 1/P converter AW went to 10-14 percent would restore full pressure relief capability of the #2 open wnh demand AW prior to startup. The 1/P converter has been 0 percent. In AUTO the replaced. The licensee intends to bench test the valve stayed at associated card to determine the root cause of failure -

10-14 percent regardless of and stated that corrective actions to restore the failed deman card to operational readiness will be performed, including a review for potential generic implication R!ll inspectors agree this item was resolved.

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6 Pressurizer Quench Tank The licensee's engineering staff has determined that Closed l Level the water was transferred by gravity drain to the #2 Clean Water Receiving Tank (CWRT). When power Indicates loss of was lost to bus YAU, Quench Tank Drain Valve ,

approximately 3500 gallons. RC225A, failed open (per design). This established a No sign of water in Reacter flowpath to the Reactor Coolant Drain Tank (RCDT).

Coolant Drain Tank or The cover gas pressure was suffeient to push water *

Containment Sum from the RCDT to the #2 CWRT. An increase in #2 CWRT level occurred at the same time the decrease in quench tank level occurred. Levelin the quench tank will be restored to normal level prior to reactor startu The quench tank level instmmentation was functioning j property. Rill inspectors agree this item was resolved.

Hard Grounds on both DC The design of the DC distribution system includes a

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7 Closed Motor Control Centers resistance of 100,000 ohm to ground. In the event of a (MCC) ground on a DC motor control center, the maximum possible ground current would be limited to High resistance grounds on 2.5 milliampere. The licensee determined that a both DC MCC ground current of this magnitude would have no safety significance. In addition, the original hard grounds I were no longer present (on one MCC no grounds were present, while a high resistance ground remained on j the other MCC). The licensee stated that a l Mainte sance Work Order was initiated to troubleshoot i the remaining ground. Rillinspectors agree t'1is item (

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r-l ISSUE DISPOSITION STATUS 8 Emergency Notification The licensee identrfied that 22 of 54 emergency sirens Closed System Vulnerabilities did not respond to a communications status check after the 6/24/98 tomado. As of 1600 on 6/28/98, the Loss of power to sirens, loss licensee has restored 49 of 54 (90.7 percent),

of federal phone system, Davis-Besse Emergency Notification System sirens. In loss of nng-down phone addition, adequate phone communication capability has been restored. Rlli inspectors agree this item was resolve Water Intrusion into Turbine The inspectors concluded water intrusion into the Closed ,

Building Cable Trays turbine building cable trays was caused by rainfall entering the turbine building through the storm induced Occurred Friday moming hole in the roof. The licensee determined that no through hole tom in turbine safety-related cables were routed in the affected tray building roof by tomado The inspectors independently verified that the cables were not safety 4 elated. In addition, the licensee uses the same type of cables in safety-related application Water impinging on the cable jackets of these cables would have no significant effects on cable functionalit Rill inspectors agree this item was resolve _

10 Switchyard Hardware The inspectors concluded that switchyard damage was Closed Problems adequately assessed and repaired. The inspectors independently inspected the switchyard and .

The storm caused damage determined that the licensee had characterized the to a number of component damage accurately. The inspectors also observed What was damaged, how repair activities and transformer testing. The was it repaired, what other inspectors determined that the resolution of the inspections were performed switchyard damage was adequate to support and what testing should be operations with only the Ohio Edison and LeMoyne done in order to have a high lines energized until the Bayshore line is restored (refer confidence in the material to item No.14). Rlliinspectors aDree this item was condrtion of the yard? resolve Fire Detection System The inspectors concluded that batteries for the Closed Sensitivity to Loss of Power essential area Fire Detection System Panels were not adversely affected by the 2-hour 8-minute power los Operability of fire detection Other non-essential area fire detection panels were panels afterloss of off-site without power for longer periods and may need to have power, battenes changed; however, the inspectors determined that appropriate compensatory measures had been taken until battery replacement could be performe This is not an issue that would preclude restart of the plant. Rlliinspectors agree this item was resolve !

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188UE DISPOSITION 8TATUS 12 Circuit Breaker ABDC1 initially the licences believed that breaker No. ABDC1 Closed Failure to Close had failed to close due to a control switch to sync-switch alignment problem. Procedure steps were ABDC1 did not close while enhanced to clarify which panel to perform the breaker attempting to parallelthe manipulabons Subsequently, the licensee determined diesel with off-site power. that the initial PCAQR response was incorrect. The operator that performed the breaker manipulations stated that closing of the ABDC1 breaker was q performed locally rather than PCAQR identded closure -

from the main control roo ,

Trouble shooting activities were begun on June 29, 1998. The licensee identified a mechanical clearance problem between the tripping trigger com and the trip plunger. The com was touching the trip plunger pin when there should have been some clearanc Procedure No. DB-ME-09104,"13.8KV and 4.16KV Westinghouse DHP Breakers," and DB-OP-01000 R01," Operation of Station Breakers," contained steps i to verify that the tnpping and closing cams were not 1 touching their trip plunger pin. The clearance was specified as 0.010 inch in the ME procedure. The OP procedure only required the operator to verify that the com to pin had clearance. Where pin to com contact -

was identified, the procedure required the operators to notify the Control Room to contact Electrical Maintenanc The licensee inspected other breakers that were in the open racked in position. One other breaker (HX02A)

also had no cam to pin clearance. However, this breaker had been successfuny operated during the event. The license indicated that Breaker No. ABDC1 wil undergo a thorough inspection and evaluation to conclusively establish the root cause of the breaker

failur The licensee replaced Breaker No. ABDC1 with a spare. This breaker was successfully tested. Rill inspectors agree that this item was resolve However, additional root cause evolubon should be performed to determine if the postulated root cause is accurat #2 EDG Electronic Govemor The inspectors concluded that Relay R3 Contact 8/11 Closed Failed during EDG failed to open and caused the electronic govemor to Shutdown fail. The licensee replaced and successfully tested a new R3 relay, in addition, the licensee tested the 120V fuses checked,4160V electronic govemor by verifying proper operation with fuses need EDG tagged out the EDG parabeled to offsite power. Rillinspectors for check agree this item was resolve l l

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P ISSUE DISPOSITION STATUS 14 Switchyard Operabon The inspectors noted that the wording in Licensee Closed Event Report (LER) 96-08 implied that only the With the Bayshore line out of LeMoyne and Bayshore lines were qualiRed off site service, switchyard cercuits Also, the inspectors noted that the LER procedure (DB-OP-06311) indicated that opening Breaker 34564, to isolate the states that the plant will LeMoyne and Ohio Edison lines during the time that

[ remain in TS 3.8.1.1 even the Bayshore line was out-of-service, dispatched the l with the LeMoyne and Ohio plant's output on only one transmesion line which may

[ Edison lines in servic not be desirable due to the off44to 345 KV retribution system. The inspectors noted that no safety review ,

had been performed to evaluate this potentially i l

undesirable alignmen The licenses subsequently generated a safety review I which appropriately addressed this issue. The safety

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review indicated that with Breaker 34564 open, the l LeMoyne and the Bayshore transmission lines would l

l not be simultaneously lost due to a single breaker failure and were considered independent circuits. Also, i the lines were considered "quahfied" and satisfied

[ Technical Specsficabon requirements in that they were l each associated with: (1) an operable 345kV l transmesson line; (2) en operable 345KV to 13.8KV l transformer; (3) en operable 13.8KV bus: and (4) an -

! operable 13.8KV to 4.16KV bus tie transformer. The safety review further stated that the USAR does not preclude taking any one of the three transmission lines out-of-service, one at a time. The Ohio Edison line, f while not considered a preferred off-site line, was not

[ inferior in design to the Bayshore or LeMoyne line The added stability for the Bayshore and LeMoyne

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transmission lines was due to the fact that they could be isolated from a fault on the "K" bus by an air circuit l- breaker, whereas the Ohio Edison line was connected 1

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to the "K" bus by an air break switch. The air break

switch was not part of the switchyard circuit breaker protechon schem The inspectors concluded that Standing Order 96-04, Revision 1, and that Temporary Approval 98-1741 completed for DB-OP-06311, clan 6ed and appropriatelyimplemented Technical Specshcotion 3.8.1.1 requirements. The inspectors also concluded that the 10 CFR 50.59 safety review l portainng to the switchyard alignment with the f- Bayshore transmission line out-of-service was

< adequate. The inspectors conclusions were based on

a review of procedure DB-OP-06311, Revisions 0t, l TA96-1741, Technical Specifications, LER 96-08,

! PCAQRs 96-1448 and 98-1293, Standng Order 96-004, Revision 1, and the USAR. Rlll inspectors agree this item was resolve _ _ _ _ - _ _ _ _ _ - _ _ _ _ _ - _ _ - -

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ISSUE DISPOSITION STATUS 15 #2 EDG Output Breaker The inspectors concluded that the reverse power trip Cicsed was caused by a failure of the R3 relay prior to the j Reverse power trip, lockout operator opening the diesel output breaker. The failure j relays. * of the R3 relay prevented the reverse power trip j function from being bypassed as designed when the plant experienced a loss-of-offsite power. The initiation .

of a reverse power condition was determined to be due to the EDG being operated in the isochronous mod In this mode, small variations in diesel output power at I low generator loads result in a reverse power conditio ,

in this instance, the fact that the R3 relay had failed resulted in the #2 EDG output breaker tri The licensee replaced and successfully tested a new R3 relay. In addition, the licensee tested the ehtronic govemor by venfying proper operation with the EDG ^

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paralleled to offsite power. Rillinspectors agree this item was resolve Control Rod 4-6 Absolute The operating crew identfied that an asymmetric alarm Closed Position Indication (API) was in for Rod 4-6. Control rod absolute position Periodic Asymmetric Alarms indication (API) asymmetric fault alarm enerDizes when an individual control rod position is nine inches misaligned from the applicable control rod group's -

average position. The inspectors noted that the alarm was not indicated on the plant process computer sequence of events during the time frame which covered a few minutes before the reactor trip and up to the point that power was lost to the plant computer system. Also, System Engineering personnel have monitored the Plant Process Computer and the Data Acquisition System for control Rod 4-6 API and no problems have been noted. Also, Rod 4-6 has been verified to be fully inserted. System Engineering personnel concluded that the alarm inadvertently ,

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actuated when buss YAU was re-energized due to an electrical spike. The inspectors did not identfy any information which would refute the conclusion of System Engineering personne The inspectors concluded that the alarm had no impact during the loss-of-offsite power event and that the API for Rod 4-6 is operable and therefore would not i preclude plant startup. The inspectors' conclusions l were based on a review of the plant process computer )

sequence of events, Technical Specification 3.1.3.3, 1 computer trends for rod position indication, PCAQR 1098-1310, and interviews with plant personnel. Rlli inspectors agree this item was resolve t j

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l ISSUE DISPOSITION STATUS l

17 Loss of Auessment The meteorological system consists of sensors Closed Functions at the mounted on a 10-meter high tower and sensors Meteorological Tower mounted on a 75-meter high tower. Due to the storm condition, one of two 10-meter speed sensors and Apparentloss of allwind both 75-meter speed sensors were lost. The licensee i speed and direction due to stated that the remaining speed sensors satisfy l physical damag emergency plan implementation requirements. In addition, attemate wind direction capability was available. Rlilinspectors noted there are sufficient l instructions for determining wind speed and direction

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during an emergency. Rillinspectors agree this item I was resolved. Water intrusion into Motor MCC E5 was located in the area exposed to rainfall Closed ,

Control Center E5 due to the hole tom in the turbine building roof. The l inspectors concluded that MCC E5 is a non-safety

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Circuit Breaker AC211 MCC which supplies non-essentiallighting only. The experienced a ground fault licensee electrically isolated AC211 pending actions to tnp. Water was observed clean wetted MCC areas. This is not an issue that inside of MCC E would preclude restart of the plant. Rillinspectors

! agree this item was resolve Control Rod Drive irip The inspectors verified the trip confirm signal was Closed Confirm Annunciator received by the ICS using the ICS DAAS. The 86-1/RT -

Problem (Reactor Trip) relay deenergized at the time of the reactor trip. The 86-1/RT relay powered two other Operator reported that the relays and the Trip Confirm Annunciator. The annunciator came in much inspectors venfied the other two relays responded later than expecte correctly and the annunciator should have alarmed at the time of the trip. Since the annunciator came in

. later, it is suspected that the annunciator window had a l

momentary problem. Surveillance Test DB-SC-03164, D ' Channel Functional Test of Manual Reactor Trip *, will be performed prior to startup which will exercise the trip confirm an.iunciator, Rillinspectors agree this item was resolved.

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