IR 05000254/1998012

Insp Repts 50-254/98-12 & 50-265/98-12 on 980529-0716. Violations Noted.Major Areas Inspected:Operations, Engineering,Maintenance & Plant Support

ML20237D673
Person / Time
Site:	Quad Cities
Issue date:	08/11/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20237D662	List: IR 05000254/1998012 ML20237D660 ML20237D667
References
50-254-98-12, 50-265-98-12, NUDOCS 9808270125
Download: ML20237D673 (38)

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U. S. NUCLEAR REGULATORY COMMISSION REGION lll Docket Nos: 50-254; 50-265 License Nos: DPR-29; DPR-30 Report No: 50-254/98012(DRP); 50-265/98012(DRP)

Licensee: Commonwealth Edison Company (Comed)

Faciliiy: Quad Cities Nuclear Power Station, Units 1 and 2 Location: 22710 206th Avenue North Cordova, IL 61242 Dates: May 29 through July 16,1998 Inspectors: C. Miller, Senior Resident inspector K. Walton, Resident inspector L. Collins, Resident inspector K. Selburg, Resident inspector J. Adams, Resident inspector- Braidwood J. Hansen, Resident inspector - LaSalle R. Crane, Resident inspector - LaSalle Z. Falevits, Reactor Engineer, DRS, Region ll1 R. Ganser, Illinois Department of Nuclear Safety R. Lerch, Project Engineer Approved by: Mark Ring, Chief Reactor Projects Branch 1 L

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EXECUTIVE SUMMARY Quad Cities Nuclear Power Station, Units 1 and 2 NRC Inspection Report 50-254/98012(DRP); 50-265/98012(DRP)

This inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers an 8-week period of resident inspectio Operation _t

. Three events during the period, caused by turbine generator equipment problems, required operators to remove the turbine generator from operation. > The inspectors

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concluded that the operators responded to the events appropriately. However, the operators continued to be challenged by equipment problems (Section M2.1). ,

.: During Unit i startup, the inspectors observed good heightened level'of awareness .

briefings and overall good operator performance (Section 01.2).

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. Poor communication led to an operator error which resulted in the trip of the control room ventilation system. A confusing procedure and inappropriate procedure usage also contributed to the error (Section O1.3).

. The Unit i reactor tripped on June 27 from full power due to a failed scram discharge volume level transmitter coincident with a surveillance test of the average power range -

monitor. All systems functioned properly and operator response to the transient was good. The licensee's investigation failed to accurately determine the cause of the scram discharge volume transmitter failure, and several weeks later another spurious signal occurred shortly before a scheduled reactor protection system test (Section 02.1).

. -The Unit 2 reactor tripped on June 28 from full power due to a main generator trip.

r Operator response to the Unit 2 automatic reactor trip was good. The licensee's efforts to identify the cause of the main generator trip were well planned and coordinated (Section O2.2).

- . - Concurrent startups of Unit 1 and Unit 2 were completed without any significant problem However, several equipment failures occurred and required reactor protection system or

- containment isolation system channels to be tripped and Unit i to be in a Technical Specification shutdown action statement.. Additionally, control rods were extremely

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difficult to withdraw which became a significant distraction to normal operator performance and resulted in rods being moved past the intended positions several times

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L .- . Due to recurrent maintenance problems and an inability to determine a cause of valve

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failure, operators were required to increase the frequency of cycling with the Unit 2 -

[ ~ recirculation system sample valves. A failure on the recirculation system sample line

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resulted in operators needing to vent primary containment to atmosphere to avoid an engineered safety features actuation. However, the inspectors concluded the licensee met. Technical Specification requirements (Section O2.4).

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Equipment problems resulting from electrical storms affected various plant system Operations management decisions on degraded control rod drive accumulators did not use formal operability determination mechanisms, did not fully take into account Updated Final Safety Analysis Report requirements, and did not use engineering assistance to determine operability when design criteria were not met (Section O2.5).

. The inspectors identified errors associated with operations surveillance tests that zinvolved different and diverse operations subdisciplines including staff, supervisory, and management positions. One of these resulted in a violation. The inspectors were

! concemed that attributes of quality established and supported by management were not

being implemented by the operations organization (Section 04.1).

Maintenance l

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Three events during the period, caused by turbine generator equipment problems,

' required operators to remove the turbine generator from operation to repair the defective conditions. The inspectors concluded that the maintenance activities and prompt

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investigation reports were timely and appropriate. However, the operators continued to be challenged by equipment problems (Section M2.1).

. The licensee's investigation failed to accurately determine the cause of the scram discharge volume transmitter failure and later another scram discharge volume spurious

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trip signal occurred (Section M1.1).

. Four average power range monitors were declared inoperable due to the failure to complete the required surveillance tests within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of entering Mode 3. Technical Specification 3.1.A.1 was entered and required the channels to be in the trip condition within one hour. The surveillance tests were completed shortly after and the average

. power range monitors wem again operable (Section M1.1).

Enoineerina

. The inspectors found that the level of review to justify important changes to the reactor protection system testing was insufficient. Later review and improved administrative L controls were added to ensure that reactor protection system jumpers were not left in place after system testing (Section E1.2).

L . Engineers did not follow the process for changing safety-related setpoints in 1996 when the second-level undervoltage setpoint was revisec. As a result, no 10 CFR 50.59 review was conducted and the Updated Final Safety Analysis Report was not updated. This was considered to be a violation of 10 CFR Part 50, Appendix B, Criterion V (Section E8.19).

.- The inspectors identified an Updated Final Safety Analysis Report discrepancy in that the

, equipment minimum running voltage under degraded voltage conditions would not meet the 90 percent equipment rated voltage for several pieces of equipment.: Calculations provided an adequate technicaljustification; however, no 10 CFR 50.59 safety evaluation was performed when the condition was discovered and the Updated Final Safety Analysis Report was not revised to refisci the actual condition of the plant (Section E8.19).

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. Qualification of commercial grade relays for use in a safety function as emergency diesel generator time delay relays failed to account for environmental concems such as vibration. This was considered a violation of 10 CFR Part 50, Appendix B, Criterion 11 (Section E 8.18).

. The licensee identified that during a shutdown of Unit 2 in February 1997, the primary ,

containment function of pressure suppression would have been bypassed for a short I period during deinerting of the containment. The procedures that allowed this alignment were subsequently changed. This was a non-cited violation of Technical Specification 3.7.K.3 (Section E8.20).

Plant Support

.- The inspectors identified numerous administrative problems associated with the fire protection compensatory actions but concluded that the regulatory commitments were satisfied. The inspectors were concemed with the quality of documentation supporting required fire watch tours and the quality of correspondence in the May 22,1998, letter to the NRC (Section F2.1).

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Report Details Summary of Plant Status Operators synchronized Unit 1 to the grid on June 2,1998, following a 165 day outage in which safe shutdown analyses and procedures were corrected. Operators secured the unit turbine generator from operation on June 4,1998, to repair pipe supports and several

. welds on the.1 A moisture separator drain tank. Operators synchronized the unit to the grid on June 5,1998. The unit was operated at full power until June 27,1998, when a

' reactor trip from full power occurred due to a failed scram discharge volume level transmitter coincident with a surveillance test. Operators synchronized Unit 1 turbine generator to the grid on June 30,1998. Operations at or near full power continued to the end of the period with short downpower maneuvers for surveillance testing and control rod pattom adjustment At the beginning of the period, Unit 2 had been operating with the turbine generator synchronized to the grid for about three days.e Operators removed the turbine generator from service on June 5,1998, to repair the Number 2 turbine combined intercept valv The generator was retumed to service on June 6,1998. Operators again removed the turbine generator from operation on June 14,1998, for one day to repair a turbine electrohydraulic control system leak. The generator was synchronized to the grid on June 14,1998, and operated at full power. On June 28,1998, Unit 2 tripped from full power due to a main generator trip. Operators retumed Unit 2 to service on July 1,199 Operations at or near full power continued to the end of the period with short downpower maneuvers for surveillance testing and control rod pattem adjustment I. Operations 01 Conduct of Operations 01.1 General Comments (71707)

Adverse effects of equipment problems on the plant challenged the operators and

. resulted in numerous plant transients. Operators responded appropriately to these transients. However, several examples of operator errors during surveillance tests and other administrative errors in the operations demonstrated lessor quality standards during the performance of more routine task .2 Unit 1 Startuo After Extended Outaae

.The inspectors observed Unit 1 stasiup activities after the extended outage to resolve Appendix R safe shutdown issues. Initial control rod withdrawal began on May 31 and

,the main generator was synchronized to the grid on June 2,1998. During the startup, the inspectors observed good heightened level of awareness briefings and overall good operator performance. The inspectors noted that at times the control room was noisy and crowded due to the high number of activities; however, the shift managers adequately controlled the situation and no serious distractions resulte <

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01.3 Safetv-Related Control Room Ventilation System inoperable Due to Operator Error Inspection Scope (93702. 71707)

l The inspectors reviewed details of an emergency notification system call on June 26,1998, in which the "B" train of the control room ventilation system was declared inoperable after the refrigeration condensing unit tripped due to operator error. The

, inspectors reviewed the surveillance procedure and the licensee's prompt investigatio Observations and Findinos

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Operators investigated increasing temperatures in the control room and found that the refrigeration condensing unit for the "B" train of the control room ventilation system had i tripped. The system was declared inoperable and the Technical Specification limiting condition for operation entered. A prompt investigation concluded that operators had l shut down the running residual heat removal service water pump which was cooling the )

refrigeration condensing unit, and the lack'of cooling had caused the u' nit to trip on high  !

discharge pressur l

. The apparent causes of the event were inattention to detailin procedure usage, misinterpretation of verbal directions, and inadequate tracking of the performance of Quad Cities Operating Surveillance 5750-02, " Control Room Emergency Filtration System Monthly Test." The surveillance test directed flushing the refrigeration condensing unit

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using the residual heat removal service water system, but allowed either residual heat removal service water or the nonsafety-related service water system to be used for

- cooling during the 10-hour test of the ventilation system. The reactor operator and equipment attendant each believed a different method of cooling would be used because the method was not communicated in advance. As a result of the poor communication,

. several procedural steps were marked "not applicable" by both the reactor operator and the equipment attendan Approximately 6-hours into the test, a Unit 2 reactor operator shut down the residual heat removal service water pump because the flush of the refrigeration condensing unit was complete, resulting in the refrigeration condensing unit trip. Approximately 1-1/2 hours later, the condition was discovered, the "B" train of control room ventilation secured, and the "A" train started. The surveillance was later completed successfully and the "B" control room ventilation system declared operable.

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The licensee planned to do a root cause investigation and submit a Scensee event repor Conclusion Poor communication led to an operator error which resulted in the trip of the control room

, . ventilation system. A confusing procedure and inappropriate procedure usage also contributed to the erro l

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O2 Operational Status of Facilities and Equipment O Unit i Reactor Trio Inspection Scooe (93702. 71707)

The inspectors responded to the site to review the licensee's response to an automatic reactor trip. The inspectors focused on the licensee's investigation of the cause of the trip and subsequent corrective action Observations and Findinar The Unit 1 reactor tripped from full power at 5:11 p.m. on June 27 due to the failure of a scram discharge volume high level transmitter on the "B" channel of the reactor protection system coincident with a surveillance test on one of the Channel"A" average power range monitors in which a % reactor protection system trip signal was inserted Subsequent to the reactor trip, all systems functioned properly,and operator performance

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was goo .The licensee's investigation concluded that a Barton electronic transmitter (1-302-109D)

failed, causing a % trip on the "B" channel of reactor protection system. An electronic board was replaced and further testing was planned to determine the exact cause of the failure. Two weeks later the same transmitter failed just prior to turbine stop valve testing r

which could also produce a % reactor protection system trip condition. Subsequent troubleshooting detected a range shift in the detector attributed to a leak in the capillary sensing line.' The licensee determined later that this was the cause of the Barton transmitter failing and not the electronic boar Conclusions The Unit i reactor tripped on June 27 from full power due to a failed scram discharge

' volume level transmitter coincident with a surveil lance test of the average power range monitor. All systems functioned properly and operator response to the transient was

' good. The licensee's investigation failed to accurately determine the cause of the scram

~ discharge volume transmitter failure, and 2 weeks later another scram discharge volume spurious trip signal occurre O2.2 Unit 2 Reactor Trio Inspection ScoDe (93702)

The inspectors responded to the site to review the licensee's response to an automatic reactor trip. An electrical specialist from the NRC Region ill office assisted the resident

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inspectors onsite in reviewing the event, Observations and Findinas I

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On June 28,1998, at 02:23 a.m., Unit 2 main generator differential protective relay 87G2 (Phase C) actuated unexpectedly and caused the 345 kV switchyard Oil Circuit Breakers 1-11 and 10-11 to open and the generator to trip. The main generator trip 7 .

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resulted in a reactor trip, in addition, 345 kV line 0403 isolated on this fault, as designed, when Oil Circuit Breakers 7-8 and Oil Circuit Breakers 8-g tripped open on actuation of the offsite protective relays. At the time of the event, severe weather and thunderstorms  ;

passed through the Quad Cities area. The licensee promptly determined that a transmission static line, located approximately ten miles from the plant, caused a Phase B to Phase C ground fault.

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- 'The 87G2 differential relay was not designed to actuate on a 0403 line fault. Only the i switchyard 0403 line protective relays should have actuated to isolate the fault. On

~ June 28,1998, the licensee inspected the Unit 2 main generator, the Unit 2 "C"isophase, j

' the 87G2 relay, and other 87 protective relays. These components were found to be i functioning as designe ' During visual inspection of the current transformer compartment junction boxes, the licensee identified several loose connections on the "B" phase and "C" phase of the current transformer connections which required tightening of approximately % inch tu .

' The licensee lifted, cleaned, and re-landed the loose connections and performe ' continuity and cable resistance checks. The licensee concluded that the apparent cause 1 of the 87G2 relay trip was electrical perturbation due to the loose wire connected on a

~ current transformer that feeds the 87G2 relay. The loose wire was apparently caused by turbine generator vibration and lack of adequate preventive maintenance. The licensee estimated that as a result of the loose wire,30 to 40 amps were flowing in the circuit during the 0403 line fault. During normal operation the expected current would be le,,:

= than five amps in this circuit. The 87G2 relay was calibrated to actuate and trip at -

. 0.2 amperes and above through the relay operating coi The inspectors determined that the licensee's actions to identify the apparent root cause of this event were well planned and coordinated. The inspectors noted good interaction

~ and interface between the operational analysis, site maintenance, engineering, and operations department Several anomalies occurred after the Unit 2 trip including:

• ' Relief valves on the condensate side of the low pressure feedwater heaters lifted

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- ' and caused the turt>ine building sump to overflow onto the condensate pumn room floo r Reactor building and turbine building ventilation fans tripped due to positive

' differential pressure indications.' The standby gas treatment system was starte Sensing lines were affected by the storm. The indications retumed to normal after j the storm, and water was removed from the sensing line r An emergency diesel generator trouble alarm was received. This also occurred after the Unit i reactor trip. . Engineers believed the transfer of electrical power i from the main genomior to offsite power caused an electrical perturbatio !

Operators had seen this before and an open corrective action item existed to -

investigate the caus i

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The 3B power operated relief valve temperature indication rose to 250 degrees Fahrenheit. The 4A and 4F main steam safety valve temperature indications also increased and exceeded other relief valve temperatures by greater than the 50 degrees which, by procedure, required the indicators to be declared inoperable. Engineers concluded that the 38 power operated relief valve temperature trends were consistent with previous temperatures recorded as reactor pressure varied. The 50 degree delta for the 4A and 4F main steam

. safety valve temperatures was determined to be arbitrary and the thermocouple were determined to be operating properf .

Four average power range monitors were declared inoperable due to the failure to complete the required surveillance tests within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of entering Mode Technical Specification 3.1.A.1 was entered and required the channels to be in the trip condition within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The surveillance tests were completed shortly thereafter and the average power range monitors were again operabl Conclusions The Unit 2 reactor tripped on June 28 from full power due to a main generator tri ' Operator response to the Unit 2 automatic reactor trip was good. The licensee's efforts to identify the cause of the main generator trip were well planned and coordinate O2.3 Dual Unit Startuo Inspection Scope (71707)

The inspectors observed the startup of Units 1 and 2 following automatic trips from full power. The inspectors provided 24-hour coverage from initial control rod withdrawal on

. Unit 1 through the Unit 2 main generator synchronization to the gri Observations and Findinos Unit 1 startup began on June 29, and the reactor-was critical at 12:15 p.m. Operator performance and supervisory oversight was good. The main generator was synchronized to the grid on June 30. Several equipment problems occurred during the startup as described belo . On June 28 a % Group 1 isolation occurred prior to startup when the Channel"B" main steam tunnel high temperature alarm was received. Reactor startup l

continued while the failed temperature switch was replace . On June 29, with the reactor at approximately 1 percent power, all four main steam line radiation monitors went downscale. Operators inserted a % Group 1

. isolation and % reactor protection system trip in accordance with Technical Specifications 3.1.A.2 and 3.2.A.2. The Technical Specification action statements were entered and would have required the main steam isolation valves to be

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closed within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and the plant to be in hot shutdown in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Electro-magnetic interference was suspected, but not confirmed as the cause. The instruments came back on scale approximately 20 minutes later. After review of previous occurrences, the instruments were declared operable and the action

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On July 1, one of four main steam line flow indicators was reading significantly lower than the other three indicators and was declared inoperable. A % Group 1 isolation was inseded in accordance with Technical Specification 3.2. Instrument technicians found a small amount of air in the sensing line to the flow switch. Troubleshooting determined the instrument to be operating property and the instrument was retumed to service in approximately 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> .- . Many control rods were difficult to move which required increased drive water pressure and flow, and procedure changes to allow the use of the rod out notch override switch for control rods that could not be moved. Thousands of additional control rod drive switch movements were required to move the control rods.' Drive water pressure was increased to double the normal pressure in some cases which increased the likelihood for control rods to move past their intended t position. ' As a result, several control rods were inadvertently moved to a position one notch further out than desired or " double notched." Some control rods required several hours of manipulation to move from the full 3n position, i

=. ' One string of feedwater heaters tripped lwhich caused an unintended four percent increase in reactor power. No thermal limit problems resulted, and operators ;

responded appropriatel '

Unit 2 reactor startup began on June 29. The reactor was critical on June 30, at

- 8:55 a.m., and the main generator was synchronized to the grid on July 1.' Several

" equipment problems and other issues occurred during the startup and required operator attention or caused delays to investigate and address the issue. These problems included:

• Control rods were difficult to move as discussed above since the rods were not

exercised prior to startup as in the past. Several" double notch" events also

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occurred on Unit 2. No rod pattem violations resulted from the double notchin .

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.: Concurrent Unit 1 and Unit 2istartups : strained qualified nuclear, engineering

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resourcese At one point, only one' qualified nuclear engineer was available and 1 reactivity manipulations occurred on only one unit at a time. During this period, E Unit 2 operators indicated that the heat up rate could be lost if control rod L withdrawal did not continue. However, a second qualified nuclear engineer

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arrived, control rod withdrawal continued, and the heatup rate was not los I

! ' Despite several equipment problems which required entry into Technical Specification action statements and required channels of either containment isolation or reactor protection system to be tripped, the reactor startups were controlled and were completed without significant anomalies or error ___ ________ _ _ _ _ -_______-_ _ - _ _ _ - -

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. Conclusions Operators performed well during concurrent startups of Unit 1 and Unit 2 after both units tripped from full power. However, several equipment failures occurred and required reactor protection system or containment isolation system channels to be tripped and Unit 1 to be in a Technical Specification shutdown action statement. Additionally, control rods were extremely difficult to withdraw which became a significant burden to operator .4 - Hiah Drywell Pressure Due to a Primary System Leak Inspection Scope (71707)

The inspectors spoke to operators, reviewed operating logs, operating procedures, and Technical Specifications related to an event involving a primary system leak, Observations and Findinas Due to recurrent maintenance problems and an inability to determine a cause of valve failure, operators increased the frequency of cycling the Unit 2 reactor recirculation

system sample valves. On June 25,1998, operators identified increasing pressure in the Unit 2 drywell after cycling the sample valves. Drywell pressure reached about 1.7 psig before operators reduced drywell pressure by starting an additional drywell cooler and venting primary containment to the reactor building ventilation system using an approved t a proceduret An engineered safety features actuation of emergency core cooling system components would have occurred automatically at 2.5 psig. The containment atmosphere monitor detected an increase in drywell airbome activity indicating a leak of a contaminated system. Operators reduced drywell pressure below the Technical Specification required 1.5 psig after about 20 minutes.- Containment venting was performed for a total of about 20 minutes during the event. About 75 minutes into the event, operators closed the recirculation system sample valves and drywell pressure quickly returned to normal levels. From periodic drywell pumpings, the operators estimated the leak rate at about 9 gp During the event the operators maintained the unit operating at full power. However, operators entered into and exited from two limiting conditions of operation action statements requiring reactor shutdown.:These included Technical. Specification 3.6.H, for an increase in unidentified leakage in the drywell and Technical Specification 3.7.G, for drywell pressure greater than 1.5 psig.-The licensee removed the recirculation system sample valves from service and planned to identify the source of the leakage during a future outage. This condition was documented on Problem Identification Form Q1998-02975.- The licensee chose to keep the reactor recirculation sample system isolated, and not to investigate the cause of the leakage following the Unit 2 reactor trip on June 28,1998. The identification and corrective actions to repair the source of the

. Unit 2 drywell leakage will be tracked by the licensees corrective action process and on Problem identification Form Q1998-02975.

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. Conclusions Recurrent maintenance problems led to an increased frequency of cycling the Unit 2

- reactor recirculation system sample valves. Following sample valve cycling, a failure on the recirculation system sample line resulted in operators needing to vent primary containment to atmosphere to avoid an engineered safety features actuation. The

licensee met Technical Specification requirements for this event, isolated the leak, and

! chose to investigate the cause of leakage at a later dat .5 Control Rod Drive Accumulator Problems Resultina From Liohinino Strike InsDection Scope (71707)

The inspectors reviewed operator response to problems resulting from a lightning strike, meluding Problem Identification Form Q1998-0287 Observations and Findinos

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On June 14,1998, operators responded to several problems resulting from an electrical o . storm in the area. The problems included less of electro-hydraulic control pressure indication for Unit 1, loss of drywell pneumatic pressure indication for Unit 1, indication of j , control rod drive accumulator trouble for 44 control rod drives on Unit 1, and numerous "

i . computer point failures. Previous storms in the area had caused a number of minor 4 *

operational problems related to annunciation and indication. : Operators initiated problem - 1 .a L identification forms and action requests to initiate repairs and corrective actions. Most corrective actions were adequately performed prior to the equipment being repaired. 'The

< inspectors found actions taken to address the 44 control rod drive accumulators was not sufficient to ensure proper operatio .The control rod drive accumulator annunciators for 44 control rod drives alarmed at one -

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time. The accumulator annunciators were designed to provide operators indication of low

[ accumulator nitrogen pressure and of water in the nitrogen side of the accumulator, either l . of which could indicate a degraded ability to move control rods following a reactor trip

signal. - Operators found the cause to be a blown fuse in the circuit for the annunciator The fuse was replaced, but blew again when the annunciators were tested at a local l panel. Technical Specifications required that when more than one accumulator was

[  : inoperable, the associated control rod must be declared inoperablen With more than ( - eight control rods inoperable, the reactor was required to be shut down.HThe UFSAR l Section 4.6.3.3.2.7.1 indicated that the control rod drive accumulators were continuously l monitored for water leakage and nitrogen pressure to ensure the accumulators were f

capable of producing a scra The operators considered the accumulators operable after the annunciators alarmed, but

- required an every 2-hour check of accumulator pressure to ensure pressure met

, Technical Specification requirements.. The inspectors found that the shift manager did not evaluate operability of the 44 accumulators with the formal problem identification form process, review the UFSAR, or consult with the system engineer when making the operability determination. The operator actions to monitor the accumulator pressure every 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> allowed for some level of confidence that accumulator pressure was adequate, although not ensuring continuous monitoring as stated by the UFSA l

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However, the operator actions did not ensure that water level in the accumulators was acceptable. Approximately 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> later, when the annunciators were made fully operable, the operators found that accumulator pressures and water levels were acceptabl Conclusion

. Equipment problems resulting from electrical storms affected various plant system # 7 Operations management decisions on control rod drive accumulators affected by the >

storm did not use formal operability determination mechanisms, did not take into account UFSAR requirements, and did not use engineering assistance to determine operability when design criteria were not met. No serious accumulator degradation occurred during the time accumulator condition was not fully verifie Operation Staff Knowledge and Performance 0 Inspector Identified Errors in Operations Department Surveillance Tests;- Inspection Scope (61726)

l The inspectors either reviewed or observed the following Quad Cities Operating ,

! Surveillance Procedures to ensure requirements were met: "

i 1600-32, "Drywell/ Torus Closeout,"

' 4100-30, * Quarterly Essential Fire Protection System Suppression Alarm Test,"

6600-01, " Diesel Generator Monthly Load Test."

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l 1 Observations and Findinas l b.1- Emeroency Diesel Generator Valve Mispositionino i t

The inspectors observed an equipment operator performing valve manipulations during a l June 22, .1998, surveillance test on the Unit 1 Emergency Diesel Generator. The inspectors observed the equipment operator open the crankcase drain valve during performance of a step which required opening (throttled) the air box drain valve. The >

operator failed to properly open the air box drain valve and moved on to the next step in .

the procedure. The inspectors mentioned their concem to both the equipment operator and the shift manager who was in attendance during the test. Upon confirmation of the i valve mispositioning, the shift manager suspended the surveillance test,' verified there i was adequate lubricating oil in the diesel crankcase, and reported the configuration

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< control discrepancy to upper management.- The licensee initiated a prompt investigation and commenced a root cause investigation (Problem Identification Form Q1998-02943).

< , The failure to operate the valve listed in Quad Cities Operating Surveillance 6600-01, ,-

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Diesel Generator Monthly Load Test," Attachment A, Step H.7.l.(4), was considered a l

Violation (50-254/98012 02) of Technical Specification 6.8.A.1. The inspectors noted t attributes put in place by management to improve operator performance were not effective in preventing this event. For example:

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the operator did not have a peer check during the evolution; e

operations management did not have a policy for evolutions requiring peer checks, but did have an expectation that peer checks would be performed;

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the procedure described the valve by noun name rather than by number; and

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management was conducting an overview of the event during the test, but the overview did not detect the erro ' b.2. . Missed Independent Verification of a Fire Protection Surveillance The inspectors identified that a fire protection surveillance test performed in April 1998,

was signed as completed but was missing required independent verification signature ; Quad Cities Operating Surveillance 4100-30, " Quarterly Essential Fire Protection System Suppression Alarm Test - Part 1," Attachment A, was not signed by the reactor operators at the completion of the test.- A senior reactor operator signed the completed surveillance as being reviewed and approved. The independent;verificationwas in place to ensure i

that the fire protection system alarms were cleared prior.to placing the fire protection isystem back into service. Operators reviewed the fire protection . computer for alarms

'once per shift, which accomplished a similar function. This issue was documented on

, Problem Identification Form Q1998-0291 The failure to complete the surveillance test in accordance with the procedure constitutes

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a violation of minor significance and is not subject to formal enforcement action. The inspectors noted this was an additional example of poor quality standards being employed by both reactor operators performing the test and a senior reactor operator n responsible for reviewing the results of the test, b3 Unit 1 Drvwell Close Out

. On May 29,~ during the close out inspection of the Unit 1 drywell, the inspectors identified l- o damaged insulation on the reactor building closed cooling water piping for the 1D and 1E ~ '

-I drywell coolers. The licensee in;uated corrective actions for the repair or removal of the {

damaged insulation. The inspectors reviewed Quad Cities Operating Surveillance I Procedure.1600-32, Attachment C, " Comment Disposition Form," completed by the licensee on May 28, and determined that the licensee failed to identify and document the m -damaged piping insulation during their close out inspection of the Unit i drywell. This failure constituted a violation of minor significance and is not subject to formal enforcement action.

i b.4 . Imoroner Chanae to a Fire Surveillance Procedure

.The inspectors identified that a fire protection surveillance test (Quad Cities Operating

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Surveillance 4100-30, " Quarterly Essential Fire Protection System Suppression Alarm Test - Part 1,") performed in October 1997, was missing Steps H.13.d and H.13.e. from

. the field copy. Both the official copy and the field copy were Revision 5, dated

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" September 30,1997.2The licensee documented the error on Problem Identification Form

- Q1998-02956 after the inspectors identified the discrepancy.' Clerical personnel had i

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introduced the error into the master copy of the procedure. The licensee identified and ;

corrected the deficiency on October 31,1997. This was an additional example of poor '

quality standards being employed by both clerical personnel entering the change to the procedure and to operations staff personnel responsible for reviewing the procedure chang Conclusions Errors identified by the inspectors associated with operations surveillance tests involved different and diverse operations subdisciplines including staff, supervisory, and management positions. The inspectors were concemed that attributes of quality established and supported by management, were not being implemented by the operations organizatio Miscellaneous Operations issues (92700)

0 Violations Associated with 1990 Event (92901)

The inspectors reviewed current licenses performance as related to the following violations:

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- (Closed) Violation 50-265/90203-01013: Nuclear Station Operator Failed to Utilize Procedures;

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(Closed) Violation 50-265/90203-01023: Inadequate Shift Briefing;

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(Closed) Violation 50-265/90203-01033: Reactor Scram After Nuclear Station Operator Failed to initiate Hold;

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1 Closed) Violation 50-265/90203-01043: Nuclear Station Operator Failed to insert Source Range Monitors at Range 4; and

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(Closed) Violation 50-265/90203-01053: Nuclear Station Operator Failed to Decrease Intermediate Range Monitor Range The violations were administratively.added to the inspection follow-up system to provide a record of closure. The inspectors, as part of the routine core and regionalinitiative inspections, have reviewed numerous reactor.startups, shutdowns, and power manipulations. Reviews of these manipulations have determined that the reactor operators effectively used procedures, initiated holds when required, inserted source range monitors as required, properly ranged intermediate range monitors as required, and

. improved shift briefings. Based on the inspectors' review of numerous successful power l- manipulations since these 1990 violations were cited, these items are closed.

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08.2 (Closed) Inspection Follow-up item 50-254/93019-01: Licensee Action to information Notice 93-33 Regarding Potential Deficiencies of Class 1E Instrumentation and Controls Cable. This item was opened to review the licensee response to this information notic At the time the item was opened, little station action had been completed. Since 1993, the licensee's corporate office conducted a review of the cable described in the information notice, and the effects as applied to each nuclear facility. This review covered the environmental effects on these types of cables, and determined that all issues described in the information notice had been addressed. The licensee continued

< to use a corporate program to track these cable types and their uses. Tht, licensee, 1 through the assistance of their corporate office, assessed and reviewed this information notice. This item is close )

08.3 (Closed) Violation 50-254/96012-04: 50-265/96012-04: Units 1 and 2 Annunciator

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Procedure Not Appropriate to the Circumstances. On August 26,1996, while performing overspeed testing on the Unit 1 reactor core isolation cooling turbine, a reactor core isolation cooling gland seal vacuum. tank high level alarm was received. The annunciator procedure, which addressed this alarm, required verification that the drain valves were

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. open; The operator was unable to open the valve with the control switch, so the reactor j core isolation cooling turbine was tripped, and the operations staff began investigating the problem. The licensee later determined that the valves were interlocked with the reactor ]

core isolation cooling turbine steam inlet valve, and that the annunciator procedure was impossible to perform under these circumstcqces. The licensee revised the annunciator 'i procedure, Quad Cities Annunciator Procedure 901(2)-4 H-15, to address this issue, and provided an explanation for the interlock in the reactor core isolation cooling system's turbine over speed test procedure (Quad Cities Operating Surveillance Procedure  !

1300-04). The licensee also conducted training for all licensed operators to describe why 1 Annunciator 901(2)-4 H-15 would be expected when the reactor core isolation cooling pump was uncoupled from the turbine. Finally, the licensee reviewed a sample of procedures from the procedure writer who had made the error in the annunciator

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procedure; no additiona! problems were identified. These items are close .4 (Closed) Violation 50-254/96014-01a: 50-265/96014-01a: Failure to Follow Procedur . On October 11,1996, the inspectors identified an uncontrolled document posted on the

- back panels in the control room. Licensee corrective actions to prevent recurrence c . included removing the posting and training operations personnel on the inappropriate use  ;

of uncontrolled documents. Through the performance of routine plant inspections and l t

. interviews oflicensee personnel, the inspectors noted that these corrective actions were effective, and Part (a) of this violation is closed (see Section M8.7 for closure of Part b of ,

the violation). 1 08.5 - (Closed) Inspection Follow-up Item 50-254/96014-02: Combined Intercept Valve Drifted

. Closed. On October 23,1996, the Unit 2 Number 1 combined intercept valve slowly drifted from its normally full open position to a closed position. During the investigation of l

.a this event, the licensee determined that the drift was due to a faulty servo amplifier

.demodulator indicator circuit board. The licensee performed tests on the faulty control i boards. During the testing, the station experienced a large transient in generator output, l from 10 megawatts electric to 280 megawatts electric. The licensee performed a root

! cause evaluation for this event and determined that the combined intercept valve failure was associated with a transistor problem. The transistor had a different part number than was described in the installation drawings. This difference between the required and

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installed transistors was related to different gains, with the installed transistor becoming very unstable at elevated temperatures. The licensee determined that during the event, the component or cabinet heated up, and the gain changed as well as the output signals to the servo valve. There were no known previous failures of this transistor on an electrohydraulic control circuit board at the station. The licensee's immediate corrective actions included replacing and calibrating the Unit 2 intercept valve Number 1 servo amplifier demodulator indicator board.' Long term corrective actions included replacing l , the Unit 2 intercept valve Numbers 3 and 5 servo amplifier demodulator indicator boards  ;

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eduring the following refueling outage. The root cause evaluation team determined that

- this load transient event was isolated, and most likely due to a feedwater heater transien >The licensee's evaluation and corrective actions effectively addressed the concem. This

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item is close .6; (Closed) Violation 50-254/96020-02: 50-265/96020-02:: Declining Operator Performanc in 1996 there were several examples.in which operators failed to exhibit good procedural j i compliance and attention to detail when. manipulating components on the control panel J

Immediate corrective actions included retuming mispositioned components into the  !

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. s : nm correct configuration.s Long term corrective actions included emphasizing through training l

. and shift meetings the importance of procedure adherence. These areas will continue to

, ~ be inspected as part of the core inspection program. These items are close t 08.7 dClosed) Violation 50-254/97002-01: 50-265/97002-01: Unit 1 Reactor Protection System 3 Relay Problem. On March 7,1997, while Unit 1 was in Mode 1, the "B" reactor protection m system trip system had less than the minimum operable instrumentation channels required by Technical Specification Table 3.1.a-1 due to the failed 1-590-108D reactor

protection system relay. The "B" reactor protection system trip system was taken out of the tripped condition although the relay had been inoperable for greater than one hou To address this violation, the Operations department conducted training to ensure that all l license holders understood the basis for the operability determinations made during this

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. covent.nThe training also discussed the Technical Specification requirements that should ,

have made the 108D relay inoperable when it was determined that it had been tripped without a valid signal. The inspectors noted that the licensee's corrective actions for this event were acceptable. These items are closed.

_08.8 ; -(Closed) Violation 50-254/97002-03: 50-265/97002-03: Failure to Control Turbine . ,

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Building at a Negative Pressure. On March 7,1997, operations personnel did not

. appmpriately implement Quad Cities Annunciator Procedure 912-5, C.2, " Turbine Building Low DP," although turbine building pressure was positive.n Operators opened the turbine x 'o -

> > building roll-up door and did not start additional exhaust fans because the fans were out l of service. The inspectors noted that with the turbine building door open, and with a l- positive pressure in the turbine building, an unmonitored release of radioactive airbome i

materials could occur. The inspectors also noted that the operators did not exhibit

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thorough responses to other ventilation alarms. The licensee attributed the violation to

> poor procedural guidance for appropriate operator actions in response to this alarm. The v -

licensee revised the procedure to provide for additional guidance on appropriate actions .

in similar circumstances. The inspectors noted that these actions were comprehensive, and if followed, would ensure that an unmonitored release of radioactive airbome materials would not occur. The licensee also provided training on this event. The inspectors noted that the training content addressed the cause of this violation. However, during routine inspections of control room activities, the inspectors continued to observe i

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slow responses to alarms associated with ventilation systems, and will continue to monitor operator actions to these alarms through routine inspection activities. However, the specific issue of response to a turbine building low differential pressure alarm was adequately addressed. These items are close .9 (Closed) Violation 50-254/97006-02: 50-265/97006-02: Failure to Properly implement

. Test Procedure. On April 15,1997, operators did not properly implement Quad Cities a Operating Surveillance Procedure 6500-3, "4 Kilovolt Bus 14-1 Undervoltage Test." The operator initialed a step as completed, but failed to verify that the breaker was close ? The breaker was in the open position. To address this event the licensee counseled the operator on the importance of procedure adherence, and ensured that the affected 1

. breaker was properly positioned and the surveillance was successfully completed. The licensee discussed the need for stringent procedural adherence for all station personne _ The inspectors continue to observe procedural adherence through routine inspection activities. These items are close .10 (Closed) Violation 50-254/97011-03! 50-265/97011-03: tValve Position Verificatio . Between-July 17 and July 22,1997, the inspectors identified four: valves on the residual heat removal service water system flow path that were not locked, sealed, or otherwise usecured in position, and were not verified within the correct position within the previous 31 days... Subsequently, the licensee identified an additional eleven valves in this

condition. The licensee determined that the surveillance deficiency was due, in part, to

. an inadequate procedure development and review for this procedure due to cognitive

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. personnel errors. The personnel who prepared and reviewed this procedure revision did not recognize that residual heat removal service water supply to the residual heat

. removal pump oil and seal cooler valves needed to be checked to meet this Technical Specification. The licensee verified the affected valves were in the correct position, and

' ensured procedures were appropriate for valve position verifications using station

- controlled drawings. Based on the licensee's review and corrective actions, these items are close .11 '(Closed) Violation 50-254/97014-01: 50-265/97014-01: Surveillance Requirements Were

. Not Met During Reactor Modes. On June 1,1996, April 29,1997, May 9,1997,

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June 23,1997,' August 19,1997,' and September 4,1997, the licensee did not ensure that

_ = surveillance requirements werc met during operational modes or other conditions l specified for individual limiting conditions for operations.WThe licensee effectively.

L _ eaddressed the cause and provided adequate corrective actions for each example of this-violationc To address the adverse trend with this. Technical Specification noncompliance,

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t the licensee performed a root cause evaluation which determined that a comprehensive review of all Technical Specification requirements was necessary to ensure the i appropriate incorporation into station procedures. The licensee performed this review, and made the appropriate changes to station procedure. The inspectors reviewed selected surveillance during the Units 1 and 2 startups in May and June 1998, and noted

. that the surveillance procedures were consistent with the licensee's Technical

- Specifications. : This area will continue to be inspected using the core inspection progra . These items are closed.

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l 11. Maintenance M1 Conduct of Maintenance M1.1 General Comments

, ' During this inspection period, equipment failures caused plant transients and two reactor j L 4 trips and also required entry into Technical Specification shutdown action statements on

- * several occasions. Some of these material condition issues were repetitive and were the~'

result of the failure to identify the root cause The scram discharge volume level

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transmitter failed and caused a Unit i reactor trip; the root cause was not pinpointed, the

. problem remained, and the transmitter failed a second time (see Section O2.1). In 'j response to other failures, such as described in Section M2.1, the maintenance 1 department adequately addressed the problem. On one occasion after the Unit 2 reactor j trip, maintenance support of operations was poor and resulted in the inoperability of four

average range power monitors because required surveillance testing was not completed on time (see Section O2.2).

. M1.2 Moisture Separator Drain Tank Line Support Repairs (62707)

Following the restart of Unit 1, water hammer caused the lines running between the 1 A moisture separator drain tank and the moisture separator to move. The licensee 'l

- determined that a newly installed controller caused erratic level control valve operation l n which precipitated the event. Some of the supports for the interconnecting line between )

the two vessels were damaged. The licensee formed a team to assess the damage, established a scope of expanded inspection, and made the necessary repairs. The licensee's response to this event was goo M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Eauipment Problems Challenaed Operators I Inspection Scope (71707)

The inspectors reviewed prompt investigations, spoke to personnel, reviewed applicable j maintenance work packages and observed maneuvering of the units in response to some of the following events:

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.- Unit 2 main turbine combined intercept valve failed to open,

. - Unit 1 "B" moisture separator drain tank supports damaged, and '

. Unit 2 electrohydraulic system lea Observations end Findinas

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< Explained below are examples of equipment performance problems during the perio j The first three events required operators to remove the turbine generator from ope'atio During the repair periods, the operators maintained the reactor critical. All these events were examples of equipment problems which continued to challenge the operator _

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. Failure of Main Turbine Combined intercept Valve to Open On May 27,1998, after closing the Unit 2 Number 2 combined intercept valve for testing,

~ the valve would not reopen. The licensee consulted with the main turbine generator vendor and continued to operate at full power with the valve closed until repairs could be initiated. On June 5,1998, operators removed the Unit 2 main turbine generator from service and replaced a defective solenoid valve. On June 6,1998, operators retumed Unit 2 main turbine generator to service.- During the removal and retum to service of Unit 2 main turbine generator, the inspectors observed operators adherence to procedures and communications were goo b.2 - Damaoe to Unit 1 Moisture Separator Drain Tank Pipina Supports j - During startup of Unit 1 on June 2,1998, an operator identified that the "B" moisture

separator drain tank was moving up and down about.10 inches, and several piping and l . tank supports were damaged. Operators stabilized the equipment by manually adjusting a level controller. The controller caused an emergency drain valve to sporadically open

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and close which produced a series of hydraulic pressure transients and damaged the l supports. Startup activities were suspended. On June 4 operators removed the Unit 1 turbine generator from service to inspect the tank and piping. The level controller was replaced, and the damaged supports were repaired. Operators placed Unit 1 turbine generator in service the following day. The inspectors concluded the prompt investigation

. into the event was good. The inspections of tank and piping identified indications which were appropriately repaired or evaluated. The erratic performance of the level controller l was still underinvestigation.

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b.3 - Leak in Main Turbine Electrohydraulic Control System l Early on June 14,1998, control room operators received an annunciator alarm indicating l - an oil leak in the electrohydraulic control system to the Unit 2 main turbine generato The operators quickly reduced turbine generator electrical load and sent personnel into a high radiation area where an operator identified about 0.6 gallons per minute leak near a welded fitting to the Number 3 control valve. The operators responded appropriately to the condition. The operators quickly reduced reactor power by inserting designated control rods and removed the turbine generator from service in a timely manner. The prompt investigation report contained sufficient ds; ail to explain possibly how the leak L : developed and recommended appropriate corrective actions.hThe licensee had L previously experienced fatigue cracking in this system and developed a modification that

! was approved in January 1997, for installation. However, the modification did not receive l a high enough ranking to be worked prior to a refuel outage.

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l Miscellaneous Eauipment Problems Operators on both units had difficulty in moving control rods during recent unit startups-(see Section O2.3). - A Unit i scram discharge volume instrument failed during reactor protection system testing which resulted in a scram (see Section O2.1). The instrument was repaired and placed back into service. However,2 weeks later, the same instrument unexpectedly failed a second time just prior to reactor protection system testing. The licensee replaced the detector, including a defective capillary tube. Operators detected a recurrent condition in the Unit 2 offgas system indicating recombination outside of the

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recombiner. Operators entered into an abnormal procedure requiring steam to the steam Jet air injectors be isolated and later retumed the offgas system to normal operation. The hydrogen water chemistry system for both units tripped at least 12 times during the period. A proposed modification was the expected fix for this problem. A feedwater heater string tripped on Unit 1 and caused reactor power to increase unexpectedly about 4 percent. Numerous % reactor trips and % Group 1 primary containment isolation signals were received or required to be inserted due to equipment failures such as main

. steam line radiation monitors, a main steam line flow detector, and a main steam tunnel e temperature switch.1These problems were corrected or were evaluated as acceptable by _

the license Conclusions The first three events were caused by turbine generator equipment problems, one of which was repetitive. Operators were required to remove thesturbine generator from

" operation to repair the defective conditions.4The inspectors concluded that the operators

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responded to ine events appropriately, but were challenged by.a large number of I equipment concem M8 Miscellaneous Maintenance issues (92902)

- M8.1 (Closed) Licensee Event Report (LER) 50-265/93025-00 "A" Loop Main Steam Isolation i

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Valves Exceeded Technical Specifications. This event was discussed, and Revision 1 l

was closed in Inspection Report 50-254/97028; 50-265/97028, Section M8. Based on the conclusions described in the aforementioned report, this item is close M8.2 (Closed) LER 50-254/94005-00: 50-254/94005-01: 1A Main Steam isolation Valve Failed i I

Local Leak Rate Test. On March 17,1994, Unit 1 feedwater check valve 1-220-58B l failed the localleak rate test. Investigation of this event determined that the valve seat ( was misaligned due to hinge pin bushing wear.'This wear allowed the swing check to be mispositioned on the valve. The licensee reviewed the hinge pin and bushing materials to verify the appropriateness for this application, and replaced the failed valve trim. The

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would occur at an alert leak limit. The licensee evaluated similar valve types for local

leak rate test failures, and noted that there was satisfactory test performance for similar i valves. Therefore, the licensee's corrective actions adequately addressed the root cause of the problem. These items are close !

M8.3 0 (Closed) LER 50-265/94006-00: Unit 2 Reactor Scram When Main Steam Line Isolation j l-

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Valves Shut. ' On August 23,1994, Unit 2 was in the run mode at approximately l 99 percent power.' During contractor instrument maintenance on an instrument rack adjacent to the main steam line high flow instrument racks, a Group l primary containment isolation signal was received from the "A" main steam line high flow signal, l _

with a reactor scram following. The cause of the event was attributed to an inadvertent

' vibrational disturbance to the main steam line high flow instruments by contractor instrument maintenance personnel working near the rack. The licensee's corrective actions included providing station and contractor personnel with enhanced training to discuss the vibrational sensitivity of various instrument racks. To address design concems, several of the main steam line high flow actuation switches were replaced with less vibrational sensitive models, and physical barriers and signs were erected around

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the instrument switches. The inspectors noted that the licensee completed the corrective actions committed to in the licensee event report. This item is close M8.4 (Closed) LER 50-254/95001-01: During Unit Startup, Reactor Core isolation Cooling Govemor Valve Failed. This event was discussed, and Revision 0 was closed in Inspection Report 50-254/97028; 50-265/97028, Section M8. Based on the conclusions described in the aforementioned reports, this item is close : M8.5 : ((Closed) Violation 50-254/96006-02: 50-265/96006-02:" Wrong Source Range Monitor Shorting Links Removed. On or about April 18,1996, instrument maintenance

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technicians working on the source range monitor trip function of the reactor protection system lifted the wrong shorting links due to incorrect information provided in the work

procedure. This work procedure had not been approved by station management and an

. - associated safety evaluation had not been performed as was required by Technical i

Specifications. To address this problem, the licensee provided enhanced training to the

, work analysts and maintenance supervisors.4The training discussed technical reviewer requirements and safety evaluation requirements.-;The licent se also revised the

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c procedure goveming the preparation and control of work packages to include enhanced - -

descriptions of these requirements. Finally, the licensee initiated a data base which listed

- individuals qualified to perform independent reviews for specific maintenance activitie > The inspectors noted that the licensee's corrective actions addressed this violatio These items are close M8.6 ' (Closed) Violation 50-254/%012-06a/ b. c: 50-265/96012-06a. b. c: Inadequate Procedures. In three different situations, maintenance instructions did not requke the verification of critical dimensions required to support proper safety-related equipment operation. The licensee had previous problems ensuring that properly sized parts were installed in safety-related equipment. The licensee addressed each example of the violation, and ensured that the appropriate parts were in place.. The licensee also revised

"* station procedures to ensure that the appropriate specifications were described.: Finally,-

the licensee conducted training for mechanical maintenance personnel to address these l issues. This particular violation has been adequately addressed by the licensee and is l- . closed. However, the licensee and inspectors continue to identify weaknesses in

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maintenance procedures, and this area will continue to be reviewed using the core I

inspection progra M8.7- (Closed) Violation 50-254/%014-01b: 50465/96014-01b:i Failure to Follow Procedur On October 23,1996, mechanical maintenance personnel performed an emergency diesel generator periodic preventive maintenance inspection proceoure out of sequence without the appropriate maintenance supervision approval. The licensee determined that L the workers had performed the procedure out of sequence because they did not

. understand the appropriate work execution process requirements. The licensee revised

the work execution procedure and provided training to maintenance groups to enforce the ( <

- :need to discuss procedural sequence adherence unless directed otherwise by . supervision. The licensee's corrective actions addressed this particular violation, and l Part (b) of this violation is closed. However, the inspectors have continued to note

! weaknesses, and have documented these weaknesses in previous inspection reports, of l' maintenance workers inappropriately complying with procedures, and will continue to

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M8.8 (Closed) Violation 50-254/96014-03: 50-265/96014-03: Title 10 CFR Part 50, Appendix B, Criterion 11 Violation. On October 22,1996, the licensee failed to ensure that maintenance technicians performing activities affecting quality on the shared standby diesel generator-were trained to assure suitable proficiency. This occurred, in part, due to a lack of understanding by the maintenance department of the licensee's job training performance expectations. To address these issues, the licensee revised the Maintenance Memo 800-01, " Maintenance Department Qualification Program" on

'Janualy 23,1997. .The change stated that the maintenance department would only use cnonqualified employees to perform tasks if a qualified employee for the task did not exis The maintenance supervisors were train *d on this procedure change. These corrective  ;

actions were adequate, and these items are close ,

M8.9 - (Open) Inspection Follow-up Items 50-254/97002-06: 50-265/97002-06: Instrument

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Calibration Program Weaknesses. The inspectors reviewed the licensee's corrective 1 actions regarding the instrument calibration program.4Several examples had been i identified in which instrumentation was not included in a calibration program. .The -

- inspectors reviewed the corrective actions for each example described in the report, and

- * : noted that the licensee effectively addressed the issues individually.cHowever, the l licensee was also working on an overall review in which to ensure that all Technical l Specification-required instruments were included in the calibration program. While the  !

inspectors did not note any immediate safety concems with this issue, these items will -

remain open pending a review of the licensee's evaluation of the calibration progra 'l

' M8.10 (Closed) Violation 50-265/97014-02: Failure to Follow Procedure. On March 11,1997, '

certain steps were not performed during the use of Quad Cities Mechanical Maintenance i Procedure 1515-07 for a valve packing repair. Specifically,' construction maintenance  ;

supervisors decided to add packing to the valve stem rather than fully repack the valve, in order to perform this action, an unauthorized change was made to the valve packing procedure.; The technical adequacy of the packing configuration was later accepted and -

' approved through an engineering request in December 1997. Additionally, the

< construction group incorporated lessons teamed from this event on procedure adherence ,

and work execution into training. Finally, the licensee included additional instructions for "

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packing addition into the aforementioned procedure. The inspectors noted that the specific corrective actions for this event were adequate. However, in inspection Report 50-254/98009; 50-265/98009 the inspectors noted other examples of supervisors l providing incorrect instructions to work groups causing them to be in violation of -

- Technical Specification-required procedures.: Since the specific corrective actions of this violation have been completed, this violation is closed.; However, the more widespread -

problem of inadequate or inconsistent supervisory guidance being provided, will be l tracked through the violations issued in the aforementioned inspection report.

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111. Enoineerina E1 Conduct of Engineering E Poor Safety Evaluation Review for Bvoassina Neutron Monitorina Scram Function Inspection Scope (71707)

The inspectors spoke to operators, engineers, and plant management; and reviewed >

procedures and safety evaluation screening documents regarding changes made to surveillance procedures which would bypass reactor protection system scram function I Observations and Findinas Recently, the licensee convened a special group to loolcinto methods of reducing reactor ,

trips. The group had a 3-month deadline to finish many of the tasks.J Following reactor l

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trips at Quad Cities due to an equipment problem coincident with the performance of a )

!- w . * ? surveillance which placed the reactor protection system in a half scram condition, licensee management shortened the completion time for completing some scram frequency reduction methods to 1 wee ' The inspectors reviewed the procedure and 10 CFR 50.59 screening form used to

' implement one change to a surveillance which involved jumpering across certain average !

- power range channel contacts in the reactor protection system. Procedure Quad Cities

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Instrument Surveillance 0700-07 " Power Operation APRM Functional Test" was changed i

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to allow a test box which effectively jumpered across a set of contacts which provided i input into reactor protection system logic and allowed scram relays to remain energized

!' even when a channel trip signal was given. The inspectors found the screening form to

~ be missing information related to requirements for indicating reactor protection system l bypasses in the control room.= The UFSAR stated, "If the ability to trip some part of the

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. system has been bypassed, this fact is continuously indicated in the control room. The ( requirements of IEEE-279-1968 IndicStion of Bypass (Paragraph 4.13) are met for l bypasses involving these REACTOR PROTECTION SYSTEM trip functions: Neutron

! monitoring system IRM and APRM scram."

l The initial screening reviewers had not considered this requirementrAfter the inspectors ;

asked engineering management how this section was met, the initial response was that the light on the test box which was hung amidst the wiring of the control room back l panels provided that indication.- When the inspectors pointed out that Indication would ]

not be visible to operators and that the light did not provide indication of bypass at all j I

ctimes, the licensee agreed to review the requirements again. Later, the inspectors were informed that a caution card would be hung in the control room to meet the requirements for continuous indication, in a conference call between the Office of Nuclear Reactor 1

- a Regulation, Region Ill, and the licensee on the issue, the Office of Nuclear Reactor Regulation explained that a caution card did not meet the intent of the Institute of 1

' Electronic and Electrical Engineers standard as interpreted by Regulatory Guide 1.47 l l

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' " Bypassed and inoperable status indication for nuclear power plant safety systems." The licensee explained they were not committed to the version of IEEE-279 to which the Regulatory Guide applied, even though the version to which they were committed (1968)

contained the same wording for bypasses as the version to which the Regulatory Guide applie Later the licensee agreed to review the situation further and discontinue testing until the

< issue was resolved. The review indicated that original design did not intend to provide

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' bypass for every reactor protection system function. Updated Final Safety Analysis r Report statement "The requirements of IEEE-279-1968 Indication of Bypass

- (Paragraph 4.13) are not applicable for the following functions and equipment ... Reactor protective system trip logic, actuators and trip actuator logic..." appeared to support that

conclusion. However the licensee could not explain the apparent disparity of the former l . and later UFSAR statements mentioned above. The licensee resumed testing of various reactor protection system scram functions using the new. test box method including enhanced administrative controls (independent verification and caution card) to ensure bypasses were removed."The inspectors reviewed performance of the' surveillance and

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ee . found no cases where reactor protection system bypasses were left in place after the 1 conclusion of the surveillance. The inspectors did find that the chances for a reactor

, protective system contact to remain jumpered were increased by the use of new procedur (

l Conclusions The inspectors found that the level of review to justify important changes to the reactor

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protection system testing was insufficient. Later review and improved administrative

. controls were added to ensure that reactor protection system jumpers were not left in l plac E8 Miscellaneous Engineering issues (92902)

E (Closed) LER 50-265/93022-00: Emergency Core Cooling System Floor Drain Check l

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. , Valves inoperable. Reactor building floor drain and equipment drain check valves were

. inoperable which created a flooding pathway into the emergency core cooling system

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' room from the torus area.s As a result of these issues, floor drain sump valves were -

l replaced with a more debris-resistant design and equipment drain check valves were L disassembled and inspected. The check valves were free of debris and were placed on a L periodic surveillance schedule. This licensee event report is closed.-

E (Closed) Inspection Follow-up item 50-254/94020-05: Residual Heat Removal

! Suppression Pool Cooling Water Hammer Concems. This issue was last reviewed in L Inspection Report 50-254/96015; 50-265/96015. In this report, the inspectors noted that

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- the licensee did not consider a mechanistic concurrent loss of offsite power and loss of m coolant accident. .The inspection followup item was left open pending review of the loss

' of offsite power and loss of coolant accident issue by the Office of Nuclear Reactor Regulation. The Office of Nuclear Reactor Regulation responded on October 21,1997, that the licensee addressed the draft general design criteria and that, in particular, the licensee's response to General Design Criteria 41 noted that the safety-related emergency core cooling systems were designed to operate over the entire spectrum of postulated design basis reactor primary system breaks concurrently with the loss of

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offsite ac power. Therefore, the Office of Nuclear Reactor Regulation concluded that a concurrent loss of offsite power and loss of coolant accident was within the station's

licensing basis, and that the licensee had to consider a mechanistic occurrence of a loss of offsite power concurrent with a loss of coolant accident. As inspection Report 50-254/96015; 50-265/96015 noted, the licensee had adequate procedures in place to address the water hammer concem. There are no other outstanding issues associated with this item. This item is close l

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E8.3 - ,(Closed) LER 50-254/95002-00:- Improperly Sized Overloads Found on the Control Room -

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. Heating, Ventilation, and Air Conditioning System Due to Inadequate Original Design '

' Analysis.' This licensee event report was left open because of differences in the i consequences between the Quad Cities and Dresden Nuclear Stations on the same ll issue. The Quad Cities LER considered the safety significance to be higher than that stated in the Dresden LER. The inspectors were concemed about the difference in safety l significance, given the similarities of.the two plants; tin response to the, inspectors'

, concems, the licensee reviewed the, safety significance assigned to the Quad Cities issue and concluded that it was correct. =The licensee also noted that there were some L4 e m = differences between the Dresden and Quad Cities design, which might have contributed to the Dresden station assigning a lower safety significance to the event. This item is j closed.

!' E8.4" - (Closed) LER 50-265/95008-00: 50-265/95008-01: Unit 2 High Pressure Coolant injection - -

Speed, Flow, and Pressure Oscillations. On October 18,1995, during the high pressure

coolant injection monthly surveillance, the Unit 2 high pressure coolant injection system

- was manually tripped from the control room and declared inoperable due to high pressure (- coolent injection flow and discharge pressure oscillations. Additionally, the high pressure l coolant injection steam line to drain pot drain valve A0-2-2301-28 failed, and the control room received a high pressure coolant injection drain pot high level alarm. The licensee effectively addressed the valve failure and high level alarm in a timely manner. However, l the licensee could not immediately identify the cause of the high pressure coolant l- injection system isolations.- After several tests, the high pressure coolant injection system, under certain conditions, continued to experience oscillations. A licensee l

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-investigative team determined that the oscillations associated with this event were caused by the low turbine loading condition which existed due to a change to the high 1 m > pressure coolant injection test flow path. The licensee also reviewed the Unit 1 system to

ensure that a similar problem did not exist. This appeared to be an isolated event. The l ,

n inspectors noted that the corrective actions taken to retum the system to operability and l to understand the cause of the problem were effective.>These items are closed.. \

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E (Closed) LER 50-265/96003-00; Unit 2 Low Pressure Coolant injection Inoperable Due to

' 2D Residual Heat Removal Pump Discharge Check Valve Failure. On November 11,

-1996, the 2D residual heat removal pump discharge check valve,2-1001-67D, failed to close after the # dual heat removal pump shut off. This resulted in a loss of the low

. pressure coolant injection piping fill pressure which caused the low pressure coolant

- injection system to be declared inoperable.. The licensee performed appropriate actions

'to retum the low pressure coolant injection system to operability within the Technical Specification-required time. The investigation into this valve failure, and into numerous failures the licensee had experienced with this valve in the past, discovered a vendor

' defect. Specifically, the chemical cleaning agent the vendor was using during the manufacture of these valves resulted in a poor bonding process between the valve and

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k the rubber sealing surface. The vendor identified several problems with these valves, and coni. squently changed the cleaning process. The licensee replaced the faulty valve with the newer processed valve, and noted no further problems. Additionally, the valve faibres appeared to occur within a 2-year period after installation. Since no other similar valves had failed in a greater than 2-year period, the licenses was confident that the degraded valves were not present in any station system. The licensee performed an evaluation of the rubber which had entered the reactor coolant system following

& degradation, and determined that there were minimal safety consequences as a result of

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+ the foreign material intrusion. ' The inspectors noted that the licensee's investigation into this event was thorough. This item is close ~ E8.6 1(Closed) Unresolved item 50-265/96005-01: Operability of Unit 2 Associated with Comer

- Room Steel Issue. During the May 1,1996, enforcement conference, operability was discussed and the NRC determined that adequate actions had been taken on Quad Cities so that no operability issue existed.,This item is close E8.7 (Closed) Violations 50-254/96005-02f 50-265/96005-02: 50-254/96005-03: '

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- 50-265/96005-03: Design Control and Corrective Action Violations Associated with

. Comer Room Steel. These violations were associated with Enforcement Action 96-114

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m * and only the corrective action violation was actually cited. .The licensee corrected the

. immediate problem and reviewed other outstanding design issues, as discussed in Inspection Report 50-254/96008; 50-265/%008. This item is close '

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' E8.8 ' (Closed) Violation 50-254/96005-04: 50-265/96005-04: Failure to Submit a LER Associated with Comer Room Steel. This violation was associated with -

Enforcement Action 96-114. The licensee verified that its Operability Manual was using

.the latest deportability guidance and provided training to its employees regarding the need

- to report non-conforming conditions. This item is close >

~ E8.9" ,(Closed) Inspection Follow-up Item 50-254/96008-14: 50-265/96008-14: Updated Final Safety Analysis Report Submittal. The inspectors reviewed the Nuclear Tracking System items associated with this issue and performed a limited sample review of the required changes in the UFSAR. The documentation to track the item c'osure was poor, but the actual changes to the UFSAR appeared to have been made. These items are close E8.10 (Closed) Inspection Follow-up Item 50-254/96017-05: 50-265/96017-05:1 Unit 1 and Unit 2

~ Engineering Review of Post Modification Testing. In 1996 the licensee identified an issue regarding improper closure of a modification conducted in11993nThe licensee initiated a review of old design modifications to identify any weaknesses or testing deficiencies. The item remained open pending inspectors' review of the licensee's review. The team analyzed results obtained from the post modification test reviews performed on a random sample of 125 design changes selected from 1980 through November 1996, for failure to test the design basis. The deviations identified produced no plant operability concems, e and a sample expansion was deemed unnecessary. The inspectors noted that the L licensee had conducted a thorough review of the post modification testing progra These items are close x-__ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ _ _ - _ - _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ - _ - _ _ _ _ - _ _ _ _ - _ _ _ _ _ - _ _ .

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l E8.11 Inspection Follow-up Item 50-254/96020-05: 50-265/96020-05: Weak Operability Assessment for the Safe Shutdown Makeup Pump. The inspectors noted that a weak operability assessment had been performed on the safe shutdown makeup pump system when valve motore were identified as undersized. Additionally, the licensee's corrective action system at the time was not properly utilized. Since this inspection report was issued, the system was restored to a fully operable status and the new corrective action

- program implemented. This item is close E8.12 : (Closed) Inspection Follow-up item 50-254/96020-06: 50-265/96020-06: Design Discrepancy with Emergency Core Cooling System Suction Strainers. On

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December 20,1996, a contract engineering firm identified that the emergency core cooling system suction strainers were not built according to design as described in the UFSAR.' Specifically, the analytical model of the installed suction strainer had a higher differential pressure across the strainer at the rated flow than that which was described in q

the UFSAR. This higher differential pressure could affect the net-positive suction head of ,

e the emergency core cooling system equipment:in post' accident conditions. The licensee declared the system inoperable, and performed a subsequent.10 CFR.50.59 analysi ,

iThe evaluation determined that there would be adequate net positive s'uction head for the '

emergency core cooling system pumps in the short and long term. However, the

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inspectors needed to further review the specific values of over pressure assumed in the

~ licensee's 10 CFR 50.59 evaluation. The basis for these values was described in LER 50-254/96025-00;" Unit One Operability Calculations Performed on Emergency Core

. Cooling System Suction Strainers." Therefore, these inspection follow-up items are

- closed. However, the reviews of the 10 CFR 50.59 evaluations will be continue to be j followed through the aforementioned LE I

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E8.13 (Closed) LER 50-254/96021-00: Control Room Heating, Ventilation, and Air Conditioning System Refrigerant Condensing Unit was Declared inoperable Due to a Crankcase

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Heater Power Supply Design Deficiency. This issue was also tracked as an Unresolved

ltem 50-254/96014-04 and 50-265/96014-04 which was closed in inspection Report 50-254/97028; 50-265/97028, Section E.8. This LER is closed based on the inspection efforts described in the aforementioned inspection repo E8.14 (Open) LER 50-254/96025-00

Unit 1 Operability Calculations Performed on Emergency

. Core Cooling System Suction Strainers. This issue was discussed in the closure paragraph for inspection Follow-up Item 50-254/96020-06; 50-265/96020-06, " Design

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. Discrepancy with Emergency Core Cooling System. Suction Strainers."; License personnel l

discussed the status of this issue with the Office of Nuclear Reactor Regulation personnel

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in a teleconference on June 19c.1998.= This item will remain open pending a review of the H original 10 CFR 50.59 evaluation completed by the licensee, and of the 10 CFR 50.59

" evaluation that will be completed after the licensee receives and reviews the new containment over pressure calculations. The second licensee evaluation was scheduled

- for completion on September 30,1998.

L ; E8.15 (Closed) Violation 50-254/97002-04: High Pressure Coolant Injection System Initiation

During Testing. This event was discussed in inspection Report 50-254/98004; l 50-265/98004 and was applicable only to Unit 2 and not to Unit 1. Therefore, this item is administratively close '

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E8.16 (Closed) Inspection Follow-uo item 50-254/97002-05: Weaknesses identified in Scheduling Activities. This event was discussed in inspection Report 50-254/98004; 50-265/98004 and was applicable only to Unit 2 and not to Unit 1. Therefore, this item is administratively close . E8.17 (Closed) Unresolved item 50-254/98004-06: 50-265/98004-06: Emergency Diesel Generator Relay Setpoint. The setpoint for the Time Delay 2 relay initially allowed relay

operation greater than the 15-second maximum time specified by the UFSAR. The

' licensee reviewed the UFSAR basis and found that there was not a true requirement for an upper limit as long as sufficient starting air was being maintained for a second start, which was assured. A revision to the UFSAR was processed. This item is close ' E8.18 (Closed) Unresolved item 50-254/98004-07: 50-265/98004-07: ' Emergency Diesel

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Generator Relay Qualification. The licensee classified the Time Delay 1 and Time Delay 2 relays for the emergency diesel generators as safety-related using a parts evaluatio The authorizing evaluation provided to the inspectors 'as justification for upgrading the commercial grade part to safety-related failed to evaluate the effects 'of environmental factors, including vibration.

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Following surveillance testing failures of emergency diesel generator time delay relays in December 1997 and January 1998, inspectors questioned engineers regarding the qualification of the relays for their operating environment. The failures had resulted from an adverse operating environment, affected by vibration of the relays which were mounted on the emergency diesel generator skid. During the trouble shooting in December and January, the relay manufacturer informed the licensee by phone that use l of the relays in a vibration environment was not recommended. The relays were supplied l under two safety-related stock numbers; St Numbers 254C71 and 794D58. Relays from SI 794D58 were originally purchased from a safety-related supplier.- Relays from

! ' Sl 254C71 were originally purchased as commercial grade parts then dedicated as

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' safety-related parts through the licensee's Part 21 dedication process. The licensee

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provided the inspectors a copy of the authorizing evaluation (M-95-0697 95) as the justification for the upgrade to safety-related classificatio On February 9,1998, following the inspectors' questioning of qualification information which indicated that vibration may not have been addressed, the licensee canceled SI

! Number 254C71 and prevented relays supplied under.this number from.being used in the emergency diesel generators. At that time the only relay with this part number installed in the plant was in the shared emergency diesel generator Time Delay 1 relay location. This

part was later replaced on April 9,1998, with a relay' purchased under the 794D58 stock number. The licensee indicated that the first use of relays in the emergency diesel

!  : generators with the 254C71 part number was in January 1991.

l Criterion Ill, " Design Control," of 10 CFR Part 50, Appendix B states, in part, " Measures

! , shall also be established for the selection and review for suitability of application of

materials, parts, equipment, and processes that are essential to the safety-related functions of structures, systems, and components." It further states

"The design control measures shall provide for verifying or checking the adequacy of design, such as j* performance of design reviews, by the use of altemate or simplified calculational

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methods, or by the performance of a suitable testing program...under the most adverse design conditions."

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Parts Evaluation CE-89-1540 ws.s used to dedicate commercial grade Square D Type EQ 1933G2 re!ays, and established that their use as emergency diesel generator time delay relays Time Delay 1 and Time Delay 2 was a safety-related functio However, the evaluation used to assure the commercial grade time delay relays for the emergency diesel generators would perform their safety function did not evaluate problems with vibration, including that from a seismic event in order to assure that those parts were suitable even under the most severe conditions. Therefore, the use of those relays installed under Part Number 254C71 from January 1991 until April 1998 was a Violation (5%?54/98012-03; 50-265/98012-03) of 10 CFR Part 50, Appendix B, Criterion Ill "usign Control." This unresolved item is close E8.19 (Closed) Unresolved item 50-254/98009-07: 50-265/98009-07: Updated Final Safety

' Analysis Report Discrepancies. During review of LER 50-254/96009; 50-265/96009, the

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. inspectors identified two UFSAR discrepancies regarding second level undervoltage setpoints and minimum running voltage for equipment under degraded voltage conditions.

L Further review of these discrepancies revealed that the licensee had previously identified

! the UFSAR discrepancy regarding second level undervoltage setpointsr This had been

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' documented on Problem Identification Form 97-2058 and was scheduled for resolution by l June 30,1998. The inspectors noted that if the second level undervoltage setpoints were i

' changed using the setpoint change process in place at the time (1996), design basis documents would have been changed at the same time as the plant change and a 50.59

evaluation would have also been performed.. Rather than using Quad Cities Administrative Procedure 0400-03, Revision 3, " Instrument / Equipment Setpoint Change,"

the design engineering department issued a memo to the system protection department requesting relay setting orders, which were subsequently issued on June 13,1996. The l failure to use the setpoint change process to change the second level undervoltage setpoints for Buses 23-1 and 24-1 in June 1996 was considered a l: Violation (50-254/9801244; 50-265/98012-04) of 10 CFR Part 50 Appendix B, Criterion V, " Instructions, Procedures, Drawings."

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- The second UFSAR discrepancy related to minimum running voltage of equipment under

! degraded voltage conditions. In April 1998, during the review of corrective actions for LER 50-25496009, dated June 18,1996, the inspectors identified a UFSAR discrepancy conceming equipment minimum voltage under degraded voltage conditions. The UFSAR

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L Section 8.3.1.8 stated, "... adequate margin exists between the calculated minimum running voltage and tha National Electric Manufacturers' Association standard that minimum voldge be limited to 90 percent of equipment rated voltage."EThe licensee event report stated, " .... some of the loads of the Unit 2 residual heat removal [ service

• water pump room coolers), core spray and emergency diesel generator [ cooling water '

pump room cooler) systems had running voltages less than the 90 percent minimum voltage required by the National Electric Manufacturer's standard MG-1."

The UFSAR also described the residual heat removal [ service water pump room coolers)

and the emergency diesel generator [ service water pump room coolers) systems. The

' UFSAR Section 9.2.1.2 described the residual heat removal service water pump room .

cooler. It stated, " The RHR service water pumps are located in watertight vaults in the turbine building condensate pump room. Each vault has one vault cooler for each pump l

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in the vault. The cooler starts when its associated pump starts. The coolers are designed to maintain the vault at or below 120 degrees Fahrenheit during pump operation with half the tubes plugged."

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I The UFSAR Section 9.5.5 described the emergency diesel generator cooling water pump room cooler, it stated, " A vault cooler is supplied for each DG cooling water pump to prevent the pump motors from overheating. Each cooler maintains vault temperature at or below 120 degrees Fahrenheit during operation of its respective pump. The vault cooler starts when its respective pump starts. Each vault cooler is supplied with cooling

' water from the respective pump's discharge line and the cooling water is retumed to the pump's suction line."

~ The licensee Justified operability of the components with calculated running voltages less than 90 percent but did not perform a safety evaluation under 10 CFR 50.59 for a change to the facility to determine that an unreviewed safety question did not exist. The UFSAR

.was not changed to reflect this plant condition. The licensee had permanently accepted this nonconforming condition but failed to perform the required 10 CFR 50.59 evaluation and update the design basis as described in the UFSAR. The failure to perform a 10 CFR 50.59 safety evaluation for this change to the facility as. described in the UFSAR i was considered a Violation (50-254/98012-05;~ 50-265/98012-05).DA problem identification form (98-02719) was generated on June 2c19_98 after the inspectors raised

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-the issuer The planned corrective actions were to perform the'10 CFR 50.59 evaluation 1 and change the UFSAR E8.20 (Closed) Unresolved item 50-254/97021-01: 50-265/97021-01: Deinerting Containment at Power Bypassed Suppression Pool. As discussed in Inspection Report 50-254/97021;

, . 50-265/97021, the licensee identified provisions from the procedures which had allowed

~ operators to bypass the pressure suppression of the torus pool.' The licensee also identified that a bypass alignment existed briefly during a shutdown of Unit 2 in February of 1997. This was a violation of Technical Specification 3.7.K3 which required that leakage i>etween the suppression chamber (torus) and the drywell to be less than i 'the equivalent leakage through a 1 inch diameter orifice at a pressure of 1 psid. After

. prompting by NRC inspectors, the licensee teported this issue in LER 50-265/97002- 0 This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Polic ~(

Non-Cited Violation (50-254/98012-06; 50-265/98012-06).

E8.21 ; (Closed) LER 50-254/97002: 50-265/97002-00: Unit 2 was shut down, per the ,

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requirements of Technical Specifications 3.5.Asand 3.6.F, because four main steam relief valve closure times did not meet inservice testing program limits.EThe timing ~

1 methodology had changed; however,'the acceptance criteria had not been reevaluate The licensee investigation determined that the acceptance criteria in use were not 7 ' appropriate.- The inspectors concluded that the licensee's corrective actions including

revisions to the acceptance criteria, review of other acceptance criteria, and training of L inservice testing personnel were adequate. This item is closed.

l E8.22 (Closed) LER 50-254/97002: 50-265/97002-01: Unit 2 was shut down, per the

requirements of Technical Specifications 3.5.A. and 3.6.F, because four main steam relief valve closure times did not meet inservice testing program limits. The timing methodology had changed; however, the acceptance criteria had not been reevaluate In addition, the Unit 2 shutdown was required because of a loss of primary containment integrity due to misinterpretation of Technical Specifications resulting in an inadequate procedure. Revision 01 of the licensee event report added a report of one occurrence of torus pressure suppression being bypassed, and identification of the procedures

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permitting this practice. The licensee revised the procedures to eliminate the containment pressure suppression bypass condition. This issue was reviewed in this report and Inspection Report 50-254/97021; 50-265/97021 as Unresolved item 50-254/97021-01; 50-265/97021-01. This item is close IV Plant Support I

~' F2 ' Status of Fire Protection Facilities and Equipment

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F Implementation of Fire Protection Prooram Compensatory Actions

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! Inspection Scope (71707)

The licensee implemented certain compensatory actions inside the facility for known fire protection program deficipacies. ;These: compensatory actions were put in place prior to starting up both units and were to remain in place until modifications 16 the facility were completed. The inspectors reviewed portions of the licensee's fire protection program to l- ensure compensatory actions were properly implemented. The inspectors spoke with,

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and followed,' fire watches during their hourly tours.- The inspectors reviewed various fire l

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watch and operator logs. The inspectors independently toured the affected fire areas and reviewed various correspondence between the licensee and the NRC pertaining to compensatory actions, Observations and Findinas l . The fire watches conducted hourly tours of most accessible spaces in the turbine

' building, reactor building, and other high risk areas. Some inaccessible areas were

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toured by viewing monitors connected to cameras in the affected areas. The fire watches

'were required to monitor for smoke, fire l flooding, and other abnormal conditions during '

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their tours. The licensee also implemented a heightened level of awareness program to j ensure transient combustibles were excluded from certain areas of the facility. The fire

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- watches were observant and knowledgeable of these addsd requirements. Transient

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combustibles identified in these areas were required to be evaluated prior to being allowed into the affected areas and were required to be attended at all times. Tours of

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the facility did not result in identification of any discrepancie j During a review of fire watch logs, the inspectors identified where the Unit 1 "A" residual heat removal service water vault, and both main steam isolation valve rooms were not

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properly classified as required compensatory fire watch areas. However, the areas were l toured by fire watches as part of their routine rounds. These discrepancies did not result in any missed fire watches. The inspectors spoke to both the fire watch supervisors and i the fire marshall about the discrepancies. The discrepancies were appropriately addresse The inspectors also reviewed correspondence from Comed to NRC dated May 22,1998, to ensure fire protection commitments were implemented. The inspectors identified that the May 22,1998, letter contained four errors. Three errors referenced incorrect procedures. The fourth error referenced fire watches as performing twice per shift effectiveness reviews in red striped areas. The twice per shift reviews were actually j

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performed and documented by equipment operators. Regulatory assurance personnel were notified of this deficiency. The licensee revised and resubmitted the I correspondence.

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l Conclusions L - The inspectors identified six administrative problems associated with the fire protection L x compensatory actions but concluded that the regulatory commitments were satisfied.

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The inspectors were concemed with the quality of documentation supporting fire watch logs and the quality of correspondence in the May 22,1998, letter to the NR F8 Miscellaneous Fire Protection issues (92904)

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'F8.1, (Closed) LER 50-254/94014-00: Twelve Instrument Maintenance Department Fire yp Surveillance Not Completed!: On June 9 and July 20,,1994rinstrument maintenance

$% department fire surveillance were deferred until'after the Unit 1 refueling outage was W " complete;c On November 7,"1994, these surveillance were identified as having gone

' past their critical date; As a corrective action to this event, system engineering personnel reviewed all fire system surveillance and identified which items required critical date ~ Additionally, training was provided for instrument maintenance schedulers. These actions

.were appropriate at the time of this licensee event report. The inspectors have observed substantial changes in the scheduling process and in the fire protection program since 1994.3 However, the inspectors have not identified further fire protection surveillance

' which went past their critical date without the appropriate actions taken. - This item is close F (Closed) Violation 50-254/97014-09: 50-265/97014-09: Poor Heater Bay Sprinkler Corrective Actions.' On September 10,1997, fire watches were not implemented to monitor areas with inoperable suppression systems intended to protect safe shutdown equipment. Fire protection impairments in the Units 1 and 2 main steam isolation valve

. rooms and the low pressure /high pressure steam tunnels and heater bay rooms required ,

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that monitoring was necessary. Due to elevated radiation areas, the areas were

' monitored by camera. A camera failure in the Unit 1 steam tunnel combined with inadequate quality on the redundant camera resulted in the required fire watches being

~ missed. ' This camera was subsequently replaced.- The licensee's corrective actions

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ecincluded enhancing the procedure goveming fire watch inspections to clarify expectations

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mwhen unanticipated conditions were encountered.0These contingency. actions were

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vdiscussed with all fire watch personnel, and were incorporated into fire watch trainin 'The' inspectors conducted severalinspections of the fire watch cameras and determined that they were providing good visual quality. Additionally, the inspectors observed fire watch personnel conduct several rounds, and noted that these individuals exhibited good camera use. These items are close V. Mananoment Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the  !

l conclusion of the inspection on July 16,1998. The licensee acknowledged the findings

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presente :

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m PARTIAL LIST OF PERSONS CONTACTED Licensee S. Perry Vice President Comed BWR Group J. Dimmette Site Vice President )

W. Pearce Station Manager M. Stevens Maintenance Manager B. Holbook Engineering Manager G. Powell Chemistry / Radiation Protection Manager (Acting)

J. Walker Quality and Safety Assessment Manager (Acting)

C. Peterson Regulatory Affairs Manager ,

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INSPECTION PROCEDURES USED IP 61726: Surveillance Observations IP 62707: Maintenance Observations IP 71707: Plant Operations 90712 in-Office LER Review

' IP 92700: Onsite Follow-up of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92901: Follow-up - Plant Operations-IP 92902: Follow-up - Engineering IP 92904: Follow-up - Plant Support IP 93702: Prompt Onsite Response to Events at Operating Power Reactors l

ITEMS OPENED, CLOSED, AND DISCUSSED

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Opened 50-265/98012-01 N/A Deleted 50-254/98012-02 VIO emergency diesel generator valve mispositioning

' 50-254/98012-03; 50-265/98012-03 VIO use of relays installed under part Number 254C71 50-254/98012-04; 50-265/98012-04 VIO {

Updated Final Safety Analysis Report discrepancies 50-254/98012-05; 50-265/98012-05 VIO Updated Final Safety Analysis Report discrepancies i 50-254/98012-06; 50-265/98012-06 NCV deinerting containment at power bypassed suppression pool Closed 50-265/90203-01013 VIO nuclear station operator failed to utilize procedures 50-265/90203-01023 VIO inadequate shift briefing 50-265/90203-01033 VIO reactor scram after nuclear station operator failed to i initiate hold )

50-265/90203-01043 VIO nuclear station operator failed to insert source range f monitors at Range 4 i-50-265/90203-01053 VIO - nuclear station operator failed to decrease intermediate range nuclear instruments ranges <

50-254/93019-01 IFl wlicensee action to information Notice 93-33 '

< regarding potential deficiencies of Class 1E qinstrumentatiort and controls cable 50-254/96012-04; 50-265/96012-04 VIO Unit 1 and 2 annunciator procedure not appropriate i to the circumstances

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50-254/96014-01a; VIO failure to follow procedure 50-265/96014-01a 50-254/96014-02 IFl combined intercept valve drifted closed 50-254/96020-02; 50-265/96020-02 VIO

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declining operator performance- '

50-254/97002-01; 50-265/97002-01 VIO Unit i reactor protection system relay problem

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50-254/97002-03; 50-265/97002-03 VIO failure to control turbine building at a negative l pressure 50-254/97006-02; 50-265/97006-02 VIO failure to properly implement test procedure 50-254/97011-03; 50-265/97011-03 VIO valve position verification

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e 50-254/97014-01; 50-265/97014-01 VIO surveillance requirements were not met during reactor modes 50-265/93025-00 LER "A" loop main steam isolation valves exceeded Technical Specifications 50-254/94005-00;50-254/94005-01 LER 1 A main steam isolation valve failed local leak rate test 50-265/94006-00 LER Unit 2 reactor scram when main steam line isolation valves shut 50-254/95001-01 LER during unit startup, reactor core isolation cooling

govemor valve failed 50-254/96006-02; 50-265/96006-02 VIO wrong source range monitor shorting links removed 50-254/96012-06a, 06b, 06c; VIO inadequate procedures 50-265/96012-06a, 06b, 06c 50-254/96014-01b; VIO failure to follow procedure 50-265/96014-01b 50-254/96014-03; 50-265/96014-03 VIO Title 10 CFR Part 50, Appendix B, Criterion 11 Violation 50-265/97014-02 VIO failure to follow procedure 50-265/93022-00 LER emergency core cooling system floor drain check valves inoperable 50-254/94020-05 IFl residual heat removal suppression pool cooling water hammer concems 50-254/95002-00 LER improperly sized overloads found on the control room heating, ventilation, and air conditioning system due to inadequate original design analysis 50-265/95008-00; 50-265/95008-01 LER Unit 2 high pressure coolant injection speed, flow, and pressure oscillations 50-265/96003-00 LER Unit 2 low pressure coolant injection inoperable due to 2D residual heat removal pump discharge check valve failure 50-265/96005-01 URI operability of Unit 2 associated with comer room steelissue 50-254/96005-02; 50-265/96005-02 VIO design control and corrective action violations associated with comer room steel 50-254/96005 03; 50-265/96005-03 VIO . design control and corrective action violations associated with corner room steel 50-254/96005-04; 50-265/96005-04 VIO - failure to submit a licensee event report associated with comer room steel 50-254/96008-14; 50-265/96008-14 IFl Updated Final Safety Analysis Report submittal 50-254/96017-05; 50-265/96017-05 IFl Unit 1 and Unit 2 engineering review of post modification testing 50-254/96020-05; 50-265/96020-05 IFl weak operability assessment for the safe shutdown makeup pump 50-254/96020-06; 50-265/96020-06 IFl design discrepancy with emergency core cooling system suction strainers 50-254/96021-00 LER control room heating, ventilation, and air conditioning system was declared inoperable due to crankcase problems

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50-254/97002-04 VIO high pressure coolant injection system initiation during testing 50-254/97002-05 IFl weaknesses identified in scheduling activities 50-254/98004-06; 50-265/98004-06 URI emergency diesel generator relay setpoint 50-254/98004-07; 50-265/98004-07 URI emergency diesel generator relay qualification 50-254/98009-07; 50-265/98009-07 URI updated final safety analysis report discrepancies 50-254/97021 01; 50-265/97021-01 URI deinerting containment at power bypassed suppression pool

50-254/97002-00; 50-265/97002-00 LER Unit 2 was shut down per Technical Specifications requirements 50-254/97002-01; 50-265/97002-01 LER Unit 2 was shut down per Technical Specifications requirements 50-254/94014-00 LER twelve instrument maintenance department fire surveillance not completed 50-254/97014-09; 50-265/97014-09 VIO poor heater bay sprinkler corrective actions 50-254/98012-06; 50-265/98012-06 NCV deinerting containment at: power bypassed suppression pool Discussed 50-254/97002-06; 50-265/97002-06 IFl Instrument calibration program weaknesses 50-254/96025-00 LER Unit 1 operability calculations performed on l emergency core cooling system suction strainers l

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LIST OF ACRONYMS AND INITIALISMS USED CFR Code of Federal Regulations Comed Commonwealth Edison Company IDNS lilinois Department of Nuclear Safety lEEE Institute of Electronic and Electrical Engineers IFl Inspection Follow-up Item LER Licensee Event Report PDR Public Document Room UFSAR Updated Final Safety Analysis Report URI Unresolved item VIO Violation

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