IR 05000341/1997014

Insp Rept 50-341/97-14 on 970923-1107.Violations Noted.Major Areas Inspected:Operations,Maint,Engineering & Plant Support

ML20216J469
Person / Time
Site:	Fermi
Issue date:	01/02/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20216J432	List: IR 05000341/1997014 ML20216J429 ML20216J453
References
50-341-97-14-01, 50-341-97-14-1, NUDOCS 9804210391
Download: ML20216J469 (26)

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U.S. NUCLEAR REGULATORY COMMISSION REGION 3 Docket No.: 50-341 License No.: NPF-43 I l

i l Report No.: 50-341/97014(DRP)

Licensee: Detroit Edison Company (DECO)

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Facility: Enrico Fermi, Unit 2 Location: 6400 N. Dixie Hw Newport, MI 48166 Dates: September 23 through November 7,1997 l

Inspectors: G. Harris, Senior Resident inspector C. O'Keefe, Resident inspector i G. Cashatt, Technical Training Specialist

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Approved by: Bruce L. Burgess, Chief Reactor Projects Branch 6

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9004210391 900102 ?

gDR ADOCK 05000341 f PDR f

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l EXECUTIVE SUMMARY Enrico Fermi, Unit 2 NRC inspection Report 50-341/97014(DRP)

This inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a six-week period of resident inspection. During this period, the plant was shut down for a sixteen-day mid-cycle outage and started up again without any personnel errors. Major outage work included sipping the entire core, replacement of two leaking fuel bundles, safety relief uwe replacement, and performance of various surveillance test Operations e The inspectors concluded that operators continued to exhibit improved performance in l monitoring plant conditions. Personnel on rounds continued to be effective in identifying ;

and reporting problems. Supervisory presence in the field for operations increased, partly !

as a result of having reduced the administrative burden in the control room. Inspectors identified concems with a repeat problem involving inadvertent deenergization of equipment, and lack of documentation of entries into allowed Technical Specification (TS)

exceptions with limited time duration. (Section 01.1)

e Both startup and shutdown evolutions were performed smoothly and without erro Licensed operator trainees in the control room were properly supervised and contributed positively to crew performance. Briefings were frequent and effective. (Section 01.2)

e The reactor vessel pressure test at the conclusion of the mid-cycle outage was performed expeditiously in a coordinated and controlled manner. Preparations, particelarly the use of the simulator, were effective in minimizing the time spent with shutdown cooling secured during a relatively high decay heat condition. However, the inspectors concluded that distractions from the test were not effectively minimized in the control roo (Section 01.3)

• The licensee identified that operators violated a TS required situational surveillance check of electrical power source operability, when it was completed nine minutes late. This TS violation is of additional concem because it is similar to a recent failure to verify electrical power availability documented in Inspection Report 50-341/97007. Prompt corrective actions significantly raised the visibility of TS actions among operators. (Section 01.4)

e The licensee was able to reduce the number of Limiting Condition for Operations (LCOs)

entries by maintaining good equipment performance and by operations staff actively pursuing resolution of all LCO issues and holding organizations accountable for timely resolution. (Section O2.1)

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Maintenance l e The inspectors identified that the standby liquid control system configuration challenged l operators while performing surveillance testing, and that the high pressure coolant

! injection surveillance test procedure did not include guidance to pump down the

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EXECUTIVE SUMMARY Enrico Ferml, Unit 2 NRC Inspection Report 50-341/97014(DRP)

l This inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a six-week period of resident inspection. During this period, the plant was shut down for a sixteen-day mid-cycle outage and started up again without any personnel errors. Major outage work included sipplag the entire core, replacement of two leaking fuel bundles, safety relief valve replacement, and performance of various surveillance test Operations

• The inspectors concluded that operators continued to exhibit improved performance in monitoring plant conditions. Personnel on rounds continued to be effective in identifying l and reporting problems. Supervisory presence in the field for operations increased, partly l

as a result of having reduced the administrative burden in the control room. Inspectors identified concems with a repeat problem involving inadvertent deenergization of equipment, and lack of documentation of entries into allowed Technical Specification (TS)

exceptions with limited time duration. (Section 01.1)

e Both startup and shutdown evolutions were performed smoothly and without erro Licensed operator trainees in the control room were properly supervised and contributed positively to crew performance. Briefings were frequent and effective. (Section 01.2)

e The reactor vessel pressure test at the conclusion of the mid-cycle outage was performed

[ expeditiously in a coordinated and controlled manner. Preparations, particularly the use ,

of the simulator, were effective in minimizing the time spent with shutdown cooling I secured during a relatively high decay heat condition. However, the inspectors concluded j that distractions from the test were not effectively minimized in the cuatrol roo j (Section O1.3)  ;

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o The licensee identified that operators violated a TS required situational surveillance check '

l of electrical power source operability, when it was completed nine minutes late. This TS i

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violation is of additional concem because it is similar to a recent failure to verify electrical power availability documented in inspection Report 50 341/97007. Prompt corrective actions significantly raised the visibility of TS actions among operators. (Section 01.4)

! * The licensee was able to reduce the number of Limiting Condition for Operations (LCOs)

entries by maintaining good equipment performance and by operations staff actively pursuing resolution of all LCO issues and holding organizations accountable for timely ,

resolution. (Section O2.1)

Maintenance l e The inspectors identified that the standby liquid control system configuration challenged operators while performing surveillance testing, and that the high pressura coolant injection surveillance test procedure did not include guidance to pump down the

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suppression pool. Coordination of switchyard maintenance with offsite personnel, though improved over the last several months, continued to need additionalimprovemen (Section M1.1)  ;

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e The mid-cycle outage was planned in greater detail than past outages, resulting in better l reviews, more complete preparations, and few schedule-related problems. Problems !

observed during the previous refueling outage were observed to have been effectively J

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corrected. Teamwork and coordination were evident in identification of equipment problems and performance of refueling floor activities. Outage management personnel effectively communicated the results of risk analyses to the entire site. These improvements resulted in completing an aggressive outage schedule slightly ahead of schedule with a minimum of problems. (Section M1.2)

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• The inspectors were concemed that the licensee did not formally evaluate and document l

the operationalimpact of the potential failure of selected solenoid operated valves

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remaining in service. Consequently, the licensee implemented additional measures to periodically verify operability of the affected valves. The licensee's corrective action of increasing surveillance of selected systems was acceptable. (Section E1.1)

Plant Support e The inspectors did not identify any specific issues in the area of plant support.

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I Report Details

' Summary of Plant Status The plant began this inspection period at 92 percent power. Power was reduced to 57 percent on September 24-26 for flux suppression testing in response to a second fuel leak. A pinhole leak was determined to exist in a bundle in the center cell, and one control rod was inserted to locally suppress power. Power was retumed to 93 percent until the plant was shut down on October 3, for a planned mid-cycle outage. The outage was initiated to sip the entire core, replace leaking fuel bundles, replace and test safety relief valves, and perform a number of surveillance tests to support extending the date of the next refueling outage. The plant was restarted slightly ahead of schedule on October 17 and the generator was synchronized to the grid on October 19. The plant was operated at or near 96 percent power for the remainder of the

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inspection period, except for a brief power reduction during October 28-29 to repair several hot spots on 345 kV switchyard bus connections.

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l. Operations 1

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I 01 Conduct of Operations I 01.1 Conduct of Operations - General Comments l Inspection Scope (71707)

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Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing I plant operations in the control room and in the fiel i Findinas and Observations The inspectors noted that Nuclear Shift Supervisors (NSS) were active in observing plant conditions and work in progress throughout the outage. On a number of occasions, the NSS identified equipment problems during tours. The inspectors noted that supervisory l tours were a direct benefit to the shift, and were a positive result of having reduced the

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administrative burden in the control room when most work control activities were assumed by the Work Control Nuclear Assistant Shift Supervisor (NASS). Also, the j licensee improved work coordination and allowed the NSS to become familiar with the l status of work and plant conditions by assigning NSSs to spend their first day back from

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time off working in the outage management conference room.

t I The inspectors noted during tumover briefs and through reviews of Condition ( Assessment Resolution Documents (CARDS) and logs that operators and other licensee personnel on rounds were effective in identifying problems in the plant. For example, a non-licensed operator identified a low temperature condition associated with an idle chiller in the control center heating, ventilation, and air conditioning (CCHVAC) syste The system was promptly declared inoperable and a faulty temperature switch was repaired. In another example, a radiation protection (RP) technician on rounds reported that the primary containment atmosphere monitoring system pump was making an abnormal sound. The pump was promptly declared inoperable and repaire Throughout the outage, the licensee staff identified equipment problems effectively. This is further discussed ir. Section M ,

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The inspectors identih wo i7tances where operators entered TS exceptions with specific time frames withM accumenting the entry. During the plant shutdown on October 3, the inspectors observed that the licensee began de-inerting primary containment with the reactor operating above 15 percent power. Technical Specification 3.6.6.2, applicability statement B, allowed the licensee to de-inert primary containment within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> before reducing power below 15 percent.' The inspectors observed that this limited time exception was entered but not noted in the logs or on a limiting condition for operations (LCO) sheet. Additionally, on October 11, the inspectors noted that the operators swapped divisions of shutdowrt cooling. An exception to TS 3.9.11.2 allowed removing the shutdown cooling pump from operation for up to two hours per eight hour period. Again, this limited time TS action was not documented. The inspectors were concemed that these TS entries into allowed exception conditions with specific time frames were not adequately documented to allow tracking. This issue will be tracked as an inspection followup item pending inspector review of licensee actions in response to these observations. (IFl 50-341/97014-01)

On October 7, operators inadvertently deenergized the west station air compressor,

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necessitating entry into the abnormal operating procedure for loss of station air. Prompt -

operator actions avoided unacceptably low air pressure. Operators wrote CARD 97-11186 to document the event and track corrective actions. The licensee concluded that the load list had not been properly updated to clearly list the compressor when it was installed in August 1996. The inspectors noted that this was similar to i previous problems with inadvertent deenergizing loads that occurred during motor control I center fused disconnect switch lubrication efforts in March-April 1997. The licensee !

instituted similar corrective actions for both events. The method used by operators to j determine the impact of opening a breaker or switch relied upon limited review of i l documentation that included incomplete information. For the instances referred to, a!I l unintentionally deenergized equipment was non-safety related. This will be tracked as an !

inspection followup item pending further inspector review of the adequacy of load list l documentation and operator practices in preparing for electrical outage l (IFl 50-341/97014-02) l The inspectors reviewed Operations Night Orders and noted that several entries had i'

l been in active status for a number of days. Operations administrative guidance suggests l that active night orders should normally be in effect for up to 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br />. The inspectors l discussed their observations with operations management who stated that additional guidance was needed to clarify management expectations. The inspectors reviewed the night orders and noted that although most had exceeded the 96 hour0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> period, no operational impact was eviden c. Conclusions l The inspectors concluded that operators continued to exhibit improved performance in monitoring plant conditions. Personnel on rounds continued to be effective in identifying and reporting problams. Supervisory presence in the field for operations increased, partly as a result of having reduced the administrative burden in the control room. Inspectors identified concems with a repeat problem with inadvertent deenergization of equipment

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and lack of documentation of entries into allowed TS exceptions with limited time duratio ,

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O1.2 Shutdown and Startuo Observations inspection Scope (71707. 71711)

The inspectors observed briefings and various plant evolutions associated with the l shutdown and subsequent startup from the mid-cycle outage, both in the control room and in the field, ] Observations and Findinas During the plant shutdown process, the inspectors observed that operators effectively briefed each significant evolution. The shutdown schedule included ample time for each evolution. Trainees performed many of the control room operations with qualified operator supervision. Reactivity controls were notably formal and controlled Procedure use and adherence was eviden Similarly, the inspectors observed a careful and deliberate startup without any personnel errors. The ir.spectors observed that the licensee appropriately decided to discontinue the approach to criticality when it became clear that criticality would have been achieved close to shift tumover time. Rod withdrawal was also conservatively stopped while a process computer problem was corrected. The approach to criticality was observed to be cautiou The inspectors noted that control room operators exhibited an excellent questioning I attitude and took their time during both startup and shutdown. No schedule pressure was I apoarent during shutdown or startup. The inspectors considered that the presence of i licensed operator trainees participating in control room operations for the first time during l these evolutions contributed positively to crew performance. The inspectors observed !

excellent trainee control and formal communications. The NSS and NASS clearly stated j their expectations in this regard, and were observed to be prompt in correcting any '

l deviations from these standards. Licensee senior management was present during both plant startup and shutdown, in addition, Nuclear Quality Assurance (NQA) provided i extensive plant restart coverag ;

' Conclusions Both startup and shutdown evolutions were performed without error. Licensed operator trainees in the control room were properly supervised and contributed positively to crew performance. Briefings were frequent and effectiv .3 Reactor Pressure Vessel (RPV) Pressure Test Observations Inspection Scoce ( 71707. 61726 )

The inspectors reviewed Infrequently Performed Test / Evolution 97-05, 'RPV Pressure ,

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Test Following the October 1997 Fuel Inspection Outage," and associated Safety Evaluation 97-0117. The inspectors then observed the briefing and performance of the RPV pressure test on October 1 l; l

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in preparation for the outage, the licensee recognized that plant conditions would be more challenging than during a normal refueling outage. The core decay heat load was expected to be relatively high because almost no fuel was expected to be replaced and l because of the short outage length. As a result of the higher decay heat load, the plant conditions required for the RPV pressure test after reassembling the reactor vessel were examined in detail to ensure they could be satisfied throughout the tes In order to avoid the possibility of an inadvertent change of operational mode due to heatup during the test, which required securing shutdown cooling flow, a number of changes were made to the process. The licensee obtained the Office of Nuclear Reactor Regulation (NRR) approval of new special test exception (TS 3.10.7) to allow plant temperatures of up to 212'F during the test. Also, NRR approved a relief request to allow testing at reduced pressure. Finally, the licensee revised the test procedure based on simulator testing and predictive modelin Simulator testing was performed to allow operators to become proficient with the use of the procedure, to test procedure enhancements based on the results in the simulator, and to determine the time required to perform the test. The same operators were then assigned to perform the actual test in the plant. Improved methods of plant temperature ,

control and higher fill rate were successfully validated ir; the simulato The inspectors observed that the actual test was well-briefed. Staffing for the test was I appropriate. Coordination was very good among groups involved which allowed the time spent with shutdown cooling secured to be minimized. Throughout the test, the inspectors observed that engineering personnel constantly verified that plant response matched predicted value Licensed operators were distracted by several balance of plant annunciators which were received repeatedly. When the NASS permitted the repetitive alarms to be left flashing, operators had to use the Sequence of Events Recorder to determine the source of new alarms because up to seven annunciators were already flashing. Also, just after reaching test pressure, a licensed operator not associated with the test conducted two I switchyard breaker manipulations. This was done without a control room briefing and !

required the attention of the NASS at a time when the test in progress was at its most j important stage. The inspectors concluded that these distractions were not effectively i minimize I c. Conclusions The RPV pressure test was performed expeditiously in a coordinated and controlled I manner. Preparations were effective in minimizing the time spent with shutdown cooling !

secured during a high decay heat condition. However, the inspectors concluded that I control of annunciators and performing switching operations during this brief test

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distracted control room operators from the tes !

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! 01.4 Missed TS Situational Surveillance Reauirement

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l Inspection Scope (71707)

l l The inspectors performed an independent followup on the licensee's self-identified violation of a TS situational surveillance requirement. The inspectors reviewed corrective actions for the event with senior plant management, and attended small group sessions for operator Findinas and Observations l

l On September 25, the licensee declared Emergency Diesel Generator (EDG) 14 l inoperable due to minor load oscillations observed during surveillance testing. Technical l Specification 3.8.1.1.b, required that with one EDG inoperable, the remaining offsite

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power sources must be verified to be available every eight hours. However, on l

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September 27, the licensee identified that operations personnel failed to complete this verification until eight hours nine minutes after completing the previous check. A prompt critique determined that the situational surveillance was discussed at the shift tumover l briefing, assigned to a specific licensed operator, and scheduled to be completed an hour I

early. The licensee determined that the assigned operator forgot, and there was no l backup by other members of the shift until five minutes before the verification check was

due. This event was of additional concern due to an recent, similar, violation of l TS 3.8.1.1.b. The circumstances of the earlier violation were discussed in inspection Report 50-341/97007. Failure to perform verification of the availability of offsite power l was a violation of TS 3.8.1.1.b. (VIO 50-341/97014-03)

l l In response to this event, senior licensee management promptly conducted small group sessions with all operators to discuss performance and responsibilities in regard to I

assuring TS compliance. Management expectations and regulatory requirements were clearly presented. The inspectors observed excellent participation by all present and noted that operators provided many suggestions for improving performance and tracking of TS actions.

Among the measures implemented was a shiftly " reflection time" meeting. Midway l through each shift, as a group, the entire operating shift reviewed important work in l progress or planned for the remaining part of the shift for TS impact. The inspectors l observed several of these meetings and determined that the intended focus on TS actions was effectively achieved. The meetings also had the benefit of involving the non-

licensed operators in TS issue The inspectors also determined that shift tumover briefs were more complete in their discussion of LCOs which were in effect and were better in ensuring that situational i surveillance requirements were discussed. However, the inspectors identified that l tumover briefing discussions of LCOs did not include the actions required in many cases.

l This was often done at the more focussed reflection time meetings.

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l Additionally, the licensee modified the software on personal computers used for log taking to include a user-set alarm program for reminding operators of situational surveillances with short time ch. ration (

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Conclusions The inspectors concluded that the licensee took prompt corrective actions for the missed TS verification requirements. The involvement by senior management in the small group I

, sessions and the solicitation of suggestions added to individual buy-in by operator Prompt corrective actions significantly raised the visibility of TS actions among operator Operational Status of Facilities and Equipment O Enoineered Safety Feature System Walkdowns (71707)

The inspectors used inspection Procedure 71707 to walk down accessible portions of the following Engineered Safety Feature systems:

l e Standby Liquid Control System

! e Standby Feedwater l e EDG 11,12,13 and Support Systems e 130/260V Battery Support Systems l

l e Reactor Protection System Power ,

l e Combustion Turbine Generator (CTG) 11-1 l l e Emergency Equipment Cooling Water System l

Equipment operability, material condition, and housekeeping were acceptable in all cases. Several minor discrepancies were brought to the licensee's attention and were corrected. The inspectors identified no substantive concems as a result of these walkdowns.

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! ' The licensee continued work to improve the reliability of CTG 11-1. Because this station l blackout generator was out-of-service for several months, the licensee installed a i l temporary modification to provide blackstart capability to the other CTGs and stationed a - !

full-time operator at the CTG yard. Additional operators were also assigned to support l l

work on CTG 11-1. Licensee management was sensitive to this manpower drain on )

operations, and increased oversight of the project. At the conclusion of this inspection period, the licensee began a series of 50 runs of CTG 11-1 to demonstrate reliability of the machine, which was expected to last a few weeks.

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l Equipment performance was good following the outage. The licensee was able to l maintain TS related equipment in service, resulting in a very low number of LCOs each l i day. The inspectors noted that this improved performance was due to operations i personnel actively pursuing resolution of all LCO issues and holding organizations

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accountable for timely resolutio Miscellaneous Operations issues (92700; 92701)

l 08.1 (Closed) Licensee Event Report 50-341/96002: Engineered Safety Feature actuation of torus to drywell vacuum breakers due to improper system lineup. An operator used the wrong hydrogen recombiner system lineup during a surveillance test such that drywell gases were pumped to the torus until a vacuum breaker actuated. This was not immediately recognized because no alarm function is associated with the vacuum ;

breakers, so two actuations occurred. The cause was personnel error due to inattention

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! to detail by the operator. Additionally, the licensee determined that the procedure was not human-factored wellin defining preferred and non-preferred lineups. System l Operating Procedure (SOP) 23.409, " Thermal Recombiner System," was revised to l

improve human factoring and clarity. Training was completed on the event and the l operator received discipline. The inspectors verified that training was completed and that l SOP 23.409 was revised to clarify the normal and emergency system lineups. Corrective i actions appeared to be adequat The licensee's analysis of this event identified that the operator inadvertently established a system lineup that created a suppression pool bypass leakage path for approximately one hour, in the event of a loss of coolant accident, steam in excess of that allowed in the Updated Final Safety Analysis Report (UFSAR) could bypass the normal blowdown path to the torus and fall to be condensed. The hydrogen recombiner system piping was 4 inch piping, but TS 3.6.2.1.b, required that the total leakage between suppression chamber and drywell be less than the equivalent of a one inch orifice at 1 psid. The

inspectors determined that the safety significance of the additional bypass leakage flow area for the brief period it occurred was minor because it remained within the UFSAR analyzed maximum allowable bypass leakage area of a 7 inch pipe. Failure to meet the l requirements of TS 3.6.2.1.b, was a violation. However, this non-repetitive, licensee-identified and corrected violation is being treated as a non-cited violation (NCV),

consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-341/97014-04)

08.2 (Closed) Violation 50-341/96002-01: Failure to follow hydrogen recombiner system operating procedure (SOP). This item is discussed in detailin Section 08.1. Corrective actions appeared adequate to prevent recurrence. This item is closed.

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08.3 [ Closed) Violation 50-341/94016-01: Failure to verify attemate decay heat removal method. Operators failed to recognize that removal of a residual heat removal service water pump from service necessitated entry into a TS-required situational surveillance to

verify availability of an alternate decay heat removal method within one hour and every 24 l hours tiareafter. The safety significance of the event was low because reactor decay heat was very low at the time, and alternate methods of decay heat removal were available. The NSS and NASS involved were removed from shift duties, counseled, and were as',igned to conduct training for operators on the event. The event was caused by three licensed operators relying on memory to determine the applicable TS actions required, with each incorrectly concluding that no action was required. In response to this l event, the licensee formed the Operations Work Control Group to ensure appropriate categorization of work documents regarding TS impact during the work planning stages, which would then be verified by the operating shift when work was approved to start.

. Shift technical advisors were added to the review chain for final approval of work. Plant l management communicated expectations for operator communications and TS impact reviews to all operations personnel. Corrective actions were completed and considered adequate. This item is closed.

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08.4 (Closed) Licensee Event Report 50-341/94008: Failure to verify altemate decay heat removal method. This was submitted as a voluntary licensee event report. This item is discussed in Section 08.3. Corrective actions appeared adequate. This item is close ,

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l 08.5 (Closed) Inspection Followup Item 50-341/94016-04: Performance of troubleshooting and corrective maintenance during surveillance activities. Inspectors identified that numerous fastener prob! ems were identified and corrected in the source range / intermediate range monitor cabinet during a surveillance test as a result of on the spot troubleshooting. The condition was later evaluated and reported as being outside the design basis of the plant because the seismic qualification was not maintained with the loose fasteners, for which an NCV was later issued. This licensee-identified example of loose fasteners involved several process radiation monitoring instrumentation cabinets, and each cabinet's fasteners were subsequently corrected through an appropriate work request. The inspectors reviewed troubleshooting procedures, observed troubleshooting in the field, and discussed troubleshooting practices with various plant personnel. The inspectors l also reviewed numerous closed work packages. No additional examples of troubleshooting or corrective maintenance during surveillance activities were identifie The inspectors concluded that procedures goveming troubleshooting clearly required separate approval and documentation. Based on the correction of the original loose fasteners issue and lack of additional occurrences, this item is close .6 (Closed) Licensee Event Report 50-341/97012-00: Automatic reactor scram on high I scram discharge volume during shutdown conditions. A licensed operator performing a surveillance procedure prematurely reset a manual scram without referring to the scram abnormal operating procedure, which caused an unplanned scram when the scram discharge volume subsequently filled up. All control rods were already fully inserted at the time of the event. Training was conducted for all operators on this event, and the operator involved received discipline. The inspectors verified that training was completed. In addition, the licensee added steps to the surveillance procedure (24.623)

to ensure the scram was properly reset per Procedure 23.610, " Reactor Protection Sysiem (RPS)." This item is close .7 (Closed) Violation 50-341/96013-01: Failure to follow procedures for resetting a reactor scram resulted in an unplanned scram. This event is discussed in Section 08.6. This item is close .8 (Closed) Violation 50-341/96002-04: Improper retum of EDG 14 to a standby conditio This event was caused by improper independent verification and failure to list all components out of the standby lineup on the tagout sheet restoration section. The licensee conducted training on the event, proper methods for performing independent verification, and proper methods for equipment removal and retum to service. This training included practical demonstrations. Additionally, operations management created the position of shift foreman to provide increased oversight of non-licensed operators by a licensed operator. The foreman was expected to brief each job when assigned. The inspectors reviewed the event critique and corrective actions. Based upon the corrective actions and lack of repeat problems in equipment restoration, this item is close .9 ' Closed) Inspection Followup Item 50-341/97002-03: Troubleshooting practices prior to writing a work request. The inspectors were concemed with the variety of methods of implementing troubleshooting under the Conduct of Operations administrative procedure, and with the lack of documentation for troubleshooting activities. The licensee revised Operations Conduct Manual Procedure 04 to add additional requirements for documentation of the planned steps before perform!ng any troubleshooting activity. The inspectors noted that this was applied to troubleshooting conducted by all personnel, not

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Just to operations personnel. The completed troubleshooting document was retained as part of the CARD reporting the problem and listed as a reference in any work requests initiated to correct the problem. The inspectors reviewed several completed troubleshooting packages, and noted that checks and approval were clearly documente The inspectors observed that operations, maintenance and system engineering personnel l involved in recent troubleshooting efforts used the new method, and were enthusiastic j about the process and results. The inspectors did not identify any other concerns. This l

item is closed.

l l 08.10 (Closed) Violation 50-341/96016-02: Operators did not adequately respond to high level i

in the fuel pool. Operators did not verify that the fuel pool manual fill valve was shut, as I

required in the annunciator response procedure, because they had not ordered it open during their shift. The valve was found to be two tums open after the fuel pool started overflowing into ventilation ducts. Operators were trained on this event, including management expectations for annunciator response, to stress the need for determining I

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the cause of alarms and ensuring that the steps taken in response correct the conditio l The inspectors observed improved annunciator response during routine control room i observations and verified that training was completed. This item is closed.

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! M1 Conduct of Maintenance I

l M1.1 General Comments 1 i

3 Inspection Scope (62707)

The inspectors observed all or portions of the following work and surveillance activities.

Work practices and procedure adherence were assessed. Tagout isolation and ,

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administration were observed and reviewed. Radiological work practices and RP support of work were observed. Work packages were reviewed for completeness and adequacy as well as plant impact and TS action implementation requirements. Surveillance procedures were reviewed and compared to TS, the UFSAR, and system design basis - ,

documentation to ensure requirements were being properiy teste i e Troubleshooting of Reactor Water Cleanup Pump B e Scram Time Testing of Control Rod Drives e Shutdown Margin Surveillance Testing e in-core Sipping and Vacuum Sipping of Fuel Bundles e Reactor Vessel Head Tensioning Activities e Bus 72EC Undervoltage Surveillance Testing e Safety Relief Valve Surveillance Testing e Drywell-Torus Vacuum Breaker Operability Surveillance Testing l

e Control center heating, ventilation, and air conditioning (CCHVAC) Duct

, LeakageTesting l e Flux Suppression Testing l e Emergency Diesel Generator (EDG) 14 Governor Troubleshooting l

• High Pressute Coolant injection (HPCI) Pump and Valve Operability Surveillance e Preheater Drain Cross-Tie Valve Repairs e Logic System Functional Test of Bus 72EA and 72EB Undervoltage Circuits

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e Feedwater Suction Strainer Inspections e Reactor Pressure Vessel (RPV) Testing

• Core Shutdown Margin Verification e Corrective Maintenance Breaker Disconnect Hot Spot Repairs I e Standby Liquid Control (SLC) Pump and Valve Operability Surveillance Test

• Emergency Diesel Generator (EDG) 11 Surveillance Test e General Service Water Sluice Gate Repairs l

• Emergency Diesel Generator (EDG) 12 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> run e Control Rod Drive Housing Support Visual inspection e Control center heating, ventilation, and air conditioning (CCHVAC) Chlorine Detection Division 1, Channel Functional Test

• Shutdown Margin Verification Testing

• Control Rod Scram Time Testing e Combustion Turbine Genemtor (CTG) Ground Isolat!on Troubleshooting '

I b. Observations and Findinas l

The inspectors noted an increased questioning attitude among maintenance workers during this inspection period. Workers increasingly utilized the CARD process to report problems that were not directly related to the work in progres While observing the SLC pump and valve operability surveillance, the inspectors noted that the system configuration complicated test performance. The valve throttled to control pressure was located 15 feet above the pumps. The gauge used for setting the throttle valve could not be seen by the operator, so a second operator reported pressure readings to the operator on a ladder. However, as the pressure increased, the pump noise and throttling noise increased to the point where communications became difficul Also, the inspectors noted that operators were unable to properly set up the step laddor used because the "A" pump prevented using all four legs. The ladder was propped against a concrete lip at the bottom and leaned against a pipe support at the top. Also, I the length of the ladder made it difficult for the operator to reach the valve l l

During the HPCI Surveillance (24.202.01) on September 29, the inspectors noted that operators operated the torus water management system to pump down the suppression pool at 450 gpm in order to maintain suppression pool level within TS level limits with the HPCI system running. The inspectors were concerned that HPCI valve seat leakage could be contributing to the suppression pool water input. The inspectors discussed this observation with a performance engineer, who was able to demonstrate by rough .

calculation that the steam input to the torus closely matched the pumpdown rate, so valve l seat leakage into the torus was unlikely. However, the inspectors noted that  :

surveillance 24.202.01 did not specify running the torus water management system in I order to control suppression pool water level. The inspectors also noted that the surveillance test was delayed two hours because test equipment problems were not ,

identified until just before the test was to star J During routine oil analysis on EDG 12 following a 41 hour4.74537e-4 days <br />0.0114 hours <br />6.779101e-5 weeks <br />1.56005e-5 months <br /> surveillance run, the licensee identified a marked increase in the severe wear index for the outboard generator bearin l Vibration monitoring and temperature trending for the bearing indicated normal bearing ;

performance. The licensee conducted a bearing inspection with the vendor present and !

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conservatively decided to replace the bearing due to observed minor but unexpected l

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! wear, even though the bearing had only accumulated about 100 run hours since it was l last replace During the mid-cycle outage, the licensee was able to correct a number of challenges to operators, including replacing the seal on the "A" reactor recirculation pump, several control rod position indication probes, and Intermediate Range Monitor "F." However, the licensee did not correct seat leakage in the reactor water cleanup blowdown valve, so operators continued to respond to repeated high pressure alarms for the blowdown lin Also, the south reactor water cleanup pump seal and impeller wem replaced during the outage, but pump problems continued to challenge operators. The pump capacity was reduced, and the seat was running above its alarm temperature. Shortly after the alarm setpoint was raised, the temperature indication failed. System engineering and ,

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maintenance personnel continued to work to resolve these issues at the conclusion of '

this inspectio '

Following generator synchronization at the conclusion of the outage, the licensee identified that several of the high temperature connections in the Division 2,345 kV switchyard were still present. A licensee investigation revealed that offsite personnel assigned to refurbish the connections had only worked connections with more than 1 mV drop for an applied 100 amp current. As a result, the licensee reduced power on  !

i October 28-29 in order to correct the remaining high temperature connections. The '

l licensee determined that inadequate control of work between the site staff and offsite work group contributed to workers deciding the connections were acceptable even though they had been identified as operating at high temperature under load. As discussed in l

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inspection report 50-341/97013, coordination of switchyard maintenance with offsite ,

organizations had improved over the last several month !

l While observing leakage testing of CCHVAC ductwork on October 6, the inspectors l observed that test engineers did not comply with work request precautions. Specifically,

! Work Request 000Z971023 directed workers to hang a safety caution sign over open duct access plates and reinstall access plates when work was delayed or stopped. The inspectors observed that signs were not hung and access plates were not reinstalled

during work stoppages until the omissions were pointed out by the inspectors. These l l deficiencies were observed to have been corrected during subsequent observations of l the work. During testing, the licensee identified that one of the dampers tested had a loose set screw on the positioner. The inspectors observed that the licensee promptly inspected all appropriate system dampers and did not identify any similar problem The inspectors reviewed documentation from the recent turbine building heating, l ventilation, and air conditioning (HVAC) system outage. The non-safety system outage was terminated when excessive temperatures were identified in the turbine building

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sicam tunnel area. Later, as a result of inspector questioning, the licensee determined

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that cesistance temperature detectors used to provide a Main Steam isolation Valve (Group I) closure were affected by the high temperatures. An operability evaluation by

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the licensee determined that the original environmental qualification life of the j components had been considerably shortened as a result of operating at higher ambient temperatures than analyzed. In response, the licensee performed additional analysis that demonstrated that the affected components remained operable with a reduced life. At the inspectors' request, NRR reviewed the licensee's operability evaluation and agreed with the licensee's operability conclusion. The inspectors further reviewed a safety 14 . , . , . ,

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evaluation for the high temperatures in the turbine building. The inspectors notod that the safety evaluation did not recognize that safety-related equipment in the turbine building could be adversely affected by 'he high temperatures. The licensee agreed with this observation and corrected the evaluation. The licensee also agreed with the inspectors' conclusion that additional emphasis is needed in the assessment of operational and safety impact resulting from non-safety system outages. The 4

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inspectors will follow the licensee's corrective actions to address the assessment of non-safety system outage impact. (IFl 50-341/97014-05) Further discussion on the conduct l of maintenance activities can be found in Section M1.2, I Conclusions

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The licensee improved plant material condition and corrected a number of operator l challenges due to equipment problems. However, several equipment-related challenges i remained. The inspectors identified that the SLC system configuration challenged i l

operators while performing surveillance testing and that the HPCI surveillance test !

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procedure did not include guidance to pump down the suppression pool despite the .

significant inventory added to the pool. Coordination of switchyard maintenance with l offsite personnel, though improved over the last several months, continued to need I additional improvemen The inspectors noted that during the turbine building HVAC system outage, turbine j building temperatures rose to within 10 degrees of the trip setpoint for Main Steam i l Isolation Valve (Group 1) closure. The licensee also agreed with the inspectors'

conclusion that additional emphasis was needed in the assessment of operational and safety impact that result from non-safety system outages. This will be tracked as an inspection followup item pending further review of corrective action (IFl 50-341/97014-05).

M1.2 Outaae Observations Inspection Scope (62707. 60710)

The inspectors reviewed the outage schedule and work scope, defense in depth plan, and an Independent Safety Engineering Group (ISEG) evaluation of the outage plan.

l Licensee adherence to the defense in depth plan was verified daily by control room l observations and attending outage meetings. Work and refueling / sipping activities listed ( in Section M1.1 were observed and are discussed further.

! ELbservations and Findinas Refuel Floor Activities

, Refueling floor activities were planned in detail. This critical path sequence included i sipping all fuel bundles in the core to identify and replace leaking bundles. The inspectors observed that although refueling ac'tivities had never been critical path during previous outages, the licensee was able to complete all activities in record time without erro vg

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i ( Supervision of activities was improved by using two refuel floor coordinators and two l senior reactor operators on each shift. Additionally, one of the refueling floor coordinators l was assigned to frequently assess foreign material exclusion practices. Coordination was l observed to be excellent on the refueling floor and with the control room. Refueling floor l work was delayed only once due to other plant activities.

l The inspectors observed that appropriate radiological precautions were taken for the fuel

' leaks. These included venting the reactor vessel through a high efficiency particulate air filter unit to the standby gas treatment suction, limiting the number of personnel on the refueling floor when moving the leaking fuel bundles, and planning the response to the potential airbome release on the refueling floor. When a slight airbome release occurred l at the start of sipping one of the leaking bundles, RP personnel sampled the air, promptly

, calculated the dose from the airbome release, and notified each person present about the l results (less than 1 mrem each). Radiation protection support of refueling floor work was observed to be excellent, and was further documented in Inspection Report No. 50-341/97015.

l The licensee planned to further review the refueling process to identify additional l enhancements and opportunities for dose savings. The licensee extensively recorded video observahons of work in progress. The inspectors noted that the licensee utilized high quality ca11 eras to monitor work progress and reduce dose. This, however, did not reduce the direct supervisio The inspectors observed that fuel moves were properly communicated to and tracked by l

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control room personnel. The senior reactor operator directing the core alterations was present on the refueling bridge. Communications and conduct on the refueling bridge exceeded the standard observed in the control room.

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The inspectors observed that licentee corrective actions for problems involving refuel l floor activities during the previous refueling outage were uniformly effective. The entire l

evolution was conducted without a personnel error or procedure adherence proble Dose was considerably lower than predicted for the evolution. Fuel pool level and water inventory were carefully monitored by operators. Head tensioning and subsequent l operational mode change were very controlled. This issue is further discussed below in i

Sections M8.1 and M8.2. Refueling bridge reliability was effectively improved under the Maintenance Rule system improvement plan, and the reliability was clearly established before the outage began. There were no schedule interruptions due to refueling bridge problems during this outag b.2 Work Control Outage management effectively limited the outage work scope, with emergent work added on a strictly controlled basis. The inspectors observed that virtually all of the work scope additions were handled by the Fermi integrated Resource Support Team; therefore, the work additions did not impact any of the planned wor The inspectors noted that the outage schedule was planned in greater detail than in previous outages. All surveillance tests were scheduled prior to starting the outage, in contrast to past practice where the tests would be added to the schedule only a few days ahead of the work. The new practice resulted in better scheduling of manpower,

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C particularly in operations. The inspectors noted that the late addition of surveillance tests ;

had previously challenged ISEG's ability to review surveillance tests to determine their !

impact on the defense in depth plan. The inspector's review of overtime identified that the operations department had virtually no unscheduled overtime during the outage, an l Issue which has been a challenge in the past. The better scheduling also resulted in virtually eliminating problems in meeting required plant conditions for surveillance tests, which was a problem that was observed a number of times during the last refueling outage, as documented in Inspection Report No. 50-341/96013(DRP).

Outage preparations included a new practice of preparing all tagouts and scaffold I requests prior to the outage. The inspectors did not identify any scaffold location or approval discrepancies during this outage, compared to numerous problems identified during the previous outage. Few tagout problems occurred during the outag b.3 Risk Management The inspectors reviewed ISEG Report 97-014 on the mid-cycle outage scope and j schedule review. The ISEG review was detailed and properly focussed on safety. The 1 ISEG identified a number of concerns in their initial review, which were adequately resolved by the licensee staff. The inspectors' review of the schedule and the resolution 1 of ISEG's concems did not identify any additional concems. Due to the limited work !

scope, the licensee was able to maintain nearly all important power sources, decay heat removal systems, and reactor vessel fill systems available throughout the outage. This ;

resulted in excellent defense in depth coverage, and fulfilled the guidelines set forth in l Operations Department Instruction (ODI) 44, " Operations Outage Philosophy."

The inspectors observed that ISEG and outage management personnel were proactive in keeping the licensee staff aware of the impact of the higher decay heat loads than during a normal refueling outage. This was of particular concem for the reactor vessel pressure test and is discussed in Section O The licensee utilized a software program for evaluating shutdown risk, Operational Risk Assessment and Management (ORAM), on a trial basis during this outage. This was performed in parallel with normal manual risk assessment. The results of this trial were generally positive and resulted in a number of plant model refinements. Outage management personnel effectively communicated the results of the ORAM analyses to the entire site by posting color graphs and brief discussions of the critical work impact on defense in depth at various locations throughout the site. The licensee planned to continue to seek industry experience with this risk assessment tool before further implementation of ORA The inspectors reviewed the new ODI 44. This document formalized past practices and delineated operations management expectations in detail. The inspectors considered this document to be a significant addition that adequately covered the topic. The inspectors observed that adherence to ODI 44 was good, although adhers. e in one minor inspector-identified case was not possible due to the ODI beinf ferty restrictively word *

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l Contractor Control l  !

I During the previous refueling outage, the licensee had a number of contractor control '

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problems. During this outage, the licensee relied almost exclusively on site personnel to ;

perform scheduled work, with refueling and fuel sipping being the significant exception l The licensee utilized a number of offsite Detroit Edison personnel to supplement the site l

work force. The inspectors observed that the control of visiting workers was excellent i

! during this outage. Site supervision for visiting workers was observed to be very active at work sites. Site access training was modified to include contractor control issue lessons

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leamed from the previous refueling outage. Pre-job briefs for visiting workers were l observed by inspectors to stress the need to ask questions of site personnel when in doub Plant Equipment Walkdowns l

The inspectors noted that the licensee effectively utilized several teams designated to conduct equipment walkdowns, particularly in normally inaccessible areas of the plant.

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These walkdowns were scheduled at appropriate times during both startup and shutdown sequences when dose was acceptably low but the systems of concem were hot and pressurized. During startup, this effort included a vacuum leak team which was effective in ensuring the plant retumed to operation with a low air inleakage rate. These walkdowns were performed jointly by operators, system engineers, and RP personne Deficiencies identified by the teams were documented on CARD Excessive Safety Relief Valve (SRV) Setpoint Drift Reported On October 13, the licensee identified that the SRV pilot valve setpoint testing of pilot valves used during the first part of the cycle indicated that 11 of 15 SRVs had a setpoint that was outside the /- 1 percent setpoint tolerance specified in TS 3.4.2.1. All SRVs were replaced during the mid-cycle outage. This condition was reported per 10 CFR 50.72.(iii)(D). The inspectors will review the plant impact of this condition under Licensee Event Report 50-341/96017, Revision Conclusions The mid-cycle outage was planned in greater detail than past outages, resulting in better reviews, more complete preparations, and few schedule-related problems. Problems observed during the previous refueling outage were observed to have been effectively corrected. Teamwork and coordination were evident in identification of equipment problems and performance of refueling floor activities. Outage management personnel effectively communicated the results of risk analyses to the entire site. These improvements resulted in completing an aggressive outage schedule slightly ahead of schedule with a minimum of problem M8 Miscellaneous Maintenance lasues (92902)

l M8.1 (Closed) Violation 50-341/96017-018: Inadvertent operational mode change due to detensioned reactor head bolt. This event was directly caused by a data recording error during initial tensioning and compounded by weak communications. The licensee determined that a procedural deficiency existed, in that, the procedure for tensioning the t

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reactor vessel head directed an operational mode change from refueling to cold shutdown '

before completing head tensioning verification. The procedure was changed to correct this deficiency. The inspectors observed improved communication and verification of 1 head tensioning data during the mid-cycle outage. Potential data discrepancies were l observed to be appropriately questioned and resolved by the refueling floor coordinators l and work group. The inspectors also observed improved communication of head l tensioning status to the control room and a mode change conducted at the appropriate I time in the sequence. Corrective actions were observed to be appropriate and effectiv l This item is close M8.2 (Closod) Licensee Event Report 50-341/96018: Inadvertent operational mode change due to detensioned rear ' head bolt. As discussed in Section M8.1, the inspectors <

determined that correc o actions were adequate to address the root causes of the !

event. This item is close M8.3 (Closed) Inspection Followup Item 50-341/95014-01: Primary containment airlock test I connection pipe cap untested following restoration from airlock testing. At Region Ill's I request, NRR performed a formal review of the licensee's practices of using l administrative controls to ensure the cap was reinstalled properly and not performing a local leak rate test (LLRT) after reinstalling the cap. The NRR response concluded that i the licensee's practice was consistent with the staff's position for LLRTs for test, vent and 1 drain connections under Option A of 10 CFR 50, Appendix J. Thus, no violation was 1 considered to have existed at the time of the inspectio j Subsequent to the inspection, the licensee adopted Option B of Appendix J. Under that j option, the cap must be tested. The inspectors determined that the licensee changed the <

surveillance test procedure for airlock LLRTs (43.401.206) to use a different test I connection which included an additional isolation valve that was Type B tested. This avoided disturbing the above cap, so the cap was also tested during the airlock LLR Therefore, the current licensee practices were determined to be in compliance with the applicable NRC requirements. This item is close M8.4 (Closed) Violation 50-341/96013-02: Non-operations personnel operated valve without permission, resulting in overfilling the spent fuel pool (SFP). The inspectors reviewed changes to Operations Conduct Manual 05, " Control of Equipment," and observed that the procedure strengthened the requirements for the approval of non-operations personnel manipulation of equipment and requiring that any exceptions be approved and logged by the NSS. The inspectors observed that a specific briefing for refueling floor workers was held prior to the recent mid-cycle outage, which stressed controls placed on operating equipment. The inspectors verified that operators exhibited increased sensitivity and frequent monitoring of fuel pool skimmer surge tank levels, and all SFP filling operations were performed only by operators, in addition, the licensee performed training for operators, system engineers and chemistry personnel on the Operations Conduct Manual 05 changes discussed above. The inspectors determined by discussions with selected individuals in these groups that the training was effective. This item is close ,-

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E1.1 Solenoid Operated Valve (SOV) Investiaation Update Inspection Scope (92902. 92903)

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The inspectors reviewed the licensee deviation event report; held conversations with maintenance and engineering personnel; reviewed technical, industry and vendor manual l

l information for SOVs; and held discussions with NRR and region specialist Observations and Findinas The inspectors continued to review issues with the solenoid valves discussed in )

Inspection Report 50-341/97013(DRP). The inspectors reviewed the licensee's '

justification for the continued operability of solenoid valves that were not planned to be l replaced prior to plant restart. The licensee identified 14 SOVs for replacement during i

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the mid-cycle uutage, scheduled system outages, and the following refueling outage. The SOVs were chosen based on model number, service conditions, and risk significanc The inspectors were concemed that the licensee did not formally evaluate and document the operationalimpact of the potential failure of the valves remaining in service. Based on NRC concerns, the licensee decided to perform increased frequency testing of the affected SOVs to verify ongoing operability. Region-based inspectors and NRR

, personnel determined that the additional corrective action was sufficient to determine l operabilit Conclusions The inspectors were concemed that the licensee did not formally evaluate and document the operationalimpact of the potential failure of the valves remaining in servic Consequently, the licensee implemented additional measures to periodically verify operability of the affected valves. The licensee's corrective action of increasing surveillance of selected systems addressed the inspector's concem E8 Miscellaneous Engineering issues (92902)

E (Closed) Licensee Event Report 50-341/96008: Auxiliary building basement not fully meeting divisional separation criteria. During a plant walkdown, the licensee identified that electrical cables from Division 1 Non-Interruptible Air System did not have adequate separation from a Division 2 instrument rack. A continuous fire watch was posted until the Division 1 cabling could be protected with fire wrap. The inspectors reviewed the plant modification, walked down the completed fire wrap modification, and discussed the protection methodology with a fire protection engineer. The modification appeared to adequately restore the required divisional separation. The licensee also performed an evaluation to determine if additional areas existed where divisional separation of cables was inadequate, and none were identified. Failure to maintain adequate separation between divisions of the safety related air system was a violation of 10 CFR 50

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Appendix R. However, 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 Policy. (NCV 50-341/97014-06)

E8.2 (Closed) Licensee Event Report 50-341/97004-01: Calibration of primary containment l oxygen monitor in de-inerted environment challenging operability of monitor in inerted !

environment. The licensee determined that the TS limit of 4 percent oxygen inside containment during power operation was never violated because the maximum observed l instrument error was based on a review of the nine occasions when an unanticipated l non-conservative error was introduced. The licensee's response to this discovery was )

discussed with licensee senior management at a pre-decisional enforcement conference on August 8,1997. As a result, it was determined that a violation occurred due to failure to report the problem in the licensee's corrective action process and violation 50-341/97013-02 was issued. This item is closed based on the issuance of the violatio E8.3 (Closed) Violation 50-341/97013-02: Failure to write a Deviation Event Report for a non-conservative error introduced in primary containment oxygen monitor calibration. The licensee implemented a new corrective actions reporting program which encompassed a greater scope of problem reporting. The inspectors observed that this process effectively lowered the threshold for reporting potential problems since its implementation in September 1997. As a result of not reportinr; this problem, past system operability was not investigated in a timely manner and corrective actions were initially incomplete. The inspectors noted that the licensee completed a special test to determine the conditions under which the error was introduced. The licensee then developed a procedure to accurately calibrate the oxygen monitor under either inerted or deinerted condition Training for operators and system engineers on the event stressed the need to question and report anomalous indications. Corrective actions appeared to be adequate. This item is close E8.4 (Closed) Unresolved item 50-341/96010-11: Inverted Boraflex panels in SFP storage racks not accounted for in calculation of impact of possible Boraflex gaps. The licensee commissioned a calculation of the combined effects of these two conditions. The inspectors reviewed License Change Request 97-128-UFS and safety evaluation (SE 97 0112) approving the change to the UFSAR to incorporate the combined calculation. The licensee analysis concluhd that under design conditions, TS 5. requirements for margin to criticality of the fuel in the SFP storage racks were met. The inspectors determined that the conclusions of the analysis appeared reasonable and were based upon conservative assumptions. This item is close E8.5 (Closed) Inspection Followup Item 50-341/96010-12: Inverted Boraflex panels in SFP storage racks not documented in UFSAR. The licensee determined that the combined effects of the two conditions discussed in Section E8.4 were not accounted for because the results of the eight storage cells with inverted panels were not documented in the UFSAR. Failure to maintain the UFSAR updated with the current configuration of the SFP storage racks was a violation of 10 CFR 50.71. However, 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 Policy. (NCV 50-341/97014-07)

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y Mansaament Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the l

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conclusion of the inspection on November 10,1997. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie X3 Management Meeting Summary On November 6-7, J. Jacobson, acting Deputy Director, Division of Reactor Safety, Region lll I visited the site to obsarve the plant condition and discuss licensee performance in preparation for l the upcoming SALP. During this visit, he met with various members of the licensee's staff.

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l PARTIAL LIST OF PERSONS CONTACTED Licensee S. Booker, Electrical Maintenance Superintendent l D. Cobb, Operations Superintendent I W. Colonnello, Work Week Manager l R. Delong, Superintendent, System Engineering i

T. Dong, NSSS, Technical Engineering i P. Fessler, Plant Manager i l

J. Greene, Superintendent of Maintenance Support '

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K. Howard, Superintendent, Plant Support Engineering E. Kokosky, Superintendent, RP and Chemistry J. Korte, Director, Nuclear Security l l R. Laubenstein, Mechanical Maintenance Superintendent l P. Lynch, NSS, Operations l

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R. Matthews, l&C Maintenance Superintendent i W. Miller, Work Week Manager l J. Moyers, NQA Director i

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N. Peterson, Acting Director, Nuclear Licensing J. Plona, Technical Director l T. Schehr, Operating Engineer J. Sweeney, Supervisor of Audits, NQA NRC j J. Pulsifer, NRR Systems Branch l i A. Kugler, Project Manager, NRR l l H. Ornstein, AEOD R. Gardner, DRS, Rlll D. Butler, DRS, Rlli t

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p-C INSPECTION PROCEDURES USED IP 60710: Refueling Activities IP 61726: Surveillance Observations IP 62707: Maintenance Observation l IP 71707: Plant Operations IP 71711: Plant Startup from Refueling IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92901: Followup - Operations IP 92902: Followup - Engineering

IP 92903

Followup - Maintenance l

l ITEMS OPENED, CLOSED, AND DISCUSSED Opened l

50-341/97014-01 IFl TSs Entered into Without Documentation 50-341/97014-02 IFl Adequacy of Load List Documentation 50-341/97014-03 VIO Failure to Perform Verification of Availability of Offsite Power 50-341/97014-04 NCV Failure to Meet Requirements of TS 3.6.2. /97014-05 IFl Non-Safety System Outage impact Assessment H 50-341/97014-06 NCV Failure to Maintain the Divisional Separation in Air System 50-341/97014-07 NCV Failure to Maintain the UFSAR Updated with Current Configuration of the SFP Storage Racks 1

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Closed 50-341/94008-00 LER Failure to Verify Altemate Decay Heat Removal Method j l 50-341/94016-01 VIO Failure to Verify altemate Decay Heat Removal Method .

! 50-341/94016-04 IFl Performance of Troubleshooting and Corrective Maintenance l l During Surveillance Activities 50-341/95014-01 IFl Primary Containment Airlock Test Connection Untested 50-341/96002-00 LER ESF Actuation to Torus to Drywell Vacuum Breakers Due to improper System lineup i

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50-341/96002-01 VIO Failure to Follow Hydrogen Recombiner SOP 50-341/96002-04 ViO Improper Retum M EDG 14 to Standby 50-341/96008-00 LER Auxiliary Building t$asement not Fully Divisional Separation Criteria !

50-341/96010-11 URI inverted Boraflex Panels in Spent Fuel Pool '

50-341/96010-12 IFl Inverted Boraflex Panels in SFP Storage Racks not Documented in ]

UFSAR 50-341/96013-01 VIO Failure to Follow Procedures for Resetting a Reactor Scram 50-341/96013-02 VIO Non-Operations Personnel Operated Valve Without Permission, l Resulting in Overfilling the Spent Fuel Pool 50-341/96016-02 VIO Operators did not adequately respond to high level in the Fuel Pool 50-341/%017-01 B VIO Inadvertent Operational Mode Change Due to Detensioned Reactor i Head Bolt 50-341/96018-00 LER Inadvertent Operational Mode Change Due to Detensioned Reactor Head Bolt

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C 50-341/97002-03 IFl Troubleshooting Practices Prior to Writing a Work Request 50-341/97004-01 LER- Calibration of Primary Containment Oxygen Monitor in De inerted Environment Challenging Operability of Monitor in inerted Environment l 50-341/97012-00 LER Automatic Reactor Scram on High Scram Discharge Volume i During Shutdown Conditions

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50-341/97013-02 VIO Failure to Write a Deviation Event Report for a Non-Conservative Error Introduced in Primary Containment Oxygen Monitor Calibration

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lC LIST OF ACRONYMS USED CARD Condition Assessment Resolution Documents CTG Combustion Turbine Generator EDG Emergency Diesel Generator HPCI High Pressure Coolant injection ISEG Independent Safety Engineering Group LCO Limiting Condition for Operation LLRT Local Leak Rate Testing NASS Nuclear Assistant Shift Supervisor l NCV Non-Cited Violation l NQA Nuclear Quality Assurance NRC Nuclear Regulatory Commission NRR Office of Nuclear Reactor Regulation NSS Nuclear Shift Supervisor ODI Operations Department Instruction ORAM Operational Risk Assessment and Management

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RP Radiation Protection l RPV Reactor Pressure Vessel SFP Spent Fusl Pool SLC Standby Liquid Control System SOP System Operating Procedure SOV Solenoid Operated Valve l SRV Safety Relief Valve

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TS Technical Specifications l UFSAR Updated Final Safety Analysis Report VIO Violation

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