IR 05000324/1999003

Insp Repts 50-324/99-03 & 50-325/99-03 on 990328-0508.Two Violations Noted & Being Treated as non-cited Violations. Major Areas Inspected:Aspects of Licensee Operations,Maint, Engineering & Plant Support

ML20195H713
Person / Time
Site:	Brunswick
Issue date:	06/07/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20195H698	List: IR 05000324/1999003 ML20195H693
References
50-324-99-03, 50-324-99-3, 50-325-99-03, 50-325-99-3, NUDOCS 9906170117
Download: ML20195H713 (33)

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l U. S. NUCLEAR REGULATORY COMMISSION REGION ll

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Docket Nos: 50-325,50-324 l License Nos: DPR-71, DPR-62 l

Report No: 50-325/99-03,50-324/99-03 l

Licensee: Carolina Power & Light (CP&L)

! Facility: Brunswick Steam Electric Plant, Units 1 & 2 Location: 8470 River Road SE l Southport, NC 28461 I

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! Dates: March 28 - May 8,1999 l

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Inspectors: T. Easlick, Senior Resident inspector E. Brown, Resident inspector E. Guthrie, Resident inspector j G. Wiseman, Reactor inspector l (Sections F1.2, F1.3, F2, F3, FS, F7)

J. Coley, Reactor Inspector (Sections M1.2, M1.3)

Approved by: B. Bonser, Chief, Projects Branch 4 Division of Reactor Projects i l'

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9906170117 990607 PDR ADOCK 05000324 .

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EXECUTIVE SUMMARY Brunswick Steam Electric Plant, Units 1 & 2 NRC Inspection Report 50-325/99-03,50-324/99-03  ;

This integrated inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a 6-week period of resident inspection; in addition, it includes the results of maintenance and fire protection inspections by regionalinspector Ooerations

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Operators responded promi,tly and efficiently to a main turbine trip and subsequent automatic reactor scram.' The licensee's event review team performed an overall event i analysis which provided the necessary root cause analysis and corrective actions to support management's decision to restart Unit 2. Engineering review of an unexpected lifting and reseating of two safety relief valves (SRVs) in response to a main steam line pressure spike was adequate to explain the event and validate the proper operation of the SRVs (Section 01.1).

A corrective action violation was identified when measures were not established to ensure that a condition adverse to quality was promptly identified and corrected. Water accumulation in the common sensing line to the Unit 1 high drywell (DW) pressure and reactor building-to-suppression pool vacuum breaker instruments caused a non-conservative instrument bias that would have caused the instruments to actuate above the Technical Specification allowed setpoint values and above the analytical safety limit for DW pressure (Section O2.1).

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Spiking local power range monitors resulted in two reactor protection system scrams on Unit 2 while the vessel was defueled. During the first scram, a control rod drive (CRD)

had not been completely removed from service and the CRD inserted. All systems !

functioned as designed (Section O2.2). i

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A clearance for the Unit 2 core spray system was prepared, authorized, and implemented in accordance with procedure (Section O2.3).

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A general walkdown of the four diesel generators verified their operability and configuration appropriate to the mode of plant operation. All accessible valves in the main system flow paths were in the correct positions. Power supplies and breakers were l

correctly aligned and available for system initiations. Local control panels were properly ;

aligned for standby mode and displayed indications were consistent with expected values (Section O2.4).

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Fuel movement activities on Unit 2 were observed to be conducted consisti with the fuel handling procedure. Independent verification was used before moving . . el '

assembly or control blade. Three-part communications were maintained throughout ;

between the refuel bridge personnel and between bridge personnel and the control l room. A senior reactor operator was present at all times during refueling activities i (Section O2.5).  !

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. A walkthrough simulating the shutdown of both units from outside the control room was ,

performed to establish the significance of an identified adverse condition. Walkthrough participants were observed to provide acceptable feedback regarding areas for improvement in the procedures, walkthrough set-up, and implementation. The lack of simulation of the effects the simulated fire had on safety-related equipment and the use of two individuals to represent seven operators limited the ability of the walkthrough to satisfactorily simulate conditions for demonstration of acceptable operator command-and-control and emergency action level classification (Section 05.1).

• Review of the classification of several condition reports revealed that guidance provided for the classification of nonconforming conditions was misleading. Based on procedure instructions, nonconformances such as operability or reportability determinations might not have received appropriate root cause determinations based on inappropriate classification as improvement items (Section 07.1).

Maintenance

. Surveillance activities observed _were performed consistent with the applicable procedure. The procedure was verified to be of the proper revision and implemented using the correct level-of-use. Three-part communication was observed (Section M1.1).

. Inservice examination activities observed were performed in a skillful and thorough manner by knowledgeable examiners. Discontinuities were properly recorded and evaluated by knowledgeable examiners using approved procedures (Section M1.2). ;

. The licensee experienced problems when attempting to apply a seal weld to reactor recirculation valve no. 2-B32-F0238. The problems were caused by unexpected leakage of water past the valve seat and inadequate venting capability. The licensee was ultimately successful in completing the repair (Section M1.3).

.- A Maintenance Rule violation was identified for maintenance rule functional failures, which were not correctly dispositioned for the inoperability of the Unit 1 high drywell pressure instruments (Section M2.1).

• Freeze sealing activities associated with the repairs on the RCR pump 28 discharge bypass motor operated valve were conducted adequately. The goveming procedure did not take into account industry experience for monitoring nitrogen flow. This did not result ,

. -in an adverse condition. The licensee was considering this in their lessons leamed for !

l this evolution (Section M2.2).

• - Observed maintenance activities on the RCR pump 2B discharge bypass motor operated valve actuator found that the technicians were very knowledgeable and skilled with the !

task. The technicians did not observe any broken or severely worn parts that would j have effected actuator operability. The inspectors found that the technicians made an accurate assessment (Section M2.3).

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In general, changes to plant design documentation reviewed were completed consistent with the guidance in the applicable engineering procedures. During review of the service

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. water and control room emergency ventilation systems, the inspectors noted minor J

discrepancies in the assumptions for several design calculations. These discrepancies

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were corrected and verified to be bounded by existing calculations and/or design documentation (Section E1.1).

Plant Support

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< Observed health physics technician activities during periods of high worker access into the radiological controlled area (RCA) found that technicians were knowledgeable

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regarding recent changes to the RCA egress controls and the new scrub polic ~ Activities were generally conducted consistent with site requirements. Minor discrepancies with crossing the RCA boundary in the small article monitor area were quickly addressed and corrected (Section R1.1).

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The Unit 2 reactor building (RB) was evacuated as a result of a fire in a distribution panel on the 20 foot elevation. Quick response by a contract health physics technician in the area resulted in the fire being extinguished within eight minutes. Operations personnel promptly established responsibilities, accessed required procedures, and mustered the fire brigade. Engineering responded quickly to evaluate the damaged components and recommend those components to reenergize to allow continuation of RB activities. Good feedback regarding equipment issues and areas for improvement were identified during the post-fire review (Section F1.1).-

. Implementation of the fire protection program requirements for control of combustible fire hazards was effective. Plant personnel followed combustible control procedures to manage the use and temporary storage of transient combustibles in safety-related area Plant housekeeping and trash control were in accordance with procedure requirements (Section F1.2)J l

.' Six incidents of smoke or equipment overheating were identified in the past 15-month period which were primarily caused by electrical component faults within safety-related areas. These fire related conditions were properly identified and mitigating actions were taken in a timely manner. No trends were identified (Section F1.3).

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• The inspectors determined that the persorial protective fire fighting equipment provided l to the brigade was i., good condition, properly maintained, and provided a sufficient level of personal safety needed to handle onsite fire emergencies. Backup lighting in the dressout area provided an adequate level of lighting in support of fire brigade operations

. (Section F2.1).' '

. Appropriate emphasis had been placed on the operability of the fire protection equipment and components. The number of degraded fire protection components was low. Manual ]

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fire fighting equipment, automatic fire detection systems, and suppression features of fire zone / areas were operational and were well maintained (Section F2.2).

.. Fire brigade pre-fire plans provided clear and sufficient fire brigade instructions and met

. the requirements of the fire protection program (Section F3.1).

. Overall fire brigade performance in fire responses and drill participation for drills conducted during the first quarter of 1999 was marginal. Fire brigade drill program implementation required four remedial drills and a series of four additional training drills before all established brigade drill objectives were successfully accomplished. A number of fire brigade drills had been performed in risk significant plant locations (Section F5.1).

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. A fire brigade response time vulnerability for the control room was identified and included in the plant corrective action program (Section F5.1).

. The licensee's Nuclear Assessment Section (NAS) assessment of the facility's Fire Protection Upgrade Program (FPPU) was effective in reporting fire protection program performance to management. The fire protection upgrade project was on schedule and had a positive impact on the quality of fire protection procedures and pre-fire plans. The NAS audit recommended that operations and training management consider additional emphasis on self-assessment in the area of fire protection to determine the status of the FPPU (Section F7.1).

. Issues were identified associated with incomplete and ineffective management oversight of implementation of the FPPU Phase I upgrades for the fire protection administrative, training and fire drill programs. Fire brigade performance was marginally effective but the previously identified declining trend had stabilized (Section F7.1).

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ReDort Details Gummarv of Plant Status Unit 1 began the report period operating at 100 percent rated thermal power (RTP). On April 9 power was reduced to 60 percent RTP to perform valve surveillances, control rod testing, and reactor feed pump maintenance. Power was returned to 100 percent RTP on April 10. At the end of the report period the unit had been operating continuously for 102 day Unit 2 began the report period operating at 100 percent RTP. On March 29 an automatic reactor scram occurred while operating at 100 percent RTP due to a high vibration signal sensed on one of the bearings on the main turbine generator. The unit was returned to 100 percent RTP on April 2. The unit operated continuously until April 17 when the unit was shutdown to begin a refueling outage. The unit was in cold shutdown at the end of the report perio . Operations 01 Conduct of Operations 01.1 Unit 2 Main Turbine Trio and Automatic Scram Event Review Inspection Scope (71707. 37551)

At 8:37 a.m. on March 29 with Unit 2 operating at 96 percent RTP, control room opere* ' received alarms and instrument indications of an automatic reactor scram as a result e s main turbine trip. The inspectors responded to the control room and observed the opewtors' response to this event. Additionally, the inspectors reviewed the following to determine the sequence of events and proper plant operation:

e plant computer transient data including plant transient traces e event log

• balance of plant post trip log e auto post trip review log e licensee's post event trip review

. licensee's root cause investigation including corrective actions e plant personnel statements Observations and Findinos On March 29' Unit 2 was in final feedwater temperature reduction operating conditions in accordance with General Procedure OGP-13, "locreasing Unit Capacity at End of Core Cycle," Rev. 5. As a result, the feedwater heater 4 and 5 bypass valve 2-FW-V120 was throttled open. At 8:37 a.m. the main turbine tripped on a high vibration signal causing an automatic reactor scram. The operators immediately implemented the emergency operating procedure for a reactor scram. Following the scram, reactor vessel water level lowered to approximately 150 inunes initiating a reactor vessel low water level 1 signal and primary containment isolation groups 1,6, and 8 isolations. This was a normal level transient following a scram. Additionally, safety relief valves (SRV)"F" and "G" lifted and

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immediately reset. All systems responded as designed with the exception of the acoustic monitor for the "G" SRV, which did not indicate the SRV had lifte Operator response to the event was good. Immediate actions taken in response to the event were prompt and deliberate.. These actions included the recognition of the need to isolate the 2-FW-V120 bypass valve following the scram. Shift supervision provided clear and concise direction to the crew and maintained positive control over control room access. An additional operator was assigned to take logs immediately following the scram. The inspectors noted that the time to reset the scram was 21 minutes. Based on the cause of the scram and the post scram activities at the time, the inspectors concluded that the time to reset the scram was lengthy. This issue was discussed with operations management and the need to expedite resetting the scram will be reenforced

. during operator trainin The inspectors observed the activities of the event review team, which was formed to conduct the post trip review including the root cause analysis of the event. The cause of the event was a failure of the number 9 generator joumal bearing vibration monitoring instrumentation resulting in a main turbine trip and subsequent reactor scram. The

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turbine vibration monitoring system was a single coincidence trip system. Based on a review of other vibration indications, bearing metal temperature, lubricating oil temperature, and bearing oil samples, the review team concluded that the high vibration signal was a spurious indication and not a valid vibration condition. The failed detector was removed and disassembled for failure analysis. The analysis indicated that the high vibration signal was caused by a separation in the signal lead wire in the detector. Prior to the unit startup, the vibration detector instruments were replaced on the number 5,7, 9,' and 10 bearing The "G" SRV acoustic monitor operation was reviewed and a definitive cause of the problem could not be determined. The instrument was declared inoperable with an associated limiting condition for operation (LCO) allowed outage time of 30 days. During the Unit 2 refueling outage the licensee discovered that the acoustic monitor for the "G" SRV was operating properly following the performance of a surveillance test completed dur!ng cold shutdown conditions. The licensee determined that the short duration time that the SRV was open (less than one second) was not sufficient to exceed the one second time delay in the acoustic monitor actuation logi ;

SRV Resoonse i The licensee reviewed the operation 'of the SRVs following the turbine trip and subsequent reactor scram. SRVs 2-B21-F013F and 2-821-F013G opened during the !

plant transient for a brief period of one second or less. A review of the reactor vessel pressure indication showed that the highest reactor pressure following the event was

' 1059.7 pounds per square inch gage (psig). The setpoint for opening F013F and F013G !

was 1130 psig with the technical specification (TS) low limit of 1097 psig. Because the !

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indicated reactor vessel pressure was well below the lift setpoint of the SRVs, the L .

licensee performed an evaluation to determine if the SRVs operated appropriately during the transien l l

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Following a review of the plant computer transient data the licensee discovered that the I pressure recorded at the pressure averaging manifold (PAM), adjacent to the turbine stop valves, indicated that a pressure spike of uncertain magnitude was developed and 4 transmitted back down the steam line to the reactor vessel. The plant computer recorded a 44 psig pressure increase to 1044 psig in 0.1 seconds, the scan interval for the computer point. The reading then went off scale high and returned on scale seconds later. The maximum calibrated range for the pressure transmitter was 1050 psig. Using that data, the licensee estimated that the peak steam line pressure was between 1109 psig and 1154 psig, within the open setpoint range for the two SRVs. The licensee also determined that because the F013F and F013G were located adjacent to i'

one another on the "C" main steam line, the shock induced into the piping by actuation of one SRV could cause an adjacent valve to unseat. During a review of industry operating experience, this pressure transient in the steam lines, as a result of the rapid closure of the turbine stop valves, has been seen at two other boiling water reactors. The licensee concluded in engineering service request (ESR) 99-00175, that the SRVs operated appropriately. The inspectors reviewed the ESR and industry operating experience, and

~ found that the licensee's conclusions were acceptabl Conclusions Operators responded promptly and efficiently to a main turbine trip and subsequent automatic reactor scram. The licensee's event review team performed an overall event analysis which provided the necessary root cause analysis and corrective actions to support management's decision to restart Unit 2. Engineering review of an unexpected lifting and reseating of two SRVs in response to a main steam line pressure spike was adequate to explain the event and validate the proper operation of the SRV Operational Status of Facilities and Equipment 02.1 Deoraded Drvwell and Vacuum Breaker Instrumentation Inspection Scope (71707. 37551)

The inspectors observed and reviewed operations and engineering activities associated with the high drywell (DW) pressure and reactor building-to-suppression pool vacuum breaker degraded instrumentation issue Observations and Findinos

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On March 26 the inspectors observed maintenance activities on Unit 1 high DW pressure instrument,1-E11-PT-N011D, which failed a channel check on the previous day. The licensee performed a nitrogen purge of the instrument sensing line in an effort to restore the instrument to an operable condition. Based on the licensee's past experience, water was thought to have been in the line causing the channel check failure. Following observations of licensee activities and discussions regarding water in the sensing line to the DW instrument, the inspectors discussed with the licensee that an adverse condition existed the cause and effect of which the licensee did not fully l

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understand.' The licensee generated Condition Report (CR) 99-00755, DW Pressure Sensing Line Wate The operability of two DW pressure instruments were effected by water accumulation in their sensing lines. This determination was made on April 7,1999, and was documented in ESR 99-00197. The instruments,1-E11-PT-N011C and 1-E11-PT-N011D had '

independent sensing lines. These instruments were gas sensing instruments that were designed to sense DW containment pressure and provide a high DW pressure signal, for a loss of coolant accident (LOCA) condition, to the emergency core cooling systems (ECCS)- low pressure coolant injection (LPCI), high pressure coolant injection (HPCI),

core spray (CS); to the primary and secondary containment isolation, and the standby gas treatment (SBGT) systems. The water in the sensing lines caused a non-conservative instrument sensing inaccuracy that would have caused the two instruments to actuate at a higher DW pressure than the instruments were sensing. This inaccuracy would have caused the instruments to actuate above the TS limit of 1.8 psig and based on instrument uncertainties would have actuated above the Updated Final Safety Analysis Report (UFSAR) analytical safety limit of 2.0 psig. Additionally with both 1-E11-PT-N011C and 1-E11-PT-N011D degraded and these channels being in the same trip system, all of the systems listed above would not have actuated before the TS allowed value or the safety limit was reached, as a result of a high DW pressure signa The logic circuitry for the above systems were configured as one-out-of-two taken twice logic. The circuitry was direct current (DC) logic, which required the associated relays to be energized to actuate the contacts in the logic circuitry. The two effected instruments degraded the output signal for the entire logic circuit. This resulted in the degradation of the initiation signal for the safety systems described above. The inspectors determined that ESR 99-00197 incorrectly identified which channels of instruments were associated with each trip system. The licensee determined that this error was carried over from a plant calculation, used for Improved Standard Technical Specification / Power Uprate verification, in which it was found that the calculation used a template statement from the reactor protection system (RPS) calculation. This application was wrong, however, in this case the error did not effect the calculation assessment results. The use of this channel identification for the ECCS systems logic in ESR 99-00197 resulted in the licensee not initially recognizing that the ECCS output signal was degraded. Additionally the inspectors found that the engineering evaluation and safety significance assessment of the instrument degradation as described and written in the reviewed documents, was not thorough, and was not precisely stated, particularly in regards to plant response based on leak sizes and the LOCA analysis. The licensee informed the inspectors that ;

they would ~ correct the' plant' calculations to accurately reflect the channel identification Two other instruments were affected by the water accumulation in the sensing, ..ne The reactor building-to-suppression chamber vacuum breaker differential pressure sensing instruments also utilized a portion of the same sensing line as the high DW pressure instruments. These instruments.1-CAC-PDS-4222 and 1-CAC-PDS-4223,  ;

were gas sensing instruments that wou; ive actuated at a higher reactor building-to- l suppression pool differential pressure than the TS allowed value of less than or equal to j 0.5 pounds per square inch differential (psid). The vacuum breakers were designed to i

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actuate at 0.5 psid following a LOCA and subsequent collapse of the high pressure

' steam environment in the DW. The UFSAR indicated that the maximum theoretical limit for DW pressure was -1.9 psig. It was determined, using the worst case instrument bias j affect caused by the water column in the sensing line, that the vacuum breakers would have actuated at a differential pressure that would have assured that the safety function

~ limit for containment would not have been exceede I 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, requires that measures shall be established to assure thct conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected. In the case of significant conditions adverse to quality, the measure shall assure that the cause of the condition is determined and corrective action taken to preclude repetition. The identification of the significant condition adverse to quality, the cause of the condition, and the corrective action shall be documented and reported to appropriate levels of managemen Contrary to the above, between April 8,1998, and March 26,1999, a condition adverse ,

to quality existed on Unit 1, when water accumulation in the common sensing line to the !

1-E11-PT-N011C and 1-CAC-PDS-4222, and the 1-E11-PT-C11D and 1-CAC-PDS-4223 instruments, caused a non-conservative instrument bias. This would have caused the instruments to actuate above the TS allowed setpoint values and above the analytical safety limit, resulting in the ECCS, primary containment, secondary containment, and the SBGT systems to not function within their required limits. During that time, measures were not established to ensure that the condition adverse to quality was promptly identified and corrected until April 7,1999, when it was determined through extensive engineering evaluation that water in the sensing lines effected operability of the instruments specified in TSs 3.3.5.3,3.3.6.1 and 3.6.5. Specifically, 1, April 8.1998- The 1-E11-PT-N011D instrument failed its channel check. The transmitter was calibrated and sensing line purged with nitrogen. The instrument was retumed to normal (TS LCO was entered for instrument inoperability). April 8.1998- A work ticket was generated for the 1-E11-PT-N011C instrument because its channel check was at or near the limit, water was suspected to be in the sensing line. The work ticket was scheduled to be worked for December 8, 199 . June 16.1998- The 1-CAC-PDS-4222 instrument common sensing line to pressure transmitter 1-E11-PT-N011C was reading 0.16 psig lower than the other instrument. The calibration performed did not correct the proble . November 22.1998- The 1-E11-PT-N011C instrument failed its channel chec The instrument was purged with nitrogen, however channel check records indicated that the instrument continued to read at or near the channel check limi ' The 1-CAC-PDS-4222 instrument readings were not corrected at that time (TS LCO was entered for instrument inoperability).

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6 March 25.1999- The 1-E11-PT-N011D instrument failed its channel check. (TS LCO was entered for instrument inoperability).

, March 26.1999-The 1-E11-PT-N011D instrument was purged with nitrogen and the instrument read normal. The 1-E11-PT-N011C instrument was reading at or near the channel check limit. The 1-CAC-PDS-4222 instrument was reading

. consistent with the 1-E11-PT-N011C instrument (common sensing line).

This Severity Level IV violation is being treated as a Non-Cited Violation (NCV),

consistent with Appendix C of the NRC Enforcement Policy. This violation is in the

. licensee's corrective action program (CAP) as CR 99-00755, DW Pressure Sensing Line Water. This NCV is identified as 50-325/99-03-01, Degraded DW Pressure Instrumentation. The significance of this degraded condition was reduced because LOCA analyses did not take credit for these instruments. Other LOCA instruments were -

not degraded and the design plant response during analyzed transients would have reduced the effect of the degraded instrument The licensee determined that the root cause of the water accumulation was due to improper design and installation of both the DW instrument penetrations and instrument piping.~ The instrument penetrations and piping had a one-quarter inch slope going away from containment which did not allow water accumulation to drain out. These conditions-were assigned corrective actions for the next refueling outage. System monitoring had been established to determine trending and action prior to instrument degradation. The licensee determined the extent of the condition for both units,' and corrective actions were planne Conclusions A corrective action violation was identified when measures were not established to ensure that a condition adverse to quality was promptly identified and corrected. Water accumulation in the common sensing line to the high DW pressure and reactor building-to-suppression pool vacuum breaker instruments caused a non-conservative instrument bias that would have caused the instruments to actuate above the TS allowed setpoint values and above the analytical safety limit for DW pressur .2 Reactor Protection System Inadvertent Actuations Inspection Scooe (71707)

The inspectors reviewed licensee response to multiple actuations of the RPS for Unit 2.

0 Observations and Findingg_

On' April 30 with Unit 2 defueled (no mode), a full RPS trip was received. At 10:22 on April 29 the 2A DC switchboard was deenergized for maintenance. The planned removal of DC power resulted in a planned loss of power to the RPS A trip system and a

' half-scram. At 4:44 a.m. work was being performed undervessel in support of the

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changeout of control rod drive (CRD) 50-31. Spiking of local power range monitor (LPRM)28-05C upscale resulted in an average power range monitor (APRM) B tri The trip of APRM B was an input into the RPS B trip system and a full scram was I inserted. CRD 50-31 fully inserted from the full-out position in the core as a result of being fully withdrawn for drive changeout and of incomplete clearance activities on the I associated hydraulic control unit. All systems were determined to have functioned as )

intended. The inspectors verified that the adverse condition was entered into the licensee's CAP sa CR 99-1083, RPS tri I At 8:07 a.m. another full scram was received as a result of spiking of a different LPRM, which caused APRM B to trip. The inspectors responded to the control room and observed the Unit 2 control operator (CO) place LPRM 36-138 in bypass. The inspectors verified that the LPRM which resulted in the earlier scram had been bypassed.' There were no undervessel activities underway during the second even The licensee formed a post scram team to investigate both events. The inspectors verified that during both events adequate cooling and level were maintained for protection of the fuel which had been completely offloaded to the spent fuel pool. The inspectors noted four days later, on May 4, that the second scram had not been entered into the CAP, despite the differences from the first scram. Upon notification by the inspectors, the licensee promptly corrected this oversight. The second scram was captured in the CAP as CR 99-1149, U2 RPS Trip /No Rod Motio Conclusions i

Spiking LPRMs resulted in two reactor protection r./ stem scrams on Unit 2 while the !

vessel was defueled. During the first scram, a CRD had not been completely removed from service and the CRD inserted. All systems functioned as designe .3 Clearance Verification Inspe_.gtion Scope (71707)

The inspectors reviewed the clearance for the Unit 2 CS system to verify that the clearance was properly prepared, authorized, and that tagged components were in the required position with the appropriate tags in plac j Observations and Findinas On May 4 the inspectors performed a verification of the proper alignment and )

implementation of clearance 2-99-0008 on the Unit 2 CS system. The inspectors reviewed Nuclear Generation Group Standard Procedure OPS-NGGC-1301, Equipment Clearance," Rev. 3. The specialinstructions for the clearance defined the scope of the j clearance and provided specific information to both facilitate the hanging of the tags and the local leak rate testing that would be performed. The clearance was prepared such that the tagging instructions delineated the order in which the tags were to be hung to prevent damage to the equipment. This sequence met the requirements of OPS-NGGC-1301. All accessible components were verified to be in the proper position with

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1 appropriate tags in place. Additionally, clearance information tags were properly hung i

on the associated control room switches l ! Conclusiong A clearance for the Unit 2 CS system was prepared, authorized, and implemented in accordance with procedur .4 Diesel Generator (DG) System Walkdown (71707)

On May 8 the inspectors performed a general walkdown of the four DGs to verify their operability and configuration appropriate to the mode of plant operation. The inspectors used Inspection Procedure 71707 to walkdown the accessible portions of the four DG The inspectors also used Operating Procedure 00P-39, " Diesel Generator Operating Procedure," Rev. 82, to review panel, electrical, and selected valve lineups during the walkdowns. .The inspectors verified that the DGs were in the standby mode in accordance with 00P-39. All accessible valves in the main system flow paths were in the correct positions. Power supplies and breakers were correctly aligned and available for system initiations. Local control panels were properly aligned for standby mode and displayed indications were consistent with expected values. Equipment material condition and general housekeeping were acceptable. The inspectors identified no substantive cor'cems as a result of the DG walkdow O2.5 Refuel Bridae Activities (71707)

On May 4 the inspectors observed fuel movement from the refuel bridge. The inspectors verified that core move sheets had been approved by the Unit Senior Control Operato Fuel movement activities were observed to be conducted consistent with Fuel Handling Precedure OFH-11 A, "Refu) ling Platform Operations," Rev. 47. Independent verification was used before moving a fuel assembly or control blade. Three-part communication was maintained throughout between the refuel bridge personnel and between bridge personnel and the control room. A senior reactor operator (SRO) was present at all

- times during refueling activities. New fuel assembly serial numbers were verified by the refuel floor SRO before placement in the core. The inspectors verified that the refuel bridge area radiation monitor was in the current calibration cycle and functionin Operator Knowledge and Performance 04.1 '.llnil'1 r Reactor Buildina Auxiliary Operator (RBAO) Daily Rounds (71707)

On March 8 the inspectors observed the Unit 2 RBAO during the performance of Operating instruction 201-3.4.2, " Unit 2 Reactor Building Auxiliary Operator Daily Check

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Sheets," Rev.10. The inspectors observed that the procedure was in use and of the proper revision. The inspectors noted that reactor building (RB) components were reviewed by the RBAO against the procedural parameters and were found to be within tolerance. The RBAO was knowledgeable of the work in progress in the building as well as recent equipment nonconformances. Good coordination and support of the fire

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protection technicians by the RBAO.was observed when a nuisance alarm repeatedly alarmed on the 117 foot (ft) elevation. The RBAO examined the area for signs of fire, promptly communicated to the control room the lack of a fire, and properly reset the alar Operator Training and Qualification O5.1 Alternate Safe Shutdown (ASSD) W91kthrouah Inspection Scope (71707. 71750)

1 The inspectors observed the performance of a walkthrough by the licensee simulating l the shutdown of both units from outside of the control room. The inspectors reviewed the walkthrough for deficiencies and discrepancies and the evaluation of operator performance. This walkthrough was evaluated by the inspectors using the crew performance standards found in Brunswick Nuclear Plant Crew Performance Measure Worksheet LOR-OJT-CP-304-E01, " Control Building Fire," Re Observations and Findinas On April 8, the licensee performed a walkthrough to establish the significance of using the shift superintendent (SS) as both the site emergency coordinator (SEC) and a unit senior control operator (SCO). The walkthrough was conducted by implementing licensed operator training (LOT) materials. The inspectors observed the walkthrough and the debrief. The participants were observed to provide acceptable feedback regarding areas for improvement in the procedures, walkthrough set-up, and implementation. The licensee concluded that the walkthrough was successful due to the demonstrated ability of the SS to meet objectives from both the emergency response program drill and the objectives defined in LOR-OJT-CP-304-E0 Based on walkthrough observations, the inspectors questioned the satisfactory performance of two of the objectives. The two objectives were: the demonstration of timely and accurate notifications to the NRC and satisfactory crew command-and-control. The inspectors observed that the status of the fire was not checked by the SEC/ Unit 2 SCO until 19 minutes after the walkthrough was initiated, which meant the

. fire had been buming for 34 minutes. Based on walkthrough assumptions this would have meant that the fire duration was in excess of the assumed duration of 30 minutes contained in the licensee's 10 CFR 50 Appendix R design document. The requirements ,

~ in the plant' emergency procedure for progression to a higher emergency action level l (EAL) were based on the fire's affect on safety equipment. As a result, the inspectors j concluded that the fire effects during the walkthrough were not simulated consistent with !

plant design assumptions. This was significant in that, a fire lasting for a duration in j excess of design may have affected more safety-related equipment than initial l walkthrough assumptions. This in turn may have required a higher EAL classificatio !

Also, the inspectors noted that essentiall" two drill controllers were used to simulate approximately seven other operators As a result, the inspectors concluded that the j ability to demonstrate adequate command-and-control was limited due to walkthrough

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l modeling constraints. The inspectors' observations were incorporated into the licensee's l lessons leamed from the walkthroug Conclusions A walkthrough simulating the shutdown of both units from outside the control room was performed to establish the significance of an identified adverse condition. Walkthrough participants were observed to provide acceptable feedback regarding areas for improvement in the procedures, walkthrough set-up, and implementation. The lack of simulation of the effects the simulated fire had on safety-related equipment and the use of two individuals to represent seven operators limited the ability of the walkthrough to satisfactorily simulate conditions for demonstration of acceptable operator command-and-control and emergency action level classificatio Quality Assurance in Operations 07.1 Imorovement item Classification a.' ' Inspection Scooe (71707)

The inspectors reviewed a sample of the licensee's CRs to assess the licensee's program for deficiency ' identification. The corrective action program was governed by Nuclear Generation Group Standard Procedure CAP-NGGC-0001, " Corrective Action Management," Rev. b.- Observations and Findinas On April 12 the inspectors performed a review of all CRs since January classified as improvement items. The inspectors questioned several CRs identified as improvement items. CR 99-759, Missed LCO Call, identified an incorrect LCO call conceming the DW pressure instrumeritation discussed in Sections O2.1 and M2.1 of this report. In addition, the CR requested a recommendation for assistance from Regulatory Affairs to determine the reportability of the nonconformance. CR 99-741, OPT-46.4 Improvement item,

- described problems with a TS surveillance acceptance criteria. The inspectors identified, as described in Section O3.1 of NRC Inspection Report 50-325(324)/99-02, that the !

condition description was not valid. The inspectors noted that the condition was later ,

properly described and classified as adverse under CR 99-844, Control Room Emergency Ventilation (CREV) Logic Missed Surveillance. However, the original CR

' was~not rewritten,' reclassified, or voided. CR 99-990,'SLC Tank in-Leakage, described that trouble-shooting activities and corrective actions to prevent SLC tank in-leakage had overlooked a valve which was hard to close. The in-leakage was causing increased I sampling and monitoring to ensure compliance with TS level and concentration requirement The inspectors reviewed CAP-NGGC-0001 and discovered that the guidance for i determining the proper classification and therefore, the correct level of evaluation could I mislead individuals during classification. This was a result of an inconsistency between i

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the definitions and guidance presented in the definitions and implementation sections.

l For example, step 9.1.1 identified that a potential operability concern or reportable event I

could be classified as either an adverse condition or an improvement item. In contrast, the definition of an improvement item was defined as "a process or efficiency enhancement." An improvement item did not require any root cause determination or corrective actions to prevent recurrence. The inspectors discussed these observations with the licensee. The licensee indicated that classification responsibilities had been i transferred to a newly formed team and that additional training would be provided to l

those individuals with classification responsibilities regarding improvement items. The CRs identified by the inspectors were reviewed and proper classification levels assigne The inspectors observations were captured in CR 99-1166, CR classification erro i Conclusions  !

Review of the classification of several CRs revealed that guidance provided for the classification of nonconforming conditions was misleading. Based on procedure instructions, nonconformances such as operability or reportability determinations might not have received appropriate root cause determinations based on inappropriate ,

classification as improvement item Miscellaneous Operations issues 08.1 Closure of Open Severity Level IV Violations (71707)

i l The NRC recently revised NUREG-1600, Rev.1, " General Statement of Policy and Procedures for NRC Enforcement Actions, "(Enforcement Policy) by the addition of ;

Appendix C. Appendix C, interim Enforcement Policy for Power Reactor Severity Level l IV Violations, effective March 11,1999, revises the NRC's enforcement approach for Severity Level IV violations. Appendix C permits closure of most Severity Level IV violations, based on the violation being entered into the licensee's corrective action l

program, as well as other considerations as described in the Appendix. The NRC has conducted a review of the following Severity Level IV violations, and considers it

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l appropriate to close these violations consistent with Appendix C of the Enforcement

! Policy:

Violation Number Corrective Action Proaram l

File Number j 50-325/98-10-03 98-02637 ,

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50-325/98-10-01 98-02623 50-325(324)/98-09-01 98-02226 50-325/98-09-04 98-02054 50-325(324)/98-07-02 98-00789 50-325(324)/98-07-03 98-01703 50-325(324)/98-06-12 98-00975 50-325(324)/98-05-03 98-00820 50-325(324)/97-09-08 97-02839 i

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11. Maintenance M1 Conduct of Maintenance M1.1 Maintenance Activities tr)?oection Scope (61726. 71707)

The inspectors reviewed all or portions of the following:

• Periodic Test OPT-14.0, " Control Rod Drive System Valve Operability Test;" Re ,and

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. Periodic Test OPT-8.1.4.b, "RHR Service Water System Operability Test - Loop B," Rev. 3 Observations and Findinas l

The inspectors observed that the procedures used were verified to be of the proper i i revision. The inspectors noted that the procedures were used consistent with the level-of-use specified. Self-checking and, independent verification were performed satisfactorily. Test equipment used was verified to be within the current calibration cycl The inspectors reviewed the applicable TSs and verified compliance with the regulation ;

Adequate three-part communications were observed between the control room and the I field technicians. During the pre-job briefing for OPT-8.1.4.b the Unit 2 CO reviewed the

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entire procedure, hold points were identified, and questions or concerns posed were appropriately resolve Conclusions I Surveillance activities observed were performed consistent with the applicable procedure. The procedure was verified to be of the proper revision and implemented using the correct level-of-use. Three-part communication was observed. Test equipment was verified to be within the current calibration cycl M Inservice inspection (ISI)- Observation of Work Activities

! Inspection Scope (73753. 92902)

' The inspectors observed vendor ultrasonic analysts evaluate phased array data for core shroud weld No. H6B; reviewed video tapes of the remote in vessel visual examination of the CS downcomer piping; reviewed documentation and held discussions with engineers and managers, and observed in-process weld repairs for throughwall holes found in the DW containment during the containment baseline visual examinations; and reviewed documentation and held discussions with cognizant engineers and managers regarding the propagation of a crack through the outer 25 percent of pipe wall to the weld overlay for recirculation system weld 2-832-RECIRC-28-1 >

13 Observations and Findinos The Code of Record for the third 10-year ISI interval for Unit 2 is the 1989 Edition of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section XI, Division 1. The inspectors observed a vendor Level ill analyst evaluate ultrasonic phased array data for bottom core plate weld H6B to the reactor vessel core shroud. The phased array technique was only used to scan from 180 degrees to 360 degrees on weld H6B. The inspectors compared this data to H68 data taken in 1996 and 1997 which used tri-modal transducers and raster scanning techniques. The 1999 data revealed a consistent reduction in crack depth ranging from 0.200 inch to 0.250 ;

inch. This reduction in the previously reported crack depth was attributed to improved )

. accuracy achieved with the technological improvements of the new phased array i techniques. The phased array ultrasonic technique also allowed personnel to increase inspection coverage previously obtained for the top core shroud weld (weld H1) from 22 percent of the shroud diameter, to approximately 70.4 percent by allowing examinations to be performed from above and below the weld .

Video tapes of invessel visual inspections (lWI) of reactor internals were reviewed by the inspectors. Specific components examined consisted of the core spray piping which penetrated the core shroud at 10 degrees and at 170 degrees. The examination surface for these piping components had been cleaned and the remote scanning of these components were performed in a thorough and efficient manne !

l During primary containment visual inspections performed in accordance with Periodic ;

Test Procedure OPT-20.5.1, Primary Containment inspection, Rev. 8 the licensee !

identified three areas in the DW liner where corrosion had penetrated the liner. These l areas were at the 18 ft, 52 ft, and 70 ft elevations. The thoughwall area at 52 ft had l corroded from the outside to the inside surface. The corrosion at the 70 ft level had !

corroded from the inside to the outside surface, it could not be determined with assurance which way the corrosion at the 18 ft level had propagated though the line The inspectors examined the portion of the liner plate removed at the 52 ft level and l examined the concrete behind the liner plate and the weld preparation for the new plat ;

In addition, the weld repair at the 18 ft level was observed. The licensee is performing a root cause evaluation to determine the cause of the DW corrosion. The inspectors' ;

walkdown of the corroded areas revealed that the licensee's visual examiners did an l excellent job in identifying these discrepant areas because of the location and small size

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when first detecte The inspectors also reviewed documentation and held discussions with cognizant i engineers and managers regarding the propagation of an axial crack through the outer 25 percent of pipe wall to the weld overlay for recirculation system weld 2-B32-RECIRC-28-11. This weld overlay had been ultrasonically examined using the manual technique so the inspectors could not reverify that the crack had not entered the overlay weld material. Discussions were held with the licensee conceming the adequacy of the design overlay (a two layer-weld overlay) since the initial crack that had required the overlay weld in 1986 was a circumferential crack 1.4 inches long and 18 percent thoughwall indication with small axial components. Overlay weld inspection techniques

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are required to only look at the outer 25 percent of the pipe and the weld overla Apparently this weld joint is experiencing active intergranular stress corrosion crack growth and the inspectors were concerned about the potential growth of the initial circumferential crack without a full structural overlay (The licensee informed the inspectors that the industry is presently preparing to request that NRC put the overlay welds back in the ISI program where they will be inspected once every 10-year inspection intervalin lieu of every other refueling outage as.now required). In response to the inspectors concern the licensee provided the inspectors a letter from Structural Integrity (their overlay design contractor) which attested to the present adequacy of the overlay wel ~ Conclusions Inservice examination activities obsented were performed in a skillful and thorough manner by knowledgeable examiners. Discontinuities were properly recorded and evaluated by knowledgeable examiners using approved procedure M1.3 Observation of Weldina on Reactor Recirculation Valve 2-B32-F023B Insoection Scooe. Unit 2. (55050.92902)

The inspectors observed welding activities and reviewed documentation related to application of a seal weld on reactor recirculation valve 2-B32-FO23B. This valve was being seal welded to stop leakage due to a defective valve bonnet-to-body gaske b. Observations and Findinas The inspectors observed welding activities, reviewed documentation and held discussions with cognizant personnel regarding the welding and inspection of the body-to-bonnet seal weld for "B" loop recirculation pump duction valve 2-832-F0238. The gasket seat for this valve leaked during operations and the licensee had elected to repair the valve by seal welding the valve's bonnet to the valve's body as shown in Drawing 2-FP-05363. The licensee experienced problems with welding the seal weld when the vent line on this valve could not keep up with the water leaking by the valve seat. The licensee then tried to apply air pressure to the valve to push the water below the seal weld lands. Air blowing out the valve, however, also affected the welding process. Although, the seal welding of this valve had been time consuming and this work was performed in a very high radiation

' area the licensee was achieving success at the conclusion of the inspectio c. Conclusions The licensee experienced problems when attempting to apply a seal weld to reactor recirculation valve no. 2-B32-F023B. The problems were caused by unexpected leakage of water past the valve seat and inadequate venting capability. The licensee was ultimately successful in completing the repai .

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, 15 M2 Maintenance and Material Condition of Facilities and Equipment

M2.1. Residual Heat Removal (RHR) System Maintenance Rule'(MR) Functional Failures (FF)

a. Insoection Scooe (62707) .

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On March 26 the inspectors observed maintenance activities on Unit 1 high DW pressure instrument 1-E11-N011D from the control roo b. Observations and Findinos

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- - ~The instrument sensing line was being blown out with nitrogen because the instrument failed the TS channel check. Water was thought to be in the sensing line causing indication problems. The instrument was considered inoperable during the maintenanc The inspectors noted, during the maintenance activity, that the licensee was confused as to how many times in the past the same maintenance had been parformed on the 1-E11-N011D instrumen ,

The inspectors reviewed the operating logs and the Maintenance Rule Events Database logs for 1998 and 1999 and determined that a discrepancy existed between the two logs as to which instrument had been worked on April 8,' 1998 and November 22,1998. The inspectors reviewed work orders and job tickets for maintenance activities on the high DW pressure instruments and found that the MR Events Database log was incorrect. The MR Events log indicated that the 1-E11-N011C instrument was worked on April 8,' 1998, when

~ it was actually worked on November 22,1998. The 1-E11-N011D instrument was worked '

on April 8,199 The inspectors found that'on December 10,' 1998, the licensee had determined that no MR functional failure occurred for the inoperability of the 1-E11-N011C or the 1-E11-N011D instruments on April 8,1998, or November 22,1998. All of the events involving these instruments were considered as miscellaneous events based on the redundancy of

. the instruments (i.e.- one out of two taken twice logic). The inspectors determined that

- this application of the MR was incorrect when the MR functional failure criteria were reviewed for the two instruments. The inspectors found that the licensee's MR Scoping and Performance Criteria stated that one of the MR functions of these instruments was to

"[p}rovide input to Core Spray & HPCI initiation Logic (High DW Pressure & LOCA Diesel Start)" and the functional failure criteria was "[f]ailure of any instrument in either division to provide necessary input on demand." The inspectors determined that inoperability of

" - either instrument met this criteria. Secondly, the inspectors found that the licensee's MR Scoping and Performance Criteria stated that another MR function for these instruments was to "(p]rovide input to HPCl/RCIC isolation instrumentation to initiate isolation of Groups 7 & 9 Primary Containment isolation Valves" and the functional failure criteria was

. "[a)ny failure that prevents an isolation signal from being generated as required or any failure that reduces the redundancy of this function." The licensee identified the 1-E11-N011D instrument as inoperable on April 8,1998 and the 1-E11-N011C as inoperable on November 22,1998 in the operations logs, because they failed the instrument channel checks. The inoperability of the instruments reduced the redundancy of the high DW

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pressure function, therefore, the inspectors determined that the inoperabilities of the instruments met the MR functional failure criteri The MR performance monitoring criteria for these instruments were specified, by the licensee, to be three functional failures within 36 months. On April 14 the MR database was updated to specify that functional failures did occur on April 8,1998, and November 22,199 The inspectors discussed the above findings with the licensee who, upon review of the MR criteria and instrument work history, agreed that the incorrect MR functional failure determination was made on December 10,1998 CR 99-00840, MR log entry

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inaccuracies, was initiated by the licensee. The licensee determined that several events associated with the high DW pressure instruments,1-E11-N011C and 1-E11-N011D, were MR functional failures. The licensee determined that subsequent inoperabilities of the instruments in March and April of 1999 had resulted in the system meeting the repetitive functional failure criteria of more than three functional failures, so that the system would be considered for 10 CFR 50.65(a)(1) monitoring against the licensee-established goals. The MR database was corrected to accurately reflect previous functional failures on Unit 1 and an action was initiated to correct potential MR errors for Unit 2. The licensee initiated an action to provide refresher training for MR implementation personnel on these issue CFR 50.65(a)(1) requires, in part, the holders of an operating licensee shall monitor the performance or condition of structures, systems, and components (SSCs) within the

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scope of the monitoring program as defined in 10 CFR 50.65(b) against licensee-established goals, in a manner sufficient to provide reasonable assurance that such SSCs are capable of fulfilling their intended function CFR 50.65(a)(2) states that monitoring as specified in (a)(1), of the rule, is not required j

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where it has been demonstrated that the performance or condition of a SSC is being effectively controlled through the performance of appropriate preventive maintenance, l

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such that the SSC remains capable of performing its intended functio Contrary to the above on March 26,1999, the NRC determined that the licensee could no longer demonstrate that the performance of the high DW pressure instruments,1-E11- 4 N011C and 1-E11-N0llD, were being effectively controlled through the performance of preventive maintenance in that a repetitive MR functional failure of DW pressure l instruments, occurred on November 22,1998 and the licensee failed to place the ,

-instruments in (a)(1)c MR functional failures were not identified on December 10,1998, i

~ for the high DW pressure instruments incapability of fulfilling their intended functions on April 8,1998 (1-E11-NO11D) and November 22,1998 (1-E11-NO11C). This Severity l Level IV violation is being treated as an NCV, consistent with Appendix C of the NRC L

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Enforcement Policy. This violation is in the licensee's corrective action program as CR I 99-00840, MR log entry inaccuracies. This NCV is identified as 50-325/99-03-02, MR Implementation Failure.

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The significance of the failure to identify the MR functional failures was that the 1-E11-N011D instrument became inoperable on March 26,1999. Also the 1-E11-N011C instrument became inoperable on March 27,1999, and again on April 2,1999. Following extensive detailed engineering evaluation the licensee determined that water was in the sensing line, which effected operability of the instrument. Had the licensee's Maintenance Rule procedure been applied correctly the inoperability of these instruments would have been addressed much soone Conclusions A Maintenance Rule violation was identified for MR functional failures, which were not correctly dispositioned for the inoperability of the Unit 1 high DW pressure instrument M2.2 Unit 2 Outaae- Freeze _ Seal a. Insoection Scope (62707)

The inspectors followed activities associated with freeze sealing activities for the repairs on the 2-B32-F032B reactor coolant recirculation (RCR) pump 2B discharge bypass motor operated valve, b.- Observations and Findinas The inspectors followed the activities associated with the freeze seal by reviewing approved procedures, attending the pre-freeze seal evolution briefing on April 26, and reviewing the completed procedure documentation. The inspectors found the procedure to be satisfactory in that it followed industry standards for accomplishing freeze seal The procedure was approved by the Plant Nuclear Safety Committee following their ;

review. The inspectors noted that the procedure adequately monitored the freeze jacket

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for temperature, but no monitoring was used for nitrogen flo !

l NRC Technical Guidance for freeze plugs discussed the use of nitrogen flow monitonng based on a freeze seal failure at a nuclear power plant in 1989 in which the plume from l the freeze jacket was observed to verify nitrogen flow to the freeze jacket existed. The ]

freeze seal failed even though the plume existed at the vents. This was discussed with ;

the licensee who used freeze seal specialists to perform this evolution. The contract l freeze seal personnel had not considered nitrogen flow measurement in the procedure or l the evolution. A failure did not occur during the freeze seal evolution, however, the j

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licensee was considering this as part of their lessons learned for this activit The licensee showed good concern for personnel safety during the activities for the handling of liquid nitrogen and the potential for hazardous atmospheric conditions from nitrogen and oxygen generation. The inspectors noted satisfactory precautions and ;

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action plans for those concerns. Additionally, the inspectors found that contingency plans were in place for a potentially failed seal plug. The entire maintenance activities for the vatve repair were conducted with the reactor vessel defueled, therefore, reducing the safety significance of the evolutio .

Multiple attempts to establish a freeze seal were required because the freeze jacket leaked. The location of the freeze jacket made the activities very difficult. The inspectors reviewed the non-destructive examination data before and after the freeze seal and found that no damage to the piping was note .

c. Conclusions -

Freeze sealing activities associated with the repairs on the RCR pump 28 discharge bypass motor operated valve were conducted adequately. The governing procedure did not take into account industry experience for monitoring nitrogen flow. This did not result in an adverse condition. The licensee was considering this industry experience in their lessons learned for this evolutio M2.3 Motor Ooerated Valve Maintenance (62707)

On April 25 the inspectors observed maintenance activities on the 2-832-F032B RCR pump 2B discharge bypass motor operated valve actuator. The inspectors observed

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maintenance technicians disassemble the actuator and assess required repair or replacement of components. Additionally, past operability of the actuator was assesse The inspectors found that the technicians were very knowledgeable and skilled with the task. The technicians did not observe any broken or severely worn parts that would have effected actuator operablility. The inspectors found that the technicians made an accurate assessment. The licensee informed the inspectors that the motor for the actuator was going to be replaced, because the motor had stalled on high torque three times. The inspectors determined that to be a good maintenance practic Ill. Enaineerina E1.1 Desian Documentation Confiauration Control a. Insoection Scooe (37551)

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The inspectors reviewed selected design basis documents to evaluate whether the plant's physical and functional characteristics were maintained in conformance with the design and licensing base b. Observations and Findinas

' The inspectors reviewed selected ESRs, modifications packages, design calculations, surveillance procedures, and applicable portions of the TS BASES. In general, changes to the design documentation were completed consistent with the guidance in the applicable engineering procedures. During review of the service water (SW) and CREV

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systems, the inspectors noted minor discrepancies in the assumptions for several design calculations. The inspectors verified that the discrepancies were bounded by existing calculations and/or design documentation. The licensee recorded this condition in CR 99-

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1181, Multiple SW Hydraulic Cales. The licensee indicated that the affected calculations j and the applicable documentation would be revised to reflect the current plant configuratio c. Conclusions l

in general, changes to plant design documentation reviewed were completed consistent '

with the guidance in the applicable engineering procedures. During review of the service water and control room emergency ventilation systems, the inspectors noted minor i l

discrepancies in the assumptions for several design calculations. These discrepancies were corrected and verified to be bounded by existing calculations and/or design documentatio IV. Plant Support R1 Radiological Protection and Chemistry Controls R1.1 Radioloaical Access Controls (71750)

The inspectors on several occasions observed health physics (HP) technician activities during periods of high worker access into the radiological controlled area (RCA). HP technicians were observed by the inspectors to perform validation activities to assure personnel on visitor access badges had completed appropriate training before obtaining dosimetry to enter the RCA. Technicians were knowledgeable regarding recent changes to the RCA egress controls and the new scrub policy. The scrub policy allowed individuals to enter certain contaminated areas using scrubs as the protective clothing in I addition to shoe covers and gloves. Egress activities were monitored by the inspector Activities were generally conducted consistent with site requirements. Minor discrepancies with crossing the RCA boundary in the small article monitor area were quickly addressed and correcte S4 Security and Safeguards Staff Knowledge and Performance i S4.1 Central Access Point (CAP) Observations (71750)

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The inspectors observed security activities during periods of high traffic through the CAP on several occasions. The inspectors noted that security personnel enforced site requirements for badging and escort requirements. Deficiencies in badging and escort activities were being identified as evidenced by several CRs initiated by security personnel. Site security management was observed performing oversight activities on ;

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F1 Control of Fire Protection Activities F1.1 Unit 2 Reactor Buildina (RB) Fire

. a. Inspection Scope (71750)

On' May 6 the inspectors observed licensee activities in response to a fire in the Unit 2 RB. The inspectors reviewed operator procedural adherence, communications, and monitored emergency response activitie b. Observations and Findinos

' At 7iO4 p.m. on May 6, the inspectors were in the control room to observe operator tumover activities.- During turnover a fire in the Unit 2 RB was reported to the control room. . The control room fire status panel indicated a fire on the 80 ft elevation. A call from the refuel floor 117 ft reported heavy smoke coming from the 80 ft elevation. In addition alarms for loss of the 2L substation sounded. Licensee response to the event

. was good. The control room staff accessed the related prefire plan and other procedures, a

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sounded the fire alarm, announced the evacuation of the Unit 2 RB, and called for the fire brigade to muster. All these actions were verified by the inspectors to be consistent with Prefire Plan Procedure OPFP-13, " General Fire Plan," Rev.17. The shift supervisor (SS)

promptly established operations personnel responsibilities. The inspectors observed that this was not just a good practice but actually necessary as a result of some of the oncoming shift having assumed their responsibilities, while parts of the offgoing shift were still officially on-shift. Three-part communication was consistently used throughout the

' event in the control room and during conversations on the radios. Personnel evacuation and accountability were quickly achieved as a result of security efforts. The fire was extinguished by a contract HP technician with a chemica! extinguisher before the fire brigade arrived. There were no injuries reporte . The inspectors observed that the fire lasted for eight minutes, and resulted in loss of lighting in some of the RB, DW, breezeway, control room backpanels, main stack, and the offices in back of the control room. Refueling activities were properly secured, and shutdown and fuel pool cooling were maintained throughout the incident. In addition to

- the. lighting, sample flow to the main stack radiation monitor flow device was affecte ;

During the interim, the chemistry organization was mobilized to provide the necessary 1 information manually to maintain main stack radiation monitoring. Sample flow to the !

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main stack flow device was restored quickly, and no other significant equipment was determined to hav6 been adversely affected.' Engineering responded quickly to evaluate the damaged components and recommend those components to reenergize to allow

= continuation of RB activitie The inspectors attended the post-fire reviewi Minor problems with some of the equipment !

utilized by the fire brigade were discussed, as well as, other suggestions for improvemen ;

The post-fire review identified that the fire was located in the 2B,480 voit distribution I panel on the 20 ft level of the RB and no component on the 80 ft elevation as originally !

reported was affected. The original reports and indications in the control room led to the

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21 fire brigade responding to the area of most smoke on the 80 ft and not the location of the fire on the 20 ft elevation. The licensee has proposed additional drills to train on misleading reports and indications. Initial licensee investigation attributed the distribution panel fire to a phase-to-phase fault. This fault was initially attributed to contaminants on an insulating tape located between the phase bars. The licensee investigation and root cause will be captured in CR 99-1184, Fire in Unit Two Rx. Buildin c. Conclusions The Unit 2 RB was evacuated as a result of a fire in a distribution panel on the 20 ft elevation. Quick response by a contract health physics technician in the area resulted in

' the fire being extinguished within eight minutes. ~ Operations personnel promptly

established responsibilities, accessed required procedures, and mustered the fire brigade. Engineering responded quickly to evaluate the damaged components and recommend those components to reenergize to allow continuation of RB activities. Good feedback regarding equipment issues and areas for improvement were identified during the post-fire revie F1.2 Combustible Material and Housekeepino Controls / Fire Hazards Reduction a. Irispection Scope (64704)

The inspectors reviewed the licensee's program for control of combustibles and performed tours of selected plant areas to determine if the program objectives had been properly implemented. The inspectors also reviewed the results of the licensee's transient combustible fire occurrence trend reports and corrective action program CRs to verify that transient combustible fire hazards issues and corrective actions were identifie b. Observations and Findinas The inspectors reviewed Operations Fire Protection Procedure (0FPP), OFPP-014,

." Control of Combustibles, Transient Fire Loads, and Ignition Sources," Rev.19, to determine if the objectives established by the licensee's commitments to implement the

- NRC approved fire protection program were being met. The inspectors toured nine of the highest ranked dominant fire risk locations identified in the licensee's Individual Plant Examination of Extemal Events (IPEEE) submitted to the NRC on June 1995 to verify proper implementation of 0FPP-01 The inspectors observed that controls were being maintained for transient combustibles in separation zones and other areas containing potential lubrication oil and diesel fuel eaks, such as the diesel generator rooms. The licensee made use of oil absorption materials to catch and soak up leaking fluid. Fire retardant treated plastic sheeting, and film materials were also being used in safety-related area The inspectors also observed that waste material trash cans were emptied on a frequent and regular basis and there was no excessive accumulation of combustible waste in

. safety-related plant areas. The inspectors concluded that, overall, the licensee's

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- implementation of the combustible control procedures and plant operational practices I were consistent with the approved fire protection program. Plant personnel routinely followed combustible control procedures to manage the use and temporary storage of transient combatibles in safety-related area Measures to identify and control transient fire hazards within the plant were included in the licensee's fire inspection and corrective action programs. Designated fire inspections were conducted to identify and correct potential fire hazards. The inspectors reviewed the results of the transient combustible fire occurrence trend reports and associated CRs written for combustible control issues identified for the period between January 1998 and i

March 1999. The licensee reports indicated that two examples of combustible hazards

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l had been identified in 1999, and that the number of fire occurrences in safety-related l plant areas involving transient combustibles had decreased since 1992. The plant fire

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protection staff had initiated corrective actions for the combustible hazards issues through the various responsible plant department supervisors. The inspectors determined that implementation of the fire protection program requirements for control of combustible fire hazards was effectiv Conclusions Implementation of the fire protection program requirements for control of combustible fire hazards was effective. Plant personnel followed combustible control procedures to manage the use and temporary storage of transient combustibles in safety-related area Plant housekeeping and trash control were in accordance with procedural requirement F1.3 Fire Reports and Investiaations a. Inspection Scope (647Q4_)'

The inspectors reviewed the station fire incident reports, fire occurrence trend reports, and CRs resulting from fire, smoke, sparks, shorts, arcing and equipment overheating incidents for the time period of 1998-1999 to assess maintenance or material condition I

problems with plant systems and equipment that may have initiated these incidents._ The !

review also assessed whether plant fire protection program requirements in Fire i Protection Procedure 0FPP-002, " Fire incident Report and Investigation," Rev.12, were met when fire-related events occurre j b. Observations and Findinas L The licensee's fire incident reports and CR issues associated with observed fire, smoke, l - sparks, shorts, arcing and equipment overheating indicated that during the 15-month period of 1998-1999, there were six incidents of fire, smoke or equipment overheating j observed within safety-related plant areas. Three of the incidents required fire brigade ;

response and investigation. The fire occurrence trends indicated a three-year rolling average of 2-3 fire incidents per year at the facility. No significant increase or decrease in the number of these fire related incidents were noted over the time period. Five of the six incidents (approximately 80 percent) were related to electrical component faults. In all

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cases, the fire or overheating condition was identified and mitigating action was taken in a timely manner so as to limit the damage to the original source and to prevent exposure to other safety-related equipment or cable c. Conclusions Six incidents of smoke or equipment overheating were identified in the past 15-month

. period which were primarily caused by electrical component faults within safety-related areas. These fire related conditions were properly identified and mitigating actions were taken in a timely manner. No trends'were identifie F2- Status of Fire Protection Facilities and Equipment i

F2.1 Inspection of Fire Briaade Eauioment i Inspection Scooe (64704)

The inspectors reviewed fire brigade control procedures, toured the fire brigade staging dress out area, and inspected fire brigade equipment to determine if the equipment was accessible and available in the staging area, Observations and Findinas The inspectors reviewed fire protection procedure 0FPP-031, " Fire Brigade Staffing and Equipment Requirements," Rev. 21, toured the staging dress out area within the fire house located outside the main power block structure and inspected four sets of fire brigade turnout gear. The equipment was in good condition and was well maintaine The inspectors also observed that there was fixed battery-powered backup lighting installed at the fire brigade staging dressout area and in the area of the fire brigade self contained breathing apparatus (SCBAs). The backup lighting was operable and provided an adequate level of lighting to support fire brigade operation Conclusions The inspectors determined that the personal protective fire fighting equipment provided to the brigade was in good condition, properly maintained, and provided a sufficient level of personal safety needed to handle onsite fire emerg ncies. Backup lighting in the dressout area provided an adequate level of lighting in support of fire brigade operation _

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i F2.2 Maintenance of Fire Protection Systems and Eauipment a. Inspection Scope (64704)

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The inspectors reviewed impairment records on the facility fire protection systems and ,

features to assess performance trends or material condition problems with fire i protection / safe-shutdown systems, and equipment. The inspectors conducted walkdown tours in five of the highest ranked dominant fire risk locations identified in the licensee's i

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IPEEE to determine the material condition of the fire suppression systems, emergency lighting, and fire barriers in these plant areas.

l b. Observations and Findinas The fire protection impairment records indicated that the number of fire protection impairments was relatively small and their duration was adequately monitored. Most of the overdue fire protection impairments were related to long-term corrective actions in process related to Thermo-Lag and penetration fire barrier seal issue During walk-down tours, the inspectors noted that the manual fire fighting equipment, automatic fire detection systems, and fire suppression features of the plant fire zone / areas were operational and were well maintaine Conclusions Appropriate emphasis had been placed on the operability of the fire protection equipment and components. The number of degraded fire protection components was low. Manual fire fighting equipment, automatic fire detection systems, and suppression features of fire zone / areas were operational and were well maintaine F3 Fire Protection Procedures and Documentation F3.1 Fire Briaade Pre-fire Plans Inspection Scope (64704)

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The inspectors reviewed upgraded fire brigade Pre-Fire Plans (PFP) for eight plant areas for compliance with the facility fire protection program. Plant tours were performed to verify that the pre-fire plans reflected as-built plant condition Observations and Findinas The inspectors reviewed pre-fire plans 1PFP-CB, Unit 1 Cable Spreading Room; OPFP-CB-23, Control Room; 1PFP-RB-1g S, Unit 1 Reactor Building South,20' elevation; 1PFP-RB1-2, Unit 1 Reactor Building, -17' elevation; 1PFP-RB1-2, Reactor Building HPCI Room; OPFP-DG-1, Diesel Generator Building Basement; 2PFP-DG-9, Diesel Generator Building, E8 Switchgear Room; and 2PFP-DG-14, Diesel Generator Building, E4

'Switchgear Roo Each of the fire fighting plans and plan drawings addressed the fire potential, area location, means of fire brigade approach, location of the available fire protection equipment, fire brigade actions, hazards to be considered, ventilation methods, special drainage instructions, and communications available. During plant tours the inspectors compared the pre-fire strategy plan drawings with as-built plant conditions. No

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discrepancies were noted. The pre-fire strategies provided a good graphicallayout of the area, contained specific information on available fire protection features and met the requirements of the fire protection progra c. Conclusions Fire brigade pre-fire plans provided clear and sufficient fire brigade instructions and met the requirements of the fire protection progra FS Fire Protection Staff Training and Qualification F5.1 Fire Briaade Drill Proaram Inspection Scope (64704)

The inspectors reviewed the fire origade drill program for compliance with plant procedures and NRC guidelines and requirement Observations and Findinas A fire brigade drill was not conducted during this inspection. The inspectors reviewed administrative procedure OAP-033, " Fire Protection Program Manual," Rev.0, fire protection procedure OFPP-052, " Fire Brigade Drill Program," Rev. 5, and the drill critique data for selected shift drills conducted during the first quarter of 1999, in the Emergency Switchgear Rooms, Cable Spreading Rooms, Emergency Diesel Generator Rooms, and Service Water Buildin The inspectors noted that the brigade drill scenarios were more realistic through the use of improved training aids and props during the conduct of drills. A number of drills had been performed in risk significant plant locations. The inspectors determined that improved standards of fire brigade performance were incorporated into the drill program for fire brigade fire attack time (<25 minutes) and dressout time (<5 minutes), however, the fire attack time established for the control room was not consistent with the time identified in the plant IPEEE or Section 5.1.4 of procedure OAP-033. The licensee j initiated CR 99-00891, Fire Drill Program, to address the enhancement of fire brigade l response attack times for risk significant plant areas into the fire brigade drill progra '

i The overall fire brigade performance in fire responses and drill participation for the drills j conducted during the first quarter of 1999 was marginal. The initial drill program ;

implementation for the five operations shifts required four remedial drills and a series of l four additional training drills before all established brigade drill objectives were successfully accomplishe Conclusions Overall fire brigade performance in fire responses and drill participation for drills conducted during the first quarter of 1999 was marginal. Fire brigade drill program

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implementation required four remedial drills and a series of four additional training drills before all established brigade drill objectives were successfully accomplished. A number of fire brigade drills had been performed in risk significant plant locations. A fire brigade response time vulnerability for the control room was identified and included in the plant corrective action progra F7 Quality Assurance in Fire Protection Activities F7.1 Fire Protection Audit Report of the Fire Protection Uparade Project (FPPU) Inspection Scope (64704)

The inspectors reviewed the 1999 Nuclear Assessment Section (NAS) audit report for the FPPU and the status of the corrective actions implemented for the audit finding b. Observations and Findinas The inspectors reviewed NAS report B-FP-99-01, that was considered the first of a series of reviews of the FPPU to be conducted during 1999. The audit noted that the fire protection upgrade project was on schedule and had a positive impact on the quality of fire protection procedures and pre-fire plans. However, none of the previously identified seven issues were closed and two additional issues were identified associated with incomplete and ineffective management oversight of implementation of the Phase I upgrades for the fire protection administrative, training and fire drill programs. The audit determined that fire brigade performance was marginally effective but that the previously identified declining trend had stabilized. The audit also recommended that operations and training management consider additional emphasis on self assessment in the area of fire protection to determine the status of the FPPU. The inspectors verified that the audit findings were properly documented in the licensee's corrective action tracking progra Conclusions The licensee's NAS assessment of the facility's FPPU was effective in reporting fire i protection program performance to management. The fire protection upgrade project was l on schedule and had a positive impact on the quality of fire protection procedures and !

pre-fire plans. Issues were identified associated with incomplete and ineffective management oversight of implementation of the FPPU Phase I upgrades for the fire protection administrative, training and fire drill programs. Fire brigade performance was marginally effective but the previously identified declining trend had stabilized. The audit ;

recommended that operations and training management consider additional emphasis on self assessment in the area of fire protection to determine the status of the FPP :

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V. Manaaement Meetinos X1 Exit Meeting Summary l The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on May 19,1999. The licensee acknowledged the

findings presented. No proprietary information was identifie PARTIAL LIST OF PERSONS CONTACTED Licensee A. Brittain, Manager Security E. Quidley, Manager Maintenance N. Gannon, Manager Operations J. Gawron, Manager Nuclear Assessment l M. Herrell, Training Manager l K. Jury, Manager Regulatory Affairs J. Keenan, Site Vice President B. Lindgren, Manager Site Support Services J. Lyash, Plant General Manager G. Miller, Manager Brunswick Engineering Support Section S. Vann, Manager Outage and Scheduling Other licensee employees or contracts included office, operation, maintenance, chemistry, radiation, and corporate personne INSPECTION PROCEDURES USED IP 37551

Onsite Engineering IP 55050; General Welding IP 61726: Surveillance Observations IP 62707: Maintenance Observations IP 64704 Fire Protection Program IP 71707: Plant Operations IP 71750: Plant Support Activities IP 73753: Inservice inspection, Observation of ISI Work Activities IP 92902: Followup - Maintenance ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-325/99-03-01 NCV Degraded DW Pressure Instrumentation (Section O2.1).

50-325/99-03-02 NCV MR Implementation Failure (Section M2.1).

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50-325/99-03-01 NCV Degraded DW Pressure Instrumentation (Section O2.1).

'50-325/98-10-03 VIO Inadequate Evaluation of Valve Failure (Section 08.1).

50-325/98-10-01 VIO Standby Gas Treatment Valve Misalignment (Section 08.1).

50-325(324)/98-09-01 VIO Failure to Implement Procedures (Section 08.1).

50-325/98-09-04 VIO ' Inadequate Review of Valve Degradation (Section 08.1).

50-325(324)/98-07-02 VIO Configuration Control Problems (Section 08.1).

50-325-(324)/98-07-03 VIO Diesel Generator Relay Failures (Section 08.1).

50-325(324)/98-06-12 VIO Failure to Properly implement and Establish Abnormal Airborne Guidance (Section 08.1).

50-325(324)/98-05-03 VIO Initialing of the QC Signoff by Unqualified QC Person (Section 08.1).

50-325(324)/97-09-08 VIO Failure to implement Smoke Detector Procedure (Section 08.1).

50-325/99-03-02 NCV MR implementation Failure (Section M2.1).

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