IR 05000324/1999005: Difference between revisions

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U. S. NUCLEAR REGULATORY COMMISSION REGION ll Docket Nos: 50-325, 50-324 License Nos: DPR-71, DPR-62 -
U. S. NUCLEAR REGULATORY COMMISSION REGION ll Docket Nos:
Report No: ~ 50-325/99-05,50-324/99-05
50-325, 50-324 License Nos:
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DPR-71, DPR-62 -
Licensee: Carolina Power & Light (CP&L)'
Report No:
Facility: . Brunswick Steam Electric Plant, Units 1 & 2 Location: 8470 River Road SE Southport, NC 28461 Dates: June 20 - July 31,1999 Inspectors: T. Easlick, Senior Resident inspector E. Brown, Resident inspector E. Guthrie, Resident inspector Approved by: B. Bonser, Chief, Reactor Projects Branch 4 '
~ 50-325/99-05,50-324/99-05
Division of Reactor Projects Enclosure 9909080097 990827 PDR G ADOCK 05000324 PDR     \
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Licensee:
Carolina Power & Light (CP&L)'
Facility:
. Brunswick Steam Electric Plant, Units 1 & 2 Location:
8470 River Road SE Southport, NC 28461 Dates:
June 20 - July 31,1999 Inspectors:
T. Easlick, Senior Resident inspector E. Brown, Resident inspector E. Guthrie, Resident inspector Approved by:
B. Bonser, Chief, Reactor Projects Branch 4
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Division of Reactor Projects Enclosure 9909080097 990827 PDR ADOCK 05000324 G
PDR
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EXECUTIVE SUMMARY Brunswick Steam Electric Plant, Units 1 & 2
EXECUTIVE SUMMARY Brunswick Steam Electric Plant, Units 1 & 2
  ' NRC Inspection Report 50-325/99-05,50-324/99-05 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a six-week period of resident inspectio Ooerations-
' NRC Inspection Report 50-325/99-05,50-324/99-05 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a six-week period of resident inspection.
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The plant responded as designed to a Unit 2 reactor scram due to a loss of all circulating water intake pumps (CWIPs) and a low vacuum in the main condenser ' The licensee's )
Ooerations-The plant responded as designed to a Unit 2 reactor scram due to a loss of all circulating
J current design and methods to prevent or alleviate intake structure traveling screen differential pressure (d/p) anomalies were not effective. The licensee formulated corrective actions to address these deficiencies. These corrective actions included l
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water intake pumps (CWIPs) and a low vacuum in the main condenser ' The licensee's J
current design and methods to prevent or alleviate intake structure traveling screen differential pressure (d/p) anomalies were not effective. The licensee formulated corrective actions to address these deficiencies. These corrective actions included l
review of design changes in the intake canal and preparation of an abnormal operating procedure to handle intake canal anomalies that could affect traveling screen d/p's. The
review of design changes in the intake canal and preparation of an abnormal operating procedure to handle intake canal anomalies that could affect traveling screen d/p's. The
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inspectors noted problems with operator log taking in that some important activities and
inspectors noted problems with operator log taking in that some important activities and events were not logged. Similar problems had been observed during two other scrams
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l that occurred in 1999 (Section 01.1).
 
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' A corrective action violation was identified when the licensee failed to promptly identify
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and correct a condition adverse to quality with the 1B nuclear service water (NSW) pump l
discharge strainer differential pressure instrument,1-SW-PDIC-140. - As a result, the l
pump operated without adequate indication to verify that the required pump flow was being achieved. The licensee was recording d/p instrument readings for each of the service water pump discharge strainers but never questioned the abnormal indication on the 1B NSW pump discharge strainer (Soction O2.1)
A violation was identified when the licensee failed to correctly enter the applicable
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Technical Specification (TS) limiting condition for operation (LCO) when the 2A core spray system was removed from service coincident with a diesel generator (DG) 1
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events were not logged. Similar problems had been observed during two other scrams l that occurred in 1999 (Section 01.1).
I outage. The LCO specified entry into TS 3.0.3. The actions required by_TS 3.0.3 were not recognized or initiated as required and the redundancy of the core spray and low pressure coolant injection systems was not recognized (Section 04.1).
 
A continuing weakness with adverse condition identification by on-shift operations
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personnel was identified. The flow input for the reactor protection system flow bias scram was bypassed and a TS LCO was entered due to surveillance test activities on the 2A core spray subsystem. Despite operator knowledge that this adverse condition had occurred previously on several occasions, the condition was not brought to management's attention nor entered into the corrective action program (Section 07.1).


! =
' A corrective action violation was identified when the licensee failed to promptly identify and correct a condition adverse to quality with the 1B nuclear service water (NSW) pump l discharge strainer differential pressure instrument,1-SW-PDIC-140. - As a result, the l pump operated without adequate indication to verify that the required pump flow was being achieved. The licensee was recording d/p instrument readings for each of the service water pump discharge strainers but never questioned the abnormal indication on the 1B NSW pump discharge strainer (Soction O2.1)
. A violation was identified when the licensee failed to correctly enter the applicable Technical Specification (TS) limiting condition for operation (LCO) when the 2A core
,
,
spray system was removed from service coincident with a diesel generator (DG) 1 I outage. The LCO specified entry into TS 3.0.3. The actions required by_TS 3.0.3 were not recognized or initiated as required and the redundancy of the core spray and low pressure coolant injection systems was not recognized (Section 04.1).


. A continuing weakness with adverse condition identification by on-shift operations personnel was identified. The flow input for the reactor protection system flow bias scram was bypassed and a TS LCO was entered due to surveillance test activities on the 2A core spray subsystem. Despite operator knowledge that this adverse condition had occurred previously on several occasions, the condition was not brought to management's attention nor entered into the corrective action program (Section 07.1).
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Maintenance
Maintenance Maintenance activities observed were performed consistent with the applicable
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Maintenance activities observed were performed consistent with the applicable procedures, which were verified to be of the proper revision and implemented using the correct level-of-use. Three part communications were observed. Test equipment was
procedures, which were verified to be of the proper revision and implemented using the correct level-of-use. Three part communications were observed. Test equipment was
- verified to be within the current calibration cycle. Maintenance technicians took the opportunity to discuss expected indicatior.s during verification of instrument calibration and valving in and out of test equipment (Section M1.1).
- verified to be within the current calibration cycle. Maintenance technicians took the opportunity to discuss expected indicatior.s during verification of instrument calibration and valving in and out of test equipment (Section M1.1).


Observation and review of maintenance activities on a 2B NSW pump discharge strainer
.
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Observation and review of maintenance activities on a 2B NSW pump discharge strainer through-wall leak found no significant deficiencies in procedures, documentation, or worker actions (Section M1.2).
through-wall leak found no significant deficiencies in procedures, documentation, or worker actions (Section M1.2).


. The activities associated with the underwater inspection of the service water intake structure were completed thoroughly and professionally. A well-coordinated effort by plant staff allowed the inspections to be completed without incident (Section M1.3).
The activities associated with the underwater inspection of the service water intake
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structure were completed thoroughly and professionally. A well-coordinated effort by plant staff allowed the inspections to be completed without incident (Section M1.3).


. The Fix It Now (FIN) team maintenance process and activities were conducted in accordance with procedures and the scope of the FIN team. The inspectors noted no deficiencies during the activities observed (Section M1.5).
The Fix It Now (FIN) team maintenance process and activities were conducted in
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accordance with procedures and the scope of the FIN team. The inspectors noted no deficiencies during the activities observed (Section M1.5).


Plant Sucoort
Plant Sucoort The integrity of the site protected area boundary was intact. No obstructions or gaps
. The integrity of the site protected area boundary was intact. No obstructions or gaps were noted in the fence. Security personnel were appropriately stationed and attentive (Section S2.1).
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were noted in the fence. Security personnel were appropriately stationed and attentive (Section S2.1).


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ReDOrt Details
ReDOrt Details
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- Summary of Plant Status i
- Summary of Plant Status     i Unit 1 began the report period operating at 100 percent rated thermal power (RTP). On June 28 power was reduced to 73 percent RTP as a result of the loss of a circulating water intake pump due to high differential pressure across the traveling screens. The unit was returned to 100 percent RTP later that same day. On July 10 the unit was reduced to 80 percent RTP to support troubleshooting and repair on the SA feedwater heater. The unit was returned to 100 percent RTP on July 11 with the 4A and 5A feedwater heaters out of servic On July 21 power was reduced to 85 percent to support retuming the 4A and 5A feedwater heaters to service. Unit i returned to full power on July 22 and remained at full power for the duration of the inspection period. At the end of the period the unit had been operating continuously for 187 day Unit 2 began the report period operating at 100 percent RTP. On June 24 power was reduced to 80 percent RTP to support removal of the 4B and 58 feedwater heaters. The unit was returned to 100 percent RTP on June 25, with the 48 and SB feedwater heaters out of servic On June 28 an automatic reactor scram occurred from 100 percent RTP due to a main turbine trip on a loss of condenser vacuum as a result of a loss of three circulating water intake pump The unit was retumed to power on June 29 and achieved 100 percent RTP on July 1. At the end of the inspection period the unit had been operating continuously for 31 day l. Operations   1 O1 Conduct of Operations 01.1 Unit 2 Reactor Trio Due to Low Condenser Vacuum   ' Inspection Scope (71707)
Unit 1 began the report period operating at 100 percent rated thermal power (RTP). On June 28 power was reduced to 73 percent RTP as a result of the loss of a circulating water intake pump due to high differential pressure across the traveling screens. The unit was returned to 100 percent RTP later that same day. On July 10 the unit was reduced to 80 percent RTP to support troubleshooting and repair on the SA feedwater heater. The unit was returned to 100 percent RTP on July 11 with the 4A and 5A feedwater heaters out of service.
The inspectors responded to and reviewed a Unit 2 reactor scram Observations and Findinas On June 28 a Unit 2 reactor scram occurred due to low vacuum in the main condense The low vacuum was caused by a loss of circulating water to the main condenser. Unit 2 experienced a loss of all running circulating water intake pumps (CWIP) due to high differential pressures (d/p) across the CWIP traveling screens. The CWIPs had an automatic high d/p trip feature at a d/p of 36 inches across the traveling screen ,
 
The inspectors responded to the control room following the Unit 2 scram and found that both units were stabilized. The inspectors found that one CWIP tripped on Unit 1 due to a high d/p across the traveling screens. Operators immediately commenced an emergency power reduction, in accordance with procedures, to about 70 percent RT .
On July 21 power was reduced to 85 percent to support retuming the 4A and 5A feedwater heaters to service. Unit i returned to full power on July 22 and remained at full power for the duration of the inspection period. At the end of the period the unit had been operating continuously for 187 days.
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Unit 2 began the report period operating at 100 percent RTP. On June 24 power was reduced to 80 percent RTP to support removal of the 4B and 58 feedwater heaters. The unit was returned to 100 percent RTP on June 25, with the 48 and SB feedwater heaters out of service.
 
On June 28 an automatic reactor scram occurred from 100 percent RTP due to a main turbine trip on a loss of condenser vacuum as a result of a loss of three circulating water intake pumps.
 
The unit was retumed to power on June 29 and achieved 100 percent RTP on July 1. At the end of the inspection period the unit had been operating continuously for 31 days.
 
l. Operations
 
O1 Conduct of Operations 01.1 Unit 2 Reactor Trio Due to Low Condenser Vacuum
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a.
 
Inspection Scope (71707)
The inspectors responded to and reviewed a Unit 2 reactor scram b.
 
Observations and Findinas On June 28 a Unit 2 reactor scram occurred due to low vacuum in the main condenser.
 
The low vacuum was caused by a loss of circulating water to the main condenser. Unit 2 experienced a loss of all running circulating water intake pumps (CWIP) due to high differential pressures (d/p) across the CWIP traveling screens. The CWIPs had an automatic high d/p trip feature at a d/p of 36 inches across the traveling screens.
 
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The inspectors responded to the control room following the Unit 2 scram and found that both units were stabilized. The inspectors found that one CWIP tripped on Unit 1 due to a high d/p across the traveling screens. Operators immediately commenced an emergency power reduction, in accordance with procedures, to about 70 percent RTP.
 
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; The Unit 1 CWIP tripped almost immediately after the Unit 2 CWIPs tripped and the Unit 2 reactor scrammed.
 
The inspectors reviewed the licensee's post-event trip review report including process plant computer transient traces, and transient plots, and verified that the plant responded to the event as expected and within design parameters. The inspectors noted that the time from when the first control room high d/p alarm annunciated until Unit 1 was stabilized was about 40 minutes. During that time period, in an effort to reduce the high d/p, the licensee used fire hose spray to reduce what was initially reported to the control room as a fish buildup on the CWIP traveling screens. The time between the first Unit 2 CWIP trip and the last CWIP trip (on Unit 1) was two minutes.
 
The inspectors concluded that the use of fire hoses during the event was not effective in
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reducing or eliminating the high d/p's. Additionally, the inspectors found that the l
licensee's current design and methods to prevent or alleviate intake structure traveling screen d/p anomalies were not effective nor were the abnormal operating procedure (AOP) symptomatic entry conditions specifically relevant to this anomaly. The inspectors discussed these observations with the licensee. The licensee acknowledged the inspectors' observations as deficiencies. The deficiencies were addressed with corrective actions to: 1) review design changes in the intake canal, and 2) prepare an AOP to handle intake canal anomalies that could affect traveling screen d/p's.
 
The inspectors observed four significant plant changes and activities that were not logged in the operator logs. An example was the emergency power reduction on Unit 2 prior to the scram. This was a continuing deficiency noted by the inspectors which was observed and discussed in previous inspection reports on two reactor scrams in 1999.
 
The licensee acknowledged the log deficiencies and informed the inspectors that several hours were scheduled in the operating licensing training program to address log taking expectations.
 
The inspectors reviewed the root cause investigation for this event and noted that the root cause was identified as detritus, a rotting vegetable and plant life material, that plugged the CWIP traveling screens creating the high d/p's which tripped the CWIPs.
 
c.
 
Conclusions The plant responded as designed to a Unit 2 reactor scram due to a loss of all CWIPs
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and a low vacuum in the main condenser. The licensee's current design and methods to prevent or alleviate intake structure traveling screen d/p anomalies were not effective.
 
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The licensee addressed deficiencies identified with corrective actions to review design changes in the intake canal and the preparation of an AOP to handle intake canal anomalies that could affect traveling screen d/p. Deficiencies were identified in operator log taking in that some important activities and events were not logged. The inspectors noted that problems with log taking were repeated from two other scrams that occurred in 1999.
 
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  ; The Unit 1 CWIP tripped almost immediately after the Unit 2 CWIPs tripped and the Unit 2 reactor scramme The inspectors reviewed the licensee's post-event trip review report including process plant computer transient traces, and transient plots, and verified that the plant responded to the event as expected and within design parameters. The inspectors noted that the time from when the first control room high d/p alarm annunciated until Unit 1 was stabilized was about 40 minutes. During that time period, in an effort to reduce the high d/p, the licensee used fire hose spray to reduce what was initially reported to the control room as a fish buildup on the CWIP traveling screens. The time between the first Unit 2 CWIP trip and the last CWIP trip (on Unit 1) was two minute The inspectors concluded that the use of fire hoses during the event was not effective in ,
02 Operational Status of Facilities and Equipment 02.1 Operational Status of 1B Nuclear Service Water (NSW) Pumo a. -
reducing or eliminating the high d/p's. Additionally, the inspectors found that the l licensee's current design and methods to prevent or alleviate intake structure traveling screen d/p anomalies were not effective nor were the abnormal operating procedure (AOP) symptomatic entry conditions specifically relevant to this anomaly. The inspectors discussed these observations with the licensee. The licensee acknowledged the inspectors' observations as deficiencies. The deficiencies were addressed with corrective actions to: 1) review design changes in the intake canal, and 2) prepare an AOP to handle intake canal anomalies that could affect traveling screen d/p' The inspectors observed four significant plant changes and activities that were not logged in the operator logs. An example was the emergency power reduction on Unit 2 prior to the scram. This was a continuing deficiency noted by the inspectors which was observed and discussed in previous inspection reports on two reactor scrams in 199 The licensee acknowledged the log deficiencies and informed the inspectors that several hours were scheduled in the operating licensing training program to address log taking expectation The inspectors reviewed the root cause investigation for this event and noted that the l root cause was identified as detritus, a rotting vegetable and plant life material, that plugged the CWIP traveling screens creating the high d/p's which tripped the CWIP Conclusions      I
Insoection Scoos (71707. 62707)
        '
The inspectors conducted a walkdown of the Service Water (SW) building on July 22 observing equipment status and condition including operating performance of the SW system.
The plant responded as designed to a Unit 2 reactor scram due to a loss of all CWIPs )
and a low vacuum in the main condenser. The licensee's current design and methods to
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prevent or alleviate intake structure traveling screen d/p anomalies were not effectiv The licensee addressed deficiencies identified with corrective actions to review design changes in the intake canal and the preparation of an AOP to handle intake canal anomalies that could affect traveling screen d/p. Deficiencies were identified in operator log taking in that some important activities and events were not logged. The inspectors noted that problems with log taking were repeated from two other scrams that occurred in 1999.


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Observations and Findinas The inspectors identified that the 1B NSW pump discharge strainer local d/p indicator,1-SW-PDIC-140, was reading less than zero and pegged low. ' The inspectors noted that the 1B NSW pump was running at the time. The inspectors observed that all of the other running SW pump discharge strainer d/p indications were reading about 1 to 2 pounds per square inch differential (psid) pressure.
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The inspectors informed the licensee of the observed d/p indication on the 1B NSW j
pump discharge strainer, and questioned if there was something wrong with the indication. The licensee observed the indication and agreed that the d/p looked abnormal for a running pump. The licensee informed the inspectors that the indication
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would be investigated that day. However, the inspectors observed on July 23, July 26,
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and July 27 that the indication was reading about the same as on July 22. Each day the inspectors questioned the licensee about what action was going to be taken with regsrd to the questionable indication. The licensee each time responded that the indication
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would be investigated.


02 Operational Status of Facilities and Equipment 02.1 Operational Status of 1B Nuclear Service Water (NSW) Pumo a. - Insoection Scoos (71707. 62707)
.)
The inspectors conducted a walkdown of the Service Water (SW) building on July 22 observing equipment status and condition including operating performance of the SW syste J Observations and Findinas The inspectors identified that the 1B NSW pump discharge strainer local d/p indicator,1-SW-PDIC-140, was reading less than zero and pegged low. ' The inspectors noted that the 1B NSW pump was running at the time. The inspectors observed that all of the other running SW pump discharge strainer d/p indications were reading about 1 to 2 pounds per square inch differential (psid) pressur The inspectors informed the licensee of the observed d/p indication on the 1B NSW j pump discharge strainer, and questioned if there was something wrong with the ;
i On July 27, following discussions with the inspectors, the licensee initiated a deficiency log entry on the 1-SW-PDIC-140 instrument. This was the first time action was taken to investigate the abnormal d/p reading on the operating 18 NSW discharge strainer. The licensee informed the inspectors that since July 15 the high d/p annunciator for the 1B NSW discharge strainer was also not alarming at the required setpoint of 8 psid. On i
indication. The licensee observed the indication and agreed that the d/p looked l abnormal for a running pump. The licensee informed the inspectors that the indication ,
'
would be investigated that day. However, the inspectors observed on July 23, July 26, )
July 27, the licensee determined the 1B NSW pump was inoperable with both the local d/p indication and the high d/p annunciator functioning abnormally. A subsequent licensee investigation identified that the local d/p indicator was reading low due to a glycerin leak in the gage and silt in the instrument tube.
and July 27 that the indication was reading about the same as on July 22. Each day the l inspectors questioned the licensee about what action was going to be taken with regsrd to the questionable indication. The licensee each time responded that the indication ,
would be investigate .)
i On July 27, following discussions with the inspectors, the licensee initiated a deficiency log entry on the 1-SW-PDIC-140 instrument. This was the first time action was taken to investigate the abnormal d/p reading on the operating 18 NSW discharge strainer. The licensee informed the inspectors that since July 15 the high d/p annunciator for the 1B ;
NSW discharge strainer was also not alarming at the required setpoint of 8 psid. On i
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July 27, the licensee determined the 1B NSW pump was inoperable with both the local d/p indication and the high d/p annunciator functioning abnormally. A subsequent licensee investigation identified that the local d/p indicator was reading low due to a glycerin leak in the gage and silt in the instrument tub The significance of the d/p indications and annunciators not functioning while the pump was in operation was that if the pump strainer had become clogged the required system flow may not have been achieved for that pump and operators may not have been aware i
of a degraded operating condition. Additionally, throughout the previous two weeks !
several SW pump discharge strainers had become plugged with oyster shells in all of those cases both the high d/p annunciator alarmed and the local d/p instrument was used to verify the clogged condition. The associated pump was secured and the strainers were taken apart to remove the oyster shell i


E l .
The significance of the d/p indications and annunciators not functioning while the pump was in operation was that if the pump strainer had become clogged the required system l.


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flow may not have been achieved for that pump and operators may not have been aware of a degraded operating condition. Additionally, throughout the previous two weeks i
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several SW pump discharge strainers had become plugged with oyster shells in all of those cases both the high d/p annunciator alarmed and the local d/p instrument was used to verify the clogged condition. The associated pump was secured and the strainers were taken apart to remove the oyster shells.


The inspectors determined that the licensee was recording the d/p instrument readings for each of the SW pump discharge strainers but never questioned the abnormal indication on the 1B NSW pump discharge strainer. The inspectors discussed this with the licensee who stated that the concern would be investigated as part of the condition report (CR) that was generate CFR 50 Appendix B, Criterion XVI, Corrective Action, states that measures shall be established to assure that conditions adverse to quality such as deficiencies, defective material and equipment, and nonconformances are promptly identified and correcte The licensee failed to promptly identify and correct a condition adverse to quality on the
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The inspectors determined that the licensee was recording the d/p instrument readings for each of the SW pump discharge strainers but never questioned the abnormal indication on the 1B NSW pump discharge strainer. The inspectors discussed this with the licensee who stated that the concern would be investigated as part of the condition report (CR) that was generated.
 
10 CFR 50 Appendix B, Criterion XVI, Corrective Action, states that measures shall be established to assure that conditions adverse to quality such as deficiencies, defective material and equipment, and nonconformances are promptly identified and corrected.
 
The licensee failed to promptly identify and correct a condition adverse to quality on the
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1B NSW pump dischargc strainer differential pressure instrument,1-SW-PDIC-140, from
1B NSW pump dischargc strainer differential pressure instrument,1-SW-PDIC-140, from
! July 22 to July 27. The 1B NSW pump continued operating over the specified period of time without adequate indication to verify that the required pump flow was being achieved. 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 identified in the licensee's corrective action program as CR 99-01886,1B NSW Strainer 1 D/P. This violation is identified as NCV 50-325/99-05-01,1B NSW Strainer d/p I Corrective Actio '
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July 22 to July 27. The 1B NSW pump continued operating over the specified period of time without adequate indication to verify that the required pump flow was being achieved. 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 identified in the licensee's corrective action program as CR 99-01886,1B NSW Strainer
 
D/P. This violation is identified as NCV 50-325/99-05-01,1B NSW Strainer d/p I
Corrective Action.
 
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l l Conclusions
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[ A corrective action violation was identified when the licensee failed to promptly identify
c.
! and correct a condition adverse to quality with the 1B NSW pump discharge strainer differential pressure instrument,1-SW-PDIC-140. As a result, the pump continued operating over the specified period of time without adequate indication to verify that the
 
Conclusions
[
A corrective action violation was identified when the licensee failed to promptly identify
!
and correct a condition adverse to quality with the 1B NSW pump discharge strainer differential pressure instrument,1-SW-PDIC-140. As a result, the pump continued operating over the specified period of time without adequate indication to verify that the required pump flow was being achieved. The licensee was recording the d/p instrument
,
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required pump flow was being achieved. The licensee was recording the d/p instrument l . readings for each of the NSW pump discharge strainers but never questioned the ( abnormal indication on the 1B NSW pump discharge strainer.
l
. readings for each of the NSW pump discharge strainers but never questioned the (
abnormal indication on the 1B NSW pump discharge strainer.


l l O2.2 Reactor Core Isolation Coolina (RCIC) System Review (71707)
l l
On July 8, the inspectors performed a verification of those accessible valves and l electrical components for the RCIC system for Unit 1. Valves in the system reviewed j were appropriately labeled and no valve leakage or missing actuator handwheels were
O2.2 Reactor Core Isolation Coolina (RCIC) System Review (71707)
On July 8, the inspectors performed a verification of those accessible valves and l
electrical components for the RCIC system for Unit 1. Valves in the system reviewed j
were appropriately labeled and no valve leakage or missing actuator handwheels were
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identified. The inspectors observed that no equipment was staged which might threaten system performance. No transient combustibles were identified in the area nor were any ignition sources observed. Accessible valves and electrical components were verified to be correctly aligned in accordance with Operating Procedure 10P-16. " Reactor Core ,
identified. The inspectors observed that no equipment was staged which might threaten system performance. No transient combustibles were identified in the area nor were any ignition sources observed. Accessible valves and electrical components were verified to be correctly aligned in accordance with Operating Procedure 10P-16. " Reactor Core
,
Isolation Cooling System Operating Procedure," Rev. 44 and drawings D-25029 sheets 1 and 2.
Isolation Cooling System Operating Procedure," Rev. 44 and drawings D-25029 sheets 1 and 2.


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04 Operator Knowledge and Pr,rformance 04.1 ' Missed Inocerability of Redundant System
04 Operator Knowledge and Pr,rformance 04.1 ' Missed Inocerability of Redundant System
. Insoection' Scone (71707)
. a.
On July 16, the inspectors reviewed the circumstances surrounding the licensee's failure to enter Technical Specifications (TS) 3.5.1.J and 3.0.3 for Unit 2 after removing the A core spray (CS) pump from service.- Observations and Findinas On July 15, the licensee discovered that TS 3.5.1.J, ECCS Operating, and TS 3. . should have been entered as a result of the 2A CS system being removed from service for scheduled maintenance concurrent with a diesel generator (DG) 1 outage. The licensee reported this event in License Event Report (LER) 50-324/99-07. The determination of a missed inoperability was made as a result of the following sequence of events:
 
July 12 - 4:06 DG1 placed under clearance and declared inoperable for scheduled maintenance. Entered 7-day LCO per TS 3.8. ;
Insoection' Scone (71707)
On July 16, the inspectors reviewed the circumstances surrounding the licensee's failure to enter Technical Specifications (TS) 3.5.1.J and 3.0.3 for Unit 2 after removing the A core spray (CS) pump from service.-
b.
 
Observations and Findinas On July 15, the licensee discovered that TS 3.5.1.J, ECCS Operating, and TS 3.0.3
. should have been entered as a result of the 2A CS system being removed from service for scheduled maintenance concurrent with a diesel generator (DG) 1 outage. The licensee reported this event in License Event Report (LER) 50-324/99-07. The determination of a missed inoperability was made as a result of the following sequence of events:
July 12 - 4:06 a.m.
 
DG1 placed under clearance and declared inoperable for scheduled maintenance. Entered 7-day LCO per TS 3.8.1.D
;
July 14 - 10:30 a.m. 2A CS was placed under clearance and declared inoperable for scheduled maintenance. Entered 7-day LCO for one emergency core cooling system (ECCS) subsystem being inoperable per TS
July 14 - 10:30 a.m. 2A CS was placed under clearance and declared inoperable for scheduled maintenance. Entered 7-day LCO for one emergency core cooling system (ECCS) subsystem being inoperable per TS
  .3.5. July 14 - 6:50 A CS subsystem restored a' nd declared operable. Exited TS 3.5. July 15 - 12:52 DG1 restored and declared operable. Exited TS 3.8. The inspectors reviewed the applicable TSs, operators logs, CR 99-1776, Safety Function Determination, and had discussions with the operations perconnel involve Through the discussions with operations personnel, it was determined that 4 hours after
.3.5.1.A 2A CS subsystem restored ' nd declared operable. Exited TS July 14 - 6:50 p.m.
' the removal of the 2A CS pump at 10:30 a.m. on July 14, the associated low pressure coo! ant injection (LPCI) subsystem should have been declared inoperable. The 2A LPCI subsystem was inoperable because TS 3.8.1.D required that, should the subsystem redundant to a system supported by DG1 (2A CS) become inoperable, the supported subsystem (2A LPCI) shall be declared inoperable within 4 hours. As a result of having two ECCS subsystems inoperable, the licensee should have entered LCO 3.5.1.J which required the immediate entry into TS 3.0.3 and the initiation of a plant shutdown within 1 hour. The inspectors concluded that the required LCOs were not entered and the TS 3.0.3-required shutdown was never initiate i
 
a 3.5.1.A July 15 - 12:52 a.m.
 
DG1 restored and declared operable. Exited TS 3.8.1.D The inspectors reviewed the applicable TSs, operators logs, CR 99-1776, Safety Function Determination, and had discussions with the operations perconnel involved.


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Through the discussions with operations personnel, it was determined that 4 hours after
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' the removal of the 2A CS pump at 10:30 a.m. on July 14, the associated low pressure coo! ant injection (LPCI) subsystem should have been declared inoperable. The 2A LPCI subsystem was inoperable because TS 3.8.1.D required that, should the subsystem redundant to a system supported by DG1 (2A CS) become inoperable, the supported subsystem (2A LPCI) shall be declared inoperable within 4 hours. As a result of having two ECCS subsystems inoperable, the licensee should have entered LCO 3.5.1.J which required the immediate entry into TS 3.0.3 and the initiation of a plant shutdown within 1 hour. The inspectors concluded that the required LCOs were not entered and the TS 3.0.3-required shutdown was never initiated.
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The licensee's decision to remove the 2A CS pump from service indicated that it was unknown at the time that the CS and LPCI systems were redundant. The error was the l
assumption that one subsystem of CS was redundant to the other and had no effect on LPCI.


The licensee's decision to remove the 2A CS pump from service indicated that it was unknown at the time that the CS and LPCI systems were redundant. The error was the l assumption that one subsystem of CS was redundant to the other and had no effect on LPC TS 3.5.1.J requires that with two or more low pressure emergency core cooling system l - (ECCS) injection spray subsystems inoperable, enter LCO 3.0.3 immediately. LCO 3.0.3 l requires, in part, that if directed by an associated ACTION, the unit shall be placed in a
TS 3.5.1.J requires that with two or more low pressure emergency core cooling system l
- (ECCS) injection spray subsystems inoperable, enter LCO 3.0.3 immediately. LCO 3.0.3 l
requires, in part, that if directed by an associated ACTION, the unit shall be placed in a MODE in which the LCO is not applicable. This ACTION is required to be initiated within
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MODE in which the LCO is not applicable. This ACTION is required to be initiated within i
i 1 hour. Contrary to the above, on July 14,1999,'at 3:30 p.m., the licensee failed to I
._ 1 hour. Contrary to the above, on July 14,1999,'at 3:30 p.m., the licensee failed to I initiate actions within 1 hour to place Unit 2 in a MODE in which the associated ACTION l of TS 3.5.1.J was not applicable when two ECCS subsystems were inoperable. This l Severity Level IV violation is being treated as an NCV, consistent with Appendix C of the j NRC Enforcement Policy. This violation is identified in the licensee's corrective action
._
initiate actions within 1 hour to place Unit 2 in a MODE in which the associated ACTION l
of TS 3.5.1.J was not applicable when two ECCS subsystems were inoperable. This l
Severity Level IV violation is being treated as an NCV, consistent with Appendix C of the j
NRC Enforcement Policy. This violation is identified in the licensee's corrective action
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program as CR 99-1776, Safety Function Determination, and is identified as NCV 50-324/99-05-02, Failure to Enter TS 3. Operations management indicated that operator knowledge regarding redundant and supported equipment did not meet management expectations. It was also stated by management that earlier use of the safety function determination program (SFDP)
program as CR 99-1776, Safety Function Determination, and is identified as NCV 50-324/99-05-02, Failure to Enter TS 3.0.3.
contained in the Technical Requirements Manual (TRM) would have alerted the operators to the required inoperability of the LPCI subsystem. The licensee initiated CR 99-1792, ITS LCO Accuracy, to address the declining trend in identifying correct LCO requirements. Also, during review of the operator's logs the inspectors could not locate any record of the entry into TS 3.0.3 once the condition was identified. The licensee was notified and an entry into the logs was backdated to document the TS-required conditio Conclusions A violation was identified when the licensee failed to correctly enter the applicable TS LCO when the 2A core spray system was removed from service coincident with a DG1 outage. The LCO specified entry into TS 3.0.3. The actions required by TS 3.0.3 were not recognized or initiated as required and the redundancy of the CS and LPCI systems was not recognize .2 Unit 0 Outside Auxiliary Operator Daily Rounds (71707)
 
Operations management indicated that operator knowledge regarding redundant and supported equipment did not meet management expectations. It was also stated by management that earlier use of the safety function determination program (SFDP)
contained in the Technical Requirements Manual (TRM) would have alerted the operators to the required inoperability of the LPCI subsystem. The licensee initiated CR 99-1792, ITS LCO Accuracy, to address the declining trend in identifying correct LCO requirements. Also, during review of the operator's logs the inspectors could not locate any record of the entry into TS 3.0.3 once the condition was identified. The licensee was notified and an entry into the logs was backdated to document the TS-required condition.
 
c.
 
Conclusions A violation was identified when the licensee failed to correctly enter the applicable TS LCO when the 2A core spray system was removed from service coincident with a DG1 outage. The LCO specified entry into TS 3.0.3. The actions required by TS 3.0.3 were not recognized or initiated as required and the redundancy of the CS and LPCI systems was not recognized.
 
04.2 Unit 0 Outside Auxiliary Operator Daily Rounds (71707)
On July 28, the inspectors observed an auxiliary operator during the performance of Operating instruction 101-03.4, " Unit 0 Outside Auxiliary Operator Daily Check Sheets,"
On July 28, the inspectors observed an auxiliary operator during the performance of Operating instruction 101-03.4, " Unit 0 Outside Auxiliary Operator Daily Check Sheets,"
Rev. 74. The inspectors observed acceptable adherence to the procedure. During the I rounds the inspectors noted that the operator had good system kr.owledge and thoroughly reviewed the operating equipment to ensure that the operating parameters were within the normal expected range. The operator observed water on the floor of the off-gas building and identified a ventilation duct as the source of the water. He immediately contacted the control room to report the deficiency and requested that a health physics technician survey the area prior to cleaning the water. The inspectors
Rev. 74. The inspectors observed acceptable adherence to the procedure. During the rounds the inspectors noted that the operator had good system kr.owledge and thoroughly reviewed the operating equipment to ensure that the operating parameters were within the normal expected range. The operator observed water on the floor of the off-gas building and identified a ventilation duct as the source of the water. He immediately contacted the control room to report the deficiency and requested that a health physics technician survey the area prior to cleaning the water. The inspectors
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also noted that proper housekeeping practices were demonstrated, such as the removal-of excess oil from around pumps and motors.
 
Quality Assurance in Operations 07.1 ' Excess Flow Check Valve indications a.
 
Inspection Scope (71707. 37551)
The inspectors reviewed the corrective actions associated with a penetration line break
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annunciator received on Unit 2. This annunciator could also be indicative of a J
malfunction or inadvertent positioning of the penetration line excess flow check valve j
(EFCV).
 
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also noted that proper housekeeping practices were demonstrated, such as the removal-of excess oil from around pumps and motor Quality Assurance in Operations 07.1 ' Excess Flow Check Valve indications Inspection Scope (71707. 37551)
Observations and Findinos
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The inspectors reviewed the corrective actions associated with a penetration line break annunciator received on Unit 2. This annunciator could also be indicative of a J malfunction or inadvertent positioning of the penetration line excess flow check valve j
On July 15, during routine review of the operator logs, the inspectors noted an entry which indicated that a penetration line break annunciator had been received during surveillance test activities on the 2A CS subsystem. The flow instrument was bypassed and a TS LCO was entered due to the affected penetration line providing input into the 1-B21-N024A/B reactor recirculation flow instruments. These flow instruments provide
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  (EFCV). Observations and Findinos
the flow portion of the reactor protection system (RPS) flow bias scram. A walkdown of the instrument line was performed to verify that no line leak existed. Upon confirmation of no leakage, no increase in area temperatures or radiation levels, and no change in related instrumentation response, the RPS flow input was restored and the associated LCO exited. The logs indicated that the unexpected closing of the penetration had been seen previously on three other occasions during stroking of the CS full flow test valve for surveillance testing.
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On July 15, during routine review of the operator logs, the inspectors noted an entry which indicated that a penetration line break annunciator had been received during surveillance test activities on the 2A CS subsystem. The flow instrument was bypassed and a TS LCO was entered due to the affected penetration line providing input into the 1-B21-N024A/B reactor recirculation flow instruments. These flow instruments provide ;
~ The operator logs, Lessons Leamed database, and associated procedures were reviewed by the inspectors. During discussion with operations personnel the inspectors questioned why no CR had been generated for the repetitive condition. The inspectors were informed that for this condition a work request / job order (WR/JO) would be written and that the condition had been previously noted in the Lessons Leamed database and therefore did not need a CR. Further discussions revealed that the system engineer was unaware of this condition.
the flow portion of the reactor protection system (RPS) flow bias scram. A walkdown of the instrument line was performed to verify that no line leak existed. Upon confirmation of no leakage, no increase in area temperatures or radiation levels, and no change in related instrumentation response, the RPS flow input was restored and the associated LCO exited. The logs indicated that the unexpected closing of the penetration had been seen previously on three other occasions during stroking of the CS full flow test valve for surveillance testin ~ The operator logs, Lessons Leamed database, and associated procedures were reviewed by the inspectors. During discussion with operations personnel the inspectors questioned why no CR had been generated for the repetitive condition. The inspectors were informed that for this condition a work request / job order (WR/JO) would be written and that the condition had been previously noted in the Lessons Leamed database and therefore did not need a CR. Further discussions revealed that the system engineer was unaware of this conditio The inspectors questioned operations management as to the need for a CR as a result of the repetitive LCO entry on safety-related RPS instrumentation, whether this condition was an operator workaround, and whether similar conditions were in the Lessons Learned database or other programs. The inspectors were informed that a CR should i have been initiated to address the repetitive nature of this condition. In addition, members of the operations organization not on-shift were performing independent reviews of logged plant events to assure that CRs were being initiated as appropriat The inspectors noted that subsequent to this discussion CR 99-1858, timely initiation of j CRs, was initiated as a result of other licensee findings regarding prompt recording of i operational issues into the corrective action program (CAP). As a result of this finding, ;
 
The inspectors questioned operations management as to the need for a CR as a result of the repetitive LCO entry on safety-related RPS instrumentation, whether this condition was an operator workaround, and whether similar conditions were in the Lessons Learned database or other programs. The inspectors were informed that a CR should i
have been initiated to address the repetitive nature of this condition. In addition, members of the operations organization not on-shift were performing independent reviews of logged plant events to assure that CRs were being initiated as appropriate.
 
The inspectors noted that subsequent to this discussion CR 99-1858, timely initiation of j
CRs, was initiated as a result of other licensee findings regarding prompt recording of i
operational issues into the corrective action program (CAP). As a result of this finding,
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NCV 50-325(324)/99-04-02, Failure to Identify Conditions Adverse to Quality (NRC l
NCV 50-325(324)/99-04-02, Failure to Identify Conditions Adverse to Quality (NRC l
Inspection Report 50-325(324)/99-04 dated July 19,1999), and other licensee-identified issues, the inspectors concluded that a continuing weakness existed with the identification of adverse conditions by on-shift operations personne Conclusions A continuing weakness with adverse condition identification by on-shift operations personnel was identified. The flow input for the RPS flow bias scram was bypassed and
Inspection Report 50-325(324)/99-04 dated July 19,1999), and other licensee-identified issues, the inspectors concluded that a continuing weakness existed with the identification of adverse conditions by on-shift operations personnel.
' a TS LCO was entered due to surveillance test activities on the 2A core spray subsystem. Despite operator knowledge that this condition had occurred previously on several occasions, the condition was not brought to management's attention nor entered into the CAP.
 
c.
 
Conclusions A continuing weakness with adverse condition identification by on-shift operations personnel was identified. The flow input for the RPS flow bias scram was bypassed and
' a TS LCO was entered due to surveillance test activities on the 2A core spray subsystem. Despite operator knowledge that this condition had occurred previously on several occasions, the condition was not brought to management's attention nor entered into the CAP.


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11. Maintenance M1 Conduct of Maintenance M1.1 Maintenance Activities Inspection Scoce (61726. 71750)
11. Maintenance M1 Conduct of Maintenance M1.1 Maintenance Activities a.
The inspectors reviewed all or portions of the following surveillance tests and/or i
 
maintenance activities:
Inspection Scoce (61726. 71750)
  .. Attachment 2 to Environment & Radiation Control Procedure OE&RC-1231,
The inspectors reviewed all or portions of the following surveillance tests and/or maintenance activities:
,  " Sampling and Analysis for Tritiated Water in Airborne Effluents," 'Rev.16, l .
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Attachment 4-2 to Environment & Radiation Control Procedure OE&RC-2002,
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  " Sampling of Radioactive Airborne Effluent Releases," Rev. 32, and
Attachment 2 to Environment & Radiation Control Procedure OE&RC-1231,
  . Maintenance Surveillance Test 1MST-RCIC22Q, "RCIC Steam Line Low Pressure Inst. Channel Calibration, Rev. Observations and Findinas The inspectors observed that good supervisory oversight was provided. Procedures used were of the proper revision and test equipment was within the current calibration cycle. Satisfactory three-part communications were observed. During the conduct of l 11MST-RCIC22Q, the maintenance technicians took the opportunity to discuss expected indications during verification of instrument calibration and valving in and out of test equipment. Technicians were knowledgeable of the evolution and expected instrument response.
" Sampling and Analysis for Tritiated Water in Airborne Effluents," 'Rev.16,
,
l Attachment 4-2 to Environment & Radiation Control Procedure OE&RC-2002,
.
" Sampling of Radioactive Airborne Effluent Releases," Rev. 32, and Maintenance Surveillance Test 1MST-RCIC22Q, "RCIC Steam Line Low
.
Pressure Inst. Channel Calibration, Rev. 7.
 
b.
 
Observations and Findinas The inspectors observed that good supervisory oversight was provided. Procedures used were of the proper revision and test equipment was within the current calibration cycle. Satisfactory three-part communications were observed. During the conduct of l
11MST-RCIC22Q, the maintenance technicians took the opportunity to discuss expected i.
 
indications during verification of instrument calibration and valving in and out of test equipment. Technicians were knowledgeable of the evolution and expected instrument response.


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M1.2 f 2B NSW Pumo Discharoe Strainer Leak Reoair l ~ Insoection Scooe (62707)
M1.2 f 2B NSW Pumo Discharoe Strainer Leak Reoair l
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~a.
 
Insoection Scooe (62707)
l The inspectors observed and reviewed the repair of a through wall leak on the 2B NSW pump discharge strainer housing. The inspectors observed the maintenance on July 21 and July 22.
l The inspectors observed and reviewed the repair of a through wall leak on the 2B NSW pump discharge strainer housing. The inspectors observed the maintenance on July 21 and July 22.


! ' Observations and Findinos L
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The inspectors observed the maintenance on the 2B NSW pump discharge' strainer l- ~ housing in the SW building and found that the workers were knowledgeable and skilled.
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' Observations and Findinos L
The inspectors observed the maintenance on the 2B NSW pump discharge' strainer l-
~ housing in the SW building and found that the workers were knowledgeable and skilled.


l The inspectors observed good housekeeping during the maintenance activity. Review of
l The inspectors observed good housekeeping during the maintenance activity. Review of
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the work package documentation during and after the maintenance revealed that the procedures and other required documentation were on hand and were used l appropriately during the observed activities. The required signatures and maintenance sequence were maintained as the activities progressed. The work package review following the completion of the maintenance found no significant discrepancies.
the work package documentation during and after the maintenance revealed that the procedures and other required documentation were on hand and were used l
appropriately during the observed activities. The required signatures and maintenance sequence were maintained as the activities progressed. The work package review following the completion of the maintenance found no significant discrepancies.


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M1.3 Service Water Intake Structure insoection l
M1.3 Service Water Intake Structure insoection l
' Inspection Scooe (62707)
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On July 4, the licensee identified in a condition report that the 1 A NSW pump was
Inspection Scooe (62707)
  . inoperable due to an inability to develop sufficient discharge pressure. The initial troubleshooting indicated that the problem was due to plugging of the discharge straine !
l On July 4, the licensee identified in a condition report that the 1 A NSW pump was
l Three other service water pumps were also exhibiting higher-than-normal strainer I l differential pressure. The inspectors observed the licensee's response to the issue, I l
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which included an inspection of the SW pump intake bay l Observations and Findinos l On July 8, the inspectors observed the performance of preventive maintenance s
. inoperable due to an inability to develop sufficient discharge pressure. The initial troubleshooting indicated that the problem was due to plugging of the discharge strainer.
procedure, OPM-STU 500, " Service Water intake Structure Inspection and Cleaning,"
 
Rev. 2, under work request 99-AEWC1. Divers performed the underwater inspection in accordance with administrative instruction 0A1-131, " Conduct of Diving Operations,"
l Three other service water pumps were also exhibiting higher-than-normal strainer l
; Rev. 3. During the inspections, one diver was in the water and two other qualified divers
differential pressure. The inspectors observed the licensee's response to the issue, I
l which included an inspection of the SW pump intake bays.
 
b.
 
Observations and Findinos l
On July 8, the inspectors observed the performance of preventive maintenance procedure, OPM-STU 500, " Service Water intake Structure Inspection and Cleaning,"
s Rev. 2, under work request 99-AEWC1. Divers performed the underwater inspection in accordance with administrative instruction 0A1-131, " Conduct of Diving Operations,"
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Rev. 3. During the inspections, one diver was in the water and two other qualified divers
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acted as support and safety personnel. Maintenance technicians provided foreign material exclusion (FME) area support during the dives to ensure that no foreign material i entered the intake bays while they were open for inspection. The FME zone was moved l from bay to bay as the inspections were completed. In addition to the visual inspection, the divers measured the sitt and shelllayer at the bottom of each bay and the hard shell growth on the walls. The inspection of the four bays was well-coordinated and efficiently managed. All work observed was performed with the work package present and in us The inspections were completed safely and without incident. The inspections indicated
acted as support and safety personnel. Maintenance technicians provided foreign material exclusion (FME) area support during the dives to ensure that no foreign material i
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entered the intake bays while they were open for inspection. The FME zone was moved l
  . that the maximum hard shell growth on the walls was 5 inches and the maximum height of the silt and shell mixture on the floor of the bays was 3 feet. This was within the
from bay to bay as the inspections were completed. In addition to the visual inspection, the divers measured the sitt and shelllayer at the bottom of each bay and the hard shell growth on the walls. The inspection of the four bays was well-coordinated and efficiently managed. All work observed was performed with the work package present and in use.


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The inspections were completed safely and without incident. The inspections indicated
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. that the maximum hard shell growth on the walls was 5 inches and the maximum height
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of the silt and shell mixture on the floor of the bays was 3 feet. This was within the
 
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acceptance criteria of OPM-STU 500; however, the presence of a large number of shells was noted. The licensee suspects that the shell growth occurred during a period of no l SW chlorination when the system was being repaired. The inspectors reviewed the
acceptance criteria of OPM-STU 500; however, the presence of a large number of shells was noted. The licensee suspects that the shell growth occurred during a period of no l
    .
SW chlorination when the system was being repaired. The inspectors reviewed the
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previous inspection results from January 1999, which indicated a similar buildup of silt and hard growth. The licensee is reviewing the adequacy of the current annual inspection program in light of the apparent impact of reduced or nr chlorination in the SW syste M1.4 Conclusions of Conduct of Maintenance The activities observed were performed consistent with the applicable procedures, which .
previous inspection results from January 1999, which indicated a similar buildup of silt and hard growth. The licensee is reviewing the adequacy of the current annual inspection program in light of the apparent impact of reduced or nr chlorination in the SW system.
were verified to be of the proper revision and implemented using the correct level-of-us Three-part communications were observed. Test equipment v:as verified to be within the
 
M1.4 Conclusions of Conduct of Maintenance The activities observed were performed consistent with the applicable procedures, which.
were verified to be of the proper revision and implemented using the correct level-of-use.
 
Three-part communications were observed. Test equipment v:as verified to be within the
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current calibration cycle. Maintenance technicians took th' opportunity to discuss expected indications during verification of instrument calibration and valving in and out of
current calibration cycle. Maintenance technicians took th' opportunity to discuss expected indications during verification of instrument calibration and valving in and out of l
' test equipmen ,
test equipment.
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l Observation and review of maintenance activities on a 2B NSW pump discharge strainer l through wall leak found no significant deficiencies in procedures, documentation, or
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worker action J l
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The activities associated with the underwater inspection of the SW intake structure were l l completed thoroughly and professionally. A well-coordinated effort by plant staff allowed the inspections to be completed without inciden ,
l Observation and review of maintenance activities on a 2B NSW pump discharge strainer l
; M1.5 Fix It Now (FIN) Team Maintenance Observations Inspection Scope (62707)
through wall leak found no significant deficiencies in procedures, documentation, or
L The inspectors observed and reviewed FIN team maintenar.ce activities on DG 3 and the l 28 NSW pump.
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worker actions.
 
J The activities associated with the underwater inspection of the SW intake structure were l
l completed thoroughly and professionally. A well-coordinated effort by plant staff allowed the inspections to be completed without incident.
 
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M1.5 Fix It Now (FIN) Team Maintenance Observations
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Inspection Scope (62707)
L The inspectors observed and reviewed FIN team maintenar.ce activities on DG 3 and the l
28 NSW pump.


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i On June 28, the inspectors observed FIN team maintenance on a DG 3 jacket water flange leak. The inspectors found that the FIN team maintenance process was well- .
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structured. Assigning the activity to the FIN team was within the scope of the team l
 
! activities and was within procedural guidance. A pre-work briefing was conducted, which !
Observations and Findinas i
        "
i On June 28, the inspectors observed FIN team maintenance on a DG 3 jacket water l.
was observed by the inspectors, and given by the FIN team supervisor. The job scope was well thought out and prepared. The FIN team workers performed the job according to the work package requirements. The entire process was sensitive to maintenance on
 
; safety-related equipment. The inspectors noted no deficiencies during observations of
flange leak. The inspectors found that the FIN team maintenance process was well-
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structured. Assigning the activity to the FIN team was within the scope of the team
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activities and was within procedural guidance. A pre-work briefing was conducted, which
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was observed by the inspectors, and given by the FIN team supervisor. The job scope was well thought out and prepared. The FIN team workers performed the job according to the work package requirements. The entire process was sensitive to maintenance on safety-related equipment. The inspectors noted no deficiencies during observations of
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activities or review of paperwor r
activities or review of paperwor r
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On July 23, the inspectors observed a packing adjustment by a FIN team member on the
On July 23, the inspectors observed a packing adjustment by a FIN team member on the
; 2B NSW pump. The inspectors found that a work package was used appropriately since j the packing served as an inservice inspection (ISI) boundary and the pump was safety-i related. The worker was knowledgeable and skilled.
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2B NSW pump. The inspectors found that a work package was used appropriately since j
the packing served as an inservice inspection (ISI) boundary and the pump was safety-i related. The worker was knowledgeable and skilled.
 
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Conclusions l
The FIN team maintenance process and activities were conducted in accordance with l
procedures and the scope of the FIN team. The inspectors noted no deficiencies during
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the activities observed.


f l Conclusions l The FIN team maintenance process and activities were conducted in accordance with l procedures and the scope of the FIN team. The inspectors noted no deficiencies during
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M8 Miscellaneous Maintenance lasues (92700)
M8.1 (Closed) Licensee Event Report (LER) 50-325 (324)/99-03: Chlorinator Flange Leak Results in Control Building Emergency Air Filtration System Actuation. The event l
documented in this LER occurred on July 24,1997; however, at the time of the control l
building emergency air filtration (CBEAF) system actuation, the CBEAF system was not I
classified as an engineering safety feature. As a result, the event was determined by the l
licensee as not reportable at that time in accordance with the requirements of 10 CFR
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50.73. The CBEAF system was subsequently reclassified as an engineering safety feature and this LER was submitted March 10,1999, to address the July 1997 event.


l l M8 Miscellaneous Maintenance lasues (92700)
While conducting post-maintenance leak checks following repair of the #2 chlorinator, l
M8.1 (Closed) Licensee Event Report (LER) 50-325 (324)/99-03: Chlorinator Flange Leak Results in Control Building Emergency Air Filtration System Actuation. The event l documented in this LER occurred on July 24,1997; however, at the time of the control l building emergency air filtration (CBEAF) system actuation, the CBEAF system was not I classified as an engineering safety feature. As a result, the event was determined by the l licensee as not reportable at that time in accordance with the requirements of 10 CFR !
chlorine gas was detected leaking from the bolted flange connecting the gas inlet line
50.73. The CBEAF system was subsequently reclassified as an engineering safety feature and this LER was submitted March 10,1999, to address the July 1997 even While conducting post-maintenance leak checks following repair of the #2 chlorinator, l chlorine gas was detected leaking from the bolted flange connecting the gas inlet line
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l spool piece to the #2 chlorinator block heater. This resulted in the CBEAF system !
spool piece to the #2 chlorinator block heater. This resulted in the CBEAF system actuation and alignment to the chlorination protection mode. The system isolation signal I
actuation and alignment to the chlorination protection mode. The system isolation signal I
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cleared shortly thereafter and the CBEAF system was restored to its normal configuration. The cause of this event was an inadequately manufactured gas intelline spool piece. Additionally, a contributing factor was the lack of a defined process for nitrogen pressure testing of the gaseous portion of the chlorination system.
cleared shortly thereafter and the CBEAF system was restored to its normal configuration. The cause of this event was an inadequately manufactured gas intelline spool piece. Additionally, a contributing factor was the lack of a defined process for nitrogen pressure testing of the gaseous portion of the chlorination system.


l ' The licensee's corrective actions included replacing and pressure testing the spool piece and performing an inspection of the in-stock spare spool pieces. The appropriate i maintenance procedures were revised to require performance of a nitrogen pressure test
l
! of the liquid and gaseous portions of the chlorination system piping in the event those portions of the system are open for maintenance. The inspectors verified that the post- !
' The licensee's corrective actions included replacing and pressure testing the spool piece and performing an inspection of the in-stock spare spool pieces. The appropriate i
maintenance testing program and work planning procedures were revise !
maintenance procedures were revised to require performance of a nitrogen pressure test
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of the liquid and gaseous portions of the chlorination system piping in the event those portions of the system are open for maintenance. The inspectors verified that the post-maintenance testing program and work planning procedures were revised.
 
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j   lli. Enoineerina i E8 Miscellaneous Engineering issues (92700,92903)
j lli. Enoineerina i
l E (Closed) Inspection Fol!owuo item 50-325(324)/98-06-01: Multiple Failures of SSFP The inspectors reviewed the corrective actions fnim the numerous CRs generated during the Unit 11998 refueling outage. These CRs des :ribed the numerous failures of the supplemental spent fuel pool cooling (SSFPC) system, the disposition of these failures, l
E8 Miscellaneous Engineering issues (92700,92903)
l E8.1 (Closed) Inspection Fol!owuo item 50-325(324)/98-06-01: Multiple Failures of SSFPC.
 
The inspectors reviewed the corrective actions fnim the numerous CRs generated during the Unit 11998 refueling outage. These CRs des :ribed the numerous failures of the supplemental spent fuel pool cooling (SSFPC) system, the disposition of these failures, l
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and the various root causes in accordance with 10 CFR 50.65, the Maintenance Rule
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(MR). The inspectors found that system reliability and performance had improved as a result of modifications in the set-up and operation of the system. The number of MR functional failures (FF) was reduced from approximately five last outage to two this
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recent outage.
 
The inspectors questioned if the cyclical performance in and out of MR paragraph (a)(1)
criteria had been reviewed. The continuing performance challenges and special j
conditions for which SSFPC was used had caused the system engineer to reconsider the performance criteria and the FF definitions. Changes to the system monitoring under MR paragraph (a)(2) criteria were proposed to be presented to the expert panel in October 1999. The licensee indicated that the remaining cause of most of the failures during the most recent outage was attributed to reliability issues with the secondary side power supply. The inspectors noted that additional actions were being planned to address this condition.


and the various root causes in accordance with 10 CFR 50.65, the Maintenance Rule ,
IV. Plant Support S2 Status of Security Facilities and Equipment S2.1 hotected Area Observations (71750)
(MR). The inspectors found that system reliability and performance had improved as a !
On July 19, the inspectors verified the integrity of the protected area (PA) fence and security static postings. The inspectors verified that members of the security force were present and attentive.. No holes or gaps were observed in the PA fence. The isolation zones were observed to be free of transient materials. Observations from the secondary i
result of modifications in the set-up and operation of the system. The number of MR
access station revealed no obstructions of the video surveillance equipment.
, functional failures (FF) was reduced from approximately five last outage to two this i recent outag I The inspectors questioned if the cyclical performance in and out of MR paragraph (a)(1)
criteria had been reviewed. The continuing performance challenges and special j conditions for which SSFPC was used had caused the system engineer to reconsider the performance criteria and the FF definitions. Changes to the system monitoring under MR paragraph (a)(2) criteria were proposed to be presented to the expert panel in October 1999. The licensee indicated that the remaining cause of most of the failures during the most recent outage was attributed to reliability issues with the secondary side power supply. The inspectors noted that additional actions were being planned to address this conditio IV. Plant Support S2 Status of Security Facilities and Equipment S2.1 hotected Area Observations (71750)
On July 19, the inspectors verified the integrity of the protected area (PA) fence and security static postings. The inspectors verified that members of the security force were present and attentive.. No holes or gaps were observed in the PA fence. The isolation zones were observed to be free of transient materials. Observations from the secondary i access station revealed no obstructions of the video surveillance equipmen ]
I V. Mananement Meetinos  j XI Exit Meeting Summary The inspector presented the inspection results to members of licensee management at the conclusion of the inspection on August 9,1999. The licensee acknowledged the ,
findings presente i
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V. Mananement Meetinos j
XI Exit Meeting Summary The inspector presented the inspection results to members of licensee management at the conclusion of the inspection on August 9,1999. The licensee acknowledged the
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findings presented.


PARTIAL LIST OF PERSONS CONTACTED Licensee A. Brittain, Manager Security N. Gannon, Manager Operations J. Gawron, Manager Nuclear Assessment M. Herrell, Training Manager 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 E. Quidley, Manager Maintenance S. Rogers, Manager Outage and Scheduling INSPECTION PROCEDURES USED iP 37551: Onsite Engineering IP 61726: Surveillance Observations IP 62707: Maintenance Observations IP 71707: Plant Operaticr.:: Program IP 71750: Plant Support Activities IP 92700: On-Site Follow Up of Written Reports IP 92903: Followup - Engineering
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PARTIAL LIST OF PERSONS CONTACTED Licensee A. Brittain, Manager Security N. Gannon, Manager Operations J. Gawron, Manager Nuclear Assessment M. Herrell, Training Manager 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 E. Quidley, Manager Maintenance S. Rogers, Manager Outage and Scheduling INSPECTION PROCEDURES USED iP 37551:
Onsite Engineering IP 61726:
Surveillance Observations IP 62707:
Maintenance Observations IP 71707:
Plant Operaticr.:: Program IP 71750:
Plant Support Activities IP 92700:
On-Site Follow Up of Written Reports IP 92903:
Followup - Engineering
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ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-325/99-05-01 NCV 18 NSW Strainer d/p Corrective Action (Section O2.1)
ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-325/99-05-01 NCV 18 NSW Strainer d/p Corrective Action (Section O2.1)
50-324/99-05-02 NCV Failure to Enter TS 3.0.3 (Section 04.1)
50-324/99-05-02 NCV Failure to Enter TS 3.0.3 (Section 04.1)
Closed 50-325/99-05-01 NCV 1B NSW Strainer d/p Corrective Action (Section O2.1)
Closed 50-325/99-05-01 NCV 1B NSW Strainer d/p Corrective Action (Section O2.1)
50-324/99-05-02 NCV Failure to Enter TS 3.0.3 (Section 04.1) )
50-324/99-05-02 NCV Failure to Enter TS 3.0.3 (Section 04.1)
)
50-325(324)/99-03 LER Chlorinator Flange Leak Results in Control Building Emergency Air Filtration System Actuation (Section M8.1)
50-325(324)/99-03 LER Chlorinator Flange Leak Results in Control Building Emergency Air Filtration System Actuation (Section M8.1)
50-325(324)/98-06-01 IFl Multiple Failures of SSFPC (Section E8.1)
50-325(324)/98-06-01 IFl Multiple Failures of SSFPC (Section E8.1)
}}
}}

Latest revision as of 21:59, 5 December 2024

Insp Repts 50-324/99-05 & 50-325/99-05 on 990620-0731.Two Violations Noted Being Treated as Ncv.Major Areas Inspected: Operations,Maint & Plant Support
ML20211K908
Person / Time
Site: Brunswick  Duke Energy icon.png
Issue date: 08/27/1999
From:
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20211K905 List:
References
50-324-99-05, 50-325-99-05, NUDOCS 9909080097
Download: ML20211K908 (17)
v • d • e


Text

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U. S. NUCLEAR REGULATORY COMMISSION REGION ll Docket Nos:

50-325, 50-324 License Nos:

DPR-71, DPR-62 -

Report No:

~ 50-325/99-05,50-324/99-05

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Licensee:

Carolina Power & Light (CP&L)'

Facility:

. Brunswick Steam Electric Plant, Units 1 & 2 Location:

8470 River Road SE Southport, NC 28461 Dates:

June 20 - July 31,1999 Inspectors:

T. Easlick, Senior Resident inspector E. Brown, Resident inspector E. Guthrie, Resident inspector Approved by:

B. Bonser, Chief, Reactor Projects Branch 4

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Division of Reactor Projects Enclosure 9909080097 990827 PDR ADOCK 05000324 G

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EXECUTIVE SUMMARY Brunswick Steam Electric Plant, Units 1 & 2

' NRC Inspection Report 50-325/99-05,50-324/99-05 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a six-week period of resident inspection.

Ooerations-The plant responded as designed to a Unit 2 reactor scram due to a loss of all circulating

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water intake pumps (CWIPs) and a low vacuum in the main condenser ' The licensee's J

current design and methods to prevent or alleviate intake structure traveling screen differential pressure (d/p) anomalies were not effective. The licensee formulated corrective actions to address these deficiencies. These corrective actions included l

review of design changes in the intake canal and preparation of an abnormal operating procedure to handle intake canal anomalies that could affect traveling screen d/p's. The

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inspectors noted problems with operator log taking in that some important activities and events were not logged. Similar problems had been observed during two other scrams

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l that occurred in 1999 (Section 01.1).

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' A corrective action violation was identified when the licensee failed to promptly identify

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and correct a condition adverse to quality with the 1B nuclear service water (NSW) pump l

discharge strainer differential pressure instrument,1-SW-PDIC-140. - As a result, the l

pump operated without adequate indication to verify that the required pump flow was being achieved. The licensee was recording d/p instrument readings for each of the service water pump discharge strainers but never questioned the abnormal indication on the 1B NSW pump discharge strainer (Soction O2.1)

A violation was identified when the licensee failed to correctly enter the applicable

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Technical Specification (TS) limiting condition for operation (LCO) when the 2A core spray system was removed from service coincident with a diesel generator (DG) 1

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I outage. The LCO specified entry into TS 3.0.3. The actions required by_TS 3.0.3 were not recognized or initiated as required and the redundancy of the core spray and low pressure coolant injection systems was not recognized (Section 04.1).

A continuing weakness with adverse condition identification by on-shift operations

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personnel was identified. The flow input for the reactor protection system flow bias scram was bypassed and a TS LCO was entered due to surveillance test activities on the 2A core spray subsystem. Despite operator knowledge that this adverse condition had occurred previously on several occasions, the condition was not brought to management's attention nor entered into the corrective action program (Section 07.1).

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Maintenance Maintenance activities observed were performed consistent with the applicable

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procedures, which were verified to be of the proper revision and implemented using the correct level-of-use. Three part communications were observed. Test equipment was

- verified to be within the current calibration cycle. Maintenance technicians took the opportunity to discuss expected indicatior.s during verification of instrument calibration and valving in and out of test equipment (Section M1.1).

Observation and review of maintenance activities on a 2B NSW pump discharge strainer

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through-wall leak found no significant deficiencies in procedures, documentation, or worker actions (Section M1.2).

The activities associated with the underwater inspection of the service water intake

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structure were completed thoroughly and professionally. A well-coordinated effort by plant staff allowed the inspections to be completed without incident (Section M1.3).

The Fix It Now (FIN) team maintenance process and activities were conducted in

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accordance with procedures and the scope of the FIN team. The inspectors noted no deficiencies during the activities observed (Section M1.5).

Plant Sucoort The integrity of the site protected area boundary was intact. No obstructions or gaps

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were noted in the fence. Security personnel were appropriately stationed and attentive (Section S2.1).

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ReDOrt Details

- Summary of Plant Status i

Unit 1 began the report period operating at 100 percent rated thermal power (RTP). On June 28 power was reduced to 73 percent RTP as a result of the loss of a circulating water intake pump due to high differential pressure across the traveling screens. The unit was returned to 100 percent RTP later that same day. On July 10 the unit was reduced to 80 percent RTP to support troubleshooting and repair on the SA feedwater heater. The unit was returned to 100 percent RTP on July 11 with the 4A and 5A feedwater heaters out of service.

On July 21 power was reduced to 85 percent to support retuming the 4A and 5A feedwater heaters to service. Unit i returned to full power on July 22 and remained at full power for the duration of the inspection period. At the end of the period the unit had been operating continuously for 187 days.

Unit 2 began the report period operating at 100 percent RTP. On June 24 power was reduced to 80 percent RTP to support removal of the 4B and 58 feedwater heaters. The unit was returned to 100 percent RTP on June 25, with the 48 and SB feedwater heaters out of service.

On June 28 an automatic reactor scram occurred from 100 percent RTP due to a main turbine trip on a loss of condenser vacuum as a result of a loss of three circulating water intake pumps.

The unit was retumed to power on June 29 and achieved 100 percent RTP on July 1. At the end of the inspection period the unit had been operating continuously for 31 days.

l. Operations

O1 Conduct of Operations 01.1 Unit 2 Reactor Trio Due to Low Condenser Vacuum

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Inspection Scope (71707)

The inspectors responded to and reviewed a Unit 2 reactor scram b.

Observations and Findinas On June 28 a Unit 2 reactor scram occurred due to low vacuum in the main condenser.

The low vacuum was caused by a loss of circulating water to the main condenser. Unit 2 experienced a loss of all running circulating water intake pumps (CWIP) due to high differential pressures (d/p) across the CWIP traveling screens. The CWIPs had an automatic high d/p trip feature at a d/p of 36 inches across the traveling screens.

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The inspectors responded to the control room following the Unit 2 scram and found that both units were stabilized. The inspectors found that one CWIP tripped on Unit 1 due to a high d/p across the traveling screens. Operators immediately commenced an emergency power reduction, in accordance with procedures, to about 70 percent RTP.

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The Unit 1 CWIP tripped almost immediately after the Unit 2 CWIPs tripped and the Unit 2 reactor scrammed.

The inspectors reviewed the licensee's post-event trip review report including process plant computer transient traces, and transient plots, and verified that the plant responded to the event as expected and within design parameters. The inspectors noted that the time from when the first control room high d/p alarm annunciated until Unit 1 was stabilized was about 40 minutes. During that time period, in an effort to reduce the high d/p, the licensee used fire hose spray to reduce what was initially reported to the control room as a fish buildup on the CWIP traveling screens. The time between the first Unit 2 CWIP trip and the last CWIP trip (on Unit 1) was two minutes.

The inspectors concluded that the use of fire hoses during the event was not effective in

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reducing or eliminating the high d/p's. Additionally, the inspectors found that the l

licensee's current design and methods to prevent or alleviate intake structure traveling screen d/p anomalies were not effective nor were the abnormal operating procedure (AOP) symptomatic entry conditions specifically relevant to this anomaly. The inspectors discussed these observations with the licensee. The licensee acknowledged the inspectors' observations as deficiencies. The deficiencies were addressed with corrective actions to: 1) review design changes in the intake canal, and 2) prepare an AOP to handle intake canal anomalies that could affect traveling screen d/p's.

The inspectors observed four significant plant changes and activities that were not logged in the operator logs. An example was the emergency power reduction on Unit 2 prior to the scram. This was a continuing deficiency noted by the inspectors which was observed and discussed in previous inspection reports on two reactor scrams in 1999.

The licensee acknowledged the log deficiencies and informed the inspectors that several hours were scheduled in the operating licensing training program to address log taking expectations.

The inspectors reviewed the root cause investigation for this event and noted that the root cause was identified as detritus, a rotting vegetable and plant life material, that plugged the CWIP traveling screens creating the high d/p's which tripped the CWIPs.

c.

Conclusions The plant responded as designed to a Unit 2 reactor scram due to a loss of all CWIPs

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and a low vacuum in the main condenser. The licensee's current design and methods to prevent or alleviate intake structure traveling screen d/p anomalies were not effective.

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The licensee addressed deficiencies identified with corrective actions to review design changes in the intake canal and the preparation of an AOP to handle intake canal anomalies that could affect traveling screen d/p. Deficiencies were identified in operator log taking in that some important activities and events were not logged. The inspectors noted that problems with log taking were repeated from two other scrams that occurred in 1999.

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02 Operational Status of Facilities and Equipment 02.1 Operational Status of 1B Nuclear Service Water (NSW) Pumo a. -

Insoection Scoos (71707. 62707)

The inspectors conducted a walkdown of the Service Water (SW) building on July 22 observing equipment status and condition including operating performance of the SW system.

J b.

Observations and Findinas The inspectors identified that the 1B NSW pump discharge strainer local d/p indicator,1-SW-PDIC-140, was reading less than zero and pegged low. ' The inspectors noted that the 1B NSW pump was running at the time. The inspectors observed that all of the other running SW pump discharge strainer d/p indications were reading about 1 to 2 pounds per square inch differential (psid) pressure.

The inspectors informed the licensee of the observed d/p indication on the 1B NSW j

pump discharge strainer, and questioned if there was something wrong with the indication. The licensee observed the indication and agreed that the d/p looked abnormal for a running pump. The licensee informed the inspectors that the indication

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would be investigated that day. However, the inspectors observed on July 23, July 26,

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and July 27 that the indication was reading about the same as on July 22. Each day the inspectors questioned the licensee about what action was going to be taken with regsrd to the questionable indication. The licensee each time responded that the indication

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would be investigated.

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i On July 27, following discussions with the inspectors, the licensee initiated a deficiency log entry on the 1-SW-PDIC-140 instrument. This was the first time action was taken to investigate the abnormal d/p reading on the operating 18 NSW discharge strainer. The licensee informed the inspectors that since July 15 the high d/p annunciator for the 1B NSW discharge strainer was also not alarming at the required setpoint of 8 psid. On i

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July 27, the licensee determined the 1B NSW pump was inoperable with both the local d/p indication and the high d/p annunciator functioning abnormally. A subsequent licensee investigation identified that the local d/p indicator was reading low due to a glycerin leak in the gage and silt in the instrument tube.

The significance of the d/p indications and annunciators not functioning while the pump was in operation was that if the pump strainer had become clogged the required system l.

flow may not have been achieved for that pump and operators may not have been aware of a degraded operating condition. Additionally, throughout the previous two weeks i

several SW pump discharge strainers had become plugged with oyster shells in all of those cases both the high d/p annunciator alarmed and the local d/p instrument was used to verify the clogged condition. The associated pump was secured and the strainers were taken apart to remove the oyster shells.

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The inspectors determined that the licensee was recording the d/p instrument readings for each of the SW pump discharge strainers but never questioned the abnormal indication on the 1B NSW pump discharge strainer. The inspectors discussed this with the licensee who stated that the concern would be investigated as part of the condition report (CR) that was generated.

10 CFR 50 Appendix B, Criterion XVI, Corrective Action, states that measures shall be established to assure that conditions adverse to quality such as deficiencies, defective material and equipment, and nonconformances are promptly identified and corrected.

The licensee failed to promptly identify and correct a condition adverse to quality on the

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1B NSW pump dischargc strainer differential pressure instrument,1-SW-PDIC-140, from

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July 22 to July 27. The 1B NSW pump continued operating over the specified period of time without adequate indication to verify that the required pump flow was being achieved. 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 identified in the licensee's corrective action program as CR 99-01886,1B NSW Strainer

D/P. This violation is identified as NCV 50-325/99-05-01,1B NSW Strainer d/p I

Corrective Action.

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c.

Conclusions

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A corrective action violation was identified when the licensee failed to promptly identify

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and correct a condition adverse to quality with the 1B NSW pump discharge strainer differential pressure instrument,1-SW-PDIC-140. As a result, the pump continued operating over the specified period of time without adequate indication to verify that the required pump flow was being achieved. The licensee was recording the d/p instrument

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. readings for each of the NSW pump discharge strainers but never questioned the (

abnormal indication on the 1B NSW pump discharge strainer.

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O2.2 Reactor Core Isolation Coolina (RCIC) System Review (71707)

On July 8, the inspectors performed a verification of those accessible valves and l

electrical components for the RCIC system for Unit 1. Valves in the system reviewed j

were appropriately labeled and no valve leakage or missing actuator handwheels were

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identified. The inspectors observed that no equipment was staged which might threaten system performance. No transient combustibles were identified in the area nor were any ignition sources observed. Accessible valves and electrical components were verified to be correctly aligned in accordance with Operating Procedure 10P-16. " Reactor Core

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Isolation Cooling System Operating Procedure," Rev. 44 and drawings D-25029 sheets 1 and 2.

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04 Operator Knowledge and Pr,rformance 04.1 ' Missed Inocerability of Redundant System

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Insoection' Scone (71707)

On July 16, the inspectors reviewed the circumstances surrounding the licensee's failure to enter Technical Specifications (TS) 3.5.1.J and 3.0.3 for Unit 2 after removing the A core spray (CS) pump from service.-

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Observations and Findinas On July 15, the licensee discovered that TS 3.5.1.J, ECCS Operating, and TS 3.0.3

. should have been entered as a result of the 2A CS system being removed from service for scheduled maintenance concurrent with a diesel generator (DG) 1 outage. The licensee reported this event in License Event Report (LER) 50-324/99-07. The determination of a missed inoperability was made as a result of the following sequence of events:

July 12 - 4:06 a.m.

DG1 placed under clearance and declared inoperable for scheduled maintenance. Entered 7-day LCO per TS 3.8.1.D

July 14 - 10:30 a.m. 2A CS was placed under clearance and declared inoperable for scheduled maintenance. Entered 7-day LCO for one emergency core cooling system (ECCS) subsystem being inoperable per TS

.3.5.1.A 2A CS subsystem restored ' nd declared operable. Exited TS July 14 - 6:50 p.m.

a 3.5.1.A July 15 - 12:52 a.m.

DG1 restored and declared operable. Exited TS 3.8.1.D The inspectors reviewed the applicable TSs, operators logs, CR 99-1776, Safety Function Determination, and had discussions with the operations perconnel involved.

Through the discussions with operations personnel, it was determined that 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after

' the removal of the 2A CS pump at 10:30 a.m. on July 14, the associated low pressure coo! ant injection (LPCI) subsystem should have been declared inoperable. The 2A LPCI subsystem was inoperable because TS 3.8.1.D required that, should the subsystem redundant to a system supported by DG1 (2A CS) become inoperable, the supported subsystem (2A LPCI) shall be declared inoperable within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. As a result of having two ECCS subsystems inoperable, the licensee should have entered LCO 3.5.1.J which required the immediate entry into TS 3.0.3 and the initiation of a plant shutdown within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The inspectors concluded that the required LCOs were not entered and the TS 3.0.3-required shutdown was never initiated.

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The licensee's decision to remove the 2A CS pump from service indicated that it was unknown at the time that the CS and LPCI systems were redundant. The error was the l

assumption that one subsystem of CS was redundant to the other and had no effect on LPCI.

TS 3.5.1.J requires that with two or more low pressure emergency core cooling system l

- (ECCS) injection spray subsystems inoperable, enter LCO 3.0.3 immediately. LCO 3.0.3 l

requires, in part, that if directed by an associated ACTION, the unit shall be placed in a MODE in which the LCO is not applicable. This ACTION is required to be initiated within

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i 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. Contrary to the above, on July 14,1999,'at 3:30 p.m., the licensee failed to I

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initiate actions within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to place Unit 2 in a MODE in which the associated ACTION l

of TS 3.5.1.J was not applicable when two ECCS subsystems were inoperable. This l

Severity Level IV violation is being treated as an NCV, consistent with Appendix C of the j

NRC Enforcement Policy. This violation is identified in the licensee's corrective action

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program as CR 99-1776, Safety Function Determination, and is identified as NCV 50-324/99-05-02, Failure to Enter TS 3.0.3.

Operations management indicated that operator knowledge regarding redundant and supported equipment did not meet management expectations. It was also stated by management that earlier use of the safety function determination program (SFDP)

contained in the Technical Requirements Manual (TRM) would have alerted the operators to the required inoperability of the LPCI subsystem. The licensee initiated CR 99-1792, ITS LCO Accuracy, to address the declining trend in identifying correct LCO requirements. Also, during review of the operator's logs the inspectors could not locate any record of the entry into TS 3.0.3 once the condition was identified. The licensee was notified and an entry into the logs was backdated to document the TS-required condition.

c.

Conclusions A violation was identified when the licensee failed to correctly enter the applicable TS LCO when the 2A core spray system was removed from service coincident with a DG1 outage. The LCO specified entry into TS 3.0.3. The actions required by TS 3.0.3 were not recognized or initiated as required and the redundancy of the CS and LPCI systems was not recognized.

04.2 Unit 0 Outside Auxiliary Operator Daily Rounds (71707)

On July 28, the inspectors observed an auxiliary operator during the performance of Operating instruction 101-03.4, " Unit 0 Outside Auxiliary Operator Daily Check Sheets,"

Rev. 74. The inspectors observed acceptable adherence to the procedure. During the rounds the inspectors noted that the operator had good system kr.owledge and thoroughly reviewed the operating equipment to ensure that the operating parameters were within the normal expected range. The operator observed water on the floor of the off-gas building and identified a ventilation duct as the source of the water. He immediately contacted the control room to report the deficiency and requested that a health physics technician survey the area prior to cleaning the water. The inspectors

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also noted that proper housekeeping practices were demonstrated, such as the removal-of excess oil from around pumps and motors.

Quality Assurance in Operations 07.1 ' Excess Flow Check Valve indications a.

Inspection Scope (71707. 37551)

The inspectors reviewed the corrective actions associated with a penetration line break

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annunciator received on Unit 2. This annunciator could also be indicative of a J

malfunction or inadvertent positioning of the penetration line excess flow check valve j

(EFCV).

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Observations and Findinos

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On July 15, during routine review of the operator logs, the inspectors noted an entry which indicated that a penetration line break annunciator had been received during surveillance test activities on the 2A CS subsystem. The flow instrument was bypassed and a TS LCO was entered due to the affected penetration line providing input into the 1-B21-N024A/B reactor recirculation flow instruments. These flow instruments provide

the flow portion of the reactor protection system (RPS) flow bias scram. A walkdown of the instrument line was performed to verify that no line leak existed. Upon confirmation of no leakage, no increase in area temperatures or radiation levels, and no change in related instrumentation response, the RPS flow input was restored and the associated LCO exited. The logs indicated that the unexpected closing of the penetration had been seen previously on three other occasions during stroking of the CS full flow test valve for surveillance testing.

~ The operator logs, Lessons Leamed database, and associated procedures were reviewed by the inspectors. During discussion with operations personnel the inspectors questioned why no CR had been generated for the repetitive condition. The inspectors were informed that for this condition a work request / job order (WR/JO) would be written and that the condition had been previously noted in the Lessons Leamed database and therefore did not need a CR. Further discussions revealed that the system engineer was unaware of this condition.

The inspectors questioned operations management as to the need for a CR as a result of the repetitive LCO entry on safety-related RPS instrumentation, whether this condition was an operator workaround, and whether similar conditions were in the Lessons Learned database or other programs. The inspectors were informed that a CR should i

have been initiated to address the repetitive nature of this condition. In addition, members of the operations organization not on-shift were performing independent reviews of logged plant events to assure that CRs were being initiated as appropriate.

The inspectors noted that subsequent to this discussion CR 99-1858, timely initiation of j

CRs, was initiated as a result of other licensee findings regarding prompt recording of i

operational issues into the corrective action program (CAP). As a result of this finding,

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NCV 50-325(324)/99-04-02, Failure to Identify Conditions Adverse to Quality (NRC l

Inspection Report 50-325(324)/99-04 dated July 19,1999), and other licensee-identified issues, the inspectors concluded that a continuing weakness existed with the identification of adverse conditions by on-shift operations personnel.

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Conclusions A continuing weakness with adverse condition identification by on-shift operations personnel was identified. The flow input for the RPS flow bias scram was bypassed and

' a TS LCO was entered due to surveillance test activities on the 2A core spray subsystem. Despite operator knowledge that this condition had occurred previously on several occasions, the condition was not brought to management's attention nor entered into the CAP.

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11. Maintenance M1 Conduct of Maintenance M1.1 Maintenance Activities a.

Inspection Scoce (61726. 71750)

The inspectors reviewed all or portions of the following surveillance tests and/or maintenance activities:

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Attachment 2 to Environment & Radiation Control Procedure OE&RC-1231,

" Sampling and Analysis for Tritiated Water in Airborne Effluents," 'Rev.16,

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l Attachment 4-2 to Environment & Radiation Control Procedure OE&RC-2002,

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" Sampling of Radioactive Airborne Effluent Releases," Rev. 32, and Maintenance Surveillance Test 1MST-RCIC22Q, "RCIC Steam Line Low

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Pressure Inst. Channel Calibration, Rev. 7.

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Observations and Findinas The inspectors observed that good supervisory oversight was provided. Procedures used were of the proper revision and test equipment was within the current calibration cycle. Satisfactory three-part communications were observed. During the conduct of l

11MST-RCIC22Q, the maintenance technicians took the opportunity to discuss expected i.

indications during verification of instrument calibration and valving in and out of test equipment. Technicians were knowledgeable of the evolution and expected instrument response.

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M1.2 f 2B NSW Pumo Discharoe Strainer Leak Reoair l

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~a.

Insoection Scooe (62707)

l The inspectors observed and reviewed the repair of a through wall leak on the 2B NSW pump discharge strainer housing. The inspectors observed the maintenance on July 21 and July 22.

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b.

' Observations and Findinos L

The inspectors observed the maintenance on the 2B NSW pump discharge' strainer l-

~ housing in the SW building and found that the workers were knowledgeable and skilled.

l The inspectors observed good housekeeping during the maintenance activity. Review of

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the work package documentation during and after the maintenance revealed that the procedures and other required documentation were on hand and were used l

appropriately during the observed activities. The required signatures and maintenance sequence were maintained as the activities progressed. The work package review following the completion of the maintenance found no significant discrepancies.

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M1.3 Service Water Intake Structure insoection l

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a.

Inspection Scooe (62707)

l On July 4, the licensee identified in a condition report that the 1 A NSW pump was

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. inoperable due to an inability to develop sufficient discharge pressure. The initial troubleshooting indicated that the problem was due to plugging of the discharge strainer.

l Three other service water pumps were also exhibiting higher-than-normal strainer l

differential pressure. The inspectors observed the licensee's response to the issue, I

l which included an inspection of the SW pump intake bays.

b.

Observations and Findinos l

On July 8, the inspectors observed the performance of preventive maintenance procedure, OPM-STU 500, " Service Water intake Structure Inspection and Cleaning,"

s Rev. 2, under work request 99-AEWC1. Divers performed the underwater inspection in accordance with administrative instruction 0A1-131, " Conduct of Diving Operations,"

Rev. 3. During the inspections, one diver was in the water and two other qualified divers

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acted as support and safety personnel. Maintenance technicians provided foreign material exclusion (FME) area support during the dives to ensure that no foreign material i

entered the intake bays while they were open for inspection. The FME zone was moved l

from bay to bay as the inspections were completed. In addition to the visual inspection, the divers measured the sitt and shelllayer at the bottom of each bay and the hard shell growth on the walls. The inspection of the four bays was well-coordinated and efficiently managed. All work observed was performed with the work package present and in use.

The inspections were completed safely and without incident. The inspections indicated

. that the maximum hard shell growth on the walls was 5 inches and the maximum height

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of the silt and shell mixture on the floor of the bays was 3 feet. This was within the

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acceptance criteria of OPM-STU 500; however, the presence of a large number of shells was noted. The licensee suspects that the shell growth occurred during a period of no l

SW chlorination when the system was being repaired. The inspectors reviewed the

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previous inspection results from January 1999, which indicated a similar buildup of silt and hard growth. The licensee is reviewing the adequacy of the current annual inspection program in light of the apparent impact of reduced or nr chlorination in the SW system.

M1.4 Conclusions of Conduct of Maintenance The activities observed were performed consistent with the applicable procedures, which.

were verified to be of the proper revision and implemented using the correct level-of-use.

Three-part communications were observed. Test equipment v:as verified to be within the

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current calibration cycle. Maintenance technicians took th' opportunity to discuss expected indications during verification of instrument calibration and valving in and out of l

test equipment.

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l Observation and review of maintenance activities on a 2B NSW pump discharge strainer l

through wall leak found no significant deficiencies in procedures, documentation, or

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worker actions.

J The activities associated with the underwater inspection of the SW intake structure were l

l completed thoroughly and professionally. A well-coordinated effort by plant staff allowed the inspections to be completed without incident.

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M1.5 Fix It Now (FIN) Team Maintenance Observations

a.

Inspection Scope (62707)

L The inspectors observed and reviewed FIN team maintenar.ce activities on DG 3 and the l

28 NSW pump.

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Observations and Findinas i

i On June 28, the inspectors observed FIN team maintenance on a DG 3 jacket water l.

flange leak. The inspectors found that the FIN team maintenance process was well-

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structured. Assigning the activity to the FIN team was within the scope of the team

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activities and was within procedural guidance. A pre-work briefing was conducted, which

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was observed by the inspectors, and given by the FIN team supervisor. The job scope was well thought out and prepared. The FIN team workers performed the job according to the work package requirements. The entire process was sensitive to maintenance on safety-related equipment. The inspectors noted no deficiencies during observations of

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activities or review of paperwor r

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On July 23, the inspectors observed a packing adjustment by a FIN team member on the

2B NSW pump. The inspectors found that a work package was used appropriately since j

the packing served as an inservice inspection (ISI) boundary and the pump was safety-i related. The worker was knowledgeable and skilled.

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Conclusions l

The FIN team maintenance process and activities were conducted in accordance with l

procedures and the scope of the FIN team. The inspectors noted no deficiencies during

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the activities observed.

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M8 Miscellaneous Maintenance lasues (92700)

M8.1 (Closed) Licensee Event Report (LER) 50-325 (324)/99-03: Chlorinator Flange Leak Results in Control Building Emergency Air Filtration System Actuation. The event l

documented in this LER occurred on July 24,1997; however, at the time of the control l

building emergency air filtration (CBEAF) system actuation, the CBEAF system was not I

classified as an engineering safety feature. As a result, the event was determined by the l

licensee as not reportable at that time in accordance with the requirements of 10 CFR

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50.73. The CBEAF system was subsequently reclassified as an engineering safety feature and this LER was submitted March 10,1999, to address the July 1997 event.

While conducting post-maintenance leak checks following repair of the #2 chlorinator, l

chlorine gas was detected leaking from the bolted flange connecting the gas inlet line

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spool piece to the #2 chlorinator block heater. This resulted in the CBEAF system actuation and alignment to the chlorination protection mode. The system isolation signal I

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cleared shortly thereafter and the CBEAF system was restored to its normal configuration. The cause of this event was an inadequately manufactured gas intelline spool piece. Additionally, a contributing factor was the lack of a defined process for nitrogen pressure testing of the gaseous portion of the chlorination system.

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' The licensee's corrective actions included replacing and pressure testing the spool piece and performing an inspection of the in-stock spare spool pieces. The appropriate i

maintenance procedures were revised to require performance of a nitrogen pressure test

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of the liquid and gaseous portions of the chlorination system piping in the event those portions of the system are open for maintenance. The inspectors verified that the post-maintenance testing program and work planning procedures were revised.

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E8 Miscellaneous Engineering issues (92700,92903)

l E8.1 (Closed) Inspection Fol!owuo item 50-325(324)/98-06-01: Multiple Failures of SSFPC.

The inspectors reviewed the corrective actions fnim the numerous CRs generated during the Unit 11998 refueling outage. These CRs des :ribed the numerous failures of the supplemental spent fuel pool cooling (SSFPC) system, the disposition of these failures, l

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and the various root causes in accordance with 10 CFR 50.65, the Maintenance Rule

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(MR). The inspectors found that system reliability and performance had improved as a result of modifications in the set-up and operation of the system. The number of MR functional failures (FF) was reduced from approximately five last outage to two this

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recent outage.

The inspectors questioned if the cyclical performance in and out of MR paragraph (a)(1)

criteria had been reviewed. The continuing performance challenges and special j

conditions for which SSFPC was used had caused the system engineer to reconsider the performance criteria and the FF definitions. Changes to the system monitoring under MR paragraph (a)(2) criteria were proposed to be presented to the expert panel in October 1999. The licensee indicated that the remaining cause of most of the failures during the most recent outage was attributed to reliability issues with the secondary side power supply. The inspectors noted that additional actions were being planned to address this condition.

IV. Plant Support S2 Status of Security Facilities and Equipment S2.1 hotected Area Observations (71750)

On July 19, the inspectors verified the integrity of the protected area (PA) fence and security static postings. The inspectors verified that members of the security force were present and attentive.. No holes or gaps were observed in the PA fence. The isolation zones were observed to be free of transient materials. Observations from the secondary i

access station revealed no obstructions of the video surveillance equipment.

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V. Mananement Meetinos j

XI Exit Meeting Summary The inspector presented the inspection results to members of licensee management at the conclusion of the inspection on August 9,1999. The licensee acknowledged the

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findings presented.

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PARTIAL LIST OF PERSONS CONTACTED Licensee A. Brittain, Manager Security N. Gannon, Manager Operations J. Gawron, Manager Nuclear Assessment M. Herrell, Training Manager 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 E. Quidley, Manager Maintenance S. Rogers, Manager Outage and Scheduling INSPECTION PROCEDURES USED iP 37551:

Onsite Engineering IP 61726:

Surveillance Observations IP 62707:

Maintenance Observations IP 71707:

Plant Operaticr.:: Program IP 71750:

Plant Support Activities IP 92700:

On-Site Follow Up of Written Reports IP 92903:

Followup - Engineering

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ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-325/99-05-01 NCV 18 NSW Strainer d/p Corrective Action (Section O2.1)

50-324/99-05-02 NCV Failure to Enter TS 3.0.3 (Section 04.1)

Closed 50-325/99-05-01 NCV 1B NSW Strainer d/p Corrective Action (Section O2.1)

50-324/99-05-02 NCV Failure to Enter TS 3.0.3 (Section 04.1)

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50-325(324)/99-03 LER Chlorinator Flange Leak Results in Control Building Emergency Air Filtration System Actuation (Section M8.1)

50-325(324)/98-06-01 IFl Multiple Failures of SSFPC (Section E8.1)

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