IR 05000338/1999001
| ML20205Q252 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 04/12/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20205Q249 | List: |
| References | |
| 50-338-99-01, 50-338-99-1, 50-339-99-01, 50-339-99-1, NUDOCS 9904210144 | |
| Download: ML20205Q252 (27) | |
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U.S. NUCLEAR REGULATORY COMMISSION R E G I O N ll Docket Nos.:
50-338,50-339 License Nos.:
50-338/99-01,50-339/99-01 Licensee:
Virginia Electric and Power Company (VEPCO)
Facility:
North Anna Power Station, Units 1 & 2 Location:
1022 Haley Drive Mineral, Virginia 23117 Dates:
January 31, through March 13,1999 Inspectors:
M. Morgan, Senior Resident inspector R. Gibbs, Resident inspector G. Wiseman, Reactor Inopector (Sections F1.1, F1.2, F1.3, F2.1, F3.1, F5.1, and F8.1)
Approved by:
R. Haag, Chief, Reactor Projects Branch 5 Division of Reactor Projects ENCLOSURE 9904210144 990412 PDR ADOCK 05000338 G
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EXECUTIVE SUMMARY North Anna Power Station, Units 1 & 2 NRC Integrated inspection Report Nos. 50-338/99-01,50-339/99-01 This integrated inspection included aspects of licensee operations, engineering, maintenance, i
and plant support. The report covers a six-week period of resident inspection. In addition,it includes the results of an announced inspection by a region based fire protection specialist.
Operations Replacement of Units 1 and 2 service water piping to the control room ventilation chillers
was properly performed. Associated Technical Specification actions statements were executed as required. After some uncertainty was observed concerning the control room pressure boundary status, a status board was prominently displayed for personnel.
Fire protection was properly addressed (Section 01.2).
The licensee inadvertently momentarily caused the Unit 1 SI "A" accumulator to
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depressurize one psig below the technical specification required limit. The depressurization was caused by inadequate communications during shift turnover, absence of an equipment status entry and ineffective procedure execution (Section 01.3).
The plant responded as designed to the loss of the 1-111 electricalinverter power source
to the associated 120 VAC vital bus. Technical specification 3.8.2.1 was properly executed. Operator response to the main feedwater transient which occurred as a result of the power loss was excellent. The operator quickly responded to the transient by taking manual control of the main feedwater regulating valves (Section 01.4).
Operators were effective in identifying issues to plant management which the operations
review board considered to be operator workarounds (OWAs). There were several active OWAs affecting safety-related equipment or equipment important to safety.
These OWAs were associated with normal operations and had no adverse effects on operating transients or accidents (Section 01.5).
A non-Cited violation was identified for the failure to perform a valid reactor coolant
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system leak rate calculation which resulted in a missed technical specification surveillance. Operators who performed the leak rate test displayed an inadequate attention to detail, in that, they failed to initiate an evaluation when the leak rate increased to approximately one third of that allowed by Technical Specifications (Section 08.1).
Management review board activities continued to provide a positive management forum
for self-assessment of station activities and were an effective contributor to the licensee's corrective action program (Section 08.4).
Maintenance A non-cited violation was identified for the failure to perform inservice testing or post
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maintenance tests (PMTs) following vent cap replacement on component cooling (CC)
water valves. The licensee subsequently justified deferring testing for some CC valves until the first available opportunity, i.e., when plant conditions allow (Section M1.1).
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Unit 1 rnaintenance activities for the 1 A component cooling water heat exchanger,1C
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charging pump lube oil cooler, and the 1-111 inverter power supply breaker were properly performed. The personnel conducting the activities were know!edgeable and properly followed work package instructions. Use of photographs to help workers better understand the work environment was noteworthy (Section M1.2).
Routine periodic tests for Unit 1 and 2 quench spray subsystems and the Unit 2 turbine
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driven auxiliary feedwater system were properly performed. Test procedures were properly followed by knowledgeable workers. The tests were properly approved by station management and included within the licensee's evaluation for on-line maintenance. Technical specifications requirements were also satisfied (Section M1.3).
Enaineerina The licensee, through thermography, determined that the breaker which tripped and
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caused a loss of the Unit 1 120 VAC vital bus 1-111 had an elevated temperature at the breaker's electrical connection. The actions to temporarily correct the condition and the licensee's plans to monitor the breaker and perform a more in-depth root cause analysis were acceptable. The licensee is evaluating the need to perform preventive maintenance on this and similar breakers (Section E1.1).
The Unit 2 conversion from a steam flow-based calorimetric to a feedwater flow-based i
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calorimetric was performed in accordance with the associated design change package.
j Although the unit produced approximately 20 megawatts more power, the revised calorimetric demonstrated that the unit was operating within licensed and core operating limits report allowable values (Section E2.1).
The licensee's operating experience program response to a 10 CFR Part 21 involving
i Agastat Series E7000 timing relays was timely, thorough and effectively resolved this issue (Section E7.1).
A non-cited violation of 10 CFR 50, Appendix B, Criterion V was identified for use of a
motor lead lug on the B charging pump that was not in conformance with material specifications (Section E8.1).
Plant Support implementation of the fire protection program requirements for control of combustible
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fire hazards was good. Plant personnel followed combustible control procedures to manage the use and temporary storage of transient combustibles in safety-related areas. Plant housekeeping and trash control were in accordance with procedure requirements (Section F1.1).
The licensee's administrative controls for ignition source control were being
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implemented in accordance with the fire protection program (Section F1.2).
Eleven incidents of smoke or equipment overheating were identified in the past three
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years which were c6used by electrical component faults within safety-related areas.
These fire related conditions were properly identified and mitigating actions were taken in a timely manner. No trends were identified (Section F1.3).
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Personal protective fire fighting equipment provided to the fire brigade was in good
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condition and provided a sufficient level of personal safety needed for onsite fire emergencies. Backup lighting in the dressout areas provided an adequate level of lighting in support of fire brigade operations (Section F2.1).
Fire brigade pre-fire strategies provided clear and sufficient instructions and met the
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requirements of the fire protection program (Section F3.1).
Fire drill critique data indicated that the fire brigade's response time and performance
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were good. All the fire brigade members were at the fire drill site and ready to attack the fire in an average of ten minutes (Section F5.1).
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Report Details Summary of Plant Status Units 1 and 2 operated at or near full power for the entire inspection period.
LOperations
Conduct of Operations 01.1 Daily Plant Status Reviews (71707.40500)
The inspectors conducted frequent control room tours to verify proper staffing, operator attentiveness, and adherence to procedures. The inspectors attended daily plant status meetings to maintain awareness of overall facility operations and reviewed operator logs to verify operational safety and compliance with technical specifications (TSs).
Instrumentation and safety system lineups were periodically reviewed from control room indications to assess operability. Frequent plant tours were conducted to observe equipment status and housekeeping. Deviation reports (DRs) were reviewed to ensure that potential safety concerns were properly reported and resolved. The inspectors found that daily operations were generally conducted in accordance with regulatory requirements and plant procedures.
O1.2 Service Water (SW) Pipina Replacement for Units 1 and 2 Control Room Ventilation i
Chillers j
a.
Inspection Scope (71707. 62707)
The inspectors observed SW piping replacement activities for the Units 1 and 2 control room ventilation chillers.
b.
Observations and Findinas On numerous occasions during the inspection period, the inspectors observed activities associated with SW piping replacement. The piping was replaced due to microbiologically induced corrosion. As each SW supply and return header was replaced entry into TS 3.7.7.1.c was required. In addition the work required multiple entries into TS 3.7.7.1.b while the control room pressure boundary was inoperable for short periods. The inspectors verified that TS requirements were properly satisfied.
The inspectors also periodically checked that the main control room pressure was greater than the turbine building pressure by at least 0.05 inches of water.
The inspectors discussed with workers and operators the actions required to restore the pressure boundary in the event of a safety injection signal. In general, the individuals interviewed understood the importance of immediately restoring operability and successfully described which actions and equipment were needed. In addition, the inspectors verified that the workers could be contacted by the control room to take action to restore the pressure boundary if required. On two occasions individuals providing management oversight or supervision were unsure of the status of the pressure boundary. As a result, the licensee prominently posted an information board which tracked the status of the pressure boundary.
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The inspectors observed portions of non-destruction examination of two SW piping welds. The inspectors verified that the shelf life of examination materials had not expired and that the examiner's training and certification were current. The inspectors discussed examination techniques with the examiner who successfully demonstrated a thorough understanding of the work.
The inspectors checked general conditions in the affected work areas to ensure that fire protection and housekeeping were properly addressed. These areas included the emergency switchgear room which is the most fire risk significant area in the plant. The area surrounding the work (e.g., grinding, welding) was kept clear of transient cornbustibles, and fire watches were present and fire extinguishers were available and in good condition. On two occasions early in the inspection period, the inspectors noted that non-fire hazard housekeeping needed improvement. The inspectors discussed this with licensee management who took immediate corrective action. On subsequent tours, the inspectors observed improved housekeeping. The inspectors also noted that scaffolding and other equipment in the areas did not have a detrimental effect on adjacent equipment.
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Conclusions Replacement of Units 1 and 2 service water piping to the control room ventilation chillers was properly performed. Associated Technical Specification actions statements were executed as required. After some uncertainty was observed concerning the control room pressure boundary status, a status board was promineniiy displayed. Fire protection was properly addressed.
01.3 Unit 1 "A" Safety Iniection (SI) Accumulator Depressurization a.
Inspection Scope (71707)
The inspectors reviewed circumstances associated with an unexpected reduction in nitrogen gas pressure for the Unit 1 "A" Si accumulator. The inspectors discussed the event with numerous plant personnel and reviewed supporting documentation.
b.
Observations and Findinas On February 8 while attempting to increase nitrogen pressure in the "A" Sl accumulator, the pressure decreased to approximately 1 psig below the TS 3.5.1.d minimum value of 599 psig. The operator restored the nitrogen pressure to above TS requirements in about nine minutes using the bottled nitrogen system. Nine minutes was well within the required TS action of one hour to restore operability. The licensee initiated DR N-99-332 to determine the cause and to address appropriate corrective actions.
The inspectors reviewed operating logs and procedures, accumulator pressure data, and discussed the event with several plant personnel. The event's immediate cause was opening of the nitrogen charging pathway without knowing that the plant nitrogen system (PNS) cryogenic pump would not operate. Contributing factors to the event were the operating crew not being aware of the pump's status and inattention to a procedure note which indicated that the pump be started before initiating nitrogen flo Tne previous shif t was aware that the pump was incperable and had discussed it with oncoming operators. Severallog entries were also made which described operational difficulties with the pump. The involved oncoming operators mistakenly believed the failure of the pump had been caused by a loss of prime due to low liquid nitrogen level in the PNS storage tank. In addition, the previous crew had not entered the pump into equipment status which is the licensee's method for tracking equipment not performing satisfactorily. The inspectors discussed management's expectation for equipment status entries with the operations superintendent who stated that the expectation was i
not clearly defined. The superintendent further stated that corrective actions for this
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deficiency would be addressed in the DR response.
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The inspectors also reviewed the operating procedure used to pressurize the accumulator and discussed its use with the involved operators and the operations superintendent. One procedure note specifically stated that he pump should be started prior to initiating nitroger, flow. The operators involved stated that they should have been more diligent in aodressing the notes and precautions. Upon review of the licensee's administrative guidance on procedure adherence, specifically for "should
i statements, the inspectors concluded that no action was required by the operators. The licensee enhanced the procedure to ensure that sufficient nitrogen pressure would be l
available in subsequent evolutions. The inspectors reviewed the revised procedure and l
concluded that it was appropriate.
Prior to the depressurization, the "A" accumulator had experienced nitrogen pressure reductions since December 1998. Operators routinely (i.e., every two to three days at the time of the depressurization) pressurized the accumulator to meet TS requirements.
The licensee suspected that an accumulator relief valve was leaking and was waiting for an opportune time to inspect the suspect relief valve. When an unrelated valve indication problem occurred requiring a containment entry, technicians examined the valve and determined that it was not leaking. The nitrogen supply valve for the "A" accumulator was found leaking through its packing. DR N-99-350 was initiated for this condition. Af ter review of the event, plant management informed the inspectors that the plant should have been more timely in addressing this issue.
c.
Conclusions The licensee inadvertently momentarily caused the Unit 1 SI "A" accumulator to depressurize one psig below the technical specification required limit. The depressurization was caused by inadequate communications during shift turnover, absence of an equipment status entry and ineffective procedure execution.
01.4 Loss of Unit 1 ElectricalInverter 1-lll l
a.
Inspection Scope (71707)
i The inspectors reviewed plant documentation and discussed with numerous personnel
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the loss of electrical inverter 1-Ill. Through this review the inspectors verified that the plant's response was as expected.
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b.
Observations and Findinas On February 19 while Unit 1 was operating at 100 percent power, the electrical breaker which supplies power to the 1-111 inverter inadvertently tripped opened resulting in a temporary loss of power to 120 VAC vital bus 1 Ill. The power loss resulted in a significant main feedwater transient and the automatic start of the standby feedwater and condensate pumps. The operating crew quickly responded to the transient and restored power to the bus using the non-inverted power source (SOLA transformer).
The operating crew properly executed TS 3.8.2.1 action statements to restore power to the bus within two hours and to restore the inverter power source to the bus within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The suspected cause of the thermally induced breaker trip (see Section E1.1)
was over heating of the breaker's positive electricallead connection. The licensee initiated DR N-99-445 to determine the cause and to address appropriate corrective actions.
The inspectors evaluated operator response to the transient through a review of operating logs and procedures, associated training material, and through discussions with severallicensed operators and trainers. The transient was challenging because the main feedwater regulating valves (FRVs) fully opened as expected for this event. As a result, all three steam generator water levels increased significantly. The operator was successful at mitigating the transient by promptly taking manual control of the FRVs.
This action prevented a turbine / reactor trip. The inspectors concluded that operator response to the transient was excellent.
The inspectors verified how the operating crew responded to certain plant parameters.
This was done by a review of completed operating procedures and expected actions based on certain parameter values. Specifically, the inspectors verified that proper actions were performed for steam generator water levels and reactor coolant pump temperatures. For example, the inspectors verified that steam generator water levels or reactor coolant pump motor bearing temperatures did not exceed values which required a plant shutdown.
The licensee performed a transient analpis to verify that the plant responded as expected based on available data from the plant computer system (PCS). The licensee also operated the training simulator to ensure modeling of the transient was accurate.
The licensee found no problems during these efforts. The inspectors reviewed the analysis and discussed findings with plant personnel. The inspectors concluded that the plant responded as designed to the loss of the 1-Ill electrical inverter power supply.
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Conclusions The plant. responded as designed to the loss of the 1-ill electrical inverter power source to the associated 120 VAC vital bus. Technical specification 3.8.2.1 was properly executed. Operator response to the main feedwater transient which occurred as a result of the power loss was excellent. The operator quickly responded to the transient by taking manual control of the main feedwater regulating valves.
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01.5 Review of Operator Workarounds (OWAs)
a.
Inspection Scope (71707)
The inspectors reviewed the active OWAs during the inspection period and attended OWA status meetings. The inspectors also discussed the OWA program with licensee management.
b.
Observations and Findinos During the inspection period there were 23 active OWAs prioritized by the operations review board (ORB) as either A, B, or C. The A priority OWAs were most significant because they were determined to have the potential to affect nuclear safety. There were five priority A OWAs. The inspectors reviewed these OWAs and found that one was over three years old. This OWA is associated with the reserve station service transformer tap changer which operates to maintain system voltage within a desired range. Over voltage conditions occur at the 1J1480 volt load center which requires manual operator action to adjust the voltage within a short period. This OWA occurs only during normal operations when the emergency bus is lightly loaded, and would not be a concern during major transients or accidents. Other notable priority A OWAs which involved equipment not performing as designed included the following:
frequent alarms associated with Unit 2 "B" reactor coolant pump degraded
number two seal (1998)
boric acid storage tank in-leakage problerns (1998)
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reliability concerns associated with heat trace circuits that maintain boration flow
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path (1998)
The inspectors noted that the OWAs listed above are associated with safety-related components or those important to safety. Based on the inspectors review of the items on the OWA list and those that had been on the list and dispositioned, the inspectors concluded that operators were informing their management of troubling plant issues.
The inspectors did not identify any examples where regulatory requirements were not satisfied.
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Conclusions Operators were effective in identifying issues to plant management which the operations review board considered to be cperator workarounds (OWAs). There were several active OWAs affecting safety-re!ated equipment or equipment important to safety.
These OWAs were associated wRh normal operations and had no adverse effects on operating transients or accidents.
Miscellaneous Operations issues (92700)
08.1 (Closed) Licensee Event Report (LER) 50-338/99001-00: reactor coolant system (RCS)
leak rate missed surveillance due to computer malfunction. TS 4.4.6.2.1.d requires performance of a RCS water inventory balance every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. On January 6 the licensee determined that the Unit 1 RCS water inventory balance calculation performed
l earlier that day, and on January 3, were in error. The licensee determined that the i
calculation level inputs from the volume control tank (VCT) and the pressurizer were zero percent versus their actual levels. Because the plant process computer (P250)
failed to insert the correct VCT and pressurizer data into the overall leak rate calculation, the water inventory balance calculation was invalid. Because the leak rate calculation was invalid, the licensee missed surveillance requirement 4.4.6.2.1.d on January 3.
On January 6 the licensee corrected the computer problem and re-performed the leak rate test satisfactorily. The licensee also ensured that the identified failures were isolated. The licensee verified that the previous test performed on December 31,1998 was satisfactory. In addition, a review of 50 selected tests from 1998 was performed and no problems were found. The test procedure was revised to ensure that plant parameters included in the test are valid for existing plant conditions.
The inspectors reviewed operating logs and the completed periodic tests to verify timeliness and accuracy of the LER. The inspectors also reviewed revised tests for both units and concluded that the revised guidance was appropriate. Based on a discussion with the operations superintendent and through a review of the water inventory balance tests performed on January 3 and January 6, the inspectors concluded that the involved operators' attention to detail was deficient. The tests required printout and review of the RCS leak rate data sheet. From this information, operations personnel should i a/e noticed that the unidentified leak rate had increased from the recent values bet.veen 0.01 and 0.04 gpm to approximately 0.3 gpm and initiated an evaluation into the step change. The new unidentified leak rate was about one third of the TS allowable value.
A more detailed review of the data sheet should have revealed that the VCT and pressurizer values were invalid, i.e.,the VCT and pressurizer levelinputs are not zero percent at full power operations. If the operators had noticed this discrepant data, the surveillance could have then been properly performed.
The inspectors evaluated the safety significance of the missed surveillance and determined it to be low. The actual RCS leak rate was well within the TS limits. Failure to perform the surveibnce is a violation of TS 4.4.6.2.1.d. This Severity Level IV violation is being treated as a Non-Cited Violation consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as DR N-99-042. This item is identified as NCV 50-338/99001-01.
08.2 (Closed) LER 50-338/99002-00: isolation valve unsecured due to personnel error. On February 13, the licensee discovered that the Unit 1 boron injection tank (BIT) manual bypass isolation valve,1-SI-77, which was to be locked closed, was in the proper position but not locked. TS 3.6.1.1 required this valve to be locked closed during normal operation to ensure that the release of radioactive materials from the containment atmosphere will be restricted to those leakage paths and associated leak rates assumed in the accident analysis. The BIT bypass valve was to be secured in a manner which would preclude manipulation of the valve's "T-type" handle. On February 9, piping insulators while installing insulation on the body of 1-SI-77, removed the chain with the lock closed from the valve handle. When the job was completed, the workers improperly placed the lock and chain assembly on the valve stem. On February 13, during monthly TS regired surveillance of locked valves, the chain and closed lock was discovered on the floor and unattached to the valve. The licensee immediately re-secured the valve. As part of their corrective actions, the licensee checked other "T-type" handled valves for similar problems. All 16 valves were verified to be in their
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required positions and were properly secured. The licensee drilled holes in the valve handles to allow the chain and lock to be more securely fastened.
The inspectors reviewed operating logs, interviewed workers, walked down the BIT area and reviewed the associated DR to verify accuracy of the LER. The inspectors concludeo that the LER was accurate and timely. Since the valve was in the correct position, this event had little significance. The failure to have the BIT bypass valve locked is violation of TS 3.6.1.1 which constitutes a violation of minor significance and is i
not subject to formal enforcement action.
l 08.3 Caroline and Sootsvivania County Local Officials Plant Visits On February 10 and 11, the inspectors rnet with the Caroline county and Spotsylvania county emergency preparedness (EP) coordinators. The following items were discussed:
EP coordinator / staff responsib;lities and their interface with the licenece's
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emergency response groups at the corporate and plant offices.
Licensee support to the EP staffs in Caroline and Spotsylvania counties.
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Communications with the NRC during routine office hours and emergncies.
- Discussions about proposed local EP facility changes and a proposed move to a
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new facility in Caroline county.
Discussions about delayed response times in Spotsylvania county (during the
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last full-scale EP drill exercise).
Discussions about faster than anticipated population growth in Spotsylvania
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county and the impact on EP response.
08.4 Manaaement Review Board Meetina (40500)
On March 8, the inspectors attended a management review board (MRB) meeting in which several topics were presented to key station managers. The inspectors listened to discussions involving operating experience (OE) program improvements, the on-going development of a detailed engineering system health report, and results of a fourth quarter 1998 DR trend report. A major OE program improvement involved the use of a "real time" computer network and improvements in OE reporting capabilities.
The DR trend report pointed out that DRs in the fourth quarter of 1998 had decreased to 791 compared to an average of 977 for the three previous quarters. The decrease was attributed to a reduction in plant activities. The inspectors concluded that MRB activities continued to provide a positive forum for self-assessment of station activities and were an effective contributor to the licensee's corrective action program.
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II Maintenance M1 Conduct of Maintenance M1.1 Failure to Perform Post Maintenance Test (PMT) for Miscellaneous Component Coolina (CC) Water Valves i
a.
Inspection Scope (62707.37551)
The inspectors reviewed circumstances associated with the failure to assign a PMT for CC water valves.
b.
Observations and Findinas On February 1 during the performance of TS 4.0.5 required stroke test,2-CC-TV-203B
failed to stroke in the required time. The stroke time in the closed direction was 16.93 l
neconds which was outside the test acceptance criteria of 19.48 seconds. The licensee immediately declared the valve inoperable and entered TS 3.6.3.1. The inspectors reviewed operating logs and discussed the issue with involved plant personnel to confirm the licensee's findings. The inspectors determined that TS were appropriately implemented for the valve test failure.
An engineering calculation was performed which changed the close stroke time requirement (i.e., reference value) to greater than 12.70 seconds. This calculation was approved by the station nuclear safety and operating committee (SNSOC). The inspectors attended the SNSOC meeting and verified that SNSOC TS requirements for quorum were satisfied. The revised stroke time reference value resulted in the valve being declared operable. The valve was successfully tested the following day using the
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the issue from an operability standpoint.
The inspectors discussed the test failure with the inservice test supervisor and the test engineer. Test engineers determined that the valve had f ailed its stroke test on February 1 because of previous maintenance that had been performed on January 29,
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1999. This maintenance had replaced the valve's vent cap because the cap had been covered with paint. The licensee had previously initiated DR N-98-2600 to determine the cause and b address appropriate corrective actions for the painting issue. One of the corrective actions for this DR was to replace the vent caps for affected valves. It
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was believed by the licensee that the excessive paint could have affected valve stroke l
time because it prevented the proper flow of air during valve operation. PMTs had not been performed for the vent cap replacements.
The licensee did not perform PMTs because it was believed that replacing the vent caps would improve valve performance (i.e., result in a slightly faster stroke time) by ensuring an unrestricted air flow from the valve's actuator. The licensee believed that changing l
tho vent caps wouH not affect valve operability. The licensee knew during the planning l
of the vent esp replacements that valve stroke times (i.e., valve performance) could be affected. in addition, the licensee's test program manual states if maintenance cannot be deferred to a shutdown condition, then an engineering evaluation must be performed j
prior to the maintenance to determine the effect of the maintenance on valve i
performance, if the evaluation shows that performance will not be affected, then no l
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PMT is required. The inspectors determined that the licensee's initial PMT assessment did not consider in sufficient detail the overall effects of the work.
Technical Specification 4.0.5.a requires inservice testing of American Society of Mechanical Engineers (ASME) Code Class 1,2, and 3 valves in accordance with Section XI of the ASME Boiler and Pressure Vessel Code and applicable Addenda.
i Section Xi references ASME/American National Standards Institute (ANSI) OMa Part l
10, " Code for Operation and Maintenance of Nuclear Power Plants," 1988 Addenda to ASME/ ANSI OM 1987 Edition. Part 10 states that following maintenance that could affect valve performance, a new reference stroke value shall be determined or the previous value reconfirmed by an inservice test prior to the time the valve is returned to service. Failure to perform the inservice testing as required by TS 4.0.5 is a violation.
This Severi!y Level IV viaktion is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as DR N-99-0266. The item is identified as NCV 50-339/99001-02.
The other CC valves that had their vent caps replaced without a PMT or subsequent successful surveillance test was evaluated by the licensee to determine if a test deferral was appropriate. (The stroke times of the valves that have been subsequently tested in accordance with their required surveillance tests were within the required acceptance criteria). There are 12 valves, however, which have not been tested. These are the Units 1 and 2 CC water supply and return isolation valves for the reactor coolant pumps.
These valves cannot be tested with the units at power because of cooling water requirements. The licensee therefore initiated engineering transmittal (ET) TI 99-004 to justify PMT deferral for these valves. The inspectors reviewed the ET and its conclusions and determined that the licensee's basis for deferral was reasonable. The inspectors confirmed that the licensee's position was consistent with NUREG 1482,
" Guidelines for Inservice Testing at Nuclear Power Plants," dated April 1995. The licensee intends to perfo,m the stroke time test at the first available opportunity when plant conditions allow.
The inspectors evaluated the safety significance of the failure to assign the PMTs and concluded that it was low. Voce the licensee formally evaluated the valve stroke times it was demonstrated that valve performance was not adversely affected. The inspectors were concerned, however, that the licensee did not conservatively assign PMTs when it was known that valve performance could change. The ether CC valves which had their vent caps replaced with no PMT and no subsequent successful test represented minimal risk to plant operation.
c.
Conclusions A non-cited violation was identified for the f ailure to perforn service testing or post maintenance tests (PMTs) following vent cap replacement on component cooling (CC)
water valves. The licensee subsequently justified deferring testing for some CC valves until the first available opportunity, i.e., when plant conditions allo,
M1.2 Observation of Maintenance Activities a.
Lnspection Scope (62707.37551)
The inspectors observed all or portions of the following Work Orders (W9s):
WO 405053 01 Inspect / repair / plug Unit 1 1 A component cooling water
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heat exchanger WO 405818 01 Test / repair lube oil cooler for Unit 1 1C charging pump
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WO 405548 02 Thermography for circuit 12 in electrical panel 1-EP-CB-12
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b.
Observations and Findinas I
All work had been properly approved by operations and was included on the plan of the day (POD). When work was associated with a risk significant structure, system, or component, it was evaluated to determine its impact on the plant's core damage frequency. The inspectors found the work performed under these activities was professional and thorough. The work was performed with the work package present and in use. Accompanying documents such as orocedures and supplemental work instructions were properly followed. Personnel were experienced, properly trained and knowledgeable of their assignments.
The inspectors attended the pre-brief for the thermography activity on the 1-ill inverter power supply breaker. The inspectors observed that the licensee used scanned photographs displayed on a computer monitor of the electrical cabinet where the work occurred. In previous maintenance activities the inspectors had also noticed the use of photographs in selected work package instructions. The inspectors discussed the use of such visual aids with the workers who thought that such technology was beneficial for work preparation. The inspectors considered that the use of photographs to he;p workers better understand the work environment was noteworthy.
The inspectors observed technicians boroscope the Unit 1 1C charging pump lube oil cooler and reviewed associated preventive maintenance (PM) and engineering documents. The cooler had developed a service water leak on February 25 which rendered the 1C charging pump inoperable. The problem was discovered by an operator on routine rounds. The licensee initiated DR N-99-499 for the failure. Once the leak was identified the licensee plugged the associated faulty cooler tube and returned the pump to service satisfactorily. The licensee initiated an engineering transmittal (ET) which evaluated the number of tubes which could be plugged without aft icting the cooler's ability to perform its function. The inspectors reviewed the ET and its onclusions were judged by the inspectors to be reasonable based on the excess co< ling capacity of the cooler. During the boroscoping the inspectors observed numerous internal tube pitting sites. The inspectors, therefore, reviewed the PM for lube oil cooler inspections. The PM did not include boroscoping, but did involve a visual inspection and cleaning. The inspectors verified that these activities were being performed. The licensee stated that the use of boroscoping would be evaluated for future PM activities.
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Conclusions
Unit 1 maintenance activities for the 1 A component cooling water heat exchanger,1C
charging pump lube oil cooler, and the 1-til inverter power supply breaker were properly l
performed. The personnel conducting the activities were knowledgeable and properly I
followed work package instructions. Use of photographs to help workers better I
understand the work environment was noteworthy.
M1.3 Miscellaneous Periodic Tests (PT) Obsevations In_spection Scopo (61726)
a.
n The inspectors observed the performance of portions of the following pts:
1-PT-64.1 A, " Quench Spray System
"A" Subsystem," Revision 24
2 PT-64.18, " Quench Spray System
"B" Subsystem," Revision 21
2-PT-71.10,"2-FW-P-2, Turbine Driven Auxiliary Feedwater Pump, and Valve
Test," Revision 21 b.
Observations and Findinas
The inspectors verified that the tests were properly approved by management and were included on the POD. For these activities, the inspectors ensured that the licensee had evaluated on-line maintenance risks in accordance with the maintenance rule program.
The inspectors checked selected components for their pre-test and post-test positions to ensure they were properly positioned and no discrepancies were identified. The inspectors examined test instruments to ensure the instruments had been calibrated and their calibration due date had not expired. When tests affected TS, the inspectors ensured that appropriate TS action statements were implemented. The inspectors also reviewed the test acceptance criteria to ensure they were consistent with TS i
requirements and no problems were found. The inspectors reviewed selected test data i
to ensure component performance was satisfactory and no problems were found.
During test performance, the inspectors evaluated procedure adherence,
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i communications between the workers, and worker knowledge of the assigned activities.
The inspectors found these testing work practices to be satisfactory.
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Conclusions Routine periodic tests for Unit 1 and 2 quench spray subsystems and the Unit 2 turbine driven auxiliary feedwater system were properly performed. Test procedures were properly followed by knowledgeable workers. The tests were properly approved by station management and included within the licensee's evaluation for on-line maintenance. Technical specifications requirements were also satisfie /
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Ill. Enaineerina E1 Conduct of Engineering E1.1 Trio of General Electric (GE) Molded Ca' a Circuit Breaker Supplyino Unit 1 1-ll! Inverter a.
Ir.spection Scope (37551)
The inspectors observed thermography of circuit 12 of electrical panel 1 EP-CB-12 CB.
This GE molded case circuit breaker tripped open causing a loss of pcwer to the 1-ll1 inverter.
t b.
Observations and Findinas On February 25 the inspectors observed thermography of the breaker which supplies
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power to the 1-lit inverter. This breaker is a GE model number THFK 226F000 with a 200 amperage (amp) rating. The breaker had tripped open on February 19 which caused a loss of power to the 1-lli inverter and deenergization of the associated 120 VAC bus (see section O1.4). The thermography indicated that the positive lead to the breaker had a higher than normal reading of about 103 degrees F, but well below the breaker thermal trip setpoint. The setpoint is dependent on current and at the time of the thermography, the current was about 56 amps. The neutral connection was about 83 degrees F. The licensee's initial assessment concluded that the electrical connections to the breaker were potentially oxidized resulting in an increase in resistence with a subsequent temperature increase. Because the breaker thermal trip devMe is located adjacent to the electrical connection area the licensee believed that this may have contributed to the breaker's thermal trip. The electrical connections to the breaker was loosened and tightened. This action was effective in lowering the resistance at the connection and subsequent thermography indicated normal temperatures at the connections.
The inspectors discussed with the licensee plans to monitor the breaker. The licensee planned to monitor the breaker connections using thermography. At the time of the inspection, the root cause cf the breaker trip was not known. The licensee intends to perform a more in-depth breaker and breaker connection inspection during the March 2000 refueling outage. An in-depth inspection could not me performed with the unit at power due to TS limiting actions. The inspectors considered that the licensee's plans for this breaker were reasonable. The inspectors also discussed with the licensee the
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applicability of this issue to other similar breakers. The licensee planned to perform additional thermography on other similar breakers to assess the scope of this issue.
While performing this inspection, the inspectors discussed with the licensee the preventive maintenance (PM) performed on this and similar breakers. No PM program had been established for these breakers and vendor recommendations were not implemented. At the end of the report period, the licensee was evaluating what PM, if any, was necessary.
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c.
Conclusions The licensee, through thermography, determined that the breaker which tripped and caused a loss of the Unit 1 120 VAC vital bus 1-ill had an elevated temperature at the
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breaker's electrical connection. The actions to temporarily correct the condition and the licensee's plans to monitor the breaker and perform a more in-depth root cause analysis were acceptable. The licensee is evaluating the need to perform preventive maintenance on this and similar breakers.
E2 Engineering Support of Facilities and Equipment E2.1 Switch-Over From a Unit 2 Steam Flow-Based to a Feedwater (FW) Flow-Based Calorimetric a.
Inspection Scope (37551)
The licensee changed the secondary calorimetric program to use FW flow instead of steam flow. The inspectors interviewed engineering and operations personnel, reviewed pertinent documentation for the change. observed related control room and secondary system reconfiguring activities, and reviewed the overall approach for the change.
b.
Observations and Findinas The inspectors noted that the licensee originally used a FW flow based calorimetric.
Due to problems with original plant chemistry and the use of copper-tubed FW heaters, the original FW flow venturis became fouled. Problems were subsequently noted with actual versus indicated reactor power whereby actual was less than indicated. Because of these differences, in 1984 the licensee switched to a steam flow based calorimetric.
In 1995 the licensee experienced problems with actual versus indicated reactor power due to a slight fouling of the steam flow venturis. In 1998 the licensee decided to convert back to a FW flow based program because the FW heaters had been replaced with stainless steel tubes and secondary chemistry had significantly improved.
During the inspection period the inspectors discussed with engineering personnel the design review for the switch-over from a steam flow to a FW flow based calorimetric (design change #98-007). The inspectors also checked on potentialimpacts of the change on the core operating limits report (COLR). The inspectors also conferred with the NRR project manager, nuclear fuels group personnel, and the on-site nuclear engineer about the change and the overallimpact on the COLR. After these discussions and review of the Unit 2 May 1998 COLR, the inspectors concluded that sufficient margin existed in the steam flow based 100% power COLR data to permit the change.
The inspectors reviewed the design change and noted that over the last year actual Unit 2 thermal power had been about 2% lower than its indicated power (i.e., about 2840 Mwt versus a licensed power of 2893 Mwt). On March 8, the licensee changed to a FW flow based calorimetric software package. Once this occurred, calculated power was about 2840 Mwt and indicated power was 98%. On March 10, the inspectors observed activities involving the increase of core power from 96% to near 100% power as shown by first stage turbine pressure and actual core Tave indicating that the core was at or near its licensed power of 2893 Mwt. Net electrical output increased by approximately 20 MW.
After the end of the report period, the licensee performed a core flux map. The inspectors reviewed the associated data and determined that parameters, such as hot
channel f actors, were within the limits established by the COLR. The inspectors considered that the calorimetric change had been successfully implemented and that core thermal power, as derived by the secondary calorimetric, was within licensed and COLR limits.
c.
Conclusions The Unit 2 conversion from a steam flow-based calorimetric to a feedwater flow-based calorimetric was performed in accordance with the associated design change package.
Although the unit produced apprnximately 20 megawatts more power, the revised calorimetric demonstrated that the unit was operating within licensed and core operating limits report allowable values.
E7 Quality Assurance in Engineering Activities E7.1 Questionable Reliability of Timino Relays - 10 CFR Part 21 Issue a.
Inspection Scope (37551)
The inspectors conducted follow-up inspections of licensee activities to address a 10 CFR Part 21 involving Agastat Serius E7000 timing relays (notification #99-03, dated January 26,1999). The inspectors conducted interviewc with engineering, reviewed
documentation for an overall assessment of the problem and reviewed the licensee's I
response to the problem.
b.
Observations and Findinas The inspectors discussed with engineering personnel the timing relay issue, reviewed related 10 CFR Part 21 information and reviewed the manufacturer's outletin. The manufacturer indicated that J the subject timing relay contacts are operated near the minimum low amperage / low voltage test acceptance criterion,100 milliamperes /6 volts DC, an oxidation film could develop and prevent the relay from functioning properly. On February 9, the licensee established a task force to investigate the issue's applicability to the station. The task team found that installed Agastat Series E7000 timing relays operated well above the minimum test acceptance criterion and all systems using this type of relay were operable. The issue was promptly entered into the licensee's operating experience (OE) data bank.
The inspectors noted that the licensee was timely in issuance of DR N-99-363 and prompt in their actual response to the 10 CFR Part 21. The inspectors determined that the relay task team was thorough in their investigation.
c.
Conclusions The licensee's operating experience program response to a 10 CFR Part 21 involving Agastat Series E7000 timing relays was timely, thorough and effectively resolved this issue.
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E8 Miscellaneous Engineering issues (37551,92903)
E8.1 (Closed) Unresolved item (URI) 50-339/98011-03: potential nonconformance with material specifications for charging pump motor lead lugs. The inspectors reviewed a corporate metallurgical laboratory report to confirm if Unit 2 B charging pump motor lead lugs met material specification requirements. Material specification NA3014 requires the use of series 6000 aluminum or aluminum alloyed charging pump motor lead lugs.
The metallurgicaliaboratory report, NESML-Q-387, dated February 8, stated that the removed lead lug was essentially pure copper and the motor lead was aluminum. The l
report also stated that the mismatch in thermal expansion coefficients of the aluminum
!
and L e copper led to a loosening of the connection between the lug and motor lead I
resulting in an overheating of the connection. Further, it was noted that a microscopic crack, found in the barrel of the copper lead lug, may have also contributed to the overheating problem. During the NRC 50-339/98-011 inspection report period, the licensee replaced all Unit 2 B charging pump motor lead lups with aluminum lugs.
During the current inspection period, the licensee continued to perform their corrective i
actions which included an examination of the lead lugs for the remaining five Unit 1 and 2 charging pump motors. The licensee did not find a similar nonconformance.
Criterion V of 10 CFR 50, Appendix B, requires that activities which affect quality be accomplished in accordance with appropriate instructions. Material specification NA3014 specified that the material for the charging pump motor lead lugs be aluminum or aluminum alloyed. A violation of 10 CFR 50, Appendix B, Criterion V was discovered on January 4,1999, in that, the installed motor lead lugs on the Unit 2 B Charging pump was copper and not a material specihed in NA3014. This Severity Level IV violation la being treated as a Non-Cited Violation (NCV) consistent with Appendix C of the NRC l
Enforcement Policy. This violation is in the licensee's corrective action program as DR N-99-017. The item is identified as NCV 50-339/99001-03.
IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls (71750)
On numerous occasions during the inspection period, the inspectors reviewed Radiation Protection (RP) practices including radiation control area entry and exit, survey results, and radiological area material conditions. No discrepancies were noted, and the inspectors determined that RP practices were proper.
S1 Conduct of Security and Safeguards Activities (71750)
During the inspection period, the inspectors performed routine walkdowns of the protected area perimeter to assess security / general barrier conditions. On February 26, the inspectors performed an off-hours inspection of the protected area perimeter. This inspection included observations of the protected area fencing conditions and night shift attentiveness of security personnel. The inspectors concluded that security posts were paperly manned, security personnel were attentive and the perimeter material condition was properly maintained.
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F1 Control of Fire Protection Activities F1.1 Combustible Material and Housekeepino Controls / Fire Hazards Reduction a.
hsgection Scope (64704)
The inspectors reviewed the Virginia Power Administrative Procedure, VPAP-2401," Fire Protection Program, Revision 10, dated July 15,1998, to determine if it satisfied the objectives established by the licensee's commitments to implement its NRC-approved l
fire protection program. The inspectors toured selected plant areas to inspect the
!
licensee's implementation of the fire prevention aspects of the program procedure and to observe housekeeping practices and cleanliness conditions to determine whether safety or fire hazards or both existed. The inspectors also reviewed the results of the licensee's periodic fire protection plant inspections and DR to verify that transient combustible fire hazards issues and corrective actions were identified.
b.
Observations and Findinas The inspectors observed that controls were being maintained for transient combustibles l
in areas containing potential lubrication oil and diesel fuel leaks, such as the diesel generator rooms. Lubricants and oils were properly stored in Underwriter's Laboratory (UL)/ Factory Mutual (FM)-approved safety containers. Fire retardant treated wood, plastic sheeting, and film materials were also being used in safety-related areas. The inspectors observed that the waste material trash cans utilized safety covered tids. The trash cans were emptied on a frequent and regular basis and there was no excessive accumulation of combustible waste in safety-related plant areas. The inspectors concluded that, overall, the licensee's implementation of the combustible control procedures and plant operational practices were consistent with the approved fire protection program. Plant personnel routinely followed combustible control procedures i
to manage the use and temporary storage of transient combustibles in safety-related areas.
Measures to identify and contrcl transient fire hazards within the plant were included in the licensee's fire inspection and corrective action programs. Designated fire inspectors from the loss prevention unit conducted monthly plant fire inspections to identify and correct potential fire hazards. The inspectors reviewed the results of the fire inspections anc other associated DRs written for combustible control issues identified for the past 3-year period (between January 1996 and February 1999). These reports indicated that four examples of combustible hazards control problems in safety-related plant areas had been identified. The plant fire protection staff had initiated corrective actions for the issues through the various responsible plant department supervisors. The inspectors determined that implementation of the fire protection program requirements for control of combustible fire hazards was good.
c.
Conclusions implementation of the fire protection program requirements for control of combustible fire hazards was good. Plant personnel followed combustible control procedures to manage the use and temporary storage of transient combustibles in safety-related l
areas. Plant housekeeping and trash control were in accordance with procedure l
requirements.
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F1.2 lanition Source and Fire Risk Reduction a.
Inspection Scope (64704)
The inspectors reviewed administrative procedure VPAP 2401," Fire Protection Program," Revision 10, dated July 15,1998, and the licensee's smoking policy. The inspectors toured the Unit 1 and 2 Emergency Switchgear Rooms and observed implementation of the licensee's ignition source controls during hot work activities that were in progress.
b.
Observations and Findinas Plant smoking policy memorandum prohibits smoking in all plant areas, except in those marked outdoor areas designated specifically as smoking areas.
A hot work operation, involving welding and grinding, was observed. The operation was being performed in association with modifications being made to service water piping
located in the Unit 2 Emergency Switchgear Rooms. A hot work permit had been issued and posted for the operation, and the appropriate fire prevention controls were established and implemented. The inspectors also observed that no work-related protective clothing or lubricants, w. 3 left unattended in the area and were located away from potential ignition sources sucn as the wciding or grinding areas. The inspectors
!
also observed that the smoking policy was being followed by plant personnel.
I c.
Conclusions The licensee's administrative controls for ignition source control were being implemented in accordance with the fire protection program.
F1.3 Fire Reports and investiaations a.
Inspection Scope (64704)
The inspectors reviewed fire incident reports and the DRs resulting from smoke and equipment overheating incidents, for the three year period 1996-1998, to assess maintenance-related or material condition problems with plant systems and equipment that may have initiated these incidents. The inspectors assessed whether plant fire protection requirements in VPAP 2401, Form No. 723378, " Fire incident Reports," were met when fire-related events occurred.
b.
Observations and Findinos The licensee's fire reports and DR issues associated with observed smoke or equipment overheating indicated that during the period 1996-1998 there were seventeen incidents of fire, smoke or equipment overhesting observed within safety-related plant areas. The inspectors determined that this indicated an average of three incidents per reactor year of operation. No significant increase or decrease in the number of these fire related incidents were noted over the time period. Eleven of the seventeen incidents (approximately 60%) were related to electrical component faults. No fires had been reported in 1999. In all cases, the fire or overheating condition was identified and
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mitigating action was taken in a timely manner do as to limit the damage to the original source and to prevent exposure to other safety-related equipment or cables.
c.
Conclusions Eleven incidents of smoke or equipment overheating were identified in the past three years which were caused by electrical component faults within safety-related areas.
These fire related conditions were properly identified and mitigating actions were taken in a timely manner. No trends were identified.
F2 Status of Fire Protection Facilities and Equipment
'
F2.1 Inspection of Fire Briaade Eauipment a.
Inspection Scope (64704)
The inspectors reviewed VPAP 2401, Section 6.6.10 " Fire Brigade Equipment" and toured the fire brigade staging area and inspected fire brigade lockers. The inspection was conducted to verify that the fire brigade equipment specified in the fire protection program was accessible and available in the staging area and fire brigade lockers, b.
Observation and Findinas Using the fire protection program turnout gear list, the inspectors toured the fire brigade staging area and inspected four fire brigade lockers. The inspectors observed that the equipment listed in the VPAP 2401, Section 6.6.10 was accessible and available for use. The equipment in the fire brigade staging area and lockers included fire brigade helmets / hoods, turnout coats, pants, boots, gloves, flashlights, radios and self-contained breathing apparatus (SCBA) for each member of the fire brigade. The equipment was in good condition and was well maintained. The inspectors also observed that there was fixed battery-powered backup lighting installed at the fire brigade staging dressout area and in the area of the fire brigade SCBAs. The backup lighting was operable and provided an adequate level of lighting to support fire brigade operations.
c.
Conclusions Personal protective fire fighting equipment provided to the fire brigade was in good condition and provided a sufficient level of personal safety needed for onsite fire emergencies. Backup fighting in the dressout areas provided an adequate level of lighting in support of fire brigade operations.
F3 Fire Protection Procedures and Documentation F3.1 Fire Briaade Pre-fire Stratecies a.
Inspection Scope (64704)
The inspectors reviewed Nre brigade pre-fire strategies for selected plant areas described in Section 6.1.'
and Attachments 18 and 19 of VPAP 2401 for compliance with the fire protection program. Plant tours were also performed to verify the fire strategies reflected as-built plant conditions and potential fire conditions.
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Observations and Findinas j
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l The inspectors reviewed the pre-fire strategies 1-FS-S-3, " Fire Fighting Strategy for the l
Unit 1 Emergency Switchgear Instrument Rack and Air Conditioning Rooms," Region 6, l
2-FS-S-3," Fire Fighting Strategy for the Unit 2 Emergency Switchgear Instrument Rack
'
and Air Conditioning Rooms," Revision 4, and 1-FS-ESG-BR-1," Fire Fighting Strategy for the Unit 1 and 2 Emergency Switchgear Battery Rooms," Revision 2. Each of the fire fighting strategies and plan drawings addressed the fire potential, area location, means of fire brigade approach, location of the available fire protection equipment, fire brigade actions, hazards to be considered, ventilation, special notes and instructions, and communications available. During plant tours the inspectors compared the pre-fire strategy plan drawings with as-built plant conditions. No discrepancies were noted. The pre-fire strategies were found to be satisfactory and met the requirements of the fire l
protection program.
c.
Conclusicn_s Fire brigade pre-fire strategies provided clear and sufficient instructions and met the requirements of the fire protection program, F5 Fire Protection Staff Training and Qualification F5.1 Fire Briaade Drill Proaram a.
Inspection Scope (64704)
The inspectors reviewed the fire brigade drill program for compliance with plant procedures and NRC guidelines and requirements, b.
Observations and Findinas A fire brigade drill was not conducted during this inspection. To evaluate drill performance, the drill critique data for selected shift drills conducted during the past 10-year period in the Emergency Switchgear Rooms, Cable Vault and Tunnel, Emergency Diesel Generator Rooms, and Turbine Oil Rooms were reviewed by the inspector. The inspectors determined that the nominal response time to assemble at the fire scene ready for fire attack was about 10 minutes. The overall fire brigade response and participation for these drills was satisfactory.
c.
Conclusions Fire drill critique data indicated that the fire brigade's response time and performance were good. All the fire brigade members were at the fire drill site and ready to attack the fire in an average of ten minutes.
F8 Miscellaneous Plant Support issues (92904)
F8.1 t' Closed) IFl 50-338.339/96013-02: Manualin Lieu of Automatic Fire Suppression System Installed in Units 1 and 2 Emergency Switchgear Rooms. This item addressed the manual Halon 1301 fire suppression systems installed in the emergency switchgt ar rooms (fire areas 6.1 and 6.2). Region il requested the Office of Nuclear Reactor
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Regulation's (NRR) assistance in Task Interface Agreement (TIA)97-004, dated February 19,1997, in evaluating the manual versus automatic actuation of the Halon system. The NRR technical evaluation was transmitted to Region 11 in a memorandum dated November 17,1998. The evaluation expressed concems of the adequacy of the Halon for a deep-seated fire hazard. The licensee provided the inspectors with information related to the risk evaluation of fire in the emergency switchgear rooms and operation of the manual Halon system which included the following information:
The licensee's fire risk assessment submitted to the NRC on June 28,
.
1994, in response to Generic Letter 88-20, Supplement 4, concluded that the North Anna Unit 1 emergency switchgear room has a core damage frequency (CDF) of 3.28E-6 per year (without credit of the manual Halon suppression system) which represents approximately 84% of the total Unit 1 fire CDF.
Smoke detection alarm procedure response demonstrated operator
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actuation of the Halon system within about 5 minutes following the alarm.
A combustible loading summary for the emergency switchgear rooms that
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indicates a total fire duration up to 72 minutes for combustibles that consist primarily of cabling, electrical control panels, and switchgear.
Halon fire suppression system functional test results that demonstrate a
.
system performance of an average Halon concentration of 7% and soak time of over 20 minutes.
An evaluation of the latest functional testing of the control room pressure
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envelope that indicates a 1.1% total area volume leakage and demonstrates the tightness of the emergency switchgear room fire barriers.
Emergency switchgear room fire door periodic test and inspection
.
procedures which verify proper latching and fit of fire doors within the emergency switchgear room fire barriers.
Emergency switchgear room fire detection system GL 86-10 engineering
.
evaluation that establishes that the system design layout is equivalent in effectiveness to that prescribed by National Fire Protection Association (NFPA) Standard 72E.
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Photographs of the emergency switchgear rooms and switchgear cabinet
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configurations that indicate acceptable ventilation paths for halon agent entry into the cabinet internals.
NUREG/CR-3656, SAND 83-2664," Evaluations of Suppression Methods
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for Electrical Cable Fires," addresses Halon fire supression system effecane.e. on deep-seated cable tray fires.
Clarification of IEEE 383 rated cable qualification tests.
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This information is being provided to NRR to f aciliate a risk informed backfit analysis to determine the need for automatic versus manual actuation of the emergency switchgear rooms fire suppression system. Based upon this information, followup inspection of this item is closed.
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V. Manaaement Meetinas X1 Exit Meeting Summary i
l The fire protection inspection scope and results were presented to licensee
!
management on February 12,1999. The inspectors presented the other inspection results to members of licensee management at the conclusion of the inspection on March 16,1999. Although the licensee initially questioned if NCV 50-339/99001-02 was a violation, they subsequently acknowledged all the findings as presented.
l The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
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PARTIAL LIST OF PERSONS CONTACTED Licensee D. Christian, Vice President, Nuclear Operations B. Foster, Superintendent Station Engineering C. Funderburk, Manager, Station Safety and Licensing J. Hayes, Acting Manager, Station Operations and Maintenance L. Jordan, Acting Superintendent, Radiological Protection P. Kemp, Supervisor, Licensing L. Lane, Superintendent, Operations T. Maddy, Superintendent, Security W. Matthews, Site Vice President H. Royal, Superintendent, Nuclear Training D. Schappell, Superintendent, Site Services R. Shears, Superintendent, Maintenance A. Stafford, Acting Director, Nuclear Oversight INSPECTION PROCEDURES USED IP 37551:
Onsite Engineering IP 40500:
Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems IP 61726:
Surveillance Observations IP 62707:
Maintenance Observations IP 64704:
Fire Protection Program IP 71707:
Plant Operations IP 71750:
Plant Support Activities i
IP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP 93903:
Followup - Engineering IP 92904:
Followup - Plant Support ITEMS OPENED AND CLOSED Opened 50-338/99001-01 NCV failure to perform a reactor coolant system leak rate test when required (Section 08.1)
50-339/99001-02 NCV failure to perform inservice testing or PMT on Unit 2 CC valves (Section M1.1)
50-339/99001-03 NCV failure to adhere to material specifications specified for the Unit 2 8 charging pump motor lead lugs (Section E8.1)
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50-338/99001-00 LER RCS leak rate missed surveillance due to computer j
malfunction (Section 08.1)
50-338/99001-01 NCV f ailure to perform a reactor coolant system leak rate test when required (Section 08.1)
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50-338/99002-00 LER isolation valve unsecured due to personnel error (Section 08.2)
50-339/99001-02 NCV failure to perform inservice testing or PMT on Unit 2 CC valves (Section M1.1)
50-339/98011-03 URI potential nonconformance with material specifications for charging pamp motor lead lugs (Section E8.1)
50-339/99001-03 NCV failure to adhere to material specifications specified for the Unit 2 B charging pump motor lead lugs (Section E8.1)
50-338,339/96013-02 IFl Manual in Lieu of Automatic Fire Suppression System installed in Units 1 and 2 Emergency Switchgear Rooms
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(Section F8.1).
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