IR 05000361/1999012

Insp Repts 50-361/99-12 & 50-362/99-12 on 990808-0918. Violations Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML20217J880
Person / Time
Site:	San Onofre
Issue date:	10/15/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20217J868	List: IR 05000361/1999012 ML20217J863
References
50-361-99-12, 50-362-99-12, NUDOCS 9910250198
Download: ML20217J880 (17)

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ENCLOSURE U.S. NUCLEAR REGULATORY COMMISSION 1

. REGION IV {

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Docket Nos.: 50-361- )

50-362~

License Nos.: NPF-10 ~

I NPF 15 ~

. Report No.: l 50-361/99-12 -

50-362/99-12 Licensee: Southern California Edison C I Facility: San Onofre Nuclear Generating Station, Units 2 and 3 Location: 5000 S. Pacific Coast Hw '

San Clemente, California Dates: " August 8 through September 18,1999 Inspectors:- J. A. Sican, Senior Resident inspector J. G. Kramer, Resident inspector ,

J. J. Russell, Resident inspector I

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' Linda Joy Smith, Chief '

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' Approved By:

Project Branch E Division of Reactor Projects

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ATTACHMENT: - Supplemental Information

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9910250198 991015 PDR ADOCK 05000361

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EXECUTIVE SUMMARY San Onofre Nuclear Generating Station, Units 2 and 3

, NRC Inspection Report No. 50-361/99-12; 50-362/99-12 Ooerations

. Operators thoroughly and methodically prepared for and conducted evolution Management and supervisors provided close oversight of operational activitic Procedure uso and operator communications were generally consistent with written licensee management expectations (Section 01.1).

A control room supervisor's knowledge of why the plant was in a shutdown act;on statement was weak. The required cooling water makeup from the fire water system to Emergency Diesel Generator 2G002 had been isolated, necessitating entry into the shutdown action statement. The control room supervisor was unable to explain, based :

on the information in the limiting condition for operation action requirements sheet, the l condition that placed the unit in the action statement or the effects on the plant (Sectica 04.1). i a An apparent violation of Technical Specifications 3.0.3 and 3.8.1 occurred because .

operators did not recognize that they had aligned Emergency Diesel Generator 3G003 to an inoperable automatic voltage regulator. Subsequently, when the opposite-train battery charger was taken out of service, the Technical Specifications required that the same-train battery charger be declared inoperable. Because these conditions were not recognized, the operators did not perform the Technical Specification-required actions for the inoperable emergency diesel generator or for the two inoperable battery chargers, j which included shutting down Unit 3. The program to control equipment status was inadequate in that it failed to prevent the alignment of the emergency diesel generator to the inoperable automatic voltage regulator, which was known to perform erratica!; Additionally, operators on several shifts failed to observe the control board indication of the inappropriate alignment (EA 99-242) (Section 08.1).

Maintenance I

= Maintenance and surveillance activities were performed adequately and in accordance j with the applicable licensee procedures. Supervisory oversight and engineering support were consistently good (Sections M1.1 and M1.2).

• Planning for control room boundary dampt r maintenance was poor. Design limits on the amount of time the control room envelop 9 could be breached, in the event of a high radiation condition, were not incorpor.ned into work plans or known by Maintenance or Operations personnelinvolved. Pr,sonnel generally thought that they had 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to restore the system integrity, whevas the design assumed only 2 minutes for system restoration and actuation aftcr radiation reached the sensors. This was a violation of 10 CFR Part 50, Appedx B, Criterion ill, for failing to translate system design requirements into the ";ork control instructions and procedures. This Severity Level IV violat;on is being treated as a noncited violation, consistent with Appendix C of the V6 Fnforcemen'. Policy. This violation was in the licensee's corrective action program a: A ,on Request 990402380 (Section M1.3).

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• ' The' Unit 2 Reactor Coolant Pump 2P004 oil collection system design was inadequat ' Oilleaking from the spinning motor shaft during Mode 1 operations was not captured by the oil collection system. Oil had puddled on the pump and the floor below and had caked

or burnt on the seal package. .This was not in compliance with 10 CFR Part 50,'

s Appendix R, regarding the capability of the oil collection system to collect this oil; An unresolved item was opened to determine the scope and the significance of the noncompliance. The licensee had not yet accounted for all of the oillosses

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• - . A violation of 10 CFR Part 50, Appendix B, Criterion XVI,'resulted from a failure of the

. licensee to promptly identify and repair all gaps in containment emergency sump cover

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plates. This Severity Level IV violation is being treated as a noncited violation, cs isl stent with Appendix C of the NRC Enforcement Policy. In 1993 the licensee repaired some of the' gaps but failed to correct two additional gaps. This violation was in the licensee's corrective action program as Action Request 990201682.' Additionally, the inspectors determined that newly-discovered gaps between the side screens and the sump cover plate were also inconsistent with design commitments for the sumps and were required to be corrected. The licensee determined that the sumps were operable in their degraded condition (Section.E8.1).

Plant Suooort-l

. *' L Licensee LARA controls during at-power containment entnes were good (Section Rt.1). I

• Plant housekeeping was generally acceptable with the following exceptions. The

. inspectors identified two pairs of unattended wire cutters laying on top of high pressure

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' safety injection to reactor coolant system Loop 1 A Flow Transmitter 2FT0311-2. Also,

.. the inspectors identified an unrestrained chair in the immediate vicinity of containment L

purge stack Radiation Monitor 2RY7828. The licensee removed the unrestrained and unattended items and initiated Action Request 990800755 to document and evaluate the occurrences (Section R2.1).

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i Report Details Summary of Plant Status Units 2 and 3 operated at essentially 100 percent reactor power during this inspection perio l. Operations 01 Conduct of Operations i

01.1' General Comments (71707) I

. The inspectors observed routine and nonroutine operational activities throught d inspection period. Some of the activities observed included: I

Shift turnover (Units 2 and 3)

Manual blend to volume control tank (Unit 3)

• Emergency Diesel Generator (EDG) 2G003 placed on the grid (Unit 2)

• Boric acid make-up pumps / tanks placed on recirculation (Unit 2) J

• - Safety injection tank fill (Unit 3) 1 Operators thoroughly and methodically prepared for and conducted evolution Management and supervisors provided close oversight of operational activitie }

Procedure use and operator communications were generally consistent with written j

. licensee management expectation J 04 Operator Knowledge and Performance

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04.1 Control Room Supervisor (CRS) Knowledae of Licensee-Controlled Specification Action Statements - Unit 2 Inspection Scoce (71707)

The inspectors performed routine control room walkdowns and discussed operator knowledge with Operations managemen Observations and Findinas j On August 25,1999, the inspectors questioned the CRS about the meaning of Limiting

' Condition for Operation Action Requirements (LCOAR) L2-99-0888. The CRS was unable to explain, after reading the information on the LCOAR sheet, why the unit was in c ' a 60-day shutdown action statement. Licensee-Controlled Specification 3.7.113 l

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required, in part, with one or more of the required components in Table 3.7.113-1 ,

L inoperable, that ope.rators restore the inoperable component to an operable status in j l 60 days or be in Mode 3 in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. A work authorization record (WAR) isolated the -

required cooling water makeup from the fire water system to EDG 2G002, a component in Table 3.7.113-1. The CRS had initialed review of the sheet and had been on shift for >

1 several hours. The CRS obtained the WAR for the equipment and was ultimately able to explain why the unit was in the action statement, as well as the effects on the plant. The i

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2 inspectors discussed the CRS's performance with Operations management and determined that the CRS's knowledge of the LCOAR did not meet management expectation Corr mions A CRS's knowledge of why the plant was in a shutdown action statement was weak. The l reqcired cooling water makeup from the fire water system to EDG 2G002 had been -

isolated, necessitating entry into the shutdown action statement. The CRS was unable to explain, based on the information in the LCOAR sheet, the condition that placed the unit in the action statement or the effects on the plan : Miscellaneous Operations issues 08.1. (Closed) Licensee Event Report (LER) 362/1999-006-00: Technical Specification 3. entry caused by an inoperable ED Insr>ection Scoce'(92700)

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- The inspectors reviewed the circumstances surro_unding a Technical Specification 3. entry resulting from EDG 3G003 being rendered inoperable and the Technical Specification-required actions not being performe l

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' Observations and Findinas j At 1:45 a.m. on June 23,1999, following repairs to an annunciator power supply for Train B EDG 3G003, operators incorrectly aligned the EDG to Automatic Voltage

' Regulator (AVR) B, which was inoperable, and declared EDG 3G003 operabl Operators had declared AVR B inoperable in December 1998 but did not indicate this information locally at the AVR selector switch at the EDG. When aligning the EDG to AVR B on June 23, the operators did not check the status of the AVR, which was documented in the Equipment Deficiency Mode Restraint system. The postmaintenance testing following replacement of the power supply failed to reveal the instability that

. rendered AVR B inoperable. This resulted in EDG 3G003 being declared operable despite being aligned to the inoperable AVR.

Because operators believed EDG 3G003 was operable, they did not perform the actions

required by Technical Specification 3.8.1 for one EDG being inoperable. Specifically,

. Action B.1 required, in part, that operators verify operability of required offsite circuits l within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and once every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter, as specified in Surveillance Requirement 3.8.1.1. Because this action was not performed, Action F required Unit 3 to be in Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (8:45 a.m. on June 23) and Mode 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> (2i45 p.m. on June 24).-

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. At 5:45 a.m. on June 23, operators removed Train A Battery Charger 3B001 frm ,ervice a for planned maintenance. Because EDG 3G003 was inoperable, Technical Specification 3.8.1 Action B.2 required that the Train B Battery Charger 38002 be declared inoperable within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. Therefore, at 9:45 a.m., Battery Chargers 38001 and i

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3B002 were both inoperable, which was an unrecognized condition that required entry into Technical Specification 3.0.3. Technical Specification 3.0.3 required that action be initiated within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> (10:45 a.m.) to place the unit in Mode 3 within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> (4:45 p.m.),

and Mode 4 within 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> (10:45 p.m.). These actions were not performe ,

l At 12:00 a.m. on June 24, Battery Charger 38001 was returned to senrice, and the l Technical Specification 3.0.3 condition was exited. The total time that the Technical l Specification 3.0.3 condition existed was 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> and 15 minutes. At 8:25 a.m. on {

-June 25, operators monitoring the control boards identified that EDG 3G003 was incorrectly aligned to AVR B, and at 8:55 a.m. operators realigned the EDG to AVR A, making EDG 3G003 operable. During the time that EDG 3G003 was inoperable, j EDG 3G002 had been removed from service for 17 minutes for hand-barring. However, l

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Technical Specification 3.8.1, Condition E, allows two required EDGs to be inoperable for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, so this condition was acceptabl The licensee took several corrective actions, which included initiating a change to the Equipment Deficiency Mode Restraint procedure to require tagging of local points of control when applicable and discussing the event with every operating crew. Action Request (AR) 990601338 and Event Report 002-99-3 were initiated to document and I evaluate the even I The licensee evaluated the safety significance of the event, from the time Technical Specification 3.0.3 should have been entered to the time that EDG 3G003 was switched to AVR A, and determined that the incremental risk increase was 7.4E-7 for core damage and 1.5E-8 for large early releas The failure to shutdown the unit on June 23 was an apparent vio!ation of Technical Specifications 3.8.1 and 3.0.3 (EA 99-242) (eel 362/99012-01), Conclusions An apparent violation of Technical Specifications 3.0.3 and 3.8.1 occurred because operators did not recognize that they aligned EDG 3G003 to an inoperable AV Subsequently, when the opposite-train battery charger was taken out of service, the Technical Specifications required that the same-train battery charger be declared inoperabla. Because these conditions were not recognized. the operators did not perform the Technical Specification-required actions for the inoperable EDG or for the two inoperable battery chargers, which included shutting down Unit 3. The program to control equipment status was inadequate in that it failed to prevent the alignment of the EDG to the inoperable AVR, which was known to perform erratically. Additionally, operators on several shifts failed to observe the control board indication of the inappropriate alignment (EA 99-242).

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11. Maintenance

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.M1 Conduct of Maintenance I t

M1.1: . General Comments

? Insoection Scope (62707)

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The inspectors observed all or portions of the following work activities:

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. Replace saltwater cooling Pump 3P112 flange (Unit 3)

Troubleshoot auxiliary feedwater Bypass Valve 2HV4762 actuator (Unit 2)

• ' Replace plant monitoring system computer circuit board (Unit 2) l

• Replace saltwater coo!ing Pump 3MP114 seal water flow indicator valve manifold i

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Repair control room emergency vent supply Damper 2/3FV9742 (Units 2 and 3)

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• Perform field change notice for saltwater from Heat Exchanger 2E002

. Valve 2HV6495 (Unit 2) l

• Perform preventive maintenance for saltwater cooling Pump 3P113 feeder

, breaker (Unit 3)

I Observations and Findinas

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The inspectors found the work performed under those activities to be thorough. All work 1 observed was performed with the work package present and in active use.' Technicians were knowledgeable and professional. The inspectors frequently observed supervisors and system engineers monitoring job progress, and quality control personnel were present whenever required by procedure. When applicable, appropriate radiation

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controls were in plac I

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Jn addition, see the specific discussions of maintenance observed under Section M1.3,

' belo ' M1.2. General CommenP on Surveillance Activities

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- Insoection Scope (61,726)

' The inspectors observed all or portions of the following surveillance activities:

• . Component cooling water Pump 2P024. safe shutdown test (Unit 2)

• - Core operating limits supervisory system operability surveillance (Unit 2)

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Monthly inservice test of auxiliary feedwater Pump 2P140 (Unit 2)

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Quarterly valve test of norrnal heating, ventilation, and air conditioning (HVAC)

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and radiation monitors (Units 2 and 3) )

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EDG 3G002 monthly surveillance (Unit 2)

Verify diesel-driven fire pump weekly autostart (Units 2 and 3)

Component cooling water makeup Pump 2MP1019 inservice test (Unit 2) Observations and Findinas

I The inspectors found all surveillances performed under these activities to be thoroug '

All surveillances observed were performed with the work package present and in active use. Technicians were knowledgeable and professional. The inspectors frequently l observed supervisors and system engineers monitoring job progress, and quality control

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personnel were present whenever required by procedure. When applicable, appropriate j radiation controls were in plac !

M1.3 Control Room Emercency Air Cleanuo System (CREACUS) Damoer Maintenance -

Units 2 and 3 q l Inspection Scope (62707)  !

On July 22,1999, the inspectors observed HVAC technicians performing preventive maintenance on safety-related CREACUS dampers. The inspectors reviewed Maintenance Order (MO) 99050855 and WAR C-9901258; Procedures SO23 3-2.27,

" Control Room And Emergency Ventilation System," Temporary Change Notice 9-1; SO23-1-8.29," Control Room Emergency Air Cleanup System (CREACUS) Boundary Door inspection," Revision 6; SO23-1-8.45, "CREACUS - Control Room Boundary Integrity inspection," Revision 4; and SO123-I-1.7,' Maintenance Order Preparation and Processing," Temporary Change Notice 6-2. The inspectors also reviewed portions of LER 362/1998-024-00 and a letter from the licensee to the NRC dated August 13,1999,

" Response to Request for AdditionalInformation Regarding Proposed Technical Specification Change Number 485," and interviewed Engineering, Maintenance, and Operations personne Observations and Findinas WAR C-9901258 directed that five Train B CREACUS dampers be maintained and inspected. Each of these Train B dampers is located in series with a separate Train A damper. Since the associated Train A dampers were all shut, with electrical power removed, both Trains of CREACUS were considered operable during the maintenance.

l Two teams of HVAC technicians performed the maintenance. One team worked L Damper 2/3HV9711. A second team worked Dampers 2/3HV9703,2/3HV9757, 2/3HV9758, and 2/3HV9779. The maintenance generally consisted of removing access

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panels, removing the damper actuator air supply and connecting a nitrogen bottle to the damper actuator, cycling and inspecting the damper, lubricating bearings and checking

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supply to the actuato ,

- In order to ensure that control room operators do not exceed dose allowances as set forth in 10 CFR Part 50, Appendix A, General Design Criterion 19, the CREACUS is designed to shift into emergency mode within 3 minutes of radiation levels exceeding allowable limits. The design assumed 1 minute for the radiation to travel to a radiation probe and 2 minutes for the radiation detector to elevate readings and for i CREACUS dampers to reposition and fans to start. The emergency mode provides at l-

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least % inch of water positive pressure in the control room envelope and exchanges at least 45 percent of control room air volume. The emergency mode is actuated by a l control room isolation signal initiated by radiation monitors, which continuously sample i

control room intake ai When access panels were removed from Dampers 2/3HV9711,2/3HV9757, and 2/3HV9779, three breaches (each one 144 square inches or greater) of the CREACUS

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boundary occurred, which exceeded the 50 square inch maximum allowable breach size

! that would allow the design positive pressure to be established. WAR C-9901258 designated Maintenance personnel as responsible for covering any breach in the event of a valid control room isolation signal actuation, and MO 99050855 directed that Maintenance personnel have the means to effectively re-establish the control room boundary integrity if directed by Operations. No time limits were provided in these instructions. The inspectors determined that Maintenance personnel would close the

. breaches as quickly as possible but were not aware of any specific design time limit Generally, operators believed that they had 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to cover breaches from the time they

- were discovered. The inspectors noted that Procedures SO123-11.7 and SO23-1-8.29 provided that, in the event the CREACUS boundary was found deficient, compensatory measures must be established within 1 hou l l

On August 31, the inspectors observed maintenance on a control room ventilation damper in accordance with MO 9805i032001. The evolution included blocking open a CREACUS boundary door. The inspectors discussed the open door with the Unit 2 CRS, who indicated that Maintenance personnel would remain in the area continuously and close the door as directed. The inspectors questioned the CRS on the allowed time to get the door closed. The CRS responded that the door must be closed within 1 hou The inspectors informed the CRS that the door closure time may be as low as 3 minutes, and the basis for that time ~was described in a letter from the licensee to the NRC dated August 13,1999. .The CRS was unaware of the content of the letter, as well as the potentially short time requirement to isolate the control room boundar CFR Part 50, Appendix B, Criterion Ill," Design Control," states, in part, that the design basis must be correctly translated into procedures and instructions. The control room isolation signal actuation is designed to provide % inch of water positive pressure in

- the control room boundary within 2 minutes of the control room isolation signal radiation monitors sensing elevated radiation levels. Contrary to this, WAR C-9901258 and MO 99050855 did not correctly translate this design time. Both the WAR and the MO did !

prescribe that the CREACUS breaches would be sealed; however, no specific time to l perform this restoration was prescibed. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the Enforcement Policy l

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Planning for control room boundary damper maintenance was poor. Design limits on the amount of time the control room envelope could be breached, in the event of a high

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radiation condition, were not incorporated into work plans or known by Maintenance or {

, Operations personnel involved. ' Personnel generally thought that they had 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to

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restore the system integrity, whereas the design assumed only 2 minutes for system

. restoration and actuation after radiation reached the sensors. This was a violation of 10 CFR Part 50, Appendix B, Criterion lil, for failing to translate system design requirements into the work controlinstructions and procedures. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This violation was in the licensee's corrective action program :

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111. Enoineerina E2, Engineering Support of Facilities and Equipment E Reactor Coolant Pumo (RCP) Oil Leakaae - Unit 2 Inspection Scoce (37551)

The inspectors reviewed the circumstances surrounding and licensee response to j decreasing lower motor oil bearing reservoir level for RCP 2P004. The inspectors i reviewed plant monitoring system data for reservoir level, performed visual inspections of the areas around RCP 2P004, observed oil additions, reviewed records of oil additions j and oil collection tank level, and participated in discussions with the NRC Office of Nuclear Reactor Regulation and licensee Station Technical personne Observations and Findinaa

~ Since Unit 2 startup from refueling in February 1999, Station Technical personnel had observed decreasing level in the RCP 2P004 lower motor bearing oil reservoir. This level is indicated on the plant monitoring system. Reservoir capacity is approximately 26 gallons. Maintenance personnel had previously installed a hopper inside containment

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to facilitate adding oil to this reservoir with the unit in Mode 1, as documented in NRC Inspection Report 50-361; 362/99-06, Section E2.1. Because of the decreasing oil level, ;

. personnel periodically entered containment and added oil. Since the Unit 2 startup, l between 3 and 4.5 gallons of oil had been added every 2 to 2% weeks.

L The oil collection system for RCP 2P004 directs oil to an oil collection tank. Maintenance ;

personnel placed the normally isolated sight glass in service on July 27,1999. The sight g! ass ' indicated approximately 1% inches in the lower sight glass. Each inch of sight

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l . glass level corresponds to approximately 5 gallons of oil; the capacity of the tank from below the top of the lower tap to that portion of the tank above the level that was present (

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I at the beginning of unit startup was approximately 6 gallons of oil. Consequently, for the l 27.5 gallons of oil that had been added prior to July 27, approximately 14 gallons were not indicated in the oil collection system tank. The licensee postulated that the leakage ,

was coming from a flange in the oil system that had been disconnected and reconnected )

during the refueling outage. The license planned on monitoring sight glass level periodically, as more oil was added, to confirm the level increased in proportion to oil added, using the 1%-inch level recorded on July 27 as a bench mark. The unaccounted for 14 gallons was not readily explainable. However, the licensee postulated that either the sight glass provided erroneous level indication or that oil had collected in the oil collection system pipin A level spike occurred on August 13 several hours after oil had been added. Level increased to 90 percent, then decreased to approximately 60 percent. The licensee postulated that during this oil addition the reservoir had been overfilled, which caused the j spike in indicated level. During such an occurrence, the oil would overflow the reservoir, '

come in contact with the spinning motor shaft, and be flung out from the shaft until the excess oil was removed. The inspectors observed that the amount of oil added on August 13 was consistent with previous oil additions that started with the same initial level. However, overfilling only occurred on two rrevious occasion The inspectors and an engineer visually inspected the areas below and adjacent to RCP 2P004 on July 27 and August 31,1999. Because of high area radiation levels, the ,

inspectors were not able to see all areas, including the suspected leaking flange or other 4 active oil leaks. The inspectors observed standing oil puddled on the pump horizontal lagging guard and on the cement floor beneath the pump, oil covering a manually-operated component cooling water valve, and darkened oil that appeared burnt caked on the entire top of the seal package and nuts and studs. No oil mist in the atmosphere or abnormal smells were noted. The location of the oil was consistent with oil being flung from the rotating shaft. On August 31 the inspectors estimated that the amount of oil in these locations was approximately M - 1 gallon, not including oil that was )

caked on the seal package or not clearly puddle J l

I The inspectors considered that the visible oil was below the safe fire loading as assumed in the fire hazards analysis. The lagging around the pump and on reactor coolant system piping below the pump is composed of a metallic lattice that contains no fibrous materia The RCP oilis a synthetic Mobil SHC 626, which has a flash point of 440 F, and an auto-ignition temperature of 720*F. Reactor coolant system hot-leg piping is l approximately 610*F, which is below the auto-ignition temperature of the oil. The RCP is located beneath thermal fire detectors and a dedicated sprinkler system. In a letter from the licensee to the NRC dated October 28,1996, the licensee performed an RCP oil collection fire hazards analysis. The licensee concluded that a fire in this area would not prevent safe shutdown and cooldown of the reacto CFR Part 50, Appendix R, Section 111.0,"Oi! Collection System for Reactor Coolant Pump," states, in part, that the RCP shall be equipped with an oil collection system capable of collecting lube oil from all potential pressurized and unpressurized leakage sites in the RCP lube oil systems, including tube oil reservoirs. Contrary to this, on August 31,1999, standing oil from a leakage site was present outside of the Unit 2 RCP 2P004 oil collection system. The failure of the oil collection system to capture this r

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accounted for. An unresolved item was opened to monitor licensee resolution of th ;

unaccounted for oil and to determine the safety significance of the oil collection system ;

deficiency (URI 361/99012-03).

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- Conclusions  !

The Unit 2 RCP 2P004 oil collection system design was inadequate. Oilleaking from the i spinning motor shaft during Mode 1 operations was not captured by the oil collection i system. Oil had puddled on the pump and the floor below and had caked or burnt on the seal package. This was not in compliance with 10 CFR Part 50, Appendix R, regarding the capability of the oil collection system to collect this oil. An unresolved item was opened to determine the scope and the significance of the noncompliance. The licensee had not yet accounted for all of the oil losse l

E8 Miscellaneous Engineering issues (37551,92700,92903)

E (Closed) Unresolved item 361: 362/99004-02: containment emergency sump design requirements and corrective action InsDection Scope Tnis unresolved item was opened to evaluate the containment emergency sump design requirements in reference to a %-inch gap at the top of the fine mesh screen and small l gaps on the top plate of the sump and to evaluate licensee corrective actions. The inspectors reviewed AR 990201682; Updated Final Safety Analysis Report (UFSAR)

Section 6.2; Regulatory Guide 1.82, " Sump for Emergency Core Cooling and Containment Spray Systems"; NRC Inspection Reports 50-361; 362/93-38 and 50-361; 362/94-02; and LER 361; 362/1993-010-0 Observations and Findinas On February 19,1999, the inspectors observed deilciencies in both trains of the Unit 2

- containment emergency sumps. The inspectors observed two gaps on the top plate, with 4 the largest being approximately % inch by 3 inches. In addition, the inspectors observed i L a %-inch gap at the top of the sump where the fine mesh screen attached to the sum The licensee initiated AR 9909.01682 to evaluate the condition. The licensee repaired the top plate but did not reprJr the %-inch gap above the fine mesh side screens in the sump. An operability assessment demonr,trated that the sumps remained operable with the %-inch gap and planned to elimincte the %-inch gap in a future outag On March 30 the inspectors performed a walkdown of the Unit 3 containment emergency sumps and observed that the sumps did not have the similar gaps in the top plate as Unit 2. However, both trains of sumps had the similar %-inch gap at the top of the sump where the fine mesh screen attached to the sump. The licensee repaired the Unit 3

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-10-sump by closing the %-inch gap prior to completing the refueling outage and determined

' that the sumps had remained operable while degrade The licensee had previously taken corrective action to close gaps in the cover plate that !

had been identified in 1993 (NRC Inspection Report 50-361; 362/93-38 and I LER 361; 362/1993-010-00). The corrective actions from that occurrence had not l completely resolved the deficiencies in the Unit 2 cover plate and were therefore inadequate, in addition, the licensee did not identify the %-inch gap over the top of the

fine mesh scree CFR Part 50, Appendix B, Criterion XVI, states, in part, that measures shall be established to assure that conditions adverse to quality, such as deficiencies, are promptly identified and corrected. The failure of the licensee to promptly identify and correct the containment emergency sump cover plate deficiencies in 1993 was a violation

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of 10 CFR Part 50, Appendix B, Criterion XVI. This Severity Level IV violation is being

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treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy (NCV 361; 362/99012-04). This violation was in the licensee's corrective action program as AR 99020168 j The inspectors reviewed UFSAR Section 6.2.2.1.2.5 and Figure 6.2-52, which described the containment emergency sumps. The UFSAR described the sump as having a mesh )

size of 0.090 inches, based on the minimum core channel opening through which the safety injection system must pump. In addition, the UFSAR, Appendix 3A, Section 3A.1.82, indicated that the sump design is consistent with the recommendations of Regulatory Guide 1.82, Revision 0, except for the differences indicated in Table 3A- Regulatory Guide 1.82 described the sump as being protected by a fine inner scree Regulatory Guide 1.82 further specified that the size of the openings in the fine screen should be based on the minimum restriction in systems served by the sump; UFSAR Table 3A-2 did not describe any deviations from Regulatory Guide 1.82 relative to that l aspect of the configuratio '

UFSAR Section 6.2.2.1.2.5 did not describe the %-inch gap over the top of the fine mesh i screen. Figure 6.2-52, Sheet 3 of 4, showed a %-inch gap over the fine screen, but the detail of figure was not clear enough to indicate that this resulted in bypass flow around the fine mesh screens. The inspectors concluded that the intent of the sump design required that all sump openings be smaller than the minimum opening through which containment emergency sump water was pumped; therefore, the licensee was required to reduce the openings to less than 0.090 inche The licensee repaired the Unit 3 sumps during the recent refueling outage and planned to repair the %-inch gap to the Unit 2 sump during the next refueling outage, scheduled to start in the fall of 2000, in addition, the licensee revised Procedure SO23-I-2.53,

" Containment Emergency Sump Inspection Surveillance," to add acceptance criteria to check that the maximum gap size of the containment emergency sump is less than 0.090 inche I

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A violation of 10 CFR Part 50, Appendix B, Criterion XVI, resulted from a failure of the licensee to promptly identify and repair all gaps in containment emergency sump cover plates. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. In 1993 the licensee repaired some of the gaps but failed to correct two additional gaps. This violation was in the licensee's corrective action program as AR 990201682. Additionally, the inspectors determined that newly-discovered gaps between the side screens and the sump cover plate were also inconsistent with design commitments for the sumps and were required to be correcte The licensee determined that the sumps were operable in their degraded conditio IV. Plant Support R1 Radiological Protection and Chemistry Controls R Containment Entry - Unit 2 (71750)

On July 27 and August 31,1999, the inspectors and licensee personnel entered Unit 2 containment in order to assess RCP 2P004, as described in Section E2.1 of this repor The Unit 2 reactor was at full power, and areas inside the biological shield adjacent to the RCP were entered. These areas were high radiation areas, and the containment was an airborne radiation area. The prejob briefing conducted by Health Physics personnel prior to the containment entries was thorough. Stay times and back-out criteria were clearly identified. Individual movements and efficient task accomplishment were emphasized so as to provide for as low a collective radiation dose as reasonable. While in containment, Health Physics technicians measured both area radiation and airborne radiation levels to confirm acceptable dose rates and to facilitate future entries. The inspectors found that licensee attention to maintaining dose as low as reasonably achievable was goo R2 Status of Radiological Protection and Chemistry Facilities and Equipment R2.1 Housekeepina - Units 2 and 3 (71750)

Plant housekeeping was generally acceptable with the following exceptions. The inspectors identified two pairs of unattended wire cutters laying on top of high pressure safety injection to reactor coolant system Loop 1 A Flow Transmitter 2FT0311-2. Also, the inspectors identified an unrestrained chair in the immediate vicinity of containment purge stack Radiation Monitor 2RY7828. The licensee removed the unrestrained and unattended items and initiated AR 990800755 to document and evaluate the occurrences.

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12-V. Manaaement Meetinas

. X1' Exit Muting Summary

The inspectors presented the inspection results to members of licensee management at the exit

' meeting on September 21,1999. The licensee acknowledged the findings presente The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. 'No proprietary information was identifie I

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i ATTACHMENT SUPPLEMENTAL INFORMATION PARTIAL LIST OF PERSONS CONTACTED l

,' Licenseg . I D. Brieg, Manager, Station Technical l J. Fee, Manager, Maintenance-J. Hirsch, Manager, Chemistry. .

R. Krieger, Vice President, Nuclear Generation '

J. Madigan, Manager, Health Physics -

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D. Nunn, Vice President, Engineering and Technical Services ,

~ A Scherer Manager Nuclear Regulatory Affairs

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- K. Slagle, Manager, Nuclear Oversight

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T. Vogt, Units 2 and 3 P' ant Superintendent, Operations R. Waldo, Manager, Operations NRC

' E. Connell, Plant Systems Branch, NRR I

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L. Raghavan, Project Manager, NRR -  !

l INSPECTION PROCEDURES USED I IP 37551: ' Onsite Engineering j

= IP 61726: Surveillance Observations IP 62707: Maintenance Observations i IP 71707: Plant Operations IP 71750: Plant Support Activities  ;

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- IP 92700: On Site LER Review-IP 92903: Followup - Engineering ITEMS OPENED AND CLOSED

- Ocened  ;

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362/99012-01 eel failure to shut unit down with inoperable EDG (EA 99-242) l (Section 08.1) ]

361/99012-03 URI RCP oil collection system noncornpliance (Section E2.1)

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' ' - Opened and Closed-l ; 362/99012-02- NCV design element not considered during maintenance activity (Section M1.3) '

361; 362/99012-04 NCV failure to promptly identify and correct containment emergency sump cover plate deficiencies (Section E8.1)

l' ' Clos 9d 362/1999-006-00 LER Technical Specification 3.0.3 entry caused by inoperable EDG (Section 08.1)

361; 362/99004-02 ' URI containment emergency sump design requirements and corrective actions (Section E8.1)

LIST OF ACRONYMS USED j l

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AR action request ,

[ AVR automatic voltage regulator l

'CFR Code of Federal Regulations CREACUS control room emergency air clearup system CRS ' control room supentisor EDG emergency diesel generator HVAC : heating, ventilation, and air conditioning LCOAR limiting condition for operation action requirements

'LER

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licensee event report MO maintenance order

! NC noncited violation NRC' Nuclear Regulatory Commission

!- .RCP reactor coolant pump .

UFSAR Updated Final Safety Analysis Report WAR work authorization record l

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