IR 05000206/1985014

Insp Repts 50-206/85-14,50-361/85-13 & 50-362/85-12 on 850323-0521.Violations Noted:Failure to Perform Tech Spec Surveillance on Auxiliary Feedwater Sys & Battery Discharge Test & Failure to Follow Approved Station Procedures

ML13323A997
Person / Time
Site:	San Onofre
Issue date:	07/30/1985
From:	Dangelo A, Huey F, Johnson P, Stewart J, Tatum J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V)
To:
Shared Package
ML13323A993	List: IR 05000206/1985014 IR 05000323/2005021 ML13323A992 ML13323A994
References
50-206-85-14, 50-361-85-13, 50-362-85-12, NUDOCS 8508200672
Download: ML13323A997 (24)

Text

U.S. NUCLEAR REGULATORY COMMISSION

REGION V

Report No /85-1.4, 50-361/85-13, 50-362/85-12 Docket No, 50-361,;50-362 License No DPR-13, NPF-10, NPF-15 Licensee:

Southern California Edison Company P. 0. Box 800, 2244 Walnut Grove Avenue Rosemead, California 92770 Facility Name:

San On6fre Units 1, 2 and 3 Inspection at:

San Onofre, San Clemente, California Inspection conducted: March 23 through May 21, 1985 Inspectors:

T/ 30(65 F. R. Huey, Senit6r Resident Inspector Date Signed Units 1, 2 and 3"'

P. Stewart Resident Inspector Date Signed

[A_

__

_

_

730 D'

-AngeloResident Aspector Date Signed J. E. Tatum, Resident Inspector Date Signed Approved By:.

730

H. Johnson, Chief Date Signed Reactor Procts Secfion 3 Summary:

Inspection on March 23 through May 17,1985 (Report Nos. 50-206/85-14, 50-361/85-13, 50-362/85-12)

Areas Inspected:

Routine,resident inspection of Units 1, 2 and 3 Operations Program including the following areas:, operational safety verification, evaluatiod of plant trips and events, monthly surveillance activities, monthly maintenance activities, refueling activities, independent.inspection, licensee event.report review and follow-up of previously identified items. This inspection involved 329 inspection hours on Unit 1, 412 inspection hours on Unit 2 and 300.inspection hours on Unit 3 for a total of 1041 inspection hours by 4 NRC inspector Results: Of the.eight areas examined, three apparent violations were identified:

(1) and (2) Failure to comply with Technical Specification surveillance requirements; and (3). Failure to follow approved station procedures. One apparent deviation was also identified: Failure to meet a Final Safety Analysis Report commitment to maintain'shutdown cooling system electrical alignmen PDR ADOCK 05000206 Q_

PDR

DETAILS 1. Persons Contacted Southern California Edison Company

• H. Ray, Vice President, Site Manager 7,#*J. Haynes, Station Manager

1. • Krieger, Deputy Station Manager

• D. Schone, Quality Assurance Manager D. Stonecipher, Quality Control Manager

• G. Morgan, Operations Manager

• D. Shull, Maintenance Manager J. Reilly, Technical Manager P. Knapp, Health Physics Manager

1. • P. Croy, Compliance Manager J. Wambold,*Training Manager D. Peacor,Emergency Preparedness Manager P. Eller, Security Manager

• W. Marsh, Operations Superintendent, Units 2/3

• J. Reeder, Operations Superintendent, Unit 1

• V. Fisher., Assistant Operations Superintendent, Units 2/3

• B. Joyce, Maintenance Manager, Units 2/3

.

H. Merten, Maintenance Manager, Unit 1

• R. Santosuosso, Instrument and Control Supervisor

• T. Mackey, Compliance Supervisor G. Gibson, Compliance Supervisor

• C. Kergis, Compliance Engineer

• King, Quality Assurance Supervisor

• G. Noel, Training Supervisor

• K. Johnson, Station Technical Supervising Engineer

• R. Neal, Station Technical Supervising Engineer

• J. Pfefferle, Compliance Enginee *G. Legner, Compliance Engineer San Diego Gas & Electric Company

• R. Erickson, San Diego Gas and Electric The.inspectors also contacted other Licensee employees during the course of the inspection, including operationsshift superintendents, control room supervisors, control room operators, QA and QC engineers, compliance engineers, maintenance craftsmen, and health physics engineers and

.technician *Denotes those attending the exit meeting on May 9, 1985.

1. Denotes those attending the exit meeting on May 21, 1985.

2. Operational Safety Verification Plant Tours'

The inspectors performed several plant tours and verified the operability of selected emergency systems, reviewed the Tag Out Log and verified proper return'to service of affected components..

.Particular attention was,given to examination for potential fire hazards,.fluid leaks, excessive vibration and verification that maintenance requests had been initiated for equipment in need of

.maintenanc During a tour of Unit'3, the inspector questioned the environmental qualification of cdntainment.radiation monitors, RE 7820-1 and RE 7820-2. The junction box at each detector has a gasketed enclosure, butthe sides of the boxes have openings in them that are open to the contaithment atmosphere.- Review of the environmental qualification records for the detectors and terminations.showed that the detectors and their associated terminations are environmentally qualified.. No other findings were identifie Unit 2 Initial Criticality After Refueling On April 12, 1985, the inspector observed control room operations to take Unit 2 Reactor critical following the first refueling outag The operation was conducted in accordance with Operating Instruction S023-5-1.3.1, "Plant Startup From Hot Standby to Minimum Load", and criticality was achieved without complications. No violations or deviations were identifie.

Evaluation of Plant Trips and Events Unit 1 (1) Failure of the West Feed Water Pump/Safety Injection Pump On May 1, 1985, at approximately 1300 hours0.015 days <br />0.361 hours <br />0.00215 weeks <br />4.9465e-4 months <br />, with.the Unit at maximum output (94% reactor powei), an equipment bearing high temperature alarm was received in the control roo Investigation by the licensee revealed that a deflection plate attached to.the rotating element of the west feedwater pump had broken and that the electric motor inboard bearing.and feedwater pump inboard bearing were warm to the touc A.load-reduction for the Unit was commenced within 26 minutes after discovery of the bearing high temperature alarm. During the load reduction, plant operators observed that the feedwater pump inboard bearing temperatures were lowering in temperature as load was decreased on the Unit. During -this period, pump discharge pressure and flow through the feedwater pump appeared to be normal from observed indications in the control roo The west feedwater pump was stopped by the plant operators with reactor power less than 65% at approximately 55 minutes after

receiving the bearing high temperature alarm. The.Unit entered Mode 3 at approximately 1843 hours0.0213 days <br />0.512 hours <br />0.00305 weeks <br />7.012615e-4 months <br /> that da Subsequent investigation by the licensee revealed that the rotating element had cracked at the outboard end of the element, where the thrust plate attaches to the rotating element. This crack and subsequent failure of the element had caused the thrust bearing assembly of the pump to fail. As a result, the element changed positi6n axially within the pump casing until other machined areas of the element contacted an obstruction within the pump preventing further axial movemen In addition, fracture of the tail-end of the rotating element caused the shaft driven lubricating oil pump to stop. This

.,resulted in its function being picked up by the electric driven auxiliary oil pum During the period between the receipt of the high bearing temperature alarm and the Unit entering Mode 3, the west feedwater pump was believed by the licensee to have remained operable. This assumption was based on indicated parameters in the control room of feedwater flow and pressure, and also the fact that bearing temperature had started to decrease with load reduction of the Uni The licensee took action to have metallurgical examinations of the rotating'pump element performed in order to determine the cause of failure. Preliminary results indicated that failure appears to be caused by high cycle fatigue of the shaft. This mode of failure was believed to require several years of operation of the pump before the number of cycles experienced by the pump would be of concern. Based on the fact that both the east and west feedwater pumps contain new rotating elements, the number of cycles experienced by these two shafts to date was believed by the licensee to be extremely low, and therefore, failure of either shaft would not be expecte The, licensee is continuing their investigation and will provide a final report -dese ibing the cause of failure.and possible corrective acion At present both feedwater pumps are performing satisfactorily and no f ilure is expected by the license Unit:2 Unit 2 synchronized the main-generator to the grid on April 17, 1985, completing a 179 day refueling and modification outag During this inspectidni report period, Unit 2 experienced the following significant trips and transients:

(1) Inadvertent Safety Injection Actuation Signal (SIAS) on March 30, 198 On March 30, 1985, atl1115, with the plant in Mode 4 (approximately 290 0F and 350 psig), an inadvertent safety injection actuation signal(SIAS) and containment cooling actuation signal.(,CCAS) wlere,received as a result of an error y

an instrumentand control technician performing a routine monthlyplantprot'ction 'system (PPS) surveillanc The licensee'reset the inadvertent SIAS and stopped all applicable safety injection components at 113 _4~e

,onc An interview with the technician who made the error determined that the technician violated the surveillance procedure in that he improperly took other PPS channels out of by-pass. In addition to the technician's 'error, a procedure.inadequacy also contributed' to the eventAnAthat the procedure, S023-II-1.1,

'Reactor,.PPS Channel'Functional Test" could not be performed with th'e plant at 350 psig. The procedure was written for normaf opdrating cbnditions in Modes 1,2 or The inspector reviewed the licensee maintenance investigation report and noted that the licensee"s corrective actions included the following:.

o Revise the,-"procedure so that it is applicable for all plant'conditions for which the procedure is to be performe Review all other instrument and control procedures for the need for similar revisio o Ensure that instrument and control technicians follow th procedur (2) Reactor Trip on April 16, 198 On April 16, 1985, at 0832, while in Mode 2 at approximately 2%

power, the reactor tripped due to a low DNBR auxiliary trip signal from the Core Protection Calculators (CPC).

The low DNBR auxiliary trip occurred due to *a temperature difference between the Reactor Coolant System (RCS) cold leg piping loops

- of the two steam generators. -The.temperature difference in the two RCS cold leg piping loops existed because the licensee was maintaining reactor power at approximately~one to.two percent power with one of the two Main Steam Isolation Valves (MSIVs),

2HV-8204 closed and the other MSIV, 2HV-8205 open. The difference in the-steaming rate between the two steam generators resulted in cooling down one pair of cold legs more than the other resulting in the CPC auxiliary trip which is designed to trip the reactor in the-event one of the two MSIV fails shut while at power..MSIV 2HV-8204 had been shut-to repair.a hydraulic oil lea (3) -Reactor Trip on April 19, 1985

.

On April 19, 1985, at 1222, while at approximately'50% power, the reactor tripped due to a low.DNBR auxiliary tiip signal from the CPC. The auxiliary.trip signal was due to a difference in temperature between the two RCS 'cold leg piping loops. This temperature difference occurred as a result of MSIV No. 2HV-8205 going shut, which resulted in reducing heat removal from steam generator E-088. The MSIV had shut due to a failed nitrogen regulator which bled nitrogen pressure.from the control valve, causing the control valve to fail ope (4) Shutdown to Perform Maintenance on MSIV on April 25, 1985 On April 25, 1985 while operating at approximately 50% power, at 0001 (2nd fuel cycle physics testing.in progress) the licensee initiated a planned shutdown to perform maintenance on an MSIV and other plant equipment. Unit 2 turbine'generator was removed from the grid at 0235 and entered Mode 2 at 030 The licensee performed repairs on the MSIV hydraulic control system (discussed under monthly 'maintenance activities, paragraph 5 in this report),: and performed turbine generator v balancing duing the outa

.

ReactoriTrip 9n May,18, -85 On May 18, 1985,.at 0430, while at 100% power, the reactor t*ipped.; on Loiw DNBR from' the core protection calculator (CPC)

as ar6sult: of-g.centrol.. group 6 control element assemblies.(CEA)

.,dropping into the core,.

Coitrol group 6 CEA's were deenI gizedais.-result. of a-loose grounding connector associated wit the power'sipply for subgroup * As a result of "'-the "trip, an emergency feedwater actuation signal was also

,Ireceived.- Thq pr blem 'was repaired and the unit was returned-ao. service at 2210 on May 19, 198 Unit 3 (1) Reactor 'Trip on March 29, 1985 On March 29, 1985, at 2108, while at 96% power, the reacto tripped,,due to 'failed electronic components in two separate steam generator low flow channels of the Plant Protective System (PPS). One channel had.a' failed component in the'matrix circuit, and the other channel had a failed component in the variable setpoint circuit. Repairs were made, and the.Unit was returned to 100% at 2230, March 31, 198 (2) Reactor Trip on April 4, 198 On April 4, 1985, at 0452, while at 100% power, the.reactor tripped on loss of load due to a fault in the Turbine Governor System. Subsequent investigation was inconclusive' and the licensee considered thatthe fault was spuriou The unit was returned to 100% power at 2030 on April 7, 198 No abnormal

Ar

)

.6 conditions were discovered which could have caused the turbine and reactor trip were discovere (3) Reactor Trip on April 8', 1985 On April 8, 1985, at 2225, while at 100% power, the reactor tripped on loss of load due to a.broken sensing line to the hydrogen gas seal oil regulator on the main generato The'

subsequent loss of seal oil pressure resulted in a loss of hydrogen from the generator into the #9bearing house which resulted in a hydrogen ignition in the bearing house. The fire was quickly extinguished by the installed.CO2 fire suppression system. Repairs were made and the unit was returned to 100%

power at 2245 on April 10, 198 (4) Reductions in Power' due to Turbine Control Valve Problems Reactor power was reduced from 100% to 92% at 1300 on April 16, 1985, due to Main Turbine Governor Control Valve, 3UV-2200F, shutting.. The valve was repaired and the unit was returned to 100%'power at 0615 on April 17, 198 Reactor power was reduced from 100% to 97% at 1410 on April 17, 1985, due to a high-motor current condition on'Main Turbine Governor Control Valve 3UV-220F. The condition was corrected and the unit was returned to 100% power at 2115on April 17, 198 (5) Reductions in.Power to Improve Condenser Seawater Flow Reactor power was reduced from 100% to 85% on March25,Mchm 28, and May6, 1985, to improve se watet flow through,

ma condenser.,With reactor power. reduced, each'sea' water, circulating pump was alternately stopped and restarted to allow any debris on the condenser tube sheet to settl (6) Reactor Shutdown on April'27, 1985 The unit was, taken off line at' 1407 on April 27, 1985 to repair packing leakage on the Reactor Coolant System letdown isolation valve to the Chemical and Volume Control System,.

3TV-0221. The packing.leak was noted approximately a month earlier and had been gradually-,increasing..The leak had inc-reased to approximately 2.5 gallons per minute prior to.,the'

shutdown. Valye 3TV-0221 was repacke'd and the unit was returned to 100% power on May 1, 198 No' violations or 'deviations were identifie.

Monthly Surveillance Activities During this inspection period, the inspector observed portions of the following surveillance activities

'

7 Unit 1_

Prior to the return to service of Uniti1, the-licensee had replaced the Unit 1 #1 DC battery. This replacement included battery cells, racks, and intermediate jumper.cables. Installation activities concerning this battery had been previously reviewed by the NRC and included in IE Inspection Repokrt No.. 50-206/84-1 The curreit inspection examined the maintenance and'surveillance programs 'in place at San On6fre for battery maintenance on Unit The followingprocedures were reviewed:

S01-1-2.5, Batteries - WeeklyInspection of Batteries 301-,I2-.6, Batteries -'Quarterly Inspection of. Batteries SOI-I-2.7 Batter-7.Refueling Interval Battery and Battery Charger Surveillances The procedures "reviewed met the requirements of the Unit 1 Technical Specifications for station battery surveillances and the manufactarer's technical' guidance on the batterie The start-up surveillance tests conducted on the No. 1 DC battery were reviewed for compliance with -technical specification requirements.. The recorded test data verified that all discharge surveillance tests were performed in the required manner with satisfactory result All reviewed data 'such as discharge capacity, individual cell voltage and cell specific gravities were within technical specification requirement Unit 2 S023-V-12.1.12, "Surveillance Requirement Fixed Incore System Channel Calibration (eighteen.month Interval)".

No violations or deviations were identifie.

Monthly Maintenance Activities -

Main Steam Isolation Valves During Unit 2 return to service following the.refueling outage, the inspector observed maintenance, operation and surveillance testing of the main steam isolation valves (MSIV's) 2HV-8204.and 2HV-820 Each MSIV has its own hydraulic skid which supplies the motive force to open the valve, and each MSIV has two Marotta valves arranged in parallel which dump the hydraulic fluid and allow the MSIV to close upon receipt of a closing signal. The Marotta valves are-powered from separate power supplies, and each valve is sized so that if one valve fails to open, the other Marotta valve has sufficient capacity to dump the hydraulic fluid from the MSIV actuator such that the MSIV will close within the required 5 second time period. Based on document review, observations and; discussions with the licensee, the inspector made the following observations:

On April 7, 1985, MSIV 2HV-8204 was taken out of service and the Train B Marotta valve was replaced. Valve 2HV-8204 was maintained closed during this maintenance activity. Satisfactory surveillance testing of the valve to demonstrate proper closing time did not take place until April

.15, 1985. An entry in the Unit 2 Control Operator's log on April 9, 1985,.-states that valve 2HV-8204 stroke time was 5.16 seconds. A Shift Superintendent's Accelerated Maintenance.was declared on April 11, 1985, to adjust the valve packing. Valve packing was adjusted on April-12, 1985, and a Control Operator's log entry on April 12, 1985, stated that valve.2HV-8204 failed closing'time bygreater than 1 second. A surveillance performed on April 14, 1985, resulted in a stroke time of 10 seconds for valve 2HV-8204. The first satisfactory-surveillance was performed on April 15, 1985, which yielded a stroke time of 4.8-second Prior to this, the most recent satisfactory surveillance on this valve, demonstrating stroke.time, was conducted on March 9, 1985, and a stroke time of 3.2 seconds was obtained. During the period from April 9 to April 15, valve 2HV-8204 was open for a-total cumulative time of 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> and 21 minutes with the unit initially in Mode 3 and finally in Mode for post refueling start-up testing (the unit was in Mode 2 or 3 throughout this period).

As documented in the Control Operator's Log, the longest continuous time period that the valve remained open was 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.and 10 minutes, during which time the unit was in Mode 3. These time intervals are illustrated in Table 1 for valve 2HV-8204. The valve was kept closed during mode change On April 10, 1985, MSIV 2HV-8205 was tested pursuant to paragraph 4. of the Technical Specifications. The Train "B" test button was pushed in the Control Room, which should.have caused valve 2HV-8205 to close 10%,

and then cycle back to the 100% open position. The Train "B" Marotta valve did not open and valve -2HV-8205 did not cycle.. The Train "A" test button was subsequently pushed, the Train "A" Marotta valve opened and the valve cycled as expected. The operators involved :assumed that only the Train "B" test circuit was faulty, and did-not verify that the. Train

"B",Marotta valve was functioning.properly even though work documented on Mainteiance Order 85040328002 indicates that on April 6 both Marotta valves for 2HV-8204 were stuck,

- along with the Marotta valve limit switche On April 1,the 90% limit switch for-the Train "B" test circuit was rep1acedwhile vat e.2HV-8205 was closed. Subsequent attempts to: open valve 2HV-8205 were unsuccessful because the Marotta

,valves were not-furictioning properly. Both Marotta valves were replaced on April 12_ to correct this'prbblem. At 0400 on April 14, a surveillance test 'was performed tb, demonstrate proper closing time of valve 2KV-820 The resilts were unsatisfactory inhthat the stroke time was 9.8 second Later; that day, atel515, another surveillance was accomplished which demonstiated-a satisfact ry lcIdoslng time of 3.6 second Prior to this, the most.-recent satisfa tory-surveillance on this valve demonstrating

.,,stroke -time was conducted on March 25, '1985, anda stroke time of seconds was obtaied.

During the period-from April 10 to April 14, valve 2HV-8205 was open for a tota'l-cumulative time of' 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> and-19 minutes with the unit initially in Mode 3 and finally in Mode 2 for start-up testing. The longest continuous time period,that the valve remained open was 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> and 20 minutes, during which time the unit was in Mode These time intervals are illustrated in Table 2 for valve 2HV-8205. The valve was kept closed during mode changes. Table.3 illustrates time -

i ntervals during which both.MSIV's were open simultaneously for the period from. April 9 to April 15, 198 TABLE 1 PERIODSDURING WHICH VALVE 8204 WAS OPE,DATE FROM TO'

TOTAL TIME MODE HR MIN /9/85 1459.

1655

56

. 9/85 1715 1840 j

3 4/f0/85 0205 0249

44

4/10Q85-0950'

1500.5 K

3 4 /85 1630 1710'

o

411/85 1930 013

0

4/12/85 1120 1201

.41

.4/14/85 0315

-

0340

25

4/14/85 1405

?

??2 4/15/85 0610 0630

20

13

TABLE 2 PERIODS DURING WHICH VALVE 8205 WAS OPEN DATE FROM TO TOTAL TIME MODE HR MIN /12/85 1110 1201

51

4/14/85 0250 0330

.40

4/14/85 0610'

0635

25

4/14/85 1342 151 TABLE 3 PERIODS DURING WHICH BOTH 8204 & 8205 WERE OPEN SIMULTANEOUSLY DAT FROM TO TOTAL TIME MODE HRS. MIN.

4/12/85-1120 1201

41

4/14/85 0315

. 0330

.

15

4/14/85 1405

??

.?

5

While conducting the MSIV maintenance activities discussed above, Unit 2 escalated from Mode 3 to Mode 2.oin two separate occasions. These mode, escalations occurred at 0325 on April 12 and at 0445 on April 14, 198 The inspector discussed the above findings with the licensee, and obtained the following additional information:

a.:

The licensee considers that, as long as the MSIVs are kept closed, the"Valves are operable in that they-are satisfying their intended safety function. The valves would only be considered inoperable during periods when they are ope The licensee provided maintenance documentation which.demonstrated that valve 2HV-8204 was not open continuously on April 10 for the 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.and 10 minutes depicted on Table.; the valve was cycled on at least two occasions to make adjustments.to the position indicating limit switches, although this was not recorded in the Control Operator's Lo The licensee does not consider that'valve 2HV-8205'was inoperable on April 10 as a result of the valve failing to exercise when the Train

"'B" test button'was pushed. *The licensee maintains that the malfunction was restricted o the test circuit only~and,-since a pro1kem was found with the 90% Limit.Switch, there 'is no reason to believe that a.problema'lso existed with the Marotta valve. The licensee aIso pointid out-thaiy each Marotta valve is sized 'to

.individually satisfy the ;MSIVR 'f 'osing time requirement of 5 seconds aitd'the Traid' "A"t,.Marotta valve was operable. The inspector cobsiders that this line of-reasoning is'inconclusive since a satisfactory surveillance test was not performed prior to replacing the Marotta valve and the manner in which the licensee performed the MSIV Iosing time surveillance does not. specifically test proper closing time for each of the two Mgrotta valve trains (e.g., closing time may not be the same for both trains)..

.

The licensee 7stated that valve 21V-8204 was not placed in'

service on 1prl10,

'195 rdr toperforming a'surveillance to demonstrate'

closing time, but that the valve was opened periodically to do maintenance and testing on'the valv The inspector noted that valve 2HV 8204 wasyiopen for a total cumulative. time of 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> and

.21 minutes, indicating that the valve was in service at least part of this tim The licensee maintains that both MSIVs were operable at 0900 on April 14, 1985 based' on locally timing the'valves. Valve.2HV-8204 closed in 3.2 seconds 'and 2HV-8205 closed in 3.5. seconds. The surveillance procedure, S02-3-3'.17, which was accomplished earlier ron April 14 had documented a closing time of approximately 10 seconds for each MSIV. 'The licensee.stated thatithe.closing time'

obtained by the surveillance:procedure is based onremote valve positioh indication in the Control Room and the uns'atisfactory stroke time for-the valves was a position indication problem onl The inspector considers that although the local measurement of valve closing-time can be a technically acceptable method 'for satisfying the operability requirement of the TechnicalSpecifications, this surveillance method should be addressed ii the procedure use The licensee's handling d control of the MSIV's during this period is considered an unresolved item (50-361/85-13-01).

6. Refueling Activities Follow-Up of Unit'2i.License Condition During this inspection period, the -inspector examined the design changes to the Qualified Safety Parameter Display System (QSPDS) on Unit '2, completed during the first refueling outage. These changes were made to satisfy the requirements of paragraph 2.C.49.0 of the Unit 2 Operating. License' dealing with NUREG 0737, "Instrumentation for Detection-of Inadequate Core Cooling."

Prior to' startup following the first refueling outage,.the licensee was directed to, complete installation of the following items:

Subcooling monitor modifications, to include the maximum unheated junction thermocouple temperature and the representative core. exit thermocouple inpu Incore detector assemblies (core exit:thermocouples and associated cabling),' to be. environmentally qualified and have seismic and.environmentally qualified Class 1E connector Qualified cables for the core exit thermocouple A safety parameter display syste The heated junction thermocouple probe and associated process instrumentatio The inspector walked down the installation to examine the accessible hardware and connections, and to'verify the environmental qualifications of the equipment. Based on this walkdown, discussions with the licensee and document review, it appeared that the Licensee had satis fied the requirements of the.Operating License, paragraph 2.C.1 Post Refueling Startup Testing During this inspection period, Unit 2 completed the refueling outage and returned to service. The inspector observed portions of the following Physics Tests and Power Ascension Tests:

S023-V-1.0.l, Criticality Following Refueling S023-V-l.0.2, Boron Endpoint Determination SO23-V-1.0.3, Isothermal Temperature Coefficient Measurement at Hot,'

Zero Power SO23-V-1.0.4; Control Element Assembly Symmetry Verification S023-V-1.0.5, Control Element Assembly Worth by Boration/Dilution S023-V-1.0.6, Control Element Assembly Worth by Exchange S023-V-1.0.7, Determination of Neutron Flux Level for Low Power Physics Testing

S023-V-1.3, Incore Detector Surveillance Testing S023-V-1.4, Radial Peaking Factors and CEA Shadowing Factor Measurements S023-V-1.9,'

Isothermal Temperature Coefficient S023-V-1.11, Doppler Power Coefficient Measurement S023-V-1.18, NSSS Calorimetric No violations or deviations were identifie.

Followup on Allegations Allegation on Unit 1"Concerning.the Installation of Hilti Concrete Expansion Anchor Bolts (ATS No. RV-83-A-36)

(1) Characterization of the Individual's Concern The allegation concerned the identification of concrete expansion anchor bolts to be used at the San Onofre sit These anchor bolts were color coded as a function of the anchor bolt length. The concern is that during the period between 1976 and 1981, when.color.4coding was used, the color coding had been performed improperly such that the color indicated on the head of the bolt would not represent the correct bolt lengt (2) Inspection Findings This.concern involved the use of mechanical expansion anchor bolts at San Onofre Unit 1. During the period between 1976 and 1981, the licensee had a system to identify mechanical concrete expansion anchor bolts lengths by color coding the threaded end of the bolt. A concerned individual believed that the color coding may have been improperly done, such that if one were to rely solely on the color coding to determine length, the color code used on a particular bolt.may indicate the incorrect bolt lengt A review of the design change packages for Unit 1 indicated that-during this period approximately 4,000 concrete expansion anchor bolts were used within Unit 1. A review was conducted by the inspector and a Quality Assurance supervisor to determine whether any nonconforming condition reports.(NCR) had been generated during this time period which identified problems with concrete expansion anchor.bolts. This review discovered more than 100 NCR's during-the time period which discussed concrete expansion anchor bolt nonconforming conditions, however, none of the NCR's identified conditions where improper bolt length or improper color coding to determine bolt length were identified. Based on a review of quality assurance documents, it did appear that QC inspectors were observing various parameters for anchor bolt installations, such as, bolt diameter, bolt spacing and bolt preload torquing. It would appear -that QC would have detected improper lengths had the incorrect bolt length been use During discussion of the anchor bolt.issue with the inspector, the licensee stated that an examination program would be:

considered to determine anchor bolt lengths of selected samples which were believed to be installed during this timeperiod. A program was initiated using ultra sonic testing (UT) of installed anchor bolts within the plant that were believed,to have been installed during the 1976 through 1981 time fram The UT testing was performed by the licensee's Quality Assurance organization utilizing qualified Level II UT inspection personnel. The sampling program involved a 1%

sample of approximately 4,000 installed concrete expansion anchor bolts within the plant. The bolts examined were

. randomly chosen throughout plant areas, and the only biasing used in the selection was to exclude expansion anchor bolt which were not installed during the time period in. question and excluding anchor bolts which were installed in high radiation areas, or where access to the expansion anchor bolts would pose a hazard to plant personnel or jeopardize sensitive equipmen During this UT inspection by the licensee, all specific parameters were recorded for each anchor bolt. The:parameters included location of the bolt, elevation of the bolt within the plant, tag number identifying the equipment that the bolt was supporting, diameter of the bolt, total length of the bolt and calculation of the imbedded portion of the bolt. Acceptance criteria for the bolt were defined to meet or exceed the

'engineer's imbedded length requirement as given in the return to service criteria, specified for Unit"1 restar During this inspection, no concrete expansion anchor bolt, out of a'totalpopulation of 40, was found to fail the acceptance criteri Based on the results of a review of NCR's and results from the UT inspectionprogram,,here is no evidence to substantiate the concer This item is considered 'close Allegation Concerning a QC Inspector (ATS No. RV-84-A-121)1 (1) Characteriztion, of the Allegation

)

A QC ins ector had looked the other way on.some jobs she had'let oime stuff slide."

This-individual, "is working as'a QC inspector where her husband is "lso employed as a welder'."

(2) Inspection Findings The individual who allegedly had accepted unsatisfactory work is, a nuclear quality control inspector.(NQC) for the-Southern

California Edison Company (SCE) and is certified to a level 2 position in the civil discipline. The.NQC inspector has been a certified civil inspector for approximately two years at the SONGS site. Based on an examination of seventeen Construction

-.Inspection DataRep6rts (CIDR s) which were completed by the NQC inspector it appears that the individual has been involved in preplacement, placement and post placement concrete inspection activities at the San.Onofre site. The NQC inspector rhas not been dertified by SCE for, inspection in an other discipline Interviews were conducted withetwo peers of the NQC inspector and air individual wo allegedly heard the NQC inspector state that finacceptable work has'pteviously been accepted by he The current civil NQC indpictors were interviewed to determine if they had, anyknowledg o5f the NQC inspector accepting unsatisfictory work. Both of their statements indicated.th they ha'd no&kn-owledge of the NQC inspector accepting unsatisfactory work. 'They further attested that the NQC inspector's knowledge 6f the subject area is sufficient to perform the inspection activitie The individual who allegedly heard the NQC inspector make a statement that unsatisfactory work had been previously accepted did notrecall hearing such a 'conversation between the NQC inspector and any'other individual The individual has stated that he has worked with the NQC inspector in previous work activities and has no knowledge of the NQC inspector accepting unsatisfactory wor Seventeen Construction Inspection Data Reports (CIDR) which were completed.by the NQC inspector wefe reviewed to determine the nature of the NQC Inspector',s work activity during th previous year. Results of that review indicate that the.NQC Inspector's.efforts have been spent in the area of.concrete preplacement, placement and post-placement inspection activities. The CIDR"s completed by the NQC.inspector appear to be complete and proper.per the Quality Assurance Program established at San Onofre with no. discrepancies'note The second concern by the alleger appears to indicate that a conflict of interest may have occurred in that.the NQC inspector' may have-inspected a spouse's work at the San Onofre site. The sp6use of the NQC inspector is employed at the San Onofre site as a pipe welde The SCE QA organization has conducted a surveillance of 80% of

'the welding records generated in 1984 to determine if welding inspection was performed by certified QC Welding inspectors only. The review conducted by QA had revealed that only authorized QC welding personnel had completed.QC sign offs on the weld records sampled. This review had not identified any, welding-records which were signed by the NQC inspector under review for this allegatio The Construction Field Forces (CFF) at the San Onofre site had also conducted a 100% review of all weld records performed by CFF. The spouse of the NQC inspector is employed by the CFF organization as a welde Based on a 100%.review of CFF weld records for 1984 no weld record has been identified which included'the NQC inspector as a witness or hold point for the weld record An additional area which had been inspected is that of whethe any guidance is in existence currently at,the San Onofre site within the Quality Control organization which would prevent an inspector from inspecting work done'by a spouse or relativ At the time of the inspection no such.guidance had existed within the QC organization.- However, licensee QC representatives stated that they did not believe a situation has ever,,occurred at the San Onofre site where a spouse or relative'would be inspecting the other's work. In response to the concern raised by the alleger, the SCE Quality Control Organization has revised Quality Control Instruction No. G00 dated June 11, 1985,, which specifies in paragraph 4.2 that "if after arriving.at~theinspection scene and/or during the assighment of an insect'ioh activity, the inspector believes that the credibility.o.f the inspection could be questioned because;of 'Aconf lift of interest or possible compromise of obje'ctirty (these conditions can be caused by, but are not lAimitedlto the' foklowing:

work performed by a close friend or relative; -repeated work causing frustration, mental 'fatigue, physical condition, tc,), the inspector shall notify the o s~hSft'QC pevisoand request..being replacedfrom the inspection "

Based on a review of the facts it has not been substantiated that' a NqC inspector had performed improperly nor has evidende been ac vered that indicates unsatisfactory or unacceptable work has been accepted. There' is no requirement which would prevent a husband or wife, or. close relatives from being employed by the same licensee. However, it would appear to be a conflict of' interest'if one of the two had to inspect th other's work. The action taken.by the licensee to prevent this situation appears adequate and no further inspection is required. This.allegation is considered close.

Licensee Event Report Review and Follow-up Through direct observations, discussions with licensee personnel, or review of the records, the following licensee event reports (LER) were closed:

Unit 1 85-07 Unit 2

-16 84-44 (Ri)

85-09 85-12 85-15 85-16 85-19 85-20 85-22 85-23

.85-24 Unit 3 85-02 85-04 85-05 85-10 85-11 85-12 85-16 No violations or deviations were identifie.

Follow-up of Previously Identified Items /84-36-01 (Open), Operation with Plant Alarms:

This item involved problems noted in Unit 1 with regard to deactivated or locked in alarm annunciators in the control'roo Several examples were observed in which Significant plan annunciators were not serving their intended function and no supplementary actions were being taken by shift personnel to ensure appropriate monitoring of involved plant parameter In response to this item, the licensee implemented an Annunciator Compensatory Action Procedure. In accordance with this procedure, the shift supervisor specifically assesses any annunciator malfunction and determines what supplementary actions need be taken by shift personnel until the annunciator malfunction is correcte These supplementary actions are documented on a procedure form and reviewed by shift personnel each shif The inspector reviewed implementation of this procedure and noted the following:

(1) The procedure has been fully implemented on Unit 1 and appears to be working well. The system is not cumbersome and is being used by shift personne (2) Units 2 ilnd 3 have not implemented a similar annunciator compensatory action program. The licensee agreed to evaluate what actions are warranted for Units 2/3 in this regar This item remains ope /85-09-04 (Closed), Shutdown Cooling System (SDCS):

This item involved an improper system line up for shutdown cooling on Unit 2. In particular, the power supply breakers (2BE-29, 2BJ-25) for trains A and B containment spray header valve operators (2HV-9367, 2HV-9368) were found to be closed rather than locked.open during SDCS operation on February 27, 198 This was not consistent with the San Onofre Units '2 and 3 Updated Final Safety Analysis Report(FSAR), section6.2.2.1.2.3C, "Operating During Shutdown Cooling", which statesthat the power supply breakers to these two valve operators will be locked open when the SDCS is in operation in order to preclude' diverting shutdown cooling flow to the' containment spray headers-Furthermore, Operating Instruction SO2-3-2.6, Re, Attachment 4,. ",SDCS Flow PathAlignment", states that the required position for these breakers is locked ope The improper positioning of these breakers appeared to be due to a procedural weakness in S023-5-i.3, "Plant Startup from Cold Shutdown to Hot Standby", which permits the initiation of Operating Instruction S023-3-2.9,;List 3, Attachment 8.3 "Containment Spray System Electrical Alignment - Unit 2", while still in mode 5 and prior to securing shutdown cooling. This alignment repositions the aforementioned breakers to the closed position though they are required to be locked open in accordance with the FSAR, since normal shutdown cooling was still in operatio Further review of this item by the inspector identified the following:

Although the licensee-procedure was not controlling inadvertent diversion of shutdown cooling flow by means of the above mentioned breakers, as committed to by the FSAR, the procedure required manual block valves in the containment spray system to remain closed until after the plant was off of shutdown cooling. The licensee has revised the applicable procedures to control inadvertent diversion of shutdown cooling using the breakers as specified in the FSA (2) The licensee did not correct the difference between the issued station procedures and the FSAR commitment in their periodic update of the FSAR, as required by 10 CFR 50.71. There also appeared to be a deficiency in the licensee's program for performing 10 CFR 50.59 reviews to preclude station procedures being revised contrary to existing FSAR commitment The failure to control inadvertent diversion of shutdown cooling as committed to in the FSAR is a deviation. (50-361/85-13-02). /85-08-01 (Closed), Auxiliary Feedwater (AFW) Monthly Tests:

This item involved failure of the licensee to perform required surveillance on the Unit 3.AFW system. In particular:

(1) Technical Specification Surveillance 4.7.1.2.1.a.4 requires that each AFW pump be demonstrated operable at least once every 31 days-by verifying that the AFW piping is full of wate This is done by ensuring that water emerges when venting th AFW discharge piping high point vents. This requirement to verify AFW piping full of water was amended to the San Onofre Unit 3 Technical Specifications on September 21, 1984, and was added to Procedure S023-3-3.16, "Auxiliary Feedwater System Monthly Tests", on November 21, 1984. Since then, the AFW monthly tests were conducted three times (November 28, 1984; December 27, 1984, and January 24, 1985), but the requirement to check the AFW system full to the vents was not performe (2) Step 6.1 of Procedure S023-3-3.16, "Auxiliary.Feedwater System Monthly Tests" required the performance of a trip test on the steam driven AFW turbine in order to comply with LCO 3.7.1.2, which states that at least three independent AFW pumps and associated flow paths must be operable. This trip test was required because the steam supply stop valve had previously been found in the tripped condition, rendering the steam driven AFW pump inoperabl This trip test was not performed for the months of November 1984 through January 198 Further review of this item by the inspectors identified the following:

Although specifically required in the body of the procedure, the station surveillance procedure for performing periodic AFW system testing did not explicitly include the missed tests in the check off list attached to the procedure. This problem has been corrected and is discussed in Unit 3 LER 84-04 o Shift operations personnel did not utilize the entire surveillabbce procedure when performing the periodic test The inspector noted that this was not consistent with the licensee's administrative procedure S023-0-35 (Use Of P'rocedures).

ThE failure to perform the required Technical Specifications sur Iveillante on the AFW system was a violatio (50-362/85-12-01).

The inspectors ndted~thit other recent procedure violations, allidentified by the licensee, indicated a need for continued attention to procedure compliance. These included:

(a) On December 11, 1984, during Unit.2 fuel inspection, a fuel module was jammed in the inspection stand and the

.fuel'module and inspection stand were subsequently damaged due to a lack of procedure compliance. This is discussed in paragraph 9.d. of Inspection Report 50-361/84-3 (b) On March 13, 1985, while Unit 3 was cooling down to.repair a leaking resistance thermal detector (RTD) thermowell, thejmnit experienced an inadvertent Safety Injection System Actuation as discussed in paragraph 4.b.3 of Inspection Report 50-361/85-04. This incident was the result of lack of operator attention in monitoring plant conditions during cdoldown and failure of.the operator to bypass the Safety Injection Actuation Signal (SIAS) as required by: cooldown procedure On March 30, 1985, an inadvertent safety injection resulted on Unit 2 Ss a result of the failure of an ins trument and,:contr ol1 technician to follow the applicable surveillance procedure. This item is discussed further in paragraph 3(b) of 'this inspection repor (d) On April 19, 1985, "iadiation monitor 3RI7821 was improperly returned to service following surveillance and maintenance in that it was not valved in. Monitor 3RI7821 is the'Turbine Plant Area Sump Radiation Monitor. This pr6blem was the result of lack of attention to detail and procedure compliance as follows:

The work authorization was not revised to reflect the use ofta revised procedure to.calibrate the instrument or the fact that the new procedure required using a clearance instead of an approva The operator posting the clearance did not initial the tagging column on the work authorization and he did not get an independent position verification as directed.by Procedure.023-0.-3 This action resulted in subsequent personnel improperly assuming that no clearancewas ever hun o The reactor operator (RO) and the SRO who reviewed the closed out work authorization did not perform an adequate review of. he document or question the improperly filled out tagging section of the work authorizatio /85-08-02 (Closed), AFW Flow Test:

This item involved failure of the licensee to-comply with the issued station procedure for performing AFW flow testing on Unit 3.' In particular, surveillance test procedure S023-3-3.16.2, "Auxiliary Feedwater Flow Test", requires that the unit be in mode 3 to test each AFW pump and that RCS temperature (no load Tavg) be at least

544 F to test the steam driven AFW pump. These procedural requirements were apparently not met on two occasions (March 1984 and November 1984) when the electrically driven pumps were tested while in mode 4 and on one occasion (December 1984) when the steam driven pump was tested with Tavg at less than 4000 Further review by the inspectors identified the following:

(1) Although the "objectives" paragraph of the :above mentioned surveillance test implied that both the electric and steam

. driven pump portions of the.test will be performed in mode 3, shift personnel had understood that only the steam driven pump portion of the test required mode 3 plant conditions and it was

• not considered to prevent performance of the electric pump portion of the test in Mode 4. To preclude future confusion, the licensee has revised the procedure to specifically clarify that the electric.pump portion of the test may be performed in Mode ) A review of operating logs for December 1984 showed that reactor coolant system (RCS) average temperature was greater than 540 0F when the steam driven pump portion of the-

-surveillance test was performed. Although the operations log did not include the actual average temperature when the steam driven pump test was performed,, it was concluded that the average temperature.was greater than 5440 F, since previous performances-of this test had specifically omitted the steam driven pump portion of the t est when average temperature was

-ikrmto less than 544 F. The inormation previously provided to the in pectors thatRCs temperature was less than 4000 Fwas based on an inforial equ pmentcontrol status chart and was in erro No viblations or deviations were identifie /85 12-01 (Open), Containment Ihtegrated Leak Rate Test:

Ti performance o a containment integrated leak rate test on Unit1i un

Tle issue concerns the-as-i m

as-found analysisdescribed in 10 CFR 50, Appendi This matter 1 bdingreviewedby the NRC and will remain open until resolve /85-09-07 Closed)-; Battery Discharge Test:

This item involves failure of the licensee to perform a battery discharge test on Unit 2, as required by -the Technical Specification In particular, a service discharge surveillance test (Surveillance Procedure S023-1-2.15), required by Technical Specifications:to be performed every 18 months, was not conducted on Unit 2 batteries 2B007 and 2B008 from the time the batteries were placed in service (February 1982) until it was accomplished during the current refueling outage. Therefore, for more than-one year the operability of these batteries was-not demonstrated with respect to their ability to carry rated vital.loads during an emergenc Further review by the inspectors identified the following:

(1) The licensee failed to conduct the required surveillance test as a result of inadequate review of battery acceptance test documentation by station maintenance personnel when

-'21 responsibility for the batteries was formally turned o er to the station maintenance group from the station start-up grou (2) The required battery discharge tests were successfully completed in December 1984 (for battery.2B007)and February 1985:(for battery 2B008).

(3) As discussed iriUnit.2 LER 83-149, the licensee is auditing all previously conducted maintenance related surveillance tests to ensure compliance with all Technical Specification requirement (4) Inspection showed that all other surveillance requirements with a period of 18 months or longer had been satisfie The failure of the licensee to perform the battery discharge tes required by the Technical Specifications is a violatio (50-361/85-13-03). /85-09-08 (Closed) Battery Capacity Testing:

This item involved the apparent failure of the licensee to perform a battery capacity test on Units 2 and 3, as committed to in the FSA ;In particular, it appeared to the inspector that the performance test of battery capacity within.the first two years of service had not been accomplished on any of the batteries. The licensee committed to.perform this test as stated in both the PSAR (par.'3.2.2.1.8D) and IEEE Standard 450-1980 (para. 5.2.1).

The licensee :maintains that the FSAR commitment was satisfied during Startup Testing, and presented the following information:

"NRC apparently contends...that the batteries were'not "placed in service" until receipt of the Operating License or commencement of commercial operation or some other point in time subsequent to the.completion of "Startup Testing,"' and that the performance test should have been completed within two years following this undefined dat "SCE believes the batteries were "placed in service" upon their initial energization-in 1979 and completion of PE-448-01 in 1981 satisfied the commitment to perform the initial capacity test "within the first two years of service."

The batteries were in fact required to be "placed in service" in order to complete other Startup tests which verified availability of DC control power to appropriate equipment. Service provided by the battery in order to perform startup testing between the time of their initial energization in 1979 and.performance of the capacity test in 1981, far exceeds the battery service expected during two years of normal operatio."The Objectives of Startup Test Procedures, in general, were established to ensure all FSAR statements regarding such testing were indeed satisfied prior to and/or immediately following receipt of th&.Operating License. Objectives 1.5' and

1.8 of 2/3 PE-448-01 were included to verify the name plate rated capacity of the battery and its ability to satisfy the DC design load requirements under emergency conditions. Testing in accordance with this.procedure satisfies the Acceptance Test, Performance Test, and.Service Test requirements in accordance with IEEE Standard 450-1980 as indicated in FSAR Section 8.3.2."

The licensee provided -the 'bove information to NRR in a letter, dated June 17, 1985, from Medford to Knighto No violations or deviations were identifie.

Review of Unit 1 Operating Procedures Contained within 'the "Contingent Rescission of Suspension" safety evaluation report prepared by.NRC,.for San Onofre Unit 1 is a statement that:

'rior to startup, emergency operating procedures will be established which describe -the required operator actions for respondin to such a seismic event, including alignment of the Spent Fuel Pool suction and alternative sources of auxiliary feedwater."

Such procedures have been established by the licensee and are discussed as follow Operating instruction S01-7-3 contains within it various alternate supply methods for refilling the Unit 1 Auxiliary Feedwater StorageTank.. This procedure describes various options which the Unit 1 operators have available to them for refilling the Unit 1 Auxiliary Feedwater Storage Tank. Such options include taking suction from the Unit 2 Condensate Storage Tank or the Service Water Reservoir on Unit 1, the Auxiliary Feedwater Pumps taking suction directly from the Service Water Reservoir, refilling the Auxiliary Feedwater Storage Tank from the domestic water system, and aligning the Auxiliary Feedwater Pump suctions directly to the Unit 1 Condensate Storage Tan The procedure describes the administrative actions to be taken by the shift superintendent and, in addition, states the specific valves to be realigned for such action Operating instruction S01-2.5-1 entitled "Earthquake," describes actions to be taken should the Refueling Water Storage Tank level fall below 96%

or become unstabl This procedure describes the realignment necessary to establish charging pump suction from the Spent Fuel Pi The procedure also describes what actions are to be taken by the operator to ensure that various systems are operable following the seismic event.

The procedure describes the plant systems to be checked for operation and parameters to be observed to ensure that each system has successfully-survived the seismic even.

Unresolved Items An unresolved item is a matter about which more information is required in order to ascertain whether it is an acceptable item, an open item, a deviation, or a violatio.

Exit Meeting On May 9, 1985, an exit meeting was conducted with the Licensee representatives identified in Paragraph 1. The inspectors summarized the inspection scope and findings as described in this report. A follow-up exit meeting was conducted with Mr. J. Haynes on May 21, 1985, to review additional inspection findings as discussed in the details of this inspection report.