IR 05000206/1984008

IE Insp Repts 50-206/84-08,50-361/84-11 & 50-362/84-11 on 840307-16 & 0330-0429.Violation Noted:Improper Completion of Equipment Control Form for Plant Protection Sys by Instrument Technician

ML20151J532
Person / Time
Site:	San Onofre
Issue date:	05/21/1984
From:	Canter H, Chaffee A, Dangelo A, Stewart J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V)
To:
Shared Package
ML20151J513	List: IR 05000206/1984008 ML20151J505 ML20151J520
References
TASK-1.C.6, TASK-TM 50-206-84-08, 50-206-84-8, 50-361-84-11, 50-362-84-11, IEB-82-04, IEB-82-4, NUDOCS 8406270112
Download: ML20151J532 (23)

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U. S. NUCLEAR REGULATORY COMMISSION s

REGION V

Report Nos. 50-206/84-08, 50-361/84-11, 50-362/84-11 Docket No , 50-361, 50-362

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License Nos. DPR-13, NPF-10, NPF-15 ,

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Licensee: Southern California Edison Company P. O. Box 800, 2244 Walnut Grove Avenue Rosemead, California 91770 Facility Name: San Onofre Units 1, 2 and 3 Inspection at: San Onofre Site, San Clemente, California Inspection conducted: March 7 through March 16 and March 30 through AJril 29, 1984 Inspectors: #'

. E. Chiffee', '$'enior Resident

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, ' Fiate digned Inspector, Units 1, 2 and 3

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J.' P. Stehfrt, Resident Inspector C4af.e Sj(gned Unit 2 and 3

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. geTo, Resident Inspector' Unit 1 6 ate' ryign/d Approved ~by: ,J 3/ I

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l.YCanL(r, Chief, Reactor Projects 4) ate Jfign(d Section 3 Smmnary: '

Inspection On March 7 through March 16 and March 30 through April' 29, 198 '

(Report Nos. 50-206/84-08, 50-361/84-11, and 50-362/84-11)

Areas Inspected: Routine,' unannounced resident inspection of Units 1, 2 and '

3 Operation Program and Unit 3 Startup Test Program including.the followin areas: Operational safety verification, ' licensee event follow-up, Power Ascension testing (Unit 3), evaluation ~ of plant trips . (Units .2' and 3), ,

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- . Monthly Surveillance activities (Units 2 and 3), Monthly Maintenance'

activities (Units.I and 3), followup of outstanding items,and Bulletins, and independent inspection. This inspection involved 83 inspection hours on ,

Unit 1, 26 inspection hours on Unit 2 and 203 inspection hours on Unit.3 for- #

j a total of 312 inspection-hours by three NRC inspector ,

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Results:

i Of the nine areas examined, one apparent violation was identified:

Improper completion of an equipment control form by an instrument technicien on the Plant Protection System, in that a channel of the Plant Protection -

i System was declared operable before the testing on it was complete f

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DETAILS' ;i

. Persons contacted - Units 1, 2, 3

. *J. Haynes, Station Manager i *H.-Morgan, Operations Manager

• Wambold, Maintenance Manager

• R. Rosenblum, Technical Manager

• D. Schone, Onsite Quality Assurance Manager

• W. Moody, Deputy Station Manager

• D. Shull, Assistant Maintenance Manager

• P. Croy, Compliance ~ Manager i *H. Speer, Lead Compliance Engineer l *R. Santosuosso, Supervisor of Instrumentation and Control

• J. Crawford, Lead Quality Assurance Engineer ( *J. McKinnon, Quality Assurance Engineer

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• J. Derfelt, Administrator ,

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G. Gibson, Supervising Compliance Engineer

.; D. Pecor, Emergency Preparedness Manager l W. Marsh, Operations Superintendent, Units 2 and 3

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V. Fisher,. Assistant Operations Superintendent, Units 2 and 3

J.LReilly, Technical Supervising Engineer K. Helm, Supervisor of Effluent Engineers

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B. Brush, Instrumentation and Control Supervisor i

The inspectors also interviewed and talked with other licensee employees during the course of the inspection; these included operations shift-superintendents, control. room' operators, chemistry foremen, and Quality

Assurance engineers.

j * Denotes those persons attending the exit interview on April- 17, 198 !

Operational-Safety' Verification (Units 1- 2, and 3) General

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< 'The' inspectors observed control room operations, reviewed applicable j logs and conducted' discussions with control room operators during' '>

the. inspection period.. The inspectors verified the operability of i '

selected emergency systems, reviewed the " tag out" logsand verified '

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i proper return -to service of affected components. . Tours of;the, 3

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' control Building (Units 1,:2 and 3),-Safety Equipment Building

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i ~ (Unitet 1; 2 and'3), Penetration Building (Units 1,'2 and 3),'Radwaste

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1> Building (Units 1, 2 and 3), Containment Building'(Unit 1),. , Auxiliary Feedwater Buildings (Units 2 and 3),-Diesel Generator._ ' '

s Buildings (Units =1, 2 and 3), the Salt Water Pump Building (Unit 2), -

l and other areas, were conducted to observed plant; and equipment -

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. i conditions. Particular attention was given to examination for

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~ potential fire hazards, fluid leaks', and excessive vibrations,' and .

s to. verify that maintenance requests had been initiated forfequipment

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it-Tripping of Turbine Valve HydyaulWActuatoe Fups

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o The inspector determined by reviewing the Unia.s2 and 3 Reactor (". ,

ii il 9,3 1984, jith Unit 3 operatin'g

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r _atOperator logspower, 100 percent that, ata 1001 worker onpem Apr; forming routine dusting '

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(housekeeping) in-the Turbine Building had unintentionally tripped;. 4' ,

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the hydraulic actustor pumps for fode Unit 3' Turbine. Valves. The' ,

's~- worker had previously trippedd nydraulic actuator pump for a 'UniE ,

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, Turbine valve approximately anjhour before. Of the fottg hydraulic g-valve actuator pumps tripped q Unit 3, three were High Pressure-Turbine Stop Valves. The closarq qf any two High Pressure Turtate '

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Stop Valves would have caused a Reuctor Trip on a Loss of Load' -

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a Signa Based on past observhtfons, it would have taken' , s' }

> approxi:aately 15-20 minutes for-a stop valve to close afte stopping ,

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it's hydraulic actuator pump. 'However, the reactor operators toc *' +

inanediate corrective actions and re-closed the breakerstfor4he~ N

' valve actuator pumps on the motor control center, thus preventing y "

. , reactor trip. The licensee's staff also directed the contractor A J o

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housekeeping work force to not dust electrical motor control ,,

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centers, including those in.the Turbine-Building. Thesinspector: ,

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also determined, based on interviewing other operators,'that a! s ' ,, { h

similar incident had occurred previously when a maintenance worker % i 1 I on March 27, 1984, hadunintentionkl,1ytrippedavalve_ actuator a .

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[ pum In ,this instance the valye closed which resulted (t; having a - '[V y 1 stop valve and a governor valve heins. closed on'two different Main a , ,

i Steam lines to the turbin In thia case, also,Lth'e re dtor operators M '

! were required to'take corrective %ction to prevent a rdagtor trip

'In addition, the licensee is planning to have plastic protective \

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windows installed over the ON/0FF push buttons"ct thi turbine valve + ' -'

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No items of noncompliance or deviatibus werp identi ied."

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] * , 6 LER 84-007 Actuation of the Reactor Protection System 3 ,,

W (RPS) (Unit 3) (Closed)

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LER 1800 in84-007 concerns which Unit 3 was in Modethe reactor r I h 'h < khk trip occurred on Nrc[ 5', y'Contr Prior to the trip, tPe

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i Element Assemblies (CEA) of shutdown Group B were being wkhd/ awn. g'

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As a result of the trip all CEAs which were withdrawn wery fully, %

inserted. Atthetimeofthe' trip,anInstrumentandControl,(I&C)h'

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Technician was removing reactor. coolant flow signal simulating 4,f '

devices in the Plant-Protection System. ?The LER stated that . Q ' m.

, . attempts to determine the cause of the trip were unsuccessful. The ^j, 1 -inspectors interviewed the I&C technician, invdive:t in 'l.heJ .

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incident, and inspected the instrumentaticn panel from which the ' a s \ 5:

technician was removing the simulating deiice. The insp M tura also 3 '

[ ,. reviewed the procedure being used and interviewed knowledgeable technicians and' supervisors.. %The inspector

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',. concluded, based ~ on these' inspections,"that the probable icause 'of stitcp ( '

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reactor'~ trip could not be determined. This LER (50-362/84'0 $ 1s7 % '~ close p

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The inspector noted that Procedure S023-II-1.6 did not require

~ double verification of the. removal of the rea'ctor coolant flow signal simulating device nor did it require the double verification of the removal of.other simulating devices which.may be installed in the Plant Protection System (PPS). The simulating device, if not removed prior to plant operation, would disable that portion of the PPS. The failure to require double verification in procedure S023-II-1.6 is a_ deficiency in the licensee's program for verifying the correct performance of operating activities. -The licensee,has

- committed to perform.a comprehensive review of maintenance and

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surveillance procedures to ensure conformance with the independent verification criteria of TMI item I.C.6. This commitment was made

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as a result of the event which is discussed in paragraph 9 of thi report. Since this previously made commitment was'still in process; of. implementation when the inspector identified the above discrepancy, no item of noncompliance will be pursued. I addition, the licensee appears to be making steady progress in. implementing corrective action .

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No items of noncompliance or. deviations'were~ identified. .

. LER 50-362/84-13 Reactor Coolant Specific Activity (Closed)'

This item is discussed in this report in paragraph 9'a as part of an

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ongoing open item 50-362/83-42-01. This item is close . Power Ascension Testing (Unit 3)

y The licensee completed startup testing on Unit 3 on March 27, 1984'with the completion of the 200 hour0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br /> warranty run. ' Commercial operation on Unit 3 started on April 1, 198 .

No items of noncompliance or deviations were identifie . Plant Trips'(And Significant Plant Transients) - Units 2 and 3 , ; Unit 2 During this report period, Unit 2 experienced reactor trips on

' March 9,"24 and~26, 1984'.

0n March 9,1984', at '1933 PST, while at 100 percent power, 'an instrument technician, while performing plant protective system testing, unintentionally' initiated a safety injection _ actuation signal (SIAS), a containment cooling actuation signal' (CCAS) 'and 4 -

containment spray actuation signal.(CSAS). The actuation of the safety .

Injection system resulted in the ' rapid addition of' highly borated C water from the Borated Water Storage Tanks via .the three emergency core cooling system charging pumps- This addition of highly

~ borated ~ water rapidly reduced reactor power and, when reactor power reached approximately 30 percent power; a manual ' reactor trip was c; initiated ~at 1950.1 The licensee' subsequently stabilized the' plant

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Approximately 6,000 gallons of borated water had been sprayed. into

, the containment as a result of the CSAS. This water also contained sodium hydroxide;. however, due to the normal delay of caustic '-

injection into the containment spray flow, no caustic was actually

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sprayed into containmen No significant equipment damage was identifie The specific cause of the actuation was the technician's failure to reset the trip in a previously tested channel before testing the second channel. The licensee has modified the affected procedure to include an independent verification of the resetting of each channe On March 24, 1984 at 1940 PST, while at 100 percent power, a failure in Control Element Assembly Calculator (CEAC) for Control Element Assembly (CEA) Number 20 position indication occurred, which then

resulted in a reactor trip signal ^from the Core Protection Calculator (CPC), thus tripping the. reactor. .CEAC No. 1 indicated that CEA 20 was about 8 inches lower than the rest of the CEAs.i ~

Group 6. A rod deviation penalty._ factor was calculated by the CPC

which was of sufficient magnitude to cause a DNBR reactor trip signal.

The penalty factor calculated by the CPC would not normally have been large enough to cause the reactor trip; however, the licensee had recently increased-the penalty factor (PFMULT) in the CPC based on a recommendation.by Combustion Engineering. .The PFMULT increase was made to account for the decalibration of the Reactor Coolant System Thermal Power (BDT) with respect to the secondary calorimetric

, power as a result of power changes ( 20%). Combustion Engineering

! had also recommended an' alternate surveillance which could have been l performed by the reactor. operator in lieu of' increasing the penalty factor in the CPC. Subsequent to the reactor trip on March 24, i 1984, the licensee has returned the CPC PFMULT back to the original

value and is presently using the alternate method,of preventing the decalibration of the calculated BD '

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<e On March 26, 1984 at 0633,PST, while at two percentspower, the .

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reactor was tripped due to a high Steam' Generator'(SG)* level in SG

- s No. 1, which occurred as a= result of. operator ' error while ~ '

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controlling the SG level in manual control using a Main Feedwaterl ,

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In addition to the reactor trips described abovef alsigkificant"'

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transient occurred on March 27, 1984 at 1510 PST.' The High

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7 ,. 6 r G Pressure (HP) Turbine governor valve 2200C c,losed.due to an

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. t 4 oil pump failure, resulting in reducing reactor power _from 100l -

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g r percent to 93 percent. Shortly after this event.HP. Turbine Stop ;!

valve 2200H closed. lit appears that Stop valve?2200H;was.closedi 3 R

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unknowingly by a plant operator wh'o was investigating the' closure of _

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governor valve 2200C. With the closure of:both HP Turbine valves '+-

2200C and 2200H only two of the four Main Ste'am lines-to the. turbine

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r were in operation. .The Reactor Operators tookLimmediate corrective action to prevent a reactor trip in'that reactor power was. reduced .

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by inserting control rods and injecting borated water. During the transient, pressurizer pressure had increased to approximately 2360'

psia, which is within 15 psia of the trip setpoint (2375 psia)

associated with the operation of the core protection calculato The inspector noted to the licensee that the events on March 26 and March 27 should be analyzed for inclusion into the Reactor Operator Simulator Training Program, including the actions taken by the

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operators in preventing the reactor trip on March 27, 1984. The licensee indicated that the~ events would be reviewed for inclusion in operator simulator trainin Unit 3 During this report period, Unit 3 experienced a reactor trip on March 10,'1984. At 2222 PST, while at 76 percent reactor power, the turbine tripped on low main condenser vacuum, which then tripped the reactor on a Loss of Load signal. The reactor power had previously been reduced from 95 percent to 76 percent in response to high chlorides in the steam generators (470 ppb) and a saltwater leak in the southeast condenser ~ quadrant (18 ppb). The cause of low vacuum was determined to be plugged drains on the condenser (north half) air remcval line Unit 3 also had a scheduled shutdown on March 30, 1984 in ordec to balance the turbine and reactor coolant pump P00 In addition, the inspectors reviewed the spurious Plant Protection System actuation event which occurred on March 5, 1984 at.1800 PS Unit 3 was in Mode 3 and the withdrawal of Shutdown Control Element Assemblies (CEA) was in-progress. Group A was' fully withdrawn.and Croup B was 100-inches out and being withdrawn when the spurious trip occurred. This event is summarized in Licensee Event Report No.84-007 and discussed in paragraph 3 of this repor ,

.Following the reactor tri~sp during this period,.the inspectors ascertained the status of the reactor and proper operation of safety systems by observation and discussions with licensee personnel and-review of the post trip review reports associated with each of the-trip .

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No items of noncompliance or deviations were identified, s Monthly Surveillance Activities (Unit 2 and 3)

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The inspector observed the performance of portions of the following surveillances: '

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Unit 2 and 3 ,

S023-3-3.25 :" Modes 1-4 Once-A-Shift Surveillance"

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The inspector noted that the recorded data was in agreement with the observations made by the inspecto Unit 3 SS023-3-3.37 " Reactor Coolant System Water Inventory Balance" In response to the occurrence on April 16, 1984 at 0615 in which the licensee idenitified that the Reactor Coolant System (RCS) leak rate was 1.1 gpm (unidentified), the inspector observed the performance of S023-3-3.37 between 0830 and 0950. The results of this leak rate calculation indicated that the increase in the RCS leak rate was due to leakage within the Chemical and Volume Control System (CVCS).

The leak rate calculation between 0330 and 0950 with the CVCS secured indicated a leak rate less than 0.3 gallon per minute. The licensee's investigation could not determine the location of the indicated leak in the CVCS. The licensee suspects that the leak was due to a leaking relief valve, which stopped leaking when the CVCS was secured. The licensee plans to modify procedure S023-3-3.37, so that leaks withi the CVCS are not included in the RCS water inventory balance when the unidentified leakage calculation is performed as required by technical .

specification 3.4.5.2.b/4.4.5.2.1.C. The licensee's technical staff has continued to investigate and track the operational problems associated with the CVCS. The CVCS problems which contribute to the frequent

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RCS/CVCS intersystem leakage occurrences are primarily due to'the lifting of relief valves at the discharge and suction of the charging pumps and relief valves in the letdown portion of the CVCS syste No items of noncompliance or deviations were identifie . Monthly Maintenance Observations (Units 1 and 3)

The inspectors observed the following maintenance:

Unit 1

. Diesel Generator No. 2 10 CFR 21 inspections Unit 3

. Repair of the hydraulic oil dump line on the Main Steam Isolation Valve HV-8205

. Repair of seawater (chloride) leaks in the Unit 3 Main Condenser The' inspector noted that all of the above work activities were performed in accordance with the maintenance procedures, maintenance orders and work authorization No items of noncompliance or deviations were identifie __ . __ _ _ . _ . . _ _ - _ _ - _

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' Followup of Outstanding Items (50-362/82-28-01) (Closed) Independent Secondary Comparative Chemistry Analysis Inadequate Based on the results of an independent comparative chemistry analysis by Torrey Pines Technology, the licensee has produced test

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results which indicate an acceptable level of performance by the

. secondary chemistry lab on Units 2 and The independent lab >

results were 145 PPB chlorides using the Ion Chromatographic method which correlated with the 123 PPB Chlorides of the Unit 2 and 3

, chemistry results using the Ion Chromatographic method. This item is closed, (50-362/82-28-02) (Closed) Piping Dynamic Effects Test Not Performed on Unit 3 Pressurizer Auxiliary Spray Piping Based on the satisfactory performance of the pressurizer auxiliary spray piping flow test, using two and three charging pumps in

accordance with Construction Work Order 4037-11 on March 6, 1984

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on Unit 3, this item is closed.

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! (50-362/82-24-02) (0 pen) Component Cooling Water Flow Tests Results Not in Agreement with FSAR during Pre-operational Startup Test 4

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The licensee has submitted FSAR Change No. 8-555 to updat ; component cooling water flow rates in Table 9.2-4'of the FSAR. This item remains open and will be reviewed after the change is incorporated into the FSA .

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No items of noncompliance or' deviations were identifie .

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Independent ~ Inspection *

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' High Primary Coolant Activity',' Unit 3 -

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The inspectors have continued to~ follow the high reactor coolant '

activity in the Unit 3 Reactor Coolant System (RCS). Inspection report 50-362/83-42 summarizes the licensee's' position on'the high'RCS -

activity. Combustion Engineering has indicated that the'high RCSJ activity will diminish af ter about 120 effective full power days (EFPD) of operation. Unit'3 presently has completed approximately 90 EFPD and_the present (April 1984) RCS Dose Equivalent Iodine has ,

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remained at 0~.5 microcurie (uc)/ gram (with 2 charging pumps "

l- . operating) with a peak of 2.37 which occurred on March _30, 1984E

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.at 0830 following a planned shutdown _of Unit'3 et 0300. fThe Dosec I Equivalent Iodine remained above 1 uc/ gram for 42 hours4.861111e-4 days <br />0.0117 hours <br />6.944444e-5 weeks <br />1.5981e-5 months <br />'from.0430 on '

March 30, 1984 to 2230'on April 1,,1984.'

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The RCS activity will be closely. monitored and the; licensee's ,

L activities in this area will be- reviewed during a : future -inspection. *

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- This item (50-362/83-42-01) remains ope m -

lNoLitems of noncompliance or deviations were~ identifie ,

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b. Fire Protection Program Deficiencies (1) Updated Fire Hazards Analysis (FHA) ,

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On March 19, 1984 the licensee submitted the updated FHA for Units 2 and 3, required by 10 CFR 50.71(e), to the NRC. The updated FHA provides more detail and improved clarity over the current FHA. The licensee expended considerable effort in updating the FH The licensee initiated a Task, Force (rather

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than a routine updating ef fort) in October 1983 to update the FHA as a result of the following events which occurred during -

the previous two years (1981-1983):

(a) Deficiencies identified by NRC inspectors during the inspection of the licensee's implementation of the  ;

requirements of 10 CFR 50 Appendix R (Sections III.0, J

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and 0), NRC Branch Technical Position (BTP) 9.5-1.(1977)

(Appendix A) and the FHA on Units 1, 2 and (b) Deficiencies identified by the licens'ee as documented in approximately forty Licensee Event Reports and Special Reports which identified several hundred individual nonconformances involving Fire Protection requirement (c) NRC Enforcement Actions taken on NRC identified deficiencies at San Onofre and the Trojan Nuclear Plan The licensee's Task Force consisted of contracted engineers from Bechtel and Impell, in addition to the licensee's.own staff. The Task Force, consisting of a staff averaging 10 full time (5-15) engineers,' worked continuously from October, 1983 to March, 1984. This effort' included the reverification of the As-Built FHA Design Featutes and Fire Protection Systems in Units 2 and Additionally, from January to March, 1984, management review and engineering analysis to resolve the large number of deficiencies required additional licensee resources. All FHA and Appendix R deficiencies, which have been ioentified by.the licensee, are being physically corrected, or have exemptions requested in~the updated FRA based on, either, (1) that equivalent fire protection has been provided in accordance with good

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engineering judgement, or (2) that the current FHA exceeded the Appendix R (Commitments) or BTP 9.5-1 requirement (2) LER 84-01 (50-361)

The licensee reported 91-nonconformance reports (NCRs) which

identified _ deficiencies which were not in conformance with ,3 cither the licensee conditions, current FHA, and/or'the

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-' Technical. Specifications. The deficiencies.were~ identified as .

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a r'esult -of routine surveillances and the~ process of updating . -

L' the FHA. The major deficiencies identified were: ',.

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Cooling Tunnel had not been installed as indicated in the FHA but in the corridor in the Turbine Building one elevation above the Saltwater Cooling Tunnel. The

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licensee will relocate the spray / sprinkler piping as described in the FHA.

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o Fire hose nozzles not Class E nozzles (for electrical cable fire zones). The licensee will have Class E nozzles installed where require o

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Inadequate fire hose stations, which do not have overlapping coverage from adjacent fire hose stations, due to design errors. The licensee has requested a change to

. the FHA for an exemption based on the Fire Brigade currently responding to these areas with sufficient fire hos o Communication cable fire wrapping not installed due to design errors or damaged due to various activities. The licensee is repairing or installing cable wraps in conformance with current design document o Damaged or missing fire wraps and inadequate separation between safety and nonsafety cables and cable trays due to installation errors and construction activities. The licensee is repairing or replacing all wrapping and cable separation deficiencies'.

o Grating rather than a one-hour rated barrier was installed in Turbine Building Battery Room. Design drawing and analysis of fire hazards in.the area show the grating-to be the approved design. The licensee has requested that the FHA be revise o Emergency lighting is not provided for all equipment necessary to achieve cold shutdown. The present approved FHA provides emergency . lighting in areas for hot shutdown

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only. This is;in conflict with~ Appendix The licensee is still evaluating corrective action and has requested an exemption to the~ cold shutdown requirement for emergency lightin o Fire / smoke detectors and' alarm systems are not installed ,

in accordance with the FHA in several plant areas due to

. design and installation errors. -The licensee is taking corrective action to correct the installation errors and/or is requesting exemptions in the updated FH ,

o ~ Cable trays located abcve suspended ceilings in the Control Building at the 30 ft. and 70 ft. elevations. As ,

corrective action the licensee will install detection a'nd suppression systems'above_the suspended ceiling Y 9 _

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o Fire blankets not certified in accordance with ASTM E-11 : Licensee will establish certification of Cerablanket to ASTM

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o Deficient-fire-rated barriers and walls. The deficient l fire barriers include penetration seals, nonfire-rated i seismic joints, expansion spaces and connections. The licensee is repairing or replacing the seals, joints and ConneClion . o Reserve transformers containing oil are 38 ft. from fire wall (50 ft. requirement). The licensee is requesting an exemption and revision to the FHA based on the presence of nonrated, heavy concrete walls surrounding the safety related equipmen (3) LER 84-15 (50-361) (open)

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4 The licensee issued LER 84-15 as a restit of the following:

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(a) IE Information Notice No. 84-09 (Lessons Learned from NRC-Inspections of Fire. Protection Safe Shutdown Systems)-which ,

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specifically identified methods of complying with Appendix R (Sections III.G,J, and 0); (b) attendance of the licensee's staf f at the February. 13-14, 1984 Nuclear Industry Fire t Protection Seminar; and (c) up-date of the discrepancie's,noted in LER 84-01 as a result of updating the FH '

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i In LER- 84-15, the licensee identified twelve areas iniwhich; '

deficiencies were identified between the Fire Prote,ction -

Program and NRC requirements. The licensee has. requested that' _ '

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deficiencies identified as Items I through V (LER 84-15) b e exempted in the updated FHA. The licensee.had'p'reviously

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believed that.these five items had been found acceptable by-the: . <

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NRC in meeting the intent of the Appendix R requirements base'd- ,

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, on the Safety Evaluation Reports issued byLthe NRC for ' , ,

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San Onofre Units 2 and i'

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Seven items in theLLER (numbered VI through XII) a're~ deficiencies-

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in-design and construction of the plants;as' described in the. t

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FHA. The deficiencies. included design and installation errors: , .

in the following areas

(1) qualification of materials ured in7 the insulation of. electrical: cables; (2) location of power. ,

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',, supplies and electrical controls for ventilation systemc;  ;

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(3) fire. protection equipment (fire sprinkler deflectors, ~ ' - ' '

missing. fire hose-shut-off. valves and_ fire' detectors, inadequate fuse rating for overcurrent protection, missing 1

Seismic Category I standpipe); (4) . improper. use of combustible materials in plant equipment and flooring; (5)' cable tray-

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' wrapping and separation;(6) fire retardant coatings-on fire . _

,  ? rated barriers,'.and_(7) smoke detectors not properly, certifie ,,

The . licensee;is requesting exemptions on the majority of.'th '

design deficiencies based on the licensee's' position that theref

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is minimalirisk in-the area'of the deficiency. The licensee-

, 'haslstatedsthat a(u'pdated LER will: address, corrective. actions'

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l which are still being determined. The corrective actions for the missing Seismic Category I standpipe, missing early warning fire detectors, and uncertified fire detectors are still being evaluated by the licensee and will be included in a revision to LER 84-1 Because the Fire Protection Program deficiencies were identified by the licensee, the deficiencies are not considered items of noncompliance based on the NRC enforcement policy which encourages the self-identification of deficiencie The corrective actions identified in the above LER's will be examined during a subsequent inspection. No items of noncompliance or deviations were identifie c. Sulfate Concentration in RCS (Unit 1)

On March 23, 1984 a reactor coolant system sample indicated an elevated sulfate concentration of 574 ppb which is above the chemistry procedure (S0123-III-1.1.1) limit of 50 pp Investigation by the licensee identified a possible source of the sulfates as comming from resin which was unknowingly contained in ducting used for ventilating the primary side of the steam generator The licensee is currently evaluating laboratory analyses of coolant samples taken at various equipment locations to determine the most likely path of sulfate intrusion. Also, a draft procedure is under review by the licensee for resin cleanup in the reactor coolant syste The cleanup activities by the licensee will be monitored by the inspector and discussed in a future repor (50-206/84-08-01)

d. Inoperability of Reactor Trip Breaker Shunt Trip Device due to Inadequate Lifted Lead Control (1) While Unit 3 was in mode four on 12/27/84, the licensee found the Reactor Trip Breaker (RTB) 8 undervoltage device to be inoperable. This is a GE-AK-2-25 breake This l

discrepancy was identified during the performance of 31 day surveillance on the plant protection system. The inoperability was due to small metal shavings in one control room manual reactor trip pushbutton. These metal shavings cross connected two normally separate contacts, which overrides the auto and

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manual inputs to trip the breaker on undervoltage. The licensee's initial investigation verified that all other breakers in Unit 3 were operable on undervoltage. While trouble shooting the above problem an I&C technician identified, on 2/28/84, that eight leads in the plant protection system cabinets, which supply power to the shunt trip devices, had been left disconnected; making the shunt trip to all affected RTBs inoperable. The UV trip was operable to all but RTB C81.

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The licensee determined through subsequent investigation that this error occurred due to personal error in completing the restoration section of surveillance procedure S023-II-3.1 (18 Month Response Time Test). The following conuributed significantly to this error:

o The restucation step in the procedure did not clearly require retermination of the eight leads in questio It simple required retermination of any leads not yet reterminated during performance of this surveillanc o The informality of the turnover process between I&C technician shifts resulted in failure to transfer the true status of the restoration proces o The individual on the oncoming shift who signed for completion of this step failed to fully verify all determinated leads had been referminated, o The procedure failed to provide any form of an independent verification of retermination of these critical lead o The policy specifying necessary actions required to be completed prior to signing for completion of a step in a procedure was vagu The restoration error occurred on february 16, 1984. The licensee ideatified and corrected this error on February 27, 1984 prior to Mode 4 entr (2) Sequence of Events November 16, 1983 Maintenance Order 83711337 was reviewed by Equipment Control for acceptability to allow performance of 18 month Plant Protection Systems Response Time Test (S023-II-3.1). The procedure was found acceptable and scheduled for January 7, 198 January 7, 1984 Channel A of the plant protection system declared (0910) inoperable by a licensed operator to perform S023-II-3.1 as documented .;n Equipment Control Form 3-30224 January 8, 1984 Unit 3 entered Mode 5 to conduct a scheduled (0425) 43 day surveillance outag January 9, 1984 Channel A of the Plant Protection System is (1815) declared inoperable to allow replacement of power supply cable in accordance with Design Change Package DCP 3-295CE as documented on Equipment Control Form (ECF) 3-27761.

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January 11, 1984 Work on 18 month Plant Protection System (0500) Response Time Test commenced in accordance with S023-II-3.1, ass documented on Maintenance Order 8371133 .

January 12, 1984 Channel A Plant Protection System' declared

(1115) .

inoperable to allow performance of a partial 31 day channel functional check surveillance (S023-II-1.1)

on the Plant Protection System, as documented on ECF 3-3036 t

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January 12, 1984 Channel A Plant Protection System declared (1500) ' operable by licensed operator'after completion of DCP 3-295CE, as documentedson ECF 3-2776 i January 13, 1984 Channel A of the Plant Protection System

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(0005) . declared operable for Mode 5 by a licensed

- operator upon completion of'a 31 day partial functional check (S023-II-1.1) to meet Mode 5 requirements for'an' operable log power instrumentation system, as documented on.ECF 3-3036 ,

January 25, 1984 Instrumentation and Control (I&C) Technician

.. (0900) prepared Temporary Change Notice (TCN 3-1) t'o -~

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SO23-II-3.1. This TCN provided new resistance c values as a result of Design Change Package -

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(DCP 386-J) and.also eliminates unnecessary limits .

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! in procedure for increased flexibilit .

January 31, 1984 TCN;3-2 to S023-II-3.1 originated and issued.

(1330) ~ 'This-TCN corrects typos, incorrect po;arity,

a . deletes unnecessary confusing phrases, changes Core Protection Calculator'Section with proper steam generator number and proper data. recording.

, 'Feb'ruary 2, 1984 I&C technician prepares TCN 3-3.to '

(1530) S023-II- This-TCN affects determination of response time of reactor. trip breakers (RTB) s by. deleting the requirement to record the longest RTB response tim *

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February 3, 1984; Work completed;cn 18 month ~ Plant Protection (0115) System Response Time 1 Test, as documented on Equipment'

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Control Form (ECF) 3-30242.by I&C' Technician, event

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though' work was not yet complete in that the restoration step-had not been complete t

. February 4, 1984 ~

PPS Cabinet A.declaredioperable by' operations  ;

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based on completibn of.the 18' month response

. , time test (S023-II-3,1),Las documented on ECF 3-30242

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by operations. . NOTE: lno 31 day-PPS Channel .

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}FunctionalCheck.(S023-II-1,1)wasrequiredbythe

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licensee to declare system operational atLthis time,  ;

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even through the system had been made inoperabl Further, the system was still inoperable due to lifted leads.

February 11, 1984 Channel A of the Plant Protection System (2000) declared inoperable to allow performance of a full 31 day surveillance function check of channel A (5023-II-1.1), as documented on ECF 3-31123.

a February 11, 1984 31 Day Plant Protection System Surveillance (2000) commenced in accordance with Procedure S023-II-1.1, Revision 10 (TCN 2), as documented on Maintenance Order 840003122.

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February 14', 1984 31 Day Plant Protection System Surveillance 4 (0645) (S023-II-1.1) completed on Bay A, as documented on l ECF 3-31123 by'an I&C Technician. NOTE: the h matrix testing of this procedure was still outstandin .

February 16, 1984 18 Month Response Time Test of Channel A of (1600) the Plant Protection-System, in accordance with,

. S023-II-3.1, is documented as complete by an I&C-Technician on Maintenance Order 8371133 This technician also signed the restoration section'of, this procedure (S023-II-3.1) as this time and filled out the data sections. This he did based on a verbal

! turnover from the last shift who he believed, based on his; turnover, had completed the restoration of this system correctly. He did, however, attempt to

. verify proper restoration completely, but failed.~

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February 26, 1984 While conducting Step 6.9.27 (Matrix Testing)Lof S023-II-1.1, " Reactor Plant' Protection System Channel i Functional Test-(31 DAY INTERVAL)," it'was noted that-s the Undervoltage Coil to_ Reactor Trip Breaker.8 did

.. not. function as expected. However, this section of' _,

the procedure was signed off as being'successfully

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completed since the observation'did not contradict the existing. acceptance criteria in_the procedur .

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February:27, 1984 Further investigation, by licensee personnel, ~

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q (0300) . fresulted in the licensee identifying that-the -

~'- UV device for-RTB 8 was inoperabl , y i

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. Unit 3' entered-Mode 4; s

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Further-investigation revealed.that the UV; device _ i,*

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. February 28, 1984 ,

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_inoperability was due to.netal' shavings.in one of,thi "'T'

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's control room reactor trip manual push buttons.

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In addition, during this investigation it was discovered, by an I&C Technician, that 8 leads in the

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back of the Plant Protection System Cabinets had not been reterminated. It was later determined that this

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had occurred due to an error in restoring this system -

l to normal after completion of the 18 month response l time test on Channel A PP The 31 Day Plant Protection System Surveillance was signed off as successfully completed and no anotations of the above discrepancies were note February 29 0029 Unit-again entered Mode March 2 0248 Unit entered Mode March 3 0333 Channel A of the Plant Protection System was declared operable by a licensed operator, as documented on ECF 3-3112 March 4 0955 Unit entered Mode March 7 0100 Unit entered Mode Unit entered Mode (3) Concern:

Inadequate Implementation of Administrative Controls to ensure Operability of.the Plant Protection System following 18 Month

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Response Time Testin The inspector interviewed plant personnel and reviewed the

, followi.ng documentation:

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o S023-II-3.1 " Plant Protection System Response ~ Time Test i

for Channel A" Revision 3 (TCN 3-3).

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o SO23-0-23 " Equipment Status Control" Revision 5L(TCN 5-1).

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o- Equipment. Control Form ECF 3-3024 Based on the above review the-inspector noted the following:

! o S023-0-22.(Equipment Status Control) states:

<- "6. The Control Operator (CO) will' determine if the tests required in the requestor section of the' ,

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l f l Equipment Control Form'are completed 'and have the . ...

l- Work Authorization holder'or the_name of'the' person- .-

l accomplishing the work, placed in the " Tests . ,

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L Required" space. For equipeent important to Safety,. & return to service shall be documented in the.ECF." .

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"6.7.2 .The C0 shall ensure that the " Test Required" section is completed by the person (or persons) responsible for the testing activity following successful completion of the required test (s)."

".1 This signature signified the test has been successfully conducted."

"6. On completion of the task, the WA holder or the person accomplishing the work or surveillance is responsible for briefing the CO of the status the equipment or repair and, when applicable, completing the Post Maintenance Testing and release the Werk Authorization."

" If the work /surveillanca cannot be completed at this time, the WA holder should indicate and explain to the CO. The CO will check the " Remaining Open" box on the WA."

o It appears based on the requirements of this procedure that the following error was made in the completion of ECF 3-3024 ' ' '

In the Return to Servica section 6f Ech 3-30242, the

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Tests Required block is. signed off ast complete on February 3, 1984, thus indicating completion of this

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surveillance. However, based on. interviews with plant personnel, it appears that completion of'this

procedure did not occur until February 16, 1984, when

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the restoration step was completed. I,n1 addition;, ' the T 18 month surveillance itself was signed off, as was the Maintenance Order, on-16 February 1984 as being complete. Thus, it appears these.two' blocks on the(

equipment control form were signed.off prematurel This is an apparent item of noncompliance with the equipment control procedure (50-362/84-11-01).

The licensee has stated that this was done to-expedite the processing of the ECF to prevent a'back 4 log of forms at the end of the outag In addition, the licensee has stated that other ECFs (3-30184, 3-27737, 3-27710, 3-30923) were still active declaring the system inoperabl In each of these cases, however, an I&C technician had signed that these work items were completed _ prior to 3 February 1984, and again for each of these only a channel ~

check S023-3-3.25 was required which would not'

have identified the lifted leads. The licensee also stated that ECF 3-30301, to implement-S023-II-1.4 to test ESFAS Manual Trip button,.was to be initiated to require inoperability of PPS channel A from February 5,1984 . February 18, 1984. The licensee

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indicated that this was a reason that the PPS was not

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restored, thus leaving S023-II-3.1 incomplete while the ECF was signed off as being complete. The inspector's concern is that this practice is contradictory to the intent of control provided by the ECF documen The signing of this block provides a misleading input to the operators, who then performing a channel check, which is not designed to demonstrate operability without completion of the 18 month surveillance, erroneously considered the system operable with regards to the 18 month surveillance, when in fact it was no As a result of this documentation, a licensed operator documented the equipment as operable on i February 4, 1984 when in fact it was no Fortunately, the 31 day PPS surveillance was performed prior to startup and, fortunately, a mainteance person did note the abnormal condition on the UV coil (an observation which was not required by the 31 day PPS test and was not even included in the remarks section of this surveillance). This observation, which is to the credit of the individual involved, and the subsequent identification ~of the lifted leads by another I&C technician, to his credit, resulted in the. correction of the problem. The surveillance procedure and implementation of established administrative controls, however, were wea '

Observations by Inspector:

The inspector reviewed the completed 18 month surveillance (S023-II-3.1) and noted the following discrepancies:

o S023-II-3.1 Revision 3 (including TCN 3-3) ste '

1 6.19.32 states:

" Record.the largest value of steps ~ 6.19','24,'6.19.28, and 6.19.31 in the Data Collection Table

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(Attachment _9.4)." - This step requires the

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determination of-the most conservative-response, tim ' '

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for the high linear power safety channel re~spodse '

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tim '

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Contrary to the above requirement.a value of 0.125

.sec. rather 0.129 sec. was-recorded.in Step 6.19.24 of .

attachment 9.4. This error yielded a-recorded. total '

response time of 0.169 sec. vice 0.174 sec. which is,.

p_ 'however, within the_acceptan'ce criteria for_this ,

- instrument (0.40'sec). This item was undetected -by all t

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required reviews. including two documented supervisory reviews and a" documented Engineering revie ,

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. 1 o Step 6.46.34 states: l

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" Complete the Response Time Data Collection Table (Attachment 9.4). If more than one combination of j

. - integral response items exist in a given function, '

use the most conservative (longest) response time value when filling in.the Time Response Table."

This step was initialled by an I&C technician and ,

then lined out and was not subsequently reinitialled as complete; and as the error above shows was in fact not complete. This appears to be an inadvertent error which subsequent reviews failed to identif , The above two discrepancies raise serious questions regarding the adequacy and thoroughness of the review processes established and implemented by the '

licensee. This aspect of the licensee's operati was brought into question previously in NRC Inspection Report No. 50-361/83-15 as regarding the I

adequacy of valve lineup review o The documentation for the 18 month surveillance does not allow reconstruction of when various steps are performed. Since this procedure occurs over several weeks and no dates are. required for each step it is very difficult to relocate a sequence of events, o The restoration section of S023-II-3.1 is vague as. ~

to what the initials for various steps in this section are attesting to. The licensee has provided an interim clarification through the issuance of_ TCN 3-8, pending further review as discussed belo The licensee has established a program,-implemented by'

procedure S0123-VI-1.0 " Station Orders, Procedures and Instructions - Preparation, Revision, Review,_ Approved and Cancellation" (effective July 18, 1983), which addresses this concern in the following fashion. Each time a procedure goes through the revision process the signatures and initial blanks in the procedure are to be clearly labeled according to the type of action (" performed by"

" reviewed by" etc.) that.the signature is intended to document. Unfortunately, in the case of S023-II-1.1, although this process was required at the time of the last revision, it was not completed. The licensee-has stated that, although it:was intended that this aspect of this procedure be followed, due to other'

constraints (such as the need to get some-procedures revised quickly) this process has not always been followed. The '

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licensee is also re-evaluating the effectiveness of the

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o S023-II-3.1 step 6.47.1 is inadaequate in.that this

! step fails to be specific enough to clearly require the retermination of the eight lifted leads which were lef t determinated at the completion of this procedure. The licensee has corrected this deficienc o No independent verification that leads, which are required to be lifted by the procedure, are then reterminated was provided for in this procedure._-

License Condition 2.C.(17) of Facility Operating License No. NPF-15 states, in part, regarding NUREG-0737 Condition

"b", "... Procedures for Verifying Correct Performance of Operating Activities (I.C.6., SSR #1)

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Prior to fuel loading, .SCE shall implement a system for

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verifying the correct performance of operating activities, and shall keep the system in effect thereafter..."

NUREG 0737.in its clarification of I.C.6 states that an ,

acceptable program for verification of operating activities involving surveillance testing is the following provision of Section 5.2.6 of ANSI Standard N 18.7-1972 (ANS 3.2), draf t 5 Revision, ". . . Temporary .nodifications, such as temporary bypass lines, electrical jumpers, lifted leads, and temporary trip point settings, shall be controlled by approved procedures which shall include._a requirement for independent verification by either a second person or by a functional test which conclusively s proves the proper installation or removal of the temporary modification. A log, or other documented evidence, shall

.be maintained of the current status of such temporary modifications..."

Thus, the requirement for this independent verification is clea .

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However, since the licensee discovered the inadequacy of

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the procedure concurrently with the inspectors and has-expeditiously revised the 18 month surveillance

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to require a second check of restoration activities; no +

item'of compliance is warranted in accordance with NRC enforcement polic The licensee has also initiated a program to review.other procedures in the maintanence and surveillance area to assure that procedures which make systems or component inoperable ~are required to have either a second

! _ verification performed or an operability test:be require by the procedure before the' system or component is

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.declaredfoperabler .(OI 84-11-03)

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The inspector reviewed the completed 31 day PPS surveillance procedure S023-II-1.1 and noted the following discrepancies:

o S023-II-1.1 31 day was completed on February 28, 1984 with no comment in remarks section about metal flakes inside tha manual reactor trip button or anotation about

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4 lifted leads.in the PPS. This is due, in part,.to a failing in the procedure in that no acceptance criteria exists to verify proper tripping motion of the shunt

- UV trip when called upon in this procedure. Thus, the lifted leads were not identified by this procedure. The license corrected this deficiency on-26 March 1984 with the issuance of TCN 10- ' Interviews with I&C Technicians Eleven individuals from I&C were interviewej to determine their-interpretation of the meaning of a " Completed by" step in a procedure and also whether it is permissible to sign such a step when another had completed the actual work function. All individuals were asked if they were aware of a station or company policy on signing for-a steplin a procedure and also.if the individual could recall of signing a procedure step for another technicia The end product of the interviews-indicated that ten of_the-J eleven individuals believed it is permissible for a technician-

! to sign a ' completed by' step in a procedure for his peer when'it

! was communicated to the technician that~the step is completed.

, The ten individuals also professed varying degrees of l verification, which they believed necessary to be'comple,ted

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i s s before signing a ' completed by' step (consisting of either  ;

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,- personal verification by observation.of the equipment, or^just ~

l requesting concurrence of their supervisor;before signing). -

One. individual stated that, to his knowledge, there was no u

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company policy which allowed an. individual,who,did not. perform - r;

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step when the technician.has not performed the work activity: ., ,

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This concern applies to work evolutions which would extend + -

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- Obviously there exists work activities which require.more than

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would be communication between all technicians involved who perform that work. An example of such an activity would be the

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excore nuclear instrument surveillance procedure where during the performance of the activity there could be as many as four or five technicians (all at different locations throughout the

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containment, at the instrument cabinet and the control room) but only one technician would sign the completion step in the procedure. The situation here is that although several persons may be involved in_the activity, only one person who had coordinated the activity and was aware by personal knowledge of the activities of the other individuals involved would sign the ste During a shift ~ turn'-over, however, there does not exist an extensive communication path between shif ts to transfer information because the turn-over process for I&C is not a formal requirement. This would allow some information, such as remaining steps to be completed, to never be passed to the oncoming shif Because a policy apparently exists allowing another technician to sign for someone else who completes the work activity without a formal transfer of information, there is a great possibility that a step may be signed as completed before all work was truly complet ,

Based on interviews with I&C personnel, it appears that the -

signature policy puts all the burden and responsibility on the working level individual to assure that if he signs for another's work he must do what is "necessary" to ensure it is done; even though the necessary requirements have not been formally defined. Little emphasis appears to be placed on first and second level supervising responsibility to monitor this risky practice to assure adequate judgement is used to .

prevent failur The issue of a technician signing a procedural step and:not having completed the work activity personally will remain as-an open item (50-362/84-11-04) until the NRC staff can complete a further revie . IE Bulletin Follow-up (IEB 82-04) Based on a review of the licensee's response to this bulletin dated March 3,- 1983, 'the inspector determined - /

that this bulletin is not applicable to Unit 2/3 since Bunker'

Ramo containment electrical penetration's are not installed or-planned to'be installed at Units: 2 and 3. _This item is close . . Exit Meeting  ! <

, ,0n April 17, 1984,'an exit meeting was conducted with the licensee ~ ~

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representatives identified in paragraph 1. The inspectors summarized-the scope of the inspection and findings as described in thistrcpor '

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, The licensee acknowledged the apparent item of noncompliance contained-in paragraph 9 of this report.

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