ML20202E901

Insp Repts 50-361/97-27 & 50-362/97-27 on 971221-980131. Violation Noted.Major Areas Inspected:Licensee Operations, 21int,engineering & Plant Support

ML20202E901
Person / Time
Site:	San Onofre
Issue date:	02/11/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20202E892	List: ML20202E888 ML20202E894 ML20202E901
References
50-361-97-27, 50-362-97-27, NUDOCS 9802190083
Download: ML20202E901 (19)

See also: IR 05000361/1997027

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ENCLOSURE 2

L U.S. NUCLEAR REGULATORY COMMISSION

L REGION IV -

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Docket Nos.: 50-361

50 362

License Nos.: NPF 10

NPF-15

Report No.: 50 361/97-27

50-362/97 27

Licensee: Southern California Edison Co.

Facility; San Onofre Nuclear Generating Station, Units 2 and 3

Location: 5000 S. Pacific Coast Hwy.

San Clemente, California

Dates: December 21,1997, through January 31,1998

Inspectors: J. A. Sloan, Senior Resident inspector

J. G. Kramer, Resident inspector

J. J. Russell, Resident inspector

Approved By: Dennis F. Kirsch, Chief, Branch F

Division of Reactor Projects

ATTACHMENT: SupplementalInformation

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EXECUTIVE SUMMARY

San Onofre Nuclear Generatic a Station, Units 2 and 3

NRC Inspection Report 50 361/97 27; 50-362/97-27

This routine announced inspection included aspects of licensee operations, maintenance,

engineering, and plant support. This report covers a 6-week period of resident inspection.

Ooerations

. Operations during this inspection period were characterized by improved

communicaticr. among operators, continued frequent Operations management

monitoring of activities, and conservative decision making. Operational activities were

well-ple ted, and prejob briefings were thorough (Section 01.1).

. Operator responses to an inadvertent Unit 2 loss of condensate polishing flow, a Unit 3

ground on a nonsafety-related electrical bus, anu a Unit 3 complete loss of the core

operating limits supervisory system (COLSS) were excellent, All of these off normal

conditions occurred during a short time period. The availability of extra reactor

operators enabled normal control board monitoring to occur during the responses

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(Section 01.2).

• During the planned reactor shutdown of Unit 2 for the midcycle outage, several

strengths were oisserved. Operator communications were thorough and complete,

augmented staffing was effectively coordinated, and supervisory oversight was evident.

The use of scripting to help coordinate activities was effective. Performance of the

standard posttrip actions was formal and professional (Section 01.3).

- The permanent reduction of reactor coolant system (RCS) cold leg temperature (T-cold)

was well planned and smoothly executed. The prejob briefing was very thorough

(Section 01.4).

. Operators performed preparations for, and entry into, midloop conditions in a thorough

and safety conscious manner. RCS Level monitoring practices and performance

improved since the previous period of midloop operations. Management oversight was

continuous and effective, and contingency plans were in place. The time-to-boil

calculation results were inconsistent, but conservative, due to an operator's error and

sone minor differences in the calculation methodology between operators. Overall

performance for the drain to midloop was outstanding (Section 01.5).

- Dunng routine operator rounds a nuclear plant equipment operator (NPEO) was

attentive and thorough. Communications with the control room were frequent and

effective. Although some minor material deficiencies were first observed by the

inspectors, the NPEO's responses to the conditions were rigorous. The NPEO's use of

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the hand-held computer's trend capability to identify a potential degrading condition was

outstanding (Section 04.1)(

• : Local monitoring of emergency diesel generator (EDC peration was weak because a

. high fuel fiar differential pressure condition went unnwiced immediately after an EDG

start, until brought to Operations' attention by the inspectors.: This was largely because1 4

EDG operating logs were not programmatically taken until the EDG had been operating -

for about 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, and because th ' :al annunciator failed to remain illuminated, even

- though the fuel filter differential p sure was about 13 psid above the annunciation;

setpoint (Section O4.2). i

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Maintenance

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• A detailed walkdown of_the component cooling water (CCW) system revealed that the -

overall external material condition was excellent, with only minor deficiencies observed

(Section 02.1).

• J - A aoncited violation was identified based on the licensee's determination that

procedures had not been adequately followed in 1993 for inspecting the lubricant---

volume in a safety-related motor-operated valve actuator. The licensee's corrective

- actions were broad and thorough (Section M2.1).

Engmeering

• - The licensee's operability assessment for a motor-operated valve actuation that had

. insufficient lubricant was thorough, soundly based, and well documented (Section M2.1).

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. The licensee's evaluation of the core damage probability (CDP) for the planned Unit 2

midcycle outage was thorough. The recommendations of the Nuclear Safety Group -

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. resulted in the implementation of changes to reduce risk in the planned outage, with little

impact on outage operations (Section E1.1).

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The facility change evaluation (FCE) for the RCS T-cold temperature reduction was

thorough (Section E1.2).

-* -.The initial operability astessment of seismically unsecured fire _ extinguishers in the

Unit 2 containment, performed by design engineers, was weak, because it did not

address all fire extinguisher locations and was not rigorous in supporting conclusions -

that the fully charged extinguishers did not represent missile hazards (Section F2.1).

Plant Sucoort

. The inspectors identified that a Unit 2 safety injection tank (SIT) sample isolation valve

located in containment had not been fully closed after a sample had been drawn,

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resuiting in minor leakage from the sample point. This indicated a weakness in attention

to detail on the part of the chemistry technician performing the sample (Section R4.1).

• The inspectr.,.. .uentified that the licensee failed to ensure that 3 fire extinguishers left in -

Unit 2 containnient during Mode 1 operations were properly seismically secured.

Ultimately, the licensee determined that 7 out of 32 fire extinguishers in Unit 2

containment were not properly restrained. This was a violation of the licensee's seismic -

program requirements (Section F2.1).

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flagert Details

Summary of Plant Status -

Unit 2 began this inspection period operating at 80 percent power. On December 22,1997,

following repairs to a failed circulat ng water pump motor, power was increased to 100 percent.

The unit operated at essentially 100 percent power until January 24,1998, when the unit was

shut down for a planned midcycle outage to irspect the steam generators. The RCS was

drained to midloop conditions on January 27i 1998, and the unit operated in Mode 5 at midloop

' for the rest of the inspection period.

Unit 3 operated at essentially 100 percent reactor power throughout this inspecuon period.

l. Operations

01 Conduct of Operations

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01.1 General Comments (71707)

The inspectors observed routine operational activities throughout this inspection period.

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Some of the activities observed included:

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• Shift tumovers (multiple observations)

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NPEO rounds (Unit 2) (one observation)

• Projob briefing for a permanent reduc' ion of RCS T-cold (Unit 2)

'* Preparations for draining the RCS to midloop (Unit 2)

- NPEO response to leaking spent fuel pool isolation valve (Unit 2)

• lsolation and restoration of atmospheric dump valve nitrogen system (Unit 2)

- Routine control room activities (multiple observations)

• Daily manager's meetings (multiple observations)

Operations during this inspection period were characterized by improved

communications among operators, continued frequent Operations management

monitoring of activities, and conservative decision making. Operational activities were

well-planned, and prejob briefings were thorough.

01.2 Control Room Ooerator Resoonse - Units 2 and 3

a. Insoection Scoce (71707)

On January 9,1998, the inspectors observed Units 2 and 3 control room operators

responding to various off-normal conditions.

b. Observations and Findinos

Unit 2 operators responded to an inadvertent opening of a condensate full flow polishing

demineralizer bypass valve. This bypass valve opening occurred during maintenance

on a condensate demineralizer controller. Unit 2 operators reestabliched condensate

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demineralizer flow by allowing the secondary system to stabilize and then gradually

shutting the bypass valve.

The common control operator performed ground isolation for 480 Volt non-Class 1E

Dus 3807, which had developed a ground.

Unit 3 operators responded to a complete loss of the COLSS. Normal COLSS failed

when the plant monitoring system failed due to an intermittent failure of an internal

communication link. The plant monitoring system providas data for the Technical

Specification (TS)-required normal COLSS Backup COLSS was out of service for a

scheduled surveillance. Unit 3 operators correctly implemented all monitoring required

by TS, and then terminated the backup COLSS surveillance and returned backup

COLSS to service.

The inspectors found that, for each condition described above, operators correctly

31iagnosed the condition and promptly took actions to correct the condition. Use of

rocedures, and compliance with TS, was excellent. Communications between

operators was good, and supervision by the Unit 2 and Unit 3 control room supervisors

was excellent. Two additional reactor operators (in addition to the two normally

assigned to the unit) assisted in performing the TS-required Unit 3 monitoring, allowing

normal control board monitoring.

c.s Conclusions

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Operator responses to an inadvertent linit 2 loss of condensate polishing flow, a Unit 3

ground on a nonsafety-related electrical bus, and a Unit 3 complete loss of the COLSS

system were excellent. All of these off-normal conditions occurred dunng a short time

period. The availability of extra reactor operators enabled normal control board

monitoring to occur during the "esponses.

01.3 Reactor Shutdown for Midevcle Outaae (Unit 2)

a. Insoection Scoce (71707)

On January 24,1998, the inspectors observed operatora reduce power from 60 percent

and shut down the reactor in preparation for the Unit 2 midcycle outage.

b. Observaticns and Findinos

The shutdown immediately folicwed completing heat treating the salt water cooling

system, which had left the unit at approximately 80 percent power.

Several extra operators were on shift to support the planned shutdown. Additionally,

Operations management was in the control room providing supervisory oversight, and

reactor engineers were in the control room monitonng and advising operators regarding

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reactivity lasues. Throughout the evolution, the control room supervisor and control

operator coordinated the activities of the support personnel effectively and efficiently.

Communications between operators during the evolution were consistently formal and

complete.- Only one instance was observed in which licensee management

- expectations for communications wat not met.

Operators closely monitored the power reduction rate to schieve an almost steady

15 percent per hour, which was the target rate.

The licensee had prepared a detailed script of the anticipated activities, including start i

and completion times, associated with the shutdown. The script paralleled, but did not

replace, the procedures. The script was very accurate, and assisted in coordinating

- activities during the shutdown.

The reactor was manually tripped from anproximately 15 percent power in accordance l

with licensee procedures. Following the reactor trip, the operators performed the

standard posttrip actions in a formal and professional manner, ,

c. Conclusions

During the planned reactor shutdown of Unit 2 for the midcycle outage, several;

• strengths were observed. Operator communications were thorough and complete,

augmented staffing was effectively coordinated, and supervisory oversight was evident.

The use of scripting to help coordinate activities was effective. Operators-in-training

were properly supervised as they performed reactivity manipulations.- Performance of

the standard posttrip actions was formal and professional

01.4 Permanent Reduction of RCS T-cold (Units 2 and 31

a. insoection Scoce (71707)

The inspectors observed the prejob briefing for the permanent reduction of RCS T-cold

in Unit 2 on January 20,1998. The inspectors reviewed plant parameter trends of the

temperature reductions in both units.

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b. Qbservations and Findinos

The licensee implemented a permanent reduction in RCS T-cold from 553 *F to

approximately 548 'F (until turbine control valves were wide open) on January 20

and 29;1998, in Units 2 and 3, respectively.

The licensee consulted its vendors and detemiined that the only set point that needed to

be changed to support the reduction was in the nonsafety-related steam bypass control

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system, in order to maintain the existing load reject capacity. The licensee implemented

the required set point change within one day of the temperature reduction in each unit.

The prejob briefing addressed procedural controls, roles and responsibilities, and

management expectations. Expected plant response was addressed with respect to

reactivity, power distribution, power indications, RCS flow, operating margins, RCS

inventory. pressurizer pressure, feedwater control, steam bypass control system issues,

secondary plant response, and electrical output.- Expected alarms were identified, and

termination criteria for the evolution were specified.

c. Conclusions 1

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The implementation of a permanent reduction of RCS T-cold was well planned and

smoothly executed. The prejob briefing was very thorough. Comments regarding the

field change evaluation associated with the reduction are in Section E1.2.

01.5 Midlooo coerations (Unit 2)

a. Insoection Scooe (71707)

The inspectors observed the preparations for, entry into, and steady state operation in

midlooo conditions in Unit 2.

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b Observations and Findinos

The licensee utilized a closed circuit television monitor to remotely monitor the reactor

water level sight glass. Operations installed a mor ' 5 the continuously-manned

Operations work process control area, and estabbed an expectation that the sight

glass level be observed at least once every 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. This was a significant

improvement in the sight glass level monitoring capability since the 1997 outages.

The prejob briefing for the drain to midloop was thorough, addressing planned and

contingent conditions and expected responses. Because of the short time-tr boil

(17 minutes) at the time of the draindown, extra operators were assigned to remain in

the radiologically controlled area ready to vent the shutdown cooling system if needed.

Prior to commencing the draindown, the licensee ensured that all the level indicating

systems were properly aligned and calibrated.

The draindown was perform . ' on January 27 and 28,1998. Two reactor operators and

an Operations manager in tt.a control room, in addition to the normal crew, assisted in

the draindown. Levelindication available included a reactor level monitoring system, a

diverse level monitoring system, a local sight glass, and incore reactor thermocouples.

Attention by the operators to this instrurnentation, and the agreement of the

instrumentation, was excellent. A hold point at 36 inches in the 42-inch hot leg was

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I used both to ensure that the instrumentation was correlating properly, and to calculate

- the time to-boiling at 26 inches in the ' lot leg. Based on continuous observation of the

evolution, the inspectors found that control room staffing and attention to level

indications were excellent.

Control room operators calculated the time-to-boil with 26 inches level in the hot leg (the

targat level) while at the 36-inch hold point mentioned above. The data for the

calculation was contained in Procedure SO23 5-1.8.1, " Shutdown Nuclear Safety,"

Revision 5, in a table of time since shutdown and time to-boil at 26 inches, with a- l

correction factor for core exit temperatures other than 120 'F. The control room

operators calculated a time-to-boil of 17.3 minutes at 1:58 a.m. on January 28,1998,

with core exit average temperature of 118.6 'F, The inspectors performed the same

calculation and determined that the operators had made a minor error in correlating time

since shutdown to fractions of days, mistaking 1:58 a.m. for 12:58 a.m. Also, the

inspectors calculated a 17.2 minute time-to boil, using a smaller interval of the nonlinear

time-to-boil numbers for interoolation than the operators had used. The inspectors also

' observed that the calculation was performed by two operators working together, and the

- calculation was not independently verified. The inspectors found that the time-to-boil-

was greater than 17 minutes (the minimum time), but that errors occurred in performing

the calculation.

c. Conclusions

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Operators performed preparations for, and entry into, midloop conditions in a thorough -

und safety-conscious manner. Level monitoring practices and performance improved

since the previous period of midloop operations. Management oversight was continuous

and effective, and contingency plans were in place. The time-to-boil calculation results

were inconsistent, but conservative, due to an operator's error and some minor

differences in the calculation methodology between operators. Overall performance for

the drain to midloop was outstanding.

02 Operational Status of Facilities and Equipment

O2.1 CCW System Walkdown - Units 2 and 3

a. Insoection Scoce (71707)

The inspectors performed a walkdown of the Units 2 and 3 CCW system. The

inspectors reviewed Procedure SO23-3-3.18, " Component Cooling / Saltwater System

Tests," Revision 8; Document DBD-SO23-400, "CCW System Design Bases

Document," Revision 5; and CCW piping and instrument Diagrams 40127A through

40127G.

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b. Observations and Findinos

The inspectors reviewed Procedure SO23 3-3.18 and determined that the alignment

verifications irmleded the necessary valves to ensure compliance with TS Surveillance

Requirement 3.7.7.2. Surveillance Requirement 3.7.7.2 required the licensee to verify

that each CCW valve i the flow path servicing safety-related equipment was in the

correct pcsition.

The inspectors verified that the CCW valves were in their correct position. However, the

inspectors identified severallabeling discrepancies. The inspectors observed that a

majority of the control room and local valve identification tag noun names did not match

Procedure SO23-3 3.18, and in some cases the procedure noun name did not

completely describe the valve. For example, the procedure noun name for

Valve S21203MUOO9 was " Containment Spray Pump." The localidentification tag noun

name for Valve S21203MU009 was "CNTMT Spray Pump 2P012 CCW Supply ISO." in

addition, the inspectors observed several instances of handwritten valve position

identification marks on the valves. The inspectors discussed the discrepancies with the

Operations supervisor. The inspectors concluded that, although the valve identification

tag did not match the procedure, sufficient information (valve number and noun name)

was available to the operators to ensure proper valve operation.

The inspectors identified several valve deficiencies. The local position indication for

Valve 3HV6212 was missing. Valve 3HV6222A had a grease leak both on the drain

plug and where the motor fastens to the actuator housing. Valves 3HV6221 and

3HV6551 had their manual handwheel clutch levers positioned aga;nst electrical

conduits. TM local position indicator for Valve 3HCV6537 indicated 15 percent open

when the valve was, in fact, closed. The inspectors discussed the discrepancies with

Operations management.

During the review of the piping and instrument diagrams, the inspectors observed

transition errors between sheets.

Operations management initiated Action Requests (AR) 980100471 through 980100474,

and 980100965, to address the inspectors' concerns,

c. Conclusions

The CCW system contained minor differences between local valve identification tags

and the monthly alignment procedure. In addition, several valve deficiencies were

identified by inspectors during a system walkdown and were appropriately addressed by

the licensee. The overall external material condition of the CCW system was excellent.

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04 Operator Knowledge and Performance

Cr 1 NPEO Rounds (Unit 2)

a. Insoection Scoca (71707)

On January 11,1998, the inspectors observed the inside portion of the Unit 2 primary

NPEO (Position 23) rounds,

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b. Observations and Findinos

Prior to initiating the rounds, the Unit 2 control operator briefed the NPEO on specific

activities that needed to be performed in conjunction with the normal rounds. The

NPEO was properly equipped and prepared for the assigned rounds.

The NPEO demonstrated thorough familiarity with the hand-held computer utilized to ,

record the data from the rounds. Prior to initiating the inside rounds, the NPEO

identified an adverse equipment trend (declining pressure in the CCW backup nitrogen

system) utilizing the data trending function of the hand-held computer During the

rounds, the NPEO utilized th computer to take notes and record required data. The a

NPEO also demonstrated flexibility la changing the sequence of the rounds, which was

controlled by the computer.

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Several minor material deficiencies were identified by the inspectors during the tour

(missing fasteners, nicked insulation, and boric acid buildup on components), in each

case the NPEO promptly documented the deficiency and initiated ARs as warranted.

The NPEO properly investigated water leakage observed from a spent fuel pool fill

valve, including obtaining Health Physics support to confirm that the water was not

contaminated.

The NPEO frequently communicated with the control operator during the rounds

regarding identified deficiencies and coordination of activities.

c. ' onclusions

During normal rounds the NPEO was attentive and thorough. Communications with the

control room were frequent and effective. Although some minor material deficiencies

were first observed by the inspectors, the NPEO's responses to the conditions were

rigorous. The NPEO's use of the hand-held computer's trend capability to identify a

potential degrading condition was outstanding.

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04.2 Local EDG Monitorino

a. _Insoection Scoce (61726)

On January 14,1998, the inspectors observed Unit 2 operators perform portions of

Surveillance Procedure SO23 3-3.43.17,"ESF Subgroup Relay K-401B Semiannual

Test," Revision 3, concurrently with Surveillance Procedure SO23 3 3.23, " Diesel

Generator Operation," Temporary Change Notice 13-1, Attachment 1. This was a

semiannual TS-required fast start of EDG 2G003, as well as a verification of proper

operation of engineered safety features subgroup Relay K-4018, which provides for,

among other functions, an EDG start on a safety injection actuation signal.

b. Observations and Findinos

The inspectors observed EDG 2G003 start locally Approximately 30 seconds after the

EDG started and achieved rated speed and voltage, the inspectors observed that local

annunciation of " engine Number 1 fuel filter restriction" illuminated and then reflashed,

indicativo of a condition present, then cleared. The EDGs are tandem machines with

two engines coupled to one generator. At the same time as the annunciation described

above, the EDG momentarily increased frequency from 60 hertz to about 61 hertz. The

licensee later explained this oscillation was due to a transfer of EDG speed control from

an automatic safety injection actuation signal control circuit to a control room control

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circuit. The inspectors alerted the NPEO monitoring the EDG locally to the

! annunciation. The NPEO reset the reflashing annunciator, but made no immed ate

attempts to investigate fuel filter differential pressure. Operations personnel did not

observe the mon'entary increase in frequency. The inspectors then observed that local

engine Number 1 fuel filter differential pressure was about 63 psid, as indicated on

Gauge 2PDl5937D. The annunciation setpoint was 48 psid, and the Operations log

specification was less than 50 psiti. Despite the high differential pressure, local

annunciation failed to reflash or to raain illuminated.

The NPEO reported the high differential pressure to control room operators. In

accordance with the local annunciator tv.ponse procedure, the right fuel filter, which

had been in service, was removed from service, and the left fuel filter was placed in

service. Each EDG engine has two fuel filters, which may be placed in service

individually or in parallel. Fuel filter differential pressure dropped to about 36 psid.

Operations personnel initiated ARs both to investigate the lack of local annunciation

when fuel filter differential pressure was greater than its indicated setpoint, and to

replace the right fuel filter. The inspectors found that this action was satisfactory;

however, they also found that local EDG monitoring was weak in that the off-normal

condition was not observed by licensee operators, until brought to their attention by the

inspectors. As a result of this, and previous observations of local EDG monitoring, the

inspectors found that NPEOs were require 1 to complete a set of local EDG operating

logs about 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after EDG start, but weie not required to monitor these same

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parameters immediately after EDG start. Consequently, if an off-normal condition did

not lead to local annunciation, the condition could go unnoticed, as described above.

c. Conclustom

Local monitoring of EDG operation was weak because a high fuel inter differential

pressure went unnoticed immediately after an EDG start, and until brought to

Operations attention by the inspectors. This was largely because EDG operating logs

were not programmatically taken until the EC'G had been operating for about 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />,

and because local annunciation failed to remaia illuminated, even though the fuel filter

differential pressure was abots 13 psid above t ie annunciation setpoint.

05 Operator Training and Qualification

05.1 Reactivity Manioulations by Ooerators-in-Trainina (Unit 2) (71701)

During the reactor shutdown of Unit 2 on January 24,1998, the inspectors observed

three operators-in-training performing reactivity manipulations.

The assistant control operator thoroughly reviewed expected plant responses with each

of the operators before the manipulations. The assistant control operator closely

monitored performance of the manipulations, and verified that the expected responses

were achieved.

The inspectors concluded that the supervision of the operators-in-training was

consistent with regulatory requirements and licensee expectations.

II. Meintenance

M1 Conduct of Maintenance s

M1.1 General Comments

a. Insoection Scoce (62707)

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

. Calibrate control room ammeter for saltwater cooling Pump 2P307 -Unit 2

. Replace saltwater cooling Pump 2MP112 moter - Unit 2

. Change out nitrogen bottles for atmospheric dump Valve 8419 - Unit 2

- Clean and plug e 'eaking tube in CCW Heat Exchanger 2ME002 - Unit 2

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bc Observations and Findings -

r - The inspectors found the work performed under these activities to be thorough. All work

observed was performed with the work package present and in active use. Technicians

were krsowledgeable and professionalc.The inspectors frequently obsewed supervisors -

and system engineers monitoring job progress, and quality control personnel were

present whenever required by procedure.- When applicable, appropriate radiation

controls were in place.

in a.idition, see the specific discussions of maintenance observed under Section M2.2,

belaw.

M1.2 General Comments on Surveillance Activities

a. 'nanection Scone (61726 and 71707)

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

t Engineered safety features subgroup Relay K-401B semiannual test - Unit 2 -

• Saltwater cooling Pump 2MP112 pump and valve test - Unit 2

+ Control element assembly position verification - Unit 2

• Atmospheric dump valve weekly checks- Unit 2

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~ The inspectors found all surveillances performed under these activities to be thorough.

. All sumeillances observed were performed with the work package present and in active

use. Technicians were knowledgeable and professional? The inspectors frequently -

observed supervisors and system engineers monitoring job progress, and quality control

personnel were present whenever required by procedure. When applicable, appropriate

radiation controls were in place.

ln addition, see the specific discussions of surveillances observed under Sections 04.2 -

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M2 Maintenance and Mateilal Condition of Facilities and Equipment

M2.2 Motor-Ooerated Vane Actuator Lubrication (Unit 2)

a. Insoection Scoce (37551 and 62707)

On December 29,1997, the licensee identified that the mote. aperated valve actuator

for Valve 2HV8162 the low pressure safety _ injection Pump 2P015 miniflow block valve,

had very little lubricant. The inspectors reviewed the licensee's evaluation and response

to this condition.

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b. Observations an1 Findinas

During performance of routine maintenance on December 29,1997, the licensee

identified that the actuator main housing of Valve 2VH8162 had very little lubricant, and

that the worm and worm gear were not immersed. The licensee documented this

condition in AR 97120157d.

The worm and worm gear had been replaced in 1993 (Cycle 7 refueling outage). The

preventive maintenance frequency for the actuator is 3R (every third refueling cycle),

and was scheduled for the next (Cycle 10) refueling outage.

The as-found motor-operated valve testing performed in December 1997 did not reveal

any degradation or anomalies. The licensee determined that the valve performance

was well within the margin requirements for valves in the Generic Letter 89-10

motor-operated valve program.

The valve is normally locked open, except during shutdown cooling operation, and is

infrequently operated. The licensee estimated that the valve had been cycled

approximately 20 times, primarily for quarterly inservice testing, since the 1993

overhaul. The licensee reviewed the results of the stroke timing tests since 1993 and

did not identify any adverse trend.

In response to the 1997 identification of insufficient lubrication, the licensee replaced the

worm and worm gear with new parts, refilled the actuator with lubricant, and performed

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as-left testing. Additionally, the licensee determined that past performance of

maintenance on Valve 2HV8162 had not been satit. factory, in that the as left

motor-operated valve testing in 1993 should have identified the deficiency, and that the

lubricant level had been checked on June 27,1993, and incorrectly documented as

satisfactory. Specifically, Procedure SO123-1-8.28, Temporary Change Notice 0-15,

was performed under Maintenance Order 921001237, and Step 6.2.2, that required

checking the lubrication level, was marked as complete and satisfactory. The licensee

documented in AR 971201574 that the step had been performed inadequately. This is a

violation of TS 6.8.1 (of the TS in effect at that time) for failure to follow procedures.

This nonrepetitive, licensee-identified and corrected violation is being treated as a

noncited violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy

(NCV 50-361/97027-01).

The licensee inspected the worm and worm mar after they were removed and

determined that they were not damaged c- aded. The licensee stated that the parts

were initially supplied with a light coating t cant that may account for the lack of

degradation.

The licensee performed an operability assessment and determined that the valve was

operable during the time that it was inadequately lubricated.

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AR 971201574 states that the licensee will inspect all the other safety-related

motor-operated valve actuators that had similar maintenance during the Cycle 7 outages

and have not since been inspected. Other corrective actions included counseling the

personnelinvolved with the previous maintenance of Valve 2HV8162 and reviewing

expectations for self- and crost checking with the electricians,

c. Conclusions

A noncited violation was identified based on the licensee's identification that procedures

had not been adeauately followed in 1993 for inspecting the lubricant volume in a

safety-related motor operated valve actuator. The licensee's operability assessment for

the recently identified condition was thorough, soundly-based, and well documented,

and the corrective actions were broad and thorough.

til. Enaineerina

E1 Conduct of Engineering

E1,1 Probabilistic Risk Assessment of Planned Midevele Outaae (Unit 2)

a. Insoection Scone (37551 and 62707)

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The inspectors discussed the licensee's Probabilistic Risk Assessment evaluation of the

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Unit 2 mic' cycle outage planned to begin in late January 1998, based on the preliminary

outage scheduie, and reviewed the recommendations made by the Nuclear Sofety

Group to minimize the outage risks. The inspectors also reviewed the licensee's

comparisons of the CDP for various significant attematives to the planned schedule.

The inspectors participated in a January 14,1998, conference call between licensee and

NRC personnel discussing outage plans.

b. Obse vations and Findinas

The outage plan included 19 days of operation at midloop, with RCS level at

approximately 26 inches above the bottom of the hot leg. This period of midloop

operations was the primary contributor to the outage cumulative CDP, determined to

be 1.,5-5. The outage was planned to last 30 days.

The licensee determined that if the plan were revised to install nozzle dame, the period

of midloop operations would be reduced to approximately 10 days, the outage would be

extended by 1 day, and the CDP would be slightly reduced, to 1.2E-5.

The licensee also determined that the CDP for an alternative plan to operate at 19

inches above the bottom of the hot leg for 19 days would be 2E 5.

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The licensee determined that performing a full-core offload would substantially extend

the outage duration, but would reduce the period of midloop operation to 12 days, and

would reduce the CDP to 4E-6.

The recommendation made by the Nuclear Safety Group and incorporated into the

outage plan during midloop operation included maintaining both trains of emergency

core cooling equipment available, running both trains of saltwater cooling and

component cooling, aligning the containment spray pumps to backup the low pressure

safety injection pumps when conditions permit, and eliminating all switchyard work from

the outage during midloop operations, Several other recommendations were also made

and incorporated into the outage plan.

The licensee determined that the CDPs for all the options reviewed were below the

annual outage risk goal cf 3E-5.

c. Conclusions

The licensee's evaluation of the CDP for the planned Unit 2 midcycle outage was

thorough. The recommendations of the Nuclear Safety Group resulted in reduced risk,

in the planned outage, with little impact on outage operations.

E1.2 FCE for RCS T-Cold Reduction (Units 2 and 31

a. insoection Scoce (37551)

The inspectors reviewed FCE 2/3-97-003, Revision 0, *RCS Tcold Reduction of 5 5,"

that documented the licensee's evaluation of a permanent reduction in RCS Tvold,

b. Observations and Findines

The FCE clearly and thoroughly documented the reason for the change; the functional

objective of the change; the impact of the change on site programs, operations, and

procedures; and various aspects of design criteria that could be affected.

The licensee obtained an evaluation of the temperature reduction from Asea

Brown-Boveri, which was referenced in the FCE. The significant contnbution of the

vendor evaluation was the identification of the impact on load reject capability, which

emuld be compensated for by changes to the steam bypass control system settings.

The 10 CFR Part 50.59 safety evaluation was thorough and rigorous. The FCE included

change requests for the Updated Final Safety Analysis Report and for the RCS design

basis document.

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c. Conclusions

The FCE for the permanent reduction of RCS T-cold, including the 10 CFR Part 50.59

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safety evaluation, was thorough. Implementation of the temperature reduction is

discussion in Section 01.4.

IV, Plant Suonort

R4 Staff Performance and Knowledge in Radiological Protection and Chemistry

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R4,1 Laakina Samole Point - Unit 2

a. insoection Scone (71707 and 71750)

On December 18,1997, the inspectors accompanied licensee Engineering personnel

during a walkdown of Unit 2 containment outside the bioshield,- The unit was at full

power,

b. Observations and Findinos

Licensee personnel performed the walkdown in order to identify boric acid leaks prior to

the upcoming midcycle outage. Concurrent with this walkdown, a chemistry technician

sampled the SITS for boron concentration.

The inspectors identified that the SIT 2T008 sample point was leaking about 10 drops

per minute. The sample line was routed to a funne'. The funnel was routed to a floor

drain on the 45-foot level of containment that apparently was clogged. Water was rising

in the vertical path of the drain, and the drain filter plate was dislodged from the drain

opening and situated in the bottom of the vertical portion of the drain. 'ihe inspectors

informed the engineers of the leaking SIT sample point and the clogged drain. The

engineers reopened, then closed, the sample isolation valve, stopping the teck. The

engineers also evaluated the drain. The inspectors found that the chemistry technician

had weakness in attention to detail in not ensuring the sample isolation valve .vas fully

closed,

c. ConclusioQs

While in Unit 2 containment during Mode 1 operations, a chemistry technician failed to

ensure that a safety injection tank sample isolation valve was fully closed after drawing a

sample. This resulted in minor leakage from the sample point. The condition was

identified by the inspectors, indicating a weakness in attention to detail on the part of the

chemistry technician.

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F2 Status of Fire Protection Facilities and Equipment

F2.1 Unrestrained t: ire Extincui3hers Inside Containment - Unit 2

a. inspection Scoce (71707 and 71750)

On December 18,1997, the inspectors accompanied licensee Engineering personnel

during a walkdown of Unit 2 containment outside the bioshield. The unit was at full

power. Licensee personnel performed the walkdown in order to identify boric acid leaks.

b. Observations and Findinas

The inspectors checked four fire extinguisher cabinet doors during the walkdown. The

inspectors observed that fire extinguisher Cabinet Numbers 14,17, and 18 contained

doors that were not latched and were free to move. The design function of the fire

extinguisher cabinet doors was to provide seismic restraint to the fire extinguishers

inside the cabinets. The cabinets did have small frames that would prevent some

extinguishers from falling out of their cabinets, but the frames were not sufficient to, nor

intended to, restrain the extinguishers during vertical vibration caused by a seismic

event. On January 9,1998, Fire Protection engineers entered Unite and 3

containments to fully investigate the extent of the issue, in addition to the doors

mentioned above, the engineers found that Unit 2 fire extinguisher Cabinet Doors 1,5,

10, and 26 were not latched and were free to move. All of these cabinets contained

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latches that were loose except Cabinet 1 (which was not loose) ano Cabinet 26, which

did not have a latch installed. The Fire Protection engineers tightened the loose latches,

closed alllatches, and secured Cabinet 26 with plastic tie wrap.

All Unit 3 containment fire extir,guisher cabinet doors were found closed and latched.

The licensee determined that the cabinet doors in Unit 3 containment had a different

type latch than those in Unit 2 containment.

There are 32 fire extinguishers cabinets in Unit 2 containment outside the bioshield.

Cabinets 1,5,10, and 17 contained 800 psig,20 pounds weight, carbon dioxide

cylinders. Cabinets 14,18, and 26 contained 195 psig,20 pounds weight, dry chemical

cylinders. Cabinet 10 was located about 2 feet away from Valve S21219MUO93, a

refueling cavity drain valve. The other locations did not contain any large valves within

4 feet. Licensee engineers assumed that a cylinder would be restricted to a 4-foot

radius if it fell from a cabinet.

After initial discovery by the inspectors on December 18,1997, licensee design

engineers performed an operability assessment of the three specific fire extinguisher

locations identified by the inspectors (AR 971201140). The engineers determined that,

although seismic configuration was not maintained, the pressurized fire extinguishers

did not pose a risk to nearby equipment. The inspectors reviewed the operability

assessment and found that it did not address all relevant aspects of the issue. It did not

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rigorously support the conclusion that an extinguisher or its nozzle could not become a

missile hazard. Additionally, it did not address the remaining 29 extinguishers in

containment.

Unit 2 containment fire extinguishers and their associated cabinets were inspected

during every unit shutdown of greater than 30 days' duration, using Fire Protection

Procedure SO123-Xll 52, Attrchment 3," Fire Surveillance Data Record-Unit 2

Containment." Unit 2 cabinets were last inspected on December 7,1996, during the

Cycle 9 refueling outage. All cabinets, with respect to doors, were recorded as

satisfactory, except Cabinet Number 26. AR 960800977 was used to document the

missing latch; however, no corrective actions were taken at that time. St*p 2 of

Procedure SO123 Xil-52 states in part that the intended function of the cabinet is to hold

the extinguisher, that the doors must be able to be closed, and that the cabinet door

must latch properly.

After the January 9,1998. containment entry, licensee personnel identif;ed numerous

similar deficiencies with fire extinguisher cabinet doors outside containment.

10 CFR Part 50, Appendix B, Criterion V, requires, in part, that activities affecting quality

shall be prescribed by documented procedures and that these activities shall be

accomplished in accordance with these procedures. Maintenance Procedure

SO123-1-20, " Seismic Controls," Revision 5, Step 6.3.6, states that " restraints shall be

placed to ensure the equipment does not topple over during a seismic event." The fire

extinguishers described above, located in Unit 2 containment, were not restrained to

ensure that they did not fall from the cabinets and topple over

(Violation 50-361/9727-02).

At the exit mesting, the licensee questioned the applicability of Procedure SO123-1-20 to

equipment failures, based on an assumption that most of the cabinets became

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i un!atched due to a failure of their latching mechanisms. The inspectors considered the

fact that all but two of the latch mechanisms on the unlatched cabinets were found to be

loose, but determined that the licensee did not establish that the looseness caused the

uniatching, or that the looseness was not preventable by reasonable licensee quality

assurance measures or mar,agement controls. On the contrary, the inspectors

determined that the apparently prevalent condition of loose latching mechanisms could

reasonably have been identified and corrected during the routine inspections the

licensee performed,

c. Conclusiom

The licensee failed to ensure that 7 out of 32 fire extinguishers in Unit 2 containment

were properly seismically secured during Mode 1 operations. This was r violation of

licensee's seismic program requirements. The inspectors identified this issue during an

at-power entry of Unit 2 containment during a walkdown with licensee engineers. The

initial operability assessment, performed by design engineers, was weak, because it did

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not address all fire extinguisher locations and was not rigorous in supporting conclusions

that the fully charged extinguishers did not represent missile hazards.

V. Mananoment Meetings

X1 Exit Meeting Summary '

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

the exit meeting on February 4,1998. The licensee acknowledged the findings

presented.

The inspectors asked the licensee whether any materials examined during the

inspection should be considered proprietary. No proprietary information was identified.

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ATTACHMENT

SUPPLEMENTAL INFORMATION

.

PARTIAL LIST OF PERSONS CONTACTED

Licensen

J. Clark, Manager, Chemistry

J. Fee, Manager, Maintenance

G. Gibson, Manager, Compliance

D. Herbst, Manager, Site Quality Assurance

M. Herschthal, Manager, Station Technical (Acting)

J. Madigan, Manager, Health P"" tics (Acting)

R. Krieger, Vice President, Nuclear Generation

D. Nunn, Vice President, Engineering and Technical Services

T. Vogt, Plant Superintendent, Units 2 and 3

R. Waldo, Manager, Operations

INSPECTION PROCEDURES USED

IP 37551: Onsite Engineering

IP 61726: Surveillance Observations

IP 62707: Maintenance Observations ,

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IP 71707: Plant Overations

IP 71750: Plant support Activities

ITEMS OPENED AND CLOSED

Ooened

50-361/97027-02 VIO seismic restraint of fire extinguishers in containment

Ooened and Closed

50-361/97027 01 NCV motor operated valve actuator with insufficient lubricant

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2.

LIST OF ACRONYMS USED

AR action request

= CCW component cooling water. -

CDP. - core damage probability

.COLSS core operating limits supervisory report

EDG . emergency diesel generator

FCE facility change evaluation

NPEO nuclear plant equipment operator

- PDR Public Document Room :

RCS reactor coolant system

SIT . safety injection tank

T-cold cold leg temperature --

-TS technical specifications

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