Text

Insp Rept 50-336/90-09 on 900417-0529.Violations Noted. Major Areas Inspected:Plant Operations,Surveillance,Maint, Previously Identified Items,Engineering/Technical Support, Committee Activities,Periodic Repts,Lers & Allegations
	ML20055E799
Person / Time
Site:	Millstone
Issue date:	06/29/1990
From:	Haverkamp D; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:	;
Shared Package
ML20055E797	List: ML20055E796; ML20055E798; ML20055E799;
References
	50-336-90-09, 50-336-90-9, GL-88-17, NUDOCS 9007120345
	Download: ML20055E799 (27)
	v • d • e

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report No.: 50-336/90-09

Docket No.: 50-336

0 License No. DPR-65

h Licensee: Northeast Nuclear Energy Company

).0. BoxT/0

Hartford, CT 06141-0270

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Facility _N.sme: Millstane Nuclear Power Station, Unit 2

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Inspection at: Waterford, Connecticut

Dates: April 17 - May 29, 1990 l

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Reporting

Inspector: Peter J. Habighorst, Resident Inspector

Inspectors: William J. Raymond, Senior Resident Inspector

Peter J. Habighorst, Resident Inspector

Thomas Moslak, Resident Inspector, Three Mile

Island

Douglas Dempse , Resident Inspector, Millstone I

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Approved by: M h T 90

05nald R. Haver m ief 9' ate'

Reactor Project on 4A

Division of Reactor Projects

Inspection Summary: Inspection on April 17, 1990 - May 29, 1990

Inspection Report No. 50-336/90-09

Areas Inspected: Routine NRC resident-inspection of plant

operations, surveillance, maintenance, previously identified

items, engineering / technical' support, committee activities, '

periodic reports, licensee event reports, and allegations.

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Results:

See Executive Summary

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gDR ADOCK 05000336

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, Executive Summary

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. Plant Operations

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E,0 -Review of licensee actions during the reactor trip concluded the licensee's

response was adequate. . NRC inspection of outage activities identified an-

experienced and efficient operations support organization.

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The inspectors will review licensee's corrective actions to prevent recurrence-

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of emer0ency diesel genert. tor exhaust pipe lagging fires.

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Radiolooical Controls

y Good health physics assistance and control were noted; specifically, in steam

generator plenum werk.

Surveilla"cland Maintenance

Review cf routine maintenance idtotified no noteworthy findings. .Surveillanc.e

activities were generally r>erfornad in accordance with established test con-

trols. A violation was idustified regarding the improper performance of_ sur-

veillance required by the technical specifications on the main station bat-

-teries. Specifically, On March 7, 1990, uncertified contractor personnel per-

formed a main station battery surveillance while not under direct observation

Lof certified test personnel;. levels of battery cells not meeting the procedure

. acceptance criterion were not documented; and water additions required by the

procedure were not performed. On March 14, 1990, the amount of water added to

individual battery cells was not documented. 3

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Engineering and Technical Support

Steam generator eddy current testing was well implemented with an adequate

inspection scope. The licensee's decision to inspect and locate the source of

primary to secondary leakage displayed a good regard for plant operational

safety.

Security.

Routine review in this area identified no noteworthy findings..

Safety Assessment / Quality Verification

Routine review in this area identified no noteworthy findings.

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TABLE OF CONTENTS

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S' 1.0 Summary of Facility Activitles.............................. 1- l

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f2.0 Plant Operations (IP 71707/93702)........................... I !

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, 2.1' Control Room -

Observations.......-....................... 1 !

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2.2 Plant Tours............................................ 2

2.3 Ma n u a l R ea c to r T ri p . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 !

2.4 Control of Outage Activities........................... 3

2.5 . Review of Plant' Incident Reports (PIRs)................ 4 s

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2.6 PIR 90-30 iB' Emergency Diesel Generator ';

Exhaust F1re........................................... 5

3.0. Radiological Controls (IP 71707)............................ 6 :

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3.1 ' Posting and Controls of Radiological Areas............. 6

'4.0 Maintenance / Surveillance (IP 62703/61726/92702)............. 6 '

4.1 Observation of Maintenance Activities.................. 6

4.1.1 -No. 1 Feedwater Regulating Valve-Failure........ 7 '

'4.2 Observation of Surveillance Activities.................. 9

4.2.1 Valve Li ne-Up Veri fication. . . . . . . . . . . . . . . . . . . . . 10

4.3 Malfunction of Main Steam Atmospheric

Relief Va1ves..........................................-10

5.0 Engineering / Technical Support (IP 92702/93702)............. 11 ,

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5.1 Inservice Testing...................................... Il !

'5.2 Reportability Conditions.............................. 13

5.2.1 Effect of Potential House Heating Steam

System Failures on Safety-Related Systems............. 13

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5.3 PIR 90-28, "Hilti Bolts on Hanger 402008- +

Found Loose".......................................... 13

5.4 Prima ry-to-Seconda ry Lea kage . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

. 5. 5 Degraded Service Water Pi p1r.g . . . . . . . . . . . . . . . . . . . . . . . . . 15 ;

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6 '. 0 Security (IP 717107)....................................... 16

7.0.'S'afety Assessment / Quality Verification

(IP 30703/90712/92702/92700)............................ .. 17

7.1 Committee Activities................................... 17 i

,7.2 Periodic Reports...................................... 17

7.3 Review of Licensee Event Reports. . . . . . . . . . . . . . . . . . . . . 17

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7.3.1 LER 89-09-01 " Radiation Monitor RM 8262 Inlet

Valve (2-AC-82) Found Closed".................. 17

7.4 Previously Identified Items

(Violation /0eviation).......... ....................... 18

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7.4.1 NC4.90-01-01 (Closed): Failure to

Report Under 10CFR50.73 A Control Room Air

Conditioning System Technical Specification

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Violation........................................ 18'

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, 8.0' Reactive Inspection-Activities (IP 62703/61726)............ 18' -;

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, -.8.1 : A. 35.01 " Loop Folders Out-of-Date". -. . . . . ... . . . . . . . . . . . . 18 ;

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8.2 tConcern: Main Station Battery-Surveillance !

i Test Performance (RI-90-A0033)........................ 20 i

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[ 9.0 :Managemen't Meetings.. ..................................... 23

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The NRC inspection manual _. inspection procedure (IP) or temporary *

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, ~, instruction (TI);that;was used as inspection guidance is listed :

for each applicable report section, i

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DETAILS

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l '. 0 Summary of Facility Activities !

Millstone Nuclear Power Station Unit 2 (Millstone 2 or the. plant) operated

at rated thermal power from the beginning of the inspection period until !

4:00 p.m. on April 26. The licensee commenced a planned downpower to:10

percent rated to remove a workman's rag located in the main generator cool-

ing air fan for the alterex (alternator-exciter collector ring). The rag- ;

was sucked into the fan housing on April 24 during preventive maintenance

activity on.the collector ring. The turbine was off-line at 8:00 p.m. and

reactor power was stabilized at 7-10 percent. The plant returned to 100

percent rated at 12:32 p a on April 28 after removal of the obstruction !

in the alterex. ~!

On May 8 at 12:49 a.m. the operators manually tripped the rea: tor based on l

decreasing water-level in the No. 1 steam generator (see report detail *

2.3). On May 10, the licensee decided te place the plant in cold shutdown- o

based on elevated primary-to-secondary leakage rate calculations. The ,

plant was in cold shutdown et 5:01 a.m. on May 11. The outage was used to E

i- conduct eddy current testing on both steam generators to identify and cor-

rect the leakage. At-the end of the inspection period, the plant was

.being maintained in cold shutdown.

.NRC Activities

The inspection activities during this report period include 162 hours0.00188 days 0.045 hours 2.678571e-4 weeks 6.1641e-5 months of

inspection during normal activity working hours. In addition, the review

of plant operations was routinely conducted during periods of backshifts

(evening shifts) and deep backshifts (weekend and midnight shifts). In-

spection coverage was provided for 21 hours2.430556e-4 days 0.00583 hours 3.472222e-5 weeks 7.9905e-6 months during backshifts and 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months ,

during deep backshifts.

On May 10,17, and 18 the resident inspector, senior resident inspector, ,

and regional Division of Reactor Projects Branch Chief met with the-

elected officials of the municipalities of Waterford, Montville, New

London, and East Lyme. The meeting agenda included the NRC inspection

activities at Millstone, and planning for an upcoming public meeting

(scheduled for July 25 in East Lyme).

2.0 Plant Operations

2.1 Control Room Observations

Control room instruments were observed for correlation between

channels, proper functioning, and conformance with. Technical

Specifications. Alarm conditions in effect and alarms received in

the control room were discussed with operators. The inspector

periodically reviewed the night order log, tagout log, plant incident

report (PIR) log, key log, and bypass jumper log. Each of the

respective logs was discussed with operations department staff. The

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inspector, reviewed and verified tag-outs: 2-715-90, 2-870-90, *

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-2-749-90, 2-631-90, 2-631-90, and 2-896-90 and bypass , jumpers !

L 2-90-27, " Inverter 2 Relay RC-1", and 2-90-29, " Shutdown Cooling

Suction Valve Interlock". No inadequacies were noted. ,

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2.2 Plant Tours

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The inspector. observed plant operations during regular and backshift !

tours of the following areas-

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Control Room Containment

Vital Switchgear Room Diesel Generator Room !

Turbine Building. Intake Structure >

Enclosure Bui; ding ESF Cubicles *

During p' ant tours, logs and records were reviewed to ensure '

compliance with station procedures, to determine if entries were '

correcth made, and to verify correct communication and equipment *

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status. No-inadeo.uacies were noted.

2.3 Manual Reactor Trip

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On May 8 at 12: 49 a.m., the control room operators manually tripped

the reactor from 100 percent of rated power based on a decreasing ;

level indication in.the No. 1 steam generator. All plant safety i

systems functioned as designed during the transient, and the trip was +

generally uncomplicated. At 4:04 a.m. the control room operators l

closed the main steam isolation valves (MSIVs) in preparation for

isolating the main condenser for planned maintenance: work activity on

the low pressure feedwater heaters. During closure of the MSIVs, o

both main steam atmospheric dumps failed to fully open resulting in

main steam safety valves opening for a short duration. The licensee ;

reopened the MSIVs at 4:20 a.m. and began troubleshooting activities .

on the atmospheric dump valve control circuitry (see report detail .

4.3). ;

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Licensee post-trip -review concluded the cause of decreasing level in

the No. I steam generator was a failure of the No. I feedwater regu-

lating valve. The licensee maintenance department disassembled the ;

valve and identified that the valve stem had separated from the plug

(see report detail 4.1.1). Feedwater system pressure upon separation

of the valve stem and plug forced the valve to close, and thus re-

sulted in decreasing level in the No. I steam generator.

The following_ lists the chronology of critical plant parameters

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during the manual ~ reactor trip: 4

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i 0:49:39.114 Steam Generator Level Deviation '

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Alarm

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0:49_:41.434 'B' Main Feedwater Pump Discharge I

Pressure High

0:49:49.-781 - Manual Reactor Trip- ,

0:49:49.599 .629 Reactor Trip Circuit Breakers Open- -

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0:49:49.821 Main Turbine Trip ;

0:49:49.974 Normal Station Service Transformer ;

Breaker Open 1

0:49:49,981 Reserve Station Service Transformer

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Supply Breaker Closed j

0:49:51 Control Room Operators _ Initiated *

Emergency Operating Procedure i

(EOP)-2525, " Standard Post Trip '

Actions"

0:49:51.684 Automatic Reactor Trip Signal on l

Low Steam. Generator Level

0:53:19:619 'B' Auxiliary Feedwater Pump Start {

0:53:21:596 ' A' Auxiliary Feedwater Pump Start '

0:55:00.00 -Operators Completed E0P-2525, and '

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Commenced E0P-2526, " Reactor Trip

Recovery" <

g The inspector. reviewed the licensee's pre-trip report, post-trip i

report, sequence of-event log and post-trip review summary. The

review consisted of verification of reactor protection system l

response time, auxiliary feedwater initiation, turbine trip time

. response, and the response of plant parameters-for steam generator

level, pressurizer level / pressure, and reactor coolant system

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temperature. Emergency operating procedure ~ implementation and the-

results of the post-trip safety function status checks were also-

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reviewed. No inadequacies were identified in the plant response to i

the transient, or in the operator actions to stabilize the-plant. ;

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-2,4. Control of Outage Activities

On May 10 at 1:47 p.m. the licensee decided to place.the unit in a

cold shutdown condition, based on elevated primary-to-secondary

' leakage rate calculations (see report detail 3.2). The planned

outage schedule duration was 39 days.

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The licensee maintained the operations outage organization as the

focal point to control outage activities. The operations outage ,

organization comprised of.two experienced shift supervisors and a i

team of operators.that provided good plant configuration control. i

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Unit planning meetings were held daily on weekdays, additional >

meetings were held to identify steam generator eddy current testing i

status and-the scope of repairs to tubes. The meetings offered 1

planning updates, kept unit personnel aware of plant status, and-

promoted effective communications between unit departments.

)" , The inspector verified licensee implementation of_ commitments to NRC

Generic Letter 88-17 prior to reduced inventory operations on May 16.

Effective control and implementation of actions was noted.

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o Major outage activities included inspection and repair of steam

!! generators, modifications to the feedwater regulating valves, reactor *

vessel mid-loop operation, feedwater venturi hydrolasing, secondary i

steam generator radiation surveys for the steam generator replacement ;

project, repairs.to the pressurizer spray and vent valves, and repair

of the No. 2 safety injection tank manway leakage.

2.6 Review of Plant Incident Reports (PIRs)

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The-plant incident reports (PIRs) listed below were identified by the

! licensee during the inspection period. The inspector (1) determined

the' significance of the events; (2) verified t5e licensee's response

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and corrective actions were proper; and, (3) verified the licensee ;

reported the events in accordance with applicable requireraents. The

following PIRs were reviewed: )

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, -- PIR 90-26, " Hydrogen Analyzer Recorder Failure" I

- .PIR 90-27, " Containment Atmosphere Content"

, - .PIR 90-28, "Hilti Bolts on Hanger 402008 Found Loose"

-- PIR 90-29, " Reactor Power Exceeded 101 percent" !

--- PIR 90-30, "'B' Emergency Diesel Generator Exhaust '

Pipe Lagging Fire"

-- PIR 90-31, "2-SW-3.2B Air Flask Inoperable" '

-- PIR 90-32, "Effect of Potential House Heating

Steam System Failures on Safety-Related '

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Systems"

-- PIR 90-33, " Manual Reactor Trip"

-- PIR 90-34, " Failure to Fully Open the Atmospheric

Dump Valves"-

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-- PIR 90-35, " Water Overflow from #1 Atmospheric Dump"

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-- PIR 90-36, "'A' Service Water Header Leak"

-- PIR 90-37, " Personnel Injury While Removing No.1 SG '

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The following PIRs warranted additional inspector follow-up: ,

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PIR 90-28 (see report detail 5.3); PIR 90-30 (see report detail 2.6);

PIR-32 (see report detail 5.2.1); PIR 90-33 (see report detail 2.3); *

PIR 90-34 (see report detail 4.3); and PIR 90-36 (see report detail 1

5.5).

2.6 PIR 90-30 'B' Emergency Diesel Generator Exhaust Fire i

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!: On May 1, the 'B' emergency diesel generator (EDG) was started at -'

4:31.a.m.. and at approximately 5:32 a.m. an auxiliary operator ,

reported a fire in the exhaust pipe insulation. The licensee was '

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making preparations to remove the 'A' EDG from service for preventa-

tive maintenance and was performing its required surveillance per

. technical specification (TS) 4.8.1.1.2.a.

Upon notification of the fire, control room operators immediately -

tripped the emergency diesel generator, and the plant equipment

operator located in the diesel generator room extinguished the fire

with a portable carbon dioxide extinguisher within two minutes of

identification, i

The inspector reviewed the fire damage to the exhaust pipe insula-

tion, reportability requirements, and licensee corrective actions. *

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Reportability requirements reviewed were the emergency plan imple-

menting procedure (EPIP) 4701-4, and 10CFR50.72. EPIP 4701-4,

requires an emergency classification of an Unusual Event if a fire

lasts greater than 10 minutes within the protected area, and an Alert

classification is required if the fire potentially affects safety

systems as based on the assessment of the control room shift super-

visor. No emergency classification was reported. Based on

discussions with the control room shift supervisor no emergency -

classification was entered based on,- (1) the fire was out in less i

than two minutes, and (2) visual examination / evaluation of the ;

affected area on the diesel concluded that it did not jeopardize the

operability of the engine. No inadequacies were noted in the

licensee's reportability determination.

The-licensee evaluation indicated that the cause of the fire was fuel

oil residue within the exhaust pipe insulation. The exhaust pipe j

heated up based on an hour of rated load operation resulting in '

ignition of fuel, j

' The diesel scavenging air is directed by a turbocharger into an

aircooler, through the piston (opposed piston diesel), to the

turbocharger (driving medium) into an exhaust manifold, and finally i

to an exhaust silencer. The location of the fire was between the i

exhaust manifold and silencer.

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The fire damage was localized to the insulation surrounding an

exhaust pipe gasket surface. The licensee corrective actions ,

included removal of the insulation'in the affected area. Permanent *

corrective actions for this event were still being evaluated by the ;

licensee at the end of the inspection period and will be reviewed

during a subsequent.NRC inspection.

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'3.0 Radiological Controls

3.1 Posting and Control of Radiological Areas

Du' ring plant tours, contaminated, high airborne radiation, and i

high radiation areas were reviewed with respect to boundary.

identif_ication, locking requirements, and appropriate control ,

points. No inadequacies were noted. ~

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Outage Control ;

Health-physics staffing during the outage was increased by the

use of contractors to support additional radiological control

points at all' elevations of containment, and at one location -

within~ the auxiliary building. 1he insptsctor routinely reviewed 3

outage radiological controls and found technicians to be f

knowledgeable and_ dedicated to assigned areas of responsibility. :

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-The ALARA (As-Low-As Reasonably Achievable) coordinator provided.

daily. status of actual man-rem expended in comparison to

estimated man-rem for major outage activities, and tracking-of 'i

exposure in relationship to overall project outage activities. 1

The licensee's estimated outage exposure was 173.1 man-rem. At

.the end of the inspection- period (May 29), the actual nn-rem "

exposure was.63.0-in comparison to a projection of 93 man-rem. ',

The inspector observed continual good health physics assistance -

and control, specifically in the steam generator plenum work ,

(i.e. nozzle dam ins *allation, eddy current testing set-up, and

manway. removal) to maintain exposure ALARA. <

4.0' Maintenance / Surveillance

4.1 Observation of Maintenance Activities .

The. inspector observed and reviewed selected portions of

preventive and corrective maintenance activities to verify

, compliance with regulations, correct use of administrative and

maintenance procedures, compliance with codes and standards,

proper QA/QC involvement, use of bypass jumpers and safety tags,

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personnel protection, and equipment alignment.and retest. The

following activities were included: -

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AWO M2-90-00437, " Repair of Feedwater

J Regulating Valves

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AWO M2-89-12435, " Pressurizer Solenoid Vent l

Valve 2-RC-422"

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AWD.M2-90-04896, " Repair. of Service Water

Spool Piece 6-J60-21"

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AWD M2-90-05421, " Repair of Vital Inverter 2"

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AWO M2-90-3566, " Spent Fuel Pool Tritium

Installation"

No inadequacies were identified.

4: 4.1.1- No. 1 Feedwater Regulating Valve Failure

m On May 8 at=12:49 a.m., the control room operators manually

tripped the reactor from 100 percent of rated power based on 1

decreasing level indication in the No. I steam generator. The

licensee post-trip review concluded that the cause of decreasing

level in the No I steam generator was a failure of the No. 1

feodwater regul ting valve.

Valve Description

The feedwater regulating valve (2-FW-51A) is a 12-inch, angle -

globe valve with a P-200-12 air operator manufactured by Copes-

Vulcan, Inc. Valve 2-FW-51A was previously evaluated by the

licensee under material equipment parts list (MEPL) evaluation

CD-153 as a non-category I QA, non-environmental equipment quali-

.fied (EEQ) and non-fire protection 0A component. The P-200-12.

air operator for the valve provides ported air to both sides of

the piston to provide positive action. Each air line contains a'

solenoid valve that is normally energized.

Valve Failure d

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On May 9, the licensee documented the preliminary investigation '

of the valve 2-FW-51A failure. Valve disassembly identified

-that the valve stem separated from the valve plug. The material ,

specification as identified on licensee drawing 25203-29090 i

Sheet 1, was ASTM-A276 for both the valve stem and plug. The i

valve stem threads were stripped, and the roll pin connecting

the plug-and stem to prevent rotational movement was sheared

off. .The valve stem and plug are connected by three mechanisms;

(1).3/16" X 1 1/2" roll pin through the plug and stem, (2) 3

-degree taper for 1 1/8 inch on the valve stem into the plug, and

(3) 15/16" threaded section on the outside diameter of the sta

mated with-the plug. Separation of the valve stem from the plug

resulted in 2-FW-51A closing as a result of main feedwater

pressure above the plug.

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,. The licensee disassembly also verified valve internal dimensions

were as reflected in plant drawings; 25203-29090 Sheets 1,2, and

l- 3. The dimensions reviewed included length and diameters of the

stem taper, and plug outside diameter in comparison.with the

inside diameter of the valve seat ring. The as-found dimension

for the diameter of the stem taper was smaller than the 1.132

L inches identified as a reference dimension on drawing 25203-

29090 Sh.3. All-other dimensions were verified satisfactory.

In conclusion, the licensee identified-inadequate taper dimen-

sion on the valve stem taper, a sheared roll pin, and stripped

valve stem threads, resulting from postulated vibration and-

L fatigue in the stem-to plug connection.

Licensee Corrective Actions

The licensee corrective actions in relationship to the failure -

of the stem-to plug connection in 2-FW-51A included; loose parts-

evaluation for the roll pin, review of the nuclear plant ,

reliability data system (NPRDS.) to identify industry experience, '

discussions with the valve vendor, modification of both feed- -

water regulating valves, and procedural revisions.

The loose parts evaluation of the sheared 3/16 inch X' 1/16 inch

roll pin concluded the pin was fully recovered, and no loose

parts were entraitred in the feedwater system or steam genera-

tors. The NPRDS data review indicated three ather facilit'es

(Point Beach, Beaver Valley, and North Anna) with similar

Copes-Vulcan feedwater regulating valves experienced preblems in :

the' stem / plug connection. All utilities surveyed by Nortneast

Utilities experienced noticeable valve vibration during opera-

tion. All plants installed a modified trim to reduce flow-

induced vibrations. Valve trim is the alteration of the port

flow openir,g in the valve seat ring. The vendor recommendations ;

included increased pre-load for the stem / plug threaded connec- '

tion from 200 ft-lbs to 300ft-lbs and a suggestion to install a '

quadrant flow baffle to reduce flow induced vibrations.

The licensee proposed modification as documented in-plant-design

change record (PDCR) evaluation MP2-90-049 is to replace the '

existing roll pin with a 1/4" X 3" taper pin; to increase the

torque between the stem and plug from 200 to 300 ft-lbs, and the

-joint (stem / plug) assembled with a joint locking compound

(Loctite / Primer 74756). The licensee will implement the above

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actions for both feedwater regulating valves prior to unit

start-up, and at the scheduled refueling outage (estimate

September, 1990) will review the trim modification, alternate '

stem material, and quadrant flow baffle.

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', The licensee approved change 1 to procedure MP-2702A1 ' Main

Feedwater Control Valves' on May 30, 1990. The inspector (

ver_ified the' change to the procedure to incorporate'the modi - !

fication actions as prescribed in PDCR evaluation MP2-90-049.

History ;

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,The inspector reviewed the recent work activities and perform-

9 ance of valves 2-FW-51A and 2-FW-518. As documented in !

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inspection report 50-336/87-19,- a reactor trip occurred on l

September 2, 1987 when the same 2-FW-51A stem / plug connection l'

failed.- -The licensee determined at the time _that.the roll pin

for the stem / plug connection was not installed, and the threads

p, on the stem and~ plug were galled and flattened. The inspector's

! review indicate that a taper dimension difference could have-

contributed to the previous failure mechanism. The inspector .

further reviewed the work history of 2-FW-51A and 2-FW-51B for ,

the past three years and identified no failures other than .

September 2, 1987 in the stem / plug connection.

Assessment ,

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Based oi. observation of the failed plug / stem connection, review

L of licensee corrective actions, and supporting documentation for

the valve modification, the inspector concluded that the t

licensee actions were detailed and well developed. Good support

interf ace existed between corporate and staf f engineering in

resolution of repairs.

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The inspector had no further questior.s, and considered the

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licensee corrective actions to be adequate. 1

4.2 Observation of Surveillance Activities ~

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The inspector observed portions of completed surveillance tests' to- !

assess performance in accordance with approved procedures and Limit- ,

ing Conditions of Operation, removal and restoration-of equipment,

and deficiency review and resolution. The following tests were re-

. viewed:

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OP 2207, " Pressurizer Flood-up"

--

OP '2316C, " Steam Generator Leak Test Using

Auxiliary Feedw ter Water and High Pressure

Nitrogen"

--

SP 21206, " Instrument Air Accumulator Test for

2-SW-3.24 and 2-SW-3.2B" >

--

SP 2611D-2 " Reactor Building Component Cooling

Water Valve Lineup"

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No inadequacies were noted.

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I 4.2.1 Valve Line-up Verification

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On May 17, 1990, the inspector accompanied a plant equipment operator

(PEO),to verify the proper configuration of selected valves for the

reactor building closed cooling water (RBCCW) system. As part of

this verification, the inspector determined that the PE0 was using a ,

controlled copy of.the latest revision-of surveillance procedure ,

'

2611D-2 in confirming the valve alignment. The inspector observed

that the PE0~ exercised accessible valves to determine actual valve

position, implemented the appropriate radiological controls to pre- ,

. vent contamination and minimize exposure, and implemented the proper'- ,

administrative controls. identified in the procedure. The inspector

performed an independent observation of the valve positions. No

valves were found to be out of the required position. The inspector t

did observe that the valves were readily identifiable through use of r

/ yellow embossed tags or recently installed, large bar-coded labels. *

Equipment material condition and general plant housekeeping was good. j

The inspector did note that the procedure, in some cases, failed to. )

identify certain valves that were inaccessible. By the licensee's

procedural requirements, if a valve is determined to be inaccessible,

it is required to base its position enecked only following.a _l

refueling outage or following system maintenance end not during ;

routine surveillance verifications. The PE0 documented the

inaccessibility of ~ these valves within the procedure and initiated

the procedural change to revise the status of the affecten valves,

t, . 3 Malfunction of Main Steam Atmospheric Relief Valves .

Follon ng the reactor trip on May 3, 1990, operations persor.nti i

determined that the main steam atmospheric relief valves (2-MS- t

190A/B) failed to open fully on demand. Approximate values of valve '

position indications were 55 percent open for 2-MS-190A and 25

percent open for 2-MS-190B. Subsequently, a plant incident report t

(90-34) was. filed and an investigation was conducted by maintenance

personnel into the possible causes of the malfunction. The valves

were tested in place and then disassembled for component inspection. .s

Results of testing indicated that the valves operated satisfactorily

under no load conditions. However, the . licensee questioned whether *

the no-load tests were representative of true valve performance under

full load.

Upon disassembly.of the air-operated valve actuators, the licensee

determined that the rubberized diaphragms appeared to be in good '

condition. The inspector confirmed that the diaphragms were flexible

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with no apparent degradation. - Based upon this preliminary evalua-

tion, the licensee.is considering that the possible failure mode is

due to an under capacity valve positioner on each valve actuator.

The present valve positioner operating range is limited by manufac-

turer recommendations to a maximum operating air pressure of 65 psig.

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The licensee is evaluating whether this operating pressure is too low

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considers that change out of the valve positioner with a higher rated

positioner, having an operating air pressure in the range of 80-100

psig, may be appropriate to correct the malfunction.

'

In parallel with this evaluation, the licensee is also evaluating if

-increasing the valve stroke from 2 1/2 inches to 3 inches could

preclude future malfunctions.

1

The inspector reviewed the plant incident report, discussed ongoing i

evaluations with licensee representatives and examined valve actuator ,

internal components.- From this, the inspector concluded that the ,

licensee is taking prudent and timely actions to correct the problem- ;

identified. The inspector also determined that licensee personnel- :

have complied with relevant site procedures (i.e., ACP 10.01 and EPIP '

4701.4) to evaluate reportability, and to address corrective actions

,

in resolving improper valve performance.

5.0 Engineering / Technical Support

5.1 Inservice Testing

On May 10, the licensee decided to conduct an in-service inspection

f and repair of the steam generators based on elevated primary-to- [

secondary leak rate calculations.

~

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The licensee performed a secondary side steam generator leak test in '!

accordance with procedure OP-2316C " Steam Generator Leak Test using-

Auxiliary Feedwater and High Pressure Nitrogen." The leakage points

were identified by video monitoring. equipment inside the steam gener-

ator channel heads. The inspector reviewed the video tape of the

leakage areas. .The test results revealed four leak locations; one ,

welded Combustion Engineering plug, wo Westinghouse mtchenical plugs i

with plug-in plugs (PIPS) installed, and one Westinghouse tube sleeve.

The plug and sleeve leakage was noted in the No I steam generator

'

hot leg and cold leg, and the No. 2 steam generator hot leg. The <

leakage from the sources ranged from drips every 15-20. seconds to

every minute.

Eddy Current Testing (ECT)

.The scope of the non-destructive testing included tube examination ;

for both steam generators in all four plenums. The examination area

was one 1.nch below the top of the tube sheet to two inches above the ,

top of the tube sheet. .The inspection area was based on the previous

location of circumferential1y oriented cracks. The primary ECT

examination method employed the rotating pancake coil (RPC) to

identify circumferentially oriented cracks. The licensee also used

an addition coil design (3-coil) to differentiate flaw characteris-

tics (crack or pit) in the steam generator, and a follow-up -

ultrasonic test to further characterize the flaw.

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The examination scope included the susceptible tube crack region

(sludge ~ pile) and a three percent random sample outside the suscep-

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tible region.. Expansion of the inspection scope was predicated on.

,, maintaining a three row boundary at the periphery of the sludge pile ;

region without a tube flaw indication. The total tube examinations

by steam l generator _ plenum cre provided below. '

No. 1 SG hot leg

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2,750 i

No. 1 SG cold leg

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1,355 4

No. 2 SG hot leg

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2,264 .;

No. 2 SG cold leg -

1,319 ,

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The examination scope represented approximately 31 percent of all :

in-service steam generator tubes.

!

Results

"

The total number of defective tubes identified was 22 or 0.27

percent of all tubes examined. The defective tubes were character- '

ized by circumferentiel extent and depth by the various non-

'

destructive techniques.

The worst case circumferential extent was in tube L52R10 in the No.1

steam generator cold leg and was 281 degrees, and the most extreme y

depth was in tube L112R10 and was greater than 90 percent thru-wall. '

The worst case average crack depth summing over 360 degrees was a

31-percent wall loss. The licensee preliminary evaluation concluded

that none of the in-service tubes-inspected exceed d the structural

design margins in NRC Regulatory Guicie 1.121. At the'end of the

inspection period, the _ licensee was implementing repairs to all de- .

fective tubes and leake.ge points noted during the secondary pressuri-

zation test, i

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. Assessment

The inspector reviewed the licensee prediction of cracked in-service ,

tubes vs. actual examination results, compared the current examina- !

- tion results with those from the October 1989 outage, and evaluated-

the licensee scope selection to ascertain the condition of tubes *

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within the steam generator. The current ECT examination results,

when compared to the October, 1989 results, indicate a reduction in

defective tubes for essentially the same operating period and

inspection scope. The averaged defect characterization is less

severe in the circumferential extent and depth range.

The ECT program was well implemented with a good representation of -t

inspection scope. The defects identified from the ECT examinations

and the pressurization tests, were of a type that would have allowed

timely detection prior to significant degradation while the reactor

operated, and would have allowed safe reactor shutdown within the

bases of the technical specification leakage limits.

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5.2 Reportability Condit*pn

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5.2.1 Effect of Potential House Heating Steam System

Failures on Safety-Related Systems

On May'17, 1990, the licensee notified the NRC Operations Center in

accordance with 10 CFR 50.72(b)(2)(iii) of the results of its pre-

e liminary engineering analysis addressing the impact on safety-related

i equipment of failure of the Unit 2 house heating steam system (HHSS).

,

The HHSS is designed to deliver low pressure saturated steam at 280

degrees F/50 psig through 4-inch piping to various building heaters

located throughout Unit 2. The preliminary engineering analysis

indicated that a piping failure of the HHSS could degrade

habitability and specifically impact the operability of equipment

located in the control room air conditioning. system room, the "A" and

"B" emergency ciesel generator rooms, the "A" emergency diesel

generator day tank room, and a room containing safety-related

ventilation equipment that services the spent fuel pool area.

As'a short-term corrective action, the licensee has secured the HHSS

and is in the process of isolating the system from affected plant

areas by severing the supply line and installing blind flanges.

Long term r.ieasures to provide heating in the affected areas is under

evaluation,

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The licensee is precaring a licensee event report (LER) in supp9rt of

these findings. This issue will be reviewed further as part of the

routine NRC review of LERs.

5.3 pIR 90-28 "Hilti , Bolt 3 on Hanger 402008 Found Loose

On April 19, the licent9e identified that mechanical snubber support

402008 aschor colts were loose. Svoport.402008 is located on the

', suction line for the shutdown cooling system. At the time of

identification, the facility was operating at full rated power. The

immediate corrective actions performed by the licensee were to

retighten the Hilti anchor bolts and visually inspect the adjacent

hangers for the shutdown cooling suction line.

The requirements for operability of support 402008 are prescribed in

technical specification (TS) action statement 3.7.8. ' snubbers.' The

support in question was not applicable for requirement 3.7.8., since i

shutdown cooling operating is required operable in cold shutdown and ,

refueling per TS 3.9.8.1, and not in power operations. l

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On April 20, Northeast Utilities Service Company (NUSCo) stress !

analysis engineering reviewed PIR 90-28 to identify the effects of

loose anchor bolts on a QA category I seismic support (402008). The 1

review referenced engineering calculation PIR-89-9-1050GP. i

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Engineering evaluation PIR-89-9-10506P compared thermal and seismic h

stresses with allowable limits in American Society of Mechanical j

Engineers (ASME)Section III,1974 edition, and determinations of ~

factors of safety. The licensee concluded the condition of the !

. restraint did not compromise system operability. <

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_ The inspector reviewed the licensee corrective actions, supporting I

engineering evaluations and conclusions. No inadequacies were noted. I

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5.4 Primary-to-Secondary Leakage i

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History

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At the beginning of the inspection period, the licensee was tracking, i

E primary-to-secondary leakage by sampling of the steam jet air

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ejector, steam generator blowdown, and condenser tritium concentra-

tion, and by the response of the main steam line (Nitrogen-16)

radiation monitors. NRC review of primary to secondary leakage

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indications was previously documented in inspection reports j

50-336/90-06 and 50-336/90-08. j .

On April 28, the licensee observed two changes in primary character-

istics from previous leakage indications, in that the No. I steam >

generator main steam line radiation monitor (Nitrogen-16) developed '

_"

detectable leakage, and the isotopic ratio half-life determinations

were in agreement between the reactor coolant and secondary samples.

Specifically, the No I steam generator Nitrogen-16 monitor increased

to a maximum of 15.95 gallons per-day (gpd) from a previous-reading

of less than one gpd, and the ratios J xenon-133 to argon-41 were in

relatively close agreement between ttz grimary and secondary samples. +

The licensee action in response to el-vated readings on the nitrogen-16 ;

monitors was to increase monitor readings to every half hour. Previous

monitor readings were in conjunction with a steam jet air ejector

monitor alarm / blowdown isolation. At the time of the change in leak-

, age characteristics, the facility was in power ascension (see Summary

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of Facility Activities) from unrelated work activities associated

with the main generator alterex.

On April 29 at approximately 11:30 a.m., the leakage calculations

based on nitrogen-16 measurements had decreased and stabilized at '

[ between 1 to 4 gpd.

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On May 8, the control room operators manually tripped the reactor.

(see report detail 2.3) During the time interval between May 8 and

_

+

May 10 with the steam generator in a hot standby condition, the

licensee developed methods to further quantify the amount of

calculated leakage between the primary and secondary.

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steam generator to develop an accurate tritium. linear regression

analysis; (2) independent review by a contractor chemistry specialist

to provide an assessment of the leakage data; (3) hourly sampling of

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gross, iodine, and tritium activities; and, (4) selection of alter-

,' nate steam generator sampling locations (surface and bottom eleva _ ,

tions of the blowdown tube). The calculated leak rate increased from 1

approximately 20 gpd to a maximum of 87 gpd, based on the tritium

regression analysis on May 10. While there were some uncertainties

in the absolute value of the leak rate from the various calculation i

methodologies, the leak rate in the No. I steam generator had d

increased from the values measured prior to the May 8. shutdown.

At 1:47 p.m. on'May 10, the licensee decided to place the unit in f

cold shutdown to identify the cause of the increased primary to 1

-secondary leakage. On May 11, licensee and NRC representatives met l

at the NRC headquarters office in Rockville, Maryland to discuss the i

scope of the steam generator inspection. 4

Assessment

Licensee efforts to implement innovative techniques to quantify i

primary-to-secondary leakage between May 8-10 was considered good, j

The ultimate decision to inspect.and locate the leakage was a l

conservative decision that showed good regard for plant operational 'l

safety. i

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5.5 Degraded Service Water System Piping i

(

The-inspector reviewed the licensee program for identifying,- j

characterizing, and evaluating leaks in the service water system t

piping, Through review of relevant documentation and discussions j

with licensee representatives, the inspector determined that the f

licensee has formalized a program to document and evaluate. material 'l

degradation and throughwall leakage that has occurred in both small !

and large bore piping. Each time a leak has been identified, the

licensee has addressed it on an individual basis to determine if ;

system operability is challenged. Specific actions taken include

initiating a non-conformance report and conducting an ultrasonic

examination to characterize the flaw, performing an operability

assessment to determine whether the identified condition is accep- t

table, for continued service, and performing an engineering evaluation -)

to project what flaw size may be experienced for the remainder of the j

operating cycle.

Based on the engineering evaluation, the licensee determines how the

projected changes in piping stress levels affect the structural

integrity and seismic considerations of the system and evaluates

system integrity t'ith respect to construction code and final safety

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analysis report criteria. If results are acceptable, a non-welded

repair to mitigate leakage is made. Strap-seals have routinely been

used.

The licensee has acknowledged the overall degradation of service

water system piping that has resulted from erosion / corrosion

mechanisms. As a long-term corrective measure, the licensee has

systematically replaced about 60 percent of the affected piping with

PVC-lined,. carbon steel, piping having increased resistance to such

mechanisms. The remainder of the piping is to be replaced during the i

next refueling outage. '

Also during that outage, the licensee will re-line the two large bore

underground concrete-lined, cast iron service water headers with an

epoxy liner utilizing an innovative in-situ form process.

Since this process has not seen widespread use in nuclear applica-

tions and does not have an established history, the inspector

requested that licensee representatives address the following three

concerns when preparing the safety evaluations in support of using

the in-situ form process, The first issue is to identify what i

engineering controls are in place to assure that, in the event of

delamination, chipping', or peeling of the epoxy liner, that dislodged

material would not impair the operability of vital components in the

service water system. The second issue is to describe what surface

preparation will be accomplished to assure proper bonding of the

epoxy coating to the concrete liner and what controls will be in

place to assure that the surface preparation technique will not

degrade the piping and components of the service water system. And

lastly, the third issue is to provide information addressing what

effects of harsh environmental conditions, i.e., sea water and

climatic changes, can be predicted on the long-term life of the epoxy

liner. The NRC staff will review the licensee safety evalw tion upon

its completion.

Overall, the inspector concluded that these actions taken by the

'

licensee are prudent and timely to assure increased reliability of

the service water system.

6.0 Security

Selected aspects of site security were verified to be proper during

inspection tours, including site access controls, personnel searches,

personnel monitoring, placement of physical barriers, compensatory

measures, guard force staffing, and response to alarms and degraded

conditions. No inadequacies were identified.

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i 7.0 Safety Assessment / Quality Verification

7.1 Committee' Activities

The inspector attended meetings 2-90-44 and 2-90-58 of the plant

F operations review committee (PORC) on May 1 and May 29. The

inspector noted by observation that committee administrative

requirements were met for the meetings, and that the committees

-

discharged its functions in accordance with regulatory requirements.

The inspector observed a thorough discussion of matters before the '

PORC and a good regard for safety in the issues under consideration

by the committee.- No-inadequacies were identified.

7.2 Periodic Reports j

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Upon' receipt, periodic reports submitted pursuant to technical I

specifications were reviewed. This review verified that the reported :

irdormation was valid and included the required NRC data. -The- o

inspector also ascertained whether any reported information should be ;

classified as an abnormal occurrence. - The following reports were :'

reviewed:

t

-- Monthly Operating Report - April, 1990 l i

No inadequacies were'noted. I

'

7.3 Review of Licensee Event Reports

7 '. 3 .1 LER 89-09-01 " Radiation Monitor RM 8262 Inlet I

Valve (2-AC-82) Found Closed" j

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(Closed) Unresolved Item 8C <4-05 !

This item was based on a description of an event in LER 89-09 dated-

November 22, 1989, and was considered open because of incomplete ;

documentation of the event, the need to further assess the potential '

plant vulnerability, and to follow up the root cause determination of

the event to prevent reoccurrence. ,

On April 2, 1990 the licensee submitted updated LER (89-09-01) to

reference additional technical specification requirements, re-total .

the time interval that the conta'inment gaseous / particulate radiation

monitors were inoperable, and to provide additional information on

the status of the containment purge isolation system during inoper-

ability.

The inspector reviewed the updated LER and noted: the reference to

the requirements of TS 3.3.2.1, that the monitor was out of service

for 52 hours6.018519e-4 days 0.0144 hours 8.597884e-5 weeks 1.9786e-5 months , and during this time the containment purge isolation

valves were shut for 33 hours3.819444e-4 days 0.00917 hours 5.456349e-5 weeks 1.25565e-5 months ; and, that one of the two radiation

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, -monitors were in service during containment. purge system operation, .

however, without the emergency source of power for the blower (i.e.

g _the 'A' emergency diesel generator).

The' inspector also noted that the 1icenseelconcluded there were no

safety consequence from the event, in _that health physics personnel

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conducted routine grab samples of the_ containment atmosphere during-

the outage,;and the-purge valves were shut during 33 out of 52 hours6.018519e-4 days 0.0144 hours 8.597884e-5 weeks 1.9786e-5 months

Jof the period when the monitor was inoperable.: To this end, during?

the remaining 19 hours2.199074e-4 days 0.00528 hours 3.141534e-5 weeks 7.2295e-6 months , RM-8123 would have performed its safety

function;except.in'the event of a loss of normal power event.

"

The; inspector _previously reviewed the licensee corrective actions

during.the event as documented in inspection report 50-336/89-24.

The licensee concluded.that the root cause of the event was personnel ~

error, and the inspector concurs. Actions taken to prevent

recurrence were. acceptable, .i

This item is closed. 1

4 1

7.4 previously Identified Items (Violation / Deviation)'

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7.4.11 Non-Compliance 50-336/90-01-01 (closed): Failure d

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to Report under 10 CFR 50.73 Technical Specification l

Violation Control Room Air Conditioning System

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Inspection report 50-336/90-01 described a violation regarding the

failure by' the licensee to document' a licensee event report (LER) for a

a condition prohibited by the technical specifications- (TS). tj

H Specifically, TS 3.7.6.1 requires that if _one CRAC system is inoper- 1

able (based on lack of an emergency power source), then-the; licensee I

shall' restore the inoperable system to operable status within seven-

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days or initiate and maintain operation of the remaining operable Q

control room emergency air clean-up system in the' recirculation mode. Li

1

On April 30,-the licensee. submitted LER-90-004 ' Control Room- i

.

-Ventilation Technical Specification Violation' to the NRC. The

'

inspector reviewed the LER and the licensee corrective actions. The ;!

inspector considers the actions adequate, which included the.sub- 1

mission of a TS change request addressing CRAC operation with raspect a

to availability emergency power sources. This item is closed.

18.0 Reactive Inspection Activities j

"

8.'1 A.35.01'" Loop Folders Out-of-Date"

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On November 30, 1989, the resident inspector reviewed concerns re- I

lated to out-of-date loop diagrams in instrument loop folders.

Specifically, diagram 25203-28500 sheet 99C, revision 4 in the loop

folder for pressurizer pressure transmitter (PT-103), was in conflict

with the most current. drawing revision (Rev. 5 dated ,

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September 25,1989) in the licensee's nuclear records department.

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The incorrect revision was identified during troubleshooting

activities for an intermittent control room alarm (CB-13) " Saturation

Trouble Facility 2". The alarm was intermittent with no indication

of a low saturation condition on the reactor coolant system sub-

cooling monitors.

In addition, a review of the instrument and controls engineering file

could not_ identify the latest revision to drawing 25203-28500 sheet

99C. In summary, the concern involved outdated drawings in loop

folders used to service quality assurance instruments. The outdated

drawings had been discussed with licensee supervision.

Transmitter PT-103 provides an input into the inadequate core coolirg

(ICC) system at Millstone 2. The ICC system is required by NUREG

0737-II.F.2 and is a category 2 instrument per NRC regulatory guide

1.97. The ICC system is quality assurance (QA) category I. The

subcooled monitor with input into the RCS subcooled/superneat monitor

is required to be operable per technical specification 3:3.3.8, table

3.3-11, item #3.

At' the time the drawing discrepancy was identified, the most current

revision to diagram 25203-28500 sheet 99C was placed in the loop

folder, and on December 1, a review of the loop folder for PT-103-1

was initiated. On the same day, an internal memorandum to the re-

sponsible department head documented the discrepancies between the

loop diagram revisions in relationship to the loop folder, and the

master engineering file revisions in relationship to the nuclear

records document. The correct revisions were placed in the loop

folder and master engineering files. The correct revision to drawing

25203-28500 sheet 99C was apparently used for troubleshooting activi-

ties for facility 2 ICC system work under authorized work orders

(AW0s) M2-89-12937, M2-89-12922, and M2-89-13549. . Inspector review

concluded that incorrect loop diagrams were located in instrument

loop folders for PT-103 and PT-103-1 between November 28 - December

1, 1990,

previous History of Inaccurate Loop Folders

On October 11, 1989, the NRC issued special inspection report

50-336/89-13. The inspection report documented an NRC-identified

violation with 10 CFR 50, Appendix B, Criterion VII, Northeast

Utilities Quality Assurance Program Topical Report, and ACP-QA-3,03

" Document Control, Rev. 33, Section 6.2.1.2" regarding various types

of drawing discrepancies in the Millstone 2 instrument and control

department files. On December 8, 1989, Northeast Utilities responded

to inspection report 50-336/89-13.

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The licensee corrective actions in response to the violation for the

control of loop circuit diagrams were considered adequate. The

actions were implemented, in part, under departmental instruction

1.09, which was effective December 5, 1989. Instruction 1.09 1

provides a method for technicians and other site personnel to verify l

that the most current revision of loop diagrams is available by use

of the generation records informational tracking system (GRITS). The

inspector noted a minor implementation discrepancy in instruction. '

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1.09 in that technicians did not initial the drawing after verifica-

tion of the GRITS program. The inspector presented this to the

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licensee. The licensee acknowledged the discrepancy and provided

corrective actions. 1

On December 14, the licensee completed an internal review of two :

cases of the out-of-date loop drawings. The review concluded, in

both cases, that the drawings were not distributed to the instrument a

and controls department from the nuclear records department. The 1

correct drawing revisions were distributed to other Unit 2 depart- 1

ments. The licensee took corrective actions to address the routing

error in the distribution of controlled drawings.

The inspector reviewed the results of the program to upgrade instru- J

ment loop folders. Out of approximately 2900 loop folders for safety

and. non-safety instrumentation, less then 1.5 percent (41 loop dia-

grams) contained drawings with the inappropriate revision. All dis- l

crepancies were resolved by the licensee. ;

The inspector independently reviewed twenty randomly selected i

instrument folders to assess the adequacy of licensee loop diagram

upgrade program. The review was completed by comparing the drawings {

in the loop folders with the GRITS program output. No inadequacies 1

were noted. '

In conclusion, the loop diagram revisions were out-dated in the

associated loop folders and the engineering master file. Inspector

review identified that the particular safety-related work activity ~

was accomplished with current drawings, and no compromise to safe

work occurred. The inspector currently plans no further action and

considers this item closed.

8.2 Concern: Main Station Battery Surveillance Test Performance ,

(RI-90-A-033) !

On March 15, 1990, the inspector reviewed several concerns regarding the

performance of technical specification surveillance on the Unit 2 main l

station batteries. The concerns included the following items:

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--On March 7, 1990, two non-certified contractor employees performed i

technical specification surveillance on main station batteries 201A j

and 201B with no direct observation or supervision by qualified unit ,

maintenance personnel as required by Millstone station quality i

control procedures. I

--The electrolyte levels of a large number of battery cells' were

- found to be at or below the minimum required by technical specifica- !

tions and the surveillance procedure, but had been logged as " normal" j

on the surveillance data sheet. l

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--The contractors had reported the unsatisfactory levels ,o an ,

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assistant maintenance supervisor, who responded that the low levels ';

were due to low temperature in the battery rooms and were not a l

problem. j

The safety related batteries at Unit 2 are C&D type LCU-33, 60-cell,

calcium grid lead acid batteries rated at 125 volts de and 2320 ,

ampere-hours (8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months rating), They are designed to provide reliable I.

power to systems required for safe unit shutdown including, through 1

inverters, the reactor protection and engineered safeguards systems

and vital instrumentation. Section 8.5.4.2 of the Unit 2 final

safety analysis report (FSAR) states that the electrolyte level of

each battery cell is checked and all water additions recorded to

ensure functional capability and detection of battery degradation.

Technical specification 4.8.2.3.2 requires that battery operability <

be demonstrated at least once every seven days by verifying' that the l

electrolyte level of each pilot cell is between the minimum and-

maximum level indication marks. ,

3

Surveillance of the station batteries is performed weekly in accor-

dance with SP-2736A, Battery Pilot Cel1 Surveillance, revision 2, .

dated December 23, 1988, and quarterly in accordance with SP-2736B,. ;

Complete Battery Cell Measurement, revision 3, change 1, dated July i

23, 1986.- Regarding cell level, both procedures require that the i

-electrolyte be between the minimum and maximum level indication

marks. The amount of water added to any cell is to be documented on

procedure data sheets. Step 6.6.1 of SP-2736A states that for

battery cells not within acceptance criteria, level shall be

recorded. Finally, any measurements that do not meet acceptance

criteria must be reported to the assistance maintenance supervisor.

These procedures are consistent with vendor technical manual VTM2- ;

127-001A, Station Batteries (C&D Power Systems), and Institute of j

Electrical and Electronics Engineers (IEEE) Standard 450-1980, d

Recommended Practice for Maintenance, Testing, and Replacement of '

Large Lead Storage Batteries for Generating Stations and Substations.

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On March 15, 1990, the inspector toured the unit 2 battery rooms and

observed that the electrolyte levels of most of the 120 cells were

above' the minimum level mark and six cells were at the minimum mark.

This condition was considered by the inspector to be adequate. The

inspector reviewed weekly surveillance data sheets for the period.

February 14 through March 28, 1990 and noted the following:

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--In all cases, electrolyte levels were recorded as " normal". A note

. prior to step 6.7 of procedure SP-2736A defines normal as half the

' distance between the high and low level marks.

--Water additions to the batteries were logged on February 14, and

March 14, 21, and 28, 1990. The method of logging additions was not- ,

uniform. Amounts added were logged either in milliliters or inches

of cell. height. On March-21, 25 cells of battery 201A and 43 cells

of battery 201B were noted to be at or below minimum level. From the '

data. recorded, the inspector was unable to determine either the

as-found levels of individual cells or the amount of water added

thereto. .t

--On March 7, 1990 no water additions were recorded and all cell

levels were logged as normal. The inspector also reviewed the

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automated work orders'(AWO) for battery surveillances performed on

March 7 and 14, 1990 ' The results logged in these AW0s were

consistent with those recorded on the surveillance data sheets.

Licensee administrative control procedure ACP-QA-8.16,~ Training, ,

Certification and Identification of Qualified Inspection, Examination '

and Testing Personnel, revision 18, dated March 22, 1988, establishes

the method of and minimum qualifications required for certifying test i

personnel at Millstone. Personnel who are assigned responsibilities

or authority to perform testing activities shall be certified in

writing as qualified. Through interviews with the unit 2 maintenance

manager and also with the assistant maintenance supervisor involved

in the allegation, the inspector determined that the contractor

personnel who performed battery surveillance on March 7, 1990 were

not certified per ACP-QA-8.16, and had performed the surveillance ,

activity while not under direct observation. l

The inspector interviewed the unit 2 maintenance manager on April 5,

1990 regarding the allegations and received a written formal response '

dated April 18, 1990. This response stated that the contractors

involved had reported to a maintenance supervisor on March 7 that 8

to 10 cells were below the minimum level .line. The cognizant

supervisor, who signed off the surveillance procedure and the AW0s,

had not been present during the performance of the activity and was

not privy to this information. He signed the AWO based on review of

the data presented, verification of test instrument calibration, and

discussion of the procedure and results with the contractors. As a

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O result, the battery cell level data recorded on the maintenance forms

associated with the surveillance performed on March 7, 1990 are 3

incorrect for the 8 to 10 unidentified cells involved.

The inspector concluded that at no time were the cell plates of bat-

". .teries'201A or 201B likely to have become uncovered. IEEE Standard l

450-1980, Appendix D1, Urgency of Corrective Actions, states that the l

addition of water is not urgent unless the tops of the plates are in

danger of being exposed. Thus, the ability of the station batteries-

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'to function-if challenged was unaffected by the low water level con-

dition, and the_ inspector considered the safety significance _ of the

condition to be minimal.

Nevertheless,_the inspector identified the'following concerns

regarding this event: !

--Contrary to the requirements of.ACP-QA-8.16, unsupervised

surveillance was performed on safety related equipment by uncertified

contractor personnel. ,

---Contrary to the requirements of SP-2736A, and as a normal practice,

cell levels which did not meet the acceptance criteria of the i

procedure were not recorded on the data sheets.

--The method of documenting water additions to individual battery

cells was not uniform, resulting in at least one occasion in which

the amount of water added to over 68 cells could not be determined

adequately,

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--On at-least one occasion, a decision was made by a licensee

supervisor to accept cell levels not meeting the acceptance criteria i

of SP-2736A based on technical considerations not adequately '

documented.

The inspector considered these activities to constitute a violation

of NRC requirements (50-336/90-09-01). Licensee corrective actions

will be considered during performance of the routine _ resident

inspection program.

This item is closed.

9.0 Management Meetings

Periodic meetings were held with station management to discuss

inspection findings during the inspection period. A summary of

findings _ was also discussed at the conclusion of the inspection. No

proprietary information was covered within the scope of the inspec-

. tion. No written material was given to the licensee during the

inspection period.

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ML20055E799

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