ML20205R880

Insp Rept 50-423/86-15 on 860415-0519.No Violation Noted. Major Areas Inspected:Plant Operations,Radiation Protection & Surveillance & Maint

ML20205R880
Person / Time
Site:	Millstone
Issue date:	05/21/1986
From:	Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20205R869	List: ML20205R865 ML20205R880
References
RTR-NUREG-0737, RTR-NUREG-737 50-423-86-15, NUDOCS 8606050510
Download: ML20205R880 (10)

See also: IR 05000423/1986015

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report No. 50-423/86-15

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Docket No. 50-423

License No. NPF-49

Licensee: Northeast Nuclear Energy Company

P.O. Box 270

Hartford, CT 06101-0270

Facility Name: Millstone Nuclear Power Station, Unit 3

Inspection At: Waterford, Connecticut

Inspection Conducted: April 14, 1986-May 19, 1986

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Inspectors: J. T. Shedlosky, Senior Resident Inspector

F. A. Casella, Resident Inspector

Approved by: @ f'/2' I8C

E. C. McCabe, Chief, Reactor Projects Section 3B Date

Inspection Summary:

Areas Inspected: Routine on-site resident inspection (167 hours0.00193 days <br />0.0464 hours <br />2.761243e-4 weeks <br />6.35435e-5 months <br />) of plant opera-

tions, radiation protection, surveillance and maintenance. Observations were made

during off-normal plant events and power ascension testing.

Results: Licensee response to several events resulting in EHC fluid or steam leaks

was prompt and minimized the potential for equipment damage or personnel injury

(Detail 2). The licensee's initial corrective actions taken to correct a design

deficiency in ITE Brown-Boveri K600 circuit breakers was found responsive in cor-

recting a Substantial Safety Hazard reported under 10CFR21.

8606050510 860523

PDR ADOCK 05000423

G PDR

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TABLE OF CONTENTS

PAGE

1. Summary of Facility Activities....................................... 1

2. Review of Plant Events............................................... 1

a. Power Reduction for EHC Repair.................................. I

b. Secondary Plant Steam Leak...................................... 2

c. Reactor Trip-Partial Loss of Circulating Water.................. 3

3. Review of Plant Operations........................................... 3

4. Power Ascension Test Witnessing...................................... 4

Results: a. Reactor Trip from 100% Power.......................... 4

b. Ini ti al Performance Test. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

5. Maintenance and Modifications........................................ 5

a. Engineered Safety Features (ESF) Status Panel................... 5

b. Main Steam Isolation Valve (MSIV) Operating Solenoids........... 6

c. Plant Maintenance............................................... 6

6. Surveillance Testing................................................. 6

7. Review of Licensee Event Reports (LERs).............................. 7

8. Licensee Action on Previous Inspection Findings...................... 7

9. Station Security Events.............................................. 8

10. Management Meetings.................................................. 8

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1. Summary of Facility Activities

The plant was operating at 75% power at the beginning of the inspection period.

Nuclear instrumentation in core and ex-core axial flux difference calibrations

were in progress. Power was increased to 90% following a brief power reduc-

tion to repair an Electro-Hydraulic Control System fluid leak. The plant

reached rated thermal power, 3411MW(t), at 2210, April 17.

The final tests in the power ascension program were conducted on April 21,

when 10% load swings and a full power generator load rejection test was com-

pleted from 1184MW(e). The reactor was made critical at 2300 the same day

and the unit was declared to be in commercial operation at 0001 on April 23.

A steam leak occurred on a bolted manway closure of the "A" Moisture Separator j

Reheat Steam Drain Tank at 0711 on April 23. Load was reduced and the turbine r

was tripped in an attempt to isolate the leak. Later, a reactor trip occurred

from 10% power on low steam generator level when the operator lost level con-

trol.

Following repairs, the reactor was made critical at 1944, April 23 and was

returned to full power at 0311, April 25 to begin the One-Hundred-Hour War-

ranty Run. This was completed at 0825, April 29. The plant operated at full

power until 0909, May 9, when the turbine was manually tripped in response /.

to the loss of two condenser circulating water pumps. This occurred when in-

take structure traveling screen clogging caused high differential pressure.

The plant remained shutdown until 2024, May 12, when the reactor was again

made critical.

A water hammer occurred at about 1900, May 12, while preparing to place the

"C" First Point (High Pressure) Feedwater Heater in service. The plant

startup had been made with the heater isolated to repair a crack on the supply

line to a shell side relief. The water hammer damaged the heater emergency

level control valve. The heater remained isolated to allow repairs to the

valve operator and yoke.

2. Review of Plant Events

a. Power Reduction for EHC Repair

On April 14 , at about 0730, an Electro Hydraulic Control (EHC) System

oil leak was discovered on the "D" main turbine gover:.or valve. The -

plant was at 75% power, 878MW(e). Oil was spraying at approximately one

gallon per minute; there was no danger of loss of reservoir level but

there was a concern about possible damage of electrical cable insulation

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in the vicinity. A power reduction was started immediately. The genera-

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tor was taken off-line, and the turbine was secured at 0838. Mode 1 was

l maintained; the reactor was borated to 10% power. Repairs were under-

l taken as soon as the affected portion of the EHC system was depressurized.

l The oil spill was well controlled and cleaned up. No electrical cable

! insulation was affected. The cause of the leak was determined to be an

improperly seated "0" Ring in the control block to the governor valve.

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Seating surfaces were cleaned and a new "0" ring installed. The ensuing

pressure test was satisfactory; the turbine was rolled at 1124 and placed

on the line at 1209. Plant recovery was timely and well done. The main

generator breaker was closed at noon and plant power was then returned

to 75%.

The inspector observed the licensee's actions taken in response to this

event. He found that they were prompt, well-coordinated, and in conform-

ance with station operating procedures and the Technical Specifications.

The licensee minimized equipment and personnel exposure to the EHC fluid.

No safety-related equipment was involved. There were no unacceptable

conditions identified.

"0" rings on the other turbine control valves were replaced during a

brief shutdown after the April 21 Full Load Rejection Test.

b. Secondary Plant Steam Leak

A manway cover gasket of the "A" Moisture Separator Reheat (MSR) Steam ,

Drain Tank failed at 0711, April 23. The unit was at about 60% power

at the time. The leak occurred with no warning; the rapid pressurization

and steam jet force ruptured an insulation package which had been in-

stalled over the manway. Due to the significant amount of steam in the

turbine building, the exact location of the leak was not determined until

the reheat steam supply was secured.

Control room operators began reducing load at 0728 and tripped the tur-

bine manually at 0753. This isolated the major source of steam. The

Main Steam Isolation Valves (MSIVs) were shut at 1009 to further isolate

the drain tank for maintenance. The licensee found that about one-third

of the failed gasket, which was a flat asbestos composition material,

had blown out, causing the leak at the bolted manway cover flange. Re-

pairs were made to both Reheat Steam Drain Tanks by replacing the flat

gaskets with reinforced spiral wound ones.

After the 0753 turbine trip, a reactor trip occurred at 0815 due to low-

low steam generator (SG) level. This was found to be due to insufficient

operator skill in maintaining manual level control of all four SGs simul-

taneously. Improvement of the operators' skill in manual SG level con-

trol is expected to require practice through experience during plant

operation. The reactor was made critical at 1944 and the tu%ine genera-

tor placed on-line at 0738, April 24.

The inspectors monitored plant status and operator actions in the control

room from shortly after the leak started until it had been isolated.

The most significant equipment damage involved non-safety-related 480

Volt Bus 32A, located on the elevation below the source of the steam leak.

At 0715, a ground was indicated on that bus, which was de energized at

0734. The bus was cleaned, dried, and satisfactorily returned to service.

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The inspectors found that the operators had taken appropriately conser-

vative actions based on the best information on the source of the leak.

Personnel from supporting departments (e.g., maintenance production test

and security) were brought in and directed to take specific action which

located the leak, minimized equipment damage, and prevented personnel

injuries.

The inspectors observed the replacement of the manway gaskets. Although

the seating surfaces were not steam cut, the "B" Drain Tank manway gasket

exhibited degradation.

There were no unacceptable conditions identified.

c. Reactor Trip-Partial Loss of Circulating Water

A reactor trip at 0909, May 9 and accompanied a manual turbine trip from /

about 85% power. This was in response to the automatic trip of two main

circulating water pumps. High differential pressure across the associated

intake traveling screens initiated the pump trips. The screen wash sys-

tem had been secured at 0630 to modify the supply piping. Although the

licensee had scheduled this system outage when weather and sea conditions

were favorable without wash water, all circulating water pumps had tripped

by 0940 due to screen fouling. The service water system was not affected.

Following completion of the modifications, which involved connecting new

replacement piping into the system, the circulating water system was re-

turned to service. It has since operated satisfactorily.

The inspector observed control room activities from shortly after the

turbine trip / reactor trip until decay heat removal systems were in ef-

fective operation. The control room operators responded well to the loss

of condenser vacuum and implemented the unit abnormal operating proce-

dures. After maintenance on a generator exciter bearing, a change in

the main turbine balance weight placement, and implementation of a modi-

fication to the MSIV operating solenoid power supplies, the reactor was

made critical at 2024, May 12, and the turbine generator placed on line

at 0513, May 13. There were no unacceptable conditions identified.

3. Review of Plant Operations

The inspector observed plant operations during regular and back shift tours

of the following:

Control Room Fence Line (Protected Area)

Auxiliary Building Yard Areas

Diesel Generator Building Turbine Building

Intake Structure Vital Switchgear Areas

Main Steam Valve Building Electrical Tunnels

Waste Disposal Building

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The control room tours included observation of instrument parameters related

to conformance to Technical Specification requirements. Alarm conditions in

effect and alarms received at the control room during the period of observa-

tion were reviewed. The operators were cognizant of board conditions. Shift

manning was compared with Technical Specifications. Plant housekeeping con-

trols were observed. Also, during plant tours, the various logs in the Con-

trol Room, Chemistry department, and Health Physics department were reviewed.

In addition, the inspector observed selected actions concerning site security

including personnel monitoring, access control and placement of physical bar-

riers. No deficiencies were identified.

4. Power Ascension Test Witnessing

The inspectors witnessed portions of various Power Ascension Tests performed

under procedures INT-8000 and INT-9000. Test witnessing included review of

the following:

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Plant Technical Specification requirements were met.

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Tests were preformed using current revisions of approved procedures with

all prerequisites and initial conditions met.

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Briefings were held for all personnel involved; operator actions during

test performance were correct, timely and coordinated.

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Communications were timely and accurate.

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Supervisory personnel made initial summary analyses to verify plant re-

sponse was as expected.

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Preliminary test evaluation was consistent with the inspector's observa-

tions.

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Test acceptance criteria were met.

Results:

a. Reactor Trip from 100% Power

This test verified the ability of the primary and secondary plants and

automatic control systems to sustain a trip from 100% power and recover

to stable conditions. Additionally, major transmission lines were moni-

tored for grid stability during the loss of this large input.

At 0500 on April 21, the main generator output breaker was opened while

the generator was loaded to 1184 megawatts. The generator trip initiated

a turbine trip which initiated a reactor trip. All rods fully inserted.

No pressurizer or steam generator safety valves lifted. Pressurizer

level remained above 20%. Pressure reached approximately 2050 psia.

Primary temperature remained above 551F. No safety injection occurred.

The inspector had no questions.

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b. Initial Performance Test

This test was performed on April 29 to verify turbine warranty require-

ments and to obtain baseline data for secondary plant performance moni-

toring. Section 7.4 of the test placed the plant in an abnormal condi-

tion to measure the turbine control valves' wide-open steam flow. Rod

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control was placed in manual at rated thermal power (3411MW). The plant

was borated to reduce Tave. Pressurizer heaters were energized to force

spray flow and induce mixing. As steam pressure lowered, the control

valves came to full open. One hour of steady state data was collected.

Boron concentration was then reduced to bring Tave back to normal, and

control rods were returned to automatic control. The inspector verified

that the Axial Flux Difference remained in the target band, the Tave-Tref

difference did not exceed 20F, and Tave did not go below 553F. The in-

spector had no questions.

5. Maintenance and Modifications

a. Modifications to the Engineered Safety Features (ESF; Status Panel

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As a result of the NUREG 0737 Control Room Design Review, six Human /

Engineering Discrepancies (HED TA 8) were found on the ESF status panel.

The licensee had committed to resolving these discrepancies prior to fuel

load, but extended the completion dates without informing NRC. The in-

spector verified that the later correction of these discrepancies did

not impact Technical Specification operability requirements or have any

adverse effect on execution of emergency operating procedures. (The

modifications enhance acceptable operator aids and displays.)

The ESF status panel is a 70" X 16" bank of 1.5" square engraved windows

that represent the condition of valves and pumps in ESF systems. The

light behind a window is energized when the component satisfies the en-

graved condition. The lights are arranged in 6 groups. Grouping is such

that all lights in a given group should be on or off depending on the

phase of the hypothesized accident involved.

The Human Engineering Discrepancies found on the ESF status panel dealt

with labelling of the six groups, illumination of blank tiles, consist-

ency of tile colors, addition of Reactor Plant Component Cooling Water

valves, and changes to related annunciators on Main Board 2.

In a letter to NRR dated January 29, 1986, the licensee committed to have

HED TA 8 completed by April 30, 1986. Moreover, the scope of the work

was expanded from the original six categories of modifications to 17

categories to further enhance display usefulness and accuracy.

As a result, to complete the modifications, the ESF status panel was de-

energized for approximately 2 days with the plant at power. Retesting

took about another 2 days after the panel was re-energized.

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The inspector reviewed the Plant Design Change Request that initiated

the modifications (PDCR MP3-86-094) and observed work in progress while

4 the ESF panel was deenergized. Appropriate compensatory measures were

taken to reasonably assure that information similar to that displayed

in the ESF status panel would be available if needed. Work was well

controlled and carefully completed. No unacceptable conditions were

identified.

-b. Main Steam Isolation Valve (MSIV) Operating Solenoids

The licensee installed current limiting devices supplied by the MSIV

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vendor in the power supply lines to the MSIV operating solenoids under

AWO M3-86-09212. This change was made to reduce heat generation by the

- solenoids, thereby extending the lifetime of the cables. Valve stroke

, times were acceptable after the modifications were completed. The in-

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spector had no further questions.

c. Plant Maintenance

The inspector observed and reviewed preventive and corrective maintenance

to verify compliance with regulations, use of administrative and main-

tenance procedures, compliance with codes and standards, proper QA/QC

involvement, use of bypass jumpers and safety tags, personnel protection

and equipment alignment and retest. The following activities were in-

cluded:

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Refurbishing of #11 main turbine / generator bearing.

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Repair of motor-driven and turbine-driven feed pump shaft seals.

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"B" Emergency Diesel Generator monthly preventive maintenance.

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Replacement of A&B Moisture Separator Reheater Drain Tank manway

cover gaskets.

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Fabrication of temporary screen wash piping.

No unacceptable conditions were noted.

6. Surveillance Testing

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The inspector observed parts of tests to assess performance in accordance with

approved procedures and Limiting Conditions for Operation, removal and res-

toration of equipment, and deficiency review and resolution. The following

tests were reviewed:

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Operational test of "A" Emergency Diesel Generator.

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Operational test of the Turbine-Driven Auxiliary Fresh Water Pump.

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Main Steam Isolation Valve Stroke time testing.

In addition, the inspector performed a check of the Turbine-Driven Auxiliary

Feedwater System valve lineup referencing surveillance procedure SP3622.4.

No unacceptable conditions were noted.

7. ReviewofLicenseeEventReports(LERsl

LERs submitted during this report period were reviewed. The inspector as-

sessed LER accuracy, whether further information was required, if there were

generic implications, adequacy of corrective actions, and compliance with the

reporting requirements of 10CFR 50.73 and Administrative Control Procedure

ACP-QA-10.09. Selected corrective actions were checked for thoroughness and

implementation.

Those LERs reviewed were:

86-016-01, Area Temperature Monitoring

86-023-00, Containment Area Radiation Monitors Calibrated Non-Conservatively

86-024-00, P-8 Protective Interlock Setpoint High

86-025-00, Control Building Inlet Ventilation Radiation Monitor Inoperability

86-026-00, Failure to Perform Axial Flux Difference Surveillance

86-027-00, Partial Safety Injection

86-028-00, Feedwater Isolation and Reactor Trip Due to Steam Generator Water

Level Transient

86-030-00, Reactor Trip on Steam Generator Low Level

8. Licensee Action on Previous Inspection Findings

a. (Closed) UNR (50-423/86-08-02)

A Brown-Boveri K6005 Breaker control wiring harness location deficiency

was verbally submitted as a 10CFR21 report on May 1, 1986; the written

report was provided on May 9, 1986. The licensee commenced corrective

modifications on May 3. These modifications entailed relocating the

control wiring harness away from the breaker racking pawl by increasing

the size of the access hole through which the wiring harness passes and

drilling and tapping the breaker frame for a new harness support. Also,

the control wiring was to be replaced if damage was discovered.

There are 140 K6005 breakers used as the 480 load center output breakers

to loads and motor control centers. Of these, 41 are safety-related and

17 of those are required to change position during an Engineered Safety

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Features actuation. These 17 breakers were the first scheduled for re-

work. All 17 have been completed. Thirteen of the remaining 24 are

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motor control center feeder breakers, whose control power fuses have been

pulled under a Bypass Jumper. These breakers are normally shut, remain

shut during accident conditions, and will only be controlled locally.

The remaining eleven 6005 breakers are racked out because they are either

spares or they supply fuel pool cooling pumps and fuel building ventila-

tion system components which will not be required until spent fuel is

present.

The licensee has committed to completing modifications on all 140 breakers

by the end of the first refueling outage. The inspector reviewed the

Plant Design Change Request (PDCR MP3-86-136), the 10CFR21 report and

selected automated work orders directing the work to be accomplished.

There were no unacceptable conditions identified.

9. Station Security Events

The inspectors reviewed three reported security events, including immediate

actions, compensatory measures, cause analysis, and long-term corrective

actions.

50-245/86-013-00 This event concerned maintenance without following estab-

lished procedures. The licensee's corrective actions were found to address

the root cause. Additionally, the security officer who discovered the condi-

tion performed well. There were no unacceptable conditions identified in

review of this licensee identified and corrected problem.

50-245/86-14-00 The inspector reviewed the licensee's actions on a security-

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related telephone call. There were no unacceptable conditions identified.

50-245/86-016-00 A security officer's attention to duty was questioned. The

licensee is considering disciplinary options. No unacceptable corrective

action conditions were identified.

10. Management Meetings

During this inspection, periodic meetings were held with senior plant manage-

ment to discuss the scope and findings. No proprietary information was iden-

tified as being in the inspection coverage. No written material was provided

to the licensee by the inspector.