ML20205R880
| 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: |
| 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.
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
ADOCK 05000423
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TABLE OF CONTENTS
PAGE
1.
Summary of Facility Activities.......................................
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2.
Review of Plant Events...............................................
1
a.
Power Reduction for EHC Repair..................................
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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. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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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)..............................
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8.
Licensee Action on Previous Inspection Findings......................
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9.
Station Security Events..............................................
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10.
Management Meetings..................................................
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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
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Reheat Steam Drain Tank at 0711 on April 23.
Load was reduced and the turbine
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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
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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.
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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
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
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maintained; the reactor was borated to 10% power.
Repairs were under-
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taken as soon as the affected portion of the EHC system was depressurized.
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The oil spill was well controlled and cleaned up.
No electrical cable
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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
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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
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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:
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.
Briefings were held for all personnel involved; operator actions during
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test performance were correct, timely and coordinated.
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Communications were timely and accurate.
Supervisory personnel made initial summary analyses to verify plant re-
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sponse was as expected.
Preliminary test evaluation was consistent with the inspector's observa-
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tions.
Test acceptance criteria were met.
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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
control was placed in manual at rated thermal power (3411MW).
The plant
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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
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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
the ESF panel was deenergized.
Appropriate compensatory measures were
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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
vendor in the power supply lines to the MSIV operating solenoids under
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AWO M3-86-09212.
This change was made to reduce heat generation by the
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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.
Replacement of A&B Moisture Separator Reheater Drain Tank manway
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cover gaskets.
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Fabrication of temporary screen wash piping.
No unacceptable conditions were noted.
6.
Surveillance Testing
The inspector observed parts of tests to assess performance in accordance with
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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.
Operational test of the Turbine-Driven Auxiliary Fresh Water Pump.
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Main Steam Isolation Valve Stroke time testing.
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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-
related telephone call.
There were no unacceptable conditions identified.
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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.