ML20023D930
| ML20023D930 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 05/21/1983 |
| From: | Elsasser T, Lipinski D, Shedlosky J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20023D921 | List: |
| References | |
| 50-245-83-06, 50-245-83-6, 50-336-83-08, 50-336-83-8, NUDOCS 8306060171 | |
| Download: ML20023D930 (19) | |
See also: IR 05000245/1983006
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U. S. NUCLEAR REGULATORY COMMISSION
Region I
t
50-245/83-06
Report No.
50-336/83-08
50-245
Docket No.
50-336
License No. DPR-65
Priority
Category
C
Licensee:
Northeast Nuclear Energy Company
P. O. Box 270
Hartford, Connecticut 06101
Facility Name: Millstone Nuclear Power Station, Units 1 & 2
Inspection at:
Waterford, Connecticut 06385
Inspection conducted:
February 27, 1983, thru April 16, 1983
Inspectors:
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J. T. Shedlosky, Sr. Resident Insp~ector
date signed
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D. R. Lipinski, Resident Inspector
date signed
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Approved by: -4
h/cLe // /ff3
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T. C. EPrfsser, Chief
dat$tigh'ed
Reactor Projects Section 18,
Division of Project & Resident Programs
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Inspection Summary:
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Unit 1:
Routine facility safety inspections, February 27, 1983, thru April 16, 1983.
(Report Number 50-245/83-06) including:
evaluations of plant operations, equipment
alignments and readiness, radiation protection, physical security, fire protection,
plant operating records, maintenance and modification, surveillance testing and
calibrations, and reporting to the NRC. The inspection involved 146 hours0.00169 days <br />0.0406 hours <br />2.414021e-4 weeks <br />5.5553e-5 months <br /> of
onsite, regular, and backshift inspection effort by two resident inspectors.
Results: No' violations . identi fied.
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8306060171 830523
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PDR ADOCK 05000245
C
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Unit 2:
Routine facility safety inspections, February 27, 1983, thru April 16, 1983
(Report Number 50-336/83-08) including: evaluations of plant operations, equipment
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alignments and readiness, radiation protection, physical security, fire protection,
plant operating records, maintenance and modifications, surveillance testing and
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calibrations, ard reporting to the NRC. The inspection involved 200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br /> of
onsite, regular, and backshift effort by two resident inspectors.
Results: One violation was identified - Failure to maintain reactor power below
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89% while monitoring in core linear heat rate with the Excore Detector Monitoring
System.
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DCS Identification Numbers
Inspection Report
50-245/83-06
50-336/83-08
DCS Number
Report Paragraph
50336-830301
3j
50245-830324
31
50245-830324
3m
50245-830331
3n
50245-830203
6
50245-830207
6
50245-830207
6
50245-830125
6
50245-830216
6
50245-830215'
6
50336-830302
6
50336-830127
6
50336-830219
6
50336-830218
6
50336-830219
6
50336-830318
6
50336-830319
6
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DETAILS
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1.
Persons Contacted
The below listed technical and supervisory level personnel were among those
contacted:
R. Asafaylo, Training Supervisor
J. Crockett, Unit 3 Superintendent
F. Dacimo, Quality Services Supervisor
J. Etheridge, Radioactive Materials Handling Supervisor
B. Granados, Health Physics Supervisor
D. Kross, Unit 2 Instrumentation and Control Supervisor
R. J. Herbert, Unit 1 Superintendent
J. Kangley, Radiological Services Supervisor
J. Keenan, Unit 2 Maintenance Supervisor
J. J. Kelley, Unit 2 Superintendent
E. J. Mroczka, Station Superintendent
V. Papadopoli, Quality Assurance Supervisor
R. Place, Unit 2 Engineering Supervisor
R. Palmieri, Unit 1 Engineering Supervisor
W. Romberg, Unit 1 Operations Supervisor
S. Scace, Unit 2 Operations Supervisor
F. Teeple, Unit 1 Instrumentation and Control Supervisor
W. Varney, Unit 1 Maintenance Supervisor
P. Weekley, Security Supervisor
2.
Status of Open Items
New Items:
1
Unit 1
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None
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Unit 2
50-336/83-08-01
Violation: Failure to maintain reactor power below 89% as
required when monitoring fuel linear heat rate with the
Excore Detector Monitoring System.
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50-336/83-08-02
Open Item: Followup results of licensee study of poential
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methods of more positively identifying and alarming process
computer failures.
Old Items:
None reviewed.
3.
Review of Plant Operation - Plant Inspection (Units 1 and 2)
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The inspectors reviewed plant operations through direct inspection and obser-
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vation of Units 1 and 2 throughout the reporting period. Unit 1 operated at
(
full power through the inspection period with the exception of a forced out-
age March 24 through 31 to correct high reactor coolant system leakage (in-
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cluding reactor trips on March 24 and 31). Unit 2 operated a full power
throughout the inspection period with the exception of a forced outage March
1 through 17 to correct high reactor coolant system leakage.
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a.
Instrumentation
Control room process instruments were observed for correlation between
channels and for confomance with Technical Specification requirements.
No unacceptable conditions were identified.
b.
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The inspector observed various alarm conditions which had been received
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and acknowledged. These conditions were discussed with shift personnel
who were knowledgeable of the alams and actions required.
During plant
inspections, the inspector observed the condition of equipment associated
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with various alanns.
No unacceptable conditions were identified.
c.
Shift Manning
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The operating shifts were observed to be staffed to meet the operating
requirements of Technical Specifications, Section 6, both to the number
and type of licenses.
Control room and shift manning was observed to
be in conformance with Technical Specifications and site administrative
procedures.
d.
Radiation Protection Controls
Radiation protection control areas were inspected. Radiation Work Permits
in use were reviewed and compliance with those documents as to protective
clothing and required monitoring instruments was inspected.
Proper posting
of radiation and high radiation areas was reviewed in addition to verifying
requirements for wearing of appropriate personal monitoring devices.
There were no unacceptable conditions identified.
e.
Plant Housekeeping Controls
Storage of material and components was observed with respect to
prevention of fire and safety hazards.
Plant housekeeping was evaluated
with respect to controlling the spread of surface and airborne contamina-
tion. There were no unacceptable conditions identified,
f.
Fire Protection / Prevention
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The inspector examined the condition of selected pieces of fire
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fighting equipment.
Combustible materials were being controlled and
were not found near vital areas.
Selected cable penetrations were
examined and fire barriers were found intact.
Cable trays were clear
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of debris. There were no unacceptable conditions identified.
g.
Control of Equipment
During plant inspection, selected equipment under safety tag control
was examined.
Equipment conditions were consistent with information
in plant control logs.
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Instrument Channels
Instrument channel checks recorded on routine logs were reviewed. An
independent comparison was made of selected instruments.
No unacceptable
conditions were identified.
1.
Equipment Lineups
The inspector examined the breaker position on switchgear and motor
control centers in accessible portions of the plant. Equipment
conditions, including valve lineups, were reviewed for conformance
with Technical Specifications and operating requirements. No unacceptable
conditions were identified.
J.
Forced Outage - March 1 Through 17 (Unit 2)
During the period of March 1 through 17, Unit 2 was in a forced
maintenance outage to correct Reactor Coolant System (RCS) leakage.
Total RCS leakage had risen irregularly during the operating cycle.
On March 1, 1983, the licensee determined that unidentified RCS
leakage exceeded Technical Specification 3.4.6.2 limit of 1.0 gallon
per minute (GPM).
The inspectors reviewed the licensee's actions and plar.t conditions
prior to, during and after the outage. This review focused in three
areas:
the measurement of total RCS leakage; the training and
control of workers in preparation for steam generator inspection and
maintenance, and the steam generator tube inspections.
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(1) Measurement of RCS Leakage
Technical Specification 3.4.6.2 establishes limits for RCS leakage
for 1.0 GPM unidentified leakage and 0.5 GPM primary-to-secondary
leakage through either steam generator. The Safety Analysis Bases
for these limits is to provide early detection of additional leakage,
which may be pressure boundary leakage, and to ensure that the dosage
contribution from tube leakage is limited to a small fraction of Part
100 limits in the event of a tube rupture or a steam line break.
Total RCS leak rate is calculated by an inventory mass balance in the
RCS, the Chemical Volume Control System and associated make-up and
waste tanks. This is normally calculated by the process computer
which, as part of the calculation, subtracts leakage collected by
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closed systems, such as the reactor coolant pump (RCP) controlled
seal flow subsystem. Technical Specification 1.14 allows for correcting
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for leakage into closed systems and leakage into the containment
atmosphere. That leakage must be from sources which are specifically
located; do not interfere with RCS leakage detection systems; are not
pressure boundary leakage and do not exceed 10.0 GPM. A quality
verification of the process computer calculations is performed using
a special engineering test procedure, T83-5, Revision 0, dated
February 4, 1983. During this test, potential leakage from the
Chemical Volume Control System is removed as is the uncertainty
associated with RCP seal flow.
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The inspectors have reviewed both methods of leak rate calculation.
There were no unacceptable conditions identified.
(a) RCS Leakage Prior to Shutdown
Prior to the plant shutdown on March 1,1983, leakage totaling
0.12 GPM had been identified from valve 2-SI-247, a safety
injection check valve, and from valve 2-RC-405, a power operated
relief valve blocking valve.
This leakage, into the containment
atmosphere, was first observed on March 9, 1982; had been
measured weekly by the licensee during the operating cycle and
was used to correct the total RCS leakage to determine the
unidentified RCS leakage.
A primary-to-secondary leak in the No. 1 Steam Generator, first
detected on March 10, 1982, was calculated at 0.29 GPM prior to
shutdown on March 1, 1983. This leakage was calculated using
radio-isotopic concentrations in the reactor coolant and steam
generator secondary water.
A reactor shutdown was begun at 1730, March 1, 1983 when total
and unidentified RCS leak rates were determined to be 1.77 GPM
and 1.34 GPM, respectively.
Because no other sources of leakage
were known, Operating License Amendment No. 82 was issued to
allow an additional 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> before the reactor was required to
be in Cold Shutduwn, Mode 5.
This allowed additional time for
inspection at operating temperature and pressure.
Inspections were conducted on March 2.
No additional sources of
RCS leakage were found; a plant cooldown was commenced at 1427,
March 2.
The reactor was placed in cold shutdown at 0908, March
3.
(b) Primary-to-Secondary Leakage No.1 Steam Generator
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An effort was made to corroborate the calculated primary-to-
secondary leak rate of the No. 1 Steam Generator.
During an
inspection, leakage from one tube was measured at 800 cc per
minute. Plant conditions established for this test were to fill
and presse<!ze the steam generator secondary to 200 psia and to
drain and vent the steam generator primary channel head.
This leakage collected corresponds to a primary-to-secondary
leak rate at operating conditions of between 0.39 and 0.68
GPM.
These valves are within the range of calculated leak
rates occuring when various assumptions are made for defect
size, shape and stability with pressure and temperature changes.
Primary-to-secondary leakage, therefore, exceeded the 0.5 GPM
limit of Technical Specification 3.4.6.2.c.
Because of this test and the inconsistency between the leak
rate calculated during operations (0.29 GPM) and that calculated
as the result of inspections (0.39 to 0.68 GPM) the NRC included
a more restrictive specification for primary-to-secondary
leakage in Operating License Amendment 83. The previous limit
of 0.5 GPM has been changed to 0.35 GPM through the end of the
present operating cycle.
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During this period the inspectors observed the licensee's
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testing program and performed independent calculations.
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Following repairs, total RCS leak rates have remained below
0.2 GPM and primary-to-secondary leakage has remained below
0.1 GPM. The licensee is investigating the inconsistency in
leak rate calculations. Although these calculations were
qualified by several outside organizations, there is no allowance
for interference caused by the sludge pile. Since the defect
location is at the top of the steam generator tube sheet, a form
of " hide-out" may occur as fission products migrate through the
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sludge pile, which is nine inches thick.
There were no additional unacceptable conditions identified.
The issue of leak rate calculations is being addressed with
the licensee by the NRC Division of Licensing.
(2) Worker Training and Radiological Controls
The inspectors observed the training conducted on March 6.
The
training was conducted prior to entry into the steam generator
primary channel heads to install reactor coolant piping nozzle covers
and CCTV cameras. The training was found to simulate actual conditions
in and around the steam generators and used full-scale mock-ups.
After indoctrination discussions, the workers were trained in teams
needed to perform the required tasks.
They were outfitted in the
same type of protective clothing used for steam generator entry and
repeated the exercise until the results and stay times were acceptable.
To further evaluate the training, an inspector participated in
mock-up training being conducted for inspection personnel on March 7.
During periods of steam generator entry for inspection or repair,
observations of the implemented radiological controls were made.
The inspectors reviewed radiological survey data taken prior to
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worker entry into the steam generators.
Using this data the stay-times
established by the licensee were verified as being conservative.
There were no unacceptable conditions identified.
(3) Steam Generator Tube Inspections
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As described in paragraph (1)(b) above, a steam generator tube
leakage test was conducted. One tube, No. 120-94 in the No. 1 Steam
Generator Hot Leg side, was found leaking. That tube is adjacent to
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a Tie Rod, which is a structural support for the steam generator tube
support plate.
Eddy Current Testing (ECT), a non-destructive examination, was
conducted of the defective tube, the five others surrounding the
tie rod and the three remaining tubes surrounding the defective
tube. Additionally six other tubes adjacent to a second tie rod
in the No. 1 Steam Generator Hot Leg side were tested.
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One other tube was found with a recordable defect of 34 percent
wall thickness. That tube, No. 121-93, is adjacent to the defective
tube and the tie rod. Both tubes were removed from service by
plugging.
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Technical Specification 4.4.5.1.3.c.1 requires additional, unscheduled
inservice inspections of steam generator tubes in the event primary-to-
secondary leakage exceeds 0.5 GPM in either steam generator.
Because
there was evidence that leakage exceeds 0.5 GPM additional inservice
inspection was required; however, since the licensee was planning a
large scale inservice inspection program for the refueling outage
scheduled to start on May 28, 1983, the NRC provided a one time
exemption from additional inservice inspection requirements. Operating
License Amendment 83 deferred the inspection requirements of Technical Specification 4.4.5.1.3.c, Table 4.4-6, Category C-1 because of
the events associated with the March 1, 1983 outage.
(4) Results of Previous Steam Generator Tube Inspections
The defective tube (120-94) had been ECT examined during the 1982
outage. The tube had not been rejected during that program and no
defects were recorded for it in the final program report.
Because this tube was now leaking, the licensee located the magnetic
tapes which contain the 1982 ECT data for this tube; then, reviewed
and re-analyzed the data. The licensee has concluded that a defect
in excess of the 40 percent plugging limit did exist, but, was
overlooked in 1982. The depth of the defect was quantified to be 83
percent of tube wall thickness when the 1982 data was re-analyzed in
March, 1983. The licensee has attributed this lack of performance in
ECT due to the location of the defect which is at the elevation that
the tube penetrates the top of the steam generator tube sheet. The
transition through the tube sheet along with an apparent dent in
the tube wall at the same height creates interferences with the
analysis of the ECT signal.
The licensee has reviewed the ECT data for other tubes in the No. 1
Steam Generator for which a dent signal was recorded at the top of
the tubesheet elevation during 1982 inspections.
From this review,
no additional defects were identified.
This data was presented to
the NRC as the bases for Operating License Amendment 83.
There were no additional unacceptable items identified.
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k.
Implementation of NRC Balletin 82-02 During Maintenance (Unit 2)
NRC Bulletin 82-02, " Degradation of Threaded Fasteners in the Reactor
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Coolant Pressure Boundary of PWR Plants", includes inspection requirements
for cracking and corrosion when components are opened for maintenance.
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During the March I through 17 outage, valve 2-SI-247 was opened for
maintenance. This valve is a 12-inch swing check valve located in a
0.35 Roentgen per hour radiation field and had levels of 2.0 Roentgen
per hour on contact.
Bulletin 82-02 provides for relief from certain requirements when
components are located in high radiation fields.
This is due to
worker exposure considerations. Based on previous experience, there
was a possibility for galling the A453 Grade 660 stainless steel
studs when being removed from the A351 Grade CF-8M cast stainless
steel valve body. As there were 16 studs in all, representatives of
the Office of Inspection and Enforcement granted relief from the full
inspection requirement during a conference call with the licensee on
March 10. Two stainless steel studs were to be fully examined using
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surface non-cRstructibletest methods; a carbon steel stud was to be
examined and then replaced with a stainless steed stud. All studs
were to be visually examined for evidence of boric acid cyrstals,
pitting, and cracking. Of particular importance was the transition
of chrome plated surfaces at the threads. Unacceptable conditions
would include gross pitting of pin-head size in the threads.
Stud
deformation was to be monitored during reassembly.
No evidence of closure stud degradation was observed during this
inspection. No unacceptable conditions or practices were identified.
1.
Forced Outage - March 24 through 29 (Unit 1)
During March 24 through 29, Unit 1 conducted a forced maintenance
outage to correct high unidentified RCS leakage.
During the preceding weeks, calculations of unidentified RCS leak
rates displayed an upward trend. On March 24 the leak rate exceeded
the Technical Specification limit of 2.5 GPM.
This leak rate is calculated
by integrating the flow from the drywell floor drain sump over a
period of time. A reactor shutdown was conducted on March 24.
Inspection revealed packing leakage from valve 1-IC-1, the Isolation
Condenser steam supply line inboard isolation valve, and a body-to bonnet
leak from a mechanical seal in valve 1-FW-118, a feedwater supply
line manual isolation valve.
Following repairs, the reactor was made
critical on March 27. A final inspection during heatup identified
additional packing leakage and mechanical connection leakage from
valve 1-MS-3A, a Target Rock Safety / Relief Valve. The reactor was
returned to cold shutdown and repairs completed. The reactor was
again made critical on March 29.
Since then, RCS unidentified
leakage has remained below 0.4 GPM.
No unacceptable conditions were identified,
m.
Reactor Trip - March 24 (Unit 1)
During the shutdown on March 24, a reactor trip occurred from low
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power level (Intermediate Range Monitor (IRM) range No. 8) at 2205.
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Reactor water level was in manual control using the feedwater regulating
valve (FRV) bypass valve. When additional water was needed, the
blocking valve for one of the two FRV's was opened.
In this case the
operator mistakenly opened the blocking valve associated with the FRV
which was selected for use with the Feed Water Coolant Injection
(FWCI) subsystem.
Since reactor water level was below the setpoint
level, the FWCI selected FRV was open. The resulting inrush of
cooler water caused power level to rise to the IRM upscale high
reactor trip level.
This transient was investigated because the running Condensate
Booster Pump and Feedwater Pump tripped due to insufficient net
positive suction head when feedwater flow rapidly increased. The
concern was that the FWCI subsystem would cause the same sequence of
events, resulting in tripping of running pumps.
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The licensee completed an engineering analysis which resulted in
changing setpoints for the feed water pump flow limiter. This
subsystem, part of the reactor water level control system, acts to
close the FRV and limit flow to 105 percent of rated. Administrative
controls have been established to require that the feed water pump
minimum flow valve be operated in automatic and that a minimum of two
condensate pumps and three condensate demineralizers be in service
during startup and shutdowns to provide adequate FWCI response in
high flow demand conditions originating from low reactor power.
Subsequent testing has confirmed acceptable FWCI performance.
n.
Reactor Trip - March 31 (Unit 1)
On March 31, 1983 at 1502, Millstone Unit 1 experienced a reactor
trip from 87% of full power.
The reactor trip resulted from a turbine trip caused by a false high
level sensed in the turbine moisture separator. The moisture separator
drain tank level control valve air operator diaphram had previously
been replaced and the valve cycled for testing. The valve subsequently
failed in the full open position due to a defective positioner. As
the drain tank emptied, staam flow through the moisture separator
resulted in vibration which spuriously tripped the mercury float-type
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level switch. All other equipment functioned properly during the
transient. The reactor was again made critical at 2241 on March 31
and reached full power on April 2.
No unacceptable conditions were observed.
4.
Review of Plant Operations - Logs and Records (Units 1 and 2)
During the inspection period, the inspector reviewed operating logs and
records covering the inspection time period against Technical Specifications
and Administrative Procedures requirements.
Included in the review were:
Shift Supervisor's Log
-daily during control room surveillance
Plant Incident Reports
-2/27/83 through 4/16/83
Jumper and Lifted Leads Log
-all active entries
Maintenance Requests & Job Orders -all active entries
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Construction Work Permits
- all active entries
Safety Tag Log
- all active entries
Plant Recorder Traces
- daily during control room surveillance
Plant Process Computer Printed Output - daily during control room surveillance
Night Orders
- daily during control room surveillance
The logs and records were reviewed to verify that entries are properly made;
entries involving abnormal conditions provide sufficient detail to communi-
cate equipment status, deficiencies, corrective action, restoration and test-
ing; records being reviewed by management; operating orders do not conflict
with the Technical Specifications; logs and incident reports detail no viola-
tions of Technical Specification or reporting requirements; and logs and re-
cords are maintained in accordance with Technical Specification and Administra-
tive Control Procedure requirements.
There were no unacceptable conditions identified.
5.
Review of Periodic and Special Reports
Upon receipt, periodic and special reports submitted by the licensee pursuant
to Technical Specification 6.9.1 and 6.9.2 and Environmental Technical Speci-
fication 5.6.a were reviewed by the inspector. This review included the fol-
lowing considerations: the report included the information required to be re-
ported by NRC requirements; test results and/or supporting information are
consistent with design predictions and performance specifications; planned
corrective action is adequate for resolution of identified problems; determin-
ation of whether any information in the report should be classified as an ab-
normal occurrence; and the validity of reported information. Within the scope
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of the above, the following periodic reports were reviewed by the inspector:
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Monthly Operating Report, Units 1 and 2, February, 1982
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Annual Report 1982, Units 1 and 2*
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- Includes report of safety / relief valve challenges made in accordance with
NUREG-0737, Item II.K.3.3.
6.
Licensee Event Reports (LERs)
The inspector reviewed the following LERs to verify that the details of the
event were clearly reported including the accuracy of the description of cause
and adequacy of corrective action. The inspector detennined whether further
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information was required, and whether generic implications were involved. The
inspector also verified that the reporting requirements of Technical Specifi-
cations and Station Administrative and Operating Procedures had been met, that
appropriate corrective action had been taken, that the event was reviewed by
the Plant Operations Review Committee, and that the continued operation of the
facility was conducted within the Technical Specification limits.
Unit 1
83-03
Setpoint drift,1 of 4 High Reactor Pressure pressure switches. LER
82-25 reported setpoint drift of a pressure switch used in this appli-
cation; however, a different switch was involved.
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83-04
Diesel Generation inoperable.' The resident inspector observed
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subsequent corrective maintenance and retesting as described
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in Inspection Report 50-245/83-05.
83-05
Setpoint drift,1 of 4 Main Steam Line Low Pressure, pressure '
switches.
LER 83-01 reported setpoint drift of a pressure
switch used in this application; however, a different switch
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was involved.
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83-06
Setpoint drift,1 of 16 Steam Tunnel High Temperature thermal
switches.
LER 82-26 reported similar drift.
83-07
Setpoint drift,1 of 8 Main Steam Line Isolation Valve limiti
switches. LER 82-15 reported setpoint drift in a limit switch
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used in this application; however, a different switch was
involved.
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83-08
Setpoint drift,1 of 2 Isolation Condenser Isolation differ-
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ential pressure switches.
LER 82-07 also reported drift in
this switch.
83-09
Setpoint drift,1 of 4 Reactor water level switches which
actuate ECCS systems.
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Unit 2
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A liquid radioactive release was made without continuously
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83-01
recording the associated radiation monitor output.
No dis-
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charge limits were exceeded. Alarm functions were unimpaired.
83-02
Failure to conduct operability test on "C" Charging Pump due
to personnel error.
83-03
High reactor coolant system iodine concentration following
the reactor trip of February 19.
Peak activity reached 1.32
microcuries per gram dose equivalent iodine 131.
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83-04
Dropped Control Element Assembly.
Inspection Report 50-336/
83-06 addresses this event
83-06
Voluntary entry into an action statement involving credit for
a repaired but yet untested High Pressure Safety Injection Pump.
83-07
An error was discovered in the reactor safety transient
analysis involving a postulated steam generator tube rupture.
The steam generator pressure which had been " assumed" to be
conservative was shown to be non-conservative.
Recalculation
of the consequences of a steam generator tube rupture event
indicates continued compliance with 10 CFR 100 (Paragraph 10).
83-08
A reactor mode change inadvertently occurred due to a feedwater
system transient. A hydraulic pipe snubber required to be
operable in the new mode was undergoing repair. Within 2
minutes, power was reduced. Snubber repairs were completed
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prior to return to power operation.
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83-09
Operation of the reactor at a power level exceeding Technical Speci-
fication limits for existing plant conditions during a period of over
5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> on March 26, 1983.
At 1546 on March 25, Millstone Unit 2 experienced a failure of its pro-
cess computer which caused computer output screens to fail to update,
and to continue to display the last values of parameters computed.
Digital clocks on both video monitors on main control board C04 and
the video monitor on the reactor operator's desk were frozen at
15:46:43. This failure went unnoticed by plant operators through a
shift change and was not identified until 2100 on March 26.
Indica-
tions of this failure available in the control room included lack of
updates of data on the three video monitors described above, particu-
larly clock updates; lack of updates of the Balance of Plant Log; and
lack of updates on the Alarm Typer.
At Millstone Unit 2, the process computer plays important roles in mon-
itoring Control Element Assembly (CEA) position and fuel linear heat
rate. Technical Specification 3.2.1 requires that fuel linear heat
rate be limited to 15.8 kilowatts per foot (KW/ft). The accompanying
surveillance requirements permit monitoring linear heat rate usirig
either incore neutron detectors or excore neutron detectors.
Incore
detector monitoring requires use of the process computer.
Excore de-
tector monitoring is independent of the process computer; but, due to
greater measurement uncertainties, reactor power is limited to a maxi-
mum of 89% of full power when relying upon excore detectors.
From the time of the failure, reactor power remained at 100% until the
operators discovered the failure and took action to reduce power.
Reac-
tor power reached 86% of rated power at 2148 on March 26. Troubleshoot-
ing revealed a fault in a circuit card (IBM Part Number 5800199). The
computer was returned to service at 0259 on March 27.
During this event, the reactor was operated at full power, above that
permitted by Technical Specifications with the process computer and in-
core neutron detectors inoperable for a period of over 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. Num-
erous symptoms of the process computer failure were available in the
control room during that time.
Failure to maintain reactor power be-
low 89% while monitoring linear heat rate with the Excore Detector
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Monitoring System is a violation (50-336/83-08-01).
Followup analysis by the licensee of plant conditions prior to, during
and following the event indicate that it is not likely that the fuel
linear heat rate limit of 15.8 KW/ft was exceeded. The licensee has
reinstructed plant operators on the necessity of monitoring the pro-
cess computer. The engineering department has undertaken a study of
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possible modifications to the process computer system to more posi-
tively identify and alarm computer failures. The inspectors will
follow this effort under open item 50-336/83-08-02.
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83-10
Usage factor applied to pressurizer spray line because .of high
differential temperature during plant cooldown.
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7.
Plant Maintenance and Modifications
During the inspection period, the inspector frequently observed various
maintenance and problem investigation activities. The inspector reviewed
these activities to verify:
compliance with regulatory requirements,
including those stated in the Technical Specifications; compliance with
the administrative and maintenance procedures; compliance with applicable
codes' and standards; required QA/QC involvement; proper use of safety
tags; proper equipment alignment and use of jumpers; personnel qualifica-
tions; radiological controls for worker protection; fire protection;
,
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retest requirements; and, reportability as required by Technical Specifi-
cations.
In a similar manner the implementation of design changes and
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modifications were reviewed.
In addition to those items addressed above,
the licensee's safety evaluation was reviewed.
Compliance with require-
ments to update procedures and drawings were verified and post modifica-
tion acceptance testing was evaluated. The following activities were
included in this review:
Unit 1
Hanger / Seismic Support modifications to the Core Spray System
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suction ring header.
,
Hanger / Seismic Support modifications to the Torus -Drywell
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Vacuum Breakers.
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Drywell Nitrogen Compressor mounting modifications.
Corrective maintenance to Feedwater Manual Stop Valve,
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1-FW-118.
Corrective maintenance on Drywell Air Coolers HVH-18 and
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HVH-22.
Unit 2
Inspection and corrective maintenance on No. 2 Steam
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Generator.
Corrective maintenance on Safety Injection Check Valve,
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2-SI-247.
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8.
Inspector Witnessing of Surveillance Tests
The inspector witnessed the performance of surveillance testing of
selected components to verify that:
the surveillance test procedure was
properly approved and in use; test instrumentation required by the procedure
was calibrated and in use; technical specifications were satisfied prior
to renoval of the system from service; the test was performed by qualified
personnel; the procedure was adequately detailed to assure performance of
a satisfactory surveillance; and test results satisfied the procedural
acceptance criteria or were properly dispositioned. The inspector witnessed
the performance of:
Unit 1
" Reactor Coolant Chemistry at Stea;ning Rates of 100,000
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Pounds per Hour or Greater" per SP-840, Revision 0 on
March 14.
" Analysis of Reactor Coolant for Radioactivity" per SP-838,
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Revision 1, on March 14.
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" Conductivity Bridge - L&N" per CP-801J, Revision 1, on
March 14*.
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" Chloride Analysis by Spectro Photometry Method" per
CP-808L, Revision 0, on March 14**.
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" Stack Gas Monitor System Functional Test" per CP-836,
Revision 2, Change 1, on March 15.
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" Main Steam Line Radiation Monitor Functional Test" per
SP-406B, Revision 1, on March 15.
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" Turbine Stop Valve Closure Functional Test" per SP-408F,
Revision 4, on March 15.
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" Main Steam Safety / Relief Valve Discharge Vacuum Breaker
Valves ISI Readiness Test" per SP-1093, Revision 0, on March 15.
---
" Inspection of Hydraulic Snubbers" per SP-673.2, Revision 4,
on March 25.
(Inspection of recirculation system snubbers
located inside primary containment)
Unit 2
---
" Aerated Liquid Rad Waste Process Radiation Monitor Functional
Test RM-9116" per SP-2404A, Revision 1, Change 3, on March 18.
---
" Calibration of Excore Nuclear Instrument (NI's) to Incores"
per SP-2401E, Revision 6, on March 22.
- This chemical analysis procedure is consistant with American Society
for Testing and Materials (ASTM), Part 23, Standard D-1125.
- This chemical analysis procedure is consistent with ASTM, Part 23,
Standard D-512-67.
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" Power Range Safety Channel and Delta T Power Channel Calibra-
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tion" per SP-26010, Revision 3, on March 22.
9.
Bulletin Follow-Ups-(Unit 2)
" Failure of the Undervoltage Trip Function of
Reactor Trip Breakers"
The inspector observed the licensee actions taken in response to Bulletin 83-04. The Reactor Protective System (RPS) at Millstone Unit 2 uses
General Electric Type AK-2 circuit breakers.
Both undervoltage and shunt
trip coils are actuated by the RPS.
Reactor Protective System integrated
response time testing is presently incorporated in the planned surveil-
lance system.
On March 14, the licensee tested'the breaker-trip mechanism for each
RPS Trip Breaker by separately de-energizing the undervoltage coil or
energizing the shunt trip coil.
Each t,'ip coil in each breaker was
tested at least once.
The inspector observed a portion of the testing;
the results were acceptable.
On March 17, the definition of " failure" in context of the subject Bulletin
was provided by the NRC OIE Events Analysis Branch as...
" ... failure to trip is considered to be either complete failure
to open, or " sluggish" action in excess of the overall system
response time (400 milliseconds for CE plants) assumed by plant
safety analyses."
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Surveillance testing of the breaker undervoltage trip devices only was
conducted on March 17 and witnessed by the inspector. All breaker under-
voltage trip devices actuated ana caused the respective breakers to open
within 0.050 seconds of voltage removal.
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The plant maintenance program addresses these breakers and includes re-
furbishment, alignment, and testing each cycle.
An independent review
is being conducted of these procedures prior to use in the May 1983
refueling outage.
A written account of the Salem fail-to-trip event has been circulated
among licensed operators reporting for shift duty. The resident inspector
reviewed routing sheets bearing operator initials documenting operator
review of the event.
No unacceptable conditions were observed.
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10.
Error in Steam Generator Tube Rupture Accident Analysis -(Unit 2)
On March 18.. the licensee determined that an ' error had been made by the
NSSS, Combustion Engineering, in the assumed initial plant conditions
for the analysis 'of a Steam Generator Tube Rupture. The current analysis
incorrectly assumed t5at the Main Steam System Atmospheric Steam Dump
Valves were operated in the manual mode and that the Steam Generator
secondary pressure was 860 psia. Lower than normal pressure was selected
to maximize the primary to secondary flow through the~ break.
A re-analysis made by the licensee established initial conditions of
Atmospheric Steam Dump Valves operating in automatic and Steam Generator ,
secondary pressure at 933 psia. The higher initial pressure resulted in-
operation of both the Atmospheric Steam Dump Valves and Steam Generator
Safety Valves, these being the release point to the environment.
In
contrast, the current analysis resulted in a release from the Unit 2
vent stack through the condenser and air ejector system.
The re-analysis resulted in a calculated thyroid dose of 250 mrem at
the site boundary. The less conservative analysis had calculated
6 mrem. This is contained in Section 14.14 of the Millstone Unit 2
FSAR, dated June 10, 1982.
This error is potentially generic because it.had been made by the NSSS supplier.
The licensee has provided the NRC with information in an LER No.50-336/83-07.
11. Design Deficiency in Emergency Diesel Generator Control Circuit - (Unit 1)
A design deficiency was determined to exist in the Millstone Unit 1 Emer-
gency Diesel Generator Control Circuit. This deficiency would prevent
successful re-start of the diesel engine during accident conditions
following re-set of the generator lock-out relay.
The diesel generator is a Colt Industries, Fairbanks-Morse Model 3800
TD8-1/8. The control circuit is a combination of designs made by Colt
Industries, Euclid Equipment and Ebasco Services.
However, other units
with a timed diesel fuel shutoff may have a similar design deficiency.
The time delay ensures that the diesel has come to a complete stop prior
to a re-start attempt, and is implemented with a 34 second time delay
relay which energizes the governor shut-down solenoid.
The problem exists during accident conditions when the Emergency Safety
Systems actuation logic provides a continuous start signal to the
diesel generator control circuit.
If the diesel is shutdown, as could
occur through operation of the generator lock-out relay, manual emer-
gency stop or local stop switches or start failure circuit, the diesel
cannot be restarted. Unless the time delay fuel shut-off relay inter-
rupts the start signal along with the diesel fuel supply, the machine
will attempt to start without fuel and will either deplete its air
start reservoir or shutdown after an unsuccessful attempt to start.
This problem may be generic to other emergency power sources having a
timed diesel fuel shutdown circuit.
It was discovered at Millstone
while following-up INPO Significant Event Report 62-82 which described
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a loss of Emergency Bus event at North Anna 2 on March 8,1982 (LER 50-
339/82-13). Details concerning this finding were provided to the
NRC OIE which subsequently issued Information Notice 83-17; " Electrical
Control Logic Problem Resulting in Inoperable Auto-Start of Emergency
Diesel Generator Units".
The licensee is preparing a modification which, using an additional relay,
will interrupt the air start signal when the fuel cut-off solenoid is
energized.
It is expected to be implemented on April 18.
12. Emergency Planning Exercise
The inspectors observed a functional test of the Emergency Plan on March 2.
The test included a radiological assessment exercise which was implemented
through a team of drill controllers using a radiological survey scenario.
A recently developed system for transmission of control room data was used.
There were no unacceptable conditions identified.
13. . Review of Radioactive Material Shipments - (Unit 1)
The inspector reviewed the activities concerning the shipment
of a'" limited quantity" shipment of contaminated tools from
Millstone Unit 1 to Vermont Yankee Atomic Power Station. The
inspector observed package preparation, radiological surveys,
and documentation. An " Exclusive use" vehicle was used. The
inspector conducted independent radiological surveys to confirm
licensee results.
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No unacceptable conditions were identified
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' 14.
Exit Interview
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At periodic intervals during the course of the inspection, meetings were
held with senior facility management to discuss the inspection scope and
findings.
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