ML18086B366
| ML18086B366 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 02/24/1982 |
| From: | Greenman E, Hill W, Norrholm L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18086B364 | List: |
| References | |
| 50-272-82-01, 50-272-82-1, 50-311-82-01, 50-311-82-1, NUDOCS 8203160505 | |
| Download: ML18086B366 (16) | |
See also: IR 05000272/1982001
Text
. .
~.
Report Nos.
Docket-Nos.
U. S. NUCLEAR REGULATORY COMMISSION
50-272/82-01
50-311/82-01
50...:272
50-311
REGION I
License Nos.
~~~~...---~~~~~~~
Licensee:
Public Service Electric and Gas Company
80 Park Plaza
Newark, New Jersey
07101
050272-820119
050272-820131
050272-820201
050272-820205
050311-820114
050311-820201
050311-.;820205
Facility Name:
Salem Nuclear Generating Station - Units 1 and 2
Inspection At:
Hancocks Bridge, New Jersey
8' 1982
Inspectors:
Approved By:
No. 2A,
Inspection Summary:
-@.(!z._
1 da e
~hLF1-
'Ciate
~Uk~
date
Inspections on January 1 - February 8, 1982 (Combined Report Numbers 50-272/82-01
and 50-311/82-01)
Unit 1 Areas Inspected: Routine inspections by the resident inspectors of
plant operations including tours of the facility; conformance with Technical
Specifications and operating parameters; log and record reviews; reviews of
licensee events; and followup on previous inspection items. The inspection
involved 62 inspector hours by the r~0siAent NRC inspectors.
. .
Results:
T#o~.*1te.ms.. of. nQf.l~QJJ1pU~ncE;,.we.r¢. * tclenttf.t~~' .{f,&flure *1ct~ follq\\.:t **PTOC~clures -
Paragraph 3~:. Pai'l ure *to fol low. radiati'cl'h protection procedure *:. Paragrapll * 4)
Unit 2 Areas Inspected: Routine inspections by the resident inspectors df *
plant operations including tours of the facility; conformance with Technical
Specifications and operating parameters; log and record reviews; reviews.of
licensee events; and followup on previous inspection items.
The inspection
involved 86 inspector hours by the resident and regional NRC inspectors.
Results: Three items of noncompliance were identified (Failure to follow/
implement procedures ...: Paragraphs 3, 4, and 6, failure to properly approve
and issue a procedure - Paragraph 6, failure to make a report in accordance
with 10 CFR 50.72 - Paragraph 6).
..
.
..
DETAILS
1. Persons Contacted
J. Driscoll, Assistant General Manager - Salem Operations
L. Fry, Operations Manager
J. Gallagher, Maintenance Manager
H. Midura, General Manager - Salem Operations
L. Miller, Technical Manager
J. O'Connor, Radiation Protection Engineer
F. Schnarr, Reactor Engineer
R. Silverio, Assistant to the General Manager
J. Stillman, Station QA Engineer
The inspector also interviewed other licensee personnel during the
course of the inspections including management, clerical, maintenance,
operations, performance and quality assurance personnel.
2. Status of Previous Inspection Items
lClosed) Unresolved Item (311/78-43-01)
Insulation removal during
in-service inspection of supports. The licensee uses
section IWF-1300 paragraph (e) of Article IWF-1000 of the
ASME Code as justification for not removing insulation
during support inspections. Accordingly, procedure M17B,
Coded Component and Pipe Support Visual Examination (Classes
1, 2, and 3), Revision*:7, dated January 6, 1982 states,
11Supports that are not welded to the system where the system
is insulated may be inspected without removing insulation
provided no stress is apparent. Supports that are welded to
the system shall have the insulation removed before inspection
is performed." The inspector had no further questions on
this item.
(Closed} Follow Item (272/81-19-01) Chemistry technician training.
Training procedure No. 41 Setting forth the training program
for chemistry technicians has been completed and issued on
December 2, 1981.
The inspector had no further questions on
this item.
(Closed)-- Follow Item (272/81-19-02) Training records for I&e: helpers.
- The training records for I&C helpers have been completed,
updated and are maintained by the ,performance Department.
The inspector had no further questions on this item.
i.,*
.,
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3
SITE
3. Shift Logs and Operating Records
a.
The inspector reviewed the following plant procedures to detennine
the licensee established requirements in this area in preparation
for a review of selected logs and records.
AP-5, Operating Practices, Revision 11, August 13, 1981;
AP-6, Incident Reports and Reportable Occurrences, Revision 7,
October 8, 1981;
AP-13, Control of Lifted Leads and Jumpers, Revision 4, February
11, 1980;
Operations Directive Manual; and,
AP-15, Safety Tagging Program, Revision 1, November 21, 1980.
b. Shift logs and operating records were reviewed to verify that:*
Control room log sheet entries are filled out and initialled;
Auxiliary log sheets are filled out and initialled;
Log entries involving abnormal conditions provide sufficient
detail to conununicate equipment status, lockout status, correc-
tion and restoration;
Log book reviews are being conducted by the staff;
Operating orders do not conflict with Technical Specification
requirements;
Incident reports detail no violation of Technical Specification
LCO or reporting requirement; and,
Logs and records were maintained in accordance with Technical
Specifications and the procedures in 3.a above.
c.
The review included examination of the following plant shift logs
and operating records and discussions with licensee personnel:
Log No. 1 - Control Room Daily Log, January 1 - February 8, 1982
Log No. 6 - Primary Plant Log, January 1 - February 8, 1982
4
Log No. 7 - Secondary Plant Log, January 1 - February 8, 1982
Log No. 8 - Unavailable Equipment Status Log, January 1 -
February 8, 1982
Night Orders, December 23, 1981 - January 6, 1982
Lifted Lead and Jumper Log - All active
Tagging Requests - All active
Nonconformance Reports for December 1981 and January 1982
d.
During the log review, the inspector identified two instances,
on January 23, 1982, in which maintenance contractor personnel
started work on the service water and safety injection systems
prior to proper isolation of the systems.
In each case, the system
was still filled and pressurized when breached.
No personnel injury
or contamination resulted in either case. Station Administrative
Procedure 15 (AP-15) requires that the supervisor in charge of the
work assure himself that the system or equipment is isolated and
the tags are in place before any work is started. The above failures
to secure this assurance contribute to noncompliance with Technical
Specification'6.8.1 (272/82-01-01).
In addition, during this period,
an attempt to clear tags on service water to containment fan coil
units was aborted by operators when the system was found not to
have been restored.
One control valve had not been reinstalled in
the system.
e.
The inspector had no further questions with respect to logs and
records reviewed.
4.
Plant Tour
a.
During the course of the inspections, the inspector made observations
and conducted multiple tours of plant areas, including the following;
(1)
Control Room (daily)
(2)
Relay Rooms
(3)
Auxiliary Building
~)
Vital Switchgear Rooms
~}
Turbine Building
..
b.
5
(6)
Yard Areas
(7)
Radwaste Building
(_8)
Penetration Areas
(9)
Control Point
(10) Site Perimeter
(11)
Fuel Handling Building
(12}
Guard House
(13)
Containment (Unit 1)
The following detenninations were made:
Monitoring instrumentation. The inspector verified that selected
instruments were functional and demonstrated parameters within
Technical Specification limits.
Valve positions. The inspector verified that selected valves were
in the position or condition required by Technical Specifications
for the applicable plant mode.
This verification included exam-
ination of control board indication and field observation of valve
positions (Charging/Safety Injection, Auxiliary Feedwater, and
Containment Spray Systems).
Radiation Controls.
The inspector verified by observation that
control point procedures and posting requirements were being
followed and that Radiation Exposure Pennits were properly employed.
Plant housekeeping conditions. The inspector observed that with
limited exceptions, housekeeping was generally acceptable.
Any
cluttered or littered areas for which maintenance was not in
progress, was brought to the attention of the plant management
or operating staff.
Fluid leaks.
No fluid leaks were observed which had not been
identified by station personnel and for which corrective action
had not been initiated, as necessary.
Piping vibration.
No excessive piping vibrations were observed
and no adverse conditions were noted .
..
6
Selected pipe hangers and seismic restraints were observed and
no adverse conditions were noted.
Equipment tagging.
The inspector selected plant components for
which valid tagging requests were in effect and verified that
the tags were in place and the equipment in the condition speci-
fied.
By frequent observation through the inspection, the inspector
verified that control room manning requirements of 10 CFR 50.54
(k} and the Technical Specifications were being met.
In addition,
the inspector observed shift turnovers to verify that continuity
of system status was maintained.
The inspector periodically
questioned shift personnel relative to plant conditions and
their knowledge of emergency procedures.
Releases.
On a sampling basis, the inspector verified that appro-
priate documentation, sampling, authorization, and monitoring
instrumentation were provided for effluent releases.
Fire protection. The inspector verified that selected fire ex-
tinguishers were accessible and inspected on schedule, that fire
alann stations were inspected on schedule, that fire alarm sta-
tions were unobstructed and that cardox systems were operable.
Technical Specifications. Through log review and direct observa-
tions during tours, the inspector verified compliance with
Technical Specifications including Limiting Conditions for
Operation (LC0
1s}. The following parameters were sampled fre-
quently:
RWST level, BAST level and temperature, containment
temperature, boration flow path, offsite power, BAST and
Accumulator chemistry.
In addition, the inspector conducted
periodic visual checks of protective instrumentation and inspec-
tion of electrical switchboards to confinn availability of safe-
guards equipment.
Security. During the course of these inspections, observations
relative to protected and vital area security were made, including
access controls, boundary integrity, search, escort, and badging.
c.
The following acceptance criteria were used for the above items:
Technical Specifications
Operation Directives Manual
Inspector Judgement
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7
d.
During a tour of Unit 1 Containment on January 8, 1982, the inspector
identified at least three individuals inside the bioshield who were
not attired as required by Radiation Exposure Permit (REP) 0008.
The
REP required that, for entries inside the biological shield, both
caps and hoods were to be worn in addition to the standard protective
coveralls, gloves and boots.
On February 2, 1982, during a tour of
the Unit 1 Fuel Handling Building, the inspector identified one in-
dividual who was present in the posted contaminated area with no
coveralls or laboratory coat. The least restrictive Radiation Ex-
posure Permit (REP) for the area, EREP # 9901, required protective
clothing for inspection tours in contaminated areas. Adherence to
stated requirements of Radiation Exposure Permits is dictated by
station Administrative Procedure 24, Radiological Protection Program.
The above failures to comply with REP requirements contribute to
noncompliance with Technical Specification 6~11: (272/82-01-03).
e.
The inspector had no further questions relative to tours made during
this inspection.
5.
Review of Periodic and Special Reports
Upon receipt, periodic and special reports submitted by the licensee
pursuant to Technical Specifications 6.9.l and 6.9.2 were reviewed by
the inspector.
This review included the following considerations:
The report included the information required to be reported by
NRC requirements;
Test results and/or supporting information were consistent with
design predictions and performance specifications;
Planned corrective action was adequate for resolution of identi-
fied problems; and,
Determination whether any information in the report *should be
classified as an abnormal occurrence.
Within the scope of the above, the following periodic reports were re-
viewed by the inspector:
Unit 1 Monthly Operating Report - December 1981
Unit 2 Monthly Operating Report - December 1981
No unacceptable conditions were identified.
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6. Operating Events
a.
UNIT 1
8
(1) The unit was shutdown to start the third refueling outage on January
1, 1982, and entered Mode 6 on January 11, 1982.
By January 20, 1982, the licensee had completed eddy current testing
of steam generator tubes in Steam Generators 12 and 14, with the
following results:
Steam Generate>'r 12
947 tubes tested
3 defective
2 degraded
1551 tubes tested
8 defective 24 degraded
All defective tubes were plugged.
Both degraded tubes in Steam
Generator 12 and 9 degraded tubes in Steam Generator 14 were plugged.
The licensee has elected to plug all defective tubes with greater
than 30 % wall thinning. All indications were found in peripheral
tubes, within five rows of the edge. All indications are located at
the first, second, and/or third support loc~tions and are in the cold
leg. Licensee Event Report 272/82-02 was submitted to document the
initial findings.
The licensee plans to inspect Steam Generators 11
and 13 prior to conclusion of the outage. Additionally, the licensee
has submitted an amendment request for relief from 100 % inspection
on the basis that this problem is confined to peripheral tubes. This
item will be inspected further on receipt of the final report and
final licensing action prior to startup (272/82-01-02).
(2) By February 1, 1982, all fuel had been removed from the reactor and
fuel inspection, using a remotely-operated TV system, identified one
failed fuel pin.
On assembly C-04, pin 9 face 2, between grid straps
7 and 8, had two complete ruptures, exposing the fuel pellets, and
a circumferential crack. Visual evidence of corrosion or wear was
found at the break sites. The assembly was scheduled for discharge
during this outage and has a total burnup of 34,674 MWD/MT.
Inspec-
tion of this assembly during the previous outage had identified pin
gap closure at this location to the extent that the two adjacent
pins may have been touching. This had been judged acceptable at the
time.
Dose equivalent Iodine just prior to shutdown on December 31,
1981 was 1.68 E-2 uCi/ml.
Complete inspection of the 33 remaining
assemblies with the same burnup scheduled for re-use in the next
cycle identified no other failures.
Prompt Licensee Event Report
272/82-05 was submitted. Vendor evaluation of the failure mechanism
is continuing.
No similar gap closures were identified in reload
fuel assemblies. This event will be reviewed further when the final
licensee event report is issued *
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(3)
(4)
9
At approximately 9:15 a.m. on February 1, a temporary connection
between the Unit 1 and Unit 2 Spent Fuel Pool Heat Exchangers
failed and spilled up to 30,000 gallons of Unit 1 Spent Fuel Pool
Water into the Unit 1 and 2 Auxiliary Buildings on elevations 84'
and 64'. To support a complete shutdown of the Unit 1 Component
Cooling System, the Spent Fuel Cooling system had been cross-
connected to the Unit 2 Spent Fuel Heat Exchanger via an 8"
diameter hard rubber hose. The hose slipped off a connection at
the Auxiliary Building dividing wall. The resulting spill dropped
level in the Spent Fuel Pool by approximately one foot.
The re-
ported maximum water level was 3" on elevation 64' before floor
drains lowered the level. Surface contamination levels to 3000
cpm were measured.
No airborne activity was found in the Auxiliary
Building. A slight increase in the plant vent monitor was noted,
resulting in a release less than 0.1 % of the instantaneous release
limit. Sixteen persons received contamination to shoes and trousers.
The most recent fuel pool gross activity was 7.2E-4 uCi/ml. Follow-
ing the hose failure, the Unit 1 Component Cooling System was re-
turned to service. Spent Fuel Pool temperature never exceeded
820F and level did not go below the 23 feet required above stored
fuel. The licensee will make a written 30-day report. The hose
installation was strengthened by the addition of another hose clamp,
for a total of three, at each fitting, specifying torque values for
clamp bolts, the addition of safety chains, and periodic surveillance
for slippage while the system was in service.
In addition, the
doors to switchgear rooms were sealed to prevent or reduce the amount
of water leaking in, should the hose fail again.
No recurrence or
slippage of the hose was identified when the system was returned to
service.
At approximately 11:00 a.m. on February 5, a health physics tech-
nician noticed lint being blown out of a dryer vent at the trailer
facility being used to launder used protective clothing.
An air
sampler was operating at the vent discharge and showed air activity
levels on the order of E-11 uCi/cc gross beta~ An area of the yard
approximately 10 feet on a side was covered with the lint discharge.
Maximum levels read with a frisker were 9000 dpm. A bypass flow-
path had developed in the discharge filter on the dryer.
The dryer
was shutdown, the area roped off and cleaned up, and the filter
replaced. Based on the potential for an unplanned release, the
licensee notified the NRC duty officer via ENS at 1:10 p.m.
The
Senior Resident Inspector was informed at 11:30 a.m. and a Radiation
Specialist already on site followed licensee actions.
No personnel
we_re contaminated.
The total postulated release was less'than 0.1
uCi. A Licensee Event Report will be submitted *.
... ,
" ...
10
Time
b.
UNIT 2
(1} Continuing problems with freezing of circulating water screens~,
required taking the generator off line at 6:55 p.m. on January 11.
The reactor remained in Mode 2.
The unit was again synchronized
at 11:14 p.m. on January 11.
l2} On January 14, 1982, Salem Unit 2 experienced a load reduction
transient which involved loss of rod control, an unseated secondary
safety valve, elevated average temperature and restoration of plant
stability without a trip. The initiating event was a reduction
in Steam Generator Feedwater Pump (SGFP} suction pressure precipi-
tated by instability in the heater drain system.
Due to several
previous trips attributed to such instability (reference NRC
Inspection Reports 50-311/81-27 and 81-29}, the licensee had
established guidelines for dealing with loss of suction pressure
and had installed a temporary alarm (set at 300 psig} to warn
operators that pressure was approaching the SGFP trip point of
215 psig. These guidelines called for bypassing the Condensate
Polishing System {CPS} and reducing turbine load in 10 % incre-
ments.
The inspector developed the following sequence of events based
on review of records, process parameter recorder charts, and
discussions with personnel.
Chart Parameters
Reactor Stm
Pzr
MWe
Power
Flow Pressure
Tavg
0104 Slight dip in heater drain pump
flow on recorder chart
0105
21 Heater Drain Tank high level 1060
0106 Intermittent, then steady, SGFP 1060
94
94
95
95
2230
2250
568
568
- low suction pressure alann (300
psig}~ Operator initiated load
reduction by intennittently re-
ducing valve position limit.
Started manual rod insertion!
Immediate Urgent Failure Alann.
No further rod motion possible
in manual or auto. Bypassed
condensate polisher. Started
manual boration at 10 gpm.
.
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11
Reactor Stm
Pzr
Time
Mwe
Power
Flow Pressure
Tavg
0107
SGFP suction pressure alann clears 230
92
85
2240
575
when CPS bypass valves fully open.
Terminate load reduction at 450,
load continues to drop to 230.
0108
SGFP suction pressure alann comes
240
89
74 ' 2230
582
up and.clears again. All high
steam flow alarms up.
Four steam
dump valve groups fully open,
remainder throttling.
0109 Tavg decreasing from 582, SGFP
250 89.5
74
2220
580
low suction pressure alarm.
enters control room, orders load
increase.
0110
SGFP low suction pressure alann
260
90
82
2210
578
clear.
22 and 24MS 167 (MSIV)
"open" lights out. Operator taps
11open
11 push button and "open
11
light immediately comes on.
0111
260
91
65
2210
576
0112
260
91
48
2200
574
0113 Begin increasing turbine load.
260
92
58
2200
574
Steam dump holding Tavg at 574
0114
310
91
58
2190
574
0115
350
89
58
2200
574
0116
400
86
58
2250
574
0117 Operator resets load rejection.
440
84
58
2290
574
0118 Pressure peak, full spray.
490
82
58
2340
592
Tavg peak
0119
530
80
56
.2290
590
0120 Tavg decreasing.
550
77
56
2250
589
SG pressure 1080.
23 MSL safety valve lifts
(23 MS 15 only::Oconfinned visually)
- ,
. .
Time
0121
0122
0123
0124
0125
0126
0127
0128
0129
0130
0131
0132
0133
0134
0135
0136
0138
0145
0148
12
Mwe
560
570
Stop boration at 98 gallons
580
590
600
610
620
625
630
630
630
640
650
660
Spray demand at zero.
2PS3 spray 670
valve
11closed
11 light not lit.
Operator taps
11close
11 push button
and light illuminates.
650
Pressurizer pressure 2050 psig
(lowest) increasing. Heaters on.
Spray closed.
Request Chemistry sample.
Pressure 2140 psig increasing.
Tavg 558.
Safety still blowing
(audible).
Reactor Stm
Pzr
Power
Flow Pressure
Tavg
77
56
2240
588
77
56
2230
587
76
56
2220
586
75
56
2210
585
72
53
2205
584
71
50
2200
584
70
47
2190
583
69
44
2190
582
68
40
2180
580
67
40
2165
580
65
40
2150
578
64
40
2135
576
63
40
2120
574
60
40
2100
572
58
40
2090
570
56
40
2080
568
13
Time
0149
(appr) Pressure peaks at 2260 psig.
0150 Spray and heaters in auto.
Pressure controller in manual due
to saturation.
0210 Pressure stable
2230.
Level stable
25 %.
Tavg stable
550.
Power
46 %.
Turbine load 480 MWe.
Urgent failure alarm still up.
Safety blowing.
0225 Call to operations Manager and Asst. General Manager
0230 Cycle 23 MS 10 three times to seat 23 MS 15 ~ doesn
1t work
0300 Sample results I-131 1.4E-3Uci/ml
0330 Operations Manager on site
0521
23 MS 15 reseated by removing manual operating yoke pin
0730
Rod control restored
The inspector
1s review of this transient developed the following observa-
tions.
Technical Specification 3.2.5 establishes the following DNB related
Limiting Conditions for Operation in Mode 1; TavgS..582 degrees F,
Pressure 2!2220 psia. The accompanying ACTION Statement requires re-
storation of the parameter to within limits within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or a reduction
to less than 5 % of rated thennal power within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
The pressure
limit is not applicable during thermal power changes in excess of 5 %/
minute.
The control room chart indicates that Tavg exceeded 582 degrees
F for a period of approximately 11 minutes, peaking at 592 degrees F.
Pressure decreased below 2220 psia on two occasions. First, for
approximately 5 minutes, dropping to 2205 psia. The second, for
approximately 22 minutes, dropping to 2065 psia.
At no time during the event were reactor protection system or emergency
safeguards system setpoints exceeded.
No automatic trip was initiated.
Control room charts indicate no significant difference in steam flow
instruments for the four steam generators during the period that valve
23 MS 15 remained unseated.
Differential pressure alarms did not
annunciate.
14
With respect to procedures, the operators employed Emergency Instruc-
tion I-4.8, Rod Control System Malfunction, which does not require
manual reactor trip on a Rod Urgent Failure alann. The procedure calls
for stabilizing the plant and boration to restore Tavg.
No limits on
Tavg are specified in this procedure. Operator action on load reduc-
tion was consistent with Operating Instruction 'I-3.4, Power Operation.
Operating Instruction III-2.3.4, Steam Dump System - Normal Operation
states that the load rejection interlock is to be reset after equilibrium
conditions are reached.
The effect of this reset is to disann the dumps
and cause all the steam dump valves to shut. At the time this was
accomplished, indicated thermal power was 84 % and turbine load was 440
MWe (38 %), based on recorder chart data.
The licensee has no procedure for dealing with an unseated or stuck open
safety valve.
If sufficient steam flow is established to trip safeguards
system limits, the emergency instructions for steam break would apply.
The guidelines for actions to be taken on receipt of a low SGFP suction
alann were contained in a procedure which had not been subject to SORC
review, nor were they issued by the Manager.
The Steam Dump operating
instruction was issued by the Manager but not SORC reviewed.
Technical Specification 6.8.1 requires procedures for activities listed
in Regulatory Guide 1.33 Appendix A.
requires these procedures to be reviewed by SORC and issued by the
Manager.prior to implementation. Regulatory Guide 1.33 includes pro-
cedures for each safety related alarm annunciator and emergency procedures
for
110ther Expected Transients that may be Applicable.
11
Regulatory Guide
1.33 includes no requirement for steam dump operating procedures.
During this event, the saturation margin recorder was inoperable for
temperature.
The pressure margin channel was operable and displayed a
minimum margin of 375 psi during the transient.
Subsequent inspection of the safety valve found that the stem plate, on
which the manual opening yoke operates, had lost a retaining cotter pin
and had worked down the threaded stem approximately two turns. This
prevented complete seating of the valve due to interference from the
operating yoke.
All valves were subsequently inspected for clearances
and for integrity of the cotter pins.
Removal of the operating mechanism
was abandoned due to Code requirements.
Rod control was restored by replacement of a firing circuit in the control
system. Subsequent testing of the spray valve controller found no anomaly
in operation.
Review of control room charts indicates that, due to the
initial high pressure, the controller may have been in saturation and
taken some time to remove the output signal.
In addition, average temp-
erature was being reduced at a significant rate at 0135, which would
account for a pressure drop independent of spray valve operation. Based
on interviews with the operators, the valve was apparently shut at this
time but had not made up the
11close
11 limit switch. Tapping the
11close
11
push button accomplished this action.
15
10 CFR 50.72 requires that a prompt (one hour) notification be made to
NRC for any event that results in the plant not being in a controlled
or expected condition while operating or shut down.
Licensee supervisors
and management interviewed stated that they did not believe the above
situation fell in this category.
No prompt notification was made.
The licensee, based on his investigation of the transient, has provided
average temperature limits in the emergency instruction for rod control
system failure (541-581 degrees F), and has prepared instructions for
dealing with stuck open secondary safety valves.
Identified inconsis-
tencies between 10 CFR 50.72 reporting requirements and emergency plan
notification procedures are also being addressed.
A 30-day Licensee Event Report will be submitted detailing the licensee's
evaluation of the event.
Failure to prepare procedures for dealing with an open steam generator
safety valve and failure to properly issue the load reduction procedure
constitute noncompliance with Technical Specification 6.8.1 and 6.8.2
(311/82-01-01 and 311/82-01-02). Failure to report the unexpected plant*
condition to NRC constitutes noncompliance with 10 CFR 50.72 (311/82-
01-03}.
Due to the frequent protective system challenges caused by loss of feed-
water pump suction pressure over the past several months and this tran-
sient, caused by an attempt to avoid such challenge, the licensee has
initiated action to evaluate and correct the steam plant instability
which appears to be precipitating such pressure loss. These actions will
be monitored by the inspector.
The inspector had no further questions with respect to events reviewed
during this report period.
7. Maintenance Activities
The inspector observed maintenance activities on the following equipment:
a.
2C Vital Undervoltage Relay
b.
21 Overpower ~T Instrument Channel
C.
12 Component Cooling Heat Exchanger - replacement
16
These activities were observed to ascertain the following:
The work
was conducted in accordance with approved procedures, regulatory
guides, Technical Specifications, and industry codes or standards.
The following items were considered during this review; the limiting
conditions for operation were met while components or systems were
removed from service; approvals were obtained prior to initiating
the work; activities were accomplished using approved procedures and
were inspected as applicable; functional testing was performed prior
to declaring that particular component as operable; activites were
accomplished by qualified personnel; radiological controls were
implemented; and fire prevention controls were implemented.
No unacceptable conditions were identified.
8. Surveillances
The inspector observed the licensee's performance of the following
surveillance procedure:
1 PD 16.2.013 Functional Test
Intermediate Range Channel N 35, Revision 0, May 5, 1980
During the perfonnance of this test, the inspector confirmed the
following: Testing was performed in accordance with adequate procedures;
test instrumentation was calibrated; limiting conditions for operations
were met; removal and restoration of the affected components were pro-
perly accomplished; and, the test results confonned with Technical
Specification and procedural requirements and were reviewed by .personnel
other than the individual perfonning the test. Any deficiencies noted
were reviewed and resolved by the personnel of the responsible depart-
ment.
The personnel performing the surveillance activities were know-
ledgeable of the systems and the test procedures.
The inspector confirmed
that these personnel were qualified to perform the tests.
The inspector had no questions regarding the performance of surveillance
activities.
9.
Unresolved Items
10.
Areas for which more infonnation is required to determine acceptability
are considered unresolved. Unresolved items are contained in Paragraph
6.
.
Exit Interview
At periodic intervals during the course of this inspection, meetings
were held with senior facility management to discuss inspection scope
and findings.