ML18086B315
| ML18086B315 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 01/22/1982 |
| From: | Greenman E, Hill W, Norrholm L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18086B313 | List: |
| References | |
| 50-272-81-29, 50-311-81-29, NUDOCS 8202190327 | |
| Download: ML18086B315 (24) | |
See also: IR 05000272/1981029
Text
U. S. NUCLEAR REGULATORY COMMISSION
OFFICE OF INSPECTION AND ENFORCEMENT
(DCS Numbers - see
attached sheet)
Report Nos.
Docket Nos.
License Nos.
Licensee:
50-272/81-29
50-311/81-29
50-272
50-311
REGION I
Public Service Electric and Gas Company
80 Park Plaza
Newark, New Jersey
07101
Faci 1 i ty Name: _ _...;S;.;;;a..:..l e.:;.;.m~N~uc.::...l;.;:e;.:;a.:...r....;G:.:.;:e;.:.;n;.;;;;.er:.....;a:;.;t:...:i.;.:.ngil--,;;.S;...;:t;.;;;;.a..;;.t1.:...:* o;.:.;n:__-....:U:..:.n:.;.i~ts.::.......;:1:......::.a:...:.;nd;;;_..;;2:__
Inspection At: __
H_a_nc_o_c_k_s_B.....;.r.....;.i_dg.._e_.,:......;..;,Ne.;;..;w.;;.._;;,J~e""'"rs"-e""'y _________ _
1981
Inspectors:
W. ~-)li-1~, Jr., e~iden_t R~ac.tor Inspecto".'
Approved By: (Ji~
.
(\\.~E.G. Greenman, Chief, Reactor Projects Sectfon No.* 2A,
'i!S
Projects Branch No. 2, DRPI
Inspection Summary:
JAN 1 3 1982
- date
JAN 1 3 1982
date
J.O.N 2 2 1982
date
Inspections on November 24 - December 31, 1981 (Combined Report Numbers 50-272/81-29
and 50-311/81-29)
Unit 1 Areas Inspected: Routine inspections by the resident inspectors of plant
operations including tours of the facility; conformance with Technical Specifi-
cations and operating parameters; log and record reviews; IE Circular review;
reviews of licensee events; and followup on previous inspection items.
The
inspection involved 85 inspector hours by the resident NRC inspectors.
Results:
Two items of noncompliance were identified (Failure to establish, im-
plement, and maintain procedures~- paragraphs 2, 8, and 12; and, failure to perform
a safety evaluation - paragraph 7)~
Unit 2 Areas Insaected:
Routine inspections by the resident inspectors of plant
operations inclu ing tours of the facility; conformance with Technical Specifi-
cations and operating parameters; log and record reviews; IE Circular:" review;
review of licensee events; and followup on previous inspection items.
The
inspection involved 91 inspector hours by the resident NRC inspectors.
Results:
Two items of noncompliance were identified (Failure to establish, im-
plement, and maintain procedures - paragraph 12; and, failure to perform a safety
evaluation - * p*ara:grapfr. 17) *
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REPORT NOS. 50-272/81-29 and 50-311/81-29
DCS NUMBERS
050272-810831
050272-810928
050272-810902
050272-810909
050272-810908
050272-810918
050272-810918
050272-810922
050272-810929
050272-811020
050272-810930
050272-811028
050272-811008
050272-811107
050272-811106
050272-811017
050272-811022
050272-811019
050272-811021
050272-811021
050272-811025
050272-811026
050272-811117
050272-811029
050272-811029
050272-811125
050272-811129
050272-811106
050272-811106
050272-811106
050272:;811213
050311-810901
050311-810901
050311-810903
050311-810906
050311-810907
050311-810915
050311-810918
050311-811006
050311-810918
050311-810924
050311-811004
050311-811009
050311-8°11006
050311-811026
050311-811022
050311-811028
050311-811028
050311-811119
050311-811127
050311-811107
050311-811110
050311-811215
050311-811217
050311-811218
\\
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. 0
1Connor, 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,
perfonnance and quality assurance personnel.
2. Status of Previous Inspection Items
(Closed} Unresolved Item (311/81-13-04} Volume calculations for containment
sump level instruments.
The inspector reviewed a document entitled,
Design Calculation No. S-C-A900-MDC-006, Revision 1, Developmental
Chronology of Previous Containment Flooding Calculations, Units
1 and 2, dated October 8, 1981.
Included in this review were com-
putation sheets dating back to 1976.
The inspector confirmed that,
based on containment dimensions, and allowing for reactor, accumu-
lator, piping, structural steel, concrete, and PRT volumes, a
flood volume of 600,000 gallons will reach an elevation of 85
1-6"
or less. Therefore the installed level measuring capacity of 86
1
is adequate for the purpose.
The inspector had no further questions
on this item.
(Closed} Unresolved Item (311/81-11-03} Surveillance for battery powered
emergency lights. The inspector reviewed procedure M4B, Emergency
Lighting Equipment Test and Inspection - Battery Units, Revision
0, dated December 16, 1981.
The procedure is conducted annually
and scheduled by Inspection Order.
The inspector had no further
questions.
(Closed} Unresolved Item (311/80'-16-03} Operator walkthrough of core thenno-
couple readout when over range. Since identification of this
issue, the licensee has stationed instrument and control techni-
cians on operating shifts and has prepared procedure PD-14.3.010,
Extended Range Reading of Incore Thennocouples.
The inspector
reviewed the procedure, which has been field-tested, and confirmed
that the actions necessary to detennine core thermocouple tempera-
tures in the event of computer failure are within the capability
of shift personnel. The inspector had no further questions on
this item.
3
(Closed) Unresolved Item (272/81-05-02) Definition of pressurizer operability
when heater groups become inoperable.
Amendment 39 to Facility
Operating License DPR-70 established two 150 KW groups of heaters-
as the minimum required in Modes 1, 2, and 3. The basis for this
minimum is the requirement to sustain natural circulation. Oper-
ational experience indicates that this heater capacity may be
insufficient to maintain pressure control during power operation.
Further review by the inspector identified no operating or emergency
procedure which addresses loss of heater capacity. Technical
Specification 6.8.1, which includes Regulatory Guide 1.33 Appendix
A by reference, requires a procedure for malfunctions of the
pressure control system. This item is resolved as noncompliance
with Technical Specification 6.8.1 (272/81-29-01).
(Closed) Noncompliance (272/80-10-02) Failure to meet the reporting require-
ments of 10 CFR 50 Appendix J.
By letter dated July 8, 1980, the
licensee provided an addendum to the CILRT report which includes
the Type C testing performed.
In addition, the licensee has con-
solidated responsibilities for leak rate testing to preclude recur-
rence of this item.
The inspector had no further questions.
lClosed) Unresolved Item (272/80-10-03) Acceptance of 1979 CILRT results.
In the July 8, 1980 addendum to the CILRT report, the licensee
revised the analysis to account for water inventory changes.
The
inspector concluded that the evaluation was adequate and the re-
vised analysis of test results met applicable acceptance criteria.
This item is resolved as acceptable.
(Closed) Unresolved Item (272/81-01-04) Identification of erroneous control
room instrumentation. The inspector reviewed the implementation
of an Operations Directives Manual procedure whereby instrumentation
which has failed or does not correspond in a channel check is de-
clared inoperable, entered in Log 13, and is identified with a
strip of translucent red tape. The system is effective in identi-
fying those instruments which would provide incorrect information
to the operator.
Based on continuing observation, the inspector
also confirmed that, in the case of reactor trip or ESF instrumen-
tation, the appropriate Technical Specification Action Statement
is also invoked.
The inspector had no further questions on this
item.
(Closed)
Open Item (311/79-30-01) Confirmation that alarm setpoints are
conservative with respect to Technical Specifications. The licensee
has concluded a review which verified that existing alarm setpoints
are consistent with Technical Specification limits.
Some minor
procedure changes resulted from this review.
The inspector had no
questions on this item.
(Closed)
(Closed)
4
Unresolved Item (272/80-31-02) Alarm setpoint for C02 system low
pressure. The Technical Specification minimum for the C02 system
is 285 psig. The alarm had been set at 275 psig and the procedures
were consistent with the as-built configuration. The licensee
has completed a design change to modify the setpoint to 290 and
the procedures have been changed accordingly. The inspector had
no further questions.
Unresolved Item (272/80-31-03) Console Alarm procedures for water
treatment system.
The alarm procedures in both units have been
changed to refer to other station procedures rather than Technical
Specification 3.7.1.7, which has been deleted.
The inspector had
no further questions on this item.
(Closed) Unresolved Item (272/80-20-02) Weight testing of miscellaneous
fuel handling (rigging) equipment. Maintenance Procedure M2Q,
Revision 0, dated August 28, 1981, provides requirements for con-
trol, inspection, testing, and maintenance of general rigging
equipment (cables, slings, shackles, etc.). This procedure provides
acceptable guidance for maintenance of general rigging equipment.
The inspector confirmed adherence to this procedure during receipt
and storage of new fuel .
(Closed} Unresolved Item (272/80-23-03) Field change to Spent Fuel Handling
Tool.
Design Changes lEC 1286 and 2EC 1299 were issued to describe
the modifications to the Spent Fuel Handling Tool.
The design
change packages were acceptable and satisfied the licensee's require-
ment for implementing engineering changes.
- , ;i.
(Closed) Unresolved Item {272/81-01-05) Air flow check/calibration of the
AMS-2 Airborne radiation monitor. Procedure RP 9.021 Calibration
of AMS-2 (Revision 1, dated April 8, 1981) has been revised to
include a check of the air flow through the AMS-2 radiation monitor.
(Closed} Unresolved Item (272/81-14-03) Fire Protection Dampers.
The licensee
provided the test{~ results of the remaining 13 dampers. All of the
dampers were tested satisfactorily. The inspector had no further
questions.
{Closed) Unresolved Item {311/81-10-02) Supervisor ... f:feview of ,~s*urveillances.
Following the observation of periodic surveillances over the past
several months, the inspector concluded that the licensee's super-
visors provide an adequate independent review of the completed
surveillance procedures.
(Closed) Unresolved Item (311/81-10-03) Annunciator Alarm.* The hinged
covers above the test switches in equipment racks 11 and 31 were
replaced. These covers were necessary to contact a microswitch to
clear annunciator alarms B-18 and B-26.
The alarms are working
properly now.
i
' I
'
I
I
I
I
(Closed)
SITE
5
Unresolved Item (311/81-19-02) Identify units of measure for control
room radiation monitors.
The radiation monitors indicated in the
control room have labels attached below the meter face.
These
labels indicate the radiation units for each meter.
3. Shift Logs and Operating Records
a. The inspector reviewed the following plant procedures to determine 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 cond1tions provide sufficient detail
to communicate equipment status, lockout status, correction 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.
6
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, November 24 - December 31, 1981
Log No. 6 - Primary Plant Log, November 24 - December 31, 1981
Log No. 7 - Secondary Plant Log, November 24 - December 31, 1981
Log No. 8 - Unavailable Equipment Status Log, November 24.-
December 31, 1981
Night Orders, November 24 - December 22, 1981
Lifted Lead and Jumper Log - All active
Tagging Requests - All active
Nonconfonnance Reports for November 1981
The inspector had no questions relative to logs reviewed during this
inspection period.
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
(_4)
Vital Switchgear Rooms
(5)
Turbine Building
(6)
Yard Areas
(7)
Radwaste Building
(_8)
Penetration Areas
(9)
Control Point
(10) Site Perimeter
(_11) Fuel Handling Building
(12) Guard House
7
b.
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.
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 vibtation.
No excessive piping vibrations were observed and
no adverse conditions were noted.
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 specified.
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 t.hat appro-
priate documentation, sampling, authorization, and monitoring
instrumentation were provided for effluent releases.
8
Fire protection. The inspector verified that selected fire ex-
tinguishers were accessible and inspected on schedule, that fire
alarm stations were inspected on schedule, that fire alarm stations
were unobstructed and t.hat 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 frequently:
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 instrumen-
tation and inspection of electrical switchboards to confirm avail-.
ability of safeguards 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
d.
During control room reviews, the inspector noted that the Unit 2 Refueling
Water Storage Tank (RWST) temperature was 55-60°F while the Unit 1 RWST
was maintained at 80-850F.
The recirculating pump to the heating water
heat exchanger was in service but the depressed temperature was of con-
cern due to expected cold weather. Technical Specification 3.1.2.6 sets
a minimum temperature of 350F.
Examination of the heat exchanger revealed
that recirculation (RWST) temperatures were identical into and out of the
heat exchanger at approximately 550F.
Heating water exceded 2000F and
the return was at ambient, approximately 700F.
Following the inspector's
expression of concern that the heat exchanger was not functioning, the
licensee determined that the heating water side was fouled with debris.
The heat *exchanger was-cleaned and an RWST temperature of 900F.,established
prior to conclusion of the inspection.
e. The inspector had no further questions relative to tours made during this
inspection.
9
5.
Review of Periodic and Special Reports
Upon receipt, periodic and special reports submitted by the licensee
pursuant to Technical Specifications 6.9.1 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 identified
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 reviewed
by the inspector:
Unit 1 Monthly Operating Report - Octobe*r and November 1981
Unit 2 Monthly Operating Report - October and November 1981
No unacceptable conditions were identified.
6. .IE Circular Followup
a.
For the IE Circulars listed below, the inspector verified that the
Circular was received by the licensee management, that a review for
applicability was performed, and that if the circulars were applicable
to the facility, appropriate corrective actions were taken or were
scheduled to be taken.
81-02, Performance of NRG-Licensed Individuals While on Duty.
The licensee's review of this Circular concludes that all
appl i cable information is included in statti1ennAdmi ni strative
Procedure AP-5, Operating Practices Program, Revision 11,
dated August 13, 1981.
81-04, The Role of Shift Technical Advisors and Importance of
Reporting Operational Events.
In a memorandum dated July 30,
1981, the licensee concludes that the concerns identified in
this Circular are also covered by AP-5.
In addition, the
inspector noted that AP-6, Incident Report and Reportable
Occurrence Program, Revision 7, dated October 8, 1981, also
covers the subject in detail.
10
81-05, Self-Aligning Rod End Bushings for Pipe Supports. The
inspector reviewed Safety Evaluation S-C-R600-MSE-112,
Revision 0, dated November 4, 1981, entitled, Spherical
Bearing Disengagement Review for Safety Related Snubbers
Salem Nuclear Generating Station No. 1 and 2 Units.
The
evaluation documents the inspection of all supports subject
to the problem.
With the exception of two, potential for
bushing disengagement was absent.
The two remaining supports
are included in the in-service inspection program.
81-08, Foundation Materials. The licensee reviewed the Circular
for applicability to Salem and$in a memorandum dated July
29, 1981, documented the following information. All seismic
Category 1 structures at Salem are on lean concrete fill
not on compacted soil. Other buildings are on steel piers.
81-12, Inadequate Periodic Test Procedure of PWR Protection System.
The licensee's review of this Circular is documented in a
memorandum dated September 24, 1981. Station surveillance
procedures test b.oth the shunt trip coil and the undervoltage
coil for the reactor trip breakers and post-trip position is
verified at the control console.
The inspector had no questions relative to Circulars reviewed.
7.
Licensee Events
a.
In Office Review of Licensee Event Reports
The inspector reviewed LERs submitted to the NRC:RI office to verify
that details of the event were clearly reported, including the accuracy
of the description of cause and adequacy of corrective action. The
inspector determined whether further information was required from the
licensee, whether generic implicatfons were involved, and whether the
event warranted onsite followup.
The following LERs were reviewed:
UNIT 1
81-83/03L
-
No. 12 Charging Pump Inoperable Due to Oil Cooler
Service Water Leak
81-84/0lT
-
Service Water Leak in Containment - No. 11 Containment
Fan Coil Unit Bottom Primary Coil
81-85/03L
-
No. 12 Charging Pump Inoperable Due to Oil Cooler
Service Water Leak
81-86/03L
-
No. 11 Containment Fan Coil Unit Inoperaole on Two
Occasions Due to Loss of Service Water Flow Indication
11
81-87/04L
-
Impingement of Three Sea Turtles on Circulating Water
Intake Trash Bars
81-88/03L
No. 2 Fire Pump Inoperable Due to Cracked Battery Cable
Clamp
81-89/03L
-
Containment Air Lock Inoperable Due to Damaged Seals -
100
1 Elevation
81-90/03L
-
No. 12 Component Cooling Water Heat Exchanger Inoperable
Due to Failed Dissimilar Metal Drain Line Weld
81-91/03L
-
Pressurizer Level Channel 3 Inoperable - Instrument
Drift
81-92/0lT
-
Service Water Leak in Containment - No. 15 Containment
Fan Coil Unit Secondary Coil
81-93/03L
-
No. 1 Fire Pump Inoperable Due to Broken Fuel Pump
Shaft
81-94/0lT
-
Service Water Leak in Containment - No. 14 Containment
Fan Coil Unit Primary Coils (2)
8l-95/03L
-
Containment Sump Level Monitoring System Inoperable Due
to Auxiliary Alarm Annunciator Failure
81-96/0lT
-
Service Water Leak in Containment - No. 11 and No. 15
Containment Fan Coil Units Primary and Secondary Coils
81-97/0lT
-
Boron Injection Tank Inlet Valves Failed to Fully Open
During Inadvertent Safety Injection
81-98/03L
-
Auxiliary Feedwater Storage Tank Below Minimum Volume
Following Reactor Trip
81-99/03L
-
No. 12 Containment Fan Coil Unit Inoperable Due to Loss
of Service Water Flow Indication
81-100/03L -
Intennediate Range Nuclear Instrumentation Channel 1
Inoperable Due to Failed High Voltage Power Supply
81-101/03L -
Pressure Decrease Below DNB Limit For Five Minutes Due
to Operation of Auxiliary Spray Valve
12
81-102/03L -
Failure to Isolate Inoperable PORV In Accordance With
License Amendment 39
81-103/03L -
Intermediate Range Detector N-36 Inoperable Due to
Failed High Voltage Power Supply
81-104/03L -
No. 13 Steam Generator Steam Flow Channel 1 Inoperable -
Instrument Drift
81-105/0lT -
Service Water Leak in Containment - No. 12 Containment
Fan Coil Unit Primary Coil
8l-106/03L -
Penetration Fire Barriers Inoperable - Fire Doors
81-107/03L -
Inadvertent Safety Injection Due to Loss of lA Vital
Instrument Inverter
'
81-108/0lT -
Service Water Leak in Containment - No. 14 Containment
Fan Coil Unit Primary Coil
81-109/0lT -
Service Water Leak in Containment - No. 12 Containment
Fan Coil Unit Primary Coil
81-110/03L -
Inadvertent Safety Injection Due to Loss of lA Vital-
Instrument Inverter
81-111/03L -
No. 11 Containment Fan Coil Unit Inoperable Due to
~
'*
--
81-112/03L
Open Breaker Trip Shutter
-
Auxiliary Feedwater Storage Tank Low Level Following
UNIT 2
81-97/03L
81-98/03L
81-99/03L
-
Individual Rod Position - 2D2 - Inoperable
Individual Rod Position Indication - 1D4, 1D3, 2D2,
and 2D3 - Inoperable
-
No. 23 Containment Fan Coil Unit Inoperable Due to
Loss of Service Water Flow Indication
81-100/03L -
No. 22 Reactor Coolant Loop Flow Channel 2 Inoperable
Due to Transmitter Failure
81-101/03L -
Radiation Monitor 2R12A Inoperable Due to Failure of
Battery Pack
13
81-102/0JL -
No. 22 Reactor Coolant Loop Flow Channel 2 Inoperable
Due to Transmitter and Equalizing Valve Assembly
Failure
81-103/0JL -
No. 24 Containment Fan Coil Unit Inoperable Due to
Loss of Service Water Flow Indication
81-104/0lT -
Failure.to Comply With Operating License Condition
Relating to Cable Fire Wrapping
81~105/03L -
No. 21 Steam Generator Level Channel 2 Inoperable Due
to Loss of Calibration
81-106/03L
Isolation Damper 2CAA4 Inoperable Due to Lack of
Lubrication
81-107/03L -
Trip of 2B Diesel Generator Due to High Jacket Water
Temperature
81-108/03L -
Individual Rod Position Indication - 2Cl and 2D2 -
81-109/03L -
2A Safeguards Equipment Control Inoperable
- *
81-110/03L -
No. 21 and 23 Containment Fan Coil Units Inoperable
Due to Loss of Service Water Flow Indication
81-lll/03L -
Reactor Coolant System Pressure and Tavg Below DNB
Limits For Five Minutes Due to Over-Boration
81-112/03L -
Containment Air Lock Inoperable - 100' Elevation
81-ll3/03L -
Containment Spray Additive Tank High Level
81-114/0lT -
Service Water Leak in Containment - No. 22 Containment
Fan Coil Unit Motor Cooler
81-115/0lT -
Service Water Leak in Containment -*No. 24 Containment
Fan Coil Unit
- .--
81-ll6/03L -
No. 22 Charging Pump Inoperable Due to Broken Impeller
Shaft
81-117/03L -
No. 21 and 22 Containment Fan Coil Units Inoperable
Due to Failed Limit Switch and Loss of Service Water
Flow Indication
_,
14
b.
Onsite Licensee Event Followup _
(1)
For those LERs selected for onsite followup (denoted by asterisks
in detail paragraph 7), the inspector verified the reporting require-
ments of Technical Specifications and Regulatory Guide 1.16 had been
met, that appropriate corrective action had been taken, that the event
was reviewed by the licensee as required by AP-4 and 6, and that con-
tinued operation b,f the facility was conducted in accordance with
Technical Specification limits. The following findings relate to the
LERs reviewed on site:
UNIT 1
81-84/0lT
81-92/0lT
81-94/0lT
81-96/0lT
81-105/0lT
81-108/0lT
81-109/0lT
Each of these events details a service water leak in
containment due to a Containment Fan Coil Unit (CFCU)
tube pinhole leak, typically 0.5 to 1.0 gpm.
In each
case, the cooler service water side is isolated to stop
the leak and one of several repair options pursued.
In
some cases, a cooler bundle is isolated by blank flanges.
As discussed in NRC Inspection Report 50-272/81-25, this
procedure_ is acceptable as long as the remaining heat
removal capacity of the unit is within design limits.
Repairs to leaking tubes using brazing techniques have
been successful but only in cases that are accessible
for the process. The majority of the leaks identified
in these LER's were repaired by applying Belzona metal
filler to the outside of the tube at the leak location.
No subsequent failure of a repair made with this metal-
epoxy filler has occurred. All CFCU coils are scheduled
to be replaced with new material at the next outage.
In
attempting to determine the acceptability of the metal
filler repair in this application, the inspector found
no documentation of any evaluation done by the licensee.
Engineering Department concurrence is implied by disposi-
tion of Deficiency Reports which state that the material
is to be employed.
However, no basis for this determina-
tion is provided. Failure to provide written documentation
to justify a maintenance action which constitutes a change
in the facility contributes to noncompliance with 10 CFR
50.59 (272/81-29-04 ' 311/81-29-03}~
81-86/03L
Loss of service water flow indication to Containment Fan
81-99/03L
Coil Units has been a recurring problem.
The licensee
is currently blowing down transmitters weekly to reduce
the adverse effects of silting. Evaluation of alternate
sensing line configurations is underway.
The inspector
had no further questions at this time. These events do
not impede actual availability of service water to cool
the CFCU's.
15
--
81-87/04L
This event report details three occasions on which
endangered or threatened species of sea turtles were
recovered from the plant circulating water system.
By corre~pondence dated December 10, 1981, the licensee
responded to an Office of Nuclear Reactor Regulation
request, dated November 17, 1981, for additional in-
formation on the subject.
The inspector had no further
questions.
--
81-90/03L
This report detailed a service water leak from a Com-
ponent Cooling Heat Exchanger drain line dissimilar
weld.
Temporary repairs were effected by cutting the
pipe, capping and welding.
The inspector confirmed that
this repair was properly dispositioned in Deficiency
Report No. MD 1034 and that a Work Order has been written
to accomplish a permanent repair at the next outage.
The
inspector had no further questions.
--
81-97/0lT
Durn.ng an inadvertent safety injection on November 6, 1981,
Boron Injection Tank inlet valves 1SJ4 and 1SJ5 failed to
open fully. The valves were subsequently opened by remote
operation from the control room.
The initial cause was
attributed to boron precipitate on the valve stems. It
was also determined that the valve operator torque settings
were set at a value of 2 in a recommended range of 2 to
3.5. Corrective action included increasing the torque
setting to 3.
The licensee's evaluation of'this event and
the torque settings on the operators is continuing and will
be included in a supplemental report. It was noted that
the valves functioned normally on an inadvertent safety
injection one week prior to this event. Further investi-
gation showed that the valves had been cycled and met
acceptable stroke times within 30 days of this event. This
item remains unresolved pending completion of the licensee's
evaluation and submission of a supplemental report (272/81-
29-02).
81-101/03L While troubleshooting pressurizer auxiliary spray valve
1CV75, pressurizer pressure decreased below the Technical
Specification DNB limit for a period of less than five
minutes.
The cause was slow operation of the valve due
to an incorrect air operator liftoff pressure in this
application of the valve.
The liftoff pressure was in-
creased and satisfactory operation achieved. The lowest
primary system pressure reached was 2175 psig based on the
inspector's review of plant records.
No other air operated
valves were identified which would be subject to a similar
problem.
The inspector had no further questions on this
event.
--
81-102/03L
--
81-106/03L
--
81-110/03L
--
81-111/03L
16
Amendment 39 to Unit 1 Facility Operating License DPR-70
provided new Technical Specifications for Power Operated
Relief Valves (PORV} and requires that, with one or more
PORV inoperable, all associated block valves be closed
and power removed from the valves. The amendment was
issued on October 8, 1981 and, at that time, the PORV
had been declared inoperable due to leakage and the block
valves closed from the control console.
By October 21,
1981, the license amendment had not been received by
operating personnel and, therefore, the additional require-
ment of removing motive power had not been accomplished.
When the licensee was informed of the new requirement by
the inspector, the power was removed.
After discussions
with station and corporate management, the inspector de-
termined that new procedure*s' will be employed to ensure
timely dissemination of new requirements to operating
personnel. *The inspector had no further questions.
Following surveillance of fire doors, the licensee deter-
mined that several did not meet acceptance criteria. In
accordance with Technical Specifications, fire detectors
were confirmed operable and a fire patrol established.
Due to continuing problems with doors, the patrol is still
in effect at the conclusion of the inspection period.
The
licensee has initiated design change 1 EC-1333 to improve
the serviceability of fire doors and will submit a supple-
mental report. This item is unresolved pending insp~ctor
review of permanent corrective action (272/81-29-05)_.
This inadvertent safety injection is detailed in NRC In-
spection Report 50-272/81-27.
The interaction between
inverter control cabling and cooling fan power leads has
been reduced by rerouting of the cables.
In addition,
administrative controls have been applied to ensure that
no work in the inverters is attempted while the plant is
in a condition susceptible to inadvertent safety system
actuation om loss of an inverter. The inspector had no
further questions.
During the above safety injection, CFCU 11 failed to start
automatically in slow speed.
The cause was determined as
failure of the breaker shutter to close when the breaker
had last been rack,ed in, resulting in automatic trip on
closure. Previous observed practice had included testing
and surveillance following equipment maintenance which
should have detected this condition.
In this particular
case, the unit had been isolated and tagged for elective
maintenance and, before any work started, had been cleared
and declared operable. Since no work had been done, no
operational test was conducted.
17
81-111/03L The licensee, in Operating Memorandum 15, requires an
(Continued} operational test of all safety related pumps following
the removal of tags, whether or not work has been
accomplished on the equipment. This requirement had
not been applied to CFCU's.
Recognizing the potential
of inoperability due to improper rack-in of breakers,
the licensee will include CFCU's in the OM-15 guidance.
This will be confirmed by the inspector(272/81-29-03).
--
81-112/03L Technical Specifications require that Auxiliary Feed-
water Storage Tank level be maintained above 94 percent
UNIT 2
81-98/03L
81-103/03L
81-110/03L 81-117 /03L
81-101/03L
--
81-104/0lT
in Modes 1, 2, and 3. This event is typical of several
in which, following a reactor trip, automatic initiation
of auxiliary feedwater results in decreased tank levels
before manual makeup valves can be opened to supply
demineralized water to the tank.
To alleviate this pro-
blem, the licensee has initiated design changes to provide
a tank leV-~l alarm before the Technical Specification
limit is reached and also to provide remote operation of
the makeup valve from the console. These modifications
will be accomplished during the January outage on Unit 1
and during the next refueling outage on Unit 2. These
actions will be confirmed during followup on a previous
item of noncompliance related to this issue.
These events detail losses of service water flow indi-
cation to Containment Fan Coil Units.
Comments under
Unit 1 LER 81-86 above apply to these events.
On October 28, 1981, the licensee supplemented this LER
to provide additional information. Failure of the radiation
monitor battery pack on loss of power was attributed to a
design error in that too many batteries were installed,
leading to overcharging and internal shorts. The design
modification to reduce the number of batteries has been
accomplished.
Periodic surveillance of the battery power
supply is accomplished during preventive maintenance of
the system by procedure. This problem is not applicable
to Unit 1 which has a different radiation monitoring system.
The inspector had no further questions.
On October 9 and November 18, 1981, the licensee supple-
mented this LER to list all additional areas in which fire
protection cable wrap had not been properly applied. Based
on complete verification by engineers in the field, the
licensee states that all required wrapping to support
alternate shutdown has been completed.
Further details of
this event are provided in NRC Inspection Report~ 50-311/
81-21.
The inspector had no further questions.
18
--
81-106/03L When reviewing this event, the inspector determined that
no periodic lubrication of damper operating gear is per-
fonned because the device is not required to be lubricated
by design.
The licensee is evaluating design modifications
to improve damper operability. Periodic testing provides
necessary assurance of availability of the dampers.
The
LER will be supplemented to provide a more complete dis-
cussion of corrective measures. This item remains unre-
solved (311/81-29-0lf.
--
81-107/03L 28 Diesel Generator tripped on surveillance testing due to
loss of service water to the jacket water cooling system.
The inspector noted that on safeguards start of the diesel
generator, this trip is bypassed and that sufficient time
would be available to restore cooling if the diesel were
required for safeguards loads. The inspector had no
further questions.
--
81-lll/03L During boration of the primary system, an operator permitted
boric acid injection for an extended period such that pres-
sure and temperature went below the Technical Specification
DNB limit for approximately five minutes.
The LER states
that the operator failed to adhere to standard procedure
while, in fact, he failed to follow standard practice.
The procedure calls for close monitoring of rod position
and plant parameters during boration.
Due to the outmotion
rod stop, plant temperature and pressure decreased before
corrective action to secure boron addition could be accomp-
lished. The inspector had no further questions on this
item.
81-114/0lT These events detail service water leaks in containment due
81-115/0lT to leaking Containment Fan Coil Units.
Comments above with
respect to Unit 1 LER 81-84/0lT apply to these events as
well. With regard to LER 81-114/0lT, the inspector noted
that once the leak was isolated, the plant tripped.
In
order to return the plant to Mode 1 operation consistent
with Technical Specification 3.0.4, the Containment Fan
Coil Unit was declared operable with a known 0.5 gpm
service water leak.
No safety evaluation was documented
to validate safety analysis assumptions with regard to
containment integrity and containment water volume.
Since
the service water system operates well in excess of con-
tainment design pressure and since 10 gpm of identified
leakage to containment is pennitted,.a valid safety concern
appears to be absent. However, failure to document this
conclusion and its basi,s- contributes to noncompliance with
10 CFR 50.59 (311/81-29-03}.
19
--
81-116/03L The charging pump impeller shaft sheared in service and
complete replacement was accomplished. Susceptibility
of this series of shafts to failure has been identified
by Westinghouse in a Part 21 report dated August 15,
1977.
In addition, a service bulletin to owners of
susceptible shafts was issued in July 1977. During the
January 1982 outage, both Salem 1 charging pumps will be
fitted with new shafts which have been modified to pre-
vent this type of failure. Both pumps on Unit 2 now
have modified shafts. The inspector had no further
questions on this item.
c. The inspector had no further questions relative to LER
1s reviewed.
8. Operating Events
UNIT 1
At 10:27 p.m. on December 13, after placing Deborating Demineralizer 11 in
service, airborne activity in the Auxiliary Building increased. The maximum
activity measured was 3.5 E-7 uCi/cc (short lived). Investigation determined
that the resin fill valve for the demineralizer had been left open following
resin replacement earlier in the day.
An area approximately 30 feet on a
side was wetted by the resulting spill. The Demineralizer was taken out of
service and isolated within 10 minutes. Plant vent monitor 1Rl6 increased to
approximately 200,000 cpm but did not reach the alarm point which is established
to alarm prior to exceeding the instantaneous release limit. Six individuals
were found to have short lived (Rb88) contamination of their clothing, which
was allowed to decay.
The initial estimate of the release was 2 Ci of noble
gas, which is below the reporting limit of the Environmental Technical Speci-
fications.
Review of the procedure, PD-3.6.014, Ion Exchanger Resin Refilling, Revision
0, indicated that the valve was to be closed following the filling operation.
This failure to follow a procedure contributes to an item of noncompliance
with Technical Specification 6.8.1 (272/81-29-01).
UNIT 2
At~2:32 a.m. on December 15, the reactor tripped from 95 percent power due to
a low level in Steam Generator 24 after a feedwater pump trip. The cause was
not identified. Because of similar trips, the licensee instrumented 51 secon-
dary process parameters.
None of these indicated the problem.
At 8:56 a.m.,
the reactor tripped at 15 percent power due to low water level in 22 Steam
Generator. The low level was caused by personnel error while shifting from
manual to automatic level control during the startup. The unit was returned
to service at 12:25 p.m.
20
Approximately 8:00 p.m. on December 17, the plant tripped from 95 percent
power due to low steam generator level caused by loss of both feed pumps.
The pumps tripped on a valid low suction pressure condition which was
apparently caused by a large reduction in heater drain pump flow.
Operation
resumed at 6:28 a.m. on December 18.
At 7:15 a.m., operator error during
the shift of power supply to the 4KV
11G
11 non-vital electrical bus caused
the loss of 24 Reactor Coolant Pump.* Loss of the RCP caused a reactor trip
from 32 percent power.
The unit was returned to service later that day.
The licensee remained below 75 percent power until the recorded data was
reviewed and heater drain pump control was verified. Several load rejection
tests were subsequently performed but did not cause or reveal the reason
for the recurrent feed pump trips. During these tests the lowest feed
suction pressure reached was 255 psi. The trip set point is 215 psi.
The recurring series of plant trips due to loss of steam generator feed-
water pumps prompted an investigation of secondary system performance
characteristics by the licensee. This investigation included the recording
instrumentation on 51 secondary parameters and on operational relays in
the pump control circuitry. Based on observations during trips and the
series of load rejection tests conducted during the period December 18-24,
the licensee concluded that loss of feedwater suction pressure on load re-
ductions is attributable to instability in heater drain pump flow and an
apparent inability of the condensate system to compensate for the flow
changes.
Corrective measures initiated by the licensee include operation
witb a heater string bypass valve open to provide an additional condensate
flow path to the feedwater pumps.
The result has been more stable response
from the heater drain pumps and an increase in steady state feedwater suction
pressure, placing the operating pressure further from the trip point. During
full power operation at the end of the inspection period, suction pressure
was between 350-360 psig. These operational modifications appear to provide
an acceptable interim solution. Permanent design solutions are being evaluated.
9.
Nuclear Review Board
The 'inspector reviewed the minutes of Nuclear Review Board (NRB) meetings
81-01 through 81-17, conducted during the period January 25 - November 19,
1981.
The inspector had no questions with respect to the following aspects
re.viewed: meeting frequency, quorum requirements, review material, conclu-
sions reached, designation and qualifications of members, and timeliness of
minutes.
The inspector selected three license change requests submitted during the
interval (LCR
1s 81-01, 81-14, and 81-18) and confirmed that they had received
prior NRB review.
No unacceptable conditions were identified.
10.
21
Fire Protection
Supplement 4 to the Salem Nuclear Generating Station Safety Evaluation Report
(SER), dated April 1980, includes the Fire Protection SER and a listing of
nine modifications yet to be performed.
The licensee stated that all listed
modifications have been completed, except as discussed below.
The inspector
conducted a sampling review of items 27, 29, 32, 33, and 36, and confirmed
that they had been accomplished.
Item 37, dealing with alternative shutdown capability, was reviewed by the
staff in detail in May 1981, and findings from that review were documented
in Supplement 6 to the Safety Evaluation Report, dated May 1981.
Open items
were included in the Salem Unit 2 Full Power Operating license and completion
of these items is discussed in NRC Inspection Reports 50-311/81-11 and 81-13,
and 81-26.
The scope of item 37 has changed since issuance of Appendix R
and as a result of the on site review in May 1981.
The licensee has committed to completion of Appendix R backfit items for
both units, with the exception of certain aspects of III.G,(Safe Shutdown
Capability) for which exemption requests are under review by the staff.
The inspector had no further questions with respect to fire protection modi-
fications at this time.
11.
Maintenance Activities
The inspector observed maintenance activities on the following equipment:
a. 1 Spent Fuel Pool Heat Exchanger - tube leak
b.
21 Main Feed Pump - weld crack in casting plug
c. 11 Component Cooling Heat Exchanger - tube cleaning and inspection
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; activities were
accomplished by qualified personnel; radiological controls were implemented;
and fire prevention controls were implemented.
No unacceptable conditions were identified *
-
~
22
12. Surveillances
The inspector observed the licensee
1s performance of the following surveillance
procedures:
a. 2 PO 2.6.045 Channel Functional Test
2 LT 529 #22 Steam Generator Level Protection Channel I, Revision
1, December 23, 1981
b.
2 PO 2.6.055 Channel Functional Test
2 LT 539 #23 Steam Generator Level Protection Channel I, Revision
1, November 23, 1981
c. 2 PO 2.6.020 Channel Functional Test
2 LT 459 Pressurizer Level Protection Channel I, Revision 2,
October 5, 1981
During the performance of these tests, the inspector confirmed the following:
Testing was performed in accordance with adequate procedures; test instrumen-
tation was calibrated; limiting conditions for operations were met; removal
and restoration of the affected components were properly accomplished; and,
the test results conformed with Technical Specification and procedural re-
quirements and were reviewed by personnel other than the individual performing
the test. Any deficiencies noted were reviewed and resolved by the personnel
of the responsible department.
The personnel performing the surveillance
activities were knowledgeable of the systems and the test procedures. The
inspector confirmed that these personnel were qualified to perform the tests.
The inspector reviewed surveillance procedure SP(O) 4.6.2.2(b) Containment
Systems - Spray Additive Unit 2, Revision 0, dated April 26, 1979.
The pro-
cedure documents the semiannual determination of spray additive tank level
and NaOH concentration. Acceptance criteria established reflected only the
lower limit of each parameter.
The upper limits which are established by
Technical Specification 3.6.2.2 were not called out in the procedure. The
"as found" values were, in fact, consistent with Technical Specifications.
Failure to establish an adequate surveillance procedure contributes to an
apparent item of noncompliance with Technical Specification 6.8.1.
(272/81-29-01, 311/81-29-02).
The inspector had no further questions regarding the performance of surveillance
activities.
23
13. System Operation and Review
The inspector conducted a walk down of selected portions of plant systems.
The following drawings were used to conduct this review:
a.
Main Steam System (Unit 2) - 205303, Revision 10, dated May
1, 1980
b.
Main Feed System (Unit 2) - 205302, Revision 10, dated May
2, 1980
c. Auxiliary Feed System (Unit 2) - 205336, Revision 6, dated
April 11, 1980
d.
Auxiliary Feed System (Unit 1) - 205236, Revision 1, dated
January 12, 1981
The walk down was conducted to confirm system operability. Included in
this review was an examination of valve positions, seismic restraints and
supports, leaks, local indicators and instrumentation, unusual noise or
vibrations, overheated equipment, and system conformance with "as built"
drawings.
No unacceptable conditions were identified.
14. Unresolved Items
Areas for which more information is required to determine acceptability are
considered unresolved. Unresolved items are contained in Paragraph 7.
15. Exit Interview
At periodic intervals during the course of this inspection, meetings were
held with senior facility management to discuss inspection scope and findings.