ML18086B156
| ML18086B156 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 12/08/1981 |
| From: | Greenman E, Hill W, Norrholm L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18086B153 | List: |
| References | |
| 50-272-81-27, 50-311-81-217, 50-311-81-27, NUDOCS 8112290363 | |
| Download: ML18086B156 (17) | |
See also: IR 05000272/1981027
Text
Report Nos.
Docket Nos.
License Nos.
Licensee:
~
050272-811029
050272-811105
050272-811106
U. S. NUCLEAR REGULATORY COMMISSION
OFFICE OF INSPECTION AND ENFORCEMENT
050311-811022
050311-811116
050311-811119
050311-811124
050311-811107
50-272/81-27
50-311/81-27
50-272
50-311
REGION I
Public Service Electric and Gas Company
80 Park Plaza
Newark, New Jersey
07101
Facility Name:
Salem Nuclear Generating Station - Units 1 and 2
Inspect ion At: " __ H_a_n_co_c_k_s_B_r_i_d..._ge-',,__N_ew_J_e_rs_e_..y ________ _
1981
Inspectors:
rholm, Senior Resident Inspector
?fJM.~).
W. M. Hill, Jr.,~sident Reactor Inspector
Approved By: ~~~
E. G. Greenman, Chief, Reactor Projects Section No. 2A,
Projects Branch No. 2, DRPI
Inspection Summary:
~,
date
Jl/1/f I
' dhte
L 11!/.IL
Inspections on October 20 - November 23, 1981 (Combined Report Numbers 50-272/81-27
and 50-311/81-27)
Unit 1 Areas Inspected: Routine inspections by the resident inspectors of plant
operations including tours of the facility; conformance with Technical Specifica-
tions and operating parameters; log and record review; reviews of licensee events;
and followup on previous inspection items.
The inspection involved 89 inspector-
hours by the resident NRC inspectors.
Results:
No items of noncompliance were identified.
.
Unit 2 Areas Insaected: Routine inspections by the resident inspectors of plant
operations inclu ing tours of the facility; conformance with Technical Specifica-
tions and operating parameters; log and record review; review of licensee events;
and followup on previous inspection items.
The inspection involved 88 inspector-
hours by tfle resident NRC inspectors.
Results:
One item of noncompliance was identified (Failure to submit a report as
required oy tbe license - paragraph 5).
8112290363 811208
PDR ADOCK 05000272
G
*- -----
DETAILS
1. Persons Contacted
J. Driscoll, Chief Engineer
L. Fry, Station Operating Engineer
J. Gallagher, Assistant Maintenance Engineer
S. LaBruna, Maintenance Engineer
H. Midura, Manager - Salem Generating Station
L. Miller, Station Perfonnance Engineer
J. O'Connor, Radiation Protection Engineer
F. Schnarr, Reactor Engineer
R.
Sil~erio, Assistant to the 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)
Open Item (311/79-04-20) Format requirements for Performance
Department procedures.
The inspector reviewed Revision 10, dated
- March 25, 1981, to Perfonnance procedure II-3.5, Procedures, which
is part of the revised Performance Department Manual.
The pro-
cedure requires that all applicable sections described in ANSI
18.7-1976 be included in Performance Department procedures. This
requirement is being implemented during the current revision pro-
cess. The inspector had no further questions on this item.
(Closedl Noncompliance (311/80-16-01) Failures to follow procedure*s* with
respect to logkeeping and tagging. The inspector confirmed that
corrective actions for these items have been taken.
The periodic
review of tagging requests has been observed and increased operator
awareness to decreasing tank levels has been noted. With respect
to low tank level alarms, the licensee has cotmnitted to installa- *
tion of such alarms at the next refueling outage. This aspect *of
corrective actions will be followed in resolution of inspection
item 50-311/81-01-01.
(Closed) Unresolved Item (272/81-12-02) Program to periodically blow down
Boric Acid Storage Tank level sensing lines. The inspector re-
viewed Inspection Orders 406131 and 406134 to confirm that the
periodic olowdown program has been established and is continuing
on a quarterly oasis to prevent recurrence of the indication Joss
documented in LER 81-21. The program is in effect on both units,
and was last conducted on September 16, 1981.
The inspector had
no further questions.
0
3
(Closed) Unresolved Item (272/81-04-04) Information feedback to operators.
The inspector reviewed procedure EPDN 16.8, Review of Significant
Licensee Event Reports or Operating Incident Reports, Revision 1,
dated July 14, 1981.
The procedure details a systematic method
of reviewing operating information and disseminating it to opera-
tions and training personnel. Through discussions with the re-
cip\\ients, the inspector confirmed that the system is functioning
and that operators rec~ive the information in requalification
training and through the use of OMT's {Temporary Operating
Memoranda) which are maintained in a required reading file in the
control room.
The inspector had no further questions.
(Closed) Unresolved Item (272/80-32-05) Inspection and cleaning program for
electrical cabinets. The inspector reviewed completed Inspection
Orders 200806 and 200807 and Maintenance Department procedure M4D,
Relay Room Electrical Panels' Inspection and Cleaning, Revision 0,
dated October 8, 1981. A program of annual inspection and cleaning
as necessary has been established and is functional. The licensee
stated that expansion of the program to areas outside the relay room
is being evaluated. The inspector had no further questions on this
item.
(Closed)
Fol low Item (31lt79-10-A) In service inspection for three pipe welds
with questionable postweld heat tf!eatment.
The inspector reviewed
the Unit 2 Pre-Service Inspection report and confirmed that the
three welds (2MS-14-5, 2MS-14-1, and 2MS-12-1) were included in the
UT program which will form the basis for the ISI program.
The
inspector had no further questions on this item.
lClosed) Noncompliance (311/80-12-01) Entry into Mode 3 contrary to Technical
Specification 3.0.4 with No. 23 Auxiliary Feedwater Pump and Con-
tainment Spray System inoperable. The inspector reviewed station
procedures and subsequent practices to confirm that corrective
actions taken were effective in preventing recurrence of this item.
Mode change checklists now.include a specific requirement to review
outstanding tagging requests. This action will ensure that no new
maintenance action just prior to mode change will have rendered a
system inoperable. Operating Memorandum OMP-19 was changed on June
23, 1981 to specifically prohibit on-the-spot changes to post-
surveillance "as left" valve lineups. These procedural steps, in
addition to increased operator awareness through Night Order entries,
should be effective in preventing recurrence of this item. The
inspector had no further questions.
4
(Closed) Noncompliance (272/81-01-01) Failure to verify safety injection
throttle valve position following maintenance.
Immediately
following identification of this item, the valves were verified
to be in the .correct position. Further details were provided
in Licensee Event Report 81-07. The inspector also verified
that a new surveillance procedure, SP(O) 4.5.2.G, ECCS - Throttle
Valves, has been issued for both units to document the position
verification following maintenance.
The inspector had no further
questions on this item.
(Closed) Noncompliance (272/81-05-01) Failure to establish certain procedures
required by Regulatory Guide 1.33. The inspector reviewed console
alarm procedures and Operating Instructions in each unit to confirm
that the changes indicated in licensee's response had been made
through the on-the-spot change procedure. All stated changes were
in place. With respect to tagging of redundant air supply valves,
the inspector confirmed that the design change to accomplish this
tagging was on site and was in progress. The work has not yet been
completed. This action will be verified during the resolution of
related unresolved item 311/80-12-02.
The licensee stated that the
work is expected to be complete by January 1, 1982.
The inspector
had no further questions on this item.
(Closed) Noncompliance (272/80-06-04) Failure to maintain feedwater flow in-
strument calibration. The inspector reviewed documentation.,,*: and
inspection orders and examined the feedwater flow transmitters in
each unit to confirm that the instruments were being calibrated
monthly and that an effective program to preserve this interval was
in place. The inspector had no further questions on this item.
(Closed) Unresolved Items (311/81-11-01 and 311/81-11-02) Fire protection
interaction analysis verification and completion of cable wrap pro-
gram *. Status of these items was reviewed in NRC Inspection Reports
50-311/81-21 and 81-26.
The program has been completed on Unit 2.
The inspector had no further questions on these items.
(Closed) Unresolved Item (272/81-25-02) Containment pressure transmitter
spiking due to steam impingement.
The inspector reviewed digital
voltmeter output data taken from the transmitters which confirmed
that they were responding to containment pressure changes~ The
inspector had no further questions.
(Closed) Follow Item (272/80-10-01} Operator training in use of portable
vibration monitor during ASME XI pump testing. Through discussions
with personnel, the inspector confirmed that training in the use of
the IRD 320 for vibration measurements during pump testing is being
provided during the current requalification training cycle.
(Closed) Follow Item (311/81-21-07) Review of Auxiliary Feedwater Pump Test
report. The report was submitted to NRR on November 3, 1981 and
will be reviewed by the staff. Lateness of the report is identified
as an item of noncompliance in report detail paragraph 5.
5
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, Operational Incidents, 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 abnonnal conditions 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.
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, October 20 - November 23, 1981
Log No. 6 - Primary Plant Log, October 20 - November 23, 1981
Log No. 7 - Secondary Plant Log, October 20 - November 23, 1981
Log No. 8 - Unavailable Equipment Status Log, October 20 - November
23, 1981
6
Night Orders, October 20 - November 20, 1981
Lifted Lead and Jumper Log - All active
Tagging Requests - All active (unit 2)
Nonconformance Reports for October 1981
Incident Reports81-369, 370, 372, 375, 376, 379-384, 387-392, 394,
402, 403, 406-410, 412, 413, 416, 418, 422.
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) Containment
(13)
Guard House
7
b.
The following determinations 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 examination
of control board indication and field observation of selected valves
in safety related systems.
Radiation Controls.
The inspector verified by observation that con-
trol point procedures and posting requirements were being followed.
Plant housekeeping conditions. The inspector observed that house-
keeping was generally acceptable.
Any cluttered or littered area
for which maintenance was not in progress, was brought to the atten-
tion of the plant management or operating staff.
Fluid leaks.
The inspector confirmed that corrective action had been
initiated for any leaks identified by station personnel.
No leaks
were observed that had not previously been identified by station
personnel.
Piping vibration.
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
ooserved 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 pro-
cedures.
Releases.
On a sampling basis, the inspector verified that appropriate
documentation, sampling, authorization, and monitoring instrumentation
were provided for effluent releases *
8
Fire protection. The inspector verified that selected fire exting-
uishers were accessible and inspected on schedule, that fire alarm
stations were inspected on schedule, that fire alarm stations were
unobstructed and that cardox systems were operable. Paragraph 2
details observations relative to the fire protection interaction
analysis and completion of the cable wrapping.
Technical Specifications. Through log review and direct observao.:.
tions during tours, the inspector verified compliance with Technical
Specifications including Limiting Conditions for Operation (LCO's).
The following parameters were sampled frequently:
RWST level, BAST
level and temperature, containment temperature, boration flow path,
shutdown margin, offsite power.
In addition, the inspector conducted
periodic visual checks of protective instrumentation and inspection
of electrical switchboards to confirm availability 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.
d.
The following acceptance criteria were used for the above items:
Technical Specifications
Operation Directives Manual
Inspector Judgement
e. The inspector had no further questions relative to tours made during this
inspection.
5. Full Power License Conditions (Unit 2)
The full power license for Salem Unit'2 was issued on May 20, 1981,and con-
tains several conditions to be met prior to given dates or events. The
inspector reviewed a number of these items to determine status of implemen-
tation. The following comments apply to the areas reviewed (Numbers refer to
paragraph references in the full power license):
2.C.(19} Differential Pressure Baseline Data.
The inspector reviewed
Startup Procedure SUP 7Q.5, RCS Flow Measurements, which was
completed 1in July 1980.
For all combinations of 1, 2, 3, and 4
Reactor Coolant Pumps in operation, the licensee has recorded
elbow tap differential pressure transmitter digital voltmeter
readings for operating and non-operating loops. This information
provides the baseline data specified in this license condition *
The inspector had no further questions on this item.
9
2.C.(22) Radiation Protection Organization.
By correspondence dated
October 1, 1980, the licensee outlined plans to reduce the
dependence on contractor personnel in the area of health physics
staffing. Organizational changes in this area are addressed in
NRC Inspection Report 50-272/81-20. The licensee also committed
to a complement of 4 Supervisors, 9 Technicians, 16 Assistants,
3 Helpers, and 3 Clerks. All would be PSE&G employees.
As of
November 1, 1981, the complement of PSE&G employees in the
Radiation Protection Department was:1 1 Senior Supervisor, 1
Lead Engineer, 1 Associate Engineer, 4 Supervisors, 9 Techni-
cians, 11 Assistants, 3 Apprentice Assistants, 6 Helpers, and
1 Clerk.
Two additional Clerks were in the process of being
hired. The inspector determined that these individuals satisfy
the license condition. It was noted that additional contractor
personnel remain on site, primarily as a result of preparations
for the upcoming Unit 1 outage.
2.C.(24)lc}lii) Auxiliary Feedwater System Pump endurance testing.
Testing of these pumps was completed on August 14, 1981.
As
documented in NRC Inspection Report 50-311/81-21, preliminary
review of data found the results acceptable. The licensee was
required by this condition of the license to provide a report
within 60 days of completion of the tests. The licensee's
report was not transmitted until November 3, 1981. This failure
to report within the time period specified constitutes non-
compliance with a condition of the operating license (311/81-27-0l).
2.C. (24)(b) Short-term accident analysis and procedures revisions.
Through specific briefings, copies of procedures, and requalifi-
cation training, operators have been made aware of changes to
emergency operating instructions precipitated by additional
reviews of small-breaks and inadequate core cooling. This re-
quirement was met prior to 30 effective full power days of
operation. This topic is again included in the current cycle
of licensed operator requalification training, a portion of
which the inspector attended.
2.C.(24}(e)lii) Primary Coolant Sources Outside Containment.
As
documented in NRC Inspection Report 50-311/81-11, the licensee
measured leakage in systems outside containment prior to initial
startup and submitted the required report. The leak rates were
measured with the plant at full system pressure and normal
operating temperature.
No additional systems were to be measured
after startup. Accordingly, no additional report is required.
The licensee's continuing program of leakage monitoring and
reduction was discussed in NRC Inspection Report 50-272/80-20.
The licensee stated that changes in responsibility and procedures
for this program are being made, but the program is continuing.
The inspector had no further questions with respect to license conditions
reviewed.
10
6.
Lessons Learned (NUREG-0737)
The following item, detailed in NUREG-0737, Clarification of Action Plan
requirements, was to be completed by October 1, 1981.
The inspector
confinned that all action had been completed in a manner consistent with
NRC documented requirements in this area.
II.B.4 - Training for mitigating core damage.
All licensed operators
have completed the first cycle of this training (Reference NRC
Inspection Reports 50-272/80-20, 81-04, and 81-05). This topic
is also included in the current cycle of operator requalification
training.
No unacceptable conditions were identified relative to the above item.
7. Station Operations Review Committee (SORC)
The inspector attended, as an observer, the October 28, 1981, Meeting of
the Station Operations Review Committee lMeeting 81-112).
No inadequaCies
were identified with respect to membership, quorum requirements, the review
process, or qualifications of individuals. Alternates are specifically
designated for Committee members and adequate controls over the number of
alternates participating as voting members were in place.
The inspector noted that a system of tracking SORC open items has been
established but does not appear to have received recent attention. Addi-
tionally, minutes had not been fonnally prepared for meetings held two
months ago.
Consequently, the inspector could not confirm that actions
taken at this meeting were properly documented in meeting minutes and
tracked to completion. The licensee stated that an effort to clear this
~acklog has been initiated.
This area will be continually reviewed during the routine inspection pro-
gram.
The specific problems of timely minutes and open item tracking
remain unresolved pending further inspector review (272/81-27-01).
8. Radiological Effluent Monitoring
The inspector evaluated the adequacy of radiological effluent monitoring
during routine containment pressure-vacuum relief operations.
To comply with Technical Specification 3.6.1.4 (Containment pressure limits
-1.5 to +0.3 psig) the licensee finds it necessary to relieve containment
pressure using the 10-inch pressure vacuum relief valves (VC 5 and 6) for
about one hour per day. This operation is distinct from containment purge,
which involves the use of 36-inch valves (VC 1~4) to exchange air in the
containment and which is prohibited by Technical Specification 3.6.1.7 in
Modes 1 through 4.
11
The inspector
1s review was prompted by observation of the following sit-
uation on October 26, 1981. The licensee conducted a containment pressure
relief operation on Unit 2 between 10:34 and 11:45 a.m. with the plant
vent gaseous activity monitor (2R41C) out of service. The containment
gaseous activity monitor (2R12A) was in service and operable with the alarm
setpoint at 4.33 E+4 cpm.
Either of these two monitors will isolate all
containment ventilation valves when its respective alarm setpoint is
reached. Unit 2 Technical Specification Table 3.3-6 (Radiation Monitoring
Instrumentation) lists the following under Process Monitors:
MINIMUM
CHANNELS
APPLICABBE
ALARM/TRIP
MEASUREMENT
INSTRUMENT
MODES
SETPOINT
RANGE
ACTION
a. Containment
lJ Gaseous Activity
al Purge & Pressure- l**
Vacuum Relief
~ 4.5 x 10-2
101- 106 cpm
Isolation
1, 2, 3, 4 & 6
Ci/Sec
- The unit vent sampling monitor functions in this capacity when the purge
and exhaust isolation valves are open.
Technical Specification Table 3.3-3 (Engineered Safety Feature Actuation
System Instrumentation) lists the following information:
MINIMUM
TOTAL NO.
CHANNELS
CHANNELS
APPLICABLE
25
FUNCTIONAL UNIT
OF CHANNELS
TO TRIP
MODES .
ACTION
c.
Containment Ventilation
!sol ation
1) Containment Atmo-
2**
1
1
1,2,3,4
sphere Gaseous
Radioactivity-High
- The unit vent sampling monitor functions in this capacity when the purge
and exhaust isolation valves are open *
17
12
Actions 17 and 25 require that valves VC 1-6 remain shut if less than one
channel is operable.
The licensee stated his position that either monitor (2R12A or 2R41C)
can serve to provide the containment isolation function and that 2R12A,
even though it is not a vent monitor, will cause the required isolation
at a setpoint equivalent to the release rate given in Table 3.3-6.
The inspector reviewed a document dated October 22, 1979, entitled, Radiation
Monitoring System Alann Trip Setpoints SNGS-2, which correlates the release
rate of 4.5E-2 uCi/sec to an R12A setpoint of 5.77E4 cpm using a maximum
plant vent flow rate of 5.5E4 cubii.ctc:feet per minute with a x/Q of 2.2E-6
seconds per cubic meter.
The observed setpoint was set at 75 percent of the above calculated value.
The vent monitor, 2R41C, is set at a value {4.89E5 cpm) designed to prevent
exceeding the instantaneous release rate limit during purge, calculated at
0.77 Ci/sec. Use of 2R41C as the isolation channel during pressure-vacuum
relief would require reducing the se~point to 2.86E4 which is not routinely
done. Consequently, 2Rl2A is usually the single channel used to satisfy
the Technical Specification monitoring requirements. For containment purge,
station procedures require that R41C be operable.
Based on the above review and discussions with NRR, the inspector concluded
that the use of channel 2R12A as the isolation monitor during containment
pressure-vacuum relief appears consistent with the letter and intent of the
Technical Specifications. To clarify the asterisk noted with regard to the
vent monitor, the licensee proposed to request a change to the Technical
Specifications. The inspector had no further questions on this item subject
to further review when an amendment request is submitted {311/81-27-02).
9. Operational Summary
Unit 1
At 1:50 p.m. on October 29, Unit 1 tripped from 98 percent power due to loss
of the lA Vital Instrument Bus.
The lA Vital Instrument Inverter output
fuse had blown, placing all Channel l protective relays in the tripped con-
dition, including the UV relay for one Reactor Coolant Pump.
Indicated loss
of one pump at this power level generates a direct reactor trip. Prior to
recovery, the Channel 1 outputs (including several high steam flows) were
still tripped when an actual Low Tave condition resulted in safety injection
at 1:58 p.m. and 2:03 p.m.
The high head pumps injected and were reset when
termination criteria were met, within 5 minutes each time.
The safety in-
jections were terminated oefore the plant went solid *
13
Irrnnediately prior to the inverter failure, the power supply fuse to the
inverter cooling fan had been replaced. All fuses were replaced and the
inverter retested.
No subsequent problems were found, and the inverter
was declared operable.
At 6:49 a.m. on November 5, a reactor/turbine trip occurred from 65 per-
cent power.
The cause for the trip was determined to be a problem in the
E-H Control System.
Extensive testing eventually identified a faulty
printed circuit board which was subsequently replaced.
At 1:30 p.m. on November 6, the unit tripped from 4 percent power due to
a low level in 12 Steam Generator because of operator error. Steam
Generator level control was in manual.
At 2:11 p.m. a Safety Injection
occurred when Tave fell below 541 degrees and steam flow indicated high
when lA Vital Instrument bus was lost. The IA Vital Instrument bus was
lost when licensee engineers removed and replaced a lamp fuse to the
cooling fan in the inverter cabinet.c (See Safety Injection on October 29).
Prior to start up, the power cab 1 e to the fan was rerouted -away. from the
control wires in the inverter. During the safety injection, two inlet
valves to the Boron Injection Tank (BIT) did not initially operate as re-
quired.
The cause was attributed to boric acid buildup on the valve stem.
The valves were cleaned, tested, and declared operable.
The licensee has
increased the frequency of tests and inspections of these valves until the
packing can be replaced during the next outage.
Unit 2
At 5:54 a.m. on October 22, a reactor/turbine trip occurred from 75 per-
cent power due to a low water level in 24 Steam Generator.
The cause for
the low level was loss of 21 Main Feed Pump which tripped on low suction
pressure*.
At 2:58 a.m. on November 16, a reactor/turbine trip occurred from 100 per-
cent power due to a low level in 24 Steam Generator caused by loss of 22
Main Feed Pump from low suction pressure.
At 5:06 p.m. on November 19, a turbine/reactor trip occurred from 90 per-
cent power due to low level in 24 Steam Generator, caused by low Main Feed
Pump 22 suction pressure.
Investigation resulted in replacing the pressure
switch and cleaning the sensing line. At 8:12 p.m., a reactor/turbine trip
occurred from 30 percent power while returning to service. The cause was
a high level in 24 Steam Generator which occurred due to operator error when
shifting from manual to automatic control. The unit was returned to service
at 2:39 a.m. on November 20 *
1-
- 10.
..
14
At 8:09 p.m. on November 24, a reactor/turbine trip occurred from 100 per-
cent power due to a low level in 24 Steam Generator. The generator low
level was caused by loss of 22 Main Feed Pump which tripped on low suction
pressure.
Installed instrumentation indicated that feed pump suction
pressure decreased while condensate flow increased. The .licensee is in-
vestigating several possible malfunctions which would give this indication.
The inspector expressed his concern about the repeated reactor/turbine
trips caused by the loss of feed pumps and low suction pressure. A licensee
representative acknowledged the inspector's concerns and outlined an exten-
sive program to identify the cause for the trips. In addition to the frequent
inspection, cleaning, and blowdown of the feed water and condensate pump
suction strainers, the mechanical traps (strainers) in the condensate polish-
ing system have been removed, inspected, repaired, as appropriate, and rein-
stalled. Several small holes were identified and repaired which would have
caused blowby of resins and clogging the feed water pump suction strainers.
The licensee is procuring additional instrumentation necessary to monitor
up to 51 plant parameters in the secondary system.
The licensee believes
this will provide enough infonnation to determine and correct the cause for
the frequent plant trips. The inspector will continue to monitor the licensee's
progress and followup any further trips which are feed pump related.
The inspector had no further questions regarding the operations during this
period.
Surveillance Activities
The inspector observed the licensee's performance of the following surveillance
procedures:
a.
l PD 2.6.020 Channel Functional Test
LT 459 Pressurizer Level Protection Channel I, Revision 3,
November 29, 1979 .
b.
l PD 2.6.017 Channel Functional Test
1 PT - 455 Pressurizer Pressure Protection channel I, Kevision
7, January 15, 1980
c. 1 PD 2.6.055 Channel Functional Test
l LT 539 No. 13 Steam Generator Level Protection Channel I,.
Revision 2, December 7, 1979
d.
l PD 2.6.045 Channel Functional Test
1 LT 529 No. 12 Steam Generator Level Protection Channel I,
Kevision 2, December 7, 1979
e.
1 PD 2.6.024 Channel Functional Test
1 PT - 505 First Stage Turbine Impulse Pressure Channel I,
Revision 4, January 10, 1978
15
A CHANNEL FUNCTIONAL TEST shall be the injection of a simulated signal
into the channel as close to the primary sensor as practical to verify
OPERABILITY including alarm and/or trip function. This requirement in
the technical Specifications demonstrates "operability" for safety re-
lated instrumentation. 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 properly accomplished; and,
the test results conformed with Technical Specifications and procedural
requirements 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 had no further questions re.g51*rding
the performance of these surveillance activities.
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11. Maintenance Activities
The inspector observed maintenance activities on the following equipment:
a.
22 Charging Pump - replacement of rotor
b.
2A SEC - replacement of drawer, one output relay and system retest
c.
Power Range Channel, 2N43 - detector current adjustment; bistable
NC 302 and NC 306 adjustment; and, console {remote meter) adjustment
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; radiolo-
gical controls were implemented; and fire prevention controls were implemented.
At 5:27 a.m. on November 7, 1981, No. 22 Charging Pump shaft failed while in
service. Replacement of the pump rotating assembly was initiated; however,
Technical Specification 3.5.2 only permits inoperability of one ECCS subsystem
for a period of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in Modes 1-3.
On November 9, the licensee requested,
and NRR granted, a one time extension to this time limit of an additional 48
hours.
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Replacement of the pump assembly would also require performance of the
ECCS flow distribution test dictated by Technical Specification 4.5.2.h.
The licensee also requested relief from this requirement, based on pump
shop test data and previous setting of the ECCS flow distribution throttle
valves.
By the same amendment to the license, this testing was deferred
until the next cold shutdown provided that an adequate analysis and cal-
culation demonstrated that the pump could be expected to perform in a
manner similar to the failed pump.
Repairs were completed on November 10, and a successful ASME XI pump test
performed as required by Technical Specification 4.0.5. The pump was
declared operable at approximately 11:30 p.m.
The inspector reviewed a
safety evaluation dated November 10, 1981 (S-2-NlOO-MSE-110, Rev. 0) en-
titled, Postponement of Technical Specification 4.5.2.h Test For the Unit
No. 2 - Centrifugal Charging/Safety Injection Pumps Salem Nuclear Generating
Station Unit No. 2. Using shop test data for the pumps, and system resis-
tance characteristics developed from previous field testing, the licensee
concludes that the new rotating assembly exhibits performance character-
istics which appear even closer to those of the installed No. 21 pump than
the failed pump displayed. Accordingly, the conclusion drawn is that there
is adequate assurance that a full flow test will show that system flow
distribution under runout conditions will meet Technical Specification 4.5.2.h requirements.
Performance of the full flow test during the next cold shutdown will be
verified at that time (311/81-27-03).
The inspector had no further questions regarding any maintenance activities
observed.
12. 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.
Component Coo 1 i ng Sys tern (Unit 1 ) - 205231, revision 11, dated
November 23, 1980
b.
Containment Spray (Unit 1) - 205235, revision 7, dated January
23, 1981
c. Containment Spray (Unit 2) - 205335, revision 7, dated January
10, 1980
d.
Safety Injection (.Charging Pumps) - 205334, revision 8, dated
May 6, 1980 -
(Unit 2)
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The walk down was conducted to confinn system operability. Included in this
review was an examination of valve positions, seismic restraints and
supports, leaks (unidentified), local indicators and instrumentation,
unusual noise or vibrations, overheated equipment, and system confonnance
with "as built" drawings~ No unacceptable conditions were identified.
13. Unresolved Items
Areas for which more information is required to determine acceptability
are considered unresolved. Unresolved items are contained in Paragraphs.
7 and 8.
14.
Exit Interview
At periodic intervals during the course of this inspections, meetings
were held with senior facility management to discuss inspection scope and
findings *