ML18095A577
| ML18095A577 | |
| Person / Time | |
|---|---|
| Site: | Salem, Hope Creek  |
| Issue date: | 10/31/1990 |
| From: | Swetland P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18095A575 | List: |
| References | |
| 50-272-90-22, 50-311-90-22, 50-354-90-16, NUDOCS 9011130391 | |
| Download: ML18095A577 (47) | |
See also: IR 05000272/1990022
Text
t.*
Report Nos.
License Nos.
Licensee:
Facilities:
Dates:
Inspectors:
Approved:
~
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
50-272/90-22
50-311/90-22
50-354/90-16
Public Service Electric and Gas Company
P. 0. Box 236
Hancocks Bridge, New Jersey 08038
Salem Nuclear Generating Station
Hope Creek Nuclear Generating Station
August 16, 1990 - October 1, _1990
T. P. Johnson, Senior Resident Inspector
S. M. Pindale, Resident Inspector
S. T. Barr, Resident Inspector
H. K. Lathrop, Resident Inspector
A. E. Lopez, Reactor Engineer
R. S. Barkley, Project Engineer
F. I. Young, Senior Resident Inspector,
Thr
Mile Island
Inspection Summary:
Inspection 50-272/90-22; 50-311/90-22;
50-354/90-16 on August 16, 199~ - October 1, 1990
IO /"3J}CJCJ
Date'
Areas Inspected:
Resident safety inspection of the following areas:
operations, radiological controls, maintenance & surveillance testing,
emergency preparedness, security, engineering/technical support, safety
assessment/quality verification, and licensee event reports and open item
fo 11 owup.
Results:
The inspectors identified one violation with multiple examples and
five non-cited violations:
three for the Salem Station and two for the Hope
Creek Station.
An executive summary follows.
9011130391 901101 -
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TABLE OF CONTENTS
I.
EXECUTIVE SUMMARY
II.
DETAILS
1. SUMMARY OF OPERATIONS
1.1 Salem Unit 1 .. .
1.2 Salem Unit 2 .. .
1.3 Hope Creek ... .
1.4 Organizational Changes.
2. OPERATIONS
.1
.1
.1
.1
Page
2.1
Inspection Activities . . . . . . . . . . . .
.2
2.2 Inspection Finding & Significant Plant Events
.2
2.2.1
2.2.2
Sal em . . .
Hope Creek.
3.
RADIOLOGICAL CONTROLS
3.1
Inspection Activities ........ .
3.2
Inspection Findings & Review of Events.
3.2.1
3.2.2
Sal em . . .
Hope Creek.
4.
MAINTENANCE/SURVEILLANCE TESTING
.2
.13
.14
.15
.15
.15
4.1 Maintenance Inspection Activities . . . .
.15
4.2 Surveillance Testing Inspection Activity.
.16
4.3
Inspection Findings .
.16
4.3.1
4.3.2
Sal em . . .
Hope Creek.
5.
5.1
Inspection Activity
5.2 Inspection Findings
6.
SECURITY
6.1
Inspection Activity
6.2
Inspection Findings
.16
.24
.26
.26
.26
.26
2
Table of Contents (Continued)
7.
ENGINEERING/TECHNICAL SUPPORT
7.1
TMI Action Plan Item Review
7.2 Salem .......... .
7.3
Hope Creek ........ .
8.
SAFETY ASSESSMENT/QUALITY VERIFICATION
8.1 Waivers of Compliance
8. 2 Sa 1 em . . . . . .
8.3
Hope Creek ....
Page
.26
.28
.31
.32
.34
.39
9.
LICENSEE EVENT REPORTS ( LERS), PERIODIC & SPECIAL REPORTS,
AND OPEN ITEM FOLLOWUP
9.1
LERs & Reports.
9.2 Open Items.
10.
EXIT INTERVIEWS
10.1 Resident ..
10.2 Specialist.
.39
.40
.41
.41
EXECUTIVE SUMMARY
Salem Inspection Reports 50-272/90-22; 50-311/90-22
Hope Creek Inspection Report 50-354/90-16
August 16, 1990 - October 1, 1990
OPERATIONS
(Modules 71707, 93702, TI 2515/101)
Salem:
The units were operated in a safe manner.
Three unplanned reactor
trips (two on Unit 1 and one on Unit 2) occurred due to:
(1) inadequate
preventive maintenance on non-safety related breaker cubicles; (2) multiple
equipment failure; and (3) development of an inadequate troubleshooting plan.
Licensee followup for these reactor trips was thorough.
An instance of
failure to follow procedural guidance and administrative controls, and several
instances of poor communications resulted in other events (ESF actuations, AFW
tank overflow, unauthorized release of tags).
The licensee effectively
conducted midloop operations at Unit 1 during the replacement of a reactor
coolant pump motor.
A personnel error and a contributing procedure weakness
resulted in a minor spill in the Unit 1 containment.
Two non-cited violations
were identified:
one was for failure to follow a turbine test procedure that
resulted in a Unit 1 reactor trip, and one was failure to follow the tagging
administrative procedure for the number 22 containment fan coil unit.
Hope Creek:
The unit was operated in a safe manner.
Licensee actions for
high moisture content in the high pressure coolant injection system lube oil
system were adequate.
An increase in drywell unidentified leak rate and an
apparent fuel pin leak were aggressively pursued by the licensee with an
appropriate level of safety perspective.
RADIOLOGICAL CONTROLS
(Modules 71707, 93702)
Salem:
No noteworthy findings were identified.
Hope Creek:
No noteworthy findings were identified .
2
MAINTENANCE/SURVEILLANCE
(Modules 61726, 62703, 73755, 73756, 92702)
Salem:
NRC observed maintenance and surveillance activities were effectively
controlled.
Failure to perform 10CFR50.59 and ASME Section XI evaluations for
degraded number 22 boric acid transfer pump flow rate is a violation.
Licensee corrective actions were evaluated to be satisfactory and no response
is required.
Containment liner corrosion issues were adequately addressed by
the licensee.
A licensee QA inspector properly identified, evaluated and
reported a potential safety concern that resulted from poor intra and
interdepartmental communications regarding a reactor trip breaker surveillance
test.
Another example of poor communication occurred during followup to a
safeguards equipment control actuation.
An error in licensed operator
judgement resulted in late declaration of auxiliary feedwater pump
inoperability.
A surveillance test procedure weakness resulted in an
inadvertent main steam line isolation.
A non-cited, licensee identified
violation regarding TS surveillance testing frequency error for the solid
state protection system was identified.
An unresolved item regarding
inservice testing vibration markings remains open due to ineffective
corrective actions.
Hope Creek:
NRC observed maintenance and surveillance activities were
effectively controlled.
Failure to follow a surveillance procedure resulted
in an inadvertent isolation of the reactor core isolation cooling system.
This is a non-cited, licensee identified violation.
A personnel error
resulted in a failure to re-baseline the service water spray wash pump after
maintenance and is a non-cited, licensee identified violation.
Common:
Maintenance troubleshooting was determined to be effectively
controlled.
However, a potential programmatic weakness regarding the control
of operations troubleshooting activities was identified.
(Module 71707)
No noteworthy findings were identified.
SECURITY
(Module 71707, 93702)
No noteworthy findings were identified .
3
ENGINEERING/TECHNICAL SUPPORT
(Modules 37828, 41400, 71707, TI 2515/65)
TMI Action Plan (TAP) Review:
Salem (TAP item II.B.1.2, 3) Unit 1 and Unit 2
reactor vessel head vents and Hope Creek control room habitability (TAP item
III.D.3.4.2) are closed.
Salem:
A review of the systems engineer training program did not reveal any
deficiencies.
Safety equipment room cooler operability associated with
licensee TS interpretation (unresolved item) remains open pending completion
of licensee actions.
A previous violation associated with the failure to
perform a safety evaluation for the seismic impact of a reactivity computer is
closed.
An unresolved item associated with charging pump flow orifices being
installed backwards is closed.
Hope Creek:
The licensee identified and properly handled a desi~n deficiency
associated with temperature limits of the ultimate heat sink (Delaware River).
SAFETY ASSESSMENT/ASSURANCE OF QUALITY
(Modules 30703, 71707, 90714, 92700,
92702, 92703, 92720)
Salem:
One NRC Regional Waiver of Compliance was processed for Salem to allow
replacement of the Unit 2 number 22 containment fan coil unit.
This submittal
was adequate.
Reactor protection system setpoint changes of steam generator
level and steam pressure were adequately handled by the licensee.
Failure to
maintain independence of station qualified reviewers, failure to perform a
safety evaluation for a non-ASME code repair (Belzona R) and failure to
properly handle significant safety issues are further examples of violations
of 10CFR50. 59.
Hope Creek:
Two NRC Regional Waivers of Compliance were processed for Hope
Creek:
One associated with inadequate diesel generator fuel oil sample
results and one associated with the replacement of the 11A11 safety auxiliaries
cooling system (SACS) pump.
The first submittal was adequate.
However,
weaknesses were identified relative to the completeness of technical
information and safety basis for the second (SACS) submittal.
Two personnel
errors occurred during the period; one by maintenance personnel during
surveillance and one by operations personnel during equipment post-maintenance
testing per ASME Section XI .
t
DETAILS
1.
SUMMARY OF OPERATIONS
1.1 Salem Unit 1
Salem Unit 1 began the report period in Mode 3 (Hot Standby) and
preparing for unit startup following resolution of main steam isolation
valve (MSIV) concerns.
During startup activities, the reactor
automatically tripped on August 17, 1990 after the No. 14 reactor coolant
pump (RCP) lost electrical power during 4 kV non-vital auxiliary power
transformer feeder breaker switching.
The unit was subsequently shutdown
to Mode 5 (Cold Shutdown) to replace the No. 14 RCP motor.
The unit was
returned to service on September 7, 1990, and operated until September
10, 1990, when an automatic reactor trip occurred while preparing to
isolate a high pressure turbine sensing line leak.
Power operation
resumed on September 12, 1990, and continued until the end of the
inspection period.
1.2 Salem Unit 2
Salem Unit 2 began the report period in Mode 3 (Hot Standby) and
preparing for unit startup following resolution of MSIV concerns.
The
unit was placed in service on August 20, 1990, and power operation
continued until September 4, 1990, when the unit tripped automatically
due to a secondary system transient caused by equipment failures.
Power
operation resumed on September 8, 1990, and continued until the end of
the inspection period.
1.3
Hope Creek
The Hope Creek unit remained operational during the report period.
Several power reductions occurred to conduct maintenance and testing
activities.
During the period, the drywell unidentified leak rate
increased, and a small fuel pin leak was noted.
1.4 Organizational Changes
On September 24, 1990, PSE&G announced the following organization changes
effective October 1, 1990:
Lynn Miller, General Manager, Salem
Operations, will assume a new position of General Manager, Nuclear
Operations Support.
His responsibilities will include management of the
Salem materiel and procedure upgrade projects.
He will also assume
interim management responsibility for nuclear services, procurement and
material control, and reliability and assessment.
Stanley LaBruna, Vice
President, Nuclear Operations, will assume responsibility as Acting
General Manager, Salem Operations.
Also, Chuck Johnson has been assigned
as acting General Manager, Hope Creek Operations since September 4, 1990,
while Joe Hagan attends management training until December 1990.
2
2.
OPERATIONS
2.1
Inspection Activities
The inspectors verified that the facilities were operated safely and in
conformance with regulatory requirements.
Public Service Electric and
Gas (PSE&G) Company management control was evaluated by direct
observation of activities, tours of the facilities, interviews and
discussions with personnel, independent verification of safety system
status and Technical Specification Limiting Conditions for Operation, and
review of facility records.
These inspection activities were conducted
in accordance with NRC inspection procedures 60710, 71707, 71711 and
93702.
The inspectors performed normal and back shift inspection (597
hours), including deep backshift inspection as follows:
Unit
Hope Creek
Inspection Hours
8:00 a.m. - 12:00 noon
6:00 a.m. - 10:00 a.m.
Dates
September 16, 1990
September 22, 1990
2.2
Inspection Findings and Significant Plant Events
2.2.1
Salem
A.
Unit 1 Reactor Trip on August 17, 1990
A Unit 1 reactor trip from 25% power occurred due to 14 steam generator
(SG) low-low water level on August 17, 1990, at 6:12 a.m.
The trip
occurred during 4KV non-vital auxiliary power transformer feeder breaker
switching.
An interlock, cell switch 52IS, prevented the feeder breaker
from properly closing during a group bus transfer.
This resulted in a
loss of power to the No. 14 reactor coolant pump (RCP) motor.
A
resultant level shrink in the No. 14 SG due to the steam pressure
increase caused the SG low level condition.
Prior to the group bus
transfer of the non-safety related distribution system, the shift
electrician had verified breaker cell switch and fuse continuity to
ensure the breaker was ful*ly racked in (interlock switch made up).
However, post trip inspection of the breaker compartment found a loose
and binding condition in the cell switch linkage that could have caused
intermittent continuity during electrical group bus swapping.
The
licensee reported the event appropriately to the NRC Operations Center.
A Significant Event Response Team (SERT) was initiated by the licensee.
After post-trip review, and in preparation for reactor restart, the No.
14 RCP was placed in service at 5:15 p.m. on August 17, 1990.
Subsequently, at 7:13 p.m., the RCP tripped on a phase to ground fault
condition.
The licensee meggered the motor and found a motor winding
failure.
The unit proceeded to Mode 5 (Cold Shutdown) to replace the No.
14 RCP motor.*
B.
3
At about 6:45 a.m. on August 17, 1990, the inspector reviewed post trip
conditions in the control room including emergency operating procedure
implementation, selected chart recorder traces, operator performance and
control room logs.
Operators were interviewed, including the reactor and
senior reactor licensed personnel.
The completed AD-16,
11 Post Reactor
Trip Review
11 , was also reviewed.
The inspector also discussed the trip
with operations and plant management personnel.
The inspector examined the failed breaker cell switch and associated
cubicle in the field.
The system engineer was questioned regarding
breaker and cubicle operation, utilizing electrical prints and
schematics.
The inspector noted that the system engineer was
knowledgeable of breaker operation and of the probable failure mechanism.
The inspector also discussed the breaker failure with the Maintenance
Department manager.
The manager acknowledged that there had been three
similar breaker failures in the past three years.
A five year preventive
maintenance (PM) task on breakers is performed by the vendor.
However,
there is no recurring task or PM to check the breaker cubicle cell switch
(52IS) and the racking mechanism alignment.
A reliability centered
maintenance recommendation was made in March 1990 to check the cell
switch/racking mechanism in each 4KV breaker every 36 .months.
This PM
activity was scheduled for Unit 2 during the fifth refueling outage
(March - May 1990).
However, tagging boundary difficulties prevented
this PM activity from occurring.
Unit 1 is currently scheduled for this
PM activity in January - February 1991.
The inspector also reviewed the related Unit 1 LER 90-29 dated September
12, 1990 and SERT report dated August 23, 1990.
The licensee concluded
that the root cause of the reactor trip was mechanical failure due to
inadequate preventive maintenance on the non-safety related breaker
cubicle (e.g., cell switch).
Licensee corrective actions included:
inspecting and repairing similar breaker cubicles, verifying operability
of breakers and cell switches, and revising maintenance procedure M3H to
include a recurring PM task.
The inspector concluded that the licensee 1s
review of the event and corrective actions were adequate.
Unit 2 Reactor Trip on September 4, 1990
On September 4, 1990, Unit 2 automatically tripped from 60% power due to
high-high water level in the No. 24 steam generator (SG).
While
operating at 100% power, an operator noted a control room indication that
one of two operating SG feedwater pumps had tripped.
The feedwater
regulating valves (FRVs) for each of the four SGs went full open to
maintain programmed water level.
The operator immediately initiated a
main turbine load reduction to 60% power and took manual control of all
four FRVs, per abnormal operating procedures.
SG levels decreased to 24%
narrow range (normal is 44%), and then began to increase.
High-high SG
level turbine.and reactor trips occurred before the operator could
manually close the associated FRV for the No. 24 SG.
A large level error
4
caused by the low SG levels, resulted in slow response of the FRV
controllers to the manual close demand signal.
Additionally, when the
FRVs were placed in manual, the No. 21 FRV operated abnormally and went
fully closed, thereby increasing feedwater flow through the remaining
three FRVs.
The licensee reported the reactor trip to the NRC via the
Emergency Notification System in accordance with 10CFR50.72 reporting
requirements.
Licensee followup of the unit trip identified that the No. 21 steam
generator feedwater pump (SGFP) tripped automatically due to low suction
pressure.
There are two automatic low suction pressure trips associated
with the SGFPs:
1) 215 psig with a three second time delay, and 2) 190
psig instantaneous trip.
The licensee identified two equipment problems
that together resulted in the plant transient, namely the miscalibration
of the No 21 SGFP suction pressure switch and a heater drain pump
discharge control valve diaphragm failure.
The failure of the No. 21 SG
FRV controller also resulted in ineffective level control.
A post-trip calibration of the No. 21 SGFP pressure switch identified
that the 215 psig setpoint was actually set high (an equivalent setpoint
of 329 psig due to sensing line configuration and pressure switch*
location).
SGFP suction pressure prior to the transient was equivalent
to 370 psig as indicated in the control room.
Therefore, only a 41 psig
suction pressure reduction would result in the time delayed No. 21 SGFP
trip (370 to 329 psig).
The licensee also determined that the No. 23 heater drain pump discharge
control valve (HD15) failed during the transient.
Specifically, the
valve's diaphragm ruptured, and the valve went fully closed, creating a
SGFP suction pressure reduction.
That pressure reduction, in combination
with the pressure switch increased trip setting, resulted in the SGFP low
suction pressure trip.
For about one hour prior to the trip, the licensee identified additional
flow oscillations (approximately 2000 gpm) on the outlet of the full flow
condensate polishing system.
These oscillations were unexplained and did
not appear to directly impact operation of the secondary system.
Nonetheless, the licensee initiated and is continuing efforts to identify
the cause of the oscillations.
Prior to the transient, one (of six) condenser circulator (No. 218) was
taken out of service for cleaning and maintenance.
Water level in the
associated cond_enser hotwell was reduced, and temperature was elevated
due to the absence of circulating water in that waterbox.
The inspector
noted that the above conditions may have contributed to the trip by
creating flashing conditions downstream of the condensate pumps and
resulting in reduced pressure at the SGFP suction.
The licensee was also
evaluating those conditions for future corrective actions.
5
During followup of the trip, the inspector reviewed the associated
abnormal operating procedures (AOPs).
11 Loss of Circulating
Water and/or Condenser Vacuum
11 , specifies procedure entry when one or
more circulating pumps trip or are taken out bf service.
The inspector
determined that the ADP was not entered by plant operators when the
single circulating pump was initially taken out of service. Discussions
with unit operators and Operations management indicated that since
circulators are frequently taken out of service for both preventive and
corrective activities, and this is considered to be a routine activity,
the ADP is not entered.
However, the operators closely monitored
condenser conditions.
The inspector reviewed AOP-COND-2 and determined
that only routine actions are directed when only one circulator is out of
service.
Additional actions are directed by the ADP only when two
circulating water pumps are out of .service on the same condenser shell.
Therefore, entry into the ADP under the specific conditions that existed
on the day of the trip would not have resulted in significant operator
response.
The inspector discussed the practice of not entering AOPs,
although specific entry conditions were met, with licensee management.
Management acknowledged the inspectors' concern and committed to evaluate
ADP usage and implement corrective actions.
A Station Operations Review Committee (SORC) meeting was conducted on
September 5, 1990, to review the post trip data and plant response.
The
inspector attended the meeting.
Plant startup was authorized with the
following conditions and short-term corrective actions:
1) calibrate the
SGFP suction devices, 2) evaluate ADP- COND-2 to develop procedure
changes to address conditions and actions specific to operating with one
circulator out of service, 3) conduct training sessions with the
appropriate personnel, and 4) complete all necessary component repairs.
Longer term recommendations included:
1) resolve condenser polisher flow
discrepancies, and 2) evaluate the condenser hotwell dynamics and the
impact on secondary plant components.
A significant event response team
(SERT) was formed and independently reviewed the event.
A unit startup subsequently commenced and the reactor was made critical
on September 6, 1990.
The inspector concluded that the licensee's review
and followup of this event, and the associated corrective actions (LER
90-36) were adequate.
C.
Unit 1 Reactor Trip on September 10, 1990
At 12:01 p.m. on September 10, 1990, an automatic reactor trip from 80%
power occurred at Salem Unit 1 when the water level in the No. 13 steam
generator (SG) reached the low-low level setpoint.
The steam generator
level shrink was a result of the unexpected closure of all four main
turbine governor and stop valves.
This occurred when operators closed
one of the governor/stop valve pairs while preparing to isolate a high
pressure turbine drain line steam leak.
The licensee's post trip review
determined that Operations personnel failed to initiate and implement an
adequate troubleshooting plan for the steam leak.
A procedural
6
inadequacy and lack of specific training also contributed to the trip.
As a result, an initial condition of greater than 85% power for the
turbine valve test procedure (OP III-1.3.3) being used by the operators
was not met.
A resulting abnormal governor valve arrangement during the
planned No. 11 governor valve closure, combined with the steam leak and
an open drain valve, caused the high pressure turbine to be deflected.
This caused an oscillation of the shaft and the electro-hydraulic (EH)
speed pick-up sensor failed high, simulating an over-speed condition and
driving all four governor valves shut.
This valve closure combined with
feed/steam flow mismatch, caused a shrink condition in all four SGs.
Plant response to the trip was normal.
However, one intermediate range
nuclear instrument (N35) appeared to be under compensated, and therefore
the source range instruments had to be manually unblocked by the
operators as power decreased following the trip.
The licensee found a
bad connection for the N35 detector in containment and made the necessary
repairs.
The licensee inspected the EH system and turbine in conjunction
with the vendor.
Repairs were made to the EH speed pick-up sensor.
No
additional problems were noted, the unit was restarted on September 13,
1990, and the turbine was synchronized at 6:40 a.m. on September 14,
1990.
A significant event response team (SERT) was formed and
independently determined the root cause.
The inspector monitored post-trip conditions including emergency
operating procedure implementation, selected control room instruments and
chart recorder traces, and operator performance.
The inspector also
reviewed the computer sequence of events log and noted that the reactor
trip first-out annunciator was
11 13 SG level low-low
11 *
Additional followup included discussions with the licensed operators,
operations and plant management, and corporate management.
A review of
procedure OP III-1.3.3 confirmed that the initial condition requiring
greater than 85% power was not met nor was a formal troubleshooting plan
developed.
This failure to follow the operating procedure is a licensee
identified violation and is not being cited because the criteria
specified in section V.G of the Enforcement Policy were satisfied (NON
50-272/90-22-01).
The inspector reviewed AD-16,
11 Post Reactor Trip Review
11 , LER 90-30, and
the SERT report.
The inspector concluded that the licensee performed a
thorough review for root cause and developed good corrective actions.
Corrective actions included:
(1) repair of the steam leak, nuclear
instrument N35, and the EH system; (2) inspection of the
turbine-generator; (3) performing a special monitoring program during
turbine-generator startup; (4) revising the turbine-generator operating
procedures OP III-1.3.1 and III-1.3.3; (5) counseling operators and
operations management personnel involved in the troubleshooting
activities; and (6) developing an operations troubleshooting procedure.
Weaknesses associated with troubleshooting activities are discussed in
section 4.3.3.A of this report.
7
D.
Auxiliary Feedwater Storage Tank Overfill
On August 12, 1990, at 8:00 a.m., the auxiliary feedwater storage tank
(AFWST) was overfi 11 ed by p 1 ant operators, spil 1 i ng water and hydrazine
into a storm drain.
This same event had previously occurred on June 22
and July 21, 1990.
Each overfi 11 took p 1 ace for a very short time ( 1 ess
than five minutes).
In five minutes, 3000 gallons and 0.1 pounds of
hydrazine can be displaced into the storm drain.
The reportable quantity
to the state and and the EPA is 1.0 pounds of hydrazine, therefore, in
each case, no report was required.
The inspector reviewed the Incident Reports (IRs) for the June 22 and
July 21, 1990, events and found that in the June 22, 1990, report an
entry into the night order book was made stating that while filling the
AFWST, the operator should station a nuclear equipment operator with a
radio to ensure the AFWST does not overflow.
After the July 21, 1990,
event, the IR stated that the root cause was that the control room
operator became distracted by other events and forgot to close the valve.
The unit shift supervisor then held a discussion with the operator
involved and other operators concerning the night order book
requirements.
A clear control room console cover, stating those
requirements, was then p 1 aced over the *pushbutton for the AFWST f i 11
valve (DR-6).
The inspector spoke with one of the operations engineers concerning the
August 12, 1990 incident.
He stated the root cause to be a noncompliance
with the night order entry.
The operations engineer said that the
personnel involved were counseled.
The Operations manager also discussed
this issue with all the shifts. After discussions with the reactor
operators (ROs), the operations engineer retracted the previous night
order entry and made another night order entry to instruct the ROs to
open the DR-6 valve when filling the AFWST and to close the valve when
the low level alarm cleared.
Previously, DR-6 would remain open so that
the AFWST could be filled beyond that point.
The operations engineer
then requested engineering to look into the issue to find a more
p.ermanent so 1 ut ion.
The overfil 1 of the AFWST has occurred three ti mes
within a two month period vf time.
The corrective actions, currently in
place, have been found to be an effective short term solution.
E.
Reduced Reactor Coolant System (RCS) Inventory Operations
On August 17, 1990, an electrical fault was discovered on the No. 14
reactor coolant pump (RCP) motor (see section 2.2.1.A).
In order to
replace the motor, Unit 1 was required to enter a reduced
inventory/midloop condition.
The RCS was in a good configuration for the reduced inventory/midloop
condition.-
The decay heat levels were very low (approximately 5.75
megawatts-thermal) due to 30 days of shutdown time, and the only type of
RCS boundary work was for the RCP motor changeout.
-- - - - - - - - - - - -
F .
8
Prior to entering the reduced inventory condition, operating procedures
II-1.3.6,
11 Draining the Reactor Coolant System,
11 and AOP-RHR-2, "Loss of
Residual Heat Removal Cooling -
RCS Level Below the Pressurizer,
11 were
reviewed by the Stations Operations Review Committee (SORC).
A safety
evaluation, Engineering Memorandum No.90-099, that justified the RCS
vent size during midloop operation for this particular outage, was
approved.
Training was given to the operations and
maintenance staffs,
including the supervisors.
The inspector attended the training and
concluded that it was satisfactory.
The inspector reviewed the licensee
1s response to Generic Letter No.
88-17, "Loss of Decay Heat Removal,
11 along with the above mentioned
operating procedures, and the safety evaluation.
The inspector
periodically monitored control room operations and toured containment to
visually inspect the level instrumentation, the level taps, and the tygon
tubing backup level indicator.
The inspector concluded that the licensee
adequately implemented the issues discussed in Generic Letter No. 88-17
(Expeditious Actions).
NRC Inspection 50-272/89-07 and 50-311/89-06
closed this item per TI 2515/101.
The inspector also concluded that the
licensee effectively conducted midloop operations in a safe and proper
manner.
Engineered Safety Feature (ESF) Actuation and Inoperable Safeguards
Equipment Control Train
During a review of an ESF actuation that occurred on September 22, 1990,
the inspector identified concerns relative to the review of a test
anomaly and the timeliness of corrective actions for an operational
event.
Some intradepartmental and interdepartmental communication
deficiencies were also identified.
On September 21, 1990, Maintenance personnel completed a periodic
functional surveillance test for the No. 2C safeguards equipment control
(SEC) train.
The SEC is designed to start and load safety equipment onto
the vital electrical system under accident and/or blackout conditions.
A
new test procedure, No. S2.MD-FT.SEC-0003(Q),
11 ESF Actuation Signal
Instrumentation Monthly Functional Test-2C SEC Logit
11 , was being used for
the first time on installed equipment.
The procedure was a recent
product of the Procedure Upgrade Project.
During the test, the
technician and supervisor noted that an accident loading input light (No.
1) had illuminated and then extinguished for no apparent reason.
This
unexpected anomaly was documented in the completed procedure comments
section, and the test was satisfactorily signed off.
On September 22, 1990, Operations personnel conducted a monthly
surveillance test of the 2C emergency diesel generator (EOG).
Upon
successful completion of the test, an operator reset the 2C SEC as
required.
Several minutes later, the 2C SEC spuriously actuated at 2:45
a.m.
The associated equipment automatically started as designed (e.g.
emergency core cooling system pumps and No. 2C EOG).
The 2C SEC was then
9
reset and all components were secured.
The NRC was notified of the ESF
actuation via the Emergency Notification System in accordance with
10CFR50.72 reporting requirements.
On September 24, 1990, the inspector reviewed the event and found that
the 2C SEC had not been declared inoperable and no troubleshooting or
additional testing activities had been initiated.
The licensee stated
that there was no indication-of an existing fault condition as the SEC
self-test was not in alarm.
Based on these items the- SEC was not
declared inoperable.
However, the inspector determined that no actions
were initiated following the September 22, 1990, ESF actuation due to
apparent communication problems between Operations and Maintenance
personnel.
Also, the inspector found that the significance of receiving
the input No. 1 light during conduct of the September 21, 1990
surveillance test was not properly evaluated by staff personnel nor was
it communicated to the appropriate level of Maintenance supervision.
It
was subsequently determined that during the test on September 21, 1990,
the 2C SEC output had been disconnected by procedure, and if connected, an
ESF would have occurred.
This was a precursor to the September 22, 1990,
event which was not recognized by the licensee.
Later on September 24, 1990, the licensee decided that it would be
appropriate to conduct the 2C SEC functional surveillance test in an
attempt to verify operability or identify potential problems.
During the
test, the accident loading input No. 1 again spuriously illuminated.
Since, by procedure, the SEC output was disconnected, no equipment
actuations occurred.
The SEC was immediately declared inoperable and a
unit shutdown was initiated in accordance with Technical Specification
(TS) requirements.
The NRC was properly notified of the initiation of
the shutdown in accordance with 10CFR50.72 reporting requirements.
Subsequent troubleshooting activities, an engineering evaluation and
discussions with the vendor postulated that a faulty SEC input relay
caused the accident loading signals.
The relay was replaced, the SEC was
satisfactorily retested, and the unit shutdown was terminated at 75%
power at 12:10 a.m. on September 25, 1990.
The licensee is continuing
efforts to develop additional periodic checks to confirm the cause of the
event and to detect relay degradation to prevent further similar
actuations.
The unit was then returned to full power.
The inspector concluded that, although a precursor on September 22, 1990,
was not properly evaluated and corrective actions for an ESF actuation
were not initiated in a timely manner, the SEC could have properly
actuated and performed its intended function if needed.
The failure
mechanism appeared to generate unnecessary input signals, however, an
actual signal to actuate the SEC would not have been inhibited.
Nevertheless, several problems were noted, including poor
intradepartmental and interdepartmental communication, ineffective review
of a completed surveillance procedure, and untimely initiation of
corrective actions for the September 22, 1990, ESF actuation.
These
10
concerns were discussed with the licensee.
The inspector will *closely
follow licensee activities in this regard.
G.
Reactor Coolant System (RCS) Spill During System Filling
On August 30, 1990, a minor reactor water spill onto the Unit 1
containment floor occurred while in Mode 5 (Cold Shutdown), during the
RCS fill and vent process.
The spill occurred because two reactor head
vent valves (1RC38 and 1RC39) were left open during the RCS fill
evolution.
A roving firewatch noticed the spill and immediately notified
the control room.
Approximately 70 gallons of water spilled and was then
drained into the containment sump.
The pressurizer level at the time of
the spill was approximately 90%.
The licensee generated an Incident
Report (IR) for this event.
The inspector reviewed Operating Department procedures II-1.3.6,
"Draining the RCS
11 and II-1.3.4, "Filling and Venting the RCS,
11 and the
IR.
Step 5.1.12 of procedure II-1.3.6 required the vent valves to be
open; however, neither procedure directed closure of the valves.
An
initial condition of the fill and vent procedure (Step 2.1.1) states that
a list should be generated of all components that are off-normal and that
they should be evaluated for their effects on normal system operation.
The licensee stated that these valves were on the generated list,
however, they were not properly evaluated by the operator.
The root
cause of this spill was oversight by the control room operator who failed
to thoroughly evaluate the off-normal
val~e report.
The procedural
weakness, the vent valves were not directed to be closed, was also a
contributing factor.
The licensee discussed this event with the operator
involved, and initiated a procedure change to add a step to procedure
II-1.3.4 to close the 1RC38 and 1RC39 vent valves.
The revision will be
completed prior to the next drain down condition.
The inspector
concluded that the licensee performed an adequate review of the spill,
and had no further questions at this time.
H.
Incident Reports
(Closed) Unresolved Item 50-272 and 311/90-81-05.
Incident Reports (!Rs)
were not written for several events which warranted such documentation
per procedure NA-AP-006, "Incident Report/Reportable Event Program and
Quality/Safety Concerns Reporting System".
The inspector reviewed the criteria listed in NA-AP-006 for writing
incident reports and also reviewed sample !Rs90-316 and 90-325.
The
procedure implies, although does not clearly specify, that !Rs should be
written for such events as the Boric Acid Transfer (BAT) pump
surveillance test failures noted by the Integrated Performance Assessment
Team (IPAT).
As stated in PSE&G 1s response to the IPAT findings, the
licensee believes that !Rs should have been written for these test
failures.
11
The IPAT stated that several instances of safety tagging error~ were not
documented in IRs.
The source of this information was apparently a
discussion with no specific examples provided.
As a result, neither
PSE&G nor the inspectors were able to specifically identify these safety
tagging errors.
Discussions with Operations personnel involved with the
tagging process indicated that they were aware of the incident reporting
system requirements for safety tagging errors and used the process as
designed.
Review of the IR logs indicated that over 600 IRs were written
at Salem station in the first eight (8) months of 1990 and about 1000 in
1989.
Further, these reports appeared to be properly screened for LER
reportability and event evaluation and follow-up.
No significant backlog
existed in the program.
No violation of NRC reporting requirements resulted from the lack of IRs
written on the BAT pump issues.
Correction of the BAT pump Inservice
Testing (IST) failures were adequately ensured by other programmatic
mechanisms exclusive of the incident reporting system.
Based on this
review, the inspectors concluded that the criteria for writing IRs are
sufficiently descriptive and encompassing to achieve the goals of the
system.
The system is clearly adequate as a screening tool for
identifying reportable incidents.
The incidents noted by the IPAT were
isolated incidents of personnel misund~rstanding the criteria for
incident reporting or the need for filing incidents reports.
The
inspectors concluded that this problem will be remedied as experience is
gained with using NA-AP-006 (implemented in mid 1989) and with continued
management emphasis on the program.
This unresolved item is considered
closed.
I.
Premature Tagging Release of Safety Equipment
On September 19, 1990, prior to post-maintenance testing, and while
personnel were inspecting the Unit 2 No. 22 containment fan cooling unit
(CFCU), tags were prematurely released, equipment was returned to
service, and the No. 22 CFCU was started.
Men working around the CFCU
motor were unaware that the motor was going to be started.
No one was
injured in the incident.
However, the incident could have resulted in
personnel 1nJury or equipment damage.
The licensee 1 s investigation
following the event found the sequence of events to be:
Maintenance Supervisor requested a temporary release of paperwork to
reduce technician heat stress and exposure.
Control Room operator called the maintenance supervisor to inform
him that they were releasing the tags.
Maintenance Supervisor told the operator not to start the CFCU until
he gave the authorization.
One of the test groups was setting up equipment in the switchgear
room to take data during the CFCU operational test. After they were
12
set up, this supervisor called the control room to tell them that
they were ready.
The operator believed that the above mentioned call was the
authorization to start the CFCU.
The fan was started.
A few minutes later, the operator received a phone call from an
electrician in containment informing that he was very close to the
CFCU when it was started.
Poor intra and interdepartment communication contributed to the event.
However, the root cause was attributed to the unauthorized release of the
tags on equipment that still had personnel working on it.
The release of
the tags left the CFCU ready to be started automatically at any time by
the associated Safeguard Equipment Control train.
The inspector
conducted an independent review of this event and concluded the root
cause to be a failure to follow Administrative Procedure No. 15 (AP-15),
11Safety Tagging Program.
11
This was complicated by the communication
problems between Operations, Maintenance and Testing personnel.
AP-15 states in section 7.3, "Temporary Tagging Release,
11 that the Job
Supervisor shall ensure all personnel ire clear of the equipment and the
work activity covered by the tagging has been suspended.
The failure of
the Job Supervisor to clear all personnel prior to requesting the
temporary tagging release is a licensee identified violation of AP-15,
and is not being cited because the criteria specified in Section V.G of
the Enforcement Policy were satisfied (NON 50-311/90-22-01).
J.
Licensed Operator Medical Records
On August 28, 1990, the inspector reviewed the medical records of four
Salem licensed reactor operators.
The licensee requires licensed
operators to take a physical exam every year.
The exams for 1989 and
1990 were reviewed and the inspector found that Form NRC-396,
"Certification of Medical Examination by Facility Licensee,
11 was filed as
required with the physical exams.
Part 55.21 of lOCFR states that the
licensee shall have a medical examination every two years and Part 55.23
states that Form NRC-396, shall be completed and signed by an authorized
representative of the facility licensee.
The inspector noted that the
medical records demonstrated that each operator reviewed was fit for
duty.
The inspector also noted the licensee to be conservative in their
approach of conducting an exam every year versus the required every two
years.
No deficiencies were identified.
2.2.2
A.
13
Hope Creek
High Pressure Coolant Injection System (HPCI) Inoperability Due to
Moisture in Lube Oil
On September 14, 1990, the licensee reported that the HPCI system had
been declared inoperable due to a high moisture content (0.04%) in the
(A similar event occurred on June 7, 1990 and is
discussed in Licensee Event Report 90-009-00.)
drained and the lube oil cooler was pressure tested in an attempt to
determine the source of the water.
The test was satisfactory, and no
obvious signs of leakage were detected.
There is no Technical Specification limit on HPCI lube oil moisture
content.
The licensee used a vendor (General Electric) recommended limit
of 0.01% moisture content.
The sump was filled with fresh oil, HPCI was
operated and another sample drawn and analyzed with a resulting moisture
content of 0.03%.
General Electric was consulted and recommended a
revised maximum limit of 0.2%.
A significant moisture content (10-20%)
could lead to swelling of the turbine oil filter and consequent flow
reduction.
The safety significance of this event was minimal because of
both the moisture content necessary to *cause filter degradation (10-20%)
and the fact that both the automatic depressurization (ADS) and reactor
core isolation cooling (RCIC) systems were operable while HPCI was out of
service.
The licensee changed their limit to 0.2% moisture and declared
HPCI operable on September 16, 1990.
The licensee plans to pursue
identification and correction of the source of leakage during the
upcoming refueling outage with technical assistance from the vendor's
systems group.
The inspector reviewed the licensee's actions and planned
activities and found them to be satisfactory.
B.
Drywell Unidentified Leak Rate
On September 4, 1990, following a power reduction during the previous
weekend for turbine control valve surveillances, shift personnel reported
that drywell unidentified leakage had increased from about 0.6 gallons
per minute (gpm) to approx1mately 1.0 gpm.
The leakage then decreased to
a constant rate of about 0.8 gpm.
The licensee's initial investigation
indicated a possible leak in the area of the
11 C
11 drywell cooler, although
the exact cause could not be identified.
Unidentified leakage increased
to 1.6 gpm over the weekend of September 22-23, 1990, following a power
reduction for control rod scram timing, then gradually decreased to a
constant value of 1.45 gpm.
An analysis of the drywell floor drain sump
water indicated that 25% of the contents was reactor coolant.
Further
investigation indicated that the source of leakage could be near the
11 8
11
reactor recirculation pump, but again the exact source could not be
determined.
At the close of this reporting period, drywell unidentified
leakage remained constant at about 1.5 gpm.
The inspector reviewed the leakage monitors, discussed the occurrence
14
with licensee personnel, and reviewed the appropriate Technical
Specifications.
The licensee demonstrated an appropriate safety
perspective with an aggressive investigation in attempting to identify
the leakage source.
The Technical Specification limit on unidentified
leakage is 5 gpm.
The licensee imposed administrative limits of 2.5 gpm
or a significant increasing trend by night order entry on September 5,
1990.
Additionally, the licensee has minimized the number of power
reductions as there appears to be a link between recirculation pump speed
and unidentified leakage.
Also, monitoring of recirculation pump seal
performance has been instituted whenever pump speed is changed.
The
inspector had no further questions at this time.
C.
Apparent Fuel Pin Leak
On September 25, 1990, at about 1:00 p.m., the Hope Creek control room
received high radiation alarms on the radwaste area exhaust and the
off-gas (OG) pre-treatment monitors.
An OG pre-treatment sample was
taken and revealed a noble gas level of about 14,000 microcuries per
second.
This was 4% of Technical Specification (TS) limit per TS 3.11.2.7 (330 millicuries per second).
The licensee did not initially
see any increase in the north or south plant vent radiation monitor.
After a few days the north plant vent monitor increased from 10 to 40
microcuries per second and the south plant vent monitor increased from
140 to 180 microcuries per second.
The OG stream is filtered and delayed
to allow for isotope decay.
The stream is then mixed with the plant vent
for further dilution.
General Electric and the corporate fuels group
were contacted and they believe these results to be indicative of a
pinhole leak in a single fuel .rod.
On Saturday, September 22, 1990, the
unit reduced power to 80% to perform scram time testing on 10% of the
control rods as required by TS.
The unit then returned to full power
using a new rod pattern and adhering to the power increase ramp rates.
By 8:00 a.m. on September 26, 1990, the OG pre-treatment radiation
monitor decreased and an OG sample pre-treatment indicated 3,000
microcuries per second.
By the end of the period (October 1, 1990), the
value had decreased to 1700 microcuries per second.
The licensee is
continuing to evaluate this situation and to take samples of reactor
water and gaseous release streams.
The inspector discussed this item with licensee engineers, operators and
management personnel.
The inspector also monitored the radiation
monitoring system (RM-11) for the affected process streams and area
monitors.
The inspector concluded that the licensee was aggressive in
their program for monitoring this apparent fuel pin leak.
3.
RADIOLOGICAL CONTROLS
3.1 Inspection Activities
PSE&G's conformance with the radiological protection program was verified
on a periodic basis.
These inspection activities were conducted in
accordance with NRC inspection procedures 71707 and 93702.
15
3.2
Inspection Findings and Review of Events
3.2.1
Salem
No noteworthy findings were identified.
3.2.2
Hope Creek
No noteworthy findings were identified.
4.
MAINTENANCE/SURVEILLANCE TESTING
4.1
Maintenance Inspection Activity
The inspectors observed selected maintenance activities on safety-related
equipment to ascertain that these activities were conducted in accordance
with approved_procedures, Technical Specifications, and appropriate
industrial codes and standards.
These inspections were conducted in
accordance with NRC inspection procedure 62703.
Portions of the following activities were observed by the inspector:
Unit
Salem 1
Salem 2
Salem 2
Salem 2
Salem 2
Hope Creek
Work Request (WR)/Order
(WO) or Procedure
Description
Various
14 Reactor Coolant Pump
Motor
Various
22 Containment Fan Coil
Unit Motor
Replace No. 23 Charging
Pump Room Cooler
Inspect/Repair Leaking
Service Water Component Cooling
Pump Room Cooler Valve
No.90-057
Various
11A
11 Safety Auxiliary
Cooling System Pump Replacement
The maintenance activities inspected were effective with respect to
meeting the safety objectives of the maintenance program.
However, as
discussed in other sections of this report, there were several examples
of improper communications, both within the Salem Maint~nance
organization and among other Salem station groups .
16
4.2 Surveillance Testing Inspection Activity
4.3
4.3.1
A.
The inspectors performed detailed technical procedure reviews, witnessed
in-progress surveillance testing, and reviewed compl~ted surveillance
packages.
The inspectors verified that the surveillance tests were
performed in accordance with Technical Specifications, approved
procedures, and NRC regulations.
These inspection activities were
conducted in accordance with NRC inspection procedure 61726.
The following surveillance tests were reviewed, with portions witnessed
by the inspector:
Unit
Procedure No.
Salem 1
SP(0)4.0.5-P-AP(13)
Salem 2
Hope Creek
HC.RE-ST.BF-OOl(Q)
Hope Creek
HC.OP-ST.AC-OOl(Q)
Hope Creek
HC.OP-ST.AC-002(Q)
Test
Inservice Testing -
Auxiliary Feed Pump Test
Reactor Trip Breaker
Semiannual Inspection,
Lubrication and Testing
Control Rod Drive Scram
Time Determination
Turbine Overspeed
Protection System Operability
Test (Weekly)
Turbine Overspeed
Protection and Bypass Valve
Verification (Monthly)
Except as discussed below, the surveillance testing activities inspected
were effective with respect to meeting the safety objectives of the
surveillance testing program.
Inspection Findings
Salem
Boric Acid Transfer (BAT) Pumps
(Closed) Unresolved Item 50-272 and 311/90-81-11, Inservice testing (IST)
deficiencies for the BAT pumps.
The Integrated Performance Assessment
Team (IPAT) team (NRC Inspection 50-272 and 311/90-81) identified an
instance where the No. 22 BAT pump apparently failed an IST test and had
fallen into the required action range.
However, the BAT pump system
engineer may have authorized acceptance of the pump test and lowered the
acceptance criteria for the pump.
Additionally, a concern was expressed
by the IPAT that the Salem units were being operated in an unanalyzed
condition because the BAT pumps were being accepted with less than the
pump manufacturer 1s data and the FSAR stated value.
17
The inspector reviewed the IST records for BAT pump Nos. 11, 12, 21 and
22 as well as the baseline data used since 1988.
The performance of the
BAT pumps has historically degraded at such a rate that trending of pump
performance was difficult.
In the particular.instance noted during the
IPAT, the inspector found that PSE&G had rebaselined the pump performance
curve to accept the BAT pump No. 22 performance test on February 8, 1990,
which was now in the acceptable range (re-baselined range) and subse-
quently returned the pump to operable status.
However, IST pump tests of
January 29, and February 1, 4, 7, 1990, were rejected due to the pump
failing to reach an acceptable flow rate at the required pressure.
The
inspector did note that the latter three of these four completed IST pump
test procedures were not maintained in the IST files, but rather were
located in the document control system with the maintenance work request
package.
This was the apparent source of a discrepancy noted between the
findings of the !PAT and a subsequent review of this matter by PSE&G, as
documented in their response to the IPAT findings and presented to NRC
Region I on August 15, 1990.
The inspector concluded that PSE&G did not accept BAT pump 22 with
performance in the alert range relative to the baseline standard (derived
as delineated in ASME Section XI) in place for that pump at that time.
Further, review of the design requirem~nts for these pumps also indicates
that the baselines established for all the BAT pumps, in all cases~ were
substantially above the minimum TS flow requirements of these pumps (10
gpm), although the inspector considered that flow rate technically
unacceptable as a performance requirement for pumps designed to produce
75 gpm, per the FSAR.
Thus, the plant was never operated in an
unanalyzed condition nor in violation of TS requirements.
The inspector also noted that ASME Section XI, Article IWP-3111, requires
that when new baseline standards for pumps are established following
modification and maintenance, a documented evaluation of the recorded
pump test reference values used for baselining, as compared to the pump
operational requirements, must be performed.
Further, 10CFR50.59
requires that changes to the plant or procedures, as described in the
FSAR, be evaluated and a written safety evaluation performed.
This
provides the bases for the determination that the change, test or
experiment does not involve an unresolved safety question.
No such
evaluations were documented for the change in pump performance
requirements needed to return the BAT 22 pump to service on February 8,
1990.
Further, no evidence was identified that such evaluations were
performed on any of the other BAT pump re-baselinings made in the past.
The failure to perform this 10CFR50.59 evaluation, which also serves to
satisfy the requirements of ASME Section XI, is a violation (VIO 50-272
and 50-311/90-22-02).
The inspector reviewed PSE&G
1 s response to the IPAT on this issue and
noted that PSE&G acknowledged the failure to perform 10CFR50.59 and ASME
Section XI evaluations of the re-baselining of the BAT pumps.
As a
result, 10 CFR 50.59 evaluation No. 272/311-90-81-Q060, dated May 25,
1990, was written to address this issue.
The evaluation provided the
18
basis for the 10 gpm flow requirement for the BAT pumps from TS
3/4.1.1.1, established an administrative low flow limit of 47.5 gpm at
235 ft. total dynamic head (TOH) for all BAT pump IST surveillances, and
justified an FSAR minimum flow value of 45 gpm at 235 ft. TOH (versus the
75 gpm presently listed).
The administrative limit of 47.5 gpm includes
a 45 to 46 gpm alert range and an action range below 45 gpm.
The
inspector reviewed the safety evaluation and found it to be technically
acceptable.
Technical Department procedure No. TI-28 was changed on June 29, 1990,
which provided additional guidance to system engineers for baselining
ASME Section XI pumps.
The procedural changes require 10CFR50.59
evaluations for pumps if they are going to be accepted below pump
operational design criteria or below the administrative limit.
Operations department procedures for boration activities were also
revised to incorporate the new FSAR low flow limit.
Additionally, all
other pumps in the IST program were reviewed to ensure that their most
recent !ST test results compared favorably to their design operational
requirements.
The inspector considered these corrective actions to be comprehensive
enough to address this matter.
As a result, no response to the Notice of
Violation on this issue is required.
Therefore, this unresolved item and
the violation are considered closed.
B.
Containment Liner Corrosion
(Open) Unresolved Item 50-272 and 311/90-81-21, Corrosion visible on the
liners of both containment buildings at Salem.
The inspector discussed this issue with the Manager - Civil Engineering.
PSE&G believes the cause of the corrosion noted by the Integrated
Performance Assessment Team (IPAT) was minor surface rusting caused by
service water spillage over the years.
However, in response to the IPAT
finding and recent NRC information regarding corrosion of steel
containment vessels (i.e. Information Notice 89-79 and Supplement 1 to
the Notice), PSE&G contracted Stone and Webster Engineering Corporation
(SWEC) to perform a study of the containment liner corrosion.
The
inspector reviewed SWEC 1 s draft report and found it technically adequate,
although the recommendations provided were non-specific with regard to
key elements of any inspection program (i.e. statistically representative
sampling sizes for liner thickness measurements).
The inspector did note
that the report stated that the containment liner was designed to be
protected by an installed cathodic protection system.
However, the SWEC
report did not recommend confirming the installation or operability of
this system.
Later discussions between the inspector and the system
engineer for the cathodic protection system determined that no such
system existed at either of the Salem units.
PSE&G immediately initiated
actions to follow-up on this finding at the conclusion of this
inspection .
19
PSE&G has not yet developed a containment liner inspection pro~ram from
the draft SWEC report.
However, PSE&G tentatively intends to develop and
implement an inspection program by the next refueling outage at either
Salem unit, currently scheduled for Unit 1 in February 1991.
This time
schedule is considered satisfactory in that indirect long-term
confirmation of containment liner adequacy via containment integrated
leak rate testing and visual inspection has never identified any
corrosion induced failure of the containment liner at either Salem unit.
The inspector considered PSE&G 1s actions to date in this matter
responsive to the NRC 1 s safety concerns.
This unresolved item will
remain open to allow for tracking the issue for NRC review of PSE&G 1 s
inspection findings for generic industry implication and to evaluate the
need for future regulatory action.
C.
Unit Shutdown During Surveillance Test Due to Inoperable Computer
On September 21, 1990, Unit 2 commenced a Technical Specification (TS)
required shutdown due to the inability to complete time response testing
of the
118
11 reactor trip breaker ( RTB).
During performance of the RTB
surveillance, the process computer (P-250) power supply failed, making
the P-250 inoperative.
The P-250 is used for RT8 time response
measurement, and its unavailability delayed completion of the
surveillance test.
The test began at 2:50 p.m.
The Action for the
applicable TS (No. 3.3.1 - Action 20) allows the
118
11 breaker to be in the
bypass position for up to two hours.
After the two hours expires, Mode 3
(Hot Standby) must be reached in the next six hours.
The licensee was in the process of pursuing the use of an alternative
device to measure the RT8 time response when the two hour time limitation
expired.
Then, at 5:51 p.m., a unit shutdown was initiated in accordance
with TS requirements.
This was reported to the NRC via the Emergency
Notification System in accordance with 10CFR50.72 reporting requirements.
A procedure change was subsequently processed, and the RT8 time response
measurements were taken using a calibrated chart recorder.
The unit
shutdown was terminated at 58% power and the TS Action Statement was
exited at 8:11 p.m.
A licensee Quality Assurance (QA) inspector was present during conduct of
the September 21, 1990, test.
On September 24, 1990, the QA inspector
identified and pursued several concerns related to the conduct of the
surveillance test.
There were two TS Action Statements applicable during
the surveillance test.
The procedure appropriately directed entry and
exit of those requirements.
However, the QA inspector identified that
due to apparent communication problems between operations and maintenance
personnel, TS Action Statements were inappropriately exited.
Specifically, TS Action Statement 3.3.2.1 was prematurely exited by
several minutes, and TS Action Statement 3.3.1 was exited and
subsequently re-entered (and restarted the time limit) when TSs should
not have been exited.
20
The resident inspector reviewed the QA findings and found them*to be
valid, although no TS violations resulted.
That is, if the TS Action
Statement were properly exited, no required actions would have been
necessary.
The inspector verified that these deficiencies are being
properly evaluated by the responsible station personnel.
The inspector concluded that the QA inspector properly identified,
evaluated and reported a potential safety concern that resulted from
interdepartmental communication deficiencies during surveillance testing.
The inspector will monitor the licensee 1s resolution of this issue during
a subsequent inspection.
D.
Inoperable Auxiliary Feedwater Pump
On September 24, 1990, the licensee conducted a monthly operability
surveillance test for the Unit 1 No. 13 turbine-driven auxiliary
feedwater (AFW) pump using surveillance test procedure No.
SP(0)4.0.5-AF(13),
11 Inservice Testing - AFW Pumps
11 *
After the pump was
started at 3:14 a.m. the terry turbine automatically tripped unexpectedly
at 3:18 a.m.
Prior to the trip, the turbine was experiencing speed
oscillations.
The pump was restarted at 3:35 a.m. and was tested.
successfully until it was manually shutdown at 5:03 a.m.
The
surveillance was documented as being satisfactorily completed .
The trip of the No. 13 AFW pump was discussed during the September 24,
1990 daily morning meeting.
The licensee suspected that the turbine may
have tripped because of excessive condensation accumulation in the steam
supply line, possibly due to a clogged orifice in the associated drain
line.
The inspector subsequently expressed concern that the AFW pump was
not declared inoperable following the turbine trip.
The licensee then
implemented actions to monitor temperatures in the turbine steam supply
line at selected locations to ascertain whether condensation was
accumulating and planned to conduct another surveillance test.
On September 25, 1990, the AFW surveillance test was started at 4:28
a.m., however, the turbine tripped at 4:32 a.m.
The pump was immediately
declared inoperable and the appropriate Technical Specification Action
Statement (TSAS) was entered.
Subsequent maintenance activities
identified that the orifice in the steam supply drain line was clogged,
in that deposits had accumulated on the orifice opening and debris (rust)
was found at the orifice flange.
The system engineer was also present,
and identified that the installed orifice assembly did not have the
required strainer (screen) on the upstream side.
On September 26, 1990, the inspector observed the installation of the
required orifice assembly, including the strainer.
Further inspector
review identified that a previous trip of No. 13 AFW pump during
surveillance testing occurred on February 11, 1990, as documented in
Incident Report (IR) No.90-115.
Corrective actions included cleaning
21
the orifice and replacing the orifice gaskets.
No additional formal
followup to IR 90-115 was performed.
The system engineer also identified that the Unit 2 AFW turbine-driven
pump (No. 23) uses a 1/8 inch orifice.
Unit 1 has a 0.03 inch orifice
(about 1/4 the size of the Unit 2 orifice).
The system engineer formally
requested that an engineering evaluation be performed to verify proper
orifice size.
AFW system differences were not identified when the Unit 1
strainer, installed initially via a 1981 modification, was removed.
The repairs to No. 13 AFW pump were completed and the pump was
satisfactorily retested on September 27, 1990, including pump response
time testing.
Slight adjustments were also made to the turbine governor.
The TSAS was properly exited on September 27, 1990, at 12:57 p.m.
Licensee corrective actions included implementing continued monitoring of
the steam supply line temperatures to ensure proper condensate drainage.
The inspector concluded that there was a similar previous event which may
not have been properly evaluated and investigated to the extent that
proper disposition may have precluded subsequent events from occurring.
The inspector also concluded that the failure to declare the No. 13 AFW
pump inoperable on September 24, 1990, was an error in licensed operator
judgement.
Specifically, although the surveillance procedure was
satisfactorily completed, additional information was available which
showed that pump performance and reliability were in question.
The
licensee agreed with this assessment and stated that Operations shift
supervisors will be briefed on management's expectations relative to
The inspector had no further questions at
this time.
E.
Inadvertent Main Steam Isolation Valve Closure During Surveillance Test
On August 19, 1990, during solid state protection system (SSPS) testing,
one of four main steam isolation valves (MSIVs) closed unexpectedly.
The
unit was critical at about 2% power.
The test is intended to close the
associated MSIV bypass valve and main steam drain line valve for that
loop, but should bypass the closure signal to the individual MSIVs.
Followup licensee review determined that due to a procedure deficiency
and inadequate communication the test equipment (voltage meter) was not
disconnected by the technician when the test switch was placed to the
"operate" position.
With the voltage meter still connected to the test
contacts, a low resistance path was provided, resulting in energization
of the relay that actuates the associated MSIV.
Inadequate
communications contributed to this event in that the operator did
not inform the technician prior to operating the test switch.
Normally,
the operator informs the technician prior to operating the test switch,
and the technician disconnects the voltage meter before the operator
proceeds with the test.
The licensee made the necessary procedure
enhancements to ensure that the meter is disconnected prior to actuating
the test circuit.
All remaining SSPS and MSIV isolation testing was
22
subsequently. performed satisfactorily.
This ESF actuation was reported
to the NRC in accordance with 10CFR50.72 reporting requirements.
The
inspector had no further questions.
F.
Surveillance Frequency Noncompliance Due to Personnel Error
On September 24, 1990, the licensee identified that they did not comply
with Technical Specification (TS) surveillance requirement 4.3.1.1.
Specifically, TS Table 4.3-1 requires that a channel functional test be
performed monthly for the safety injection input from the solid state
protection system (SSPS), howevBr, the licensee found that they have
historically performed that test once every 62 days on a staggered test
basis.
This discrepancy was identified during a TS verification audit,
being performed to ensure all TS surveillance requirements are met.
The licensee determined that the root cause of this event was personnel
error.
The licensee also determined that the staggered test basis
frequency for the above surveillance requirement is consistent with the
current Westinghouse Standard TSs.
Therefore, a TS change request has
been initiated.
Upon discovery of this event, the appropriate Unit 1 and 2 SSPS channels
were tested satisfactorily.
Therefore, the affected channels would have
properly performed their intended functions.
The surveillance procedure
frequency requirements were corrected to comply with the current 31 day
specification.
The inspector concluded that the appropriate corrective
action was completed by the licensee.
The licensee identified violation
of Technical Specifications is not being cited because the criteria of
Section V.G
of the Enforcement Policy were satisfied (NON
50-272/90-22-03).
G.
Reactor Trip Breaker Test Failures
On September 24, 1990, and October 1, 1990, the licensee informed the NRC
that the Unit 2 undervoltage trip atta~hment (UVTA) for reactor trip
breakers (RTBs)
118
11 and
11A
11 , respectively, failed the trip bar lift force
measurement test.
The failures were identified during the performance of
the semiannual RTB maintenance activity, which includes response time
testing, trip bar lift force measurements, and UVTA output force
measurements.
The trip bar lift force measurement test determines the excess margin
that the RTB overcomes to trip the breaker by adding weight to the trip
bar.
Following the failure of the
118
11 RTB on September 24, 1990, as
found conditions were determined.
The breaker tripped with 240 grams
added.
The acceptance criterion is greater than or equal to 460 grams.
Preventive maintenance activities were then completed in accordance with
procedure M3Q-2, however, post-maintenance testing also failed to meet
the 460 gram requirement.
The UVTA was subsequently replaced, and was
satisfactorily retested (700 grams) .
H.
23
When the
11A
11 RTB failed its 460 gram UVTA trip bar lift force measurement
test on October l, 1990, the licensee decided to replace the UVTA.
No
additional as-found testing was performed, and the post-repair testing
was successfully completed (640 grams).
The licensee attributed the
failure to obtain as-found data to be the result of ineffective
communication between Technical Department and Maintenance Department
personnel.
As documented in previous NRC inspectioh reports, the licensee had
identified an apparent marginal lot of UVTAs received at Salem.
Both of
the above mentioned installed UVTAs were from that lot.
The previous NRC
inspections had concluded that considerable margin remained to trip the
breakers based upon as-found testing results of at least 380 grams.
However, the as-found margin for the
11 B
11 RTB was only 240 grams and that
for the
11A
11 RTB was not determined ..
The existing Unit 1 and 2 Technical Specifications (Table 3.3-1) require
that the licensee immediately report to the NRC and prior to any repair
or maintenance any failure to meet the RTB or bypass RTB trip force
requirement.
The licensee recently received a Technical Specification
amendment (not yet implemented), which relaxed the Salem specific*
conservative reporting requirement to a 300 gram threshold for the trip
bar lift force measurement.
The licensee stated that procedures will be
changed to require as-found testing following initial test failure.
The inspector will continue to monitor licensee efforts in this area with
regard to potential UVTA problems.
Inservice Testing (IST) Program
(Open) Unresolved Item 50-272/89-11-06, failure to properly mark the
auxiliary feedwater (AFW) pumps for inservice testing (IST) vibration
probe placement.
The scope of this unresolved item will be expanded to
include all pumps in the !ST Program.
In response to previous NRC findings (Inspection Report No.
50-272/90-03), the licensee stated that by March 31, 1990, one-inch paint
marks would be provided to identify specific pump and motor vibration
measurement points.
In a memorandum dated May 8, 1990, Engineering
stated that they completed the program to mark the pumps for vibration
readings.
During this inspection period, the inspector visually checked
several of the pumps and found specific vibration markings missing.
The
inspector brought this to the attention of the responsible !ST program
engineer who stated that he had recently completed a check of the pumps
and was aware of the problem.
He also stated that the pumps had all been
marked, however since that time, maintenance work on charging and safety
injection pumps had removed selected markings.
The inspector concluded
that the initial actions taken were satisfactory.
However,
administrative controls to maintain the markings have been ineffective.
As a corrective action, procedure No. SP(O) 4.0.5-P-GEN,
11 Inservice
Testing Guidelines,
11 will be changed to instruct the operator p*erforming
the test to notify the appropriate personnel if any of the vibration
measurement markings are missing.
The operator is not to continue the
test until the markings have been reapplied. *
As a future action for the vibration readings, the licensee plans to
permanently.attach bayonet mounts to the pumps for the vibration probes,
however, they are currently investigating whether these mounts will
constitute a design/configuration change to the components.
This item
will remain open pending completion of the program to mark the IST pumps
for the vibration probe readings.
4.3.2
Hope Creek
A.
Technical Specification (TS) 4.0.5
8.
On August 13, 1990, the licensee identified that the
118
system spr~y wash pump had not. been iest~d for a re-baseline after
maintenance was performed in July 1990.
This condition constituted a
violation of Technical Specification (TS) 4.0.5 and ASME Section XI
criteria.
The licensee identified violation is not being cited because
the criteria specified in Section V.G. *of the Enforcement Policy were
satisfied (NON 50-354/90-16-02).
The root cause of the violation was identified as inadequate review of a
completed work order on July 6, 1990, by *a nuclear shift supervisor
(NSS).
The work order included maintenance activities for an oil flinger
ring adjustment and replacement of a new mechanical seal.
The NSS
thought that only the flinger ring was worked, and he deleted the retest
requirements as the ASME Code requires retesting if pump disassembly was
required, and the flinger ring adjustment could be made without
disassembly of the pump.
A retest performed on August 13, 1990, was
satisfactory as there were no significant deviations from the previous
baseline data.
The inspector reviewed the licensee event report (LER 90-13), the
incident report and the work order.
The inspector concluded that
was factual, and that licensee corrective actions were adequate.
inspector had no further questions at this time.
the LER
The
Reactor Core Isolation Cooling (RCIC) System Isolation During Testing
On August 21, 1990, the licensee reported than an emergency safety
feature (ESF) actuation signal had been received which shut the RCIC
system inboard steam isolation valve.
After determining the cause of the
isolation, the isolation logic was reset and the valve was reopened,
returning RCIC to its normal standby lineup.
The isolation was caused by
personnel error by Maintenance technicians performing a surveillance test
on the steam leak detection system circuitry associated with the RCIC
isolation valve.
The technicians failed to place a keylocked switch in
25
11 bypass 11 as required by the test procedure (IC-FT.SK-001, step -S;l.2).
Failure to follow the surveillance procedure is a licensee identified
violation and is not being cited because the criteria specified in
Section V.G of the Enforcement Policy were satisfied (NON
50-354/90-16~01).
The licensee 1s investigation determined this was an isolated event, and
the technicians involved were counseled with regard to job performance
expectations and the use of helpers during surveillance testing.
This
event was documented in Licensee Event Report (LER)90-015.
The
inspector reviewed the event, the LER, and discussed the event with
licensee personnel.
The licensee
1 s corrective actions appear to
adequately address the root cause of this event.
The inspector had no
further questions at this time.
4.3.3
Common Troubleshooting Activities
A.
The inspector reviewed administrative guidance and procedural controls
for troubleshooting activities at Salem and Hope Creek including:
Common
Salem
NA.AP.ZZ-13,
11 Control of Temporary Modifications
11
NA.AP.ZZ-9,
11Work Control Program 11
OD-15,
11 Use of Operations Department Procedures 11
MllE,
11Mechanical Equipment Troubleshooting and Repair
11
IC-GP.ZZ-006,
11Controls Equipment - Troubleshooting 11
Hope Creek
MD-GP.ZZ-008,
11 Equipment Troubleshooting
11
IC-GP.ZZ-008,
11Maintenance Troubleshooting 11
Based on this review, the recent Salem Unit 1 reactor trip on September
10, 1990, as discussed in section 2.2.l.C, and the findings from the
Salem and Hope Creek Maintenance Team Inspections (Report Nos. 50-272 and
311/90-200 and 50-354/90-80), the inspector concluded that there was
adequate programmatic guidance for troubleshooting and adequate
implementing procedures for maintenance personnel.
However, there were
no implementing procedures for Operations Department troubleshooting
activities.
The inspector discussed this item with licensee management
personnel and they concurred that this is a potential programmatic
weakness.
The inspector will review licensee efforts in this area during
future inspections.
26
5.
5.1
Inspection Activity
The inspector reviewed PSE&G's conformance with 10CFR50.47 regarding
implementation of the emergency plan and procedures.
In addition,
licensee event notifications and reporting requirements per 10CFR50.72
and 10CFR50.73 were reviewed.
5.2
Inspection Findings
No noteworthy findings were identified.
6.
SECURITY
6.1
Inspection-Activity
PSE&G's conformance with the security program was verified on a periodic
basis, including the adequacy of staffing, entry control, alarm stations,
and physical boundaries.
These inspection activities were conducted in
accordance with NRC inspection procedu~e 71707.
6.2
Inspection Findings
No noteworthy findings were identified.
7.
ENGINEERING/TECHNICAL SUPPORT
7.1
TMI Action Plan (TAP) Item Review
A.
Salem Reactor Vessel Head Vents (TAP Item II.B.1.2 and 3)
B .
The licensee completed modifications on both Salem units to add reactor
vessel head vents.
The design was approved in 1983.
The NRC inspected
the installation in NRC Inspections 50-272/84-08, 85-15, 86-01 and
311/84-08, 85-17, 85-20, 86-01.
The item remained open pending inspector
walkdown of the system, review of operating and emergency procedures, and
verification of Technical Specifications (TSs).
The inspector performed a walkdown of accessible portions of the system,
including control room switches and indicators.
The inspector
interviewed selected licensed operators to verify their knowledge, and
reviewed system operating and emergency operating procedures to verify
that the head vent valves were included.
The inspector also verified
that TS 3/4.4.12 addresses head vent valve operability, action statements
and surveillance requirements.
No unacceptable conditions were noted and
TAP Item II.8.1.2 and 3 are closed for Salem Units 1 and 2.
Hope Creek Control Room Habitability (TAP Item III.D.3.4.2)
Hope Creek Control Room Habitability (TAP Item III.0.3.4) Section
II.0.3.4 of NUREG-0737, "Clarification of TM! Action Plan Requirements,"
27
required the licensee to assure that control room operators would be
adequately protected against the effects of accidental release of toxic
and radioactive gases.
The item also required that the plant could be
safely operated and shutdown under design basis accident conditions.
The
licensee's submittals to the NRC in support of an application for an
operating license detailed the means by which the licensee proposed to
meet these requirements.
The NRC staff determined that the licensee had
demonstrated that the control room habitability systems would adequately
protect the operators and found the licensee in compliance with
NUREG-0737, TAP Item III.0.3.4 (see NUREG-1048, "Safety Evaluation Report
(SER) related to the operating of Hope Creek Generating Station", October
1984, Attachment 6.4).
A number of issues were not explicitly discussed in the SER.
However,
data was required by NUREG-0737 and the licensee included discussion of
and actions taken to address these in section 6.4 of the Updated Final
Safety Analysis Report (UFSAR).
These issues were reviewed by the
inspector as follows:
The licensee committed to having a minimum of a five day supply of
food and water for five persons available within the control room
envelope (as defined in Figure 6.4-1 of the UFSAR).
A locked
freezer is located in a dedicated storage area.
The freezer's
contents were noted to be in excess of the 75 meals (three meals/day
per person) required.
Additionally, a supply of fresh water is
provided (located in the same space as the freezer) from tank
00-T-411 which contains greater than 1000 gallons.
A check valve is
installed in the tank fill line to prevent draining the tank should
normal system pressure be lost.
The tank can be isolated from
exterior water sources and be pressurized by a small air compressor.
The freezer is completely restocked annually.
The inspector noted,
however, there was no formal program to assure an annual replacement
or to periodically verify the edibility of the frozen food.
Operations management immediately issued an order to obtain
replacement food annually.
A first aid kit for minor injuries is located in a second cabinet
across from the operator's ready room.
An additional first aid kit
and assorted bandages is located in the senior nuclear shift
supervisor's (SNSS) office.
The site also has a full-time emergency
medical team (EMT) for more significant injuries.
(KI) tablets are contained in the same cabinet as the first aid kit.
The cabinet's contents are inventoried quarterly and the KI tablets
are replaced if found to be within three months of their shelf life
expiration date.
The SNSS is authorized to obtain and issue the KI
tablets as provided in the Artificial Island Emergency Plan.
KI
tablets are also available at a variety of locations, including the
main radiological control point located just across the corridor
from the control room envelope.
28
At least eight sets of emergency breathing equipment are lncated in
the hallway next to the instructional viewing area (based on a
minimum of one extra set for every three sets needed to meet the
minimum capacity).
The equipment is inspected monthly for material
condition and functionality.
Because there are no toxic chemicals either stored on site or
located within five miles of the site, the licensee determined that
the requirements of Regulatory Guides 1.78 and 1.95 were not
applicable to Hope Creek.
While the control room outside air
intakes were located to minimize the possibility of various gases
entering the control room, exhaust gases from the emergency diesel
generators (EOG) could enter the control room via the air intakes
under certain circumstances.
The licensee's analysis of this issue
indicated a calculated maximum concentration of 1.6 ppm, well below
the limiting threshold value of 3.0 ppm (UFSAR Sections 6.4.4.2 and
6.4.7.1).
Consequently, operation of the EDGs would not compromise
The inspector discussed with a number of
operations personnel whether they noted diesel fumes when the EDGs
were running.
Several indicated that they had on occasion, but also
indicated the fumes had created no problems.
The fumes were far
more noticeable in the corridor outside the control room envelope .
Because no chlorine is stored onsite or within five miles of the
site boundary, the requirement to have a chlorine detection system
is not applicable to Hope Creek.
The analysis also included a
review of Delaware River traffic.
Hope Creek's Technical Specifications (TSs) included the requirement
that the control room emergency filtration system (CREF) be able to
pressurize the control room envelope to at least 1/8 inch wat~r
gauge, and would isolate by test signals with damper closure within
five seconds (TS 3/4.7.2).
Surveillance tests are in place to
verify system operability.
Based on this review, TAP Item III.D.3.4.2 is closed for Hope Creek.
7.2
Salem
A.
System Engineer Qualification and Performance
The Integrated Performance Assessment Team (!PAT) noted weaknesses in the
performance of Salem system engineers, specifically in the areas of: (1)
system knowledge, (2) lack of field presence, (3) lack of a questioning
attitude, and (4) lack of attention to detail.
These weaknesses were
categorized based on several examples of system engineer performance
noted by the !PAT.
To assess the apparent weaknesses in system engineer knowledge and
performance, the inspector reviewed the formal training and qualification
29
process for the engineers and interviewed and observed system engineers.
Specifically, the inspector reviewed training department procedure
TQ-TP.ZZ-909(Z),
11System Engineer Training,
11 which outlines the formal
classroom training and the qualification process for system engineers.
The program is designed to train degreed engineers to near the level of
senior reactor operators through a six month classroom and simulator
training effort.
The inspector reviewed the content of the training
program and found it to be comprehensive and reasonably challenging.
Frequent testing of the students in the program was required and
remedi~tion of individuals who failed portions of the program was
provided.
The process includes formal classroom and on-the-job training,
demonstrated working skills, and an oral board.
Discussions between the inspector and several of the system engineers
found the individuals to be knowledgeable of system/equipment design and
of system status.
No noteworthy performance-related issues were
identified with the engineers, although only a limited number of
activities were observed.
The inspector concluded that the system engineers received adequate
formal training to carry out their job responsibilities.
However,
performance problems may exist which the IPAT identified, but were not
evident to the inspector.
No examples of such problems were noted during
this inspection.
Evidence of management commitment to improved
performance was apparent.
The resident inspectors will continue to assess personnel performance in
the future as part of the normal inspection program and licensee event
reporting process, and will evaluate recurrent examples of poor
performance which affect plant safety.
No further review of this issue
is warranted at the present time.
Based upon the review condu~ted by the
inspectors, no significant deficiencies were identified in the training
program or qualification process for system engineers.
8.
Salem Safety Equipment Room Coolers
At 2:00 p.m. on September~. 1990, the licensee discovered a through-wall
leak in the service water system piping to the No. 12 charging pump room
cooler.
The piping failure consisted of an approximately 2 inch long
split in the pipe.
The unit entered a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Technical Specification
Action Statement (TSAS).
The licensee stated that the charging pump
operability could be restored prior to replacement of the failed piping
because the room cooler is not considered to be required for charging
pump operability.
The licensee isolated the leak and declared the No. 12
charging pump operable before the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> TSAS expired.
The inspector questioned the basis for the licensee's conclusion that the
room cooler was not needed for pump operability.
The licensee uses a TS
interpretation per Operations Procedure No. OD-12.
This procedure states
that the room coolers may be out of service for seven or 31 days
30
(depending on service water availability) without declaring the
respective pump(s) inoperable.
The 00-12 interpretation was based on an
engineering evaluation (SGS/M-F0-29) dated October 9, 1979.
The inspector reviewed FSAR Section 9.4.2 which states that these room
coolers, in conjunction with the auxiliary building air flows, limit
equipment area temperatures below the environmental qualification
requirements.
The referenced engineering evaluation was also reviewed by
the inspector, however, a sufficient basis for the interpretation was not
identified.
The inspector concluded that the basis for the 00~12 interpretation was
lacking sufficient detail.
The licensee concurred and stated that their
long term program to upgrade, revise and formally approve these
interpretations (Unresolved Item 50-272/89-27-03) is currently in
progress with all but four items completed.
The room cooler TS
interpretation is currently under final engineering review and is
scheduled for completion by early November 1990.
Until this room cooler evaluation is complete, the licensee stated that
they would not take room coolers out of service for scheduled
maintenance.
The inspector will continue to follow this area and this
item remains unresolved.
C.
Open Item Followup
1.
(Closed) Violation 50-272/89-11-03: Failure to complete an
10CFR50.59 safety evaluation to address the seismic impact
reactivity computer on adjacent safety related equipment.
reviewed the licensee's response and discussed the concern
reactor engineer.
adequate
of a portable
The inspector
with the
The reactivity computer racks have been removed from the Salem Unit 1 and
2 control rooms and will only be temporarily reinstalled for short time
durations (four days on the average) and controlled by procedures.
As
part of the control room redesign modification, the Unit 1 reactivity
computer will be permanently installed, wired and operable, prior to the
end of the next unit refueling outage.
The Unit 2 reactivity computer is
currently installed permanently in the control room, however, it is not
wired and operable.
This work will be completed prior to the end of the
next unit refueling outage.
This item is closed.
2.
(Closed) Unresolved Item 50-272/89-11-10: Orifices installed backwards in
the centrifugal charging pump injection lines.
Licensee investigation of
the event determined that the orifice configuration resulted in lower
indicated flow rates in the control room.
The root cause was determined
to be personnel error.
Through engineering calculations and discussions
with the pump manufacturer, the licensee determined the following:
31
The short period of operation during the test did not cause pump
damage, as verified by the pump manufacturer;
There was sufficient suction pressure available for all modes of
pump operation;
The*pump motors were sized to accommodate the increased flow rate;
and,
The increased load would not exceed the allowable 2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br />
continuous load rating of the emergency diesel generators.
The licensee concluded that the systems and components affected by the
reversed orifice plates would have performed their safety function if
required.
This event was detailed in Licensee Event Report No.89-020.
Corrective actions to prevent recurrence included the development of
Procedure No. MllY,
11 Flow Orifice Plate Removal and Installation,
11 which
includes areas for clear documentation of the maintenance work.
Also,
specific orifice installation/removal training for maintenance personnel
was conducted.
The inspector reviewed the licensee's event investigation
findings and the subsequent corrective actions and found them to
adequately address the concerns of this issue.
This item is closed .
7.3
Hope Creek
A.
Ultimate Heat Sink Design Deficiency
During an engineering evaluation of minimum station service water pump
performance, the licensee determined that the Technical Specification
(TS) limit of 90.5 degrees F was non-conservative.
This 90.5 degrees F
limit was established taking credit for station design margins in service
water pump flow rates and heat exchanger heat removal capability.
Normal
expected degradation of station service water pump performance would
result in potentially inadequate heat removal capabilities with river
temperatures greater than 85 degrees F.
Administrative limits and a TS
interpretation were established to define a maximum allowable service
water temperature of 85 degrees F.
The licensee made an ENS call to
report this to the NRC on August 17, 1990 at 8:45 a.m.
The inspector was also briefed by the licensee regarding this finding.
The inspector monitored the ENS call and verified licensee corrective
actions.
At the time of the report, river temperature was 79 degrees F.
The inspector also discussed this item with licensee engineering,
operations and management personnel.
The inspector reviewed LER 90-14,
dated September 14, 1990, regarding this event.
The licensee concluded
that river temperature was greater than 85 degrees F for a six hour
period on August 5, 1988, when it reached 86.8 degrees F.
A failure of one of the redundant loops of service water and safety
auxiliaries cooling systems combined with river temperature greater than
8.
8.1
A.
32
85 degrees F would result in being outside the design basis for a
offsite power and LOCA.
The licensee further concluded that this
condition would have been minimized because the plant would be in
hour TS Action Statement with these water systems out of service.
inspector had no further questions at this time.
SAFETY ASSESSMENT/QUALITY VERIFICATION
Waivers of Compliance
Hope Creek Emergency Diesel Generators (EDGs) Fuel Oil
loss of
a 12
The
On August 22, 1990, the Hope Creek chemistry department received test
results from a vendor indicating that a diesel fuel oil shipment
delivered on August 15, 1990, did not meet Technical Specification (TS)
test criteria.
PSE&G immediately sampled the fuel oil storage tank to
which the oil had been delivered and shipped the sample to the vendor for
testing to ensure that the tank 1s entire contents still met the required
criteria.
These test results were received on August 23, 1990, and the
results indicated that the fuel oil impurity level, as measured by
ASTM-02274-70, were within TS limits.
In discussing the test results
with the vendor, however, PSE&G learned that the vendor was, in fact, not
testing the fuel oil impurity level in accordance with ASTM-02274-70, as
required by the Hope Creek TSs.
PSE&G subsequently discovered that the
vendor had never performed the test per the specified standard and did
not possess the equipment to do so.
The licensee concluded that TS 4.8.1.1.2.f .2 had not been performed for any of the fuel oil that was in
storage and that the operability of all four EDGs was in question.
Consequently, the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> provision of TS 4.0.3 was placed into effect at
2:40 p.m. on August 23, 1990, when the missed surveillances were
discovered.
This action was subsequently reported in LER 90-16.
In order to maintain the EDGs in an operable status, TS 4.8.1.1.2.f.2 had
to be performed for all diesel fuel oil in storage.
The time required
for PSE&G to find new vendors capable of performing the required test and
for the test to be carried out was going to exceed the 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> allowed
by TS 4.0.3, so on August 24, 1990, PSE&G requested a NRC Regional Waiver
of Compliance allowing a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> extension of the TS.
Based on other
valid, satisfactory tests of the fuel oil, the NRC granted the 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />
extension to allow for completion of the diesel fuel oil testing.
All
diesel fuel oil was tested and found to be within TS limits on or by
August 25, 1990, with all EDGs subsequently deemed operable, and the TS
Action Statement was exited on the same day.
In response to the fuel oil incident, Hope Creek Station Quality
Assurance (QA) conducted a special investigation to determine the cause
of the fuel oil surveillance deficiencies and to review the
qualifications of the vendor who had been performing the fuel oil
analyses.
The investigation was concluded by the end of the inspection
period, and the inspector reviewed the report the investigation team had
B.
33
submitted to the Hope Creek General Manager.
The inspector found the
report to be open and complete.
The report thoroughly assessed the
performance of the vendor, Hope Creek Chemistry Department, PSE&G
Procurement QA, the PSE&G Research Lab, PSE&G.Purchasing Department and
the Hope Creek Station QA organization.
The investigation team concluded
that the responsibility to ensure compliance with the necessary Technical
Specification was not properly understood and that there was an apparent
lack of ownership on both PSE&G's and the vendor's part to ensure that
the contract requirements were adhered to.
Immediate corrective actions
taken by PSE&G included the suspension of the use of the original vendor
and the qualification of two new vendors to perform the diesel fuel oil
surveillances.
Longer term recommendations included the development of a
formal Nuclear Department diesel fuel oil program and a review of the
adequacy and currency of the TS 4.8.1.1.2.f .2 requirements.
The
inspector determined the corrective actions taken to be adequate and will
follow up on the recommendations in a future inspection report.
Hope Creek Safety Auxiliary Cooling System (SACS)
On September 26, 1990, condensation was observed on the surface of the
"A" SACS pump casing.
A one inch linear indication was found on the
pump's lower casing.
The pump, an ASME Class 3 component, was isolated
and tagged out of service for repairs.
The NRC was informed at 10:25
a.m.
The unit was placed in a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Technical Specification Action
Statement (TSAS 3.7.1.1), which would expire at 9:11 a.m. on September
29, 1990.
On September 27, 1990, after the "A" SACS pump had been
disassembled and the inside of the pump casing examined, the licensee
determined that replacing the pump casing would be more prudent than
attempting a weld repair.
A spare casing had already been staged in
close proximity to the "A" SACS pump.
By September 28, 1990, the pump
casing had been replaced and pump reassembly nearly completed, leaving
the final pump/motor alignment and baseline pump performance testing to
be accomplished.
Any delay encountered could have extended beyond the allowed 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> TSAS
time period.
The licensee, therefore, requested from the NRC a Waiver of
Compliance from TS 3.7.1.1 for a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period to provide sufficient
time margin for the alignment uncertainties.
The licensee submitted the
request on September 28, 1990, and telephone discussion was held among
licensee, NRC Region I and NRC NRR personnel.
The justification for the
Waiver was not thoroughly documented and the licensee submitted a
followup letter on September 29, 1990.
This second submittal addressed
these NRC concerns.
The NRC granted a Waiver of Compliance to expire at
9:11 a.m. September 30, 1990, subject to a number of conditions,
including establishing roving firewatches in areas containing "B" SACS
loop equipment, and conducting extensive shift turnover briefings
covering the realignment of emergency diesel generator and
filtration/ventilation cooling water in case of a loss of SACS.
Additionally, the Waiver would terminate immediately upon it being
- "
,,
34
determined that any redundant emergency core cooling equipment was
The unit exited the TSAS and associated Waive~ at 3:55 p.m. on September
29, 1990, when the
11A
11 SACS pump was restored to an operable status.
The
inspector reviewed the licensee 1s actions relative to the conditions of
the Waiver and found them to be adequate.
Shift personnel were cognizant
of the additional actions imposed by the Waiver and they exhibited a good
safety perspective.
C.
Salem Number 22 Containment Fan Coil Unit (CFCU)
The licensee requested an NRC Regional Waiver of Compliance in a letter
dated September 17, 1990.
The No. 22 CFCU motor had failed on low speed
at 1:40 p.m. on September 11, 1990.
This placed Unit 2 in a seven day
Technical Specification Action Statement (TSAS) because the low speed
function mitigates the post-accident containment pressure rise.
The
licensee requested a waiver.
The .failure mechanism had been well under-
stood by the licensee and corrective actions to replace all of these
motors were underway.
The waiver was requested to prevent a shutdown of
the unit because replacement of the motor inside containment would exceed the
7-day TSAS.
NRC Region I granted a wafver to extend the TSAS for an
additional six days until September 24, 1990.
This was justified because
redundant equipment was available to mitigate an accident during this
period.
The inspector reviewed the submittal, the work in progress, and the TSAS,
and discussed this ~tern with licensee maintenance and management
personnel.
The inspector *verified that the _specific provisions of the
Waiver of Compliance were adequately followed.
The 22 CFCU motor was
replaced, repaired,. tested and declared operable.
The TSAS was exited on
September 20, 1990.
8.2 Salem
A.
Reactor Protection System (RPS) Setpoint Changes and License Change
Request
On September 4, 1990, PSE&G submitted a request, License Change Request
(LCR) 89-05, for an amendment of Facility Operating Licenses DPR-70 and
DPR-75 for Salem Unit 1 and Unit 2, respectively.
The proposed amendment
would modify Technical Specification Section 2.2, Table 2-2.1 and Section
3/4.3.2, Table 3.3-4, and incotporate new trip setpoints for steam
generator water level low-low and steam line pressure low.
The steam
generator water level low-low setpoint would be raised from 8.5% to 16%,
and the steam line pressure low setpoint would be raised from 500 psig to
600 psig.
The new, more conservative setpoints were derived as a result of a review
of all RPS instrument loops by Westinghouse.
This review was initiated
by PSE&G to ensure existing setpoints were conservative in order to
satisfy an NRC concern stemming from PSE&G
1s 1986 request to allow the
removal of the Salem reactor coolant system resistance temperature
.,
B.
35
detector bypass manifolds.
When the setpoints were reviewed with the
latest Westinghouse setpoint methodology, the only two setpoints shown to
be non-conservative were the steam generator water level low-low and
steam line pressure low setpoints.
The results from Westinghouse were
received by PSE&G in May 1989, and the setpoint changes were necessitated
by uncertainties that had been added by replacement transmitters and the
one hour harsh environment criteria which had been imposed by NUREG 0588.
While plans were being developed to implement the new setpoints, PSE&G
completed an engineering evaluation in May 1989, to justify operation
with the old setpoints.
The inspector reviewed the evaluation for both
setpoints and determined both were adequate and complete in their
analysis and justification of the existing values.
The licensee
subsequently prepared Design Change Packages (DCP lSC-2241 and 2SC-2241)
for implementing the new setpoints, which was accomplished in November
1989.
The inspector also reviewed the DCPs, found them satisfactory, and
determined that a license change was not required to change the setpoints
to the higher, more conservative valves since the Salem Technical
Specifications only required that the setpoints be
11 greater than or equal
to
11 8.5% and 500 psig, respectively.
Licensee management explained to
the inspector that the LCR was not submitted until this past September
due to the LCR essentially being an administrative task and other Salem
projects having a higher safety significant priority.
The inspector
noted that LCR 89-05 was complete and accurate, and had no further
questions concerning the RPS setpoint changes.
Station Qualified Reviewer
(Closed) Unresolved Item (50-272 and 311/90-81-16),
Station Qualified
Reviewer (SQR) independence for procedure change reviews was not
maintained as specified in Technical Specification (TS) 6.5.3.2.a.
The inspector reviewed and discussed the IPAT findings and the applicable
station procedures with PSE&G to determine if the second review for
procedure changes was independent. This review determined that an
independent SQR technical review had not been maintained in all
instances.
For example, a January 9, 1990, change to procedure
SP(0)4.0.5-P-RH-12,
11 Inservice Testing -
RHR,
11 did not receive an
independent review.
The failure to perform independent reviews is
considered to be another example of a violation of TS Section 6.5.3.2.a,
and of 10CFR50.59 as discussed in section 4.3.1.A of this report (VIO
50-272 and 50-311/90-22-02).
Discussions with the licensee indicated that their review confirmed that
an independent SQR technical review had not been maintained for certain
reviews. After the IPAT inspection, PSE&G issued additional guidance to
station personnel to re-emphasize the importance of assuring that an
independent SQR technical review was performed as required by TSs .
..
36
On November 1, 1990, PSE&G is scheduled to begin implementation of
station procedures that will apply to both facilities.
AP-32,
11 Implementing Procedures Program,
11 will be replaced with a new procedure
NC.NA-AP-ZZ-32 (NA-AP-32),
11 Preparation, Review and Approval of
Procedures.
The inspector reviewed the current guidance for station
personnel and the new procedure NA-AP-32 to ensure that PSE&G adequately
addressed the concern.
As an interim measure until the new procedure is
issued, a memorandum was issued to station personnel which described the
methodology to be used to ensure that an independent technical review is
maintained.
Based on the above corrective action, the inspector
considered the unresolved item and the violation closed.
C.
Misapplication of 10CFR50.59
(Open) Unresolved Item 50-272 and 311/90-81-23:
The NRC identified
examples of misapplication of 10CFR50.59 requirements.
For example, a
10CFR50.59 safety evaluation was used to justify the installation of a
non-code repair.
In another case, a required 10CFR50.59 safety
evaluation was not performed when an eroded containment fan coil unit was
repaired through the use of Belzona
11 R
11 metal.
Additionally, station
management displayed an unfamiliarity with 10CFR50.59 requirements, and
Administrative Procedure AP-32,
11 Implenienting Procedures Program, 11
contained erroneous information with respect to 10CFR50.59.
To assess the licensee 10CFR50.59 safety evaluation process, a review of
the applicable procedures was performed.
Presently, Salem Generating
Station Administrative Procedure (AP) 32, Revision 4,
11 Implementing
Procedure Program
111 and DE-AP-ZZ-008,
11 10CFR50.59 Reviews and Safety
Evaluations
11 are the two procedures that govern procedure changes.
AP-32
has been revised since the IPAT inspection and now refers to DE-AP-ZZ-008
for guidance on performing safety evaluations.
By November 1, 1990,
AP-32 will undergo a major revision.
That revised procedure (No.
NA-AP-ZZ-32), along with
NC.NA-AP-ZZ-0059 (NA-AP-59)
11 10CFR50.59 Reviews
and Safety Evaluations,
11 will govern the process associated with
implementing procedures and 10CFR50.59, safety evaluations, replacing
AP-32 and DE-AP-ZZ-008.
One of the significant changes in the PSE&G program has been to eliminate
the use of the Significant Safety Issue screening processing.
A
10CFR50.59 applicability screening process will be used. This approach
will involve answering the following three questions:
Does this make changes to the facility as described in the Safety
Analysis Report (SAR)?
Does this make changes to procedures as described in the SAR?
Does this result in the conduct of tests or experiments not
described in the SAR?
37
If the screening process, which includes a second independent reviewer,
concludes that all three questions can be answered no, the facility or
procedure change may be issued for use.
If any of the answers to the
three questions is yes, a safety evaluation a~ curr~ntly defined in
DE-AP-ZZ-008 must be performed.
Although this process conforms with
10CFR50.59 as noted below, the inspector questioned the licensee's
philosophy of answering the above three questions.
All completed safety
evaluations are required to be reviewed by the Station Operations Review
Committee (SORC) prior to issuance of the procedure.
With respect to plant modifications, the same logic as described above is
applied, however, all modification packages, regardless of its 10CFR50.59
applicability, must go to SORC prior to implementation.
Specific to
temporary modifications (T-MODs), the same screening process is also
applied, along with a second independent review.
The inspector reviewed and discussed the !PAT findings and applicable
station procedures with the licensee to determine if misapplication of
10CFR50.59 requirements occurred.
For the 10CFR50.59 safety evaluation
used to justify the installation of a non-code repair and in another
case, for an eroded containment fan coil unit repaired through the use of
Belzona
11 R
11 metal, the inspector determined that a misapplication of the
safety evaluation process had occurred. The failure to perform a proper
safety evaluation is a violation of lOCFR part 50.59 requirements and
another example of a previous violation (Section 4.3.1.A) (VIO 50-272 and
50-311/90-22-02).
On June 15, 1990, the NRC issued Generic Letter 90-05 that addressed
non-code repairs.
Based on this guidance, the inspector determined that
the appropriate people in PSE&G understand the requirement of how to
perform non-code repairs.
Additionally, the inspector reviewed the
applicable station procedures that were in effect at the time of the !PAT
inspection.
The inspector determined that Attachment 6 of AP-32,
contained conflicting guidance with respect to 10CFR50.59 and
DE-AP-ZZ-008.
Subsequent to the IPAT inspection, AP-32 has been revised
by the removal of Attachment 6, the inspectors considered the .issue to be
resolved.
The inspector determined that the licensee's process to comply with
10CFR50.59 .is adequate.
However, for PSE&G to implement th~ process
correctly, all employees involved with safety evaluations must understand
how to interpret and answer the questions correctly.
The inspector reviewed and discussed the examples stated in IPAT with
PSE&G management and engineering personnel.
From these discussions, the
inspector found that the licensee approach and philosophy on how to answer
the screening question was not as conservative (i.e. too narrow in scope)
as it should be.
Thus, it allowed/and would allow certain activities to
occur at the facility without a safety evaluation and the associated SORC
review being performed.
The licensee allows the reviewer to answer the
questions in the negative if in his view the safety evaluation concludes
- -
38
that no unreviewed safety question exists, whether or not a change to the
SAR was made.
The conceptual difference is being referred to regional
management for possible further discussions, if warranted.
This item
remains unresolved.
D.
Misapplication of Safety Significant Issue (SSI)
(Closed) Unresolved Item (50-272 and 311/90-81-17), Misapplication of
significant safety issues as specified in TS 6.5.1.6.a.
A review of the applicable procedures was performed.
Presently, Salem
Generation Station Administrative Procedures (AP) 32 and DE-AP.ZZ-008,
11 10CFR50.59 Reviews and Safety Evaluations,
11 are the two procedures that
govern procedure changes.
AP-32 has been revised since the IPAT
inspection.
Procedures NC.NA-AP-ZZ-0032 (NA-AP-32),
11 Preparation, Review
and Approval of Procedures,
11 and NC.NA-AP-ZZ-0059 (NA-AP-59)
11 10CFR50.59
Reviews and Safety Evaluations,
11 are to be implemented on November 1,
1990, and will govern the processes associated with implementing
procedures and 10 CFR 50.59 safety evaluations replacing AP-32 and
One of the significant changes in the PSE&G program has been
to eliminate the use of the Safety Significant Issue screening process
and to substitute a 10CFR50.59 applicability screening process.
The inspector reviewed and discussed the !PAT findings with PSE&G to
determine if misapplication of the safety significant issue (SS!) process
occurred.
The inspector determined instinces where procedure changes
involving safety significant issues were implemented through the SQR
process instead of receiving SORC review and approval, as specified in TS 6.5.1.6.a.
For example, procedure OP-ST.SJ-0013(Q) was revised on May
20, 1990, to include additional acceptance criteria and no SS!
determination was made.
The failure to perform a SSI determination in
accordance with these Technical Specifications 6.5.1.6a is considered a
violation of 10 CFR part 50.59 requirements and another example of the
previous violation as discussed in section 4.3.1.A (50-272 and
50-311/90-22-02).
However, based on the review of the new program which eliminated the use
of SS! determination as a screening factor, the inspector considered the
issue resolved and closed.
E.
Personnel Errors and Communications
During the period several personnel errors occurred.
Poor communications
between departments and within departments was also noted on several
occasions.
Examples included failure to follow testing and
administrative procedures by Operations, poor judgement by Operations in
assessing equipment operability, and poor communications exhibited by
Maintenance during review of equipment testing abnormalities.
The
39
licensee adequately addressed each of these issues and their
effectiveness will be monitored in future inspections.
F.
Management Involvement
Salem management was noted as being aggressively involved in safe
operation of the facility as demonstrated by the recent initiation of a
Daily Management Summary Report.
This report is discussed daily at the
9:30 a.m. management meeting.
Items addressed in this report (and at the
meeting) included unit status and schedules, open issues, and selected
projects status.
This appears to be an effective mechanism to assure
management
1s continued involvement.
8.3
Hope Creek
A.
Personnel Errors
B.
Two personnel errors were identified by the licensee.
One was caused by
a maintenance technician during surveillance testing that resulted in an
isolation of the reactor core isolation cooling system.
The other was
caused by a senior reactor operator that resulted in a missed re-baseline
of a service water spray wash pump as required by ASME Section XI.
The
licensee was aggressive in identification of the errors, and in
corrective actions.
Management Involvement
Hope Creek management was noted as being aggressively involved in safe
operation of the facility as demonstrated by aggressive pursuit for the
causes of and the corrective actions for a higher than normal
unidentified drywell leak rate, and for a small fuel pin hole leak.
However, weaknesses were identified with the completeness of the
technical information and the related safety basis for the safety
auxiliary cooling system waiver of compliance.
9.
LICENSEE EVENT REPORTS (LERs), PERIODIC AND SPECIAL REPORTS, AND OPEN ITEM
FOLLOWUP
9.1
LERs and Reports
PSE&G submitted the following licensee event reports and, periodic
reports, which were reviewed for accuracy and the adequacy of the
evaluation:
Salem and Hope Creek Monthly Operating Reports for August and September
1990 .
,,
40
Salem LERs
Unit 1
LER 90-29 (See section 2.2.1.A of this report)
LER 90-30 (See section 2.2.1.C of this report)
Unit 2
LER 90-34 (See section 4.3.1.E of this report)
LER 90-35 (See section 4. 3 .1. F of this report)
LER 90-36 (See section 2.2.1.B of this report)
Hoee Creek LERs
LER 90-12 concerns an entry into TS 3.0.3 on August 11,
1990.
This event was reviewed in NRC Inspection 50-354/90-14.
No inadequacies were noted relative to this LER.
LER 90-13 (See section 4.3.2.A of this report)
LER 90-14 (See section 7.3.A of this report)
LER 90-15 (See section 4.3.2.B of this report)
LER 90-16 (See section 8.1.A of this report)
9.2 Deen Items
The following previous inspection items were followed up during this
inspection and are tabulated below for cross reference purposes.
Site
Salem
272/89-27-03
272/89-11-03
272/89-11-10
272/311/90-81-05
272/311/90-81-11
272/311/90-81-21
272/311/90-81-16
272/311/90-81-17
272/311/90-81-23
272/311/90-22-02
Section
7.2.B
7.2.C
7.2.C
2.2.1.H
4.3.1.A
4.3.1.B
8.2.B
8.2.D
8.2.C
2.2.1.H
8.2.B, C, D
Status
Open
Closed
Closed
Closed
Closed
Open
Closed
Closed
Open
Closed
~ j '
Hope Creek
354/90-16-01
354/90-16-02
10.
EXIT INTERVIEW
10.1 Resident
4.3.2.A
4.3.3.B
41
Closed
Closed
The inspectors met with Mr. S. LaBruna and Mr. C. P. Johnson and other
PSE&G personnel periodically and at the end of the inspection report
period to summarize the scope and findings of their inspection
activities.
Based on Region I review and discussions with PSE&G, it was determined
that this report does not contain information subject to 10CFR2
restrictions.
10.2 Specialist
Date(s)
9/25-28/90
Subject
Security
Inspection
Report No.
272 '311/90-23
354/90-19
Reporting
Inspector
Dexter