ML18094A320
| ML18094A320 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 03/29/1989 |
| From: | Swetland P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18094A317 | List: |
| References | |
| 50-272-89-01, 50-272-89-1, 50-311-89-01, 50-311-89-1, NUDOCS 8904130148 | |
| Download: ML18094A320 (22) | |
See also: IR 05000272/1989001
Text
Report No.
.License
Licensee:
Facility:
Dates:
Inspectors:
Approved:
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
50-272/89-01
50-311/89-01
DRP-70
DRP-75
Public Service Electric and Gas Company
P. 0. Box 236
Hancocks Bridge, New Jersey 08038
Salem Nuclear Generating Station - Units 1 and 2
January 31, 1989 - March 20, 1989
Kathy Halvey Gibson, Senior Resident Inspector
Noel F. Dudley, Project Engineer
Steve M. Pindale, Resident Inspector
Peter W. Kelley, Resident Inspector
Specialist
P. D. Swetland, Chief, Projects Section 2B
Inspection Summary:
Inspection 50-272/89-01; 311/89-01 on January 31, 1989 - March 20, 1989
Areas Inspected:
Resident safety inspection of the following areas:
operations, radiological controls, surveillance testing, maintenance,
emergency preparedness, security, engineering/technical support, safety
assessment/assurance of quality, and review of licensee event reports.
Results:
Two violations were identified during the report period involving 3
examples of failure to follow procedures which resulted in inadvertent safety
system actuation (paragraph 2) and the failure to correct or prevent
,
recurrence of licensee identified nonconformances with regard to material
control (paragraph 8).
~904130148 890329
ADOCK 05000272
Q
1.
DETAILS
SUMMARY OF OPERATIONS
Unit 1 operated at 100% power until February 6, 1989, when the reactor
tripped during performance of a surveillance test.
The unit returned to
power operations on February 8.
On February 15, 1989, a controlled
shutdown was commenced to effect repairs to a component cooling water
leak inside containment.
On February 18, 1989, with the unit critical at
lOE-8 amps, the reactor tripped as a result of an error made during
surveillance testing.
The unit returned to power on February 18, 1989
and remained at full power for the remainder of the inspection period.
Unit 2 operated at 100% power until February 5, 1989, when the reactor
tripped due to loss of both steam generator feedpumps.
The unit returned
to service on February 8.
On March 3, 1989, discretionary enforcement
was granted by the NRC to extend the Technical Specification Action
Statement time limit for containment spray header inoperability for the
licensee to replace a leaking spool piece on No. 21 CS header.
The CS
header was returned to service on March 7, 1989.
On March 12, 1989 a
reactor trip and safety injection ~ccur~ed as a result of the failure of
10 vital instrument bus.
The unit returned to service on March 13, 1989.
2.
OPERATIONS
(71707, 93702)
2.1
Inspection Activities
On a daily basis throughout the report period, the inspectors verified
that the facility was 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
facility, interviews and discussions with personnel, independent
verification of safety system status and Limiting Conditions for
Operation, and review of facility records.
These inspection activities
were conducted in accordance with NRC inspection procedure 71707.
The
inspectors performed 334 hours0.00387 days <br />0.0928 hours <br />5.522487e-4 weeks <br />1.27087e-4 months <br /> of normal and backshift inspection
including deep backshift and weekend tours of the facility on February 10
(9:30 p.m.-2:30 a.m.), March 5 (6:30 a.m.-1:30 p.m.), March 12 (9:30
a.m.-10:30 a.m.).
2.2 Inspection Findings and Significant Plant Events
2.2.1
A.
Un-it 1
On February 6, 1989, during performance of a channel functional
test on No. 14 steam generator (SG) steam pressure channel I,
the reactor tripped due to No. 14 SG steam flow - feed flow
mismatch coincident with low SG level. Plant systems responded
to the trip as designed and the unit was stabilized in Mode 3
(hot shutdown).
On February 8, 1989 the unit returned to power
operation.
8.
2
Steam flow for each SG is sensed by two steam flow channels
which are density compensated utilizing the electrical signal
from corresponding steam pressure channels.
Either of the two
compensated steam flow channels for each SG may be selected by
the reactor operator (RO) for input to the SG water level control
circuitry.
In performing the functional test, the I&C technician
engaged the test switch upon which the corresponding steam flow
signal decreased to zero causing the SG water level control
circuitry to respond closing No. 14 SG feedwater control valve
(14BF19) which reduced feedwater flow to No. 14 SG.
The low
feedwater flow resulted in No. 14 SG reaching the low level
setpoint (25%) and the steam flow - feed flow mismatch signal
since the steam flow bistable had been tripped making up the
input to the reactor protection system.
Licensee investigation
determined that in preparing to perform the functional test, the
channel I steam flow bistable had been tripped, however the RO
at the controls failed to switch to the alternate steam flow
channel (II) in accordance with procedures.
The inspector reviewed the I&C surveillance procedure, No. 14
SG Steam Pressure Channel Functional Test, discussed the event
with operations personnel and determined that failure to switch
to the alternate steam flow channel constitutes an apparent
violation of T.S. 6.8.1 in that surveillance test procedures
for safety systems were not followed.
(50-272/89-01-01)
On February 7, 1989, the licensee performed a surveillance test
on the reactor coolant pump breaker status indication to the
The surveillance for Nos. 11 and 12
RCP 1 s were completed satisfactorily.
However, prior to
restarting No. 13 RCP and contrary to test procedure
SP(0)4.3.l.l.l,
11 Reactor Coolant Pump.Breaker Status
Indication", the reactor operator (RO) failed to defeat the
second level undervoltage (UV) protective relay for C vital
bus.
Defeating the UV relays is required prior to starting
each RCP and is accomplished by pres.sing 3 pushbuttons 1 ocated
on the control room console, one for each vital bus.
The
relays for A and B vital buses were defeated.
As a result of
the UV relay defeat for C vital bus not being energized, when
No. 13 RCP was started, voltage decreased to the 91.6% relay
setpoint and the C vital bus loads were stripped.
No. lC
emergency diesel generator automatically started and closed on
the bus and the blackout loads were then sequenced on to the
bus.
AOP-ELEC.4KV-C
11 Loss of lC 4KV Vital Bus
11 was entered and
C vital bus was restored to normal.
Related systems responded
as designed and this event had no adverse affect on the unit
which was in Mode 3 (hot shutdown).
The inspector r~viewed the
AOP, discussed the event with operations personnel and
determined that this second instance of failure to follow
c.
D.
3
procedures for surveillance procedure "Reactor Coolant Pump
Breaker Status Indication
11 is an apparent violation of T.S.
6.8.1. (50-272/89-01-01)
On February 15, 1989, the licensee commenced a controlled
shutdown from 100% power as a result of a component cooling
water (CCW) leak inside containment.
The leak occurred as
maintenance workers were attempting to tighten a leaking pipe
cap on CCW drain valve 13CC293.
Valve 13CC293 is connected to
the CCW supply to No. 13 reactor coolant pump (RCP).
The drain
piping and valve are 3/4 inch in diameter and the drain line is
unisolable without securing CCW to the RCP.
As the pipe cap
was tightened, the valve sheared off. A plant shutdown was
initiated to facilitate isolation of the leak.
During the
shutdown, makeup was continuously supplied to the CCW system.
Approximately 30,000 gallons of CCW was spilled from the CCW
system to the containment sump.
After the unit was removed
from service, No. 13 RCP was secured, the leak was isolated and
the drain line repaired.
Several maintenance workers were wetted with CCW which contains
potassium chromate.
The workers have undergone medical review
with no adverse results identified.
The licensee hosed down
the affected areas with water to flush the chromated water from*
the floor and piping to the containment sump.
The leakage and
flush water were transferred to the waste holdup tanks (WHUT).
The WHUT is being processed by a vendor using demineralization.
The inspector had no further questions concerning this event.
On February 18, 1989 with the unit critical at lOE-8 amps, the
reactor tripped as a result of an error made during
surveillance testing.
During the performance of procedure
l!C-2.6.025 "lPT-506 First Stage Turbine Impulse Pressure" the
instrument and controls (I&C) technician did not properly
verify by status panel indication that the turbine was latched.
Since the surveillance was attempted with the turbine
unlatched, when the P-7 bistable was tripped as part of the
surveillance procedure, the Reactor Protection System sensed
reactor power greater than 10% with the turbine tripped and
caused a reactor trip. All equipment responded as designed to
the trip.
The inspector reviewed the surveillance procedure
and discussed the event with I&C and operations personnel.
An
instrument and controls technician failed to verify the proper
status of reactor protection system panel lights for turbine
stop valves closed and turbine low oil pressure as specified in
procedure l!C-2. 6*. 025
11 lPT-506 First Stage Turbine Impulse
Pressure' 1 *
The inspector is concerned that the technician
continued with the procedure after recognizing that procedural
instructions were not met and did not consult with the
supervisor and/or operations personnel.
This third instance of
2.2.2
A.
4
failure to properly implement surveillance procedures is an
apparent violation of T.S. 6.8.1 (50-272/89-01-01).
The unit
returned to power on February 19, 1989.
Unit 2
On February 5, 1989, after removing Nos. 23A and 238 circulators
from service for condenser cleaning and circulator repair, No.
22 steam generator feed pump (SGFP) tripped due to low suction
pressure and caused a reactor trip resulting from No. 23 SG
steam flow - feed flow mismatch coincident with low SG level.
Plant systems responded as designed to the trip and the unit was
stabilized in Mode 3.
The inspector discussed the circumstances surrounding the.trip
with operations and engineering personnel and determined the
following.
With both No. 23 condenser circulators and No. 23
heater drain pump out of service, steam flashing occurred in
No. 23 hotwell which caused some cavitation in No. 23
condensate pump and' low suction pressure to the SGFPs ..
In
addition, the licensee determined that the non-safety related
suction pressure trip mechanism for No. 22 SGFP was
electrically degraded such that the as-found trip setpoint was
at 256 psi versus 215 psi, the intended setpoint.
Upon the
trip of No. 22 SGFP, the reactor operator (RO) quickly reduced
power to 67% in an attempt to maintain SG level and avert a
reactor trip, however No. 21 SGFP subsequently tripped for an
unknown reason.
Licensee followup testing with respect to No.
21 SGFP did not reveal any deficiencies.
Following repair of
the No. 22 SGFP suction pressure trip mechanism, testing of No.
21 SGFP and No. 23 condensate pump and reset of three main
steam safeties (discussed later); the unit was returned to
service on February 9, 1989.
The inspector reviewed procedure
11 Loss of Circulating Water and/or Condenser Vacuum
11
which the licensee has upgraded to provide added controls to
ensure proper SGFP suction pressure with circulators and heater
drain pumps out of service.
The inspector had no further
questions regarding the trip.
During plant stabilization following the trip, main steam
safety valve No. 23MS15 lifted.
As a result, reactor coolant
average temperature was reduced from 548 degrees F to 538
degrees F when the valve reseated.
Subsequent testing by the
licensee determined that this valve lifted at 960 psi versus
its required setpoint of '1070 psi.
The licensee tested all 20
main steam safety valves to verify their setpoints and
determined that valve No. 21MS12 was slightly low and 21MS13
was slightly higher than required.
All other valves tested
satisfactorily.
Valves 23MS15, 21MS12 and 13 were adjusted to
their proper values.
The inspector notes that the main steam
5
safety valves were lift tested and set at the vendor's shop
during the August 1988, refueling outage.
In addition, valve
23MS15 lifted prematurely at 1000 psi (vs 1070 psi) on November
18, 1988 with the unit in Mode 3 and was subsequently reset by
the licensee.
Licensee investigation into the cause of the
discrepant setpoints has been inconclusive.
Licensee discussions
with the vendor indicate that valve setpoint drift does occur,
but infrequently.
The inspector is concerned that valve 23MS15
has exhibited setpoint drift twice and to this point cannot be
explained by the vendor or licensee.
The inspector will continue
to follow licensee actions relative to monitoring and resolution
of the apparent setpoint drift.
8.
On March 3, 1989, the licensee identified two pinhole thru wall
leaks on No. 21 containment spray (CS) header piping between
the inboard and outboard containment isolation valves.
The
leaks were about 1/2
11 apart on the outside radius of a 10
degree bend in a 4 ft. long spool piece.
The piping material
is 8" schedule 10, 304 stainless steel.
The header was
immediately isolated by the licensee.
To ensure containment
integrity a blank flange was installed at the valve 21CS6
location inside containment, where a flanged spool piece had
been previously installed in place of the 21CS6.
Technical
Specification Action Stat~ment (TSAS) 3.6.2.1 was entered which
allows one containment spray header to be out of service for 72
hours before a plant shutdown is required.
After evaluating
repair methods and the low safety consequences of extending the
out of service period (the redundant CS header and 5 containment
fan coil units were operable), the licensee requested and NRC
granted discretionary enforcement to extend the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> TSAS by
96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> with the condition that the redundant containment spray
header and all 5 containment fan coil units remain operable.
The leaking spool piece was replaced by ~ flanged spool piece
and No. 21 CS header was returned to service on March 7, 1989.
The licensee's evaluation of the cause and extent of the leak,
and the applicability of the problem to similar piping configu-
rations on the Nos. 21 and 22 headers consisted of the following
tests:
1.
Visual walkdown of piping.
A darkening or discoloration
of the leaking spool piece was noted.
Similar discoloration
was noted on 2 additional bends in the No. 21 CS header and
on 1 bend in the No. 22 CS header.
2.
Ultrasonic testing (UT) was performed on the four darkened
bend locations.
Results on the leaking spool piece showed
indications of 9 pitting areas on the top (10 o'clock to 2
o'clock) section of the leaking pipe.
The other three bend
c.
3.
4.
6
areas showed baseline noise at the top portion of the p1p1ng
which the licensee stated is indicative of a rough surface.
No other indications of pitting were observed.
Radiography of the failed spool piece revealed several
small hairline cracks in the area of the two thru wall
holes.
The radiography results and visual observation of
the inside of the spool piece after it was cut out, did
not support the UT
results of 9 pit areas.
Radiography
of the other three areas showed no indications.
Metallography performed by Westinghouse on the failed
spoolpiece indicated a small area of sensitization in the
immediate area of the thruwall cracks.
The failure
mechanism has been attributed to intergranular stress
corrosion cracking resulting from borated stagnant water
in the sensitized piping.
A visual walkdown of Unit 1 CS p1p1ng did not identify any
similar areas of concern.
The licensee stated that the Unit 1
piping contains mitered welds rather than bends in the pipes as
in Unit 2.
The licensee is evaluating a surveillance plan for other areas
where stagnant borated water IGSCC may be of concern such as
hot and cold leg safety injection piping, BIT outlet piping and
various sample piping.
The inspector is following licensee
actions in this regard.
On March 12, 1989, a reactor trip and safety injection
occurred.
The inspector responded to the site and determined
the following concerning the transient.
The initiating event
was the failure of the 10 vital instrument bus inverter due to
a loose control power fuse.
The loss of the 10 inverter
resulted in Channel IV inputs to the reactor protection system
(RPS) being made up.
In addition, the steam generator feed
pump master controller is powered from the 10 vital instrument
bus, and upon failure of the inverter the feedpump controller
reduced the two main feedpumps to idle speed.
The reduction in
feedwater flow resulted in steam generator steam flow/feed flow
mismatch and coincident with steam generator low level (Channel
IV input), the reactor trip occurred.
When a reactor trip occurs, high steamline flow signals result
since some steam flow is present in the steamlines and the
steam flow bistables reset to their no-load value upon a
3.
3.1
7
reactor trip signal.
High steamline flows coincident with a
low steam pressure (Channel IV inputs - 2 of 4) caused by the
loss of lD inverter made up the logic for safety injection
(SI) actuation.
Plant systems responded as expected to the trip and SI.
The SI
was terminated 27 minutes after initiation, when the operators
had completed diagnostics and reached the appropriate SI
termination step in EOP-TRIP-1.
During this time the
pressurizer filled and a power operated relief valve (2PR2)
cycled sev~ral times to relieve the pressure.
Valve 2PR2 was
subsequently isolated (block valve 2PR7 closed) due to leakage
apparently caused by passing steam and water through the valve.
The licensee does not plan to repair the valve at this time.
The inspector observed the subsequent reactor startup on March
13, 1989.
No inadequacies were identified.
RADIOLOGICAL CONTROLS (71707, 83750, 92701, 92702)
Inspection Activities
PSE&G 1 s compliance with the radiological protection program was verified
on a periodic basis.
These inspection activities were conducted in
accordance with NRC inspection procedure 71707.
In addition, the inspector reviewed licensee planning and preparation in
the area of radiological controls for the upcoming Unit 1 refueling
outage.
Areas reviewed were as follows:
organization and staffing
training and qualification of radiation protection personnel and
radiation workers
ALARA; including source term reduction
oversight of contractor personnel
planning and work package review by radiological controls personnel
work scope and knowledge of work scope by radiological control
personnel
hot particle control
management support of radiological controls
incorporation of lessons learned from previous outages
licensee efforts to address radiological controls weakness
previously identified by the NRC
radwaste volume reduction
use of engineering control to minimize use of respiratory equipment
protection
8
3.2 Inspection Findings
The licensee appeared to be providing adequate planning and preparation
for the upcoming outage.
Special emphasis was being placed on efforts to
preclude recurrence of weaknesses in the implementation of the
radiological controls program identified during the last outage at Unit
2.
At the time of this inspection, licensee radiological controls
personnel indicated that planning and preparation for outage work tasks
were about 70% complete.
Licensee personnel indicated they were somewhat
behind in do~umentation of work packages, but they believed most work
packages would be completed by the start of the outage.
3.3 Followup on Open Items
A.
B.
(Closed) Violation 272/88-16-01; Post Accident Sampling System (PASS)
equipment not properly maintained, procedures not properly implemented
or issued in a timely manner.
The inspector verified that the licensee
has developed a prioritization system for ensuring timely completion
of PASS work orders.
Refer to Unresolved Item 272/88-16-06.
The
inspector verified that chemistry personnel retraining on procedure
implementation has been conducted.
Corrective actions for this
violation appear to be adequate.
This item is closed.
(Closed) Unresolved Item 272/88-16-02; Ensure capability of obtaining
backup samples.
The inspector reviewed Engineering Memo (EM)89-005
dated February 17, 1989 which delineates a project scope proposal for
backup grab sampling capability for PASS in-line monitored parameters.
The EM states that modification and upgrades to the PASS panel,
chemistry laboratory and equipment, procedures and training are
required to be able to obtain grab samples for pH, chloride, hydrogen
and boron.
The inspector concludes that implementation of the EM
proposal would satisfy T.S. and NUREG-0737 requirements.
Integrated
dose estimates will be calculated as part of the design change package.
The NRC recognizes that failure to provide backup sampling and
analysis capability for PASS in-line monitored parameters is a
deviation from NUREG-0737, Item II.B.3 and license conditions.
However, inspector review of previous correspondence between PSE&G
and the NRC concerning this issue leads to a conclusion that PSE&G
informed the NRC and implemented what they thought was an alternate
method (i.e. timely instrument repair) for meeting the intent of
NUREG-0737 requirements relative to backup sampling capability.
The
licensee was not informed by the NRC of the unacceptability of their
position.
Since being informed of the deficiency in Inspection
Report 272/311/88-16, the licensee is in the process of developing
an action plan as discussed previously to resolve the issue.
Since
it is reasonable that PSE&G did not know that their position would
not meet the intent of NUREG-0737 requirements and acceptable
corrective actions are planned by the licensee, enforcement action
will not be taken.
c.
D.
E.
F.
9
The inspector noted that the EM estimates complete implementation in
1990, while the licensee's response dated October 19, 1988 estimates
backup grab sampling capability implementation by December 1989.
The licensee should keep the NRC informed as to any changes in the
completion date as the design change package is developed.
The
inspector will follow licensee activities in this regard to ensure
timely implementation.
This item is closed.
(Closed) Unresolved Item 272/88-16-03; Proper control and testing of
the PASS area radiation monitor (ARM).
The inspector verified that
calibration and testing of ARM 2R52 is acceptable and that the
instrument has been added to the Radiation Monitor System manual.
This item is closed.
(Closed) Unresolved Item 272/88-16-04; Verify completion of PASS
sample valve maintenance.
Maintenance on PASS sample valves is
complete.
This item is cl~sed.
(Closed) Unresolved Item 272/88-16-05; Hydrogen comparison results
between the reactor coolant system (RCS) and PASS samples are not
consistent.
The inspector verified that licensee equipment and
calibration procedure upgrades have improved consistency in RCS and
This item is closed.
(Closed) Unresolved Item 272/88-16-06; Implement provisions to
ensure PASS availability with support systems isolated.
Initial
inspector review determined that the licensee's response to this
item was unacceptable.
In further discussion with the licensee, the
inspector clarified the concern to radiation protection and
licensing* personnel.
Subsequentl~ the licensee dev~loped
administrative controls to ensure that timely action is taken by
Operations and Chemistry personnel to maintain the PASS operable
when support systems are taken out of service.
The administrative
controls include an operations procedure for tracking PASS support
system and PASS availability, chemistry notification, and
establishing time requirements for restoration; establishment of
work order priority for PASS components; and development of
proceduralized alternatives for each PASS support system.
The
inspector reviewed a memo dated February 23, 1989 entitled "Post
Accident Sampling System-Priority and Operability" from the Salem
General Manager to the station managers delineating the
administrative controls and directing implementation within 60 days.
The inspector determined that the administrative controls appear to
be acceptable in ensuring PASS operability.
The inspector will
monitor licensee implementation and the effectiveness of this
program in future inspections.
This item is closed.
'.
G.
10
(Closed) Violation 311/88-25-01; Personnel did not adhere to
radiation protection procedures as required by Technical
Specification 6.11.
The licensee satisfactorily implemented the
corrective actions outlined in the March 10, 1989 letter to NRC.
This item is closed.
H.
(Closed) Unresolved Item 311/88-25-02; NRC to review dosimetry
record system, exposure control methods, and exposure limits.
Inspector review indicated that the licensee reviewed previous
personnel exposure results which were possibly subject to
interpretation errors.
No unusual exposures were identified.
The
licensee revised exposure control method~ to provide computer flags
for unusual exposures.
The licensee clarified exposure limits for
the areas between the knee and ankle.
This item is closed.
I.
(Closed) Unresolved 272/88-18-02; 311/88-18-02; NRC to review
licensee control of access to the Seal Table Rooms.
Keys to the
rooms were left in the doors to the rooms in containment and removed
when containment was opened for general access.
The seal table room
doors are independently pad locked closed.
The pad lock keys are
issued by radiation protection personnel in accordance with
applicable licensee procedures.
This item is closed.
J .
(Closed) Violation 272/88-18-01; 311/88-18-01; Personnel did not
adhere to radiation protection procedures.
The licensee implemented
the corrective action outlined in their December 22, 1988 letter to
the NRC.
The licensee also implemented the applicable corrective
action outlined in their December 27, 1988 letter to the NRC.
One
item remaining to be completed is the revision of RPlOOl, Radio-
logical Occurrence Investigation, to address root causes for
recurring problems.
The licensee has committed in the letters
above, to complete this revision by April 15, 1989.
Completion of
this revision will be followed in a subsequent inspection.
(311/89-01-02)
This item is closed.
K.
(Closed) Inspection Followup Item (50-272/88-19-01);
The licensee
was to implement enhancements to the post accident gaseous effluent
monitoring program described in their March 6, 1985 letter to the
NRC.
These enhancements included procedure upgrades, additional
personnel training, enhanced documentation and various design
changes.
The licensee satisfactorily implemented these
enhancements.
This item is closed.
4.
SURVEILLANCE TESTING
(61726)
4.1
Inspection Activity
During this inspection ~eriod the inspector performed detailed technical
procedure reviews, witnessed in-progress surveillance testing, and
reviewed completed surveillance packages.
The inspector verified that
the surveillance tests were performed in accordance with Technical
11
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 1
SP(0)4.l.2.l(A)
SP(0)4.5.4.2a
lIC-2.6.025
REM Part III-3
REM Part III-7
Unit 2
2PD-4 .1. 038
SP(0)4.8.1.1.2
2IC-2 .10. 054
2IC-1.4.003
2IC-16.4.046
4.2
Inspection Findings
Reactivity Control Systems - Boration -
Vital Heat Trace
ECCS Subsystems
lPT-506 First Stage Turbine Impulse
Pressure
Reactor Trip and Bypass Breaker
Surveillance Testing
Spent Fuel Pit Drag Test
New Fuel Receipt Inspection
2R24A Seal Water Injection Filter
calibration
A&B Emergency Diesel Generators - 15
minute run
2TE-413A No. 21 RCS Hot Leg Wide Range
No. 23 Auxiliary Feed pump tachometer
calibration
Reactivity Computer Recorder calibration
On February 22, 1989, the licensee informed the NRC that the Unit 1 "N'
reactor trip bypass breaker undervoltage trip attachment (UVTA) failed
the output force measurement test.
This test measures the margin of
force in addition to the weight of the trip bar that the UVTA is capable
of overcoming.
The maintenance and testing of the reactor trip breaker
(RTB) and UVTA is performed as part of the above six-month preventive
maintenance activity.
As a result of the Salem ATWS event, the licensee
is committed to report any deficiencies identified with the RTBs to the
NRC.
The inspector witnessed licensee investigation of the failure which
12
consisted of reperforming the output force measurement test.
Subsequent
attempts were satisfactory.
As a result, the licensee concluded that
operability of the UVTA was marginal in that test results were not
consistent.
The licensee replaced-the UVTA and maintenance procedure
M3Q-2 was completed successfully.
Similar test failures have occurred in
the past due to installation of a batch of UVTAs with marginal
performance.
Following the Unit 1 refueling outage in April 1989, all
such UVTAs will have been replaced.
The inspector had no further
questions in this area.
5.
MAINTENANCE
(62703)
5.1
Inspection Activity
During this inspection period the inspector observed portions of selected
maintenance activities 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
in~pection procedure 62703.
Portions of the following activities were observed by the inspector:
871202128
880401319
0092324
890227156
890223083
Procedure
MllE
MllG
Ml4A-4
2IC1.4.003
M3Z
I
M3R
M34-l
MllE
Description
12 Fuel Handling Building
Exhaust Fan - repair
motor vibration.
12SW387 - 12 Component
Cooling Heat Exchanger Service
Water (CCHX SW) inlet valve -
remove and repair.
22SW158 -
RHR pump room
cooler outlet control valve -
replace diaphragm.
lC Diesel Generator (DG)
lube oil heater - replace.
Boric acid filter vent
heat trace shorted -
repair.
relief valve return to day tank
leaks - repair .
870801108(09)
880913131
890224114
890303089
881227094
5.2
Inspection Findings
1. 4. 003
NDWP
M6E
CJP S-89-036
CJP S-89-012
13
11&12AF21 - Auxiliary
Feedwater inlet valve to steam
Generator, adjust limits and
measure stroke.
11 CC pump vent line -
seal weld threaded connection.
23 charging pump -
replace blown packing.
header - replace
defective pipe with flanged spool
piece.
12A CCHX - repair leak. in
valve.
A.
The maintenance activities inspected were effective with respect to
meeting the safety objectives of the maintenance program.
In
particular, the activities associated with the containment spray
piping replacement were well coordinated and well supervised.
B.
The inspector noted that some maintenance workers compile notebooks
containing the work order, procedures, vendor manuals, instrument
Data cards, etc. for their assigned activities.
The inspector
observed that this practice results in an effective, organized
approach in performing the tasks.
6.
( 71707)
A.
On March 16, 1989, a security and fire protection drill with regard
to a simulated fire and medical emergency was held onsite with the
Lower Alloways Creek. Fire Department.
The NRC was notified by
letter on that date of the planned drill and the licensee's
intention to waive certain security access requirements.
The
inspector discussed the drill scenario and security controls with
the Senior Fire Protection Supervisor and the Nuclear Security
Manager.
The inspector will review the licensee's critique report
of the drill when available.
7.
SECURITY
(71707)
7.1
Inspection Activity
PSE&G's compliance with the security program was verified on a periodic
basis, including adequacy of staffing, entry control, alarm stations, and
physical boundaries.
~- - - -
14
7.2
Inspection Findings
The inspector observed an inconsistency in the method security force
members (SFM) use to verify the integrity of the diesel rooms' personnel
escape hatch latch.
Some SFMs climb the ladder to the hatch and verify
the proper position of the latch, while others shine a flashlight up to
the latch.
The inspector observed that it is difficult to see the latch
from the floor even with a flashlight.
This issue was discussed with the
Nuclear Security Manager who stated that the SFM should climb the ladder
to verify latch integrity and all SFM would be reinstructed to do so.
The inspector will continue to monitor the implementation of the security
program in this regard.
8.
ENGINEERING/TECHNICAL SUPPORT
(35065, 92701)
8.1
Inspection Activity
The inspector conducted an inspection of material storage by reviewing
Quality Assurance (QA) audits, QA surveillances and Storage and Material
Control procedures, and by conducting interviews with management
personnel.
8.2 Inspection Findings
Materials delivered to the rece1v1ng area undergo a receipt inspection,
are classified and are assigned an appropriate shelf life.
Material
Control personnel enter the information into a computer data base and
conduct a put away inspection of the material to verify various
~ttributes such as correct storage bin location, consistent
classification and shelf life with material in the same bin, and properly
completed identification tags.
If any errors are identified during put
away a problem report is prepared.
The problem report is then
dispositioned by the Engineering and Procurement Branch (E+PB).
The
questionable material is tagged with the problem report, but remains in
storage.
No attempt is made to physically segregate the material or to
correct the identified problem until disposition of the problem report is
completed.
Problem reports appear to be dispositioned only if the
nonconforming material is requisitioned.
During issuance of material for maintenance activities, a check is made
that the part number requested on the work order matches the part number
attached to the material.
There is no formal verification of the
material classification, shelf life or the proper disposition of problem
reports applicable to that part number.
In 1987, a new classification system was instituted which created
different classifications for some material.
The licensee has decided
not to review and update the classifications of existing material in
storage which were classified under the old system.
As a result, problem
reports are generated whenever an inconsistent classification of material
15
is identified.
A new shelf life program was also implemented in May 1988
and the shelf lives of all material were evaluated and problem reports
were written for identified inconsistencies.
PSE&G surveillances as early as 1986 identified nonconformances in the
areas of material ~dentification and control, such as incorrect or
inconsistent classifications and shelf lives.
Corrective Action Request
(CAR) MR-87-C-001 was written on these nonconformances in April 1987, and
a letter was sent to the Manager Material Control in July 1987,
identifying a lack of appropriate corrective actions.
Apparently a
management decision was made not to attempt to identify similar
occurrences of the identified problems, not to physically segregate
material and not to establish any compensatory formal controls to prevent
questionable material issuance.
In June 1988, Quality Action Report (QAR) SP-88-QOOl was issued to the
Manager Material Control for failure to correct material identification
and control problems which were identified in February 1988.
In response
to the QAR, problem reports were written for the deficiencies and
submitted to Procurement Engineering for disposition.
There is no record
to indicate that the problem reports were dispositioned or that the
problems were corrected.
Again, no apparent action was taken to
determine similar problems nor to physically segregate material tagged
with problem reports.
The last three Quarterly Reports for 1988 from the Manager Procurement
Quality Assurance to the Manager Material Control requested corrective
actions to be taken to resolve the generic problems underlying the
continued identification of nonconformances.
There was apparently no
response to the Reports nor any actions taken to correct the problem.
In August 1988, Management Action Request (MAR) MA-88-MOOl was issued to
the General Manager of Nuclear Services concerning, in part, problems of
material identification and control.
A corrective action plan was
developed and implemented, however no attempt was made to identify and
correct problems similar to those documented in the MAR or to establish
compensatory controls for material issuance.
In October 1988, QAR MR-88-Q005 was issued to the Manager Material
Control concerning recurring nonconformances in the areas of material
identification and control.
On December 5, 1988 a letter was sent to the
Manager Material Control from the Engineer-QA Material Compliance
requesting an expedited disposition of the QAR since the response was
past due.
The response detailed the actions taken to correct the
documented problems, however no apparent attempt was made to identify and
correct similar problems.
- .-*:':::
16
From the above QA reports, the inspector concludes that material of mixed
classifications exists in the same bin and that an undetermined amount of
material in the storage areas may be fncorrectly classified.
Due to the recurring licensee identified problems with inventory storage
and control, it appears that corrective actions taken over the last three
years have not precluded the recurrence of problems in these areas nor
have actions been taken to formally control and more closely monitor the
potential for issuance of nonconforming material.
The failure to correct
or prevent recurrence of self identified nonconformances for over a three
year period is considered an apparent violation of 10CFR50 Appendix B
Section XVI.
(50-272/89-01-02)
The licensee 1 s identification of recurring nonconformances is indicative
of adequate Quality Assurance surveillances and audits, however
inadequate steps have been taken to resolve potential nonconformances,
identify root causes and implement corrective actions which prevent or
alleviate recurrence of similar nonconformances.
There are presently over 1400 problem reports that have not bee11
dispositioned.
Approximately 50% of the reports are for shelf life
discrepancies which were identified in June 1988 when the interim shelf
life program was implemented.
Disposition of shelf life discrepancies
are not planned until a new standard for self life is completed later
this year.
No plans exist for reducing the backlog of problem reports.
This is inconsistent with procedure M-ll-P-300, rev 2, Storage and
Handing of Material, which specifies disposition of problem reports in an
expeditious manner.
A problem report identifies a nonconformance since it identifies a
deficiency in the documentation of material characteristics that render
the quality of the material unacceptable or indeterminate.
In accordance
with ANSI N18.7, Administrative Controls and Quality Assurance for the
Operational Phase of Nuclear Power Plants, the control of- nonconformances
with tags is acceptable, however physical segregation and marking is
preferable.
Due to the backlog of problem reports further consideration
should be given to the preferred method of physical segregation of
nonconforming material.
There is presently material in the storage area which is over two years
old and may be incorrectly classified in accordance with the present
classification system.
The licensee apparently made a decision that
having an unknown number of improperly classified items in the storage
area is acceptable based on the checks made during put away and the
ev~ntual reordering of all_ material.
-
17
There is no formal verification or validation of the correctness of
material classification and shelf life prior to issuance of the material,
even though there is a significant amount of nonconforming material in
mixed storage in the storage areas.
Instances have been i.dentified in
CAR SA-88-C016, issued in August 1988, and in CAR MAR-87-COOS, issued in
May 1987, where material was issued to the maintenance department and the
appropriate material control tags were not issued or not retained with
the work package.
Follow up licensee investigations verified that the
material installed in the facility was properly qualified.
The inspector is concerned that due to the amount of nonconforming
material in the storage area and the lack of formal verification of
material acceptability upon .issuance, there is a significant potential
that nonconforming material could be issued for use in safety grade
equipment.
This issue is considered an unresolved* item.
(272/89-01-03)
8.3
Open Item Followup
A.
(Closed) Unresolved Item No. 272/311/87-35-02:
Review of the
licensee's evaluation and resolution of degraded grid voltage
problems which could affect the operability of safety related
equipment.
After a Power Technology Inc. transient analysis study
identified the degraded grid voltage problems, six circulating water
pump power supplies were shifted from the Salem 13 KV electrical
distribution system to the Hope Creek 13 KV electrical distribution
system to reduce loads on the Salem grid to below the base value
determined by the study.
An EBASCO calculation, which was initially issued in draft form on
July 15, 1987, provides the design basis for the Salem electrical
system.
Based on the calculation, two 600 volt feeder lines at Unit
1 and three lines at Unit 2 were installed from the the vital buses
to the motor control centers in the service water building in order
to reduce the voltage drop.
In December 1987, an analysis was performed, based on the EBASCO
calculations, for the voltage drop from the 230 V vital MCCs to 120
V control power circuits.
Based on the analysis, interposing relays
were added to approximately 48 control circuits to assure their
operability at the expected low voltage conditions.
In October 1988, an Engineering Evaluation was completed by PSE&G
using plant specific equipment responses.
The Evaluation reanalyzed
motor operating conditions for motors whose voltage had fallen below
80% rated voltage in the EBASCO calculation. It was concluded that
adequate voltage would be available to start and run the vital
motors.
In addition field measured voltage drops were compared to
the calculated values to verify the analysis.
18
The licensee is planning on completing major modifications to the
off site power grid for Salem over the next five to seven years.
The modifications are expected to reduce the degraded grid problems
and provide additional flexibility in conducting maintenance on the
equipment in the electrical yard.
The inspector has no further questions on the short term resolution
of the degraded grid voltage concern.
This Item is closed.
B.
(Closed) Inspector Follow Item 272/88-13-01; Containment Electrical
Backup Protection Modifications.
Modifications to add backup
protection devices for Unit 1 penetrations will be completed during
the upcoming refueling outage under Design Change Package lSC-2001.
This item is closed.
9.
SAFETY ASSESSMENT/QUALITY VERIFICATION
(35502, 40500)
9.1
9.2
Inspection Activity
The inspector reviewed the license2 1 s self assessment capabilities
including interviews with supervisory and management personnel from the
following PSE&G Quality Assurance groups: Programs and Audits, On Site
Safety Review Group, and Off Site Safety Review Group.
An inspection. was
made of selected reviews, audits and reports produced by these groups.
They were evaluated based on quality of the review or audit, quality of
the recommendations made, and the implementation and follow-up on the
recommendations.
The SORC process and the licensee's corrective action
tracking system were also reviewed.
Inspection Findings
The inspector reviewed the quality assurance audits performed on Salem
maintenance and operations in 1987 and 1988, corrective action audits
performed in 1987 and 1988, and corrective action follow-up on several QA
initiated action items.
In general the audits were of sufficient depth
to make a meaningful evaluation of the activity inspected.
Open items are followed by the licensee's corrective action tracking
system (now called ATS).
The inspector observed, however, that a
significant number of QA initiated items were listed on ATS as overdue.
Quality Assurance personnel were questioned as to the reason for the
overdue items.
They indicated that there has been a problem in getting
station response to open QA items in the past.
Part of the problem
appears to be due to the large number of items opened on the ATS by
various groups without a priority established.
Discussions with the Vice
President - Nuclear Operations, General Manager - QA/NSR, and the Salem
General Manager, all of whom are fairly recent appointees to these
positions, indicate that they are working to resolve the prioritization
and responsiveness issues.
The inspector has noted a slight improvement
in the number of overdue items on ~he ATS over the past several months.
,.
,
19
Based on management's acceptance of the problem and commitment to
resolution, and the downward trend on overdue items, unresolved item
272/88-16-07 is closed.
However, the inspector will continue to monitor
licensee progress in this area.
The inspector reviewed the Technical Specification required functions of
the Off Site Safety Review group.
The quality of the unresolved safety
question reviews was adequate, although made less useful by being on a
parallel vice series path with SORC.
The audit function of the Salem QA
program was adequate.
The functions of the On Site Safety Review (SRG) group were
reviewed.
Detailed safety system functional reviews, problem area reviews, root
cause investigations, and post trip reports have been produced by this
group alone or in conjunction with other engineering resources.
Inspector review of a sample of these documents determined that they
appear to be thorough and provide meaningful information for management
action.
The inspector noted that this group does not meet the Technical
Specification 6.5.2.2 which requires manning levels of a Manager, On-Site
Safety Review Group (SRG), who is supported by at least four dedicated,
full-time engineers located on site.
Presently the on-site Safety Review
Group consists of an onsite safety review engineer assisted by three
engineers.
This issue is unresolved pending NRC review of outstanding
license amendment requests (UNR 50-272/89-01-04).
Station Operations Review Committee (SORC) reviews of engineering design
changes were determined to be adequate.
10.
LICENSEE EVENT REPORT ( LER) AND OPEN ITEM FOLLOWUP
(90712, 92700)
10.1 Review of Licensee Reeorts
The inspector reviewed the fo 11 owing licensee reports for accuracy and
timely submission.
Unit 1 Monthly Operating Report - December, 1988 and January, 1989
Unit 2 Monthly Operating Report - December, 1988 and January, 1989
Unit 1 LER 89-001; On January 4, 1989, an Unusual Event was declared
and a Unit 1 shutdown commenced due to all three groups of
containment fan coil units (CFCU) being inoperable.
This event was
discussed in NRC Inspection Report 50-272/88-24; 311/88-27.
The
inspector had no further questions following review of the LER.
Unit 1 LER 89-003; On January 25, 1989, the licensee identified that
two impaired relay room penetrations had not been addressed in a
Special Report in accordance with Technical Specification (T.S.).
The deficiency is due to inattention to detail in entering computer
data which is used to compile the information for the Special
Reports.
The personnel involved have been counseled.
The inspector
verified that the two impairments have been added to Special Report
88-3-6.
Due to the administrative nature of this problem and small
- ,
20
safety significance, the inspector has determined that failure to
include the two impairments in a Special Report is a licensee
identified violation of T.S. 3.7.11.a for which no further action is
required. (50-272/89-01-02).
Unit 1 LER 89-004; On January 20, 1989, an Unusual Event was
declared and a reactor shutdown commenced due to the breaker
position input to the reactor trip system for all four reactor
coolant pumps (RCP) being declared inoperable.
This event was
discussed in NRC Inspection Report 50-272/88-24; 311/88-27.
The
i~spector had no further questions following review of the LER.
Unit 1 LER 89-005; On January 27, 1989, both trains of ECCS were
declared inoperable due to unrelated equipment problems.
No. 11
train was inoperable due to No. 12 service water (SW) header being
out of service to effect repairs to No. 12A component cooling water
heat exchanger (CCHX) SW inlet piping.
No. 12 train was inoperable
due to the inoperability of lC diesel generator to repair it's
failed lube oil heater.
A blank flange was installed in 12A CCHX SW
inlet piping to allow 12 SW header to be placed in service within
the two hour T.S. action statement and a plant shutdown was not
required.
The equipment deficiencies have been corrected by the
licensee.
Inspector review of this issue is complete.
Unit 2 LER 89-001; On January 3, 1989, both service water headers
were inoperable due to unrelated equipment problems.
The Unit was
in Mode 4.
Equipment deficiencies were corrected by the licensee
within TSAS requirements and a reduction in mode was not required.
The inspectors review of this issue is complete.
Unit 1 Supplemental Special Report 88-3-6 addresses additional
licensee identified fire barrier penetration seal impairments
discovered as a result of the Penetration Seal Program.
Unit 2 Special Report 88-8;
Inadvertent actuation of the
pressurizer over pressure protection system (POPS).
On October 31, 1988, with Unit 2 in cold shutdown, POPS Channel II
actuated with an indicated pressure of approximately 360 psig, which
is below the actuation set point of 370 psig.
POPS Channel I did
not actuate even though actual pressure was determined to be
approximately 380 psig.
The inspector found the special report to be inadequate to meet the
requirements of Technical Specification action statement 3.4.10.3.c.
The description and the apparent cause of the event did not provide
sufficient details regarding to the components that failed.
The
source of the error in the main control board bezel reading was not
identified by the report as affecting the indication from both
channels or that both sensors were properly calibrated.
The
corrective actions did not include steps that would be implemented
to prevent reoccurrence of the event.
21
After review of the report and discussions with the licensee it
appears that the Channel I POPS comparitor was set above the maximum
Technical Specification set point and therefore rendered the channel
inoperable for an undetermined period of time.
The licensee has not
addressed the cause for the inoperability of the channel, the time
that the channel was inoperable nor what steps would be taken to
preven~ reoccurrence of the inoperability.
Based on the identified deficiencies in the report the licensee was
requested to reevaluate the POPS actuation and provide a supplement
to the Special Report.
This issue is unresolved pending NRC review
of the supplemental report. (UNR 50-311/89-01-01)
Unit 2 Special Report 88-9 des~ribes a non-valid 2C diesel generator
(DG) test failure as a result of a speed relay and alarm reset
switch problem.
The equipment deficiencies were corrected and the
DG tested satisfactorily.
The inspectors review of this occurrence
is complete.
10.2 Reference to Open Items
The following open items from previous inspections were followed up
during this inspection and are tabulated below for cross reference
purposes.
Closed
Closed
Closed
Closed
Closed
Closed
Closed
Closed
Closed
Closed
Closed
Closed
Closed
VIO 272/88-16-01
UNR 272/88-16-02
UNR 272/88-16-03
UNR 272/88-16-04
UNR 272/88-16-05
UNR 272/88-16-06
VIO 311/88-25-01
UNR 311/88-25-02
UNR 272/311/88-18-02
VIO 272/311/88-18-01
IFI 272/88-19-01
UNR 272/311/87-35-02
IFI 272/88-13-01
11.
EXIT INTERVIEW
(30703)
Section 3.3
Section 3.3
Section 3.3
Section 3.3
Section 3.3
Section 3.3
Section 3.3
Section 3.3
Section 3.3
Section 3.3
Section 3.3
Section 8.3
Section 8.3
The inspectors met with Mr. L. Miller 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 10 CFR 2
restrictions.