ML20235T850
| ML20235T850 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 10/01/1987 |
| From: | Swetland P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20235T827 | List: |
| References | |
| 50-354-87-17, NUDOCS 8710130249 | |
| Download: ML20235T850 (14) | |
See also: IR 05000354/1987017
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S.' NUCLEAR REGULATORY COMMISSION
REGION I.
050354-870605
050354-870608
Report No.
50-354/87-17
_050354-870611'
050354-870624
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Docket
=50-354
050354-870626
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050354-870629
License
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Licensee:
Public Service Electric and Gas Company
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Facility:
Hope Creek Generating Station
Conducted:
July 14, 1987 - August 17, 1987-
Inspectors:
R. W. Borchardt, Senior. Resident Inspector
D. K. Allsopp, Resident Inspector
R. J. Summers, Project Engineer
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R. R. Brady, k ctor
gineer
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Approved:
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P. Swetland, Chief, Projects Section 2B
Oate
Inspection Summary:
Inspection on July 14, 1987 - August' 17,'1987 (Inspection Report Number
50-354/87-17)
Areas Inspected: Routine onsite resident inspection of theLfo110 wing
areas:
followup on outstanding inspection items, operational ~ safety
verification, surveillance testing,' maintenance activities, engineered
safety feature system walkdown, residual heat removal pressure transmitter-
operability, instrument calibration data cards,' review of non-essential
diesel. generator trips, and licensee event report followup.
This-
inspection involved 189 hours0.00219 days <br />0.0525 hours <br />3.125e-4 weeks <br />7.19145e-5 months <br /> by the inspectors.
Results: One apparent violation of Technical Specifications was identified
concerning the control of plant equipment (paragraph 7)
.Although-this viola-
tion was licensee identified, its similarity to a violation cited in NRC
Inspection Report 50-354/86-48 and to other recent plant equipment control
problems is of concern to the NRC. An enforcement conference will be scheduled
regarding these problems.
Paragraph 8 of this report details the NRC's understanding of the licensee's
corrective action commitments in response to incorrect instrument calibration
data cards.
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8710130249'871005
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ADOCK 05000354
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DETAILS
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1.
Persons Contacted
Within this report period, interviews and discussions were conducted
with Mr. S. LaBruna and members of the licensee management and staff'
and various contractor personnel as necessary to support inspection
activity.
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2.
Followup on Outstanding Inspection Items
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a.
(Closed) Inspector Follow Item (87-05-01); Mislabeled in-line smoke
detectors in the control room emergency filtration (CREF) system.
While inspecting the "A" CREF train, the inspector identified
incorrect labeling on two in-line smoke detectors (XSH 9588A2, XSH
9588A1). The licensee also determined that the smoke detector
electrical output cables were incorrectly wired and labeled such
that the Al detector lit the A2 annunciator and vice versa.
Since
these are redundant indicators in the same duct, there were minimal
consequences from this wiring problem.
The licensee implemented
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design change DCR 4-HM-0116 to correct the smoke detector and output
cable labeling, and to swap electrical leads at control panel 10C413.
The licensee. conducted a functional retest on the in-line fire
detection system following the design change completion, to insure
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correct alarm point response.
The inspector verified the correct
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labeling on the smoke detectors and output cables in panel 10C413,
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This item is closed.
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b.
(Closed) Unresolved Item (87-16-02); Instrument root valve for
RHR pressure transmitter isolated.
This item has been upgraded to a
violation and is discussed in paragraph 7 of this report.
This item
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is closed.
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c.
(Closed) Unresolved Item (87-14-03); Backflow of drains into the
The inspector held discussions with
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the system engineer, reviewed the control rod drive hydraulic system-
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isometric drawings, and reviewed the liquid radioactive waste (LRW)
piping and instrument diagram.
The SDV vent and drain valves both
drain to the LRW tank which is vented to preclude an internal
pressure increase. The LRW tank is located a minimum of 38 feet
below the vent and drain taps off the SDV.
The-inspector concluded
there was no feasible scenario in which the LRW tank could backflow
and fill the scram discharge volume. This item is closed.
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3.
Operational Safety Verification
3.1 Inspection Activities
On a daily basis throughout the report period, inspections were
conducted to verify that the facility was operated safely and in
conformance with regulatory requirements.
The licensee's
management control system was evaluated by direct observation of
activities, tours of the facility, interviews and discussions
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with licensee personnel, independent verification of safety
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system status and limiting conditions for operation, and review
of facility records.
The licensee's adherence to the radiological
protection and security programs was also verified on a periodic
basis.
These inspection activities were conducted in accordance with~
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NRC inspection procedures 71707, 71709, and 71881 and included
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weekend and backshift inspections conducted on July 16 (0:30-6:00
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a.m.), July 19(4:30-10:30 p.m.), and August 16 (10:00-1:30 p.m.)
3.2 Inspection Findings and Significant Plant Events
The unit entered this report period at maximum allowable power as
limited by the transmission network stability curves generated after
the damage of the Keeney 500 KV transmission lines.
The unit
continued to operate at full power throughout this report period
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except for short power reductions for testing and as discussed below.
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On July 14, 1987, the plant. experienced a high pressure coolant
injection (HPCI) automatic start in response to an erroneous
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reactor vessel low leesl signal.
The HPCI system was secured
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prior to water injection into the reactor vessel. The low
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vessel level signal was generated from a minor pressure spike in
a level transmitter common reference leg while valving in a fuel
zone level transmitter. The fuel zone level transmitter and
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a wide range reactor vessel level transmitter which share a common
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instrument line were isolated to prevent spurious ESF actuations
while drawing a post accident sample for training. The sample is.
drawn from the same common instrument line used by the level trans-
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mitters.
The wide range transmitter provides an input into the HPCI
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automatic start logic.
During the restoration of the fuel zone
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transmitter, a pressure spike was transmitted to the wide range
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level instrument creating the spurious HPCI actuation,
The root cause of this occurrence was determined
to be related to the high sensitivity of the Rosemount 1153 level
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transmitters.
The level transmitters have a very short response time
and are therefore overly sensitive to minor pressure perturbations in
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the reference leg caused by isolation valve manipulations.
Short
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term corrective actions consisted of reemphasizing to instrument and
calibration technicians the need to valve in level transmitters in a
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slow and deliberate manner.
Longer term corrective actions consist
of implementing a previously identified design change to replace the
electronics module on this and all Rosemount 1153 level transmitters
when environmental qualification of the redesigned module is
complete.
This design change is scheduled for implementation during.
the first refueling outage.
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At 9:10 a.m. on July 30, 1987, the reactor automatically scrammed due
to a reactor vessel low water level condition.
The HPCI and Reactor
Core Isolation Cooling (RCIC) systems automatically initiated and
injected water into the vessel until secured by the operators.
The
plant responded as designed and vessel water level was quickly
restored to normal.
The low water leve1 condition was caused by a
temporary loss of power to the feedwater control logic normally
energized by miscellaneous instrumentation power supply IBD483.
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loss of power occurred when an equipment operator made an error while
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switching power supplies to inverter 180483.
The power supplies were
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being switched to allow performance of preventative maintenance on
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the inverter. While attempting to transfer the inverter power supply
from an alternate to normal source, the transfer switch was
momentarily placed in an incorrect position which caused the main
fuse on the inverter section to blow, deenergizing the feedwater
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level control (FWLC) system and other loads normally supplied by
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IBD483. The loss of power to the FWLC system caused reactor vessel
water level to decrease until the low water level scram setpoint was
reached. The unit remained in hot standby until the restart was
authorized following the identification of the root cause of the
event.
The reactor was made critical at 9:36 p.m. on July 31.
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Creek was synchronized with the grid at 4:45 a.m. on August 1 and
reached full power at 6:05 p.m. the same day.
On July 30, 1987, the "E" Filtration Recirculation Ventilation
System (FRVS) fan automatically started for no apparent reason.
The "E" FRVS fan was quickly secured and returned to its normal
line-up. There are six FRVS units, five of which are normally
running, with the remaining unit in standby.
The standby unit
automatically starts on either an accident actuation signal or low
flow in one of the other units. The licensee determined the cause of
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the FRVS fan start signal was due to dirty contacts on the low flow
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switches for the "A" FRVS fan.
When low flow was spuriously sensed
at the "A" FRVS fan, the "E" FRVS fan received an automatic start
signal.
The licensee has cleaned the low flow switch contacts on
both the "A" and "B" FRVS fans and has received no additional spurious
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FRVS actuations.
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On August 6, 1987, the licensee identified a potential environmental
qualification problem on flow switches in the FRVS (Dwyer EP
Switches, Model No. 1950-00-2B)' system. The flow' switches.in
question, will auto start the "E"
and "F" FRVS fans upon low flow in
either the "A", "B", "C" or "D"
trains.
Upon identifying the
potential problem, the licensee replaced the affected switches with
qualified equipment (Dwyer EP Switch, Model No. 1950-00-2F) taken
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from another system at the plant that did not need to meet the " harsh"
environmental qualification requirement.
Following the replacement,
on August 7, the inspector met with the licensee to deterraine the
cause of this problem.
The preliminary investigation indicates that
the vendor (Dwyer) substituted a different flow switch. - for a licensee
replacement parts order, resulting in the licensee receiving equipment
for which they had no record of environmental qualification. The
vendor was contacted and assured the licensee that the flow switches
were, in fact, environmentally qualified and'provided a copy of the-
environmental qualification (EQ) test data to the licensee.
Subsequently, the inspector determined that this same EQ test data
was, in fact, onsite during this occurrence, but had not been
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identified by licensee engineers.
On August 7, 1987, the licensee found an emergency diesel generator
(EDG) room recirculation fan control switch in the "off" position.
The licensee performed a walkdown of all control switches in the four
diesel generator rooms to verify that all other controls were
properly positioned. The affected EDG and one other were test
started satisfactorily. This is similar to a previous event in which
manual control switches for certain EDG support equipment were found
mispositioned. The EDG would have started and operated properly even
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with the recirculation fan off.
The licensee increased the security
patrols in the area and plans to add a checklist of switch positions
to the equipment operator daily log.
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On August 16, 1987, the licensee declared,and termina'ted an unusual
event for a reactor scram with HPCI injection which occurred at 2:07
a.m. the same day.
The plant was operating at 85's power prior to the
scram. All systems functioned as designed.
The reactor scram
occurred while operators were attempting to return the'"C" reactor
feedpump turbine (RFPT) to service after corrective maintenance and
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inadvertently blew a RFPT rupture disc.
This rupture disc protects
the RFPT exhaust piping and the main condenser from overpressure
conditions. After the disc blew out, condenser vacuum quickly
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dropped and tripped the two operating RFPTs.
Reactor' vessel level
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decreased until the scram occurred at level 3.
The licensee con-
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cluded that the most probable cause for the blown rupture disc was
due to steam leak-by past the RFPT steam isolation. valve. The
licensee has implemented an on-the-spot change to the RFPT startup
procedure to modify the valve sequence to minimize leakage past the
RFPT steam isolation valve. The licensee's declaration of the
unusual event was made approximately four hours after the reactor-
scram occurred. The licensee's failure to initially identify the
ECCS actuation with discharge to the vessel as an unusual event was
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due to poor indexing in the event classification guide (ECG). The
licensee has conducted operator training on the ECG as an interim
action, and will upgrade the ECG index as long term corrective action.
The licensee made the reactor critical at 3:10 p.m. on August 17.
and synchronized with the grid at 7:30 p.m. the same day.
No further inadequacies were identified.
4.
Surveillance Testing
4.1 Inspection Activity
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During this inspection period 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 Specifications, licensee approved
procedures, and NRC regulations.
These insnection activities
were conducted in accordance with NRC ins;+ction procedure
61726.
The following surveillance tests were reviewed, with portions
witnessed by the inspector:
- IC-FT.SE-020
Functional Test of "B" Rod Block Monitor
- IC- FT . S E-006
Functional Test of Intermediate Range
Monitor (IRM) "B"
IC-FT.SE-011
Functional Test of IRM "G"
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- IC-SC.BJ-010
High Pressure Coolant In.jection (HPCI)
Suppression Pool' Level sensor calibration
OP-IS.BJ-001
HPCI Inservice Test
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No violations were identified.
5.
Maintenance Activities
5.1
Inspection Activity
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During this inspection period the inspector 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.
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5.2. Inspection Findings
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Portions of the following activities were observed by the
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inspector:
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Work Order
Procedure
Description
87-07-017-039-4
Troubleshoot,
rework, and
calibrate the
"B"
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analyzer
870810050
DCP 4-HM-0156
Standby liquid
control system
relay replacement
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870805082
Standby liquid
CJP-H-87-043
control system
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squib valve
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replacement and
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hydrostatic test.
Additional details on the standby liquid control system maintenance
can be found in paragraph 6 of this report.
No violations were identified.
6.
Engineered Safety Feature (ESF) System Walkdown
6.1 Inspection Activity
The inspectors independently verified the operability of . selected ESF
systems by performing a walkdow1 of accessible portions of the system
to confirm that system lineup procedures match plant drawings and the
as-built configuration.
This ESF system walkdown was also conducted
to identify equipment conditions that might degrade performance, to
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determine that instrumentation is calibrated and functioning, and to
verify that valves are properly positioned and locked as appropriate.
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This inspection was conducted in accordance with NRC inspection
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procedure 71710.
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6.2 Inspection Findings
The standby liquid control (SLC) system was inspected and in plant
conditions were found to be acceptable. _The inspector verified that
certain technical specification surveillance test requirements are
satisfied through a review of the following procedures
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OP-ST.BH-001
SLC Valve Operability Test - Monthly
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OP-ST.BH-002
SLC Flow Test - 18 Month
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OP-ST.BH-003
SLC System Tank Flow Test - 18 Month
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OP-ST.BH-004
SLC Storage Tank Operability Test - 18 Month
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Standby Liquid Control Pump Inservice _ Test
Although a number of minor material deficiencies such as valve
packing leaks were noticed by the inspector, the licensee had
previously identified these items and had scheduled repairs.
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The NRC staff has expressed concern that the current Hope Creek
technical specification requires a SLC pump minimum flow of 41.2 gpm
(82.4 gpm total) as compared to the 10 CFR 50.62(c)(4) minimum flow
rate of 86 gpm at a 13.0 weight percent (w/o) sodium pentaborate
solution.
The SLC pumps currently produce a total flow of 89.9 gpm.
The licensee has responded to NRC's concern by submitting a license
change request dated July 14, 1987 to increase the minimum required
sodium pentaborate solution concentration to 14.0 w/o, thereby
ensuring that a sufficient amount of sodium pentaborate will enter
the reactor vessel when required, even with reduced SLC pump flow.
This amendment request is currently under review by NRC:NRR.
At 9:44 p.m. on August 4, 1987, the plant experienced an automatic
initiation of the "B" SLC pump and firing of the associated squib
valve.
The control room operator secured the pump 12 seconds after
it started since it was obvious from control room indications that
there was no valid reason for the auto start. At 10:10 p.m., the "B"
SLC pump automatically started again and was secured by the operator
after a 7 second run.
In order to prevent further automatic starts,
the electrical power supply breaker for the pump was opened and the
SLC system was declared inoperable.
The licensee conducted an
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investigation into the cause of these automatic starts and found that
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the redundant reactivity control system (RRCS) self test circuit
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pulses were causing a fluttering movement of the Struthers-Dunn
isolation relays located between RRCS and the Bailey 862 logic
cards. Although not proven conclusively, the l',ensee believes that
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under the right circumstances, the relay fluttering could momentarily
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pass an initiation signal from RRCS to the Bailey logic which has a
" seal in" feature.
Troubleshooting efforts did not identify any
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problems with the RRCS or the specific Bailey 862 logic cards.
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SLC system is the only Hope Creek system which utilizes isolation
relays to isolate the Bailey 862 logic cards from a self test circuit
pulse.
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As corrective action for this event, the licensee performed a design
change (DCR 4-HM-0156) to replace the Struthers-Dunn isolation relays
with Agastat relays in the circuitry for both SLC pumps. Testing and
post installation experience has shown that the Agastat relays are
not subject to the same fluttering movement because they have a
substantially larger. relay coil.
The design change package including
retest, safety evaluation, infield work, and system restoration was
observed by the inspector and found to be acceptable.
The licensee
intends to instrument the SLC circuitry so that should another
spurious initiation occur more troubleshooting data would be
available.
Based upon reactor vessel water samples and calculations considering
pump flow rate and run times it does not appear that any sodium
pentaborate entered the reactor vessel.
The SLC system piping was
drained and flushed to the maximum extent possible during power
operations and will be completely flushed during the upcoming fall
outage.
No violations were identified.
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7.
Control of Plant Equipment
During the previous inspection period, the licensee discovered that the
instrument root valve, P-BC-9993, for the
"C" RHR pump pressure
transmitters (PT-N055H and PT-N056D) was out of position (closed), thereby
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disabling an input to the automatic depressurization system (ADS)
permissive logic.
Each train of the ADS logic is set up such that the
ADS relief valves will not open unless either 1) both pumps in the
associated core spray loop are running or 2) one of the two RHR pumps
(Low Pressure Coolant Injection Mode) are running.
Having BC-9993 closed
prevented the possibility of actuating ADS using the "C" RHR pump.
This
condition requires entry into technical specification action statement 3.3.3
which declares the "C" RHR pump inoperable and allows continued operation
in this mode for 30 days. Once the licensee became aware of the mispositioned
valve it was immediately opened, returning the pressure transmitters to
service and fully restoring the ADS logic.
The licensee has been unable
to determine why, and for how long this instrument root valve (IRV) was
closed. The IRV was last known to be open during a routine surveillance
test on April' 10, 1987. At the time this event was identified, the pressure
transmitters for the other RHR pumps as well as the core spray pumps were
inservice, and would have resulted in normal actuation of the ADS logic.
However, since the licensee was unaware of the mispositioned root valve
other redundant components may have been voluntarily removed from service,
relying on the operability of the
"C" RHR pump and technical specification 3.3.3 action statement was exceeded because the IRV could have been isolated
longer than the 30 day allowed by the technical specification.
Licensee
corrective action included identifying each ADS IRV and affixing operator
aide tags to each, specifying the correct position and actions to be taken
when the IRVs are manipulated.
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During dayshift on July 25, 1987, the control switches for both of the
High Pressure Coolant Injection (HPCI) room coolers were placed in the
stop. position to prevent fan operation while maintenance personnel were
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welding in the HPCI room. While both HPCI room cooler . switches are in
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"off", the HPCI turbine is considered inoperable.
The technical
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Specification 3.5.1 action statement for an inoperable HPCI pump requires
the pump to be returned to service within 14 days or shutdown the plant.
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The welding job was postponed, but the room cooler switches were not
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returned to automatic.
The licensee identified the out of service HPCI .
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room coelers and returned them to automatic at 6:00 p.m. on July 28. All
other emergency core cooling systems and the reactor core isolation
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cooling system were operable during this time period.
Since the coolers
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were out of service less than 14 days, the TS limiting condition for
operation had not been exceeded.
Another example of a mispositioned instrument root valve was identified by
the licensee on August 13, 1987.
/tn equipment operator found that
isolation valve P-FD-V9991 to HPCI exhaust pressure transmitter PT-N056E
was shut. Although this transmitter-is not required to be operable by
technical specifications it does provide an input to a HPCI turbine trip.
A contributing factor into this valve being mispositioned was an error in
the licensee's valve lineup database.
The inspector will followup on the
licensee's verification of the valve lineup database as part of the above
violation followup.
The licensee's administrative procedure OP-AP.ZZ-108(Q), Removal and
Return of Equipment to Service, requires that all TS LCO's be reviewed to
determine if entry into an action statement is required prior to placing
equipment out of service. A similar event was identified and cited in
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NRC Inspection Report 50-354/86-48. Although the above events were
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licensee-identified, they are indicative of continued licensee problems
with control of plant equipment despite corrective action implemented for
the previous violation. NRC determined that an-enforcement conference
was necessary to discuss these concerns.
This item remains unresolved
pending the results of that meeting.
(37-17-01)
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8.
Instrument Calibration Data Cards
At 11:00 p.m. on July 29, an unusual event was declared and a plant
shutdown commenced after it was determined that the filtration,
recirculation and ventilation system (FRVS) flow transmitters were
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previously calibrated using incorrect calibration data.
The
incorrect and non-conservative calibrations would have prevented the
FRVS recirculation fans from reaching the design flow rate of 30,000
SCFM per fan.
The actual flow rates would have bean limited to
approximately 23,000 SCFM per fan. The root cause of the miscalibration
was that subsequent to startup testing, a Bechtel gene n ted instrument
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calibration data (ICD) card was inadequately reviewed and substituted for
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correct data determined during the startup test program.
The FRVS
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ventilation fans were similarly_affected although their design flow rate
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is 9000 SCFM/ fan.
By 1:15 a.m. on July 30,. one FRVS vent fan and five
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FRVS recirculation fans were declared operable and the unusual event / plant
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shutdown terminated.
The unit remained in a 7 day LCO until the second
FRVS vent fan was declared operable.
As of 7:00 a.m. on July 30, the unit
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had returned to 100*; power.
The licensee has reviewed all "Q" systems and
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determined the only suspect ICD card calculations involve pitot tubes used
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for flow measurement in heating, ventilation, and air conditioning (HVAC)
systems. As corrective action, the licensee has committed to.
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Conduct a detailed review of all "Q" pitot tube instrument ICD
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card calculations to verify agreement with the test package
review and infield configuration.
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Conduct a detailed review of all "Q" ICD card calculations
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altered subsequent to the startup test program.
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In addition, the remaining 2000 safety related ICD cards will be
verified within the next 4 months (7,000 safety related ICD.
cards have already been verified).
Also as part of this
commitment, for any instrument found to be in excess of 10
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percent of its normal tolerance band, the ICD calibration data
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will be verified correct prior to resetting the instrument.
This issue will be remain unresc'ved pending NRC review of the
significance of reduced FRVS flow rnes and the completion of licensee
corrective action.
(87-17-02)
9.
Bypass of Non-Essential Diesel Generator Trips (Region TI:87-04)
The inspector reviewed the detailed logic for diesel engine trips and the
integrated emergency diesel generator surveillance test, and held
discussions with the system engineer. All non-essential emergency diesel
generator trips are bypassed for a loss of coolant accident (LOCA), loss
of offsite power (LOOP) or both simultaneously. The only automatic diesel
trips active during a LOCA or LOOP signal are:
a switchgear fault, low
lube oil pressure, and engine overspeed.
The switchgear fault trip
includes generator differential current, generator overcurrent, and bus
differential current trips.
The capability to bypass non-essential diesel
trips with a LOCA or LOOP signal present is routirely tested during the 18
month integrated diesel surveillance test (0P-ST.KJ-008).
No violations were identified.
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10.
Review of Licensee Written Reports
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The licensee submitted the following event and routine reports during the
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inspection period.
These_ reports were reviewed for accuracy and timely _
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submission.
The asterisked reports received additional followup by the
inspector for corrective action implementation.
The (#) items iden.tify
reports which involve licensee identified technical specification
violations which are not being cited based upon meeting the criteria of
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Monthly Operating Report for June, 1987
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LER 87-023
Technical Specification Violation'- Emergency Diesel
Generators B and C Starting Air Pressure Low Due to Alarm
Setpoint/ Technical Specification' Inconsistency
LER 87-024
Unanticipated Primary Containment Isolation System (PCIS)
Trip - ESF Actuation
LER 87-025
Non-Conservative Liquid Effluent Sampling Frequency Due to
Inconsistency Between Technical Specification Requirements
and Procedural Requirements
LER 87-026
Technical Specification Violation - MOV Thermal Overloads
Installed Without Bypass Capability Due to Inadequate
Technical Specification and Design Reviews
LER 87-027
Spurious Isolation of High Pressure Coolant Injection
Inboard Steam Isolation Valve Due to Failed Temperature
Module
LER 87-028
Isolations of the RWCU System of High Differential Flow
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Due to Design Deficiencies
LER-023 details the events which resulted in the "B" and "C" emergency
diesel generators (EDG) starting air pressures dropping below the minimum
technical specification (TS) limit.
The "B" and "C" EDG air compressors
had both been turned off by an operator checking compressor oil levels
who subsequently failed to return the compressors to automatic operation.
A contributing cause of this incident was a low air pressure alarm that
is set at a value below the TS limit, and this does not provide warning
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of low system pressure prior to exceeding the TS limit.
Corrective
action included an addition to operator logs to periodically check _the
status of starting air compressor handswitches, changing the method of
checking compressor oil level which precludes switch operation, and a
review to resolve the actual alarm setpoint and TS operability
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requirements. This constitutes a licensee-identified ~TS violation.
(87-17-03)
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LER 87-025 describes a station procedural deficiency in the sampling
frequency requirements for composite-tritium and gross alpha which
resulted in.a violation of TS sampling requirements _ The root cause of
this TS and station procedure inconsistency was an inadequate review'of
final draft TS by the TS coordinator.and responsible chemistry department
reviewers.
Immediate corrective actions included revising the affected-
chemistry department procedure and reviewing all other chemistry
department procedures against TS surveillance requirements.
Long term
corrective actions consist of reviewing current station administrative
programs to e m ure adequate identification of TS changes to affected
departments.
This constitutes a licensee-identified TS violation.
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(87-17-04)
LER 87-026 describes the failure to install required thermal overload
protection bypass circuits on service water intake screen spray wash
isolation valves and the turbine auxiliary cooling to' safety auxiliary
cooling system return isolation valves.
This failure was cited as a
violation and is discussed in detail in paragraph 3.2 of NRC inspection
report 354/87-16.
LER 87-028 describes two reactor water cleanup (RWCU) isolations on
high differential flow due to design deficiencies. The first RWCU
isolation occurred during an attempt to backwash the resin trap.
The
second RWCU isolation occurred due to leak-by through the RWCU precoat
inlet valve.
The RWCU system is susceptible to high differential flow
isolations because the leak detection flow transmitters ar'e only partially
compensated for temperature and density differences. Without this com-
pensati,an, the leak detection logic can sense high system leakage due to
temperature differences at the inlet and outlet of.the system when
a smaller leakage actually exists.
The licensee believes that RWCU
isolations are a result of this lack of temperature / density compensation
coupled with water leak-by between single isolations valves which separate
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the high and low pressure portions of the RWCU system. .The latter
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leakage is normally manifested during resin trap backwashing evolutions.
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As corrective action, the licensee has made procedural and operational
changes to improve the performance of resin trap backwashing. The procedure
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for operation of RWCU has been revised to explicitly define the valving
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sequence to be followed when backwashing an outlet resin trap.
The chemistry
department has instructed their technicians not to backwash the outlet
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resin traps unless the associated filter / demineralized (F/D) is out of
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service and depressurized. As long term corrective action, the licensee
plans to complete installation of the following design changes prior to
the first refueling outage.
A design change to RWCU F/D logic to allow a F/D to be returned to
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service following a RWCU isolation without having'to backwash the F/D
first. This change will permit the F/D to be reset and returned to
service immediately rather than having to be.first backwashed and
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precoated.
This change will reduce the frequency of backwash /precoat
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operations necessary and also reduce'the volume of radwaste
generated.
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A second design change will provide double valve isolation prior
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to pressurizing the F/D. This design change will reduce the
number of isolations caused by seat leakage on the single
isolation valves which form the pressure boundary between the
high and low pressure portions of the RWCU system.
11. NRC Region I Administrator's Visit
William Russell met with licensee management and toured the'PSE&G
Nuclear Training Center on August 3, 1987, and inspected the Hope
Creek Generating Facility the following day.
The inspection included
the control room, reactor building, diesel generators, IE switchgear,
and the remote shutdown panel.
12. Unresolved Items
Unresolved items are matters about which more information is required
in order to determine whether they are acceptable, an item of
noncompliance or a deviation.
Unresolved items disclosed during the
inspection are discussed in paragraph 8.
13.
Exit Interview
The inspectors met with Mr. S. LaBruna and other licensee personnel
periodically and at the end-of the inspection report to summarize the
scope and findings of their inspection activities.
Based on Region I review and discussions with the licensee, it was
determined that this report does not contain information subject to
10 CFR 2 restrictions.
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