ML18153B881
| ML18153B881 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 09/01/1989 |
| From: | Fredrickson P, Holland W, Larry Nicholson, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18153B879 | List: |
| References | |
| 50-280-89-21, 50-281-89-21, NUDOCS 8909140004 | |
| Download: ML18153B881 (26) | |
See also: IR 05000280/1989021
Text
,,
Report Nos. :
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION 11
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
50~280/89-21 and 50-281/89-21
Licensee:
Virginia Electric and Power Company
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50-281
Facility Name:
Surry 1 and 2
Inspection Conducted:
July 2-29, 1989
License Nos.: DPR-32 and DPR-37
<*~ ~~//
Inspectors:
~)?/.
~~
W. * E. Ho 11 ang:sei, o.rResi dent Inspector
J. W~Re~~r --~
L. E.3ifichoison, Resident Inspector
Accompanying I~
7: _t_Bre~ au, Be actor Engineer
Approved by: C.,--! I (]~'1,.-,VI/Vr:?J,/~
P. E. Fredrickson, Section Chief
Division of Reactor Projects
SUMMARY
Scope:
Date Signed
1/11~~1
Date Signed
1/i/Y2
Date'Signed
7/t/P}
Daite Signed
This routine resident inspection was conducted on site in the areas of plant
operations, p 1 ant maintenance, p 1 ant survei 11 ance, 1 i censee event report
review, followup on inspector identified items, and plant startup from
refueling.
Certain tours were conducted on backshifts or weekends.
The resident staff
maintained 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> coverage of the Unit 1 startup beginning on July 2 and
continuing through the return to power operations on July 7.
In addition,
backshift or weekend tours were conducted on July 8, 9, 15, 16, 17, 18, 19, 20,
23, and 29.
Results:
During this inspection period, three violations were identified for:
failure
to provide adequate procedures and/or instructions for calibration of the power
range nuclear instrumentation as required by Technical Specification 6.4
- 390':/ 140004
!='DR
A:OOCK
G!
.
- 3 l~J () '7' (> 1
osooo2::::o
F'DC:
- ---!.-.. :,
2
(paragraph 3.a); failure to place an inoperable canal level instrument in trip
within one hour as required by Technical Specification Table 3.7-2, Item 5.a
- (paragraph 3.g); and failure to maintain the condensate storage tank level at
or above the limit specified in Technical Specification 3.6.B.2 (pargraph 3.g).
Two unresolved items *were identified:
one regarding the reportability in
accordance-with 10 CFR 50.72 of two events which resulted in the tripping of
safety-re 1 ated chi 11 ers and charging pump service water pumps (paragraph 3. g),
and the other involving the licensee's program to effectively implement
requirements that are invoked by amendments to the technical specifications
(paragraph 6.h).
-
In addition, a weakness was identified during the Unit 1 restart with regards
to multiple procedure concurrent usage and a lack of sensitivity to initial
conditions in procedure (paragraph 3.a).
Also, a weakness was identified
regarding.the transmittal of data used by operations for reactivity calcula-
tions (paragraph 6.g) .
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
2 .
W. Benthall, Supervisor, Licensing
R. Bilyeu, Licensing Engineer
R. Blount, Superintendent of Technical Services
D. Christian, Assistant Station Manager
D. Erickson, Superintendent ot Health Physics
- E. Grecheck, Assistant Station Manager
- M. Kansler, Station Manager
T. Kendzia, Supervisor, Safety Engineering
- J. McCarthy, Superintendent of Operations
- G. Miller, Licensing Coordinator, Surry
J. Ogren, Superintendent of Maintenance
T. Sowers, Superintendent of Engineering
A. Price, Site Quality Assurance Manager
Other licensee employees contacted included control room operators, shift
technical advisors, shift supervisors and other plant personnel.
- Attended exit interview
On July 24, i989, one of the Commissioners of the Nuclear Regulatory
Commission, James R. Curtiss, visited the Surry Power Station for a
familiarization tour, to meet with licensee management and staff, and to
review the current status of the station.
Commissioner Curtiss was
accompanied by the following personnel:
A. Gibson, Director, DRS, Region II
K. Connaughton, Technical Assistant to the Commissioner
M. Sinkule, Branch Chief, DRP, Region II
NRC Resident Inspectors
The Commissioner attended the morning management meeting, met with the
resident inspectors, was given a presentation on the status of the station
by licensee management, and was taken on a tour of the station including
the turbine building, control room, emergency diesel generator rooms, and
the independent spent fuel storage installation.
Acronyms and intialisms used throughout this report are listed in the last
paragraph.
Plant Status
Unit 1 began the reporting period in intermediate shutdown with a slow
heat up in progress.
The unit reached hot shutdown on July 4, and the
2
reactor was taken critical on July 5, 1989.
Physics testing commenced the
same day and was completed on July 6.
The unit was operating at 63% power
when an automatic reactor trip occurred at 0643 hours0.00744 days <br />0.179 hours <br />0.00106 weeks <br />2.446615e-4 months <br /> on July 9, 1989r
The trip, which is discussed in paragraph 3.~, was appropriately reviewed
and the unit was returned to criticality at 2353 hours0.0272 days <br />0.654 hours <br />0.00389 weeks <br />8.953165e-4 months <br /> on the same day.
The unit recommenced power operation on July 10 and remained at power for
the remainder of th~ period.
Unit 2 began the reporting period in cold shutdown.
The unit remained in
cold shutdown for the duration of the inspection period while substantial
operational reviews and maintenance activities were being conducted.
During the period, the hydrostatic testing of the S/G feedwater 1 i ne
repairs was accomplished.
3.
Operational Safety Verification (71707)
a.
Daily Inspections
The inspectors conducted daily* inspections in the following areas:
control room staffing, access, and operator behavior; operator
adherence to approved procedures, techni ca 1 speci fi cat i ans, and
limiting conditions for operations; examination of panels containing
instrumentation and other re~ctor protection system elements to
determine that required channels are operable; and review of control
room operator logs, operating orders, plant deviation reports, tagout
1 ogs, jumper 1 ogs, and tags *on components to verify compliance with
approved procedures. *
The inspectors specifically focused on Unit 1 restart activities
during the earlier part of the inspection period.
Twenty-four hour
monitoring coverage of the Unit 1 restart activities by the resident
inspector staff continued from the l_ast inspection period until
July 7, 1989.
During the monitoring of the Unit 1 startup, the inspectors noted
that the controlling procedures were not coordinated in a manner such
that one procedure would be completed prior to the next sequential
procedure being started.
One example was identified when OP-1.3,
Unit Startup Operation (350/450 to HSD), was not completed and
OP-1.4, Unit Startup Operation -
HSD to 2% Power, was being
accomplished at step 5.22 in the performance section.
Of special
concern was the fact that O.P-1.4, initial condition 3.2, required
that OP-1.3 be complete, yet the operators appeared to be comfortable
in OP-1. 4 without * a 11 initial conditions being verified and *
documented.
The inspector did verify, that the intent of OP-1.3 had
been *completed and that the operators were in proper control of the
startup; however, multiple procedures were unnecessarily being
performed concurrently and a lack of sensitivity to initial
conditions was apparent .
3
On July 9, 1989 at 0643 hours0.00744 days <br />0.179 hours <br />0.00106 weeks <br />2.446615e-4 months <br />, Unit 1 experienced an automatic reactor trip from approximately 63% reactor power.
The reactor trip
was caused by a turbine trip which was initiated by a high level in
SIG B.
The high level in S/G B was caused by a transient
(approximately 30% turbine runback in about 9 seconds) due to the
protect ion circuitry sensing a rod drop condition on power range
channel N41.
The unit did not ride out the transient due in part to
B S/G .feedwater regulating valve being in manual control, rod control
being in manual, and an inadvertent operator action in closing the
main steam dump valves.
The operator actions were due to
misdiagnosis of the transient.
All safety systems functioned as
required during and after the reactor trip.
However, source range
channel N31 failed to reinstate automatically after the reactor trip
due to improper compensation of intermediate range channel N35.
Operators took the necessary actions to reinstate source range
channel N31.
After the trip, the plant was stabilized in the hot shutdown
condition.
The licensee held a post trip review meeting with those
operators involved in the trip,to review the sequence of events.
The
inspectors attended that meeting and with the information provided
from the meeting and other charts provided from computer printouts
determined the sequence of events as follows:
T0 minus 162 seconds - initiation of turbine runback signal
T minus 157 seconds - all steam dumps receive open signal
0
T
mi nus 153 seconds - turbine runback stops (approx. 50% load
r2duction)
T0 minus 145 seconds - all steam dumps open
T0 minus 120 seconds - S/G A, Band C level at 25%
T0 minus 96 seconds - S/G A, B, and C level at 32%
T0 minus 48 seconds - S/G A and C level at 44%; S/G B level at 55%
T minus 40 seconds - steam dumps receive close signal by operator
aetion
T0 minus 24 seconds - S/G A and C level at 50%; S/G B level at 68%
T0 minus 5 seconds - steam dumps start to close
T minus 2 seconds - S/G A and C level at 54%; S/G B level at 75%;
tSrbine trip
T0 - reactor trip
4
T plus 12 seconds -
steam dumps receive open signal based on
oSerator action and Tave-Tref mismatch
-
T0 plus 20 seconds - steam dumRs full open
T0 plus 50 seconds - steam dumps mostly closed due to Tave-Tref match
As shown above, the initial transient caused the S/G to decrease in
level (shrink).
Steam generators A and C were in automatic feed
control and were maintained in a band which would not have resulted
in a turbine/reactor trip.
However, B S/G feed control was in manual
due to the automatic control experiencing some electrical problems
earlier.
Operator action was required to maintain the proper SIG
level during the transient.
Due to an apparent overfeeding of the B
S/G during the early part of the transient to compensate for shrink,
the B S/G level increased to the turbine trip setpoint (75% level)
~pproximately 2 minutes and 40 seconds after the transient began,
resulting in the turbine trip/reactor trip.
After evaluation of the transient, the inspectors focused
specifically on the cause of the turbine runback.
During the
licensee's post trip review meeting with the operators, the licensee
determined that the cause of the transient was due to a blown control
fuse in NI cabinet N41.
The bl own fuse was caused by the I&C
technicians use of an ungrounded volt meter during recalibration of
the NI flux setpoints.
It was also noted that several discussions
had been held between the I&C technicians and their supervisor on
~hether to use a grounded or an ungrounded meter during the calibra-
tion.
However, no clear resolution was provided to this concern
prior to the mistake being made.
Also, the procedure used for the
calibration did not specify the type of meter to use.
The inspectors, after hearing the discussions above, concluded that
the I&C shop sensitivity to resolving problems prior to them becoming
a significant event was not what is required to ensure that safety
systems would not be unnecessarily challenged.
The inspectors
discussed this concern with station management and were reassured
that ensuring that the job is correctly performed each time is a
requirement.
This assurance was confirmed by aggressive management
actions with regard to changes in the shop supervision along with
other personnel actions.
The licensee also instituted a performance
improvement program in the I&C area.
After reviewing *all the above, the inspectors concluded that
appropriate corrective actions were being implemented; however, the
above event was a result of a failure to provide adequate procedure
and/or instructions for calibration of components involving the
nuclear safety of the station. Technical Specification 6.4 requires
that detailed written procedures with appropriate*check-off lists and
5
instruct ions be provided for calibration of instruments, components,
and systems involving the nuclear safety of the station.
Failure to
provide an,adequate procedure and/or instruction for calibration of
the power range nuclear instrumentation is a violation of TS 6.4
(280/89-21-01).
b.
Weekly Inspections
The inspectors conducted weekly inspections in the following areas:
verification of operability of selected ESF systems by valve
alignment, breaker positions, condition of equipment or component(s),
and operability of instrumentation and support items essential to
system actuation or performance.
Plant tours were
conducted which
included observation of general plant/equipment conditions,* fire
protection and preventative measures, control of activities in
progress, radiation protection controls, physical security controls,
plant housekeeping conditions/cleanliness, and missile hazards.
The
inspectors routinely monitored the temperature of the auxiliary
feedwater pump discharge piping to ensure steam binding is prevented.
- c.
Biweekly Inspections
The inspectors conducted biweekly inspections in the following areas:
verification review and walkdown of safety-related tagout(s) in
effect; review of sampling program (e.g., primary and secondary
coolant samples, boric acid tank samples, plant liquid and gaseous
samples); observation of control room shift turnover; review of
implementation of the plant problem identification system; verifica-
tion of selected portions of containment isolation lineup(s); and
verification that notices to workers are posted as required by
-
d.
Areas Inspected
Inspections included areas in the Units 1 and 2 cable vaults, vital
battery rooms, steam safeguards areas, emergency switchgear rooms,
diesel generator rooms, control room, auxiliary building, Unit 2
containment, cable penetration areas, independent spent fuel storage
facility, low level intake structure, and the safeguards valve pit
and pump pit areas. Reactor coolant system leak rates were reviewed
to ensure that detected or suspected 1 eakage from the system was
recorded, investigated, and evaluated; and that appropriate actions
were taken, if required.
The inspectors routinely independently
calculated RCS leak*rates using the NRC Independent Measurements Leak
Rate Program (RCSLK9).
On a regular basis, RWPs were reviewed and
specific work activities were monitored to assure they were being
conducted per the RWPs.
Selected radiation protection instruments
were periodically checked, and equipment operability and calibration
frequenci were verified.
6
The residents observed chemical analyses being performed for boron
concentrations in the hot laboratory.
These analyses were for
operations information and to support certain parameter requirements
being used in physics testing.
On July 7, 1989, the inspectors
discussed with chemistry personnel a reactor power level hold at 30
percent because chlorides on the secondary side were 34 ppb.
Chemistry limits are 20 ppb chlorides.
The chloride level was
lowered by using S/G blowdown and adding clean makeup water.
The
licensee
1 s chemist stated that it is not unusual to have chloride
spikes after having a unit down for such a long period of time
(Unit 1 had been down 10 months).
A 11 actions appeared to be
conservative.
e.
Physical Security Program Inspections
In the course of monthly activities, the inspectors included a review
of the licensee
I s physical security program.
The performance of
various shifts of the security force was observed in the conduct of
daily activities to include:
protected and vital areas access
controls; searching of personnel, packages and vehicles; badge
issuance and retrieval; escorting of visitors; and patrols and
compensatory posts.
f.
Licensee 10 CFR 50.72 Reports
(1)
On July 9, 1989, the licensee made a report in accordance with
10 CFR 50. 72 with regards to an automatic reactor trip/turbine
trip on Unit 1.
Details of this event are discussed in
paragraph 3.a.
(2)
On July 9, 1989, the licensee made a report in accordance with
10 CFR 50. 72 with regards to degradation of the emergency
assessment capability in that the SPDS displays from the ERF
computer were not functioning properly.
This condition occurred
during downloading of data from the Unit 1 reactor trip that
occurred earlier that day.
The licensee diagnosed the problem
as SPDS hardware related.
The problem was corrected and the
unit returned to power.
g.
Operations Related Problems
The inspectors expressed concern regarding i ndi cat ions of poor
operator performance that surfaced during the latter part of the
inspection period.
Discussions were held with appropriate levels of
station and corporate management with everyone in agreement that
operator performance warranted corrective actions.
Specific examples
of the problems included the following:
(1)
7
Intake Canal Level Instrumentation
- On July 14, 1989, the licensee identified via stati~n deviation
S2-89-610 that an inoperable intake canal level channel was not
placed in the tripped condition within one hour as required by
TS Table 3.7-2, Item 5.a.
Channei III of the intake canal level
instrumentation system was rendered inoperable when stop logs
were installed in accordance with TM S2-89-76 at 1210 hours0.014 days <br />0.336 hours <br />0.002 weeks <br />4.60405e-4 months <br /> on
July 14, 1989.
The channel was not placed into a tripped
condition until 1910 hours0.0221 days <br />0.531 hours <br />0.00316 weeks <br />7.26755e-4 months <br /> that day.
Further evaluation of this
event by the licensee revealed that a similar event occurred
when Unit 1 exceeded the 350 DEGF/450 PSIG 1 imitations on
July 2, 1989, and ~ont i nued ope rat ion with an inoperable level
channel until July 5, 1989, without placing the channel in the
tripped condition.
The safety consequence during these two
evolutions were minimal, however, due to the waterbox being
dewatered and therefore causing the level channel to
automatically go to the trip condition.
Previous SSFI issues required the installation of four
independent level indicators at the high level intake structure
that provide input to a 3 out of 4 logic circuit for initiation
of non-essential SW isolation.
The four level sensors. are
located in the i ndi vi dual high level intake screenwe 11 bays
(Unit 1-bays
18
1 and
1D
1
, Unit 2-bays
1A
1 and
1C1 ), between the
rotating screens and trash bar racks.
This is a shared system
that provides input to both units ESF logics.
The stop logs are
essentially large plates that are installed in the canal at the
intake structure and a 11 ow dewateri ng of the pl ant systems
downstream of the intake structure.
The installation of stop
logs on the bays that contain the level instrumentation isolates
the level sensors from the actual canal.
The operators failed to realize that installation of stop logs
on certain Unit 2 intake structures rendered the downstream
level . indicators inoperable that were required for Unit 1
operation.
The affected channel automatically goes to the
tripped position, however, when the waterbox is dewatered below
the actuation setpoi nt.
A review of the sequence of events
revealed that the licensee operated for approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />
with a less conservative 3 out of 3 logic instead of the
required 3 out of 4.
A sequence of events is summarized as follows (times indicated
in parentheses):
6/14/89
6/23
New level system placed in service.
Technical Specification amended requiring system
operability.
...
. ..,-:.*
6/25
7/2 (2200)
7/5
(2100)
7/14 (1210)
7/14 (1521)
7/14 (1910)
7/17 (1157)
8
Stop log installed & unit 2-A waterbox dewatered.
Unit 1 enters mode requiring operable level
instrumentation.
Unit 2-A waterbox refilled and stop logs removed.
Unit 2-A stop logs installed.
Unit 2-A waterbox dewatered.
Canal level channel III placed in trip.
Unit 2-A stop logs removed.
The stop logs were installed and removed using the station TM
system as prescribed in stat ion admi ni strati ve procedure
SUADM-0-11.
The station does not have a specific procedure
outlining the method and precautions involved with stop log
installations.
The inspectors reviewed the TM log sheets for
the installations noted above and concluded that an inadequate
review and analysis were performed prior to authorization by the
shift supervisor for stop lo~ installation.
Paragraph C.2 of
the subject TM logs was marked
11 N/A
11 , therefore deleting any
need for a safety analysis or 10 CFR 50.59 review for the impact
on the UFSAR or TS requirements.
In addition, subsequent
review of this TM by both the Superintendent of Operations and
the SNSOC failed to identify and correct the 1 ack of a review or
analysis on the initial TM stop log installation.
The inspectors reviewed th~ training lesson plans given to all
licensed operators regarding the installation of the new canal
level instrumentation.
Three separate lesson plans contained
information on the location and function of the* new sensofs.
Although the fact that the stop log installation would interfere
with the level sensors was not specifically detailed in the
lesson plans, the inspector concluded that sufficient training
was conducted.
-
The licensee performed a human performance evaluation of this
event and presented the preliminary findings to the resident
inspector staff on July 24 and 25.
A general conclusion was
given that this problem was essentially a human performance
problem with a lack of attention to detail.
In addition,
several weaknesses were identified that contributed to the TS
violation.
The inspectors reviewed the licensee 1s evaluation of
this situation and agreed with the following conclusions:
No procedures existed for the installation and removal of
stop logs.
This work was performed under a TM with no
formal procedure in place.
(2)
9
The closeout process for the design change package that
installed the new level system. failed to adequately
identify the need for revision of applicable procedures.
The review and safety analysis of the TM that installed and
removed the stop logs*were inadequate.
Technical Specification Table 3. 7-2, Item 5. a, requires that
i noperab 1 e 1 ow intake cana 1 1 eve 1 channe 1 s be p 1 aced in a
tripped condition within one hour.
failure to place the low
intake canal level channel III in a tripped condition when it
became inoperable on July 14, 1989, is a violation of the TS
(280/89-21-02).
Corrective actions were being evaluated by the licensee as the
inspection period ended.
A standing order (S.O. 10) was issued
on July 27 that * requires the Superintendent of Operations
approval prior to installation of stop logs.
Service Water Cooling
On July 18, 1989, a total Joss of SW cooling to the Units 1 and
2 charging pumps occurred apparently due to the operation of an
adjacent MOV and therefore connecting an empty line to the SW
flowpath.
A six hour LCO to place the unit in .hot shutdown was
initiated after both SW pumps to the charging pumps became
airbound.
In addition, since the Unit 2 SW pumps also became
ai rbound, -a seven day LCO was entered due to the 1 oss of
crosstie charging capability.
A report of this event was being
p*repared in accordance with 10 CFR 50. 73.
Maintenance was
performing stroke testing on
a
(2-SW-MOV-201A) that supplies water to the Unit 2 bearing
cooling water heat exchangers when the event occurred.
The six
inch SW supply to the subject pumps taps off a thirty-six inch
supply line to the bearing ~oolers.
The perturbation occurred
when the large MOV was cycled open.
The licensee stated at the
time that air in the large bearing cooling line was drawn into
the suction of the safety-related SW lines .and resulted in the
air binding.
Station engineering later stated, after the
July 23 event, {see next paragraph), that the SW discharging to
a basically empty Unit 2 discharge tunnel could have contributed
to pulling air back up into the system.
The system configura-
tion contributes to the problem in that the SW charging pumps
for both units (1 & 2- SW-P-10 A & B) and all three main control
room envelope chillers take SW suction off a common header.
Air
entrainment into this common header results in a loss of both
trains of equipment for both units.
10
On July 23, 1989, operation of the SW system again resulted in a
total loss of SW to mechanical equipment room #3, which resulted
in a loss of main control room envelope chillers and cooling
water to the charging pumps.
This event was similar to that
discussed above in that it was initiated by the operation of a
SW valve (2-SW-MOV-2018) to the Unit 2 bearing cooling water
heat exchanger.
Although system engineering could not identify
the exact cause of this pertubation, it does indicate that the
operation of the SW system is extremely sensitive to pertuba-
t ions in thfs area.
The ope rat ions staff was aware of the
previous event and was prepared to close the bearing cooling
valve upon indications of air binding.
It became apparent
following this event that the full implications of discharging
to an empty un*it 2 discharge tunnel was not understood.
The
1 i censee is prepa*ri_ng a report to the NRC on this event in
accordance with 10 CFR 50.73.
During the event on July 23, the inspector was in the control
room during part of the recovery of some of the components.
The
inspector observed that the operators were fo 11 owing the
required procedures; however, with the loss of multiple
components, it was noted that 1 imited guidance was provided
regarding the appropriate sequence of recovery for components.
Also, the.inspector observed recovery operations at the location
of most of the components (MER3) and again concluded that
procedural . guidance regarding the appropriate venting of the
system was not available to the operators.
These areas are
under review by the licensee for possible enhancements.
The inspectors questioned the licensee with regards to
reportability of the two above events as required by
10 CFR 50. 72.
The licensee stated that although there is no
formal analysis documenting an acceptable dufation of operation
without SW cooling, they have historically been able to vent the
air from the system and restore flow prior to any adverse
effects on the charging pumps.
A review of the Unit 2 charging
pump data during the 47 minute duration that the SW was
inoperable indicated that the thrust bearing temperature
increased over that period.
The inspection period ended prior to reso 1 ut ion of the
reportability of these events~
This issue is identified as an
unresolved item (280/89-21-03) pending additional
NRC and
licensee review of reportability and appropriate classification
of charging pump operability.
(3)
Component Cooling Water Perturbation
On July 26, 1989 at 2119 hours0.0245 days <br />0.589 hours <br />0.0035 weeks <br />8.062795e-4 months <br />, operators were attempting to
refill a CCW heat exchanger (1-CC~E-18) and caused a rapid level
_)
11
drop in the CCW head tank that resulted in low CCW pump
discharge header pressure and an automatic start of a standby
pump.
The motor amperage *for the running CCW pumps fluctuated,
but th~ reactor coolant* pump parameters remained stable during
this transient.
The procedure used to return the heat exchanger
to service, MOP-1.6, Return To Service Of Safety Related Heat
Exchangers (Generic), is a generic procedure with no instruc-
tions pertaining to the CCW heat exchangers.
The inspectors reviewed this event and discussed the facts with
station management.
The transient was formally identified on
station deviation Sl-89-1752 that was submitted on July 27.
The
immediate safety consequence of this event is a loss of cooling
to the reactor coolant pumps on Unit 1.
Component cooling also
provides cooling to the RHR system and various primary heat
exchangers.
The licensee stated that this event was caused by a
lack of adequate supervision of an inexperienced auxiliary
operator.
Corrective act i ans were being developed as the
inspection period ended.
Although this event was not considered to be a violation of
regulatory requirements, the inspector agree with licensee
managements assessment that proper overview and ctintrol of an
evolution which could affect the safe operation of the station
must be maintained.
(4)
Emergency Condensate Storage Tank Level Drop
On July 27, 1989, operators allowed the level in the Unit 2
emergency condensate storage tank (2-CN-TK-1) to fall
approximately 10,000 gallons below the TS limit while trans-
ferring water to fill the underground condensate tank.
This
condition is 1n violation of TS 3.6.B.2 that requires a minimum
of 60,000 galloni of water be available from the opposite ~nit
to supply the auxiliary feedwater crossconneGt.
The transfer of water was being performed in accordance with
operating procedure 2-0P-31.2.5,
Filling The
Emergency
Condensate Makeup Tank, 2-CN-TK-3.
Section 4.0 of this
procedure references a requirement to maintain greater than
60,000 ga 11 ons in tank 2-CN-TK-1.
A review of the reactor
operator logs indicated that the level was adequate at 1000
hours and had fallen to 44 percent (50,000 gal) at 1400 hours0.0162 days <br />0.389 hours <br />0.00231 weeks <br />5.327e-4 months <br />.
The operator 16gged this level without realizing that the level
was in.violation of TS.
The problem was detected at 1822 hours0.0211 days <br />0.506 hours <br />0.00301 weeks <br />6.93271e-4 months <br />
and the tank level ~as refilled to greater than 60w000 gall~ns
by i844 hours.
Technical Specification 3.6.B.2 requires that a minimum of
60,000 gallons of water shall be available in the tornado
protected condensate storage tank of the opposite unit to supply
12
emergency water to the auxiliary feedwater pump suction of that
unit.
Failure to maintain greater than 60,000 gallons of water
in tank 2-CN-TK-l on July 27, 1989, is a.violation of TS
(280/89-21-04).
The above problems indicate a lack of attention to detail.
Two of the
events, i.e. stop 1 og and condensate l eve 1, are related in that the
operators for Unit 2 ~ere not sensitive to the effects of their action on
the opposite unit at power.
The SW events indicate that the performance
of this system is very sensitive to inappropriate operation.
Within the areas inspected, three violations and one unresolved item were
identified.
4.
Operational Readiness Program Review - Unit 2 (71710)
The inspectors reviewed the Unit 2 restart action items list.
Currently
75 of 211 items still remain open.
All of these items and any additional
items added to the list will be resol.ved before Unit 2 is restarted.
Items will be added as a result of the system walkdowns.
The licensee has
completed 100 percent of the system walkdowns in Unit 2 containment and is
evaluating the results.
A review of the containment charging and
ventilation systems revealed that six items would be added to the restart
list for the ventilation system and two would be added for the charging
system.
In the case of the six items, three involved cleaning filters and
three involved repairing or evaluating a valve.
In the case of the two
- items for the charging systems, one involved a missing flow transmitter
(the transmitter had been removed to repair one on Unit 1) and the second
item involved the necessity to add several supports for a charging line.
The inspectors reviewed selected findings from the system engineering
walkdown of the Unit 2 SI system.
A problem was identified (station
deviation S2-89-682) pertaining to the labeling of certain .valves and
instrumentation in the hot leg SI lines.
Components indicated on station
drawing 11548-FM-0898, sheet 4 of 4, as injection lines to the hot leg of
the reactor coo 1 ant loop 1 are actually associated with the hot leg
loop 3, and vice-versa.
The problem was limited to components downstream
of any MOVs or components requiring operator actions.
The Operations
Superintendent reviewed the situation and concluded that the problem would
not have an adverse effect on operation during any accident scenario.
The
inspectors reviewed the evaluations and concurred with the findings.
On July 22, 1989, the inspectors observed a Unit 2 containment walkdown
for parts of the auxiliary feedwater system and SIG blowdown system by
systems engineers. The methods used for the evaluation and the findings
appeared to be acceptable.
Within the areas inspected, no violations or deviations were identified .
,.,,"_ -
13
5.
Maintenante In~pections (62703 & 42700)
During the reporting period, the inspectors reviewed maintenance
activities to assure compliance with the appropriate procedures.
Inspection areas included the following:
'
a.
Pressurizer Power Oper~ted Relief Valve
b.
The inspectors reviewed the repair of the pressurizer PORV
2-RC-PCV-2455C following the valve failure that occurred on June 21,
1989.
The RCS was being maintained in a reduced inventory condition
with the PORVs open and vented to the primary relief tank.
The
control room operator n~ticed that the subject valve went from open
to close when the II Lo Air Bottle Press ure
11 annunciator came on.
The
operator attempted unsuccessfully to reopen the valve.
Field
inspections revealed that the valve actuator had cocked and several
cap screws within the actuator had sheared.
The backup air b'ott l es
had depressurized.
The inspectors observed certain failed parts from this valve and
reviewed the corrective actions and failure analysis associated with
this _event.
It appears that the regulator in the backup air bottle
supply failed and allowed the full 2400 psig pressure to be applied
- to the valve actuator.
The licensee performed an evaluation of the
failure as documented in EWR 89-499, dated July 8, 1989.
The results
of this evaluation concluded that this event did not constitute an
unreviewed safety question.
The inspectors reviewed the evaluations
and documentation pertaining to this event and agreed with the
licensee's assessment.
No discrepancies were identified.
Feedwater Regulating Valve
On July 14; 1989, the inspectors observed the repair on the Vnit 1
feedwater regulating valve 1-FW-FCV-1488.
This valve is the main
feedwater regulating valve for the B S/G.
The valve was sticking in
certain positions making it more difficult to control the water level
of the S/G.
In order to make the repair, the licensee reduced power
on Unit 1 to 19 percent, isolated the valve, and used the feedwater
bypass line to supply feedwater to the S/G .. The inspector observed
replacement of the valve cage and the double plug and stem. The
internal part of the valve and adjacent piping were inspected for
cleanliness and foreign objects.
The torquing technique for the cage
and some o*f the bolts was observed. The inspectors examined the
procedure being used, Procedure No.
MMP-C-FW-145, Disassembly,
Repair, Reassembly, and Testing of Feedwater Regulating Valve.
The
torquing values being used were in accordance with the procedure and
14
the appropriate steps were being initialed.
A later evaluation by
the 1 i censee showed that the va 1 ve externa 1 spring was rubbing
against one side of the yoke inhibiting it 1 s feedwater control
function.
No discrepancies were identified.
Within the areas inspected, no violations or deviations were identified.
6.
Surveillance Inspections (61726 & 42700)
During the reporting period, the inspectors reviewed various surveillance
activities to assure comp 1 i ance with the appropriate procedures as
follows:
Test prerequisites were met.
Tests were performed in accordance with approved procedures.
- Test procedures appeared to perform their intended function.
Adequate coordination existed among' personnel involved in the test.
Test data was properly collected and recorded.
Inspection areas included the following:
a.
Containment Spray System
On July 2, 1989, the inspector reviewed test documentation for
periodic test l-PT-17.1, Containment Spray System, for spray pumps
l-CS-P-18, tested on June 3, 1989 and both 1-CS-P-lA and 1-CS-P-18,
tested on June 12, 1989.
Documentation was complete; the test
results indicated that satisfactory performance was obtained, with
the exception that pump 18 was placed in an alert status due to high
axial vibration from the inboard bearing.
The licensee issued.EWR 89-433 to eva 1 uate the results, and subsequently determined and
approved on June 20, 1989, new reference va 1 ues based on prior
performances of the pumps.
These new values permitted the licensee
to remove pump 18 from an alert status.
No discrepancies were noted.
b.
Charging Pump Operability Test
On July 2, 1989, the inspector reviewed test documentation for
periodic test 1-PT-.18.7, Charging Pump Operability and Performance
Test, for charging pumps: 1-CH-P-lA, tested June 4, 1989, 1-CH-P-18,
tested June 18, 1989, and 1-CH-P-lC, tested June 27, 1989.
Documentation
was
complete;
results indicated satisfactory
performance with the exception of pump 18.
Pump 18 was placed in an
alert status due to a high axial vibration on the inboard bearing .
. -_ .. :-.--
15
The licensee had several !SI pumps listed in the alert status in June
due to high vibration measurements as compared to their respective
reference va 1 ues.
The 1 i censee issued EWR-89-445 to eva 1 uate the
existing base 1 i ne va 1 ues, which were es tab 1 i shed using computer
generated reference values taken by the predictive analysis group
over the last year.
It was determined that these values were not
reflective of actua 1 component operating conditions.
The 1 i censee
establish new reference values using the actual data from the last
two tests; these values were approved by SNSOC on June 27, 1989.
Based on these hew values, pump l-CH-P-18 was not ~onsidered as being
.in an alert status.
No discrepancies were noted.
c.
Motor Driven Auxiliary F~edwater Pumps
On July 3, .1989, the inspector reviewed periodic test l-PT-15.lA,
Motor Driven Auxiliary Feedwater Pump, for pumps l-FW-P-3A, tested on
June 9, 1989 and l-FW-P-38, tested on June 15, .1989.
Test results
indicated that both pumps were in an a 1 ert status due to high
vertical vibration on the outboard pump bearing.
The test critique
. sheet for pump 3A did not correctly reflect this condition however,
and the licensee was informed of this error *in documentation.
The
licensee promptly corrected the documentation discrepancy.
Based on
the new reference values noted in EWR 89-445, both pumps were removed
from an alert status by the licensee.
No further discrepancies were
noted.
d.
Containment Inside Recirculation Spray System
On July 3, 1989, the inspector reviewed periodic test l-PT-17.2,
Containment Inside Recirculation Spray, for pumps 1-RS-P-lA and
l-RS-P-18, tested on June 21, 1989.
Documentation was complete; test
results indicated that pump lA was satisfactory and 18 was unsatis-
factory because the ERFSC failed to display the required information.
The 1 i censee adjusted the ERFCS and retested pump 1B on June 23,
1989.
The test results indicated that pump 18 performance was
satisfactory.
No discrepancies were noted.
e.
Containment Outside Recirculation Spray System
On July 4, 1989, the -inspector reviewed periodic test-l-PT-17.3,
Containment Outside Recirculation Spray, for pump l-RS-P-2A, tested*
on June .16, 1989.
Documentation was adequate; test results indicated
that the pump was satisfactory but placed on the alert status due to
high axial vibration on the inboard bearing.
The new reference
values, which were subsequently determined by EWR 89-445, permitted
pump 2A to be removed from an alert status.
No discrepancies were
noted .
f.
16
Emergency Service Water Pumps
On July 4, 1989, the inspector reviewed periodic tests l-PT-25.3A,
- .38, and .3C, Emergency Service Water Pump, for pumps 1-SW-P-lA,
tested on June 20, 1989; and 1-SW-P-lB and 1-SW-P-lC, tested on
February 15, 1989.
Documentation was adequate and test results
- indicated that the pumps performed as desired.
No discrepancies were
noted.
g.
On July 4, 1989, the inspector witnessed hot rod testing of the
Unit 1 rods in accordance with periodic test 1-PT-7.2, Hot Rod Drops,
dated January 29, 1989.
This test measured the drop time for each of
the 48 control rods from fully withdrawn to dashpot entry.
The
inspector reviewed se 1 ected timing traces to independently verify
. that the drop time was within the 2.4 seconds allowed by TS.
Step 3.1 of the above test procedure requires the calculation of the
shutdown margin prior to changing core reactivity.
The inspector
reviewed the calculated shutdown margin and noted that the data used
(i.e. critical boron, rod worth, etc.) was supplied by the reactor
engineer in lieu of the curve book.
Although the procedure _that
performs this ca lcul at ion, OP-lF, specifies that approved data may be
supp 1 i ed by the reactor engineer, the data used for the above
calculation was obtained from a single sheet of paper marked
11 for
reference only
11 , with no revi'eW or approval process evident.
The
i nspec*tor revi e.wed the data and concluded that the figures used were
more conservative; however,
the use of the substitute data
constituted a revision to the station curve book without a comparable
review process.
The 1 i censee concurred that this is an apparent
weakness and plans to revise their method for supplying engineering
data regarding reactor startup.
The inspector reviewed a station
memorandum, dated July 24, 1989, that addressed this weakness and
out 1 i ned the need for improvement.
This i tern is i dent i fi ed as a
weakness with the control of data used for reactivity calculations.
h.
Reactor Trip Bypass Breaker
The inspectors reviewed the details regarding the inability to test
the automatic shunt trip feature on the reactor trip bypass breakers
as required by TS Table 4.1-1. This condition was identified by the
licensee (station deviation Sl-89-1646) dur1ng a review of the TS.
Because Surry does *not have automatic shunt trips on their reactor
trip bypass breakers, the licensee could not comply with the TS.
Amendment 117 to the TS, issued in 1987, required that the reactor
trip bypass breaker local manual undervoltage trip be tested prior to
placing the breaker in service and the automatic shunt trip be tested
17
every refueling.
A local manual undervoltage trip and an automatic
shunt trip feature do not exist at Surry.
The inspectors discussed
the existing breaker features with NRC regional management and NRR,
and ascertained that the existing condition is acceptab 1 e for
continu~d operations.
The .licensee is planning to submit a TS change
for this compliance issue.
The above discrepancy indicates a potent i a 1 weakness in the
licensee's program that implements TS requirements and assures that
compliance is achieved.
The fact that a specific requirement was
added in 1987 and the normal implementation and review/audit
functions did not identify that compliance was impossible until 1989
raises questions regarding the effectiveness of the programs.
This
item is identified as an unresolved item (280,281/89-21-05) pending a
more thorough review of the licensee 1 s program that implements TS
requirements.
Within the areas inspected, one unresolved item was identified.
7.
Licensee Event Report Review (92700)
The inspectors reviewed the LER's listed below to ascertain whether NRC
reporting requirements were being met and to determine appropriateness of
the corrective actions. The inspector's review also included followup on
implementation of corrective action and review of licensee documentation
that all required corrective actions were complete.
LERs that identify violations of regulations and that meet the criteria of
10 CFR, Part 2, Appendix C,Section V shall be identified as NCV in the
following closeout paragraphs.
NCVs are considered first-time occurrence
violations which meet the NRC Enforcement Policy for exemption from
issuance of a Notice of Violation.
These items are identified to allow
for proper evaluations.of corrective actions in the event that similar
events occur in the future.
(Closed) LER 280/88-021, Lifting of PORV Due to Overly Conservative
Setpoint:
This event was initiated with Unit 1 in cold shutdown, and was
caused by a pressure transient during a start of the RCP with a solid
plant.
The licensee
1s corrective actions, which included increasing the
PORV lift pressure setpoi nt by 10 lbs. to account for instrument
inaccuracies and revising operating procedure OP-5.1.2 to reflect the
desired RCP operations during solid water plant conditions appeared to be
adequate.
This LER is c~osed.
(Closed) LER 280/88-023,
11C
11 S/G Steam Flow Channel IV Failed Low Due to
Failed Mult.iplier/Divider.
The licensee was not able to determine the
cause for the fai 1 ed multiplier/divider power supply transformer.
However, corrective actions were routine, e.g., replaced failed component
and conducted logic circuit tests.
Since the reactor protection and SI
instrumentation is periodically tested and calibrated, no additional
corrective actions are necessary.
This LER is closed.
18
(Closed) LER 280/88-025, Control/Relay Room Chillers Inoperable Due to
Inadequate Service Water Flow.
The licensee believed that the cause of
the event was due to inadequate SW flow to the chiller condensers as a
result of the method used to start/stop the chillers.
The licensee's
corrective action consisted of developing a procedure for starting/
stopping,control room chillers.
The inspector determined from a review of
operating procedure OP-21.4, dated September 20, 1988, that the procedure
provides adequate details to operate the control room chillers.
This LER
is closed.
(Closed) LER 280/88-028, Spent Fuel Assembly Placed in Wrong Location Due
To Inadequate Procedure.
The licensee determined that the cause of this
event was due to deficiencies in the methods used when spent fuel movement
was initiated and directed by on-site personnel.
The licensee revised
procedure OP-4.22, dated May 9, 1989, to include a verification that
Region I spent fuel pool area contains only Region I applicable fuel
assemblies prior to moving a dry storage cask into the fuel building.
The
inspector I s review of this procedure indicated that the procedure is
adequate to prevent recurrence of this event.
This LER is closed.
(Closed) LER 280/88-034, Control Room Chiller Tripped Due to Inadequate
Service Water Flow.
This event was caused by pressure control valves
being incorrectly adjusted.
The licensee's corrective action of
overhauling and setting the pressure control valves to their correct
setting is similar to the corrective actions of LER 88-007, which is a
similar event.
The corrective actions for LER 88-007 included a design
review to upgrade the SW supply to the control room and relay room
chillers; this review is not complete.
The inspector believes that the
licensee I s actions for LER 88-034 are adequate, but wi 11 continue to
monitor the status of the design work to upgrade the SW supply to the
chillers.
This LER is closed.
(Closed) LER 280/88-035, Iodine Spike.
This event is suspected to have
been caused by fuel element defects.
The licensee I s corrective actions
consisted of inspecting the fuel assemblies during their outage coupled
with subsequent shipment of fuel assemblies.
The inspector noted during
this review that one leaking assembly was identified during the
inspections.
The licensee replaced the defective assembly and removed
debris from 10 other assemb 1 i es.
The i rispector considers the licensee
I s
corrective actions as adequate.
This LER is closed.
(Closed) LER 280/88-036, Charging Pump Component Cooling Pumps Inoperable
Due To Air Binding.
Thi~ event was caused by an inadequate system design
in that the system does not allow for adequate venting of the CCW side of
the intermediate seal coolers, without air binding of the pumps, after the
system has been opened for maintenance.
The licensee's corrective action
consisted of performing an engineering review to resolve system design
inadequacies.
The inspector determined that the licensee has installed
high point vents to mitigate future air binding problems and that related
- __ ., _.-.- ... -~,>-_
., --------
~~-.-,....:~.--.;-ro..,;..
19
drawings and procedures have been adequately updated to reflect these
changes.
This LER is closed.
(Closed) LER 280/88-037, Fire Watch Not Posted at Improperly Sealed
Pe net rat ion Within One Hour Due to Personnel Error.
The cause of this
event was attributed to the failure of a* QA inspector in promptly
reporting the unsealed penetration to the control room.
Also, operations
personnel, once notified, failed to post a fire watch within one hour.
The licensee
1s corrective actions consisted of personnel being counseled
on the need to take prompt corrective act ions when discovering or
receiving reports of any abnormal plant conditions.
The inspector
believes these actions are aqequate to prevent recurrence.
This LER is
closed.
~
(Closed)
LER 280/88-039, Control/Relay Room Chillers Trip Due To
Inadequate SW Flow.
This event was cause by a small refrigerant leak in
combination with insufficient SW cooling.
SW flow was being controlled
manually because normal pressure control valves were out of service, thus
preventing automatic increase in SW flow when higher demand was required.
The lice~see
1s corrective action was to overhaul the pressure control
valves * and recharge the refrigerant.
The inspector I s review of the
licensee
1 s corrective action indicated that these actions were adequate.
This LER is similar to LERs88-007 and 88-034, which substantiates the
need for the licensee to resolve SW flow design problems with this system.
The actions of this LER are adequate, but as noted above, the inspector
will monitor the licensee
1s design review to resolve SW flow problems.
This LER is closed.
(Closed) LER 280/88-042, Process Ventilation System Hi-Range Radiation
Monitors Out of Service Due to Failed Circuit Board.
The licensee 1s
corrective action consisted of replacing the failed circuit board, and is
considered adequate.
This LER is closed.
(Closed) LER 280/88-043, RSHX SW MOVs Discovered With Wrong Size Torque
Motors.
This event was
noted during the 1 i censee I s engineering
evaluation, conducted in response to IE Bulletin 85-b3.
The above MOVs
were noted as having undersized motors.
The licensee
1 s corrective actions
included replacing the undersized motors with the required 5 ft-lb torque
motors and expanding the MOV program to include all safety-related MOVs.
The inspector determined that the correct motors were installed and that
the licensee expanded its MOV program.
The MOV program is tracked as part
of commitment 89-0101-001 in response to NRC Inspection Report 280,281/88-45.
The licensee
1s corrective actions are adequate.
This LER is closed.
(Closed) LER 280/88-044, Unplanned Actuation of ESF Components, TV-DG-108A
and SOV-VS-101A.
This LER is germane to both units.
The event was
presumed to occur due to personnel in the area of the SOV disturbing it,
resulting in its actuation.
No conclusive evidence for the cause of this
20
event was determined in the ensuing investigation.
The licensee's actions
included normal refueling SI functional testing during the outage to
ensure operability.
This testing will be completed prior unit startup.
The inspector's review concluded that successful SI testing was completed
for Unit 1.
This corrective action is considered adequate.
This LER is
closed.
(Closed) LER 280/88-046, Operating MCR/ESGR Chi 11 er Turned Off Due To
Personnel Error.
The cause of this event was attributed to the control
room shift supervisor incorrectly assuming that only one chiller was in
operation, therefore, when l-SW-263 closed, the shift supervisor
incorrectly assumed all SW to the chillers had been isolated.
The shift
supervisor thus directed a control room operator to stop the
11C
11 chiller.
The licensee's corrective action consisted of counselling the shift
supervisor concerning his responsibility to maintain an accurate status of
plant components and systems.
The inspectors review determined that the
corrective actions are adequate.
This LER is closed.
(Closed)
LER 280/88-048, Diesel Fire Pump Batteries Not Seismically
Qualified.
This event was due to the failure in identifying the
operability concern of the* system when the deficiency was noted in
Jun~ 1986.
The licensee's corrective action consisted of re-em~hasizing
the policy of prompt reporting of discrepant conditions and to upgrade the
battery racks to meet seismic qualifications.
The inspector reviewed
these actions and determined that the battery racks meet seismic
~ualifications.
This LER is closed.
8.
Plant Startup from Refueling (71711)
During this inspection period, the inspectors witnessed selected portions
of the Unit 1 restart special testing as follows:
The inspectors witnessed testing and monitored activities associated with
periodic test l-PT-28.11, Startup Physics Testing.
This procedure was the
controlling procedure for several of the tests that were required to be
performed at low power. levels following refueling.
The inspectors
witnessed pre-test briefings, verified that specified conditions were met,
and witnessed selected portions of the following tests:
Reactivity Computer Accuracy Determination
This test determines the reliability range of the reactivity computer that
is used in subsequent testing by inserting and withdrawing control rods to
subtract or add react i vfty.
The computer was determined to be accurate
within plus or minus 30 pcm.
No discrepancies were noted.
Isothermal Temperature Coefficient
This test involves measuring the moderator temperature coefficient by
determining the effects of plant temperature changes on reactivity while
21
maintaining constant rod position and boron concentration.
The MTC was
determined to be -3.61 pcm/°F.
No discrepancies were noted.
Rod Swap Reference Bank Measurement
This test allows for measurement of rod worth (pcm) of the reference bank
(Cqntrol Bank 8) when fully inserted from 225 steps to O steps.
No
discrepancies were noted.
Integral Rod Worth Measurements Using the Rod Swap Technique
This test allows for determination of the differential rod worth of the
reference bank (Control Bank B) when each of the remaining rod banks is
fully inserted from 225 to O steps.
The* inspector witnessed se 1 ected
portions of this test when control banks C and D were the test banks.
During this testing, several urgent rod* control failure alarms were
received.
The operators were able to immediately clear the alarms.
The
cause of the a 1 arms was determined to be the rod bank se 1 ector switch.
Several times when the selector switch passed through the C control bank
position to another bahk position, the alarm would come in.
A deviation
report was written to identify the prob 1 em.
However, the 1 i censee
determined that the problem did not affect proper operation of the rod
control system and testing was completed. satisfactorily.
No other
discrepancies were notedr
In the areas inspected, no violations or deviations were noted.
9.
Allegation Case No. RI! 89-A-0010
a.
Background:
An individual, herein after referred to as the alleger, contacted
Region II staff and reported that a worker modified a cable tray
label (identification) to match the tray identification entered for
the cable on the pull ticket.
b.
Allegation Inspection:
The inspectors had discussions with two of the licensee 1 s engineers
concerning the marking and identification of electrical cable trays.
The engineers stated that the letter designations were the most
important part of the marking because these letters determine the
type of cable that will go into that tray. The designations are as
follows:
A- instrumentation cables
8- power cables
C- control cables plus power cables for up to 60 h.p. motors or 60
amperes .
22
The engineers stated that a 1 was added in front of the letter
designation, and was not important to the cable tray designation.
During an
NRC electrical inspection conducted May 10-12, 1989,
violation 280/89-12-01, failure to maintain cable tray covers in
place as required by Appendix R, was issued. As a result of this
violation, the licensee has agreed to walk down the cable trays,*
making sure that the cable trays are properly marked, and issue new
drawings as necessary.
The electrical engineer performing the walk down under EWR 89-283
found trays with numbers pee 1 ed off, trays with added numbers
(numbers added with ink markers), and trays that had the wrong color
code. The new markings will be of a standard height and stenciled
onto the cable tray.
All of the trays in Unit 1 containment were
walked down before startup.
Unit 2 containment will be walked down
before startup.
c.
Conclusions
Visual inspection of the electrical cable tray in question from
approximately 20 feet below appears to substantiate the allegation,
however, this marking of a 1 in front of a letter had no safety
significance.
As discussed previously, all safety-related electrical
cable trays will be walked down and properly identified.
10. Action on Previous Inspection Findings
(92701, 92702)
(Closed) VIO 280,281/87-32-01, Inadequate Emergency Operating Procedure
for Natural Circulation Cooldown, e.g., Cooldown Curves Exceed Those in
the Technical Specifications.
The inspector determined from a review of
the licensee's corrective actions that a TS change request was submitted
which indicates the cooldown curve, Figure 3.1-1, is based on RCS cold leg
temperature .. The inspector also noted that emergency procedures EP-1.02A
and EP-l.02B, reflect the corrected TS cooldown curve.
The licensee
1s
corrective actions are adequate; this item is considered closed.
11.
Exit Interview
The inspection scope and fi.ndings were summarized on August 2, 1989, with
those individuals identified by an asterisk in paragraph 1.
The following
new items were identified by the inspectors during this exit:
One violation was identified (paragraph 3.a) for failure to provide
adequate
procedures
for
the
calibration
of
instrumentation
(280,/89-21-01).
One violation was identified (paragraph 3.g) for failure to place an
inoperable low intake canal level channel in trip as required by TS
Table 3.7-2, Item 5.a (280/89-21-02)
23
One violation was identified (paragraph 3.g) for failure to maintain
greater than 60,000 gallons of water in 2-CN-TK-1 as required by
TS 3.6.B.2 (280/89-21-04).
.
One unresolved item was identified (paragraph 3.g) for additional NRC and
1 icensee review of reportabil ity in accordance with 10 CFR 50. 72 of two .
events which resulted in the tripping of safety-related chillers and
charging pump service water pumps (280/89-21-03).
One unresolved* item was identified (paragraph 6.h) for additional
inspections of the licensee
1s program for implementing TS requirements
(280,281/89-21-05).
.
In addition, a weakness was identified (paragraph 3.a) during the Unit 1
restart with regards to multiple procedure concurrent usage and a lack of
sensitivity to initial conditions in procedures.
Also, a weakness was
identified (paragraph 6.g) regarding the transmittal of data used by
operations for reactivity calculations.
The licensee acknowledged the inspection findings with no dissenting
comments.
The licensee did not identify as proprietary any of the
materials provided to or reviewed by the inspectors during this
inspection.
12.
INDEX OF ACRONYMS AND INITIALISMS
ccw
cm
cw
DEGF
DR
ERFSC
ft-lb
GPM
HSD
I FI
!SI
LCO
LER
ABNORMAL OPERATING PROCEDURE
COMPONENT COOLING WATER
CODE OF FEDERAL REGULATIONS
CIRCULATING WATE~
DEGREE FAHRENHEIT
DEVIATION* REPORT
DIVISION.OF REACTOR PROJECTS
DIVISION OF REACTOR SAFETY
EMERGENCY RESPONSE FACILITY
EMERGENCY RESPONSE FACILITY STATUS COMPUTER
ENGINEERED SAFETY FEATURE
EMERGENCY SWITCHGEAR ROOM
ENGINEERING WORK REQUEST
FOOT-POUND
.
GALLONS
GALLONS PER MINUTE
HIGH PRESSURE SAFETY INJECTION
HOT SHUTDOWN
INSTRUMENT AIR
INSTRUMENTATION AND CONTROL
INSPECTOR FOLLOWUP ITEM
INSERVICE INSPECTION
LIMITING CONDITION FOR OPERATION
LICENSEE EVENT REPORT
' '
MER3
MOV .
MTC
NI
NRC
OP
ppb
SNSOC
S/G
SNSOC
sov
ssn
Tave
Tref
TM
TS
24
MECHANICAL EQUIPMENT ROOM 3
MOTOR OPERATED VALVE
MAIN CONTROL ROOM
MODERATOR TEMPERATURE-COEFFICIENT
NON-CITED VIOLATION
NUCLEAR INSTRUMENTATION
NUCLEAR REGULATORY COMMISSION
NUCLEAR REACTOR REGULATION
OPERATING PROCEDURE
PERCENT MILLIRHO
PREVENTATIVE MAINTENANCE
POWER OPERATED RELIEF VALVE
PARTS PER BILLION
POUNDS PER SQUARE INCH
POUNDS PER SQUARE INCH GAUGE
PERIODIC TEST
QUALITY ASSURANCE
QUAL ITV CONTROL
STATION NUCLEAR SAFETY AND OPERATING COMMITTEE
SAFETY PARAMETER DISPLAY SYSTEM
RESIDENT ACTION ITEM
REACTOR COOLANT PUMP
REACTOR OPERATOR
RECIRCULATION SPRAY HEAT EXCHANGER*
RECIRCULATION SPRAY SYSTEM
RADIATION WORK PERMIT
SAFETY EVALUATION REPORT
SAFETY. INJECTION
STATION NUCLEAR SAFETY AND OPERATING COMMITTEE
SOLENOID OPERATED VALVE .
SAFETY PARAMETER DISPLAY SYSTEM
SENIOR REACTOR OPERATOR
SAFETY SYSTEM FUNCTION INSPECTION
AVERAGE TEMPERATURE
REFERENCE TEMPERATURE.
TECHNICAL* SPECIFICATIONS
UPDATED FINAL SAFETY ANALYSIS REPORT
UNRESOLVED ITEM
VIOLATION