ML18152A338
| ML18152A338 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 12/30/1993 |
| From: | Belisle G, Branch M, Tingen S, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A339 | List: |
| References | |
| 50-280-93-26, 50-281-93-26, NUDOCS 9401240037 | |
| Download: ML18152A338 (16) | |
See also: IR 05000280/1993026
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
.
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
Report Nos.:
50-280/93-26 and 50-281/93-26
Licens*ee:
Virginia_ Electric and Power *Company
5000 Dominion Boulevard
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50-281
License Nos.:
Facility Name:
Surry 1 and 2
Inspection Conducted:
November 7 through December 4, 1993
Inspectors:
M. W. Branch, Senior Resient
Inspector
J. W. York,~t Inspector
- z
- : JI.
---* /V\\.--
s. G. Tingen, Resident Inspector
Approved by:
~~
G. A1~e1S~on Clef
Division of Reactor Projects
SUMMARY
Scope:
I.;.- :Sc-r-..3
Date Signed
IJ-3P- t'3
Date Signed
/J--.J~ !'3
Date Signed
I L:,--.t o -; J
Date Signe
This routine resident inspection was conducted on site in the areas of plant
status, operational safety verification, maintenance inspections, surveillance
inspections, licensee event review, and .action on previous inspection items.
While performing this inspection, the resident*inspectors conducted reviews of
the licensee's backshifts, holiday or weekend operations on November 10, 15,
18, 19, 26, 30, and December 1 and 4, 1993.
Results: .
Operation functional area:
Prudent testing of the Unit 1 turbine driven auxiliary feedwater pump
based on recent industry experience was considered a strength (paragraph
4.c).
9401240037 93i230
ADOCK 05000280
G
2
An unresolved item was identified concerning the adequacy of Emergency
Operating Procedures associated with throttling the auxiliary feedwater
flow during a reactor trip to prevent excessive plant cooldown
(paragraph 3.a).
Engineering functional area:
A non-cited violation was identified because the annunciator response
procedure for alarm E-2 did not provide the correct guidance for
clearing the alarm (paragraph 5.a).
- The failure to ensure that the emergency service water pump house door
seal plates be watertight as specified in the Updated Final Safety
Analyses Report, section 2.3.1.2.2, was identified as a violation
(paragraph 7) .
-~--
I.
Persons Contacted
Licensee Employees
REPORT DETAILS
- W. Benthall, Supervisor, Licensing
- R. Bilyeu, Licensing Engineer
_
H. Blake, Jr., Superintendent of Nuclear Site Services
- R. Blount, Superintendent of Maintenance
- D. Christian, Assistant Station Manager
J. Costello, Station Coordinator, Emergency Preparedness
- J. Downs, Superintendent of Outage and Planning
D. Erickson, Superintendent of Radiation Protection
A. Friedman, Superintendent of Nuclear Training
- B. Hayes, Supervisor, Quality Assurance
- M. Kansler, Station Manager
C. Luffman, Superintendent, Security
J. McCarthy, Superintendent of Operations
A. Meekins, Supervisor of Administrative Services
- A. Price, Assistant Station Manager
.
R. Saunders, A~sistant Vice President, Nuclear Operations
E. Smith, Site Quality Assurance Manager
- T. Sower_s, Superintendent of Engineering
_
J. Swientoniewski, Supervisor, Station Nuclear Safety
- G. Woodzell, Nuclear Training
NRC Personnel
M. Branch, Senior.Resident Inspector
- S. Tingen, Resident Inspector
- J. York, Resident Inspector
- Attended Exit Interview
Other licensee employees contacted included control room operators,
shift technical advisors, shift supervisors and other plant personnel.
Acronyms and initialisms used throughout this report are listed in the
-1 ast paragraph.
2.
Plant Status
Unit I began the reporting period at 98% reactor power on day 3 of the
power coastdown for refueling. At the end of the period reactor power
was at 80% with the refueling outage scheduled to commence on January
21, 1994.
Unit 2 began the reporting period at 96% power in order to minimize
level oscillation in the C SG.
On November 15, the unit tripped from
95% reactor power when all three FWRVs closed on a loss of electrical.
power to their solenoids. A 10 CFR 50.72 report was submitted to notify
the NRC of the reactor trip which is described in detail in paragraph
,-
2
3.a. Subsequent to the trip, the licensee elected ti cooldown the unit
to investigate the cause of the C SG level oscillationi that h~d been
restricting power operation since unit startup .from the refueling in
May.
The unit was returned to power operations on December 1, and at
th~ end*of the period was operating at 100% reactor power.
3.
Operational Safety Verification {71707, 42700)
The inspectors conducted frequent tours of the control room to verify
proper staffing, operator attentiveness and adherence to approved
procedures.
The inspectors attended plant status meetings and reviewed
operator logs on a daily basis to verify operational safety and
compliance with TSs and to maintain overall facility operational
awareness.
Instrumentation* and ECCS lineups were periodically reviewed
from control room indication to assess operability .. Frequent plant
tours were conducted to observe equipm~nt status, fire protection
programs, radiological work practices, plant security programs and
housekeeping.
Deviation reports were reviewed to assure that potential
safety concerns were properly addressed and reported.
a.
November 15 Unit 2 Reactor Trip
At 8:19 p.m., on November 15, 1993, Unit 2 tripped from
approximately 95% reactor power.
The steam-flow/feed-flow
mismatch coinci9ent with low SG level reactor trip occurred when
all three FWRVs closed. * 'rhe FWRV closure resulted from when
electrical power was lost to the A train solenoid valves when
their supply breaker tripped open.
Plant response to the
trahsient was as expected except the A AFW pump had to be secured
due to heated packing which filled the room with smoke {see
paragraph 3.c). A resident inspector was on-site performing
backshift inspections and responded to the control room to monitor
the licensee's actions.
Breaker number 16 was the supply breaker that tripped open.
This-
breaker is a 15 amp molded case circuit* breaker located in DC
distribution panel 2-1.
The breaker was originally quarantined
for failure investigation until troubleshooting could be
initiated. Initial troubleshooting did not identify a cause for
the breaker trip. However, the electricians determined. that the.
breaker would not reclose and was defective.
The breaker, which
the licensee identified as original equipment, was sent offsite
for failure analysis. A replacement breaker was reinstalled and
satisfactorily tested. Three other molded case circuit breakers
in Unit 2 were replaced as a preventive measure since their
failure would also result in a reactor trip.
During the reactor trip, the RCS temperature cooled to
approximately 525 degrees F.
This cooldown was caused, in part,
by the initiation event that cause the trip {i.e., all three FWRVs
closing). All three AFW pumps started and delivered greater than
350 gpm to each of the three SGs for a total flow of greater than
b.
3
1050 gpm.
The inspectors reviewed EOP l-ES-0.1 rev1s1on 10,
Reactor Trip Response, to determine if the procedure would allow
th~ottling AFW flow to minimize the RCS cooldown .. Step 1 of the
procedure checks that total AFW flow is greater than 550 gpm (350
gpm W/0 RCPs}.
Step 2 ,of that procedure checks that RCS
temperature is stable at 547 degrees F.
If a positive response to
the RCS temperature stable question is not obtained, the procedure
. directs methods to reduce the RCS cooldown.
The* (b} action of the
response not obtained instruction states, "WHEN narrow range level
greater than 11% in at least one SG, THEN limit total feed flow to
maintain level". It does not appear that the Surry EOP allows
throttling AFW flow until the narrow range level in one of the SGs
is greater than 11%.
During the November 15 Unit 2 trip, the
inability to throttle AFW flow early in the transient appears to
have contributed to the RCS cooldown.
The AFW flow was not
throttled until approximately 20 minutes into the event after
approximately 20,000 gallons of relatively cold water was
injected.
The inspectors reviewed the WOG standard procedure and North
Anna's equivalent procedure step to determine if those procedures
were as restrictive as the Surry procedure.
In both cases, the
procedures allowed throttling of AFW flow to limit the cooldown.
The inspectors discussed the apparent procedural discrepancy with
station management and requested the procedure evaluation
including the engineering basis for deviating from the WOG
guidelines.
Additionally, through interviews with operators~ it
appeari that training also instructs the operators not to throttle
AFW flow until level is recovered to the 11% val*ue in one SG.
This item is identified as URI 50-280, 281/93-26-01, EOP Adequacy
pending a review of the licensee's basis for the procedure
deviation.
.
Through-Wall Leaks in Service Water Valve Bodies
As discussed in previous inspection reports the site has recently
experienced through-wall leaks in a number of 1-1/2 and 2 inch
aluminum bronze valves in the SW system.
In order to evaluate the
extent of-this condition to other systems the inspectors performed
a walkdown of systems where these types of valve may be installed.
Additionally, the inspectors reviewed the licensee's evaluation -
(Memorandum from R. Rasnic dated November 15, 1993, Summary
Report: Dealloying of Aluminum Bronze Valves Surry Power Station).
The licensee concluded that all of the aluminum bronze valves at
Surry were being replaced and that there were no similar aluminum
bronze valves installed at North Anna.
The inspectors' walkdown
did not identify any additional leaking valves and confirmed that
the problem was only associated with the CCP SW system.
The licensee's review did identify that there were 15 nickel
aluminum bronze valves installed at Surry.
Eight are_ 30-inch
diameter butterfly valves in the SW lines supplying the RSHXs.
4
The rema1n1ng seven are s~aller butterfly valves in the SW sy~tem
for the control room chillers and the charging pumps.
These
va.l ves are inspected periodically during .RFOs.
Discussions with
the systems engineer and an interior photograph review of some
valves made during inspections revealed no apparent corrosion
problems at this time.
The nickel aluminum bronze has better
corrosion resistance than the normal aluminum bronze *. Periodic
inspections and maintenance record reviews should identify any
corrosion problems.
On Unit 2, ten of the valves were replaced with 90-10 copper-
nickel alloy spool pieces using a system design change.
The
remaining Unit 2 aluminum br~nze valves were replaced with 316
stainless steel valves during the November 15 ~ December 1 forced
outage.
In Unit 1, three valves have been replaced and the
remaining 17 will be replaced during the next RFO scheduled to
start on January 21, 1994 *. The inspectors verified that the
appropriate valves were being or were scheduled for replacement.
The inspectors reviewed the safety evaluation no.93-197, rev. 1,
dated November 5, 1993, and JCO no. C-93-004 which allowed the
operating the units with a very small amount of seepage through
these valves. These evaluations concluded that the system perform
its function.* The inspector's document review did not reveal any
negative results. Included in the actions to be taken was a
weekly walkdown inspection by the system engineer.
On November
29, the inspectors, al6ng with a region based inspector,
accompanied the system engineer on the weekly valve inspection and
found this inspection to be tho~ough and well organized.
c.
Cause of Packing to Smoke on AFW Pump 2-FW-P-3A
When the Unit 2 reactor tripped on November 15, the AFW pumps
started on low-low SG level. The packing smoked excessively on
AFW pump 2-FW-P-3A and the pump was secured and declared
The amperage drawn by the pump was noted by operators
to have increased when the packing smoked.
The inspectors
reviewed the licensee's investigation into what caused the packing
to smoke and subsequent corrective actions. The inspectors
i-nspected the packing that smoked after it was as removed from
pump f-FW-P-3A.
The braided graphite packing was soft and pliable *
and visually appeared to be in good condition.* The packing did
not appear to be burned or overheated.
A history review determined that during the spring 1993 Unit 2
RFO, a new type of braided graphite packing was installed in the
Unit 2 AFW pumps.
In October, the packing on pump 2-FW-P-3A
smoked and the pump was repacked with the same type of packing.
The pump 2-FW-P-3A packing was discussed in NRC Inspection Report
Nos. 50-280, 281/93-24 .
5
On Ncivember 17, the inspectors attended a meeting between the
licensee and the vendor that supplied the braided graphite
packing.
The vendor explained that the exterior layer of the
packing contains an acrylic resin and at approximately 350 degrees
F the acrylic resin burns off. The_vendor stated that the acrylic
resin normally burns off approximately 30 minutes after initial
pump operation following packing installation. During the packing
break-in, it is normal for the packing to smoke and the pump motor
to draw larger than normal amperage.
The licensee's normal procedure following repacking AFW motor
driven pumps was to run a pump for approximately ten to fifteen
minutes which, based on vendor information, was not sufficient
time to break-in the braided graphite packing.
On November 15,
pump 2-FW-P-3A operated for approximately 23 minutes before the
pump it was s~cured ~ue to the packing smoking.
It appeared that
the braided graphite packing was breaking in and smoked while the
pump operated following the reactor trip.
-. The licensee concluded that pump flow rates were acceptable and
. that the pump was operable with the braided graphite packing
installed. However, the licensee was concerned that the smoke
could affect the operators ability to enter the area if needed._
As a result of this concern, the licensee replaced the br~ided
graphite packing in the Unit 2 AFW pumps with another packing type
that did not smoke during the.break-in process.
Based on *
discussions with the braided graphite packing vendor, the
- inspectors agreed with the licensee's conclusion that the pumps
were operable when the braided graphite packing was installed.
d.
Unit 2 Startup
The inspectors observed portions of the Unit 2 startup activities
from the main control room.
On November 30, a review of the
procedure b~ing used in the control room, 2-GOP-1.4 rev. 7, Unit 2
Startup, Hot Shut Down to 2% Reactor Power, dated September 7,
1993, was completed by the inspectors.
No problems with the
procedure quality were noted.
Criticality was achieved at 5:29 a.m., on December 1.
The
inspectors observed the reactor power increase as well as tying
the unit to the electrical grid at 1:54 p.m.
Command and contrpl
and procedure adherence was evident and no problems were nQted by
ihe inspectors during the unit startup .
. Within the areas inspected, no violations were identified.
4.
Maintenance Inspections (62703) (42700)
During the reporting period, the inspectors reviewed the following
maintenance activities to assure compliance with the approp_ri ate
procedures.
6
- a.
Control Rod M-10
, Each control rod.in the rod cohtrol system has an individual
control rod position indicator or IRPI.
The function of these
indicators is to provide information concerning the actual
position of each rod. Unit 2 IRPI M-10 indicates 20 to 30 steps
withdrawn nearly every time the unit trips from full power.
Almost every reactor trip report since 1986 has identified this as
a potential problem.
In 1988, an engineering work request was
written to document the operability of IRPI M-10.
This
operability evaluation was based on discuss ions wHh the vendor,
Westinghouse, as well as hot rod drop test results that proved
that the rod fully inserted when tripped.
Westinghouse documentation indicated that the IRPI problem
described may result from two .possible causes.
The first is that
the control rod pressure housing {rod travel housing) may have
some magnetic properties {permeability) that can affect the rod
position indication, but not the actual control rod position. The
documentation states that some older plants have pressure housings
with chemical impurities that could become magnetized and provide
a false rod position indication.
The second possible cause is the fluid dynamics in the reactor's
upper head region and _inside the control rod pressure housing.
Fluid dynamic changes in the upper head region at different power
levels can change the control rod driveshaft temperature.
The
driveshaft's permeability is a function of fts temperature.
Temperature fluctuations could cause permeabi 1 ity changes, causing
a drifting control rod position indication until the temperature
stabilizes.
The inspectors reviewed the licensee's engineering evaluation of
the rod M-10 problem as documented by EWR-052.
This EWR also
describes the possibility that the IRPI coil itself could be
defective and may need replacing.
The EWR concludes that the
- described behavior of rod M-10 during reactor trips is not
desirable but that it is not a safety concern. Although the rod
M-10 IRPI problem is not a safety concern, the inspectors
identified a concern with EOP response to the licensee.
Specifically, after a reactor trip the EOPs direct the operators
to verify that the control rods are on the bottom by observing rod
bottom lights and IRPI indication~ The EOPs further instruct the
operators to emergency borate if more than one control rod does
not indicate fully inserted. With M~Io providing one not-fully-
inserted indication, another not-fully-inserted indication,
whether real or another IRPI- indication malfunction, would cause
the operators to emergency borate in accordance with the EOP
instructions. Thus, emergency boration could be initiated when
technically it is not needed; thereby distracting the operators
from potentially more important tasks.
7
The licensee performed testing during the short forced outage
which occurred during this inspection period (ref. EWR 93-052).
First, the licensee performed the rod drop time test and the rod
met the acceptance criteria; After the test when the rod <position
indicator was reconnected, it indicated that the rod was 25 steps
from the bottom (normally after this test the RPI shows O steps}.
_When M-10 signal cables leads from the containment to the control
room were swapped with RPI F-12 cables, the M-10 position
indication did not change.
However, when the signal cable leads
going to the bench board indicators were swapped, the indication
rod position indication did reverse for the two rods. This seemed
to indicate that the problem was in the RPI cabinet: The licensee
is still evaluating the information collected. The licensee has*
indicated that possible JWapping or replacement of the IRPI.coil
was beirig considered for a fut~re refu~ling outage if the problem
cannot be isolated. The inspectors continue to follow the
licensee's activities in this area.
b.
Inspection and Cleaning of Unit 2 C Steam Generator
Based on continuing problems in the C SG water level oscillations,
the licensee decided to inspect, pressure pulse clean, and sludge
lance the .C SG during a forced outage caused by a trip unrelated
to this problem.
The inspectors reviewed the vendor's (Westinghouse} proprietary
procedure that was to be used for the cleaning the support plates.
The process utilizes a pulsed pressurized nitrogen method to
remove the sludge from the support plates, tubes, and other
secondary side internals. The inspectors also attended the
SNSOC's meeting on November 19 that reviewed and approved the
procedure.
On November 20, the inspectors accompanied Westinghouse personnel
during the C SG upper steam drum inspection. This visual
inspection looked for conditions that could create level
oscillations in the SG.
Areas inspected were the primary
separator riser barrels, feed water ring and J-nozzles, SG level
indication pen et rations, secondary stage separators and. the
overall condition of the drain tubes and deck plates.
During the inspection, Westinghouse identified a small through
wall penetration in one primary separator riser barrel. The.
probable cause of the hole was impingement erosion from an
adjacent feedwater J-nozzle. The hole size was approximately 2
inches by one inch and oval in shape. There were several other
riser barrels that showed erosion evidence but none with through-
wall defects. Westinghouse evaluated the small hole and concluded
that it was acceptable to operate with the hole until the next
scheduled RFO.
8
The inspectors reviewed safety evaluation no.93-216, Steam
Generator Pressure Pulse Cleaning, which .addressed the pressure
pulse cleaning effects on the steam generator components.
The
assessment concluded the integrity of the,steam generator was
maintained following the pressure pulse cleaning.
No dissenting
views were identified.
The inspectors also reviewed the as-found and as-left tube bundle
support plate inspection video tapes.
The as-found video
identified that the passages through the quatrefoil assemblies in
the upper tube support plates were partially blocked with a sludge
like material. Sludge samples were obtained and will be analyzed.
The as-left videos taken after the pressure pulse cleaning
revealed that the process was not successful in removing all the
deposits in the tube support plate quatrefoil areas.
The licensee
estimated that approximately ten percent of the deposits were
removed.
Apparently this amount of deposit removal was enough to
allow the unit to return to 100 percent power.
The oscillation
magnitude, aft~r the cleaning, was disc~ssed with the licensee and
observed on the narrow range SG level indication in the control
room after the cleaning operation.
The C SG level oscillations
now appeared to be normal.
c.
Unit 1 Turbine Driven AFW Pump Repair
On December 2, the Unit 1 turbine driven AFW pump 1-FW-P-2 failed
due to overspeed during its monthly test. When operators
attempted to start the pump a second time, the pump tripped again
on overspeed.
The pump was declared inoperable (72-hour LCD} and
a work request submitted.
Wheh maintenance personnel disassembled the governor ~alve, the
stem connecting the governor valve to the governor was found
bound._ This prevented the governor from functioning and caused
the pump to trip on overspee_d.
The inspectors visually examined
the disassembled valve and observed corrosion buildup on the stem.
the inspectors observed the valve parts being replaced using
procedure no. O-MCM-0401-01, rev. 2, Valves and Traps in General,
dated s*eptember 17, 1992.
On December 3, the 1 icensee performed
the post maintenance testing by starting the pump with the steam
supply closed (normally started with a full steam supply} and
slowly opening the supply. This verified that the governor valve
stem and linkage were free to move.
Additionally, the licensee
successfully performed a pump start and flow test to further
demonstrate equipment operability prior to returning the pump to
service. Since the pump was warm from previous testing when the
operability verification was performed, the licensee elected to
start the pump cold on the following day. This additional testing
9
was not considered necessary for the work performed but was
prudent based on indu.stry experiences with governor problems.
Within the areas inspecte~, no violations were identified.
5.
Surveillance Inspections (61726, 42700)
During the reporting period, the inspectors reviewed surveillance
activities to assure compliance with the appropriate procedure and TS
requirements.
a.
Ventilation System Test
On November 23, the inspectors witnessed the performance of
procedure O-OPT-VS-002, Auxiliary Ventilation Filter Train Test,
dated May 11, 1993. This test placed the ventilation system in an
SI alignment and verified proper atr flow rate through the system.
Differential .pressure across the ventilation system filters was
also verified to be within acceptable limits.
Prior to the performing this test, Filter Exhaust Fan 1-VS-f-SSA
was aligned to the Unit 2 containment and to the fuel building.
The inspectors noted that in this.alignment, alarm E-2, Safety
Filter Inlet HDR Hi-Lo Pressure, was actuated on the Unit I and 2
com~on alarm panel. This ~lignment was ~ecured in order to
perform the test and alarm E-2 cleared. The test was then
performed with no deficiencies identified by operators.
During the te~t performance, the inspectors noted that when
I-VS-F-58A was started, alarm E-2 came in and immediately cleared.
When I-VS-F-58B was started, alarm E-2 came in and stayed in until
the f~n was secured.
The inspectors reviewed the annunciator
response procedure for alarm E-2.
The annunciator response
procedure stated that the desired pressure in the safety filter
inlet header was between five to eight inches of water.
The
procedure directed operators to adjust the fan controller to
.obtain this pressure in order to clear the alarm.
The inspectors
questioned the operators in the control room concerning their
failure to follow the annunciator response procedure and adjust
the fan controller to clear the alarm.
The inspectors were
informed that this action would have been contrary to an
engineering memorandum that instructed them not to adjust the fan
controller. The controller was set to provide the design system
flow rate and further adjusting the controller could result in a
system flow rate outside of the design flow rate of 36,000
plus/minus 3000 CFM.
The inspectors concluded that the annunciator response procedure
for alarm E-2 was inadequate because it provided the wrong
guidance to operators for clearing the alarm.
10 CFR 50, Appendix
B, Criterion V, requires that activities effecting quality be
prescribed by adequate instructions. The inadequate guidance
provided by the annunciator E-2 response.procedure was identified
as NCV 50-280, 281/93-26-02. * This NRC identified violation is not
being cited because criteria specified in Section VII.B of the NRC
Enforcement Policy were satisfied. The inspectors discussed this
issue with the licensee.
On November 24, the annunciator response
procedure for alarm E-2 was revised to provide the proper guidance
to operators for clearing th~ alarm.
Within the areas inspected, one NCV was identified.
6.
Licensee Event Review {92700)
The inspectors reviewed the LERs listed below and*evaluated the adequacy
of the corrective action.* The inspectors' review also included followup
of the licensee's corrective action implementation.
a.
(Closed) LER 50-281/92-03, Two MCR/ESGR Chillers Inoperable Due to
High SW Differential Pressure and Inoperable Emergency Power
Source. During a routine test of chiller l-VS-E-4C, it was
discovered that the SW flow rate through the heat exchanger was
inadequate and the chiller was declared inoperable. At the time
of this discovery, the emergency electrical power source to
.
chiller l-VS-E-4B was not available; therefore, this chiller was
also declared inoperable. Because TSs do not allow two of the
three MCR/ESGR chillers to be inoperable, a six-hour LCO to Hot
Shutdown was entered in accordance with TS 3.0.l~ The cause of
the low SW flow through chiller l-VS-E-4C was attributed to be
sediment accumulation in the SW side of the heat exchanger.
The
heat exchanger was flushed and the SW flow rate through the heat
exchanger was satisfactory. The chiller was returned to service
and the. six-hour LCO was exited.
As long term corrective action;
two additional MCR/ESGR chillers were installed and placed in
service this inspection period.
The additional chillers
increased operational flexibility and improved the capability to
withstand single failures.
b.
(Closed) LER 50-281/92-04, Two MCR/ESGR Chillers Inoperable Due to
Personnel Error. During a No. 3 MER walkdown, an SRO identified
that the local compressor control switch for MCR/ESGR chiller
l-VS~E-48 was in the OFF position.
The chiller was required to be
operating but with the local switch in the OFF position, *the
chiller compressor would not operate.
The chiller was therefore
declared inoperable.
When this was identified, chiller l-VS-E-4A
was inoperable due to scheduled maintenance.
Because TSs do not *
allow two of the three MCR/ESGR chillers to be inoperable, a six-
hour LCO to Hot Shutdown was entered in accordance with TS 3.0.l.
Chiller l-VS-E-48 compressor control switch was placed in the ON
position and the chiller operated as required.
The TS six-hour
LCO was exited .. Apparently, the switch was out of position due to
contract personnel inadvertently bumping the switch when
11
installing scaffolding in the area.
As previously discussed, two
additional MCR/ESGR chillers were installed and placed into
service.
c.
(Closed) LER 50-280, 281/93-05, Two MCR/ESGR Chillers Inoperable
Due to Personnel Error. This issue involved MCR/ESGR chillers
l-VS-E-48 and l~VS-E-4C being declared inoperable due to a freon
loss to the chillers~ condensers.
When chiller l-VS-E-4C was
placed in service, the operator failed to properly open the
strainer backwash valve to the chiller's heat exchanger.
When the
chiller's compressor was started with the backwash valve closed,
th~ he~t added to the system could not be removed which cause the
condenser freon reli~f valve to open and discharge freon.
The
operator then attempted to place chiller l-VS-E-48 into service
and again failed to *open the backwash valve which resulted in
freon discharging from that chiller's condenser.
Because TSs do
not allow two of the three MCR/ESGR chillers to be inoperable, a
six ho~r LCO to Hot Shutdown was entered in accordance with TS 3.0.1. Freon was added to l-VS-E-48, the chiller was returned to
service and _the six hour LCO was exited. The event was attributed
to personnel error and difficulty in determining the strainer
backwash valve,s position.
As corrective action, valve position
enhancements were implemented to the backwash valves and procedure
O-OP-VS-006 was revised to provide guidance for valve position
indication. The inspectors verified that valve positions were
clearly* marked and that 0-0P-VS-006 contained instructions on
positioning the backwash valves.
- *
d.
(Closed) LER 50-280/93-10, Operation With a Non-lsolable Leak on a
B SG Channel Head Drain Line. This issue involved failure to
adequately evaluate and investigate Unit _l RCS leakage and was
identified as VIO 50-280/93-22-0l. Corrective action
implementation will be reviewed during review of the violation.
e. .
(Closed) LER 50-280, 281/92-09, Two MCR/ESGR Chillers Inoperable
Due to Inadequate SW Flow Caused by SW Strainer Fouling.
On three
occasions, July 12, 15 and 27, two of the three MCR/ESGR chillers
were declared inoperable due to low SW flow.
The low SW flow was
attributed to Y strainer fouling at the individual chiller SW
pumps' suction.
The Y strainer fouling occurred at an accelerated
rate due to deterioration of the upstream rotating, self-cleaning
SW strainers 1-VS-S-lA and l-VS-S-18 .. In each case, *when the low
SW flow was identified to two chillers, a six-hour LCO to Hot
Shutdown was entered in accordance with TS 3.0il.
In each case,
the Y strainers were cleaned, the chillers were returned to
service and the six~hour LCO was exited.
As long term corrective
action, rotating SW strainers 1-VS-S-lA and l-VS-S-18 were to be
replaced and an engineering study was to be performed to evaluate
improved designs for the rotating strainers and upgrade the
MCR/ESGR chillers by installing two additional chillers. The
inspectors verified that rotating strainer 1-VS-S-lA was replaced
12
and that strainer 1-VS-S-lB was scheduled for replac~ment in March
1994.
The inspectors also reviewed the engineering study which
recommended strainer material upgrades which are scheduled to be
incorporated in March 1994.
As previously discussed, two *
additional MCR/ESGR chillers were installed and placed into
service during this inspection period.
The new chillers utilize
six inch duplex strainers to filter SW in lieu of rotating
strainers 1-VS-S-lA or 1-VS-S-lB~
Within the areas inspected, no violations were identified.
7.
Action on Previous Inspection Items (92701,92702)
(Closed) URI 50-280, 281/93-22-03, ~SW Pump Building With Degraded Flood
Barriers. This issue involved the ability of the watertight barriers
installed over the ESW pump house louvers and doors to prevent flooding
as described in the UFSAR.
The licensee reviewed the design basis for
the air intake louver covers and concluded that the covers do not need
to be watertight. The watertight duct wells permanently installed over
the louvers inside the ESW pump house provided adequate protection
against flooding.
The UFSAR will be revised accordingly.
The
inspectors walked down the duct wells installed over the louvers and
agreed with the licensee's conclusion.
The licensee also reviewed the design basis for the watertight seal
plates required to be installed in front of the two access doors into
the building when flooding was anticipated. The licensee concluded that
seal plates were not watertight as installed on A~gust 31, 1993, in
preparation for hurricane Emily. Engineering judgement was utilized to
determine that personnel stationed in the ESW pump house during flooding
conditions could have adjusted the seal plates using wedges and any
available materials such as rags to limit the water leakage into the
building.
Engineering personnel made several recommendations to improve
the seal plate des\\gn to make them watertight. Engineering also
evaluated the flooding effects if no operator action was taken to make
the seal plates watertight. Engirieering concluded that under flooding
c6nditions, from 15 to 23 inches -0f water could accumulate in the
building. This water level would not effect the operability of the ESW
pumps.
The UFSAR, section 2.3.1.2.2, stated that the ESW pump house doors are
equipped with removable watertight seal plates to protect against
flooding into the building.
The UFSAR did not address that operator
involvement was needed to aid in making the seal plates watertight nor
were materials staged in the building t~ adjust the seal plates or limit
leakage past the seal plates if needed.
10 CFR 50, Appendix 8,
Criterion III requires that measures be established to assure that the
design basis as specified in the license application are correctly
translated into specifications, drawings, procedures, and instructions.
The failure to design the ESW pump house doors' seal plates watertight
13
as specified in the UFSAR was identified as VIO 50-280, 281/93-26-03,
Failure to Design the ESW Pump House Doors' Se~l Plates Watertight.
Within the are~s inspected, one violation was identified.
8.
Exit Interview
The inspection scope and findings were summarized on December 6, 1993,
with those persons indicated in paragr~ph 1.
The inspectors described
the areas inspected and discussed in detail the inspection results
addressed _in the Summary section and those listed below.
Item Number
URI 50-280, 281/93-26-01
NCV 50-280, 281/93-26-02
LER 50-281/92-03
LER 50-281/92-04
LER 50-280, 281/93-05 LER 50-280/93-10
- LER 50-280, 281/92-09 -
URI S0-280, 281/93-22-03
VIO 50-280, 281/93-26-03
Status
Open
Closed
Closed
Closed
Closed
Closed
Closed
Closed
Open
Description
(Paragraph No.)
EOP Adequacy (paragraph 3.a).
Alarm E-2 Response Procedure
Did Not Provide The Correct
Guidance (paragraph 5.a).
Two MCR/ESGR Chillers
Inoperable Due to High SW
Differential Pressure and
Inoperable Emergency Power
Source (paragraph 6.a).
Two MCR/ESGR Chillers
Inoperable Due to Personnel
Error (paragraph 6.b).
Two MCR/ESGR Chillers
Inoperable Due to Personnel
Error (paragraph 6!c).
Operation With a Non-lsolable
Leak on a B SG Channel Head
Drain Line (parigraph 6.d).
Two MCR/ESGR Chillers
Inoperable Due to Inadequate
Fouling (paragraph 6.e).
ESW Pump Building With
Degraded Flood Barriers
(paragraph 7) *
Failure to Design the ESW pump
House Doors' Seal Plates
Watertight (paragraph 7).
"'
,
"' .
14
Propriety information is not contaitied in this report. Dissenting
comments were not received from the licensee.
9.
Index of Acrbnyms and Initialisms
ECCS -
ESGR -
EDP
F
FWRV -
GPM
HOR
IRPI -
JCO
LER
LCO
MER
NO.
NRC
RFD
RSHX -
SNSOC -
TS
UFSAR -
- URI
-
COOLANT CHARGING PUMPS .
CUBIC FEET PER MINUTE
EMERGENCY SWITCHGEAR ROOM
EMERGENCY OPERATING PROCEDURE
ENGINEERING WORK REQUEST
EMERGENCY SERVICE WATER
FAHRENHEIT
FEEDWATER REGULATING VALVE
GENERAL OPERATING PROCEDURE
GALLONS PER MINUTE
INDIVIDUAL ROD POSITION INDICATION
JUSTIFICATION FOR CONTINUED OPERATION
LICENSEE EVENT REPORT
.
LIMITING CONDITIONS OF OPERATION
MECHANICAL EQUIPMENT ROOM
MAIN CONTROL ROOM
NON-CITED VIOLATION
NUMBER
NUCLEAR REGULATORY COMMISSION
REACTOR COOLANT PUMP
REFUELING OUTAGE
ROD POSITION INDICATION
- RECIRCULATION SPRAY HEAT EXCHANGER
SAFETY INJECTION
_
STATION NUCLEAR SAFETY AND OPERATING COMMITTEE
SENIOR REACTOR OPERATOR
TECHNICAL SPECIFICATION
UPDATED FINAL SAFETY ANALYSIS REPORT
UNRESOLVED ITEM
- VIOLATION
WESTINGHOUSE OWNERS GROUP