ML20137S940
| ML20137S940 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 02/04/1986 |
| From: | Butcher R, Caldwell J, Dance H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20137S877 | List: |
| References | |
| 50-416-85-46, IEIN-85-094, IEIN-85-94, NUDOCS 8602180147 | |
| Download: ML20137S940 (12) | |
See also: IR 05000416/1985046
Text
s
pa iE4
UNITE 3 STATES
4
q'o
NUCLEAR REGULATORY COMMISSION
,
[
REGION li
,
g
.j
101 MARIETTA STREET, N.W.
ATLANTA, GEORGI A 30323
\\...../
Report No.:
50-416/85-46
'
Licensee: Mississippi Power And Light Company
Jackson, MS 39205
Docket No.:
50-416
License No.: NPF-29
Facility Name: Grand Gulf Unit 1
Inspection Conduc ed: December 21, 1985 - January 17,.1986
Inspectors:
&%
o
>
R.' C
utche
Senior / sident Inspector
(Tatd Signed
OW
U
h
(o
_
J.
. Caldwell, Resident Inspector
Bate Si ned
Approved by:
[N
H. C. Dance,TChief, Project Section 2B
Da'te '51gned
Division of Reactor Projects
SUMMARY
Scope: This routine inspection entailed 177 resident inspector-hours at the site
in the areas of Operational Safety Verification, Maintenance Observation,
Surveillance Observation, Cold Weather Preparations, Reportable Occurrences,
Operating Reactor Events, and Inspector Followup and Unresolved Items.
Results: Violation - Three examples of failure to follow procedures'for placing
shutdown cooling in effect, to maintain reactor vessel water level and feedwater
pump discharge pressure as required.
8602180147 960207
ADOCK 05000416
G
-
- - -
-
-
- -.
,_
,
,
(
'
,
.
>
REPORT DETAILS
1.
Licensee Employees Contacted
- J.
E. Cross, Site Director
- C. R. Hutchinson, General Manager
>
'
~*R.' F. Rogers, Technical Assistant
- J. D. Bailey, Compliance Coordinator
M. J.. Wright, Manager, Plant Operations
- L. F. Daughtery, Compliance Superintendent
D. Cupstid, Technical Support Superintendent
R. H. McAnuity, Electrical Superintendent -
R.-V. Moomaw, Manager, Plant Maintenance
-B. Harris, Compliance Coordinator
-
J. L. Robertson, Operations Superintendent
-
L. Temple, I & C Superintendent
.
,
J. Mueller, Mechanical Superintendent
'g
Other. licensee employees contacted included technicians, operators, securfty
~
force members, and office personnel.
u
- Attended exit interview
t.['
2.
Exit Interview
The inspection scope and findings were summarized on January 17, 1986, with
'
those persons indicated in paragraph I above. The licensee did not identify
as proprietary any of the materials provided to or reviewed by the
inspectors during this inspection.
The licensee had no comment on the
following inspection f.indings:
a.
416/85-46-01, Violation.
Failure to follow procedures for placing '
~ hutdown cooling in effect when in operational condition 2. Failure to
\\
s
follow procedures to maintain reactor. vessel water';evel and reactor
feed pump discharge pressure as requ' ired. (Paragraph 5.a and 9.e)
b.
416/85-46-02, IFI.
Licensee prepare comprehensive procedure for
placing shutdown cooling in effect when in operational condition 2.
.(Paragraph 5.a)
c.
416/85-46-03,
IFI.
Incorporate requirement to declare affected
Emergency Core Cooling System (ECCS) inoperable when minimum flow path
"
is unavailable. (Paragraph 5.b)
d.
416/85-46-04, IFI. Documentatien of 'significant events that are not
reportable by the licensee. (Paragraph 9.a)
'
se
!
i
!
-
.
2
e.
416/85-46-05, IFI.
Prepare comprehensive cold weather preparations
procedure. (Paragraph 11)
3 .'
Licensee Action on Previous Enforcement Matters (92702)
a.
(Closed)
Deviation- 416/85-28-01.
The_ _ Surveillance
Procedure
06-0P-1C61-R-0002 committed to be issued by August 31, 1984 in letter
AECM 84/0418 dated August 20, 1984 was issued on August 30, 1985. This
item is closed.
b.
(Closed)
Vio.lation 416/85-22-01.
The inspectors reviewed the
corrective actions taken by the licensee and found them acceptable.
Subsequent inspections have not revealed any recurrence of this
violation. This item is closed.
4
Unresolved Items
Unresolved items were not identified during this inspection.
.5.
Operational Safety Verification (71707)
.
The inspectors kept informed on a daily basis of the overall plant status
and any .significant safety matters related to plant operations.
Daily
discussions were held with plant management and various members of the plant
operating staff.
The inspectors made frequent visits to the control room such that it was
visited at least daily when an inspector was on site. Observations included
instrument readings, setpoints and recordings status of operating systems;
tags and clearances on equipment controls and' switches; annunciator
alarms; adherence to limiting conditions for operation; temporary alterations
in effect; daily journals and data sheet entries; control room manning; and
access controls.
This inspection activity included numerous informal
discussions with operators and their supervisors.
Weekly, when onsite, selected ESF system were confirmed operable.
The
confirmation is made by verifying the following: Accessible valve flow path
alignment; power supply breaker and fuse status; major component leakage,
lubrication, cooling and general condition; and instrumentation.
'
General plant tours were conducted on at least a biweekly basis. Portions
of the control building, turbine building, auxiliary building and outside
areas were visited. Observations included safety related tagout verifica-
tions, shift turnover, sampling program, housekeeping and general plant
conditions, fire pactection equipment, control of activities in progress,
radiation protection controls, physical security, problem identification
systems, and containment isolation. The following comments were noted:
a.
On Decen:ber 22, 1985, the licensee initiated a reactor startup
following an outage- to repair ~ some condenser tube leaks. At 11:27
a.m.,
the reactor mode switch was placed in startup (operational
.. .
_ .
_ _ - _ _ - _ _ _ _ _ _ _ _
-
.
3
condition 2).
Control rod withdrawal was initiated at 11:31 a.m.
At
12:25 p.m. with the reactor subcritical, the B Residual Heat Removal
(RHR) system was placed in the shutdown cooling mode to maintain plant
conditions.
This made the Low . Pressure Coolant Injection (LPCI) B
system inoperable and the plant entered action statement b.1 of
Technical Specification (TS) 3.5.1 which states "with either LPCI
.
subsystem B or C inoperable, restore the inoperable LPCI subsystem B or
l
C to operable status within 7 days." The licensee used the provisions
of a special test exception in TS 3.10.5', Training Startups, which
permits one loop of RHR to be aligned for shutdown cooling for training
startups provided the reactor vessel is not pressurized, thermal power
is less than or equal to 1% of rated thermal power and reactor coolant
temperature is less than 200 F.
A similar reactor startup on June 6, 1985 was discussed in Report 85-20
and the licensee had committed to referencing the requirements of
TS 3.10.5 in their procedure to ensure the operators are aware of the
requirements.
This was inspector followup item 416/85-20-03.
The
licensee revised Integrated Operating Instruction (I0I) 03-1-01-1, Rev.
30, paragraph 2.1.11 to state "with shutdown cooling inservice, while
performing cold criticalities, limit the reactor coolant temperature
to less than or equal to 150 F and thermal power less than or equal
to 1%."
Paragraph 5.26 states "If reactor startup is for training
purposes per TS 3.10.5, or cold criticals begin recording reactor
vessel unpressurized, thermal power and reactor coolant temperature on
Data Sheet III. These readings must be taken hourly."
At 12:15 p.m., the.A and B recirculation loop suction temperatures were
189"F and 188 F respectively which exceeds the temperature limits
specified in 101 03-1-01-1.
At 2:00
p.m., the A and B recirculation
loop suction temperatures were both 159*F indicating a cooldown of 30*F
(which is an appreciable positive reactivity addition) in less than two
hours. During this period, data sheet III of 10I 03-1-01-1 was nct
being used.
TS 6.8.1 requires written procedures be Jestabli shec ,
implemented and maintained covering the procedures recommended in
Appendix A of Regulatory Guide (RG) 1.33.
RG 1.33 requires written
procedures for plant operation from hot standby to minimum load. The
failure to follow I0I 03-1-01-1 is a Violation (416/85-46-01). Other
examples of procedural violations are discussed in paragraph 9.e.
Discussions with the Manager, Plant Operations, indicate that he
r
thoroughly discussed the above evolution with the on shift operations
personnel and they were aware of the plant conditions. The resident
inspector contacted Region II supervision and NRR regarding the
incorporation of shutdown cooling during startup for other than
training or cold criticalities.
Certain other facility TS have
provisions for operating shutdown cooling while in operational
condition 2 (startup) and, if properly controlled, such operation is
permissible. The resident clso confirmed that NRC does not consider
all potential plant evolutions not specifically prohibited and/or
discussed in TS to be permissible. A conservative approach to plant
operations is recommended when off normal operational conditions arise.
-
_
_ - _ _ _ _ _ _ - _ - _ - _ _
.
4
.
Although I0I 03-1-01-1 has a few specific TS limitations for having
shutdown cooling inservice when in mode 2,
it appears a specific
detailed procedure giving precautions,
i.e., avoid pulling control rods
while cooling down, ete, would be necessary to perform this evolution
in the future.
The licensee committed to prepare a comprehensive
procedure for placing shutdown cooling in effect when the plant is in
operational condition 2 with appropriate precautions and limitations by
February 2, 1986. This will'be Inspector Followup Item (416/85-46-02).
b .-
IE Information Notice 85-94, Potential for loss of Minimum Flow Path
Leading to ECCS Pump Damage During a LOCA, was discussed with the
licensee. Although the review of IE Notice 85-94 is not complete the
Manager, Plant .0perations stated that any time the minimum - flow
provisions might not be available for the Emergency Core Cooling
Systems-(ECCS), the affected ECCS should be declared inoperable. Until
incorporated into plant procedures or position statements, this will be
Inspector Followup Item (416/85-46-03).
6.
Maintenance Observation (62703)
During the report period, the inspector observed selected maintenance
activities:
The observations included a review of the work documents for
adequacy, adherence to procedure, proper tagouts, adherence' to technical
specifications, radiological controls, observation of all or part of the
actual work and/or retesting in progress, specified. retest requirements, and
adherence to the appropriate quality controls.
One event occurred regarding the inadvertant starting of the Division 3
diesel generator.
This event is discussed in Paragraph 9.d.
No violations or deviations were identified.
7.
Surveillance Testing Observation (61726)
The inspector observed the performance of selected surveillances.
The
observation included a review of the procedure for technical adequacy,
conformance to technical specifications, verification of test instrument
calibration, observation of all or part of the actual surveillances, removal
from service and return to service of the system or components affected, and
review of the data for acceptability based upon the acceptance criteria.
On January 10, 1986, the licensee identified two containment penetration
isolation valves, E61F009 and E61F010, which are used for containment purge
and which have not been local leak rate tested every 92 days as required.
TS 4.6.1.2.j states that purge supply and exhaust isolation valves with
resilient material seals shall be tested and demonstrated operable per
surveillance requirement 4.6.1.9.2.
TS 4.6.1.9.2 states that at least once
per 92 days. each containment purge supply and exhaust isolation valve with
resilient material seals shall be demonstrated operable by verifying that
the measured leakage rate is less than or equal to 0.01 La when pressurized
.
-
- -
-
- g.
'
.
5
to Pa. Containment penetration 65 isolation valves E61F009 and F010 are
the suction valves for ~ the containment purge system.
E61F009 and F010
were last local leak rate tested on October 11, 1984 but they were included
as boundary valves in the integrated leak rate test conducted during the
~
October 11, 1985 thru December 7, 1985 outage.
The licensee immediately
conducted a local leak rate test which the valves successfully passed.
The
licensee has now included the above valves in their program to be local leak
.
rate tested every 92 days.
Failure to test the. valves as required is a
violation.
The inspector's review determined that this matter met the
criteria of 10 CFR 2, Appendix C for licensee - identified violations and
therefore will not be cited.
No other violations or deviations were identified.
8.
Reportable Occurrences (90712 & 92700)
The below listed event reports were reviewed to determine if the information
provided met the NRC reporting requirements.
The determination included
adequacy of event description and corrective action taken or planned,
t
existence of potential generic problems and the relative safety _ significance
of each event.
Additional inplant reviews and discussions with plant
personnel as appropriate were conducted for the reports indicated by an
asterisk. The event reports were reviewed using the guidance of the general
policy and procedure for NRC enforcement' actions.
The_ foilowing License Event Reports (LERs) are closed.
LER No.
Event Date
Event
85-44'
November- 18, 1985
Control Room Emergency
Filtration System-
Actuates on False
Chlorine Signal.
85-47
December 16, 1985
Control Room Emergency
Filtration System
Actuates on False
Chlorine Signal.
- 85-45
December 5,1985
Valve Limit _ Switches-
Found In Noncompliance
With 10 CFR 50.49
See Paragraph 10.d for a discussion of LER 85-45.
No violations or deviations were identified.
-
.
6
9.
Operating Reactor Events (93702)
The inspectors reviewed activities associated with the below listed reactor
events. The review included determination of cause, safety significance,
performance of personnel and systems,and corrective action. The inspectors
examined instrument recordings, computer printouts, operations journal
entries, scram . reports and had discussions with operations, maintenance and
engineering support personnel as appropriate.
During the period of December 30, 1985 - January 1,
1986, five events
occurred at the Grand Gulf Nuclear Station (GGNS) which resulted in major
reductions in power or challenges to safety systems. These events include
two trips of the recirculation pumps, two reactor scrams and an inadvertant
start of Division 3 Emergency Diesel Generator (EDG).
The inspectors
reviewed each of these events and-a discussion of these events is provided.
below.
a.
The first event which occurred at approximately 11:15
a.m.
on
December 30, 1985, involved the inadvertant tripping of both recircula-
tion' pumps to the Low Frequency Motor Generator (LFMG) set. At the
time of the event, the plant was operating at approximately 100?J power
and Instrumentation and Control (I&C) technicians were performing
surveillance procedure 06-IC-IC34-M-0001.
During the performance
of this surveillance procedure, the recirculation pump trip system
received a false low reactor water level trip signal which caused the
recirculation pumps to transfer to the LFMG set rapidly reducing
reactor power from 100?6 to approximately 55?;. This rapid reduction in
power caused vessel water level to increase to approximately 51 inches,
just below the high level scram trip, turbine trip and feed pump trip
setpoints.
The licensee's investigation into the event involved
repeating the sequence of events which the I&C technicians performed
prior to the recirculation pump trip.
This repeat of the I&C
technicians actions and the surveillance procedure failed to reproduce
the false low water level signal which caused the trip. The licensee
has been unable -to determine the cause of the recirculation pump
transfer to the LFMG Set.
During the review of this event, the inspectors discovered the licensee
had not performed any documentation of the occurrence. A review of
the plant requirements for documenting operating events revealed an
interpretation problem with the threshold used to determine when an
event should be written up and hence evaluated.
The licensee agreed
that this event should have been documented and has committed to taking
the necessary actions to ensure that all significant events will be
documented.
This will be identified as an Inspector Followup . Item
(416/85-46-04).
b.
The second event which occurred at 7:15 p.m. on December 30, 1985,
involved the inadvertant tripping of B recirculation pump using the
Anticipated Transient Without a Scram (ATWS) trip function. At the
time of the event, the reactor was operating at 80?; power recovering
from the previous recirculation pump trip discussed above.
j
4
~
.
7
technicians were performing surveillance procedure 06-IC-1821-M-1012,
ATWS Reactor Vessel Level / Reactor Pressure Functional Test, when the B
recirculation pump tripped. This ATWS trip of B recirculation pump
caused reactor power to rapidly decrease to approximately 55*4 but the
plant was able to withstand the transient without shutting down
completely.
The licensee's investigation into 'the event involved
.
repeating the I&C technicians actions prior to the event but they were
unable to reproduce the inadvertant. ATWS trip signal. The cause of
this event as .well as the previous recirculation pump trip discussed
above remain undetermined by the licensee.
c.
Scram No. 35. The third event involved a reactor scram from 100*4 power
.
at 12:51 p.m. on December 31, 1985. Prior to the scram the plant had
been receiving low level alarms on the Intermediate Pressure (IP)
condenser hotwell but the control room level instrumentation indicated.
a level well above the low level setpoint.
To ensure .that an actual
low level condition existed operations dispatched I&C technicians
'
to the level instruments to fill and vent their reference legs.
Performance of the fill and vent procedure required the automatic
level control on the condenser hotwells to be placed in manual since.
the control signals come' from the level instruments.
As the I&C
technicians were securing from the fill and vent procedure, the
condensate pumps tripped due to a low water level signal in the IP
condenser hotwell .
This trip of the condensate pumps resulted in a
loss of feed to the vessel and a low level reactor scram.
It was determined later that an actual low level condition did exist
in the IP condenser hotwell.
The combination of placing the hotwell
level controls in. manual and the performance of the fill and vent
procedure prior to filling the condenser hotwell to clear the low level
alarm caused the low level. trip of the condensate pumps.
Just after-the scram in response to the decreasing level in the vessel,
the - operator manually initiated both Reactor Core Isolation Cooling
(RCIC) and High Pressure Core Spray (HPCS).
These two systems would
have automatically initiated if left alone oecause the vessel level
dropped well below their trip setpcint.
During the manual initiation
of HPCS, the operator noticed that it was taking a long time for the
injection valve to open so he opened it manually. An investigation by
the licensee determined that the HPCS injection valve failed to open
,
automatically due to a defective relay base. This defective base was
an Agastat relay type CR0009 base and problems associated with this
base were identified in a General Electric (GE) SIL No. 384 in October
1982 and a NRC IE Information ' Notice 82-48 in December 1982. The
licensee had taken the actions recommended by GE SIL NO. 384 in June
of 1983 and replaced all unsatisfactory relay bases on safety related
equipment. This particular base has now been replaced with a better
type and the injection valve was tested satisfactorily prior to
restart.
g:
- ,
. .
_
.
_
-
_
_
_
-
.
8
d.
The fourth event which occurred at 10:40 p.m. on December 31, 1985
involved the inadvertant starting of Division.3 Emergency Diesel
Generator (EDG).
At the time of the event, plant personnel were
performing troubleshooting, under Maintenance Work Order (MWO) 58932,
to isolate the cause of the HPCS injection valve failure to open
automatically.
The performance of troubleshooting involved _ lif ting
various leads by'I&C technicians to prevent automatic initiation of
the EDG while checking the operation of the injection valve circuits.
However, the technicians overlooked a seal-in relay which would give
the EDG a start signal. Since this relay was still in the circuit the
trouble shooting not only checked the automatic opening circuit for the
injection valve but also automatically initiated the Division 3 EDG.
The diesel generator was brought up to speed, loaded, run for 30
minutes and then secured as required.
The trouble shooting was then
completed without further incident.
e.
Scram No. 36. The fifth event which occurred at 9:12 a.m. on January
1,
1986 involved a reactor scram from less than 1% power during a
reactor startup. Reactor power was being monitored in the intermediate
range with pressure approximately 600 psig. The control room operator
received an annunicator indicating a high or low . vessel water level
condition. The level indication available to the operator consisted
of three level meters just above a level recorder. The operator only
looked at the level recorder and decided that the high low alarm was
due to a high level condition which was normal for this stage of the
startup.
However, unknown to the operator, the level recorder had
stuck and the level meters indicated a decreasing water level.
The
actual water level finally decreased to the low level scram satrient
and automatically scrammed the reactor.
The operator not only missed
the decreasing water level but also failed to keep the feed pump
discharge pressure 100 psig above reactor pressure as required, which
prevented the feed pump from maintaining the vessel water level.
The root cause of this scram was the failure of the operator to monitor
all the required instrumentation available to ensure the reactor was
maintained in a stable condition.
The failure of the operators to
monitor the three level meters installed above the level recorder was
also identified earlier in the post trip analysis associated with scram
number 21. Scram number 21, involved a malfunction of the switch used
to select the level instrument channel monitored by the feedwater
control system to maintain reactor vessel level.
This switch failure
caused a decreasing water level signal to the feedwater control system
and the level recorder to indicate decreasing level.
The operator
noticed the level recorder decreasing and feed pump flow increasing
to compensate for the level decrease but failed to monitor the three
level instruments above the recorder, which indicated actual level
was increasing- toward the high
level scram setpoint.
One of the
recommendations of the' post' trip analysis of scram number 21 was that
control room operators should compare recorder readings to indicator
readings often when monitoring reactor vessel water level. Administra-
tive Procedure (AP) 01-S-06-2, Conduct of Operations, step 6.3.6
l
_
_
_ _ -
._
~
.
9
requires in part tha't one licensed operator be dedicated to monitoring
important parameters such as water level and pressure during a reactor
startup.
Licensed operators are also trained to monitor all the
instrumentation available when monitoring a parameter. The failure of
the operator to monitor all the reactor vessel level instrumentation
during -startup and in response to a water level annunciator resulted
in an automatic scram and will be identified as a second example of
Violation (416/85-46-01).
See also Paragraph 5.a.
-The operator also fai. led to monitor the feed pump discharge pressure
to ensure the feedwater pump was able to maintain vessel water level.
Integrated Operating Instruction (I0I) 03-1-01-1, Cold Shutdown to
Generator Carrying Minimum Load, step 6.2.14.b requires a . feedwater
pump be placed in service to maintain feedwater to the vessel and the
caution just below step 6.2.14.b requires the feedwater pump turbine
speed be increased as necessary to maintain feedwater pump discharge
pressure 100 psig above reactor pressure. The failure of the operator
to maintain feedwater pump discharge pressure 100 psig above reactor
pressure resulted in a reactor scram and will be identified as a-third
example of Violation (416/85-46-01).
The five events appear to indicate a decreasing trend in performance which
could be a precursor to more serious events.
The inspector . discussed the
events and the inspector's concerns with the General Manager. The inspector
was told by the General Manager and the Site . Director that actions were
already being taken to address what they also considered to be an unaccept-
able trend. Corrective actions were. reviewed by the inspector and Region II
Management and were considered appropriate at this time.
10.
Inspector Followup And Unresolved Items. (92701).
a.
(Closed) IFI 416/85-20-03.
The startup on December 22, 1985 as
discussed in paragraph 5.a of this report addresses the subject of
initiating shutdown cooling when in operational condition 2.
This item
is closed.
b.
(Closed) LIC 416/83-SC-01. This event was reported in LER 83-126. LER
83-126 was closed in IE Report 416/84-30.
This item is closed.
c.
(Closed) IFI 416/85-09-03.
Step 8.3.1.1.4.1.d of the GGNS FSAR has
been revised to reflect the correct configuration in the plant relating
to the initiation logic for Division 1 and Division 2 diesel
generators. This item is closed.
d.
(Closed) Unresolved Item (416/85-45-10). On December 2,1985, Grand
Gulf Nuclear Station (GGNS) maintenance personnel discovered several
environmentally qualified valves with limit switches that appeared to
be unqualified.
The maintenance personnel documented their findings
an a Material Nonconformance Report (MNCR) and submitted this MNCR to
the Nuclear Plant Engineering (NPE) department for evaluation.
On
. . .
.
10
December 5,1985, NPE determined that some of the limit switches ~were
required to be qualified and were still evaluating the others.
The
plant staff then notified - the NRC of the identification of these
unqualified limit switches. The plant was in cold shutdown at the
time of discovery of the unqualified limit switches. Walkdowns were
performed by plant staff of other environmentally qualified equipment
and no other discrepancies were discovered.
The -licensee concluded
from the walkdowns that a generic breakdown of their Environmental
Qualification Program did not exist.
The licensee also replaced or
otherwise qualified all of the suspected limit switches prior to
restart on December 7, 1985~.
Subsequent evaluations by NPE determined that of the 17 suspected limit
switches only 13 were required to be qualified.
These 13 limit
switches only provided indication or inputs to computer points and
their failure could not affect the operation of their associated
valves. This item is closed.
e.
(0 pen) Unresolved Item 416/85-45-01.
By memo dated December 9,1985,
the plant requested Nuclear Plant Engineering (NPE) evaluate the low
flow for Standby Service Water (SSW) system B to certain electrical
switchgear room coolers.
NPE was specifically asked if the rise in
temperature would be significant enough to cause a safety system
inoperability, a loss of a safety function, or in anyway significantly
compromise plant safety?
NPE's response stated that the Material
Nonconformance Report (MNCR) reported low flow conditions on the B loop
of SSW and the . redundant A train coolers are available for cooling
their respective switchgear rooms.
Also per Final Safety Analysis
Report (FSAR) Table 9.4-8, if a cooler loses its cooling capability
resulting in a loss of operation of electrical switchgear in that room,
the other ESF electrical switchgear located in other rooms is available
for operation. The plant then decided to check the flow capability of
the A SSW system to the electrical switchgear room coolers and found
that the A SSW system also experienced low flows.
NPE was ver bally
~
requested to evaluate the additional information and by memo dated
December 20, 1985.
NPE concluded that the effect of low SSW flow to
the _ electrical switchgear room coolers would not have resulted in the
rooms exceeding 140 F (which is the upper temperature limit for- the
safety related equipment located in the ESF switchgear rooms).
This
evaluation took into account the fact that the ceiling of room 1A410
is the roof of the auxiliary building and during winter conditions
provides a large area for heat to be lost to the atmosphere.
No
comment was made regarding the effect of operation in the heat of
summer. It appears NPE's original evaluation in response to the plants
December 9,1985 memo was very cursory in that no consideration was
given to the root cause of the B SSW ESF room coolers low flow (which
is the deposit of sand from the Plant Service Water (PSW) system that
supplies the ESF switchgear room coolers during normal operations) and
which did in fact cause low flow in the A SSW ESF room coolers. The
plant staff questioned the operability of the A SSW ESF room coolers
which caused them to test the A SSW loop and determine low flow was
-
,,
1
~
.
11
present there also. NPE's second evaluation also appears cursory in
,
that it did not address operability during warm weather'and failed to
address what actions would be necessary to continue operating with the
possibility of the ESF room coolers becoming stopped up again.
No
mention of changing out room coolers, conducting periodic flow tests,
or other surveillance methods to ensure operability was discussed. The
licensee failed to recognize that FSAR paragraph 9.4.5.4 requires the
ESF room coolers be periodically inspected to ensure all normally
operating equipment is functioning properly and standby components are
periodically tested to ensure system operation.
This last item was a
deviation in Report 416/85-45.
11'
Cold Weather Preparations (71714)
.
The licensee has initiated certain cold weather protection actions based on
past experience. The daily plant work schedule for December 13, 1985 listed
several cold weather action items, however the items listed on the work
schedule was not complete for all affected areas.
The licensee's cold
weather preparations.are not procedurally defined nor~ are there any. cold
weather periodic maintenance requirements specified to ensure operability.
The resident inspector has discussed this with plant management and the
licensee has committed to prepare a comprehensive procedure, ' including
necessary periodic maintenance requirements, for cold weather preparations
by February 15, 1986.
This will be an Inspector Followup Item
(416/85-46-05).