ML17328A775
| ML17328A775 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 11/09/1990 |
| From: | Darrin Butler, Fresco A, Gardner R, Lennartz J, Storey T, Sullivan K, Ulie J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17328A773 | List: |
| References | |
| 50-315-90-18, 50-316-90-18, NUDOCS 9011190229 | |
| Download: ML17328A775 (69) | |
See also: IR 05000315/1990018
Text
U.S.
NUCLEAR REGULATORY'Of1NI SS ION
REGION I I I
Reports
No.:
50-315/90018(DRS);
50-316/90018(DRS)
Docket Wos.:
50-315;
50-316
Licensee:
Company
1 Riverside
Plaza
Columbus,
OH
43216
Licenses
No.:
Facility Name:'.
C.
Cook Nuclear
Power Station,
Units
1 and
2
Inspection At:
Bridgman, llI
49106
Inspection
Conducted:
September
10-14, October
5 and
November 6,
1990
Inspectors:
But er
Date
ay
n rtz
a
g
Date
ny
resco - BNL
Date
e
e
Su
>van - BNL
Date
o as Storey -
AIC
Date
~. u9
o
l1.
i e
T
Leader
Date
/
Approved By:
R
n
.
ar ner,
C se
Plant Systems
Section
ate
5'Oi i 1 90225 90i i 05
ADOCK 050003i5
PAP.'
Ins ection
Summar
Ins ection
on
Se tember
10-14
October
5 and
November
6
1990
(Re orts
No. 50-315
90018 DRS; 50-316
90018
Areas
Ins ecte
Specia
, announce
inspection of licensee
action
on previous
inspection
in ings and
a full,scope reinspection
of Sections III.G, J and
L of
10 CFR Part 50, Appendix
R.
The inspection
was performed in accordance
with
NRC Hanual Chapter
Procedures
30703,
64100,
64704,
92701
and 92702.
Results:
In the areas
that were reviewed,
the following items were identified:
one v>elation of audit team composition
requirements
(Paragraph 3.i.); one
non-issued
deviation from a commitment to protect structural
steel
(Paragraph 4.a.);
one apparent violation with three
examples
of inadequate
design control (Paragraphs
4.b., 4.c.
and 5.e.);
one apparent violation with three
examples
of fai lure to
take adequate
corrective actions
including human factor procedural
deficiencies
and emergency
lighting deficiencies
(Paragraphs
5.b., 5.c.
and 7.); one apparent
violation concerning
an inadequate shift staffing procedure
(Paragraph 5.c.);
one apparent violation regarding
the loss of heating, ventilating
and air
conditioning
(HVAR) for both units'ontrol
rooms
(Paragraph 5.e.);
and
one
unresolved
item regarding the lack of a completed
high impedance fault analysis
(Paragraph 8.a.).
,
Persons
Contacted
DETAILS
Indiana tlichi an Power
Com an
- J
- R
- G
- K
tl.
- p
- J
R.
,. *p
- E
J.
- D
- L
- W
T.
R.
J.
- B
- l
American Electric Power Service
Cor oration
Allard, Computer Science
Allen, Maintenance-Regulatory
Group
P. Arent, Operations
R. Baker, Assistant Plant Manager of Production
E. Barfelz, Senior Engineer
Carteaux,
Superintendent,
Safety
and Assessment
Dwyer, tlaintenance-Regulatory
Group
J.
Heydenburg,
Computer Science
Jacques,
Fire Protection Coordinator
V. Kincheloe, Superintendent,
Training
Labis, Supervisor
Loope, Radiation Protection
J. tlatthias, Administrative Superintendent
A. ttichols, Operations
Training Supervisor
Postlewait,
Project Engineering Superintendent
Russell,
Project Engineering
R.
Sampson,
Operations
Superintendent
A. Svensson,
Manager,
Licensing Action Coordinator
L. ltagoner, tlaintenance
- tl.
D.
o*S
S.
- B
- R.
- B
- G
- P
- R.
- E
- K.
- L
- S
- H
P. Alexich, Vice-President,
Nuclear Operation
R.
Beam, guality Assurance
Engineer
J. Brewer, tlanager,
Nuclear Safety
and Licensing
R. Gane, Site gualhy Assurance Auditor
J.
Gerwe, Piping,
HVAC and Fire Protection
(PHF)
A. Green,
Nuclear Safety
and Licensing
Engineer
McLean, Nuclear Safety
and Licensing
Engineer
Patel,
Nuclear Design
J. Russell,
PHF
L. Shoberg,
Section
Manager
Taylor, Electrical Engineer
J. Toth, Licensing
H. VanGinhoven, Site Design
J. Wolf, Senior guality Assurance
Auditor
Young,
PHF-HVAC
Im ell Cor oration
- D. R. Brecken, Technical
Services
- D. S. Turley, Technical Services
- G. A. Weber, Section
Manager
e
U.S. Nuclear
Re ulator
Commission
- R. N. Gardner,
Chief, Plant Systems Section,'RS,
Region III
- J. A. Isom, Senior Resident
Inspector
- H. J. t~iiller, Director, Division of Reactor Safety,
Region III
- D. G. Passehl,
Resident
Inspector
- Denotes those
persons
in attendance
at the exit interview on
September
14,
1990.
'Denotes
those
persons participating in the telecon exit interview on
November 6, 1990.
The inspectors
also contacted
other licensee
personnel
during this
inspection.
Executive
Summar
A full scope,
post -fire safe
shutdown capability (10 CFR Part 50,
Appendix
R) reinspection
was conducted at the
D.
C.
Cook Nuclear
Power
Plant during the period of September
10 to November 6, 1990.
The
NRC
inspection
team reviewed the design
and implementation of Sections III.G,
J and
L of Appendix
R to 10 CFR Part 50, to ascertain
whether the licensee
was in conformance with the identified post fire safe
shutdown capability
requirements
including exemptions
and other requirements
approved
by the
Office of Nuclear Reactor Regulation
(NRR).
Significant post fire safe
shutdown capability deficiencies
were identified
by the licensee just before the inspection
and by the
NRC inspection
team
during the inspection period.
These deficiencies
included .the following:
(1) an inadequate
emergency lighting evaluation of two Emergency
Remote
Shutdown
(ERS) procedure revisions;
(2) inadequate
corrective actions regarding
emergency lighting system unit components;
(3)
a postulated
Appendix
R
fire in any of five fire zones
could have resulted
in a loss of HVAC
for both units control
rooms potentially affecting the ability to maintain
the plant in a safe
shutdown condition; (4) design translation deficiencies
that could have resulted in the loss of control power to all four
pumps or all four
CCW pumps;
(5) local shutdown instrumentation
(LSI)
panel
cable routing errors;
(6) lack of a completed
high impedance fault
analysis;
(7) an inadequate shift staffing procedure;
(8) examples of
mislabeling and/or difficult to accomplish
steps
in the
ERS procedures;
and (9)
a failure to design for a loss of control
room ventilation due to
postulated fires outside of the control
room.
Issues
(1), (7),
and (8)
were determined
to be deficiencies
having similarities to those deficiencies
identified during the
1982 Appendix
R post fire safe
shutdown inspection.
The deficiencies
identified in Issue
(8) were determined to be the types of
deficiencies
also identified during the
1988
Emergency
Operating
Procedures
(EOP) inspection.
Additionally,,the inspection
addressed
two
other issues
that are not related to the post fire safe
shutdown capability
aspects
of the inspection.
These additional
issues
are:
(1) utilizing a
licensee staff member for a triennial auditing
team while this individual
had direct responsibilities
in the area
being auditied;
and (2)
a deviation
from an
FSAR commitment to protect structural steel.
During the course of this inspection,
the following strengths
were
noted:
The reorganization
of the
ERS Procedures
(Revision 9) facilitated the
implementation of these
procedures.
The licensee's
administrative'ontrol
of combustibles
and maintenance
of fire protection
equipment
and fire area
boundary features
were
found to be of high. quality.,
The engineering
analyses
of fire detection,
suppression,
and fire
barriers
were found to be thorough
and detailed.
The
ERS procedure
status
tracking sheet was'ound to be very
beneficial during the implementation of this procedure.
3.
Action On Previous
Ins ection Findin
s
a.
(Closed) Violation (315/82-08-01;
316/82-08-01):
Redundant trains of
equipment,
cabling or associated
circuits for systems
necessary
to
achieve
and maintain hot shutdown conditions were not provided with
the fire protection features
required
by 10 CFR 50, Appendix
R,
Sections III.G.2 or III.G'.3.
Each of the examples
from this issue
are noted below along with the
inspector'
conclusions:
(1)
The Unit 1 component
cooling water
(CCW) redundant
pumps were
separated
by approximately
13 feet.
The Unit 2
CCW redundant
pumps were also separated
by approximately
13 feet.
The Unit 1
and Unit 2 redundant
pumps were in the
same
area
separated
by
approximately ll feet.
An ionization fire detection
system
was
installed in the
pump area.
were not installed
separating
any of these
pumps,
and
a fixed fire suppression
-system
was not installed in the area.
During this inspection, it was determined that by letter dated
December
23,
1983, the
NRC had granted
an exemption to the
licensee
allowing partial height fire barriers
separating
the
CCW pumps.
In addition, the exemption
was
based
on the
installation of an automatic water suppression
system
protecting the pumps.
The inspector
observed
the area containing the
CCW pumps
and
determined that the fire protection features
described
in the
Safety Evaluation Report
(SER)
had been properly installed.
Based
on the approved
and field verification,
this item is considered
resolved.
1
V
I
(2)
The Unit 1
CCll redundant
heat exchangers
were separated
by
approximately
12 feet.
Redundant
valves servicing the Unit 1
CCW heat exchangers
were also separated
by approximately
12 feet.
Ionization fire detection
and pre-action sprinkler
fire suppression
systems
were installed in the area.
No fire
barriers
were installed separating
the redundant
components.
Subsequent
to this finding, the licensee
modified their analysis
'- to rely on the unaffected unit for safe
shutdown.
The Unit
1
and Unit 2
CCW heat exchangers
are separated
by approximately
40 feet.
Automatic suppression
protects
the area
around
each
unit's heat exchangers.
Smoke detection
is provided in the
area of concern.
Any manual actions
necessary
to realign
from one unit to another
are in a different fire area
on another
elevation.
This arrangement
is considered
satisfactory
to
address
the above stated finding.
This issue is considered
resolved.
(3)
(4)
The Unit 2
CCW redundant
heat exchangers
were separated
by
approximately
12 feet.
Redundant
valves servicing the Unit 2
CCW heat exchangers
were also separated
by approximately
12 feet.
Ionization fire detection
and pre-action sprinkler
fire suppression
systems
were installed in the area.
Fire
barriers
were not installed separating
the, redundant
components.
Based
on the discussion
provided for issue
(2) above, this
example of the issue is also considered
closed.,
I
The Unit
1 redundant
essential
(ESW)
pumps were
separated
by more than
20 feet.
The Unit 2 redundant
ESW pumps
were also separated
by greater
than
20 feet.
Fire detection
and automatic fire suppression
systems
were not installed in
these
areas.
During this inspection, it was determined that the
December
23, 1983,
SER issued
by the
HRC approved
an exemption
for lack of automatic
suppression
for the areas
containing the
ESW pumps.
The exemption
was based
on the installation of
detection in these
areas.
During this inspection,
the
inspector verified that detection
had
been installed in the
areas identified in the
SER.
This issue is considered
resolved.
(5)
The Unit
1 redundant ventilation
system fan motor heater
control switches
and breakers for the redundant
pump rooms
were separated
by approximately
18 'inches.
The Unit 2
redundant ventilation
system fan motor heater control switches
and breakers for the redundant
pump
rooms were also
separated
by approximately
18 .inches.
These Unit
1 and Unit 2
controls were separated
from each other by approximately
,4 feet.
were not installed separating
any of
these
control switches or breakers.
Fire detection
and
automatic fire suppression
systems
were not installed in the
area.
~
~
r
(6)
This finding pertained
to Fire Zone
29G which is below the
pumps.
The December
23,
1983
SER approved
an exemption for
lack of suppression
in this Zone.
The redundant
cables
necessary
for safe
shutdown were identified in the
SER as being
protected with 1-hour rated material.
No other breakers
or
switches
were identified by the licensee
in their request for
exemption
as being required for safe
shutdown.
During this
inspection, it was verified that the cables
discussed
in the
SER were in fact protected.
It was also verified by the
licensee that the redundant fan motor control switches
and
breakers
mentioned
in the original findings were not required
for safe
shutdown.
Therefore,
based
on the approved
exemption
for this Zone
and
a field verification of the fire protection
features,
this issue is considered
res'olved.
The Unit 1 redundant
non-essential
service water system
(NESWS)
pumps were separated
by approximately
50 feet.
The Unit
1
redundant
NESWS
pump discharge
valves
(1-WMO 901
and
1-WMO 902)
were also separated
by approximately
50 feet.
were not installed separating
these
redundant
components.
Fire
detection
and automatic fire suppression
systems
were not
installed in the area.
Based
on
a re-analysis
by the licensee
since the original,
inspection,
the
NESWS
pumps were determined
not to be necessary
for safe
shutdown of the plant.
This was verified by the
licensee
during the inspection.
Therefore,
the original
concern is no longer applicable
and this issue is considered
resolved.
The Unit 2 redundant
NESWS
pumps were separated
by
approximately
30 feet.
The Unit 2 redundant
NESWS
pump
discharge
valves
(2-WMO 901
and
2-WMO 902) were also separated
by approximately
30 feet.
Conduits servicing the redundant
NESWS
pump discharge
valves
(Conduit 4126-2 for Valve 2-WMO 901
and Conduit 4140-2 for Valve
2-WMO 902) were separated
by
approximately
one foot.
were not installed
separating
these
redundant
components.
Fire detection
and
automatic fire suppression
systems
were not installed in the
area.
As with the Unit
1
NESWS
pumps discussed
above,
the Unit 2
pumps
have
been determined to be not necessary
for safe
shutdown.
Therefore, this issue is considered
resolved.
The Unit 1 plant air system
(PAS) and control air system
(CAS)
compressors
were separated
by approximately
11 feet.
A wet pipe
sprinkler system
was installed in the area.
were
not installed to separate
the redundant
components.
A fire
detection
system
was not installed in the area.
Based
on
a re-analysis
by the licensee,
the
PAS and
compressors
are
no longer necessary
for safe
shutdown.
Since
the above stated
issue is no longer applicable, this issue is
considered
resolved.
(9)
The Unit 2
PAS and
CAS compressors
were separated
by
approximately
11 feet.
A wet pipe sprinkler system
was
installed in the area.
were not installed to
separate
the redundant
components.
A fire detection
system
was
not installed in the area.
As with the Unit 1 compressors
discussed
above,
the Unit 2
compressors
are
no longer required for safe
shutdown
and this
issue is considered
resolved.
, (10) The Unit 1 and
2 control
rooms were provided with alternative
shutdown capability (Hot Shutdown Panels).
These
panels
were
separated
from their respective
control
rooms
by
a three-hour
rated fire barrier."'unctional fire detection
and fixed fire
suppression
systems
were not installed in the control rooms.
During this inspection, it was determined that the
December
23,
1983
SER approved
an exemption for lack of
automatic suppression
in the control rooms.
It was identified
in the
SER that detection
was provided in each control room.
During this inspection, it was verified that detection
was
present
in both control
rooms including the hot shutdown
rooms.
Based
on the approved
exemption
and verification that
detection
was .present,
this issue is considered
resolved.
(ll) The Unit 1 and
2 cable vaults are separated
from each other
by
a three
hour fire barrier.
The Unit 1 and
2 cable vaults
contain redundant
cabling for all safe
shutdown
equipment
including instrumentation
and control to both the respective
control
rooms
and hot shutdown panels.
The separation
requirements
of Section III.G.2 were not satisfied
in these
areas,
and alternative or dedicated
shutdown capability was not
=provided in accordance
with Section III.G.3.
Fire detection
and automatic fire suppression
systems
were installed in these
areas.
'uringth'is inspection, it was verified that alternate
shutdown
could be achieved
independent
of the affected
cable vaults.
The verification included electrical
and mechanical
systems
and
procedural
reviews which are discussed
in detail
in other
sections of this report.
Therefore,
since alternate
shutdown
capability
has
now been provided for each
cable vault mentioned
above, this issue is considered
resolved.
E
b.
C.
(Closed) Violation (315/82-08-06A; 316/82-08-06A):
Examples of
inadequate
alternate
safe
shutdown procedure.
This issue is addressed
in Paragraph
5 of this report.
(Closed)
Open Item (315/82'-08-07;
316/82-08-07):
The
ERS procedure
lacked organization.
This issue is addressed
in Paragraph
5 of this report.
d.
, (Closed)
Open Item (315/82-08-08;
316/82-08-08):
The inspectors
examined
the procedure
review process
and found that the review and
approval of procedures
did not include
a walk-through to determine
procedure feasibility
and adequacy.
This issue is addressed
in Paragraph
5 of this report.
e.
(Closed)
Open Item (315/87016-03;
316/87016-03):
Numerous
concerns
regarding the completeness,
technical
adequacy,
and prioritization
of various steps
in the
ERS procedure
were identified.
This issue is addressed
in Paragraph
5 of this report.
(Closed)
Open Item (315/89004-01(DRS)
316/89004-01(DRS)):
The
licensee
had not ensured
that all fire dampers
would close under
air-flow conditions.
The licensee
had tested
Ruskin dampers
which
were the subject of a Part
21 report.
However, the licensee
was
requested
to verify that all dampers
regardless
of manufacturer
would close
under air-flow conditions.
In addition, the licensee
was requested
to make the test results available for inspector
review.
During this inspection,
the inspector
reviewed fire damper test
results.
The licensee
presented
closure test data for the majority
of fire dampers
under actual air-flow conditions.
The licensee
stated that for some
dampers it was not practical to perform an
actual test, either
due to damper size or location.
For these
the licensee
performed calculations
to determine if the
would close.
The inspector
discussed
both the test data
and
the calculations
and found them to be acceptable.
Based
on the
licensee's
damper test program, it was determined that
a number of
may not close under air-flow conditions.
The licensee
had
implemented administrative controls to manually shut-off ventilation
for a fire in the affected areas.
The inspector
reviewed these
procedures
and found that they did not clearly state
which fans
required
shutdown for given fire locations.
The licensee
presented
the inspector with modified procedures
prior to the end of the
inspection.
These revised procedures,
1-OHP 4024.102,
Revision 4,
2-OHP 4024.201,
Revision 4,
and
1-OHP 40240.10,
Revision 4, clearly
identified which fans required
shutdown.
This issue is considered
closed.
(Closed)
Unresolved
Item (315/89004-04(DRS);
316/89004-04(DRS) ):
During a review of Plant Manager Instruction (PHI) No. PHI-2270,
Revision 19, "Fire Protection," it was noted that the procedure
pertained
only to specified
areas
of the plant which contained
safe
shutdown
equipment.
The inspector
observed that the corridor to the
diesel
generator
rooms of 'each unit contained
safe
shutdown cabling,
but these
areas
were omitted from the procedure.
The licensee
provided
a response
to this issue that clarified that
the intent of Paragraph
4.9 of the
PHI was to identify the entire
auxiliary building as having
a more restri ctive administrative
control than certain other plant areas.
To add clarity to the
PHI-2270 specified
paragraph,
the licensee
implemented
a procedure
change to specifically address
the diesel
generator
corridors.
This
issue is considered
resolved.
(Closed) Violation (315/89004-05(DRS);
316/89004-05(DRS)):
During
a
plant walkdown of the carbon dioxide
(CO
) system valves,
an
inspector
observed
an operator verify that
a valve was
open
as
required;
however, with the chain
and seal
in their as-found
condition, the valve could have
been
closed without disturbing the
seal.
During this inspection,
an inspector verified that the previous
improperly sealed
valve (No. 12-FCO-174)
was sealed
properly
and was
in the correct
(open) position.
In addition,
two other carbon
dioxide
(CO
) system valves were'lso verified to be sealed
properly
and in the correct position.
Further,
the licensee
provided
Operating
l1emo 89-071
( I) which emphasized
the importance of proper
sealing of
CO
valves
and,
in particular,, the type of valve related
to the above issue.
On the above basis, this issue is considered
resolved.
(Closed)
Unresolved
Item (315/89004-06(DRS);
316/89004-06(DRS)):
A
concern
was raised regarding
the audit team composition in that
audit team personnel
selected
by the licensee
had direct
responsibility for the fire protection
program which was being
audited.
On September
19, 1990, discussions
regarding this issue
were
conducted
by telecon
between
licensee staff and
a Region III
inspector.
The licensee reiterated
points discussed
in the
licensee's
internal
response
to the issue
dated
September
6, 1990.
Specifically, the licensee
emphasized
that the individual in
question,
although identified as
an audit team member,
served in a
technical advisor/facilitator capacity only.
The licensee
also
cited additional
NRC guidance
information which the licensee
believed to be appropriate for the issue
in question.
The inspector
concurred that having qualified licensee
personnel
available
who are
responsible for fire protection, to clarify and answer audit related
questions
during an audit is most appropriate;
however,
including
these
individuals as audit team
members
was not considered
appropriate.
10
0
In accordance
with the gA audit criterion and Generic Letter 82-21,
the three-year
audit must (emphasis
added
in the Generic Letter) be
performed
by an outsi3e
independent fire protection consultant.
The
fire protection engineer
can
be
a licensee
employee
who is not
directly responsible for the site fire protection
program for two'f
three years,
but must also* be an outside
independent fire protection
consultant
every third year.
During this inspection, it was the inspector's
conclusion that the
audit team
member identified in
NRC Inspection
Report
Nos.
315/89004-06(DRS)
and 316/89004-06(DRS)
had direct responsibility
for portions of the fire protection
program (design)
being audited.
Those portions of the fire protection
program being audited included
the Safe
Shutdown Capability
Assessment,
th'e Fire Hazards Analysis,
Information Notice No. 88-04,'nd other requirements.
Having
an
audit team composition
as described
in the licensee's
internal
response
did not assure
the independence
of future fire protection
audit teams.
Therefore,
based
on the above, this issue is considered
a violation (315/90018-01(DRS);
316/90018-01(DRS))
as described
in the
On September
28,
1990, the
AEP Director of guality Assurance
specified
that for future triennial fire protection audits,
individuals having
'direct fire protection responsibility for this program wi 1'I no longer
be included
as
members of the audit team.
On this basis, this issue
is considered
resolved.
(Closed) Violation (315/89004-07;
315/89004-07):
This issue
regarded
the incorrect'erouting
of the control cables for the
Unit 1 East
and Unit 2 West
pump discharge
valves out of the
opposite Unit control
room cable vaults.
The licensee
implemented
modification No. 12-Htl-028 to reroute the affected cables
out of the
opposite Unit control
room cable vaults.
The rerouting
was
completed
on tray 10, 1989, in Unit 1 and
on February
15, 1989, in
Unit 2.
In addition, the licensee
enhanced
procedure
Nos.
GP.3.1
(Design
Changes)
and
Pt1P,5040
NOD.004 (Request
For Change)
by
strengthening
the design verification process.
The procedure
changes
should prevent the recurrence
of design control problems
in
the future.
The inspectors
have
no further questions
on this item.
(Closed) Violation (315/89004-08;
316/89004-08):
The incorrect
electrical
cable routing that was identified during the licensee's
corporate
design
reviews
on September
15
1988,
was not communicated
to the plants'taff in
a timely manner
greater
than
90 days from
the date of discovery).
The licensee
reviewed their corrective
action process
and determined that existing controls were sufficient
to ensure that violations in this area
would be prevented
in the
future.
In addition, involved licensee
personnel
were instructed
as
to the importance of prompt communication of problem report
evaluation results.
"I
The inspectors
had reviewed the licensee's
corrective actions for LER
Nos.
315/90008 (refer to Paragraph
4.b.)
and 315/90010 (refer to
Paragraph 4.c.).
The corrective actions
were initiated in a timely
manner
and they were adequate
in the short term until the final
corrective actions
are
implemented
in upcoming outages.
The
inspectors
have
no further questions
on this item.
(Closed)
Unresolved
Item (315/89004-09;
316/89004-09):
Determine
if non high/low pressure
interface control cables
should
be analyzed
for two hot shorts within a multiconductor cable.
The
NRC has determined that multiple shorts within a multiconductor
cable is not
a credible event for a non high/low pressure
interface
circuit.
This position is consistent with 'the guidance
contained
in
The inspectors
have
no further questions
on
this item.
~b1
E
The inspectors
reviewed the following Licensee
Event Reports
(LERs) by
means of direct observation,
discussions
with licensee
personnel,
and
a
review of related
documentation.
a ~
(Closed)
LER (315/90007-LL; 316/90007-LL):
This LER, although not
reportable,
was voluntarily submitted
by the licensee.
The
LER
regards
the failure to apply fire resistive material
on exposed
structural steel within five lube oil storage
rooms.
This failure
to protect the structural
steel
was determined to be
a deviation
from a licensee
commitment which was described
to the
NRC in a
January
31,
1977 response
to Appendix A to Branch Technical
Position 9.5.1.
According to the licensee's
evaluation,
each of'the lube oil rooms
is equipped with fire detection
and fire suppression
capability, in
addition to fire brigade availability following identification of a
'ire
condition.
The licensee's
corrective action to protect, the
exposed structural
steel
was scheduled for completion
by
October 1, 1990.
During this inspection,
an inspector toured the identified areas
and
three others
the licensee
had found in need of additional structural
steel protection.
The inspector
observed that fire resistive material
installation activities were in progress
and certain of these
rooms
were nearing
completion.
Discussions
held between
Region III staff
and
NRC Headquarters
Fire Protection
personnel
did not reveal
any
further required actions,
including int'crim compensatory
measures.
However, this issue is considered
a deviation (315/90018-02(DRS);
316/90018-02(DRS))
from the licensee's
January
31,
1977 commitment.
This issue
meets
the tests of 10 CFR Part 2, Appendix
C,Section V.G.;
consequently,
no Notice of Deviation will be issued
and this issue is
considered
closed.
12
I'
(Closed)
LER (315/90008-LL; 316/90008-LL):
This
LER regarded
10 CFR Part 50, Appendix
R design translation deficiencies
which could have
resulted
in the loss of control, power to all fou'r
pumps or all
four of the
CCW pumps.
On June
19, 1990, the lice'nsee identified that the isolation relay
circuitry for the
ESN low header
pressure
auto-start circuitry had
been incorrectly installed.
The Unit
1 pressure
switches
(WPS 701
and
WPS 705) are located in the
ESW Pipe Tunnel (Fire Zone 112).
The Unit 2 pressure
switches
(WPS 702 and
WPS 706) are also located
in the
ESW Pipe Tunnel (Fire Zone 113).
However, the four pressure
switches
are located within approximately
3 feet of each other in
the center of the shared
pipe tunnel.
There is no automatic
detection
or suppression
capability located'n this area.
The proposed
design
(RFC-01-2668
and RFC-02-2685)
was to install
isolation fuses
(10A) and the isolation relay
(63X-HPL) in the start
circuitry of each
ESW pump.
The relay coil was to connect directly
(through fuses)
to the
DC control
bus through the pressure
switch
auto-start
contact.
A fire in the
ESW pipe tunnel would have
caused
the isolation relay fuses to blow, isolating the affected pressure
switches.
Control power would therefore
be available for starting
the
ESW pumps.
The design
sketch
was sent to drafting for incorporation onto the
installation drawings.
However, during translation,
the isolation
relay fuses
were
shown connected
to the breaker's
internal
control power.
The breaker's
control
power is fused through
a
10A
fuse in series with a 35A bus fuse.
A fire induced short in a
pressure
switch had the potential to blow that breaker's
10A control
power fuse.
Because
of the close proximity of all four pressure
switches, all four of the
ESW pumps
could have lost their control
power.
On June
20, 1990, the licensee identified that the
same condition
existed in the isolation relay circuit for the low header
pressure
auto-start circuit for the
CCW pumps.
The
CCW pressure
switches
and
pumps are located in Fire Zone 44 south.
The licensee
had installed
a 78 inch high, three (3) hour rated fire wall between
the Unit
1
and Unit 2 pumps.
There were
no intervening combustibles
traversing
the fire wall.
The pressure
switches
were installed
approximately
15 feet on either side of the wall, and automatic
detection
and suppression
was provided in the fire zone.
The inspectors
reviewed the two request for change
(RFC) packages
that installed the modifications.
Both packages
proposed
the
correct design.
The installation drawings that were received
back
from drafting with the incorrect design
had been
checked,
and
approved for construction
by the cognizant engineer.
This condition
has existed
since the installation of other Appendix
R type
modifications
(1985 time frame).
13
~
~
~
C.
Failure of the licensee
to verify that the
ESW and
CCW isolation
relay design
had been correctly translated
onto drawings
by
a design
interface organization is an example of an apparent violation
(315/90018-03a(DRS);
316/90018-03a(DRS))
Criterion III, Design Control.
The licensee
took immediate corrective actions
when the above
discrepancies
were discovered.
The negative
and positive leg
10A
fuses that were in series with the isolation relay coil were
replaced with 5A fuses.
This established
an acceptable
fuse to fuse
selectivity ratio with the
10A breaker control power fuse.
Minor
modification 12-NH-110 was
issued to restore
the wiring and fuses to
the original design intent.
Unit 2 rewiring is in progress
and Unit 1
rewiring will be completed
during the next refueling outage.
The
ESW and
CCW systems
are placed in service to,support residual
heat
removal
(RHR) cooldown in Procedure
No.
1-OHP 4023.001.001,
"Remote
Shutdown Procedure."
If either of these
systems
are not
available,
the procedure
provided instructions
on
how to initiate
restoration.
Local control of the above
system breakers
is
established
by removing the control fuses,
stripping all the
outgoing wires and installing
a jumper on Terminal Block No. AJ. If
electrical
power
cannot
be restored
to the breaker, it is up to the
control
room operator to direct
a manual closing of the breaker.
The
charging spring should
be charged at this time which would permit
one manual
close attempt.
If this failed,
a jacking bar would be
used to manually recharge
the spring.
A reactor operator
accompanied
by the inspectors
walked through the
manual
closing steps
and the manual jacking steps.
All of the
reactor operators
and auxiliary equipment operators
had received
training on manual operation of the 4160
Vac breakers.
The equipment utilized for manual operation of the breakers
was
provided in locked storage
near the breakers.
The Appendix
R tool
box was located in the switchgear
room and contained
the jumpers
and the breaker
manual trip cord.
Personal
safety gear,
such
as
face shield, gloves
and protective clothing,
and the jacking bar
were stored in a locked cabinet just outside of the switchgear
room.
The reactor operator
was able to collect the necessary
equipment in a reasonably
short time frame.
Based
on the above,
the licensee
would have
been able to mitigate
the consequences
of a complete
loss of
ESW or
CCW control power and
restore
ESW or
CCW flow to support
RHR cooldown.
(Closed)
LER(315/90010-LL; 316/90010-LL):
This
LER regarded
10 CFR,
Part 50, Appendix
R cable routing deficiencies that had the
potential to cause
a loss of power to the Local Shutdown Indication
(LSI) panels.
e
14
The licensee identified in, Problem Report
No.90-874,
dated
July 20, 1990, that
a number of Appendix
R safe
shutdown
cables
had been incorrectly routed.
The licensee
determined
on August 24, 1990, that Unit 1 safe
shutdown
cable
No. 1-29685G,
which 'runs between
LSI panels
No. 1-LSI-6 and
1-LSI-6X, ran through fire zones
41, 55,
and
56 (fire areas
(FA) 40,
48,
and 49) which required
complete alternative
shutdown.
The Unit 1 normal
power feed to the 1-LSI panels
was
assumed
to be
lost for a fire in any one of the above fire zones.
A fire induced
fault in cable
No. 1-29685G would have eliminated the Unit 2
alternate
feed to the 1-LSI panels.
Due to the cable misrouting,
the 1-LSI panel indications would have been'ost.
The existing plant
operating
and emergency
procedures
did not cover such
an event.
On September
6, 1990, it was discovered that
a similar condition
existed for one plant area involving the Unit 2 LSI panels.
Cable
No. 1-1936R,
which provides the Unit 2 LSI panel's
alternate
power,
had been
run through fire zone
24
(FA 29) along with the LSI panel's
normal
power supply cable (2-12467).
Neither of the cables
had been
provided with acceptable
protection from fire.
Consequently,
a fire
in fire zone
24 could have
caused
a complete loss of normal
and
alternate
power to the Unit 2 LSI panels.
However, fire zone
24 is
not a complete alternate
shutdown area
and the Unit 2 LSI panels
would not be required for a fire in this zone.
These conditions
have existed
since the installation
o'f other Appendix
R type
modifi cat ion s (1985/1986
time frame) .
For two of the affected locations
(FA 40 and 29), the licensee
claimed either
a power source
was subsequently
found available
or
that
an indirect means
was avai lable to obtain instrumentation
information.
For the remaining
two areas
(FA 48 and 49),
no
alternative
methods or means
were
known to have existed for obtaining
the lost instrumentation
information.
This could have adversely
affected
an orderly plant cooldown or could have adversely affected
the licensee's ability to maintain the reactor in a safe condition.
For
a fire in fire zone
41
(FA 40), the licensee
has determined that control
room indication would not have
been lost.
The preferred
power
source
to the control
room instrumentation distribution inverters is
located in fire zone
42C.
Therefore
normal control
room process
monitoring indication would have
been available.
However, safe
'shutdown procedures
did not address
the complete loss of the LSI
panels
and did not provide instructions to use the control
room
instrumentation.
For
a fire in fire zones
55 and
56
(FA 48 and 49), both control
room
and 1-LSI power would have
been lost.
The licensee
has determined
that local steam pressure
indication would have
been available.
However, instrumentation
such
as
RCS pressure,
pressurizer
level,
letdown
and charging flow, T-hot, T-cold, source
range,
level,
and
RCS wide range
temperature
which are required for complete
alternate
shutdown
areas
would not have
been available.
0
S
Failure of the licensee
to verify or check that Cable
No.
1-29685G
and Cable
No. 1-1936R were routed correctly are additional
examples
of an apparent
viol.ation (315/90018-03b(DRS);
316/90018-03b(DRS))
of
10 CFR 50, Appendix B, Criterion III, Design Control.
The licensee
took immediate corrective action (Unit 1 LSI panels)
and installed
a lA fuse to provide electrical isolation of cable
No. 1-29685G.
This fuse satisfactorily coordinates
with the upstream
2.5A fuse.
The two fuses
were of the
same class,
rating
and
manufacturer.
Cable
No.
1-29685G will be rerouted out of the
affected fire zones
in the near future.
The licensee
has initiated tlinor tiodification 2-f1N-132 (Unit 2 LSI
panels)
to provide
a one (1) hour fire wrap around approximately
10 feet of conduit No. 2-12467 that is run through fire zone
24
(FA
29).
Upon completion, this will bring this fire zone into compliance
with Appendix R.
The fire wrap was to be completed
during the Fall
1990 Unit 2 outage.
In all of the above fire zones,
suppression
and detection capability
was available.
5.
ERS Procedure
Review
a
~
ERS Procedure
1-OHP 4023.001.001
Revision
9
The licensee
has
developed
Procedure
1-OHP 4023.001.001
to provide
an alternate
method of achieving safe
shutdown in Unit 1 with or
without offsite power available in the event of a fire which
precludes
control of Unit 1 equipment
from the control
room or hot
standby
panel.
Once the procedure is entered
and the decision is made to evacuate
the control, room, the reactor is tripped from the control
room and
the
ERS team is assembled.,
Several
other immediate actions will be
attempted
from the control
room prior to evacuation.
If unsuccessful,
the remaining
immediate actions
can
be performed from outside the
control
room.
The Unit Supervisor will assign specific procedural
attachments
to the four reactor operators
assigned
to the
ERS team
by
the Shift Supervisor.
When
an operator is assigned
an attachment
by
the Unit Supervisor,
he/she will perform that attachment
in its
entirety
and then inform the Unit Supervisor
when completed,
and
await further instructions.
The Unit Supervisor will track
attachment
assignments
and completions
on the
ERS Procedure
Status
Tracking Sheet
which allows the Unit Supervisor to maintain
a
complete record of the procedure
and
ERS team
member
status
during
procedure
implementation.
16
b.
Plant Mal kdowns
Plant walkdowns of selected
ERS procedure
attachments
were performed
during this inspection.
The walkdowns were performed
by
a
team'onsisting
of one
NRC inspector
and two licensee
representatives.
The walkdowns were performed to verify that the
ERS procedure
specified
actions
could be accomplished
using existing equipment,
controls,
and
instrumentation.
During inspector discussions
with licensee
personnel,
, it was indicated that the
ERS procedures
had been previously walked
down in accordance
with their administrative
procedures.
However,
the following are specific examples
of procedure deficiencies that
were identified during the inspection
Attachments
LS-2-1, "Cross-tie
1E/2W 'A'FW," and LS-2-2, "Cross
Tie 1W/2E AFW," Step 2.a directs
an operator to manually
open
the motor driven auxiliary feedwater
pump discharge
cross-tie
,valves.
However, the valves are located approximately
8 feet
from the floor and would be difficult to reach without the use
of a ladder.
There
was
no dedicated
ladder available for this
purpose.
The
NRC inspector
determined that
a competent
operator
could reach
the valves
by standing
on existing
suppor ts located
on the floor below the valves.
Attachment LTI-3-1, "DG1AB Trip And Isolation," Step 1.a.2.c
directs the operator to close
DG1AB Air Receiver Outlet
Valves 2-DG-184A and 2-DG-186A.
However,'he
valves in the
plant are labeled
as
DGlAB Air Receiver Outlet Valves
and lDG-185A.
The fact that there are only two valves
on the
outlet of the air receivers
allowed the licensee
representative
to identify the valves that were required to be closed
even
though the procedure
referenced
the incorrect valves.
The
procedure deficiency delayed
completion of this step
due to
confusion
on the part of the licensee
representative,
but did
not prevent the task from being accomplished.
Therefore, this
deficiency is not considered to be safety significant.
In
addition, completion of this particular attachment
is not
required to achieve
hot shutdown conditions for the plant.
Attachment LTI-1-3, "Local Generator
Output Breaker Trip And
Isolation," Step 1.c.2.a directs the operator to install
a
jumper between points Hl and Kl on terminal blocks
H and
5 in
the circuit breaker
K control cubicle.
The procedure,
as
written, implies that the location of the circuit breaker
K
control cubicle is the 345kv switchyard control building.
Contrary to this, the circuit breaker
K control cubicle is
actually located in the 345kv switchyard area.
Due to this
procedure deficiency, the licensee
representative
searched
for
terminal blocks
H and
K in the control building for approximately
30 minutes prior to locating them in the switchyard.
Completion
of this attachment
is strictly for equipment protection, specif-
ically the main generator,
and is not required to achieve
hot
shutdown conditions in the plant.
Therefore, this is not
considered
safety significant.
12
C
Attachment LS-2-3, "Relatch Ul Turbine Driven Auxiliary
Pump (TDAFP)," Step 3.a.2.b directs the operator to
install
a jumper across
terminal block TCF points
14A and
15 for
local
TDAFP turbine
speed
indication.
However, there
was
no
dedicated
jumper available at'the cabinet to complete this step
which would delay, completion of this attachment.
Completion of
this particular attachment
is not required to achieve
hot
shutdown conditions in the plant.
Therefore, this finding is
not considered
to be safety significant.
It was determined following an in-office review that similar human
factor procedure deficiencies
were identified during the
1982 Appendix
R
inspection
and
1988 Emergency Operating
Procedure
inspection.
Based
on the recurring
human factor procedural
deficiencies identified
during this inspection,
these repetitive types of deficiencies
are
considered
an apparent violation (315/90018-04a(DRS);
316/90018-04a(DRS))
of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action.
Simulated Fire Scenario
A simulated fire in the cable vault requiring control
room evacuation
was conducted utilizing a crew of licensed operators that were on
their continuing training week.
The crew consisted
of a Shift
Supervisor,
a Unit Supervisor
and four reactor operators.
This is
the required
ERS team composition
necessary
for ERS procedure
implementation
as
committed to by the licensee.
A member of the
inspection
team accompanied
each operator performing the tasks
assigned
by the Unit Supervisor.
The scenario
was terminated after
stable
hot standby conditions were achieved.
The scenario
was
a timed exercise
in which the inspection
team could
analyze
the following time sensitive actions
and their associated
required
completion times
as identified by the licensee:
Perform
a reactor trip prior to control
room evacuation.
Establish
RCS isolation within 8 minutes of spurious
pressurizer
PORY operation.
Restore
process
monitoring instrumentation within 20 minutes of
control
room evacuation.
Restore
RCP seal injection within 30 minutes of loss of
charging
and thermal barrier cooling.
- Restore Auxiliary Feedwater flow within 40 minutes of reactor
trip.
Commence
RCS cooldown within 90 minutes of initiating seal
injection.
18
0
n,
The inspection
team noted the following items
as
a result of the
simulated fire scenario
timed exercise:
1
The communications
to and from the Unit Supervisor
were clear,
concise
and easily understood.
The
ERS procedure
status
tracking sheet is
a very effective
tool for the Unit Supervisor
during procedure
implementation.
All of the identified. time sensitive actions
were completed
within the allowed time.
The external
speaker for the radio at the hot Shutdown
Panel
failed to function.
However, the headset
that the Unit
Supervisor
was wearing did function properly.
The operators
displayed
a good understanding
of the procedure
and the safe
shutdown
equipment required.
After initial control
room evacuation,
some operators
re-entered
the control
room through the affected fire barrier to get
assignments
from the Unit Supervisor.
When the inspection
team
questioned
the licensee
about this inappropriate transit route,
the licensee identified an appropriate alternate
route that
would be used
by the operators
in the
case of a real fire
emergency.
CVCS cross-tie flow indicator 12-gFI-201 is
a 0-150
gpm dual
gauge which is to be used to locally monitor
CVCS flow for
pressurizer
level control.
The dual
design allows the
same
gauge to be used
when Unit 1 is supplying Unit 2 as well
as
when Unit 2 is supplying Unit 1.
The gauge
design
along
with its proximity to the
CVCS cross-tie flow control valve
rendered
the flow indication difficult to read.
While executing
attachment LTI-2-1, "Steam Line Isolation,"
vent valves
1-CA-2515 and 1-CA-2480 are required to be opened
to bleed control air from 1-t<RV-242 and 1-NRV-231 causing
them
to fail open.
It was noted that 1-CA-2515 and 1-CA-2480 had
installed pipe caps which required
a wrench for their removal
to accomplish the task.
flo dedicated
wrench
was available for
this purpose.
This could preclude'ompletion
of this attachment
in a timely manner.
Completion of this attachment
is not
required to achieve
hot shutdown conditions
and is therefore
not
considered
to be safety significant.
This item is
a further
example of an apparent violation (315/90018-04b(DRS);
316/90018-04b(DRS))
of 10 CFR 50, Appendix B, Criterion XVI,
Corrective Action.
19
At the conclusion of the simulated fire scenario,
the findings were
discussed
in detail with the licensee.
The licensee
acknowledged
the inspection
team's
observations
and stated that they would
evaluate
the need for a different method of verifying CVCS cross-tie
flow.
The licensee
also stated that any tools required to
accomplish
procedural
tasks
would be dedicated for that purpose.
V
I
In general,
the inspection
team concluded that the D.
C.
Cook
ERS
procedure
was technically accurate
and could be accomplished
using
existing equipment,
controls -and indications.
This inspection
review encompassed
an overall re-review of the
ERS procedure.
The
current
ERS procedure revision eliminated
many of the previous
ERS
procedure deficiencies identified in previous inspections.
Other
current
ERS procedure deficiencies
are discussed
in this report.,
On
the above basis,
inspection report items 315/82-08-06A
and 07;
316/82-08-06A
and
07 are considered
closed.
In addition, inspection
report item 315/87016-03;
316/87016-03
is also considered
closed.
The licensee
committed to perform complete
walkdowns
on both Unit 1
and Unit 2
ERS procedures,
and to incorporate
any applicable
human
factor procedure
deficiencies identified including the
human factor
procedure deficiencies identified by the inspection
team.
The team noted that the minimum staffing requirements
described
in
OHI-4011, "Conduct Of Operations" (Shift Staffing), Revision 4, were
not sufficient to ensure that the required
number of licensed
operators
would be available to implement the
ERS procedure.
The
minimum shift staffing requirements
identified in OHI-4011, Step
3.1. 7, were
as follows:
a)
With both units operating
(Nodes
1 through 4)
1 Shift Supervisor
(SRO)
2 Unit Supervisors
(SRO)
4 Reactor Operators
(RO)
4 Auxiliary Operators
b)
With one unit operating
(t1odes
1 through 4)
1 Shift Supervisor
(SRO)
1 Unit Supervisor
(SRO)
3 Reactor Operators
(RO)
3 Auxiliary Equipment Operators
In addition,
Step 3.1.2 of OHI-4011 states,
"A unit supervisor with
a Senior Reactor Operators
license
(SRO), shall, at all times
be in
the control
room from which
a reactor is being operated,"
and Step
3.1.3 of OHI-4011 states,
"A licensed
Reactor Operator shall
be
present at the controls at all times."
In the event of a fire in one
unit with both units operating,
a minimum of five Reactor Operators
would be required.
Four Reactor Operators
wo~u
d be required to
implement the
ERS procedure
and
one Reactor Operator would be required
to remain "at the controls" in the unaffected unit.
Contrary to
this, the minimum staffing requirement
described
in OHI-4011, Step
3. 1.7.a, for both units operating,
was
4 Reactor Operators.
20
,I
Additionally, an Appendix
R fire with only one unit operating
would
also require
a minimum of five reactor operators.
Contrary to this,
the minimum staffing requirement
described
in OHI-4011 Step 3.1.7.b.
for one unit operating,
was three reactor operators.
In this
situation,
the minimum staffing requirements
would fail to ensure
enough
licensed
personnel
were available to implement the
ERS
procedure.
The licensee
took prompt corrective actions
when the inspection
team
identified the inadequate
minimum staffing requirements.
Standing
Order OS0.100,
"Administrative fianning Requirements-Appendix
R,"
Revision 0, was issued
on September
26, 1990, to specify the following
minimum shi'ft manning requirement
when
one unit is in Nodes 1-4:
Three (3) - Senior Reactor Operators
Five (5) - Reactor Operators
(can hold
SRO license)
Six (6) - Auxiliary Equipment Operators
In addition, the licensee
has
committed to revising OHI-4011 by
December
15,
1990, to reflect the minimum shift manning requirements
described
in Standing
Order OS0.100.
The licensee
was informed that failure to assur e that activities
affecting quality are prescribed
by adequate
procedures
and
accomplished
in accordance
with the procedures
is an apparent
violation (315/90018-05(DRS);
316/90018-05(DRS))
of 10 CFR 50,
Appendix B, Criterion V, Instructions,
Procedures
and Drawings.
ERS Procedure
Review and
A
royal Process
With the exception of one procedural
deficiency which the licensee
promptly corrected,
the inspection
team considered
the review and
approval
process
in place for the
ERS procedure
to be adequate.
On
this basis,
Inspection
Report item 315/82-08-08;
316/82-08-08 is
considered
closed.
A ril 1990
SER Issue 2.8.1 - Need for HVAC to Su
ort Safe Shutdown
The staff noted that except for certain electrical
equipment
such
as the emergency
diesel
generators
HVAC was not identified as being
required to maintain the viability of safe
shutdown equipment.
During the audit, the licensee
provided calculations
addressing
the
following equipment
and scenarios:
(1)
Steady state
temperature
in the diesel
generator transfer
pump
room under loss of HVAC.
(2)
Haximum ambient temperatures
in the Hest motor-driven auxiliary
pump room 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after loss of HYAC due to a fire.
(3)
t'laximum ambient temperatures
in the East
and West switchgear
rooms
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after loss of HYAC.
Also included were similar
calculations for the
4KV switchgear
rooms, inverter room,
CRDN
power cabinet
room and battery
room.
21
(4)
72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> time-temperature
curve calculations for centrifugal
char ging
pump rooms with the
pumps running
and
no forced
ventilation.
(5)
Steady state
temperature
in any
RHR pump cubicle with the
pump
running
and
no forced ventilation.
Also provided was
an undated
"Loss of HYAC Study" which attempted
to
answer the staff's concerns,
and
an internal
memorandum
dated
April 26, 1988, which addressed
the loss of ventilation to the diesel
generator
rooms,
the inverter rooms
and the
AB and
CD battery
rooms
from the perspective
of routing of electrical
cables
and associated
circuits.
The most obvious omissions
in the licensee's
information were the
following:
(1)
An analysis
regarding
the loss of control
room ventilation
due
to postulated fires outside the control
room.
(2)
An analysis
regarding
loss of ventilation to one unit'
mechanical
components
such
as the centrifugal charging
pumps or
pumps.
The failure to verify that the design of the
HVAC fan motors'ircuits
precluded, for fire zones
44N/44S,
51/52 or 69, the vulnerability of a
simultaneous
loss of HVAC for both Unit 1 "and Unit 2 control
rooms
is considered
a further example of .an apparent violation
(315/90018-03c(DRS);
316/90018-03c(DRS))
Criterion III, Design Control.
In response
to the inspector's
questions, it was determined that
a
postulated fire in fire zones
44S/44N,
51/52 or 69,
as described
in
LER Nos.
315/90009-LL; 316/90009-LL, could result in a loss of HVAC
to both units'ontrol
rooms simultaneously.
The licensee's
evaluation of control
room temperature
response for a loss of both
unit's
HYAC, without a co'ncurrent
loss of off-site power,
concluded
that the control
room temperature
would reach
120 degrees
F in two
hours,
135 degrees
F in ten hours
and
175 degrees
F at the end of
the
72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> period.
Additional control
room temperature
evaluations
were conducted
by the licensee utilizing different event criteria.
Two additional evaluations
that were performed
concluded the following:
If normal control
room lighting was shut off, (with the
operators utilizing emergency lighting) combined with propping
open the control
room doors
leading to the turbine building,
the control
room temper ature would reach
120 degrees
F in 18
hours
and the maximum control
room temperature
would be 133.9
degrees
F.
If both the control
room doors leading to the turbine building
and the door leading to the auxiliary building were propped
open while using portable fans to circulate air through the
control
room at 4000 cfm, with normal control
room lighting, the
22
control
room, temperature
would reach
120 degrees
F in 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />.
The maximum control
room temperature
under those criteria would
be 132.2 degrees
F.
It was concluded that for all cases
the operators
could achieve
hot
standby
and execute
actions to be in hot shutdown from each'unit's
control
room.
Following the time period to reach
120 degrees
F, the
control
rooms would become uninhabitable.
Evacuation of both control
rooms would be required
and the
ERS procedure
would be implemented
..for both units.
The following is the issue of concern regarding
loss of HVAC to both units simultaneously.
)
1
The
ERS procedures
in effect during the inspection
were not
designed
to shutdown both plants simul'taneously.
This could
adversely affect the licensee's ability to maintain hot standby
conditions
and subsequently
achieve
cold shutdown conditions
within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
Additionally, simultaneous
implementation of
the
ERS procedures for Unit 1 and Unit 2, if both units were
operating,
would appear
to require
11 licensed operators,
1 Shift Supervisor
(SS),
2 Unit Supervisors
(USs),
and
8 Reactor
Operators
(ROs)
(4
ROs for each unit).
Contrary to this, the
licensee
recently- issued Operations
Standing
Order OS0.100,
"Administrative Manning Requirements
- Appendix R," Revision 0,
which requires
only 8 licensed
operators
(3 Senior Reactor
Operators
(SROs),
5 ROs)
as the minimum shift manning with one
unit operating.
This would provide the
number of licensed
operators
needed
to shut
down one unit, but would fail to ensure
enough
licensed operators
were available to simultaneously
implement the
ERS procedure if both units were operating.
OS0.100 is presently
the most conservative
requirement
regarding
shift manning in effect.
This issue is considered
an example of an apparent violation
(315/90018-06(DRS);
316/90018-06(DRS)
of Sections
III.'G.3 and III.L
of Appendix
R to 10 CFR 50.
During discussions
with the
NRC inspectors
regarding -this event,
the
licensee
indicated that the control
rooms would not necessarily
be
evacuated,
and implementation of the
ERS procedure for both units
simultaneously
would not be required.
The licensee
stated that the
ERS procedures
would be entered
upon initiation of the event but
would be exited prior to assembly of the
ERS team,
once the fire in
the affected
zone
was contained,
and it was determined that the fire
had not
come in contact with any normal safe
shutdown equipment.
At
this point, the unit supervisors
would make the decision to allow
the units to remain at power or be shut down.
In either
case,
normal operating
procedures
would be utilized and not the
ERS
.procedures.
Concurrently,
a restoration
procedure,
which is under
development,
would be implemented to restore
HVAC to the control
rooms to preclude
simultaneous
evacuation
of both control rooms.
The licensee
took prompt interim compensatory
measures
upon
identification'of the potential for simultaneous
loss of HVAC to
both'ontrol
rooms.
These
compensatory
measures
involved the
establishment
of roving 'fire watches
in the affected areas.
The
23
0
't
roving fire watch will continue to be posted
in the areas
of concern
'ntil:
1) plant procedures
are revised to incorporate actions for
restoration
of, control
room cooling capability in the event of
fire induced loss of this capability; 2) the necessary
repair equipment
is made available for restoration of HYAC to both control
rooms
and
power supplies
required
by the restoration
procedure
have
been
committed for Appendix
R use (these repairs
are not required to
achieve
hot shutdown conditions);
and 3) cognizant
personnel
are
made
aware of the actions required to mitigate the loss of control
room
cooling during
a fire.
The long term corrective action is to institute
procedures
to cope with fire induced
loss of normal control
room
HVAC.
)
A ri 1 1990
SER Issue 2.10. 1 - Dia nostic Instrumentation
The staff noted that in the
1987 revised
safe
shutdown methodology,
no diagnostic instrumentation was'identified
as being required for
post fire safe
shutdown.
This is contrary to the information
provided in Information Notice 84-09.
During the audit, the licensee
maintained that no diagnostic
instrumentation
was required
beyond the process
monitoring functions
explicitly identified in Information Notice 84-09 (i.e., source
range monitoring, pressurizer
pressure
and level, etc.).
However,
the inspectors
noted that during the emergency
procedure
walkdown
certain
instruments
such
as
a
CYCS cross-tie
flowmeter and
a steam
generator
PORY nitrogen accumulator
pressure
were procedurally
called out.
The licensee
agreed to identify these
as diagnosti c
instrumentation.
On this basis, this issue is considered
resolved.
A ri 1-1990'SER
Issue 2.11.1 - Manual
0 erator Actions
The staff noted that the licensee
was taking credit for a number of
manual operator actions to achieve
safe
shutdown.
The staff's
concerns
were:
(1)
Operator actions
were credited in the fire area within the
f
h
f
h
di
(2)
An unrecoverab
1 e plant condi tion may develop
due to fire damage
before operator actions
are
implemented
in
~an
fire area.
In reviewing Procedure
1-OHP 4023.001.001,
Revision 9, "Emergency
Remote
Shutdown,"
the only direct reference
to performing operator
actions in a fire area after the discovery of a fire occurs in
Attachment LTI-6, "Trip/Isolation of Spuriously Actuated
Pumps."
For
spurious operation of the charging,
safety injection, containment
spray or residual
heat
removal
pumps,
the procedure
states
that if
the
4KV switchgear
room is accessible
and free of fire damage,
enter the room to remove control
power fuses
and trip the
pump
breaker for the respective
pump.
An alternative
step is provided
which involves actions outside the switchgear
room (i.e., to locally
open the circuit breaker for the respective
pump's miniflow
24
0
1
recirculation valve and manually
open the valve
so that the
pump is
in the recirculation
mode).
The remote
shutdown procedure is also
intended to apply for all of
the fire zones
which require either complete or partial alternative
shutdown.
For those fire 'zones, reliable control from inside the
control
room may not be feasible.
A concern
was noted during the
procedural
walkdown that the individual sub-procedures
within the
numerous
attachments
are not performed in any rigid sequence
by
specific operators.
Rather,
as individual operator s complete the
sub-procedures,
they report back to the Unit Supervisor,
who then
assigns
them to perform possibly
a completely different sub-procedure
in another
attachment.
This causes
the operators
to traverse
the
plant in an almost
random order.
Depending
upon which fire zone the
fire occurs in, the access
path between
the location of one operator
action point to the next assigned
location will vary.
This has
implications from both the point of view of the necessity for operators
to traverse
the fire affected
area
and the time required to take
alternative routes,
as well as the location of emergency lighting
throughout the plant.
The licensee
was questioned
as to whether the
time-manpower studies that had been
performed accounted for the need
to avoid the fire affected
areas for those fires outside the Control
Room.
The response
was that it had not been specifically addressed,
but that access
paths to and from the control
room to the individual
locations
could be considered
to simplify the analysis.
A sample walkthrough considering realistic access
paths
between
action locations specified in the procedure
was developed
by the
licensee
during the inspection for Fire Zone 44S, auxiliary building
South - EL.609'.
These
access
paths
were partially walked down by
the inspector
on September
14, 1990.
The feasibility of performing
the required actions
was considered
adequate.
Based
on this limited
sampling,
the inspectors
considered
the feasibility of performing the
required
manual actions for fires in fire zones outside the control
room which require complete alternative
shutdown to be adequate.
A ril 1990
SER Issue 2.12.1 - Hot Shutdown
Re airs
The staff had two specific concerns:
(1)
that repairs for hot shutdown were being proposed
and
(2)
that shutdown
procedures
indicated that certain actions would
only be taken after consultation with a corporate
engineering
team
and the potential delay involved.
These
issues
were closed out in the
SER based
on the licensee's
response,
in the first case,
that repairs to the
RHR system were only
required to achieve
cold shutdown,
not hot shutdown,
since
RHR is
not required during. hot shutdown
and, in the second
case,
that the
consultation
(which involves the repairs to the
RHR system)
would
only take place after hot shutdown
had
been
achieved.
25
'I
In addition, for cold shutdown,
repowering of one
RHR pump in the
fire affected unit may be required.
This is accomplished
by
repowering
the
pump. through disconnection
of the power supply to
either the
RHR or containment
spray
pumps in the unaffected unit.
This is
a cold shutdown repair
and is procedurally
addressed.
During the onsite visit to verify the
SER closeout
assumptions,
Maintenance
Procedure
No. 1tlHP2140.082.001,
Revision 2, "l1aintenance
Procedure for Repowering
an
RHR Pump,"
was walked down.
Only two
problems of a minor nature
were noted.
One was that
a label
on the
cable
spool with the cable designated for the
RHR pump repair
indicated that the cable
was purchased for an auxiliary feedwater
pump.
The other was that
some confusion could result from step 7.3.3
which states,
"Route the temporary
power cable
between
the Unit 2
supply
4KV breaker
and the Unit 1 motor."
This is preceded
by step
7.3.2 which states,
"Route the jumper cable
assembly
between
the U-2
motor and the U-1 motor."
Step 7.3.3 is really an alternative to
7.3.2,
and is not necessarily
preferred.
Prior to the exit interview, the licensee
indicated that the cable
spool label
had been
removed
and also provided
a procedural
change
notice which clarified the procedural
steps.
Therefore, this item
remains satisfactorily addressed
and closed.
A ri 1 1990
SER Issue 2.13. 1 - Hot Shutdown
Panel Isolation
The staff's
concern
regarded
a fire in the local shutdown indication
panel
area that might result in damage to the normal
shutdown
capability in the control
room.
The licensee
noted that the local shutdown indication (LSI) panels
were physi'cally and electrically isolated from the control
room.
During the onsite review, the licensee's
method of providing
physical
and electrical
separation for the LSI panels
was reviewed
and found to be acceptable.
The LSI panels
are physically located
in fire areas
separate
from the control
room and are adequately
provided with electrical isolation through the use of
isolation/transfer
switches.
Safe
Shutdown
S stems
Review
The licensee
has
made provisions to utilize all of the systems
necessary
to achieve
safe alternative
shutdown conditions from
initial hot standby to hot shutdown
and finally to cold shutdown.
The measures
taken provide reactivity control, reactor coolant
system level
and pressure
control, decay
heat removal,
process
monitoring,
and all appropriate
support
systems.
These
measures
are
,in accordance
with the November 22,
1983
SER and subsequent
approvals.
Alternate Shutdown method(s)
Review
Of the five alternate
shutdown methods,
Method ASl, "Complete
Alternative Shutdown"
was reviewed
and evaluated
during the walkdown
26
A
and drill of Emergency
Operating
Procedure
1-OHP 4023.001.001,
"Emergency
Remote Shutdown," Revision 9, dated
September
7,
1990
(which applies to Unit 1).
The drill was conducted
to the point of
achieving hot standby conditions.
The procedure
and method satisfactor-
ilyy
addressed
all of the required actions to achieve reactivity control,
reactor coolant pressure
and level control,
decay
heat removal,
and
process
monitoring,
and assured
the availability of appropriate
support
systems.'.
~Summar
The inspection
team identified a number of "Human Factor" type
procedural
weaknesses
during the procedure
walkdowns
and simulated
fire scenario.
The procedure
review proces's
in place
should
have
identified these
procedure deficiencies.
The fa'ct that these
items
were not identified during the review process
demonstrates
a lack of
"attention to detail" on the part of the licensee.
In addition, the inspection
team reviewed procedure
weaknesses
that
were identified during
a recent
SSFI regarding
the plant alternate
shutdown capability.
It was determined
by the inspection
team that
the
ERS procedure currently in effect,
1-OHP 4023.001.001,
Revision 9,
adequately
addresses
the procedure
weaknesses
identified above.
6.
Communications
The normal
communications
system
used. at this site
was the Public Address
(PA) system.
The fire and emergency
two-way radio system initially used
a single repeater
which was located in the Unit 2 4KV switchgear
room.
During operator training on the emergency
remote
shutdown procedures,
the
radio system
was
used
and was found acceptable
at all critical safe
shutdown
equipment locations.
For a fire in any fire zone in Unit 1, the radio system
was available.
For most fires in Unit 2, the radio system would be available with normal
PA communications
also available.
The only Unit 2 fire which would
disable the radio system
was
a fire in the Unit 2 switchgear
room,
a safe
shutdown fire area
(FA NN).
The inspectors
determined that the
PA system
would have
been available to back up the radio system for a fire in FA NN.
The licensee
has
proposed
enhancements
to the entire radio system.
The
changes
should provide broader plant radio coverage
and provide
a total of
three
channels for use during
an emergency.
Also,
a second radio system
has
been installed in Unit 1.
7.
Emer enc
Li htin
, During the original post fire safe
shutdown inspection (April 12-16,
1982), three areas
of the plant did not have
emergency
lighting units
installed
as required.
Subsequently,
licensee letters
dated
Nay 4,
Hay 10 and June ll, 1982,
addressed
the corrective actions to be taken in
the emergency lighting area.
The June
11,
1982 letter indicated that the
emergency lighting requirements
had been corrected
in areas
identified as
requiring emergency lighting.
The June
1982 letter further specified that
27
the safe
shutdown capability reanalysis
could necessitate
the installation
of additional
emergency lighting uni'ts in new areas.
The 'previously
deficient three
areas
were confirmed to have
emergency
lighting units
installed during
a subsequent
inspection.
The inspection report pertaining
to that inspection
noted that the overall adequacy
of the installed
emergency
lighting system
was scheduled for review during this inspection.
Consequently,
'during this inspection,
the inspectors
conducted
a review of
the emergency
lighting area.
The review consisted
of the following:
(1) witnessing
an eight hour
emergency
lighting battery
draw down (discharge)
test;
(2) witnessing
a
simulated
loss of AC power test;
(3) selective
walkdown of emergency
lighting to determine that adequate
lighting units were in place;
and (4)
emergency lighting surveillance
procedure
review'.
On September
12, 1990,
a full eight hour discharge test
was conducted
on
five emergency
lighting units to determine
the operability of the units in
their installed condition.
An inspector witnessed
the initiation of each
unit's test
and periodically checked
these units during the test.
Each of
the five emergency
lighting units continued to light after eight hours.
Therefore, all tested units passed
the eight hour discharge test.
Also,
on September
12,
1990,
a simulated
loss of AC power test
was
performed in five plant areas
to determine
the adequacy
of illumination
provided by the units in their installed locations.
As a result of this
test,
the
NRC concluded that
an appropriate
number of emergency
lighting
units were installed
in, each of these plant areas
and that with one
exception,
adequate
illumination was provided.
Emergency lighting unit
Ho. 364, located in the Unit 1 reciprocating
charging
pump room,
was
observed to be inoperable at the initiation of the test.
However, it was
concluded that this defective
emergency
lighting unit would have
been
identified during the next surveillance.
Prior to the team's
departure
from the site, the licensee
installed
an operable lighting unit at the
Unit 1 reciprocating
charging
pump room location.
An inspector also reviewed the emergency
lighting unit periodic planned
maintenance
(PH) Task 9, dated
Hay 24,
1990,
and the annual preventive
maintenance
Task 9, dated April 13, 1989.
These
procedures
were
determined to be generally satisfactory.
However,
no administrative
system
was in place to ensure that the yearly draw down test included
a
sampling of emergency lighting units required for safe
shutdown.
Also,
the licensee
needs to consider
having
a formal process for assuring that
following the annual testing of the sampled
emergency lighting units,
adequate
interim lighting (e.g.,
hand held lights) is available for
operator
use, if needed, until the tested batteries
have
been adequately
recharged.
Finally, the inspector
requested
the licensee
to determine
whether the three types of emergency lighting unit bulbs could be
physically interchanged.
If so, the procedure
should
be revised to
require that defective bulbs are replaced
by identical type bulbs.
As part of the emergency lighting review,
an evaluation of LER No. 90006
(dated August 28,
1990)
was conducted.
This
LER regarded
three
emergency
lighting walkdowns (April 19, June 20-21,
and July 17, 1990) that
had
determined that lighting needed to be improved in certain plant areas
to
28
facilitate the accomplishment
of the emergency
remote
shutdown procedures.
During this inspection,
inspectors
walked down plant areas that had been
identified as having inadequate
lighting along with other designated
alternative
shutdown routes
not identified as having lighting deficiencies
but still required for safe
shutdown.
In addition, during the timed
emergency
remote
shutdown
proce'dure drill (postulated
Unit
1 control
room/cable vault fire scenario), the adequacy
of emergency
lighting was
observed.
On the above basis,
along with the lighting system tests
noted
previously, it was determined that adequate
emergency
lighting was
now in
place.
However, for Revision
8 of the emergency
remote
shutdown procedure
(addressed
in the
LER) and for Revision
0 of the emergency
remote
shutdown
procedure (in effect as of June
10, 1986), it was concluded that numerous
examples of an inadequate
emergency lighting evaluation
were
known to have
occurred.
Also, during this inspection,
a review of completed
emergency
lighting surveillance
procedures
determined that adequate
timely corrective
actions
had not been
taken until recently to preclude repetitive failures
of emergency
lighting system unit components.
In April'990, the licensee
recognized this deficiency
and took proper corrective actions.
At that
time, it was confirmed that the
same repetitive lighting problems
were
being identified during successive
survei llances;
however,
the need to
complete the surveillances
rather than the corrective actions
were taking
priority.
The inadequate
emergency
lighting evaluation
and the fai lure to
take adequate
timely corrective action to preclude repetitive failures of
the
same
emergency
lighting units are considered
as further examples
of an
apparent violation (315/90018-04c(DRS);
316/90018-04c(DRS))
of 10 CFR 50,
Appendix B, Criterion XVI, Corrective Action.
In addition, the licensee
received
an
NRC exemption
(Nay 26,
1987) from
installing an emergency lighting unit with eight-hour battery
power in the
,
outdoor yard adjacent to the nitrogen regulator valves.
The existing
outdoor lighting system is powered from a normal
power source
and
may be
powered from the security diesel generator.
The lighting system
power and
control cables
are run external to the plant.
The security diesel
generator
is tested
monthly and is also located external to the plant.
Based
on the
above, this portion of the outdoor lighting system satisfies
the
Appendix R,Section III.J emergency lighting requirement.
Associated Circuits
a ~
Review of the
Common
Power Source Associated Circuit Concern
The sample of circuits selected for in-depth review of this concern
was based
on
a pre-inspection
review of related
documentation
submitted to the inspection
team by the licensee.
This
documentation
included the D.
C.
Cook Safe
Shutdown Capability
Assessment
Report
(SSCA), Revision 1, dated
December
1986
and
a
contractor
( Impell) evaluation entitled Electrical Protection
Coordination Study,
Report
Number 09-0120-0146,
Revision 1, dated
November 21,
1988.
As
a result of this review, the Impell coordination
study was found
to identify several
examples of power supplies,
which may be relied
on to achieve
post fire safe
shutdown, that lacked
an adequate
level
of coordination.
The scope of the Impell coordination
study included
29
all onsite
power sources
(4160Vac
and below)
and was not limited to
a review of only those
power sources identified in the
SSCA as required
to achieve
post fire safe
shutdown.
The licensee
has initiated
corrective actions
under Request for Change
(RFC) DC-12-3008 which
will address,
and correct
as. necessary,
all coordination deficiencies
identified in the Impell report.
During the audit, the licensee
was requested
to provide additional
technical justifications regarding
Appendix
R coordination
deficiencies identified by the Impell study.
The licensee
was
subsequently
able to provide sufficient information necessary
to
adequately
address all of the inspector's
concerns.
(1)
Hi
h
Im cdance
Faults
As stated
in Section 5.3.8 of Generic Letter 86-10, the
NRC
staff has determined that to meet the separation criteria of
Sections III.G.2 and III.G.3 of Appendix R, simultaneous
high
impedance faults (below the trip point of the breaker
on each
individual circuit) for all associated
circuits located within
the fire area
should
be considered
in the evaluation of safe
shutdown capability.
Therefore, circuit coordination studies
should not be limited to
a review of low impedance
"bolted" type
faults,
such
as those
considered
in the Impell study, but must
also consider
the affects of high impedance
(arcing) type faults
which may occur simultaneously
as
a result of fire on all
associated
circuits, of a required
power supply that are located
in a fire'area of concern.
\\
The D.
C.
Cook circuit coordination studies
and related
documentation
did not include
a detailed evaluation of the
potentially adverse affect of simultaneous
high impedance
faults.
In its response,
dated
February
21, 1990, to an
NRC
Request for Additional Information (RAI) related to this i'ssue,
the licensee
described its "position" on the credibility of
occurrence for such faults, rather than provide
a detailed
technical
evaluation of the concern.
The licensee's
response
stated,
in part,
"The Generic Letter
GL 86-10 postulates
a
fault potentially affecting associated
safe, shutdown circuits
that is unlikely to happen
and does not justify detailed
evaluation."
The status
of the licensee's
evaluation of the
high impedance fault concern
remained
open in the Safety
Evaluation Report
(SER)
issued
by the staff on April 26,
1990.
In its response
(SER item 2.23), the staff stated that the
lic'ensee's
position would be scrutinized during the upcoming
fire protection audit.
At the time of the audit, the licensee
was requested
to provide
a technical
basis which viould support its argument
presented
in
the February 21,
1990 submittal.
In response,
the licensee
presented
an "Executive Summary" of a currently ongoing
. evaluation of the concern.
A review of this summary
document
found it to state
the basic
assumptions
being applied during
the evaluation.
The electrical
systems
reviewer found these
30
F
0
assumptions
to be comparable to those previously found to be
acceptable
by the
NRC/NRR staff during its review of simi lar
evaluations
performed
by other facilities.
Based
on the
initial implementation of the basic assumptions,
however, the
summary
document
was found to identify numerous
required
power
sources for each unit as being potentially affected
as
a result
of such faults.
It should
be noted that the overall objective
of this preliminary study was to screen for potentially
affected supplies
by applying the basic fault assumptions
to
all power sources
required to achieve
post fire safe
shutdown.
As
a result,
those supplies
which would not be affected
under
any postulated fire scenario
were segregated
from those which
exhibited
a potential for loss
due to the occurrence
of such
faults
on connected
cabling.
The limi'ting factors for
determining if a specific supply would actually
be affected
by
such faults are typically the current interrupting rating of
the feeder breaker/fuse
to the supply
and the number of power
supply load cables that may be located within a specific fire
area.
The licensee
was currently in the process
of identifying
the specific cable routing,
by fire area,
of load cables
associated
with required
power sources
which have the potential
for loss
due to the occurrence of such faults.
During a
telecon
between
the licensee
and
NRC personnel,
the licensee
indicated that no examples
of high impedance faults affecting
safe
shutdown
had been found.
The licensee
was to have completed the Appendix
R review
including the high impedance fault analysis
by July 11,
1986.
This issue is considered
an unresolved
item (315/90018-07(DRS);
316/90018-07(DRS))
pending further review of this issue.
This issue also correlates
to an
NRR open item numbered
2.23.1
as described
in the April 26,
1990
SER.
b.
Review of the
S urious Si nals Associated Circuit Concern
The licensee's
analysis of this concern is documented
in Section
4
of the Safe
Shutdown Capability
Assessment
Report
(SSCA).
Section 4.7
of this report indicates that Failure Nodes
and Effects Analyses
(Ft'lEA) were performed to determine if the mal-operation of control
circuit interlocks between
required
equipment
and other equipment
could prevent the proper
operation of the safe
shutdown equipment;
or
if fire initiated conductor-to-conductor
shorts,
open circuits or
shorts to ground
on cables of equipment that had the potential to
defeat safety functions
as
a result of their spurious operation,
could result in a component transition to an unacceptable
state.
A review of the licensee's
analysis
and method of protection for fire
initiated spurious signals did not identify any items of concern
and
was found to be acceptable.
31
C.
d.
Common Enclosure Associated Circuit Concern
Based
on
a review of a sample of raceways
known to contain circuits
required to a'chieve
post fire safe
shutdown,
the licensee's
protection
for the
Common Enclosure
concern
was found to be acceptable.
Review of Redundant Train Cable
Se aration
(Cable Routin
)
9.
Fire
During the inspection,
the routing of power and control cables
associated
with redundant
components
required to achieve
post fire
shutdown
was reviewed.
The objective of this review was to verify,
on
a sample basis,
compliance
wi .h the separation
requirements
of
Section III.G.2 and III.G.3 for redundant trains of cabling of
'required
equipment.
The licensee's
method of compliance
was found
to be acceptable
based
on the inspector's
review of color coded cable
tray and raceway
drawings which depicted
the power and control cable
routing of selected
components.
Barriers
a
~
Doors
b.
Fire doors in fire area
boundaries
were reviewed to determine if the
doors were rated to ihe fire resistance
requirements
defined in the
Fire Hazards Analysis.
In addition,
doors were inspected
to determine
if modifications
have
been
performed which may degrade
the fire rating
of the door.
Based
on
a plant walkdown,
'no doors within fire area
boundaries
were found which were not properly rated.
Hodifications
were noted
on
some doors for security hardware.
However, the licensee
had evaluated
each of the modifications including having Underwriter's
Laboratories,
Inc. perform an independent
review of the doors.
This
review was
documented
in a report dated January
23, 1985.
The
UL
report identified a number of minor changes
required to correct door
deficiencies.
These
changes
had
been
performed
by the licensee.
Procedures
were also reviewed which require prior approval
by the
Fire Protection Coordinator before
any
new modifications to doors 'can
be performed.
During the plant walkdown,
some doors were found to be in a degraded
state
and would not close properly.
These
doors,
however,
were
appropriately identified as inoperable.
A fire watch patrol.had
been
established.
As
a 'result of the review of fire doors, it was
deter'mined that the licensee
had installed rated doors in fire area
boundaries,
had adequately
evaluated modifications to these
doors
and
.had in place
adequate
administrative
procedures
to control door
modifications
and impairments.
The inspector
reviewed fire barrier penetration
seals
to determine
if they were adequately
installed
and qualified to the required'fire
rating.
Design documentation
was reviewed in addition to visual
inspection of randomly selected
seals.
Although the seals
inspected
were properly in place
and did not appear
to be degraded,
the
32
0
0
inspector
was concerned
that the fire resistive rating of a number of
seals
in the plant could not be supported
by fire test data.
NRC Generic Letter 88-04 provides guidance
on the qualification of fire
barrier penetration
seals
and references
acceptable
test criteria.
The licensee
stated that subsequent
to the issuance
a program
had been initiated to review penetration
seal
qualifications.
This program is intended to substantiate
seal
qualification by analyzing
a minimum of 100 randomly selected
seals.
The licensee
stated that if problems
were found with these
seals,
the sample would be expanded.
The licensee
committed to an
August 1,
1991 completion date for this program.
The inspector
reviewed penetration
seal
documentation
that
had
been collected at
the time of the inspection.
Based
on this review and
a determination
that no substantial
problems
had
been identified to" date, this issue
is considered
closed.
Barrier Eva lu at ions
Section 3.1.2 of NRC Generic Letter 86-10 provides guidance
on
evaluating fire area
boundaries.
This section states
that "where
boundaries
are not sealed floor-to-ceiling and/or wall-to-wall,
evaluations
must be performed to determine if the barriers
can
withstand the fire hazards
associated
with the adjoining fire
areas.
These evaluations
can
be submitted to the
NRC staff but must
be available for NRC audit."
During this inspection,
the inspector
requested
to see
any
evaluations
that had
been
performed
on fire area
boundaries
that had
not been previously reviewed
by the
NRC.
The licensee
presented
a
l.ist of 21 evaluations that had
been
performed in accordance
with
criteria in Generic Letter 86-10.
The inspector
randomly selected
.
fire evaluations
from this list (Appendix A) and reviewed
them for
acceptability.
Based
on this review, the inspector
found the
evaluations
to adequately
address
discrepancies
in fire area
boundaries
and to provide
a sound engineering
basis for
acceptability of the stated
discrepancy.
In addition,
a field
walkdown was performed to assess
barrier adequacy.
No discrepancies
in barrier integrity were found which had not been previously
addressed
by the licensee.
Structural
Steel Protection
The inspector
reviewed measures
used to protect structural steel
members that were either part of a fire barrier or could affect the
integrity of a fire barrier should they fail.
Unprotected structural
steel
was identified in several
areas
of the plant.
The licensee
presented
the inspector with an analysis
which calculated
projected
steel
member temperatures
during
a fire.
The analysis
methodology
was the
same
used at several
other. plants
and
had been previously
accepted
by the
NRC.
The licensee's
analysis identified one area
where the unprotected
steel
would reach its failure point during
a
fire.
For the
one area,
the Screenhouse, it was determined that the
potential existed for the roof to collapse.
However, the licensee
concluded that collapse of the roof would not impact the
ESW pumps
33
J
0
e.
due to the design of the
ES'H
pump enclosures.
After review of the
analysis,
the inspector
concluded that the licensee
had adequately
addressed
concerns .related to unprotected structural steel.
Conduit and Cable Tra
Protection
10.
Fire
The inspector
reviewed cable tray and conduit protection including
drawing review, installation procedure
review, and field verification.
The licensee
has utilized Thermalag
manufactured
by TSI, for protection
of safe
shutdown circuits.
This mate'rial is qualified as
a 1-hour
barrier
and
has
been
accepted
by the
NRC for use at
a number of
plants.
The inspector
reviewed the licensee's
installation procedure
which was based
on manufacturer
supplied design details.
This
procedure
was found acceptable.
The inspector
reviewed the
installation drawing accuracy=by
randomly selecting
raceways
and
conduits,
from the safe
shutdown analysis,
which required protection
to meet the requirements
of Appendix R.
A field walkdown of these
raceways
and conduits
was performed to verify that Thermalag
was
adequately
applied.
Based
on the walkdown,
no discrepancies
were
observed relating to the appropriate installation of Thermalag.
Detection
and
Su
ression
a ~
Partial
Covera
e Detection
and
Su
ression
Appendix
R and supplemental
guidance
provided in Generic Letter 86-10 requires that where detection
and suppression
is necessary
to
meet the requirements
of Appendix R, it should
be installed
throughout the fire area of concern.
Generic Letter 86-10 states
that partial coverage
suppression
and/or detection
in the fire area
of concern is acceptable if it can
be demonstrated
through
engineering
analysis that partial coverage
would provide adequate
protection.
The Generic Letter also states
that these
analyses
must
be available for NRC audit.
The inspector
requested
the licensee
to
provide all analyses
which pertain to partial coverage
detection
and
suppression.
The licensee
presented
a list of 21 analyses
that
addressed
either partial
coverage
detection or, partial
coverage
suppression.
From this list, the inspector
randomly chose
seven
analyses for review (Appendix B).
Based
on
a review of these
analyses,
the inspector
found that the licensee
provided adequate
documentation
to justify the lack of either full area detection or
suppression
in the areas
addressed.
In addition,
no partial
coverage
conditions were noted during
a plant walkdown which had not
been evaluated
by the licensee.
b.
NFPA Code Conformance
Generic Letter 86-10, Section 8.9, states,
in part,
"NRC guidelines
reference
certain
NFPA codes
as guidelines to the systems
acceptable
to the staff,
and therefore
such
codes
may be accorded
the
same
status
as Regulatory Guides."
The inspector
reviewed the design
and
installation of suppression
and detection
'systems
protecting
safe
shutdown
components
and circuits to determine if they are in
accordance
with guidance
provided in the National Fire Protection
34
Association
(NFPA) Fire Codes.
The licensee
has
conducted
a series
of NFPA Code compliance studies.
Item 2.2 of the April 26,
1990
issued
by the
NRC addressed
these
code compliance
reviews.
The
identified this issue
as
an open item pending
submission of the
results of the licensee's
code review to the staff for review.
, During this inspection,
the inspector
requested
a status of these
reviews
and any modifications that
may be deemed
necessary
as
a
result of the reviews.
The licensee
informed the inspector that the
final code compliance
review was in the process
of final review by
the licensee.
In addition, the licensee
provided copies of two
design
change
packages
which addressed
required
system modifications
resulting from the design
review.
The licensee
stated that these
modifications would be completed
by Decembe'r
31,
1991.
The inspector
reviewed the design
change
packages,and
concluded that none of the
issues
identified would impact the operability of the Fire Protection
system
and that the licensee
was adequately
addressing
code
compliance
issues.
However, the open
issue
in the
SER will still remain
open
pending
NRR review of this issue.
c.
Fire
Su
ression Affects on Safet -Related
Com onents
The inspector
requested
information from the licensee
regarding
their response
to issues
discussed
in Information Notice
( IEN) 8/-14
concerning
inadvertent actuation of fire suppression
systems affecting
safety-related
components.
Based
on
a review of the licensee's
response
to.this issue, it was determined that the response
to IEN'7-14 was
adequate.
11.
Instrumentation
That
Su
orts Surveillance
Re uirements
The inspectors
reviewed the fire protection section of D. C. Cook'
Technical Specifications
(TS).
Based
on the review, inspectors
determine'd that the licensee
was adequately
maintaining process
instrumentation that was used to support fire protection
systems
surveillance
requirements.
12.
Unresolved
Item
Unresolved
items are matters
about which more information is required in
order to ascertain
whether they are acceptable
items;
items of
noncompliance,
or deviations.
An unresolved
item disclosed
during this
inspection is discussed
in Paragraph
8.a.
13.
Deviations for Which
A "Notice of Violation/Deviation" Will Not be Issued
The
NRC uses
the Notice of Violation/Deviation as
a standard
method for
formalizing the existence
of a violation/deviation of a legally binding
requirement/commitment.
However,
be'cause
the
NRC wants to encourage
and
support licensee's
initiatives for self-,identification
and correction of
problems,
the
NRC will not generally
issue
a Notice of Violation/Deviation
for a violation/deviation that meets
the tests of 10 CFR 2, Appendix C,
Section
V.G.
These tests
are:
(1) the violation/deviation
was identified
35
(
by the licensee;
(2) the violation/deviation would be categorized
as
Severity Level IV or V; (3) the violation/deviation
was reported to the
NRC, if required;
(4) the violation/deviation will be corrected,
including
measures
to prevent recurrence,
within a reasonable
time period;
and (5)
it was not a violation/deviation that could reasonably
be expected to have
been prevented
by the licensee's
corrective action for a previous violation.
One violation/deviation of a regulatory
commitment being addressed
as
a
result of this inspection for which
a Notice of Violation/Deviation will
not be issued is discussed
in Paragraph
4.a.
14.
Exit Interview
The inspectors
met with licensee
representatives
(denoted
in Paragraph
1)
at the conclusion of the inspection
on September
10-14,
and
November 6,
1990,
and
summarized
the scope
and findings of the inspection.
The
inspectors
also discussed
the likely informational content of the
inspection report with regard to documents
reviewed
by the inspectors
during the inspection.
The licensee
did not identify any of the documents
as proprietary.
36
(