ML050540508
| ML050540508 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 08/31/2003 |
| From: | Ogle C Division of Reactor Safety II |
| To: | Sumner H Southern Nuclear Operating Co |
| References | |
| FOIA/PA-2004-0277 IR-03-006 | |
| Download: ML050540508 (41) | |
See also: IR 05000321/2003006
Text
UNITED STATES
- ock
NUCLEAR REGULATORY COMMISSION
REGION 11
sSAM
NUNN ATLANTA FEDERAL CENTER
61 FORSYTH STREET SW SUITE 23T85
g
<ATLANTA,
GEORGIA 30303-8931
Southern Nuclear Operating Company, Inc.
,
ATTN: Mr. H. L. Sumner, Jr.
-:
Vice President
P. O. Box 1295
Birmingham, AL 35201-1295
SUBJECT:
EDWIN I. HATCH NUCLEAR POWER PLANT - NRC TRIENNIAL FIRE
PROTECTION INSPECTION REPORT 05000321/2003006 AND
b
Dear Mr. Sumner:
On July 25, 2003; the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at
your Hatch Nuclear Plant Units 1 and 2. T146 enclosed inspection report documents the
inspection findings, which were discussed on that date with Mr. R. Dedrickson and other
members of your staff. Following completion of additional review in the Region II office, a final
exit was held by telephone with Mr. S. Tipps and other members of your staff on
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commission's rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and riecords, observed activities, and interviewed
personnel.
- i
This report documents two findings that have potential safety significance greater than very
low significance, however, a safety significance determination has not been completed. One
issue involving a procedural inadequacy did present an immediate safety concern, however,
your staff revised the procedure pri6r to the end of the inspection. The other issue did not
present an immediate safety concbern. In addition, the repor documents three NRC-identified
findings of very low safety significance (Green), all of which were determined to involve
violations of NRC requirements/However, because of the very low safety significance and
because they are entered into your corrective action program, the NRC is treating these three
findings as non-cited violations (NCVs) consistent with Section VLA of the NRC Enforcement
Policy. If you contest any NCV in this report, you should provide a response within 30 days of
the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory
Commission, ATTN.: Docuument Control Desk, Washington DC 20555-0001; with copies to the
Regional Administrator Re" ion II; the Director, Office of Enforcement, United States Nuclear
Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the
Hatch Nuclear Power Plant.
g
V
10
2.
Local Manual Operator Action was Too Difficult and Physically Unsafe
Introduction: A finding of very low safety significance was identified in that a local
manual operator action to operate SSD equipment was too difficult and was also
physically unsafe. The team judged that some operators would not be able to perform
the action. This finding involved a violation of NRC requirements.
Description: The team observed that Steps 4.15.8.1.1 and 9.3.5.1 of the Fire Procedure
relied upon local manual operator actions instead of providing physical protection for
cables or providing a procedure for cold shutdown repairs. Both steps required the
same local manual operator action: 'Manually OPEN 2E1 1 -F01 5A, Inboard LPCI
Injection Valve, as required." This action was to be taken in the Unit 2 drywell access,
which was a locked high radiation, contaminated, and hot area with temperatures over
100 degrees F.
Valve 2E1 1-F015A was a large (24-inch diameter) motor-operated gate valve with a
three-foot diameter handwheel. The main difficulty with manually opening this valve was
lack of an adequate place to stand. An operator showed the team that to perform the
action he would have to climb up to, and stand on a small section of pipe lagging (a
curved area about four inches wide by 12 inches long), and then reach back and to his
right side, to hold the handwheel with his right hand, while reaching forward and to his
right to hold the clutch lever for the motor operator with his left hand. The operator
would not have good balance while performing the action. The foothold, which was
large enough to support only one foot, was well flattened and appeared to have been
used in the past to manually operate this valve. The foothold was about six to seven
feet above a steel grating, and the team observed that the space available for potential
use of a ladder to better access the 2E1 1 -F01 5A valve handwheel was not good.
Other difficulties with manually opening the valve included the heat; the need to wear
full anti-contamination clothing, a hardhat, and safety glasses; and inadequate
emergency lighting (see Section 1 R05.07). Also, there was no note or step in the
procedure to ensure that the RHR pumps were not running before attempting to
manually open the 2E11-FO15A valve. If an RHR pump were running, it could create a
differential pressure across the valve which could make manually opening it much more
difficult. If the operator did not have sufficient agility, strength or stamina, he would be
unable to complete the action. Also, the team judged that inability to remove sweat from
his eyes, due to wearing gloves that could be contaminated, would be a limiting factor
for the operator. In addition, if the operator slipped or lost his balance, he could fall and
become injured. Considering all of the difficulties, the team judged that this action was
physically unsafe and that some operators would not be able to perform it.
The licensee had no operator training JPM for performing this action an
demonstrv
1hat-alfoperators-oouldlperform-the-ectien. One experienced operator,
who appeared to be in much better physical condition that an average nuclear plant
operator, stated that he had manually operated the valve in the past, but that it had bee
very difficult for him.
NAcXe~c
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b.
Findings
- -No
findings of significance were identified.
1 R21 Safety System Design And Performance Capability
-.01
Design Change Reauest 91-134. SRV Backup Actuation Via Pressure Transmitter
Signals
a.
Inspection Scope
The team performed an independent design review of plant modification DCR 91-134 in
order to evaluate the technical adequacy of the design change package. The scope of
the review and circuit analysis performed by the team was limited to the Group A SRVs
for which the licensee takes credit in mitigating a fire in the fire areas selected for the
inspection.
b.
Findings
Introduction:
An inadequate plant modification, DCR 91-134, failed to implement the design input
requirements of "one-out-of-two taken twice" logic for the SRV's backup actuation using
PT signals.
Description:
DCR 91-134 was implemented in response in to concerns raised in General Electric
Report NEDC-3200P, Evaluation of SRV Performance during January-February 1991
Turbine Trip Events for Plant Hatch Units 1 and 2. In order to ensure that individual
SRVs will actuate at or near the appropriate set point and within allowable limits, a
backup mode of operation for the SRVs was implemented by this DCR. The design was
intended to mitigate the effects of corrosion-induced set point drift of the Target Rock
SRVs.
Automatically controlled, two stage SRVs are installed on the main steam lines inside
containment for the purpose of relieving nuclear boiler pressure either by normal
mechanical action or by automatic action of an electro-pneumatic control system. Each
SRV can be manually controlled by use of a two position switch located in the main
control room. When placed in the "Open" position, the switch energizes the pilot valve
of the~ iidual SRV and causes it to go open. When the switch is placed in the uAuto"
positi nstle SRV is opened upon receipt of either an Automatic Depressurization
SysteDS), or Low-Low Set (LLS) control logic signal. Either signal will initiate
opening of the valve. DCR 91-134 provided a backup mode for initiation of electrical trip
of the pilot valve solenoid which was independent of ADS or LLS logic. The backup
mode required no operator action to initiate opening of the SRVs and was considered a
"blind control loop" to the operators, (i.e., there are no instruments that provide the
operators information concerning the open/close status of the SRVs.)
I
21
specified design input requirements; The independent design verification performed for
DCR 91-134 failed to identify this error in the logic scheme. Additionally, the
Appendix R Impact Review performed for DCR 91-134 failed to identify the potential
failure mode of all eleven SRVs because of fire-induced damage in Fire Area 2104.
Based on the logic input from trip unit master unit relays K31 OD, and K335D and their
associated trip unit slave relays, the plant modification installed for DCR 91-134 failed to
correctly implement the one-out-of-two taken twice" logic that was specified in the SRV
backup actuation via PT signals design change package. This failure has created a
condition where fire-induced failures of two reactor pressure instrument circuit cables,
(within close proximity to each other), could result in spurious actuation of all eleven
i
a stuck open mode of operation. Pending
completion of a significance det rmination by the NRC, this item is identified as URI 50-
366/03-06-06, Inspector Conce s Associated with Implementation o0 DCR 91-134.'
OTHER ACTIVITIES
0
Irtnt~f~ot-^
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4.
AP'A
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lUetIMMUCIllUIl C111U r-1:ZiU1UL1U11 U1 r-1U~l)VilbZ
a.
Inspection Scope
The team reviewed a sample of licensee audits, self-assessments, and CRs to verify
that items related to fire protection and to SSD were appropriately entered into the
licensee's CAP in accordance with the Hatch quality assurance program and procedural
requirements. The items selected were reviewed for classification and appropriateness
of the corrective actions taken or initiated to resolve the issues. In addition, the team
reviewed the licensee's applicability evaluations and corrective actions for selected
industry experience issues related to fire protection. The operating experience reports
were reviewed to verify that the licensee's review and actions were appropriate.-
The team reviewed licensee audits and self-assessments of fire protection and safe
shutdown to assess the types of findings that were generated and to verify that the
findings were appropriately entered into the licensee's corrective action program.
b.
Findings
No findings of significance were identified.
-
40A6 Meetings. Including Exit
The lead inspector presented the inspection results to licensee management and other
members of the licensee's staff at the conclusion of the onsite inspection on July 25,
2003. Subsequent to the onsite inspectiori, the lead inspector and the Team Leader,
Fire Protection, held a follow-up exit by telephone with Mr. S. Tipps and other members
of licensee management on seugue9003, to update the licensee on changes to the
preliminary inspection findings. The licensee acknowledged the findings.
ADS,:
APCSB
BTP.
Co 2 .
CRs'
CST.
1MG
'P
ma
NFPA~
NRC
RCIC'
SRVs;
SSD
TS
XLPE
LIST OF ACRONYMS
Automatic Depressurization System
Abnormal Operating Procedure
Auxiliary and Power Conversion System Branch
Analog Transmitter Trip System
Branch Technical Position
Corrective Action Program
Carbon Dioxide
Condition Reports
Condensate Storage
s
Design Change Request
Electrical Raceway Fire Barrier System
Fire Hazards Analysis
Heat Capacity Temperature Limit
High Pressure Coolant Injection
Inspection Manual Chapter
Inspection Procedure
Job Rerformance Measure
WTop Set
of oolant Accident
lb-a
\\Motoyperated Valves
-Cited Violations
National Fire Protection Association'
Nuclear Regulatory Commission
Occupational Safety and Health Administration
Pressure Transmitter
Reactor Core Isolation Cooling
Self-Contained Breathing Apparatuses
Significance Determination Process
Safety Evaluation Reports
Safe Shutdown Analysis Report,
Technical Specification
Updated Final Safety Evaluation Reports
Unresolved Item
Cross-Linked Polyethylene
Attachment
cUNITED
-I
^< - at:NUCLEAR
REGULA'
REG
Cfr
SAM NUNN ATLANT
61 FORSYTH STRE
ATLANTA, GEOI
Southern Nuclear Operating Company, Inc.
ATTN: Mr. H. L.'Sumner, Jr.
Vice
President
' P. 0. Box 1295
- .
Al
Q20fln1 4 0nC
STATES
TORY COMMISSION
ION 11
A FEDERAL CENTER
RGIA 30303-8931
. .
- ol -
.I
..
Y
csr
Ing am
/AL. Q;JrL I - I rU;
.-,.
'.SUBJECT:
EDWIN I. HATCH NUCLEAR POWER PLANT - NRC TRIENNIAL FIRE'
PROTECTION INSPECTION REPORT 05000321/2003006 AND.'
Dear Mr. Sumner.
'
On July 25, 2003, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at
your Hatch Nuclear Plant Units 1 and 2. The enclosed inspection rep fi documents the
rispection findings, which were discussed on that date with Mr. R. D drickson and other
me
ers of your staff.
A
The inspection examined activities conducted under your licens as they relate to safety and
compliance with the Commission's rules and regulations and with the conditions of your license.
. 'The inspectors reviewed selected procedures and records, bserved activities, and interviewed
personnel.
This report docume ts two findings that have potential s fety significance greater than very
low significance, ho
ver a safety significance determi ation has not been completed. One
'
issue involving a proc dural inadequacy did present aa immediate safety concern, however,
your staff revised the
ocedure prior to the end of th inspection. The other issue did not
present an immediate safety concern. In addition, t
report documents three NRC-identified.'.
findings of very low safe
significance (Green), all f which were determined to involve
violations of NRC require ents. However, becaus of the very low satety significance and
because they are entered to your corrective acti n program, the NRC is treating these three
findings as non-cited violati ns (NVs) consiste
with Section VL.A of the NRC Enforcement
Policy. If you contest any N V in this report, y
should provide a response within 30' days of
the date of this inspection repa, with the bas
for your denial, to the Nuclear Regulatory
Commission, ATTN.: Documen
ontrol
k, Washington DC 20555-0001; with copies to the
\\
Regional Administrator Region II; t
ctor, Office of Enforcement, United States Nuclear
Regulatory Commission, Washington, DC .20555-0001; and the NRC Resident Inspector at the
Hatch Nuclear Power Plant.
(C
following completion of additional review in the Region II office, a final exit was held with'
/ .
And other members of your staff onr
i
SNC, Inc.
'
2
In accordance with 1 0 CFR 2.790 of the NRC's 'Rules of Practice," a copy of this letter and its
enclosure will be available electronically for public inspection in the NRC Public Document
Room or from the Publically Available Records (PARS) component of NRC's document system
(ADAMS). ADAMS is accessible from the NRC Website at
http: /www.nrc.aov/readin -rm/adams.html (the Public Electronic Reading Room).
Sincerely,
Charles R. Ogle, Chief
. I -
Engineering Branch 1
Division of Reactor Safety
Docket Nos.: 50-321, 50-366
License Nos.: DPR-57- NPF-5
Enclosure:
NRC Triennial Fire Protection Iinspection Report 50-321/03-06,.50-366/03-06
w/Attachment: Supplemental Information
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cc w/en'cl:
J. D. Woodard
Executive Vice President
Southern Nuclear Operating Company, Inc.'
Electronic Mail Distribution
George R. Frederick
General Manager,'Plant Hatch
-
Southern Nuclear Operating Company, Inc.
Electronic Mail Distribution
.
..
.
.
.
.
..
.
.
.I
Raymond D. Baker
Manager Licensing - Hatch
Southern Nuclear Operating Company, Inc.
Electronic Mail Distribution
Arthur H. Domby, Esq.
Troutman Sanders
Electronic Mail Distribution
Laurence Bergen
Oglethorpe Power Corporation
Electronic 'Mail Distribution
(cc w/encl cont'd - See page 3)
I
SNC, Inc.,
3
(cc w/erncl cont'd)
-'Director
Department of Natural Resources
205 Butler Street, SE, Suite 1252
.tlantaGA
30334
Manager, Radioactive Materials Program
Department of Natural Resources
Electronic Mail Distribution
Chairman.
Appling County Commissioners
County Courthouse
Baxley, GA 31513
Resident Manager:
Oglethorpe Power Corporation
Edwin I. Hatch Nuclear Plant
..Electronic Mail Distribution
Senior Engineer - Power Supply
Municipal.Electric Authority
of Georgia'.'
Electronic Mail Distribution
Reece McAlister
Executive Secretary
Georgia Public Service Commission
244 Washington Street, SW
Atlanta, GA 30334
Distribution w/encl:
'
S. Bloom, NRR
L. Slack, RII EICS
RIDSNRRDIPMLIPB
PUBLIC.
OFFICE
RII:DRS
RII:DRS
RII:DRS
.
CONTRCTOR
RiI:DRP
SIGNATURE
NAME
OSMITHR
IN
WI
KSULLIVAN
BONSER
DATE
8/
12003
8/
12003
8/
1200 3
0
8/
12003
8/
/2003
8/
/2003
E-MAILCOPY?
NO
YES
NO
YES
NO
YES
NO
YES
NO
YES
. NO
Y
N
PUBLIC DOCUMENTI
YES
NO
.
FIrlIAL
-nLLUH UUI-T
IAJl.U~
ICIT I'AC.sM\\~cc
.~J~l
Clrancn 1\\hotrcn ' uuSSutitrw
OFFICIAL RECORD COPY
L)UUUMtN I NAMt:
SMRSEng Branch I Viatch 2003-061irmpa
.. 1. .
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.1
.
.
Docket Nos.:
License Nos.:
Report No.:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Accompanying
Personnel:
U. S. NUCLEAR REGULATORY COMMISSION
REGION II
50-321, 50-366
05000321/2003006 and 05000366/2003006
Southern Nuclear Operating Company
E. I. Hatch Nuclear Plant
P. O. Box 2010-
Baxley, GA. 31513
July 7-11,2003 (Week 1)
July 21-25, 2003 (Week 2)
C. Smith, P E., Senior Reactor Inspector, (Lead Inspector)
R. Schin, Senior Reactor Inspector
G. Wiseman, Fire Protection Inspector
K. Sullivan, Consultant, Brookhaven National Laboratory
S. Belcher, Nuclear Safety Intern, Week 1
Approved by:
Charles R. Ogle, Chief
Engineering Branch 1
Division of Reactor Safety
Enclosure
CONTENTS
SUMMARYOFFINDINGS
.. ........
FIRE .PROTECTION
.
.............
.
.................... .........
..
Systems Required to Achieve and Maintain Post- ire Safe Shutdown ....
Fire Protection of Safe Shutdown Capability ......................................
Post-Fire Safe Shutdown Capability .........................-..
.
Alternate Shutdown Capability/Operational Implementation of Alternative Shutdown
Capability ..................
,
.,.;.'
Communications ....................
'.-
...
Emergency Lighting .................................................
'.':
'Cold Shutdown Repairs .....................................................
iFre Barriers and Fire Area/Zone/Room Penetration Seals ........................
Fire Protection Systems, Features, and Equipment ............................
Compensatory Measures
.
.;.'.'.;
SAFETY SYSTEM DESIGN AND PERFORMANCE CAPABILITY
Design Change Request 91-134, SRV* Backup Actuation Using Pressure Transmitter
'
"'
'
Signals ...
...
~~Sgn l
....
.. .,...,.
...............................................................
OTHER ACTIVITIES
-
Identification and Resolution of Problems.
Meetings Including Exit ...............
- .
a
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.
T
SUMMARY OF FINDINGS
IR 05000321/2003-006, 05000366/2003-006; 7/7-11/2003 and 7/21-25/2003 E. l. Hatch'
Nuclear Plant, Units 1 and 2; Triennial Fire Protection
The report covered an announced two-week period of inspection by three regional inspectors
and a consultant from Brookhaven National Laboratory. Three Green non-cited violations
(NCVs) and two unresolved items with potential safety significance greater than Green were :
'I
identified. The significance of most findings is indicated by their color (Green, White, Yellow,'
Red) using Inspection Manual Chapter (IMC) 0609, 'Significance Determination Process.
(SDP). Findings for which the SDP does not apply may be Green or be assigned a'severity
level after NRC management review. The NRC's program for overseeing the safe operation of
commercial nuclear power reactors is described in NUREG-1 649, "Reactor Oversight Process,"
Revision 3, dated July 2000.
A.
NRC-Identified and Self-Revealing Findings
Cornerstone: Initiating Events, Mitigating Systems, and Barrier Integrity
TBD. The team identified an unresolved item in that a local n)anual operator action, to
prevent spurious opening of all eleven safety relief valves (SFiVs) during a fire event,
would not be performed in sufficient time to be effective. Also, licensee reliance on this
manual action for hot shutdown during a fire, instead of physically protecting cables from
fire damage, had not been approved by the NRC.
-This finding is unresolved pending completion of a significance determination. The
finding is greater than minor because it affects the objective of the mitigating system
cornerstone. Also, the finding has potential safety significance greater than very low'..
safety significance because failure to prevent spurious operation of the SRVs could
result in them opening durinn/certain fire scenariop, thereby complicating the post-fire
recovery actions. (Section
05.04/.05.b.1)
/
Green. The team identified non-cited violatioI/qf 10 CFR 50, Appendix R,
Section III.G.1 and Technical Specificatio Y$)i,.4.1 because a local manual operator
'
action to operate safe shutdown equipme rs
too difficult and was also unsafe. The
licensee had relied on this action Instead of providing physical protection of cables from
fire damage or preplanning cold shutdown repairs. However, the team determined that'
some operators would not be able to perform the action.
The finding is greater than minor because it affected the availability and reliability
objectives and the equipment performance attribute of the mitigating systems
cornerstone. This finding is of very low safety significance because the licensee would
have time to develop and implement cold shutdown repairs to facilitate accomplishment
of the action, this finding did not have potential safety significance greater than very low
safety significance. (Section 1 R05.04/.05.b.2)
I:~
2.:z
Green. The team identified a non-cited violation of 10 CFR 50, Appendix R,.:
Section III.G.2 in that the licensee relied on some manual operator actions to operate
safe shutdown equipment, instead of providing the required physical protection of cables
from fire damage without NRC approval..
The finding is greater than minor because it affected the availability and reliability.
objectives and the equipment performance attribute of the mitigating systems -:.
cornerstone. Since the actions could reasonably be accomplished by operators in a
timely manner, this finding did not have potential safety significance greater than very
low safety significance. (Section 1 R05.04/.05.b.3) -
Green. The team identified non-cited violation 10 CFR 50, Appendix R, Section III.J
- because emergency lighting was not adequate for some manual operator actions that
were needed to support post-fire operation of safe shutdown equipment.:
The finding is greater than minor because it affected the reliability objective and the
equipment performance attribute of the mitigating systems cornerstone. Since
operators would be able to accomplish the actions with the use of flashlights, this finding
did not have potential safety significance greater than very low safety significance.,:
(Section 1 R05.07.b)
/
TBD: The team identifi~ed rnresolved item in connection with the implementation of
- -
Ad
design change reques((Dl))b 1-134, SRV Backup Actuation via Pressure Transmitter
'
-
Signals. The installed plant modification failed to implement the "one-out-of-two taken
twice logic that was specified as a design input requirements in the design change
package. Additionally, implementation of a "two-out-of-two coincidence taken twice
logic has introduced a potential common cause failure of all eleven SRVs as a result of
-
the potential for fire induced damage to two instrumentation circuit cables in close
proximity to each other.
""- '
.i..1
!
This finding is unresolv4 d pending completion of a significance determination. This
finding is greater thpn
ninor because it impacts the mitigating systpr~i cornerstone. 'This
finding has the pot nti I for defeating manual control of Group
-
RVs that are required
for ensuring that t e-s
pession pool temperature will not e
ed the heat capacity
temperature limit
the suppression pool. (Sectio
R21.01.b) -
Licensee-Identified Violations
B.
/Jt~T.i
None
i
REPORT DETAILS
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems and Barrier Integrity
1R05 Fire Protection
The purposq'of this inspection was to review the Hatch Nuclear Plant fire protection
program (FPP) for selected risk-significant fire Ureas. Emphasis was placed on
verification that the post-fire safe shutdown (SSD) capability and the fire protection
features provided for ensuring that at least one redundant train of safe shutdown
systems is maintained free of fire damage. The inspection was performed in
accordance with the Nuclear Regulatory Commission (NRC) Reactor Oversight Program
using a risk-informed approach for selecting the fire areas and attributes to be
inspected. The team used the licensee's Individual Plant Examination for External
Events and in-plant tours to choose four risk-significant fire areas for detailed inspection
and review. The fire areas chosen for review during this inspection were:,.
Fire Area 2016, West 600 V Switchgear Room, Control Building, Elevation 130
feet.
Fire Area 2104, East Cableway, Turbine Building, Elevation 130 feet.
.
Fire Area 2404, Switchgear Room 2E, Diesel Generator Building, Elevation 130 -
.feet.
- -
-
Fire Area 2408, Switchgear Room 2F, Diesel Generator Building, Elevation 130
feet.
.
The team evaluated the licensee's FPP against applicable requirements, including
Operating License Condition 2.C.(3)(a), Fire Protection; Title 10 of the Code of Federal
Regulations, Part 50 (10 CFR 50), Appendix R; 10 CFR 50.48; Appendix A of ranch.
Technical Position (BTiP) Auxiliary and Power Co rversion Systems Branch (A7CSB)
9.5-1; related NRC Safety Evaluatj6n Reports (S Rs); the Hatch Nuclear. Plant Updated
Final Safety Analysis Report (UFVAR); and plant'rS. The team evaluated all areas of
this inspection, as documented below, against these requirements.
Documents reviewed by the team are listed in the attachment.
.01
Systems Required to Achieve and Maintain Post-Fire SSD
a.
Inspection Scope
The licensee's Safe Shutdown Analysis Report (SAR) was reviewed to determine the
components and systems necessary to achieve and maintain safe shutdown conditions
in the event of fire in each of the selected fire areas. The objectives of this evaluation
were as follows:
A^
2.
c
X Verify that the licensee's shutdown methodology has correctly identified
the components and systems necessary to achieve and maintain a SSD
condition.
Confirm the adequacy of the systems selected for reactivity control,
'reactor
coolant makeup, reactor heat removal, process monitoring and
support system functions.-'
c
Verify that a SSD can be achieved and maintained without off-site power,'
when it can be confirmed that a postulated fire in any of the selected fire
areas could cause the loss of off-site power.
-
Verify that local manual operator actions are consistent with the plant's'-
fire protection licensing basis.
- b.
.Findings
The team identified a potential concern in that the licensee used manual actions tV
di connect terminal board sliding links In order to isolate two 4 to 20 milli-amp (r)
'
intrumentation loop control circuits in order to prevent the spurious actuation of eleven'
V
This issue is discussed in section 1 R05.03.b of the report. No other findings of
significance were identified.'
.02
Fire Protection of SSD Capabilitv
a.
Inspection Scope
For the selected fire areas, the team evaluated the frequency of fires or the potential for
fires, the combustible fire load characteristics and potential fire severity, the separation
of systems necessary to achieve SSD, and the separation of electrical components and: -
'
circuits located within the same fire area to ensure that at least one SSD path was free
of fire damage. The team also inspected the fire protection features to confirm they..
were installed in accordance with the codes of record to satisfy the applicable separation
and design requirements of 10 CFR 50, Appendix R, Section III.G, and Appendix A of
BTP APCSB 9.5-1. The team reviewed the following documents, which established the
controls and practices to prevent fires and to control combustible fire loads and ignition
sources, to verify that the objectives established by the NRC-approved FPP were
'
satisfied:
,
UpdatedFinarSaferyAnalysi
4Section 9.1-A, Fire'Protection
Plan
Administrative Procedure 40AC-ENG-008-OS, Fire Protection Program
Administrative Procedure 42FP-FPX-01 8-OS, Use, Control, and Storage of
Flammable/Combustible Materials
.
Preventive Maintenance Procedure 52PM-MEL-012-0, Low Voltage Switchgear
Preventive Maintenance
The team toured the selected plant fire areas to observe whether the licensee had
properly evaluated in-situ fire loads and limited transient fire hazards in a manner
consistent with the f-ie prevention and combustible hazards control procedures. In
addition, the team reviewed the licensee's ffOe safety inspection reports and corrective
action program (CA ) condition reports (C s) resulting from fire, smoke, sparks, arcing,
'and oehangiciet frte years 2000-2002 to assess the effectiveness of the fire'
prevention Orogrami
and to identify any maintenance or material condition problems
related to fire incidents.
The team reviewed fire brigade response, fire brigade qualification training, and drill
iprogram procedures; fire brigade drill critiques; and drill records for the operating shifts
from January 1999 - December 2002.; The reviews were performed to determine
whether fire brigade drills had been conducted in high fire risk plant areas and whether
fire brigade personnel qualifications; drill response, and performance met the
- requirements of the licensee's approved FPP.
The team walked down the fire brigade equipment storage areas and dress-out locker
areas in the fire equipment building and the turbine building to assess the condition of
- .~~fire
fighting and smoke control equipment. Fire brigade personal protective equipment..
located at both of the fire brigade dress-out areas and fire fighting equipment storage
area in the turbine building were revijewed to evaluate equipment accessibility and
functionality. Additionally, the team observed whether emergency exit lighting was
- ' .
providedtfor personn
eacuaoition pathways to the oUtside exits as identified in' t
National Fire Protection Association (N-jPA) 101 L
afety Code' and the
Occupational Safety and Health Administrto (S(IA)Pr
190, Occupational Safety
and Health Standards. This review also included examination of whether backup
emergencylighting was provided for access pathways to and within the fire brigade
equipment storage areas an- dress-out locker areas in support of fire brigade'
operations should power faill uring a fire emergency. The fire brigade self-contained
breathing 'apparatuses (SCq As) were reviewed for adequacy as well as the availability
of supplemental breathing air tanks and their refill capability.
The team reviewed fire fighting pre-f ire plans for the selected areas to determine If
appropriateainformation was provided to fire brigade members and plant operators to
facilitate suppression of a fire that could impact SSD. Team members also walked
down the selected fire areas to compare the tsscinated pre-f ire plans and drawings with
as-built plant conditions. This was done to v. rifyethat fire fighting pre-fcire plans and
drawings were consistent with the fire protetion features and potential fire conditions
described in'the Fire Hazards Analysis (FfA).
- The team reviewed the adequacy of the design, installation, and operation of the Manual
suppression standpipe and fire hose system for the control building. This was
s
accomplished by reviewing the FHA, pre-fire plans and drawings, engineering'
- mechanical equipment drawings, design flow and pressure calculations, and NFPA 14
for hose station location, water flow requirements and effective reach capability. -Team
members also walked down the selected fire areas in the control building to ensure that
hose stations were not blocked and to verify that the required fire hose lengths to reach
the safe shutdown equipment in each of the selected areas were available. Additionally,
the team observed placement of the fire hoses and extinguishers to assess consistency
- '
.'with
the fire fighting pre-fire plans and drawings..
- b.
Findings
No findings of significance were Identified.
.03.
a.-
4
Post-Fire SSD Capability
Inspection Scope
On a sample basis, the inspectors evaluated whether the systems and equipment
identified in the licensee's SSAR as being required to achieve and maintain hot,.
.::
shutdown conditions would remain free of fire damage in the event of fire in the selected
fire areas. The evaluation included a review of cable routing data depicting the location
of power and control cables asso ated with SSD Path I and Path 2 components of the
reactor core isolation cooling (RqlC) and high pressure coolant injection (HVCI).
systems. Additionally, on a sample basis, the team reviewed the licensee's analysis of..
electrical protective devicg (e.g., circuit breaker, fuse, relay) coordination. The following
motor operated valves (10Vs)
and other components were reviewed:.-
Component ID '
Description
RCIC Pump Suction from Suppression Pool Valve "
2E51 -F01 0
RCIC Pump Suction Valve from Condensate Storage Task (CIT
.
Plant Service Water Pump
2211-F011A
Residual Heat Removal (RI 1R) Heat Exchanger A Drain to
Suppression Pool Valve
2P41 -C001 B
Plant Service Water Pump 2B
HPCI Turbine Steam Supply Valve
HPCI Turbine Steam Supply Inboard Containment Isolation Valve:
I
II
2E41 -F006
HPCI Pump Inboard Discharge Valve
2E41 -FOO8
HPCI Pump Discharge Bypass Test Valve to CST
. b..
Findings
The team identified a potential concern In that the licensee used manual actions to
isolate two 4 to 20 ma instrumentation loop control circuits associated with eleven SRVs
in lieu of providing physical protection. This did not appear to be consistent with the
plant's licensing basis nor 1 0 CFR 50 Appendix R. Spurious action of these SRVs could
impact the licensee's fire mitigation strategy. In addition, the licensee provided no
objective evidence that post-fire safe shutdown equipment could mitigate this event.
The SSAR stated that a fire in Fire Area 2104 could cause all eleven SRVs to spuriously
actuate as a result of fire damage to two cables located in close proximity in this area.
The specific circuits that could cause this event were identified by the licensee as
circuits: ABE019C08 and ABE019C09. Each circuit separately provides a 4 to 20 ma
instrumentation signal from an SRV high-pressure actuation transmitter 2B21-N127B or
2B21-N127D to its respective master trip unit (2B21-N697B or 2B21-N697D). The
purpose of this circuitry was to provide an electrical backup to the mechanical trip:
capability of the individual SRVs. In the event of high reactor pressure, the circuits
would provide a signal to the master trip units which would cause all eleven SRVs to
actuate (open). The pressure signal from each transmitter would be conveyed to its
respective master trip unit through a two-conductor, instrument cable that was routed
through this fire area (two separate cables). Each cable consisted of a single twisted
pair of insulated conductors, an uninsulated drain wire that was wound around the
twisted pair of conductors, and a foil shield. In Fire Area 2104, the two cables were
located in close proximity in the same cable tray. Actuation of the SRV electrical backup..
is completely "blind" to the operators. That is, unlike ADS, it does not provide any pre-
actuation indication (e.g., actuation of the ADS timer) or an inhibit capability (e.g., ADS
inhibit switch). Because the operators typically would not initiate a manual scram until
fire damage significantly interfered with control of the plant, it is possible that all eleven
SRVs could open at 100% power, prior to scramming the reactor. This event could
-place the plant in an unanalyzed condition..
- Unlike a typical control circuit, a direct short or "hot short" between conductors of a
4 to 20 ma instrument circuit may not be necessary to initiate an undesired (false high)
signal. For cables that transmit low-level Instrument signals, degradation of the..
insulation of the individual twisted conductors due to fire damage may be sufficient to
cause leakage current to be generated between the two conductors. Such leakage'
'current would appear as a false high pressure signal to the master trip units. If both
-
cables were damaged as a result of fire, false signals generated as a result of leakage
current in each cable, could actuate the'SRV electrical backup scheme which would
i cause all eleven SRVs to open. The con ductor insulation and jacket material of each
cable was cross-linked polyethylene (XLOPE). Because both cables were in the same
tray and exposed to the same heating rate, there would be a reasonable likelihood that
' both instrumentation cables could suffer insulation damage at the samne time and both
circuits could fail high simultaneously..'
The licensee's SSAR recognized the potential safety significance of this event and'
described methods that have been developed to'prevent its occurrence and/or to
mitigate its impact on the plant's post-fire SSD capability (should it occur). To prevent
this event, the licensee developed procedural guidance which directs operators to open
link BB-10 in panel 2H11-P927 and link BB-10 in panel 2H11-P928. These panels are
located in the main control room. 'Opening of these links would prevent actuation of the
SRV trip units by removing the 4 to 20 ma signal fed by the pressure transmitters to the
master trip units. In the event the SRVs were to open prior, to the operators completing
this action, the SStRslang-Core spray loop Alto mitigate the event.
The inspection team had several concerns regarding the licensee's approach to this
'
potential spurious actuation of the SRVs. Specific concerns identified by the team
'.
include:.
1.'
The links may not be opened in time to preclude inadvertent actuation of the
SRVs.
2.
The use of links to avoid Inadvertent actuation of the SRVs did not appear to be
consistent with the current licensing basis.
3. Noobjecive eidence existed to demonstrate that the post-fire SSD equipment
could adequately mitigate a fire in Fire Area 2104, if the SRVs; were to open.
4.
The operations staff would be unable to manually control the Group A SRVs,
which are credited for mitigating a fire in Fire Area 2104, should they spuriously,...
actuate'as a result of fire-induced damage.
With regard to the timing of operator actions to prevent fire damage from causing all
SRVs to open, the licensee performed an evaluation during the inspection which
estimated that approximately thirty minutes would pass from the time of fire detection to
the time an operator would implement procedural actions to open the links. -The
inspectors independently arrived at a similar time estimate based on their review of the
procedure. In response to inspector's concerns that this interval may be too lengthy to
preclude fire damage to the cables of interest and subsequent actuation of the SRVs,.
the licensee agreed to enhance its existing procedures so that the action would be
taken immediately following confirmation of fire in areas where the'spurious actuation:
could occur. This issue is discussed in Section 1 R05.'04/.05.b.1 of this report..
The team also determined that the opening of terminal board links was not In
compliance with the plant's licensing basis. Current licensing basis documents,
- specifically Georgia Power request for exemptijn dated May 16, 1986, and a~
subsequent NRC Safety Evaluation Report (SVR) dated January 2, 1 987, characterized
the opening of links as a repair activity that is not permitted as a means of complying
- with 10 CFR 50, Appendix R, Section lll.G. The inspectors concluded that, the opening
of links was considered a repair by both the licensee and the NRC staff in 1987. The
VI~
licensee could not provide any evidence to justify why these actions should ot be
D
-A
.Additionally, because there Is a potential for all SRVs to spuriousl ac
eulto
r
104 at a time when RHR is not available, the SA
Of
core spray loop A to accomplish the reactor coolant makeup funci.
uring the
I
.inspeilorn-,the-licensee
perfogrmed a sirnulat~ctbr-i,,of an event which caused all 1 1
SRVs to open. During this exercise, simul tor RPV Iay~ Iinstruments indicated that core
- :' spray would be capable of maintaining leved-abovert
ie top of active fuel. However, the
licensee did not provide any objective evidence (ag g, specific calculation r analysis)
which demonstrated that, assuming worst-case fire damage in Fire Are 2104, the.
-'limited
set of equipment available would be
unablet
of mitigating the eG nt in a manner
'
-
that satisfied theishutdowniperformanceiga
oas
afreinFire As
pendix R,
'
Section
'l..L.l.e.
(;'.
Finally, the logic that was Installed byr a
for
e
sasa fro
t-of -twcs
a
coincidence taken twice' logic in addit
o
-
i
logic.' The team determined that the two-mut-o
c
elinfrom trip
-'unit
master relays K310D and K335D repr sented
mmon cause failure for
A
SRVs for a fire in Fire Area 2104. Specifically, cable ABE01 9008 associated with
.
pressure transmitter2 B213-N12713 current loop, and cable ABE0o
t
9t 9 associated with
l
7 -
. -
pressure transmitter 2B21-N127D current loop, were routed in close proximity to each
other in the same cable tray in Fire Area 2104. Both shielded twisted pair instrument
cables were unprotected from the effects of a fire in this fire area. Fire-induced
insulation damage to both cables could result in leakage currents and cause the
instrument loops to fail high. This failure mode would simulate a high nuclear boiler
pressure condition and would initiate SRV backup actuation of all the Group A SRVs.
Whenever a SRV lifted, it would remain open until pressure reduced to about 85% of its
overpressure lift setpoint However, the instrument loops, having failed high, would
ensure that the trip unit master relays and the trip unit slave relays continued to energize
the pilot valve of the individual SRV and keep the SRV open. This issue is discussed In
-
more detail in Sectior21.01. Ultimately, this failure mode would prevent the..
operators from manualy controlling the roup A SRVs as required per the SSAR.
In response, the licensee initiated CR 2003800152, dated July 24, 2003, to evaluate
actions to open links to determine if they are necessary to achieve hot shutdown, and if
an exemptio from Appendix R in required. Pending additional review by the NRC, this
issue is ide itified a §URI,50-36 /03-06-01, Concerns Associated with Potential Opening
of SRVs. J
-
.04/.05 Alterna
hutdown Capabilitv/Overational Implementation of Alternative Shutdown
-,'.. .,Capabilttv.
i
I
.
n
I.
I. At~f ~~l
The selected fire areas that were the focus of this Inspection all Involved reactor
_ shutdown from the control room. None involved abandoning the control room a
I
alternative safe shutdown from outside of the control room. Thus, alterna
itdown
capability was not reviewed during this Inspection. However, the licensee's plans for
SSD following a fire in the selected areas involved many local manual operator actions
that would be performed outside of the control area of the control room. This section of.
the inspection focused on those local manual operator actions.
The team reviewed the operational Implementation of the SSD capability for a fire In the
selected fire areas to determine if: (1) the procedures were consistent with the SSAR;
(2) the procedures were written so that the operator actions could be correctly
performed within the times that were necessary for the actions to be effective; (3) the
training program for operators included SSD capability; (4) personnel required to
achieve and maintain the plant in hot standby could be provided from the normal onsite
staff, exclusive of the fire brigade; and (5) the licensee periodically performed operability
testing of the SSD equipment.
- 1
- 1
The team walked down SSD manual operator actions that were to be performed outside
of the control aea of the main control room for a fire in the selected fire areas and
discussedthe with operators. These actions were documented in Abnormal Operating
Procedure (UP) 34AB-X43-001 -2, Version 10.8, dated Ma 28, 2003. The team
evaluated whether the local manual operator actions coul reasonably be performed,
using the criteria outlined in NRC Inspection Procedure (iP) 71111.05, Enclosure 2. The
team also reviewed applicable operator training lesson plans and job performance
-
-
8
measures (JPMs) and discussed them with operators. In addition, the team reviewed
records of actual operator staffing on selected days.
b.
Findings
Untimely and Unapgroved Manual Operator Action for Fire SSD
Introduction: The team found that a local manual operator action to prevent spurious
opening of all eleven SRVs would not be performed in sufficient time to be effective.
Licensee reliance on this manual action for hot shutdown during a fire, instead of
physically protecting cables from fire damage, had not been approved by the NRC.
Description: The team noted that Step 9.3.2.1 of AOP 34AB-X43-001-2, Fire
Procedure, Version 10.8, dated May 28, 2003, stated: "To prevent all eleven SRVs from
opening simultaneously, open links BB-1 0 in Panql 2H1 1 -P927 and BB-1 0 in Panel
2H1 1-P928." The team noted that spurious opening of all eleven SRVs should be
considered a large loss of coolant accident (L
A) and that a LOCA be prevented from
occurring during a fire event. Specifically, to comply with 10 CFR 50, Appendix R,
Section III.L. Section lll.L requires that, during a post-fire shutdown, the reactor coolant
system process variables (e.g., reactor vessel water level) shall be maintained within
those predicted for a loss of normal a.c. power. Having all eleven SRVs opened during
a fire would challenge this. Additionally, the team observed that this step was
sufficiently far back in the procedure that it may not be completed in time to prevent
potential fire damage to cables ftom causing all eleven SRVs to spuriously open.
The licensee had no preplannq 6 estimate of how long It would take operators to
complete this step during a fir) event, there was no event time line or operator training
on this step. The team noted that, during a fire,
operators could be using many other procedures concurrent with the Fire Procedure.
For example, they could be using other procedures to communicate with the fire brigade
about the fire, respond to a reactor trip, deal with a loss of offsite power, and provide
emergency classifications and offsite notifications of the fire event. During the
inspection, licensee operators estimated that, during a fire event, it could teho about
30 minutes before operators would accomplish Step 9.3.2.1. The team concurred with
that time estimate which the team had previously determined independently. However,
NRC fire models indicated that fires could potentially cause damage to cables in as
short a period of five to ten minutes. Consequently, the team concluded that during a
fire event, the licensee's procedures would not ensure that Step 9.3.2.1 would be
accomplished in time to prevent potential spurious opening of all eleven SRVs.
The team also identified other Issues with Step 9.3.2.1. There was no emergency
lighting inside the panels, hence, if the fire caused a loss of normal lighting (e.g., by
causing a loss of offsite power), operators would need to use flashlights to perform the
actions inside the panels. Consequently, the team considered the emergency lighting
for Step 9.3.2.1 to be inadequate (see Section 1 R05.07.b). In addition, labeling of the
links inside the panels was so poor that operators stated that they would not fully rely on
the labeling. Also, the tool that operators would use to loosen and slide the links inside
the energized panels was made of steel and was not professionally, electrically
insulated. Further, licensee reliance on this operator action, instead of physically
.9
protecting the cables as required by 10 CFR 50, Appendix R, Section III.G.2, had not
been approved by the NRC.
- .
~
~ ~ ~~.
.
.
................
The licensee stated that cable damage to two reactor pressure instrument cables, w6uld
be needed to spuriously open all eleven SRVs. Because the licensee stated that tfe
two cables were in the same cable tray in Fire Area 2104, the team considered thjt a'
fire in that area could potentially cause all eleven SRVs to spuriously open (set
ction
1 R21 .01 .b).
.
-
In response to this issue, the licensee initiated CR 2003008203 and promptly revised
the Fire Procedure before th end of the inspection, moving the actions of Step 9.3.2.1
to the beginning of the pro dure. The procedure change enabled the actions to be:
accomplished much soo
r during a fire in the Unit 2 east cableway or. in other-fire:
areas that were vulner
le to the potential for spuriously opening all eleven SRVs. The,'
team determined tha his issue is related to associated circuits. As described in NRC'
-
Inspectiorrnrpced elIPi71111.05, Fire Protection, inspection of associated circuits Is'
temporarily lirlte
Consequently, the team did not pursue the cable rou ifig or circuit
analysis that would be necessary to evaluate the possibility, risk, or po ntial safety .-'-'-..
significance of Group B and C SRVs spuriously opening due to fire
mage to the
instrument cables. The team did, however, perform a circuit analy s of Group A SRVs'
for which the licensee takes credit during a fire in fire area 21 04 -(tee Section -
1 R21.01.).
Analysis: The team determined that this finding was associated with the protection
against external factors attribute. It affected the objective of the mitigating system
cornerstone to ensure the availability of systems that respond to initiating events and Is!
therefore greater than minor. The team determined that the finding' had potential safety
significance greater than very low safety significance because failure to prevent .:
spurious operation of the SRVs could result in them opening in certain fire scenarios,
thereby complicating the post-fire recovery actions. However, the finding remains
unresolved pending completion of the SDP.
Enforcement: 10 CFR 50, Appendix R, Section lll.G.2 requires that twhere cables or
equipment, including associated non-safety circuits that could prevent operation or
cause mal-operation due to hot shorts, open circuits, or shorts to ground, of redundant.
trains of systems necessary to achieve and maintain hot shutdown conditions are
located within the same fire area outside of the primary containment, one of the
following means of ensuring that one or the redundant trains is free of fire damage shall
be provided: 1) a fire barrier with a 3-hour rating; 2) separation of cables by a horizontal
distance of mbre than 20 feet with no intervening combustibles and with fire detectors
and automatic fire suppression; or 3) a fire barrier with a 1-hour rating with fire detectors
and automatic suppression.
The licensee had not provided physical protection against fire damage for the two
instrument cables by one of the prescribed methods. Instead, the licensee had relied on
local manual operator actions to prevent the spurious opening of all eleven SRVs.
Licensee personnel stated that fire'damage to two cables was outside of the Hatch
licensing basis and, consequently, there was no requirement to protect the instrument
cables. However, the licensee could not provide evidence to support that position.
10
This potential issue' will remain unresolved pending the qompletion of a significance
determination by the NRC. This issue is identified as U RI 50-366/03-06-02, Untimely
and Unapproved Manual Operator Action for Post-Fire SSD.
- 2.
Local Manual Operator Action was Too Difficult and Unsafe
.'Introduction:
A finding of very low safety significance was identified in that a local
manual operator action to operate SSD equipment was too difficult and was also unsafe.'
"The
team judged that some operators would not be able to perform the action. This
finding involved a violation of NRC requirements.
Description: The team observed that Steps 4.15.8.1.1 and 9.3.5.1 of the Fire Procedure
relied upon local manual operator actions instead of providing physical protection for
cables or providing a procedure for cold shutdown repairs. Both steps required the
same local manual operator action: "Manually OPEN 2E1 I -F01 5A, InboardcLPCiV)
Injection Valve, as required." This action was to be taken in the Unit 2 dryweIaccess,
which was a locked high radiation, contaminated, and hot area with temperatures over
100 degrees F.
Valve 2E1 I -F01 SA was a large (24-inch diameter) motor-operated gate valve with a'
three-foot diameter handwheel. The main difficulty with manually opening this valve was
.lack of an adequate place to stand., An operator showed the team that to perform the
action he would have to climb up to, and stand on a small section of pipe lagging (a'
curved area about four inches wide by 12 inches long), and then reach back and to his
right side, to hold the handwheel with his right hand, while reaching forward and to his
right to hold the clutch lever for the motor operator with his left hand. The operator
would not have good balance while performing the action. The foothold, which was
large enough to support only one foot, was well flattened and appeared to have been
used in the past to manually operate this valve. The foothold was about six to seven
feet above a steel grating, and the'team observed that the space available for potential
- use of a ladder to better access the 2E1 1 -F01 5A valve handwheel was not good.
'Other difficulties with manually opening the valve Included the heat; the need tc wear'
full anti-contamination clothing, a hardhat, and safety glasses; and inadequate
- ' : - emergency lighting (see Section 1 R05.07). Also, there was no note or step in the
procedure to ensure that the RHR pumps were not running before attempting to
manually open the 2E1l-FO15A valve. If an RHR pump were running, it could create a
differential pressure across the valve which could make manually'opening it much more
difficult. If the operator did not have sufficient agility, strength or stamina, he would be
unable to complete the action. Also, the team judged that inability to remove sweat from
- his
eyes, due to wearing gloves that could be contaminated, would be a limiting factor
for the operator. In addition, if the operator slipped or lost his balance, he could fall and
become injured. Considering all of the difficulties, the team judged that this action was
unsafe and that some operators would not be able to perform it.
The licensee had no operator training JPM for performing this action and could not
demonstrate that all operators could perform the action. One experienced operator,
who appeared to be in much better physical condition that an average nuclear plant
- e
S
operator, stated that he had manually operated the'valve in the past,'but that itfhad been
'
very difficult for him.
The team judged that, since this action was not required to maintain hot shutdown but
only required for coid shutdown following a fire in one of the four selected fire areas,:
licensee personnel could have time to improve the working conditions after a fire. They
could have time to install scaffolding or temporary ventilation; improve the lighting; and
assign multiple operators to manually open the valve. They could have time to perform
a cold shutdown repair. However, the licensee had not preplanned any cold shutdown'.
repairs for opening this valve.
Analysis: This finding is greater'than minor because it affected the availability and
reliability objectives and the equipment performance attribute of the mitigating systems
cornerstone. Because the licensee would have time to develop and implement cold.'
shutdown repairs to facilitate accomplishment of the action, this finding did not impact
-
the effectiveness of one or more of the defense in dept elements. Hence, this finding,'
did not have potential safety significance greater than v ry low safety significance:,
(Green).
Enforcement: 10 CFR 50, Appendix R
ection III.G.1 requires that fire protection
features shall be provided for syste
important to safe shutdown and shall be capable
of limiting fire damage so that systF s necessary to achieve and maintain cold
-
shutdown from either the cor triom or emergency control stations can be-repaired
-
within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. In addition,
.4.1 requires that written procedures shall be
established, implemented, and maintained covering activities including FPP
implementation and including the applicable procedures recommended In Regulatory
Guide 1.33, Revision 2, Appendix A, February 1978. Regulatory Guide 1.33'
recommends procedures for combating emergencies including plant fires and
procedures for operation and shutdown of safety-related BWR systems. The fire'
protection program includes the SSAR which requires that valve 2E11 -F01 5A be
opened for SSD following a fire in Fire Area 2104, the Unit 2 east cableway. AOP
34AB-X43-001-2, Fire Procedure, Version 10.8, dated May 28, 2003, implements these
requirements in that it provides information and actions fecess-ar, to mitigate the
consequences of fires and to maintain an operable'shutdown train following fire damage.
- 'to
specific fire areas. Also, AOP 34AB-X43-001-2 provides Steps 4.15.8.1.1 and 9.3.5.1'
for manually opening valve 2E11-F01 5A following a fire in Fire Area 2104.
-'
Contrary to the above, the licensee had no procedure for repairing any related fire '
damage within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Instead, the licensee relied on local manual operator actions,
as described in Steps 4.15.8.1.1 and 9.3.5.1 of AOP 34AB-X43-001-2. However, those
procedure steps were inadequate in that some operators would not be able to perforr
them because the required actions were too difficult and also were unsafe. In respobse
to this issue, the licensee initiated CR 203008202. Because the identified inadequafe
operator actions are of very low safety significance and the issue has been ejtereint6V
the licensee's corrective action program, this violation is being treated as anN
f
consistent with Section VL.A of the NRC's Enforcement Policy: NCV 50-366/6-03,
Inadequate Procedure for Local Manual Operator Action for Post-Fire Safe Shutdown
Equipment.
.
.
F
3.'"'
--.. ..
.:
. .
.
.
.
.
.
.
.
.
.
.
.
.
.
.:
.
...
,
12'
Unapproved Manual Operator Actions for Post-Fire SSD
Introduction: A finding of very low safety significance was identified in that the licensee
relied on some local manual operator actions to operate SSD equipment, 'instead of
providing the required physical protection'of cables from fire damage. This finding"'
involved a violation of NRC requirements.
Description: The team observed that AOP 34AB-X43-001-2, Fire Procedure, included
some local manual operator actions to achieve and maintain hot shutdown that had not.'.
been approved by the NRC. Examples of steps from the procedure included:
Step 4.15.2.2; ... lf a loss of offsite power occurs and emergency busses
energize ...'Place Station Service battery chargers 2R42-S026 (2R42-SO29),
2R42-S027 (2R42-S030) AND 2R42-S028 (2R42-S031) in service per,34SO-
R42-001-2.
Step 4.15.4.5; ... lf HPCI fails to automatically trip on high RPV level.... OPEN the.;
following links to energize 2E41-F1l24, Trip'Solenoid Valve, AND to fail 2E41-. -
-
F3025 HPCI Governor Valve, in the CLOSED position:
-
':
TT-75 in panel 2H1 1 -P601
-
' '
-
'
TT-76 in panel 2H11-P601 "
'.
.
Step 4.15.4.6; ... lf HPCI fails to automatically trip on high RPV level.'.. OPEN
breaker 25 in panel 2R25-S002 to fail 2E41-F3052, HPCI Governor Valv6, in the
CLOSED position.
' -
The team walked down these actions using the guidance corntained in Inspection\\
Procedure 71111.05T and judged that they could reasonably be accomplished by
..
operators in a timely manner. However, the team determined that these operator
actions were being used instead of physically protecting cables from fire damage that.
could cause a loss of station service battery chargers or a HPCI pump runout.
Analysis: The finding is greater thanri minor because It afeclteu the availability a.nd.
reliability objectives as well as the equipment performance a ribute of the mitigating
systems cornerstone. Since the actions could reasonably
accomplished by operators
in a timely manner, this finding did not have potential safe significance greater than
very low safety significance'.
Enforcement: 10 CFR 50, Appendix R, Section III
uires that where cables or'
equipment, including associated non-safety circuit
a.ould prevent operation or
cause maloperation due to hot shorts, open circuits, or shorts to ground, of redundant
trains of systems necessary to achieve and maintain hot shutdown conditions are
located within the same fire area outside of the primary containment, one of the
following means of ensuring that one of the redundant trains is free of fire damage shall
be provided: 1) a fire barrier with a 3-hour rating; 2) separation of cables by a horizontal
distance of more than 20 feet with no intervening combustibles and with fire detectors
and automatic fire suppression; or 3) a fire barrier with a 1-hour rating with fire detectors
and automatic suppression.
.
.
l
- .
@ @
.
.
6
@
.
.
.
%
..
.
.
.
S
.
4
> A;
B
.
.
.
.
- -
.06
.
-
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. .
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.
.
.
.
.
..
-
.a.
.
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.
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.
.
.
13
Contrary to the above, the licensee had not provided the required physical protection
against fire damage for power to the station service battery chargers or for HPCI
electrical control cables. Instead, the licensee relied on local manual operator actions,.
without NRC approval.. In response to this issue, the licensee initiated CR2003800166.
Because the issue had very low safety significance and has been entered into the
licensee's corrective action program, this violation is being treated as an NCV,
consistent with Section VL.A of the NRC's Enforcement Policy: NCV 50-366/03-06-04,
Unapproved Manual Operator Actions for Post-Fire Safe Shutdown..
Communications
Inspection Scope
l
The team reviewed the plant communications systems that would be relied upon to.
-
support fire brigade and SSD activities. The team walked down portions of the SSD
procedures to verify that adequate communications equipment would be available for
personnel performing local manual operator actions. In addition, the team reviewed the
-
.
adequacy of the radio communication system used by the fire brigade to communicate
.
. with the main control room.
b.
Findings
No findings of significance were Identified.
.07
a.
Inspection Scope
The team inspected the licensee's emergency lighting systems to verify that 8-hour
emergency lighting coverage was provided as required by 10 CFR 50, Appendix R,
Section lll.J, to support local manual operator actions that were needed for post-fire
operation of SSD equipment. During walkdowns of the post-fire SSD operator actions'
for fires in the selected fire areas, the team checked if emergency lighting units wore
installed and if lamp heads were aimed to adequately illuminate the SSD equipment, the
equipment identification tags, and the access and egress routes thereto, so that
operators would be able to perform the actions without needing to use flashlights.
b.
Findings
Inadequate Emergency Lighting for Operation of SSD Eguipment
Introduction: A finding with very low safety significance was identified in that emergency
lighting was not adequate for some manual operator actions that were needed to
support post-fire operation of SSD equipment. This finding involved a violation of NRC
requirements.
Description: The team observed that emergency lighting was not adequate for some
manual operator actions that were needed to support post-fire operation of SSD
-
14
equipment. Examples included the following operator actions in procedure 34AB-X43-
' 001-2, Fire Procedure, Version 10.8, dated May 28, 2003:
-*
Step 4.15.2.2; ...if a loss of offsite power occurs and emergency busses energize:
.. "Place Station Service battery chargers 2R42-S026 (2R42-S029), 2R42S027..
- (2R42-S030) AND 2R42-S028 (2R42-S031) in service per 34SO-R42-001 -2.' ':
Step 4.15.4.5; ...lf HPCI fails to automatically trip on high RPV level.'.. OPEN the.
following links to energize 2E41-F124, Trip Solenoid Valve, AND to fail 2E41'
F3025 HPCI Governor Valve, In the CLOSED position:
- ' .
TT-75 in panel 2Hi 1-P601
-:..
-
.
TT-76 in panel 2HlI-P601'
Step 4.15.5; 'IF 2R25-S065, Instrument Bus 28, is DE-ENERGIZED perform the.
following manual actions to maintain 2C32-R655, Reactor Water Level.
Instrument, operable:
4.15.5.1;At panel 2H11-P612, OPEN links AA-11 and AAA12
4.15.5.2; At panel 2H1 1 -P601, CLOSE links HH-48 and HH-49.:
Steps 4.15.8.1.1 and 9.3.5.1; "Manually OPEN 2E11 -F015A, Inboard LPCI
'
Injection Valve, as required..
- .? ..
e.
Steps 4.15.8.1.2 and 9.3.5.2; 'Manually CLOSE 2E1 -FO18A, RHR Pump A '
Minimum Flow Isolation Valve, as required.'.
.
Step 9.3.2.1; 'To prevent all 11 SRVs from opening simultaneously, open links
BB-10 in Panel 2H11-P927 and BB-10 in Panel 2H11-P928.:
- 'Step
9.3.3; 'At Panel 2H1 1 -P627, open links AA-1 9, AA-20, AA-21, and AA-22,'
to prevent spurious actuation of SRVs 2B21-F013D AND 2B21-F013G.'
Step 9.3.6; 'OPEN link TB9-21 in Panel 2H1 1 -P700 to open Drywell Pneumatic
System Inboard Inlet Isolation, 2P70-F005.-
Step 9.3.7; 'OPEN link TBI-12 In Panel 2H11-P700 to open Drywell Pneumatic
System Outboard Inlet Isolation, 2P70-F005.'
Step 9.3.9.1; 'Confirm OR manually CLOSE RHR Shutdown Cooling Valve:
Step 9.3.9.2; 'Manually OPEN Shutdown Cooling Suction Valve 2E1 1 -F008, IF'
required...'
The team verified that flashlights were readily available and judged that operators would
be able to use the flashlights and accomplish the actions, with two exceptions. One
' '
exception was the action to open terminal board links in two panels to prevent all eleven
SRVs from spuriously opening, which was judged to be untimely (see Section
1 R05.041.05.b.1). The other exception was the action to open 2E1 1 -F01 5A, which was
judged to be too difficult (see Section 1 R05.04/.05.b.2). For both of these actions, the
1 5
lack of adequate emergency lighting could make the actions mor'e difficult to complete in'-
a timely manner and increase the chance of operator error.
Analysis: This finding is greater than minor because it affected the reliability objective
and the equipment performance aPttribute of the mitigating systems cornerstone. Since
operators would be able to accomplish the actions with the use of flashlights, this finding..
-did not impact the effectiveness of one or more of the defense in depth elements.
Hence, this finding did not have potential safety significance greater than very low safety..
significanice (Green)...
Enforcement: 1 0 CFR 50, Appendix R, Section lll.J, requires that emergency lighting
units with at least an 8-hour battery power supply shall be provided in all areas needed
for operation of safe shutdown equipment, and *in access and egress routes thereto.
Contrary to the above, emergency lighting units were not adequately provided in all
areas needed for operation of SSD equipment. In response this issue, the licensee
initiated CRs 2003008237 and 2003008179. Because the identified lack of emergency'
lighting is of very low safety signif icance and has been entered into the licensee's
corrective action program, this violation is being treated as an NCV, consistent with
Section VL.A of the NRC's Enforcement Policy: NCV 50-366/03-06-05, Inadequate
Emergency Lighting for Operation of. Post-Fire Safe Shutdown Equipment.
c
wit th
ecpion
08l
Cold: Shtdw R:.air
of the potential need for a cold shutdown repair to open valve 2E1 1 -F0l 5A (see Section
1 a05.05.b.2), the team identified no other need for cold shutdown repairs.
Consequently, this sectiongof IP 71111.05 was not performed.
09
Fire Barriers and Fire Area/Zone/Room Penetration Seals
a.
Inspection Scoude
The team reviewed the selected fire areas to evaluate the adequacy of the fire
resistance,
o firenarea barrier enclosure walls, ceilings,nfloors, fire barrier mechanical
and electrical penetration seals, fire doors, and fire dampers. The team selected
several fire barrier features for detailed evaluation and inspection to verify proper
installation and qualification. This was accomplished by observing the material condition
and configuration of the installed fire barrier features, as well as construction details and
supporting fire endurance tests for the installed fire barrier features, to verify the as-built
configurations were qualified by appropriate fire endurance tests. The team also
reviewed the F-A to verify the fire loading used by the licensee to determine the fire
- -: .
reasis
edtance
rating of the fire barrier enclosures. The team also re iesud the icenstli
instructions for sliding fire doors, the design details for mechanicalnd elea ral
penetrations, the penetrationyseal database, Generic Letter
i6-10 evaluations, and
the fire protection penetration seal deviation analysis for the tedsn ical basis of fire
- barrier penetration seals to verify that the fire barrier installations met design
requirements and license commitments. In addition, the team r
wiewed
completed
e
16
- .
surveillance and maintenance procedures for selected fire barrier features to verify the,'
fire barriers were being adequately maintained.
.
.
'
The team evaluated the /dequacy of the fire resistance of fire barrier electrical raceway
- fire barrier system (ERq13S) enclosures for cable protection to satisfy the'applicabled-' '
separation and design requirements of 10 CFR 50, Appendix R, Section III.G.2..
Specifically, the team examined the.design drawings, construction details, installation
records, and supporting fire endurance tests for the ERFBS enclosures installed in Fire
Area 2104, the Unit 2 East Cableway. Visual inspections of the enclosures were.'.
performed to confirm that the ERFBS Installations were consistent with the design -
drawings ad tested configurations.
The tea
reviewed abnormal operating fire procedures, selected fire fighting pre-plans,.
firedad
per location and detail drawings, and heating ventilation and air conditioning
-
_VA )~system drawings to verify that access to shutdown equipment and selected ' '
/
operator manual actions would not be inhibited by smoke migration from one area to,
adjacent plant areas used to accomplish SSD.
-
b.
Findings
-No findings of significance were Identified.
.10.
Fire Protection Systems. Features, and Eduipment
.
' -
a.
Insnection Scope
The team reviewed flow diagrams, cable routing information, and operational valve:
lineup procedures associated with the fire pumps and fire protection water supply
system. The review evaluated whether the common fire protection water delivery and
supply components could be damaged or inhibited by fire-induced failures of electrical
power supplies or control circuits. Using operating and test procedures, the team toured
the fire pump house and diesel-driven fire pump fuel storage tanks to observe the
system material condition, consistency of as-built'configurations with engineering
drawings, and determine correct system controls and valve lineups. Additionally, the
team reviewed periodic test procedures for the fire pumps to assess whether the'
surveillance test program was sufficient to verify proper operation of the fire protection.
water supply system in accordance with the program operating requirements specified-
in Appendix B of the FHA.
The team reviewed the adequacy of the fire detection systems in the selected plant fire
areas in accordance with the design requirements in Appendix R, III.G.1 and III.G. 2.
The team walked down accessible portions of the fire detection systems in the selected
fire areas to evaluate the engineering design and operation of the installed
configurations. The team also reviewed engineering drawings for fire detector types,
spacing, locations and the licensee's technical evaluation of the' detector locations for
the detection systems for consistency with the licensee's FHA, engineering evaluations
for NFPA code deviations, and NFPA 72E. In addition, the team reviewed surveillance
procedures and the detection system operating requirements specified in Appendix B of
17'
the FHA to determine the adequacy of fire detection component testing and to ensure
that the detection systems could function when needed.
The team performed in-plant walk-downs of the Unit 2 East Cable way automatic wet
pipe sprinkler suppression system to verify the proper type, placement and spacing of
the 'sprinkler heads as well as the lack of obstructions for effective functioning. The
team examined vendor information, engineering evaluations for NFPA code deviations,
and design calculations to verify that the required suppression system water density for
the protected area was available. Additionally, the team reviewed the physical
configuration of electrical raceways'and safe shutdown components in the fre rat
determine whether water from a pipe rupture, actuation of the automatic suppression
system, or manual fire suppression activities in this area could cauise damage that could
inhibit the plant's ability to SSD.
The team r9ewed the adequacy of the design 'and installation of the manual carbon
dioxide (Q92) hose reel suppression system for the diesel generator building switchgear
rooms 2E and 2F (Fire Areas 2404 and 2408). -The team performed in-plnt walk-
downs of the diesel generator building 002 fire suppression system to determine correct
system controls and valve lineups to assure accessibility and functionality of the system,.
as well as associated ventilation system fire dampers; The team also reviewed the'
licensee's actions to address the potential for 002 migration to ensure that fire
..suppression and post-fire SSD actions would not be impacted. This was accomplished
by the review of engineering drawings, schematics, flow diagrams, and evaluations
associated with the diesel generator building'floor drain system to determine whether
systems and operator actions required for SSD would be inhibited by 002 migration
through the floor drain system.
b.
Findings
Nofindings of significance were Identified.
11 Comp6rnsatorv Measures
a
Inspection Scone
The team reviewed Appendix B of the FHA and applicable sections of the FPP.
administrative procedure regarding administrative controls to Identify the need for and to
implement compensatory measures for out-of-service, degraded, or inoperable fire
protection or post-fire SSD equipment, features, and systems. The team reviewed
licensee reports for the fire protection status of Unit 1, Unit 2, and of shared structures,
systems, and components.. The review was performed to verify that the risk associated
with removing fire protection and/or post-fire systems or components, was properly
- -assessed
and implemented in accordance with the FPP. The team also reviewed CAP
- -CRs
generated over the last 18 months for fire protection features that were out of
service for long periods of time. The review was conducted to assess the licensee's
effectiveness in returning equipment to service in a reasonable period of time.
18
b.
Find*ings
-No findings of significance were identified.
1 R21 Safety System Design And Performance Capability
-..01
-Gesicnifte
-nRemest-fDCR)91-134, SRV Backup Actuation Via Pre
.
re
.
Transmitter Signals
a.
lnsnection Scope
The team performed an independent design review of plant modification DCR 91-134 In
order to evaluate the technical adequacy of the design change package. The scope of
the review and circuit analysis performed by the team was limited to the Group A SRVs
for which the licensee takes credit in mitigating a fire in the fire areas selected for the
inspection.'
.
-' ,>
!8
b.
Findings..
-
..............
, .
.;
- .
Introduction:
'An Inadequate plant modification, DCR 91-134, failed to implement the design input
requirements of one-out-of-two taken twice logic for the SRV's backup actuation using
pressure transmitter signals.
.
.
Description:
DCR 91-134 was implemented In response in to concerns raised in General Electric
-Report NEDC-3200P, Evaluation of SRV Performance during January-February 1991.
Turbine Trip Events for Plant Hatch Units 1 and 2. In order to ensure that individual'
SRVs will actuate at or near the appropriate set point and within allowable limits, a
backup mode of operation for the SRVs was implemented by this DCR. The design
Was intended to mitigate the effects of corrosion-induced set point drift of the Target
~Rock SRVs.-;
Automatically controlled, two stage SRVs are installed on the main steam lines inside
containment for the purpose of relieving nuclear boiler pressure either by normal
mechanical action or by automatic action of an electro-pneumatic control system. Each
SRV can be manually controlled by use of a two position switch located in the main
control room. When placed in the "Openw position, the switch energizes the pilot valve
of the individRVl SRV and causes it to go open. When the switch is placed in the
i
Aut
position thevSRV is opened upon r.ceipt of either an Automatic Depressurization
System (ADS), or Low-Low Set (LUS) control logic signal. Either signal will initiate
opening of the valve. DCR 91-134 provided a backup mode for initiation of electrical trip
of the pilot valve solenoid which was independent of ADS or LLS logic. The backup
mode required no operator action to initiate opening of the SRVs and was considered a
"blind control loop" to the operators, (i.e., there are no instruments that provide the
operators information concerning the open/close status of the SRVs.)
19
The scope of the plant modification involved the installation of four Rosemount pressure
transmitters (Model No. 1154GP9RJ), 0-3000 psig, in the 2H21-P404 and -P405
instrument racks at Elevation 158 of the reactor building. Each pressure transmitter
formed part of a 4 to 20 ma current loop and provided the analog trip signal for SRV
actuation within the following set point groups:
SRV GrouD
SRV Identification Tags
SRV Set Point
2B21-F013B, D, F, and G
1120 psig
.
.
.
B
2B21 -FO13A, C, K, and M
1130psig.. .
C4
2B21-FO13E, H, and L
1140 psig
Pressu e
ransmitters (PTs) 2B21-N127A and 2B21-N127C were wired to A
S
cabinet
11 -P927. Pressure transmitter 2B21 -N127A instrument loop components
consisted of a trip unit master relay K308C and trip unit slave relays K321 C and K332C.
The loop components for PT 2B21-N127C consisted of a trip unit master relay K335C In
addition to trip unit slave relays K336C and K363C. These two instrument loops
constituted a 'division" of pressure monitoring channels and were intended to provide
the None-out-of-two" logic signal from this division for initiating SRV backup actuation.
Additionally, PTs 2B21-N127B and 2B21-N127D were wired to ATTS cabinet'
2H11-P928. Pressure transmitter 2B21-N127B instrument loop components consisted
of a trip unit master relay K31 OD and trip unit slave relays KK312D and K332D.' The
loop components for PT 2B21-N127D consisted of a trip unit master relay K335D In
addition to trip unit slave relays K336D and K363D. These two instrument loops
constituted a separate "division' pressure monitoring channels and were'intended to
provide the "one-out-of-two' logic signal from this division for initiatingRV backup
actuation. The design objective of having two instrument channels ys to assure
compliance with HNP-2-FSAR, Section 15.1.6.1, Application otSin e Failure Criteria.
This criteria requires for anticipated operational occurrences (A'
that the protection
sequences within mitigation systems be -ing!e compmnent failure proof. A fa,!ure cf on
instrument channel in a division will therefore not eliminate the protection provided by
either of the instrument channels.
The following table identifies the division, PT loops and the associated trip unit master
and slave relays:
Division
A
PT LooDs
Tri, Unit Master Relays
Trip Unit Slave Relays
K321 C and K332C
K336C and K363C
2B21-N127C
' - K308C
' K335C
B
2B21 -N127B
2B21 -N127D
K31OD
K335D
K312D and K332D
K336D and K363D
The Group A SRVs were provided logic Input signals from the trip unit master relays.
The Group B and C SRVs were provided logic input signals from the trip unit slave
20
-
relays. The 12 relays described above, (6 in ATTS cabinet 2H1 1-P927 and 6 in ATTS
'.'
cabinet 2H1 1-P928), were intended to be wired to provide
one-out-of-two taken twice.
,ogic for actuation of the SRVs. The design objective was to assure that a single relay
failure in either division would not cause'an inadvertent SRV actuation. Coincident logic
, input is required from both division instrument loops in order to initiate a SRV backup
actuation using the pressure transmitter signals. This occurs when the circuit, used to.
energize the individual SRV pilot valve to open the SRV, is enabled by receiving
simultaneous logic inputs from either instrument loop in both divisions.
The team performed a circuit analysis of SRV 2821 -FO1 3F (Path 1) and SRV 2B21-
F01 3G (Path 2) in order to verify that the design objectives of implementing a one-out-
of-two taken twice' logic had been achieved. Based on this review the team determined
'that the design objective of implementing a 'one-out-of-two taken twice' logic had not
been installed for the SRVs. The logic installed for the SRVs was a two-out-of-two
taken twice' logic in addition to a "one-out-of-two taken twice' logic.
The coincident
logic implemented using trip unit master relays K31 OD and K335D could result In
spurious actuation of Group A SRVs for a' fire in Fire Area 2104. In addition this
spurious actuation defeats the capability to manually control these SRVs. Whenever a,
- SRV lifts, it will remain open until nuclear boiler pressure is reduced to about 85% of its
'
overpressure lift setpoint However, because the instrument loops have failed high, the
' trip unit master relays and the trip unit slave relays will continue to'energize the pilot
valve of the individual SRV and keep the SRV open. As a result, this failure. mode
-
prevents the operators from manually controlling the Group A SRVs as is required per
the SSAR.
-
Analysis: This finding Is greater than minor because it affected the a alabil
6
y7d
reliability objectives and the equipment performance attribute of t!j mitigating system
_
cornerstone. The team determined that the finding had potentiarsafety significanc
greater than very low safety significance because it prevent
he oper torslri
' manually controlling the Group A SRVs which the license
(a
mitigating a fire in
Fire Area 2104. Manual control of the-Grou'p A SRYS is
d to ensure that the
suppression pool temperature will not exceed the CT or the suppression pool.
F 'iure to ensure that the suppression pool temperaturc Will net cxcccd the HCTL could
result in loss of net positive suction head for the Core Spray pumps which the licensee
slang for mitigating this event. However, the finding remains unresolved pending
completion of a significance determination.
-
Enforcement: 10 CFR 50, Appendix B, Criterion Ill, requires that design control
,measures
shall provide for verifying or checking the adequacy of design.
DCR 91-134 specified design input requirements for the sensor initiated logic that
electrically activates the SRVs to be a 'one-out-of-two taken twice' logic scheme. It also
identified the potential worst case failure'mode of this logic modification as a short in the
, :
logic which would result In an inadvertent opening of a SRV. It concluded that the
modification was designed so that the actuation logic would not fail to cause inadvertent
opening of a SRV nor prevent a SRV from lifting upon ADS/LLS activation. Contrary to
the above, the logic implemented by the licensee for DCR 91-134 was different from the
specified design input requirements. The independent design verification performed for
DCR 91-134 failed to identify this error in the, logic scheme. Additionally, the Appendix
m I.,I
21
R Impact Review performed for DCR 91-134 failed to identify the potential failure mode
of all eleven SRVs because of fire-induced damage in Fire Area 2104.
Based on the logic input from tripunit master unit relays K31 OD, and K335D and their
associated trip, unit slave relays. The plant modification installed for DCR 91-134 failed'-'
to correctly implement the "one-out-of-two taken twice logic that was specified in the'."
SRV backup actuation via pressure transmitter signals design change package. This .
failure has created a condition where fire-induced failures of two reactor pressure'
instrument circuit cables, (within close proximity to each other), could result in spurious
,
actuation of all eleven SRVs with the eleven SRVs assuming a stuck open mode of.'..
operation. Pending completion of a significance determination by the NRC, this item Is
identified as URI 50-366/03-06-06, Inspector Concerns Associated with Implementation
of DCR 91-134.
4.
OTHER ACTIVITIES
40A2 Identification and Resolution of Problems
a.
Inspection Scope
-The team reviewed a sample of licensee audits, self-assessments, and CRs to verify,
- that items related to fire protection apd to SSD were appropriately entered into.the:
licensee's CAP in accordance with the Hatch quality assurance program and procedural,.'
requirements. The items selected were reviewed for classification and appropriateness'
of the corrective actions taken or initiated to resolve the issues. In addition, the team:'
reviewed the licensee's applicability evaluations and corrective actions for selected
'industry experience issues related to fire protection. The operating experience reports'-'
were reviewed to verify that the licensee's review and actions were appropriate.:,:
'
The team reviewed licensee audits and self-assessments of fire protection and safe.
shutdown to assess the types of findings that were generated and to verify that the
findings were appropriately entered Into the licensee's corrective action program.,
b.
Findings
No findings of significance were identified.
.
40A6 Meetings. Including Exit.
The lead inspector presented the in
etio results t licensee management and other
members of the licensee's staff at
e
r1clusion of he onsite inspection on July 25,
2003. Subsequent to the gns te
spectdn, the le
inspector and the Team Leader,'
Fire Protection, managl
11
ex
y telephone with Mr. S. Tipps and
other members of licensee
e
n August 29, 2003, to update the licensee on
changes to the preliminary inspection findings. The licensee acknowledged the findings.
SUPPLEMENTAL INFORMATION
.! s
.'
,..'..
- .
.. .. ..
.KEY
POINTS OF CONTACT
Licensee personnel:
-
M. Beard, Acting Engineering Support Supervisor
V. Coleman, Quality Assurance Supervisor
.-...:M. Dean, Nuclear Specialist, Fire Protection -.
R Dedrickson, Assistant General Manager for Plant hatch
.B. Duval, Chemistry.Superintendent
M Googe, Maintenance Manager
.
-
J. Hammonds, Operations Manager
D. Javorka, Administrative Assistant, Senior
R. King, Acting Engineering Support Manager
.I Luker, Senior Engineer, Licensing
T. Metzer, Acting Nuclear safety and Compliance Manager
'-.'::.
-. ' .'A. Owens, Senior Engineer, Fire Protection:.
'.' Parker, Senior Engineer, Electrical
J. Payne, Senior Engineer, Corrective Action Program:
J. Rathod, Bechtel'Engineering Group Supervisor
.'. .:.'M. Raiybon, Summer Intern .R'~
.. Rosanski, Oglethorpe Power Corporation Resident Manager
J. Vance, Senior Engineer, Mechanical & Civil
R. Varnadore, Outages and Modifications Manager.
-. .NRC Personnel:.
.
N. Garret, Senior Resident Inspector
C. Payne, Fire Protection Team Leader
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Obened
' .- 50-366/03-06-01
Concerns Associated with Potential Opening of S
' .
.
1
-R05.03.b)
50-366/03-06-02
Untimely and Unapproved Manual Operator.Actio
'.
SSD (Section 1 R04/05.b.1)
50-366/03-06-06
Inspector Concerns Associated with Implementati
- ' ... '
.
DCR 91 -134 (Section 1 R21.01.b)
Opened and Closed
.
RVs (Section
n for Post-Fire
on of
50-366/03-06-03
Inadequate Procedure for Local Manual Operator Action for Post-
Fire SSD Equipment (Section 1 R04/05.b.2)
Attachment
50-366/03-06-04
50-366/03-06-05
.
Discussed
None
NCV 1Unappro d Manual
erator Actions for Post-Fire'SSD'
(Sectiot1 1 R04.0
.3
. .
.
'
.
-
Inadequate Emergency Lighting for Operation of Post-Fire:SSD'--
Equipment. (Section 1 R05.07.b)
5 /
>
.~~~-' .
..
A
---
2--
.
- 2..A:\\
Attachment
.3
LIST OF DOCUMENTS REVIEWED
Procedures.
Administraive rcdr OCEG08OFr Protection Programn, Rev. 9.2
Adinist'ative Procedure 42FP-FPX-01 8-OS; Use, Control, and Storage of
Flammable/Combustible Materials, Rev. 1.0
Department Instruction DI-FPX-02-0693N, Fire Fighting Equipment Inspection, Rev.5
Fire Protection Procedure 42FP-FPX-005-OS, Drill Planning, Critiques and Drill Documentation.
Rev; 1 EDI
Fire Protection Procedure 42FP-FPX-007-OS, Hot0 Work, Rev. 1.2
Preventive Maintenance Procedure 52PM-ML02O LwVlaeSwitchgear Preventive
- Maintenance', Rev. 25.0'
Preventive Maintenance-Procedure 52PM-M EL-Ol14-0, Transformer Maintenance, Rev. 10.1
'Surveillance Procedure 423SV-FPX-002-OS, Low Pressure CO2 System Surveillance, Rev. 7.1
'Surveillance Procedure 425SV-FPX-004-OS, Fire Pump Test, Re'v. 8.6
Surveillane Procedure 42SV-FPX-006-OS, Fire Damper Surveillance, Rev. I ED 1
Surveillance Procedure 42SV-FPX-021 -OS, Surveillance of Swinging Fire Doors, Rev.-1.6'.'
Surveillance Procedure 42SV-FPX-024-OS, Fire Hose Stations 31 Day Surveillance, Rev. I
Surveillance Procedure 42SV-FPX-030-OS, Fire Emergency'Self Contained Breathing
Apparatus Inspection and Test, Rev. I
Surveillance Procedure 42S V-FPX-032-OS, Automatic Sliding Fire Door Visual Inspection,
..Rev.'3.3
Surveillance Procedure 423SV-FPX-036-08, Annual Fire Pump Cap acity Test, Rev. 8.6 .
.
Surveillance Procedure 42S V-FPX-037-OS, Fire Detection Instrumentation Surv'eillance,,
- Rev. 5.1
System Operating Procedure 34S0-X43-001-1, Fire Pumps Operating.Procedure, Rev.A4.3.
Training Procedure 73TR-TRN-.003-0S,.Fire Training Program, Rev.4
.
AOP 34AB-C 1-OO1 -2, Loss of CRD System, Version 2.3
~AOP 34AB-C71 -001-2, Scram Procedure, Version 9.9
~AOP 34AB-C71-002-2, Loss of RPS, Version 4.3.
AOP 34AB-N61-002-2S, Main Condenser Vacuum Low, Version 0.4
AOP 34A8%-P41-001-2, Loss of Plant Se.-ice Water, VIcrsion 8.1
- AOP 34AB-P42-001-2S, Loss of Reactor Building Closed Cooling Water, Version 1.4.
~AOP 34AB-P51 -001-2, Loss of Instrument and Service Air System or Water Intrusion Into the
Service Air System, Version 3.0
AOP 34AB-R22-001 -2, Loss of DC Busses, Version 2.4
~AOP 34AB-R22-002-2, Loss of 41 60V Emergency Bus, Version 1.4
AOP 34AB-R22-003-2, Station Blackout, Version 2.3
'AOP 34AB-R22-004-02, Loss of 41 60V Bus 2A, 2B, 2C, or 2D, Version 1.3
AOP 34AB-R23-001-2S, Loss of 600V Emergency Bus, Version 0.4-
AOP 34AB-R24-001 -2, Loss of Essential AC Distribution Buses, Version 1.3
AOP 34AB-R25-002-02, Loss of Instrument Buses, Version 5.4
AOP 34AB-T47-001-2, Complete Loss of Dsywell Cooling, Version 1'.8
AOP 34AB-X43-OO1-2, Fire Procedure, Version 10.8
AOP 34AB-X43-002-0, Fire Protection System Failures, Version 1.3
SOP 34S0-C71-001-2,1I20VAC RPS Supply System, Version 10.2
Attachment
.4
SOP 34SO-N40-001-2, Main Generator Operation, Version 10.8
-
SOP 34SO-R42-001-2S, 125V DC and 125/250 VDC System, Version 7.1
SOP 34SO-S22-001-2, 500 KV Substation Switching, Version 5.2
31 EO-EOP-01i0-2S, RC RPV Control (Non-ATWS), Rev. 8, Attachment 1
31 EO-EOP-01 2-2S, PC-1 Primary Containment Control, Rev. 4, Attachment 1i
31 EO-EOP-013-2S, PC-2 Primary Containment Control, Rev. 4, Attachment 1
31 EO-EOP-01 4-2S, SC - Secondary Containment Control, Rev. 6, Attachment I,-
31 EO-EOP-01 6-2S, CP-2 RPV Flooding, Rev. 8, Attachment I
Procedure 34AB-X43-001 -2S, Rev.1 OED3, 41Fire Procedure," dated 5/28/03.
Calibration Procedure 57CP-CAL-097-2, Rosemount 1153 and 1154 transmitters, Revision
No. 19.9.
Drawings
'
H-i 1814, Fire Hazards Analysis, Control Bldg. El. 1 30'-0", Rev. 5
H-1 1821, Fire Hazards Analysis, Turbine Bldg. El. 130'-0", Rev. 0
H-1 1846, Fire Hazards Analysis, Diesel Generator Bldg., Rev. 2
H-26014, R.H.R. System P&ID Sheet 1, Rev. 49
H-26015, R.H.R. System P&ID Sheet 2, Rev. 46
H-26018, Core Spray System P&ID, Rev. 29
B-1 0-1 326, Rectangular Fire Damper Schedule, Rev. 2
B-10-1329, Rectangular Fire Damper, Rev. I
H-1 1033, Fire Protection Pump House Layout, Rev. 47
H-1 1035, Fire Protection Piping and Instrumentation Diagram, Rev. 22
H-1 1226, Piping-Diesel Generator Building Drainage, Rev. 6
H-1 1824, Fire Hazards Analysis Drawing, Control Building, Rev. 1
H-1 1821, Fire Hazards Analysis Drawing, Turbine Building, Rev. 1
H- 1846, Fire Hazards Analysis Drawing,' Diesel Generator Building, Rev. 2
H-1 1894, Fire Detection Equipment Layout-Diesel Generator Building, Rev. 2
H-1 1915, Fire Detection Equipment Layout-Control Building, Rev. 2
H-13008, Conduit and Grounding, Fire Pump House, Rev. 9
H-13615, Wiring Diagram, Fire Pump House, Rev. 13
H-1 6054, Control Building HVAC System, Rev. 19
H-41509, Diesel Generator Building CO2 System-P&ID, Rev. 5
H-43757,-Penetration Seals-Type, Number, and as-Built Location, Rev. 3
Calculations. Analvses, and Evaluations
'E.'I. Hatch Nuclear Plant Units I and 2 Safe Shutdown Analysis Report, Rev. 20.
Edwin I. Hatch Nuclear Plant Fire Hazards Analysis and Fire Protection Program, Rev. 20
Calculation SMFP88-001, Hydraulic Analysis' of Sprinkler Systems in Control Building East
Cableway, dated 03/11/1988
Calculation SMNH94-046, FCF-F1OB-006, Fire Resistance of Concrete Block at HNP, dated
09/30/1994
Calculation SMNH94-048, FCF-F1 OB-006, Cable Tray Combustible Loading Calculation, dated
09/30/1994
Attachment
-,
5
" '
Calculation SMNH98-023, HT-98617, Fire Protection Penetration Seal Deviation Analysis
dated 10/28/1998
1
'.-
H
N
Ps
A1
date
.9108/2000
Calculation SMNHo0-01
0606, Hose Nozzle Pressure Drop Analysis, dated 09/08/2000.:'.
Evaluation HT-91722, Fire Protection Code Deviation Resolution, dated 04/22/1i992..'
Hatch Response to NRC IN 1999-005, dated 05/04/1999
'Hatch Response to NRC IN 2002-024, dated 09/20/2002
.
Calculation SENH 98-003, Rev. 0, plot K, protective relay settings 4kV bus 2E; '..
Calculation 85082MP, Plot 29, 600V Switchgear 2C
Calculation SENH 94-004, Attachment A, Sheets 7&8, 600/208 Reactor Building MCC 2C
Calculation SENH 91-011, Attachment P, Sheet 6, Reactor Building DC MCC 2A'...
Calculation SENH 94-013, Sheets 28 and 29, 600V Reactor Building MCC 2E-B"
Calculation SENH 91-011, Attachment P,. Sheet 16, Reactor Building 250VDC MCC 2B-.
' '
Audits and Self-Assessments
Audit No. 01-FP-1, Audit of the Fire Protection Program, dated April 12,2001
Audit No. 02-FP-1, Audit of the Fire Protection Program, dated February 28, 2002'.
Audit No. 03-FP-1, Audit of Fire Protection, dated April 21, 2003
1999-001106, Lighting in Fire Equipment Building
2002-000629, Inordinate Number of Buried Piping Leaks
2002-002127,InadequateBunkerGear'-'.:
2002-002129, Health Physics Support and Participation for Fire Brigade
2003-000735, Impact on Cold Weather on Operating Units
Audit Report 01-FP-1, Audit of Fire Protection Program, dated 04/12/2001
Audit Report 02-FP-1, Audit of Fire Protection Program, dated 02/28/2002
Audit Report 03-FP-1, Audit of Fire Protection Program, dated 04/21/2003
CRs Reviewed
CR 2000007119, Fire Procedure 34AB-X43-001-1 S Needs to be Enhanced,
CR 2001002032, Fire Procedure 34AB-X43-001 -2S Needs Actions for Diesel Fuel Oil Pumps
CR 2003004377, Fire Procedure 34AB-X43-001-1 Enhancements
'. .
CR 2003004379, Fire Procodure 34AB-X43-001-2 Enhancemonts
.
CR 2003004382, SSAR Discrepancies
.
CRs Generated During this Inspection
CR 2003007129, No Fire Procedure Actions for a Fire in the 2C Switchgear Room
CR 2003007719, Use of Link Wrench
.CR 2003007978, Fire Damper Corrective Action
CR 2003008141, Breaker Maintenance Handle
CR 2003008165, SSAR Section 2.100
CR 2003008179, Drywell Access Emergency Lights
CR 2003008181, Link Labeling
CR 2003008202, Manually Opening MOV 2E1 1 -F01 5A
CR 2003008203, SRV Manual Action Steps in Fire Procedure
CR 2003008237, Emergency Lights and Component Labeling for Manual Actions
Attachment
CR 2003008238, C02 Migration Through Floor Drains
CR 2003800132, SSAR Error for Position of 2E1 1 -FO04A '.
.
CR 2003800151, Instruments for Manual Actions
CR 2003800152, Sliding Links in SSAR
CR 2003800153, Promat Test Report
CR 2003008250, Communications for Post-Fire SSD
.
CR 2003800166, Review Fire Procedure Step 34AB-X43-001-2 Steps to Verify Compliance
with Appendix R.'
Design Criteria and Standards
Design Philosophy for Fire Detectors at E. I. Hatch Nuclear Plants, Rev. 2
.Completed Surveillance Procedures and Test Records
42SV-FPX-021 -OS, Surveillance of Swinging Fire Doors, Task # 1-3367-1 (completed on .
01/09/2003)
42SV-FPX-024-OS, Fire Hose Stations, Task # 1-3359-1 (completed on 06/27/2003)
42SV7FPX-030-OS, Fire Emergency Self Contained Breathing Apparatus Inspection and Test,
Task # 1-4200-3 (completed on'07/07/2003)
42SV-FPX-032-OS, Automatic Sliding Fire Door Surveillance, Task # 1-3361-2 (completed on
08/13/2002 .
Promatec Technologies Installation Inspection Report for Fire Area 2104, MWO 2-98-00881,
-Record 09367-2289, dated 09/03/1998
.
Technical ManualsNendor Information
..
- nic
..
./V
.r
,
-
'DowCorning Fire Endurance Test on Penetration Seal Systems in Precast Concrete F Using
Silicone Elastomers, dated.10/28/1975
Dow Corning 561 Silicone Transformer Fluid Technical Manual,10-453-97, dated 1997
S-80393, Mesker Instructions for Installing d&H TPyromatic" Automatic Sliding Fire Door Closer.-
S-27874B, General Electric Instruction Book GEK-26501, Liquid-Filled Secondary Unit
Substation Transformers, Rev. 2
S-52429A, Bisco, Fire Rated Penetration Seal Qualification Data, dated 08/16/1990
S-52480, Factory Mutual, Fire Rated Penetration Seal Qualification Data-Chemtrol Design
FC-225, dated 08/31/1990
S-54875B, Promatec, Fire Barriers-Unit 2 East Cableway, Rev. 2
Omega Point Laboratories, SR90-005, Three Hour Wall Test, dated 06/06/1990
'
Promatec Technologies Inc., PSI-001, Issue 1, General Construction Details, dated 07/21/1998
Promatec Technologies Inc., IP-2031, Installation Inspection for Promat's Three Hour Solid
WalVCeiling Protection System, Issue C, dated 06/16/1998
System Information Document No. Sl-LP-01401-03, Main Steam and Low Low Set System,
dated 4/3/2000
.
Attachment
7
ADDlicable Codes and Standards
ANSI N45.2.11-1974, Quality Assurance Requirements for the Design of Nuclear Power Plants
NFPA 12, Standard for Carbon Dioxide Systems, 1973 Edition.
NFPA 13, Standard for the Installation of. Sprinkler Systems, 1976 Edition.'.:'.'
NFPA 14, Standard for the Installation of Standpipe and Hose Systems, 1974 Edition'
NFPA 20, Standard for the Installation of Centrifugal Fire Pumps, 1973 Edition
NFPA 72D, Standard for the Installation, Maintenance, and Use of Proprietary Protection..
Signaling Systems, 1975 Edition.
NFPA 72E, Standard on Automatic Fire Detectors, 1974 Edition
NFPA 80, Standard on Fire Doors and Windows, 1975 Edition. -
NUREG-1 552, Supplement 1, Fire Barrier Penetration Seals in Nuclear Power Plants, dated
'January 1999
OSHA Standard 29 CFR 1910, Occupational Safety and Health Standards,..
-
Underwriters Laboratory, Fire Resistance Directory, January 1998
..
Other Documents
- ..Design Change Package 91-009, Retrofill Dielectric Fluid on Unit 2 Transformers, Rev 1
Fire Protection Inspection Reports for the period 2001-2002
.
.
Fire Service Qualification Training, FP-LP-1 0003, Fire Fighter Safety, dated 01/14/2002.:
Fire Service Qualification Training, FP-LP-1 0004, Fire Fighter Personal Protective Equipment,
dated 01/14/2002
Fire Service Qualification Training, FP-LP-1 0014, Fire Streams, dated 01/22/2002
Fire Service Qualification Training, FP-LP-10018, Fire Fighting Principles and Practices, date-d ..'.
01/22/2002
Hatch Response to NRC Information Notice 1999-05, Inadvertent Discharge of Carbon Dioxide;.
Fire Protection System and Gas Migration, dated 05/04/1999
Hatch Response to NRC Information Notice 2002-24, Potential Problems with Heat Collectors '
.'
on Fire Protection Sprinklers, dated 09/20/2002
1 OCFR21 -001, ELECTRAK Corporation, Software Error within TRAK2000 Cable Management."
and Appendix R Analysis System, dated 03/07/2003
U. S. Consumer Product Safety Commission, invensys Building Systems Anncunce P.RC-l'of
Siebe Actuators in Building Fire/Smoke Dampers, dated 10/02/2002
Pre-fire Plan A-43965, Power-Block Areas Methodology, Rev. 0'
Pre-fire Plan A-43966, Fire Area 2404, Diesel Generator Building Switchgear Room 2E, Rev. 2
Pre-fire Plan A-43966, Fire Area 2408, Diesel Generator Building Switchgear Room 2F, Rev. 2
Pre-fire Plan A-43965, Fire Area 2016, W 600V Switchgear Room 2C, Rev.4
'.
'License Basis Documents
Hatch UFSAR Section 3.4, Water Level Flood Design, Rev. 20 .
Hatch UFSAR Section 9.1-A, Fire Protection Plan, Rev. 18C
Hatch UFSAR Section 17.2, Quality Assurance During the Operations Phase, Rev. 20B
Hatch Fire Hazards Analysis, Appendix B, Fire Protection Equipment Operating and
Surveillance Requirements, Rev. 12B
Attachment
Hatch Fire Hazards Analysis, Appendix H, Application of National Fire Protection Association
Codes, Rev. 12B
Hatch SER dated April 18, 1994
-Safe Shutdown Analysis Report for E.I. Hatch Nuclear Plant Units 1 and 2, Rev. 26
Fire Hazards Analysis for E. l. Hatch Nuclear Plant Units 1 and 2, Rev.1 8C, dated 7/00.
NRC Safety Evaluation Report dated 01/02/1987; Re: Exemption from the requirements of
'-
.
-Appendix R to 10 CFR Part 50 for Hatch Units .1 and 2 (response to letter dated
May 16, 1986)..
Letter dated 05/16/86, From L. T. Guewa (Georgia Power) to D. Muller, NRC/NRR; Re: Edwin I
Hatch Nuclear Plant Units 1 and 2 1 0 CFR 50.48 and Appendix R Exemption Requests
Design Chanae Request Documents
DCR No.91-134, SRV Backup Actuation via Pressure Transmitter Signals, Revision 0.
'Drawing No. H-26000, Nuclear Boiler System P&ID, Sheet 1, Revision 39
Drawing No. H-27403, Automatic Depressurization System 2B21 C Elementary Diagram, Sheet
6 of 6, Revision 2
Drawing No. H-27472, Automatic Depressurization System 2B21 C Elementary Diagram, Sheet.
3 of 6, Revision 2-
Drawing No. H-27473, Automatic Depressurization System 2B21 C Elementary Diagram, Sheet
4 of 6, Revision 2
Drawing No. H-24427, Elementary Diagram, ATTS System 2A70 Sheet 27 of 35, Revision 3
.. Drawing No. H-24428, Elementary Diagram, ATTS System 2A70 Sheet 28 of 35, Revision 3
Drawing No. H-24429, Elementary Diagram, ATTS System 2A70 Sheet 29 of 35, Revision 5
Drawing No. H-24430, Elementary Diagram, ATTS System 2A70 Sheet 30 of 35, Revision 3
Drawing No. H-24431, Elementary Diagram, ATTS System 2A70 Sheet 31 of 35, Revision 3
-Drawing No. H-24432, Elementary Diagram, ATS System 2A70 Sheet 32 of 35, Revision 6
Attachment