ML050540514
| ML050540514 | |
| 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: ML050540514 (36) | |
See also: IR 05000321/2003006
Text
UNITED STATES
_, ,> NUCLEAR REGULATORY COMMISSION
IV4i1J X-REGION 11
SAM NUNN ATLANTA FEDERAL CENTER
61 FORSYTH STREET SW SUITE 23T85
ATLANTA, GEORGIA 30303-8931
Southern Nuclear Operating Company, Inc.'
ATTN: Mr. H. L. Sumner, Jr.
Vice President
P. 0. Box 1295
Birmingham, AL 35201-1295
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 report documents the
inspection findings, which were discussed on that date with Mr. R. Dedrickson and other
members of your staff.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissio 's rules and regulations and with the conditions of your license.
The inspectors reviewed selectid procedures and records, observed activities, and interviewed
personnel.
This report documents idings that h ve potential safety significance greater than very
low significance, howe ra afety sign ance determination has not been completed. One
issue involving a proce r inadequacY.id present an immediate safety concern, however,
your staff revised the procedure prior t Lthe end of the inspection. The other issue did not
present an immediate safety concern. In addition, the report 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 VL.A 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.: Document Control Desk, Washington DC 20555-0001; with copies to the
R gional Administrator Region II; the Director, Office of Enforcement, United States Nuclear
R gulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the
H4tch N clear Power Plant.
M4tlowing Completion of additional review in the Region II office, a final exit was held with
d other members of your staff on
SNC, Inc. 2
In accordance with 10 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.cov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
Charles R. Ogle, Chief
Engineering Branch 1
Division of Reactor Safety
Docket Nos.: 50-321, 50-366
-- License Nos.: DPR-57, NPF-5
Enclosure: NRC Triennial Fire Protection Inspection Report 5o0321/03-G6, ou-ooolO-06
w/Attachment: Supplemental Information J
C)5ooo 3.-&i/'2oo3 "4 hA J6 so
cc w/encl:
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
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)
SNC, Inc. 3
(cc w/encl cont'd)
Director
Department of Natural Resources
205 Butler Street, SE, Suite 1252
Atlanta, GA 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 1.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, Rll EICS
RIDSNRRDIPMLIPB
PUBLIC
OFFICE RII:DRS RII:DRS RII:DRS CONTRCTOR RII:DRP
SIGNATURE
NAME CSMITH RSCHIN GWISEMAN KSULLIVAN BONSER
DATE EV 120 8/ 10320003 12003 J3 W 12003 & 12003
E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO
PUBLIC DOCUMENT YES NO
Ut-t-K.JAL K~AJIEV UUJ- Ul)Uo NtA ffiA=..uxtng__ D._f
rIT 4fl BEnAD n -u~~m~p
OFFICIAL HEWL;HD L;Ut UL)UUMtN I NAMt: MRSEng Branch i match 2003-061irmpa
U. S. NUCLEAR REGULATORY COMMISSION
REGION 11
Docket Nos.: 50-321, 50-366
Report No.: 0500032 1/2003006 and 05000366/2003006
Licensee: Southern Nuclear Operating Company
Facility: E. I. Hatch Nuclear Plant
Location: P. O. Box 2010
Baxley, GA. 31513
Dates: July 7-11, 2003 (W ek)
July 21-25, 2003 eek 2)
Inspectors: C. Smi ,R. nior Reactor Inspector, (Lead Inspector)
R. Schi Reactor Inspector
G. Wiseman, re Protection Inspector
K. Sullivan, Consultant, Brookhaven National Laboratory
Accompanying S. Belcher, Nuclear Safety Intern, Week 1
Personnel:
Approved by: Charles R. Ogle, Chief
Engineering Branch 1
Division of Reactor Safety
Enclosure
1'.. .-
CONTENTS
SUMMARY OF FINDINGS .... ............... ..
REPORT DETAILS ...........................................................
FIRE PROTECTION ..........................................................
Systems Required to Achieve and Maintain Post-Fire Safe Shutdown ..............
Fire Protection of Safe Shutdown Capability .
Post-Fire Safe Shutdown Capability ........................................
Alternate Shutdown Capability/Operational Implementation of Alternative Shutdown
Capability..
- Communications.
Comncain .. ............................................................
Emergency Lighting .............................................
Cold Shutdown Repairs .:. ....
W4
Fire Barriers and Fire Area/Zone/Room Penetration Seals ..............
5
_j
Fire Protection Systems, Features, and Equipment .I. .
Compensatory Measures .......................................
SAFETY SYSTEM DESIGN AND PERFORMANCE CAPABILITY
Design Change Request 91-134, SRV Backup Actuation Using Pressure Transmitter
Signals ..............................................................
OTHER ACTIVITIES
Identification and Resolution of Problems ....................................
Meetings Including Exit ..................................................
.1.
SUMMARY OF FINDINGS
IR 05000321/2003-006, 05000366/2003-006; 7/7-11/2003 and 7/21-25/2 0. . 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
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 manual operator action, to
prevent spurious opening of all eleven safety relief valves (SRVs) 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 spurio s operation of the SRVs could
result in them opening during certain fire scenarios hereby complicating the post-fire
recovery actions. (Section 1R05.04/.05.b.1
Green. The team identified non-cited violation of 10 CFR 50, Appendix R,
Section III.G.1 and Technical Specification (TS) 5.4.1 because a local manual operator
action to operate safe shutdown equipment was 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 Ii ensee would
have time to develop and implement cold shutdown repairs to facilitate a complishment
of the action
sagfty i 4 . (Section 1R05.04/.05.b.2)
I
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 reaso ably be accomplished by operators in a
timely manner, this finding did not have pot ntial safety significance greater than very
low safety significance. (Section 1R05.0 5.b.3)
S 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 th use of flashlights, this finding
did not have potential safety significance greater t an v low safety significance.
(Section 1R05.07.b) an,0 $(it fs
tea rdentif'iekd ur'eeeFved item in connection with the implementation of
s agn
nge guest (go)91-134, 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.
This finding is unresolved pending completion of a significance determination. This
finding is greater than minor because it impacts the mitigating system cornerstone. This
finding has the potential for defeating manual control of Group A SRVs that are required
for ensuring that the suppression pool temperature will not exceed the heat capacity
temperature limit (HCTL) for the suppression poo (Section 1R21.01.b)
LI^1^4n{;;A
I;^lt;t^IU lii It{ VsIU U I0 / - I- e&4A
D. D. LILtenseet-IUtenlInec VlolalcxnIs1
None --
a^& OA
REPORT DETAILS
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems and Barrier Integrity.
1R05 Fire Protection
The purpose of this inspection was to review the Hatch Nuclear Plant fire protection
program (FPP) for selected risk-significant fire areas. 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 Branch
Technical Position (BTP) Auxiliary and Power Conversion Systems Branch (APCSB)
9.5-1; related NRC Safety Evaluation Reports (SERs); the Hatch Nuclear Plant Updated
Final Safety Analysis Report (UFSAR); and plant TS. 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 (SSAR) 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:
I I
2
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.
- 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 cal manual operator actions are consistent with the plant's
fire prote ion licensing basis.
-b. Findings
The team ideWified a potential concern in that the licensee used manual actions to
disconnect rminal board sliding links in order to isolate two 4 to 20 milli-amp (ma)
instrume ation loop control circuits in order to prevent the spurious actuation of eleven
- SRVs. his issue is discussed in section 1R05.03.b of the report. No other findings of
significance were identified.
.02 Fire Protection of SSD Capability
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 Il.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:
- Updated Final Safety Analysis Report (UFSAR) Section 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 fire prevention and combustible hazards control procedures. In
addition, the team reviewed the licensee's fire safety inspection reports and corrective
action program (CAP) condition reports (CRs) resulting from fire, smoke, sparks, arcing,
3
and overheating incidents for the years 2000-2002 to assess the effectiveness of the fire
prevention program 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
program 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 reviewed to evaluate equipment accessibility and
functionality. Additionally, the team observed whether emergency exit lighting was
provided for personnel evacuation pathways to the outside exits as identified in the
National Fire Protection Association (NFPA) 101, Life Safety Code, and the
Occupational Safety and Health Administration (OSHA) Part 1910, Occupational Safety
and Health Standards. This review also included examination of whether backup
emergency lighting was provided for access pathways to and within the fire brigade
equipment storage areas and dress-out locker areas in support of fire brigade
operations should power fail during a fire emergency. The fire brigade self-contained
breathing apparatuses (SCBAs) were reviewed for adequacy as well as the availability
of supplemental breathing air tanks and their refill capability.
The team reviewed fire fighting pre-fire plans for the selected areas to determine if
appropriate information 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 associated pre-fire plans and drawings with
as-built plant conditions. This was done to verify that fire fighting pre-f ire plans and
drawings were consistent with the fire protection features and potential fire conditions
described in the Fire Hazards Analysis (FHA).
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
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.
11
4
.03 Post-Fire SSD Capability
a. 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 associated with SSD Path 1 and Path 2 components of the
reactor core isolation cooling (RCIC) and high pressure coolant injection (HPCI)
systems. Additionally, on a sample basis, the team reviewed the licensee's analysis of
electrical protective device (e.g., circuit breaker, fuse, relay) coordination. The following
motor operated valves (MOVs) and other. components were reviewed:
Component ID DescriDtion
2E51 -F029 RCIC Pump Suction from Suppression Pool Valve
2E51--F010 RCIC Pump Suction Valve from Condensate Storage Ta (CST)
2P41 -CO01A Plant Service Water Pump 2A
2E11-FO11A Residual Heat Removal (RHR) Heat Exchanger A Drain to
Suppression Pool Valve
2P41-CO01 B Plant Service Water Pump 2B
2E41 -F001 HPCI Turbine Steam Supply Valve
2E41 -F002 HPCI Turbine Steam Supply Inboard Containment Isolation Valve
2E41 -F006 HPCI Pump Inboard Discharge Valve
2E41 -F008 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 10 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: ABE01 9C08 and ABE01 9C09. Each circuit separately provides a 4 to 20 ma
5
instrumentation signal from an SRV high-pressure actuation transmitter 2B or
7-137
21321-N1 27D to its respective master trip unit (21321 -N697B3 or 2B21 -N697) The
purpose of this circuitry was to provide an electrical backup to the mech ial trip
capability of the individual SRVs. In the event of high reactor pressure, tecircuits
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
cause all eleven SRVs to open. The conductor insulation and jacket material of each
cable was cross-linked polyethylene (XLPE). 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 same 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-P927eand link BB-10 in panel 2H11-P928. These panels are
located in the main control ro vn. Opening of these links would prevent actuation of the
SRV trip units by removing t 4 to 20 ma signal fed by the pressure transmitters to the
master trip units. In the eve t the SRVs were to open prior to the operators completing
this action, the SSAR ore spray loop A to 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.
6
2. The use of links to avoid inadvertent actuation of the SRVs did not appear to be
consistent with the current licensing basis.
.3. No objective evidence 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 1R05.04/.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 exemption dated May 16, 1986, and a
subsequent NRC Safety Evaluation Report (SER) dated January 2, 1987, 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 III.G. The inspectors concluded that, the opening
of links was considered a repair by both the licensee and the NRC staff in 1987. The
licensee could not provide any evidence to justify why these actions should not by
characterized as a repair activity in its current SSAR.
Additionally, because there is a potential for all SRVs to spuriously actuate esult of
fire in Fire Area 2104 at a time when RHR is not available, the SSAR sathe use of
core spray loop A to accomplish the reactor coolant makeup function. During the
inspection, the licensee performed a simulator exercise of an event which caused all 11
SRVs to open. During this exercise, simulator RPV level instruments indicated that core
spray would be capable of maintaining level above the top of active fuel. However, the
licensee did not provide any objective evidence (e.g., specific calculation or analysis)
which demonstrated that, assuming worst-case fire damage in Fire Area 2104, the
limited set of equipment available would be capable of mitigating the event in a manner
that satisfied the shutdown performance goals specified in 10 CFR 50 Appendix R,
Section IlI.L.1.e.
Finally, the logic that was installed by DCR 91-134 for the SRVs was a two-out-of-two
coincidence taken twice" logic in addition to a one-out-of-two coincidence taken twice
logic. The team determined that the two-out-of-two coincidence logic input from trip
unit master relays K31OD and K335D represented a common cause failure for Group A
SRVs for a fire in Fire Area 2104. Specifically, cable ABE01 9C08 associated with
pressure transmitter 2B21-N127B current loop, and cable ABEO19CO9 associated with
- *. .c
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 Section IR21.01. Ultimately, this failure mode would prevent the
operators from manually controlling the Group 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 exemption from Appendix R is required. Pending additional review by the NRC, this
issue is identified as URI 50-366/03-06-01, Concerns Associated with Potential Opening
of SRVs.
.04/.05 Alternate Shutdown Capability/Operational Implementation of Alternative Shutdown
'"'I1'-I .' Capability
a.' Inspection Scone
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 and
alternative safe shutdown from outside of the control room. Thus, alternate shutdown
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.
The team walked down SSD manual operator actions that were to be performed outside
of the control area of the main control room for a fire in the selected fire areas and
discussed them with operators. These actions were documented in Abnormal Operating
Procedure (AOP) 34AB-X43-001-2, Version 10.8, dated May 28, 2003. The team
evaluated whether the local manual operator actions could 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 t em reviewed'
records of actual operator staffing on selected days.
b. Findings
1. Untimely and Unaggroved Manual Oerator Action for Fire D
Introduction: The team found that a local manual operaor action to prevent spurious
opening of all eleven SRVs would not be performed' sufficient time to be effective.
Licensee reliance on this manual action for hot shtdown during a fire, instead of
physically protecting cables from fire damaged not been approved by the NR
Description: The team noted that Step 9.3.2 of AOP 34AB-X43-001-2, Fir
Procedure, Version 10.8, dated May 28, 20 3, stated: 'To prevent all elev n SRVs from
opening simultaneously, open links BB-1O n Panel 2H1 -P927 and BB- in Panel
2H1 l-P928." The team noted that spurius opening of all eleven SRV should be
considered a large loss of coolant accid nt (LOCA), and that a LOCA e prevented from-
occurring during a fire event. Specificoy, to comply with 10 CFR 50, Appendix R,. ;
Section III.L. Section lll.L requires th , during a post-fire shutdown, the reactor coolant
system process variables (e.g., react vessel water level) shall be maintained within
those predicted for a loss of normal . 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 from causing all eleven SRVs to spuriously open.,
The licensee had no preplanned estimate of how long it would take operators to
complete this step during a fire event. There was no event time line or operator training
job performance measure (JPM) 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 take 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 1R05.07.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
I
) A
9
protecting the cables as required by 10 CFR 50, Appendix R,Section lll.G.2, had not-'
been approved by the NRC.
The licensee stated that cable damage to two reactor pressure instrument cables, would'
be needed to spuriously open all eleven SRVs. Because the licensee stated that the ' '
two cables were in the same cableItray in Fire Area 2104, the team considered that a -
fire in that area could potentially cause all eleven SRVs to spuriously open (see section;'
1R21.01 .b).
In response to this issue, the licensee initiated CR 2003008203 and promptly revised
the Fire Procedure before the end of the inspection, moving the actions of Step 9.3.2.1
to the beginning of the procedure. The procedure change enabled the actions to be.,
accomplished much sooner during a fire in the Unit 2 east cableway or in other fire
areas that were vulnerable to the potential for spuriously opening all eleven SRVs. The
team determined that this issue is related to associated circuits. As described in NRC
Inspection Procedure (IP)71111.05, Fire Protection, inspection of associated circuits is
temporarily limited. Consequently, the team did not pursue the cable routing or circuit
analysis that would be necessary to evaluate the possibilit, risk, or potential safety
significance of Group B and C SRVs spuriously ope g ue to fire damage to the
instrument cables. The team did, however, perf ra ci cuit analysis of Group A SRVs
for which the licensee takes credit during a fire i a 2104. (See Section.'.
1R21.01.)
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 Il.G.2 requires that where 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 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.
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 completion of a significance
determination by the NRC. This issue is identified as URI 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 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 I -F01 5A 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 1R05.07). 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 2E1 1-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 operat6rs 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
1.
operator, stated that he had manually operated the valve in the past, but that it had been
very difficult for him.
The team judged that, since this action was not required to maintain hot shutdown but
only required for cold 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 depth elements. Hence, this finding
did not have potential safety significance greater than very low safety significance .
(Green).
Enforcement: 10 CFR 50, Appendix R, Section III.G.1 requires that fire protection
features shall be provided for systems important to safe shutdown and shall be capable
of limiting fire damage so that systems necessary to achieve and maintain cold
shutdown from either the control room 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, TS 5.4.1 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 2E1 1-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 necessary 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 -FO15A 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 perform
them because the required actions were too difficult and also were unsafe. In response
to this issue, the licensee initiated CR 203008202. Because the identified inadequate
operate-aties are of very low safety significance and the issue 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 50-366/03-06-03,
Inadequate Procedure for Local Manual Operator Action for Post-Fire Safe Shutdown
Equipment.
12
3. Unap~proved 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.
- Descrio~tion: The team observed that AOP 34AB-X43-001-2, Fire Procedure, included
some local manual operator actions to achieve and main tain hot shutdown that had not
been approved by the NRC. Examples of steps from the procedure included:
- Step 4.15.2.2; ... If a loss of offsite power occurss and emergency busses
energize ... "Place Station Service battery charger s 2R42-S026 (2R42-S029),
21R42-S027 (2R342-S030) AND 21R42-S028 (21R42. -S031) in service per 34SO-
R42-001-2."
following links to energize 2E41 -Fl124, Trip Solen :)id Valve, AND to fail 2E41-.
- - .
- 4-1 . -,fr-. --
F3025 HPCI Governor -
Valve,
4,
in
- 4,
thei CLOSED - -
pos-
sition:
TT-75 in panel 2H1-1-P601.
TT-7 in panel 2H -P601
Step 4.1 5.4.6; ...If HPCI fails to automatically trip on high RPV level... OPEN
breaker 25 in panel 21r25-S002 to fail 2E41P-F305: 2, HPCI Governor Valve, in the
CLOSED positiong o
The team walked down these actions usin the guidance contained in Inspection
rF I U UU I II I I VO I CIIU JUU!fUU LI 10.1 I lY %.UUIU I a a.VIIaLJIY LUUai.,%.,uIi Ij.JIIyi IU DIs
y
'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 than minor because it affected the availability and
reliability objectives as well as 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.
Enforcement: 10 CFR 50, Appendix R, Section Ill.G.2 requires that where cables or
equipment, including associated non-safety circuits that could 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.
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.,,
.06 Communications
a. Inspection Scope
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.
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 III.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 were
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
t .
. . . I 14
equipment. Examples included the following operator actions in procedure 34AB-X43-
I:; 001-2, Fire Procedure, Version 10.8, dated May 28, 2003:
. -. 1 ." *. Step 4.15.2.2; ...if a loss of offsite power occurs and emergency busses energize
7. , : _- ..."Place Station Service battery chargers 2R42-S026 (2R42-S029), 2R42-S027
(2R42-S030) AND 2R42-S028 (2R42-S031) in service per 34SO-R42-001-2."
following links to energize 2E41 -F1 24, Trip Solenoid Valve, AND to fail 2E41-
F3025 HPCI Governor Valve, in the CLOSED position:
TT-75 in panel 2H11-P601
- TT-76 in panel 2H11-P601"
- Step 4.15.5; 'IF2R25-S065, Instrument Bus 2B, is DE-ENERGIZED perform the
following manual actions to maintain 2C32-R655, Reactor Water Level
I Instrument, operable: - -
- 4.15.5.1;Atpanel2H1 -P612, OPEN linksAAA-11 andAAA-12.
- 4.15.5.2; At panel 2H1 1-P601, CLOSE links HH-48 and HH-49.0
- Steps 4.15.8.1.1 and 9.3.5.1; "Manually OPEN 2E11-FO15A, Inboard LPCI
Injection Valve, as required."
- Steps 4.15.8.1.2 and 9.3.5.2; "Manually CLOSE 2E11 -F018A, 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 2H11 -P627, open links AA-19, AA-20, AA-21, and AA-22,
to prevent spurious actuation of SRVs 2B21-FO13D AND 2B21-FO13G."
- Step 9.3.6; 'OPEN link TB9-21 in Panel 2H1 -P700 to open Drywell Pneumatic
System Inboard Inlet Isolation, 2P70-F005."
- Step 9.3.7; "OPEN link TB1-12 in Panel 2H1 1-P700 to open Drywell Pneumatic
System Outboard Inlet Isolation, 2P70-F005."
- Step 9.3.9.1; "Confirm OR manually CLOSE RHR Shutdown Cooling Valve
2E1 1-F006D.:
- 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
1R05.04/.05.b.1). The other exception was the action to open 2E11 -FO15A, which was
judged to be too difficult (see Section 1R05.04/.05.b.2). For both of these actions, the
15
lack of adequate emergency lighting could make the actions more 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 attribute 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
significance (Green)..
Enforcement: 10 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 theabove, emergency lighting units were not adequately provided in all
areas needed for operation of SSID equipment. In response this issue, the licensee
- initiated CRs 2003008237 and 2003008179. Because the identified lack of emergency
- lighting is of 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 VI.A of the NRC's Enforcement Policy: NCV 50-366/03-06-05, Inadequate
Emergency Lighting for Operation of Post-Fire Safe Shutdown Equipment.
.08 Cold Shutdown Repairs
The licensee had identified no needed cold shutdown repairs. Also, with the exception
of the potential need for a cold shutdown repair to open valve 2E11 1-F15A(e eto
1R05.05.b.2), the team identified no other need for cold shutdown repairs.
Consequently, this section of IP 71111.05 was not performed.
.09 Fire Barriers and Fire Area/Zone/Roomn Penetration Seals
a. Inspection Sco'e
The team reviewed the selected fire areas to evaluate the adequacy of the fire
resistance of fire area barrier enclosure walls, ceilings, floors, 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 FHA to verify the fire loading used by the licensee to determine the fire
resistance rating of the fire barrier enclosures. The team also reviewed the installation
instructions for sliding fire doors, the design details for mechanical and electrical
penetrations, the penetration seal database, Generic Letter (GL) 86-10 evaluations, and
the fire protection penetration seal deviation analysis for the technical basis of fire
barrier penetration seals to verify that the fire barrier installations met design
requirements and license commitments. In addition, the team reviewed completed
-I
16
surveillance and maintenance procedures for selected fire barrier features to verify the
fire barriers were being adequately maintained.
The team evaluated the adequacy of the fire resistance of fire barrier electrical raceway
fire barrier system (ERFBS) enclosures for cable protection to satisfy the applicable'.
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 and tested configurations.
The team reviewed abnormal operating fire procedures, selected fire fighting pre-plans,
fire damper location and detail drawings, and heating ventilation and air conditioning
(HVAC) 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 Equipment
a. Inspection 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 systemsi could function when needed.
The team performed in-plant walk-downs of the Unit 2 East Cableway 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 fire area to
- determine whether water from a pipe rupture, actuation of,the automatic suppression
t. system, or manual fire suppression activities in this area could cause damage that could
- inhibit the plant's ability to SSD.
...
The team reviewed the adequacy of the design and installation of the manual carbon
dioxide (C02) hose reel suppression system for the diesel generator building switchgear
rooms 2E and 2F (Fire Areas 2404 and 2408). The team performed in-plant walk-
downs of the diesel generator building C02 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 C02 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 C02 migration
',;' through the floor drain system.
b. Findings
No findings of significance were identified..
.11 Com rensatorv Measures
a. Inspection Scope
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. Findings
No findings of significance were identified.
I R21 Safety System Design And Performance Capability
.01 Design Change Request (OCR)91-134. SRV Backup Actuation Via Pressure
Transmitter Sianals
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
pressure transmitter signals.
Description:
DCR 91-134 was implemented in response in to concerns raised in General Ele nc
Report NEDC-3200P, Evaluation of SRV Performance during January-Febru y 1991
Turbine Trip Events for Plant Hatch Units 1 and 2. In order to ensure that i dividual
SRVs will actuate at or near the appropriate set point and within allowabl imits, a
backup mode of operation for the SRVs was implemented by this DCR. he 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 individual SRV and causes it to go open. When the switch is placed in the 'Auto"
position the SRV is opened upon receipt of either an Automatic Depressurization
System (ADS), 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.)
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 Group SRV Identification Taps SRV Set Point
A 2B21-FO13B, D, F, and G 1120 psig
B 2B21-FO13A, C, K, and M 1130 psig
C 2121-FO13E, H, and L 1140 psig'
Pressure transmitters (PTs) 2321 -N127A and 2121 -N127C were wired to ATTS
cabinets 2H11-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 2121 -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 "one-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
2H1-1-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 initiating SRV backup
actuation. The design objective of having two instrument channels was to assure
compliance with HNP-2-FSAR, Section 15.1.6.1, Application of Single Failure Criteria.
This criteria requires for anticipated operational occurrences (AOOs) that the protection
sequences within mitigation systems be single component failure proof. A failure of one
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 PT Loons Trip Unit Master Relays Trip Unit Slave Relays
A 2821 -N127A K308C K321 C and K332C
2B21-Ni27C K335C K336C and K363C
B 2B21-N127B K31 OD K312D and K332D
2B21 -N127D -K335D 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"
logic 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 2B21-FO13F (Path 1) and SRV 2B21- -
FO13G (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 K31OD 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 require er
the SSAR. -
Analysis: This finding is greater than minor because it affected the avail and
reliability objectives and the equipment performance attribute of the Igating system
cornerstone. The team determined that the finding had potential s ety significance
greater than very low safety significance because it prevented th operators from
manually controlling the Group A SRVs which the licensee with mitigating a fire in
Fire Area 2104. Manual control of the Group A SRVs is required to ensure that the
suppression pool temperature will not exceed the HCTL for the suppression pool.
Failure to ensure that the suppression pool temperature will not exceed 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 91-1 34 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
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 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 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 inspe *n result to licensee management and other
members of the licensee's staff at t conclusion df the onsite inspection on July 25,
2003. Subsequent to the onsite in ection, th lefd inspector and the Team Leader,
Fire Protection, manag=ent held/follow-up exi~by telephone with Mr. S. Tipps and
other members of licensee management on August 29, 2003, to update the licensee on
changes to the preliminary inspection findings. The licensee acknowledged the findings.
r Act e
- - ; t b: :
- jl. . riP f : b
- 's f S-
- S;t At
. :. ' . ' ! .,
.
.
....
. .
..
SUPPLEMENTAL INFORMATION
- . . .
.. . .
- ' ,j, ' .
- ,, t . . ...
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
D. Parker, Senior Engineer, Electrical
J. Payne, Senior Engineer, Corrective Action Program
J. Rathod, Bechtel Engineering Group Supervisor
M. Raybon, Summer Intemr
K. 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
Onened
50-366/03-06-01 URI Concerns Associated with Potential Opening of S s(
1R05.03.b)
50-366/03-06-02 URI Untimely and Unapp oved Manual Oper Action for I ire
SSD (Section 1 5.b.1)
50-366/03-06-06 URI Inspector Concerns Associated with Implementation of
DCR 91 -134 (Section 1R21.01.b)
Opened and Closed.
50-366/03-06-03 NCV Inadequate Procedure for Local Mar for Post-
Fire SSD Equipment (Section 1FR04)
Attachment
- .
50-366/03-06-04 NCV Unappr ed Ma s for Post-Fire SSD
50-366/03-06-05 NCV Inadequate Emergency Lighting for Operation of Post-Fire SSD
Equipment (Section 1R05.07.b) :
Discussed
None
Attachment
t.
3
LIST OF DOCUMENTS REVIEWED
Procedures
Administrative Procedure 40AC-ENG-008-OS, Fire Protection Program, Rev. 9.2
Administrative 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, Hot Work, Rev. 1.2
Preventive Maintenance Procedure 52PM-MEL-012-0, Low Voltage Switchgear Preventive
Maintenance, Rev. 25.0
Preventive Maintenance Procedure 52PM-MEL-014-0, Transformer Maintenance, Rev. 10.1
Surveillance Procedure 42SV-FPX-002-OS, Low Pressure CO2 System Surveillance, Rev. 7.1
Surveillance Procedure 42SV-FPX-004-OS, Fire Pump Test, Rev. 8.6
Surveillance Procedure 42SV-FPX-006-OS, Fire Damper Surveillance, Rev. 1 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. 1
Surveillance Procedure 42SV-FPX-030-OS, Fire Emergency Self Contained Breathing
Apparatus Inspection and Test, Rev.1
Surveillance Procedure 42SV-FPX-032-OS, Automatic Sliding Fire Door Visual Inspection,
Rev. 3.3
Surveillance Procedure 42SV-FPX-036-OS, Annual Fire Pump Capacity Test, Rev. 8.6
Surveillance Procedure 42SV-FPX-037-OS, Fire Detection Instrumentation Surveillance,
Rev. 5.1.
System Operating Procedure 34SO-X43-001-1, Fire Pumps Operating Procedure, Rev. 4.3
Training Procedure 73TR-TRN-003-OS, Fire Training Program, Rev.4
AOP 34AB-Cl 1-001-2, 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 34AB-P41-001-2, Loss of Plant Service Water, Version 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 4160V Emergency Bus, Version 1.4
AOP 34AB-R22-003-2, Station Blackout, Version 2.3
AOP 34AB-R22-004-02, Loss of 4160V 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 Drywell Cooling, Version 1.8
AOP 34AB-X43-001-2, Fire Procedure, Version 10.8
AOP 34AB-X43-002-0, Fire Protection System Failures, Version 1.3
SOP 34SO-C71-001-2,120VAC 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-01 0-2S, RC RPV Control (Non-ATWS), Rev. 8, Attachment 1
31 EO-EOP-012-2S, PC-1 Primary Containment Control, Rev. 4, Attachment 1
31 EO-EOP-01 3-2S, PC-2 Primary Containment Control, Rev. 4, Attachment i;
31 EO-EOP-014-2S, SC - Secondary Containment Control, Rev. 6, Attachment 1
31 EO-EOP-01 6-2S, CP-2 RPV Flooding, Rev. 8, Attachment 1
Procedure 34AB-X43-001 -2S, Rev.1 OED3, "Fire Procedure," dated 5/28103.
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. 130'-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-10-1 326, Rectangular Fire Damper Schedule, Rev. 2
B-10-1329, Rectangular Fire Damper, Rev. :
H-11033, Fire Protection Pump House Layout, Rev. 47
H-11035, Fire Protection Piping and Instrumentation Diagram, Rev. 22
H-1 1226, Piping-Diesel Generator Building Drainage, Rev. 6
H-11814, Fire Hazards Analysis Drawing, Control Building, Rev. 5
H-1 1821, Fire Hazards Analysis Drawing, Turbine Building, Rev. 11
H-1 1846, Fire Hazards Analysis Drawing, Diesel Generator Building, Rev. 2
H-1 1894, Fire Detection Equipment Layout-Diesel Generator Building, Rev. 2
H-11915, 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-16054, Control Building HVAC System, Rev. 19
H-41509, Diesel Generator Building CO 2 System-P&ID, Rev. 5
H-43757, Penetration Seals-Type, Number, and as-Built Location, Rev. 3
Calculations. Analyses. and Evaluations
E. l. Hatch Nuclear Plant Units 1 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
- *W 5; s d i' t
- ,,¢.;,;-,;r we,- i, ,
- i i e r*n : s {4 i; W
' :N ; . .: \:
- . : f b :
.; He f
5
- Calculation SMNH98-023, HT-98617, Fire Protection Penetration Seal Deviation Analysis,
dated 10/28/1998
- Calculation SMNH0-01 1, HT-00606, Hose Nozzle Pressure Drop Analysis, dated 09/08/2000
Evaluation HT-91722, Fire Protection Code Deviation Resolution, dated 04/22/1992
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 25OVDC 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, Inadequate Bunker Gear
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 04/1212001
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 -IS 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 Procedure 34AB-X43-001-2 Enhancements
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 2E11 -F01 5A
CR 2003008203, SRV Manual Action Steps in Fire Procedure
CR 2003008237, Emergency Lights and Component Labeling for Manual Actions
Attachment
6
CR 2003008238, C02 Migraticon Through Floor Drains
CR 2003800132, SSAR Error I or Position of 2E1 1-F004A
CR 2003800151, Instruments I'or Manual Actions
CR 2003800152, Sliding Links in SSAR
CR 2003800153, Promat Test Report
CR 2003008250, Communicati tons for Post-Fire SSD
CR 2003800166, Review Fire IProcedure Step 34AB-X43-001-2 Steps to Verify Compliance
with Appendix R.
Design Criteria and Standards
Design Philosophy for Fire Det ectors 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)
42SV-FPX-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 Manuals/Vendor Information
Dow Corning 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,1 0-453-97, dated 1997
S-80393, Mesker Instructions for Installing d&H "Pyromatic" 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
Wall/Ceiling 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
'1
- 7
Applicable 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-1552, 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-10003, Fire Fighter Safety, dated 01/14/2002
Fire Service Qualification Training, FP-LP-10004, Fire Fighter Personal Protective Equipment,
dated 01/14/2002
Fire Service Qualification Training, FP-LP-10014, Fire Streams, dated 01/22/2002
Fire Service Qualification Training, FP-LP-1 001 8, Fire Fighting Principles and Practices, dated
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
1OCFR21 -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 Announce Recall of
Siebe Actuators in Building Fire/Smoke Dampers, dated 10/02/2002
Pre-f ire 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
'I
8
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 EL Hatch Nuclear Plant Units. and 2, Rev. 26
Fire Hazards Analysis for E. 1.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 05/1 6/86, From L. T. Guewa (Georgia Power) to D. Muller, NRC/NRR; Re: Edwin I
.- Hatch Nuclear Plant Units 1 and 2 10 CFR 50.48 and Appendix R Exemption Requests
Design Change Reguest 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 2B21C Elementary Diagram, Sheet
3 of 6, Revision 2
Drawing No. H-27473, Automatic Depressurization System 2B21C 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, ATTS System 2A70 Sheet 32 of 35, Revision 6
Attachment