ML040090431
| ML040090431 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 12/22/2003 |
| From: | Ogle C NRC/RGN-II |
| To: | Stall J Florida Power & Light Co |
| References | |
| FOIA/PA-2003-0358 IR-03-002 | |
| Download: ML040090431 (26) | |
See also: IR 05000335/2003002
Text
May XX, 2003
Florida Power and Light Company
ATTN:
Mr. J. A. Stall, Senior Vice President
Nuclear and Chief Nuclear Officer
P. 0. Box 14000
Juno Beach, FL 33408-0420
SUBJECT:
ST. LUCIE NUCLEAR PLANT - NRC TRIENNIAL FIRE PROTECTION
INSPECTION REPORT 50-335/03-02 AND 50-389/03-02
Dear Mr. Stall:
On March 28, 2003, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection
at your St. Lucie Nuclear Plant Units 1 and 2. The enclosed inspection report documents the
inspection findings, which were discussed on March 28, 2003, with Mr. D. Jernigan and other
members of your staff.
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 records, observed activities, and interviewed
personnel.
This report documents a finding concerning silicon oil filled transformers in the B Switchgear
Room which had not been considered or evaluated in the licensee's fire hazards analysis.
Additionally, a finding was identified concerning the crediting of manual operator actions outside
the main control room in lieu of physical protection of cables and equipment relied on to achieve
safe shutdown during a fire, without prior NRC approval, for areas designated as 10 CFR 50
Appendix R,Section III.G.2. These findings involved violations of NRC requirements. These
findings collectively have potential safety significance greater than very low significance.
However, a safety significance determination has not been completed. These findings did not
present an immediate safety concern. In addition, the report documents one NRC-identified
finding of very low safety significance (Green), which was determined to involve a violation of
NRC requirements. However, because of the very low safety significance and because it was
entered into your corrective action program, the NRC is treating this as a non-cited violation
(NCV) consistent with Section VL.A of the NRC Enforcement Policv. Additionaliv. two lii6nsee
identified violations which were determijed to e 'of very low safety sinif icance a' listed in this
report. 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
Regional Administrator Region II; the Director, Office of Enforcement, United States Nuclear
Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at St.
Lucie Nuclear Plant.
II
2
In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter and its
enclosure, and your response (if any) will be available electronically for public inspection in the
NRC Public Document Room or from the Publicly Available Records (PARS) component of
NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at
httD://www.nrc.gov/readinc-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
Charles R. Ogle, Chief
Engineering Branch 1
Division of Reactor Safety
Docket Nos. 50-335, 50-389
Enclosure: Inspection Report 50-335, 389/03-02
w/Attachment: Supplemental Information
cc w/encl: (See page 3)
SUMMARY OF FINDINGS
IR 05000335/2003-002, 05000389/2003-002; Florida Power and Light Company; 03/10 -
28/2003; St. Lucie Nuclear Plant, Units 1 and 2; Triennial Fire Protection.
The report covered a two-week period of inspection by regional inspectors and a consultant.
Three Green non-cited violations (NCVs) and one unresolved item 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 Determinati6n 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 1649, "Reactor Oversight Process," Revision 3, dated July 2000.
A.
NRC-Identified and Self-Revealing Findings
Cornerstone: Initiating Events
TBD. The team identified a violation of 10 CFR 50.48 and the St. Lucie Nuclear
Plant' (PSL) Unit 2 Operating License Condition (OLC) 2.C.(20), Fire Protection.
The fire hazards analysis (FHA) failed to consider and evaluate the combustibility
of 380 gallons of transformer silicone dielectric insulating fluid in each of six
transformers (installed in three Unit 2 fire areas) as contributors to fire loading
and effects on safe shutdown (SSD) capability, as required by Fire Protection
Program (FPP) commitments.
This finding is greater than minor because it affected the objective of the initiating
events cornerstone to limit the likelihood of those events that could upset plant
stability and challenge critical safety functions' relied upon for SSD during a fire.
The six previously unidentified silicone oil-filled transformers represented an
increase in the ignition frequency of the associated fire areas/zones. This
findinrg is unresolved pending completion of a 'significance'determination. Also,
when assessed with other findings identified in this report, the significance could
be greater than very 16w significance. (Section 1 R05.02)
Cornerstone: Mitigating Systems
TBD. A violation of 10 CFR 50,'Appendix R,Section III.G.2, was identified for
failure to ensure thatone train of equipment necessary, to achieve and maintain
safe shutdown would be free of fire damage. Train A 480 volt (V) vital load
center 2A5 and associated electrical cables were located in the Train B
switchgear room (fire area C) without adequate spatial separation or fire barriers.
This load center powered redundant equipment (via motor control center 2A6
which powered boric acid makeup pumps 2A and 2B) required for SSD in the
event of a fire. In lieu of providing adequate physical protection for load center
2A5 and the' associated electrical cables, rrianual operator actions outside the
main control room'(MCR) were relied on and'credited, without prior NRC
approval, for achieving and maintaining SSD.
This finding was greater than minor because fire damage to the unprotected
cables could'prevent operation of the equipment from the MCR and challenge
the operators' ability to maintain adequate reactor coolant system (RCS)
inventory and reactor coolant pump (RCP) seal flow for SSD during a fire in the
B switchgear room.
Green. A non-cited violation of 10 CFR 50, Appendix R, Section III.G.2 was,
identified concerning a lack of spacial separation or barriers to protect cables
against fire damage in containment could result in spurious opening of the
pressurizer power operated relief valve (PORV).
This finding is greater than minor because it affected the mitigating system
cornerstone objective of equipment reliability, in that, spurious opening of the
PORV during post-fire safe shutdown would adversely affect systems intended to
maintain hot shutdown. The finding is of very low safety significance because
the initiating event likelihood was relatively low, manual fire suppression
capability remained unaffected and all mitigating systems except for the PORV
and block valve were unaffected. (Section 40A5)
B.
Licensee-Identified Violations
One violation for which the significance has not been determined and two violations of
very low safety significance, which were identified by the licensee and entered in the
corrective action program, were reviewed by the inspection team. (Section 40A7)
TBD. Many local manual operator actions were used in lieu of the required
physical protection of cables for equipment relied on for SSD during a fire,
without obtaining prior NRC approval for these deviations from the approved fire
protection program. This condition applied to numerous fire areas, including the
areas selected for this inspection.; This reliance on large numbers of local
manual actions, in place of the required physical protection of cables, could
potentially result in an increased risk of loss of equipment'that was relied upon
for SSD from a fire. (Section1R05.05),
A violation of PSL Unit 2 (OLC) 2.C.(20) and the Fire Protection Program was
identified. However, this finding is unresolved pending completion of a'
significance 'determination.. The finding is greater than minor because it could
potentially result in an inc'reased risk of loss of equipment that was relied upon
for SSD from afire. (Section 1R05XX)
Other violations of very tow safety significance which were identified by the licensee,
have been reviewed by the team.' Corrective actions taken or plan
have been entered into the licensee's corrective action programn Thene violations and
corrective action tracking numbers'are listed in Section 4A07.
cc:
Senior Resident Inspector
St. Lucie Plant
U.S. Nuclear Regulatory Commission
P.O. Box 6090
Jensen Beach, Florida 34957
Craig Fugate, Director
Division of Emergency Preparedness
Department of Community Affairs
2740 Centerview Drive
Tallahassee, Florida 32399-2100
M. S. Ross, Attorney
Florida Power & Light Company
P.O. Box 14000
Juno Beach, FL 33408-0420
Mr. Douglas Anderson
County Administrator
St. Lucie County
2300 Virginia Avenue
Fort Pierce, Florida 34982
Mr. William A. Passetti, Chief
Department of Health
Bureau of Radiation Control
2020 Capital Circle, SE, Bin #C21
Tallahassee, Florida 32399-1741
Mr. Donald E. Jernigan, Site Vice President
St. Lucie Nuclear Plant
6501 South Ocean Drive
Jensen Beach, Florida 34957
Mr. R. E. Rose
Plant General Manager
St. Lucie Nuclear Plant
6501 South Ocean Drive
Jensen Beach, Florida 34957
Mr. G. Madden
Licensing Manager
St. Lucie Nuclear Plant
6501 South Ocean Drive
Jensen Beach, Florida 34957
3
Mr. Don Mothena
Manager, Nuclear Plant Support Services
Florida Power & Light Company
P.O. Box 14000
Juno Beach, FL 33408-0420
Mr. Rajiv S. Kundalkar
Vice President - Nuclear Engineering
Florida Power & Light Company
P.O. Box 14000
Juno Beach, FL 33408-0420
Mr. J. Kammel
Radiological Emergency
Planning Administrator
Department of Public Safety
6000 SE. Tower Drive
Stuart, Florida 34997
Attorney~ General
Department of Legal Affairs
The Capitol
Tallahassee, Florida 32304
Mr. Steve Hale
St. Lucie Nuclear Plant
Florida Power and Light Company.
6351 South Ocean Drive
Jensen Beach, Florida 34957-2000
Mr. Alan P. Nelson
Nuclear Energy Institute
1776 I Street, N.W., Suite 400
Washington, DC 20006-3708
APN@NEI.ORG
David Lewis
Shaw Pittman, LLP
2300 N Street, N.W.
Washington, D.C. 20037
Mr. Stan Smilan
5866 Bay Hill Cir.
Lake Worth, FL 33463
U. S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
License Nos:
Report No:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved by:
50-335, 50-389
50-335/03-02, 50-389/03-02
Florida Power and Light Company (FPL)
St. Lucie Nuclear Plant, Units 1 & 2
6351 South Ocean Drive
Jensen Beach, FL 34957
March 10-28, 2003
R. Deem, Consultant, Brookhaven National Laboratory
P. Fillioh, Reactor Inspector
F. Jape, Senior Project Inspector
M. Thomas, Senior Reactor Inspector (Lead Inspector)
S. Walker, Reactor Inspector
G. Wiseman, Senior Reactor Inspector
Charles R. Ogle, Chief
Engineering Branch 1
Division of Reactor Safety
REPORT DETAILS
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems and Barrier Integrity
1R05 FIRE PROTECTION
01.
Systems Required to Achieve and Maintain Post-Fire Safe Shutdown
a.
Inspection Scope
The team evaluated the licensee's fire protection program against applicable
requirements, including Operating License Condition (OLC) 2.C.20, Fire Protection; Title
10 of the Code of Federal Regulations Part 50 (10 CFR 50), Appendix R; 10 CFR 50.48;
Appendix A to Branch Technical Position (BTP) Auxiliary Systems Branch (ASB) 9.5-1,
Guidelines for Fire Protection for Nuclear Power Plants; related NRC Safety Evaluation
Reports (SERs); the St. Lucie Updated Final Safety Analysis Report (UFSAR); and plant
Technical Specifications (TS). The team evaluated all areas of this inspection, as
documented below, against these requirements. The team reviewed the licensee's
Individual Plant Examination for External Events (IPEEE) and performed in-plant walk
downs to choose three risk-significant fire areas for detailed inspection and review. The
three fire areas selected were:
Unit 2 Fire Area B - Cable Spreading Room (Fire Zone 52). A fire in this area
would involve alternate shutdown from outside the main control room (MCR).
Unit 2 Fire Area C - Train B Switchgear Room (Fire Zone 34) and Electrical
Equipment Supply Fan Room (Fire Zone 48). Fire Area C and the essential
equipment and cables within were evaluated by the licensee with respect to the
protection and separation criteria of 10 CFR 50, Appendix R, Section III.G.2, to
assure that the ability to safely shut down the plant was not adversely effected
by a single fire event. Safe shut down of Unit 2 from the MCR using Train A
equipment was credited for a fire in this area.
Unit 2 Fire Area I - Fire Zone 51 West (Cable Loft), Fire Zone 21 (Personnel
Rooms), Fire Zone 32 (PASS and Radiation Monitoring Room), Fire Zone
331 (Instrument Repair Shop), and Fire Zone 23 (Train B Electrical
Penetration Room). Fire Area I and the essential equipment and cables within
were evaluated by the licensee with respect to the protection and separation
criteria of 10 CFR 50, Appendix R Section III.G.2 to assure that the ability to
safely shut down the plant was not effected by a single fire event. Safe
shutdown from the MCR using Train A equipment was credited for a fire in this
area.
The team reviewed the licensee's fire protection program documented in the St. Lucie
UFSAR (Appendix 9.5A, Fire Protection Program Report); safe shutdown analysis
3
2
(SSA); fire hazards analysis (FHA); SSD essential equipment list; and system flow
diagrams to identify the components and systems necessary to achieve and maintain
safe shutdown conditions. The objective of this evaluation was to assure the safe
shutdown equipment and post-fire safe shutdown analytical approach were consistent
and satisfied the Appendix R reactor performance criteria for safe shutdown. For each
of the selected fire areas, the team focused on the fire protection features, and on the
systems and equipment necessary for the licensee to achieve and maintain safe
shutdown conditions in the event of a fire in those fire areas. Systems and/or
components selected for review included the pressurizer PORVs; boric acid makeup
pumps 2A and 2B and gravity feed valves V-2508, V-2509; auxiliary feedwater (AFW);
charging pumps and volume control tank discharge valve V-2501; shutdown cooling;
heating, ventilation, and air conditioning (HVAC); atmospheric dump valves (ADVs); and
component cooling water. This review also included verifying that manual valves
operated during post fire safe shutdown were included in the licensee's maintenance
program.
b.
Findings
No findings of significance were identified.
.02
Fire-Protection of Safe Shutdown Capabilitv
a.
Inspection Scone
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 train of redundant
safe shutdown systems 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 Ill.G, and Appendix A of BTP ASB 9.5-1. The team reviewed the following
documents which establish 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 fire protection program (FPP) were satisfied:
Updated Final Safety Analysis Report (UFSAR), Appendix 9.5A, Fire Protection
Program Report
Plant St. Lucie (PSL) Individual Plant Examination of External Events (IPEEE)
Administrative Procedure 1800022, Fire Protection Plan
Administrative Procedure 0010434, Plant Fire Protection Guidelines
3
Electrical Maintenance Procedure 52.01, Periodic Maintenance of 4160 Volt
Switchgear
The team toured the selected plant fire areas to observe whether the licensee had
properly evaluated in-situ compartment 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 fire protection inspection reports, and corrective action
program condition reports (CRs) resulting from fire, smoke, sparks, arcing, and
equipment overheating incidents for the years 2001-2002 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 the fire brigade response procedures, training procedures, and drill
program procedures. The' team reviewed fire brigade initial training and continuing
training course materials to verify appropriate training was being conducted for the
station firefighting personnel. In addition, the team evaluated fire brigade drill training
records for the operating shifts from August 2001- February 2003. 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 fire protection program.
The team walked down the fire brigade staging and dress-out areas in the turbine
buildings and fire brigade house to assess the condition of fire fighting and smoke
control equipment. The team examined the fire brigade's personal protective
equipment, self-contained breathing apparatuses (SCBAs), portable communications
equipment, and various other fire brigade equipment to determine accessibility, material
condition and operational readiness of equipment. Also, the availability of supplemental
fire brigade SCBA breathing air tanks, and the capability for refill, was evaluated.
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 Occupational Safety and
Health Administration (OSHA) Part 1910, Occupational Safety and Health Standards.
This review als6 included an examination of backup emergency lighting availability on
pathways to and within the dress-out and staging areas to support fire brigade
operations during a fire-induced power failure. The fire brigade self-contained breathing
apparatuses were examined and assessed for adequacy.
Team members walked down the selected fire areas to compare the associated fire
fighting pre-fire strategies and drawings with as-built plant conditions. This was done to
verify that fire fighting pre-fire strategies and drawings were consistent with the fire
protection features and potential fire conditions described in the UFSAR Fire Protection
Program Report. Also, the team performed a review of drawings and engineering
calculations for fire suppression caused flooding associated with the floor and
equipment drain systems for the Train B Switchgear Room, Electrical Equipment Supply
Fan Room, and Train B Electrical Penetration R6om. The review focused on
4
ensuring that those actions required for SSD would not be inhibited by fire suppression
activities or leakage from fire suppression systems.
The team reviewed design control procedures to verify that plant changes were
adequately reviewed for the potential impact on the fire protection program, SSD
equipment, and procedures as required by PSL- Unit 2 Operating License Condition
2.C(20). Additionally, the team performed an independent technical review of the
licensee's plant change documentation completed in support of 2002 temporary
modification, TSA 2-02-006-3, that placed two exhaust fans on a fire damper opening
between the cable spreading room and the Train B switchgear room. This TSA was
evaluated in order to verify that modifications to the plant were performed consistent
with plant design control procedures.
b.
Findings
Inadequate Fire Hazards Analysis
Introduction: The team identified a Green non-cited violation (NCV) associated with
failure to meet the fire protection program plan requirements. 'The team found that six
silicone oil filled transformers installed in three Unit 2 fire zones [Fire Zone 37, Train A
Switchgear Room; Fire Zone 34, Train B Switchgear Room; and Fire Zone 47, Turbine
Building Switchgear Room] were not evaluated in the Fire Hazards Analysis (FHA) as
contributors to fire loading and effects on'SSD capability as required by fire protection
program commitments.
Description: At PSL, the indoor medium voltage power transformers installed in Unit 1
were of the dry type. However, six of the indoor medium voltage power transformers in
Unit 2 were cooled and insulated by a silicone-type fluid. The licensee provided the
team with information from the transformer vendor which indicated that the transformer
insulating fluid was Dow Corning (DC) 561, a dimethyl silicone insulating fluid. The
team performed an independent technical review of the licensee's engineering
calculations and maintenance documentation, transformer vendor technical information
manual, insulating fluid manufacturer information, Underwriters Laboratory (UL) and
Factory Mutual (FM) listing agencies' documentation, and Institute of Electrical and
Electronics Engineers (IEEE) Standards.
The DC 561 technical manual described the DC 561 fluid as a silicone liquid that will
burn, but was less flammable than paraffin-type insulating oils.- The technical manual
also stated that the DC 561 fluid had a flash point of 324 0C,
a total heat release rate
(HRR) of 140 kw/m2 (per ASTM E1354-90), and a fire point of 357 "C. In their Fire
Hazard Analysis the licensee evaluated the adequacy of their fire area/zone and
electrical raceway fire barrier system (ERFBS) enclosure barrier features based on the
combustible hazard content and overall fire loading (analyzed fire duration) present
within the associated area/zone. Based on the above, the team concluded that the
transformer insulating fluid was a in-situ combustible liquid not accounted for nor
evaluated in the PSL FHA. Additionally, the team noted that the licensee had conducted
I .
5
an UFSAR Combustible Loading Update evaluation in 1997. This evaluation was
documented in PSL-ENG-SEMS-97-070, but failed to identify that the transformers in
fire zone 37 contained combustible silicone insulating fluid. Also a PSL Triennial Fire
Protection Audit (documented in QA audit Report QSL-FP-01-07) conducted in 2001,
reviewed the FHA but did not identify any fire loading discrepancies.
The team determined that the previously unidentified six silicone oil-filled transformers
represented an increase in the ignition frequency of the associated fire areas/zones.
Also, the additional in-situ combustible fire load and fire severity represented by the
combustible transformer insulating fluid increased the likelihood of a sustained fire event
from a catastrophic failure of an effected transformer that may upset plant stability and
challenge critical safety functions during SSD operations.
The l-T-E Unit Substation Transformers Instruction Manual recommended that the
dielectric insulating fluid be sampled annually and the dielectric strength of the fluid be
tested to ensure that it is at 26 KV or better. The licensee determined that except for
four tests conducted during the period 1990-1992, there were no records of the
transformers' fluid being sampled and tested. This issue was entered into the corrective
action program as CR 2003-0978 and will followed up by the NRC resident inspectors at
PSL.
Analysis: The team determined that this finding was associated with the "protection
against external factors"'attribute and affected the objective of the initiating events
cornerstone to limit the likelihood of those events that could upset plant stability and
challenge critical safety functions relied upon for SSD from a fire, and is therefore
greater than minor. The six previously unidentified silicone oil-filled transformers in Unit
2 represented an increase in the ignition frequency of the associated fire areas/zones.
The finding was considered to have very low safety significance (Green) because it did
not involve the impairment or degradation of NRC approved fire protection features and
the overall SSD capabilities for the areas were evaluated by the licensee's SSA as
adequate to ensure SSD capability. However, when assessed in combination with other
findings identified in this report, the significance could be greater than very low
significance.
Enforcement:. 10 CFR 50.48 states, in part, "Each operating nuclear power plant must
have a fire protection program that satisfies Criterion' 3 of Appendix A to this part." PSL
Unit 2 Operating License NPF-16, Condition 2.C.(4) specifies, in part, that the licensee
implement and maintain in effect all provisions of the approved FPP as described in the
UFSAR for the facility and as approved by the NRC letter dated July 17, 1984, and
subsequent supplements. The approved FPP is maintained and documented in the
PSL UFSAR,,Appendix 9.5A, Fire Protection Program Report.
The Fire Protection Program Report stated, in part, that the PSL fire protection program
implements the philosophy of defense-in-depth protection against fire hazards and
effects of fire on safe shutdown equipment. The PSL fire protection program is guided
by plant fire hazard analyses and by credible fire postulations. It further stated that the
6
FHA performed for PSL Unit 2 considered potential fire hazards and their possible effect
on safe shutdown capability.
-
PSL administrative fire protection procedure, 1800622, Section 8.3 states that the FHA
is an individual study of each plant's design, potential fire hazards in the plant, potential
of those threats occurring, and the effect of postulated fires on safe shutdown capability.
Further, Section 8.7.1.A of this procedure stated that in-situ combustible features were
evaluated in the FHA as contributors to fire loading in the respective fire zones.
Contrary to the above, the FHA for fire zones 34, 37, and 47 was not adequate and did
not meet FPP commitments. Specifically, 380 gallons of in-situ combustible transformer
silicone dielectric insulating fluid in each of six transformers located in Unit 2 was not
considered nor evaluated in the FHA as contributors to fire loading and possible effects
on SSD capability. This condition was contrary to the requirements of the PSL FPP as
outlined in UFSAR, Section 9.5A, and therefore did not meet the requirements as set
forth in 10 CFR 50.48 and PSL OLC 2.C.(20).
Because the failure to evaluate in-situ combustible transformer silicone dielectric
insulating fluid as a contributor to fire loading in the FHA is of very low safety
significance and has been entered into the corrective action program as CR 2003-0637,
this violation is being treated as an NCV in accordance with Section VI.A.1 of the NRC's
Enforcement Policy. This item is identified as NCV 50-389/03-02-OX, Failure to
Evaluate In-situ Combustible Transformer Dielectric Insulating Fluid as a
Contributor to Fire Loading in the FHA.
.03
Post-Fire Safe Shutdown Circuit Analysis
a.
Inspection Scope
The team reviewed how systems would be used to achieve inventory control, reactor
coolant pump seal protection, core heat removal and reactor coolant system (RCS)
pressure control during and following a postulated fire in the fire areas selected for
review. Portions of the licensee's Appendix R Safe Shutdown Analysis Report which
outlined equipment and components in the chosen fire areas, power sources, and their
respective cable functions and system flow diagrams were reviewed. Control circuit
schematics were analyzed to identify and evaluate cables important to safe shutdown.
The team traced the routing of cables through fire areas selected for review by using
cable schedule, and conduit and tray drawings. The team walked down these fire areas
to compare the actual plant configuration to the layout indicated on the drawings. The
team evaluated the above information to determine if the requirements for protection of
control and power cables were met. The licensee's circuit breaker and fuse coordination
study was reviewed for adequate electrical scheme protection of equipment necessary
for safe shutdown. The following equipment and components were reviewed during the
inspection:
V1474 and V1475, Pressurizer PORVs
7
VV1476 and V1477, Pressurizer Isolation Block Valves
MV-09-03 and MV-09-04, Feedwater Bypass Valves
2HVE-13B, Control Room Booster Fan
V2501, VCT Discharge Outlet Valve
MV-07 -04, Containment Spray Isolation Valve
LP-208, Lighting Panel 208
LP-209, Lighting Panel 209
HCV-3625, Safety Injection Block Valve
V3444, Shutdowin Cooling Block Valve
P1-1107/1 108, Pressurizer Pressure for Hot Shutdown Panel
LI-1 104/1105, Pressurizer Level for Hot Shutdown Panel
LI-9113/ 9123, Steam Generator Level for Hot Shutdown Panel
SIAS Logic
MCC 2A5/2A6 and relative feeds, 480 Volt Motor Control Center
MCC 2B5/2B6'and relative feeds, 480 Volt Motor Control Center
Load Center 2A5 480 Volt Switchgear
b.
Findings
No findings of significance were identified.
04.
Alternative' Post-Fire Safe Shutdown Capability
a.
Inspection Scope
The cable spreading room, which was one of two alternate shutdown (ASD) fire areas
listed in the St. Lucie SSA for Unit 2, was selected for detailed inspection of post-fire
SSD capability. Emphasis was placed on verification that hot and cold shutdown from
outside the control room could be implemented; and that transfer of control from the
main control room to the hot shutdown control panel (HSCP) and other equipment
isolation locations could be accomplished within the performance goals stated in 10 CFR 50, Appendix R, Section III.L.3.
Electrical diagrams of power, control, and instrumentation cables required for ASD were
analyzed for fire induced faults that could defeat operationlfrom the MCR or the HSCP.
The team reviewed the electrical isolation and protective fusing in the transfer circuits of
components (e.g., motor operated valves) required for post-fire SSD'at the HSCP to
verify that the SSD components were physically and electrically'separated from the fire
area. The team also'examined the electrical circuits for a sampling of components
operable at the HSCP to ensure that a fire in the B Switchgear Room would not
adversely affect safe shutdown capability from the MCR. The team's review was
performed to verify that adequate isolation capability of equipment used for safe
shutdown implementation was in place, accessible, and that the hot shutdown control
panel was capable of controlling all the required equipment necessary to bring the unit
to a safe shutdown condition. This also included a review to verify that the shutdown
process met the performance goals of 10 CFR 50,Appendix R,Section III.L.3 and
8
guidance in generic letter (GL) 86-10, by comparing it to the thermal hydraulic time line
analysis provided by the licensee.
b.
Findings
No findings of significance were identified.
05.
Operational Implementation of Post-Fire Safe Shutdown CaPabilit
a.
Inspection Scope
The team reviewed off normal operating procedure 2-ONP-100.02, Control Room
Inaccessibility, Rev. 13B, the licensee's procedure for alternate safe shutdown, and
procedure 2-ONP-100.01, Response to-Fire, Rev. 9, the licensee's operating procedure
for post-fire safe shutdown from the MCR. The review focused on ensuring that all
required functions for post-fire safe shutdown and the corresponding equipment
necessary to perform those functions were included in the procedures. The review also
examined the consistency between the operations shutdown procedures and other
procedure driven activities associated with post-fire safe shutdown (i.e., fire fighting
activities).
b.
Findings
The team noted that the licensee had identified that manual operator actions outside the
MCR were credited and used in lieu of physical protection of cables'and equipment
relied on for SSD during a fire without obtaining prior NRC approval.. Use of manual
operator actions outside the MCR for 10,CFR 50, Appendix R,Section III.G.2 areas
(Fire Area C and Fire Area I for this inspection) without prior NRC approval wAas not in
accordance with the licensee's approved Fire Protection Program. The licensee
identified this issue in CR 03-0153 prior to this inspection.' This finding is More Than
Minor. This finding will be Unresolved pending completion of the SDP to determine the
risk associated with using manual operator,actions in lieu physical protection. 10 CFR 50, Appendix R, Section lII.G specified the need to identify equipment to achieve and
maintain safe shutdown functions, and the protection requirements for that equipment.
It also stated that one train of safe shutdown equipment should remain free of fire
damage for non-alternate shutdown (II.G.2) designated fire areas. Two of the three fire
areas inspected were so designated. In these areas, manual operator actions outside
the MCR were bein'g used and credited in the SSA to achieve safe shutdown.
Determination of the licensing basis and required NRC exemption to use manual
operations in lieu of protection for one shutdown train was addressed by another
inspection team member. The inspection team was also concerned whether all potential
spurious operations were, properly accounted for in the shutdown procedures.
Subsequent review of the licensee's procedures for these areas did demonstrate that
manual actions required to mitigate spurious signals on both units were properly
dispositioned.
9
06.
Communications
a.
Inspection Scope
The team reviewed plant communications to verify that adequate communications were
available to support unit shutdown and fire brigade duties. This included verifying that
site paging (PA), portable radios, and sound-powered phone systems were available
consistent with the licensing basis. The team reviewed the licensee's communications
features to assess whether they were properly evaluated in the licensee's SSA
(protected from exposure fire damage) and properly integrated into the post-fire SSD
procedures. The team also walked down sections of the post-fire SSD procedures to
verify that adequate communications equipment would be available to support the SSD
process."- The team also reviewed the periodic testing of the site fire alarm and PA
systems; maintenance checklists for the sound-powered phone circuits and amplifiers;
and inventory surveillance of post-fire SSD operator equipment to assess whether the
maintenance/surveillance test program for the communications systems was sufficient
to verify proper operation of the systems.
b.
Findings
No findings of significance were identified.
07.
Emergencv Lighting
a.
Insrection Scope
The team reviewed licensee emergency lighting against the requirements of 10 CFR 50,
Appendix R,Section III.J, to verify that eight hour emergency lighting coverage was
provided in areas where manual operator actions were required during post-fire safe
shutdown operations, including the ingress and egress routes. The team's review also
included 'erifying that emergency lighting requirements were evaluated in the licensee's
SSA and properly integrated into the Appendix R safe shutdown procedures as
described in UFSAR Appendix 9.5A, Section 3.7. During'plant walk downs of selected
areas where 6perators performed local manual actions defined in the post-fire SSD
procedures, the team inspected area emergency Iightirig units (ELUs) for operability and
checked the aiming of lamp heads to determine if adequate illumination was available to
correctly'and safely perform the actions required by the procedures. The team also
inspected emergency lighting features along access and egress pathways used during
SSD activities for adequacy and personnel safety. The team checked the ELUs' battery
power supplies to verify that they were rated with at least an 8-hour capacity. In
addition, the team reviewed the manufacturer's information and the licensee's periodic
maintenance tests to verify that the ELUs were being maintained and tested in
accordance with the manufacturer's recommendations.
b.
Findings
10
No findings of significance were identified.
08.
Cold Shutdown Repairs
a.
Inspection Scope
The team reviewed the licensee's SSA and existing plant procedures to determine if any
repairs were necessary to achieve cold shutdown, and if needed, the equipment and
procedures required to implement those repairs was available onsite.
b.
Findings
No findings of significance were identified.
.09
Fire Barriers and Fire Area/Zone/Room Penetration Seals
a.
Inspection Scope
The team walked down the selected fire zones/areas to evaluate the adequacy of the
fire resistance of barrier enclosure walls, ceilings, floors, and cable protection. The
team randomly selected several fire barrier features for detailed evaluation and
inspection to verify proper installation and qualification. This evaluation included fire
barrier penetration fire"stop seals, fire doors, fire dampers, fire barrier partitions, and
Thermo-Lag electrical raceway fire barrier system (ERFBS) enclosures to ensure that at
least one train of SSD equipment would be maintained free of fire damage from a single
fire.
The team observed the material condition and configuration of the selected fire barrier
features and also reviewed construction details and supporting fire endurance tests for
the installed fire barrier features.. This review'was performed to compared the observed
fire barrier penetration seal and ERFBS'configurations to the design drawings and
tested configurations.' The team also compared the penetration seal and ERFBS ratings
with the ratings of the barriers in which they were installed.
The team reviewed licensing documentation, engineering evaluations of Generic Letter 86-10 fire barrier features, and NFPA code deviations to verify that the fire barrier
installations met design requirements and license commitments. In addition, the team
reviewed surveillance and maintenance procedures.for selected fire barrier features to
verify the fire barriers were being adequately maintained. -
"
b.
Findings
No findings of significance were identified.
.10
Fire Protection Systems, Features, and Equipment
11
a.
Inspection Scope
The team reviewed flow diagrams, electrical schematic diagrams, periodic test
procedures, engineering technical evaluations for NFPA code deviations, operational
valve lineup procedures, and cable routing data for the power and control circuits of the
electric motor-driven fire pumps and the fire protection water supply system yard mains.
The review was performed to assess whether the common fire protection water delivery
and supply com'pone'nts could be damaged or inhibited by fire-induced failures of
electrical power supplies or control circuits and subsequent possible loss of fire water
supply to the plant. Additionally, team members walked down the fire protection water
supply system piping and actuation valves for the selected fire areas to assess the
adequacy of the system material condition, consistency of the as-built configuration with
engineering drawings, and operability of the system in accordance with applicable
administrative procedures and NFPA standards.
The team walked down accessible portions of the fire detection and alarm 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 spacing
and locations in the four selected fire areas for consistency with the licensee's fire
protection plan, engineering evaluations for NFPA code deviations, and the
requirements in NFPA 72A and 72D.
The team also walked down the selected fire zones/areas with automatic sprinkler
suppression systems installed to verify the proper type, placement and spacing of the
heads/nozzles and the lack of obstructions. The team examined vendor information,
engineering evaluations for NFPA code deviations, and design calculations to verify that
the required suppression system density for each protected area was available.
The team reviewed the manual suppression standpipe and fire hose system to verify the
adequacy of their design, installation, and operation for the selected fire areas. The
team examined design flow calculations and evaluations to verify that the required fire
hose water flow and sprinkler system density for each protected area were available.
The team checked a sample of manual fire hose lengths to determine whether they
would reach the SSD equipment. Additionally, the team observed placement of the fire
hoses and extinguishers to assess consistency with the fire fighting pre-plan drawings.
b.
Findings
No findings of significance were identified.
4.
Other Activities
40A2 Problem Identification and Resolution
a.
Inspection Scone
12
The team reviewed a sample of licensee audits, self-assessments, and plant condition
reports (CRs) to verify that items related to fire protection and safe shutdown were
appropriately entered into the licensee's corrective action program in accordance with
the licensee's quality assurance program and procedural requirements. The items
selected were also reviewed for classification and appropriateness of the corrective
actions taken or initiated to resolve the items.
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 reports are listed in the List of Documents Reviewed Section.
b.
Findings
>
No findings of significance were identified
40A3 Event Followup
-
.1
(Closed) LER 50-335. 389/00-01, Outside Design Bases Appendix R Hi-Lo Pressure
Interface and Separation Issues.
On March 9, 2000, the licensee identified seven cases where the plant was not in
compliance with 10 CFR 50, Appendix R, Sections Ill.G.2.d and IlI.G.2.f. The first
case, involving the pressurizer PORVs, applied to Units 1 and 2, and is discussed in
.Section 4AO5 of this report. The other six cases apply to Unit 2 only, and are discussed
as follows.
Shutdown cooling valves
Shutdown cooling valves V3652 and V3481 could spuriously open due to fire induced
cable-to-cable short circuits. The location of vulnerability was a pull box (JB-2031) in the
annulus region of containment. The valves are motor operated type valves which are
de-energized by procedure during normal plant operation. The problem however is that
the power cables for both these valves were routed through a pull box together with
other three-phase power cables. Therefore, the potential existed for fire induced cable
to cable short circuiting which could inadvertently energize the motors to open these
valves. Both valves would have to open to have a problem. Opening of these valves
directly connects the RCS to piping that is not rated for RCS normal operating pressure.
Should the valves open when the RCS is at operating pressure, a pressure relief valve
would open and RCS coolant would flow from the RCS to the containment sump. This
situation-is essentially a large break LOCA; Valve V3545.is a normally open motor
operated valve in series with .V3652 and V3481. Theoretically,-V3545 could be closed
by the operator to stop the outflow, but the cables for V3545 could have been damaged
by the same fire. The licensee resolved the problem by installing new power cables
using armored cable. This precluded the possibility of cable to cable short circuits.
13
Inspectors confirmed implementation of the modification through review of plant
modification PCMO1028.
The reported condition was a violation of Appendix R requirements of more than minor
significance because it could adversely affect the equipment reliability objective of the
cornerstones of mitigating systems and barrier integrity as described above. Using
techniques described in NRC Procedure 0609, Appendix F, the inspectors determined
that the finding was of very low safety significance (Green). Specifically the SDP
worksheet for large break LOCA was evaluated. The conclusion was supported
primarily by the negligible probability of the initiating event occurring and the fact that
cables for mitigating systems for LOCA are located outside containment. The
enforcement considerations for this violation are given in Section 40A7.
Pressurizer pressure instrumentation affected by tray-conduit interaction
Lack of 20-foot separation or a radiant heat shield between a cable tray and two
conduits in containment meant that a fire which could start in the cable tray due to cable
self ignition could result in damage to a number of pressurizer pressure instrumentation
loops. PT-1105, PT-1106 and PT-1107 are in cable tray L2224; and PT-1103, PT-1104
and PT-1108 are in conduits 2501 BY and 23091A. PT-1107 and PT-1108 were the
instruments specified in the post-fire shutdown procedure. These instruments also
provide input to alarms, automatically initiate automatic actions, provide permissives,
computer inputs, input to calculations and indications of pressure at various locations.
The inspector reviewed the consequences and ramifications of instruments failing either
high or low. Also reviewed, was which pressurizer pressure instrumentations remain
unaffected by the fire. This information was analyzed by the inspector, and it was
concluded that the affected instrumentation would not lead to any transient nor to
change in core damage frequency. The finding is therefore of very low safety
significance. As corrective action, conduits 25018Y and 23091A were protected by a
radiant heat shield for twenty feet either side of the tray L2224 by plant modification
PCM99104i Supplement 1. The licensee reports the fact that both channels of
pressurizer pressure instruments specified in the post-fire shutdown procedure could
have been affected by one fire represents a violation of 10 CFR 50, Appendix R, Section
Ill, G, 2. Refer to Section 40A7 of this report for enforcement aspects.
Pressurizer level instrumentation affected by tray-conduit interaction
Lack of 20-foot separation or a radiant heat shield between a cable tray and two
conduits in containment meant that a fire which could start in the cable tray due to cable
self ignition could result in damage to all pressurizer level instrumentation loops. LT-
111OX and LT-1105'are in tray L2213; and LT-111OY and LT-1104 are in conduits
23320D and 23090A. LT-1 I1 OX & Y were specified in the post-fire shutdown
procedure. It'was determined that the failure mode for a short-circuit between the
twisted pair or open circuit caused by fire exposure of the signal wires was level fails
low. Level failing low initiates several automatic actions some of which tend to cause
level to rise and some of which cause level to fall. The de-energization of pressurizer
14
heaters dominates the situation and results in falling level. This leads to a reactor trip
with safety injection on low pressurizer pressure. When the safety injection pumps start,
the level will rise. Since the operator cannot see level, he may not turn off the safety
injection pumps. So it follows that the pressurizer will go solid. The post-fire safe
shutdown procedure directs the operator to place the PORVs in override due to
concerns about spurious opening. Therefore, rising level and concomitant pressure rise
would be relieved by the safety relief valves. To obtain the risk significance of the fire
induced failure of pressurizer level instrumentation, the SDP worksheet for stuck open
relief valve was evaluated. The results indicated the finding was of very low safety
significance (Green) for the same reasons mentioned in Section 4A05.1 which deals
with spurious opening of. PORVs. The licensee reports the fact that both channels of
pressurizer level instruments specified in the post-fire shutdown procedure could have
been affected by one fire represents a violation of 10 CFR 50, Appendix R, Section 1I1,
G, 2. Refer to Section 40A7 of this report for enforcement aspects.
Pressurizer level instrumentation affected by conduit to conduit interaction
Lack of 20-foot separation or a radiant heat shield between two conduits in containment
containing cables for redundant channels of pressurizer level instrumentation 'meant that
the separation requirements of Appendix R were not met. The location of the interaction
is in the annulus area at an elevation where there are no ignition sources other than the
cables themselves. It is not considered credible that low voltage, low energy,
instrumentation circuits could self-induce cable ignition, and even if such occurred within
a conduit, the fire would not affect another conduit. The reported problem was a
violation of Appendix R requirements with regard to separation of cables. The
inspectors determined that, given the particular configuration at issue, it could not
credibly adversely affect any cornerstone. The licensee corrected the separation
problem by installing a radiant heat shield on one of the conduits per plant modification
PCM99104, Supplement 1. This licensee identified issue constitutes a violation of minor
significance that is not subject to enforcement action in accordance with Section IV of
the NRC's Enforcement Policy.
Circuits related to automatic pressurizer pressure control affected by conduit to conduit
interaction
Lack of separation or a radiant heat shield between certain conduits in containment
related to automatic pressurizer pressure control meant that the separation
requirements of Appendix R were not met. The circuits involved were for the PORV
and the auxiliary spray isolation valves. The concern was that, if one fire could affect
both these circuits, two diverse subsystemris designed to reduce pressure when
necessary may not function. There're other ways to reduce pressure, but the above
mentioned ones were'the systems designated in the post-fire shutdown procedure for
this function. The location of the interaction is in the annulus area at an elevation where
there are no ignition sources other than the cables themselves. It is'not considered
credible that a fire starting within one conduit would expand to affect other nearby
conduits. The reported problem was a violation'of Appendix R requirements with regard
15
to separation of cables. The inspectors determined that, given the particular
configuration at issue, it could not credibly adversely affect any cornerstone. The
licensee corrected the separation problem by installing a radiant heat shield on a
sufficient number of the conduits per plant modification PCM99104, Supplement 2. This
licensee identified issue constitutes a violation of minor significance that is not subject to
enforcement action in accordance with Section IV of the NRC's Enforcement Policy.
Radiant heat shields not installed per Appendix R accepted deviation
Inside containment in the area between the containment wall and the bioshield four
groups of cable trays are installed. There are five trays in each group. These trays run
horizontally along the circumference of the containment'to carry cables from the
penetration area to their various ultimate destinations in the containment. Train B
cables are in trays near the containment'wall, and Train A cables are in trays near the
bioshield. There is at least seven foot horizontal separation between these two sets of
trays in the area of interest. Both the Train A set and the Train B set consists of a group
running above the 45-foot elevation grating and a group running above the 23-foot
elevation grating. Examples of cable trays involved are instrumentation trays L2223
(Train A) and L2224 (Train B); or control trays C2223 (Train A) and C2224 (Train B).
According to the safety evaluation report each of the four groups should have had a
radiant heat shield installed directly below the group. This is' actually an accepted
deviation, or exemption, from the requirement to have a heat shield between the
redundant cables. The licensee reported in the LER that the radiant heat shields below
the groups at the 45-foot elevation were not installed. The missing radiant heat shields
have now been installed per PCM01028.
The inspector evaluated the risk significance of the lack of radiant heat shield below the
45-foot elevation groups of trays. The conclusion of this evaluation was that the
problem was of very low safety significance (Green). Some of the dominant factors
considered were:
Fire brigade capability for a fire in containment was not impaired.
In-situ ignition sources were'negligible, and transient ignition sources and
combustibles are not present during normal plant operation.
Only the top tray in each group contains power cables (480 volt) carrying
sufficient energy capable of self ignition of IEEE 383 flame tested cable. Most of
the power cables in'containment are not energized during normal plant
operation. These trays are solid metallic bottom and cover type trays. This
construction inherently limits the spread of internal tray fire, and effectively
provides a shield limiting the radiant heat energy.
The "target" cable trays have a minimum spatial separation of 15 feet vertical
and 7 feet horizontal from the potentially burning cable tray. The target trays
have solid metallic bottoms. Radiant energy flowing between source and target
16
is blocked to a great extent by intervening HVAC ducts, large pipes, tanks and
building steel. Hot gas layer is not a factor in the part of containment under
.consideration.
The target cables would be instrumentation cables, and various scenarios
involving damage to these same instrumentation cables discussed in relation to
other findings within this report Section were shown to be of very low safety
significance.
A very similar configuration in the Unit 1 containment was analyzed by the
licensee and reviewed by the NRC in great detail, and found to be an acceptable
configuration from the fire protection viewpoint. The Unit 1 study had a safety
factor of at least two, which provides margin to account for geometry and other
unknown differences between the two units.
Failure to adhere to the configuration of cable trays and radiant heat shields described
in an exception to 10 CFR 50, Appendix R, Section III.G.2 represents a licensee
identified violation. Refer to Section 4AO7 of this report for enforcement aspects.
.2 .
(Closed) LER 50-335/00-04, PressurizerLevel Instrumentation Conduit Separation
Outside Appendix R Design Bases..,.,-
Lack of 20-foot separation or a radiant heat shield between a cable tray and a conduit in
Unit 1 containment meant that a fire which could start in the cable tray due to cable self
-ignition could result in damage to all pressurizer level instrumentation. The discussion
of risk significance and requirements for this issue would be identical to the discussion
of essentially the same issue on Unit 2 in Section .1 above under the heading:
Pressurizer level instrumentation affected by tray-conduit interaction.. Refer to Section
4AO7 of this report for enforcement aspects.
40A5 Other Activities
.1
(Closed) URI 335.389/99-08-03. PORV Cabling May Not be Protected from Hot-Shorts
Inside Containment
- -
Introduction: A Green NCV was identified for failure to comply with 10 CFR 50,
Appendix R, Section 1II, G, 2.d and f, related to spurious opening of the pressurizer
PORV.
..
Descriotion: During conduct of an inspection in the area of fire protection (NRC
Inspection Report 50-335, 389/99-08, dated January 31, 2000) the inspectors identified
the possibility that the PORV cables inside containment were not protected from fire
induced cable to cable short circuits. The issue was identified tirough review of the
licensee's analysis. However, the analysis referred to a study which showed that the
cable to cable short circuit leading to spurious opening of the PORV was not credible.
Since the study could not be located at the time of the inspection, an unresolved item
17
was initiated to track this issue. Subsequently LER 50-335, 389/00-01 reported that the
pressurizer PORVs could open due to fire induced short circuits that could occur in a
cable tray in containment. In addition, cables for the associated block valve were routed
in the same cable tray. This meant the block valve may not be available to counter the
spurious opening of the PORV. Cables for one PORV and its block valve were in a tray
near the containment wall and cables for the other set were in a tray near the bioshield.
The condition applied to both units.
The licensee resolved the problem by installing new PORV cables using armored cable.
This precluded the possibility of cable to cable short circuits. The potential for spurious
opening due to spurious pressure signal had already been offset by having the operator
place the control switch in override in response to a fire' in containment. Inspectors
confirmed the modification was implemented through review of plant modification
package PCM00059 (Unit 1) and PCM99104, Rev4 (Unit 2).
LER 00-01 mentioned above also reported licensee identified findings in the area of
Appendix R. In addition, Unit 1 LER 00-04 reported similar problems. Refer to Section
40A3 for discussion of these findings.
Analysis: The finding was a performance deficiency because it represented a violation of
Appendix R requiremrents. It was considered greater than minor because it could
adversely affect the cornerstones of mitigating systems and barrier integrity. It affects
mitigating systems in the sense that systems designated for post-fire shutdown would
be adversely'affected by an open PORV during the early stages of post-fire shutdown.
It affects the cornerstone of barrier integrity in the sense that a spuriously open PORV
represents a breach of the RCS pressure boundary which is one of the barriers. Using
techniques described in NRC Procedure 0609, Appendix F, the inspectors determined
that the finding was of very low safety significance (Green). Specifically, the SDP
worksheet'for stuck open relief valve was evaluated., A key factor leading to this
conclusion was that the initiating event likelihood was relatively low. It was less likely
than the likelihood for stuck open PORV due to non-fire induced causes. Manual
suppression of fires in the containment was in the normal state because the plant had
fire detectors, a fire plan and there were no automatic valves in the water source that
could be affected by the fire. Even though no credit could be given for the block valve,
other mitigating systems were unaffected. This was primarily due to the fact that the
associated cables were all outside containment.
Enforcement: Because this violation of 10 CFR 50, Appendix R, Section III, G.2.d. and f,
is of very low safety significance, has been entered into the CAP (CROO-0386) and the
problem has been corrected through a plant modification it is being treated as an NCV,
consistent with Section VL.A of the NRC Enforcement Policy. The number and title of
this NCV are: NCV 50-335, 389/03-02-01, Failure to Meet 10 CFR 50, Appendix R,
Section III, G, 2, for Protection of the PORV Cables in Containment.
40A6 Meetings
18
On March 28, 2003, the team presented the inspection results to Mr. D. Jernigan and
other members of your staff, who acknowledged the findings. The team confirmed that
proprietary information is included in this report.
40A7 Licensee-Identified Violations
The following findings of very low safety significance (Green) were idenitified by the
licensee and are violations of NRC requirements which meet the criteria of Section VI of
the NRC Enforcement Policy, NUREG-1600, for being dispositioned as NCVs.
10 CFR 50, Appendix R, Fire Protection Program, Section 1i, Specific
Requirements, Subpart G, Fire protection of safe shutdown capability, requires
that for cables, 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 and located inside
noninerted containments, one of the following fire protection means shall be
provided:
1.
Separation of cables of redundant trains by a horizontal distance of more
than 20-feet with no intervening combustibles or fire hazards; or
2.
Separation of cables of redundant trains by a non-combustible radiant
energy shield.
Contrary to this, since the requirement became effective, the required fire
protection was not provided for the following redundant cables:
1.
Shutdown cooling valves V3652 and V3481 on Unit 2.
2.
Pressurizer pressure instrumentation PT-1107 and PT-1108 on Unit 2
3.
Pressurizer level instrumentation LT-1 11 OX and LT-1 11 OY on Units 1 & 2
4.
Cables contained in cable trays L2223 (Train A) and L2224 (Train B)
These findings have been entered into the CAP (CR 99-1963, Rev. 2, and CR
00-0386), corrected by plant modifications, and are of very low safety
significance for reasons given in Sections 4AO3.1 and .2.
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
D. Albritton, Assistant Nuclear Plant Supervisor
19
P. Barnes, Fire Protection Engineering Supervisor
R. De La Esprella, Site Quality Manager
B. Dunn, Site Engineering Manager
K. Frehafer, Licensing Engineer
J. Hoffman, Design Engineering Manager
D. Jernigan, Site Vice President
G. Madden, Licensing Manager
R. Maier, Protection Services Manager
R. McDaniel, Fire Protection Supervisor
T. Patterson, Operations Manager
R. Rose, Plant General Manager
V. Rubano, Engineering Special Projects Manager
S. Short, Electrical Engineering Supervisor
NRC Personnel
C. Ogle, Branch Chief
R. Rodriguez, Nuclear Safety Intern (Trainee)
T. Ross, Senior Resident Inspector
S. Sanchez, Resident Inspector