ML20071P715
| ML20071P715 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 11/30/1989 |
| From: | Fresco A, Robert Lewis, Macdougall E BROOKHAVEN NATIONAL LABORATORY |
| To: | NRC |
| Shared Package | |
| ML20071P712 | List: |
| References | |
| CON-FIN-A-3872 A-3875-T4, A-3875-T4-R01, A-3875-T4-R1, NUDOCS 9408100110 | |
| Download: ML20071P715 (145) | |
Text
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CHNICAL REPORT
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BRUNSWICK STEAM ELECTRIC PLANT UNIT 2 RISK-BASED INSPECTION GUIDE i
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Technical Report A 3872 T4 Rev.1 i
I
- BRUNSWICK STEAM ELECTRIC PLANT UNIT 2 RISK-BASED INSPECTION GUIDE l
Prepared by:
A. Fresco, E. MacDougall, and R. Lewis Engineering Technology Division November 198a Department of Nuclear Energy Brookhaven National Laboratory Upton, New York 11973 Prepared for:
U.S. Nuclear Regulatory Commission Washington, DC 20555 I
FIN A-3872 l
I
CONTENTS I
Title Page ;
Section
.. . . . . 1 INTRODUCTION.. . .. . .
1.
i
.. 1
- 2. DOMINANT ACCIDENT SEQUENCES.. ..... . . .
6
- 3. SYSTEM PRIORITY LIST. . . - . . .. . .. .
8 COMMON CAUSE OR DEPENDENT FAILURES...... :... .
4.
- IMPORTANT HUMAN ERRORS (Including Recovery Actions). .. . . 8 5.
. .. 9
- 6. SYSTEM INSPECTION TABLES. . . . . . .
.. . . . 12
- 7. REFERENCES . . . . . .
Title Page Appendix A IMPORTANCE BASIS AND FAILURE MODE IDENTIFICATION
. A-1 TABLES AND MODIFIED SYSTEM WALKDOWN TABLES..
B PLANT OPERATIONS, SURVEILLANCE AND CALIBRATION, AND MAINTENANCE INSPECTION TABLES.. . .. .. B1 C-1 C CONTAINMENT AND DRYWELL WALKDOWN . ..... ... . . . . . .
D-1 D SYSTEM DEPENDENCY MATRIX . . . . . . . .
O e
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TABLES Page Title Table No.
.. . .. . . 5 1 ATWS with Isolation Success Criteria. .. . 6 2 ATWS (Without Isolanon) Success Criteria.. . . . . . . . 7 3 System Priority Ranking . .. ..
. . . ... . .. A1 A.1 Emergency Diesel Generator (EDS) System.. A-1 A.1-1 Imponance Basis and Failure Mode Identification. .- A-3 A.1-2 Modified System Walkdown .
... A6 .
A.1-3 Proposed Inspection Plan for Diesel Generators at Nuclear Plants..
. . . A-9 High Pressure Coolant lajection (llPCI) System ...
A.2 . = ....... A-9 -
A.2 1 Importance Basis and Failure Mode Identification A 11 A.2-2 Modified System Walkdown.. . . .
.. . . . . . A-18 A.3 Automatic Depressurization System (ADS).. .
A 18 A.3 1 Importance Basis and Failure Mode Identification.. . . . A-20 A.3-2 Modified System Walkdown..... ... .. . ..
.. .. . A-23 A.4 Diesel Generator and Switchgear Cell Fans = A-23 A.4 1 Importance Basis and Failure Mode Identification.. .. .. A-25 A.4 2 Modified System Walkdown.._ . . . . . . . . .
. .. . . A-30 A.5 Standby Ligeid Control (SLC) System A-30 A.5-1 Importance Basis and Failure Mode Identification. A-32 A.5 2 Modified System Walkdown.. - . .._..
. . . .. A-36 A.6 Reactor Protection System (RPS).- . .
A 36 A.6-1 Importance Basis and Failure Mode Identification.
. ... ,. A-42 A.7 Service Water System (SWS) . . . . . . . . . . . . . . . . . A-42 A.7-1 Imponance Basis and Failure Mode Identification. .. ... A-45 A.7 2 Modified System Walkdown .
. . . . A-51 A.8 Residual Heat Removal (RHR) System . . . .... . . . .
.. A-SI A.8-1 Importance Basis and Failure Mode Identification: A 55 A.8-2 Modified System Walkdown-- - . - - - . . . . .
A-66 A.9 DC Power (DCP) System = .
. A-66 A.9 1 Importance Basis and Failure Mode Identification... . . . . . ~ . . . A-68 Modified System Walkdown..... . . . . .
A.9-2
. . . A-72 AC Power (ACP) System.. .. . . . . . . . .
A.10 .. A-72 A.10-1 Importance Basis and Failure Mode Identification... ..... . . . . . . A-77 A.10-2 Modified System Walkdown . ... . ...
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TABLES (Cont'd)
Title Page Table No.
. A-83 A.!1 Battery Room Fans and Heaters .. .., . A-83 A.ll-1 Importance Basis and Failure Mode Identification.. . A-85 A.11 2 Modified System Walkdown.. . . .. .. ..- ... .
. . . . A-89 A.12 Reactor Core Isolation Cooling (RCIC) System.. .. .... .. ... ... ..
. A 89 A.12-1 Imponance Basis and Failure Mode Identification. A.91 A.12-2 Modified System Walkdown..... . . .. .
...... A-97 A.13 Control Rod Drive (CRD) Hydraulic System .. .. . . .
.. A.97 A.13 1 Imponance Basis and Failure Mode Identification. .. A-98 A.13 2 Modified System Walkdown... .. .
i
. A-101
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A.14 Emergency Core Cooling System (ECCS) Actuation..... .
. . . . . . . . A 101 A.14-1 Imponance Basis and Failure Mode Identification. .. A 104 A.14-2 Modified System Walkdown.. .. . .... . . .
. B-1 B.1 Plant Operations Inspection Guide... . .. B-2 B.2 Surveillance and Calibration Inspection Guidance.
.. B-7 .
B.3 Maintenance Inspection Guidance.. .
C-1 C.1 CotuAmment and Drywell Walkdown.. ..
. . . D-1 D.1 Frontline-Suppon System Dependencies = .
.. . D-2 i D.2 Suppon-Support System Dependencies... .. ..... . .
FIGURES i Caption Page Figure No.
.... . ... . A-8 f A.1-1 DG Simplified Diagram . . . . . . . . . .. .
. A-15 l
HPCI Simplified Diagram. . .. ..
= . . . . . . .
A.2-1 A-22 I
A.3 1 Reactor Coolant System Showing ADS Simplified Diagram .. .. ..... . . .
. . . . . ..... A-35 A.5-1 SLC Simplified Diagram. . . . .
A.6-1 Reactor Protection System-Schematic Diagram of Logics in
. A 39 :
One Trip System.. _. - . . . . . . . .
A-40 A.6-2 Recircu'.ation Pump Trip (ATWS)/ Alternate Rod injection Logic ... . .. . .
A-41 A.6-3 Alternate Rod injection Logic. . . . . ..... . . . . . ..
= . . A-49 i A.7 1 Cooling Water Systems Functional Diagram. !
Service Water System Showing Component Locations . A 50 A.7-2 A-64 A 8-1 RHR (LPCI) Simplified Diagram . . . . . . . . . .
A-65 RHR (Suppression Pool Cooling) Simplified Diagram -.
- A.8-2 A-71 A.9 1 DC Power Simplified Diagram.
A-80 A.10-1 AC Power Simplified Diagram.. . ... .... . _ . - . . . . . . . . . . . . . . . . .
.-..... A 94 A.12-1 RCIC Simplified Diagram. A 100 A.13-1 Control Rod Drive Simplified Diagram
. . . . A-107 A.14-1 ECCS Actuation Diagram - . . . . .., . .
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ACKNOWLEDGEMENTS Ths authors wish to express their gratitude to the numerous people who were instrument in producing this document. Our NRC Technical Monitor, Dr. Steven Long provid valuable insights and assistance to facilitate the preparation of this document. Dr. See Meng Wong and Dr. Roben Youngblood established the computer model of the accide sequence cutsets which form the technical basis for this repon. William Shier also significantly in this effon. Our thanks go as well to Vicki Feldman, Joy Monaco, Terry Jones, Craig Sirot, Madeline Batsche and Mary Wigger who worked tirelessly to conven the published accident sequence cutsets into PC-based floppy disks, and who pr excellent typing skills to produce this document.
S P
O S
vii !
BRUNSWICK STEAM ELECTRIC PLANT (BSEP)
- 1. INTRODUCTION This document has been prepared to provide inspection guidance dbased to on re the Probabilistic Risk Assessment (PRA), (Reference 1). The guidance should be use aid in the selection of areas to inspect and is not intended either to replace curr inspection guidance or to constitute an additional set of inspection requirem information contained herein is based almost entirely on the Brunswick dPRA perf the plant design as of October 1,1986. Hence, recent system experience, failur modifications should be considered when reviewing these tables. Since plant mod are normally an ongoing process it is recommended that relevant changes be ca that this inspection guidance can be periodically revised as required.
- 2. DOMINANT ACCIDENT SEQUENCES The Brunswick PRA has a number of different accident sequences that contribute significantly to overall core damage frequency (CDF), which is 2.lE-5/ year sequences that dominate core damage frequency at Brunswick Unit 2 are their initiating events.
- Anticipated Transients Without Scram (ATWS)
(44% of core damage frequency)
- Station Blackout t38%)
- Failure of High Pressure Injection and ADS (13%)
- Failure of Long-Term Decay Heat Removal (4%)
- Other (1%)
Six sequences have frequencies greater than 1.0 E-6/ year and contribute ,
total core damage frequency (CDF). Six more have frequencies greater than 1.0 E- '
and contribute to 14% of total CDF. The remaining sixteen dominant sequences co ;
to total CDF.
The sequences are grouped below by their initiating events or their common outco; such as loss of long-term decay heat removal, etc.
- 2.1 Anticipated Transients Without Scram ( ATWS) (43.5%)
In the BSEP PRA, ATWS events are divided into two major categories: !
(1) Events where the MSIVs remain open and the turbine bypass is initially (2) Events where the MSIVs are closed (isolation events). Th assumed in the BSEP PRA for the two categories above are shown in Tables 1 a ]
1 1
l 1
1
. = .
Of the 28 dominant accident sequences, all eight of the ATWS sequences are iso events. except for one (ATWS without isolation and SLCS failure). The domina i sequcaces are as follows:
a) Failure of water level control at high pressure. (11.7%)
b) Failure of water level control at low pressure. (5.9%)
c) Failure of HPCI with ADS inhibited (5.3%)
d) Failure of SLC e) Failure of HPCI, failure to inhibit ADS (although this is not actually a failure because ADS is desired in this case), and failure of water level control at low ,
(4.4%) ,
pressure.
f) Failure to inhibit ADS and failure of water level control at low pressure.(0.4%
g) Failure to depressurize long-term to meet heat capacity (~0.1 thetmal
%) limit (H (2.7%)
- 2. ATWS without isolation and failure of Standby Liquid Control (SLC)
During an ATWS it is necessary to provide protectmn of the core and contain such time as subcriticality is achieved. The core requires coolant makeup to match th power level. Recirculation pump trip will reduce powe steam flow to the turbine or turbine bypass or steam discharge through the SRVs to suppression pool.
In the event that the turbine bypass is unavailable, all of the heat being generated the core will be directed to the suppression pool through the SRVs. For some ATW events, normal suppression pool cooling will not be sufficient to control containment pressure and temperature within allowable limits. For tho may also be necessary to depressurize the reactor long-term into the acciden HCTLs, whether or not the HPCI system is operational.
For isolation transients, recirculation pump trip and SLCS activation must occur very early in the sequ;nce to limit power to a level that can be accommodated by H to limit suppression pool heatup. Suppression pool cooling by the RHR system ha determined by calculation not to be a significant factor in pool temperaturefinal control. F l 43 gpm SLCS capacity, water level control in the core is necessary to limit -
suppression pool temperature. The operator must inhibit ADS and throttle to accomplish this. If HPCI fails and the operator inhibits ADS, it is assumed t .
core damage.
Failure of the affected components is reflected in the accident sequences descr above.
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2.2 Station Blackout (37.3%) 1 l
Station blackout (no ac power) sequences, the next most sizable contributors to core l
damage frequency are initiated by loss of off-site power. Failure of both Diesel Generator 3 and 4 (DG3 and DG4) represents station blackout. If HPCI, RCIC, or ADS and LPCI (Unit 1 powered components) succeed, all reactor safety functions are provided for some time.
In BWR station blackout phenomenology, there are three issues which control accident sequence progression and timing. The first issue is battery depletion. With no ac batteries are not being recharged. Depletion can be expected to occur between two and eight hours After loss of all ac power, depending on the load distribution. For BS depletion was assumed at 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. It is then no longer possible to control HPCI, R LPCI because of lack of instrumentation in the reactor to measure water leve HPCI and RCIC generally require room cooling for the turbine instrumentation and bearing cooling from the pumped fluid stream. LPCI generally requires both pump se cooling and room cooling. Loss of cooling in the HPCI and RHR rooms or RCIC and rooms will not result in high enough room temperatures within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to result in turbine failure. Over heating of the HPCI turbine bearing will occur sometime after 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> when suppression pool temperature ranges from 200 F to 240 F. RCIC isolation will occur a about 6 to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> because of high suppression pool backpressure. Early isolation of HPC or RCIC on steam tunnel temperature at about 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is expected to be overridden by the operators as per the emergency operating procedures. HPCI/RCIC failure will be until 6 to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> but battery depletion occurring at 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> takes precedence over these later events.
Finally, it is necessary to maintain the heat capacity thermal limits (HCTL). As statio blackout cuminues, the suppression pool will continue to heat up reaching the upper HCTL at about 5 to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. The reactor must then be depressurized to maintain the limit, ultimately to a level so low that HPCI and RCIC become inoperable. There is then no further assurance that core damage will not occur. Critical timing for entering this steam cooling stage is about 8 to 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> from initiation of station blackout. However, again battery depletion would occur beforehand at about 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
During a station blackout, HPCI, RCIC and LPCI can operate until one of the three situations described above leads to their failure. In the case of a stuck open SRV, HPCI unavailability occurs at approximately two hours because of inadequate steam pressure.
The actual loss of off-site power sequences in the BSEP PRA, and their percent contribution to core damage frequency, are as follows:
Loss of off-site power and:
a) Failure of on-site ac power (DGs) de battery failure at 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, and failure to (36.2%)
recover off-site power by 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.
b) Failure of Unit 2 DGs 3 and 4, failure of HPCI and RCIC, and failure of LPCI (0.5%)
(components powered by Unit i DGs).
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l c) Subsequent stuck open SRV, failure of Unit 2 DGs 3 and 4, success of i (components powered by Unit 1 DGs), de battery failure at 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, an (0.3%)
to recover off-site power within 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. ;
d) Subsequent stuck open SRV, failure of Unit 2 DGS 3 and 4, failure of L '
(components powered by Unit 1 DGs), and failure to recover (0.2%) off-site po:
hours.
e) Failure of Unit 2 DGs 3 and 4, failure of HPCI and RCIC (0.1%) (but success and failure to recover off-site power by 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> 2.3 Failure of liigh Pressure Injection (llPI) and Automatic Depressurization System ( ADS) (12.6%) -
Several accident sequences lead up to failure of high pressure injection, i.e. H RCIC and CRD, with subsequent failure of the ADS. These sequences include: ~
a) Transient with subsequent stuck open SRV, failure of HPCI, and failure (10.2%)
b) Loss of off-site power, failure of HPCI, RCIC and CRD, and failure of (1.6%)
c) Failure of turbine bypass, with eventual MSIV closure, failure (0.4%) of HPC and CRD, and failure of ADS.
d) Turbine trip, subsequent loss of feedurater, failure of HPCI, RCIC and C and failure of ADS. (0.2%)
e) Intermediate LOCA, failure of HPCI, and failure of ADS. (0.1%)
f) Small LOCA, failure of HPCI and RCIC, and failure of ADS.
g) Turbine trip, failure of turbine bypass, failure of HPCI, RCIC (0.1%) and C failure of ADS.
It should be noted that the adequacy of HPCI, RCIC or CRD to mitigate the course, dependent on the nature of the initiating event, e.g. RCIC is inadequ intermediate LOCAs and is therefore its operability is irrelevant in that situation.
2.4 Failure of Long-Term Decay Heat Removal (3.7%)
The final major group of accident sequences is one which consists of transi ultimately evolve into failure of the long-term decay heat removal function (L LTDHR can be accomplished by RHR suppression pool cooling, suppression po shutdown cooling or altemate shutdown cooling. It can also be accomplished wi ~
Condensate, Feedwater, CRD, LPCI or CS systems together with the Power C System. These sequences include: .
a) Failure of turbine bypass, with eventual MSIV closure, and(2.7%) failure of L (0.5%)
b) Transient with stuck open SRV and loss of LTDHR. (0.3%)
c) Turbine trip, failure of turbine bypass, and failure of LTDHR.
d) Loss of de bus 2A1, failure of turbine bypass, and loss of (0.1%) LTDHR. (0 e) Small LOCA and failure of LTDHR.
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2.5 Other Dominant Accident Sequences (1.6%)
The remaining dominant accident sequences, which comprise somewhat over 1% of core damage frequency, are the following, all assumed to lead directly to core damage:
a) Reactor vessel rupture. (-1.4%)
b) Steamline bred outside containment and failure of MSIV closure. (-0.1 %)
c) Interfacing system LOCA. (-0.1 %)
The reactor vessel rupture was assumed large enough such that no coolant injection '
systems can keep the core covered. The steamline LOCA with MSIV failure bypasses the containment as does the RHR interfacing system LOCA (the so-called "V sequence").
TABLE I 6
ATWS WITH ISOLATION SUCCESS CRITERIA'"
Coolant Containment Decay IIcat Reactor Makeup
- Protection
- Removal Suberiticality HPCI Control water level Decay heat removal Manual scram or throughout transient is not considered in and the ATWS event RPT and SLCS or SLCS trees. ATWS events 2/7 ADS and 1/2 CS and which involve suc-or Depressurize at HCTL cessful reactor subcriticality, coolant 2/7 ADS and 1/4 LPCI makeup, and contain-ment protection but failure of long-term decay heat removal are negligible
(<l.0 x 10*/yr).
ite notation m/n denotes m out of n trains (or components) must be successful in order to fulfill the function in question.
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TABLE 2 ATWS (WITIIOUT ISOLATION) SUCCESS CRITERIA'"
Containment Decay IIeat Reactor Coolant Removal Makeup
- Protection'*'
Suberiticality SLCS Decay heat removal Manual scram HPCI '
and is not considered in or or Feedwater Depressurize at HCTL the ATWS event RPT and SLCS trees. ATWS events or which involve suc-2/7 ADS and 1/2 CS cessful reactor or subcriticality, coolant 2/7 ADS and 1/4 makeup, and contain-LPCI ment protection but '
failure of long-term ,
decay heat removal are negligible
(<l.0 x 10*/yr).
'" Assumes a 43-gpm SLCS and no ARI
'*he notation m/n denotes m out of a trains (or components) must be successful in order to function in question.
- 3. SYSTEM PRIORITY LIST The Brunswick core Jamage prevention systems have been ranked in Table 3 acco i
ing to their importances in preventing core damage. Other plant systems not the list are generally of lesser importance than those included here.
l
! There are two criteria that contribute to the risk significance of a system or compo-nent: the probability that it will fail and the amount that risk is increased when it i i
inoperable. In planning inspections, it is usually best to consider a combinatio two criteria so that the items most likely to cause significant risk increases are given th l most attention. The " Inspection Importance Measure,"* which combines both criteria, been used to rank the systems and components in thh guide. However, some items very low failure probabilities can cause very large increases in risk if they do bec inoperable. Consequently, ranking systems solely on the basis of their risk c when inoperable ** can result in a substantially different ordering of the plant's syste -
When a system is known to be inoperable or is experiencing abnormally high failure it is appropriate to consider the importance of that system's failure independ normal failure rate assumed for it in the PRA. Therefore, Table 3 also includes a se system list rank ordered by the importance of their failures.
'The Inspection Importance Measure is equivalent to the Fussell-Vesely imponanc purposes. Both measures combine the risk significance of a system's failure or '
probability that the system will fail or be unavailable.
- The Birnbaum imponance Measure considers only the risk significance of a system sho l unavailable, regardless of the actual probability that it will fail or be unavailable.
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l TABLE 3 SYSTEM PRIORITY RANKING By Risk Significance of By Contribution to System Being Unavailable
- Core Damage Frequency' Reactor Protection Emergency Diesel Generators Service Water High Pressure Coolant Injection .... . . . ....... .............................
Automatic Depressurization.
Automatic Depressurization .-... - ..-.---..- ..........-.-.......-....... ..
Diesei Generator and Switchgear Cell Emergency Diesel Generators Ventilation AC Power Standby Liquid Control Battery Room Ventilation Reactor Protection ...-.................-.........-.....................
Service Water Diesel Generalor and Switchgear Ce11 Ventilation Residual Heat Removal DC Power DC Power Residun Heat Removal AC Power Standby Liquid Control Battery Room Ventilation Reactor Core Isolation Cooling liigh Pressure Coolant injection
.-....~............-.~.......-.........-...-...-...
Reactor Water C1eanup"'
Reaetor Waier Cleanup"'
ECCS Actuation Control Rod Drive Hydraulic Control Rod Drive Hydraulic ECCS Actuation Reactor Core Isolation Cooling Screen Wash
- Low Pressure Coolant Injection'" Screen Wash
~ ... . ....... . . .........-
Reactor Building Closed Cooling Water"' Core Spray"'
Reactor Building Closed Cooling Water"'
General Notes:
'The ranking in co:umn I is appropriate to ( < for systems that are functioning normally. It is base Fussell-Vesely Importance Measure, which is the systems's contnbution to the core damage frequ assuming that the system ;s operating with normal reliability.
'The ranking in column 2 is appropriate to use for determining the significance of known system degradation or inoperability. It is based on n,e Birnbaum importance Measure, which indic increase in the core damage frequency that results when the system is assumed to be inoperable.
'The containment system shown on these lists are ranked with respect to their comributions to core da frequency, only. Their importance for accident consequence mitigation was not considered.
' The dashed tines represent significant differences between imponances of systems that are adjac lists. Systems not separated by dashed lines should be assumed to have imponances app equivalent to each other, within the precision of the PRA quantification.
Soccific Notes:
"' Analyzed in PRA together with SLC.
'" Included with RHR system.
"' System not appearing among dominant accident sequence cutsets in the PRA. Therefore sy inspection tables could not be developed for this system. ,
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i Because there is uncertainty 'in the data and medelitig assumptions contained inl PRA, there is also uncertainty with respect to the risk significance of each syl i h ld be thus, uncertainty in their rank order in Table 3. Adjacent systems on the l st s ou l considered to have approximately equal contributions to risk, except where they ha separated by dashed lines to indicate numerically significant differences in their ;
measure values.
- 4. COMMON CAUSE OR DEPENDENT FAILURES In the BSEP PRA, common cause, or dependent, failures are classified into se different categories. Common cause initiating event dependencies are divided in and external event classes.
Internal events include general transients such as loss of off-site power, failure ,
specific de busses (special transients), LOCAs and interfacing system LO directly to core damage. External events include physical interaction i hdepend those resulting from fire, flood and seismic events. Human interaction dependenc es, s as operator failure to initiate systems, etc. are discussed in Section 5 followin It should be noted that loss of the Nuclear Service Water System was consider negligible as an initiating event.
From the results of the BSEP PRA, important dependent failures for the systems affected are as follows:
a) Two or more ADS SRVs fail to open because of o-ring leakage or other dependent failure mechanisms.
b) Diesel generators 3 and 4 fail to start or fail to run.
c) RHR system failures:
i) LPCI Mode
- 1) Loops A and B pumps (C002A,B,C and D) fail to stan or run
- 2) Loops A and B minimum flow MOVs (F007 A and B) fail to open ii) Suppression Pool Cooling (SPC) Mode
- 1) Loops A and B heat exchanger bypass MOVs (F048 A and B) fail to op
- 2) Loops A and B injection MOVs (F028 A and B) fail to open
- 3) Loops A and B injection MOVs (F024 A and B, F027 A and B) fail to open -
d) Standby Liquid Control (SLC) pumps A and B fail to start e) Service Water Systern (SWS) ,
i) 4 or more pumps fail to run ii) RHR heat exchanger MOVs (V105 and V101) fail to open
- 5. IMPORTANT llUMAN ERRORS (Including Recovery Actions)
Human errors can be very significant to overall plant risk. The BSEP PRA has identified several human errors as particularly important contributors to risk:
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5.1 Pre-Accident Errors j
These errors consist of failure to restore components to their proper position after '
testing, maintenance or calibration activities. The most important errors are:
1 a) Failure to restore I&C for valves, F007 A or B, RHR pump minimum flow I recirculation to suppression pool isolation MOVs.
b) Miscalibration of flow switch N021 A or B controlling RHR minimum flow recirculation valves F007 A or B.
5.2 Operator Errors During an Accident These errors pertain to actions identified in the operating procedures which involve manual operation or alignment from the Control Room of components which must be operated manually or have failed to operate automatically. The most important errors are:
1.CRD a) Failure to fully open CRD flow throttling valve F002A b) Failure to fully open CRD pressure regulating valve F003.
- 2. HPCI Operator fails to empty drainpot A. (If drain pot A fails to drain prior to starting th HPCI turbine, a slug of water could be forced through the turbine and out the exhaust line, which will cause water hammer damage and probable turbine trip on high exhaust pressure).
3.ATWS Failure to inhibit ADS and failure to control RPV water level at low pressure.
4.RHR Operator fails to correctly initiate suppression pool cooling through Loop A 5.SLC Operator fails to actuate the SLC system.
5.3 Post Accident Recovery Actions This last category of human errors involves mitigating actions taken by the operators to recover from the effects of an accident. The most imponant of these are the following:
- 1. AC Power Failure to recover offsite power.
- 2. Diesel Generator Room Cooling Failure to open switchgear room doors after HVAC failure.
- 6. SYSTEM INSPECTION TABLES Taken together, the systems ranked by their risk imponance in the first column of Table 3 contribute 95% of the core damage frequency for Brunswick Unit 2. For each of those systems, inspection guidance is provided in the form of a failure mode table, an abbreviated walkdown checklist, and a simplified system diagram. Each of these is explained in detail below.
9
In using these tables, however, it is essential to remember that other systems and components are also imponant. If, through inattention, the failure probabilities of oth systems were allowed to increase significantly, their contributions to risk might q equ exceed that of the systems in the following tables. Consequently, a balanced inspection l program is essential to ensuring that the licensee is minimizing plant risk. The fo are most tables allow an inspector to concentrate on systems and components that significant to risk. In so doing, however, cognizance of the status of systems perform other essential safety functions must be maintained.
APPENDIX A Table A.X System Failure Modes For each system X, a table A.X-1 of system failure modes is provided. The d introduc-tion to these tables provides a brief description of the system and the success criteria use for the system in the PRA. (Note that the PRA success criteria may be different from th success criteria contained in the FSAR.)
The entries in these tables are the dominant events (component failures, operator errors, etc.) contributing to system failure, provided in rank order according to their risk ;
significance. Since most systems are designed with redundant trains, it will generall j more than one of these events to fail the entire system. No effon has been made to list all of the combinations of the events that are sufficient to produce system failure because that is usually apparent from the system description in the introduction. Where single events are sufficient to fail the entire system, that is noted in the brief discussion of the event. For '
l certain events that are important primarily because of the circumstances of a panicular l accident sequence, that information is also noted.
Inspection focussed on the items in the table will address approximately 95% of risk for that system. Because PRAs do not contain the detail necessary to attribute the lis failures to the most probable specific root causes, it is necessary for the inspector to draw from his experience, plant operating history, ASME Codes, NRC Bulletins and Informat Notices, INPO SOEP.s, vendor notices e.nd similar sources to determine how to actually conduct his inspections of the listed items. Where appropriate, codes have been includ following each event description to indicate which licensee programs / activities provid inspectable aspects of the risk. These codes are as follows:
PC-Periodic calibration activities, procedures and training.
PT-Periodic testing activities, procedures and training. -
MT-Preventive or unscheduled maintenance activities, procedures and training.
OP-Normal and emergency operating procedures, chect-off lists, training, etc.
TS-Technical specifications.
ISI-In-service inspection.
10
Table A.X Modified System Walkdown As above, for each system X, a table A.X-2 is included which provides an abbreviated version of the licensee's system checklist, where available, but includes only those items which are related to the dominant failure modes. It is generally much less than the normal checklist. It can be used to rapidly review the line up of important system components on a routine basis. Caution should be observed when using the checklists, since they are based on cenain versions of the licensee's system operating instructions. Valve numbers used are those identified in the licensee system checklists, or P&ID's.
Figure A.X - Simplified System Diagram A simplified line diagram is provided for each system treated. These are intended to aid in visualizing the system configuration and the location of the components discussed in the two tables. The drawing is merely a simplified schematic of the actual P&ID's in effect at the time that the PRA was prepared. It is neither a complete representation of the P&ID's nor is it a controlled document. It was utilized in the preparation of the PRA and any significant differences between this drawing and actual plant conditions may affect the information provided in Tables A.X-1 and A.X-2 and should be reponed to the appropriate NRC personnel. 1 APPENDIX 11 Table ill - Plant Operations Inspection Guidance This table is a collection of all of the risk significant operator actions listed in the preceding system tables. It is provided as a cross reference for use in observing operato actions and training.
Table B2 - Surveillance and Calibration Inspection Guidance This table is a collection of all of the risk significant components listed in the preceding system tables that are considered to be significantly influenced by survei and calibration activities. It is provided as a cross reference to assist in selecting risk important activities for observation during inspections of the licensee's surveillance calibration programs.
Table B3 - Maintenance Inspection Guidance This table is a collection of the risk significant components listed in the preceding
- system tables that are considered to be significantly influenced by maintenance ac i is provided as a cross reference to assist the inspector in selecting risk impoltant a for observation during inspections of the licensee's maintenance program. Important factors include the frequency and duration of maintenance as well as errors that degrade the !
component or render it inoperable when it is retumed to service.
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APPENDIX C Table C1 - Containment and Drywell Walkdown Table Because they are normally inaccessible during operation, a separate walkdown c ,
list is provided for those components listed in the preceding system tables tha inside the containment or drywell. This is intended for efficient inspection of those ite when the opponunity arises.
APPENDIX D Table D1 - Frontline-Support System Dependencies -
In a matrix format, the dependencies of the frontline systems are correlated to th associated support systems. This illustrates the impact failures or outages of suppor .
systems have on the various frontline systems.
Table D2 - Support Support System Dependencies As in Table D1, in a matrix format, the dependencies of the support systems are ,
correlated to other support systems which they interface with. This illustrates the impa failures or outages of support systems have on other support systems.
- 7. REFERENCES i j
- 1. Brunswick Steam Electric Plant Probabilistic Risk Assessment. Raleigh, North !
Carolina: Carolina Power and Light Company, April 1988. l
- 2. B. Wooten and P. Lobner (Editor), " Nuclear Power Plant System Sourcebook-Bmnswick 1 & 2,50-325 and 50-324 " Science Applications Intemational Corp.,
Report No. SAIC 89/1011, January 1989.
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I APPENDIX A l
Importance Basis and Failure Mode Identification Tables and Modified System Walkdown Tables i
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BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-B ASED INSPECTION GUIDE Emergency Diesel Generator (EDS) System Table A.1-1. Importance Basis and Failure Mode Identification CONDITIONS THAT CAN LEAD TO FAILURE Mission Success Criteria Four DG sets are located in the Diesel Generator Building (DGB) east of the plant.
Unit 1 is generally served by DGs 1 and 2 through emergency buses El and E2 whil 2 is generally served by DGs 3 and 4 through emergency busesinE3 theand OPENE4. Tie bre allow interconnection of the emergency buses; however, they are left RACKED-OUT position to prevent paralleling of opposite division emergency power sources. Two of the Unit 2 RHR pumps and both LPCI injection valves are powered by Unit I emergency buses.
Each DG set consists of a General Electric generator driven by a Nordberg diesel engine, with a Woodward load-sensing type govemor to maintain v eengine and generat DGB, except speed. Auxiliary systems and components for each DG are also located in as noted. The DG systems for BSEP Units 1 and 2 are identical. The auxiliary systems f each DG are:
- 1. diesel engine air intake and exhaust system,
- 2. diesel engine fuel oil system,
- 3. diesel engine starting air system,
- 4. diesel engine cooling system,
- 5. diesel engine lube oil system
- 6. diesel generator jacket water system,
- 7. governor, and
- 8. generator.
The success criteria in the PRA for the DGs is to start on demand and provide electrical power for a six-hour mission time. DGs 3 and 4 can provide emergency ac power to buses E3 and E4. Only one of these DGs is required to provide emergency power.
six-hour mission time was determined based on considerations of off-si.'e power recovery.
- 1. Diesel Generators 1.2.3 or 4 Fail to Start or Run Under loss of offsite power conditions, failure of the diesels to stan or run causes loss.of all AC power (PT, MT)
A-1
It should be noted that an extended loss of offsite power incident occurred at BS 17,1989 in which the diesel generators were required to beginning on the evening of June operate for a period of approximately 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> to provide power to Unit 2. T the importance of EDGs failing to run.
- 2. Diesel Generators 1,2,3 or 4 in Test or Maintenance Similarly, unavailability of the diesels due to test or maintenance, TS). combined w other failures, fails all AC power under loss of offsite power conditions (PT,MT,
- 3. Diesel Generators 1,2,3 or 4 Generator Output or Output Breaker Failure _
No power output from the diesel generators or failure of the output breaker .
all AC power under loss of offsite power conditions (PT,MT). -
Note:
Other significant DG related failure modes are identified for the DG Cell -
Ventilation, Battery Room, and Switchgear Cell Ventilation AC Power and Service W Systems. BNL has developed a proposed specific inspection guide for dies is provided in Table A.1-3.
O
_ A-2 l
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 :
RISK-H ASED INSPECTION GUIDE ;
Emergency Diesel Generator (EDG) System TABLE A.12 MODIFIED SYSTEM WALKDOWN Pow. Sup. Required Actua! l Desired Actual Breaker # Location Position Position ID No. Location Position Position Description
- Diesel Gener. Neutral '
Diesel Gen.1 stor Bldg.-
- Circuit Breaker Gen. Control Control Switch Panet DG.
Cell 1
- Diesel Gener- Neutral i 4160V System stor Bldg.-
Circuit Breaker Gen. Control Control Switch Panel DG. l Cell 1
- Diesel Gener- Neutral Diesel Gen. 2 ator Bldg.-
Circuit Breaker Gen. Control Control Switch Panel DG.
Cell 2
- Diesel Gener- Neutral f' 4160V System ator Bldg.- ,
Circuit Breaker Gen. Control Control Switch Panel DG.
Cell 2
- Diesel Gener- Neutral Diesel Gen. 3 stor Bldg.-
Circuit Breaker Gen. Control Control Switch Panet DG.
Cell 3
- Diesel Gener. Neutral
- 4160V System ator Bldg.-
Circuit Breaker Gen. Control Control Switch Panel DG.
Cell 3 l
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L BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 :
RISK-BASED INSPECTION GUIDE t Emergency Diesel Generator (EDG) System TABLE A.12 MODIFIED SYSTEM WALKDOWN (Cont'd)
Required Actual Desired Actual Pow. Sup.
Location Position Position Position Breaker #
Desenption ID No. Location Position
- Diesel Gener. Neutral Diesel Gen. 4 stor Bldg.-
Circuit Bresker Gen. Cont.ol ,
Control Swi:ch Panet DG, Cell 4
- Diesel Gener. Neutral 4160V System ator Bldg.-
Circuit Breaker Gen. Control Control Switch Panel DG, Cell 4 General Actua. 1,2,3&4 D.G.
tion Signal Rooms 4
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- Check latest surveillance test to assure that any unsatisfactory items have been corrected. \
I A-4
TABLE A.12 (Cont'd)
REFERENCE DOCUMENTS TITLE ID.NO. REV DATE Systems Procedures:
Diesel Generator Operating Procedure OP-39 040 9/22/88 System
Description:
Brunswick PRA Volume I Section M.3.4.10
" Emergency Diesel Generators" P&ID's No.:
Brunswick PRA Volume I Fig. M.3.4-20 "DG Simplified Diagram" e
9 A-5
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE Emergency Diesel Generator (EDG) System Table A.1-3. Proposed Inspection Plan for Diesel Generators at Nuclear Plants A. Objective To review and evaluate Diesel Generator design operation, and maintenance at NPP to ensure that the DGs will be available when needed to power safety systems.
B. Details .
- 1. The inspection of the following items should focus on DG auxiliary systems as follows: Fuel Injection System, Turbocharger, Starting System, Speed / Load Con -
trol, Cooling Watcr, Lube Oil, Fuel Oil, Control and Monitoring Systems, and Generator.
- 2. Using the LER,50.55e, and Part 21 systems computer printout and select 3 r failures (within 2 years) for followup at the NPP. When at the plant select an additional 2 failures from the internal systems. Evaluate the licensee's response to these failures for proper failure analysis, corrective action, notification of vendor, Part 21 evaluation and documentation.
- 3. Maintenance: Refer to IE I.P.s 62700 and 62702, as they apply to DG mainte nance. Additionally, does the NPP have, and have they implemented the DG vendors' maintenance recommendations (especially those recommendations unique to nuclear service DGs such as Colt's described in NSAC-79)? Ar maintenance personnel specially trained on DGs? Is failure information fed into maintenance program? Has the NPP implemented recommendations of ous studies referenced in Section 4 above.
- 4. Design Change Control: Select two DG modifications and verify proper im mentation. Utilizing information from DG vendor inspection on modifications recommended, verify that NPP is receiving all pertinent information in this area from the vendor. (Reference IE I.P. 37700).
- 5. Spare Parts and Procurement: Review how spare parts and services .
and parts stored, both from DG vendor and direct from subvendor. Ver adequate Part 21 and QA, particularly when vendors are only supplying and co cial grade parts and services (e.g., Woodward Governor and Stewart '
Stevenson). Verify ASME code specified where appropriate. Tour spare parts storage area. (Reference IE I.P. 38701B).
- 6. Training: Ensure appropriate DG specific training given to maintenance, opera-tions, QA, and management personnel. Are there adequate documents to d DG operation onsite moth main engine and auxiliary system)? (Refere 41700).
A-6 l 1
- 7. Observe DGs in operation. Ensure they run smoothly and are operated per procedure. Look for abnormal vibration and leaks (air, fuel oil, or lube oil). Check that readings are within specified limits. Are limits per DG vendor recommenda-tions? Are recommendations clearly specified? Is air quality in DG room satisfac-tory without excenive dust? Are control cabinets properly gasketed? Are instru-ments calibrated? Is trending of operating deta performed to detect degradation early?
- 8. Is NPP receiving all appropriate service information from vendor: design, mainte-nance, operational, etc? This is especially important for General Motors DG j owners (verify they receive " Power Pointers" from GM). l l
- 9. Review site practices to limit DG cold fast starts.
- 10. Reliability records and calculations: Check logs, procedures, and calculations ;
versus Reg. Guide 1.108 criteria.
- 11. Ensure that pertinent studies on DG performance have been reviewed and recom-mendations implemented as appropriate (e.g., NUREG/CR-0660 and NSAC-79).
- 12. Torquing: Ensure plant has adequate specifications for all torquing. Ensure it h l documented and done with calibrated equipment. Observe re-torquing if in pro-I gress.
l 1 Source l J.C. Higgins and M. Subudhi,"A Review of Emergency Diesel Generator Performance at Nuclear Power Plants," NUREG/CR-4440, Brookhaven National Laboratory, November 1985.
References
- 1. NSAC-79, "A Limited Performance Review of Fairbanks Motse and General Motors Diesel Generators at Nuclear Plants," Nuclear Safety Analysis Center, Electric Power Research Institute, April 1984.
- 2. G. Boner and H. Hanners, " Enhancement of Onsite Emergency Diesel Generator Reliability," NUREG/CR-0660, University of Dayton, February 1979.
A-7
GENERIC P&lD DG 1, 2, 3, & 4 m arrun P0 6
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=c = c . -
$= " '.m.. (%)g.oai'"p_4, _.i .
scu.s 8LJ 11/2Ut6 Fig. A.1-1 (PRA Fig. M.3.4 20). DG Simplified Diagram.
CAUTION: This is NOT. a controlled document.
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i IIRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE High Pressure Coolant Injection (HPCI) System Table A.2-1 Importance Basis and Failure Mode Identification i f
CONDITIONS TilAT CAN LEAD TO FAILURE !
j Mission Success Criteria The High Pressure Coolant Injection (HPCI) System, an Engineered Safeguards ,
excessive fuel cladding
- System, serves to provide sufficient core cooling to prevent temperatures in the event of a small line break of any unisolatable line directly associated with the nuclear boiler. It is designed to operate and maintain the reactor core covered when reactor pressures are high and the break area is small (up to five inches in diameter).
The success criterion for the HPCI system is the availability of the system to inject 4250GPM into the reactor vessel in accordance with technical specification requirements using the HPCI pump with flow through injection valve F006 for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
f HPCI consists of a 100% capacity single train with DC motor-operated valves and a steam turbine-driven pump.The normal water supply is from the condensate Storage Tank (CST). If the CST level decreases to a predetermined level, or the suppression pool level rises above a predetermined level, pump suction is automatically transferred to the suppression pool. Injection to the reactor vessel is into the A feedwater line (through valve F006) and is distributed through the feedwater spa:gers.
- 1. HPCI Pump or Turbine Fails to Start or Run Since HPCI is a single train system, failure of the pump or turbine to start or run l prevents HPCI flow (PT,MT).
- 2. HPCI Pump or Turbine in Tests or Maintenance As above, unavailability of HPCI for test or maintenance prevents HPCI flow.
- 3. Failure of Level Switch LEN014 Since LEN014 monitors the level in Drain Pot "A", failure of this switch can cause a water slug to the HPCI turbine. (PC,PT,hfr).
- 4. Operator Failure to Override Steam Tunnel High Temperature Trip l l
During station blackout scenarios, early isolation of the HPCI turbine on high steam tunnel temperature will occur automatically unless overridden by the operators. l Failure of the operators to override when required can lead to core damage (OP).
l A-9 l
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- 5. Normally Closed HPCI Pump Discharge Isolation MOV F006 Fails Closed Failure of MOV F006 to open when required prevents HPCI flow to the feedwater injection line (PT,MT).
Through the Mini-Flow Line Due to MOV F012 Failing to Open Failure of F006 to open in a timely manner together with insufficient flow through the minimum flow line resulting from isolation MOV F012 failing to open will cause failure of the HPCI pump due to deadheading (PC,PT,MT).
- 7. Failure of Normally Closed Steam Supply Isolation Valve F001 to Open .
Failure of MOV F001 to open when required prevents steam flow to the HPCI turbine (PT,MT). .
- 8. Failure of Lube Oil Cooling The HPCI pump discharge provides cooling water flow to the turbine lube oi cooler. Failure of this cooling system will cause HPCI turbine failure (PT,MT).
- 9. Failure of the Vacuum Breaker on Startup Causes Insufficient Steam Flow fro the Turbine Valves F075,76,77 and 79 form a vacuum breaker on the steam line to the suppression pool. If the breaker fails when HPCI initiates, condensing steam vacuum which will draw water from the suppression pool into the steam discharge This causes a trip on high exhaust line pressure and/or water hammer will rupture th discharge piping (PT,MT).
- 10. Insufficient Flow From HPCI Pump Discharge Line Insufficient flow through the HPCI pump discharge line can be caused by failure of check valve F005 to open or by normally open MOV F007 failing closed (PT,MT
- 11. Operator Fails to Empty Drain Pot "A" If drain pot "A" fails to drain prior to starting the HPCI turbine, a slug of water could be forced through the turbine and out the exhaust line, thereby causing water ha . ,
and HPCI turbine trip on high exhaust pressure (OP).
- 12. Failures in Pipe Segment Leading From Drain Pot "A" .
Failure of DC solenoid AOVs F028 and F029 to open when required could cause a slug of water from Drain Pot "A" to be forced through the turbine, thereby caus hammer and HPCI turbine trip on high exhaust pressure as in 9 above (PT,MT).
A-10
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE ,
High Pressure Coolant Injection (HPCI) System ;
TABLE A.2 2 MODIFIED SYSTEM WALKDOWN
)
Actual Pow. Sup. Required Actual Desired Position Breaker # Location Position Position .
Description ID No. Location Position i 125V DC On >
HPCI T.D. Dist. Panel l Pump
?
13 4A j Control and
. Relay Logic 14 CSS PNL On Level SW 2.G-41 2 A.RX Drain Pot A LSH- ;
EL 20' N014-1 120V AC Compart. MCC On MOV injection F006 Control Closed Roorn ment B-17 2XDA t Valvs Control EL 20' Sw'..ch (SS) Panel P601 4 120V AC* On (Heater) Dist. l 2DX EL f Comp. MCC On i MOV Control F091 Control closed '
Room B-21 2XDA
" witch (S3) EL 20' Panel P601 8 120V AC On (HTR) Dist. Pnl. ;
2DXA El 17' Comp. MCC On l MOV Control F012 Control Closed Room B-16 2XDA l Switch EL 20' Panet P601 Comp. 120V AC On B 24 Dist. Pnt.
2XDA EL 17' il 120V AC On (HTR) Dist. Pnt.
2DXA EL 17 A-Il 1
HRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE High Pressure Coolant Injection (HPCI) System TABLE A.2 2 MODIFIED SYSTEM WALKDOWN (Cont'd)
Required Actual Desired Actual Pow. Sup.
Location Position Position Breaker #
Description ID No. Location Position Position Comp. MCC on Lube Oil Cool- Reactor B 11 2XDA ing System Bldg. EL EL 20 .
20' 12 120V AC On
- Aux. Oil Pump HTR Dist. Pnt.
2DXA N/A MCC Stop Local Control Switch 2XDA B Il N/A MCC Nonn Key Lock Switch 2XDA B-11 MCC Vacuum Panet 2XA P601 Breaker EL 20' Control Room Comp.DE MCC On F075 Open MOV 2 2XA EL 20' l
7 120V Dist. On l
HTR Panet HS3 EL 20' MCC On Open Corr.p.
MOV F079 Panel DQO 2XB
- Pool EL 20' Control Room 24 On F079 MCC Norm Key Lock Lo- HTR cal Sw. 2XB DT 2 MCC Off ASSD Feed 2XC A-12
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BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK BASED INSPECTION GUIDE High Pressure Coolant Injection (HPCI) System TABLE A.242 MODIFIED SYSTEM WALKDOWN (Cont'd)
Actual Pow. Sup. Required Actual Desired Position Breaker # Location Position Position Des.:ription ID No. Location Position 3 120V AC On MOV F007 Panel Open P601 Dist. Panel Control 2DXA ,
Room Open i F028 Panel Open AOV RI A. HPCI Roof MOV P601 IV EL 4' Control 203 & 103 Room RI A-IV HPCI Roof Open MOV F029 Panet Open P601 202 & 102 EL 4' Control Room 3
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A-13
l TABLE A.2 2 (Cont'd) ,
REFERENCE DOCUMENTS I.D. NO. REV DATE TITLE System Procedures:
OP-19 060 8/11/88 High Pressure Coolant Injection System System
Description:
Section M.3.4.3 Brunrvick PRA Volume I "High Pressure Coolant injection System" P&ID's No.:
Fig. M.3.4-3 Brunswick PRA Volume 1 Sheets 1-3 "HPCI Simplified Diagram"
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BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE Automatic Depressurization System (ADS)
Table A.3-1 Importance Basis and Failure Mode Identification CONDITIONS TilAT CAN LEAD TO FAILURE Mission Success Criteria The Automatic Depressurization System (ADS) is an engineered safeguards system.
As a Core Standby Cooling System (CSCS),it serves as a backup for HPCI. Should .
fail during loss-of-coolant accident (LOCA) conditions from a small line break, th depressurizes the nuclear system so that the Low Pressure Coolant Injectio Spray Systems (CSS) can operate. ADS is designed to depressurize the r sufficient time to allow LPCI or CSS to provide core cooling to prevent excessive fu cladding temperatures.
There are 11 safety-relief valves (SRVs) (B21-F031 A through L, excluding I) ass ated with reactor pressure vessel overpressure protection. Seven of these 11 valve F013A, C, D, H, J, K, and L, are used in the ADS. When open, each valve discharge l through a separate line to a point below the minimum water level of the suppress The success criterion for the ADS is two of seven ADS valves operating success to depressurize the RPV until the LPCI and/or CSS can be used.
The analysis given by the report Determination of the Minimum Number of S Relief Valves for Brunswick Boiling Water Reactor Depressurization (Nuclear Safe CP&L) was considered. The analysis was done using the RELAP5 MOD 2 comp determine if one SRV with CCS is sufficient to prevent core damage. The sequence analyzed was one in which a transient event is followed by a scram with los pressure systems that would normally be available open, pressure would be reduced to 350 psia within 16.67 minutes with no problems. '
Also analysis given by GE, document NEDC-30936-P, dated November 198 Owner's Group Technical Specification Improvement Methodology (With Demons -
1, was considered. The GE analysis For BWR ECCS Actuation Instrumentation) Part showed two SRVs are required to depressurize the vessel below the shutoff hea pressure systems in time to provide adequate core cooling.
Therefore, using the conservative approach given by the GE document, it is that two of the seven ADS valves must operate.
A-18
- 1. O-Ring Leakage or Other Dependent Failure Mechanisms Cause Two or More ADS SRVs Failing to Open Dependent, or common cause, failure is most likely to cause ADS failure when required. Such failures can be caused by a 0-ring leakage of the ADS SRVs (PT,MT).
9 9
I I
A-19 I
f BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 !
RISK-BASED INSPECTION GUIDE Automatic Depressurization System TABLE A.3 2 MODIFIED SYSTEM WALKDOWN Pow. Sup. Required Actual Desired Actual Position Breaker # Location Position ID No. Location Position Position Description
- D.C. Solenoid Valves . 4 i
11 Control Bldg. On
- ADS Relay H12- Dist. Pni. 4B. 1 i
i Logic A&B P628 EL 49' .
125V D.C.
11 Control Bldg. On Fluid Flow De- CB-X4- Dist. Pn1. '
tector Cabinet 73 32B EL 49' Emer. 125V AC 3 Same On Relay Logic A E 11 Panel 4A i !
11 Same On Relay Logic B N/A ,
l 36 Cont, Bldg. On l
Control Electronic Normal ;
Logic B Power Panet Equip. i Pnl. 2AB Sup. Isol. H12- Room EL !
Switch P628 49' I c
I 1
l l
could affect all eleven relief valves, this
- Note: Since "O" ring leakage is a common cause event that walkthrough should assure that this matter is currently addressed in existing maintenance procedu 1
1 A-20 1
1 i
e =. .-
TABLE A.3 2 (Cont'd)
REFERENCE DOCUMENTS 1.D. NO. REV DATE TITLE System Procedures:
OP-20 003 3/28/88 Automatic Depressurization System
Description:
Section M.3.4.6 Brunswick PRA Volume 1
" Automatic Depressurization System" P&ID's No.:
Fig. M.3.4-9 Brunswick PRA Volume 1
" ADS Simplified Diagram" Sheets 1 & 2 I
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BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-B ASED INSPECTION GUIDE Diesel Generator and Switchgear Cell Fans Table A.4-1 Importance Basis and Failure Mode Identification CONDITIONS TilAT CAN LEAD TO FAILURE Mission Success Criteria Diesel Generator and Switchgear Cell Fans The supply air flow to the various cells is one of the major differences between the LOOP and other upset condition branches. For the LOOP events, supply flow requires three fans to be operational. Since only one fan is operating, this implies that the temperature sensing circuitry to automatically start the additional fans is functional. For all other upset conditions, only one fan is required.
The other condition required for successful cooling is that there is a flow path from the supply fan (s) into the cell and a flow path out of the cell. This requires that the supply dampers, exhaust dampers, exhaust fans, and control circuitry all function correctly. This requirement is considered to be very conservative.
The mission time is 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Credit was taken in the PRA for the fourth supply fan for LOOP conditions, even though abnormal operating procedures do not address its use. Credit was also taken for SWGR cell cooling recovery by opening of doors. Because of the limited heat generation in these cells, opening the doors will create enough circulation to keep the cells from overheating.
- 1. Supply and Recirculation Damper Faults for Diesel Generator Cells 3 or 4 Faults in the supply and recirculation dampers for DG Cells 3 or 4 will cause overheating of the cells (OP,MT).
- 2. Operator Failure to Open Switchgear Rooms After an HVAC Failure
- Opening of the Switchgear Room doors after a failure of the HVAC system can create enough circulation to keep the cells from overheating. Operator failure to take this action will cause the cells to overheat (OP).
A-23
- 3. Insufficient HVAC Flow Through Switchgear Rooms E3 and E4 Due to Faults in ,
8 the Supply or Exhaust Dampers or Fans Faults in the supply or exhaust dampers or fans will cause insufficient HVAC flow through Switchgear Rooms E3 and E4. (OP, MT).
- 4. Exhaust Damper Faults for Diesel Generator Cells 3 or 4 Faults in the exhaust dampers for DG Cells 3 or 4 will cause overheating of the cells (OP,MT),
- 5. Power Not Avaihble to Diesel Generator Cells 3 and 4 Exhaust DGC and MCC DGD_
As in 4 above, no power to the exhaust dampers for DG cells 3 and 4 will cause overheating of the cells (OP, MT). .
- 6. Control Circuit Fails to Provide Actuation Signal to Diesel Generator Cells 3 and 4 Supply and Recirculation Dampers Failure of the control circuit actuate the DG cell supply and re .:irculation dampers can cause overheating of the cells (PC, MT).
Note: When the PRA was generated, the Switchgear Room HVAC System was dependent upon the Instmment Air System. Since that time, plant modifications have bee eliminate this dependency. Therefore, faults in the supply or exhaust dampers or fan should be relatively less probable than the original results. (These faults are shown i original order of probability.)
l l
A-24 l
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-B ASED INSPECTION GUIDE Diesel Generator and Switchgear Cell Fans TABLE A.4 2 MODIFIED SYSTEM WALKDOWN Actual Pow. Sup. Required Actual Desired Position Breaker # Location Position Position Description ID No. Location Position i
1 Comp.No. DG Bldg.- Closed :
Supply Fan DJ7 MCC DGC-El.
CSF-DG for 23'-DG Cell DG Cell 3 No.3 DJ7 DG Bldg.- Normal
, Supply Fan MCC DGC-El.
Normal /
CSF-DG for Local Se- 23'-DG Cel!
DG Cell 3 No.3 lector Switch DJ7 Local DG Bldg.- Stop Supply Fan Control MCC-DGC-El.
CSF-DO for Switch 23'-DG Cell DG Cell 3 No.3 Comp. No. DG Bldg.- Closed i Exhaus Fan G- MCC DGC El. ;
DJ6 '
EF-DG for DG 23'-DG Cell Cell 3 No.3 DJ6 DG Bldg.- Normal Exhaust Fan G-Normal / MCC-DGC El.
EF DG for DG 23'-DG Cell Local Se-Cell 3 lector No.3 Switch DJ6 Local DG Bldg.- Stop Exhaust Fan G-Control MCC DGC-El.
EF-DO for DG Switch 23'-DG Cell Cell 3 No.3 Comp.No. DG Bldg.- Closed Supply Fan A. MCC-DG A El.
DR7 SF-DO
Local Se- 23'-DG Cell 1 lector Switch ,
DR7 Local DG Bldg.- Stop Control - MCC-DG A-El.
Switch 23'-DG Cell 1 A-25 1
=
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK B ASED INSPECTION GUIDE Diesel Generator and Switchgear Cell Fans TABLE A.4 2 MODIFIED SYSTEM WALKDOWN (Cont'd)
. Required Actual Actual Pow. Sup.
Desired Location Position Position Breaker #
Description ID No. Location Position Position Closed Comp.No. DG Bldg.-
Supply Fan D68 MCC DGD-El. ,
D.SF-DG Circuit 23'-DG Cell -
Breaker No.4 DG Bldg.- Normal -
D68 Normal / MCC-DGD.El.
D-SF-DG Switch 23'-DG Cell No.4 Closed Comp.No. DG Bldg.-
Exhaust Fan D59 MCC DGD-El.
H-EF-DG 23'-DG Cell DG Cell 4 No.4 DG Bldg.- Normal D59 Exhaust Fan Normal / MCC-DGD-El.
H.EF-DG Local Se- 23'-DG Cell
. DG Cell 4 lector No.4 Switch DG Bldg.- Stop D59 Local Exhaust Fan Control MCC-DGD-El .
H EF DG Switch 23'-DG Cell DG Cell 4 No.4 DG Bldg.- Closed D51 Eahaust Fan MCC DGD-El.
D-EF-DG for 23'-DG Cell 4160V SWGR No.4 Rm E-4 e
e A-26 l
g
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE Diesel Generator and Switchgear Cell Fans TABLE A.4 2 MODIFIED SYSTEM WALKDOWN (Cont'd)
Desired Actual Pow. Sup. Required Actual [
Position Breaker # Location Position Position Description ID No. Location Position Comp.No. DG Bldg.- Closed Supply Fan DZ9 MCC-DGB El.
B-SF-DG :
23' DG Cell No.2 DZ9 DG Bldg.- Normal Normal / MCC-DGB-El. t Local Sc. 23'-DG Cell I lector No.2 l
Switch DZ9 Local DG Bldg.- Stop l i
Control MCC-DGB.El.
Switch 23'-DG Cell ;
r No.2 6 Unit 2 Con- Closed DG Cell No.
trol Bldg.
1&3 Damper '
Panel 2-32A-Control Power !
El. 23' 6 Unit 2 Con- Closed DG Cell No. trol Bldg.
2&4 Damper Panel 2 32B- ,
Control Power El. 50' l
s Y
t A-27 l I
. - - - - - _ _ = _
i BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 '
RISK. BASED INSPECTION GUIDE !
i Diesel Generator and Switchgear Cell Fans !
TABLE A,4 2 MODIFIED SYSTEM WALKDOWN (Cont'd) !
Pow. Sup. Required Actual i Desired Actual Location Position Position Location Position Position Breaker # ,
Description ID No.
I Comp.No. DG Bldg.- Closed l i
Exhaust Fan DOS MCC-DGC-El.
C-EF DG for [
23'-DG Cell , ,
4160V SWGR No.3*
E-3 i
. I i :
i i ?
l
- Loss of In- I strument Air to ;
Supply and Re-circulation l Damper l 1 1
I l l t i
L I
L t
k a
li l
I i
I
' As shown on Figure A.4-1. t
- Loss of lastrument air supply can cause damper failure to open; check to be sure instrum l
< E l
srpply damper.
?
5 l
e A-28 I
-- -- _ ~ . _ . . _ . _ . _,
I I
TABLE A.4 2 (Cont'd)
REFERENCE DOCUMENTS TITLE 1.D. NO. REV DATE l System Procedures:
)
Diesel Generator Building Heating & Ventilation OP-37.4 012 4/21/88 System System
Description:
Brunswick PRA Volume I Section M.3.4.16
" Heating, Ventilating and Air Conditioning Systems" P&ID's No.:
1 Brunswick PRA Volume I Fig. M.3.4-33 "DG and SWGR Cell Cooler Detailed Diagram" S
9_
A-29 l 1
~ - - - - - - - _ _ _ _ - _ - _ _ _ . - _ - - _ _
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE Standby Liquid Control (SLC) System Table A.5-1 Importance Basis and Failure Mode Identification CONDITIONS TilAT CAN LEAD TO FAILURE Mission Success Criteria r
The SLC system consists of a storage tank containing a neutron absorbing (sodiumpentaborate), two full capacity pumps, a test tank, a drain tank, a .
piping, valves, instrumentation and controls.
The system is placed in operation by manual operation of a control switc RTGB. Control switch operation stans the selected pump, causes d isolatestwo the explosi to open establishing a flow path from the storage tank reactor vessel through a single injection line feeding the poison sparger in the lo plenum of the teactor vessel. Shutdown occurs within one to two hour injected.
SLC operation is successful if sufficient sodium pentaborateSLC solution occurs from th; tank is injected into the reactor vessel through both pump loops. Failure of the !
if one of the following occurs:
- 1. Faults in the injection line between the explosive (squib) valves and the reactor vessel.
- 2. Either pump loop fails.
- 3. The storage tank or piping to the SLC suction valves fails.
l
- 1. Operator Fails to Actuate the SLC System Since the SLCS can only be initiated manually, and given the operator reluctance utilize the system because of the injection of sodium pentaborate into the re -
failure of the operator to initiate the system is the most likely failure mode (OP).
- 2. Normally Open Reactor Water Cleanup MOV G31-F004 Fails to Close .
Failure of RWCU MOV F004 to close when required will cause flow diversi the SLC pump discharge (PT,MT). i A-30
l
- 3. Faults in the SLC Injection Line from the Squib Valves to the Reactor Vessel Faults in the pipe segment between the squib valves and the reactor vessel such as failure of check valves F006 and F007 to open, will prevent SLC flow to the vessel. This segment is subjected to periodic testing only during refueling outages. (PT,MT).
- 4. Plugging of Locked Open Manual Valve F001 at the SLC Tank Plugging of valve F001, which is adjacent to the SLC tank, and is in the single line from the tank to the SLC pumps, prevents all SLC flow (PT, MT).
- 5. SLC Pumps A or B in Test or Maintenance' Unavailability of the SLC pumps A or B due to test or maintenance prevents SLC flow (PT.MT,TS).
- 6. SLC Pumps A or B Fail to Start or Run' SLC flow is prevented by failure of the SLC pumps A or B to start or run (I'T, MT). .
- 7. SLC Pumps Bypass Relief Valves F029A or F029B Fail to Close' Failure of either SLC pump bypass relief valve F029A or F0298 prevents SLC pump flow to the reactor vessel (PT,MT).
' Note: When the PRA was generated, it was assumed that enriched sodium pentaborate would be used, thereby requiring only one of two SLC pumps to operate. It has since been decided not to utilize the enriched solution, thereby requiring successful operation of both SLC pumps. This significantly increases the imponance of pump unavailability.
a 9
A-31
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE Standby Liquid Control (SLC) System TABLE A.S.2 MODIFIED SYSTEM WALKDOWN Required Actual Actual Pow. Sup.
Desired Location Position Position Breaker #
Description ID No. Location Position Position MCC ZXDB On Open RWCU 1sola. G31 125/250V DC -
tion MOV F004 Reactor Locked SCL Sior. Tank C41- Open F001 Bldg.
- Outlet Isol.
SLC Con-Valve (Manual) trol Sta-tion EL.
80' C41 Same Locked SLC Outboard Open injection Valve F005 (Manual)
C-41 Inside Locked SLC Inboard Open Drywell injection Valve F008 EL. 38' AZ 206*
120V AC On 11 C-41 Control Locked SLC Pump Panel 2AB
- Room Stop EL. 23' (Sup.
Control Switch CS.S1
. Panet ply Bkr.)
H12 P603 Same On 12 t
.. t A-32
BRUNSWICK STEAM ELECTRIC PLANT-ONIT 2 RISK BASED INSPECTION GUIDE Standby Liquid Control (SLC) System TABLE A.5 2 MODIFIED SYSTEM WALKDOWN (Cont'd) ,
Actual Pow. Sup. Required Actual Desired Position Breaker # Location Position Position Description ID No. Location Position
- Comp. 480V MCC On SLC Pump 2A - -
EG6 2XG EL. 80' 6
2 480V MCC On (HTR) 2XG EL. 80' ,
- Comp. 480V MCC On SLC Pump 2B - _
EK2 2XH EL. 80' .
2 480V MCC On (HTR) 2XH EL. 80' ,
I i
I A-33
e i
I TABLE A.S.2 (Cont'd)
REFERENCE DOCUMENTS I.D. NO. REV DATE TITLE System Procedures:
OP-05 026 9/23/88 Standby Liquid Control System Syst:m
Description:
Section M.3.4.9 Brunswick PRA Volume I ,
" Standby Liquid Control System" P&ID's No.:
Fig. M.3.4-18 Brunswick PRA Volume I "SLC Simplified Diagram" e
eut 9
1 9
F A-34
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Fig. A.5-1 (PRA Fig. M.3.4-18). SLC Simplifi-d Diagram. j CAUTION: This is NOT a controlled document.
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-ilASED INSPECTION SYSTEM Reactor Protection System (RPS)
Table A.6-1 Generalized Inspection Plan Discussion The Brunswick PRA does not model the Reactor Protection System (RPS) in any detail. RPS clectrical failure and mechanical failure on demand were assigned value OE-5 and 1.0E-5, respectively, i.e., the system was simply treated as a data value. N -
dominant failure modes are determined. A generic inspection plan is adapted and di below. .
System Description
The Reactor Protection System initiates protective action when the integrity of the nuclear fuel or the nuclear process barrier is threatened. Two types of protective actio available:
A. Reactor scram B. Manual select rod insert (Unit 2 only)
The Reactor Protection System (RPS) contains two independent, fail-safe trip systems, each of which controls the continuity or discontinuity of electrical power to one of the two solenoid-operated scram pilot valves associated with each control rod.
The Alternate Rod Injection System provides a path for reactor shutdown which is diverse and independent from the Reactor Protection System. It is common to the shutdown components only in the scram inlet and discharge valves, the control rod and the control rods themselves. The automatic signal to initiate the ARI function w come from high reactor vessel pressure or low reactor vessel water level.
ARI System logic uses existing recirculation pump trip initiation instrumentation high reactor vessel pressure serpoint will be such that a nonnal scram should been initiated at the time its setpoint is reached, and the low reactor vessel water l setpoint will be set lower than the reactor vessel low water level scram set .
System performs a function redundant to the backup scram system, althoug System has a different design basis. The ARI System is not redundant in itse .
Inspection Areas
- 1. Review and witness RPS function surveillance tests and preventive maintenance.
-include witness of partial manual scram test, single rod scram, tests of individual RPS channels, and RPS circuit breaker and motor generator set preventive mainte Dance.
A-36
- References include: NRC R.G.1.22, " Periodic Testing of Protection System Actua-tion Function," for RPS and RRCS; R.G.1.118, " Periodic Testing of Electric Power and Protection Systems," which endorses IEEE Std 338-1977, " Criteria for Periodic Testing of Nuclear Power Generating Station Safety Systems," for ARI only.
- Detailed guidance for review of LPRM and APRM calibration is contained in NRC Inspection Procedures 61703 and 61704.
- 2. Inspect sensing instrument racks for correct valve configuration, labelling, and separa-tion.
- 3. Ensure no abnormal RPS alarms in the control room, and verify bypass conditions are properly logged and justified.
- 4. Check RPS panels for jumpers and lifted leads. Documentation of same with the appropriate review and approval is required.
- 5. Review post work testing of RPS maintenance tasks.
- 6. Review calibration records of RPS sensors and compare results to Brunswick technical f specifications. Observe trends.
- 7. Review qualifications and training for technicians performing testing and/or mainte-nance on the system.
- 8. Review control rod drive mechanism maintenance inspection procedure and results.
Ensure trending of detected wear is performed.
- 9. Review preventive maintenance practices for solenoid operated valves located in the instrument air header and at the HCU scram inlet and outlet valves.
- 10. Review surveillance and maintenance of ARI instruments.
I t
A-37
TABLE A.61 (Cont'd)
REFERENCE DOCUMENTS 1.D. NO. REV DATE TITLE System
Description:
SD-03 014 8/29/88 Unit O-Reactor Protection System including Volume II Alternate Rod injection System O
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A-38
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nett la 12 contacts for tuttime caerrol valve rest Cleeure Trip Arpass are la Datt he. 2 cirrait.=.y only, c .. .> u . - .t m a.m.
Fig. A.6-1. Reactor Protection System--Schematic Diagram of Logics in One Trip System (SD-03, Rev.14, Fig. 3-1).
CAUTION: This is NOT a controlled document.
A-39
.il 1
T4CIC "A" IocIC "B"
- ,, , , t i , ,
= = PRESS. = = LEVEL
. PRESS. - LEVEL "" N025A-2
= = N0258-2 " " NO45C
= =N045D '
i
.- PRESS. - IZvEL
. PRESS. LEVEL "" NO24A-2
"" NO2 43-2 " " N045A
"" N0455 J k i
K46A K46C N K463 K460 I
i 1
.=
n=
REMY K46A TRUS Pt.*,MP "A" "A"
EMY K463 TRDS PUMP ' '
"B" RELAY K46C TRDS PUMP "B" RELAY K46D TRDS PUMP .
i Fig. A.6-2. Recirculation Pump Trip (ATWS)/ Alternate Rod Injection L Rev.14, . Fig. 3-11).
CAUTION: This is NOT a controlled document.
A-40 1
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PART OF DWG NO. LL-9046 SH AH-6 V TO ARI VALVES Fig. A.6-3. Altemate Rod Injection Logic (SD-03, Rev.14, Fig. 3-12).
CAUTION: This is NOT a controlled document.
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE Service Water System (SWS)
Table A.7-1 Importance Basis and Failure Mode Identification CONDITIONS TilAT CAN LEAD TO FAILURE Mission Success Criteria The Service Water System (SWS) provides water from the Cape Fear River for cooling and lubrication of equipment in the Reacto Building, Diesel Generator Building, Turbine -
Building, and to the circulating water pumps. In the BSEP PRA, the SWS also cover screen wash system which filters the intake water to the SWS pumps.
The Service Water System is subdivided into two major headers: one for nuclear or vital equipment in the Reactor Building and the other nonnally supplying convent equipment in the Turbine Building. The two headers are normally operated inde with each consisting of a group of service water pumps, parallelloads, and interconnecting headers. Cross-connect valves allow the conventional pumps to supply the nuclear equi ment as conditions dictate.
Service water is provided from the Cape Fear River through four sets of motor-operated traveling screens into the SWS pump suction bay. This bay is comm Units 1 and 2. Five venical shrft pumps, located at the intake structure, take suction from the bay and discharge to the nuclear and conventional service water headers. Two pu are aligned to the nuclear header. The remaining three pumps normally supply the conventional header but may also be aligned to the nuclear header.
In addition to the normal service water pumps, there are four additional pumps, the RHR Service Water Pumps. These are specifically used to increase the pressure of the service water for the RHR heat exchangers to ensure that any leaks in the heat exchanger would not result in a radioactive release to the environment.
One operational screen is sufficient to supply to the service water intake bay to supp .
operation of two SWS pumps per unit.
Two SWS pumps are necessary to supply sufficient water to the various -loads. Th -
FSAR (Sectior. 9.2, page 9.2.1-5) states that, during the first 10 minutes of the desig accident, only one pump is required but that a second pump is required later to suppo RHR heat exchangers. Thus, it was assumed that two pumps would be the success c for satisfactory operation. This is a conservative value since some of the transients may require fewer than two pumps.
A-42
1 A bypass switch has been added in the Control Room to allow the operators to bypass the interlock requiring that one of two RHR SWS pumps must start in order for the discharge valves to open.
To ensure sufficient flow to the emergency equipment, it is assumed that the RBCCW heat exchanger must be isolated from the nuclear header and that the TBCCW heat exchangers must be isolated from the conventional header.
Due to the two-pump criteria and isolation of the TBCCW, the flow for the chlorina-tion system was an assumed on-line diversion. Thus, flow through this path is already accounted for in the two-pump criteria.
- A 24-hour mission time is assumed for the SWS.
- 1. Dependent, or Common Cause, Failure ' or More SWS Pumps Fail to Run Four or more SWS pumps failing to run will cause insufficient SWS flow (OP,PT,MT,TS)
- 2. Loop A or Loop B RHR Heat Exchanger is Unavailable Due to Test or Mainte-nance The RHR heat exchangers 2A and 2B are cooled by separate RHR Service Water pumps. Unavailability of the pumps or heat exchangers due to test or maintenance prevents the suppression pool cooling and shutdown cooling modes of RHR operation (PT,MT,TS).
- 3. Loop A or Loop B P HP lleat Exchanger Fails Due to Plugging Plugging of tne RHR heat exchangers has occurred in the past at BSEP due to problems with the chlorination system (OP,PT,MT).
- 4. Diesel Generator 1,2,3 or 4 Heat Exchanger is Unavailable Due to Test or Maintenance l
Unavailability of the DG 1,2,3 or 4 heat exchangers due to test or maintenance can cause loss of the diesels should they begin to operate under a loss of off-site power condition (PT,MT,TS).
- 5. Diesel Generator 1.2.3 or 4 Heat Exchanger is Unavailabic Oue to Plugging Similar to the above, unavailability of the DG 1,2,3 or 4 heat exchangers due to plugging can cause a loss of the diesels should they begin to operate under a loss of off-site power condition (PT,MT).
- 6. Normally Closed RHR Heat Exchanger Suction header Isolation MOVs V105 and V101 Fail to Open Failure of the nonnally closed RHR heat exchanger isolation MOVs V105 and V101 to open will prevent operation of the RHR heat exchangers (PT,MT).
l l
l A-43
- 7. Insufficient Flow Through Screens l A, IB, 2A and 2B Due to Failure of Screen Drives or Other Faults Insufficient flow through screens l A, IB,2A and 2B due to failure of the screen drives or other faults will cause loss of the Service Water pumps (OP, MT).
- 8. Conventional Pump 2A, 2B or 2C Unavailable Due to Test or Maintenance In the BSEP PRA, it was assumed that any one Conventional SW Pump would be i automatically started and aligned to the conventional header or that it could also b manually aligned to the nuclear header and then staned. Therefore, unavailab Conventional Pump aligned to the nuclear header due to test or maintenance will p ,
from discharging to that header when required (OP,PT,MT,TS).
e i
e e
A-44
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK. BASED INSPECTION GUIDE Service Water System (SWS) 1 l
TABLE A.7 2 MODIFIED SYSTEM WALKDOWN l Pow. Sup. Required Actual Desired Actual !
Breaker # Location Position Position ID No. Location Position Position !
Description .
Comp. Reactor Bldg. On l V105 Control Closed RHR Heat Ex. DMI 480V MCC i changer MOV Room ;
2XB-El. 20'.
Fails Panel 601 l South Comp. Reactor Bldg. Normal DM1 Nor- 480V MCC mal Key 2XB-El. 20'.
t Lock South i
Switch 9 Reactor Bldg. On Motor MCC 2XB.
120V AC Heater 1 Dist. Pnt.
}
HN9 Comp. Reactor Bldg. On V101 Control Closed RHR Heat Ex. DH5 480V MCC changer MOV Room 2XA-El. 20'-
Fails Panel 601 North On ;
23 Reactor Bldg.
Valve Mo- MCC 2XA tor Htr. 120V AC l Dist. Pnt.
HS3 6
I 9
- i A-45 !
1
- 1 l
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK. BASED INSPECTION GUIDE
. Service Water System (SWS) l TABLE A.7 2 MODIFIED SYSTEM WALKDOWN (Cont'd) l Pow. Sup. Required Actual Desired Actual Breaker # Location Position Position Description ID No. Location Position . Position Comp.No. DG Bldg. Racked In '
Conventional TA 4160V Emerg AJ4 ,
Service Water Bus E3 4KV ,
Pump Cell 3 ,
AJ4 Local DO Bldg. Normal !
Key Lock 4160V Emerg Switch Bus E3-4KV Cell 3 AJ4 Motor DG Bldg. On Htr. 4160V Emerg Bus E3-4KV Cell 3 DG Bldg. On AJ4 Elapsed 4160V Emerg Time Bus E3-4KV Meter Cell 3 Comp. No. DG Bldg. Racked In ,
Conventional 2B 4160V Emerg AL2 Service Water Bus E4 KV Pump Cell 4 On AL2 Motor DG Bldg.
Hir. 4160V Emerg Bus E4 KV Cell 4 AL2 D G Blo g. On t
Elapsed 4160V Emerg Time Bus E4 KV Meter Cell 4 Comp. ' No. DG Bldg. Racked In Conventional 2C 4160V Emerg AF6 -
Service Water Bus El-4KV Pump Cell 1 DG Bldg. On ,
AF6 4160V Emerg Bus El-4KV i Cell I DG Bldg. On AF6 Elepsed 4160V Emeng ,
Time Bus El-4KV~
Meter Ceti 1 9
A-46
l BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE Service Water System (SWS)
TABLE A.7 2 MODIFIED SYSTEM WALKDOWN (Cont'd)
Desired Actual Pow. Sup. Required Actual Position Position Breaker # Location Position Position Description ID No. Location Comp.No. DG Bldg. Racked in Nuclear Service 2A AJ3 4160V Emerg Water Pump
- Bus E3-4KV Cell 3 j AJ3 Motor DG Bldg. On Htr. 4160V Emerg '
Bus E3 4KV Cell 3 ;
AJ3 Local DG Bldg. Normal Key Lock 4160V Emerg Switch Bus E3-4KV Cell 3 AJ3 DG Bldg. On Elapsed 4160V Emerg Time Bus E3-4KV Meter Cell 3 2B Comp.No. DG Bldg. Racked in Nuclear Strvice ALI 4160V Emerg Water Pump Bus E4 KV Cell 4 ALI Motor DG Bldg. On Her. 4160V Emerg Bus E4-KV Cell 4 ALI Local DG Bldg. Normal Key Lock 4160V Emerg Switch Bus E4 KV Cell 4 AL1 DG Bldg. On Elapsed 4160V Emerg Time Bus E4-KV Meter Cell 4 l
- Assume that screens I A, IB, 2A and 2B are operabic.
A-47 l
. , . ., - . - , . . . _ . . _ . - . ~ , _ _ , .
TABLE A.7-2 (Cont'd)
REFERENCE DOCUMENTS 1.D. NO. REV DATE TITLE System Procedures:
OP-43 057 3/9/88 Service Water System System
Description:
Section M 3.4.14 Brunswick PRA Volume I
" Service Water System" P&lD's No.:
Fig. M.3.4-27 Brunswick PRA Volume 1 Sheets 1-5 "SWS Simplified Diagram" l
l 9
l A-48
I r 7 RBCCWS IIEAT ,
_, EXCilANGERS l
j L J DISCHARGE CANAL r 3 g F DISCHARGE SAFEGUARD d CANAL LOADS L J I l r ,
CAPE r ,
FEAR DIESEL TOINTAKE HIVER y GENERATORS
- CAtML
---> SWS J L J t
k L r 3 e
l RilRSWS INTAKE CANAL L J dL r 3 DECAY
_p 11 EAT ___
REMOVAL L J k TO RBCCws . Descsor BuMng Cbsed Cooling Water System RHRSWS . Resital Heat Demovat Senace water System m NON-ESSENTIAL swS - sennca wawr sy5 tem ' HEAT LOADS Fig. A.7-1 (SAIC 89/1011 Figure 3-1). Cooling Water Systems Functional Diagram for Brunswick I and 2 CAUTION: This is NOT a controlled document.
I
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~~ -;[o
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- ~~ .
o, c, *,
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f, = "
o 2 > -: g;J L 7 .m _ .
.m "M
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=
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. : [O==
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- g. .
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~ *= :q? fi-
- . -- .z.
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. ;[
.4 w, .UNL.es.Aes T -- .U M.sf..snm. .OAB.
e..
Fig. A.7-2 (SAIC 89/1011 Figure 3.7-2). Brunswick 2 Service Water System
, Showing Component Locations CAUTION: This is NOT a controlled document. . .
9 8
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE Residual Heat Removal (RHR) System Table A.8-1 Importance Basis and Failure Mode Identification t
CONDITIONS THAT CAN LEAD TO FAILURE Mission Success Criteria The RHR system is a closed loop system of piping, valves, pumps, and heat exchang-ers designed to protect the reactor from overheating. The system is designed to perform three primary functions which comprise the following operating modes:
- 2. Containment cooling, and
- 3. Shutdown Cooling (SDC).
In addition to these three functions, the RHR system may be used to assist in fuel pool cooling and pumping water from the reactor or suppression pool to the Radwaste System.
The containment cooling mode is subdivided into the Suppression Pool Cooling (SPC) mode and the Containment Spray (CNS) mode.
The system consists of two essentially complete and independent loops, identified as loop A and loop B, as shown in Figure M.3.4-12. Each loop is comprised of two pumps, piping, valves, a heat exchanger, and associated instmmentation and controls. Each loo piped and valved flexibly to permit the system to carry out its multiple functions.
The source of pumpage can either be from the suppression pool or from reactor recirculation loop A suction header. The discharge point can be any of the following:
- 1. suppression pool via the RHR full flow test line through valves Ell-F028A(B) and F024A(B),
- 2. suppression pool via the spray header through valves El1-F028A(B) and F024A(B),
- 3. drywell via containment spray header through valves Ell-F016A(B) and F021A(B), or
- 4. reactor vessel via the reactor recirculation loop discharge header through valves Ell-F017A(B) and F015A(B).
The RHR cross-tie valve (E11-F010) is maintained closed during normal operation.
LPCI Success / Failure Criteria. Success of the RHR in the LPCI mode is defined least one pump delivering rated flow to the reactor vessel with suction from the suppressio pool. For large LOCAs where the break is in a recirculation loop, at least one pump must A-51
l l
\
l discharge through the unbroken recirculation loop. For all other initiators the di any one of the four RHR pumps to either recirculation loop is sufficient for success l DHA Success / Failure Criteria. The DHA function is the removal of decay heat to the SWS system (and thence to the environment following a large or intermediate containment. It is identical to the LPCI mode except that MOV F048A (B) is closed. T arrangement of the RHRS is also expected to be used for transients and small LO inside containment where high pressure injection systems have failed, reactor vessel been depressurized, and LPCI has been actuated successfully. For a large or LOCA inside containment, the return path from the RPV to the suppression pool is the break. For the transients, the return path is through the open ADS or SRV valves were opened to depressurize the RPV. For DHA success, one pump must be a -
cooled water into the RPV. Note that DHA is similar to altemate shutdown cooling except that it is not necessary to open one or more SRVs since the break or the valves used to ,
depressurize the vessel provide the return path.
SPC Success / Failure Criteria. Success of the RHR in the SPC mo success of one pump in one loop. Suction is from the suppression pool and discharg the suppression pool via either the test retum line or the torus spray header. Th requires manual actuation by operators in the control room. If the RPV pressure lowered enough for automatic actuation of LPCI to occur, then it is assumed that the operating mode applies for the long-term removal of decay heat. Therefore t applies only to those cases following transients and small LOCAs inside conta where the HPCI or another high pressure system has been successful in supplying water to the core.
The SPC mode transfers heat from the containment to the SWS (an environment). Thus cooling via the heat exchangers is required.
It should be noted that for some ATWS events, the nonnat suppression pool coolin will not be sufficient to control temperature and pressure within allowable limits. For those events, it is necessary to control water level at the top of the active fuel to limit total he production.
CNS Success / Failure Criteria. Success of the RHR in the CNS mode be the success of one pump in one loop. Suction is from the suppression pool and disch must be to both the torus spray header and the drywell spray header. Except for the discharge path, the CNS mode is similar to the SPC mode. .
SDC Success / Failure Criteria. In the SDC mode, suction is from the RPV via the suction portion of recirculation loop A through MOVs F008, F009, and F006A(B '
Discharge is to the discharge portion of the appropriate recirculation loop andthroug F015A(B) and F017A(B). The suppression pool suction valves F020A(B)
F005A(B,C,D) are closed for the loop operating in the SDC mode. The breakers for F009, and F006A(B,C,D) are normally racked out, so these must be restored befor valve positions can be changed. The failure of either F008 or F009 to open a single faults for both loops of the RHR in the SDC mode.
A-52
i
- 1. RHR Loop A or Loop B Unavailable Due to Test or Maintenance Combined with a failure in the opposite loop, test or maintenance of either RHR loop will cause loss of LPCI and RHR functions (PT,MT).
- 2. RHR Heat Exchanger Bypass MOVs F048A and F048B Fail to Close When Required Failure of RHR heat exchanger bypass MOVs F048A and F048 to close when required will prevent cooling of the suppression pool and the reactor vessel during the suppression pool cooling and shutdown cooling modes (PT,MT,OP).
. 3. RHR Mini-Flow Recirculation Line MOVs F007A and F007B Fail to Close When Required Failure of the RHR mini-flow recirculation line MOVs F007A and F007B to close when required will cause insufficient flow from the LPCI/RHR pumps during the various modes of operation (PT,MT).
- 4. Instrumentation and Control for Mini-Flow Recirculation Line MOVs F007A and F007B Not Restored or PDIS N021 A and N021B Miscalibrated Failure to properly restore the I&C for MOVs F007A and F007B, or miscalibration of flow switch PDIS-N0 A/B located in the discharge line of the two pumps per loop, will prevent proper automatic operation of the RHR pumps minimum flow bypass valves F007A and F007B. This can cause loss of the RHR pumps (PC.PT.MT).
- 5. Faults in Pressure Transmitters for MOVs F007A and F007B As in 3 and 4 above, failure of the instrumentation controlling MOVs F007A and F007B, such as pressure transmitter faults, will prevent proper automatic operation of the RHR pumps minimum flow bypass and cause possible loss of the pumps (PC,PT,MT).
- 6. Suppression Pool Strainers S1 and S2 Fail Due to Plugging Plugging of the suppression pool strainers S1 and S2 will prevent cooling of the pool by the RHPs pumps (OP,PT,MT). Consequently, it will also prevent reactor core flooding and cooling as well.
- 7. RHR Injection Header to Suppression Pool Isolation MOVs F028A and F028B, F027A and F027B, or F024A and F024B and Fail to Open or Fail to Close When Required
' Failure of the normally closed suppression pool injection header isolation MOVs F028A and F028B, F027A and F027B, or F024A and F024B, to open when required will prevent cooling and level control of the suppression pool. Failure of the valves to close when required will diven flow from the LPCI injection lines to the suppression pool (PT,MT).
i I
A-53 l
I
- 8. Loops A and B RHR Pumps C002A,B,C and D Fail to Start or Run Dependent, or common cause, failure of the four RHR pumps C002A,B,C, and D to start and run fails all RHR modes of operation (PT,MT). This is a significant risk contributor according to the PRA.
- 9. Common Cause Failure of RHR Heat Exchangers Due to Plugging The BSEP has experienced plugging and rupture of an RHR heat exchanger several years past. If one exchanger is failed, the other is very likely to be fouled also.
These events are caused by failure of the service water chlorination system leading in turn to the biological fouling (OP,PT,MT). -
- 10. Operator Fails to Correctly Initiate Suppression Pool CooLng-Loops A and B Suppression pool cooling is manually aligned when the pool upper temperature or level limits are reached. Failure of the operator to correctly initiate cooling will prevent this ,
mode of operation (OP).
e e
A-54
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK BASED INSPECTION GUIDE Residual Heat Removal (RHR) System TABLE A.8 2 MODIFIED SYSTEM WALKDOWN Pow. Sup. Required Actual .
Desired Actual i Breaker # Location Position Position ID No. Location Position Position Description .
r 7 Reactor Bldg. On F048A Control Open
Breaker 2XA (Rear)
Panel 120V AC H12-P601 -
Dist. Pnt.
HL3 El. 20' North Comp.No. Reactor Bldg. On Control Switch DG2 480V MCC- '
(Valve) 2XA (Rear)
El. 20' North ,
i Comp No. Reactor Bldg. On F048B Control Open RHR Heat Ex- DM8 480V MCC.
changer MOV Room l 2XB (Rear)
Panel El. 20' South H12-P601 DM8 Reactor Bldg. Normal Normal / 480V MCC. ,
Local 2XB (Rear)
Cont. Sw. El. 20' South 18 Reactor Bldg. On Control Switch Motor Hir. 480V MCC.
r (Valve) Circuit 2XB (Rear)
Breaker 120V AC l
Dist. Pnt.
HL4 El. 20' South 1
Comp.No. Reactor Bldg. On F007B Control Closed RHR Min.- DL3 480V MCC-6 Flow Recircula. Room 2XB (Rear) tion Line MOV Panel El. 20' South H12.P601
. Comp.No. Reactor Bldg. Normal l j
DL3 Local 480V MCC-Key Lock 2XB (Rear)
, Switch El. 20' South l 6 Reactor Bldg. On Control Switch l Motor Hir. 480V MCC (Valve) Circuit 2XB (Rear) ;
Breaker 120V AC Dist. Pal.
HL4 El. 20' South
- Normal position depends on operating mode. Concern is " failure to close" from open p mode.
A-55 !
i 1
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. . ~ _ , _ m._
t i
t.
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 l RISK-BASED INSPECTION GUIDE i Residual Heat Removal (RHR) System l
TABLE A 8 2 MODIFIED SYSTEM WALKDOWN (Cont'd) '
Pow. Sup. Required Actual j Desired Actual Location Position Position j Location Position Position Breaker #
Description ID No. i 16 Reactor Bldg. On 7 F007A Control Closed !
RHR Min.- Motor Htr. 480V MCC.
Flow Recircula- Room l Breaker 2XA (Front) tion Line MOV Panel -
120V AC H12-P601 !
Dist. Pal.
HS3 El. 20' . ,
North t Comp. No. 480V MCC- On ;
Control Sw. DF1 2XA (Front) l (Valve F007A) El. 20' Nonh t
i i
l S2 Clean
- Suppression f Pool Strainer !
i i
i i
o t
i l
l l
St Clean i
- Suppression .
Pool Strainer f
i
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- I
?
r i
i
[
l !
[
- Inspect strainer for possible clogging when suppression pool is drained. i t
I A-56 t
[
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK BASED INSPECTION GUIDE l Residual Heat Removal (RHR) System TABLE A.8 2 MODIFIED SYSTEM WALKDOWN gent'd)
Pow. Sup. Required Actual 1 Desired Actual Breaker # Location Position Position l ID No. Location Position Position Description Comp.No. Reactor Bldg. On RHR Injection F028A Control Closed DGO 480V MCC.
Header to Sup- Room
. 2XA-2 (Front) pression Pool Panel El 20' North Isolation MOV H12 P601 6 Reactor Bldg. On Control Suisch F028A HPCI 480V MCC Roof /
(Valve) 2XA (Front)
NRHR 120V AC Valve
. Dist. Pni.
Location HS3 El. 20' North Comp. No. 480V MCC- On )
RHR Injection F028B Control Closed '
DM5 2XB 2 (Front)
Header to Sup- Room El. 20' South pression Pool Panet Isolation MCV H12-P601 DM5 Local 480V MCC Normal Control Switch F028B Control 2XB-2 (Front)
(Valve) Switch El. 20' South 16 Reactor Bldg. On l
Motor Htr. 480V MCC Breaker 2XB (Rear) 120V AC Dist. Pnl.
HL4 El. 20' South 4
A-57
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 ;
RISK BASED INSPECTION GUIDE i Residual Heat Removal (RHR) System I
TABLE A.8 2 MODIFIED SYSTEM WALKDOWN (Cont'd) i Pow. Sup. Required Actual Actual Desired Position Position Position Breaker # Location
! Description ID No. Location Position s t
Comp. No. 480V MCC C.i F024B Control Closed i Suppression DM2 2XB (Rear)
Pool Cooling Room El. 20' South Injection Line Panet -
l MOV H12.P601 DM2 480V MCC Norrnal Control Switch D Norm./ 2XB (Rear) l (Valve) Local Con. El. 20' South trol Switch +
13 Reactor Bldg. On Motor Hir. 480V MCC Circuit 2XB (Rear)
Breaker 120V AC Dist. Pal, HL4 El. 20' ,
South Comp. No. 480V MCC on ;
F024A Control Closed ,
Suppression DF7 2XA (Rear) 'I Pool Cooling Room El. 20' North Injection Line Panet l MOV H12.P601 !
i f
3 480V MCC On Control Switch HPCI !
Roof Motor Htr. 2XA (Rear) !
(Valve) Circuit 120V AC NRHR- i Breaker Dist. Pnt. '
El.2' HL3 El. 20' ,
North I
Comp.No. Reactor Bldg. On F027B Control Closed Suppression DM4 480V MCC Pool Cooling Room ,
2XB (Rear) injection Line Panel El. 20' South MOV H12.P601
- 15 Reactor Bldg. On Control Switch Motor Hit. 480V MCC (Valve) Circuit 2XB (Rear)
Breaker 120V AC ,
Dist. Pnt.
[
HL4 El. 20' South i
[
A-58 ,
A m.m.L m..Lu - %.D+ -,4A 4*a-u4- 44<*# .4---, -~d -. ~ , + m e-% E-BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 ,
RISK. BASED INSPECTION GUIDE .
l Residual Heat Removal (RHR) System TABLE A.8 2 MODIFIED SYSTEM WALKDOWN (Cont'd)
Pow. Sup. Required Actual ,
Desimd Actual !
Location Position Position Position Breaker #
Description ID No. Location Position P Comp. No.' Reactor Bldg. On F027A Contrei Closed l Suppression DF9 480V MCC Pool Cooling Room l 2XA (Rear) l Injection Line Panel El. 20' North MOV H12 P601 Reactor Bldg. On !
4
- Control Smtch Motor Hir. 480V MCC ,
Circuit 2XA (Rear) j Breaker 120V AC Dist. Pal. .
HL3 El. 20' North Racked in l AJ1 Loop A DG Loop A RHR C002A Motor Bkr. Bldg. 4160V Pump Emerg. Bus E3 El. 45' Cell 3 i AJ1 Loop A DG On
)
- Motor Hir. Bldg. 4160V .
Circuit Emerg. Bus !
Breaker E3 El. 45' Cell 3 l :
AJ1 Loop A DG On Elapsed Bldg. 4160V ,
Time Emers. Bus <
Circuit E3 El.45' Breaker Cell 3 1 AF5 Loop A DG Rucked in :
Loop A RHR C002C Motor Bkr. Bldg. 4160V l Pump Emerg. Bus EI. El. 45' [
Cell ! l AF5 Loop A DG On Motor Htr. Bldg. 4160V
. Circuit Emerg. Bus '
Breaker El. El. 45' i
Cell 1 t AF5 Loop A DG On .
Elapsed Bldg. 4160V .
Time Emerg. Bus I Circuit El. El. 45'
, Breaker Cell 1 i
i i
A-59 !
l i
~~_
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-B ASED INSPECTION GUIDE Residual Heat Removal (RHR) System TABLE A.8 2 MODIFIED SYSTEM WALKDOWN (Cont'd)
Required Actual Desired Actual Pow Sup.
Location Position Position Breaker #
Description ID No. Location Position Position AK1 Loop B DG Racked In Loop B RHR C002B Motor Bldg.4160 Pump Circuit Emerg. Bus -
Breaker E4 El. 45' Cell 4 Loop B DG On AK3 Motor Htr. Bldg. 4160 Circuit Emerg. Bus Breaker E4 El. 45' Celt 4 Loop B DG On AK3
- Elapsed Bldg. 4160 Time Emerg. Bus Circuit E4 El. 45' Breaker Cell 4 AK3 Loop B DG Normal Normat/ Bldg. 4160 Local Con- Emerg. Bus trol Switch E4 El 45' Cell 4 AG9 Loop B DG Racked in Loop B RIIR C002D Motor Bldg. 4160V Pump Circuit Emerg. Bus Breaker E2 E1.45' Cell 2 Loop B DG On AG9 Motor Htr. Bidg. 4160V Circuit Emerg. Bus Breaker E2 El. 45' Cell 2 Loop B DG On '
AG9 Etapsed Bldg. 4160V Time Emerg. Bus Circuit E2 El. 45'
- Breaker Cell 2 AG9 Loop B DG Normal Normal / Bidg. 4160V Local Con. Emerg. Bus trol Switch E2 El. 45' Cell 2 A-60
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE Residual Ileat Removal (RHR) System TABLE A.8 2 MODIFIED SYSTEM WALKDOWN (Cont'd) i Pow. Sup. Required Actual Desired Actual Breaker # Location Position Position ID No. Location Position Position Description ,
PDIS- Next to Open Low Pressure ;
Instrument 1:o1. N021B. Instru-Valve 4 ment Rack H21-P021 !
PDIS- Next to Open High Pressure Instrument Isol. NO21B- Instru-Valve 3 ment Rack H21-P021 .
PDIS- Next to closed High Pressure lostrument Test N021B- Instru- '
Valve 10 ment Rack H21 P021 PDIS- Next to Closed Low Pressure Instrument Test NO21B- Instru-Valve 11 ment ,
Rack H21 P021 PDIS- Next to Open High Pressure Instru. i lastrument Iso. N021A- '
lation Valve 3 ment Rack ,
I H12-P018 PDIS. Next to Open Low Pressure Instrument Iso- NO21A. Instru- 1 lation Valve 4 ment Rack H12-P018 A-61
HRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE Residual Heat Removal (RHR) System TABLE A.8 2 MODIFIED SYSTEM WALKDOWN (Cont'd)
Required Actual Desired Actual Pow. Sup.
Location Positian Position I
Position Position Breaker #
Desenption ID No. Location PDIS- Next to Closed High Pressure Instrument Test NO21A- Instru-Valve 10 ment .
Rack H12 P018 PDIS- Next to Closed Low Pressure Instrument Test NO21A. Instru-Valve 11 ment Rack H12 P018 I
i I
(
l l
l 1
l Note:
Pressure transmitters for MOV F007A and B should be visually inspected.
A-62
1 TABLE A.8 2 (Cont'd) l REFERENCE DOCUMENTS l
1.D. NO. REV DATE TITLE System Procedures:
Residual Heat Removal System OP-17 078 9/27/88 System
Description:
Section M.3.4.8 Brunswick PRA Volume I
" Residual Heat Removal System" P&ID's No.:
Bruntwick PRA Volume I Figs. M.3.4-13 to "RHR (LPCI) Simplified Diagram" M.3.4-16 "RHR (SPC) Simplified Diagram" "RHR (CNS) Simplified Diagram" "RHR (SDC) Simplified Diagram" m
O O
A-63 l
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. i-i I .*= I Fig. A.8-1 (SAIC 89/1011 Figure 3.3-6). Brunswick 2 Residual IIeat Removal System, Loops A and C, Showing Component Locations CAUTION: This is NOT a controlled document. . .
. 9
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BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK BASED INSPECTION GUIDE DC Power (DCP) System Table A.9-1 Importance Basis and Failure Mode Identification CONDITIONS TilAT CAN LEAD TO FAILURE Mission Success Criteria ~
The DCP consists of battery banks, battery chargers, circuit breakers, distribut switchboards, de motor control centers (MCCs) and de distribution panels. The -
sets of 125 V battery banks (2A-1, 2A-2, 2B-1, and 2B-2). Each battery bank has a associated battery charger to keep the battery bank fully charged. The battery charg fed from 480 Vac MCCs. Two battery banks and two battery chargers feed eac distribution Vdc switchboards (2A and 2B). This enables each distribu power to the various Unit 2 de MCCs and de distribution panels.
provide 125/250 Switchboard 2A provides power to division I loads and switchboard 2B provides powe division 2 loads.
The DCP system is designed so that the loss of any single piece of equipmen battery charger or distribution panel, etc., will not prevent the equipment re emergency core cooling from operating. The DCP is configured so that the equipment, such as primary relays, is fed from one battery bus and the fed from the other battery bus. Some common de loads are fed from both batt a transfer switch provided to change to the alternate feed, should the primary fa The DCP system includes the circuit breakers that feed power from the 480 to the battery chargers. However, as modeled in the PRA, the DCP system h do the circuit breakers that feed power from the de MCCs and the de distribution pan various safety systems. The DCP is successful if the 125 Vdc MCCs and distr that provide power to the safety-related loads remain or power unavailable from battery bank and associated charger. The m DCP was chosen to be 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
- 1. Fault in Battery Bank 2B-1 or in Output Breaker '
Failure of Battery Bank 2B-1 prevents power from being supplied to its esse loads (PC,MT,TS).
- 2. Fault in Battery Bank 2A-2 or in Output Breaker Similarly, failure of Battery Bank 2A-2 prevents power from being supp essential loads (PC,MT,TS).
l A-66 l
t
- 3. Fault in Panel 4-A or in the Supply Breaker DC panel 4A supplies power to several reactor safeguards actuation loads. Failure of Panel 4A prevents power to the essential loads (PC,MT,TS).
- 4. Fault in Panel 4B or in the Supply Breaker Similuly, DC Panel 4B supplies power to several reactor safeguards actuation
( PC,MT,TS).
loads. Failure of Panel 4B prevents power to the essential 10.0
- 5. Fault in Distribution Switchboard 2A-P Failure of Distribution Switchboard 2A-P will prevent power from being supplied to the essential loads (PC,MT,TS).
- 6. Fault in Distribution Switchboard 2B-N Similarly, failure of Distribution Switchboard 2B-N will prevent power from being )
supplied to the essential loads (PC,MT,TS).
- 7. Fault in Battery Bank 2A-1 or in the Output Breaker Failure of Battery Bank 2A-1 prevents power frorn being supplied to its essential loads (PC,MT,TS).
- 8. Fault in MCC 2XDA or in the Feeder from 2A-P or 2A-N A fault in MCC 2XDA or in the feeder from 2AP or 2A-N will prevent power from being supplied to its essential loads (PC,MT.TS).
O A-67
1 BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 ,
RISK-H ASED INSPECTION GUIDE DC Power (DCP) System i TABLE A.9 2 MODIFIED SYSTEM WALKDOWN ,
Desired Actual Pow. Sup. Required Actual Location Position Position Breaker # Location Position Position
- Description ID No. !
- Battery Bardt 2E1 Compart. Conti. Bldg. Off" GM2 125/250V DC Output Breaker ,
Switchboard ,
2B Div. II El. 23' Bat. ,
tery Room [
- Battery Bank 2A2 Compart. Conti. Bldg. Off"
' Output Breaker GK2 125/250V DC S witchboard 2A Div. I El.
23' Battery }
Room f
t Panel Supply 4A Compart. Conti. B.dg. On i
Breaker G16 125/250V DC 5 vitchboard 2 AP Div. I :
El. 23' Bat.
tery Room ,
- Examine battery bank and circuit breaker for temperature and ventilation conditions.
i "During normal operation, this breaker will be in the "on" position.
i L
A-68
1 l
l 1
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE DC Power (DCP) System TABLE A.9 2 MODIFIED SYSTEM WALKDOWN (Cont'd) i Require.d Actual Desired Actual P : w. Sup.
Location Position Position l Location Position Position Breaker #
Description ID No. t Compt. Conti. B!dg. Off * *
- Battery Bank 2Al GK1 125/250V DC l Output Breaker Switchboard 2A Div.1 El.
i 23' Battery Room e
i i
Compt. Conti. Bldg. On l DC-MCC 2XDA GJ3 125/250V DC 1 Switchboard 2A Div. I El.
23' Battery Room ,
t I
l r
i
?
I i
Compt. Conti. Bldg. On 4B Battery N/A N/A l 125 Volt Dist. GK6 El. 25' 125/
Room l Panel 250V DC Switchboard ,
2B Div. II (
r I
l 1
i i
)
- Examine battery bank and circuit breaker for temperature and ventilation conditions. ;
"During normal operation, the breaker will be in the "on" position. l
)
l A-69
TABLE A.9-2 (Cont'd)
REFERENCE DOCUMENTS I.D. NO. REV DATE TITLE System Procedures:
OP-51 018 2/19/88 DC Electrical System Operating Procedure System
Description:
Brunswick PRA Volume I ,
"DC Power System"
, (
P&lD's No.:
Fig. M.3.4-24 Brunswick PRA Volume I
"_DCP Simplified Diagram" l
l 1
9 A-70 1 - - _ _ _ - - - .
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BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE AC Power (ACP) System ,
i Table A.10-1 Importance Basis and Failure Mode Identification I CONDITIONS TilAT CAN LEAD TO FAILURE i Mission Success Criteria ~
The ACP consists of transformers, circuit breakers,4160 V120-208 auxiliary V buse emergency buses,480 V unit sub-stations,480 V motor control centers, and -
power distribution panels. The ACP system does not include f comp the CP&L power grid, the diesel generators, or the circuit breakers that feed po the diesel generators to the emergency buses. ,
The auxiliary buses (IC, ID, 2C, and 2D) receive ac power frcm either the startu auxiliary transformers (SAT) or the unit auxiliary transformers (UAY). Th during startup, shutdown, and abnormal plant operating conditions. It r power from the CP&L power grid and steps it down to 4160 VV. The normal operation after the unit's main generator has been brought on lin power from the main generator and steps it down to 4160 V. Powe h SAT to the UAT is performed by operator action, while power transfer from the UAT is performed by either operator action or automatic fast transfer. Interlocks from being supplied from both the SAT and UAT simultaneously.
The emergency buses (El, E2, E3, and E4) receive power from the auxilia except during loss of off-site power conditions. During loss of off-site powe is provided by the diesel generators. Each auxil one known as the " master" and the other known as the " sla breakers trip open as a result of automatic control circuitry actuation or o The emergency buses provide power directly to some safety-related d e as RHR pumps, and to loads off of the 480 V unit 1substations. busses El and Power E2, . to RHR Service Water Purops 2C and 2D is supplied from Unit respectively. Similarly, power to Unit 1 RHR and RHR Service Wa ,
supplied from Unit 2 busses E3 and E4, respectively. The LPCI inje l supplied from the opposite unit busses. The unit substations consi step down 4160 V power to 480 V power and 4 120-208 V power for use by power transfonners that step down the 480 V power to 120-208 V power panels.
distribution panels. The power distribution panels feed A-72 i
The ACP to the individual safety-related loads is successful if the 4160 V emergency buses, the 480 Vac MCCs, and the 120-208 Vac power panels that provide power to the safety-related loads remain energized. Failure can occur as a result of any one of the following: a bus fails, a transformer fails, a feeder breaker fails, a feeder breaker fails on ICC, insufficient HVAC provided to the Diesel Generator Building, diesel generator power not available, a MCC fails, or an ac power panel fails. The mission time for ACP was chosen to be 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
- 1. Failure to Recover Offsite Power Within One Half Hour Combined with subsequent faults in the Emergency Diesel Generator System, failure to recover offsite power within one half hour can lead to loss of all AC power (OP,PC,MT,TS).
- 2. 480V Bus E7 Fault or 4160/408 Transformer Failure or Bus E7 Feeders Fail Open 480 V Bus E7 supplies several motor control centers and the battery chargers for DG3. Faults in the bus or in the 4160/408 transformer or of the feeders failing open causes unavailability of the connected loads (OP,PC,MT,TS).
- 3. 480 Bus E8 Fault or 4160/408 Transformer Failure or Bus E8 Feeders Fail Open Similarly,480V Bus E8 supplies several motor control centers and the battery chargers for DG4. Faults in the bus or in the 4160/408 transformer or of the feeders failing open causes unavailability of the connected loads (OP,PC,MT TS).
- 4. 480 VAC MCC 2CA Fault or Feeder Fails Open 480 VAC MCC 2CA controls the supply and exhaust fans for Battery Room 2A and supplies the power to battery chargers 2A-1 and 2A-2. Faults in the MCC or feeder can cause insufficient HVAC flow through the battery room, thereby failing the battery, or preventing battery chargers 2A-1 and 2A-2 from functioning (OP, PC, MT).
- 5. 480 VAC MCC 2CB Fault or Feeder Fails Open Similarly,480 VAC MCC 2CB controls the supply and exhaust fans for Battery Room 2B and supplies the power to battery chargers 2B-1 and 2B-2. Faults in the MCC or feeder can cause insufficient HVAC flow throuEh the battery room, thereby failing the battery, or preventing battery chargers 2B-1 and 2B-2 from functioning (OP, PC, MT).
- 6. Fault in 4160V E3 Bus 4160V Bus E3 supplies power from Diesel Generator 3 to 480V Bus E7 which in tum feeds several motor control centers and the battery chargers for DG3. Failure of this bus causes unavailability of the connected loads which include (OP,MT,TS):
a) Core Spray Pump 2A b) RHR Pump 2A room cooling c) RHR Pump 2A A-73
rT .
=
d) Service Water System-Nuclear Header Pump 2A e) Service Water System-Conventional Header Pump 2A
- 7. Fault in 4160V E4 Bus 4160V Bus E4 supplies power from Diesel Generator 4 to 480Failure Bus E8 of which in tum also feeds several motor control centers and the battery chargers TS): far DG4.
this bus causes unavailability of the connected loads which include (OP,MT, a) Core Spray Pump 2B b) RHR Pump 2B room cooling -
c) RHR Pump 2B d) Service Water System- .
Nuclear Header Pump 2B l
' e) Service Water System-Conventional Header Pump 2B .
- 8. Power Fails for Battery Rooms 2A and 2B Duct Heaters The duct heaters for Battery Rooms 2A and 2B are supplied from a common source. Failure of the duct heaters can cause failure of Batteries 2A an overcooling (OP,MT).
- 9. Complete or Panial Loss of Off Site Power Caused by the Following:
a) Feeder to Bus E3 Fails Open Due to I&C Related or Other Faults b) Stanup Auxiliary Transformer (SAT) Fails c) Feeder From SAT to Bus 2D Fails Open Due to I&C Related or Other Faults d) 4160 VAC Bus 2D Fault Assuming initially no power from the Unit Auxiliary Transformer (UAT), failure of the above can cause either a partial or complete loss of off-site power, forcing relianc upon Diesel Generator No. 3 (OP. PC, MT).
Caused by the Following:
- 10. Complete or Partial Loss of Off-Site Power a) Feeder to Bus E4 Fails Open Due to I&C Related or Other Faults ,
b) Stanup Auxiliary Transformer (SAT) Fails.
c) Feeder from SAT to Bus 2C Fails Open Due to I&C Related or Other Faults d) 4160VAC Bus 2C Fault Again assuming initially no power from the UAT, failure of the above can cause either a panial or complete loss of off-site power, forcing reliance upon Diesel Gene No. 4 (OP,PT,MT).
A-74
- 11. 480 VAC MCC 2XA Fault or Feeder Fails Open 480 VAC MCC 2XA controls numerous motor-operated valves. Faults in the MCC or feeder can cause loss of power to those valves and components which include (OP, P MT):
a) MOV F027A-RHR suppression pool spray b) MOV F024A-RIIR suppression pool return c) MOV F007A-RHR Pump 2A minimum flow bypass d) MOVs F016A, F021 A-RHR drywell spray e) MOV F048A-RHR Heat Exchanger 2A bypass f) MOVs F006A, F0060-RHR Pumps 2A,2C shutdown cooling flowpath suc-tion isolation valves g) MOVs F008, F009-RHR outboard and inboard shutdown cooling isolation vMves h) MOVs F004A, F004C-RHR Pumps 2A,2C suppression pool suction isolation valves i) MOV F020A-RHR suppression pool isolation valve to pumps 2A and 2C suction lines j) MOV V004-SWS conventional header isolation for Turbine Building Closed Cooling Water (TBCCW) Sy:, tem k) MOV V106-SWS alignment valve for Reactor Building Closed Cooling Water (RBCCW) System
- 1) MOV Vlli-SWS alignment valve to Vital Service Header (to RHR pump seal coolers, RHR pump room coolers and Core Spray pump room coolers) from Conventional Header m) MOV V118-SWS isolation valve for Vital Service Header from Con tional Header n) MOV F002A-RHRSWS Pump 2A discharge o) RHR Pump Room 2A Fan Cooler Unit (FCU)
- 12. 480 VAC MCC 2XB Fault or Feeder Fails Open 480 VAC MCC 2XB, like its counterpart MCC 2XA, controls numerous motor-operated valves, almost all of which are the Train B counterparts to the Train A va components identified above. Faults in the MCC or feeder can cause loss of power valves and components which include (OP, PC, MT):
a) MOV F027B-RHR suppression pool spray b) MOV F024B-RHR suppression pool return c) MOV F007B-RHR pump 2B minimum flow bypass d) MOVs F016B, F021B-RHR drywell spray e) MOV F048B-RHR Heat E7 changer 2B bypass f) MOVs F006B, F006D-RHR Pumps 2B,2D shutdown cooling flowpath suc-tion isolation valves g) MOVs F004B, F004D-RHR Pumps 2B,2D suppression pool suction isolationf; valves A-75
i i
l I
)
l h) MOV F020B-RHR suppression pool isolation valve to pumps 2B and 2D ,
suction lines i) MOV V105-SWS alignment valve for RHRSWS pumps from Nuclear Heade j) MOV V117-SWS alignment valve to Vital Service Header (to RHR pump coolers, RHR pump room coolers and Core Spray pump room coolers) from Conventional Header k) MOV V102-RHRSWS crosstie valve between RHRSWS pumps 2A and 2C suction header and pumps 2B and 2D suction header
- 1) RHR Pump Room 2B Fan Cooler Unit (FCU)
- 13. 480 VAC MCC 2XA-2 Fault or Feeder Fails Open 480 VAC MCC 2XA-2 controls RHR MOV F015A, the RHR return line to Recirculation Loop A isolation valve, which must open for the Low Pressure Coolant Injection (LPCI) and Shutdown Cooling (SDC) modes of operation, and MOV
- RHR return line to the suppression pool isolation valve, which must open for the Suppression Pool Cooling (SPC) and Containment Spray (CNS) modes of op ,
in the MCC or feeder can prevent operation of these valves when required (OP, PC, M
- 14. 480 VAC MCC 2XB-2 Fault or Feeder Fails Open Similar to MCC 2XA-2 above, MCC 2XB-2 controls RHR MOV F015B and F028B, the Train B counterparts to MOV F015A and F028A discussed above. Faul MCC or feeder can prevent operation of these valves when required (OP, PC, MT).
- 15. Power Not Available from Bus El Unit 1 Bus El provides power directly to RHR and RHR Service Water Pumps 2 on Unit 2. Unit 1 Bus El is a Division I bus which can also be used to supply power companion Division I Bus E3 for Unit 2. Failare to provide power from Bus El reqrired fails Bus E3 of Unit 2 and Unit 2 RHR and RHRSW Pumps 2C, (OP TS).
- 16. Power Not Available from Bus E2 Similarly, Unit 1 Bus E2 provides power directly to RHR and RHR Service W Pumps 2D on Unit 2. Unit 1 Bus E2 is a Division II bus which also can be us power to its companion Division II Bus E4 for Unit 2. Failure to provide po E2 when required fails Bus E4 of Unit 2 and Unit 2 RHR and RHRSW Pumps ,
MT, TS).
A-76
HRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE {
AC Power System
- r TABLE A.10 2 MODIFIED SYSTEM WALKDOWN Pow. Sup. Required Actual Desired Actual i Breaker # Location Position Position ID No. Location Position Position Description A09 Unit Sub- Closed Feed to 480V Station E-8 i
- AC MCC 2CB Div. II Diesel l Bldg.
L i
1 AY9 Unit Sub. Closed ,
Feed to 480V Station E-7 in !
MCC 2CA Div. I Diesel i Bldg.
I I
I l
AJ9 Swgr. E-4 Closed Feed to 4160 Volt Bus E-4" l I
2ACB" Swgr. 2C Closed j Disc. Control On Feed to Bus ,
2C No. Room i AC6 Panel j H12-XU5 l l
'The PRA projects most of the AC power failures as hardware failures or failures related to other syste (covered elsewhere). This table lists limited observations that can reduce the risks of AC power fa
" Check latest surveillance records for satisfactory completion of any open items or concerns regard circuit breakers feeding this load. !
{
A-77 ,
t I
I BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK BASED INSPECTION GUIDE AC Power System
- TABLE A.10 2 MODIFIE!> SYSTEM WALKDOWN (Cont'd)
Required Actual Actual Pow. Sup.
Desired Location Position Position Breaker #
Description ID No. Location Position Position Div. Bop Closed On 2ADL Bkr. Feeding Discon- Control Swgr. 2D from SAT 2 to nect No. Room 2AD4 Panet Swgt. 2D" H12 X45 Div. I Diesel Closed AZ1 Feeder to Bus BidB-(
E-7 Breaker" Div. Il Diesel Closed AZ5 Feeder to Bldg.
Swgr. E-8" Sub-Station Closed AY 2 Cir. Bkr. Feed. E 7 Div. I ing MCC Diesel Bldg.
2XA" >
Sub-Station Closed AT8 Cir. Bkr. Feed. E-5 Div. I ing MCC Diesel Bldg.
2XA2" ding the
" Cheek latest surveillance records for satisf actory completion of any open items or concern circuit breakers feeding this load.
A-78
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE AC Power System
- TABLE A.10 2 MODIFIED SYSTEM WALKDOWN (Cont'd)
Paw. Sup. Required Actual Desired Actual Location Position Position Description ID No. Location Position Position Breaker # f AO2 Sub-Station Closed Cir. Bkr. Feed. E-8 Div. II ing MCC Diesel Bldg.
2XB" l
l i
1 IACB Div. BOP Closed 4160V AC Bus Swgr. IC E-2 "
l l
l l
l AG4 Div. II Swgr. Closed E-2 1
Closed ;
lADI Div. BOP 4160V AC Bus Swgr. ID (
E- 1 "
l -
AG6 Div. I Swgr. Closed E1
" Check latest surveillance records for satisfactory completion of any open items or concerns regarding the circuit breakers feeding this load.
A-79
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AC DIsrHIBUTION I
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BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE Battery Room Fans and Heaters Table A.ll-1 Importance Basis and Failure Mode Identification j
CONDITIONS TilAT CAN LEAD TO FAILURE i
Mission Success Criteria Battery Room Fans and Heaters Successful operation of the battery room ventilation system for a 24 hom mission tim l
requires that the supply and exhaust fans are operable and that there is a flow p; supply fan to the battery room and out to the atmosphere. Failure of the system -
i the intake filter is restricted, a fan is inoperable, or the dampers fail. The duct heater must be operational to provide sufficient heating. Thus, overcooling will result if the he or the power to the heater fails.
Insufficient HVAC flow through the battery room can cause two types of faults: ,
- 1. Hydrogen buildup with the risk of explosion, and .
- 2. Temperature increase with the risk of battery charge output failure. .
HVAC analyses provided in the PRA indicate that the battery rooms will not heat up ;
enough within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to fail the batteries. Hydrogen buildup during rapid chargin without the HVAC system might be significant. However, the frequency of such an event combined with a reactor scram is assumed to be negligible in the PRA. Operator recovery action can be taken by opening the battery room doors. 1
- 1. Battery Rooms 2A and 2B Supply and Exhaust Fans Fail to Run Failure of the battery room supply and exhaust fans to run can cause heat or >
hydrogen buildup in the battery rooms (OP MT).
- 2. Battery Rooms 2A and 2B Supply and Exhaust Dampers Fail Closed Due to Faults !
in the Actuation Control for the Vortex Dampers Faults in the actuation control for the vortex dampers will cause the battery room
, l supply and exhaust dampers to fail closed, thereby causing inadequate battery room l ventilation (PC, MT).
t A-83 ;
- 3. Failure of Thermostats for Battery Rooms 2A and 2B Duct Heaters Causing Overcooling Failure of the thermostats for the duct heaters of Battery Rooms 2A and 2B can cause overcooling of the rooms and subsequently insufficient charge output from batteries (PC,MT).
- 4. Insufficient Supply Flow to Battery Rooms 2A and 2B Due to Restriction of the Intake Plenum Air Filters Restrictions in the intake plenum air filters can cause insufficient supply flow to th battery rooms (OP,MT).
G e
e A-84
i BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE Battery Room Fans and Heaters !
l TABLE A.112 MODIFIED SYSTEM WALKDOWN Pow. Sup. Required Actual !
Desired Actual j Location Position Position Location Position Position Breaker #
Desenption ID No. !
On l Comp.No. Control Bldg. ;
Battery Room 2C-S F- Disconnect PJ5 2A Supply Fan CB Switches Above Battery Room I
Comp.No. Control Bldg. On .,
Battery Room 2B SF. Disconnect !
PJ6 '
1B Supply Fan CB Switches Above Battery f Room Comp.No. Control Bldg. On l Battery Room 2C EF- Disc. Switch l PKO ;
2A Exhaust CB EL-70 i Fan ',
l l
l i
Comp.No. Control Bldg. On j Battery Room 2 B.S F- 480V MCC ,
4 P 2B Supply Fan CB 2CB 120V Motor Heater (C42) Distribution Circuit Breaker Panel l t
5 Control Bldg. On Battery Room 2B SF- Disc. Sw. EL 2B Exhaust CB 70' .
Fan Motor Hester Circuit Break-r (C43) On l PJ9 Control Bldg. i Disc. Sw. EL r
70' Comp. No. Unit 2 Con. On Battery Room 2B-SF- trol Bldg.
C43 I 2B Supply Fan CB 480V MCC 2CB EL 23'
, I F
i A-85 i t
l BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE i Battery Room Fans and Heaters TABLE A.112 MODIFIED SYSTEM WALKDOWN (Cont'd) !
Pow. Sup. Required Actual !
Desired Actual Location Position Position i Location Position Position Breaker # !
Description ID No. !
Comp.No. Unit 2 Con. On f Battery Room 2B-EF- trol Bldg.
C42
- Enhaust Fan CB 480V MCC i 2CB El. 23' ;
)
12 Control Bldg. On l 2C-EF- j Battery Room 480V MCC 2A Exhaust CB 2CA 120V j Fan Motor Distribu. tion Hester Circuit Panel Breaker (C20)
Control Bldg. On j 13 Battery Room 2C-S F- l 480V MCC 2A Supply Fan CB 2CA 120V t l
Motor Hester Deeribution j
Circuit Breaker Panel i
t On !
Comp. No. Unit 2 Con- I Battery Room 2C-EF- C20 trol Bldg.
.,2A Exhaust CB 480V MCC Fan 2CA El. 23' t
i i
On e
Comp.No. Unit 2 Con- !
Battery Room 2 C-S F. trol Bldg. ,
C21 f 2A Supply Fan CB 480V MCC i
2CA El. 23' i i
l
. i I
t l
t I
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A-86 1
1
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK.B ASED INSPECTION GUIDE Battery Room Fans and Heaters l TABLE A.112 MODIFIED SYSTEM WALKDOWN (Cont'd)
Pow. Sup. Required Actual Desired Actual Location Position Position Position Position Breaker #
De scription ID No. Locatic i 21 Control Bldg. On Battery Room 926 120V E ner.
2A Damper gency Distri-SOV bution Panel 2C-HYO El.
23' Battery Room l
i 2B Damper Battery Room 2A Supply &
Exhaust Damp-ers*
Battery Room 2B Supply &
Exhaust Damp-ers*
- Thermostat for Battery Room 2A O
- Thermostat for Battery Room 2B
- Visually inspect thermostats and dampers for possible signs of failure.
A-87 I i
TABLE A.112 (Cont'd)
REFERENCE DOCUMENTS __
I.D. N O. REV DATE TITLE
=__
System Procedures:
OP-37 017 12/17/87 Control Building Ventilation System System
Description:
Section M.3.4.16 Brunswick PRA Volume I .
" Heating. Ventilating. and Air Conditioning Systems" .
P&ID's No.:
Fig. M.3.4-32 Brunswick PRA Volume I
" Battery Room Cooler and Heater Detailed -
Diagram (1 of 2) F-4080
" Battery Room Cooler and Heater Detailed Diagram (2 of 2) F-03493 4
A-88
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE Reactor Core Isolation Cooling (RCIC) System Table A.12-1 Importance Basis and Failure Mode Identification !
i CONDITIONS TilAT CAN LEAD TO FAILURE l
Mission Success Criteria '
The Reactor Core Isolation Cooling (RCIC) system can be operated manually or
' automatically to maintain the reactor vessel water level in the event of a reacto ;
accompanied by a loss of feedwater. RCIC is considered to be redundant t >
transients and small LOCAs. For intermediate LOCAs and anticipated transients scram (ATWSs), RCIC is not sufficient to replace HPCL The success criteria for the RCIC system is that the RCIC pump starts and contin .
deliver rated Gow of 400 GPM into the reactor vessel in accor specification requirements for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The flow rate is approximately equa water boil-off rate 15 minutes after shutdown.
RCIC consists of a 100% capacity single train with de motor-operated valves a steam turbine-driven pump. The normal water supply is from the Condensate S (CST). If the CST level decreases to a predetermined level, or the suppres rises above a predetermined level, pump suction is automatically transferred to ,
suppression pool. The RCIC pump discharges into the B feedwater line (t F010) and subsequently into the feedwater spargers.
- 1. RCIC Pump Fails to Start or Run Failure of the RCIC pump to start or to mn for its required mission time prevents ,
7
- 2. RCIC Pump in Test or Maintenance
~
Testing or maintenance of the RCIC pump also prevents RCIC flow (PT,MT
- 3. Operator Failure to Override Steam Tunnel High Temperature2Tri During station blackout scenarios, early isolation of the RCIC turbine on steam tunnel temperature will occur automatically unless overridden by the operators.
Failure of the operators to override when required can lead to core damage (OP).
A-89
- 4. Faults in RCIC System Prevent RCIC Pump Discharge Flow RCIC flow is prevented by the following (PT,MT):
a) Normally closed RCIC pump discharge isolation de-powered MOV F013 fails to open when required b) Normally closed RCIC turbine steam supply isolation de-powered MOV F045 fails to open when required c) Normally open RCIC pump discharge isolation de-powered MOV F012 fails to remain open or check valve F014 fails to open d) Normally open RCIC pump suction isolation de-powered MOV F010 fails to remain open or check valve F011 fails to open
- 5. Failure of Lube Oil Cooling The RCIC pump discharge provides cooling water flow to the turbine tube oil cooler. Failure of this cooling system will cause RCIC turbine failure (PT,MT).
- 6. Failure of the Vacuum Breaker on Startup Causes Insufficient Steam Flow from the Turbine The RCIC turbine exhausts to the suppression pool via a submerged penetration. A vacuum breaker line, containing MOVs F062 and F066 and check valves F063 and F064, connects the turbine exhaust line to the suppression pool atmosphere allowing for vacuum relief of the turbine exhaust line. Failure of the vacuum relief can prevent exhaust steam flow from the RCIC turbine, thereby preventing RCIC flow (PT,MT).
A-90
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 !
RISK-BASED INSPECTION GUIDE ,
Reactor Core Iso'lation Cooling (RCIC) System !
j TABLE A.12 2 MODIFIED SYSTEM WALKDOWN Required Actual Desired Actual Pow. Sup. +
Location Position Position Breaker #
Description ID No. Location Position Position Reactor Bldg. On l Open Comp.
Condensate F010 Control 250V MCC B 38 Storage Tank Room 2XDB EL. 20' Suction Valve RTGB Control Switch Pnt. H12 P601 B 38 Con- Same Normal ?
trol Switch ,
120V AC Pnl. On ,
2 l Hir. 2DXB EL.17' 1 On !
C >m p. Reactor Bldg. !
F012 Same Open Pump Dis. B 40 .250V MCC charge Valve 2XDB EL. 20' Control Smitch Same Normal Conp.
B 4 0 Con-trol Switch On f 4 120V AC Pnt.
Htr. 2DXB EL.17' ,
2XDB EL. 20' On b
Closed Comp. :
RCIC Injection F013 Same B-41 Valve Control Switch Same Normal B-41 Con.
trol Switch )
Panel 2DXB On f 5
Htr. EL.17' \
2XDB EL. 20' On Closed Comp.
Vac. Pump In- F045* Reactor B-44 board Test Bldg.
Valve South RHR Pump Rm.
B-44 Con- Same Normal trol Switch 8 2DXB EL.17' On Hir.
- Note: The PRA identified the failure of this pump to start or to run its mission time Exarnine pump for visual defects and assure that maintenance procedures are current. !
A-91 2
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i l
l BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-B ASED INSPECTION GUIDE
.: tor Core isolation Cooling (RCIC) System TABLE A.12 2 MODIFIED SYSTEM WALKDOWN (Cont'd)
Pow. Sup. Required Actual Desired Actual Breaker # Location Position Position ID No. Location Position Position Description Comp. MCC 2XA On Turbin6 Ex- F062 Reactor Bldg.
DE4 Cir.
haust Vac. Bkr. Bkr. EL. 20' Valve 9 Dist. Panel On Hir. HS 3 Reactor Bldg. EL. 20' DW2 Alt. MCC 2XD Off Feed Reactor Bldg.
EL. 20' s
Turbine Ex- F066 Reactor Bldg.
2XB EL. DL5 haust Vac. Bks. EL. 20' Valve Selector 20' Re-attor i Switch
' Bldg.
t 8 Dist. Panel On Her. HL4 Reactor Bldg. EL. 20' O
I l ,
l l
A-92 l
1
TABLE A.12 2 (Cont'd)
REFERENCE DOCUMENTS I.D. NO. REV DATE TITLE System Procedures:
OP-16 053 8/23/88 Reactor Core Isolation Cooling System System
Description:
Section M.3.4.4 Brunswick PRA Volume I
" Reactor Core Isolation Cooling System" P&ID's No.:
Fig. M.3.4-5 Brunswick PRA Sheets !.2,3 "RCIC Simplified Diagram"
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A-93
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CAUTION: This is NOT a controlled document.
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.- .. .w Fig. A.12-1 (PRA Fig. M.3.4-5). RCIC Simplified Diagram (Sheet 3 of 3).
CAUTION: This is NOT a controlled document.
l I
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-11ASED INSPECTION GUIDE Control Rod Drive (CRD) Hydraulic System Table A.13-1 Importance Basis and Failure Mode Identification CONDITIONS THAT CAN LEAD TO FAILURE i Mission Success Criteria During normal reactor operations the Control Rod Drive (CRD) system provides water from the Condensate Storage Tank (CST) to the CRD hydraulic control units (HCUs) and each individual control rod drive. High pressure water (1400 psig) is supplied by one of two pumps to drive individual rods into or out of the core and keep the HCU scram accumulators charged for rapid insertion of the rods in the event of a trip signal. In addition, CRD also provides approximately 0.44 gpm of cooling water flow to each drive mechanism. This flow enters the drive mechanism via the insert line (bott piston) and flows past the piston seals into the reactor vessel.
To pmvide makeup water to the reactor vessel following a reactor trip, flow to the vessel can be increased by the plant operators to greater than 140 gpm. The flow path to the vessel in this condition is through the cooling water lines for each of the 137 CRD drives as described above. CRD is considered to be redundant to HPCI and RCIC f transients.
The success criterion for the CRD tree is the ability to inject water with both CRD pumps simultaneously through the scram valves and the cooling water header. T criterion was developed from reviews of independent studies by GE and CP&L which indicate that the CRD system is capable of providing sufficient makeup following a transient to maintain reactor vessel level. These studies concluded that lev maintained with 135 gpm makeup (GE) or 140 gpm makeup (CP&L). Instrumentation currently available in the plant cannot measure system flow above 140 gpm. This appears to be at or near the upper limit of one pump. This, coupled with uncertainties in the analysis, resulted in the decision to define both pumps operating as the minimal success criterion.
- 1. Operator Fails to Fully Open Valve F002A In the event of a transient, to properly use the CRD system for makeup to the reactor vessel, flow must be increased to the maximum amount of 140 gpm. Operator failure to fully open flow control valve F002A prevents adequate makeup to the vessel (OP).
- 2. Operator Fails to Fully Open Valve F003 As above, operator failure to open pressure regulating valve F003 prevents ade-quate makeup to the vessel (OP).
A-97 i
s BRUNSWICK STEAM ELECTRIC Pl. ANT-UNIT 2 RISK-B ASED INSPECTION GUIDE Control Rod Drive (CRD) Hydraulic System TABLE A.13 2 MODIFIED SYSTEM WAL'.'DOWN --
Required Actual Desired Actual Pow. Sup.
Location Position Position Breaker #
Desenption ID No. Location Position Position Comp. EZO React. EL. 20 On C-12 Control Open Drive Water East 480V F003 Room MCC 2XM Pressure Con.
trol Valve RTGB Panet HR9 Panel _
H12.P603
(
React. EL. 20 On 5
Hir. East 480V MCC 2XM Panel HR9 Control Bldg. On 10 C 12 Reactor Operable CRD Flow EL. 23' Panel F002A Bld g.
Control Valve 2 AB 120V Inst. AC Rack 1R- -
RB-2 EL.
20' East 9
A-98
}
TABLE A.13-2 (Cont'd)
REFERENCE DOCUMENTS 1.D. NO. REV DATE TITLE System Procedures.
OP-08 013 8/11/88 Control Rod Drive Hydraulic System System
Description:
Section M.3.4.5
. Brunswick PRA Volume I
" Control Rod Drive (CRD) Hydraulic" P&ID's No.:
Fig. M.3.4-7 Brunswick PRA Volume I "CRD Simplified Diagram" e
O i
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CAUTION: This is NOT a controlled document.
- 6 r- ,- , - - - . . - . . , . , - - - - - - ,-<-r .w - , , . , , - , - . - - - ,-
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE ,
Emergency Core Cooling System (ECCS) Actuation Table A.14-1 Importance Basis and Failure Mode Identification CONDITIONS THAT CAN LEAD TO FAILURE e
Mission Success Criteria ,
?
l The Emergency Core Cooling System (ECCS) actuation circuitry provides the in sary control signals to start each of the subsystems that comprise the EC subsystems are HPCI, ADS, LPCI, and CSS. The reql
- quacy of core cooling. This occurs regardless of the availability of off-site po The RCIC can also provide core cooling. The RCIC actuation circuitry is not; a part of the ECCS; however, because of the fun '
ECCS system actuation uses de pov.ci from two different supply panels, The subsystems that make up the ECCS are actuated by independent con provide pump start signals and valve control logic to e .
systems; not all are discussed below.
t IIPCI Actuation The HPCI system is actuated by a low water level (LL2) signal or a high d pressure signal. Control signals are provided to both the turbine steam discharge valves.
The actuation control circuitry is powered from 125 Vdc andFour consists chan- of a train that monitors reactor vessel level and containment atmospheric. pressure. l nels of each are provided and arranged so that one trip of the A or B charm ;
of the C or D channels will cause a system actuation. i t
RCIC Actuation I The RCIC system is actuated by a reactor low water , level (LL2) signal.;
signals are provided to both the turbine steam supply and the pump d ,
' The level signal causing actuation corresponds to a level of 118 inchesl instrument zero, and originates from the level indicating master trip units.
t A-101
l j
The actuation control circuitry is powered from 125 Vdc and consists of a single-loj train that monitors reactor vessel level. Four channels are provided and arranged s one trip of the A or B channels and one trip of the C or D channels will cause a syste actuation.
ADS Actuation The ADS system is actuated by reactor vessel low water level (LLI and LL3) signa at two distinct setpoints if low pressure core cooling is available. !
After receipt of initiation signals, and after a delay provided by timers, the sole operated air valves open, allowing nuclear system depressurization. The l system actuation is a single trip system containing two logics, each logic of wh initiate automatic depressurization.
LPCI Actuation The LPCI is actuated by low water level (LL3) in the reactor pressure vessel or h ;
drywell pressure if the high drywell pressure is also accompanied by a low pressure signal.
The actuation control circuitry consists of two logic trains, each powered from a sepa' rate de power supply. Successful actuation requires a signal from only independent, redundant logic trains. Each train monitors four independent c reactor vessel pressure, drywell pressure, and reactor vessel water level. Checks made of pump power supply availability. When one of the A or B channels and C or D channels of level or pressure are tripped, a trip is successful for that particul segment. Actuation of the LPCI system depends on detecting a trip condition reactor vessel water level network, or a trip in both the high drywell pressure and lo reactor vessel pressure networks.
f CSS Actuation The CSS is actuated by low water level (LL3) in the reactor pressure vessel or drywell pressure if the high drywell pressure is also accompanied by a low pressure signal.
The CSS logic scheme is comprised of one trip system per loop which actuates on :
receipt of sufficient low water signals or upon receipt of sufficient high drywell -
signals and low reactor pressure signals. The same sensors actuate the tr Loop A and Loop B using isolated relay contacts for isolation between trip sys .
1 i ECCS Actuation Mission Success ECCS actuation is successful if an actuation signal is provided when n:-ded fo of the subsystems of the ECCS. Failure of the ECCS occurs if any component l
actuation fails to receive it. The following top level events were defined:
A-102
l
- 5. Actuation signal to Recirculation Loop to RHR Pump Suction valve F015A (RHR-ICC-FA-G0001),
- 6. Actuation signal to Recirculation Loop to RHR Pump Suction valve F015B (RHR-ICC-FA-G0002),
- 11. Actuation signal to Core Spray Isolation MOV E21-F005A fails (CSS-IC G0001),
- 12. Actuation signal to Core Spray isolation MOV E21-F005B fails (CSS-IC G0002),
- 13. CSS actuation of Core Spray Pump E21-C001 A fails (CSS-ICC-FA-G
- 14. CSS actuation of Core Spray Pump E21-C001B fails (CSS-ICC-FA-G00 Note: Only the following failure modes contributed to the dominant accident quences
- 1. HPCI Actuation to HPCI Pump Discharge Isolation Valve F006 Fails Due to Failure of HPCI Turbine Stop Valve V8 or HPCI Turbine Steam Admission V Permissives HPCI flow injection depends upon successful opening of valve F006. Fail V8 or F001 permissives prevents F006 from opening (PC,PT,MT).
- 2. RCIC Actuation to RCIC Pump Discharge Isolation Valve F013 Fails Due Failure of Permissives for Stop Valve or RCIC Turbine Steam Admission Va Faults in K3 Relay RCIC flow injection depends upon successful opening of valve F013. Fa permissives for the RCIC turbine stop valve or valve F045, or faul prevent F013 from opening (PC,PT,MT).
A-103
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-HASED INSPECTION GUIDE Emergency Core Cooling System (ECCS) Actuation TABLE A.14 2 MODIFIED SYSTEM WALKDOWN 4 Pow Sup. Required Actual Desired Actual Locationi Position Position 7 Position Breaker #
Description ID No. Location Position I
E41.V 8 Control Closed HPCI Turbine ~
Stop Valve Room .
Panel !
P601 .
Comp.No. Reactor Bldg. On HPCI Injection E41- Control Closed B17 MCC 2XDA Valve F006 Room El. 20' Panel ,
P601 4 120V AC On Motor Htr. Dist. Pnt. ;
Circuit 2DXA El.17' e f Breaker Comp.No. Reactor Bldg. On E41- Control closed Turbine Steam B21 MCC 2XDA Supply Valve F001 Room El. 20' Panet P601 8 Reactor Bldg. On l Motor Her. Miscellaneous Circuit 120V AC Breaker Dist. Pni.
2DXA El.17' l
i e
5 E
i 1
A-104 1
- n--- --- - - - - ~ _ - - - - - - - . . . - . , , , - - , ,,7, e - - ., , , , . ,
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-HASED INSPECTION GUIDE i Emergency Core Cooling System (ECCS) Actuation i i
1 TABLE A.14 2 MODIFIED SYSTEM WALKDOWN (Cont'd) !'
Required Actual [
Desired Actual Pow. Sup. !
Location Position Position Desenption ID rio. Location Position Position - Breaker #
Normal l Closed Comp.No. Reactor Bldg.
Turbine Steam E51- Control 250V MCC l B44 Supply Valve
- F045 Room 2XDB El. 20' Normal /
RTGB South Local '
Panel Contl. Sw.
H12 P601 Reactor Bldg. On ;
L B44 l
Circuit 250V MCC '
Breaker 2XDB El. 20' i South i
8 Reactor Bldg. On Motor Htr. Miscellaneous Circuit 120V AC l Breaker Dist. Pnt.
2DXB El.17' f r
South i Comp.No. Reactor Bids. Normal Control Closed '
RCIC Injection E51- B41 250V MCC -
Valve F013 Room >
Normat/ 2XDB El. 20' ;
RTGB Local South -
Panel Conti. Sw.
H12-P601 Reactor Bldg. On j B41 Circuit 250V MCC Breaker 2XDB El. 20' South 5 Reactor Bldg. On .
Motor Hir. Miscellaneous I Circuit 120V AC !
Breaker Dist. Pnt.
2DXB El.17' ,
L
- South r
RCIC Stop Valve Permis- i sive*
K-3 Relay *
- Review latest surveillance tests on permissives logic for valves F045 and RCIC stop vl l r
I J r A-105 m, w-.. - - - --- - . . ,- , _ . - - . - - - . . . - - - - - - - - . - - - - -, + . - , - . - - . - - - - - - - - - - - - - - - - - + - - , < - - - - .,
I i
l TABLE A.14 2 (Cont'd)
REFERENCE DOCUMENTS I.D. NO. REV DATE TITLE System Procedures: 53 8/23/88 OP-16 Reactor Core Isolation Cooling (RCIC) 60 8/11/88 OP-19 High Pressure Coolant injection (HPCI)
System
Description:
Section M.3.13 Brunswick PRA Volume I -
" Emergency Core Cooling System Actuation" .
P&ID's No.:
Fig. M.3.4-25 Brunswick PRA Volume I Sheets 1,2,3,4 "ECCS Actuation Diagram" O
9 A-106 1
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l CAUTION: This is NOT a controlled document.
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- CAUTION: This is NOT a controlled document.
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1 l
APPENDIX B i
- Plant Operations, Surveillance and Calibration, and Maintenance Inspection Tables I
i
- l i
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-B ASED INSPECTION GUIDE TABLE B.1 PLANT OPERATIONS INSPECTION GUIDE Recognizing that the normal system lineup is important for any given standby safety system, the following human errors are identified in the PRA as important to risk.
Failure Discussion Transient or System Section 2 Par. 2.1
' Anticipated Transient ATWS with Isolation (MSIV Closure) and Operator Failure to Without Scram Control RPV Water Level at High
- (ATWS) or Low Pressure Section 2, Par. 2.1 ATWS With Isolation (MSIV Closure) and Operator Failure to inhibit ADS (with HPCI Opera-tional) and Failure to Control RPV Water Level at Low Pressure Table A.12-1, Item 3 Reactor Core l>ulation Operator Fails to Override Steam Cooling (RCIC) Tunnel High Temperature Table A.2-1 Item 4 High Pressure Coolant Operator Fails to Override Steam Tunnel High Temperature Trip Injection (HPCI)
Table A.2-1, Jtem 10 Operator Fails to Empty Drain Pot "A"
Table A.4-1 Item 2 Operator Fails to Open Switchgear Diesel Generator and Switchgear Cell Venti- Rooms After an HVAC Failure lation Table A.5-1, Item 1 Standby Liquid Control Operator Fails to Actuate the SLC (SLC) System System Table A.8-1, item 4 Residual Heat Removal I&C for Mini-Flow Rectrulation (RHR) System Line MOVs F007A and F007B Not Restored or PDIS N021A and )
- N021BM Table A.8-1. Item 10 Operator Fails to Correctly Initiate Suppression Pool Cooling-Loops A and B Table A.131, Item 1 Control Rod Drive Operator Fails to Fully Open (CRD) Hydraulic Sys- Valve F002A tem Table A.13-1, item 2 Operator Fails to Fully Open Valve F003 B-1
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE '
i j
TABLE B.2 SURVEILLANCE AND CALIBRATION INSPECTION GUIDANCE l
The listed components are the risk significant components for which periodic surveillance l
testing and/or calibration should minimize failure. l 1
Failure Discussion f Transient or System Diesel Generators 1, 2, 3 or 4 Fail Table A.1-1, Ite m I Emergency Diesel Gen- j crators (EDG) to Start or Run Diesel Generators 1, 2, 3 or 4 in Table A.1-1, Item 2 f l
Test or Maintenance Diesel Generators 1, 2, 3 or 4 Table A.1-1, item 3 Generator Output or Output 1 Breaker Failure !
Table A.2-1, ite m 1 :
High Pressure Coolant HPCI Turbine Fails to Start or I Injection (HPCI) Run HPCI Pump or Turbine in Test or Table A.2-1, item 2 r i
Maintenance Table A.2-1, item 3 Failure of Level Switch Table A.2-1, item 4 f Normally Closed HPCI Pump Dis- i charge Isolation MOV F006 Fails ;
Closed - i Delayed Actuation Signal to MOV Table A.2-1, item 6 ;
F006 on Scram Coupled with in-sufficient Flow Through the Mini-Flow Line Due to MOV F012 Failing to Open 1 Table A.2-1, item 7 )
Normally Closed Steam Supply Isolation MOV F001 Fails to Open f Failure of Lube Oil Cooling Table A.2-1, item 8 i Table A.2-1 Item 9 Failure of the Vacuum Breaker on l Startup Causes insufficient Steam -
7 l
Flow from the Turbine :
Insufficient Flow from HPCI Pump Table A.2-1, item 10 i Discharge Line Failures in Pipe Segment Leading Table A.2-1, item 12 l j
from Drain Pot A to Barometric :
Condenser r
B-2
TABLE B.2 SURVEILLANCE AND CALIBRATION INSPECTION GUIDANCE (Cont'd)
Failure Discussion Transient or System O-Ring Leakage or Other Dependent Table A.3-1. Item 1 Automatic Depressurization Sys- Failure Mechanisms Cause Two or More ADS SRVs Failing to Open tem (ADS)
Table A.4-1. Item 6 Diesel Generator and Control Circuit Fails to Provide Switchgear Cell Venti- Actuation Signal to Diesel Gener-ator Cells 1 and 2 Supply and Re-lation circulation Dampers Normally Open Reactor Water Table A.5-1, Item 2 Standby Liquid Control Cleanup MOV G31-F004 Fails to
, (SLC)
Close Faults in the SLC Injection Line Table A.5-1, item 3 from the Squib Valves to the Re-actor Vessel Plugging of Locked Open Manual Table A.5-1, Item 4 ,
Valve F001 at the SLC Tank l Table A.5-1, Item 5 SLC Pumps A and B in Test or Maintenance SLC Pumps Fail to Start or Run Table A.5-1 Item 6 l SLC Pumps Bypass Relief Valves Table A.51, Item 7 l l
F029A and F029B Fail to Close Table A.7-1, Item 1 Service Water Dependent, or Common Cause, Failure---4 or More SWS Pumps 1
' Fail to Run Loop A or Loop B RHR Heat Ex- Table A.71, item 2 changer is Unavailable Due to Test or Maintenance Table A.7-1, Item 3 Loop A or Loop B RHR Heat Ex-changer Fails Due to Plugging Diesel Generator 1, 2, 3 or 4 Hat Table A.7-1, item 4 Exchanger is Unavailable Due to Test or Maintenance Diesel Generator 1, 2, 3 or 4 Heat Table A.7-1, item 5 Exchanger is Unavailable Due to Plugging Normally Closed RHR Heat Ex-Table A.7-1, Item 6
( changer Suction Header Isolation
/ MOVs V105 and V101 Fail to Open Conventional Pump 2C Unavailable Table A.7-1 Item 8 Due to Test or Maintenance i
l l
B-3 l _ - - _-_
TABLE B.2 SURVELLLANCE AND CALIBRATION INSPECTION GUIDANCE (Cont'd)
Failure Discussion Transient or System RHR Loop A or Loop B Unavail- Table A.8-1, Item 1 Residual Heat Removal (RHR) able Due to Test or Maintenance RHR Heat Exchanger Bypass Table A.81, Item 2 MOVs F048A and F048B Fail to Close When Required RHR Mini-Flow Recirculation Line Table A.8-l. Item 3 MOVs F007A and F007B Fail to .
Close When Required Table A.8-1, item 4 I&C for Mini-Flow Recirculation '
Line MOVs F007A and F007B Not Restored or PDIS NO21 A and N021B Miscalibrated Table A.8-1, Item 5 Faults in Pressure Transmitters for MOVs F007A and F007B .
Table A.8-1, Item 6 Suppression Pool Strainers S1 and S2 Fail Due to Plugging RHR Injection Header to Suppres. Table A.8-1, Item 7 sion Pool Isolation MOVs F028A and F028B, F027A and F027B, or F024A and F024B Fail to Open or Fail to Close When Required Table A.8-1, item 8 Loops A and B RHR Pumps C002A, B, C, D Fail to Start or Run Common Cause Failure of RHR Table A.8-1. Item 9 Heat Exchangers Due to Plugging Fault in Battery Bank 2B-1 or in Table A.9-1, Item 1 DC Power Output Breaker Fault in Baticry Bank 2A-2 or in Table A.9-1, Item 2 Output Breaker Fault in Panel 4A or in the Sup- Table A.9-1, Item 3 ply Breaker ,
Table A.9-1 Item 4 l Fault in Panel 4B or in the Supply f
Breaker f Table A.9-1, Item 5 Fault in Distribution Switchboard 2A-P Table A.9-1, item 6 Fault in Distribution Switchboard 2B-N B-4
TABLE B.2 SURVEILLANCE AND CALIBRATION INSPECTION GUIDANj (Cont'd)
Discussion j Transient or System Failure Table A.9-1 Item 7 Fault in Battery Bank 2A-1 or in j the Output Breaker !
Table A.9-1, Item 8 Fault in MCC 2XDA or in Feeder from 2A-P or 2A-N Table A.10, Ite m 1 AC Power Failure to Recover Offsite Power ;
Within One Half Hour l r
- Table A.10-1. Items 2-3 '
480V Bus E7(E8) Fault or 4160/
408 Transformer Failure or Bus i
- E7(E8) Feeders Fail Open Table A.10-1, items 4-5 480 VAC MCC 2CA(2CB) Fault I or Feeder Fails Open Table A.10-1, item 9 Complete or Partial Loss of Offsite Power Cause by:
a) Feeder to Bus E3 Fails Open
- Due to I&C Related or Other Faults ,
b) Startup Auxiliary Transformer Fails c) Feeder from SAT to Bus 2D Fails Open Due to I&C Re-
- lated or Other Faults d) 4160 VAC Bus 2D Fault Table A.10-1, Item 10 Complete or Partial Loss of Offsite Power Caused by
a) Feeder to Bus E4 Fails Open '
Due to 1&C Related or Other Faults ,
b) Startup Auxiliary Transformer Fails ;
c) Feeder from SAT to Bus 2C !
Fails Open Due to I&C Re- .
lated or Other Faults d) 4160 VAC Bus 2C Fault Table A.10-1, Items 11-12 l 480 VAC MCC 2XA(2XB) Fault or Feeder Fails Open Table A.10-1, Items 13-14 480 VAC MCC 2XA-2(2XB-2)
Fault or Feeder Fails Open
- Table A.10-1. Items 15-16 Power Not Available from Bus >
El(E2) i I
I l f ,
B-5 ,
TABLE B.2 SURVEILLANCE AND CALIBRATION INSPECTION GUIDANCE (Cont'd)
Failure Discussion Transient or System Battery Rooms 2A and 2B Supply Table A.11-1 Item 2 Battery Room Fans and and Exhaust Dampers Fail Closed Heaters Due to Faults in the Actuation Control for the Vortex Dampers Failure of Thermostats for Battery Table A.11-1, Item 3 i
Rooms 2A and 2B Duct Heaters ,
Causing Overcoolin1, RCIC Pump Fails to Start or Run Table A.12-1, Item 1 -
Reactor Core Isolation Cooling (RCIC) -
RCIC Pump in Test or Mainte. Table A.12-1. Item 2 nance Faults in RCIC System Prevent Table A.12-1. Item 4
, RCIC Pump Discharge Flow Failure of Lube Oil Cooling Table A.12-1 Item 5 Table A.12-1, Item 6 Failure of Vacuum Breaker on Startup Causes Insufficient Steam Flow from the Turbine Table A.14-1, item i ECCS Actuation HPCI Actuation to Valve F006 Fails Due to Failure of V8 or F001 Permissives Table A.14-1, item 2 RCIC Actuation to Valve F013 Fails Due to Failure of Permissives for Stop Valve or F045 or Faults in K3 Relay W
G i.
B-6 l
BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK-BASED INSPECTION GUIDE TABLE B.3 MAINTENANCE INSPECTION GUIDANCE Failure Discussion Transient or System Diesel Generators 1, 2, 3 or 4 Fail Table A.1-1, item I Emergency Diesel Gen-erators (EDG) to Start or Run Diesel Generators 1, 2, 3 or 4 in Table A.1-1 Item 2
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Test or Maintenance Diesel Generators 1, 2, 3 or 4 Table A.1-1, Item 3 Generator Output or Output Breaker Failure HPCI Pump or Turbine Fails to Table A.21, item i High Pressure Coolant Injection (HPCI) Start or Run HPCI Pump or Turbine in Test or Table A.2-1, item 2 Maintenance Failure of Level Switch LEN014 Table A.2-1, item 3 Normally Closed HPCI Pump Dis- Table A.2-1, item 5 charge Isolation MOV F006 Fails Closed Delayed Actuation Signal to MOV Table A.2-1, item 6 F006 on Scram Coupled with in-sufficient Flow Through the Mini-Flow Due to MOV F012 Failing to Open Normally Closed Steam Supply Table A.2-1, item 7 1 solation MOV F001 Fails to Open Failure of Lube Oil Cooling Table A.2-1, item 8 Failure of the Vacuum Breaker on Table A.2-1, item 9 Startup Causes lasufficient Steam Flow from the Turbine Insufficcient Flow from HPCI Table A.2-1, item 10 Pump Discharge Line Failures in Pipe Segment Leading Table A.2-1, item 12 from Drain Pot "A" to Barometric Condenser O-Ring Leakage or Other Depend- Table A.3-1, item i Automatic Depressurization (ADS) ent Failure Mechanisms Cause Two or More ADS SRVs Failing to Open B-7
TABLE B.3 MAINTENANCE INSPECTION GUIDANCE (Cont'd)
Failure Discussion Transient or System Table A.4-1 Item 1 Diesel Generator and Supply and Recirculation Damper Switchgear Cell Venti- Faults for Diesel Generator Cells ,
lation 1, 2, 3 or 4 Insufficient HVAC Flow Through Table A.4-1, item 3 Switchgear Rooms E3 and E4 Due to Supply or Exhaust Damper Faults or Unavailability of the In-strument Air Supply item 3 Table A.4-1, Exhaust Damper Faults for Diesel Generator Cells 1, 2, 3 or 4 Table A.41, Item 5 Power Not Available to DG Cells 1 and 2 Exhaust Fans from MCC DGA and MCC DGB Control Circuit Fails to Provide Table A.4-1, item 6 Actuation Signal to DG Cells 1 and 2 Supply and Recirculation Dampers Normally Open Reactor Water Table A.5-1, Item 2 >
Standby Liquid Control (SLC) Cleanup MOV G31-F004 Fails to ,
Close Faults in the SLC Injectian Line Table A.5-1, item 3 from the Squib Valves to the Re-actor Vest.el Plugging of Locked Open Manual Table A.51, item 4 Valve F001 at the SLC Tank SLC Pumps A and B in Test or Table A.5-1, item 5 Maintenance SLC Pumps A and B t: ail to Start Table A.5-1, item 6 or Run SLC Pumps Bypass Relief Valves Table A.5-1, item 7 F029A and F029B Fail to Close ,
Table A.7-1, ite m 1 Service Water (SWS) Dependent, or Common Cause, ,
Failure-4 or More SWS Pumps ,
Fail to Run Loop A or Loop B RHR Heat 3x- Table A.7-1, item 2 changer is Unavailable Due to Test or Maintenance Loop A or Loop B RHR Heat Ex- Ta. A.7-1, Item 3 changer Fails Due to Plugging l
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TABLE B.3 MAINTENANCE INSPECTION GUIDANCE (Cont'd) !
Failure Discussion .
Transient or System !
DG 1, 2, 3 or 4 Hat Exchanger is Table A.7-1, Item 4 Unavailable Due to Test or Main-tenance '
DG 1, 2, 3 or 4 Heat Exchanger Table A.7-1, item 5 '
is Unavailable Due to Plugging Normally Closed RHR Heat Ex. Table A.7-1, item 6 f changer Suction Header Isolation
. MOVs V105 and V101 Fail to Open I Insufficient Flow Through Screens Table A.7-1, Item 7 I 1 A, IB, 2A and 2B Due to Fail- !
I ure of Screen Drives or Other ,
Faults l Conventional Pump 2C Unavailable Table A.7-1, item 8 i,
Due to Test or Maintenance I RIIR Loop A or Loop B Unavail. Table A.8-1, Item I i Residual Heat Removal l (RHR) able Due to Test or Maintenance !
RHR Heat Exchanger Bypass Table A.8-1, Item 2 MOVs F048A and F048B Fail to i Close When Required Table A.81, item 3 l RHR Mini-Flow Recirculation Line !
MOVs F007A and F007B Fail to l Close When Rgquired Table A.8-1. Item 4 ,
I&C for Mini-Flow Recirculation ,
Line MOVs F007A and F007B Not Resto; .d or PDIS N021 A and N021B Miscalibrated Table A.8-1, item 5 l Faults in Pressure Transmitters for MOVs F007A and F007B Table A.8-1, Item 6 Suppression Pool Strainers Si and ;
, S2 Fail Due to Plugging '
Table A.8-1, Item 7 RHR Injection Header to Suppres- '
sion Pool isolation MOVs F028A and F028B, F027A and F027B, or F024A and F024B Fail to Open or Fail to Close When Required Table A.81, Item 8 Loop A and Loop B RHR Pumps
[ C002A, B, C and D Fail to Start 4 j or Run l
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TABLE B.3 MAINTENANCE INSPECTION GUIDANCE (Cont'd)
Failure Discussion Transient or System Table A.8-1, item 9 Common Cause Failure of RHR Heat Exchangers Due to Plugging Fault in Battery Bank 2B-1 (2A-2) Table A.9-1, items 1-2 DC Power (DCP) or in Output Breaker Table A.9-1, items 3-4 Fault in Panel 4A(4B) or in the Supply Breaker Table A.9-1, items 5-6 Fault in Distribution Switchboard 2A-P (2B-N) ,
Fault in Battery Bank 2A-1 or in Table A.9-1, item 7 the Output Breaker ,
Table A.9-1, item 8 Fault in MCC 2XDA or in the Feeder from 2A-P or 2A-N Table A.9-1, item 1 AC Power (ACP) Failure to Recover Offsite Power Within One Half Hour Table A.9-1, items 2-3 480V Bus E7(E8) Fault or 4160/
408 Transformer Failure or Bus E7(E8) Feeders Fail Open Table A.9-1, items 4-5 480VAC MCC 2CA(2CB) Fault or Feeder Fails Open Table A.9-1, items 6-7 Fault in 4160V E3(E4) Bus Power Fails for Battery Rooms 2A Table A.9-1, Item 8 and 2B Duct Heaters Complete or Partial Loss of Offsite Table A.9-1, items 9-10 Power Caused by:
a) Feeder to Bus E3(E4) Fails Open Due to I&C Related or Other Faults b) Startup Auxiliary Transformer Fails c) Feeder from SAT to Bus -
2D(2C) Fails Open d) 4160 VAC Bus 2D(2C) Fault 480 VAC MCC 2XA(2XB) Fault Table A.10-1 Items 11-12 ,
or Feeder Fails Open Table A.10-1, Items 13-14 480 VAC MCC 2XA-2(2XB 2)
Fault or Feeder Fails Open Table A.9-1, items 15-16 Power Not Available from Bus El(E2)
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l TABLE B.3 MAINTENANCE INSPECTION GUIDANCE (Cont'd)
Discussion l Transient or System Failure Table A.11-1, Item 1 f Battery Rooms Fans Battery Rooms 2A and 2B Supply and Heaters and Exhaust Fans Fail to Run Table A.ll-1, Item 2 l Battery Rooms 2A and 2B Supply l and Exhaust Dampers Fail Closed '
Due to Faults in the Actuation Control for the Vortex Dampers !
Table A.11-1, Item 3 ;
Failure of Thermostats 'for Battery !
Rooms 2A and 2B Duct Heaters Causing Overcooling Table A.11-1, Item 4 I Insufficient Supply Flow to Battery Rooms 2A and 2B Due to Restric- l tion of the Intake Plenum Air Fil- I ters !
Table A.14-1, Item I Emergency Core Cool- HPCI Actuation to Valve F006 ing System (ECCS) Fails Due to Failure of V8 or .
l Actuation F001 Permissives Table A.14-1, Item 2 ,
RCIC Actuation to Valve F013 !
Fails Due to Failure of Permissives !
for Stop Valve or F045 or Faults i in K3 Relay RCIC Pump Fails to Start or Run Table A.12-1. Item 1 Reactor Core isolation '
Cooling (RCIC)
Table A.12-1, Item 2 l RCIC Pump in Test or Mainte- l nance Table A.12-1, item 4 ;
Faults in RCIC System Prevent a
RCIC Pump Discharge Flow t Table A.12-1, Item 5 l Failure of Lube Oil Cooling Table A.12-1, Item 6 f Failure of the Vacuum Breaker on l Startup Causes insufficient Steam Flow from the Turbine i t
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APPENDIX C ,
- Containment and Drywell Walkdown I
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BRUNSWICK STEAM ELECTRIC PLANT-UNIT 2 RISK BASED INSPECTION GUIDE TABLE C.1 CONTAINMENT AND DRYWELL WALKDOWN Discussion Since the drywell is generally inaccessible during normal plant operation, those compo nents listed in the preceding tables which are located either within the drywell o in the containment are listed below:
TAllLE C.1 CONTAINMENT AND DRYWELL WALKDOWN Desired Actual Position Position ID No. Location Description Containment Open F002
- Containment Operable
- 2. ADS Solenoid Valves El. 44' F013 A AZ 30' "A"PSL AZ. See Left F013C AZ 80' "B"PSL F013D AZ 80' "B"PSL F013H AZ 330' "D"PSL F013J AZ 280' "D"PSL F013K AZ 265* "C"PSL F013L AZ 100* "B"PSL (Ref. DWG F-2945)
- 3. SLC System: Locked Grating F008 Containment Inboard Injection Valve Above El. 38'-2' (Ref. DWG F-2945) Above Grat- Open ing AZ.190*
- 4. RHR/LPCI: Suppression Clear Suppression Pool Strainers Pool
" (Inspect only if accessible)
F067 Containment Locked Shutdown Cooling isolation Open El. 34'- Over-Valve head 17' Grating AZ.180' C-1 !
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TAllLE C.1 CONTAINMENT AND DRYWELL WALKDOWN (Cont'd)
Desired Actual Location Position Position Description ID No.
F060A Containment Open RHR Injection Line Valves El. 31'-
(Ref. DWG F-2943) Overhead 17' Grating AZ. 90' F060B Containment Open '
El. 3 l'-
Overhead 17' .
Grating AZ. 270' F007 Containment Open
- 5. RCIC System:
Steam Supply Line MOV El. 31'-
Overhead 17' (Ref. DWG F-2943 Grating AZ.185*
e C-2
1 APPENDIX D
- System Dependency Matrix A
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SYSTEM DEPENDENCY MATRIX TABLE D.1 FRONTLINE-SUPPORT SYSTEM DEPENDENCIES Support System Instrument AC Power DC Power Air HVAC Frontline B SWS RBCCW Division 2 i System Divisien i Note B Note A X Note A HPCI Note A Note B Note A Note A X RCIC Note A X Note B X Note A Note A CRD X Note C X X ADS Note B X X X CSS X Note B a X X b RHR X X SLC X X Note D X X X X DGs h PRA.
ibly Note A- Components depend upon this system for cenain types fi of o for low frequency LOCAs or high energy line breaks. f il Note C - Even ifinstrument air noninterruptible fails, the ADS valves have accumulators and backu to ADS was considered to be negligible. ,
Note D- The DGs have their own compressed air system.
SYSTEM DEPENDENCY MATRIX TABLE D.2 SUPPORT-SUPPORT SYSTEM DEPENDENCIES Supgiort System l Instrument l AC Power DC Power Air IIVAC Support B SWS RBCCW Division 1 Division 2 A System X X X X AC Power X Note A X X DC Power Note A Note B Note B X SWS X X X X RBCCW X X Note C X HVAC X X Note A - If ac power is lost, batteries can supply de power to necessary systems for at least four hours.
e d to 4 Note B - Only for certain SWS applications.
Note C - The DG cell HVAC dampers fail closed upon loss of air. (These remain open if air is lost.
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