ML20127L660
| ML20127L660 | |
| Person / Time | |
|---|---|
| Site: | 05200001 |
| Issue date: | 01/12/1993 |
| From: | Fox J GENERAL ELECTRIC CO. |
| To: | Poslusny C Office of Nuclear Reactor Regulation |
| References | |
| NUDOCS 9301270253 | |
| Download: ML20127L660 (755) | |
Text
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GE NucIcar Energy ww ::,m c?;e 115 Curim r kene Swn Jnt rA !!5125 January 12,1993 Docket No. STN 52 001 Chet Posiusny, Senior Project Manager Standardization Project Directorate Associate Directorate for Advanced Reactors and License Renewal Office of the Nuclear Reactor Regulation
Subject:
Submittals Related to Resolution of ABWR Open Items
Dear Mr. Poslusny:
In accordance with your request, I am providing the attached list of recent submittals related
,. to the resolutim of open items identified in the Draft Final Safety Evaluation (DFSER) for the Advanced Boiling Water Reactor (ABWR), They had either been provided to the Staff by facsimile or by direct mail but had not been sent to the Document Control Desk directly.
Please attach this transmittalletter to these documents to facilitate docketing of the information.
In the future, for those submittals which must be provided immediately to the Staff to support the accelerated review schedule, I will attach the submittal to a transmittal memo, provide it via facsimile machine, then send the original through the mail. For those provided via overnight mail, I wi!! include a transraittal memo.
Sincerely,
.b Ja'ck Fox Advanced Reactor Programs cc: Jack Duncan Jnut 260004 c .#pq I
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-' e Recent submittais related to resolution of ABWR open items:
-DAIE_ ITEM and SUBJECT 01/11/93 Fax from J. Fox to C. Posiusny
- USl\GSl(ABWR) 01/06/93' Fax from J. Fox to C. Poslusny, W. Burton Marked up SSAR Section 5.4.93 01/06/93 Fax from J. Fox to C. Poslusny, G. Kelly Core Damage Frequency Sensitivity to Maintenance Outage Times 01/05/93 Fax from J. Fox to C. Postusny .
Inservice Testing, markup of SSAR Section 3.9.53.6 12/31/92 Fax from J. Fox to C. Posiusny, G. Kelly ABWR Seismic Margins Analysis 12/29/92 Fax from J. Fox to G. Kelly Responses to Staff Questions on ABWR Uncertainty Analysis 12/21/92 '
Fax from C. Buchholz to C. Posiusny -
Response to Staff Questions on Sump Shield 12/18/92. Fax from J. Fox to C. Poslusny, W. Burton Resolution of Plant Systems Open item 9.5.13.1-1 12/18/92 Fax from J. Fox to C. Poslusny, G. Thomas ABWR Conformance with Generic Letter 92 04 12/18/92 Fax from J. Fox to C. Poslusny, W. Burton -
Resolution of Plant Systems Open Item 6.2.4-2 12/18/92- Fax from J. Fox to D. Scaletti, C. Posiusny Response to SSAR Appendix 19P Issues 12/17/92 Fax from P.D. Knecht to R. Palla, G. Kelly .
. Suppression Pool Bypass Evaluation
.12/17/92 Fax from J. Fox to C. Poslusny SSAR Revisions to Chapter 13 12/17/92 Note from P.D. Knecht to D. Scaletti, R. Palla = .
Design Modification Evaluation (SSAR Appendix 19P)
-12/17/92 SSAR Appendices 190 (Shutdown Rick) and 19R (Flooding Analysis)
.(Items were provided in overnight package with no transmittal memo.)
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7-12/16/92 Fax from L. Frederick to R. Palla Draft SSAR Section 19D.7 12/15/92 Fax from J. Duncan to G. Kelly, R. Palla, D. Scale:ti, C. Poslusny ABWR PRA Issue Status 12/14/92 Fax from J. Duncan to O. Kelly, B. Palla Draft Version of SSAR Section 19.7 12/10/92 Fax from C. Buchholz to C. Poslusny Severe Accident Resolution issue Responses 12/08/92 Fax from R. Louison to C. Poslusny ABWR ITAAC-2.10 Power Cycle 12/08/92 Fax from N. Hackford to C. Poslusny ABWR ITAAC Responses to NRC Ouestions 12/07/92 Fax from J. Quirk to C. Posiusny, J. Wilson GE Schedule for FDA Activities 12/04/92 Fax from C. Larson to O, Kelly Draft SSAR Appendix 19K 12/02/92 Fax from J. Fox to C. Posiusny DFSER Issue Resolution Schedule
! 11/30/92 Fax from J. Fox to C. Posiusny
- FDA Schedule Milestones
- - 11/23/92 Fax from L. Frederick to R. Palla HEP Information
- 11/16/92 Note from J. Fox to C. Poslusny High Frequency Seismic Design Information
, 11/12/92 Fax from L. Frederick to R. Palla Response to NRC Questions on Ibman Error Modeling in ABWR PRA 11/05/92 Fax from P.D. Knecht to R. Palla, G. Kelly i Response to NRC Questions on Suppression Pool Bypass 10/28/92 Letter to R. Palla from H. Careway ABWR PRA Consequence Analysis Inputs 4
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- Enclosure 3 TABLE 1. LISTING OF V51s AND G51s AFFECTING DESIGN OF ABWR.
W Dn kj $mQ l. Open items 5/rus_M CTE fy.ft Issue No. Issue Title f'"'#Y IE)
A8 Mark !! Containment Pool Dynamic Loads Long Term $,I.',2 g#
A-16 Steam Effects on BWR Core Spray Distribution Mt y pA p-s2 A-30 Adequacy of Safety Related DC Power Supply J.ntm26 5 tt /7t* M6 X B5 Ductility of Two Way Slabs and Shells and Buckling #W' "M B6 Loads, load Combinations, Stress Limits pgjn g,[ gg,jwgr B-9 Electrical Cable Penetrations of Containment di' h3 N / O B-14 Study of Hydrogen Mixing Capability in Containment Post LOCA5-/ rim e V "' '""'
B-26 Structural Integrity of Containment Penetrations M' #. ^ A N XX X X B-32 Ice Effects on Safety-Related Water Supplies 3. irim s o m itre su B 48 BWR Control Rod Drive Mechanical Failures ,g, g +
B 51 Assessment of Inelastic Analysis Techniques for '
Equipment and Components Sme>rw ><smm Pt B 57 Station Blackout f,f ,q99 ,,f ,fm gy C3 Insulation Usage Within Containment C 11 Assessment of Failure and Reliability of Pumps and Valves arp, N# M C-12 Primary System Vibration Assessment sRP FM*
D3 Control Rod Drop Accident sy d A tC*
X f2. Failure of Protective Devices on Essential Equipment pno p -
- 6. Separation of Control Rod from its Drive and BWR High Na #8q #
! Rod Worth Events 1
- 16. BWR Main Steam Isolation Valve Leakage Control Systems 5 # Tre '-f "' N M
- 19. Safety Implications of Nonsafety Instrument and Control 3. ,rea A YT ##### # d Power Supply Bus L 20. Effects of Electromagnetic Pulse on Nuclear Power NR ##i" s 1 Plants re-JsM l **"d'C' #933 WR WEA ALY REM W S Sv83 UmdQ IU AMIAfE #U MEp. mb'0/Vm
g, ; ' '
._; H d '.LE M .M M '8 M0Rfl ES JU BouR' AWR
%D wi er M 5h hemNo. Item Title PoLr h p$"/d/" "
- 39. Potential for Unacceptable Interaction Between the CR0 f. trrm y sn e rm n System and Non Essential Control Air System
- 46. Loss of 125 Volt DC Bus J'/
- 26 * "" M i
- 47. Loss of Offsite Power #
J-l,rj g ,) e'o uf
- 48. LCO fer Class lE vital Instrument Buses in Operating Reactors f.,7,m a s utme/s
- 62. Reactor Systems Bolting Applications "'# #
X 73. Detached Thermal Sleeves #4 jff, x x 76.
Instrumentation and Control Power Interactions paop N0. 9F5.
X 77.
Flooding of Safety Equipment Compartments by Back flow f irw &l7 m //7d Ad7 Through Floor Drains i
x x 110.
Equipment Protective Devices on Engineered Safety BR#F Features 114. Seismic induced Relay Chatter #
h[ r'4 x XX 120. On line Testability of Protection Systems W D-x 132. RHR Pumps Inside Containment DROP -
135.
Storage and Use of Large Quantities of Cryogenic il Combustibles On Site
., ;x 142. Leakage Through Electrical Isolators in # #-
.j instrumentation Circuits 149. Adequacy of Fire Barriers
,x 151. Reliability of Anticipated Transient Without #0 M' N
, SCRAM Recirculation Pump Trip in BWRs IX 153. Loss of Essential Service Water in LWRs I
- if tf l 155.3 Improve Design Requirements for Nuclear Facilities NP i
Lf- L ICGus /U615J VV f>p. 20 PS)0 Riff If DA 2
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- J All, l i : 92; Il:20A!! 'GE E LEAI A PI' i
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- 2. Items that Reauire Justification from GE
- wa
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i item No. Item Title
- Ar tolo /rw a pioretr_ l'rrov c !
j 25. Automatic Air. Header Dump on BWR Scram System emx na n //
- 40. Safety Concerns Associated with Pipe Breaks in the SWR N4 #4"8'#
p Scram System
i ant /Ffo l X 94. Additional Low Temperature Overpressure Protection for Light Water Reactors #14t/ GL 90 44
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- 3. Items That Are Addressed-In'The $$AR And Are To Be Evaluated-5' item No. Item Title
(
} A 13 Snubber Operability Assurance ct Cl II j g p.; 3 9,3 +
)( A 17 Systems Interactions in-Nuclear Power Plants VH- ifN po RPR.
A-24 Qualification of Class IE Safety-Related_ Equipment- guir roMi" A-25 Non Safety Loads on Class IE Power Sources - C
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!y SRP REV'JHS g j x A 29 Nuclear Power Plant Design for the Reduction of # ' W
1 #f f D. -
Vulnerability to Industrial Sabotage
- A 31 RHR Shutdown Requirement 3
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_ J4 P J.if.7 A-35 Adequacy of Offsite Power Systems 3, p ga,j +
A-36 Control of- Heavy Loads Near Spent Fuel:
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A 39 ' Determination of Safety Relief Valve Pool Dynamic 3RP AWI//04/
Loads 1and Temperature Limits vs T x )( A-40 Seismic-Design' Criteria vfrJ 15AP #EMMA#
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g g item No. Item Title
- hu .h s 4 O'N' $1 froctuc1' A 42 Pipe cracks in Boiling Water Reactors 4 T#Q*
j A-43 Containment Emergenc'y Sump Performance v31 5#r grg'"
4 y j A 44 Station Blackout un Ran/AF6 i
ovtos 1. lif x A 45 Shutdown Decay Heat Removal Requirements un yy ['
)( X A 47 Safety Implicat Mns of Control Systems un g . .
X X X A-48 Hydrogen Control Measures and Effects of Hydrogen gg i v sz Burns on Safety Equipment
- gf q,
- B-10 Behavior of BWR Mark til' Containments ggy S N P #Fru/ov
' B-36 Develop Design, Testing, and Maintenance Criteria for Atmosphere Cleanup System Air Filtration and Adsorption ava 6vspr/.svo "
Units for Encineered Safety Feature Systems and for # F6 * '" "
Normal Ventilation Systems X B-55 Improved Reliability of Target Rock Safety Relief Valves /40.
j X X B-56 Diesel Reliability gpu 8-63 Isolation of Low Pressure Systems Connected to the J 4 F 19 4 Reactor Coolant Pressure Boundary l C 10 Effective Operation of Containment Sprays in a LOCA $4r452*
i- X X )( 29. Bolting Degradation or Failure.in Nuclear Power Plants 88 M ^'d A N
! 36. Loss of Service Water pg gap orvino#
- so hce
- 50. Reactor Vessel Level Instrumentation in BWRs pg mpg . g.f 4
! )( X 57. Effects of Fire Protection System Actuation ,,,,*
on Safety Related Equipment y, X x x 75. Generic Implications of ATWS Events NA RM at the Salem Nuclear Plant
,~
p vist h l H 3 XI 82. Beyond Design Basis Accidents in Spent fuel Pools - #"- so N Xf
! 86, t.ong Range' Plan for Dealing with Stress Corrosion #B (($,[(*
X X X X 96. RHR Suction Valve Testing 3. ;rs /or niirm se r 4
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Asvots Me IV A9pnl ALUR q'$ n'w l cz u QQ b '* Re>0wn w na Ites NL Item Tit 1L P,.d r,71 gas ave r_
101. .BWR Water Level Redndancy n/on a t 5 9->I l ri r r .
- y y xx 105. Interfacing Systems LOCA at LWRs giu x 106. Piping and Use of Highly Combustible Gases in Vital m 4 0, i Areas xx 113. Dynamic Qualification Testing of Large Bore giu av ge og, Hydraulic Snubbers ,
X: xix s 128. Electrical Power Reliability gpy &L j/ :-It c4
- at Xp XX 130. Essential Service Water Pump Failures at Multiplant Hl6H Sites st p,ig )3 i
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, s c TRANSACTION REPORT > c1_ u _1ee3<t o o 14 u 6 E RECEIVE 3 s
j NO. DATE T it1E DESTINATION STATION PG, DURATION tODE RESULT-6731 1-11 14:14 4089251193 6 O*02'26' NORf1.E OK 6 O'02'26*
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(2) The feedwater lines are designed to conduct The snarerials used in t' e piping are in water to the reactor vessel over the full accordance with the applicable design code and (
range of reactor powca operation. supplernentary requirements described in Section 5.4.9.3 Description 3.2. The valve between the outboard isolation valve and the shutoff valve upstreatu of the RHR entry to the feedwater line is to effect a Tbc main stearn piping is described in Section closed loop outside containment (CLOC) for 10.3. The main steam and feedwater piping from containment bypass leakage control (Subt. :tions the reactor through the containment isolation 6.2.6 and 6.5.3).
interfaces is diagrammed in Figure 5.13.
The general requirements of the feedwater As discussed in Table 3.21 and shown in system are described in Subsections 7.1.1.7, Figure 5.13, the main steamlines are Quality 7.7.1.4, 7.7.2.4, and 10.4.7.
Group A from the reactor vessel out to and includ. I ing the outboard MSIV and Ouality Group B from 5.4.9.4 Safety Evaluation the outboard MSIVs to the turbine stop valve.
They are also Seismic Category I only from the l Differential pressure on reactor internals reactor pressure vessel out to the seismic inter- !
under the assumed accident condition of a rup face restraint. tured steamline is limited by the use of flow 3
IN SERT A l restrictors and by the use of four main steam-The feed ster piping consists of two $50 A lines. All main steam and feedwater piping will i
diameter lines o the_feedwater supp!v header be designed in accordance with the requirements to the reactor. ' Isolation of each line i} defined in Section 3.2. Design of the piping in accomplished by two containment isolation valves accordance with these requirements ensures consisting of one check valve inside the drywell meeting the safety design bases.
and one positive closing check valve outside ,
/'
containment (Figure 5.13). Also included in 5.4.9.5 Inspection and Testing this portion of the line is a manual maintenance ("
valve (F005) between t)e inboard isolation valveJ Testing is carried out in accordance with and the reactor nozzleNThe design ternperature Subsection 3.9.6 and Chapter 14. Inservice and pressure of the feedwater line is the same as inspection is considered in the design of the that of2 the reactor inlet nozzle (i.e.,87.9 main steam and feedwater piping. This consider-kg/cm g and 3020C). ation assures adequate working space and access The feedwater piping upstream of the second' isolation valve contains a remote, manual, 5.4.10 Pressurizer motor-operated gate valve and upstream of the
, gate valve, a seismic interface restraint. The Not Applicable to BWR g
" outboard isolation valve and the seismic inter-face restraint provide a quality group transi- 5.4.11 Pressurizer Relief Discharge Systern tional point in the feedwater lines.
Not Applicable to BWR As discussed in Table 3.21 and shown in l Figure 5.1-3 the feedwater piping is Quality 5.4.12 Valves Group A from the reactor pressure vessel out to and including the outboard isolation valve, 5.4.12.1 Safety Design Bases n Quality Group B from the outboard isolation valve
, 3 to and including the scismic interface restraint, Line valves, such as gate, globe, and check and Quality Group' D beyond the shutoff valve.
The feedwater piping and all connected piping of l 65A or larger nominal size is Seismic Category I only from the reactor presjure vessel out to and including the seismic inter face restraint.
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- j. On each of-the feedwater lines from the common feedwater supply header, there shall be a seismic interface restraint. - The seismic interface restraint serves as the boundary between the Seismic Category I piping and the non -
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' seismic piping. Downstream of the seismic intedace restraint, there is a remote' manual, motor-operated valve powered by a non safety-grade bus. These motor-
. operated valves serve as the shutoff ~ valves for the feedwater lines; Isolation of each line is accompiished by two containment isolation valves consisting of one check valve inside the drywell and one positive closing check valve outside containment (Figure 5.1-3), The positive closing check valve outside the containment is a spring-closing
- check valve that is held open by air. Inside the containment, downstream of the F
inboard FW line check valve th r' ie s s a manual maintenance valve (821 F005),
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< TRANSACTION REPORT > 01-06-1993(LED) 09:34-E RECE I VEE 3 PC. DATE TIME DESTINATION STATION PO. DURATION MODE RESULT 7120 1-06 09:32 408 92S 1687 3 0*01'27' NORr1.E OK i 3 0*01'27*
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). November 18,1992 cc: J. D. Duncan S. Visweswaran 4
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- R. P. Raftery a
Subject:
ABWR CDF Sensitivity to Test and Maintenance Outage Times AttachednewSSAR5ection190.9(Attachment 1)-respondstoanNRCrequest i for information~regarding ABWR C0F sensitivity to outage times and
- surveillance intervals. Its inclusion in the.SSAR will close out DSER open i item C-48 on page nine of J. D. Duncan*s 10/02/92 punch list. Attachment 2 f provides update replacements for section 190.3.4 and Table 190.3 2 which j are consistent with Section 190.9. ,
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- R. P. Raftery Principal Engineer 4
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Attachment 1 190.9 C0F SENSITIVITY TO OUTAGE TIMES AND SURVE!LLANCE INTERVALS 190.9.1 Summary A: a consequence of 1992 GE-NRC discussions of ABWR DSER questions regarding applicability of GESSAR test and maintenance (T&M) ~ unavailabilities to the ABWR PRA, it was agreed that ABWR T&M unavailabilities would be increased over those of GESSAR to provide utility operational flexibility.
Consequently T&M values for RCIC, HPCFB, HPCFC, RHRA, RHRB, and RHRC were-each raised to two percent-in-the PRA model, and the calculated core damage frequency of 1.56E-07 reflects inclusion of these values.
190.9.2 Sensitivity to Test and Maintenance Outage Times C0F sensitivity to T&M outage times was assessed by varying system values individually as well as'in combination. Results presented in- attached Tables 19D.91 and 190.9-2 -illustrate the impact of increasing system T&M unavailabilities by a factor of five from two to ten percent. -Ten percent was judged to be a reasonable upper bound' for T&M unavailability for a single system. As can be seen, calculated CDF.is most sensitive to the RCIC system T&M unavailability. This is due in large part to the fact that station blackout sequences dominate C0F, and in these sequences RCIC is essential for successful core cooling. Since no credit was taken in the Level 1 PRA for fire water injection, this calculated CDF sensitivity to RCIC T&M-unavailability is actually somewhat conservative. in addition, ample time is available for maintenance of RCIC-during refueling outages without CDF risk implications, since during shutdown the system is unable to perform its ECCS function.
Second in importance is the T&M unavailability of HPCFB. HPCFB includes a hard-wired manual initiation backup.in the control room. This provides a diverse means of manually initiating HPCFB in-the event'of essential multiplexing system common mode failure, a feature which; increases the importance of HPCFB relative to other ECCS systems.-
CDF-is:very insensitive to the T&M unavailability of systems _other than RCIC' and HPCFB, either individually or in combination. Table 190.9-3 provides a summary of bounding scenarios in which individual: syitems are removed-completely from service. These results support the conclusions drawn from Tables 190.9 1 and 19D.9 2. Further, even with RCic the most sensitive system completely out of service,. the NRC core damage frequency goal of
~'
10E-05 is still-satisfied.
190.9.3 Sensitivity to Surveillance: Intervals .
Since no' changes were made to established BWR surveillance intervals (CESSAR values.were applied in the ABWR PRA), sensitivity to changes in surveillance intervals was not investigated.
.. .- -. - . . - .. ~ . . . . - -. . . .- --. . . . . - . - . - - . . - - - . . . - .
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! TABLE 190.9 1 l CDF SENSITIVITY TO TLM OUTAGE UNAVAILABILITIES
! 115][d SINGLE SYSTEM PERTURBATIONS TO BASE CASE T&M VALUE OF TWO PERCENT RCIC 2.00E-2 1.00E-1 2.00E 2 2.00E 2 2.00E-2 2.00E 2 2.00E 2 i HPCFB 2.00E 2 1.00E-1 HPCFC 2.00E-2 1.00E-1 2.00E-2 1.00E-1 l
RHRA i RHRB 2.00E-2 1.00E-1 RHRC 2.00E 2 1.00E-1 3
CDF 1.56E-7 2.93E-7 1.77E-7 - 1.57E-7 1.57E-7 1.56E-7 1.56E-7 e
% INCR - 86 13 <1 <1 <1 <l i
TABLE 190.9 2 l CDF SENSITIVITY TO T&M OUTAGE UNAVAILABILITIES
! SYSTEM BULTIPLE SYSTEM PERTURBATIONS TO BASE CASE TLM VALVE OF TWO PERCENT
, e
- RCIC ._1.00E-1 2.00E 2 2.00E-2 1.00E-1 2.00E-2 1.00E-1 1.00E-1 I HPCFB 2.00E-2 1.00E-1 1.00E-1 ~1.00E-1 1.00E-1 1.00E-1 t
l HPCFC 2.00E-2 1.00E-1 2.00E-2 1.00E-1 1.00E-1 1.0PE:1 i
- RHRA 11QQJ-1 2.00E-2 2.00E 2. 2.00E-2 1.00E-1 2.o* o s 2 2.c o G-1 RHRB m " " " "
1.00E-1 i RHRC 1.00E-1 1.00E-1 C0F 2.94E-7 1.78E-7 1.57E-7 3.14E-7 1.77E-7 3.15E-7 3.18E-7 2
% INCR 88 14 <1 101 13 102 104 4
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TABLE 190.9-3 CDF SENSITIVITY TO T&M OUTAGE UNAVAILABILITIES SYSTEM IMPACT OF SINGLE SYSTEMS COMPLETELY REMOVED FROM SERVICE- .
RCic 2.00E-2 hQQ 2.00E-2 2.00E-2 2.00E-2 2.00E 2 2.00E-2 HPCFB 2.00E-2 idQ HPCFC 2.00E 2 ldQ -
RHRA 2.00E-2 hQQ RHRB 2.00E-2 hQQ i
l RHRC
= a a 2.00E-2 LQQ -
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CDF 1.56E-7 1.83E 6 4.08E 7 1.62E-7 1.64E-7 1.59E-7 1.57E ;
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[bl.,';93 10:ikel 6E lELEAL App g73 p, g 4 Attachment 2 19D.3.4 Test and Maintenance Unavailabilities Equipment test and mainterance unavailabilities used in the initial ABWR PRA submittal were taken from the GESSAR PRA and were based upon BWR experience.
in subsequent discussions with NRC regarding applicability of the GESSAR values to ABWR it was agreed that ABWR T&H unavailabilities would be increased over those of GESSAR to provide utility operational flexibility.
Consequently TLM values for RCIC, HPCFB,.HPCFC, RHRA, RHRB, AND RHRC were each raised to two percent in the PRA model as shown in Table 190.3 2. The final calculated CDF of 1.56E-07 reflects inclusion of these values.
Sensitivity of CDF to ECCS T&M outage times is summarized in Appendix 190.9.
Table 190.3-2 ABWR TEST AND NAINTENANCE UNAVAlt.A81LITIES RCic 0.02 HPCFB 0.02 HPCFC 0.02 RHRA 0.02 RHRB 0.02 RHRC 0.02 ,
__m__ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
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N 8 JJ GENochearEnergy ABWR I/s/93 Date =r!4 l15 To C (Che&PosInny x 4im Fax No. -
(Tel) 50q- 2 L 6 o Thispageplus 7 page(s)
From TerK FdY Mail code 7 81 175 Curtner Avenue San Jose, CA 95125 Phone (408) 925 # 2 'I FAX (408)925-1193 or (408) 925-1687 Subject rs T
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ny.t a um a mcun Am gg u g ABWR /ust ceWB f#///ANST &M-08%4& MhdREVDNga 4 u-e Standard Plant 3.9.5.3.6 Stress, Defonnation, and Fatigue 3.9.6 In. service Testing of Pumps and Valves Limits for Safety Class sad Other Reactor laternals (Eacept Core Suppcrt Structures) In service testing of safety related pumps and valves will be performed in aecordance witb-For safety class reactor internals, the stress the requirements of ASMEAM Code 1990mSub]
deformation and fatigue criteria listed in Tables sTetion ISTflWC and Annendix 1.fTable 3.9 8 3.9 4 through 3.9 7 are based on the criteria lists the in. service testing parameters and established in applicable codes and standards for frequencies for the safety-related pumps and ,
similar equipment, by manufacturers standards, or valves. The reason for each code defined 6 by empirical methods based on field experience testing caception or justification for each code <
and testing. For the quantity SFmin (minimum exemption request is noted in the description of f safety factor) appearing in those tables, the the affected pump or valve. Valves having a $
following values are used: containment isolation function are also noted in <
the listing. In. service inspection is discussed Senice Servtce in Maech W and M.
37 Lml Conditina m ain Details of the in service testing program, A Normal 2.25 including test schedules and frequencies will be B Upset 2.2$ reported in the in-service inspection and C Emergency 1.5 testing plan whleh will be provided by the D Faulted 1.125 applicant referencing the ABWR design. The plan willintegrate the applicable test requicements Components inside the reactor pressure vessel for safety related pumps and valves including such as control rods which must move during those listed in the technical specilications accident condition have been examined to (Chapter 16) and the containment isolation-determine if adequrte clearances exist during system, (Subsection 6.2.4). For example, the emergency and faulted conditions, No mechanical periodic leak testing of the reactor coolant clearance problems have been Identified. The pressure isolation valves in Table 3.9 9 will be forcing functions applicable to the reactor performed in accordance with Chapter 16 internals are discussed in Subsection 3.9.2.5. Surveillance Requirement SR 3.6.1.5.10. This plan will include baseline pre.nervice testing The design criteria, loading conditions, and to support the periodic in service testing of analyses that provide the basis for the design of the components. Depending on the test results, the safety class reactor internals other than the the plan will provide a commitment to core support structures incet the guidellacs of disassemble and laspect the safety related pumps NG 3000 and are constructed so as not to and valves when limits of the OM Code are adversely affect the integrity of the core exceeded, as described in the following support structures (NO 1122), paragraphs. The primary elements of this plan, including tbc requirements of Generic Letter The design requirements for equipment 8910 for motor operated valves, are delineated classified as non esfety (other) class laternals in the subsections to follow. (See Subsection (e.g., steam dryers and shroud heads) are 3.9.7.3 for COL license information specified with appropriate consideration of the requirements),
intended service of the equipment and expected plant and environmental conditions under which it 3.9.6.1 In earvice Teatlas of Safety Related will operate. Where Code design requirements are Punspa not applicable, accepted industry or engineering practices are used. The ABWR safety related pumps and piping configurations accommodate in-service testing at a flow rate at least as large as the maximum design flow for the pump. In addition, the 3M Amendment
, 3A!!. 5 M ll: D M GE E LEAF AEW gg gjg ABWR awan '
gm e Standard Plant sizing of each ininimum recirculation flow path is experience. (See Subsection 3.9.7.3(1) for COL cvaluated to assure that its use under all license information requirements.)
analyced conditions will not result in degradatic s of the pump. The flow rate through 3.94.2.2 Motor Operated Valves minimum recirculation flow paths can also be The motor operated valve (MOV) equipment periodically measured to verify that flow is in accordance with the design specification, spec!rications require the incorporation of the results of either in situ or prototype testing The safety-related pumps ere provided with with full flow and pressure er full differential instrumentation to verify that the net positive pressure to verify the proper sizing and correct suction head (NPSH) is greater than or equal to switch settings of the valves. Guidelines to the NPSH required during all modes of pump justify prototype testing are contained in Ocneric Letter 8910, Supplement 1, Ouestions 22
, operation. These pumgcan be disysembl d for ,
v
' evaluation wb J g,$1IFsection ISgtesting results and 24 through 28, The COL applicant will in a deviation 'which falls within the ' required provide a study to determine the optimal [ ,
/kd 6 action range.' The Code provides criteria limits frequency for valve stroking during in.scrvice for the test parameters identified in Table testing such that unnecessary testing and damage 3.9 8. A program will be developed by the COL is not done to the valve as a result of the i testing. (See Subsection 3.9.7.3(2) for COL f applicant to establish the frequency and the extent of disassembly and inspection based on license information requirements),
suspected degradation of all safety related pumps, including the basis for the frequency and The concerns and issues identified in the extent of each disassembly. The program may Generic Letter 8910 for MOVs will be addressed be revised throughout the plant life to minimize prior to plant startup. The method of assessing disassembly based on past disassembly the loads, the method of sizing the actuators,.
experience. (See Subsection 3.9.7.3(1) for COL and the setting of the torque and limit switches license information requirements.) will be specifically addressed.- (See Subsection 3.9.7.3(3) for COL license informationg 3.94.2 laservice Treting of Safety Related requirement 8).
Valves The in service testing of MOVs will rely on 3.94.2.1 CheckValm diagnostic techniques that are conalstent with the state of the art and which will permit an All ABWR safety related piping systems assessment of the performance of the v 1 incorporate provisions for testing to demonstrate actual loading. Periodic testing per 6ubsectEup the operability of the check valves under design ($t)%11 be conducted under adequate differ-conditions. In service testing will incorporate ential pressure and flow conditions that allow a the use of advance non intrusive techniques to justifiable demonstration of continuing MOV per;odically assess degradation and the capability for design basis conditions, performance characteristics of the check valves, including recovery from inadvertent valve Tb Subsection 1537(Eiiis will be performed, and positioning, MOVs that fall the acceptance gg c eck valves that fail to exhibit the required criteria, and are ' declared inoperable," for performance can be disassembled for evaluation. stroke tests and leakage rate can be The Code provides criteria limits for the test disassembled for evaluation. The Code provides criteria limits for the test parameters
- parameters identified in Table 3.9 8. A program 11 be developed by the' COL applicant to identified in Table 3.9 8. A program will be 2 establish the frequency and the extent of developed by the COL applicant to establish the (
disassembly and inspection based on suspected frequency and the extent of disassembly and degradation of all safety related pumps, inspection based on suspected degrada. tion of all including the basis for the frequency and the safety related 'MOV's*, including the basis for.
extent of each disassembly. The program may be the frequency and the extent of each revised throughout the plant life to minimize disassembly. Tbc program may be revised disassembly based on past disassembly throughout the plant life to minimize 3wI Amnoung
I ,
J A!,l. 5 8 ll:2~AM GE IPJCLEAR A DP 1288 L46 ABWR 3mioare prva Standard Plant disassembly based on past disassembly exper.
lence. (See Subsection 3.9.7.3(1) for COL license information requirements.)
d 3.9.6.2.3 lentation Valve Imk Tests The leak tight integrity will be verified for each valve relied upon to provide a leak tight function. These valves include:
2 (1) pressure isolation valves valves that-provide isolation of pressure differential
' from one part of a system from another or i between systems; j
4 (2) temperature isolation valves - valves whose j leakage may cause unacceptable thermal i loading en supports or stratification in the
- piping and thermalloading on supports or whose leakage may cause steam binding of
- pumps; and 1
- (3) containment isolation valves . valves that
, perform a containment isolation function in accordance with the Evaluation Against Criterion 54, Subsection 3.1.2.5.5.2, including valves that may be exempted from i Appendix J, Type C testing but whose leakage
- may cause loss of suppression pool water
- inventory.
Leakage rate testing of valves will be in N' ' S # ' '
accordt.nce witQbsection ISTC, Paragraply5 hrI' /$ 83TY (ISTC 4.3.2 anu 4.3y An crampicis the fusible
< plug valves that provide a lower drywell flood for severe accidents described in Subsection
- 9.5.12. The valves are sefety.related due to the i function of retaining suppression sool water as
- shcwn in Figure 9.5 3. These special valves are noted here and not in Table 3.9 8. The fusible plug valve is a nonreclosing pressure relief device and the Code requires replacement of each at a maximum of 5 year intervals.
1 l
4 I
3.944.2 Amendment e
J All,. 5 93 ll:23Al1 GE ilVCLEAF' AEIF' -!i2788 f,5 8 ABWR twimn un Standard Plant Table 3,9-8 (Continued)
IN. SERVICE TESTING SAFETY.RELATED PUMPS AND VALVES P41 Reactor Service Water System Valves (Continued)
Safety Code Valve Test Test SSAR Class Cat. Func. Para Frog. Fig.
No. Qty Description (h)(l) (a) (c) - (d) (e) - (f) (g) .
3 C P R 5 yrs 9.27(1,2,3)
L F010 9 RCW HX tube side (service water side) j relief valve 3 C P E1 9.27(1,2,3) i F011 9 Bypass line around RCW HX outlet line
) outlet valve MOV P41-F0uS B P E1 9.27(1,2,3)
Sernce water sampling valve 3 h F012 9 3 B A P 2 yrs 9.27(1,2,3)
F013 6 Service water drainer outlet valve
[, S M L 3 B P P. 2 yrs 9.27(1,2,3)
F014 3 Common service water strainer outlet valw 9.2-7(1,2,3)
Discharge line to discharge canal MOV 3 B P E1
/ FD15 3 3 B P E1 9.27(1,2,3) k F501 9 RCW HX she!! side drain valve to SWSD RCW HX shell side wat valve to SWSD 3 B P El 9.27(1,2,3)
[ F502 9 RCW HX shell side deala valw to SWSD 3 B P El 9.27(1,2,3)
) F503 9 3 B P E1 9.2 7(1,2,3) ' .
L F504 9 RCW HX shell side wnt valve to SWSD B P E1 9.27(1,2,3)
' F701 6 Pump discharge pressure instr root valve 3 9.2-7(1,2,3)
Service water supply pressure lastr rot valve 3 B P E1
, F702 3 3 B -P E1 9.2,7(1,2,3) i FX)3 6 Diff P across service water strainer upstream instrument root volw I F704 6 Diff P across service water stralner 3 B P El 9.2-7(1,2,3) downstream instrument root valve
[' 3 B P El 9.27(1,2,3)
F705 9 Service water diff P across RCW HX upstream instr root valve
/; F706 9 SerMee water diff P across RCW HX 3 B P El 9.27(1,2,3)
I downstream instr root valve L'
P51 Service Air System Valves I
f F131 'l Outboardisolation manualvalvt 2 A i I,P _ L RO. 9.3-7
' T132 1 laboard isolation manualvalve -2 A I,P_ L ~RO 9.3-7 PS2 Instrument Air System Valves 3
D - F276 1- OutboardIsolation valw 2 A . 1,A LP R 9.36 F277 1 ' Inboardisolation check valve 2 _
A,C 1,A LPj 9.36 i
R0 3.9.)s.2$
Aniendewa .
, J A!!. ' M l i d.! AM M ELEA.F ADF bn oc o - .,-y p;a ABM 234ucosz
%s Standard Plant Table 3.9 5 (Continued)
IN.SERVICETESTING SAFETY.RELATED PUMPS AND VALVES 1 T49 Flammability Control System Valves Safety Code Valve Test Test SSAR Class Cat. Func. Pers Freq. Fig.
No. Qty Demiption(h)(1) (a) (c) (d) (e) (f) (s)
Flow control valve for ihe FCS inlet line 3 B A P_ 2 yrs 6.2 40 FD03 2 S 3 mo fron drywell Blower bypass line flow control valve 3 B A P 2 yrs 6.2 40 FD04 2 I S 3 mo
, F005 2 Blowey discharge line to wetwell check 3 C A S @@p6.2-40 i valw(ll '/) 2 A I,A 1,P 2 yrs 6.24 l F006 2 Discharge line to wtwell outboard i isolation valve S 3mo Discharge line to wetwcllinboard 2 A I,A 1,P 2 yrs 6.2 40 j F007 2 isolation nive S 3mo Cooling water supply line from the RilR 3 B A P 2 yrs 6.2-40 FDOS 2 System MOV S 3 mo i
Coohng water supply line maintenance valve 3 B P El 6.2 40
)' FD09 2 2 yrs 6.2 40 A
Cooling water supply line admissbn MOV 3 B P l F010 2 S 3 mo i
) Inlet line from drywell drain line valve 3 B P El 6.2-40 FD13 2
( F014 2 Blower drain line valve 3 B P El 6.2-40 Blower discharge line to wetwcu pressure 2 A,C 1,A R 5 yrs 6.2 40 F015 2 relief valve L RO Blower discharge line to wtwell pressure 2 A.C_ 1,A 1,S RO 6.2 40 fFD16 2
- reliefline check valve (h3)
' Inlet line from drywell test line valve 2 B P El 6.2 40 F501 2 F502 2 Ducharge line to wetwell test line valve 2 B P El 6.2 40
/ El 6.2 40 3 B P I 1 F504 2 Blower suction line test line vabt F505 2 Blower discharge line test line valve 3 B P El 6.2 40 F506 2 Drain line to 1m Conductivity Waste 3 B P El 6.2 40 (LCW) vahe Cooling water supply line test line valve 3 B P El 6.2 40
( F507 2 3 B P_ El 6.2 40
) F701 2 FE T49 FE002 upstream instrument line j root valve 3 B P El 6.2-40
\ F702 2 FE T49-FE002 downstream instrument (inc root valve Blower suction line pressure 'mstrument line 3 B P El 6.2 40 F703 2 f root valve l F704 2 FE T49 FE004 upstream instrument line 3 B P El 6.2 40 '
) root valve 3 B P El 6.2 40 F705 2 FE T49 FE004 downstream instrument line
( root valve
/
1 S.58 30 Amendan
! A!l. E ? II:2 DAM GE.!PSLEAR AMlE- (2783 F,7 3 ABWR n oioo4 m.. a Standard Plant -
Table 3.9-8 (Continued) ,
INSERVICE TESTING SAFE'IY RELA'!TD PUMPS AND VALVES NOIT.Si (a) 1,2. or 3. Safety N***6 SSAR Sh6 3.23,
/ ANst ems -l91i Addee/o to jSmf/4y$f pg-l983 I (d) romp test parametets per ASMEh gg 4 N- Speed ra- oischer , Pro ore Pt. talet Pressere 0- Plow Rate v4 ruk-t p.4 va, a +r --
vv. P d version velocky
/us2 oma-Itte Orda ?)MlMM M-1988
( (c) A, B. C or D Vah cNegory per ASMEUM r* mv.& mc.r % / /0 (d) Vah f=reW-1- Primary ==8ai===' h $$AR Sih i 614 A or r . Active or peash per ASME Code in (c) above 13).
l (e) Velve test p r . per ASME Cods is (c) above:
. .% 4 L. Laskaps rete aragraph $$AR Table 6.2 7 for valves with fA I ls (d) abon)) r f' l#e
- r. Imalposidos veriscados Twigraph .1) _ _ .
/jo,,
R- Relief valve i a.m._ visau - est and tightaess testlag v 4.1.) ( Port I, PH ** I !. M p,r f j>o 1 41 , V 4 /.1/'f. 2. /. 2 s- Strois esercies Casebry A or B enensreshs CeegwyC M w e1a 1 m -- /% f f o, X- Esplante charge tes N,3.1, /, g ,y , g , ej, y, s , y (f) Pump of valve teet esclosions, ahernadves and tregasocy por ASME Code la (b) or (c) above or Appendet 1:
C5 Cold shadows RO. Redentog outage and/or ao cras yester them two years.
E1 Used ter operadas convenisses, l.s, pesehe net, drain, L c r camace l
=hes, or a eraen or.xrot vnho. Tem en act mquir.d 7 J ). p rtio E2 In regeler uns. Test frequency in mot required provided the test pennetdrs vt analymd ,
and meanted a an operados haarvel aos someegg three months.
h,yf /4 _ Catemorf A or 5, StroksMyr A m. 4. 24 1. f cuegwy c, streks W f --- A m. y.), 2.3 E3- Operability teet every sie months. set negenere and leak test every mfmeling outast.
(MME oes Loeo wsu. AppeedMI 11'm Farf bretrafh /. J.tV.3 f;dM the E10 In Regular use. Test frequency is not regelred p. arameters are recorded at least ones every thres enoeths of operados _
1 --PerTLj E11- L.acklag regelred fleid beventory. Tom abaR be a least ones every two years with required thdd lavestory provided { .
Port 6 msx e-)Y
J A!!, 5 '3 Il: 28M 6EllELEAf' arf k2788 f,8 R ABM tw u Standard Plant m, Table 3.9 8 (Continued)
INSERVICE TESTING SAFETY.RELATED Pl%1PS AND VALVES NOTES (Contloued): ,
(g) Piping and instrument symbols and abbresiations are defined in Figure 1.71, Figwe page numbers are shown in parenthesis (). -
prt /0; ,AI.').l. b sr d 4 3. 3 '-
o (b) Reasons for code defined testing exceptioca (ParagraphDsC 412. 4D).
(hl) launuihle inerted contalament and/or steam tunnel radation during power operations.
(h2) Avoids vahe damage and impacts on power operations.
(h3) Avoids impact: on power operadoes.
(b4) AWetemNary cronatic la neccuary to Lbe c l violett et,wsoona Srpr$' x,oollagloads. AyM7n(#[ CCIJ!'u (h5) Avoids cold / bot water injection to RFV during power operations.
(b6) Maintain pressure isolation during normal operation.
(h7) Inventory evabble onh during refuellag outage.
D (h8}4MR_ M, tkFPC is searcued at i.f.Dina outamTa 7eyh4 .a / // O Ag ,,,w repose vo'Irt osv.rsk f.s ardd sw/e snub wfaLM - -
fgbyn,Yg, (i) Su() is r--- .sa ma 3.2, "'l
- for e amenapk- rupeest g l'RQ forJ9fe rfh m L2, y?)5 fd/C Air 1yv9918 2 (ii) M f '-
- -, . PI no ' '*"
) The peping in =hW full by a traction of the A d.
s Sow capacity, fler/rsar/f' >wv3y Y 4 C*H d'Wt2PVd'c4* ' fets/ f*:re.
s- wor pung'k a coolid; b] fess bcf, g Acceutie with tha two 3.IF socar replacemeenti overY RED permol oferufnu rill be we wikiseas,1 the sifjefht of ca<sfouf ,eyan of fA.e y>w.eee //'Iew ywSemo a enrw' .
fA '
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.e /7sa mus-md aw N ut ie m R. Me 7"Y a,yJ onalyyed & 41/}shrk! low flow aperaNen wdhe 11111 derro da h'en.
0 4h kl conm4n sine is tirre((ictant A,. f;) g gj g.
Ofobo" NH Ave,- m F forf s take af,,,;, y .y j,,, p.
eterr/foa an*' A// shese g,,,,ay ,ep,ahy o,rfop, A R*t
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wo e Jd prnorije fje sewbry whismf- Jryd sfecihd luniEs, dv3 efkdin7 fewer erfera hrn.
(hC) Tes/sy g+ p w r u;/) ibpoc/ ofwrsfjur; L,coyu th yolees &
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- 1iino/,
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< TRANSACTION REPORT > ,1_o3_io,3<1m , 13,2.
A C RECEIUE 3 tao. DATE TIME DEST itMT ION STAT ION PO. M ATlW M kESR T 7073 1-05 13:21 4009251193 8 0'04'10' NORM.E OK 0 0'04'16" I .
..._-_____2_. .. _ _ _ _ _ _ _ _ _ _ ___-__________m-.2.m_2m..______ ___mm_-,____u_a ___2_
tu a w m : . , o e a u t , , t u .> .,
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GENudewEnergy ABWR N Date .a u 's i /s 2-To CVeV Pos\vsnm } Fax No.
iGlenn hlly a This page plus _A L page(s)
From Jaek Fox Mali code 18 7-175 Curtner Avenue San Jose, CA 95125 FAX (408)925-1193 Phone (408)025 4 8'4 4 or (408) 925-1687 Subject _ Asw R. %s s-se. % n s ; Awodm a su a
Message .naven Nu 'tra<
rs)
KC 31 '92 lit M41 G C to:LE@ it.!G J
~
P.2 .32 CE PTUCLEAR ENERGY San Jose. California cc: J. D. Luncan December 30, 1992 1.. C. Frederick O. Cokcek R. P Raftery To: J. N. f'ox Trom: S. Visvesvaran
Subject:
Appendix 191 ABVR Seismic Hargins Analysis Attached for transmittal to the tiRC (Clenn Kelly) and to DOE (Norman Fletcher) is the ABVR Seismic Hargins Analysin. Advanced copies have been faxed to both parties.
9 S. Visveswaran M/C 469, Ext. $6609 ii
LE 31 'N 11: 3x41 G C f fXLCAP fus; J p Anpgndix 19I ADWR Seinmic McLq.inE_AtlalYnis 19I.1 INTRODUCTION A noismic marginn analysin han bonn conducted for the ADWR using a modification of the Fragility Analysin method of Roference 1 to calculate high confidence low probability of failuro (!!CLPF) accolerations for important accident sequences and accident clausos.
HCLPF values were calculated for components and structures using the relationship HCLPF = A,* cxp (-2. 3 2 6
- Be )
where:
is the median peak ground acceleration corresponding A, to 50% failure probability B is the logarithmic standard deviation of the component C or structura fragility.
The resulting HCLPF acceleration corresponds essentially to the 95th percent confidence level that at that acceloration the failure probability of a particular ntructure or component la less than 0.05 (5%).
HCLPFs for accident sequences were evaluated through une of event trees, and neismic nystem analysin was performed with fault trees to determine HCLPFs of systems.
The seismic marginn analysin evaluates the capability of the plant and In thin analysis, equipment to withstand a largo earthquake (2*SSE).
two alternative methods were used to evaluate the neismic accident sequencen - a " convolution" method and a " min / max" method.
In the convolution method, accident nequences are evaluated by combining input fragility curves according to the Boolean exprension for each sequence. Seismic and random / human failure probabilitics are calculated and combined (convolved) for discrete intervals of ground acceleration, and then integrated over the rango of intorest.
In the min / max method, input fragilities are combined by using the lowest (minimum) llCLPF value of a group inputs operating in an OR logic, and by using the highest (maximum) HCLPF value of a group inputs operating in an AND logic.
Analysis of the effects beyond core damage (Level 2 PRA However, analysis) event was trees were not a part of this poismic margins analysis.
conntructed to examine the possibility of lons of containment isolation resulting in a large release given the earthquake and a resulting core damaging accident.
Because of the inclusion of a rupturu dink in the ABWR design as an ultimate means of containment heat removal, and because an earthquake would not prevent rupture of the disk, failure of containment heat removal is not modeled in the seismic margins analysis. (There are no class II sequences in the analysic.).
. m
I0. S1_ '92 11 h41 G E f 0: lcm DLt ; J F.4 42 19I.2 COMPONENT AND STRUCTURE TRAGILITY - A,,D, for Component and structure fragility values have have beenidentified been established au e selected structurca and components that potentially important to the neinmic margins analysis. The fragility aE[
$}
values uued in the analynis are shown in Table 191.2-1,The together with component the calculated component / structure and nystem HCLPro.
fragility values are based on generic components used in operating plants having SSEs of 0.15-0.2 g. Thene component fragilition areFor p:t conse rva tive for a plant designed and built to an SSE of 0.3 g. a more inf ormation regarding the development of these f ragilitios and capacities, refer to Appendix 19H.
191.3 EVENT TREE ANALYSIB The event trees used jn the ABWR Level 1 neinmic margins analynis are shown on Figures 191.3-1 through 19I.3-3. The individual paths through the event treen represent tho accident nequences which are input to but the HCLPF analysis. There ic essentially only one neismic event tree, it is pronented on three figures representing transfers from Figure 191.3-1 to Figuros 191.3-2 and 191.3-3.
191.3.1 Dupport Stato Event Tree The seismic event tree of Figure 191.3-1 starts with the spectrum of seinmic Ovents, Considers WhGther or not there is a Structural failure (node SI), whether or not offsite power is lost (node IOP) and continues from there. Because of the ground rulen of the analysis and the relative values of seinmic fragilities, loss of structural integrity renults in core damage, and nurvival of of fsite power resultn in sucenssful event termination. Thus, all remaining accident sequences on Figure 191.3-1 are for casen of no structural failure, but always with lonn of offsite power.
The success or failure of enorgency AC power and/or service water (node APW), and the emergency DC power (station batterien) (nodo DP) are taken into consideration in Figure 191.3-1 to eliminate dependencies among safety system fault trcos. Failure of all DC power results in a high-presnure core melt since all control is lont, the high-pressure systems fail, and the reactor cannot be depressurized. The condition of successful emergency AC and DC power and succosuful scram is indicated by the ET transfer and in described in detail in Figure 191.3-2. The condition of succcasful emergency AC and DC power, but with failure to scram is indicated by the A1HS trannfer, and is described in Figure 191.3-3.
The condition of failure of emergency Ac continues on Figure 19I.3-1.
The next questions are whether or not there is a loss Failure of DC power to scram is (station batteries) and failure to nctam With(nodo C). DC power and scram, successful considered an a Class IV core melt.
RCIC (node UR) and firewater (node FA) are the only available means of
' water injection into the RPV sinco all AC power is lost. Since station batteries will eventually discharge resulting in loss of RCIC, to or if allow RCIC falln, the reactor must then be depressurized (node X) firewater injection.
.-. - - - - . - - - _ - - - - - . . ---- - .- - ~.---
T E 31 ' 92' 11 wig r texttm gtr4 y 1
4 The ' rewater system han diesel drivun pumps and all nooded valves can i~~ ed and operated manually. No support systems are required for 1
The firewater pump is housed in an external 23: 0.:;er culluing (shod), opuration.whono collapse would not prevent the pump from starting end running. The failure probability of firewater is dominated by For the upper branch, whero j
l '
operator failure to initiato the system.the operator han 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> before the station RCIC in successful, For i
batterico expire and RcIC trips. The HEP for this case is 1E-3.
j the lower branch, whero RCIC fails, the operator has only 30 minutes For in which to depressurize thu reactor and initiate firewater injection.In the event t this case, the HEP is 0.1. ,
to ctart, the operator could mako uso of a fire truck, but this was not i '
j 4 modeled.
i If the RHR heat exchanger fails-(node HX) due to tho earthquake, it is 1 presumed that the failure could include a pipe break that couldThose saquencco partially drain the suppression pool.
j j with a "P" (e .g. , IB2-P) .
i
- 19I.3.2 LOSP with Emergency Power and Scram Event Tree In the ovent treo of Figure 191.3-2 (ET transfer), there are two i
2 similar divisions depending on whether If there is a atuck-open or not thero is a stuck-open valve, the reactor j relief valvo (node PC).
will eventually depressurize causing losa of RcIC steam supply. The
' probability of having a stuck-open valve is 2E-3, based on operating i experience. If both high-pressure injection systems fail, (LPFL the reactor
-V1, or j must condensatebe deprossurized rapidly for low-pressure system useIn ABWR, condensate p injection -V2) to tho enorgency bus by the operator.
1 19I.3.3 ATW8 Event Tree f
Figure 19I.3-3 ( ATWS transfer) represents failure to scram, and l
4 requires standby liquid control (automatic) and operator _that action areto control reactor water level with the injection system (s) available. In this ATWS analysis, if high-pressure systems rail, core i
j 4
No credit is given to low-pressure injection. For an
- to 0.1, on the basin of increased SRV activity.
!, 19I.4 SYSTEM ANALYSIS -
I The fault trees used in the scismic nystem analysis.ar' shown on-Figuren 191.4-4 through 19I.4-15. The seismic system analysis j _
a j_
calculates the probability of seismic-failure of each of the .important The system systems throughout the soismic ground acceleration spectrum.naism One
- combined with random system failuro probabilities and human errors.
of the important ground rules of the seismic margins analysis is that-f all like components always fail together.
+
e gy-- -
--FT-p'1*-'s*tr w'-W'*ew-- - =
- _ _ . . - - - -- - , -~_ -_ _...-.-.- - -- ,
~
W 31 '?L 81t W41 G c tyLcw tttg y P6W 2
The reactor protection syntem, control rod drivu system, and alternate 1
! rods rod insortion system were not modeled ninco the failure of control to insert is dominated by the relatively low soismic fragility of the e
ll -
fuoi annomblies, control rod guide tubos, and housings. A soismic fault l
s tree for reactivity control is shown on Figure 191.4-13.
I A seismic fault tree for the standby liquid control system is shown on I
f Figure 191.4-14. Failure of the standby liquid control system is 1
dominated by failuro of two components - the pump and boron supply tank.
Since the most fragile component is ceramic insulator in the switchyard, the locs of offsito power dominutos the analysis and the 4
availability of emergency power becomes very important. The loss-of-power fault treo (Figuro 19I.4-10) is for emergency AC power.
j i
j In the loss of emergency AC power fault true, the more fragile 4 components are the diesel generator ,.The transformers, motortree DC power fault control (Figuro l centers, inverter and relay switch.
l j 191.4-11) has two branches - with and without availability of AC power.
i
- Systemn and equipment which requiro of f site power, such as theare not m
- feodwater system, The condensato injection
' not available for the-core damage sequences.
j -
system is modeled on Figura 19I.4-15 Dinco credit is given to the(See Figure operator for transferring condensato to an emergency bus.
19I.3-2.) The human error probability is much groator than the l
i failure probability, therefor, this fault
! scismicly j tree has induced negligible equipmentimpact on the HCLPF value of the corresponding i accident sequences.
1 Essential service water is as important as emergency power, and its loss would have much the same effect as the loss of emergoney power.The l The loss-of-service-water fault trae is shown on Figure 19I.4-12.
]
more fragilo components in this system are the service water pump, The i
' transformer, motor control center and room air conditioning unit.-
service water pump houno, with a HCLPF of 0.96,_ is also included in this ,
, fault tree.
i Structure failures-that-could contribute to seismic coro damago are-In this analysis, any one or more of these shown on Figure 19I.4-9.
structural f ailures are conservatively. presumed to result- in core damage. The structures having the lowest seismic capacity are the
{
' reactor building and control building.
L The remainder of the fau3tLtreen are for coro Thecooling and containment more fragile components l -coolingc(Figuros 19I.4-4 through 19I.4-8). ,
!~ in those systems are the pumps, heat exchangers, and the firewater supply tank. ,
I 19I.5 ACCIDENTLSEQUENCE HCLPF ANALYSIS i
Seismic fragility of a structure or component is defined as the 4
conditional probability of its failure as a function of peak ground
- accoleration. The probability model adopted-for Theeach component l
density function for the l
i fragility _is the log-normal distribution.
component' fragility, f(g) , can be_ written:
4 1
- - - - . - - - . = ~ = . - - . - .. . .- .
!EC 31 '96 11: :41Gcnntretog y i
! l i
i exp(-1/2*(in(g/A ,)/Bc ) ) fr g>0 f(g) " AF *D c*g
- f. ,
l Wheres J
l A, a Median capacity of the component i
l Dg i Logarithmic standard deviation of the fragility function
~
The cumulative distribution of the component fragility, F(g), will then J, bot i
l 9 F(9)
- j gy exp(-1/2*(in(gy /A,)/Be ) ) dg g
!' O 3c.g1 -
l l 19I.5.1 Convolution Analysis j If a system, S, (or sequence) contains two components (A,B) operating in OR logic (the failure of any component will fail the system, S = A +
i D) then the cumulative fragility distribution of the system is one minus 1
4 the product of their complementary cumulative fragility distributions :
j Fg(g) = 1-(1-F3(g) ) * (1-FB I9II i
On the other hand, if two olements operate in AND logic (only.the l
i failuro of both componentn will fail the system, S = . A
- D) than the cumulative fragility distribution of the system is the product of their j
cumulativo fragility distributions:
a.
l Fg(g) = F3(g)*F3(g)
Using the two principios above, the distribution function of each i
system fragility is obtained by combining its component fragility-l t
functions based on its Boolean expression derived from the system fault l' tree.
! similarly, the distribution for eacB accident sequence is derived from i
system. fragility functions by using the Boolean expression obtained from the seismic accident sequence event trees. The fifth and fiftieth percentiles of the combined cumulative. distribution of_each accident sequence are-used to'obtain the A and B .for the corresponding
~
}
sequence.. Then, the HCLPF of eac8 accidO'1t sequenco .is;obtained;by j
j using the formula presented in- the Introdu: tion'soction: as follow:
' llCLPF = A,* exp (-2. 3 2 6
- Bg )
where the parameters A and B are the median'capecity and logarithmic standard deviation of Ehe logRormal distribution of tne accident sequence.
IE 651 lit red .; t u n t m y ,; y P. 6 ar 19I.5.2 Min \ Max Analysis If a system, S, (or sequence) containa two components (A,B) operating fail the system, S=A+
in OR logic (the failure of any component willtragility distribution of the system is govl:
a) then the cumulative the weakest component. This principle I
by the fragility distribution ofis applied to the cystem fault troos, which generally ar gaten.
If two elements oporato in AND logic (only the failure of both components 'ill fail the system, S=A* B) than the cumulative fragility d.stribution of the system is governed by the isfragility This principio applied to distribution of the strongest component.
which are composed of ANDed elemontu.
accident sequences, 191.6 RESULT 8 OF THE ANALYSED The results of the convolution analysis are shown on the event treen and in Table 191.6-1 in terms of HCLPF valuen for the accident As seensequences, in the event with and without the the inclusion HCLPF ofvalues random forfailures.
all accident sequences are trees and the table, which is twice the sufo shutdown carthquako (SSE =
greater 0.30g). than 0.60g,The redultu of the convolution analysis in terms of accident classes are shown in Tablo 19I.6-2.
The HCLPF value of accident sequences obtained from the min \ max analysis are printed on the event trees next to tne column of accident classes.
The combination of HCLPF and random failure probabilitics As can of accident be seen, the HCLPF sequences arc described in Table 191.6-3.
values for all accident sequences are greator than 0.60g.
19I.7 CONTAINMENT ISOLATION AND BYPASS ANALYSIS In the scismic margins analysis there were no cutsets leading A supplemental analysisto was core
- damage with HCLPF values lower than 0.69 conducted to evaluate the HCLPF values for containment result ofisolation for an carthquake, events that could cause containment bypass as a with potential for large releases to the environment.
Based on the results of the bypass analysis discussed in Subsection 19E.2.3.3 and summarized in Table 19E.2-22, the ovents selected for evaluation in this analysis are:
- Tecdwater or SLC injection lines
- Reactor instrument, RWCU instrument, LDS instrument /nample or containment atmosphere monitoring lines
- RCIC steam supply or RWCU auction lines
- Post accident sampling lines
- Drywell sump drain lino
- SRv discharge lines
- ECCS lines
- Drywell inorting/ purge linos
- Wetwell/drywell vacuum breaker lines
__m_____._.--
i IE al 'K 118 ht G C f u:Ltfp Rtc J 4
1 1
i l These bypans pathways are depicted on Figure 19E.2-19A through 19E.2-19K. The bypass paths for drywell vents or atmosphuric control
! system cronstio linen require Sinceinadvertent the seismicopening analysis of considerstwo normally closed a fail to i motor operated valven.
! open mode for the normally closed valvos, these bypass paths are not 4 included in the analysis.
Those An event tree was constructed for onch of the above events.
event trees are shown on Figures 19I.1-1 through 19I.7-10. All event
- trees start with the earthquake as the initiating event followed by a ,
core-damaging accident. If thero is no core damage thorn is no large 1
- release. The HCLPF and random failuro probability are shown for each branch point, and the sequence HCLPrs using convolution and min-max i methods are also shown on the figuros, 1
l Figure 191.7-1 is for suppression pool-bypass-via main steam linen, j
Following the earthquake and accident,.the question is asked whether or If there j not thero is a break in a main steam line outside containment.
in a break, the question is asked whether or not at leant one MSIV in l
i each steam line closos to isolate the-break. For the case where there j is no break, thero could still be a bypass release to the main condenser j
if a turbine bypans valve in open - unicss the MSIVs are closed to
- isolato the break. The two bypans sequences for this ovent both have-a llCLPF capacition of 0.74g.
Figure 191.7-2 is an= event troe for bypass via feedwater or standby 11guld control lines. These lines inject into the RPV-and are protected i
from reverse flow by redundant chock valves. These chock valves provide i
isolation of upstream breaks provided that one of the_valvos closen in l
l the line with the break. The two bypasu sequences for this event also
' have HCLPF capacitios of 0.74g.
l j', Figure 19I.7-3 is for bypass via reactor - instrument, RWCU instrument, LDS instrument, LDS sample or containment atmosphere monitoring lines.
i Those lines are also protected by check valves, a single valvo in each
- line. The-bypass sequence for this caso also has a HCLPF of-0.749 f
I Figure 191.7-4 is for bypass via either the RCIC steam supply line or the RWCU suction;11ne. Both of these lines are protected by motor i
l- operated isolation valvos which require power. Sinco offsite power is The two bypass
)
lost due to-the earthquake, omergency power is required.
sequences for this event both have HCLPFs of 0.74g.
J Figure 191.7-5 inLfor bypass via the pont accident sampling-lines.
i I
These linos are-alco isolated by-motor oporated' valves. The bypass i sequences _for_this event also havo HCLPra of 0.74g.
4 . Figure 191.7-6 is for' bypass via the drywell sump drain line. This l
line is protected by a motor operated isolation valve and a check valvo, i Both components have HCLPF capacities of 0.74g.
_7 J
N.,-...-.;...--,,_-i.... . ._.-w.. . . . , . - , , . ~ . . - - . . ~ . . - - _ . - - - , _ _ . . . . . . . -
IM 31 '92 1 r ige 4 c ro:tt,p gg,., y P. 20 12 1
la for bypass via the SRV discharge lines. If thern is and Figure 19I 7-7in an SRV discharge line during a core-damaging a break accident, it is In this analysis, that SRV is open, a bypass pathway will exist. The resulting unsumed that the SHV will be open during the accident.
HCLPF capacity is 0.74g.
The lines of Figure 19I.7-8 in for bypasn via any of the ECCS lines.
concern are the HPCF and LPFL warm-up and discharge lines. These linos The are protected by motor operated isolation valvon and check valves.
resulting HCLPF capacity is also 0.749 These Figure 19I.7-9 is for bypass via drywell inerting/ purge The bypass linen. for sequence lines are protected by air operated valves.
this case has a HCLPF value of 0.74g.
Figure 19I.7-10 is for bypass via watwoll/drywell vacuum bakertolines.
It require an inadvertent opening of vacuum bakor (check valve)The bypass sequenc initiate a bypass during a severe accident.
thin case also has a HCLPF of 0.74g.
All sequences for all events in the bypass analysis have HCLPF capacitico of 0.749 which is significantly largor than 0.60g (twc timos l -
SSE) and therefore, no further analysis is needed.
19I.8 REFERENCEB
" Assessment of Seismic Margin Calculation Methoda", RUREG/CR-5270, 1.
R.P. Kennedy, et al, Lawrence Livermore National Laboratory, March, 1989.
9
- - - - - . . . - . . - - . . - . _ .- - .- - - . -. - - -. - .~. - . . . . - . .- .
ICC 31 '92" l1 EdI 4 C textctp gg y P. l l M2 '
l j
1 TADLE 91.2=1 ;
ABWR SYSTEMS AND COMPONENTS / STRUCTURES PRAGILITIES LOO,8TD HCLPF FAIL. PROD.
1 SYSTEM / COMPONENT MED_cP (in g) (rail /Dem)
(A,) (D,)
e 2.8 .45 .98 0.0
- 1. Plant Ess. Structures (SI) .45 .98 l -Reactor Building 2.8 4.3 .44 1.56
-Containment 7.9 .44 2.84
- -HPV Fedental 2.8 .45 .90 l
-Control Duilding .33 2.46 5.3 4
-Reactor Pressure Vossel I 2. Support systems _(PW) 1 1.8 46 .62 1.6E-3 l .a. AC Powgr_1&g21 1.8 .46 .62 ,
]
-Diesel Generator 1.8 .46 .62 j -Transformer (400 V AC) 1.8 .46 .62
-Motor Control Center 3.0 .60 .74
-Cable Tray .50 63
-Relay Switch 2.0 1
J 1.8 .46 .62 9.72-5 i hz_ service water (SW1 1.8 .46 .62
! -Transformer 1.8 .46 .62 .
-Motor Control Conter 1.8 .46 .G2 j
-Pump (Motor Drivon) .45 .70
-Heat Exchanger 2.0
-Valve (Motor Operated) 3.0 .60 . 74
- 3.0 .60 .74 l
-Check Valvo 2.0 .50 .63 i -Room Air Cond. Unit 3.0 .60 .74
-Piping .45 .98 l
-SW Pump House 28 3.0 .60 .74
-AC Ducting l
i 3.3 .4s 1.13 7.22-6 I c. DC Power (DCE1 33 .46 1.13 i
- Batteries & 2.2 46 .75
- Inverter l 2.7E-3
- 3. High Press. Core Floder (UH) 1.8 .46 62~
1 1.8 46 .62 i -Pump (Motor Driven) 3.0 .60 .74
-Injection Valvo (Motor Op) 3.0 ' 60 .74- ;
l -HPCF Piping .
1 45 .70 '6.02-2 ;
- 4. Reactor Cors Is. Cooling (UR) 2.0
.45 .70
-Pump (Turbine Driven) 2.0 3.0 . 60 .74
-Steam Sup. Valvo - (PK)) .60 .74 j 3.0
-Discharge Valve (MO) .60 .74 3.0
'- -Min Flow Valve (MO) 3.0 .60 .74
-Check Valvo 3.0 .60 .74
-RCIC Piping-i 1
4
~ - . . . - . - , , . . , ,- -. - , . - e , . . - - - ,-,,,-.4.-,_. . . . , , , - , , , . . - -,,,,y. ,,,,,,,,-v,...,y, . . . ,.-,-..,-.-.,w,_,,
IE 31 '92 12 * ??ddl G C IUCt.E@ Itt ; J P. it/.82 i
i TABLE 19I.2-1 (CONTINUED) a' LOG _STD HCLPF FAIL. PROB l SYSTEM / COMPONENT MED_CP (A ,) (B,) (in g) (rail /Dem) l 1.8 46 .62 3,1E-4
- 5. Low Pressure Core Floder (V1) .46 .62
- -Pump (Motor Driven) 1.8
.60 .74 1 -Check Valvo 3.0
.60 .74
! -Injection Valve (MO) 3.0
.60 .74 l
-Discharge Valvo (Mo) 3.0
.60 .74 2 -LPCF Piping 3.0
.45 .70 6.0E-5
, 6. RHR Heat Exchanger (HX) 2.0
.45 ,70
-Heat Exchanger 2.0 ,
i
.53 1.0E-8 i
- 7. Reactivity Control Sys. (C) 1.2 .35
.35 .53
-Fuel Assemblien 1.2 4
1.7 .36 .74 1 -CRD Guide Tube .46 1.33
-CRD Housing 3.9 1
-Shroud Support 1.9 .36 .82 ,
.50 .63
-Hydraulic Control Unit 2.0 ,
3.0 .60 .74 2E-3,1E-1
- 8. SRys close (PC,PC1) f -Safety Relief Valvo 3.0 .60. 74
]
.60 .74 6.2E-6 l 9. Depressurization (I) 3.0
.60 .74
-Safety Relief Valve 3.0 3.0 .60 .74 1.0E-2 j 10.-Level & Press. Control (LPL) 3.0 .60 .74
- -Safety Relief Valve l
.60 .74 2.4E-3
.60 .74 l . -Safety Relief Valve 3.0 4
1.8 46 .62 1.4E-2
- 12. Standby Liq Cont. Sys. (C4) l
-SLC Tank 1.8 .46 .62
-SLC Pump 1.8 .46 .62
) -Valve (Motor operated) 3.0 .60 .74 1
3.0 .60 .74
-SLC Piping I 13. Condensate Injection (V2) 1.8 .46 .62 1.0E-1 18 .46 .62
-Pump (Motor Driven) .60 74
-Injection Valve (MO) l 3.0 3.0 .60 .74
-Piping-1.8 .46 .62 1E-3,1E-1
- 14. Fire Water System (FW) 2.1 45 .79 2- -FW Tank .46 .62 1.8
-Pump-(Diosel-Driven) .60
-Injection. Valve (Manual) 3.6 .89.
i 3.0 .60 .74-
! -FW Piping 3.6 .60 .89
-Valve (Manual)
Note: HCLPF = A,*exp(-2.326*Bc) 10 1
a
,,,_...y.-__ - . _ , , - . , , , . _ , , , , - , . . , , . . , , . , -
---,y-.i.-.,, ,,,,y--
IO: 31 '92 11: FMIG cf0:LCe# [LIG J p TABLE 191.6-1 SEIBMIC MARGIN FOR ABWR ACCIDENT SEQUEN0E8 WITH RANDON FAILURE WITHOUT RANDOM FAILURE MED CAP LOG BTD HCLPF KED CAP LOG STD HCLPF ACC. SEQUENCE #
(in g) (A;) (B;) (in g) (A;) (n;)
1.13 3.30 0.46 1 1.13 3 30 0 46 3.52 0.38 1.46 3.52 0 38 1.46 2 1.40 0.29 !
0.72 1.40 0.29 0.72 3 2.13 0.33 l 0.99 2.13 0.33 0.99 4
3.00 0.57 0.79 3.00- 0.57 ,
5 0.79 0.44 '
3.34 0.44 1.21 3.34 6 1.21 0.26 1,58 0.28 0.89 1.62 7 0.83 0.29-8 1 09 2.17 0.30- 1.12 2 18 3.01 0.49 0.98 3.01 0.48 9 0 97 0.41 1.29 3.34- 0.41 1.29 3.34 10- 0.48 1.14 0.22 11 0.6s 1.14 0.22 2.01 0.35 0.89 2.01 0.35 0.89 12 1.14 3.30 0.46 13 1.14 3.30 0.46 1.46 3.52 0.38 1.46 3 52 0.38 14 0.90 2.13 0.37 15 0.90 2.13 0.37 0.31 1.24 2.55 0.31 1.24 2.55 16 1.15 2.00 0.24 17 1.12 1.97 0.24 1.13 3.04 0.43 1.14 3.04 0.42 18 3.11 0.37 19 1.28 3.10 0.38 1.30 0.45 1,46 4.16 0.45 20 1.46 4.16 0.25 0.94 1.67 0.25 ,
21 0.92 1.66 3.00 0.54 0.s5 3.00 0.54 22 0.85 0.45 0.91 2.82 0.48 1.05 3.03 23.
24 1.25 4.05 0.50 1.38 4.16 0.47 0.82 2.98 0.55 0.85 3.00 0.54 25 1.39 0.26 26 0.75 1.38 0.27 0.76 0.25 0.93 1.67 0.25 27 0.93 1.66 "t(C si ~ ' M 11:3381 G E 18XLCIS 1t14 J P.14/42 I TABLE 192.6-2 j
SEISMIC MAROINS TOR ABWR ACCIDENT CLASSES
]
i WITHOUT RRNDOK FAILURE WITH RANDOM FAILURE j HCLPF MED CAP. LOG STD. ECLPF MED CAP. LOG STD.
i ACCIDENT CLASS (in g) (5,) (D ,) (in g) (I,) (Bg) i 1.76 0.32 0.45 1.76 0.31 IA 0.84 i 0.72 1.40 0.29 IB2 0.72 1.40 0.29 f
0.86 1.41 0.21 0.s9 1.43 0.20 IC 1
t i
1.49 0.25 0.90 1.52 0.22 i ID -0.s4
)
2.13 0.37 0.90 2.13 0.37 IE 0.90-0.66 1.06 0.21 0.67 1.06 0.20 IV 1.51 0.22 IA-P , IE I P 0.90 1.51 0.22 0.91 s
10: 31 '90 !!82W41 G E tex tcre rg,rg y P.1p.:2 TABLE 191.6-3 HCLPF DERIVATION FOR THE ADWR ACCIDENT BEQUENCED (MIN /MAI METff0D I Scquence 1 : DP*FA
- 1.139*(0.62941.0E-3)
- _J.13g_
l Sequenco 2 : DP* FA* HX - 1.13 g * ( 0. 6 2a g + 1. 0E-3 )
- 0. 79 -+
- 1.13g*(0.62g+1.0E-3)
- L 13(1 4 -
Sequence 3 : APW*FA - ( 0. 6 29 +1. 6E-3 ) * ( 0. 62g41. 0E-3 )
t 0.629 4 1.6E '
- 0. 62a -
Soquence 4 : !!X* APW* FA ~ 0. 7 0g * ( 0. 629+ 1. 6E-3 ) * ( 0. 62941. 0E-3 ) ~
- _ 0 . 7 0 g_,
Sequence S : X*APW ~ 0.74g*(0.62g+1.6E-3)
~
- 0.74a
~
Sequence 6 : ilX*X*APW ~ 0.70g*0.749*(0.62g41.6E-3)
- 0.74a
~
Sc(Nence 7 : FA*UR*APW - ( 0. 62g + 1. 0E-1) * ( 0. 7 0g+6. 0E-2 ) * ( 0. 6 2g+1. 6E-3 )
l : _0.70a . 0.62a*6.0E-2 I Sequence 8 : PX*FA*UR*APW-~
- 0.70g*(0.62941.0E-1)*(0.70946.0E-2)*(0.62g+1.6E-3) *
- 0.70a_
a ~
Sequence 9 : X*UR*APW - 0.74g*(0.74g+6.0E-2)*(0.62g+1.6E-3)
- _0.74a Sequence 10 : !!X* X* UR
- APW ~ 0. 7 0g
+ :_0.74a_
V t(E 31 'M 11:4NI G E f fXLE@ ULI6 J P.16M2 l l
~
Sequence 11 : C*APW
- 0.539*(0.02g+1.6E-3)
- A Q2n 0. 52 n
- 1. 6 E. _;L_
l
~
Sequence 12 : HX
- C* APW - 0. 7 0g* 0. 5 3g * ( 0. 6 29+ 1. 6E-3 ) j 0.70g_
~
Segunnce 13 : DP*APW - 1.139*(0 62g+1.6E-3)
- 1.13c
~
Sequence 14 : HX*DP*APW - 0.70g*1 13g*(0.62g+1.GE-3)
- 1.134_
Sequence 15 : SI -
t 0 . 9 8 n__
Sequence 16 : HX*SI - 0.70g*0.98g -
- 0.980_
Sequence 17 : V2*Vl*UH*UR - ~
- (0.62g+1.0E-1)*0.62g*(0.629+2.7E-3)*(0.70g+6.0E-2)
- 0.70c . 0.620*5 0E
- Segunnce 18 : X*UH*UR - 0.74g*(0.629+2.7E-3)*(0.70g+6.0E-2)
- 0.74g_
Snquence 19 : V2*Vl*UH*PC - ~
- (0.629+1.0E-1)*0.62g*(0.62g+2.7E-3)*(0.74g+2.0E-3)
- 0.74a , 0.62c*2.0E-3_
Sequence 20 : X*UH*PC - 0.74g*(0.629+?.7E-3)*(0.74g+2.0E-3)
- __qu?_ig_,
Sequence 21 : UR*UH*C - (0.70g+6.0E-2)*(0.62g+2.7E-3)*0.539 -
- 0.70a . 0.620*6.0E-2_
Sequencu 22 : PA*C - (0.749+2.4E-3)*0.539 -
_0.74c 0.S3a*2.4E-3
- _ - - _ _ _ - _ - _ - - - _ _ . . - -._.. - . - - __ _ _ ~ . - . - -.. _. -_ .__ ._ - ____ - _-
ICC 31 '!C 111.:Cgst G t so; tty gg,tg y P.1 <.42 l
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. 0. 6 2n
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l
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.\ TREE \ DAD 4.CAF 12-28-92 FIGURE 191.4-5 RCIC SEISMIC FAULT TREE
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.\ TREE \ DADS.CAF FIGURE 191.4-6 LPCF SEISMIC FAULT TREE i
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- I 12-28-92 Page 1 FW SEISMIC FAULT TREE .\ TREE \ DAD 7.CAF FIGURE 191.4-8
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I i i : I FIGURE 191.4-9 STRUCT. SEIS. FAULT TREE .\ TREE \ DAD 8. ACF 12-28-92 j Page 1
4 t
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> FIGURE- 191.4-10
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[ t<44EsPT I Itceoctel l tRAssv i O O O- 0 0 8
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.\ TREE \ DAD 12.CAF 12-28-92 Page 1 FIGURE 191.4-13 RC SEIS FAULT TREE
l b.
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I SEISMIC F AfL OF SLC n SYSTEu B
l 5 l 'F'C 5 w
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LOSS OF SLC PUMP LOSS & SLC VALVE 1
LOSS OF SLC TANK LTIM LkWP Q 5
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- I 3 1 2 1 1 : I 12-28-92 I Page 1
.\ TREE \ DAD 13.CAF 1 FIGURE 191.4-14 SLC SEISMIC FAULT TREE
1
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.\ TREE \ DAD 14.CAF- 28-92 Page.
FIGURE 191.4 CI- SEISMIC. FAULT TREE
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CLASS Min-Max Convolution f Seismic No Severe Vacuum Breaker Closes in f.
Event Accident j All Lines P
3
' SE- SVAC CHVLV OK SE OK SVAC-15 BP- 0.74g 1.12g 12-29-92 Figure -.191.7-10 Suppression Pool Bypass Via Wetwell/Drywell Vacuum Breaker Lines f
N
< TRANSACTION REPORT > 12_31-18sanan 13 46 C RECEIVE 3 FC. DATE Tite DESTINATION STATION PO. DURATICN N00E RESULT 6961 12-31 13:32 408 92S1687 42 0'13'49' NORM.E OK 42 O*13'49" f
4 4
I i
1
i ABWR PROJECT FAX TRANSMITTAL COVER SilEET DATE: 12-29-92 TO: C1.ENN KELLY, NRC '
FROM: J. N. FOX, CE NUCLEAR ENERGY, San Jose, California TELEPil0NE: (408) 925-4824 NUMBER OF PAGES F01MNING Tl!1S COVER SHEET: FIVE (5)
MESSAGE: Attached are our responsen to NRC questions raised under item (2j of NRC letter from Clenn Kelly to Jack Duncan. " Additional Questions Regarding GE ABVR PRA Submittals", dated August 10,1992. They relate to the draft ,
ABVR PRA data uncertainty analysis previously submitted to the NRC for re'tiew on June 18, 1992.
k ICC 29 '92 02: 00R1 P.2 I
RESPONSE TO NRC QUESTIONS ABOUT ABVR DRAFT UNCERTAINTY ANALYSIS REPORT 1.0 Introduction This analysis is in response to questions by NRC regarding the ABVR Uncertainty Analysis. Reference question 2 of URC letter to Jack Duncan, from Glenn Kelly, dated August 10, 1992. References to page numbers refer to the draf t uncertainty analysia report.
2.0 Setting All EFs To 15.
Question: On page 1 of the draft uncertainty analysis report, lGE claims that if all error factore are increased to 15, the core damage frequency results only increase 14% for the 95th percentile. This seems unusually low.
Reopense: GE maintains that the low increase in the ninety fifth percentile of the CDF is not unusual. The EFs were set equal to 15 in order to determine how sensitive the ABWR uncertainty analysis results were to the ETs used in the ABVR fault trees. The results showed that when all EPs were set to 15, the 95th percentile of the CDF increased by only 14%. This result is not surprising when considered in terms of the information presented in Table 1 and Figure 1, given below. Table 1 (Table 5 in the uncertainty analysis draf t' report) presents the top ten contributing basic events (BEs) to the CDF uncertainty. Figure 1 (Figure 2 in the draft report) is a sensitivity curve for x /mean ( where x is the 95th porcentile of the BE probability (BEP)0 95an a function of 0the*
95 uncertainty (EF) of the estimate of that BEP, since the mean is a constant, figure 1 is also a sensitivity curve for the 95th percentile. Table 1 and Figure 1 provide the following pertinant information:
a) Table 1 shows that four of the top ten contributors to uncertainty already have EF - 15 in the base case, and the change will not affect the BEP distributions in these cases. Two were raised from EP - 10 to EF - 15, and only four were raised from EF
- 5 to EF- 15 in the EF sensitivity study.
b) Figure 1 shows that the difference in the values of the 95th.
percentile is less than 3% when the base case EF-10 is raised to EF - 15. (I.e., x 5
/mean changes from about 3.7 to about 3,8).
Similarly, whenth2'basecaseEF-5israisedtoEF=15, the difference is about 27%. (I.e., x /mean hanges from about 0*95 3.0 to about 3.8).
ICC 29 '92 OI: 01PI1 P. 3 I
a Combining this information from Table 1 and Figure 1, we see that the 95th percentile of the top ten contributors to CDF uncertainty changed a small i amount, on the average, when the Ers of the top ten BEs are raised to an EP
- 15.
3.0 Sampling Of The Tails 4
Question: Please provide additional information on the sampling of the tails of distributions used in your Monte Carlo analysis.
Response: UNCERT is a Monte Carlo simulation program (developed by SAIC) which was used-in the ABWR uncertainty analysis. S:.apling is performed using the method for generating random numbers which is described in section 26.8 (pages 949 and 950) of Handbook of Mathematical Functions With Formulas, Craphs, and Mathematical Tables, Edited by M. Abramowitz and I. A Stegun, NBS Applied Mathematical Series 55, December 1972 printing. SAIC has checked the accuracy of the sampling for the 95th percentile of two lognormal distributions each with maan E 04, one with EF-3 and the other with EF - 15.
The results are within the 95th percentile confidence limits for both these Cases.
4.0 Coupling Of Human Errors Question: On page 8 GE state that the human error events were not coupled when analyzing uncertainties ecause GE believes that different operators and different crews would provide a tendency toward uncoupling. This is not necessarily true for a maintenance crew or operations crew that performs calibrations, tests, or maintenance. The staff takes this position based on current operating experience.
Response: GE believes that in the case of the ABWR PRA, in general the coupling of human error probabilities (HEPs) does not contribute significantly to the mean value of the CDF. In order to verify our position, the HEPs were coupled and the uncertainty analysis was rerun. CE coupled all the i
operator (post event) actions separately and all the maintenance (pre-event) actions separately because the actions are basically different and control room operator crews are manned by different people than the maintenance crews.
- Basic' events whose error factors were equal were coupled together. It was found that although coupling of these human error events gives an increase of about 20% in the CDF, almost all of the increase comes from the coupling of just two (2) human actions -
"Q" or "Q2", "and H00BOPHL", which are post event operator actions relating to high pressure inj ection. Coupling of maintenance events had very little effect on CDF. For the case of operating crews, it is felt that different crews, at 6 fferent plants, and in different locations within the total population of plants, will result in differences between the HEP performance of "Q" or "Q2", and "H00BOPHL".
2-1
ICC 25 '92 02: 01F11 pg 4
5.0 Multiplying The Mean Values By Two Question 1 On page 9 GE states that the effect of multiplying all basic events by 2.0 is equivalent to choosing a value above tna 85th percentile.
The staff notes that this is only true if your error factor is small.
Response: GE maintains that the effect of multiplying all basic event probabilities by 2.0 results in all probabilities being above the 85th percentile for all basic events, irrespect *e of whether the error factor is small or not. The justification fer chis statement is provided in paragraph 8.0. It is shown that the maximum value of the 85th percantile (x0'85) divided by the mean ( x )can be calculated as follows:
I max - exP ( 0.5(ZO.85 ))
(*0.85I wh.re Z 85
- th 85th percentile of the standard normal distribution (whichksequalto1.04).
The maximum value of this ratio is approximately 1.72. This shows that the
$5th percentile of any lognormal distribution is always less than two times its mean value.
6.0 Comparison of Tightly Coupled And Moderately Coupled Cases Question: For Tabis 4, page 12, please explain why "modcrately coupled" has a higher mean than " tightly coupled"?
The differences between the mean values in Table 4 F355 12 of
Response
the draft report are very small and era due to statistical variation.
7.0 Effect Of includin6 More Cutsers Question: If we assume that the top 300 cutsets did not include coupled events, would these results chan5e if we were to include more cutsets?
Response: No, the results would not change. The coupling which was performed for the uncertainty analysis is such- that the coupled events very rarely appear together in the same cutsets, and thus the mean values of the cutsets are affected very little by the coupling. Since the top 300 cutsets
- contribute 98% of the CDF, coupling the cutsets below the top 300 should not add more than a few percent to the total, even if almost all the basic events appearing in many of the cutsets were coupled.
3 i
g, gg ,92 02:01F11 p., g 8.0 Derivation Of The Value For ( x 0.85 ! max First, the EF can be writton in terns of the median and the 95th percentile as I ~ *0.95 /*0.5 where x - 9 th percentile 0.95 x - 50th percentile 0.5 From this definition follows that EF - exp(1.645CI )
and that
( - (in EF)/1.645 where, 6 = the standard deviation of the standard normal distribution.
- u. can also write the 85th percentile, x 2
0.85 ' ""
'x0.85 ~ *0,5 eXP( ZO.85 (in EF )/1.645) (1) where Z - the 85th percentile of the standard normal distribution.
0*85
- 1.04.
Substituting equation 1 into the equation for the mean, x , of a legnormal distribution gives:
x-x 0,5 exp ((in EF )2/2(1.645)2) (2)
Dividing equation 1 by equation 2 gives x
0.85
/ x - exp(1.04(in EF )/ 1.645 -
0.5'((in EF)/1.645)2)
This equation is a maximum when in EF - (1.04) (1.645) - 1.711.
This value of EF gives the maximum value of the ratio x0.85/ I (x 0.85 / I max - exp ( 0.5(1,04 )) - 1.72.
l
ICC 29 '92 02:02Pl1 P.6 Table 1 for TT.N COKTRIBUTORS To UNCERTAIFTY IN THE CDF Kank By r.y Standard Deviation 2 Lair. . Eve nt 1 lenartanee_ f2E 08)
RCItVINT 10 1 7.51 ccTwa 15 4 4.99 RTU001DH 15 $ 4.68 HootontL 3 2 3.01 CCTTLU 13 8 2.74 114CTH 15 9 2.48 Q $ 3 2.22 Q2 5 6 1.94 RJM001DV 4.5 7 1.28 EBY1CCF 10 12 1.0*
34 - _ 5 36
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w:. 21 :mM GE MEO E4 !a220 i, i GENorJmor Ermray ABWR ll$T' Date \1/v l%
To 0 lu 4 %usno Fax No. -
d r i O Thispageplus a page(s)
From OgolE~Eotuoto Mali code ~7s4 175 Curtner Avenue San Jose, CA 95125 Phone (408) 925- ms FAX (408) 925-1193 or (408) 925-1687 Subject 12ssymse b Lmq EM (%sbs Message 7temsc. L w el 4tGs 4<h k omme u Chd %% Ta\A - $5 O N fe m 5 &
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4 1 Advanced Reactor Program
- - San Jue, Califomia < '
! . Phone (408) 9251785 l Fax (408) 9251193 y CEB92-65 I
- Mon, Dec 21,1992 I To
- Chet Poslusny, NRC
- Bob Palla, NRC
[ John Monninger, NRC From: Carol E. Buchholz
Subject:
- Responses to questions on sump shield l
i i
The following information provides GE's responses to the issues you raised in your i November 23 fax. As we had discussed, I had held this package until Tony D'Angelo j had returned and we were able to talk on Friday.1;think these responses are i consistent with our discussion. I hope this information is useful in resolving any questions you may have about the sump protecdon as you write the FSER.
J j 1mpe 1: Chemical Rhintance of Shield Wall Material i
- _ GE proposes to use a refractory brick for the sump shield with a melting point of j- 2180K. GE has not addressed chemical attack on the refractory brick from the l
- corium. In light of the recent MACE test (M2), which had an early failure of the crucible containing the melt, GE should explain why their choice of refractory -
[ material would not be subject to a similar failure froni corium attack?'-
Response 1:
8
- The analysis contained in the GE submittal was for a representative refractory brick. The final material selection will be doue during the detailed design phase,
! However, resistance to chemical reactions should be considered in the material selection. A.first order estimate of resistance to chemical reactions can be obtained I; by comparing the Gibb's free energy of the wall material to' that of the oxides in die.
i debris. The lower (more negative) the free energy the more stable an oxide tends to -
~ be. The free energies of interest are contained in the following table.
l Since the free energy of MgO is higher (less negative) than the other oxides, it may f 'be susceptible.to chemical reactions when interacting with the potential' constituents of core debris. This is confirmed by in Marks' Handbook which states
~;_
that MgO has poor resistance to siliceous steel-slags. The side walls in the MACE M2 test were constructed of MgO and failed due to chemical attack, h CEBW45 Page1
j [g, 21 . : Ri 6E WCLEAP ANP u b- P. ? r-i 1
Table 1 g Oxide Free Energy Free Energy (kcal/ mole)
. Oxide (298 K) (2000 K)
! AlO3 2 377 -247 MgO 136 -77 UO2 257 -177*
]
i PuO2 -245 -lfA*
i ZrO2 258 -173 SiO2 190 -124 l '
! Ca0 -144 96 i 242 -120 FesO4
- cxtrapolated Alumina (AlyO ), 3 on the other hand, has good resistance to +.his type of slag. The l-
- comparison of free energies also indicates that alumina will have good chemical resistance to debris constituents.
- Running through the corium shield' acceptance calculations contained in the GE-l submittal demonstrates that alumina ~is an acceptable wall material with regard'to thermal performance. Since alumina will not chemically react with core debris and meets the thermal performance requirements, it is a likely candidate for final shield material.
Attachment 19ED (submitted in draft form in CEB92-47 on August 7,1992) will be -
modified to include consideration of the chemical resistance of the shield wall--
. matenal to the expected emironment.
k Issue 2:Imnact of shleid on normal operation and mai mic considerations -
The HCW and LCW sumps in the lower drywell, which GE is proposing to protect
- with the corium shield, perform system functions of equipment leakage collection _
(LCW sump) and leakage detection (HCW sump). The HCW sump would normally be open to the drywell floor to collect any liquid accumulation from z a potential--
RPV leak. The proposed corium shield may _have an effect on floor drainage 4 because of the small openings in the corium shield and may have an effect on the RPV leakage detection. system if the shield openings clog. GE should address these additional functions in light of potential clogging, Also, GE should address the -
seismic adequacy of the shield and possible missile generation in the containment -
r i from a seismic event.'
L Response fa: Effect of Shield on Leak Detection (Normal Sump Operation)
The corium shield will be designed so that it will not significant effect primary-system leakage detection. The floor drain (HCW) sump collects unidentified CEB92-65 - Page 2
.. , . ., . - - . . - - . . . - - . - . _ . - . - , , . . - ~ - . . .
- . - . ~ -. --- . . .-.- -.-- . . .-
E .21 "2 2. c iitt GE E LEAF' M um ,;
a leakage from the primary system. The limit on unidentified leakage is equal to or l
less than five gpm Leakage in excess of the limit, which cannot be brought under
- controlin four hours, requires plant shutdown, i
The floor drain sump in the lower.drywell is currently designed to have a perimeter '
of approximately 1.5 meters. The flow channels can occupy most of this length.
F However, some of the shield perimeter will be solid be proside the necessary support for the wall. The amount of the perimeter closed to flow will be kept to a j minimum in order to minimize the effect on leakage detection. It is expected less i- than one-half of the perimeter will be closed to flow. Thus, the channel opening width is expected to be at least 0.75 meters. The final design will be determined in i the detailed design phase of the ABWR.
i l The entrance to the channels will be covered with a wire mesh to prevent, or at
[ least minimize, clogging by loose material in the lower drywell. Material which l could have the potential to clog a significant portion of the channels would also 4 tend to block the entrance to the sump pump. Thus, some of the steps taken to keep the sump pumps from clogging will also provide protection from channel j clogging.
j Even if a channel opening width of only 0.5 meters is available, the water . ..
!- accumulation height required to drive 5 gpm through the thannels is smaller than the height of the channels themselves. Therefore, the preser:ce of the corium shield arotmd the HCW sump should not effect water leak detection during normal operation. This conclusion wdl be also be proven for the final design developed during the detailed design phase of the ABWR.
! Response 2b: Selsmic Adequacy and Missile Generation l
Seismic adequacy will be established during the detailed design phase. Any
- measures necessary to provide seismic _ support will be designed at that time. These
!- supports, if put into place, will not play a role in the shield's primary function '-
j keeping debris out of the sump. Missiles will not present a significant design
! cha.lenge because the shield is in the lowest part of the containment and far from i
critical equipment.
4 Issue 3: DetmHed Demien
[ GE has only provided the conceptual design with a sample heat transfer calculation for the' corium shield. GE should submit more detailed information (e.g. support system to keep bricks in place, diameter and r3 umber of pipes entering top of j corium shield, consequence of corium shield failure, consequence of corium u entering sump with water present in the sump). :
- Response 3: .
Detailed-design information (support structure and number of pipes) will be generated later in the design process. The goal of the current level of design detail is to provide the Staff with enough information to rule on plant safety. The
-probability that the shield will fail to perform its function is extremely small.
i CEB92-65 : Page S .
l
, . . ., - ., ---tv -- -y- -
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IjC.,21. 92 :d.i GE PKl.EAF AEI? y_. 3,q p, r -
1 i
i l 2 !
l Coupling this with the extremely small probability of getting significant debris
- relocation to the lower drywell generates an accident sequence that is remote and
. speculative. The consequences of which are irrelevant.
> Imue 4: Embedded Piping in Floor Paragraph 4.5.2.9.2 of the EPRI Evolutionary Requirement 3 Document, describes l
j provisions to prevent transport of corium into drain or sump piping. Does the
, lower dowell floor contain embedded piping within the concrete, which could be reached by the corium during continued concrete ablation.
p Response 4:
1 j The lower drywell floor does not contain embedded piping.
2 Issue 5: Contact Resistance and Shield Sunoort Structure The GE analysis for the sump corium shield addressed the heat transfer aspects for j debris freezing. The analysis did not address contact resistance between the bricks
! of the shield. Although contact resistance may be neglected for thick blocks of material with a low conducthity, GE has not provided any such justification fro 3
neglecting evaluation of contact resistance. Also, there is no discussion on the
- corium shield's ability to limit the interior temperature of the sump and therefore, protect the support structure of the shield, 1
Issue 5a: Contact Resistance Between Bricks
! Contact resistance was neglected in the original GE submittal (CEB92-47). The submittal will be modified to include a requirement to chose a final shield design with a contact resistance which is either negligible or, at least, does not prevent debris solidification. This could be done by choosing bricks which are large
, enough and smooth enough to minimize contact resistances or, potentially, using.
- a high temperature fdl material between the bricks. The final solution will bc
- chosen and demonstrated during the detailed design phase.
Issue 5b: Shield Support Structure--
~
- Consideration oflong term support of the shield by an internal structure is not i required. When the debris material comes into contact with the shield it will quickly form a crust which will grow in time. Crust formation eliminates the buoyancy forces on the shield and provides support for the shield bricks.
3 Therefore, the internal support is only required during the initial onslaught of the 4 debris. The roof of the shield is not expected to accumulate significant amounts of !
debris. Therefore, even if its support structure fails, only negligible amounts of 3 debris will enter the sump.
G 1
l s
Page 4 -
- CEB92-65
< TRANSACTION REPORT > 12-21-1992(PO D 16223 E RECEIVE 3 NO, DATE Tit E DESTINATION STATION PO, DURATION. MODE RESULT 6685 12-21 16:20 4099251193 5 O*02'41' NORr1.E OK S O*02'41" C
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i 10: 18 '92 CGt 1W41 G E lu:LC# DLIG J p,;
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TYPEt GENERIC 1.ETIIRS lasue b'9, PdL 'l1111 Com'a'"t 90@) 12/11/90 Altetnative Requirements for Snubber VisualInspection Intervals and Cc.rtective Actions 91 03 -03/06/91 Reporting of Safeguards Events COL applicant 91 04 01/02/91 Changes in Technical Specification Surveillance Intervals to Accommodate a 24-Month Fuel Cycle 91-05 04/Gt/91 Licensee Commercial Grade Procurement and Dedication Programs !
91 06 04/29/91 Resolution of Generic issue A 30,' Adequacy of Subsection Safety-Related DC Power Supplies.* Pursuant to 1911.2.24 10CIM$0.54(f) 91 30 07/08/91 Explosive Searches at Protected Area Portals COL applicant 91 11 07/19/91 Resolution of Generie issues 48, *LCOs for Class Subsection IE Tic Breakers
- Pursuant to 10CIV50.54(l) Ill.2.24 91 14 09/23/91 Emergency Telecommunications 91 10 10/03/91 Licensed Operators' and Other Nuclear Facility COL applicant l '
Personnel Fitness for Duty 91 17 10/17/91 Generic Safety issue 29, *Ilolting Degradation or Failure in Nuclear Power Plants" 97-04 g/is/97. Res oU ton oI8c TsN<s R4.\okeel COL of f h e.=M
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C RECE1UE 3 tJ0. DATE TlHE DESTlNATION STATION PO. DURATION HODE RESULT 6200 12-18 10:13 408 9251687 2 0'00'51' tJORti. E OK 2 0'00'51'
ICC 18 '92 11:18idi G E lu:LEr# ILt4 J p.1
'b GENudewEnergy ABWR Date l'LA s /91 To C % k % \+>+m _ Fax No. -
w.\h sn % hon This page plus _L_ page(s)
From Jacb Gov Mail code 18L -
175 Curtner Avenue San Jose CA 95125 Phone (408)925 4814 FAX (408) 025-1193 or (408) 925-1687 Subject OT G.2A-2 Message
.A +
ta is we is owi c c tent # ru.; a , ;.
o t 6.2.4 - 2.
nuimac AlnVR REY C S(IlDdgridhtilt automatic reopening of containment isolation (5)The ABWR Standard Plant design is consistant valves. Reopening of contaioruent isolation with this position.
valves shall terluire deliberate operator action.
(6) All ADWR containment purge vahes meet the (5) The containment setpoint pressure that initiates criteria provided la UTP CSD 6-4. The ronin 22' containment isolation for non-cz.sential penetra. purge valves are fail closed and are maintained l tions must be reduced to the minimmo compat. closed through power operation as defined in the ,
ible with normal operating conditions. plant technical specifications. All purge and veet valves are remote pneumatically operated, fail closed and retelve containment isolation signals, (6) Containment purge valves that do not sathfy the Certain vent valves can be opened manually in i operability criteria set forth in Braub Technical Position CSB 6-4 or the Staff Interim Position of the presents of an isolation signal, to permit October 23,1970 must be scaled closed as de- venting through the SGTS.
fined in SR1' 6.2.4, item 11.6.f during operational .
l conditions 1,2,3, and 4. Furthermore, these (7) In the AUWR design, the containment purge and vent isolation valves will be automatically holated R valves must be verified to be clused at least every 31 days.
on high radiation levels detected in tbc reactor $
building HVAC air exhaust or in the fuel (7) Containment purge and vent isolation valves handling area air ethaust. I must close on a high radiation s,ignal.
Response
(1) The isolation provisions described in the Stan-datd Review Plan, Subsection 6.2.4 (i.e., that there be diversity in the parameters sensed for the initiation of containment isolation) were re-viewed in conjunction with the ABWR Standard Plant design. It was determined that the ABWR Standard Plan is designed in accordance with these recommendations of the SRP.
(2) This request appears to be directed primarily toward operating plants. Ilowever, the classifi.
cation of structures, systems and components for the ABWR Standard Plant design is addressed **
J M in Section 3.2 of this SSAR. The basis for classi. -r b G 5 f# Ss t fication is also presented in Section 3.2.ffhe %W vw w wdb MT ABWR Standard Plant fully conforms with the d.ed a cchew o d J\ b a c.o d ^ # *
- 3 NRC position so far as it relates to the new cu 4 clo\ % M m"To\.ke C. 2. - 7 equipment supplier.
(3) All non essential systems comply with tbc NRC position to automatically isolate by the contain.
ment isolation signals, and by redundant safety grade isolation vahu.
(4) Control systems for auton.atic containment iso-lation valves are icsigned in accordance with this position for the ADWR Standard Plant.
Design.
1A29 l Arpendment t7
c . .
. < TRANSACTION REPORT > 12-10-1992(FRl) 13:18 ,
(
C RECEIVE 3 NO. DATE TIME DESTINATION STATION PO. DURATICrJ tODE RESULT 6615 12-18 13: 17 408 92E1087 2 0'01'00* NORM.E OK 2 0' 01 * (9
- l
[CC 10 #92 01 2 711 G C iD:LDW litlG -J P.1'"
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J From Jo.ek poe Maii code 1 e t-175 Curtner Avenue San Joso, CA 95125 Phone (408) 925 4 Ot4 FAX ~ (408) 925-1193 or (408) 925-1687 Subject A P PGMD W \9P 1 S S US S Message Savc+ -Cor ove ekn$ m . .
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October 20, 1992 cc: JD Duncan l JF Fox i
To: Ji Quirk . . .
From PD Knecht
Subject:
Rf 50t UT10N Of 1,$MLR[lMQ_10_AEP1NjJL,lg I
References:
! 1. NRC Letter, Pierson to Marriott, " Resolution of issues related to Appendir 19P (Evaluation of Potential Design Modifications) of the Standard Safety Analysis Report (SSAR) for the Advanced Boiling Water Reactor (ABWR) Design", September 2, 1997 a
- 2. NRC Letter, Pierson to Harriott, " Clarification of issues Related to a Staff Request for Additional Information dated September 2, 1992",
September 30, 1992
. Responses to the Requests for Information contained in Reference 1 as modified by Reference 2 follow. As-outlined during our meeting on October 7 and 8, these responses are believed to be acceptable to the NRC Staff.
- 1. GC has concluded that a filtered containment vent system is not applicable to the ABWR. a) Provide an expanded basis for this conclusion. b) Provide an analysis for inclusion of a filtered vent with consideration of the recent developments in the moderate cost filter systems designed in furope (venturi, wire mesh , etc.)
RESPONSE
GE considers, because it provides a scrubbed release from the containment, that the current rupture disk system contained in the ABWR
- provides an equivalent benefit to any potential filtered vent system such as is being implemented in Europe. Nevertheless, in order to show a more complete range of potential modifications to the ABWR design,
! Appendix 19P and the SAMDA Technical Support Document will be modified i to include an ovaluation of a European style filtered containment vent.
The reference cost assumed for this modification will be $3,000,000.
l 2. CE has concluded that core retention devices have already been incorporated into the ABWR Design. a) Provide a description of the
" incorporated core retention devices" and the supporting analysis to i demonstrate their effectiveness, b) provide the experimental data base to demonstrate that the passive containment flooding capability "provides an equivalent function to a core retention device", and c) provide an analysis that includes a " core catcher device similar to the ones described in NUREG/CR 3908, " Survey of the State of the Art in Mitigation features".
/ tcc le T ouMu G t lumn tuiG J P. M RESPONSL 1he passive containment flooder cools a devrb bed by flooding over the molten core in the lower drywell with water from the suppression pool.
if a severe accident has resulted in a loss of RPV integrity, accident management guidance will specify that sprays be initiated to quench the debris bed. Af ter the molten core has been quenched, no further ablation of concrete is expected and the decay heat can be removed by normal containment cooling methods such as suppression pool cooling. j The text of Appendix 19P will be clarified to indicate that the passive ,
flooder provides a backup function to the capability to flood the '
drywell through sprays from the diesel ti riven firepump. A justification of the Passive flooder design is provided in Appendix 19G.3 of the SSAR. The benefit of a system similar to those described in the NUREG will be added to Appendix 19P for completeness.
- 3. GE identified a list of potential modification from a variety of previous studies performed to address severe accidents. Has GC performed a systematic review or " brain storming sessions" to identify any new innovative methods for addressing severe accidents? If so, please describe the process.
RESPONSE
Ho specific " brain storming" session was conducted for the ABWR.
Evaluation of potential modifications has been a continuous part of the design process on the ABWR design as the PRA has progressed and as designs have become further developed. Section 19.7 includes a discussion of the use of the PRA to evaluate these potential modifications. Several modifications which showed a potential for significant risk reduction were included in the ABWR design whenever practical. The previous studies reviewed in Appendix 19P provide a confirmation based on other activities that a worthwhile modification was not overlooked.
Additional modifications which address areas evaluated separately from the PRA also were identified and evaluated as part of the design process. In particular, seismic hardening of some systems was recommended when improvements in the seismic margins could be identified. Similarly, procedural modifications have been identified based on the Shutdown PRA and the- flooding analyses.
The text of Appendix 19P will be expanded to address the ABWR design process as a tool for identification of additional modifications. In addition a potential modification to the bottom head drain piping to make it less susceptible to molting will be included in the text to Appendix 19P.
l to: to '92 OU2am 6t orttm tot 6 J P, n l
- 4. The $1,000 per person-rem figure has been used by the NRC and industry for many years. Presently, consideration is being given to increasing this value by an amount that may change the benefits associated with some of the proposed design modifications. Please provide a sensitivity analysis relative to the cost benefit ratio to evaluate the potential benefits of modifications if the $1,000 per person rem values were increased to $10,000 per person rom.
RESPONSE
As indicated in Reference 2, no response to this request is.needed.
- 5. Provide a more detailed assessment of the following potential modifications emphasizing description, cost estimation process and cost data, calculation of risk reduction and benefits. The analysis should include other offsite costs in addition to the dollar value used for person-rem averted.
- Reactor Building Sprays
- Anticipated Transient without S: ram sized Vent Improved Depressurization Drywell Head flooding
- Improved Vacuum Breakers Suppression pool Jockey pump
- Reactor Water Cleanup (RWCU) Decay lleat Removal
RESPONSE
For the items indicated in the question, additional information will be added to Appendix 19P_on the cost basis and the process used to estimate the benefits. As indicated in Reference 2, however, no consideration of "other offsite costs" will be included. Rather the
$1,000 per person-rem value is considered to encompass such costs for the purpose of this evaluation.
- 6. It is NRC's policy that in the consideration of cost benefit related to the analysis of design alternatives, averted onsite costs should be accounted for in the cost benefit equation as reductions in the costs associated with the proposed design alternative. If averted onsite costs are considered in this manner, identify those modifications that would be deemed cost-beneficial based on a range of person rem averted of up to $10,000.
RESPONSE
As indicated in Reference 2, the 51,000 per person-rem standard will be used in this evaluation. The. previous evaluation of design-modifications did not include on-site cost reduction benefits as. a reduction of the modification cost basis since such reductions were considered to be best applied to the benefit _ side of the equation,
< ,-m- - , ,,- .__ ,, , p,,, . , _ , , , , _ _ _ _ _ _ ,
,e w - -- -ww -
/
- t(c te w 01:s11 G t to:toiP tric J P . 'W As a procedural matter, consideration of averted on site costs is a considoration only applicable in the application of the Backfit Rule which does not apply during certification. Nevertheless, the cost basis included in Appendix 19P will be revised to reflect the averted on-site costs in accordance with the methods described in NUREG 0058.
j Revision 1 and NUREG/CR 3568.
In addition, mitigative modifications will reviewed to identify any reductions associated with on site cleanup costs. Such reductions will be included in the evaluation.
i 7. In evaluating the benefit of improved depressurization, the GF
' submittal assumed a reduction in depressurization failure rate of a factor of 2. Why wouldn't a reduction of 510 be more appropriate, given a diverse system?
RESPONSE
lhe design modification described in the submittal is not a diverse 4 system. The concept was initially developed during the certification 2
of the GESSAR 11 design and was selected due to its low cost rather a than high potential benefit. Because of the relatively higher high j pressure coolant makeup capability the importance of depressurization is reduced in the ABWR design, lherefore diverse concepts were not considered. Clarification will be provided in the Appendix 19P text.
- 8. GE stated that a larger containment would not prevent containment failure. Would not a longer time to failure increase the likelihood of core and containment heat removal recovery, which might prevent ultimate containment failure? Please address.
i
RESPONSE
i A longer time available for recovery does provide a higher chance of recovery which could reduce the chance of containment failure. This additional benefit for this modification was not considered due to the extreme cost of the modification. lhe text of Appendix 19P will be clarified.
- 9. Some of the modification seem to incur a relatively low cost, such as the RWCU procedural upgrades for enhanced decay heat removal. Given the probabilistic risk assessment uncertainties, why shouldn't the small cost actions be implemented?
RESPONSE
The basis for conducting cost-bonefit evaluations is to balance the costs against risk reduction benefits. Only if there were significant safety benefits would a low cost modification be included. The low frequency of core damage in the ABWR justifies that . potential benefits do not justify even low cost items.
,' Kc w ' n 01 w:m .:, t to:LE,w tot 6 3 r> . . c
- 10. In evaluating the cost of a dedicated RiiR de power supply, GE only considered fuel cells (56 Hillion) or an additional battery system (5?.5 Million). A small diverse gas or diesel de battery charging gencrator would appear to offer much of the same benefit for much lower cost. Please address.
RESPONSE
The addition of a battery charging system was not specifically evaluated since it was not clear if a benefit would result. A detailed sizing study of a charging system would be needed to determine the smallest and least expensive generator which would either compensate for the battery drain or provide a recharge in an acceptable period of time. While a :;omewhat lower cost system may be possible, the relatively low benefit to be derived from this type of system modification, do not justify a more refined consideration. The text of Appendix 19P will be :1arified.
- 11. GE's dose calculations were based on offsite exposure over a 50. nile radius. Previous analyses have considered dose accumulations over a much larger area surrounding the reactor. In this regard, provido an assessment of the risk reduction potential for the various alternatives if a 1000 mile radius is used.
RESPONSE
As indicated in Reference 2, no response to this request is needed.
- 12. Use of fire water for core injection or wetwell sprays is an important i contributor to reduced risk for the ABWR and appears to be dominated by human error, in this regard, please provide justification for not considering enhancements which would facilitate the use of diesel driven fire pumps as an alternative, such as providing the capability
. to achieve the necessary valve alignment from the control room.
RESPONSE
1he use of the fire water system is described in Appendix 19G.2 of the SSAR. All valves requiring manual manipulation are located in the same room. The success probability of manual initiation (-90%) is based on the operator recognition of the need f or initiation and would not change due to enhancements to facilitate the alignment from the control room.
- 13. Table 19P.3 1 identifies a number of modifications already included in i the ABWR design. Please identify the SSAR section where such
- modifications are described, or provide a detailed description of the
' modification and its use in the ABWR, if not included in the SSAR.
tcc le '90 0122011 G t uxLUF tot 6 J P.7 ,
RESPONSE
Cross ieference to the appropriate SSAR sections will be added to Table 19P.*,-1. In addition, the titles and labels will be reviewed and clarified where appropriate.
Additional commitments were made during the meetings with NRC October 8 and
- 9. These were:
- 1. The core damage tabic for lype 11 cycnts will be made to be consistent with the PRA tables.
- 2. Group 4 SAMDAs on lable 19P.3-1 will be included in the text descriptions where appropriate.
- 3. The vacuum breaker improvement will be updated to be consistent with the revised Bypass study (19E.2.3.3).
- 4. The consequence tables (19P.?-l and 19P.2 3) will be made consistent with the corresponding tables in the TSD and Appendix 190.3.
- 5. Scismic risk discussions will be revised to be consistent with the current discussion of seismic margins.
4
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12/17/92 i
To: R Palla cc: J.D. Duncan G Kelly From: P.D. Knecht
Subject:
Suooression Pool Byoass Evaluation (Section 19E.2.3.3) i Attached is the final draft of section 19E.2.3.3 of the ABWR PRA. This version i incorporates responses to NRC questions (0 4) and comments and updates the text for consistency with the current edition of the PRA.
This revision is considered final. If there are any questions, please call.
,p ,% -a f'
/
PD Knecht Principal Engineer (408)9256215 ;
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The plant design criterie ensure a highly rellebte if the total toess risk is to be losignificent, the test I system for contelrvnent isoletion. hevertheles6, even tore in e42stion (2) eust be auch less then the first, ors
\ though there la diveralty in the types of valves, ett types have emperienced f ailures et operating nucteer plants and certeln events, such as the station f (3) blackout event, ser make the early isotetton of some lines lupossible. This section evaluates the the total tr/pess and non irmess event frequencies (7) significence of bypass paths in order to justify that noted above are the total core demspe fre<:pmeles for no additionet treatment In the PtA la necessary. these events and assume that att bypots events have the same consMpence. $1nce this is soldas the case, the (3) Nothodology for twelustion of $@pression Pool trypets frequency must be defined such that the proper typees consegJence is applied. thle is accomplished thecuph evolustion of fleu optit fractions (f) es discussed below.
The evaluellon of s@pression pool bypess pathwere is l based on a methodology which evaluetes the potential ;
relative increase In of fsite consequence f rom bypese The total bypass fregsency con be espressed est l events over those events with s w eession pal scrdelne. then, knowing this emmeit of increase, if f a fg a sur.[P 1 (4) it con be shown that the prohebility of bypest is j sufficiently low as to offset the increased where Fed a The totst core demote ]
conseg;ence, the eMed risk from these pathways can be fregaency and considered to te insignificent.
P e The total conditional ,
the justification for this approach is es follows probability of fuit !
s e cession pool bypass in allt e ??tAL (tythf f atoutWCY M CON $t0VENCt] (1) bypass path l, elven a core e f aC +7 aC (2) demoge event.
Where 7 e the total core damage f*equency of the conditionet probability of full bypots can be further non bypass events refined by the empression C e The consequence of a non bypass P e P a f, ($)
event where f g a the fraction of fission pro & cts F e the total core demose frequency of ponerated Arirg a core demote event bypass events which are ogJivelent which pass through line I (section to a conotete bypass of the 19t!.3.3.3 (1) discusses this term in s @pression pool. more detall)
C e The consequence of a complete The flow split fraction (f) is defined bypass event . as the retto of the flow rete editch posses out of a bypeas pothway to the total flow rete of aerosols generated bring the core melt process, the line flow split reduces the consegaence associated with saatter Lines h e to inherent flow restrictions in those lines as compared with the corwegsence of tercer lines, the flow split fraction accounts for this consegaence re&ction by reducing the egJlvetent j bypass probability.
p; 12/17/92 ) i To: R Palla cc: J.D. Duncan G Kelly ,
j From: P.D. Knecht .
5
Subject:
igouression Pool Bynats Evaluation (Section 19E.2.3.31 Attached is the final draft of section 19E.2.3.3 of the ABWk'PRA. This version incorporates responses to NRC questions f0 4) and comments and updates the .
text for consistency with the current edition of the PRA. !
This revision is considered final. If there are any questions, please call, YAM-/I' ?
PD Knecht Principal Engineer (408)9256215 P
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- i 1pt2.3.3 Suppression Pool typess Poths risk. Consowently, the probabittstic risk asseensent e l
does not re wire a seperate eyeluetten of hypots
]1 1pt2.3.3.1 -introection sospences, unless the sewences develop kring the course i
i of en evere for eassple, as a result of low swression ;
thle section revieve the potentist elsk of certeln poet water levet, such cases are considered in section
) ;
oppression pool bpets paths and demonstrates that, 100.$.T i
with the onception of wetwell drywell voc u breekers and certeln other lines, bypass paths present no movertheless, certain bypass lines which result from j eignificant risk following severe accidents, Secause plpire failures outside of the primary contelneant are I of this insignificence, only the vectAan breakers and included in this revlev in order to essess their the other ilnes rewire further consideretten in the elsnificence.
ApWR PRA. The approach used in thle evoluetten le 1 eluller to that admitted to the met in opport of the (2) Mechantoms for $wression Poet typeos l GillAt (Ref ererte $) review.
All lines which originate in the reector vessel er the j the results of the evetuotton is that bypass linee primary conteltonent are respired by sections of 10tF050 to j evaluated contribute no more then about 10% of the meet certeln rewirements for contelnment teotetten.
total plant risk and con therefore do not need to be Lines which originate in the reactor vesset or the l
specifically evetuated further in the pea. contatraent are rowired by General Design Criterle 55 and ,
j 56 to have het barrier. protection which is generetty l 41) Definition of Sweteston Poot spots obtelned by reendent (setetten velves. Lines d ich are considered non+essentist in mitteeting en eccleont are I
suppression Poot typass is defined as the transport of etso rowired to automatically lootste in reopense to
- fission proects through pathways which do not include diverse footetten signale. Other lines which any be j the suppression pool. In such cases, the scr4bing useful in mittpating en accident are canaldered onceptis 4 i action for fission pro &ct retention le lost and the to the Generet Design Criterle (uutto 0000, section 6.2.4) and are permitted to have temote menuet isolation valves,
- (
potential consowences of the release are higher.
The potentist for suppression pool bypass has been a orovi.d that e -ens is o.eiiebie t. . eci ieeks.o .r breaks in these lines outside of the primary contaltment.
! subject of enetysis since the early days of WlN 1400.
i the *V" sewence which represented a break of a low A potentlet mechenlem for s w pression pool bypese is the pressure line outside of the primary conutrment was *En contalrpent LOCA" which results from the conbined l '
one of the more dominent release sewences in WIN failure of a line outside of the primary contelnsent along I
1600. ' The IDCon enetyses and gMI.2104 also reviewed with the failure of. Its re&ndent footetton vetves to sewences in which the swpression poet scr4bing close. if thla ceabinetton of events occurs, the operator 4 oction wee not obtelned in the release pothway, is made swore of the situation through leakage detection storms and is instructed by plant proce&res to menuelly ,
in order to review the toportance of suppression pool f ootste the lines, if possible, when the susp water level bypass pathwers, the potential mechentems, in eroes outside contelnment exceeds a predetere!ned j
- probabilities and source locations were reviewed to point.
i Identify where fission pro & cts might be retoosed outside of the contelruent. The enetyels has pecause of these provlelene the probability of_ sgpression l
j conservettvely focused on the station blackout event poet bypass occurring from the "Ea conteltpent LOCA* is ,
because it teeds to a higher liketthood of stepreselon entremely emell since it re w ires the slauttanoeus pool bypeas and because it le considered one of the failures of a piping system, re&ndent and electrically l
j more probable core demote sowences. separate isolation wolves and the failure of the operator i to take action.- Section ist.2.3.3.4 suunerties en 1 The principle conclusion of the review is that, with evelustion of the core denote f rewoney fram
- . the exception of certain lines addressed in ta contatteent LOCAs.
contairement event trees of the pea, s@pression pool b bypass pathways do not contribute significently to 1
i s
-t-+ wa + w +-+ n ee w-=mwv,-. -erw--ee-- nr.++r-m-mww-e- _ ---+ wwer w e e- arur--tw wwa +.ee *wv- a re m r w -a-r -w-e,-v"w-s e . a- w-r
a -lY . . . . - - . . . .. .
the plant design criterte ensure e highly retlebte if the total bypass risk is to be inelentficent, the test I system for contelryment isolation. hevertheless, even tore in owetion (t) aust be auch less than the first, ort
\ though there is diversity in the types of volves, ett types have esportenced failures et operating nuclear g plants and certain events, such es the station F (3) blackout event, may make the early isolation of some lines (spossible. This section evaluetes the The totst bypass and t w bypese event fre wencies (t) slenificance of bypass pathe in order to justify that noted above are the total core demose frewencies for no additional treatment in the PAA lo hacessary. these events and assume that all bypass events have the sene conso w ence. Since this le seldom the case, the (3) feethodology for tvetuation of $@pression Pool bypees frewency anat be defined such that the proper typees consowence is applied. This is accomplished through evolustion of flow eptit fractions (f) es 61scussed below.
The evaluation of s @ ntession pool bypass pathways le based on a methodology which evaluates the potentist rotative increase in of fsite consowence from bypass the total bypass fropency can be empressed ess ;
events over those events with s @pression pool j scr @ lnf. Then, knowing this amount of increase, if F e F a LatP 3 (4)
It een be shown that the probability of twess is suf ficiently low as to of f set the increased where Fed = The total core demepe l I
conseg.sence, the added risk from these pathueys can be freg.sency and considered to be insignificant.
P e The total conditional The justification for this approach is as follows probability of futt I
s @pression pool bypass in
, Rilt
- TOTAL (EVENT FRIOVEhCT X CONSf 0VENCt] (1) bypass path 1, given a core e aC (2) demoge event.
F@ a C@ + FW 4 Where F e The total core damage frequency of the conditional probability of full bypass can be isther non bypass events refined by the expressions C e The consequence of a non bypass P e P a fg ($)
event dere f, a The fraction of fission pro & cts F e The total core demose frequency of generated Arl a e core demepe event bypass events which are ewivalent which pass through line 1 (section +
to a couplete bypass of the 19E2.3.3.3 (1) discusses this tore in s @pression pool. more detalt)
C e The ccrisequence of a complete The f(ov optit fraction (f) is defined bypeso event as the retto of the flow rate which posses out of a bypass pathway to the totet flow rete of aerosols generated during the core melt process. The Line flow split re eces the cormequence associated with smetter lines he to inherent flow restrictions in those Lines se ccapere(' with the consequence of larger lines. The flow spttt fraction accounts for this consequence re&ction by reducing the equivalent g
bypass probability.
.- -. .= - = -
7,_ , ; _ _ _
g_-.- - - . . - . - . - ~
The corresponding retto based on values in febte 19P.t.1
! and is 8.4t.6 which con be uses in the evolustion of pool P e the conditional .vobability of bypass in trypass significence. further evoluetion of "Es contelnment line I (section 19te 1.3.3 (2) discusses (DCAs s@presstrW pool INpees paths In the PGA le not this term in more detell). necessary if it con be choin that the total bmese probability le slenificantly less than this cunsessence the conditional probability of bypass Is retto, established through a detalled evolustion of each potential bypse pathway, iM2.3.3.2 Identification and Description of Swpression estabitshing the f ailure which sust occur Pool typass Pethvers for a bypots path *o develop and j estignire e probability to that f ailure. Identification of the potentlet stspression pool bypass pathways was based on information in the ADWR Stenderd Safety Analysts Report and s@ porting piping ord Core demsee events result in essentietty two types of instru ent Diepreme. The potentlet pathwers are sho.sn in !
rettesel rettests which bypeat the s @ pression pool metria form in Table 1M.218.
and those that do not. With ttle sloplification, the total ren' bypass frequency con also be defined as: Table 19t.2+1 sweherises the results of reviewing the ABWR design for tires which are potential pathways, for ees.h line the table provides the line stres, pathways and type F e p . F (6) of Isoletion @ to the second isolation valve. The bypass N'
- lines identifled in table 198.21 were derived from e Inserting equations (6), (5) and (6) into egaetton (3) systematic review of the ASWR P&lDs.
yletos Severet lines In febte 19E.!*1 were excluded from further a f (T) consideration on the beels of a verlety of judgements P
4 CgC discussed in the febte notes. In generet the esclusion
( if equation (7) is settsfied, then the total bypese risk la insignificant.
was based on deterministic rather than probabilistic ergwnents. For instrace, the RWCV Return line to feedwater and LPFL Loop A were included in table 19t.21 ord escluded frora further onetysis because the bypass path is (4) Criterie for Exclusion of typass Sequences in protected by the feedwster check volves.
the PRA The remaintne lines are considered petentist sources for As noted previously, if it een be shown ths't the slentficant fission product release following severe probability of bypass is sufficiently low as to offset accidents. Although the probablLity that these lines the increased conseesence, the risk resulting from could reteese a slpolficant amoet of fission products la release through bypass pathways will be insignificant. extremely smett, they are reviewed further in aseectlen 19E2.3.3.3 to essess the leportance of these releases.
To establish a threshold for this frequency, the consequence retto (rlpht side of equation (7)) was 19E2.3.3.3 tvetuation of typass Probability evetuated using the MAAP 3a.AsWe ord CRAC codes to establish the a;9roximate order of magnitude for Equation (T) of section 19(2.3.3.1 estat ilshes the need evaluation purposes. for evetuation of the flow splits and ft!!wre probability I for each line not excluded in table 195.2 1. This section l For the non twass case, the of fsite dose from normet provides the bests for the evolustion of each of these contelrewnt teoksee following core damese was used as factore.
a bests. "oCL", described in Amendia 19P, is the -
l consequence from normal contalrvnent leekspe; " Case 7" may be used as en approximation of the full suppression poet b@ess consequence.
k
. . ...._. ~ .,_.,_-
(1) Evaluation of typess flow Split fraction (f ) g Solving for f',
f To essess the fraction of aerosol release which bypass f' e 1991 Y d te/ry) /1991 ny,d, (e/ry) f the s +pression pool e flow split fraction is needed.
the flow split fraction (f) is defined as the retto of e Y d ,(#/K) /nY d ,te/K) (11) the flow rete which posses out of a bypeas pathway to the total flow rete of aerosols generated charing the tcM tlen (11) may be rearranged to shows core sett process. Two generell ed bypass paths have been evaluated: 1) e path from the RPV which passes 9 f8 e (1/n) (f;/f ig/d,) g (12) the reactor building with the remainder possing to the a le i# 1 (K /K 1 s wpression pool through the StVs and 2) e path from the drywell to the reactor building with the remainder The espressions in equation (5) were eveiusted numerically possing to the s @pression pool through the dr)vell for the octuel line conffpurations to arrive at the flow vents, spilt values shown in Table 19t.2*21. The following assuiptions were ende in this enelytist The flow split fraction may be defined est
- 1. Contelnment pressure following the cote melt le faW / (W ej n W,1 (8) assumed to be et en overese of 45 pois during the post core melt period. Although the containment where W e the flow rate which passes through pressure could eventually increase to a higher level, the bypass pathway the everage is used to essess the total amount of release since a release would be occurring throughout We the flow rete in a single line thle period. This pressure le typical of those (stV or drywell vent) which posses calculated in severe accident onelyses e see fleures to the suppression pool 19t.2*2 through 19t.2*12.
j na the ru eer of flow paths to the 2. Prior to RPV mettathrough, the reactor pressure 4 s@pression pool vessel (RPV) is maintained at a retellvely tow pressure (100 pets) by the outunatic depressurisetion This een be sleptified into the forms systen or equivalent manuel operator action. Four ten inch safety rollsf velves (ADS valves) are open to fa f' / 1+f' (9) release RPV effluent to the s w pression pool. This le consistent with alnimus instructions in the EPGs.
where f' s W /rg Ten 24 inch drywell vent paths are consistent with the ASWR deslyn conf fpurntion. For conservatism the f rom the formula for turbulent conpressible fluid flow vents are assumed to be one quarter uncovered.
(Reference 7)
- 3. The pressure drop in the bypees path between the W e 1891Yd ((@)/KV) (10) fleston prodact source end the release point is a fmction of whether the line prochaces sonic or where W e jork(tb/hr) 6 @ eonic velocities. For RPV sources, en overste T e Expansion factor 100 pois internal RPV pressure is assumed during the d . Internal diameter (in) core melt process. This is based on en everage 65
@ e Differentlet pressure (peld) psig drywell pressure and on assumed SRV design which K e Resistance coef ficient a f'L/D e t' closes the say when a differentlet pressure of about (se friction factor 50 paid exists between the main steenline end the snV L/D e pipe length to diameter retto, including discherpe line.
corrections for valves and bends.
E' e additional f actors for entrance and salt Depressuritetton of the RPV or contatronent through effects the bypese path is not conaldeved. the essweption is V e Specifft volune of fluid (cf/lb) made that pressure is continuously ponerated during the severe occident in sufficient quantity to mcover the StV d(scherpe or Drywell vents.
(
. , ~
. m.m.w w . . ,
.- - ~_ - - -
_ . . . _- -~ ._.---
- 4. The flow in the non bypass path between the fissica product source and the stwression f ebte 19t.219 shows sogle flow split resu'.ts (f 8 from
{ pool release point clepends on the elevation equation 12) for e line with two motor operated valves, in heads that are experienced with the the evaluellon cf Indivi kel bypass lines the actual swpression pool. The s @pression pool level confleuretion is used, the evetustion of flow split is ess med to be higher then normet tecause of fractions is considered to be conservative for several the depressurisation r,f the RPV to the reasons:
S p ression pool through the $tVs. For pPV sources, the levs emperience about a 20 foot 1) sypese release poths would normetty to expected to be more restricted then evalueted h e to smelter lines, (6.ON) elevation land over the StVs kring the core melt process. For drywell sources a 15 more velves and pipe bende, valves being portially foot (4.5M) elevation head is esperienced over closed or pipe breaks being emetter then the piping the wper horisontal vent, for the station diameter, blackout eegaence, the effect of (CC8 system operation on s wpression pool level hos been 2) We credit is taken for additional retention of Ipnorod. fiesIon producte in the resttor butIding, in piping or through redloactive decoy.
- 5. The length of lines discharging to the suppression pool and through the bypots paths 3) for drywell sources, a higher then enetyted effects the resistence coef ficient (equation differentist pressure should estat between the (10)). posed on the AgWR errensement drawines drywell and the wetwell, this will lead to lower this length is estimated to be approalmetely flows through the bypees path.
85 ft. (25M). For crywell sources the path to the suppression pool is estimated to le 5 f t. (2) (volustion of fel(ure Probabilities (P )
(1.5M).
The fellure probabilities used for the detailed other values used in the calculation are listed belows calculation of the bypass probabilities are swoorleed in f Parameter a
ess ced volve posts table 19E.2 20. The bases for these probabilities are provided belows poststence Coef ficient (of*L/D) (e) The f ailure to close probability (P1) for the steen pilot M5ivs is judged to be somewhat bisher then for f riction f actor (f") . 011 to .018 Reference $ (Ps cometable Mllys in currently operating plants t 25) ($1:e tocause of its rellence on operation of a steen pilot
- pendent) solenold rather then en alr pilot solenold. Steam l pilot velves have not proved very reliable in Line Diameter (0) Vertove Line slie (see operating plante since the rotatively high fable 19t.2 1) teaperature tende to lead to binding or sticking in the solenoid volves. The current operating plant M51V other teststances (K) Reference 5 (Ps fellure to close probability is about 't 3/ demand A 30) with a common mode f ailure probability of about Gate Velve 13 it.4/ demand, for this evoluetion a higher cessen check volve 135 eode felture probability of.18 3 la esstaned for f globe velve 340 failure of both velves in a sing le line to close.
Entrance effects .5 talt ef f ects 1.0 (b) Current operating plants evetuste Mlly leakage -
against a lookege requirement of 11.5 SCFM per volve.
I tapansion f actor (T) . 6 to .9 geference 5 (Ps About 50% of the valves typically fall this local A 22) (dP,K dep.) teek rate test et thle tevel and about 10% are believed to typically eaceed the 640 SCfH level allowed by AgWR proposed technicel specifications.
The teskope probability (P2) used in this enelysis was based on three leakage gro@st 1 .
(-
l e w..-.e..- ..-.-m- e, .-m, i. ,. -.y-,,-o%q ..-- =>-- 7..,,u. ,a..i.;w.g.= ,,pp 9 y., -,.m g
W .
T -
Pt0 gag lLiff (f) AC solenold and motor operated valves are s@ ject to )
GROUP LtAKAGE P(t VALVI PER Likt a com on eode failure (P8) If motive power is movellebte such se Wring a Stetton giockout event.
G1 e 11.$ scfh .$ .5 for station blackout events these volves will have e G2 11.$ TO 640 scfh .4 .2 conditionet fellure probability of 1.0. For this C3 e 640 scfh .1 .01 enetysis a failure probability of 1.0 was conservettvely assmed.
The MllV teekepe probebility (P2) is assigned a vetue of .71 to correspond to the total line (3) Check vetves have been observed to fall in such a way f teekage probabl(Ity. Flow split fractions et to perelt fuit reverse flow, a cordition necessary )
to peralt stepression pool bypass for some lires.
were determined for each of the groups and a welphted everage flow split fraction (welphted Maintenance errors associated with testable check by the line teoksee probabilities) was volves have else been observed. The trestry f ailure determined for use in the evetuatIon. rates for check wetvos eitowing conptata reverse fiow (P9), based on 7000 hours0.081 days <br />1.944 hours <br />0.0116 weeks <br />0.00266 months <br /> of opetettor, per operating (c) The probability of flow possing to the main cycle, is about 8.4t.3 per cycle per volve. A consen cordenser is judged to be governed by the cause f ailure among check vetves aos considered itr failure of the bypese valve to close. This lines contelning rodadent series check vetwee. Only probability (P3) is taken at 4E.3 from f eedwater and the $LC paths conteln more then one Reference 8. Once flow posses to the maln check valve. For these lines a sete factor of .18 condenser, the condenser is assmed to f all was used for the f alture of the secord valve.
(P4) via the relatively low positive pressure rupture disks. (h) When power is ovellebte, some nor1nelly closed velves open & ring en event in response to en injection (d) The main steamline break probebility (PS) was signal, even though the actual injection falls (a based on the Large line break probability requirement for core damage to occur). The
(,Pil). probability that ECCS velves are not closed by en operator (P10) is considered remote during a severe (e) Wormetly open pneumatic (P6) and DC motor accident. Avalueof0.$isjudgedreasonable operated velves (PT) have failed to close, especially considering the potentlet for room Causes include leproper setting of torcpe envirorvnent depredation. For station blackout switches leading to valve stem falture, events, since the valves do not open, these lines do m detected valve operator fattures and not contribute to potentlet bypass risk.
Igroper packing easteriale or tubricants, ct has issued several service information letters (I) Some normatty closed valves may be open et the on volve problems and reconenended actions to beginning of the event. The felture probability (P11) prevent recurrence of the failures. The for these valves ass mes they are open 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> & ring Irdustry f ailure rates for motor operated a 7000 hour0.081 days <br />1.944 hours <br />0.0116 weeks <br />0.00266 months <br /> operating cycle and that the operator valves is about 3.6E 3/ demand and 4.1E 3 for falls to recognite the open path and close the velve.
ele operated vetves. These failure rates are A .5 probablLity is judged reasonable for the not significantly effected by the volve operators failure to act prior to or A ring the core envl rorvnents. A conenon coute f aliure among damese event.
str operated vetves was considered for tirws contelning redndent scries valves. For these (j) Sone vetves may be opened by the operator kring the lines a Bete factor of .18 wee used for the course of the event. Such action may be in f ailure of the second valve. compliance with written proce&res or it may occur ke to confusion in following a proce&re. The probability that volves are inadvertently opened (P12) is considered a violation of ptenned procedures, A value of it 3 is judged reasonable during a core damage event.
k
, -- -g -
n . . - _ .. _ _
(k) Pipe r@ture is entremely rare in stelnless the ACAS has espressed concern regardths the f ailure of steel piping. However, carbon steel piping the RWCU suction in ecsubinetton with f ailure of the has teen otserved to f all trder certeln isolation velves to close. The concern is that there soy conditions. The fregsency of these failures be a flooding situation that could have a high corwequence has teen widely stWied and shown to te in the if it leads to an eventuel loss of sumression poet and range of 1E*7 events / year. The probabilities Ctf inventory or flooding of other (CCS rocme. Such an of line twture as a fmetion of line slie event would not be consistent with this presumed (P13, Pt4, Pil) are taken from reference 5. Indeperdence of the essawd corditionet probabilities.
Four line sevents outside of the contelrvnent are esswed for each beast tirse. The if a break in the RWCU suction line were the postulated Intermediate tire site (3 to 6 inches) LOCA, the contaircent isoletion volves would be eyected probability is esswed to be twice that of the to close, terminating the event. WRC concerne over Motor torge line slie (greater than 6 itches). Operated Velve (Mov) closure capability are being addressed es an Irdsstry activity. In this evetuation it For pipe f ailures in an Individust bypass was assmed that the volves f all to close case to e Stetton line, it was pressed that an undetected break glockout event. Furthermore, should the isolation volves in an urpressurised line could occur et any fell to close, the system arrangement assures that the time. Therefore, the corditional probability core is not uncovered and EPCs rewire depressuritetton of a bypass path was then taken to be the same which both slows the breth flow ord terminates any long as the f ailure rete ckJring a one year period term release from the break. Therefore if the LPG actions (which was estimated to be 7000 hours0.081 days <br />1.944 hours <br />0.0116 weeks <br />0.00266 months <br />). This are taken, no eMitional consequence of the event occur.
e mroach of estinsting pipe fallure probability is judged to be conservative. The system arrangement routes the RWCU tines above the core to evold a potential alshon of the core inventory, the failure probabilities used in the evolustion In the event of an misolated RWCU line break, tawering should be considered condititnal probabilities, given the RPV levet to telow the shutdown cooling suction and
( a core melt. In generet the above probabilitles are not effected by the core melt process itself and can depressurl:Ing the RPV would be suf ficient to teralrete the break flow without causing core damage. This setton therefore be considered trdeperdent of the event should be possible prior to any impact on other ECCS process. egalpment, these actions are included in Section 190.7.
Whether the bypass path is the initiator or occurs (3) Evaluation of Iypass Probability sinultaneously with the event is inconsequential in the evaluation based on the following discussion. Table 19E.2+21 sw marties the results of these The omroach taken in the bypass study is to consider evolustions. for each potentist bypass pathway, it shows the presence of a bypass path as on Independent event the flow spilt fraction based on the line site ord valve f rca the events which caused the core damage in a configuration, the eq2atter to calculate the bypass specific se vence, this approach is acceptable probability, the results of the probability calculations because for large breaks the associated systens are using the data from fable 19E.2 20 and the bypass fraction not in general relled won to prevent core damage and for the line. the table etso inctodes reference to the no consecpence of these f attures have been identified sketch (Figure 19E.2 19) which illustrates the potential which would ef fect the systene preventing core pathways. The evetuation is based on the conservative damage. Therefore whether the break la en initiator essw ption of a station blackout event since it is or consemential does not ef fect the final believed to be the dominant core damage sequence and Gives evaluation. $1miterly, none of the systems associated the highest trypass fractions, with the smaller b mass lines are associated with preventing core damage. Therefore they too are not associated with the cause of the core sett.
(
W* . . . . _ .
I (4) twelustion of tesults v1 Line gresk Outside + The freenney of piping breaks in emett, medlue or large breaks evtside of Section 19t.2.3.3.1 (4) provides e conservettve conteltsent and elch communicate directly with the justification that kypeos paths with a total brpess reactor venel. The tires are proged by type of fraction less then 8.6t*4 do not substantletty Isoletten. The beels for each event initletten increase the offsite risk. As shown in Table 1M.2 21 fregeoney is the time else and the total raster of the totet evaluated bypess probability is about 3.9E $ . Lines considered, the bests for the pipe break for ett potentiel paths not s eressed in the frogsoncy is provided in Appendis 19t.t.3.3.3 (2)(k).
Contaltsent event trees. This totet is well within the goal. N Line Isoletten + The conditionet probability of g
automatic isoletlen velves falling to close given the Potential bypess through the Wetwell Drywell vacuun on containment LOCA. Vetues used and the menner in greskers and the Irweting lines are included in the dich probabilities were cochined are shown en table contalreent event trees. (Section 190.5). 19t.2 21.
gesed on the above discussion,' It een be concluded P g
Oper. Actlen + The conditionet probability that that a p pression pool bypass paths and ta Contelnment operator falls to act to menuelty isolete the LOCAs not addressed by the Contaireer.t event trees & es contalruent LOCA. Such a felture to oct could be not contribute a slentfic et offsite risk and do not he to a lock of instrumentation ovellability or reed further evolustion in the PaA. mechanical failure. For most bypese paths considered, the very conservative asso,tlen was made that no operator action is taken. f or (CCS 19E.2.3.3.4 Evolustion of ts conteltsent LOCA Core discharge lines and worunap lines the operator is Demoge f regJency assumed to act 16 close en open volve, if needed.
The bests for the vetus chosen (P10 in section (1) Introduction 19f.2.3.3 (2)) is based on generet operator sworeness of the potentlei for these paths to be unisolated.
To provide a separate essessment of the I gortance of Although the leek detection system is edequate to bypass paths, a more co#9eehensive onetysis of the etert the operator of a break in the system, frequency of core demose from LOCes outside instrumentation failure is not canaldered to provide conteirment was conducted using event tree and f ault a strong contributlen to the felture probability, tree technig>es.
0 Second Division not Af fected f or sest lines it is Conse'rvettve and simplified event trees of LOCA conservatively assumed that the LOCA af fects the outside contelnment events were developed and included division in which the break occurs. This factor es Figures 19t.2 20s through 19f.2 20c. These trees represents the conditionet probability that the LOCA show that the total cc,re damage fregaency be to LOCAs also effects the regJited makeup for core cooling outside of contalrsent is about 1.3E 8 per year. The from a second electricot divisten. It is assumed end point for these trees is core damese with or that such failure results from environmentet effects without bypest of the contalruent. from flooding or pressurlietion effects.
(2) Assu9tione ' A systemette eyelustion of potentist cold flooding he to on contalrunent breaks was summarised in The following definitions and considerations were Appendia 19t, Probabilistic Flooding Analysis.
applied in development of the trees. flooding in the reactor builditg is noted to disable the system effected and potentistly flood the Reettor guilding corridor, but not disable other make g ogJlpment h e to the water tight doors contained in the design.' The enetysis of an misolated R@ break in s 4section 198.4.5 shows that no cooling systems witi be demoped, f
.- . . . _ ._ .- r -
I Comerteent pressurisetton and envirorsnental COOLANT MActWP FAILust (c )
ef fects of high pressure LOCAs in secondary getAtllti contalryment were considered in the development ggAJL MEDitsi L At t.f l of Fleures 195.2 20s through c. Igulpment in Olv. not Affected 2.2t*T 6.2tay 6.tE*T l the Asw design is errenged with consideration 1 Olv. effected 1.18 6 8.6t*6 8.$t*6 of divfolonet separation. A high energy line 2 Olv. effected 3.6t4 3.T3 3.?t 3
- brook in a diviolon would cause the blowout l penets from the division to telleve the The conditionet probability when one or more f
, initisl presaure spike to the steen tumet. electricot WIvlsione are ef fected wre derived by
$thse went pressurisation of the reae cculd disabling the moet tietting divleton in the LOCA l
eventuelty cause e reteese of the energy into event trees and then calculating the resulting
]
theneatadjacentdivisioninaclockwise conditlenet probability.-
! progression through the reactor buildire.
i - for LOCAs dich occur in the reactor bullding, the As doors from the corridor and penettettone event is assumed to felt the division in Alch the f break occurs. For other LOCAs, such as LOCAs in the
( ore forced open, the environment of the i
edjacent divisions could be ef fected by the turbine building, no divisional 19ect is ass med.
presence of steem. However, th apaellficellen of the equipment to 2t2 degrees F and 1001 Consideration of inventory depletion due to the LOCA
+ h oldity makes the probability of further . Outside contelnment is addressed by (PGs which i system movellability mtlkely. Where a LOCA specify that cootent make@ tources using inventory 4
could occur in en area edjacent to a seperate sources outside of contalrvnent be used as the division, e value of it*3 was assumed for preferred source. In ths ABWR design emelt breaks i 0 , based on conservettve engineering can be accomodated by any of the high pressure
) jhoment, to represent the remote possibility cootent makew systems (nCIC, WPCF 5 and NPCP C)
J for failure of these edjacent systems. which are in separate divisions and which drew water j from the condensate storego. Since condeneste is for line breaks in the turbine building the ef fectively en unlimited supply and makeup capability l
effect of the break would not lopect the exists, no additionet concern is necessary for thi j divisionet power distribution eM, for these small break LOCAs outside of contalrvnent.
i segw.nces, the o value was judged to be negligible. Medluu and terse breaks outside of contaltunent con be accomodated by any of the threr divisions in the Although line routing are not specified, the short term following a brook without concern for
' enelysis assumes that breaks inside reactor Inventory loss in the ePV. Att perwtrations, encept butiding ogJipment rooms ef fect the division the RPV/RWCU bottom head drain (e unique situotlen i "
! In which the breaks occur; LOCAs outside of addressed separately in Section 19.9.1 by en event the secondery contaltunent are not asstaned to - specific proce & re), are above the top of active fuel I: felt a division of o wlpment. so that core m covery due to inventory depletion is
{ not a concern. In the longer term, the break will 0- Coolant makeg This factor represents the depressurlie the ePV which effectively re &ces the conditionet probability of core cooting loss of inventory from the break to a level welt l'
failure by att sources of cooling with within the makew cepecity of other. evellebte systems a consideration to those effected by the which makeup from sources outside of.contaltunent, es.contalrunent LOCA. the values used are such as fireweter. Due to the redJction in lots rete derived from en evetustion of the PAA fault through the breek, significent time is evellable for trees and ero suunerlsed belows operators to componeste for the usage of water and -
flooding in the ef fected eres. Furthermore, 5 operators are assumed to follow plant proce&res in
! lootating the break or towering RPV tevel to a level i below the effected penetretton, if necessary.
- Adequate Instru.nentation and tone term make, from
{ fireweter and condensett sources would normally be
, evellebte.
T
,,w-
-+r e- r - - " - - - * + e ~ - , - . > - -
t 4
' (3) Conclusion f or each of the event trees shown in fleures 19t.210e throveh c the totet non bypass and bypass core demose frecpencies are shown and are susenetted belows Core Demoge f requency (events /yr)
Epn_;,troese. syness totet small LOCAs 1.2t 8 1.it 9 1.3t*8 Intersediate LOCAs 2.3t 10 1.2t*10 3.$t 10 Large LOCAs 2.0faiO 4.hta13 2.0f.10
' 1.2t*9 1.3t*8 TOTAL 1.2t*8 ta conteltsment LOCA events without bypest represent e emett fraction of the total core densee f receeency (1.6t*D are therefore justified as not belns further evaluated in the PaA.
Although the consequence from bypens events is greater then for non bypass events, the totet f re<pency of bypots events concurrent with core demote is estremely emell. The core demote f re<pency of es contaltunent LOCAs with bypass le toss then 1% of the total evetuated
,j core danese fre<pency. Loree LOCAs con be
% eactuned from further conalderation on the bests of low prouebittty. tactusion of Medium and Snell bypost sequences is based on the additionet consideration of the reductions in consequences of the es.contelrunent LOCAs eJe to the flow spilts provided by restrictlons da to Line siting. This is discussed in Section 19t.2.3.3.3.
In addition, since sientftcent mergin exists between the current PRA results and the safety poets, it con be concluded that the bypass events do not significantly contribute to the offsite exposure risk.
19t.2.3.3.5 Suspression Poot typass aesulting from -
Enternet twents the effect of enternet events on the S g ression Poot typeos evetuation is discussed in Appendis 191 to determine if a sientficaat potentlet for bypassing the seression poot results from component failures induced by a selsmic event. Only selsmic events were considered to provide a significant chattense to the creation of hype:s paths beyond that streedy f considered in the PRA.
1
o.=mi D. cme compaar
@Q PROPRIETARY ISTORMATION om g,
m.
Standard Plant than 1 E 7 per > car that the maa steun isolation 3 y
g T8"g(4) Evaluation of Results ,
valves fail opto as a result of an earthquake.
Based on this low frequency, no further s #p c- Ocuon nr.4.J.3.1 (4) provides a conservative asseument wu judged neceuary, gr Tjustification that bypass paths with a total bypass pg fraction less than 1.2E 4 do not substantiaDy increase the offsite rssk. As is shown in Table 19E.2 21, the (2) Main Steam Drain Line Break. The dr line bility is about 7.9E 5 for all events includes two motor operated isolatio alves, bypass p except werwcu U vacuum breakers. This meets which fail open on lou of emergency wet. The the established Therefore, o,dy the case of pipe break frequency is less than tVirequency of stuck open wetwell ell vacuum breakers need piping support failure, about k$ E.7 per year.
further analysis. This alysis is provided in However, since there k a wiflimited amount of subsection 19E.2.4.6. piping involved, it it . i/
that this particularuldpip break pdandto ec invery unlikely result About 80% of the bypass risk rives from suppression pool b Therefore, this event is sources which originate in the drywell a me not considered er, bypass paths it the containment is vented or he containment fails in the wetwell airspace. Two (3) Fe edwater t.e Break. Each feedwater line these lines, the drywell purge exhaust, and the includes t e check valves in series, on of which inerting system crosstic represent inadvertent spric osed, a different design than the other operator actions which may be teduced in signifi- e fall open frequencyis about L5 E 7 per cance by operator training. yes a result of an carthquake. With a d' crent v 'e in series, the failure of all three Based on the above discussion,it can conclude alves is judge law to consider further, that bypass paths contribute less than 10% of the risk. These results justify the relatively low 4) Containment Structu Failure. With a seismic importance of tlic 'Ex containment LOCA* paths capacity of 4.3 g, contain t structural failure and indicate that further specific study of othe as a result of an earthquake a frequency of bypan lines in the PRA is needed only for e about 1 E 8 per year. Even such a failure does
( werwell drywell vacuum breskers, not necessarily lead to pool bypass. Thus, this sequence was judged too low to consider further.
19E.2.3.3.4 Suppression Pool Bypass Resu ng fioer y y J External Event Analysis ce mecia,nism
% Suppression Pool Drainage, wes4desened which could c partial drainage The results of the external event analysis were l of the suppression pool ailure of RHR head reviewed to determine if a signific t potential for exchanger anchor bolts /A:pa L 2 : ; N bypassing the suppression pool r suits from these could allow sufficient heat exchanger motion that event initiators. the connecting RHR piping leading to the suppression poolis broken. The normally open Five pm ntial pool by ss mechanisms were identified: main steam ' olation valve failure, I, suction vahac could be closed by the control room unisolated maio ma i in line break, unisolated \ cause such a failure, there is some chance that no feedwater line bM. #4nment structural failure ec power would be available te clo,e the valve E,,,3, and suppression pai ?ainap As noted below, the Should these conditions exist, p7ath is opened first four were jud d to be of sufficiently low between the suppression pool and the RHR probability as to a substac!ially affect the results. pump room.
The last (suppre ica pool drainage) should not result la pool b ass, but,it could have other effects The suppression pool (unpressurized at the start 4 on the weident quence analpis. of the cent) will drain to the RHR pump rooms, flooding them and the vertically rising pipe chase (1) Main Ste da Isolat;on Valve Failure. As noted in corridors to an equilibrium level at about half the Table 11 4 2, the ,eismic capacity of these valves normal poollevel. As the pool pressure increases u a result of the severe accident, pool is aboup.5 g. witn a combined uncenainty of 0.6.
When combined with the seismic hazard curve level would further decrease; and the level in the
( (Figure 19.4-2), this results in a frequency of less pipe chase corridors would increase untilleakage (F D 19u.9 w,%, {.l y
V
- ~ =
. . , aa- -
-- .s omenalmenew can, y gg PROPRIETARY INFORMAT12N Standard Plant om. m ,'{^s from the corridors beglas. This elevation is wall resulting from a postulated break of the RHR -
j(
- about equal to the normal suppression poollewl. pump discharge pipe were estimated using applicable .
1
!s If allowed to costiave, virtually complete pool test data. This wall ruas parallel wkh the discharge -l drainage could occur, since the floor area of the pipe at a distanes of approximately 4 ft. The length !
i pool is about equal to the Door area of b three of this well is 43 ft, the belght is 30 ft. The RHR J j pump rooms. Further discussion of this event is pump discharge piping is assumed to rus 2 h above
! pressated in 19E.2.3.4 and 19E.2.4.5. the,equipeest room, with the rupture located canctly j opposite to the middle of the wall (worst case).
19E.2J.4 E#ect of RHR Heat Enchanger Failure la
! a seismic Ewat Tk dynamic loads result from the discharge of
' i the containment atmospbete through the broken
- L. the water poolla the RHR equipment N
- N- - -- - - - ic pipe j onom>weveverwhwa4 failure of the RHR beat root. k v .a conservedwely assumed that the actire '
! enchanger mous% *Mi *:?"' conservatively volumem the equipment room was Gooded with the -
{ be postulated to shear the pipe between the RNR pump suppression poolwater.
j discharge and the RHR heat eschanger About 30 .
j minutes is available for the operator to close the The gas discharged from the brunes pipe will be i RHR suction valve to the suppression pool. 3ier laitially alc ost pure alttoges,later a mixture of j ... . . 43 - _ -.2_7 _ n __ _ - this nitreges and usam with docusing mitt ogen comem, -
i M W.-- m.w if so power is avai?able - and Smally, aher all the nitrogen is purged out of the
! or if the operator failld to close the suction va've(s), containment, pure steam. The mean flow rates L the suppression pool will drain to the RHR through the broken pipe will be a function of
. equipment rooms. Tirr 4::::: r:i:se- pressure la the containment, sbich in turn will t l "- " " ' "a i^* ? ' if P : 2. initiaDy depend on the accident scenario. la the long j term, however, the mass flow rate will be driven by >
t This subsection describes the analysis of these the steam generated from the decay heat, it ist sequences which concludes that structural integrity of assumed that there will be no pressurization of any'*
l{
l la~effect, the suppression pool scrubblag is -
transferred from the suppresslos pool to the RHR ' This situation is similar to the discharge of the l
! equipment rooms, drywell atmosphere through the drywell vents into - ,
L the suppression pool during a LOCA. The test l- 19E.2J 4.1 RHR Equipment Room Flooding - resuks frona LOCA tests conducted by GE for a wide range of break slaes demonstrate that the highest -
! The RHR equipment room drains to a sump wetwell pressure loads due to this 4harge arc room below. This sump room also receives fralas esperiescad late in the svest during the . hugging
- l regime charaetarised by_ low mass flura5 F from the HpCF equipment room (in two cases) and 3
from tbc RCIC room (in one case). The design of: -(<10 lba/s.ft3 ) sad high staam/ sir rstics -
these drelas is -- m '- " ' i assumed (<15 air), At higher mass Dunes the condensation j: gb h ** shot a device to prevent one sump from Alling and _- encillation regime) and higher air contents, the loads
- backflowing up to the NPCF or RCIC rooms,in . were *amiany so,or.
M. The device *,s assumed to funcdon wkhout _
AC power. This prevents the loss of HPCF or RCIC To estimate the chugging loads on the RHR l: room waB, the Mark Ill PSTF test data were used.
resuking from RHR equipment room floodag. i 1
The Mark 111 data were chosen because of the -
. The analysis of the resulting loads la the RHR horizontal orientation of the vents and because no -l equipment and the basis for concluding that the pressurization of the airspecs above suppression pool
- room will remala intact is described in the following which approximates the situation is the ABWR -!
R o
paragrsphs.- RHR room. The highest chugging loads on the well
! seen during the Mark Ill experimcats were 100 pst 19E.2J.4.2 Dynaale lands laduced by Cheslag _ These pressures were observed on the drywc!! well' f adjacent to the vent exit into the pool. Because of The dynamic loads on the RHR equipecat room -the close proximity of the pressure sensor to the
- f o
sl 'I'E >35 m e te I
4
,-. _ ,-- - - ~ - -. . _ _- -_. . . , _ _- . - -_ - . _ . - - - -
co. s.nne conp.n ABWR rnorR2ETARY ibToRMATioN om asAs As
. Standard Plant source of the pressure disturbance (tl.e collapsing which leads to the heat exchanger mounting failure
- , steam bubble) this preuure can be considered to be causing the postulated room flooding. No structural x
the actual bubble preuure. damage is predicted, although some concrete cracking is inevitable. After the earthquake, the wall The period between the pressure spikes was would be structurally sound to withstand the loads typicaDy 1 to 5 seconds or more. FoDowing the pcak imposed by Gooding as described below, pressure spike, a series oflower amplitude preuure osciuntions were observed, with frequencies that The seismic. induced flood imposes loadings to were in th: tange of the natural frequencies of the the room in the form of hydrostatic and vents and water pool. The maximum amplitude of hydrodynamic pressures. It is resumed that no these oscillations was typically leu than 10% of the dsmaging aftershocks would occur during flood.
maximum preuure spike. From the above discussion the most significant hydrodynamic load is caused by chugging. The Given the RHR equipment room geometry, and preuure transient on the wallis idealized by a sharp using a conservative pressure attenuation model preuure spike with a maximum amplitude of about 4 (supported by the Mark III crperimental data), it psig preceded by a half cycle sinusoidal and followed
, was calculated that the pcsk, spatially averaged, by a decay sinusoidal with much smaller amplitudes.
dpamic wall pressure will be below 4 psi,if the maximum bubble pressure of 100 psiis auumed. To find the dynamic effect on the wall response, With higher flowrotes and higher non condensable the wall was modeled as an equivalent single degree
! contents in the discharge, the loads are crpected to of freedom system subjected to the pressure be lower. Therefore, this conclusion should also transient described above. The results show that the cover a range of severe accidents during which maximum dynamic amplification factor is 0.26. The non condensable gases (e.g., H2 , CO2 ) are equivalent static chugging pressure is thus about 1 generated from metal water reaction and/or psig.
corium. concrete interaction.
Under the combined hydrostatic pressures of a 19E.2.3AJ RHR Equipment Room Structural fully flooded condition and equivalent static chugging lategrity pressure uniformly distributed over the entire wall, the stress analpis was performed by treating the wall
, The structuralintegrity of the RHR equipment as a flat plate with fixed supports along the edges.
toom structure was evaluated for the loads resulting The resulting maximum moment is found to bc l from the seismic induced flood. The RHR room is about $6% of the ultimate moment capacity in located at the reactor building basemat level la cach accordanen with the ultimate strength design method
, of the three divisions. The most critical wallin a for reinforced concrete. The maximum shear streu typical room was chosen for this investigation. This - is within the AC1449 code allowable. The leaktight
- wall runs along the 900 2700direction of the reactor RHR room access door was also evaluated and is building and connects to the exterior wall and the found to be structuraUy sound against flood loadings.
, containment at both sides. The wallis approximately
- 13 m (43.64 ft) wide,6.5 m (21.32 ft) tall, and 0.5 m la summary, the structural integrity of the RHR (1.64 ft) thick. room can be maintained for the seismic. induced flood. This ensures that fission products can bc
, The wall was examined for its ability to withstand scrubbed by the entrapped water.
a 2 g carthquake which is more severe than that 1 (
, Amendswas 3 .19EaM i
centil Dutrw company MM PROPRIETARY lhTORMAT10N nA61ooAs Standard Plant a= m %*
i s
TABLE 19E.21 POTENTIAL SUPPRESSION POOL BYPASS LINES PATHWAY BASIS FOR NUMBER SIZE (mm) ISOLATION EXCLUSION DESCRIPTION OF LINES FROM IQ (1 in. - 25.4 mm) VALVES MEE W neN2 Main Steam 4 RPV ST 700 (SP, SP) -
Main Steam Line Drain 1 RPV ST 200 MO, MO 3 Feedwater 2 RPV ST $50 CK,CK -
Reactor Inst. Lines 30 RPV RB 6 CK -
103 RPV RB <1 CK, MA 1 CRD lasert/ Withdraw HPCF Discharge 2 RPV RB 200 CK,MO -
HPCF Warmup 2 RPV RB 25 MO, MO -
HPCF Suction 2 SP RB 400 MO 2 Supp Poolinstrumentation 4 SP RB 6 None 2 SLC Injection 1 RPV RB 40 CK, CK -
RCIC Steam Supply 1 RPV RB 150 (MO, MO) -
RCIC Discharge 1 RPV RB 150 CK, MO 5 RCIC Min, Flow 1 SP RB 150 MO 2 RCIC Suction 1 SP RB 200 MO 2
( RCIC Turbine Exhaust 1 SP SP RB RB 350 40 MO MO, MO 2
2 RCIC Turb. Exh Vac Bkr 1 RCIC Vac Pump Discharge 1 SP RB 50 MO 2 RHR LPFL Discharge 2 RPV RB 250 CK, MO -
RHR Warmup Lines 2 RPV RB 25 MO,MO -
RHR Wetwell Spray 2 WW RB 100 MO 2,4 RHR DrywellSpray 2 DW RB 260 MO, MO 4 RHR SDC Suction 3 RPV RB 350 MO, MO 3 RHR Supp PoolSuction 3 SP RB 450 MO 2 SP RB 250 MO 2,3 RHR Supp. Pool Return 3 I !
Amendment 8
4 cour=1 Dectne compaa ABWR raorRiETARv isTonx4Tios cu m 234.iooxs u.
Standard Plant ,
I a
TABLE 19E 21 (Continued)
POTENTIAL SUPPRESSION POOL BYPASS LINES PATHWAY BASIS FOR NUMBER SIZE (mm) .ISOI.ATION EXC1.USION DESCRIPTION OF LINES EQM IQ f1 u' t = 15 4 mm) VALVES fSEE *EEKT) pekJ RWCU Suction 1 RPV RB 200 (M0,M0) -
RWCU Return 1 RPV RB 200 MO, MO 5 RWCU Head Spray Line 1 RPV RB 150 . CK, MO 3 RWCU lastrument 1.ines 4 RPV RB 6 CK -
Post Accident Sampling 4 RPV RB 25 (MO, MO) -
RIP Motor Purge 10 RPV RB <1 CK, CK 1 RIP Cxting Water 4 RPV RB 50 MO, MO. -
1.DS instruments - 9 RPV RB 6 CK -
SPCU Suction 1 SP RB 200 MO, CK -. 2 SPCU Return 1 SP RB 250 MO, MO 2 Coot. Atmosphere Monitor 6 DW RB 25 MA .
8 +
LDS Samples 2 DW RB 30 . (SO,50) .-
Drywell Sump Draias 2 DW RB 100 MO, MO #T HVCW/RBCW Supply 4 DW RB 100 CK, MO 1,8 4 DW RB 100 MO, MO 1,8
{ HVCW/DWCW Return DW Exhaust /SGTS 2 DW RB 250 AO, AO - C9 Wetwell Vent to SGTS 1 WW- RB- 250 AO,AO 2 DW Inerting/ Purge 2 DW RB 200 AO 8 WW Inerting/rurge 2 WW RB 200. AO 2,8 lastrument Air 2 'DW RB- 50 CK, MO 1 SRV Pneumatic Supply 3 DW RB $0 CK, CK . 1 Flamability Control-- 1 DW RB 100 (MO, MO) 3 ADS /SRV Discharge 8 'RPV WW XO- RV. -
ACS Crosstie -2 DW WW. 200 AO AO 8 WW/DW Vacuum Breaker 8. DW WW $00 CKg A Miscellaneous 1.4akage 1 DW RB -- NONE Access Tunasis 2 -DW RB - NONE 6
'l I ' -
Amendment S l
i Table 19t.2*1 (Conttrued)
POTENTI AL SUPPRES$10N POOL sfPASS L!ht Woffs LICfWD AND Ate 0NYuS PATHWAY tine is used, the fission product source term would source (from) Termination (To) be expected to have been streedy significantly kPV teactor Pressure Vessel W Wetwett re&ced be to decoy and other removat mechentsas.
DW Drywell kg Reactor stdg SP $@pression Pool W Wetwelt 4. Some llnes tAlch originate in the primary contaltwent ST Steam Tunnel are designet for operating Pressures higher then Isolation Velve Types would be expy.ted in the contalrunent durIng a severe occident. These Lines (ulth design pressurew greater SF Steam Pilot Operated than about 100 psis) were excluded since the Ao Air Operated probability of a break mder less than normet Mo Motor operated operating pressures and coincident with the severe RV Relief Vetve accident is extremely emell.
CK Check Valve MA Manuelty Actuated 5. Some lines return to the fee & ster line. These 50 Solenoid operated pathways (such as LPCF toop A and SWCU) are excluftd
() Cominon Mode fatture Potentist (See Section since they are bounded by the evaluation of 19t2.3.3.3 (2)) feedwater.
Bates fo* Exclusion 6. Acceptable Long term Leekage from the drywell to the reactor building following a design basis accident is
- 1. Closed systems such as closed cooling water specified at .4% of drywell volume per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
systems which do not directly connect to the During severe accident conditions this leakage could
( RPV or contelrunent atmosphere require two be somewhat greater due to higher than design basis contalrnent pressure. However, the contribution of faltures to become a bypass pathways a leek t,r break within the cooled ccaponent and a line this Leakage to overall risk is ignored because this break outside of contalrunent. Very low flow Leakage is through numerous tortuous passages of is expected out of the break or leak at the smelt diameter which provide emple opportunity for cooled co'iponent is Likely se to the high plateout and plugging effects (see subsection degree of restriction. These pathways are not 19E2.1.3.4). A discussion of the drywell access considered further on the basis of this very tumets is included in section 19F.
Low flow rate. Stellarly, extreme restrictions in CRD seats provides the basis 7. Drywelt susp Drains - The drywett floor and equipnent for excluding those lines. drain susps are assuned to be normatty open and isolated by motor operated valves. The discharge is
- 2. Pathways which originate in the primary assumed to pass to e drain header in the reactor contalraent wetwell altspace or the buttding geckflow into the reactor building is s wpression pool are excluded because fission assumed to be prevented by check volves, product aerosols would first be trapped in the suppression pool and would thus not be 8. NVAC Cooling Water, Reactor guilding Cooling Water, avaltable for release through the bypeas path. Contalement Atmospheric Control - Line sises shown in table 19E.2-1 are assumed for these systems.
- 3. Scae lines are closed Aring normal plant 9. Drywell purge lines are normatty closed and felt operation and would not be expected to be closed. The potential for inadvertent opening is opened in the short term following a plant considered remote and is addressed by Emergency accide t. These lines are excluded on the Procedure guidelines.
basis of low frequency of use. Furthermore,
( should a bypass pathway develop later when the
.. ~ _ .. . . - . - . ... - ..~ _ - _
Genetil sonne company ABM rnornitTrav isTonx4Tios nx.ioo ,
Standard Plant am ao 4
(
Table 19E.2.18 Potential Bypass Pathway Matrix FROM Wetwtu Suppresion
.Ia REY Drnell AinDagg Pool Drywen No NA NA NA
. Wetwe!! . .
Airspace Yes Yes NA NA I Reactor Building Yes Yes Yes Yes Turbine Building Yes Yes Yes Yes
'f .
4 The above matrix shows the paths that potentiaDy bypass the suppression pool 4
4
' f athways which originate in the drywell and potentiaDy release into the wetwell are potential bypass paths if the containment is vented or the wetwcu fails during the severe accident.
1 4
l .
Amendment 8
~ W '~
- . .l.
~ ~ ~
Geners! Doctre Company ABM 2
raornistravisTonurrios 23x.iOO s Standard Plant cui m no *
- ('
Table 19E.219 Flow Split Fractions i
1 ane has Flow 5plit Fractm EUD in RFV Source Drv=ttl kmrcs 6 0.25 IJFAS 12 0J 9.4E 05 b'Y l 1s i s.na .i t, af . 5
- 50 2 uEas /. t, cf -%
100 4 1AE42 ha b 150 6 4Aus /. f i- '
,o, , ,.,u,
- t. f l-/ '
1 250 10 1.4E 01
&' g, t d*!
l s. a y, g d-!
! 300 12 2.0E41 8
1 . 330 14 2.6E41 6 g 1s 'nygg
$* $ b'l
- 450 18 3.8E 01 1 ' 7 I"/
(.
500 -20 4.3E 01 1 7, I d'#-
100 28 LIMI 1 /e /I'/
io00 0 us41 Meat 9,8 #-#
l 1
i E
I I
Arnenament 8 i
,._. -________x____ _ _
9 ocursi Deane camp. y ABM PaoPaitTrav tNronurTios cw m 23x.iooss p.,, 3 Standard Plant I
Table 19E.2 20 j
~
Failure Probabilities ,-
os
- l. Cf Symbol Descrietion ProbMvent Egh /_
P1 Steam pilot opersted valve (MSIV) 1.0E 3 a ,y MSTV leakage probability 7.1E 1 b FY P2 P3 Turbine Bypass isolation 4.0E 3 c y P4 Main condenser failure 1.0 e #
8' P5 MSI. break outside containment 5 d '7 i
P6 Air operated valve (NO) 4.1E 3 e iy P7 @ Motor operated valve (NO) 3.6E 3 e y P8 gt, Motor Operated valve (NO SBO) 1.0 f gY P9 Check Valve 8.4E 3 g iy 5.0E 1 h g vr f ,
P10 Motor operated valves (NC) 2.8E-4 i g
- Pil Motor operated valves (NC) l P12 Inadvertent opening 1.0E 3 j '
N
- P13 Smallline break 2.4E 4 k
{ 7' ,
i 1
P14 Medium line break 1.6E 5 k y }
I.
P15 1.arge line break 8.0E-6 k y ,
b 4,'g o,J p )e
(
19E2 66 f Amendment 8
T
~ ~ ~
M
~
T :. L-- .^ . . .. LL .
General Deeme Company MM PROPRIETARY ISTORMATION 23A6tooAs Standard Plant cau m ua i
Table 19E.2 21
. Summary of Bypass Probabilities unatrna antry Bypass Flow Split Probability Bypass Bypass Fqure i Pathway Fractina Enuntina Probability Fraction 19E.219 i
Main Steam 6,7E 1 4*Pl*(P3*P4 + P5) 1.6E5 1.1E 5 A gg i
sd
- Main Steam Leakage 2.2E 5 4*P2*(P3'P4 + P5) 1.1E 2 WE7 A Feedwater 5.2E 1 2*P9W'P15 B Reactor last.1.ines 3.1E 5 30*P13'P9 6.0E 5 1.9E 9 D HPCF Discharge 1.1E 1 2'P9'P10*P14 1.3E 7 1.5E4 C g La .
HPCF Warmup 1.0E 3 2'P10*P11'P13 6.7E4 M E 11 C ,
8
- 4. f 4 . 4 *
}f SLC Injection 3.0E 3 1*P9'Ap*P13 1m 1 B RCIC Steam Supply 6.9E 2 1'P8'P14 1.6E 5 1.1E4 E
! R9tR Discharge 1.7E 1 2*P9'P10*P15 6.7E4 1.1E4 C a
' &M&. (,1_
HPer Warmup 1.ine 1.0E 3 2*P10'P11'P13 6.7E4 M E 11 C ,
nA RWCU Suction 1.2E 1 1*P8'P14 1.6E5 ME4 E 31 ME4 2.5E 10 D i RWCU Inst l_ines 3.1E 5 4*P13*P9 Post Acc Sampling 14E 3 4*P8'P13 94E 4 9.9E 7 J F
1.DS instruments 3.1E 5 9'P13*P9 1.8E.5 .j7E 10 D I*II*Y ' "
pv disch* (.9d** ps f' W Total 5 i
( .
1 These lines may be excluded for station blackout event:
s.
Amendmen,' 19E.247
- - - - . _ ....m - . . . . _ , . . . .
ocami Deeme compeny ABM rnoPaitTAxv isFonarTios cu m
- 3xsiooxs w4 Standard Plant
\
Table 19E.2 21 Summary of Bypass Probabilities (Continued)
IJnes froen the Drwell Bypus Flow Split Probability Bypus Bypus Figure Io <
Pathway Fraction Eauntion Probability Fraction d' s.s er. 9 Coat Atmos Monitor SOE-fI.Tt f 6'P9'P13 1.2E$ HFr9 D p.Es 'r 1JEr4 /.W*8 2*P8'P13 43E 4 6mE8 E 1.DS Samples
- o. s i.f Drywell Sump Drain 2JE.3 8.*(+ t 2'P8'P13 4.8E 4 14Er4 J
-- -- -- . _ _ . _ _ _ _ _ _ _ __.gy 2.0E 3 34E=$ ty
/ DW Page/ Exhaust _M /.44 8 2'P12 i
" org.3 3.s d.y 2.4E.3 /,vs./ 2'P6*944 7 3 M 40 I
& DW Inerting/ Purge g.< t L 4.,
ACS Crosstie BAE.3 /./ g.p 2'PG e fss. 2Mr3 H '
- o. d s WW DW Vac Bkr 4JE4f.t( / 8'P9 6.7E 2 G
/
f SP* Nduce 6 9F ? 8'P14 13E-4 005 ! r _
Total excluding vacuum breaker, 6 M r+ /. r*(- f p' * .a d'* ** bey t,.es Grand Total excluding vacuum breakey 74E 5 's . 9 d-#
p m ~ ., ~ , ~ ..
s,- m _y M 00 h$ YhO hhhf
~
f$ m:a Amendmem 8
^ .. .._-._- - -_ _ _ . _ .
Cenerol EJecine Compsry PROPRIETARY INTORMATION A.B M ca iii 234.i.oAs Standard Plant uA f A. MAIN STEAM
\
NO LE AK Act (P21 No STRE AML NE TUm8lNE SVP A$$ Om P AiLumE TO 150L ATE (*11 SmtAK(PSI ISOL ATiON (P3s OK OK
/
tYPA15 ' SYPAS x mPv X If 0 D. 44413 74 Figure 19E.2-19A SUPPRESSION POOL BYPASS PATHS AND CONFIGURATIONS ; ( B. FEEDWATER OR SLC No cwECEVALVE NO LINEBRE AK P AILumE (P91 (P t 3, P131 OK l OK i
- sv> Ass l
l l C+2 I
' TumsiNE suiLoiNG thi N mPv '/r . 'fl /l mEAcTom sutLoiNGTstei 1 as4tsas I '
Figure 19E.2-198 SUPPRESSION POOL BYPASS PATHS AND CONFIGURATIONS 19E 210' Arnenenent i
< osami meme camp.ny ,
PROPIUETARY thTORMTION MN cans m 334nooas - i Standard Plant m. ! C. ECCS LINES NocHecavALvt P AILumt IP91 CPE m Aton No ! ,f 04 CLOSE5 VALYL LIN t te t Ax arton ) s YP Ass (Pi t t iPis.Pta Pisi i QE i . I i ox l i on i i SYPA55 N I i i i i mPv 7 ", ', X ," meActom sv LoiNG as41ste l l Figure 19E.2-19C SUPPRESSION POOL BYPASS PATHS AND CONFIGURATIONS 4 .
. D. INSTRUMENT LINES NO check l' NO LINE Bat AK FAILune (P13.P14.P1SI (P96 OK l.
4 ox l i SYP AS$ - l. l I I mPv l h: y C 46413 77 f
. Figure 19E.2-19D SUPPRESSION POOL BYPASS PATHS AND CONFIGURATIONS 4
i 19E.2104 Amendmans I 4 + l____. _ _ _ _ _ _ _ _ _ _ _ - ~__
"y .
,' ceam! tectric camp..y PROPRIETARY 1hTORMAT10N 0 "* HI 22AstooAs Standard Plant ,,
E. STATION SLACKOUT AFFECTED LINES 180 iL,A.T,10N L,3. s. I.INE,ent,A,K,, OK 1 OK to s sveAss i mix aev l g5
-<x: 'x es41s 7s Figure 19E.2-19E SUPPRESSION POOL SYPASS PATHS AND CONFIGURATIONS F. CONTAINMENT ATMOSPHERIC MONITOR ,
NO CHECKVALVE wo F AILURE MANUAL VALVE LINE SME AK iP9' CLosuME te isi OK OK OK BYPASS OR YWE LL - gf b B8413 79 I Figure 19E.2-19F SUPPRESSION POOL SYPASS PATHS AND CONFIGURATIONS
'19E.2109 a.m g ,
i . >. .e ; . g. , . . ..- prim cown
.PR ME 4 * *'TSi? M, Y- thTOR.WTION w nasiocas Standard Plant u, i G. ORYWELL.WETWELL VAC. SKR$
'f Cw80K VALy[ ( e
' g;v w . pg ,
P AILUllt [ IP96 j OK 4
.e f
1 4 1 i $ $ i
- i BYPA$$
i I
- I I A OM N ILL- y i WETWELL
! i i l i l CONTAINMENT VENT a ASSUM E D 844 340 2 Figure 19E.2-19G SUPPRES$10N POOL BYPASS PATHS AND CONFIGURATIONS 1 f- -- H. hRhwE LL VENTS OR)TMOSPHERIC CONTROL SYSTEM CROS$ TIE < l NOINADVERTENT #* opgNiNo ip123 j444 /e,(e'T &g) OK i i 1
,- -- c , L .
I 4 - N" f ,' ! i' p i - evPA35 g ' ,_ __w. g vtNT STACK 'i DMYWELL X , X OR_ _ WETWELL i so4 34: I Figure 19E.2-19H SUPPRESSION POOL SYPASS PATHS AND CONFIGURATIONS l
%3 . 191.31 to 4
o mi w c.e,..y PROPIUETARY DGORMATION
. ABM Standard Plant
- o. m 23A6100A$ .
u A. I, ORYWELL INERTING (
\ NO Aim vALvt No UNE P AILum t getAg i (Psi- (Pisi-Og l
s 4 i 04 i 1 i SvPAss I DmvWELL ' // ^ M
- WETWELL 0041342 J -
l Fipre 19E.2-198 SUPPRES$lON POOL BYPASS PATHS AND CONFIGURATIONS .: I s i( . I J. SAMPLE LINES OR SUMPS ! NO CHECK VALVE l NO $7ATiON NO P AlLum E SLAct0VT LINE DatAK - (SUMP 5 0NLYi i (PS) 19131 (Pti s OK OK i f SVPASS i i' SvPASS APV [ STAT ON AGACTOR DavWELL [ s. ',0 i N G . '
- 9041343 l
[ . ' Fipre 19E.2-19J - SUPPRES$10N POOL BYPASS PATHS AND CONFIGURATIONS , l_
- 19E.2 lit A.isemen B I
4 , , , , - ,. . . . - - . .- . . , . . . . , ,
,~.. . - - - . . . - . . . . - . . . . _ . _ . . _
- _ . - ~ _ _ _ _ _ _ . . - . _ , . - . - . . . _ - . _ . , , . _ , _ _ _
- . Goaerei saarw coopery j
gg PROPRIETARY INFORMATION b III 23A4100A5
- l. -* Standard Plant Rav A 7 .
i n N , s I i 3 l i K.SRVOlSCHARGE h j f AD85mv NO SRV DL smtAE i OPEN (P141 l OE 't i 2. OE { i 1.0 i J gypAgg I I 2 2 // f p rr I mev I i 1 i CONTAINMENT VENT - l Assuuso i so4:244 i Figure 19E.2-19K SUPPRES$10N POOL BYPASS PATHS AND CONFIGURATIONS g 5
.- ~- -
4-f. mg , itE,3112
y: . .. ..... ..... . . . . .
'~
FIGURE 19E.2 20a SMALL LOCAs OUTSIDE CONTAINMENT ( Line-. Break Line Oper. Second Div. Coolant Outside Isolation Action Not Affected Makeuo-(V3 ) (X3 ) (P3 ) (Q3 ) (Q,) Reactor Instrument Lines (30) RWCU Instrument Lines (4) LDS Instruments (9) OK' l.lE-6 1.0E-2 - -1.lE-8 NON-BYPASS 8.4E-3 0 NON-BYPASS 1.0 OK 1.lE-6 9.2E-Il BYPASS HPFL Warmup (2) LPFL Warmup (2) OK 9.6E-4 1.lE-6 1.4E-4 1.lE-09 NON-BYPASS
-g .5 OK 1 1.1E-6 7.4E-14 BYPASS Post Accident Samolina (4) 9.6E-4 0 NON-BYPASS-0 1.0 1.0 OK r M 1 BYPASS-SLC In.iection L.1E-9 OK 1.1E-6 2.4E-4 2.6E-10 NON-BYPASS 1.SE-3 0 1.0 OK .
1.1E-6 4.0E-13 BYPASS TOTALS NON-BYPASS 1.2E-8 BYPASS 1.1E-9 i
m ._ . . _m . m . . ..... ..m . b 4 FIGURE 19E.2-20b MEDIUM LOCAs OUTSIDE CONTAINMENT ( Line Break Line Oper.- Second Div. Coolant Outside Isolation Action Not Affected Makeuo' (V3 ) (X3 ) (P3 ) (Q3 ) (Q,) HPCF Discharoe (2) OK 8.6E-6 3.2E-5 2.3E-10 NON BYPASS 0 4.2E-3 OK 8.6E-6
.5 5.8E-13 BYPASS lE-3 OK 3.7E-3' 2.4E-13 BYPASS RCIC Steam Sucoly (1)
RWCU Suction (1) 3.2E-5 0 OK 0 OK g 1.0 OK' q . 8.6E-6 1.0 .2.8E-Il BYPASS lE-3 OK 3.7E-3 1.2E-Il BYPASS SRV Discharae (8) 0 NON BYPASS 1.3E-4 1.0 0. NON-BYPASS 1.0 OK 6.2E-7 8.lE-11 BYPASS TOTAL NON-BYPASS 2.3E-10. BYPASS 1.2E-10 '(
1 FIGURE 19E.2-20c ( LARGE LOCAs OUTSIDE CONTAINMENT Line Break Line Oper. Second Div. Coolant Outside Isolation Action Not Affected Makeun (V3 ) (X3 ) (P) 3 (Q3 ) (Q,) MAIN STEAMLINE (4) OK 6.1E-7 3.2E-5 2.0E-Il NON-BYPASS 0 1E-3 OK 6.lE-7 1.0 2.0E-14 BYPASS Negl OK Negl BYPASS FEEDWATER (2) (including RWCU return and LPFL A Discharge) OK 6.4E-5 3.9E-11 NON-BYPASS OK 1.5E-3 OK (* ' i 6.lE-7 1^ q 1.0 I 5.9E-14 BYPASS Negl OK Negl BYPASS L LPFL DISCHARGE (2) (Loops B and C) - OK 8.5E 1.6E-5 1.4E-10 NON BYPASS OK 4.2E-3 OK 8.5E-6
.5 2.8E-13 BYPASS lE-3 OK-3.7E-3 1.2E-13 BYPASS TOTALS NON-BYPASS 2.0E-10
! BYPASS 4.8E-13 l-1
ICC.17 '92 04:45Pt1 G E I0:LE M FLIG J P.1/14 I l GENuclesEnergy ABWR
. Date t 2 h, lex To c k a.+ PoS v.ss9 Fax No. -
This page plus t3 page(s) From J&ck PoM Mail Code 181 175 Curtner Avenue San Jose, CA 95125 Phone (408) 925 '3 8 % 4 FAX (408) 925-1193 or (408) 925-1687 Subject c%g h< t1 8 s svu Message phae %J o.n n aAu e s % - QI_13. '3 1 ,13 3-2 COL- (3. 3 - l ,13 .~3 -2 ,13. 6. 2 - 1 122 . G . 2. - 21 (3. 6 . 3 - t ,. \ 3 , G . 3. S'- t-( 3 6,3. 3 -1, ( 3. 6. 3. 3 - 3 , t 3 . 6 . 3 . s - t 13 G. 3 5 Pa ct of OI t . t -t R%5p owsts Yadb 'ITA AC. Mb Cd \ hCMJ ( I3*'3 - 3 *
- d .
Y n . c. s. c . n o w ow h -de M op
. - -m .._m __ _ _ . _ _ _ .__,_ . . . _ _ _ ._ _. _ _,_ _ _ _ _ _ , _ , , , ,_ ,
p ICC 17 92 _048 4Pl1 G E idXt_ EAR ELIG J - Pi2/14-thA 8 of L.1-1
;ABWR
-- - nuun
$hmdard Pltwt-- _ _ _
na with continuous communications with an by NRC and the overall system power demands,- j l j individualin each continuously manned -The-PA boundaeyhh4*g-sut*ygem is Se naly. l
--c*eet& TW : +yd :- -6 " p e" A l alarm station (i.e., CAS, SAS, PAP). This may be accomplished by using multi- Dmc- ' 9:r;#1 p x ce"::c,7:r;"ri frequency radio or microwave transmitted .a d eq uate.4om pe nsawy-mea r,u r es-stw.sab two way voice communications. Ehed !- 'he the's ;4 -"4 !=;4:&- -
. p.
(b) Communicatio'ns shall be provided between the local law enforcement The power subsystem shall be alarmed to thE authorities and the nuclear plant CAS and CAS and SAS to arisure the continuously SAS.- manned security station operators are aware or any power system failure or attempt at tamper. (c) Communications shall be provided- ing. between the main plant control room and nuclear plant CAS and SAS (i.e., dedicated Enginecring Rationale telephone service that does not have any - terminations outside the protected area To assure that the security system will have a re-boundary, radio, etc.). liable source of power to maintain alarm, con-trol, and response functions necessary to prevent (d) Communication system failure or taroper undetected intrusion into vital or protected
. attempts shall alarm to the CAS and SAS. . areas. It is recognized that PA boundary light-ing is such a large load that it would require a Engineering Rationale - dedicated independent power source to main.
tain it. Therefore, this lighting load is exempted The communications requirements are from UPS power requirements, provided provided to meet the intent of 10CFR73.555(e) adequate compensation measures are taken. and (f). (21) Data Management; Chapter 9, Sections 5.2.13.1 (a) To allow the CAS, SAS, or PAP operator and 5.2.13.2, Rev. 0 to have knowledge of all security personnel locations and capabilities. . The overall station security system shall utilize
" host
- online redundant central processing units (b) Provides CAS or SAS operator with means (CPUs). These CPUs should interface with to direct the response team and call for remote processing units (i.e., CPUs, micropro-offsite assistance if required. cessors, minicomputers) that have on. board
- memory to allow them to stand alone, for a de-(c) Informs plant control room operator with fined period,'should communications with the assessment capability to mitigate sabotage - host CPUs be interrupted.
initiated LOCA attempt. These ' host
- CPUs shall be required to have all -
(d) Alarrns indicating security, communications data transmissions supervised and alarmed if a failure or tampering will expedite restora- failure or tamper attempt occurs, tion of service and provide early indication l -of a potential sabotage thrcat to.other All Security CPUs shall be dedicated to se::urity - plant systems. functions only and shall not perform any other processing functions (e.g., used to incorporate
.-(20) Power Source: Chapter 9, Section 5.2.12.1,- the Orc detection or protecuon system momtor-Ret 0 . ing or controf).
The security power subsystem shall be a~ - Engineering Rationale non-interruptible power source capable of ' L meeting the minimum requirements imposed - This requirement is intended to assure that data is processed quickly, accurately, and on n 190.246 Amendment 22 - l~ 9*
- __ - . e., - -=c r e;-m - . - - ,- . . , , - y-,- m--3r -,*w ,n< , - - - .-
. J (CC 17 '92 - 04:4UTI G E tlXLE@ Etf6 J P.3/14 1 a
ABWR -
- umms Standard PIAul-ne .A q 19B.3 COL LICENSE INFORMATION 19B.3.8 Interdisciplinary Design Reviews i 19B.3,1 Quality Assurance Program COL applicants shall establish an I i I
interdisciplinary design review group and direct I COL applicants shall have a Ouality Anurance reviews for site specific design and construction work Program satisfying the requirements of Subsection as required by Subsection 19B125(4). 19B.2.1(2) including the right to impose additional quality assurance requirements. - 19B.3.9 Sabotage Vulnerability During Plant Shutdown 19H.3.2 Prevention of Core Damage Tbc sabotage vulnerability analysis required by l COL applicants shall approve applicable design Subsection 19B.2.4(10) has been performed for tbe deviations in divisional totalindependence and ABWit and is contained in Appendix 19C. However, separation both mechanically and electrically as COL applicants shall include provision in the plant l l i l required by Subsections 19B.2.3(3),19824(2), and start.up procedures to inspect critical safety 1911.2.11(2). equipment within the containment for possible tampering just prior to sealing the containment in 19B.3.3 Protection from External Threats preparation for start.up. Such equipment includes
. the ADS /SRV valves and associated accumulators l COL applicants shall evaluate listed man.made and their charging lines and the inboard valves hazards except sabotage on a site unique basis as associated with the emergency core cooling systems required by Subsection 19U24(6). (i.e., IIPCF, RHR and RCIC).
19B.3.4 Ultimate Heat Sink Models :19H.3.10 Impact of Security System on Plant Operation, Testing and Maintenance l COL applicants shall implement the development of predictive analytical models as In the design of the security system, COL required by Subsection 19B.2.9(1) through applicants shall include an evaluation of its impact ou 19B.2.9(4). plant operation, testing and maintenance. This evaluation shall be conducted as required by 19H.3.5 Ultimate Heat Sink Reliability Subsections 19B.2.4(12) and 9.5.13.11. -&- *S*g l COL applicants shall have an ultimate beat sink 198.3.11 Security Plan Compallbility with = COL design goal for the service water flow as required by ALWR Requirements n.G.3.5 2. i Subsection 19B.2.10(1) through 19B210(13). ! The ADWR security plan will comply with the
- 19B.3.6 Main Transformer Design ALWR requirements as defined in 19B.2.4. Future amendments of the ALWR Requirements Document -
l COL applicants shall provide main transformer must be reviewed for ADWR compliance by the COL-j fire protection as required by Subsection 198118. applicants, j 19B.3.7 Plant Siting 19B.3.12 Plant Security Systems Electrical ggg Reqmrements " ' l- COL applicants shall approve in writing the c.o t a c h c.o.d4 J P e
- M '-
- - listed final design paramercrs to be used at the plant r the site security system}
- pad ;g i site as required by Subsection 19B.2.19(3), r% non. Class 1E vital (uninterruptible) ac powerl-The-
..preeed are (M) H :!:ry !!gh"pg =b:y:::m n
- a. ..
- g. . t n_g . r .9 7 r -
q;" A 7
, '"bryd r rgb pr _::dE3 m
- . m y. 4 :i A p~e, au, ~ p ~u_,ag 7 9 1 . n.;v .-> cry -:= c.; :- r'^5"'Hd !- 'he de's
. p9:a m...hy : ! -mg p, m = l : ett4ic e c h " p - -
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Amendment 23 19tt31
IEC 17 '92 0.D EF11 C, E f #XLEM EW J P. .U 14
. . . OL. I L 6. 3- 5 INSGGLT 4 operate under accident conditions, (2) the card reader design is required to s preclude the possibility of failure of one card reader affecting the operation of any other card reader, (3) card reader doors are required to have a key-operated override, and (4) emergency exits are required to be provided for exiting without using keys or card readers. The staff considers this response to be consistent with currently accepted industry practice and is therefore acepotable r Jur-the-cre, $$AR-Chapter-k9rAppenMx-19Bc3rlO,-eequires+EOL applicent-t-o-
-evaluate the eMects of the recurity--system en required operatosctions
-d ur ieg-a4+me rgewy-modes-of-o p e r a t i o n The staff 4 positten is that"This analysis should include consideration of an emergency requiring evacuation of the control room in the control building to the. remote. shutdown panel in the reactor building. -This-was--ident4f4ed-as OSFR (SECY-91-235) Open Item 37.
E-vahat4cn of compliance "ith the vital equipment prompt access-requi.nements of-10 CTil 73.55(d)(4)(+i-)-is-GOL-AeMen-4 tem-1A6rM-2-that wil' be resolved-h during-+evic> of the pl% specific-security pl
~
3.6 Bullet-Resisting Walls and Doors, Security Grills, and Screens SSAR Section 13.6.3.6 discusses bullet-resistant walls and doors and security grills and screens incorporated into the building design, with the stated intent of minimizing forcible access to the control room. ; Responses to RAls 0910.13, Q910.23, Q910.24 did not resolve staff uncertainty as to the adequacy of barriers in all man-sized openings in physical barriers that , separate other vital from non-vital areas. Also, the staff position on the e effectiveness of the ventilatior. system barriers described in SSAR Sec- t tion 13.6.3.6 remained as described in RAI Q910.13; that is, consideration may need to be given to how accessible, isolated, and hidden from view these barriers will be, as well as whether they can be penetrated with hand tools available on site. While SSAR Section 13.6,4. 6 only addresses the main control room heating, ventilation, and air conditioning (HVAC) ducting and t exterior air exhaust systems, SSAR Chapter 19, Appendix 19B.2.4(13) was changed to include EPRI ALWR requirements on utility port openings (e.g., HVAC, cooling, and piping) through all vital or protected area boundaries, in accordance with EPRI Evolutionary Requirements Document Chapter 9, Set-tion 5.2.5.1, Revision 0. Specifically, the SSAR indicates that the ABWR l design will minimize the use of utility port openings through all vital or protected area boundaries and will provide security access control of these utility ports. GE's change in Appendix 198.2.4, which clarifies that the ABWR design will comply with the above ALWR requirements, satisfactorily resolves this issue. . Desion Certification Material , The staff expects that at least 60 days before loading fuel, a COL licensee referencing the ABWR design shall have confirmed that the as-built bullet-resistant feature of walls and doors and the penetration-resistant feature of barriers in HVAC ducting and exhausts, committed to in SSAR Section 13.6.3.6, f have been installed in all locations required by the commitment. This inspec-j tion requirement should be included in appropriate building ITAAC and is Open Item 13.6.3.6-1.
~ _
i A ABWR DFSER -- 13 5 October 1992
ttc ir w w a.rm. e r oxtBe tu.: > r.s ia ABWR usuooxs Standard l!! ant ne A 4 apperrutc c!.cusa liu;d in!:dacwfo4-the-WV-- b;.J:. !!gh!!q. (See Subsection 19H.2A(20)) 1911.3.13 Holting Degradation or Failure l COL applicants shall provide the bolting infortnation detailed in Subsection 1913.2.12(6). 1911.3.14 Outsider Sabotage COL applicants shall provide sufficient analyses to ensure that the plant is adequately protected frotu acts of outsider sabotage. Amendment 23 19D.3 2
s
-P.10/14~
, fCC 17 '92 04:JSFil G C f U1 EAR R.[G J ~ m si m ABWR i.' Standard Plant anv a e . SECITON 13.6
- 1 I- CONTENTS -,
. P,agg I bTfli.0_Il Tillia i
1
- Err]i_ min.aryfLangle.m U.6-1 13.6.1 13.6 1 '
13.6.2 Stspritv Plan f 13.6 3 ff)L License information Physical Security f D.6 2 h j-1 13.6 ' 13.6 3.1 Introduction Design Bases -
' D.6 2 r 13.6.3.2
!- D.6-2 i 13.633 Vital Ascas U.6-2 l
! 13.6 3.4 . Methods of Access Control 13.6 3.5 Access Control and Security Measures Through 13.6 2 Exterior Doors to the Nuclear Island 13.6 3.6 Bullet-Resisting WaUs and Doors, Security l - 13.6-3
' Grills and Screens - Compatibility with the Remainder of the Plant 13.6-3'- 13.6 3.7 i 13 C 3+ 8 Secoy i , Cow-h wyw ey o w d c_a __,n_r i3 C.S.9 A e. kev % M of- Oparn.howak S+^b f I 2. G.3.1 o Vs4o 5 -CAosJd h su u d c%4ed.mm a s <.~kc.c. A\a o^ Y S-\ Osuw .t 4 13 E b il V ev s fs c. air g o 4.k ,,t v ,4 d s yb,, l Ca s ? adorn y , 5, p
* * *
- Ggj Mg Ne oh C.ta %* EnhpoggA . h0V4 At.
f . ,3. c . t. o coy.+ik.M3 w A R R.t,, s.i z. Pos h c~wmpatsga mod,wg I i~ g 13.6-ii i Amendment 13
'f l
. - . _ - _ _ . _ . . _ _ _ . _ . ~ _ . _ . . . - _
[CC 17 '92 04: Wif11 G C iIXt.EfR BLlai J P.11/1 1
/kbkN DA6100AM Pn3 Standard Plant _
13.6.3 COL License infonnation [ysical Sucurit 4 C%ss c. % fay s k %% Aol f M o I 3. G- %- Aa +%,4Mr SAFEGUARDS INFOIGiATION Prmided under separate cover. (Includes pages 13.6-2 through 13.6-2.2) 13.6 2 Amend <nent 23
ICc 17 '92 O S & 11 h E IMLEfF [W J P.12'14 g3.G.3.8 S e cv A , C o d' ^ 7*"cg i A G "cwd "Tm. s e ) P \ oW 13.0.2 R c-u r i ty '" = T h e C ot- ,gg dh4hc SSA" st-at+s-that-this-4-beyond-t e-scope-ef the [F st andard pl ant- , 6g ' des 94 n--The-McR grecs . ! addit 4 i terr- Ltstsd in Sac- ' dg ~ tion 13.0.3 cf the SS.4,-the uti'it-y,pn , applicant te the e tgactio/ provide site-specific
- security, contingency, and guard training plans in accordance with 10 CFR .
f d f50.34, 10 CFR Part 7). 4hn-b-C41 t 3. G 5. 9 A eb eeceT o ~f omd-A-tic.i* ' tem 13.0.2-1. p eet. app M and N ct:f-f -requires--that At least 60 days before loading fuel, Aa-C4L holwr will confirm that security systems and programs described in its physical security plan, safeguards contingency plan, and guard qualification and training plan have achieved operational status and are available for the m Nuclear Regulatory Commission (NRC) inspection. Operational status means i that the security systems and programs are functioning in entirety as they j would when the reactor is operating and will remain so. The COL 5 cider't
. Determination that operational status has been achieved must be based on tests I
[ conducted under realistic operating conditions of sufficient duration to l demonstrate (1) that the equipment is properly operating and capable of long- l
'ou J term, reliable operationi (2) that procedures have been developed, approved, !
g and implemented; and (3) that personnel responsible for security operations I and maintenance have been appropriately trained and have demonstrated their > capability of performing their assigned duties and responsibilities. -This is- I
--COL Acticn Item 13.5.2-2. H$M 13.0.3 Centrel--of Access to-Areas 4ettte4tdeg Vital-Equipment-2
~m~ a.,- .
c "J -Sect i on 13. 0. 3 c f thc 55AR - i den' '" trmber of inturfeces bet een the A9W-
-standard-plant--design-end--the-r- *-af-the - pl ant that -s t be addre s t ed by-COL spplieents whc reference the ASWP standard-pl2nt deriy 4he staff reviewed-the %terface and detershed.that -there are not interJacess--- ~
as-descr4 bed 4n-lG-GFR 52.47 but %:tead are 2ctica: te be acccmpli bed--as-pwt-of the COL appl 4c-at4cn. The st:f f finds-them-to-be-aeceptable-as cob- ),
-action itemt subject-to-tha w ition gf the vo rm i r eme n t that the a nnl igant. 3
.previtia-plant-speci4ic-security,.-cont 4ncycncy, and guard trainirg pl:as 4%
accordance with 10 CFR 50.3' :nd 4 art ??. -This is COL actien4 tem 13.6.3 1. f; / fi 13.5.3.1 -Introduction. ~ ., 7 This section of the SSAR . states that SSAR Section 13.6.3 is concerned with the
;.ontrol of access to areas containing vital equipment.
13.6.3.2 Design Bases This section of the SSAR states that security functions described in Sec-tion 13.6.3 are incorporated into the overall ABWR design so that the plant is in compliance with the requirements of 10 CFR Part 73. The Electric Power Research Institute (EPRI) Advanced Light Water Reactor (ALWR) Requirements Document (Volume II, Revision 1, Chapter 11, Sec-tion 8.4.1) specifically requires the protected area lighting to be powered from an uninterruptible power source. GE's response to request for additional
} information (RAl) Q910.18 identified a site security load on the non-Class lE vital (uninterruptible) load list (SSAR Table 20B-1), but the staff considered i
ABWR DFSER 13-3 Oc t o b_e r-
uc nv we n - t a n no ht6 1 P.t: 11 4
- - - - - m
( ~thedescription of this interconnection to be insufficiently defined. In i
/
response to staff comments, GE added 55AR Section 19B.3.12, which clarified the connection between the security systr.m uninterruptible power requirements L (to be later so determined by the plant-1pecific security system designer as s to meet required security system performance) and the non-Class 1E vital power 4
- supply capacity. 55AR Section 19B.3.12 allows the protected area lighting to be powered from an interruptible power source, which conflicts with the
! lighting guidelines in the IPRI ALWR Requirements Document. This is part of % Open item 1.1-1 discussed in Chapter 1 of this report. -
[ NRC Information Notice 83-83 suggested that new plant designs that make extensive use of solid-state devices in instrument and control circuits may ' , ! experien.e reactor system malfunctions and spurtous a,ctuations as a result of portable communication devices in their vicinity, iln 'RAls Question (Q)910.10 and 0910.17, the staff asked that radio frequency interference design criteria be established to ensure that security personnel within the reactor and control building could maintain radio commun".ation without advrc telv affrct-ing plant operation. GE's response to Q910.17 referenced discus: .. of system tolerance to electromagnetic interference.1The staff consi,. *s the plant security systems criteria in SSAR Section 9.5.13.11 and the L idment to SE Appendix 7A, in response to a concern raised in the USER Section 7.1.3.3, to adequately resolve staff's concern. aO:..' .!
] l' .
13 . 6. 't . 3 Vital Areas This section of the SSAR ltemizes by location the plant equipment to be con- I sidered vital equipment in the sense of 10 CFR 73.2 and the vital areas con-
- taining that equipment. SSAR figures 13.6-1. through 13.6-14 outline the vital areas. : n:- E.; . e-RAl" 910.9, 0910.11, and Q910.20 addressed .tfie completeness of the list of vita :quipment in SSAR Section 13.6.3.3. Additional clarification was docu-mented by GE on February 22, 1991, following discussions with staff. The staff is satisfied that the list of vital equipment includes all active and passive plant equipment essential to safe shutdown of the reactor, including necessary support systems, the reactor vessel and the remainder of the reactor coolant system pressure boundary within primary containment, the suppression pool, spent fuel in the fuel pool, and any associated piping,' equipment, and controls whose f ailure could result in an offsite release in excess of 10 CFR Part 100 limits, The staff finds this to be compatible with NRC Review Guide-line 17 (January 23, 1978, memorandum from R. Clark to safeguards licensing
*W
- G .G.3.lo V M h** C b 8 M #" C
- 9 g ,pr4er--to 4uuanse-of-a-00Lrthe-+taf f's-eev4ew-of-4he-des 49nat4en-ef-equireent, i g as vital in plant-specific applications will focus on plant support equipment D g outside the scope of the certified ABWR design, in addition, 10 CFR 73.55(e) ]
- requires the central alarm station to be considered a vital area and secondary p O power supply systems for alarm annunciator equipment JJ and non-portable communi-cations equipment to be located in vital areas. The secondary alarm stati v Ac-4s-typ4 ally en- site-and treatM n : " ital ma/ Vital area classifica- .d;y tion of the central and secondary alarm stationsJs 401- Adivn-ItmO.0.0.M-t h a t-will- be- ad d re s s ed - a t - t h e t-i me -o f-t h e-ph n t-s peef f4 c-s e c u ri t y-pla n-cev h m tl be p rovuW b 3 4h cot. a p p h c. ,.A .
ABWR DFSER 13-4 October 1992
uc n m w. u n ' r t u t i m t w. 3 tu u t 3. G . 3 0 Vovdc.due & V' D " " kA* s r- n e N e s a+ COL. M P r^ Ths-staM-emm that at least 60 days before loadirg fuel, ahicinena shalL-vi hwe confirmW that no po tion of as-built vital syste ns are located outside I of designated vital areas or can be prevented from performing their safety q;ffunctionsfromoutsidethevitalareas(e.g.,byreach-rodvalvemanipula-g
- l tion). This verification should include piping, valves, and motor control i centers that are required for boundary integrity, for performance of safe i J' reactor shutdown cooling function, and to isolate safety-related equipment from non-safety-related equipment. -This4: Cot- Aet4en-4+em-43164h (o
U/ ' 8 5.G.3 12. Ev An: hon o f Su e %4e RAspo m Fo m s The plant-spec 4(4e-14(ens 4ng-*v4ew-of-the-secuetty-and-+ont4ngency-+esponse-d plan-also-wi41-4nc4udeqan evaluatio of-whether the security response force q icapability to interdict the violent xternal assault postulated in 10 CFR ml 73 l(a)(1)(1) properly accounts for the minimum penetration delay provided by G the vital area barriers and doors. This-4s-00lp Aot40n4 tem 43r6&B -h-J& 3LB.S.3.1 4 % Cot MHheds-of-Acec','.-- C= rol ka L"M k W f f w i \.,4 b y,4.M c-Q d A ,)? 43.d.3.5 Auen-Gontvel-and4esur4ty448a urss Thr-ough4xtardor Doors-to 4hs_.
-Huclea r-4 & land- --
= .
SSAR Section 13.6.3.4 describes, in general terms, the types of door controls In response to RAls ) that will be used to control access ta vital areas. - 0910.12, Q910.21, and Q910.22, statements were added to the SSAR that all doors and hatches connecting vital to non-vital areas are to be alarmed and emergency egress will not require keys or card readers. Section 13.6.3.5 , describes the specific security measures at portals into the reactor and
) control buildings from exterior areas and facilities of the remainder of the n12 nt . r -
h.G. 5.13 CAP ' kids Ob5.dM./d5 M COI Y YM #A P'D
%e-t y pe s -o f-door-con t rol s-spec 4f4ed-4 n - SSAR-Sec-t4en-1 A 6 r3r4-ar& g e ne ral4y-i acupt ablei-but insuff4c4ent-detail ir prov4ded40-deteratee compat4tM44y--
M with RG 5.12 41evision 0; -Thh-<lesce4pt4en-if-ascost,-c4ntrol methods-4440-A 'does-not-add,essr the positive control requirement of 10 CTR 73.55(d)(7)(i)(B) and the record-keeping requirement of 10 CFR 73.70(d), WMch-requ4ees ' egg 4n9-u;( $ ind444du+1+Lt4mes-of-ent,ry-t0-end-ex44-frer eachw&tal-arm This 4& sue-I 414-be-cons 4dert4-dur4ng- reviceOf-the-plant-spee4(4e-security phn --4hb a wa5-4 dent 4fied-as-OSER-(SE4-91-23&}-Open-44em46 Th4s-is40l-Aet4en j W# / e a [he md w iii d h oes h b O d d " '"'dV*!# * * '" P In mi QiiiO lu,-ittr staff aiked WhTtTe p.Trameters Tor envTronmenta'1ToldW (tions in SSAR Appendix 31 should not apply to the design and qualification o security access control components. TM1 Action Item II.B.2 (NOREG-0737) identifies areas for which environmental qualification of equipment necessary to ensure post-accident access may need to be considered. Although the
" security center" is not safety related, it is included in NUREG-0737 because I access to it may be necessary to give access to the rest of the plant. NRC Information Notice 86-106, Supplement 2, discussed an event at the Surry Power Station in which condensed steam saturated a security card reader and caused a short circuit in the card reader system for the entire plant. As a result, by cards would not open doors controlled by the security system. In the same event, the performance of a security communications system radic repeater was j temporarily degraded as a result of a thick layer of ice formed on it from actuation of a carbon dioxide discharge nozzle. In response to RAI 0910.19, }
GE stated that (1) this equipment is not safety related and is not required to i BWR DFSER 13-5 October 1992
~-~.% - -.- __--. __ -
I tu 17 '9;: p e' i'4 cm. :T1i i; t un(t.w tubik I4';'t 3, 3 t ABWR m _- mi t StandanlEant ye t, 13.3 EMERGENCY PIANNING Emergency planning is not within the scope of the ABWR design. However, there are design features, f acilities, functions, and equipment necessary for emergency planning that must be considered in the design bases of a standard plant. Table 13.31 is a summary of the AllWit design considerations pertaining to emergency planning, th e COL 4 f ph c.<uk un il p rov \ d Q s yv o v- awt p \ o. r .Y tr CA C C Q V~ tkwtA w 54 10 C I R 5 4eks o w C O. 4 7. Ameumem u 333 l l l
1i.c 17 w 04. m is c tou s.P tt!1 J ~~ ^ P . 7 ' t .) . OT LL 3-1
. ABWR n_ - twit i Standard Plant wu Tuble 13.31 AllWR 1)ESIGN CONSillEllATIONS FOR EMERGENCY PLANNING REQU1REMENTS Primary Document / Emespency Planning ABWR DMty Etr1La.!! R'emirements Dtt lErLCMlWIRLLD Technical Support NUREG.0696/ The TSC is an oralte The AllWR Standard Center (TSC) 1.3.1 facility located close Plant wU comply to the control room with all the TSC that shall provide design requirements.
plant management and Specifically, a 13C technical support to of sufficient site to the reactor operating support % people is 2b personnellocated in located in the the contaof room dur. service building ing emergency cond- adjacent to the ions. It shall have control building. technical data displays The neceuary fac-and plant records ilities and equip. available to aulst ment called for in in the detailed ann. Section 2 of lysis and dinguosis of NUREG 0596. abnormal plant condit-ions and any significant release of radioactivity to the etnironment. The TSC shall be the primary communications center for the plant during an emergency. A senior official, designated by the licensee, shall use the resources of the TSC to assist the control room operators by handl-ing the administradve items, technical evaluat-lora, and contact with offsite activities, reliev-ing them of these functions. The TSC facilities inay also be used for performing normal functions, such as shift technical supeni&>r and plant oiperations/ rnaintenance analysis functions, as well as for emergencies. Amendmtnt it 1112
e.m a tcc n w cmaem c c to:ttm fu,0 V1 t h 3 - i AHWR mum samlanLPhnt =- - - - n,s o Table 13.31 l AllWR DESIGN CONSIDERATIONS FOR EMERGENCY PLANNING REQUIREMENTS (Cotitirtued) 1 Primary Document / Einertency Planning AllWR Dalva Considm!11e ! ffLiiL Settle !!aultrusstin Operatpal. ppor NUREG-0@6/ The OSC is an onsite he OSC is not wid.1 Center o 1.3.2 assembly area separate - t scope of the All R (OSC) from the control room St datd Plant. A :01. and the TSC where app ant is respc sl. Licensee operations ~ ble (< identifyi - e %e support personnel tyhe O. , and oomuni. y report in an emergency. tion mte ac for 4 nere is direct commun. loclusion ' be AA ications between the detailed _ ,n of OSC and the control the con ol e om and room and between the TSC. he de iled OSC and the TSC s.o req rements a . that the personnel pr vided in Sect n3 reportingio the OSC NUREG0&M. can be assigned to duties in support of , emergency operations. Emergency Opci. NUREG-0@6/ The EOFis a offsite The EOFis not within ations Facility 1.3.3 support facility for the scope of the AUWR the management of over Standard Plant, it COL t '3 . 'S - 2. (EOF)
-all licensee emergency is the responsibility response, coordination of the cot, applicant of radiological and to identify his EOF environmental aucu. and Ihe communication ments and determination interfaces for inclu-of recomn. ended public sion in the detailed protective actions. design of the TSC and The EOF has appropriate control room. The l
technical data displays detailed requirements
- and plant records to are provided in assist in the dagnosis Section 4 of of plant conditions to NUREG 06%.
evalu te the potential or actual release of radioactive materials to the envirnomnet. A senior licensee officialin the EOF organizes and mamages licensee offsite resources to support the TSC and the control room operators. assembly area seperate from the Amendment 23 113 3
. -_ . - = . _ . , - _ - - - , . , . - . _ , . - ._ . _ . . - - - - . - _ , - , - . . _ . . - - - - - . ~ , - . . _ - . - . . - . ~ - -
(CC 17 '92 OM 4M1 G E t o:LErF ILf 4 1 _____m P,9/11 CT13.3>2 Insert AA The ADWR Standard Plant will comply with all the OSC design requirements. Specifically, the lunch room adjacent to the Tsc in the service building which is adjacent to the control building will bo identified au the OSC. The COL applicant in rouponsible for identifying the communication intorfaces for inclusion in the dotallod donign of the control room and TSC. The detallod requiroments are provided in ocction 3 of InfREG-0696. l L 4 i rr 7 T-p+,v- 9=e- -rw17i-wy=-"3- 3--Tv-m-vr,y-w--r-yw y- it w ,y-%-y yy gy,r-rvtweiy*- i-WTT-rvv w 'r t*Yfr* - yvw w wv-g w y-giev iwy- g-mymir'eev-y *-y' -1 aw-ww-+M--*
12/17/92 To: D Scaletti cc: J.D. Duncan R Palla J.F. Quirk from: P.D. Knecht
Subject:
Desian Modification Evaluation (ADoendix 19P) and Technical Support Document L Attached is the final draft of Appendix 19P, Evaluation of Potential Modifications to the ABWR design. Also attached is the first draft of the corresponding Technical Support Document prepared to support the SAMDA submittal. These documents incorporate NRC concerns expressed during our meetings on October 8. 1992. This revision to Appendix 19P is considered final. Any comments on the Technical Support Document are appreciated. If there are any questions, please call, f';'/4 ~< A f PD Knecht Principal Engineer (408) 925 6215 l
t _ .[ l 1 .i i i 1 1 J )
- APPENDIX 19P
! EVALUATION OF POTENTIAL MODIFICATIONS ! TO THE ABWR DESIGN n 4
>. < a, , v
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ABWR numas Standard Plant an 4 APPENDIX 19P TAllLE OF CONTENTS Sutlan Illic bge 19P.1 Intrrduril211Atid Summary 19P.1 1 19P.1.2 flackground 19P.1 2 19P.1.2 Evaluation Criteria 19P.1 3 19P.1.3 Methodology 19P.14 19P.2 Sc5ere Accident PJsk of AllWR 19P.2 1 19P 3 Potential AllWR Mndifications 19P.31 19P.4 Risk reduction Of Potential Modifications 19P.41 19P 4.1 Accident Management 19P.4-1 19P.4.2 Decay lleat Removal 19P.4 2 19P.4.3 Containment Capability 19P.4-3 19P.4.4 Containment Heat Removal 19P.4-4 19P.4.5 Containment Atmosphere Mas,s Removal 19P.4 5 19P 4.6 Combustible Gas Control 19P.4 6 19P.4.7 Containment Spray Systems 19P 4 7 19P.4.8 Prevention Concepts 19P.4 8 19P.4.9 AC Power Supplies 19P.4 9 19P.4.10 DC Prwer Supplies 19P.4-10 19P.4.11 ATWS Capability 19P.4-11 19P.4.12 Seismic Capability 19P.412 19P.4.13 System Simplification 19P 413 19P.5 Cost Impacts Of Potential Modifications 19P.5-1 19P.5.1 Accident Management 19P.51 19P il Amendment 24
i ABWR n^um^s Rev ^ Standard Plant 1 i APPENDIX 19P i TABLE OF CONTENTS (Continued) l Secllon 11112 EAgt 19P.S.2 Decay 11 eat removal 19P.S.2 i . 19P.S.3 Containment Capability 19P.5 3 j 19P.5.4 Containment 11 eat itemoval 19P.5 4 i . I 19P.S.5 Containment Atmosphere Mass removal 19P.5 5 I 19P.5.6 Combustible Oas Control- 19P.5-6 J 19P.S.7 Containment Spray Systems 19P.57 19P.5.8 Prevention Concepts 19P.5 8 l l l 19P.5.9 AC Power Supplies 19P 5 9 19P.5.10 DC Power Supplies 19P.510 t 19P.5.11 ATWS Capability 19P.511 1 19P.S.12 Seismic Capability 19P.512 19P.S.13 System Simplification 19P.513 l ' 19P.6 ' Evaluntlan Of Potential Modifications 19P.61 - 19P,7 EMaman of Conclusions 19P.71 i 19PJ Refmaces 19P.81 I e
.E e
d J 19P iil Amendment 24
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ABWR :mims ne a Standnrd Plant SECTION 19P.1 CONTENTS 3
- Sectlon IlfIf Eagt 19 P.I .1 }}ackzround 19P.I.2 19 P.1.2 Evaluation Criteria 19P.1 3 19P.13 Methodolocy 19P.14 l
19P.13.1 Selection of Modifications 19P.14 19P.13.2 Costs Estimates 19P.1 4 l 19P.133 flenefit Estimates 19P.14 19P.13.4 Summary of Results 19P.1 4 i 19P.1-ii Amendment 24
ABWR mams g,y 4 Standard Plant 19P.1 INTRODUCTION AND
SUMMARY
This section provides a description of an esaluation of potential changes to the ABWR design in order to determine whether further modifications "= u?^ ; ;; A- cm & Jusl e /r ed, 19P11 Amendment 24
ABWR m as Sinadard Plant ne, a 19P.1.1 Background The U.S. Nuclear Regulatory Commission's policy related to severe accidents requires,in part, that an application for a design approval comply with the requirements of 10CFR5034(f). Item (f)(1)(i) requires " perform [ance of] a plant site specific [PRA) the aim of which is to seek improvements in the reliability of core and containment heat removal systems as are significant and practical and do not impact excessively on the plant'. Chapter 19 prosides the base PRA of the ABWR plant. To address this requirement, a review of potential modifications to the ABWR design, beyond those included in the Probabilistic Risk Assessment (PRA), was conducted to evaluate whether potential severe accident design features could be justified on the basis of cost per manma averted. g fees ~.ve , This appendix summarizes the results of GE's review and evaluation of the ABWR design. Improvements have been reviewe gainst conservative estimates of risk reductio iased on ic. the PRA and minimum order of magnitude costs, to determine what modifications are potentially attractive. Amendment 24 19P.12 _ _ _ _ _ - _ _ _ _ - _ - _ - _ _ _ _ = _ _ _ - _ _ _ _ - _ _ _ - _ _ _ _ _ _
1 ABWR umius i
- Standard Plant n,v A !
} 19P.1.2 Evaluation Criteria i The benefit of a particular modification was defined to be its reduction in the risk to the general j public. j Offsite factors evaluated were limited to health j cffects to the general public based on total exposure 1 (in person tem) to the population within 50 miles of the site. Five representative US regions were ; evaluated for selected individual ABWR sequences {
- by the CRAC02 code. The regional results were then averaged to determine the exposures.
l Consistent with the standard used by the NRC to
- evaluate radiological impacts, health effect costs were evaluated based on a value of $ 1000 per offsite
- person rem averted due to the design modification.
I The offsite costs for other items such as ' I relocation of local residents, elimination of land use ,
< " *"" y and decontamination of contaminated land were not
' 7j,'N , ,gs.,,
j considered. Reductions in the risk of6conomic y j losses, replacement power costs and direct accident costs in this i==:::d F i; a[9'"'rr*' 9-%rp, evaluation tfic costconsidered of the < l modification. s s.), ' Based on the PRA results (Section 19P.2) 4W% of the offsite risk results from H2iow probability $10 w , high consequence. ease 6e. The maximum justifiable , i cost of a modification was determined to be $183. l Therefore, based on this methodology, no modifi. ~ cations are justifiable. However, a variety of
- . modifications were reviewed to establish the relative l attractiveness of potential changes.
i 1 I i i t i i 4 l Amendment 24 - 19P 14 I l
. - . . _ _ . . , . . , _ . . - - , , , , . . -.. ._, .___.,er ,mm._,m.,, y _,_u,.,,,
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ABWR - ms
%4 Standard Plant s., .+fa,-+ , n. o n m en,c,a.< w -i 19P.I.3 Methodology s
, The costs of modificat ,ns (see ,ection 19P3 were further reduced by r amount M$*'N) '
The overall approach was to estimate the bera6t thc*ptc5cnt worth oldt Mthe risk of ascrf ed of nodifications in terms of dollar cost per total onsite costs. Onsite costs .nclude replacement power person. rem averted. Underestimated costs and costs, direct accident to . (including onsite cleanup) overestimated benefits were assessed in order to and the economic loss c. the facility. Evaluation of favor modifications. Because of the uncertainties in t his a dj Eis$ t 8 scluded Ihe following g i the methodology and the desire to address severe considerations: accidents with sensible modifications, this basis is . judged to be acceptable for purposes of this study. (1) Accidents we assumed to occur at any time during the 60 year life of the plant. All onsite 19P.1J.1 Selection of Modifications costs associated with the accident were evaluated as to their value at the time of the Potential rnodifications were identified from a accident. The economic risk of such onsite variety of previous industry and NRC sponsored costs was eva@ed as a function pf_tirnt~ u,g, 3 studies of preventative and mitigative features which based on the onsite costg'nd the%g core address severe accidents. !!ased on this composite dam @'IWiYe7EA. The plant core list of modincations considered on previous designs, damage frequency was considered to be potential modifications were selected for further constant over the life of the plant. The review based on being 1) applicable to the AllWR cconomic risks were then evaluated based on desigt and 2) not included in the reference PRA. Af/' ha# the present worth of the time dependent M , / ~ ~ i< A < A ~ ,/ ~ economic risks.
./ /, < .A -
19P.1.3.2 Costs Basis h
- A' - Ad a- / M J .
(2) Replacement power was based on a rate of A I.hNough order of magnitude costs were $.013/kwh differential bas bar cost. The assigned for each modification based on the costs of differential rate was assumed to be constant systems and system improvements determined by over the remaininglife of the plant. GE. These costs represent the estimated incremental costs that would be incurred in a new plant rather (3) The economic value of the facility at the time than costs that would apply on a backfit basis, of the accident was based on a straight line Section 19P.5 defines the cost estimates for each of depreciated value. The initialinvested cost the modifications. was taken at $1.4 Billion based on DOE cost guideline . Even for a new plant such as the ABWR, N' "" g m, 4,,/.yo ,,,M I relatively large costs (several million dollars) can be (4) A'[ideat costsjwere evaluated based on expected for some modifications if they involve cAcalated costs to the time of the accident. x modifications of the building structures or Reference accident costs to the facility were l arrangement. This is because the cost of labor and assumed to be $2 Billion. materialis often a function of the building area required. For other modifications which involve (5) The economic evaluations were based on a minor hardware addition, the cost is often dominated discount rate of 8% and escalation factor of by the need for procedure and training additions 3E which can amount to hundreds of thousands of dollars. 19P.1.3.3 Benefit Basis The costs estimates were intentionally biased on The cumulative risk of accidents occurring during the low side, but all knowc or reasonably expected the life of the plant was used as a basis for estimating costs were accounted for in order that a reasonable the maximum benefit that could be derived from l assessment of the minimum cost would be obtained, modifications. A particular modification's benefit Actual plant costs are expected to be higher than was based on its effect on the frequency of eventi, or indicated in this evaluation. All costs are referenced associated offsite_ dose summarized in Tables 19P.21 to 1991 U.S. dollars. ~~3nTTable 19P.23 This basis is consistent with the approach taken in NRC evaluations. The cumulative X I i offsite risk was 'aluated over a 60 year plant life ps.,,. A en /..u 4 Amendment 24 /*. /.as '? 'M/- i8 19P.1-4 e
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** fMe s pt.w4 s 4 /*fr e., er ec f J f*~*U A' d= e *>e-( , M g . fh< /e e e/ / */ m.e eeYe Ced **a= .
mamas ! ABWR n,v A Standard Plant with no escalation in the evaluation criteria of j
$K100/ person rem.
Section 19P,4 summarires each concept and estimated benefit for each individual potential modification. For each modification the cost per person rem averted was evaluated to obtain the results of the individual evaluations. These conclusions are prosided in Section 19P.7. 19P.I.4 Summary of Results Potentially attractive modifications were selected j based on previous evaluations of potential prevention and mitigation concepts applicable during severe accidents. Of the modifications applicable to the ABWR design and which were not already implementedxTwenty $were selected for g additional resiew. -% The low evaluated frequency of core damage and subsequent release of radioactive material does not support modification to the ABWR based on costs in relationship to the benefit of averted crposures. Mone of the modifications considered x met the $1,000/ person rem averted criteright g~ , . era., a . .:= ye .w .~.9 bn" '- 9 e t '6 a - -'- % r SE 'rn W **Tb?;d O' OI : . N75,0CC pa pszpun ism M g ,, ,a , aw * / * *1-
- 4 Since the ost beneficial modification was >
evaluated to be, =: :H Err d?! higher than the criteria,it was concluded that no additional modifications are warranted in the ABWR design to address severe accidents. Furthermore, due to its magnitude it can be calculated that this conclusion will not be sensitive to variations in the astumptions used in the PRA results. 191* I 4 Amendment 24 l l f
ABWR maams Standard Plant nn SECTION 19P.2 TAllLES Inhle IWs Pugs 19P.2 1 Offsite Accident Cases 19P.2 2 19P.2 2 Offsite Costs Assumptions 19P.2 3 19P.2 3 Core Damage Frequency Contributors 19P.2 4 19P.2 ii Amendment 24
ABWR 2mtmas Rev A Standard Plant 19P.2 SEVERE ACCIDENT RISK OF Case 7 Low Pressure Core Melt with Dr>well AllWR llend failure and no mitigation. Tbc reference design for this study was the ABWR Case 8 }{igh Pressure Core Melt with Early p PRA as presented in tb N.ad m the internal Containment failure, events PRA [Section 19.0). This evaluation accounts for features which were included in the current Case 9 ATWS event with Drywell licad ABWR design specifically to address severe failure, accidents, bese are further discussed in Section 19.3.1.5. These features and the reference NCL description include: Normal Containment Reactor Building. j,,.. Leakage p* [to (* i SSAR References The offsite exposures for each case shown in
- 1) Firewater pump crout i c 1 Wet fM 8 M* Table 19P.21 were calculated by ipe CRAC2 code
- 2) Passive containment flooder 10GA lo sos. for five representative US regions)for the selected
(. 3) Gas turbine generator 9.5.11 Individual ABWR sequences 4 Table 19P.21_
- 4) Overpressure Protection 1E4 c,or.a4 Eummarizes the average values obtained among the Gye US regions and includes the assumed regional 4 A sumi e .1 the core damage frequency and offsite exp -
frequency with these features hvalues used in the analysis which were efere u r m a n n ___
~
derived from j included i ,hown in Table 19P.21. Event frequencies used in this evaluation were the same as Table 19P.2 2 provides additional detail on the - assumed in the base PRA. Individual contributors to the total core damage frequen As indicated on Table 19P.2 2, the core
. damage Wolninated by low pressure transient The offsite exposures shown in Table 19P.21 were calculated by the CRAC2 code for release cases events (LCLP) (61.4%), followed by high pressure with similar consequences. Although discussed in transient events (LCl{P) (28.1%) and station i Appendix 19E.3.2pe cases can be characterized as blackout sequences (SBRC)(10.3%).
follows: Review of Table 19 '.21 also indicates that the dominant contributors to the ABWR ofIsjte._.g n Case 1 Core Melt arrested in vessel or in Contsinment with actuation of exposure risk are the relatively low probabilit>6igh v v=/v ; containment rupture disk. consequence events (Case through 9) which contribute about)E% of the o ite crposure risk. Case 2 Low Pressure Core Melt w}th suppression pool bypass anu actuation g of containment rupture disk. [g. g Case 3 High Pressure Core Melt with drywell 11ead failure and fire water spray initiation. Case 4 Suppression Pool Decontamination reduction (Not used). Case 5 Large Break LOCA without recovery and with actuation of containment rupture disk. Case 6 liigh Pressure Coic Melt with Drywell Head failure and no firewater sprmy initiation. 19P,21 Amendmen 24 __-_______ _ ____ - -_ _ ~
ABWR 2mim4s Rev A Simidllrd_ldmit Table 19P 21 OFFSITE ACCIDENT CASES CASE I REQUENCY VWKl!@ EXPOSURE" COS lilUTION 4 t'%) (per yr) (per esent) (per )n) ("< ) Case 1 2.0E-08 11,500 .014 7,7 Case 2 7.8E 11 8,328 3.9E5 0.02 371,400 2.8E5 0.02 Case 3 13E 12 206,400 0 0 8(f, Case 4 0 Case 5 63E 12 493,380 3.5E 5 0.02 Case 6 1.2E 10 2,216,000 .018 9.8 Case 7 3.7E 10 2,726,000 .061 33.2 Case 8 2.1E 10 3.202,000 .040 21.9 Case 9 1.5E 10 3,312,000 .031 16.8 NCL 1.4E 07 2300 .019 10.4 TOTAL 1.6E 07 .183 100 n.u n ra s t ry. s .a.
- For case descriptions see fable 19E3-61 ferv< ..~ ~ - -
" Regional values used i J= #c.te- # u.3
^"I / ; l
'""i,'""
~
[ Region (People /sq ml) Meteorology Northeast 230 Caribou, M e, 'y
~ Midwest 120 Madison, Wi. O South 100 Lake Charles, La f West 50 Medford, Or.
- l. South West 30 Brow i W __nsville,' Tx.
Distance considered (, l 50 miles Evacuation included I isotode Assumptions See Table 19E.3-6 19P.2 2 Ameadment 24
ABWR mems Standard Plant an A Table 19P.2 2 Core Damage Frequency Contributors EVENT SEQUENCE % INIT. EVENT l A 181 152 IR3 1D li lilD IV TOTAL CONTRIB SCRAM 1.1E 08 43E 10 9.5E 13 1.1E 08 73 TURB TRIP 6.8E-09 2.7E 10 3.7C 11 7.1E 09 4.$ l$0LATION 1.8E-08 7.1E 10 1.1E 11 1.9E-08 11.9 LOOP 2 - 4.1E-09 1.5E 11 4.2E 13 4.1E-09 2.6 LOOP 8 2.4E-09 9.6E 12 1.4E 12 2.4E 09 1.5 LOOP 8 + 5.8E 10 1.1E-09 6.0E 11 1.7E 09 1.1 SBO2 6.6E 12 6.7E 08 6.7E 08 42.9 SBO8 2.6E-08 2.6E 08 16.7 SBO8+ 1.5E-08 8.9E 10 1.6E 08 10.3 IORY 1.1E 09 2.0E 10 9.$E 13 13E 09 0.8 SBLOCA 2.5E 10 2.5E 10 0.2 ATWS 1.5E 10 1.5E 10 0.1 TOTAL 4.4E 08 2.6E 081.5E 08 8.9E 10 7.0E 08 1.1E 10 2JE.10 IJE 10 137E 07 100 OFFSITE RELEASE GROUP LCHP SRRC LCLP AC LBLC A1WS TOTAL CASE CASE 1 3.4E 09 7.9E 10 1.6E-08 5.1E 11 2.0E 08 CASE 2 7.8E 11 7.8E 11 CASE 3 13E 12 1.3E 12 CASE 4 0 CASE 5 63E 12 63E 12 CASE 6 1.2E 10 1.2E 10 CASE 7 1.1E 10 2.6E 10 3.70E 10 CASE 8 2.1E 10 2.1E 10 CASE 9 1.1E 12 1.5E 10 1.5E 10 NCL(N) 4.0E48 1.5E-08 8.0E 08 2.0E 10 1.4E 07 TOTAL 4.4E 08 1.6E 08 9.6E 08 1.!E 12 2JE 10 IJE 10 1.57E 07 CONTRIB % 28.1 10 3 61.4 0.122 0.2 0.1 100
' For description see Section 19E.2.2 Amendment 24 19P 2 3
ABWR um,,s p ,, ,s Standard Plani SECrlON 19P.3 TAllLES Iahic lith Eage 19P.31 ModiGeations Considered 19p3 2 19P3 2 ModiGeations Evaluated 19pj.4 19P3 il Amendment 24
i i i ABWR 2mios
- Standard Plant %4 4 10P.3 POTENTIAL ABWR MODIFI.
4 TIONS I i weie 4 Potential modifications to the ABWR design we 4 3 derived from a survey of varic,m, studies indicated in i references 19P.8.1 through 19P.8.7 and the ABWR V desigDdiscussed in Section 19.7. From these, a Ije5 composite list of modifications crridmd an pd. r Mps was 6 hen established. This list of potential modifications was resiewed to identify l concepts which were already included in the ABWR 4 design or which are not applicatile. 1 l l Table 19P.31 summarizes the complete list of j modifications and their classification according to the j following categories: j 1. Modification is applicable to ABWR and already Incorporated in the ABWR design. No further evaluation is neededf. Table 19P.31 provides a g cross reference to,supportingAcetion of the SSAR.) i j 2. Modification is applicable to ABWR and not 4 incorporated in ABWR design. (Table 19P.3 2 lists the Category 2 modifications which are evaluated further in this report.) i, ' f j 3. Modification is not applicable to the ABWR design due to the basis provided. l t L 4. Modification is applicable to ABWR and !s i incorporated with the referenced modification t I 1 i I t Amendmen 24 19r.3.t 4 I f g ,- , ~ws---,v., e,~ -,, mere-,,,n, ..m,,-,,.-,,,,--,-,--w..,n--.. , . . , - - , , wv,,,-,m, y m ~ y--- , - - +-- -g..
ABWR 2amms Standard Plant Re% d i Table 19P.31 MODIFICATIONS CONSIDERED f Itasis Reference (SSAR g g, g ,,, y ) 4 Modification Category Reference)
- 1. ACCIDENT MANAGEMENT
- a. Severe Accident EPGs/AMGs 2 1
- b. Computer Aldedinstrumentation 2 1
- c. Improved Maintenance Procedures / Manuals 2 1
- d. Preventive Maintenance Features 4 Seetc 1
- c. Improved Accident Mgt instrumentation 4 See Ib 1
- f. Rernote Shutdown Station 1 (7.4.2) 1
- g. Security System 1 (13.6 3) 1
- h. Simulator Training for Severe Accidents 4 See Ib 1
- 2. REACTOR DECAY HEAT REMOYAL
- a. Passive High Pressure System 2 1
- b. Improved Depressurization 2 1,2,3,5
- c. Suppression PoolJockey Pump 2 1
- d. Improved liigh Pressure Systems 1 (63) 1
- c. Additional Active liigh Pressure System 1 (63) J$ ,in W
- f. Improved Low Pressure System (Firepump) 1 (".*l.g)V 1,2,3 ( r.v.7 t to)
- g. Dedicated Suppression Pool Cooling 1 (6.2.2) 1,2
- h. Safety Related Condensate Storage Tank 2 1
- 1. Extended Station Blackout injection 4 see 10e 1
- j. Improved Recirculation Mode 3 PWR 3
- 3. CONTAINMENT CAPAlllLITY
- a. Larger Volume Containment 2 1,4
- b. Increased Containment Pressure Capacity 2 1
- c. Improved Vacuum Breakers 2 1
- d. Increased Temperature Margin for Seals 1 (19F3.2.2) 1,4
- e. Improved Leak Detection 1 (73.2) 3 j f. Suppression Pool Scrubbing 1 (19E3 2) $
Improved Bottom l'nd ;L . L':: "-id
- g. 2 6 ., e < r.n m. w
- 4. CONTAINMENT HEAT REMOVAL
- a. Larger Volume Suppression Pool 2 1
- b. RWCU Decay Heat Removal 1 (19 3) 2
- c. High Flow Suppression Pool Cooling 1 (6.2.2) 1,4
. d. Passive Overpressure relief 1 (i ' 3(2)) 1,2,5 y (s.a.r.e.6)
- 5. CONTAINMENT ATMOSPHERE MASS REMOYAL
- a. High Flow Unfiltered Vent . 3 Mark Ill 1,4
- b. High Flow Filtered Vent 3 Mark til 1,4
- c. 2 1,2,3,4 Low Flow (Gitered) Vent
- d. (44G 4}- 1,2,3,4 Iow Flow Vent (unfiltered) 1 g-1: 2- ) b (l t. J'. L . 4 )
Amendment 24 19P.3-2 l
ABWR u-s Standard Plant an A Table 19P.31 MODIFICATIONS CONSIDERED (Continued) Basis (SSAR Modification Category Reference) Reference
- 6. COMHUSTIBLE GAS CONTROL
- a. Pot,t Accident inerting System 3 Inerted 1,4
- b. flydrogen Control by Venting 3 Inerted 1,4
- c. Preinerting 1 Inerted 1,4
- d. Ignition Systems 3 Inerted 1,3,4,6
- c. Fire Suppression System inerting 3 Inerted 1,4
- 7. CONTAINMENT SPRAY SYSTEMS
- a. Drywell Head Flooding 2 2
- b. Containment Spray Augmentation 1 (490-?) 1,2,3,6 8 fes/ < 1 1. te t o
- 8. PREVENTION CONCEFIS
- a. Additional Senice Water Pump 2 3
- b. Improved Operating Response 1 (7.7.2) 1
- c. Diverse Egr !5 Systen& h *, ** h a 4 See 2a - 1
- d. Operating Experience Feedback 1 1
- c. Improved MSIV/SRV Design 1 (5.4 J 5.4.13) 1
- 9. AC POWER SUPPLIES
- a. Steam Driven Turbine Generator 2 1
- b. Alternate Pump Power Source 2 1
- c. Deleted
- d. Additional Diesel Generator 1 (83.1) 1,3
- c. Inctcased Electrical Divisions 1 (83.1) 1
- f. Improved Uninterruptable Power Supplies 1 (83.1) 1
- g. AC Bus Cross-ties 1 - (83.1) I
- 9
- O l'
- h. Gas Turbine 1 (AM(4)PI
- i. Dedicated RHR (bunkered) Power Supply 4 See 2g 1
- 10. DC POWER SUPPLIES
- a. Dedicated DC Power Supply 2 1
- b. Additional Batteries / Divisions 4 See 10e 1
- c. Fuel Cells 4 See 10e 1
- d. DC Cross ties 1 (83.2) 1
- c. Extended Station Blackout Provisions 1 (19E.2.1.2.2) 1,3
- 11. A'IWS CAPABILIW
- a. ATWS Sized Vent 2. 2,4,6
- b. Improved ATWS Capability 1 (19.7.2(2),(4)) 1,5,6
- 12. SEISMIC CAPABillW
- a. Increased Seismic Margins 1 3
(ttt:9(t))C' 0 9 0 Mark 111
- b. Integral Basemat 1
- 13. SYS1TM SIMPLIFICATION
- a. Reactor Building Sprays 2 2
- b. System Simplification 1 (13.5) I
- c. Reduction in Reactor Bldg Flooding 1 (19.73(4)) 5 Amendment 24 19PJ3
I 1 ~ j ABWR Standard Plant m ims n,y A , Table 19P.31 1 j MODIFICATIONS CONSIDERED (Continued) i ! Basis (SSAR ]_ 1 Modification Category Reference) Reference t i i 14. CORE RETENTION DEVICES i
! a. Mooded Rubble Bed 2 1,2,4,6
- b. Reactor Cavity Mooder 1 (!?'3{2); 3 - f *l < t e i t-
- c. Basaltic Cements 1 (19.7.3(4)) 1,4 i
1 i .) i j i I l e i f l a i j' , I ? 3 4 }
- i k; I i
{ i-4 : i i J t i 2 i.
- g .
l< $ Amendment 24 19P.34 I
*"w'-*t'r= F- ^-w 2w- -attv-+-e'r--~ v+y-- +, w yv,y-r--re-- e e w -+w w w-4 -w w m-e v &w- , w--y--""Mww e- * --e m- * - -
. ABWR nuums Standard Plant nu A 4 Table 19P.3 2 MODIFICAT!ONS EVALUATED l 1 ACCIDENT MANAGEMENT a. Severe Accident EPGs/AMGs i b. Computer Aided Instrumentation J
- c. Improved Maintenance Procedures / Manuals I 2 DECAY llEAT REMOVAL a. Passive High Pressure System I b. Improved Depressurization
- c. Suppression PoolJockey Pump
- d. Safety Related Condensate Storage Tank 3 CONTAINMENT CAPAHILITY a. Larger Volume Containment i b. Increased Containment Pressure Capacity
! c. Improved Vacuum Breakers
' d. Imptoved Bottom D ' :~ "-Hal M ws ewov ~ l 4 CONTAINMENT HEAT REMOVAL a. Larger Volume Suppression Pool f 5 Containment Atmosphere W Gas Removal a. L w Flow Filtered Vent t ! 7 CONTAINMENT SPRAY a. Drywe1111 cad Flooding i 8 PREVESTION CONCElTS a. Additional Service Water Pump 9 AC IWER SUPPLIES a. Steam Driven Turbine Generator l b. Alternate Pump Power Source 10 DC POWER SUPPLIES a. Dedicated DC Power Supply 11 A1WS CAPAHILITY a. ATWS Sized Vent j 13 SYSTEM SIMPLIFICATION a. Reactor Building Sprays i s p, / 14 Core Retention Devices a. Flooded Rubble Bed i grs** 4 ] i a f Amendment 24 ID ' i i
l ABWR 2mimas nn. A Standard Plant - . . SECTION 19P,4 CONTENTS Secilon Title East 19 P.4.1 Accident Manaarment 19P.41 19P.4.1.1 Severe Accident EPGs/AMGs 19P.4 1 19P.4.1.2 Computer Aided Instrumentation 19P.41 19P.4.13 Improved Maintenance Procedures / Manuals 19P.41 19P 4.2 Decay Heat Removal 19P.4 2 19P.4.2.1 Passive High Pressure System 19P.4 2 19P.4.2.2 Improved Depressurization 19P.4-2 19P 4.23 Suppression Pool Jockey pump 19P.4 2 19P.4.2.4 Safety Related Condensate Storage Tank 19P.4-2 19P.4.3 Containment Canability 19P.4 3 19P.43.1 Larger Volume Containment 19P.4 3 19P.43.2 Increased Containment Pressure Capacity 19P.4 .i 19P.433 Improved Vacuum Breakers 19P.4 3 fa., M k 0 w 19P.43.4 Improved Bottom -. ;.. L;... Mm.ial 19P.4 3 19P.4.4 Coa
- 8--ant Heat Removal 19P 4-4 19P.4.4.1 Larger Volume Suppression Pool 19P.4-4 19P.43 Containment Atmosnhere Mass Removal 19P.4 5 19P.4.5.1 Low Flow Filtered Vent 19P.4 5 19P.4.6 Combustible Gas Control 19P 4 6 19P.4.7 - Containment Sprav Svatem, 19P.4 7
- 19P.4.7.1 Drywell Head Flooding 19P.4 7 19P.4.8 Prevention Concents 19P.4 8 19P 4 il Amendment 24 i
l ABWR 2mmas Standard Plant nev ^ SECTION 19P.4 CONTENTS (Continued) Secilon litic l' age 19P.4.8.1 Additional Senice Water Pumps 19P.4 8 19P.4.9 AC Power Sunolles 19P.4 9 19P.4.9.1 Steam driven Turbine Generator 19P.4-9 19P.4.9.2 Alternate Pump Power Source 19P.4 9 19P.4.10 DC Pour Sunniles 19P.410 19P.4.10.1 Dedicated DC Power Supply 19P.410 19P.4.11 A'IWS Canabilltv 19P.411 19P.4.11.1 A1WS Sized vent 19P,411 19P.4.12 Schele Canability 19P.412 19P.4.13 Svstem S[ginlineation 19P.4-13 19P.4.13.1 Ret.: tor fluilding Sprays 19P 413 19P.4.14 Core Retention Devices 19P.414 19P.4.14.1 Flooded Rubble Bed 19P,4-14 TABLES Table Illit Pagt 19P.4-1 Summary of Benefits 19P 415 19P.4-lil Amendment a
ABM uxsimas Standard Plant ,__ %A r, 6./ 4 e a -' 19P.4 RISK REDUCTION OF already part of the ABWPy design. Additional X POTENTIAL MODIFICATIONS artincialintelligence could be designed which would dispisy procedural options for the operator to This section providcs evaluations of the benefits evaluate during severe accidents. The system would of potential modifications to the ABWR design be an extension of ERIS to provide human identified in Table 19P.3 2. For each modification engineered displays of the important variables in the the basis for the evaluation and the concept is EPGs and AMGs. described. Table 19P.41 summarizes the benefit in terms of person rem averted risk for each of the Operatur actions are made significantly more evaluated modifications, reliable by new features such as Emergency Procedure Guidelines, Safety Plant Parameter 19P.4.1 Accident Management Displays (SPDS), and training on simulators. If the improvements described in Subsection 19P.4.1.1 are Accident management is a current topic under assumed to be implemented d gn, the incremental ,<. generic development within the Industry through the p 3ed to be is ex development of Accident Management Guidelines (AMGS) and revisions to Emergency Procedure benefit w4k preventiveof additionalimprovement)'EMp "m7 ~ Guidelines (EPGs). The following modifications an incremental benefit over severe accident EPGs - "'M 4 tweden implementaiian of such generic ctivity. (Subsection 19P.4.1.1) is about 3% in core damage ,$.c.
" trequency (CDF). Because the improvement affects 19P.4.1.1 Snere Accident EPGs/AMGs all release cases, the incremental benent is about .01 perron rem.
The symptom based EPGs, were developed by the BWR Owners Group following the accident at 19P.4.1.3 Improved Maintenance - Three Mile Island, Unit 2. Currently 'he EPGs are Procedures /Mauals under revision and accident management guidelines (AMGs) are being developed for severe accidents. For the GE scope of supply this item would These should provide a significant improvement provide additionalinformation on the components which reduces the likelihood of a severe accident. important to the risk of the plant, As a result of Elements of these guidelines (such as containment improved maintenance manuals and information it pressure and temperature control guidelines) also would be expected that increased reliability of the deal with mitigating the effects of accidents. important equipment would occur. This item would be a preventative improvement which would address In the ABWR PRA, Emergency Operating several system or components to different degrees. Procedures (EOPs) are based on these guidelines Additional extensions of the EPGs and EOPs could Based on a 10% improvement in the reliability of be made to address arrest of a core melt, emergency the High Pressure Core Flooder (HPCF), Reactor planning, radiological release assessment and other Core Isolation Cooling (RCIC), Residual Heat areas related to severe accidents. Removal (RHR) and Low Pressure Core Flooder g (LPCF) systems, the CDF is reduced by about M1_. Q < s Since the existing EPGs cover preventien actions which has a corresponding estimated person-rem and some mitigative actions, the incremental benefit reduction of about .016. of this item would be primarily mitigative, he reliability ognual actions associated with p
. mitigation w*e improv-d by 10%, especialls in use Je M of core melt afrest proce.c- es,,the offsite risk weeki u , ,,, ,, , .e- F be reducT7about .015 person-rem over 60 years. T 1em , #v M+ * ^w
- W, ~~*^3 "*
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* #"'~~* " ~ '# ^
19P.4.1.2 Computer Alded lastrumentation Computer aided artificialintelligence can be added which provides attention to risk issues in man machine interfaces. Significant computer assisted display and plant status monitoring is Amendment 24 t9PA-1 i l
l ABWR m-s Standard Plant %3 19PA.2 Decay Heat Removal tne suppression pool would be through existing piping such as shutdown cooling return lines. Significant improvements in the reliability of ABWR high pressure systems have been made. The benefit of this modification would be similar Among these are RCIC restart (NUREG 0737, to that provided by the firewater injection and spray 11K3.13) and isolation reliability improvements capability, but it would have the advantage that long (NUREG 0737, ll.K.3.15). Additionally, the term containment inventory concerns would not redundant HPCF is an improvement over early occur, product lines which used the single HPCS system. c F N. %,,, r'-'Qj/. , If thgsystenr'gcould
/
make low pre sure coolant $ 19P.4.2.1 Passi e liigh Pressure System makeup 10% reliable, significant red :tions in CDF would not be achieve ' A cause other low pressure This concept would provide additional high systems are alreac li 7 reliable. 'he estimated pressure capability to remove decay heat through a benefit is that CN teduced diverse isolation condenser type system. Such a person-rem wee 4.d. / - 7 / J. 02 JS system would have the advantage of removing not only decay heat, but containment heat if a similar [, b4*khM 19P.4.2.4 Safety Related Cor&nsate Storage Tank
,c system to that swn.; for the Simplified ABWR,is employed ~ '- c ~ r . .< 4 , The current ABWR design consists of a standar4 L0s-) ,,.., m non seismically qualified Condensate Storage Tank The benefit f this system would be equivalent to (CST). This modification would upgrade the an additional CIC system in addition to an structure of the CST such that it would be available additional cont _ainment heat removal system. ifThe to provide makeup to the reactor following a scismic es%j ~ added system was 90% reliable, designed to operate event. y j,,8 p^"~~~~ ,g,,,
f independent of offsite in-vessel core melt power arrest,,the and benefit Gl to beMuth:,mble This o# modification only benefits the risks of core e .069 person rem averted. 9 -'- ,;"l,;^ 7
, damage following seisrgic e,vg./However, because
/
the suppressiopt pc - a.pn alternate suction 19P.4.2.2 Improved Depressurhation source and e+s HCLPF4relatively highrthe dominant failure modes are not limited by water This item would provide an improved depress- availability. Therefore the benefit of this urization system which would allow more reliable modification is considered small. A benefit of 0.1 access to low pressure systems. Additional person-rem averted was arbitrarily chosen for an/ ', depressurization capability may be achieved through upgraded CST. / manually controlled, seismically protected, air '
/
powered operators which permit depressurization to be manually accomplished in the event of loss of DC control power or control air events. D's*& 4 The ABWR high pressure core damage events 'E) represent about 28% of the total core damage mie,N but about 46% of the offsite expo,sure risk. 4fhe
- succ {,magal initiation were assumed to be **'+ M 5 50%%ess by a factor of 2o,dep"ressurizationf..agure e
Offsite c dM' reduced by rate /Mreduced about 23% and e estimated benefit is about .042 pctson-rem. 6 .e < o o e"~ * */ **N 19P.4.2.3 Suppression Pool Jockey Pump This modification would provide a small makeup pump to provide be low pressure decay heat removal from the Reactor Pressure Vessel (RPV) using suppression pool water as a source. eturn pab m 19P42 Amendment 24 y l
i ABM 2munas Standard Plant wA 19PA.3 Containment Capability normal containment leakage, the person. rem risk 4 would be about .02 person tem /60 years. Therefore, The ABWR containment is desigied for about 45 the benefit would be about .16 person. rem. y psig internal pressure and includeFa containment rupture disc which would relieve excessive pressure if 19P.433 Improved Vacuum Breakers it develops during a severe accident. By providing the telease point from the wetwell airspace, The ABWR design contains single vacuum mitigation of releases are achieved through breaker valves in each of eight drywell to wetwell J scrubbing of the fi:sion products in the suppression vacuum breaker lines. The PRA included failure of pool. vacuum breakers in " Case 2* assuming operation of wetwell spray. This modification would reduce the 1 I 19P 43.1 Laqger Volume Containment probability of a stuck open vacuum breaker by making the valves redundant in each line and 3 This modification would provide a larger volume climinate the need for operator action. . containment as a means to mitigate the effects of
- + severe accidents. By increasing the size,the if Case 2 sequences were climinated, the benefit containment could be able to absorb additional of this modification would be about .00003 l noncondensible gas generation and delay activation person rem averted.
of the containment rupture disc or early containment %.s p A p,,, y __ < failure, 19P 43.4 Improved BottomM"-!:p,- Li.I 2.- The ABWR design includes a# q., L J/::cI/ ( ~ 3*1 ~ - "
'This item would mitigate the e4eet of an accident cr. 2:
i by delsying the time before the severe accident drainline from the bottom of the RPV which is used
- source term is released and allowing more time for to prevent thermal stratification in the RPV during a ra**%~ , f recovery of systems. However,if recovery does not operation and to pro'ide cleanup of the bottom head , o,o if.
4 "" ~l occur, eventual release is not prevented and if by the RWCU system.EDuring a severe accident this r-s.d'- . operation of the containment overpressure rupture dlfMScTa%e susceptible to melting and may ,C 7 disc does not occur, ultimately the containment will provide the earliest path for release of molten core w.. / - * ^ fait due to the long term pressurization caused by material from the RPV to the containment. **"" i core concrete interactionm s **-. pe-.eM** . / /-' h # b The modification is to change theArm4mc ~7" If $ +. ~~ /~/.f*,!.~,J.".<i'W~[*ll )'amateria to leonel or Stainless Steel which has rtri4ng-t&mbM
- sequeneenavolving ; lcu ef ceraainment-hvat higher melting point. By so doing, additional time - Tw
"^
- -d the offsite risks would be reduced by about would be available for Lecovery of core cooling .
! systemsetrrhe bene _0t of W*s modification *would be y3.% and about .y person rem would be averted. I to reduce the probability of in vessel arrest failurW4 19P.4J 2 lacreased Containment Pressure Capacity (NO IV). Based on consideration of the heatup rate """ N of the bottom head, it has been estimated that TheMRM pressure of tSc containment 3 49I'"*WMal could provide up to is 45 psig,andpe containment rupture disc pressure two hours additional time for recovery of systems. It and ultimate capability are significantly higher. By is estimated, based on engineering judgement, that increasing the ultimate pressure capability of the this time could result in the invessel arrest failure containment (including seals), the effects of a severe probabilities being reduced by a factor of two. The accident could be reduced or climinated by delaying resulting benefit is about Od7 person rem aserted. the time of release. If the strength exceeded the , a #7 maximum pressure obtainable in a severe accident, A,p .Jnegative aspect of the modification *is tha only normal containment leakage would result.~ failure could occur at another unknown location such as CRO gn:!ntka; r the bottom head iiscif p This modification would mitigate the evekt,iset Although the time of vessel failure would be not change the core damage frequency anttlie extended, the failure mode from these other increased pressure capab;11ty may not be sufficient to locations could be potentially more energetic and contain the long term pressurization caused by core lead to unevaluated consequences, concrete interaction However,,if it were able to 1
- prevent all severe s rce term release except for l l
Amendment 24 tT 4 I , A f tw* I y,e,P*~ l 1 l l a
. . . . -. . .~ - . ,- - s..~ , ~~ .- - .. ....... - . . ~. - - . - ~. . - -
l' i i INSERT A The penetrations for the f'ine motion control rod drives in the ABWR also may provide a pathway for release fron. the .l RPV following a' severe accident. Falture of the internal l I . blowout s p ris on the tower core plate, provided to l 1 ellelnate the support structur" in current generation BWRs, i and welds of the drives at the bottom of the vessel may allow the CRDs to be partletty ejected into the drywell during the severe accident which would provide e small-l '.
- pathway for release to the contalrunent.
, INSERT B i . This modification also would establish external welds or restraints on the CRDs external to the vessel so that the i drives would not be ejected following failure of the
. internal welds. The concept would be to make such external welde and supports small enough thet the benefit is not
. Lost from eliminating the support beams in current ! -' generation BWRs. _ a s:
~
i } i 4 e e i = 4. i-s i
- j. '
e 4
'W 1 y w- g 9 w. - y- w ye pw. e w --g-.g.3 y. rse e-.,g ,ypy,ay w g-y--er .* WT @ y---wga
-- . . .- . . . ~ . . . _ _ - - - . . - _ - . - , - _ _ ---.-.-. - - - . . - _.
23A6100AS ' Standard Plant a,, 4 -- 19P.4.4 Containment Heat Removal The ABWR design contains 3 divisions of l suppression pool cooling and provisions for a l containment rupture disc for decay heat removal, in ) addition, modifications have been made to use the RWCU heat exchangers to the maximum extent possible. Consequently. loss o containment heat removal events contribute only .1% of the total core damage frequency and offsite exposures. Additional modifications are not likely to show substantial safety
- benefits.
19P.4.4.1 Larger Volume Suppression Pool This item would increase the size of the suppression pool so that the heatup ra t in the pool is reduced. The increased size would allow more time for recovery of a heat removal system. Since this modificatiortprimarily affects LHRC events (see Table 19P.2-2J), the maximum b;nefit
-~
would be elimination of the LHRC contribution to - the Case 9 sequences. These events are mitigated by the containment rupture disc and only contribute about .0002 person-rem to the base case risk. The assessed maximum benefit is therefore about .0002 person rem. 1 l l 1 Amendment 24 19P 4-4
_ _.._.. _ _ _ ... _ .. . _ _ _ . _ . ~ . . _ _ _ _ . - . . .
=
MN 23A6100AS Standard Plant no 3 ) 19P.4.5 Containment Atmosphere Mass Removal-l The ABWR design contains a containment i rupture disc which provides containment
- overpressure protection from the wetwell airspace l and utilizes the suppression pool scrubbing feature of the suppression pool to reduce the amount of l
radioactive material released. One additional
- modification was considered.
-19P.4.5.1 Low Flow Filtered Vent .
Some BWR facilities, espscially in Europe, i recently have added a filter system external to the ! containment to further reduce the magnitude.of j radioactive release. The systems typically use a - multi venturi scrubbing system to circulate the j exhaust gas and remove particulate material. In the
- ABWR, because of the suppression pool scrubbing -
- l. capability, a significant safety improvement is not
- - expected due to this modification.
i
.The release of radioactive isotopes from the.
i ABWR following severe accidents occurs through ! the containment rupture disc for Cases 1,2 and 5. l These sequences total about 8% of the exposure risk. The remaining sequences involve drywell head ! failure or early containment failure which would not .
- j. be affected by this modification. The maximum j benefit of the external vent system is therefore about-l
.014 person rem assuming perfect initiation of the j_ filtered containment vent system.
l I 9 i i J i- _ i Amendment 24 ' 19P 4-5 j^ j. s
ABWR m ei m s Standard Plant ac A 19PA.6 Combustible Gas Control No additional modifications to the ABWR were identified in this group. Amendment 24 19P 4-6
ABWR- m
.i, Standard Plant %3 19P.4.7 Containment Spray Systems 19P.4.7.1 Drywell Head Flooding This concept would provide intentional flooding of the upper drywell head such that if high drywell temperatures occurred, the drywell head seal would not fail. Additionally,if the seal were to fait due to overpressurization of the drywell, some scrubbing of the released fission products would occur. This system would be designed to operate passively or use an AC independent water source.
Q If an extension of the/tre pump to drywell spray crosstle were considered for manualinitiation of upper head flooding, additional reduction in the high temperature containment failure sequences (Case 8) would result. Additionally, a reduction in the high consequence drywell head failure sequences (Cases 6
"[/4f and 7) could be achieved. If Case 8 sequences were eliminated and Case 6 and 7 source terms were 4',
reduced to a level similar to Case 3, the conservative benefit would .10 person rem. The estimated f benefit of this is a ut person-rem assuming a 50% reliability of in' lation.
.o k
.?
19P.8-7 Amendment 24 ___-__-____-_-_______2_--_____._---_-__--__ _ - _ - -
ABWR msims wa Standard Plant 19PA.8 Prevention Concepts The ABWR design contains an additional division of high pressure makeup capability to improve its capability to prevent severe accidents other features such as the fire pump injection capability and the combustion gas turbine have been included in the design to enhance the plant capability to prevent core damage. The following additional concepts were considered: 19P.4.8.1 Additional Service Water Pumps This item addresses a reduction in the common cause dependencies through such items as improved manufacturer diversity, separation of equipment and support systems such as service water, air supplies, or heating and ventilation (HVAC). The HPCF, RCIC, and LPCF pumps are diverse in the ABWR design since they are either supplied by different manufacturers or have different flow characteristics. Equipment is separated in the ABWR design in accordance with Regulatory Guide 1.75. Thus, no further improvement is expected with regard to separation. Common cause dependencies from support systems such as service water systems, could conceivably reduce the plant risk through an improvement in system reliability. The concept for this item would be to provide dedicated support systems for each of the four diverse injection systems identified above. The current design provides support to these systems from one of three divisions. Thus, the effect of this change would be to include additional support systems. In addition, diversity in instrumentation which controls these systems could be included so that redundant indication and trip channels would rely on diverse instrumentation. A 10% increase in the reliability of the four systems was assumed which is the same improvement that may be derived from improved maintenance (Subsection 19P.4.1.3). This results in an estimated benefit of about rson-tem.
,o O tw a -
Amendment 24
AMM Standard Plant 23A6100AS n,, a l 19P.4.9 AC Power Supplies 3 y The current ABWRJ1ectrical design is improved i through application ofa gas-turbine generator to
- augment the offsite electrical grid. The following
- concepts were considered for additional on site
- power supplies.
j 19P.4.9.1 Steam Driven Turbine Generator i
- A steam driven turbine generator could bc
} installed which uses reactor steam and exhausts to the suppression pool. The system would be
- conceptually similar to the RCIC system with the generator connected to the offsite power grid,
] i i The benefit of this item would be similar to the addition of another gas turbine generator, but would be somewhat less due to the relative unreliability of - the steam turbine compared with a diesel generator j and its unavailability after the RPV is depressurized. If it were sized large enough,it could have the ,j advantage of providing power to addition f, } _ j equipment. _ if the system has a 80% bility for all events, g/ the benefit is similar to eduction in the diesel . J a A *- */
- j
' generator common mode failure rate 4th resulting e*"*** benefit is c""" f about .052 person-rem. W f 19P 4.9.2 Alternate Pump Power Source i j' 'he ABWR provides separate diesel driven j power supplies to the HPCF and LPCF pumps. j Offsite power supplies the feedwater pumps, This
- modification would provide a small dedicated power source such as a dedicated diesel or gas turbine for l the feedwater, or condensate pumps so that they do
! not rely on offsite power.
j- The benefit would be less dependence on low
- pressure systems during loss of offsite power events t and station blackout events. If the feedwater system were made to be 90 % available during loss of offsite 1- power events and station blackouts, the benefit would be similar to adding an additional RCIC i
system The resulting benefit would be about .069 perso rem. I
. g y .t*I )
L I (pff Y p,V .. i l 19PA-9 Amendment 24 I I i !
I
- - ABWR- uuimas 1
[ Standard Plant ac A
- 19PA.10 DC Power Supplies
! The ABWR contains 4 DC divisions with sufficient capacity to sustain 8 hours of station j blackout (with some load shedding). This represents
)
i 1
- an improvement over current operating plant 3
designs. 4 l 19P.4.10.1 Dedicated DC Power Supply This item addresses the use of a diverse DC l power system such as an additional battery or fuel
- cell fut the purpose of providing motive power to j certain components; Conceptually a fuel cell or separate battery could be used to power a DC motor / pump combination and provide high pressure RPV injection and containment cooling. With
- proper starting controls such a system could be sized to provide several days capability.
Providing a separate DC powered high pressure l injection capability has a benefit of further reducing j i- the station blackout and loss of offsite power event { risks which represent about 75% of the total CDF, but only a small fraction of the offsite risk, if the
- effective unavailability of the RCIC is reduced by a-i factor of 10 due to the availability of a diverse system, one benefit would b[eand similar to adding a
! power supply for feedwate (19P.4.9.2) the benefit would be about 4069 person-rem. h s00 ' i I, 1 p l e i l i, 19P.4-10 ! Amendment 24 4 4
ABWR zuums Standard Plant ne u 19P.4.11 ADVS Capability The current ABWR design provides improvements in containment heat removal and detection of ATWS events to limit the impact of this class of events. The PRA indicates that ATWS events contribute about .1To of the core damage frequency,and about 17Pc of the offsite riskt t.~ a ) . [ p . t.vtl 19P.4.ll.1 ATWS Sized Vent This modification would be available to remose reactor heat from ATWS events in addition to severe accidents and Class 11 events. It would be similar to the containment rupture disc (which is currently sized to pass reactor power consistent with,RCIC __ g 7"*" j / injection), but it would be of the larger size required F'd to pass the additional steam associated with LPCF injection. The system would need to be manually initiated. The benefit of this venting concept is to prevent core damage and to reduce the source term available for release following ATWS events. The evaluation shows that an ATWS sized vent manually initiated with a 1007o reliability would rmhnstte ottsite dose by about .03 person-rem by reassigning the
#[}N[
f,y..,Jy consequences from case 9 to case 1. 19P.4-It Amendment 24
ABWR mei as Standard Plant an a 19P.4.12 Seismic Capability The current ABWR is designed for a Safe Shutdown Earthquake of .3g acceleration The seismic margins analysigaddresses the margins associated with the seismic design and concludes that there is a 95% confidence that existing equipment has less than a 5% probability of failure at twice the SSE level. This capability is' considered adequate for the ABWR design and no / additional changes are considered. pn fYV Amendment 24 19P 412
ABM ussimas Standard Plant a, 3 19P.4.14 Core Retention Devices Core retention features are incorporated into the i ABWR Design. A)lidiscussed in Appendix 19E.2,if a severe accident has resulted in a loss of RPV integrity, accident management guidance specifies that drywell sprays be initiated which will cause the suppression pool to overflow into the lower drywell after a few hours and quench the debris bed. After the molten core has been quenched, no further ablation of concrete is expected and the decay heat can be removed by normal containment cooling methods such as suppression pool cooling. If sprays can not be initiated, the Lower Drywell Flooder _ g 9, y, , u System described in Ap~ ah !?C-$ cools a debris bed by flooding over the molten core in the lower drywell with water from the suppression pool. This system is similar to the " Post Accident Flooding" concept included in Reference 19P.8.4 One additional concept from Reference 19P.8.4 is included. 19P.4.14.1 Flooded Rubble Bed f C bis concept consists of a bed of refractory pebbi which fill the lower drywell :avity and r,ctain the molten 3rc above the water introducedJr6m the suppression p 1 as in the current deign. The system is superio the post accid,en[ flooding case j / in assuring that co coner,cte interaction is terminated and it woulc educe any uncertainty N[.@ 7 associated with the heat'tr sfer upward from ,,,/(*I'g the operation of Il f molten material which is assume the post acciden).flo'oding system.
,/
The, benefit of tlis modification ' -s in a red,uctfon in the uncertaintv that the passive ing g sWtem will be effectivg FOnly sequences in which no p ',, U squid injection to the drywellEiEEe the rupture ***** disk. TW ::p::nnt: :ba,. ik us tiw Uass i ",* g, ., a < -';" . transaatse m M xqrren. A conservative '# estimate of the benefit of this concept over the existing design would bej! 15 d d.c Cm : cuent u - - 2._ u ." This corresponds to about.0tc .
- 8 person-rem averted.
4 - . .A - a f ray e - t < fte c ore e A i, Cses e A e =* 4 e m fn. .or
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A ott . ** < - */ feel.=*1 fa./*-e. rw ed Y/**"d* Jr / 9 4.L o
- do e *4*-* 4 & /),
4 f1e r i s + ef d
*/ e ~. o , e m .
191' 4 14 Amendment 24
19P.4.14.1 Flooded Rubble Bed This concept consists of a bed of refractory pebbles which fill the lower drywell cavity and are flooded with. water. The bed impedes the flow of molten corium and increases the available heat transfer area which enhances debris coolability. The use of thoria (Th02) Pellets in a multiple layer geometry has been shown to stop melt penetration; thus, preventing core-concrete interaction. Drawbacks to using thorium dioxide include
- j,..t # cost, toxicity, and the radiological impact of radon gas release into the lower drywell via thB thorium try :W Other refractories such as
<"7 alumina slow corium penetration but may fail to stop core-concrete contact. Other refractories may be susceptible to chemical attack by the corium and may melt at lower _ temperatures. Pebbles composed of refractories other than thoriardiay(alspbe susceptible to floating because they have a lower density than the corium. A major drawback common to all flooded rubble bed core retention systems is the need for further experimental testing in order to validate the concept s' r := =isA w 8+
a eit a s. -. . w -,,,;,/4 G,A d W The beneffof this modification lies in the potential elimination of core-concrete interaction and a corresponding decrease in non-condensible as generation, ktrh.T.= 1^EC indicates a 90% certainty thatgebm will e coolable in the current ABWR design,<0ebns on a concrete floor covered u+ tD-
.!i ...ui. For ttus reason,10% of the sequences that havTRHItrecovery were presumed to have containment failure because of continued core-concrete interaction. Without RHR recovery, containment failure would occur with the timing not being greatly affected by core-concrete interaction. Thus, the benefit ofinstalling of flooded pebble bed system which completely eliminates core-concrete interaction is a reduction in radiological consequence of ??? person-rem.
L _ The J<.e p ,,t n. <,6e n .~. u s<. #- H eA ~ o .f n ,,e rey-ee o s . * /. *-> c # # 4 en A
/N Y sM o'n s
ABWR 2mies Standard Plant a, A j Table 19PA 1
SUMMARY
OF BENEFITS i Potential ! Modification Manrem Averted 1 ACCIDENT MANAGEMENT
- la. Severe Accident EPGs/AMGs 0.015 j lb. Computer Aided Instrumentation 0.010 i-
. 2 DECAY HEAT REMOVAL j 2a. - Passive High Pressure System 0.138 2b. Improved Depressurization 0.042 2c. Suppression PoolJockey Pump 0.002
- 2d. Safety Related Condensate Storage Tank 0.01 i
i 3 CONTAINMENT CAPABILITY ! 3a. Larger Volume Containment 0.M < d i 3b.- Increased Containment Pressure Capacity 0.02 - j 3c, improved Vacuum Breakers- 0.00003 3d. Improved Bottom '.". e'e..4. ""-"I t 0.057
- re o~. w 4 CONTAINMENT HEAT REMOVAL i 4a. Larger Volume Suppression Pool .0.0002 5 CONTAINMENT ATMOSPHERE GAS REMOVAL --
i $A. Low Flow Filtered Vent 0.014 i 7 CONTAINMENT SPRAY SYSTEMS p,,, i 7a. Drywell Head Flooding ! 8 PREVENTION CONCEliS ! 8a. AdditionalService Water Pump 0.016 ) 9 AC POWER SUPPLIES ! 9a. Steam Driven Turbine Generator 0.052 9b. Alternate Pump Power Source 0.069 I 10 DC POWER SUPPLIES 10a. Dedicated DC Power Supply' O.069
' 11 ATWS CAPABILITY -
d lla. ATWS Sized Vent 0.03-13 SYSTEM SIMPLIFICATION - _13a." Reactor Building Sprays 0.017 14 CORE RETENTION DEVICE - 14a. Flooded Rubble Bed - 0.0t12 .i co l 2-(' Amendment 24. 19PA-15 i a a
- , s-
ARWR 2mimas Standard Plant no ^ SECTION 19P.5 CONTENTS Section Illlt Eagt 19 P.5.1 Accident Manacement 19P.5-1 19P.5,1.1 Severe Accident EPGs/AMGs 19P.5-1 19P.S.I.2 Computer Aided Instrumentation 19P.51 19P.5.13 Improved Maintenance Procedures / Manual 19P.5 1 19P.5.2 Decay IIcat Removal 19P.5-2 19P.S.2.1 Passive High Pressure System 19P.5-2 19P.5.2.2 Improved Depressurization 19P.5-2 19P.5.23 Suppression Pool Jockey Pump 19P.5 2 19P.S.2.4 Safety Related Condensate Storage Tank 19P.5-2 19P.53 Containment Canability 19P.5-3 19P.53.1 Larger Volume Containment 19P.5 3 19P.53.2 increased Containment Pressure Capacity 19P.5-3 19P.533 Improved Vacuum Breakers 19P.5 3 on a 4 w h - c.>, . +~.- 19P.53.4 Improved Bottom Dd Lic.c N' a.;al 19P.5 3 19P.5.4 Containment IIcar_ Removal 19P.5-4 19P.5.4.1 Larger Volume Suppression Pool l'9P.5-4 19P.S.5 Containment Atmosohere Mass Removal 19P.5-5 19P.5.5.1 Low Flow Filtered Vent 19P 5-5 19P.S.6 Combustible Gas Control 19P.5-6 19P.5.7 CJmtainment Soray Systems 19P.5-7 19P.5.7.1 Drywell Head Flooding 19P.5-7 19P.5.8 Prevention Concent3 19P.5-8 19P.5 il Amendment 24
7 ABWR 23^cuo^s nev ^ Standard Plant SECTION 19P.5 CONTENTS (Continued) Section Illlt Eagt 19P.S.8.1 Additional Service Water Pump 19P.5 8 19 P.5.9 AC Power Sunnlles 19P.5 9 19P.S.9.1 Steam Driven Turbine Generator 19P.5-9 19P.5.9.2 Alternate Pump Power Source 19P.5-9 19P.5.10 DC Power Sunolles 19P.5 10 19P 5.10.1 Dedicated RHR DC Power Supply 19P.510 19 P.5.11 ADVS Capability 19P.5-11 19P.S.11.1 ATWS Sized Vent 19P.5-11 19P.5.12 Seismic Capabilltv 19P.512 19P.S.13 Sntem SimulincatID.n 19P.513 19P.5.13.1 Reactor Building Sprays 19P.5-13 19P.5.14 Core Retention Devices 19P.5 14 19P.S.14.1 Flooded Rubble Bed 19P.514 TABLES-Table Ihlt Eagt 19P.5-1 Summary Of Costs 19P.5-15 19P.5-lii Amendment 24 l
ABWR u-xs Standard Plant Rev A 19P.5 COST IMPACTS OF POTENTIAL 19P.5.13 Improsed Maintenance MODIFICATIONS Procedures / Manuals As discussed in Section 19P.13.1, rough order of The cost of at least $ 300,000 would be required to magnitude costs were assigned to each modification identify components which should receive enhanced based on the costs of systems determined by GE. maintenance attention and to prepare the additional These costs represent the incremental costs that detailed proccJures or recommended information would be incurred in a new plantjatg gan costs beyond that currently planned. Cr@t for reduction 4 that would apply on a backfit basis.jhc dnsite costs in onsite costs reduces the cost basis to $299,000, A averted by the modification are discussed in Section 19P.13.2. For each modification which reduces the core damage frequency an estimate of the impxt was made and then applied to the potential averted offsite cost. This section summarizes the cost basis for each of the modification evaluated in Section 19P.4. This basis is generally the cost estimate less the credit for onsite averted costs. Table 19P.51 summarizes the results. The costs were biased on the low side, but all known or reasonably expected costs were accounted for in order that a reasonable assessment of the minimum cost would be obtained. Actual plant costs are expected to be higher than indicated in this evaluation. All costs are referenced to 1991 U.S. dollars based on changes in the Consumer Price Index. 19P.5.1 Accident Management 19P.5.1.1 Severt Accident EPGs/AMGs The cost of extending the EPGs would be largely a one. time cost which should be prorated over several plants if accomplished by the BWROG. Current industry activity is addressing this as part of Accident Management Guidelines (AMG). If plant specific, symptom based, severe accident emergency procedures were to be prepared based on AMGs, the cost would be at least $ 600,000 for plant specific modifications to EOPs. 19P.5.1.2 Computer Aided lastrumentation Additional software and development costs associated with modifying existing Safety Pla , p- p ', Display Systems are estimated to cost at leas S e N P 600,000 for a new plant. This estimate is based on assumed additions of isolation devices to transmit C#p[Ig
** "f data to the computer and in plant wiring. Because this modification reduces the frequency of core damage events, a present worth of $400 onsite costs are averted and the cost basis is $599/40.
19P $-t Amendment 24
ABWR msionxs Standard Plant an 3 19P.S.2 Decay Heat Removal 19P.S.2.1 Passive liigh Pressure System The cost of an additional high pressure system for core cooling would be extensive since it would not only require additional system hardware which would cost at least $ 1,200,000, but it would also require additional building costs for space available for the system. Assuming the system could be located height, buildingin costs the are reactor estimated building without to be anothe $/ increasing (ljs 3
$50,000. The credit for averted onsite costs is aboot'
$6,000 which brings the cost basis to $1,744,000.
19P.5.2.2 Improsed Depressurization The cost of the additional logic changes, pneumatic supplies, piping and qualification was estimated for the GESSAR design (reference 19P.8.1), A similar cost would be expected for the ABWR design. The cost is estimated to be at lead 5 600,000 for an improved system for depressurizatio This estimate assumes no building space increase for the added equipment. The credit for averted onsite costs was evaluated to be $1,400 which makes the cost basis $598,600. 19P.5.2.3 Suppression Pool Jockey Pump The cost of an additional small pump and associated piping is estimated at more than 5 60,000 induding installation of the equipment. It is assumed that increases in/ower supply capacity and { building space are not required. Controls and associated wiring could cost an additional 5 60,000 for a total cost of at least $120,000. A credit of $200 for averted onsite costs makes the cost basis
$119,800.
19P.5.2.4 Safety Related Condensate Storage Tank Estimating the cost of upgrading the CST structure to withstand seismic events requires a detailed structural analysis and resultant material. It is judged that the final cost increase would be in excess of $ 1,000,000. No credit for onsite cost averted was assumed for this modification. Arnendment 24 IW M
, ABWR not s Standard Plant au 19P.5.3 Containment Capability 19P.53.1 larger Volume Containment Doubling the containment volume requires an l increase in the concrete and rebar. If structural costs of the containment can be made for $ 1,200 per square foot, doubling the containment volume
- without increasing its height, the cost would be at
- least $ 8,000,000. This estimate does not include reanalysis and other documentation costs. Since this modification is mitigative, no credit for onsite averted costs was assumed.
19PJJ.2 Increased Containment Pressure Capacity i j The cost of a stronger containment design would ' be similar in magnitude to increasing its size (see a Subsection 19P.53.1). If the costs are primarily due i to denser rebar required during installation andi additional analysis, an estimate of at least'$) 12,000,000 could be required. Since this modification is mitigative, no credit for onsite averted costs was j assumed. i 19P.533 Improved Vacuum Breakers The cost of redundant vacuum breakers including 4 installation and hardware is estimated at more thad s)' 10,000 per line. Instrumentation associated with thiv modification is not included. For the eight lines the f cost of this modification is more than 3 100,000. $ .e l Since this modification is mitigative, no credit for '/ r s , ',,#p $[,,',,r - onsite averted costs was assumed. , . f ,, r
- f 4a. M ceso n s eW'4;"'
19P.53.4 Improved Bottom Drein-4dee+teterial 1 a The cost increase of using, stainless or inconel %-a. im oeu d:n "r., .7 .a .d as opposed to carbon steel would i . j be e.xpected to be smallin comparision to the i erigenchring and documentation change costs 1
\
associated with the change.{uch changes arc (* 8 0 " "'M*~ .. estimated to be at least,5f4:000.
,,,... .e.- .- .- n ~
I Since this modification is mitigative, no credit for / , y , , averted onsite costs apphes, y 3,.m ,,.j ,4 s n u,a sa / e ~M .h2L .t .:m
- 19P.5-3 Amendment 24
ABWR nyims Standard Plant no 3 19P.5.4 Containment Heat Removal 19P.5.4.1 Larger Volume Suppression Pool This concept would result in similar costs as item Subsection 19P.5.3.1 for providing a larger containment. An estimate of $ 8,000,000 is assigned to this item. i 1 Amendment 24 19P.5-4
( . -.- - ..- ..~ .- -. -.-_. -_~ ... - . . . - . . --. . . . - - ~ ~ . . . . {. 23A6100AS
- Standard Plant . n,v A .
i 4
'19P.5.5 Containment Atmosphere Mass c -
Removal
- ' 19P.5.5.1 Low Flow Filtered Vent I
! The cost of added equipment associated with the FILTRA system _(excluding a test program) was estimated to be about $5,000,000 in Reference 19P.8.4. Athough a detailed estimate was not j. prepared for the ABWR, an estimate of $3,000,000 has been assumed for the purpose of this evaluation. !. Since this modification is mitigative, no credit for j averted onsite costs applies. 5 3 1 1 l. ], 4
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i i 1 h' N s s-l d i l' ) 4 1 i 1 t' 19P.5-5 Amendment 24 _ T Y
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ABWR ua6imas Standard Plant nev ^ 19P.5.6 Combustible Gas Control No additional modifications to the ABWR were identified in this group. 19P,54 Amendment 24
ABWR nyims Slandard Plant g,, ,3 19P.S.7 Containment Spray Systems 19P.5.7.1 Drpell Head Flooding i An additional line to flood the drywell head using existing firewater piping would be a relatisely inexpensive addition to the current system. ~ Instrumentation and controls to permit manual control from the control room would be needed, it is estimated that the total modification cost would be at least $ 100,000 for the engineering, piping, vahes and cabling. Because this modification is mitigative, no credit for averted onsite costs has been applied, 1 p)P s - Amendment 24
ABWR 2mimas Standard Plant an 4 19P.5.8 Prevention Concepts 19P.5.8.1 Additional Service Water Pump The use of diverse instrumentation would not presumably have a significant equipment cost, but there would be an increased cost of maintenance and spare parts due to less interchangeability and less standardization of procedures. These costs, however, are probably low in comparison with the extra support systems for air supply and service water. Equipment, power supplies and structural changes to include these new systems are estimated to cost at least S 6,000,000. A small credit for averted onsite costs makes the cost basis for this item $5,999,000, based on the benefits discussed in Subsections 19P.4.13 and 19P.S.13. 19P 3-8 Amendment 24
. --.. - . - ~ . . - - . - - . - . . . - - - . _ . - _ - - - . - . . . . - - . - _ _
ABM 234sioors a,, 4 .i Standard Plant e
! 19P.$.9 AC Power Supplies
. 19P.S.9.1 Steam Driven Turbine Generator The cost of the system should be similar to that y for the RCIC system, but additional cost would be j- needed for structural changes to the reactor building plus the generator and its controls. This item is expected to cost at least $ 6,000,000. ' i ' With credit for averted onsite costs, the cost basis i for this item becomes 5 5,994.300. i-ij 19P.5.9.2 Alternate Pump Power Source A typicalkeedwater pump for an ABWR sized 1 [ plant coul require a 4000 Kwe sired generetor, at
$300 per Kwe, a separate diesel generator and the i supporting auxiliaries could cost at least 51.200,000.
This cost would include wiring and installation of the ! alternate generator, but does not assume additional - structural costs.
~With credit foh averted onsite costs, the cost i
basis for this item becomes $ 1,194,000. 3 1 1 l 1 h i fI 1 1 I ? i I k ) 4 E I9I3*9
. _ AMCndmCGI 24 f
F l ( 2)A6100AS Standard Plant m3 Y j 19P.5.10 DC Power Supplies 4 - i 19P.5.10.1 Dedicated DC Power Supply l 4 l Fuel cells are largely a developmental
- . technology, at least in the large size range required 1
for this application. In addition the process involves
! some risk of fire. To address these concerns a cost of -
at least $ 6,000,000 would be expected. l 4
! A separate battery would be less expensive than j fuel cells, but would involve additional space requirements which could make this modification more expensive than adding a diesel generator as
- discussed in Subsection 19P.S.9.2. A battery bank
- capable of supplying 400 Kwe would be about 50 l times larger in capacity than the emergency batteries.
This number of batteries would require at least 5,000 square feet of space, assuming extensive stacking and ' without concern for seismic response, At
$500/ square feet construction cost, the additional
- space required would amount to $2,500,000 for this
- modification. Additional costs would be required for l
DC pumps, cabling and instrumentation a . controllers. A~ total cost would be at least $ j 3,000,000.- 4 } i J { .' i. 1-1-- t
' t9P.5 10 Amendment 24 i
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ABWR :3.%,ms S111Rditrd Plant an 3 19P.S.11 ABYS Capability 19PJ.ll.1 ATWS Sind Vent Larger piping and additional training would be required to extend the existing rupture disk feuure to be available during an ATWS event. Additional instrumentation and cabling would be required to make the sent operable from the control room it is estimated that the incremental cost would be at least $ 300,(XX). Amendment 24 19P3 1l
ABWR mams Standard Plant _ nna 19P.5.12 Seismic Capability No modifications were considered for this group. 191'3 10 Amendment 24
ABWR z wimas Standard Plant un_3 19P.S.13 System Simpillication 19P.$.13.1 Reactor flullding Sprays The cost of this modification is judged to be
$1milar to the cor:cpt of drywell head flooding (Subsection 19P.5.5.1) if it only involves piping and valves which are tied into the firewater system. An estimate of $ ItxMKK) has been assigned te this item.
Onsite cleanup costs also could be affected by this. modification. If the cleanup costs were clin /nated an averted cost would conservately be ahg$5,lXX). s J 4 Amendment 24 IVPL13
ABWR **[,] Sinndard 18l ant 19P.S.14 Core Retention Devices 19P.5.14.1 Flooded Rubble Ited Refrence 19P.8.4 est! mated that the refractory material needed for this modification would cost approrimately $ 1,000 per pound. If the lower drywell were filled with about 1.5 feet of this material, which would remain well below the senice platform, e' -' 1250 cubic feet of material would be requit. weigas l$ pounds / cubic feet, the material . < e would amount to 518,750,(K10. l l l l i Amendment 24 I9I'I'I4
ABWR :=uas
""^
Standard Plant -- Table 191'.51 SUSINIAltY OF COSTS hiodineation Estimated Cost i ACCIDENT hlANAGEhfENT la. Severe Accident EPGs $ UK)0K lb. Coreputer Aided Instrumentation $ SW.6K le. Improved hiaintenance Procedures /hlanuals $ 2W.0K 2 DECAY llEAT REhlOVAL 2a. Passive fligh Pressure System $ 1744.0K 2b. Improved Depressurization $ 598.6K 2e. Suppression Pool Jockey Pump $ 120.0K 2d. Safety Related Condensate Storage Tank $ 1(xxt0K 3 CONTAINhlEST CAPABILIW 3a. Larger Volume Containment $8000.0K 3b. Increased Containment Pressure Capacity $12fm0K 3e. Improved Vacuum Breakers $ 100.0K 3d. Improved Bottom Desn44eMaterial $A50eK .-< ro-e l o h e M.w ygo, ouz 4 CONTAINMENT llEAT REMOVAL 4a. Larger Volume Suppression Pool 58000.0K
$ CONTAINh1ENT ATMOSPilERE GAS REMOVAL
$ 3(xx).0K 4 $/.*' Filtered Containment Vent 7 CONTAINMEST SPRAY SYSTEMS 7a. Drywelllicad Flooding $ 100.0K 8 PREVENTION CONCEITS 8a. Additional Senice Water Pump $ 59.ROK 9 AC POWER SUPPLIES 9a. Steam Driven Turbine Generator $ 59943K 9b. Alternate Pump Power Source $1194.0K 10 DC POWER SUPPLIES 10a. Dedicated RilR DC Power Supply $ 3000.0K 11 ATWS CAPABILIW 11a. ATWS Sized Vent $ 300.0K 13 SYSTEM SIMPLIFICATION 13a. Reactor Building Sprays $ 100.0K 14 CORE RETENTION DEVICES 142. Flooded Rubble Bed $18,750.0K Amendment 24 N
ABWR mwmss Standard Plant n,y a SECTION 19P.6 TABLES Iahlt Illic l' age 19P.61 Summary Of Results 19P.6 2 19P.6 ii Amendment 24 l l
ABWR nui,,as Sinndard Plant an 3 1 i 19P.6 EVALUATION OF POTENTIAL MODIFICATIONS A ranking of the modifications by $/ person tem averted is shown in Table 19P.61 based on the results and estimates provided in Sections 19P.4 and 19P.S. j Ilo c> The lowest cost /; ctson tem averted modification is more than 800 times the target criteria of $ 1,000 per person tem averted. Clearly none of the modifications is justifiable on the basis of costs for person tem averted. This can be attributed to the low probability of core damage in the ABWR with the modifications to reduce risk already installed. 191- l Amendment 24
l ABWR mums
- Standard Plant n,, 4 4 Table 19P.61 Summary of Results ,
I (we.# Modincation Cost /Meeren Astried N . o. A- 4 .w S, a 59 3d. Improved Bottom DesmUne+taterial $ K"
- I 7a. Dr>well Head Flooding $ ggd t;%eK
*13a. Reactor Building Sprnys $ 5,8827 11a. ATWS Sized Vent $ 9,882K -
qd. Safety Related Condensate Storage Tank
$ 10.000K,
.b. Improved Depressurization $ 14.173K
- 96. Alternate Pump Power Source $ 17,351K t c. Improved Maintenance Procedures / Manuals $ 18,298K 2a. Passive High Pressure System $ 25,158K la. Severe Accident EPGs $ 39,834K 10a. Dedicated DC Power Supply $ 43,478K 3a. Larger Volume Containment $ 5# 1 t' lb. ' Computer Alded Instrumentation $ 60,000K 2c, Suppression PoolJockey Pump $ 62,130K 9a. Steam Driven Turbine Generator $ 114,726K Sa. Low Flow Filtered Vent $ 214,286K Sa, Additional Service Water Pump $ 375,000K 4b. RWCU Decay Heat Removal $ 425,000K 3b. Increased Containment Pressure Capacity $ 600,000K 3c, improved Vacuum Breakers $ 3,329,000K 14a. Flooded Rubble Bed $ 1^,3Go,0^0% -
4a. Larger Volume Suppression Poni $ 40,000,000K _ p# 1 )$0 D 1 19Ph2 Amendment 24 i l
- f. _ _ _ _ _ _ _ _,
ABWR 2mius Standard Plant _ m 19P.7
SUMMARY
OF CONCLUSIONS Potentially attractive modifications were identified from previous evaluations of potential prevention and mitigation concepts applicable during severe accidents and discussion with the NRC staff. Potential modifications were reviewed to select those which are applicable to the ABWR design and which have not already been implemented in the design. Of these modifications, twenty W*o were selected for additional review. The low level of risk in the A13WR is demon-strated by the total 60 year offsite exposure risk of
.183 person tem. At this level only modifications L which cost less than $ 183 can be justified. Ilased on this low level no modifications are justified for the ABWR.
$ ese of m m s4 M /r J A',s a None of the modifications provided a substantial improvement in plant safety.fhe most cost effective
, change waninimproverrMnt to the bottom head
( drain line material which was evaluated at more j than $ 800,000 per person tem averted. p_ l l 19P.71 l Amendment 24
k , ABWR mams i Standard Plant _ am i 1
- 19P.8 REFERENCES j 1. Evaluation of Proposed Modifications to the ;
L GESSAR 11 Design, NEDE 30640, Class Ill, ! June 1984. , 2. Supplement to the Final Environmental ! Statement . Limerick Generating Station, Units 1 j- and 2, NUREG 0974 Supplement, August 16, - j 1989
- 3. Issuance of Supplement to the Final Environmental Statement Commanche Peak Steam Electric Station, Units 1 and 2, NUREG-0775 Supplement December 15,1989
- 4. Survey of the State of the Art in Mitigation Systems NUREG/CR 3908, R&D Associates,
, December 1985 1
; 5. Assessment of Severe Aceldent Prevention and 1 Mitigation Features, NUREG/CR 4920, l -- Brookhaven National Laboratory, July 1988. ,
- 6. Design and Feasibility of Accident Mitigation
! Systems for Light Water Reactors, NUREG/CR ! 4025, R&D Anociates, August 1985 ': 7. Severe Accident Risks: An Assessment for Five !- US Nuclear Power Plants, NUREG 1150, January 1991, f
- 8. Technical Guidance for Siting Criteria j
Development, NUREG/CR 2239, Sandia National Laboratories, December 1982. [ 4 t i 4 4 f f , 'i l 4 I s Amendment N 19P 8 ;
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DCC 17 '92 03:14ft1 P.2 i i i k j t i l j
- 1 0
, TECHNICAL SUPPORT DOCUMENT FOR AMENDMENTS TO 10 CFR PART 51 l CONSIDERING SEVERE ACCIDENTS
- UNDER NEPA FOR PLANTS OF ABWR DESIGN l
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ICC 17 '92 03814AM P.3 TABLE OF CONTEN'I% F. AGE LI ST O F TAB LES . . . .. .. . . . . . . ... . . . . . . .. .. .. . . . .. . .. .. .. .. .. .. .. . . . . .. . . . . . . .. .. .. .. . .. .. .. . . . . . . . . . . . . .. .. .. .. .. . . EXECUTIVE SU MMARY... .... .. . . .. .. ....... .......... . . .. . . ... . .. ..... .. .. .. .. . .. .. . . . . .. .. .. ...... .. . . .. . ... . .. . . .. . . .. i l l 1.0 INTRO D U CTIO N. ... . . . . . .. . . . . . . .. . .. . .. . .. .. . . . . . . . . . . . . . . . . . . .. . .. . .. ... ... .. . . . . . . . . . . . . . . . . . . . . . . . . .. . 1.1 Background...............................................................................................................I 1.2 Purpose......................................................................................................... 2 1.3 Descripdon of Technleal Support Document........................................ 3 2.0 EVALUATION OF RADIOLOGICAL RISK FROM NORMAL OPERATIONS AND SEVERE ACCIDENTS IN PLANTS OF ABWR DESIGN......................... 3 1.1 Radiological Risk from Normal Operadons of an ABWR Plant ........ 3 f.2 Severe Accident Conclusions from Chapter 19 of ABWR SSAR........... 3 2.3 Overall Conclusions regarding Severe Accidents for ABWR Desi Remote and Speculadve Severe Acddent Sequences........................ .... 6 2.4 Socio. Economic Risks for Severe Accidents ........................................... 7 2.5 Uncertalnties in Severe Accident Evaluadon......................................... 7 2.6 Overall Conclusions from Chapter 19 of the ABWR SSAR................... 8 3.0 EVALUATION OF SEVERE ACCIDENT MITIGATION DESIGN ALTERNATIVES (SAMDAs) UNDER NEPA......,................................................ 8 3.1 Candidate SAMDAs for the ABWR Design .............................................. 8 3.2 Evaluadon of SAMDAs under NEPA and Limedek Ecology Action.. 8 i 3.3 Cost /beneat Standard for NEPA Evaluadon of SAMDAs.................... 9 4.0 COST. EFFECTIVENESS EVALUATION OF POTENTIAL MODIFICATIONS l TO THE ABWR D ESI GN. . .......... ...... .. .... ...... ............ .. .... .. .. .. ...... ...... .. .. .. . ... .. .. ........ 10 4.1 Cost Esdmates of Potential Modifications to the ABWR Design.......10 4.2 Evaluadon of Bene 8ts of Potendal Modl5cadons to ABWR Design 10 4.3 Cost / Bene 8t Comparison of SAMDAs.................................................... 10 5.0
SUMMARY
AND CONCLUSIONS ............................... .................................... .. 10 l NEPA/SAMDA. page i DRAFT December M.1992
ECC 17 '92 03814ft1 P.4 6.0 REFEREN C ES . . . . . . . . .. . . . . . . . . . . .. .. .. .. . . . . . . . . . . . . . . . . . . . . . . .. . . .. .. . . . . .. .. . . .. . . . . . .. . . . . .. l l
- NEPA/SAMDA, page il DRAFT December 17,1992
DEC 17 '92 03: a5(41 P.9 4 LIST OF TABLES 1 i Table 1: Severe Accident Risk Reducdon Alternadves Enluated for ABWR Design..........................................................................................................13 l Table 2: Severe Accident Risk Reduedon Features Incorporated into the
- ABWR D e si g n . .. .. . . . . . . . . . . .. .. .. .. .. . . . . . . .. .. . . . . .. . . . . .. .. . . . . . . . . . . .. . . . . . . . . .. .. .. . . . .. .. .. .... .. . . . 14 i
Table 3: SAMDAs not Appilcable to ABWR Design............................................ 15
! Table 4: Esdmated Costs of Each Potential Modl6 cation to the ABWR Design........................................................................................................16 Table 5: Basis for Assigning Benefit to Each SAMDA Evaluated.................... 1/
T a t.e 6: Cost.Effeedvenen Quodent for SAMDA Evaluation .......................... 18 I 4 4 3 ) i 4 i i 4 I e 1 4 NEPA/5AMDA page til DRAFT December 17.190s _-. 2. , . . .-. . , . . - - - - - . - - - - . . .
CCC 17 '92 03819AM P.6 i i .i j EXECUTIVE
SUMMARY
l ' ne term " severe accident" refers to those events which are "b coverage of design basis events" and includes those for ere whichbond is substandal the substand j damage to the reactor core whether or not there are serious o5eite consequences, j nee Severe Accident Policy Statement,50 Fed. Reg. 32,138,32,139 (August 8,1985). For
- new reactor designs, such as the ABWR, the Nuclear Regulatory Commission (NRC),
! in satisfaction among other things, of the its severe evaluationaccident of design safety alternadves requirements to reduce theand guldance, is requ radfologica ! risk from a severe accident by preventing substantial core damage (i.e., preventing a ! severe accident) or by limiting releases from the containment in the event that ,
i substantial core damage occurs (i.e., mitigadng the impacts of a severe accident). ! The Nadonal Environmental Policy Act (NEPA) re uires the consideradon of reasonable alternatives to proposed major Federal actions signl8cantly afeedng the j q uality of the human environment, including alternatives to mitigate the trapacts of ; { tme proposed action. In 1989, a Federal Court of Appeals determined that NEPA-
- required consideration of certain design alternatives; namely, severe accident j= mitigation design alternatives (SAMDAs), see iherM Erninev Aedon v. NRC,869 i
i F.2d 719 (Srd Cir.1989). ne court indicated that "[SAMDAs) are, u the name suggests, 1 accident,but possible to lessenplant designofmodi the severity 5cadons the impact of anthat accidentare intended should onenot to prevent an occur." i li at 731. The court rejected the use of a policy statement as an acceptable basis for i ' closing out NEPA consideration of SAMDAs in a licensing proceeding, because. among other things, it was not a rule making, see id, at 739. Recently, the NRC Stas expanded the concept of SAMDAs to encompass design 3 alternatives to prevent severe accidents, as well as mitigate them, see NUREG-1437, 3
" Generic Environmental Impact Statement for License Renewal of Nuclear Plants,"
(Volume I, p ,%100). By doing so, the StaK makes the set of SAMDAs considered under NEPA the same as the set of SAMDAs considered in sadsfaction of the ) Commission's severe accident requirements and rolicy. This document provides the technical basis for determining the status of severe accident closure under NEPA. The report concludes that there is an adequate technical basis for closure of severe accidents under NEPA. The basis and conclusions are expected to be codi5cd in the form of proposed amendments to 10 j CFR Part 51. ne amendments would provide that: s (1) For the ABWR design, all reasonable steps have been taken to reduce the ! occurrence of a severe accident involving substantial damage to the core and - l to midgate the consequences of such an accident should one occur; (t) No costefective SAMDAs to the ABWR design have been idendned to arevent 1 or mitigate the consequences of a severe accident involving substantia. damage to the core; and, . 4 (3) No further evaluation of severe accidents for the ABWR design,' including SAMDAs to the design, is required in any environmental report, NEPA/sAMDA, page lv DaAFT December 17.1ss
.r-.i- . _ - 4_ .m,_ i-.-,J._,s_,,.,m,....i.,...,. _ . . _ - . . _ . . __.__J.i_.,__.-.-..D._1....JJ-__~.
ICC 17 '92 03 1". #1 P.7 environmental assessment, environmental impact statement or other environmental analysis prepared in connection with issuance ot* a combined license for a nuclear power plant referencing a cerdSed ABWR design. 1 4 NEPA/SAMDA, py v DRAr!' Deemim 17,1901 i
LCC 1*/ '92 0381Ut1 P.0
1.0 INTRODUCTION
1.1 Background
'Ihe tenn " severe accident" refers to those events which are "beyond the substantial coverage of dealgn basis events" and includes those for which there is substantial damage to the reactor core whether or not there are serious off site consequences, see Severe Acddent Policy Statement,50 Fed. Reg. 32,138,32,139 (August 8,1985). For new reactor designs, such as the ABWR, the Nuclear Regulatory Commission (NRC),
in satisfaction of its severe accident safety requirements, is requiring, among other things, the evaluation of design alternadres to reduce the rad:ological risk from a severe accident by preventing substantial core damage (i.e., preventing a severe accident) or by limiting releases from the containment in the event that substantial core damage occurs (i.e., mitigating the impacts of a severe accident). The Commission's severe accident safety requirements for new designs are set forth in 10 CFR Part 52, A52.47(a)(1)(ii), (iv) and (v). Paragraph 52.47(a)(1)(ii) references the Commission's Three Mile Island safety requirements in 550.34(f). Paragraph 52.47(a)(1)(iv) concerns the treatment of unresolved safety issues and generic safety issues. Paragraph 52.47(a)(1)(v) requires the performance of a design-specific probabillatic risk anessment (PRA). The Severe Accident Policy Statement elaborates what the Commission is requiring for new designs. The Safety Goal Policy Statement sets goals and objectives for determining an acceptable level of radiological risk. As part ofits application for certification of the ABWR dealgn, GE has prepared a Standard Safety Analysis Report (ABWR SSAR), Chapter 19 of the ABWR SSAR,
" Response to Severe Accident Policy Statement," demonstrates how the ABWR design niccts the Commission's severe accident safety requirements and policies. In particular, Chapter 19 includes:
(1) Identification of the dominant severe accident sequences and associated source terms for the ABWR design; (2) Descriptions of modifications that have been made to the ABWR design, based on the results of the Probabilistic Risk Assessment (PRA), to prevent or mitigate severe accidents and thereby reduce the risk of a severe accident; ($) Bases for concluding that "all reasonable steps [have been taken) to reduce the chances of occurrence of a severe accident invohing substantial damage to the reactor core and to mitigate the consequences of such an accident should one occur," (Severe Accident Pelicy Statement (50 Fed. Reg. 32,139)); and (4) Bases for concluding that the safety goals, (Safety Goals for the Operations of Nuclear Power Plants; Policy Statement (51 Fed. Reg. 30,028 (August 21,1986))), have been met. Consequently, the conclusions are drawn in Chapter 19 that further modi 5 cations to the ABWR design to reduce severe accident risk are not warranted. ' hge 1
8CC 17 '92 0311641 P.9 f The National Environmental Policy Act (NEPA) requires the consideradon of reasonable alternatives to proposed major Federal actions signi8cantly aEcedng the q uality of the human environment, inclu.Alng attematives to midgate the im sacts of tie proposed acdon. In 1989, a Federal Court of Appeals determined that NEDA required consideration of certain design alternatives; namely, seve.e accident mitigadon design alternatives (SAMDAs). [hnedch ha% Ardan v. NMn 869 F.2d 719 (3rd Cir.1989). The court indicated thae "[SAMDAs) are, as the name sus rests, possible plant dedgn modlScations that are t, tended not to prevent an accic ent, but to lessen the severity of the impact of an ac6 dent should one occur " & at 731. The court rejected the use of a policy statement as an acceptable bads for closing out NEPA consideradon of SAMDAs in a licensing proceeding, because, among other things, it was not a rule making, see (d. at 739. Subsequent to the f Jmedek decision, the NRC lasued Supplemental Mar.1 Environmental Impact Statements for the Ilmerick and Comanche Peak facilities which considered whether there were any cost efecdve SAMDAs that should be added to these facilities ("NEPA/SAMDA FES Supplements"). On the basis of the evaluations in the supplements (called "NEPA/SAMDA evaluadons"), the NRC determined that further modifications would not be cost effecdve and were not necessary in order to satisfy the mandates of NEPA. In recognidon of the Mastkk decision, the Commission is requiring NEPA consideradon in Part 52 licensing of whether there are cost erecdve SAMDAs which should be added to a new reactor design to reduce severe accident risk. While this consideration could be donc later on a fadlityspeci8e basis for each combined license applicadon under Subpart C to Part 52, the Commission has decided that maintenance of design standardizadon will be enhanced if this is done on a generic basis for each standard design in conjuncdon with design cerd8 cation, see SECY91-229, " Severe Accident Mitigation Design Alternatives for Certl6cd Standard Designs." That is, the Commission has decided to resolve the NEPA/SAMDA quesdon through rule = making at the time of cerd6 cation in a scH:alled unitary proceeding, rather than in the context oflater licendng proceedings. Recently, the NRC Star expanded the concept of SAMDAs to encompass design alternstlves to prevent severe accidents, as well as midgate them. $sa NUREG 1437,
" Generic Environmental Impact Statement for License Renewal of Nuclear Plants,"
(Volume I, p. 5100). By doing so, the Staf makes the set of SAMDAs considered under NEPA the same as the set of SAMDAs considered in satisfaction of the Commission's severe accident requirements and policies. 1.2 Purpose The purpose of this technical support document is to provide a basis for determining the status of severe accident closure under NEPA for the ABWR design. The document supports a determination, which could be codified in a manner similar to the format of the Waste Confidence Rule (10 CFR $ 51.23) as proposed amendments to 10 CFR Part 51. These amendments would provide that: hee s
DCC 17 '92 03867ft1 P.10 j > 1 ) (1) For the ABWR design all reasonable steps have been taken to reduce the J occurrence of a severe accident invohing substantial damage to the core and j to mitigate the consequences of such an accident should one occur' i
- (2) No further cost <ffeedve SAMDAs to the ABWR design have been identined to i mitigate the consequences of or prevent a severe accident involving substandal l damage to the core; and,
!' (3) No further evaluation of severe accidents for the ABWR design, including ! j SAMDAs to the design, is required in any environmental report, i environmental assessment, environmental impact statement or other i environmental analysis prepared in connecdon with issuance of a combined j license for a nuclear power plant referencing a cerdfled ABWR design. ! i 3 i The evaluation presented in this document is modeled after that found in the Limerick and Comanche Peak NEPA/SAMDA Final Environmental Statement (FES) l Supplements for those facilities. Additional information concerning the radiological dak tom severe accidents for those plants is not found in the supplements, but in i the FESS for the Limerick and Comanche Peak facilities. That informadon with j respect to the ABWR design is presented in this document. T14e discussion herein of i the radiological dak from severe accidents is based on Chapter 19 of the ABWR SSAR. L3 Desadpdon of Technical Suppost Docussent i Chapter 2.0 provides an overview of the radiological risks from normal operations . and severe accidents. Chapters 3.0 through 5.0 provide the NEPA/SAMDA analysis, j Chapter 3.0 discusses the methodological approach to the evaluation of SAMDAs j under NEPA. Chapter 4.0 presents the ress ta of the cost effectiveness evaluadon of , l the potential SAMDA modlBcations. Chapter 5.0 presents the conclusions and l Chapter 6,0 the references. 2.0 EVALUATIONS OF RADIOLOGICAL RISE PROM NUCLEAR POWER ; PLANTS ! 1 2.1 Evaksation of SAMDAs under NEPA and Iantarick Ecology Action l f j UmerM Frainev Acdan stands for two proposidons. First, that NEPA requires j 4' explicit consideradon of SAMDAs unless the Commission makes a finding that the severe accidents being mitigated are remote and speculative. Second, that the i Commission may not make this finding and dispose of NEPA consideradon of t . 4 - _ m m - n n m ..
@of@ow topalflinU U' V l
[f taken to reduce the radiological anvironmentalimpacts from no
' operadons, including expected operadonal occurrences, to as low as reasonably 1 1 hievable (AIARA). See Chapter 2.0 of this document.
hse s
. - . - _ - - ~ . - - - -- -- , -- -- - - . . - . - . _ _ _ , - . . -
j Dcc 17 '92 03 4 W ei P.11 l i 1
- SAMDAs by means of a policy statement. The purpose of evaluadng SAMDAs under i NEPA is to assure that all reasonable means have been considered to mitigate the 1 impacts of severe seddents that are not remote and speculadve. As discussed above, j the Commission has indicated that it will resolve the NEPA/SAMDA issue in the j same proceeding, called a unitary proceeding, in which it cerdGes a new reactor j design.
The Commission's Severe Accident and Safety Goal policy statements require the 1 Coramission to make certain Sndings about each new reactor design. For ! evolutionary designs, of which the ABWR is one, this must be done y the Staffin l conjunction with FDA approval and by the Commission in conjunction with
! cerd8cadon. First, the Commission must find that an evolutionary plant meets the
- safety goals and objecdves; i.e., that the radiological risk from operating an i evolutionary plant will be acceptable, meaning that any further reduction in risk will i
not be substantial. Second, the Commission must and that all reasonable means have been taken to i reduce severe accident risk in the evolutionary plant design. As part of the basis for !- making this Snding, the cost-efectiveness of risk reduedon alternatives of a j preventive or mitigative nature must be evaluated. l Chapter 19 of the ABWR SSAR demonstrates that these Sndings can be made for the l i ABWR design. Given the nature and Endings of these severe accident and safety goal evaluadons, GE believes that a sunicient basis exists for Andin rule that further { consideradon of severe accidents, including evaluation of pursuant to l NEPA, is neither necessary nor reasonable. l , 1.2 Cost /benent Standard for NEPA Evaluation of SAMDAs he Limsdsk decision inter >reted NEPA to require evaluation of SAMDAs for their
- risk recluction potential. In mplementing the court's decision, the NRC considered
- the cost eNectiveness of each candidate SAMDA in mitigatin
! accident, using the $1,000 per person rem averted stand ard. g thestandard Thir impact of is aa severe j surrogate for all ofsite consequences. ! The basic approach herein is to rank the SAMDAs in terms of their cost efeedveness in mitigating the impact of a severe accident. ne criterion applied is the $1,000 per i person rem averted standard, which is what the Commission has hitherto used in l distinguishing among and ranking design alternadves, including SAMDAs. i . The Commission has used this standard in the context of both safety and NEPA
- analyses. For example, in the context of safety analysis, the standard has been used to 4
' perform evaluadons associated with implementadon of 10 CFR Part 50, Appendix I; , the Safety Goal Policy Statement; the Severe Accident Policy Statement; and I 50.34(f) requirements. In the context of environmental analysis, it has been used in the lements; and in the draft ' Limerick and Comanche Generic Environmental Peak NEPA/SAMDA Impact Statement for License FES Supl>tenewal of Nuclear P j' (NUREG 1437), i na -
r 9tc t7 '92 m w v1 @ As indicated above, NUREG 1437 provides the bues for the Commission's proposed amendments to 10 CFR Part 51 concerning the environmental impacts oflicense renewal, including conalderation of severe acddents and SAMDAs. NUREC-1437 makes dear that the use of this standard in the evaluation of severe acddent risk reduction alternatives, which indude SAMDAs, is acceptable.(see NUREG-1437, p. 5-10 , Additionally pxndix ! determinations are used to satisfy NEPA requirements wi respect to r oLogical impacts from normal operations Bued on these considerations, the cost / benefit ratio of $1,000 per person rem adverted is viewed as an acceptable standard for the purposes of evaluating SAMDAs under NEPA. 2.3 Socioeconomic Risks for Severe Accidents As discussed above in Section 2.2, the Commission uses the $1,000/ person rem averted standard as a surrogate for all oEsite consequences, see SECY. 80102, "I ementation of Safety Goal Policy" However, Environmental Impact Statements (El ) for nudear power plants provide se 3arate, general discussions of the socio-economic risks from severe accidents. In leeping with this precedent, GE is providing a general discussion of socio-economic risks for the ABWR design, based in large measure on the discussion of such risks in NUREG 1437, " Draft Generic EmironmentalImpact Statement for License Renewal of Nudear Plants." The term "socio-economic risk from a severe accident" means the probability of a severe accident multiplied by the socio<conomic impacts of a severe accident.
" Socioeconomic impacts" in turn relate to offsite costs. The off-site cosa considered in NUREG 1437 (see Vol. I at 540) are:
- evacuation costs, a
value of crops or milk, contaminated and condemned,
- costs of decontaminating property where practical, indirect costs due to the loss of the use of property or incomes derived therefrom (including interdiction to prevent human injury), and impacts in wider regional markets and on sources of supply outside the contaminated area.
NUREG-1437 estimated the socio-economic risks from severe accidents. The estimates were bued on 27 FESS for nuclear power plants that contain analyses considering the probabilities and consequences of severe accidents. For these plants, the off-site costs were endmated to be as high as $6 billion to $8 billion dollars for severe accidents with a probability of once in one million operating years. Higher costs were estimated for severe accidents with much lower probabil. tics. The projected costs of adverse health effects from deaths and illneues were estimated to average about 10 20% of off-site mitigation costs and were not induded in the $6 $8 billion dollar estimate, w , ________---_-------A
ECC 17 '92 03819't1 P.a3 Another source of costs, which NUREG 1437 indicated could reach into the billions of dollars, were costs associated with the termination of economic activities in a contaminated area, which would create adverse economic impacts in wider regional markets and sources of supplies outside the contaminated area. The predicted conditional land contamination was estimated to be small (10 acres / year at most), see NUREG 1437, pp. 5-90 through 5-93. NUREG 1437 provides the bases for the Commisalon's proposed amendments to 10 CFR Part 51 concerning the emironmental impacts oflicense renewal. The proposed amendments find that the socio<conomic risks from severe accidents are ?redicted to be small and the residual impacts of severe accidenu so minor that detaled consideration of mitigation alternatives is not warranted, see 56 Fed. Reg. 47,016, 47,019,47,034-35 (September 17,1991). The socio-economic risks contained in NUREG-1437'are bounding for plants of ABWR design. First, the core damage frequency for plants of ABWR t'esign is 1.6E 7 per year. Thus, no accidents, and hence no offsite cosu, are expecte f at probabilities at or greater than once in one million years. Second, plants of ABWR design meets the safety goals set forth by the NRC, see Section 3.2, below. 3.0 RADIOLOGICAL RISK FROM NORMAL OPERATIONS AND SEVERE ACCIDENTS IN PLANTS OF ABWR DESIGN 3.1 Radiological Risk from Normal Operadons of an ABWR Plant 1/ Sections 50.34a and 50.36a of 10 CFR Part 50 rec uire, in effect, that nuclear power reactors be designed and operated to keep levels of radioactive materials in gaseous and liquid effluents during normal operations, including expected operational occurrences, "as low as reuonably achievable" (AIARA). Compliance with the guidelines in Appendir I to 10 CFR Part 50 is deemed a conclusive showing of compliance with these ALARA requirements. In addition to specifying numericallimits, Appendix I also requires an applicant to include in the radwaste system "allitems of reasonably demonstrated technology that, when added to the system sequentially and in order of diminishing cost / benefit 1/ Non-radiological impacts from operation of an ABWR plant include those from the circulatin cooling lakes,g etc.),system which removes intake systems for the water heat from in the the reactor circulating (c g., cooling towers, systems, discharge systems for the water in the circulating system, blocide treatment in circulatng water to prevent fouling by organisms, chemical waste treatment and disposal, sanitary waste treatment system, and electrical transmission facilities. Each of these systems is part of that prtion of the ABWR design which is not being certiGed because it is site-specific. It may be appropriate to consider design alternatives for these systems under NEPA. However, the choice of alternative will not have an effect on the portion of the ABWR design that is being certi6ed. Consideration of alternative designs to systems affecting non radiological impacts must be done on a site-specific basis, hee o
I ICC 17 '92 0381NH P.14 i l l return can for a favorable cost /benent ratio, effect reduedons in dose to the ! population expected to be within f ^ miles of the reactor". The standard to be used in j making this assessnent is the cost /benent rado of $1,000 per person rem averted. ne ABWR design complie' with the guidance of Appendix I, as documented in Chapter 12 of the ABWR .iSAR. Consequently, further consideradon of alternatives to reduce the radiological risks from normal operation of a dant of ABWR design is ! not warranted in order to satisfy NEPA. Moreover, the racJological impacts from j normal operation of an ABWR are environmentally insignincant. i ! 3.3 Severe Accidents in Plants of ABWR Design i Chapter 19 of the ABWR SSAR, " Response to Severe Accident Policy Statement," j establishes that the Commission's severe accident safety requirements have been met i for the ABWR design, including treatment ofinternal and external events, { uncertainties, performance of sensidvity studies, and support cf conclusions by appro i j 50.34(priate f). It also determinisde establishes that the analyses and the Commission's safetyevaluations required goals have been met. by 10 CFR Part SpeciBeally, the following topics were addressed in Chapter 19: ! (1) Consideradon of the contribudons ofinternal events (Secdon 19.3) and j external events (secdon 19.4) to severe accident risks, including a seismic risk analysis based on the application of the seismic margins methodologgyA N I4Z) (2) Idendficadon of the ABWR dominate accident sequences; 4 (S) IdendScadon of severe accident risk reduction features which were included i in the ABWR design to achieve accident prevention and midgadon (addressed ! in Section 19.7.3(2); ! (4) Consideradon of additional modl8 cations, evaluated in accordance with j $ 50.S4(f)(1) (addressed in Appendix 19P, " Evaluation of Potential l ModlHcadons to the ABWR Design").. l Appendix 19P concludes that the severe accident requirements of 10 CFR Part 52 (5 52.47 (a)(1)(ii), (iv) & (v)) and the Severe Accident Policy Statement have been met. It also provides a summary of the bases for these conclusions. In pardeular, Appendix 19P presents a summary of the bases for concluding that the requirements of 8 50.34(f) (referenced in 352.17(a)(1)(ii)) have been met, including 850.S4(f)(1)(i), which requires " perform [ance of) a plant / site speciBc [PRA), the aim of which is to i seek such improvements in the reliability of core and containment heat removal [ systems as are signi8 cant and practical and do not impact excessively on the plant."
- Appendix 19P aso presents the bases for concluding that further modi 8 cations to -
the ABWR design are not warranted in order to reduce the risk of a severe accident i through the addidon of design features to prevent or mitigate a severe accident. 3 Section 19.6 of Chapter 19 addresses how the goals of the Severe Accident Polley [ Statement have been met for plants of ABWR design, nese goals include: Y*
- - - . . - _ . - - - -.- - -- -._.. _ = _ --
sk.c u m a m v. m
- prevendon of core damage o
prevention of early containment failure for dominant accident sequences , e evaluadon of the effects of hydrogen generadon { heat removal to reduce the probability of containment failure
- prevention of hydrogen deflagration and detonadon 3
I
- offsite dose, and l
j
- containment conditional failure probability.
Speci8c conclualons concerning severe accidents for plants of ABWR design based l on the Chapter 19 evaluations are as follows: f (1) Care Demange Frequence. The ABWR core damage frequency was determined l to be 1.6E 7 per reactor year in SSAR Section 19D. The goal was 1E4 per reactor ; j year. i
- (t) p- w-*c-' .a y.u.. hunb. The condidonal containment
, failure probability was shown to be less than 0.1 in Section 19.6.8. i (3) Individual Risk (Prompt Fatality Risk). We prompt fatality risk to a ! biologically average individual within one mule of an ABWR site boundary was . i determined to be 1.4E 15 per individual per year in Section 19E.S. nis is } significantly less than the goal of one tenth of one percent of the sum of i prompt fatality risks resulting from other accidents to which members of the i U.S. Populadon are generally exposed. he numedcal value of this goal is 3.9E 7 per individual per year (or 0.04 per 100,000 people per year). ! (4) (latant Fataller Risk). The latent fatality risk to the populadon l wi 0 iles of an ABWR site boundary was determined to be 8.4E 13 per g _ per year in ABWR SSAR Section 19E.5. his is significan less than l . the goal of one-tenth of one percent of the sum of the cancer fatall risks } resuldng from all other causes. The numerical value of thie goal is .7E4 per ' l individual per year (or 0.17 deaths per 100,000 people per year). l (5) W~^- af L a Cf" '
- E=. ne probability of exceeding a whole body i
dose of 28 rem at a distance of one-half mile from a ABWR was determined to { be less than IE-9 per reactor year in Secdon 19E.3. ! (6) Ranidual Radialortemi Risk. Residual radiological risk from severe accidents in plants of ABWR design is summarized in Table 19P.t-1 of the ABWR SSAA (reproduced here as Table 1). The cumulative exposure risk to the population i-within 50 miles of a plant of ABWR design is approximately 0.18 person-rem for an assumed plant life of 60 years. his calculat on includes the dominate sequences, as well as. several se ences which are considered remote and speculative (see next section7tJS . + f 1 ~s L i
tcc 87 '92 cmn1 Nb S.3 Domi Severe Aceldents Sequences for Plants of ABWR Design v In performing the PRA for the ABWR design, GE idendBed and evaluated many severe acddent sequences. For each sequence, the analysis identified an initiating event and traced the accident's progression to its end. For sec uences invoh'ing core damage, condidonal containment failure probabilities and oEsite consequences were estimated. After the accident scenarios wer9;bjr)ned according to radiological release (source term) parameters, only two domiycases remained <
/jg The dominEe5 cues are Case 1 (best estimate core damage sequences which had b" '
rupture disk activation) and NCL (core damage with normal containment leakage). The residual risks of these two cases can be found in Table 1 (also see Table 19P.2-1 of the ABWR SSAR). 'Ihe complete radiological consequence analysis of the dominate sequences can be found in Section 19E.S of the ABWR $5AR. Tne probability of occurrence of dominate sequences is greater than IE 9 per year. Several sequences with occurrence probabilities less than IE 9 per year were carried through the severe acddent analysis in order to determine the sensithity of plants of ABWR design to certain phenomena and parameters. These sequences were alm considered in the SAMDA evaluation for sensitivity purposes. Sequences with probabilities of occurrence less than IE 9 were considered remote and speculative. While the Commission has not yet speciBed a quantitative point at which it will consider severe accident probabillues as remote and speculative, it has indicated that a decision to consider severe accidents remote and speculative would be based upon the accident probabilities and the accident scenarios being analyzed. SegVermont Yankee Nuclear Power Cornoration. (Vermont Yankee Nuclear Power Station), CLI 9047, 32 NRC 129,132 (1990) GE believes that the severe accident analysis in Chapter 19 of the ABWR SSAR provides a sufBelent basis for the Commission to find that ABWR sequences which are not dominant can be deemed remote and speculative. 3.4 Overall Conclusions from Chapter 19 of the ABWR SSAR The speciGe conclusions about severe accident risk discuned above support the overall conclusion that the environmental impacts of severe accidents for plants of ABWR design represent a low risk to the population and to the environment. For the ABWR design, all reasonable steps have been taken to reduce the occurrence of a severe accident invohing substantial damage to the core and to mitigate the consequences of such an accident should one occur. No further cost-effective modi 6 cations to the ABWR design have been identined to reduce the risk from a severe accident involving substantial damage to the core. No further evaluation of severe accidents for the ABWR design is required to demonstrate compliance with the Commission's severe accident requirements or policy or the safety goal. Page 9
ICC 17 '92 03:21rti P.17 ) i 4.0 COST /REWJIT EVALUATION OF SAMDA5 FOR PLANTS OF ABWR i DEstGN 4.1 SAMDA Defhdtton Applied to Plants of ABWR Dasign Appendix 19P of the ABWR SSAR considered whether the ABWR design should bc l
- modlSed in order to prevent or mitigate the consequences of a severe accident in l
) sadafaction of the NRC's severe accident requirements in 10 CFR Parts 50 & 52 and the Severe Accident Policy Statement. Tbc cost / bene 6t evaluation of SAMDAs to i plants of ABWR design used the expanded definidon of SAMDAs: design alternadves j which could prevent and/or mitigate the consequences of a severe accfdent. a 4.2 Cost / Benefit Standard for Evaluadon of ABWR SAMDAs 4 discussed in Secdon 2.2 above, the cost / benefit raio of $1,000 per person rem pv'erted is viewed by the NRC and the nuclear industry as an acceptable standard for s tKe purposes of evaluadng SAMDAs under NEPA. his standard was used as a surrogate for all off4fte costs in the cost /beneSt evaluation of SAMDAs to plants of i ABWR design. In order to accurately reflect the costs associated with prevention of i severe accidents, adverted on site costs were incorporated for SAMDAs which were at least partially preventative in nature. On41tc costs resulting from a severe accident include replacement power, on site cleanup costs, and economic loss of the facility. 2 A more detailed discussion on adverted ongite costs can be found in Section 19P.1.3.2 of the SSAR.
- The equation used to determine the cost / benefit ratio is e at fSAMDAimplementation - rted on - site costs K cost / bene 6t ratio ,
reduction in residual dak (person rem / plant life) . A plant life dme of 60 years was assumed to maximhe the reduction in residual risk. LS Candidate SAMDAs for the ABWR Design ne complete list of SAMDAs considered for plants of ABWR dealgn is contained in Table 2. This list is also contained in Table 19P.S 1. The SAMDAs are classi5ed according to the following categories: 1 (1) Modification is applicable to the ABWR and already incorporated into the design. No further evaluation is needed. ne cross reference to the ABWR SSAR which discusses the modification is also provided. (2) Modification is applicable to the ABWR but not incorporated into the design. nese modifications were considered further in Appendix 19P and the results of the cost / benefit analysis will be presented in this document. (3) - Modification is not apphcable to the ABWR design due to the basis provided. Page 10
.___-___m _ __ _ -.._ _-__.._ _._ _ - ._ _ _ _ . _ . _ - . _ _ -
j tcc a7 '92 03:22rs1 P.t0 J }l (4) Modi 8cadon is considered as part of another modl6cadon listed in the table. Table 3 list the advantages and disadvantages of each desi alternadve which is ! i applicable to the ABWR but not incorporated into the d (T classi5 cation in Table 2). A detalled discussion of each alternative Jd contained in Secdon 19P.4. M If 44 Cost Rad ==tes of Potential Modificadoes to the ABWR Desiga
- Table 4 2rovides a brief explanation of the endmated costs of each design alternadve applicab!e to the ABWR design. Details of the cost estimadon methodology are provided in Seedon 19P.1.3.2 of the ABWR SSAR. As discussed in Appendix 19P, rough
- order of magnitude costs, biased in favor of making a modificadon, were assigned to j each modincadon. The costs represent the incremental costs that would be incurred ;
i in a new plant rather than costs that would apply on a back5t basis. The estimated costs of d g3 alternatives which are, at 14t partially, preventadve in $ , nature were usted for Ferted on4ite costs. This adjustment is included in the ! cost esdmates Table 4. Design alternatives which are purely midgative in nature ! are not assigned any adverted on site costs because these modincadons do not j signincantly effect site clean up cost nor signincantly lessen the plant investment < 3 lou. Secdon 19P.5 of Appendix 19P discusses the bases for assigning rted on site A
- costs in detail, i
- Considerable uncertainties prevent precise cost estimates because design details have not been developed and construcdon and licensing delays cannot be accurately l evaluate. For purpose of this evaluadon, all known or reasonab expected costs were 1
accounted for in order that a reasonable assessment of the mi um cost could be obtained. Using a minimum cost favors implementation of a modl8 cation.- Actual 3 implementadon costs are expected to be agnincantly higher than those used in this l evaluation. i 4.5 - Benefits of Pa4*=dal Modi 8eadans to the ABWR Design 3 Table 5 summarizes the basis for assigning a benent to each SAMDA. In general, j benc6ts were endmated from the PRA results of Chapter 19 considering which sec uences are affected by each modi 5cadon. Detailed on of the method for i estmatin benents is provided in Seedon 19P.4. The rted residual risk for each g SAMDA also given in Table 5. s
- to Cost /Benent Comparison of RAMDAs i-
- Table 6 summarines the results of combining the cost endmates from Table 4 with the
- .- - bene 5t esdmates from Table 5. - As is evident from Table 6, none of the SAMDAs requires further evaluation since the cost /benent standard wu met. The closest desp alternative exceeds the criteria more than a factor ??? Based on the smaa residual risk of a plant of ABWR sign,0.183 person-re or the endre plant l .
, hee i1
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ICC 17 '92 03:22ft1 P.19 life, a mitigative design modificadon would have to cost $185 or less in order to meet the standard of $1,000 per person-rem adverted. 5.0
SUMMARY
AND CONCLUSIONS A reasonable and comprehensive set of candidate SAMDAs relevant to the ABWR were evaluated in terms of minimum costs, adverted on osts and potential benents. A screening criteria of $1,000 per person-rem rted was used to i determine which alternatives, if any, were cost effective. one were found to meet the criteria. In fact, the implementation cost of a SAMDA would have to be less than
$183 in order to pass.
Given the low res5 dual risk profile of the ABWR desi(In, SAMDAs cannot be renonably pursued in a cost effective manner. On tse basis of the foregoing analysis, further irscorporation of SAMDAs into the ABWR design is not warranted. No further screening of SAMDAs is needed atd no SAMDAs need be incorporated into ABWR design in satisfaction of NEPA. Page is lui- n. i i i i . -- .
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6.0 REFERENCES
Advanced Rothng Water Rondor Standant Safety Analyds Report, Rev. A, NED 2SA6100AS, GE Nuclear Energy, SanJose, CA, December 1992. Assasmont ofSewre Auident Prewntion and Mit(gation Featurn, NUREG/CR-4920, Brookhaven National Laboratory, July 1988. Dadgn and Feasibilty ofAccident Mitigation Systensfor Lighi Water Raadors, . NUREG/CR4025, R&D Associates, August 1985. Evaluation ofPmposed Medipcations to the GESSAR HDaign, NEDE $0640, Class 111, GE Nuclear Energy, SanJose, CA, June 1984. Generic EnvironmentalImped Skiementfor License Renewal ofNucieer Plants, NUREG-14S7, DraA for Comment.
" Issuance of Supplement to the Final Environmental Statement Comanche Peak Steam Electric Station, Units 1 and 2", NUREG 0775 Supplement, December 15, 1989.
Sewrr Acddent Risks: An AsssssmentfmMve USNudnarPtoorPlants, NUREG-1150, January 1991.-
"Sup plement to the Final Environmental Statement - Limerick Generadng Station, Un: ts 1 and 2", NUREG 0974 Supplement, August 16,1989.
Surwy of the State of the Art in Mitigation Systems, NUREG/CR-S908, RkD Associates, December 1985. Technical Guidancefor Siting Critoria Drulopment, NUREG/CR EtS9, Sandin National Laboratories, December 1982. Title 10, Code of Federal Regulations, Part 50 and 52. 50FRSt1S8, Ptky Statement on Sewre Reador Aeddents Remiingl%ture Daigns and i EmistingPlants, August,1985. l r Page 13 i
,. _ . . ---_1
DCC 17 '92 03: m P.21 -I I l Table 1 Radiological Consequences of ABWR Accident Sequences Whole Body Cumulative Probability Exposure,30 mile Exposure Risk Case (Event / year)* (person-rem) (per-rem /60 yr) NCL 1.4507 2.30E3 0.019 4 1 2.0E 08 1.15E4 - 0.014 2 7.8E 11 S.SSES 0.000 3 1.3E 12 3.71E5 0.000 4 0 2.06E5 0.000 5 6.3L12 - 9.34E4 0.000 6 1.2L10 2.42E6 0.018 7 S.7L10 2.7SE6 0.061 8 2.1L10 3.20E6 ' O.040 9 1.5E 10 3.31E6 0.031 total: 0.183 '
- Sequences with probabilities of occurrence less than IL9 per year are considered remete and speculative.
5 i Page 14 1 i
Table 2 , Severe Accident Mitigation Design Alternatives (SAMDAs) Con;idered for the ABWR Design Hooification Cateaory
- 1. ACCIDENT MANAGEMENT
- a. Severe Accident EPGs/AMGs 2
- b. Computer Aided Instrumentation 2
- c. Improved Maintenance Procedures / Manuals 2
- d. Preventive Maintenance Features 4
- e. Improved Accident Mgt Instrumentation 4
- f. Remote Shutdown Station 1
- g. Security System I
- h. Simulator Training for Severe Accidents 4
- 2. REACTOR DECAY HEAT REMOVAL
- a. Passive High Pressure System 2
- b. Improved Depret.surization 2
- c. Suppression Pool Jockey Pump 2
- d. Improved High Pressure Systems 1
- e. Additional Active High Pressure System 1
- f. Improved Low Pressure System (Firepump) I
- g. Dedicated Suppression Pool Cooling I
- h. Safety Related Condensate Storage Tank 2
- i. 16 hour Station Blackout Injection 4
- j. Improved Recirculation Mode 3
- 3. CONTAINHENT CAPABILITY
- a. Larger Volume Containment 2
- b. Increased Containment Pressure Capacity 2
- c. Improved Vacuum Breakers 2
- d. Increased Temperature Margin for Seals 1
- e. Improved Leak Detection 1
- f. Suppression Pool Scrubbing 1
- g. Improved bottom Penetration Design 2
- 4. CONTAINMENT HEAT REMOVAL
- a. Larger Volume Suppression Fool 2
- b. RWCU Decay Heat Removal I
- c. High Flow Suppression Pool Cooling 1
- d. Passive Overpressure relief 1
- 5. CONTAINMENT ATMOSPHERE MASS REMOVAL
- a. High Flow Unfiltered Vent 3
- b. High Flow Filtered Vent 3
- c. Low Flcu Vent Ifiltered) 2
- d. Low Flow Ven' an filtered) -1
- 6. COMBUSTIBLE GAS CONTROL
- a. Post Accident Inerting System 3
- b. Hydrogen Control by Venting 3
- c. Preinerting 1
- d. Ignition Systems 3
- c. Fire Suppression System laerting 3
i Table 2 .
- SevereAccidentMitigationDesignAlternatives(SAMDAs)
Considered for the ABWR Design . Modification Cateaorv
- 7. CONTnINMENT SPRAY SYSTEMS
- a. Drywell Head flooding 2
- b. Containment Spray Augmentation 1
- 8. PREVENTION CONCEPTS
- a. Additional Service Water Pump 2
, b. Improved Operating Response 1 i c. Diverse Injection System 4
- d. Operating Experience Feedback 1
- e. Improved MSIV/SRV Design 1
- 9. AC POWER SUPPLIES
- a. Steam Driven Turbine Generator 2
- b. Alternate Pump Power Source 2
- c. Deleted
- d. Additional Diesel Generator 1
- e. Increased Electrical Divisions 1
- f. Improved Uninterruptable Power Supplies 1 j' g. AC Bus Cross-ties I
- h. Gas Turbine 1
- i. Dedicated RHR (bunkered) Power Supply 4
- 10. DC POWER SUPPLIES
- a. Dedicated DC Power Supply 2
- b. Additional Batteries / Divisions 4
- c. Fuel Cells 4 I
- d. DC Cross-ties 1
- e. Extended Station Blackout Provisions 1
- 11. ATWS CAPABILITY
- a. ATWS Sized Vent 2
- b. Improved-ATWS Capability- 1
- 12. SEISMIC CAPABILITY
, a. Increased Seismic Margins 1
- b. Integral Basemat 3 i 13. SYSTEM SIMPLIFICATION
- a. Reactor Building Sprays 2
- b. System Simplification- _
1-
- c. Reduction in Reactor Bldg Flooding 1
- 14. CORE RETENTION DEVICES
- a. Flooded Rubble ' Bed - 2
- b. Reactor Cavity Flooder 1
- c. Basaltic Cements 1
- SAMDAs include both preventive and mitigative design alternatives
'f
, - , , - y- %., ., , _ _ - - . . ,.
Table 3 SAMDAs Evaluated Under NEPA for the ABuR POTENTIAt lure 0VtMENT ADVANTACES QLi40VANTACES
- 1. Severe Accident EPCs I mroved arrest of core melt Wone progress and prevention of contairvnent f ailure.
- 2. Comuter Aided Instrunentation I mroved prevent!on of core Additional training melt sequences
- 3. I mroved Maintenance I mroved prevention of core Increased docunentation cost Procedures / Manuals melt sequences
- 4. Passive High Pressure System I mroved prevention of core High cost of additional system melt sequences
- 5. I mroved Depressurization Imroved utilization of Low Cost of additional equipment Pressure systems for prevention of core melt sequences
- 6. Suppression Pool Jockey Pump I mroved prevention of core Cost of additional equipment melt sequences
- 7. Safety Related condensate storage Avaltability following Design and structural costs Tank Seismic events
- 8. Larger Volune Contairenent increased time before Extrene cost of structural contairinent f ailure changes and contairinent f ailure not prevented
- 9. Increased Containment Pressure Eliminates large releases Extreme cost and att sequences capacity not prevented
- 10. Imroved vacuun Breakers Reduced probability of increased maintenance and suppression pool bypass eqJipnent costs
- 11. !@ roved Bottom Penetration Design increased time for in vessel Cost for equipnent and analysis arrest
- 12. Larger Volume Suppression Pool increased heat absorption Extreme cost and minor within contairvnent, time f or radiological benefit system recovery and time before containment failure
- 13. Low flow Filtered Vent Reduced offsite exposures High cost of equipnent with little benefit
- 14. Drywell Head Flooding Mitigation of drywell Marginal benefit failure sequences I
Table 3
$AMDAs Evaluated under kiPA for the AB'lt w
- 15. Additional Service Water Pw p I mroved prevention of core Additional cost of equipnent melt sequences
- 16. Steam Driven Turbine Generator I mroved prevention of core Additional cost of equipment melt sequences
- 17. Alternate Pw p Power Source I m roved prevention of core Additional cost of equipment melt sequences
- 18. Dedicated DC Power Supply i groved prevention of core Additional cost of equipnent melt sequences
- 19. ATWS sized vent Additional time before Marginal benefit contalment overpressure
- 20. Reactor Building sprays Reduced release of fission uncertain Location and unknown products from Reactor potentist and consequences from Building inadverttnt actuation
- 21. Flooded Rubble Bed Prevention of Core-concrete small benefit over passive interaction affects flooding system
P.25 ICC 17 '92 03:2441 Table 4 Cost Esthnata of SAMDAs* E5aluated for the ABWR Under NEPA Potential Improvement Cost Basis Estimated Minimum Coat
- 1. Larger Containment Double current volume $8,000,000 Volume 0 $1200/ft8 2 Increase Containment Similar to 1, but denser $12,000,000 Pressure Capability rebar and labor required.
Assumed 50% higher cost
.t. Improved Vacuum Eight lines at $10,000 per $80,000 Breakers line
- 4. Increase Suppression Assumed to be the same 58,000,000 Pool Volume as 1
- 5. Drywell Head Minor valve and piping $60,000 Flooding modification with instrumentation
- 6. Reactor Building Minor valve and piping $60,000 Sprays modification with instrumentation __
- SAMDAs include both preventative and mitigative design alternatives
$g/ '
/
/
Page 18
ICC 17 '92 03:2#ti P.26 Table 5 Benefit Esthnstes of SAMDAs* Evaluated for the ABWR Under NEPA Adverted Risk Potendal Imprmement Benent Basis (person-rem)
- 1. Larger Containment 50% reducdon in all cases except 0.09 Volume normal containment leakage (NCL) 2 Increase Containment Prevention of all cues except 0.18 Preuure Capability normal containment leakage (NCL)
- 3. Improved Vacuum Vacuum breakers account for about 0.01 Breakers 50% of the total bypass risk which is about 10% of the total risk. Thus, net reduction is $% of total.
- 4. Increase Suppression 50% reduction in all cases except 0.09 Pool Volume normal containment leakage (NCL)
- 5. Drywell Head Elimination of 50% of the risk of 0.04 Flooding high temperature failure sequence (one of the sequences in case 7)
- 6. Reactor Building Elimination of radiological 0.17 Sprays consequences of cases not involving normal containment leakage (NCL) or rupture disk activation (case 1)
- SAMDAs include both preventative and mitigative design alternatives c )
p + 1),/ l
/
Page 19
TEc 17 '92 02:24m P.27 l Table 8 Comparison of Esdmeted Costs and Benefits on SAMDAs Evaluated for the ABWR Under NEPA Adverted Risk Cost BeneSt Rado Atential Improvement Cost (person rem) ($M/ person-rem)
- 1. Larger Containment $8,000,000 0.09 89 Volume 2 Increase $12,000,000 0.18 67 Containment Pressure Capability S. Improved Vacuum $80,000 0.01 8 Breakers
- 4. Increase Suppression $8,000,000 0.09 89 Pool Volume
- 5. Drywell Head $60,000 0.04 1.5 Flooding
- 6. Reactor Building $60,000 0.17 0.35 Sprays
- SAMDAs include both preventative and mitigative design alternatives
/ y' ,
l t i l y j@
! /
Page to l
InterOITice Memo KG\ To: J.N. Fox From: A.J. McSherry b d Date: December 17.1992
Subject:
ABWR Shutdown Risk and Flooding SSAR Sections CC: JDD,SV Attached are the latest revisions to the ABWR SSAR sections on Shutdown Risk (19Q) and Probabilistic Flooding Analysis (19R). Responses to the NRC questions for both these sections have been included in the text as appropriate. It should be noted that a change to the flooding analysis has been made since the last revision. The fire doors in the corridor of the Reactor Building first Door (B3F) are now assumed to be closed and latched during normal operation. Previously, these doors were assumed to be closed but unlatched in order to allow flood water to open the doors and make the entire corridor volume available to contain the postulated Good water. The fire doors are now designed to function as other fire doors in the plant and will act as effective fire barriers as well as limiting flood propagation and pressure spikes resulting from potential breaks in the reactor water cleanup system. Flood levels in ECCS rooms and the corridor due to line breaks are now evaluated on a divisional basis (i.e., Gooding in an ECCS room may fill the room up and overnow to the corridor of the same division via the floor drains in the room above). It has been shown that the combined volumes of the ECCS room and divisional corridor can contain the water from all postulated floods in that division.
l 1 i .i
- APPENDIX 19Q ABWR SHUTDOWN RISK EVALUATION I
h
ABWR uxomas Standard Plant Rev A l APPENDIX 19Q TABLE OF CONTENTS Section T111C East 19Q ABWR SHUTDOWN RISK 19Q.1 INTRODUCTION 190.1 1 19Q.2 EVALUATION SCOPE 190.2 1 19Q.3
SUMMARY
OF RESULTS 1903-1 4 19Q.4 - FEATURES TO MINIMlZE SHUTDOWN RISK 190.4 1 19 0.4.1 Decay Heat Removal 19 0.4-1 1 j 19 0.4.2 Inventory Control 190.4 3 190.43 Containment Integrity 19 0.4-6 19 0.4.4 Electrical Power 19 0.4-7 190.4.5 Reactivity Control 19 0.4-8 i , 19 0.4.6 Summary of Shutdown Risk - Category Analysis 19 0.4-9 I 19Q.5 INSTRUMENTATION 19 0.5-1
- 19Q.6 FLOODING AND FIRE PROTECTION 19 0.6-1 19Q.7 DECAY HEAT REMOVAL RELIABILITY STUDY 190.7 1 1
19 0.7.1 -Introduction 190.7 1 19 0.7.2 Purpose 190.7 2 190.73 Summary 19 0.7-3 19 0.7.4 Methodology 19 0.7-4 19 0.7.5 Core Damage Probability Goal and RPV Boiling 190.7 5-19 0.7.6 Success Criteria 190.7 6 19 0 .7.7 Accident Progression and Event Trees 190.7 7-I i
)
190-il l Amendment
ABWR mams Standard Plant nev 4 APPENDIX 19Q TABLE OF CONTENTS (Continued) Section 11112 East 19 0.7.8 System Fault Trees 190.7-9 19Q.7.9 Results and Conclusions 190.7 10 19Q.8 USE OF FREEZE SEALS IN ABWR 190.8 1 19Q.9 SHUTDOWN VULNERABILITY RESULTING FROM NEW FEATURES 190.9 1 19Q.10 PROCEDURES 190.10-1 19Q.11
SUMMARY
OF REVIEW OF SIGNIFICANT SHUTDOWN EVENTS: ELECTRICAL POWER AND DECAY HEAT REMOVAL 190.11 1 19Q.12 RESULTS AND INTERFACE REOUIREMENTS 190.12 1 19 0.12.1 Insights Gained From The Analysis 190.12 1 190.12.2 Important design Features (Input to ITAAC) 190.12 2 19 0.12.3 Operator Actions (Input to COL Action items) 190.12 3 19 0.12.4 Reliability Goals (input to PRA) 19 0.12-4 19 0.12.5 Conclusions 19 0.12-5 A'ITACHMENT A FAULT TREES A'ITACHMENT 8 DHR RELIABILITY STUDY A'ITACHMENT C REVIEW OF SIGNIFICANT SHUTDOWN EVENTS: ELECTRICAL POWER AND DECAY HEAT REMOVAL 19 0-111 Amendment
i ABWR nuims Standard Plant an x 19Q.1 INTRODUCTION - Due to events at operating plants in the past several years such as the loss of off site power at Vogtle on March 20,1990 and the loss of decay heat removal (DHR) at Diablo Canyon on April 10,1987, i the shutdown risk associated with nuclear power plants has become more of a concern to the industry.
- On January 17, 1992 the NRC issued Draft i NUREG 1449, *NRC Staff Evaluation of Shutdown
- and Low Power Operation". In NUREG 1449 the NRC staff identified some safety issues that may result in new regulatory requirements.
! As part of the certification proecss for the ! advanced boiling water reactor (ABWR), an evaluation of the shutdown risk associated with the ' ABWR was completed. This Appendix discusses the design and procedural features of the ABWR that I contribute to the conclusion that the ABWR shutdovm risks are negligible. 4 s I i i 1~ l 4 l l i Amendment 190.1 1 1
-r_-r- , e-n--- w e
l ABWR mmas i Standard Plant wA 19Q.2 EVALUATION SCOPE Review and Safety Analysis Boiling Water Reactors
- were reviewed along with certain loss of The ABWR shutdown risk evaluation covers the DHR events from INPO Significant Evaluation important aspects of NUREG-1449 as well as- Reports (SERs) and Significant Operating specific items requested by the NRC. Experience Reports (SOERs) and NRC Information Notices. Over 100 precursor events to loss of DHR The evaluation encompasses plant operation in were reviewed.
modes 3 (hot shutdown),4 (cold shutdown), and 5 (refueling). The ABWR full power PRA covered To ensure that new features (i.e., different than operation in Modes 1 (power operation) and 2 current operating BWRs) of the ABWR do not (startup/ hot standby). This evaluation addresses introduce any additional vulnerabilities to operation conditions for which there is fuelin the reactor of the plant, a failure modes and effects analysis pressure vessel (RPV).. It includes all aspects of the (FMEA) was completed on these new features.The nuclear steam supply system (NSSS), the FMEA focused on the potential safety impact of containment, and all systems that support operarien identified failure modes and why these do not
- of the NSSS and containment. It does not address contribute to increased risk of ABWR shutdown
' events involving fuel handling outside the primary operation. cm .tainment or fuel storage in the spent fuel pool. Lastly, a detailed reliability study was completed The evaluation was broken down into several of the ABWR DHR function. Probab:listic risk i topics covering design, procedures, and ABWR assessment (PRA) models including Fault and Event ! features that have the potential to prevent / mitigate Trees were completed for all DHR and makeup-
! past operating events that are considered precursors systems. Based on PRA results, minimum sets of to loss of decay heat removal capability and fuel equipment were identified that,if available, would damage. The design issues included: decay heat result in acceptable shutdown risk.
removal, inventory control, containment integrity, 4' electrical power, reactivity control, and instru. Based on this shutdown risk evaluation, input has mentation. Guidelines for generation of ABWR pro- . been provided to other parts of the SSAR. Systems cedures are covered in a separate section, as well as and components important to safety were identified the risk implications of using freeze seats during for inclusion in the reliability assurance program.
, ABWR maintenance. COL action items such as a need for shutdown procedures and important operator actions were In NUREG.1449 it was pointed out that due to specified. Plant features important to risk reduction the increased level of maintenance activity while were identified and made part of the Inspections,
- shutdown, the potential for fires and flooding in Test, Analysis, and Acceptance Criteria (ITAAC operating nuclear plants is considered higher during Requirements).-
4 shutdown. These topics are covered separately to j highlight the ABWR features designed to minimize i the shutdown risks from fires and flooding. l In order to evaluate the ABWR features that are i capable of preventing or mitigating safety significant - 1 events that have occurred at operating plants in the past, a study was completed of specific past events that resulted either in a loss of offsite power or a challenge to DH~R. Loss of power events as described in NUREG 1410," Loss of Vital AC Power and the Residual Heat Removal System During 5 Mid. Loop Operation at Vogtle Unit 1 on March 20, l 1990* were evaluated and ABWR features which
.could have prevented / mitigated the event were described. A total of 74 loss of power events were evaluated. In a like manner, events described in i=
5 NSAC-88," Residual Heat Removal Experience Amendment 190.2 1 I f
ABWR mams Standard Plant Ro A 19Q.3
SUMMARY
OF RESULTS doors, equipment mounted on pedestals, and the 1 ability to fully contain potential flood sources (where The ABWR design has been evaluated for risks appropriate), j associated with shutdown conditions (i.e., modes 3,4, and 5). The evaluation included the following Adequate protection from fire is provided by shutdown risk categories discussed in NUREG.1449: means of fire barriers and physical separation of the three independent safety divisions. Use of fire
. Decay heat removal detectors, alarms, sprinkler systems, fire water
. Inventory control system and a trained crew of fire fighters keep the
. Containment integrity risk related to fire at a negligible level.
. Loss of electrical power
. Reactivity control To assure the flood and fire related risks are kept low during shutdown, the shutdown procedures that The evaluation also included shutdown risk the COL applicant is required to develop have been reduction features of the ABWR design due to identified.
instrumentation, flooding and fire protection, use of freeze seals, and procedure guidelines. ABWR Based on a FMEA of the new features features that are not part of current dometic BWR incorporated into the ABWR that are differee.t from designs were evaluated to determine if any new operating domestic BWR plants,it is concluded that shutdown risk vulnerabilities would be introduced, none of the new features willintroduce additional Finally, minimum sets of plant systems that if shutdown vulnerabilities, available would meet a goal of a conditional core .- melt probapility (i.e., given loss of one RHR system) Instrumentation was identified that is available of 1.0 x 10 were identified. during shutdown to adequately monitor the status of the plant and operation of systems which will result The results of this shutdown risk evaluation in low levels of shutdown risk. demonstrate that the ABWR incorporates design features which make the plant risk during shutdown Guidance was presented on how freeze seals negligible. This conclusion is based on the following could be used during maintenance on unisoable principal ABWR features which are capable of valves to minimize the risk associated with loss of the mitigating shutdown risks: freeze seal. Shutdown Risk Concern Principal ABWR Feature Recommendations on outage planning procedures , were presented to ensure that activities scheduled
. Decay Heat Removal Three physically and during outages take into account plant status and
, electrically independent potentially high risk periods or configurations during RHR and support systems shutdown. It was pointed out that the single most important element of reducing shutdown risk is inventory Control Multiple makeup systems. proper outage scheduEng of maintenance on systems and sources and support systems capable of removing decay heat or supplyinginventory makeup. Loss of ElectricalPower Two offsite and four onsite power sources An analysis of 70 loss of power and over 100 loss of DHR precursor events at operating BWRs Reactidty Control RPS and standby liquid confirmed that the ABWR design features would controf systems and prevent or mitigate the most safety significant of laterlocks to prevent - these events, accidental reactivity excursions The PRA model for analyzing the loss of DHR accident initiation identified about 12 systems that The ABWR is adequately protected from can be used to prevent core damage. The resultant internal flooding by redundant floor drains, sump core damage frequency was negligible (< < 1.0E 7 pumps, watertight doors, water level alarms, per-year) but the focus of the study was to identify automatic isolation of flow sources, raised sills on minimum combinations of systems that if available
' Arnendment 1903-1
4 ABWR nx6: mas Standard Plant _ Rev 4 would result in a conditional core melt probability which is less than the goal of 1.0E-5 per year gisen a loss of RHR event. It was found that generally about four of the 12 systems are sufficient to met the above goal. In all cases, the minimum type and number of systems required by technical specifications plus systems normally operating during shutdown (e.g., CRD and fire water) are sufficient to maintain adequate shutdown safety margins. Many such combinations are possible, but certain specific combinations of minimum sets of systems have been identified to provide guidance to the COL applicant. Additional minimum sets of systems can be identified by the COL applicant,if needed, by using the PRA model. These combinations of systems identified will allow COL owners much flexibility in preparing outage plans to enst.re that shutdown safety margins are adequate at all times. (9032 Amendment
ABWR 2mimas Standard Plant ne A APPENDIX 19Q.4 CONTENTS Section Htle P_ age 19Q.4.1 Dreav Heat Removal 19 0.4-1 19Q.4 2 Inventon Control 19 0.4-3 19Q.4 3 Containment Inteerity 190.4-6 19Q.4.4 Electrical Power 19 0.4-7 19Q.4.5 Reactivity Control 19 0.4-8 19Q.4.6 Summary of Shutdown Risk Catenorv Analysis 190.4-10 TABLES Table Illle Eage _ 190.4 1 ABWR features That Minimize Shutdown Risk 190.4-11 p 190.4-ii Amendmen' l
1 l ABWR umwas ! Standard Plant wA 19Q.4 FEATURES TO MINIMlZE shutdown can lead to fuel uncovery and damage. It SHUTDOWN RISK can be initiated by loss of the operating RHR system or by loss of an intermediate or ultimate heat sink. If As part of the process for certifying the AB% R loss of DHR occurs shortly after shutdown, bulk design, the NRC requested that General Electric boiling of reactor cooltnt and fuel uncovery can provide a specific discussion of ABWR features that - happen quickly (i.e.,less than one half hour for bulk minimize shutdown risk. boiling and approximately five hours to core uncovery if no protective action is taken). The list of ABWR shutdown risk features is presented in Table 190.41. The features are Past Esperience grouped by risk categories as discussed in NUREG 1449,"NRC Staff Evaluation of Shutdown There has never been a loss of DHR in a BWR and Low Power Operation". Fire protection was not which resulted in actual core uncovery but several discussed in NUREG 1449 but was added to the list precursors to such an event have occurred in the based on discussions with the NRC. The risk past. Section 190.11 discusses many of these categories ;re: precursor events and describes ABWR features that could have prevented or mitigated each event.
- Decay Heat Removal Inventory Con;rol For BWRs, the most common precursor events
- Containment Integrity involved temporary loss of RHR due to various
- Electrical Power reasons including inability to open Shutdown Cooling
- Flooding Control (SDC) valves inside containment and isolation of-
- Reactivity Control SDC due to low water levelin the RPV or loss of
- Fire Protection power to the Reactor Protection System (RPS). In all of these r.ases, redundant loops cf RHR or NUREG 1449 also discussed reactor coolant alternate DHR .nethods were available.
system pressurization but this was not included in the list because it is mainly a PWR issue. BWR shut- ABWR Features down pressure control concerns are ultimately inventory (i.e., LOCA) concerns and are addressed The ABWR contains many features to minimize under Inventory Control, the loss of DHR. The ABWR contains three divisions of RHR and associated support systems The ABWR has been designed with the mini- that are electrically and physically sepasated. This is mization of risk being a high priority. PRA methods the first line of defense in maintaining DHR. One have been very influentialin the design of the RHR loop could be in maintenance and if a single ABWR, The ABWR features described in Table - failure were to occur to the operating loop, the third-190.41 along with appropriate Technical Specifi- loop could be placed in service. It is also possible,if cations and utility operating and maintenance conditions warrant, to run RHR loops in parallel, in procedures (which contain insights gained from risk this case, failure of one loop would not result in even based evaluations) all result in the conclusion that a temporary loss of DHR. during shutdown conditions the ABWR is adequately protected against accidents and the estimated core in the unlikely event that all RHR loops were damage frequencyis negligible. unavailable, several alternate methods of DHR could - be used. Steam from the RPV could be directed to-The following sections describe the shutdown risk the main condenser (if available). Make up to the concern, past experience at operating bWRs for each - RPV could be supplied by many sources as discussed risk concern, and the ABWR features that contribute in Section 190.4.2. Other heat sinks include the sup-towards minimizing shutdown risk for each concern. pression pool (via the safety rclief valves), the reactor water cleanup system, or the spent fuel pool 19Q.4.1 Decay Heat Removal (if the reactor water levelis raised to the refueling level). As a final method,if the RPV bead was - Shutdawn Risk removed, bulk boiling of reactor coolant in the RPV with adequate make up would prevent fuel damage. Loss of decay heat removal (DHR) while 19 0.4-1 Amendment
4 ABWR 23^6t m s Standard Plant Rev A As mentioned above, SDC flow has been temporarily interrupted at operating plants in the past due to a loss of RPS logic power, Loss of RPS power does not result in isolation of the SDC system in the ABWR design. A loss of power to the multi plexed ABWR safety system logic would result in SDC isolation valves failing 'as is". It takes an actual need for completion of a safety function, not simply a loss of power,in order for the ABWR safety system logic to cause actuation of safety systems (e.g., isolation of SDC). From the above it can be seen that there are multiple methods to maintain DHR in the ABWR such that the shutdown risk associated with loss of DHR is negligible. Amendment 19042
ABWR u=xs Standard Plant n- x i 19Q.4.2 inventory Control During shutdown there are many maintenance tasks and evolutions that could lead to potential Shutdown Risk draining of the RPV. These include: CRD and Reactor Internal Pump (RIP) removal and Loss of inventory control can lead to uncovering replacement, and failures or operator errors associ. the fuct and damage by overheating. Reduction of ated with operation of the reactor water clean up reactor coolant inventory is more likely when the system and the RHR system. These potential plant is shutdown because additional paths for drainage paths are discussed below: diversion of coolant (e.g., RHR system) are operable. In addition, there are shutdown activities CRD Replacement such as test and maintenance that require seldom used valve line-ups and plant configurations which CRD replacement for the ABWR will use the increase the probability of operator errors associated same procedure followed for current operating with inventory control. BWRs. The CRD is withdrawn to the point where the CRD blade back seats onto the CRD guide tube. Past Experience This provides a metal to metal seal that prevents RPV drainage when the CRD is removed. The As discussed in Section 190.11, events at many years of BWR experience with CRD removal operating plants bve reaulted in reduction of reactor gives a high degree of assurance that the risk from coolant inventory. For BWRs this typically involved this operation will be negligible for the ABWR. diversion of reactor coolant from the RPV to the suppression pool due to improper valve line ups RIP Motor and Impeller Replacement _ (e.g., opening suppression pool suction valve before SDC suction was fully closed) or valve leakage (e.g., Nuclear plants with RIPS have been in operaion RHR pump mini recir: valve). Other inventory for over 15 years. Over 500 RIPS and motors have losses were due to leaking RHR heat exchanger been successfully removed and reinstalled in tubes, placing a partially drained RHR loop on line European BWR plants. This has demonstrated that following maintenance, and buckling of an RHR heat replacement activities can be carried out without exchanger due to marine growth. In all cases, the draining the vessel. loss of inventory was either recovered due to operator action or automatically stopped by isolation Replacement of RIP motor and impeller involves of SDC on low RPV level. the following steps. The RIP lower bolts are loosened and the pump allowed to move downward ABWR Features approximately 1/4 inch to the point where the impeller becomes backseated. An integralinflatable The ABWR contains several design features to sealis then actuated as a backup sealing device to minimize the potential for inventory loss. Indication assure no RPV leakage. The RIP motor can then be of RPV levelis displayed to the operator in the removed. Following motor removal, a temporary control room during all shutdown configurations cover plate is bolted to the bottom. The impeller is including refueling. To ensure adequate level is then removed from the top. The bolted cover plate maintained in the RPV, multiple sources of make-up prevents leakage of coolant from the RPV. After the exist including: Suppression pool, condensate impeller is removed, a plug is installed on the RPV storage tank, main condenser hotwell, and AC bottom head at the impeller nozzle to provide independent water addition system. additional protection against draining the RPV. To minimize the potential for pipe breaks, RHR During maintenance setivities on the RIP, there system valves are interlocked with reactor system are two periods when the potential for leakage is pressure to ensure that low pressure RHR piping is greatest: when removing the motor and when not exposed to full system pressure. In the event that completing maintenance on the secondary seals. In the interlocks fail or are bypassed, the RHR piping is both these cases, the temporary bottom cover plate is capable of withstanding full reactor pressure without removed. During motor removal, the primary and rupture, secondary seals prevent leakage but they could fail. In this case, only smallleakage could occur because of the tight clearances between the RIP housing and 190 4-3 Amendrnent
ABWR mums Standard Plant %x the impeller shaft. If the seals were to leak, the 11/4 inch line. Therefore, the probability of bottom cover could Fe bolted in place to prevent draining the RPV through the CRD hydraulic system further leakage. Maintenance on the secondary seals is considered negli6ible. requires removal of the motor, impeller and shaft, and the temporary bottom cover The plug on the Reactor Water Clean Up System (CUW) impeller shaft nozzle is the only protection against a major leak. Strict administrative procedures are During shutdowr., the CUW provides continuous implemented to ensure that the nozzle plug is not cleaning of the reactor coolant. Water is removed removed when the temporary bottom cover is not in through a line attached to the RPV bottom head and place, if the operator were to violate procedure and after passing through a series of heat exchangers and attempt to remove the nozzle plug @n the bottom a filter demineralizer is returned to the RPV either cover plate was also removed, the for.c required to via an attachment to the upper head or through the remove the less than 100 pound plug would be well feedwater lines and spargers, over 1000 pounds due to the head od water over the plug (the actual force will depend on the height of Potential drainage paths exist due to several water over the plug). The crane used to lift the plug maintenance flush and drain valves and CUW has an installed load cell and the operator should discharge paths to the low conductivity water (LCW) recognize the increased force required and sump and the suppression pool. The latter two paths investigate the cause. Even if the load cell is are urad during reactor startup to control excess miscalibrated or the operator fails to notice the reactor water due to heat up and thermal expansion. inercased force, upon initial lifting of the plug, maintenance personnel below the RIP would see the For any of the potential flow paths described leak and inform the operator. The plug could then above to result in RPV drainage, multiple failures of be replaced and the leak stopped. Due to the equipment and operator errors must occur. In multiple errors required to cause a major leak during addition, if the RPV were to start draining all but RIP maintenance, the risk from RIP maintenance is one of the potential flow paths (LCW sump) would considered negligible, be automatically isolated on low RPV level. The flow path to the LCW sump is controlled by two Control Rod Drive Hydraulle System valves in series one of which is locked closed and both are under administrative control. If drainage During operating modes 4 & 5, the control rod were to occur, LCW sump welllevel alarms would drive hydraulic system (CRDHS) continues annunciate in the control room. Also, the line is only operating with one pump running to provide purge 2* in diameter and so the flow rate would be slow water to the FMCRDs. With one pump in enough to allow ample operator time to mitigate the operation, the head of the pumping water can easily leak. overcome the head of water in the RPV; hence, draining the RPV is unlikely. In the event that Because of the multiple failures and operator neither pump is in operation, there are several errors that must occur to cause RPV drainage potential paths for draining the RPV through the through the CUW and the automatic RPV isolation CRDHS. logic to stop most potential flow paths, the risk of RPV drainage though the CUW is considered With neither CRD pump operating, the scram negligible, valves will open due to low Hydraulic Control Unit (HCU) charging header pressure. The scram valves . . Residual Heat Removal System may remain open due to operator error in not resetting the RPS logic or other system failures such The ABWR Residual Heat Removal (RHR) as loss of instrument air to the scram valve. This System is a closed system consisting of three combined with multiple mechanical failures to check independent pump loops (A, B, and C where B and valves and operator errors in CRD hydraulic system C are similar) which inject water into the vessel \ valve kneups could result in RPV drainage through and/or remove heat from the reactor core or the CRD hydraulic system. Multiple failures are containment. Loop A differs from B and C in that required for RPV Icakage to occur and even if a leak its return line goes to the reactor pressure vessel were to develop, only two CRDs would be affected (RPV) through the feedwater line whereas loop B & and the leak would be small since it would occur in a C return lines go directly to the RPV. In addition, Amendment 190 4-8
ABWR m6imas Standard Plant Rev A loop A does not have connections to the drywell or ulve must be fully closed before the suppression wetwell sprays or a return to the fuel pool cooling pool suction or return valve can be opened, the two system. However, for purposes of this analysis, the series dry well spray valves cannot be opened at the l differences are minor and the three loops can be same time unless the drywell pressure is high). Thus l considered identical. The RHR system has many loss of RPV level through these paths is not likely, i modes of operation, each mode making use of Loss of RPV level through the wetwell spray valve i common RHR system components. These requires a mechanical failure or an operator error to I components are actuated by the operator. Protective open the valve when not required. The only other 1 interlocks are provided to prevent the most likely potential path is sia the RHR pump mini flow valve. l interactions of mode combinations. This valve is designed to open to allow water flow back to the suppression poolif the RHR pump is The operator has five mode selection switches running at shutoff head. This is a pump pruettion available that will automatically perform the required feature. The valve opens and closes automatically valve alignment for the mode selected. This feature depending on measured RHR flow. reduces the chance of operator error by only requiring one action, selection of the mode switch, to Whether the potential flow path is caused by realign several valves. Only one mode at a time can mechanical failure or operator error, two features be operational, thus precluding potential undesirable er.ist to mitigate the loss of RPV level. On a kw multiple me interactions. The five modes are: 1) RPV level signal, both RPV isolation valves close to low pressur . coding; 2) suppression pool cooling; stop all flow out of the RPV. The RPV low level
- 3) shutdown cooling; 4) wetwell spray; and 5) drywell setpoint is 3.18 meters above the top of the fuel.
spray. Even if the low RPV level isolation feature were to fail (after a previous valve mechanical failure or There are two basic ways that the ABWR RPV operator error), flow out of the RPV would water level can potentially be decreased through the automatically stop when the RHR shutdown cooling RHR system during shutdown cooling. The first way nozzle is uncovered. At this point,1.7 meters of is through operator error in opening manual water would still be above the top of the active fuel. isolation valves that are used for RHR system Therefore, the draining of the RPV via the RHR maintenance. These paths are to the HiFh system to the point of uncovering the fuel and Conductivity Water sump and the Liquid Waste causing fuel damage is not considered credible for Flush system. These valves are normally closed the ABWR. during the shutdown cooling mode of plant operation. These are 2 inch and 6 inch lines Another potential for loss of inventory control is respectively. Inadvertent opening of these valves through the use of freeze seals on piping attached to would result in a relatively slow RPV level decrease the RPV. Section 190.8 discusnes how freeze seals which would be alarmed to the operator in the will be used on the ABWR and why the risks control room such that there would be adequate time associated with freeze seals will be small. to respond. If the operator failed to notice the decreased RPV level, an alarm would annunciate in In summary, the ABWR contains many redundant the control room and the RPV isolatisa valves would and diverse features such that, ang with the use of automatically close on low RPV level. The fuel experience proven administrative contrels, loss of would remain covered with water and no fue1 inventory controlis not a significant safety concern. damage would occur. The second way that RPV level could decrease would be for one of the motor operated valves (MOVs) in the RHR system to open inadvertently or by operator error. Most of the MOVs in the RHR system are interlocked to prevent inadvertent diversion of RPV water (e.g., the shutdown cooling (SDC) suction line is interlocked so that the suppression pool suction and return valves and wetwell spray valve must be closed before the SDC valve can be opened, the shutdown cooling suction Amendment 19Q 4 5
o ABWR me s i Standard Plant wa l l 19QA.3 Containment Integrity Shutdown Risk A breach of containment integrit;> is not by itself an issue of high safety significance but, in conjunction with other initiating events, could in-crease the severity of the initiating event. A breach of containment integrity followed by breach of another radiological barrier or boiling of the reactor coolant could lead to a direct release to the atmosphere. Attachment 190B discusses potential offsite releases following boiling in the RPV with the head removed and shows that releases would be a small fraction of normal operating limits. In addition, the PRA results in Section 190.7 indicate that the risk of RPV boiling is low. During refueling of the BWR, the primary containment is open and cannot be readily closed since the drywell head is removed. None the less, loss of containment integrity has not been an issue ._ for BWRs in the past. ABWR Features During shutdown with the drywell head removed, the ABWR has the secondary containment which can be automatically isolated on high radiation from a radiological boundary breach or fuel handling accident. The standby gas treatment system (SGTS) filters air from the secondary containment to reduce potential contamination to the atmosphere. The ABWR secondary containment and use of the SGTS results in a negligible risk concern for loss of containment integrity. NM Amendment
ABWR m ei o s Standard Plant w4 19Q.4.4 Electrical Power ABWR can use alternate sources of DHR with only on site power sources. Shutdown Risk in the event that one phase of the main A loss of all off site power challenges the on site transformer were to fail, an installed spare is sources to power safety related equipment to available to return the preferred source of off site maintain safe shutdown. Loss of individual buses power to service without the need to procure and (AC or DC) affects divisional train capability and deliver a new transforme r. results in loss of redundancy to complete required safety functions. As discussed more fully in Section 190.11, the ABWR clectrical power distribution system has Past Esperience features that are capable of mitigating potential loss of power events that have occurred at operating As discussed in Section 190.11, loss of power plants in the past. The design features described events have occurred at many nuclear power plants. above in conjunction with appropriate Technical There have been several cases of a total loss of Specifications and other administrative controls off site power which, in some instances, led to loss of result in an electrical distribution system that is able shutdown cooling and increases in coolant to maintain an adequate levei of redundancy and temperatures of as much as 140 F. capacity even with equipment out for maintenance or testing. This ensures that safety margins can be The majority of totalloss of off site power events maintained at all times during shutdown and normal were due either to severe weather or operator errors, plant operation. - Severallosses of on site power events were due to objects falling on transformers while operators were performing maintenance activities in the switchyard. In other cases, switching errors resulted in temporary loss of power to vital busses or off site power. ABWR Features The ABWR electrical system has the following features to prevent or mitigate potential loss of power events:
- Three physically and electrically independent Class 1E emergency diesel generators
- Two independent sources of off site power
- Three unit auxiliary transformers powering three Class 1E and non 1E power buses
- Combustion turbine generator (CTG) that can be used to power any of the Class 1E or non-1E buses The ABWR clectrical power system contains redundancy and diversity of electric power sources.
This allows sources to be in maintenance during shutdown and still have adequate power sources to meet potential equipment failures. Even in the case of a loss of off-site power, the CTG has the ability to start a feedwater or other pump for DHR or inventory makeup if required. This means that the Amendment 190 A7
g,,. . m _ ,. . . ., .,,2_ 2. _ . . . . .,.-#. .. +. a. , .._iu._..m,_ _ E ABWR uxsimxs Standard Plant no 4 19QA.5 Reactivity Control ABWR tod drop accident risk is considered negligible. 4 Shutdown Rhk Control Rod Ejection
- Reactivity control during shutdown may be a
- concern because local criticality can be achieved For a control rod ejection accident to occur while through movement of control rods or errors in fuel shutdown, RPV pressure would have to be increased
{ handling that may not be adequately detected by (e.g., during a hydrostatic test). The series of events installed neutron detectors. Also at lower that would have to occur are: temperatures, the inherent negative feedback , available at normal operating temperature and J) During RPV hydrostatic testing a control rod i pressure is less able to mitigate potential power is withdrawn for testing and, excursions. (2a) A break in the CRD housing of an adjacent
- While overall core shutdown margins are rod occurs which also results in failure of the adequate to protect the fuel as long as procedures internal control rod anti ejection supports 4
are followed, inadvertent withdrawal of two adjacent (' shootout restraints") CRDs or fuel handling errors can lead to fuel damage, or Past Experience (2b) A break in the CRD insert pipes coupled with i failure of both its ball check valve and, A few isolated cases of BWR shutdown reactivity electro-mechanical brake. control concerns have been identified in the past and were attributed to operator errors (e.g., withdrawing Due to the short amount of time that the RPV undergoes hydrostatic testing and the multiple the wrong controt rod). j failures required for a control rod ejection to occur, the risk from this event is considered negligible. Reactivity excursion events could occur due to j any one of the following: Refueling Error 1 - Control Rod Drop i - Control Rod Ejection During refueling, inserting a fuel bundle at the
- Refueling Error maximum fuel grapple speed into a fueled region of
- Rod Withdrawal Error the core which has a withdrawn control rod blade
' could result in a reactivity accident.
- Fuel Loading Error Control Rod Drop The ABWR features that prevent or mitigate -
refueling errors are: i While shutdown, the only time a control rod drop
- 'could occur is during control rod testing, if one (1) An interlock with the mode switch in the control rod is fully withdrawn, a rod block signal REFUEL position which prevents hoisting prevents withdrawal of a second control rod. If the another fuel assembly over the vessel if a rod block signal were to fail and the operator were to control blade has been removed.
incorrectly select an adjacent control rod for withdrawal, a latch mechanism exists such that if the (2) While in the REFUEL position, only one rod ' rod were to become stuck and decouple from its can be withdrawn at a time. Any attempt to
- drive it could only drop a maximum of eight inches, withdraw a second control rod would result in In addition, a Class 1E separation detection system - a rod block signal being initiated by the would sense a separated control rod drive and refueling interlock.
initiate a rod block signal. l (3) The operator would be alerted to a refueling-1 Due to the combination of events required to error by the source range neutron monitoring cause a control rod drop including operator error system.
;. coincident with' multiple mechanical failure 5, the Amendment 19Q 4-8 ~
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~$ ABWR :mimas an x Standard Plant Due to the combination of operator errors, interlock failures, and core configuration required for this event to occur, refueling accident risks are considered negligible. Rod Withdrawal Error if two adjacent control rods are withdrawn at the same time, the reactor may become critical. To prevent this the ABWR has a refueling interlock which prevents any more than one control rod being withdrawn at a time. If the interlock fails and the rod is withdrawn, the rods would scram on a high flux signal. The coincident failures of the refueling interlock and reactor protection system in conjunction with operator error, which are required to cause a rod withdrawal error are considered improbable and the risk negligible. Fuel Loading Error _ This event is similar to a refueling error, in this case the refueling procedure is not followed and a higher than design core reactivity configuration is formed. If not identified by the core verification process, subsequent control rod testing may result in inadvertent criticality and power excursion. A high flux scram would terminate the excursion. The risk from a fuelloading error is considered negligible because of the combination of events required for the accident to occur. Summary of Reactivity Control The ABWR refueling interlocks, control rod design, reactor protection system operability during shutdown, and strict administrative controls all combine to support the conclusion that shutdown Reactisity Controlis a negligible risk concern for the ABWR design. 1 190 4-9 Amendment
ABWR nx6tm^s nev ^ Standard Plant 19Q.4,6 Summary of Shutdown Risk Category Analysis The ABWR design was evaluated against shutdown risk categories from NUREG 1#9. The analysis took into account past experie nce at operating BWRs. The conclusion from this analysis is that the AB%R design contains multiple features to minimize potential risk during shutdown for the major shutdown risk categories. 10 Amendment
i ABWR = =s Standard Plant an A Table 19Q,41 ABWR FEATURES THAT MINIMIZE SilUTDOWN RISK CATEGORY FEATURE SHUTDOWN RISK CAPABILID' Decay }{ cat Residuall{ cat Removal Three independent (100% capacity) divisions of Removal (D11R) (RilR) System RilR and support systems for normal DliR. Each RilR division has several DilR modes 5 (e.g.,5DC, SPC).
- Reactor Coolant Temp- During shutdown, reactor coolant temperature is i crature Measurement determined by measuring reactor water cleanup l (CUW) inlet water temperature.
j Shutdon Cooling Nonle The shutdown cooling mode of RilR uses i i suction piping that connects directly to a nonle i on the RPV instead of to an external piping
- system. Thl 1 educes the probability of losing RilR pump suction due to air entrapment or '
i cavitation. i Safety Relief Valves Can be used as alternate means of decay heat removal by venting steam to the suppression ( pool. They are also actuated to depressurlie the RPV to allow use of low pressure R}{R or other . Iow pressure systems. i
- Suppression Pool A potential heat sink and make up source for
- decay heat removal. Pool temperature is moni-4 tored in the control room to indicate trends in pool temperature. This large heat sink allows s.
1 ufficient time for appropriate operator actions. i l Reactor Water Cleanup Can be used under certain conditions to remove System (CUW) decay heat. See Section 190.7 and Attachment j 190A for more details on this feature. RPV Boiling When the RPV head is removed, boiling is an l effective (although not preferred) heat transfer i method as long as RPV water level can be main-
- tained by available make up sontces.
Condenser The mair, condenser (if aval'able) can be used for DHR.' l 1 Remote Shutdown Panel Cold Shutdown can be achieved and maintained (Two Didsions) from outside the control room if the control room is uninhabitable due to fire, toxic gas, or I other reasons. The remote shutdown panel is ! powered by Class IE power to ensure availability following a Loss Of Preferred Power (LOPP). Controls are hard wired and thus not dependent 4 4 Amendment - 190 4 11 l 4
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7 _ _ ._._ _ _ .._ _ ._.. _ _ _ _ _ . _ . _ _ _ .. 1 ABWR - mas Standard Plant . Rev A i Table 19Q,41 I' AB%1t FEATURES THAT MINIMIZE SHUTDOWN RISK ! CATEGORY FEATURE SHUTDOWN RISK CAPABILI'IY . on multiplexing systems. A minimum set of . monitored parameters and controls are included to ensure the ability to achieve and maintain cold shutdown. ! Instrumentation Adequate Instrumentation is available to operators both inside and outside of the control room for monitoring shutdown conditions throughout the plant. Some of the safety significant parameters monitored during
- shutdown include: RPV water level, reactor
- coolant temperature, neutron flux, drywell pres.
l sure RHR flow, reactor pressure, and suppression pool temperature and level. In addition to monitoring, signals arc also avail-able to actuate ECCS functions on low RPV _ water level, scram control rods on high flux, and elose isolation valves on appropriate signals. Four divisions of instrumentation allow one . - dhision to be in maintenance witho'ut disabling the function, thus assuring availability of instrumentation during shutdown. Fuel Pool The fuel pool cooling system (FPC) can be used for DHR during mode 5 (refueling). The pool does not contain drains and includes antisiphon , devices to prevent inadvertent drainage. The RHRS can be interconnected to the FPC to aid cooling of fuelin the poolif required. Reactor Imentory H16h Strength Low Pres. Low pressure piping connected to high pressure sure Piping piping has been redesigned to a higher pressure rating and is therefore expected to withstand full ' reactor pressure on a rupture criteria basis. This minimh.es the potential for loss of inventory while shutdown. Interlocked RHR Valves The RPV shutdown cooling suction valve must be fully closed before the suppression pool return or suction va4ves can be opened. Shutdown cooling suction vahe cannot be opened until suppression pool suction and return valves are fully closed. This prevents inadvertent draining of the RPV to the suppression pool. 1904-12 , . Amendment : 9 g 9 9 9 y ---.yg..w g.y-..my w'h- e%y _mq -w,-i--,p m. , qpp,m m g wy ,,,,,w c,_y.q.,v.,
ABWR nasians llev A Standard Plant Table 19Q,41 ABWR FEATURES THAT MINIMlZE SHUTDOWN RISK (Continued) CATIGORY FEATURE SilVTDOWN RISK CAPABILITY RPV isolation Valves Alllargo diametet (>2 inches) isolation valves in the RilR and CUW systems that connert to the RPV (except injection lines) automatically close on a low RPV water level signal. --This reduces potential for the core being uncovered due to an inadvertent RPV drain down event. Make up Control If RPV level decreases, High Pressure Core-Flooder (HPCF), Automatic Depressur. Iration System (ADS), and Low Pressure Flooder (LPFL) systems initiate automati-cally.'If HPCF and LPFL systems are in the test mode and a RPV low level signalis received, the systems automatically switch to the vesselinjection mode. Feedwater and Cond. Three electric driven pumps that can be used ensate Pumps during shutdown for make up. High Pressure /14w Controls position of RilR valves to ensure Pressure Interlocks that the RHR is not exposed to pressurca in excess ofits design pressure. Make up Sources Multiple sources of RPV make up are poten-tially available while the plant is shutdown . (e.g., main condenser hotwell, condensate - storage tank, suppression pool, control rod drive system, AC ladependent water addition system). No Recirculation Elimination of Recirculation piping external Piping to RPV reduces probability of LOCA both . during normal operations and while shutdown. RPV 14velindication Permanently installed RPV water level indication for all modes of shutdown, Sensors arranged in a 2 out of 4 logic to ensure high reliability.
- Amendment 190 8'13
I ABWR msms Standard Plant an 4 J l 4 Table 19Q 41 AHWR FEATURES THAT MINIMlZE SHUTDOWN RISK (Continued) CATEGORY FEATURE SHUTDOWN RISK CAPABILl1T l Containment Integ. Containment Reinforced concrete structure surrounds rity RPV to withstand LOCA loads and contain radioactive products from potential accidents I during hof Autdown. Secondary containment > permits isolation and monitoring all potential radioactive leakage from the primary containment. Standby Gas Treatment Removes and treats contaminated air from l System the secondary containment following potential accidents. , Reactor Building tsola. Automatically closes isolation dampers on tion Control detection of high radiation. These dampers are potentialleakage paths for radioactive _ materials to the environs following breach of nuclear system barriers or a fuel handling accident. , Electrical Power 3 Diesel Generators One diesel for each safety didslon. Indepen. i dent, both electrically and physically, of each other to minimize common mode failure. Allows for diesel maintenance while vill maintaining redundancy.- Combustion Turbine Redundant and diverse means of supplying Generator power to safety and non safety buses in event ofloss of offsite power and diesel generator failures. - 2 Sources of Off.She Reduces risk of LOPP due to equipment Power failure or operator error, Electrical Cable Pen. Will prevent propagation of fire damage and etrations water from postulated flooding sources. 4 Divisions of DC Electrically and physically independent, Power . Includes batteries and chargers. Diverse . means'of electrical power for control circuits and emergencylighting. l l
. Amendment . 190 4-14 l
4 ABWR nuim4s Standard Plant un A . Table 19Q,41 ABWR FEATURES THAT MINIMIZE SHUTDOWN RISK (Continued) 4 CATEGORY FEATURE SHUTDOWN RISK CAPABILIW i 4 Flooding Control Flood Monitoring and Reactor, control, and turbine building ); Control Dooding is monitored and alarmed in the con-
- trol room, This alerts the operator to potential flooding during shutdown. Meny
~ l
. Good sources (e.g., HVAC, EDO Fuel) are relatively small volume and are selflimiting.
l j Operation of the fire water systert.15 alarmed ; e in the control room to help the og.crator differentiate between a break in the firewater I - system and the need to extinguish a fire. ( Larger sources are mitigated by means of 1 raised silis on room doors, equipment mounted on pedestals, floor drains, . watertight doors, pump trip,. valves closing, , i antisiphon valves, or operator actions. , j Room Separation The three divisions of ECCS are physically ! separated and self contained within flooding I resistant walls, floors, and doors. No ECCS 4 wall penetrations are located below the ! highest potential flood levelin the reactor i building first floor corridor. No external potential flooding sources are routed through 1 the ECCS rooms and potential flooding ! sources in other rooms will not overflow into i- the ECCS tooms and cause damage to ECCS electrical equipment. If ECCS flood barricts must be breached during shutdown, adminis-4 trative controls ensure that at least one ECCS division is operable and all barriers in that di-j vision are maintained intact. 3 i Reactivity Control Refueling Interlocks A system of interlocks that restricts movement of refueling equipment and l control rods during refueling to prevent . inadvertent criticality. When the mode switch !- is in the REFUEL position, only one control rod or rod pair can be withdrawn at a time. j! Fuel Handling Fuel handling and storage facilities are designed to prevent inadvertent criticality and to maintain adequate shielding and cooling for spent fuel. i 190 015 Amendment 1 3
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a ABWR nasuors Standard Plant Rev A Table 19Q.41 ABWR FEATURES THAT MINIMlZE SHUTDOWN RISK (Continued) CATEGORY FEATURE SHUTDOWN RISK CAPABILIW CRD Supports and CRD supports limit the travel of a control-Brake rod in the event a control rod housing is ruptured. The brake limits the velocity at which a control rod can fall out of the core should a hydraulle line break or failure of flange bolts or a spool piece. Both of these limit reactivity escursions and thus protect the fuel barrier. Instrumentation Reactor protection system (RPS) high flux (set down) and manual scram functions are ogwrable during shutdown. Fire Protection Divisional Se paration - The three ECCS divisions are physically separated so that a fire initiated in one - division will not propagate to another division. Procedures ensure that during shutdown if fire barriers between divisions must be breached due to maintenance, at least one division will be available with barri. ers intact. Detection Fire detection sensors that alarm in the control room are located throughout the plant and operate during shutdown. Actuation of the fire water system is alarmed in the control room. Also, during shutdown more personnel are located throughout the plant to identify, extinguish, and report potential fires. Suppression Water and chemical fire suppression systems are located at appropriate plant locations. Water Supplies Multiple water supplies and both electric and diesel powered fire pumps can deliver water to any location in the plant during shutdown. Multiplexed systems Eliminates the need for a cable spreading room which is a major fire concern in most plants. 19Q 416 Amendment
=
a ABWR :wiw^s ne, A Standard Plant Table 19Q.41 AllWR FEATURES TilAT 511Nih11ZE SilUTDOWN RISK (Continued) CATEGORY FEATURE SilUTDOWN RISK CAPAlllLITY llVAC Dual purpose HVAC/ SMOKE Control system, divirt onally separated, to control indhidual room pressure and assure clean air path for fire suppressiori personnel, b Amendment IN #^I
I ABWR 2 Mum ^s ' Slandard Plant Rev A 19Q.5 INSTRUMENTATION . Four channels of instrumentation to allow for bpass during maintenance and testing while l The ABWR instrumentation system contains still retaining tedundancy. (The many features that help reduce shutdown risk, two out of four logic reverts to twc.out-These features are contained in the basic design of of three during maintenance bypass), the instrument systems and in the type and number of parameters monitored. - Continuous monitoring for detection of Dres or nooding in safety related and other arcas. During shutdown, the main concern from a risk Operability of the reactor protection system i perspective is removal of decay heat from the fuel in . the RPV. The large volume of water in the spent (RPS) during shutdown to mitigate potential fuel pool and low probability of draining makes the reacthiry excursions. risk associated with fuel pool operation relatively low. The smaller reactor pressure vessel (RPV) . Interlocked refueling bridge operation to volume and relatively high decay heat load of the fuel prevent reacthiry excursion. increases the cooling requirements and decreases the
- available time to recover from loss of decay heat . Automatic isolation of shutdown cooling removal (DHR). Thus, to minimite shutdown risk, (SDC) on low level in the reactor pressure the instrument 41cn sptem must monitor RTV level vessel (RPV) to ensure against fuel ut>covery. ,
1 and water temperature, status of makeup sources i and heat sinks, and display these to the plant . Interlocked residual heat removal (RHR) l operators in a reliable and easy to understand valves (SDC and suppression pool) to reduce manner, the potential for diversion of coolant from the 7 j RPV to the suppression pool.
- Design Features
. Ability to control shutdown plant , status from ;
- The ABWR utilizes redundant channels of safety the remote shutdown panelin the event that
- related instruments for initiating safety actions and the control room becomes uninhabitable.
1 - monitoring plant status. This is accomplished by a i four division correlated and separated protection . = Ability to monitor radiation levels throughout i logic complex called the safety system logic and - the plant to detect breaches in radiological i control (SSLC). The SSLC receives signals from the barriers. redundant channels of instrumentation, displays information to the operator, and makes decisions on Parameters Monitored safety actions. l The key shutdown parameters monitored by the The safety system setpoints are determined by ABWR instrumentation system include: j analysis and experience, factoring in instrument
- crrors, drift, repeatability, safety margins, and the . RPV level, water temperature, and pressure need to minimize spurious actuations. The system i provides continuous automatic on line testing of the . Neutron Dux logic and offline semi automatic end to-end (sensor-
- input to trip actuator) testing.-This combination - ' Drywell and wetwell pressure and temperature 4
-meets all current regulatory requirements.
. Suppression pool temperature and level Specific instrumentation features important to shutdown operations include: . Reactor, turbine and control building Doooing level
. Automatic initiation of ECCS to ensure-adequate RPV make up. . RHR Dow rate and temperature
. Fire detection in various buildings
- Amendment 19031
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- Electric power distribution system parameters (e.g., power, voltage, current, Ircquency)
- Operation of fire water system 19032 Amendment
1 i l ABWR nwms j Signdard Plant w4 l; 19Q.6 FLOODING AND FIRE systems PROTECTION j The ADWR has three independent safety related
, The ABWR has been designed to minimize the divisions, any one of which is capable of maintaining i risks associated with fires and flooding though the the reactor in a safe cold shutdown condition. With 1 basic layout of the plant and the choice of systems to this arrangement, a single division may be out for ! enhance the plants tolerance to fires and flooding. maintenance and a single random failure could occur i which disabled another division, but the third i Plant Layout division could be available to ensure continued
- DHR. In addition, there are non. safety related sys.
The plant layout is such that points of po sible tems such as condensate that can be used to i common cause failure between safety related and maintain cold shutdown. non safety related systems have been minimized. As 4 an example, the control room is situated between the In general, systems are grouped together by safety 3 reactor building and the turbine buWing. Thus division so thatt with the exceptions of the primary
- safety related equipment and controls that are used containment, the control room, and the remote shut.
I to shutdown and maintain long term cold shutdown down room (when operating from the remote
- of the plant cannot be impacted by failures of shutdown panels); there is only one division of safe non safety related systems in the turbine building.' shutdown equipment in a fire area. Complete
- Likewise, non safety related systems / equipment in burnout of any fire area without recovery will not j tt e turb!ne building that could be used to reach and prevent continued DHR, therefore, complete i maintain cold shutdown (e.g., condensate, main burnout of a fire area is acceptable from a public risk.
l condenser) are not affected by failures of safety perspective, j related equipment, therefore, fr.teractions between i reactor and turbine building systems are minimized. The separation execption in the primary i containment is made because it is not practical to I Normal and alternate preferred power is divide the primary containment into three fire areas.
- supplied through the turbine building to the reactor The design is deemed acceptable because
building for safety related loads. These non safety related power sources are backed up by safety 1) Sprinkler coverage is provided by the ! related diesel generators located in the reactor containment spray system. building. The diesel generators are thus not affected by events in the turbine building. 2) Only check vtlves and ADS /SRV valves (if the l RPV head is on) are required to operate 5 The buildings are laid out internally so that fire within containment to provide DHR. A fire areas of the same division are grouped together in could not prevent the operation of a check i block form as much as possible. This grouping is valve nor would it prevent a safety valve from l coordinated from building to building so that the being lifted on its spring by pressure. The
- divisional fire areas lineup adjacent to each other at high pressure pumps are capable of providing l the interface between the reactor and control build- sufficient head to lift the SRV valves against l ing. An arrangement of this fashion natually groups their spring settings so that a fire could not
- piping, HVAC ducts, and cable trays together in prevent injection of water to and relief of
- divisional arrangements and does not require routing steam from the reactor vessel.
of services of one division across space allotted to another division. 3) In addition, maximum separation is . maintained between the divisional equipment
. A major difference between the ABWR and - within primary containment.
- current reactor designs is that due to the l multiplexing of plant systems, there is no need for a All divisions are present in the control room and cable spreading room.. This removes a significant this cannot be avoided. The remote shutdown panel
- source of potential fires that could lead to core provides redundant control of the DHR and ECCS
; damage both during normal plant operation and functions from outside of the control room. The shutdown conditions. controls on the remote shutdown panel are hard wired to the field devices and power supplies. The Amendment 19061 4
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1 ABWR rums Standard Plant an A signals between the remote shutdown panel and the 3) Electrical penetrations which are required to control room are multiplexed over fiber optic cables have been type tested to ASTM E119, so that there are no power supply interactions including a hose stream test. between the control room and the remote shutdown panel. 4) piping penetrations which are required to have been type tested to ASTM E119, including a There are some areas where there is equipment hose stream test. from more than one safety division in a fire area. Each of these cases is examined on an individual 5) Fire dampers for any HVAC duct penetrating basis to determine that the encroachment is required a fire barrier and which must have a rating of and that failure in the worst conceivable fashion is three hours. The only fire dampers separating acceptable. These are documented in the SSAR divisions are in the HVAC duct for secondary Section 9A.5.5 under Special Cases Fire Separation containment (six total). The plant for Disisional Electrical Systems. arrangement minimizes fire dampers. Divisions 1 and 2125 VDC and 120 VAC power 6) Fire rated columns and support beams, which supplies, reactor building cooling water pumps and are required to be of reinforced concrete heat exchangers, emergency chillers and emergency construction or, if of steel construction, HVAC systems are located in the control building. enclosed or coated to provide a three hout Since these systems are required for DHR if the rating. function of the control room is lost, they are separated from the control room complex and its 7) Backup of the fire barrier penetration seals by-HVAC system by rated fire barriers. A fire resulting the HVAC systems operatig in the smoke in the loss of function of the control room will not removal mode. This backup feature is affect the operation of the remote shutdown or accomplished in the reactor and control remote shutdown support systems. buildings by maintaining a positive static pressure for the redundant divisional fire areas When the plant is shutdown and if due to normal with respect to the fire area with the fire, maintenance or other work fire barriers must be Lenkage is into the fire impacted area under breached between two safety divisions, the third divi- sufficient static pressure to confine smoke and sion must be operable and its barriers checked to heat to the fire area experiencing the fire, even ensure they are intact. if there is a major mechanical failure of the penettation seal. Fire Containment Other aspects of the ABWR design that minimize The ' ire containment system is a combination of the ri.ek due to fires while shutdown are: structures and barriers that work together to confine the direct effects of a fire to the fire area in which - HVAC systems dedicated to the divisional the fire originates. The fire containment system is areas which they serve. comprised of the following elements:
- A smoke control system to remove smoke and
- 1) Concrete fire barrier floors, ceilings and walls heat from the affected area, to control the which must be at least six inches thick if made pressure in a room due to a fire, assure that from carbonate and silicious aggregates. any fire barrier leakage is into the fire area Other aggregates and thicknesses are experiencing the fire, and supply a clean air accep;able if the type of construction has path for fire suppression personnel. The been tested and bears a UL (or equal) label HVAC system has been designed for the dual for a three hour rating. purposes of HVAC and smoke control.
- 2) Fire doors,which are required to have a UL - Fire alarm systems.
(or equal) label certifying that they have been tested for a three hout rating per ASTM - Fire suppression system to automatically E119, including a hose stream test. initiate, where appropriate, and extinguish fi'es. Amendment 190 6-2 l
i 1 ABWR mas m4 i Standard Plant 2
- Manual fire suppression equipment such as Other aspects of the ABWR design that minimize
- hand held CO r chemical fire extinguishers, the risk from flooding are the practice of not routing and hoses, 2 unlimited sources of water (e.g., service water) i through divisional areas and ensuring that other -
i . Administrative controls to ensure that at least large water sources (e.g., suppression pool) can be
- one safety division is available with intact contained without damaging equipment in more than barriers at all times. one safety division if a flool were to occur.
,i
, Fires During Maintenance An analysis has been completed of all ABWR
. internal flood sources and the tenits show that When the plant is shutdown, maintenance during shutdown conditions at leasi onc safety activities may require breaching the fire barriers for division would be unaffected by water da nage for i
! one or more activities. The recommended outage any postulated Hood. Features, beside sepration, i philosophy regarding fire barrier integrity is that that contribute to this low level of r!si m:
through administrative controls, one division of Adequately sized room floor drains, water level
- safety equipment will be available (i.e., not in alarms and auton atic isolation of flood sources for maintenance) and its physical barriers will be intact. potentially affected rooms, mounting motors and This division will be in standby and one other other electrical equipment on pedestals above floci i
i division will be operating to remove decay heat and level, and watertight doors, As was discussed unt'er
! complete other required functions (e.g., fuel pool fire protection, administrative controls will be cooling, t,ixt> purging, reactor water cleanup). The implemented to assure that at least one ssfety third division could then be fully in maintenance, in division with intact barriers is available at all t mes this configuration, a fire in any one division would during plant shutdown. The watertight doois on
! not result in loss of decay heat removal capability, if - ECCS rooms are designed not to open under a htad the fire were to occur in the intact division, the fire of water due to Goodingin the ECCS toom. Taf.
- barriers would restrict the fire to that division only seals on the doors seat with water pressure from and the operating division could continue to remove Doods outside the room but only smallleakage past decay heat. For fires in either of the other two the seals is expected from flooding in the ECCS divisions, even if the barriers between the two room.- Therefore, during shutdown if maintenance j divisions were breached, the intact division would be' tasks require breaching the barriers of two divisions, 1
available to remove decay heb. flooditg in the intact division will not cause damage l to equipment in all three divisions. Additional As discussed more fully in 190.7, the COL details on the ABWR flood mitigation capability is 1 applicant must identify a minimum set of systems contained in Appendix 19R. that will not be in maintenance such that the i conditional probability of core damage due to certain Summary of Fire and Flood Features initiating events is less than 1E 5. The minimum set + selected should take into account fires in various The ABWR has been designed to minimize the
- locations of the plant, if the above outage risk due to fires or flooding during shutdown
- philosophy is followed, the risk from fires during conditions by plant configuration and system design.
shutdown conuitions will be low, Divisional separation, both physically and
- electrically, as well as fire / flooding mitigation Flooding systems exist to reduce plant risks from these
' potential accidents. Along with these design -
- - Many of the features that are designed to features, administrative controls are implemented to mitigate fires also serve to protect the plant from ensure that at least one safety division is not in damage due to Gooding. Physical separation of maintenance and its physical barriers are intact.
safety divisions not only prevents propagation of fires but also restricts or prevents flooding of safety
, related equipment. The fire barriers will also prevent potential water from entering a divisional area due to flooding from non divisional sources or
- contain water in the fire area for divisional water
- sources.
190.6 3 Amadment _ . _ . , - - - _ _ - -- - - -- -,, - . - - - . . .. - ,. - _ ~ -
ABWR mums Standard Plant a., a APPENDIX 19Q.7 CONTENTS Section Il11e East 19Q.7.1 Introduedl9.D 190.7 1 19Q.7.2 Eurpose 190.7 2 19Q.7J Summary 190.7 3 19Q.7.4 Methodoloav 190.7 4 19Q.7.5 Core Dama=e Probabillty Goal and RPV Bollinn 190.7.$ 19Q.7.6 Success Criteria 19 0.7/i 19Q.7.7 Accident Proeression and Event Tress 190.7 7 190.7.7.1 Loss of RHR Due to Failure in the Operating RHR System 190.7 7 19 0.7.7.2 Loss of RHR Due to Loss of Service Water 190.78 190.7.73 Loss of RHR Due to Loss of Offsite Power 190.7 8 19Q.7J Svstem Fault Trees 190.79 19Q.7.9 Results and Conclusions 190.7 10 19 0.7.9.1 Introduction 190.7 10 19 0.7.9.2 Loss of RHR Initiator 190.7 10 190.7.93 im of SW Initiator 190.7 11 19 0.7.9.4 Loss of Offsite Power laitiator 190.711 19 0.7.9.5 Adequacy of Technical Specification 190.7 11 TABLES Table Ililt East 190.7 1 Success Criteria For Prevention Of Core Damage 190.7 13 190.7 2 Minimum Sets Of Systems For Modes 3 And 4 190.7 14 190.7 3 - Minimum Sets Of Systems For Mode $ (Unflooded) 190.7 15 190.7-il Amendment y- - -- 2 .w--.- m. - - ---w .=.Wii
ABWR u^uas Rn ^ Slandard Plant APPENDIX 19Q.7 TABLES (Continued) Table Illic Page 190.7 4 Minimum Sets of Systems for Mode 5 (flooded) 190.7 16 ILLUSTRATIONS Figure Illh Eagt f 190.7 1 Loss of One RHR Mode 3, Starting at 4 Hrs 190.7 17 190.7 2 Loss of One RHR Mode 4,6 Hrs to 2 Days 190.7 18 190.7 3 less of One RHR Mode 5,2 to 3 Days 190.719 19 0.7-4 less of One RHR Mode 5,3 to 4.5 Days 190.7 20 190.7 5 Loss of One RHR Mode 5,4.3 to 14 Days 190.7 21 - 19 0.7-6 loss of One RHR Mode 5,14 to 33 Days 190.7 22 190.7 7 loss of Div A Sws Mode 3, Starting at 4 Hrs 19D.7 23 190.7 8 Loss of Div A Sws Mode 4,6 Hrs to 2 Days 190.7 24 190.7 9 Loss of Div A Sws Mode 5. 2 to 33 Days 190.7 25 190.7 10 Loss of Div C Sws Mode 3, Starting at 4 Hrs 190.7 26 190.7 11 Loss of Div C Sws Mode 4,6 Hrs to 2 Days 190.7 27 190.7 12 loss of Div C Sws Mode 5,2 to 3 days 190.7 28 190.7 13 Loss of Div C Sws Mode 5,3 to 4.5 Days 190.7 29 190.7 14 loss of Div C Sws Mode 5,4.5 to 14 Days 190.7 30 190.7 15 Loss of Div C Sws Mode 5,14 to 33 Days 190.7 31 .i 190.7 16 Loss of Offsite Power Mode 3, Starting at 4 Hrs 190.7-32 190.717 Loss of Offsite Power Mode 4,6 Hrs to 2 Days 190.7 33 190.7 18 loss of Offsite Power Mode 5,2 to 33 Days 190.7 34 190.7 iii Amendment
4 ' ABWR m si m s an. A Standard Plant 19Q.7 DECAY HEAT REMOVAL RELIABILITY STUDY 19Q.7.1 Introduction As part of the ABWR shutdown risk evaluation, a reliability assessment of the decay heat removal (DHR) capability was completed. Decay heat removal reliability has received increasing attention due to events such as those at Vogtle and Diablo Canyon where deesy heat removal systems were made inoperable due to loss of electric power and other causes. Attachment 190C summartres approximately 200 events at operating plants which were either loss of decay heat removal events or precursors to sneh events. The ;;latively large number of events underscores the potential for loss of decay heat removal c.u.ts and the potential for associated core damage. 190 % 1 Amendment
ABM zwimas a,a Standard Plant 19Q.7.2 Purpose The purpose of this study is to determine the minimum number of systems that might be available during shutdown to ensure that the risks associated with loss of decay heat removal events are acceptable. For the purposes of this study, acceptable risk is assumed to be I conditional core damage probability of 1.0E 5. That is, given a loss of the operstioS RilR system for any reason, the subsequent conditional probability of core damage must be less than 1.0E 5 using only those systems that are potentially available (i.e., system not in maintenance but which could experience random failures). The results of this study provides guidance regarding various combinations of systems, that if kept available during a plant outage, will ensure that the risk associated with loss of DiiR systems will be acceptable. A utility may choose to keep more systems available but as long as a minimum set is made available, shutdown risk will be considered acceptable. This minimum set of systems will give a utility flexibility in scheduling maintenance activities for DHR systems. The minimum sets described in this study are representative of acceptable combinations. There may be additional sets of equipment that were not included in this study which would also result in acceptable risk levels. The minimum sets of systems take into account plant conditions (i.e., modes) and the fuel decay heat generation rate as a function of time. Both safety and non safety (e.g., power conversion) systems are included in the minimum sets. 190 12 Amendment { 1
ABWR urams P.ev A Standard Plant 19Q.7.3 Summary outage schedules to ensure adet, . safety margins are maintained at all times during the outage. The Using probabilistic risk assessment (PRA) risk goal can,in general, be met by just those systems techniques, an acceptable level of shutdown risk required to be operable (and theiefore available) by (conditional probabilit) of 1.0E 5 for core damage the ABWR Technical Specifications plus normally given a loss of an RHR system) was demonstrated operating systems (e.g., CRD, fire water, CUW). for sarious minimum sets of equipment and systems that were assu.aed to be available (i.e., not in maintenance). These minimum sets were determined for an initiating event insolving loss of an operating RHR system. The three primary causes of a loss of the RHR system were identified to be the following:
- 1) Mechanical or electrical failures in the operating RHR system.
- 2) Loss of service water associated with the operating RHR system.
- 3) Loss of offsite power.
Loss of service water and offsite power were evaluated separately as the cause for loss of RHR because of their impact on other DilR systems, Each potential cause for loss of the RHR system was considered an initiating event. Recommended minimum sets of systems were identified based on the assumption that the loss of RHR was due to 1) above. Modifications to the sets were made for loss of service water as the initiating event. Separately, a recommended minimum set of electrical power sources were identified to protect against loss of offsite power. Success criteria were determined for each initiating event, taking into account decay heat load and plant operating mode. Minimum complements of systems that will prevent core damage given the initiating event and the time dependent core decay beat generation rate were then identified. Event trees were generated based on the assumed initiating event and applicable success criteria. System failure probabilities were determined with the help of fault tree analysis. The results from the study are summarized in Tables 190.7 2,190.7 3, and 190.7 4. The tables show that significant flexibility exists for completion of system maintenance during outages while still maintaining adequate safety margins. These minimum sets of systems can be used by utilities for initial outege planning and for evaluating changes to 190 M Amendment 1
UA M As ABWR ku 4 Standard Plant 19Q.7.4 Methodology used for this study. The loss of RHR escra is assumed to terminate successfully if the mitigning The methodology used in this study was the same systems start and run for a period of 24 hours. It is utilized in full power PRAs (i.e., event trees and fault assumed that provisions for long term maintenance trees). The plant is assumed to be shutdown with of decay heat removal will be made within 24 hours. decay heat being removed by the RHR system in the This assumption is consistent with other full power shutdown cooling (SDC) mode. Loss of the PRAs. operating RHR system is then assumed. The loss A number of deterministic analyses were could occur due to mechanical or electrical component failures of the RHR systern, loss of performed and documented it, Attachment 190B. service (i.e., cooling) water in the same division as These include the estimation of time available for the operating RHR system, or loss of offsite operator action and human reliability analysis to electrical power. The three types of failures are estimate the probability of operator error under assumed to be initiating events. various conditions. For each initiating event, the success criteria The event trees were quantified with an initiating were determinert. The success criteria are the vent frquency of 1.0. Thus the core damage minimum complement of systems that are capable of probt.bility that is obtained by (Hs evaluation yields preventing core damage. As the decay beat load is the conditional probability of core damage given a dependent on the time following shutdown, the loss of decay heat removal event The event trees minirnum systems required to remove the decay heat were quantified assuming various complements of will also be time dependent. Therefore, the success systems to be available. The various minimunt criteria have been determined as a function of time. complements of systems that met the 1.0E 5 goal Section 190.7.6 discusses the success criteria in more were selected for inclusion in Table 190.71. detait Maintenance of the suppression pool was not With the help of the success criteria, event trees modeled in this study. If the suppression poollevel for each initiating event were developed for each must be lowered for any reason, several options exist, period. A total of 18 event trees were analyzed, such as: off loading all fuelin the RPV to the spent Section 190.7.7 discusses the event trees. fuel pool or making systems available which do not rely on the suppression pool as a source of water The branch points on the event trees model the (e.g., condensate, fire water, HPCF). From a risk probability of success and failure for each system perspective, the suppression pool should only be included in the success criteria. The failure drained during periods when it is not relied upon for a source of water or heat sink in performance of an probability for each system was evaluated by a fauli tree analysis. The fault trees model potential system ECCS function. If the above recommendations are failures due to mechanical failure of components, followed, the suppression pool unavailability will loss of electric power to pumps or valves, or operator have a negligible impact on core damage frequency errors associated with manual actions (e.g., valve line during shutdown. ups or remote control of pumps and valves). Unavailability due to maintenance was modeled as follows. For a system included in a minimum set, the maintenauce unavailability was taken to be 0 (i.e., the system is assumed to not be in maintenance). For a system not in a minimum set, the maintenance unavailability was taken to be 1. In other words, the system was assumed to be completely unavailable. This is a very conservative assumption because it is unlikely that all systems allowed to be in maintenance would all be in maintenance at the same time, in addition, some systems in maintenance snight be returned to service in time. The fault trees used in this study are contained in Attachment 190A. A mission time of 24 hours was 190 7-8 Amendmen
ABWR nwmas u4 Standard Plant 19Q.7.5 Core Damage Probability Goal CUw, RHR, HPCF, and FPC. No other areas in and RPV Bolling the plant would be exposed to the steam environment that operators would need to enter to The conditional core damage probability goal of assure continued decay heat remosal capabinty. 1.0E 5 was selected for this study for the folhwing reasons. The initiating event frequency for loss of an The RHR and HPCF systems are qualified for a RHR system is not included in this probability goal, harsh environment and their operation would not be but can be conservatively assumed to be 0.1 per year, affected by the steam. The impact of the steam on in the analysis, it is conservatively assumed that all operation of CUW or FPC is a moot point because systems not explicitly required to be kept out of either the systems had previously failed or the decay maintenance are totally unavailable (i.e., all in heat load exceeded their capacity or boiling would maintenance). Then, the conditional core damage not have occurred. probability of 1.0E.$ for the remaining systems would result in a conservative core damage The CRD system is not qualified for a steam environment but due to its hardy construction it frequency of 1.0E 6 per reactor year, would be expected to operate for some period of This compares to the NRC goal of an overall time. Depending on the decay beat load, the time to core damse frequency of 1.0E-4 and a large release boiling could vary between 446 hours. After 4.5 goal of 1.0E-6 per reactor year, in reality, loss of days, the time to boiling is approximately 15 hours RHR events occur less than 0.1 times per year and and after 14 days is 26 hours. Therefore, for most of more importantly, not all systems allowed to be in the outage, the CRD system could be relied upon for maintenance will all be in maintenance at the same makeup for a significant period of time following lost time. Typically, the results show that more than six of normal decay heat removal before being damaged to ten systems are allowed to be under maintenance by the steam environment, and there is a very low probability that all the systems will be simultaneously under maintenance. There would also be non safety related equipment An analysis using more realistic maintenance in other buildings that would not experience the unavailability assumptions results in core damage steam enviroment which could be relied upon for frequency estimates less than 1.0E 7 per makeup (e.g., condensate). The fire water system reactor year. The simplifying assumption of 0 or 1 can also be used for makeup at low pressure. for maintenance unavailability allows for the calculation of core damage probabilities without The fire water system ties into the RHR system having to model maintenance unavailability for each through a connection on the outside of the reactor system. This avoids discussion of overlapping building. Three RHR valves inside the reactor maintenance periods for systems during outages. building must be manually opened to inject fire These conservative assumptions allow for a water into the RPV Adequate time would be straightforward determination of minimum system available to open these valves following loss of RHR - availabilities that also meet the NRC risk goals. before boiling occurred so that the operator would not be affected by the steam environment. All other la Mode 5 with the RPV bead removed,it is operator actions to mitigate loss of RHR can be assumed that successful DHR can be achieved by performed outside the reactor building. allowing water in the RPV to boil and making up lost water by various water sources. Boiling under these conditions is an effective means of DHR but it is not desirable because the resultant pressure buildup in secondary containment could catuse loss of containment integrity (l.c., steam reletse to the atmosphere). Calculations presented in Attachment 190B show that the boiling release rates, assuming l no core damage, are well below allowable limits for l normal plant operations. l Equipment in the reactor building would be exposed to the steam environment including: CRD, 190 73 Amendment
ABWR mm46
%4 Standard Plant l 19Q.7.6 Success Criteria available from the condensate LPFL or AC independent water addition systems. Low In order to prevent core damage given an pressure makeup may require inhiating esent, sufficient systems must be available depressurization of the RPV by actuation of to ensure that the core decay heat is removed and ADS or individual SRVs. :
t the fuel remains covered by water. No fuel damage will occur as long as the fuel remains covered by 3) In Mode 5 with the RPV head removed, water. There are three ways to achieve success: a) boiling of water in the RPV with adequate remove decay heat directly from the coolant in the makeup from low or high pressure sources is ! RPV; b) remove decay heat indirectly by condensing considered success for the purposes of this the steam produced, and provide makeup water to study, the RPVt and c) allow the coolant to boilin the RPV and provide makeup water to the RPV to keep the Mitigation of loss of offsite power requires recovery of offsite power or use of the emergency i core covered, diesel generators or combustion turbine generator. These three ways to achieve success are discussed The AC independent water addition system can be in detail below: used for make up in the event of a loss of all AC power.
- 1) Direct Decay Heat Removal from RPV .
Recovery of the failed RHR system, use of The success criteria and event trees do not , one of the other two RHR systems (SDC) or explicitly model maintenance of RPV water level for the reactor water cleanup (CUW) system availability of the reactor water cleanup system or- i (under certain plant conditions)is sufficient RHR. RPV levelis assumed to be maintained by for success. The CUW system capacity is automatic activation of ECCS (i.e., LPFL or HPCF) temperature dependent and requires both in Modes 2 4 and Mode 5 (reactor cavity pumps and nonregenerative heat enchangers unflooded). In Mode 5 with the reactor cavity (the regenerative heat exchangers must be flooded, RPV level control is assurred since the bypassed). In Mode 5, the fuel pool cooling water level will be 23 feet above the RPV flange. and cleanup (FPC) system can be used after the reactor cavity is flooded. FPC alone after Table 190.71 summarizes the loss of RHR 4.5 days or in conjunction with CUW at success criteria, earlier times is sufficient to remove all the decay beat. Both FPC pumps and heat exchangers and the supporting systems are required. - ;
- 2) Decay Heat Removal and RPV Water <
Makeup . Under certain plant conditions the main condenser,if available, can be used to remove decay heat by condeasing steam. The MSIVs must be opened and a condensate return path to the RPV is required. if the condenser is unavailable, steam can be released through the SRVs into the suppression pool and RPV makeup can be supplied by several sources, The availability of the SRVs is not explicitly modelled. At least one SRV is expected to be operable in the safety mode (i.e., spring pressure) even if power is not available. High pressure makeup can be accomplished by the HPCF, CRD, or feedwater and condensate systems. Low pressure makeup is 1476 Amendment - __ , , _ . , . , - . _ , _. .. - _ ,___-..,;. , w - --
ABWR u^simas Standard Plant Reg A 19Q.7,7 Accident Progression and Event decay heat (W2)if the RPV temperature is abose j Trces 234 F. ; l Loss of RHR may initiate from a failure in the if all DHR means are unavailable, the only path operating RHR System, loss of Service Water to success is to keep the core covered by either high System, or loss of offsite power. The accident pressure or low pressure sources. The high pressure progression for each of the above initiators is sources are feedwater and condensate (Q), HPCF discussed below. (UH), or a CRD pump (C). The HPCF initiates automatically whereas the other two systems require 19Q.7,7.1 Loss of RHR Due to Failure la operator action. If all these fail, the operator must the Operating RHR System depressurire the RPV by actuation of individual SRVs or ADS willihitlate automatically (X) on low . water level in the RPV. Successful depressurization -l Following reactor shutdown, the plant is cooled down by rejecting steam to the main condenset and would make the LPFL (VI), condensate (CDS), or l making up water loss in the RPV by the feedwater AC independent water addition (FW) systems system. The RHR system in the SDC mode can be available , , initiated at about 150 psia which corresponds to approximately 360*F. The RHR system is then used Failure to depressurire the reactor or failure of to cool down to either Mode 4 (less than 200 F) or FW leads to core damage. ' Mode 5 (refueling). Loss of the operating RHR loop is assumed to occur sometime after at has been if at node OP, the operator falls to follow the initiated. correct procedure, the reactor coolant temperature. and pressure in the RPV will rise, the SRVs will Less of RHR in Mode 3 or 4 open and discharge steam to the suppression pool and eventually the HPCF will initiate (UH) on low Figure 190.71 and 190.7 2 are the escot trees RPV water level, if HPCF fails, ADS will actuate on for loss of RHR in Mode 3 or 4, respectively. The low water level (X). Failure to depressurize will lead following discussion applies to both event trees. to core damage. Following successful reactor Following loss of the operating RHR loop (event depressurization, LPFL will inject on low water tree node RHR), the operator has to recognize the level (VI). Failure to inject with LPFL leads to core event and start following the correct procedure (OP). damage. The sequence of events following the successful outcome at this node is described first. The operator less of RHR in Mode $ can identify the failed system and request the maintenance crew to restore it to operation. An Figure 190.7 3 shows the event tree for loss of analysis showed that for the decay heat load at this RHR in Mode 5 less than 3 days after shutdown. time, water in the RPV would begin to boilin 1.3 This sequence is the same as the previous one except hours. Using a typical mean time to repair for the that since the RPV head is removed, the main RHR system, and 1.3 hours as the time for recovery,' condenser and feedwater pumps are unavailable and the system recovery probability was determined ADS is not required 3s the RPV cannot become (REC). pressurized. Also, at this low temperature, CUW by itself is not capable of removing all the decay heat if the failed RHR system cannot be recovered, generated within three days of shutdown, the operator could initiate one of the other two RHR systems,if available,in the shutdown cooling mode Figure 190.7 4 shows the event tree for loss of (R). If all RHR systems fail, the RPV would RHR in Mode 5 for 3-4.5 days after shutdown. If the pressurize and the main condenser could be made reactor cavity has been flooded and the spent fuel available (V2) by opening the MSIVs, drawing a pool gates are opened, the fuel pool cooling and vacuum in the condenser, and operating the cleanup (FPC) and CUW systems together (RF) feedwater and condensate pumps for makeup. have adequate capacity to remove the decay heat 3 days following shutdown. Use of these systems if the main condenser fails or is unavailable, the requires operator action. The other success paths operator can use the CUW system to remove the are the same as in the previous event tree (Figure 190.7 3). Figure 190.7 5 shows the event tree for . Amendmcat , IW 7
I ABWR nuims n,, x 3 Standard Plant loss of RHR in Mode $ for the period 4.5.a4 days I and Figure 190.7-6 shows the event tree for greater } than 14 days. The differences in these event trees ) are that for the period 4.514 days FPC alone is . success (FPC) and beyond 14 days CUW alone (W2) is success. l j 19Q.7.7.2 Loss of RHR Due to Loss of Service 1 Water f Figures 190.7 7 tbrough 190.715 show tbe event l trees for loss of service water. The scenarios are , ! basically the same as for a loss of RHR except that
! loss of service water may impact other DHR or j- makeup systems in addition to the operating RHR 1 pump. For example, loss of Division A senice water L also results in loss of CUW and FPC. Likewise, loss of Division C senice water causes loss of HPCF(C) in addition to tbc Disision C RHR pump.
{ 1 l 19Q.7.7.3 less of RHR Due to less of Offsite 1 Power 4
< Figures 190.716,190.717 and 190.718 show the event trees for loss of offsite power in Modes 3, 4, and $ respectively. The success criteria are the
- j. same but longer time is available for recovery in l Mode 5, Following a loss of offsite power, it is- ,
t possible to recover power in time to prevent core ,
- damage. If power is not recovered, the available DG will start automatically. and if the DG fails, CTG can il be manually initiated. Following loss of all AC
! power, the AC independent water addition system j can be used for make up if the RPV can be 4 depressurized by opening SRVs. l i I b I I el t i 19 0.1-8 Amendment l 2
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ABWR urum^s He, A Standard Plant 19Q.7.8 System Fault Trees The unasailability of a system to perform its safety function on demand given a loss of RilR was evaluated by fault tree analysis. Eleven fault trees were used in this analysis. The fault trees are contained in Attachment 190A, Five of the fault trees: liPCF, RilR (SDC), RilR (LPFL), Reactor Duilding Service Water, and ADS were taken from the full power PRA with modifications (e.g., maintenance unavailability and operator actions) to refleet shutdown conditions. The other six fault trees were developed specifically for the shutdown PRA and include: Reactor Water Cleanup, Fuel Pool Cooling. Main Condenser, CRD, Condensate, and Feedwater. The fault trees model system unavailability due to mechanical f ailures, loss of power, and operator errors. Ar, previously mentioned, maintenance unavailability is either issumed to be 1 or 0 (i.e., . system is in or out oi dntenance). The unavailability of the AC independent water addition system was estimated based on the assumed operator error in manually initiating the system. Amendment 190 19
ABWR msms
%4 Sandard Plant 19Q,7.9 Results and Conclusions may become unavailable due to random failures or operator errors. All division 'C' systems are 19Q.7.9.1 Introduction assumed to be in maintenance. For the abuse assumed configuration, one of the isolation valses for The esent trees described in the previous section RHRB is powered by division 'c'(due to single were naluated and the core damage probability f ailure concerns with containment isolation). If calculated with certain systems assumed unavailable RilRB is required, the valve can be opened manually due to maintenance in general,the minimum set of or didsion 'C' power made available momentarily.
equipment assumed to be available was initially This configuration was selected because it is one that taken as that required by the Technical meets minimum technical specincation requirements Specifications for the given operating mode. (i.e.,2 ECCS and 2 RHR systems available). Other Combinations of systems were made available until a configurations could have been selected but this one set resulted in a conditional probability of less than is typical and the resulting minimum sets identified 1.0E.5. Each of these sequences that met the 1.0E 5 will demonstrate the low risk associated with loss of criterion is considered a minimum set for assuring decay heat removal for the ADWR and the flexibility acceptable shutdown risk. afforded utilities for outage maintenance scheduling while still maintaining low risk levels. If one of the Minimum sets were obtained for each of the assumed power sources becomes unavailabic, the three loss of RHR initiators: Loss of Operating utility should make another power source (e.g., a RHR System Loss of Operating SW System and second EDG) available to ensure tbc safety criterion Loss of Offsite Power, will be met. Normal surveillance testing should be used to assure the availability of these systems. Tables 190.7 2 through 190.7 4 list certain minimum sets of systems that meet the 1.0E.5 19Q.7.9.2 Loss of RilR Initiator criterion for loss of the operating RHR system initiator for the three major configurations during The minimum set for loss of RilR is discussed shutdown. The configurations are: Modes 3 or 4, first. Table 190.7 2 lists some minimum sets of Mode 5 prior to flooding the reactor cavity, and systems that if available during mode 3 or 4 meet the Mode 5 after the reactor cavity has been flooded. core damage criterion. As can be seen,if the 2 The effect of changes in decay heat, as a function of ECCS systems are assumed to be RHR, then only a time, will be discussed for each of the three plant CRD pump plus ac independent water addition or conditions. CUW plus AC independent water addition need be made available. This is not restrictive since one With about 12 systems available, and about four pump from CRD and firewater are usually available needed to meet the goal, many minimum sets can be for other reasons (e.g., CRD to purge the FMCRDs identified. In order to simplify the selection of and AC independent water addition for fire minimum set systems, the following maintensoce protection) and CUW is usually operable during this philosophy was assumed: all of division C in period. The table shows four different minimum maintenance; division B, ADS, and combustion sets. This is indicative of the flexibility for turbine generator (CTG) are available. Although performing ABWR shutdown maintenance while still the CTG is not covered by Tecnical Specifications,its maintaining risk margins. availability is assumed to be controlled by Administrative Procedures. Other maintenance Table 190.7 3 lists some minimum sets of systems philosophies can be adopted and the model used to for Mode 5 during 2 3 days after shutdown. In this identify appropriate minimum systems. Additional configuration the RPV head bolts have been details of the plant configuration based on selected detensioned and the head is off but the reactor cavity maintenance philosophy is as follows. The plant is bas not been fIooded. For this Mode 5 being cooled through use of RHR 'A' and its configuration, fewer systems are available than support systems (i.e., service water 'A', RCW "A*, during Mode 3 or 4 or after flooding the reactor electric power division 'A*). Other division 'A' cavity but enough systems are available to ensure systems, including EDG *A* may be in maintenance adequate risk margins. Also, this is a relatively short unless specifically included as a support system in duration of the outage. The main condenser is not one of the minimum sets. All division 'B' systems available since the RPV cannot be pressurized. Fuel are assumed to be not in maintenance, although they pool cooling cannot be used because the RPV and 19Qtto Amendment I AM
ABWR mw s wn Standard Plant fuel pool have not been connected together and EDO and the CTG along with not recovering offsite CUW capacity is not sufficient to remove all the power within 80 minutes is less than 1E.4. For core decay heat due to the low RPV temperature and damage to occur, loss of AC inclependent water high decay heat load. The table shows three addition or ADS must occur. This scenario is less minimum sets of systems which meet the risk than 1.0E.5 and thus meets the criterion. Since the criteria. As was noted for Modes 3 and 4, the CRD above maintenance philosophy assumes only EDGB pump whico is normally available in addition to one and the CTG are available, no ndditions to the other make up system meet the core damage minimum sets already identified are required for the criterion. loss of offsite power initiator. Table 190.7 4 lists seven minimum sets for mode 19QA.7.9.5 Adequacy of Technical Specifications 5 following 3 days after shutdown when the reactor cavity is flooded. RHR plus condenstae end fire From the above results, the fo' lowing can be water meet the criterict. After 4.5 days, CUW or stated regarding adequacy of the ABWR Technical condensate along with fire water and FPC meet the Specifications. In Mode 5 the onset of boiling is criterion. As time following shutdown increases, most dependent on water level (or total inventory), more systems become able to remove decay heat and and thus the most vulnerable condition is at low greater time is available for operator actions prior to water level prior to flooding up of the reactor cavity. boiling cr core damage. in this condition, not only is the time to boiling relatively insensitive to decay heat level, but RHR in As tables 19Q.7 2 through 190.7 4 illustrate, shutdown cooling (SDC)is the only source of decay many combinations of systems can be made available heat removal. This is the basis for the Technical to ensure adequate shutdown risk while still allowing Specifications requiring that two loops of RHR SDC for maintenance to be performed on systems. As be available in this condition; one normally operating previously rnentioned, these minimum sets are only a and one in standby. Results of the analysis show that few of the possible combinations that will ensure given the loss of the operating RHR {oop, with one adequate shutdown risk margins, other minimum RHR loop in standby there is a 5x10' probability of sets can be identified for different assumed plant the onset of boiling. Assuming a one in ten conditions. An irnportant point that is illustrated by probability of the initiating event, bciling would the minimum sets identified in this study is that occur once in two hundred years. This it acceptable under all shutdown plant conditions, minimum given the short time duration the plant is crpected to technical specification requirements plus systems be in this unique condition and the benign that are normally operating or available during - consequences that are calculated to result so long as shutdown (e.g., CUW, FPC, CRD, and fire water) core damage is avoided. Clearly, a utility could are enough to ensure adequate shutdown risk further reduce the likelihood of boiling by assuring margins. that the third Jivision of RHR SDC provided in the ABWR design is available during these conditions. 19Q.7.9.3 tess of SW Initiator Thus, durh.g the early stages of the transition from Mode 4 to Mode 5 (prior to flood.up), the if loss of reactor building service water (RSW) is availability of the third loop of RHR SDC further assumed to be the initiating event, Division 'A' of reduces shutdown risk. However, given the other CUW and FPC are also lost. As both divisions of compensatory measurcs available to delay the onset " CUW and/or FPC pumps and heat enchangers are of boiling and prevent core damage (e.g., required to reinove decay beat CUW and FPC must condensate, AC independent water addition, CRD), be assumed unavailable. Thus in Table 190.7 2, the the two loops of RilR SDC required by ABWR minimum set that assumes CUW available would not Technical Specifications are more than adequate apply for loss of RSW. Also, the four sets in Table during these plant conditions. 190.7 4 that assumes availability of CUW plus FPC would not be applicable. 19QA.7.9.6 Contribution of Human Errors to CDF 19Q.7.9.4 Loss of Offskt Power initiator The ABWR design is relatively insensitive to human error contributions to CDF during shatdown For a loss of offsite power initiator, calculations for the following recons. Although several potential have shown that the probability of failing both the human errors have been identified (e.g., failure to 190 713 Amendment
ABWR ** [5 Standard Plant recognize the loss of operating RHR loop and failure ; te manually actuate systems such as condensate, fire l water, reactor water cleanup, and fuel pool cooling), multiple systems and paths for decay heat removal and makeup are available during shutdown to mitigate these errors. Also, automatic actuation of makeup from LPCF and HPCF and multiple alarms to alert the operator to potential unsafe conditions . during shutdown (e.g., high RHR temperature, sump pump alarms, fire detection, low RPV level, high j area radiation, and hich neutron flux) all contribute to the conclusion thrt the ABWR is tolerant of human errors. The methodology used in this study does not allow for a quantitative estimate of the impact of human errors to CDF, but based on the above discussion it is considered to be low. j gg . gy Anwndment
.m___ . . . . - . _ _ _ _ _ _ - - - - - - - - - - -
1 A.BWR nuims } Standard Plant n,- A l Table 190 71 4 SUCCESS CRITERI A FOR PREVENTION OF CORE DAMAGE i i System (s) Comment 1 RHR (SDC) All times when available. or ] 1
' if available, open MSIVs and establish condensate return j Main Condenser path to RPV.
9 or CUW If temp >234 F or after 14 days (using 2 pumps and using 2 4 nonregenerative heat exchangers and with regenerative heat I exchanger bypassed). I % or CUW + FPC Mode 5 only after 3 days. After 4.5 days FPC alone is success. Both pumps and heat exchangers in each system required. 1 or 1 Feedwater + High pressure injection. 1 Condensate 1
- or i
1HPCF High pressure injection. i or ! 1CRD High pressure injection. l \ or h l 1 Condensate Low pressure injection (may need ADS). or 1LPFL Low pressure injection (may need ADS). i or f \
- 1 AC Independent Water low pressure injection (may need ADS).
Addition System . 4 190.7 13
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^ X L12-1 CTGF RXDPRESS X L12-2 msei.o im .nu Figure 19Q.7-16 LOSS OF OFFSITE POWER - Pad)E 3, STARTING AT 4 HRS n[-
g 77 a , >w e
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2 RECOVERY ALL DIESEL CTG ADS FIREWATER CLASS SEO NAME LOSS OF E OF LOOP GENERATORS PUMP OFFSITE POWER NOT Fall REC DG -CTG X FW LOSP1' , OK LOSP OK REC 90 og DGF OK FIREWATR X L121 STGF RXDPRESS X L12-2 tosessat. . , . . , ; Figure 19Q.7-17 LOSS OF OFFSITE POWER - MODE 4,'6 IIRS TO 2 DAYS y 8 E d F
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CTG NOT Fall SEO NAME 3. LOSS OF. RECOVERY OF ALL DIESEL T-OFFSITE POWER LOOP GENERATORS F NOT Fall ?, DG CTG FW LOSP1 REC t OK OK LOSP i OK REC 50
-DGF OK CTGF
- I FIREWATR tosersne anw g
[ y$ 5 Figure 19Q.7 18 LOSS OF OFFSITE POWER - MODE 5,2 'TO 33 DAYS wh
J t ABWR uxa.4s Standard Plant n, 4 19Q.8 USE OF FREEZE SEALS IN ABWR f. ) Freeze seals are used for repairing and replacing i such components as valves, pipe fittings, pipe stops, i and pipe connections when it is impossible to isolate l the area of repair any other way. Freeze seals have j successfully been used in pipes as large as 28 inches ! in diameter. 4-F, i The ABWR design has eliminated a significant l amount of piping associated with the reactor coolant ! system (e.g., no recirculation loops). This by itself
- will reduce the necessity for freeze seals in ABWRs
- over other plant designs.
1 In addition to reduced RCS pipin6, the ABWR design has most piping connected to the reactor pressure vessel (RPV) enter at a level significantly higher (five feet) than the top of active fuel. Inadvertent draining from these lines will - automatically stop without exposing the fuel. The only piping connection below the top of active fuel
, (reactor water cleanup system) is small in size (< 2 i inches), if a freeze seal were required on this line
! and it were to fail, several sources of makeup are i available to refill the RPV to prevent core uncovery.- 4 ! Whenever freeze seals or other temporary i boundaries are used in the ABWR,' administrative ) procedures will be necessary to ensure integrity of ! -the temporary boundary. - Also, mitigative measures j will be identified in advance and appropriate backup i systems made available to ensure no loss of coolant l inventory occurs. i f An option that a utility could choose is to i off. load all the fuelin the RPV to the spent fuel pool j when repair or maintenance of an unisoable valve must be completed. { I t The selected method for working on unisoable j valves must take into account adequate safety , margins, personnel experience with freeze seals,
- availability of backup systems, and the potential j impact on other outage activities.
i 4 4 190 8-1 0 - Amendment 4
)
1 l i
. ABWR usumxs nes A
- Slandard Plant
- . i
+ APPENDIX 19Q 9 1- ' CONTESTS 1 Section Illlt East ! 19Q.9 Shytdown Vulnerability Resultinn From New
- Features .190.9 1 i
f . TABLES 4 Table Illis East i 190.9 1 Shutdown Vulnerability Evaluation Of New ABWR Features 190.9 2 i. i i 1 4 b 1 I i i-r- 4 l 1 1 i l l. 4 4 . j~ 4 I k-
.190.9-il j
Amendment l l j 4
. . , . . . , r- . , , , , - , . ..m. . , .. ,, . ,
AB M usamts a,, x Standard Plant 19Q.9 SHUTDOWN VULNERABILITY RESULTING FROM NEW FEATURES The ABWR has incorporated many new design features that do not exist in current operating domestic BWRs. These features have been added based on past operating experience, advances in technology since earlier designs were finalized, and the results of detailed probabilistic risk assessments (PRAs). In order to evaluate the potential shutdown risk associated with these new features, a Failure Modes and Effects Analysis (FMEA) was completed for e.ach new feature. The feature is identified followed by potential failure mode (s). The possible method for detecting each failure mode is then presented followed by the potentialimpact on safe shutdown and any preventive or mitigating feature that may exist. Finally, the overall shutdown vulnerability evaluation is described. The FMEA is contained in Table 190.91. As the results presented in Table 190.91 show, there are no identified vulnerabilities resulting from implementation of new design features in the AB%Tl that affect shutdown risk. 190.9-t Amendment
Table 19Q.9-1 50> [g SHUTDOWN VULNERABILITY EVALUATION OF NEW ABWR FEATURES $3 C= m# 7 R
. Potential Preventive /
~
Shutdown Mitigative Vulnerability Failure flow Impact on Feature Evaluation - Mode Detected Safe Shutdown Feature :s
~
Inventory loss, Multiple seals, None,past exper-Reactor Inter- RPV leakage Visualindication rience with of leakage fuel uncovery. administrative nal pumps during mainte- maintenance on controls. nance RIPS indicates (RIPS) no concerns. Two independent None, adequate off-Fails to start No output voltage loss of electrical Combustion Tur- off-site power site and on-site or pick up load. on demand or test. power redundancy. bine Generator sources and three power sources exist (CTG) Emergency Diesel if CGT were to fail. Generators (EDGs). 1 Two other divisions None, redundant Improper synchron- Loss of bus voltage less of vital power Capable of supply- power supplies and when CGT output bus. ization to exist- administrative controls ing vital power, ing power sources. breaker closes on fantisync circuit prevent auto synchronization demand or test. any impact on safe shut-circuit, administra-tive controls. down. CGT capable of feeding None, increases number Fail to start or No voltage on vital less of pmr to one Third EDG any vital bus, two of on-site vital bus bus on demand or bus. pick up load. independent sources of sources. f test. off-site power. Two other di.isions None, increases reumber Single failure Safety function not less on one ECCS div-Third ECCS Div- capable of complet- of ECCS divisions to completed (e.g., no ision. ision results in loss ing safety function. complete safety functions, of third ECCS ECCS flow given ini-allows for ECCS maintei.- division. tiation signal) on t ance without tosalloss of demand or test. redundancy, separation .,, $ 4 reduces common mmle #y 7
$ failure suscegebility.
Table 190.9-1 Cn > [ SHUTDOWN VULNERABILITY EVALUATION OF NEW ABWR FEATURES (Continued) m hg ' "g 5# Shutdowu rotential Preventive /
"h ca.
Impact en Mitigative Vulnerability "_c Fallere flow m Safe Sheldows Feature Evaluation Detected Festare Mode 3 liigh reliability with None, increased relia-Fails to initiate ECCS function not loss of ECCS function Micro Processor bility of ECCS k>gic. completed on demand self test feature. Based Safety safety signal. or during test. Reduced shutdown margin. Only one CRD can be None, adequate pie. Fine Motion Fails to control CRD does not move withdrawn at a time, ventive mitigative . Control Rod CRD motion on when directed or RPS active during features exist.
- Drives (FMCRDs), demand. spurious movement.
shutdown (hi flux . Alternate Rod or manual trip). Insertion (ARI) less of all safety CGT and three EDGs. None, increased number Two independent Loss of off-site No voltage on bus.- division power sources. of onsite and off. site Preferred Power power. power sources. Sources less of ECCS funct;on. Self testingcapability, None, increased ECCS Multiplex Control less of control ECCS functions not high reliability. reliability and elemi-System Sensor power to ECCS. completed on demand , nation of cable spread-interfaces or test. ing room. t less of safety equip- Redundant heat exchanger None, closed kop RCW Closed loop Re- IIcat exchanger liigh temperature on ment (e.g., EDGs, can supply necessary s pplies cleaner water actor Buikling tube failuse. ' RB equipment, water accumulation in RCW RilR heat exchangers), cooling. te safety equipment en-Cooling Water - h ancing cooling capa-System (RCW) room alarms in cor.- fiility (i.e., reduced trol room. fouling of heat transfer surfaces) as compared to direct cooling with ser-vice water. y 5 8 RCW isolation ' liigh Temperature on See lleat Exchanger Three divisions of RCW. See IIcat Exchanger y$
$ failure. failure. > 3; Valve failed RB equipment. .i closed.
. . - . -~ .. -- -.
. - . .- --.-.~ ---- - - -. - . . - . --
Table 190.9-1 SHUTDOWN VULNERABILITY EVALUATION OF NEW ABWR FEATURES (Continued) 1 8
!! Potential Preventive /
E Shutdown Mitigative Vulnerability a Fallere How Impact on Mode Detected Safe Sheldown Featver Esaleation 3 m Feature See IIcat Exchanger Redundant pump can See llcal Exchanger d RCW pump fails liigh temperature on Failure. supply necessary Failure. to supply water. RB equipment. flow. less of ADS /SRV capa- Other high pressure None, nitrogen supply Ifigh Pressure Gas leak. less of pressure bility to reduce RPV DilR means exist instead of air reduces Nitrogen Gas in accumulators. pressure and allow use (e.g.,11PCF, cond- potential corrosion of Supply to ADS valves and loss of system of k>w pressure for ensate RCIC). Can - and SRVs reduce RPV pressure pressure due to compres-IIcat Removal (DilD) Systems. through use of RCIC. sor failures. More reliabic than air ; systems. See gas leak. See gas leak. See gas leak. Bottle isolated Surveillance test. due to valve closure (operator error). less of ability to Three SRV controls None, added features Enhanced Remote Transfer switches Safety equipment control fourth SRV exist, local control enhance shutdown Shutdown Panel fail to actuate ' fails to actuate on demand or during of equipment is - shutdown safety. (e.g.,4 SRVs, fourth SRV and and llPCF from the .
- test. remote shutdown possible.
IIPCF) IIPCF. panel. Loss of warning to local alarms will None, no safety function Coatainment At- Fails to detect During test. operator on breach actuate. just monitoring. mospheric Moni- high radiation l ofradiological oring System or iemperature in containment. barrier. (CAMS) ti
~ >
d t ?*$
> te e
Table 190.9-1 M> g SHUTDOWN VULNERABILITY EVALUATION OF NEW ABWR FEATURES (Continued) mW I ca.#
! m E Sheldown Potential Parventive/
Vulnerability c. How Impact on Mitigative Fallere Feateer Mode Detected Safe Shutdown Feature Esalension 3 m loss of some redund- 16 T/Cs remain to None, enhancement to d Enhanced Sup- Fails Io detect During operation ancy in pool temp- monitor temperature. suppression pool moni-pression Pool correct pool or test. ature monitoring. toring function. Temperature temperature. Monitorirg (48 T/Cs Instead of 16) toss of pool water Localindication. None, does not Suppression Fails to detect During operation level monitoring perform a safety Pool Level - correct pool or test. function, level capability. Monitoring t 4 i
.t gJ a n-i w " >sm i
ABWR memxs an 4 Standard Plant 19Q,10 PROCEDURES The plant specific procedures for outage planning and control should ensure that the appropriate focus The ABWR has been designed to minimize risk is maintained on the following actidties: associated with plant operations both at normal power and shutdown conditions. As previously 1) Documentation of outage philosophy including mentioned, PRA techniques have been employed to organizations responsible for outage identify potential accident scenarios and, where scheduling. This should address not just the appropriate, design modilications have been included initial outage plan but all safety significant to reduce estimated risks. In addition to the physical changes to the schedule. plant design and configuration, the ABWR will incorporate operating procedures that are based on 2) Ensuring that all activities, particularly higher rigorous engineering evaluations including safety risk evolutions, receive adequate resources. analyses. These procedures will be prepared The plan should consider scope growth and consistent with NUMARC Guidelines presented in . unanticipated changes. NUMARC 91 XX," Guidelines to enhance safety during shutdown". 3) Ensuring that the " defense in depth" concept that is central to power operation be main. Each utility must generate plant specific tained during shutdown to ensure that safety operating procedures based on individual site margins are not reduced. Safety systems must characteristics and training program requirements, be taken out of service for maintenance but A procedures guideline will be completed for the alternate or back up systems can be made-ABWR to address shutdown conditions. The available if proper planning is completed. guideline will provide insight into two general areas:
- 4) Ensuring that all personnelinvolved in outage
- 1) Effective outage planning and control. planning and execution receive adequate training. This should include operator
- 2) Maintenance of key shutdown safety func- simulator training to the extent practicable.
tions: Decay heat removal capability, Other plant personnel, including temporary inventory control, electrical power avail- personnel, should receive training ability, reactivity control, and containment commensurate with the outage tasks they will integrity (primary and secondary), be performing. Outage Planning and Control 5) After completion of outage planning, but prior to final approval, a review of the schedule Although design features help, shutdown risk can should be completed by an independent safety best be minimized through appropriate outage review team. The main objective of this planning and control procedures. Planning is review is to assure that the defense in depth important because of the large number and diversity principal will not be violated at any time of tasks that must be completed during the outage, during the outage. Safety and support systems must be taken out of service for maintenance. This reduces redundtncy of Shutdown Safety issues safety systems. If alternate means are not utilized to back up the lost safety system, a reduction in safety Procedures for outage planning and control margin may occur. The ABWR contains multiple address general aspects of risk reduction during normal and alternate systems to complete all shutdown. Specific shutdown procedures are required shutdown safety functions. Availability of required to maintain key safety functions during normal and alternate systems must be made known shutdown. The following guidelines should be used to all personnelinvolved in planning and execution of - for each key shutdown safety function. the outage. This is an ever changing situation during outages and proper planning and tracking of 1) Decay Heat Removal Capability The normal activities is required to ensure safety margins are method of Decay Heat Removal (DHR)is maintained. through use of the Residual Heat Removal system (RHR) in the shutdown cooling moue. 190141 Amendmem
I ABWR ms Standard Plant wa As discussed in Section 190.7 and 190.11, periods of higher risk evolutions (e.g., there have been many events at operating unbolting the RPV head prior to flooding th: plants that have resulted in partial or total reactor cavity). Many of the loss of power loss of DHR. A recovery strategy should be events discussed in Section 190.11 were established to address loss of normal RHR. caused by operator errors (e.g., switching This should include identification of alternate errors, inadequate maintenance / testing DHR systems as well as personnel procedures) and grounding of transformers in responsible for execution of the recovery switchyards due to movement of equipment by plan, in addition to recovery plans, outage crancs and trucks. All maintenance and planning should emphasire availability of switchyard activities should be reviewed to DHR by postponing maintenance on RHR identify single failures or procedural errors systems to later in the outage when decay that could result in lots of power to vital buses heat loads have been reduced or to when the during shutdown. Procedures should be core has been off loaded to the spent fuel developed for implementattun of alternate pool. In the case of core off load, procedures sources of power including applicable breakers should be prepared to ensure maintenance of and bus locations, required tools, and spent fuel pool cooling. sequence of steps to be performed.
- 2) Inventory Control . If DHR were to be lost, 4) Reactivity Control Shutdown reactivity the time to reactor coolant boiling and core control for the ABWR is maintained by core uncovery will be d:termined by the initial design analysis and interlocks that restrict fuel coolant inventory and make up capability, and control rod drive movements. Procedures Procedures should be prepared to ensure that are required to ensure that the core is loaded adequate coolant inventory is maintained at per design requitements and that q all times during shutdown. Also, plant unauthorized fuel movement does not occur actisities or configurations where a single simultancous with CRD mechanism failure can result in loss of inventory should maintenance, if the refueling sequence must be identifie.d and compensatory measures be altered, new shutdown margin analyses established. Specific activities for the ABWR should be performed. All fuel movements that should be reviewed for the potential of should be verified by knowledgeable trained inventory deduction are: Use of freeze seals personnel.
(see Section 190.8 for a more complete '* discussion); removal of control rods, control 5) Containment integrity The ABWR primary tod drives, and reactor internal pumps; RHR containment will not be available during most valve actuations or leakage leading to of the refueling outage but procedures should diversion of RPV coolant to the suppression be developed to ensute its availability during pool (e.g., RHR pump mini. flow valve Mode 3 and during Mode 4 (if appropriate). failure / leakage, switching shutdown cooling Dur'ng all modes, procedures should be from one division to another); and as:4 table to ensure that secondary inadvertent actuation of safety relief valves, containment can be maintainta functional as required, especially during higher risk
- 3) Electrical Power Availability. As discussed in evolutions.
Sections 190.4.4 and 190.11, loss of electrical power during shutdown has resuhed in loss of Procedure Reviews DHR in the past. The ABWR has two sources of off site (prelerted) and four An important part of procedures implementation sources of on site electrical power. is a review of the adequacy of all operating Procedures should be utillied to ensure that procedures. All shutdown operating procedures defense in depth for electrical power sources should be reviewed periodically to ensure that the is maintained. Maintenance of power sources defense in depth concept is being maintained given should teflect the current plant conditions. the actual events occurring at each site. This resiew Availability of normal and alternate power should include not only procedure adequacy but sources should be ensured especially during dissemination of the outage philosophy to all 190.t0 2 Amendment I
ABWR nyu s v,a Standard Plant personnelinvolved in scheduling and executing the outage plan and training of personnelincluding temporary personnel. This review should be documerced and retained as a permanent plant record. 190 10-3 Amendment
ABWR nam ^s nn A Standard Plant 19Q.11
SUMMARY
OF REVIEW OF The Loor esents can be grouped into the SIGNIFICANT SilUTDOWN EVENTS: following categories: ELECTRICAL POWER AND DECAY HEAT REMOVAL . Loss of all off site power sources due to various reasons including weather, operator As part of the certification process for the errors or grid upset ABWR design, the NRC has requested that General Electric complete a review of significant shutdown . Loss of one or more off site sources with at events in operating plants and discuss ABWR least one off site source remaining features which could prevent or mitigate such events.
. Isolation of off. site power due to on site To complete this evaluation, a review was made electrical faults of operating events involving loss of off site power (LOOP) and loss of Decay Heat Removal (DHR). . Degraded off site or on site power sources ,
These two areas appear to have the greatest resulting from errots in maintenance activities i l potential for causing core damage during shutdown based on past experience. The sources u'%ed for As discussed in Table 190C 1, the ABWR information on past shutdown events wen. electrical distribution system has several features which would prevent or mitigate every precursor
- Residual Heat Removal Experirnet Review event evaluated in this study. Prevent or mitigate in and Saftry Analysis, NSAC 88, March 1966 this case means that at least one Class IE power suppiy would be available to energize equipment to' Loss of l'itol AC Power and the Residual Heat maintain plant cold shutdown.
RemovalSystem dwing Mid Loop Operations at Vogtle Unit i on March 20,1990, A one line diagram of the ABWR clectrical NUREG 1410, June 1990 system is contained in Attachment 190C. The main features of the electrical system are: NRC Staff Evaluation of Shutdown and Low Power Operation, NUREG 1449, March . Twoindependent sources of off site power 1992
. Three physically and electrically independent
. Sciected INPO SEO Reports and NRC Class 1E emergency diesel generators Information Notices.
. Three unit auxiliary transformers powering The resuits of this evaluation are contained in three Class 1E and three non 1E power buses Attachment 190C, Tables 190C 1 and 190C.2 for LOOP and loss of DHR respectively. The following . Combustion Turbine Generator (CTG) that is a discussion of the results for each event type. can be used to power any of the Class 1E or non 1E power buses LOOP The above features of the ABWR electrical NUREG 1410 contains a discussion of 70 distribution system, along with appropriate Technical LOOP events at operating plants both PWR and Specifications and other administrative controls.
BWR. Although the response to LOOP events will assures that adequate power sources would be differ for PWRs and BWRa the initiating tvents are available to mitigate potential electrical events such similar in that olf sits and on site power as those described in Table 190C 1. configurations are similar for both reactor types. The events evaluated in NUREG 1410 occurred toss of DilR between 1965 and 1989. Two additional recent LOOP events were added to this list and are NSAC 88 contains a discussion of 90 loss or included in Table 190C.1. degradation of DHR events during the seven year period 1977 through the end of 1983. The source for these events were s.ict;nsee Event Reports (LERs). 190 111 Amendment
ABWR n^um^s Standard Plant Rev A Other events described in INPO SEO reports and None of the events described above and in Table i NRC information notices were also reviewed and 190C4 resulted in fuel being uncovered. The I included in the study. flexibility of the RHR system and the several j alternate means of DHR that were available served Summat7 of DHR Events to mitigate the component failures or operator errors. The results of this c<aluation are contained in Attachment 190C Table 190C.2. Not all of the Summary events discussed in NSAC 88 are contained in i Table 190C.2. Those events that were due to Significant shutdown events in operating plants random failures of single components and did not have been reviewed to determine ABWR features result in loss of DHR or other significant plant which could prevent or mitigate the events. l.oss of effects were not evaluated further. If the single offsite power and loss or degradation events from f allure resulted in loss of coolant, over. published nuclear industry reports were the database pressurization, flooding, or loss of Shutdown Cooling for this review. The results of this review demon. (SDC) function, the event was included and the rate that ABWR design includes many features that applicable ABWR feature to prevent or mitigate the prevent or mitigate unacceptable consequences of event was discussed. typical past ev-nts. For the purposes of this study, prevention or The main features of the ABWR that will present mitigation means that, given the DHR challenge or mitigate shutdown esents are: event, the ABWR design would either not be . susceptible to the postulated failure or it has design . Three divisions of ECCS and support systems features that could be relied upon to ensure that the that are physically and electricauy independent fuelin the RPV remained covered with water at all times. . Two independent off site power sources Of the events described in Table 190C 2, some . Four on site power sources (three emergency were single failures of RHR system components that dir.sel generators and one combustion turbine resulted in either delayed achievement of shutdown renerator) - cooling (SDC), reduction in reactor pressure vessel (RPV) water level, or a temporary loss of SDC. In - Plant configuration and structural integrity to all of there events, the fuel remained covered with minimize common mode failures due to fire water and alternate means of DHR remained and floods available (e.g., reactor water cleanup system, main condenser, and ECCS systems), in the cases of . Appropriate Technical Specifications and
-delayed or temporary loss of SDC3RPV water other administrative controls to ensure temperature increases ranged from 10 140 F. In availability of sy. ems during periods of all cases, SDC was restored and alternate means of potentially high risk operations DHR were not used although available. Operator errors associated with improper valve lineups or - Several alternate means of DHR if normal incorrect maintenance were identified in these systems were to fail or be out of service for cases, delays in implementing SDC or temrotary loss . maintenance j of SDC occurred while the error was corrected. in a few cases, marine growth caused failcre of one or . Instrumentation availability during shutdon j
- more RHR heat exchangers which resulted in to monitor plant safety status and initiate j temporary loss of SDC while other RHR loops or safety systems when seeded alternate cooling paths were implemented. In one case, a freeze seal failure in the RHRSW caused
- 15,000 gallons of water to damage ECCS power supplies resulting in temporary isolation of SDC.
p 1 190 11 2
- Amendmen
,+,rr- , ,---c, y,, ym-m - ,, n y s - . - + -g N, m_e.,-w , w y, , - .,, -m, y ,- g n r- ,,e---- >+,-,.m, ,,n.,--e , gn,-e N-
7_-...._._......__.-
' MN naamAs g,, . j Standard Plant APPENDIX 19Q.12 CONTENTS Section Title g Insinhts Gained From The Analysis 190.12 1 19Q.12.1 19Q.12.2 Imnortant Desian Features (Innut to ITAACI 190.12 2 19Q,12.3 Onerator Actions (Innut to COL Action items) 19Q,12 3 Rellability Goals (Innut to RAP) 19Q,12 4 19Q.12.3 i
e F 5 !~ t 19Q.12-1i Amendment -
2m6imas ABWR pu 4 Slandard Plant maintenance tasks, an evaluation must be 19Q.12 RESULTS AND INTERFACE completed to ensure that a minimum set of REQUIREMENTS systems capable of meeting the shutdown safety 19Q 12.1 Insights Gained from the criterion will remain available if a fire or nood were to occur. This applies to flooding / fire in the Analysis intact didsion as well as the breached dinsions. Completion of the ABWR shutdown risk analysis has resulted in the following insights: 6. The minimum technical specification requirements plus systems normally operating
- 1. The most important element in control of during shutdown (e.g., CRD, fire water, CUW) shutdown risk is adequate planning of are adequate to ensure that safety margins can be maintenance on systems and support systems that maintained during shutdown due to a loss of an can be used to remove decay heat or supply operating RHR train. Also, no technical inventory makeup to the RPV. specification changes are required to mitigate fires or floods during shutdown. Adminis.trative
- 2. The ABWR design has incorporated a significant controls are recommended on maintenance number of new design features relative to activities during shutdown to ensure the operating BWRs. Past events that have led to availability of systems to mitigate loss of RHR, loss of decay heat removal capability or loss of fires, and floods offsite power can,in general, be mitigated by ABWR design features.
- 3. The ABWR design has a very low risk associated with loss of decay heat removal. Adequate shutdown safety margins exist if only systems required by Technical Specifications and those .
that are already in operation (e.g., CRD, FPC, fire water) are relied upon. Minimum combinations of systems have been identified that,if available, will ensure adequate shutdown safety margins. Combinations other than those identified in this study may exist which also result in adequate shutdowm risk margins. By taking advantage of these available decay beat removal and makeup systems, utilities can exercise much flexibility in outage maintenance scheduling while ensuring that adequate safety margins are maintained at all times during shutdown conditions.
- 4. The above safety margins were calculated using very conservative estimates for human error probabilities. For all events analyzed during shutdown, sufficient time is available to prevent core damage that no extraordinary operator actions are required. ABWR safety is designed
,t into the plant.
- 5. Fire and floods during shutdown can be mitigated by ensuring, through administrative procedures that at least one safety division is not in maintenance and its physical boundaries remain intact. If it is decided to breach the boundaries of two safety divisions to complete 190121 Amendment
~ - __ - ___ _ _____ -___________________________-__ - . _- _ _ _ _ - _ - _ _ _ _ _ _ -
ABWR nuims an 4 Standard Plant 19Q.12.2 Important Design Features (Input to ITAAC) The following ABWR features have been identified as important contributors to the low level of risk associated with shutdown and base been included as part ofITAAC:
- Lines attached to the RPV have isolation i vahes that close on a low RPV water level. 1
- Shutdown cooling piping connects to a nozzle in the RPV at an elevation that is above the 1
top of the active fuel.
- The RHR system has mode switches to automatically realign valves in the RHR system.
. Two offsite and four onsite sources of electric power that are indepecdent and physically -
separated.
- Three disisions of ECCS and support systems that are independent and physically separated.
- Watertight doors on ECCS and RCW rooms.
- Floor drains in all floors above the first floors in control and reactor buildings.
- The RHR in the shutdown cooling mode does not isolate on loss of logic power.
- AC independent water addition system.
- CRD pump can be used for makeup under all shutdown conditions.
190 12 2 Amendment
ABWR nwas Rn A Standard Plant 19Q.12.3 Operator Acilons (Input to COL . Procedures should be prepared to address the Action lierris) following tatLs during shutdown: The following operator actions have been - Fire fighting with part of the fire identified that are important to minimitatisn of protection system in maintenance shutdown risk and have been included as COL action
. Outage planning to minimize risk using items: guidance from NUhiARC 91016
- Use of freeze seals
. Ability to recognize failure of an operating . Replacement of RIPS and CRD blades RHR system.
- 1.oss of offsite power
- Increasing CRD pump flow when using
. Rapid implementation of standby RHR for inventory control s; stems following loss of operating RHR - Maintenance of suppression pool as it relates to maintaining safety margins system, for decay beat remova!
- Use of alternate means of decay heat removal - Ensure that one safety division is using non safety grade equipment such as always available with intact fire / flood CU FPC, or main condenser. barricts.
- Use of shernate means of !nventory makeup using non safety grade equipment such as AC l independent water addition, CRD pump.
feedwater, or condensate.
- How to utilire beiling for decay beat removal in Mode 5 with the RPV head removed including available makeup sources.
- Implementation of fire / flood watches during periods of degraded safety disisica physical integrity.
. Fire fighting during shutdown.
- Use of remote shutdown panel duriag shutdown.
- Instrumentation must be made available during shutdown to support the following functions:
- Isolation of RPV
- ADS
- HPCF
- 1.PFL
- RPV water level, pressure, and tem.
perature
- RHR system alarms
. EDG
- Refueling interlocks
- Flood detection and associated valve isolation and pump trips 19Q 12 3 Amendment
ABWR mums Standard Plant nn 4 , 19Q.12.4 Reliability Goals (Input to RAP) The following assumed system unavailabilities were determined to be important in minimiring shutdown risk and are included in the ABWR Reliability Assurance Program: Svitem Unnallability RHR (SDC) 0.1 reactor year RilR (LPFL) 1x10, per reactor year itPCF 1x10 CRD 1x10' per perreactor reactor year year CTO 0.05/ demand EDG 0.07/ emand 4x10' per reactor year Offsite Power APS 1x10 per reactor year
-6 DC Power 5x10 per reactor year IM 124 Amendment
e- _ Ji&m_m.A aDa_._4 --m a-- -.a+_ _ _ '___an J_ aa_A L.-am__Jm.--._A. e_+_--W.AwJ4a A.an a s_c__.4_ah .A&+,1s.4Ah_..w4m4 m p_s 3, 4 ,.h.J..,_4_hp h,mm,5 g,1,w,ah_,_.J,, f I ATTACHMENT B APPENDIX 19Q DHR RELIABILITY STUDY ( s i - -. - ~..-- . . . - . . . ._ ._. ._--. , , _ _ . .
. ..- e , -
I 2aums ABWR nu 4 Standard Plant A1TACllMENT 19Qll.2 CONTESTS Section Illls Eagt TI%IE TO RE ACil flOlllVG 190B.21 19Qll.2 ILLUSTRATIONS Figure Ihlt East 190B.21 Results for Time to Boiling for the RPV 190B.2 2 190B.2 li Amendment
l i } ! l ABWR mawas Slandard Plant a,, 4 k 1908.1 OFFSITE DOSE AND The values in the above equation such as 1131 j OPERATOR RECOVERY carryover,1131 concentration, and dispersion factor CALCULATIONS are conservative estimates based on ABWR SSAR i analysis and regulatory guidance. This attachment covers three different calculations that were completed for various aspects The decay heat 1 9 at d 3 and 14 days i of the ABWR Decay Heat Removal Reliability shutdown is 5.9x10 Blu/hr and 3.2x10(ollowing Blu/hr, i Study. The calculations are: respectively. Using the above equatiog the doses foj 24 hours at 3 and 14 days are 7.5x10 and 4.04x10 o
- 1) Offsite doses folkwing RPV boiling in Mode REM, respectively, This is significantly below the :
j 5. FEMA lignit of 5 REM per 24 hours for normal plant I operations. Thus boilin? In Mode 5 will not exceed i i 2) Time to reach RPV boiling for specific plant . any offsite dose limits and is a viable success criteria.
- conditions and decay heat loads.
- 3) Time for RPV water level to reach top of-l active fuel (TAF).
- 4) Human Reliability Analysis.
) i i .19QB,1.1 Offsite Doses 4 j For the ABWR Decay Heat Removal Reliability ] Study, the success criteria for Mode 5 allows boiling
- of water in the RPV or spent fuel pool. The l following calculation of offsite doses assuming i boiling in the RPV and spent fuel pool substantiates l why boiling is a viable success criteria in Mode 5.
l The equation for calculating offsite doses is: Dose = RR ' DF
- BR
- DCF l
- Dose = Offsite dosa for 24 hour period j (REM) i
! RR = Release rate for 24 hours Decay liest 1.oso rDtv/hr) , , 4 , 1- 92$ Stu/lb Water I Em l 0.015 (I 131 carryever)
- 454
- 24
! lb 1 3 j DF = Dispersion factor = 1.2x10'3 sec/m BR = Breathing rate = 3.47x10 m /sec 1 DCF = Thyroif dose concentration factor = l 1.08x10 REM /ci i i Amendment 190B 11
ABWR n^um^s Standard Plant Rev A 19QB.2 TIME TO REACH BOILING Th: time for an operator to recover a failed RHR system in the ABWR Decay Heat Reliability Study is conservatively based on the time to boiling in the RPV or the spent fuel pool. The following discussion addresses the calculation of time to boiling for the RPV and RPV plus spent fuel pool at various times after shutdown. It is assumed that the initial temperature of the RPV or spent fuel poolis 140 F. This is typical for normal Mode 4 or 5 operation. The equation for time to twiling is: t = lAT/ heat up rate ( F/ht)] 212 140 t = (Decay Heat Rate / Mass of Water) Table 1908.21 shows the results for time to boiling for the RPV alone at 2 and 3 days following - shutdown and for the RPV plus spent fuel pool (i.e., reactor casity flooded and fuel pool gates opened) at 3 and 14 days. As can be seen, the time for operator action varies from a little over an hour for the RPV alene to approximately one day for the RPV plus spent fuel pool 14 days after shutdown. Amendment 19QB 21 m,, , , , , . . . ,
l i ABWR m.ms a,, 3 Standard Plant
- Table 19QB 21
- i
,' RESULTS FOR TIME TO HolLING FOR THE RPV i Decay Heat Mass of Water Time to Reach hladt Days aner Shutdown (Blu/hr) (Ibs) Bolline (hrs) 6 3,7 4 2 6.8x10 1.1x10 6 l,3 5 3 5.9x10 1.1x10 7
5 3 5.9x10 1.2x10 15 5 14 3.2x10 1.2x10 27 l 190 8.2-2 Amendment l. e-v e-9-+ y . 9 z g = }mW w + - s--- --pw< = =~ca--+a iw ,s -em,= ,.=-44m.-e-r
ABWR .. s-Standard Plant l l I ATTACHMENT 19QH.3 I CONTENTS , Sectlon Ig[g gpgg
+
19QHJ TISf E FOR RPV WATER LEVEL TO RE ACH TOP OF ACTIVE FL'EL 19083 1 ILLUSTRATIONS - i Figure Igif East 190B31 Time for RPV Water 1.evel to Reach TAF 190B3-2 i l i 1 l l-I l-2 190B3 il-l-
- Amendment .
1 g- ,- y . w w grs-r- w7wy--yi-- y y- y -yn g g- %.y.q W g *w q y p-ng.,,,,y% .,,p,n. +-
ABWR msims
, , ,. 4 Standard Plant 19QB.3 TIME FOR RPV WATER LEVELTO REACilTOP OF ACTIVE FUEL This section summarizes the calculations for the time to reach top of acthe fuelin modes 3,4, and 5.
The results show it will take 6.4 hours in mode 3.13 hours in mode 5,15 hours in the early part of mode 5 before flooding of the casity, and more than a week after cavity flooding in mode 5. Assuming that it takes 925 Btu to vaporize 1 lb of water, the decay heat at a specific time is divided by 925 to find the rate of vaporization. Division of water mass by this vaporization rate results in the time for RPV water level to reach TAF. Table 190B.31 shows the results. 19QD}i Arnendment
ABWR 2mams an. 4 Standard Plant Table 19Q11.31 TIME FOR RPV WATER LEVEL TO REACil TAF Deca) Heat Mass of Crater Time to _@tu/hr) (Ibs) Reach TAR Medt After Shutdown 0 3 4 hrs 1.43x10 9.8x10 6.4 hrs 5 4 2 days 6.hx10 9.8x10 13 hrs 5 3 days 59x10 9.8x10 15 hrs 5 7 3 days 59x10 1.2x10 7.8 days 5 7 14 days 3.2x10 1.1x10 14.5 days 5 19QB}2 Amendment
ABWR noms Standard Plant un 4 l ATTACllMENT 19QB.4 ) CONTENTS Section Illic Eagt ! 19QB.4 IIUMAN RELIABILITY ANALYSIS (lira) 1908.41 19Q B.4.1 Purpose 1908.41 190B.4.2 Summary 190B.4 2 19QB.4.3 blethodolon 1908.43 190 B.4.3.1 Control Room arid Alarms 190B.4 3 190 8.4.3.2 Alloation of Times to Diagnosis and Post. Diagnosis Actions 190B.4 3 19QB.4.4 Besults and Co,clusions 190B.4-4 19QB.4.5 Eritancu 190B.4-5 TABLES Table Illic Pc 190 5.4-1 Probability of Failure to Diagnose 190B,4-6 1908.4-2 Probability of Failure to Start a Specified" Minimum Set
- System 190 B.4-7
, 190B.4 3 Control Room Alarms Aiding Diagnosis of
*One RHR lest" 190B.4-8 190B.4-4 Times Available (In Hours) 190B.4-9 190B.4 li Amersdment k
ABMR ustimss j Standard Plant an 3 , 19Qll.4 !!U$lAN RELIAlllLITY i ANALYSIS (11RA) i s 19Qll.4.1 Purpose The purpose of this IIRA is to calculate the
; human error probabilities (HEPs) for the decay heat removal reliability study.
1 l i I l I i I i J } } 1 4 h e Amendment 1909 &l
ABWR umm4$ Standard Plant nu 19Q11.4.2 Summary Tables 1908.41 and 190B 4 2 show the HEPs which were calculated for sarious time frames and plant modes for two cases. Case a Operator action required before water starts to boi!. Case b Operator action required te prevent core damage (CD). Ilowever,it was decided that more conservative values should be used in the PRA. These values are also shown in these tables. 9 190042 Amendmen
ABWR n^um^s Po A Sundard Plant 19QllA.3 Methodology various times which were to calculate the llEPs. Column three gives the calculated times before The HEP calculatione vere performed boiling (case a), and core damage (case b), or the conservatisely using the pre . dure for normal total time available for allocation. Columns 4 and 5 human reliability analysis (HRA)in Table 81, show the results of the allocation. Enough time is Reference 1 with the following steps: allocated to post diagnostic actions, so that there is sufficier,t time for recovery of human errors, even if (c) The displays and alarms available to the the required action must take place outside the operator were identified. control room. (b) The times to boiling and core damage were identified. (c) The times for diagnosis and post. diagnosis actions were allocated. (d) The HEPs for diagnosis and post diagnosis actions were calculated using Tigure 81 and Table 8 3 and 8 5 of Reference 1. (c) Higher than calculated values were assigned conservatively for use in the PRA. (f) It is assumed that at least two operators are in the control room at all times during shutdown. 15QB.43.1 Control Room and Alarms Table 190B.4 3 shows the relevant alarms which are available in the CR (Reference 2). Operator is alerted to the failure of the operating RiiR by means of one of the RHR specific alarms. If none of these alarms work, he will be alerted to the RPV parameters alarm 2 (though RPV pressure and water level may not be available prior to boiling). With these multiple alarms, it is reasonable to assume that all operators will be promptly alerted to the RHR failure. In mode 5 with the reactor cavity flooded, the operator would be made aware of heating the fuel pool by many other indications. Personnel on the refueling floor will all sense the increased temperature and will see steam formr. tion, if no personnel notice the fuel pool heat up, the operator would receive an alarm of low fuel pool level and initiation of fuel pool level make up. 19QB.43.2 Allocation of Times to Diagnosis and Post Diagnosis Actions The time available to the operators were allocated between time for diagnosis and time for post diagnosis action. Table 1908.44 shows the 190043 Amendmens
nyi ABWR s
, ,, 4 Sandard Plant 19QB.4.4 Results and Conclusions The results of this l{RA study is documented in Tables 190B.41 and 190B.4 2, it is conduded that the operator has adequate instrumentation and alarms to diagnose the event. Adequate procedures and operator training will assure proper response to the loss of RHR event.
P* 19QD u Amendment
ABWR :mius n,, a Slamlard_l'lant 19QIIA.5 References (1)Snain, A.D., Accident sequence Evaluation Program Human Reliabiltty Analysts Procedure, SanJia National Laboratories NUREG
/CR-(n2, U.S. Nuclear Regulatory Commission,
, Washington, D.C., February 1987, (2) Interlock Block Diagram,IBD,137C8326, Sh.18. Rev. 2. e I I f 1 190B 4-5
/ mendment
. _ =
ABWR mims n,, 3 Slanditrd Plant Table 19Qll.41 PROllAlllLITY OF FAILURE TO DIAGNOSE Time After Prob. (l'all to Diagnose) Case Mode Shutdown Calculated Used in PRA a 5 2 3 days 1.0E 04 1.0E 03 a 5 >3 days < < 1.0E 05 1.0E 04 b 3,4, and 5 Any tirne (prior to flood. After Shutdown < < 1.0E-05 1.0E 04 ing reactor cav-ity) b 5 (after flood. Any Time < < 1.0E 05 1.0E-04 ing reactor cav-ity) 1900 4 Amendment
s ABWR msimxs ne. 4 Standard Plant Table 19QB,4 2 PROBABILITY OF FAILURE TO START A SPECIFIED ' MINIMUM SET SYSTEM Time After Prob. (Fall to Diagnose) Case Mode Shutdown Calculated Used in PRA a All 4.0E-03 2.0E 02 b All 4.0E 03 2.0E 02 190B4-7 Amtadmeat
4 1 I i ABWR mn , ! n, 4 Standard Plant
- Table 19QB.4 3 CONTROL ROOM ALARMS AIDING DIAGNOSIS OF'ONE RHR LOST' i RHR Specine RPY Panmeten
- 1. Pump discharge pressure high 1. Temperature l
i l 2. Pump motor over 2. Pressure
- 3. RHR loop power failure 3. Water level
' 4. RHR loop loop logic failure
- 5. RHR pump motor trip
- 6. RCW outlet temperature high t
N 190 B M Amendmtal
ABWR m_s gn 4 SIRD.dard Plant Table 19QB.4 4 l TIMES AVAILAllLE (IN llOURS) Total Time Allocated Diagnosis Time for Post Diagnosis l Case blode To Esent Time (TD) Actions (T ) l a 5 (Days 2 to 3) 1.2 0.5 0.7 a 5 (after 3 daysi > 14 12 22 b All 16.4 22.4 24 l l 19QB 4 9 Amendment
A ABWR msios Standard Plant as 4 1908.5 DECAY HEAT REMOVAL CAPABILITY OF CLAY AND FPC The purpose of the following heat removal > calculations is to determine heat removal capabilities of FPC and CUW after flooding the envity as a 4 function of time following shutdown. The results show that in mode 5 after 3 days shutdown. FPC and CUW, together, are capable of removing the decay
' heat. After 4.5 days, fuel pool cooling alone is sufficient and after 14 days CUW alone is sufficient, in Modes 3 and 4. FPC cannot be used but CUW is able to remove the decay heat because ofincreased capacity at higher temperatures. To perform these l
caigulations for CUW, an outlet temperature of J 212 F for the non regenerative heat exchangers and inlet temperature of 95 F for cooling water were assumed. Multiplying the temperature difference (212 95) by mass flow rate through the pumps,676 gpm, and the heat exchanger effectiveness of 0.81 results in 9.39 MW which matches the decay heat 14 days after shutdown. Similar calculations are performed for FPC, but this time the mass flow rate and heat exchanger effectiveness are 2200 gpm and 0.39, respectively. The result shows if FPC is used 4.5 days from shutdown, the water temperature will not reach 212"F. The heat removal capability of FPC 4.5 days after shutdown is 14.72 MW which is equal to the decay heat at that time, i i 19005-1 Amendment l
- u. . _ _ . _ . _ . . ~ . - ~ _ . _ _ _ _- _ _ _ . . _ _ . -_ . . _ _ . _ _ . _ _. _..
ATTACHMENT 19QC ~ APPENDIX 19Q REVIEW OF SIGNIFICANT SHUTDOWN EVENTS: j
~
ELECTRICAL POWER AND DECAY HEAT REMOVAL I s
+
'> a.- - - - - _ - - .--.-_-___.L-__.--____._
u
< l 23A61WAS i g,v i
- Standard Plant p
ATTACHMEST 19QC.1 ', CONTENTS - l Section In[R East e l 19QC.1 REVIEW OF SIGNIFICANT SHUTDOWN ' EVENTS 190C.I.1 f Summary of DHR Events 190C.1 1 19QC.I.1 Summary 190C.1 1 7 19QC.I.2 - i i i TABLES j. Table Title Eagt 190C.1-1 Loss of Power Precursors 190C.12 i Decay Heat Removal Precursors 190C.1 17 190C.12 i i 2-i. 4 i i e e s A 4 190C.1 il f r 4 Amendment t l d ;
.~ ., .
ABWR -
- uxsars bA Standard Plant The main features of the ABWR that will prevent 19QC.1 REVIEW OF SIGNIFICANT j SHUTDOWN EVENTS or mitigate shutdown events are:
A review was made of operating events involving loss - Three divisions of ECCs and support systems - of off site power (LOOP) and loss of Decay Heat that are physically and electrically independent i
- Removal (DHR). These two areas appear to have the greatest potential for causing core damage - Two independent off site power sources
- during shutdown based-on past experience. The sources utilized for inforraation on past shutdown - Four oresite power sources (three emergency diesel generators and one combustion turbine events were
] generator)
- Residual Heat Removal Erperience Review and Saf ty Analysis, NSAC-88, March 1986
- - Plant configuration to minimize common
' mode failures due to fire and floods 1 Loss of Vital AC Power and the Residual Heat RemovalSystem during Afid Loop Operations- - Appropriate Technical Specifications and i
i at Pogtle Unit 1 on Afarch 20, 1990, administrative controls to ensure availability of NUREG 1410, June 1990 systems during periods of potentially high risk l operations I - NRC Staff Evaluation of Shutdown and Low 4 Power Operation, NUREG 1449, March - Several alternate means of DHR if normal i 1992 systems were to fail or be out of service for
- ' maintenance
(
- Selected INPO Reports (e.g., SOE and 4 SOCR summaries) and NRC Information - Instrumentation availability during shutdown d
Notices. to monitor plant safety status an initiate l safety systems when needed The results of this evaluation are contained in Tables 190C.1 1 and 190C.12 for LOOP and loss ! of DHR respectively. ' 19QC.I.1 Summan of DHR Events I Not all of the events discussed in NSAC 88 are contained in Table 190C,12. Those events that were due to random failures of single components j and did not result in loss of DHR or other significant plant effects were not evaluated further. If the single failure resulted in loss of coolant, cver press. urization, flooding, or loss of Shutdown Cooling
- (SDC) function, the event was included end the
^ applicable ABWR feature to prevent or mitigate the i event was discussed. i 19QC.1.2 Summan i The results of this review demonstrate that ABWR design includes many features that will prevent or mitigate unacceptable consequences of typical past events. i 19QC.11-i Amendment i I
T able 190C.1-1 y;p. LOSS OF OFF-SITE POWER PRECURSORS = te g i APPLICARLE ARWM FFAT11Rf3 EVENT. DESCRitTH)N mg d. ABWR has two independent offsite power sources. These are Indian Point 2 and " Great Northeast Blackout
- backed up by three physically and electrically sep# rate trains of T
~
m Yankee Rowe (11/9/65) Class 1E AC power each containing an emergency diesel generator. These are further lucked up by a permanent onsite 3 Combustion Tuibine Generator (LTG) whi(h is capalde of peeringany one of the three trains if all three diesels were to all fail. The Cl G is also capable of supplying p>wer to non-l' l safety busses such that feedwater or condensate pumps can also be used to provide reactor coolant make up. las of all transmission lines, See discussion of Indian Point 2 and Yankee Rowe (I1/9/65). Point Beach 1 (2/5B1) failure of three transformer dif-ferential relays, causing trans-former lockout.
. ABWR has two independent transformers peered by two Plant siding fellinto 34.5kv line Ginna (3/4p1) - independent offsite power supplies which reduces the connecting sole startup probability of h> sing offsite pmer. In the event oflosing transformer. offsite power, features described under Indian Point 2 and Yankee Rowe (11/9/65) can mitigate the event.
See discussion of Ginna (3/4pl). Transmission line fault, isolation Palisades (9/2g1) breaker failure. Backup reliy iso-lated 345kv bus. ABWR uses three auxiliary transformets. Ikh peers one of San Onofre 1 (6/7p3) 138ky auxiliary transformer out the ihree Class IE and mm-lE buses. In addition, a reserve for maintenance. Ground fault auxiliary transformer is available to pmcr all three Class IE operated differential relays, . buses. LT(; also available which can pmer Ili and m n-lE deenergizing other auxiliary trans- busses without usingihe auxiliary aransformers. formers. - The ABWR also has two sources of offsite power. 230kv switchyard isolated, HUkv y Oconee 1 (1/4B4) 3 off-site source remained energized pg to supply power to the plant. > ,n s O
.u
-!..;..-_-,_,-.,.-m
1 [ Table 190C.1-1 rm . EI i g E,# LOSS OF OFF-SITE POWER PRECURSORS (Continued) i y -
!! APPLICABLE ARWR FEATilRFS EVENT DESCR!ITION c.
3-See Indian Point 2 and Yankee Rowe (11/8/65) and Ginna y Sole 161kv backup off-si:e trans- m Fort Calhoun (3/13/75) (3/4/71). 3 mission line out for maintenance. 345kv output tweaker iripped (fauhy gwotective relays), open-ing remabing connection to off-site power. Off-site power L could have been supplied from 345kv switchyard by opening genera-
' tot disconnects-See Indian Point 2 and Yankee Rowe (11/1/65).
Turkey Point 4 Less of Off-site Power (IDOP) (5/16/ 71) Protective relays operated when See Indian Point 2 and Yankee Rowe (11/1/65). Connecticut Yankie lines were re-energized after ser-(6/26/76) vice, causmg LOOP. LOOP due to lightening rarikes. See Indian Point 2 and Yankee Rowe (l1/1/65).
. Indian Point 2 Emergency Diesel Gesterators (EDGs)
(7/13/77) - operated. ABWR has two offsite power sources so prob.ibility of one Substation switching error. St. Lucie 1 (5/14/78) switching caror resuking in loss of all ofIsite p>wer is low. Ilut if it were to occur, mitigasion features exist as di cussed in
- Indian Point 2 and Yanker, Rowe (11/1/65).
See Indian Point 2 and Yankee Rowe (II/9/65). Turkey Point 3 (4/4/79) . Imss of all 7 transmission lines due to weather. AllWR has two sources of mm IE power. A ground fauh en One EDG out for mainienance. One one would mit result in loss of a!! mm-IE power. In addition, , Davis Besse (4/19/MI) 13fkv Ines connected, other ener- y if all non 1E power were to be to:J, no valves umnccted to the 3-gized lua mg connected. Ground RilR System would automatically cy(le and cause loss of 7 f )
~
fault on Intkv ims caused loss of , 0: NPSil to any RilR pump. Also, the AllWR *# threc 0 non-nu(lear instruments. Air was independent (1810'1) RilR Systems suth that low of one would puSed into DilR pump, arvi pump was - not resuh in loss of the ability to rcmme dcray heas.
. stopped liy operator, Pump vented
. and eestossed .ilter 21/2 lueurs.
i Table 190C.1-1 m> E ;c t 1 [ LOSS OF OFF-SITE POWER PRECURSORS N y N APPLICA1 LE AllWR FFA111RES O. DESCRII' TION \ ? EVENT j ' See St. Lucie 1(5/14/78). 3 to Maintenance error caused LOOP. San Onofre 1 (4/22/80) 3 See Indian Point 2 and Yankee Rowe (11/9/65). Weather related LOOP. Prairie Island I (7/15/W) See St. Lucie I (5/14/78). Maintenance error caused LOOP. San Onofre I (11/22/80) See Indian Point 2 and Ya: Ace Rowe (11/9/65). IDOP caused by brush fire. Diablo Canyen 1 (10/16/82) See St. Lucie 1 (5/14/78). Switchyard breaker failure during Farley 2(10/8/83) refueling. Deliberate deenergiration of See Indian Point 2 and Yankee Rowe (l1/9/65) and Ginn.e Palisades (1/8/84) (3/4/71). AllWR technical specifications require one of fsite off-site power to isolate faulty and one onsite power source be available at all times. breaker. One EDG out for mainte-nance, other available Imt its ser-vice water pump was out for rnainte-nance, and operators failed Io recognize this before authorizing work on breaker. Available EDG overheated and was manually iripped. A similar event at an MlWR could be more c.nity mitipted Ground short on Salkv switchyard Sequoyah I (3/26/84) due to the existence of the CTG and three fiDGs breaker deenergiicd transformer. Startup transformer supplied power. See Seqeoyah I (3/26/84). One ll5kvline out for mainte- , y Yankee Rowe (5/3/84) nance,other energized. Normal supply transformer energized. Tem- y 6 porary fault deteoion relay h {,g O caused breakers from normal supply 8-transformer to open.
. -. -.. .. ...-. - - . . . - - - - . _ . . - - - . . . . . - ...-~. - -..
Table 190C.1-1 L')> ' i m tlC - 1 LOSS OF.OFF-SITE POWER PRECURSORS (Continued) p- : g " 3 DESCRitTION ' Al*PUCARLE ARWR FEATilRES , EVE!R CL ; One of three safety buses was out Exh of the three ABWR safety trains have separat: 2 8 Salem 1(6/5/84) independent emergency power supplies and suppewt systems of service for maintenance and one ~ so each dicsci can supply power io its own cooling water ' of the batteries in the two re- j maining safety trains was out of pump. ABWR technical specifications require one of(site service for replacement. Auto- and one onsite power supply tw avaitalite at all times. 3 matic transfer relay which should i have energized Ihis buswas removed and p! aced in Unit 2 and not replaced in Unit 1, loss of ! power to awo buses resuhed in two i operable EDGs to start but loss of ' DC control to one of theliains r prevented ck> sing of the EDG out-l put breaker. One EDG did energire one bus but EDG cooling water pump was powered by EDG which lost con-trol power. EDGs ran for two hours without cooling water. One 115kv transmission line out See San Onofre I (6/7/73). ' Connecticut Yankee - for maintenance,one auxiliary (8/24/84)
- ransformer out for maintenance. .
Differential relay opened breakers [ to remaining auxiliary . t aransformer. Breaker alignment errors during ' ABWR design does not alknv cross-ties betaccn plants. '! Poini Beach'2 (10/22/84)- . cross-tie between units caused LO'sP. , U b 75 "o ? i h i
Table 190C.1-1 CA Ei>t;g
- LOSS OF OFF-SITE POWER PRECURSORS (Continued) E,-
%[ APPLICAMIE ARWK FEA'IURES m
!! DESCRIETION ca.
2 EVENT 1l2 L Object frena roof fell onto startup See San Onofre I (6/7/73) and Ginna (3/4/71). E Indian Point 3 l- transformer. d I (11/16/84) See Indian Point 2 and Yankee Rtme (11/9/65).
- Turkey Point 3 Startup and C transformer were .
buth a,ut of service. Offsite (4/29/85) power supplied through main trans- [.
- former. Relay failure resuked in loss of main transformer and LOOP. One EDG started and loaded its safety bus.
l See Indian Point 2 aral Yankee R<me (11/9/65). Turkey Point 3 Brush fire disabled station. (5/17/85) See San Onofre 1 (6/793). fightning caused loss of preferred Walesford 3(12/12/85) offsite power source. Two EDGs started and loaded. Two sourecs of offsite power were availabic. 1 EDG and akernate offsite power' : See Indian Point 2 and Yankee Rowe (11/9/65) and Fort Calhoun (3/21/87) . source were out for maintenance, Palisades (1/8/84). controls for other EDG bypassed to prevent auto-start. Maintenance error tripped off-site prmer; EDG had to be manually loaded. ' See Sequoyah I (3/26/84).
- Maintenance error caused kms of 2 Yankee Rowe(6/1/87)
- of 3 safety buses. .
,e
-]n >f
?
w g.
,-_= . . . , . . . . , . , . . . _ . . ,_ ..
e
Table 190C.1-1 Cn> Egt
=r N LOSS OF OFF-SITE POWER PRECURSORS (Continued) ca.
1 a APPL.lCAHLE ARWR l'EATURES y DESCNilTIDN c1. a- EVENT "U I offsite power source and i EDG See Indian Point 2 and Yankee Rowe (I1/9/65). E McGuise 1 (9/16/87) out for maintenance. Test error 3 caused loss of exher offsite power source. Remaining EDG started and - loaded. Offsite power restored l after 25 minutes. See Judian Point 2 and Yankee Rowe (11/9/65) and San 1 EDG out for maintenance. Safety Onofrc 1 (op/73). Also, ABWR design does md allow Crystal River buses cross-tied. Maintenance safety twscs to be cross-tied. Therefore, this event canmd
,(10/14/87) error caused loss of I safety occur in ABWR.
bus. Cross-connect breaker then tripped and locked out. Dead bus transfer was required to close one - cross-connect tweaker. This required shuttingihe running EDG and resetting the under voltage lockout. See Indian Poir4 2 and Yankee Ron (11/9/65) and San I safety bus'and its EDG out for Onofre 1 (6p/73). Crystal River ' maintenance. Maintenance error (10/15/87) grounded offsite power supply. Re-maining EDG started and kiaded. Anti-pump circuitry has been redesigned in the AllWR to
~ 1 safety bus and i EDG out for- allow closure followingbreaker trip when required
' Wolf Creek (10/16/87) maintenance. Error deenergized other hus. EDG output breaker i
opened and would not close due to anti-p6mp circuit preventing reclosure once it had been opened after EDG started on under- , voltage. DilR kist for 17 minutes _ 5
?E
'8 i> c
{
, - . i
Table 190C.1-1 F 2 LOSS OF OFF-SITE POWER PRECURSORS (Continued) (E 3s 3# 2 e APPLICAHLE AllWR l EATURES 3 DESCRWTION c.
~ EVENT See Indian Point 2 and Yankee Rowe (11/9/05). Al!WR 2
A All of f-site power going through 1 RPV water level instruments are powered liy batteries and I Oconee 3 (9/11/88) breaker. Maintenance error caused at least two divisions are required to tw operaI>Ie during 6 this breaker to open, and it coukt shutdown o suppori ECCS automatie initation functions. not be redosed. No instruments
. to determine actual level and tem-perature of water in reactor core 1 region (incere therinocouples ruw f yet reconnerted, and no power to RPV leveltransmitters).
See Indian Point 2 and Yankee Rowe (11/9/65) and Point Surry I and 2 (4/6/89) Electrical fault and transformer h>ckout. *Tliis de-energized one ileach 2 (10/22/84). safety bus in each unit. Unit 2 EDG started and h>aded. Unit 1 EDG controf in manual. Maintenance ettor caused power are See Indian Point 2 and Yankee Rowe (11/9/65). Diablo Canyon I and LOOP. EDGs started and (3/7/91) k>aded. See Indian Point 2 and Yankee Rowe (11/9/05L I transmission line out for mainte. Nine Mile Point nance. Maintenance error caused (11/17/73) has of other line. See Indian Point 2 and Yankee Rowe (II/9/65). Lightning caused has of all 345Lv s'ilgrim (4/15/74) lines. 23kv line remain energiicd. See indian Point 2 and YanLee Rowe ( A t/9/65). All 345kv lines deenergired (cause Pilgrim (5/26/74) unknown). 23kv line remained ener-giicd. 5 xz 78 b >D o l L I t I- _ _ _ _ -
Table 190C.1-1 r>
" C2 1
i LOSS OF OFF-SITE POWER PRECURSORS (Continued) 5$
! DESCRIlmON APPLICAHLE AHWK FEATURES $%
c.
~
EVEfff See Indian Point 2 and Yankee Rowe (I1/9/65). 2 Brunswick 2 (3/26/75) I train of 230kv huse; for each y
~
unit out for maintenance. Relay error caused breakers on all five lines supplying remaining buses to open. Reduced voltage on grid caused See Indian Point 2 and Yankee Rowe (11/9/65). ABWR Quad Cities 2(2/13/78) has an alarm at 95% of rated voitage (degraded voitage). under-vokage relays to grip break-This gives operalor 5 minutes o restore full voitage Ixfore ers on both safety buses. System offsite breakers would (9en. i ' dispatcher increased grid voltage. See Indian Point 2 and Yankee Rowe (11/9/65).
. Maintenance error caused LOOP.
FinPatrick (3/27/79) See lodian Point 2 and Yankee Howe (11/9/05). Browns Ferry I and 2 lee storm caused kiss ofloth off-site lines. Power supplied ty (3/1/80) Unit 3. See Saw Onofre 1 (6pp3). 4.16kv breaker was racked out Montiecllo (4/27/81) under load. Breaker then shorted, causingloss of both safety buses. See Browns Ferry I and 2 (3/1/tal). Not really an event: Unit i Quad Cities 1 (6/22/82) supplied Unit 2 when Unit 2 scrammed. See Indian Point 2 and Yankee Rowe (l1/9/65). Pilgrim (10/12/82) Storms failed M5kv lines. 231v remained energifed. 9 ew 8 *
>s
.o r,n I
~ ' - '
a - . - . Table 190C.1-1 W> E Y i LOSS OF OFF-SITE POWER PRECUFISORS (Continued) 5W $ APPLICAllLE AllWR l'EATURES Q EVENT DESCRitTION c:. _5 See Indian Point 2 and Yankee Rowe (I1/9/(6). I offsite power source out for L' Brunswick I (4/26/83) test. Maintenance error caused d less of second source resulting in IIX)P. For the AllWR, the CTG could t e used to power one of the f Fort St. Vrain i EIXi out for maintenance. 2nd safety buses if offsite power was not secure. In event of EDG in parallel with off-site I OOP from any sources, features described under Indian (5/17/83) power. Storm caused LOOP, and 2nd Point 2 and Yankee Rowe (11/9/65) would mitigate the EDG tripped on overcurrent due to event. faulty load sequencer and operat-l ing non-essentialloads. l See Indian Point 2 and Yanice Rowe (II/9/65). Lightning caused :.;,s of all Pilgrim (8/2/83) 345kv. See Ginna (3/4/71) and Sequoyah I (3/26/St). Fire caused loss of power to 1 Oyster Creek (11/14/83) stattup transformer. Switchyard deenergized to permit cleanup. Main generator disconnect links were removed, which allowed for use of unit transformer if neces-sary (wasn't used). I reserve transformer, I safety See Indian Point 2 and Yankee Rowe (11/9/65). Monticello (6/4/84) bus,1 EDG out for maintenance. Procedure error caused loss of c nergized but 5 E5 b >? 9 5
~;
Table 190C.1-1 d' I k'
. it - LOSS OF OFF-SITE POWEH PRECURSORS (Continued)
"s c2.
.ag . APP 1.lCAHLE AHWR FEA1 ORES $ ,
~
EVENT DESCRIITION ch. - See Indian Point 2 and Yankee Rowe (11/9/65) and 3 i Quad Cities 2(5/7/85) Unit 2 dedicated EDG out for main-
- Browns Ferry I and 2 (3/l/80). y f e
tenance. Maintenar.cc error caused ~ . IDOP to Unit 2. Unit I plus swing EDG pmvered Unit 2. t Reserve station transformer out See Indian Point i and Yankee Rowe (11/9/65). " i Millstone 1 (11/21/85)
. for maintenance. EDG out for nain- ;
' tenance. Maintenance error caused ioss of 345kv supply.
+
In the ABWR design, loss of the preferred offsite power Peach Bottom 3. Explosion and fire in transformer source would result in all three emergency diesels starting caused loss of I startup trans. -[ (4/13/86) former. Ahernate startup trans- and picking up respective IE buses. Power could Ic - manually transferred to the alternate preferred power former supplied power. ! source (reserve transformer) if desired depending on offsite power reliability. See Indian Poif 2 and Yankee Rowe (11/9/65). flope Creek (5/2/86) 2 of 4 EDGs out for maintenance. , I ' 1 of 3 off-site line cut for main-tenance. Inadvertent relay actua-tion caused LOOP to safety buses. i See Indian Point 2.snd Yankee Rowe (1t/9/65). Pilgrim (11/19,36) Storm failed all 345kv. 23kv remained energized.
' I 345kv out for maintenance. ' See Indian Point 2 and Yankee Rowe (11/9/65).
Pilgrim (12/23/86) r Hashower caused loss of osher
,345kv. 23kv still available.
J 3' a'
>g.
S ' 0, k
. . _ _ . . _ . . . . _ . . _ . _ . . _ . . - .._ _ . _ . . _ _ . . . . _ . . _ _ . _ . _ ._ _ _ -. _.m _.. . . . _ . _ _ . _ . . _ . .. . _.
3 Table 190C.1-1 rop :! g- EilC t .i LOSS OF OFF-SITE POWER PRECURSORS (Continued) 3 i L a a m - E DESCRIPTION APPLICAMI.E AHWR FEATURES
~ EVENT L !
. I of 3 EDGs out for maintenance, See Peach Hottom 3 (4/13/m). 3 m
Shoreham (3/18/87) -
' I safety bus out for maintenance.
1 , Current transformers shorted as a safety measure. This unbalanced .; relays servingboth service trans-formers,but without actuating dif- ; icreatial current relays. 3 weeks later, condensate pump start ; caused differential relay trip, opening bredas from sernce transforme' /.utomatic fast trans- ;I fer to reserve service transformer - .t occurred,twa ucsalance caused it to trip. 2 EDGs searted and - loaded. See Indian Point 2 and Yankee Rowe (11/9/65). .! Pilgrim (3/31/87) ; 1345kv ring bus breaker out for-'
-[
maintenance. - 1345kv line lost - due ao storm. Other sne isolated ' i due to resukant tweaker open-ings. 23kv line still availabic. i Lightning caused loss of I of 2 See Peach Bottom 3 (4/13/M). Peach Bottom 2 & 3 off-site. This caused ks. s of i - (7/10/87) . startup transhwmer. Other trans-former remained in service.'
- ?
8 ?- n-
>yw 5
I i . . - - -- - - - : _=- - _ - _ . . -- .- A
Table 19QC.1-1 W
$. LOSS OF OFF-SITE POWER PRECURSORS (Continued)
La
- 8. E.$ .
~
EVENT DESCRIITION APPLICAHLE AHWR FEATtIRES $%, ca. Both startup transformers and I of See Indian Point 2 and Yankee Rowe (II/9/65). 2 Vermont Yankee 2 345kv main generator output yl
~
(8/17/87) breakers out for maintenance. Main generator disconnect links were removed. Unit auxiliary transformer energized by main transformer. Upset a grid caused osher output breaker to open, caus-ing LOOP. EDGs started, and backup source was still available. 23kv line out of service. Snow See Indian Point 2 and Yankee Rowe (It/9/65). Pilgrim (I1/12/87) failed lxwh 345kv lines. Startup transformer deenergized due to arcing. EDGs started, and power
- was restored by removing main gen-crator disconnect links and backfeeding to auxiliary i transformer.
1115kv line out for snaintenance. See Indiara Point 2 and Yankee Rowe (11/9/65). l'itzPatrick (10/31/88) liigh windsinterrupted other I15kv - line. EDGs energized safety buses; efforts were directed at other systems, so shuumn cooling was unavailable for 95 minutes (RCS temperature increased 10 deg. F). s 3 F C D.
>gvs U
.- , .. - .. .. - --... - - ..~ . - . - - .. - . . - . - - ._ - ~ - . - .- - - - - ..... . _
I r a Table 190C.1-1 4 EIt g i i LOSS OF OFF-SITE POWER PRECURSORS (Continued) y & g m DESCRIt' TION APPLICABLE AHWK FEATURES
"' EVENT C.
i See Indian Point 2 and Yankee Rowe (II/9/65). _"t! Nine Mile Point 2 111%v line out for maintenance. m (12/26/88) Current transformer failure caused . 1 , loss of other line. Out of ser-vice line was returned to service and EDGs also started and loaded. See Indian Point 2 and Yankee Rowe (11/9/65) and Pilgrim (2/21/89) 345kv!ast due to cable failure. 23kvline available, SBO EDG avail. Sequoyah I (3/26/H1). able. Disconnect links removed for backfeed. Bus fault on secondary side of sta. See Ginna (3/4/71) and San Onofre I (6/7/73). Browns Ferry 2 tion transformer. EDGs started.
'(3/9/89)
ABWR undervokage load shed system will md inadvertenity Main generator disconnect links re. Millstone 1 (4/29/89) trip 6900 volt kuds. ABWR undenvoltage relays sertw moved. toads had been transferred to station service transformer. . power on bus independent of source. Design error in relay ofload shed system caused opening of 4.16kv breakers when reserve station g transformer was deenergiied. Normal station transformer remained energized.
.e Ground faults opened breakers from See Peach Ikdtom 3 (4/13/86).
Browns Ferry 1 500kv switchyard. Off-site power
.($/5/89) restored to safety buses from .
161kv switchyard through startup transformer.
~
5 '
. 75 I
. ? >m
~ . ._ . _ _ . . _ . _ _ _ _ _ . _ . . _ _ _ . . _ . . _ _ . _ _ _ _ . _ . __._ ____ ~ _ _ _ . __
Table 190C.1-1 & N Eit g LOSS OF OFF-SITE POWER PRECURSORS (Continued) m , g2, i N a ) a DESCRIlrl'lON APPLICAHLE AHWR iEATilRES 9 E EVENT ca. 1 safety bus out for maintenance. In the ABWR, the two operable emergency buses could 3 m i WrJP-2 (5/14/89) - have been energiicd from either the combustion turbine 2 EDGs out for maintenance. Opera- E gener ator or the alternate preferred offsite reserve trans- ' tor error caused i OOP to other safety buses. EDG started and former. loaded I safety bus. , t 1 of 4 preferred transformers Scc WNP-2 (5/14/89).' ! River Bend (6/13/89) out. Maintenance error tripped I prefened transformer, causing loss 14 power to 1 safety bus. EDG started and loaded. Mainte-nance error tripped main generator ! output breakers, causing LOOP to non-safety buses. . i ABWR has two offsite power sources, three diesel , Oyster Creek (3/9/91) One EDG and I bus out for mainte-nance. R(,atine check revealed generators, and one combustion turbine generator. , i other EDG had fauky land gastet ; which would have caused failure if ! required. This left plant with only I source of power,the
. startup transformer.
~ LOOP due to improper maintenance ABWR procedures do not allow independent vitalImses to
! ' Vermont Yankee be cross connected. The multiple sources o! nn-site and ; in switchyard.' While installing a
'(4/23/91) new battery on non-1E 125 VDC bus, off. site power roduces the need to attempt cross connecting
- buses. The ABWR has four physically separate and
' two vital DC buses were cross con-
'nected through a battery charger independent 125 VDC systems.
after defeating a mechanicalinter. lock. Whu the battery charger i breaker was opened to install the
- new battery, a vokage , h_,
3 ? n=
>w
- un 1
I l
I Table 190C.1-1 Z> i LOSS OF OFF-SITE POWER PRECURSORS (Continued) Q E,/ ' [ so DESCRil'I'lON APPLICARLE AHWR FEA'IURidi -s R EVENT ch transient was sent through the
-c E
- entire DC control power system which caused both off. site power E
breakers to trip and kxk open; LOOP caused by boom of mobile ABWR has two independem preferred sources of off-site . Diablo Canyon Unit 1 crane shorting out 500kv trans- power. 3/7/91 former. Standby startup trans- I former was out of service for main-tenance. 'ne three EDGs started .i and picked-up vital buses. Off-site power was restored in five hours. ABWR offsite axiwer supplies are physically and cicctrica!!y LOOP while working on aux. bailer Nine Mile Point separated so kiss of both is rmt expected to o: cur slue to circuitry. Div. I diesel was out 3/23/92 common cause failure. Three independent electric divissims for mainter:ance. Div.11 diesel
- started and loaded. Div. III (including instrument UPSs) would reduce likelihmal of (IIPCS) started but tripped on over .. simultaneous failure of allthree divisions. ,
temperature due to lack of cooling - water. All control room annuncia-tors lost due to loss of A and B .i UPS. t I i i f , 5 "$ 13;
.?
i 5 4
Cn l- Table 190C.1-2 88 s it a DECAY HEAT REMOVAL PRECURSORS Ss # ' E 3. EVEfR CATEGORY: IDSSES OR DEGRADATION OF RilRS DUE TO LOSS OF COOLANT FkONI REACTOR VESSEL, 3 PLANT INITIAL PLA!W REPORTED CAUSE APPLICABLE ABWR FEATURE CONDITIONS EVENT DESCRifTION LER/DATE AllWR component design and A slight reactor water level drop was de- Failure of the minimum Peach Mode 4 Cold Shut- flow recirculation procurement will emphawe tected and determined to be caused by leak- labrication quality and proper Bottom 3 down. kIIRS in op- valve associated witb 794X12 eration on kx>p 'A , age through the minimum flow recirculation the 'A' RI1RS pump. maintenance to minimue in-vasve for time *A* RilR pump (MO-16A). dividual component failures. January 8, Vessel level was maintained by use of the 1(719 llowever,if tailure occurs,SDC stmy full pressurizing system. Attempts would be tempwarily kist but to eliminate the leakage by further two other RilR trains would be closing the minimum how valve resulted in available to re-establish DilR its failure to the wide open position. before any fuel damage occur-This failure caused a loss os coolant to red. In additinn uther heat the suppressionpx>l. The loss of vessel removal systcms (e.g, fuel pw l water level conimued to the point of cleanup and neling (l'It), isolation of the shutdown cooling system reactor water cleanup) are on low water level at which time ifie available for DilR depending water level stabili$cd. The time required on plant conditions. Other to raise the reactor water level, via ihe makeup sources (e g, IIPCF, stay full system, clear the RilRS isolation fecdwater AC Independent and reestablish shutdown cooling with the water add,ition CRDS)can be
'C' RilRS pwnp, allowed the coolant to rise used if no DIIk system is avail-to about 20lT'F, causmg a gaseous re- able and the react (,e umlant lease via disassembled RCIC steam iso- begins to Imil.
lation valves. None reported. See Peach Ihdtom 3 (1/8/79). Mode 5, Refueling. The 'B' loop RIIRS was placed in service in llatch 1 the shutdown cooling mode and vessel level August 13, RilRS in operation. was observed to be dropping. Valve Ell-
. l'I/9 F0048 was determined to be leaLing to the suppression tool. A localleak rate test of the RilRS *B* pump torus su(tion isola-tion valve showed the valve to be IcaLing in excess of specified criteria. Follow-ing corrective action, the valve was sat-islactority retested.
O d me
? g O se a
-~ .. . _ _ _ _ . _ . _ . _ _ . . . . - . . . _ _ . _ _ _ _ _ _ . _ _ _ . _ _ _ _ _ _
-i, TatHe 190C.1-2 l
E,e DECAY HEAT REMOVAL PRECURSORS (Continued) $ l 1 EVEM CARGORY: LOSSES OR DEGRADATION OF RHRS IMIE TO LOSS OF COOL
~ ca.
"C
'i INITIAL PLANT REPORTED CAUSE APPLICAHIE ANWR FEAWRE m"- .
PLAM EVENT DESCRitTION s t LER/DAE: CONDITIONS ~ Circumferential through See Peach thstom 3 (1/8/79).
- Mode 5, Refueling. - This event consists actually of two sep-Oyster arate events involvine shutdown coohng wall cracks in one tube t
. Creek RllRS system in of ahe 'A' heat ex-operation on kmp heat enchanger tubeTeaks. On Augusl changer and (me tube of 81-038 with reactor water temperature F, at 197,27, the *C heat exchanger, j.' A 27, 'C. Reactor had the *C shutdown cooling heat enchanger -
1 - been shutdown for 13.. due to fatigue failure . August 28, . days. . devek d a tube leak resuk' in reactor - caused byllow induced # water inginto the RBCL system as vitwation. 1981 " indicated by the RBCCW process radiation" monitor. About 2 minutes later reactor water level began to decrease. the decrease occurred over approximately 10
, minutes,with an estisaated leak rate of 400 gym. Reac.or vessel water level was recovered by make up supplied by the feedwater and condensate system. The 'C loop was secured and temperature maintained below 212 F by use of tbc 'A*-
shutdown coolingloop. f
. On August 28, another RBCCW muss moeitor alarm was received and the RBCCW surge tank was reported to be overflow.
~
The *A* shutdown cooling key was '
'- ed. The 'B' heat enchanger was out of service but was made serviceable in a - .
few hours. Temperature was maintained by
- - increasing flow to the RWCU nonregenera-
- tive heat excha er and increasing letdown to the main c .nser. Water was pumped i
, back to the reactor using a condensate 4 pump, in addition to RWCU and main condcaser systems, the istdalism camdenser and ilCCS systems were all::vaitalde. t U
,, E l h S
. 10 a
- b 1
A
k m Table 1EOC.1-2 5.j j
~
DECAY HEAT REMOVAL PRECURSORS (Continued) lA)SSES OR DEGRADATION OF HilRS DOETO LOSS OF COOLANT FROM HEACTOR VESSEL, c.,% EVENT CATEGORY: T APPLICAllLE AllWR FEATURE F INITIAL PLANT REPORTED CAUSE 3 PIANT EVENi sESCRIF110N
- LER/DATE CONDITIONS AllWR has three independent leaking flange on spool While placing RIIR 'A' hop in service in RIIR loops. Also the mam laSalle 1 Mode 3, Ilot Shut- piece on 'A' RilR oump the shutdown cooling mode, leakage was sucti<m line, caused by condenser and RNCU are 824739 June down. Plant cool- discovered at the 'A RIIR pump si:ction capable of :emoving decay heat down in progress thermal growth on heat-9,1982 line. RilR kmp *A' was taken out of up and cimidown. in Mmle 3.
RilR loop *A' being service for repasts. Alternate methods of placed in service. decay heat removal were reactor recirc (Prior to initial pumps and inboard main steam line drain criticality.) l with RWCU. AllWR procedures will clearly Personnel did not recog-The unit was in cold shutdown fc!!owing niec the potential describe proper operational LaSalle 1 Afode 4, Cold steps and the technical specifb performance of reactor internals vibraton vessel drain path that 824)42 Shutdown (Prior to lesting. *B' RilR system was operating in existed upon returni..g calmns will I e based on mini-June 11, initial criti. the shutdown cooling mode with all flow miring plant risks during cality). the system to a m>rmal normal full power operation 1982 lineup from standby bypassing the 'B' RIIR heat exchanger tomamiain operation. The test reactor temperature between 140 and shutdown conditions.1he F and 200 F. The 'A' RilR system was lined AllWR has three indegendent procedure failed to RIIR systems and SDC is iw-up for standby shutdown cooling. The 'A' recogn,ize the current ! and 'B' RIIR suppression pool suction operatmgstatusof the lated on hm RPV level. valves were out of service electneally RilR system in for repair and the valves were manually shutdown cooling. The closed. No backup means of decay heat levelinstruments ap removal was available due to the reactor efIthe downcomer building ck> sed cooling water system being region where shutdown out of service. (No actual decay heat cooling receives its existed.) suction. The Tech Specs were interpreted Testing of the 'A' RIIR drywell spray such that Imth shutdown outboard isolation valve was approved and cooling hops were performed in accordance with procedure. reqmred operable with After the test was completed, the system one in operation, and was returned to standby operation. The that the idle pump restoration p'rocedure directed the opening could be out of ser ice of the RilR A' heat exchanger bypass for only 2 hours. This valve. When this valve was opened, water was a conservative in from the reactor vesel filled the U
?E d >t G
}
Table 190C.1-2 5.y DECAY HEAT REMOVAL PRECURSORS (Continued) $% [
~
1 OSSES OR DEGRADATION OF RIIRS DilE TO IA)SS OF COOLANT FROM REACI'OR c. VENS MENT CATEGORY: "U APPLICAHLE ABWR FEATURE :7 PLANT INITIAL PLANT REPORTED CAUSE m CONDITIONS EVENT DESCRilTION LER/DA'IE terpretation but it ag-previously drained RIIR 'A' piping, from gravated the event by draining atmut 3 tXXI gallons of water imposing an arbitrary
.he vessel. At 115 inches level an time restraint on the automatie isolation of the shutdown test, cooling system occurred. The vessel level was restored and the 'B' RilR h>op was verified lilled and vented, and shutdown cooling system suction isolation valves reopened. Reactor vessel fewl again decreased to about 10 inches and a second isolation occurred. It was determined that this second isolation resulted from the starting transient and resulting level drop in the downcomer region. Vessel level was aga;n restored; ami shutdown vented, arri restarted; cooling and the unisolated,k>op
'A' RilRs determined operable.
Operator error; misin- The potential for this operator Mode 4, Coki laxy'A' of the RilRS was lined up in the terpretation of vabe error has been climinated in the j Grand Gulf LPLI mode, and h>op *B' was lined up in position indication. ABWR design hv providing NA Shutdown, after the shutdown cooling mode for a surveil- valve interhits.'When RitR A I 3, initial critie- RXb
- fully open"indi-lance test, After completion of the test calor light was not system is in the shutdown ct=>l-1 ality. RIIRS lxiop the operator returned *B' kup to the LfCl ing mixle (i.e. taking su(tion "B' m Shutdown B' burning, but neither from the RPV), the dis (lurge Cooling. mode, which required shutting the loop *he was the " fully shus' SDC suction valve (RMM) and opemng t valves to the suppsession powel indicator. Valve was hmp 'B' suppression pool suction valve probably in a parsially are interlocked m ihe chised b d t gesition to prevent inadvertent (RJIM open position. Reasam on the).
openSince a light indicator for RXM, o r-bulbthewas urne ou for RkM MOV breaker draining of the RPV Torea-ator assumed that RME was already ut, h trip not explained. lign to the low Pree 're Riunt-and opened RXH. This opened a flow pat er (LPI'L) mixie, the suppres-from the reactor vessel via the 'B' RIIR skm gw=>l suoion vahe cannot hmp to the suppression pool. Approx- be opened until the SDC suc-imately 10,(X)J gallons of water drained skm valve is fully closed. from the react 6r vessel prior to automatic isolation of the RilRS on low water level. The operator attempted to reshut RMM up(m ,, recemng a low level alarm, but ihe valve's MOV breaker tripped. % d I$
>m h
~
N Table 19QC.1-2 m to a 5,y DECAY HEAT REMOVAL PRECURSORS (Continued) l
~
EVENT CA'ITGORY: LOSSES OR DEGRADATION OF HIIRS DOE TO LOSS OF COOL. ANT FROM REACTOR VESSEL, c.,
"O INITIAL PLANT REPORTED CAUSE APPLICARLE AHWR FEATURE E PLANT EVENT DESCRIPTION :s LER/DATE CONDITIONS
} Reactor Coolant System See LaSalle I (6/11/82).RilR Mode 3,Ilot During a startup test to determine the shrinkage caused by valve misalignments are mini-Susquehanna capainlity of the shutdown cooling male of mired in the AllWR design by 1834156 Shutdown. RIIR, the *A* RilR heat exchanger was valved rapid temperature de-crease. Valve lineup male switches for the five April 7,1983 in causing a rapid temperature decrease. operational RilR males. Se-As a result of RPV water volume shrinkage, error caused loss of tection of a male (e.g., SDC inventory to suppres-the RHR automaticallyisolated on kwv smo pool. causes automatie valve real-reactor water level. CRD flow was used to ignments). sestore level; and MSIV's were opened to decrease the vessel delta-T. RWCU was established to stop stratification. Rif R loop 'A' was restored, but a valve lineup - error caused the pump miniflow valve to t bypass RilR flow to the suppression pool, ! causmg a second RilR isolation on low level. Level was restored and RilR rein-iriated, but the inventory addition via condensate transfer cayd another temp-crature decrease of 120 in 5 minutes,d ! so the RilR system was isolated a thir time to halt the cooldown. The system was I restored again, and a fourth short isolation was received when starting the
'B' RilR pump.
Using an unusual valve See laSalle 1 (6/II/M2). The With the control rod drive system in ser- AllWR design has adequate LaSalle 2 Cold shutdown. sice and the reactor water cleanup system lineup and bypassing Preoperational automatic safety feat- safety featurcs. Ilowever, N/A August out of service reactor water level was unusual valve lineups and 15,1983 testing prior to being controlled by draining through the ures. fuel load. bypassingof safetyleasures RI1RS *B* knp to the suppression pool. A should ik performed under new drain path was being established via strict admmiserative contro! the 'A' RIIR loop (RD: and HU6). As soon as this new drain path was lined up the reactor vessel began draining rapidly. The event did not terminate automatically on low RV water levelisolation of RilRS,
,,, xe 78 p
>D.
U
. . . . . - _- - - . . . ~ - - . - - - . - . - . - - - . - - - - . .
N Table 19QC.1-2
- tC 5,#
DECAY HEAT REMOVAL PRECURSORS (Continued) " l ~ o. EVEfft CATEGORY: LOSSES OR DEGRADATION OF RilRS DOE TO LOSS OF COOLANT FROM REACTOR VESSEE "U PLANT INITIAL Pt ANT REPORTEI) CAUSE APPLICAHLE AHWR FEA111RE F CONDITh;NS EVENT DESCRIPTION :s LER/DA1E ~ because the low level isolati<m signal had been bypassed by transferring control for the RilR shutdown cooling isolation valves to the remote shutdown panel. This was done intentionally to prevent inadvertent ! isolations of the temporary drain path. The loss of coolant event was termmated operator action,32* above the top of - t fuel re loaded). gion (fuel had not yet been RI1RS operable but shutdown cooling status Trip fingers which hold See Peach Bottom 3 (I/8/M). LaSalle 1 Cold shutdown. N mmimum flow the motor operation in 83-108 RIIRS operable. not stated. IWAA)RlidSstuc pump *k open following handwheel operation September I, bypass valve (down cooling was lined up were found broken. 1983 a test. If shut Valve motor damaged. to loop 'A' then a drain path to the suppression pool existed. The LPCIinjection ABWR comgxment design and . LaSelle 1 Cold shutdown. Rif R kgic testing was in progress which re- procurement will emphasize quired opening most loop B mjection and check valve was stuck 83-105 open. Inspection of Iahrication quality and proper September spray vafves drywell spray valves (R)16B maintenance to minimite and F017B), suppression twx>l spray valve tiie valve revealed 14,1983 and test return valves (Rf27B and F024B), improper maintenance individual component failures. on the valve operator. RIIR higic testmg ducs not and B and C kx>p injection valves (ID428 require that RPV isol.itism rely and IDt2C . This lineup relied on test. The valve had been reassembled by lining im a single chesk valve durmg
. able injecti)on check valve IDilB to p,re. RilR higac testmg.
vent reactor vessel inventory loss via m. up the wrong mark on jection valve R)42B to the open spray and Ihe spline shaft to ahe test return lines. When R)42B was opened, air operator gears, reactor vessel inventory was rapidly lost which held the check - to the drywell and suppression pool be. valve 35 open. The cause the testable chtck valve was stuck packin f oo lic,g httogland was also open. Most of the water lost from the full closure.pumit reactor vessel went to the suppression U 8 ,e 7 C >h(n N
Table 190C.1-2 hw 5,#, l DECAY HEAT REMOVAL PRECURSORS (Continued) y
~
EVENT CATEGORY: LOSSES OR DEGRADATION OF RHRS DUE TO LOSS OF COOLANT FROM REACTOR VIGSEl_. c.
"t!
PLANT INITIAL PLANT EVENT DESCRIfTION REPORTED CAUSE APPLICAHl.E ABWR FEATURE F LER/DNIE CONDITIONS ~ 2 pool. The operator terminated the event aber a 5(r level d op to alx>ut Ifdr alxwe the top of Ihe active fuel. Total inven'ory loss was hetween 5,tXXI and 10,000 gallons. It should be noted ahat no automatic isolation feature would have terminated this f.ow path; however, the LPCI injection line penetration is atxwe the top of the active fuel. Operator error in AllWR procedures will Quad Cities 1 Cold shuttkywn. The RPV level decreased 14 inches in two highlight RIIR syqcm, valve related events. The shutdown cooling suc- misaligning RIIR valves. 1/24/91 ahgnments durmg mamtenance. inn valve was sinAed as a mamtenance The keep fill pump and check but some vent and drain valves in pressure alarm assures a full the k>op were also open when the SDC loop. suction valve was open th RPV drained 5 inches. The operator isolated SDC to s'op the flow bt.2 when the kx>p was returned to service an additional 9 incks were drained from the RPV into the partially empty RIIR loop. U b "55 9 >w 0
Table 190C.1-2 5,5 DECAY HEAT REMOVAL PRECURSORS (Continued) y
~ LOSSES OR DEGRADATION OF MilRS DilE TO LOSS OF COOLANT FROM REACIOR Vsegggt c2.,
)- EVENT CATEGORY: T APPLICAltLE AHWR FEATURE m INITIAL PtANT REPORTED CAUSE ::: PLANT EVENT DESCRllTION LER/DATE CONDITIONS ACWR RilR valves are Operator error in not interhx:ked to prevent SDC After isolating RCW the RPV level began to folkming approved pro-Quad cities Cold Shutdown. On increase. Operators attempted to reduce cedure for draining the su(thm and injection valves shutdown cooling in from being open at the same 2 8/17/87 one Rif R loop, reac- level by draming to the suppression pool RPV. using the RilR system test return valve time as the suppresskm p=>l for water clean up return valves. (14 mch valve). This resulted in rapid (RCW) system out decrease in RPV to km level setpomt and for mamtenance. an automatic RPV isolation. ABWR RilR system keep fill Operator error in plac- alarm woukt alert operator in a
~ SDC k>op was being put in service but ing SDC kmp in service Fermi 2 flot Shutdown fol- normal loop heat.up alignment could not be partially drained hiop condition.
lowing test, usmg unapproved 3/17/87 used because one valve would not open procedure. one RIIR .A inoperable. (24 inch testable check valves)d Io fill smaller (1 inch) valve was use the loopbut the normal 4 inch drain line caused drainage faster than the I inch
= line could fill the loop. This drained the loop but operator could not (cII.
When proper SDC toop tem rature was reached operator opened S suction valve to the RPV and RPV level decreased to the low level setpoint and RPV isolation occurred. Operator error in not ABWR RilR suppressi m pol During the process of shifting SDC from Di- following proper procc- sucthm and SDL suctmn valves Fermi 2 Cold Shutdown. vision Il to Division I, a RPV low level are interhicked to prevent SDC on Division II. dure placmg SDL in ser- inadvertent RPV drainage. 8/2/87 s'agnal occurred because valves were mis- vice. ahgned resuhing in an open ihm ath to the suppression pool from the RI V. Operator error in rol Suppression pel suction valve While returning from SDC to standby low knowing that stroke cannot be op ned until SIX' WNP.2 Cold Shutdown in pressure injecton mode of RilR, the opera- sucthm valve is fully el.ml. SDC. time for each valve is 5/7/85 tor opened the suppression p(ml suction 90 - 1(K) seconds. valve before the SDC suction valve was fully chised. This opened a drain path from the RPV to the suppression smol re-sulting in a km RPV and SDC isolation. h
,z b 7S o >?
E
cn;; Eg d i Table 190C.1-2 h
! DECAY HEAT REMOVAL PRECURSORS (Continued)
FA'ENT CATEGORY: lA)SSES OR DEGRADATION OF HilRS DUE TO IA)SS OF COOL. ANT FR(Mf2REACTOR V REPORTED CAUSE APPI.ICAllLE AllWR FEA111RE y PLANT INITIAL P*aANT EVENT DESCRII' TION ~ LER/DATE CONDITIONS See WNP.2 See WNP-2 While returning one RilR loop to standby, $p/85. 5/7/85. j Shoreham Cold Shutdown botb operator opened suppression gxml suctitm RIIR loops in SDC valve while SDC suction vahe was par-7/26/85 mode. tially open (see WNP-2 5/7/85). Operator error in not AllWR RilR hwips are I Ixiop *C" SDC suction valve remained- open knowuig status of Rif R independent and cross train Peach Cold Shutdown. after previous SDC operation.12)op A re- flow cann d occur. SDC on "A" RilR system valves. Bottorn 2 quired a full flow test due to, pump prob-9/24/85 loop. lem mvestigation. SDC A* isolated and "A* pump abed to suppression pool for test. This opened pathTram RPV to sup-pr:ssion pool through "C" SDC suction v Jve. See WNP-2 See WNP-2 While restoring SDC loop to standby, sup- 5/7/85. Riverbend Cold Shutdown. pression pool suction and SDC suction 5/7/85. 9/23/85 valves were open at the same time. Operator error improper AllWR procedures will(learly A" SDC on line a path was describe proper valve lineups. Cold Shutdown. While placing"RPV to the main condenser. valve line.up. Susquehanna open from the 2 HPV level dropped 35 inches resu!!ing in 4/27/85 RPV low level signal and isolation of SDC. Valve failure. SDC woukt isolaic on low RPV SDC pump mini-Ilow valve failed open allow- level. Su hanna Cold Shutdown. ing water lo flow from RPV to suppression I 5 peol. 5/ Operator error. SDC The keep till alarm would aler an isolation she operator to a partially Cold Shutdown. While warming-up SDC hxy, flow. Opera- loop isolation not drained RilR hop. WNP-2 signal occurred on high SDL alarmed in control 8/23/84 for did not mxice and kmp dramed to the room. radwaste system. When operator placed hop in service water drained from RPV into empty SDC hop. AHWR RIIR sy, tem tests Maintenance error. would md require all valves he RilR hop in test mode with several valves LaSalle I Cold Shutdown. open. lamp check valve depended upon to open and rely'on (hc(k valve to isolate RPv. Check valve failed open due isolate the Rt V p 9/14/83 g to mis. assembly and improper packing gland _ y installation. h g >w b
cn;p. - Table 190C.1-2 y I [ 5.$, E-DECAY HEAT REMOVAL PRECURSORS (Continued) LOSSES OR DEGRADATION OF RilRS DUE TO U)SS OF COOLANT FROM REACTOR VESSEI, w% 9 c. EVENT CARGORY: 3 m INITIAL, PLANT REPORRI) CAUSE APPLICAllLE AllWR FEATURE :s PIANT EVENT DESCRIPTION ~ LER/DATE CONDITIONS RilR system drain to th-Operator error. radwaste syerm omtains awo Cold Shutdown. Operator attempted to lower suppressi<m Brunswick 2 pool level to radwaste but loop was in SDC valves in series tiot 9/24/84 mode and resulted in water diversion from automane: ally dose on low RPV R PV to radwaste. Icvel. Electrical contacts in See Peach Ikutom 3 (1/8/71) Mode 5, Refueling While performing maintenance on a feeder the pump trip h>gic and LaSalle I (6/lt /82).
"Nrim RilRS in operation. transformer a live transfer of power was were corrmied to the O G4 attempted. h(al-operation of a power extent that they,scited
' m:2mber Coolgnt temperature breaker deenergized a vital instrument in the open pmtion.
21,1981 at 70 F.
'C RIIRS pump, Ihere-panel, causing two shutdown cooling fore didvalvesgMO-47 not trip when and MO-48) to close on receipt j i
of a reactor high pressure isolation signal. the suction valves leIt The 'C RilRS pump simuld have tripped their full open pisi-immediately when its sucti m valves shut, tiam. Inadequaciesin but failed to do so. After atx>ut 5 hours,d to the implementation of when the process computer was returne admimstrative controls service, atinormal heat exchanger for shift turmwer temperatures alerted operators to a valve lineup checks, pro 6 tem. At this time, the 'C RilRS pump and board checks aggra-was observed to be running with lxdh sne-vared the situati<m. tion valves shut. The *C pump was Extcasiw: maintenance tripped, the valves opened, and the *A* activities distracted pump siarted Io restore shutdown cooling. operators. The Reactor Protection Loss of power does nsw cause The RilRS was operating in the shutdown System (RPS) was oper- isolation of SDCin the AllWR Susquehanna Male 4 Cold Shut- cooling mode. A Division I isolation design. The muhi-ptexed safety 1 83-030 down. kif RS in op. ating on alternate eration on loop *A . signal to the inicard isolation valve to power supplies while system lopic will emly cause February 16, the RilRS caused a kiss of shutdown cool- isolati<m d a valid iwletion 1983 the RPS MG set was ing. The system was reestablished by undergoing omdithm existed. resetting the signals. A second occur- maintenance. Spurk>us rence was experienced within an hour. tripsof the RPS alternate power supply breakers caused iwla-tion signals. N xs b >e h O O
~
......L.._._.
l l cn y;> SI Table 190C.1-2 [ DECAY HEAT REMOVAL PRECURSORS (Continued) -r
! li)SSES OR DEGRADATION OF RIIRS DUE TO I.OSS OF COOT. ANT FROM REACTOR VESSEL _,
l EVENT CATFGORY: 3
- D INITIAL PLAST REPORTED CAUSE APPI.ICAllt.E ABWR FEATURE 3 PIANT EVENT DESCRitTION ~
LER/DATE CONDITIONS See Susquchanna 1 (2/1f,/81). RPS actuati<m caused by An RPS actuation caused RilR loop *fr oper- an inadvertent lireaker Susquehanna Mode 4 Cold Shut- ating in the shutdown cooling mode to iso-183M) down. I't!IR in op- D' tripped Iwice on at-cration on loop 'B'. late. Rilk pump *RilR cooling was estab-trip (bumped by)a con-struction worker . The April 11, l tempts to restart.
- restart trips are 1983 lished again on loop 'B' usmg pump B'. beheved to le due to a faulty shutdown cooling flow switch.
The power supply fuses AllWR solk! state logic Folh> wing electrical maintenance during to the isolation higic minimites use of fuses and logic Grand Gulf Mode 4 Cold Shut- which some shutdown cooling motor-operated had not been replaced testing is easier sah that these 834%9 May down. [Duringini- valves were bhicked open, power was types of operator errors willIie 23,1983 tial plant startup folhiwing compfetion of restored, and the valves were unblocked. a design change. reduced phase). The valves isolated as a result of a previously existing isolation signal from the valve esclation k>pc, causmg a loss of both shutdown cooling loops. The solid state trip ABWR has three independent Both RilR shutdown cooling hops isolated unit for the common (bothphysical!y and Grand Gulf Mode 4, Cold on two occasions during attempts to start ciectrically) RIIR systems. No Shutdove. RilRS 480V trip breaker had 83-119 a control room air-condithming compres- common power supplies August 18, kop 'A' in oper- failed. between RIIR systems exist. ation. (During sor. The systems mteraction was due to a 1983 common power source to the compressor and initial plant to leakage detection L>gic circuitry, startup phase.) which caused the isolaton. See Susquehanna I (2/16/M3). The RilRS isalated after shifting the RPS The distributhm trans-Mode 4, Cold former on the unregu-Grand Gulf power supply to an ahernate source. The lated RPS alternate 83-137 Shutdown. RI1RS alternate supply breaker tri . d, causing September I, kop *A'in gewer source was an isolation of shutdown et ing. subject to transients. 1983 operation. (During initial plant startup phase.) See Grand Gulf (M/18/81). The cause of the isola- AllWR solid state logic Mode 4, Cold During an instrument surveillance on the tion was a tip breaking Grand Gulf isolation h>gic for shutdown croling,Ihe off a minitest clip eliminates need for test 83-193 Shutdown. outtmard sucthm valve (1008) closed, jumpers. Surveittance is used for jumpermg. eg Decemler isolatingImth hops of the SDC system. automated to reduce chance of 27,1983 The system was returned to service in 49 operator error. g x-y mmutes. n,
>m
U WMW I Cn
~
- o Table 190C.1-2 N
a 5,y DECAY HEAT REMOVAL PRECURSORS (Continued) $% l EVENT CATEGORY: 1.OSSES OR DEt;MADATION OF RilRS DOE TO IA)SS OF C(M)lANT FRO 41 REALTOR c., VESSE "O APPL.ICAHLE AHWR l EATURE 5" Pl. ANT INITIAL P1 ANT REPORTED CAUSE 3 CONDITIONS EVENT DESCRIITION ~
!.ER/DATE The cause of the trip AllWR see Susquchanna I Mode 5,0% Power. During the Unit 1 - Unit 2 tie-in outage, was a failed breaker. (2/16/83).
Susquehanna one of the RPS *B* breakers tripped, clos-1 HF172 ing SDC inimard and outboard isolation . December valves. Reactor coolant recirculati<m was 30,1983 established through the fuel pool cooling l system. j Personnel error in not AllWR procedures will(learly Received a kiw RPV water level signal placing level specify required maintenance Ilatch 2 Mode 4 Cold while valving out a RPV level indicator. steps and precauchms to Shutdown. transmester in bypass September This resulted in a scram signal and tefore valving out preclude inadvertent SIX: 19,1986 isolation of SDC. SDC was restored in isolation. detector. 10 minutes. Surveillance procedure AllWR solid state logic does Mode 4, Cold lost SDC for 1.5 hours due to inadvertent required removal of not require the uw of jumpers Ilatch 2 RilR suction valve isolatkm during a mstrument links , to complete circuit k.gic dccks. September Shutdown. surveillance test. mstead of jumpermg 21,1986 them out. When links were opened, a fillR valve isolateon signal was initiated. inadequate procedure See Susquehanna I (2/It,/M). Mode 4, Cold While transferring RPS power to an for transferrmg gmwer Perry 1 alternate bus to complete RPS MG set October 24, Shutdown. maintenance, a voltage transient occurred between buses. 1986 which resulted in isolation of SDC. Personnelerror. See Susquehanna I (2/16/H1). SDC valve was inadvertently chised when River Bend 1 Mode 4, Cold technician accidentlyy, rounded a porihm October 28, Shutdown. of the valve controf circuitry during a 1986 surveillance test. The ground caused a bk>wn control circuit fuse which resulted in a valve cksure signal. IE 9 sh W
' l
i cos' l Table 190C.1-2 gg , i 5.$ DECAY HEAT REMOVAL PRECURSORS (Continued) 5%
! EVENT CATEGORY: lA)SSES OR DEGRAI)ATION OF RilRS DUE TO IDSS OF COOtANT FROM REA(TOR VFSSEE, ca. !
T ; En PtANT INITIAL. PLA!R REPOR1ED CAUSE APPLICARLE ANWR FEATURE - 3 CONDITIONS EVENT DESCRifT10N ~ IER/DATE See Susquehanna I (2/16/83). f SDC isolated due to kiss of power to RPS W>ltage fluctuation due Perry 1 Coki Shutdown. bus. RPS was being powered by alternate to startmg ame <4 the plant's circulatitm
. power single MG set was in mamtenance. water pumps caused electrical protettion devices (EPAs) to trip !
resultmg m kiss (4 power to the RPS. The tweaker controller See Ilatch 2 (9/19/H6). Mode 4, Cold While performing a reactor coola it system for the high pressure Clinton 1 hydnistatic leak test. An isolation of January 22, Shutdown. SDC occurred due to high system pressure. - interkick RilR valve was 1987 racked out prior to the
~ test to prevent valve chisure. Folkmingihe l test, the trip functum '
was not reset prnw to rackingin the tweaker. When the tweaker was racked in 'i the valve chised due to the kicked.ie high pressure sigal , r b =e 78 0 >3 , e a
..._.m._._._ ___ . _ . _ . _ _ _ . _ _ _ __ _ _ . _ _ _ --*
, .- . _ - . . _ - . - - . . - - - . - . . - - . - .- _ .. - - - - . _ .~. -. -- - - - - . - .-. -. .._
tn % i Table 190C.1-2_ gg [
. DECAY HEAT REMOVAL PRECURSORS (Continued) 5.$
! EVENT CATEGORY: iA)SSES OR DEGRADATION OF RifRS DUE TO IDSS OF COOL. ANT FROM REACTOR VESSEL, c.
*C,_
PLANT INITIAL PLANT EVENT DESCRitTION REIM)RTED CAUSE APPLICAltl.E AHWR FEAlURE g LER/DA'lE CONDITIONS ~ Maintenance procedure See Susquchanna I (2/16/83). Mode 5, Refueling. Isolation of SDC occurred during main-Peach tenance on emergency bus relays. called for pulling Hottom 2 fuses prior to replace-March 28, ment of certain relay 1987 coils. When one ofIhe required fuses was pulled, the high pecu sure RilR interfock coil was de-energized. This resuked in isolatk>n ; of SDC. The neutral wire for AllWR 54dil state is less t WNP-2 Mode 5, Refueling. SDC isolated when an isolation control several rclays, susceptible to this ty;c 4 i relay for a non SDC function was de- including the SDC failure. Maintenance hypau April 21, energized for maintenance. does not require the lifimg of 1987 relay,were all connected together. leads. Liftingihe neutral 'o one relay caused a loss of power to all relays with a common neutral. SDC loop was only par- See llatch 2 (9/19/8t.). Mode 3,llot While placinst a SDC loop in service, RPV Itatch 1 level dropped from 62 to 3 inches. tially full prior to April 22, Shutdown. place 3 in service. 1987 RPS MG set output See Susquehanna I (2/16/83). Mode 5, Refueling. SDC isolated when power was lost to the breaker madvertently llatch 1 RPS bus. June 7,1987 tripped. Procedure did not See Susquehanna I (2/16/N3). , Mode 4, Cold SDC isolated when power was removed from , Perry 1 recgnire the impact on
. July 4,1987 Shutdown. the RPS bus for a surveillance test. SDL of removing power from the RPS bus.
The cause of the loss See Susquchanna I (2/16/81). Peach Mode 4, Cold SDC isolation occurred when the normal of offsite power was Bottom 2,3 Shutdown. offsire power supply was lost and a ,, transfer to an alternate source temp- not included in the
- Au report. ,[
f 19 bust 16, crarily de-energized electrical buses. - s'
>l l
i
~ - - - _ _ _ - _ _ _ _ _ _ _ _ _
4 g ; ;f g- -[ Tatzte 190C.1-2 i DECAY HEAT REMOVAL PRECURSORS (Continued) j 9 EVENT CATEGORY: ti)SSES OR DEGRADATION OF RilRS DUE TO II)SS OF COOf ANT FROM REA(TOR VESSEL 2 n o rr iNmAt,nar EVENT DESCRifTRON REPORTED CAUSE APPLICAl!LE ABWR FEATURE [ :i LER/DNIE CONDmONS ~ See Suu .I SDC isolated during maintenance on SDC isolation coil Peach Mode 4 Cold electric circuits. inadvertently - and WNbchanna 2(4/21/8 ). 1 2/16/83) Shutdown. Bottom 2 de-energized during August 28, mamtenance. - 1951 -
+
A spurious high RilR ' ABWR solid state logic Susquehanna : Mode 4, Cold While transferr' SDC from the 'A' to Ihe Ihm signal caused the requires 2-out-of-4 signal to 1 Segwember - Shutdown. .* C' RilR pump,. ' isolated. actuate a safety functmn. SDC isolation. 13,l'987 toss of power to a MCC. See Susquehanna 1 g2/16/83). Peach Mode 4 Cold SDCisolated7or 15 minutes. -! Bottom 2 ~ Shutdow,n. September 16,1987-SDC isolat,ed during a pressure transmitter Personnel error in See Ilatch 2 (9/19/84 ). Perry 1 Mode 4, Cold allowing pressure September Shutdown. response time test. ' signal from test t 29,1987 instrument to exceed SDC high pressure , i-isolation set point. SDC isolated on loss of power to 480V bus Cause for loss of power See Susquchanna I (2/16/83). Pilgrim - Mode 5, Refueling. - not reported.
.. October 6, .. ' which supplies power to the isolation
- t. 1987 valve.
SDC isolated during maintenance on primary Anincorrect lead was See WNP.2 (4/21/87). Pilgrim . Mode 4 Cold Efted which generated October 15, Shutdown. containment isolation system. a false high reactor < 1987 pressure signal. I' . SDC isolated when R PS power supply was Mcmentary kiss of RPS ' See Susquchanna I (2/16/83) l Susquehanna Mode 5, Refueling. power.
- j. November 1, transferred between alternate sources. -
" 1987 A temporary hiss of ' See Susquchann.s I (2/16/83). Mode 5, Refueling. SDC isolated during maintenance on power Grand Gulf power occurred when November buses. tius was re-energized . . l 30,1987. following maintenance. *g -
- . g- pS 'I
- O- 7 3l E
>b i
i l . .I l-
i Table 190C.1-2 N m tg - DECAY HEAT REMOVAL PRECURSORS (Continued) R$ l~ ".,% EVENT CATEGORY: IX)SSES OR DEGRADATION OF RilRS DUE TO IA)SS OF COOLANT FROM REAGOR VESSEL, c "U PLANT INITIAL PLANT EVENT DESCRitTION REPORTED CAUSE APPLICAllt.E AHWR FEATURE E LER/DNIE CONDIDONS 3
~
See Itatch 2 (9/19/N6), j SDCisolated due to initiation of reactor Technician caused a Peach Mode 4, Cold scram signalIo be i BotIom 2 Shutdown. seram signal. r generated during an December 6, NI'WS kgic pressure ; 1987 switch calitwation. SDC isolated during maintenance on RPV Technician caused a See flatch 2 (9/19/86). Nine Mile Mode 4, Cold pressure surge in the Shutdown. level sensor, - Point 2. mstrument ime which February 1, resuhed in a high RilR , 1988 system pressure signal to be generated. SDC isolation signal generated during Personnel error during See Ilatch 2 (9/19/Hr ). , Pilgrim Mode 4, Cold maintenance. Shutdown. maintenance on emergency parameter Fet>ruary 2, 1988 mformation computer. SDC isolated during refueling outage. Maintenance personnel See Grand Gulf (5/23/M1) and WNP-2 ' Mode 4, Cold pulled wrong :,et of Susquchanna 1 (2/16/RT) May 30,1988 . Shutdown. tuses. SDC isolated during maintenance on PCIS Inad uate See Ilatch 2 (9/19/M3) Peach Mexle 4, Cold SDC isolati< m procedure. kigic
. Bottom 2 Shutdown. hgic circuitry.
should have been July 29,1988 blocked as part of mamtenance task. Technician See Susquehanna I (2/16/83). Mode 4, Cold SDC isolated during modification work on a Nine Mile inadvertently grounded Point 2 Shutdown. RPS cabmet. the RPS 24 Vdc gewer October 25, supply. 1988 Loss of RPS power See Susquehanna I (2/16/M3). Mode 5, McIucliag. SDC isolated following a hiss of two FitzPatrick L offsite power lines and a 120 Vac UPS. caused SDC isolation. October 31, . 1988
=e ;
0 Ih
> wi b
I J r> mtg
- s :
!a Table 190C.1-2 6 a
E-DECAY HEAT REMOVAL PRECURSORS (Continued) 1 , 1.OSSES OR DEGRADATION OF Rif RS DUE TO I.OSS OF COOLANT FROM REALTOR VESSEL,
' EVENT CATEGORY: 3 INITIAL PLANT REPOR1ED CAUSE APPL.ICAh!.E AMWR FEATURE PIA NT EVENT DESCRil'f10N LER/DATE CONDTTIONS !
Technician caused a See Ilatch 2 (9/19/W.). Peach Mode 4, Coki SDC isolated due to initiation of reactor scram signal to te Shutdown. scram signal. generated during an Hottom 2 December 6, ATWS hype pressure 1987 switch caht> ration. Technician caused a See Ilatch 2 (9/19/W.). ; Mode 4, Cold SDCisolated during maintenance on RPV Nine Mile level sensor. pressure surge in the Point 2 Shutdown. mstrument hne which February 1, resulted in a high RilR , 1988 system pressure signal i to be generated. l SDC isolation signal generated during Personnel error during See Ilatch 2 (9/19/R.). ; Pil im Mode 4, Cold mamtenance. mamtenance on emergency parameter Fe ruary 2, Shutdown. mformation computer. 1988 SDC isolated during refueling outage. Maintenance personnel See tirand(iuff 5 8 ) and ; WNP-2 Mode 4, Cold ed wrong set of Susquehanna 1 ( _ May 30,1988 Shutdown. : SDC isolated during maintenance on PCIS Inadequate procedure. See flatch 2 (9/19/M3). Peach Mode 4, Cold SDC isolation logic Bottom 2 Shutdown. logic circuitry. should have been July 29,1988 bhicked as part of t mamtenance tast Technician See Susquehanna 1(2/16/83). Mode 4, Coki SDC isolated during modification work on a Nine Mile inadvertently grounded Point 2 Shutdown. RPS cabinet. the RPS 24 Vdc power October 25, supply. 1988 . SDC isolated folh> wing a loss of two lossof RPS See Suutuchanna I (2/I6/83L FitzPatrick Mode 5 Refueling. caused SDC powersolatiim. October 31, offsite power lines and a 120 Vac UPS. 1988 t . b oe. o 7h E, !
t t w [ g Table 190C.1 i- 5.$ DECAY HEAT REMOVAL PRECURSORS (Continued) $% [ c. EVENT CATEGORY: LOSSES OR DEGRADATION OF RilRS DUE TO LOSS OF COOLANT FROM REACTOR VESSEL "U
~
APPLICAHLE ABWR FEATURE in PLANT INITIAL PLANT REPORTED CAUSE = CONDfTIONS EVENT DESCRirrlON ~
. LER/DA'IE See Susquehanna I (2/16/83).
Momentary loss of Mode 5, Refueling. SDC pump stopped when SDC isolation valve t
. FitzPatrick left its open positson. tower to RPS caused -t November 9, SDC ealve o start !
1988 closing. Interlock of
- SDC isolation valve and ,
pump caused control breaker to open. l
- SDC isolated when Div.1 ESF power was loss of power cause not See Suwuchanna 1 (2/16/83).
Mode 4, Cold l
~ Fermi'2 reported. .;
January 10, - . Shutdown. lost. 1989
'SDC isolated during testing of RCIC kgic. While attemptin;t to See Grand Gulf (5/23/81) and Clinton - Mode 5, Refueling. jumper out the $DC Susquehana'a I (e/I( /M3).
January 10, isolation signal, a 1989 technician - -l inadvertently grounded - the RPV kiw level circuit. ~ lyes caused a fuse io blow and SDC to l isolate. t i SDC isolated during a surveillance test of Test procedure See liatch 2 (9/19/W ). Nine Mile Mode 4, Cold specified the wrong Shutdown. the reactor building high temperature <
' Point . isolatiors signal. isolation si actuated. gnalbe g January 22, .
1989 Procederal error. See liarch 2 (9/19/N6) and ' During performance of a surveillance test, Ilatch 2 (9/21/H6). Ilope Creek - . Mode 4, Cold . ' the SDC iniccfion valve closed resuking lxads were lifted to e March 1, Shutdown. alhiw completion of ! in a loss of SDC. RilR k>gic test without 1989 valve actuations. The lead for the RilR i
. injection valve was inadvertently left off the list of leads to be -i lifted.
ti
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- i.
F
i 4 Cn> EIg , C Table 190C.1-2 i
! DECAY HEAT REMOVAL PRECURSORS (Continued)
EVENT CNIEGORW l.OSSES OR DEGRADATION OF RilRS DOE TO !A)SS OF COOT. ANT2llROM h)' APPL.ICAHLE AHWR l' EAT 14 E $ j PtANT - ' INITIAL PIANT EVENT DESCRIFTION REPOR~IED CAUSE ~ LER/DATE CONDITIONS ! Maintenance personnel See Susquehanna I (2/16/83).
' Mode 5, Refueling. SDC cooling, isolated when 120 Vae de-energised krie !
River Bend divisional higac was de-energiicd. March 25, power to comp!cte work 1989 on the reactor plant sampimg system. , SDC isolated due to loss of RI"i power. A jumper fell off dur- See Ilatch 2 (9/21/W and River Bend Mode 5, Refueling. ing installation caus- Susquehanna 1 (2 f If ./83). March 29, ing a ground of RPS 1989 power and a bkmn fuse ' m the RPS power supply i Technician lifted DC See IIarch 2 (9/21/W ). Mode 4, Cold RIIR pump tripped during surveillance test power k:ad for RCIC Grand Gulf of RCIC trip shrottle valve. April 26, Shutdown. throttle valve but did 1989 not realire that the RIII} path trip logie waspump ~no suctism also on the circuit. When the lead was lifted,d.the trippe RilR pump 4 I cad became discon- See Ilatch 2 (9/21/W,). Mode 5, Refueling. SDC isolated during a surveillance test of nected during test and River Ber.d manual scram function. April 27, grounded out she RIIR 1989 high pressure interkxk circuit. This caused the isolation valve to close. f5
>h 9
u 1
Table 19d0.1-2 hm> DECAY HEAT REMOVAL PRECURSORS (Continued) 5.$ EVENT CATEGORY: LOSSES OR DEGRADATION OF RilRS DUETO LOSS OF COOL. ANT FROM REACTOR VESSFl. c. INITI AL PLANT 2 PLANT REPORHD CAUSE APPLICAHl1 AHWR FEATURE :n CONDITIONS EVENT DESCRilTION :3 LER/DATE " A reactor cooldown was in progress Ruptured flange gasket See Peach llottom 3 (1/8/71). Brunswick 1 Mode 3 llot Shut- on RIIRSW kmp IA AllWR uses analog transmit-774M5 down. flant cool- following a scram. y'ith reactor water heat exchanger outlet ters instead of pressure switthes July 28,1971 down in progress. temperature at 372 F, preparations were for actuation carsuits, so ahis commenced for placmg RIIRS hop 'A' in valve, causing spray-Te rature at induced electrical type of failure would not oc(ur 372 7 shutdown cooling. RilRS Imoster pumps were in the AllWR. started in conjunction with the IB nuclear damage. SW pump. A gasket ruptured on the RllR service water system as it was being placed in shutdown cooling. Water was observed spraying from the overhead of the 20 ft. elevaten m the reactor building. He ly k>op of RilRS was placed in service at 325 E When attempting to place the RllRS 'lB' k>op in s'autdown coolinF ti was found that the mtmard shutdown cooling suction valve would not open, due to a false signal from a pressure switch. After a reactor shutdown, while establish- Electromechanical brake See Peach Botsom 3 (1/8/77). Brunswick 2 Mode 3 Ilot Shut- on valve operator fail- The current levelof the ABWR 784)36 down. flant cool- ing shutdown cooling the shutdown cooling design does not generally outtmard suction valv,e (IUJ8) would not ed, causing valve to April 3,1978 down in progress. bind r.nd the motor address detail component feat-open remotely. Valve was opened manually ures. Ilot it is expected th.it as and reactor placed in cold sliutdown. operator to draw exces-save current when is the case for operating plants, cr.ergized. MOVs will include handwherls to mitigate events such as this. Cause for valve failure See Peach thittom 3 (1/8/71). Brunswick 2 Mode 34 flot Shut- During normal shutdown RilRS shutdown and cooldown, cooling valve located inside not reported. Person-784152 down.11 ant cool- net air lock inner door June 3,1978 down in pnyress. the containment (ITm) would mit open from would mit open due to the ctmtrol room. This valve must be sticLy gaskets, caused opened before the reach >r can be placed in cold shutdown. Entry into the drywell via by large amount of the personnel air kick was unsuccessful. compressive force Entry into the drywell was made through apphed to g,askets by the CR0 hatch and the RllRS valve was strongback mstalled 2 manually opened. days earlier for test Stamchack removed on day devent. y fe 13y
>w
\ l D
- n W k Table 190C.1-2 a
i ! DECAY HEAT REMOVAL PRECURSORS (Continued) [ EVENT CATEGORY: 1 OSSES OR DEGRADATION OF Rif RS DUE TO IA)SS OF COOI. ANT - INITIAL PLANT REPORTED CAIJSE APPLICAllLE AHWR FEARJRE $ l PLANT EVENT DESCRIITION LER/DNIE CONDITIONS See Brunswid I (7/28/77). Reactor steam dome high pressure switch Sticking microswitrh Brunswick 2 Mode 3, llot Shut- would rus reset and would mg allow RilRS caused'mstrument feil-784174 down. ure. valve (11X)H) to open for shutdown coohng November at a reactor pressure of 102 psig. 12,1978 Thorour,h investigation See Pea <h flottom 3 (I/8/71). Following a reactor shutdown, while revealed no cause for Brunswick 2 Mode 3 flot Shut- attempting i ace RilRS shutdown cooling down. flant cool- failed motor windings. 814119 down in progress. into serv cc i RilR sup inimard February 14, isolation valve (HXN) wou not open 1981 electricall . Burned motor windings prevente the valve motor from opening the valve. Valve was manually opened and RIIRS shutdown cooling placed in service. Cold shutdown reached 8 hours after opening valve. lamse fastener on one See Peach Bottom 3(t/8/71). face RI1RS shutdown Brunswick 2 Mode 3 Ifot Shut- While attempting to klIRS shutdown of the overcurrent 814J70 down. flant cool- cooling into service, inboard isolation valve devices in the vahe down in progress. coolin sup motor breaker, result-July 18,1981 RXN wou not open on a remote s' . mg m an overcurrent alve was manually opened, RilRS s tdown condition on two of the cooli ig placed in service and cold shut- m(sor phases, trippint' dowi achieved in 8 hours, the breaker. Fkrw switch had been See 11runswhk I (7/28/77). When liningup for shutdown cooling opera- isolated io perform LaSalle 1 Mode 3,llogShut- tion, the RitR shutdown cmling isolation 82-034 down at 225 F. . n due to an iso- calibration check; failed June 5,1982 (During initial valve (Run) would not ogiiow switch. maintenance tech lated RilR pump suction to unisolate instrument plant startup phase.) after test. Relaxing torque switch sce rea<h th stom 3(1/8/71). During startup of shutdown cooling for a problem, whuh caused Monticello Mode 3 Ilot Shut- refochng outage, ahe RIIRS outtmard shut-down. flant cool- continuous (fose signal 824Xn down cooling isolation vahr (MO-2010) to jam the valve gate September 2, down in progress. motor failed. ento the seat. 1982 Y: b o. I?
>c 5
Table 190C.1-2 N 5,CU j DECAY HEAT REMOVAL PRECURSORS (Continued) $ ~ EVENT CATEGORW LOSSES OR DEGRADATION OF RilRS DUE TO l.055 OF COOLANT FROM REACTOR VESSEL $% c "O PLANT P:tTIAL PLANT EVENT DESCRIFTION REPORTED CAUSE APPL.lCAHLE ABWR FEATURE E LER/DATE !.DNDIT10NS :2
' Mode 3,llot Shut. The RilR shutdown cooling suction inboard During the last operat- See LaSalle 1(6/11/82).
LaSalle 1 ing perim!,ihe valve down. isolation valve (RKN) could rms be opened 83-142 was manually seated to AllWR has 3 RilR systems. November 4, either by ahe motor operator or manually. One of the Iwo rema ning SDC The unit was shutting down for planned stop leakage. With the 1983 plant at lower tempera- loops would be availalile to mamtenance. bring the plant to cold ture, the valve would not open. Failure was shutdown. attributed Io high differential tempera-tures resultmg an thermal contraction and pinchingof the disc wedge mto the valve seat.
'B' phase winding of See LaSalle ex y and Mode 3 hot shut- While cooling down to cold shutdown Browns Ferry down. l #tant cool- following a manual scram, the inboard RilR motor operator had Peach Ikutom 3 (I/1 (11/4'8/79).
I 844)12 shutdown cooling isolation valve failed. Apparentlyahe February 14, dovm to cold shut- gate had stuck in the 1984 down in progress. (FCV-t-74-78) Iaded to open, making it impossib!c to achieve cold shutdown using valve seat and the normal shutdown cooling. An ALERT was motor could not gener-declared, and the plant brought to cold ate enough tor shut h through continued normal cooIJown open the valve.que Fur- to to the main condenser, and time use of ther investigation control rod drive pumps and RWCUS as revealed that the alternate inventory adilition and heat 'close* torque switch removal systems. Since the stuck shut setting was set higher suction valve was inside gontainment, a than the manufacturer's containment entry was necessary to open recommended value the valve manually, it took approxiraately (2.5 vice 2.0). This five hours to de-inert the drywell eo over-tightemng prob-and amWher fours hours to ably contritmted to the permit entry,k open the stuc valve anl establish stuck valve. after which the ALERT shutdown cooling, was cancelled. Ad ditional alternate means of heat removal were available. o= b 75 9 .h W
l l Cn> N Table 190C.1-2 Eg l E 5-Y m
! DECAY HEAT REMOVAL PRECURSORS (Continteed)
{ EVENT CATEGORY: LOSSES OR DEGRADATION OF RilRS DUE TO I OSS OF COOLANT FROM REACTOR 2 Pl. ANT INITIAL PLANT REPORTED CAUSE APPLICAliLE AHWR FEATURE y CONDITIONS EVENT DESCRIITION ~ LER/DATE An inadvertent heatup and pressurization Valve lineup error. See LaSalic 1 (f./II/82). Dresden 3 Mode 4 Cold Shut- Post maintenance AllWR does mit have external down. kIIRSjn op- was caused by a valve lineup error during recirc pumps or valves May,1978 containment leak rate testing. Atmut 18 testingof a recirc cration at 160 F. pump MG set required a Rextor internal pumps (RIPS) hours after reaching test pressure, reac- supply recuc it.w so this event for vessel flange temperature wgs discov- recuc pump test run. The motors were un- could n it occur in ihe ABWR. cred to be at approximately 300 F and increasing. One kio . of shutdown cooling coupled from the recirc pumps for the test. was in service rectg g a temperature of ne motors would nd approximately 160 . The RIIRS heat start treausepumpf exchanger shell temperature and vessel va!ve interkicks gave a flange temperature shouki have been trip signal to the pump equal. Investigation revealed that the motor smce the suction recirc pumps were of'and recare kop and discharge vahrs suction and discharge valves were open. This lineup resulted in the majority of were closed. Conse-RIIRS flow circulating through the recirc quently, maintenance kop and not the core. The vessel heatup personnel opened the valves to perform the and pressurization caused a temperature test. This permitted and pressure increase in the drywell. The shutdown cooling flow computer program used to calculate the o leypass ahe core via containment fe'ak rate was using shutdown cooling temperature to indicate conditions the recirc hmp,caus-inside the vessel. %e computer misin- ing the inadvertent terpreted vessel conditions and concluded heatup and pressur-there was a large inleakage condition. ization. Faulty auxiliary con- AUWR has three HilR husgn, Mode 4 Cold Shut- With the reactor in the shutdown mode failure of huip tr with loop A-llatch 1 durirg testing, ahe shutdown cooling Iact block. He nor-80-057 down. kilRS in suction valve for the *B' RilRS pump mally chned relay in maintenance couhl be miti-May 25,1980 operasion. amtact was found stuck gated ley using k=>p C . The (lumb) failed to open. The 'B pump was in the open position. RWCt1 system, ITC, and main declared inoperable. Since the *N divi- camdenser can aho lic used for sion of RilRS was out for maintenance, both DilR under ccriain plant pumps in the 'B' division were required to conditions. be operable. U
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O Cry N Table 190C.1-2 y [ 5.$
~
DECAY HEAT REMOVAL PRECURSORS (Continued) $' c. EVENT CATEGORY: LOSSES OR DEGRADATION OF MilRS DUE TO LOSS OF COOLANT "J FROM APPLICAllLE ARWR FEAWRE EI PLANT INITIAL PLANT EVENT DESCRIFrlON REPORTED CAUSE :3 CONDfTIONS ~ LER/DA'IE Procedures were inade- See LaSalle I (6/lI/82). Mode 4 Cokt Shut- Shortly after achieving cold shutdown, quate to address temp-Dresden 3 RWCU system down. AllRS system with recire crature stratificatkm 804)47 isolated, andpumns wit'h oneoff, kop of shutdown in reactor vessel with December in operation. cooling system in operation,it was noted recire pumps off and 21,1980 that reactor vessel pressure was 150 pug low shutdown cooling whiJp recirc kop tempcrature was , flow. Analysisin 15vF. Primary containment integnty NSAC-27 also indicated l specTecations had been violated and txxh a lower than normal j the llPCI and isolation condenser systems reactor vessel water j were out of service. A second shutdown level contributed to coo!ing loop was placed in operation to l the vent by precludmg ' achieve greater vessel flow, and to core natural chmmate temperature stratificaton. circulathm. When the muung occurred, recirc kop"F. temperature temporarily exceeded 212 Pressure and temperatures were reduced when the second loop was placed into service. The reactor pressure was above 90 psig for about 1-1/4 hours. The valve stem packing See Peas.h Botsom 3(1/8/77).
. Mode 3 hot shut- During preparation for placing shutdown leakage from a nearby Dresden 2 cooling in service, a shutdoes croling 83 052- down. flant cool- valve simrted out the down in progress. return valve (MO-5A) failed to open. valve operator motor.
June 21,1983 I The 'B' heat exchanger Placement of RI1RS Mode 4 CokiShut- During' shutdown cooling operation on RIIRS valve breaker was temperature detettors LaSalle 1 down. kilRSloop kmp *H , the *B* heat exchanger discharge accurately reflect RCS tem-834FM valve (RK138) failed to open. Most or all defective. The
*B* in shutdown measured 'B' heat peraturcsif proper flow rates August 24, RilR llow was allowed to bypass the heat exist. See Peach thwtom 3 1983 cooling operation. exchanger temperatures exchanger, and the heat exchanect outlet were conciuded to be (I/N/?#) for discussion of temprature increased from 137'F to inaccurate due to component quality and 186 F over a three l'our perkxt. The - temperature element - redundancy of DilR capability.
inlet temperatures sim3arly inct ased. locathm. After three hours of attempts to open the shut valve, the B' RilR kop was secured ti nS b 78 o >D l
. . . . - - - - . - . - ~ . . - . - .- _ - , - ~ - - . - - - . . . -~ . .- - -_ ~ -.
t (A g > j
.N Table %QC.1-2 .g 5.g $ !
DECAY HEAT REMOVAL PRECURSORS (Continued)
~[ .
EVENT CATEGORY: ti)SSES OR DEGRADATION OF RHRS DUE TO LA)SS OF C(MMANT FROM REACTOR c. VESSEL I
"C f PLANT INITIAL FtANT REPORTED CAUSE AFFLICARLE ABWR FEARJRE Ei' CONDtT10NS EVENT DESCRIFnON E LER/DATE and the 'A' loop started. 'B' kxip temp- I erature indicatum had not been accurate because of low flow conditions and temp- .
crature element placement,so actual reactor coolant iemperature was higher.
'A' loop heat exchanger inlet temperature !
reached 20f'F (violating cold shut &mn limits). The RFV head drain gicated a maxirnum temperature of 220 F. . The 'B' RilR heat exchanger outlet valve it is believed that the See Peach Bottiwn 3 (1/8/71). LaSalle 1 - Mode 4, Cold Shut. valve became i uyerable 83-147 down. (It03B) failed to open either by the moser in the chised petum i Novernber operator or manually. He *A* kxip of due to water trapped m 12,1983 RHRS was operable to control decay heat, '; but one of the two RHR SW pumps cooling the Ixxty/lionnet cavity > the *A* loop was inoperable. above the disc / seat, tmg seals. He cavity h not have a mech-anism towr.t estrapped water. , Ruptured sealin 1C ABWR technical specifications . Mode 4 Cold Shut- While in the shutdown cooling mode, the IC . Hatch 1 ' RHRS pump. will be based on risk associated 79-050 down. kHRS in RilRS pump was found to haw: an excessive with shut &mn nuxle and decay operation on loop leak at the mechanical scal. He r imp was heat loadt Under certain July 25,1979 removed from service to repair t' seat. *
*A*. conditions to minimite risk, at Both RHR pumps in the 'B' Rilks kx>p were least two divisions of RIIR or out of service for hanger repairs. De IC multiple ahernate mes!wxis of RHRS pump was return to the shutdown D1IR willim required to be cooling mode, the IC RIIRS pump was found operable.
to have an excessive leak at the mech-anical seat. The pump was removed from - service to repais the seal. %c IC RIIRS pump was returned Io service on July 27, 1 1979. l s ' O 75 I.m a iD
+ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ -
l-
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@ . t Table 19QC.1-2 is ;
i m-i -a DECAY HEAT REMOVAL PRECURSORS (Continued) m E EVENT CNIEGORY: IDSSES OR DEGRADATION OF RHRS DUE TO LOSS OF COOLANT FItOM REACTOR VESSEI, g - [ 2
'b PLANT INITIAL PLANT REPORTED CAUSE APPLICABLE AhWR FEATURE CONDITIONS EVENf DESCRIPTION
- LER/DATE i design changes, contud Personnel error in The three ABWR'RilR '
Hatch 1 Mode 4, Cold - ' power While cables performing'he RHRS outboard isola- making the mexlifica- systems are independent of . 79-051 Shutdown. RHRS in to t tions to ahe operalde ' cach ether. No common
- operation.
' July 26,1979
. cut with th(e valve in the <tum ^ ion. RHRS valve isolatum instead ofH108) the valve were components, disconnected exist outside the RPV, which would impactand more The inboard isolation va 19) had . than one RilR division.
raiile to a modifica- inoperable valve. ;
. been made i L
! : tions to be a' to it. One of Ihese . . valves is requered for isolation of both ! divisionsof the RHRS. ABWR has three disisions of f
. In both events, mainte.
. Brunswick'2 = Mode 4 Cold Shut- On December 7, RHRSW was secured in the nasce was sus completed RIIR. In this case, loop't" f down. kCgtempera- 'A' loop to repeer a leak on a l' pipe to coukt have leen used. See !
.80-107 ' . the RHRSW radiation monitor. Shutdown in expected time. In -
December 8, ture at 165 F. ahe first everd loop B laSalle 1 (6/11/82) for RHRS in o cooh'ngtwas lined up to the *A* knop with discussion of AHWR .i 1980 was available but not 80-112 on 'A' loop.peration an RHMS pump running ~ (to recerc the vessel insed, due to potential procedures. December 9, water volume williout heat removal). Both leaks on a nxmi cooler reactor recire pennps were secured. 45 ' t 1980 minutes were estiniated to complete SW and the requirement for repas'ts. However, repairs were completed manual valve operation in 3 hours. RCS. temperature at ihis tune due to inoperative i pumps sectum valve
. ateroached 212"F with a local maximum of motors. In the second t
, 2WF. The reactor head vents were open [ with ainiospheric pressure in the vessel. . . cwnt, securing RHRS ! SW was restored and shutdown cooling was ' pumps while mainten- i initia ed. Prinsary coolant temperature ance was in progress ' > decreased to nornial levels appromimately - caused loss of repre- , 30 minutes after repairs were complete. sentative temperature , Shutdown cooling was not lined up in kop indications due to km ,
'B' because it was expected that loop *A* flow and lack of sessel would be back iyrviceprior to recirculation. Control ;
approachi, 212 F,and neca sse there room operators did not ! were p . e leaks on a nuvet cm ler and recogmic the he.t up inoperative 'B' kop pump s4 acta valve rate. Failure io plan s motors. and promptly implement contingency plans for the p>ssdalwy of unex- [ On the next day, the conventional and
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- ._ . . , _ ~_ ,
cmy ' N Table 190C.1-2 Eg-c- i a m E DECAY HEAT REMOVAL PRECURSORS (Continued) 5 i EVENT CATEGORY: IA)SSES OR DEGRADATION OF RHRS IMIE TO IDSS (W COOLANT FROM REACTOR VESSEL, e PLANT INITIAL PIANT REPORTED CAUSE AFFLICAhlE AMWR FEATURE . CONDf110NS EVENT DESCRIFUON ~ LER/DATE , nuclear SW systems were secured to repair pected delays in mainte- r the 2A conventional SW pump discharge nance also contributed i check valve. RCS temperatare was ini- ta the problem. , 120 F. Approximately 2 hours [ tially later, <RHRS pumps were secured to reduce
' coolant heat mput from the mps.
A omimately 4-1 hours er wisen the s eni was restor ty average RCS tem- t perature was oveg2 2 F with a kxal
. naanimum of 256 F. Again, vessel head ;
vents were open during the event. With the unit shutdown for maintenance, IAL of timely cmwdina- See Brunswkk 2 (12/8/N0). Peach. Mode 4 CokiShut- shutdown cooling was secured ao permit tion hetween operations Bottons 2 - down. kilRS in op- and maintenance person-eration. maintenance of a shutdown cooling suctimi , 8I-031 ' ion valve. PCS temperature cucceded ncL ; May 18,1981 212 before cooling was reestablished. ; f Temperature exceeded 212"F for atmut 2,-1/2 hours. Primary containment integ , . rity,requacments were not met during this
. period.
The "A* loop flow indicators for tweh R11RS Sliding links were See LaSalle I (6/9/M2 and
' flatch 2 82-030
' Mode RIIRS5m , Refueling.
operation and Ri1RSW systems were noticed so be inop- opened by maintenance 6/11/82). personnel while perform- I Aptd' 20, on loop *A . etable. Invesaisation revealed that the mg a wiring change. 1982 indicators and controller for the RilRSW , heat exchanger pressure control valve were . deenergized. The "A* loop RilRS and 'A' ! RilRSWS were declared inoperable and fuel ; movement was suspended. ! t O. IE
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t. l !
1 m Table 150C.1-2 5.g i DECAY ii4 EAT REMOVAL PRECURSORS (Continued) $
~'
EVENT CATEGORY: thSSES OR DEGRADATION OF RHRS IMIE TO I.OSS OF COOI. ANT FROM REALTOR ca. . VESSE
*7
~
m INITIAL PLANT REFORTED CAUSE APPLICAHLE ABWR FEATURE :s - PLANT EVENT DESCRINION ~ LER/DATE CONDITIONS See lirunswick 2 2/ Nato)and i The spring clips on the l Mode 4, Cold $bw- The RilR and RilRSW ikw 'ndicator for the fuse block energiring Ilatch I (7/25/7 . Hatch 2 'A' in shwdown cooling were in'per- the "A* Ioop RIIR and 82-042 down, with *A* loop 'A' loop was declared inoper-A il 27, of shutdown cooling abic. RHRSW Ikm indicalors abic. %c *B* kep was already inoperable were kmse. I service. for the leak rate testing. Leakinginner head See IMalle 1 (6/9/82 and Browns Ferry Mode 4 Cold ShW- The radiation monitor on the RHRSW dis- gasket en heat ex- 6/11/82). down. kHRS in op- charge line froni IA RHRS heat exchanger cha r, due to kmse I cration on loop 'A . showed an increasing radiation lewl, d in stud 77-003 appronianate 1 hour after being place leak solation a,ioits. due Delay to in January 4, service. He exchanger service water ef- failure to acknowledge 1977 fluent was saanpled and found to be in alarm, and commumca-excess of release limits. The IC RIIRS r was then placed in service, tions misunderstanding heat excha over the actual release approxionate 5 hours after the initial rate occurring. radiation alarm. Excessive differential ABWR procedures to minimite Mode 4 Cold Shus-Duringinspections,the 2B RHRS beat pressure across the marine growth have been - Brtmswick 2 exchanger baffle plate was found to be par- manlified to ensure this type d ~ 80-030 down. 8 HRS in op- haffle plate due o an tial buckled near the bottom where it auumulation of marine event does not occur. A il 12, cration. fitte into the groove of the channel Intermediate RCW system Lep growth shells in the l cover. The plate was 8.5 in off. center, heat exchanger. priwides clean water so sac and welds up each side were pulled loose RilR heat eschanger. Afsn. with'm the waterbox. Appronsmately akernate metimds of Dif R such , FPC 3-10 in. thick accumulation of marine . as the main condenser,d under Browth and RWCU can lie use of 2B heatshells werewaterbox, exchanger found in the and inlet side about certain plant conditions. the same in 2A heat exchanger inlet waterbox, ak h the 2A 6affle plate was not damaged. T buckling created a ser-vice water bypass flow path from the heat - exchanger inlet to outlet bypassing the tubes. N
,e
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~.,. . - .-
l k Table 190C.1-2 g$, E-w g E EVENT CATEGORY: LOSSES OR DEGRADATION OF Rif RS DUE TO LOSS OF COOLANT FROM REACTOR DECAY HEAT REMOVAL PRECURSORS (Continued) Q VES 2 REPORTED CAUSE APPLICABLE ARWR FEATURE y PIANT INITIAL PIANT EVENT DESCRit' TION ~ LER/DATE CONDmONS- See Grunswick 2 (4/12/MI). Failure of plate wekts, During inspection of the iB RllRS heat resuhing from exces-Brunswick 1 Mode 4 Cold Shut. exchanger, d was found that the heat down. kIIRS in op- sive dif ferential pres-81-032 exchanger baffle plate was displaced about sure across the plate. April 19, cration. creatina a direct SW flow path from 9"let Excessive differential ! 1981 in to outlet, bypassing the tubes. reessure attributed to l During repair of the IH heat exchanger, a blockage of the tubes l loss of cooling was experienced immeds- by marme shells accumu-ately following the startmg of a second latingin the heat ex-RHRSW pump on the 1A heat exchanger. Al- changer. The SW chkwi-ternate cooli wasflow established from the with the wssel, nation system had been RHRS system out of service for an through the fue pool coolers and the extended period. CST. Vessel temperature remained below 170 F. The 1A heat exchanger was also found to also have a displaced baffic plate. Same cause as for See Brunswick 2 (4/12/N)). As a resuk of proldems,with Unit 1 RilRS Unit I above. Brunswick 2 Mode 1,76% power. heat exchangers, a special mspection of 81-049 Unit 2 RHR IIXs was conducted at power. May 6,1981 Heat exchanger 2B was dam 7.ividerd and plugged marine shellbuildup The e was found buckled about 3* (it had en re above.)placed in 1980 - see LER f(MJ30The heat exchanger had bkxked and obstructed tubes. IIcat exchanger 2A was undamaged with no divider plaie buckling, but was substantially blocked by shells. A8WR is a single unit design The *A2' pump discharge and failures will not propagate Units 1 & 3, Mode 4 The A2 RilR service water /EECW pump dis- air wat valve failed Browns Ferry charge line air vent vahr faded result- to other plants. If more than - Cold Shutdown. Um,a to seal because of a one ABWit is at a site,unss I/2/3 2, Condition 1,91% ing in the ikxxiing of 'A' RilR$ service ump mom to a depth of a twoken float guide, 81-047 connected syucms i esween water causing the IToat to proximately 6 I p/2 Iect, rendering A1,
/EECW A2,p-August 22, Power, misalign with the seat. units will mit le allowed. In 1981 U
k b IE n >R t
Cnh
$ Table 190C.1-2 g
[ DECAY HEAT REMOVAL PRECURSORS (Continued) 5.f. l EVENT CATEGORY: LOSSES OR DEGRADATION OF RilRS DUE TO IA>SS OF COOLANT FROM REACTOR VESSEL c 3 PIANT INITIAL PIANT REPORTED CAUSE APPLICAHLE AHWR ITATURE m CONDITIONS EVENT DESCRil' TION :s LER/DNIE ~ addition, ECCS divisional and A3 RilRSW/EECW pumpsinoperable. rooms contain water tight doors the *A* RilRS heat exchangers Consequently,became inoperable. (%c such ahat thwxling would be for the 3 umts contained within the roorn and RilRSW/EECW system is common to all only affect one dnism. Ihxis three units.) in onher reactor building rooms are mitigated by raised sills, fhior drains, and operator action in respmse io Ik=xt alarms. Twelve dented tubes AllWR has three independent Mode 4 Cold Shut- RilR heat exchanger 3D leaked reactor cool- RilR knips. %c prob.shihty of Browns Ferry were found in the 'D' 3 down RIIRS in oper- ant into the RilRS service water in excess heat exchanger. One of hising all three h=>ps due to 834XM ation on loop *fr. of Technical Specification limits. The component failures is very low.
'D' heat exchanger andpump were removed the dented tulx-s was January 16, from service and the *B heat exchanger leaking. The *lr heat Even ifIms of all RIIR were to 1983 exchanger did not actu- occur DilR could be and pump placed in service. Approximately completed using the main 8 hours later an alarm was received on the ally, leak, but had to Ic isolated untilit condenser, RWCU, l'PC, CR D, SW cffluent monitor. %c *B* heti exch- could te confirmed to condenute,or fire proicctiem anger and pump were removed from service. not le leaking. The 311 water systems depending on (He *A* and *L heat exchanger and pumps and 3D heat exchangers plant condisions.
were inoperable due to a bent stem on their common injection valve.) Thus there share a common radia-was a complete kiss of RilR shutdown tion monitor, cooling capability. ghe RCSjemperature increased Irom 188 F to 211 F in approximately 45 minutes. Reactor heat removal was provided by steaming to the main condenser and by coolant makeup from the CRD and RWCU systems. ti b na o b
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Cnp N Table 190C.1-2 :=
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a DECAY HEAT REMOVAL PRECURSORS (Continued) 8j # E EVENT CAW (;ORY: LOSSES OR DEGRADATION OF RilRS DtlE TO IA)SS OF COOLANT FROM REACTOR VESSEL 1 PLANT INITI AL PLANT EVENT DESCRil' TION REPORTED CAUSE APPLICAHLE ABWR FEATURE $n LER/DATE CONDITIONS Operator failed to rec- See I.aSalle 1 (6/1I/82). Peach Mode 4, Cold Shut- While in cold shutdown near ihe end of an extended refueling outage, difficulty in ogniec that l>e was Bottom 3 down. losing primary system maintaining reactor water level was encoun-81-014 inventory when the CRD September 2, tered when the control rod drive water water system was re-system was removed from service to support 1981 plant testin Vessellevel decreased to moved from sersice. In-
. A feedwater inlet valve complete closure of about 60 in feedwater inlet valve was then opened slightly to supply make-up water to the vessel. (Pumping source not MO-3-2-298 caused and uncertam because levelincrease almvc stated turbine in LER, feed pumps are unusable in main steam line nonles driven cold shutdown. Source was probably and subsequent pres.
condensate pump.) Vessellevel was re- surization. covered to 90 inches and the feedwater valve closed. leakage through the vahe occurred and level increased atx3ve itse main steam line nonles. As a result of the kns of the reactor vent path (main steam lines to condenser), the reactor pressurized to about 32 psig for almut 35 minutes (MSIVs assumed to be shut to prevent fl<xxiing of steam lines). To de-crease sessel level, water was transferred from the vessel to the torus. Later during an attempt to obtain a tight shut. off of the feedwater inlet valve, the reactor was again pressurized to almut 79 psig for 30 minutes. He reactor head vents were opened to depressunze the vessel. b r r 0 A v 5 b
cn l iii;g>. A Table 19QC.1-2 [ 5.$, DECAY HEAT REMOVAL PRECURSORS (Continued) m %. .-
-r
!- c2.
EVENT CATEGORW EDSSES OR DEGRADATION (W RHRS DUE TO LOSS (W COOtANT 3 FROM R INmAL PLANT REPORTED CAUSE APPLICAHLE.ARWR FEATURE g l Pt#ff EVENT DESCRIPTION ~ LER/DA*IE CONDmONS See LaSalle 1 (6/1I/82). Cause not reported in During preparation for a containment inte- AHWR has complete devisional ! Browns Ferry ' Mode 5, Refueling. ' LER. separatkm in a 2-out-of-4 logie l grated leak rate test (ILRT), a spurious 2 . Iow reactor vessel water level signal was network that prevents spurious 83-005 mitiation signals from smgle Felwuary 16, . initiated,f eration o a .rently due drywell to imotoper presure swwch op- event errors. 1983 drain.11me combination of km water Ictel and high drywell pressure signais stacted four core my pumps, foest RilR pumps, and eight scrators. The RifR system was fore injection into ahe vesseloxurred. flowever,a ofalof
. 44,000 gallons of water were injected into the vessel from the torus via the crwe spray system, which caused spillage into slic drywell sumps via an open head vent, and pig sonic water into the steam lines.
The vessel head was in place with the head fastening n.its not installed. b.
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o , . 9 mi g Table 190C.1-2 :s k g 8. a ' DECAY HEAT REMOVAL PRECURSORS (Continued) g E LOSSES OR DEGRADATION (W RHRS IMIE TO IDSS (W CtMMAfW FROM REACTOR VESSEt, EVEfW CATEGORY: 2 y REPORTED CAUSE APPLICARIE ARWR FEATURE PLAffr INITIAL PLANT EVENT DESCRIFTION ~
-LER/DATE. CONDITIONS and The spurious low water
' Mode 5, Refueling. During a refueling outage, an inadvertent level sgpial was caused See BrownsLaSalle 1 (6/11/M2)1).
Ferry 2 (2/36/8 Peach - initiasma of two RiiR pumps in the LPCI by a pressure surge in Hottom 3 ' mode caused an injectmn of 65,000 gallons . the reference leg of 8 3-0101 of water from the torus into the reactor the 2B Yarway mstru-March 3, vesscL Since the unit was in refueling mentation loop during 1983 with the reactor cavity flooded, most of . surveillance testing. the water overflowed onto the fuel floor, and down the main hatchw to Et.135, animately 50 flowed out
. where' the under the ra oad dooc mid into the storm drain system. The ini-tiation was a false low water level signal which was present for less than 33 seconds. "Ik signal started all operable diesel generators, tripped and isolated recire pwegstn'pped liPSW pumps, and started 2 RHR pmaps.. Diesel generator -
siarts and the large number of spurious alarms distracted operators from verifying reactor water level until about as which 4 minutes time ihe pumps . after were actuation, tryped an d injection valves closed. Personnel exited the area, and no person-net exposures resuked from the flooding.
, %e total dose associated with the subsc-
' quent cleanup effort was less ahan 2 man-rem. Total release was estimated at 316 microcuries.
b :*$ D b = - . - - - - _ _ . . . . . , . . . . . , . . . . . . . . _
r - _ - - = . N
=
Table 19QC.1-2 E.tz m j DECAY HEAT REMOVAL PRECURSORS (Continued) ".y o g
~ EVENT CA1EGORY: 1DSjlES OR DEGRADATION OF RHRS DUE TO IDSS OF COOEANT FROM REACTOR VESSEL "O
APPLICABLE ABWKFEATURE m PtANT INITIAL PLANT EVENT IESCRifTION REPORTED CAUSE :s
. CONDFI10NS .-
- LER/DME Improper use of in the ABWR design, racking With loop *B* of RilR in SDC mode and kmp out the RilR pump tweakers Vermont Mode 5 Cold Shut. *A* out of service for maintenance,"A*. procedures.
down.~ kHRS in . does not resuk in the mini-fkm Yankee and 'C' RHR pump motor tweakers were - valves e ning. See tasalle I March 9 - operation on loop racked out for maintenance. S em logic
- 19t19 *B*.
for these ( ) for discuwi(m eif then causes the mini-fkw va A procedures.
- n. Following maintenance,Ihe
. punips A* andto SDC suction valves were man- !
mally stroked open per procedure. This opened a drase h froen the RPV to the
. suppression Reactor cavity level .
. dr approximate 72 inches to 218 ateve top of vefuel.
Excesdve time to com- Alternate means of DilR could With reactgr coolant temperature apprami- lie used including main cim-Susquehanna Mode 4 cold Shut - . mately 125 F,the RilR system was removed plete maintenance. denser, v.cnting sacam to the 1 February 3, down itHRSin frosn service to perform a test of the RPS suppression pool through SRVs
<j SDC mode using 1990 electrical grotection asse (EPA break- andsuppressees pool cimii loop *A*. ers. RHR must be secured uringi test See Su quehanna 1 (2/16/M .
because open' the EPA breakers causes isolation of S I ollowing testing,
- difficulty was experienced m c some of the EPA breakers to energize i RPS.
This delayed reestablishing SDC. Regor coolant temperature increased to 253 F and pressure increased to 19 psig before
- SDL was restored. '
' Inadverten: actution See Susquehanna 1 (2/16/M3)
Mode 4, Cold SDC was lost for Iwo hours and twenty of fire prefection - Quad Cities 2 minutes due to loss of power to IE buses. f. 4/2/92 Shutdown. deluge system.
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g 7 Table 190C.1-2 [ DECAY HEAT REMOVAL PRECUGSORS (Continued) h l EiT M e:ATEGORY: 1.OSSFS OR DEGRAD ATION OF RIIRS DOE TO t.OSS OF COO! ANT FRO %f REACTOR T VESNFt. PIANT INITIAL PIANT REPORTED CAUSE APPI,ICAIII.E AllWR FEA1URE g CONDITIONS EVENT DESCRII" TION ~ LER/DATE %c AllWR wrPressk* Pa.I Operators were in the process of changing improper operator suoi m vahe unnos I.c ogwncJ Washington Cok! Shutdoms with he operating SDC huip from *B" to "A". actm.n. until the St K'sustW.a sahr is Nucicar Plant RIf R ~B* in SDC He twocedure ca3ed Ior tiosing the loop m<xic. iully closed 2 ~B SDC suctkm vahe and then open the May 1,1988 loop-B suppresske pud suctim valve. De operator did not wait until the SDC suction valve completely (kned lefore openine the suppression gxcl suctkm valve. *fhe stroke time on each of these valves is 120 seconds. B4xh valves were partially onen for 40 seconds and resulted in about 16,000 gap.ons of water draining from the reactor cavity to the ession pool. Dramdoms was automat SDCwas lerminated on law RPV level w isolated. impnger freeze seal ABWR frecie seal pruccJurcs formed on the standby mIIinclude adequate Cold Shutdown. Work was implementation. River Bend service water ( supply and return administrative ctman ls to April 19, valves. Asthese are unisoahic, minimize frecie seal fedures. 19tr> freeze seals were being used to isolate Analysis have I.een completed the valves. One of the freeze seals toensure hat th==ImganIhe faded and caused averoximately 15 000 gal- ABWR will rme resuis m kws of , lons of water toIksl the Division if ECCS or RPS pmer supphes. ECCS power supply room. Electrical fauks resuhed in loss of power to RPS bus *B". This caused coatainment isolation and loss of SDC.
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W - l l SBWR Date W8/92 To Fax No. C. Pos tusNy _. Thispagoplus Ib page(s) Fmm , fl. !]ca c k !,c ecl un code 76A- ' 175 Curtner Avenue San Jose, CA 95125 l Phone (408) 925- la P 9 FAX (408) 925-1193 or (408) 925-16B7 Subject A e wR 1* TA A C - Response 4 NRc . d2va sta da Message e'E- 6 **m. 4r ,- .=e; g
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12/S/92 FLANT $Y51T% Ei 0 CH CO.\D.ENT;, 2#0* TF WE 7 iAIN STE 9 ' E c';' 02dMB!T Q.: SPLB 2.10.1 1
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y r - w ,.- . Comment rejected. J Beyond the scope of TIER 1/ ITAAC. T DEMdBLT__1Q: SPLB 2,10.12 ) 4 i Discuss MSIV's ability to shut during rraximum DP and flow conditions ; i GE RESPO!1SE: Comment rejected. Not practical to test MS!Vs for closure speed against maximum differential pressure and maximum flow. Closure times are expected to be faster under maximum dP and flow because upstream pressure tends to seat the valve (i.e. the disk is on the upstream side of the valve seat). The stroke time of the valves will be tested, llowever, stroke rate testing of MSIVs against high pressure steam cannot occur until start up. COMMENT ID: SPLB 2.10.1-3 Identify seismic interface restraint GE RESPONSEt id . 0 4 :: . A i .ibl4 . s rk ;i.. w.... .s . . .; ..
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i FnANT SYSTDIS BRANCH CO.\bfEN~I5 w-Ofy ce'eme cW: Md cuamy cx (incun; n "n; accruTters for MSFys ano sfe:yireast van. anc cf;b.z. ;:ar
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cuilomg is dis;ws.J m tr. un.p D.u:;pw . a . n. m a u . .. j The Seismic Class and Quality Group of the pneumatic supply lines for the ; l MSIVs and SRVs is not discussed in the NBS ITAAC. QDJNAENT ID: SPLD 2.10.15 Discuss features to protect MS line from water entrainment , GE RESPONSE: 4 Comment rey:ted. No cL.nen u!! be m.u to Mc NEa ITAAC as a rnuft of this comment. The MSLs have drain lines to drain the MSLs during startup, before full j power operation, The steam separator / steam dryer inside the RPV prevent moisture carryover during normal power operation. Also, the MSLs are insulated to
- limit the generation of condensate.
Closure of the turbine stop valves on RPV high water level 8 initiates a reactor scram. This lin.!ts moisture carryover when the steam separators are flooded. OpMMENI_lD: SPLB 2.10.16 n . . ~ . . ,
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12/S/92 PLA.Ni 5YSTriM5 Hiv.NG COMMENI S
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w... . . . . . ...i;.-__,,- u - , J SYSTEMS
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COPENSSTE AND FEED'lATER SYSTEM QDldMENT ID: SPLB 2.10.21 Provide drawing GE RESPONSE: Not appropriate for Tier 1 material. DDEliFlLU D_: SPLB-2.10.2 2 . h :.' , c:t m; :.. ace ;;e g. c H e a<, 5 ;,.E . c.: c c _a.m GE RESPONSE: Not appropriate for Tier i material. CDJdMENT IQ: SPLD 2.10.2 3 Discuss isolation provisions and supporting instrumentation GE RESPONSE: This topic applicable to Nuclear Boiler System, Section 2.1.2. C.MidEMU.Q: SPLB 2.10.2 4
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- 12/8/92 PLANT SYSTD15 BRANCH CO.\1.NENTS let '4y seismic interf ace 'Ott'a *!
.X AESPONSE:
MAIN CONDENSER EVACUATION SYSTEM C_OMn ENT ID: S F L E L.i c.:. 0 State that the system is designed for hydrogen GE RESPONSE: This will be included in Design Description. COMMENT ID: SPLB 2.10.2 7 It is not cient tnat the fiew ;r's:' ment snown On the diagram is what is used for isolation cf off;c: c n 'cw ii:v.
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GE RESPONSE: Flow element is shown at inlet to 2d stage ejector and discussed in Design Description. COMMENT ID: SPLB 2.10.2 8 Identify functions of the pressure instrumentation GE RESPONSE: Will clarify Design Description to show that pressure indicator indicates operability.
" T 171;I_ln: S P L E : '. * " C Indicat6 that ina mecnan; cal vacuum pump trips en nign mam steam kne radiction GE RESPONSE:
This is discussed in Design Description and ITAAC. 16
i 12/8/92 PLA'<T s'i SiTd!S BR ANCil COMMENTS G2fdMENT ID: SFLb4.;DJ 10
= -
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l GE RESPONSE: I'co cetaneo for Tier 1. .w wr. :w C_OMM E NT IQ: S P L B.2.10.2 11 ! Show the hydrogen analyzers on the drawing 4 GE RESPONSE: This level of detail is not appropriate for Tier i material ! CONDENSATE PURlF!CATCN SYSTEM 2.10 4 COMMENT ID: SPLB 2.10.41 SPLB has no responsibility for this system and should ce removed as the primary review branch GE RESPONSE No GE action. 4 2.10.7 MAIN TURBlNE COMMENT ID: SPLB 2.10.7.1 4 Clarify which valves trio and which modulate J F.EEPONSE:
'//: :: nL :: , R .: 1.:- :
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12/8/92 PLANT SYSTEMS BRANCH COMMENTS GE RESPONSE: Not acercorinto for Tier 1 material.
.. , _ . . . .c_., .
COMMENT IDt SPLD 2,10.91 F:o.,: c c 0:w. sing GE RESPONSE: A simpilfled SSAR drawing (10.4.2) will be provided. GOMMENT ID: SPLB 2.10.9 2 include the blower oxhaust rad monitor on the drawing GE RESPONSE: This will bo included on simplified SSAR orawing orovided for comment SPLB 2.10.9 2. fc0MMENT 10: SPLB 2.10.9 3 Clarify steam sources (auxiliary steam, main steam, process steam from high prossure heater drain tank vent risader) GE RESPONSE: This will be clarified on simplified SSAR drawing provided for comment SPLB 2.10.9 2. CDJdMENT IQ: SPLB 2.10.9 4 t: / :r: c;e>ing so.z:t ' ': tr.e :cece ser GE EESPCNTE:
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DO_idMENT lt1: SPLB-2.10.9 5 IS _ l
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12/8/92 Fl. ANT SYSTEMS BRANCH COM.\1ENTS Clar.ly how :nv steam scurce ; cnange; ce nigh mc~ c:;n a . c;nc cri1UT IV Of EUt^"'at cal!y? l Too detchd for Tier 1 material and site specific. l COMMENT ID. b E L. B 2 .i v .t 6 l l include the fact that the system providos sealing steam for the turbine , stop and control valvos and the combined intermediate valves GE RESPONSE: This will be included on simplified SSAR drawing provided for comment SPLB 2.10.9 2. 2 'O $3 TURBINE BYPASS SYSTEM COMMENT ID: S PLB.2.10.13 1 incluce statement that system can accommodate a fullload rejection without lifting main steam safety /rehof valves GE RESPONSE: No. SRVs will lift on full load rejection. COMMENT la: SPLB 2.10.13 2 Identify that turbine bypass valves (TBVs) close on loss of vacuum, LOSP, and loss of hydraulle pressure GE RESPDn i
. .- 1 _-
11 Ili?"'? I' I3 li ^ M i-O 9Mr + dermDt on fand tett' "+ vaivet coen wnen itsam pressur6 GXCOCOL pr6501 DreE5u rt, 19
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4 12/8/92 PLANT SYSTEMS BRANCli COM.NfENTS GE RESPONSE: This will be added to Design Description. ! - c o- jn. pr .+ -; 1 .: ! Include drawing i GE tie 5PCGSE. Not necessary refer to 2.10.1 schematic. COMMENT ID: SPLB 2.10.13 5 i Ensure that all the high energy lines associated with this system are located in the Turbine Bldg (Turbine Bfdg ITAAC)- ! GE RESPONSE: OK in Turb:no Buitaing ITAAC. f CQMMENT ID: SPLB 2.10.13 6 State that piping up to and including the TBVs are seismic Category 1 and l Safety Class 2 and that remainder of piping up to the condenser can i withstand an SSE 4 l GE RESPONSE: t No This piping is not safety related. 2.10.21 MAIN CONDENSER COMMENTID! SPLB 2,10.21 1
!nclude etwmp GE iiEEFONSE:
Too ceta!!sd - Not recuvec in any SSAR (or T4r i matena:) CCWl E !I ID: S P L E,.2.10.21 2 20
12/8/92 PLANT SYSTINS BRANCM CO.\ NESTS Include important instrumeMati0n on drawing (conductivity, vacuum , l monitor, rad monitcr) l 7 - - 3 r. tic - e r .a n i . Desgn er -. .: COMMEN1 IQ: SPLB 2.10.213 List all connections to condenser GE RESPONSE: This is not appropriate for Tier 1 material. COMAENT ID: S PLB-2.10.21 4 Include fact that system receives and collects condensate flows, removes air and noncondensaoles, and removes hydrogen and oxygen GE RESPONSE: This is included in Design Description. COMMENT ID: SPLD 2.10.215 Include 4 minute condensate retention capability GE RESPONSE: This is in Design Description. CO.MMENT ID: SPLB 2.10.216 Include fact that maximum flood !evel is less than grade if condensate sp;c- ex'c M GE RESPONSE: The CWS System, 2.10.23, is flood limiting - clarify. l 2.10.23 CIRCULATING WATER l 21
4 12/8/92 PLANT SYSTEMS BRANCH CO.\ ihfENTS COMMENT ID: SPLB 2.10.23-1 Indicate that system dumps heat to the power cycle heat smk.
,:et I
i 4 COMMENT ID: SPLB 2.10.23 2 Wnere will the level switches be shown (the Turbine Bldg ITAAC)? GE RESPONSE: COMMENT ID: SPLD 2,10.23 3 Indicate anc show that the logic scheme minimizes potential for spurious "high level system" isolation trips-l l GE RESPONSE: Not Tier 1. This level of detail not appropriate for Tier 1 material.. i COMMENT ID: SPLB 2.10.23 4 l State that there will be features provided to prevent organic fou!ing i GE RESPONSE: Not Tier 1. This level of detail not appropriate for Tier 1 material. COMMENT ID: SPLB 2.10.23 5 Ic!entify that the system wm func:icn on :cw !evel in ne power cycle heat sink GE RESPONSE: Not Tier 1. This level of detail not appropriate for Tier 1 material. 22
l :.. .. .. ,; .;. -; - , ,, a i 11/8/92 PLANT SYSTEMS BRANCH COMMENTS COMMENT ID: SPLD 2,10.23 6 f Include the fact that features are provided to maintain a man; mum
, , ..7 ..:..,
GE riddFC.NSE: l 2 Not Tier 1. This level of detail not accropriate for Tier 1 material. 4 i j COMMENT ID: SPLB 2.10.23 7 i Ensure that all Turbine Building flooding will be confined to the condenser ' pit (Turbine Building ITAAC) GE RESPONSE: See Turbine Building Section 2.15.11. 1 l I i 5 1 t 23
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Division of Engineering Technology Comments Comme nt- ID_ Comment /GE Response
- CO mfENT IDt D ET.2.10.1 1
- L..?.: u M:: iwJn em 4
The ABWR plant design has chratnated the main steam isciar.on valve le.txa;; control system. Instead, GE proposes to rely on the use of an alternate leakage path which takes advantage of the large volum: and surface area in the main steam piping, by pass line, and condenser to hold up and plate out the release of l fission products following core damage. Therefore, these components are used to , mitigate the consequences of an accident and are required to remain functional during and after a safe shutdown earthquake. The commitments that OE has made relative to this issue are in Section 3.2 of the SSAR and are summarized in Section 3.2.1 of the staffs Final Safety Evaluation Report for the ABWR. The l i
- discussion in Section 2.10.1 and the ITAAC in Table 2.10.1 should be revised to '
~ reflect this information and to confirm that it he.s been implemented in accordance with the SSAR commitments. GE RESPONSE: I See response to Radiation Protection Branch comment- RPB.2.10.11. i COMMENT IDt DET.2.10.4 1 2.10.4 Condensate Purification Svstem ! The proposed Certified Design Commitment and ITAAC do not address the primary function of the system and how to verify its operability. OE should revise the ITAAC accordingly. See comments on attached marked up page. I GE RESPONSEt GE will delete reference to water treatment additions since there may be several, 3 depending on final detailed material selection, e.g. 02 H2, Fe, etc. ! 32
12/8/92 RADIATION PROTECTION BRANCH COMMENTS RADIATION EBQJEQJ108 BRANCH COMMENTS E E L^4 2. " L ' E 1 2 t Id? d 1 :220 $4133 CC"llENT LQi_R F D 2.10.1 1 The staff has rev:ewoo Section 2,10.1. Turbine Main Steam System in the Tier 1 Design Cert.fication Material (TDCM) and finds that tne des gn description and its related ITAAC (Table 2.10.1) should include (1) the operability requirement of main steam drain valve from main control room via essential power supply (Class IE), (2) the structural Integrity requirement for main steam lines, draln lines, and main condenser for their leak tightness following a postulated LOCA. GE RESPONSE: COMMENTID: RPG 2,10.1 2 The main steam lines from MSIV to the main condenser, including the drain lines, should be analyzed, and (3) using a seismic analysis to demonstrate appropriate structural integrity for leak tightness under SSE loading conditions. The staff has provided a credit for iodine removal in the main steam lines, drain lines, and condenser following a postulated LOCA and accepted the ABWR design without a MSIV leakage control system. This. Is Open item 2,3.61. GE RESPONSE: l 1 l
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12/8!93 , 4 RADIATION PROTECTION BRANCl! COMMENTS 3.0 Section 2.101. Turbine Main Sigam System COMMENT ID: RPB 2.10.13 3.i Add the following two certified design commitments in Table 2.10.1 as ITAAC items. (1) the main steam drain valves are operable from the main control ' room via essential power supply (class IE). . (2) the main steam piping from MSIV to the condenser inlet including the main steam drain pipe is analyzed to demonstrate appropriate leaktightness under SSE loading conditions. 3.2 The basis for adding the above ITAAC items are that (1) the staff has provided a credit for altborne radioactive lodine removal in the main steam (and drain) piping and in the main condenser following a postulated LOCA, and (2) the staff accepted the ABWR design without a MSIV leakage control system. . 3.3 A marked up copy of Section 2.10.1 is enclosed. incorporates comment 3.1 GERESPONSE: Agree to add. 18
LEC. , e n s: E n i.s.d e M n iis i,1HD ,, 12/8S2 ACRS COMMENTS COMMENT ID: ACRS 1 2.10.2-1 Section 2.10.2, page 1 thru -5 (6/1/92) Condensate and Feedwater System, Design Description, Page 2.10.2-1, Paragraph, Last Sentence, states: This portion of the piping is analyzed for dynamic effects from '
- postulated events and safety / relief valve discharges.
Table 2.10.2a, Inspections, Tests, Analyses and Acceptance Cdteria, Page 2,10.2 4, doesn't explicitly provide verification that this analysis has been performed. (Perhaps Certified Design Commitment number 1 was intended to imply this verification; however, that commitment could be met without coverage of the analysis mentioned here.) GB RESPONSE: This sentence deleted. The referenced piping applies to NBS. COMMENT ID1 ACRS , 2.10.2-2 Section 2.10.2, page 1 thru -5 (6/1/92) Main Condenser Evacuation System, Design Description, Page 2.10.2-2, Third Paragraph, states: The MCE System is designed to Qpality Group D. Table 3.0, Page -5, the entry for 2.10.2 shows 3.3 Piping Design as not applicable. Quality Group D requires piping designed to B31.1. GB RESPONSE: Section 3.3 Piping Design is not applicable to non safety-related Qpality Group D. No change. 45
b
, DIC..i 92 8: NAM GE WC. EAR Am 0336 f.WH a.
12/IS2 ACRS COMMENTS COMMENT ID: ACRS x 2.10.4-1 Section 2.10.4, page -1 and .2 (6/1/92) Design Description. Page 2.10.4 -1. Third Paragraph, states: ., The CP System is designed to Quality Group D. Table 3.0, Page -5, the entry for 2.10.4 shows 3.3 Piping Design as not applicable. Quality Group D requires piping designed to 831.1. GB RESPONSB: Section 3.3 Piping Design is not applicable to non-safety related Quality Group D. No change. . 1 i 9 e
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12/8/92 ACRS COMMENTS COMMENT ID! ACRS 2.10.7-1 Section 2.10.7, page 1 and 2 (6/1/92) Page 2.10.7-2, Table 2.10.7, ITAAC doesn't include any coverage of verification that LP rotors have been center-bored. See David A. Ward's , letter to James M. Taylor of April 13,1992, Item 6 on page 4. GB RESPONSB: Too detailed for Tier 1. Center boring LP rotors is dependent on available technology and should be at the discretion of vendor and customer. No action taken. CQMMENT ID ACRS 2.10.7 2 Section 2.10.7, page 1 and -2 (6/1/92) Section 2.10.7 barely mentioned the Turbine Controls. Yet Section 10.2.8, Turbine Controls, says that the topic is covered in Section 2.10.7. Figure 2.2.7a Reactor Protection System, on Page 2.2.7 8, provides a block ("C71 RPS") of four (4) input signal from turbine 1&C. The RPS ITAAC don't include verification of the I&C for these turbine inputs. Coverage is required somewhere. GB RESPONSB: The RPS ITAAC includes input signals from Turbine Controls. ITAAC 2.2.7, item 3, simulation testing will verify that I&C provides signal to RPS, P 47 i
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, :E;,,9 si E:MA" Si .'rJ: LEAF AEU. 'd335 F, !?/2;
- 12/8S 2 ACRS COMMENTS COMMENT ID! ACRS 2.10.91 Section 2.10.9, page 1 and 2 (6/1/92) i Design Description, Page 2.10.91, Fourth Paragraph, states:
,i The TGS System is designed to Qpality Group D. Table 3.0, Page -5, the entry for 2.10.9 shows 3.3 Piping Design as , not appilcable. Quality Group D requires piping designed to B31.1. i Turther, Design Description, Page 2.10.91, last Paragraph, states: P.11ef valves on the seal steam header prevent excessive seal steam
- pressure.
- I i TMs sho involves " piping design." ;
GB RESPONSD: 1 Section 3.3 Piping Design is not appilcable to non safety related Qyality Group
- D. No change. - .
i i i \ i b i S i dh
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- ACRS COMMENTS
) t COMMENT IDi ACRS 1 2.10.13 1 Section 2.10.13, page 1 and -2 (6/1/92) , I j The failure or malfunction of the Turbine Bypas' System has the j
- potential to cause severe transients effects on tht. Reactor Coolant
- System. The coverage in Section 2.10.13 doesn't appear consistent with l that importance.
i i
- Design Description, Page 2.10.13 1, Fourth Paragraph, I.ast Sentence, and last Paragraph, state respectively:
! The TB System is designed to bypass nominally 33% of the rated ' main steam flow to the condenser. i
- The TB System in conjunction with the reactor systems, provides I the capability to shed 40% of the turbine-generator rated load
- without reactor trip.
j These important capabilities are no doubt assumed in various transient
- analyses and should be confirmed by the ITAAC. -
GB RESPONSE: ! Too detailed for Tier 1. In addition the TBS is not safety related. l 4 i
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OFPJmlenrEnergy ARWR 1 Dnte & 7-97_ t To cHc r RxsLQ6yY Fax No. l _JgR RT Mh LSO/s/ This page plus ._&_ pago(s) From ~ TOE QVIRK uni \ code 175 Curtner Avenue San Jaso, CA 951 ?S Phone (408)925- FAX (408)925-1193 or (408) 925-16!!7 Subject 6 G~ Sct/ehhLLE- Fh/LAcNrT)ES Message 4 tho.c4mujo& 6EL cwnmo;fij_ an:rkdsemu Ne;L e, Adw fu /64 w/ dhusu Car 2Jtffhd,] jag // efend 1 Paua,, seuse e%ga:ouapar
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TAate t ABY!R FDA Schedule i b 1992 1993 g Activity Jan Feb Mar Apr May Jun Jul Aug Sep Finish { Oct Date Nov Dec ] a l I l I DFSER issue Resolution 2/28/93 ; I I Forma! SSAR Amer.dment 3/15/93 6 j j
~,
! I i i ! i 6
I Reformatted SSAR Preparation 3/31/93 E
! ! I . E t g i Reformatted SSAR lssued 3/31/93 A p 3
NRC SSAR Verification 4/30/93 M FSER!ssued 4!30/93 A ACRS Review 5/31/93 M "N 1 { ! Conforming Changes to SSAR 6/15/93 *Ml ;
! 8 l *
! ! FDA issued 6/30/93 i 11 l , t __ ! DCD Preparation / Submittal 8/15/93 EE DCD Approval 9/15/93 M I k - l Initiate Certification 9/30/93 ji I 9 e
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TABLE 2 DFSER issua Resolution Sch:dule
~
Nov. Dec. Jan. Fab. Ma.
} Oct.
No. cf ' ugeM ~l Branch jssues Chacters J _ i
' e uee mg i SPLB 144 3,6.9,10.11 e A e _A A 10.11 j A conference 8 l
can 5 ' I EELB 142 8 e . ._0 A- 4_A 8 5 o OTSB 3 16 A A a A 16 m
~
l C
- I PEPB 3 13 +
A 13 P 1 m I i i PSGB 1 13 A _ l SICB 1 7 A7 - i 1 PRPB 6 12 A A 12 DAR 6 14 4
- EMEB 128 2.3,5,9.14 e A , e_A _A 2, 3, 5, 9,14 SRXB 23 4,5.6,15 A__A 4,6,15 i SPSB 78 19.1 eA-e a A A 19 f
SCSB - 19.2 e A HICB 41 7 A A 7 a HHFB- 23 18 An 18 4 RPEB 22 14,17 An 17 i m [ Var;eus 22 ,20 e A 9 1 T.O ;,, e W
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! . . itc or s e r .. . o ..;., o, e p, a .a 3 ~ DFSElt ISStJE RESOLt.rl10N SCilEDUI.E NOTES The DFSER issue resolution schedule provides chapter by. chapter , specific submittal dates utilizing the NRC Branch chapter wise review responsibilities. When issue resolution for all the chapters scheduled for a given Branch are complete, the chapters unique to 4 that Branch and the chapter (s) concluded by completion of that Branch's issue resolution activities are scheduled for submittal. A SSAR amendment for these chapters will be submitted by GE to the
- NRC within two weeks following the Branch's resolution activity.
The current SSAR will be used as the vehicle for closing out the outstanding items. GE is developing, in parallel, a reformatted and verified version of the SSAR which will be submitted to the NRC at 2 the end of March 1993. 4 I I a i e 4 d 4 h 1 I . r r-- -e .- , - .~ m -.
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, l 7. Y C. L. LARSON, M/C 489 GE NUCLEAR ENERGY RELIABILITY ENGINEEPTNG SEPVTCES 175 CURTNER AVENUE SAN JOS". N.tTPOU"T\
4 BY TELECOPY: (40P) 925 1412 C1.L 92042
, cc: J. D. DUNCAN S. VISVESVARAN R. P. RATTFDY 1.TR Bn0V, TELECOPY TRANSMITTAL DATE: 12/04/92 TIME: 3:30 PS7 TO: CLENN KELLY, USNRC FAX: 301 504-2260 1
SENDER: C. L 1 ARSON (CE), (408) 925 3702 TRANSMITTAL INCLUDES COVER SHEET PLUS 11 PAGES il3}JJ.CT- ABVR PRA; SECTION 19K: PRA INPUT TO RELIABILITY /.SSURANCE PROCPAM (RAP) 4 COMMENTS: ATTACHED DRAFT OF 19X IS INTENDED TO ADDRESS QUESTIONS AND COMMENTS FROM MEETINGS AT CE-NE ON 11/10 6 11/11/92. PLEASE ADDRESS PURT!!ER COMMENTS TO ME AT THE ABOVE PHONE OR FAX NUMBERS. A1.50 PLEASE ADVISE ME VMEN YOU EXPECT TO COMPLETE YOUR REVIEW OF 19K. Jatr~ LS~t L 2suc% A /-l20 4 2/~ 3i Ac- (fax W a
1 Cenoral Electric Company ABUR 23A6100A5 Stender d jant .. _ _ _ Ret .c . 19R.1 Introduction ! i l In this cppaed!x. the resvits of the FRA are revfe ad to determine the appreprir.re relishility end maintenance actions that *Fmtid be considered throughout the life of an A*VR plant so that the P'A ra" ming An adequata hasta for quantifying plant rafaty. These actiona compriro a part of the plant'n reliebility eraurance pro, gram (RAP). Paragraph 8.8 "Maintanenca and Surveillance", of the AEWR I.icensing Review Baces (Referenae 1), - ade in part, "0E is to provida in the SSAR the reliability and maintenenea criteria that a future applicant must satisfy to ensure that the safety of the as built facility will continue to be accurately dancribed by the cerrifiad design." This appendix provides tha PRA based reltability and maintenance me.tions which should be considered for incorpora. tien into the future applicant's (i.e., the applicant referencing the ABVR design) operating and maintenanca procedures required by Standard Review Plan (SRP) snetton 13.5.2. As indicated in Table 1.5-19. SRP 13.5.2 in an inter-fact. requirenent to de provided by the utility applicant referencing the ABVR design. Amenomant __ 12/04/92 19K.1
Consral Electrie Cozpany !
- . /.WR 23A6100As
! ftardgyd Plant Rev. C l, 19K.2 General Approach t
- To determine the appropriate reliability and maintenance related j a-tivities that should he ennsidered to susure that plant safety is maintained l as operation proceeds, reeutta of PRA and other analyses were reviewed. The '
{ objective of the review was to daterreine the relative importance of prevention j and mitigation features of the ABWR in satisfying the key PRA goals related to , core damage frequency (CDP) and frequency of off. site raleepe. Also l considsred ware the initiating events that had significant impact on CDT . 4 From this review (Section 19L 3), the most important plant features were j identified. 1 I l The PRA rins further reviewed (secticas 19K.4 threugh 19K.20) for other important features, the failure of which was not addressed directly in Section ! IfK.3, to surplement the above list. Finally (Sec. tion 19K.11), the individual features identified in Sections 19K.3 throu6h 19K.10 were revisued to ,
- determine appropriate ronintenance and surveillance actions.
I 5 i i j E i j . s . 5 1 i , 4 I 1 4 Amendment _ - 12/04/92 19K.2 4 i r
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Ceneral Electric Company AsvR 23A6100AS Stender.d.Plent R.etu, C 19K.3 Datermination of "Inportant structures, Fy*tema and componants" for Level 1 Analysis To determine which plant structures, systems and components (SSCs) are a tha most important with respect to CDF, the Level 1 enelysis results were analytad. The SSCs were listad in order of Tussell-Vesely (TV) importanca, or the percent of cutsats that contributa to the CDF, as calculated by the CAFTA c o le . A nacond criterion for selecting SSCs was to conalder those SSCs with high " risk achiavament v'-th", or the increase in CDF if that SSC always fatis. The 19 SSCs of greatest importance, in that they had TV importance gtcater than 1%,-contributed more than 60% of the sum of the importances and they are shown in Table 19K.3 1. Also shown for each SSC is its risk achievement worth, and five additional SSCs with risk achievement worth greater than 20 were considered. Not shown in Table 19K.3 1 are several-human error contributions. Significant human arrors are addressed in Subsection 19D.7. The 24 SSCs in Table 19K.3 1 were further evaluated to eliminate those with a combination of low values for both TV importance and risk achievement worth. The five SSca meeting this criterion are so indiented. However, one ofthosefiveisretainedbecauseofitsdesignation:ana"criticaltask"in the human factors evaluation of Subsection 18E.2. The other four are not considered further in this Section. The remaining 20 designated SSCs of Table 19K.3-1 should be included with F important SSCs being conaidered for periodic testing and/or preventive maintenance (PM.) as part of the Reliability Assurance Pro 5 ram (RAP) of the plant owner / operator, The reliability and maintenance actions suggested for the listed SSCs are identified in Section 19K 11. A second table, 19.K.3 2, was prepared to show those SSCc vith risk achievement worth between 5 and 20. These SSCs all have very low Fussell-Vesely importance, indicating a low probability of failure. However..if they fail, the impact on CDF is not negligible. Most of these SSCs have risk Amendment __ 12/04/92 19K-3 i l l
Constal Electric Co:pany AB7R 23A6100AS 7.t.PD4%Fif1ADt
- _ Revmq ;
, Table 19K.3 1 AWR SSCs of Createst Importanes for CDF. lavel 1 Analyrie Fussell Vasely Risk Importance Achievement SSC g Wnh__
l RCIC System (Unavailable. Test or- , Maintenance ) 21.8 ' 12. l l Multiplex Transmission Network (CCF) 12.1 204,400, i RCIC Turbine 12.0 12. RCIC Pump 7.4 12. Trip Logic Units 6.0 204,300. Remote Multiplexins Units 6.0 204.,300.- RCIC Turbine Lubrication System 4.6 12. I { Statior. Batteries (CCF) .3.3 13.160. i [ Single Offsite Power Line (1) 3.1 4.1 j RCIC Min Flow Bypass Valve E51-F011 (NOFO) 2.0 12. RCIC Min Tiow Bypass Valve E51 F011 (NCFC) 1.9 12. ! RCIC Injection Valve E51-F004 (NCFC) 1.9 12. j RCIC Steam Supply Valve E51-F037 (NCFC) 1.9 12. l HPCF Maintenance Valve E22 F005B (2) 1.7 2.7 l Combustion Tarbine Generator (1) 1.7- 1.3 f- RCIC Isolation Si 5nal Logic 1.5 12. l- Both Offsite Powar-Sources 1.3 14. l, HPCF Pump (1) 1.1 '2.6 l SkVs (1) 10 - 4. 3 RER Flow Transmitters (CCF Miscalibration) 0.2 32. SRV (CCF) -
< 0.1 189.
1.ovel 2 pensors-(CCF). < 0.1 273.
- j. Level 8 Sensors (CCF Miscalibration). < 0.1 28.
! Digital Trip Modules (CCF) << 0.1 281 l 3 l 4 (1) SSCs with low FV importance and low risk achievement worth.
- l
^ (2) Not. SSCconsidered with low FVfurther for RAP. importance and low risk achievement worth,- but retained because of human factor importance.
. i 1
~
19K-4' Amandment _ 12/04/92 l
'l
_.._-.....__.-..a
__ . . . _ _ , ~ . ___..__ . - - -. ._ - Cansrci Elsetric cetpany A37R 23A6100AS-MPndar.4,flant RJ yd Table 19K,3 2 .. ABUR SSCs Vieh Risk Aeblevement Worth 1 Between 5 6 20 For CDF. Level 1 Analysis f 1 i Fussell.Vesely Risk ' Importance Achievement SEC 4 Verth l RCIC Turbine Exhaust Isolation valve F039 Limit Switch Fails 0,74 12, RCIC Steam Supply Bypass Valve F045 Limit Switch Fails -0.74 12,
, Div 1 Transmission _Ntvk Failure (EMS) 0.70 13, i All 3 Diesel Cenerators, CCF 0.56 11.
1st ESF RMU Div 1 Fails 0.34 13,
- 2nd ESF RMU Div 1 Fails 0,34 13.
- RCIC Flow Sansor E51 F7007 2 Fails '0.32 12.
RCIC Isolation Valve F036 Fails (NOFC) 0,18 12. , RCIC Isolation Valve F035 Fails (NOFC) 0.18 12. d , RCIC Isolation Valve F039 Fails-(NOFC) 0.18 12. i' RCIC Check Valve E51 F003 Fails-to open 0.15 12. RCIC Check Valve F038 Fails to Open 0,15 12 . ; RCIC Outboard Check Valve F005 Fails to Open -
. 0.15 12.
NBS Isolation Check Valve B21.F003B , I (FW Isolation) Fails Closed . 0,15 12, l NBS Isolation Check Valve B21-F004B
- (FW Isolation) Fails closed 0.15 12.
NBS Manual Valve B21-F005B (FW Isolation) Fails closed (NOFC) 0,14 12. e RCIC Pres Sensor PIS.2605 Miscalibrated 0.054 12. RCIC Flow Sensor FT 007 2 Miscalibrated 0,054 12. l RCIC pressure Sensor E51 FIS.Z605 Fails 0.013 12, Failure of Division 1 Distribution Panel 0.0064' 12, ,l SP Temp High (Loss of Pump Head) 0,00055 6,6 SLU/ EMS Link.for Div 1 SLU 1 Faile 4-(RCIC Jails) 0.00046 12- , SUU/ EMS Link ~for- Div 1 SLU- 2 Fails ! (RCIC Fails) 0.00046 12, 1 l Notes: EMS - Essential Multiplexing System ESF - Engineered Safety Feature , RMU = Remote Multiplex Unit- ] SLU = Safety System Logic Unit. Amendment __ 12/04/92 -19K 5 i i g y ,- ,- --,
...,s . - , , , , , _ . - n- .,e -r- -- -- -
. 0-N2 canstal Electric Company ABVR 23A6100AS 5.tandn d Plant _R L Q achievement worth of 12 because their failure would reault in failure of the l RCIC system to' perform its function.
Initiating events that are significant contributors to CDF in the Level 1 analysis are listed in Table 19K.3 3. There are five such events which are shown with their frequency and their total and relative contribution to CDP. The three most significant events, accounting for more than 70s of the CDF, are all station blackout events. The next two events, contributing lit and 7% of CDF, respectively, are isolation / loss of feedwater and manual reactor shutdown. All other initiating events contribute less than 5% of CDF each. i The components within the control of the COL applicant that are of most j significance to limiting the frequency of station blackout are the diesel genere. core and the combustion turbine. The col applicant should assure that maintenance and test activities for these componenta are appropriate to assure high reliability. Systems that are most important to limiting the frequency of isolation / j loss of feedwater are the feedwater and_feedwater control (FWC) systems. The FWC system is triply redundant, having digital logic with'self checking. The ( automatic checkin5 of the FWC system assures that its reliability remains high l throughout operation. The COL applicant should assure that maintenance and test activities for risk-significant components in the:FW system, the FW pumps i and motors, are appropriate to assure h1 5h reliability.
. Unplanned manual reactor shutdowns occur with a relatively short tima for j preparation, in gentrast with a planned shutdown. To assure that the unplanned shu'tdowns will not cause undue risk to the plant, the training procedures should-include adequate training, including simulator exercises, f for such events so the operating crews can respond to plant conditions during such shutdowns on short notice.
The RAP activities-for important SSCs identified by consideration of . initiating events are included in Table 19K.11-1, . Amendment __ 12/04/92 19K 6 i
-General-Electric Company
~* - ABVR 23A6100A5 SJandat.d_Elant Roy d Table 19K.3 3 ABWR Initiating Event contribution to CDF, Level 1-Analysis Events Total 8 Percent CDF Initiatine. Event Per Year CDF X 10 Contribution Station Blackout for Less Than Two Hours 1.22E.6- 6.67 42.7 Station Blackout for Two to ti 5 ht Hours 4.46E.? 2.57 16.5 Station Blackout for More
=Dian Eight Hours 1,62E.8 1,71 11.0
_ Isolation / Loss of- Feedvator 0.18 l'.70 10.9 Unplanned Manual Reactor Shutdown 1.00 1.15 7,4 The relative importance of some ABVR features is not; establie ad by the-Level 1 ar.alysis described above because some.important SSCs are not treated in the Level 1 calculation. To identify other important.SSCs, the Level 2, seismic, fire, flood and shutdown analyses results were carefully reviewed by knowled6 eable engineers who identified additional SSCs for-the RAP. The important SSCs-identified in these'other studies are'5 ven 1 in Sections 19K.4 through 19K 10, and RAP activities ara in Section 19K.11. 1 Amendment __ 12/04/92 19K-7
. -~
General Electric Compcny _ . ABVR- 23A6100AS_ S.ttndAgd Plant Rev. C 19K 4 Determination of "Important Structures, Systems and Components" for , 1 Level 2 Analysis The Level 2 analyele evaluates the offsite release of fission products following core damage. Those analyses related to the consequences of cora damage vara reviewed, including nource term sensitivity studies, deterministic analysin of plant performance, and containment event trees. Those systems which vould be important with regard to mitigating a core damage event were-considated as potential risk significant SSCs. -The following features were identified: i
- 1. The automatic depressurization system (ADS) The ADS depressurizes the j RPV so that the low pressure systems can inject water. Even~if no water inj accion is available, the depressurization via one safety / relief ' valve (SRV) eliminates the potential for direct containment heating in event of RPV failure. The SRVs are important SSCs for_the ADS since they are the components that function to release steam to reduce' RFV pressure.
- 2. The ac. independent water addition (ACIVA) system _-- The ACIVA system has two major benefits. First, it can inject water into the RPV to prevent core damage or facilitate in vessel recovery. Second, it helps protect the containment by flooding the lower drywell (diverso from LDF) to-cool corium in event of cora melt and vessel failure. The ACIWA system can also be usad to reduce high drywell temperature when operated in the dryvell spray mode.
Also, for e,equences with loss of containment heat removal..the ACIVA
~
system adds thermal mass to the containment, significently delaying the time of rupture disk openin5 The important SSCs for the ACIVA system are the valves and the diesel driven pump, as they provide for the addition of-water to the core and/or dryvell.
- 3. The lower dryvell floodar (LDF) - The LDF system was seleeced.because it-is important in providing cooling for corium released from the reactor vessel and in scrubbing fission products released from the corium in the Amendment __ 12/04/92 19K-8
e en n - 2 t .- l Constal Electric Company . ABVR 4 23A6100AS Standard _Elant _ Jtes, C event all the automatic and manual systems fail to inject water. The LDP fumibia plug valves ara important SScs for the LDP system sinea they provide for flooding of the dryvell floor. 4 The containment overpressure protection system (COPS) .. The COPS is
- - important since it prevents containment failure and assures a fission i product release path through the suppression pool. This serves to limit I
the potential offsite dose after a core damage event. Sequences which { result in slow pressurization will lead to a failurn in the wetwell, as opposed to the drywell. Since the suppression pool scrubs fission
- products before they enter the wetwell air space, this results in a much lower source term than does the case of a dryvell head failure, l The COPS vill also reduce the potential for a class II sequence to lead to
! core damage. The predominant mechanism for core damage in Class II
- sequences is failure of containment or reactor building structures causing damage to long term heat removal equipment. Operation of the COPS directs the gas flow to the stack, preventing damage to the equipment. The COPS SSCs identified by the analysis are the rupture disks, which prevent
! containstent failure and limit offsite doses after core dama5e, the
'* isolation valves, and the flow lines.
t { 5, The RHR system is a primary source of decay heat -removal. Decay haat
- removal is necessary to prevent fission product release from the
! containment in the unlikely event of a severe necident. Also, the dryvell spray function of the RRR is an important feature in limiting the consequences of the Level 2 analysis. The valves of the RHR system that control this spray function are included in rap. The wetvell spray function of the RHR is used for control of bypass leakage by keeping containment pressure lov. It does not play.as important a role in the enalyses performed as does the dryvell spray, so its components vill not be a part of the RAP, l l The RAP activities for important SSCs identified by this Level 2 analysis-are given in Table 19K.11-1. Amendment _ 12/04/92- 19K-9 1 yg-+v quu
.-. m .
General Electric Company i ABVR 23A6100AS ! Standjrd Plant Re d 19K.5 Determination of 'Important Structures, Systeen end Componenta" for I Seismic Analysic The seismic analysis considers the potential for enre damage from plant , damage resulting from a seismic event. The reacita of the seismic analysis identified key features by consideration of those SSCs important to reactor shutdown or to decay heat removal which could potentially be damaged by seismic action. The following featuras were identified as having high confidence, low probability of failure (HCLPF) capacities less than 0.60 , (twice SSE). i ?
- The diesel generators, 480Vac transformers, and motor control centers of ;
the ac power system ! - The batteries, battery racks and inverters of the de power system l - The motor driven pumps, heat exchangers, and room air conditioning units of the service water system
- The motor driven pumps of the high pressure core flooder system 4
i The motor driven pumps of the residual heat removal system !
- The SLC tank and the motor driven pumps of the standby liquid control !
l system , - The motor driven pumps of the fire water system The RAP activities for important SSCs identified by this setemic analysis are given in Table 19K 11 1. B ! . 1 { ' i i i i-Amendment __ 12/04/92 19K 10 j
.s !
4 l_ 4 e _ _ _ ~ _ _ _
yr.m , v. I Cen2rel Elsetric Company- ABWR 23A6100AS Standard Plant _ Rev. C l 19K.6 Determination of "Important Structures , Systema and Components" far i Fire Analysis 4 The fire analysis considers the potential for core damage from plant damage resultin6 from a fire. The important SSCs identified by this analysis are the room fire barriors, Which prevent the fire from spreading to other ! rooms, the smoke renoval system, which maintains pressure differentials .o exhaust smoke rather than allow it to reach other areas, and the remotr shutdown panel and control which are needed following a fire in the control { room or HVAC failure in the control room. The RAP activities for important SSCs identified by this fire analysis are given in Table 19K,11 1.
- 19K.7 Determination of "Important Structures,_ Systems and Components" for Flood Analysis The flood analysis considers the potential for core damage from plant damage resulting from a flood. The important SSCs identified by this analysis are the ECCS room and turbine building / service building water ti 6h t doors, which prevent water from flowing into rooms other than the one with the leak, isolation valves on the reactor sarvice water system, which limit the amount of water spille}}