ML20215J022
| ML20215J022 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 10/20/1986 |
| From: | Wisenburg M HOUSTON LIGHTING & POWER CO. |
| To: | Noonan V Office of Nuclear Reactor Regulation |
| References | |
| ST-HL-AE-1779, NUDOCS 8610240259 | |
| Download: ML20215J022 (44) | |
Text
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The Light Company n.,nsi,,, ugim,,g u.,m m H.,x imi n.,ns,,,,,.,->i anmmn October 20, 1986 ST-HL-AE-1779 File No.: G9.1, G9.17 Mr. Vincent S. Noonan, Project Director PWR Project Directorate #5 U. S. Nuclear Regulatory Commission Washington, DC 20555 South Texas Project Units 1 and 2 Docket Nos. STN 50-498, STN 50-499 Annotated FSAR Revisions Concerning the MSIV Closure Logic - Closure of Confirmatory Item No. 17
Reference:
1.
Letter ST-HL-AE-1265 dated 5/31/85; M. R. Wisenburg to G. W. Knighton 2.
Letter ST-HL-AE-1589 dated 1/23/86; M. R. Wisenburg to V. S. Noonan 3.
Letter ST-HL-AE-1667 dated 5/23/86; M. R. Wisenburg to V. S. Noonan
Dear Mr. Noonan:
In NRC Questions 440.57N and 440.80N, the NRC requested that the South Texas Project (STP) justify the main steam isolation valve (MSIV) closure logic which, at that time, called for automatic MSIV closure upon safety injection (SI) actuation. Responses to these questions were transmitted to the t:RC in References 1 through 3 above.
In reference 3, Houston Lightir.g & Power Company (HL&P) committed that the MSIV closure logic would be modi" 'd to be consistent with other Westinghouse plants.
In addition, HL6P committed to revise the FSAR as necessary to ensure that it accurately reflects the MSIV closure logic.
The MSIV closure on SI has been modified to MSIV closure on a HI-2 containment pressure signal and, from the excessive cooldown protection logic, on a low steamline pressure signal and a low-low T signal.
The MSIV closureonmanualandhighsteampressureratesigESkds will be maintained.
Attached are the annotated FSAR revisions reflecting this change.
These revisions will be incorporated in a future FSAR amendment.
HL&P believes the attached information is sufficient to support the closure of Safety Evaluation Report (SER) confirmatory item no. 17.
8610240259 861020 L1/NRC/er PDR ADOCK 05000498
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Houston Lighting & Power Company ST-HL-AE-1779 File No.: G9.1, G9.17 Page 2 If you should have any questions on this matter, please contact Mr. M. E. Powell at (713) 993-1328.
Very truly yours, M.
ise burg Deputy Proj t Manager MEP/yd
Attachment:
Annotated FSAR Revisions to Chapters 1, 6, 7, 10, 15 and Questions 211.32, 211.52, 440.57N & 440.80N L1/NRC/er
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Houston Lighting & Pbwer Company ST-HL-AE-1779 File No.: G9.1, G9.17 l
Page 3 cc:
-Hugh L. Thompson, Jr., Director _
A. Backus/J. E. Malaski Division of PWR Licensing - A City of Austin Office of Nuclear Reactor Regulation P.O. Box 1088 U.S. Nuclear Regulatory Commission Austin, TX 78767 Washington, DC 20555 J. B. Poston/A. vonRosenberg Robert D. Martin City Public Service Board Regional Administrator, Region IV P.O. Box 1771 Nuclear Regulatory Commission San Antonio, TX 78296 611 Ryan Plaza Drive, Suite 1000 Arlington, TX 76011 Brian E. Berwick, Esquire Assistant Attorney Ceneral for N. Prasad Kadambi, Project Manager the State of Texas U.S. Nuclear Regulatory Commission P.O. Box 12548, Capitol Station 7920 Norfolk Avenue Austin, TX 78711 Bethesda, MD 20814
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Lanny A. Sinkin Claude.E. Johnson Christic Institute Senior Resident Inspector /STP 1324 North Capitol Street c/o U.S. Nuclear Regulatory Washington, D.C.
20002 Commission P.O. Box 910 Bay City, TX 77414 Oreste R. Pirfo, Esquire Hearing Attorney Office of the Executive Legal Director M.D. Schwarz, Jr., Esquire U.S. Nuclear Regulatory Commission Baker & Botts Washington, DC 20555 One Shell Plaza Houston, TX 77002 Citizens for Equitable Utilities, Inc.
c/o Ms. Peggy Buchorn J.R. Newman, Esquire Route 1, Box 1684 Newman & Holtzinger, P.C.
Brazoria, TX 77422 1615 L Street, N.W.
Washington, DC 20036 Docketing & Service Section Office of the Secretary Director, Office of Inspection U.S. Nuclear Regulatory Commission and Enforcement Washington, DC 20555 U.S. Nuclear Regulatory Commission (3 Copies)
Washington, DC 20555 Advisory Committee on Reactor Safeguards T.V. Shockley/R.L. Range U.S. Nuclear Regulatory Commission Central Power & Light Company 1717 H Street P.O. Box 2121 Washington, DC 20555 Corpus Christi, TX 78403 i
L1/NRC/er Revised 10/09/86
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TAME 1.3-2 (Contimed)
SICNIFICANT DESICN OIANCES Refereces Iten EiAR Descriptim of Omnge l
Various coincidence logic changes Sectim 7.2, 7.3 1)
SG low-low wter level reactor trip chsiged from 2/3 to 2/4.
2)
- nabine stop valves closed signal for reactor trip dumend fran m
3/4 to 2/4.
Q m
m 3)
SG higMdgh weer level signal (P-14) for turbine trip and N N
isolatim chmged fran 2/3 to 2/4.
- 4) Turbine trip signals nodified to meet pimt needs.
Ihase B containnent isolation Section 7.3 Signal is no longer used to activate any egifenmt; contimed supply 45 of C01 to the BCPs is desirable and isolation is ruote manual for cignal these isolation valves.
M E uual override of contaimmt Section 7.3 Muual override of contalment isolation signals is no longer permitted; the M
cycrEar sust resat the contaimmt isolation signal to open the valve.
isolation signals v
Main stean Ifne isolation signals Sectim 7.3
'Ihe-SI-signal fa_now.fmetionally-identical-te v c h energmey-borsth "7
aignal-mi-is-used-for-M31Vtiosurer Addition of high steam pressure rate for Mi1V closure below the P.-11 setpoint.
l l
Feedunterisolation/turbinetrip Section 7.3 Addition of SI signal to signals causing N isolatim and turbine trip.
- $>g i
cm Ebel hedling building exhm2st Section 7.3 System is actuated following m SI signal to prwide filtration of any leakage in the EsF ptmp cubicles.
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horfifmy feedwater initiation Sectim 7.3 Raps are now also started on loss-of-offsite power; however, AN regulating valves do not open until SI signal or low-law SG meer i
i signals level signal is received. Capability to block the low-low weer level signal added.
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TABE 1.3-2 (Continued) l SICNIFICANT DEST (N 01ANCES References item FSAR Description of Change Cask Handling System Secticn 9.1.4 Cask handling systen changed frm dry to vet.
Essential cooling water Section 9.2.1 Revision of equipnent served by H31, deletion of SIS /GS ptsup coolers, addition of chiller, etc.
Ocuponent Cooling E ter Syst e Section 9.2.2 Oumge to permit continued operation of CYCS charging ptmps following 1
i SI signal generation. Changed to AVI chenistry.
Sepling Systen Section 9.3.2 Primary and secondary systens have been expanded to meet detailed design systen sanpling needs. Post accident sapling systen has been added.
q.2.84. Y-Cross failed fuel detection Section M
&nitor has been designed to exadne gross activity rather than 0'
,5
- o delayed neutrons.
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RCP seal bypass line Section 9.3.4 Mxlified seal bypass line.
Imtdom filters Section 9.3.4 Added two letdown filters in parallel %_2 of the denineralizers.
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Supplanentary Contairunent Purge Section 9.4 System (except containnent isolation valves) is m longer supplied by Systan Class IE power. Redurriant isolation valves inside containnent are f
no longer supplied.
y> 4 i
Control Rocun and EAB Systen Section 9.4 Renmed " Essential {hillel Eter Systenf' which also serves EAB j
chilled water supply during normal operation, now im'1mh additional areas in MAB p]>I and HIB that require safety class cooling.
m-3 2 i
h el-Handling Building Section 9.4.2 Eliminated the " pool sweep" concept, where supply air is discharged N
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" pool sweep" concept at one side of the fuel pool perineter, swept across the surface, and exhausted in the other side through ventilation boxes to the
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exhmist subsysten.
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TANI 1.3-2 (Com. ire)
SI mIFIC MI DESIQi O W CES References Itm 75AR Description of Oumge Contairmant isolation for steen Section 7.3, 6.2.4 Contaimmt isolation phase A sigial chsiged to AlW initiefm signal generator bloudoun ed saple lines (SI or Ione-low SG water level).
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Electrical penetration space Section 7.3 Syste is no longer actuated by control room emergency ventilation ventileien syste actustion signal, only by SI signal.
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Actuarart equipment lists Section 7.3 Various chages are required to sgport systen design changes.
Radiarim input to contaiment Section 7.3 Input via redtst! ant safety-grade BCB purge isolation senitors.
h 45,,,.
ventilation isoleim l,
Pmr===ive cooldoun ymi a. tion Section 7.3 Block pensissive for excessive cooldoun protection changed fran P-12 block perudasive (Iow-im T to P-11 (pressurfz r precoure).
K h
C Ede ruige M5 preamere Section 7.4, 7.6 Addition of 2 NE wide raise pressure channels. Relocation of 3 4
j nodifications transnitters outside contairement.
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Pbst scetA=it unitorfrg Sect 7.5, Apperulix 7B Upgrade instnmentation to address RG 1.97, Rant. 2.
instri==r**ien t)ialified Display Lcing Section 7.5 Addition of safety-related display processing systm whidt prwides Systen (@PS) redtsidant data acquisition auf display.
> -t-4 lbergency Response Facilities Section 7.5 Prwides signal prnramaing md display for BeerEmcy Qw Facilities M
i Data Acquisition and Display mui addresses SPDS requirement of NURHM)6%.
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E Imedown stop valves Section 7.6 Ovunges to letdown isolation signals.
M -4 i
pressurizer level interlocks i
Reactor coolet purity control Sections 7.6, 9.3.4 Addition of =?'i===ar to meet nere stringent reactor makeg unter l
- k chemistry p= _ ars. Addition of safety grade isolation valves.
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ATTACHMENT STP FSAR ST HL AE-1974 PAGE 4 OF V/
! e 6.2.1.4 Mass and Energy Release Analysis for Postulated Secondary
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System Pipe Ruptures Inside the Containment.
Following a postulated main steam line break or a main feedwater line break inside the f'ontainment, the 4
oftheotherSGswillbeisolatedbythema[insteamisolationvalves(MSIVs) contents of one SG will be released to the ontainment. Most of the contents x
and main feedwater isolation valves.
Containment pressurization following a i
secondary side rupture depends on how much of the break fluid enters the fon-
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tainment atmosphere as steam. Mainsteamlinebreakflowscanbepuresleam or two-phase, while main feedwater line break flows are two-phase. With a i
puresteamblowdown,allofthebreakflowentersthegontainmentvaporspace l
atmosphere. With two-phase blowdown, part of the liquid in the break flow y
boilsoffinthe/ontainmentandisaddedtothevaporspaceatmosphere,while theremainingliquidfallstothesumpandcontributesnothingto/ontainment er pressurization.
For main steam line break cases with large break area, steam cannot escape fast enough from the two-phase region of the ruptured SG, and the two-phase level rises rapidly to the steam line nozzle. A two-phase
' blowdown results. The duration of this blowdown is short, there@orereducing primary-to-secondary heat transfer, and the break flow is largely liquid.
For main steam line break cases with small break areas, steam can escape fast enough from the two phase region of the SC with the ruptured line that the level swell does not reach the steam line nozzle, and a pure steam blowdown results.
Because of the pressure-reducing effects of active and passivegdon-tainmentheatsinks,thehighestpeakgontainmentpressureresultingfroma main steam line break for a given set of initial SC conditions occurs for that 4
case where the break area is the maximum at which a pure steam blowdown can
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occur.
For conservatism, the main steam line break analysis assumed only pure
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steam blowdown for all break sizes and power levels.
l pcoct "cir :::e 117.2 i;;1etien i; initisted en d.; fellering-signals:
SI, high b D
~'~'* m;; t ir: steam-line*preesureWte, (only-below-the-P-11-setpoint), and manualO 49 2
j Main feedwater line isolation is initiated by SC High-High water level, excessive cooldown protection signal, reactor trip in conjunction with low I
Tf0Hy,andSI.
Both the MSIVs and the main feedwater isolation valves are 2
1 closed in 5 seconds, a
j The Auxiliary Feedwater System functions automatically following a secondary 49 system line break to assure that a heat sink is always available to the RCS by j
supplying cold feedwater to the SGs.
For conservatism, it was assumed that the Auxiliary Feedwater System attains full flow to the SG immediately follow-ing feedwater isolation.
In addition, the analysis includes the flashing of the volume of fluid located between the main Feedwater isolation valve and the affected SG.
This fluid then flows through the affected SG and into the 49 Containment.
'Ihe feedwater enters the SG in the two-phase region; ther(fore, main 1
feedwater line break cases always result in two-phase blowdowns through small-l ersizelinesanddonotproducepeak/ontainmentpressuresassevereasmain Y
steam line break cases.
To permit a determination of the effect of main steam line break upon gontain-mentpressure,aspectrumofbreaksizeswasassumedtooccurinsidethegon-l'C tainment, downstream from the integral steam line flow restrictors and up stream of the MSIVs. Unrestricted critical flow from the rupture was assumed.
i 6.2-21 Amendment 49 i
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ATTACHMENT ST-HL AE-l??q PAGE 5 OF 'If Insert D to Page 6.2-21 Main steam line isolation is initiated on the following signals: high-2 containment pressure, low steamline pressure or low-low T-cold (above P-11 setpoint), high negative steamline pressure rate (below the P-il setpoint), and manual, j
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L1/NRC/er
ced.d erd c M pE STP FSAR ATTACHMENT ST-HL AE /7M PAGE h OF 4g 6.2.1.4.1 Mass and Energy Release Data MSLB - Long Term: A complece analysis of main steam line breaks inside fontainment has been performed using X
I the methods described in WCAP-8822, " Mass and Energy Releases following a Steam Line Rupture," R.E. Land. This transient is analyzed by usin," the de-X tailed digital computer code MARVEL (Ref. 6.2.1.4-1).
This code simulates a multi 3oopsystem,neutronkinetics, the pressurizer, feedwater system, SG, x
and SG safety valves. The code computes pertinent plant variables including primary and secondary temperatures and pressures, steam flow and power level during the cooldown. A total of 24 cases covering four power levels, two break sizes and three single failures were analyzed.
Table 6.2.1.4-1 presents the ogss and energy release rate data for the design basis steam line break, 1.4 ft double-ended rupture at hot shutdown with failure of one of the CHRS trains. Among the steam line breaks analyzed, this l49 break results in the maximum containment pressure. Table 6.2.1.4-2 presents the mags and energy release rate data for the design basis steam line break, 1.4 ft double-ended rupture at 102 percent power with failure of one of the CHRS trains. Among the steam line breaks analyzed, this break results in the l49 maximum containment temperature.
All the blowdowns used in the analyses were conservatively assumed to consist of dry steam although considerable entrainment can be expected on the double-ended break.
14 Thesignificantparametersaffectingthemassandenergyreleasestofontain.
Q222K ment following a steam line break are discussed below.
6 6.2.1.4.2 Plant Power Level:
Steam line breaks can be postulated to I
occur with the plant in any operating condition ranging from hot shutdown to full power.
Since SG water mass decreases with increasing power level, breaks l49 occurring at a lower power generally result in a greatcr total mass release to theplantfontainment. However, because of increased energy storage in the primary plant, increased heat transfer in the SGs, and the additional energy generationinthenuclearfuel,theenergyreleasetothe/ontainmentfrom a(
breaks postulated to occur during power operation may be greater than for breaks occurring with the plant in a hot shutdown condition. Additionally, the steam pressure and the dynamic conditions in the SGs change with increas-l49 ing power and have significant influence on the rate of blowdown following a steam line break event.
The power generated in the core due to the cooldown effect from the negative moderator coefficient is included in the analysis for each power level since it adds to the energy released to containment. Because of the opposing effect of changing power level on steam line break mass and energy releases, no single power level can be singled out as a worst case initial condition for a steam line break. Therefore, a spectrum of power levels spanning the operating range (102 percent, 70 percent, and 30 percent),
as well as the hot shutdown condition, has been considered.
6.2.1.4.3 Break Type, Area, and Location:
1.
Break Type There are two possible types of pipe ruptures which must be considered in evaluating steam line breaks.
g 6.2-22 Amendment 49
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ATTACHMENT STP FSAR ST HL-AE 1714 PAGE 4 0FVf
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The first is a split rupture in which a hole opens at some point on the
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side of the steam pipe or steam header but does not result-in a complete severance of the pipe. A single, distinct break area is fed uniformly by all SGs until steam line isolation occurs. The blowdowns from the indi-vidual SGs are not independent since fluid coupling exists between all steam lines. Because of the flow limiting orifices in each SG, the larg-est possible split rupture can have an effective area prior to isolation that is no greater than the throat area of the flow restrictor times the number of plant primary coolant loops.
Following isolation,the effective X,
break area for the SG with the broken line can be no greater than the flow restrictor throat area.
The second break type is the double-ended guillotine rupture in which the steam pipe is completely severed and the ends of the break displace from each other. Guillotine ruptures are characterized by two distinct break locations, each of equal area but being fed by different SGs. The larg-
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est possible guillotine rupture can have an effective area per SG no greater than the throat area of one steam line flow restrictor.
2.
Break Area The breaks analyzed include two break areas (one full double-ended and one split rupture) at each of the four initial power levels, as follows:
Of.,
a.
A full double-ended pipe rupture downstream of the steam line flow restrictor.
For is case, the actual break area equals the cross g4
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brgken line is controlled by the flow restrictor throat area (1.4 06 sectional area of steam line, but the blowdown from the SG with the Q22 ft').
The reverse flow from the intact SGs is controlled by the smaller of the pipe cross section, or the total flow restrictor throat area in the intact loops.
i b.
A split break that represents the largest break which will not gen-erate a steam line isolation signal from the primary protection equipment.
Steam and feedwater line isolation signals will be gen-ersted for these cases,
___eed"byshigh,gontainment A
_.._-._.o....
4 e'
pressurej sign.h, 3.
Break Location.
t l
Break location affects steam line blowdown by virtue of the pressure l4 losses which would occur in the length of piping between the SG and the break.
The effect of the pressure loss is to reduce the effective break area seen by the SG.
Although this ~would reduce the rate of blowdown, it would not significantly change the total release of energy to the don-y, o
tainment.
Therefore, piping Q1oss effects have been conservatively ig-noted in all blowdown results.L delelt spun 6.2.1.4.4 Main Feedwster Addition Prior to Feedwater Line Isolation:
All of the double ended ruptures generate main steam and feedwater isolation signals very quickly following the break.
Isolation of these lines is assumed 1
I to be complete following a time delay sufficiently long to allow for l
1 l
6.2-23 Amendment 49
ATTACHMENT STP FSAR ST HL AE l'F/9 PAGE 8' 0F 41 instrument response time and signal processing delay (2 sec) and valve closing time (5 sec).
For the split ruptures the feedwater line isolation and main steam line iso-j f
t: th; SI '-
X lation signah resultf from t.he>high/ ontainment pressure,irput 4,ignabprotect4ve trip S The fontainment pre sure at which feedwater line and 494 steam line isolation is assumed to occur is 5.5 psig..she-isolation is as-sumed t be comp 1 g e after a time delay of 7.0 sec fter the setpoint is reached
.dwskn ne@a h 4+*u"*A h be ce-e O g%\\ tA8-eC44r. he. deg.4 soswaJ. A.c % sehr.
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Prior to complete isolation, the depressurization of the SG results i gnifi-cant amounts of feedwater being added to the broken loop SG through the main feedwater system. The quantity of feedwater added is conservatively evaluated using the following assumptions:
1.
The main feedwater flow is conservatively calculated assuming the appro-priate number of pumps operating for the power level analyzed and assum-
-ing main feedwater control valves fully open.
2.
Prior to receipt of an isolation signal, all main feedwater control valves maintain the position that exists at " valves wide open" power operation.
14 Q222.
3.
Immediate closure of the feedwater isolation valves and control valves in 06 the intact loops upon receipt of the isolation signal.
4.
No flow reduction through the feedwater isolation valve and control valve j
in the broken loop prior to complete closure (i.e., no credit is taken for decrease in flow during valve closure).
49 5.
The pressure in the intact loop SGs remains at the level existing prior to a double-ended guillotine rupture, while the broken loop SG depressur-izes.
The pressure in the intact loop SGs decays at the same rate as the broken loop generator pressure subsequent to a split rupture.
These assumptions were used along with the Feedwater System hydraulic resistances and pump performance curves to determine the amount of feedwater added to the SG with the broken loop.
6.
(Paragraph deleted).
7.
(Paragraph deleted).
8.
(Paragraph deleted).
9.
(Paragraph deleted).
6.2.1.4.5 Auxiliary Feedwater System Design: Generally;within the first M
minute following a steam line break, the Auxiliary Feedwater System is initi-ated on any one of several protection system signals. Addition of auxiliary g
feedwater to the SGs increases the secondary mass available for release to the
/'ontainment as well as increasing the heat transferred to the secondary fluid.
^
The effects on SG water mass are maximized in the calculation by assuming full I
6.2-24 Amendment 49
eJ:4.w.d
,t ATTACHMENT ST HL-AE /799 STP FSAR PAGE O OF V /
,4 auxiliary feedwater flow to the faulted SG starting at time zero and continu-l'9 ing until manually stopped by the plant operator. Although operator action after 10 minutes following the break is anticipated, it is conservatively assumed in this analysis that auxiliary feedwater is manually terminated after 30 minutes.
The Auxiliary Feedwater System design is such that only one auxiliary feed-water pump feeds each SC.
The maximum flow that can be delivered to a de-pressurized SC is 1210 spa (pump runout flow). This flow is assumed, although the AW flow control valve, in combination with the AW flow element and the Qualified Display Processing System (QDPS); (described in Sections 7.5 and 10.4.9), begin to limit and control A W flow delivered to the SG at approx-49 instely 550 gym.
The mass and energy release data presented are conservatively based on an auxiliary feedvater addition of 1210 gpa to the 50 with the broken line from 0 to 1800 seconds.
Fluid Stored in the Feedwater Piping Prior to Isolation.
The blowdown data were determined assuming a value of 260 fts of unisolated volume in each main feedline.
Fluid Stored in the Steam Piping Prior to Isolation.
All the steam in the steam lines up to the check valves upstream of the tur-14 binesteamchest(6520fts)isassumedtobereleasedtothe[ontainmentfol-loving the break for the case of the main steam line isolation valve (MSIV)
Q2
- failure, 06 1
j Availability of Offsite Power Lors of offsite power following a steam line rupture would result in tripping of the reactor coolant pumps and steam driven main feedwater pumps, and delay of auxiliary feedwater initiation due to standby DC starting and sequencer
~9 loading delays. Each of these occurrences aids in mitigating the effects of the steam line break releases by either reducing the fluid inventory available to feed the blowdown or reducing the energy transferred from the primary cool-ant system to the SGs. Thus, blowdown cases which occur in conjunction with a j
IDOP are less severe than cases where offsite power is available. Therefore, blowdown has been determined assuming offsite power ir available. However, c9
)
for purposes of determining the activation time of the CSS, the main steam 53 i
line breaks are conservatively assumed to occur simultaneously with a IDOP.
Safety System Failures 1.
Failure of Main Feedwater Line Isolation Valve There are two valves in series open during power operation in each feed-water line and beth are designed to close within 7 see after the feed-water isolation setpoint is reached (2 see instrumentation response time including delays and 5 sec valve closing time).
6.2-25 Amendment 53
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sib ed ATYACHMENT, STP FSAR ST.HL-AE 1%
PAGE 10 0F h i
Failure of one valve following a steam line break would increase the ur@solatable feedwate line by the volume between the two valves, which x
)
is assumed to be 80 ft 2.
Failure of Main Feedwater Pump Trip i
No credit is taken for feedwater pump trip and coastdown in calculating main feedwater addition prior to feedwater line isolation. Therefore, this failure has no effect on the results presented.
3.
Failure of a Main Steam Line Isolation Valve Failure of a main steam line isolation valve is assumed to incr' esse ghe volume of steam piping,in the analysiswhichemptiesintothegontainmengby5570ft X
This case is included 14
!ontainment pressures and tem-x The effects of this failure on calculated)f the failure of one fontain-peratures were compared with the effects o x
ment spray train. Withrespecttothemaximum/ontainmentpressure, x
calculations showed that the adverse effects of a main steam line isola-tionvalvefailurewereconsiderablylessthanthatofone/ontainment X
49 spray train failure. Withrespecttothemaximum/ontainmenttempera-t ture, no significant difference was found between the two failures.
4.
Failure of One Containment Heat Removal Train The worst single failure following a steam line break is the failure of one of the three redundant CHRS trains. The spray actuation is assumed 49 tooccur69.1secfollowingthetimeatwhichthegontainmentpressure i
i reaches 22.0 psig. The fan cooler actuation is assumed to occur 30.0 see afterthegontainmentpressurereachesitssetpoint.
r 49 6.2.1.4.6 Deleted.
23 6.2.1.4.7 Short Term Steam Line and Feedwater Line Breaks: The REIAP 5/ MOD 1 (Reference 6.2.1.2-6) computer program was used for the secondary sys-tem pipe break analysis. The initial conditions for the main steam system are taken to be at full power (100 percent) operating conditions (1100 psia and 556.6*F).
Some of the major assumptions made in the analysis, all of them conservatively maximizing the blowdown, are the following:
1.
The postulated high energy line double-ended rupture is assumed to reach its maximum open area (with each pipe end discharging through a break 49 area equal to the internal cross-sectional area of the pipe) within one millisecond of break initiation.
2.
During the course of the ;ransient, the SG pressure and temperature are assumed to remain constant at the initial conditions.
3.
All four main steam isolation valves remain wide open for the duration of the transient. Since the simulation is carried out to 1 second only, the transient will have ended before the MSIVs receive the signal to close.
I 6.2-26 Amendment 52
ATTACHMENT ST HL AE-IT PAGEifAF
/
STP FSAR followedshortlybythegenerationofanSIsignal[,initiatedbylow 2
pressuriser pressure. The SI signal automatically terminates normal feedwater supplyMeotatec--ee --in ei--- isolet-ion-walee] and initiates auxiliary feedwater addition.' After reactor trip the break flow reaches equilibrium at the point where incoming safety injection flow is balanced by outgoing break flow. The resultant brea~k flow persists from plant trip for a period of time (dependent on break size and here assumed to be 30 minutes) during which the recovery procedure to isolate the affected steam generator is implemented.
36 bc The reactor trip automatically trips the turbine and if offsite power is 4
available,(Oie'-enaffe?M*-- fir.2Mn=cenfunctionM)the ateam dump
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W
' valves h M M ^;:::d to allow steam blowdown to the condenser. In the event of a coincident Loss of Offsite Power (LOOP)4the steam dump valves 51 would automatically close to protect the condenser. The SG pressure would rapidly increase,resulting in steam discharge to the atmosphere through the SG safety Tnd/or power-operated relief valves.
5.
Following reactor trip, the continued action of auxiliary feedwater sup-ply and borated safety injection flow (supplied from the RUST) provide a heat sink which absorbs some of the decay heat. Thus, steam bypass to the condenser, or in the case of loss of offsite power, steam relief to atmosphere, is attenuated during the period in which the recovery proce-dure leading to isolation is being carried out.
6.
Safety injection flow results in increasing pressurizer water level. The time after trip at which the operator can clearly see returning level in C
the pressurizer is dependent upon the amount of, operating auxiliary equipment, and operator actions to cooldown and depressurizer the RCS.
Results and Conclusions of Steam Generator Tube Rupture A steam generator tube rupture will cause no subsequent damage to the RCS or the reactor core. An orderly recovery from the accident can be completed even assuming simultaneous loss of offsite power.
Criteria Used To Judge The Adequacy of The ECCS 10CFR50.46 provides the following criteria to judge the adequacy of the ECCS.
1.
Peak clad temperature calculated shall not exceed 2200*F.
2.
The c.alculated total oxidation of the clad shall nowhere exceed 0.17 times the total clad thickness before oxidation.
3.
The calculathd total amount of hydrogen generated from the chemical reac-tion of the dad with water or steam shall not exceed 0.01 times the hypothetical amount that would be generated if all of the metal in the clad cylinders surrounding the fuel, excluding the clad around the plenum volume, were to react.
4.
Calculated changes in core geometry shall be such that the core remains amenable to cooling.
6.3-19 Amendment 51 1
e-m
-- e e,-
,,,,,a,
ATTACHMENT ST HL hE I'Yl4 STP FSAR PAGE /G OF 4f/
TABLE 7.1-2 (Continued)
-(
DIFFERENCES FROM REACTOR TRIP SYSTEM (Continued)
COMANCHE PEAK NUCLEAR STATION 8.
Source Range Flux Detector 8.
On Comanche Peak, each source Energization (Figure 7.2-3) range flux detector is ener-gized and de-energized by logic output from a single train (the two detectors are on separate trains). On STP, to de-energize each detector, outputs from both A and B actu-ation trains are used; to energize each detector, output from either actuation train (A or B) is used.
ENGINEERED SAFETY FEATURES ACTUATION SYSTEMS 1.
Interlock P-15 1.
Comanche Peak does not provide (Figure 7.2-4) a P-15 signal.
On STP, the F-15 signal is developed from P-4 (reactor tripped) or 2/4 power range detectors showing neutron flux below setpoint.
/
P-15 is used as an interlock in
(
excessive cooldown protection logic 44 (Figure 7.2-9).
2.
Steam Generator High-High 2.
Four channels are used for each Water Level Signal SG (2/4 logic) on STP; three (Figure 7.2-7) channels are used for each SG (2/3 logic) on Comanche Peak.
3.
Main Steam Line Isolation 3.
Automatic actuation signals k
Initiation (Figure 7.2-8) for Comanche Peak are high negy +C steam pressure rate, low steamlino pressure and SWE k ContainmentHI-2 pressure,)
4,[for STP are-highet:utomatic::tt-tien/ signa 2 "- hel d t c. OT.
{
L ald:be. b %e-H. &~t. Q^'{hi een C"
.pressur m t* mnd caf a hj inject-iof k signal--(which i: ecewaeed Lj Ic. b i
st-eam14ns--pre==m.) -ud Centoimcui HI-1 pressure as weit as otiie s signals).
Note that ::tpoint1H2 for n! - 1 and-H' " -- ^'
it the reep;utiv. pl.uts.4-(
7.1-32 Amendment 49
ATTACHMENT ST HL-AE-M79 PAGE 13 OF # /
Typical maximum allowable time delays in generating the actuation signal 3
for secondary system break protection, in addition to the above, are:
,,,f' a.
Steam line pressure (from which 0.6 seconds steam line pressure rate is also derived and to which add 0.5 sec) 5.0 seconds with flow b.
Tcold (direct immersion in cold 78% of nominal and leg) straight line to 10 43 seconds at zero flow.
c.
Actuation signals for auxiliary 2.0 seconds feedwater pumps (steam generator water level) d.
Primary loop flow 1.0 seconds e.
Feedwater flow 2.0 seconds 3.
The time delay in generating the Containment ventilation signal for a fuel handling accident inside Containment is the total of the time delay in the radiation monitors and the time delay in the Solid-State 43 Protection System to generate the Containment ventilation isolation signal. The maximum allowable time delay is 3.0 seconds for the design 53 basis release analyzed in Section 15.7.
7.3.1.1.5.6.2 System Accuracies -
1.
Typical accuracies required for generating the required actuation 43 signals for Reactor Coolar:t System break protection are:
a.
Pressurizer pressure (uncompensated) 114 psi f
0 7
b.
Containment ($I 1) pressure 11.8 percent of full scale 2.
Typical accuracies required in generating the required actuation signals for secondary system break protection, in addition to the above, are:
a.
Steam line pressure 12.5% of span 43 b.
T A
cold Actuation /ignalsforauxiliary c.
43 feedwater pumps (steam generator 12.3 percent of span water level) d.
Primary loop flow 12.75% AP span 13 7.3-8 Amendment 53
~
ST-HL-AE-1794 q '
PAGE/4 OF 41 TABLE 7.3-2 INSTRUMENTATION OPERATING CONDITION FOR WESTINGHOUSE ESFAS 43 No. of No. of Channels No.
Functional Unit Channels To Trip 43 1.
Safety Injection Signal (See Figures 7.2-8 and 7.2-9) a.
Manual 2
1 b.
HI-1 Containment pressure 3
2 h3 c.
Low compensated steam line 12 (3/ steam 2/3 in any steam pressure
- line) line h3 d.
Pressurizer low pressure
- 4 2
e.
Low-low compensated T 12 (3/ loop) 2/3 in any loop Id (interlocked with P-137 A h3 2.
Containment Spray Signal (See Figure 7.2-8) h3 s
a.
Manual **
2 1
g) b.
Containment pressure 4
2 HI-3 3.
Auxiliary Feedwater Initiation 43 Signal a32.1 (See Figure 7.2-16)
Safety Injection Signal See item 1 of this table a.
b.
Steam generator low-low 16 (4/SG) 2/4 in any SG water level
- Permissible bypass if reactor coolant pressure is less than P-11 (nominally 43 1900 psig).
- Manual actuation of Containment spray is accomplished by actuating either of two sets (two switches per set). Both switches in a set must be actuated to obtain a manually initiated spray signal. The sets are wired to meet separation and single-failure requirements of IEEE 279-1971. Simultaneous operation of two switches is desirable to prevent inadvertent spray actuation.
1 7.3-31 Amendment 43
ATTACHMENT ST HL-AE #194 STP FSAR PAGEISOFV/
TABLE 7.3-2A FUNCTIONS / SYSTEMS ACTUATED BY WESTINCHOUSE ESFAS SIGNALS SAFETY INJECTION SIGNAL CONTAINMENT SPRAY SICNAL Reactor Trip System Containment Spray System 43 Turbine Trip Containment Isolation Phase B (no actuated equipment)
Feedwater Isolation Auxiliary Feedwater System Main-Steam--Line-Isolation-@
AUXILIARY FEEDWATER INITIATION SIGNt.L 43 Standby Diesel Generators Auxiliary Feedwater System Q32.16 Component Cooling Water System Steam Generator Blowdown Isolation Safety Injection System Steam Generator Sample Isolation Essential Cooling Water System Reactor Containment Fan Coolers (rlata STVMMLTMF M#
, _L J
.a
~
e' w-e, Containment Isolation Phase A
~ '/
yp sb t.m G7 '5 43 Containment Ventilation Isolation gA h th6d b
Control Room Envelope HVAC System EAB Main Area HVAC System FHB HVAC Exhaust Subsystem ESF Ioad Sequencers Essential Chilled Water System 53 Electrical Penetration Space HVAC System
~
7.3-32 Amendment 53 l
~
ATTACHMENT ST HL-AE Mr19 STP FSAR
.-PAGE /t, OF #f TABLE 7.3-3 INSTRUMENT OPERATING CONDITIONS FOR ISOIATION FUNCTIONS No. of No. of Channels No.
Functional Unit Channels To Trip 1.
Containment Isolation Phase A (See Figure 7.2-8) a.
Safety Injection See item 1 (a through e) of Table 7.3-2 b.
Manual 2
1 2.
Steam Line Isolation (See Figure 7.2-8) 43 a.
High steam 12 (3/ steam line) 2/3 in any pressure negative rate steam line (enabled by Excessive 53 Cooldown Protection SI Block - see Figure 7.2-9) o b.
Safety Injection See item 1(p)a.ad(c) e e :;#. ?
of Table 7.3-2 J.
Manual
- 2 1
f e /. C-.A :n 4.d-P<usace E-1
.3 1
3.
Feedwater Line Isolation (See Figures 7.2-8 and 7.2-14) a.
SC hi-hi water level 16 (4/SC) 2/4 in any SG b.
Safety Injection See item 1 (a through e) of Table 7.3-2 c.
Low compensated 12 (3/ loop) 2/3 in any loop Teold
.\\
(interlocked with P-15)
^#
(
1,o c.4;W su rJ $,,#
'2 O/ wiQ 24. % 4 54*
6.
c. t.w - w e.,as U re.w*
t2.(n4 1,$ 4 me, G 4lec4.cl d u. A P-tS) p
- In addition to the two system level steam line isolation switches, each steam loop is provided with switches to effect steam line isolation in that loop.
c M
- E '* h I5 I"3 N~ F-f I (^ * '"'
f+ (e,mtss;ldt 3;[reuke P
l% at?
7.3-33 Amendment 53
,y
- - ~ -
.---..,.--..._e._
,... - -., _ - -. - _.. _. -. -.. - - -. - -, - -, - ~.. -
ATTACHMENT qC ST HL AE 1974 PAGE sq0F 41 STP FSAR TABLE 7.3-4 (Continued)
(
INTERLOCKS FOR ENGINEERED SAFETY FEATURES ACTUATION SYSTEM Function Designation Input Performed
- l. 3 P-12 2/4 T below low-low Pr'esence of P-12 blocks 4
ratpoinE steam dump except for cooldown condenser dump valves Presence of P-12 allows l'
manual bypass of steam. dump block for the cooldown valves only P-14 2/4 SG water level above Presence of P-14 closes all setpoint on any SG FW control and bypass valves Presence of P-14 trips all main FW pumps and closes all FW isolation and bypass valves 43 Presence of P-14 actuates turbine trip
(
P-15 Reactor trip (P-4) or 2/4 Presence of P-15 allows S1 neutron flux (power-range)
_ actuation,on low-low T old below setpoint and allows FW isolation and turbine trip from low f
compensated T r high FW old
/
flow e
{ M-.! --,.,
n, s> & )
\\M
\\
{
l 1
7.3-36 Amendment 43
1 y
TABLE 7.3 S (Continued) l i
SAFETY INJECTION ACTUATED EQUIPMENT LIST l
J EQUIP.
ESF FICURE PAID LOCIC SYSTQ1 IDENTIF DESCRIPTION TRAIN FUNCTION NURSER NUMBER NURSER 1
i l
SI FV-3936 SwST TO SFPCCS ISOLATION VALVE A
CLOSE 6.3-1 9 FOS 013 242004 St FV-3937 RWST TO SFPCCS ISOLATION VALVE B
CLOSE 6.3-1 9 FOS 013 242004 SI HMSI PUNP 1A MIGN MEAD SAFETY INJECTION PUNP 1A A
STARTe 6.3-1 9 FOS 013 242000 SI HMSI PunP 18 MICM HEAD SAFETY INJECTION PUMP 19 R
STARTe 6.3-2 9 FOS 014 242000 2
i SI HMSI PUNP 1C NICH HEAD SAFETY INJECTION PURP 1C C
STARTS 6.3-3 9 FOS 01S 242000 SI LMSI PUNP 1A LOW HEAD SAFETY INJECTION PUMP 1A A
STARTe 4.3-1 9 FOS 013 242000 SI LHSI PunP 18 LOW MEAD SAFETY INJECTION PUMP 18 h
STARTe 6.3-2 9 FOS 014 242000 SI LMSI PUNP IC. LOW HEAD SAFETY INJECTION PUMP 1C C
STARTe 6.3-3 9 FOS 015 242000 i
SI XS100394 ACCUMULATOR DISCHARGE ISOLATION VALVE A
OPEN 6.3-4 9 FOS 016 242028 y
q SI XSIOO398 ACCUMULATOR DISCHARGE ISOLATION VALVE B
OPEN 6.3-4 9 FOS 016 242024 i
SI XSICO39C ACCUNULATOR DISCHARCE ISOLATION VALVE C
OPEN 6.3-4 9 FOS 016 242024 SP DG 11 BRNR STANDSV DIESEL CENERATOR FEEDER BREAMER A
SEE FIC. a.3-4SN3 NONE 242121 l
SP DG 12 BRNR STANDSV DIESEL CENERATOF "EEDER BREANER S
SEE FIG. a.3-4SN3 NONE 242121 l
l SP DG 13 BRNR STANDtY DIESEL CENERATOR FEEDER BREANER C
SEE FIG. 4.3-4SN3 NONE 242121 DO i
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SP SEOUENCER 1A ESF LOAD SEOUENCER A
START 4.3-4SN2 NONE 242117 O H m >
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SP SEOUENCER 1h ESF LOAD SEOUENCER S
START e.3-4SN2,NONE 242114
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SP SEOUENCER SC ESF LOAD SEOUENCER C
START 4.3-4SN2 NONE 242113 O--m k
M2 d-4 s
s
- Actuation le through the ESF 1eed sequencer.
n
- Equipment not directly actueted ESFAS signet.
Actuation le from equipment directly actuated.
w f
See" $ N'Tobie5 7.3-7. 7.3-9 7.3-11. 7.3-15. 7.3-17 and 7.3-18 Sofety injection signal le used as en input to algnete actuatin equipment listed in those tables.
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ATTACHMENT ST-HL-AE-I??q PAGEdL50F yr 1
10.3.2.4 Power-Operated Relief Valves (PORVs). The PORVs, one for each MS line, are required for removal of heat from the Nuclear Steam Supply System (NSSS) during periods when the condenser is not available as a heat sink or when the MSIVs are closed.
The valves are ASME Class 2 and are supplied with 39 Class IE power.
The design mass flowrate of each PORV (one per SG, four total) is 68,000 lb/hr l54 saturated steam at 100 psia. The wide open condition does not exceed 1.05 x 108 lb/hr at 1,300 psia. The valve design is in accordance with ASME B&PV Code,Section III, Subsection NC and has a body design pressure and tempera-ture of 1,285 psig and 600*F, respectively. The operation of these valves is not required to protect against SG overpressure or to provide the necessary safety relief capacity.
The PORVs, which are equipped with electric-hydraulic actuators and controlled through the Qualified Display Processing System (QDFS) discussed in Section 53 7.5.6, are set to open below the lowest SG safety valve setting to preclude the operation of safety valves during transients when the condenser is unavailable as a heat sink. The opening of the valves is automatic, based l39 upon steam line pressure. A remote pressure control station is provided for each PORV to permit setpoint adjustments of each valve over the entire pressure range up to the safety valve setting. Remote manual operation is provided for a safe shutdown at the control room and at the auxiliary shutoown panel.
Local control is provided in case of complete loss of automatic control. Direct position indication is provided, with input also to the QDPS 39 computer.
r 10.3.2.5 Main Steam Isolation Valves.
The MSIVs are located in each MS line downstream of the FORV, and as close to the RCB as practical (see Figure 10.3-1).
A small bypass valve at each isolation valve is provided for startup purposes.
Steam is conducted from each SG in a separate line through the RCB, each line being anchored at the Containment wall. Main steam line anchorage is covered in Section 3.8.1 and Containment isolation in Section 6.2.4.
The lines have the capability to absorb thermal expansion. Testing of the MSIVs is discussed l39 in Section 14.2.3.1.
pet The MSIVs and bypass isolation valves are provided withj remote manual con-trols. Automatic signals which close the MSIVs and the small bypass isolation V
Pvalves arq(the ::f;ty inj;;tien (SI) si i.;I :nd the high steam 3 pressure rate 39 signals.(e. See wion 7.5 fus oign:1: initiating the SI sign:1)L-The MSIVs use jpistonactuatorsandthebypassvalvesusediaphragmactuators. The valves are held open by instrument air pressure on the bottom of the actuator.
Spring pressure on the actuator acts as the driving force for valve closure.
The MSIV logic is shown in Figure 7.3-18.
To assure safety function actua-39 tion, redundant actuation solenoid vent valves, powered from separate Class lE Q32.11 power sources, open to vent air from the bottom of the piston actuator through Q32.34 two separate vent lines. Remote valve position indications are provided in the control room. An annunciator located in the control room alarms on MSIV l
closure.
g m (o k. E peeaart,IoM W Ust-te m s * % L **' ' l'"' N' A
- 10.3-4 Amendment 54
.~
I i
TABLE 15.0-6 FLANT STSTEMS AND EQUIPMENT AVAILA31.E FOR TRANSIENT AND ACCIDENT CONDITIONS
~
Reactor Trip Functions ESF Actuation Functions Other Equipment ESF Equipment Tncident y,
15.1 Increase in Nest Removed by the Secondary Systees Feedwater systees Fower range high flux.
High-high steam Feedwater toolation Auxiliary Feedwater Systes
[
ealfunctione causing oveOeuperature AT.
generator water level-valves, stese generator
- 3 m an increase in feed-overpower AT. eenval produced feedwater safety valves m
toolation and turbine water flow 4
trip L
g" Excessive increase in Power range high flux.
Fressuriser safety valves.
f3
?
steam isolation valves, w
secondary steam flow overtemperature AT.
overpower AT annual Inadvertent opening of Low pressuriser Low-low compensated Feedwater teolation valves.
Aux 111ery Feedwater System, a steam generator re-pressure, safety injec-T low preneuriser main etese isolation valves Safety injection Systen p
lief or safety valve tion signal. overten-pfINdre.Iowcompen-r,3 perature AT. overpower mated steen line pres-AT. power range high sure annual flux. annual l18 Steam systen piping Low pressuriser Low-low compenested Feedwater isolation valves.
Auxiliary Feedwater System.
l3 fatture pressure, safety injec-T low pressuriser main stese isolation valves Safety Injection System tion signal. power pfENdre.Iowcompen-range high flux, mated steam line pres-p K
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.)
ne ressure Main Steam Isolation Safety Injection System.
Conta:
a) 1.arge Break Containment (HI-l[4and HT-3). Low Valves, Feedwater Reactor Containment Fan 43 Pressure (HI-1) pzessuriser pressure-Toolation valves. Steam Coolere. Containment Spray Generator Safety Valves Systen O
b) Small Break Low Pressuriser Low Freenuriser Main Steam Isolation Safety Injection System.
Fresente Pressure Valves. Feedwater Isolation Auxiliary Feedwater System y
p Valves. Steam Cenerator sa N
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- ;l gl ACCIDENTAL DEPRESSURIZATION OF THE MAIN STEAM SYSTEM Figure 15.0 9 Amendment 43
ATTACHMENT ST HL-AE.lge}9 PAGE.1370F V/
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HIGH 2 2/3 CONTAINMENT PRESSURE LOW ETEAM LINE 2/3 3
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ATTACHMENT ST HL AE l'M ~
b.
Excessive cooldown protection (2/3 low compensated steamline 55 pressure from any SG or 2/3 low-low compensated T-cold in any loop) l 2.
Reactor trip will occur from either; a) high neutron flux, b) overpower 43 AT, c) two out of four low pressurizer pressure signals, and d) receipt of an SI signal.
3.
Redundant isolation of the main feedwater lines: sustained high feed-water flow would cause additional cooldown. Therefore, in addition to 55 the safety injection signal, an excessive cooldown protection signal vill rapidly close all feedwater control valves and feedwater isolation valves jg3 and trip the main feedwater pumps.
I 4.
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A block diagram summarizing various protection sequences for s'afety actions 2
required to mitigate the consequences of this event is provided in Figure Q211 15.0-9.
Systems and equipment which are available to mitigate the effects of the acci-dent are also discussed in Section 15.0.8 and listed in Table 15.0-6.
15.1.4.2 Analysis of Effects and Consequences.
Method of Analysis The following analyses of a secondary system steam release are performed for this section:
1.
A full plant digital computer simulation using the LOFTRAN (Ref. 15.1-1) code to determine RCS temperature and pressure, during cooldown, and the effect of safety injection 3
2.
Analyses to determine that there is no consequential damage to the' core or. reactor coolant system.
The following conditions are assumed to exint at the time of a secondary sys-tem steam release:
(2 1.
End-of-life shutdown margin at no-load, equilibrium xenon conditions, and with the most reactive RCCA stuck in its fully withdrawn. position. Oper-ation of RCCA banks during core burnup is restricted in such a way that addition of positive reactivity in a secondary system steam release acci-dent will not lead to a more adverse condition than the case analyzed.
2.
A negative moderate coefficient corresponding to the end-of-life rodded core with the most reactive rod cluster control assembly in the fully withdrawn position. The variation of the coefficient with temperature 16 and pressure is included. The k fp versus temperature at 1000 psi i
corresponding to the negative mo84tator temperature coefficient used is j
15.1-9 Amendment 55
ATTACHMENT STP FSAR ST-HL-AE IM9 PAGE M OF 4l The analysis of a main steam line rupture is performed to demonstrate that the following criterion is satisfied:
Assuming a stuck RCCA, with or without offsite power, and assuming a 3
single failure in the SIS, the core remains in place and intact.
Although DNB and possible clad perforation following a steam pipe rupture are not necessarily unacceptable, the analysis, in fact, shows that no DNB occurs for any rupture assuming the most reactive assembly stuck in its fully with-drawn position.
A major steam line rupture is classified as an ANS Condition IV event (see Section 15.0.1).
The major rupture of a steam line is the most limiting cooldown transient and, thus, is analyzed at zero power with no decay heat. Decay heat would retard the cooldown thereby reducing the return to power. A detailed analysis of
~ this transient with the most limiting break size, a double-ended rupture, is presented here.
The following functions provide the necessary protection for a steam line rupture:
2 1.
Safety injection actuation from either:
a.
Two out of four low pressurizer pressure b.
Excessive cooldown protection (Two out of three low compensated steamline pressure from any SG or two out of three low low compensated T-cold in any loop) 2.
The overpower reactor trips (neutron flux and AT) and the reactor trip 44 occurring in conjunction with receipt of the SI signal.
3.
Redundan'. isolation of the main feedwater lines: rustained high feed-water flow would cause additional cooldown. Therefore, in addition to the safety injection signal, an excessive cooldown protection signal will rapidly close all feedwater control ~ valves and feedwater isolation 43 valves, as well as trip the main feedwater pumps.
4.
Closure :f the fret ecting " iu L Isolatien Velves-(MSIV)- (designed-Q-4
-i.u close-in 1::: th:n 5 ; econ".) h um either: ?
l 9
a.
S ef-ty indeet-ien -uuacion tr---High-negaelve :::
pressure rete in-any-loop-fbelow-Permissive-C _
r-ii ) ' ^
Fast-acting isolation valves are provided in each steam line that will fully close within 10 seconds of a large break in the steam line. For breaks down-stream of the isolation valves, closure of all valves would completely termi-nate the blowdown. A descriptica of steam line isolation is included in 43 Chapter 10.
[
Design criteria and methods of protection of safety related equipment from the dynamic effects of postulated piping ruptures are provided in Section 3.6.
15.1-12 Amendment 44
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STP FSAR ATVACHMENT ST-HL-AE- /~779 PAGE 30 0F g/
The core parameters used for each of the two cases correspond to values determined from the respective transient analysis.
Both the cases above assume initial hot shutdown conditions at time zero since this represents the most pessimistic initial condition. Should the reactor be just critical or operating at power at the time of a steam line break, the reactor will be tripped by the normal overpower protec-tion system when power level reaches a trip point. Following a trip at power the RCS contains more stored energy than at no-load, the average coolant temperature is higher than at no-load and there is appreciable energy stored in the fuel. Thus, the additional stored energy is removed via the cooldown caused by the steam line break before the no-load condi-tions of RCS temperature and shutdown margin assumed in the analyses are reached. After the additional stored energy has been removed, the cooldown and reactivity insertions proceed in the same manner as in the analysis which assumes no-load condition at time zero.
-7.
In computing the steam flow during a steam line break, the Moody Curve (Ref. 15.1-3) for f(L/D) = 0 is used.
8.
Perfect moisture separation in the steam generator is assumed.
Results The calculated sequence of events for all cases analyzed is shown in Table 5.1-1.
(-
The results presented are a conservative indication of the events which would occur assuming a steam line rupture since it is postulated that all of the conditions described above occur simultaneously.
Core Power and Reactor Coolant System Transient Figures 15.1-15 through 15.1-17 show the RCS transient and core heat flux following a main steam line rupture (complete severance of a pipe) at initial no-load condition (case a).
Offsite power is assumed available such that full reactor coolant flow exists. The transient shown assumes an uncontrolled steam release from only one steam generator. Should the core be critical at near zero power when the rupture occurs, the initiation of safety injection by l2 low steam line pressure will trip the reactor. Steam release from more than A h
=et4ag h --* one steam generator will be prevented by automatic el:: re ef --t
=
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of one valve, release is limited to no more than 10 seconds from the other steam generators while the one generator blows down. The steam line stop valves are designed to be fully closed in less than 5 seconds from receipt of a closure signal.
As shown in Figure 15.1-17, the core attains criticality with the RCCA's 3g inserted (with the design shutdown assuming one stuck RCCA) shortly before boron solution at 2,500 ppe enters the RCS. A peak core power less than the h
nominal full power value is attained.
The calculation assumes the boric acid is mixed with and diluted by the water
[\\
flowing in the RCS prior to enterin'g the reactor core. The concentration 15.1-15 Amendment 43
ATTACHMENT ST-HL-AE /774 PAGE e l 0F Vi Insert A to Pg. 15.1-9 J
4.
Closure of the fast-acting main steam isolation valves (MSIVs) (designed to close in less than 5 seconds) from either a a.
Low steamline pressure or low-low T-cold signal (two out of three in any loop) above the P-11 setpoint, or b.
High negative steamline pressure rate signal (two out of three in any loop)-below the P-ll setpoint.
Insert B to Page 15.1-2 4.
Closure of the fast-acting main steam isolation valves (MSIVs) (designed to close in less than 5 seconds) from either a a.
High-2 containment pressure signal, b.
Low steamline pressure or low-low T-cold signal (two out of three in any loop) above the P-ll setpoint, or c.
High negative steamline pressure rate signal (two out of three in any loop) belew the P-ll setpoint.
Insert.C to Page 15.1-15
... closure of the fast-acting isolation valves in the steamlines via the low steam line pressure signal.
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ATTACHMEN ST HL-AE 11 PAGE JA.0F l
7.
The worst possible break area is assumed. This maximizes the blowdown discharge rate following the time of trip which maximizes the resultant heatup of the reactor coolant.
J 8.
A conservative feedwater line break discharge quality is assumed prior to the time the reactor trip occurs, thereby maximizing the time the trip setpoint is' reached. After the trip occurs, a saturated liquid discharge is assumed until all the water inventory is discharged from the affected steam generator. This minimizes the heat removal capability of the affected steam generator.
9.
Reactor trip is assumed to be actuated when the low-low steam generator water level trip setpoint minus 10 percent of narrow range span in the 43 affected steam generator is reached.
32 10.
The A W is actuated by the low-low steam generator water level signal.
The AW is assumed to supply a total of 540 gal / min to one intact steam Q211.
generator. A 60-second delay was assumed following the low-low water 74 level signal'to allow time for startup of the standby diesel generators and the auxiliary feedwater pumps. An additional 83 seconds was assumed 43 before the feedwater line was purged and the relatively cold (120*F) auxiliary feedwater entered the intact steam generator.
11.
No credit is taken for heat energy deposited in RCS metal during the RCS heatup.
12.
No credit is taken for charging or letdown.
13.
Steam generator heat transfer area is assumed to decrease as the shell-side liquid inventory decreases.
14.
Core residual heat generation is based on the 1979 version of ANS 5.1 54 (Reference 15.2-6).
ANSI /ANS-5.1-1979 is a conservative representation of the decay energy release rates.
15.
No credit is taken for the following potential protection logic signals to mitigate the consequences of the accident:
a.
High pressurizer pressure b.
Overtemperature AT c.
High pressurizer level d.
High Containment pressure Receiptofalow)-lowsteamgeneratorwaterlevelsignalinatleastonesteam generator starts the motor-driven and turbine-driven auxiliary feedwater pumps, which in turn initiate auxiliary feedwater flow to the steam genera-tors.
Similarly, receipt of a low steamline pressure signal in at least one steamline initiates
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15.2-15 Amendment 54
ATTACHMENT ST HL AE 1779 PAGE 33CF LII STP FSAR origin. Activity in the steam and power conversion system is subject to
)
continual surveillance and an accumulation of minor leaks which exceed the limits established in the Technical Specifications is not permitted during the unit operation.
Due to a series of alarms, as described below the operator will readily deter-mine that a SG tube rupture has occurred, and identify and isolate the faulted l45 steam generator. The isolation procedure can be completed within 30 minutes of accident indication and ensures that break flow to the secondary system is l45 terminated before water level in the affected SG rises into the main steam pipe. Sufficient indications and controls are provided to enable the operator to carry out these functions satisfactorily.
Assuming normal operation of the various plant control systems, the following sequence of events is initiated by a tube rupture:
1.
The condenser vacuum pump discharge radiation monitor will alarm, indi-45 cating a sharp increase in radioactivity in the secondary system. In addition, indication will be available from the steam line and SG blowdown radiation monitors.
2.
Pressurizer low pressure and low level alarms are actuated and charging flow increases in an attempt to maintain pressurizer level. On the sec-- l 45 ondary side there is a steam flow /feedwater flow mismatch before trip as feedwater flow to the faulted SG is reduced due to the RCS break flow l 45 which is now being supplied to that unit.
i 3.
Continued loss of reactor coolant inventory leads to a reactor trip sig-nel generated by low pressurizer pressure. Resultant plant cooldown following reactor trip leads to a rapid change of pressurizer level. A l 45 safety injection (SI) signal, initiated by low pressurizer pressure, follows soon after the reactor trip. The SI signal automatically ter-minates normal feedwater supply and initiates auxiliary feedwater addition. -Alsa ; th=41-signal-au;u iluolly closes-all-main-steam-<
45 4soistion-valve. (iiSIV ).-
4.
The reactor trip automatically trips the turbine and if of site power is A
available, the-enaff::::d ::: - 112::. in csajusilm. cith he steam dump In the 45
'valvespiffopene#To allow steam blowdown to the condenser.
'i event of a coincident Loss of Offsite Power (LOOP) the steam dump valves would automatically close to protect the condenser. The SG pressure would rapidly increase resulting in steam discharge to the atmosphere through the SG safety and/or power-operated relief valves.
5.
Following reactor trip, the continued action of auxiliary feedwater (AFW) supply and borated SI flow (supplied from the refueling water storage tank) provide a heat sink which absorbs some of the decay heat. Thus, steam bypass to the condenser or in the case of a LOOP, steam relief t 45 atmosphere from the faulted SG is attenuated during the 30 minutes in which the recovery procedure leading to isolation is being carried out.
i 15.6-6 Amendment 45
ATTACHMENT ST-HL-AE !??9 PAGE F/OF 4 /
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Dump steam to the I:ondenser from the unfaulted SGe at a maximum rate to establish subcooling margin for subsequent RCS depressurization. The amount of RCS cooldown is deter.nined by the faulted SG pressure.
5.
Decrease RCS pressure by use of pressurizer spray valves until the water level returns in the pressurizer and RCS pressure and faulted SG pressure are equal.
45 6.
Based on pressurizer water level, secondary heat sinks, RCS subcooling, and increasing RCS pressure, stop the SI pumps and all but one charging pump to minimize break flow to the secondary system. At this point, RCS pressure and faulted SG pressure should be maintained approximately
- equal, uA40 7.
Continue dumping steam to the condenser from thegeehet*SGs and simulta-neously decrease RCS pressure by use of pressurizer spray valves.
Decrease pressure in the faulted SG by backfill, blowdown, or steam release.
8.
Initiate operation of the Residual Heat Removal System (RHRS).
With a LOOP:
1.
Manually regulate AFW flow to SGs to maintain a minimum on-scale water level.
Identify the faulted SG by rising water level. Stop AFW flow to the faulted SG.
2.
The SG pressure will rapidly increase resulting in steam discharge to the atmosphere through the SG safety and/or PORVs. 6 team-wi-14-be dumped-f-romC'-
=stablish-no-load--reactor-cor. r _, -
-the-safet: eraalief velves ta
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(_ n es e. s e.
3.A/solateallvsteampathsfromthefaultedSG.
7 e% r-Dump steam through the unfaulted SGs' -sefetyMrelief valves at maximum 4.
rate to establish subcooling margin for subsequent RCS depressurization.
The amount of RCS cooldoun is determined by the faulted SG pressure.
'5 4
5.
Open the safety grade pressurizer relief valve to reduce RCS pressure until water level returns in the pressurizer and RCS pressure and faulted SG pressure are equal.
6.
Based on pressurizer water level, secondary heat sinks if any, RCS sub-cooling, and increasing RCS pressure, stop SI pumps and all but one charging pump to minimize break flow to the secondary system. At this point, RCS pressure and faulted SG pressure should be maintained approximately equal.
l Amendment 45 15.6-8
ATTACHMENT
~
ST HL AE f?M PAGE350F 41 STP FSAR 7.
Continue dumping steam from the other SGs and simultaneously decrease RCS 45 pressure. Decrease pressure in faulted SG by backfill, blowdown, or steam release.
S'.
Gk4-e. epen% a$ %e (L u r Y ll'eE'~ As.mevs hsN After the RHRS is placed in operation, the condensate accumulated in the sec-ondary system can be examined and processed as required.
There is ample time available to carry out the above recovery actions such 45 that isolation of the faulted SG is established before water level rises into the main steam pipes. Normal operator vigilance ensures that excessive water level will not be attained.
Results
_ The previous assumptions lead to a conservative upper limit estimate of l45-125,000 pounds for the total amount of reactor coolant transferred to the secondary side of the faulted SG as a result of a tube rupture accident.
l 45 15.6.3.3 Environmental Consequences. The postulated accidents involving release of steam from the secondary system do not result in a release of sec-ondary system radioactivity unless there is leakage from the RCS to the secon-dary system in the SGs.
A conservative analysis of the postulated SG tube rupture assumes the LOOP and hence involves the release of steam from the secondary system. The conservative analysis of the potential offsite doses resulting from this accident is presented using the Technical Specification limit secondary coolant concentrations.
Parameters used in the analysis are given in Table 15.6-3.
45 l The following conservative assumptions and parameters are used to calculate the activity releases and offsite doses for the postulated SG tube rupture.
l 45 l 1.
Prior to the accident, an equilibrium concentration of fission products exists in the primary system.
l 45 2.
Prior to the accident, the secondary coolant specific activity is equal to the Technical Specification limit of 0.10 pCi/gm dose equivalent of I-131.
This activity is presented in Table 15.A-5.
3.
The primary-to-secondary leakage of 1 gal / min (Technical Specification limit) is assumed to continue for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> following the -accident at the pre-accident rates.
It is assumed that prior to the accident 0.35 gal / min leakage occurred in the defective SG and 0.217 gal / min leakage in l45 each of the unfaulted SGs.
4.
Offsite power is lost and the condensers are not available for steam dump.
5.
Eight hours after the accident, the RHRS starts operation to cool down the plant. No further steam or activity is released to the environment.
6.
The iodine partition factor in the SGs during the accident is equal to
(
0.01.
l45 15.6-9 Amendment 45
61
] %)( 3D PAGE $6W3F /
ATTACHMENT STP FSAR ST.HL-AE-M Response (Continued) would be less severe from a core integrity standpoint than the steamline ruptures at hot zero power presented in Chapter 15.
Technical Specification 55 require shutdown margins such that the return-to-power transient would be less severe than the cases presented in Chapter 15.
The engineered safeguards functions desired during a steamline rupture are actuation of SI and steamline isolation. When the low pressurizer pressure signals and the excessive cooldown protection signals are blocked, SI and l 55 steamline isolation may be automatically initiated by the following sir,als:
1.
Hi Negative Steamline Pressure Rate Signal This signal is unblocked automatically when the excessive cooldown protection 55 signals are blocked.
(Actuates steamline isolation.)
-e 29 M.onta[nment Pressure Signal
~
2.
(Actuates
& steamline isolation )
SI and steamline isolation may al(so be actuated manually by the operator.
C
- r A During a steamline break, steamline pressure, pressurizer pressure, pressurizer level and steam generator water level will tend to decrease and l55 steam flow will increase. These parameters are all displayed in the control The operator's attention may be drawn to them by the following alarms; room.
a.
Low pressurizer level deviation alarm b.
Low pressurizer level alarm c.
Steam flow /feedwater flow mismatch alarm d.
Low steam generator level deviation alarm i
e.
Low steam generator level alarm 3
Q&R 6.3-23f Amendment 55
ATTACHMEN q;
ST HLjE 17 /
A 0F
[pl(*
System (RCS) for xenon decay. Replenishment of the AFST may be from one of two nonsafety systems (Demineralized Water or Secondary Make-up Storage Tank) or from the Essential Cooling Pond (ECP) while boric acid is added to the RCS via the safety grade Chemical and Volume Control System (CVCS).
55 For the following events involving breaks in the RCS or secondary system pip-ing, additional requirements for operator action have been identified.
Main Steam Line Break (See Table Q211.52-1)
Following the hypothetical main steam line break (MSLB) incident, a main steam isolation signal will be generated, causing the main steam isolation valves to close within ten seconds of the break.
If the break is downstream of the iso-lation valves, all of which subsequently close, the break will be isolated.
If the break is upstream of the isolation valves, or if one valve fails to close, three SGs will be isolated while one will continue to blow down. Only in the case in which one SG continues to blow down is operator action required.
g,s.s A msr Ws mol In the analysis of a steam line break (Section 15.1.5), it has been assumed that the faulted steam generator is unisolable.
The low steam line pressure signal automatically nitiates a SI signal which results in "Cr? :ler"r-1 *=
-the i-tret la p-==d*MFIV closure in all loops, as well as SI flow. The 55 analysis proceeds for 600 seconds (10 minutes). All applicable safety criteria are met for this event without assuming operator action. It is implicitly assumed, however, that within a reasonable time period (30 41 minutes), the operator will begin corrective measures to orderly shutdown the plant, in accordance with the plant's Emergency Operating Procedures as discussed below.
4 The only source of water to the SG will be AFW since the SI signal or diverse
.55 excessive cooldown protection signal will cause main feedwater isolation to Following main steamline isolation, steam-pressure in the steam line occur.
for the unisolated SG will continue to fall rapidly, while pressure stabilizes i
in the remaining three main steam lines. The difference in steam line i
pressures, available seconds after steam line isolation, will provide the l
information necessary to identify the affected SG at which time the operator will isolate the AFW to the SG.
Manual controls for the AFW pumps and the AFV regulating and isolation valves are provided in the control room. The required equipment for detecting the affected SG and isolating its AFW is 8
safety grade. The operator's failure to isolate the AFW to the SG or the isolation of the wrong generator will result ir the SG continuing to blowdown.
l r
The second required operator action is to se mai; y control repressurization of
{
I the RCS.
Following the automatic SI ac'uc. tin. d after the affected SG has been isolated, continued operation of thw saic q Injection System (SIS) will increase the RCS pressure to the maximum SI pump shutoff head (-1600 psia).
(The RCS can be repressurized without isolating the affected SG; however the process will take longer). Above 1600 psia the operator must restore normal pressure and level control systems. The operator may terminate SI based on criteria established in the Emergency Operating Procedures. If the operator l55 1 fails to stop the SI pumps after the pressurizer level and pressure return to 1
Q&R 15.0-18a Amendment 55
ATTACHMENT.
ST HL AE
normal values, there will be no impact since the SI pump shutoff head is below normal operating pressure.
To maintain the pressurizer water level, the operator can use the centrifugal charging pumps as necessary. The operator has pressurizer level indication instrumentation available in the control ro'om as required for post accident monitoring. As soon as pressurizer water level returns to at least the low
'5 c
level setpoint the operator can reestablish normal letdown flows.
If the operator fails to modulate the charging flow, the pressurizer may overfill and water relief through the pressurizer PORVs may occur.
The operator also reestablishes operation of the pressurizer heaters to main-tain a steam bubble in the pressurizer to control RCS repressurization. The requirements to terminate AW flow to the affected SG, reestablish normal charging and letdown flows, and reestablish operation of the pressurizer heat-ers can be met by simple switch actions by the operator in the control room.
For the removal of decay heat in the long-term (following the f.nitial cooldown), the operator is instructed to use the unaffected SGs with the AWs as a water source and the steam dump. system or SG PORVs te relieve steam.
f.he l55 AW regulating valves and the SG water level indication are both safety grade.
Feedwater Line Break (See Table Q211.52-2)
Auxiliary feedwater is initiated automatically for all feedwater line break on receipt of either a low-low SG water level signal or a SI signal.
For the feeduater line break downstream of the main feedwater isolation valves (MFIV),
4g the required operator actions are similar in nature to the required actions for the main steam line break. An accident caused by a feedwater line break upstream of the MFIVs is automatically terminated by feedwater isolation, c2ms % esrfs '^cl in the analysis of a feedwater line break (Section 15.2.8), the faulted steam generator has been assumed to be unisolable. The low-low stem generator water level signal automatically initiates reactor trip and auxiliary feedwater system start up.
The low steam line pressure signa initiates a SI 53 signal which results in e m % "" h 211 loops-en#MFIV closure in the intact loops. The analysis proceeds for 10000 seconds (2.75 hours8.680556e-4 days <br />0.0208 hours <br />1.240079e-4 weeks <br />2.85375e-5 months <br />). All applicable acceptance criteria are met without operator action. The following operator actions would complement orderly plant shutdown, in accordance with the plant's Emergency Operating Procedures.
The first required operator action is to identify the affected SG, isolate AW flow to that SG, and close any main steam and MFIVs valves not closed by the automatic signal. The operator will identify the affected SG by comparison of individual main steam line pressures after steam line isolation has occurred.
After identifying the affected SC, the -operator is instructed to isolate AW flow to that SG by shutting the AW regulating and isolation valves. The steam line pressure indication and AW regulating and isolation valves are l55 safety grade.
The operator must provide for decay heat removal through the unaffected SGs by maintaining SG water level using AW as a makeup supply. The operator can use the turbine bypass system or the SG PORVs to begin a controlled cooldown.
If the operator fails to modulate the AW flows to the intact SCs, overfilling of a SG may occur.
Q&R 15.0-18b Amendment 55
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ATTACHMENT @
ST HL-AE-IT STP FSAR PAGE 390F '//
Question 440.57N O
In Amendment 43, Figure 15.0-9 and the information in Sections 15.1.4 and 15.1.5, and the revised response to Question 440.01 (Amendment 44) all indi-i cate that the MSIVs are closed on any SI signal. Amendment 44 indicates that this includes SI actuation on low RCS pressure. The previous FSAR version in-dicated thet the M11V would close on high containment pressure or evidence of steam line break, which is typical of most Westinghouse plants. Closure of the intact steam generator MSIVs on any SI signal would prevent utilization of condenser steam dump in the event of steam generator tube rupture (SGTR) or a small break IDCA when offsite power is available. This would probably result in slower mitigation of the accident and increase the offsite cose. The Westinghouse Emergency Response Guidelines (ERGS) which have been approved by NRC take credit for condenser steam dump when it is available. Therefore, please justify this design change on the basis of increased safety.
b O
Response
S e. e %g d W The automatic closure of the main steam isolation valves (MSIVs) on a safety injection (SI) signal is not expected to have any adverse impact on the mit-igation or recovery from a steam generator tube rupture (SGTR) or small break f Loss-of-Coolant Accident (LOCA). The Emergency Response Guideline (ERG) for SGTR recovery requires that the operator isolate the ruptured steam generator (SG) from the intact SGs prior to the initial cooldown of the Reactor Coolant System (RCS). This isolation step is accomplished by either closing the MSIV for the ruptured SG or the MSIVs for the intact SGs.
If the MSIVs are auto-f
{ matically closed on an SI signal, the operator will not have to perform this step.
If the condenser is not available, as assumed in the design basis analysis, the RCS cooldown can be accomplished by using the power-operated relief valves (PORVs) on the intact SGs, and the MSIVs would not have to be opened.
If the condenser is available, the MSIVs or bypass valves for the intact SGs would have to be opened to permit steam dump to the condenser.
However, the time required for opening the MSIVs would be offset by the time saved by not having to perform the isolation step initially. Thus, it is concluded that the automatic closure of the MSIVs on an SI signal would not adversely affect the SGTR recovery actions.
For a small break IDCA, steam dump is utilized for the RCS cooldown in the post-LOCA cooldown ERG.
If the condenser is available, the MSIVs can be opened to permit steam dump to the condenser for the RCS cooldown, or alter-natively, the cooldown can be performed using the SG FORVs.
Since the time required to perform the post-LOCA cooldown is not critical to the recovery operation, the time required to open the MSIVs would not adversely affect the recovery.
Since the ERCS were developed for a reference plant which does not have auto-matic closure of the MSIVs on an SI signal, the changes required to accom-modate this design feature will be incorporated in the conversion of the ERGS to plant specific Emergency Operating Procedures (EOPs) for STP.
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h STP FSAR Response (Continued)
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Tn~ addition, the non-DOCA events of Chapter 15 are not adversely impacted bj automatic closure of the MSIVs on an SI signal. For the credible steamline break event (Section 15.1.4), the SI initiated MSIV closure results in earli steamline isolation than with the logic typical of most Westinghouse plants.
Therefore, a less severe transient would result.
For the credible steamline break analysis of the STP FSAR, reactor trip is assumed to occur immediately.
The primary side depressurizes to the low pressurizer pressure SI setpoint.
This initiates SI and causes the feedwater isolation valves to close and the main feedwater pumps to trip.
In the STP FSAR analysis, as would be required with analyses for logic typical of most Westinghouse plants, credit is not taken for steamline isolation (MSIV closure) at this point. The MSIV closure is assumed to occur later at the low steam line pressure setpoint. The current STP FSAR analysis meets all.the applicable acceptance criteria. The STP isolation of the steamline (MSIV closure) following low pressurizer 53 pressure SI provides earlier mitigation of the event than that of logic typical and most Westinghouse plants.
For the hypothetical steamline break (Section 15.1.5), the low steam line pressure signal would initiate SI/MSIV closure for STP and, in the logic of most Westinghouse plants, would initiate both MSIV closure and SI.
For this transient there wouli be no differences in the current STP FSAR analysis.
A spurious SI signal and subsequent MSIV closure would result in a Loss of Load / Turbine Trip event. As discussed in Section 15.5.1, introduction of borated water into the reactor coolant system following a spurious SI signal is not a credible event.
This event, if there.was no immediate reactor trip
(
due to the SI signal, would be bounded by the Turbine Trip of Section 15.2.3 4
which assumes a late reactor trip on an OTAT or high pressurizer pressure signal following turbine trip.
Because the immediate reactor trip due to the SI signal mitigates the tran.=ient earlier, it is not as severe as that nalyzed in Section 15.2.3.
i Vol. 3 Q&R 15.0-23N Amendment 53
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Response
ku%ssr The Main Steamline Isolation Valve (MSIV) closure logic +-111 L=' modified to be consistent with that of other Westinghouse plants. The MSIV closure on manual and high steam pressure r ge i nals will be maintained. The MSIV closure on
,,3 a safety injection signal =
modified to MSIV closure only on a HI-2 containment pressure signal and, from the excessive cooldown protection logic, signal.
on a low steamline pressure signal and on a low-low Tcold i
i 1
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Vol. 3 Q&R 15.6-17N Amendment 55
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