L-80-175, Discusses Main Steam Line Break Analysis.Results Show That Peak Containment Pressure Is Not Influenced by Assumed Addition of Auxiliary Feedwater Ruptured Steam Generator. Forwards Assumptions Used in Analysis
| ML17208A735 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 06/20/1980 |
| From: | Robert E. Uhrig FLORIDA POWER & LIGHT CO. |
| To: | Eisenhut D Office of Nuclear Reactor Regulation |
| References | |
| L-80-175, NUDOCS 8006240189 | |
| Download: ML17208A735 (19) | |
Text
=
c i
I REGULATORY ORMATION DISTRIBUTION SY M (RIDS)
ACCESSION" NBR;80062uoi89 DOC ~ DATE: 80/06/20 NOTARIZED:
NO FACIL;50-335 St. Lucie Pl anti Unit 1 i Florida'Power 8 Light'o, AUTH ~ NAME AUTHOR AFFILIATION UHRIG E R ~ E ~
Florida Power 8 Light Co, RECIP ~ NAME RECIPIENT AFFILIATION EISENHUTiD ~ G ~
Division of Licensing DOCKET 05000335
SUBJECT:
Discusses main steam line break analysis, Results show that peak containment pressure is not influenced by assumed addition of AFW to reuptured steam generator, Forwards assumptions used in analysis L explanation of results, DISTRIBUTION CODE:
AOO IS COPIES RECEIVED:LTR Q ENCL Q SIZE:gQ.
TITLE: General Distribution for after Issuance of Operating'Lic N
SC
~
- DIES, RECIPIENT ID CODE/NAME ACTION; BC Ql.ggf g, 05 INTERNAL: A/D CORE 5
CS21 CHEM ENG BR 17 HANAUERES ~
?0 MOOREEV ~
22 OELD 14 QA BR 15 COPIES LTTR ENCL 7
7 1
0 1
0 1
1 1
1 1
0 1
0 RECIPIENT ID CODE/NAME A/D REACT SYS18 EMERG PREP 16 ILE 12 NRC PDR 0?
O~SE BR 19 01 COPIES LTTR ENCL 1
0 1
0
?
2 1
1 1
0 1
1 EXTERNAL: ACRS NSIC 20 00 16 16 1
1 LPDR 03 1
1 TOTAL NUMBER OF COPIES REQUIRED:
LTTR 38 ENCL 31
V
/
W Il, I
7 IW 7
~
71 I
I,
'17
. BOX 529100, MIAMI,FL 33152
@Alki
~jpr~a$~
l FLORIDA POWER 8 LIGHTCOMPANY June 20, 1980 L-80-175 Office of Nuclear Reactor Regulation Attention:
Mr. Darrell G. Eisenhut, Director Division of Licensing U. S. Nuclear Regulatory Commission Washington, D.CD 20555
Dear Mr. Eisenhut:
Re:
St. Lucie Unit 1
Docket No. 50-335 Auxiliar Feedwater Addition The Main Steam Line Break (MSLB) analysis for St. Lucie Unit 1
has been com-pleted by our NSSS vendor.
The assumptions used in the analysis are listed in Enclosure (1).
The results of the analysis show that the peak containment pressure is reached according to the steam inventory added to the containment following the MSLB.
The inventory added to the containment by boil off of the auxiliary feedwater (AFW), with an assumed delay time of three (3) minutes, is not sufficient to cause the containment pressure to experience a "second peak."
In other words, under these conditions, the peak containment pressure is not influenced by the assumed addition of the AFW to the ruptured steam generator.
For licensing
- purposes, the peak containment pressure following a MSLB remains the same as was calculated in the FSAR, and is not influenced by the AFW.
An explanation of these results is provided in Enclosure (2).
Enclosure (3) discusses the Return-to-Power aspect of feedwater addition following a MSLB. It concludes that the MSLB events presented in the FSAR and subsequent reload submittals conservatively bound the MSLB event with automatic AFW initiation after. a three minute time delay.
Very truly yours, Robert E. Uhrig Vice President Advanced Systems
& Technology REU/MAS/pa Enclosures (3) cc:
J.
P. O'Reilly, Region II Harold F. Reis, Esquire 8006240~j, P PEOPLE... SERVING PEOPLE
1 S'
lI
(
W
ENCLOSURE (t)
ASSU)1PTIOHS USED IH T}IE ANALYSIS General Notes C
Nl HSSS data used was identical to that used in the FSAR, except that AFtl was added to the affected steam generator with an assumed three (3)
., minute delay.
Com uter Simulation Codes HSLB/AFM Blowdown SGHIII'ontainment Pressure/Temperature
Response
COHTfNHS Note:
505 failure of the containment active heat removal system is assumed.
This assumption was used in the FSAR.
HSSS Data Reactor Power Primary Side Initial Pressure, psia PrQnary Side Inlet, 'F Secondary Side In',tial Pressure, psia HSLB Pure Steam Break Area, ft 2570 2250 55l 013 5.355
'ote:
Credit w=s not taken for the action of the reverse flow check valve (RFCY) in the main steam lines adjacent to the affected steam generator; this assumption was us d in the FSAM.
Auxiliarv Feedwater Data
~e 2 ot
~ l F'low From One Electric Pump, GPll*
Flow From Turbine Driven Pump, GPH**
Total AFll Flow To Affected Unit
- 750 700
~450 Note:
The flow from the other electric pump was assumed to be unavailable to the affected steam generator due to AFjl piping arrangement.
As a conservatism this flow was not added to the unaffected steam generator since the cold AFll to the unaffected unit would indirectly inhibit the heat transfer process at the affected steam generator.
- Flow at runout extrapolated.
~ Turbine pump runout flow - 1400 GPN, extrapolated Turbine pump assumed to be at 50% RPli 0.50 x 1400
=
700 GPH Containment Data Free Yolume, ft Passive ffeat Sinks Initial Conditions:
Temperature,
'F
- Pressure, psia Relative Humidity 2.5053 x '10 FSAR Table 6.2-3 120*
14.7+
10.0%"'The data used are the usual values recommended bv CE for peak containment pressure/temperature calculat.;ons 'his data was not listed in the FSAR.
Containment S rav Data
- Rate, GPtf (1 spray.
)"'etpoint, psig Delay Time, seconds 2700 10 60**
"'Failure of 1 spray assumed.
- 4'Assumed; not listed in FSAR.
sI 3 Fan Cooler Data Capacity (each)
~ Delay Time, 'seconds tfumber of fan coolers 60.0 x 10 Btu/hr 6
l0*
2 *A' Ho data was available 'in the FSAR.
The assumption of. 10 seconds delay is conservative for this plant.
S P
"* Failure of 2 fan coolers assumed.
EXPLN<ATION OF RESULTS The AFH does not reach the affected steam generator until 180 seconds, by hypothesis.
Consequently, there is no associated steam release to the containment until this time.
By contrast, the MSLB blowdown is essentially
.i over at about 120 seconds,
'so that there is an HSLB caused peak containment pressure during the first 120 seconds of the event; the time of this peak depends on the competition between the MSLB steaming rate to the containment and the sum of the spray, fan cooler, and passive heat sink removal rates.
Typically, the rates described above are equal some time after the sprays are on, but before the affected steam generator is fully emptied.
Following the MSLB peak pressure, the containment pressure will continue to decrease as the HSLB steam rates decrease.
This process will continue until the steaming rat s are suddenly increased by the sudden addition of ABI to the affected steam generator at 180 seconds, at thich time the rate of decrease of the containment pressure slows.
At this point in time the NSSS possesses adequate energy to completely boil the AF!l'flow; in time, as decay heat decreases and as sensible he'at is'removed by the boiling of the. ABl,,i:he !!SSS. wUl..aa,.longer,. be.,hat..enough, to boil al.'l of the AFll.
Following'this time, the AFll-caused steaming rates will gradually decrease, and the AFW not boiled off will accumulate as heated water in the aff'ected steam generator.
The heating of the accumulated AFl1 removes a corresponding amount of energy from the primary side.
The maximum AF>l steaming rate is the AFll rate itself since there is no significant stored inventory in the affected steam generator at 180 seconds; the affected unit is completely boiled dry at this time.
The AFll rate is 1450 GPH, or about 200 ibm/sec.
The majority of the steam is released as saturated steam, with an approximate enthalpy of 1200 Btu/ibm.
Accordingly, the energy released to the containment via the complete boiling of the AFH is at most 200"1200
= 240,000 Btu/sec.
The containment vapor space will be saturated at this time since the sprays have been on for about two minutes.
If the total containment pressure were, say, 40 psig (steam plus air total pressure) then the corresponding vapo) space temperature would be about 260'F.
Using 260'F, the fan cooler heat removal is about 33,000 Btu/sec.
from two (2) fan coolers.
Added to
this rate is the spray heat removal rate.
Since the containment is saturated, the spray rate is limited by the energy required to heat the spray to saturated liquid conditions.
The spray rate is 2700 gpm *{1 spray),
, or 370 ibm/sec.
The corresponding spray heat removal rate is then about 370 x {264-95)
= 62,500 Btu/sec.
Consequently, the sum of the fan and spray heat removal rates from the containment is:
2 fan coolers 1 spray Total 33,000 Btu/sec.
62,500 Btu/sec.
95,500 Gtu/sec.
1~hile this sum is less than the 240,000 Btu/sec.
associated with the full AR/ boiloff, it is presented in this form to demonstrate the fact that the containment total active heat removal rate of 4 fan coolers and 2 sprays (total capacity approximately 200,000 Btu/sec) with no assumed single active failures is comparable to the AFH steami.ng rate.
This is not un-expected since both the AFif and the containment active heat removal systems are sized with respect to decay heat removal.
I The last containm nt heat removal term is that associated with the containment passive heat sinks. 'he total passive heat sink energy removal rate is, of
- course, the sum of the individual heat sink rates.
There is no simple hand calculation for these rates since the. heat, conduction equation must be numerically solved'for each heat sinL subject to time varying containmeht temperatures and heat transfer coefficients.
At 180 seconds, computer..
calculations of this process show a total rate in excess of 200,000 Btu/sec.
Summing all heat removal rites now provides a total of. more than 295,500 Btu/sec.,
compared to a maximum of 240,000 Btu/sec. input.
The above comparison clearly shows why there is no second peaL containment pressure associated with the AFll.
The restrictions associated vgth this result are:
1) 50Ã failure of containment sprays and fans.
2)
. AFM rate of. no more than 1450 GPH.
3)
AFll input only after 100 seconds.
4
Enclosure (3)
This attachment illustrates the impact of automatic initiation of auxiliary feed-water system (AFMS ) on the 1 i censing cases analyzed for a Ila in Steam Line Break Event; The pro'vided results of analysis for the most limiting Hain Steam Line Breaks (HSLB) with respect to return 'to power assume this system is designed with a delay in the automatic delivery of the auxiliary feedwater to the ste m genera-tors.
The analyses performed for this evaluation, there ore allowed. for a three-(3) minute delay in the actuation of the AFllS subsequent to receiving a low steam generator water level trip signal.
The conclusions of this analysis are considered to be applicable to the following nuclear reactor plants: Calvert Cliffs Units 1
and 2, Ft. Calhoun, l1illstone Unit 2, Palisades, and St. Lucie Unit 1.
The most limiting cases analyzed were those selected from the Oesign Basis Events analyzed in the FSAR or subsequent reload licensing submittals, as appropriate.
The most limiting case v!as found to be a full power-full flow flain Steam Line.
Break inside containment with automatic initiation of AFl/S after a
3 minute delay.
The analysis was continued until the subcriticality margin was continuously in-creasing.
lhe delay of 3 minutes assumed as part of the design of the automati-cally initiated,auxil',ary feed system was modeled conservatively in the analysis.
The flSLB outside containment is less limiting because the blowdown rate of the steam generators is restricted by the flow venturies located in the steam lines
'hus leading to a less sev'ere reactivity insertion and a smaller potential for return-to-power than the results presented herein.
Th~ veu~lts...af. the limitirg, ~se.show.that. the. ~>Hected. steam, generator. hives..dry..
in about 70 seconds, and begins Reactor Coolant System (RCS) cooldown with feed-water only.
The peak power level attained including decay heat and subcritical multiplication is 12.
From the time the steam generator runs dry until the actuation of auxil>avy feedwater
- system, boron inj cted by High Pressure Safety Injection (HPSI), actuated at about 16 seconds into the transient, continu s to add more negative reactivity to the core.
After the initiation of AFli flow, the
. cooldown of the reactor coolant system (RCS) is resumed.
The auxiliary flo>> is conservatively assumed to feed the affected steam generator only.
The assumed auxiliary flow to th affected steam generator was conservatively taken to be about 208 of the full power feedwater flow.
The continued cooldown of the RCS adds more positive reaciivity which is eventually terminated by the Low Pressure Safety Injection (LPSI) flow injected due to low RCS pressure.
The negative reactivity inserted via LPSI flow terminates the reactivity excursion.
The return-to-power attained after the AFl'S delivery is 10.7Ã.
Thus, with the 3 minute delay in the actuation of AF!IS, the auxiliary feedwater will be introduced away from the most critical time frame with respect to return-to-power and the con-clusions of. the HSLB events presented in th FSAR and the subsequent reload
's'ubmittals conservatively bound those with the control grade automatic initia-tion of auxiliary feedwater systems included.
- A typical sequence of events, typical for operating C-E plants, for*the limiting case are presented in Table l.
3 N
The HSLB results presented in the FSAR and subsequent reload licensing submittals assumed the following consequential failures in addition to the single failure
'hich initiates the event (i.e., the double ended pipe break'inside containment):
(a)
On reactor scram, the'ighest worth Control Element Assembly is assumed to stick in the tully withdrawn position, (b) On Safety Injection Actuation, the HPSI and one of the LPSI safety 'injection pumps are assumed to fail to start.
(c)
No main feedwater.isolation is assumed on llSIS.
The main feed flow is assumed to coastdown to 5;l of full power flow in GO seconds.
(i)ore realistically flow would ramp to zero in about 20 seconds.
)
Single failures were considered in the design basis to the extent that a failure initiates the event and safety grade equipment is designed to accommodate single failures as descri'd above and is consistent with the desion basis presented in the'FSnR..
Ho consequen'al fc ilures other than previously identified were con-sidered.
All control s;stems considered were assumed to function in the manner consistent with the FSr"..
,Single failures concurrert with the HSLB (other than those identified above),
as well as loss of offsite power concurrent with f1SLB, are not, and have not been part of the design basis as described in the FSAR and, therefore, were not con-
"sidered.
P
Sequence of Events for the tlain Steam Line Break Event with Automatic Initiation of Auxiliary Feedwater System (Full load, Two-Loop Condition, Nozzle Break)
Time sec Event 5
Safet Svstepl Initiated Set oint or Yalue
'.0.0 Initiati on of break 3
4.3 4e8 Low steam Generator Pressure tlip signal occurs, HSIS
~
initiated and flain Steam Isolation 'e'alves begin to close.
Trip break rs open CEAs begin to drop into core Reactor. Protection System Hain Steam Isolation System I
~ ~ i /
e ~sv 5I Reactor Protection System 478 psia 1 0e'7 16.2 Complete closure of Hain Steam Isolation Valves to terminating blowdown from
. the intact steam generator Pr essuri zer empti es Low RCS pressure,'IAS Initiated Safety Injection System 1553 psia 22.8
.'igh Pressure Safety Injection flow Ini tiated Safety Injection System 1220 psia 64.8
't3ain feedwater flow completes ramp down to 55
.68.7 71.9 Affected steam generator liquid inventory depleted and beginning of blowdown of feedwater only Peak return-to-power"occurs with a peak reactivity of -.186/hp 5
125 return-to-power includes decay heat and subcritical multiplication
V YC
AOI.E n-1 ontinued Time (sec.
Event Safet S stem Initiated Set oint or Value 150.0'18.7 Auxiliary Feedwater flow to, Auxiliary Feedwater System affected steam geneva".or snstsated Low Pressure Safety Injection Safety Injection System flo<I Initiated 207 psia 319.9 345 Peak reactivity post auxiliary feedwater delivery Peak return to power post auxiliary feedwater delivery
+.13@ p
- 10. 7X
E